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Home My WebLink About224-065Nolan 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: 9/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240927 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T39593 T39594 T39595 T39596 T39597 T39598 T39599 T39600 T39601 T39602 T39603 T39603 T39604 T39605 T39605 T39605 T39605 T39606 T39606 T39607 T39608 T39609 T39609 T39610 T39611 NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 14:47:28 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 9/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 7/22/2024 BAKER RPM Blossom 1 50133206480000 215015 8/31/2024 READ Coilflag Blossom 1 50133206480000 215015 9/2/2024 READ MemoryRadialCementBondLog KBY 43-07Y 50133206250000 214019 9/9/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/29/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/4/2024 AK E-LINE Plug/Perf NCIU A-20 50883201960000 224065 8/29/2024 AK E-LINE Perf NCIU A-20 50883201960000 224065 9/3/2024 AK E-LINE Plug/Perf PBU N-21A (REVISED) 50029213420100 196196 3/28/2024 BAKER SPN PBU N-02 50029200830000 170055 7/25/2024 BAKER SPN PBU S-104 50029229880000 200196 7/7/2024 BAKER SPN PBU Z-68 50029234930000 213093 7/6/2024 BAKER SPN Pearl 11 50133207120000 223032 6/24/2024 BAKER SPN Revision explanation: OmniView .las file was the same as the carbo/oxygen .las file, omniview file has been replaced with the correct file and data. Please include current contact information if different from above. T39545 T39546 T39546 T39547 T39548 T39548 T39549 T39549 T39550 T39551 T39552 T39553 T39554 NCIU A-20 50883201960000 224065 8/29/2024 AK E-LINE Perf NCIU A-20 50883201960000 224065 9/3/2024 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.12 12:52:42 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,633 N/A Casing Collapse Structural Conductor 230psi Surface 4,750psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: CT / N2 Ops / Initial Completion CO 68A 8/12/2024 4-1/2" LTP & Baker TE-5 5,373 (MD) 3,365 (TVD) & 433 (MD) 433 (TVD) 9,633' Perforation Depth MD (ft): ѷ7,304 - ±9,325 4,260' ±4,493 - ±6,445 6,748'4-1/2" 30" 9-5/8" 384' 5,584' MD 1,630psi 6,870psi 384' 3,466' 384' 5,584' Length Size Proposed Pools: L-80 TVD Burst 5,423 8,430psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 224-065 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20196-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-20 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY N Cook Inlet Unit None Tertiary System Gas 6,748 9,588 6,704 2,640psi N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.07.31 08:26:29 - 08'00' Dan Marlowe (1267) 324-442 By Grace Christianson at 8:35 am, Jul 31, 2024 Submit CBL to AOGCC and obtain approval to proceed before perforating. DSR-8/2/24 BOP test to 3000 psi. Weekly BOP tests approved for CT unit while remaining on leg #2. X BJM 8/5/24 A.Dewhurst 05AUG24 10-407 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.05 15:14:49 -08'00'08/05/24 RBDMS JSB 080624 Initial Completion Well: NCIU (Tyonek) A-20 Well Name:NCIU (Tyonek) A-20 API Number:50-883-20196-00-00 Current Status:New drill gas well Leg:Leg #2 (SW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:224-065 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,285 psi @ 6,445’ TVD 9.8ppg at Deepest planned perf Max. Potential Surface Pressure: 2640 psi Using 0.1 psi/ft Brief Well Summary Jackup Rig #151 finished drilling and completing Tyonek well A-20 on 7/9/24. The drilling rig is currently completing a second well on this same leg (#2). Once the rig transitions to leg #1 for additional drilling, we will be able to access A-19 and A-20 new drills for post-drill work. A-20 is a closed system currently and is not open to the formation. This procedure addresses the initial post-drill completion wellwork to get the well online. All planned perforations below are within the Tertiary System Gas Pool as defined by CO 68A. The goal of this project is to complete the well after the drilling rig leaves. Pertinent wellbore information: - TRSSSV installed -Live GLV’s were already installed when the tubing was run - 7/8/24 o CMIT-TxIA to 3000psi PASSED o MIT-T to 3000psi PASSED (also confirmed liner integrity. No TTP was set) Coiled Tubing Procedure 1. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high a. Multiple wells planned for CT intervention on this leg (#2) b. Hilcorp requests a weekly CT BOP test requirement while on this leg, instead of each well 3. MU cleanout BHA 4. RIH to PBTD and swap well over to water if needed 5. Obtain CBL (may be executed on EL. TBD) Submit CBL to AOOGCC 6. RIH and blow well dry with nitrogen a. Reverse circulate water out of wellbore (no perforations, passing MIT’s) b. Want to evacuate all IA fluid through live GLV’s as well 7. RDMO CT Weekly BOP test approved for leg #2 only. -bjm Initial Completion Well: NCIU (Tyonek) A-20 E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. Ensure CBL approval from AOGCC before perforating 4. RIH and perforate Beluga gas sands from ±7304’ - ±9,325’ MD (±4,493’ - ±6,445’ TVD) per RE/Geo a. All proposed perfs within Tertiary System Gas Pool b. Bottom pool is below PBTD c. Top pool is at top Sterling sands (Far above top BEL-A at 7,304’ MD / 4493’ TVD) d. Pressures: i. 9-5/8” at 3465’ TVD: LOT at 13.8PPG ii. Worst case pressure could create a 13.3ppg at the top sundried perf (4493’ TVD) 5. RDMO EL CONTINGENCY plug/patch: (if any zone makes unwanted solids or water) 1. RU nitrogen to tubing and PT lines to 3000psi (or higher if needed) 2. Pressure up on tubing and displace water back into formation 3. MIRU E-line and pressure control equipment 4. PT lubricator to 250psi low / 3000psi high 5. Set 4-1/2” isolation plug or patch per OE 6. RDMO Nitrogen and EL CONTINGENCY CT Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. MU FCO BHA 4. RIH and cleanout to PBTD or as deep as practical a. Working fluid will be water (8.33ppg or greater) b. Take returns to surface up the CT x tubing annulus c. Add foam and nitrogen as necessary to carry solids to surface d. Can use GL to assist with hole cleaning 5. Once cleanout is completed, blow well down with nitrogen 6. RDMO CT Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOP Drawing (Fox energy) 4. Nitrogen procedure Updated by CJD 7-29-2024 SCHEMATIC North Cook Inlet Unit NCIU A-20 PTD: 224-065 API: 50-883-20196-00-00 PBTD = 9,588’ / TVD = 6,704’ TD = 9,633’ / TVD = 6,748’ RKB = 126.6’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,584’ 4-1/2" Prod Lnr 12.6 L-80 JFE Lion 3.958” 5,373’ 9,633’ 4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,423’ 130” 12-1/4” hole 4-1/2” JEWELRY DETAIL No. Depth Item 1 433’SSSV 2 1,057’ ES Cementer 3 2,263’ GLM 4.5” x 1.5” FO-2 4 5,309’ GLM 4.5” x 1.5” FO-2 5 5,362’ X nipple 3.813” Profile 6 5,406’ Seal Stem 7 5,373’ Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 – 365 bbls Stg 2 - 337 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 264 bbls / T – 37 bbls 8-1/2” hole 2 4 5/6/7 3 _____________________________________________________________________________________ Updated By: JLL 07/30/24 PROPOSED North Cook Inlet Unit NCIU A-20 PTD: 224-065 API: 50-883-20196-00-00 PBTD = 9,588' / TVD = 6,704' TD = 9,633' / TVD = 6,748' 1 2 Beluga Gas Sands 3/4/5 RKB = 126.6’ 8-1/2” hole 12-1/4” hole 30” 4-1/2” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,584’ 4-1/2" Prod Lnr 12.6 L-80 JFE Lion 3.958” 5,373’ 9,633’ 4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,423’ JEWELRY DETAIL No.Depth MD Depth TVD Item 1 433’ 433' Baker TE-5 SSSV 2 1,057’ 1,051' ES Cementer 3 5,362’ 3,360' X nipple 3.813” Profile 4 5,406’ 3,380' Seal Stem 5 5,373’ 3,365' Liner hanger / LTP Assembly GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,263 1,989 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 7/8/2024 2 5,309 3,336 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod)24 Orifice 7/8/2024 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Beluga Gas Sands ѷ͖Ϡ͒͏͓Д ±9,325' ±4,493' ±6,445' ±2,021' Future Proposed OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 – 365 bbls Stg 2 - 337 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 264 bbls / T – 37 bbls KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. David Douglas Hilcorp Alaska, 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: Date: 07/26/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: NCIU A-20 PTD: 224-065 API: 50-883-20196-00-00 FINAL LWD FORMATION EVALUATION LOGS (06/03/2024 to 07/03/2024) x EWR-P4, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Data Main Folders: Please include current contact information if different from above. 224-065 T39305 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.26 11:41:32 -08'00' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] NCIU A-20 FIT Date:Thursday, June 20, 2024 3:39:24 PM Attachments:image002.png image003.png NCIU A-20 csg test and FIT.xls HILCORP NCI A-20 2 STAGE SURFACE.docx I called the FIT at 13.9ppg. The cement plug didn’t bump but the shoe was full of cement when we drilled out. I get a 61 bbl KTV. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 20, 2024 12:47 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] NCIU A-20 FIT Sean, Have you performed the FIT on this well yet? If so, can you send over the data so we can include the actual kick tolerance as part of the waiver write-up. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. CASING AND LEAK-OFF FRACTURE TESTS Well Name:NCIU A-20 Date:6/20/2024 Csg Size/Wt/Grade:9-5/8'', 47#, Supervisor:auck/Dambacher Csg Setting Depth:5584 TMD 3460 TVD Mud Weight:8.8 ppg LOT / FIT Press =922 psi LOT / FIT =13.92 ppg Hole Depth =5619 md Fluid Pumped=8.4 Bbls Volume Back =1.9 bbls Estimated Pump Output:0.083 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->0 0 ->0 0 ->10 123 123 ->10 389 ->20 312 189 ->20 920 ->30 474 162 ->30 1517 ->40 628 154 ->40 2060 ->50 778 150 ->50 2688 ->60 922 144 ->60 3300 ->70 1003 81 ->71 3798 ->80 1061 58 -> ->90 1100 39 -> ->100 1132 32 -> ->102 1138 6 -> -> -> -> -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 1138 ->0 3794 ->1 963 ->2 3786 ->2 864 ->4 3782 ->3 785 ->6 3775 ->4 724 ->8 3770 ->5 675 ->10 3766 ->10 524 ->12 3761 ->15 433 ->14 3759 -> ->16 3754 -> ->18 3754 -> ->20 3752 -> ->22 3751 -> ->24 3748 -> ->26 3745 -> ->28 3743 -> ->30 3740 -> -> 0 10 20 30 40 50 60 70 80 90 100102 0 10 20 30 40 50 60 71 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 3900 4000 0 10 20 30 40 50 60 70 80 90 100 110Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 1138 963 864 785 724675 524 433 3794 3786 3782 3775 3770 3766 3761 3759 3754 3754 3752 3751 3748 3745 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 3900 4000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA HILCORP ALASKA LLC Alaska District, ALASKA For: SHANE HAUCK Date: Thursday, June 13, 2024 NCI A-20 NCI HILCORP NCI A-20 2 STAGE SURFACE 909386499 Job Date: Thursday, June 13, 2024 Sincerely, STEVE MCCOY Legal Notice Disclaimer: All information in this report is provided subject to the terms and conditions which govern the services provided by Halliburton. Halliburton personnel use their best efforts in gathering information and their best judgment in interpreting it, but any interpretation, research, analysis or recommendation furnished by Halliburton are opinions based upon inferences from measurements and empirical relationships and assumptions, which inferences and empirical relationships and assumptions are not infallible, and with respect to which professionals in the industry may differ. iCem 3D Displacement results are used to understand how fluids intermix during a cement job. Simulation and 3D displacement results are not intended as and should not be used as a replacement for bond logs in determining top of cement. Current 3D model calculations are known to model more volume than the input volume for standard cases due to known calculation improvements required. For rotational cases, the modeled volume will be impacted by the same calculations impacting the standard cases, as well as additional constraints imposed to make the calculation time required operationally feasible. Therefore, until further notice, 3D displacement results should not be used for replacement of a bond log, or used as an identifier of top of cement. HALLIBURTON IS UNABLE TO GUARANTEE THE ACCURACY OF ANY CHART INTERPRETATION, RESEARCH ANALYSIS, OR JOB RECOMMENDATION and any interpretation or recommendation is not for use of or reliance upon by any third party. The customer has full responsibility for any of its decisions which are based on the information provided in this report. © 2021 Halliburton. All rights reserved. Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 3 (v. 7.0.192.0) Created: Thursday, June 13, 2024 Table of Contents Real-Time Job Summary ....................................................................................................................................... 4 Job Event Log ......................................................................................................................................................................................... 4 Attachments ......................................................................................................................................................... 9 HILCORP NCI A-20 2 STAGE SURFACE 909386499-Custom Results.png ................................................................................................ 9 HILCORP NCI A-20 2 STAGE SURFACE 909386499-2nd Stage.png ....................................................................................................... 10 HILCORP NCI A-20 2 STAGE SURFACE 909386499-1st Stage.png ........................................................................................................ 11 Custom Graphs ....................................................................................................... Error! Bookmark not defined. Custom Graph .......................................................................................................................................... Error! Bookmark not defined. Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 4 (v. 7.0.192.0) Created: Thursday, June 13, 2024 1.0 Real-Time Job Summary 1.1 Job Event Log Type Seq . No. Activity Graph Label Date Time Source DS Pump Press DH Density Comb Pump Rate Comb Pump Total Pump Stg Tot Comments (psi) (ppg) (bbl/mi n) (bbl) (bbl) Event 1 Other Call Out 6/10/20 24 16:00:0 0 USER Requested at the Heliport 1900 Event 2 Other Arrive on Rig 6/10/20 24 19:30:0 0 USER Event 3 Other Check out equipment 6/10/20 24 20:30:0 0 USER Event 4 Other RIH Shoe track 6/11/20 24 08:00:0 0 USER Drop Bypass baffle on top of float collar Event 5 Other RIH ES Cementer 6/12/20 24 02:20:0 0 USER Event 6 Other Casing on bottom 6/12/20 24 10:15:0 0 USER Rig circulated -+ 1200 bbls @ 5 bpm 150 psi FCP 19 VIS Event 7 Other Well Info 6/12/20 24 10:59:0 0 USER TD: 5599 12.25" Float Shoe: 5584' Float Collar: Baffle Adapter: 5455' Casing: 9.625" L80 47# Event 8 Other PRE JOB Safety 6/12/20 11:00:0 USER Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 5 (v. 7.0.192.0) Created: Thursday, June 13, 2024 meeting 24 0 Event 9 Start Job Start Job 6/12/20 24 13:32:1 2 COM3 0.51 8.25 0.00 0.00 0.00 Event 10 Test Lines Test Lines 6/12/20 24 13:35:5 6 USER 82.20 8.35 0.00 5.03 5.03 1030 PSI LOW PRESSURE TEST 4450 HIGH PRESSURE TEST Event 11 Pump Spacer 1 Pump Spacer 1 6/12/20 24 13:47:3 0 USER 19.29 8.30 0.00 0.00 0.00 Pump 60 bbls Tuned Prime Spacer @ 10.5 ppg @ 3.5 bpm 300 psi Event 12 Other SHUTDOWN 6/12/20 24 14:01:0 6 USER 240.28 10.25 2.62 25.45 25.45 SHUTDOWN DOWN DUE TO POOR BULK DELIVERY Event 13 Pump Lead Cement Pump Lead Cement 6/12/20 24 14:19:5 7 USER 397.70 11.22 4.15 59.38 0.69 MIXED & PUMPED 317 BBLS 12 PPG, 2.393 Y, 14.2 GPS @ 4 BPM 400 PSI Event 14 Other Pump Tail Cement 6/12/20 24 15:42:5 2 USER 135.72 13.42 2.40 388.80 1.39 MIXED & PUMPED 48 BBLS @ 15.8 PPG, 1.158 Y, 4.985 GPS @ 2 BPM 150 PSI Event 15 Shutdown Shutdown 6/12/20 24 16:09:4 5 USER 154.67 15.87 0.00 437.45 50.04 DROP 1ST STAGE CLOSING PLUG Event 16 Drop Plug Drop Plug 6/12/20 24 16:11:2 8 USER 21.01 15.87 0.00 437.45 50.04 Event 17 Pump Displacement Pump Displacement 6/12/20 24 16:13:1 1 USER 19.39 15.87 0.00 437.45 50.04 PUMPED 20 BBLS FRESH WATER @ 4 Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 6 (v. 7.0.192.0) Created: Thursday, June 13, 2024 BPM 310 PSI Event 18 Shutdown Shutdown 6/12/20 24 16:18:5 4 USER 138.54 8.18 0.00 458.31 20.75 Turn over rto Rig to displace 9.3 ppg WBM Rig pumped 292 bbls(3517 strokes) @ 6 bpm 177 psi slowed rate to 5 bpm with 40 bbls of WBM away FCP 6 bpm 500 psi Event 19 Other Pump Displacement Spacer 6/12/20 24 17:16:0 0 USER Rig displaced 64 bbls 9.6 ppg spacer Event 20 Other Pump Displacement WBM 6/12/20 24 17:35:0 0 USER Pumped WBM to bump plug. with 405.6 bbls away into displacement plug did not pump which was half the shoe track + 1bbls. Decision was made to drop opening tool. Event 21 Other Drop opening plug 6/12/20 24 17:56:0 0 USER Event 22 Other open ES Cementer 6/12/20 24 18:13:0 0 USER ES Cementer opened @ 407 psi. Circulate well 5 bpm 185 psi Event 23 Other Cement to Surface 6/12/20 24 18:15:0 0 USER Circulated 3 bbls of cement and 62 bbls of Spacer off the top of the tool. Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 7 (v. 7.0.192.0) Created: Thursday, June 13, 2024 Event 24 Start Job Start Job 6/12/20 24 20:55:0 0 COM3 0.01 8.24 0.00 2.19 2.19 5 bbls @ 2 BPM 60 PSI Event 25 Pump Spacer 2 Pump Tuned Spacer 6/12/20 24 21:00:3 9 USER 15.56 8.24 0.00 0.00 0.00 Mixed & Pumped 56 bbls Tuned Spacer @ 10.5 PPG @ 4 BPM 220 PSI Event 26 Pump 2nd Stage Tail Slurry Pump Cement 6/12/20 24 21:20:0 4 USER 117.95 10.61 2.91 63.04 0.27 Mixed & Pumped 1040 sks Primary Cement @ 12.0 ppg, 2.433 Y, 14.426 GPS @ 5 BPM 450 PSI Event 27 Shutdown Shutdown 6/12/20 24 23:03:2 9 USER 245.23 12.65 0.11 550.29 487.52 Event 28 Drop Plug Drop Plug 6/12/20 24 23:04:3 1 USER 27.07 12.66 0.00 550.29 487.52 Event 29 Pump Displacement Pump H2O Displacement 6/12/20 24 23:05:3 0 USER 27.09 12.63 0.00 550.29 0.00 Event 30 Shutdown Shutdown 6/12/20 24 23:14:4 0 USER 198.66 8.22 0.00 579.41 29.12 Event 31 Circulate Well Rig WBM Pump Displacement 6/12/20 24 23:15:0 9 USER 27.05 8.39 0.00 579.41 29.12 Rig Pumped 47.8 bbls 9.4 ppg WBM @ 5 BPM 241 PSI Event 32 Circulate Well Slow Rate 6/12/20 24 23:23:0 0 USER 15.89 8.39 0.00 579.41 29.12 Slowed rate to 3 bpm 150 psi for the last 10 bbls of displacement Event 33 Circulate Well Bump Closing Plug 6/12/20 24 23:29:0 0 USER Bumped plug with 77 bbls of displacement pumped FCP 150 psi Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 8 (v. 7.0.192.0) Created: Thursday, June 13, 2024 Brought pressure up to 1800 psi observed tool shift closed Event 34 Shutdown Release pressure 6/12/20 24 23:35:0 0 USER Confirmed tool closed no flow Event 35 Shutdown Post job safety meeting 6/12/20 24 23:45:0 0 USER Event 36 Drop Plug Cement Returns to Surface 6/12/20 24 23:46:0 0 USER 60 BBLS SPACER TO SURFACE 128 BBLS OF CEMENT TO SURFACE Event 37 End Job End Job 6/12/20 24 23:55:0 0 COM3 Event 38 Shutdown Depart Rig 6/13/20 24 02:00:0 0 USER Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 9 (v. 7.0.192.0) Created: Thursday, June 13, 2024 2.0 Attachments 2.1 HILCORP NCI A-20 2 STAGE SURFACE 909386499-Custom Results.png Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 10 (v. 7.0.192.0) Created: Thursday, June 13, 2024 2.2 HILCORP NCI A-20 2 STAGE SURFACE 909386499-2nd Stage.png Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 11 (v. 7.0.192.0) Created: Thursday, June 13, 2024 2.3 HILCORP NCI A-20 2 STAGE SURFACE 909386499-1st Stage.png Customer: HILCORP ALASKA LLC Job: HILCORP NCI A-20 2 STAGE SURFACE Case: HILCORP NCI A-20 2 STAGE SURFACE 909386499 | SO#: 909386499 Page 12 (v. 7.0.192.0) Created: Thursday, June 13, 2024 P.I. Supv Comm: Rig Coil Tubing Unit? No Rig Contractor Rig Representative Operator Operator Representative Well Permit to Drill # 2240650 Sundry Approval # Operation Inspection Location Working Pressure, W/H Flange P Pit Fluid Measurement P Working Pressure P P Flow Rate Sensor P Operating Pressure P P Mud Gas Separator P Fluid Level/Condition P P Degasser P Pressure Gauges P P Separator Bypass P Sufficient Valves P FP Gas Detectors P Regulator Bypass P P Alarms Separate/Distinct P Actuators (4-way valves) P P Choke/Kill Line Connections P Blind Ram Handle Cover P P Reserve Pits P Control Panel, Driller P P Trip Tank P Control Panel, Remote P PFirewallP FP 2 or More Pumps P P Kelly or TD Valves P Independent Power Supply P P Floor Safety Valves P N2 Backup P FP Driller's Console P Condition of Equipment P P Flow Monitor P Flow Rate Indicator P Pit Level Indicators P Valves FP PPE P Gauges P Remote Hydraulic Choke P Well Control Trained P Gas Detection Monitor P FOV Upstream of Chokes P Housekeeping P Hydraulic Control Panel P Targeted Turns P Well Control Plan P Kill Sheet Current P Bypass Line P FAILURES:4 CORRECT BY: COMMENTS See attached CHOKE MANIFOLD Tyonek Platform MUD SYSTEM NCIU A-20 Drilling CLOSING UNIT ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT HCR Valve(s) Manual Valves Annular Preventer Working Pressure, BOP Stack Stack Anchored Choke Line Kill Line Targeted Turns Pipe Rams Blind Rams D. Hebert / D. Boyd S. Hauck / B. LaFleur Locking Devices, Rams BOP STACK Josh Hunt 6/17/2024INSPECT DATE AOGCC INSPECTOR Prior to proceding with the well plan. Hilcorp 151 Enterprise Hilcorp Alaska LLC MISCELLANEOUS Flange/Hub Connections Drilling Spool Outlets Flow Nipple Control Lines RIG FLOOR 2024-0617_Rig_Hilcorp151_NCIU_A-20_jh rev. 4-19-2023 9 9 9 9 9 9 9 9 99 See attached James B. Regg Digitally signed by James B. Regg Date: 2024.07.26 09:54:38 -08'00' Rig Inspection – Hilcorp 151 NCIU A-20; PTD 2240650 Associated Report # bopJDH240620193106 AOGCC Inspector J. Hunt 6/17/2024 Remarks from Rig Inspection Report: The locking devices for the BOP's/rams were not on location at the time of inspection. They promptly got the welder to modify some from a larger set that they did have and were completed before I left location. The Flow Nipple/ Riser was installed but woudn't hold water due to a bad weld. The planned to remove it after testing and get it repaired prior to picking up BHA. The manual valve on the choke line failed initially and passed a retest after greasing. CMV # 7 failed initially and passed a restest after greasing. The rig itslef was actually slid off of the jack up part and onto the platform due to the jack up configuration not having enough reach. Very interesting set up, they were able to add in the reserve pits for more volume. This set up involved a lot more high/low pressure lines and flow lines and a lot more potential for leaks and exposure but seems to work well for what they are doing. 9 9 9 9 9 9 9 locking devices for the BOP's/rams were not on location gy low Nipple/ Riser was installed but woudn't hold water manual valve on the choke line failed CMV # 7 failed initially STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________N COOK INLET UNIT A-20 JBR 07/26/2024 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:2 After pushing a day and a half they weren't ready when I showed up. Good Rig Inspection. We fought air in the system and a huge temperature change during this test which caused it to go a lot longer than it should have. Tested with 4.5" and 5" test joints. F/P on CMV #7 and Manual Choke valve. Greased and cycled, passed. Test Results TEST DATA Rig Rep:D. Hebert / D. BoydOperator:Hilcorp Alaska, LLC Operator Rep:S. Hauck / B. LaFleur Rig Owner/Rig No.:Hilcorp 151 PTD#:2240650 DATE:6/17/2024 Type Operation:DRILL Annular: 250/2500Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopJDH240620193106 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 14 MASP: 2758 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 1 P Inside BOP 1 P FSV Misc 0 NA 13 FPNo. Valves 1 PManual Chokes 2 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8" 5M P #1 Rams 1 2-7/8 X 5-1/2"P #2 Rams 1 Blinds 5M P #3 Rams 1 2-7/8 X 5-1/2"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8" 5M FP HCR Valves 2 3-1/8" 5M P Kill Line Valves 3 3-1/8" 5K, 2 3 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3150 Pressure After Closure P1800 200 PSI Attained P38 Full Pressure Attained P136 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P16@2100 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 0MS Misc Inside Reel Valves 0 NA Annular Preventer P12 #1 Rams P11 #2 Rams P12 #3 Rams P11 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 9 9 9 9 9999 9 9 9 FP FP After pushing a day and a half they weren't ready when I showed up F/P on CMV #7 Manual Choke 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): ~9633 None Casing Collapse Structural Conductor 230 Surface 4750 Intermediate Production 7500 Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone:907-223-6784 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng NCIU A-20 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 37831 & 17589 224-065 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20196-00-00 PRESENT WELL CONDITION SUMMARY Hilcorp Alaska, LLC Length Size Proposed Pools: North Cook Inlet Tertiary System Gas Pool ~6727 ~9550 L-80 TVD Burst ~5357' 8430 MD 1630 6870 ~384' ~3450' ~384' ~5557' ~6727'~9633' 30" 9-5/8" ~384' ~5557' 4-1/2" 12.6# None Perforation Depth MD (ft): None ~9633' 4-1/2" ~6645 2758 None Monty Myers Drilling Manager Sean McLaughlin sean.mclaughlin@hilcorp.com Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Managed Pressure Drilling June 19, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.06.17 15:24:45 - 08'00' Sean McLaughlin (4311) Sean McLaughlin for Monty Myers 324-347 By Grace Christianson at 3:55 pm, Jun 17, 2024 DSR-6/17/24 See attached conditions of approval. 10-407 A.Dewhurst 20JUN24BJM 6/20/24*&:JLC 6/21/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.21 09:15:15 -08'00'06/21/24 RBDMS JSB 062524 NCIU A-20 (PTD 224-065) Sundry #324-347 and Waiver to 20 AAC 25.033(b)(1)(A) conditions of approval ēĖŜϙŜŪĲîŘƅϙŜôŘŽôŜϙÍŜϙÍĲϙÍŕŕŘĺŽÍīϙťĺϙŪŜôϙÍϙîŘĖīīĖĲČϙƲŪĖîϙťēÍťϙîĺôŜϙĲĺťϙēÍŽôϙŜŪƯĖèĖôĲťϙîôĲŜĖťƅϙťĺϙ overbalance the pressure of the uncased portion of the formations penetrated in the 8-3/4” hole section of this well, which requires a waiver to 20 AAC 25.033(b)(1)(A). This waiver is conditional on the following: 1. A Managed Pressure Drilling (MPD) system is to be used to apply the surface pressure required to keep the open hole formations in an overbalanced state whenever the drilling ƲŪĖîϙîôĲŜĖťƅϙĖŜϙĖĲŜŪƯĖèĖôĲťϙťĺϙıÍĖĲťÍĖĲϙĺŽôŘæÍīÍĲèôϙťĺϙťēôϙĺŕôĲϙēĺīôϙċĺŘıÍťĖĺĲŜϟ 2. ēôϙ>Iϯ[iϙŕŘôŜŜŪŘôϙĖŜϙŜŪƯĖèĖôĲťϙťĺϙıÍĖĲťÍĖĲϙѳ30 bbls kick tolerance with a 0.5 ppg kick intensity above the highest anticipated reservoir pressure. This is a relatively high kick tolerance which provides some room for error in MPD choke system failure or human errors associated with kick prevention anîϙſôīīϙèĺĲťŘĺīϙŘôŜŕĺĲŜôϟϙϙXĖèħϙťĺīôŘÍĲèôϙťĺϙæôϙŽôŘĖƱôîϙ using actual FIT/LOT data derived from the test performed after drilling out the previously set casing shoe of this well. i@ϙŽôŘĖƱèÍťĖĺĲϙĺċϙŜŪƯĖèĖôĲťϙ>Iϯ[iϙŘôŜŪīťŜϙŘôŗŪĖŘôîϙ before waiver will be approved. Ai@ϙŽôŘĖƱôîϙa 13.9 ppg LOT EMW at the surface casing shoe 6/20/24 -bjm 3. īīϙĖĲƲŪƄôŜϙťĺϙæôϙcirculated out per conventional well kill protocols, with closed BOP and ŜīĺſϙŕŪıŕϙŘÍťôϟϙϙa"ϙŜƅŜťôıϙſĖīīϙĲĺťϙæôϙŪŜôîϙċĺŘϙèĖŘèŪīÍťĖĲČϙĺŪťϙĖĲƲŪƄôŜϠϙſēôťēôŘϙťēôϙĖĲƲŪƄϙ occurred while drilling, while making a connection or while tripping, or while conducting any other operation. 4. ôťŪŘĲϙƲĺſϙŜťŘôÍıϙťĺϙæôϙŘĺŪťôîϙťēŘĺŪČēϙťēôϙƲĺſīĖĲôϙÍĲîϙƲĺſϙŕÍîîīôϙîĺſĲŜťŘôÍıϙĺċϙťēôϙ a"ϙèēĺħôϙÍĲîϙĺŘôĺīĖŜϙƲĺſϙıôťôŘϙŜĺϙťēôϙîŘĖīīôŘϙèÍĲϙĺæŜôŘŽôϙèēÍĲČôŜϙťĺϙŘôťŪŘĲϙƲĺſϙŘÍťôϙ independent of the MPD system. 5. Kick while drilling drills to be held daily on each tour while using MPD system. An additional consideration for this waiver approval is the relatively low uncertainty for the ıÍƄĖıŪıϙŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôŜϙĖĲϙťēĖŜϙēĺīôϙŜôèťĖĺĲϙîŪôϙťĺϙťēôϙıŪīťĖŕīôϙŕôĲôťŘÍťĖĺĲŜϙæôīĺſϙťēôϙ Tyonek Platform. Reservoir pressures are well understood and thus the risk of a kick intensity of ѳ͏ϟ͔ϙŕŕČϙÍæĺŽôϙıÍƄϙÍĲťĖèĖŕÍťôîϙŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôϙĖŜϙīĺſϟ Page 1 June 17, 2024 NCI A-20 Change of Approved Program APD 224-065 A-20 Waiver request to 20 AAC 25.033(b)(1)(A) Description: A combination of hydrostatic pressure and choke pressure will be used to provide overbalance while drilling. The technique is called Managed Pressure Drilling. MPD equipment: 1. 1. 2. 2. 3. 4. 5. MPD layout: Attached Planned Overbalance while drilling: 0.5 ppg Maximum expected choke pressure (static fluid column): 9.1 ppg MW, 9.8 ppg reservoir pressure at 6727’ TVD (TD), 10.3 ppg bottom hole pressure: 420 psi Influx management:. Rig crew to monitor flow and pit levels per standard operations. Rig crew to shut in per standard operations (no change to standing orders). Influx will be managed conventionally. Rig crew training: MPD awareness only. Additional driller responsibility to notify the MPD technician of a change in pump rate. This is a courtesy notification as the system will automatically trap pressure when the pump is shut down. On the job training, as the first 3000’ will be drilled with overbalanced fluid and MPD will only be used to keep constant BHP. Sean McLaughlin (907)223-6784 See additional e-mail correspondence from Sean McLaughlin on 6/20/24 further describing the limited role MPD equipment will play in well control response and the driller's responsibility to follow the rig's standing orders. - bjm NCI A-20 Change of Approved Program APD 224-065 BOP Schematic Note: the fluid flow stream passes through the flow paddle in the flowline downstream of the MPD manifold and Coriolis flow meter, allowing driller a traditional means of monitoring changes in return flow rate. -bjm Updated by CJD 6-17-2024 Proposed SCHEMATIC North Cook Inlet Unit NCIU A-20 PTD: 224-065 API: 50-883-20196-00-00 PBTD = 9,550’ / TVD = 6,645’ TD = 9,633’ / TVD = 6,727’ RKB = 126.6’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,557’ 4-1/2" Prod Lnr 12.6 L-80 JFE Lion 3.958” 5,357’ 9,633’ 4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,357’ 130” 12-1/4” hole 4-1/2” JEWELRY DETAIL No. Depth Item 1 ±500’ SSSV 2 ±1,006’ ES Cementer 3 ±2,360’ GLM with Dummy 1-1/2” valve 4 ±4,573’ GLM with Dummy 5 ±4,626’ X nipple 3.813” Profile 6 ±5,357’ Seal Stem 7 ±5,357’ Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 – 362 bbls Stg 2 - 336 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 263 bbls / T – 37 bbls 8-1/2” hole 2 4 5/6/7 3 6 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Cc:Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Date:Thursday, June 20, 2024 10:54:19 AM Attachments:image001.png Bryan, If the mud pump is stopped the MPD choke will automatically be maintaining a set pressure. The MPD choke will automatically trap pressure in the event of a pump shut down. The choke pressure will be set to maintain a constant BHP. The driller doesn’t need to step the pump down or consult with the MPD supervisor. Per the AOGCC concerns the revised procedures keep the systems independent. The driller can shut down pumps and shut in at will. The MPD chokes will prevent a sudden drop in surface pressure if the pumps are stopped suddenly. For reference, the proposed MPD kit is a more advanced system than in use on the CTD rigs. In those operations when the pump speed is changed the choke is manually changed. If the pump stops suddenly then the well will flow until the choke is shut in. Both crews drilled to these standing orders yesterday. There was no confusion in responsibilities. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 20, 2024 10:15 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Sean, For kick while drilling, can you describe what will be happening with the MPD choke during the period between stopping the pump (Highlighted in yellow in the standing orders below) and upper pipe ram sealing around the drill pipe. Does the MPD choke system automatically trap pressure when pumps go down? If so, how is the pressure level determined? Does the driller need to step the pump rate down slowly to allow the MPD choke to adjust pressures, or will the driller just turn the pumps off immediately, like a switch? If the latter, the sudden drop in surface pressure resulting from pumps going off will result in a period of increased flow until the pipe rams seal around the drill pipe. Even with the simplified approach for MPD, there are still some subtle differences when using underbalanced fluids. These differences need to be clear so there is no confusion in the heat of the moment. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Thursday, June 20, 2024 9:27 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Bryan, Here is the additional information you requested: Kick while drilling: If flow is observed the well will be shut in per standing orders (attached). The pumps will be shut down and the upper pipe rams closed. The kick will be handled through conventional well control equipment. This action can happen independent of MPD operations. The MPD annular will be in use and the well is being drilled on a choke so MPD may shut in to arrest flow prior to the well control equipment being activated. CAUTION: This email originated from outside the State of Alaska mail system. Do not CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Kick while making a connection: : If flow is observed the well will be shut in per standing orders (attached). The well can be shut in independently from MPD operations as back pressure is being applied above the well control equipment. The upper pipe rams can be shut in at will. Again, the MPD annular will be in use and the well is on a choke so MPD may shut in to arrest flow prior to the well control equipment being activated. Please reach out with any further questions. The intent of this revised plan was to ease the AOGCC’s concerns and make well control operations conventional. All the focus will be on holding back pressure on the well to stay in an overbalance state. This is very similar to CTD operations and a common MPD technique. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, June 19, 2024 5:19 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request The sundry application is not going to be approved. There’s insufficient information to support the waiver. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Wednesday, June 19, 2024 3:55 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request click links or open attachments unless you recognize the sender and know the content is safe. Bryan, What is the status of the A-20 Change to Approved program? sean From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Monday, June 17, 2024 3:30 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: McLellan, Bryan J (CED <bryan.mclellan@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Hello, Please expedite. Please see attached electronic distribution for NCIU A-20 (PTD #224-065). Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 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. 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. 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. From:McLellan, Bryan J (OGC) To:Sean Mclaughlin Cc:Rixse, Melvin G (OGC); Regg, James B (OGC) Subject:NCIU A-20 (PTD 224-065) and NCIU A-19 (PTD 224-026) Waiver request denied Date:Friday, June 14, 2024 4:54:00 PM Attachments:image001.jpg Sean, Hilcorp is planning to use the MPD system to maintain overbalance in the absence of kill weight fluid, and to circulate out small-volume influx using the MPD system at full drilling pump rate. Recognizing that there is industry precedent for this, and that the methods to safely control kicks are described in SPE papers 189995 and 170684, and others. These papers describe an Influx Management Envelope (IME) that is developed for each well to determine the size and intensity of the kick that can safely be circulated out of the well. Please let me know if there are other published papers describing alternative methods used by Hilcorp and Beyond to control influxes with MPD systems. The approved PTDs for both wells allow for MPD use with mud weight overbalanced to the highest anticipated reservoir pressure, which is compliant with 20 AAC 25.033. The permit to drill for NCIU A-20 conditionally approved the use of mud weight less than required to maintain overbalance, however: Condition 4c requires: “MPD Well Control scenario modeling to be submitted to AOGCC and MPD Operations Matrix to be agreed with AOGCC before drilling below surface casing shoe.” This condition has not been completed to AOGCC’s satisfaction and thus the drilling mud weight must be capable of maintaining overbalance to the open hole formations at all times without the assistance of applied surface pressure. The AOGCC believes that the MPD Operations Matrix is inadequate to ensure that procedures and practices are in place to warrant waiver approval under 20 AAC 25.033(j). Before using a mud weight incapable of maintaining overbalance to the formation pressures will be permitted, A 10-403 Sundry application for “change to approved permit” will be required, demonstrating that the alternative drilling fluid program meets the design criteria of 20 AAC 25.033(b) and the corresponding equipment and procedures are at least equally effective in preventing the loss of primary well control will be required. Here’s what AOGCC needs to consider the waiver request under 20 AAC 25.033(j) for wells NCIU A-20 (PTD 224-065) and NCIU A-19 (PTD 224-026). The sundry should include: 1. Identify which sections of 20 AAC 25.033 will not be followed and require a waiver. 2. The IME or some equivalent means of determining the safe volume vs. intensity of kick that can be circulated out with the MPD system. It should include limitations of the Mud-Gas separator gas handling capacity. 3. The choke pressure schedule while circulating out the kick. Describe how this will be determined rapidly after the influx is identified since it needs to be implemented immediately. 4. Procedures for maintaining overbalance while drilling, making connections and while tripping, including contingencies for sudden loss of pump pressure or failure of automatic choke. 5. The alternate Standing orders to the driller and rig crew, with clear instructions on how to respond to a kick and who has the authority and responsibility to decide when to shut the well in. 6. Explain the drills and training that will be done for the rig crew and when/how often they will take place. 7. Evidence that the drilling crew has received the training in these alternate well control response measures. 8. Equipment description and diagrams (similar to what was included in the PTD). Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________N COOK INLET UNIT A-20 JBR 07/24/2024 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:5" TJ used 23 Accumulator bottles average pre charge 1000psi. Single straight vent line below diverter bag. 29' from diverter tee and 15' passed substructure 77' from closest ignition source with wind monitoring. TEST DATA Rig Rep:D. Herbert/S. WilsonOperator:Hilcorp Alaska, LLC Operator Rep:S. Sunderland/B. Lafleur Contractor/Rig No.:Hilcorp 151 PTD#:2240650 DATE:6/6/2024 Well Class:DEV Inspection No:divKPS240606175405 Inspector Kam StJohn Inspector Insp Source Related Insp No: Test Time:1 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:NA 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:12.25 P Vent Line(s) Size:16 P Vent Line(s) Length:29 P Closest Ignition Source:77 P Outlet from Rig Substructure:15 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:23 P Knife Valve Open Time:6 P Diverter Misc:0 NA Systems Pressure:P3125 Pressure After Closure:P2150 200 psi Recharge Time:P10 Full Recharge Time:P95 Nitrogen Bottles (Number of):P16 Avg. Pressure:P2250 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: NA NAMud System Misc: 9 9 9 9 9 0HPRDWWDFKHGGHVFULELQJYHQWOLQHDQGZLQGPRQLWRULQJSURJUDP-5HJJ0HPRDWWDFKHGGHVFULELQJYHQWOLQHDQGZLQGPRQLWRULQJSURJUDP 2024-0606_Diverter_Hilcorp151_NCIU_A-20_ksj Page 1 of 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO:Jim Regg DATE:6/06/2024 P. I. Supervisor FROM:Kam StJohn SUBJECT:Diverter – Hilcorp 151 Petroleum Inspector NCIU A-20 Hilcorp Alaska LLC PTD 2240650 6/06/2024: I traveled out to Tyonek Platform for Hilcorp 151 diverter inspection; rig package has been skidded off the jackup and onto the platform, set over NCIU A-20. This report supplements the Diverter Test Report (Rpt # divKPS240606175405) and addresses the wind monitoring required as a condition of approval. I met with Hilcorp’s Platform Manger Sandy Reynolds and Rig Representative Sloan Sunderland to discuss the diverter vent line waiver (related to ignition sources). All Platform Operators and rig crew are aware of the possible close ignition sources – for this rig-up the closest ignition source (platform crane) is 77 feet from the vent line outlet. Wind direction monitoring is being watched at the Tyonek platform weather station. Wind direction is also continuously monitored in the platform’s control room. According to the Hilcorp representatives the prevailing wind is south by southeast. At a minimum every hour the rig floor is checking with the control room for wind directions, and the control room will let the rig know of any shift in wind direction. There is also an alarm tied into the control room that alerts if the rig goes on diverter, triggering a shutdown of the platform flare stack (approximately 200 feet from the vent line outlet). On the previous well (NCIU A-19) they did the same monitoring but did not log the wind directions. For NCIU A-20, wind direction will be documented in a log. I was told that drilling operations on NCIU A-19 were stopped at least once due to wind direction. Attachments:Diverter Vent Line Pictures (2) 9 9 9 9 9 9 9 jp Diverter Test Report , divKPS240606175405 Wind direction monitoring alarm James B. Regg Digitally signed by James B. Regg Date: 2024.07.24 10:24:04 -08'00' 2024-0606_Diverter_Hilcorp151_NCIU_A-20_ksj Page 2 of 2 Hilcorp Rig 151 Diverter Vent Line Photos NCIU A-20 (PTD 2240650) Photos by AOGCC Inspector K. StJohn 6/6/2024 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: North Cook Inlet, Tertiary System Gas Pool, NCIU A-20 Hilcorp Alaska, LLC Permit to Drill Number: 224-065 Surface Location: 1310' FNL, 1025' FWL, Sec 6, T11N, R9W, SM, AK Bottomhole Location: 784' FNL, 1968' FEL, Sec 12, T11N, R10W, SM, 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 day of June 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.04 15:42:50 -08'00' 4th 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 9,633' TVD: 6,727' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 126.6 15. Distance to Nearest Well Open Surface: x-332043 y-2581959 Zone-4 N/A to Same Pool:1526' to NCIU B-03A 16. Deviated wells:Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 64 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 4-1/2" 12.6# L-80 GBCD 4,276' 5,357' 3,361' 9,633' 6,727' Tieback 4-1/2" 12.6# L-80 Hyd 533 5,357' Surface Surface 5,357' 3,361' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 384' Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 6/22/2024 5583' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Tieback Assy. LengthCasing Cement Volume Driven 384' Drilling Manager Monty Myers Conductor/Structural 30"~384 Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate 5,557'Surface Surface 5,557'3,450' Effect. Depth MD (ft):Effect. Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1480 ft3 / T - 207 ft3 2758 343' FNL, 1682' FEL, Sec 12, T11N, R10W, SM, AK 784' FNL, 1968' FEL, Sec 12, T11N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1310' FNL, 1025' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 / ADL 37831 8328 18. Casing Program:Top - Setting Depth - BottomSpecifications 3431 12-1/4"9-5/8"47# L-80 DWC/C (including stage data) NCIU A-20 North Cook Inlet Unit Tertiary System Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 MDSize Plugs (measured): St 1 L - 1779 ft3 / T - 253 ft3 St 2 L - 1572 ft3 / T - 313 ft3 s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 05/16/24 Monty M Myers By Grace Christianson at 10:00 am, May 16, 2024 224-065 SFD 5/29/2024 SFD DSR-5/20/24 50-883-20196-00-00 2586670 BJM 6/3/24 See attached conditions of approval. *&:JLC 6/4/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.06.04 15:43:05 -08'00' 06/04/24 06/04/24 RBDMS JSB 060624 NCIU A-20 (PTD 224-065) Conditions of Approval 1. Initial BOP test to 5000 psi. Subsequent BOP tests to 3000 psi. All annular tests to 2500 psi. 2. Submit FIT/LOT data within 48 hrs of acquiring data. 3. A variance to 20 AAC 25.035(c)(2)(C)(i)&(ii) is approved with the following conditions a. Vent line is to be at least 50’ from any ignition source and extend at least 10’ from the rig substructure. b. Drilling of the surface hole section will not be allowed if the wind direction is from ESE direction +/- 20 deg, (between 92.5 – 132.5 degrees). If the wind direction moves into this window during drilling operations, drilling must cease until wind shifts to a more favorable direction. c. Include in the 10-407 time-stamped wind speed and direction data from the Tyonek platform weather station for the time period while diverter is rigged up. d. See attached process safety vapor cloud dispersion model and email chain from Sean McLaughlin. 4. Waiver to 20 AAC 25.033 for mud weight less than required to maintain overbalance approved, with the following conditions: a. Managed pressure drilling (MPD) system must be used to always maintain well in overbalance condition while drilling. b. Pressure-while-drilling (PWD) tools must be included in the drillstring when drilling to verify bottom hole pressure exceeds reservoir pressure. c. MPD Well Control scenario modeling to be submitted to AOGCC and MPD Operations Matrix to be agreed with AOGCC before drilling below surface casing shoe. A-20 Drilling Program Tyonek Sean McLaughlin PTD May 14, 2024 Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Planned Wellbore Schematic.............................................................................................................6 7. Drilling Summary...............................................................................................................................7 8. Mandatory Regulatory Compliance / Notifications.........................................................................8 9. R/U and Preparatory Work.............................................................................................................11 10. N/U 21-1/4” 2M Diverter..................................................................................................................12 11. Drill 12-1/4” Hole Section.................................................................................................................13 12. Run 9-5/8” Surface Casing...............................................................................................................15 13. Cement 9-5/8” Surface Casing.........................................................................................................18 14. ND/NU and Test casing ....................................................................................................................23 15. BOP N/U and Test.............................................................................................................................24 16. Drill 8-1/2” Hole Section...................................................................................................................25 17. Run 4-1/2” Production Liner...........................................................................................................26 18. Cement 4-1/2” Production Liner.....................................................................................................28 19. Wellbore Clean Up & Displacement...............................................................................................31 20. Run Completion Assembly...............................................................................................................31 21. BOP Schematic..................................................................................................................................33 22. Wellhead Schematic..........................................................................................................................34 23. Anticipated Drilling Hazards...........................................................................................................35 24. Jack up position ................................................................................................................................36 25. FIT Procedure...................................................................................................................................37 26. Choke Manifold Schematic..............................................................................................................38 27. Casing Design Information ..............................................................................................................40 28. 8-1/2” Hole Section MASP...............................................................................................................41 29. Plot (NAD 27) (Governmental Sections).........................................................................................42 30. Slot Diagram......................................................................................................................................43 Page 2 May 14, 2024 NCI A-20 Drilling Program APD 224-026 1. Well Summary Well NCI A-20 Drilling Rig Rig 151 Leg & Slot Leg 2 / Slot 5 Directional plan wp02 Pad & Old Well Designation NA - Grassroots Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing GL Comp Target Reservoir(s)Beluga A-U Kick off point NA Planned Well TD, MD / TVD 9633’ MD / 6727’ TVD PBTD, MD 9533’ MD AFE Number AFE Days AFE Drilling Amount Work String(s)5” 19.5# S135 NC50 RKB – AMSL 126.6’ MSL to ML 74.10’ Page 3 May 14, 2024 NCI A-20 Drilling Program APD 224-026 2. Management of Change Information Date: May 14, 2024 Subject: Changes to Approved Permit to Drill File #: NCI A-20 Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approval: Drilling Manager Date Prepared: Engineer Date Page 4 May 14, 2024 NCI A-20 Drilling Program APD 224-026 3. Tubular Program Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft)Grade Conn Burst (psi) Collap se (psi) Tension (k-lbs) Conductor (previously installed) 30”Assume 29”--Assume 158#X-56 Weld 1630 230 12-1/4”9.625”8.681”8.525”10.625”47 L-80 DWC/C 6870 4750 1086 8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288 ** Minimum of 100’ overlap required between casing strings 4. Drill Pipe Information Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k Page 5 May 14, 2024 NCI A-20 Drilling Program APD 224-026 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to mmyers@hilcorp.com, cdinger@hilcorp.com, sean.mclaughlin@hilcorp.com 3. EHS Incident Reporting x Notify EHS field coordinator. i. Garrett St. Clair: C: (907) 252-7780 x Spills: i. Adrian Kersten: C: 907-564-4820 ii. Monty Myers: O: 907-777-8431 C: 907-538-1168 iii. Sean Mclaughlin x Report ALL spills to the water within 15 minutes. x Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 May 14, 2024 NCI A-20 Drilling Program APD 224-026 6. Planned Wellbore Schematic Page 7 May 14, 2024 NCI A-20 Drilling Program APD 224-026 7. Drilling Summary A-20 is a 9633’ MD / 6727’ TVD development gas well drilled from leg 2 slot #5 off the Tyonek platform. The base plan is an infill wellbore to the Beluga U. The well will be completed with a 4-1/2” gas lift tie-back completion. Drilling operations is expected to commence approximately June 2024. General sequence of operations pertaining to this drilling operation: Rig Work 1. Rig 151 will MIRU over leg 2, slot 5 2. Rig 21-1/4” x 2M Diverter (Waiver requested) 3. MU 12-1/4” bit with 8” drilling tools (GR/RES) 4. Drill 12-1/4” hole to 5557’ MD. Run and cmt 9-5/8” casing (2 stages). 5. N/D riser and N/U casing head 6. Test casing to 3500 psi. Secure well with BPV and dryhole tree 7. N/U and test 13-5/8” x 5M BOP to 3000 psi, Rig up MPD equipment 8. MU 8-1/2” bit with 6-3/4” tools (Triple Combo LWD) 9. Mill shoe track with 20’ of new formation. 10. Perform FIT to 14.8 ppg EMW 11. Drill 8-1/2” production hole to 9633 MD, performing short trips as needed x MPD equipment to be used as primary well control barrier x NOV Agitator tool to be used to reduce stick slip if necessary 12. Swap well over to KWF. POOH w/ directional tools. 13. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 14. Perform Clean out run to polish bore, LDDP 15. Perform liner lap test to 2000 psi. 16. Run 4-1/2” gas lift completion. 17. Land hanger and test.MIT-T to 3000 psi, MIT-IA to 3000 psi 18. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Production Hole: Triple Combo LWD q) GR/RES p, gp Triple Combo LWD 2 stages Rig 151 Page 8 May 14, 2024 NCI A-20 Drilling Program APD 224-026 8. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that drilling and completion operations comply with the below AOGCC regulations. 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. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/5000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. o The highest reservoir pressure expected is 3431 psi in the Beluga U sand (6727' TVD). MASP is 2758 psi with 0.1psi/ft gas in the wellbore. x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed:3000 psi. x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: x 20 AAC 25.035(c)(2)(C)(i)&(ii) - Diverter variance request:Divert line will be less than 75’ from substructure and ignition source. Process Safety vapor cloud dispersion model conducted to access risk. Requirements for operation: o Vent line is to be at least 50’ from any ignition source AND extend at least 10’ from the rig substructure. o Drilling of surface hole will not be allowed if the wind direction is from ESE direction +/- 20 deg (blowing toward the ignition sources). If the wind direction moves into this window during drilling operations, drilling must cease until winds shift to a more favorable direction. Variance approved. Vapor cloud dispersion modeling attached. See conditions of approval -bjm Page 9 May 14, 2024 NCI A-20 Drilling Program APD 224-026 x 20 AAC 25.033 variance request:Managed Pressure Drilling equipment and technique will be used for primary well control in place of drilling mud while drilling the 8-1/2” production hole. Kill weight fluid will be used for primary well control during surface hole and running liner. Benefits of using MPD with hydrostatically underbalanced mud weight: o Ability to utilize lighter mud weight and compensate for ECD difference through SBP (Surface Back Pressure) to stay above PP/wellbore stability o Improve ROP and minimize differential sticking o Ability to increase or reduce EMW downhole by adjusting SBP, without going through the process of displacing to new mud weight. o More effective downhole pressure control when comes to high pressure or abnormal pressure regimes. o Coriolis flowmeter is able to measure small flowrates difference (up to +/- 0.10% of flow rate accuracy for liquid, technical specs sheet as per attached) thus able to identify influx or losses before it's picked up by the conventional PVT system. o Applying constant SBP can help to minimize ballooning and swabbing. o Holding SBP during connections help to minimize pressure cycling in the sensitive formation o With RCD and MPD Choke manifold in place, the drilling system is going to be closed loop all the time where MPD chokes will be opening and closing automatically depending on flowrates down the string to apply desired target SBP. o While ensuring SBP is applied constantly (except during the cases of losses), any flow is diverted away from the rig floor. Equipment and Generic Flow path: o Major Equipment includes: 1. MPD Choke Manifold Building (With MPD Choke Manifold) o MPD Control Console (inside MPD Choke Manifold Building) o Coriolis flowmeter spool (inside MPD Choke Manifold Building) 2. MPD Remote Control Panel 3. RCD Body 4. RCD Bearing assembly with sealing elements (installed into RCD Body) 5. Various piping (4” and 2”) and hoses (4” and 2”) 6. Isolation valves o A general flow path diagram is as follows. An actual flow path diagram will be created during rig up and prior to drilling with MPD. Variance conditionally approved, pending submission of MPD well control scenario modeling and agreement of MPD Operations Matrix threshold for Well Control response. See attached conditions of approval. -bjm Page 10 May 14, 2024 NCI A-20 Drilling Program APD 224-026 Contingency: o There will be sufficient weighting material on location to bring the drilling mud up to KWF weight. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4 x 21-1/4” x 2M Hydril MSP diverter Function Test Only 8-1/2” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer SL Double gate x Blind ram in bottom cavity x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 5M Choke Manifold x Standpipe, floor valves, etc Initial Test: 250/5000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Page 11 May 14, 2024 NCI A-20 Drilling Program APD 224-026 Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9. R/U and Preparatory Work 1. Mix WBM mud for 12-1/4” hole section. 2. Set test plug in wellhead prior to N/U riser to ensure nothing can fall into the wellbore if it is accidentally dropped. 3. Install 7” liners in mud pumps. Plan to pump at 1000 gpm to clean the 30” conductor. 7” liners will deliver 575 gpm @ 98% eff @ 3623 psi. Page 12 May 14, 2024 NCI A-20 Drilling Program APD 224-026 10. N/U 21-1/4” 2M Diverter 1. N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 21-1/4” x 2 M riser on 28” landing ring. x N/U 21-1/4” 2M diverter w/16” outlet. x Knife gate, 16” diverter line. x Diverter waiver request: o Vent line to extend 10’ beyond rig substructure. o Vent line to be 50’ from ignition sources o Drilling to cease if wind direction is toward the ignition sources. 2. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure.Annular element must close in less than 45 seconds. 3. Set wear bushing in wellhead. 4. Rig and Diverter Line Orientation on Tyonek Platform (Leg #2): Page 13 May 14, 2024 NCI A-20 Drilling Program APD 224-026 11. Drill 12-1/4” Hole Section 1. 12-1/4” hole mud program summary: x 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. We will start with a simple gel + FW spud mud at 9.2ppg. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:8.9 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 400’ – 5557’8.9 – 9.5 80-120 20 - 40 35 - 55 <10 8.5 – 9.5 System Formulation:Aquagel / FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL BARAZAN D+ PAC-L /DEXTRID LT BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROID 41 caustic soda ALDACIDE G 0.905 bbl 0.5 ppb 15 - 25 ppb as needed if required for <10 API FL 5 ppb total 5 ppb total 4.0 ppb as required for weight 8.8 – 9.2 ppg 0.1 ppb (8.5 –9.5pH) 0.1 ppb AQUAGEL and BARAZAN D+ should be used to maintain rheology. Begin system with a 55 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 - 20 ppb total) BARACARBs/BAROFIBRE/STEELSEALs should be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. Additions of CON DET PRE- MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high-clay content sections. Maintain the pH in the 8.5 – 9.5 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Mix a ~50 bbl LCM pill prior to drilling out of the conductor, to be available for immediate use if losses are seen drilling the Surface hole. The pill formulation will be the 50 ppb pill from the LCM tree. Mix the recommended LCM material in thinned back base mud. Page 14 May 14, 2024 NCI A-20 Drilling Program APD 224-026 Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Sweep Formulations: 20 barrels mud, add 1.0 ppb BARAZAN D. Additions of CON DET PREMIX are recommended when penetrating high-clay content sections to reduce the incidence of bit balling and shaker blinding. At TD, a Walnut “flag” (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout - to help calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. 2. MU 12-1/4” milltooth bit with 8” Drilling o Ensure BHA components have been inspected previously. o Drift and caliper all components before M/U. o Pump at 1000 gpm to clean the hole effectively. 3. TIH to top of fill in the 30” conductor. Fill was tagged at 331’ during prerig magnet run. 4. Displace hole to spud mud and begin drilling out cmt plug at 350’ to 400’. This plug will be approx. 50 – 100 ft thick. 5. Drill 12-1/4” hole section. x GR/RES only for surface hole. x Rationale for casing shoe depth is ~40’ TVD above CI sands and ~40’ TVD below disposal zone. Same surface casing plan as A-14, A-15, A-16 drilled by Conoco in 2009 and A-17 and A-18 drilled by Hilcorp in 2023. x Pump at 900 - 1000 gpm. 900 gpm equates to an annular velocity of 170 fpm in the openhole, and 27 fpm in the 30” casing which is poor for effective hole cleaning. Short trips and sweep will be required. Ensure shaker screens are set up to handle this flowrate. x Circulate hole clean and pump sweep before dropping rate to prevent fall back and sticking. Maximize drill string RPMs, Pump sweeps and 6rpm rheology (target 10) to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Pull wiper trips as often as necessary. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Take MWD surveys every stand drilled. GR/RES only for surface hole. Page 15 May 14, 2024 NCI A-20 Drilling Program APD 224-026 12. Run 9-5/8” Surface Casing 1. R/U and pull wear bushing. 2. R/U PESI (Volant) 9-5/8” casing running equipment x Ensure 9-5/8” NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Plan to rig up Volant CRT if available x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8-1/2” on the location prior to running. x Note that 47# drift is 8.525” 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. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” DWC, 1 Centralizer 10’ from bottom w/ stop ring 1 joint – 9-5/8” DWC, NO Centralizer 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” DWC, 1 Free floating centralizer 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle Page 16 May 14, 2024 NCI A-20 Drilling Program APD 224-026 x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 5. Float equipment and Stage tool equipment drawings: Page 17 May 14, 2024 NCI A-20 Drilling Program APD 224-026 6. Continue running 9-5/8” 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 5 joints below the ES Cementer 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. 7. Install the Halliburton Type H ES-II Stage tool so that it is positioned at ~600’ MD below the conductor. x Install free floating centralizers on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damage to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. Page 18 May 14, 2024 NCI A-20 Drilling Program APD 224-026 8. Continue running 9-5/8” 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: No centralizers in the conductor. 9. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. Slow in and out of slips. 11. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 13. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 14. After circulating, lower string and land hanger in wellhead again. Cement returns will be out the 2 x 4” side outlets. Ensure hose is in place to take returns and dump into the inlet over the side of the platform. 13. Cement 9-5/8” Surface Casing 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 Discuss how to handle cement returns at surface. x Determine which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount 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. Page 19 May 14, 2024 NCI A-20 Drilling Program APD 224-026 2. Document efficiency of all possible displacement pumps prior to cement job. 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. 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. 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs. -bjm Page 20 May 14, 2024 NCI A-20 Drilling Program APD 224-026 9. Attempt to reciprocate casing during first stage cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 11. Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 12. Land hanger. 13. Displacement calculation is in the Stage 1 Table above. 73 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±6 bbls before consulting with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 17. Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 18. Be prepared for cement returns to surface. Cement returns to be taken overboard. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 21 May 14, 2024 NCI A-20 Drilling Program APD 224-026 Second Stage Surface Cement Job: 19. Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 20. HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 21. Fill surface lines with water and pressure test. 22. 73 bbls of Spacer is already in the casing string. 23. Mix and pump cmt per below recipe for the 2nd stage. 24. Cement volume based on annular volume + 100% open hole excess. Job will consist of lead & tail, TOC brought to surface. However, cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Verified cement calcs. -bjm Page 22 May 14, 2024 NCI A-20 Drilling Program APD 224-026 Cement Slurry Design (2nd stage cement job): 25. Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 26. After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 27. Displacement volume is in the Stage 2 table above. 28. Monitor returns closely while displacing cement. Adjust pump rate if necessary. Cement return will be taken from 2 x 4” outlets and sent overboard. 29. Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. 30. Close 4” valves on wellhead side outlet and monitor pressure build up. 31. R/D cement equipment. Flush out wellhead with FW. 32. Back out and L/D landing joint. Flush out wellhead with FW. 33. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 34. Lay down landing joint and pack-off running tool. Ensure to report the following on wellview: 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 Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 23 May 14, 2024 NCI A-20 Drilling Program APD 224-026 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 sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 14. ND/NU and Test casing 1. N/D the Diverter 2. N/U 11” 5M multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi. 3. Test casing to 3500 psi. 30 min charted. 4. Mix 9.0 WBM mud for 8-1/2” hole section. 5. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. x Pump range for drilling will be 400-500 gpm. This can be achieved with one or both pumps. 6. 8-1/2” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated KWF in the event of a well control situation. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x MPD will be used to add pressure to the hydrostatic mud column to provide primary well control. Page 24 May 14, 2024 NCI A-20 Drilling Program APD 224-026 o PWD will be used to monitor the annular pressure and adjust surface pressure based on ECD. x KWF or a spike pill will be required when swapping out a BHA or running liner. System Type:LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 5557’- TD 8.8-10.1 40-53 6-15 13-24 8.5-9.5 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 – 4 ppb as needed 0.1 ppb 7. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 8. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. 15. BOP N/U and Test 1. N/U 13-5/8” x 5M BOP as follows (top down): x RCD for MPD (Beyond Energy) x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” 5M Shaffer Type SL Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” 5M Shaffer Type SL single ram. (2-7/8” X 5” VBR) Page 25 May 14, 2024 NCI A-20 Drilling Program APD 224-026 x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. x 11” 5M adapter required 2. Run BOPE test plug. 3. Test BOPE. x Test BOP to 250/5000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. o Initial test to 5000 psi if first well in the program, subsequent tests to 3000 psi. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! x Test VBRs on a 4-1/2” and 5” test joints (5000 psi initial test) x Test Annular on 4-1/2” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 4. Pull test plug. 16. Drill 8-1/2” Hole Section 1. M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 2. TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 3. TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 4. Drill out shoe track and 20’ of new formation. 5. CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 6. Conduct FIT to 14.8 ppg EMW. Chart test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 14.8 ppg with 9.8 ppg BHP and 9.2ppg mud equates to a 70 bbl KTV. x Send Results to AOGCC within 48 hrs. 7. POOH & LD Cleanout BHA 8. Drift & caliper all MWD components before M/U. Visually verify no debris inside components that cannot be drifted. 9. Ensure TF offset is measured accurately and entered correctly into the MWD software. 10. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-500 gpm. Page 26 May 14, 2024 NCI A-20 Drilling Program APD 224-026 11. P/U 8-1/2” PDC bit and 6-3/4” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES). 12. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the drop section of the wellbore. 13. TIH to window. Shallow test MWD on trip in. 14. Drill 8-1/2” hole to 9633’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust ECD with MPD as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. x Maintain API fluid loss < 6. x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole 15. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and swap well to KWF. KWF dependent on pressures observed while drilling. Flow check well for 10 minutes. 16. TOH with drilling assembly, handle BHA as appropriate. 17. Run 4-1/2” Production Liner 1. R/U Baker 4-1/2” liner running equipment. x Ensure 5” NC50 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified prior to running. x Be sure to count the total # of joints 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. Page 27 May 14, 2024 NCI A-20 Drilling Program APD 224-026 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer 10’ from the bottom with stop ring x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. No centralizer x Centralizers will be run on 4-1/2” liner every joint to 7300’ and every other joint above that. x Ensure proper operation of float shoe & FC. 4. Continue running 4-1/2” production liner to TD x Short joint run every 1000’, RA Tag 1000’ and 2000’ from bottom. x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 28 May 14, 2024 NCI A-20 Drilling Program APD 224-026 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 18. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 15 bbls 12.5 ppg spacer. Page 29 May 14, 2024 NCI A-20 Drilling Program APD 224-026 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. 6. Mix and pump cement per below recipe and volume below with xx lbs/bbl of loss circulation fiber. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to TOL. 7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs. Slurry Information: Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs. -bjm Page 30 May 14, 2024 NCI A-20 Drilling Program APD 224-026 8. Drop DP dart and displace with KWF. 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 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 10. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not overdisplace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 13. Bleed pressure to zero to check float equipment. 14. P/U, verify setting tool is released. 15. 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). 16. 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. 17. 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. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19. POOH, LDDP. Backup release from liner running tool: 20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. Page 31 May 14, 2024 NCI A-20 Drilling Program APD 224-026 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on Wellview: 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 liner 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 Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 19. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 3000 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 20. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly to above the liner top x Tubing will be 4-1/2” L-80 12.6# TBD x SSSV to be placed at 500’ x CIM to be placed at 2000’ Page 32 May 14, 2024 NCI A-20 Drilling Program APD 224-026 x GLM will be run (depths TBD) 2. Swap the well over to FIW x Circulate a hi-vis pill followed by a soap train per Baroid x Circulate FIW until clean-up is satisfactory. x Leave FIW in the annulus. 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 33 May 14, 2024 NCI A-20 Drilling Program APD 224-026 21. BOP Schematic Page 34 May 14, 2024 NCI A-20 Drilling Program APD 224-026 22. Wellhead Schematic Page 35 May 14, 2024 NCI A-20 Drilling Program APD 224-026 23. Anticipated Drilling Hazards Lost Circulation: Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and A-01A) x Maintain sufficient volumes while drill. x Maintain ability to take on FIW during drilling phase x If a LC event occurs pumping cement will be the likely remedy Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. Anti Collision: N/A Page 36 May 14, 2024 NCI A-20 Drilling Program APD 224-026 24. Jack up position Page 37 May 14, 2024 NCI A-20 Drilling Program APD 224-026 25. 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 plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 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. Page 38 May 14, 2024 NCI A-20 Drilling Program APD 224-026 26. Choke Manifold Schematic Page 39 May 14, 2024 NCI A-20 Drilling Program APD 224-026 Page 40 May 14, 2024 NCI A-20 Drilling Program APD 224-026 27. Casing Design Information Page 41 May 14, 2024 NCI A-20 Drilling Program APD 224-026 28. 8-1/2” Hole Section MASP Page 42 May 14, 2024 NCI A-20 Drilling Program APD 224-026 29. Plot (NAD 27) (Governmental Sections) Page 43 May 14, 2024 NCI A-20 Drilling Program APD 224-026 30. Slot Diagram A-20 6WDQGDUG3URSRVDO5HSRUW 0D\ 3ODQ1&,$ZS +LOFRUS$ODVND//& 1RUWK&RRN,QOHW 1RUWK&RRN,QOHW8QLW 3ODQ1&,8$6ORW 1&,$ -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500True Vertical Depth (1000 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 Vertical Section at 212.00° (1000 usft/in) NCI A-20 Tgt1 Base Beluga A NCI A-20 Tgt2 Beluga P 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 500 1 0 0 0 1 5 0 0 200025003000350040004500500055006000650070007 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 9 6 3 3 NCI A-20 wp02 Start Dir 2º/100' : 400' MD, 400'TVD Start Dir 3.5º/100' : 600' MD, 599.84'TVD End Dir : 2446.36' MD, 2086.51' TVD Start Dir 3º/100' : 6196.36' MD, 3730.4'TVD End Dir : 7996.36' MD, 5115.33' TVD Total Depth : 9633' MD, 6727.1' TVD Top Sterling X Top Beluga A Top Beluga I Top Beluga M Beluga T/U Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: NCIU A-20 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2586669.75 332043.70 61° 4' 35.7919 N 150° 56' 54.6151 W SURVEY PROGRAM Date: 2024-03-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 52.53 900.00 NCI A-20 wp02 (NCI A-20) 3_Gyro-CT_Drill pipe 900.00 5557.00 NCI A-20 wp02 (NCI A-20) 3_MWD+AX+Sag 5557.00 9633.00 NCI A-20 wp02 (NCI A-20) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3492.00 3365.37 5652.52 Top Sterling X 4470.00 4343.37 7304.14 Top Beluga A 5426.00 5299.37 8311.82 Top Beluga I 5824.00 5697.37 8715.96 Top Beluga M 6727.00 6600.37 9632.89 Beluga T/U REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: NCIU A-20 - Slot 2005, True North Vertical (TVD) Reference:Prelim @ 126.63usft Measured Depth Reference:Prelim @ 126.63usft Calculation Method:Minimum Curvature Project:North Cook Inlet Site:North Cook Inlet Unit Well:Plan: NCIU A-20 Wellbore:NCI A-20 Design:NCI A-20 wp02 CASING DETAILS TVD TVDSS MD Size Name 3450.13 3323.50 5557.00 9-5/8 9 5/8" x 12 1/4" 6727.10 6600.47 9633.00 4-1/2 4 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 52.53 0.00 0.00 52.53 0.00 0.00 0.00 0.00 0.00 2 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 400' MD, 400'TVD 3 600.00 4.00 115.00 599.84 -2.95 6.32 2.00 115.00 -0.85 Start Dir 3.5º/100' : 600' MD, 599.84'TVD 4 2446.36 64.00 213.00 2086.51 -813.90 -435.04 3.50 99.90 920.76 End Dir : 2446.36' MD, 2086.51' TVD 5 6196.36 64.00 213.00 3730.40 -3640.62 -2270.73 0.00 0.00 4290.72 Start Dir 3º/100' : 6196.36' MD, 3730.4'TVD 6 7996.36 10.00 213.00 5115.33 -4515.87 -2839.12 3.00 180.00 5334.18 End Dir : 7996.36' MD, 5115.33' TVD 7 9633.00 10.00 213.00 6727.10 -4754.22 -2993.91 0.00 0.00 5618.34 Total Depth : 9633' MD, 6727.1' TVD -4950 -4675 -4400 -4125 -3850 -3575 -3300 -3025 -2750 -2475 -2200 -1925 -1650 -1375 -1100 -825 -550 -275 0 275 South(-)/North(+) (550 usft/in)-3300 -3025 -2750 -2475 -2200 -1925 -1650 -1375 -1100 -825 -550 -275 0 275 West(-)/East(+) (550 usft/in) NCI A-20 Tgt2 Beluga P NCI A-20 Tgt1 Base Beluga A 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 250500750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 50005250550057506000625065006727 N CI A-20 wp02 Start Dir 2º/100' : 400' MD, 400'TVD Start Dir 3.5º/100' : 600' MD, 599.84'TVD End Dir : 2446.36' MD, 2086.51' TVD Start Dir 3º/100' : 6196.36' MD, 3730.4'TVD End Dir : 7996.36' MD, 5115.33' TVD Total Depth : 9633' MD, 6727.1' TVD CASING DETAILS TVD TVDSS MD Size Name 3450.13 3323.50 5557.00 9-5/8 9 5/8" x 12 1/4" 6727.10 6600.47 9633.00 4-1/2 4 1/2" x 8 1/2" Project: North Cook Inlet Site: North Cook Inlet Unit Well: Plan: NCIU A-20 Wellbore: NCI A-20 Plan: NCI A-20 wp02 WELL DETAILS: Plan: NCIU A-20 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2586669.75 332043.70 61° 4' 35.7919 N 150° 56' 54.6151 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: NCIU A-20 - Slot 2005, True North Vertical (TVD) Reference:Prelim @ 126.63usft Measured Depth Reference:Prelim @ 126.63usft Calculation Method:Minimum Curvature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0.000.751.502.253.00Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)NCIU A-10BA-10NCIU A-16NCIU A-15NCIU A-19 wp02A-11NCI A-11ANCIU A-09ANCIU A-09PB1A-09No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS: Plan: NCIU A-20 NAD 1927 (NADCON CONUS) Alaska Zone 04Water Depth: 101.00+N/-S+E/-W NorthingEastingLatitudeLongitude0.000.002586669.75 332043.70 61° 4' 35.7919 N150° 56' 54.6151 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-20 - Slot 2005, True NorthVertical (TVD) Reference:Prelim @ 126.63usftMeasured Depth Reference:Prelim @ 126.63usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name3450.13 3323.50 5557.00 9-5/8 9 5/8" x 12 1/4"6727.10 6600.47 9633.00 4-1/2 4 1/2" x 8 1/2"SURVEY PROGRAMDate: 2024-03-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool52.53 900.00 NCI A-20 wp02 (NCI A-20) 3_Gyro-CT_Drill pipe900.00 5557.00 NCI A-20 wp02 (NCI A-20) 3_MWD+AX+Sag5557.00 9633.00 NCI A-20 wp02 (NCI A-20) 3_MWD+AX+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)NCIU A-18 PB1NCIU A-18 PB1NCIU A-18 PB1NCIU A-18 PB1NCIU A-18NCIU A-18NCIU A-18NCIU A-18A-08NCIU A-10BA-10AA-10NCIU B-04 wp01NCI A-03AA-03A-05NCIU A-14NCIU A-16NCIU A-16NCIU A-15NCI A-21 wp01NCI A-21 wp01B-02SUNFISH 3A-12NCI A-12ANCI A-12BNCI A-12BNCIU A-19 wp02NCIU A-19 wp02NCI A-01AA-01A-11NCI A-11AA-06A-06B-01AB-01A-02A-07NCIU A-09ANCIU A-09ANCIU A-09PB1NCIU A-09PB1A-09A-09NCIU B-03AB-03A-04NCI A-04ANCI A-17NCI A-17NCI A-17 PB1NCIU A-13GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference52.53 To 9633.00Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-20Wellbore: NCI A-20Plan: NCI A-20 wp02Ladder/S.F. Plots WELL DETAILS: Plan: NCIU A-20 NAD 1927 (NADCON CONUS) Alaska Zone 04Water Depth: 101.00+N/-S +E/-W NorthingEastingLatitudeLongitude0.000.002586669.75 332043.70 61° 4' 35.7919 N 150° 56' 54.6151 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-20 - Slot 2005, True NorthVertical (TVD) Reference:Prelim @ 126.63usftMeasured Depth Reference:Prelim @ 126.63usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name3450.13 3323.50 5557.00 9-5/8 9 5/8" x 12 1/4"6727.10 6600.47 9633.00 4-1/2 4 1/2" x 8 1/2"SURVEY PROGRAMDate: 2024-03-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool52.53 900.00 NCI A-20 wp02 (NCI A-20) 3_Gyro-CT_Drill pipe900.00 5557.00 NCI A-20 wp02 (NCI A-20) 3_MWD+AX+Sag5557.00 9633.00 NCI A-20 wp02 (NCI A-20) 3_MWD+AX+Sag0.0010.0020.0030.0040.0050.0060.0070.0080.0090.00100.00Centre to Centre Separation (20.00 usft/in)75 150 225 300 375 450 525 600 675 750 825 900 975 1050 1125 1200 1275 1350 1425 1500Measured Depth (150 usft/in)NCIU A-18 PB1NCIU A-18 PB1NCIU A-18NCIU A-18A-08A-08NCIU A-10BA-10ANCIU B-04 wp01NCI A-03ANCI A-03AA-03A-03A-05A-05NCIU A-14NCIU A-16NCIU A-16NCIU A-15NCI A-21 wp01NCI A-21 wp01A-12NCI A-12BNCI A-12BNCIU A-19 wp02NCIU A-19 wp02NCI A-01AA-01A-11NCI A-11AA-06A-06B-01AA-02A-02A-07NCIU A-09AA-09A-04A-04NCI A-04ANCI A-04ANCI A-17Equivalent Magnetic DistanceGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference52.53 To 9633.00Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-20Wellbore: NCI A-20Plan: NCI A-20 wp02Ladder/S.F. Plots 1Diverter Release Lower Flammable Limit (LFL) Model • Plume depicts max expected UFL (red), LFL (green) and 50% LFL (blue) of release to expected SE from SE oriented diverter at 10 mmscfd. • Affected radii's show plume’s extent regardless of release direction Top View 2Dispersion Plume Geometry (50% LFL)Potential Ignition Source(Heater Exhaust)Potential Ignition Source(Generator Exhaust)• Conservative model, assumes both a release and wind direction towards NW ignition sources• Shows extent of LFL modeled at 50% LFL (.025 by volume for methane) in blue, LFL in green and UFL in red 3Dispersion Plume Geometry (20% LFL)• Assumes both wind and release in same direction• Shows extent of observable LFL as shown by a 20% LFL (a typical alarm threshold) in blue, 50% LFL in green, LFL in red and UFL in purple 4Key Points-Assumptions:-10 MMSCFD conservative steady-state release rate from 16” diverter-11 mph (5 m/s) wind aided release in stable atmosphere-Primarily methane gas composition-Consider multiple release & wind directions but expected release is to SE (diverter orientation)-Results/Conclusions:-100% LEL Boundary ~50 ft (Closest ignition source ~55 ft, 29 ft below release point)-The gas is buoyant in atmosphere and models demonstrate minimal sinking of gas to elevations lower than release point. Elevation of release point being higher than the ignition sources is a key mitigating factor.-Wind is typically from NE or SW. Ignition sources are NW of release point. -Wind direction and atmosphere stability affect plume geometry but diverter/release direction is the primary driver.-Typical wind conditions reduce risk of gas reaching ignition sources to the NW.-No scenario identified where LEL boundary reaches an ignition source-Recommend to monitor wind direction during activity and re-assess if wind shifts from SE CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Cc:Regg, James B (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL] NCIU A-19 Diverter Waiver Date:Wednesday, May 1, 2024 3:40:05 PM Bryan, The PSE has finished up with the modeling. When would you be free to review over Teams with the PSE? Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, April 26, 2024 11:30 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Sandy Reynolds <sreynolds@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean and Sandy, Thanks for discussing the issues with the diverter vent-line location relative to the ignition sources on the platform. Significant shallow gas has been encountered within the planned surface hole interval on at least one well drilled from the Tyonek platform. The starting point for any variance or waiver needs to acknowledge that shallow gas is present, and there is potential for the diverter to be used to divert gas away from the rig and platform. The risk reduction measures need to assume that there could be a significant quantity of gas discharging uncontrollably from the diverter vent line. If it is impossible to comply with the regulations that require 75’ between ignition source and diverter vent-line discharge per 20 AAC 25.035(c), I suggest a detailed analysis of the situation be performed by a process safety professional, with recommendations for risk reduction measures. I’m not sure what they might come up with, but things like a vapor-cloud dispersion model, location of gas detectors and protocols for shutting down the platform before a vapor cloud reaches the ignition sources are a few relevant examples. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, April 23, 2024 1:18 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Sandy Reynolds <sreynolds@hilcorp.com> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, 2pm tomorrow would work for the Sandy, the Platform Supervisor. Last year there was an open deck on leg two and we were able to extend the divert line to the States satisfaction. We had large area in which to perform work and the space is needed when working with 16” lines. With the rig being on leg two the cellar opening is such that only one stick of 16” diverter can be pointed out. A flange will not fit through the opening. The limitation is to avoid hanging people from a temporary manrider winch and using the platform crane to make up a flange 100’ above the water. In addition, the pipe extension would be unsupported. Assurances 50’ is sufficient: A good deal of work has been performed on the risk assessment and shallow hazard assessment. There is a low probability that a vapor cloud emanating from the vent line would occur, this is not an exploration well. There needs to be a source. Wind direction plays a significant part when drilling with a single diverter. Drilling will not occur if the wind direction will carry gas to an ignition source. There is more often wind than not. The ignition source was analyzed and discussed last year. The generators are in the bowels of the platform and the exhaust is run outside. The exhaust temperature is about 50% of methane auto ignition temperature. The rig is a significant baffle and tortuous path for gas to move in a straight line distance to the source. Dispersion or deflection would occur. Methane is lighter than air and the diverter is located about 15’ above the ignition source. Any methane is expected to remain above the ignition source. While drilling, a facility operator is present in the control room and can ESD the platform if required. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 23, 2024 12:07 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, Thanks for offering to set up a meeting with the platform supervisor and facility engineer. I’m free after 2:00 pm tomorrow or Thursday or Friday before 1:00 pm. A couple of points for discussion: 1. What was the solution last year to getting the diverter outlet >75’ from the ignition sources? Why won’t that work this year? 2. What assurance can Hilcorp provide that 50’ is far enough between the diverter ventline outlet and ignition source to prevent ignition of a vapor cloud emanating from the ventline during a blowout? Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 22, 2024 4:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. The vent line will extend about 10’ beyond the rig and platform. The rig will be at the edge of the platform and there is no egress around the rig. This is about the same point in space as it was last year. The diverter will be pointed out the back of the rig (South) and egress is out for the front (North). Please keep in mind that the rig has been skidded off its traditional substructure. The jack up is more than 100’ away and contains, the mud pits, pumps, fluids shack, power generation, and most of the people. The process safety equation is substantially different than a conventional rig up. I’d be happy to set up a meeting with Facility Engineer, Mark McKinley or Platform Supervisor, Sandy Reynolds to discuss. Two grass roots wells were drilled on diverter last year with a similar diverter location. Last year we kept close approach wells flowing. Because of the variance request we decided to shut in the close approach well, A-15. The proposed configuration has prompted no changes to the platform response for a divert event. Hilcorp has not conducted a HAZOP. We believe there is no shallow hazard. As such, I’m not sure there is a node to start a Hazop from. We conducted a risk conversation and that turned into the shallow hazard analysis that was submitted to the AOGCC. The result of the risk assessment was the original diverter variance request. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 22, 2024 9:47 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, We are evaluating the variance requests. A few questions 1. How far beyond the rig substructure are you planning to place the vent-line discharge and how far beyond the platform structure? 2. Does Hilcorp have an OIM and process safety engineer that can meet with us to discuss options for complying and risks of non-compliance? 3. Has Hilcorp performed a HAZOP to evaluate the risks? Thank you Bryan McLellan 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. Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, April 19, 2024 11:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, Thank you for the information ahead of the PTD so we can plan a different route. Please consider the following two variance requests for A-19: 1. 20 AAC 25.035 (c)(2)(C) the vent line must extend to a point at least 75 feet (i) away from a potential source of ignition a. Hilcorp proposes 50 foot between the generator exhaust and the vent line. The exhaust points west between legs 1 and 2 and the vent line points south. The rig is between the vent line and exhaust. A schematic is attached. b. Please also consider information supplied in the original diverter waiver request. Drilling experience shows there is not an intensity kick potential. Swabbing in surface hole is unlikely and drilling experience supports that. The are no reports of lost circulation. Drilling experience shows that surface hole flow is not likely or expected. 2. 20 AAC 25.035 (c)(2)(C) (ii) the vent line must extend to a point at least 75 feet beyond the drill rig substructure, or to a point within the reserve pit and at least 50 feet beyond the drill rig substructure; a. Please note that because we are drilling from a platform, we are unable to meet the requirement. While drilling on diverter the vent line will extend beyond the rig substructure and the platform structure. The rule was previously waived on Tyonek in 2009 during the drilling of A-14, A-15, and A-16. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. For reference, the threshold for a variance is drilling experience in the near vicinity: (h) Upon request of the operator, the commission will, in its discretion, approve a variance (1) from the BOPE requirements in (e) of this section if the variance provides at least an equally effective means of well control; and (2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter system is not necessary. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, April 18, 2024 3:54 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, The diverter waiver request for this well will not be approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. 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. 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. 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. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-065 NCIU A-20 North Cook Inlet Unit Tertiary System Gas WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-20Initial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240650NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes Surf Loc & TD lie in ADL0017589; Top Productive Interval lies in ADL0017589;2 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY GAS - 564570 - governed by 68A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNo Waiver approved to allow <75' between ventline discharge and ignition source.27 If diverter required, does it meet regulationsYes Drilling mud waiver conditionally approved with MPD system to maintain overbalance. See COAs.28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2758 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes Yes. Normal pressure gradient expected to at least Beluga M sands at 8715' MD. Pressure36 Data presented on potential overpressure zonesNA expected to increase to 9.8 ppg EMW from there to TD. Operator's mud program and Managed37 Seismic analysis of shallow gas zonesNA Pressure Drilling technique appear sufficient to mitigate anticipated pressures. LCM38 Seabed condition survey (if off-shore)NA supplies will be available onsite.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/29/2024ApprBJMDate6/3/2024ApprSFDDate5/29/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 6/4/2024