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Home My WebLink About225-027Nolan 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: 7/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250715 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF BCU 14B 50133205390200 222057 6/20/2025 AK E-LINE Perf BR 03-87 50733204370000 166052 6/15/2025 AK E-LINE Perf BRU 211-35 50283201890000 223050 6/2/2025 AK E-LINE Perf BRU 213-26 50283201920000 223069 6/23/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/4/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/22/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/12/2025 AK E-LINE PPROF BRU 241-23 50283201910000 223061 6/10/2025 AK E-LINE Cement/Perf BRU 241-23 50283201910000 223061 6/19/2025 AK E-LINE CIBP BRU 241-23 50283201910000 223061 6/21/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 6/4/2025 AK E-LINE PlugPerf KBU 43-07Y 50133206250000 214019 6/17/2025 AK E-LINE Perf KU 41-08 50133207170000 224005 6/24/2025 AK E-LINE Plug Perf LIS L5-26 50029220790000 190110 6/21/2025 AK E-LINE Patch MRU M-25 50733203910000 187086 6/17/2025 AK E-LINE CIBP PBU 15-14A 50029206820100 204222 6/3/2025 BAKER SPN PBU 18-15C 50029217550300 211172 6/12/2025 AK E-LINE CBL/Perf PBU F-38B 50029220930300 225029 6/12/2025 BAKER MRPM SRU 241-33B 50133206960000 221053 5/25/2025 AK E-LINE CIBP Please include current contact information if different from above. T40659 T40660 T40661 T40662 T40663 T40664 T40664 T40664 T40665 T40665 T40665 T40665 T40666 T40667 T40668 T40669 T40670 T40671 T40672 T40673 BRU 221-24 50283202020000 225027 6/4/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/22/2025 AK E-LINE Perf BRU 221-24 50283202020000 225027 6/12/2025 AK E-LINE PPROF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.16 10:52:24 -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: 6/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250618 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN 07RD2 50733200120200 195113 6/1/2025 AK E-LINE LDL AN 24RD 50733202850100 207170 6/1/2025 AK E-LINE LDL BRU 221-24 50283202020000 225027 5/29/2025 AK E-LINE CBL KALOTSA 10 50133207320000 224147 5/21/2025 AK E-LINE Perf KALOTSA 2 50133206590000 216155 5/25/2025 AK E-LINE Perf PAXTON 11 50133207040000 221114 5/27/2025 AK E-LINE Perf PAXTON 11 50133207040000 221114 5/26/2025 AK E-LINE Perf PBU 06-12C 50029204560300 225022 5/17/2025 HALLIBURTON RBT-COILFLAG PBU 15-32C 50029224620300 217104 5/27/2025 HALLIBURTON RBT PBU D-01B 50029200540200 224155 5/18/2025 BAKER MRPM PBU D-01B 50029200540200 224155 5/18/2025 HALLIBURTON RBT-COILFLAG PBU H-18A 50029208800100 224011 5/14/2025 BAKER MRPM PBU H-18A 50029208800100 224011 5/14/2025 HALLIBURTON RBT-COILFLAG PBU L-109 50029230460000 201201 5/24/2025 HALLIBURTON IPROF PBU L-115 50029230350000 201140 5/19/2025 HALLIBURTON IPROF PBU L-117 50029230390000 201167 5/30/2025 HALLIBURTON IPROF PBU N-07B 50029201370200 223122 6/7/2025 HALLIBURTON RBT PBU S-100A 50029229620100 224083 5/26/2025 HALLIBURTON PPROF-LDL PBU Z-34 50029234690000 212061 5/17/2025 HALLIBURTON IPROF-LDL Please include current contact information if different from above. T40566 T40567 T40568 T40569 T40570 T40571 T40571 T40572 T40573 T40574 T40574 T40575 T40575 T40576 T40577 T40578 T40579 T40580 T40581 BRU 221-24 50283202020000 225027 5/29/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.18 12:03:53 -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: 6/11/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 221-24 PTD: 225-027 API: 50-283-20202-00-00 FINAL LWD FORMATION EVALUATION LOGS (05/09/2023 to 05/19/2025) DGR, PCG, ADR, ALD, CTN, ROP (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey GeoTap Formation Pressure Tester Folder Contents: Please include current contact information if different from above. 225-027 T40545 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.12 08:11:40 -08'00' From:Rixse, Melvin G (OGC) To:Stefan Reed Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC) Subject:RE: BRU 221-24 (PTD # 225-027) - Additional Perf Zone Date:Friday, June 6, 2025 4:52:01 PM Attachments:image002.png image003.png image004.png Stefan, Hilcorp is approved to add perforations as described below: Note: Approved perfs per Sundry 325-330 Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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. You don't often get email from stefan.reed@hilcorp.com. Learn why this is important CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Friday, June 6, 2025 4:32 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: Fw: BRU 221-24 (PTD # 225-027) - Additional Perf Zone Mel, As discussed, we plan to per the below interval which is between already approved perf zones. Thank you. -Stefan Get Outlook for iOS From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Friday, June 6, 2025 12:54 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: BRU 221-24 (PTD # 225-027) - Additional Perf Zone Bryan, We are currently working on well BRU 221-24 (sundry 325-330) and would like to and an additional zone to the sundried perf interval listed below: Sand MD Top MD Base TVD Top TVD Base Footage Beluga J2 ±7565 ±7578 ±6391 ±6404 ±13 Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 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 individualor entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that anydissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is acceptedby 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: Initial Completion 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): 8,146'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng LTP; N/A 3,447' MD / TVD; N/A 6,962'8,076'6,893' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 221-24CO 802A Same 6,959'3-1/2" 2778 4,696' N/A Length June 1, 2025 Tieback 3-1/2" 8,143' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 3,673' Size 120' 3,673' MD Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 3,481' 10,160psi 2,768' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 21128 225-027 50-283-20202-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t n N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-330 By Gavin Gluyas at 8:00 am, May 29, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.28 16:14:18 - 08'00' Noel Nocas (4361) 10-407 A.Dewhurst 30MAY25 Cement bond log was received by AOGCC and cement top is confirmed above top requested perf interval. BJM 5/30/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.02 13:20:13 -08'00'06/02/25 RBDMS JSB 060225 Well Prognosis Well Name: BRU 221-24 API Number: 50-283-20202-00-00 Current Status: New Drill Well Permit to Drill Number: 225-027 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: 3165 psi @ 6459’ TVD (Based on 0.49 psi/ft gradient – J Sands) Max. Potential Surface Pressure: 2778 psi (Based on 0.06 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.712 psi/ft using 13.7 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.712-0.06) = 2778 psi / 0.652 = 4261’ TVD with J sands open Top of SBGP (CO 802A): ~4120’ MD/~3064’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary BRU 221-24 is the first of five grass roots well to be drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to perforate the well and flow the new drill well. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A Wellbore Conditions: - Max Inclination – 61.95° at 2,801’ MD - T & IA PT to 3000 psi (30 min) - Min ID- 2.992” 3-1/2” tubing/liner - Top Of Pool per CO : 4120’ MD/3064 TVD - Formation pressure in sands from Beluga I sands & shallower is 0.40 psi/ft or less, the J Sands have a 0.49 psi/ft gradient Work to be completed on PTD# 225-027 Step 20: - Eline run CBL (Send log to state prior to perforating on this sundry) - CT cleanout well with water and displace with N2. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 3,000 psi high 3. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 4. 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 sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD Amt BEL G1 ±5,978' ±5,981' ±4,827' ±4,830' ±3' BEL G4 ±6,077' ±6,081' ±4,925' ±4,929' ±4' BEL G4 ±6,090' ±6,093' ±4,938' ±4,941' ±3' BEL G8 ±6,158' ±6,164' ±5,005' ±5,011' ±6' BEL G9 ±6,198' ±6,203' ±5,044' ±5,049' ±5' Well Prognosis BEL H ±6,264' ±6,274' ±5,109' ±5,119' ±10' BEL H5 ±6,443' ±6,447' ±5,286' ±5,290' ±4' BEL H6 ±6,468' ±6,472' ±5,311' ±5,315' ±4' BEL H7 ±6,494' ±6,519' ±5,336' ±5,361' ±25' BEL H9 ±6,563' ±6,573' ±5,404' ±5,414' ±10' BEL H10 ±6,616' ±6,629' ±5,457' ±5,470' ±13' BEL H11 ±6,651' ±6,683' ±5,491' ±5,523' ±32' BEL H12 ±6,706' ±6,712' ±5,545' ±5,551' ±6' BEL H13 ±6,763' ±6,777' ±5,601' ±5,615' ±14' BEL H15 ±6,835' ±6,858' ±5,672' ±5,695' ±23' BEL H16 ±6,891' ±6,899' ±5,727' ±5,735' ±8' BEL I ±6,922' ±6,932' ±5,758' ±5,767' ±10' BEL I1 ±6,962' ±6,968' ±5,797' ±5,803' ±6' BEL I4 ±7,093' ±7,097' ±5,926' ±5,930’ ±3' BEL I5 ±7,111' ±7,119' ±5,944' ±5,951' ±8' BEL I6 ±7,130' ±7,153' ±5,962' ±5,985' ±23' BEL I8 ±7,217' ±7,222' ±6,048' ±6,053' ±5' BEL I10 ±7,296' ±7,300' ±6,126' ±6,129' ±4' BEL J1 ±7,463' ±7,487' ±6,290' ±6,314' ±24' BEL J3 ±7,626' ±7,635' ±6,450' ±6,459' ±9' 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 ii. The Beluga J sands will be plugged and capped with 25ft of cement before anything shallower than 4261’ TVD is perforated in this well. iii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 5. RDMO 6. Turn well over to production & flow test well 7. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Attachments: 1. Current Schematic 2. Proposed Schematic Updated by CAH 05-27-25 CURRENT SCHEMATIC Beluga River Unit BRU 221-24 PTD: 225-027 API: 50-283-20202-00-00 PBTD = 8,076’ MD / TVD = 6,893’ TD = 8,146’ MD / TVD = 6,962’ RKB to GL = 19.8’ , CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,673’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”3,447’8,143’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 3,481 3/4 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 20’Cactus CTF-ONE-CTL 11” Liner Hanger w/ 4” Type H BPV profile 2 3,371’Retrievable Hydraulic DHL Packer (58K Release) 3 3,481’Bullet seal assembly spaced 1.64’ off no-go 4 3,482’Ranger Liner Hanger W/ Scout packer (5.25” ID) OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 60 bbl 10.5 ppg spacer, 222 bbl (517 sx) 12 ppg lead cement followed by 40 bbl (193 sx) 15.8 tail cement. Bumped plug at 160 bbls (calculated 165 bbls), spacer & 97 bbls of contaminated cement to surface, 0 bbls of losses 3-1/2” 187 bbls (446 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug @ 72 bbls (calc 76 bbls), 46 bbls cement to surface, 18bbls of losses during job. TOC based on CBL @ xxxx’ To be completed before perforating. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 4,120’ MD/3,064’ TVD RA 7,638’ RA 4,666’ RA 5,663’ RA 6,637’ Notes: 10’ Short jt w/ RA tags 7638, 6637, 5663, 4666 10’ Short joints 7136, 6163, 5165, 4161 Deviation Kick off below surface build to 62 deg @ 2801. Drop to 10deg @ 5000’ 1 2 Updated by CAH 05-27-25 PROPOSED Beluga River Unit BRU 221-24 PTD: 225-027 API: 50-283-20202-00-00 PBTD = 8,076’ MD / TVD = 6,893’ TD = 8,146’ MD / TVD = 6,962’ RKB to GL = 19.8’ , CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,673’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”3,447’8,143’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 3,481 3/4 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 20’Cactus CTF-ONE-CTL 11” Liner Hanger w/ 4” Type H BPV profile 2 3,371’Retrievable Hydraulic DHL Packer (58K Release) 3 3,481’Bullet seal assembly spaced 1.64’ off no-go 4 3,482’Ranger Liner Hanger W/ Scout packer (5.25” ID) OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 60 bbl 10.5 ppg spacer, 222 bbl (517 sx) 12 ppg lead cement followed by 40 bbl (193 sx) 15.8 tail cement. Bumped plug at 160 bbls (calculated 165 bbls), spacer & 97 bbls of contaminated cement to surface, 0 bbls of losses 3-1/2” 187 bbls (446 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug @ 72 bbls (calc 76 bbls), 46 bbls cement to surface, 18bbls of losses during job. TOC based on CBL @ xxxx’ To be completed before perforating. 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 4,120’ MD/3,064’ TVD BEL G1 ±5,978'±5,981'±4,827'±4,830'±3'Proposed TBD BEL G4 ±6,077'±6,081'±4,925'±4,929'±4'Proposed TBD BEL G4 ±6,090'±6,093'±4,938'±4,941'±3'Proposed TBD BEL G8 ±6,158'±6,164'±5,005'±5,011'±6'Proposed TBD BEL G9 ±6,198'±6,203'±5,044'±5,049'±5'Proposed TBD BEL H ±6,264'±6,274'±5,109'±5,119'±10'Proposed TBD BEL H5 ±6,443'±6,447'±5,286'±5,290'±4'Proposed TBD BEL H6 ±6,468'±6,472'±5,311'±5,315'±4'Proposed TBD BEL H7 ±6,494'±6,519'±5,336'±5,361'±25'Proposed TBD BEL H9 ±6,563'±6,573'±5,404'±5,414'±10'Proposed TBD BEL H10 ±6,616'±6,629'±5,457'±5,470'±13'Proposed TBD BEL H11 ±6,651'±6,683'±5,491'±5,523'±32'Proposed TBD BEL H12 ±6,706'±6,712'±5,545'±5,551'±6'Proposed TBD BEL H13 ±6,763'±6,777'±5,601'±5,615'±14'Proposed TBD BEL H15 ±6,835'±6,858'±5,672'±5,695'±23'Proposed TBD BEL H16 ±6,891'±6,899'±5,727'±5,735'±8'Proposed TBD BEL I ±6,922'±6,932'±5,758'±5,767'±10'Proposed TBD BEL I1 ±6,962'±6,968'±5,797'±5,803'±6'Proposed TBD BEL I4 ±7,093'±7,097'±5,926'±5,930'±4'Proposed TBD BEL I5 ±7,111'±7,119'±5,944'±5,951'±8'Proposed TBD BEL I6 ±7,130'±7,153'±5,962'±5,985'±23'Proposed TBD BEL I8 ±7,217'±7,222'±6,048'±6,053'±5'Proposed TBD BEL I10 ±7,296'±7,300'±6,126'±6,129'±4'Proposed TBD BEL J1 ±7,463'±7,487'±6,290'±6,314'±24'Proposed TBD BEL J3 ±7,626'±7,635'±6,450'±6,459'±9'Proposed TBD Bel G1 to Bel J3 RA 7,638’ RA 4,666’ RA 5,663’ RA 6,637’ Notes: 10’ Short jt w/ RA tags 7638, 6637, 5663, 4666 10’ Short joints 7136, 6163, 5165, 4161 Deviation Kick off below surface build to 62 deg @ 2801. Drop to 10deg @ 5000’ 1 2 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Joshua Riley - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:BRU 221-24 MIT Date:Monday, May 26, 2025 6:55:04 AM Attachments:BRU 221-24 MIT 5-26-25.xlsx Here you go Josh Riley Hilcorp DSM (907)776-6776 Cell (907)252-1211 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. %HOXJD5LYHU8QLW 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250270 Type Inj N Tubing 3200 3180 3175 Type Test P Packer TVD 2656 BBL Pump 0.8 IA 120 120 120 Interval O Test psi 3000 BBL Return 0.8 OA 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250270 Type Inj N Tubing 180 180 180 Type Test P Packer TVD 2656 BBL Pump 1.4 IA 3225 3225 3220 Interval O Test psi 3000 BBL Return 1.4 OA 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Post completion testing prior to moving off Notes: Notes: Hilcorp Alaska LLC Beluga River Unit Josh Riley 05/25/25 Notes:Post completion testing prior to moving off Notes: Notes: Notes: BRU 221-24 BRU 221-24 Form 10-426 (Revised 01/2017)2025-0526_MIT_BRU_221-24_2tests 9 9 9 99¾ 9 0,77 0,7,$ 999 9 9 *DVSURGXFHU -5HJJ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________BELUGA RIV UNIT 221-24 JBR 07/21/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Tested all with 4-1/2" TJ. Test #6 leaking off ,rebuilt Sensator, retest still bad, Function Lower Pipe Rams several times, retest and pass. No other failures. Rig was very clean and organized. Test Results TEST DATA Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Rig Owner/Rig No.:Hilcorp 147 PTD#:2250270 DATE:5/14/2025 Type Operation:DRILL Annular: 250/5000Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopSTS250519104510 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7 MASP: 2442 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 13 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2-7/8" x 5"P #2 Rams 1 Blinds P #3 Rams 1 2-7/8"x5"FP #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 2-1/16",3-1/8 P Kill Line Valves 1 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1700 200 PSI Attained P19 Full Pressure Attained P87 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2550 ACC Misc NT0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P20 #1 Rams P4 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1        STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________BELUGA RIV UNIT 221-24 JBR 07/18/2025 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:15 charge bottles ranging from 950 to 1000 psi. Response time for annular was 29 seconds. TEST DATA Rig Rep:J. MurphyOperator:Hilcorp Alaska, LLC Operator Rep:K. Porterfield Contractor/Rig No.:Hilcorp 147 PTD#:2250270 DATE:5/9/2025 Well Class:DEV Inspection No:divGDC250506145021 Inspector Guy Cook Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:NA NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:24.25 P Hole Size:9.875 P Vent Line(s) Size:16 P Vent Line(s) Length:111 P Closest Ignition Source:93 P Outlet from Rig Substructure:99 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:P Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:29 P Knife Valve Open Time:14 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P1500 200 psi Recharge Time:P24 Full Recharge Time:P110 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2550 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: NA NAMud System Misc: 9 9 9 9 9 9 9 9 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: Same 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 120'N/A Casing Collapse Structural Conductor Surface Intermediate Production 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 MPSP (psi): N/A BRU 221-24 Beluga River Unit Sterling - Beluga GP Will perfs require a spacing exception due to property boundaries? Current Pools: N/A Subsequent Form Required: Suspension Expiration Date: Tubing Grade:Tubing MD (ft): Nathan Sperry Nathan.Sperry@hilcorp.com 907-777-8450 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 AOGCC USE ONLY 120' N/A Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 21128 225-027 3800 Centerpoint Drive, St 1400, Anchorage, AK 99503 50-283-20202-00-00 Hilcorp Alaska, LLC Length Size Proposed Pools: Plugs (MD): 120'120'N/A TVD Burst N/A MD 120'120'16"120' N/A N/A Drilling Manager Joe Engel for Sean Mclaughlin 5/9/2025 N/A N/A Perforation Depth MD (ft): N/A m n P s 66 t _ c 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 1:13 pm, May 08, 2025 Digitally signed by Joseph Engel (2493) DN: cn=Joseph Engel (2493) Date: 2025.05.08 10:29:16 - 08'00' Joseph Engel (2493) 325-288 RUSH SFD SFD 5/8/2025 5/9/2025 May 08, 2025 All conditions of approval in the original PTD still apply. BJM 5/8/25 10-407 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.09 14:19:53 -08'00'05/09/25 RBDMS JSB 051225 Well Prognosis Well: BRU 221-24 Date: 5/8/25 Well Name:BRU 221-24 API Number:50-283-20202-00-00 Current Status:Rigging up Estimated Start Date:5/9/25 Rig:Rig 147 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-027 First Call Engineer:Nathan Sperry (907)-777-8450 (O) Second Call Engineer AFE Number: Change to Approved Program Summary: The surface casing depth was changed from 4,221’ MD to 3,617’ MD to a more competent formation. The surface cement volume, production cement volume, and production hole FIT values have been updated accordingly. Plan Forward: 1. Rig up and spud well; execute PTD program 225-027, with the attached changes if approved. Attachments: 1.Proposed Schematic 2.Updated Cement Volumes 3.Updated FIT/KTV BRU 221-24 (K pad) PTD Program Beluga River Unit May 8, 2025 Page 3 Rev 1.0 May 8, 2025 BRU 221-24 Drilling Procedure 2.0 Management of Change Information Updated by CJD 5/8/25 Proposed Schematic Beluga River Unit BRU 221-24 PTD: 225-027 API: 50-283-20202-00-00 PBTD = 8,100’ MD / TVD = 6,932’ TD = 8,146’ MD / TVD = 6,977’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 3,617’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” ±3,417’ 8,146’ 3-1/2” Production Tieback 9.2 L-80 EUE 2.992” Surf ±3,417 1/2 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 ±3,417’ Liner hanger / LTP Assembly 2 ±3,417’ Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8" L – 1236 ft3 / T – 128 ft3 (75% excess) 3-1/2” L – 1063 ft3 / T – 131 ft3 (40% excess) 6-3/4” hole Page 7 Rev 1.0 May 8, 2025 BRU 221-24 Drilling Procedure 7.0 Drilling / Completion Summary BRU 221-24 is an S-shaped directional grassroots development well to be drilled from BRU K 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 ~500’MD. Maximum hole angle will be ~60 deg. and TD of the well will be 8146’ TMD/ 6977’ TVD, ending with 10 deg inclination. Drilling operations are expected to commence approximately May 6, 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 3617’MD / 2728’ 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 run to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells. The contingency plan will be tohaul cuttingsto the Kenai 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 3617’ MD. Run and cmt 7-5/8”surface casing. 4. Test casing to 3500 psi. Perform 13.7# FIT 5. ND diverter,N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to 8146’MD. Perform Wiper trip. 7. Run and cmt 3-1/2”production liner. 8. Displace well to inhibited 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 May 9, 2025 per attached 10-403 form. -bjm Page 17 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (3117’ MD to surface)Tail Slurry (3617’ to 3117’ 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 Page 21 Rev 1.0 May 8, 2025 BRU 221-24 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 –9.7 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 13.7# ppg FIT will result in a 25 bbl KTV. 15.14 Drill 6-3/4” hole section to 8146’ MD / 6977’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Lost circulation potential when drilling through Beluga D and E. SLOW ROP, Add Black products and background LCM to the mud. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8”shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA 20 bbls kick tolerance with 9.7 ppg mud, heaviest planned in the PTD. -bjm Page 27 Rev 1.0 May 8, 2025 BRU 221-24 Drilling Procedure Estimated Total Cement Volume: Page 28 Rev 1.0 May 8, 2025 BRU 221-24 Drilling Procedure Cement Slurry Design: Lead Slurry (7646’ MD to 3417’ MD)Tail Slurry (8146’ to 7646’ 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 YJOC procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Beluga River Unit, Sterling-Beluga Gas Pool, BRU 221-24 Hilcorp Alaska, LLC Permit to Drill Number: 225-027 Surface Location: 2220' FNL, 0' FWL, Sec 23/24, T13N, R10W, SM, AK Bottomhole Location: 368' FNL, 2572' FWL, Sec 24, 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 15h day of April 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.15 15:39:12 -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: 8,146' TVD: 6,977' 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): 96.6 15. Distance to Nearest Well Open Surface: x-323331 y-2633417 Zone-4 78.1 to Same Pool:1109' to BRU 222-24 16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 60 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 4,221' Surface Surface 4,221' 3,165' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,125' 4,021' 3,087' 8,146' 6,977' Tieback 3-1/2" 9.2# L-80 EUE 4,021' Surface Surface 4,021' 3,087' 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 221-24 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 - 903 ft3 / T - 131 ft3 2442 798' FNL, 1957' FWL, Sec 24, T13N, R10W, SM, AK 368' FNL, 2572' FWL, Sec 24, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2220' FNL, 0' FWL, Sec 23/24, T13N, R10W, SM, AK ADL 22128 18. Casing Program:Top - Setting Depth - BottomSpecifications 3140 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 1864 ft3 / T - 307 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): 5/1/2025 3938' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 489 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 sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.03.25 14:48:39 - 08'00' Sean McLaughlin (4311) By Grace Christianson at 3:55 pm, Mar 25, 2025 Initial BOP test to 5000 psi. Subsequent BOP tests to 3000 psi. All annular tests to 2500 psi. 50-283-20202-00-00 21128 225-027 BJM 4/15/25 A.Dewhurst 10APR25 DSR-4/1/25 Submit FIT/LOT data within 48 hrs of performing test. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.15 15:39:27 -08'00' 04/15/25 04/15/25 RBDMS JSB 041725 BRU 221-24 (K pad) PTD Program Beluga River Unit March 14, 2025 BRU 221-24 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................12 12.0 Run 7-5/8” Surface Casing..........................................................................................................14 13.0 Cement 7-5/8” Surface Casing....................................................................................................16 14.0 BOP N/U and Test........................................................................................................................19 15.0 Drill 6-3/4” Hole Section..............................................................................................................20 16.0 Run 3-1/2” Production Liner......................................................................................................22 17.0 Cement 3-1/2” Production Liner................................................................................................25 18.0 3-1/2” Liner Tieback Polish Run................................................................................................28 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................29 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................30 21.0 Diverter Schematic ......................................................................................................................33 22.0 BOP Schematic.............................................................................................................................34 23.0 Wellhead Schematic.....................................................................................................................35 24.0 Anticipated Drilling Hazards......................................................................................................36 25.0 Hilcorp Rig 147 Layout...............................................................................................................38 26.0 FIT/LOT Procedure ....................................................................................................................39 27.0 Choke Manifold Schematic.........................................................................................................40 28.0 Casing Design Information.........................................................................................................41 29.0 6-3/4” Hole Section MASP..........................................................................................................42 30.0 Spider Plot....................................................................................................................................43 31.0 Surface Plat As-Staked................................................................................................................44 Page 2 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 1.0 Well Summary Well BRU 221-24 Pad & Old Well Designation BRU K pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 8146 MD / 6977’ TVD PBTD, MD / TVD 6777’ MD AFE Number AFE Drilling Days AFE Drilling Amount Maximum Anticipated Pressure (Surface)2442 psi Maximum Anticipated Pressure (Downhole/Reservoir)3140 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 96.60’ Ground Elevation 78.10’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 2.0 Management of Change Information Page 4 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 P110/ L-80 GBCD/ BTC 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. 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 Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 6.0 Planned Wellbore SchematicSuperseded Updated by CJD 4/15/25 Proposed Schematic Beluga River Unit BRU 221-24 PTD: TBD API: TBD PBTD = 8,100’ MD / TVD = 6,932’ TD = 8,146’ MD / TVD = 6,977’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 4,221’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” ±4,021’ 8,146’ 3-1/2” Production Tieback 9.2 L-80 EUE 2.992” Surf ±4,021 1/2 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 ±4,021’ Liner hanger / LTP Assembly 2 ±4,021’ Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8" L – 1462 ft3 / T – 128 ft3 (75% excess) 3-1/2” L – 903 ft3 / T – 131 ft3 (40% excess) 6-3/4” hole Page 7 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 7.0 Drilling / Completion Summary BRU 221-24 is an S-shaped directional grassroots development well to be drilled from BRU K 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 ~500’ MD. Maximum hole angle will be ~60 deg. and TD of the well will be 8146’ TMD/ 6977’ TVD, ending with 10 deg inclination. Drilling operations are expected to commence approximately May, 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 4221’ MD / 3165’ 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 notobserved, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 147 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to 4221’ MD. Run and cmt 7-5/8” surface casing. 4. Test casing to 3500 psi. Perform 13.5# FIT 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to 8146’ MD. Perform Wiper trip. 7. Run and cmt 3-1/2” production liner. 8. Displace well to inhibited completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo Page 8 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of BRU 221-24. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. Page 9 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Page 10 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 9-7/8” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 K pad: Page 12 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 4221’ MD/ 3165’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-4221’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 16 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 17 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (3720’ MD to surface)Tail Slurry (4221’ to 3720’ 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 Cement calcs use wrong hole size. Need revision. -bjm Superseded Page 17 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (3720’ MD to surface) Tail Slurry (4221’ to 3720’ MD) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add. FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 18 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job Page 19 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Initial test to 5000 psi. -bjm Page 20 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 4221’- 8146’9.0–9.7 40-53 15-25 15-25 8.5-9.5 11.0 Page 21 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 9.7 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 13.5 ppg EMW. A 13.0# ppg FIT will result in a 27 bbl KTV. 15.14 Drill 6-3/4” hole section to 8146’ MD / 6977’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Lost circulation potential when drilling through Beluga D and E. SLOW ROP, Add Black products and background LCM to the mud. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA Page 22 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA 15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with YJOC landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 23 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Page 24 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 25 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 26 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (7646’ MD to 4020’ MD)Tail Slurry (8146’ to 7646’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 27 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by YJOC procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Page 28 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 17.21. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC procedure. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 29 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 No SSSV, CIM, GLM planned 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.48 hr notice required. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.48 hr notice required. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #147 Page 30 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 31 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Page 32 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx Page 33 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 21.0 Diverter Schematic Page 34 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 22.0 BOP Schematic Page 35 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 23.0 Wellhead Schematic Page 36 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 37 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 38 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 25.0 Hilcorp Rig 147 Layout Page 39 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 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 40 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 27.0 Choke Manifold Schematic Page 41 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 28.0 Casing Design Information Page 42 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 29.0 6-3/4” Hole Section MASP Page 43 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 30.0 Spider Plot Page 44 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx 31.0 Surface Plat As-Staked Page 45 Rev 0.0 March 14, 2025 BRU 221-24 Drilling Procedure PTD xxx-xxx !""# $% & ' -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 54.34° (1500 usft/in) BRU 221-24 wp02 tgt2 BRU 221-24 wp02 tgt1 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 500 1 0 0 0 1 5 0 0 200025003000350040004 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 1 4 6 BRU 221-24 wp02 Start Dir 3º/100' : 500' MD, 500'TVD End Dir : 2504.35' MD, 2157.39' TVD Start Dir 3º/100' : 3364.35' MD, 2587.39'TVD End Dir : 5031.02' MD, 3909.73' TVD Total Depth : 8146' MD, 6977.39' TVD STERLING_A1 STERLING_B STERLING_C BELUGA_D BELUGA_E BELUGA_F BELUGA_G BELUGA H BELUGA_I BELUGA_J Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: BRU 221-24 78.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2633417.00 323331.40 61° 12' 14.8096 N 151° 0' 6.2599 W SURVEY PROGRAM Date: 2025-03-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 4220.00 BRU 221-24 wp02 (BRU 221-24) 3_MWD+AX+Sag 4220.00 8146.00 BRU 221-24 wp02 (BRU 221-24) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 221-24, True North Vertical (TVD) Reference:Permit RKB @ 96.60usft (147) Measured Depth Reference:Permit RKB @ 96.60usft (147) Calculation Method:Minimum Curvature Project:Beluga River Site:BRU K-Pad Well:Plan: BRU 221-24 Wellbore:BRU 221-24 Design:BRU 221-24 wp02 CASING DETAILS TVD TVDSS MD Size Name 3165.00 3068.40 4220.87 7-5/8 7-5/8" x 9-7/8" 6977.39 6880.79 8146.00 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 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD 3 1300.00 24.00 50.00 1276.81 106.13 126.49 3.00 50.00 164.64 4 2504.35 60.00 55.00 2157.39 578.45 762.51 3.00 7.35 956.75 End Dir : 2504.35' MD, 2157.39' TVD 5 3364.35 60.00 55.00 2587.39 1005.64 1372.61 0.00 0.00 1701.49 Start Dir 3º/100' : 3364.35' MD, 2587.39'TVD 6 5031.02 10.00 55.00 3909.73 1536.72 2131.07 3.00 180.00 2627.34 End Dir : 5031.02' MD, 3909.73' TVD 7 8146.00 10.00 55.00 6977.39 1846.97 2574.16 0.00 0.00 3168.22 Total Depth : 8146' MD, 6977.39' TVD FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3322.60 3226.00 4405.84 STERLING_A1 3508.60 3412.00 4612.29 STERLING_B 3661.60 3565.00 4775.28 STERLING_C 3888.60 3792.00 5009.54 BELUGA_D 4079.60 3983.00 5203.51 BELUGA_E 4389.60 4293.00 5518.29 BELUGA_F 4794.60 4698.00 5929.54 BELUGA_G 5087.60 4991.00 6227.06 BELUGA H 5764.60 5668.00 6914.50 BELUGA_I 6265.60 6169.00 7423.23 BELUGA_J 01503004506007509001050120013501500165018001950South(-)/North(+) (300 usft/in)0 150 300 450 600 750 900 1050 1200 1350 1500 1650 1800 1950 2100 2250 2400 2550 2700West(-)/East(+) (300 usft/in)BRU 221-24 wp02 tgt1BRU 221-24 wp02 tgt27-5/8" x 9-7/8"3-1/2" x 6-3/4"250500750100012501 5 0 01 7 50 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 04000425045004750500052505500575060006250650067506977BRU 221-24 wp02Start Dir 3º/100' : 500' MD, 500'TVDEnd Dir : 2504.35' MD, 2157.39' TVDStart Dir 3º/100' : 3364.35' MD, 2587.39'TVDEnd Dir : 5031.02' MD, 3909.73' TVDTotal Depth : 8146' MD, 6977.39' TVDCASING DETAILSTVDTVDSS MDSize Name3165.00 3068.40 4220.87 7-5/8 7-5/8" x 9-7/8"6977.39 6880.79 8146.00 3-1/2 3-1/2" x 6-3/4"Project: Beluga RiverSite: BRU K-PadWell: Plan: BRU 221-24Wellbore: BRU 221-24Plan: BRU 221-24 wp02WELL DETAILS: Plan: BRU 221-2478.10+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.002633417.00 323331.40 61° 12' 14.8096 N 151° 0' 6.2599 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 221-24, True NorthVertical (TVD) Reference: Permit RKB @ 96.60usft (147)Measured Depth Reference:Permit RKB @ 96.60usft (147)Calculation Method:Minimum Curvature ( # ) * " # + ,-. + / /0 ! ! $&*#$ "## #$%&'&()* !+, .% !-( .0 . +#$%&'&()* !+, 1 + . ! / *) 2 .$) ( 3 *).$) %+*01 , 2 3 %+*2 34242, 5(! 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",%& "%)&./ ",*&// "/&")",%&0 ('*(*('*(*('*(* "+&%) +/& "&*+ +%*&/ "*&.++/& ('*(*('*(*('*(* """&/ .%& "&-* .""&.) "*&)%.%&0 (')"(*(')"(*(')"(* +*&/ "+&% +"&*/ "+&% *-&))"+&%0 (')"(*(')"(*(')"(* +)&*- *& +"&" ..&- %&+-*& (')"(*(')"(*(')"(* """&-+ .& ")&)- +--&-* "%&*/.&0 ( *%'"$($"$() <- *.=- *. !?% !="+&% ),& '"() *123!4! 5),& +,")/& '"() *123!4! 5 6 7 89(& 7 :&0 7 7 $ &0 ; $#< $( =& 5 :: & 7 75267607 8 7 6& 0.001.002.003.004.00Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: BRU 221-24 NAD 1927 (NADCON CONUS)Alaska Zone 0478.10+N/-S+E/-W Northing EastingLatittudeLongitude0.000.00 2633417.00 323331.40 61° 12' 14.8096 N 151° 0' 6.2599 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 221-24, True NorthVertical (TVD) Reference: Permit RKB @ 96.60usft (147)Measured Depth Reference:Permit RKB @ 96.60usft (147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-03-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 4220.00 BRU 221-24 wp02 (BRU 221-24) 3_MWD+AX+Sag4220.00 8146.00 BRU 221-24 wp02 (BRU 221-24) 3_MWD+AX+Sag0.0015.0030.0045.0060.0075.0090.00Centre to Centre Separation (30.00 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)BRU 212-24TBRU 233-23BRU 241-23GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 8146.00Project: Beluga RiverSite: BRU K-PadWell: Plan: BRU 221-24Wellbore: BRU 221-24Plan: BRU 221-24 wp02Ladder / S.F. PlotsCASING DETAILSTVD MD Name Size3165.00 4220.87 7-5/8" x 9-7/8" 7-5/86977.39 8146.00 3-1/2" x 6-3/4" 3-1/2 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 BRU 221-24 BELUGA RIVER 221-24 225-027 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 221-24Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2250270BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes ADL0211282 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 servNA15 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 = 2442 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Max anticipated reservoir pressure is 8.65 ppg EMW, with many sands severley under-pressured.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate4/10/2025ApprBJMDate4/15/2025ApprADDDate4/10/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 4/15/2025