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Home My WebLink About224-135Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250216 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. 162-037 T40080 T40081 T40082 T40082 T40083 T40084 T40085 T40086 T40087 T40088 T40089 T40090 T40091 T40092 T40093 T40094 T40095 T40096 T40097 CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.18 13:06:47 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, January 27, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 10RD2 CANNERY LOOP UNIT 10RD2 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/27/2025 10RD2 50-133-20553-02-00 224-135-0 N SPT 4998 2241350 3000 0 3056 3037 3032 0 0 0 0 OTHER P Josh Hunt 12/28/2024 MIT-T to 3000 psi. Post 3-1/2" tubing completion run, good test. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:CANNERY LOOP UNIT 10RD2 Inspection Date: Tubing OA Packer Depth 0 30 30 30IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH241228141731 BBL Pumped:0.2 BBL Returned:0.2 Monday, January 27, 2025 Page 1 of 1 9 9 9 9 99 9 9 9 9 999 9 9 9 *DVSURGXFHU MIT-T Post 3-1/2" tubing completion run James B. Regg Digitally signed by James B. Regg Date: 2025.01.27 10:56:57 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, January 27, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 10RD2 CANNERY LOOP UNIT 10RD2 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/27/2025 10RD2 50-133-20553-02-00 224-135-0 N SPT 4998 2241350 3000 0 45 45 45 0 0 0 0 OTHER P Josh Hunt 12/28/2024 MIT-IA to 3000 psi. 3-1/2" X 7" Post completion test. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:CANNERY LOOP UNIT 10RD2 Inspection Date: Tubing OA Packer Depth 0 3069 3056 3048IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH241228142958 BBL Pumped:2.5 BBL Returned:2.5 Monday, January 27, 2025 Page 1 of 1 9 9 9 9 9 9 9 9 9 99 9 9 9 9 9 *DVSURGXFHU MIT-IA to 3000 psi Post completion test James B. Regg Digitally signed by James B. Regg Date: 2025.01.27 10:53:11 -09'00' 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: 01/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: CLU-10RD2 PTD: 224-135 API: 50-133-20553-02-00 FINAL LWD FORMATION EVALUATION LOGS (12/08/2024 to 12/25/2024) x DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 224-135 T39987 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.22 14:25:00 -09'00' From:McLellan, Bryan J (OGC) To:Chad Helgeson; Davies, Stephen F (OGC) Cc:Donna Ambruz; Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Date:Monday, January 6, 2025 5:46:00 PM Chad, Hilcorp has approval to perforate per Sundry 324-721. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Monday, January 6, 2025 11:03 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Bryan/Steve, Please see attached the Cement bond log for CLU-10RD2. We have good cement throughout the production interval, except eh UB4 sand where we were taking all the losses from 5830-5890. Please let us know if we have approval to perforate. Thanks Chad Helgeson From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, January 2, 2025 1:46 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Reid CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Edwards <reedwards@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Chad, I’m requesting the well log info to confirm Hilcorp’s reported depth for the base of the Sterling C Gas Storage Pool. Thanks, Steve Davies AOGCC From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, January 2, 2025 11:47 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Reid Edwards <reedwards@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Steve, Hilcorp provides weekly reports (every Wednesday) to AOGCC with the info you are requesting. With the holiday on Wednesday this may not have been distributed yet, but here is the report for CLU-10RD2. Which has: Daily ops summary Depth, hole and casing diameters Cement type, yield, volumes, etc. The logs have not been submitted yet. We are running the cement evaluation for production interval today and will submit this tomorrow. Are you expecting to get open hole logs provided to you before completion sundries will be approved, or is it because we drill through CINGSA Storge sand? Chad From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, January 2, 2025 10:57 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Chad, I’m conducting the geology portion of AOGCC’s review for Hilcorp’s Sundry Application to perforate CLU-10RD2. Could Hilcorp please provide copies of all cementing reports or daily operations summaries that present depths, hole and casing diameters, and cement types, yields, and volumes (sacks, cubic feet, and / or barrels)? I did not find any logs for this well listed in AOGCC’s main well log inventory. Could Hilcorp please provide field-quality copies of all open-hole well logs recorded in this well and, if also recorded, a copy of the cement evaluation log across the production hole section? Images submitted in .pdf format and digital well log data in .las format would be greatly appreciated. Please note that these reports, field-quality logs, and data do not satisfy the final reporting requirements of 20 AAC 25.071. Thanks and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793- 1224 or steve.davies@alaska.gov. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, December 31, 2024 5:26 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: CLU-10RD2 (PTD# 224-135) Sundry Chad, 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. I plan to be in the office Thursday but not tomorrow or Friday. I’ll review the Sundry Thursday and hopefully we can have you something for the weekend. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, December 31, 2024 12:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: CLU-10RD2 (PTD# 224-135) Sundry Bryan, Hilcorp submitted the attached completion sundry for CLU-20RD2 which the rig recently moved off the well. I am sending this email, so you are aware that we would like to start the coil blowdown this weekend (Saturday or Sunday) if we can get approval or a verbal for the coil blowdown of the well. We will be conducting the CBL on Thursday (1/2) and will submit those results to you once we have the log. Ideally, we will have the facility and ready to perf next Tuesday (1/7) or Wednesday, but will wait for sundry approval before starting any of the perforating work. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Davies, Stephen F (OGC); Roby, David S (OGC) Subject:RE: CLU-10RD2 (PTD# 224-135) Sundry Date:Thursday, January 2, 2025 1:27:00 PM Chad, The below approval has the following conditions of approval: 1. Provide 24 hrs notice for AOGCC opportunity to witness BOP test 2. BOP test pressure = 3500 psi. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Thursday, January 2, 2025 1:26 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: CLU-10RD2 (PTD# 224-135) Sundry Chad, Hilcorp has verbal approval to complete the CT cleanout and N2 blowdown portion of the work as described in the referenced sundry application, which has been assigned #324-721. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, December 31, 2024 12:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: CLU-10RD2 (PTD# 224-135) Sundry Bryan, Hilcorp submitted the attached completion sundry for CLU-20RD2 which the rig recently moved off the well. I am sending this email, so you are aware that we would like to start the coil blowdown this weekend (Saturday or Sunday) if we can get approval or a verbal for the coil blowdown of the well. We will be conducting the CBL on Thursday (1/2) and will submit those results to you once we have the log. Ideally, we will have the facility and ready to perf next Tuesday (1/7) or Wednesday, but will wait for sundry approval before starting any of the perforating work. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated outside of ENSTAR/TSU. Do not click links or open attachments unless you recognize the sender and know the content is safe. If you are not sure, use the "Report Phish" button or contact enstar.helpdesk@enstarnaturalgas.com CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Sean McLaughlin To:Matthew Federle; McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: CLU 10RD2 CBL across the CINGSA interval Date:Monday, December 16, 2024 9:57:14 AM The CBL was run prior to drilling out the shoe. From: Matthew Federle <Matthew.Federle@cingsa.com> Sent: Monday, December 16, 2024 8:44 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] RE: CLU 10RD2 CBL across the CINGSA interval Sean, the bottom 100’ or so of the log is missing. From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Saturday, December 14, 2024 11:09 PM To: Matthew Federle <Matthew.Federle@cingsa.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: CLU 10RD2 CBL across the CINGSA interval Matt and Bryan, CLU 10RD2 was drilled through the CINGSA storage interval without issue. Yesterday we ran and cemented 7” intermediate casing. The cement job went as planned. Fox Energy pumped 57.4 bbls of 10.5 ppg spacer, 77 bbls of 12.5 ppg Class G lead, and 35 bbls of 15.3 Class G tail. The plug bump 2 bbls over calculated displacement and 15 bbls of spacer was observed at surface. There was zero bbls lost during the job. 5358’ MD Top Cingsa 5612’ MD Base Cingsa 5708’ TD in the UB3 Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9.Property Designation (Lease Number):10.Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7861 N/A Casing Collapse Structural Conductor 1,500psi Surface 2,260psi Intermediate 3,090psi Intermediate 2 5,410psi 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 7,240psi Baker S-5 BXCE TRSSSV; Ranger LTP 326' MD/ 326' TVD; 5,528' MD/ 5084' TVD See Attached Schematic Perforation Depth TVD (ft): Beluga Gas 20" N/A Length Size CO 231A Same 7,392'3-1/2" 2397 2,337' 7387 7801 7327 Cannery Loop 7,867' Perforation Depth MD (ft): 3,290' (TOW) 13-3/8" 5,700' 7" 5,700' 2,979' 123' 1,953' January 4, 2025 Tieback 3-1/2"See Attached Schematic 5,252' Tubing MD (ft): 123' 9-5/8"3,820' 1,953' MD 5,750psi 3,060psi 5,020psi 123' PRESENT WELL CONDITION SUMMARY Proposed Pools: 9.2# / L-80 TVD Burst 5,523' 10,160psi 1,865' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 60569 224-135 50-133-20553-02-00 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 10RD2 AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Subsequent Form Required: 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: Chad Helgeson, Operations Engineer Tubing Size: No 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 12:51 pm, Dec 31, 2024 324-721 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.12.31 12:20:00 - 09'00' Noel Nocas (4361) Perforate Place 25' of cement on top of any plugs set to isolate lower perf intervals. Exceptions may be made with AOGCC approval. Submit CBL to AOGCC and obtain approval before perforating. CT BOP test to 3500 psi BJM 1/2/25 Yes, for CT Ops only 1/2/25 Bryan McLellan SFD 1/2/2025 X 10-404 MEUIRUMOF Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.01.03 10:11:38 -09'00'01/03/25 RBDMS JSB 010925 Initial Completion Well: CLU-10RD2 Well Name:CLU-10RD2 API Number:50-133-20553-02-00 Current Status:New Drill Gas Producer Permit to Drill Number:224-135 First Call Engineer:Chad Helgeson (907) 229-4824 (c) Second Call Engineer:Scott Warner (907) 830-8863 (c) Maximum Expected BHP:3125 psi @ 7267’ TVD Using 0.43 psi/ft gradient Max. Potential Surface Pressure:2397 psi @ 7267’ TVD Using 0.1 psi/ft gas gradient Applicable Frac Gradient:0.68 psi/ft using 13.2 ppg EMW FIT @ 7” casing shoe 12/16/24 Shallowest Potential Perf TVD:MPSP/(0.68-0.1) = 2397 psi / 0.58 = 4133‘ TVD Top of Pools per CO 231A:Beluga Gas Pool – 5,615’ MD/5,169’ TVD Brief Well Summary CLU-10RD2 was sidetracked from CLU-10RD and completed with Hilcorp Rig 169 December 2024 targeting Beluga sands in Cannery Loop Field. The well was TD’ last week and completed with a 3.5” liner completion. The objective of this sundry is to clean out the production liner with coil tubing, reverse the water from the well and perforate the Beluga sands. Initial targeted sands will be in the Beluga Pool per CO 231A Wellbore Conditions: - Liner filled with 9.1 ppg mud - Tubing and annulus full of 8.35 ppg CI water - MIT-T & IA– 3000 psi - Minimum ID is 2.813” Profile inside SSSV @ 326’ - Maximum Angle is 33.9° @ 2753’ MD - Liner/seal assembly @ 5,523’ MD - CINGSA Pool bottom – 5,615’ MD (5,169’ TVD) Pre sundry well work - Run CBL to bottom on Eline – send log to AOGCC prior to perfs Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 24hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD (7801’) cleanout well and swap well over to 8.4 ppg water 5. Once well is clean with 8.4 ppg water a. Reverse circulate water b. Target recovery = 68 bbls 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Eline Procedure 8. MIRU E-line and pressure control equipment 9. PT lubricator to 250psi low / 2500psi high Agree. SFD Agree. SFD Initial Completion Well: CLU-10RD2 10. Ops pressure up well to ~1500 psi or determined by Reservoir engineer 11. RIH and perforate Lower Beluga Sands from 7,081-7741’,Middle Beluga Sands 6960-6980’and the upper Beluga sands 5965-5980’. a. Proposed perf depths shown on schematic, but the top zone potential is 5,965’ and deepest of 7,741’. b. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. c. Record initial and 5/10/15 minute tubing pressures after firing, d. Pending well production, all perf intervals may not be completed e. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations f. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations g. Above perfs are in the Beluga Gas Pool governed by CO 231A 12. RD E-Line Unit and turn well over to production 13. Operations to flow well and test zones 14. Test SVS as necessary once well has reached stabile flow rates Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 15. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 16. Provide AOGCC 24hrs notice of BOP test 17. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 18. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 19. RDMO coil tubing Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure RIH and set plug above the perforations Dump bail 25' of cement on plugs. - bjm Agree. SFD _____________________________________________________________________________________ Updated by CAH 12-31-24 CURRENT SCHEMATIC Cannery Loop Unit – Pad # 1 Well: CLU-10RD2 PTD: 224-135 API: 50-133-20553-02-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surf 123' 13-3/8'Surface 68 /L-80/ BTC 12.415 Surf 1,953’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835 Surf 3,820’(TOW) 7”Intermediate 2 26 / L-80 / TXPBTC 6.276 Surf 5,700’ 3-1/2”Prod liner 9.2 / L-80 / Hyd 563 2.992 5,530’7,867’ 3-1/2”Tieback 9.2 / L-80 / EUE 8RD 2.992 Surf 5,523’ JEWELRY DETAIL No Depth Item 1 16’Cactus CTF-ONE-CTL 11” Liner Hanger w/ 4” Type H BPV profile 2 326’Baker TRSSSV S-5 BXCE (2.813 X Profile) 3 5,523’Bullet seal assembly spaced 1’ off no-go 4 5,528’Ranger Liner Hanger W/ Scout packer (5.25” ID) OPEN HOLE / CEMENT DETAIL 8-1/2” Pumped 77bbls (200 sks) of 12.5 ppg Class G Lead followed by 35 bbls (155 sks) of 15.3 ppg Class G. Bumped plug. CBL (12- 13-24) shows TOC @ ~3828’ (top of 7”) 6-1/8”Pumped 91bbls (243 sks) of 12.5 ppg Lead and 26.5 bbls (121 sks) of 15.3 ppg tail. Bumped plug. CBL (TBD) PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of CINGA Storage Pool – 5368’ MD/ 4928’ TVD Beluga Pool Top Per 231A- 5615’ MD / 5169’ TVD (Base of CINGSA) Notes: Short jt w/ RA tags 6268, 7390 Short joints 5757, 6780 Agree. SFD _____________________________________________________________________________________ Updated by CAH 12-30-24 PROPOSED Cannery Loop Unit – Pad # 1 Well: CLU-10RD2 PTD: 224-135 API: 50-133-20553-02-00 TD = 7861’ MD / 7387’ TVD PBTD =7801’ MD / 7327’ TVD 20” RKB: 16.05’ 3-1/2” 1 TOW 3,820’ 13-3/8” 9-5/8” 7” 3/4 CLU-10RD TOC @ 3,260’ 2 CINGSA Base 5,615’ MD 5,169’ TVD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / N/A 18.73 Surf 123' 13-3/8' Surface 68 /L-80/ BTC 12.415 Surf 1,953’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835 Surf 3,820’(TOW) 7” Intermediate 2 26 / L-80 / TXPBTC 6.276 Surf 5,700’ 3-1/2” Prod liner 9.2 / L-80 / Hyd 563 2.992 5,530’ 7,867’ 3-1/2” Tieback 9.2 / L-80 / EUE 8RD 2.992 Surf 5,523’ JEWELRY DETAIL No Depth Item 1 16’ Cactus CTF-ONE-CTL 11” Liner Hanger w/ 4” Type H BPV profile 2 326’ Baker TRSSSV S-5 BXCE (2.813 X Profile) 3 5,523’ Bullet seal assembly spaced 1’ off no-go 4 5,528’ Ranger Liner Hanger W/ Scout packer (5.25” ID) OPEN HOLE / CEMENT DETAIL 8-1/2” Pumped 77bbls (200 sks) of 12.5 ppg Class G Lead followed by 35 bbls (155 sks) of 15.3 ppg Class G. Bumped plug. CBL (12- 13-24) shows TOC @ ~3828’ (top of 7”) 6-1/8”Pumped 91bbls (243 sks) of 12.5 ppg Lead and 26.5 bbls (121 sks) of 15.3 ppg tail. Bumped plug. CBL (TBD) PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of CINGA Storage Pool – 5368’ MD/ 4928’ TVD Beluga Pool Top Per 231A- 5615’ MD / 5169’ TVD (Base of CINGSA) UB 5 ±5965’±5980’ ±5511’ ±5526’±15 Proposed TBD MB 7 ±6960’±6980’ ±6487’ ±6507’±20 Proposed TBD LB Upr ±7081’±7088’ ±6608’ ±6615’±7 Proposed TBD LB Mid ±7092’ ±7098’ ±6619’ ±6625’±6 Proposed TBD LB Lwr ±7104’ ±7109’ ±6631’ ±6636’±5 Proposed TBD LB 1A ±7142’±7162’ ±6669’ ±6699’±20 Proposed TBD LB 1C Upr ±7172’ ±7177’ ±6699’ ±6704’±5 Proposed TBD LB 1D ±7212’ ±7218’ ±6739’ ±6745’±6 Proposed TBD LB 1E ±7257’ ±7261’ ±6784’ ±6788’±4 Proposed TBD LB 1F Upr ±7268’ ±7271’ ±6794’ ±6797’±3 Proposed TBD LB 1F Mid ±7292’ ±7295’ ±6818’ ±6821’±3 Proposed TBD LB 1F Lwr ±7321’ ±7327’ ±6847’ ±6853’±6 Proposed TBD LB 1G Upr ±7348’ ±7356’ ±6874’ ±6882’±8 Proposed TBD LB 1G Mid ±7363’ ±7366’ ±6889’ ±6892’±3 Proposed TBD LB 1G lwr ±7375’ ±7383’ ±6901’ ±6909’±8 Proposed TBD LB 2 ±7402’ ±7419’ ±6928’ ±6945’±17 Proposed TBD LB 2B Upr ±7482’ ±7490’ ±7008’ ±7016’±8 Proposed TBD LB 2B Lwr ±7494’ ±7506’ ±7020’ ±7032’±12 Proposed TBD LB2C Upr ±7523’ ±7528’ ±7049’ ±7054’±5 Proposed TBD LB 3 ±7732’ ±7741’ ±7258’ ±7267’±9 Proposed TBD Notes: Short jt w/ RA tags 6268, 7390 Short joints 5757, 6780 Agree. SFDBeluga Pool Top Per 231A- 5615’ MD / 5169’ TVD (Base of CINGSA) STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Reid Edwards To:Davies, Stephen F (OGC); Chad Helgeson Cc:Donna Ambruz; Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC); Sean McLaughlin Subject:RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Date:Thursday, January 2, 2025 2:26:16 PM Attachments:CLU 10RD2 LWD REC 5TVD.pdf CLU 10RD2 LWD REC.las CLU 10RD2 LWD REC 5MD.pdf Steve, I’ve attached PDFs of the LWD MD and TVD logs as well as the LWD las file. Let me know if these will be sufficient Reid Edwards Sr Reservoir Engineer Kenai Team Hilcorp Alaska 907-777-8421 (work) 907-250-5081 (mobile) From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, January 2, 2025 1:46 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Reid Edwards <reedwards@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Chad, I’m requesting the well log info to confirm Hilcorp’s reported depth for the base of the Sterling C Gas Storage Pool. Thanks, Steve Davies AOGCC From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, January 2, 2025 11:47 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Reid Edwards <reedwards@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Steve, Hilcorp provides weekly reports (every Wednesday) to AOGCC with the info you are requesting. With the holiday on Wednesday this may not have been distributed yet, but here is the report for CLU- 10RD2. Which has: Daily ops summary Depth, hole and casing diameters Cement type, yield, volumes, etc. The logs have not been submitted yet. We are running the cement evaluation for production interval today and will submit this tomorrow. Are you expecting to get open hole logs provided to you before completion sundries will be approved, or is it because we drill through CINGSA Storge sand? Chad From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, January 2, 2025 10:57 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] RE: CLU-10RD2 (PTD# 224-135) Sundry - Requests Chad, I’m conducting the geology portion of AOGCC’s review for Hilcorp’s Sundry Application to perforate CLU-10RD2. Could Hilcorp please provide copies of all cementing reports or daily operations summaries that present depths, hole and casing diameters, and cement types, yields, and volumes (sacks, cubic feet, and / or barrels)? I did not find any logs for this well listed in AOGCC’s main well log inventory. Could Hilcorp please provide field-quality copies of all open-hole well logs recorded in this well and, if also recorded, a copy of the cement evaluation log across the production hole section? Images submitted in .pdf format and digital well log data in .las format would be greatly appreciated. Please note that these reports, field-quality logs, and data do not satisfy the final reporting requirements of 20 AAC 25.071. Thanks and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793- 1224 or steve.davies@alaska.gov. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, December 31, 2024 5:26 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: CLU-10RD2 (PTD# 224-135) Sundry Chad, I plan to be in the office Thursday but not tomorrow or Friday. I’ll review the Sundry Thursday and hopefully we can have you something for the weekend. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, December 31, 2024 12:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> 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. Subject: CLU-10RD2 (PTD# 224-135) Sundry Bryan, Hilcorp submitted the attached completion sundry for CLU-20RD2 which the rig recently moved off the well. I am sending this email, so you are aware that we would like to start the coil blowdown this weekend (Saturday or Sunday) if we can get approval or a verbal for the coil blowdown of the well. We will be conducting the CBL on Thursday (1/2) and will submit those results to you once we have the log. Ideally, we will have the facility and ready to perf next Tuesday (1/7) or Wednesday, but will wait for sundry approval before starting any of the perforating work. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________CANNERY LOOP UNIT 10RD2 JBR 01/30/2025 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 4-1/2" joint. Upper Kelly replaced for a pass. Test Results TEST DATA Rig Rep:Jon Van EveraOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Rig Owner/Rig No.:Hilcorp 169 PTD#:2241350 DATE:12/7/2024 Type Operation:DRILL Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM241210201400 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 2447 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 FP Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2-7/8"x5"P #2 Rams 1 Blinds P #3 Rams 1 2-7/8"x5"P #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/P Kill Line Valves 3 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3025 Pressure After Closure P1700 200 PSI Attained P22 Full Pressure Attained P92 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2437 ACC Misc NA0 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 P13 #1 Rams P4 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 99999 9 9 9 9 9 FP Upper Kelly replaced 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: Cannery Loop Unit Field, Beluga Gas Pool, CLU-10RD2 Hilcorp Alaska, LLC Permit to Drill Number: 224-135 Surface Location: 274' FSL, 520' FEL, Sec 7, T5N, R11W, SM, AK Bottomhole Location: 369' FSL, 1406' FWL, Sec 8, T5N, R11W, 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 26th day of November 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.26 10:59:04 -09'00' 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: 7,699' TVD: 7,197' 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): 37.8' 15. Distance to Nearest Well Open Surface: x-272452 y-2388727 Zone-4 19.8' to Same Pool: 980' to CLU-09 16. Deviated wells:Kickoff depth: 3,820 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 34 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 7" 26# L-80 TXP 5,793' Surface Surface 5,793' 5,342' 6-1/8" 3-1/2" 9.2# L-80 Hyd 563 2,076' 5,593' 5,146' 7,669' 7,197' Tieback 3-1/2" 9.2# L-80 EUE 8RD 5,593' Surface Surface 5,593' 5,146' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): N/A TVD 123' 1,866' 3,449' 5,235' 7,836' 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 CLU-10RD2 Cannery Loop Unit Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Will be plugged PreDrill 417 sx 5,921'7" 9-5/8" 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 Tieback Assy. 2447 369' FSL, 1406' FWL, Sec 8, T5N, R11W, SM, AK 369' FSL, 1406' FWL, Sec 8, T5N, R11W, SM, AK LOCI 78-156 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 274' FSL, 520' FEL, Sec 7, T5N, R11W, SM, AK ADL 60569 18. Casing Program:Top - Setting Depth - BottomSpecifications 3167 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) 526 ft3 396 ft3 7,290'6,393' Effect. Depth MD (ft):Effect. Depth TVD (ft): 8,803'7,838' LengthCasing 7,290' Size Will be plugged PreDrill Conductor/Structural 20"123' Authorized Title: Authorized Signature: 4-1/2" Authorized Name: Production Liner 4,129' 2,044' 3,119' Intermediate Driven 123' 1,953'13-3/8"606 sx 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): 1,953' 3,820' (TOW) 305 sx 330 sx 12/5/2024 2674' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 8,801' 183 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) By Grace Christianson at 2:35 pm, Nov 13, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.11.13 12:32:15 - 09'00' Sean McLaughlin (4311) A.Dewhurst 19NOV24 Notify AOGCC if OAP reacts to FIT/LOT pressure and if so, obtain approval before drilling 8.5" hole. BOP test to 3000 psi, annular test to 2500 psi. Submit FIT/LOT data within 48 hrs of performing test. Submit 7" CBL within 48 hrs of running log. 50-133-20553-02-00 3:26 pm, Nov 19, 2024 224-135 DSR-11/21/24BJM 11/25/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.26 10:59:22 -09'00' 11/26/24 11/26/24 RBDMS JSB 112924 CLU 10RD2 PTD Program V2 Cannery Loop November 9, 2024 CLU 10RD2 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 Current Schematic (Plugging Plan) .............................................................................................6 7.0 Planned Wellbore Schematic........................................................................................................7 8.0 Drilling / Completion Summary...................................................................................................8 9.0 Mandatory Regulatory Compliance / Notifications....................................................................9 10.0 R/U and Preparatory Work........................................................................................................11 11.0 BOP N/U and Test........................................................................................................................12 12.0 Set Whipstock / Mill Window.....................................................................................................12 13.0 Drill 8-1/2” Hole Section..............................................................................................................14 14.0 Run 7” Intermediate Casing.......................................................................................................15 15.0 Cement 7” Intermediate Casing.................................................................................................17 16.0 Drill 6-1/8” Hole Section..............................................................................................................20 17.0 Run 3-1/2” Production Liner......................................................................................................22 18.0 Cement 3-1/2” Production Liner................................................................................................26 19.0 3-1/2” Liner Tieback Polish Run................................................................................................29 20.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................29 21.0 BOP Schematic.............................................................................................................................30 22.0 Wellhead Schematic.....................................................................................................................31 23.0 Anticipated Drilling Hazards......................................................................................................32 24.0 Hilcorp Rig 169 Layout...............................................................................................................33 25.0 Choke Manifold Schematic.........................................................................................................34 26.0 Casing Design Information.........................................................................................................35 27.0 8-1/2” Hole Section MASP..........................................................................................................36 28.0 6-1/8” Hole Section MASP..........................................................................................................37 29.0 Spider Plot (660’).........................................................................................................................38 30.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................39 Page 2 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 1.0 Well Summary Well CLU 10RD2 Rig 169 Pad & Old Well Designation Cannery Loop – Pad 1 Sidetrack Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Beluga Planned Well TD, MD / TVD 7669 MD / 7197’ TVD PBTD, MD / TVD 7699’ MD AFE Number AFE Days AFE Amount Maximum Anticipated Pressure (Surface)2447 psi Maximum Anticipated Pressure (Downhole/Reservoir)3167 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 37.8 Ground Elevation 19.8 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 2.0 Management of Change Information Page 4 Version PTD V2 November 9, 2024 CLU 10RD2 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) 8-1/2”7 6.276 6.151 7.656 26 L-80 TXP 7240 5410 604 6-1/8”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 *Ensure at least 100’ of overlap between casing and liner 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version PTD V2 November 9, 2024 CLU 10RD2 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 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 6.0 Current Schematic (Plugging Plan) Page 7 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 7.0 Planned Wellbore Schematic Page 8 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 8.0 Drilling / Completion Summary CLU 10RD2 is an S-shaped sidetrack development well to be drilled from Cannery Loop Pad 1. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga sands. The base plan is a slant wellbore with a kickoff point at ~3820’ MD. An Intermediate casing string will be run and cemented across the CINGSA gas storage pool. Maximum hole angle will be ~27 deg. and TD of the well will be 7669’ TMD/ 7197’ TVD. Vertical separation will be 1937 ft. Drilling operations are expected to commence approximately December 2024. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. Planned Pre Rig operations: - Abandon the CLU 10RD reservoir - Decomplete 4-1/2” tubing - Test casing to 3000 psi General sequence of operations: 1. Rig 169 will MIRU over CLU 10RD 2. NU BOPE and test to 3000 psi. (MASP 2447psi) 3. Set 9-5/8” 40# whipstock at 3820’ and 45L. Swap well to 9.0 ppg mud. 4. Mill window with 20’ of new formation. 5. Perform FIT to 13.0 ppg EMW 6. MU 8-1/2” bit with 6-3/4” tools (Triple Combo) 7. Drill 8-1/2” Intermediate hole to 5793’ MD 8. Run 7” Intermediate casing. TOC planned to 2820’ MD 9. Swap casing rams to VBRs, Remove single gate, Add tubing spool 10. Rig up eline and run CBL. Perform casing test to 3700 psi 11. MU 6-1/8” bit with 4-3/4” tools (Triple Combo) 12. Drill out casing shoe and preform FIT to 13 ppg EMW. 13. Drill 6-1/8” production hole to 7669’ MD 14. RIH w/ 3-1/2” liner. Set liner and cement. Circ wellbore clean. 15. Perform Clean out run to polish bore, LDDP 16. Perform liner lap test to 3000 psi. 17. Run 3-1/2” tie back completion. 18. Land hanger and test.MIT-T to 3000 psi, MIT-IA to 3000 psi 19. ND BOPE, NU tree and test void Reservoir Evaluation Plan: -bjmPre-rig operations are included in a separate "plug for redrill" sundry for the CLU-10RD well. Page 9 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx Intermediate Hole: Triple Combo Production Hole: Triple Combo 9.0 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 CLU 10RD2. Ensure to provide AOGCC 24 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 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 10 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” and 6-1/8” 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 (remove while drilling production hole) 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 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. 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) Page 11 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 10.0 R/U and Preparatory Work 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. 8-1/2” 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, and Toolpusher 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 3820’- 5793’9.0– 10.2 40-53 15-25 15-25 8.5-9.5 11.0 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 8.8 – 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 6. 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 Page 12 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx with 5-1/2” liners. 11.0 BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. 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 7” fixed 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. 3. Run BOPE test plug. 4. Test BOPE. x Test BOP to 250/3000 psi for 5/10 min. x 7” test joint required for FBR x Test VBR’s with 4-1/2” and 3-1/2 test joint x Test annular to 250/2500 psi for 5/10 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. 5. Mix 9.0 ppg 6% KCL PHPA mud system. 6. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 12.0 Set Whipstock / Mill Window Operation Steps: 1. Pull test plug. Set wear bushing in wellhead. Ensure ID of wear bushing > 8.5”. 2. Make up the WIS Mechanical set Whipstock. Page 13 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 4. Orient whipstock as directed by the directional driller. The directional plan specifies 45 deg LOHS. 5. Set the top of the whipstock at ~3820’ MD (confirm depth after RWO) x 9-5/8” Collars at 3812’ and 3855’. x Ref log: YJOC CBL CLU-10RD 09-SEPT-2022 (9-5/8” TOC @ 3425’) x Parent well plugged to TBD 6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 13.0 ppg. ¾**Assuming the kick zone is at TD, a FIT of 13.0 ppg EMW gives a Kick Tolerance volume of 88 bbls with 9.2 ppg mud weight. ¾Monitor OA during FIT and report and change in pressure. 8. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. Notify AOGCC if OA pressure is impacted by FIT/LOT. -bjm Page 14 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx ¾Before pulling the BHA through the BOPE. 9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 13.0 Drill 8-1/2” Hole Section 1. P/U 6-3/4” Sperry Sun motor drilling assy w/ triple combo tools (DEN, POR, RES) and 8-1/2” bit 2. Ensure BHA components have been inspected previously. 3. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~400 gpm. 6. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 7. TIH to window. Shallow test MWD on trip in. 8. Circulate well with 9.0 ppg mud to warm up mud until good 9.0 ppg in and out. 9. Drill 8-1/2” hole to 5793’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. 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. x Minimize backreaming when working tight hole x CINGSA gas storage reservoir between 5358’ – 5605’ MD. x Critical Casing Shoe: Geologist to confirm that the CINGSA gas storage interval has been drilled and casing shoe is set at the base of the UB 1/2. 10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. Page 15 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 11. Clean out wellbore as necessary 12. TOH with drilling assembly, handle BHA as appropriate. 13. Confirm 7” FBR previously installed in BOP stack and tested with 7” test joint. 14.0 Run 7” Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7” casing running equipment. x Ensure 7” TXP x CDS40 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Ensure all casing has been drifted to 6.125” on the location prior to running. x Note that 26# drift is 6.151” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80’ shoe track assembly consisting of: 7” Float Shoe 1 joint – 7” BTC, 1 Centralizer 10’ from bottom w/ stop ring 7” Float Collar 1 joint – 7” BTC, 1 Free floating centralizer 7” Landing collar 5. Continue running 7” intermediate casing x Centralization: x 1 centralizer every joint to the window x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 16 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx Page 17 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 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. 9. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 10. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging. Stage up pump slowly and monitor losses closely while circulating. 11. After circulating, lower string and land hanger in wellhead again. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 15.0 Cement 7” Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x Determine which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Confirm positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. Page 18 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to 2820. Estimated Cement Volume: Verified cement calcs. -bjm Page 19 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, and cementers during the entire job. 11. Ensure rig pump is used to displace cement. 12. Land hanger. 13. Displacement volume is in Table above. 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 17. Not expected, but be prepared for cement returns to surface. Cement returns to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 18. R/D cement equipment. Flush out wellhead with FW. 19. Back out and L/D landing joint. Flush out wellhead with FW. 20. 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. 21. 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 Page 20 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 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 sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 16.0 Drill 6-1/8” Hole Section 1. Set test plug. Remove Single gate due to wellhead height restrictions. Add tubing spool. Swap 7” FBR to 2-7/8” x 5” VBR, test with 4-1/2” and 3-1/2” test joints to 3000 psi.,.Test all breaks. Pull test plug, run and set wear bushing. 2.Run CBL across the 7” casing. 3. Ensure BHA components have been inspected previously. 4. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly. 6. Ensure TF offset is measured accurately and entered correctly into the MWD software. 7. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 8. 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. 9. 6-1/8” hole section mud program summary: Starting mud weight for the production interval is 9.2 ppg or the intermediate interval mud weight at TD, whichever is heavier. Run CBL across the 7” casing.Please provide copy of CBL to both AOGCC and CINGSA as per Beluga Oil Pool Rule 3. Page 21 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 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, and Toolpusher office. System Type:9.2 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 5793’- 7669’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 10. TIH w/ 4-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 11. R/U and test casing to 3700 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7” L-80 burst is 7240 psi / 2 = 3620 psi. 12. Drill out shoe track and 20’ of new formation. 13. CBU and condition mud for FIT. 14. Conduct FIT to 13 ppg (8.5 ppg BHP, 9.2 ppg MW = unlimited bbl KTV) 15. Drill 6-1/8” hole section to 7669’ MD / 7197’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 gpm. Ensure shaker screens are set up to handle this flowrate. Page 22 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through to interval make a wiper trip to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. 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. x LC Risk is UB3/4: Minimize ECD, Surge, and ROP when drilling through the UB3/4 to reduce LC risk. Include background LCM and Black Products in the mud 16. At TD; pump sweeps, CBU, and pull a wiper trip back to the 7” shoe. 17. TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 18. POOH LDDP and BHA. 19. Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint 17.0 Run 3-1/2” Production Liner 1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” Liner 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. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 4. Continue running 3-1/2” production liner Page 23 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 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” window. Leave the centralizers free floating. 5. Continue running 3-1/2” production liner Page 24 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx Page 25 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 6. Run in hole w/ 3-1/2” liner to the 7” shoe. 7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 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. 11. Set casing slowly in and out of slips. 12. PU 3-1/2” X 7” 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. 13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 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. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 26 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 18.0 Cement 3-1/2” Production Liner 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 cementing 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. 2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 3. Pump 5 bbls spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining spacer. 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 27 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx Estimated Total Cement Volume: 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. 8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 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. 10. Bump the plug and pressure up to up as required by Hanger provider to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 11. Slack off total liner weight plus 30k to confirm hanger is set. Page 28 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 12. Do not overdisplace by more than 2x shoe track volume. Shoe track volume is 0.7 bbls. 13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17. Pressure up drill pipe to 500 psi and pick up to remove the packoff bushing from the nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 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. 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. 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. 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 Page 29 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 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. 19.0 3-1/2” Liner Tieback Polish Run 1. No liner cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 3000 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 3. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe. 4. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC procedure. 5. POOH, and LDDP and polish mill. 20.0 3-1/2” Tieback Run, ND/NU, RDMO 1. Run 3-1/2” tubing completion assembly to above the liner top x Tubing will be 3-1/2” L-80 9.2# EUE 8rd x SSSV required ~350’ 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4. Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 30 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 21.0 BOP Schematic Single Gate to be removed for production hole due to wellhead height. Page 31 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 22.0 Wellhead Schematic Page 32 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 23.0 Anticipated Drilling Hazards 8-1/2 and 6-1/8” 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. 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 pressures are present in this hole section. Page 33 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 24.0 Hilcorp Rig 169 Layout Page 34 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 25.0 Choke Manifold Schematic Page 35 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 26.0 Casing Design Information Page 36 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 27.0 8-1/2” Hole Section MASP Page 37 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 28.0 6-1/8” Hole Section MASP Page 38 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 29.0 Spider Plot (660’) Page 39 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx 30.0 Surface Plat (As-Built NAD27 & NAD83) Page 40 Version PTD V2 November 9, 2024 CLU 10RD2 Drilling Procedure PTD# xxx-xxx !"# $% &"'('' ) "* ) " 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175 6500 6825 7150 7475 7800True Vertical Depth (650 usft/in)975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 Vertical Section at 87.39° (650 usft/in) CLU-10RD2 wp05 T1 4 0 0 0 4 5 0 0 5 0 0 0 55 00 6000 6500 7000 7500 8000 Cannery Loop Unit 10 4 0 0 0 4 5 0 0 5 000 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 500 88 03 CLU-10RD 9 5/8" TOW 7" x 8 1/2" 3 1/2" x 6 1/8" 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7000 7500 7669 CLU-10RD2 wp05 KOP: 12.3º/100' : 3820' MD, 3448.82'TVD : 45° LT TF End Dir : 3837' MD, 3464.07' TVD Start Dir 3º/100' : 3937' MD, 3553.17'TVD End Dir : 4699.24' MD, 4274.34' TVD Start Dir 3º/100' : 6549.14' MD, 6079.84'TVD End Dir : 6968.47' MD, 6495.8' TVD Total Depth : 7068.47' MD, 6595.8' TVD Top CINGSA Base CINGSA UB 1/2 UB4 Lower Beluga LB 2B 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: Cannery Loop Unit 10 Ground Level: 19.80 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2388727.51 272451.95 60° 31' 56.845 N 151° 15' 48.377 W SURVEY PROGRAM Date: 2024-09-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 131.80 3820.00 CLU-10 (Cannery Loop Unit 10) 3_MWD 3820.00 4220.00 CLU-10RD2 wp05 (Plan: CLU-10RD2) 3_MWD_Interp Azi+Sag 4220.00 5793.00 CLU-10RD2 wp05 (Plan: CLU-10RD2) 3_MWD+IFR1+MS+Sag 5793.00 7669.48 CLU-10RD2 wp05 (Plan: CLU-10RD2) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 4916.80 4879.00 5357.50 Top CINGSA 5158.80 5121.00 5605.45 Base CINGSA 5210.80 5173.00 5658.73 UB 1/2 5376.80 5339.00 5828.82 UB4 6595.80 6558.00 7068.47 Lower Beluga 6998.80 6961.00 7471.47 LB 2B REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 10, True North Vertical (TVD) Reference:CLU-10RD As-Built @ 37.80usft Measured Depth Reference:CLU-10RD As-Built @ 37.80usft Calculation Method: Minimum Curvature Project:Kenai C.I.U. Site:Cannery Loop Unit #1 Pad Well:Plan: Cannery Loop Unit 10 Wellbore: Plan: CLU-10RD2 Design:CLU-10RD2 wp05 CASING DETAILS TVD TVDSS MD Size Name 3448.82 3411.02 3820.00 9-5/8 9 5/8" TOW 5342.00 5304.20 5793.16 7 7" x 8 1/2" 7196.81 7159.01 7669.48 3-1/2 3 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 3820.00 25.51 105.40 3448.82 -249.49 1346.12 0.00 0.00 1333.34 KOP: 12.3º/100' : 3820' MD, 3448.82'TVD : 45° LT TF 2 3837.00 26.99 102.06 3464.07 -251.27 1353.42 12.30 -45.00 1340.56 End Dir : 3837' MD, 3464.07' TVD 3 3937.00 26.99 102.06 3553.17 -260.75 1397.81 0.00 0.00 1384.47 Start Dir 3º/100' : 3937' MD, 3553.17'TVD 4 4699.24 12.58 43.62 4274.34 -236.47 1627.30 3.00 -151.47 1614.83 End Dir : 4699.24' MD, 4274.34' TVD 5 6549.14 12.58 43.62 6079.84 55.21 1905.25 0.00 0.00 1905.79 Start Dir 3º/100' : 6549.14' MD, 6079.84'TVD 6 6968.47 0.00 0.00 6495.80 88.40 1936.88 3.00 180.00 1938.90 End Dir : 6968.47' MD, 6495.8' TVD 7 7068.47 0.00 0.00 6595.80 88.40 1936.88 0.00 0.00 1938.90 8 7669.48 0.00 0.00 7196.81 88.40 1936.88 0.00 0.00 1938.90 Total Depth : 7068.47' MD, 6595.8' TVD -298-255-213-170-128-85-4304385128170213255298South(-)/North(+) (85 usft/in)1275 1318 1360 1403 1445 1488 1530 1573 1615 1658 1700 1743 1785 1828 1870 1913 1955 1998 2040 2083West(-)/East(+) (85 usft/in)CLU-10RD2 wp05 T13250350037504000Cannery Loop Unit 103250350037504 0 0 0 42 5 045004750CLU-10RD9 5/8" TOW7" x 8 1/2"3 1/2" x 6 1/8"3250350037504 0 0 04250450047505000525055005750600062506500675070007197CLU-10RD2 wp05KOP: 12.3º/100' : 3820' MD, 3448.82'TVD : 45° LT TFEnd Dir : 3837' MD, 3464.07' TVDStart Dir 3º/100' : 3937' MD, 3553.17'TVDEnd Dir : 4699.24' MD, 4274.34' TVDStart Dir 3º/100' : 6549.14' MD, 6079.84'TVDEnd Dir : 6968.47' MD, 6495.8' TVDTotal Depth : 7068.47' MD, 6595.8' TVDCASING DETAILSTVDTVDSS MDSize Name3448.82 3411.02 3820.00 9-5/8 9 5/8" TOW5342.00 5304.20 5793.16 7 7" x 8 1/2"7196.81 7159.01 7669.48 3-1/2 3 1/2" x 6 1/8"Project: Kenai C.I.U.Site: Cannery Loop Unit #1 PadWell: Plan: Cannery Loop Unit 10Wellbore: Plan: CLU-10RD2Plan: CLU-10RD2 wp05WELL DETAILS: Plan: Cannery Loop Unit 10Ground Level: 19.80+N/-S +E/-W Northing Easting Latitude Longitude0.00 0.002388727.51 272451.95 60° 31' 56.845 N151° 15' 48.377 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 10, True NorthVertical (TVD) Reference:CLU-10RD As-Built @ 37.80usftMeasured Depth Reference:CLU-10RD As-Built @ 37.80usftCalculation Method:Minimum Curvature +# ) # " ,# -. ,# " / / !" 0)#0" 12 #$%$%& % ! 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eparation Factor4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000 6200 6400 6600 6800 7000 7200 7400 7600Measured DepthCannery Loop Unit 10CLU-10RDNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: Cannery Loop Unit 10 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 19.80+N/-S+E/-W Northing EastingLatitudeLongitude0.000.002388727.51 272451.95 60° 31' 56.845 N 151° 15' 48.377 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 10, True NorthVertical (TVD) Reference:CLU-10RD As-Built @ 37.80usftMeasured Depth Reference:CLU-10RD As-Built @ 37.80usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2024-09-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool131.80 3820.00 CLU-10 (Cannery Loop Unit 10) 3_MWD3820.00 4220.00 CLU-10RD2 wp05 (Plan: CLU-10RD2) 3_MWD_Interp Azi+Sag4220.00 5793.00 CLU-10RD2 wp05 (Plan: CLU-10RD2) 3_MWD+IFR1+MS+Sag5793.00 7669.48 CLU-10RD2 wp05 (Plan: CLU-10RD2) 3_MWD+IFR1+MS+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000 6200 6400 6600 6800 7000 7200 7400 7600Measured DepthCannery Loop Unit 10CLU-10RDGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference3820.00 To 7669.48Project: Kenai C.I.U.Site: Cannery Loop Unit #1 PadWell: Plan: Cannery Loop Unit 10Wellbore: Plan: CLU-10RD2Plan: CLU-10RD2 wp05Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name3448.82 3411.02 3820.00 9-5/8 9 5/8" TOW5342.00 5304.20 5793.16 7 7" x 8 1/2"7196.81 7159.01 7669.48 3-1/2 3 1/2" x 6 1/8" Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-135 CLU 10RD2 KENAI C.L.U. BELUGA GAS WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:CANNERY LOOP UNIT 10RD2Initial Class/TypeDEV / PENDGeoArea820Unit10320On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241350KENAI C.L.U., BELUGA GAS - 449575NA1 Permit fee attachedYes Well location in Hilcorp fee lease (formerly ADL 060569)2 Lease number appropriateYes3 Unique well name and numberYes KENAI C.L.U., BELUGA GAS - 449575 - governed by CO 231A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA Sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA20 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 pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2447 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 Measures not required. Nearby wells did not encounter H2S gas.35 Permit can be issued w/o hydrogen sulfide measuresYes Sterling to Upper Beluga intervals all expected to be under-pressured to severely under-pressured36 Data presented on potential overpressure zonesNA with normal pressures at TD.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate11/19/2024ApprBJMDateApprADDDate11/19/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 11/26/2024