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Home My WebLink About223-117Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 09/15/2025 InspectNo:susSTS250729154419 Well Pressures (psi): Date Inspected:7/26/2025 Inspector:Sully Sullivan If Verified, How?Other (specify in comments) Suspension Date:5/4/2025 #325-139 Tubing:170 IA:0 OA:100 Operator:Hilcorp North Slope, LLC Operator Rep:Andy Ogg Date AOGCC Notified:7/25/2025 Type of Inspection:Initial Well Name:PRUDHOE BAY UNIT 11-42 Permit Number:2231170 Wellhead Condition Clean, no oil stains or sign of leakage, Valves operted easily and guages were easy to read. Surrounding Surface Condition Clean and free of debris Condition of Cellar Clean with no signs of contaminents Comments Location verified by well pad plot map Supervisor Comments Photos (3) attached. Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Monday, September 15, 2025 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 2025-0726_Suspend_PBU_11-42_photos_ss Page 1 of 2 Suspended Well Inspection – PBU 11-42 PTD 2231170 AOGCC Inspection Rpt # susSTS250729154419 Photos by AOGCC Inspector S. Sullivan 7/26/2025 2025-0726_Suspend_PBU_11-42_photos_ss Page 2 of 2 7. 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 11-42 Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 223-117 50-029-23775-00-00 14159 Conductor Surface Intermediate Production Liner 8694 157 4882 10532 3739 8451 20" 10-3/4" 7" 4-1/2" 6697 47 - 204 47 - 4929 45 - 10577 10417 - 14156 47 - 204 47 - 3939 45 - 8365 8244 - 8694 8890 2470 5410 7500 8451 5210 7240 8430 None 4-1/2" 12.6# 13Cr80 43 - 8653 None Structural 4-1/2" HES TNT Perm Packer 8469 6711 Dave Bjork for Bo York Operations Manager Andy Ogg andrew.ogg@hilcorp.com 907.659.5102 PRUDHOE BAY, PRUDHOE 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 0028322, 0028325 43 - 6856 N/A N/A 0 0 0 170 N/A 13b. Pools active after work:PRUDHOE OIL No SSSV Installed 8469, 6711 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 3:23 pm, Aug 13, 2025 Digitally signed by David Bjork (3888) DN: cn=David Bjork (3888) Date: 2025.08.13 14:22:37 - 08'00' David Bjork (3888) RBDMS JSB 081825 J.Lau 11/4/25 DSR-9/11/25 ACTIVITY DATE SUMMARY 7/26/2025 T/I/O = 170/0/100. Temp = SI. AOGCC SU well inspection (AOGCC witnessed by Sully Sullivan). Pictures taken. SV = C. WV = LOTO. SSV = C. MV = O. IA, OA = OTG. 10:15 Daily Report of Well Operations PBU 11-42 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 28 Township: 11N Range: 15E Meridian: Umiat Drilling Rig: N/A Rig Elevation: N/A Total Depth: 14,159 ft MD Lease No.: ADL028325 Operator Rep: Suspend: X P&A: Conductor: 20" O.D. Shoe@ 127 Feet Csg Cut@ Feet Surface: 10-3/4" O.D. Shoe@ 4,929 Feet Csg Cut@ Feet Intermediate: 7" O.D. Shoe@ 10,577 Feet Csg Cut@ Feet Production: O.D. Shoe@ Feet Csg Cut@ Feet Liner: 5" x 4-1/2" O.D. Shoe@ 14,156 Feet Csg Cut@ Feet Tubing: 4-1/2" O.D. Tail@ 8,653 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Retainer 8,590 ft 8,452 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 2770 2696 2674 IA 0 0 0 OA 108 115 118 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Reservoir abandonment of PBU 11-42 and then suspended. Well has 2500 ft of diesel freeze protect and 8.3 ppg KCL from 5952 to 8452 ft MD. Due to high winds on 5/3/2025 they could only do the MIT-T. The plug tag was performed on 5/4/2025. May 4, 2025 Sully Sullivan Well Bore Plug & Abandonment PBU 11-42 Hilcorp North Slope LLC PTD 2231170; Sundry 325-139 none Test Data: P Casing Removal: Andreas Ponti Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0504_Plug_Verification_PBU_11-42_ss 9 9 9 99 99 9 9 9 9 9 9 9 9 999 999 999 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.05.19 14:18:43 -08'00' 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:Oliver Sternicki Cc:David Bjork Subject:RE: 11-42 (PTD # 223-177) Sundry # 325-139- execution extension request Date:Thursday, April 17, 2025 2:32:57 PM Oliver, You are approved for a 30 day extension to complete the reservoir abandonment. Jack From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Thursday, April 17, 2025 12:54 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: David Bjork <David.Bjork@hilcorp.com> Subject: 11-42 (PTD # 223-177) Sundry # 325-139- execution extension request Importance: High Jack, Well 11-42 is in ops shutdown per sundry 324-159 dated 5/3/24. We are required to complete or abandon the well no later than 4/22/25 per the conditions of approval. Sundry 325-139 for suspension of the well was approved on 3/26/25 and WIO approval for completion of the work was just approved in the last couple days. We would like to request an extension of 30 days to complete the required reservoir abandonment work on the well. Regards, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Supervisor Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com 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. By Grace Christianson at 3:36 pm, Mar 12, 2025 325-139 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.03.12 14:19:33 - 08'00' Torin Roschinger (4662) DSR-3/24/25 X AOGCC Witnessed tag TOC and MIT-T to 2500 psi. SFD 3/18/2025 March 31, 2030 JJL 3/17/25 10-407 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.26 08:25:47 -08'00'03/26/25 RBDMS JSB 032725 Well Name:11-42 API Number: 50-029-23775-00-00 Current Status:Producer Rig: EL Estimated Start Date:April 1 2024 Estimated Duration:1 days New PTD Number:223-117 Date Approval Rec’vd:3/15/24 Regulatory Contact:Carrie Janowski First Call Engineer:David Wages 713.380.9836 (Cell) 2nd Call Engineer:David Bjork 907.440.0331 (Cell) Current Bottom Hole Pressure: Max Bottom Hole Pressure: Min ID: Reservoir Pressure MASP 2982 psi @ 8010’ TVD 3000 psi @ 8010’ TVD N/A 3365 psi 2458 psi (Estimated, offset SBHP, 7.2 ppg) (Estimated, offset SBHP, 7.2 ppg) Brief Well Summary: 11-42 is a new Zone 1 FURy producer, similar to offsets 11-23, 11-39 and 11-40. After drilling the production section, the production liner was run. The last 200’ required 2 rpm @ 7000 ft-lbs torque. The cement job was pumped per plan. It took two tries to get the liner hanger set then two tries to get the packer set. The added time to get off the liner hanger plus a potential early set of the cement caused the drill pipe to be cemented in place. While trying to move pipe we parted at 674’ on 3-2-24. The pipe was overshotted and eline followed up with a free point and found the pipe free to 10,000’, successfully drift through liner setting tool to 10,614’ (TOL @ 10,417’) with a CCL that confirmed the Liner setting tool is off the packer by ~8’ and up then proceeded to perform the following cuts: 3/3/24: 1st cut @ 10,314’, unable to pull free with 75k overpull. 3/4/24: 2nd cut @ 10,094’ ELM, 75k overpull, not free 3rd cut @ 9872’ ELM, 75k overpull, not free 4th cut at 9653’ ELM, 75k overpull, not free 5th cut @ 9434’ ELM, welltec says no successful cut 6th cut @ 9403’ ELM, 75k overpull, not free 7th cut @ 9152’ ELM, 75k overpull, not free 8th cut @ 8902’ ELM, welltec says no successful cut 3/5/24: Try again at 8901’, unable to cut, welltec tool damaged, remaining cuts not effective until BHA changed out 3/6/24: CBL, vendor (attached, below), TOC called at 8900’ Punch pipe @ 8890’, unable to establish circulation 3/7-8/24: made unsuccessful cuts at 8868’, 8613’, 8050’, 8038’ 9th cut @ 8008’ ELM, drillpipe free 3/9/24: Latch onto fish, unable to pull free, RU cutter 10th cut @ 8890’, some movement but not free 11th cut @ 8640’, some movement, eventually got free, top of drill pipe fish at 8640’ Rig performed washpipe run prior to running completion. Free point tool was likely run in soft cement and is the reason pipe was cut so low on the first attempt. 3/23/2024: Coil milled on drill pipe fish, summary below 3/28: camera run 4/9: attempted to mill top of drill pipe open without success Objective: The purpose of this outline is to provide background information and summary program to support reservoir abandonment of 11-42 to satisfy 20 AAC 25.072(d). Procedure: Slickline: 1. Drift for tubing punch Eline: 2. Tubing punch @ ~8518’ a. 3-5’ of shot, top shot at ~8518’, across top full joint collar. Coil: Vol between tubing packer and DP annulus TOC (ID+OD): 15.2 bbls 3. Set cement retainer @ ~8590’ below upper X-nipple in tubing tail. 4. Pump 30 bbls cement a. Circulate in 15 bbls 15.8# cement, attempt to squeeze 5 bbls cement below retainer (20 bbls pumped through retainer) 5. Unsting from retainer, lay in remaining 10 bbls to safety. a. Safety @ 7932’ 6. If possible, downsqueeze from safety additional 5 bbls. a. TOC after attempt should be at 8260’ 7. Reverse FCO to 8465’ 8. POOH Slickline 9. Tag TOC and record in AWGRs *AOGCC Witnessed tag TOC and MIT-T to 2500 psi. - JJL Current WBD: 8890’ - Drill Pipe Splintered Into Itsself Proposed WBD: Post Rig Drillpipe CBL: Drilling Manager 05/10/24 Monty M Myers By Grace Christianson at 3:03 pm, May 14, 2024 DSR-5/14/24WCB 2-12-2025 RBDMS JSB 052825 Note: Lined spaces provided. Do Not add or delete rows from the tables. If you have more data than spaces provided, don't CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBU DS11-42 Date:2/6/2024 Csg Size/Wt/Grade:10.75 45.5# L-80 Supervisor:Barber/Carter Csg Setting Depth:4929 TMD 3929 TVD Mud Weight:9.6 ppg LOT / FIT Press =933 psi LOT / FIT =14.17 ppg Hole Depth =4959 md Fluid Pumped=3.9 Volume Back =2.1 bbls Estimated Pump Output:0.093 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->080 ->00 ->2 141 ->584 ->4 203 ->10 241 ->6 266 ->15 486 ->8 334 ->20 759 ->10 381 ->25 1044 ->12 437 ->30 1250 ->14 493 ->35 1511 ->16 557 ->40 1784 ->18 593 ->45 2061 ->20 639 ->50 2340 ->22 686 ->55 2625 ->24 722 ->60 2912 ->26 755 ->65 3200 ->28 786 ->30 816 ->32 838 ->34 862 ->36 888 ->38 910 ->40 921 ->42 933 Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->1 821 ->0 3234 ->2 742 ->1 3233 ->3 716 ->2 3232 ->4 692 ->3 3230 ->5 674 ->4 3230 ->6 658 ->5 3229 ->7 647 ->6 3228 ->8 633 ->7 3228 ->9 622 ->8 3226 ->10 611 ->9 3226 ->10 3224 ->15 3221 ->20 3220 ->30 3218 use all data points. Record all casing test pressures and volumes even though the higher values will not appear on the gra 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 0 5 10 15 20 25 30 35 40 45 50 55 60 65 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 3100 3200 3300 0 10203040506070Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA aph. 821 742716692674658647633622611 32343233323232303230322932283228322632263224 3221 3220 3218 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 3100 3200 3300 3400 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBU 11-42 Date:2/18/2024 Csg Size/Wt/Grade:7" 26# L-80 BTC Supervisor:Anderson/Amend Csg Setting Depth:10,577 TMD 8,365 TVD Mud Weight:8.5 ppg LOT / FIT Press =654 psi LOT / FIT =10.00 ppg Hole Depth =10602 md Fluid Pumped=1.4 Bbls Volume Back =0.5 bbls Estimated Pump Output:0.093 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->032 ->2107 ->444 ->4362 ->681 ->8664 ->8 156 ->12 1001 ->10 241 ->16 1211 ->12 396 ->20 1472 ->14 540 ->24 1748 ->15 654 ->28 2038 -> ->32 2340 -> ->36 2654 -> ->40 3009 -> ->44 3312 -> ->48 3642 -> ->50 3694 Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 654 ->0 3694 ->0.5 637 ->1 3652 ->1 630 ->2 3646 ->1.5 624 ->3 3642 ->2 620 ->4 3638 ->3 612 ->5 3636 ->4 606 ->10 3628 ->5 600 ->15 3624 ->6 595 ->20 3622 ->7 590 ->25 3621 ->8 586 ->30 3620 ->9 582 -> ->10 579 -> -> -> 0 4 6 8 10 12 14 15 2 4 8 12 16 20 24 28 32 36 40 44 48 50 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 3100 3200 3300 3400 3500 3600 3700 3800 0 102030405060Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 654637630624620612606600595590586582579 369436523646364236383636 3628 3624 3622 3621 3620 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 3100 3200 3300 3400 3500 3600 3700 3800 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA ACTIVITYDATE SUMMARY 3/14/2024 Pick up the tubing hanger & make up to the string. Install TWC at rig floor, land tubing hanger with TWC, Visually verify through upper annulus valve. Run in LDS & torque gland nuts, then LDS to 450 ft-lbs, Lay down landing joint. Close blind rams & test tubing hanger at 3500 psi (good test). Stand by for BOP nipple down. Clean the tubing hanger void, TWC & ring groove areas, lightly grease the seal areas, and install SBMS: Nipple up adapter & dry hole tree. Test the tubing hanger void at 500 psi for 5 min & 5000 psi for 10 min (good tests). Sting the SBMS monitor port & stand by for the rig to test the tree. (good test). Pull TWC with the dry rod. Stand by for freeze protect. Set H BPV #109 with Dry rod. Secure well head RDMO. 3/15/2024 T/I/O=0/0/0. Post Parker 273. Set 4" CIW "H" TWC and Removed 4" dryhole tree and installed 4" CIW FLS production tree. Torqed flanges to API spec. Pressure tested upper tree against TWC to 500/5000 psi. Pass. Pulled 4" "H" TWC. Connected production piping and set wellhouse. ***Job Complete*** Final WHP's 0/0/0. 3/16/2024 T/I/O = TWC/0/0. Removed 4' Gate valve above Master. Installed 4" CIW Upper tree, torqued to spec. Tested against Master, PT low (350 psi) Passed. PT High (5000 psi) Passed. Pulled 4" CIW TWC. Rolled OA Gate Valve from front to back. Installed VR Plug on Companion OA torqued to spec. FWP = 0/0/0 3/16/2024 T/I/O=16/0/15. Assist Slickline - Circ out well down TBG up IA. Pumped 10 bbls 60/40 Down TBG to prove communication. Pumped 213 bbls Inhibited 1%KCL. Pumped 5 bbls 60/40 and 85 bbls 90* diesel Down TBG. U-Tube FP. Perform MIT-T. Perform MIT-IA. SL in control of well and DSO notified upon LRS departure. MIT-T - 26/23/0 Pumped 1.9 bbls Diesel to achieve MAP of 3600 psi. 3604/314/0 TBG lost 68 psi 1st 15 min, lost 30 psi 2nd 15 min. Final 3506/307/0 - MIT-T = PASSED. Bled back 0.7 bbls MIT-IA - 2016/175/0 - Pumped 2.68 bbls Diesel to achieve MAP of 3600 psi. 2503/3604/0 TBG lost 54 psi 15 min, lost 20 psi 2nd 15 min. Final 2489/3530/27 - MIT-IA = PASSED. Bled back 2.9 bbls 3/16/2024 ***WELL S/I ON ARRIVAL***(post rig) DRIFT TO XN @ 8,582' MD W/ 3.8" G.RING SET 4-1/2" PXN IN XN NIPPLE @ 8,582'MD SET P-PRONG IN PXN @ 8,582' MD W/ BAITSUB AND GUTTED JD (catcher) LRS SET PRODUCTION PACKER, MIT-T TO 3506 PSI, LOST 68 PSI IN 1ST 15 MIN, 30 PSI 2ND 15 MIN, PASS MIT-IA TO 3530 PSI, LOST 54 PSI 1ST 15 MIN, 20 PSI 2ND 15 MIN, PASS PULL 1" BK-DMY GLV FROM STA #2 @ 8,046' MD PULL 1" BK-DMY GLV FROM STA #1 @ 8,366' MD ***CONT WSR ON 03/17/2024*** 3/17/2024 ***CONT WSR FROM 03/16/2024*** PULL 1" BK-DMY GLV FROM STA #3 @ 7,317' MD PULL 1" BK-DMY GLV FROM STA #4 @ 6,285' MD PULL 1" BK-DMY GLV FROM STA #5 @ 4,309' MD SET 1" BK-LGLV (16/64" ports, 1876# tro) IN STA #5 @ 4,309' MD SET 1" BK-LGLV (16/64" PORTS, 1869# tro) IN STA #4 @ 6,285'MD SET 1" BK-LGLV (16/64" PORTS, 1,848 tro) IN STA #3 @ 7,311' MD SET 1" BK-LGLV (16/64" ports, 1822# tro) IN STA #2 @ 8,046' MD ***CONT WSR ON 03/18/2024*** 3/18/2024 ***CONT WSR FROM 03/18/2024*** HES 759 R/D ***WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED ON WELL STATUS*** Daily Report of Well Operations PBU 11-42 Daily Report of Well Operations PBU 11-42 3/18/2024 ***WELL S/I ON ARRIVAL*** SET BK-OGLV IN ST #1 (8,366' MD) FAILED IA DDT. ***CONTINUED ON 3/19/24 WSR*** 3/19/2024 ***CONTNUED FROM 3/18/24 WSR***(New well post) PULLED 3 1/2" BAITSUB, GUTTED JD,P-PRONG FROM PLUG @ 8,573' MD(Empty) RAN 4 1/2" D&D HOLEFINDER TESTING BETWEEN EACH VALVE(Leak @ st #5) PULLED & REPLACED BK-LGLV FROM ST #5 @ 4,309' MD(Good ia ddt) PULLED PX PLUG BODY FROM 8,573' MD DRIFTED w/ 1.76" CENT,20'x1.56 DUMMY GUNS(1.72" Swell),1.75" S.BAILER TO STICKY TAG @ 8,871' SLM RAN 5'x2 1/2" DD BAILER TO HARD TAG @ 8,865' SLM(Metal marks on bailer bottom) ***CONTINUED ON 3/20/24 WSR*** 3/19/2024 T/I/O/ 571/600/0 Temp S/I (TFS unit 4 assist SL with DND holefinder) Pumped 2.2 bbls of crude to Assist SL with DND holefinder. Pollard Sl in control of well upon TFS departure FWHPS = 850/825/0 3/20/2024 ***CONTINUED FROM 3/19/24 WSR*** (New well post) RAN 2.80" LIB TO 8,638' SLM(Impression from entring drillpipe but otherwise clean) RAN 2" LIB TO 8,864' SLM(Impression of jagged metal through center of lib) ***WELL S/I ON DEPARTURE*** 3/23/2024 LRS #1 1.5" coil, 0.134WT blue coil Objective: Dress/mill 4" drill pipe, Extended adperf Weekly bop test. MIRU. Function BOPs on installation. Make up and RIH with BOT 1.77" diamond speed mill. Start time milling at 8871', made ~3' at surface and stopped making progress. Trip out to inspect mill. 1.77" speed mill had a 1/2" hole milled into the off center face of the mill to a depth of ~3/4" into the mill. Basically milled out one of the three jets, welded it shut and forced the flow out the two other jets and washed them out/jet cut them. RBIH with new 1.77" diamond speed mill with no side cutting structure. Tag 8875' ctm, begin turning mill, rih slow, no motor work down to 8883', pull back up through original spot, smooth. RIH slow to next cut area. Experienced stalls at next cut area 8890 ctm. ***In progress*** Daily Report of Well Operations PBU 11-42 3/24/2024 LRS #1 1.5" coil, 0.134WT blue coil Objective: Dress/mill 4" drill pipe, Extended adperf Continue to experience motor work/ mill cut area near 8890'-8899'. Quite a few stalls at different depths trying to get back to 8899'. See log. Trip to inspect mill. 1.77" diamond mill is intact and still in full gauge. No marks on side or face of mill. Swap to 1.875" diamond parabolic. Tagged and milled at previous spot 8863 CTM - right at the same flag from run #1. Did not make progress. POOH to swap mills. Lay down the mill and missing .25" of the mill face. Broken off at the 1.5" OD of the shoulder. RIH with 1.77" diamond speed mill. Tagged at 8875. PUH and bring pump online and made it past the cut 8'. PBUH and tag at 8875 again. Cycle pipe to get in. Tried various pump rates and speeds and never could get back in there. POOH for 2.125" motor + 2.27" diamond parabolic. Cut 100' of pipe. RIH. Tag 8875', Start milling at 8873' (Paint new Blue/orange flag). Begin time milling. When milling it is pretty grabby, 8k overpulls but comes free easily. *Perform man down drill* ***Left in hole: .25" x 1.5" cutting structure of a diamond parabolic mill**** ***In progress*** 3/25/2024 LRS #1 1.5" coil, 0.134WT blue coil Objective: Dress/mill 4" drill pipe, Extended adp Continue time milling at ~8871' with 2.27" diamond parabolic mill (see log). 1.7bpm resulted in less stalls vs 1.5bpm. Made it past and tagged at the second cut at 8892 CTM. Time drilled and made it 2' past the cut and continued to have stalls and not make progress. POOH to check mill. 2.27" diamond parabolic was heavily worn (2.17" OD now), see log for details. RIH with 1.85" convex mill. Make it down to 8901 and could not make progress. Instantaneous stalls. POOH. MU/RIH with 1.69" bowspring cent + 1.75" DJN, tag twice at 8900' ctm. POOH. MU/RIH with 2.125" motor + 2.28" diamond parabolic mill. **In progress** 3/26/2024 LRS #1 1.5" coil, 0.134WT blue coil Objective: Dress/mill 4" drill pipe, Extended adp RIH w/ 2.125" motor + 2.28" diamond parabolic mill. Dry tag 8897'. Start motorwork ~8887'. Detained for a moment at 8888' while backreaming, got free without jars firing. Getting motorwork at 8875' now. Able to dry drift down to 8895. There is something going on ~8877 where it doesnt like a 2.28" mill spinning but you can drift through it. Dry drifted up/dn through this spot a couple times with no issue. Drift down and start time milling 8887'. Milled down 7.4' and stopped making progress. POOH to inspect mill. Similar to the previous diamond parabolics OD is worn down to 2.21" and all buttons on the side up the shoulder to a 1.78" OD are completely stripped. Relay results to OE and decision to prep for camera run. RIH with 1.85" tapered mill. Experienced consistent stalls at 8898.5' with no progress. CIrculate video water (Filtered FW + LO71 clarifier) from deepest depth all the way OOH. Drop circ sub ball once out of the drill pipe and chase OOH. FP well to 2500' with 60/40. Tapered mill looked barely used. 3/8" circ sub ball recovered. Continue RD. ***In progress*** Daily Report of Well Operations PBU 11-42 3/27/2024 LRS #1 1.5" coil, 0.134WT blue coil Objective: Dress/mill 4" drill pipe, Extended Adperf Winds below 35 mph. Lay down mast and complete rig down. Standby for E-pad snow removal before traveling to E-pad. ***Job Scope Not Completed*** 3/29/2024 ***WELL S/I ON ARRIVAL*** ( READ 1.69" CAMERA) RIG UP YJ ELINE. PT PCE 300 PSI LOW /3000 PSI HIGH RIH W/CH/ X2 1 11/16'' WT BARS / 1.69" READ CAMERA TO IDENTIFY RESTRICTIONS OR CUTS TO THE DP. AT 15:29 / 8637 WE BELIEVE IS THE TOP OF THE OVERSHOT. AT 15:26/ 8640' WE THINK IS THE TOP OF THE STUB FLUID CLAIRITY WAS DECENT DOWN TO THE TOP OF THE 4" DP CUT AT ~8,639'. CLARITY GOT MUCH WORSE ONCE INSIDE THE 4" DP. UNABLE TO GET GOOD CLEAR VIDEO. AT 8,895' THE VIDEO SHOWES A MOJOR PIPE DISTORTION THAT COULD POSSIBLY BE STRETCHED OUT PIPE OR A SECTION OF PIPE THAT HAS BEEN OPENED UP. THE VIDEO IS UNCLEAR. THE VIDEO TIME LOG AFTER 2 PM IS THE MOST RELEVANT. AWAIT PLAN FORWARD FROM TOWN, VIDEO LOG COMPLETE FOR NOW. ***WELL S/I ON DEPARTURE*** 4/9/2024 LRS CTU #1 - 1.50" CT Job Objective: Camera Log Support MIRU CTU. Make up slim 1.50" DJN BHA. ...Job Continued on WSR 4-10-24... 4/10/2024 LRS 70 - Assist CTU. Heat Diesel Transport to 70*F ***3 hours standby time for transport*** 4/10/2024 LRS CTU #1 - 1.50" CT. Job Objective: Camera Log Support RIH with slim DJN BHA and tag obstruction at 8897' CTMD. Circulate the well with heated diesel followed by neat methanol. Pumped 1.4X bottoms up to get good methanol clarity at surface. POOH pumping pipe displacement and maintain pressure to avoid CI brine in IA from inflowing. OOH with slim DJN BHA. Stack down and prep for E/L camera run. ***Job Continue on 4/11/2024*** ***8.5 hours waiting on fluids*** 4/11/2024 *** LRS COIL ON HOLE *** ELINE TO RU NEXT TO LRS FOR CAMERA INSPECTION LOG 8895 FT OBSERVE AREA OF INTEREST, TROUBLED PIPE... PULLED MULTIPLE PASSES POOH JOB COMPLETE ***WELL S/I ON DEPARTURE*** 4/11/2024 LRS CTU #1 - 1.50" CT. Job Objective: Camera Log Support Standby while E/L runs camera. Decision made to rig down. ***Job Complete*** Drilling Manager 03/12/24 Monty M Myers By Grace Christianson at 11:30 am, Apr 22, 2024 * Operation shutdown approved for no more than 1 year from 22-APRIL-2024. Well to be completed or abandoned by 22-APRIL-2025. *Well is currently secure with passing MIT to 3500 psi. MGR22APR24 A.Dewhurst 02MAY24 10-404 DSR-4/23/24JLC 5/3/2024 _____________________________________________________________________________________ Prudhoe Bay Unit Well: 11-42 Last Completed: TBD PTD: 223-117 Operations Shutdown request for 11-42: The well was successfully drilled to TD at 14,159 MD. 4-1/2 liner was successfully run and cemented in place. However, we ended up sticking the running tool assembly and were unable to get free before cement reached its thickening time. In this attempt to free, the drillstring was parted at ~650 MD. An overshot run successfully grabbed on to the parted drillpipe joint and following e-line runs indicated the running tool was ~8 above the tieback receptacle on the top of the liner, and able to drift into the 4-1/2 production liner. Although a freepoint log indicated free pipe just above the running tool, mechanical cuts indicated otherwise. This was confirmed by a CBL that indicated TOC at ~8,920 with spacer and likely cement stringers above. Ultimately, we have recovered drillpipe down to 8,640 MD with the last segment (8,008 to 8,640) showing cement on the connection upsets, further indicating cement stringers above the TOC. An attempt was made, Sunday night, to try and wash over the drillpipe stub and recover more drillpipe. However, little progress was made after 8,698 and the risk of milling a hole in the 7 intermediate casing is too high and ultimately ended our drillpipe recovery efforts. We then ran in and dressed off the drillpipe stub looking up and performed a passing casing/liner/fish test to 3,500psi for 30 minutes. After the successful test, we displaced the fluids above the drillpipe stub from 8.8ppg drilling mud to 8.8 ppg brine. Currently, we are coming out of the hole with the dressoff assembly. Hilcorp is requesting an Operations Shutdown on 11-42. The proposed configuration of the well will allow for intervention access and flexibility to either complete or abandon. Attached is the proposed schematic the condition of the well at rig release. Proposed plan forward after laying down the dressoff assembly: 1. Run 4-1/2 kill string with overshot to swallow the dressed off drillpipe stub at 8,640 MD. NOTE: a. This kill string will include a production packer, landing nipples, and gas lift mandrels (with dummy valves installed) for possible future production opportunities or as a conduit for P&A. b. As a kill string, the production packer will not be set by Parker 273. The packer will not be set unless approved in a future Sundry with the AOGCC. 2. Circulate freeze protect to ~2,400 MD per the original program 3. Set TWC. 4. ND BOPE. NU tree and test. 5. RDMO p p y performed a passing casing/liner/fish test to 3,500psi for 30 minutes. 1 Joseph Lastufka From:Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent:Tuesday, March 12, 2024 1:23 PM To:Frank Roach Cc:Joseph Lastufka Subject:[EXTERNAL] RE: PBE 11-42 (PTD 223-117) Operations Shutdown Request Frank, Joe, Submit the 10- Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Tuesday, March 12, 2024 10:09 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PBE 11-42 (PTD 223-117) Operations Shutdown Request Mel, - The well was successfully drilled to TD at 14,159 MD. 4-1/2 liner was successfully run and cemented in place. However, o free, the drillstring was parted at ~650 MD. An overshot run successfully grabbed on to the parted drillpipe joint and following e- the 4- running tool, mechanical cuts indicated otherwise. This was con rmed by a CBL that indicated TOC at ~8,920 with spacer and likely cement stringers above. and wash over the drill 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. 2 ran in and dressed o the drillpipe stub looking up and performed a passing casing/liner/sh test to 3,500psi for 30 he successful test, we displaced the uids above the drillpipe stub from 8.8ppg drilling mud to 8.8 ppg brine. Currently, we are coming out of the hole with the dresso assembly. - 1. Run 4-1/2 kill string with overshot to swallow the dressed o drillpipe stub at 8,640 MD. NOTE: a. b. approved in a future Sundry with the AOGCC. 2. Circulate freeze protect to ~2,400 MD per the original program 3. Set TWC. 4. ND BOPE. NU tree and test. 5. RDMO dresso BHA is at surface and laid down. A 10- Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office 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 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 the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: 4/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240412 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU E-19 50029227460000 197037 3/25/2024 READ CaliperSurvey MPU G-18 50029231940000 204020 3/21/2024 READ CaliperSurvey MPU L-07 50029220280000 190037 3/30/2024 READ CaliperSurvey PBU 01-19C 50029208000300 213171 2/22/2024 BAKER MRPM PBU 01-28B 50029215970200 223089 1/21/2024 BAKER MRPM PBU 11-42 50029237750000 223117 3/5/2024 HALLIBURTON RBT PBU N-11D 50029213750300 223083 2/14/2024 BAKER MRPM PBU N-21A 50029213420100 196196 3/28/2024 BAKER SPN PBU S-201A 50029229870100 219092 4/8/2024 READ LeakPointSurvey Please include current contact information if different from above T38705 T38706 T38707 T38708 T38709 T38710 T38711 T38712 T38713 PBU 11-42 50029237750000 223117 3/5/2024 HALLIBURTON RBT Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.16 11:46:27 -08'00' 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: 03/26/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: PBU 11-42 PTD: 223-117 API: 50-029-23775-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (01/30/2024 to 02/27/2024) x AGR, DGR, BaseStar, ABG, EWR-M5, ADR, LithoStar, Horizontal Presentation x (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: LWD Subfolders: Geosteering Subfolders:g Please include current contact information if different from above. 223-117 T38673 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.27 11:18:03 -08'00' 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:Dewhurst, Andrew D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] FW: PBU 11-42 Sundry 324-164 (PTD 223-117): Data Request Date:Thursday, March 14, 2024 4:10:42 PM From: Dewhurst, Andrew D (OGC) Sent: Thursday, March 14, 2024 16:10 To: 'Joseph Lastufka' <Joseph.Lastufka@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Cc: Brodie Wages <David.Wages@hilcorp.com> Subject: RE: [EXTERNAL] FW: PBU 11-42 Sundry 324-164 (PTD 223-117): Data Request Received. Thank you. Andy From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Thursday, March 14, 2024 15:50 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Cc: Brodie Wages <David.Wages@hilcorp.com> Subject: RE: [EXTERNAL] FW: PBU 11-42 Sundry 324-164 (PTD 223-117): Data Request Andy, Talked with Brodie and we decided I’d send out the information after your phone discussion with him earlier. Please see attached directional survey and open hole field final log. Our geologist for this well is out of office until next week so as soon as we have them I’ll forward them along as well. It is understood that this submittal does not meet the final reporting requirements of Regulation 20 AAC 25.071 for this well. Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Office: (907)777-8400, Cell:(907)227-8496 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, March 14, 2024 3:18 PM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] FW: PBU 11-42 Sundry 324-164 (PTD 223-117): Data Request Joe, Forgot to CC you. Andy From: Dewhurst, Andrew D (OGC) Sent: Thursday, March 14, 2024 14:13 To: david.wages@hilcorp.com Cc: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: PBU 11-42 Sundry 324-164 (PTD 223-117): Data Request Brodie, I am reviewing the sundry for PBU 11-42. Would you please send me a copy of the digital data for this well: directional survey (.txt or .xls), logs (.las), and geologic tops (.xls)? Thank you, Andy Please note that this preliminary information does not meet the final reporting requirements of Regulation 20 AAC 25.071 for this well. Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 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 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. By Grace Christianson at 3:49 pm, Mar 13, 2024 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643) Date: 2024.03.13 15:26:33 - 08'00' Aras Worthington (4643) 324-164 10-407 MGR14MAR24 DSR-3/14/24A.Dewhurst 14MAR24*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.15 10:29:52 -08'00'03/15/24 RBDMS JSB 031924 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT 11-42 JBR 03/07/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 good test. Tested/functioned remote panel in TP office Test Results TEST DATA Rig Rep:J. King/ B. HerbertOperator:Hilcorp North Slope, LLC Operator Rep:S.Barber/S. Carter Rig Owner/Rig No.:Parker 273 PTD#:2231170 DATE:2/5/2024 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopAGE240207132701 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 2458 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 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 5"P #2 Rams 1 Blind shear P #3 Rams 1 2 7/8 X 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8"P Kill Line Valves 2 2 1/16"-3 1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P2000 200 PSI Attained P16 Full Pressure Attained P74 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2575 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P20 #1 Rams P6 #2 Rams P8 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1      STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT 11-42 JBR 03/07/2024 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:All 5 alarms stations tesed good. 5" test joint was used and the blocks were slacked off to verify complete bag closure. Pre charge bottles: 24 @1078 psi. TEST DATA Rig Rep:Brandon DavisOperator:Hilcorp North Slope, LLC Operator Rep:Shane Barber Contractor/Rig No.:Parker 273 PTD#:2231170 DATE:1/28/2024 Well Class:DEV Inspection No:divJDH240129134617 Inspector Josh Hunt Inspector Insp Source Related Insp No: Test Time:1.5 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:0 NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:13.5 P Vent Line(s) Size:16 P Vent Line(s) Length:36 P Closest Ignition Source:100 P Outlet from Rig Substructure:50 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:P Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:39 P Knife Valve Open Time:32 P Diverter Misc:0 NA Systems Pressure:P3050 Pressure After Closure:P2300 200 psi Recharge Time:P30 Full Recharge Time:P65 Nitrogen Bottles (Number of):P14 Avg. Pressure:P2500 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: 0 NAMud System Misc:           Annulars close and Knife-valve open times passing based on Diverter size but slow (45 sec allowed for Annular close time) -- J. Regg; 3/7/2024 New Well Post Well: 11-42 Current PTD: 223-117 Well Name:11-42 API Number: 50-029-23775-00-00 Current Status:Producer Rig: SL, coil, WT Estimated Start Date:March 18, 2023 Estimated Duration:8 days New PTD Number:223-117 Date Approval Rec’vd:12/21/23 Regulatory Contact:Carrie Janowski First Call Engineer:David Wages 713.380.9836 (Cell) 2nd Call Engineer:David Bjork 907.440.0331 (Cell) Current Bottom Hole Pressure: Max Bottom Hole Pressure: Min ID: 2982 psi @ 8010’ TVD 3000 psi @ 8010’ TVD 1.95” Liner Hanger setting tool (schematic below) (Estimated, offset SBHP, 7.2 ppg) (Estimated, offset SBHP, 7.2 ppg) Brief Well Summary: 11-42 is a new Zone 1 FURy producer, similar to offsets 11-23, 11-39 and 11-40. The completion packer has NOT been set Completion depths subject to change only slightly after tubing is spaced out Summary of drilling events associated with cemented drill pipe: After drilling the production section, the production liner was run. The last 200’ required 2 rpm @ 7000 ft-lbs torque. The cement job was pumped per plan. It took two tries to get the liner hanger set then two tries to get the packer set. The added time to get off the liner hanger plus a potential early set of the cement caused the drill pipe to be cemented in place. While trying to move pipe we parted at 674’ on 3-2-24. The pipe was overshotted and eline followed up with a free point and found the pipe free to 10,000’, successfully drift through liner setting tool to 10,614’ (TOL @ 10,417’) with a CCL that confirmed the Liner setting tool is off the packer by ~8’ and up then proceeded to perform the following cuts: 3/3/24: 1st cut @ 10,314’, unable to pull free with 75k overpull. 3/4/24: 2nd cut @ 10,094’ ELM, 75k overpull, not free 3rd cut @ 9872’ ELM, 75k overpull, not free 4th cut at 9653’ ELM, 75k overpull, not free 5th cut @ 9434’ ELM, welltec says no successful cut 6th cut @ 9403’ ELM, 75k overpull, not free 7th cut @ 9152’ ELM, 75k overpull, not free 8th cut @ 8902’ ELM, welltec says no successful cut 3/5/24: Try again at 8901’, unable to cut, welltec tool damaged, remaining cuts not effective until BHA changed out 3/6/24: CBL, vendor (attached, below), TOC called at 8900’ Punch pipe @ 8890’, unable to establish circulation 3/7-8/24: made unsuccessful cuts at 8868’, 8613’, 8050’, 8038’ 9th cut @ 8008’ ELM, drillpipe free 3/9/24: Latch onto fish, unable to pull free, RU cutter 10th cut @ 8890’, some movement but not free 11th cut @ 8640’, some movement, eventually got free, top of drill pipe fish at 8640’ Rig performed washpipe run prior to running completion. New Well Post Well: 11-42 Current PTD: 223-117 Free point tool was likely run in soft cement and is the reason pipe was cut so low on the first attempt. As cuts were made, I would expect some of the soft cement to slough into the well, slickline drift prior to coil arrival. Objective: Set production packer, install LGLVs, perforate liner, POP well Procedure: Slickline w/ fullbore assist- 1. Pull BPV if not already done 2. Fullbore circulate corrosion inhibited 1% KCl plus freeze protect: a. Below 8640’: i. 12.5 ppg mudpush on drillpipe annulus ii. 9.2 ppg mud inside drillpipe b. T+IA Volume to tubing tail at 8640’: 293 bbls c. T+IA freeze protect volume to 2500’: 85 bbls d. Inhibited brine volume: 210 bbls 3. Slickline: Drift to deviation a. Step to ensure properly overshot over the drillpipe 4. Install Plug in XN nipple 5. Follow HES setting procedure to set production packer 6. MIT-T to 3500 psi 7. Bleed tubing pressure to 2000 psi, MIT-IA to 3500 psi 8. Install LGLVs 9. Pull TTP 10. Drift to deviation 1.56” guns (1.76” swell) Coiled Tubing Notes: x This work may be completed with either 1.5” or 1.75” coil, whichever is first available x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. x The well will be killed and monitored before making up the initial perfs guns. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. 1. After MU MHA and pull test the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 2. If slickline tagged up in or near the liner packer running tool, perform mill run through drillpipe and liner running tool. a. 2.52” ID for the upper 9.63’ portion of the running tool (10,365’ – 10,375’) b. Dog sub down is 1.95” Drift ID (10,375’ – 10,404’) 3. MU and RIH with GR/CCL and long drift nozzle for 1.76” swell guns. 4. Log from TD to surface 5. Flag pipe as appropriate per WSS for addperf runs. New Well Post Well: 11-42 Current PTD: 223-117 6. Ensure well is dead before POOH, and circulate a kill with 8.4ppg 1% KCl as necessary. Max tubing pressure 3500 psi. (This step can be performed any time prior to open-hole deployment of the perf guns. Timing of the well kill is at the discretion of the WSS.) PIPE VOLUMES: Wellbore volume to estimated PBTD of 14,077’ = 205.1 bbls a. 4-1/2” Tubing – (8640’ – surface) X 0.0152bpf = 131.3 bbl b. 4” Drillpipe – (8640’ – 10,404’) X 0.011 bpf = 18 bbl c. 4-1/2” Liner – (10,404’ – 14,077’) x 0.0152 bpf = 55.8 bbl 7. POOH pumping pipe displacement and freeze protect tubing as needed. 8. Confirm good log data. 9. At surface, prepare for deployment of TCP guns. 10. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, 8.4 ppg 1% KCl or 8.5 ppg as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 11. Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. d. At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns one time to confirm the threads are compatible. 12.Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. Perf Schedule *Planned for 1.56” Halliburton Millennium charges, max swell 1.76” (in liquid), 3.62#/ft loaded weight. Perf Interval Perf Length Gun Length Weight of Gun (lbs)Comments Run 1 13,254’ – 13,623’ 369’ 369’~1335#Discuss with OE need for re- logging for pipe stretch Run 2 12,335’ – 12,732’ 397’ 397’~1437# Run 3 11,833’ – 12,107’ 274’ 274’~991# Run 4 11,474’ – 11,813’ 339’ 339’~1227# Total 1379’ 1379’ 13. MU lubricator connection at QTS. RIH with perf gun and tie-in to coil flag correlation. Pick up and perforate interval per Perf Schedule above. e. Note any tubing pressure change in WSR. 14. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and stick the BHA. Confirm well is dead and re-kill if necessary before pulling to surface. 15. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary. 16. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 17. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 18. Repeat steps 8 through 16 for subsequent runs to complete the desired perforated footage. 19. RDMO CTU. 20. RTP or FP well. New Well Post Well: 11-42 Current PTD: 223-117 Well Testing- New Well POP 1. MIRU Well Test Unit a. 11-30 may be used to flow 11-42, confirm with pad operator 2. POP well per SLBU program below 3. Once well is on stable production, obtain a 12 hour piggyback well test a. Retest as needed to confirm pad separator rates New Well Post Well: 11-42 Current PTD: 223-117 Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Diagram 3. Coil Tubing BOPE Schematic 4. Standing Orders for Open Hole Well Control during Perf Gun Deployment 5. Equipment Layout Diagram 6. Sundry Change Form 7. Tie in Log and screenshots 8. Liner setting tool diagram 9. Screenshot of 5/24 RBT 10. SLBU Procedure 11. Cross-section 12. Cerberus New Well Post Well: 11-42 Current PTD: 223-117 Coiled Tubing BOPs New Well Post Well: 11-42 Current PTD: 223-117 Standing Orders for Open Hole Well Control during Perf Gun Deployment New Well Post Well: 11-42 Current PTD: 223-117 Equipment Layout Diagram New Well Post Well: 11-42 Current PTD: 223-117 Sundry Change Form Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date New Well Post Well: 11-42 Current PTD: 223-117 Tie in Log: New Well Post Well: 11-42 Current PTD: 223-117 Perf Interval #4, 11,474’ – 11,813’ New Well Post Well: 11-42 Current PTD: 223-117 Perf Interval #3, 11,833’ – 12,107’ New Well Post Well: 11-42 Current PTD: 223-117 Perf Interval #2, 12,335’ – 12,732’ New Well Post Well: 11-42 Current PTD: 223-117 Perf Interval #1, 13,254’ – 13,623 New Well Post Well: 11-42 Current PTD: 223-117 Liner Hanger Running Tools: New Well Post Well: 11-42 Current PTD: 223-117 3-5-2024 RBT: Drillpipe Retrieved from 8640’ and up. Last run was a washpipe assy to clean cement off fish OD New Well Post Well: 11-42 Current PTD: 223-117 Slow Bean-Up (SLBU) Procedure for Wells that received ~500’+ of new perforations Notes: - The objective of this procedure is to outline rough guidelines for making choke & drawdown changes to extended add-perf (ExtADP) wells to limit the rate of drawdown, which minimizes shock to the reservoir and minimizes sand-face failure (sand production) and completion damage. This should be considered general and not rigid rules. - This procedure should be followed any time an existing or new well receives an Ext ADP intervention or post drill where more than 500’ of perfs have been added. - Each well has different flow characteristics and as such may result in varying times to reach FOC and/or optimal choke setting. - GL should be shut-off anytime a well is shut-in. This prevents from displacing gas into the formation and thus can lead to applying a large amount of drawdown over a short time interval when re-POP’ing that can result in high amounts of sand production. 1. Open the choke to minimum choke position. Start GL at 1 MMSCFD and maintain this setting for 6 hours after the well is kicked off.Consider adjusting the choke if the WHT is <50F and/or WHP is >500 psi for a prolonged period (mitigate hydrate formation). x Expect WHP to initially drop when opening the choke until GL has time to build pressure and KO well. x If well is setup with continuous AF / EB / Meth injection at the wellhead, add as necessary to help reduce slugging until well stabilizes out. x If well is setup for continuous methanol injection, add methanol into the GL stream as necessary until well is warm and stable. x After the well kicks off, adjust gas lift rate at this time to get stable flow. Flow should be as stable as possible before opening up the choke. 2. After the 6 hour hold period, open choke 10 steps x Increase GL to target rate at the end of the 6 hour hold period. Adjust GL as necessary to achieve stable flow and limited slugging.Target 1500 TGLR. 3. Hold at this choke setting for 2 hours x If the stages are lengthened due to operational constraints that is fine. Bean-up should take a minimum of 10 hours to get to target. x After a bottoms up is seen, take a solids sample. If the shakeout sample shows a solid content >1% contact OE. o Will likely want to hold at choke setting for an additional bottoms up . o At the end of the hold period, grab another shakeout to confirm solids production has reduced to a manageable level before proceeding with any additional drawdown changes. x If solids sample <0.2%, open choke up 10 more steps x If possible, obtain a water salinity every choke adjustment. 4. Repeat the choke opening steps as described above to fully open well to flow. Discuss with OE if there are any flowing BHP limitations. New Well Post Well: 11-42 Current PTD: 223-117 Cross Section New Well Post Well: 11-42 Current PTD: 223-117 Cerberus: Case: 1.5” HS-80 coil, 500’ of 1.56” guns, graph shows 0.25 FF 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:Shane Barber - (C) To:Regg, James B (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay Cc:Frank Roach; Brett Anderson - (C); Steve Carter - (C); Oliver Amend - (C) Subject:BOP test form Date:Sunday, March 3, 2024 1:35:58 PM Attachments:PBU 11-42 Hilcorp BOPE Test - Parker 273 3-2-24.xlsx All, Please see attached BOP test form. Thank you. Shane G. Barber | Drilling Foreman Hilcorp Alaska, LLC Rig “Parker 273” Office: 907-659-5673 Mobile: 907-841-5208 Harmony: 7008 sbarber@hilcorp.com Alternate: Brett Anderson 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 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 the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 3%8 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSubmit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:273 DATE: 3/2/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2231170 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: Weekly: Bi-Weekly: X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2458 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 1P Standing Order Posted P Misc.NA Ball Type 2P Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP #1 Rams 1 2-7/8"x5" VBR 5M P Flow Indicator PP #2 Rams 1 Blind/Shear 5M P Meth Gas Detector PP #3 Rams 1 2-7/8"x5" VBR 5M P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result HCR Valves 2 3-1/8" 5M P System Pressure (psi)3100 P Kill Line Valves 2 2-1/16",3-1/8" 5M P Pressure After Closure (psi)1850 P Check Valve 0NA200 psi Attained (sec)15 P BOP Misc 0NAFull Pressure Attained (sec)69 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2346 P No. Valves 15 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 27 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 14 P Inside Reel valves 0NA #3 Rams 7 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:5.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2-29-24 @ 20:18 Waived By Test Start Date/Time:3/1/2024 19:30 (date) (time)Witness Test Finish Date/Time:3/2/2024 0:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Kam StJohn Parker Tested with 4-1/2" & 2-7/8" test joints. Tested annular to 3,500psi. Test with water. Function all BOP components from remote panels located in the LER & Rig Managers office, and Accumulator. B. Davis / B. Herbert Hilcorp North Slope LLC S. Barber/ S. Carter PBU 11-42 Test Pressure (psi): rig273mgr@parkerwellbore.com Sbarber@hilcorp.com Form 10-424 (Revised 08/2022) 2024-0302_BOP_Parker273_PBU_11-42 9 9 9 9 9 9 9 99 9 9 -5HJJ 9 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:Brett Anderson - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Frank Roach; Robert Tool Pusher Subject:PBU 11-42 Hilcorp BOPE test - Parker 273 2-17-24 Date:Sunday, February 18, 2024 4:47:33 PM Attachments:PBU 11-42 Hilcorp BOPE Test - Parker 273 2-17-24.xlsx Please see attached BOPE test report for Parker 273 on PBU 11-42. Brett Anderson Hilcorp DSM, Parker 273 Office: 907-659-5673 Mobile: 907-240-6258 brett.anderson@hilcorp.com Alternate: Shane Barber sbarber@hilcorp.com 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 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 the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 3%8 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b mitt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:273 DATE: 2/17/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name: PTD #22231170 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: Weekly: Bi-Weekly: X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2458 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1FP Permit On Location P Hazard Sec.P Lower Kelly 1P Standing Order Posted P Misc.NA Ball Type 2P Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP #1 Rams 1 2-7/8"x5" VBR 5M P Flow Indicator PP #2 Rams 1 Blind/Shear 5M P Meth Gas Detector PP #3 Rams 1 2-7/8"x5" VBR 5M P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result HCR Valves 2 3-1/8" 5M P System Pressure (psi)3100 P Kill Line Valves 2 2-1/16",3-1/8" 5M P Pressure After Closure (psi)1800 P Check Valve 0NA200 psi Attained (sec)14 P BOP Misc 0NAFull Pressure Attained (sec)67 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2475 P No. Valves 15 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 25 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 11 P Inside Reel valves 0NA #3 Rams 6 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:18.5 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2-15-24 @ 07:03 Waived By Test Start Date/Time:2/16/2024 7:30 (date) (time)Witness Test Finish Date/Time:2/17/2024 2:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Guy Cook Parker Tested with 4" & 2-7/8" test joints. Tested annular to 3,500psi. Upper IBOP failed. Replaced with rebuilt replacement from warehouse and re-tested - pass. Test with water. Function all BOP components from remote panels located in the LER & Rig Managers office, and Accumulator. Jon King/ Kaleo Enfield-Ayonay Hilcorp B. Anderson / O. Amend PBU 11-42 Test Pressure (psi): rig273mgr@parkerwellbore.com brett.anderson@hilcorp.com Form 10-424 (Revised 08/2022) 2024-0217_BOP_Parker272_PBU_11-42 +LOFRUS$ODVND//&MEU 9 9 9 9 9 9 9 9 9 9 9 -5HJJ Upper IBOP failed FP 1 Junke, Kayla M (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, February 7, 2024 12:16 PM To:Frank Roach Cc:Rixse, Melvin G (OGC); Joseph Lastufka Subject:RE: 11-42 10-3/4" Casing Test and LOT (PTD: 223-117) Thanks Frank. I would call leakoff at 910 psi due to signiﬁcant change in slope, which is equivalent to 14.1 ppg which provides sufficient kick tolerance. Hilcorp has approval to drill ahead. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Wednesday, February 7, 2024 8:53 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: 11‐42 10‐3/4" Casing Test and LOT (PTD: 223‐117) Bryan, Please see the aƩached casing test and LOT results. Surface cement job went well. Good cement was observed at surface and switched to tail early. Circulated 570bbls good cement to surface. No losses were observed during the cement job. As for the LOT yesterday, the iniƟal report/call from the rig indicated that we did not achieve the 13.3 ppg EMW that was in the approved PTD, achieving only a 13.0ppg EMW. As per our phone discussion, we talked about miƟgaƟng acƟons on the rig for this lower kick tolerance. However, upon receiving the actual test data, we decided to redo the LOT so we have the data density. The subsequent test showed a high perm trend, but achieving the desired LOT. The test was repeated to conﬁrm the trend. The repeat test is aƩached. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 907.854.2321 mobile 907.777.8413 office 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 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 the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is 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 Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU 11-42 Hilcorp Alaska, LLC Permit to Drill Number: 223-117 Surface Location: 1125' FSL, 371' FEL, Sec 28, T11N, R15E, UM, AK Bottomhole Location: 279' FSL, 475' FEL, Sec 16, T11N, R15E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this 21 day of December 2023. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.12.21 11:02:40 -09'00' Drilling Manager 12/07/23 Monty M Myers By Grace Christianson at 8:02 am, Dec 08, 2023 SFD 12/11/2023 DSR-12/8/23MGR20DEC2023 * BOPE test to 3500 psi. Annular to 2500 psi. *FIT/LOT and Casing test digital data to AOGCC immediately upon completion of FIT/LOT 50-029-23775-00-00223-117 *&: Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.12.21 11:05:09 -09'00' 12/21/23 12/21/23 Prudhoe Bay East (PBU) 11-42 Drilling Program Version 0 12/06/2023 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: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 11 10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12 11.0 Drill 13-1/2” Hole Section ........................................................................................................ 14 12.0 Run 10-3/4” Surface Casing .................................................................................................... 17 13.0 Cement 10-3/4” Surface Casing ............................................................................................... 20 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 23 15.0 Drill 9-7/8” Intermediate Hole Section .................................................................................... 24 16.0 Run 7” Intermediate Casing .................................................................................................... 30 17.0 Cement 7” Intermediate Casing .............................................................................................. 33 18.0 Drill 6-1/8” Production Hole Section ....................................................................................... 36 19.0 Run 4-1/2” Production Liner ................................................................................................... 40 20.0 Cement 4-1/2” Production Liner ............................................................................................. 43 21.0 Perforate 4-1/2” Liner ............................................................................................................. 46 22.0 Run Upper Completion/ Post Rig Work ................................................................................. 47 23.0 Parker 273 Rig Diverter Schematic ......................................................................................... 51 24.0 Parker 273 Rig BOP Schematic ............................................................................................... 52 25.0 Wellhead Schematic ................................................................................................................. 53 26.0 Days Vs Depth .......................................................................................................................... 54 27.0 Formation Tops & Information............................................................................................... 55 28.0 Anticipated Drilling Hazards .................................................................................................. 58 29.0 Parker 273 Rig Layout............................................................................................................. 64 30.0 FIT Procedure .......................................................................................................................... 65 31.0 Parker 273 Rig Choke Manifold Schematic ............................................................................ 66 32.0 Casing Design ........................................................................................................................... 67 33.0 9-7/8” Hole Section MASP ....................................................................................................... 68 34.0 6-1/8” Hole Section MASP ....................................................................................................... 69 35.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 70 36.0 Surface Plat (As Staked) (NAD 27) ......................................................................................... 71 Page 2 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 1.0 Well Summary Well PBU 11-42 Pad Prudhoe Bay DS-11 Planned Completion Type 4-1/2” Production Tubing Target Reservoir(s) Ivishak Sands Planned Well TD, MD / TVD 14,271’ MD / 8,648’ TVD PBTD, MD / TVD 14,191’ MD / 8,663’ TVD Surface Location (Governmental) 1,125' FSL, 371' FEL, Sec 28, T11N, R15E, UM, AK Surface Location (NAD 27) X= 707,148.75, Y= 5,952,840.03 Top of Productive Horizon (Governmental)2,018' FSL, 291' FEL, Sec 21, T11N, R15E, UM, AK TPH Location (NAD 27) X= 707,044.81, Y= 5,959,010.78 BHL (Governmental) 271' FSL, 475' FEL, Sec 16, T11N, R15E, UM, AK BHL (NAD 27) X= 706,756.00, Y= 5,962,537.00 AFE Number 231-00147 AFE Drilling Days 26 AFE Completion Days 8 Maximum Anticipated Pressure (Surface) 2458 psig Maximum Anticipated Pressure (Downhole/Reservoir) 3332 psig Work String 5” 19.5# S-135 XT-50 and 4” 14.0# S-135 XT-39 Parker 273 KB Elevation above MSL: 26.2 ft + 46.95 ft = 73.15 ft GL Elevation above MSL: 26.2 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay East PAVE 1-1 Ivishak Producer 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 13-1/2” 10-3/4” 9.950 9.875 11.750 45.5 L-80 TXP 5,210 2,470 1,040 9-7/8” 7” 6.276 6.151 7.656 26.0 L-80 BTC 7,240 5,410 604 6-1/8” 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 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) Surf, Int, & Prod 5”4.276”3.500”6.500”19.5 S-135 XT50 44,000 52,800 712klb 4”3.340”2.688” 4.875”14.0 S-135 XT39 17,700 21,200 513klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay East PAVE 1-1 Ivishak Producer 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.com, frank.roach@hilcorp.com, 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, frank.roach@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, frank.roach@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 Frank Roach 907.777.8413 frank.roach@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 David Bjork 907.564.4672 david.bjork@hilcorp.com Geologist Christopher Clinkscales 907.777.8316 christopher.clinkscales@hilcorp.com Reservoir Engineer Tanner Gansert 907.564.5234 tanner.gansert@hilcorp.com Drilling Env. Coordinator Chris Keil 303.681.8844 chris.keil@hilcorp.com EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 7.0 Drilling / Completion Summary 11-42 is a grassroots producer planned to be drilled in the Ivishak sands. The directional plan is 13-1/2” surface hole and 10-3/4” surface casing set in the base of the SV3. A 9-7/8” section will be drilled and 7” intermediate casing set at TSAD. A 6-1/8” horizontal section will be drilled to Ivishak Zone 1. A 4-1/2” production liner will be run in the open hole section and cemented in place. After testing, the liner will be perforated using DPC perf guns. The well will be completed with 4-1/2” production tubing. Parker 273 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately December 23, 2023, pending rig schedule. Surface casing will be run to 4,953’ MD / ~3,934’ TVD and cemented to surface via a single stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. 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 Parker 273 Rig to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 13-1/2” hole to TD of surface hole section. Run and cement 10-3/4” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 9-7/8” to TD of intermediate hole section. Run and cement 7” intermediate casing 6. Drill 6-1/8” hole to TD 7. Run and cement 4-1/2” production liner 8. Perforate 4-1/2” production liner 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. Remote Ops geologist. LWD: GR + Res 2. Intermediate Hole: No mud logging. Field Ops geologist for casing pick. LWD: GR + Res 3. Production Hole: No mud logging. Field Ops geologist. LWD: Triple-Combo (For geo- steering) Ivishak Zone 1. ” horizontal section will be drilled to Page 8 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with 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 11-42. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,500 psi & subsequent tests of the BOP equipment will be to 250/3,500 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”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources 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 9 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure AOGCC Regulation Variance Requests: Summary of Parker 273 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 13-1/2”x 21-1/4” 2M Annular BOP w/ 16” diverter line Function Test Only 9-7/8” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind/Shear ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,500 Annular: 250/2,500 Subsequent Tests: 250/3,500 Annular 250/2,500 6-1/8” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind/Shear ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven pump and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Page 10 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 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. 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 Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@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 11 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 11-42 will utilize a newly set 20” conductor on SIP Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 Ensure any necessary wellhead equipment is staged prior to MIRU. A slip-loc starting head should also be staged in the cellar in the event that surface casing must be set using emergency slips. 9.8 MIRU Parker 273 Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.9 Mix spud mud for 13-1/2” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 5-3/4” liners in mud pumps. x NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96% volumetric efficiency. Page 12 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” diverter (Diverter Schematic attached to program). x N/U 20” riser to BOP Deck x N/U 20”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 13 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 14 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 11.0 Drill 13-1/2” Hole Section 11.1 P/U 13-1/2” directional 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 Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool. 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 surface hole section. 11.2 Begin drilling out from conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 13-1/2” hole section to section TD in the SV3 (projected ~4,953’ MD). Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well, targeting the shale package in the base of the SV3, ~60’ TVD above the SV2. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. 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 washing out permafrost. x Pump at 450-550 gpm while drilling through permafrost. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Avoid sliding when drilling across the prognosed base of permafrost, top SV6, and the EOCU to prevent high dogleg severity. x Once below base permafrost, perform wiper trip top BHA and run back to bottom. x Slowly increase pump rate between 550 and 650 gpm while drilling to surface TD. 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. x Adjust MW and viscosity as necessary to maintain hole stability. x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 15 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure x In PBE hydrates are not present. However, continue to drill using hydrate mitigation measures: x Keep mud temperature as cool as possible, Target 60-70*F x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready x Drill through hydrate sands and quickly as possible, do not backream. x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 13-1/2” hole mud program summary: System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density PV YP API FL HPHT Drill Solids MBT Hardness Surface –BPRF 8.8 –9.0 10-20 20-45 NC NA <9 <35 <200 BPRF - TD 9.0 –9.5 10-30 20-45 <10 NA <9 <35 <200 System Formulation: Gel + FW spud mud Product Quantity Water 0. 967 Bbls Soda Ash 0.125 ppb M-I GEL 35.0 ppb Primary Products Weight Material M-I WATE Viscosifiers M-I GEL Fluid Loss Additives M-I Pac UL (only if needed for fluid loss near TD) Alkalinity Control Soda Ash Bit & BHA Balling SCREENKLEEN (only if needed for balling in surface) Contingency Products Thinner CF Desco II, TANNATHIN & SAPP Cement Contamination Sodium Bicarbonate & SAPP Screen Blinding SCREENKLEEN Lost Circulation Material NUT PLUG FINE & MEDIUM, M-I-X II FINE & Medium Foaming/Aeration SCREENKLEEN / DEFOAM EXTRA 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. Page 16 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure x Casing Running:Reduce system YP 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 (check with the cementers to see what YP value they have targeted). 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and a 2nd BU. Rack back one stand every 30 minutes to avoid washing out the hole. Drop mud temp as low as possible as well. x Pump at full drill rate (600-650 gpm) and maximize rotation. x Monitor well for any signs of packing off or losses. x Once hole is cleaned up, obtain PU/SO/ROT weights for baseline prior to wiper trip. 11.6 Perform a wiper trip to BPRF on elevators. If tight hole is encountered attempt to wipe clean before pumping/backreaming. 11.7 TIH to TD, cleaning any tight spots encountered on the way. Note any trouble spots for final trip out and casing run. 11.8 At TD, CBU to ensure hole clean x Pump at full drill rate (600-650 gpm) and maximize rotation. x Monitor well for any signs of packing off or losses. x Once hole is cleaned up, obtain PU/SO/ROT weights prior to POOH. 11.9 POOH for casing run. Final trip should be on elevators. Wipe any tight spots along the way and note for casing run. 11.10 LD BHA 11.11 No open hole logging program planned. Page 17 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 12.0 Run 10-3/4” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 10-3/4” casing running equipment (CRT & Tongs) x Ensure 10-3/4” TXP/BTC x XT50 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 9.875” 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. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 80’ shoe track assembly consisting of: 10-3/4” Float Shoe 1 joint –10-3/4”, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 10-3/4”, 1 Centralizer mid joint w/ stop ring 10-3/4” Float Collar 1 joint – 10-3/4”, 1 Centralizer mid joint with stop ring x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment components. 10-3/4” 45.5/# L-80 TXP BTC MUT Casing OD Minimum Optimum Maximum 10-3/4” 20,370 ft-lbs 22,630 ft-lbs 24,890 ft-lbs Page 18 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Page 19 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 12.5 Continue running 10-3/4” surface 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 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints from ~1,000’ above shoe to ~200’ from surface 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. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.6 Continue running 10-3/4” surface casing 12.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.8 Slow in and out of slips. 12.9 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.10 Lower casing to setting depth. Confirm measurements. 12.11 While the primary method to land surface casing is with a mandrel hanger, have slips staged in cellar, along with necessary equipment for setting casing with slips as a contingency. 12.12 Circulate and condition mud through CRT. Reduce YP 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 20 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 13.0 Cement 10-3/4” Surface Casing 13.1 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. 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. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 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. 13.4 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. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 120 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations for the job, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 40% open hole excess from TD to base permafrost and annular volume + 500% from base permafrost to surface. Job will consist of lead & tail, with TOC brought to surface. Estimated Total Cement Volume: Page 21 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Cement Slurry Design: 13.8 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. 13.9 After pumping cement, drop top plug and displace cement with spud 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. 13.10 Ensure rig pump is used to displace cement. 13.11 Displacement calculation: = (4,953-80)*.0962 =469 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Decide ahead of time what will be done with cement returns once they are at surface. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±3.8 bbls before consulting with Drilling Engineer. 13.14 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. Lead Slurry Tail Slurry Density 11.0 lb/gal 15.8 lb/gal Yield 2.54 ft3/sk 1.16 ft3/sk Mix Water 12.2 gal/sk 4.97 gal/sk Page 22 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 23 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” 5M casing spool and 11” x 13-5/8” adapter. 14.2 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 2-7/8” x 5” VBRs or 5” solid body rams in top cavity,blind/shear ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” 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 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,500 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 2-7/8” and 5” test joints. This covers the smallest and largest diameters used for the well. 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 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 9.5 ppg (or match density to mud weight at surface TD, whichever is higher) LSND fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5-3/4” liners in mud pumps. Page 24 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 15.0 Drill 9-7/8” Intermediate Hole Section 15.1 MU 9-7/8” directional BHA x RSS and Gr/Res 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. x Drill string will be 5” 19.5# S-135 XT50. x Run a solid float in this hole section. 15.2 TIH w/ 9-7/8” BHA to 2 stands above float collar. 15.3 RU and test casing to 3,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on LOT graph. AOGCC reg is 50% of burst = 5,210 / 2 = ~2,605 psi. 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 Wash down and tag plugs. Note depth tagged on AM report. Drill out shoe track to within 10’ of the float shoe. Displace well over to 9.5 ppg (or equal to surface mud weight at TD, whichever is higher) LSND for upcoming hole section 15.5 Continue to drill out remaining shoetrack and 20’ of new formation. 15.6 CBU and condition mud for LOT. 15.7 Conduct LOT. 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 LOT digital data to AOGCC. x 12.6 ppg EMW provides >>25bbls based on 11.0 ppg MW, 10.0 ppg PP (swabbed kick at 11.0 ppg EMW BHP) Email casing test and LOT to AOGCC immediately upon completion. email: melvin.rixse@alaska.gov For a Kick Tolerance for a 0.5 kick intensity, a minimum of 13.3 PPGE LOT will be required. If LOT less than 13.3 call Mel Rixse at AOGCC to discuss operational controls going forward. Page 25 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 15.8 9-7/8” hole section mud program summary: System Type:9.5 – 11.0 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~4,953’ – ~8,571’ Shoe –CM3 9.5 – 9.8 5 – 20 15 – 30 < 8 N/A <6% <12 <200 ~8,571’ – ~9,834’ CM3 –CM1 9.8 – 10.4 5 – 20 15 – 30 < 8 N/A <6% <20 <200 ~9,834’ – ~10,304’ CM1 –THRZ 10.4 – 11.0 5 – 20 15 – 30 < 6 N/A <6% <20 <200 ~10,304’ – TD THRZ –TD 10.4 – 11.0 5 – 20 15 – 30 < 6 <10 <6% <20 <200 Product Quantity Water 0.916 bbls/bbl Soda Ash 0.17 ppb DUO-VIS 1.0 –1.5 ppb (as needed) DUAL-FLO/ FLO-TROL 3.0 ppb SCREENKLEEN 0.25% v/v M-I Wate 55 ppb (as needed for wt.) Busan 1060 2.1 gals/100 bbls Sodium Metabisulfite 0.25 ppb (added at rig only) Primary Products Viscosifiers DUO-VIS/ XCD Fluid Loss Additives FLO-TROL/ DUAL-FLO Bit & BHA Balling SCREENKLEEN (only if needed for balling/Ugnu/WS) Bridging Agent SAFE-CARB 20 & 40 Alkalinity Control Soda Ash Inhibition Potassium Chloride Lubricants LUBE 776 & LOTORQ Corrosion Control Sodium Metabisulfite (added at rig only) Bacteria Control Busan 1060 Contingency Products Cement Contamination Sodium Bicarbonate & SAPP Weight Material Sodium Chloride Foaming/Aeration SCREENKLEEN, DEFOAM EXTRA Lost Circulation Material NUT PLUG FINE & MEDIUM, SAFE-CARB 40, 250 & 750 x Density: Weighting material to be used for the hole section will be Barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. Page 26 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure x Solids Concentration: Solids concentration should be kept low while drilling the intermediate hole section. Keep the shaker screen size optimized and utilize centrifuge as needed. x Rheology: Keep viscosifier additions reasonably low (DUO-VIS / XCD). Utilize sweeps (weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 10 (hole diameter) for sufficient hole cleaning x Dump and dilute as necessary to keep drilled solids low. 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. 15.9 Install MPD RCD 15.12 Obtain initial ECD benchmark readings prior to drilling ahead. 15.13 Drill 9-7/8” hole section from 10-3/4” shoe to ~8,400’ MD (~200’ MD above CM3) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-750 GPM x RPM: Maximize RPM when rotating Take the first couple stands to understand BHA tendency. Maintenance slides may be necessary to keep sail angle x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 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. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. 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 any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. The SV sands and Ugnu will drill faster than this, but good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Target ROP is as fast as we can clean the hole without having to backream connections and staying below 200 FPH x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 Page 27 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 15.14 Toward the end of the above interval and if not already there, begin to weight up to 9.8 ppg. Ensure mud is a consistent 9.8 ppg ~200’ before entering the CM3. x Overpressure is not expected in the UG4 through UG1 from GNI disposal, but maintain vigilance. 15.15 Drill 9-7/8” hole section from ~8,400’ MD to ~9,600’ MD (~200’ MD above CM1) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-750 GPM x RPM: Maximize RPM when rotating x Limit WOB to 20k max to maintain bit stability 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. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. 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 any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Target ROP is as fast as we can clean the hole without having to backream connections and staying below 200 FPH x During this interval, before entering the CM2, ensure the mud weight is at 10.1 ppg or higher. x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 15.16 Toward the end of the above interval, begin to weight up to 10.4 ppg. Ensure mud is a consistent 10.4 ppg ~200’ before entering the CM1. x If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation and inducing losses/breathing 15.17 Drill 9-7/8” hole section from ~9,600’ MD to ~10,100’ MD (~200’ MD above HRZ) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700 – 750 GPM x RPM: Maximize RPM when rotating x Limit WOB to 20k max to maintain bit stability 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 Ensure mud is a consistent,g 10.4 ppg ~200’ before entering the CM1. y,g Ensure mud is a consistent 9.8 ppg ~200’ before entering the CM3. before entering the CM2, ensure the mud weight is at 10.1 ppg org higher. Page 28 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. 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 any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Target ROP is as fast as we can clean the hole without having to backream connections and staying below 200 FPH x MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 15.18 Toward the end of the above interval, ensure mud weight is consistent and at least a 10.4 ppg. Add black product to the mud system for HRZ stability. Ensure mud is a consistent 10.4 ppg ~200’ before entering the HRZ. 15.19 Prior to entering the HRZ, CBU and perform a wiper trip back to the shoe. Note any tight spots and wipe clean as needed. 15.20 Drill 9-7/8” hole section from ~10,100’ MD to section TD (projected at ~10,556’ MD) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 600 – 650 GPM x RPM: Maximize RPM when rotating x Keep pumps on and pumps of slow and smooth to minimize the cycling effects on the HRZ 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 Limit maximum instantaneous ROP to < 120 FPH. Over the final interval, control drill with WOB, RPM, and flow rate to indicate when transitioning across the LCU and into the TSAD. x NOTE: LCU truncates out all of the Kingak, Sag River, and Shublik formations. Most recent offset wells (11-39 and 11-40) went from HRZ to Zone 4. x MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 15.21 Reference:Intermediate Casing Pick procedure x Control drilling is key! With the LCU around DS-11, the HRZ sits on top of TSAD (Kingak, Sag River, and Shublik are truncated). As such, the traditional Sag casing pick procedure can’t be followed. Recognizing when to stop drilling to call TD is key before getting too deep into the Ivishak formation and going on losses. ppg Ensure mud is a consistent 10.4 ppgpy ~200’ before entering the HRZ. () MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation Page 29 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure x Drill through HRZ. Once THRZ is identified, use prognosed thickness to establish first stop point. x Stop drilling and CBU if one of the three occur: x Drilling break observed (drill additional 5’ MD before CBU) x Ivishak sand or fluvial shale identified in return samples x Near-bit GR shoes a baseline shift x Reach above established stop point x If Ivishak sand is not confirmed in samples, drill additional 5’ and CBU. x Repeat above steps until Ivishak sand is confirmed in samples. 15.22 At TD, CBU at least 3 times at 600 gpm and max 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 Obtain BHCT from MWD tools and provide to Halliburton cementers. 15.23 Wiper trip to the 10-3/4” casing shoe x Pump and pull until above HRZ to limit swab effect on the HRZ shales. x Once above the HRZ, pull on elevators to the casing shoe. x If tight hole is encountered, RIH 2-3 stands and CBU. If tight spot is at the same depth, begin backreaming. x If backreaming operations are commenced, continue backreaming to the shoe. x Monitor pressure, ECD, torque, and return flow to indicate potential packing off. x If backreaming is initiated, utilize MPD to close on connections while BROOH. x CBU minimum two times at trip point. 15.24 RIH to TD on elevators and circulate hole clean. 15.25 POOH and LD BHA. x Pump and pull until above HRZ to limit swab effect on the HRZ shales 15.26 Change out VBRs in the upper ram cavity to 7” fixed rams. Test with 7” test joint for upcoming intermediate casing run. Page 30 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 16.0 Run 7” Intermediate Casing 16.1 Well control preparedness: In the event of an influx of formation fluids while running the intermediate casing, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 5” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” casing. 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. 16.2 R/U 7” casing running equipment. x Ensure 7” 26# BTC x XT50 crossover is on rig floor and M/U to FOSV. 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. 16.3 Run 7” intermediate casing x Use BOL 2000 or equivalent thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Centralization: x 1 centralizer every joint to ~ 2000’ MD from shoe x 1 centralizer every 2 joints from ~2,000’ above shoe to 1 jt below 10-3/4” surface casing shoe (~5,000’ MD) x Utilize a collar clamp until weight is sufficient to keep slips set properly. x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. x Obtain up and down weights of the casing before entering open hole. x See data sheets on the next page for MU torque for the 7” casing connection. 12.13 Continue M/U & thread locking 80’ shoe track assembly consisting of: 7” Float Shoe 1 joint –7”, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 7”, 1 Centralizer mid joint w/ stop ring 7” Float Collar 1 joint –7”, 1 Centralizer free floating 7” 26/# L-80 BTC MUT – Make up to Mark 10 jts Take Average Casing OD Minimum Optimum Maximum 7” 13,280 ft-lbs Mark 16,230 ft-lbs Page 31 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 16.4 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.5 Slow in and out of slips. 16.6 RIH with 7” intermediate casing to 10-3/4” shoe at ~ 4,953’ MD. CBU and extablish PU and SO weights prior to exiting shoe. Page 32 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 16.7 Continue to RIH with 7” intermediate casing using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 10-3/4” shoe to THRZ: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Toward the end of this interval, circulate down consecutive joints to achieve a full bottoms-up by THRZ x THRZ to TD: Do not circulate. Fill pipe only 16.8 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 5’ from TD. 16.9 Break circulation at 1 bpm to avoid breaking down formation. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 2 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until casing is on bottom and cementers are ready. Page 33 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 17.0 Cement 7” Intermediate Casing 17.1 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. 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. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 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. 17.4 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. 17.5 Fill surface cement lines with water and pressure test. 17.6 Pump remaining 80 bbls 12.5 ppg tuned spacer. 17.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations and confirm actual cement volumes with cementer after TD is reached. 17.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of a tail slurry, TOC brought to 2,000’ above 7” casing shoe. Estimated Total Cement Volume: Page 34 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Cement Slurry Design: 17.9 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. 17.10 After pumping cement, drop top plug and displace with the rig pumps and LSND 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. 17.11 Displacement calculation: = (10,556-80)*.0383 = 402 bbls 17.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are seen at any point during the job. 17.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±1.5 bbls before consulting with Drilling Engineer. 17.14 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. 17.15 Set packoff and test per wellhead tech. 17.16 Freeze protect 10-3/4” x 7” casing annulus to ~2,400’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. x Freeze protect with ~120 bbls of dead crude/diesel x Establish breakdown pressure and inject 5 bbls past breakdown to confirm annulus is clear x Ensure total injection volume injected down the annulus (including mud used to keep annulus open) doesn’t exceed 110% of the 10-3/4” x 7” annular volume. 17.17 LD 5” drillpipe and prepare to PU 4” drillpipe for next hole section. Tail Slurry Density 15.3 lb/gal Yield 1.23 ft3/sk Mix Water 5.57 gal/sk Page 35 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 17.18 Change upper rams from 7” casing rams to 2-7/8” x 5” VBRs and test to 250 psi low, 3,500 psi high for 5/5 minutes with 4” and 2-7/8” test joints. 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 36 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 18.0 Drill 6-1/8” Production Hole Section 18.1 PU and rack back as much 4” drillpipe need to TD hole section. 18.2 MU 6-1/8” directional BHA x RSS and Triple Combo 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 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 4” 14.0# S-135 XT39. x Run a solid float in the production hole section. 18.3 TIH w/ 6-1/8” BHA to float collar. Note depth TOC tagged on AM report. Drill out shoe track to 10’ above float shoe. 18.4 RU and test casing to 3,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. 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. 18.5 Displace well to 8.5 ppg PowerPro drilling fluid. 18.6 Drill out remaining shoe track and 20’ of new formation. 18.7 CBU and condition mud for FIT. 18.8 Conduct FIT to 9.9 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 9.7 ppg EMW provides >>25bbls based on 9.1 ppg MW, 7.33 ppg EMW PP (swabbed kick at 9.1 ppg EMW BHP) 18.9 6-1/8” hole section mud program summary: System Type:8.5 – 9.1 ppg PowerPro drilling fluid Properties: Interval Density PV YP API FL Drill Solids pH MBT Hardness Production 8.5-9.1 <8 10 –20 <10 <6 9.0 –10.0 <10.0 <200 FIT and Casing test digital data to AOGCC immediately upon completion. email: melvin.rixse@alaska.gov Page 37 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Product Quantity Water 0.916 bbls/bbl Soda Ash 0.17 ppb POWERVIS 0.75 –1.25 ppb (as needed) DUAL-FLO/ FLO-TROL 4.0 ppb SCREENKLEEN 0.125% v/v KLC 21.8 ppb (6% by wt.) SAFE-CARB 20 22 ppb SAFE-CARB 40 22 ppb Salt 14.4 ppb (as needed for density) LUBE 776 1.0% v/v LOTORQ 1.0% v/v Busan 1060 2.1 gals/100 bbls Sodium Metabisulfite 0.25 ppb (added at rig only) Primary Products Viscosifiers POWERVIS Fluid Loss Additives FLO-TROL/ DUAL-FLO Bridging Agent SAFE-CARB 20 & 40 Alkalinity Control Soda Ash Inhibition Potassium Chloride Lubricants LUBE 776 & LOTORQ Corrosion Control Sodium Metabisulfite (added at rig only) Bacteria Control Busan 1060 Bridging/Density SAFE-CARB 20 & 40, Salt Contingency Products Cement Contamination Sodium Bicarbonate & SAPP Weight Material Sodium Chloride / SAFE-CARB 20 & 40, Salt Foaming/Aeration SCREENKLEEN, DEFOAM EXTRA Lost Circulation Material NUT PLUG FINE & MEDIUM, SAFE-CARB 40, 250 & 750 x Density: Weighting material to be used for the hole section will be sodium chloride. Additional NaCl 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 (POWERVIS/FLO-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 6.5 (hole diameter) for sufficient hole cleaning Page 38 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure x Run the centrifuge as needed 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. 18.10 Install MPD RCD 18.11 Begin drilling 6-1/8” 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 18.12 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 250-350 GPM, target min. AV’s 200 ft/min, 175 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 joint, until landed in Zone 1. Once landed, surveys can be taken every stand to TD. Survey frequency 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 BHA for any extended period of time. x Reservoir plan is to land in the Ivishak Zone 1 and geosteer, staying in the lower Zone 1 sands before toeing up at TD. x Limit maximum instantaneous ROP to < 120 FPH. The sands will drill faster than this, but With geosteering close to BSAD, data density and low ROP is key to react and stay in zone. x MWD data quality is key for well placement. If any issues arise with data quality or data detection, stop drilling and troubleshoot. x 6-1/8” Hole Section A/C: x 11-09 has a 0.957 CF. This well has been reservoir P&A’d. 18.13 At TD, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings Page 39 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 18.14 Perform wiper trip to the 7” casing shoe x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. x If backreaming operations are commenced, continue backreaming to the shoe 18.15 CBU minimum two times at 7” shoe and clean casing with high vis sweeps. 18.16 Trip back to TD and CBU 2x or until well cleans up, whichever comes later. 18.17 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 40 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 19.0 Run 4-1/2” Production Liner 19.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: x P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW. x Proceed with well kill operations. 19.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 12.6# VT x XT39 crossover is on rig floor and M/U to FOSV. 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. 19.3 Run 4-1/2” production liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. 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 If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 4-1/2” liner connections. x Centralization: x 1 centralizer every joint to ~ 50’ MD from 7” shoe 19.4 Run 4-1/2” injection liner as follows: 4-1/2” Float Shoe 1 joint – 4-1/2”, 2 Centralizers 10’ from each end w/ stop rings 4-1/2” Float Collar 1 joint – 4-1/2”, 1 Centralizer free floating 4-1/2” landing collar for liner wiper plug 1 joint –4-1/2”, 1 Centralizer mid joint w/ stop ring 4-1/2” 12.6/# L-80 VT – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 41 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Page 42 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 19.5 Ensure hanger/pkr will not be set in a 7” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 7” connection. 19.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 19.8 M/U Baker SLZXP liner top packer to 4-1/2” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 19.9 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. 19.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure 4” DP has been drifted x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 19.11 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. 19.12 CBU at the 7” shoe. Obtain up and down weights of the liner before entering open hole. 19.13 RIH to TD, filling pipe along the way. Utilize the same parameters used in step 19.10. Tag bottom and PU to position float shoe ~2’ off bottom. 19.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 43 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 20.0 Cement 4-1/2” Production Liner 20.1 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. 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. 20.2 Document efficiency of all possible displacement pumps prior to cement job. 20.3 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. 20.4 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. 20.5 Fill surface cement lines with water and pressure test. 20.6 Pump remaining 60 bbls 12.5 ppg tuned spacer. 20.7 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry, TOC brought to top of liner. Estimated Total Cement Volume: Page 44 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Cement Slurry Design: 20.8 Wash up lines back to the cement unit. This will help reduce risk of cement stringers in the liner. Drop drillpipe dart and displace with perf pill before swapping to drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 20.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 20.10 If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 20.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 20.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool Slack off total liner weight plus 30k to confirm hanger is set. 20.13 Bleed DP pressure to 0 psi and check floats. 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. 20.14 PU to neutral weight, close BOP and test annulus to 1,500 psi for 5 minutes to confirm liner top packer is set. 20.15 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, repeat setting process in 20.13. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting. 20.16 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top) 20.17 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. Tail Slurry Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 45 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 20.18 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20.19 RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 20.20 If not done already, test upper and lower VBRs with both 4-1/2” and 2-7/8” test joints to cover maximum and minimum pipe diameters for upcoming operations.. 20.21 Pressure test casing and liner to 250 psi low / 3,500 psi high for 30 minutes. Do not test until cement has reached minimum 1,000 psi compressive strength. Note: Once running tool is LD, swap to the completion AFE. Page 46 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 21.0 Perforate 4-1/2” Liner 21.1 If not completed in the previous BOPE test, test annular, upper and lower VBRs with 2-7/8” test joint to 250psi low 3,500psi high for 5/5 minutes. 21.2 RU to run 2-7/8” perforating assembly per vendor procedure. x Initial plan is ~2,000’ of 2-7/8” PowerJet Omega (or equivalent) perforation guns will be needed. x Exact perforated intervals to be determined by as-drilled logs data. Depths to be determined and confirmed by Geo/OE/DE. x Include a contingency hydraulic ball-drop disconnect in assembly x Limit personnel on rig floor to those required to make up DPC guns. 21.3 RIH with the perforating assembly. Stop to take PU/SO weights at the top of the 4-1/2” liner. 21.4 Space out DPC assembly by tagging the landing collar and spacing out on the upstroke. 21.5 Perforate the well per vendor procedure x An electronic firing head will be used. Review and follow vendor procedures for arming and firing the DPC guns. 21.6 Immediately after confirming guns have fired, POOH while keeping the hole full to get guns above the top shot. x This is to minimize sticking issues from possible sanding x Flow check well and establish loss rate prior to POOH 21.7 POOH, keeping the hole filled with KWF. x Record loss rate x Flow check at the 4-1/2” liner top and before pulling BHA through the BOPE 21.8 POOH and LD perf gun assembly. Verify all shots have fired. x Hydraulic tongs may be used with no backup tongs to spin out guns during rig down to minimize trapped pressure issues. Page 47 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 22.0 Run Upper Completion/ Post Rig Work 22.1 RU to run 4-1/2” 12.6#, 13Cr-80 Vam Top tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, Vam Top x 4” XT39 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. 22.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): a. Torque Turn All Connections b. Tubing Jewelry to include (top to bottom): c. 1x ‘X’ Nipple d. 6x GLMs (size and depths to be determined by OE) e. 1x ‘X’ Nipple f. 1x Production Packer g. 1x ‘X’ Nipple h. 1x ‘XN’ Nipple with RHC profile installed i. 1x WLEG j. Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top 4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 48 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Page 49 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 22.3 Space out the completion to land such that the 4-1/2” WLEG is inserted half-way into the PBR on the 4-1/2” production liner. Record PU and SO weights prior to picking up tubing hanger. 22.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec. 22.5 Reverse circulate heated kill-weight brine. Circulate surface-to-surface at a maximum of 4 BPM with brine and inhibited brine as follows: x Clean brine within the tubing from WLEG to surface x Inhibited brine on the annular side from the shear valve depth to the WLEG x Clean brine on the annular side from surface down to the shear valve. x At the end of the above displacement, reverse circulate an additional 5 bbls clean brine x With the 5 bbls over displacement complete, spot the fluids back in place by pumping 5 bbls clean brine down the tubing. This is to clean the RHC-M plug face before dropping the ball & rod. 22.6 Drop the ball & rod to the RHC-M (confirm whether roller stem is required due to the sail angle of the well). 22.7 Once ball & rod has landed, pressure up and set the packer. 22.8 Pressure test the tubing to 250 psi low, 3,500 psi high for 30 minutes. 22.9 Slowly bleed tubing pressure to 2,000 psi (confirm shear valve pressure) and test the IA to 250 psi low, 3,500 psi high for 30 minutes. 22.10 Hold pressure on the IA and bleed off the tubing pressure to shear the GLM valve. Confirm 2- way communication through the shear valve. 22.11 Install and pressure test TWC from above. 22.12 ND BOPE. NU the tubing head adapter and tree. 22.13 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 22.14 RU lubricator and pull TWC. 22.15 Freeze protect the wellbore. x Rig up to pump heated diesel down the IA, taking returns up the tubing up the tubing. Reverse 82 bbls heated diesel into the IA. Do not exceed 3bpm while circulating. x Shut in the IA. x Line up to U-tube from the IA to the tubing. x U-tube the diesel and freeze protect the tubing and IA to ~2,400’ MD. 22.16 After u-tube is complete, RU lubricator and install BPV. 22.17 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. Page 50 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 22.18 RDMO Parker 273 i. POST RIG WELL WORK (sundry to follow) 1. Slickline/Fullbore a. Pull BPV. b. Change out GLV per GL ENGR c. Pull B&R and RHC 2. Well Tie-In Page 51 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 23.0 Parker 273 Rig Diverter Schematic Page 52 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 24.0 Parker 273 Rig BOP Schematic Page 53 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 25.0 Wellhead Schematic Page 54 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 26.0 Days Vs Depth Page 55 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 27.0 Formation Tops & Information Page 56 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Page 57 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure Page 58 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 28.0 Anticipated Drilling Hazards 13-1/2” 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 NOT been seen on DS-11. 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 There are no wells with a clearance factor of <1.0 Wellbore stability (Faults): 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. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. Page 59 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure H2S: DS-11 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-11 has a history of H2S in their wells. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level 11-23 20 ppm 05/17/2023 #2 Closest SHL Well H2S Level 11-09A 14 ppm 10/30/2021 #1 Closest BHL Well H2S Level 11-39 14 ppm 08/22/2023 #2 Closest BHL Well H2S Level 11-40 16 ppm 10/27/2023 Max. Recorded H2S on nearest Pad/Facility 11-22 2000 ppm 11/10/1993 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. DS-11 is an H2S location. T Page 60 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 9-7/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. 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 > 600 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: DS-11 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-11 has a history of H2S in their wells. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level 11-23 20 ppm 05/17/2023 #2 Closest SHL Well H2S Level 11-09A 14 ppm 10/30/2021 #1 Closest BHL Well H2S Level 11-39 14 ppm 08/22/2023 #2 Closest BHL Well H2S Level 11-40 16 ppm 10/27/2023 Max. Recorded H2S on nearest Pad/Facility 11-22 2000 ppm 11/10/1993 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. DS-11 is an H2S location. Page 61 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Closest active disposal wells to DS-11 are GNI (1.97 miles away) and LPC-02 (2.7 miles away). Expected pore pressure when drilling through the Ungu sands is 9.0 ppg. Ensure mud is at least 9.5 ppg prior to drilling through. Ugnu/West Sak Hardstreaks: Hard formations (which are not necessarily predictable) can be encountered resulting in damage to PDC cutters. Damage occurs due to high impact loading of the bit cutting structure when hard streaks are hit at high ROP. Follow the appropriate mitigation strategy of reducing rotary speed while maintaining WOB. Formation Breakout (HRZ instability): This is related to the fissile (finely laminated) nature of the formation in conjunction with higher pore pressure, which requires higher mud weight to maintain wellbore stability. If splintering cuttings are observed at surface, additional circulations and mud weight may be required. 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. 9-7/8” Hole Section Specific AC: x There are no wells with a CF < 1.0 (y) Ensure mud is at least 9.5 ppgppp prior to drilling through. Page 62 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 6-1/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. 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 > 200 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: DS-11 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-11 has a history of H2S in their wells. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level 11-23 20 ppm 05/17/2023 #2 Closest SHL Well H2S Level 11-09A 14 ppm 10/30/2021 #1 Closest BHL Well H2S Level 11-39 14 ppm 08/22/2023 #2 Closest BHL Well H2S Level 11-40 16 ppm 10/27/2023 Max. Recorded H2S on nearest Pad/Facility 11-22 2000 ppm 11/10/1993 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. DS-11 is an H2S location. Page 63 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 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. 6-1/8” Hole Section Specific AC: x 11-09 has a 0.957 CF. This well has been reservoir P&A’d. Page 64 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 29.0 Parker 273 Rig Layout Page 65 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 30.0 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 66 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 31.0 Parker 273 Rig Choke Manifold Schematic Page 67 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 32.0 Casing Design Page 68 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 33.0 9-7/8” Hole Section MASP Page 69 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 34.0 6-1/8” Hole Section MASP Page 70 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 35.0 Spider Plot (NAD 27) (Governmental Sections) Page 71 Prudhoe Bay East PAVE 1-1 Ivishak Producer Drilling Procedure 36.0 Surface Plat (As Staked) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 'HFHPEHU 3ODQZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ 3ODQ -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Tr u e V e r t i c a l D e p t h ( 1 5 0 0 u s f t / i n ) -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 Vertical Section at 359.26° (1500 usft/in) 11-42 wp04 tgt 2 11-42 wp04 tgt 3 11-42 wp04 tgt 1 11-42 wp04 tgt 4 11-42 wp04 tgt 5 11-42 wp04 tgt 6 10 3/4" x 13 1/2" 7" x 9 7/8" 4 1/2" x 6 1/8" 5 0 0 1 0 0 0 15 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 11000 115 0 0 12 000 12 500 13 000 13500 1 4 0 0 0 1 4 2 7 1 11-42 wp10 Start Dir 3º/100' : 300' MD, 300'TVD Start Dir 3.5º/100' : 600' MD, 598.77'TVD End Dir : 1750' MD, 1591.17' TVD Start Dir 5º/100' : 3150' MD, 2527.03'TVD End Dir : 3412.39' MD, 2719.05' TVD Start Dir 5º/100' : 9385.25' MD, 7429.94'TVD End Dir : 9601.97' MD, 7600' TVD Start Dir 6º/100' : 10632.82' MD, 8400'TVD Start Dir 10º/100' : 11231.17' MD, 8720.15'TVD End Dir : 11423.89' MD, 8742.67' TVD Start Dir 3º/100' : 12212.42' MD, 8721.15'TVD End Dir : 12265.94' MD, 8718.94' TVD Start Dir 3º/100' : 12751.92' MD, 8692.07'TVD End Dir : 12924.18' MD, 8690.03' TVD Start Dir 3º/100' : 13507.44' MD, 8705.43'TVD End Dir : 13574.54' MD, 8706.02' TVD Start Dir 3º/100' : 13674.54' MD, 8705.15'TVD End Dir : 13750.12' MD, 8703.07' TVD Start Dir 4º/100' : 13949.18' MD, 8693.87'T End Dir : 14150.9' MD, 8670.42' T Total Depth : 14270.66' MD, 8648.15' T BPRF SV6 SV5 SV4 SV3 SV2 SV1 UG4 UG4A UG3 UG1 WS2 WS1 CM3 CM2 CM1 THRZ LCU/TSAD 42N TCGLBCGL 25N22P TZ1BTDF Hilcorp North Slope, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: 11-42 26.20+N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5952840.03 707148.75 70° 16' 28.5334 N 148° 19' 27.1916 W SURVEY PROGRAM Date: 2023-11-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 46.95 950.00 11-42 wp10 (11-42) GYD_Quest GWD 950.00 4953.00 11-42 wp10 (11-42) 3_MWD+IFR2+MS+Sag 4953.00 10556.00 11-42 wp10 (11-42) 3_MWD+IFR2+MS+Sag 10556.00 14270.66 11-42 wp10 (11-42) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1901.15 1828.00 2213.71 BPRF 2405.15 2332.00 2967.67 SV6 3175.15 3102.00 3990.67 SV5 3296.15 3223.00 4144.09 SV4 3787.15 3714.00 4766.62 SV3 3994.15 3921.00 5029.07 SV2 4363.15 4290.00 5496.92 SV1 4930.15 4857.00 6215.81 UG4 4944.15 4871.00 6233.56 UG4A 5144.15 5071.00 6487.14 UG3 5762.15 5689.00 7270.69 UG1 6460.15 6387.00 8155.67 WS2 6708.15 6635.00 8470.11 WS1 6788.15 6715.00 8571.54 CM3 7262.15 7189.00 9172.52 CM2 7780.15 7707.00 9834.10 CM1 8145.15 8072.00 10304.43 THRZ 8340.15 8267.00 10555.70 LCU/TSAD 8344.15 8271.00 10560.86 42N 8456.15 8383.00 10707.63 TCGL 8478.15 8405.00 10738.48 BCGL 8526.15 8453.00 10809.65 25N 8632.15 8559.00 10996.17 22P 8678.15 8605.00 11101.37 TZ1B 8723.15 8650.00 11243.16 TDF REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 11-42, True North Vertical (TVD) Reference:11-42 as staked rkb @ 73.15usft Measured Depth Reference:11-42 as staked rkb @ 73.15usft Calculation Method:Minimum Curvature Project:Prudhoe Bay Site:11 Well:Plan: 11-42 Wellbore:11-42 Design:11-42 wp10 CASING DETAILS TVD TVDSS MD Size Name 3934.00 3860.85 4952.81 10-3/4 10 3/4" x 13 1/2" 8340.00 8266.85 10555.51 7 7" x 9 7/8" 8648.15 8575.00 14270.66 4-1/2 4 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 600.00 9.00 20.00 598.77 22.10 8.04 3.00 20.00 21.99 Start Dir 3.5º/100' : 600' MD, 598.77'TVD 4 1550.00 41.26 355.44 1448.98 415.28 8.55 3.50 -30.00 415.14 5 1750.00 48.05 353.01 1591.17 555.02 -5.77 3.50 -15.00 555.05 End Dir : 1750' MD, 1591.17' TVD 6 3150.00 48.05 353.01 2527.03 1588.50 -132.55 0.00 0.00 1590.09 Start Dir 5º/100' : 3150' MD, 2527.03'TVD 7 3412.39 37.93 5.34 2719.05 1766.43 -136.94 5.00 144.65 1768.06 End Dir : 3412.39' MD, 2719.05' TVD 8 9385.25 37.93 5.34 7429.94 5422.36 204.87 0.00 0.00 5419.25 Start Dir 5º/100' : 9385.25' MD, 7429.94'TVD 9 9601.97 39.10 348.00 7600.00 5555.92 196.84 5.00 -90.69 5552.91 End Dir : 9601.97' MD, 7600' TVD 10 10632.82 39.10 348.00 8400.00 6191.84 61.67 0.00 0.00 6190.52 Start Dir 6º/100' : 10632.82' MD, 8400'TVD 11 11231.17 75.00 348.00 8720.15 6674.97 -41.02 6.00 0.00 6674.94 11-42 wp04 tgt 1 Start Dir 10º/100' : 11231.17' MD, 8720.15'TVD 12 11423.89 91.56 357.96 8742.67 6864.06 -64.02 10.00 31.57 6864.31 End Dir : 11423.89' MD, 8742.67' TVD 13 12212.42 91.56 357.96 8721.15 7651.80 -92.15 0.00 0.00 7652.35 11-42 wp04 tgt 2 Start Dir 3º/100' : 12212.42' MD, 8721.15'TVD 14 12265.94 93.17 357.92 8718.94 7705.24 -94.07 3.00 -1.24 7705.81 End Dir : 12265.94' MD, 8718.94' TVD 15 12751.92 93.17 357.92 8692.07 8190.15 -111.68 0.00 0.00 8190.91 Start Dir 3º/100' : 12751.92' MD, 8692.07'TVD 16 12857.60 90.00 358.01 8689.15 8295.72 -115.43 3.00 178.38 8296.52 11-42 wp04 tgt 3 17 12924.18 88.49 359.31 8690.03 8362.26 -116.99 3.00 139.26 8363.08 End Dir : 12924.18' MD, 8690.03' TVD 18 13507.44 88.49 359.31 8705.43 8945.28 -123.97 0.00 0.00 8946.13 Start Dir 3º/100' : 13507.44' MD, 8705.43'TVD 19 13574.54 90.50 359.32 8706.02 9012.37 -124.77 3.00 0.18 9013.23 End Dir : 13574.54' MD, 8706.02' TVD 20 13674.54 90.50 359.32 8705.15 9112.36 -125.96 0.00 0.00 9113.22 11-42 wp04 tgt 4 Start Dir 3º/100' : 13674.54' MD, 8705.15'TVD 21 13750.12 92.65 0.04 8703.07 9187.91 -126.38 3.00 18.62 9188.77 End Dir : 13750.12' MD, 8703.07' TVD 22 13949.18 92.65 0.04 8693.87 9386.76 -126.22 0.00 0.00 9387.60 Start Dir 4º/100' : 13949.18' MD, 8693.87'TVD 23 14070.47 97.50 0.09 8683.15 9507.53 -126.08 4.00 0.53 9508.37 11-42 wp04 tgt 5 24 14150.90 100.72 0.13 8670.42 9586.93 -125.93 4.00 0.74 9587.76 End Dir : 14150.9' MD, 8670.42' TVD 25 14270.66 100.72 0.13 8648.15 9704.60 -125.65 0.00 0.00 9705.42 11-42 wp04 tgt 6 Total Depth : 14270.66' MD, 8648.15' TVD 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 So u t h ( - ) / N o r t h ( + ) ( 1 0 0 0 u s f t / i n ) -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 West(-)/East(+) (1000 usft/in) 11-42 wp04 tgt 6 11-42 wp04 tgt 5 11-42 wp04 tgt 4 11-42 wp04 tgt 1 11-42 wp04 tgt 3 11-42 wp04 tgt 2 10 3/4" x 13 1/2" 7" x 9 7/8" 4 1/2" x 6 1/8" 750 1250 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7500 7 7 5 0 8 0 0 0 8 2 5 0 8 5 0 0 8648 11-42 wp10 Start Dir 3º/100' : 300' MD, 300'TVD Start Dir 3.5º/100' : 600' MD, 598.77'TVD End Dir : 1750' MD, 1591.17' TVD Start Dir 5º/100' : 3150' MD, 2527.03'TVD End Dir : 3412.39' MD, 2719.05' TVD Start Dir 5º/100' : 9385.25' MD, 7429.94'TVD End Dir : 9601.97' MD, 7600' TVD Start Dir 6º/100' : 10632.82' MD, 8400'TVD Start Dir 10º/100' : 11231.17' MD, 8720.15'TVD End Dir : 11423.89' MD, 8742.67' TVD Start Dir 3º/100' : 12212.42' MD, 8721.15'TVD End Dir : 12265.94' MD, 8718.94' TVD Start Dir 3º/100' : 12751.92' MD, 8692.07'TVD End Dir : 12924.18' MD, 8690.03' TVD Start Dir 3º/100' : 13507.44' MD, 8705.43'TVD End Dir : 13574.54' MD, 8706.02' TVD Start Dir 3º/100' : 13674.54' MD, 8705.15'TVD End Dir : 13750.12' MD, 8703.07' TVD Start Dir 4º/100' : 13949.18' MD, 8693.87'TVD End Dir : 14150.9' MD, 8670.42' TVD Total Depth : 14270.66' MD, 8648.15' TVD CASING DETAILS TVD TVDSS MD Size Name 3934.00 3860.85 4952.81 10-3/4 10 3/4" x 13 1/2" 8340.00 8266.85 10555.51 7 7" x 9 7/8" 8648.15 8575.00 14270.66 4-1/2 4 1/2" x 6 1/8" Project: Prudhoe Bay Site: 11 Well: Plan: 11-42 Wellbore: 11-42 Plan: 11-42 wp10 WELL DETAILS: Plan: 11-42 26.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5952840.03 707148.75 70° 16' 28.5334 N 148° 19' 27.1916 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 11-42, True North Vertical (TVD) Reference: 11-42 as staked rkb @ 73.15usft Measured Depth Reference:11-42 as staked rkb @ 73.15usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH 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L F R O O L V L R Q 5 H S R U W I R U 3 O D Q Z S &R P S D U L V R Q : H O O 1 D P H : H O O E R U H 1 D P H ' H V L J Q #0 H D V X U H G 'H S W K X V I W 0L Q L P X P 'L V W D Q F H X V I W (O O L S V H 6H S D U D W L R Q X V I W #0 H D V X U H G 'H S W K XV I W &O H D U D Q F H )D F W R U 6F D Q 5 D G L X V L V 8 Q O L P L W H G & O H D U D Q F H ) D F W R U F X W R I I L V 8 Q O L P L W H G 0 D [ ( O O L S V H 6 H S D U D W L R Q L V X V I W 6L W H 1 D P H 6F D Q 5 D Q J H W R X V I W 0 H D V X U H G ' H S W K &O R V H V W $ S S U R D F K ' 3 U R [ L P L W \ 6 F D Q R Q & X U U H Q W 6 X U Y H \ ' D W D + L J K VL G H 5 H I H U H Q F H 5H I H U H Q F H ' H V L J Q 3 O D Q Z S 0H D V X U H G 'H S W K X V I W 6X P P D U \ % D V H G R Q 0L Q L P X P 6H S D U D W L R Q : D U Q L Q J (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V &H Q W U H ' L V W D Q F H 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ &H Q W U H ' L V W D Q F H 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V &H Q W U H ' L V W D Q F H 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ &H Q W U H ' L V W D Q F H 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V &H Q W U H ' L V W D Q F H 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ &H Q W U H ' L V W D Q F H 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V % % &H Q W U H ' L V W D Q F H 3 D V V % % (O O L S V H 6 H S D U D W L R Q 3 D V V % % &O H D U D Q F H ) D F W R U 3 D V V % 3 % % 3 % &H Q W U H ' L V W D Q F H 3 D V V % 3 % % 3 % (O O L S V H 6 H S D U D W L R Q 3 D V V % 3 % % 3 % &O H D U D Q F H ) D F W R U 3 D V V ' H F H P E H U &2 0 3 $ 6 6 3D J H R I 3U X G K R H % D \ +L O F R U S 1 R U W K 6 O R S H / / & $Q W L F R O O L V L R Q 5 H S R U W I R U 3 O D Q Z S &R P S D U L V R Q : H O O 1 D P H : H O O E R U H 1 D P H ' H V L J Q #0 H D V X U H G 'H S W K X V I W 0L Q L P X P 'L V W D Q F H X V I W (O O L S V H 6H S D U D W L R Q X V I W #0 H D V X U H G 'H S W K XV I W &O H D U D Q F H )D F W R U 6F D Q 5 D G L X V L V 8 Q O L P L W H G & O H D U D Q F H ) D F W R U F X W R I I L V 8 Q O L P L W H G 0 D [ ( O O L S V H 6 H S D U D W L R Q L V X V I W 6L W H 1 D P H 6F D Q 5 D Q J H W R X V I W 0 H D V X U H G ' H S W K &O R V H V W $ S S U R D F K ' 3 U R [ L P L W \ 6 F D Q R Q & X U U H Q W 6 X U Y H \ ' D W D + L J K VL G H 5 H I H U H Q F H 5H I H U H Q F H ' H V L J Q 3 O D Q Z S 0H D V X U H G 'H S W K X V I W 6X P P D U \ % D V H G R Q 0L Q L P X P 6H S D U D W L R Q : D U Q L Q J (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V &O H D U D Q F H ) D F W R U 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V 3 % 3 % &O H D U D Q F H ) D F W R U 3 D V V 3 % 3 % (O O L S V H 6 H S D U D W L R Q 3 D V V &H Q W U H ' L V W D Q F H 3 D V V &O H D U D Q F H ) D F W R U 3 D V V 3 % 3 % &H Q W U H ' L V W D Q F H 3 D V V 3 % 3 % &O H D U D Q F H ) D F W R U 3 D V V / / / / &O H D U D Q F H ) D F W R U 3 D V V / / / (O O L S V H 6 H S D U D W L R Q 3 D V V / / / &O H D U D Q F H ) D F W R U 3 D V V / / / (O O L S V H 6 H S D U D W L R Q 3 D V V / / / &O H D U D Q F H ) D F W R U 3 D V V / / / (O O L S V H 6 H S D U D W L R Q 3 D V V / / / &O H D U D Q F H ) D F W R U 3 D V V / / / (O O L S V H 6 H S D U D W L R Q 3 D V V / / 3 % / 3 % &O H D U D Q F H ) D F W R U 3 D V V / / 3 % / 3 % (O O L S V H 6 H S D U D W L R Q 3 D V V ' H F H P E H U &2 0 3 $ 6 6 3D J H R I 3U X G K R H % D \ +L O F R U S 1 R U W K 6 O R S H / / & $Q W L F R O O L V L R Q 5 H S R U W I R U 3 O D Q Z S 6X U Y H \ W R R O S U R J U D P )U R P X V I W 7R X V I W 6X U Y H \ 3 O D Q 6 X U Y H \ 7 R R O Z S * < ' B 4 X H V W * : ' Z S B 0 : ' , ) 5 0 6 6 D J Z S B 0 : ' , ) 5 0 6 6 D J Z S B 0 : ' , ) 5 0 6 6 D J (O O L S V H H U U R U W H U P V D U H F R U U H O D W H G D F U R V V V X U Y H \ W R R O W L H R Q S R LQ W V 6H S D U D W L R Q L V W K H D F W X D O G L V W D Q F H E H W Z H H Q H O O L S V R L G V &D O F X O D W H G H O O L S V H V L Q F R U S R U D W H V X U I D F H H U U R U V &O H D U D Q F H ) D F W R U ' L V W D Q F H % H W Z H H Q 3 U R I L O H V ' L V W D Q F H % H W Z H H Q 3 U R I L O H V ( O O L S V H 6 H S D U D W L R Q 'L V W D Q F H % H W Z H H Q F H Q W U H V L V W K H V W U D L J K W O L Q H G L V W D Q F H E H W Z H H Q ZH O O E R U H F H Q W U H V $O O V W D W L R Q F R R U G L Q D W H V Z H U H F D O F X O D W H G X V L Q J W K H 0 L Q L P X P & X U Y D WX U H P H W K R G ' H F H P E H U &2 0 3 $ 6 6 3D J H R I 0. 0 0 1. 0 0 2. 0 0 3. 0 0 4. 0 0 Separation Factor 0 2 7 5 5 5 0 8 2 5 1 1 0 0 1 3 7 5 1 6 5 0 1 9 2 5 2 2 0 0 2 4 7 5 2 7 5 0 3 0 2 5 3 3 0 0 3 5 7 5 3 8 5 0 4 1 2 5 4 4 0 0 4 6 7 5 4 9 5 0 5 2 2 5 Me a s u r e d D e p t h ( 5 5 0 u s f t / i n ) 11 - 0 9 No - G o Z o n e - S t o p D r i l l i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . WE L L D E T A I L S : P l a n : 1 1 - 4 2 N A D 1 9 2 7 ( N A D C O N C O N U S ) Al a s k a Z o n e 0 4 26 . 2 0 +N / - S + E / - W N o r t h i n g E a s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0. 0 0 59 5 2 8 4 0 . 0 3 70 7 1 4 8 . 7 5 70 ° 1 6 ' 2 8 . 5 3 3 4 N 14 8 ° 1 9 ' 2 7 . 1 9 1 6 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : 1 1 - 4 2 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : 1 1 - 4 2 a s s t a k e d r k b @ 7 3 . 1 5 u s f t Me a s u r e d D e p t h R e f e r e n c e : 11 - 4 2 a s s t a k e d r k b @ 7 3 . 1 5 u s f t Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e SU R V E Y P R O G R A M Da t e : 2 0 2 3 - 1 1 - 3 0 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o S u r v e y / P l a n To o l 46 . 9 5 9 5 0 . 0 0 1 1 - 4 2 w p 1 0 ( 1 1 - 4 2 ) G Y D _ Q u e s t G W D 95 0 . 0 0 4 9 5 3 . 0 0 1 1 - 4 2 w p 1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 49 5 3 . 0 0 1 0 5 5 6 . 0 0 1 1 - 4 2 w p1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 10 5 5 6 . 0 0 1 4 2 7 0 . 6 6 1 1 - 4 2 w p1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 0. 0 0 30 . 0 0 60 . 0 0 90 . 0 0 12 0 . 0 0 15 0 . 0 0 18 0 . 0 0 Centre to Centre Separation (60.00 usft/in) 0 2 7 5 5 5 0 8 2 5 1 1 0 0 1 3 7 5 1 6 5 0 1 9 2 5 2 2 0 0 2 4 7 5 2 7 5 0 3 0 2 5 3 3 0 0 3 5 7 5 3 8 5 0 4 1 2 5 4 4 0 0 4 6 7 5 4 9 5 0 5 2 2 5 Me a s u r e d D e p t h ( 5 5 0 u s f t / i n ) 11 - 3 0 11 - 2 3 11 - 1 0 11 - 0 9 NO G L O B A L F I L T E R : U s i n g u s e r d e f i n e d s e l e c t i o n & f i l t e r i n g c r i t e r i a 46 . 9 5 T o 1 4 2 7 0 . 6 6 Pr o j e c t : P r u d h o e B a y Si t e : 1 1 We l l : P l a n : 1 1 - 4 2 We l l b o r e : 1 1 - 4 2 Pl a n : 1 1 - 4 2 w p 1 0 La d d e r / S . F . P l o t s 1 o f 3 CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 39 3 4 . 0 0 3 8 6 0 . 8 5 4 9 5 2 . 8 1 1 0 - 3 / 4 1 0 3 / 4 " x 1 3 1 / 2 " 83 4 0 . 0 0 8 2 6 6 . 8 5 1 0 5 5 5 . 5 1 7 7 " x 9 7 / 8 " 86 4 8 . 1 5 8 5 7 5 . 0 0 1 4 2 7 0 . 6 6 4 - 1 / 2 4 1 / 2 " x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eparation Factor 48 0 0 5 1 0 0 5 4 0 0 5 7 0 0 6 0 0 0 6 3 0 0 6 6 0 0 6 9 0 0 7 2 0 0 7 5 0 0 7 8 0 0 8 1 0 0 8 4 0 0 8 7 0 0 9 0 0 0 9 3 0 0 9 6 0 0 9 9 0 0 1 0 2 0 0 1 0 5 0 0 Me a s u r e d D e p t h ( 6 0 0 u s f t / i n ) L3 - 3 1 11 - 0 9 11 - 0 9 A 11 - 4 0 11 - 3 9 No - G o Z o n e - S t o p D r i l l i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . WE L L D E T A I L S : P l a n : 1 1 - 4 2 N A D 1 9 2 7 ( N A D C O N C O N U S ) Al a s k a Z o n e 0 4 26 . 2 0 +N / - S + E / - W N o r t h i n g E a s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0. 0 0 59 5 2 8 4 0 . 0 3 70 7 1 4 8 . 7 5 70 ° 1 6 ' 2 8 . 5 3 3 4 N 14 8 ° 1 9 ' 2 7 . 1 9 1 6 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : 1 1 - 4 2 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : 1 1 - 4 2 a s s t a k e d r k b @ 7 3 . 1 5 u s f t Me a s u r e d D e p t h R e f e r e n c e : 11 - 4 2 a s s t a k e d r k b @ 7 3 . 1 5 u s f t Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e SU R V E Y P R O G R A M Da t e : 2 0 2 3 - 1 1 - 3 0 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o S u r v e y / P l a n To o l 46 . 9 5 9 5 0 . 0 0 1 1 - 4 2 w p 1 0 ( 1 1 - 4 2 ) G Y D _ Q u e s t G W D 95 0 . 0 0 4 9 5 3 . 0 0 1 1 - 4 2 w p 1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 49 5 3 . 0 0 1 0 5 5 6 . 0 0 1 1 - 4 2 w p1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 10 5 5 6 . 0 0 1 4 2 7 0 . 6 6 1 1 - 4 2 w p1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 0. 0 0 30 . 0 0 60 . 0 0 90 . 0 0 12 0 . 0 0 15 0 . 0 0 18 0 . 0 0 Centre to Centre Separation (60.00 usft/in) 48 0 0 5 1 0 0 5 4 0 0 5 7 0 0 6 0 0 0 6 3 0 0 6 6 0 0 6 9 0 0 7 2 0 0 7 5 0 0 7 8 0 0 8 1 0 0 8 4 0 0 8 7 0 0 9 0 0 0 9 3 0 0 9 6 0 0 9 9 0 0 1 0 2 0 0 1 0 5 0 0 Me a s u r e d D e p t h ( 6 0 0 u s f t / i n ) NO G L O B A L F I L T E R : U s i n g u s e r d e f i n e d s e l e c t i o n & f i l t e r i n g c r i t e r i a 46 . 9 5 T o 1 4 2 7 0 . 6 6 Pr o j e c t : P r u d h o e B a y Si t e : 1 1 We l l : P l a n : 1 1 - 4 2 We l l b o r e : 1 1 - 4 2 Pl a n : 1 1 - 4 2 w p 1 0 La d d e r / S . F . P l o t s 2 o f 3 CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 39 3 4 . 0 0 3 8 6 0 . 8 5 4 9 5 2 . 8 1 1 0 - 3 / 4 1 0 3 / 4 " x 1 3 1 / 2 " 83 4 0 . 0 0 8 2 6 6 . 8 5 1 0 5 5 5 . 5 1 7 7 " x 9 7 / 8 " 86 4 8 . 1 5 8 5 7 5 . 0 0 1 4 2 7 0 . 6 6 4 - 1 / 2 4 1 / 2 " x 6 1 / 8 " 3U X G K R H % D \ +L O F R U S 1 R U W K 6 O R S H / / & $Q W L F R O O L V L R Q 5 H S R U W I R U 3 O D Q Z S (O O L S V H H U U R U W H U P V D U H F R U U H O D W H G D F U R V V V X U Y H \ W R R O W L H R Q S R LQ W V 6H S D U D W L R Q L V W K H D F W X D O G L V W D Q F H E H W Z H H Q H O O L S V R L G V &D O F X O D W H G H O O L S V H V L Q F R U S R U D W H V X U I D F H H U U R U V &O H D U D Q F H ) D F W R U ' L V W D Q F H % H W Z H H Q 3 U R I L O H V ' L V W D Q F H % H W Z H H Q 3 U R I L O H V ( O O L S V H 6 H S D U D W L R Q 'L V W D Q F H % H W Z H H Q F H Q W U H V L V W K H V W U D L J K W O L Q H G L V W D Q F H E H W Z H H Q ZH O O E R U H F H Q W U H V $O O V W D W L R Q F R R U G L Q D W H V Z H U H F D O F X O D W H G X V L Q J W K H 0 L Q L P X P & X U Y D WX U H P H W K R G ' H F H P E H U &2 0 3 $ 6 6 3D J H R I &O H D U D Q F H 6 X P P D U \ $Q W L F R O O L V L R Q 5 H S R U W ' H F H P E H U +L O F R U S 1 R U W K 6 O R S H / / & 3U X G K R H % D \ 3O D Q Z S 5H I H U H Q F H ' H V L J Q 3 O D Q Z S &O R V H V W $ S S U R D F K ' 3 U R [ L P L W \ 6 F D Q R Q & X U U H Q W 6 X U Y H \ ' D W D + L J K VL G H 5 H I H U H Q F H :H O O & R R U G L Q D W H V 1 ( 1 : 'D W X P + H L J K W D V V W D N H G U N E # X V I W 6F D Q 5 D Q J H W R X V I W 0 H D V X U H G ' H S W K *H R G H W L F 6 F D O H ) D F W R U $ S S O L H G 9H U V L R Q % X L O G ( 6F D Q 5 D G L X V L V 8 Q O L P L W H G & O H D U D Q F H ) D F W R U F X W R I I L V 8 Q O L P L W H G 0 D [ ( O O L S V H 6 H S D U D W L R Q L V X V I W */ 2 % $ / ) , / 7 ( 5 $ 3 3 / , ( ' $ O O Z H O O S D W K V Z L W K L Q R I U HI H U H Q F H 6F D Q 7 \ S H 6F D Q 7 \ S H 3U X G K R H % D \ +L O F R U S 1 R U W K 6 O R S H / / & $Q W L F R O O L V L R Q 5 H S R U W I R U 3 O D Q Z S &R P S D U L V R Q : H O O 1 D P H : H O O E R U H 1 D P H ' H V L J Q #0 H D V X U H G 'H S W K X V I W 0L Q L P X P 'L V W D Q F H X V I W (O O L S V H 6H S D U D W L R Q X V I W #0 H D V X U H G 'H S W K XV I W &O H D U D Q F H )D F W R U 6F D Q 5 D G L X V L V 8 Q O L P L W H G & O H D U D Q F H ) D F W R U F X W R I I L V 8 Q O L P L W H G 0 D [ ( O O L S V H 6 H S D U D W L R Q L V X V I W 6L W H 1 D P H 6F D Q 5 D Q J H W R X V I W 0 H D V X U H G ' H S W K &O R V H V W $ S S U R D F K ' 3 U R [ L P L W \ 6 F D Q R Q & X U U H Q W 6 X U Y H \ ' D W D + L J K VL G H 5 H I H U H Q F H 5H I H U H Q F H ' H V L J Q 3 O D Q Z S 0H D V X U H G 'H S W K X V I W 6X P P D U \ % D V H G R Q 0L Q L P X P 6H S D U D W L R Q : D U Q L Q J &H Q W U H ' L V W D Q F H )$ , / &O H D U D Q F H ) D F W R U )$ , / $ $ &O H D U D Q F H ) D F W R U 3 D V V &O H D U D Q F H ) D F W R U 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V &H Q W U H ' L V W D Q F H 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ &H Q W U H ' L V W D Q F H 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V % % (O O L S V H 6 H S D U D W L R Q 3 D V V % % &O H D U D Q F H ) D F W R U 3 D V V % 3 % % 3 % (O O L S V H 6 H S D U D W L R Q 3 D V V % 3 % % 3 % &O H D U D Q F H ) D F W R U 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V $ $ (O O L S V H 6 H S D U D W L R Q 3 D V V $ $ &O H D U D Q F H ) D F W R U 3 D V V (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V 3 % 3 % (O O L S V H 6 H S D U D W L R Q 3 D V V 3 % 3 % &O H D U D Q F H ) D F W R U 3 D V V &H Q W U H ' L V W D Q F H 3 D V V ' H F H P E H U &2 0 3 $ 6 6 3D J H R I 3U X G K R H % D \ +L O F R U S 1 R U W K 6 O R S H / / & $Q W L F R O O L V L R Q 5 H S R U W I R U 3 O D Q Z S &R P S D U L V R Q : H O O 1 D P H : H O O E R U H 1 D P H ' H V L J Q #0 H D V X U H G 'H S W K X V I W 0L Q L P X P 'L V W D Q F H X V I W (O O L S V H 6H S D U D W L R Q X V I W #0 H D V X U H G 'H S W K XV I W &O H D U D Q F H )D F W R U 6F D Q 5 D G L X V L V 8 Q O L P L W H G & O H D U D Q F H ) D F W R U F X W R I I L V 8 Q O L P L W H G 0 D [ ( O O L S V H 6 H S D U D W L R Q L V X V I W 6L W H 1 D P H 6F D Q 5 D Q J H W R X V I W 0 H D V X U H G ' H S W K &O R V H V W $ S S U R D F K ' 3 U R [ L P L W \ 6 F D Q R Q & X U U H Q W 6 X U Y H \ ' D W D + L J K VL G H 5 H I H U H Q F H 5H I H U H Q F H ' H V L J Q 3 O D Q Z S 0H D V X U H G 'H S W K X V I W 6X P P D U \ % D V H G R Q 0L Q L P X P 6H S D U D W L R Q : D U Q L Q J (O O L S V H 6 H S D U D W L R Q 3 D V V &O H D U D Q F H ) D F W R U 3 D V V 3 % 3 % &H Q W U H ' L V W D Q F H 3 D V V 3 % 3 % (O O L S V H 6 H S D U D W L R Q 3 D V V 3 % 3 % &O H D U D Q F H ) D F W R U 3 D V V / / / / &O H D U D Q F H ) D F W R U 3 D V V / / / &H Q W U H ' L V W D Q F H 3 D V V / / / (O O L S V H 6 H S D U D W L R Q 3 D V V / / / &O H D U D Q F H ) D F W R U 3 D V V / / / &O H D U D Q F H ) D F W R U 3 D V V / / / (O O L S V H 6 H S D U D W L R Q 3 D V V / / / &O H D U D Q F H ) D F W R U 3 D V V / / 3 % / 3 % &O H D U D Q F H ) D F W R U 3 D V V 6X U Y H \ W R R O S U R J U D P )U R P X V I W 7R X V I W 6X U Y H \ 3 O D Q 6 X U Y H \ 7 R R O Z S * < ' B 4 X H V W * : ' Z S B 0 : ' , ) 5 0 6 6 D J Z S B 0 : ' , ) 5 0 6 6 D J Z S B 0 : ' , ) 5 0 6 6 D J ' H F H P E H U &2 0 3 $ 6 6 3D J H R I 0. 0 0 1. 0 0 2. 0 0 3. 0 0 4. 0 0 Separation Factor 10 4 0 0 1 0 6 0 0 1 0 8 0 0 1 10 0 0 1 1 2 0 0 1 1 4 0 0 1 1 6 0 0 1 1 8 0 0 1 2 0 0 0 1 2 2 0 0 1 24 0 0 1 2 6 0 0 1 2 8 0 0 1 3 0 0 0 1 3 2 0 0 1 3 4 0 0 1 3 6 0 0 1 3 8 0 0 1 4 0 0 0 1 4 2 0 0 Me a s u r e d D e p t h ( 4 0 0 u s f t / i n ) 11 - 2 3 11 - 0 9 11 - 0 9 A 11 - 4 0 11 - 4 0 P B 1 11 - 3 9 P B 1 11 - 3 9 No - G o Z o n e - S t o p D r i l l i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . WE L L D E T A I L S : P l a n : 1 1 - 4 2 N A D 1 9 2 7 ( N A D C O N C O N U S ) Al a s k a Z o n e 0 4 26 . 2 0 +N / - S + E / - W N o r t h i n g E a s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0. 0 0 59 5 2 8 4 0 . 0 3 70 7 1 4 8 . 7 5 70 ° 1 6 ' 2 8 . 5 3 3 4 N 14 8 ° 1 9 ' 2 7 . 1 9 1 6 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : 1 1 - 4 2 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : 1 1 - 4 2 a s s t a k e d r k b @ 7 3 . 1 5 u s f t Me a s u r e d D e p t h R e f e r e n c e : 11 - 4 2 a s s t a k e d r k b @ 7 3 . 1 5 u s f t Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e SU R V E Y P R O G R A M Da t e : 2 0 2 3 - 1 1 - 3 0 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o S u r v e y / P l a n To o l 46 . 9 5 9 5 0 . 0 0 1 1 - 4 2 w p 1 0 ( 1 1 - 4 2 ) G Y D _ Q u e s t G W D 95 0 . 0 0 4 9 5 3 . 0 0 1 1 - 4 2 w p 1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 49 5 3 . 0 0 1 0 5 5 6 . 0 0 1 1 - 4 2 w p1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 10 5 5 6 . 0 0 1 4 2 7 0 . 6 6 1 1 - 4 2 w p1 0 ( 1 1 - 4 2 ) 3 _ M W D + I F R 2 + M S + S a g 0. 0 0 30 . 0 0 60 . 0 0 90 . 0 0 12 0 . 0 0 15 0 . 0 0 18 0 . 0 0 Centre to Centre Separation (60.00 usft/in) 10 4 0 0 1 0 6 0 0 1 0 8 0 0 1 10 0 0 1 1 2 0 0 1 1 4 0 0 1 1 6 0 0 1 1 8 0 0 1 2 0 0 0 1 2 2 0 0 1 24 0 0 1 2 6 0 0 1 2 8 0 0 1 3 0 0 0 1 3 2 0 0 1 3 4 0 0 1 3 6 0 0 1 3 8 0 0 1 4 0 0 0 1 4 2 0 0 Me a s u r e d D e p t h ( 4 0 0 u s f t / i n ) NO G L O B A L F I L T E R : U s i n g u s e r d e f i n e d s e l e c t i o n & f i l t e r i n g c r i t e r i a 46 . 9 5 T o 1 4 2 7 0 . 6 6 Pr o j e c t : P r u d h o e B a y Si t e : 1 1 We l l : P l a n : 1 1 - 4 2 We l l b o r e : 1 1 - 4 2 Pl a n : 1 1 - 4 2 w p 1 0 La d d e r / S . F . P l o t s 3 o f 3 CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 39 3 4 . 0 0 3 8 6 0 . 8 5 4 9 5 2 . 8 1 1 0 - 3 / 4 1 0 3 / 4 " x 1 3 1 / 2 " 83 4 0 . 0 0 8 2 6 6 . 8 5 1 0 5 5 5 . 5 1 7 7 " x 9 7 / 8 " 86 4 8 . 1 5 8 5 7 5 . 0 0 1 4 2 7 0 . 6 6 4 - 1 / 2 4 1 / 2 " x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evised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PBU 11-42 PRUDHOE OIL 223-117 PRUDHOE BAY W E L L P E R M I T C H E C K L I S T Co m p a n y Hi l c o r p N o r t h S l o p e , L L C We l l N a m e : PR U D H O E B A Y U N I T 1 1 - 4 2 In i t i a l C l a s s / T y p e EX P / P E N D Ge o A r e a 89 0 Un i t 11 6 5 0 On / O f f S h o r e On Pr o g r a m EX P Fi e l d & P o o l We l l b o r e s e g An n u l a r D i s p o s a l PT D # : 22 3 1 1 7 0 PR U D H O E B A Y , P R U D H O E O I L - 6 4 0 1 5 0 NA 1 P e r m i t f e e a t t a c h e d Ye s S u r f a c e L o c a t i o n l i e s w i t h i n A D L 0 0 2 8 3 2 5 ; T o p P r o d I n t & T D l i e w i t h i n A D L 0 0 2 8 3 2 2 . 2 L e a s e n u m b e r a p p r o p r i a t e Ye s 3 U n i q u e w e l l n a m e a n d n u m b e r Ye s P R U D H O E B A Y , P R U D H O E O I L - 6 4 0 1 5 0 - g o v e r n e d b y 3 4 1 J 4 W e l l l o c a t e d i n a d e f i n e d p o o l Ye s 5 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m d r i l l i n g u n i t b o u n d a r y Ye s 6 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m o t h e r w e l l s Ye s 7 S u f f i c i e n t a c r e a g e a v a i l a b l e i n d r i l l i n g u n i t Ye s 8 I f d e v i a t e d , i s w e l l b o r e p l a t i n c l u d e d Ye s 9 O p e r a t o r o n l y a f f e c t e d p a r t y Ye s 10 O p e r a t o r h a s a p p r o p r i a t e b o n d i n f o r c e Ye s 11 P e r m i t c a n b e i s s u e d w i t h o u t c o n s e r v a t i o n o r d e r Ye s 12 P e r m i t c a n b e i s s u e d w i t h o u t a d m i n i s t r a t i v e a p p r o v a l Ye s 13 C a n p e r m i t b e a p p r o v e d b e f o r e 1 5 - d a y w a i t NA 14 W e l l l o c a t e d w i t h i n a r e a a n d s t r a t a a u t h o r i z e d b y I n j e c t i o n O r d e r # ( p u t I O # i n c o m m e n t s ) ( F o r NA 15 A l l w e l l s w i t h i n 1 / 4 m i l e a r e a o f r e v i e w i d e n t i f i e d ( F o r s e r v i c e w e l l o n l y ) NA 16 P r e - p r o d u c e d i n j e c t o r : d u r a t i o n o f p r e - p r o d u c t i o n l e s s t h a n 3 m o n t h s ( F o r s e r v i c e w e l l o n l y ) NA 17 N o n c o n v e n . g a s c o n f o r m s t o A S 3 1 . 0 5 . 0 3 0 ( j . 1 . A ) , ( j . 2 . A - D ) Ye s 2 0 " 1 2 9 . 5 # d r i v e n t o 1 1 0 ' 18 C o n d u c t o r s t r i n g p r o v i d e d Ye s F u l l y c e m e n t e d , s u r f a c e c a s i n g s h o e a t 3 9 3 4 ' T V D 19 S u r f a c e c a s i n g p r o t e c t s a l l k n o w n U S D W s Ye s 2 s t a g e c e m e n t j o b . S t a g e c o l l a r a t B O P F . S i g n i f i c a n e x c e s s a c r o s s P F . 20 C M T v o l a d e q u a t e t o c i r c u l a t e o n c o n d u c t o r & s u r f c s g Ye s 7 " i n t e r m e d i a t e s h o e s e t i n T S A G . T O C ~ 3 7 1 5 ' M D a b o v e 7 " s h o e . 21 C M T v o l a d e q u a t e t o t i e - i n l o n g s t r i n g t o s u r f c s g Ye s 4 - 1 / 2 " f u l l y c e m e n t e d . 22 C M T w i l l c o v e r a l l k n o w n p r o d u c t i v e h o r i z o n s Ye s 23 C a s i n g d e s i g n s a d e q u a t e f o r C , T , B & p e r m a f r o s t Ye s P a r k e r 2 7 3 h a s a d e q u a t e t a n k a g e a n d g o o d t r u c k i n g s u p p o r t . 24 A d e q u a t e t a n k a g e o r r e s e r v e p i t NA T h i s i s a g r a s s r o o t s w e l l . 25 I f a r e - d r i l l , h a s a 1 0 - 4 0 3 f o r a b a n d o n m e n t b e e n a p p r o v e d Ye s H a l l i b u r t o n c o l l i s i o n s c a n i d e n t i f i e s o n l y 1 c l o s e a p p r o a c h t o a n a b a n d o n e d w e l l i n p r o d u c t i o n h o l e 26 A d e q u a t e w e l l b o r e s e p a r a t i o n p r o p o s e d Ye s 2 0 " d i v e r t e r f o r d r i l l i n g 1 2 - 1 / 4 " s u r f a c e h o l e 27 I f d i v e r t e r r e q u i r e d , d o e s i t m e e t r e g u l a t i o n s Ye s 28 D r i l l i n g f l u i d p r o g r a m s c h e m a t i c & e q u i p l i s t a d e q u a t e Ye s 1 a n n u l a r , 3 r a m , 1 f l o w c r o s s 29 B O P E s , d o t h e y m e e t r e g u l a t i o n Ye s 5 0 0 0 p s i s y s t e m t e s t e d t o 3 5 0 0 p s i . 30 B O P E p r e s s r a t i n g a p p r o p r i a t e ; t e s t t o ( p u t p s i g i n c o m m e n t s ) Ye s 31 C h o k e m a n i f o l d c o m p l i e s w / A P I R P - 5 3 ( M a y 8 4 ) Ye s 32 W o r k w i l l o c c u r w i t h o u t o p e r a t i o n s h u t d o w n Ye s D S - 1 1 i s a n H 2 S p a d . M o n i t o r i n g r e q u i r e d . 33 I s p r e s e n c e o f H 2 S g a s p r o b a b l e NA 34 M e c h a n i c a l c o n d i t i o n o f w e l l s w i t h i n A O R v e r i f i e d ( F o r s e r v i c e w e l l o n l y ) No D S 1 1 w e l l s a r e H 2 S - b e a r i n g . H 2 S m e a s u r e s a r e r e q u i r e d . 35 P e r m i t c a n b e i s s u e d w / o h y d r o g e n s u l f i d e m e a s u r e s Ye s U g n u , W e s t S a k , C o l v i l l e , a n d H R Z a r e o v e r p r e s s u r e d . P r o d u c t i o n i n t e r v a l i s u n d e r p r e s s u r e d . O p e r a t o r ' s 36 D a t a p r e s e n t e d o n p o t e n t i a l o v e r p r e s s u r e z o n e s NA p l a n n e d m u d p r o g r a m a p p e a r s a d e q u a t e t o c o n t r o l e x p e c t e d p r e s s u r e s . M P D w i l l b e a v a i l a b l e 37 S e i s m i c a n a l y s i s o f s h a l l o w g a s z o n e s NA t o m i t i g a t e b o r e h o l e i n s t a b i l i t y . 38 S e a b e d c o n d i t i o n s u r v e y ( i f o f f - s h o r e ) NA 39 C o n t a c t n a m e / p h o n e f o r w e e k l y p r o g r e s s r e p o r t s [ e x p l o r a t o r y o n l y ] Ap p r SF D Da t e 12 / 1 1 / 2 0 2 3 Ap p r MG R Da t e 12 / 2 0 / 2 0 2 3 Ap p r SF D Da t e 12 / 1 1 / 2 0 2 3 Ad m i n i s t r a t i o n En g i n e e r i n g Ge o l o g y Ge o l o g i c Co m m i s s i o n e r : Da t e : En g i n e e r i n g Co m m i s s i o n e r : Da t e Pu b l i c Co m m i s s i o n e r Da t e *& :