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Home My WebLink About224-156Alaska 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 January 15, 2026 Greg Hobbs Regulatory Engineer, Wells Team ConocoPhillips Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: OTH-25-050 Notice of Violation – Closeout Late Log and Geologic Data Submittal KRU 3S-714 (PTD 224-151), KRU 3T-616 (224-138), KRU 3T-731 (224-156), KRU 3S- 723 (225-016), KRU 3T-730 (225-010), KRU 3S-703 (225-035) Dear Mr. Hobbs: ConocoPhillips Alaska, Inc responded to the above referenced notice of violation by electronic letter dated November 4, 2025. The missing data sets noted on the NOV were all submitted by November 3, 2025. The Alaska Oil and Gas Conservation Commission does not intend to pursue any further enforcement action regarding the late log and geologic data submittal. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: Phoebe Brooks Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2026.01.14 08:24:23 -09'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2026.01.15 08:21:30 -09'00' November 4, 2025 Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Comm’n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Gregory Wilson Commissioner Alaska Oil and Gas Conservation Comm’n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 VIA E-MAIL (samantha.coldiron@alaska.gov) Re: Docket No. OTH-25-050 Notice of Violation – Late Log and Geologic Data Submittal Commissioners Chmielowski and Wilson: On October 23, 2025, the AOGCC sent a Notice of Violation (NOV) to ConocoPhillips Alaska, Inc. (CPAI) regarding the late submission of logging and geologic data for six Kuparuk River Unit wells. The NOV ordered CPAI to submit the missing data within 14 days. As of November 3, 2025, all of these missing data have been submitted. These submissions completed 1 full set and 5 partial sets of data owed to the AOGCC by CPAI. The exercise reinforced the AOGCC requirements for image logs delivery formats, redefined internal requirements of a complete package, and highlighted log provider delivery issues that have been addressed by CPAI. Please find the acknowledged transmittals for the data attached. If there are further questions or requests, do not hesitate to reach out. Sincerely, Greg Hobbs Regulatory Engineer, Wells Team ConocoPhillips Alaska, Inc. Attachments Greg Hobbs, P.E. Regulatory Engineer, Wells Team 700 G Street, ATO 1504 Anchorage, AK 99501 (907) 263-4749 (office) Greg.S.Hobbs@conocophillips.com By Samantha Coldiron at 3:44 pm, Nov 04, 2025 Greg Hobbs Digitally signed by Greg Hobbs Date: 2025.11.04 15:06:07 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:1 Township:12N Range:7E Meridian:Umiat Drilling Rig:Rig Elevation:Total Depth:13269 ft MD Lease No.:ADL 025528 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 120 Feet Csg Cut@ Feet Surface:10 3/4"O.D. Shoe@ 2625 Feet Csg Cut@ Feet Intermediate:7 5/8"O.D. Shoe@ 4809 Feet Csg Cut@ Feet Production:4 1/2"O.D. Shoe@ 13259 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet Tubing:4 1/2"O.D. Tail@ 4800 Feet Tbg Cut@ 4559 Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Other 7879 ft 4564 ft 8.7 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1730 1650 1620 IA 1070 1070 1070 OA 100 100 100 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Sid Ferguson Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Plug is for a redrill. Top of cement was at the top of the retainer as designed, to allow room for setting the kickoff whipstock. No cement sample was taken as cement was through retainer. October 31, 2025 Bob Noble Well Bore Plug & Abandonment KRU 3T-731 ConocoPhillips Alaska Inc. PTD 2241560; Sundry 325-593 none Test Data: P Casing Removal: rev. 3-24-2022 2025-1031_Plug_Verification_KRU_3T-731_bn                   Fullbore T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3T-616 PB2 Pixstar 224-138 DATE: 10/10/2025 Transmitted: 3T-616 PB2 Pixstar Updated Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-616 PB2 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 224-138 T41019 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.21 09:42:24 -08'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3T-616 Pixstar 224-138 DATE: 10/21/2025 Transmitted: 3T-616 Pixstar Updated Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-616 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 224-138 T41018 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.21 09:38:53 -08'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3T-730 225-010 DATE:10/24/2025 Transmitted: 3T-730 EcoScope Image File Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-730 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 225-010 T41035 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 08:24:59 -08'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3S-714 Mudlog Image File DATE: 10/27/2025 Transmitted: 3S-714 Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3S-714 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 224-151 T41037 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 14:15:39 -08'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3T-731 Microscope Image File DATE:10/27/2025 Transmitted: 3T-731 Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-731 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 224-156 T41036 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 14:14:24 -08'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3S-703 DATE:11/03/2025 Transmitted: 3S-703 Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3S-703 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 225-035 T41048 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.03 12:57:06 -09'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3S-723 DATE:11/03/2025 Transmitted: 3S-723 Pixstar Updated Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3S-723 - e-transmittal well folder Receipt: Date: 225-016 T40739 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.03 13:00:48 -09'00' Alaska/IT-Data Services |ConocoPhillips Alaska | 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 October 23, 2025 CERTIFIED MAIL – RETURN RECEIPT 7018 0680 0002 2052 9846 Greg Hobbs Regulatory Engineer, Wells Team ConocoPhillips Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: OTH-25-050 Notice of Violation (NOV) – Late Log and Geologic Data Submittal KRU 3S-714 (PTD 224-151), KRU 3T-616 (224-138), KRU 3T-731 (224-156), KRU 3S- 723 (225-016), KRU 3T-730 (225-010), KRU 3S-703 (225-035) Dear Mr. Hobbs: Regulation 20 AAC 25.071 establishes the due date for logs and geologic data acquired during well work, and the types of data to be submitted to the Alaska Oil and Gas Conservation Commission (AOGCC). Per 20 AAC 25.071(b), data are due to the AOGCC within 90 days after completion, suspension, or plugging of a well or well branch, or not later than 90 days after the date of acquisition of the data, whichever occurs first. The following table lists wells with data that has not been submitted to the AOGCC within the 90-day time frame: PTD Well Name Date Well Completed Date Data Due Data Not Submitted 224-151 KRU 3S-714 2/24/2025 5/25/2025 mudlog image files, show reports 224-138 KRU 3T-616 3/9/2025 6/7/2025 PixStar image file 224-156 KRU 3T-731 4/11/2025 7/10/2025 MicroScope image files 225-016 KRU 3S-723 4/16/2025 7/15/2025 PixStar image file 225-010 KRU 3T-730 5/2/2025 7/31/2025 EcoScope image file 225-035 KRU 3S-703 6/2/2025 8/31/2025 PixStar all data On October 9, 2025, the AOGCC requested that by October 20, 2025, ConocoPhillips provide a firm timeline with actionable dates for when missing datasets would be provided for each well, along with an accounting of which data were still not available. This request was unfulfilled. Two earlier email requests from the AOGCC sent on August 11 and August 19, 2025, were also not Docket Number: OTH-25-050 October 23, 2025 Page 2 of 2 responded to by either providing the missing data or acknowledging that the requested data was still missing. Data for KRU 3S-714 is almost 5 months late, and the partial mudlog data submitted on October 13, 2025, was not provided until the AOGCC noted it was missing in an email to ConocoPhillips on October 9. The PixStar, MicroScope, and EcoScope image files are required by 20 AAC 25.071(b)(6), and the mudlog image files and show reports (if available) are required by 20 AAC 25.071(b)(1). While late reporting of data may not implicate a threat to public safety or the environment, this type of violation may demonstrate an overall inability to manage regulatory compliance. Moreover, this violation impacts timely public access to data and requires an inordinate amount of AOGCC staff time to rectify. Within 14 days after receipt of this letter (next business day if the due date falls on a weekend or holiday), ConocoPhillips Alaska is required to submit any outstanding data required by 20 AAC 25.071 for the six wells referenced in this notice. If the data are not yet available from vendors, ConocoPhillips must submit a written response to Meredith Guhl outlining which specific items are not yet available, a proposed date for submission of those items, and the contact information for the ConocoPhillips employee who will be managing the submission of the data. The information request is made pursuant to 20 AAC 25.300. Failure to comply with this request will be an additional violation. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Questions regarding this letter should be directed to Meredith Guhl at meredith.guhl@alaska.gov or 907-793-1235. Sincerely, Jessie L. Chmeilowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.23 11:52:56 -08'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.10.23 13:33:07 -08'00' From:Hobbs, Greg S To:Guhl, Meredith D (OGC); Dodson, Kate Cc:Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Starns, Ted C (OGC); Coldiron, Samantha J (OGC) Subject:RE: [EXTERNAL]Missing logs follow up Date:Friday, October 10, 2025 11:03:05 AM Hello Meredith, We are still waiting on this data ourselves. It was noted in a 9.30.25 internal check on data. My boss, Chris Brillon, is following up with Halliburton. Have a great weekend! Greg From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Thursday, October 9, 2025 9:49 AM To: Dodson, Kate <Kate.Dodson@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Subject: RE: [EXTERNAL]Missing logs follow up Importance: High Greg, I’m attempting to complete the compliance review for KRU 3S-714, completed February 24, 2025. No mudlog data have been submitted. It is nearing 8 months after the well completion date. The timeline and data required are clearly listed in Regulation 20 AAC 25.071, and although some delays are allowable, an almost 5 month delay for submittal of the mudlog dataset, a standard data type, is troubling. By October 20, 2025, ConocoPhillips is required provide a firm timeline with actionable dates for when datasets will be provided for each well, along with an accounting of which data are still missing. If data for wells listed below have been submitted, the data type and date of submittal should also be included. A response to my last email, below, is also required. Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From: Guhl, Meredith D (OGC) Sent: Tuesday, August 19, 2025 10:15 AM To: Dodson, Kate <Kate.Dodson@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Gluyas, Gavin R (OGC) <gavin.gluyas@alaska.gov> Subject: RE: [EXTERNAL]Missing logs follow up Kate, Thank you for the update. However the data for KRU 3S-723 is not complete, as a PDF and/or TIF image file is also required, per 20 AAC 25.071(b)(7) which states “an electronic image file in formats acceptable to the commission of all open-hole logs and mud logs run, including common derivative formats such as tadpole plots of dipmeter data and borehole images produced from sonic or resistivity data,”. Meredith From: Dodson, Kate <Kate.Dodson@conocophillips.com> Sent: Monday, August 18, 2025 10:10 AM To: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Gluyas, Gavin R (OGC) <gavin.gluyas@alaska.gov> Subject: RE: [EXTERNAL]Missing logs follow up Meredith, CPAI is working with one of our log vendors to better understand delivery timeline and their responsiveness has been slow. Please see below for the latest data update. Thank you for the flexibility as CPAI works to get data delivery streamlined. 3T-616 – Still working on all data submission requirements. 3T-731 – Data submission complete. 3T-730 – Still working on all data submission requirements. 3T-613 – Still working on all data submission requirements. 3T-605 – Still working on all data submission requirements. 3T-617 – Still working on all data submission requirements. 3S-714 – Still working on all data submission requirements. 3S-723 – Data submission complete. 3S-703 – Still working on all data submission requirements. 3S-721 – Data submission complete. 3S-719 – Still working on all data submission requirements. Thanks, Kate Dodson | Senior Drilling Engineer ConocoPhillips Alaska | Alaska Wells O: 907-265-6181 | M: 907-217-3655 | Kate.Dodson@conocophillips.com From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Monday, August 11, 2025 8:23 AM To: Dodson, Kate <Kate.Dodson@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Gluyas, Gavin R (OGC) <gavin.gluyas@alaska.gov> Subject: RE: [EXTERNAL]Missing logs follow up Good Morning Kate, Halliburton PixStar data was submitted for KRU 3T-616 and KRU 3S-723 last week, but only DLIS data was supplied. A PDF and/or TIF image file of the log is also required, see bolded portion of the regulation below. Please advise on ETA for when the full complement of required data will be submitted for the two wells noted above, and the status of the other wells on your list below. Thank you, Meredith From: Dodson, Kate <Kate.Dodson@conocophillips.com> Sent: Friday, July 18, 2025 8:43 AM To: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> 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. Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]Missing logs follow up Meredith, CPAI Reviewed wells drilled in 2025 for missing data, the CD4 wells are not on the list, but CPAI will review them for missing data. See below for the list of wells CPAI is working to get submitted to AOGCC. 3T-616 – Still working on all data submission requirements. 3T-731 – Data submission complete. 3T-730 – Still working on all data submission requirements. 3T-613 – Still working on all data submission requirements. 3T-605 – Still working on all data submission requirements. 3T-617 – Still working on all data submission requirements. 3S-714 – Still working on all data submission requirements. 3S-723 – Data submission complete. 3S-703 – Still working on all data submission requirements. 3S-721 – Data submission complete. 3S-719 – Still working on all data submission requirements. Thanks, Kate Dodson | Senior Drilling Engineer ConocoPhillips Alaska | Alaska Wells O: 907-265-6181 | M: 907-217-3655 | Kate.Dodson@conocophillips.com From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Thursday, July 17, 2025 2:51 PM To: Dodson, Kate <Kate.Dodson@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL]Missing logs follow up CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hello Kate, After a discussion with Andrew Dewhurst and Steve Davies, the AOGCC requests that ConocoPhillips continues to use the branded tool name in box 22 when submitting 10-407s. The reasons for this request include: 1. Easily identifiable for both COP and AOGCC staff when comparing Box 22 list of logs with the submitted data file names, i.e.: a. 09-52_BHGE_LTK_RLT_Composite_FE Drilling Data.las b. CD4-539_MagniSphere_Services_Memory_Drilling_12038ft-22957f.las c. OP14-S3 L1_LWD_PeriScope_Resistivity_RM_LAS_10100_21371.las 2. Matches tool names noted in daily drilling reports and listed in permit to drill applications. 3. Using the tool name clearly delineates log type from the general log collection of GR/RES/NEU/DEN. I’m not sure which wells are on your list of missing logs, but if CD4-536, CD4-539, and CD4- 587 aren’t on it, please add them as all appear to be missing the GeoSphere logging data based on file names in data submitted. The AOGCC understands that the missing log data will be delivered separately from the already delivered LWD data. That is permissible in this case, but going forward, all LWD logging data should be submitted as a single data package within 90 days of well completion, suspension, or abandonment, or within 90 days of log acquisition. Note that 20 AAC 25.071(b) (7) states “an electronic image file in formats acceptable to the commission of all open-hole logs and mud logs run, including common derivative formats such as tadpole plots of dipmeter data and borehole images produced from sonic or resistivity data,” so an image file, in addition to any DLIS or LAS files should be submitted if available. Thank you, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From:Guhl, Meredith D (OGC) To:Ambatipudi, Anu Cc:kate.dodson@conocophillips.com; Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC) Subject:PTD 225-035: KRU 3S-703 BakerHughes data: AutoTrak and PixStar Date:Wednesday, July 16, 2025 11:19:00 AM Hello Anu, I’m completing the initial loading of downhole data for KRU 3S-703. On the 10-407 form it is noted that LithoTrak, AutoTrak, and PixStar were collected. However, reviewing the BakerHughes data submitted to date, only the LithoTrak data is present in the dataset. Will the AutoTrak and PixStar data be delivered separately? Thank you, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. Originated: Delivered to:5-Nov-25Alaska Oil & Gas Conservation Commiss05Nov25-NR !"#$$%$ !&$$'($)*%+ ($)*%,-.WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3T-730 50-103-20907-00-00 225-010 Kuparuk River WL TTiX-IPROF FINAL FIELD 6-Oct-253J-03 50-029-21399-00-00 185-164 Kuparuk River WL PPROF FINAL FIELD 7-Oct-252X-01 50-029-20963-00-00 183-084 Kuparuk River WL IPROF FINAL FIELD 10-Oct-252Z-07 50-029-20946-00-00 183-064 Kuparuk River WL CBP FINAL FIELD 11-Oct-252Z-03 50-029-20964-00-00 183-085 Kuparuk River WL IPROF FINAL FIELD 14-Oct-253R-17 50-029-22242-00-00 192-005 Kuparuk River WL LDL FINAL FIELD 16-Oct-253S-722 50-103-20886-00-00 224-066 Kuparuk River WL TTiX-IPROF FINAL FIELD 20-Oct-252U-06 50-029-21282-00-00 185-019 Kuparuk River WL RBP FINAL FIELD 25-Oct-253T-731 50-103-20905-00-00 224-156 Kuparuk River WL Cutter FINAL FIELD 2-Nov-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1Please return via courier or sign/scan and email a copy to Schlumberger."2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8" ! - +"8#!(3 . 8)"3 8#!9 3 : 8" +868 8 "8#!;" " 3 - 3" 3""+ 3 + <+3!% T41052T41053T41054T41055T41056T41057T41058T41059T410603T-73150-103-20905-00-00224-156Kuparuk RiverWLCutterFINAL FIELD2-Nov-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.11.05 12:45:23 -09'00' T40406 T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE: 3T-731 Microscope Image File DATE:10/27/2025 Transmitted: 3T-731 Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-731 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 224-156 T41036 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 14:14:24 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): Kuparuk River Field / Coyote Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10854' None None Casing Collapse Structural Conductor Surface 2470 Intermediate 4790 / 7870 Production 9210 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: Cameron Johnson Contact Email: Contact Phone:907-223-6277 Authorized Title: Wells Engineering Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7059' 10854' 7059' cameron.johnson2@cop.com 12725' MD - 12731' MD 8407 Open Hole: 4177' TVD - 4177' T 11/23/2025 4-1/2" Packer: Haliburton TNT Packer SSSV: None 4745' 2585' Perforation Depth MD (ft): 4809 20" 10-3/4" 80' 4091 120' 2625' 41774-1/2" 7-5/8" 13259 Length Size L-80 TVD Burst 4800' 11590 MD 6890 / 10860 5210 120' 2511' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528 / ADL025544 224-156 P.O. Box 100360, Anchorage, AK 99510 50-103-20905-00-00 ConocoPhillips Alaska Inc KRU 3T-731 Tubing Grade: Tubing MD (ft): Packer: 4656' MD and 4042' TVD SSSV: N/A Perforation Depth TVD (ft): Tubing Size: 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: AOGCC USE ONLY P 2 6 5 6 t _ Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. 325-593 By Grace Christianson at 8:26 am, Oct 01, 2025 DSR-10/15/25 10/20/2025 1:42 pm, Oct 16, 2025 TS 10/16/25 10-407 TS 10/16/25 TS 10/16/25 X AOGCC witnessed tag or pressure test of retainer. Record the actual location and integrity of cement retainer, using one of the following methods, which in the case of a cement retainer may be performed before cement is placed on top of the retainer (1) placing sufficient weight on the retainer to confirm its location and to confirm that the retainer has set and a competent plug is in place; (2) testing the plug to hold a surface pressure of 1,500 psi J.Lau 10/16/25 10/23/25 KRU 3T-731 AOGCC Sundry Saved: 13-Oct-25 Change to Approved Sundry, Well KRU 3T-731 Page 1 of 5 Printed: 13-Oct-25 KRU 3T-731 PTD# 224-156 Application for Sundry Approval Revised 13-Oct-25 Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) .............................................................. 2 2. Overview ..................................................................................................................... 2 3. Planned Operations ...................................................................................................... 2 4. BOPE Information ........................................................................................................ 2 5. Casing and Cementing In Place ...................................................................................... 2 6. Abandonment Cement ................................................................................................. 3 7. Discussion of Mud and Cuttings Disposal ....................................................................... 3 8. Schematics .................................................................................................................. 4 KRU 3T-731 AOGCC Sundry Saved: 13-Oct-25 Change to Approved Sundry, Well KRU 3T-731 Page 2 of 5 Printed: 13-Oct-25 1. Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted for is KRU 3T-731. 2. Overview The 3T-731 well was drilled and completed in March - April 2025. The well was fracture stimulated and a wellbore cleanout was performed with coiled tubing. After this cleanout, the production from the well abruptly decreased. This decrease in production has required the production section to be re-drilled and completed. 3. Planned Operations 1. Rig up coil tubing 2. Run in hole and set 4-1/2 cement retainer at ~4600 MD 3. Squeeze ~50 bbls of 15.8 ppg Class G Cement to cover liner volume down to frac sleeve #14. a. Leave no cement on top of retainer 4. Pull out of the hole and rig down coil tubing 5. Rig up wireline unit and equipment 6. Cut 4-1/2 tubing at ~4559 MD, below downhole gauge and above production packer 7. Pull valve in lower GLM for circulation point if circulation cannot be established through cut. 8. MIRU Doyon 142. 9. Displace out diesel freeze protect with kill weight fluid through tree, taking returns to tiger tank. 10. Observe well for flow to confirm well is dead 11. Set and test BPV 12. Nipple down production tree. 13. Nipple up BOPE and test to 250/5000 psi with 3-1/2 & 4-1/2 test joints. Test Annular to 250/2500 psi 14. Remove BPV. 15. Pull 4-1/2 tubing (pre-cut at ~4559 MD). 16. Run in hole with cement retainer on 4 drillpipe and set at ~4,505 MD. 17. Establish injection 18. Abandon lateral by squeezing ~30-50 bbls of 15.8 ppg Class G Cement to cover liner volume down to frac sleeve #14. a. Not leaving cement on top of retainer. 19. Pick up whipstock and milling assembly 20. Run in hole on 4 drillpipe and set whipstock on top of tubing stub with the bottom of the ramp at ~4500 MD 21. Ready to move into drilling phase under new PTD. 4. BOPE Information Please reference BOPE schematics on file for Doyon 142 5. Casing and Cementing In Place OD Hole Size Depth (MD) Weight Grade Conn. 20 42 120 94 H-40 Welded 10 3/4 13 1/2 2625 45.5 L-80 Hyd563 7 5/8 9 7/8 3943 29.7 L-80 Hyd563 7 5/8 9 7/8 4785 33.7 P-110S Hyd563 4 1/2 8 3/4 13192 12.6 P-110S Hyd563-MS 2491 sx of 14.8 ppg Lead and 226 sx of 15.3 ppg Tail. TOC logged at 4010' MD / 3717' TVD Casing and Cement In Place Cement Program 10 yds 949 sx of 11.0 ppg Lead and 281 sx of 15.8 ppg Tail (cement returned to surface) *AOGCC witnessed tag or pressure test of retainer. - JJL KRU 3T-731 AOGCC Sundry Saved: 13-Oct-25 Change to Approved Sundry, Well KRU 3T-731 Page 3 of 5 Printed: 13-Oct-25 The 3T-731 well was completed as a two-string well. The 10-3/4 surface casing was run and cemented with the following. 150 bbls of 11.0 ppg Lead Cement was returned to surface. The 7-5/8 x 4-1/2 production casing string was run to TD. Lost circulation was experienced during the primary cement job. A cement log was run and the TOC was not sufficient. The 4-1/2 liner was perforated at 12725 MD and a secondary cement job was pumped as follows. A wireline cement evaluation was performed and the top of cement was found at 4010 MD / 3717 MD. The required TOC for this well was 500 MD / 250 TVD above the top of the Coyote formation at 4843 MD / 4106 TVD. The following interpretation was provided by the ConocoPhillips Cementing SME. Channeling of annular fluid from surface to 1,050 Fluid is most likely diesel pumped as freeze protection. From 1,050 to 3,240 fluid is very homogenous reading 20mV, this is most likely mud remaining in hole from previous operation due to losses during cement job. Amplitude of annular fluid drops from 20 mV to 10-11 mV from 3,240 to 3,920 most likely more mud from previous operation, again due to lack of removal because of losses during the cement job. Moderate to good bond from 3,920 to 3,980 Kick to the left on Gamma indicates the possible loss zone at 3,970 3,980. 3,980 to 4,010 Moderate bond. Good cement bond for Isolation from 4,010 to 4,830. 6. Abandonment Cement The 3T-731 Lateral will be abandoned by placing a 4-1/2 cement retainer in the 4-1/2 tubing at 4559 MD, above the production packer and below the downhole gauge. ~50 bbls of 15.8 ppg Glass G Cement will be squeezed below the retainer. Any cement on top of the retainer will be washed up to allow the whipstock to be set on the retainer. Cementing Calculations Lateral Abandonment Total Volume = 50 bbls => 242 sx of 15.8 Class G + Add's + Add's @ 1.16 ft³/sk 7. Discussion of Mud and Cuttings Disposal Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well. Lead Tail 438 bbls => 949 sx of 11.0 ppg + Add's @ 2.59 ft³/sk 58 bbls => 281 sx of 15.8 ppg Class G + Add's @ 1.16 ft³/sk Lead Tail 590 bbls => 2491 sx of 14.8 ppg Class G + Add's + Add's @ 1.33 ft³/sk 50 bbls => 226 sx of 15.3 ppg Class G + Add's + Add's @ 1.24 ft³/sk KRU 3T-731 AOGCC Sundry Saved: 13-Oct-25 Change to Approved Sundry, Well KRU 3T-731 Page 4 of 5 Printed: 13-Oct-25 8. Schematics Current Schematic KRU 3T-731 AOGCC Sundry Saved: 13-Oct-25 Change to Approved Sundry, Well KRU 3T-731 Page 5 of 5 Printed: 13-Oct-25 Abandonment Schematic KRU 3T-731 AOGCC Sundry Saved: 13-Oct-25 Change to Approved Sundry, Well KRU 3T-731 Page 6 of 5 Printed: 13-Oct-25 Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the Abandon box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer TS 10/16/25 3T-731 325-593224-156 TS 10/16/25 WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS E-Delivery3T-731 50-103-20905-00-00 224-156 KUPARUK RIVER MWD/LWD/DD Data GeoSphere/MicroScope FINAL FIELD 10-Apr-25 1Transmittal Receipt________________________________ X____________________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.aurana@slb.comSLB Auditor - A Transmittal Receipt signature confirms that a package (box, envelope, etc.) has been received and the contents of the package have been verified to match the media noted above. The specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this point.# Schlumberger-Private224-156T40406Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.08.04 10:28:33 -08'00' Originated: Delivered to:31-Jul-25Alaska Oil & Gas Conservation Commiss31Jul25-NRATTN: Meredith Guhl333 W. 7th Ave., Suite 100 600 E 57th Place Anchorage, Alaska 99501-3539Anchorage, AK 99518(907) 273-1700 main (907)273-4760 faxWELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTIONDATA TYPE DATE LOGGED3S-703 50-029237-61-00-00 223-056 Kuparuk River WL TTiX-HSD FINAL FIELD 8-Jul-253T-731 50-103209-05-00-00 224-156 Kuparuk River WL TTiX FSI & SCMT FINAL FIELD 12-Jul-253T-603 50-103208-87-00-00 224-074 Kuparuk River WL Caliper & Perforation FINAL FIELD 14-Jul-253S-606 50-103208-70-00-00 223-111 Kuparuk River WL TTiX- IPROF FINAL FIELD 21-Jul-25Transmittal Receipt________________________________X__________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.Nraasch@slb.comSLB Auditor - TRANSMITTAL DATETRANSMITTAL #A Delivery Receipt signature confirms that a package (box, envelope, etc.) has been received. The package will be handled/delivered per standard company reception procedures. The package's contents have not been verified but should be assumed to contain the above noted media.# Schlumberger-Private225-035T40727T40728T40729T407303T-73150-103209-05-00-00224-156Kuparuk RiverWLTTiX FSI & SCMTFINAL FIELD12-Jul-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.08.01 08:56:13 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3T-731 JBR 05/02/2025 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:0 4", 5-1/2" & 7-5/8" TJ used 16 accumulator bottles avg precharge 1000 psi. Test Results TEST DATA Rig Rep:H. Huntington/S. MichaOperator:ConocoPhillips Alaska, Inc.Operator Rep:M. Tucker/ B. Marmon Rig Owner/Rig No.:Doyon 142 PTD#:2241560 DATE:4/5/2025 Type Operation:DRILL Annular: 250/3500Type Test:OTH Valves: 250/4000 Rams: 250/4000 Test Pressures:Inspection No:bopKPS250405092248 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5.75 MASP: 1374 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 4 P Inside BOP 2 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 3-1/2" X 6" V P #2 Rams 1 Blind Shears P #3 Rams 1 3-1/2" X 6" V P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 3 3-1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P2975 Pressure After Closure P1725 200 PSI Attained P8 Full Pressure Attained P55 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6 @ 1962 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 P19 #1 Rams P7 #2 Rams P7 #3 Rams P7 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1      Test charts attached BOPE - Doyon 142 KRU 3T-731 (PTD 2241560) AOGCC Insp Rpt #bopKPS250405092248 4/5/2025 Test BOPE 4”, 5”, 7 5/8’’ Test Joints 250/4000psi on All Components / Hyd & Manual Chokes 2000psi 1. 4” TJ, Annular, 1, 12, 13, 14, Rig floor Kill, 4” Dart, Upper IBOP, 250/3500 2.4’’ TJ, 3-12’’x6’’ UPR’s 1,12,13,14, rig floor kill, 4’’ dart, Upper IBOP 250/4000 3.4” TJ, 3-1/2”X6” UPR’s, CMV’s #’s 9,11, Mezz Kill, 4” TIW #1, Lower IBOP, 250/4000 4.4” TJ CMV’s #’s 8,10, HCR Kill, 4” TIW #2 250/4000 5.4” TJ CMV’s #’s 6, 7, Manual Kill 250/4000 6.Super Choke / 2000 7.Manual Choke / 2000 8.4” TJ CMV’s #’s 2, 5 250/4000 9.4” TJ Lower Pipe rams 3-1/2” x 6” VBR’s 250/4000 Perform Koomey Draw Down (Break down XT-39 TIW’s/Dart M.U NC50) Remove 4 ” Test Joint 10.Blind / Shears CMV’s 3, 4, NC50 Dart 250/4000 Install 5 ” Test Joint 11. 5” TJ, 3 ½’’ X 6’’ UPR, HCR Choke, NC50 TIW#1 250/4000 ? 12.5” TJ, 3 ½” X 6” UPR, Manual Choke NC50 TIW#2 250/4000 13.5” TJ, 3 ½” X 6” LPR 250/4000 Lay down 5 ” Test joint Install 7 5/8 ’’ Test joint 14.7 5/8’’ TJ, Annular t/ 250/3500 BOPE - Doyon 142 KRU 3T-731 (PTD 2241560) AOGCC Insp Rpt #bopKPS250405092248 4/5/2025 DOYON RIG 142 ACCUMULATOR DRAW DOWN WORKSHEET WELL: 3T-731 4/5/2025 ACCUMULATOR PSI 2975 MANIFOLD PSI 1500 FUNCTION RAMS/ANNULAR/ HCR'S, DON'T FUNCTION BLINDS! FUNCTION ONE RAM TWICE LET PRSSURE STABILIZE AND RECORD BACK UP NITROGEN BOTTLE'S ACCUMULATOR PSI 1725 NITROGEN BOTTLE'S PSI BOTTLE # 1 2000 BOTTLE # 2 1950 BOTTLE # 3 2000 BOTTLE # 4 1975 BOTTLE # 5 1950 BOTTLE # 6 1900 AVG FOR 6 BOTTLE'S =1962 TURN ON ELEC. PUMP, SEC FOR 200 PSI =8 TURN ON AIR PUMP'S TIME FOR FULL CHARGE =55 Annular 19 UPR 7 Blind/ Shear 7 LPR 7 KILL HCR 1 Choke HCR 1 BOPE - Doyon 142 KRU 3T-731 (PTD 2241560) AOGCC Insp Rpt #bopKPS250405092248 4/5/2025 Originated: Delivered to:19-Jun-25Alaska Oil & Gas Conservation Commiss19Jun25-NR !"#$$%$ !&$$'($)*%+ ($)*%,-.WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED1C-158 50-029237-61-00-00 223-056 Kuparuk River WL TTiX-RST FINAL FIELD 7-Jun-251C-17 50-029228-72-00-00 198-224 Kuparuk River WL IPROF FINAL FIELD 8-Jun-253T-731 50-103209-05-00-00 224-156 Kuparuk River WL TTiX-HSD FINAL FIELD 10-Jun-253S-721 50-103209-11-00-00 225-025 Kuparuk River WL TTiX-SCMT FINAL FIELD 12-Jun-251A-22 50-029221-27-00-00 191-0003 Kuparuk River WL PPROF FINAL FIELD 17-Jun-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1Please return via courier or sign/scan and email a copy to Schlumberger."2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8" ! - +"8#!(3 . 8)"3 8#!9 3 : 8" +868 8 "8#!;" " 3 - 3" 3""+ 3 + <+3!% T40618T40619T40620T40621T406223T-73150-103209-05-00-00224-156Kuparuk RiverWLTTiX-HSDFINAL FIELD10-Jun-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.06.25 08:36:59 -08'00' T R A N S M I T T A LL FROM:Anu Ambatipudi TO: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC 700 G Street 333 W.7 th Ave., Suite 100 Anchorage AK 99501 Anchorage, Alaska RE:: 3T-731 Permit: 224-156 DATE: 05/15/2025 Transmitted: 3T-731 Via SFTP ____ GeoLog Mudlog Data Package Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-612 - e-transmittal well folder Receipt: Date: 224-156 T40411 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.15 14:18:37 -08'00' Alaska/IT-Data Services |ConocoPhillips Alaska | WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS E-Delivery3T-731 50-103-20905-00-00 224-156 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 10-Apr-25 13T-730 50-103-20907-00-00 225-010 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 30-Apr-25 1Transmittal Receipt________________________________ X____________________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.aurana@slb.comSLB Auditor - A Transmittal Receipt signature confirms that a package (box, envelope, etc.) has been received and the contents of the package have been verified to match the media noted above. The specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this point.# Schlumberger-PrivateT40406T404073T-73150-103-20905-00-00224-156KUPARUK RIVERMWD/LWD/DDVISION ServiceFINAL FIELD10-Apr-251Transmittal Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.05.14 09:03:24 -08'00' ao?q -ISM 1 ,729 SAMPLE TRANSMITTAL TO: AOGCC 333 WEST 7TH SUITE 100 ANCH. AK. 99501 279-1433 OPERATOR: CPAI SAMPLE TYPE: Dry Cuttings SAMPLES SENT: 3T-731 2650-13269 4 Boxes SENT BY: M. McCRACKEN DATE: 05/02/2025 AIR BILL: NIA CPAL CPA12025050202 CHARGE CODE: N/A NAME: 3T-731 NUMBER OF BOXES: 4 Boxes UPON RECEIPT OF THESE SAMPLES, PLEASE NOTE ANY DISCREPANCIES AND RETURN A SIGNED COPY OF THIS FORM TO: CONOCOPHILLIPS, ALASKA 700 G ST ATO-380 ANCHORAGE, AK. 99510 ATTN:MIKE McCRACKEN Mike.mccracken@conocophillips.com RECEIVED HAY 0 2 2025 A0GJCC 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?3T-731 Yes No 9. Property Designation (Lease Number):10. Field: Coyote 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): Casing Collapse Structural Conductor Surface 2474 Production 4789 Production 4789 Production 9210 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 CO 819 KRU Coyote Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 Senior Completions Engineer Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): 4,656' MD / 4,042' TVD Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528/ADL025544 224-156 P.O. Box 100360 Anchorage, Alaska 99501-0360 50-103-20905-00-00 ConocoPhillips Alaska, Inc. Length Size Proposed Pools: L-80 TVD Burst 4,800 10860 MD 6885 5209 119 2511 3672 119 2625 40917-5/8" 20" x 34" 10-3/4" 119 7-5/8"3943 2625 4809 Perforation Depth MD (ft): 3943 12,725' MD 866 4-1/2" 4,177' TVD 5/1/2025 132698450 4-1/2" 4177 HES TNT Production Packer m n P 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.04.24 14:25:49-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard 325-255 By Grace Christianson at 3:03 pm, Apr 24, 2025 Fracture Stimulate DSR-4/29/25 RUSH SFD 5/1/2025 CDW 04/25/2025 SFD 5/2/2025 4,656' MD / 4,042' TVD X VTL 5/5/2025 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.05 14:35:01 -08'00'05/05/25 Section 1 - Affidavit 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283(a)(1). April 16, 2025 VIA E-MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3T-731 Well ADL 025528 & ADL 025544 Kuparuk River Unit, Alaska CPAI Contract No. 203828 Pursuant to 20 AAC 25.283, ConocoPhillips Alaska, Inc. (“CPAI”) as Operator of the Kuparuk River Unit, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing in accordance with 20 AAC 25.280 (“Application”) for the 3T- 731 Well (the “Well”). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about April 16, 2025. The Well is currently planned to be drilled as a directional horizontal well on lease ADL 025528 and ADL 025544 as depicted on Exhibit 1, and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 3,626’ 5,147’ T12N R7E 1 Umiat Top Open Interval 4,185’ 4,743’ T12N R7E 1 Umiat Bottomhole 2,091’ 3,533’ T12N R7E 13 Umiat Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well (“Notification Area”), which includes the reservoir section. Exhibit 2 is a list of the names and addresses of all owners, landowners, surface owners, and operators of record at the time of this Application for all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, Ryan C. King, CPL Staff Land Negotiator Attachments: Exhibits 1 & 2 Ryan C. King, CPL Staff Land Negotiator Land & Business Development P.O. Box 100630 Anchorage, AK 99510-0360 Office: 907-265-6106 Fax: 907-263-4966 ryan.c.king@cop.com BCC: Madeline Woodard Brian Buck John Evans Patrick Perfetta Exhibit 1 Exhibit 2 List of the names and addresses of all owners, landowners, surface owners, and operators of record of all properties within the Notification Area. Operator & Owner: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO-1480 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attn: GKA Asset Development Manager Owner (Non-Operator): ConocoPhillips Alaska, Inc. II ExxonMobil Alaska Production Inc. 700 G Street, Suite ATO 1226 PO Box 196601 Anchorage, Alaska 99510 Anchorage, AK 99519 Attn: GKA Asset Development Manager Attn: Todd Griffith Landowners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Surface Owner: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Section 2 –Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer KUP KRU KUPARUK RIVER UNIT 501032044600 3S-22 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044801 3S-17A PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032046000 3S-19 SUSP Suspended Yes - Suspended Yes - Suspended KUP KRU KUPARUK RIVER UNIT 501032069900 MORAINE 1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK NAK NORTH ALASKA EXPLORATION 501032064500 NUNA 1 SUSP Suspended Yes - Suspended Yes - Suspended NAK NAK NORTH ALASKA EXPLORATION 501032064570 NUNA 1PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK OU OOOGURUK UNIT 501032066000 NDST-02 SUSP Suspended Yes - Suspended Yes - Suspended NAK OU OOOGURUK UNIT 501032066070 NDST-02PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032069500 3S-620 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032073500 3S-613 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087800 3S-626 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032088200 3T-621 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032088700 3T-603 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032089000 3T-608 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032089600 3T-612 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032089900 3T-616 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032089970 3T-616PB1 PROP Proposed Yes Yes KUP TOROK TOROK 501032089971 3T-616PB2 PROP Proposed Yes Yes 24 wells/PB identified. 25 if count 3S-17 and 3S-17A. See (a)(10) for detail (CDW 04/25/2025) SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), “That portions of the aquifers on the North Slope described by a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field”. SECTION 4 – PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283(a)(4) There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5 – DETAILED CEMENTING AND CASING INFORMATION 20 AAC 25.283(a)(5) All casing is cemented and tested in accordance with 20 AAC 25.030. See Wellbore schematic for casing details. Packer set 4656 ft MD/4042 ft TVD CDW 04/25/2025 SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: The 10-3/4” casing cement pump report on 3/15/2025 shows that the original job pumped as designed. The cement job was pumped with 438 barrels of 11.0 ppg lead cement and 58 barrels 15.8 ppg tail cement, displaced with 9.8 ppg mud. The plug bumped at 950 psi and the floats held. 150 bbls of cement returned to surface. The 7-5/8” x 4-1/2” casing cement report on 4/1/2025 shows that the job was pumped with 50 barrels of 14.8ppg cement, 540 bbls of 14.8ppg cement with Bridge Maker II, and 50 bbls of 14.8ppg cement. The cement was displaced with 9.6ppg CI brine. The plug bumped with pressure increasing to 1780 psi and held for 5 minutes and floats held. Losses were observed during the job. A cement bond log indicated the cement top at 12,750’ MD. The 7-5/8” x 4-1/2” casing remedial cement report on 4/7/2025 shows that the job was pumped with 50 bbls of 14.8ppg cement, 217 bbls of 14.8ppg cement w/ Bridge Maker II, and 253 bbls of 14.8ppg cement through the perforation at 12,725’ MD. The cement was displaced with 9.7ppg CI brine and 520bbls of fluid was lost during the job. After cement reached 500 psi compressive strength, the cement top was logged at 4,010’ MD / 3,717’ TVD (834’ MD / 389’ TVD above the Coyote). Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Due to the losses observed during the primary cement job on the tapered production casing string and perforation placement for the remedial job, the first two stages of stimulation will not be pumped. The stimulation will begin at stage 3 for this well. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. gp y j p p the f irst two stages of stimulation will not be pumped SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 3/17/2025 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 4/3/2025 the 7-5/8” x 4-1/2” tapered casing was pressure tested to 3,850 psi for 30 minutes. On 4/10/2025 the 4-1/2” tubing was pressure tested to 4,550 psi for 30 minutes. On 4/10/2025 the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,075 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7-5/8" Annulus pressure test 3,850 4-1/2" Tubing pressure Test 4,075 Electronic PRV 8,075 Highest pump trip 7,575 SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2,474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 P-110S 11,590 9,210 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the gross Coyote interval, has an average thickness greater than 100 ft TVD over the course of the lateral section of well 3T-731, from where it intersects the top formation at 4,843’ MD to TD of the well. At the heel of the well it has a gross thickness of ~110’ thickening to ~195’ at the toe of the well. The Coyote interval is comprised of thinly interbedded sandstone and siltstone layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and are of the size range from silt to very fine sand. The estimated fracture pressure for the Coyote interval is approximately 12.9-16.1 ppg. The overlying confining interval is represented by distal toe of slope (deep marine) claystone with thin siltstone beds of the Cretaceous Seabee Formation. This interval is present in thicknesses of ~300’ TVD in the vicinity of the 3T-731 wellbore. The top of the confining intervals starts at ~3,744’ TVDSS (4,134’ MD). It should be noted that slope to basin shales and siltstones are present from the top of the Seabee formation to the surface casing shoe at 2,446’ MD. This interval acts as a continuation of the upper confining interval. Currently, there is no data of the fracture gradient of the overlying Seabee formation, however, CPAI estimates the fracture closure pressure gradient to be 0.67 psi/ft based on diagnostic fracture injection testing (DFIT). The fracture gradient of the overlying Seabee formation will be greater than the fracture closure pressure gradient of 0.67 psi/ft. The lower confining interval of the Coyote comprises slope to basin floor mudstones of the Torok formation, which are present in thicknesses of ~860’ TVD in the vicinity of the 3T-731 wellbore. This same confining zone forms the upper confining interval of the Kuparuk River Unit, Torok Oil Pool. The estimated fracture gradient for this section ranges from 15-18 ppg. The base of the gross Coyote interval is estimated from seismic to be at ~4,157 ft TVDSS at the heel, and ~4,240’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1695 – 1,817 psi at a depth of 4,100’ TVDSS. SECTION 10 – LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing & Cement assessments for all wells that transect the confining zone: 3S-17 & 3S-17A: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-17 and 3S- 17A (sidetrack from 3S-17 on 4/29/2003), commencing operations on 7/30/2022 and completing the Plug and Abandonment on 9/25/2023. A cement retainer was set at 8,333’ MD via coil tubing and 27 bbls of cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 8,324’ SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 8/13/2022. The tubing was then cut at 8,273’ MD and the tubing pulled out of hole. A bridge plug was set at 5,883’ MD in the 7” casing and the 7” casing was perforated from 5,707’-5,857’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,513’ SLMD in the 7” casing and a MIT-T performed to 1500 psi, witnessed by AOGCC (pg. 16 at link below). TOC was determined in the annulus at 5,707’ MD / 4,022’ TVD / 3,965’ TVDSS via log. Coil was used to pump 22 bbls of 15.8ppg cement in the 7” casing. The TOC was tagged at 5,273’ MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC (pg. 15 at the link below). The top cement job was performed on 9/5/2023 with 223 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface. The final abandonment was completed on 9/25/23, witnessed by AOGCC (pg 2 at link below). 203-080 - Laserfiche WebLink 3S-19: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-19, commencing operations on 1/1/2024 and completing the Plug and Abandonment on 3/25/2025. From the original cement job, a CBL was conducted on 12/22/2012 from 9170ft to surface. CBL log indicated good to fair cement from 9170ft to 7350ftMD. A cement retainer was set at 9,620’ MD via coil tubing and 35 bbls of cement was pumped below the retainer. Another cement retainer was set at 8,515’ MD and 50 bbls of cement was pumped below the retainer and 2 bbls on top. Cement was tagged at 8,274’ SLMD and a passing MIT-T was performed and witnessed by AOGCC on 5/17/2023 (pg. 15 at link below). The tubing was then cut at 8,271’ MD and the tubing pulled out of hole. A CIBP was set at 6,596’ MD in the 7” casing and the 7” casing was perforated from 6,420’- 6,570’ MD. Coil was utilized to perf wash and cement with 65bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 6,120’ SLMD in the 7” casing. TOC was determined in the annulus at 6,420’ MD / 4,033’ TVD / 3,977’ TVDSS via log. A CIBP was set at 6,598’ MD and coil was used to pump 42 bbls of 15.8ppg cement in the 7” casing. The TOC was tagged at 5,474’ MD and a MIT-T performed to 1,710 psi, witnessed by AOGCC (pg. 8 at the link below). A top cement job was performed on 12/30/2023 with 210 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface. Pressure was still observed at surface on the production casing. Cement was milled down to 3,780’ MD and a CIBP set at 3,777’ MD. The casing was tested against the CIBP to 1,650 psi, witnessed by AOGCC on 3/15/2025 (pg. 1 at the link below). An additional top cement job was completed on 3/16/2025 with 165 bbls of 15.8ppg cement from 3,777’ MD to surface. Awaiting final abandonment operations once the rig moves. 203-096 - Laserfiche WebLink 3S-22: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-22, commencing operations on 5/1/2023 and completing the Plug and Abandonment on 3/25/24. Original drilling did not cover the zone of interest. A CBL was run prior to the P&A showing the original cement height at 6255' MD. A cement retainer was set at 7,690’ MD via coil tubing and 32 bbls of 15.8ppg cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 7,418’ SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 5/12/2023 (pg. 12 at link below). The tubing was then cut at 7,420’ MD and the tubing pulled out of hole. A CIBP was set at 5,467’ MD in the 7” casing and the 7” casing was perforated from 5,291’-5,441’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,107’ SLMD in the 7” casing and TOC was determined in the annulus at 5,291’ MD / 4,018’ TVD / 3,960’ TVDSS via log. Coil was used to pump 38 bbls of 15.8ppg cement in the 7” casing. The TOC was tagged at 4,445’ MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC (pg. 5 at the link below). The top cement job was performed on 2/28/2024 with 193 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface. The final abandonment was completed on 3/25/24, witnessed by AOGCC (pg. 2 at link below). 203-011 - Laserfiche WebLink 3S-610: The 7-5/8” casing cement report on 3/23/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 201 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 22 barrels of 15.3 ppg without BM II. The plug did not bump, pressure held at 1140 psi indicating that floats are competent. A cement bond log indicates competent cement with a cement top @ 3,549 MD (3,156’ TVD / 3,092’ TVDSS). 223-126 - Laserfiche WebLink 3S-611: The 7-5/8” casing cement report on 10/13/2018 shows that the job was pumped as designed, indicating competent cementing operations. 12.5 ppg MPII was pumped before dropping bottom plug, this was then chased with 270 bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.4 ppg LSND mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,228’MD/3,967’ TVD/3,904’ TVDSS (pg. 274 at the link below). 218-103 - Laserfiche WebLink 3S-612: The 7-5/8” casing cement report on 11/4/2018 shows that the job was pumped as designed, indicating competent cementing operations. 12.5 ppg MPII was pumped before dropping bottom plug, this was then chased with 303bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.5 ppg LSND mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,270 ’MD/3,832’ TVD/3,768’ TVDSS (pg. 289 at the link below). 218-111 - Laserfiche WebLink 3S-613: The 7-5/8” casing cement report on 5/2/2016 shows that the 2-string job was pumped as designed, indicating competent cementing operations. The first stage consisted of 47bbls of 15.8ppg cement and plugs bumped and floats held. The second stage consisted of 189bbls of 15.8ppg cement and the plug bumped and floats held. Full returns were seen throughout both jobs. A SonicScope was run to determine TOC, but the log began at estimated TOC and no free ringing pipe was logged to help determine a clear TOC. Interpretation shows a potential TOC at 6,095’ MD/3,711’ TVD/3,646’ TVDSS from the log (pg. 35, 192 at the link below). 216-020 - Laserfiche WebLink 3S-615: The 7-5/8” casing cement report on 11/13/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 200 barrels of 15.3 ppg lead cement with BMII, followed with 33 barrels of 15.3 ppg tail cement, displaced with 524 barrels of 9.6 ppg mud. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,620 MD (3,340’ TVD / 3,279’ TVDSS). 222-101 - Laserfiche WebLink 3S-620: The 7-5/8” casing cement report on 2/6/2015 shows that the job was pumped as designed, indicating competent cementing operations. 11.5 ppg Mud Push II was pumped before dropping bottom plug, this was then chased with 181 bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.7 ppg mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. 48bbls of fluid was lost during the job. A SonicScope was run to determine TOC, but the log began at estimated TOC and no free ringing pipe was logged to help determine a clear TOC. Interpretation shows potential TOC above 5,400’ MD/3,567’ TVD/3,514’ TVDSS from the log. 214-167 - Laserfiche WebLink 3S-625: The 7-5/8” casing cement report on 9/29/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 297 barrels of 15.3ppg cement with BMII. The cement was displaced with 574 barrels of 9.6ppg LSND drilling mud. The plug did not bump and 50% of shoe track volume was pumped. Losses totaled 21 barrels during the job. Cement floats held. A cement bond log indicates competent cement with a cement top @ 7,850’ MD (3,970’ TVD / 3,908’ TVDSS). 222-079 - Laserfiche WebLink 3S-626: The 7-5/8” casing cement report on 06/01/2024 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped in two stages utilizing a stage tool. The first stage cement job had 188 bbls of 15.3 ppg cement. Plug bumped and floats held. The second stage cement job had 42 bbls of 15.3 ppg cement. Plug bumped and all indications are the stage tool at 6807’ MD closed. A cement bond log run on 06/03/24 indicates competent cement with cement top at 5,908’ MD/3,775’ TVD/3,711’ TVDSS. Due to issues with the freeze protect of the OA, a RWO was performed. The 7-5/8" fish was successfully recovered down to the original cut made with Doyon 142 at 2020 ft MD. A new 7-5/8” casing with a sealing overshot and cementer was installed, and cement was pumped through the cementer to the surface. The 7-5/8" packoff was then installed and tested to 3840 psi, confirming its integrity. 224-007 - Laserfiche WebLink 3S-626PB1: This wellbore was abandoned due to shale collapse in the lateral. A cement retainer was set at 9,198’ MD and 33bbls of 15.3ppg cement was pumped. The TOC was tagged at 8,874’ MD with 10klbs and was witnessed by AOGCC (pg. 128 at link below). A CIBP was set at 3,454’ MD, casing was cut at 3,400’ MD, and the casing was pulled out of hole and laid down. A kick off plug was pumped above the CIBP into the 10-3/4” surface casing with 75bbls of 16.3ppg cement. The 10-3/4” was tested to 1,500 psi for 30 minutes, witnessed by AOGCC (pg. 68 at link below). The TOC was tagged at 2,580’ MD/2,306’ TVD/2,243’ TVDSS with 10klbs, tag witness waived by AOGCC. 224-007 - Laserfiche WebLink 3T-603: The 7-5/8” casing cement report on 9/20/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 136 barrels of 14.0 ppg lead cement with BMII, followed with 31 barrels of 15.3 ppg tail cement, displaced with 408.5 barrels of 9.5 ppg FWP. The plug bumped and floats held. A cement bond log run indicates competent cement with a cement top @ 5,692’ MD (3,578’ TVD/3,527’ TVDSS). 224-074 - Laserfiche WebLink 3T-608: The 7-5/8” casing cement report on 10/28/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 203 barrels of 14.0 ppg lead cement with BMII, followed with 31 barrels of 15.3 ppg tail cement, displaced with 463 barrels of 9.5 ppg FWP. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,768 MD (3,843’ TVD /3,792’ TVDSS). 224-094 - Laserfiche WebLink 3T-612: The 7-5/8” casing cement report on 12/07/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 98 barrels of 14.0 ppg lead cement, followed with 58 barrels of 15.3 ppg tail cement. This was displaced with 375 barrels of 9.5 ppg BaraECD NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 4,799 MD (3,489’ TVD /3,438’ TVDSS). 224-128 - Laserfiche WebLink 3T-616: The 7-5/8” casing cement report on 01/24/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 117 barrels of 14.0 ppg lead cement with BMII, followed with 58 barrels of 15.3 ppg tail cement. This was displaced with 405 barrels of 9.5 ppg BaraECD NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,041 MD (3,422’ TVD/3,370’ TVDSS). The 4-1/2” liner cement report on 03/06/2025 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 310 barrels of 14.8 ppg cement. The cement was displaced with 9.5ppg CI NaCl brine and the plugs bumped and held for 5 minutes. Floats held. 224-138 - Laserfiche WebLink 3T-616PB1: This wellbore was drilled in the Torok pool and was abandoned on 2/21/2025 with 42bbls of 16.3ppg cement laid in at the heel of the wellbore into the 7-5/8” intermediate casing shoe. The cement top was then tagged at 9,065’ MD/5,104’ TVD/5,053’ TVDSS with 12klbs. 224-138 - Laserfiche WebLink 3T-616PB2: This wellbore is sidetrack from the 3T-616PB1. The TD of this sidetrack is 12,440’ MD/4,758’ TVD/4,707’ TVDSS. This sidetrack did not exit the Torok pool, but did enter the Torok shale. 224-138 - Laserfiche WebLink 3T-621: The 7-5/8” casing cement report on 05/05/2024 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 82 bbls of 15.3 ppg cement. Plugs bumped and floats held. A cement bond log run on 05/06/24 indicates competent cement with cement top at 6,530’ MD/3,708’ TVD/3,668’ TVDSS. 224-022 - Laserfiche WebLink Moraine 1: The cement report on 3/3/2015 shows that the 8-1/2” hole was abandoned with 3x plugs starting at 5,610’ MD (TD). A total of 849 sx of 15.8ppg Class G cement was used to set all three plugs. The top cement plug was then tagged at 3,687’ MD/3,643’ TVD/3,600’ TVDSS with 15klbs, witnessed by the AOGCC (pg. 132 at link below). This tag is above the Coyote top at 4,127’ MD. A cement retainer was then set at 2,362’ MD and 21bbls of 15.8ppg Class G slurry was pumped below and 3 bbls above the retainer. A final plug was laid above a CIBP set at 508’ MD to surface using 11ppg AS1 cement. Photos of the final abandonment and marker plate and the submittal to AOGCC are on pages 100-104 at the link below. 214-198 - Laserfiche WebLink NDST-02: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, the 7-5/8” casing was cemented on 2/8/2013. The cement report indicates that the job was pumped with 60 bbl s of 15.8ppg Premium Cement with 3% Halad (R)-344 low fluid loss control. Full circulation was seen throughout the entire job. A USIT confirmed TOC at 8672' MD/4,841’ TVD/4,800’ TVDSS. Frac operations could not be completed because a lodged ball damaged the tubing, and 60 bbl of CaCO3 was spotted on 4/13/2013. On 4/14/2013, XX plug was set in nipple at 4,550’ WLMD. ConocoPhillips Alaska Inc. re -entered on 1/3/2023, pulled the XX plug at 8,360’ CTMD (restriction) instead of at the nipple and performed injectivity test at 0.5 bpm on 1/21/2023. The tubing was cut at 8,316’ MD and was removed from the well. On 10/8/2024, coil tubing set a cement retainer at 10,441’ MD and pumped 110bbls of 15.8ppg cement into the 4.5” liner. Coil unstung from the retainer and laid an additional 68bbls of 15.8ppg cement on top of the retainer. The cement plug was not tagged due to issues with deviation/thick fluid, but a pressure test was completed to 1700 psi and witness by AOGCC on 10/12/2024 (pg. 2-6 at link below). Another attempt to tag the TOC was completed on 2/8/2025 with coil tubing, tagging at 8,812’ MD with 4klbs and witnessed by AOGCC (pg. 1 at link below). The well is currently awaiting perf/wash/cement operations. The Coyote is not currently isolated by cement in the 7-5/8” x 10-3/4” annulus. The outer annulus of this well (7-5/8” x 10-3/4”) will be monitored during the stimulation of 3T-731. Given the longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic fractures will intersect the Nuna 1 wellbore in the Coyote sand. 212-163 - Laserfiche WebLink NDST-02 PB1: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, on 1/30/2013, the bottom plug was pumped with 52bbls of 15.8ppg premium cement. Plug #2 was placed at 8,600’ MD with 52bbls of 15.8ppg premium cement. TOC was tagged at 8,012’ MD with 30klbs. On 1/31/2013, the kick off plug was pumped with 60 bbls of 17ppg premium Class G cement. Tagged firm cement at 5,236’ MD/3,228’ TVD/3,186’ TVDSS with 20klbs on 2/2/2013. 212-163 - Laserfiche WebLink Nuna 1: According to the Pioneer Natural Resources job log on the AOGCC website, the 7-5/8” casing was cemented in place on 2/16/2012. The cement report indicates that the job was pumped with 40 bbls 15.8ppg Class G cement. The plugs bumped and partial returns were observed during the job (pg. 187 at link below). A log was run to interpret TOC which has been indicated as 7,040’ MD/4,860’ TVD/4,817’ TVDSS (pg. 167 at link below). Suspension operations began on 1/18/2023 where a cement retainer was set at 9,062’ CTMD and 65bbls of Class G cement was pumped through the retainer. Another retainer was placed at 7,965’ MD and 48bbls of 15.8ppg cement was pumped with another 12 bbls laid on top of the retainer. The TOC was tagged at 7,003’ MD and a MIT-T performed to 1700 psi, witnessed by AOGCC on 3/1/2023. A tubing cut was completed at 6,960’ MD and the 4.5” tubing was then pulled. A CIBP was set at 6,910’ MD and tested to 1,200 psi. Cement was laid on top of the retainer and tagged at 6,621’ MD two times with 12klbs. The Coyote is not currently isolated with cement. The outer annulus of this well (7-5/8” x 10-3/4”) will be monitored during the stimulation of 3T-731. Given the longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic fractures will intersect the Nuna 1 wellbore in the Coyote sand. 211-155 - Laserfiche WebLink Nuna 1 PB1: According to the Pioneer Natural Resources job log on the AOGCC website, three abandonment plugs were placed on 2/10/2012. The three plugs were set as balanced plugs at the following depths: 7,347’- 6,847’ MD with 52 bbls of 15.8ppg Class G cement, 6,847’-6,285’ MD with 60bbls of 15.8ppg Class G cement, and 6,285’-5,800’ MD with 49bbls of 17.0ppg Class G cement. The top plug was tagged with 25klbs at 5,790’ MD/4,192’ TVD/4,149’ TVDSS prior to kick off for the main wellbore (pg. 186-187 at link below). 211-155 - Laserfiche WebLink SECTION 11 – LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(11) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that two faults transect the Coyote reservoir within one half mile radius of the 3T-731 wellbore trajectory. These faults intersect the 3T-731 wellbore at ~5,500’, and 11,700’ MD. The fault at ~5,500’ MD is interpreted to have minimal throw at this location (< 5 feet). This fault has an interpreted W – E strike and is downthrown to the South. There is no mapped offset at the Top Coyote based on seismic in the area where it is picked in the 3T-731 wellbore. The fault at 11,700’ MD is interpreted to have a throw of 10 – 20’ where it intersects the 3T-731 wellbore. This fault has an interpreted ~W – E strike and is downthrown to the south. These faults are interpreted to lose throw into the confining intervals above and below the Coyote reservoir. The interpreted fault should not affect overburden integrity and therefore their presence should not interfere with containment. If there is any indication that a propagated fracture has intersected the mapped fault (or any other faults unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3T-731 was completed in 2025 as a horizontal producer in the Coyote formation. The well was completed with a 4.5” tubing upper completion and a 7-5/8” x 4-1/2” tapered casing string with dart actuated sliding sleeves in the lateral. The first stages of the job will not be treated due to issues scene with cement. Injection will be established into the well and a dart will be dropped for stage 3 to initiate treatment. Once each stage is complete, a dart will be dropped for each subsequent stage. These darts will provide isolation from the previous stage and allow fracturing from the toe of the well towards the heel. Proposed Procedure: Halliburton Pumping Services: 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre- existing conditions. 2. Ensure the frac tree was tested to 10,000 psi on the rig. 3. Ensure all pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to ~2,000’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100ºF seawater. 6. MIRU HES Frac Equipment. 7. PT Surface lines to 10,000 psi using a pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Bring up pumps and increase annulus pressure to 3,500 psi as the tubing pressures up. 10. Pump the frac job per the attached Halliburton pump schedule at 20-22 bpm with a maximum expected treating pressure of 7,075 psi. 11. RDMO Halliburton Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. The well is ready for post-frac well prep/production tree installation and flowback (after Slickline and Coiled Tubing Cleanout). SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) After the fracture stimulation, ConocoPhillips (“CPAI”) plans to flowback the well for cleanup purposes for an estimated 7 to 14 days. The flowback liquids will be routed through a portable test separator then onto either CPF3 or Drill Site 3T’s facilities. Once the well’s flowback liquids meet CPF3 criteria all liquids will be routed to CPF3. CPAI plans to limit the flowback time to what is necessary to achieve conforming production liquids. Stage Job Size (lb) Top MD (ft) Top TVD (ft) Propped Half- Length (ft) Fracture Height (ft) Avg Fracture Width (in) 1 2 3 203,000 12,914 4,037 680 140 0.399 4 303,000 12,457 4,016 770 160 0.438 5 303,000 11,998 4,016 870 160 0.441 6 203,000 11,505 4,025 590 150 0.409 7 203,000 11,008 4,025 600 150 0.412 8 203,000 10,511 4,034 630 140 0.41 9 153,000 10,013 4,083 580 90 0.319 10 153,000 9,517 4,071 540 100 0.347 11 153,000 9,018 4,081 530 90 0.349 12 153,000 8,521 4,069 530 100 0.348 13 153,000 8,023 4,071 520 100 0.356 14 153,000 7,527 4,068 530 100 0.347 15 153,000 7,030 4,066 520 100 0.346 16 153,000 6,531 4,081 520 85 0.346 17 153,000 6,031 4,055 490 100 0.346 Disclaimer Notice: KRU 3T-731 This model was generated using commercially available modeling software and is based on engineering estimates of reservoir properties. Conoco Phillips is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results Not Stimulated Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-04-15 Alaska HARRISON BAY 50-103-20905-00-00 CONOCOPHILLIPS 3T 731 -150.26922564 70.41991874 NAD83 none Oil 4178 655263.75 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone Produced Water (Density 8.5)Operator Base Fluid Density = 8.50 SEAWATER (SG 8.52)Operator Base Fluid Density = 8.52 BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Calcium Chloride Customer Salt Solution Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%63.91808%5578588 Corundum 1302-74-5 60.00%18.90529%1650000 Mullite 1302-93-8 40.00%12.60353%1100000 Sodium chloride 7647-14-5 5.00%3.36411%293610 Crystalline silica, quartz 14808-60-7 100.00%0.51888%45287 Guar gum 9000-30-0 100.00%0.23457%20473 Water 7732-18-5 100.00%0.18171%15860 Calcium Chloride 10043-52-4 100.00%0.11458%10000 Water 7732-18-5 100.00%0.04870%4250 EDTA/Copper chelate Proprietary 30.00%0.03913%3416 Denise Tuck, Halliburton, 3000 N. Sam Houston Pkwy E., Houston, TX 77032, 281-871- 6226 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ethanol 64-17-5 60.00%0.03563%3110 Monoethanolamine borate 26038-87-9 100.00%0.03419%2984 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01782%1555 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01782%1555 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ammonium persulfate 7727-54-0 100.00%0.01564%1365 Sodium hydroxide 1310-73-2 30.00%0.01187%1036 Ethylene glycol 107-21-1 30.00%0.01026%896 Ammonium chloride 12125-02-9 5.00%0.00652%570 Oxyalkylated phenolic resin Proprietary 10.00%0.00594%519 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Walnut hulls NA 100.00%0.00573%500 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Flow Insurance Copper Proprietary 100.00%0.00557%486 Patina Energy Product Stewardship test@patinaen ergy.com 6692416025 Oxylated phenolic resin Proprietary 30.00%0.00469%410 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00297%260 Naphthalene 91-20-3 5.00%0.00297%260 Polyamine Proprietary 30.00%0.00172%150 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ammonia 7664-41-7 1.00%0.00130%114 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00117%103 Glycol Ether Proprietary 85.00%0.00117%102 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ammonium acetate 631-61-8 100.00%0.00105%92 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00059%52 Confidential Proprietary 20.00%0.00042%37 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Sodium chloride 7647-14-5 1.00%0.00040%35 Acetic acid 64-19-7 30.00%0.00032%28 Hemicellulase 9025-56-3 5.00%0.00029%25 Ethylene Glycol 107-21-1 20.00%0.00029%25 C.I. pigment Orange 5 3468-63-1 1.00%0.00016%14 Cured acrylic resin Proprietary 1.00%0.00006%5 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00006%5 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1-naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%3 * Total Water Volume sources may include fresh water, produced water, and/or recycled water _ ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.5 All component information listed was obtained from the supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. Production Type: True Vertical Depth (TVD): Total Water Volume (gal)*: MSDS and Non-MSDS Ingredients are listed below the green line Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Fracture Date State: County: API Number: Operator Name: CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731SALES ORDERBHST (°F)LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In SKIP DO NOT OPEN2-1 Shut-In SKIP DO NOT OPEN3-1 Shut-In Shut-In1:40:10 3-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:40:10 3-3 Shut-In Shut-In1:35:24 3-4 30# Linear Displace Dart to Seat 15 7,748 184 184 0:12:18 1:35:24 1.00 2.00 30.00 2.000.153-5 30# Linear DFIT 10 1,680 40 40 0:04:00 1:23:06 1.00 2.00 30.00 2.000.153-6 Shut-In Shut-In1:19:06 3-7 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:06 0.45 1.00 0.50 2.00 30.00 2.000.153-8 30# Delta Frac Pad 20 8,930 213 213 0:10:38 1:05:46 0.45 1.00 0.50 2.00 30.00 2.000.153-9 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:08 0.45 1.00 0.50 2.00 30.00 2.000.153-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:47:50 0.45 1.00 0.50 2.00 30.00 2.000.153-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:27 0.45 1.00 0.50 2.00 30.00 2.000.153-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:28 0.45 1.00 0.50 2.00 30.00 2.000.153-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:11 0.45 1.00 0.50 2.00 30.00 2.000.153-14 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:21:58 0.45 1.00 0.50 2.00 30.00 2.000.153-15 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:33 0.45 1.00 0.50 2.00 30.00 2.000.153-16 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:05:50 0.45 1.00 0.50 2.00 30.00 2.000.153-17 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.154-1 30# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 30.00 2.000.154-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 30.00 2.000.154-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 30.00 2.000.154-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 30.00 2.000.154-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 30.00 2.000.154-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 30.00 2.000.154-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 30.00 2.000.154-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 30.00 2.000.154-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 30.00 2.000.154-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.155-1 30# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 30.00 2.000.155-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 30.00 2.000.155-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 30.00 2.000.155-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 30.00 2.000.155-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 30.00 2.000.155-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 30.00 2.000.155-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 30.00 2.000.155-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 30.00 2.000.155-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 30.00 2.000.155-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.156-1 30# Delta Frac Pad 20 8,930 213 213 0:10:38 1:18:22 0.45 1.00 0.50 2.00 30.00 2.000.156-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:07:44 0.45 1.00 0.50 2.00 30.00 2.000.156-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 1:00:25 0.45 1.00 0.50 2.00 30.00 2.000.156-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:57:03 0.45 1.00 0.50 2.00 30.00 2.000.156-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:51:04 0.45 1.00 0.50 2.00 30.00 2.000.156-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:44:46 0.45 1.00 0.50 2.00 30.00 2.000.156-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:34:34 0.45 1.00 0.50 2.00 30.00 2.000.156-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:25:08 0.45 1.00 0.50 2.00 30.00 2.000.156-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:18:25 0.45 1.00 0.50 2.00 30.00 2.000.156-10 30# Linear Flush 20 6,795 162 162 0:08:05 0:14:05 1.00 2.00 30.00 2.000.156-11 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 6-12 Shut-In Shut-InLiquid AdditivesDry Additives50-103-20905Interval 1Interval 2Interval 3@ 12121.25 - 12125.25 ft - °FInterval 4@ 11624.46 - 11628.46 ft - °FInterval 5@ 11128.66 - 11132.66 ft - °FInterval 6@ 10630.93 - 10634.93 ft - °FConoco Phillips - 3T-731Planned Design1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731SALES ORDERBHST (°F)LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-20905v7-1 Shut-In Shut-In1:25:52 7-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:25:52 7-3 Shut-In Shut-In1:21:06 7-4 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:21:06 1.00 2.00 30.00 2.000.157-5 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:06 0.45 1.00 0.50 2.00 30.00 2.000.157-6 30# Delta Frac Pad 20 8,930 213 213 0:10:38 1:05:46 0.45 1.00 0.50 2.00 30.00 2.000.157-7 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:08 0.45 1.00 0.50 2.00 30.00 2.000.157-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.0000 20 2,600 62 67 5,200 0:03:23 0:47:50 0.45 1.00 0.50 2.00 30.00 2.000.157-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:27 0.45 1.00 0.50 2.00 30.00 2.000.157-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:28 0.45 1.00 0.50 2.00 30.00 2.000.157-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:11 0.45 1.00 0.50 2.00 30.00 2.000.157-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:21:58 0.45 1.00 0.50 2.00 30.00 2.000.157-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:33 0.45 1.00 0.50 2.00 30.00 2.000.157-14 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:05:50 0.45 1.00 0.50 2.00 30.00 2.000.157-15 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.158-1 30# Delta Frac Pad 20 8,930 213 213 0:10:38 1:05:46 0.45 1.00 0.50 2.00 30.00 2.000.158-2 30# Delta Frac Conditioning Pad 100M 0.5000 20 6,000 143 146 3,000 0:07:18 0:55:08 0.45 1.00 0.50 2.00 30.00 2.000.158-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:47:50 0.45 1.00 0.50 2.00 30.00 2.000.158-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:27 0.45 1.00 0.50 2.00 30.00 2.000.158-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:28 0.45 1.00 0.50 2.00 30.00 2.000.158-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:11 0.45 1.00 0.50 2.00 30.00 2.000.158-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:21:58 0.45 1.00 0.50 2.00 30.00 2.000.158-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:33 0.45 1.00 0.50 2.00 30.00 2.000.158-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:05:50 0.45 1.00 0.50 2.00 30.00 2.000.158-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.159-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 30.00 2.000.159-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 30.00 2.000.159-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 30.00 2.000.159-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 30.00 2.000.159-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 30.00 2.000.159-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 30.00 2.000.159-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 30.00 2.000.159-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 30.00 2.000.159-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 30.00 2.000.159-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.1510-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 30.00 2.000.1510-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 30.00 2.000.1510-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 30.00 2.000.1510-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 30.00 2.000.1510-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 30.00 2.000.1510-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 30.00 2.000.1510-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 30.00 2.000.1510-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 30.00 2.000.1510-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 30.00 2.000.1510-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.1511-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 1:00:25 0.45 1.00 0.50 2.00 30.00 2.000.1511-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:54:16 0.45 1.00 0.50 2.00 30.00 2.000.1511-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:46:58 0.45 1.00 0.50 2.00 30.00 2.000.1511-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:44:22 0.45 1.00 0.50 2.00 30.00 2.000.1511-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:39:52 0.45 1.00 0.50 2.00 30.00 2.000.1511-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:35:10 0.45 1.00 0.50 2.00 30.00 2.000.1511-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:27:37 0.45 1.00 0.50 2.00 30.00 2.000.1511-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:20:33 0.45 1.00 0.50 2.00 30.00 2.000.1511-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:15:31 0.45 1.00 0.50 2.00 30.00 2.000.1511-10 30# Linear Flush 20 5,199 124 124 0:06:11 0:12:11 1.00 2.00 30.00 2.000.1511-11 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 11-12 Shut-In Shut-InInterval 9@ 9131.33 - 9135.33 ft - °FInterval 10@ 8632.96 - 8636.96 ft - °FInterval 11@ 8133.85 - 8137.85 ft - °FInterval 7@ 10131.13 - 10135.13 ft - °FInterval 8@ 9630.71 - 9634.71 ft - °FConoco Phillips - 3T-731Planned Design2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731SALES ORDERBHST (°F)LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-20905v12-1 Shut-In Shut-In1:09:49 12-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:09:49 12-3 Shut-In Shut-In1:05:04 12-4 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:05:04 1.00 2.00 30.00 2.000.1512-5 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:03:04 0.45 1.00 0.50 2.00 30.00 2.000.1512-6 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 30.00 2.000.1512-7 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 30.00 2.000.1512-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 30.00 2.000.1512-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 30.00 2.000.1512-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 30.00 2.000.1512-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 30.00 2.000.1512-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 30.00 2.000.1512-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 30.00 2.000.1512-14 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 30.00 2.000.1512-15 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.1513-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 30.00 2.000.1513-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 30.00 2.000.1513-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 30.00 2.000.1513-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 30.00 2.000.1513-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 30.00 2.000.1513-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 30.00 2.000.1513-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 30.00 2.000.1513-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 30.00 2.000.1513-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 30.00 2.000.1513-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.1514-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 30.00 2.000.1514-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 30.00 2.000.1514-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 30.00 2.000.1514-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 30.00 2.000.1514-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 30.00 2.000.1514-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 30.00 2.000.1514-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 30.00 2.000.1514-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 30.00 2.000.1514-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 30.00 2.000.1514-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 0.50 2.00 30.00 2.000.1515-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:50:14 0.45 1.00 0.50 2.00 30.00 2.000.1515-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:44:05 0.45 1.00 0.50 2.00 30.00 2.000.1515-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:46 0.45 1.00 0.50 2.00 30.00 2.000.1515-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:34:11 0.45 1.00 0.50 2.00 30.00 2.000.1515-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:40 0.45 1.00 0.50 2.00 30.00 2.000.1515-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:58 0.45 1.00 0.50 2.00 30.00 2.000.1515-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:26 0.45 1.00 0.50 2.00 30.00 2.000.1515-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:22 0.45 1.00 0.50 2.00 30.00 2.000.1515-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:20 0.45 1.00 0.50 2.00 30.00 2.000.1515-10 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 0:02:00 1.00 2.00 30.00 2.000.1516-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:50:14 0.45 1.00 0.50 2.00 30.00 2.000.1516-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:44:05 0.45 1.00 0.50 2.00 30.00 2.000.1516-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:46 0.45 1.00 0.50 2.00 30.00 2.000.1516-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:34:11 0.45 1.00 0.50 2.00 30.00 2.000.1516-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:40 0.45 1.00 0.50 2.00 30.00 2.000.1516-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:58 0.45 1.00 0.50 2.00 30.00 2.000.1516-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:26 0.45 1.00 0.50 2.00 30.00 2.000.1516-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:22 0.45 1.00 0.50 2.00 30.00 2.000.1516-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:20 0.45 1.00 0.50 2.00 30.00 2.000.1516-10 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 0:02:00 1.00 2.00 30.00 2.000.1517-1 30# Delta Frac Pad 20 5,165 123 123 0:06:09 0:58:09 0.45 1.00 0.50 2.00 30.00 2.000.1517-2 30# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:52:00 0.45 1.00 0.50 2.00 30.00 2.000.1517-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:44:41 0.45 1.00 0.50 2.00 30.00 2.000.1517-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:42:05 0.45 1.00 0.50 2.00 30.00 2.000.1517-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:37:35 0.45 1.00 0.50 2.00 30.00 2.000.1517-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:32:53 0.45 1.00 0.50 2.00 30.00 2.000.1517-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:25:21 0.45 1.00 0.50 2.00 30.00 2.000.1517-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:18:17 0.45 1.00 0.50 2.00 30.00 2.000.1517-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:13:15 0.45 1.00 0.50 2.00 30.00 2.000.1517-10 30# Linear Flush 20 3,288 78 78 0:03:55 0:09:55 1.00 2.00 30.00 2.000.1517-11 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 17-12 Shut-In Shut-In689,225 16,410 19,379 2,795,000Interval 12@ 7634.07 - 7638.07 ft - °FInterval 13@ 7138.5 - 7142.5 ft - °FInterval 14@ 6638.36 - 6642.36 ft - °FInterval 15@ 6138.62 - 6142.62 ft - °FInterval 16@ 5643.59 - 5647.59 ft - °FInterval 17@ 5143.43 - 5147.43 ft - °F16:53:31 Conoco Phillips - 3T-731Planned Design3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731SALES ORDERBHST (°F)LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-20905vDesign Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTE BE-6652,6952,750,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)29,75045,000Initial Design Material Volume 293.7 682.4 326.3 1,364.9 20,473.4 1,364.9 102.4-6,780- 0.2506 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTE BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 0.4 0.8 0.4 1.7 25.2 1.7 1.7 0.1-Min Additive RateFluid Type30# Delta Frac30# LinearSeawaterFreeze Protect----Proppant TypeWanli 16/20 Ceramic100M---Conoco Phillips - 3T-731Planned Design4 ORIGINATED TRANSMITTAL DATE: 4/21/2025 ALASKA E-LINE SERVICES TRANSMITTAL #: 5377 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5377 3T-731 50103209050000 Cement Bond Log 2-Apr-2025 RECIPIENTS Conoco DIGITAL FILES PRINTS CD'S 1 FTP Transfer 0 0 USPS Attn: NSK-69 Richard.E.Elgarico@conocophillips.com 700 G Street Lorna.C.Collins@conocophillips.com Anchorage, AK 99503 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 224-156 T40324 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.28 08:18:58 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com Originated: Delivered to:10-Apr-25 Halliburton Alaska Oil and Gas Conservation Comm. Wireline & Perforating Attn.: Natural Resource Technician Attn: Fanny Haroun 333 West 7th Avenue, Suite 100 6900 Arctic Blvd. Anchorage, Alaska 99501 Anchorage, Alaska 99518 Office: 907-275-2605 FRS_ANC@halliburton.com The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of the sender above WELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET# 1 1Y-27 50-029-22379-00 909953476 Kuparuk River Packer Setting Record Field- Final 1-Apr-25 0 1 2 1Y-27 50-029-22379-00 909915690 Kuparuk River Packer Setting Record Field- Final 20-Mar-25 0 1 3 1Y-27 50-029-22379-00 909953476 Kuparuk River Packer Setting Record Field- Final 31-Mar-25 0 1 4 1Y-29 50-103-21852-00 909915382 Kuparuk River Multi Finger Caliper Field & Processed 23-Mar-25 0 1 5 2A-04 50-103-20026-00 909976821 Kuparuk River Multi Finger Caliper Field & Processed 31-Mar-25 0 1 6 2K-20 50-103-20120-00 909966603 Kuparuk River Multi Finger Caliper Field & Processed 26-Mar-25 0 1 7 2T-20 50-103-20215-00 909915691 Kuparuk River Multi Finger Caliper Field & Processed 13-Mar-25 0 1 8 2V-10 50-029-21310-00 909915383 Kuparuk River Packer Setting Record Field- Final 17-Mar-25 0 1 9 3T-731 50-103-20905-00 909991288 Kuparuk River Cement Evaluation with CAST Field & Processed 2-Apr-25 0 1 10 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com Date:Signed: Transmittal Date: 193-088 188-091 184-053 189-118 195-029 185-048 224-156 T40310 T40310 T40310 T40311 T40312 T40313 T40314 T40315 T40316 4/10/2025 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.10 14:23:59 -08'00' Cement Evaluation with 9 3T-731 50-103-20905-00 909991288 Kuparuk River CAST Field & Processed 2-Apr-25 0 1 224-156 Originated: Delivered to:11-Apr-25Alaska Oil & Gas Conservation Commiss11Apr25-NR !"#$$%$ !&$$'($)*%+ ($)*%,-.WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3T-731 50-103-20905-00-00 224-156 Kuparuk River WL SCMT- HSD FINAL FIELD 6-Apr-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1Please return via courier or sign/scan and email a copy to Schlumberger."2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8" ! - +"8#!(3 . 8)"3 8#!9 3 : 8" +868 8 "8#!;" " 3 - 3" 3""+ 3 + <+3!% 224-156T40317Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.04.11 08:15:32 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: ADL025528 / ADL025544 Kuparuk River Field Coyote Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): Casing Collapse Structural Conductor Surface 2470 Production 4790 Production 9210 Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. W ell Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. W ell Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Yes Date: GAS WAG GSTOR SPLUG AOGCC Representative: Victo GINJ Op Shutdown Abandoned Contact Name:Matt Smith Chris Brillon Contact Email: Contact Phone: 907-263-4324 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 KRU 3T-731 Wells Engineering Manager matt.smith2@cop.com Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 4/5/2025 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 224-156 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20905-00-00 ConocoPhillips Alaska Inc. Length Size Proposed Pools: TVD Burst 11590 MD 6890 5210 119 2511 4091 119 2625 41774.5 20 10.75 80 7.6254809 2586 13259 Perforation Depth MD (ft): 4809 12,725 8,450 4177 4/7/2025 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-208 By Grace Christianson at 1:58 pm, Apr 07, 2025 SFD 4/7/2025 DSR-4/7/25 Victoria Loepp Diverter variance granted per 20 AAC 25.035(h)(2) Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available 10-407 VTL 4/10/2025 X X *&: 4/10/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date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equirements of 20 AAC 25.005(c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equirements of 20 AAC 25.005 (c)(6) "#!$" , !$6$", #$/$ 5=!> +' !: =!> 9!$ ='/& > " , 6$", < + 9' , #&"%! ##' 0 +. , &" < < 0 6 +.375345-%!(!#$" - "/(,# !$:= > . 6 +.4 , %! &"#'(# '( )* + !* , - . # / " 0 * # !-1! 2 3 !- 2 45 & , %! //'#&$'"?//'#&$ "!'@'' #!$ 1/-"//'#&, #&" CONTINGENCY 2 NOT NEEDED OR APPROVED 4/7/2025 ( )* + ! # 4 0-!6 3 -(( 45 )*+", %! .//'#&, 0###/#(!$ 1/ ),!" !, 1/%!''/,- $&" !#" -345- !'!:!$.//'#&, 0" "!'& AB#&$ '"## ?C#D& #E"##,!$F##!<' "!'-& AB-#&$ '"## ?C#D& #E"##,!$F##!' "' , <& AB#&$ '"## ?C#D& #E !$G , H/I "!'& AB.#&$ '"## ?C#D& #E "' , & AB.#&$ '"## ?C#D& #E !$G , H/I "!'& AB.#&$ '"## ?C#D& #E "' , & AB.#&$ '"## ?C#D& #E CONTINGENCY 2 NOT NEEDED OR APPROVED From:Loepp, Victoria T (OGC) To:Matt Smith Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Wallace, Chris D (OGC) Subject:APPROVAL TO PROCEED: 3T-731 (PTD#: 224-156 )Remediation Cement 10-403 Date:Wednesday, April 9, 2025 8:35:42 AM Attachments:image001.png image001.png 3T-731 RCBL Field Log 4-9-2025.pdf Matt, Approval is granted to proceed. The log looks good and the Coyote is isolated. Victoria Sent from my iPhone On Apr 9, 2025, at 6:45ௗAM, Smith, Matt <Matt.Smith2@conocophillips.com> wrote: Mrs. Victoria, Please see attached the CBL log run on wireline last night on Doyon 142. Also below is the interpretation of the log from our COP SME in Houston. Our loss zone was further up hole than anticipated, and we obtained cement above the intended depth to isolate the Coyote. -------------------- See interpretation after reviewing RCBL from the 7 5/8” section of 3T-371. 1. Channeling of annular fluid from surface to 1,050’ – Fluid is most likely diesel pumped as freeze protection. 2. From 1,050’ to 3,240’ fluid is very homogenous reading 20mV, this is most likely mud remaining in hole from previous operation due to losses during cement job. 3. Amplitude of annular fluid drops from 20 mV to 10-11 mV from 3,240’ to 3,920’ most likely more mud from previous operation, again due to lack of removal because of losses during the cement job. 4. Moderate to good bond from 3,920’ to 3,980’ 5. Kick to the left on Gamma indicates the possible loss zone at 3,970’ – 3,980’. 6. 3,980’ to 4,010’ Moderate bond. 7. Good cement bond for Isolation from 4,010’ to 4,830’. As this covers the Coyote formation, we plan to move forward with our upper completions run, and complete the well as originally premised. Schematic of the final well design below. Please provide approval to proceed. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Smith, Matt Sent: Tuesday, April 8, 2025 10:02 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]RESUBMITTAL REQUEST: 3T-731 (PTD#: 224-156 )Remediation Cement 10-403 Good morning Victoria, I wanted to send an update on operations on 3T-731. We pumped our remedial cement job last night and unfortunately did not have good returns. We are currently waiting on cement, while we prep to go into ‘Contingency #1’ as specified in the sundry sent yesterday. I will pass along logs once we receive them. If you have any questions please let me know. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Monday, April 7, 2025 2:01 PM To: Smith, Matt <Matt.Smith2@conocophillips.com>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]RESUBMITTAL REQUEST: 3T-731 (PTD#: 224-156 )Remediation Cement 10-403 Hi Matt, Thank you for the quick reply. This application has been received for processing. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). From: Smith, Matt <Matt.Smith2@conocophillips.com> Sent: Monday, April 7, 2025 1:48 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]RESUBMITTAL REQUEST: 3T-731 (PTD#: 224-156 )Remediation Cement 10-403 Apologies! Please see attached. Thanks, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.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. From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Monday, April 7, 2025 10:38 AM To: Smith, Matt <Matt.Smith2@conocophillips.com>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: [EXTERNAL]RESUBMITTAL REQUEST: 3T-731 (PTD#: 224-156 )Remediation Cement 10-403 Importance: High CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Matt, This sundry needs a digital signature with date (box 17) and then please resubmit for processing. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). From: Smith, Matt <Matt.Smith2@conocophillips.com> Sent: Monday, April 7, 2025 10:27 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: 3T-731 (PTD#: 224-156 )Remediation Cement 10-403 Victoria, Please find attached sundry for the current operations on 3T-731. If you have any questions please let me know. We plan to be pumping cement likely later this afternoon. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? KRU 3T-731 Yes No 9. Property Designation (Lease Number): 10. Field: ADL025528 / ADL025544 Kuparuk River Field Coyote Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): Casing Collapse Structural Conductor Surface 2470 Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. W ell Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. W ell Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Yes Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Matt Smtih Chris Brillon Contact Email: Contact Phone: 907-263-4324 Authorized Title: Wells Engineering Manager 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 matt.smith2@cop.com Victoria Loeppe Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 3/17/2025 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 224-156 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20905-00-00 ConocoPhillips Alaska Inc Length Size Proposed Pools: TVD BurstMD 5210 119 2511 119 2625 20 10.75 80 2586 Perforation Depth MD (ft): 3/17/2025 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-172 By Grace Christianson at 11:05 am, Mar 26, 2025 X Diverter variance granted per 20 AAC 25.035(h)(2) Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available DSR-4/3/25VTL 4/10/2025 10-407 SFD 3/27/2025 X *&: 4/10/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.10 10:32:37 -08'00' RBDMS JSB 041025 ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage,Alaska 99510-0360 Telephone 907-276-1215 March 17, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry for PTD# 224-156 Well Name: 3T-731 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Sundry to an Approved Program, for the onshore Coyote producer 3T-731, which was spud on 3/11/2025. It is requested to revert to a single stage cement job on the production casing, due to the risk of debris from the stage cementer, posing significant risk to being able to complete the wellbore. Upon running the tapered production string as per the original PTD, cement will be pumped to 250’ TVD above the Coyote, as planned, in a single stage. Surface casing was run and cemented in place on 3/15/2025 with 150 bbls of good cement to surface. Please find attached the information required 1.Form 10-403 2.Proposed drilling program 3.Proposed completion diagram Information pertinent to the application that is presently on file at the AOGCC: 1.Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2.A description of the drilling fluids handling system. 3.Diagram of riser set up. If you have any questions or require further information, please contact Matt Smith at 907-263-4324 (matt.smith2@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-731 Well File / Jenna Taylor ATO 1804 Will Earhart ATO 1552 Matt Smith Chris Brillon ATO 1548 Drilling Engineer Pat Perfetta ATO-14-1462 y, revert to a single stage cement job on the production casing 3T-731 AOGCC 10-403 Sundry 3/17/2025 3T-731 AOGCC 10-403 Sundry 1 | 3 1. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. Pick up and run in hole with 9 7/8” x 8 3/4” drilling BHA to drill the production hole section. 2. Chart casing pressure test to 3,000 psi for 30 minutes. 3. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 4. Drill 9 7/8” hole to 4761’MD / 4,095 . Close underreamer and drill 8 3/4” to production section TD in the Coyote Reservoir. (LWD Program: GR/RES/Den/Neu). 5. Pull out of hole with drilling BHA. 6. Run tapered 7 5/8” x 4 1/2” casing with frac sleeves and toe valve. Displace to corrosion inhibited brine. 7. Pump single stage cement job to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4,000 psi (charted). Pump 3-5 bbls of diesel down OA. 8. WOC to reach 100psi compressive strength. Rig up wireline and log TOC. If casing not pressure tested on plug bump, pressure test to 4,000 psi. 9. Run 4 1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. Test hanger seals to 5,000 psi 10. Pressure test against the glass plug to set production packer, test tubing to 4,550 psi, chart test. 11. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 12. Install HP-BPV and test to 1500 psi. 13. Nipple down BOP. 14. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 15. Freeze protect down tubing and annulus. 16. Secure well. Rig down and move out. Please note – This well will be frac’d 2. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.70 33.70 L80 P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 4 1/2 8 3/4 12.60 P110S Hyd563-MS Cemented with frac sleeves *7 5/8” x 4 1/2” run together as a tapered string, utilizing a crossover joint 3T-731 AOGCC 10-403 Sundry 3/17/2025 3T-731 AOGCC 10-403 Sundry 2 | 3 10 3/4” Surface Casing run to 2,625 ’ MD / 2,511 ’ TVD Cement: Cemented on 3/15/25 with 438bbls of 11.0ppg lead + 58bbls of 15.8ppg tail. Full returns during the job, and 150bbls of cement returned to surface. 7 5/8” x 4 1/2 Production Casing (Tapered String) run to 13,269 MD / 4,191 TVD Top of slurry is designed to be at 4,155 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. Assume 40% excess in 9 7/8” hole and 15% excess in 8 3/4” hole. Lead 7 5/8 Tail 182 ft3 => 150sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk assuming 40% excess in 9 7/8” hole 4 1/2 Tail 3,015 ft3 => 2,270 sx of 14.8 ppg Class G + Add's @ 1.33 ft3/sk assuming 15% excess in 8 3/4” hole Total Cmt 3198 ft3 => 2404 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk 3T-731 AOGCC 10-403 Sundry 3/17/2025 3T-731 AOGCC 10-403 Sundry 3 | 3 3. Proposed Completion Schematic From:Loepp, Victoria T (OGC) To:Smith, Matt Subject:APPROVAL KRU 3T-731 PTD Submission Date:Monday, March 17, 2025 10:40:00 AM Attachments:image001.png image002.png Matt, Approval is granted to conduct a single stage cement job as outlined below. Please follow with a change of approved program sundry as soon as possible. Thank you, Victoria Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Smith, Matt <Matt.Smith2@conocophillips.com> Sent: Thursday, March 13, 2025 2:52 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dodson, Kate <Kate.Dodson@conocophillips.com>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com> Subject: RE: [EXTERNAL]RE: 3T-731 PTD Submission Good afternoon Victoria, I called earlier and left a voicemail, but I wanted to reach out and make sure you received this request. We’ll be beginning our production section ~Monday, so I want to make sure you don’t have any concerns with us reverting back to the plan outlined in the original permit submission. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Smith, Matt Sent: Wednesday, March 12, 2025 12:44 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dodson, Kate <Kate.Dodson@conocophillips.com>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com> Subject: RE: [EXTERNAL]RE: 3T-731 PTD Submission All, Upon further detailed planning and writing of the procedure for 3T-731, the below plan to utilize a stage tool for cementing has significant risk to the well. In order to run our final completion string, we have to perform a cleanout run on the stage collar, and have found that due to the design of the stage tool, there are several large pieces of material that are not anchored/supported, and will become debris that will fall downhole. With the size and geometry’s of those pieces, we may not be able to clean out or fish them, jeopardizing the entire well. We have determined the best option to ensure we can complete the well, is to displace the wellbore prior to our cement job with a corrosion inhibited brine with a low crystallization point (TCT), ~0°F, so that in the unlikely event we do encounter a more in-gauge hole than anticipated, the OA is already freeze protected and we would not be worried about having cement slightly inside of our surface shoe. We would then inject ~3-5bbls (~50-100’ annular space) of diesel down the annulus after the cement job, to avoid any surface temperature effects, that could freeze the near surface fluid when ambient temperatures are below 0°F. COPA would like to revert back to the original PTD, pumping only a single stage cement job, with the same planned volumes to sufficiently cover the Coyote as per regulations. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, January 14, 2025 11:33 AM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL]RE: 3T-731 PTD Submission CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Matt, This would be a revision to the PTD. If the changes only affect a few pages of the PTD document, you can send the individual updated pages to me and we will splice them into the exiting application. 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. Otherwise, resubmit the entire updated PTD package to the permitting email address with a comment saying that it supersedes the original submission. Andy From: Smith, Matt <Matt.Smith2@conocophillips.com> Sent: Tuesday, 14 January, 2025 10:45 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: 3T-731 PTD Submission All, After further discussions internally surrounding the 3T-731, 2 string well, we’ve decided to pump a 2-stage cement job on our production casing string, and bring cement to surface. With the large volume of cement for the tapered production string and standard excess cement of 40% in the overburden section and 15% in the lateral, there is potential to plug off the surface shoe, if we were to encounter a more in-gauge hole than anticipated. In order to mitigate this potential, we’ve decided to utilize a stage collar to allow us to open the annulus to circulate and analyze any cement returns to determine if this is required in the future, as well as to cement the OA to surface for long term integrity of the well. Please see below schematic. As the permit is not approved yet, do I need to submit a sundry, or a full new permit, for this additional cement? The well path itself has not changed. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM 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 Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, Coyote Oil Pool, KRU 3T-731 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-156 Surface Location: 1634' FSL, 129' FWL, NWSW S1 T12N R7E, UM Bottomhole Location: 3235' FSL, 1752' FWL, SENW S13 T12N R7E, UM Dear Mr.Brillon: 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 AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this22thday of January2025. . Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.22 14:58:23 -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: 13269 TVD: 4191 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon:8.DNR Approval Number: 13.Approximate Spud Date: 1/20/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2087' to ADL025528 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-467338 y- 6003362 Zone- 4 12 to Same Pool: 4150' to 3S-701A 16.Deviated wells: Kickoff depth: 300 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 94 H-40 Welded 81 39 39 120 120 13.5" 10.75" 45.5 L-80 Hyd563 2561 39 39 2600 2498 9.875" 7.625" 29.7 L80 Hyd563 3922 39 39 3961 3702 9.875" 7.625" 33.7 P110S Hyd563 800 3961 3702 4761 4095 8.75" 4.5" 12.6 P110S Hyd563-MS 8508 4761 4095 13269 4191 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Matt Smith Chris Brillon Contact Email:matt.smith2@cop.com Wells Engineering Manager Contact Phone:907-263-4324 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 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1634' FSL, 129' FWL, NWSW S1 T12N R7E ADL025528 / ADL025544 (including stage data) 1145' FSL, 544' FWL, SWSW S1 T12N R7E LONS 01-013 3235' FSL, 1752' FWL, SENW S13 T12N R7E 2560 / 2560 GL / BF Elevation above MSL (ft): 1874 1374 18. Casing Program: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips 59-52-180 3T-731 730sks 11ppg Lead, 280sks 15.8ppg Ta 1st stage: 2404sks 14.8ppg 2nd Stage: 233sks 11.0 ppg Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Casing Length Size Cement Volume MD Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Surface Conductor/Structural Liner Production Intermediate Perforation Depth MD (ft): Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. 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 2:02 pm, Jan 14, 20252:02 pm, Jan 14, 2025 224-156 Alaska, Inc. A.Dewhurst 14JAN25 DSR-1/16/25 Diverter variance granted per 20 AAC 25.035(h)(2) X Coyote Oil Pool 50-103-20905-00-00 KRU Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available V. Loepp 1/22/2025*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.22 14:58:38 -09'00' 01/22/25 01/22/25 RBDMS JSB 012425 <ZhϯdͲϳϯϭ Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. .58'67 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. 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: 13269 TVD: 4191 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1/20/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2087' to ADL025528 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-467338 y- 6003362 Zone- 4 12 to Same Pool: 4150' to 3S-701A 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 94 H-40 Welded 81 39 39 120 120 13.5" 10.75" 45.5 L-80 Hyd563 2561 39 39 2600 2498 9.875" 7.625" 29.7 L80 Hyd563 3922 39 39 3961 3702 9.875" 7.625" 33.7 P110S Hyd563 800 3961 3702 4761 4095 8.75" 4.5" 12.6 P110S Hyd563-MS 8508 4761 4095 13269 4191 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Matt Smith Chris Brillon Contact Email:matt.smith2@cop.com Wells Engineering Manager Contact Phone:907-263-4324 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 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1634' FSL, 129' FWL, NWSW S1 T12N R7E ADL025528 / ADL025544 (including stage data) 1145' FSL, 544' FWL, SWSW S1 T12N R7E LONS 01-013 3235' FSL, 1752' FWL, SENW S13 T12N R7E 2560 / 2560 GL / BF Elevation above MSL (ft): 1874 1374 18. Casing Program: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips 59-52-180 3T-731 730sks 11ppg Lead, 280sks 15.8ppg Ta 2404sks 14.8ppg Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Casing Length Size Cement Volume MD Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Surface Conductor/Structural Liner Production Intermediate Perforation Depth MD (ft): Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) KRU Coyote Oil Pool Alaska, Inc. 224-156 50-103-20905-00-00 Initial BOP test to 5000 psig; subsequent BOP test to xxxx psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available Diverter variance granted per 20 AAC 25.035(h)(2) X DSR-12/20/24 Superseded by revision to 10-401 related to revised production cementing plan. -A.Dewhurst 14JAN25 A.Dewhurst 09JAN25 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: 13269 TVD: 4191 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1/20/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2087' to ADL025528 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-6003362 y- 467338 Zone- 4 12 to Same Pool: 4150' to 3S-701A 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 94 H-40 Welded 81 39 39 120 120 13.5" 10.75" 45.5 L-80 Hyd563 2561 39 39 2600 2498 9.875" 7.625" 29.7 L80 Hyd563 3922 39 39 3961 3702 9.875" 7.625" 33.7 P110S Hyd563 800 3961 3702 4761 4095 8.75" 4.5" 12.6 P110S Hyd563-MS 8508 4761 4095 13269 4191 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Matt Smith Chris Brillon Contact Email:matt.smith2@cop.com Wells Engineering Manager Contact Phone:907-263-4324 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 Perforation Depth MD (ft): Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. Intermediate Production Liner Effect. Depth MD (ft): Effect. Depth TVD (ft): Surface Conductor/Structural Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Casing Length Size Cement Volume MD Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): 730sks 11ppg Lead, 280sks 15.8ppg Ta 2404sks 14.8ppg STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips 59-52-180 3T-731 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1634' FSL, 129' FWL, NWSW S1 T12N R7E ADL025528 / ADL025544 (including stage data) 1145' FSL, 544' FWL, SWSW S1 T12N R7E LONS 01-013 3235' FSL, 1752' FWL, SENW S13 T12N R7E 2560 / 2560 GL / BF Elevation above MSL (ft): 1874 1374 18. Casing Program: Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 'HF By Grace Christianson at 1:25 pm, Dec 17, 2024 DSR-12/20/24 6003362 Diverter variance granted per 20 AAC 25.035(h)(2) Superseded by corrected 10-401. See attached emails. -A.Dewhurst 08JAN25 Coyote Oil Pool KRU 224-156 467338 50-103-20905-00-00 Alaska, Inc. X Initial BOP test to 5000 psig; subsequent BOP test to xxxx psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage , Alaska 99510-0360 Telephone 907-276-1215 December 11, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-731 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Producer well from the 3T drilling pad. The intended spud date for this well is 1/20/2025. It is intended that Doyon 142 be used to drill the well. 3T-731 will utilize a 13 1/2” surface hole drilled to TD and 10 3/4” casing will be set and cemented to surface. The 9 7/8” hol e will be drilled to ~4761’MD, where the underreamer will be closed and the 8 3/4” horizontal section will be drilled and geosteered in the Coyote formation. A 7 5/8” x 4 ½” tapered casing string will be set and cemented from TD to secure the production casing and cover a 500’ or 250’ TVD above any hydrocarbon-bearing zones (Coyote) per AOGCC regulations. The well will be completed as a cemented, fracture stimulated Producer with 7 5/8” x 4 1/2” casing with frac sleeves. The 4 ½” upper completion will include a production packer with GLM’s and a downhole guage tied back to surface. A variance is requested for a BOPE test interval of 21 days for this project. Doyon 142 is a strong participant in the CPAI BOPE betweel well maintenance program, reflected by low failure rates in BOP tests since its entry into the CPAI fleet. The variance allows effective drilling and completion of problematic zones, or longer intervals during the well construction. It is also requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well 3T-731. At 3T, there has not been a significant indication of shallow gas hydrates to date, through the surface hole interval. An additional variance is requested to the casing ram requirement under 20AAC 25.035(e)(1) is granted for well 3T- 731. Being a 2 string well, COPA has determined the risk of inducing and/or handling a kick during the short duration of running the 7 5/8” casing is low. At the time in which the 7 5/8” casing will be picked up, the reservoir section will have been open, and pressures known and observed for over a week. If a kick were to be induced, the 4 1/2” casing will be within the reservoir section, and the well would be able to be controlled from the source. During the 7 5/8” casing run, a kick joint made up of 7-5/8” casing and 5” drill pipe will be available in the pipe shed, to be made up to the 7 5/8” casing, and run in hole to allow the full use of our annular and both 3-1/2” x 6” VBR’s to control any potential influx that is encountered. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1.Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a) 2.Proposed drilling program 3.Proposed drilling fluids program summary 4.Proposed completion diagram 5.Pressure information as required by 20 ACC 25.005 (c) (4) (a-c) 6.Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) Information pertinent to the application that is presently on file at the AOGCC: 1.Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2.A description of the drilling fluids handling system. 3.Diagram of riser set up. Recommend granting diverter variance based on previous analysis of KRU 3T-608, KRU 3T-603, KRU 3T-621, Nuna-1, and NDST-02. See documentation from KRU 3T-612 PTD (224-128). A.Dewhurst 23DEC24 variance of the diverter requirement Surface hole gas readings provided for offset well KRU 3T-612 are not credible due to values over 300 units before spudding. CPAI suspects gas sensor was not calibrated. See attached emails. -A.Dewhurst 09JAN25 If you have any questions or require further information, please contact Matt Smith at 907-263-4324 (matt.smith2@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-731 Well File / Jenna Taylor ATO 1804 David Lee ATO 1552 Matt Smith Chris Brillon ATO 1548 Drilling Engineer Pat Perfetta ATO-14-1462 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 1 | 12 3T-731 Well Plan Application for Permit to Drill Table of Contents 1. Well Name ............................................................................................................................................ 2 2. Location Summary ................................................................................................................................ 2 3. Proposed Drilling Program ................................................................................................................... 4 4. BOP and Diverter Information.............................................................................................................. 5 5. Procedure for Conducting Formation Integrity Tests .......................................................................... 7 6. Casing and Cementing Program ........................................................................................................... 7 7. Drilling Fluid Program ........................................................................................................................... 8 8. Abnormally Pressured Formation Information .................................................................................... 9 9. Seismic Analysis .................................................................................................................................... 9 10. Seabed Condition Analysis ................................................................................................................... 9 11. Evidence of Bonding ............................................................................................................................. 9 12. Discussion of Mud and Cuttings Disposal and Annular Disposal ......................................................... 9 13. Drilling Hazards Summary .................................................................................................................. 10 14. Proposed Completion Schematic ....................................................................................................... 12 3T-731 AOGCC 10-401 APD 1/6/2025 3T-731 AOGCC 10-401 APD 2 | 12 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 3T-731 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1,634 FSL, 129 FWL, NWSW S1 T12N R7E, UM NAD27 Northing: 6003362 Easting: 467338 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 1145‘ FSL, 544‘ FWL, SWSW S1 T12N R7E, UM NAD27 Northing: 6002871 Easting: 467751 Measured Depth, RKB:4,704 Total Vertical Depth, RKB:4,079 Total Vertical Depth, SS:4,028 Total Depth (Toe) 3235‘ FSL, 1752‘ FWL, SENW S13 T12N R7E, UM NAD27 Northing: 5994397 Easting: 468928 Measured Depth, RKB:13,269 Total Vertical Depth, RKB:4,191 Total Vertical Depth, SS:4,140 Please see attached well stick diagram for the current planned development of the pad. Pad Layout 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 2 | 12 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 3T-731 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1,634 FSL, 129 FWL, NWSW S1 T12N R7E, UM NAD27 Northing: 467338 Easting: 6003362 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 1145‘ FSL, 544‘ FWL, SWSW S1 T12N R7E, UM NAD27 Northing: 467751 Easting: 6002871 Measured Depth, RKB:4,704 Total Vertical Depth, RKB:4,079 Total Vertical Depth, SS:4,028 Total Depth (Toe) 3235‘ FSL, 1752‘ FWL, SENW S13 T12N R7E, UM NAD27 Northing: 468928 Easting: 5994397 Measured Depth, RKB:13,269 Total Vertical Depth, RKB:4,191 Total Vertical Depth, SS:4,140 Please see attached well stick diagram for the current planned development of the pad. Pad Layout Superseded by corrected Location Summary table. See attached emails. -A.Dewhurst 08JAN25 5994397 467338 6002871 467751 6003362 468928 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 3 | 12 Well Plat 3T-731 AOGCC 10-401 APD 1/14/2025 3T-731 AOGCC 10-401 APD 4 | 12 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 142 onto 3T-731 2. Rig up and test riser, dewater cellar as needed. 3. Drill 13 1/2” hole to the surface casing point as per the directional plan. 4. Run and cement 10 3/4” surface casing to surface. 5. Install BOPE and MPD equipment. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8” x 8 3/4” drilling BHA to drill the production hole section. 8. Chart casing pressure test to 3,000 psi for 30 minutes. 9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 10. Drill 9 7/8” hole to 4761’MD / 4,095 . Close underreamer and drill 8 3/4” to production section TD in the Coyote Reservoir. (LWD Program: GR/RES/Den/Neu). 11. Pull out of hole with drilling BHA. 12. Run tapered 7 5/8” x 4 1/2” casing with frac sleeves and toe valve. Pump two stage cement job to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached), with second stage bringing cement to surface. Pressure test casing if possible on plug bump to 4,000 psi (charted). 13. Drill out stage tool while WOC to reach 100psi compressive strength. Rig up wireline and log TOC. If casing not pressure tested on plug bump, pressure test to 4,000psi. 14. Run 4 1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. Test hanger seals to 5,000 psi 15. Pressure test against the glass plug to set production packer, test tubing to 4,550 psi, chart test. 16. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 17. Install HP-BPV and test to 1500 psi. 18. Nipple down BOP. 19. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 20. Freeze protect down tubing and annulus. 21. Secure well. Rig down and move out. Please note – This well will be frac’d 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 4 | 12 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 142 onto 3T-731 2. Rig up and test riser, dewater cellar as needed. 3. Drill 13 1/2” hole to the surface casing point as per the directional plan. 4. Run and cement 10 3/4” surface casing to surface. 5. Install BOPE and MPD equipment. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8” x 8 3/4” drilling BHA to drill the production hole section. 8. Chart casing pressure test to 3,000 psi for 30 minutes. 9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 10. Drill 9 7/8” hole to 4761’MD / 4,095 . Close underreamer and drill 8 3/4” to production section TD in the Coyote Reservoir. (LWD Program: GR/RES/Den/Neu). 11. Pull out of hole with drilling BHA. 12. Run tapered 7 5/8” x 4 1/2” casing with frac sleeves and toe valve. Pump cement to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4,000 psi (charted). 13. WOC to reach 100psi compressive strength. Rig up wireline and log TOC. If casing not pressure tested on plug bump, pressure test to 4,000psi. 14. Run 4 1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. Test hanger seals to 5,000 psi 15. Pressure test against the glass plug to set production packer, test tubing to 4,550 psi, chart test. 16. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 17. Install HP-BPV and test to 1500 psi. 18. Nipple down BOP. 19. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 20. Freeze protect down tubing and annulus. 21. Secure well. Rig down and move out. Please note – This well will be frac’d Superseded by updated program related to revised production cementing plan. -A.Dewhurst 14JAN25 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 5 | 12 4. BOP and Diverter Information Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP schematics on file for Doyon 142. Doyon 142 will use a BOPE stack equipped with an annular preventer, 2 sets of variable rams in upper and lower cavities, and blind/shear rams in the middle cavity, while drilling and running casing in the production section of 3T-731. 3T-731 has a MASP of 1,374 psi in the production hole section using the methodology in section 6 MASP calculations. With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2. Per 20AAC 25.035.e.1.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing being used, except that pipe rams need not be sized to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type Production Drilling & Casing: Annular Preventer (iii) 3-1/2” x 6” VBR’s Blind/Shear Rams (ii) 3-1/2” x 6” VBR’s (i) *A kick joint will be readily available to make up to the 7-5/8” casing if an influx is encountered, to allow RIH with the casing string and utilizing our annular and both 3-1/2” x 6” VBR’s 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 6 | 12 MASP Calculations Requirements of 20 AAC 25.005(c)(4) (A) maximum downhole pressure and maximum potential surface pressure; Maximum Potential Surface Pressure (MPSP) is determined as the lesser of: Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 1 Method 2 = [( ×0.052 ) ] × = ( ) × Where: FG – Fracture gradient at the casing seat in lb/gal 0.052 – Conversion from lb/gal to psi/ft Gas Gradient – 0.1 psi/ft TVD – True Vertical Depth of casing seat in ft RKB Where: FPP – Formation Pore Pressure at the next casing point Gas Gradient – 0.1 psi/ft The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: Section Hole Size Previous CSG Section TD MPSP psi MPSP MPSP Size MD TVD FG ppg Pore Pressure ppg | psi MD TVD Pore Pressure ppg | psi Method 1 psi Method 2 psi SURF 13 1/2 20 120 120 10.9 8.6 54 2,600 2,498 8.6 1,117 56 56 867 PROD 9 7/8 x 8 3/4 10 3/4 2,600 2,498 12.5 8.6 1,117 13,269 4,191 8.6 1,874 1,374 1,374 1,455 (B) data on potential gas zones; The wellbore is not expected to penetrate any shallow gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary 3T-731 AOGCC 10-401 APD 1/14/2025 3T-731 AOGCC 10-401 APD 7 | 12 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out casing shoe and perform LOT test or FIT in accordance with the LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.70 33.70 L80 P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 2nd stage ~200’ below surface casing to surface 4 1/2 8 3/4 12.60 P110S Hyd563-MS Cemented liner with frac sleeves *7 5/8” x 4 1/2” run together as a tapered string, utilizing a crossover joint 10 3/4” Surface Casing run to 2,600 ’ MD / 2,498 ’ TVD Cement Plan: Cement 2,600 MD to 2,100 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 2,100' to surface with 11.0 ppg Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,755 ’ MD), zero excess in 20” conductor. Lead 2,103ft3 => 730 sx of 11.0 ppg Class G + Add's @ 2.92 ft3 /sk Tail 316 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk 7 5/8” x 4 1/2 Production Casing (Tapered String) run to 13,269 MD / 4,191 TVD Top of slurry is designed to be at 4,155 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. Assume 40% excess in 9 7/8” hole and 15% excess in 8 3/4” hole. Lead 7 5/8 Tail 182 ft3 => 150sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk assuming 40% excess in 9 7/8” hole 4 1/2 Tail 3,015 ft3 => 2,270 sx of 14.8 ppg Class G + Add's @ 1.33 ft3/sk assuming 15% excess in 8 3/4” hole Total Cmt 3198 ft3 => 2404 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk 2nd Stage – 7-5/8” x 10-3/4” surface casing, from 2,799’ (~200’ below surface shoe) to surface 7 5/8 CH 627 ft3 => 215sx of 11 ppg Class G + Add's @ 2.92ft3 /sk assuming 10% excess in cased hole 7-5/8 OH 54 ft3 => 18sx of 11 ppg Class G + Add's @ 2.92 ft3 /sk assuming 25% excess in open hole Total Cmt 681ft3 => 233 sx of 11 ppg Class G + Add's @ 2.92 ft3 /sk 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 7 | 12 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out casing shoe and perform LOT test or FIT in accordance with the LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.70 33.70 L80 P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 4 1/2 8 3/4 12.60 P110S Hyd563-MS Cemented liner with frac sleeves *7 5/8” x 4 1/2” run together as a tapered string, utilizing a crossover joint 10 3/4” Surface Casing run to 2,600 ’ MD / 2,498 ’ TVD Cement Plan: Cement 2,600 MD to 2,100 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 2,100' to surface with 11.0 ppg Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,755 ’ MD), zero excess in 20” conductor. Lead 2,103ft3 => 730 sx of 11.0 ppg Class G + Add's @ 2.92 ft3 /sk Tail 316 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk 7 5/8” x 4 1/2 Production Casing (Tapered String) run to 13,269 MD / 4,191 TVD Top of slurry is designed to be at 4,155 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. Assume 40% excess in 9 7/8” hole and 15% excess in 8 3/4” hole. Lead 7 5/8 Tail 182 ft3 => 150sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk assuming 40% excess in 9 7/8” hole 4 1/2 Tail 3,015 ft3 => 2,270 sx of 14.8 ppg Class G + Add's @ 1.33 ft3/sk assuming 15% excess in 8 3/4” hole Total Cmt 3198 ft3 => 2404 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk Superseded by updated program related to revised production cementing plan. -A.Dewhurst 14JAN25 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 8 | 12 7. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Production Hole Size in. 13 1/2 9 7/8 x 8 3/4 Casing Size in. 10 3/4 7 5/8 x 4 1/2 Density PPG 9.0 – 10.5 9.0 – 10.0 PV cP 20-50 7-12 YP lb./100 ft2 30 - 80 15 - 30 Funnel Viscosity s/qt. 250 – 300 35-50 Initial Gels lb./100 ft2 30 - 50 5- 10 10 Minute Gels lb./100 ft2 50 - 70 7 - 15 API Fluid Loss cc/30 min. N.C. – 15.0 < 6.0 HPHT Fluid Loss cc/30 min. N/A < 10.0 pH 9.5 – 10.0 9.5 – 10.5 Surface Hole: A water-based spud mud will be used for the surface interval. Mud engineer to perform regular mud checks to maintain proper specifications The mud weight will be maintained at P9.8 ppg by use of solids control system and dilutions where necessary. Production Hole: The horizontal production interval will be drilled with an inhibited fresh water polymer mud system weighted to 9.0 – 10.0 ppg. MPD will be utilized for adding backpressure during connections if necessary for wellbore stability. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 9 | 12 8. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 9. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 11. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 12. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 10 | 12 13. Drilling Hazards Summary 13 1/2" Hole - 10 3/4” Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low Follow real time surveys very closely, gyro survey as needed to ensure survey accuracy. Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Hole Swabbing on Trips Medium Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts/Hole Sloughing Medium Cool mud temperatures, minimize circulating times when possible Running sands and gravels Medium Maintain planned mud properties, increase mud weight, use weighted sweeps 9 7/8 x 8 3/4” Hole - 7 5/8 x 4 1/2” Production Casing - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Medium Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material Sloughing shale / Tight hole / Stuck Pipe Low Good hole cleaning, pre-treatment with LCM, stabilized BHA, maintain planned mud weights and adjust as needed, real time equivalent circulating density (ECD) monitoring Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Medium Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Casing to Bottom Medium Properly clean hole on the trip out with BHA, perform clean out run if necessary, monitor T&D real time Insufficient TOC to cover Coyote formation Medium Pre job modeling of pump rates and ECD’s. Proper mud conditioning prior to the job. Monitoring losses and adjusting pump rates as needed during the job. To be posted in Rig Floor Doghouse Prior to Spud 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 11 | 12 Well Proximity Risks: 3T is a multi-well pad, with only a few existing wells. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Unlikely to encounter any abnormal pressure, however, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the primary intermediate cement job will be replanned to cover the zone as per the agency regulations. Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 3T-731 AOGCC 10-401 APD 1/14/2025 3T-731 AOGCC 10-401 APD 12 | 12 14. Proposed Completion Schematic 3T-731 AOGCC 10-401 APD 12/12/2024 3T-731 AOGCC 10-401 APD 12 | 12 14. Proposed Completion Schematic Superseded by updated schematic related to revised production cementing plan. -A.Dewhurst 14JAN25 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 10000 10000 13664 3T-731 wp09 Plan Summary 0 4 Dogleg Severity0 2000 4000 6000 8000 10000 12000 Measured Depth 10-3/4" Surface Casing 9-7/8 to 8-3/4 hole transition 7-5/8" Production Liner 30.0 30.0 60.0 60.0 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 752 801 850 898 945 993 1039 1085 NDST-02 752 801 850 898 945 993 1039 1085 3950100150200250300350400450500550600650700750800850900950100010501100115012001250130013501400145015001552160316541704 1754 1803 1850 1897 1943 1988 3T-730 (I14) wp08 19391985202920722113 3T-622 wp05 v5 1735 17831830187619201962 3T-623 wp05 v5 1285 1333 1382 1431 1480 1530 1580 1629 1677 17243T-625 wp05 v5 993 1042 1091 1140 1188 1237 1285 1334 1382 1431 1480 1528 1576 3T-626 wp05 v5 3950100150200250300350400450500550599649698748797 846 896 944 993 1042 1091 1139 1187 1235 1283 3T-628 wp05 v5 3950100150200250300350400450500550599649698748 797 846 895 944 992 1040 1088 1136 3T-629 wp05 v5 0 2500 True Vertical Depth0 1500 3000 4500 6000 7500 9000 Vertical Section at 169.68° 10-3/4" Surface Casing 9-7/8 to 8-3/4 hole transition 7-5/8" Production Liner 25 38 Centre to Centre Separation0 425 850 1275 1700 2125 2550 2975 Measured Depth DDI 6.824 SURVEY PROGRAM Date: 2019-05-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.10 300.00 3T-731 wp09 (3T-731) INC 300.00 2620.00 3T-731 wp09 (3T-731) MWD+IFR2+SAG+MS 2620.00 13269.84 3T-731 wp09 (3T-731) MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 2517.10 2620.34 10-3/4" Surface Casing 4095.10 4761.53 9-7/8 to 8-3/4 hole transition4191.10 13269.98 7-5/8" Production Liner Mag Model & Date: BGGM2024 01-Feb-25 Magnetic North is 13.93° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.62° 57189.02nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00000 3 525.00 2.25 313.00 524.94 3.01 -3.23 1.00 313.00 -3.54 Start Build 2.50000 4 1378.57 23.59 313.00 1352.10 132.42 -142.00 2.50 0.00 -155.71 Start 109.11807 hold at 1378.56602 MD 5 1487.68 23.59 313.00 1452.10 162.20 -173.93 0.00 0.00 -190.72 Start DLS 3.50000 TFO 128.25430 6 2317.58 22.86 31.96 2231.50 417.68 -210.84 3.50 128.25 -448.69 Start 4.68606 hold at 2317.58199 MD 7 2322.27 22.86 31.96 2235.82 419.23 -209.88 0.00 0.00 -450.04 Start DLS 3.75000 TFO 137.92263 8 4961.13 81.87 170.00 4135.66 -734.43 465.02 3.75 137.92 805.83 Start Build 3.50000 9 5136.13 88.00 170.00 4151.10 -906.01 495.27 3.50 0.00 980.06 3T-731 P14 T1 041124 Start 20.00000 hold at 5136.12760 MD 10 5156.13 88.00 170.00 4151.80 -925.70 498.74 0.00 0.00 1000.05 Start DLS 1.50000 TFO 48.91294 11 5332.90 89.74 172.00 4155.28 -1100.25 526.39 1.50 48.97 1176.73 Start 7977.60042 hold at 5332.82176 MD 1213269.98 89.74 172.00 4191.10 -8960.00 1631.00 0.00 0.00 9107.24 FORMATION TOP DETAILS TVDPath Formation 1376.10 Top Ugnu 1701.10 Base Perm 2020.10 Top West Sak 2412.10 Base West Sak 2588.10 C-80 3601.10 Anomalous Zone 3901.10 C-35 4079.10 Top Coyote By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet la teral tolerance. Prepared by Checked by Accepted by Approved by Plan 12+39.1 @ 51.10usft (D142) 0150030004500True Vertical Depth0 1500 3000 4500 6000 7500 9000Vertical Section at 169.69°10-3/4" Surface Casing9-7/8" to 8-3/4" hole transition7-5/8" Production Liner10002000300040005000600070008000900010000110001200013000133100°30°60°90°3T-731 (P14) wp09Top UgnuBase PermTop West SakBase West SakC-80Anomalous ZoneC-35Top Coyote3T-731 (P14) wp0912:38, October 30 2024Section View -8000-6000-4000-20000South(-)/North(+)-6000 -4000 -2000 0 2000 4000 6000 8000West(-)/East(+)3T-731 P14 T1 0411243T-731 P14 T2 10302410-3/4" Surface Casing9-7/8 to 8-3/4 hole transition7-5/8" Production Liner50010001500200025003000350040004500500055006000650070007500800085009000950010000105001100011500120001250013000132713T-731 wp093T-731 wp09While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.13:32, October 30 20243ODQ6XUYH\ 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 10000 10000 13270 3T-731 wp09 TC View 30 30 60 60 90 90 120 120 150 150 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 3960110160210260309359 409 458 507 557 606 655 704 752 801 850 898 945 993 1039 1085 1130 1174 1218 1260 NDST-02 3960110160210260309359 409 458 507 557 606 655 704 752 801 850 898 945 993 1039 1085 1130 1174 1218 1260 2429 2461 2491 2521 3T-612 wp14 1154120312531302135114011450150115561609 166217141765181418621909 1952 1993 2032 2069 3T-621 39501001502002503003504004505005506006507007508008509009501000105011001150120012501300135014001450150015521603165417041754 1803 1850 1897 1943 1988 2032 2075 2117 2158 2200 3T-730 (I14) wp08 2025207321202164 2206 2247 2285 2321 3T-619 wp06 v5 1809186019111959200620512093 2134 2173 2210 3T-620 wp05 v5 122812761324 1372 1421 1471 1524 1579 1633 1687 1739179118421891193919852029207221132152 218922242258 3T-622 wp05 v5 3950100150200250300350400449499549598647696745794843892941990103910881137118512341282 1331 1379 1429 1478 1530 1583 1634 16851735178318301876192019622003204220792114 3T-623 wp05 v5 395010015020025030035040045049954959864769674679584489394299110391088 1137 1185 1233 1282 1330 1378 1427 1476 1528 1580 1631 1682 1732 1781 1828 1874191819612002204220793T-624 wp05 v5 395010015020025030035040045049954959864869774679684589494399210411090 1139 1188 1236 1285 1333 1382 1431 1480 1530 1580 1629 1677 1724 1770 1815185718991938 3T-625 wp05 v5 39501001502002503003504004505005495996486987477968468959449931042 1091 1140 1188 1237 1285 1334 1382 1431 1480 1528 1576 1623 1669 1714 1757 1800 1840 3T-626 wp05 v5 3950100150200250300350400450500549598 647 696 744 792 839 885 931 976 1020 1064 1106 3T-627 wp05 v5 3950100150200250300350400450500550599649698748797846 896 944 993 1042 1091 1139 1187 1235 1283 1330 1377 1426 1474 1522 1569 1615 1661 3T-628 wp05 v5 3950100150200250300350400450500550599649698748797 846 895 944 992 1040 1088 1136 1184 1231 1278 1324 1371 1419 1467 1515 1562 3T-629 wp05 v5 SURVEY PROGRAM Date: 2019-05-03T00:00:00 Validated: Yes Version: From To Tool 39.10 300.00 INC 300.00 2620.00 MWD+IFR2+SAG+MS 2620.00 13269.84 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 2517.10 2620.34 10-3/4" Surface Casing 4095.10 4761.53 9-7/8 to 8-3/4 hole transition 4191.10 13269.98 7-5/8" Production Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00000 3 525.00 2.25 313.00 524.94 3.01 -3.23 1.00 313.00 -3.54 Start Build 2.50000 4 1378.57 23.59 313.00 1352.10 132.42 -142.00 2.50 0.00 -155.71 Start 109.11807 hold at 1378.56602 MD 5 1487.68 23.59 313.00 1452.10 162.20 -173.93 0.00 0.00 -190.72 Start DLS 3.50000 TFO 128.25430 6 2317.58 22.86 31.96 2231.50 417.68 -210.84 3.50 128.25 -448.69 Start 4.68606 hold at 2317.58199 MD 7 2322.27 22.86 31.96 2235.82 419.23 -209.88 0.00 0.00 -450.04 Start DLS 3.75000 TFO 137.92263 8 4961.13 81.87 170.00 4135.66 -734.43 465.02 3.75 137.92 805.83 Start Build 3.50000 9 5136.13 88.00 170.00 4151.10 -906.01 495.27 3.50 0.00 980.06 3T-731 P14 T1 041124 Start 20.00000 hold at 5136.12760 MD 10 5156.13 88.00 170.00 4151.80 -925.70 498.74 0.00 0.00 1000.05 Start DLS 1.50000 TFO 48.91294 11 5332.90 89.74 172.00 4155.28 -1100.25 526.39 1.50 48.97 1176.73 Start 7977.60042 hold at 5332.82176 MD 1213269.98 89.74 172.00 4191.10 -8960.00 1631.00 0.00 0.00 9107.24 3T-731 wp09AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 300.00 INC300.00 2620.00 MWD+IFR2+SAG+MS2620.00 13269.84 MWD+IFR2+SAG+MSCASING DETAILSTVD MDName2517.10 2620.3410-3/4" Surface Casing4095.10 4761.539-7/8 to 8-3/4 hole transition4191.10 13269.987-5/8" Production Liner1010202030304040505060600901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in]75280185089894599310391085NDST-027528018508989459931039108539501001502002503003504004505005506006507007508008509009501000105011001150120012501300135014001450150015521603165417041754180318501897194319883T-730 (I14) wp08193919852029207221133T-622 wp05 v51735178318301876192019623T-623 wp05 v512851333138214311480153015801629167717243T-625 wp05 v59931042109111401188123712851334138214311480152815763T-626 wp05 v539501001502002503003504004505005505996496987487978468969449931042109111391187123512833T-628 wp05 v539501001502002503003504004505005505996496987487978468959449921040108811363T-629 wp05 v539 500500 800800 11001100 15001500 20002000 30003000 50005000 1000010000 13270From Colour To MD39.10 To 2700.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00525.00 313.00 313.001378.57 313.00 0.001487.68 313.00 0.002317.58 31.96 128.252322.27 31.96 0.004961.13 170.00 137.925136.13 170.00 0.005156.13 170.00 0.005332.90 172.00 48.9713269.98 172.00 0.00 3T-731 wp09AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 300.00 INC300.00 2620.00 MWD+IFR2+SAG+MS2620.00 13269.84 MWD+IFR2+SAG+MSCASING DETAILSTVD MDName2517.10 2620.3410-3/4" Surface Casing4095.10 4761.539-7/8 to 8-3/4 hole transition4191.10 13269.987-5/8" Production Liner60601201201801802402403003003603600901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [120 usft/in]260026242650266726863T-612 wp1426282660269027183T-611 wp06 v526153T-617 wp05 v539 500500 800800 11001100 15001500 20002000 30003000 50005000 1000010000 13270From Colour To MD2600.00 To 4800.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00525.00 313.00 313.001378.57 313.00 0.001487.68 313.00 0.002317.58 31.96 128.252322.27 31.96 0.004961.13 170.00 137.925136.13 170.00 0.005156.13 170.00 0.005332.90 172.00 48.9713269.98 172.00 0.00 3T-731 wp09AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 300.00 INC300.00 2620.00 MWD+IFR2+SAG+MS2620.00 13269.84 MWD+IFR2+SAG+MSCASING DETAILSTVD MDName2517.10 2620.3410-3/4" Surface Casing4095.10 4761.539-7/8 to 8-3/4 hole transition4191.10 13269.987-5/8" Production Liner60601201201801802402403003003603600901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [120 usft/in]10182101831018310183101831018310184101841018410184101841018510185Moraine 18736870386718638860685738541850884763S-6121316613206132463S-719 (P02) wp0539 500500 800800 11001100 15001500 20002000 30003000 50005000 1000010000 13270From Colour To MD4700.00 To 13270.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00525.00 313.00 313.001378.57 313.00 0.001487.68 313.00 0.002317.58 31.96 128.252322.27 31.96 0.004961.13 170.00 137.925136.13 170.00 0.005156.13 170.00 0.005332.90 172.00 48.9713269.98 172.00 0.00 3T-731 wp09Spider Plot13:47, October 30 2024 To 13270.00Northing (6500 usft/in)Easting (6500 usft/in)354 0455055Moraine 135404550NDST-0235404550NDST-02PB135404550Nuna 135404550Nuna 1PB1354045 5055603S-19354045503S-611354045503S-612354045503S-613354045503S-615354045503S-620354045503S-62535403S-719 (P02) wp0535403S-721 (I03) wp0435403S-740 (I15) wp0335403S-741 (P15) wp02354045503T-603354045503T-608354045503T-608 wp14 - tied to int srvy354045503T-612 wp14354 0 45503T-616 wp13.13540455 0553T-62135403T-730 (I14) wp083 5 4 0 4 5503T-601 wp05 v53 5 4 0 4 5503T-602 wp05 v5354045503T-604 wp05 v5354045503T-605 wp05 v5354045503T-606 wp06 v5354045503T-607 wp05 v5354045503T-609 wp06 v5354045503T-610 wp05 v5354045503T-611 wp06 v5354045503T-613 wp05 v535404 5503T-614 wp05 v535404 5 503T-615 wp05 v5354045503T-617 wp05 v535404 5 503T-618 wp05 v5354045503T-619 wp06 v535404 5 503T-620 wp05 v5354045503T-622 wp05 v535404 5 503T-623 wp05 v5354045503T-624 wp05 v5354045503T-625 wp05 v535404 5 503T-626 wp05 v5354045503T-627 wp05 v53 5 40 45 503T-628 wp05 v5354045503T-629 wp05 v535403T-731 wp09 3T-731 wp09Spider Plot13:49, October 30 2024To 13270.00Northing (2000 usft/in)Easting (2000 usft/in)353739414 3454749515355Moraine 1NDST-02NDST-02PB1353739Nuna 1353739Nuna 1PB1353739 41434547495153555759613S-193537394143454749513S-6113537394143454749513S-6124749513S-613394143454749513S-6153537394143454749513S-620513S-62535373 9 413S-719 (P02) wp0535373 93S-721 (I03) wp0435373 9 413S-740 (I15) wp03353 7 393S-741 (P15) wp023T-603353T-608353T-608 wp14 - tied to int srvy35373941433T-612 wp1435373 9 4 1 43454749513T-616 wp13.13T-621353739413T-730 (I14) wp083 5 3 7 3 93T-601 wp05 v53 5 3 7 3 9 4 1 4 3 4 5473T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-606 wp06 v53T-607 wp05 v5353T-609 wp06 v53T-610 wp05 v535373941433T-611 wp06 v53T-613 wp05 v5353739414 3 4 5 4749513T-614 wp05 v53T-615 wp05 v535373941434547493T-617 wp05 v53T-618 wp05 v5353T-619 wp06 v535373T-620 wp05 v5353739414345473T-622 wp05 v5353739413T-623 wp05 v53537394143453T-624 wp05 v5353739414345473T-625 wp05 v535373T-626 wp05 v535373941433T-627 wp05 v53 5 37 3 9 4 13T-628 wp05 v535373941433T-629 wp05 v5353739413T-731 wp09 3T-731 wp09Spider Plot13:50, October 30 2024 To 13270.00Northing (200 usft/in)Easting (200 usft/in)NDST-02NDST-02PB1Nuna 1Nuna 1PB13S-6113T-603203T-608203T-608 wp14 - tied to int srvy2022243T-612 wp1420223T-616 wp13.120223T-621202224263T-730 (I14) wp083T-601 wp05 v52 03T-602 wp05 v3T-604 wp05 v53T-605 wp05 v53T-606 wp06 v53T-607 wp05 v53T-609 wp06 v53T-610 wp05 v520223T-611 wp06 v5203T-613 wp05 v520223T-614 wp05 v5203T-615 wp05 v520223T-617 wp05 v520223T-618 wp05 v520223T-619 wp06 v520223T-620 wp05 v52022243T-622 wp05 v520223T-623 wp05 v520223T-624 wp05 v5203T-625 wp05 v5203T-626 wp05 v520223T-627 wp05 v5203T-628 wp05 v520223T-629 wp05 v52022242 62830 32343638403T-731 wp09 3T-731 wp09Spider Plot13:51, October 30 2024 To 13270.00Northing (65 usft/in)Easting (65 usft/in)681012NDST-02681012NDST-02PB112Nuna 112Nuna 1PB13S-61124 68101214163T-62124681012141618203T-730 (I14) wp08123T-617 wp05 v51012143T-618 wp05 v52468101214163T-619 wp06 v52468101214163T-620 wp05 v524681012141618203T-622 wp05 v524681012141618203T-623 wp05 v524681012141618203T-624 wp05 v5246810121416183T-625 wp05 v5246810121416183T-626 wp05 v5246810123T-627 wp05 v5246810121416183T-628 wp05 v52468 10121 4 16183T-629 wp05 v524681012141618363T-731 wp09 3T-731 wp09Moraine 13S-193S-6113S-6133S-6203T-730 (I14) wp083-D View3T-731 wp0913:55, October 30 2024 3T-731 wp09Moraine 1Nuna 1PB13S-193S-3S-6123S-6133S-6203T-730 (I14) wp083T-615 wp05 v53-D View3T-731 wp0913:56, October 30 2024 -10000-8000-6000-4000-20000South(-)/North(+) (2000 usft/in)-6000 -4000 -2000 0 2000 4000 6000 8000 10000West(-)/East(+) (2000 usft/in)410041504200M o r a in e 1 NDST-02NDST-02PB1Nuna 1Nuna 1PB14100415042003S-194100415042003S-6114100415042003S-6124100415042003S-6134100415042003S-6154100415042003S-62041004150 4200 3S-625410041503S-719 (P02) wp0541003S-721 (I03) wp04410041503S-740 (I15) wp0341003S-741 (P15) wp023T-6033T-6083T-608 wp14 - tied to int srvy3T-612 wp144 1 0 041504200 3T-616 wp13.13 T -6 2 1 410041503T-730 (I14) wp083T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-606 wp06 v53T-607 wp05 v53T-609 wp06 v53T-610 wp05 v53T-611 wp06 v53T-613 wp05 v54100415042003T-614 wp05 v53T-615 wp05 v53T-617 wp05 v53T-618 wp05 v53T-619 wp06 v53T-620 wp05 v53T-622 wp05 v53T-623 wp05 v5410041503T-624 wp05 v53T-625 wp05 v53T-626 wp05 v54100415042003T-627 wp05 v53T-628 wp05 v5410041503T-629 wp05 v5410041503T-731 wp093T-731 wp09Quarter Mile View14:19, October 30 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-731 P14 T1 041124 4151.10 Circle (Radius: 100.00)3T-731 P14 T2 103024 4191.10 Circle (Radius: 100.00)3T-731 T1 QM 4151.10 Circle (Radius: 1320.00)3T-731 T2 QM 4191.10 Circle (Radius: 1320.00) -10000-8000-6000-4000-20000South(-)/North(+) (2000 usft/in)-6000 -4000 -2000 0 2000 4000 6000 8000 10000West(-)/East(+) (2000 usft/in)410041504200M o r a in e 1 4100415042003S-615410041503S-719 (P02) wp05410041503T-730 (I14) wp0810-3/4" Surface Casing9-7/8 to 8-3/4 hole transition7-5/8" Production Liner410041503T-731 wp093T-731 wp09Quarter Mile View14:45, October 30 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-731 P14 T1 041124 4151.10 Circle (Radius: 100.00)3T-731 P14 T2 103024 4191.10 Circle (Radius: 100.00)3T-731 T1 QM 4151.10 Circle (Radius: 1320.00)3T-731 T2 QM 4191.10 Circle (Radius: 1320.00) 02004006008001000South(-)/North(+) (200 usft/in)-1000 -800 -600 -400 -200 0 200 400 600West(-)/East(+) (200 usft/in)NDST-02NDST-02PB12352Nuna 12352Nuna 1PB13S-6113T-60323523T-60823523T-612 wp143T-616 wp13.123523T -6 21 23523T-730 (I14) wp083T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-606 wp06 v523523T-607 wp05 v523523T-609 wp06 v523523T-610 wp05 v523523T-611 wp06 v523523T-613 wp05 v53T-614 wp05 v523523T-615 wp05 v523523T-617 wp05 v523523T-618 wp05 v523523T-619 wp06 v523523T-620 wp05 v523523T-622 wp05 v523523T-623 wp05 v523523T-624 wp05 v523523T-625 wp05 v523523T-626 wp05 v53T-627 wp05 v523523T-628 wp05 v52352 3T-629 wp05 v523523T-731 (P14) wp083T-731 (P14) wp08 6XUIDFH&DVLQJ U14:25, October 29 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-731 P14 T1 041124 4151.10 Circle (Radius: 100.00)3T-731 P14 T2 032824 4191.10 Circle (Radius: 100.00)3T-731 Srf Csg 2352.10 Circle (Radius: 500.00) 025050075010001250South(-)/North(+) (250 usft/in)-1000 -750 -500 -250 0 250 500 750 1000West(-)/East(+) (250 usft/in)3T-60325173T-60825173T-612 wp143T-616 wp13.13 T -6 2 1 10-3/4" Surface Casing2 5 1 7 3T-731 wp093T-731 wp096XUIDFH&DVLQJ U14:52, October 30 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-731 P14 T1 041124 4151.10 Circle (Radius: 100.00)3T-731 P14 T2 103024 4191.10 Circle (Radius: 100.00)3T-731 Srf Csg 2352.10 Circle (Radius: 500.00) 3T-731 wp09 Surface Location 3T-731 wp09 Surface Location #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-731 wp09 Surface Casing 3T-731 wp09 Surface Casing #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-731 wp09 Top Coyote 3T-731 wp09 Top Coyote #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-731 wp09 TD 3T-731 wp09 TD # Schlumberger-Confidential Certificate Of Completion Envelope Id: C6B75F31-E059-49F1-B3CB-F7E01B87F24E Status: Completed Subject: Complete with Docusign: 3T-731 PTD Submission.pdf Source Envelope: Document Pages: 58 Signatures: 1 Envelope Originator: Certificate Pages: 4 Initials: 0 Matt Smith AutoNav: Enabled EnvelopeId Stamping: Disabled Time Zone: (UTC-06:00) Central Time (US & Canada) 925 N Eldridge Pkwy Houston, TX 77079 Matt.Smith2@conocophillips.com IP Address: 138.32.8.5 Record Tracking Status: Original 12/12/2024 3:46:28 PM Holder: Matt Smith Matt.Smith2@conocophillips.com Location: DocuSign Signer Events Signature Timestamp Chris Brillon chris.l.brillon@cop.com Security Level: Email, Account Authentication (None) Signature Adoption: Pre-selected Style Using IP Address: 138.32.8.5 Sent: 12/12/2024 3:49:35 PM Viewed: 12/17/2024 9:16:50 AM Signed: 12/17/2024 9:18:41 AM Electronic Record and Signature Disclosure: Accepted: 12/17/2024 9:16:50 AM ID: 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By selecting the check-box next to ‘I agree to use electronic records and signatures’, you confirm that: x You can access and read this Electronic Record and Signature Disclosure; and x You can print on paper this Electronic Record and Signature Disclosure, or save or send this Electronic Record and Disclosure to a location where you can print it, for future reference and access; and x Until or unless you notify ConocoPhillips as described above, you consent to receive exclusively through electronic means all notices, disclosures, authorizations, acknowledgements, and other documents that are required to be provided or made available to you by ConocoPhillips during the course of your relationship with ConocoPhillips. 1 Dewhurst, Andrew D (OGC) From:Smith, Matt <Matt.Smith2@conocophillips.com> Sent:Thursday, 9 January, 2025 15:38 To:Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S Subject:RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions Hey Andy, I asked around, and we don’t have a gas sample for these wells since they’ve never given us a reason to while drilling. The biogenic comment was based on the low counts and the fact that its consistent throughout the section, and we’re not seeing anything that would indicate a speciƱc hydrate source or anything of that nature. Let me know if you need anything else! Thanks, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Smith, Matt Sent: Thursday, January 9, 2025 1:26 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions Good Morning Andy, Please see attached. There are multiple tabs with each well drilled so far on 3T. So far our gas readings have been from ~35-350 units per our sensor, which is 0.3% to 3.5% gas. The steady low gas response across the surface interval appears to be biogenic gas across the section and not a single point source. We monitor the well on each connection, and perform multiple Ʋow checks throughout the section, and we’ve not observed any breakout/bubbling at surface, which is indicative of hydrates, or had any Ʋow during our Ʋow checks. If you have any further questions please let me know. Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, January 8, 2025 4:06 PM 2 To: Smith, Matt <Matt.Smith2@conocophillips.com > Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions MaƩ, Thank you for the informaƟon. In the KRU 3T-612 daily reports, the max gas was reported to be 168 units. To be Ʃer understand this, would you provide your interpreta Ɵon of the source of the gas along with a log of the total gas for the surface hole? Are there any other observaƟons of gas at a similar depth at the 3T pad? Thanks, Andy From: Smith, Matt <Matt.Smith2@conocophillips.com > Sent: Monday, 6 January, 2025 11:47 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions Good morning Andy, Hope you had a good Christmas and New Year! Please see below response from my geologist, as well as attached documents as requested. If you need anything further please let me know. Thanks, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, December 23, 2024 4:29 PM To: Smith, Matt <Matt.Smith2@conocophillips.com > Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. MaƩ, 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. 3 I am compleƟng my review of the KRU 3T-731 and have a few quesƟons: x What is the anomalous zone prognosed at 3,821’ MD? This is a zone where we map a bright seismic anomaly. We have penetrated to anomaly in the 3T-603 well, where it was mapped at 5863Ō MD, but there was no increase in gas recorded in the well in the vicinity of the mapped bright. x It appears that the X and Y coordinates have been switched on the 10-401 form (box 4b) and in Sec Ɵon 2 (LocaƟon Summary). If this is the case, would you please send corrected PDFs for those two pages? x In support of the diverter variance request, has the KRU 3T-612 TD’d the surface hole yet? If so, would you please send a copy of the daily reports and the total gas log for the surface hole? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Monday, 23 December, 2024 16:29 To:Smith, Matt Cc:Hobbs, Greg S; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Loepp, Victoria T (OGC) Subject:KRU 3T-731 PTD (224-156): Questions MaƩ, I am compleƟng my review of the KRU 3T-731 and have a few quesƟons: x What is the anomalous zone prognosed at 3,821’ MD? x It appears that the X and Y coordinates have been switched on the 10-401 form (box 4b) and in Sec Ɵon 2 (LocaƟon Summary). If this is the case, would you please send corrected PDFs for those two pages? x In support of the diverter variance request, has the KRU 3T-612 TD’d the surface hole yet? If so, would you please send a copy of the daily reports and the total gas log for the surface hole? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 1 Dewhurst, Andrew D (OGC) From:Smith, Matt <Matt.Smith2@conocophillips.com> Sent:Tuesday, 14 January, 2025 12:52 To:Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S; Davies, Stephen F (OGC); Loepp, Victoria T (OGC); Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL]RE: 3T-731 PTD Submission Attachments:3T-731 Updated 10-401_2stage Cement.pdf; 3T-731 -Updated_2 stage Cement.pdf Great, thanks Andy. Please see attached updated 10-401 (added 2 nd stage to cement), as well as a couple other pages updated. If you need anything additional please let me know. Appreciate it, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, January 14, 2025 11:33 AM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL]RE: 3T-731 PTD Submission CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. MaƩ, This would be a revision to the PTD. If the changes only a īect a few pages of the PTD document, you can send the individual updated pages to me and we will splice them into the exi Ɵng applicaƟon. Otherwise, resubmit the enƟre updated PTD package to the permiƫng email address with a comment saying that it supersedes the original submission. Andy From: Smith, Matt <Matt.Smith2@conocophillips.com > Sent: Tuesday, 14 January, 2025 10:45 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com > Subject: 3T-731 PTD Submission 2 All, After further discussions internally surrounding the 3T-731, 2 string well, we’ve decided to pump a 2-stage cement job on our production casing string, and bring cement to surface. With the large volume of cement for the tapered production string and standard excess cement of 40% in the overburden section and 15% in the lateral, there is potential to plug oƯ the surface shoe, if we were to encounter a more in-gauge hole than anticipated. In order to mitigate this potential, we’ve decided to utilize a stage collar to allow us to open the annulus to circulate and analyze any cement returns to determine if this is required in the future, as well as to cement the OA to surface for long term integrity of the well. Please see below schematic. As the permit is not approved yet, do I need to submit a sundry, or a full new permit, for this additional cement? The well path itself has not changed. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.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. 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. KUPARUK RIVER KRU 3T-731 224-156 COYOTE OIL From:Smith, Matt To:Loepp, Victoria T (OGC) Subject:RE: [EXTERNAL]RE: 3T-731 PTD & API Numbers Date:Tuesday, January 21, 2025 2:46:13 PM Attachments:image001.png Hi Victoria, if needed our subsequent tests would be to 4,000psi high/250psi low for rams, and 2500psi high/250psi low for the annular. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Tuesday, January 21, 2025 1:39 PM To: Smith, Matt <Matt.Smith2@conocophillips.com> Subject: [EXTERNAL]RE: 3T-731 PTD & API Numbers CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. What is the subsequent BOP test pressure you plan to test to? Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Loepp, Victoria T (OGC) Sent: Thursday, January 16, 2025 8:05 AM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: 3T-731 PTD & API Numbers Victoria Loepp CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Smith, Matt <Matt.Smith2@conocophillips.com> Sent: Thursday, January 16, 2025 6:06 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: 3T-731 PTD & API Numbers Hi Victoria, I should’ve asked yesterday when we spoke. I know you guys are prioritizing your work, but have you assigned a PTD # and an API number to the 3T-731 yet, that you could share with me? I’m needing to order well house signs, finish my procedure etc, and I’m missing those numbers. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM 1 Dewhurst, Andrew D (OGC) From:Smith, Matt <Matt.Smith2@conocophillips.com> Sent:Tuesday, 14 January, 2025 12:52 To:Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S; Davies, Stephen F (OGC); Loepp, Victoria T (OGC); Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL]RE: 3T-731 PTD Submission Attachments:3T-731 Updated 10-401_2stage Cement.pdf; 3T-731 -Updated_2 stage Cement.pdf Great, thanks Andy. Please see attached updated 10-401 (added 2nd stage to cement), as well as a couple other pages updated. If you need anything additional please let me know. Appreciate it, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, January 14, 2025 11:33 AM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL]RE: 3T-731 PTD Submission CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. MaƩ, This would be a revision to the PTD. If the changes only aīect a few pages of the PTD document, you can send the individual updated pages to me and we will splice them into the exi Ɵng applicaƟon. Otherwise, resubmit the enƟre updated PTD package to the permiƫng email address with a comment saying that it supersedes the original submission. Andy From: Smith, Matt <Matt.Smith2@conocophillips.com > Sent: Tuesday, 14 January, 2025 10:45 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com > Subject: 3T-731 PTD Submission 2 All, After further discussions internally surrounding the 3T-731, 2 string well, we’ve decided to pump a 2-stage cement job on our production casing string, and bring cement to surface. With the large volume of cement for the tapered production string and standard excess cement of 40% in the overburden section and 15% in the lateral, there is potential to plug oƯ the surface shoe, if we were to encounter a more in-gauge hole than anticipated. In order to mitigate this potential, we’ve decided to utilize a stage collar to allow us to open the annulus to circulate and analyze any cement returns to determine if this is required in the future, as well as to cement the OA to surface for long term integrity of the well. Please see below schematic. As the permit is not approved yet, do I need to submit a sundry, or a full new permit, for this additional cement? The well path itself has not changed. Thank you, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.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. 1 Dewhurst, Andrew D (OGC) From:Smith, Matt <Matt.Smith2@conocophillips.com> Sent:Thursday, 9 January, 2025 15:38 To:Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S Subject:RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions Hey Andy, I asked around, and we don’t have a gas sample for these wells since they’ve never given us a reason to while drilling. The biogenic comment was based on the low counts and the fact that its consistent throughout the section, and we’re not seeing anything that would indicate a speciƱc hydrate source or anything of that nature. Let me know if you need anything else! Thanks, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Smith, Matt Sent: Thursday, January 9, 2025 1:26 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions Good Morning Andy, Please see attached. There are multiple tabs with each well drilled so far on 3T. So far our gas readings have been from ~35-350 units per our sensor, which is 0.3% to 3.5% gas. The steady low gas response across the surface interval appears to be biogenic gas across the section and not a single point source. We monitor the well on each connection, and perform multiple Ʋow checks throughout the section, and we’ve not observed any breakout/bubbling at surface, which is indicative of hydrates, or had any Ʋow during our Ʋow checks. If you have any further questions please let me know. Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, January 8, 2025 4:06 PM 2 To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions MaƩ, Thank you for the informaƟon. In the KRU 3T-612 daily reports, the max gas was reported to be 168 units. To be Ʃer understand this, would you provide your interpreta Ɵon of the source of the gas along with a log of the total gas for the surface hole? Are there any other observaƟons of gas at a similar depth at the 3T pad? Thanks, Andy From: Smith, Matt <Matt.Smith2@conocophillips.com > Sent: Monday, 6 January, 2025 11:47 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions Good morning Andy, Hope you had a good Christmas and New Year! Please see below response from my geologist, as well as attached documents as requested. If you need anything further please let me know. Thanks, Matt Smith Drilling Engineer – Kuparuk 700 G ST ANCHORAGE ALASKA, ATO-1566 OFFICE: +1.907.263.4324 CELL: +1.432.269.6432 MATT.SMITH2@COP.COM From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, December 23, 2024 4:29 PM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: [EXTERNAL]KRU 3T-731 PTD (224-156): Questions CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. MaƩ, 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. 3 I am compleƟng my review of the KRU 3T-731 and have a few quesƟons: x What is the anomalous zone prognosed at 3,821’ MD? This is a zone where we map a bright seismic anomaly. We have penetrated to anomaly in the 3T-603 well, where it was mapped at 5863Ō MD, but there was no increase in gas recorded in the well in the vicinity of the mapped bright. x It appears that the X and Y coordinates have been switched on the 10-401 form (box 4b) and in SecƟon 2 (LocaƟon Summary). If this is the case, would you please send corrected PDFs for those two pages? x In support of the diverter variance request, has the KRU 3T-612 TD’d the surface hole yet? If so, would you please send a copy of the daily reports and the total gas log for the surface hole? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Monday, 23 December, 2024 16:29 To:Smith, Matt Cc:Hobbs, Greg S; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Loepp, Victoria T (OGC) Subject:KRU 3T-731 PTD (224-156): Questions MaƩ, I am compleƟng my review of the KRU 3T-731 and have a few quesƟons: x What is the anomalous zone prognosed at 3,821’ MD? x It appears that the X and Y coordinates have been switched on the 10-401 form (box 4b) and in SecƟon 2 (LocaƟon Summary). If this is the case, would you please send corrected PDFs for those two pages? x In support of the diverter variance request, has the KRU 3T-612 TD’d the surface hole yet? If so, would you please send a copy of the daily reports and the total gas log for the surface hole? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3T-731Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241560KUPARUK RIVER, COYOTE OIL - 490120NA1Permit fee attachedYesADL025528 and ADL0255442Lease number appropriateYes3Unique well name and numberYesKUPARUK RIVER, COYOTE OIL - 490120 - governed by CO 8194Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes81' Conductor18Conductor string providedYesSC set at 2600' MD19Surface casing protects all known USDWsYes160% excess cement planned20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgYescemented production liner22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYesDiverter variance granted per 20 AAC 25.035(h)(2)27If diverter required, does it meet regulationsYesMax reservoir pressure is 1874 psig(8.6 ppg EMW); will drill w/ 9.0-10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1374 psig; will test BOPs initially to 5000 psig and subsequently to 4000 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated35Permit can be issued w/o hydrogen sulfide measuresYesCoyote reservoir anticipated to be at 8.6 ppg EMW36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate12/23/2024ApprVTLDate1/22/2025ApprADDDate12/23/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 1/22/2025