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Home My WebLink About2025-12-03_325-7341. 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): 24,600 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 12/16/2025 24,594'13,591' 4-1/2" 5201' Halliburton TNT Prod Packer Baker ZXP, No SSSV 7-5/8" 20" 10-3/4" 80' 7-5/8"10,997' 2,694' 133' 119' 2,733' 5,012'11168' 11,035' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL393883 / ADL025528 / ADL025544 / ADL390434 225-090 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20925-00-00 ConocoPhillips Alaska, Inc. Proposed Pools: KRU 3T-614 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): TNT Packer: 10,827' MD / 4,920' TVD ZXP: 11,003' MD / 4,969' TVD Perforation Depth TVD (ft): L-80 11,009' Perforation Depth MD (ft): 4-1/2" 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 Length Size TVD Burst Allen.Eschete@ConocoPhillips.com 907-265-6558 Senior Completions Engineer None5,201 24,594 5,201 1,828 10,860 MD 6,890 5,210 119' 2,471' 4,978' Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 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: 2025.12.02 14:47:11-09'00' Foxit PDF Editor Version: 13.1.6 Allen Eschete 325-734 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 one-half mile radius of the current or proposed wellbore trajectory. Well 3T-614 lies within acreage that was located inside the former Oooguruk Unit before it was purchased by ConocoPhillips Alaska Inc. and included within the 12th expansion of the KRU. Page 17 of EPA class I UIC permit number AK1I009-B for Oooguruk Unit disposal wells DW-1 and DW-2 (obtained with that purchase) states: “The requirement to monitor the strata overlying the confining zone for fluid movement is waived since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet “No USDW” criteria).” 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. 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 10/14/2025 shows that the job was pumped with 394 barrels of 11.0 ppg lead cement and 61 barrels 15.8 ppg tail cement. This was displaced with 234 bbl 9.8 ppg spud mud. The plug bumped and the floats held. The 7-5/8” casing cement report on 10/22/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 159 barrels of 14.0 ppg lead cement, followed with 63 barrels of 15.3 ppg tail cement. This was displaced with 499 barrels of 9.5 ppg NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. According to the log and SLB interpretation, the good TOC reached 8,353’ MD with a transition zone up to 4,194’. We also had the ConocoPhillips Cementing SME (Dale Doherty) review the log, and his interpretation is that the TOC reached approximately 6,300’ MD with VDL pipe signal slightly fading and the amplitude readings suggesting that the cement is still setting up. The 4-1/2” liner cement report on 11/03/2025 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 380 barrels of 15.3 ppg cement. The cement was displaced with 302 bbls of 9.5 ppg brine and the plugs bumped and held for 5 minutes. Floats held. 60 bbls of mud push with trace cement was observed after circulating a bottoms up from the liner top packer indicating the entire lateral is cemented. 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 10/15/2025 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 10/22/2025 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes. On 11/05/2025 the 4-1/2” tubing was pressure tested to 4,200 psi for 30 minutes. On 11/05/2025 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) 7,050 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 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 300 ft TVD over the course of the lateral section of well 3T-614, from where it intersects the top formation at 11,146’ MD (-4,955’ 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 840’ TVD along the 3T-614 trajectory. The top of the Torok confining interval in the well starts at 8,623 MD (-4,116 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 -5,260’ 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-612: The 7-5/8” casing cement report on 11/4/2018 shows that the job was pumped as designed, indicating competent cementing operations. 12.5 ppg MPII was pumped before dropping bottom plug, this was then chased with 303bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.5 ppg LSND mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,270’MD/3,832’ TVDRKB/3,768’ TVDSS Source: 218-111 - Laserfiche WebLink 3S-625: The 7-5/8” casing cement report on 9/29/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 297 barrels of 15.3ppg cement with BMII. The cement was displaced with 574 barrels of 9.6ppg LSND drilling mud. The plug did not bump and 50% of shoe track volume was pumped. Losses totaled 21 barrels during the job. Cement floats held. A cement bond log indicates competent cement with a cement top @ 7,850’ MD (3,970’ TVDRKB / 3,908’ TVDSS). Source: 222-079 - Laserfiche WebLink 3T-613: The intermediate casing cement job was pumped with 211 bbls of 14.0ppg lead cement and 59 bbls of 15.3ppg tail cement. Plugs bumped and floats held. Source: Laserfiche WebLink 225-036 3T-616: The intermediate casing cement job was pumped with 117 bbls of 14.0ppg with BMII lead cement and 58bbls of 15.3ppg tail cement. Plugs bumped and floats held. Source: Laserfiche WebLink 224-138 3T-616 PB1: The abandonment plug consisted of 42bbls of 16.3ppg cement laid in at the heel of the wellbore into the 7-5/8” intermediate casing shoe. The cement top was then tagged at 9,065’ MD/5,104’ TVD/5,053’ TVDSS with 12klbs. Coyote isolated via main wellbore 3T-616. Source: Laserfiche WebLink 224-138 3T-616 PB2: Not cemented. Coyote isolated via main wellbore 3T-616. Source: Laserfiche WebLink 224-138 3T-619: The intermediate cement job was pumped with 191 barrels of 14.0 ppg lead cement, followed with 61 barrels of 15.3 ppg tail cement. This was displaced with 520 barrels of 10.0 ppg 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 @ 7,652’ MD (3,974’ TVDRKB). The intermediate column of good cement of 437’ MD in combination with the weaker column of cement above in excess of 2600’ MD meets regulation (AOGCC’s approval on 09/03/2025). Source: 225-063 - Laserfiche WebLink 3T-622: The Intermediate casing cement job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 433 barrels of 13.5 ppg cement. The cement was displaced with 303 bbls of 9.5 ppg brine and the plugs bumped and held for 5 minutes. Floats held. 112 bbls of good cement were observed after circulating a bottoms up from the liner top packer indicating the entire lateral is cemented. Source: 225-079 - Laserfiche WebLink Nuna-1: The 7-5/8” casing was cemented in place on 2/16/2012. The cement report indicates that the job was pumped with 40 bbls 15.8ppg Class G cement. The plugs bumped and partial returns were observed during the job (pg. 187 at link). Suspension operations began on 1/18/2023 where a cement retainer was set at 9,062’ CTMD and 65bbls of Class G cement was pumped through the retainer. Another retainer was placed at 7,965’ MD and 48bbls of 15.8ppg cement was pumped with another 12 bbls laid on top of the retainer. The TOC was tagged at 7,003’ MD and a MIT-T performed to 1700 psi, witnessed by AOGCC on 3/1/2023. A tubing cut was completed at 6,960’ MD and the 4.5” tubing was then pulled. A CIBP was set at 6,910’ MD and tested to 1,200 psi. Cement was laid on top of the retainer and tagged at 6,621’ MD two times with 12klbs. Source: Laserfiche WebLink 211-155 Colville Delta 3: Colville Delta 3 was abondoned on 3/31/1986 with a cement retainer set at 5000' MD. Additionally, a surface plug was pumped and witnessed by AOGCC. Cement was then pumped down the 7" x 9-5/8 annulus. The wellhead was removed and the 9-5/8" and 7" casing were cut off. A plate was welded over the 7" casing and deemed adequately plugged by the AOGCC according to the Plugging and Location Clearance Report on 2/27/96.Source: 185-211 - Laserfiche WebLink 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 four faults transect the Torok Oil Pool reservoir within one half mile radius of the 3T-614 wellbore trajectory shown in Plat 1. Two faults intersect the 3T-614 well trajectory at 20,792’ MD (Fault 1) and 20,913’ MD (Fault 2) respectively. Both are interpreted to strike NE-SW, downthrown to the South with less than 20’ of offset. There are two other faults within the half mile radius, but neither intersect the 3T-614 wellbore. The first, (Fault 3), is southwest of the 3T-614 toe, striking NE-SW, downthrown to the South with approximately 10’ of throw in the ½ mile radius. The second (Fault 4), is located to the Northwest of the 3T-614 heel, striking NE-SW, downthrown to the South with approximately 10’ of throw. All faults in the ½ mi area of the 3T-614 are difficult to trace on the seismic data, due to a) lack of fine-scale resolution at the Torok Oil Pool level and b) lack of reflectivity in the overlying Torok shales, the result of the monotonous shaly lithology. Faults 1 and 2 are interpreted to be confined to the Moraine interval as they are not explicitly mapped on seismic and are interpreted only on well log correlation. Fault 3 is seismically mappable but not interpreted to penetrate through the overburden, into the overlying hydrocarbon bearing Coyote Oil Pool. Fault 4 is mapped both on seismic and with well penetrations and has the potential to penetrate through the overburden into the overlying hydrocarbon bearing Coyote Oil Pool, however; due to the shaly overburden and horizontal stress acting on the fault (interpreted to be 15.8 ppg at the fault’s mapped orientation) the fault will not interfere with containment. If there is any indication that a fracture has intersected any 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-614 was completed in November 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 22 dart activated sliding sleeve and 4 ball drop 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 ball/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. Balls/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 2,235’ MD / 2,124’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 40 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. Pump Frac Stages 1 through 27 by following attached pump schedule at ~37 bpm with a maximum expected treating pressure of ~7,050 psi. x Skip stage 8 due to proximity of fault. 11. The well is ready for Post Frac well prep/production tree installation, coiled tubing cleanout and flowback. 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: