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Home My WebLink About224-1497. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU W-01B Establish MI Inj per AA to AIO 25A.028 Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-149 50-029-21866-02-00 16569 Conductor Surface Intermediate Production Liner 4952 80 1995 8664 6751 14072 20" 13-3/8" 9-5/8" 7" x 4-1/2" 5266 28 - 108 28 - 2023 26 - 8690 7399 - 14150 28 - 108 28 - 1972 26 - 5188 4864 - 5269 None 2260 3090 5410 / 7500 None 5020 5750 7240 / 8430 8996 - 13937 4-1/2" 12.6# L-80 24 - 8680 5198 - 5263 Structural 4-1/2" HES TNT Perm Packer 7710 4999 Torin Roschinger Operations Manager Tyson Shriver tyson.shriver@hilcorp.com 907-564-4542 PRUDHOE BAY, POLARIS OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 028263, 028264, 047451 24 - 5187 N/A N/A 2915 955 500 0 1600 2350 N/A 13b. Pools active after work:POLARIS OIL No SSSV Installed 7710, 4999 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 2:03 pm, Apr 08, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.04.08 10:40:11 - 08'00' Torin Roschinger (4662) RBDMS JSB 041025 DSR-4/11/25JJL 5/8/25 ACTIVITY DATE SUMMARY 4/4/2025 T/I/O= 1118/0/160, (WAG SWAP) Pumped 2 bbls 60/40 down FL for FP, Pumped 2 bbls 60/40 down TBG followed by 127 bbls 180* Diesel, *** Job Continued 4/5/25 *** stand by for fluids for 8 hours 45 minutes. 4/5/2025 *** Job Continued from 4/4/25 *** ( Hot Diesel Breakover ) Pumped 32 bbls 180*F diesel down TBG for a total of 160 bbls diesel. Secure well. FWHP=1931/0/171 Daily Report of Well Operations PBU W-01B MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, March 21, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-01B PRUDHOE BAY UN POL W-01B Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/21/2025 W-01B 50-029-21866-02-00 224-149-0 W SPT 4999 2241490 1500 1271 1273 1191 1147 168 184 176 175 INITAL P Sully Sullivan 2/8/2025 Tested to 2000 psi for 500 psi dp. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN POL W-01B Inspection Date: Tubing OA Packer Depth 416 2013 1971 1955IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250209134357 BBL Pumped:3.3 BBL Returned:3 Friday, March 21, 2025 Page 1 of 1 9 9 9 9 9 9 9 9 99 999 99 9 9 9 SVLORVVRIWXELQJSUHVVXUHGXULQJWHVWVHHDWWDFKHGIRUH[SODQDWLRQIURPRSHUDWRUMEU James B. Regg Digitally signed by James B. Regg Date: 2025.03.21 08:54:14 -08'00' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:PB Wells Integrity To:Regg, James B (OGC); PB Wells Integrity; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Cc:Oliver Sternicki; Andrew Ogg Subject:RE: [EXTERNAL] RE: Hilcorp (PBU) February 2025 MIT Forms Date:Thursday, March 20, 2025 6:50:23 PM Mr. Regg, I reviewed the data from the instrumented choke setting, injection temperature, injection rate, injection pressure transmitter on the well slot flowline and W pad produced water header pressure on 02/08/25. In my opinion, there is no explanation in this data for the pressure falloff observed on the tree cap pump truck transmitter recording tubing pressure during the MIT-IA on W-01 conducted between 09:00 and 10:00. The choke was static for weeks before the test. The injection rate / temperature was stable throughout the day. The well slot pressure transmitter recorded 1281 psi at the start of the test and increased to only 1283 psi by the end of the test. The produced water header pressure for the pad was flat. There is no record of pigging on the pad for the two weeks prior to the test in the operator notes. The only explanation would be some kind of gauge malfunction, local blockage to the needle valve on the tree cap or pressure fall off between surface and the perfs during the test. Please let me know if you have any other questions or requests. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Wednesday, March 19, 2025 10:16 AM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: [EXTERNAL] RE: Hilcorp (PBU) February 2025 MIT Forms Please explain the tubing pressure loss in PBU W-01A (126psi) during the 30 minute MIT-IA Jim Regg MEUonly explanation would be some kind of gauge malfunction, local blockage to the needle valve on the tree cap or pressure fall off between surface and the perfs during the test MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, March 13, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-01B PRUDHOE BAY UN POL W-01B Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/13/2025 W-01B 50-029-21866-02-00 224-149-0 N SPT 4999 2241490 3500 983 1643 1683 1669 155 175 155 155 OTHER P Sully Sullivan 1/21/2025 Pre injection MIT-IA to 3500psi with Innovation rig per conditions of approval on PTD. Also tested Tubing (see related inspection) 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN POL W-01B Inspection Date: Tubing OA Packer Depth 10 3712 3611 3577IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250122122615 BBL Pumped:6.4 BBL Returned:6.5 Thursday, March 13, 2025 Page 1 of 1 9 9 9 9 9 9 999 9 9 99 9 5HODWHGWHVWPLW676 Pre injection MIT-IA to 3500psi James B. Regg Digitally signed by James B. Regg Date: 2025.03.13 15:34:40 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, March 13, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-01B PRUDHOE BAY UN POL W-01B Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/13/2025 W-01B 50-029-21866-02-00 224-149-0 N SPT 4999 2241490 3500 0 3713 3576 3528 155 155 155 155 OTHER P Sully Sullivan 1/21/2025 Pre injection MIT-T to 3500psi with Innovation rig per conditions of approval on PTD. Also tested IA (see related inspection) 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN POL W-01B Inspection Date: Tubing OA Packer Depth 0 93 104 99IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250121145313 BBL Pumped:1.8 BBL Returned:1 Thursday, March 13, 2025 Page 1 of 1 9 9 9 9 9 9 999 9 9 9 9 9 9 9 UHODWHGWHVWPLW676 Pre injection MIT-T James B. Regg Digitally signed by James B. Regg Date: 2025.03.13 15:31:35 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/2/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250302 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24 MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Please include current contact information if different from above. T40161 T40161 T40162 T40163 T40164 T40165 T40166 T40167 T40168 T40169 T40170 T40171 T40172 T40173 T40174 T40175 T40176 T40177 T40178 T40179 PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.03 10:15:14 -09'00' David Douglas Hilcorp North Slope, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 02/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: PBU W-01B PTD: 224-149 API: 50-029-21866-02-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING (12/29/2024 to 01/12/2025) x AGR, ABG & BaseStar Gamma Ray, EWR-M5 and StrataStar Resistivity, Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Geosteering and EOW Report SFTP Transfer – Main Folders: PBU W-01B LWD Subfolders: PBU W-01B Geosteering Subfolders:g Please include current contact information if different from above. 224-149 T40068 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.07 14:12:07 -09'00' 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. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: HAK PBU W-01B (PTD: 224-149) 9-5/8" Casing Test and FIT Date:Thursday, January 9, 2025 3:53:28 PM Attachments:PBW W-01B 9.625 Csg test-FIT 1-8-2025.pdf From: Joseph Engel <jengel@hilcorp.com> Sent: Thursday, January 9, 2025 2:55 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: HAK PBU W-01B (PTD: 224-149) 9-5/8" Casing Test and FIT Jack – Attached is the casing test and FIT for 9-5/8” casing on W-01B. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CASING AND LEAK-OFF FRACTURE TESTS Well Name:PPBW W-01B Date:1/8/2025 Csg Size/Wt/Grade:9.625" 40# L -80 Supervisor:Mo n tag u e/Menapac e Csg Setting Depth:8,690 TMD 5188 TVD Mud Weight:9.2 ppg LOT / FIT Press =755 psi LOT / FIT =12.00 ppg Hole Depth =8720 md Fluid Pumped=1.7 Bbls Volume Back =1.6 bbls Estimated Pump Output:0.062 Barrels/Stroke ## LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here HHere Here HHere ->00 ->00 ->56060 ->10 336 ->10 205 145 ->20 630 ->15 352 147 ->30 916 ->20 496 144 ->40 1204 ->25 632 136 ->50 1501 ->30 760 128 ->60 1796 -> ->70 2080 -> ->80 2384 -> ->90 2656 -> ->94 2730 -> -> -> -> -> -> Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 760 ->0 2730 ->1 666 ->1 2720 ->2 576 ->2 2715 ->3 532 ->3 2711 ->4 504 ->4 2708 ->5 491 ->5 2705 ->6 481 ->10 2699 ->7 474 ->15 2691 ->8 468 ->30 2680 ->9 464 -> ->10 460 -> -> -> -> -> -> -> 0 5 10 15 20 25 30 0 10 20 30 40 50 60 70 80 90 94 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 102030405060708090100Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 760 666 576 532504491481474468464460 273027202715271127082705 2699 2691 2680 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UN POL W-01B JBR 02/10/2025 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:2 4-1/2", 5" & 9-5/8" joints. Outermost kill FP-greased for a pass. Upper Kelly FP-greased for a pass. Test Results TEST DATA Rig Rep:Sture/EvansOperator:Hilcorp North Slope, LLC Operator Rep:Lott/Menapace Rig Owner/Rig No.:Hilcorp Innovation PTD#:2241490 DATE:1/6/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM250106184026 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 1815 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 FP Lower Kelly 1 P Ball Type 2 P Inside BOP 1 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"x5-1/2"P #2 Rams 1 Blinds P #3 Rams 1 9-5/8"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"FP Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1400 200 PSI Attained P28 Full Pressure Attained P116 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P6@2295 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 P12 #1 Rams P9 #2 Rams P9 #3 Rams P9 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9999 9 9 9 9 9 9 9 Upper Kelly FPOutermost kill FP FP FPUpper Kelly Kill Line Valves CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:Revised Program Required for PTD 224-149 W-01B Date:Monday, December 9, 2024 10:26:00 AM Attachments:PBW W-01B Sidetrack Drilling Program_V2.pdf From: Joseph Engel <jengel@hilcorp.com> Sent: Thursday, December 5, 2024 2:08 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] Revised Program Required for PTD W-01B Jack – Thanks for the phonecall earlier today. Attached is the revised program per your questions. Comments below in red. Let me know if you have any other questions. -Joe From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Wednesday, December 4, 2024 1:22 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Sean McLaughlin <sean.mclaughlin@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Christianson, Grace K (OGC) <grace.christianson@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL] Revised Program Required for PTD W-01B Joe – After reviewing the PTD package for W-01B, please submit a revised program addressing the following: Include schematic of the current condition of the well upon arrival. Included in section 6 Is there arctic pack? If so, what is the plan circulate it out/ handle it? Records show no arctic pack in the OA, see section 10.7 What is your contingency if the casing doesn’t pull free? See section 10.12 Final Schematic needs to be accurate – include sacrificial liner on schematic and accurate cement tops Updated and included in section 6 Step 16.35 – States cement to 9-5/8” casing shoe. Diagram shows cement to liner top. Which is correct? Do you want cement up to liner top for this injection well. Ensure displacement volumes match. Cement is planned to 9-5/8” shoe with 30% excess. Schematic updated to match. Step 16.36 – conflict in displacement volume for liner if liner running tool is at 4- 1/2” x 7” XO Corrected. See section 17.24 (note, numbering has been updated in attached program) Step 16.36 – incorrect DP displacement volume Corrected. See section 17.24 (note, numbering has been updated in attached program) Step 16.36 – total disp volume incorrect Corrected. See section 17.24 (note, numbering has been updated in attached program) Step 18.13 – MITIA needs be witnessed since injector (25.412.e) Included in section 18.13 Page 45 – Wellhead diagram needs to be legible Wellhead is from 1988, unfortunately that is the only drawing we have. Diagram has been annotated and updated. Thanks, Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Prudhoe Bay West (PBU) W-01B Drilling Permit Version 2 12/4/2024 Table of Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................5 5.0 Internal Reporting Requirements................................................................................................6 6.0 Pre-Window Plugged & Planned Wellbore Schematic ..............................................................7 7.0 Drilling / Completion Summary.................................................................................................10 8.0 Mandatory Regulatory Compliance / Notifications..................................................................11 9.0 MIRU & Test BOPE....................................................................................................................14 10.0 Pull Tubing String, Cut & Pull 9-5/8” .......................................................................................16 11.0 Set Whipstock, Mill 12-1/4” Window.........................................................................................18 12.0 Drill 12-1/4” Hole Section............................................................................................................21 13.0 Run 9-5/8” Intermediate Casing.................................................................................................24 14.0 Cement 9-5/8” Casing..................................................................................................................27 15.0 Drill 8-1/2” Hole Section..............................................................................................................30 16.0 Open Hole P&A Kit for PA ........................................................................................................35 17.0 Run & Cement 7” x 4-1/2” Injection Liner...............................................................................38 18.0 Run Upper Completion/ Post Rig Work....................................................................................45 19.0 Innovation Rig BOP Schematic..................................................................................................48 20.0 Wellhead Schematic.....................................................................................................................49 21.0 Days Vs Depth..............................................................................................................................50 22.0 Formation Tops & Information..................................................................................................51 23.0 Anticipated Drilling Hazards......................................................................................................53 24.0 Innovation Rig Layout.................................................................................................................57 25.0 FIT Procedure..............................................................................................................................58 26.0 Innovation Rig Choke Manifold Schematic ..............................................................................59 27.0 Casing Design...............................................................................................................................60 28.0 MASP............................................................................................................................................61 29.0 Spider Plot (NAD 27) (Governmental Sections)........................................................................63 30.0 Surface Location..........................................................................................................................64 Page 2 Prudhoe Bay West W-01B SB Injector Drilling Procedure 1.0 Well Summary Well PBU W-01B Pad Prudhoe Bay W Pad Planned Completion Type 4-1/2” Injection Target Reservoir(s)Schrader Bluff OBd Sand Planned Well TD, MD / TVD 16,549’ MD / 5011’ TVD PBTD, MD / TVD 14,250’ MD / 5278’ TVD Surface Location (Governmental)1157' FNL, 1189' FEL, Sec 21, T11N, R12E, UM, AK Surface Location (NAD 27)X= 612,049, Y= 5,959,100 Top of Productive Horizon (Governmental)1451' FNL, 794' FEL, Sec 22, T11N, R12E, UM, AK TPH Location (NAD 27)X= 617,728 , Y= 5,958,892 BHL (Governmental)2260' FNL, 1094' FEL, Sec 26, T11N, R12E, UM, AK BHL (NAD 27)X= 622,811, Y= 5,952,884 AFE Number 241-00159 AFE Drilling Days 31 AFE Completion Days 4 Maximum Anticipated Surface Pressure - Intermediate 1763 psig Maximum Anticipated Surface Pressure - Production 1815 psig Maximum Anticipated Pressure (Downhole/Reservoir)2348 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL:26.5 ft + 50.61 ft = 77.11 ft GL Elevation above MSL:53.81 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay West W-01B SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay West W-01B SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in)Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20”19.25 ---X-52 Weld *17-1/2”13-3/8”12.415 12.259 14.375 68 L-80 BTC 5,020 2,260 1,556 12-1/4”9-5/8”8.835 8.679 10.625 40 L-80 TXP 5,750 3,090 916 8-1/2”7”6.276 6.151 7.656 26 L-80 563 7,240 5,410 604 4-1/2”3.958 3.833 5.200 12.6 L-80 563 8,430 7,500 288 Tubing 4-1/2”3.958 3.833 5.000 12.6 L-80 JFEBear 8,430 7,500 288 *Existing hole section and casing string Page 5 Prudhoe Bay West W-01B SB Injector Drilling Procedure 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Int & Production 5”4.276”3.25”6.625”19.5 S-135 NC50 30,730 34,136 560klb Page 6 Prudhoe Bay West W-01B SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Tyson Shriver 907.564.4542 tyson.shriver@hilcorp.com Geologist Ben Rickards 210.287.7711 benjamin.rickards@hilcorp.com Reservoir Engineer Tim Davis 907.564.4886 tidavis@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 7 Prudhoe Bay West W-01B SB Injector Drilling Procedure 6.0 Pre-Rig, Pre-Window, & Planned Wellbore Schematic Pre rig / Post P&A Sundry Schematic Page 8 Prudhoe Bay West W-01B SB Injector Drilling Procedure Pre-Window Schematic Page 9 Prudhoe Bay West W-01B SB Injector Drilling Procedure Proposed Schematic Page 10 Prudhoe Bay West W-01B SB Injector Drilling Procedure 7.0 Drilling / Completion Summary PBU W-01B is a sidetrack injector planned to be drilled in the Schrader Bluff OBd sands. W-01B is part of a multi-well program targeting the Schrader Bluff sand on PBU W-pad The parent bore, W-01A, is a shut-in vertical injection well. The Ivishak and Schrader Bluff reservoirs will be abandoned prior to the rig’s arrival on the well, operations covered on a separate sundry. The directional plan is 12-1/4” intermediate hole and 9-5/8” casing string set into the top of the Schrader Bluff OBd sand. An 8-1/2” lateral section will be drilled which includes an appraisal tail that will extend across an east-west fault to help determine future development opportunities. The tail will be drilled outside of the participating area boundary and will be abandoned via a cemented open hole P&A kit prior to running the lower completion. An injection liner will be run and cemented in the remaining open hole section, followed by 4-1/2” tubing. The well will not be pre-produced The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately December 10, 2024, pending rig schedule. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U & Test 13-5/8” BOPE 3. Pull 4-1/2” Tubing, cut & pull 9-5/8” casing 4. Set 13-3/8” whipstock, mill 12-1/4” window 5. Drill 12-1/4” hole to TD 6. Run and cement 9-5/8” casing 7. Drill 8-1/2” lateral to well TD 8. Run and cement 7” x 4-1/2” liner 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering), Neu/Den Page 11 Prudhoe Bay West W-01B SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU W-01B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 12 Prudhoe Bay West W-01B SB Injector Drilling Procedure AOGCC Regulation Variance Requests: Hilcorp would like to request a variance from 20 AAC 25.412.(b)which states: “A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone.” In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at the OBd production interval at ~86 degrees inclination. In order to make the ball and rod we land to set the production packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees inclination. The MD we currently have planned for 70 degrees is at ~7750’ MD. The X-nipple below the production packer will be set at ~7650’ MD and the production packer will be ~50’ MD above the X nipple which puts it at ~7600’ MD / ~4987’ TVD. The intermediate casing shoe is planned at ~8575’ MD / ~5184’ TVD which means the planned packer depth is ~975’ MD away. From a TVD standpoint, the production tubing packer is ~197’ TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader Bluff sand, and the injection packer set inside the intermediate casing, injection fluids will be confined to the Schrader bluff sands. Hilcorp would like to request a variance from AIO 25A Rule #4 which states: “b. Within three months of start of injection in a new or converted injector, a step rate test and surveillance log must be run for detection of fluids moving out of the approved injection stratum.” The Polaris pool is unique among nearby Schraeder Bluff oil pools in its requirement to perform step-rate tests and surveillance logs on all new or converted injectors to justify the maximum injection pressures for a given well. The original justification for this change that was shared with the Commission in November 2003 were step-rate tests on W-212 and S-215 which indicated injection pressures up to 0.8 psi/ft caused no detectable migration of fluids outside of approved strata. To date, all step-rate tests performed on injectors in the Polaris oil pool have indicated that the established injection gradient of 0.8 psi/ft does not cause fluids to migrate out of zone. For W-01B, Hilcorp is requesting that 0.8 psi/ft be established as the injection limit for this well without conducting the step-rate test and surveillance log listed in AIO 25A Rule #4. Page 13 Prudhoe Bay West W-01B SB Injector Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc 250/3,000 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs and changing rams x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 14 Prudhoe Bay West W-01B SB Injector Drilling Procedure 9.0 MIRU & Test BOPE 9.1 W-01A will be the parent well for this sidetrack. Ensure to review the attached surface plat and make sure the rig is over appropriate well. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Level pad and ensure enough room for layout of rig footprint and R/U. 9.4 Rig mat footprint of rig. 9.5 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.6 Mud loggers WILL NOT be used on either hole section. 9.7 Give AOGCC 24hr notice of BOPE test, for test witness. 9.8 Install BPV, ND tree and THA 9.9 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve. 9.10 RU MPD RCD and related equipment 9.11 Run 5” BOP test plug 9.12 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 3-1/2” test joint x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech Page 15 Prudhoe Bay West W-01B SB Injector Drilling Procedure 9.13 RD BOP test equipment 9.14 Dump and clean mud pits, send spud mud to G&I pad for injection. 9.15 Mix 9.4 LSND for well work operations 9.16 Set wearbushing in wellhead 9.17 If needed, rack back as much 5” DP in the derrick as possible to be used when drilling future hole section. 9.18 Ensure 5” liners in mud pumps x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 16 Prudhoe Bay West W-01B SB Injector Drilling Procedure 10.0 Pull Tubing String, Cut & Pull 9-5/8” 10.1 RU tubing handling equipment x Tubing is 4-1/2” x Tubing cut depth: ~2,700’, confirm with pre rig well work report 10.2 PU landing joint or spear and engage tubing hanger 10.3 Backout lock down screws 10.4 Pull tubing hanger with landing joint to the rig floor, have appropriate protectors ready. 10.5 If necessary, circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. 10.6 POOH laying down 4-1/2” tubing. RD tubing handling equipment 10.7 MU Baker or Yellowjacket mechanical cutter, RIH to TOC and cut 9-5/8” casing at 2,120’ MD. x Note: The operator performed a 9-5/8” x 13-3/8” downsqueeze with 300 sx of 14.0 ppg Permafrost ‘C’ cement followed by 150 bbls of crude during initial completion in 1988. A CBL of the 9-5/8” casing was pulled while performing an RWO in 2022 which showed a clear TOC at 2,650’ with stringers up to 2,200’. 10.8 POOH and inspect mechanical cutter for wear. LD mechanical cutter x If inspection indicates, RIH with backup cutter and repeat. 10.9 RU casing handing equipment x Casing is 9-5/8” 47# L-80 NSCC 10.10 PU spear and engage casing hanger 10.11 Back out lock down screws 10.12 Pull casing free x If casing does not pull free, contingent cutting and fishing operations will take place to pull the 9-5/8” casing. Any changes will be discussed with AOGCC prior to implementation. 10.13 Circulate at least 1.5x BU after pulling casing free. If desired circulate a sweep surface to surface to clean further. Fluid behind the 9-5/8” is dead crude. 150 bbls were pumped from surface. 10.14 POOH laying down the 9-5/8” casing x Note: stand-off clamps were installed on every 3rd joint of 9-5/8” casing. Page 17 Prudhoe Bay West W-01B SB Injector Drilling Procedure 10.15 RD casing handling equipment Page 18 Prudhoe Bay West W-01B SB Injector Drilling Procedure 11.0 Set Whipstock, Mill 12-1/4” Window 11.1 MU 13-3/8” casing scraper assembly and RIH to top of 9-5/8” cut 11.2 RU casing testing equipment and PT 13-3/8” casing to 2000 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 11.3 If unable to get passing PT of the 13-3/8”, P/U 13-3/8” mechanical plug, RIH to set depth (TBD based on cut depth and CCL) & set same 11.4 Whipstock Set Depth Information x Planned TOW: 2025’ x WS should be set to avoid a collar while milling the window, casing tally available in O- Drive x Drilling Foreman, Whipstock hand and drilling engineer to agree on the set depth 11.5 MU 12-1/4” mill/whipstock assembly as per WIS tally x MU HWDP, string magnets and float sub x Ensure magnets are in trough, under shakers and flow area to capture metal shavings circulated 11.6 Install MWD and orient. Rack back mill assembly x Ensure a dedicated MWD is available for the orientation of the whipstock 11.7 Verify offset between WD, and the whipstock tray, witnessed by the Drilling Foreman, MWD/DD and WIS rep. Document and record offset in well file. 11.8 Slowly run in the hole as per fishing Rep. 11.9 Run in hole at 1 ½ to 2 minutes per stand, or per contractor rep. Ensure work string is stationary prior to setting the slips to avoid weakening the shear bolt and prematurely setting the anchor. 11.10 Shallow test MWD at first drill pipe fill up depth. 11.11 Stop at least 30-45’ above planned set depth, obtain survey with MWD. 11.12 Milling fluid will be 9.4 ppg LSND 11.13 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 11.14 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30q LOHS – Consult with milling hand Page 19 Prudhoe Bay West W-01B SB Injector Drilling Procedure 11.15 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 15L to 45L, target is 30 LOHS Hole Angle at window interval (@ 2,025’, 22° inc, 103° azi). Sidetrack tangent section is 60q inclination and 83q azimuth 11.16 Once whipstock is in desired orientation, set WS per Baker Hughes rep. 11.17 CBU and confirm 9.4 ppg MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings x Visc: 40-60, YP: 18-20 11.18 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 11.19 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 11.20 Clean catch trays and ditch magnets frequently while milling window. 11.21 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 11.22 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 11.23 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 11.24 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 45L 15L Page 20 Prudhoe Bay West W-01B SB Injector Drilling Procedure 11.25 Pull back into 13-3/8” casing and perform FIT to 11.5 pg EMW, Chart Test x 13-3/8” casing is cemented. Open hole weak point is the top of the window at ~ 2025’ MD, 1973’ TVD x 11.5 Fit provides a > 25 bbl KT based upon 9.4 ppw MW, 8.46 PP (swabbed kick at 9.4 BHP) x If 11.5 is not achieved, contact drilling engineer. 11.26 POOH & LD milling BHA. Gauge mills for wear. 11.27 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. Page 21 Prudhoe Bay West W-01B SB Injector Drilling Procedure 12.0 Drill 12-1/4” Hole Section 12.1 P/U 12-1/4” motor drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the hole section. 12.2 RIH with 12-1/4” BHA, to top of whipstock. Shallow test MWD at the first fill up point 12.3 Orient directional motor same as whipstock orientation and slide through window with no pumps or rotary x Confirm set orientation of whipstock, and have BHA match 12.4 Displace wellbore to 9.4 ppg LSND x 9.4 ppg due to hydrates, free gas and potential for Cretaceous over pressure (although none has been see at W pad, be aware from 4500’ TVD and deeper) 12.5 Drill 12-1/4” hole section to section TD, in the Schrader OBd sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Efforts should be made to minimize dog legs in the intermediate hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from over melting hydrates x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off.Wood has been observed across shakers during the interval TVD. x Gas hydrates are have been seen on W pad. In PBW they have been encountered typically around 1660’ TVD (Base of Perm) to 3400’ TVD (Top Ugnu) and below. Be prepared for hydrates: x Keep mud temperature as cool as possible, Target 60-70*F. Page 22 Prudhoe Bay West W-01B SB Injector Drilling Procedure x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold pre-made mud on trucks ready. x Drill through hydrate sands and quickly as possible, do not backream. x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Intermediate Hole AC, CF <1.0 : x There are no wells with a CF less than 1.0 12.6 12-1/4” hole mud program summary: x Density:Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. MW for free gas and hydrates based upon offset wells Depth Interval MW (ppg) Window - TD 9.4+ (For Hydrates/Free Gas based on offset wells and cretaceous injection mitigation) x PVT System:PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology:Aquagel and Barazan D+ should be used to maintain rheology. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss:DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 23 Prudhoe Bay West W-01B SB Injector Drilling Procedure System Type:8.8 – 9.8 ppg LSND Properties: Section Density LSYP PV YP MPT API FL pH Temp Intermediate 8.8 – 9.8 4-6 15 - 30 25-45 <8 <10 8.5 – 9.0 70 F 12.7 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 12.8 RIH to bottom, proceed to BROOH to window x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.9 CBU x2 at the 13-3/8” shoe and clean casing with high visc sweeps 12.10 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at window for any higher than expected pressure seen 12.11 Orient BHA and pull through window with no pumps or rotary 12.12 TOOH and LD BHA Page 24 Prudhoe Bay West W-01B SB Injector Drilling Procedure 13.0 Run 9-5/8” Intermediate Casing 13.1 Install 9-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with test joint. RD testing equipment. 13.2 R/U 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 13.3 P/U shoe joint, visually verify no debris inside joint. 13.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” , 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring 9-5/8” Float Collar x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment 13.5 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x Bowspring Centralizers only x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to TOC x Verify depth of uppermost significant oil with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. 9-5/8” 40# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”18860 20960 23060 Page 25 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 26 Prudhoe Bay West W-01B SB Injector Drilling Procedure 13.6 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 13.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.8 Slow in and out of slips. 13.9 Lower casing to setting depth. Confirm measurements. 13.10 Have slips staged in cellar, along with necessary equipment for the operation. 13.11 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 27 Prudhoe Bay West W-01B SB Injector Drilling Procedure 14.0 Cement 9-5/8” Casing 14.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface if seen. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 14.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 14.5 Fill surface cement lines with water and pressure test. 14.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail, TOC brought to 500’ above the Schrader Bluff x Calculations based upon cement 500’ MD above Schrader NB Sand, 6,808’ MD, x NB Top: 7,308’ MD. x Note: TOC will be adjusted to 500’ above uppermost significant oil Estimated Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (8575-6808)' x 0.0558 bpf x 1.4 = 138.0 774.1 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 147.1 825.2 711.4Tail Page 28 Prudhoe Bay West W-01B SB Injector Drilling Procedure Cement Slurry Design (Single Stage Cement Job): 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with mud out of mud pits x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. 14.12 Displacement calculation: = (8,575’-120’) x .0758 bpf = = 641 bbls 14.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 14.14 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. 14.15 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, before consulting with Drilling Engineer. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 29 Prudhoe Bay West W-01B SB Injector Drilling Procedure 14.17 9-5/8” will be set on slips. Make initial cut on 9-5/8”, ld cut joint, make final cut. Dress off, install tubing spool. 14.18 CBL evaluation of intermediate cement job will be performed after production liner is set and cemented. x This will allow sufficient time for cement to reach compressive strength Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 30 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH to TOC above the shoe track. Note depth TOC tagged on morning report. 15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. 15.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum required to drill ahead x 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP) 15.7 POOH and LD cleanout BHA 15.8 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 NC50. x Run a solid float sub in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 Page 31 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.9 8-1/2” hole section mud program summary: x Density:Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration:It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology:Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPH T Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10%<8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 32 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.10 TIH with 8-1/2” directional assembly to bottom 15.11 Install MPD RCD 15.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid x Density may change based upon TD of prior hole section 15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Reservoir plan is to stay in OBd sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff OBd Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C, CF < 1.0: x There are no wells with a CF < 1.0 15.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. Page 33 Prudhoe Bay West W-01B SB Injector Drilling Procedure x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.17 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD 15.18 Displace 1.5 OH + liner volume with viscosified brine. x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 Monitor the returned fluids carefully while displacing to brine. 15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.23 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen Page 34 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.24 POOH and LD BHA. 15.25 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. x Only LWD open hole logs are planned for the hole section. There will not be any additional logging runs conducted. Page 35 Prudhoe Bay West W-01B SB Injector Drilling Procedure 16.0 Open Hole P&A Kit for PA 16.1 Note: W-01B lateral plan has an appraisal section drilled beyond the AIO/PA boundary. Before the cemented injection liner can be ran, the section of the lateral outside of the PA is to be plugged back with an open hole P&A kit. Below is email correspondence (10/25/24) with AOGCC regarding this plan prior to approval. Page 36 Prudhoe Bay West W-01B SB Injector Drilling Procedure 16.2 Plan outline of lateral x AIO Boundary: 15,220’ MD x Fault: ~14,446’MD x Planned OH P&A Packer Depth: 14,200’ MD 16.3 MU Baker OH P&A Kit consisting of: x 4-1/2” Float Shoe x 4-1/2” Float Collar x ~2,348’ of 4-1/2” sacrificial liner x 4-1/2” ECP x Liner Setting Sleeve, HRDE 16.4 RIH with OH P&A Kit on 5” DP to TD 16.5 Break circulation Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Confirm all pressures with Baker 16.6 Prior to proceeding with cement job, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.7 Circulate and condition mud for cement job 16.8 RU Lines for cement job if not already done so Page 37 Prudhoe Bay West W-01B SB Injector Drilling Procedure 16.9 Pump 30 bbls of 11ppg tuned spacer 16.10 Mix and pump cement as per plan 16.11 Cement volume based on OH annular volume * open hole excess (30%) + filling the sacrificial liner with cement. Job will consist of single slurry, TOC brought to the ECP setting depth, ~ 14,200’ MD 16.12 After pumping cement, drop dart and displace cement with mud out of mud pits. x 14,200’ * .0171 bpf (5” dp capacity) x = 243 bbl 16.13 Pressure up to inflate the ECP. Continue pressuring up to release the HRDE Running Tool 16.14 Bleed DP Pressure, PU running tool above ECP 16.15 Break Circulation and circulated excess cement to surface, have blackwater on hand in pits 16.16 POOH, LD running tool Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8-1/2" OH x 4-1/2" (16,548 - 14,200)' x 0.0505 bpf x 1.3 = 154.2 865.1 4-1/2" Liner Volume 2348' x 0.0152 bpf = 35.7 200.3 Total Tail 189.9 1065.3 918.4Tail Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 38 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.0 Run & Cement 7” x 4-1/2” Injection Liner 17.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints 17.2 Well control preparedness: In the event of an influx of formation fluids while running the 7” x 4-1/2” liner, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint with x 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW. x -OR- x 7“ XO installed on bottom, TIW valve in open position on top, 7” handling joint above TIW. x These joints shall be fully M/U and available prior to running the first joint of 4-1/2” liner or 7” liner, respectively. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 17.3 R/U liner running equipment. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 17.4 Run 4-1/2” injection liner x Use API Modified or “Best O Life 2000 AG”thread compound. Confirm pipe dope with TRS. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Install jewelry as per the Running Order (From Completion Engineer post TD). o ~13 NCS Sleeves, 1 sleeve every ~450’MD x Centralization: 1 per joint, solid body centralizers x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Liner Torque – ftlbs OD PPF Connection Minimum Optimum Maximum Yield Torque 4-1/2 12.6 Hydril 563 3200 3700 5600 12600 7 26 Hydril 563 7800 9400 13700 39000 Page 39 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 40 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 41 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.5 RU 7” running equipment and run 7” 26# H563 section x ~1,175’ total. TOL ~7,400’ MD x Centralized ½ joints, bowspring centralizers 17.6 Ensure to run enough 7” liner is provide for sufficient overlap inside 9-5/8” casing tubing packer completion. Tentative liner set depth ~ 7,400’ MD. x 7” will be ran under the liner hanger for the production packer. Confirm with completion engineer. 17.7 Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 17.8 Before picking up Baker Flex Lock liner hanger / ZXP packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.9 M/U Baker Flex Lock liner hanger and ZXP liner top packer to liner. x Confirm with OE any 7” joints between liner top packer and 4-1/2” liner for tubing packer setting depth x Liner running tool extension will need to be ran so liner wiper darts are positioned at the 7” x 4-1/2” XO 17.10 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.11 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” DP/HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. x Use HWDP as needed for running liner 17.12 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 17.14 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. Page 42 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.15 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.16 Rig up to pump down the work string with the rig pumps. 17.17 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Confirm all pressures with Baker. 17.18 Prior to proceeding with cement job, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 17.19 Circulate and condition mud for cement job 17.20 RU Lines for cement job if not already done so 17.21 Pump 30 bbls of 11ppg tunes spacer 17.22 Mix and pump cement as per plan 17.23 Cement volume based on OH annular volume + open hole excess (30%). Job will consist of single slurry, TOC brought to the 9-5/8” casing shoe, ~ 8575’ MD Cement Slurry Design (Single Stage Cement Job) 17.24 After pumping cement, drop dart and displace cement with mud out of mud pits. x Displacement calculations are based upon x 5” dp from surface to liner top (7400’ MD) x 2-7/8” liner running tool extension from liner top to 7” x 4-1/2” XO (8575’ MD) x 2-7/8” 6.5# EUE x Due to liner wiper plug effective diameter x 4-1/2” from 7” x 4-1/2” XO to PBTD of 14200’ MD Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8-1/2" OH x 4-1/2" (14,200 - 8,575)' x 0.0505 bpf x 1.3 = 369.3 2071.8 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 371.1 2081.9 1189.6Tail Tail Slurry System SoluCem Density 15 lb/gal Yield 1.75 ft3/sk Mixed Water 7.88 gal/sk Page 43 Prudhoe Bay West W-01B SB Injector Drilling Procedure x Displacement Calculation: x 7400’ * .0171 bpf (5” dp capacity) = 126.6 bbl (DP volume) x (8575 – 7400) * .0058bpf (2-7/8” capacity) = 6.8bbl x (14,200’-120’-8575’) * .0152bpf (4-1/2” cap) = 83.7 bbl (Liner volume) x = 217.1 bbl 17.25 Monitor returns and pump pressure closely while displacing, slow donw pumps when dart latches onto liner wiper plug and when plug lands 17.26 Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on well report: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 17.27 Continue pressuring up to 2,600 psi to set the Flex lock liner hanger. Hold for 5 minutes. Slack off 20K lbs on the Flex Lock liner hanger to ensure the HRDE setting tool is in compression for release from the liner hanger/packer. Continue pressuring up 4,000 psi to set the ZXP liner top packer and release the HRDE running tool. 17.28 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 17.29 PU with running tool above Liner top packer and circulate bottoms up to remove any excess cement from around the running tool. 17.30 Reengage liner running tool. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. Page 44 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.31 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 17.32 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 17.33 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 45 Prudhoe Bay West W-01B SB Injector Drilling Procedure 18.0 Run Upper Completion/ Post Rig Work 18.1 RU Slickline and perform CBL from liner top (~7400’ MD) to 1000’ above calculated TOC of 9- 5/8” casing x Calculated TOC on 9-5/8” with excess ~ 6808’ MD, w/o excess ~6,100’ MD 18.2 RU to run 4-1/2”, 12.6#, L-80 JFEBear tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, L-80 JFEBear x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 18.3 PU, MU and RIH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Tubing Jewelry to include: x 2x X Nipple x 1x Production Packer i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval. x 1x X Nipple x XXX joints, 4-1/2”, 12.6#, L-80 JFEBear x WLEG Page 46 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 47 Prudhoe Bay West W-01B SB Injector Drilling Procedure 18.4 PU and MU the tubing hanger. 18.5 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.6 Land the tubing hanger and RILDS. Lay down the landing joint. 18.7 Install 4” HP BPV. ND BOP. Install the plug off tool. 18.8 NU the tubing head adapter and NU the tree. 18.9 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.10 Pull the plug off tool and BPV. 18.11 Reverse circulate the well over to corrosion inhibited source water follow diesel to freeze protect for both tubing and IA to 2,500’ MD. Open well at surface / rig up jumper and allow freeze protect to U-tube between tubing and IA. 18.12 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure 18.13 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Record and notate all pressure tests (30 minutes) on chart. x Notify AOGCC 24hrs prior to test for opportunity to witness 18.14 Bleed both the IA and tubing to 0 psi. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. x Work with Ops Engineer and Well Integrity to complete 10-426 Form for the initial MIT-T and MIT-IA. This form must be completed regardless of AOGCC witness. 18.16 RDMO Innovation i. POST RIG WELL WORK x Slickline o Pull B&R and RHC body x Coil o Contingent: Pull B&R and RHC body if SL unable to o Shift injection sleeves open o Contingent: Pump 15% HCl to breakdown cement behind injection sleeve x Ops o Put well on injection o AOGCC witnessed MIT-IA once injection is stable Page 48 Prudhoe Bay West W-01B SB Injector Drilling Procedure 19.0 Innovation Rig BOP Schematic Page 49 Prudhoe Bay West W-01B SB Injector Drilling Procedure 20.0 Wellhead Schematic Wellhead is 1988 McEvoy 13-5/8” 5K Page 50 Prudhoe Bay West W-01B SB Injector Drilling Procedure 21.0 Days Vs Depth Page 51 Prudhoe Bay West W-01B SB Injector Drilling Procedure 22.0 Formation Tops & Information Reference Plan:CommentsKOP 2,0251,973.4-1896.31SV4 Gas Hydrates 2,0912,034.7-1957.57 895 8.46SV3 Gas Hydrates 2,7862,559.3-2482.18 1126 8.46SV1 Gas Hydrates 3,8373,096.9-3019.78 1363 8.46Ugnu 4A Heavy Oil 4,6133,491.1-3413.99 1536 8.46Heavy oil in Ugnu sands possibleUG3 Heavy Oil 5,2943,837.0-3759.93 1688 8.46Ugnu MA Heavy Oil 6,7734,589.1-4511.98 2019 8.46NB Water 7,3084,858.8-4781.72 2138 8.46OA Top Oil 7,6084,990.2-4913.13 2196 8.46Oba Top Oil 7,7695,048.1-4971.02 2221 8.46Previous injection/productionObc Top Oil 8,0745,130.2-5053.13 2257 8.46Previous injection/productionObd Top Oil 8,5735,184.3-5107.20 2281 8.46Previous injection/productionFault Oil 9,300Fault Oil 14,300End of completed productive sectionObd Top Oil 14,8265,330.5-5253.40Obd Top Oil 15,8585,337.9-5260.76Obc Top Oil 16,041 5279.61 -5202.50Oba Top Oil 16,2045,209.3-5132.21OA Top Oil 16,3015,160.1-5083.01NB Oil 16,5265,024.1-4946.99EASTINGEst.PressureGradientEXPECTEDFLUIDMD(FT)TVD(FT)TVDSS(FT)NORTHINGW-01B wp08ANTICIPATED FORMATION TOPS & GEOHAZARDSTOP NAMELITHOLOGY Page 52 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 53 Prudhoe Bay West W-01B SB Injector Drilling Procedure 23.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates/Free Gas Gas hydrates have been seen on PBU W Pad. Be prepared for them. They have been reported between 1800’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free penetrations of offset wells. x Be prepared for gas hydrates o Keep mud temperature as cool as possible, Target 60-70*F o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready o Drill through hydrate sands and quickly as possible, do not backream. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Cretaceous Over Pressure: W-Pad does not have a history of over-pressure in the cretaceous interval (4500-5300’ TVD). However, as a precaution ensure MW is above 9.0. Be prepared while drilling this interval. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x No Wells with CF < 1.0 Page 54 Prudhoe Bay West W-01B SB Injector Drilling Procedure Wellbore stability (Permafrost, running sands and gravel Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Maintain mud parameters and increase MW to combat running sands and gravel formations. Stuck pipe, wood chunks over shakers and other hole stability issues are specific to W pad. Be prepared and review Pad Data Sheet. Bad see pad data sheet H2S: Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 55 Prudhoe Bay West W-01B SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 56 Prudhoe Bay West W-01B SB Injector Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific A/C: x No wells with CF < 1.0 Page 57 Prudhoe Bay West W-01B SB Injector Drilling Procedure 24.0 Innovation Rig Layout Page 58 Prudhoe Bay West W-01B SB Injector Drilling Procedure 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 59 Prudhoe Bay West W-01B SB Injector Drilling Procedure 26.0 Innovation Rig Choke Manifold Schematic Page 60 Prudhoe Bay West W-01B SB Injector Drilling Procedure 27.0 Casing Design 12-1/4"Mud Density:9.4 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1763 psi (see attached MASP determination & calculation) 1815 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8"4-1/2" 0 8,575 0 5,184 8,575 14,200 *completed MD 5,184 5,273 *completed TVD 8,575 5,625 40 12.6 L-80 L-80 TXP H563 343,000 70,875 343,000 70,875 916 439 2.67 6.19 2,561 2,605 3,090 3,470 1.21 1.33 1,763 1,815 5,750 6,090 3.26 3.36Worst case safety factor (Burst) 12-1/4" MASP: Production Mode Minimum Yield (psi) Weight (ppf) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Worst Case Safety Factor (Collapse) Length Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: MASP: WELL: PBU W-01B Hole Size Hole Size Casing Section Design Criteria: Calculation & Casing Design Factors Drilling Mode Hole Size Collapse Resistance w/o tension (Psi) Top (TVD) Tension at Top of Section (lbs) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Page 61 Prudhoe Bay West W-01B SB Injector Drilling Procedure 28.0 MASP MD TVD Planned Top: 2025 1973 Planned TD: 8575 5184 Anticipated Formations and Pressures: Formation Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OBd Sand 2281 Oil 8.46 0.440 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 13-3/8" shoe considering a full column of gas from shoe to surface: 5184 (ft) x 0.78(psi/ft)= 4044 4044 (psi) - [0.1(psi/ft)*5184(ft)]= 3525 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand) 5184 (ft) x 0.440(psi/ft)= 2281 psi 2281(psi) - 0.1(psi/ft)*5184(ft) 1763 psi Summary: 1. MASP while drilling hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. 2. Maximum planned mud density for the 12-1/4" hole section is 9.5 ppg. Maximum Anticipated Surface Pressure Calculation 12-1/4" Hole Section PBU W-01B Prudhoe Bay Unit TVD 5,184 Page 62 Prudhoe Bay West W-01B SB Injector Drilling Procedure MD TVD Planned Top: 8575 5184 Planned Deepest OBD: 15858 5337 Planned TD: 16548 5011 Anticipated Formations and Pressures: Formation Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OBd Sand 2348 Oil 8.46 0.440 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 5184 (ft) x 0.78(psi/ft)= 4044 4044 (psi) - [0.1(psi/ft)*5184(ft)]= 3525 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand) 5337 (ft) x 0.440(psi/ft)= 2348 psi 2348(psi) - 0.1(psi/ft)*5337(ft) 1815 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Maximum Anticipated Surface Pressure Calculation 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 8-1/2" Hole Section PBU W-01B Prudhoe Bay Unit TVD 5,337 Page 63 Prudhoe Bay West W-01B SB Injector Drilling Procedure 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 64 Prudhoe Bay West W-01B SB Injector Drilling Procedure 30.0 Surface Location Page 65 Prudhoe Bay West W-01B SB Injector Drilling Procedure From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:Revised Program Required for PTD W-01B PTD 224-149 Date:Friday, December 6, 2024 2:55:15 PM From: Joseph Engel <jengel@hilcorp.com> Sent: Friday, December 6, 2024 10:43 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Christianson, Grace K (OGC) <grace.christianson@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] Revised Program Required for PTD W-01B No problem, Jack. Will do first thing this morning. Re liner cement top: there are a few reasons for using the 9-5/8” shoe as the TOC vs. the liner top: Schrader laterals that have had lwd calipers ran show mostly gauge hole. Using the 9-5/8” shoe with a 30% excess has a high likelihood of bring TOC beyond the 9- 5/8” casing shoe Gauge hole TOC with 370bbls of cement pumped will bring cement to just below the liner top Gauge hole volume is ~284bbl, 86bbl of excess in the 9-5/8” x 7” annulus is ~1134’, planned liner top is 7400’, 9-5/8” shoe is 8575’ (1175’ liner lap) Due to the 1175’ of liner lap on this well, bringing cement up to the liner top is ~1075’ further than the 100’ liner lap minimum as per 20 AAC 25.030 (d) 6 With excess pumped and historical gauge hole, there is a high likelihood TOC will be beyond the 100’ lap minimum Recently we have struggled with our liner hanger vendor on cemented liner jobs and releasing the liner running tool with cement above the liner top (PBU 11-42 and DIU 2-72), resulting is loss of an entire well or significant post rig intervention By using the 9-5/8” shoe and planned toc and 30% excess, this will minimize the risk of cement above the liner top causing issues with releasing the running tool. We are also adding longer pump times on our cement blends and adjusting liner hanger operations to minimize this risk Injection fluids will be confined to the OBd by the 9-5/8” cement job, and confirmed with a passing 9-5/8” FIT and the 9-5/8” TOC determined by CBL as stated in step 14.18 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: External sender. DO NOT open links or attachments from UNKNOWN senders. Please let me know if you have any questions on this, and Joe L and I will get the new 401 submitted asap. Joe From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, December 6, 2024 8:58 AM To: Joseph Engel <jengel@hilcorp.com> Cc: Christianson, Grace K (OGC) <grace.christianson@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] Revised Program Required for PTD W-01B Joe, After discussing with the team, the most efficient way to process this is for you to submit a new 401. I should have requested that yesterday. What’s the reasoning for not bringing the cement up through the liner lap seeing its an injector? We would prefer it. Jack From: Joseph Engel <jengel@hilcorp.com> Sent: Thursday, December 5, 2024 2:08 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] Revised Program Required for PTD W-01B Jack – Thanks for the phonecall earlier today. Attached is the revised program per your questions. Comments below in red. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Let me know if you have any other questions. -Joe From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Wednesday, December 4, 2024 1:22 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Sean McLaughlin <sean.mclaughlin@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Christianson, Grace K (OGC) <grace.christianson@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL] Revised Program Required for PTD W-01B Joe – After reviewing the PTD package for W-01B, please submit a revised program addressing the following: Include schematic of the current condition of the well upon arrival. Included in section 6 Is there arctic pack? If so, what is the plan circulate it out/ handle it? Records show no arctic pack in the OA, see section 10.7 What is your contingency if the casing doesn’t pull free? See section 10.12 Final Schematic needs to be accurate – include sacrificial liner on schematic and accurate cement tops Updated and included in section 6 Step 16.35 – States cement to 9-5/8” casing shoe. Diagram shows cement to liner top. Which is correct? Do you want cement up to liner top for this injection well. Ensure displacement volumes match. Cement is planned to 9-5/8” shoe with 30% excess. Schematic updated to match. Step 16.36 – conflict in displacement volume for liner if liner running tool is at 4- 1/2” x 7” XO Corrected. See section 17.24 (note, numbering has been updated in attached program) Step 16.36 – incorrect DP displacement volume Corrected. See section 17.24 (note, numbering has been updated in attached program) Step 16.36 – total disp volume incorrect Corrected. See section 17.24 (note, numbering has been updated in attached program) Step 18.13 – MITIA needs be witnessed since injector (25.412.e) Included in section 18.13 Page 45 – Wellhead diagram needs to be legible Wellhead is from 1988, unfortunately that is the only drawing we have. Diagram has been annotated and updated. Thanks, Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Polaris Oil Pool, PBU W-01B Hilcorp Alaska, LLC Permit to Drill Number: 224-149 Surface Location: 1157' FSL, 1189' FEL, Sec 21, T11N, R12E, UM, AK Bottomhole Location: 2260' FNL, 1094' FWL, Sec 26, T11N, R12E, UM, AK Dear Mr. McLaughlin: 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 AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, 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 1th day of December2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.10 15:49:12 -09'00' REVISED 2 By Grace Christianson at 11:48 am, Dec 06, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.12.06 11:38:23 - 09'00' Sean McLaughlin (4311) JJL 12/6/24 * BOPE test to 3000 psi. Annular to 2500 psi. * MIT-IA to 3500 psi. 24 hour notice to AOGCC for opportunity to witness. * Variance to 20 AAC 25.412(b) Approved for >200' packer placement above the top of perforations. Packer to be placed below the base of Polaris oil pool confining zones. * Variance to AIO 25A Rule 4 Approved for establishing 0.8 psi/ft as the injection limit for this well without conducting the step-rate test and surveillance log. * MIT-IA to minimum .25 X TVD of packer setting depth after 10 days of stabilized injection. * CBL required for 9-5/8" intermediate liner for injectors per 20 AAC.412(d) CDW 12/09/2024 224-149 A.Dewhurst 06DEC24 50-029-21866-02-00 DSR-12/10/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.10 15:49:28 -09'00'12/10/24 12/10/24 RBDMS JSB 121324 2321 26 2321 26 K221112 K241112 P-09 P-09L1 P-30 W-01W-02 W-02A W-03 W-03A W-04 W-05A W-05AL1 W-05AL1PB1 W-06PB1 W-07A W-08 W-08A W-15 W-16 W-16A W-17 W-17A W-18 W-18A W-19 W-19AL1 W-19AL1PB1 W-19B W-19BL1 W-19BL1PB1 W-19BPB1 W-20 W-200 W-200PB1 W-201 W-202 W-202L1 W-202L2 W-203 W-203L1 W-203L2 W-204 W-204PB1 W-205 W-205L1 W-205L1PB1 W-205L2 W-207 W-207PB1 W-209 W-209PB1 W-21 W-210 W-211 W-212W-213 W-215 W-215PB1 W-216 W-217 W-217PB1 W-219 W-219PB1 W-219PB2 W-21A W-21AL1 W-21AL1-01 W-22 W-220PB1 W-220PB2 W-223 W-22PB1 W-23 W-23A W-24 W-25 -26 W-26A -27 W-29 W-30 W-31 W-31A W-32 W-32A W-32APB1 W-34 W-35 W-36 W-37 W-39 W-40 W-400 W-42 W-56 W-59PB1 W-06B W-06BPB1 W-01B_WP HILCORP NORTH SLOPE Greater Prudhoe Bay W-01B AOR MAP W-01B Proposed Location FEET 0 1,000 2,000 3,000 POSTED WELL DATA Well Label WELL SYMBOLSLocation INJ Well (Water Flood) P&A Oil/Gas J&A Plugback Active Oil Injector Location Producer Location Shut in Injector REMARKS Well symbols at top of Schrader OBD sand. Purplecircle and lines = 1320' radius from the completed OBD sand in W-01B. (OBD sand is top proposed sand forinjection). By: BTR -2024 November 19, 2024 PETRA 11/19/2024 2:00:37 PM Well Name PTD API Distance / StatusTop of Oil Pool(SB OBd, MD)Top of Oil Pool(SB OBd, TVDss)Top of Cmt(MD)Top of Cmt(TVDss)ZonalIsolationCommentsPBU W-205 203-202 50-029-23165-00-00 956 / Producer 7494' 5093' 5265' 3955' ClosedPumped 122 bbls (566 sx) 15.8 ppg Premium Class 'G' cement. 7-5/8" casing was reciprocated during cementing operationsand 100% returns achieved throughout job. Including shoe track volume, volumetric calculations place the TOC in the 7-5/8" x9-7/8" annulus at 5265' MD when accounting for 30% washout.PBU W-207 203-049 50-029-23145-00-00 1260' / Injector 11,642' 5233' 7840' 4030' Closed Pumped 125 bbls 15.8 ppg Class 'G' cement. No losses reported. 7" TOC logged at 7840' MD with USIT on 4/16/2003.K221112 176-009 50-029-20192-00-00 752' / Abandoned 5486' 5131' 2551' 2487' Closed- 8-1/2" hole drilled to 5755' MD before sticking BHA. Backed off drill pipe at 4978' MD and spotted 125 sx Class 'G' cementthrough open ended drill pipe. Drilled through cement stringers at 4433' MD and dressed off cement plug to 4831' MD. Kickedoff cement plug and continued drilling 8-1/2" hole to 10,192' MD.-Stage 1 was the initial cement circulated through the 7" casing shoe. A total of 500 sx (116.6 bbls) Class 'G' cement waspumped. First 300 sx had a slurry weight of 16 ppg and last 200 sx had 17 ppg. No losses reported.-Stage 2 was circulated after opening the FO collar at 5749' MD with 227 sx (44.5 bbls) 16.2 ppg Class 'G' cement. Enoughcement was circulated to reach the next higher FO collar at 4051' MD, accounting for 30% washout. No losses reported.-Stage 3 was circulated after opening the FO collar at 4051' MD with 218 sx (36 bbls) Permafrost cement. Enough cement wascirculated to reach the next higher FO collar at 2925' MD, accounting for 30% washout.-Stage 4was circulated after opening the FO collar at 2925' MD with 260 sx (43 bbls) Permafrost cement. TOC calculates2551' MD. No washout assumed as this cement was placed predominantly in the 13-3/8" cased hole.- The well was fully P&A'd March 2007.Area of Review PBU W-01B Prudhoe Bay West (PBU) W-01B Drilling Permit Version 2 12/4/2024 Table of Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................5 5.0 Internal Reporting Requirements................................................................................................6 6.0 Pre-Window Plugged & Planned Wellbore Schematic ..............................................................7 7.0 Drilling / Completion Summary.................................................................................................10 8.0 Mandatory Regulatory Compliance / Notifications..................................................................11 9.0 MIRU & Test BOPE....................................................................................................................14 10.0 Pull Tubing String, Cut & Pull 9-5/8” .......................................................................................16 11.0 Set Whipstock, Mill 12-1/4” Window.........................................................................................18 12.0 Drill 12-1/4” Hole Section............................................................................................................21 13.0 Run 9-5/8” Intermediate Casing.................................................................................................24 14.0 Cement 9-5/8” Casing..................................................................................................................27 15.0 Drill 8-1/2” Hole Section..............................................................................................................30 16.0 Open Hole P&A Kit for PA ........................................................................................................35 17.0 Run & Cement 7” x 4-1/2” Injection Liner...............................................................................38 18.0 Run Upper Completion/ Post Rig Work....................................................................................45 19.0 Innovation Rig BOP Schematic..................................................................................................48 20.0 Wellhead Schematic.....................................................................................................................49 21.0 Days Vs Depth..............................................................................................................................50 22.0 Formation Tops & Information..................................................................................................51 23.0 Anticipated Drilling Hazards......................................................................................................53 24.0 Innovation Rig Layout.................................................................................................................57 25.0 FIT Procedure..............................................................................................................................58 26.0 Innovation Rig Choke Manifold Schematic ..............................................................................59 27.0 Casing Design...............................................................................................................................60 28.0 MASP............................................................................................................................................61 29.0 Spider Plot (NAD 27) (Governmental Sections)........................................................................63 30.0 Surface Location..........................................................................................................................64 Page 2 Prudhoe Bay West W-01B SB Injector Drilling Procedure 1.0 Well Summary Well PBU W-01B Pad Prudhoe Bay W Pad Planned Completion Type 4-1/2” Injection Target Reservoir(s)Schrader Bluff OBd Sand Planned Well TD, MD / TVD 16,549’ MD / 5011’ TVD PBTD, MD / TVD 14,250’ MD / 5278’ TVD Surface Location (Governmental)1157' FNL, 1189' FEL, Sec 21, T11N, R12E, UM, AK Surface Location (NAD 27)X= 612,049, Y= 5,959,100 Top of Productive Horizon (Governmental)1451' FNL, 794' FEL, Sec 22, T11N, R12E, UM, AK TPH Location (NAD 27)X= 617,728 , Y= 5,958,892 BHL (Governmental)2260' FNL, 1094' FEL, Sec 26, T11N, R12E, UM, AK BHL (NAD 27)X= 622,811, Y= 5,952,884 AFE Number 241-00159 AFE Drilling Days 31 AFE Completion Days 4 Maximum Anticipated Surface Pressure - Intermediate 1763 psig Maximum Anticipated Surface Pressure - Production 1815 psig Maximum Anticipated Pressure (Downhole/Reservoir)2348 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL:26.5 ft + 50.61 ft = 77.11 ft GL Elevation above MSL:53.81 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay West W-01B SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay West W-01B SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in)Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20”19.25 ---X-52 Weld *17-1/2”13-3/8”12.415 12.259 14.375 68 L-80 BTC 5,020 2,260 1,556 12-1/4”9-5/8”8.835 8.679 10.625 40 L-80 TXP 5,750 3,090 916 8-1/2”7”6.276 6.151 7.656 26 L-80 563 7,240 5,410 604 4-1/2”3.958 3.833 5.200 12.6 L-80 563 8,430 7,500 288 Tubing 4-1/2”3.958 3.833 5.000 12.6 L-80 JFEBear 8,430 7,500 288 *Existing hole section and casing string Page 5 Prudhoe Bay West W-01B SB Injector Drilling Procedure 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Int & Production 5”4.276”3.25”6.625”19.5 S-135 NC50 30,730 34,136 560klb Page 6 Prudhoe Bay West W-01B SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Tyson Shriver 907.564.4542 tyson.shriver@hilcorp.com Geologist Ben Rickards 210.287.7711 benjamin.rickards@hilcorp.com Reservoir Engineer Tim Davis 907.564.4886 tidavis@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com 2025' - Set Whipstock 2700' - Cut Tubing Page 9 Prudhoe Bay West W-01B SB Injector Drilling Procedure Proposed Schematic Page 10 Prudhoe Bay West W-01B SB Injector Drilling Procedure 7.0 Drilling / Completion Summary PBU W-01B is a sidetrack injector planned to be drilled in the Schrader Bluff OBd sands. W-01B is part of a multi-well program targeting the Schrader Bluff sand on PBU W-pad The parent bore, W-01A, is a shut-in vertical injection well. The Ivishak and Schrader Bluff reservoirs will be abandoned prior to the rig’s arrival on the well, operations covered on a separate sundry. The directional plan is 12-1/4” intermediate hole and 9-5/8” casing string set into the top of the Schrader Bluff OBd sand. An 8-1/2” lateral section will be drilled which includes an appraisal tail that will extend across an east-west fault to help determine future development opportunities. The tail will be drilled outside of the participating area boundary and will be abandoned via a cemented open hole P&A kit prior to running the lower completion. An injection liner will be run and cemented in the remaining open hole section, followed by 4-1/2” tubing. The well will not be pre-produced The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately December 12, 2024, pending rig schedule. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U & Test 13-5/8” BOPE 3. Pull 4-1/2” Tubing, cut & pull 9-5/8” casing 4. Set 13-3/8” whipstock, mill 12-1/4” window 5. Drill 12-1/4” hole to TD 6. Run and cement 9-5/8” casing 7. Drill 8-1/2” lateral to well TD 8. Run and cement 7” x 4-1/2” liner 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering), Neu/Den Page 11 Prudhoe Bay West W-01B SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU W-01B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 12 Prudhoe Bay West W-01B SB Injector Drilling Procedure AOGCC Regulation Variance Requests: Hilcorp would like to request a variance from 20 AAC 25.412.(b)which states: “A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone.” In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at the OBd production interval at ~86 degrees inclination. In order to make the ball and rod we land to set the production packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees inclination. The MD we currently have planned for 70 degrees is at ~7750’ MD. The X-nipple below the production packer will be set at ~7650’ MD and the production packer will be ~50’ MD above the X nipple which puts it at ~7600’ MD / ~4987’ TVD. The intermediate casing shoe is planned at ~8575’ MD / ~5184’ TVD which means the planned packer depth is ~975’ MD away. From a TVD standpoint, the production tubing packer is ~197’ TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader Bluff sand, and the injection packer set inside the intermediate casing, injection fluids will be confined to the Schrader bluff sands. Hilcorp would like to request a variance from AIO 25A Rule #4 which states: “b. Within three months of start of injection in a new or converted injector, a step rate test and surveillance log must be run for detection of fluids moving out of the approved injection stratum.” The Polaris pool is unique among nearby Schraeder Bluff oil pools in its requirement to perform step-rate tests and surveillance logs on all new or converted injectors to justify the maximum injection pressures for a given well. The original justification for this change that was shared with the Commission in November 2003 were step-rate tests on W-212 and S-215 which indicated injection pressures up to 0.8 psi/ft caused no detectable migration of fluids outside of approved strata. To date, all step-rate tests performed on injectors in the Polaris oil pool have indicated that the established injection gradient of 0.8 psi/ft does not cause fluids to migrate out of zone. For W-01B, Hilcorp is requesting that 0.8 psi/ft be established as the injection limit for this well without conducting the step-rate test and surveillance log listed in AIO 25A Rule #4. Page 13 Prudhoe Bay West W-01B SB Injector Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc 250/3,000 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs and changing rams x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 14 Prudhoe Bay West W-01B SB Injector Drilling Procedure 9.0 MIRU & Test BOPE 9.1 W-01A will be the parent well for this sidetrack. Ensure to review the attached surface plat and make sure the rig is over appropriate well. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Level pad and ensure enough room for layout of rig footprint and R/U. 9.4 Rig mat footprint of rig. 9.5 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.6 Mud loggers WILL NOT be used on either hole section. 9.7 Give AOGCC 24hr notice of BOPE test, for test witness. 9.8 Install BPV, ND tree and THA 9.9 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve. 9.10 RU MPD RCD and related equipment 9.11 Run 5” BOP test plug 9.12 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 3-1/2” test joint x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech Page 15 Prudhoe Bay West W-01B SB Injector Drilling Procedure 9.13 RD BOP test equipment 9.14 Dump and clean mud pits, send spud mud to G&I pad for injection. 9.15 Mix 9.4 LSND for well work operations 9.16 Set wearbushing in wellhead 9.17 If needed, rack back as much 5” DP in the derrick as possible to be used when drilling future hole section. 9.18 Ensure 5” liners in mud pumps x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 16 Prudhoe Bay West W-01B SB Injector Drilling Procedure 10.0 Pull Tubing String, Cut & Pull 9-5/8” 10.1 RU tubing handling equipment x Tubing is 4-1/2” x Tubing cut depth: ~2,700’, confirm with pre rig well work report 10.2 PU landing joint or spear and engage tubing hanger 10.3 Backout lock down screws 10.4 Pull tubing hanger with landing joint to the rig floor, have appropriate protectors ready. 10.5 If necessary, circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. 10.6 POOH laying down 4-1/2” tubing. RD tubing handling equipment 10.7 MU Baker or Yellowjacket mechanical cutter, RIH to TOC and cut 9-5/8” casing at 2,120’ MD. x Note: The operator performed a 9-5/8” x 13-3/8” downsqueeze with 300 sx of 14.0 ppg Permafrost ‘C’ cement followed by 150 bbls of crude during initial completion in 1988. A CBL of the 9-5/8” casing was pulled while performing an RWO in 2022 which showed a clear TOC at 2,650’ with stringers up to 2,200’. 10.8 POOH and inspect mechanical cutter for wear. LD mechanical cutter x If inspection indicates, RIH with backup cutter and repeat. 10.9 RU casing handing equipment x Casing is 9-5/8” 47# L-80 NSCC 10.10 PU spear and engage casing hanger 10.11 Back out lock down screws 10.12 Pull casing free x If casing does not pull free, contingent cutting and fishing operations will take place to pull the 9-5/8” casing. Any changes will be discussed with AOGCC prior to implementation. 10.13 Circulate at least 1.5x BU after pulling casing free. If desired circulate a sweep surface to surface to clean further. Fluid behind the 9-5/8” is dead crude. 150 bbls were pumped from surface. 10.14 POOH laying down the 9-5/8” casing x Note: stand-off clamps were installed on every 3rd joint of 9-5/8” casing. * Assure KWF and no pressure on tubing or annulus before backing out LDS - JJL Page 17 Prudhoe Bay West W-01B SB Injector Drilling Procedure 10.15 RD casing handling equipment Page 18 Prudhoe Bay West W-01B SB Injector Drilling Procedure 11.0 Set Whipstock, Mill 12-1/4” Window 11.1 MU 13-3/8” casing scraper assembly and RIH to top of 9-5/8” cut 11.2 RU casing testing equipment and PT 13-3/8” casing to 2000 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 11.3 If unable to get passing PT of the 13-3/8”, P/U 13-3/8” mechanical plug, RIH to set depth (TBD based on cut depth and CCL) & set same 11.4 Whipstock Set Depth Information x Planned TOW: 2025’ x WS should be set to avoid a collar while milling the window, casing tally available in O- Drive x Drilling Foreman, Whipstock hand and drilling engineer to agree on the set depth 11.5 MU 12-1/4” mill/whipstock assembly as per WIS tally x MU HWDP, string magnets and float sub x Ensure magnets are in trough, under shakers and flow area to capture metal shavings circulated 11.6 Install MWD and orient. Rack back mill assembly x Ensure a dedicated MWD is available for the orientation of the whipstock 11.7 Verify offset between WD, and the whipstock tray, witnessed by the Drilling Foreman, MWD/DD and WIS rep. Document and record offset in well file. 11.8 Slowly run in the hole as per fishing Rep. 11.9 Run in hole at 1 ½ to 2 minutes per stand, or per contractor rep. Ensure work string is stationary prior to setting the slips to avoid weakening the shear bolt and prematurely setting the anchor. 11.10 Shallow test MWD at first drill pipe fill up depth. 11.11 Stop at least 30-45’ above planned set depth, obtain survey with MWD. 11.12 Milling fluid will be 9.4 ppg LSND 11.13 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 11.14 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30q LOHS – Consult with milling hand Page 19 Prudhoe Bay West W-01B SB Injector Drilling Procedure 11.15 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 15L to 45L, target is 30 LOHS Hole Angle at window interval (@ 2,025’, 22° inc, 103° azi). Sidetrack tangent section is 60q inclination and 83q azimuth 11.16 Once whipstock is in desired orientation, set WS per Baker Hughes rep. 11.17 CBU and confirm 9.4 ppg MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings x Visc: 40-60, YP: 18-20 11.18 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 11.19 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 11.20 Clean catch trays and ditch magnets frequently while milling window. 11.21 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 11.22 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 11.23 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 11.24 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 45L 15L Page 20 Prudhoe Bay West W-01B SB Injector Drilling Procedure 11.25 Pull back into 13-3/8” casing and perform FIT to 11.5 pg EMW, Chart Test x 13-3/8” casing is cemented. Open hole weak point is the top of the window at ~ 2025’ MD, 1973’ TVD x 11.5 Fit provides a > 25 bbl KT based upon 9.4 ppw MW, 8.46 PP (swabbed kick at 9.4 BHP) x If 11.5 is not achieved, contact drilling engineer. 11.26 POOH & LD milling BHA. Gauge mills for wear. 11.27 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. * Email casing test and FIT digital data to AOGCC engineer upon completion of FIT - JJL Page 21 Prudhoe Bay West W-01B SB Injector Drilling Procedure 12.0 Drill 12-1/4” Hole Section 12.1 P/U 12-1/4” motor drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the hole section. 12.2 RIH with 12-1/4” BHA, to top of whipstock. Shallow test MWD at the first fill up point 12.3 Orient directional motor same as whipstock orientation and slide through window with no pumps or rotary x Confirm set orientation of whipstock, and have BHA match 12.4 Displace wellbore to 9.4 ppg LSND x 9.4 ppg due to hydrates, free gas and potential for Cretaceous over pressure (although none has been see at W pad, be aware from 4500’ TVD and deeper) 12.5 Drill 12-1/4” hole section to section TD, in the Schrader OBd sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Efforts should be made to minimize dog legs in the intermediate hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from over melting hydrates x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off.Wood has been observed across shakers during the interval TVD. x Gas hydrates are have been seen on W pad. In PBW they have been encountered typically around 1660’ TVD (Base of Perm) to 3400’ TVD (Top Ugnu) and below. Be prepared for hydrates: x Keep mud temperature as cool as possible, Target 60-70*F. Page 22 Prudhoe Bay West W-01B SB Injector Drilling Procedure x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold pre-made mud on trucks ready. x Drill through hydrate sands and quickly as possible, do not backream. x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Intermediate Hole AC, CF <1.0 : x There are no wells with a CF less than 1.0 12.6 12-1/4” hole mud program summary: x Density:Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. MW for free gas and hydrates based upon offset wells Depth Interval MW (ppg) Window - TD 9.4+ (For Hydrates/Free Gas based on offset wells and cretaceous injection mitigation) x PVT System:PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology:Aquagel and Barazan D+ should be used to maintain rheology. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss:DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 23 Prudhoe Bay West W-01B SB Injector Drilling Procedure System Type:8.8 – 9.8 ppg LSND Properties: Section Density LSYP PV YP MPT API FL pH Temp Intermediate 8.8 – 9.8 4-6 15 - 30 25-45 <8 <10 8.5 – 9.0 70 F 12.7 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 12.8 RIH to bottom, proceed to BROOH to window x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.9 CBU x2 at the 13-3/8” shoe and clean casing with high visc sweeps 12.10 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at window for any higher than expected pressure seen 12.11 Orient BHA and pull through window with no pumps or rotary 12.12 TOOH and LD BHA Page 24 Prudhoe Bay West W-01B SB Injector Drilling Procedure 13.0 Run 9-5/8” Intermediate Casing 13.1 Install 9-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with test joint. RD testing equipment. 13.2 R/U 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 13.3 P/U shoe joint, visually verify no debris inside joint. 13.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” , 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring 9-5/8” Float Collar x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment 13.5 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x Bowspring Centralizers only x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to TOC x Verify depth of uppermost significant oil with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. 9-5/8” 40# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”18860 20960 23060 Page 25 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 26 Prudhoe Bay West W-01B SB Injector Drilling Procedure 13.6 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 13.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.8 Slow in and out of slips. 13.9 Lower casing to setting depth. Confirm measurements. 13.10 Have slips staged in cellar, along with necessary equipment for the operation. 13.11 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 27 Prudhoe Bay West W-01B SB Injector Drilling Procedure 14.0 Cement 9-5/8” Casing 14.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface if seen. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 14.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 14.5 Fill surface cement lines with water and pressure test. 14.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail, TOC brought to 500’ above the Schrader Bluff x Calculations based upon cement 500’ MD above Schrader NB Sand, 6,808’ MD, x NB Top: 7,308’ MD. x Note: TOC will be adjusted to 500’ above uppermost significant oil Estimated Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (8575-6808)' x 0.0558 bpf x 1.4 = 138.0 774.1 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 147.1 825.2 711.4Tail Page 28 Prudhoe Bay West W-01B SB Injector Drilling Procedure Cement Slurry Design (Single Stage Cement Job): 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with mud out of mud pits x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. 14.12 Displacement calculation: = (8,575’-120’) x .0758 bpf = = 641 bbls 14.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 14.14 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. 14.15 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, before consulting with Drilling Engineer. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 29 Prudhoe Bay West W-01B SB Injector Drilling Procedure 14.17 9-5/8” will be set on slips. Make initial cut on 9-5/8”, ld cut joint, make final cut. Dress off, install tubing spool. 14.18 CBL evaluation of intermediate cement job will be performed after production liner is set and cemented. x This will allow sufficient time for cement to reach compressive strength Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 30 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH to TOC above the shoe track. Note depth TOC tagged on morning report. 15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. 15.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum required to drill ahead x 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP) 15.7 POOH and LD cleanout BHA 15.8 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 NC50. x Run a solid float sub in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 * Email casing test and FIT digital data to AOGCC upon completion of FIT. - JJL Page 31 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.9 8-1/2” hole section mud program summary: x Density:Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration:It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology:Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPH T Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10%<8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 32 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.10 TIH with 8-1/2” directional assembly to bottom 15.11 Install MPD RCD 15.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid x Density may change based upon TD of prior hole section 15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Reservoir plan is to stay in OBd sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff OBd Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C, CF < 1.0: x There are no wells with a CF < 1.0 15.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. Page 33 Prudhoe Bay West W-01B SB Injector Drilling Procedure x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.17 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD 15.18 Displace 1.5 OH + liner volume with viscosified brine. x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 Monitor the returned fluids carefully while displacing to brine. 15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.23 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen Page 34 Prudhoe Bay West W-01B SB Injector Drilling Procedure 15.24 POOH and LD BHA. 15.25 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. x Only LWD open hole logs are planned for the hole section. There will not be any additional logging runs conducted. Page 35 Prudhoe Bay West W-01B SB Injector Drilling Procedure 16.0 Open Hole P&A Kit for PA 16.1 Note: W-01B lateral plan has an appraisal section drilled beyond the AIO/PA boundary. Before the cemented injection liner can be ran, the section of the lateral outside of the PA is to be plugged back with an open hole P&A kit. Below is email correspondence (10/25/24) with AOGCC regarding this plan prior to approval. Page 36 Prudhoe Bay West W-01B SB Injector Drilling Procedure 16.2 Plan outline of lateral x AIO Boundary: 15,220’ MD x Fault: ~14,446’MD x Planned OH P&A Packer Depth: 14,200’ MD 16.3 MU Baker OH P&A Kit consisting of: x 4-1/2” Float Shoe x 4-1/2” Float Collar x ~2,348’ of 4-1/2” sacrificial liner x 4-1/2” ECP x Liner Setting Sleeve, HRDE 16.4 RIH with OH P&A Kit on 5” DP to TD 16.5 Break circulation Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Confirm all pressures with Baker 16.6 Prior to proceeding with cement job, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.7 Circulate and condition mud for cement job 16.8 RU Lines for cement job if not already done so Page 37 Prudhoe Bay West W-01B SB Injector Drilling Procedure 16.9 Pump 30 bbls of 11ppg tuned spacer 16.10 Mix and pump cement as per plan 16.11 Cement volume based on OH annular volume * open hole excess (30%) + filling the sacrificial liner with cement. Job will consist of single slurry, TOC brought to the ECP setting depth, ~ 14,200’ MD 16.12 After pumping cement, drop dart and displace cement with mud out of mud pits. x 14,200’ * .0171 bpf (5” dp capacity) x = 243 bbl 16.13 Pressure up to inflate the ECP. Continue pressuring up to release the HRDE Running Tool 16.14 Bleed DP Pressure, PU running tool above ECP 16.15 Break Circulation and circulated excess cement to surface, have blackwater on hand in pits 16.16 POOH, LD running tool Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8-1/2" OH x 4-1/2" (16,548 - 14,200)' x 0.0505 bpf x 1.3 = 154.2 865.1 4-1/2" Liner Volume 2348' x 0.0152 bpf = 35.7 200.3 Total Tail 189.9 1065.3 918.4Tail Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 38 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.0 Run & Cement 7” x 4-1/2” Injection Liner 17.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints 17.2 Well control preparedness: In the event of an influx of formation fluids while running the 7” x 4-1/2” liner, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint with x 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW. x -OR- x 7“ XO installed on bottom, TIW valve in open position on top, 7” handling joint above TIW. x These joints shall be fully M/U and available prior to running the first joint of 4-1/2” liner or 7” liner, respectively. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 17.3 R/U liner running equipment. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 17.4 Run 4-1/2” injection liner x Use API Modified or “Best O Life 2000 AG”thread compound. Confirm pipe dope with TRS. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Install jewelry as per the Running Order (From Completion Engineer post TD). o ~13 NCS Sleeves, 1 sleeve every ~450’MD x Centralization: 1 per joint, solid body centralizers x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Liner Torque – ftlbs OD PPF Connection Minimum Optimum Maximum Yield Torque 4-1/2 12.6 Hydril 563 3200 3700 5600 12600 7 26 Hydril 563 7800 9400 13700 39000 Page 39 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 40 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 41 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.5 RU 7” running equipment and run 7” 26# H563 section x ~1,175’ total. TOL ~7,400’ MD x Centralized ½ joints, bowspring centralizers 17.6 Ensure to run enough 7” liner is provide for sufficient overlap inside 9-5/8” casing tubing packer completion. Tentative liner set depth ~ 7,400’ MD. x 7” will be ran under the liner hanger for the production packer. Confirm with completion engineer. 17.7 Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 17.8 Before picking up Baker Flex Lock liner hanger / ZXP packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.9 M/U Baker Flex Lock liner hanger and ZXP liner top packer to liner. x Confirm with OE any 7” joints between liner top packer and 4-1/2” liner for tubing packer setting depth x Liner running tool extension will need to be ran so liner wiper darts are positioned at the 7” x 4-1/2” XO 17.10 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.11 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” DP/HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. x Use HWDP as needed for running liner 17.12 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 17.14 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. Page 42 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.15 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.16 Rig up to pump down the work string with the rig pumps. 17.17 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Confirm all pressures with Baker. 17.18 Prior to proceeding with cement job, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 17.19 Circulate and condition mud for cement job 17.20 RU Lines for cement job if not already done so 17.21 Pump 30 bbls of 11ppg tunes spacer 17.22 Mix and pump cement as per plan 17.23 Cement volume based on OH annular volume + open hole excess (30%). Job will consist of single slurry, TOC brought to the 9-5/8” casing shoe, ~ 8575’ MD Cement Slurry Design (Single Stage Cement Job) 17.24 After pumping cement, drop dart and displace cement with mud out of mud pits. x Displacement calculations are based upon x 5” dp from surface to liner top (7400’ MD) x 2-7/8” liner running tool extension from liner top to 7” x 4-1/2” XO (8575’ MD) x 2-7/8” 6.5# EUE x Due to liner wiper plug effective diameter x 4-1/2” from 7” x 4-1/2” XO to PBTD of 14200’ MD Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8-1/2" OH x 4-1/2" (14,200 - 8,575)' x 0.0505 bpf x 1.3 = 369.3 2071.8 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 371.1 2081.9 1189.6Tail Tail Slurry System SoluCem Density 15 lb/gal Yield 1.75 ft3/sk Mixed Water 7.88 gal/sk Page 43 Prudhoe Bay West W-01B SB Injector Drilling Procedure x Displacement Calculation: x 7400’ * .0171 bpf (5” dp capacity) = 126.6 bbl (DP volume) x (8575 – 7400) * .0058bpf (2-7/8” capacity) = 6.8bbl x (14,200’-120’-8575’) * .0152bpf (4-1/2” cap) = 83.7 bbl (Liner volume) x = 217.1 bbl 17.25 Monitor returns and pump pressure closely while displacing, slow donw pumps when dart latches onto liner wiper plug and when plug lands 17.26 Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on well report: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 17.27 Continue pressuring up to 2,600 psi to set the Flex lock liner hanger. Hold for 5 minutes. Slack off 20K lbs on the Flex Lock liner hanger to ensure the HRDE setting tool is in compression for release from the liner hanger/packer. Continue pressuring up 4,000 psi to set the ZXP liner top packer and release the HRDE running tool. 17.28 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 17.29 PU with running tool above Liner top packer and circulate bottoms up to remove any excess cement from around the running tool. 17.30 Reengage liner running tool. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. Page 44 Prudhoe Bay West W-01B SB Injector Drilling Procedure 17.31 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 17.32 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 17.33 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 45 Prudhoe Bay West W-01B SB Injector Drilling Procedure 18.0 Run Upper Completion/ Post Rig Work 18.1 RU Slickline and perform CBL from liner top (~7400’ MD) to 1000’ above calculated TOC of 9- 5/8” casing x Calculated TOC on 9-5/8” with excess ~ 6808’ MD, w/o excess ~6,100’ MD 18.2 RU to run 4-1/2”, 12.6#, L-80 JFEBear tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, L-80 JFEBear x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 18.3 PU, MU and RIH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Tubing Jewelry to include: x 2x X Nipple x 1x Production Packer i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval. x 1x X Nipple x XXX joints, 4-1/2”, 12.6#, L-80 JFEBear x WLEG Page 46 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 47 Prudhoe Bay West W-01B SB Injector Drilling Procedure 18.4 PU and MU the tubing hanger. 18.5 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.6 Land the tubing hanger and RILDS. Lay down the landing joint. 18.7 Install 4” HP BPV. ND BOP. Install the plug off tool. 18.8 NU the tubing head adapter and NU the tree. 18.9 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.10 Pull the plug off tool and BPV. 18.11 Reverse circulate the well over to corrosion inhibited source water follow diesel to freeze protect for both tubing and IA to 2,500’ MD. Open well at surface / rig up jumper and allow freeze protect to U-tube between tubing and IA. 18.12 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure 18.13 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Record and notate all pressure tests (30 minutes) on chart. x Notify AOGCC 24hrs prior to test for opportunity to witness 18.14 Bleed both the IA and tubing to 0 psi. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. x Work with Ops Engineer and Well Integrity to complete 10-426 Form for the initial MIT-T and MIT-IA. This form must be completed regardless of AOGCC witness. 18.16 RDMO Innovation i. POST RIG WELL WORK x Slickline o Pull B&R and RHC body x Coil o Contingent: Pull B&R and RHC body if SL unable to o Shift injection sleeves open o Contingent: Pump 15% HCl to breakdown cement behind injection sleeve x Ops o Put well on injection o AOGCC witnessed MIT-IA once injection is stable Page 48 Prudhoe Bay West W-01B SB Injector Drilling Procedure 19.0 Innovation Rig BOP Schematic Page 49 Prudhoe Bay West W-01B SB Injector Drilling Procedure 20.0 Wellhead Schematic Wellhead is 1988 McEvoy 13-5/8” 5K Page 50 Prudhoe Bay West W-01B SB Injector Drilling Procedure 21.0 Days Vs Depth Page 51 Prudhoe Bay West W-01B SB Injector Drilling Procedure 22.0 Formation Tops & Information Reference Plan:CommentsKOP 2,0251,973.4-1896.31SV4 Gas Hydrates 2,0912,034.7-1957.57 895 8.46SV3 Gas Hydrates 2,7862,559.3-2482.18 1126 8.46SV1 Gas Hydrates 3,8373,096.9-3019.78 1363 8.46Ugnu 4A Heavy Oil 4,6133,491.1-3413.99 1536 8.46Heavy oil in Ugnu sands possibleUG3 Heavy Oil 5,2943,837.0-3759.93 1688 8.46Ugnu MA Heavy Oil 6,7734,589.1-4511.98 2019 8.46NB Water 7,3084,858.8-4781.72 2138 8.46OA Top Oil 7,6084,990.2-4913.13 2196 8.46Oba Top Oil 7,7695,048.1-4971.02 2221 8.46Previous injection/productionObc Top Oil 8,0745,130.2-5053.13 2257 8.46Previous injection/productionObd Top Oil 8,5735,184.3-5107.20 2281 8.46Previous injection/productionFault Oil 9,300Fault Oil 14,300End of completed productive sectionObd Top Oil 14,8265,330.5-5253.40Obd Top Oil 15,8585,337.9-5260.76Obc Top Oil 16,041 5279.61 -5202.50Oba Top Oil 16,2045,209.3-5132.21OA Top Oil 16,3015,160.1-5083.01NB Oil 16,5265,024.1-4946.99EASTINGEst.PressureGradientEXPECTEDFLUIDMD(FT)TVD(FT)TVDSS(FT)NORTHINGW-01B wp08ANTICIPATED FORMATION TOPS & GEOHAZARDSTOP NAMELITHOLOGY Page 52 Prudhoe Bay West W-01B SB Injector Drilling Procedure Page 53 Prudhoe Bay West W-01B SB Injector Drilling Procedure 23.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates/Free Gas Gas hydrates have been seen on PBU W Pad. Be prepared for them. They have been reported between 1800’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free penetrations of offset wells. x Be prepared for gas hydrates o Keep mud temperature as cool as possible, Target 60-70*F o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready o Drill through hydrate sands and quickly as possible, do not backream. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Cretaceous Over Pressure: W-Pad does not have a history of over-pressure in the cretaceous interval (4500-5300’ TVD). However, as a precaution ensure MW is above 9.0. Be prepared while drilling this interval. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x No Wells with CF < 1.0 Page 54 Prudhoe Bay West W-01B SB Injector Drilling Procedure Wellbore stability (Permafrost, running sands and gravel Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Maintain mud parameters and increase MW to combat running sands and gravel formations. Stuck pipe, wood chunks over shakers and other hole stability issues are specific to W pad. Be prepared and review Pad Data Sheet. Bad see pad data sheet H2S: Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 55 Prudhoe Bay West W-01B SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 56 Prudhoe Bay West W-01B SB Injector Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific A/C: x No wells with CF < 1.0 Page 57 Prudhoe Bay West W-01B SB Injector Drilling Procedure 24.0 Innovation Rig Layout Page 58 Prudhoe Bay West W-01B SB Injector Drilling Procedure 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 59 Prudhoe Bay West W-01B SB Injector Drilling Procedure 26.0 Innovation Rig Choke Manifold Schematic Page 60 Prudhoe Bay West W-01B SB Injector Drilling Procedure 27.0 Casing Design 12-1/4"Mud Density:9.4 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1763 psi (see attached MASP determination & calculation) 1815 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8"4-1/2" 08,575 05,184 8,575 14,200 *completed MD 5,184 5,273 *completed TVD 8,575 5,625 40 12.6 L-80 L-80 TXP H563 343,000 70,875 343,000 70,875 916 439 2.67 6.19 2,561 2,605 3,090 3,470 1.21 1.33 1,763 1,815 5,750 6,090 3.26 3.36Worst case safety factor (Burst) 12-1/4" MASP: Production Mode Minimum Yield (psi) Weight (ppf) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Worst Case Safety Factor (Collapse) Length Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: MASP: WELL: PBU W-01B Hole Size Hole Size Casing Section Design Criteria: Calculation & Casing Design Factors Drilling Mode Hole Size Collapse Resistance w/o tension (Psi) Top (TVD) Tension at Top of Section (lbs) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Page 61 Prudhoe Bay West W-01B SB Injector Drilling Procedure 28.0 MASP MD TVD Planned Top: 2025 1973 Planned TD: 8575 5184 Anticipated Formations and Pressures: Formation Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OBd Sand 2281 Oil 8.46 0.440 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 13-3/8" shoe considering a full column of gas from shoe to surface: 5184 (ft) x 0.78(psi/ft)= 4044 4044 (psi) - [0.1(psi/ft)*5184(ft)]= 3525 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand) 5184 (ft) x 0.440(psi/ft)= 2281 psi 2281(psi) - 0.1(psi/ft)*5184(ft) 1763 psi Summary: 1. MASP while drilling hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. 2. Maximum planned mud density for the 12-1/4" hole section is 9.5 ppg. Maximum Anticipated Surface Pressure Calculation 12-1/4" Hole Section PBU W-01B Prudhoe Bay Unit TVD 5,184 Page 62 Prudhoe Bay West W-01B SB Injector Drilling Procedure MD TVD Planned Top: 8575 5184 Planned Deepest OBD: 15858 5337 Planned TD: 16548 5011 Anticipated Formations and Pressures: Formation Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OBd Sand 2348 Oil 8.46 0.440 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 5184 (ft) x 0.78(psi/ft)= 4044 4044 (psi) - [0.1(psi/ft)*5184(ft)]= 3525 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand) 5337 (ft) x 0.440(psi/ft)= 2348 psi 2348(psi) - 0.1(psi/ft)*5337(ft) 1815 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Maximum Anticipated Surface Pressure Calculation 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 8-1/2" Hole Section PBU W-01B Prudhoe Bay Unit TVD 5,337 Page 63 Prudhoe Bay West W-01B SB Injector Drilling Procedure 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 64 Prudhoe Bay West W-01B SB Injector Drilling Procedure 30.0 Surface Location Page 65 Prudhoe Bay West W-01B SB Injector Drilling Procedure 6WDQGDUG3URSRVDO5HSRUW 1RYHPEHU 3ODQ:%ZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ : 3ODQ: 3ODQ:% 1800240030003600420048005400True Vertical Depth (1200 usft/in)0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000Vertical Section at 140.00° (1200 usft/in)Smokescreen wp05 tgt1Smokescreen wp03 tgt2Smokescreen wp03 tgt3Smokescreen wp03 tgt4Smokescreen wp03 tgt6Smokescreen wp08 tgt52000250030003500400045005000550060006500700075008000W-0113 3/8" x 17 1/2" TOW9 5/8" x 12 1/4"7" x 8 1/2"2500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016549W-01B wp08Start Dir 12.3º/100' : 2025' MD, 1973.72'TVD : 30° LT TFEnd Dir : 2042' MD, 1989.35' TVDStart Dir 4.5º/100' : 2062' MD, 2007.61'TVDEnd Dir : 2881.43' MD, 2610.98' TVDStart Dir 5º/100' : 7170.98' MD, 4791.12'TVDEnd Dir : 8360.35' MD, 5169.44' TVDBegin GeosteeringStart Dir 4º/100' : 8660.35' MD, 5190.37'TVDSV4SV3SV1Ugnu 4AUG3Ugnu MANBOA TopOBaOBcOBdHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: W-01Ground Level: 50.61+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.005959100.04612048.99 70° 17' 49.9407 N 149° 5' 33.4497 WSURVEY PROGRAMDate: 2024-10-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool30.25 2025.00 W-01 Srvy 1 GCT-MS (W-01) 3_Gyro-CT_pre-1998_Csg2025.00 2425.00 W-01B wp08 (Plan: W-01B) 3_MWD_Interp Azi+Sag2425.00 8575.00 W-01B wp08 (Plan: W-01B) 3_MWD+IFR2+MS+Sag8575.00 16548.58 W-01B wp08 (Plan: W-01B) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation2034.68 1957.57 2091.78 SV42559.29 2482.18 2785.63 SV33096.89 3019.78 3837.49 SV13491.10 3413.99 4613.12 Ugnu 4A3837.04 3759.93 5293.77 UG34589.09 4511.98 6773.47 Ugnu MA4858.83 4781.72 7308.05 NB4990.24 4913.13 7608.92 OA Top5048.13 4971.02 7769.14 OBa5130.24 5053.13 8074.52 OBc5184.31 5107.20 8573.53 OBdREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: W-01, True NorthVertical (TVD) Reference:W-01B planned @ 77.11usftMeasured Depth Reference:W-01B planned @ 77.11usftCalculation Method: Minimum CurvatureProject:Prudhoe BaySite:WWell:Plan: W-01Wellbore:Plan: W-01BDesign:W-01B wp08CASING DETAILSTVD TVDSS MD SizeName1973.81 1896.70 2025.10 13-3/8 13 3/8" x 17 1/2" TOW5184.41 5107.30 8575.00 9-5/8 9 5/8" x 12 1/4"5011.09 4933.98 16548.78 7 7" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 2025.00 22.21 103.11 1973.72 -101.18343.31 0.00 0.00 298.18 Start Dir 12.3º/100' : 2025' MD, 1973.72'TVD : 30° LT TF2 2042.00 24.05 100.55 1989.35 -102.54 349.84 12.30 -30.00 303.42 End Dir : 2042' MD, 1989.35' TVD3 2062.00 24.05 100.55 2007.61 -104.03 357.85 0.00 0.00 309.72 Start Dir 4.5º/100' : 2062' MD, 2007.61'TVD4 2881.43 59.45 83.67 2610.98 -95.39 891.22 4.50 -24.62 645.94 End Dir : 2881.43' MD, 2610.98' TVD5 7170.98 59.45 83.67 4791.12 311.86 4562.92 0.00 0.00 2694.09 Start Dir 5º/100' : 7170.98' MD, 4791.12'TVD6 8360.35 86.00 140.30 5169.44 -128.37 5540.24 5.00 75.28 3659.53 End Dir : 8360.35' MD, 5169.44' TVD7 8560.35 86.00 140.30 5183.39 -281.87 5667.68 0.00 0.00 3859.04 Smokescreen wp05 tgt18 8660.35 86.00 140.30 5190.37 -358.62 5731.40 0.00 0.00 3958.80 Start Dir 4º/100' : 8660.35' MD, 5190.37'TVD9 8694.63 87.03 140.28 5192.45 -384.95 5753.27 3.00 -1.05 3993.0210 9789.00 87.03 140.28 5249.18 -1225.60 6451.65 0.00 0.00 5085.9111 9893.08 90.00 141.24 5251.88 -1306.17 6517.46 3.00 17.89 5189.9212 10643.08 90.00 141.24 5251.88 -1891.00 6987.00 0.00 0.00 5939.7513 10659.84 89.99 141.66 5251.88 -1904.11 6997.45 2.50 91.41 5956.5014 12425.60 89.99 141.66 5252.20 -3289.05 8092.82 0.00 0.00 7721.5215 12425.65 89.99 141.66 5252.20 -3289.09 8092.85 2.50 73.13 7721.57 Smokescreen wp03 tgt316 12448.46 90.03 141.09 5252.20 -3306.91 8107.09 2.50 -86.42 7744.3717 13876.43 90.03 141.09 5251.56 -4418.07 9003.98 0.00 0.00 9172.0818 13890.07 90.04 141.50 5251.55 -4428.72 9012.51 3.00 87.99 9185.73 Smokescreen wp03 tgt419 14037.55 84.59 139.23 5258.45 -4542.13 9106.44 4.00 -157.43 9332.9820 15348.34 84.59 139.23 5381.94 -5530.41 9958.62 0.00 0.00 10637.8221 15484.85 90.00 140.00 5388.38 -5634.24 10046.93 4.00 8.13 10774.12 Smokescreen wp08 tgt522 16548.78 132.56 140.00 5011.09 -6376.36 10669.64 4.00 0.00 11742.89 Smokescreen wp03 tgt6 Total Depth : 16548.78' MD, 5011.09' TVD -7200-6600-6000-5400-4800-4200-3600-3000-2400-1800-1200-60006001200South(-)/North(+) (1200 usft/in)0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800West(-)/East(+) (1200 usft/in)Smokescreen wp08 tgt5Smokescreen wp03 tgt6Smokescreen wp03 tgt4Smokescreen wp03 tgt3Smokescreen wp03 tgt2Smokescreen wp05 tgt18962W-01APB18930W-01A50015002250250027503000325035003750400042504500475050005250550057506000625065006750700072507500775080008250850087509235W-0113 3/8" x 17 1/2" TOW9 5/8" x 12 1/4"7" x 8 1/2"325 0 3 50 0 3750 4000 42 5 0 4 50 0 4 75 05000 52505011W-01B wp08Start Dir 12.3º/100' : 2025' MD, 1973.72'TVD : 30° LT TFEnd Dir : 2042' MD, 1989.35' TVDStart Dir 4.5º/100' : 2062' MD, 2007.61'TVDEnd Dir : 2881.43' MD, 2610.98' TVDStart Dir 5º/100' : 7170.98' MD, 4791.12'TVDEnd Dir : 8360.35' MD, 5169.44' TVDBegin GeosteeringStart Dir 4º/100' : 8660.35' MD, 5190.37'TVDCASING DETAILSTVDTVDSS MDSize Name1973.81 1896.70 2025.10 13-3/8 13 3/8" x 17 1/2" 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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. POLARIS OIL 224-149 PBU W-01B PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT W-01BInitial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241490PRUDHOE BAY, POLARIS OIL - 640160NA1 Permit fee attachedYes ADL028263, ADL047451, and ADL0282642 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, POLARIS OIL - 640160 - governed by CO 484A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Governed by AIO 25A.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" to 80'18 Conductor string providedYes This is a sidetrack from an existing surface casing. Milling window above existing shoe. FIT to assure shoe.19 Surface casing protects all known USDWsYes Existing surface casing fully cemented.20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Intermediate casing to land horizontally in reservoir. Cement above confining zones.22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Hilcorp Innvovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitYes 10-403 for abandonment is approved. Sundry 324-63025 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes No diverter required27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Innovation has 10X 2-9/16"" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/8" remote hyd choke31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring will be required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. 63 ppm measured at W-204 (2021).35 Permit can be issued w/o hydrogen sulfide measuresYes No abnormally geo-pressured strata are anticipated. MPD to mitigate any abnormal pressures.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate12/4/2024ApprMGRDate12/6/2024ApprADDDate12/3/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateThis well includes a pilot hole/appraisal tail that extends outside of the Polaris Oil Pool and AIO. This tail will be plugged back and cemented; no injection will occur outside AIO affected area.*&:JLC 12/10/2024