Alaska Logo
Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
Loading...
HomeMy WebLinkAbout225-044Nolan 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: 2/10/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260210 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 224-34T 50283202050000 225044 1/30/2026 AK E-LINE Perf T41349 CLU 11RD 50133205590100 225013 1/24/2026 AK E-LINE Perf T41350 CLU 11RD 50133205590100 225013 1/27/2026 AK E-LINE Plug/Perf T41350 KU 24-07RD2 50133203520200 225126 1/14/2026 AK E-LINE CBL T41351 KU 24-07RD2 50133203520200 225126 1/20/2026 AK E-LINE IPFOF T41351 MPI 2-74 50029237850000 224024 1/25/2026 AK E-LINE Whipstock T41352 MPU 1-36 50029236770000 220047 2/1/2026 AK E-LINE Packer T41353 MPU R-110 50029238260000 225085 10/24/2025 YELLOWJACKET RCBL T41354 NFU 14-25 50231200350000 210111 12/29/2025 YELLOWJACKET CBL T41355 SDI 3-15 50029217510000 187094 1/23/2026 AK E-LINE Whipstock T41356 SRU 214A-27 50133101580100 225133 2/4/2026 YELLOWJACKET SCBL T41357 SRU 231-33 50133101630100 223008 7/31/2025 YELLOWJACKET PLUG-PERF T41358 SRU 242-16 50133204050000 188157 1/24/2026 YELLOWJACKET PLUG-PERF T41359 SU 43-10 50133207390000 225107 1/19/2026 YELLOWJACKET GPT-PLUG- PERF T41360 SU 43-10 50133207390000 225107 12/31/2025 YELLOWJACKET SCBL T41360 Please include current contact information if different from above. BRU 224-34T 50283202050000 225044 1/30/2026 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.10 14:51:05 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 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): 6,007' 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 FEDA029656 225-044 50-283-20205-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,225' 10,160psi 2,586' Size 120' 2,607' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,607' February 5, 2026 Tieback 3-1/2" 6,007' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 224-34TCO 802A Same 5,944'3-1/2" ~2170psi 3,785' N/A Length Scout Pkr; N/A 2,185' MD / 2,169' TVD; N/A, N/A 5,944' 5,546' 5,477' 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 326-052 By Grace Chistianson at 8:14 am, Jan 26, 2026 DSR-1/27/26 Perforate SFD 1/26/2026BJM 1/28/26 10-404 JLC 1/29/2026 01/29/26 Well Prognosis Well Name: BRU 224-34T API Number: 50-283-20205-00-00 Current Status: Gas Producer Permit to Drill Number: 225-044 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: 2434 psi @ 5,292’ TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2170 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.756 psi/ft using 14.55 ppg EMW FIT at the 7-5/8” surface casing window Shallowest Potential Perf TVD: MPSP/(0.756-0.05) = 2170 psi / 0.706 = 3074’ TVD Top of SBGP (CO 802A) & BLM PA: ~2892’ MD/~2865’ TVD Well Status: Online flowing ~2.4 mmscfd @ 306 psi, making 30 bwpd Brief Well Summary BRU 224-34T was drilled in the 2025 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 and BRU PA. Wellbore Conditions: - Max Inclination – 13° at 3,038’ MD - Cement top ~3830’ (CBL run 7/27/25) Procedure: 1. Review all COA’s for AOGCC & BLM 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: Sands Top MD Btm MD Top TVD Btm TVD Amt Top of Pool & PA per CO 802A: ~2,892’ MD/2,865’ TVD BEL D ±3,657' ±3,674' ±3,615' ±3,632' ±17' BEL D2 ±3,712' ±3,716' ±3,670' ±3,674' ±4' BEL D3 ±3,741' ±3,751' ±3,698' ±3,708' ±10' BEL D4 ±3,768' ±3,777' ±3,725' ±3,734' ±9' BEL D5 ±3,797' ±3,805' ±3,754' ±3,762' ±8' BEL D6 ±3,822' ±3,842' ±3,778' ±3,798' ±20' BEL D7 ±3,853' ±3,861' ±3,809' ±3,817' ±8' BEL E2 ±3,907' ±3,920' ±3,863' ±3,875' ±13' BEL E2 ±3,937' ±3,940' ±3,892' ±3,895' ±3' BEL E2 ±3,983' ±3,988' ±3,938' ±3,943' ±5' BEL E3 ±4,045' ±4,049' ±3,999' ±4,003' ±4' BEL E3 ±4,054' ±4,057' ±4,008' ±4,011' ±3' BEL E4 ±4,083' ±4,093' ±4,037' ±4,047' ±10' BEL E5 ±4,123' ±4,139' ±4,077' ±4,092' ±16' BEL E5 ±4,171' ±4,181' ±4,124' ±4,134' ±10' BEL E6 ±4,217' ±4,221' ±4,170' ±4,174' ±4' Well Prognosis 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 BEL E6 ±4,234' ±4,237' ±4,187' ±4,190' ±3' BEL F5 ±4,424’ ±4,430’ ±4,375’ ±4,381’ ±6’ BEL F5 ±4,439’ ±4,442’ ±4,390’ ±4,393’ ±3’ BEL F5 ±4,454’ ±4,457’ ±4,405’ ±4,408’ ±3’ Updated by CAH 09-15-25 SCHEMATIC Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PBTD = 5,546’ MD / TVD = 5,477’ TD = 6,007’ MD / TVD = 5,944’ RKB to GL = 19.7’ 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 P-110 GBCD 6.875”Surf 2,607’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”2,185’6,005’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,225’ 2/3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Liner Hanger w/ 4” Type H BPV profile 2 2,185’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,225’4” Bullet seal assembly, 0.92’ off no-go 4 5,546’CIBP set 8/19/25 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (351 sx) 12 ppg lead cement followed by 37 bbl (179 sx) 15.8 tail cement. Bumped plug at 113 bbls (calculated 116 bbls), spacer & 60 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 151 bbls (355 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 235 bbls during cement job (only had returns from 105 bbl & 140bbls pumped during lead) TOC @ 2832’based on CBL @ 8/9/25 Squeeze 8/1 Block squeeze 4 bbls @ 3630’ of 15.3 ppg cement Squeeze 8/4 Block squeeze 3 bbls @ 3625’ of 15.3 ppg cement with cement retainer, no returns Squeeze 8/6 Suicide squeeze 16 bbls @ 3330’ of 15.3 ppg cement, no return during squeeze using cement retainer Squeeze 8/7 Block squeeze 5 bbls @ 2910’ of 15.3 ppg cement Squeeze 8/9 Block squeeze 2 bbls @ 2870’ of 15.3ppg cement Squeeze 8/12 Block squeeze 3 bbls @ 2860’ of 15.3 ppg cement 6-3/4” hole Notes: 10’ Short jt w/ RA tags 5512, 4485, 3454 10’ Short joints 4998, 3970, 2938 Deviation 13.7deg @ 3038’, 3900-6007’ @ 7 deg RA 5512’ RA 3454’ RA 4485’ Bel F6 to Bel H11 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~2,892’ MD/2,865’ TVD Top of PA (BLM) NA/Punch 2,840’ 2,842’ 2,813’ 2,815’2 8/6/25 Squeezed NA/Punch 3,340’ 3,342’ 3,302’ 3,304’2 8/3/25 Squeezed NA/Punch 3,623’ 3,625’ 3,581’ 3,583’2 8/3/25 Squeezed NA/Punch 3,730’ 3,732’ 3,687’ 3,689’2 7/29/25 Squeezed Bel F6 4,508’ 4,525’ 4,458’ 4,475’ 17’9/19/25 Open Bel F7 4,640’ 4,650’ 4,588’ 4,598’ 10’9/19/25 Open BEL F8 4,745’ 4,751’ 4,693’ 4,699’ 6’ 8/24/25 Open BEL F10 4,801’ 4,807’ 4,748’ 4,754’ 6’ 8/24/25 Open BEL G5 5,005’ 5,017’ 4,951’ 4,963’ 12’ 8/23/25 Open BEL G10 5,173’ 5,189’ 5,117’ 5,133’ 16’ 8/23/25 Open BEL G10 5,197’ 5,201’ 5,141’ 5,145’ 4’ 8/23/25 Open BEL H 5,232' 5,236' 5,176' 5,180' 4' 8/23/25 Open BEL H 5,243' 5,249' 5,187' 5,193' 6' 8/22/25 Open BEL H1 5,291' 5,300' 5,234' 5,243' 9' 8/22/25 Open BEL H2 5,333’ 5,348’ 5,277’ 5,292’15 8/22/25 Open BEL H7 5,556' 5,562' 5,497' 5,503' 6' TBD Plugged BEL H11 5,718' 5,748' 5,657' 5,687'30’TBD Plugged Sidetrack TOW @ 2411’ TOC @ 2832’ 4 Updated by CAH 09-15-25 PB1 Schematic Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PB-1 Schematic Updated by CAH 1-22-26 PROPOSED Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PBTD = 5,546’ MD / TVD = 5,477’ TD = 6,007’ MD / TVD = 5,944’ RKB to GL = 19.7’ 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 P-110 GBCD 6.875”Surf 2,607’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”2,185’6,005’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,225’ 2/3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Liner Hanger w/ 4” Type H BPV profile 2 2,185’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,225’4” Bullet seal assembly, 0.92’ off no-go 4 5,546’CIBP set 8/19/25 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (351 sx) 12 ppg lead cement followed by 37 bbl (179 sx) 15.8 tail cement. Bumped plug at 113 bbls (calculated 116 bbls), spacer & 60 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 151 bbls (355 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 235 bbls during cement job (only had returns from 105 bbl & 140bbls pumped during lead) TOC @ 2832’based on CBL @ 8/9/25 Squeeze 8/1 Block squeeze 4 bbls @ 3630’ of 15.3 ppg cement Squeeze 8/4 Block squeeze 3 bbls @ 3625’ of 15.3 ppg cement with cement retainer, no returns Squeeze 8/6 Suicide squeeze 16 bbls @ 3330’ of 15.3 ppg cement, no return during squeeze using cement retainer Squeeze 8/7 Block squeeze 5 bbls @ 2910’ of 15.3 ppg cement Squeeze 8/9 Block squeeze 2 bbls @ 2870’ of 15.3ppg cement Squeeze 8/12 Block squeeze 3 bbls @ 2860’ of 15.3 ppg cement 6-3/4” hole Notes: 10’ Short jt w/ RA tags 5512, 4485, 3454 10’ Short joints 4998, 3970, 2938 Deviation 13.7deg @ 3038’, 3900-6007’ @ 7 deg RA 5512’ RA 3454’ RA 4485’ Bel F6 to Bel H11 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~2,892’ MD/2,865’ TVD Top of PA (BLM) NA/Punch 2,840’ 2,842’ 2,813’ 2,815’2 8/6/25 Squeezed NA/Punch 3,340’ 3,342’ 3,302’ 3,304’2 8/3/25 Squeezed NA/Punch 3,623’ 3,625’ 3,581’ 3,583’2 8/3/25 Squeezed BEL D ±3,657' ±3,674' ±3,615' ±3,632' ±17' TBD Proposed BEL D2 ±3,712' ±3,716' ±3,670' ±3,674' ±4' TBD Proposed NA/Punch 3,730’ 3,732’ 3,687’ 3,689’2 7/29/25 Squeezed BEL D3 ±3,741' ±3,751' ±3,698' ±3,708' ±10' TBD Proposed BEL D4 ±3,768' ±3,777' ±3,725' ±3,734' ±9' TBD Proposed BEL D5 ±3,797' ±3,805' ±3,754' ±3,762' ±8' TBD Proposed BEL D6 ±3,822' ±3,842' ±3,778' ±3,798' ±20' TBD Proposed BEL D7 ±3,853' ±3,861' ±3,809' ±3,817' ±8' TBD Proposed BEL E2 ±3,907' ±3,920' ±3,863' ±3,875' ±13' TBD Proposed BEL E2 ±3,937' ±3,940' ±3,892' ±3,895' ±3' TBD Proposed BEL E2 ±3,983' ±3,988' ±3,938' ±3,943' ±5' TBD Proposed BEL E3 ±4,045' ±4,049' ±3,999' ±4,003' ±4' TBD Proposed BEL E3 ±4,054' ±4,057' ±4,008' ±4,011' ±3' TBD Proposed BEL E4 ±4,083' ±4,093' ±4,037' ±4,047' ±10' TBD Proposed BEL E5 ±4,123' ±4,139' ±4,077' ±4,092' ±16' TBD Proposed Perforations Continued on Page 2 Sidetrack TOW @ 2411’ TOC @ 2832’ 4 Updated by CAH 01-22-26 PB1 Schematic & Perfs Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PB-1 Schematic PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL E5 ±4,171' ±4,181' ±4,124' ±4,134' ±10' TBD Proposed BEL E6 ±4,217' ±4,221' ±4,170' ±4,174' ±4' TBD Proposed BEL E6 ±4,234' ±4,237' ±4,187' ±4,190' ±3' TBD Proposed BEL F5 ±4,424’ ±4,430’ ±4,375’ ±4,381’ ±6’ TBD Proposed BEL F5 ±4,439’ ±4,442’ ±4,390’ ±4,393’ ±3’ TBD Proposed BEL F5 ±4,454’ ±4,457’ ±4,405’ ±4,408’ ±3’ TBD Proposed Bel F6 4,508’ 4,525’ 4,458’ 4,475’ 17’ 9/19/25 Open Bel F7 4,640’ 4,650’ 4,588’ 4,598’ 10’ 9/19/25 Open BEL F8 4,745’ 4,751’ 4,693’ 4,699’ 6’ 8/24/25 Open BEL F10 4,801’ 4,807’ 4,748’ 4,754’ 6’ 8/24/25 Open BEL G5 5,005’ 5,017’ 4,951’ 4,963’ 12’ 8/23/25 Open BEL G10 5,173’ 5,189’ 5,117’ 5,133’ 16’ 8/23/25 Open BEL G10 5,197’ 5,201’ 5,141’ 5,145’ 4’ 8/23/25 Open BEL H 5,232' 5,236' 5,176' 5,180' 4' 8/23/25 Open BEL H 5,243' 5,249' 5,187' 5,193' 6' 8/22/25 Open BEL H1 5,291' 5,300' 5,234' 5,243' 9' 8/22/25 Open BEL H2 5,333’ 5,348’ 5,277’ 5,292’ 15 8/22/25 Open BEL H7 5,556' 5,562' 5,497' 5,503' 6' TBD Plugged BEL H11 5,718' 5,748' 5,657' 5,687' 30’ TBD Plugged 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: 11/14/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251114 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# PBU 01-10A 50029201690200 225055 8/29/2025 BAKER MRPM BRU 224-34T 50283202050000 225044 8/9/2025 AK E-LINE CBL MGS ST 17595 30 50733204560000 193120 8/13/2025 AK E-LINE CBL MPU H-11 50029228020000 197163 8/17/2025 AK E-LINE JetCut PCU D-10 50283202080000 225082 10/6/2025 AK E-LINE CBL Please include current contact information if different from above. T41100 T41101 T41102 T41103 T41104 BRU 224-34T 50283202050000 225044 8/9/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.14 12:58:13 -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: 10/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251002 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF T40937 BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF T40938 BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF T49038 BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG T40938 BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF T40939 BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF T40940 BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf T40941 BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch T40942 BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf T40942 END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF T40943 END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF T40944 END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF T40945 KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf T40946 KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF T40947 KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF T40948 KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf T40948 MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL T40949 MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL T40950 MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf T40951 MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf T40952 NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL T40953 NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF T40954 PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL T40955 PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL T40956 SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf T40957 SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf T40958 SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf T40958 Please include current contact information if different from above. T40942BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.03 09:00:56 -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: 09/12/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250912 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40 END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40 END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24 NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey Please include current contact information if different from above. T40874 T40875 T40875 T40875 T40875 T40876 T40877 T40878 T40879 T40879 T40880 T40881 T40882 T40883 T40884 T40885 T40886 T40887 T40888 T40889 T40890 T40891 T40892 T40893 BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.12 14:33:03 -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: 08/26/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250826 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF T40803 BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist T40804 BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf T40804 BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf T40804 BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf T40805 BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf T40805 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch T40806 KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf T40807 MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey T40808 NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf T40809 ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey T40810 PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG T40811 PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG T40812 PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT T40813 PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG T40814 PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG T40815 PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG T40816 PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf T40817 SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf T40818 WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer T40819 Please include current contact information if different from above. T40806BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL T40806BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL T40806BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL T40806BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.27 08:12:23 -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: 08/21/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 224-34T + PB1 PTD: 225-44 API: 50-283-20205-00-00 (BRU 224-34T) API: 50-283-20205-70-00 (BRU 224-34TPB1) FINAL MUDLOGS - EOW DRILLING REPORTS (07/14/2025 to 07/19/2025) 1. FINAL EOW REPORT 2. DAILY REPORTS 3. DIGITAL DATA (LAS) 4. LITHOLOGY DESCRIPTIONS 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Data Folders: Please include current contact information if different from above. T40796 T40797 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.22 08:24:56 -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: 08/21/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 224-34T + PB1 PTD: 225-44 API: 50-283-20205-00-00 (BRU 224-34T) API: 50-283-20205-70-00 (BRU 224-34TPB1) FINAL LWD FORMATION EVALUATION LOGS (07/01/2025 to 07/20/2025) ROP, BaseStar GR, ADR and StrataStar Resistivity, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Main Folder Contents: Sub-Folder Contents: Please include current contact information if different from above. T40796 T40797 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.22 08:24:40 -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:McLellan, Bryan J (OGC) To:Chad Helgeson; Maercklein, William C Cc:Donna Ambruz; Ryan Lemay; Joshua Stephenson - (C) Subject:RE: BRU 224-34T (PTD# 225-044) Sundry #225-441 Additional Perf interval Date:Thursday, August 14, 2025 2:26:00 PM Chad, Additional perf interval is approved. 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: Wednesday, August 13, 2025 4:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Maercklein, William C <wmaercklein@blm.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Ryan Lemay <Ryan.Lemay@hilcorp.com>; Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com> Subject: BRU 224-34T (PTD# 225-044) Sundry #225-441 Additional Perf interval Hilcorp would like to add one additional zone to our proposed perf interval in BRU 224-34T. We would like to add the Beluga H2 (5333-5348). This zone is in between the proposed perfs already approved. We expect the same pressure regimen as the other Beluga H sands. We expect we will add this zone potentially on Sunday when we start perforating if all our cement squeeze zones pass our pressure test, which we expect to test again on Friday this week. Please let us know if we can add this zone to our planned perforations. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. 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:McLellan, Bryan J (OGC) To:Chad Helgeson; Maercklein, William C; Garcia, Stephen B Cc:Donna Ambruz; Joshua Stephenson - (C) Subject:RE: BRU 224-34T (PTD# 225-044) Remedial Squeeze bond log & plan forward Date:Monday, August 11, 2025 10:58:00 AM Chad, Hilcorp has approval to proceed with perforating all intervals requested in sundry 325-441. 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: Monday, August 11, 2025 9:43 AM To: Maercklein, William C <wmaercklein@blm.gov>; Garcia, Stephen B <sbgarcia@blm.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com> Subject: BRU 224-34T (PTD# 225-044) Remedial Squeeze bond log & plan forward Please find attached the field cement bond log we ran after all of our squeeze work on BRU 224-34T. Below are the highlights of the work completed to date: Squeeze #1 Pumped 3 bbl block squeeze at 3730’ Drilled plug and ran CBL – signs of cement up to 3640’ Squeeze #2 Pumped 3bbl suicide squeeze from 3625-3342’ No circulation during squeeze Drilled out plugs & retainer ran CBL – signs of good cement up to 3490’ Squeeze #3 Pumped 16.5 bbl suicide squeeze from 3342’ to 2840’ Small dribble of returns during job, but circulated mud after unsting from retainer Squeeze #4 Pumped 5bbl block squeeze Drilled out cement, retainer from #3 squeeze and chased to bottom Ran CBL, showing Squeeze #3 TOC @ 3070’ and Squeeze #4 TOC @ 2514’ Squeeze/cement plug #5 Pumped and laid in 2bbl of cement at 2840’ Plan forward: Perform pressure test on cement plug (test tubing & liner above cement) Drill out cement plug to 2855’ (perform pressure test on tubing & liner to 1500 psi) Drill out remaining cement & composite plug (@ 2870’) Cleanout well to bottom Blow well dry with N2 Start perforating program in Beluga H sands I do not plan to run another bond log as I feel we have successfully remediated the cement behind pipe over the Pool/PA. Please let me know if you need any additional steps taken before we start perforating and flowing the well. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. 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: Intial 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): 6,007'N/A Casing Collapse Structural Conductor 1,410psi Surface Intermediate 4,790psi 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 FEDA029656 225-044 50-283-20205-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,225' 10,160psi 5,987' Size 120' 2,607' MD See Attached Schematic 6,890psi 2,980psi120'120' 2,607' July 28, 2025 Tieback 3-1/2" 6,007' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 224-34TCO 802A Same 5,944'3-1/2" ~2665psi 3,785' N/A Length Scout Pkr; N/A 2,190' MD / 2,174' TVD; N/A, N/A 5,944'5,943'5,881' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic 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 1:40 pm, Jul 25, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.25 12:18:55 - 08'00' Noel Nocas (4361) 325-441 2587' -bjm 10-407 Submit Post-cement squeeze CBL and obtain AOGCC approval before perforating shallower than 3890' MD. BJM 7/28/25 A.Dewhurst 29JUL25JLC 7/29/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.29 14:18:12 -08'00'07/29/25 RBDMS JSB 073125 Well Prognosis Well Name: BRU 224-34T API Number: 50-283-20205-00-00 Current Status: New Drill Well Permit to Drill Number: 225-044 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Maximum Expected BHP: 2665 psi @ 5794’ TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2375 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.756 psi/ft using 14.55 ppg EMW FIT at the 7-5/8” surface casing window Shallowest Potential Perf TVD: MPSP/(0.756-0.05) = 2375 psi / 0.706 = 3364’ TVD Top of SBGP (CO 802A): ~2892’ MD/~2865’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary BRU 213-26T is the third of five grass roots well to be drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. During the drilling of the well the well went on losses and while remediating the losses with cement, the drill pipe became stuck and was cemented in place, up inside the surface casing shoe. A CIBP was set in the surface casing, with a whip stock and the well was sidetracked from the surface casing. While drilling production interval again, the well went on losses at same interval at 3948ft. The losses were healed with one successful remedial cement squeeze and the well was successfully drilled to TD as planned and liner was run to bottom. The well was on complete losses while pumping the liner cement (only gained returns during the job for 33 bbls of the 176bbls of cement pumped. The objective of this sundry is to confirm cement location and remediate as necessary to above the top of the pool. Shallowest potential pay zone in the well is 2992-2999ft, which will be target for any cement remediation necessary. Once cement remedial cement is confirmed, the well will be blown dry and perforated. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination – 13° at 3,038’ MD - T & IA PT to 3000 psi (30 min) - Min ID- 2.992” 3-1/2” tubing/liner - Liner filled with 9.4 ppg drilling mud, tubing is filled with 8.4 ppg water - Top Of Pool per CO : ~2892’ MD/~2865’ TVD Work to be completed on PTD# 225-044 Step 20: - Eline run CBL (submit to AOGCC and BLM for review) Squeeze Procedure (If necessary based on CBL data – if no cement is above 2850’): Depths listed below in procedure are estimated based on predicted loss zone at 3948’, but will change depending on CBL results, volumes of cement will also adjust pending CBL results. 1. Review all approved COAs (BLM & AOGCC) 2. Provide AOGCC 48hrs notice for CT BOP Test 3. RU E-line, PT Lubricator to 2500 psi 4. Set CBP for coil depth control above TOC est at ~3850’ 5. PU tubing punch and shoot squeeze holes at ~3840’ 6. MIRU Coiled Tubing & cement equipment, PT BOPE & cement equipment to 3000 psi. Superseded Well Prognosis 7. RIH with cement nozzle pumping 6% KCl at min rate, when pressure increases (indicates fluid level), tag CBP, taking returns then establish an injection rate 8. Mix ~8bbls of 15.3# Class I cement 9. Pump ~6 bbls of 15.3# cement & displace with 6%KCl (coil volume) 10. PU to ~ 3500’ Pressure up to 100psi, establish leak off, pump ~1-2 bbls pending engineers request (hesitation block squeeze). Bleed pressure off well. 11. POOH and wait for cement to set up 12. RIH w/ milling BHA and bit (preference is tri-cone bit) 13. Tag cement, drillout and drill up CBP 14. RIH to PBTD & circ out drilling mud and displace to fresh water 15. RU Eline (PT to 2500 psi) 16. Make CBL run (might need temp analysis to determine TOC) 17. PU CBP & RIH and set above TOC from block squeeze (Est. ~3800’) 18. PU tubing punch and punch holes ~ 10ft above CBP 19. Add additional tubing punch holes for suicide squeeze (est 300ft above previous tubing punch) 20. Coil tubing PU and RIH w/ cement retainer, tag for depth control, PU & set at ~3780’ 21. Establish circulation 22. Mix and pump annular volume of cement (~10.3 bbls) a. 6.75” hole x 3.5” liner = 0.0324 bbl/ft b. 300ft x 0.0324bbl/ft = 9.7 bbls 23. Unsting with 10bbls pump and lay 0.25 bbls on top of retainer (~25ft) 24. TOOH to upper squeeze holes, lay in 1.5-2 bbls of cement (~200’) cement above upper holes 25. PU to 3200ft & Circulate clean, TOOH, WOC (12hr min) 26. PU motor and mill, drill out cement, retainer & composite plug 27. Log CBL, send to AOGCC & BLM a. Repeat steps 17-26 until cement is above top of pool, or unable to squeeze or get circulation 28. Once CBL is complete and cement is confirmed, Coil blow well dry with N2, leaving perf pressure on well when complete (est 1800-2000psi) 29. MIRU E-line and pressure control equipment 30. PT lubricator to 250 psi low / 2,500 psi high 31. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 32. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sands may be added/removed depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD Amt BEL D ±3,657' ±3,674' ±3,615' ±3,632' ±17' BEL D2 ±3,712' ±3,716' ±3,670' ±3,674' ±4' BEL D3 ±3,741' ±3,751' ±3,698' ±3,708' ±10' BEL D4 ±3,768' ±3,777' ±3,725' ±3,734' ±9' BEL D5 ±3,797' ±3,804' ±3,754' ±3,761' ±7' BEL D6 ±3,822' ±3,842' ±3,778' ±3,798' ±20' BEL D7 ±3,853' ±3,861' ±3,809' ±3,817' ±8' BEL E2 ±3,907' ±3,920' ±3,863' ±3,875' ±13' BEL E2 ±3,938' ±3,940' ±3,893' ±3,895' ±2' BEL E2 ±3,983' ±3,988' ±3,938' ±3,943' ±5' Superseded Well Prognosis BEL E3 ±4,045' ±4,049' ±3,999' ±4,003' ±4' BEL E3 ±4,055' ±4,057' ±4,009' ±4,011' ±2' BEL E4 ±4,083' ±4,093' ±4,037' ±4,047' ±10' BEL E5 ±4,123' ±4,139' ±4,077' ±4,092' ±16' BEL E5 ±4,171' ±4,181' ±4,124' ±4,134' ±10' BEL E6 ±4,218' ±4,221' ±4,171' ±4,174' ±3' BEL E6 ±4,234' ±4,237' ±4,187' ±4,190' ±3' BEL E6 ±4,241’ ±4,261’ ±4,194’ ±4,213’ ±20' BEL F1 ±4,283’ ±4,288’ ±4,235’ ±4,240’ ±5’ BEL F1 ±4,294’ ±4,304’ ±4,246’ ±4,256’ ±10’ BEL F4 ±4,342’ ±4,346’ ±4,294’ ±4,298’ ±4’ BEL F4 ±4,378’ ±4,383’ ±4,329’ ±4,334’ ±5’ BEL F5 ±4,424’ ±4,431’ ±4,375’ ±4,382’ ±7’ BEL F5 ±4,439’ ±4,442’ ±4,390’ ±4,393’ ±3’ BEL F5 ±4,454’ ±4,457’ ±4,405’ ±4,408’ ±3’ BEL F6 ±4,508’ ±4,525’ ±4,458’ ±4,475’ ±17’ BEL F7 ±4,640’ ±4,650’ ±4,589’ ±4,599’ ±10’ BEL F7 ±4,682’ ±4,689’ ±4,630’ ±4,637’ ±7’ BEL F8 ±4,745’ ±4,752’ ±4,693’ ±4,700’ ±7’ BEL F10 ±4,801’ ±4,808’ ±4,748’ ±4,755’ ±7’ BEL G3 ±4,938’ ±4,948’ ±4,884’ ±4,894’ ±10’ BEL G5 ±5,005’ ±5,028’ ±4,951’ ±4,973’ ±23’ BEL G10 ±5,173’ ±5,189’ ±5,117’ ±5,133’ ±16’ BEL G0 ±5,197’ ±5,201’ ±5,141’ ±5,145’ ±4’ BEL H ±5,232' ±5,236' ±5,176' ±5,180' ±4' BEL H ±5,243' ±5,250' ±5,187' ±5,194' ±7' BEL H1 ±5,291' ±5,300' ±5,234' ±5,243' ±9' BEL H7 ±5,556' ±5,562' ±5,497' ±5,503' ±6' BEL H11 ±5,718' ±5,748' ±5,657' ±5,687' ±30' BEL H13 ±5,844' ±5,856' ±5,782' ±5,794' ±12' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations (if necessary) i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 33. RDMO 34. Turn well over to production & flow test well 35. Test SVS as necessary once well has reached stable flow rates a. Notify state 48 hrs prior to testing within 5 days of stable production Attachments: 1. Current Schematic Superseded Well Prognosis 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations Superseded Well Prognosis Rev 1 Well Name: BRU 224-34T API Number: 50-283-20205-00-00 Current Status: New Drill Well Permit to Drill Number: 225-044 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Maximum Expected BHP: 2665 psi @ 5794’ TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2375 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.756 psi/ft using 14.55 ppg EMW FIT at the 7-5/8” surface casing window Shallowest Potential Perf TVD: MPSP/(0.756-0.05) = 2375 psi / 0.706 = 3364’ TVD Top of SBGP (CO 802A): ~2892’ MD/~2865’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary BRU 213-26T is the third of five grass roots well to be drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. During the drilling of the well the well went on losses and while remediating the losses with cement, the drill pipe became stuck and was cemented in place, up inside the surface casing shoe. A CIBP was set in the surface casing, with a whip stock and the well was sidetracked from the surface casing. While drilling production interval again, the well went on losses at same interval at 3948ft. The losses were healed with one successful remedial cement squeeze and the well was successfully drilled to TD as planned and liner was run to bottom. The well was on complete losses while pumping the liner cement (only gained returns during the job for 33 bbls of the 176bbls of cement pumped. The objective of this sundry is to confirm cement location and remediate as necessary to above the top of the pool. Shallowest potential pay zone in the well is 2992-2999ft, which will be target for any cement remediation necessary. Once cement remedial cement is confirmed, the well will be blown dry and perforated. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination – 13° at 3,038’ MD - T & IA PT to 3000 psi (30 min) - Min ID- 2.992” 3-1/2” tubing/liner - Cement top ~3830’ (CBL run 7/27/25) - Liner filled with 9.4 ppg drilling mud, tubing is filled with 8.4 ppg water - Top Of Pool per CO : ~2892’ MD/~2865’ TVD Work to be completed on PTD# 225-044 Step 20: - Eline run CBL (submit to AOGCC and BLM for review) Squeeze Procedure: 1. Review all approved COAs (BLM & AOGCC) 2. Provide AOGCC 48hrs notice for CT BOP Test 3. RU E-line, PT Lubricator to 2500 psi 4. Set CBP for coil depth control above TOC est at ~3640’ 5. PU tubing punch and shoot squeeze holes at ~3630’ 6. MIRU Coiled Tubing & cement equipment, PT BOPE & cement equipment to 3000 psi. 7. RIH with cement nozzle pumping 6% KCl at min rate, when pressure increases (indicates fluid level), tag CBP, taking returns then establish an injection rate. Well Prognosis Rev 1 a. If unable to get injectivity for block squeeze a suicide squeeze may be performed for the 1st squeeze attempt. With upper perfs at 3500’ (following steps 20-27 below) 8. Mix ~8bbls of 15.3# Class I cement 9. Pump ~6 bbls of 15.3# cement & displace with 6%KCl (coil volume) 10. PU to ~ 3500’ Pressure up to 100psi, establish leak off, pump ~1-2 bbls pending engineers request (hesitation block squeeze). Bleed pressure off well. 11. POOH and wait for cement to set up 12. RIH w/ milling BHA and bit (preference is tri-cone bit) 13. Tag cement, drillout and drill up CBP 14. RIH to PBTD & circ out drilling mud and displace to fresh water 15. RU Eline (PT to 2500 psi) 16. Make CBL run (might need temperature analysis to determine TOC) 17. PU CBP & RIH and set above TOC from block squeeze (Est. ~3600’) 18. PU tubing punch and punch holes ~ 10ft above CBP 19. Add additional tubing punch holes for suicide squeeze (est 300ft above previous tubing punch @ ~3300’) 20. Coil tubing PU and RIH w/ cement retainer, tag for depth control, PU & set at ~3585’ 21. Establish circulation 22. Mix and pump annular volume of cement (~10.3 bbls) a. 6.75” hole x 3.5” liner = 0.0324 bbl/ft b. 300ft x 0.0324bbl/ft = 9.7 bbls 23. Unsting with 10bbls pump and lay 0.25 bbls on top of retainer (~25ft) 24. TOOH to upper squeeze holes, lay in 1.5-2 bbls of cement (~200’) cement above upper holes 25. PU to 2800’ & Circulate clean, TOOH, WOC (12hr min) 26. PU motor and bit, drill out cement, retainer & composite plug 27. Log CBL, send to AOGCC & BLM a. Repeat steps 17-26 until cement is above top of pool, or unable to squeeze or get circulation 28. Once CBL is complete and cement is confirmed, Coil blow well dry with N2, leaving perf pressure on well when complete (est 1800-2000psi) 29. MIRU E-line and pressure control equipment 30. PT lubricator to 250 psi low / 2,500 psi high 31. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 32. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sands may be added/removed depending on results of these perfs, between the proposed top and bottom perfs Will not perforate above Beluga E2 sands until cement is confirmed above proposed perfs. Sands Top MD Btm MD Top TVD Btm TVD Amt BEL D ±3,657' ±3,674' ±3,615' ±3,632' ±17' BEL D2 ±3,712' ±3,716' ±3,670' ±3,674' ±4' BEL D3 ±3,741' ±3,751' ±3,698' ±3,708' ±10' BEL D4 ±3,768' ±3,777' ±3,725' ±3,734' ±9' BEL D5 ±3,797' ±3,804' ±3,754' ±3,761' ±7' BEL D6 ±3,822' ±3,842' ±3,778' ±3,798' ±20' BEL D7 ±3,853' ±3,861' ±3,809' ±3,817' ±8' BEL E2 ±3,907' ±3,920' ±3,863' ±3,875' ±13' BEL E2 ±3,938' ±3,940' ±3,893' ±3,895' ±2' Well Prognosis Rev 1 BEL E2 ±3,983' ±3,988' ±3,938' ±3,943' ±5' BEL E3 ±4,045' ±4,049' ±3,999' ±4,003' ±4' BEL E3 ±4,055' ±4,057' ±4,009' ±4,011' ±2' BEL E4 ±4,083' ±4,093' ±4,037' ±4,047' ±10' BEL E5 ±4,123' ±4,139' ±4,077' ±4,092' ±16' BEL E5 ±4,171' ±4,181' ±4,124' ±4,134' ±10' BEL E6 ±4,218' ±4,221' ±4,171' ±4,174' ±3' BEL E6 ±4,234' ±4,237' ±4,187' ±4,190' ±3' BEL E6 ±4,241’ ±4,261’ ±4,194’ ±4,213’ ±20' BEL F1 ±4,283’ ±4,288’ ±4,235’ ±4,240’ ±5’ BEL F1 ±4,294’ ±4,304’ ±4,246’ ±4,256’ ±10’ BEL F4 ±4,342’ ±4,346’ ±4,294’ ±4,298’ ±4’ BEL F4 ±4,378’ ±4,383’ ±4,329’ ±4,334’ ±5’ BEL F5 ±4,424’ ±4,431’ ±4,375’ ±4,382’ ±7’ BEL F5 ±4,439’ ±4,442’ ±4,390’ ±4,393’ ±3’ BEL F5 ±4,454’ ±4,457’ ±4,405’ ±4,408’ ±3’ BEL F6 ±4,508’ ±4,525’ ±4,458’ ±4,475’ ±17’ BEL F7 ±4,640’ ±4,650’ ±4,589’ ±4,599’ ±10’ BEL F7 ±4,682’ ±4,689’ ±4,630’ ±4,637’ ±7’ BEL F8 ±4,745’ ±4,752’ ±4,693’ ±4,700’ ±7’ BEL F10 ±4,801’ ±4,808’ ±4,748’ ±4,755’ ±7’ BEL G3 ±4,938’ ±4,948’ ±4,884’ ±4,894’ ±10’ BEL G5 ±5,005’ ±5,028’ ±4,951’ ±4,973’ ±23’ BEL G10 ±5,173’ ±5,189’ ±5,117’ ±5,133’ ±16’ BEL G0 ±5,197’ ±5,201’ ±5,141’ ±5,145’ ±4’ BEL H ±5,232' ±5,236' ±5,176' ±5,180' ±4' BEL H ±5,243' ±5,250' ±5,187' ±5,194' ±7' BEL H1 ±5,291' ±5,300' ±5,234' ±5,243' ±9' BEL H7 ±5,556' ±5,562' ±5,497' ±5,503' ±6' BEL H11 ±5,718' ±5,748' ±5,657' ±5,687' ±30' BEL H13 ±5,844' ±5,856' ±5,782' ±5,794' ±12' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations (if necessary) i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 33. RDMO 34. Turn well over to production & flow test well 35. Test SVS as necessary once well has reached stable flow rates a. Notify state 48 hrs prior to testing within 5 days of stable production Attachments: Well Prognosis Rev 1 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations Updated by CAH 07-25-25 SCHEMATIC Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PBTD = 5,943’ MD / TVD = 5,881’ TD = 6,007’ MD / TVD = 5,944’ RKB to GL = 19.7’ 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 P-110 GBCD 6.875”Surf 2607’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”2,224’6,007’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,225’ 2/3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Liner Hanger w/ 4” Type H BPV profile 2 2,190’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,225’4” Bullet seal assembly, .92’ off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (351 sx) 12 ppg lead cement followed by 37 bbl (179 sx) 15.8 tail cement. Bumped plug at 113 bbls (calculated 116 bbls), spacer & 60 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 151 bbls (355 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 235 bbls during cement job (only had returns from 105 bbl & 140bbls pumped during lead) TOC based on CBL @ ??? 6-3/4” hole Notes: 10’ Short jt w/ RA tags 5512, 4485, 3454 10’ Short joints 4998, 3970, 2938 Deviation 13.7deg @ 3038’, 3900-6007’ @ 7 deg RA 5512’ RA 3454’ RA 4485’ 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~2,892’ MD/2,865’ TVD Top of PA (BLM) Sidetrack TOW @ 2411’ TOC TBD Updated by CAH 07-25-25 PROPOSED Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PB-1 Schematic Updated by DMA 07-24-25 PROPOSED Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PBTD = 5,943’ MD / TVD = 5,881’ TD = 6,007’ MD / TVD = 5,944’ RKB to GL = 19.7’ 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 P-110 GBCD 6.875”Surf 2607’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”2,224’6,007’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,225’ 2/3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Liner Hanger w/ 4” Type H BPV profile 2 2,190’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,225’4” Bullet seal assembly, .92’ off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (351 sx) 12 ppg lead cement followed by 37 bbl (179 sx) 15.8 tail cement. Bumped plug at 113 bbls (calculated 116 bbls), spacer & 60 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 151 bbls (355 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 235 bbls during cement job (only had returns from 105 bbl & 140bbls pumped during lead) TOC based on CBL @ ??? 6-3/4” hole Notes: 10’ Short jt w/ RA tags 5512, 4485, 3454 10’ Short joints 4998, 3970, 2938 Deviation 13.7deg @ 3038’, 3900-6007’ @ 7 deg Squeeze #1 Block squeeze through punch at xxxx-xxxx’. Xx bbls of cement on backside (xxft of cement). CBL shows TOC @ xxxx’. Squeeze #2 Suicide Squeeze from perfs at xxxx to perfs at xxxx’, with hesitation squeeze on top. CBL shows TOC @ xxxx’. RA 5512’ RA 3454’ RA 4485’ Bel D to Bel H13 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~2,892’ MD/2,865’ TVD Top of PA (BLM) NA/Punch xxxx xxxx xxxx xxxx 4 TBD Proposed NA/Punch xxxx xxxx xxxx xxxx 4 TBD Proposed NA/Punch xxxx xxxx xxxx xxxx 4 TBD Proposed BEL D ±3,657'±3,674'±3,615'±3,632'±17'TBD Proposed BEL D2 ±3,712'±3,716'±3,670'±3,674'±4'TBD Proposed BEL D3 ±3,741'±3,751'±3,698'±3,708'±10'TBD Proposed BEL D4 ±3,768'±3,777'±3,725'±3,734'±9'TBD Proposed BEL D5 ±3,797'±3,804'±3,754'±3,761'±7'TBD Proposed BEL D6 ±3,822'±3,842'±3,778'±3,798'±20'TBD Proposed BEL D7 ±3,853'±3,861'±3,809'±3,817'±8'TBD Proposed BEL E2 ±3,907'±3,920'±3,863'±3,875'±13'TBD Proposed BEL E2 ±3,938'±3,940'±3,893'±3,895'±2'TBD Proposed BEL E2 ±3,983'±3,988'±3,938'±3,943'±5'TBD Proposed BEL E3 ±4,045'±4,049'±3,999'±4,003'±4'TBD Proposed BEL E3 ±4,055'±4,057'±4,009'±4,011'±2'TBD Proposed BEL E4 ±4,083'±4,093'±4,037'±4,047'±10'TBD Proposed BEL E5 ±4,123'±4,139'±4,077'±4,092'±16'TBD Proposed BEL E5 ±4,171'±4,181'±4,124'±4,134'±10'TBD Proposed BEL E6 ±4,218'±4,221'±4,171'±4,174'±3'TBD Proposed BEL E6 ±4,234'±4,237'±4,187'±4,190'±3'TBD Proposed BEL E6 ±4,241’±4,261’±4,194’±4,213’±20'TBD Proposed BEL F1 ±4,283’±4,288’±4,235’±4,240’±5’TBD Proposed PERFORATION DETAIL - Continued on Following Page Sidetrack TOW @ 2411’ TOC TBD Updated by DMA 07-24-25 PROPOSED Beluga River Unit BRU 224-34T PTD: 225-044 API: 50-283-20205-00-00 PB-1 Schematic PERFORATION DETAIL – Continued from Previous Page Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL F1 ±4,294’ ±4,304’ ±4,246’ ±4,256’ ±10’ TBD Proposed BEL F4 ±4,342’ ±4,346’ ±4,294’ ±4,298’ ±4’ TBD Proposed BEL F4 ±4,378’ ±4,383’ ±4,329’ ±4,334’ ±5’ TBD Proposed BEL F5 ±4,424’ ±4,431’ ±4,375’ ±4,382’ ±7’ TBD Proposed BEL F5 ±4,439’ ±4,442’ ±4,390’ ±4,393’ ±3’ TBD Proposed BEL F5 ±4,454’ ±4,457’ ±4,405’ ±4,408’ ±3’ TBD Proposed BEL F6 ±4,508’ ±4,525’ ±4,458’ ±4,475’ ±17’ TBD Proposed BEL F7 ±4,640’ ±4,650’ ±4,589’ ±4,599’ ±10’ TBD Proposed BEL F7 ±4,682’ ±4,689’ ±4,630’ ±4,637’ ±7’ TBD Proposed BEL F8 ±4,745’ ±4,752’ ±4,693’ ±4,700’ ±7’ TBD Proposed BEL F10 ±4,801’ ±4,808’ ±4,748’ ±4,755’ ±7’ TBD Proposed BEL G3 ±4,938’ ±4,948’ ±4,884’ ±4,894’ ±10’ TBD Proposed BEL G5 ±5,005’ ±5,028’ ±4,951’ ±4,973’ ±23’ TBD Proposed BEL G10 ±5,173’ ±5,189’ ±5,117’ ±5,133’ ±16’ TBD Proposed BEL G0 ±5,197’ ±5,201’ ±5,141’ ±5,145’ ±4’ TBD Proposed BEL H ±5,232' ±5,236' ±5,176' ±5,180' ±4' TBD Proposed BEL H ±5,243' ±5,250' ±5,187' ±5,194' ±7' TBD Proposed BEL H1 ±5,291' ±5,300' ±5,234' ±5,243' ±9' TBD Proposed BEL H7 ±5,556' ±5,562' ±5,497' ±5,503' ±6' TBD Proposed BEL H11 ±5,718' ±5,748' ±5,657' ±5,687' ±30' TBD Proposed BEL H13 ±5,844' ±5,856' ±5,782' ±5,794' ±12' TBD Proposed 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. 1 McLellan, Bryan J (OGC) From:Chad Helgeson <chelgeson@hilcorp.com> Sent:Monday, July 28, 2025 10:55 AM To:McLellan, Bryan J (OGC); Joshua Stephenson - (C) Cc:Donna Ambruz; Noel Nocas Subject:BRU 224-34T (PTD # 225-044) CBL & revised cement plan Attachments:BRU_224-34T_CBL_27-Jul-2025_(5581)_FieldPrint.zip; BRU 224-34T Initial Completion - July 2025 Rev 1.pdf Bryan, Attached is the CBL from this weekend on BRU 224-34T. We did get cement over most of our target intervals and objectives of the well and very close to where we predicted the TOC to be. We would still like to attempt a remedial squeeze as soon as possible, setting plug and punching tubing starting tomorrow (pending agency approval), with the attached procedure, in which the depths were modiƱed from the original procedure in the sundry application. If requested we will provide you with updated CBLs as we execute the work or we can submit a Ʊnal CBL once we have remediated as far as we choose to go, prior to perforating any intervals in the well. The correct depth for the surface casing TVD is 2586’ in Box 11 of the 10-403. (Sorry I missed that one) Please give me a call or shoot me an email today if you have any questions on the plan or the bond log. 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 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. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: This email originated from outside 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:McLellan, Bryan J (OGC) To:Chad Helgeson; Joshua Stephenson - (C) Cc:Donna Ambruz; Noel Nocas; Dewhurst, Andrew D (OGC) Subject:RE: BRU 224-34T (PTD # 225-044) CBL & revised cement plan Date:Tuesday, July 29, 2025 10:50:00 AM Chad, Hilcorp has verbal approval to proceed with the remedial cementing operations. Condition of approval: Submit the post-cement CBL to AOGCC and obtain approval before perforating. 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: Monday, July 28, 2025 10:55 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: BRU 224-34T (PTD # 225-044) CBL & revised cement plan Bryan, Attached is the CBL from this weekend on BRU 224-34T. We did get cement over most of our target intervals and objectives of the well and very close to where we predicted the TOC to be. We would still like to attempt a remedial squeeze as soon as possible, setting plug and punching tubing starting tomorrow (pending agency approval), with the attached procedure, in which the depths were modified from the original procedure in the sundry application. If requested we will provide you with updated CBLs as we execute the work or we can submit a final CBL once we have remediated as far as we choose to go, prior to perforating any intervals in the well. The correct depth for the surface casing TVD is 2586’ in Box 11 of the 10-403. (Sorry I missed that one) Please give me a call or shoot me an email today if you have any questions on the plan or the bond log. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20250715 0754 PTD 225-044 Hilcorp Well BRU 224-34T_ Casing Test & FIT Data Date:Tuesday, July 15, 2025 9:35:26 AM Attachments:BRU 224-34T FIT Sidetrack_.pdf From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Tuesday, July 15, 2025 7:53 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: FW: PTD 225-044 Hilcorp Well BRU 224-34T: Casing Test & FIT Data Good morning Bryan, I’ve attached the FIT test for the BRU 224-34T sidetrack. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Nathan Sperry Sent: Tuesday, July 8, 2025 9:09 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: PTD 225-044 Hilcorp Well BRU 224-34T: Casing Test & FIT Data Good morning Bryan, I’ve attached the casing test and FIT data for BRU 224-34T. The cement job went well with over 60 bbls of cement returned to surface. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CASING AND FIT TESTS Well Name:BRU 224-34T Date:7/14/2025 Csg Size/Wt/Grade:77.625" 29.7# P-110 Supervisor:Riley / Richardson Csg Setting Depth:2423 TMD 2425 TVD Mud Weight:9.0 ppg LOT / FIT Press =700 psi LOT / FIT =14.55 ppg Hole Depth =2443 md Fluid Pumped=25.0 Gals Volume Back =25.0 Gals Est. Test Pump Output:2.500 Gallons/Per Inch LOT DATA (test pump) CASING TEST DATA (test pump) Enter Gallons Enter Pressure Enter Gallons Enter Pressure Her e HHere Here HHer e ->0.0 0 ##### ->0.0 0 ->2.5 80 80 ->10.0 ->5.0 172 92 ->20.0 ->7.5 250 78 ->30.0 ->10.0 323 73 ->40.0 ->12.5 393 70 ->50.0 ->15.0 455 62 ->60.0 ->17.5 522 67 ->70.0 ->20.0 580 58 ->80.0 ->22.5 642 62 ->90.0 ->25.0 700 58 ->100.0 ->-700 ->103.0 ->0 -> ->0 -> ->0 -> ->0 -> ->0 -> 0 -> 0 -> 0 -> 0 -> 0 -> 0 0 0 0 0 0 0 0 Enter Holding Enter Holding Time Here Pressure Here Time Here ->0 700 ->0 ->1 558 ->5 ->2 508 ->10 ->3 471 ->15 ->4 446 ->20 ->5 425 ->25 ->6 407 ->30 ->7 393 -> ->8 381 -> ->9 369 -> ->10 358 -> ->11 348 -> ->12 340 -> ->13 330 -> ->14 323 -> ->15 315 -> 0.0 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 22.5 25.0 0.00 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0 110.0 120.0 130.0 140.0 150.0Pressure (psi)Gallons (# of) LOT DATA (test pump) CASING TEST DATA 700 558 508 471 446 425 407 393 381 369 358 348 340 330323 315 0 100 200 300 400 500 600 700 800 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT DATA (test pump) CASING TEST DATA (test pump) 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:Rixse, Melvin G (OGC) To:Sean McLaughlin Cc:McLellan, Bryan J (OGC) Subject:20250712 1552 APPROVAL Plan forward after stuck pipe - BRU 224-34T (225-044) Stuck drill pipe Date:Saturday, July 12, 2025 3:55:52 PM Sean, This plan is approved. Please send me a note or text message me when you confirm the TOC inside drill pipe. (Approval not necessary if within 500’ of shoe) If TOC is higher than 500’ inside the DP above the surface casing shoe, please call to confirm your forward plan. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell and/or 907-223-3605 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Bryan From: Sean McLaughlin <sean.mclaughlin@hilcorp.com> Sent: Saturday, July 12, 2025 3:16 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: Fwd: BRU 224-34T (225-044) Stuck drill pipe Begin forwarded message: From: Sean McLaughlin <sean.mclaughlin@hilcorp.com> Date: July 12, 2025 at 2:12:40 PM AKDT To: "Bryan J McLellan (CED)" <bryan.mclellan@alaska.gov> Subject: BRU 224-34T (225-044) Stuck drill pipe  Bryan, A fourth cement job to cure losses was conducted on BRU 224-34T and the drillpipe was stuck in hole. The drill string is 4-1/2” CDS40 with a mule shoe on the bottom. No Motor, MWD, or LWD tools were in the hole. After running to 3919’(4273’ current TD) and stopping above the suspected loss zone, 80 bbls of LCM cement was pumped. 57 bbls were pumped into formation. No movement occurred when the drillpipe was picked up. The remaining 23 bbls of cement inside the drillpipe was unable to be pumped out. The suspected TOC inside the dp is 2241’ and the 7-5/8” surface casing shoe is at 2607’ md. It is suspected that the annular cement went up above the end of pipe to another loss zone and packed off. Eline will confirm the TOC depth within the drill pipe. If it is within 500’ of the SC shoe the dp will be backed off. A 7-5/8” whipstock will be set and the hole redrilled. Roughly 80’ of stand-off will be required due to magnetic interference. The intention is to recover from the stuck pipe and stay within the approved scope and not make substantive change. After milling the window the FIT results will be sent in for review per the current COAs. Is a Change to Approved program necessary in this case? Regards, Sean The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean Mclaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint, Suite 1400 Anchorage, AK, 99503 Re: Beluga River Unit, Sterling-Beluga Gas Pool, BRU 224-34T Hilcorp Alaska, LLC Permit to Drill Number: 225-044 Surface Location: 212' FNL, 431' FEL, Sec 4, T12N, R10W, SM, AK Bottomhole Location: 151' FSL, 1963' FWL, Sec 34, T13N, R10W, SM, AK Dear Mr. McLaughlin Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 26 day of June, 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.26 15:14:46 -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: 6,007' TVD: 5,953' 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): 102.8' 15. Distance to Nearest Well Open Surface: x-315224 y-2619716 Zone-4 84.3' to Same Pool: 752' to BRU 224-34 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 8 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# P-110 GBCD 2,604' Surface Surface 2,604' 2,583' 6-3/4" 3-1/2" 9.2# L-80 GB ACME 3,603' 2,404' 2,385' 6,007' 5,953' Tieback 3-1/2" 9.2# L-80 EUE 2,404' Surface Surface 2,404' 2,385' 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 BRU 224-34T Beluga River Unit Sterling-Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 777 ft3 / T - 131 ft3 2084 33' FNL, 765' FEL, Sec 4, T12N, R10W, SM, AK 151' FSL, 1963' FWL, Sec 34, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 212' FNL, 431' FEL, Sec 4, T12N, R10W, SM, AK AKA029656 18. Casing Program:Top - Setting Depth - BottomSpecifications 2679 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 855 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): LengthCasing Size Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate Drilling Manager Sean Mclaughlin 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): 7/3/2025 3283' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1387 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s s D 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 2:17 pm, Apr 25, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.04.25 11:47:32 - 08'00' Sean McLaughlin (4311) 6/29/2025 SFD CT BOP test to 3500 psi. Submit FIT/LOT data within 48 hrs of performing test. BJM 6/26/25 DSR-4/29/25 225-044 BOP test to 3000 psi. Annular test to 2500 psi. SFD 6/25/2025 50-283-20205-00-00 GCW 06/26/2025 6/26/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.26 15:15:01 -08'00' RBDMS JSB 070125 BRU 224-34T Drilling Program Beluga River Unit April 22, 2025 BRU 224-34T 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........................................................................................................11 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................12 11.0 Drill 9-7/8” Hole Section..............................................................................................................14 12.0 Run 7-5/8” Surface Casing..........................................................................................................16 13.0 Cement 7-5/8” Surface Casing....................................................................................................18 14.0 BOP N/U and Test........................................................................................................................22 15.0 Drill 6-3/4” Hole Section..............................................................................................................23 16.0 Run 3-1/2” Production Liner......................................................................................................25 17.0 Cement 3-1/2” Production Liner................................................................................................28 18.0 3-1/2” Liner Tieback Polish Run................................................................................................33 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................34 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................35 21.0 Diverter Schematic ......................................................................................................................38 22.0 BOP Schematic.............................................................................................................................39 23.0 Wellhead Schematic.....................................................................................................................40 24.0 Anticipated Drilling Hazards......................................................................................................41 25.0 Hilcorp Rig 147 Layout...............................................................................................................43 26.0 FIT/LOT Procedure ....................................................................................................................44 27.0 Choke Manifold Schematic.........................................................................................................45 28.0 Casing Design Information.........................................................................................................46 29.0 6-3/4” Hole Section MASP..........................................................................................................47 30.0 Spider Plot w/ 660’ Radius for SSSV.........................................................................................48 31.0 Surface Plat (As-Staked NAD27 & NAD83)..............................................................................49 Page 2 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 1.0 Well Summary Well BRU 224-34T Pad & Old Well Designation BRU C Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 6007’ MD / 5953’ TVD PBTD, MD / TVD 6007’ MD / 5953’ TVD AFE Drilling Days 16 AFE Completion Days 3 Maximum Anticipated Pressure (Surface)2084 psi Maximum Anticipated Pressure (Downhole/Reservoir)2679 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 102.8’ Ground Elevation 84.3’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 2.0 Management of Change Information Page 4 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 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 GBCD 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 GB ACME 10160 10540 168 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 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 multiple 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. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 7.0 Drilling / Completion Summary BRU 224-34T is an S-shaped directional grassroots development well to be drilled from BRU C 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 ~45 deg. and TD of the well will be 6007’ TMD/ 5953’ TVD, ending with 10 deg inclination left in the hole. Vertical separation will be 775 ft. Drilling operations are expected to commence approximately July 3 rd, 2025. The Hilcorp Rig #147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2,604’ MD / 2,583’ 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 BLM and 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 surface TD. Run and cmt 7-5/8” surface casing. 4. ND diverter, N/U & test 11” x 5M BOP. 5. Test casing to 3500 psi. Perform 14.0# FIT (13.7# minimum to drill ahead). 6. Drill 6-3/4” hole section to production TD. 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 8-deg max angle. -bjm 8 degrees. SFD Page 8 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all relevant AOGCC regulations and all BLM regulations pertaining to Onshore Order No.1. 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 224-34T. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing. 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 and BLM approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the BLM APD and 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. BLM Regulation Variance Requests: x Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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: 250/5000 (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. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time within 24 hours. x 72 hours before casing running and cmt operations x 72 hours before BOPE tests x 72 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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) BLM Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127 Email:aschoessler@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov Page 11 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 12 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 C Pad (orientation is subject to change on location): Page 13 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Page 14 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 2,604’ MD/ 2,583’ 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 a wiper trip halfway through the surface hole interval. Make additional wiper trips if hole conditions dictate. 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 15 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface Interval 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 16 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker TRS 7-5/8” casing running equipment. x Ensure 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 17 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 18 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 19 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2104’ MD to surface)Tail Slurry (2604’ to 2104’ 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 Superseded Page 19 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2104’ MD to surface) Tail Slurry (2604’ to 2104’ 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 20 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job Page 21 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 22 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 23 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 Production Hole 9.0–9.2 40-53 15-25 15-25 8.5-9.5 ” 11.0 Page 24 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 – 10.0 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. 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 13.7# ppg FIT will result in a 25 bbl KTV assuming an 8.65ppg PP and a 9.2ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 6007’ MD / 5953’ 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’ to 1200’ 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 Sterling A1, B, C, Beluga D, E, and F (3071’ to 4774’ MD). 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, laying down drill pipe. LD density and porosity tools. Page 25 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” GB ACME 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 Baker 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 26 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Page 27 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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” 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 28 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 29 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Estimated Total Cement Volume: Superseded Page 29 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Estimated Total Cement Volume: Verified cement calcs -bjm Page 30 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Cement Slurry Design: Lead Slurry (5507’ MD to 2604’ MD)Tail Slurry (5507’ to 6007’ 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 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 service company 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 (HRD-E) from the liner. Page 31 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 packoff bushing from the nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 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. Backup release from liner hanger (verify with service company rep): 17.21. If the tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 17.22. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 17.24. WOC until the compressive strength hits at least 500 psi before testing casing to 3000 psi and chart for 30 minutes. Page 32 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 33 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per service company 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 34 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 35 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 20.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 2-1/2” liner (send results to AOGCC to review) 4. RDMO E-line Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD, cleanout well as necessary (based on CBL depth) and swap well over to 8.4 ppg water a. If well is left with 9.4 ppg mud or less, mud may be circulated out with Nitrogen, based on Operations Engineer direction without swapping to water. 5. Once well is clean with 8.4 ppg water a. Reverse circulate water 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Submit Completion sundry for perforating well. Attachments to be included 1. Coil Tubing BOP Diagram 2. Standard Nitrogen Operations Page 36 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Page 37 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure Page 38 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 21.0 Diverter Schematic Page 39 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 22.0 BOP Schematic Page 40 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 23.0 Wellhead Schematic Page 41 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 24.0 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 42 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 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 43 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 25.0 Hilcorp Rig 147 Layout Page 44 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 26.0 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 45 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 27.0 Choke Manifold Schematic Page 46 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 28.0 Casing Design Information Page 47 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 29.0 6-3/4” Hole Section MASP Page 48 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 30.0 Spider Plot w/ 660’ Radius for SSSV Page 49 Version 0.0 April 2, 2025 BRU 224-34T Drilling Procedure 31.0 Surface Plat (As-Staked NAD27 & NAD83)                  !!"  #$ %  "     0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000True Vertical Depth (800 usft/in)-800 -400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 Vertical Section at 297.00° (800 usft/in) 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 06007 BRU 224-34T wp01 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 566.67' MD, 565.8' TVD Total Depth : 6007' MD, 5953.19' TVD Sterling A1 Sterling B Sterling C Beluga D Beluga E Beluga F Beluga G Beluga H Beluga I 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: BRU 224-34T 84.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2619716.06 315224.52 61° 9' 58.6561 N 151° 2' 47.2352 W SURVEY PROGRAM Date: 2025-04-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2603.00 BRU 224-34T wp01 (BRU 224-34T) 3_MWD+AX+Sag 2603.00 6007.00 BRU 224-34T wp01 (BRU 224-34T) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well BRU 224-34T, True North Vertical (TVD) Reference:RKB Permit @ 102.80usft Measured Depth Reference:RKB Permit @ 102.80usft Calculation Method: Minimum Curvature Project:Beluga River Site:BRU C-Pad Well:BRU 224-34T Wellbore:BRU 224-34T Design:BRU 224-34T wp01 CASING DETAILS TVD TVDSS MD Size Name 2583.00 2480.20 2603.69 7-5/8 7-5/8" x 9-7/8" 5953.19 5850.39 6007.00 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 3 566.67 8.00 297.00 565.80 8.44 -16.56 3.00 297.00 18.59 End Dir : 566.67' MD, 565.8' TVD 4 6007.00 8.00 297.00 5953.19 352.18 -691.18 0.00 0.00 775.73 Total Depth : 6007' MD, 5953.19' TVD -75-3803875113150188225263300338375413South(-)/North(+) (75 usft/in)-713 -675 -638 -600 -563 -525 -488 -450 -413 -375 -338 -300 -263 -225 -188 -150 -113 -75 -38 0West(-)/East(+) (75 usft/in)7-5/8" x 9-7/8"3-1/2" x 6-3/4"250500750100012501500175020002250250027503000325035003750400042504500475050005250550057505953BRU 224-34T wp01Start Dir 3º/100' : 300' MD, 300'TVDEnd Dir : 566.67' MD, 565.8' TVDTotal Depth : 6007' MD, 5953.19' TVDCASING DETAILSTVDTVDSS MDSize Name2583.00 2480.20 2603.69 7-5/8 7-5/8" x 9-7/8"5953.19 5850.39 6007.00 3-1/2 3-1/2" x 6-3/4"Project: Beluga RiverSite: BRU C-PadWell: BRU 224-34TWellbore: BRU 224-34TPlan: BRU 224-34T wp01WELL DETAILS: BRU 224-34T84.30+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.002619716.06 315224.52 61° 9' 58.6561 N 151° 2' 47.2352 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well BRU 224-34T, True NorthVertical (TVD) Reference: RKB Permit @ 102.80usftMeasured Depth Reference:RKB Permit @ 102.80usftCalculation Method:Minimum Curvature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eparation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:BRU 224-34T NAD 1927 (NADCON CONUS)Alaska Zone 0484.30+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002619716.06 315224.52 61° 9' 58.6561 N 151° 2' 47.2352 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well BRU 224-34T, True NorthVertical (TVD) Reference: RKB Permit @ 102.80usftMeasured Depth Reference:RKB Permit @ 102.80usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-04-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 2603.00 BRU 224-34T wp01 (BRU 224-34T) 3_MWD+AX+Sag2603.00 6007.00 BRU 224-34T wp01 (BRU 224-34T) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)BRU 223-34BRU 224-34BRU 242-04GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 6007.00Project: Beluga RiverSite: BRU C-PadWell: BRU 224-34TWellbore: BRU 224-34TPlan: BRU 224-34T wp01CASING DETAILSTVD TVDSS MD Size Name2583.00 2480.20 2603.69 7-5/8 7-5/8" x 9-7/8"5953.19 5850.39 6007.00 3-1/2 3-1/2" x 6-3/4" 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. STRLG-BELUGA GAS 225-044 BELUGA RIVER BRU 224-34T WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 224-34TInitial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250440Field & Pool:BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes Entire Well lies within ADL0029656.2 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) (For NA15 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 = 2084 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 Expected pressure range is 0.117 to 0.449 psi/ft (2.2 to 8.6 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/25/2025ApprBJMDate6/4/2025ApprSFDDate6/25/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 6/26/2025