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224-118
T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA Jan 09, 2025 AOGCC Attention: Meredith Guhl 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject: Final Log Distribution for ConocoPhillips Alaska, Inc. KRU 1H-106/ KRU 1H-106L1 Kuparuk River API #: 50-029-23800-00-00/50-029-23800-60-00 Permit No: 224-117/224-118 Rig: Doyon 25 The final Coil deliverables were uploaded via https://copsftp.sharefile.com/ for the above well. Items delivered: Digital Las Data, Graphic Images CGM/PDF and Survey Files. Thank you. Signature of receiver & date received: Please return transmittal letter to: Hampton, Jerissa Jerissa.Hampton@conocophillips.com Luis G Arismendi Luis.arismendi@bakerhughes.com 224-117: T39942 224-118: T39943 KRU 1H-106L1 50-029-23800-60-00 224-118 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.09 08:10:34 -09'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV U WSAK 1H-106L1 JBR 01/30/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 21 day BOP test. Very good test. All involved seemed to be very knowleagable. Gas and PVts were tested. 4" and 5" were both tested and they had the floRr valves to cover them. Test Results TEST DATA Rig Rep:FrittsOperator:ConocoPhillips Alaska, Inc.Operator Rep:Reinhardt Rig Owner/Rig No.:Doyon 25 PTD#:2241180 DATE:12/20/2024 Type Operation:DRILL Annular: 250/3500Type Test:OTH Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopRCN241221145435 Inspector Bob Noble Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time MASP: 1562 Sundry No: 324-680 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 4 P Inside BOP 2 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8"P #1 Rams 1 2 7/8 x 5"P #2 Rams 1 Blind/ Shears P #3 Rams 1 2 7/8 x 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8"P Kill Line Valves 2 3 1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1800 200 PSI Attained P15 Full Pressure Attained P84 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6 @ 1933 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P16 #1 Rams P6 #2 Rams P5 #3 Rams P5 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 999999 9 9 9 9 6XQGU\LVIRUFKDQJHRIDSSURYHGSURJUDPGLUHFWLRQDOSODQDQG/ODWHUDONLFNRIIZLQGRZ 7HVWFKDUWVDWWDFKHG %23(7HVW'R\RQ .58+/ 37' $2*&&,QVS5SWERS5&1 1H-106 L1 12/20/2024 Tested to 250 PSI / 5 Min, 3500 PSI / 5 Min 5” Test Jt. 1. Annular Preventer, 5” DART, Valves: 1, 13, 14, 15, Kill Line demco 2. Upper Pipe Rams (2 7/8 x 5”), 5” TIW #1, HCR kill, Valves: 2, 10, 12 3. Valves: 6, 9, 11, Manual Kill, 5” TIW #2 4. Valves: 5, 7, 8, 4” DART 5. Valve: 3, 4” TIW #1 6. Lower (2 7/8”x 5”), 4” TIW #2 7. Blind Rams, Valve 4 4” Test Jt. 8. Super Choke & Manually Operated (8 = MANUAL Choke – 8A = Hydraulic Choke) 9. Annular, HCR choke, Upper IBOP 10.Upper pipe rams (2 7/8” x 5” VBR’S), Lower IBOP, manual choke 11.Lower pipe rams (2 7/8” x 5” VBR’S) %23(7HVW'R\RQ .58+/ 37' $2*&&,QVS5SWERS5&1 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 West Sak Oil Pool West Sak Oil Pool 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 21963 N/A Casing Collapse Structural Conductor Surface Intermediate Production Liner 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:Brad Gorham Contact Email: Contact Phone: 907-265-6487 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 N/A Brad.Gorham@conocophillips.com Drilling Engineer 4116 KRU 1H-106L1 21394 4121 N/A 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 Victoria Loepp 12/3/2024 Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025637, ADL025638, ADL025639 224-118 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-029-23800-60-00 ConocoPhillips Alaska, Inc. Length Size Proposed Pools: N/A N/A N/A TVD Burst N/A MD 120 1738' 3931' 120 1770' 4121'4-1/2" N/A N/A 42" 13-3/8" 80 9-5/8"10580' 1770' 21394' Perforation Depth MD (ft): 10580' N/A 12030 N/A 12/4/2024 N/A N/A m n P 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 'HF By Grace Christianson at 8:01 am, Dec 04, 2024 324-680 SFD 12/4/2024 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig Diverter variance not approved; diverter required. BOPE testing on a 21-day interval is approved with the attached conditions RAM configuration allowing three preventers for MPSP < 3000 psig is approved as outlined in 20 AAC 25.035.c.1.A for Int and production holes file w/ PTD 10-407 VTL 12/4/2024 X X 12/4/2024 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.06 10:14:52 -09'00'12/06/24 RBDMS JSB 121324 ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 December 4th, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry for 1H-106L1 Directional Plan and Window Depth Dear Sir or Madam: ConocoPhillips Alaska, Inc hereby applies for Application for Sundry Approval to provide a new directional plan as well as the change in the L1 window placement (PTD #: 224-118) an onshore West Sak dual-lateral producer. The 16” surface hole was TD’d and the 13-3/8” casing was set and cemented to surface. The 12-1/4” intermiedate section was drilled and landed in the West Sak B formation. A 9-5/8” casing string was run and cemented in place as per plan. The 6-3/4” mainbore lateral was then drilled to 21,693’ MD. After conducting a short trip and laying down the BHA, the 4-1/2” OHSAS mainbore liner was run. Ultimately the 1H-106 mainbore liner was unable to reach the planned set depth. Progress stopped at approximately 21,394’ MD, which is 569’ short of the target. Since this well is utilizing a Level 5 RAM junction, setting the mainbore liner hanger higher impacts the planned L1 window depth, now adjusted to 9,311’ MD, placing it within the Ugnu formation. To address this, we are seeking approval to run two swell packers alongside solid tubulars from the window down to the West Sak D sand, as detailed in the attached schematic. The shallowest swell packer will be set in an Ugnu shale for isolation, while the second will isolate the West Sak D sand from the West Sak Nb formation. This configuration, combined with the Level 5 junction, will ensure no crossflow occurs between the Ugnu and West Sak pools. Furthermore, this well is a producer so the risk of crossflow is low. It is important to note that the change is purely the L1 window depth and the directional plan that was adjusted accordingly. The operational steps are no different then what was outlined in the approved 1H-106L1 PTD. This request was approved via email by Victoria Loepp on 12/3/24 as per attached. 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 10-403 2. A proposed drilling program 3. Planned Wellbore Schematic 4. Original Wellbore Schematic 5. 1H-106L1wp07 Directional Plan 6. Approval email from Victoria Loepp 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: Brad Gorham, (907) 265-6487 / Brad.Gorham@conocophillips.com, Sincerely, cc: 1H-106 Well File / Jenna Taylor ATO 1560 David Lee ATO 1726 Chris Brillon ATO 1548 Brad Gorham Andy Mack Kuukpik Drilling Engineer 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 1 | 14 1H-106L1Well Plan Application for Permit to Drill Table of Contents 1. Well Name ............................................................................................................................................. 2 2. Location Summary ................................................................................................................................. 2 3. Proposed Drilling Program ..................................................................................................................... 5 4. Diverter and BOP Information ................................................................................................................ 5 5. MASP Calculations ................................................................................................................................. 6 6. Procedure for Conducting Formation Integrity Tests ............................................................................... 8 7. Casing and Cementing Program .............................................................................................................. 8 8. Drilling Fluid Program .......................................................................................................................... 10 9. Abnormally Pressured Formation Information ...................................................................................... 10 10. Seismic Analysis ................................................................................................................................... 11 11. Seabed Condition Analysis ................................................................................................................... 11 12. Evidence of Bonding ............................................................................................................................. 11 13. Discussion of Mud and Cuttings Disposal .............................................................................................. 11 14. Drilling Hazards Summary .................................................................................................................... 11 15. Proposed Completion Schematic .......................................................................................................... 13 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 2 | 14 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 1H-106L1 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 70 FNL, 762 FEL, S33 T12N R10E, UM NAD27 Northing: 5980632.86 Easting: 549579.90 RKB Elevation 39.61’ AMSL Pad Elevation 54’ AMSL Top of Productive Horizon (Heel) 4557 FSL 4461 FSL, 5197 FEL 51445 FEL, S26 T12N R10E, UM NAD27 Northing: 5985302.25 5985207.23 Easting: 555663.47 555715.70 Measured Depth, RKB: 9692‘ MD True Vertical Depth, RKB: 3721‘ TVD 3649’ MD True Vertical Depth, SS: 3628‘ TVDss 3555’ TVDss Total Depth (Toe) 4127 FSL 4332 FSL, 495 FEL 500 FEL, S14 T12N R10E, UM NAD27 Northing: 5995467.78 5995673.14 Easting: 560275.35 560268.35 Measured Depth, RKB: 21763‘ MD 21905’ MD True Vertical Depth, RKB: 4067‘ TVD 4059’ TVD True Vertical Depth, SS: 3973‘ TVDss 3965’ TVDss Please see attached well stick diagram for the current planned development of the pad. * Note that the application form states 21,963' MD SFD * 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 3 | 14 Pad Layout 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 4 | 14 Well Plat 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 5 | 14 3. Proposed Drilling Program NOTE: Previous operations are covered under the 1H-106 Application for Permit to Drill 1. PU 6-3/4'' bit, motor, GR/Res and magnets and drill ~200’ of new hole in the West Sak D in the Ugnu and West Sak Nb sand to establish separation from mainbore. POOH. 2. Pick up 6-3/4'' RSS lateral drilling assembly (LWD Program: GR/Azimuthal RES/Den/Neu) and TIH. 3. Drill and geo-steer West Sak D sand lateral to section TD per directional plan. 4. Circulate the hole clean and POOH to window. Circulate hole clean, POOH and LD same. 5. TIH with whipstock retrieval tool. Retrieve whipstock, POOH and LD same. 6. Run 4-1/2'' Open Hole Standalone Screens. PU Baker RAM L5 Junction and MWD for orientation. POOH with running tools and LD same. 7. Make up and run in hole to install LEM (lateral entry module) with SLZXP packer. Set packer, POOH with running tools and LD same. 8. Pick up upper completion as required, TIH to setting depth and land tubing. 9. ND BOPE, NU tree and test same. 10. Freeze protect well with diesel by pumping in the 4-1/2'' x 9-5/8'' annulus, taking returns from the tubing and allowing to equalize. 11. Secure well and RDMO 4. Diverter and BOP Information Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP and diverter schematics on file for Doyon 25. Doyon 25 will use a BOPE stack equipped with an annular preventer, fixed, 9-5/8'' solid body rams, blind/shear rams and variable bore rams while drilling and running casing in the intermediate section of 1H-106 1H-106L1 has a MASP of 1490 psi in the production hole section using the methodology presented in section 5 MASP calculations. 20 AAC 25.035.e.1.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 sized to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 6 | 14 Intermediate Drilling/ Casing x Annular Preventer (iii) x 9-5/8'' Fixed Rams x Blind/Shear Rams (ii) x VBR’s (i) Production: x Annular Preventer (iii) x Solid Body Rams x Blind/Shear Rams (ii) x VBR’s (i) 5. MASP Calculations Requirements of 20 AAC 25.005(c)(4) (A) maximum downhole pressure and maximum potential surface pressure; Maximum Potential Surface Pressure (MPSP) is determined as the lesser of: Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 1 Method 2 ܯܲܵܲ = [(ܨܩ × 0.052 )െܩܽݏ ܩݎܽ݀݅݁݊ݐ] × ܸܶܦ ܯܲܵܲ = ܨܲܲ െ (ܩܽݏ ܩݎܽ݀݅݁݊ݐ) × ܸܶܦ 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 The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: VBR 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 7 | 14 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 16 20 80 80 12.5 8.6 36 1928 1864 8.6 833 44 44 647 INT 12.25 13.375 1928 1864 12.5 8.6 833 10463 3922 9.2 1,876 1,025 1,025 1,484 PROD 6.75 4.5 9692 3721 12.5 9.2 1,780 21763 4067 9.2 1,945 1,538 2,047 1,538 (B) data on potential gas zones; The wellbore 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 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 8 | 14 6. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out casing shoe and perform LOT test or FIT in accordance with the LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 7. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H40 Welded Cemented to surface with 10 yds slurry 13-3/8'' 16" 68# L80 H563 Cement to Surface 9-5/8'' 12-1/4'' 40# L80 H563 250' TVD above T/ Ugnu C 4-1/2'' 6-3/4'' 12.6# 13CR-80 JFE BEAR N/A – Open Hole Stand Alone Screens 13-3/8'' Surface Casing run to 1928' MD/ 1864' TVD Cement Plan: Cement from 1928’ MD to 1428’ (500’ of tail) with Class G + Adds @ 15.8 ppg, and from 1428' to surface with 11.0 ppg LiteCRETE. Assume 250% excess annular volume in the lead and 50% in the tail, zero excess in 20” conductor. Lead 368 bbls => 1082 sx of 11.0 ppg LiteCRETE + Add's @ 1.91 ft³/sk Tail 68 bbls => 328 sx of 15.8 ppg Class G + Add's @ 1.165 ft³/sk 9-5/8'' Intermediate Liner run to 10463' MD/ 3922' TVD Cement Plan: Cement from 10463’ MD to 9463’ MD (1000’ of tail) with Class G + Adds @ 15.3 ppg, and from 9463’ MD to ~3678’ MD with 14.0 ppg extended class G Ext. Class G. Top of slurry is designed to be at 3678' MD/ 2845' TVD, which is 250' TVD above T/ Ugnu C. Assume 25% excess annular volume in the lead and 25% in the tail. Lead 403 bbls => 1466 sx of 14.0 ppg Ext. Class G + Add's @ 1.545 ft³/sk Tail 76 bbls => 346 sx of 15.3 ppg Class G + Add's @ 1.23 ft³/sk 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 AOGCC 10-401 APD 9 | 14 Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackLead: Conductor 0' - 80' 80 0.182 0% 82 14.52 0 0.00 0 0 82 14.52 43 11.0 ppg LiteCRETE 1.910Lead: Thru Perm 80' - 1428' 1348 0.075 250% 567 100.97 1417 252.44 0 0 1984 353.41 1039 11.0 ppg LiteCRETE 1.910648 115.49 1417 252.44 0 02066 367.93 1082 11.0 ppg LiteCRETE 1.91Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackTail: 500' 1428' - 1928' 500 0.075 50% 210 37.45 105 18.73 0 0 315 56.18 271 15.8 ppg Class G 1.165Tail: Shoe Track 1848' - 1928' 80 0.150 0% 67 11.98 0 0.00 0 0 67 11.98 58 15.8 ppg Class G 1.165278 49.43 105 18.73 0 0383 68.16 328 15.8 ppg Class G 1.165Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackLead Lead: 250' TVD above T/ Ugnu C 3678' - 9463' 5785 0.056 25% 1812 322.70 453 80.67 0 0 2265 403.37 1466 14.0 ppg Ext. Class G 1.5451812 322.70 453 80.67 0 02265 403.37 1466 14.0 ppg Ext. Class G 1.545Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackTop Tail (1000' Tail Coverage) to Shoe 9463' - 10463' 1000 0.056 25% 313 55.78 78 13.95 0 0 391 69.73 318 15.3 ppg Class G 1.230Shoe Track 10383' - 10463' 80 0.076 0% 34 6.07 0 0.00 0 0 34 6.07 28 15.3 ppg Class G 1.230347 61.85 78 13.95 0 0426 75.79 346 15.3 ppg Class G 1.23Total VolumeSurfaceIntermediateTailTotal Lead Volume = 14.52 + 353.41 bbls = 367.93 bbls => 1,082 sx of 11.0 ppg LiteCRETE @ 1.91 ft³/skFootageFootageLeadPlacementTotal Tail Volume = 56.18 + 11.98 bbls = 68.16 bbls => 328 sx of 15.8 ppg Class G @ 1.165 ft³/skSacks BlendPlacement bbl/ft% ExcessVolumeXS VolumeAdditional bblsTotal VolumeSacks Blendbbl/ft% ExcessVolumeXS VolumeAdditional bblsTotal Lead Volume = 403.37 bbls => 1,466 sx of 14.0 ppg Ext. Class G @ 1.545 ft³/skPlacement Footage bbl/ft% ExcessVolumeXS VolumeAdditional bblsTotal VolumeSacks BlendPlacement Footage bbl/ft% ExcessVolumeTailTotal Tail Volume = 69.73 + 6.07 bbls = 75.79 bbls => 346 sx of 15.3 ppg Class G @ 1.23 ft³/skXS VolumeAdditional bblsTotal VolumeSacks Blend 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 10 | 14 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate Production Hole Size in 16" 12-1/4'' 6-3/4'' Casing Size in 13-3/8'' 9-5/8'' 4-1/2'' Mud System Spud Mud FWP FloPro NT Base Fluid WBM WBM WBM Density ppg 8.8 - 9.5 ppg 9.2 ppg 9.2 ppg PV cP ALAP ALAP ALAP YP lb./100 ft2 30 - 80 20 - 30 15 - 30 Funnel Viscosity s/qt 100 - 300 N/A N/A Initial Gels lb./100 ft2 30 - 50 8 - 15 10 10 Minute Gels lb./100 ft2 30 - 50 < 30 15 API Fluid Loss cc/30 min N.C. < 10 4 HPHT Fluid Loss cc/30 min N/A N/A 10 pH 9.0 - 10.0 9.0 - 10.0 9.0 – 9.5 Surface Hole: A freshwater Spud Mud will be used for the surface interval. Keep flow line viscosity at ± 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight 8.8 - 9.5 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 from 9.2 ppg and be prepared to add loss circulation materials as needed if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as needed) will all be important in maintaining wellbore stability. Production Hole: The horizontal production interval will be drilled with water-based mud drill-in fluid weighted to 9.2 ppg. Diagram of Doyon 25 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 11 | 14 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Discussion of Mud and Cuttings 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. 14. Drilling Hazards Summary 16" Hole | 13-3/8'' Casing Interval Event Risk Level Mitigation Strategy Broach of Conductor Low Monitor cellar continuously during interval. Gas Hydrates Moderate Reduced pump rates, Reduced drilling fluid temperatures, Additions of ScreenKleen Running Sands and Gravels Low Maintain planned mud parameters, Increase mud weight, use weighted sweeps. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts / Hole Sloughing Low Cool mud temperatures, minimize circulating times when possible Anti-Collision Moderate Follow real time surveys very closely, shut in nearby wells that we have collision concerns with, gyro survey to ensure survey accuracy. 12-1/4'' Hole | 9-5/8'' Casing Interval Event Risk Level Mitigation Strategy Running Sands and Gravels Low Maintain planned mud parameters, increase mud weight, use weighted sweeps. Stuck Pipe Low Good hole cleaning, pre-treatment with lost circulation material, stabilized BHA, decreased mud weight. Abnormal Reservoir Pressure Low BOP training and drills, increased mud weight. Lost circulation Moderate Reduced pump rates, mud rheology, LCM. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 12 | 14 6-3/4'' Hole | 4-1/2'' Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Abnormal Reservoir Pressure Low Stripping drills, shut-in drills, increased mud weight. Stuck Pipe Low Good hole cleaning, PWD tools monitoring and analysis, decreased mud weight if possible if pipe does get stuck. Lost Circulation Moderate Reduced pump rates, mud rheology, LCM program, additional fluid stored on location during completion run. Differential Sticking Moderate Follow mud program, keep pipe moving when able. Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out or backreaming. Fault Crossings and Concretions Moderate Use developed best practices for concretion drilling. Anti-Collision Moderate Follow real time surveys very closely, shut in nearby wells that we have collision concerns with. Utilize periscope to maintain geological certainty to stay within zone. Casing wear Moderate Maintain low dog legs in the surface interval and utilize super sliders for drilling, milling, and liner running operations to minimize casing wear. Consider logging casing thickness to calibrate casing wear model. Getting Liner to Bottom Moderate Properly clean hole on the trip out with the BHA, perform clean out run if necessary, utilize super sliders for weight transfer, monitor torque and drag. Whipstock Retrieval Moderate A dedicated clean out run prior to attempting to pull whipstock can be used to reduce the risk of fishing operations. To be posted in Rig Floor Doghouse Prior to Spud Well Proximity Risks: 1H is a multi-well pad, containing an original plan of 38 wells. The 1H NEWS Phase 2 program will consist of 4 dual lateral wells targeting West Sak B & D sands. Directional drilling / collision avoidance information is provided in the following attachments. Drilling Area Risks: Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. Fault Crossings – Lost circulation: Standard LCM material and potentially wellbore strengthening pills are expected to be effective in dealing with lost circulation if required. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 13 | 14 15. Proposed Completion Schematic 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 14 | 14 16. Original Completion Schematic Original 0 2750 5500 8250 11000 13750 West(-)/East(+) (5500 usft/in)0225045006750900011250135001575018000South(-)/North(+) (4500 usft/in)1H-1069-5/8" Intermediate Casing4-1/2" Production Casing1H-106L1 wp073750True Vertical Depth (1500 usft/in)3000 4500 6000 7500 9000 10500 12000 13500 15000 16500 18000 19500 21000 Vertical Section at 35.77° (3000 usft/in)1H-1069-5/8" Intermediate Casing4-1/2" Production Casing1H-106L1 wp07SECTION DETAILSSecMD Inc Azi TVDss+N/-S+E/-W Dleg TFaceVSect1 9274.81 78.64 51.48 3563.07 4264.88 5860.13 0.00 0.00 6886.002 9309.00 78.64 51.48 3569.80 4285.75 5886.36 0.00 0.00 6918.273 9322.50 80.82 50.68 3572.21 4294.10 5896.69 17.15 -20.00 6931.084 9362.50 80.82 50.68 3578.59 4319.12 5927.24 0.00 0.00 6969.245 9863.72 71.32 42.24 3699.32 4652.99 6279.63 2.50 -140.15 7446.126 10033.91 71.32 42.24 3753.81 4772.36 6388.01 0.00 0.00 7606.327 10781.00 90.00 42.00 3874.50 5316.78 6880.21 2.50 -0.75 8335.778 10915.44 91.82 43.98 3872.37 5415.10 6971.86 2.00 47.51 8469.119 11433.80 91.82 43.98 3855.94 5787.89 7331.66 0.00 0.00 8981.9110 11524.85 90.00 43.85 3854.50 5853.47 7394.80 2.00 -175.80 9072.0211 11588.89 88.72 43.83 3855.22 5899.65 7439.15 2.00 -179.01 9135.4212 13436.09 88.72 43.83 3896.50 7231.94 8718.01 0.00 0.00 10963.9513 13484.63 88.24 44.67 3897.79 7266.69 8751.86 2.00 119.32 11011.9414 14865.68 88.24 44.67 3940.10 8248.31 9722.40 0.00 0.00 12375.7215 14999.90 88.00 42.00 3944.50 8345.87 9814.45 2.00 -95.26 12508.6816 15028.56 87.60 41.41 3945.60 8367.26 9833.51 2.50 -124.20 12537.1717 15106.41 87.60 41.41 3948.86 8425.59 9884.95 0.00 0.00 12614.5718 15232.09 90.00 38.50 3951.50 8521.90 9965.63 3.00 -50.46 12739.8819 15332.09 90.00 36.00 3951.50 8601.49 10026.15 2.50 -90.00 12839.8320 15432.09 90.00 36.00 3951.50 8682.39 10084.93 0.00 0.00 12939.8321 15517.65 87.49 35.46 3953.37 8751.83 10134.87 3.00 -167.77 13025.3622 15634.83 87.49 35.46 3958.50 8847.18 10202.78 0.00 0.00 13142.4323 15820.61 82.00 34.50 3975.50 8998.70 10308.80 3.00 -170.20 13327.3424 16002.86 87.39 33.55 3992.35 9149.05 10410.30 3.00 -10.01 13508.6525 16221.04 90.96 28.05 3995.50 9336.34 10521.94 3.00 -57.04 13725.8726 16544.04 88.69 18.65 3996.50 9632.54 10649.80 3.00 -103.57 14040.9327 16887.64 82.04 10.74 4024.30 9963.33 10736.64 3.00 -130.39 14360.0828 17451.11 90.00 0.00 4063.50 10521.73 10788.86 2.37 -53.86 14843.6529 17504.63 91.52 0.51 4062.79 10575.25 10789.10 3.00 18.52 14887.2130 17553.15 91.52 0.51 4061.50 10623.74 10789.53 0.00 0.00 14926.8031 17682.17 95.37 0.09 4053.75 10752.50 10790.20 3.00 -6.17 15031.6632 17838.69 90.67 0.05 4045.50 10908.77 10790.40 3.00 -179.48 15158.5633 18107.33 82.61 0.05 4061.23 11176.72 10790.62 3.00 -179.97 15376.0934 18118.57 82.61 0.05 4062.68 11187.87 10790.63 0.00 0.00 15385.1435 18353.21 89.65 0.02 4078.50 11421.82 10790.77 3.00 -0.21 15575.0436 18437.94 92.19 359.96 4077.14 11506.54 10790.75 3.00 -1.45 15643.7637 18768.52 92.19 359.96 4064.50 11836.88 10790.49 0.00 0.00 15911.6238 18890.43 95.84 359.74 4055.96 11958.46 10790.17 3.00 -3.40 16010.0739 18970.14 93.46 359.75 4049.50 12037.90 10789.81 2.99 179.71 16074.3240 19092.75 89.79 359.97 4046.03 12160.44 10789.52 3.00 176.53 16173.5741 19446.67 89.79 359.97 4047.35 12514.36 10789.35 0.00 0.00 16460.6142 19506.29 88.00 0.00 4048.50 12573.97 10789.33 3.00 179.12 16508.9743 19587.06 85.58 359.99 4053.02 12654.60 10789.33 3.00 -179.76 16574.3844 19691.82 85.58 359.99 4061.10 12759.05 10789.31 0.00 0.00 16659.1145 19805.92 89.00 0.00 4066.5012873.01 10789.30 3.00 0.17 16751.5646 19851.26 89.91 359.98 4066.93 12918.35 10789.29 2.00 -1.42 16788.3447 20813.05 89.91 359.98 4068.50 13880.13 10788.91 0.00 0.00 17568.4448 20837.53 90.39 0.05 4068.44 13904.61 10788.92 2.00 8.77 17588.3149 21280.59 90.39 0.05 4065.42 14347.67 10789.32 0.00 0.00 17948.0150 21336.12 91.50 0.00 4064.50 14403.19 10789.35 2.00 -2.69 17993.0751 21405.01 93.56 359.89 4061.46 14472.00 10789.28 3.00 -3.12 18048.8652 21473.60 93.56 359.89 4057.19 14540.46 10789.15 0.00 0.00 18104.3253 21592.44 90.00 0.00 4053.50 14659.22 10789.03 3.00 178.19 18200.6154 21654.08 88.78 359.81 4054.1614720.86 10788.93 2.00 -171.06 18250.5655 21905.54 88.78 359.81 4059.5014972.26 10788.08 0.00 0.00 18454.04Azimuths to True NorthMagnetic North: 13.87°Magnetic FieldStrength: 57187.2nTDip Angle: 80.63°Date: 11/15/2024Model: BGGM2024TMREFERENCE INFORMATIONCoordinate(N/E) Reference: Well 1H-106, True NorthVertical (TVD) Reference: Doyon 25 Actual KB (54.0+39.5DF) @ 93.50usft (Doyon 25)Section (VS) Reference: Slot - (0.00N, 0.00E)Measured Depth Reference: Doyon 25 Actual KB (54.0+39.5DF) @ 93.50usft (Doyon 25)Calculation Method: Minimum CurvatureConocoPhillips Alaska Inc_KuparukProject: Kuparuk River Unit_1Well: 1H-106Site: Kuparuk 1H PadWellbore: 1H-106L1Design: 1H-106L1 wp07MD Annotation9274.81 Start 34.19 hold at 9274.81 MD9309.00 Start DLS 17.15 TFO -20.009322.50 Start 40.00 hold at 9322.50 MD9362.50 Start DLS 2.50 TFO -140.159863.72 Start 170.19 hold at 9863.72 MD10033.91 Start DLS 2.50 TFO -0.7510781.00 Start DLS 2.00 TFO 47.5110915.44 Start 518.36 hold at 10915.44 MD11433.80 Start DLS 2.00 TFO -175.8011524.85 Start DLS 2.00 TFO -179.0111588.89 Start 1847.20 hold at 11588.89 MD13436.09 Start DLS 2.00 TFO 119.3213484.63 Start 1381.05 hold at 13484.63 MD14865.68 Start DLS 2.00 TFO -95.2614999.90 Start DLS 2.50 TFO -124.2015028.56 Start 77.84 hold at 15028.56 MD15106.41 Start DLS 3.00 TFO -50.4615232.09 Start Turn -2.5015332.09 Start 100.00 hold at 15332.09 MD15432.09 Start DLS 3.00 TFO -167.7715517.65 Start 117.18 hold at 15517.65 MD15634.83 Start DLS 3.00 TFO -170.2015820.61 Start DLS 3.00 TFO -10.0116002.86 Start DLS 3.00 TFO -57.0416221.04 Start DLS 3.00 TFO -103.5716544.04 Start DLS 3.00 TFO -130.3916887.64 Start DLS 2.37 TFO -53.8617451.11 Start DLS 3.00 TFO 18.5217504.63 Start 48.51 hold at 17504.63 MD17553.15 Start DLS 3.00 TFO -6.1717682.17 Start DLS 3.00 TFO -179.4817838.69 Start DLS 3.00 TFO -179.9718107.33 Start 11.24 hold at 18107.33 MD18118.57 Start DLS 3.00 TFO -0.2118353.21 Start DLS 3.00 TFO -1.4518437.94 Start 330.58 hold at 18437.94 MD18768.52 Start DLS 3.00 TFO -3.4018890.43Start DLS 2.99 TFO 179.7118970.14 Start DLS 3.00 TFO 176.5319092.75 Start 353.92 hold at 19092.75 MD19446.67 Start DLS 3.00 TFO 179.1219506.29 Start DLS 3.00 TFO -179.7619587.06 Start 104.76 hold at 19587.06 MD19691.82 Start DLS 3.00 TFO 0.1719805.92 Start DLS 2.00 TFO -1.4219851.26 Start 961.78 hold at 19851.26 MD20813.05 Start DLS 2.00 TFO 8.7720837.53 Start 443.06 hold at 20837.53 MD21280.59 Start DLS 2.00 TFO -2.6921336.12 Start DLS 3.00 TFO -3.1221405.01 Start 68.59 hold at 21405.01 MD21473.60 Start DLS 3.00 TFO 178.1921592.44 Start DLS 2.00 TFO -171.0621654.08 Start 251.46 hold at 21654.08 MD21905.54 TD at 21905.54SURVEY PROGRAMDepth From Depth To Survey/PlanTool109.60 1726.98 Survey #1 (1H-106)r.5 SDI_URSA11823.59 9274.81 Survey #2 (1H-106)MWD+IFR2+SAG+MS9274.81 9575.00 1H-106L1 wp07 (1H-106L1)r.5 MWD9575.00 21905.54 1H-106L1 wp07 (1H-106L1)MWD+IFR2+SAG+MSCASING DETAILSTVD MD NameSize3569.80 9309.00 9-5/8" Intermediate Casing9.6254059.49 21905.00 4-1/2" Production Casing4.500LOCATION INFORMATION:Ground Level: 54.00Northing: 5980384.67Easting: 1689611.52Lattitude: 70° 21' 27.291 NLongitude: 149° 36' 1.572 WPROJECT DETAILS: Kuparuk River Unit_1Geodetic System: US State Plane 1983Datum: North American Datum 1983Ellipsoid: GRS 1980Zone: Alaska Zone 4System Datum: Mean Sea Level1H-106L1 wp07 SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9274.81 78.64 51.48 3563.07 4264.88 5860.13 0.00 0.00 6886.002 9309.00 78.64 51.48 3569.80 4285.75 5886.36 0.00 0.00 6918.273 9322.50 80.82 50.68 3572.21 4294.10 5896.69 17.15 -20.00 6931.084 9362.50 80.82 50.68 3578.59 4319.12 5927.24 0.00 0.00 6969.245 9863.72 71.32 42.24 3699.32 4652.99 6279.63 2.50 -140.15 7446.126 10033.91 71.32 42.24 3753.81 4772.36 6388.01 0.00 0.00 7606.327 10781.00 90.00 42.00 3874.50 5316.78 6880.21 2.50 -0.75 8335.778 10915.44 91.82 43.98 3872.37 5415.10 6971.86 2.00 47.51 8469.119 11433.80 91.82 43.98 3855.94 5787.89 7331.66 0.00 0.00 8981.9110 11524.85 90.00 43.85 3854.50 5853.47 7394.80 2.00 -175.80 9072.0211 11588.89 88.72 43.83 3855.22 5899.65 7439.15 2.00 -179.01 9135.4212 13436.09 88.72 43.83 3896.50 7231.94 8718.01 0.00 0.00 10963.9513 13484.63 88.24 44.67 3897.79 7266.69 8751.86 2.00 119.32 11011.9414 14865.68 88.24 44.67 3940.10 8248.31 9722.40 0.00 0.00 12375.7215 14999.90 88.00 42.00 3944.50 8345.87 9814.45 2.00 -95.26 12508.6816 15028.56 87.60 41.41 3945.60 8367.26 9833.51 2.50 -124.20 12537.1717 15106.41 87.60 41.41 3948.86 8425.59 9884.95 0.00 0.00 12614.5718 15232.09 90.00 38.50 3951.50 8521.90 9965.63 3.00 -50.46 12739.8819 15332.09 90.00 36.00 3951.50 8601.49 10026.15 2.50 -90.00 12839.8320 15432.09 90.00 36.00 3951.50 8682.39 10084.93 0.00 0.00 12939.8321 15517.65 87.49 35.46 3953.37 8751.83 10134.87 3.00 -167.77 13025.3622 15634.83 87.49 35.46 3958.50 8847.18 10202.78 0.00 0.00 13142.4323 15820.61 82.00 34.50 3975.50 8998.70 10308.80 3.00 -170.20 13327.3424 16002.86 87.39 33.55 3992.35 9149.05 10410.30 3.00 -10.01 13508.6525 16221.04 90.96 28.05 3995.50 9336.34 10521.94 3.00 -57.04 13725.8726 16544.04 88.69 18.65 3996.50 9632.54 10649.80 3.00 -103.57 14040.9327 16887.64 82.04 10.74 4024.30 9963.33 10736.64 3.00 -130.39 14360.0828 17451.11 90.00 0.00 4063.50 10521.73 10788.86 2.37 -53.86 14843.6529 17504.63 91.52 0.51 4062.79 10575.25 10789.10 3.00 18.52 14887.2130 17553.15 91.52 0.51 4061.50 10623.74 10789.53 0.00 0.00 14926.8031 17682.17 95.37 0.09 4053.75 10752.50 10790.20 3.00 -6.17 15031.6632 17838.69 90.67 0.05 4045.50 10908.77 10790.40 3.00 -179.48 15158.5633 18107.33 82.61 0.05 4061.23 11176.72 10790.62 3.00 -179.97 15376.0934 18118.57 82.61 0.05 4062.68 11187.87 10790.63 0.00 0.00 15385.1435 18353.21 89.65 0.02 4078.50 11421.82 10790.77 3.00 -0.21 15575.0436 18437.94 92.19 359.96 4077.14 11506.54 10790.75 3.00 -1.45 15643.7637 18768.52 92.19 359.96 4064.50 11836.88 10790.49 0.00 0.00 15911.6238 18890.43 95.84 359.74 4055.96 11958.46 10790.17 3.00 -3.40 16010.0739 18970.14 93.46 359.75 4049.50 12037.9010789.81 2.99 179.71 16074.3240 19092.75 89.79 359.97 4046.03 12160.44 10789.52 3.00 176.53 16173.5741 19446.67 89.79 359.97 4047.35 12514.36 10789.35 0.00 0.00 16460.6142 19506.29 88.00 0.00 4048.50 12573.97 10789.33 3.00 179.12 16508.9743 19587.06 85.58 359.99 4053.02 12654.60 10789.33 3.00 -179.76 16574.3844 19691.82 85.58 359.99 4061.10 12759.0510789.31 0.00 0.00 16659.1145 19805.92 89.00 0.00 4066.50 12873.01 10789.30 3.00 0.17 16751.5646 19851.26 89.91 359.98 4066.93 12918.35 10789.29 2.00 -1.42 16788.3447 20813.05 89.91 359.98 4068.50 13880.1310788.91 0.00 0.00 17568.4448 20837.53 90.39 0.05 4068.44 13904.61 10788.92 2.00 8.77 17588.3149 21280.59 90.39 0.05 4065.42 14347.67 10789.32 0.00 0.00 17948.0150 21336.12 91.50 0.00 4064.50 14403.19 10789.35 2.00 -2.69 17993.0751 21405.01 93.56 359.89 4061.46 14472.00 10789.28 3.00 -3.12 18048.8652 21473.60 93.56 359.89 4057.19 14540.46 10789.15 0.00 0.00 18104.3253 21592.44 90.00 0.00 4053.50 14659.22 10789.03 3.00 178.19 18200.6154 21654.08 88.78 359.81 4054.1614720.86 10788.93 2.00 -171.06 18250.5655 21905.54 88.78 359.81 4059.5014972.26 10788.08 0.00 0.00 18454.04151530304545606075759090901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [usft]9275935094259500957496499724980098759950100251009810171102441031710389104621053510608106811075410827109011097511049111231119811272113471142211499115761165111726118011187611951120261210112176122511232612401124761255112626127011277612851129261300113076131511322613301133761345113526136011367613751138261390113976140511412614201142751435014425145001457514650147251480014875149511502615101151741524715320153941546915545156201569615773158481592015993160651613616208162811635516429165031657716653167291680416880169541702717101171751724917323173981747117545176181769117769178471792518002180801815418227183001837318447185221859718672187471882018893189701904819124191991927419349194241950119579196541972819800198741994920024200992017420249203242039920474205492062420699207742084920924209992107421149212242129821371214452152221599216762175121826218831H-106Project: Kuparuk River Unit_1Site: Kuparuk 1H PadWell: 1H-106Wellbore: 1H-106L1Plan: 1H-106L1 wp07ANTI-COLLISION SETTINGSInterpolation Method: MD, interval: 25.00Depth Reference: 9274.81 To 21905.54Results Limited By: Ellipse Separation: 1000.00Reference: 1H-106L1 wp07 (1H-106/1H-106L1)REFERENCE INFORMATIONCalculation Method: Minimum CurvatureError System: ISCWSAScan Method: Trav. Cylinder NorthError Surface: Combined Pedal CurveWarning Method: Error Ratio9275 1000010000 1100011000 1200012000 1300013000 1500015000 1800018000 2000020000 22000From Colour To MDDepth Range: 7R 1H-106L1 wp071H-106L1 wp07SURVEY PROGRAMDepth From Depth ToSurvey/PlanTool109.60 1726.98 Survey #1 (1H-106)r.5 SDI_URSA11823.59 9274.81 Survey #2 (1H-106)MWD+IFR2+SAG+MS9274.81 9575.00 1H-106L1 wp07 (1H-106L1)r.5 MWD9575.00 21905.54 1H-106L1 wp07 (1H-106L1)MWD+IFR2+SAG+MS !" " # $%&'( ($ '( ($ ")*"& '( ($ +,- .$(/! 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A ! $7(+> !4> !4 A < "!> "!> "! 86 A 4 5 ; 5 9 0 . < 0 / )?(> D % ;0 .3 - < &(?E 20 "E F & 7-- . 7-- - . !" # $"%&'()&" *+ , 2 0 .3 > * - > 5 From: To: Cc: Subject: Sent: CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: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. Loepp, Victoria T (OGC) Gorham, Brad Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); AOGCC ReporƟng (CED sponsored); [EXTERNAL]APPROVAL 1H-106 Liner (PTD#224-117) and 1H-106L1 (PTD#: 224-118) Window Placement 12/2/2024 8:00:35 PM Brad, Approval is granted to proceed as outlined below. Please follow up with a change of approved sundry as soon as possible. Victoria Sent from my iPhone On Dec 2, 2024, at 6:12ௗPM, Gorham, Brad <Brad.Gorham@conocophillips.com> wrote: Victoria, As discussed, we were unable to get our 1H-106 mainbore liner to the planned set depth. We were unable to make any progress once we got to ~21,394’ MD, which is ~569’ short of the planned set depth. Due to the this well utilizing Level 5 RAM hanger, the fact that the liner hanger was set high means that our L1 window will now also be higher. The new planned L1 window depth is 9280’ MD, which places it in the Ugnu formation. We are proposing to run two swell packers in conjunction with solid tubulars down to the West Sak D sand, as shown in both the schematic below and the attachment, in addition to the Level 5 hanger to ensure that we will not have any crossflow between the Ugnu and West Sak Pools. The shallowest swell packer will be set in an Ugnu shale to provide isolation while the second swell packer will be placed to isolate the West Sak D sand from the West Sak Nb formation. We are seeking approval for the new window placement and isolation method so that we can set our hanger and keep progressing operations on the rig this evening. We will follow up with a subsequent sundry and documentation for the changes to the 1H-106 L1 lateral in the coming days. Please let us know if we have approval to proceed and can set our liner hanger as soon as possible. If you have any further questions please don’t hesitate to give me a shout on my cell. Thanks, Brad 907-351-5082 From: Gorham, Brad Sent: Monday, December 2, 2024 5:24 PM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: FW: 1H-106 Discussion- Victoria, See the picture below for reference. I have highlighted the changes in red. I will call you shortly. Thanks, Brad From: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Sent: Monday, December 2, 2024 4:40 PM To: Gorham, Brad <Brad.Gorham@conocophillips.com> Subject: FW: 1H-106 Discussion- From: Hobbs, Greg S Sent: Monday, December 2, 2024 4:36 PM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Subject: 1H-106 Discussion- Brad Gorham and I will call you in a moment. Greg Hobbs, P.E. Regulatory Engineer | Wells Team ConocoPhillips Alaska Inc. Office: 907-263-4749 Cell: 907-231-0515 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.govChris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, West Sak Oil Pool, KRU 1H-106L1 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-118 Surface Location: 70 FNL, 762 FEL, S33, T12N, R10E, UM Bottomhole Location: 4127 FSL, 495 FEL, S14, T12N, R10E, UM Dear Mr. Brillon: Enclosed is the approved application for the permit to drill the above referenced well. The permit is for a new wellbore segment of existing well Permit Number 224-117, API Number 50- 029- 23800-00-00. Production from or injection into this wellbore must be reported under the original API Number stated above. 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 29th day of October 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.29 07:21:45 -06'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 21,763 TVD: 4067 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 93.61 15. Distance to Nearest Well Open Surface: x- 549580 y- 5980633 Zone- 4 54 to Same Pool: 1242' to 1H-120 16. Deviated wells: Kickoff depth: 9692 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 94.52 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6.75" 4.50" 12.6# 13CR-80 JFE BEAR 12321 9442 3630.06 21763 4066.61 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Cement to surface with 10 yds slurry 80 1864 3912 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: Chris Brillon Contact Email: Brad.Gorham@conocophillips.com Wells Engineering Manager Contact Phone: 907-265-6487 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska, Inc.59-52-180 KRU 1H-106L1 P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field West Sak Oil Pool 70 FNL, 762 FEL, S33 T12N R10E, UM ADL025637, ADL025638, ADL025639 4557 FSL, 5197 FEL, S26 T12N R10E, UM 931812000, 931695000, 931696000 November 1st, 2024 18. Casing Program:Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) 4127 FSL, 495 FEL, S14 T12N R10E, UM 2560, 2560, 2560 4784' to ADL025636 GL / BF Elevation above MSL (ft): 1945 1538 N/A:Open Hole Standalone Screens Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Casing Length Size Cement Volume MD Conductor/Structural 80 20" 80 Surface 1918 13-3/8" 1082 sx of 11.0 ppg LiteCRETE + 328 sx of 15.8 ppg Class G 1918 Perforation Depth MD (ft): Perforation Depth TVD (ft): Intermediate 9987 9-5/8" 1466 sx of 14.0 ppg Ext. Class G + 346 sx of 15.3 ppg Class G 9987 Production Liner If checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.Brad Gorham 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 3:39 pm, Aug 23, 2024 DSR-8/26/24VTL 10/28/2024 3,812 A.Dewhurst 10OCT24 X 224-118 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig Diverter variance not approved; diverter required. 50-029-23800-60-00 BOPE testing on a 21-day interval is approved with the attached conditions RAM configuration allowing three preventers for MPSP < 3000 psig is approved as outlined in 20 AAC 25.035.c.1.A for Int and production holes *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.29 07:21:57 -06'00' 10/29/24 10/29/24 RBDMS JSB 102924 KRU 1H-10 and 1H-10L1 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, AK 99510-0360 Telephone 907-276-1215 August 21, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill 1H-106L1 Dear Sir or Madam, ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore West Sak D Sand lateral Producer, sidetracked from the 1H-106 wellbore on the 1H drilling pad. The intended spud date for this well is September 16, 2024. It is intended that Doyon 25 be used to drill the well. 1H-106 will drill a 16" surface hole on diverter. 13-3/8'' casing will be run and cemented to surface. The remaining intervals will utilize Doyon 25’s 13-5/8” x 5000 psi BOP stack with required ram installations and tested on a 21 day cycle in accordance with ConocoPhillips and AOGCC policy. The 12-1/4'' intermediate hole section will be landed in the top of the West Sak B sand. 9-5/8'' intermediate casing will be run and cemented in place with a 500’ or 250’ TVD column of cement above the highest hydrocarbon bearing zone per AOGCC regulation. After completing the lower 6-3/4'' West Sak B production lateral, the upper 1H-106L1 6-3/4'' West Sak D production lateral will be geo- steered and completed with a 4-1/2'' Open Hole Standalone Screens. It is requested that a variance of the diverter requirement under 20 AAC 25.035 (h)(2) is granted. Three consecutive surface intervals have recently been drilled at 1H, (1H-112, 1H-120, 1H-107), and have not encountered any shallow gas or had any issues related to hydrates. A variance is also requested for a BOPE test interval of 21 days for this project. Doyon 25 supported the CPAI BOPE between well maintenance program with a replacement of its NOV BOP stack with a Cameron stack due to lack of NOV support. The variance allows effective drilling and completion of this multi-lateral well with reservoir instability and a complex middle completion to isolate the lateral junction. 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. Proposed drilling program 3. Proposed drilling fluids program summary 4. Proposed completion diagram 5. Pressure information as required by 20 ACC 25.005 (c) (4) (a-c) 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 Brad Gorham at 907-265-6487 (Brad.Gorham@conocophillips.com) or Greg Hobbs at 907-263-4749 (greg.s.hobbs@conocophillips.com). Regards, Brad Gorham Staff Drilling Engineer cc: 1H-106 Well File / Jenna Taylor ATO 1732 David Lee ATO 1552 Chris Brillon ATO 1548 Data presented in attached emails do not justify diverter variance. -A.Dewhurst 25SEP24 variance is also requested for a BOPE test interval variance of the diverter requirement 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 1 | 13 1H-106L1Well Plan Application for Permit to Drill Table of Contents 1. Well Name ............................................................................................................................................. 2 2. Location Summary ................................................................................................................................. 2 3. Proposed Drilling Program ..................................................................................................................... 5 4. Diverter and BOP Information ................................................................................................................ 5 5. MASP Calculations ................................................................................................................................. 6 6. Procedure for Conducting Formation Integrity Tests ............................................................................... 8 7. Casing and Cementing Program .............................................................................................................. 8 8. Drilling Fluid Program .......................................................................................................................... 10 9. Abnormally Pressured Formation Information ...................................................................................... 10 10. Seismic Analysis ................................................................................................................................... 11 11. Seabed Condition Analysis ................................................................................................................... 11 12. Evidence of Bonding ............................................................................................................................. 11 13. Discussion of Mud and Cuttings Disposal .............................................................................................. 11 14. Drilling Hazards Summary .................................................................................................................... 11 15. Proposed Completion Schematic .......................................................................................................... 13 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 2 | 13 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 1H-106L1 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 70 FNL, 762 FEL, S33 T12N R10E, UM NAD27 Northing: 5980632.86 Easting: 549579.90 RKB Elevation 39.61’ AMSL Pad Elevation 54’ AMSL Top of Productive Horizon (Heel) 4557 FSL, 5197 FEL, S26 T12N R10E, UM NAD27 Northing: 5985302.25 Easting: 555663.47 Measured Depth, RKB: 9692‘ MD True Vertical Depth, RKB: 3721‘ TVD True Vertical Depth, SS: 3628‘ TVDss Total Depth (Toe) 4127 FSL, 495 FEL, S14 T12N R10E, UM NAD27 Northing: 5995467.78 Easting: 560275.35 Measured Depth, RKB: 21763‘ MD True Vertical Depth, RKB: 4067‘ TVD True Vertical Depth, SS: 3973‘ TVDss Please see attached well stick diagram for the current planned development of the pad. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 3 | 13 Pad Layout 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 4 | 13 Well Plat 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 5 | 13 3. Proposed Drilling Program NOTE: Previous operations are covered under the 1H-106 Application for Permit to Drill 1. PU 6-3/4'' bit, motor, GR/Res and magnets and drill ~200’ of new hole in the West Sak D sand. POOH. 2. Pick up 6-3/4'' RSS lateral drilling assembly (LWD Program: GR/Azimuthal RES/Den/Neu) and TIH. 3. Drill and geo-steer West Sak D sand lateral to section TD per directional plan. 4. Circulate the hole clean and POOH to window. Circulate hole clean, POOH and LD same. 5. TIH with whipstock retrieval tool. Retrieve whipstock, POOH and LD same. 6. Run 4-1/2'' Open Hole Standalone Screens. PU Baker RAM L5 Junction and MWD for orientation. POOH with running tools and LD same. 7. Make up and run in hole to install LEM (lateral entry module) with SLZXP packer. Set packer, POOH with running tools and LD same. 8. Pick up upper completion as required, TIH to setting depth and land tubing. 9. ND BOPE, NU tree and test same. 10. Freeze protect well with diesel by pumping in the 4-1/2'' x 9-5/8'' annulus, taking returns from the tubing and allowing to equalize. 11. Secure well and RDMO 4. Diverter and BOP Information Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP and diverter schematics on file for Doyon 25. Doyon 25 will use a BOPE stack equipped with an annular preventer, fixed, 9-5/8'' solid body rams, blind/shear rams and variable bore rams while drilling and running casing in the intermediate section of 1H-106 1H-106L1 has a MASP of 1490 psi in the production hole section using the methodology presented in section 5 MASP calculations. 20 AAC 25.035.e.1.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 sized to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 6 | 13 Intermediate Drilling/ Casing x Annular Preventer (iii) x 9-5/8'' Fixed Rams x Blind/Shear Rams (ii) x VBR’s (i) Production: x Annular Preventer (iii) x Solid Body Rams x Blind/Shear Rams (ii) x VBR’s (i) 5. MASP Calculations Requirements of 20 AAC 25.005(c)(4) (A) maximum downhole pressure and maximum potential surface pressure; Maximum Potential Surface Pressure (MPSP) is determined as the lesser of: Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 1 Method 2 ܯܲܵܲ = [(ܨܩ × 0.052 )െܩܽݏ ܩݎܽ݀݅݁݊ݐ] × ܸܶܦ ܯܲܵܲ = ܨܲܲ െ (ܩܽݏ ܩݎܽ݀݅݁݊ݐ) × ܸܶܦ 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 The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: VBR 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 7 | 13 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 16 20 80 80 12.5 8.6 36 1928 1864 8.6 833 44 44 647 INT 12.25 13.375 1928 1864 12.5 8.6 833 10463 3922 9.2 1,876 1,025 1,025 1,484 PROD 6.75 4.5 9692 3721 12.5 9.2 1,780 21763 4067 9.2 1,945 1,538 2,047 1,538 (B) data on potential gas zones; The wellbore 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 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-106L1 AOGCC 10-401 APD 8 | 13 6. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out casing shoe and perform LOT test or FIT in accordance with the LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 7. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H40 Welded Cemented to surface with 10 yds slurry 13-3/8'' 16" 68# L80 H563 Cement to Surface 9-5/8'' 12-1/4'' 40# L80 H563 250' TVD above T/ Ugnu C 4-1/2'' 6-3/4'' 12.6# 13CR-80 JFE BEAR N/A – Open Hole Stand Alone Screens 13-3/8'' Surface Casing run to 1928' MD/ 1864' TVD Cement Plan: Cement from 1928’ MD to 1428’ (500’ of tail) with Class G + Adds @ 15.8 ppg, and from 1428' to surface with 11.0 ppg LiteCRETE. Assume 250% excess annular volume in the lead and 50% in the tail, zero excess in 20” conductor. Lead 368 bbls => 1082 sx of 11.0 ppg LiteCRETE + Add's @ 1.91 ft³/sk Tail 68 bbls => 328 sx of 15.8 ppg Class G + Add's @ 1.165 ft³/sk 9-5/8'' Intermediate Liner run to 10463' MD/ 3922' TVD Cement Plan: Cement from 10463’ MD to 9463’ MD (1000’ of tail) with Class G + Adds @ 15.3 ppg, and from 9463’ MD to ~3678’ MD with 14.0 ppg extended class G Ext. Class G. Top of slurry is designed to be at 3678' MD/ 2845' TVD, which is 250' TVD above T/ Ugnu C. Assume 25% excess annular volume in the lead and 25% in the tail. Lead 403 bbls => 1466 sx of 14.0 ppg Ext. Class G + Add's @ 1.545 ft³/sk Tail 76 bbls => 346 sx of 15.3 ppg Class G + Add's @ 1.23 ft³/sk 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 AOGCC 10-401 APD 9 | 13 Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackLead: Conductor 0' - 80' 80 0.182 0% 82 14.52 0 0.00 0 0 82 14.52 43 11.0 ppg LiteCRETE 1.910Lead: Thru Perm 80' - 1428' 1348 0.075 250% 567 100.97 1417 252.44 0 0 1984 353.41 1039 11.0 ppg LiteCRETE 1.910648 115.49 1417 252.44 0 02066 367.93 1082 11.0 ppg LiteCRETE 1.91Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackTail: 500' 1428' - 1928' 500 0.075 50% 210 37.45 105 18.73 0 0 315 56.18 271 15.8 ppg Class G 1.165Tail: Shoe Track 1848' - 1928' 80 0.150 0% 67 11.98 0 0.00 0 0 67 11.98 58 15.8 ppg Class G 1.165278 49.43 105 18.73 0 0383 68.16 328 15.8 ppg Class G 1.165Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackLead Lead: 250' TVD above T/ Ugnu C 3678' - 9463' 5785 0.056 25% 1812 322.70 453 80.67 0 0 2265 403.37 1466 14.0 ppg Ext. Class G 1.5451812 322.70 453 80.67 0 02265 403.37 1466 14.0 ppg Ext. Class G 1.545Weight Yieldft3bblsft3bblsft3bblsft3bbls ppgft3/ SackTop Tail (1000' Tail Coverage) to Shoe 9463' - 10463' 1000 0.056 25% 313 55.78 78 13.95 0 0 391 69.73 318 15.3 ppg Class G 1.230Shoe Track 10383' - 10463' 80 0.076 0% 34 6.07 0 0.00 0 0 34 6.07 28 15.3 ppg Class G 1.230347 61.85 78 13.95 0 0426 75.79 346 15.3 ppg Class G 1.23Total VolumeSurfaceIntermediateTailTotal Lead Volume = 14.52 + 353.41 bbls = 367.93 bbls => 1,082 sx of 11.0 ppg LiteCRETE @ 1.91 ft³/skFootageFootageLeadPlacementTotal Tail Volume = 56.18 + 11.98 bbls = 68.16 bbls => 328 sx of 15.8 ppg Class G @ 1.165 ft³/skSacks BlendPlacement bbl/ft% ExcessVolumeXS VolumeAdditional bblsTotal VolumeSacks Blendbbl/ft% ExcessVolumeXS VolumeAdditional bblsTotal Lead Volume = 403.37 bbls => 1,466 sx of 14.0 ppg Ext. Class G @ 1.545 ft³/skPlacement Footage bbl/ft% ExcessVolumeXS VolumeAdditional bblsTotal VolumeSacks BlendPlacement Footage bbl/ft% ExcessVolumeTailTotal Tail Volume = 69.73 + 6.07 bbls = 75.79 bbls => 346 sx of 15.3 ppg Class G @ 1.23 ft³/skXS VolumeAdditional bblsTotal VolumeSacks Blend 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 10 | 13 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate Production Hole Size in 16" 12-1/4'' 6-3/4'' Casing Size in 13-3/8'' 9-5/8'' 4-1/2'' Mud System Spud Mud FWP FloPro NT Base Fluid WBM WBM WBM Density ppg 8.8 - 9.5 ppg 9.2 ppg 9.2 ppg PV cP ALAP ALAP ALAP YP lb./100 ft2 30 - 80 20 - 30 15 - 30 Funnel Viscosity s/qt 100 - 300 N/A N/A Initial Gels lb./100 ft2 30 - 50 8 - 15 10 10 Minute Gels lb./100 ft2 30 - 50 < 30 15 API Fluid Loss cc/30 min N.C. < 10 4 HPHT Fluid Loss cc/30 min N/A N/A 10 pH 9.0 - 10.0 9.0 - 10.0 9.0 – 9.5 Surface Hole: A freshwater Spud Mud will be used for the surface interval. Keep flow line viscosity at ± 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight 8.8 - 9.5 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 from 9.2 ppg and be prepared to add loss circulation materials as needed if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as needed) will all be important in maintaining wellbore stability. Production Hole: The horizontal production interval will be drilled with water-based mud drill-in fluid weighted to 9.2 ppg. Diagram of Doyon 25 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 11 | 13 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Discussion of Mud and Cuttings 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. 14. Drilling Hazards Summary 16" Hole | 13-3/8'' Casing Interval Event Risk Level Mitigation Strategy Broach of Conductor Low Monitor cellar continuously during interval. Gas Hydrates Moderate Reduced pump rates, Reduced drilling fluid temperatures, Additions of ScreenKleen Running Sands and Gravels Low Maintain planned mud parameters, Increase mud weight, use weighted sweeps. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts / Hole Sloughing Low Cool mud temperatures, minimize circulating times when possible Anti-Collision Moderate Follow real time surveys very closely, shut in nearby wells that we have collision concerns with, gyro survey to ensure survey accuracy. 12-1/4'' Hole | 9-5/8'' Casing Interval Event Risk Level Mitigation Strategy Running Sands and Gravels Low Maintain planned mud parameters, increase mud weight, use weighted sweeps. Stuck Pipe Low Good hole cleaning, pre-treatment with lost circulation material, stabilized BHA, decreased mud weight. Abnormal Reservoir Pressure Low BOP training and drills, increased mud weight. Lost circulation Moderate Reduced pump rates, mud rheology, LCM. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 12 | 13 6-3/4'' Hole | 4-1/2'' Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Abnormal Reservoir Pressure Low Stripping drills, shut-in drills, increased mud weight. Stuck Pipe Low Good hole cleaning, PWD tools monitoring and analysis, decreased mud weight if possible if pipe does get stuck. Lost Circulation Moderate Reduced pump rates, mud rheology, LCM program, additional fluid stored on location during completion run. Differential Sticking Moderate Follow mud program, keep pipe moving when able. Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out or backreaming. Fault Crossings and Concretions Moderate Use developed best practices for concretion drilling. Anti-Collision Moderate Follow real time surveys very closely, shut in nearby wells that we have collision concerns with. Utilize periscope to maintain geological certainty to stay within zone. Casing wear Moderate Maintain low dog legs in the surface interval and utilize super sliders for drilling, milling, and liner running operations to minimize casing wear. Consider logging casing thickness to calibrate casing wear model. Getting Liner to Bottom Moderate Properly clean hole on the trip out with the BHA, perform clean out run if necessary, utilize super sliders for weight transfer, monitor torque and drag. Whipstock Retrieval Moderate A dedicated clean out run prior to attempting to pull whipstock can be used to reduce the risk of fishing operations. To be posted in Rig Floor Doghouse Prior to Spud Well Proximity Risks: 1H is a multi-well pad, containing an original plan of 38 wells. The 1H NEWS Phase 2 program will consist of 4 dual lateral wells targeting West Sak B & D sands. Directional drilling / collision avoidance information is provided in the following attachments. Drilling Area Risks: Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. Fault Crossings – Lost circulation: Standard LCM material and potentially wellbore strengthening pills are expected to be effective in dealing with lost circulation if required. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 1H-106L1 AOGCC 10-401 APD 8/20/2024 1H-107L1 10-401 APD 13 | 13 15. Proposed Completion Schematic 9692 10000 10000 11000 11000 12000 12000 13000 13000 15000 15000 18000 18000 20000 20000 220000 1H-106L1 wp05 Plan Summary 1H-106L1 wp05 1H-05 1H-105 1H-101 1H-101L1 1H-101L2 1H-101L3 1H-101L4 1H-102 1H-102L1 1H-102L2 1H-102L3 1H-102L4 1H-1031H-103L1 1H-103L2 1H-103L3 1H-103L4 1H-104 1H-104L1 1H-104L2 1H-104PB1 1H-107 (O31) wp16.1 1H-107L1 wp07 1H-108 1H-108A 1H-108B 1H-109 1H-1101H-111 1H-112 1H-112L1 1H-112PH1 1H-113 1H-114 1H-115 1H-116 1H-117 1H-118 1H-120 1H-120L1 1H-401 1H-106 wp17 1H-502 wp07 1H-112PH1 0 Dogleg Severity 0 3500 7000 10500 14000 17500 21000 Measured Depth 13-3/8" Surface Casing 9-5/8" Intermediate Casing 4-1/2" Production Casing 50 50 100 100 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/i 1H-106 wp17 0 6000 True Vertical Depth 0 3000 6000 9000 12000 15000 18000 21000 Vertical Section at 36.16° 13-3/8" Surface Casing 9-5/8" Intermediate Casing 4-1/2" Production Casing 0 48 Centre to Centre Separation 0 3000 6000 9000 12000 15000 18000 21000 Measured Depth Equivalent Magnetic Distance DDI 7.507 SURVEY PROGRAM Date: 2024-08-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.61 1927.87 1H-106 wp17 (Plan: 1H-106) 1927.87 9692.00 1H-106 wp17 (Plan: 1H-106) 9692.00 9992.00 1H-106L1 wp05 (Plan: 1H-106L1) 9992.00 21763.91 1H-106L1 wp05 (Plan: 1H-106L1) r.5 SDI_URSA1 MWD+IFR2+SAG+MS r.5 MWD MWD+IFR2+SAG+MS Surface Location North / 5980384.67 East / 1689611.52 Ground / 54.00 CASING DETAILS TVD MD Name 3721.33 9692.01 9-5/8" Intermediate Casing 4066.61 21763.90 4-1/2" Production Casing Mag Model & Date:BGGM2024 01-Oct-24 Magnetic North is 13.93° East of True North (Magnetic Declination) Mag Dip & Field Strength:80.63° 57191.75nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 9692.00 66.98 43.28 3721.33 4630.00 6114.76 0.00 0.00 7346.26 Start DLS 17.15 TFO -20.00 2 9705.50 69.16 42.43 3726.37 4639.18 6123.28 17.15 -20.00 7358.70 Start 40.00 hold at 9705.50 MD 3 9745.50 69.16 42.43 3740.60 4666.77 6148.50 0.00 0.00 7395.86 Start DLS 3.00 TFO 4.34 4 10457.42 90.46 44.01 3865.81 5174.18 6625.84 3.00 4.34 8087.17 Start 25.23 hold at 10457.42 MD 5 10482.64 90.46 44.01 3865.61 5192.32 6643.36 0.00 0.00 8112.17 Start DLS 2.00 TFO -108.09 6 10526.02 90.19 43.19 3865.36 5223.73 6673.27 2.00 -108.09 8155.17 Start 817.18 hold at 10526.02 MD 7 11343.19 90.19 43.19 3862.61 5819.53 7232.55 0.00 0.00 8966.21 Start DLS 2.00 TFO 45.72 8 11396.35 90.94 43.95 3862.09 5858.04 7269.19 2.00 45.72 9018.91 Start 273.71 hold at 11396.35 MD 9 11670.06 90.94 43.95 3857.62 6055.07 7459.13 0.00 0.00 9290.07 Start DLS 2.00 TFO 179.89 10 11775.99 88.82 43.95 3857.85 6131.32 7532.65 2.00 179.89 9395.02 Start 520.94 hold at 11775.99 MD 11 12296.93 88.82 43.95 3868.61 6506.26 7894.14 0.00 0.00 9911.03 Start DLS 1.00 TFO -177.87 12 12463.50 87.15 43.89 3874.47 6626.17 8009.62 1.00 -177.87 10075.98 Start 529.67 hold at 12463.50 MD 13 12993.18 87.15 43.89 3900.79 7007.40 8376.39 0.00 0.00 10600.19 Start DLS 2.00 TFO -8.51 14 13010.78 87.50 43.84 3901.61 7020.08 8388.58 2.00 -8.51 10617.62 Start DLS 2.50 TFO 52.89 15 13127.38 89.26 46.16 3904.91 7102.48 8470.99 2.50 52.89 10732.78 Start 209.50 hold at 13127.38 MD 16 13336.89 89.26 46.16 3907.61 7247.57 8622.10 0.00 0.00 10939.08 Start DLS 2.00 TFO 131.51 17 13445.68 87.82 47.79 3910.38 7321.77 8701.61 2.00 131.51 11045.90 Start 1319.79 hold at 13445.68 MD 18 14765.47 87.82 47.79 3960.61 8207.75 9678.53 0.00 0.00 12337.66 Start DLS 2.00 TFO 76.00 19 14911.40 88.53 50.63 3965.26 8303.02 9788.95 2.00 76.00 12479.73 Start 519.46 hold at 14911.40 MD 20 15430.86 88.53 50.63 3978.61 8632.44 10190.38 0.00 0.00 12982.57 Start DLS 3.50 TFO -102.19 21 15863.72 85.41 35.78 4001.61 8946.54 10485.48 3.50 -102.19 13410.28 Start DLS 3.50 TFO -74.40 22 16303.72 89.66 20.96 4020.61 9332.21 10693.63 3.50 -74.40 13844.49 Start DLS 3.50 TFO -45.84 23 16503.52 94.52 15.94 4013.31 9521.50 10756.79 3.50 -45.84 14034.57 Start DLS 3.50 TFO -139.42 24 16681.00 89.80 11.90 4006.61 9693.56 10799.42 3.50 -139.42 14198.64 Start DLS 3.25 TFO -109.91 25 17317.30 82.90 352.36 4047.47 10324.65 10823.28 3.25 -109.91 14722.22 Start DLS 3.50 TFO 32.14 26 17657.21 93.00 358.66 4059.61 10662.70 10796.78 3.50 32.14 14979.50 Start DLS 1.50 TFO 133.46 27 17838.00 91.13 0.63 4053.09 10843.34 10795.66 1.50 133.46 15124.68 Start 146.75 hold at 17838.00 MD 28 17984.74 91.13 0.63 4050.19 10990.05 10797.27 0.00 0.00 15244.07 Start DLS 2.00 TFO 178.44 29 18116.45 88.50 0.70 4050.61 11121.74 10798.80 2.00 178.44 15351.28 Start DLS 2.99 TFO -160.21 30 18301.43 83.29 358.81 4063.85 11306.17 10798.03 2.99 -160.21 15499.73 Start DLS 2.50 TFO 12.16 31 18612.72 90.90 0.45 4079.61 11616.81 10796.05 2.50 12.16 15749.35 Start DLS 2.00 TFO -29.06 32 18648.33 91.52 0.10 4078.86 11652.41 10796.22 2.00 -29.06 15778.19 Start 197.50 hold at 18648.33 MD 33 18845.82 91.52 0.10 4073.61 11849.84 10796.58 0.00 0.00 15937.79 Start DLS 2.00 TFO -12.49 34 18937.41 93.31 359.71 4069.75 11941.34 10796.43 2.00 -12.49 16011.57 Start 192.86 hold at 18937.41 MD 35 19130.27 93.31 359.71 4058.61 12133.88 10795.45 0.00 0.00 16166.44 Start DLS 2.00 TFO 172.98 36 19293.13 90.08 0.11 4053.80 12296.64 10795.18 2.00 172.98 16297.69 Start 132.72 hold at 19293.13 MD 37 19425.86 90.08 0.11 4053.61 12429.37 10795.42 0.00 0.00 16404.98 Start DLS 2.00 TFO -126.56 38 19432.40 90.00 0.00 4053.61 12435.91 10795.43 2.00 -126.56 16410.27 Start DLS 2.00 TFO -178.95 39 19514.60 88.36 359.97 4054.79 12518.10 10795.41 2.00 -178.95 16476.61 Start 405.86 hold at 19514.60 MD 40 19920.46 88.36 359.97 4066.43 12923.79 10795.19 0.00 0.00 16804.01 Start DLS 2.00 TFO 1.05 41 20002.66 90.00 0.00 4067.61 13005.98 10795.17 2.00 1.05 16870.35 Start DLS 2.00 TFO -13.29 42 20019.43 90.33 359.92 4067.56 13022.75 10795.16 2.00 -13.29 16883.88 Start 869.36 hold at 20019.43 MD 43 20888.79 90.33 359.92 4062.61 13892.10 10793.99 0.00 0.00 17585.04 Start DLS 2.00 TFO 174.13 44 20918.88 89.73 359.98 4062.60 13922.18 10793.97 2.00 174.13 17609.32 Start 845.03 hold at 20918.88 MD 45 21763.91 89.73 359.98 4066.61 14767.20 10793.74 0.00 0.00 18291.39 TD at 21763.91 FORMATION TOP DETAILS TVDPath Formation 1498.61 T-5 1638.61 Base Permafrost 1898.61 T-3 2112.61 K-15 3095.61 Ugnu C 3360.61 Ugnu B 3489.61 Ugnu A 3735.61 Nb 3764.61 WSAK D Plan: 54+39.61 @ 93.61usft (Doyon 25) Project: Kuparuk River Unit_1Site: Kuparuk 1H PadWell: Plan: 1H-106 (O33)Wellbore: Plan: 1H-106L1Design: 1H-106L1 wp05060001200018000South(-)/North(+) (3000 usft/in)0 6000 12000 18000 24000West(-)/East(+) (3000 usft/in)1H-106L1 T007 Rev011H-106L1 T006 Rev011H-106L1 T014 Rev011H-106L1 T012 Rev011H-106L1 T010 Rev011H-106L1 T005 Rev011H-106L1 T004 Rev011H-106L1 T015 Rev011H-106L1 T001 Rev011H-106L1 T018 Rev011H-106L1 T013 Rev011H-106L1 TD 1320ft1H-106L1 T016 Rev011H-106L1 Landing Heeling1H-106L1 T017 Rev011H-106L1 T003 Rev011H-106L1 T008 Rev011H-106L1 T019 Rev011H-106L1 T011 Rev011H-106L1 T002 Rev011H-106L1 Heel Target 1320ft1H-106L1 T009 Rev011 H -0 5 1H-1051H-1011H-101L11H-101L21H-101L31H-101L41H-1021H-102L11H-102L21H-102L31H-102L41H-1031H-103L11H-103L21H-103L31H-103L41H-1041H-104L11H-104L21H-104PB11H-107(O31)wp16.11H-107L1wp071H-1081 H -1 0 8 A1H-108B1H-1091H-1101 H -1 1 1 1 H -11 3 1H-1141H-1151 H -1 1 6 1H-1171H-1181H-4011H-106 wp171H-502wp071H-1121H-112L11H-112PH11H-1201H-120L113-3/8" Surface Casing9-5/8" Intermediate Casing4-1/2" Production Casing500100015002000250030003500400040671H-106L1 wp05Plan View with offset wells Project: Kuparuk River Unit_1Site: Kuparuk 1H PadWell: Plan: 1H-106 (O33)Wellbore: Plan: 1H-106L1Design: 1H-106L1 wp05060001200018000South(-)/North(+) (3000 usft/in)0 6000 12000 18000 24000West(-)/East(+) (3000 usft/in)1H-106L1 T007 Rev011H-106L1 T006 Rev011H-106L1 T014 Rev011H-106L1 T012 Rev011H-106L1 T010 Rev011H-106L1 T005 Rev011H-106L1 T004 Rev011H-106L1 T015 Rev011H-106L1 T001 Rev011H-106L1 T018 Rev011H-106L1 T013 Rev011H-106L1 TD 1320ft1H-106L1 T016 Rev011H-106L1 Landing Heeling1H-106L1 T017 Rev011H-106L1 T003 Rev011H-106L1 T008 Rev011H-106L1 T019 Rev011H-106L1 T011 Rev011H-106L1 T002 Rev011H-106L1 Heel Target 1320ft1H-106L1 T009 Rev0113-3/8" Surface Casing9-5/8" Intermediate Casing4-1/2" Production Casing500100015002000250030003500400040671H-106L1 wp05Plan View 030006000True Vertical Depth (1500 usft/in)0 4000 8000 12000 16000Vertical Section at 36.16° (2000 usft/in)1H-106 wp1713-3/8" Surface Casing9-5/8" Intermediate Casing4-1/2" Production Casing100020003000400050006000700080009000100001100012000130001400015000160001700018000 1 9 0 0 020000210001H-106L1 wp05Start DLS 17.15 TFO -20.00Start 40.00 hold at 9705.50 MDStart DLS 3.00 TFO 4.34Start DLS 2.00 TFO -108.09Start DLS 2.00 TFO 45.72Start DLS 2.00 TFO 179.89Start DLS 1.00 TFO -177.87Start DLS 2.00 TFO -8.51Start DLS 2.50 TFO 52.89Start DLS 2.00 TFO 131.51Start DLS 2.00 TFO 76.00Start DLS 3.50 TFO -102.19Start DLS 3.50 TFO -74.40Start DLS 3.50 TFO -45.84Start DLS 3.50 TFO -139.42Start DLS 3.25 TFO -109.91Start DLS 3.50 TFO 32.14Start DLS 1.50 TFO 133.46Start DLS 2.00 TFO 178.44Start DLS 2.99 TFO -160.21Start DLS 2.50 TFO 12.16Start DLS 2.00 TFO -29.06Start DLS 2.00 TFO -12.49Start DLS 2.00 TFO 172.98Start DLS 2.00 TFO -126.56Start DLS 2.00 TFO -178.95Start DLS 2.00 TFO 1.05Start DLS 2.00 TFO -13.29Start DLS 2.00 TFO 174.13TD at 21763.91Section View Project: Kuparuk River Unit_1Site: Kuparuk 1H PadWell: Plan: 1H-106 (O33)Wellbore: Plan: 1H-106L1Design: 1H-106L1 wp05 !" 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C & :0 .3 + ) BD 20 %D = ) ++ , . ++ , + , . %&' () * ( ) + , - 2 0 .3 @ < + @ 5 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. 029-23800-00-00224-117 KUPARUK RIVER KRU 1H-106L1 WEST SAK OIL 224-118 WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV U WSAK 1H-106L1Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241180KUPARUK RIVER, WEST SAK OIL - 490150NA1Permit fee attachedYesADL025637, ADL025638, and ADL0256392Lease number appropriateYes3Unique well name and numberYesKUPARUK RIVER, WEST SAK OIL - 490150 - governed by CO 406C4Well located in a defined poolYesApproaches minimum 500' distance to KRU/PBU unit boundary5Well 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)NA18Conductor string providedNA19Surface casing protects all known USDWsNA20CMT vol adequate to circulate on conductor & surf csgNA21CMT vol adequate to tie-in long string to surf csgNoopen hole standalone screens; no cement22CMT 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 approvedYesAnti-collision analysis complete; no major risk failures26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYesMax reservoir pressure is 1945 psig(9.2 ppg EMW); will drill w/ 8.8-9.5 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1538 psig; will test BOPE to 5000 psig initially and 3500 subsequently; 21 day BOPE testing frequency30BOPE 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)NoWell 1H-104 measured 160 ppm H2S in July of 2023. H2S measures required.35Permit can be issued w/o hydrogen sulfide measuresYesTarget reservoir anticipated to be at 9.2 ppg EMW.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate9/25/2024ApprVTLDate10/28/2024ApprADDDate9/17/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 10/29/2024
