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Home My WebLink About225-079 T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3T-622 Permit: 225-079 DATE: 12/08/2025 Transmitted: 3T-622 Mudlog Data Via SFTP 225-079 T41194 TTransmittal instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-622 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.12.16 08:34:23 -09'00' Originated: Delivered to:TRANSMITTAL DATE2-Nov-25Alaska Oil & Gas Conservation CommissionTRANSMITTAL #02Nov25-AP01ATTN: Gavin Gluyas !"# $%&'() $%&'(+,-!.WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS e-TRANS DATE/ CD3T-622 50-103-20923-00-00 225-079 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 4-Oct-25 1Path .PDF-Qty .LAS-Qty .DLIS-Qty .PPT-Qty .TXT-Qty.CSV -QtyData from M/LWD Tools1NA NA NANANA/0 10 1*23/*"*0(01*4*)(5/ 10*)(5/& 5*2*)(5/' /*"*06 11 + ! 36 *03!4 (01*45/ + & & ! 5/& + & & ! 5/' + & & 6 *03!4 !1*) 6 11 + ! 36 *03!4 (01*45/ & ! 5/& & ! 5/' , 6 *03!4 103 5*23/*"*0!1*) 5/' *0 4474 5/' , *0 4474 5/' , *0 811/!!0-) 44745/10*-*Anchorage, Alaska 99501-3539Data DescriptionEOW Letter9 )!*!1!*/ *11*"7!*: Transmittal Receipt;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;; <;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;;6 *!) *"! /!Please return via courier or sign/scan and email a copy to Schlumberger.! !!=:1>)5? 4* ( !:)*!1*0:*"! -* ):!!0!2!"$>.#10#%!:> *4!4:-0!2!"!> *-*4)!)4*!4!>:0*-*-/:!43 ! 4080 *:)!8 )!8!> *-*4- :: @!1*811!*:0*A5?(6 *!225-079T41046Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.11.05 08:09:07 -09'00' SAMPLE TRANSMITTAL TO: AOGCC 333 WEST 7T" SUITE 100 ANCH. AK. 99501 279-1433 OPERATOR: CPAI SAMPLE TYPE: Dry Cuttings SAMPLES SENT: 3T-622 9619 - 24255 4 Boxes SENT BY: M. McCRACKEN I q q � DATE: 11 /10/2025 AIR BILL: N/A CPAI: CPA12025111001 CHARGE CODE: N/A NAME: 3T-622 NUMBER OF BOXES: 4 Boxes UPON RECEIPT OF THESE SAMPLES, PLEASE NOTE ANY DISCREPANCIES AND RETURN A SIGNED COPY OF THIS FORM TO: CONOCOPHILLIPS, ALASKA 700 G ST ATO-380 ANCHORAGE, AK. 99510 ATTN: MIKE McCRACKEN Mike.mccracken@conocophillips.com RECEIVED:_ zI �v 1. 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): 24,255 1,749 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 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 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): TNT Packer: 9,267' MD / 4,926' TVD ZXP: 9,435' MD / 4,970' TVD Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528 / ADL393884 / ADL390434 225-079 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20923-00-00 ConocoPhillips Alaska, Inc. Length Size Proposed Pools: L-80 TVD Burst 9,451' 10,860 MD 6,890 5,210 119 2,455 4,712 119 2,692 8,620 4-1/2" 4,991 20" 10-3/4" 80 7-5/8"8,582 2,653 907-265-6558 Senior Completions Engineer KRU 3T-622 4,991 24,254 4,991 None 995 4-1/2" Allen.Eschete@ConocoPhillips.com 10/23/2025 24,254 Halliburton TNT Prod Packer Baker ZXP, No SSSV 9,615 Perforation Depth MD (ft): 5,0157-5/8" 14,819 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 3:04 pm, Oct 10, 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: 2025.10.10 13:55:31-08'00' Foxit PDF Editor Version: 13.1.6 Allen Eschete 325-622 10-404 J.Lau 10/14/25 TS 10/15/25 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test tubing PRV, IA PRV, and pump trips to the set pressures detailed in the section 7 table. DSR-10/15/25 CDW 10/14/2025 10/23/2025 10/16/2025 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-622 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 09/15/2025 shows that the job was pumped with 401 barrels of 11.0 ppg lead cement and 60.3 barrels 15.8 ppg tail cement. This was displaced with 225 bbl 9.8 ppg spud mud. The plug bumped and the floats held. The 7-5/8 casing cement report on 09/22/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 143 barrels of 14.0 ppg lead cement, followed with 67.8 barrels of 15.3 ppg tail cement. This was displaced with 431.5 barrels of 9.0 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 @ 4,485 MD (3,240 TVD). The 4-1/2 liner cement report on 10/07/2025 shows the 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. 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 09/16/2025 the 10-3/4 casing was pressure tested to 3,000 psi for 30 minutes On 09/22/2025 the 7-5/8 casing was pressure tested to 4,000 psi for 30 minutes. On 10/09/2025 the 4-1/2 tubing was pressure tested to 4,200 psi for 30 minutes. On 10/09/2025 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 200 ft TVD over the course of the lateral section of well 3T-622, from where it intersects the top formation at 9,574 MD (-4,954 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 850 TVD along the 3T-622 trajectory. The top of the Torok confining interval in the well starts at 7,041 MD (-4,098 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 -5,120 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: 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. Source: Laserfiche WebLink 224-138 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 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-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 (AOGCCs approval on 09/03/2025). Source: 225-079 - Laserfiche WebLink 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. 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-622 wellbore trajectory. These faults are all estimated to strike NE-SW and are shown in Plat 1. Three faults intersect the 3T-622 well trajectory at 12,515 MD (Fault 1) and 15,175 MD (Fault 2) and 20,802 MD (Fault 3), respectively, while the fourth fault is past the toe of the well and is not intersected. Faults 1,2, and 3 are interpreted to be upthrown on the northern side, between 20-30 ft. The fourth fault in the ½ mile radius area surrounding the 3T-622 is also upthrown to the North. Throw on the fault uncertain as it has not been penetrated by any offset wells but is estimated to be between 40 to 70. All faults in the ½ mi area of the 3T- 622 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. Fault #1 & #4 (past the toe) have 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 faults mapped orientation) the presence of the faults will not interfere with containment. Fault 2 and Fault 3 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. 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-622 was completed in October 2025 as a horizontal producer in the Torok formation. The well is completed with a 4.5 tubing upper completion and a cemented 4.5 liner with 25 dart activated sliding sleeve and 3 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 2,278 MD / 2,153 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 29 by following attached pump schedule at ~37 bpm with a maximum expected treating pressure of ~7,050 psi. 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: 1 Starns, Ted C (OGC) From:Eschete, Allen <Allen.Eschete@conocophillips.com> Sent:Wednesday, October 15, 2025 11:53 AM To:Starns, Ted C (OGC) Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Lau, Jack J (OGC); Wallace, Chris D (OGC) Subject:RE: [EXTERNAL]KRU 3T-622 frac sundry (Sundry 325-622, PTD 225-079) Ted, Thank you for working on this so quickly! I spoke with our land group and con rmed that Colville Delta 3 is within ½ mile 3T-622. Colville Delta 3 is currently P&Ad and not in line with our fracture geometry so we dont have any concerns with isolation between the 2 wells. I have updated the AOR spreadsheet to show this. Thanks, Allen Eschete Office: (907) 265-6558 Cell: (907) 519-2976 From: Starns, Ted C (OGC) <ted.starns@alaska.gov> Sent: Tuesday, October 14, 2025 3:24 PM To: Eschete, Allen <Allen.Eschete@conocophillips.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL]KRU 3T-622 frac sundry (Sundry 325-622, PTD 225-079) 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. Good afternoon Allen, Im reviewing sundry 325-622 for the 3T-622 stimulation. In the process of my AOR, I noticed that Colville Delta 3 appears to be ~300 NE of the 3T-622 well bore trajectory in the horizontal portion of the 3T-622. Can you please con rm that the Colville Delta 3 is not located within the ½ mile radius of the 3T-622 and thus not included in Section 10 of the sundry application? If it is within ½ mile of the 3T-622 wellbore, can you please con rm adequate isolation of the Moraine? 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. 2 Im using the Moraine Frac AOR Spreadsheet that CPAI has kindly placed in the SharePoint. You could update the information there if necessary. Thanks for your attention to this, we are trying to get this turned around quickly for you. Ted Ted Starns Petroleum Geologist AOGCC 907-793-1225 (o ce) 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-622 Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-079 Surface Location: 1733' FSL, 279' FWL, NWSW S1 T12N R7E Bottomhole Location: 2894' FSL, 1364' FWL, NENW S21 T13N R7E 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 20th day of August 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.20 17:58:49 -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: 24,738 TVD: 5038 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 9/12/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2370' to ADL355037 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-467488 y- 6003461 Zone- 4 12 to Same Pool: 1218' to 3T-616 16. Deviated wells: Kickoff depth: 400 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 2589 39 39 2628 2418 9.875" 7.625" 29.7 L80 Hyd563 8920 39 39 8959 4876 9.875" 7.625" 33.7 P110-S Hyd563 800 8959 4876 9759 5056 6.5" 4.5" 12.6 P110-S Hyd563 15129 9609 5008 24738 5038 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 1733' FSL, 279' FWL, NWSW S1 T12N R7E ADL025528 / ADL393884 / ADL390434 (including stage data) 44440' FSL, 4018' FWL, SENE S3 T12N R7E LONS 01-013 2894' FSL, 1364' FWL, NENW S21 T13N R7E 2560 / 5645 / 2556 GL / BF Elevation above MSL (ft): 2253 1749 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-622 1250sks 11ppg, 280sks 15.8ppg 560sks 14ppg, 280sks 15.3ppg Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks 1800sks 15.3ppg 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 4:16 pm, Jul 17, 2025 VTL 8/20/2025 X T.Starns 8/20/25 225-079 50-103-20923-00-00 Diverter variance granted per 20 ACC 25.035 (h)(2) DSR-7/18/25 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. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.20 17:59:06 -08'00'08/20/25 08/20/25 RBDMS JSB 082525 <ZhϯdͲϲϮϮ 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 July 16, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-622 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Moraine Producer well from the 3T drilling pad. The intended spud date for this well is 9/12/2025. It is intended that Doyon 142 be used to drill the well. 3T-622 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 Producer 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-622. 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-622 Well File / Jenna Taylor ATO 1560 Will Earhart ATO 1552 Matt Smith Chris Brillon ATO 1548 Drilling Engineer Jenny Doherty ATO 1410 incerely, M tt S ith 3T-622 PTD Page 1 of 10 3T-622 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 ................................................................................................................................................ 6 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 ..................................................................................................................... 11 3T-622 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-622 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1,733 FSL, 279 FWL, NWSW S1 T12N R7E, UM NAD 1927 Northings: 6003461 Eastings:467488 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 44440‘ FSL, 4018‘ FWL, SENE S3 T12N R7E, UM NAD 1927 Northings: 6006200 Eastings: 460678 Measured Depth, RKB: 9,759 Total Vertical Depth, RKB:5,056 Total Vertical Depth, SS:5,005 Total Depth (Toe) 2894‘ FSL, 1364‘ FWL, NENW S21 T13N R7E, UM NAD 1927 Northings: 6020516 Eastings: 456490 Measured Depth, RKB:24,737 Total Vertical Depth, RKB:5,038 Total Vertical Depth, SS:4,987 Pad Layout 3T-622 PTD Page 3 of 10 Well Plat 3T-622 PTD Page 4 of 10 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 142 onto 3T-622 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 FIT/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. 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 FIT/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 24,737 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-622 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-622. 3T-622 has a MASP of 1,749 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-612, 3T-731 and 3T-730’s surface shoes within 500’ of the 3T-622. Based on previous assessments by AOGCC on 3T-612; and 3T-730, 3T-731, & 3T-612 SCP within 500' of planned 3T-622, recommend approving diverter variance. - T. Starns 8.15.25 A diverter waiver is requested 3T-622 PTD Page 6 of 10 6. MASP Calculations Requirements of 20 AAC 25.005(c)(4) (A) maximum downhole pressure and maximum potential surface pressure; 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 2,628 2,418 8.6 2,261 56 56 839 INTRM 9 7/8 10 3/4 2,628 2,418 13.0 8.6 1,081 9,759 5,056 8.6 2,261 1,456 1,456 1,755 PROD 6 1/2 7 5/8 9,759 5,056 13.0 8.6 2,261 24,737 5,038 8.6 2,261 1,749 2,912 1,749 (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 3T-622 PTD Page 7 of 10 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 10 3/4” Surface Casing run to 2,628 ’ MD / 2,418 ’ TVD Cement 2,628 MD to 2,128 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 2,128' to surface with 11 ppg Arctic Lite Crete. Assume 250% excess annular volume in permafrost and 50% excess below the permafrost (1,649 ’ MD), zero excess in 20” conductor. !"# !$%#&' ##( )*+,-#./ !0 !#" !$%1' #&.1( )*+,-#.#2 !0 7 5/8” Intermediate Casing run to 9759’ MD / 5,056 ’ 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 50% excess annular volume. 1"1 !$%&"' #3( )*+,-#.&" !0&'4/2015 !3! !$%1' #&.!( )*+,-#.& !0&'4/2015 4 1/2” Production Liner run from 9,759 MD / 5,056 ’ TVD to 24,737 MD / 5,038 TVD Cement the liner from TD to the liner top using a 15.3 ppg Class G + Add's cement. Assume 30% excess annular volume in the open hole, and 0% excess in the 7 5/8” intermediate casing. !& !$%# 1'' #&.!( )*+,-#.!# !0!'4"#05 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: 3T-622 PTD Page 8 of 10 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: 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 3T-622 PTD Page 9 of 10 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. 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. 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. 3T-622 PTD Page 10 of 10 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-622 PTD Page 11 of 10 16. Proposed Completion Schematic 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 17000 17000 24739 3T-622 wp10 Plan Summary 0 4 Dogleg Severity0 4000 8000 12000 16000 20000 24000 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] 391002003004004995996987973T-619 wp07.2 39111211 311411 510 610 710 81291310151117 121913213T-6212026 3T-731 39100200300400500600699798 898 998 1097 11973T-620 wp05 v5 3910020030040050160170180290310041105120713081410 15121612 171418161918 3T-623 wp05 v5 39100200300400501601702803 9051006110812091311141215131613171518163T-624 wp05 v5 39100200300400501601 3T-625 wp07.1 0 3000 True Vertical Depth0 3000 6000 9000 12000 15000 18000 Vertical Section at 326.93° 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 DDI 7.382 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.00 800.00 3T-622 wp10 (3T-622) r.5 SDI_URSA1 800.00 2620.00 3T-622 wp10 (3T-622) MWD+IFR2+SAG+MS 2620.00 9750.00 3T-622 wp10 (3T-622) MWD+IFR2+SAG+MS 9750.00 24738.79 3T-622 wp10 (3T-622) MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 2418.00 2628.27 10-3/4" Surface Casing 5055.87 9759.00 7-5/8" Intermediate Casing 5038.07 24737.79 4-1/2" Production Liner Mag Model & Date: BGGM2025 10-Oct-25 Magnetic North is 13.53° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.59° 57151.50nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.002 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 600.00 2.00 294.00 599.96 1.42 -3.19 1.00 294.00 2.93 Start Build 2.254 1512.64 22.53 294.00 1487.00 79.87 -179.39 2.25 0.00 164.82 Start 108.27 hold at 1512.64 MD 5 1620.91 22.53 294.00 1587.00 96.75 -217.29 0.00 0.00 199.64 Start Build 2.256 2675.55 46.26 294.00 2451.00 337.36 -757.72 2.25 0.00 696.17 Start 20.00 hold at 2675.55 MD7 2695.55 46.26 294.00 2464.83 343.24 -770.93 0.00 0.00 708.30 Start DLS 3.00 TFO -10.00 8 3465.55 69.10 289.82 2873.89 581.56 -1371.58 3.00 -10.00 1235.77 Start 5470.00 hold at 3465.55 MD9 8935.55 69.10 289.82 4825.25 2314.04 -6179.03 0.00 0.00 5310.87 Start DLS 3.00 TFO 70.651010445.83 88.24 331.97 5134.15 3269.79 -7254.05 3.00 70.65 6698.39 Start 484.49 hold at 10445.83 MD11 10930.32 88.24 331.97 5149.06 3697.23 -7481.63 0.00 0.00 7180.77 Start DLS 2.00 TFO 126.5112 11118.54 86.00 335.00 5158.52 3865.41 -7565.54 2.00 126.51 7367.49 Start Build 2.00 13 11318.54 90.00 335.00 5165.50 4046.52 -7650.00 2.00 0.00 7565.35 Start DLS 2.00 TFO 75.0314 11441.02 90.63 337.37 5164.82 4158.56 -7699.45 2.00 75.03 7686.22 Start 739.17 hold at 11441.02 MD15 12180.19 90.63 337.37 5156.67 4840.76 -7983.90 0.00 0.00 8413.12 Start DLS 2.00 TFO 84.6116 12312.43 90.88 340.00 5154.92 4963.94 -8031.96 2.00 84.61 8542.57 3T Hayes T02 040725 Start DLS 2.00 TFO 89.481712645.53 90.93 346.66 5149.64 5282.82 -8127.44 2.00 89.48 8861.89 Start 934.18 hold at 12645.53 MD 1813579.71 90.93 346.66 5134.40 6191.68 -8342.91 0.00 0.00 9741.09 Start DLS 1.00 TFO -101.6419 13616.72 90.86 346.30 5133.82 6227.66 -8351.56 1.00 -101.64 9775.97 3T Hayes T03 040725 Start DLS 1.00 TFO -98.3120 13665.07 90.79 345.82 5133.12 6274.58 -8363.21 1.00 -98.31 9821.65 Start 1988.31 hold at 13665.07 MD 21 15653.38 90.79 345.82 5105.71 8202.14 -8850.18 0.00 0.00 11702.67 Start DLS 1.00 TFO -27.282215653.94 90.79 345.82 5105.70 8202.68 -8850.32 1.00 -27.2811703.20 3T Hayes T04 040725 Start DLS 1.00 TFO -27.28 2315654.83 90.80 345.82 5105.69 8203.55 -8850.54 1.00 34.7111704.04 Start DLS 1.00 TFO 34.712416983.77 90.80 345.82 5087.08 9491.89 -9175.97 0.00 0.0012961.25 Start DLS 1.00 TFO -179.302517009.01 90.55 345.82 5086.78 9516.36 -9182.15 1.00 -179.30 12985.13 3T Hayes T05 040725 Start DLS 1.00 TFO -179.62 26 17033.25 90.31 345.82 5086.60 9539.86 -9188.08 1.00 -179.62 13008.06 Start 1114.37 hold at 17033.25 MD27 18147.62 90.31 345.82 5080.62 10620.26 -9461.08 0.00 0.00 14062.40 Start DLS 1.50 TFO -174.542818168.22 90.00 345.79 5080.56 10640.23 -9466.13 1.50 -174.5414081.89 3T Hayes T06 040725 Start DLS 1.50 TFO -178.882918315.05 87.80 345.75 5083.38 10782.52 -9502.22 1.50 -178.8814220.82 Start 331.26 hold at 18315.05 MD3018646.31 87.80 345.75 5096.11 11103.35 -9583.72 0.00 0.0014534.15 Start DLS 1.50 TFO 0.87 31 18793.13 90.00 345.78 5098.93 11245.62 -9619.81 1.50 0.8714673.07 3T Hayes T07 040725 Start DLS 1.50 TFO 1.853218934.41 92.12 345.85 5096.32 11382.56 -9654.43 1.50 1.8514806.71 Start 1144.63 hold at 18934.41 MD33 20079.04 92.12 345.85 5054.01 12491.69 -9934.09 0.00 0.0015888.77 Start DLS 1.00 TFO -178.8634 20150.86 91.40 345.83 5051.81 12561.30 -9951.65 1.00 -178.8615956.68 3T Hayes T08 040725 Start DLS 1.00 TFO -179.1035 20234.13 90.57 345.82 5050.38 12642.03 -9972.03 1.00 -179.1016035.46 Start 612.20 hold at 20234.13 MD 36 20846.33 90.57 345.82 5044.32 13235.55 -10121.99 0.00 0.0016614.65 Start DLS 1.00 TFO 178.7837 20903.08 90.00 345.83 5044.04 13290.57 -10135.88 1.00 178.78 16668.34 3T Hayes T09 040725 Start DLS 1.00 TFO 178.1838 20949.22 89.54 345.85 5044.23 13335.30 -10147.17 1.00 178.18 16711.99 Start 527.84 hold at 20949.22 MD 39 21477.06 89.54 345.85 5048.47 13847.11 -10276.22 0.00 0.0017211.30 Start DLS 1.00 TFO -4.6740 21523.33 90.00 345.81 5048.66 13891.96 -10287.55 1.00 -4.6717255.07 3T Hayes T10 040725 Start DLS 1.00 TFO -1.13 41 21712.25 91.89 345.77 5045.55 14075.07 -10333.91 1.00 -1.1317433.82 Start 369.76 hold at 21712.25 MD4222082.01 91.89 345.77 5033.36 14433.30 -10424.74 0.00 0.0017783.57 Start DLS 1.00 TFO 179.29 43 22140.90 91.30 345.78 5031.72 14490.36 -10439.20 1.00 179.29 17839.28 3T Hayes T11 040725 Start DLS 1.00 TFO 175.23 44 22179.25 90.92 345.81 5030.98 14527.53 -10448.61 1.00 175.23 17875.56 Start 953.82 hold at 22179.25 MD45 23133.07 90.92 345.81 5015.70 15452.13 -10682.37 0.00 0.0018777.94 Start DLS 1.00 TFO 176.38 46 23225.03 90.00 345.87 5014.96 15541.30 -10704.86 1.00 176.38 18864.94 3T Hayes T12 040725 Start DLS 1.00 TFO 176.8147 23345.53 88.80 345.94 5016.23 15658.16 -10734.21 1.00 176.81 18978.88 Start 125.61 hold at 23345.53 MD 48 23471.14 88.80 345.94 5018.86 15779.98 -10764.72 0.00 0.0019097.61 Start DLS 1.00 TFO -20.77 49 23492.86 89.00 345.86 5019.28 15801.05 -10770.01 1.00 -20.7719118.15 3T Hayes T13 042425 Start DLS 1.00 TFO -19.7150 23507.28 89.14 345.81 5019.51 15815.02 -10773.54 1.00 -19.7119131.79 Start 1231.51 hold at 23507.28 MD 51 24738.79 89.14 345.81 5038.09 17008.83 -11075.37 0.00 0.00 20296.90 3T Hayes T14 042425 TD at 24738.79 FORMATION TOP DETAILS TVDPath Formation 1376.00 Ugnu C 1613.00 Base Perm 1629.00 Ugnu B 1742.00 Ugnu A 2027.00 West Sak 2369.00 West Sak Base 2585.00 C-80 2675.00 C-50 3910.00 C-35 4056.00 Coyote 4219.00 Coyote Base 5050.00 Moraine 5139.00 Lower Moraine 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 17500 20000Vertical Section at 326.93°10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner10002000300040005000600070008000900010000110001200 0 13 000 1 4000 1 500 0 1 600 0 1 7000 18 000 1 9 00 0 2000 0 2100022000 23 000 24000247390°30°60°69°88°90°9 1° 91 ° 91 ° 91 ° 90°88°9 2 ° 9 1°90°9 2 ° 91 °89°3T-622 wp10Ugnu CBase PermUgnu BUgnu AWest SakWest Sak BaseC-80C-50C-35CoyoteCoyote BaseMoraineLower Moraine3T-622 wp107:05, July 17 2025Section View 035007000105001400017500South(-)/North(+)-17500 -14000 -10500 -7000 -3500 0 3500 7000West(-)/East(+)10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner50010001500200025003000350040004500500050383T-622 wp103T-622 wp10While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.7:07, July 17 20253ODQ9LHZ 0.000.751.502.253.003.754.505.256.006.757.50Separation Factor-1500 0 1500 3000 4500 6000 7500 9000 10500 12000 13500 15000 16500 18000 19500 21000 22500 24000 25500Measured Depth (3000 usft/in)Colville Delta 3Nuna 13T-6133T-6163T-616PB13T-619 wp07.23T-6213T-614 wp10.13T-624 wp05 v53T-625 wp07.1STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3T PadWell: Plan: 3T-622 Hayes (P)Wellbore: 3T-622Design: 3T-622 wp10 0 35 Centre to Centre Separation0 500 1000 1500 2000 2500 Partial Measured Depth3T-619 wp07.23T-6213T-7313T-622 wp10 Ladder View 0 150 300 Centre to Centre Separation0 4000 8000 12000 16000 20000 24000 Measured DepthNDST-02NDST-02PB13T-6123T-6133T-6163T-616PB13T-616PB23T-6173T-617 wp103T-619 wp07.23T-6213T-7303T-731Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 39.00 800.00 3T-622 wp10 (3T-622) r.5 SDI_URSA1 800.00 2620.00 3T-622 wp10 (3T-622) MWD+IFR2+SAG+MS 2620.00 9750.00 3T-622 wp10 (3T-622) MWD+IFR2+SAG+MS 9750.00 24738.79 3T-622 wp10 (3T-622) MWD+IFR2+SAG+MS 7:18, July 17 2025 CASING DETAILS TVD MD Name 2418.00 2628.27 10-3/4" Surface Casing 5055.87 9759.007-5/8" Intermediate Casing 5038.07 24737.79 4-1/2" Production Liner 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 17000 17000 24739 3T-622 wp10 TC View 30 30 60 60 90 90 120 120 150 150 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 1010 1104 1191 1274 1349 NDST-02 1010 1104 1191 1274 1349 39100200300400499599698797896 995 1094 1192 1291 1390 1488 1586 1685 3T-619 wp07.2 39111211311411 510 610 710 81291310151117 121913211423 1524 1624 1725 1827 1928 2030 3T-621 39100200300400501603707811 914 1018 1122 1225 1328 1431 1532 1630 1732 1835 1938 2041 2145 2248 2349 2447 2540 2629 2714 2792 3T-730 811914 1018 1121 1225 1328 1431 1533 1632 1734 1834 1932 2026 2113 2194 3T-731 39100200300400500600699798898 998 1097 1197 1297 1397 1497 1596 1696 1796 1895 1995 3T-620 wp05 v5 3910020030040050160170180290310041105120713081410 15121612 171418161918202121232226232924332536264027442851 29573065317232803388349535943693 3T-623 wp05 v5 39100200300400501601702803 905100611081209131114121513161317151816191720182120222123232424252626282730 2834 2937 3041 3145 3248 3351 3T-624 wp05 v5 39100200300400501601703804 9061008111112131316141815211621172418271931203421382242 3T-625 wp07.1 39100200300400501602704 8069081011111412161320142315261626 3T-626 wp05 v5 39100200300400501602 703 804 903 1000 3T-627 wp05 v5 39100200300400 5016027058089111014 1116 1219 1322 3T-628 wp06 39100200300400502603706809912 1014 1117 1219 3T-629 wp05 v5 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: From To Tool 39.00 800.00 r.5 SDI_URSA1 800.00 2620.00 MWD+IFR2+SAG+MS 2620.00 9750.00 MWD+IFR2+SAG+MS 9750.00 24738.79 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name2418.00 2628.27 10-3/4" Surface Casing5055.87 9759.00 7-5/8" Intermediate Casing5038.07 24737.79 4-1/2" Production Liner 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 2 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.003 600.00 2.00 294.00 599.96 1.42 -3.19 1.00 294.00 2.93 Start Build 2.254 1512.64 22.53 294.00 1487.00 79.87 -179.39 2.25 0.00 164.82 Start 108.27 hold at 1512.64 MD5 1620.91 22.53 294.00 1587.00 96.75 -217.29 0.00 0.00 199.64 Start Build 2.256 2675.55 46.26 294.00 2451.00 337.36 -757.72 2.25 0.00 696.17 Start 20.00 hold at 2675.55 MD7 2695.55 46.26 294.00 2464.83 343.24 -770.93 0.00 0.00 708.30 Start DLS 3.00 TFO -10.008 3465.55 69.10 289.82 2873.89 581.56 -1371.58 3.00 -10.00 1235.77 Start 5470.00 hold at 3465.55 MD 9 8935.55 69.10 289.82 4825.25 2314.04 -6179.03 0.00 0.00 5310.87 Start DLS 3.00 TFO 70.65 1010445.83 88.24 331.97 5134.15 3269.79 -7254.05 3.00 70.65 6698.39 Start 484.49 hold at 10445.83 MD 11 10930.32 88.24 331.97 5149.06 3697.23 -7481.63 0.00 0.00 7180.77 Start DLS 2.00 TFO 126.51 12 11118.54 86.00 335.00 5158.52 3865.41 -7565.54 2.00 126.51 7367.49 Start Build 2.00 1311318.54 90.00 335.00 5165.50 4046.52 -7650.00 2.00 0.00 7565.35 Start DLS 2.00 TFO 75.03 1411441.02 90.63 337.37 5164.82 4158.56 -7699.45 2.00 75.03 7686.22 Start 739.17 hold at 11441.02 MD 1512180.19 90.63 337.37 5156.67 4840.76 -7983.90 0.00 0.00 8413.12 Start DLS 2.00 TFO 84.61 1612312.43 90.88 340.00 5154.92 4963.94 -8031.96 2.00 84.61 8542.57 3T Hayes T02 040725 Start DLS 2.00 TFO 89.48 1712645.53 90.93 346.66 5149.64 5282.82 -8127.44 2.00 89.48 8861.89 Start 934.18 hold at 12645.53 MD 1813579.71 90.93 346.66 5134.40 6191.68 -8342.91 0.00 0.00 9741.09 Start DLS 1.00 TFO -101.64 1913616.72 90.86 346.30 5133.82 6227.66 -8351.56 1.00 -101.64 9775.97 3T Hayes T03 040725 Start DLS 1.00 TFO -98.31 20 13665.07 90.79 345.82 5133.12 6274.58 -8363.21 1.00 -98.31 9821.65 Start 1988.31 hold at 13665.07 MD 21 15653.38 90.79 345.82 5105.71 8202.14 -8850.18 0.00 0.00 11702.67 Start DLS 1.00 TFO -27.28 2215653.94 90.79 345.82 5105.70 8202.68 -8850.32 1.00 -27.2811703.20 3T Hayes T04 040725 Start DLS 1.00 TFO -27.28 2315654.83 90.80 345.82 5105.69 8203.55 -8850.54 1.00 34.7111704.04 Start DLS 1.00 TFO 34.71 2416983.77 90.80 345.82 5087.08 9491.89 -9175.97 0.00 0.00 12961.25 Start DLS 1.00 TFO -179.30 2517009.01 90.55 345.82 5086.78 9516.36 -9182.15 1.00 -179.3012985.13 3T Hayes T05 040725 Start DLS 1.00 TFO -179.62 2617033.25 90.31 345.82 5086.60 9539.86 -9188.08 1.00 -179.6213008.06 Start 1114.37 hold at 17033.25 MD 2718147.62 90.31 345.82 5080.62 10620.26 -9461.08 0.00 0.00 14062.40 Start DLS 1.50 TFO -174.54 2818168.22 90.00 345.79 5080.56 10640.23 -9466.13 1.50 -174.5414081.89 3T Hayes T06 040725 Start DLS 1.50 TFO -178.88 2918315.05 87.80 345.75 5083.38 10782.52 -9502.22 1.50 -178.8814220.82 Start 331.26 hold at 18315.05 MD 3018646.31 87.80 345.75 5096.11 11103.35 -9583.72 0.00 0.00 14534.15 Start DLS 1.50 TFO 0.87 31 18793.13 90.00 345.78 5098.93 11245.62 -9619.81 1.50 0.87 14673.07 3T Hayes T07 040725 Start DLS 1.50 TFO 1.85 3218934.41 92.12 345.85 5096.32 11382.56 -9654.43 1.50 1.8514806.71 Start 1144.63 hold at 18934.41 MD 33 20079.04 92.12 345.85 5054.01 12491.69 -9934.09 0.00 0.00 15888.77 Start DLS 1.00 TFO -178.86 34 20150.86 91.40 345.83 5051.81 12561.30 -9951.65 1.00 -178.8615956.68 3T Hayes T08 040725 Start DLS 1.00 TFO -179.10 35 20234.13 90.57 345.82 5050.38 12642.03 -9972.03 1.00 -179.1016035.46 Start 612.20 hold at 20234.13 MD 36 20846.33 90.57 345.82 5044.32 13235.55 -10121.99 0.00 0.00 16614.65 Start DLS 1.00 TFO 178.78 37 20903.08 90.00 345.83 5044.04 13290.57 -10135.88 1.00 178.7816668.34 3T Hayes T09 040725 Start DLS 1.00 TFO 178.18 38 20949.22 89.54 345.85 5044.23 13335.30 -10147.17 1.00 178.1816711.99 Start 527.84 hold at 20949.22 MD 39 21477.06 89.54 345.85 5048.47 13847.11 -10276.22 0.00 0.00 17211.30 Start DLS 1.00 TFO -4.67 40 21523.33 90.00 345.81 5048.66 13891.96 -10287.55 1.00 -4.6717255.07 3T Hayes T10 040725 Start DLS 1.00 TFO -1.13 41 21712.25 91.89 345.77 5045.55 14075.07 -10333.91 1.00 -1.1317433.82 Start 369.76 hold at 21712.25 MD 4222082.01 91.89 345.77 5033.36 14433.30 -10424.74 0.00 0.00 17783.57 Start DLS 1.00 TFO 179.29 43 22140.90 91.30 345.78 5031.72 14490.36 -10439.20 1.00 179.2917839.28 3T Hayes T11 040725 Start DLS 1.00 TFO 175.23 44 22179.25 90.92 345.81 5030.98 14527.53 -10448.61 1.00 175.2317875.56 Start 953.82 hold at 22179.25 MD 45 23133.07 90.92 345.81 5015.70 15452.13 -10682.37 0.00 0.00 18777.94 Start DLS 1.00 TFO 176.38 46 23225.03 90.00 345.87 5014.96 15541.30 -10704.86 1.00 176.3818864.94 3T Hayes T12 040725 Start DLS 1.00 TFO 176.81 47 23345.53 88.80 345.94 5016.23 15658.16 -10734.21 1.00 176.81 18978.88 Start 125.61 hold at 23345.53 MD 48 23471.14 88.80 345.94 5018.86 15779.98 -10764.72 0.00 0.0019097.61 Start DLS 1.00 TFO -20.77 49 23492.86 89.00 345.86 5019.28 15801.05 -10770.01 1.00 -20.7719118.15 3T Hayes T13 042425 Start DLS 1.00 TFO -19.71 50 23507.28 89.14 345.81 5019.51 15815.02 -10773.54 1.00 -19.71 19131.79 Start 1231.51 hold at 23507.28 MD 51 24738.79 89.14 345.81 5038.09 17008.83 -11075.37 0.00 0.00 20296.90 3T Hayes T14 042425 TD at 24738.79 3T-622 wp10AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 800.00 r.5 SDI_URSA1800.00 2620.00 MWD+IFR2+SAG+MS2620.00 9750.00 MWD+IFR2+SAG+MS9750.00 24738.79 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2418.00 2628.27 10-3/4" Surface Casing5055.87 9759.00 7-5/8" Intermediate Casing5038.07 24737.79 4-1/2" Production Liner1515303045456060757590900901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [30 usft/in]39100200300400499599698797896995109411923T-619 wp07.239111211311411510610710812913101511171219132114231524162417253T-621254026293T-73018341932202621133T-73139100200300400500600699798898998109711971297139714973T-620 wp05 v5391002003004005016017018029031004110512071308141015121612171418161918202121232226232924333T-623 wp05 v53910020030040050160170280390510061108120913111412151316141715181619172018212022212323242425263T-624 wp05 v53910020030040050160170380490610081111121313163T-625 wp07.1391002003004005016027048063T-626 wp05 v5391002003004003T-627 wp05 v539 500500 800800 11001100 15001500 20002000 30003000 50005000 80008000 1200012000 1700017000 24739From Colour To MD39.00 To 2700.00MD Azi TFace39.00 0.00 0.00400.00 0.00 0.00600.00 294.00 294.001512.64 294.00 0.001620.91294.00 0.002675.55 294.00 0.002695.55 294.00 0.003465.55 289.82 -10.008935.55 289.82 0.0010445.83 331.97 70.6510930.32 331.97 0.0011118.54 335.00 126.5111318.54 335.00 0.0011441.02 337.37 75.0312180.19 337.37 0.0012312.43 340.00 84.6112645.53 346.66 89.4813579.71 346.66 0.0013616.72 346.30 -101.6413665.07 345.82 -98.3115653.38 345.82 0.0015653.94 345.82 -27.2815654.83 345.82 34.7116983.77 345.82 0.0017009.01 345.82 -179.3017033.25 345.82 -179.6218147.62 345.82 0.0018168.22 345.79 -174.5418315.05 345.75 -178.8818646.31 345.75 0.0018793.13 345.78 0.8718934.41 345.85 1.8520079.04 345.85 0.0020150.86 345.83 -178.8620234.13 345.82 -179.1020846.33 345.82 0.0020903.08 345.83 178.7820949.22 345.85 178.1821477.06 345.85 0.0021523.33 345.81 -4.6721712.25 345.77 -1.1322082.01 345.77 0.0022140.90 345.78 179.2922179.25345.81 175.2323133.07 345.81 0.0023225.03 345.87 176.3823345.53 345.94 176.8123471.14 345.94 0.0023492.86 345.86 -20.7723507.28 345.81 -19.7124738.79 345.81 0.00 3T-622 wp10AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 800.00 r.5 SDI_URSA1800.00 2620.00 MWD+IFR2+SAG+MS2620.00 9750.00 MWD+IFR2+SAG+MS9750.00 24738.79 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2418.00 2628.27 10-3/4" Surface Casing5055.87 9759.00 7-5/8" Intermediate Casing5038.07 24737.79 4-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]262927142792286229263T-7309251931393809452952896103T-614 wp10.126993T-620 wp05 v526402744285129573065317232803388349535943693379238913990408841874286438444833T-623 wp05 v52628273028342937304131453248335134533553365137493846394340403T-624 wp05 v526602767287829893101321433273440354436433T-625 wp07.139 500500 800800 11001100 15001500 20002000 30003000 50005000 80008000 1200012000 1700017000 24739From Colour To MD2600.00 To 9800.00MD Azi TFace39.00 0.00 0.00400.00 0.00 0.00600.00 294.00 294.001512.64 294.00 0.001620.91294.00 0.002675.55 294.00 0.002695.55 294.00 0.003465.55 289.82 -10.008935.55 289.82 0.0010445.83 331.97 70.6510930.32 331.97 0.0011118.54 335.00 126.5111318.54 335.00 0.0011441.02 337.37 75.0312180.19 337.37 0.0012312.43 340.00 84.6112645.53 346.66 89.4813579.71 346.66 0.0013616.72 346.30 -101.6413665.07 345.82 -98.3115653.38 345.82 0.0015653.94 345.82 -27.2815654.83 345.82 34.7116983.77 345.82 0.0017009.01 345.82 -179.3017033.25 345.82 -179.6218147.62 345.82 0.0018168.22 345.79 -174.5418315.05 345.75 -178.8818646.31 345.75 0.0018793.13 345.78 0.8718934.41 345.85 1.8520079.04 345.85 0.0020150.86 345.83 -178.8620234.13 345.82 -179.1020846.33 345.82 0.0020903.08 345.83 178.7820949.22 345.85 178.1821477.06 345.85 0.0021523.33 345.81 -4.6721712.25 345.77 -1.1322082.01 345.77 0.0022140.90 345.78 179.2922179.25345.81 175.2323133.07 345.81 0.0023225.03 345.87 176.3823345.53 345.94 176.8123471.14 345.94 0.0023492.86 345.86 -20.7723507.28 345.81 -19.7124738.79 345.81 0.00 3T-622 wp10AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 800.00 r.5 SDI_URSA1800.00 2620.00 MWD+IFR2+SAG+MS2620.00 9750.00 MWD+IFR2+SAG+MS9750.00 24738.79 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2418.00 2628.27 10-3/4" Surface Casing5055.87 9759.00 7-5/8" Intermediate Casing5038.07 24737.79 4-1/2" Production Liner65651301301951952602603253253903900901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [130 usft/in]134811347813474Colville Delta 3979298933T-614 wp10.111621115411145811372112821118411100110211094410859107693T-615 wp09.139 500500 800800 11001100 15001500 20002000 30003000 50005000 80008000 1200012000 1700017000 24739From Colour To MD9700.00 To 24740.00MD Azi TFace39.00 0.00 0.00400.00 0.00 0.00600.00 294.00 294.001512.64 294.00 0.001620.91294.00 0.002675.55 294.00 0.002695.55 294.00 0.003465.55 289.82 -10.008935.55 289.82 0.0010445.83 331.97 70.6510930.32 331.97 0.0011118.54 335.00 126.5111318.54 335.00 0.0011441.02 337.37 75.0312180.19 337.37 0.0012312.43 340.00 84.6112645.53 346.66 89.4813579.71 346.66 0.0013616.72 346.30 -101.6413665.07 345.82 -98.3115653.38 345.82 0.0015653.94 345.82 -27.2815654.83 345.82 34.7116983.77 345.82 0.0017009.01 345.82 -179.3017033.25 345.82 -179.6218147.62 345.82 0.0018168.22 345.79 -174.5418315.05 345.75 -178.8818646.31 345.75 0.0018793.13 345.78 0.8718934.41 345.85 1.8520079.04 345.85 0.0020150.86 345.83 -178.8620234.13 345.82 -179.1020846.33 345.82 0.0020903.08 345.83 178.7820949.22 345.85 178.1821477.06 345.85 0.0021523.33 345.81 -4.6721712.25 345.77 -1.1322082.01 345.77 0.0022140.90 345.78 179.2922179.25345.81 175.2323133.07 345.81 0.0023225.03 345.87 176.3823345.53 345.94 176.8123471.14 345.94 0.0023492.86 345.86 -20.7723507.28 345.81 -19.7124738.79 345.81 0.00 3T-622 wp10Spider Plot8:13, July 17 202539.00 To 24738.79Northing (5000 usft/in)Easting (5000 usft/in)3537394143454749515355575961636567Colville Delta 3353739414345474951NDST-0235373941434547495153NDST-02PB1353739414345474951Nuna 135373941434547495153Nuna 1PB13537394143454749513T-6033537394143454749513T-6053537394143454749513T-6083537394143454749513T-6123537394143454749513T-6133537394 1 4 345 4749513T-6163537394 1 4 345 4749513T-616PB13537394 1 4 345 4749513T-616PB235373941434547493T-6173537394143454749513T-617 wp103537394143454749513T-619 wp07.2353739414345474951535 53T-621353739413T-730353739413T-7313 537394143454749513T-601 wp05 v53 53739414345474951533T-602 wp05 v53537394143454749513T-604 wp05 v53537394143454749513T-606 wp083537394143454749513T-607 wp053537394143454749513T-609 wp063537394143454749513T-610 wp053537394143454749513T-611 wp1035373941434 5 4 749 513T-614 wp10.135373 9414 3454749513T-615 wp09.135373 94 14 3454749513T-618 wp0735373941434 54 749513T-620 wp05 v535373941434 54 749513T-623 wp05 v53537394143454749513T-624 wp05 v53537394143454749513T-625 wp07.135373941434 5 4749513T-626 wp05 v53537394143454 749 513T-627 wp05 v53 5 3 7 3 9 4 1 43 4 5 47493T-628 wp0635373941434547493T-629 wp05 v53537394143454749513T-622 wp10 3T-622 wp10Spider Plot8:14, July 17 202539.00 To 24738.79Northing (1500 usft/in)Easting (1500 usft/in)3537394143454749515355575961636567Colville Delta 33537394143454749NDST-0235373941434547495153NDST-02PB1353739414345474951Nuna 135373941434547495153Nuna 1PB13537394143454749513T-60335373941433T-60535373941434547493T-6083537394143454749513T-61235373941434547493T-6133T-6163T-616PB13T-616PB235373941434547493T-6173537394143454749513T-617 wp103537394143454749513T-619 wp07.2353739414345474951535 53T-621353739413T-730353739413T-7313T-601 wp05 v53T-602 wp05 v5353T-604 wp05 v535373T-606 wp083537394143454749513T-607 wp053537394143454749513T-609 wp063537394143454749513T-610 wp053537394143454749513T-611 wp103T-614 wp10.135373 9 4 1 43454749513T-615 wp09.135373 9 4 1 43454749513T-618 wp0735373941434 5 4749513T-620 wp05 v535373941434 5 4749513T-623 wp05 v53537394143454749513T-624 wp05 v53537394143454749513T-625 wp07.135373941434 5 47493T-626 wp05 v53T-627 wp05 v53 5 3 7 3 9 4 1 4 3 4 5 47493T-628 wp0635373941434547493T-629 wp05 v53537394143454749513T-622 wp10 3T-622 wp10Spider Plot8:15, July 17 202539.00 To 24738.79Northing (500 usft/in)Easting (500 usft/in)1517192123NDST-021517192123NDST-02PB115171921232527293133Nuna 115171921232527293133Nuna 1PB115173T-6031517193T-605151719212325272931333T-6081517192123252729313335373T-61215171921232527293T-6131517192123253T-6161517192123253T-616PB11517192123253T-616PB21517192123252729313335373941433T-61715171921232527293133353739413T-617 wp101517192123252729313T-619 wp07.215171921232527293T-62115171921232 52 7 293133353739413T-73015171921232 5272931 33353739413T-7313T-601 wp05 v3T-602 wp05 v153T-604 wp05 v15173T-606 wp0815171921232527293T-607 wp05151719212325272931333T-609 wp061517192123252729313T-610 wp0515171921232527293133353T-611 wp101517192123253T-614 wp10.1151719212325273T-615 wp09.115171921232527293T-618 wp07151719212325272931333T-620 wp05 v5151719212325272931333T-623 wp05 v515171921232527293133353T-624 wp05 v515171921232527293133353T-625 wp07.11517192123252729313T-626 wp05 v51517192123253T-627 wp05 v515171921232527 2 9 3 1 3 33T-628 wp06151719212325272931333T-629 wp05 v5151719212325272931333537393T-622 wp10 3T-622 wp10Spider Plot8:17, July 17 202539.00 To 24738.79Northing (90 usft/in)Easting (90 usft/in)68101214NDST-0268101214NDST-02PB112141618Nuna 112141618Nuna 1PB118203T-612163T-6131416183T-6171416183T-617 wp1024681012141618203T-619 wp07.224 681012141618203T-6212468101214161820222 6 3T-7300246810121416182022303234363T-73114163T-615 wp09.1121416183T-618 wp0724681012141618203T-620 wp05 v52468101214161820223T-623 wp05 v52468101214161820223T-624 wp05 v52468101214161820223T-625 wp07.124681012141618203T-626 wp05 v5246810123T-627 wp05 v524681012141618203T-628 wp062468101214161820223T-629 wp05 v5246810121416182022243T-622 wp10 Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KRU 3T-622 225-079 KUPARUK RIVER TOROK OIL WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3T-622Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250790Field & Pool:KUPARUK RIVER, TOROK OIL - 490169NA1Permit fee attachedYesSurface Location lies within ADL025528; Top Productive Interval lies in ADL0392959; TD lies within ADL393884.2Lease number appropriateYes3Unique well name and numberYesKUPARUK RIVER, TOROK OIL - 490169 - governed by CO 725A4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes81'18Conductor string providedYesSurface casing set at 2628' MD19Surface casing protects all known USDWsYes183% excess20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYes27If diverter required, does it meet regulationsYesMax reservoir pressure is 2253 psig(8.6 ppg EMW); will drill w/ 8.6-10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1749 psig; initial BOP test to 5000 psig; subsuquent 4000 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYes33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)Yes35Permit can be issued w/o hydrogen sulfide measuresNoMoraine pore pressure anticipated to be 8.6ppg EMW. MPD will be utilized36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate8/13/2025ApprVTLDate8/4/2025ApprTCSDate8/13/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 8/20/2025