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HomeMy WebLinkAbout224-098CAUTION: 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:Chad Helgeson To:McLellan, Bryan J (OGC); Davies, Stephen F (OGC) Cc:Donna Ambruz; Trevor Willms - (C) Subject:BRU 221-26 (PTD# 224-098) Sundry # 326-051 Perf adjustments Date:Tuesday, February 3, 2026 3:59:26 PM Attachments:BRU 221-26 PROPOSED (corrected) - 2-3-26.pdf Bryan/Steve, We were reviewing the sundry we submitted and was approved last week for BRU 221-26 (PTD# 224- 098) perf adds and found an error in our perf depths we submitted. Somehow our depths for the shallower D Perfs were correct, but our E Perfs somehow were not the correct depths. Attached is a schematic with the correct perfs and the table below. LABEL SAND MD TOP MD BASE TVD TOP TVD BASE FOOTAGE BRU 221-26 TOP POOL 2,989 2,896 Beluga D1 3,814 3,832 3,716 3,734 18 Beluga D4 3,888 3,894 3,790 3,796 6 Beluga D5 3,919 3,923 3,820 3,824 4 Beluga E1 4,023 4,029 3,924 3,930 6 Beluga E1 4,054 4,059 3,954 3,959 5 Beluga E5 4,204 4,216 4,103 4,115 12 Beluga E5 4,221 4,229 4,120 4,128 8 Beluga E5 4,244 4,252 4,143 4,151 8 Beluga E6 4,303 4,314 4,202 4,213 11 These do not change any maximum potential surface pressures. Please let us know if we have approval to perforate these new depths, or if you need a change of program. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual orentity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that anydissemination, 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 bythe company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Updated by CAH 02-03-26 PROPOSED (revised) Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PBTD = 6,896’ / TVD = 6,780’ TD = 6,961’ / TVD = 6,845’ RKB to GL = 20.3’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 7-5/8"Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875”Surf 2,759’ 3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,558’6,958’ 3-1/2"Prod Tieback 9.3 L-80 Hyd 563 2.992”Surf 2,568’ 3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,558’4.875”6.540”5-1/2” HRD-E ZXP Liner top packer & Flex lock hanger w/ 3-1/2” XO 3 2,558’4.790”6.340”Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8"166 bbls (382 sx) of 12 ppg lead followed by 36 bbls (174 sx) of 15.8 ppg tail, w/76 bbls of returns to surface 8/26/24. No losses on job. 3-1/2” 177 bbls (415 sx) of 12 ppg Type I lead followed by 27 bbls (122sx) of 15.3 ppg tail in 6.75” hole. 45 bbls of Cement/contaminated returned 9/5/24. 10bbls lost during job. TOC per CBL run on 9/10/24 is 2,754’. 6-3/4” hole 2 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Top of Pool per CO 802A & BLM PA: ~2,989’ MD/2,896’ TVD Bel D1 ±3,814’±3,832’±3,716’±3,734’±18’TBD Proposed Bel D4 ±3,888’±3,894’±3,790’±3,796’±6’TBD Proposed Bel D5 ±3,919’±3,923’±3,820’±3,824’±4’TBD Proposed Bel E1 ±4,023’±4,029’±3,924’±3,930’±6’TBD Adjusted Bel E1 ±4,054’±4,059’±3,954’±3,959’±5’TBD Adjusted Bel E5 ±4,204’±4,216’±4,103’±4,115’±12’TBD Adjusted Bel E5 ±4,221’±4,229’±4,120’±4,128’±8’TBD Adjusted Bel E5 ±4,244‘±4,252’±4,143’±4,151’±8’TBD Adjusted Bel E6 ±4,303‘±4,314’±4,202’±4,213’±11’TBD Adjusted Bel F 4,369’4,381’4,268’4,280’12’10/29/24 Open Bel F4 4,434’4,450’4,332’4,348’16’10/29/24 Open Bel F4 4,468’4,471’4,366’4,369’3’10/29/24 Open Bel F4 4,481’4,487’4,379’4,385’6’10/28/24 Open Bel F5 4,504’4,516’4,402’4,414’12’10/28/24 Open Bel F6 4,545’4,550’4,443’4,448’5’10/28/24 Open Bel F6 4,565’4,570’4,463’4,468’5’10/28/24 Open Bel F6 4,579’4,589’4,477’4,487’10’10/28/24 Open Bel F7 4,659’4,669’4,556’4,566’10’10/28/24 Open Bel F7 4,699’4,710’4,596’4,607’11’10/28/24 Open Bel F7 4,729’4,734’4,626’4,631’5’10/27/24 Open Bel F10 4,773’4,785’4,669’4,681’12’10/27/24 Open Bel F10 4,789’4,801’4,685’4,697’12’10/27/24 Open Bel F10 4,821’4,825’4,717’4,721’4’10/26/24 Open Bel G1 4,881’4,884’4,776’4,779’3’10/26/24 Open Bel G2 4,908’4,912’4,803’4,807’4’10/26/24 Open Bel G3 4,919’4,924’4,814’4,819’5’10/26/24 Open Bel G3 4,934’4,940’4,829’4,835’6’10/26/24 Open Bel G3 4,944’4,949’4,839’4,844’5’10/26/24 Open Bel G3 4,961’4,966’4,856’5,861’5’10/26/24 Open Bel G5 5,007’5,027’4,902’4,922’20’10/26/24 Open Bel G6 5,044’5,048’4,939’4,943’4’10/25/24 Open Bel G8 5,081’5,086’4,976’4,981’5’10/25/24 Open Bel G8 5,093’5,101’4,988’4,996’8’10/25/24 Open Bel G9 5,110’5,120’5,005’5,015’10’10/25/24 Open Bel G10 5,143’5,157’5,037’5,051’14’10/25/24 Open Perforations continued on Page 2 NOTES Short Joints w/ RA Tags (~15ft)3,342’, 3,848’, 4360’, 4864’, 5367’, 5879’, 6389’ RA 5,879’ RA 6,389’ RA 3,848’ RA 3,342’ RA 5,357’ RA 4,360’ RA 4,864’ Updated by CAH 02-03-26 PROPOSED (revised) Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PERFORATION DETAIL Continued form Page 1 Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel H 5,194’ 5,205’ 5,088’ 5,099’ 11’ 10/25/24 Open Bel H 5,217’ 5,222’ 5,111’ 5,116’ 5’ 10/24/24 Open Bel H1 5,225’ 5,230’ 5,119’ 5,124’ 5’ 10/24/24 Open Bel H2 5,267’ 5,273’ 5,160’ 5,166’ 6’ 10/24/24 Open Bel H2 5,288’ 5,294’ 5,181’ 5,187’ 6’ 10/24/24 Open Bel H2 5,301’ 5,307’ 5,194’ 5,200’ 6’ 10/24/24 Open Bel H4 5,366’ 5,371’ 5,260’ 5,265’ 5’ 10/24/24 Open Bel H7 5,466’ 5,486’ 5,358’ 5,378’ 20’ 10/20/24 Open Bel H9 5,526’ 5,530’ 5,418’ 5,422’ 4’ 10/20/24 Open Bel H9 5,555’ 5,566’ 5,447’ 5,458’ 11’ 10/20/24 Open CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Chad Helgeson To:McLellan, Bryan J (OGC) Cc:Donna Ambruz Subject:RE: [EXTERNAL] BRU 221-26 (PTD 224-098) CBL Date:Friday, September 27, 2024 6:12:35 AM Attachments:Reporting - Daily Completion and Workover - KEU KU 12-17 - 2024-09-26 05.17.41.pdf Bryan, I finally got this back from AK Eline and our open hole logs came back so were able to confirm it is on depth. AK Eline reworked the CBL, and their mistake was in how much of the free pipe log actually made it into the print. Attached is the reworked log. Looks like there is cement under the liner, but good cement below the surface casing. Chad From: McLellan, Bryan J (OGC) bryan.mclellan@alaska.gov Sent: Thursday, September 26, 2024 8:51 AM To: Chad Helgeson Subject: RE: [EXTERNAL] BRU 221-26 (PTD 224-098) CBL Chad, FYI, I’m holding this sundry for your response about the CBL. No hurry on my end, just letting you know in case you are wondering where the sundry is. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, September 19, 2024 11:42 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] BRU 221-26 (PTD 224-098) CBL Let me dig into it. I figured they labeled the free pipe pass incorrect and wasn’t the final log yet, but I agree the free pipe pass should not be below the liner top packer, which is why I thought it was mislabeled. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, September 19, 2024 10:30 AM CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] BRU 221-26 (PTD 224-098) CBL Chad, Why did Alaska Eline do the free pipe pass below the liner top if there is possible cement there? Wouldn’t it make sense to do it above the liner top where they know there’s no cement present? Seems like they could benefit from some additional training. I recently received an AK Eline CBL on a different Hilcorp well where they did their free pipe pass in gas, then claimed TOC was at the bottom gas lift mandrel because they saw the shift from gas to water in the annulus and claimed it was cement. Seems like a similar calibration error here. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, September 19, 2024 10:03 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] BRU 221-26 (PTD 224-098) CBL Attached is the uncorrected log. We are having some discrepancies with our open hole gamma ray near the sterling sands. The issue is 2-3ft difference which is important for us to resolve before we start to perforate anything. However this depth is not critical for the CBL. The official CBL we submit later will be corrected and may have different depths (+/- 2-3ft) I am calling the TOC at 2754 or at approximately the bottom of the 7-5/8” surface casing, however I do think there is some cement in the liner lap. Either way the TOC is above the top of the pool at 3251MD and 3160 TVD. Let me know if you need anything else. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, September 19, 2024 9:45 AM To: Chad Helgeson <chelgeson@hilcorp.com> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Subject: [EXTERNAL] BRU 221-26 (PTD 224-098) CBL Chad, Could you send me the CBL for this well? 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. 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Page 1/2 Well Name: KEU KU 12-17 Report Printed: 9/26/2024 www.peloton.com Daily Completion and Workover API / UWI 50-133-20577-00-00 Surface Legal Location Field Name Kenai Gas Field License No. State/Province ALASKA Well Configuration Type Original KB/RT Elevation (ft) 0.00 RKB to GL (ft) 0.00 Original Spud Date Rig Release Date PBTD (All) Total Depth All (TVD) Report # 7, Report Date: 9/25/2024 Job Name 242-01601 KU 12-17 RWO 2024 Job Category Capital Workover Primary Job Type AFE Number 242-01601 Objective Contractor Rig Name/# AFE Number 242-01601 Total Job AFE + Sup Amount (Cost) 754,454.00 Daily Job Total (Cost) 62,100.00 Cumulative (Cost) 326,106.03 Daily Readings General Conditions Temperature (°F) Road Condition Rig Time (hr) Responsible Daily Contacts Supervisor Title Mobile Daily Fluids Summary Fluid To well (bbl) From well (bbl) To lease (bbl) From lease (bbl) Daily Summary Last 24hr Summary IFO, PJSM, Perform diagnosis on wellbore fluid changes, Pump bottoms up while monitoring psi & taking fluid wts (8.9 ppg to 10.6 ppg), Continue milling while reversing F/4657-T/4666, Circulate Bottoms up & check MW (IA-10.2 ppg, TBG 10.4 ppg, Continue Milling F/4666-T/4666, Circulate bottoms to equilize TBG & IA Mud weights, Continue milling F/4666-T4673, Surge tubing by swapping from reverse to conventional circulation to clear tubing obstruction, Circulate bottoms up in intervals of 500 stks & flow check @ 2000 total stks wellbore balanced, Rack back swivel & trip out of the hole, Spot in & rig up YJ Eline, Perform caliper runF/4550-T/0, Rig down and release YJ Eline, Pressure test BOPE. Job Time Log Start Time End Time Dur (hr) Phase Op Code Operation 06:00 08:00 2.00 RPCOMP PJSM, Diagnosis well bore dynamics, Pressure on IA 45 psi after bleeding off from 60 psi, IA on vaccum, Decsion made to circulate hole. Pump 10 bbls with partial returns, Shut down pumps, and monitor flow IA flowing, Kick in pumps & pump another 20 bbls (full returns @ 6 bbls away), 8.9 ppg out, 9.9 ppg in, Continue circulating and checking mud every 500 stks, 500-9.5, 1000-9.6, 1500-9.9, 2000-10.3, 2500-10.6, 3000-10.8, 3500-10.3, 4000-9.5, 4200-9.2+, Decsion made to continue milling. 08:00 10:00 2.00 RPCOMP Ream down while reversing F/4657-T/4666 250 psi @ 1.8 BPM TQ: 4200 10:00 11:00 1.00 RPCOMP Circulate bottoms up checking mud wts: IA-10.2 ppg, TBG-10.4 ppg 11:00 12:00 1.00 RPCOMP Ream down while reversing F/4666-T/4666 250 psi @ 1.8 BPM TQ: 4200 Pump pressure came up to 700psi & started losing returns. Surge string swapping hoses from reverse to conventional circulation. 12:00 13:30 1.50 RPCOMP Circulate bottoms up to clear utube from wellbore, make connection jt 144 13:30 18:00 4.50 RPCOMP Ream down while reversing F/4666-T/4673 270 psi @ 1.3 BPM TQ: 3000 18:00 19:00 1.00 RPCOMP CIrculate in 500 stk intervals to find wellbore balance, Circulated 2000 stks and IA flowed 3.5 bbls back to pits, TBG -static. 19:00 20:30 1.50 RPCOMP Lay down 1 joint & rack back swivel in derrick. Prep floor to trip out of hole. 20:30 00:30 4.00 RPCOMP Trip out of hole to BHA 71 stds, Rack back 6 dc & break down BHA. (displacement 20.9, calculated 21) 00:30 05:00 4.50 RPCOMP Spot in & rig up YJ Eline, Surface calibrate 56 arm caliper. Run in hole to 4550' & log up F/ 4550'-T/0, Rig down YJ tools & equipment. 05:00 06:00 1.00 RPCOMP Pick up & make up test joint and plug on 3-1/2" tubing. 250-low, 3000-high. Daily Pressures Date Pressure Type Pressure (psi) Gas Emissions Date EmissionType Method Measured Duration (min) Completion/Zone P Cas (psi) P Tub (psi) Emissions Data Safety Meetings / Operational Checks Time Des Type Com Page 2/2 Well Name: KEU KU 12-17 Report Printed: 9/26/2024 www.peloton.com Daily Completion and Workover API / UWI 50-133-20577-00-00 Surface Legal Location Field Name Kenai Gas Field License No. State/Province ALASKA Well Configuration Type Original KB/RT Elevation (ft) 0.00 RKB to GL (ft) 0.00 Original Spud Date Rig Release Date PBTD (All) Total Depth All (TVD) Report # 7, Report Date: 9/25/2024 Logs Time Type Top (ftKB) Btm (ftKB) Cased? Perforations Time Top (ftKB) Btm (ftKB) Current Status Linked Zone Stim/Frac Stage Interval Number Type Top (ftKB) Btm (ftKB) Comment Stim/Treat Company Tubing Run Run Time Tubing Description Set Depth (ftKB) String Max Nominal OD (in) Weight/Length (lb/ft) String Grade Tubing Pulled Pull Time Tubing Description Set Depth (ftKB) String Max Nominal OD (in) Weight/Length (lb/ft) String Grade Other in Hole Run (Bridge Plugs, etc) Run Time Des OD (in) Top (ftKB) Btm (ftKB) Other in Hole Pulled (Bridge Plugs, etc) Pull Time Des Top (ftKB) Btm (ftKB) OD (in) Cement Start Time Des Type Cemented String Cement Comp 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): 6,961' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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: 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 chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 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 Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 21127 224-098 50-283-20201-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 2,568' 10,160psi 2,668' Size 120' 2,772' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,759' February 5, 2026 Tieback 3-1./2" 6,958' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 221-26CO 802A Same 6,842'3-1/2" ~2128psi 4,400' N/A Length LTP; N/A 2,558' MD/2,469' TVD; N/A 6,845' 6,896' 6,780' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.01.23 16:20:44 - 09'00' Noel Nocas (4361) 326-051 By Grace Chistianson at 8:07 am, Jan 26, 2026 10-404 BJM 1/29/26 DSR-1/27/26SFD 1/26/2026 Perforate JLC 1/30/2026 01/30/26 Well Prognosis Well Name: BRU 221-26 API Number: 50-283-20201-00-00 Current Status: Gas Producer Permit to Drill Number: 224-098 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) First Call Engineer: Ryan LeMay (661) 487-0871 (C) Maximum Expected BHP: 2401 psi @ 5,458’ (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: 2128 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.76 psi/ft using 14.59 ppg EMW FIT at the surface casing shoe 8/27/24 Shallowest Potential Perf TVD: MPSP/(0.76-0.1) = 2128 psi / 0.66 = 3225‘ TVD Top of SBGP (CO 802A & BLM PA): 2,989’ MD, ~2,896' TVD Well Status: Currently online at 950 mcfd / 1 bwpd water / 284 psi FTP (As of 1/22/26) Brief Well Summary BRU 221-26 was drilled in the 2024 Beluga River drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to add perforations to the well. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A. Wellbore Conditions: - Max Inclination – 21° at 1,360’ MD w/ 4 deg Max dogleg @ 1800’ - CBL run 9/10/24 shows TOC @ 2,754’ Procedure: 1. Review all COA’s for AOGCC 2. MIRU E-line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed Attachments: 1. Current Schematic 2. Proposed Schematic Sands Top MD Btm MD Top TVD Btm TVD Amt Top of Pool per CO 802A & BLM PA: ~2,989’ MD/2,896’ TVD Bel D1 ±3,814’ ±3,832’ ±3,716’ ±3,734’ ±18’ Bel D4 ±3,888’ ±3,894’ ±3,790’ ±3,796’ ±6’ Bel D5 ±3,919’ ±3,923’ ±3,820’ ±3,824’ ±4’ Bel E1 ±4,779’ ±4,791’ ±3,856’ ±3,868’ ±12’ Bel E1 ±4,816’ ±4,820’ ±3,893’ ±3,897’ ±4’ Bel E5 ±4,845’ ±4,857’ ±3,922’ ±3,933’ ±12’ Bel E5 ±4,892’ ±4,896’ ±3,968’ ±3,972’ ±4’ Bel E5 ±4,918‘ ±4,930’ ±3,994’ ±4,006’ ±12’ Bel E6 ±4,947‘ ±4,950’ ±4,023’ ±4,026’ ±3’ p g ) 0.05 psi/ft gas gradient Updated by CAH 1-23-26 Schematic Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PBTD = 6,896’ / TVD = 6,780’ TD = 6,961’ / TVD = 6,845’ RKB to GL = 20.3’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 7-5/8" Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875”Surf 2,759’ 3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,558’6,958’ 3-1/2"Prod Tieback 9.3 L-80 Hyd 563 2.992”Surf 2,568’ 3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,558’4.875”6.540”5-1/2” HRD-E ZXP Liner top packer & Flex lock hanger w/ 3-1/2” XO 3 2,558’4.790”6.340”Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8"166 bbls (382 sx) of 12 ppg lead followed by 36 bbls (174 sx) of 15.8 ppg tail, w/76 bbls of returns to surface 8/26/24. No losses on job. 3-1/2” 177 bbls (415 sx) of 12 ppg Type I lead followed by 27 bbls (122sx) of 15.3 ppg tail in 6.75” hole. 45 bbls of Cement/contaminated returned 9/5/24. 10bbls lost during job. TOC per CBL run on 9/10/24 is 2,754’. 6-3/4” hole 2 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Top of Pool per CO 802 & BLM PA: ~2,989’ MD/2,896’ TVD Bel F 4,369’4,381’4,268’4,280’12’10/29/24 Open Bel F4 4,434’4,450’4,332’4,348’16’10/29/24 Open Bel F4 4,468’4,471’4,366’4,369’3’10/29/24 Open Bel F4 4,481’4,487’4,379’4,385’6’10/28/24 Open Bel F5 4,504’4,516’4,402’4,414’12’10/28/24 Open Bel F6 4,545’4,550’4,443’4,448’5’10/28/24 Open Bel F6 4,565’4,570’4,463’4,468’5’10/28/24 Open Bel F6 4,579’4,589’4,477’4,487’10’10/28/24 Open Bel F7 4,659’4,669’4,556’4,566’10’10/28/24 Open Bel F7 4,699’4,710’4,596’4,607’11’10/28/24 Open Bel F7 4,729’4,734’4,626’4,631’5’10/27/24 Open Bel F10 4,773’4,785’4,669’4,681’12’10/27/24 Open Bel F10 4,789’ 4,801’ 4,685’ 4,697’ 12’10/27/24 Open Bel F10 4,821’ 4,825’ 4,717’ 4,721’ 4’10/26/24 Open Bel G1 4,881’ 4,884’ 4,776’ 4,779’ 3’10/26/24 Open Bel G2 4,908’ 4,912’ 4,803’ 4,807’ 4’10/26/24 Open Bel G3 4,919’ 4,924’ 4,814’ 4,819’ 5’10/26/24 Open Bel G3 4,934’ 4,940’ 4,829’ 4,835’ 6’10/26/24 Open Bel G3 4,944’ 4,949’ 4,839’ 4,844’ 5’10/26/24 Open Bel G3 4,961’ 4,966’ 4,856’ 5,861’ 5’10/26/24 Open Bel G5 5,007’ 5,027’ 4,902’ 4,922’ 20’10/26/24 Open Bel G6 5,044’ 5,048’ 4,939’ 4,943’ 4’10/25/24 Open Bel G8 5,081’ 5,086’ 4,976’ 4,981’ 5’10/25/24 Open Bel G8 5,093’ 5,101’ 4,988’ 4,996’ 8’10/25/24 Open Bel G9 5,110’ 5,120’ 5,005’ 5,015’ 10’10/25/24 Open Bel G10 5,143’ 5,157’ 5,037’ 5,051’ 14’10/25/24 Open Bel H 5,194’ 5,205’ 5,088’ 5,099’ 11’10/25/24 Open Bel H 5,217’ 5,222’ 5,111’ 5,116’ 5’10/24/24 Open Bel H1 5,225’ 5,230’ 5,119’ 5,124’ 5’10/24/24 Open Bel H2 5,267’ 5,273’ 5,160’ 5,166’ 6’10/24/24 Open Bel H2 5,288’ 5,294’ 5,181’ 5,187’ 6’10/24/24 Open Bel H2 5,301’ 5,307’ 5,194’ 5,200’ 6’10/24/24 Open Bel H4 5,366’ 5,371’ 5,260’ 5,265’ 5’10/24/24 Open Bel H7 5,466’ 5,486’ 5,358’ 5,378’ 20’10/20/24 Open Bel H9 5,526’ 5,530’ 5,418’ 5,422’ 4’10/20/24 Open Bel H9 5,555’ 5,566’ 5,447’ 5,458’ 11’10/20/24 Open NOTES Short Joints w/ RA Tags (~15ft)3,342’, 3,848’, 4360’, 4864’, 5367’, 5879’, 6389’ RA 5,879’ RA 6,389’ RA 3,848’ RA 3,342’ RA 5,357’ RA 4,360’ RA 4,864’ Updated by CAH 01-22-26 PROPOSED Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PBTD = 6,896’ / TVD = 6,780’ TD = 6,961’ / TVD = 6,845’ RKB to GL = 20.3’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 7-5/8" Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875”Surf 2,759’ 3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,558’6,958’ 3-1/2"Prod Tieback 9.3 L-80 Hyd 563 2.992”Surf 2,568’ 3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,558’4.875”6.540”5-1/2” HRD-E ZXP Liner top packer & Flex lock hanger w/ 3-1/2” XO 3 2,558’4.790”6.340”Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8"166 bbls (382 sx) of 12 ppg lead followed by 36 bbls (174 sx) of 15.8 ppg tail, w/76 bbls of returns to surface 8/26/24. No losses on job. 3-1/2” 177 bbls (415 sx) of 12 ppg Type I lead followed by 27 bbls (122sx) of 15.3 ppg tail in 6.75” hole. 45 bbls of Cement/contaminated returned 9/5/24. 10bbls lost during job. TOC per CBL run on 9/10/24 is 2,754’. 6-3/4” hole 2 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Top of Pool per CO 802A & BLM PA: ~2,989’ MD/2,896’ TVD Bel D1 ±3,814’±3,832’±3,716’±3,734’±18’TBD Proposed Bel D4 ±3,888’±3,894’±3,790’±3,796’±6’TBD Proposed Bel D5 ±3,919’±3,923’±3,820’±3,824’±4’TBD Proposed Bel E1 ±4,779’±4,791’±3,856’±3,868’±12’TBD Proposed Bel E1 ±4,816’±4,820’±3,893’±3,897’±4’TBD Proposed Bel E5 ±4,845’±4,857’±3,922’±3,933’±12’TBD Proposed Bel E5 ±4,892’±4,896’±3,968’±3,972’±4’TBD Proposed Bel E5 ±4,918‘±4,930’±3,994’±4,006’±12’TBD Proposed Bel E6 ±4,947‘±4,950’±4,023’±4,026’±3’TBD Proposed Bel F 4,369’4,381’4,268’4,280’12’10/29/24 Open Bel F4 4,434’ 4,450’ 4,332’ 4,348’ 16’10/29/24 Open Bel F4 4,468’ 4,471’ 4,366’ 4,369’ 3’10/29/24 Open Bel F4 4,481’ 4,487’ 4,379’ 4,385’ 6’10/28/24 Open Bel F5 4,504’ 4,516’ 4,402’ 4,414’ 12’10/28/24 Open Bel F6 4,545’ 4,550’ 4,443’ 4,448’ 5’10/28/24 Open Bel F6 4,565’ 4,570’ 4,463’ 4,468’ 5’10/28/24 Open Bel F6 4,579’ 4,589’ 4,477’ 4,487’ 10’10/28/24 Open Bel F7 4,659’ 4,669’ 4,556’ 4,566’ 10’10/28/24 Open Bel F7 4,699’ 4,710’ 4,596’ 4,607’ 11’10/28/24 Open Bel F7 4,729’ 4,734’ 4,626’ 4,631’ 5’10/27/24 Open Bel F10 4,773’ 4,785’ 4,669’ 4,681’ 12’10/27/24 Open Bel F10 4,789’ 4,801’ 4,685’ 4,697’ 12’10/27/24 Open Bel F10 4,821’ 4,825’ 4,717’ 4,721’ 4’10/26/24 Open Bel G1 4,881’ 4,884’ 4,776’ 4,779’ 3’10/26/24 Open Bel G2 4,908’ 4,912’ 4,803’ 4,807’ 4’10/26/24 Open Bel G3 4,919’ 4,924’ 4,814’ 4,819’ 5’10/26/24 Open Bel G3 4,934’ 4,940’ 4,829’ 4,835’ 6’10/26/24 Open Bel G3 4,944’ 4,949’ 4,839’ 4,844’ 5’10/26/24 Open Bel G3 4,961’ 4,966’ 4,856’ 5,861’ 5’10/26/24 Open Bel G5 5,007’ 5,027’ 4,902’ 4,922’ 20’10/26/24 Open Bel G6 5,044’ 5,048’ 4,939’ 4,943’ 4’10/25/24 Open Bel G8 5,081’ 5,086’ 4,976’ 4,981’ 5’10/25/24 Open Bel G8 5,093’ 5,101’ 4,988’ 4,996’ 8’10/25/24 Open Bel G9 5,110’ 5,120’ 5,005’ 5,015’ 10’10/25/24 Open Bel G10 5,143’ 5,157’ 5,037’ 5,051’ 14’10/25/24 Open Perforations continued on Page 2 NOTES Short Joints w/ RA Tags (~15ft)3,342’, 3,848’, 4360’, 4864’, 5367’, 5879’, 6389’ RA 5,879’ RA 6,389’ RA 3,848’ RA 3,342’ RA 5,357’ RA 4,360’ RA 4,864’ Updated by CAH 01-22-26 PROPOSED Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PERFORATION DETAIL Continued form Page 1 Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel H 5,194’ 5,205’ 5,088’ 5,099’ 11’ 10/25/24 Open Bel H 5,217’ 5,222’ 5,111’ 5,116’ 5’ 10/24/24 Open Bel H1 5,225’ 5,230’ 5,119’ 5,124’ 5’ 10/24/24 Open Bel H2 5,267’ 5,273’ 5,160’ 5,166’ 6’ 10/24/24 Open Bel H2 5,288’ 5,294’ 5,181’ 5,187’ 6’ 10/24/24 Open Bel H2 5,301’ 5,307’ 5,194’ 5,200’ 6’ 10/24/24 Open Bel H4 5,366’ 5,371’ 5,260’ 5,265’ 5’ 10/24/24 Open Bel H7 5,466’ 5,486’ 5,358’ 5,378’ 20’ 10/20/24 Open Bel H9 5,526’ 5,530’ 5,418’ 5,422’ 4’ 10/20/24 Open Bel H9 5,555’ 5,566’ 5,447’ 5,458’ 11’ 10/20/24 Open Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250318 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-51 50733204640000 195004 3/1/2025 READ CAliperSurvey AN-51 50733204640000 195004 3/1/2025 READ CaliperSurvey/SBHPS BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF BRU 241-34S 50283201980000 224077 3/1/2025 AK E-LINE PPROF IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper MRU A-12RD 50733200760100 171029 3/7/2025 AK E-LINE Correlation MRU A-13 (REVISED)50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-32RD2 50733204620200 217091 3/4/2025 AK E-LINE Correlation PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT PBU 16-24A 50029215360100 224158 2/23/2025 HALLIBURTON RBT-COILFLAG PBU F-21 50029219490000 189056 2/25/2025 READ CaliperSurvey SD37-DSP01 50629234510000 211089 2/28/2025 HALLIBURTON WFL-TMD3D Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40221 T40221 T40222 T40222 T40223 T40224 T40225 T40226 T40226 T40227 T40228 T40229 T40230 T40231 T40232 T40233 T40234 BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.18 15:55:41 -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: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241205 Well API #PTD #Log Date Log Company Log Type AOGCC ESet AN 15(GRANITE PT ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24 MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Please include current contact information if different from above. T39808 T39809 T39810 T39810 T39811 T39812 T39813 T39813 T39814 T39815 T39816 T39817 T39818 T39819 T39820 T39820 T39821 T39822 T39823 T39823 T39823 T39823 T39824 T39825 T39826 T39827 BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.05 14:52:46 -09'00' 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: 10/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241030 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch Please include current contact information if different from above. T39726 T39727 T39728 T39732 T39733 T39734 T39735 T39736 T39737 T39738 T39739 T39739 T39740 T39741 T39742 T39742 T39743 T39744 T39744 T39745 BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.01 13:27:33 -08'00' From:McLellan, Bryan J (OGC) To:chelgeson@hilcorp.com Subject:BRU 221-26 (PTD 224-098) verbal approval for CTCO Date:Friday, October 4, 2024 12:17:00 PM Chad, Hilcorp has verbal approval to perform the CT work as described in the sundry for this well submitted on 9/16/24. FYI, it will be sundry number 324-530. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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: 10/03/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 Final GeoTap Formation Pressure Tester (08/23/2024 to 08/31/2024) SFTP Transfer - Data Folders: Please include current contact information if different from above. 224-098 T39615 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.03 15:25:46 -08'00' 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: 9/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 FINAL LWD FORMATION EVALUATION LOGS (08/23/2024 to 08/31/2024) DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 224-098 T39612 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 15:02:14 -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: 9/27/2024 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 BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 14:47:28 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Brooks, Phoebe L (OGC) To:Joshua Riley - (C) Cc:Regg, James B (OGC) Subject:RE: BOPE Test Report Date:Thursday, September 26, 2024 1:43:33 PM Attachments:MIT BRU 221-26 09-06-24 Revised.xlsx Josh, I changed the interval to “O”. Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Joshua Riley - (C) <jriley@hilcorp.com> Sent: Saturday, September 7, 2024 1:00 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: BOPE Test Report Here is the MIT f/ BRU 221-26 Thank You The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the I changed the interval to “O”. Please update your copy. Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2240980 Type Inj N Tubing 0 3040 3020 3020 Type Test P Packer TVD 2469 BBL Pump 0.7 IA 0 20 20 20 Interval O Test psi 3000 BBL Return 0.7 OA 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2240980 Type Inj N Tubing 0 425 425 425 Type Test P Packer TVD 2469 BBL Pump 1.2 IA 0 3060 3060 3060 Interval O Test psi 3000 BBL Return 1.2 OA 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:End of well MIT operational assurace test Notes: Notes: Hilcorp Alaska LLC BRU 221-26 Josh Riley 09/06/24 Notes:End of well MIT operational assurace test Notes: Notes: Notes: BRU 221-26 BRU 221-26 Form 10-426 (Revised 01/2017)2024-0906_MITP_BRU_221-26_2tests O O 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: Initial Completion, N2 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): 6,961'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi 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: 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 LTP; N/A 2,593' MD/2,504' TVD; N/A 6,844'6,925'6,809' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 221-26CO 802 Same 6,843'3-1/2" ~2294psi 4,366' N/A Length September 25, 2024 Tieback 3-1./2" 6,959' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 136'136' 2,759' Size 136' 2,772' MD Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 2,568' 10,160psi 2,668' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 21127 224-098 50-283-20201-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 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: m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:59 am, Sep 16, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.09.13 15:50:15 - 08'00' Noel Nocas (4361) 324-530 BJM 10/3/24 SFD 9/16/2024 X DSR-9/25/24 10-407 CT BOP test to 2500 psi JLC 10/3/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.07 10:41:27 -08'00' 10/07/24 RBDMS JSB 100824 Well Prognosis Well Name: BRU 221-26 API Number: 50-283-20201-00-00 Current Status: New Drill Well Permit to Drill Number: 224-098 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 2969 psi @ 6749’ TVD (Based on 0.44 psi/ft gradient)) Max. Potential Surface Pressure: 2294 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.76 psi/ft using 14.59 ppg EMW FIT at the surface casing shoe 8/27/24 Shallowest Potential Perf TVD: MPSP/(0.76-0.1) = 2294 psi / 0.66 = 3476‘ TVD Top of Pools per CO 802: Sterling-Beluga Gas Pool: 3,254’ MD, ~3,160' TVD Well Status: New Drill Initial Completion Brief Well Summary: BRU 221-26 is the fifth of five grass roots wells drilled in the 2024 Beluga River drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to clean out the liner with coil tubing/nitrogen, and perforate multiple Beluga sands. All sands lie in the Sterling-Beluga Gas Pool. Wellbore Conditions: - Liner full of 9.3 ppg 6% KCl mud - Tubing and IA displaced to 8.4 ppg CIW - T & IA pressure tested to 3000 psi - Planned top perf In Beluga D sand @ 3776’ MD: 3679 TVD - CBL run 9/10/24 shows TOC @ 2,754’ Procedure: 1. MIRU Coil Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 48hr notice for BOP test 3. RIH & clean out wellbore to PBTD (~6880’), displace liner to 8.4 ppg water 4. Reverse out wellbore with nitrogen, trap ~2000 psi on wellbore o ~60 bbls total wellbore volume 5. RDMO coil tubing 6. RU E-line, PT lubricator to 2500 psi 7. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 8. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up: Pool Top (Sterling A1) 3254’ MD 3160’ TVD Planned Interval (Beluga D – J) 3776’ – 6864’ MD 3679’ – 6749’ TVD a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. a. Above perfs are in the Sterling-Beluga Gas Pool governed by CO 802. b. Pending well production, all perf intervals may not be completed Shallowest proposed perf is allowable SFD , equivalent to about 3,575' MD SFD Well Prognosis 9. RDMO 10. Turn well over to production & flow test well 11. Test SVS as necessary once well has reached stable flow rates a. Notify state 48hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 2. Provide AOGCC 24hrs notice of BOP test 3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 4. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 5. RDMO coil tubing Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations Updated by CAH 09-13-24 CURRENT SCHEMATIC Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PBTD = 6,925’ / TVD = 6,809’ TD = 6,961’ / TVD = 6,845’ RKB to GL = 20.3’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 136’ 7-5/8"Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875”Surf 2,759’ 3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,593’6,959’ 3-1/2"Prod Tieback 9.2 L-80 EUE 2.992”Surf 2,568’ 3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,593’4.875”6.540”5-1/2” HRD-E ZXP Liner top packer & Flex lock hanger w/ 3-1/2” XO 3 2,558’4.790”6.340”Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8"166 bbls (382 sx) of 12 ppg lead followed by 36 bbls (174 sx)of 15.8 ppg tail, w/76 bbls of returns to surface 8/26/24. No losses on job. 3-1/2” 177 bbls (415 sx) of 12 ppg Type I lead followed by 27 bbls (122sx) of 15.3 ppg tail in 6.75” hole. 45 bbls of Cement/contaminated returned 9/5/24. 10bbls lost during job. TOC per CBL run on 9/10/24 is 2,754’. 6-3/4” hole 2 1 NOTES Short Joints w/ RA Tags (~15ft)3,342’, 3,848’, 4360’, 4864’, 5367’, 5879’, 6389’ RA 5,879’ RA 6,389’ RA 3,848’ RA 3,342’ RA 5,357’ RA 4,360’ RA 4,864’ Updated by CAH 09-13-24 PROPOSED Beluga River Unit BRU 221-26 PTD: 224-098 API: 50-283-20201-00-00 PBTD = 6,925’ / TVD = 6,809’ TD = 6,961’ / TVD = 6,845’ RKB to GL = 20.3’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 136’ 7-5/8"Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875”Surf 2,759’ 3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,593’6,959’ 3-1/2"Prod Tieback 9.2 L-80 EUE 2.992”Surf 2,568’ 3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,593’4.875”6.540”5-1/2” HRD-E ZXP Liner top packer & Flex lock hanger w/ 3-1/2” XO 3 2,558’4.790”6.340”Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8"166 bbls (382 sx) of 12 ppg lead followed by 36 bbls (174 sx)of 15.8 ppg tail, w/76 bbls of returns to surface 8/26/24. No losses on job. 3-1/2” 177 bbls (415 sx) of 12 ppg Type I lead followed by 27 bbls (122sx) of 15.3 ppg tail in 6.75” hole. 45 bbls of Cement/contaminated returned 9/5/24. 10bbls lost during job. TOC per CBL run on 9/10/24 is 2,754’. 6-3/4” hole 2 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Pool Top Sterling A1 - 3,254’ MD / 3,160’ TVD Beluga D-J ±3,776’±6,864’±3,679’±6,749’Proposed TBD NOTES Short Joints w/ RA Tags (~15ft)3,342’, 3,848’, 4360’, 4864’, 5367’, 5879’, 6389’ RA 5,879’ RA 6,389’ RA 3,848’ RA 3,342’ RA 5,357’ RA 4,360’ RA 4,864’ STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard 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 Transport. 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 Nitrogen vendor 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 Transport. 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:Joshua Riley - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:BOPE Test Report Date:Saturday, September 7, 2024 1:00:45 PM Attachments:BRU 221-26 9-6-24 MIT.xlsx Here is the MIT f/ BRU 221-26 Thank You 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. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2240980 Type Inj N Tubing 0 3040 3020 3020 Type Test P Packer TVD 2469 BBL Pump 0.7 IA 0 20 20 20 Interval I Test psi 3000 BBL Return 0.7 OA 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2240980 Type Inj N Tubing 0 425 425 425 Type Test P Packer TVD 2469 BBL Pump 1.2 IA 0 3060 3060 3060 Interval I Test psi 3000 BBL Return 1.2 OA 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska LLC BRU 221-26 Josh Riley 09/06/24 Notes:End of well MIT operational assurace test Notes: Notes: Notes: BRU 221-26 BRU 221-26 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:End of well MIT operational assurace test Notes: Notes: Form 10-426 (Revised 01/2017)2024-0906_MITP_BRU_221-26_2tests 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: Beluga River Unit Field, Sterling-Beluga Gas Pool, BRU 22-26 Hilcorp Alaska, LLC Permit to Drill Number: 224-098 Surface Location: 487' FSL, 2588' FWL, Sec 23, T13N, R10W, SM, AK Bottomhole Location: 442' FNL, 2065' FWL, Sec 26, T13N, 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, Jessie Chmielowski Commissioner DATED this 14th day of August 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.14 15:29:18 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 6,961' TVD: 6,844' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 93.7 15. Distance to Nearest Well Open Surface: x-320601 y- 2630887 Zone-4 75.2 to Same Pool:1370' to BRU 224-23T 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 19 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 2,772' Surface Surface 2,772' 2,678' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,389' 2,572' 2,480' 6,961' 6,844' Tieback 3-1/2" 9.2# L-80 EUE 2,572' Surface Surface 2,572' 2,480' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: 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 8/20/2024 4502' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 Tieback Assy. 480 Drilling Manager Monty Myers 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):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 919 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 3125 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 976 ft3 / T - 131 ft3 2441 105' FNL, 2246' FWL, Sec 26, T13N, R10W, SM, AK 442' FNL, 2065' FWL, Sec 26, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 487' FSL, 2588' FWL, Sec 23, T13N, R10W, SM, AK ADL 21127 BRU 221-26 Beluga River Unit Sterling-Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 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 No s 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 07/15/24 Monty M Myers By Grace Christianson at 10:19 am, Jul 15, 2024 224-098 BOP test to 3000 psi. Annular test to 2500 psi. 50-283-20201-00-00 DSR-7/15/23A.Dewhurst 24JUL24 Submit FIT/LOT results within 48 hrs of performing test. BJM 8/14/24 24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.14 15:29:32 -08'00' 08/14/24 08/14/24 RBDMS JSB 081624 BRU 221-26 PTD Program Beluga River Unit July 01, 2024 BRU 221-26 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................12 12.0 Run 7-5/8” Surface Casing..........................................................................................................14 13.0 Cement 7-5/8” Surface Casing....................................................................................................16 14.0 BOP N/U and Test........................................................................................................................19 15.0 Drill 6-3/4” Hole Section..............................................................................................................20 16.0 Run 3-1/2” Production Liner......................................................................................................22 17.0 Cement 3-1/2” Production Liner................................................................................................25 18.0 3-1/2” Liner Tieback Polish Run................................................................................................28 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................29 20.0 Diverter Schematic ......................................................................................................................30 21.0 BOP Schematic.............................................................................................................................31 22.0 Wellhead Schematic.....................................................................................................................32 23.0 Anticipated Drilling Hazards......................................................................................................33 24.0 Hilcorp Rig 147 Layout...............................................................................................................35 25.0 FIT/LOT Procedure ....................................................................................................................36 26.0 Choke Manifold Schematic.........................................................................................................37 27.0 Casing Design Information.........................................................................................................38 28.0 6-3/4” Hole Section MASP..........................................................................................................39 29.0 Spider Plot....................................................................................................................................40 30.0 Surface Plat As-Built...................................................................................................................41 Page 2 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 1.0 Well Summary Well BRU 221-26 Pad & Old Well Designation BRU J Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 6961 MD / 6844’ TVD PBTD, MD / TVD 6861’ MD AFE Number AFE Drilling Days AFE Drilling Amount Maximum Anticipated Pressure (Surface)2441 psi Maximum Anticipated Pressure (Downhole/Reservoir)3125 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 93.70’ Ground Elevation 75.20’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 2.0 Management of Change Information Page 4 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 - Surface 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 DWC/C 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 ** Liner must overlap surface casing by at least 100’. 4.0 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 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. 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. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 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 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 6.0 Planned Wellbore Schematic Page 7 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 7.0 Drilling / Completion Summary BRU 221-26 is an S-shaped directional grassroots development well to be drilled from BRU J Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~19 deg. and TD of the well will be 6961’ TMD/ 6844’ TVD, ending with 6 deg inclination left in the hole. Drilling operations are expected to commence approximately August, 2024. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2772’ MD / 2678’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 147 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to 2772’ MD. Run and cmt 7-5/8” surface casing. 4. Test casing to 3500 psi. Perform 14.0# FIT 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to 6961’ MD. Perform Wiper trip. 7. Run and cmt 3-1/2” production liner. 8. Displace well to 6% KCL completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo Page 8 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our 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 of BRU 221-26. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 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. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC 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. Page 9 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. 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 testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Page 10 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 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 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 9-7/8” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 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. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Estimated Diverter line orientation on BRU J Pad: Page 12 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2772’ MD/ 2678’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: 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 8.8 ppg. 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, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2772’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 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. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 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. 12.11 After circulating, lower string and land hanger in wellhead again. Page 16 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 17 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2272’ MD to surface)Tail Slurry (2772’ to 2272’ MD) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 18 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 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. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 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. 13.17 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 Page 19 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 20 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. 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, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2772’- 6961’9.0 – 9.7 40-53 15-25 15-25 8.5-9.5 ” 11.0 Page 21 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 9.7 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 13.6# ppg FIT will result in a 23 bbl KTV. 15.14 Drill 6-3/4” hole section to 6961’ MD / 6844’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Lost circulation potential when drilling through Beluga D and E. SLOW ROP, Add Black products and background LCM to the mud. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA Page 22 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA 15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted 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. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with YJOC landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 23 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD Page 24 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 25 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 26 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (6461’ MD to 2573’ MD)Tail Slurry (6961’ to 6461’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 27 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. 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. 17.10. Bump the plug and pressure up to up as required by YJOC procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. 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). 17.18. 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. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Page 28 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 17.21. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes. 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 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 cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC procedure. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 29 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Install chemical injection mandrel at ~1,500’ MD. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.48 hr notice required. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.48 hr notice required. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #147 Page 30 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 20.0 Diverter Schematic Page 31 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 21.0 BOP Schematic Page 32 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 22.0 Wellhead Schematic Page 33 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous 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/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 34 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. 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. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 35 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 24.0 Hilcorp Rig 147 Layout Page 36 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 25.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 37 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 26.0 Choke Manifold Schematic Page 38 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 27.0 Casing Design Information Page 39 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 28.0 6-3/4” Hole Section MASP Page 40 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 29.0 Spider Plot Page 41 Version PTD July 01, 2024 BRU 221-26 Drilling Procedure PTD 30.0 Surface Plat As-Built                 !""#  $ %        -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000True Vertical Depth (1000 usft/in)-1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 Vertical Section at 209.00° (1000 usft/in) BRU 221-26 tgt1 7 5/8" x 9 7/8" 3 1/2" x 6 3/4" 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 6 9 6 1 BRU 221-26 wp02 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 933.57' MD, 922.01' TVD Start Dir 3º/100' : 2235.05' MD, 2152.53'TVD End Dir : 2668.71' MD, 2575' TVD Total Depth : 6960.92' MD, 6843.7' TVD STERLING_A1 STERLING_B STERLING_C BELUGA_D BELUGA_E BELUGA_F BELUGA_G BELUGA H BELUGA_I BRU_BELUGA_J 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: BRU 221-26 75.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2630887.48 320601.63 61° 11' 49.4882 N 151° 1' 1.1682 W SURVEY PROGRAM Date: 2024-06-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2773.00 BRU 221-26 wp02 (BRU 221-26) 3_MWD+AX+Sag 2773.00 6960.92 BRU 221-26 wp02 (BRU 221-26) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3146.70 3053.00 3243.56 STERLING_A1 3312.70 3219.00 3410.47 STERLING_B 3457.70 3364.00 3556.27 STERLING_C 3660.70 3567.00 3760.39 BELUGA_D 3881.70 3788.00 3982.61 BELUGA_E 4225.70 4132.00 4328.50 BELUGA_F 4725.70 4632.00 4831.26 BELUGA_G 5062.70 4969.00 5170.11 BELUGA H 5793.70 5700.00 5905.14 BELUGA_I 6334.70 6241.00 6449.12 BRU_BELUGA_J REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 221-26, True North Vertical (TVD) Reference:RKB As-Built @ 93.70usft (147) Measured Depth Reference:RKB As-Built @ 93.70usft (147) Calculation Method: Minimum Curvature Project:Beluga River Site:BRU J-Pad Well:Plan: BRU 221-26 Wellbore:BRU 221-26 Design:BRU 221-26 wp02 CASING DETAILS TVD TVDSS MD Size Name 2678.00 2584.30 2772.28 7-5/8 7 5/8" x 9 7/8" 6843.70 6750.00 6960.92 3-1/2 3 1/2" x 6 3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 933.57 19.01 209.68 922.01 -90.47 -51.56 3.00 209.68 104.12 End Dir : 933.57' MD, 922.01' TVD 4 2235.05 19.01 209.68 2152.53 -458.74 -261.42 0.00 0.00 527.96 Start Dir 3º/100' : 2235.05' MD, 2152.53'TVD 5 2668.71 6.00 208.23 2575.00 -540.42 -307.30 3.00 -179.33 621.64 End Dir : 2668.71' MD, 2575' TVD 6 6960.92 6.00 208.23 6843.70 -935.71 -519.52 0.00 0.00 1070.26 BRU 221-26 tgt1 Total Depth : 6960.92' MD, 6843.7' TVD -1200 -1125 -1050 -975 -900 -825 -750 -675 -600 -525 -450 -375 -300 -225 -150 -75 0 75 150 South(-)/North(+) (150 usft/in)-825 -750 -675 -600 -525 -450 -375 -300 -225 -150 -75 0 75 150 225 West(-)/East(+) (150 usft/in) BRU 221-26 tgt1 7 5/8" x 9 7/8" 3 1/2" x 6 3/4" 250 500 750 1000 1250 1500 1750 2000 22 50 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 67506844 BRU 221-26 wp02 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 933.57' MD, 922.01' TVD Start Dir 3º/100' : 2235.05' MD, 2152.53'TVD End Dir : 2668.71' MD, 2575' TVD Total Depth : 6960.92' MD, 6843.7' TVD CASING DETAILS TVD TVDSS MD Size Name 2678.00 2584.30 2772.28 7-5/8 7 5/8" x 9 7/8" 6843.70 6750.00 6960.92 3-1/2 3 1/2" x 6 3/4" Project: Beluga River Site: BRU J-Pad Well: Plan: BRU 221-26 Wellbore: BRU 221-26 Plan: BRU 221-26 wp02 WELL DETAILS: Plan: BRU 221-26 75.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2630887.48 320601.63 61° 11' 49.4882 N 151° 1' 1.1682 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 221-26, True North Vertical (TVD) Reference:RKB As-Built @ 93.70usft (147) Measured Depth Reference:RKB As-Built @ 93.70usft (147) Calculation Method:Minimum Curvature  & # '  "  #   ( )*+ (             ,  , -    !  ! %#   ./ "##  $ %&'()* +, -). + $ !/* +- 0123 0 4 .+ ($ %&'()* +, -). 0 / ( 5  ! 2 .  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"0-)%&* +0-,%&,* .&*+*)0.)&./     ('--(*('--(*('--(**&". *)&-) +&* *)&+ "&-%.*)&-)/    ('--(*('--(*('--(**&*+ *+%& +&", *+%&% .&%"+*+%&     ('--(*('--(*('--(**-&+ %& *&) -..&)* ,&-.,%&/     ( '**(*('**(*('**(*--&,* *)%&" -"&-* *)%&+ "*&".**)%&"/    ( '**(*('**(*('**(*--&.) -& -"&** *..&,* "&*.,-&     ( '**(*('**(*('**(*-,&., %& --&)+ -.+&. ""&*+%&/     (    = , '->, '-  @"  >",&% 0++*& '"() *123!4! 50++*& )0.)&. '"() *123!4! 5           '"$ !%! !%&    6     7 89 (&   7  : &/ 7    7 $   &/    ;  $ #<  $ (   =&   5  : :  &      7 752676/7 8 7 6&      0.000.751.502.253.00Separation Factor0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400Measured Depth (1200 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: Plan: BRU 221-26 NAD 1927 (NADCON CONUS) Alaska Zone 0475.20+N/-S+E/-W NorthingEastingLatitude Longitude0.00 0.00 2630887.48 320601.63 61° 11' 49.4882 N 151° 1' 1.1682 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 221-26, True NorthVertical (TVD) Reference: RKB As-Built @ 93.70usft (147)Measured Depth Reference:RKB As-Built @ 93.70usft (147)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2678.00 2584.30 2772.28 7-5/8 7 5/8" x 9 7/8"6843.70 6750.00 6960.92 3-1/2 3 1/2" x 6 3/4"SURVEY PROGRAMDate: 2024-06-13T00:00:00 Validated: Yes Version: Depth FromDepth To Survey/PlanTool18.50 2773.00 BRU 221-26 wp02 (BRU 221-26) 3_MWD+AX+Sag2773.00 6960.92 BRU 221-26 wp02 (BRU 221-26) 3_MWD+AX+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400Measured Depth (1200 usft/in)BRU 211-26BRU 224-23TBRU 233-23T wp03BRU 244-23BRU 232-26GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 6960.92Project: Beluga RiverSite: BRU J-PadWell: Plan: BRU 221-26Wellbore: BRU 221-26Plan: BRU 221-26 wp02Ladder/S.F. Plots 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. 224-098 BELUGA RIVER BRU 221-26 STRLG-BELUGA GAS WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 221-26Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240980BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes ADL211272 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by CO 8024 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day 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 proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2441 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 anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Max reservoir pressure anticipated at 7.8 ppg EMW, with many intervals with sever underpressure (2.3 ppg EMW)36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate7/24/2024ApprBJMDate8/14/2024ApprADDDate7/24/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate($8JLC 8/14/2024