The URL can be used to link to this page

Home My WebLink About224-151Alaska 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' 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. DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 We l l N a m e / N o . K U P A R U K R I V U N I T 3 S - 7 1 4 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 2/ 2 4 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 5 1 0 Op e r a t o r C o n o c o P h i l l i p s A l a s k a , I n c . MD 16 3 9 2 TV D 42 0 4 Cu r r e n t S t a t u s WA G I N 11 / 1 7 / 2 0 2 5 UI C Ye s We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : GR , R E S , D E N , D I R , N E U , P O R , S O N I C , C A L I P E R , M U D , U l t r a s o n i c I m a g i n g No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 3/ 3 / 2 0 2 5 28 0 0 6 5 0 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : CP A I _ K u p a r u k _ R i v e r _ 3 S - 7 1 4 _ T O C . l a s 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : CP A I _ 3 S _ 7 1 4 _ R 1 _ 7 . 6 2 5 i n _ C a s i n g _ S o n i c S c o p e 4 75 _ R M _ T O C _ R e p o r t ( 1 ) . p p t x 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C . d l i s 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C . h t m l 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C . p d s 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C _ 1 0 0 0 M D _ R M . p d f 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C _ 2 0 0 0 M D _ R M . p d f 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C _ 2 0 0 M D _ R M . p d f 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C _ 4 0 0 0 M D _ R M . p d f 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C _ 5 0 0 M D _ R M . p d f 40 1 8 0 ED Di g i t a l D a t a DF 3/ 3 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ K u p a r u k _ R i v e r _ 3 S - 71 4 _ T O C _ 6 0 0 0 M D _ R M . p d f 40 1 8 0 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 11 0 1 6 3 9 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ C O M P _ M E M . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 11 0 1 6 3 9 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ C O M P _ M E M _ F u l l h e a d e r . l a s 40 2 3 7 ED Di g i t a l D a t a Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 1 o f 5 Su p p l i e d b y Op Su p p l i e d b y Op CP A I _ 3 S - , 71 4 _ CO MP _ M E M . l a s DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 We l l N a m e / N o . K U P A R U K R I V U N I T 3 S - 7 1 4 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 2/ 2 4 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 5 1 0 Op e r a t o r C o n o c o P h i l l i p s A l a s k a , I n c . MD 16 3 9 2 TV D 42 0 4 Cu r r e n t S t a t u s WA G I N 11 / 1 7 / 2 0 2 5 UI C Ye s DF 3/ 2 6 / 2 0 2 5 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ A P - T I M E _ M E M _ R u n 1 . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ A P - T I M E _ M E M _ R u n 2 . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ A P - T I M E _ M E M _ R u n 3 . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 11 0 1 6 3 9 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ V S S - D E P T H _ M E M . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ V S S - T I M E _ M E M _ R u n 1 . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ V S S - T I M E _ M E M _ R u n 2 . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : C P A I _ 3 S - 71 4 _ V S S - T I M E _ M E M _ R u n 3 . l a s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ A P - TI M E _ M E M _ R u n 1 . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ A P - TI M E _ M E M _ R u n 2 . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ A P - TI M E _ M E M _ R u n 3 . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - DE P T H _ M E M . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - TI M E _ M E M _ R u n 1 . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - TI M E _ M E M _ R u n 2 . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - TI M E _ M E M _ R u n 3 . a s c 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ 9 7 5 i n _ r e a m i n g _ 1 - 20 0 f t . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ 9 7 5 i n _ r e a m i n g _ 1 - 40 f t . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ 9 7 5 i n _ r e a m i n g _ 1 - 20 0 f t . P D F 40 2 3 7 ED Di g i t a l D a t a Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 2 o f 5 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 We l l N a m e / N o . K U P A R U K R I V U N I T 3 S - 7 1 4 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 2/ 2 4 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 5 1 0 Op e r a t o r C o n o c o P h i l l i p s A l a s k a , I n c . MD 16 3 9 2 TV D 42 0 4 Cu r r e n t S t a t u s WA G I N 11 / 1 7 / 2 0 2 5 UI C Ye s DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ 9 7 5 i n _ r e a m i n g _ 1 - 40 f t . P D F 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ I m a g e t r a k - Pr o c e s s e d _ 9 7 5 i n _ 2 7 9 0 - 6 6 0 1 f t _ 1 - 2 0 0 F T . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ I m a g e t r a k - Pr o c e s s e d _ 9 7 5 i n _ 2 7 9 0 - 6 6 0 1 f t _ 1 - 4 0 F T . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ 9 7 5 i n _ 2 7 9 0 - 66 0 1 f t . d l i s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ I m a g e t r a k - Pr o c e s s e d _ 9 7 5 i n _ 2 7 9 0 - 6 6 0 1 f t _ 1 - 2 0 0 F T . P D F 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : Co n o c o P h i l l i p s _ 3 S _ 7 1 4 _ L W D _ I m a g e t r a k - Pr o c e s s e d _ 9 7 5 i n _ 2 7 9 0 - 6 6 0 1 f t _ 1 - 4 0 F T . P D F 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C o n o c o P h i l l i p s _ 3 S - 71 4 _ P R O C E S S E D _ L T K . d l i s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C o n o c o P h i l l i p s _ 3 S - 71 4 _ P R O C E S S E D _ L T K _ I M A G E _ 1 _ 2 4 0 _ R U N 2 . c gm 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C o n o c o P h i l l i p s _ 3 S - 71 4 _ P R O C E S S E D _ L T K _ I M A G E _ 1 _ 2 4 0 _ R U N 2 . p df 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C o n o c o P h i l l i p s _ 3 S - 71 4 _ P R O C E S S E D _ L T K _ I M A G E _ 1 _ 2 4 0 _ R U N 3 . c gm 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C o n o c o P h i l l i p s _ 3 S - 71 4 _ P R O C E S S E D _ L T K _ I M A G E _ 1 _ 2 4 0 _ R U N 3 . d li s 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C o n o c o P h i l l i p s _ 3 S - 71 4 _ P R O C E S S E D _ L T K _ I M A G E _ 1 _ 2 4 0 _ R U N 3 . p df 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 2 M D _ C O M P _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 2 T V D _ C O M P _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 3 o f 5 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 We l l N a m e / N o . K U P A R U K R I V U N I T 3 S - 7 1 4 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 2/ 2 4 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 5 1 0 Op e r a t o r C o n o c o P h i l l i p s A l a s k a , I n c . MD 16 3 9 2 TV D 42 0 4 Cu r r e n t S t a t u s WA G I N 11 / 1 7 / 2 0 2 5 UI C Ye s DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 5 M D _ C O M P _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 5 T V D _ C O M P _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ A P - TI M E _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - DE P T H _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - TI M E _ M E M . c g m 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 2 M D _ C O M P _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 2 T V D _ C O M P _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 5 M D _ C O M P _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 71 4 _ 5 T V D _ C O M P _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ A P - TI M E _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - DE P T H _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : C P A I _ 3 S - 7 1 4 _ V S S - TI M E _ M E M . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : 3 S - 7 1 4 D e f i n i t i v e S u r v e y s NA D 2 7 . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : 3 S - 7 1 4 D e f i n i t i v e S u r v e y s NA D 2 7 . t x t 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : 3 S - 7 1 4 D e f i n i t i v e S u r v e y s NA D 8 3 . p d f 40 2 3 7 ED Di g i t a l D a t a DF 3/ 2 6 / 2 0 2 5 E l e c t r o n i c F i l e : 3 S - 7 1 4 D e f i n i t i v e S u r v e y s NA D 8 3 . t x t 40 2 3 7 ED Di g i t a l D a t a DF 10 / 1 3 / 2 0 2 5 66 5 0 1 6 3 9 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 00 _ 3 S - 7 1 4 _ F i n a l M u d l o g L A S _ 1 6 3 9 2 _ f t _ M D . l a s 40 9 8 9 ED Di g i t a l D a t a DF 10 / 1 3 / 2 0 2 5 66 5 0 1 6 3 9 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 00 _ 3 S - 7 1 4 _ G a s F a c t F i n a l L A S _ 1 6 3 9 2 _ f t . l a s 40 9 8 9 ED Di g i t a l D a t a Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 4 o f 5 50 - 1 0 3 - 2 0 9 0 3 - 0 0 - , 00_ 3 S-7 1 4 _ F i n a l M u d l o g L A S_1 6 3 9 2 _ ft_ M D . l a s DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 We l l N a m e / N o . K U P A R U K R I V U N I T 3 S - 7 1 4 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 2/ 2 4 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 5 1 0 Op e r a t o r C o n o c o P h i l l i p s A l a s k a , I n c . MD 16 3 9 2 TV D 42 0 4 Cu r r e n t S t a t u s WA G I N 11 / 1 7 / 2 0 2 5 UI C Ye s We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 2/ 2 4 / 2 0 2 5 Re l e a s e D a t e : 1/ 9 / 2 0 2 5 DF 10 / 1 3 / 2 0 2 5 E l e c t r o n i c F i l e : 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 _ 3 S - 71 4 _ L i t h o l o g y D o w n l o a d _ 1 6 3 9 2 _ f t . t x t 40 9 8 9 ED Di g i t a l D a t a DF 10 / 2 7 / 2 0 2 5 E l e c t r o n i c F i l e : 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 _ 3 S - 71 4 _ F o r m a t i o n Ev a l u a t i o n _ 1 6 3 9 2 _ f t _ M D _ 2 i n c h . p d f 40 9 8 9 ED Di g i t a l D a t a DF 10 / 2 7 / 2 0 2 5 E l e c t r o n i c F i l e : 5 0 - 1 0 3 - 2 0 9 0 3 - 0 0 - 0 0 _ 3 S - 71 4 _ F o r m a t i o n Ev a l u a t i o n _ 1 6 3 9 2 _ f t _ M D _ 5 i n c h . p d f 40 9 8 9 ED Di g i t a l D a t a 2/ 2 7 / 2 0 2 5 66 0 0 1 6 3 9 2 41 9 2 4 Cu t t i n g s Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 5 o f 5 11 / 2 5 / 2 0 2 5 M. G u h l MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 3S-714 KUPARUK RIV UNIT 3S-714 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/22/2025 3S-714 50-103-20903-00-00 224-151-0 W SPT 4098 2241510 1500 0 0 0 0 570 615 617 609 INITAL P Kam StJohn 9/20/2025 Initial MIT-IA for new injector. This well is on a vac injecting +- 2000 bbls a day Temp and IA pressures have been stable 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 3S-714 Inspection Date: Tubing OA Packer Depth 900 1800 1770 1770IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS250920193356 BBL Pumped:0.8 BBL Returned:0.8 Wednesday, October 22, 2025 Page 1 of 1             T40989 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 L 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-714 224-151 DATE:10/13/2025 Transmitted: 3S-714 Via SFTP Transmittal instructions: please promptly sign, scan, and e-mail to CC: 3S-714- e-transmittal well folder Receipt: Date: || CDW 07/31/2025 Corrected chemical disclosure showing ResMetrics tracers included to www.fracfocus.org 7/31/2025. CDW Corrected chemical disclosure showing ResMetrics tracers included to www.fracfocus.org 7/31/2025. CDW 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address:7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:2571' FNL, 4008' FEL S18 T12N R8E, UM 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 24.0 BF: Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI:x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth:x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: 23. BOTTOM 20"X65 120' 10 3/4"L-80 2520' 7-5/8"L-80 4139' 4 1/2"P110S 4204' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD)AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: N/A - Injection Well Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate Flow Tubing SIZE DEPTH SET (MD) 10 Yards Sr Res EngSr Pet GeoSr Pet Eng 6-1/2" 6475'4.5" N/A Oil-Bbl:Water-Bbl: Water-Bbl: PRODUCTION TEST Date of Test:Oil-Bbl: 6332'MD/4066'TVD 6453'MD/4098'TVD BOTTOM 13.5"Lead: 473bbls 11ppg class G Tail: 60bbls 15.8ppg class G CASING 1665'MD/1639'TVD SETTING DEPTH TVD 473252 474539 CEMENTING RECORD 5993854 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): Liner: (2/20/2025) 6453'-16387'MD/4098'-4204'TVD Gas-Oil Ratio:Choke Size: suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A 41' 40' Per 20 AAC 25.283 (i)(2) attach electronic information 6639'40' 78.67 45.5 120' TOP SETTING DEPTH MD PACKER SET (MD/TVD) 6453' 42" 12.6 41' 29.7 40' 40' 2803' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): WT. PER FT.GRADE GR, RES, DEN, DIR, NEU, POR, SONIC, CALIPER, MUD, Ultrasonic Imaging STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 2/24/2025 224-151 50-103-20903-00-00 KRU 3S-714 1/28/2025 16392'MD/4204'TVD N/A 63.2 P.O.Box 100360, Anchorage, AK 99510-0360 476193 2763' FSL, 33740' FWL S18 T12N R8E, UM 1876' FNL, 2726' FEL S30 T12N R8E, UM 2/16/2025 5993899 Kuparuk River Field/ Coyote Oil Pool ADL380107, ADL0392374 LONS 01-013 5983986 TOP HOLE SIZE AMOUNT PULLED ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 57 bbls of 15.3ppg class G9-7/8" TUBING RECORD 277bbls of 15.3ppg class G16387'4098' W d 1b 0 D p op and B om; Perf L s ((atta Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment Complete 2/24/2025 JSB RBDMS JSB 040125 G Received 3/21/2025 DSR-4/7/25VTL 7/30/2025 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface 1421 1408 1644 1619 1665 1639 1808 1768 2108 2024 Base West Sak 2693 2452 C-80 3059 2666 C-50 4823 3417 C-35 5771 3870 6431 4093 16392 4204 31. List of Attachments: Directional Survey, Well Schematic, Cement Operations, Operations Summary 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Abby Warren Digital Signature with Date: Contact Phone:907-240-9293 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31:Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Ugnu A Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and INSTRUCTIONS Contact Emai:abby.warren@conocophillips.com Authorized Title: Drilling Engineer West Sak If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Attached Seperately Formation Name at TD: Nanushuk Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Ugnu C 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS Top of Productive Interval: Nanushuk Permafrost - Base Ugnu B N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov In t e r m e d i a t e I C a s i n g 7- 5 / 8 " 2 9 . 7 # L 8 0 H 5 6 3 + 6 2 9 ' 33 . 7 # P 1 1 0 S H 5 6 3 H e a v y H e e l 66 3 9 ' M D / 4 1 3 9 ' T V D Ba s e P e r m 16 4 4 ' M D / 16 2 0 ' T V D In t e r m e d i a t e I T O C 55 3 0 ' M D / 3 7 6 5 ' T V D Su r f a c e C a s i n g 10 - 3 / 4 " 4 5 . 5 # L 8 0 H 5 6 3 28 0 3 ' M D / 2 5 2 0 ' T V D Ce m e n t e d t o S u r f a c e Le a d : 1 1 . 0 p p g D e e p C R E T E | Ta i l : 1 5 . 8 p p g C l a s s G 20 " 9 4 # H 4 0 I n s u l a t e d C o n d u c t o r 12 0 ' M D / T V D - Ce m e n t e d t o S u r f a c e Pr o d u c t i o n T O L Pr o d u c t i o n L i n e r T o p P K R Pr o d u c t i o n L i n e r 4- 1 / 2 " 1 2 . 6 # P 1 1 0 - S H 5 6 3 16 3 8 7 ' M D / 4 2 0 4 ' T V D 3S - 7 1 4 F I N A L To p C o y o t e 64 2 6 ' M D / 4 0 9 1 ' T V D Up p e r C o m p l e t i o n : 1. 2 e a . G a s L i f t M a n d r e l s 2. H E S O p s i s S i n g l e D o w n h o l e G a u g e 3. H E S 7 - 5 / 8 " x 4 - 1 / 2 " T N T P a c k e r 4. A r s e n a l 5 , 5 0 0 p s i G l a s s D i s k S u b 5. S L B 3 . 7 5 " D B N i p p l e P r o f i l e 6. H E S S e l f - A l i g n i n g M u l e s h o e w i t h B a k e r S h e a r L o c a t o r Lo w e r C o m p l e t i o n : 1. B a k e r F l e x l o c k L i n e r H a n g e r / Z X P P a c k e r 2. A U F r a c S l e e v e s 4. C i t a d e l M O A S S h o e 64 5 3 ' M D / 4 0 9 8 ' T V D Page 1/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 1/25/2025 21:00 1/26/2025 00:00 3.00 MIRU, MOVE MOB P Stomp out motor, pump and pits. Put all on suspension. Raise C section and lower cattle shute. Skid rig floor and lower derrick. Pull pits off rig mats. 0.0 0.0 1/26/2025 00:00 1/26/2025 02:30 2.50 MIRU, MOVE MOB P Raise cellar walls, Unpin pipe shed and stomp out from sub. 0.0 0.0 1/26/2025 02:30 1/26/2025 05:00 2.50 MIRU, MOVE MOB P Continue stomp pipe shed 50' turn and place on suspention. Pull pipe shed off mats 0.0 0.0 1/26/2025 05:00 1/26/2025 06:00 1.00 MIRU, MOVE MOB P Stomp sub off well center at 0500hrs. 0.0 0.0 1/26/2025 06:00 1/26/2025 14:00 8.00 MIRU, MOVE MOB P Install Jeep onto sub, Move sub off mats. Spot mats on 3S-714 well, Spot sub on 3S-714 well at 13:30 hrs. 0.0 0.0 1/26/2025 14:00 1/26/2025 18:00 4.00 MIRU, MOVE MOB P Move pipe shed with trucks close to Stomping position. Stomp pipe shed and shim and pin to sub. 0.0 0.0 1/26/2025 18:00 1/26/2025 19:30 1.50 MIRU, MOVE MOB P Raise and secure derrick. Set pits and pump modules. 0.0 0.0 1/26/2025 19:30 1/26/2025 22:00 2.50 MIRU, MOVE MOB P Skid rig floor to drilling position, Crane in MPD choke skid and control panel. 0.0 0.0 1/26/2025 22:00 1/27/2025 00:00 2.00 MIRU, MOVE MOB P Lower C section, Raise cattle shute, (change HP hose in pump room) Set mats and move casing shed into postion. 0.0 0.0 1/27/2025 00:00 1/27/2025 02:30 2.50 MIRU, MOVE MOB P Set motor module in place, Lower cellar walls, Stomp in casing module. 0.0 0.0 1/27/2025 02:30 1/27/2025 10:00 7.50 MIRU, MOVE MOB P Hooking up interconnections. Prep to scope up derrick. Run steam to rig floor, Work on rig acceptance checklist. 0.0 0.0 1/27/2025 10:00 1/27/2025 11:00 1.00 MIRU, MOVE MOB P Swap rig to highline power at 09:40 hrs. Scope up derrick. Rig accepted at 11:00 hrs 1-27-25 0.0 0.0 1/27/2025 11:00 1/27/2025 19:00 8.00 MIRU, MOVE RURD P Install surface riser and 4" conductor valves. M/U bell nipple flange, M/U Joes box and insulate. Install 90' mouse hole, N/U jet and fill up lines, Install trip nipple. SIMOPS: P/U BHA tools, Derrick inspection, Stock pits with chemicals, Take on mud to pits. 0.0 0.0 1/27/2025 19:00 1/27/2025 21:00 2.00 MIRU, MOVE BHAH P P/U and rack back 5" HWT drill pipe and jars. 0.0 0.0 1/27/2025 21:00 1/27/2025 22:30 1.50 MIRU, MOVE BHAH P P/U BHA #1, 13.5" Clean out assy. Tagged at 43' MD 13.5" Kymera Bit 8" Ultra XL-HP motor (1.5°) 12-1/8" Stabilizer Filter sub X/O 5" HWT DP 0.0 43.0 1/27/2025 22:30 1/28/2025 00:00 1.50 MIRU, MOVE REAM P Break circulation, Pressure test surface system to 3500psi (good test) Wash and ream 20" conductor from 43' MD to 132' MD. GPM: 450 PSI: 580 Off PSI: 630 On RPM: 30 TRQ: 2-4k ROT: 56k 43.0 132.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 2/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 1/28/2025 00:00 1/28/2025 00:30 0.50 MIRU, MOVE DDRL P Drill 13.5” hole f/ 132’ to 200’ MD/TVD WOB: 2k GPM: 450 PSI: 600 RPM: 30 TQ: 2k PU: 54k SO: 59k ROT: 60k AST: 0.0 hrs ART: 0.5 hrs Bit hrs: 1.2 hrs 132.0 200.0 1/28/2025 00:30 1/28/2025 01:30 1.00 SURFAC, DRILL BKRM P BROOH from 200' MD to 45' MD. GPM: 450 PSI: 600 RPM: 30 TQ: 1-2k 200.0 0.0 1/28/2025 01:30 1/28/2025 04:00 2.50 SURFAC, DRILL BHAH P Continue P/U 13.5" BHA #1. Continue wash in hole to 200' MD . Take Gyro survey at 20" conductor at 132' MD. 0.0 137.0 1/28/2025 04:00 1/28/2025 06:00 2.00 SURFAC, DRILL DDRL P Drill 13.5” hole from 200’ to 341’ MD/TVD WOB: 2k GPM: 600 PSI: 600 RPM: 40 TQ: 2k PU: 72k SO: 77k ROT: 76k AST: 0.5 hrs ART: 1.8 hrs Bit hrs: 2.5 hrs 200.0 341.0 1/28/2025 06:00 1/28/2025 12:00 6.00 SURFAC, DRILL DDRL P Drill 13.5” hole from 341’ to 778’ MD 777' TVD WOB: 2k GPM: 600 PSI: 600 RPM: 40 TQ: 2k PU: 72k SO: 77k ROT: 76k AST: 0.5 hrs ART: 2.5 hrs Bit hrs: 5.5 hrs Jar: 0.7 hrs 341.0 778.0 1/28/2025 12:00 1/28/2025 18:00 6.00 SURFAC, DRILL DDRL P Drill 13.5” hole from 341’ MD to 778’ MD 777' TVD WOB: 15k GPM: 600 PSI: 1497 RPM: 40 TQ: 2k ROT: 86k ECD: 9.9 ppg AST: 0.7 hrs ART: 3.2 hrs Bit hrs: 9.4 hrs Jar: 4.6 hrs 778.0 1,255.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 3/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 1/28/2025 18:00 1/29/2025 00:00 6.00 SURFAC, DRILL DDRL P Drill 13.5” hole from 778’ MD to 2000’ MD 1,937' TVD WOB: 5k GPM: 700 PSI: 2180 RPM: 40 TQ: 5k ROT: 122k ECD: 10.1 ppg AST: 2.2 hrs ART: 1.7 hrs Bit hrs: 13.3 hrs Jar: 8.5 hrs 1,255.0 2,000.0 1/29/2025 00:00 1/29/2025 10:00 10.00 SURFAC, DRILL DDRL P Drill 13.5” hole from 2000’ MD to 2808’ MD 2522' TVD. Section TD 2808' MD/ 2522' TVD WOB: 5k GPM: 700 PSI: 2176 RPM: 60 TQ: 6k ROT: 118k ECD: 10.3 ppg AST: 3.5 hrs ART: 2.7 hrs Bit hrs: 19.5 hrs Jar: 14.7 hrs 2,000.0 2,808.0 1/29/2025 10:00 1/29/2025 11:30 1.50 SURFAC, TRIPCAS CIRC P Circulate BU while BROOH 1 std. 700 GPM 2205 PSI 60 RPM 4-6k TQ 10.3ppg ECD 2,808.0 2,750.0 1/29/2025 11:30 1/29/2025 12:00 0.50 SURFAC, TRIPCAS OWFF P Flow check. Static loss rate of 12 BPH 2,750.0 2,750.0 1/29/2025 12:00 1/29/2025 14:00 2.00 SURFAC, TRIPCAS OWFF T Low volume of mud in pits. Take on mud from ball mill. 2,750.0 2,750.0 1/29/2025 14:00 1/29/2025 18:00 4.00 SURFAC, TRIPCAS BKRM P BROOH f/ 2750' to 1908'. 700 GPM 2076 PSI 60 RPM 5k TQ 2,750.0 1,908.0 1/29/2025 18:00 1/29/2025 19:00 1.00 SURFAC, TRIPCAS CIRC P Pump sweep and circulate hole clean. 700 GPM 2075 PSI 1,908.0 1,813.0 1/29/2025 19:00 1/29/2025 19:30 0.50 SURFAC, TRIPCAS OWFF P Flow check and blow down TD. Static loss rate of 12 BPH. 1,813.0 1,813.0 1/29/2025 19:30 1/29/2025 20:00 0.50 SURFAC, TRIPCAS TRIP P Attempt to POOH on elevators. Observed 40k OP at 1730'. Drop back down to 1813'. 1,813.0 1,813.0 1/29/2025 20:00 1/29/2025 22:00 2.00 SURFAC, TRIPCAS PMPO P Pump OOH f/ 1813' to BHA. 400 GPM 785 PSI. 1,813.0 780.0 1/29/2025 22:00 1/30/2025 00:00 2.00 SURFAC, TRIPCAS BHAH P Flow check and rack back HWDP 780.0 230.0 1/30/2025 00:00 1/30/2025 04:00 4.00 SURFAC, TRIPCAS BHAH P Finish Pumping OOH racking back HWDP. LD BHA to surface. 230.0 0.0 1/30/2025 04:00 1/30/2025 04:30 0.50 SURFAC, CASING CLEN P Clean and clear rig floor. Stage casing equipment. 0.0 0.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 4/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 1/30/2025 04:30 1/30/2025 05:30 1.00 SURFAC, CASING RURD P RU casing running equipment. 0.0 0.0 1/30/2025 05:30 1/30/2025 06:30 1.00 SURFAC, CASING PUTB P MU 10 3/4" 45.5# L-80 H563 shoe track and RIH. Threadlock each joint. 0.0 171.0 1/30/2025 06:30 1/30/2025 12:00 5.50 SURFAC, CASING PUTB P RIH w/ 10 3/4" 45.50# L-80 H563 casing to 1980'. 16.2k MU TQ 171.0 1,980.0 1/30/2025 12:00 1/30/2025 12:30 0.50 SURFAC, CASING CIRC P Circulate BU at 1980'. Stage rate up to 8 BPM. 8 BPM 211PSi 1,980.0 1,980.0 1/30/2025 12:30 1/30/2025 16:00 3.50 SURFAC, CASING PUTB P RIH w/ 10 3/4" 45.50# L-80 H563 casing f/ 1980' to 2761'. 16.2k MU TQ 1,980.0 2,761.0 1/30/2025 16:00 1/30/2025 17:00 1.00 SURFAC, CASING PUTB P MU hanger and landing joint. Attempt to Land hanger. Unsuccessful. Tagging up at 2800'. Attempt to wash/rotate down with no success. 8 BPM 265 PSI 5 RPM 10k TQ 2,761.0 2,800.0 1/30/2025 17:00 1/30/2025 21:00 4.00 SURFAC, CASING PUTB T Decison made to space out with pup joints. LD landing joint/hanger joint. LD joint # 64. MU spaceout pups Hanger joint and landing joint. Attempt to wash down. Tag 1ft from landing out at 2796'. Work string and attempt to land hanger. 1-2 inches from landing out. 2,796.0 2,796.0 1/30/2025 21:00 1/30/2025 23:00 2.00 SURFAC, CASING PUTB T Blow down TD. Drain stack to check if landed. Discovered landing ring had shifted. Discuss with office and decision made to use emergency slips. 2,796.0 2,796.0 1/30/2025 23:00 1/31/2025 00:00 1.00 SURFAC, CASING PUTB T LD landing joint and hanger joint. MU and RIH with joints #64 and #66 + 15' pup joint. Tagged at 2800'. Attempt to wash down with no success. Decision made to cement at 2800'. Note: coupling 5.5' below landing ring. 2,800.0 2,800.0 1/31/2025 00:00 1/31/2025 02:00 2.00 SURFAC, CEMENT CIRC P Stage up pumps to 8 BPM. Circulate and condition mud for cement job. 8 BPM 200 PSI 2,800.0 2,800.0 1/31/2025 02:00 1/31/2025 03:00 1.00 SURFAC, CEMENT RURD P Blow down TD. RU cement lines. 2,800.0 2,800.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 5/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 1/31/2025 03:00 1/31/2025 07:00 4.00 SURFAC, CEMENT CMNT P Test lines to 3500 PSI. Pump 100 BBLS 10.5 PPG MudPush @ 5.5 BPM/200 PSI. Drop bottom plug. Pump 473 BBLS 11.0 PPG lead cement (Cement wet @ 03:30hrs). MudPush observed at surface at 340 BBLS cement pumped. Pump 60 BBLS 15.8 PPG tail cement (Cement wet @ 05:07hrs). FCP - 282 PSI @ 5 BPM. SD. Drop top plug. Pump 20 BBLS FW with cement unit. Swap to rig pumps. Displace with 9.5 PPG spud mud. Bump plug with calculated strokes. 244 BBLS / 2423 strokes, FCP - 905 PSI @ 3 BPM. Pressure up to 1500 PSI. Hold for 5 minutes. Check floats. Good. Cement in place at 07:00hrs on 1/31/24. Note: Cement to Surface - 110 BBLS. Lost returns at 1400 strokes into displacement. Worked string and rotate with no improvement. Cement was still at surface when ND risers. 2,800.0 2,800.0 1/31/2025 07:00 1/31/2025 10:00 3.00 SURFAC, WHDBOP CLEN P Blow down lines. Flush all surface equipment w/ black water. Clean joes box,valves and cuttings pit. 0.0 0.0 1/31/2025 10:00 1/31/2025 14:30 4.50 SURFAC, WHDBOP NUND T ND lower riser and prep for casing cut. Make cut on 10 3/4" casing. SimOps: RD casing equipment. LD mousehole. Clean out manifolds on MP#1 and #2. 0.0 0.0 1/31/2025 14:30 1/31/2025 17:00 2.50 SURFAC, WHDBOP NUND T LD cut jt. (34.48'). ND risers and remove starting head. 0.0 0.0 1/31/2025 17:00 1/31/2025 19:30 2.50 SURFAC, WHDBOP NUND T Cut conductor. Dress off conductor stump. SimOps: LD casing equiment. Stage wellhead and emergency slips. 0.0 0.0 1/31/2025 19:30 1/31/2025 21:30 2.00 SURFAC, WHDBOP NUND T Install faceplate and slips per StreamFlo. Cut and dress off surface casing stump.(1.8' cut). SimOps: Stage wellhead in BOP deck. Prep adaptor flange. 0.0 0.0 1/31/2025 21:30 1/31/2025 23:00 1.50 SURFAC, WHDBOP NUND P Install wellhead and test to 2000 PSI. Pad operator approved orientation. 0.0 0.0 1/31/2025 23:00 2/1/2025 00:00 1.00 SURFAC, WHDBOP NUND P Install adapter flange. 0.0 0.0 2/1/2025 00:00 2/1/2025 03:30 3.50 SURFAC, WHDBOP NUND P NU high pressure riser,BOP, choke and kill lines. 0.0 0.0 2/1/2025 03:30 2/1/2025 08:00 4.50 SURFAC, WHDBOP NUND P Torque down riser and BOPE bolts. MU flow line and jet lines. Install mousehole. Seal up Joes box. RU MPD lines. MU orbit valve. 0.0 0.0 2/1/2025 08:00 2/1/2025 09:00 1.00 SURFAC, WHDBOP RURD P Set test plug. MU MPD test cap. flood lines. 0.0 0.0 2/1/2025 09:00 2/1/2025 10:00 1.00 SURFAC, WHDBOP MPDA P Test MPD equipment 250 psi low/ 1500 psi high. 0.0 0.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 6/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/1/2025 10:00 2/1/2025 18:00 8.00 SURFAC, WHDBOP BOPE P Test BOPE: 7-5/8" test joint- Annular 250/3500 PSI for 5min each. UPRs 7- 5/8" casing ram / 4" kill line / HCR Kill and Choke / Manual Choke and Kill / 5" FOSVs #1 and #2 / Dart valve to 250/5000 PSI for 5 min each. Blind/Shear rams- 250/5000 PSI for 5 min each 5" test joint- Annular 250/3500 PSI for 5 min each. LPRs 2-7/8" x 5" VBRs 250/5000 PSI for 5 min each. Accumulator drawdown- ACC = 3000 PSI. Manifold = 1500 PSI. 1925 PSI post function. 200 PSI increase = 13 sec. Full system recovery = 65 sec. Nitrogen 6 bottles average = 1941 PSI. Closing times - Annular= 10 sec.UPRs = 6 sec. LPRs = 5 sec. Blind/Shears = 5 sec. Choke HCR = 2 sec. Kill HCR = 2 sec. Test PVT Gain/Loss and flow out alarms. Test LEL and H2S alarms. Witnessed waived by AOGCC Cam St John 0.0 0.0 2/1/2025 18:00 2/1/2025 18:45 0.75 SURFAC, DRILLOUT RURD P Retrieve test plug. Install 10.0" ID wear bushing. 0.0 0.0 2/1/2025 18:45 2/1/2025 19:45 1.00 SURFAC, DRILLOUT CLEN P Clean and clear rig floor. BD choke and kill lines. PJSM on BHA. Stage BHA 0.0 0.0 2/1/2025 19:45 2/1/2025 22:00 2.25 SURFAC, DRILLOUT BHAH P MU and RIH w/ BHA #2 to 716'. 0.0 716.0 2/1/2025 22:00 2/1/2025 23:30 1.50 SURFAC, DRILLOUT TRIP P RIIH w/ BHA on 5" DP to 2500'. 716.0 2,500.0 2/1/2025 23:30 2/2/2025 00:00 0.50 SURFAC, DRILLOUT CIRC P Break circulation and wash down to 2594 while performing shallow test on MWD. Good test. 2,500.0 2,594.0 2/2/2025 00:00 2/2/2025 01:30 1.50 SURFAC, DRILLOUT PRTS P RU test equipment. Test casing to 3500 PSI f/ 30 minutes. Good test. 7 BBLs pumped/returned. RD test equipment. 2,594.0 2,594.0 2/2/2025 01:30 2/2/2025 02:00 0.50 SURFAC, DRILLOUT WASH P Wash down and tag plugs at 2710'. 2,594.0 2,710.0 2/2/2025 02:00 2/2/2025 06:30 4.50 SURFAC, DRILLOUT DRLG P Drill out plugs/FC/shoetrack/FS to 2800'. DRill new formation to 2828' MD. 630 GPM 1140 PSI 2-16k WOB 60-80 RPM 4-10k TQ 124k ROT 2,710.0 2,828.0 2/2/2025 06:30 2/2/2025 07:30 1.00 SURFAC, DRILLOUT FIT P Backream back into shoe. RU test equipment. Perform LOT to 16.2ppg EMW. RD test equipment. 2,828.0 2,828.0 2/2/2025 07:30 2/2/2025 08:30 1.00 INTRM1, DRILL DISP P RIH to 2806'. Pump HiVis spacer and displace hole to 9.5ppg NAF OBM. 2,828.0 2,828.0 2/2/2025 08:30 2/2/2025 10:30 2.00 INTRM1, DRILL CLEN P Blow down TD. Clean surface equipment. PU MPD equipment. 2,828.0 2,828.0 2/2/2025 10:30 2/2/2025 13:30 3.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 2828' MD to 2973' MD /2620' TVD. 650 GPM 1180 PSI 3k WOB 80 RPM 4k TQ 9.9ppg ECD 124k ROT 2.4 Bit hrs 17.1 Jar hrs 2,828.0 2,973.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 7/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/2/2025 13:30 2/2/2025 14:00 0.50 INTRM1, DRILL CIRC P Circulate BU. 675 GPM 1300 PSI 80 RPM 3k TQ 2,973.0 2,973.0 2/2/2025 14:00 2/2/2025 15:00 1.00 INTRM1, DRILL MPDA P Retrieve trip nipple and install MPD bearing assembly. 2,973.0 2,973.0 2/2/2025 15:00 2/2/2025 18:00 3.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 2973' MD to 3133' MD /2707' TVD. Holding 125 PSI w/ MPD on connections 650 GPM 1365 PSI 8k WOB 150 RPM 5k TQ 10.2ppg ECD 128k PU 118k SO 120k ROT 4.3 Bit hrs 19 Jar hrs 2,973.0 3,133.0 2/2/2025 18:00 2/3/2025 00:00 6.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 3133' MD to 3502' MD /2842' TVD. Holding 125 PSI w/ MPD on connections. 640 GPM 1765 PSI 7k WOB 120 RPM 6k TQ 10.3ppg ECD 138k PU 108k SO 120k ROT 9.2 Bit hrs 23.9 Jar hrs 3,133.0 3,502.0 2/3/2025 00:00 2/3/2025 06:00 6.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 3502' MD to 4009' MD /3025' TVD. Holding 150 PSI w/ MPD on connections. 700 GPM 2075 PSI 7k WOB 140 RPM 6k TQ 10.5ppg ECD 138k PU 105k SO 122k ROT 18.4 Bit hrs 33.1 Jar hrs 3,502.0 4,009.0 2/3/2025 06:00 2/3/2025 12:00 6.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 4009' MD to 4621' MD /3314' TVD. Holding 150 PSI w/ MPD on connections. 700 GPM 2200 PSI 7k WOB 140 RPM 6k TQ 10.7ppg ECD 147k PU 102k SO 125k ROT 18.4 Bit hrs 33.1 Jar hrs 4,009.0 4,621.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 8/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/3/2025 12:00 2/3/2025 21:30 9.50 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 4621' MD to 5307' MD / 3531' TVD. Holding 11.3 ppg w/ MPD. 700 GPM 2365 PSI 6k WOB 140 RPM 6k TQ 11.3ppg ECD 160k PU 108k SO 132k ROT 23.3 Bit hrs 38 Jar hrs 4,621.0 5,307.0 2/3/2025 21:30 2/3/2025 22:00 0.50 INTRM1, DRILL SVRG P Service Top Drive. 5,307.0 5,307.0 2/3/2025 22:00 2/4/2025 00:00 2.00 INTRM1, DRILL RGRP T Troubleshoot Top Drive. Faults out and loses rotation. Having to SD and reset. 5,307.0 5,307.0 2/4/2025 00:00 2/4/2025 02:00 2.00 INTRM1, DRILL RGRP T Troubleshoot Top Drive. Replace Inverter. 5,307.0 5,307.0 2/4/2025 02:00 2/4/2025 02:30 0.50 INTRM1, DRILL SVRG P Service top drive. 5,307.0 5,307.0 2/4/2025 02:30 2/4/2025 06:00 3.50 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 5307' MD to 5519' MD / 3760' TVD. Holding 11.3 ppg w/ MPD. 700 GPM 2410 PSI 6k WOB 140 RPM 7k TQ 11.3ppg ECD 157k PU 112k SO 129k ROT 29.1 Bit hrs 43.8 Jar hrs 5,307.0 5,519.0 2/4/2025 06:00 2/4/2025 12:00 6.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 5,519' MD to 5,889' MD / 3918' TVD. Holding 11.3 ppg w/ MPD. 700 GPM 2480 PSI 7k WOB 140 RPM 3-6k TQ 11.3ppg ECD 175k PU 110k SO 141k ROT 34.1 Bit hrs 48.8 Jar hrs 5,519.0 5,889.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 9/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/4/2025 12:00 2/4/2025 17:00 5.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 5,889' MD to 6,178' MD / 4020' TVD. Holding 11.3 ppg w/ MPD. 700 GPM 2560 PSI 7k WOB 140 RPM 3-6k TQ 11.3ppg ECD 175k PU 110k SO 141k ROT 38.1 Bit hrs 52.8 Jar hrs 5,889.0 6,178.0 2/4/2025 17:00 2/4/2025 18:15 1.25 INTRM1, DRILL CIRC T Circulate bottom up, while BROOH from 6,178' to 6,087' MD with 700 GPM 2552 PSI 100 RPM 5k TQ 11.3ppg ECD 45% FO 140k ROT 6,178.0 6,087.0 2/4/2025 18:15 2/4/2025 19:00 0.75 INTRM1, DRILL RURD T Change out MPD bearing do to leak at seal. 6,087.0 6,087.0 2/4/2025 19:00 2/4/2025 19:30 0.50 INTRM1, DRILL WASH P Wash down from 6,087' to 6,178' MD with following paramters, while down linking: 700 GPM 2540 PSI 100 RPM 6k TQ 6,087.0 6,178.0 2/4/2025 19:30 2/5/2025 00:00 4.50 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 6,178' MD to 6,554' MD / 4121' TVD. 700 GPM 2620 PSI 11k WOB 140 RPM 5-6k TQ 11.3ppg ECD 178k PU 108k SO 136k ROT 42.1 Bit hrs 56.8 Jar hrs 6,178.0 6,554.0 2/5/2025 00:00 2/5/2025 02:00 2.00 INTRM1, DRILL DDRL P Drill 9 7/8" Intermediate section f/ 6554' MD to 6650' MD / 4141' TVD. 700 GPM 2660 PSI 1k WOB 140 RPM 5-6k TQ 11.3ppg ECD 172k PU 112k SO 139k ROT 43.1 Bit hrs 57.8 Jar hrs 6,554.0 6,650.0 2/5/2025 02:00 2/5/2025 02:30 0.50 INTRM1, TRIPCAS SVRG P Service rig 6,650.0 6,650.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 10/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/5/2025 02:30 2/5/2025 04:30 2.00 INTRM1, TRIPCAS RGRP T Discovered flange leaking on pop-off at MP #1. Repair flange. Circulate with MP # 2 while repairing. Holding 11.3ppg EMW with MPD. 340 GPM 960 PSI 130 RPM 5k TQ 6,650.0 6,650.0 2/5/2025 04:30 2/5/2025 05:30 1.00 INTRM1, TRIPCAS CIRC P Circulate rotate and reciprocating from 6,650' to 6,590' MD with following parameters: 700 GPM 2720 psi 46% FO 130 RPM 5 - 6k TQ 6,650.0 6,590.0 2/5/2025 05:30 2/5/2025 07:00 1.50 INTRM1, TRIPCAS CIRC P Circulate bottom up and reciprocating from 6,590' to 6,455' MD with following parameters: 700 GPM 2660 psi 46% FO 120 RPM 5 - 7k TQ 6,590.0 6,455.0 2/5/2025 07:00 2/5/2025 12:00 5.00 INTRM1, TRIPCAS REAM P BROOH from 6,455' to 5,580' MD with following parameters: 700 GPM 2530 psi 45% FO 11.5 ppg ECD 138k ROT 120 RPM 6 - 8k TQ Note: SIMOPS Lay down 5" drill pipe using mouse hole. 6,455.0 5,580.0 2/5/2025 12:00 2/5/2025 18:00 6.00 INTRM1, TRIPCAS REAM P BROOH from 5,580' to 4,190' MD with following parameters: 700 GPM 2260 psi 45% FO 11.2 ppg ECD 123k ROT 120 RPM 4 - 6k TQ Note: SIMOPS Lay down 5" drill pipe using mouse hole. 5,580.0 4,190.0 2/5/2025 18:00 2/6/2025 00:00 6.00 INTRM1, TRIPCAS REAM P BROOH from 4,190' to 2,903' MD with following parameters: 700 GPM 2003 psi 45% FO 11.2 ppg ECD 123k ROT 120 RPM 2 - 4k TQ Note: SIMOPS Lay down 5" drill pipe using mouse hole. 4,190.0 2,903.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 11/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/6/2025 00:00 2/6/2025 00:30 0.50 INTRM1, TRIPCAS PMPO P Pump OOH from 2903' to 2,784' MD with following parameters: 700 GPM 2000 psi 45% FO 11.3 ppg ECD 123k ROT Note: SIMOPS Lay down 5" drill pipe using mouse hole. 2,903.0 2,784.0 2/6/2025 00:30 2/6/2025 02:00 1.50 INTRM1, TRIPCAS CIRC P Pump 40 BBLs Hi VIS sweep and circulate 2 x BU. 700 GPM 2000 PSI 11.3ppg ECD 2,784.0 2,680.0 2/6/2025 02:00 2/6/2025 05:00 3.00 INTRM1, TRIPCAS SMPD P SOOH f/ 2680' to 790'. Holding 11.3ppg EMW with MPD. 2,680.0 790.0 2/6/2025 05:00 2/6/2025 06:00 1.00 INTRM1, TRIPCAS OWFF P Relax wellbore and flowcheck. Static. 790.0 790.0 2/6/2025 06:00 2/6/2025 07:00 1.00 INTRM1, TRIPCAS MPDA P Retrieve MPD bearing assembly and install trip nipple. 790.0 790.0 2/6/2025 07:00 2/6/2025 10:45 3.75 INTRM1, TRIPCAS BHAH P POOH laying down HWDP, jars and BHA 790.0 0.0 2/6/2025 10:45 2/6/2025 12:00 1.25 INTRM1, CASING RURD P Flush stack, pull wear bushing, clean and clear rig floor, and function test BOPs. 0.0 0.0 2/6/2025 12:00 2/6/2025 13:15 1.25 INTRM1, CASING RURD P RU CRT and equipments for 7 5/8" casing. 0.0 0.0 2/6/2025 13:15 2/6/2025 20:30 7.25 INTRM1, CASING PUTB P PJSM PU and MU shoe track. Run 7- 5/8” Intermediate Casing from surface to 2,790' MD. Filling pipe on the fly on every 10 joints. Connections are within MU band. SO weight 130k o 7-5/8” 33.07# MU TQ is 12.1k ft-lbs o 7-5/8” 29.06# MU TQ is 10.3k ft-lbs 0.0 2,790.0 2/6/2025 20:30 2/6/2025 21:00 0.50 INTRM1, CASING CIRC P Circulate Bottom Up at 6 bpm / 120 psi, MW in or out 9.5 ppg. 2,790.0 2,790.0 2/6/2025 21:00 2/7/2025 00:00 3.00 INTRM1, CASING PUTB P Continue Run 7-5/8” Intermediate Casing from 2,790' to 4,280' MD. Filling pipe on the fly on every 10 joints. Connections are within MU band. SO weight 145k o 7-5/8” 29.06# MU TQ is 10.3k ft-lbs 2,790.0 4,280.0 2/7/2025 00:00 2/7/2025 02:30 2.50 INTRM1, CASING PUTB P Continue Run 7-5/8” Intermediate Casing from 4280' to 5270' MD. Filling pipe on the fly on every 10 joints. Connections are within MU band. SO weight 158k 7-5/8” 29.7# MU TQ is 10.3k ft-lbs 4,280.0 5,270.0 2/7/2025 02:30 2/7/2025 03:00 0.50 INTRM1, CASING CIRC P Circulate BU f/ 5270' to 5315'. Stage rate to 6 BPM 160 PSI. 5,270.0 5,315.0 2/7/2025 03:00 2/7/2025 06:30 3.50 INTRM1, CASING PUTB P Continue Run 7-5/8” Intermediate Casing from 5270' to 6605' MD. Filling pipe on the fly on every 10 joints. Connections are within MU band. SO weight 158k 7-5/8” 29.7# MU TQ is 10.3k ft-lbs 5,315.0 6,605.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 12/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/7/2025 06:30 2/7/2025 07:00 0.50 INTRM1, CASING PUTB P MU hanger and landing joint. Fill pipe and land hanger. Float shoe depth 6640'. 6,605.0 6,640.0 2/7/2025 07:00 2/7/2025 09:00 2.00 INTRM1, CEMENT CIRC P Circulate and condition mud. Stage rates to 7 BPM/ 257 PSI. 6,640.0 6,640.0 2/7/2025 09:00 2/7/2025 12:00 3.00 INTRM1, CEMENT CMNT P Line up to cementers. Load bottom plug #1 and pump 5 bbls of H2O. Test lines to 4000 PSI – test good. Shut Down. Load bottom plug #2 pump 60 BBLS 12.5 PPG Mud Push 5 BPM/150 PSI. Swap to cementers. Pump 57 BBLs 15.3 PPG Tail cement. Shut Down. Load top plug. Cementers pump 10 BBLS FW. Swap to rig pumps. Displace w/ rig at 6 BPM. Slow rate to 3 BPM at 20 BBLs left. Bump plug at 2873 Stks. FCP= 380 PSI. Pressure up to 1902 PSI and hold. Bleed off and check floats. Good. Cement in place at 10:51 hrs 02-07- 2025. 6,640.0 6,640.0 2/7/2025 12:00 2/7/2025 13:00 1.00 INTRM1, CEMENT RURD P Blow Down cement line. RD cementing and CRT / Equipments. 6,640.0 0.0 2/7/2025 13:00 2/7/2025 15:15 2.25 INTRM1, CEMENT RURD P Back out landing joint. Install packoff and test to 5000 psi for 5 min - test good. Lay down landing joint. 0.0 0.0 2/7/2025 15:15 2/7/2025 16:15 1.00 INTRM1, WHDBOP RURD P Change upper pipe rams to 2 7/8" x 5" VBRs. Note SIMOPS changing out wash pipe on Top Drive. 0.0 0.0 2/7/2025 16:15 2/8/2025 00:00 7.75 INTRM1, WHDBOP BOPE P Test BOP 250/3500 psi low/high, choke vavles, 1-15, kill HCR, manual kill, UIBOP, LIBOP, test annuar, upper & lower VBR's w/ 4" test joint, test super & manual choke to 2000 psi. Perform koomey drawdown - ACC = 3000 psi, Manifold = 1500 psi. Acc after function test 1775 psi, 14 sec to 200 psi, full system pressure achieved 110 sec. Nitrogen bottle average 1808 psi. Closing times annular 17 sec, UPR's 7 sec, LPR's 6 sec, blinds 6 sec, kill HCR 1 sec, choke HCR 1 sec. Witnessed by AOGCC - Guy Cook 0.0 0.0 2/8/2025 00:00 2/8/2025 01:30 1.50 INTRM1, WHDBOP BOPE P Install 4 1/2" test joint. Test UPRs/LPRs/HCR choke and manual choke t/ 250 psi low/ 3500 psi high f/ 5 min ea. 0.0 0.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 13/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/8/2025 01:30 2/8/2025 09:15 7.75 INTRM1, WHDBOP RGRP T Pull test joint and plug, pump out stack, clean flow box, blow down choke, kill, jet, hole fill lines. Install test plug and remove test joint, close blinds, RD orbit valve, remove trip nipple and katch ken, RCD head and bag cap. Remove old annular element and install used element. Re-install bag cap. Install MPD equipment, hoses, and orbit valve. Install and seal joes box. Flood BOP stack and MPD chokes. Test MPD equipments to 1400 psi - test good. Note:SIMOPS pull valves and seat on Mud Pump #2 Freeze Protect OA: ICP was 600 psi at .5 BPM, FCP was 770 psi at 2.5 BPM with 75 bbls of diesel pumped. 0.0 0.0 2/8/2025 09:15 2/8/2025 16:30 7.25 INTRM1, WHDBOP RGRP T PU 4" test joint, test annular 250/3500 psi for 5 min low/high - test passed. PU 4 1/2" test joint and test annular to 250/3500 psi for 5 min low/high - test failed. Note: SIMOPS change out KR valve on koomey. Change out saver sub on Top Drive. 0.0 0.0 2/8/2025 16:30 2/9/2025 00:00 7.50 INTRM1, WHDBOP RGRP T Pull test joint and plug, pump out stack, clean flow box, blow down choke, kill, jet, hole fill lines. Install test plug and remove test joint, close blinds, RD orbit valve, remove trip nipple and katch ken, RCD head and bag cap. Remove old annular element. Adaptor ring and Piston ring. Install new element and re- install bag cap. 0.0 0.0 2/9/2025 00:00 2/9/2025 03:30 3.50 INTRM1, WHDBOP RGRP T Install piston ring,adaptor ring, element and cap. Purge air from system. Function annular to break in element. 0.0 0.0 2/9/2025 03:30 2/9/2025 05:00 1.50 INTRM1, WHDBOP BOPE P Test annular w/ 4" and 4 1/2" test joint. 250 psi low/ 3500 psi high f/ 5 min ea. 0.0 0.0 2/9/2025 05:00 2/9/2025 08:00 3.00 INTRM1, WHDBOP RGRP T install RCD head. NU orbit valve. Test MPD to 250 psi low/ 1400 psi high f/ 5 min ea. 0.0 0.0 2/9/2025 08:00 2/9/2025 09:15 1.25 INTRM1, WHDBOP RURD P Pull test plug and install 7.68" ID wear bushing. 0.0 0.0 2/9/2025 09:15 2/9/2025 10:30 1.25 INTRM1, WHDBOP RURD P Test mud pumps at low rate for rate increase. OK. SimOps: Finish swapping out saver sub for 4" DP. 0.0 0.0 2/9/2025 10:30 2/9/2025 12:00 1.50 INTRM1, WHDBOP PRTS P Test casing to 4000 PSI for 30 minutes. Good test. 7 BBLS returned. 0.0 0.0 2/9/2025 12:00 2/9/2025 12:30 0.50 INTRM1, WHDBOP RURD P RD casing test equipment. Blow down choke and kill. Clean and clear rig floor. Prep for BHA. 0.0 0.0 2/9/2025 12:30 2/9/2025 15:00 2.50 INTRM1, DRILLOUT BHAH P MU and PU 6 1/2" production BHA 0.0 0.0 2/9/2025 15:00 2/9/2025 18:00 3.00 INTRM1, DRILLOUT TRIP P RIH with 4" doubles from pipe shed from 163' to 2,739' MD SO weight 80k 0.0 2,739.0 2/9/2025 18:00 2/9/2025 18:45 0.75 INTRM1, DRILLOUT CIRC P Perform shallow test for MWD at 300 GPM / 1730 psi - shallow test good. 2,739.0 2,739.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 14/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/9/2025 18:45 2/10/2025 00:00 5.25 INTRM1, DRILLOUT TRIP P RIH with 4" doubles from pipe shed from 2,739' to 6,325' MD SO weight 98k Note: Log down for 200’ at 450 FPH to 3000’. Continue RIH logging at 1800 FPH to 6325’ 2,739.0 6,350.0 2/10/2025 00:00 2/10/2025 01:00 1.00 INTRM1, DRILLOUT SLPC P Cut/Slip drill line (102' cut). 6,350.0 6,350.0 2/10/2025 01:00 2/10/2025 02:00 1.00 INTRM1, DRILLOUT WASH P Wash down f/ 6350' to 6505'. Cement stringers at 6505'. 250 GPM 1740 PSI 6,350.0 6,505.0 2/10/2025 02:00 2/10/2025 08:00 6.00 INTRM1, DRILLOUT DRLG P Rotate/wash down and tag plugs at 6549'. Drill out FC/shoetrack/FS to 6639'. Clean out rathole to 6650'.Work through shoe x 2. Drill 22' new formation to 6672' MD. 6,505.0 6,672.0 2/10/2025 08:00 2/10/2025 09:00 1.00 INTRM1, DRILLOUT CIRC P Circulate and condition mud while BROOH to inside shoe to 6578'. 250 GPM 1675 PSI 80 RPM 4-5k TQ 6,672.0 6,541.0 2/10/2025 09:00 2/10/2025 10:00 1.00 INTRM1, DRILLOUT LOT P RU test equipment. Perform LOT to 13.7ppg EMW. RD test equipment. 6,541.0 6,578.0 2/10/2025 10:00 2/10/2025 11:00 1.00 PROD1, DRILL MPDA P Retrieve trip nipple. Install MPD bearing assembly. 6,578.0 6,578.0 2/10/2025 11:00 2/10/2025 12:00 1.00 PROD1, DRILL WASH P Wash back to bottom from 6,578' to 6,672' MD with following parameters 250 GPM 1680 psi 31% FO 6,578.0 6,672.0 2/10/2025 12:00 2/10/2025 18:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 6,672' MD to 7,111' MD / 4181' TVD. 275 GPM 2235 PSI 160 RPM 7k TQ 4k WOB 11.4ppg ECD 143k PU 84k SO 106k ROT 5.1 Bit Hrs 6,672.0 7,111.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 15/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/10/2025 18:00 2/11/2025 00:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 7,111' MD to 7,582' MD / 4182' TVD, holding 150 psi while drilling and 220 psi in slips with MPD. 275 GPM 2242 PSI 160 RPM 7k TQ 4k WOB 11.3ppg ECD 148k PU 83k SO 108k ROT 9.7 Bit Hrs Note: Max gas 247 units @ 7,124' MD 7,111.0 7,582.0 2/11/2025 00:00 2/11/2025 06:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 7,582' to 8,086' MD / 4184' TVD, holding 165 psi while drilling and 220 psi in slips with MPD. 275 GPM 2600 PSI 180 RPM 8k TQ 4 - 10k WOB 11.3ppg ECD 155k PU 76k SO 117k ROT 14.1 Bit Hrs Note: Max gas 137 units @ 7,802' MD 7,582.0 8,086.0 2/11/2025 06:00 2/11/2025 10:30 4.50 PROD1, DRILL DDRL P Drill 6 1/2" production section from 8,086' to 8,463' MD / 4190' TVD, holding 175 psi while drilling and 215 psi in slips with MPD. 300 GPM 2710 PSI 180 RPM 6 - 8k TQ 4 - 12k WOB 11.5ppg ECD 151k PU 78k SO 105k ROT 17.4 Bit Hrs Note: Max gas 67 units @ 8,466' MD 8,086.0 8,463.0 2/11/2025 10:30 2/11/2025 11:30 1.00 PROD1, DRILL CIRC T Circulating bottom up, while rotating and reciprocating pipe with 300 GPM 2700 psi 31% FO 11.5ppg ECD 100 RPM 6 - 7k TQ 8,463.0 8,463.0 2/11/2025 11:30 2/11/2025 12:30 1.00 PROD1, DRILL RURD T Swap out RCD bearing, while maintaining back pressure @ 230 psi. 8,463.0 8,463.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 16/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/11/2025 12:30 2/11/2025 18:00 5.50 PROD1, DRILL DDRL P Drill 6 1/2" production section from 8,463' to 9,031' MD / 4187' TVD, holding 175 psi while drilling and 230 psi in slips with MPD. 300 GPM 2790 PSI 180 RPM 6 - 8k TQ 17k WOB 11.6ppg ECD 165k PU 79k SO 119k ROT 21.5 Bit Hrs Note: Max gas 182 units @ 8,858' MD 8,463.0 9,031.0 2/11/2025 18:00 2/12/2025 00:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 9,031' to 9,610' MD / 4189' TVD, holding 173 psi while drilling and 220 psi in slips with MPD. 300 GPM 2850 PSI 180 RPM 8k TQ 18k WOB 11.6ppg ECD 175k PU 72k SO 110k ROT 25.9 Bit Hrs Note: Max gas 362 units @ 9,599' MD 9,031.0 9,610.0 2/12/2025 00:00 2/12/2025 06:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 9,610' to 10,163' MD / 4190' TVD, holding 165 psi while drilling and 210 psi in slips with MPD. 300 GPM 2940 PSI 180 RPM 8k TQ 5 - 18k WOB 11.9ppg ECD 180k PU 110k ROT 30.3 Bit Hrs Note: Max gas 497 units @ 9,882' MD and lost down weight @ 9,976' MD 9,610.0 10,163.0 2/12/2025 06:00 2/12/2025 12:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 10,163' to 10,824' MD / 4191' TVD, holding 169 psi while drilling and 215 psi in slips with MPD. 300 GPM 3090 PSI 180 RPM 8 - 9k TQ 10 - 19k WOB 12.1ppg ECD 196k PU 113k ROT 35.0 Bit Hrs Note: Max gas 271 units @ 10,143' MD 10,163.0 10,824.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 17/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/12/2025 12:00 2/12/2025 18:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 10,824' to 11,367' MD / 4191' TVD, holding 175 psi while drilling and 220 psi in slips with MPD. 300 GPM 3180 PSI 180 RPM 8 - 9k TQ 10 - 16k WOB 11.9ppg ECD 195k PU 115k ROT 38.7 Bit Hrs Note: Max gas 179 units @ 11,109' MD 10,824.0 11,367.0 2/12/2025 18:00 2/12/2025 20:30 2.50 PROD1, DRILL DDRL P Drill 6 1/2" production section from 11,367' to 11,530' MD / 4191' TVD, holding 166 psi while drilling and 213 psi in slips with MPD. 300 GPM 3180 PSI 180 RPM 8 - 9k TQ 10 - 16k WOB 11.9ppg ECD 195k PU 115k ROT 38.7 Bit Hrs Note: Encountered fault between 11,340’ to 11,375’ MD 11,367.0 11,530.0 2/12/2025 20:30 2/13/2025 00:00 3.50 PROD1, DRILL CIRC T Rack back stand in mousehole, circulate across top of hole monitoring loss rates. Pumped 88 bbls of 35 ppb LCM Pill with following parameters. BROOH from 11.385' to 11,288' MD and rack back two stands. Continue pumping across top of hole with 168 GPM, monitoring static loss rate at 3.5 BPH. Initial loss rate was 190 to 200 bph. 50 GPM 1040 Psi 13% FO Note: Holding back pressure at 150 psi, 40 RPM, 8k Torque and 120 RO weight 11,530.0 11,530.0 2/13/2025 00:00 2/13/2025 02:00 2.00 PROD1, DRILL CIRC T Continue pumping across top of hole with 168 GPM, monitoring static loss rate at 3.5 BPH, while building 100 ppb LCM pill. Dynamic loss 60-90 bph at 240 to 300 GPM with no back pressure. 11,530.0 11,530.0 2/13/2025 02:00 2/13/2025 03:30 1.50 PROD1, DRILL CIRC T Drop 1.75" ball inside drill string to open well commander with 142 / 84 GPM, 20 RPM, 7k torque, ball seat 81 bbls. Well Commander open at 3815 psi. Dropped 1.698" isolation ball to isolate BHA. Note: 92 bbls out of 195 bbls total lost bled back. 11,530.0 11,530.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 18/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/13/2025 03:30 2/13/2025 06:00 2.50 PROD1, DRILL CIRC T Attempt to pump 100 bbls of 100 ppb LCM Pill. Observed charge pump Isolation valve failed and contaminating active mud system with LCM pill. Continue circulating on pit #2 with 168 GPM, 710 psi, 20 RPM, 6k Torque. While pumping contaminated pits across shakers to screen out LCM and build another 100 ppb LCM pill. 11,530.0 11,530.0 2/13/2025 06:00 2/13/2025 07:45 1.75 PROD1, DRILL CIRC T Rotate and reciprocate pipe with 168 GPM, 710/80 psi, 26% FO, 20 RPM, 5- 6k Torque, 119 ROT. Pumping through well commander, no losses. Continue Build 2nd 100ppb LCM pill. 11,530.0 11,530.0 2/13/2025 07:45 2/13/2025 09:30 1.75 PROD1, DRILL CIRC T Pump 108 bbls of 100 ppb LCM pill @ 4 bpm, 585 psi, 30% FO, 20 RPM, 5-6k TQ, 120 ROT. Chase with NAF, close MPD chokes @ 1350 stks pumped. Decrease pump rate to 2 BPM. Pump 106 bbls with choke shut in. Shut down and monitor pressures. FCP on pump 450 psi, wellbore pressure 284 psi. Attempt to bleed off SPP. Float stuck open. Shut down stand pipe and monitor pressures. Wellbore pressure at 268 psi. 11,530.0 11,530.0 2/13/2025 09:30 2/13/2025 11:30 2.00 PROD1, DRILL CIRC T Continue monitoring wellbore pressure 257 psi @ 11:30. SIMOPS change out isolation valve on charge lines. Change out charge pump #1. 11,530.0 11,530.0 2/13/2025 11:30 2/13/2025 13:00 1.50 PROD1, DRILL CIRC T Pump 3 bbls down string with MPD chokes closed. Stand pipe 245 psi, wellbore at 267 psi. Stage up pumps to 200 GPM while opening MPD choke, with 970 psi, 116 psi back pressure, 26% FO, 20 RPM, 5-6k TQ, 116k ROT. Continue stage up pump to 250 GPM, 1318 psi / 60 psi back pressure, 33% FO, 20 RPM, 5K TQ, 116k ROT. Circulate bottom up, shut down pump, attempt to bleed off stand pipe with 260 psi on wellbore. Float stuck open. Shut down pump, Open MPD choke. Attempt to break out Top Drive, 30 bbls bled back to pits. Unable to drop well commander closing ball. 11,530.0 11,530.0 2/13/2025 13:00 2/13/2025 15:00 2.00 PROD1, DRILL CIRC T Pump down string with 250 GPM, 1272 psi, 48 psi back pressure, 32% FO, 20 RPM, 5-6k TQ, 117k ROT. Pump 10 bbl LVT pill and spot at float. Shut down and bleed off stand pipe while holding 200 psi on back side. Drop well commander closing ball. Pump ball down @ 4 BPM with 685 psi, 100 psi back pressure. Ball on seat at 975 stks, shifted closed at 3600 psi. 11,530.0 11,530.0 2/13/2025 15:00 2/13/2025 16:00 1.00 PROD1, DRILL WASH T Wash down from 11,290' to 11,530' MD with 210 GPM, 1708 psi, 60 RPM, 7k TQ, 116k ROT. 11,290.0 11,530.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 19/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/13/2025 16:00 2/13/2025 18:00 2.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 11,530' to 11,663' MD / 4192' TVD, Close MPD choke on connections 200 GPM 1636 PSI 120 RPM 7 - 8k TQ 5k WOB 10.6ppg ECD 200k PU 122k ROT 42.5 Bit Hrs Note: Max gas 20 units @ 11,655' MD 11,530.0 11,663.0 2/13/2025 18:00 2/13/2025 20:00 2.00 PROD1, DRILL CIRC P Attempt to make connection float stuck open. Cycle pumps, open MPD choke. Attempt to break out Top Drive, 43 bbls bled back to pits. Unable to floats not holding circulate bottom up to get 9.4 ppg MW inor out, 200 GPM, 1620 psi, 10.5 ppg ECD, 80 RPM, 6k TQ, 115k ROT. Observed ECD's drop from 10.5 ppg to 10.3 ppg. 11,663.0 11,663.0 2/13/2025 20:00 2/14/2025 00:00 4.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 11,663' to 11,890' MD / 4192' TVD, Close MPD choke on connections 200 GPM 1640 PSI 140 RPM 8k TQ 12 - 15k WOB 31% FO 10.6ppg ECD 220k PU 123k ROT 45.8 Bit Hrs Note: Max gas 223 units @ 11,840' MD 11,663.0 11,890.0 2/14/2025 00:00 2/14/2025 08:30 8.50 PROD1, DRILL DDRL P Drill 6 1/2" production section from 11,890' to 12401' MD / 4192' TVD, Close MPD choke on connections 220 GPM 1740 PSI 140 RPM 8k TQ 12 - 15k WOB 31% FO 10.5ppg ECD 220k PU 125k ROT 50.5 Bit Hrs Note: Max gas 223 unit @ 11,840' MD 11,890.0 12,401.0 2/14/2025 08:30 2/14/2025 09:00 0.50 PROD1, DRILL CIRC T While making connection. Drillstring floats leaking by. Work bleeder valve on standpipe several times dumping pressure and floats working. Make connection 12,401.0 12,401.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 20/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/14/2025 09:00 2/14/2025 12:00 3.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 12,401' to 12,689' MD / 4193' TVD, Close MPD choke on connections 240 GPM 2350 PSI 160 RPM 8 - 9k TQ 13k WOB 30% FO 10.4ppg ECD 210k PU 137k ROT 54.5 Bit Hrs Note: Max gas 179 unit @ 12,404' MD 12,401.0 12,689.0 2/14/2025 12:00 2/14/2025 18:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 12,689' to 13,065' MD / 4193' TVD, Close MPD choke on connections 220 GPM 2180 PSI 120 RPM 8 - 9k TQ 10k WOB 30% FO 10.8ppg ECD 220k PU 143k ROT 58.9 Bit Hrs Note: Max gas 113 unit @ 13,047' MD 12,689.0 13,065.0 2/14/2025 18:00 2/15/2025 00:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 13,065' to 13,482' MD / 4193' TVD, Close MPD choke on connections 220 GPM 2230 PSI 120 RPM 8 - 9k TQ 10k WOB 30% FO 10.8ppg ECD 220k PU 143k ROT 63.7 Bit Hrs Note: Max gas 272 unit @ 13,318' MD 13,065.0 13,482.0 2/15/2025 00:00 2/15/2025 06:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 13482' to 13875' MD / 4193' TVD, 220 GPM 2300 PSI 140 RPM 10k TQ 5-18k WOB 32% FO 10.8ppg ECD 220k PU 143k ROT 68.1 Bit Hrs Note: Max gas 1266 unit @ 13,598' MD 13,482.0 13,875.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 21/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/15/2025 06:00 2/15/2025 12:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 13,875' to 14,324' MD / 4198' TVD, 240 GPM 2790 PSI 150 RPM 10 - 11k TQ 12k WOB 32% FO 11.1ppg ECD 220k PU 150k ROT 72.7 Bit Hrs Note: Max gas 946 unit @ 13,972' MD 13,875.0 14,324.0 2/15/2025 12:00 2/15/2025 18:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 14,324' to 14,840' MD / 4200' TVD, 240 GPM 2910 PSI 150 RPM 10 - 11k TQ 12k WOB 32% FO 11.2ppg ECD 265k PU 152k ROT 77.2 Bit Hrs Note: Max gas 975 unit @ 14,525' MD 14,324.0 14,840.0 2/15/2025 18:00 2/16/2025 00:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 14,840' to 15,310' MD / 4201' TVD, 240 GPM 3000 PSI 150 RPM 10 - 11k TQ 10k WOB 33% FO 11.2ppg ECD 270k PU 152k ROT 81.4 Bit Hrs Note: Max gas 852 unit @ 15,100' MD 14,840.0 15,310.0 2/16/2025 00:00 2/16/2025 06:00 6.00 PROD1, DRILL DDRL P Drill 6 1/2" production section from 15310' to 15755' MD / 4202' TVD, 240 GPM 3100 PSI 150 RPM 10 - 11k TQ 12k WOB 32% FO 11.4ppg ECD 284k PU 150k ROT 85.5 Bit Hrs Note: Max gas 458 unit @ 15,553' MD 15,310.0 15,755.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 22/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/16/2025 06:00 2/16/2025 13:15 7.25 PROD1, DRILL DDRL P Drill 6 1/2" production section from 15,755' to 16,392' MD / 4203' TVD, Close MPD choke on connections 240 GPM 3140 PSI 150 RPM 10 - 13k TQ 13k WOB 33% FO 11.4ppg ECD 305k PU 143k ROT 91.2 Bit Hrs Note: Max gas 360-470 units @ 16,392' MD 15,755.0 16,392.0 2/16/2025 13:15 2/16/2025 16:00 2.75 PROD1, TRIPCAS CIRC P Obtain final survey and perform T&D. Rotate and reciprocate pipe from 16,392' to 16,308', while circulating 2x Bottom up with: 250 GPM 3375 psi 120 RPM 10-12k Torque 11.4ppg ECD 32% FO 305k PUW 142k ROT 16,392.0 16,308.0 2/16/2025 16:00 2/16/2025 18:00 2.00 PROD1, TRIPCAS OWFF P Fingerprint / relax well at 16,392' MD, keep string moving with 6 gpm, 7-9k TQ. Open/close cycles, 5-10 mins per cycle, initial wellbore pressure 290 psi and final wellbore pressure 0 psi. Total flow back to pits 118 bbls. Decrease in flow, pressure and fluid flow back each cycle. Close orbit valve, open 2" valve on RCD and OWFF - well static. 16,308.0 16,308.0 2/16/2025 18:00 2/17/2025 00:00 6.00 PROD1, TRIPCAS BKRM P BROOH from 16,379' to 15,270' MD and lay down stands of 4" drill pipe in mousehole with following parameters: 240 GPM 2955 psi 32% FO 10.9 ppg ECD 10 - 13k TQ 120 RPM 144k ROT 16,308.0 15,270.0 2/17/2025 00:00 2/17/2025 06:00 6.00 PROD1, TRIPCAS BKRM P BROOH from 15270' to 13783' MD and lay down stands of 4" drill pipe in mousehole with following parameters: 240 GPM 2570 psi 32% FO 10.5 ppg ECD 11k TQ 120 RPM 142k ROT 15,270.0 13,783.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 23/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/17/2025 06:00 2/17/2025 09:30 3.50 PROD1, TRIPCAS BKRM P BROOH from 13783' to 12866' MD racking back HWDP. 240 GPM 2490 psi 32% FO 10.4 ppg ECD 11k TQ 120 RPM 140k ROT 13,783.0 12,866.0 2/17/2025 09:30 2/17/2025 10:00 0.50 PROD1, TRIPCAS SVRG P Service Top Drive. 12,866.0 12,866.0 2/17/2025 10:00 2/17/2025 12:00 2.00 PROD1, TRIPCAS RGRP T MU TIW, head pin and circulate at 2 bpm, Change out swivel packing on Top Drive. 12,866.0 12,866.0 2/17/2025 12:00 2/17/2025 18:00 6.00 PROD1, TRIPCAS BKRM P BROOH from 12,866' to 10,852' MD racking back HWDP. Rack back seven stand of 4" drill pipe from 10,852' to 10,286' MD. 240 GPM 2490 psi 32% FO 10.1 ppg ECD 11k TQ 120 RPM 115k ROT 12,866.0 11,137.0 2/17/2025 18:00 2/18/2025 00:00 6.00 PROD1, TRIPCAS BKRM P BROOH from 10,286' to 9,312' MD Lay down 4" drill pipe. 240 GPM 1957 psi 33% FO 10.1 ppg ECD 10k TQ 120 RPM 108k ROT 11,137.0 9,312.0 2/18/2025 00:00 2/18/2025 06:00 6.00 PROD1, TRIPCAS BKRM P BROOH from 9,312' to 7,711' MD Lay down 4" drill pipe. in mousehole with following parameters: 240 GPM 1670 psi 33% FO 10.0 ppg ECD 9k TQ 120 RPM 108k ROW 9,312.0 7,711.0 2/18/2025 06:00 2/18/2025 09:00 3.00 PROD1, TRIPCAS BKRM P BROOH from 7,711' to 6,828' MD Lay down 4" drill pipe. in mousehole with following parameters: 240 GPM 1664 psi 33% FO 10.1 ppg ECD 8k TQ 120 RPM 110k ROW 7,711.0 6,828.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 24/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/18/2025 09:00 2/18/2025 09:30 0.50 PROD1, TRIPCAS CIRC P Obtain T&D by rotate and reciprocate pipe from 6,828' to 6,630' MD for the following parameters: 240 GPM 270 Psi 100k PU 133k SO 110k ROT 6,828.0 6,630.0 2/18/2025 09:30 2/18/2025 11:00 1.50 PROD1, TRIPCAS CIRC P Pump down 1 3/4" ball to open well commander @ 2 BPM, 280 psi, 15k torque. Ball on seat at 324stk(27bbls). Staged up pump and observed shear ball @ 3480 psi. Confirm well commander is open by staged pumps to 500 GPM, 2315 psi, 80 rpm, 6-7k torque, reduce pump rate to 400 gpm, 1687 psi, total strokes pumped 6450stk. 6,630.0 6,630.0 2/18/2025 11:00 2/18/2025 12:30 1.50 PROD1, TRIPCAS CIRC P Fingerprint to relax well at 6,579' MD by open and close chokes every 5 to 10 minutes interval. Wellbore initial pressure 80 psi and final 5 psi. Total BBLs bled back 1.2 bbls. Close orbit valve and open up 2" valve on RCD. OWFF - well static. 6,630.0 6,630.0 2/18/2025 12:30 2/18/2025 13:00 0.50 PROD1, TRIPCAS SVRG P Rig service, RU man basket, derrick board inspection. 6,630.0 6,630.0 2/18/2025 13:00 2/18/2025 17:00 4.00 PROD1, TRIPCAS RGRP T Install toe board and safety restraints to monkey board while circulating at 84 gpm, 143 psi. 6,630.0 6,630.0 2/18/2025 17:00 2/18/2025 18:30 1.50 PROD1, TRIPCAS RURD P Blow down Top drive. Drop 1 3/4" colsing ball, pull RCD bearing and install trip nipple. hole fill line. 6,630.0 6,630.0 2/18/2025 18:30 2/18/2025 19:00 0.50 PROD1, TRIPCAS CIRC P Pressure up at 2 bpm and shift well commander to closed position at 3536 psi, 2.3 bbls to pressure up. confirm flow rate to verify well commander closed. Blow down Top drive. Drop 2.4" OD hollow drift. 6,630.0 6,475.0 2/18/2025 19:00 2/18/2025 23:00 4.00 PROD1, TRIPCAS TRIP P POOH from 6,475' to 163' MD, while monitoring disp. 6,475.0 163.0 2/18/2025 23:00 2/18/2025 23:30 0.50 PROD1, TRIPCAS OWFF P Pull drift from pipe. OWFF - Well static. SIMOPS pull PS-21's 163.0 163.0 2/18/2025 23:30 2/19/2025 00:00 0.50 PROD1, TRIPCAS BHAH P PJSM and started to lay down 6 1/2" production BHA. 163.0 0.0 2/19/2025 00:00 2/19/2025 02:00 2.00 PROD1, TRIPCAS BHAH P LD BHA to surface. 0.0 0.0 2/19/2025 02:00 2/19/2025 03:00 1.00 COMPZN, CASING CLEN P Clean and clear rig floor. Function BOPs. 0.0 0.0 2/19/2025 03:00 2/19/2025 04:30 1.50 COMPZN, CASING RURD P RU liner running equipment. 0.0 0.0 2/19/2025 04:30 2/19/2025 10:00 5.50 COMPZN, CASING PUTB P PJSM. RIH with 4 ½” P110S Hyd563 12.6# liner lower completion from surface to 2.373' MD. Install one 4 1/2" x 6 1/8" Hydroform centralizer per joint. Applied thin layer of BOL-AG 2000 on each connection. Install Frac Sleeve every 11 joints. Note: MU TQ 5600 ft/lbs. 0.0 2,373.0 2/19/2025 10:00 2/19/2025 10:30 0.50 COMPZN, CASING SVRG P Install PS21's grease / flush, grease IBOP, blocks, wash pipe. 2,373.0 2,373.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 25/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/19/2025 10:30 2/19/2025 18:00 7.50 COMPZN, CASING PUTB P RIH with 4 ½” P110S Hyd563 12.6# liner lower completion from 2,373' to 7,154' MD. Install one 4 1/2" x 6 1/8" Hydroform centralizer per joint. Applied thin layer of BOL-AG 2000 on each connection. Install Frac Sleeve every 11 to 12 joints. Obtain T&D Up/Down/Rotate at 6,620' MD, PU-72k, SO-70k, ROT-71k, RPM 20, Torque 2k Note: MU TQ 5600 ft/lbs. 2,373.0 7,154.0 2/19/2025 18:00 2/19/2025 23:00 5.00 COMPZN, CASING PUTB P RIH with 4 ½” P110S Hyd563 12.6# liner lower completion from 7,154' to 9,943' MD. Install one 4 1/2" x 6 1/8" Hydroform centralizer per joint. Applied thin layer of BOL-AG 2000 on each connection. Install Frac Sleeve every 12 joints. Obtain T&D Up/Down/Rotate at 7,570' MD, PU-79k, SO-68k, ROT-72k, RPM 20/30, Torque 2.8/2.8k. MU TQ 5600 ft/lbs. 7,154.0 9,943.0 2/19/2025 23:00 2/20/2025 00:00 1.00 COMPZN, CASING PUTB P MU ZXP liner hanger and fill with Zanplex. RD elevators/bail extensions and CRT. 9,943.0 9,943.0 2/20/2025 00:00 2/20/2025 07:00 7.00 COMPZN, CASING RUNL P RIH w/ 4 1/2" liner on 4" DP and 4" HWDP f/ 9943' to 15523'. Take ROT weights and TQ every 1000'. MD RPM TRQ U/D/R 10,222' 20/30 2.8/3k 80/71/73k 11,164' 20/30 3.5/3.5k87/73/75k 12,107' 20/30 3.8/4k 94/76/100k 13,030' 20/30 4/4.5k 110/88/100k 14,876' 20/30 5.6/6.5k146/105/125k 15,523' 20/30 7/7.5k 170/110/132k 9,943.0 15,523.0 2/20/2025 07:00 2/20/2025 09:30 2.50 COMPZN, CASING RUNL P RIH with 4 1/2" Liner on 4" DP/HWDP from 15,523' to 16,245' MD SOW 110k. Drift HWDP out of derrick with 1.9" OD drift. AT16,267' MD loss 10k SOW, Rotate down to 16,392' MD with 20 RPM, 7k TQ, ROW 140k, PU to 16,387' MD. 15,523.0 16,245.0 2/20/2025 09:30 2/20/2025 10:00 0.50 COMPZN, CEMENT RURD P MU cement head to drill string, RU cement head. Line up to fill string and vent air from string. 16,245.0 16,387.0 2/20/2025 10:00 2/20/2025 11:00 1.00 COMPZN, CEMENT CIRC P Stage pump up to 4 bpm, 220 psi with 9.5 ppg BARAECD, 124 bbl observed returns, isolate vent. Continue pump down through drill string. Break circulation with 2 bpm pressure increased to 500 psi. 16,387.0 16,387.0 2/20/2025 11:00 2/20/2025 15:30 4.50 COMPZN, CEMENT CIRC P Blow down Top Drive and close IBOP. Line up to pump down through cement head. Break circulation with 84 gpm, 660 psi. Pump 40 bbls of HI VIS spacer until seen to surface with 9.5 ppg BARAECD @ 2.5 bpm, 650 psi. 16,387.0 16,387.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 26/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/20/2025 15:30 2/20/2025 19:00 3.50 COMPZN, CEMENT CIRC P Pressure test lines to 4200 psi - test good. Drop 1.5" setting ball. Circulate at 2-3 bpm, 778 psi, ball on seat with 2445 strokes. Pressure up to set hanger to 2500 psi and second time at 2600 psi.Did not set. Pressure up to 2800 psi and SO 50k .Hanger set at 16,387' MD. Increased pressure to 3600 psi and hold for 5 min. Bleed pressure down to 500 psi. Pick up 2' past free travel of 175k, set 50k down, increased pressure to shear ball seat at 4327 psi. Pick up 4' to verified hanger released. Circulation at 3 bpm, 755 psi. 16,387.0 16,387.0 2/20/2025 19:00 2/20/2025 22:30 3.50 COMPZN, CEMENT CMNT P PJSM for cement job. Pressure test lines to 4000 psi - test good. Pump 50 bbls of 11 ppg of mud push at 3 bpm with rig. Pumped 277 bbls of 15.3 ppg cement at 3.5 bpm with SLB. Pump 1 bbl H2O, dropped dart, and pumped 9 bbls of H2O. Displace with rig 140 bbls of Brine, swap to transition spacer continue displace at 4 bpm, 960 psi. Reduce rate to 3 bpm, ICP 806 psi and bumped plug at 2251 strokes, FCP 1300 psi and hold for 5 min, bleed of pressure and check floats - float is holding. 16,387.0 16,387.0 2/20/2025 22:30 2/20/2025 23:00 0.50 COMPZN, CEMENT CIRC P Expose the dog subs by PU 8' past break over 170 k, rotate 20 rpm, 144k ROTt, set down 50k, rotate for 2 min twice. Packer set. Pressure up to 500 psi. PU 8' observe pressure drop off, increased rate to 4 bpm, 550 psi. Flush out liner top profile, Top of liner at 6,453' MD. 16,387.0 6,453.0 2/20/2025 23:00 2/21/2025 00:00 1.00 COMPZN, WELLPR CIRC P Pump 100 bbls of cleaning spacer and chase with CI Brine, circulate surface to surface at 6 bpm. 750/900 psi. Note: Observed all of the mudpush at shakers. Possible traces of cement. 6,453.0 6,453.0 2/21/2025 00:00 2/21/2025 05:00 5.00 COMPZN, WELLPR CLEN P L/D single, R/D cement head. Pull shaker screens, clean pits, pull PS21's, clean Joes box/flow line, off load remaining OBM. Pump surfactant pill f/ trip tanks over shakers, through suction lines f/pits 1-4, 6,453.0 6,453.0 2/21/2025 05:00 2/21/2025 05:30 0.50 COMPZN, WELLPR PRTS P Close annular, PT well t/3850 psi f/5 min 7bbls to pressure up 7 bbls bled back. 6,453.0 6,453.0 2/21/2025 05:30 2/21/2025 06:00 0.50 COMPZN, WELLPR OWFF P Flow check. Static 6,453.0 6,453.0 2/21/2025 06:00 2/21/2025 06:30 0.50 COMPZN, WELLPR SVRG P Rig Service for Iron roughneck 6,453.0 6,453.0 2/21/2025 06:30 2/21/2025 15:30 9.00 COMPZN, WELLPR TRIP P POOH laying down 4" HWDP/DP from 6,456' to 43' MD. Lay down Baker running tool. 6,453.0 0.0 2/21/2025 15:30 2/21/2025 16:30 1.00 COMPZN, WELLPR PRTS P Line up and purge kill line close blinds. Perform JUG test to 3932 psi for 30 minutes, pumped 8 .4 bbls and bleed off 5.8 bbls back. Blow down kill line. Note good test. 0.0 0.0 2/21/2025 16:30 2/21/2025 19:00 2.50 COMPZN, WELLPR TRIP P RIH with 4" drill pipe from derrick to 4,882' MD. SOW 100k 0.0 4,882.0 2/21/2025 19:00 2/22/2025 00:00 5.00 COMPZN, WELLPR PULD P POOH with 4" drill pipe from 4,882' to 1,041' MD. 4,882.0 1,041.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 27/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/22/2025 00:00 2/22/2025 01:00 1.00 COMPZN, WELLPR PULD P POOH LD 4" DP f/ 1041' to surface. 1,041.0 0.0 2/22/2025 01:00 2/22/2025 03:00 2.00 COMPZN, WELLPR RURD P Pull PS-21 slips. Jet stack and retrieve wear bushing. Jet landing ring profile. 0.0 0.0 2/22/2025 03:00 2/22/2025 05:00 2.00 COMPZN, RPCOMP RURD P RU volant tool, bail extensions and handling equipment. RU spool and spooling unit. 0.0 0.0 2/22/2025 05:00 2/22/2025 19:30 14.50 COMPZN, RPCOMP PUTB P PJSM RIH with 4 1/2" 12.6 #, H563 upper completion from surface to 6,477' MD. MU torque 3800 ft/Ibs. Test TEC wire every 1000' and filling on fly with 9.3 ppg CI Brine. Note: SOW 93k. 0.0 6,477.0 2/22/2025 19:30 2/22/2025 21:00 1.50 COMPZN, RPCOMP PUTB P Fully located and set down 10k @ 6,477' MD, shear pins with additional 10k. Lay down three joints from 6,477' to 6,418' MD. MU space out pups. PU 116k, SO 93k, 6,477.0 6,418.0 2/22/2025 21:00 2/23/2025 00:00 3.00 COMPZN, RPCOMP RURD P Lay down CRT. MU hanger and landing joint. MU TEC wire in hanger. Pressure test connections to 5000 psi for 5 minutes. Land out hanger at 6,474' MD, three feet from fully located. Lock down hanger in well head, pressure test hanger seals to 5000 psi for 15 minutes. 6,418.0 6,474.0 2/23/2025 00:00 2/23/2025 00:45 0.75 COMPZN, RPCOMP PRTS P Set packer and test tubing: Monitor IA for leak. Pressure up to 500 PSI on tbg hold f/ 5 minutes. Pressure up to 4550 PSI for 30 minutes. Test charted. Note: Packer set and tbg tested. 6,474.0 0.0 2/23/2025 00:45 2/23/2025 01:30 0.75 COMPZN, RPCOMP PRTS P Bleed off tbg pressure to 2200 PSI. Pressure up and test IA to 3850 PSI for 30 minutes. Charted. Good test. Bleed IA down to 3000 PSI. Dump pressure on tbg and shear SOV. 0.0 0.0 2/23/2025 01:30 2/23/2025 02:00 0.50 COMPZN, WHDBOP OWFF P Flow check. Static. 0.0 0.0 2/23/2025 02:00 2/23/2025 03:00 1.00 COMPZN, WHDBOP WWSP P Install BPV. SimOps: Clean and clear rig floor. 0.0 0.0 2/23/2025 03:00 2/23/2025 06:00 3.00 COMPZN, WHDBOP NUND P ND BOPE and HP riser. SimOps: Disconnect Ball mill and move away from rig. Redress MPS to 6 1/2" liners. 0.0 0.0 2/23/2025 06:00 2/23/2025 07:30 1.50 COMPZN, WHDBOP NUND P ND 5' spool and drilling adapter. 0.0 0.0 2/23/2025 07:30 2/23/2025 12:00 4.50 COMPZN, WHDBOP PULD P PU and MU tubing head adapter, 10K frac tree. SIMOPS blow down pump / pits interconnects and continue dress pump with 6 1/2" liners. 0.0 0.0 2/23/2025 12:00 2/23/2025 15:30 3.50 COMPZN, WHDBOP RURD P Remove press plate and lay down. MU and torque tubing adapter. Terminate Halco TEC wire. Pressure test seals and flanges to 5000 psi for 15 minutes - test good. Clean cellar box. Final readings on TEC line: 1935 PSI 102 deg F 0.0 0.0 Rig: DOYON 25 RIG RELEASE DATE 2/24/2025 Page 28/28 3S-714 Report Printed: 2/25/2025 Operations Summary (with Timelog Depths) Job: DRILLING ORIGINAL Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/23/2025 15:30 2/23/2025 16:30 1.00 COMPZN, WHDBOP RURD P MU 10k frac tree and confirm orientation with frac supervisor. Install swab valve and torque. SIMOPS change out saver sub to 4 1/2" IF. Secure derrick for scope. RD baker BPA. RU scoping yokes. Remove kelly hose. 0.0 0.0 2/23/2025 16:30 2/23/2025 17:00 0.50 COMPZN, WHDBOP PRTS P Fill tree with diesel, purge air, RU 10k test pump, test tree to 250 psi for 5 minutes and 10,000 psi for 15 minutes - test good. RD test equipments. 0.0 0.0 2/23/2025 17:00 2/23/2025 17:30 0.50 COMPZN, WHDBOP RURD P RIH with T-bar to install tree test dart. SIMOPS RU frac tree to freeze protect to LRS. 0.0 0.0 2/23/2025 17:30 2/23/2025 18:00 0.50 COMPZN, WHDBOP FRZP P Pump lines with diesel, pressure test to 2000 psi - test good. SIMOPS RU scoping lines and blow down H2O. 0.0 0.0 2/23/2025 18:00 2/23/2025 23:00 5.00 COMPZN, WHDBOP FRZP P Start pumping diesel down IA and taking returns up tubing to the pits. Drop rate from 1 bpm to 0.4 bpm due to max pressure at 2000 psi. Line up to bleed down IA to unit(LRS), bleed back 2.3 bbls to 50 psi. Resume pumping down to IA with 0.40 bpm, pressure between 1500 to 2500 psi. Shut down as needed to allow pressure to bleed down FCP 950 psi and pump 94 bbls of diesel. Note: At 64 bbls away restriction cleared up. Pumped rest of diesel away at 1 BPM no issues. SIMOPS Blow down water, bridal up, scope derrick down, remove bridal lines, secure top drive and energy track, pull 11 wraps off drawworks, Blow down steam to sub. 0.0 0.0 2/23/2025 23:00 2/24/2025 00:00 1.00 COMPZN, WHDBOP OWFF P U-Tube IA and tubing equalized to 50 psi. 0.0 0.0 2/24/2025 00:00 2/24/2025 02:00 2.00 COMPZN, WHDBOP MOB P RD squeeze manifold. Remove outer wing valve. Secure well and RDMO. SIMOPS put casing shed on suspension. Blow down rig floor steam loop. Continue unplugging modules. 0.0 0.0 Rig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age 1/1 3S-714 Report Printed: 2/25/2025 Cement Cement Details Description Surface String Cement Cementing Start Date 1/31/2025 03:00 Cementing End Date 1/31/2025 03:00 Wellbore Name 3S-714 Comment Test lines to 3500 PSI. Pump 100 BBLS 10.5 PPG MudPush @ 5.5 BPM/200 PSI. Drop bottom plug. Pump 473 BBLS 11.0 PPG lead cement (Cement wet @ 03:30hrs). MudPush observed at surface at 340 BBLS cement pumped. Pump 60 BBLS 15.8 PPG tail cement (Cement wet @ 05:07hrs). FCP - 282 PSI @ 5 BPM. SD. Drop top plug. Pump 20 BBLS FW with cement unit. Swap to rig pumps. Displace with 9.5 PPG spud mud. Bump plug with calculated strokes. 244 BBLS / 2423 strokes, FCP - 905 PSI @ 3 BPM. Pressure up to 1500 PSI. Hold for 5 minutes. Check floats. Good. Cement in place at 07:00hrs on 1/31/24. Note: Cement to Surface - 110 BBLS. Lost returns at 1400 strokes into displacement. Worked string and rotate with no improvement. Cement was still at surface when ND risers. Cement Stages Stage # 1 Description Surface String Cement Objective Top Depth (ftKB) 40.7 Bottom Depth (ftKB) 2,803.0 Full Return? No Vol Cement …Top Plug? Yes Btm Plug? Yes Q Pump Init (bbl/m… 5 Q Pump Final (bbl/… 3 Q Pump Avg (bbl/… 5 P Pump Final (psi) 985.0 P Plug Bump (psi) 1,500.0 Recip? No Stroke (ft) Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Comment Cement Fluids & Additives Fluid Fluid Type Fluid Description Estimated Top (ftKB) Est Btm (ftKB) Amount (sacks) Class Volume Pumped (bbl) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) CmprStr 1 (psi) Additives Additive Type Concentration Conc Unit label Surface String Cement Page 1/1 3S-714 Report Printed: 2/25/2025 Cement Cement Details Description Intermediate String 1 Cement Cementing Start Date 2/7/2025 09:00 Cementing End Date 2/7/2025 11:00 Wellbore Name 3S-714 Comment Line up to cementers. Load bottom plug #1 and pump 5 bbls of H2O. Test lines to 4000 PSI – test good. Shut Down. Load bottom plug #2 pump 60 BBLS 12.5 PPG Mud Push 5 BPM/150 PSI. Swap to cementers. Pump 57 BBLs 15.3 PPG Tail cement. Shut Down. Load top plug. Cementers pump 10 BBLS FW. Swap to rig pumps. Displace w/ rig at 6 BPM. Slow rate to 3 BPM at 20 BBLs left. Bump plug at 2873 Stks. FCP= 380 PSI. Pressure up to 1902 PSI and hold. Bleed off and check floats. Good. Cement in place at 10:51 hrs 02-07-2025. Cement Stages Stage # 1 Description Intermediate String 1 Cement Objective Top Depth (ftKB) 5,665.0 Bottom Depth (ftKB) 6,639.3 Full Return? No Vol Cement …Top Plug? Yes Btm Plug? Yes Q Pump Init (bbl/m… 7 Q Pump Final (bbl/… 3 Q Pump Avg (bbl/… 6 P Pump Final (psi) 380.0 P Plug Bump (psi) 1,902.0 Recip? No Stroke (ft) Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Comment Load bottom plug #1 and pump 5 bbls of H2O with SLB. Test lines to 4000 PSI – test good. Shut Down. Load bottom plug #2 pump 60 BBLS 12.5 PPG Mud Push 5 BPM/150 PSI. Swap to cementers. Pump 57 BBLs 15.3 PPG Tail cement. Shut Down. Load top plug. Cementers pump 10 BBLS FW. Swap to rig pumps. Displace w/ rig at 6 BPM. Slow rate to 3 BPM at 20 BBLs left. Bump plug at 2873 Stks. FCP= 380 PSI. Pressure up to 1902 PSI and hold. Bleed off and check floats. Good. Cement in place at 10:51 hrs 02-07-2025. Cement Fluids & Additives Fluid Fluid Type Primary Cement Fluid Description Estimated Top (ftKB) 5,665.0 Est Btm (ftKB) 6,639.3 Amount (sacks) Class G Volume Pumped (bbl) 57.0 Yield (ft³/sack) 1.25 Mix H20 Ratio (gal/sack) 5.43 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 80.0 Thickening Time (hr) 5.00 CmprStr 1 (psi) Additives Additive Type Concentration Conc Unit label Intermediate String 1 Cement Page 1/1 3S-714 Report Printed: 2/25/2025 Cement Cement Details Description Production String 1 Cement Cementing Start Date 2/20/2025 19:33 Cementing End Date 2/20/2025 22:30 Wellbore Name 3S-714 Comment PJSM for cement job. Pressure test lines to 4000 psi - test good. Pump 50 bbls of 11 ppg of mud push at 3 bpm with rig. Pumped 277 bbls of 15.3 ppg cement at 3.5 bpm with SLB. Pump 1 bbl H2O, dropped dart, and pumped 9 bbls of H2O. Displace with rig 140 bbls of Brine, swap to transition spacer continue displace at 4 bpm, 960 psi. Reduce rate to 3 bpm, ICP 806 psi and bumped plug at 2251 strokes, FCP 1300 psi and hold for 5 min, bleed of pressure and check floats - float is holding. Cement Stages Stage # 1 Description Primary – Full Bore Objective Cement 4 1/2" lower liner completion Top Depth (ftKB) 3,450.0 Bottom Depth (ftKB) 16,387.0 Full Return? Yes Vol Cement …Top Plug? Yes Btm Plug? No Q Pump Init (bbl/m… 4 Q Pump Final (bbl/… 3 Q Pump Avg (bbl/… 4 P Pump Final (psi) 1,338.0 P Plug Bump (psi) 832.0 Recip? No Stroke (ft) Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Comment Cement Fluids & Additives Fluid Fluid Type Fluid Description Estimated Top (ftKB) Est Btm (ftKB) Amount (sacks) Class Volume Pumped (bbl) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) CmprStr 1 (psi) Additives Additive Type Concentration Conc Unit label Production String 1 Cement 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 3S-714 Yes No 9. Property Designation (Lease Number): 10. Field: Coyote Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 16392 4204 16392 5163 2305 None None Casing Collapse Structural Conductor 20" 132.0 Surface 10-3/4" 2803 5210 2470 Intermediate 7-5/8" 6639 10860 7850 Liner 4-1/2" 16392 11590 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:Rodrigo Ruysschaert Rodrigo Ruysschaert Contact Email:Rodrigo.Ruysschaert@cop.com Contact Phone: 907-621-0671 Authorized Title: Completions Engineer 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 6599.3 9940.14 4-1/2" 4204.00 92.0 2762.2 MD 132.0 2520.00 4139.00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL380107 / ADL392374 224-151 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20903-00-00 ConocoPhillips Alaska Inc. Proposed Pools: Kuparuk Field AOGCC USE ONLY Tubing Grade:Tubing MD (ft): TNT packer: 6331 ft MD/4066 ft TVD SLZXP packer: 6452 ft MD/4098 ft TVD Perforation Depth TVD (ft): L-80 Perforation Depth MD (ft): Apr 04 2025 Halliburton TNT Prod Packer Baker SLZXP, No SSSV Mar 04 2025 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 Length Size TVD Burst 6475 m n Pe _ 2 66 t e t t e N 325-126 By Gavin Gluyas at 8:14 am, Mar 05, 2025 Fracture Stimulate DSR-3/10/25 10-404 X SFD 3/24/2025 X CDW 03/10/2025 A pr 04 2025 WA G VTL 3/25/2025*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.26 08:22:45 -08'00'03/26/25 RBDMS JSB 032725 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). 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) 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”. Agree: Aquifers affected by this well are exempt. This well lies within the Kuparuk River Unit (KRU) boundary of 1984 that forms the basis for the aquifer exemption granted by Title 40 CFR 147.102(b)(3) according to a recent opinion by the EPA, which states in part: "In short, EPA finds that the boundary of Alaska’s aquifer exemption at 40 C.F.R. 147.102(b)(3) was determined on May 11, 1984. After a program is approved or promulgated, additions to aquifer exemptions, including boundary expansions to aquifers or parts thereof, submitted as part of a UIC program cannot change unless EPA approves those additions in accordance with EPA’s UIC program regulations (See 40 C.F.R. 144.7(b)(1) and (3)).” (Reference: Email from Evan Osborne, US EPA Region 10, to Steve Davies, AOGCC, dated December 2, 2024.) SFD 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. Agree. SFD 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. 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: 10 & 3/4” casing cement pump report on 1/31/2025 shows that the original job pumped as designed. The cement job was pumped with 43 barrels of 11.0 ppg lead cement and 60 barrels 15.8 ppg tail cement. The plug bumped and floats held. Lost returns at 1400 strokes into displacement. Worked string and rotate with no improvement. Cement was still at surface when ND risers. Cement to Surface - 110 BBLS. The 7 & 5/8” casing cement report on 2/7/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped pump with 60 BBLS 12.5 PPG Mud Push 5 BPM/150 PSI. followed by 57 BBLs 15.3 PPG Tail cement. Bump plug at 2873 Stks, and floats held. A cement bond log indicates competent cement with a cement top @ 5530 ft MD / 3765 ft TVD. Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. 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. Agree. Top of consistent, excellent bond is 5,575' MD. SFD g Cement to Surface - 110 BBLS Agree. SFD SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 2/2/2025 the 10-3/4” casing pressure was tested to 3,500 psi for 30 minutes On 2/9/2025 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes. On 2/23/2025 the 4-1/2” tubing was pressure tested to 4,550 psi. Good Test. On 2/23/2024 the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi. Good Test. 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 A 4550 psi tubing test allows a 4136 psi differential (110%). With 3500 psi backpressure, max surface pressure is limited to 7636 psi. I will correct step 12 in program to this value. CDW 03/10/2025. 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 2474 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 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up FMC 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 500 ft TVD over the course of the lateral section of well 3S-714, from where it intersects the top formation at 6,431’ MD to TD 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 more than 350’ TVD across the area. The top of the confining intervals starts at ~3,550’ TVDSS (5,210’ MD). 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 greater than 300’ TVD across the area. 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 ~4,575 ft TVDSS at the heel, and ~4,840’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1715 – 1,840 psi at a depth of 4,150’ 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-08C: The 7" casing cement report on 03/18/2023 indicates the job was pumped as designed except for some losses in the last 20 bbls,Pump 5 bbls Mudpush @ 12.8ppg, Test lines to 3000 psi, Con't pump 20 bbls 12.8ppg Mud push, Drop bttm plug, Pump batch mixed 15.8ppg slurry 40.2 bbls , Av PR 3.7 bpm, drop top plug, kick out plug pumping 10 bbls wash up and turn over to rig. Rig displaced plug w/ 10.2ppg mud Av PR 4 bpm, recipricating 20' strock. Full returns throughtout job until the last 20 bbls displacement.Casing stuck on the up strock 25' up from shoe point and 75% loss of returns. Bumper plug with calculated strokes 3231 to 1900 psi. Held 5 min. Checked floats "OK" Shoe @ 8795' MD / 5848' TVD, 85.24 deg inclination. 3S-08CL1: is a CTD sidetrack, belogs to 3S-08C mother bore 7" casing cement as per 3S- 08C. 3S-08CL1PB1: is a CTD sidetrack that was plugged back entirely with cement, belogs to 3S- 08C mother bore, 7" casing cement as per 3S-08C. 3S-701A: The 7-5/8” casing cement report on 1/20/2023 shows that the job was pumped as designed, indicating competent cementing operations. The first stage cement job was pumped with 77 barrels of 15.3 ppg. The plug was bumped and the floats held. A cement bond log indicates competent cement with a cement top @ 6,800’ MD (3,723’ TVD). 3S-704: The 7-5/8” casing cement report on 1/20/2023 shows that the job was pumped as designed, indicating competent cementing operations. Pump 59 BBLS 12.5 PPG spacer , drop bottom plug , pump 62.5 BBLS 15.3 lead CMT Bridgemaker II LCM in the first 41 BBLS , drop top plug , pump 10 BBLS H2O , chase with 319.5 BBLS 9.6 PPG mud . plugs bump at 319.5 BBLS 3170 STKS , pressure up 500 over T/1300 F/5 min , bleed off check floats, No losses. The 7-5/8" Intermediate Cement was Logged with sonicscope. TOC identified at 6000 ft. 3S-620: The 7-5/8” casing cement report on 2/16/2015 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 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. 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 first stage cement job was pumped with 264 barrels of 15.3ppg lead cement and 33 barrels of 15.3ppg tail cement. 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 to 21 barrels during the job. Cement floats jpp cement bond lo g , Logged with sonicscope held. A cement bond log indicates competent cement with a cement top @ 7,850’ MD (3,970’ TVD). 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). 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 BMII. The plug did not bumped, 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). 3S-18: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-18. Several cement plugs were pumped starting May 2023, including a cement squeeze of the surface casing from 2840 ft to surface with 104 bbls of 15.8 ppg Class G Cement in the OA. Last cement plug was pumped on February 2024, completing the P&A of this well with cement all the way to surface. PALM 1: Three abandonment cement plugs were pumped in Palm 1 on 02/21/2001. First plug at 5900-6620 ft with class G 15.8 ppg cement and Second plg at 5880-5200 with class G 15.8 ppg cement, tagged cement at 5247 ft, final abandonment plug at 4700-4100 ft with class G 15.8 ppg cement. https://ogc-docs.commerce.alaska.gov/weblink/0/doc/18739/Page1.aspx" 3S-22: 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.The P&A of this well included a perf/wash/cementing operation. A CIBP was set at 5467', the casing was then perforate at 5291-5441', ~68 bbls of cement was pumped leaving cement ~150' above the perfs inside casing. The cement was then cleaned out inside casing and a CBL was run to confirm cement in the OHxCasing annulus 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 4/12/2023 and completing the Plug and Abandonment on 9/25/2023 The top cement job was performed on 9/5/2023. The casing was cemented to surface. 3S-21:The 7” intermediate was cemented on 3/31/2003 with 36 bbls 15.8 ppg Class “G”, plug was bumped, slight returns. Calculated cement top at 7,719’ MD. The well was P&A’d in 2022: 8/12/2022, Set retainer at 9,200’, pumped 25.4 bbls of 15.8 ppg cement. 16.4 bbls below retainer, 9 bbls above 9/12/2022, Casing perforated at 6,332’-6,482’, cement with 36 bbls 15.8 ppg. 10/14/2022, 90 bbls 15.8 ppg Class “G” was pumped in OA with the cement top at surface. 10/17/2022, 250 BBLs of 15.8 ppg Class G Cement laid from 6500' to surface in production casing. 3S-23:The 7” casing cement report on 4/18/2003 shows 53.5 bbls 15.8 ppg Class “G” was pumped. Good returns throughout job" pg p cement bond log CBL cement bond log pg cement bond log 3S-24:The 7” casing cement report on 6/3/2003 shows a lead of 75 bbls of Lite Crete cement was pumped at 4 bpm. Full returns throughout the job and the floats held. A 3-1/2” production liner was run and cemented 198 bbls of 15.8ppg cement, full returns until 52 bbls from end of cement job. Bumped the plug and floats held. " 3S-24A: This well was a sidetrack from the 3S-24, sidetracked at 10,509’ MD in 2004. A 3- 1/2” liner was run and cemented with 88 bbls of 15.8ppg Clas “G”. Full returns throughout job, the plug bumped and the floats held." 3S-701: 1/11/2023 - Pumped 208 bbls of 15.3ppg cement, no losses during the cement job. Once unlatched, started circulating at 3370' MD, dumped 204 bbls of contaminated mud 3S-626PB1: The 7-5/8” casing cement report on 4/25/2024 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 183 bbls of 15.3 ppg cement. The plug bumped and floats held. A cement bond log run on 04/27/24 indicates competent cement with cement top at 4523’ MD/3179’ TVD. 3S-23A: This well was a sidetrack from the 3S-23, sidetracked at 4,090’ MD. The 7” casing cement report on 5/9/2006 shows the 43 bbls of 15.8 ppg Class “G” cement was pumped. Approximately 10-15% returns during the job and the plug did not bump. Calculated top of cement at 9,471’ (10,491’ TD)." 3S-03:The 7” production liner was cemented 53.3 bbls (256 sxs) 15.8ppg Class “G”. Plug was bumped and the floats held. Calculated cement top at 2,805’ KB" 3S-19: 7” casing cement pump report on 7/2/2003 shows that job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg Class G Cement, displaced with seawater. The plug bumped at 2000psi, and the floats were checked and they held. CBL conducted on 12/22/2012 from 9170ft to surface. CBL log indicates good to fair cement from 9170ft to 7350ftMD. 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 5908’ MD/3775’ TVD. jp cement bond log CBL ppg A cement bond log 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 one fault transects the Coyote reservoir within one half mile radius of the 3S-714 wellbore trajectory. This fault may intersect the 3S-714 wellbore trajectory at ~11,206’ MD. This fault is interpreted to have minimal throw at this location (< 5 feet). This fault has a presumed NW – SE strike and is downthrown to the NE. It is in line with the projection of the fault that was encountered at the heel of the offset 3S-704 Coyote well. There is no mapped offset based on seismic in the area where this fault projects to intersect the 3S-714 wellbore. The interpreted fault should not affect overburden integrity and therefore its 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) 3S-626 was completed in 2024 as a horizontal producer in the Torok formation. The well was completed with a 4.5” tubing upper completion and a 4.5” liner with a ball-actuated sliding sleeve and plug-actuated sliding sleeve lower completion. The first stage will be pumped through a toe initiator valve in the toe of the lateral. After the 1st stage frac balls will be dropped to shift open the 2nd stage sleeve and isolate the first stage. The 2nd stage will then be pumped and a third ball drop (progressively getting larger) after each remaining stage, these balls will provide isolation from the previous stage and allow fracturing from the toe of the well towards the heel. The last three stages will be opened by the plug (Interra’s dissolvable plug). 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 2326’ MD/ 2197’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 24 clean insulated Frac tanks (450 bbls usable volume per tank), with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100ºF treated produced water (approx. 1,130 to 3,350 barrels are required for each stage with breakdown, maximum pad and pumping down the next ball) [Contingency: Seawater – the chemical concentrations will be adjusted. See the attached chemical disclosures for both options]. 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. Perform DFIT after opening the Alpha Sleeve according to the attached pump schedule. Ensure sufficient volume is pumped to load the well with Frac fluid, prior to shut down. Resume pumping to pump Frac Stage 1. 11. Perform minifrac test after opening the frac sleeve for Stage 2. Resume pumping to pump Frac Stage 2. 12. Pump Frac Stages 3 through 20 by following attached pump schedule at 20-22 bpm with a maximum expected treating pressure of 8,500 psi. 13. The well is ready for Post Frac well prep/production tree installation and flowback (after Slickline and Coiled Tubing Cleanout). Patina tracers Will be pumped in the toe and Resmetrics oil and gas tracers will be pumped in remaining stages. See Halliburton chemical disclosure sheet which includes this other chemicals. Max. surface pressure of 7636 psi. CDW 03/10/2025. p 8,500 psi. Frac Model Result: SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) Flowback will be initiated through a de-sander unit until the fluids clean up at which time it will be turned over to production for initial clean up production. 02/07/2025 15:52:12 Cementing Job Report CemCAT v1.7 Well 3S-714 Field GPB Engineer DCole Country United States Client CPAI SIR No. 1054111.01.13 Job Type INT 1 Job Date 02-07-2025 Time 02/07/2025 06:25:17 02/07/2025 11:05:30 hh:mm:ss 06:25:17 06:45:00 07:05:00 07:25:00 07:45:00 08:05:00 08:25:00 08:45:00 09:05:00 09:25:00 09:45:00 10:05:00 10:25:00 10:45:00 11:05:30 11:05:30 Pressure PSI 0.00 1000 2000 3000 4000 5000 Density LB/G 5.0 9.0 13.0 17.0 21.0 25.0 Rate B/M 0.00 2.0 4.0 6.0 8.0 10.0 WHP PSI 0.00 1000 2000 3000 4000 5000 Messages rate checks good PJSM Start Job Water Ahead Low PT Check Trips High PT #4000 Reset Total, Vol = 5 bbl Batching CMT Rig dropped 1st plug Rigged pumped Spacer rigged dropped 2nd bottom plug Start Cement Slurry End Cement Slurry Loading Top Plug Reset Total, Vol = 57 bbl Water Behind End Water Behind Reset Total, Vol = 10 bbl Swap to rig for Displacment CMT @ shoe Bumped 2873 stks Checked Floats, Good End Job Stopped Acquisition Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Location (legal) Kuparuk Schlumberger Location Job Start Feb/07/2025 Field GPB Formation Name/Type Deviation deg Bit Size 9.9 in Well MD 6650.0 ft Well TVD 4123.0 ft County State/Province Alaska Well Master API/UWI BHP psi BHST 82 degF BHCT 65 degF Pore Press. Gradient lb/gal Rig Name D25 Drilled For Service Via Land Offshore Zone Well Class Well Type Drilling Fluid Type Max. Density lb/gal Plastic Viscosity cP Service Line Cementing Job Type INT 1 Max. Allowed Tub. Press psi Max. Allowed Ann. Press psi WH Connection Service Instructions Pump, Silo, Batchmixer, Compressor Treat Down Casing Displacement 300.0 bbl Packer Type Packer Depth ft Tubing Vol. bbl Casing Vol. 305.0 bbl Annular Vol. bbl Openhole Vol. bbl Casing/Tubing Secured 1 Hole Vol. Circulated prior to Cement X Casing Tools Squeeze Job Lift Pressure psi Shoe Type Float Squeeze Type Pipe Rotated Pipe Reciprocated Shoe Depth 6640.0 ft Tool Type No. Centralizers 66 Top Plugs 1 Bottom Plugs 2 Stage Tool Type Tool Depth ft Cement Head Type Stage Tool Depth ft Tail Pipe Size in Job Scheduled For Feb/07/2025 Arrived on Location Feb/07/2025 Leave Location Feb/07/2025 Collar Type Float Tail Pipe Depth ft Collar Depth 6541.0 ft Sqz. Total Vol. bbl Casing/Liner Depth, ft Size, in Weight, lb/ft Grade Thread 5540.0 7.6 29.7 6640.0 7.6 33.7 Tubing/Drill Pipe T/D Depth, ft Size, in Weight, lb/ft Grade Thread Perforations/Open Hole Top, ft Bottom, ft shot/ft No. of Shots Total Interval ft ft ft ft ft Diameter in ft ft Cementing Service Report Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 06:25:17 -17 3.19 0.0 0.0 0.0 117 Started Acquisition 02/07/2025 06:26:17 -15 2.21 3.0 2.0 2.0 116 02/07/2025 06:27:17 -40 1.82 0.0 3.1 3.1 114 02/07/2025 06:28:17 -15 -0.00 3.0 4.7 4.7 104 02/07/2025 06:29:06 -63 0.00 0.0 6.1 6.1 98 rate checks good 02/07/2025 06:29:17 -63 0.00 0.0 6.1 6.1 106 02/07/2025 06:30:17 -70 -0.00 0.0 6.1 6.1 109 02/07/2025 06:31:17 -76 0.01 0.0 6.1 6.1 101 02/07/2025 06:32:17 -68 0.00 0.0 6.1 6.1 84 02/07/2025 06:33:17 -67 0.00 0.0 6.1 6.1 63 02/07/2025 06:34:17 -65 -0.00 0.0 6.1 6.1 89 02/07/2025 06:35:17 -77 0.00 0.0 6.1 6.1 89 02/07/2025 06:36:17 -77 0.01 0.0 6.1 6.1 91 02/07/2025 06:37:17 -78 0.00 0.0 6.1 6.1 92 02/07/2025 06:38:17 -74 0.00 0.0 6.1 6.1 92 02/07/2025 06:39:17 -80 0.00 0.0 6.1 6.1 83 02/07/2025 06:40:17 -66 -0.00 0.0 6.1 6.1 82 02/07/2025 06:41:17 -68 0.00 0.0 6.1 6.1 84 02/07/2025 06:42:17 -68 0.00 0.0 6.1 6.1 79 02/07/2025 06:43:17 -79 0.00 0.0 6.1 6.1 84 02/07/2025 06:44:17 -68 0.00 0.0 6.1 6.1 80 Page 1 of 7 Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Location (legal) Kuparuk Schlumberger Location Job Start Feb/07/2025 Field GPB Formation Name/Type Deviation deg Bit Size 9.9 in Well MD 6650.0 ft Well TVD 4123.0 ft County State/Province Alaska Well Master API/UWI BHP psi BHST 82 degF BHCT 65 degF Pore Press. Gradient lb/gal Rig Name D25 Drilled For Service Via Land Offshore Zone Well Class Well Type Drilling Fluid Type Max. Density lb/gal Plastic Viscosity cP Service Line Cementing Job Type INT 1 Max. Allowed Tub. Press psi Max. Allowed Ann. Press psi WH Connection Service Instructions Pump, Silo, Batchmixer, Compressor Treat Down Casing Displacement 300.0 bbl Packer Type Packer Depth ft Tubing Vol. bbl Casing Vol. 305.0 bbl Annular Vol. bbl Openhole Vol. bbl Casing/Tubing Secured 1 Hole Vol. Circulated prior to Cement X Casing Tools Squeeze Job Lift Pressure psi Shoe Type Float Squeeze Type Pipe Rotated Pipe Reciprocated Shoe Depth 6640.0 ft Tool Type No. Centralizers 66 Top Plugs 1 Bottom Plugs 2 Stage Tool Type Tool Depth ft Cement Head Type Stage Tool Depth ft Tail Pipe Size in Job Scheduled For Feb/07/2025 Arrived on Location Feb/07/2025 Leave Location Feb/07/2025 Collar Type Float Tail Pipe Depth ft Collar Depth 6541.0 ft Sqz. Total Vol. bbl Casing/Liner Depth, ft Size, in Weight, lb/ft Grade Thread 5540.0 7.6 29.7 6640.0 7.6 33.7 Tubing/Drill Pipe T/D Depth, ft Size, in Weight, lb/ft Grade Thread Perforations/Open Hole Top, ft Bottom, ft shot/ft No. of Shots Total Interval ft ft ft ft ft Diameter in ft ft Cementing Service Report Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 06:46:17 -75 0.01 0.0 6.1 6.1 80 02/07/2025 06:47:17 -72 0.00 0.0 6.1 6.1 82 02/07/2025 06:48:17 -81 0.00 0.0 6.1 6.1 86 02/07/2025 06:49:17 -76 0.00 0.0 6.1 6.1 87 02/07/2025 06:50:17 -78 0.00 0.0 6.1 6.1 93 02/07/2025 06:51:17 -76 0.00 0.0 6.1 6.1 97 02/07/2025 06:52:17 -72 -0.00 0.0 6.1 6.1 90 02/07/2025 06:53:17 -71 -0.00 0.0 6.1 6.1 87 02/07/2025 06:54:17 -72 -0.00 0.0 6.1 6.1 90 02/07/2025 06:55:17 -72 0.00 0.0 6.1 6.1 91 02/07/2025 06:56:17 -77 0.01 0.0 6.1 6.1 95 02/07/2025 06:57:17 -77 0.00 0.0 6.1 6.1 96 02/07/2025 06:58:17 -73 0.02 0.0 6.1 6.1 107 02/07/2025 06:59:17 -82 0.00 0.0 6.1 6.1 100 02/07/2025 07:00:17 -79 0.00 0.0 6.1 6.1 94 02/07/2025 07:01:17 -80 -0.00 0.0 6.1 6.1 94 02/07/2025 07:02:17 -80 0.00 0.0 6.1 6.1 94 02/07/2025 07:03:17 -78 0.00 0.0 6.1 6.1 92 02/07/2025 07:04:17 -82 -0.00 0.0 6.1 6.1 93 02/07/2025 07:05:17 -86 0.00 0.0 6.1 6.1 92 02/07/2025 07:06:17 -81 0.00 0.0 6.1 6.1 84 02/07/2025 07:07:17 -82 0.00 0.0 6.1 6.1 88 02/07/2025 07:08:17 -84 0.00 0.0 6.1 6.1 91 02/07/2025 07:09:17 -81 -0.00 0.0 6.1 6.1 64 02/07/2025 07:10:17 -84 0.01 0.0 6.1 6.1 134 02/07/2025 07:11:17 -83 -0.00 0.0 6.1 6.1 117 02/07/2025 07:12:17 -82 -0.00 0.0 6.1 6.1 65 02/07/2025 07:13:17 -83 -0.00 0.0 6.1 6.1 64 02/07/2025 07:14:17 -83 -0.00 0.0 6.1 6.1 62 02/07/2025 07:15:17 -83 -0.00 0.0 6.1 6.1 63 02/07/2025 07:16:17 -84 0.00 0.0 6.1 6.1 61 02/07/2025 07:17:17 -82 -0.00 0.0 6.1 6.1 64 02/07/2025 07:18:17 -82 0.00 0.0 6.1 6.1 61 02/07/2025 07:19:17 -82 0.00 0.0 6.1 6.1 62 02/07/2025 07:20:17 -82 0.00 0.0 6.1 6.1 64 02/07/2025 07:21:17 -85 0.00 0.0 6.1 6.1 63 02/07/2025 07:22:17 -84 0.00 0.0 6.1 6.1 60 02/07/2025 07:23:17 -83 0.00 0.0 6.1 6.1 113 02/07/2025 07:24:17 -82 0.00 0.0 6.1 6.1 185 02/07/2025 07:25:17 -34 2.04 0.0 6.1 6.1 195 02/07/2025 07:26:17 -75 1.90 0.0 6.1 6.1 196 02/07/2025 07:27:17 -70 -0.00 0.0 6.1 6.1 212 02/07/2025 07:28:17 -78 -0.00 0.0 6.1 6.1 219 02/07/2025 07:29:17 -74 -0.00 0.0 6.1 6.1 212 02/07/2025 07:30:17 -80 0.00 0.0 6.1 6.1 214 02/07/2025 07:31:17 -74 1.71 0.0 6.1 6.1 234 02/07/2025 07:32:17 -75 0.00 0.0 6.1 6.1 235 02/07/2025 07:33:17 -82 0.00 0.0 6.1 6.1 237 02/07/2025 07:34:17 -89 0.00 0.0 6.1 6.1 246 02/07/2025 07:35:17 -86 0.00 0.0 6.1 6.1 262 02/07/2025 07:36:17 -81 -0.00 0.0 6.1 6.1 262 02/07/2025 07:37:17 -81 -0.00 0.0 6.1 6.1 269 02/07/2025 07:38:17 -81 -0.00 0.0 6.1 6.1 281 02/07/2025 07:39:17 -80 0.00 0.0 6.1 6.1 284 Page 2 of 7 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 07:41:17 -82 0.00 0.0 6.1 6.1 310 02/07/2025 07:42:17 -80 0.00 0.0 6.1 6.1 319 02/07/2025 07:43:17 -82 -0.00 0.0 6.1 6.1 329 02/07/2025 07:44:17 -79 0.00 0.0 6.1 6.1 341 02/07/2025 07:45:17 -76 0.00 0.0 6.1 6.1 346 02/07/2025 07:46:17 -78 0.00 0.0 6.1 6.1 373 02/07/2025 07:47:17 -78 -0.00 0.0 6.1 6.1 372 02/07/2025 07:48:17 -80 0.01 0.0 6.1 6.1 366 02/07/2025 07:49:17 -79 -0.00 0.0 6.1 6.1 384 02/07/2025 07:50:17 -79 0.00 0.0 6.1 6.1 417 02/07/2025 07:51:17 -81 -0.00 0.0 6.1 6.1 408 02/07/2025 07:52:17 -82 0.00 0.0 6.1 6.1 414 02/07/2025 07:53:17 -79 0.00 0.0 6.1 6.1 410 02/07/2025 07:54:17 -79 0.00 0.0 6.1 6.1 419 02/07/2025 07:55:17 -79 0.00 0.0 6.1 6.1 409 02/07/2025 07:56:17 -82 0.00 0.0 6.1 6.1 451 02/07/2025 07:57:17 -82 -0.00 0.0 6.1 6.1 435 02/07/2025 07:58:17 -80 0.00 0.0 6.1 6.1 451 02/07/2025 07:59:17 -78 0.00 0.0 6.1 6.1 441 02/07/2025 08:00:17 -82 -0.00 0.0 6.1 6.1 502 02/07/2025 08:01:17 -78 0.00 0.0 6.1 6.1 498 02/07/2025 08:02:17 -80 0.00 0.0 6.1 6.1 506 02/07/2025 08:03:17 -82 0.00 0.0 6.1 6.1 510 02/07/2025 08:04:17 -80 0.00 0.0 6.1 6.1 515 02/07/2025 08:05:17 -81 -0.00 0.0 6.1 6.1 558 02/07/2025 08:06:17 -82 -0.00 0.0 6.1 6.1 538 02/07/2025 08:07:17 -80 0.00 0.0 6.1 6.1 534 02/07/2025 08:08:17 -80 0.00 0.0 6.1 6.1 553 02/07/2025 08:09:17 -80 -0.00 0.0 6.1 6.1 574 02/07/2025 08:10:17 -82 0.00 0.0 6.1 6.1 572 02/07/2025 08:11:17 -78 0.00 0.0 6.1 6.1 565 02/07/2025 08:12:17 -78 0.00 0.0 6.1 6.1 551 02/07/2025 08:13:17 -82 0.00 0.0 6.1 6.1 569 02/07/2025 08:14:17 -81 -0.00 0.0 6.1 6.1 578 02/07/2025 08:15:17 -79 -0.00 0.0 6.1 6.1 573 02/07/2025 08:16:17 -80 0.00 0.0 6.1 6.1 601 02/07/2025 08:17:17 -81 0.00 0.0 6.1 6.1 563 02/07/2025 08:18:17 -59 0.00 0.0 6.1 6.1 578 02/07/2025 08:19:17 -64 0.00 0.0 6.1 6.1 542 02/07/2025 08:20:17 -76 0.00 0.0 6.1 6.1 528 02/07/2025 08:21:17 -78 -0.01 0.0 6.1 6.1 537 02/07/2025 08:22:17 -72 -0.00 0.0 6.1 6.1 502 02/07/2025 08:23:17 -73 0.00 0.0 6.1 6.1 509 02/07/2025 08:24:17 -74 -0.00 0.0 6.1 6.1 470 02/07/2025 08:25:17 -71 0.00 0.0 6.1 6.1 455 02/07/2025 08:26:17 -74 -0.00 0.0 6.1 6.1 451 02/07/2025 08:27:17 -74 0.01 0.0 6.1 6.1 450 02/07/2025 08:27:55 -71 0.00 0.0 0.0 0.0 433 PJSM 02/07/2025 08:28:02 -72 0.00 0.0 0.0 0.0 438 Start Job 02/07/2025 08:28:17 -71 0.00 0.0 0.0 0.0 423 02/07/2025 08:29:17 -73 0.00 0.0 0.0 0.0 421 02/07/2025 08:30:17 -73 0.00 0.0 0.0 0.0 393 02/07/2025 08:31:17 -73 -0.00 0.0 0.0 0.0 370 02/07/2025 08:32:17 -74 0.00 0.0 0.0 0.0 382 Page 3 of 7 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 08:34:17 -74 0.00 0.0 0.0 0.0 359 02/07/2025 08:35:17 -77 0.00 0.0 0.0 0.0 352 02/07/2025 08:36:17 -74 -0.00 0.0 0.0 0.0 328 02/07/2025 08:37:17 -72 -0.00 0.0 0.0 0.0 328 02/07/2025 08:38:17 -76 -0.00 0.0 0.0 0.0 327 02/07/2025 08:39:17 -76 0.00 0.0 0.0 0.0 320 02/07/2025 08:40:17 -74 0.00 0.0 0.0 0.0 320 02/07/2025 08:41:17 -72 0.00 0.0 0.0 0.0 312 02/07/2025 08:42:17 -73 0.00 0.0 0.0 0.0 299 02/07/2025 08:43:17 -78 -0.00 0.0 0.0 0.0 296 02/07/2025 08:44:17 -74 0.00 0.0 0.0 0.0 228 02/07/2025 08:45:17 -74 -0.00 0.0 0.0 0.0 83 02/07/2025 08:46:17 -74 -0.00 0.0 0.0 0.0 126 02/07/2025 08:47:17 -76 0.00 0.0 0.0 0.0 149 02/07/2025 08:48:17 -77 0.00 0.0 0.0 0.0 150 02/07/2025 08:49:17 -73 -0.00 0.0 0.0 0.0 299 02/07/2025 08:50:17 -76 -0.00 0.0 0.0 0.0 306 02/07/2025 08:51:17 -74 -0.00 0.0 0.0 0.0 296 02/07/2025 08:52:17 -76 0.00 0.0 0.0 0.0 82 02/07/2025 08:53:17 -76 0.00 0.0 0.0 0.0 264 02/07/2025 08:54:17 -74 0.00 0.0 0.0 0.0 302 02/07/2025 08:55:17 -73 0.00 0.0 0.0 0.0 296 02/07/2025 08:56:17 -76 0.00 0.0 0.0 0.0 294 02/07/2025 08:57:17 -75 -0.00 0.0 0.0 0.0 53 02/07/2025 08:58:17 -77 0.00 0.0 0.0 0.0 54 02/07/2025 08:59:17 -74 -0.00 0.0 0.0 0.0 53 02/07/2025 09:00:17 -66 -0.00 0.0 0.0 0.0 52 02/07/2025 09:01:17 -63 -0.00 0.0 0.0 0.0 51 02/07/2025 09:02:17 -73 0.00 0.0 0.0 0.0 50 02/07/2025 09:03:17 -74 0.00 0.0 0.0 0.0 55 02/07/2025 09:04:08 -76 0.01 0.0 0.0 0.0 53 Water Ahead 02/07/2025 09:04:17 -79 -0.00 0.0 0.0 0.0 49 02/07/2025 09:05:17 -45 0.00 1.6 0.6 0.6 69 02/07/2025 09:06:17 -1 -0.00 2.3 2.5 2.5 71 02/07/2025 09:07:17 -7 2.70 2.3 4.8 4.8 66 02/07/2025 09:08:01 -2 0.00 0.0 5.1 5.1 56 Low PT Check Trips 02/07/2025 09:08:17 1 0.00 0.8 5.1 5.1 58 02/07/2025 09:09:02 676 0.00 0.0 5.2 5.2 735 High PT #4000 02/07/2025 09:09:17 1295 0.00 0.1 5.2 5.2 1362 02/07/2025 09:10:17 4080 -0.00 0.0 5.2 5.2 4119 02/07/2025 09:11:17 1322 0.00 0.0 5.2 5.2 1324 02/07/2025 09:11:27 -12 0.00 0.0 5.2 5.2 54 Reset Total, Vol = 5 bbl 02/07/2025 09:12:17 -18 -0.00 0.0 0.0 5.2 54 02/07/2025 09:13:17 -17 -0.00 0.0 0.0 5.2 56 02/07/2025 09:14:17 -13 0.00 0.0 0.0 5.2 90 02/07/2025 09:15:17 227 0.00 0.0 0.0 5.2 213 02/07/2025 09:16:17 213 8.14 0.0 0.0 5.2 200 02/07/2025 09:17:03 209 8.95 0.0 0.0 5.2 189 Batching CMT 02/07/2025 09:17:17 217 10.44 0.0 0.0 5.2 187 02/07/2025 09:18:17 230 15.12 0.0 0.0 5.2 185 02/07/2025 09:19:17 229 15.89 0.0 0.0 5.2 172 02/07/2025 09:20:17 232 15.56 0.0 0.0 5.2 163 02/07/2025 09:21:17 230 15.57 0.0 0.0 5.2 145 02/07/2025 09:22:17 230 15.54 0.0 0.0 5.2 144 Page 4 of 7 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 09:23:43 227 15.54 0.0 0.0 5.2 139 Rig dropped 1st plug 02/07/2025 09:24:01 225 15.54 0.0 0.0 5.2 144 Rigged pumped Spacer 02/07/2025 09:24:17 225 15.54 0.0 0.0 5.2 99 02/07/2025 09:25:17 223 15.54 0.0 0.0 5.2 91 02/07/2025 09:26:17 225 15.54 0.0 0.0 5.2 88 02/07/2025 09:27:17 219 15.53 0.0 0.0 5.2 87 02/07/2025 09:28:17 220 15.54 0.0 0.0 5.2 53 02/07/2025 09:29:17 228 15.53 0.0 0.0 5.2 54 02/07/2025 09:30:17 217 15.52 0.0 0.0 5.2 52 02/07/2025 09:30:18 219 15.53 0.0 0.0 5.2 51 rigged dropped 2nd bottom plug 02/07/2025 09:31:17 223 15.52 0.0 0.0 5.2 49 02/07/2025 09:32:17 213 15.53 0.0 0.0 5.2 50 02/07/2025 09:33:01 211 15.48 0.0 0.0 5.2 52 Start Cement Slurry 02/07/2025 09:33:17 62 15.48 0.0 0.0 5.2 78 02/07/2025 09:34:17 201 15.52 2.7 2.1 7.3 104 02/07/2025 09:35:17 294 15.48 3.7 5.4 10.6 131 02/07/2025 09:36:17 401 15.13 4.0 9.3 14.5 155 02/07/2025 09:37:17 304 15.34 4.0 13.3 18.5 111 02/07/2025 09:38:17 445 15.37 4.0 17.2 22.4 160 02/07/2025 09:39:17 247 15.32 4.0 21.2 26.4 97 02/07/2025 09:40:17 256 15.41 3.7 24.9 30.1 103 02/07/2025 09:41:17 423 15.54 4.0 28.1 33.3 151 02/07/2025 09:42:17 210 15.54 3.0 32.4 37.6 97 02/07/2025 09:43:17 409 15.30 4.0 35.5 40.7 147 02/07/2025 09:44:17 423 15.55 4.0 39.5 44.7 151 02/07/2025 09:45:17 415 15.66 4.0 43.5 48.7 145 02/07/2025 09:46:17 205 15.32 2.7 46.5 51.7 102 02/07/2025 09:47:17 198 15.15 2.7 49.2 54.4 102 02/07/2025 09:48:17 214 15.33 2.7 51.9 57.1 104 02/07/2025 09:49:17 202 15.40 2.7 54.6 59.8 102 02/07/2025 09:50:17 53 15.40 1.6 56.9 62.1 78 02/07/2025 09:50:45 -21 15.35 0.0 57.0 62.2 59 End Cement Slurry 02/07/2025 09:50:59 -19 15.34 0.0 57.0 62.2 58 Loading Top Plug 02/07/2025 09:51:17 -20 15.34 0.0 57.0 62.2 55 Reset Total, Vol = 57 bbl 02/07/2025 09:52:17 23 15.40 0.0 0.0 62.2 56 02/07/2025 09:53:17 58 9.86 0.0 0.0 62.2 54 02/07/2025 09:54:17 52 9.82 0.0 0.0 62.2 57 02/07/2025 09:55:17 50 9.83 0.0 0.0 62.2 54 02/07/2025 09:55:42 46 9.83 0.0 0.0 62.2 55 Water Behind 02/07/2025 09:56:17 279 9.86 3.7 0.7 62.8 155 02/07/2025 09:57:17 207 9.01 4.0 4.6 66.8 88 02/07/2025 09:58:17 195 8.65 4.0 8.6 70.7 87 02/07/2025 09:59:03 13 6.75 0.0 10.0 72.2 50 End Water Behind 02/07/2025 09:59:13 4 6.28 0.0 10.0 72.2 52 Reset Total, Vol = 10 bbl 02/07/2025 09:59:17 1 6.15 0.0 0.0 72.2 52 02/07/2025 09:59:30 12 6.58 0.0 0.0 72.2 74 Swap to rig for Displacment 02/07/2025 10:00:17 51 8.67 0.0 0.0 72.2 80 02/07/2025 10:01:17 61 10.05 0.0 0.0 72.2 229 02/07/2025 10:02:17 55 10.14 0.0 0.0 72.2 235 02/07/2025 10:03:17 56 10.14 0.0 0.0 72.2 202 02/07/2025 10:04:17 60 10.14 0.0 0.0 72.2 201 02/07/2025 10:05:17 -18 9.93 0.0 0.0 72.2 193 02/07/2025 10:06:17 64 9.51 0.0 0.0 72.2 197 02/07/2025 10:07:17 -6 9.12 0.0 0.0 72.2 200 Page 5 of 7 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 10:09:17 18 8.83 0.0 0.0 72.2 195 02/07/2025 10:10:17 42 8.40 0.0 0.0 72.2 201 02/07/2025 10:11:17 34 8.43 0.0 0.0 72.2 206 02/07/2025 10:12:17 31 8.44 0.0 0.0 72.2 198 02/07/2025 10:13:17 28 8.48 0.0 0.0 72.2 205 02/07/2025 10:14:17 -23 8.23 0.0 0.0 72.2 210 02/07/2025 10:15:17 -24 7.56 0.0 0.0 72.2 206 02/07/2025 10:16:17 -22 7.11 0.0 0.0 72.2 209 02/07/2025 10:17:17 23 8.28 0.0 0.0 72.2 217 02/07/2025 10:18:17 -20 8.13 0.0 0.0 72.2 217 02/07/2025 10:19:17 -23 7.76 0.0 0.0 72.2 213 02/07/2025 10:20:17 54 7.64 0.0 0.0 72.2 223 02/07/2025 10:21:17 -24 7.72 0.0 0.0 72.2 225 02/07/2025 10:22:17 -20 7.44 0.0 0.0 72.2 212 02/07/2025 10:23:17 -12 7.20 0.0 0.0 72.2 239 02/07/2025 10:24:17 4 7.80 0.0 0.0 72.2 234 02/07/2025 10:25:17 45 7.83 0.0 0.0 72.2 218 02/07/2025 10:26:17 -23 6.93 0.0 0.0 72.2 224 02/07/2025 10:27:17 -11 6.57 0.0 0.0 72.2 218 02/07/2025 10:28:17 -21 7.02 0.0 0.0 72.2 213 02/07/2025 10:29:17 35 7.32 0.0 0.0 72.2 214 02/07/2025 10:30:17 -29 8.27 0.0 0.0 72.2 229 02/07/2025 10:31:17 -32 8.27 0.0 0.0 72.2 242 02/07/2025 10:32:17 -25 8.12 0.0 0.0 72.2 241 02/07/2025 10:33:17 16 7.31 0.0 0.0 72.2 265 02/07/2025 10:34:17 -24 6.94 0.0 0.0 72.2 310 02/07/2025 10:35:17 -31 6.28 0.0 0.0 72.2 296 02/07/2025 10:36:17 30 7.12 0.0 0.0 72.2 331 02/07/2025 10:37:17 1 7.69 0.0 0.0 72.2 331 02/07/2025 10:38:17 -25 6.68 0.0 0.0 72.2 336 02/07/2025 10:39:17 -29 8.27 0.0 0.0 72.2 61 02/07/2025 10:40:17 -28 8.30 0.0 0.0 72.2 393 02/07/2025 10:41:17 -30 8.30 0.0 0.0 72.2 402 02/07/2025 10:41:57 -30 8.31 0.0 0.0 72.2 416 CMT @ shoe 02/07/2025 10:42:17 -30 8.32 0.0 0.0 72.2 425 02/07/2025 10:43:17 -31 7.94 0.0 0.0 72.2 477 02/07/2025 10:44:17 42 7.89 0.0 0.0 72.2 507 02/07/2025 10:45:17 48 8.07 0.0 0.0 72.2 540 02/07/2025 10:46:17 49 8.10 0.0 0.0 72.2 569 02/07/2025 10:47:17 -19 7.29 0.0 0.0 72.2 396 02/07/2025 10:48:17 14 7.06 0.0 0.0 72.2 426 02/07/2025 10:49:17 -31 6.84 0.0 0.0 72.2 431 02/07/2025 10:50:17 -33 6.74 0.0 0.0 72.2 698 02/07/2025 10:50:58 -32 6.72 0.0 0.0 72.2 833 Bumped 2873 stks 02/07/2025 10:51:17 -31 6.70 0.0 0.0 72.2 1411 02/07/2025 10:52:17 -21 6.73 0.0 0.0 72.2 1967 02/07/2025 10:53:17 3 6.77 0.0 0.0 72.2 1954 02/07/2025 10:54:17 7 6.75 0.0 0.0 72.2 1903 02/07/2025 10:55:17 -29 6.74 0.0 0.0 72.2 58 02/07/2025 10:56:17 -33 6.73 0.0 0.0 72.2 55 02/07/2025 10:57:17 -29 6.72 0.0 0.0 72.2 53 02/07/2025 10:58:17 -32 6.71 0.0 0.0 72.2 54 02/07/2025 10:59:17 72 6.73 0.0 0.0 72.2 53 02/07/2025 11:00:17 49 8.09 0.0 0.0 72.2 52 Page 6 of 7 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 Date Time 24-hr clock Treating Pressure PSI Denisty LB/G Rate B/M Stage BBL TOT BBL WHP PSI Message 02/07/2025 11:01:17 64 8.16 0.0 0.0 72.2 51 02/07/2025 11:02:17 -31 3.12 0.0 0.0 72.2 55 02/07/2025 11:03:17 -33 1.67 0.0 0.0 72.2 56 02/07/2025 11:04:17 -33 0.00 0.0 0.0 72.2 56 02/07/2025 11:05:17 -31 -0.00 0.0 0.0 72.2 52 02/07/2025 11:05:27 -30 -0.01 0.0 0.0 0.0 53 End Job Post Job Summary Volume of Fluid Injected, bbl N2 Maximum Rate 4.7 Average Pump Rates, bbl/min Slurry 3.1 Mud Total Slurry 57.0 Mud 294.0 Spacer 60.0 N2 Treating Pressure Summary, psi Breakdown Fluid Maximum 4105 Final -31 Average 252 Bump Plug to 900 Breakdown Type Volume bbl Density lb/gal Avg. N2 Percent % Designed Slurry Volume 57.0 bbl Displacement 302.0 bbl Mix Water Temp 80 degF Cement Circulated to Surface?Volume bbl Washed Thru Perfs To ft Customer or Authorized Representative Schlumberger Supervisor DCole Circulation Lost Job Completed X -- Page 7 of 7 Post Job Summary Volume of Fluid Injected, bbl N2 Maximum Rate 4.7 Average Pump Rates, bbl/min Slurry 3.1 Mud Total Slurry 57.0 Mud 294.0 Spacer 60.0 N2 Treating Pressure Summary, psi Breakdown Fluid Maximum 4105 Final -31 Average 252 Bump Plug to 900 Breakdown Type Volume bbl Density lb/gal Avg. N2 Percent % Designed Slurry Volume 57.0 bbl Displacement 302.0 bbl Mix Water Temp 80 degF Cement Circulated to Surface?Volume bbl Washed Thru Perfs To ft Customer or Authorized Representative Schlumberger Supervisor DCole Circulation Lost Job Completed X -- Well 3S-714 3S-714 Field GPB Job Start Feb/07/2025 Customer CPAI Job Number 1054111.01.13 From:Ruysschaert, Rodrigo To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]RE: 3S-714 (PTD 224-151) Frac Sundry Submission Date:Wednesday, March 19, 2025 3:10:49 PM Attachments:image002.png Hi again, Is this the same fault that is mentioned as intersecting 3S-714 at about 11,206’ MD? It is possible, as the map view projection of the fault that intersects 3S-704 generally aligns with the fault/fracture seen in 3S-714. What is the vertical displacement along this fault? It is difficult to determine as there is no mapped seismic offset at the 3S-714 location. The estimate is 5 feet or less for the feature identified in the 3S-714 wellbore. It is possible that the feature in 3S-714 is a zero offset fracture. Does it penetrate into or through either the upper or lower confining layers for the Coyote reservoir? If so, please provide details. The feature does not show seismic offset at the top or base of the Coyote reservoir. What is the expected azimuth for the planned induced fractures in 3S-714? Fractures are expected to be longitudinal to the well. Will any of the induced fractures potentially intersect this fault? Based on expected hydraulic fracture length, We have spaced out the sleeves above and below the feature to ensure that the hydraulic fractures do not reach it. If so, will these constitute a risk to confining fracturing fluids to the planned fracturing interval? If so, what mitigation measures does CPAI plan to ensure fracturing fluids and future injection are confined to the Coyote reservoir? Regards, Rodrigo From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Wednesday, March 19, 2025 12:55 PM To: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]RE: 3S-714 (PTD 224-151) Frac Sundry 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. Rodrigo, In addition to my request attached below, while reviewing CPAI’s application I noticed an apparent fault (represented by a magenta-colored line) intersecting well 3SD-704 on CPAI’s Frac Lease Plat shown below. This fault appears to closely approach 3S-714. Questions: Is this the same fault that is mentioned as intersecting 3S-714 at about 11,206’ MD? What is the vertical displacement along this fault? Does it penetrate into or through either the upper or lower confining layers for the Coyote reservoir? If so, please provide details. What is the expected azimuth for the planned induced fractures in 3S-714? Will any of the induced fractures potentially intersect this fault? If so, will these constitute a risk to confining fracturing fluids to the planned fracturing interval? If so, what mitigation measures does CPAI plan to ensure fracturing fluids and future injection are confined to the Coyote reservoir? Thanks for Your Help and Be Well, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (OGC) Sent: Wednesday, March 19, 2025 12:13 PM To: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: 3S-714 (PTD 224-151) Frac Sundry Submission Thanks for your help with this Rodrigo. Could CPAI please provide a copy of the cement report or the daily operations summary the provide details for cementing of surface casing? Thanks Again and Be Well, Steve Davies AOGCC From: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Sent: Tuesday, March 4, 2025 4:26 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) 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. Some people who received this message don't often get email from rodrigo.ruysschaert@conocophillips.com. Learn why this is important <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Subject: RE: 3S-714 (PTD 224-151) Frac Sundry Submission All, Please find attached the supporting documents for the 3S-714 Frac Sundry. In the .zip file you will find a .las file that is a combined file for the surface, interm, and prod sections. Thanks, Rodrigo Ruysschaert | Completions Engineer | ConocoPhillips O: + 1 907-263-3709| M: +1 907-621-0671 | 700 G Street, ATO-1586, Anchorage, AK 99501 From: Ruysschaert, Rodrigo Sent: Tuesday, March 4, 2025 4:19 PM To: Loepp, Victoria T (OGC <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC <andrew.dewhurst@alaska.gov>; AOGCC Permitting (CED sponsored <aogcc.permitting@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Dodson, Kate <Kate.Dodson@conocophillips.com> Subject: 3S-714 (PTD 224-151) Frac Sundry Submission AOGCC team, Please find attached the 10-403 application for the 3S-714 Frac Sundry. I will send a separate email with supporting documents including logs. Let me know if you have any questions/concerns with the application. Thank you! Rodrigo Ruysschaert | Completions Engineer | ConocoPhillips O: + 1 907-263-3709| M: +1 907-621-0671 | 700 G Street, ATO-1586, Anchorage, AK 99501 From:Davies, Stephen F (OGC) To:"Ruysschaert, Rodrigo" Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC) Subject:RE: 3S-714 (PTD 224-151) Frac Sundry Submission Date:Wednesday, March 19, 2025 12:55:00 PM Attachments:image004.png Rodrigo, In addition to my request attached below, while reviewing CPAI’s application I noticed an apparent fault (represented by a magenta-colored line) intersecting well 3SD-704 on CPAI’s Frac Lease Plat shown below. This fault appears to closely approach 3S-714. Questions: Is this the same fault that is mentioned as intersecting 3S-714 at about 11,206’ MD? What is the vertical displacement along this fault? Does it penetrate into or through either the upper or lower confining layers for the Coyote reservoir? If so, please provide details. What is the expected azimuth for the planned induced fractures in 3S-714? Will any of the induced fractures potentially intersect this fault? If so, will these constitute a risk to confining fracturing fluids to the planned fracturing interval? If so, what mitigation measures does CPAI plan to ensure fracturing fluids and future injection are confined to the Coyote reservoir? Thanks for Your Help and Be Well, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (OGC) Sent: Wednesday, March 19, 2025 12:13 PM To: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: 3S-714 (PTD 224-151) Frac Sundry Submission Thanks for your help with this Rodrigo. Could CPAI please provide a copy of the cement report or the daily operations summary the provide details for cementing of surface casing? Thanks Again and Be Well, Steve Davies AOGCC From: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Sent: Tuesday, March 4, 2025 4:26 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) 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. Some people who received this message don't often get email from rodrigo.ruysschaert@conocophillips.com. Learn why this is important <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Subject: RE: 3S-714 (PTD 224-151) Frac Sundry Submission All, Please find attached the supporting documents for the 3S-714 Frac Sundry. In the .zip file you will find a .las file that is a combined file for the surface, interm, and prod sections. Thanks, Rodrigo Ruysschaert | Completions Engineer | ConocoPhillips O: + 1 907-263-3709| M: +1 907-621-0671 | 700 G Street, ATO-1586, Anchorage, AK 99501 From: Ruysschaert, Rodrigo Sent: Tuesday, March 4, 2025 4:19 PM To: Loepp, Victoria T (OGC <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC <andrew.dewhurst@alaska.gov>; AOGCC Permitting (CED sponsored <aogcc.permitting@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Dodson, Kate <Kate.Dodson@conocophillips.com> Subject: 3S-714 (PTD 224-151) Frac Sundry Submission AOGCC team, Please find attached the 10-403 application for the 3S-714 Frac Sundry. I will send a separate email with supporting documents including logs. Let me know if you have any questions/concerns with the application. Thank you! Rodrigo Ruysschaert | Completions Engineer | ConocoPhillips O: + 1 907-263-3709| M: +1 907-621-0671 | 700 G Street, ATO-1586, Anchorage, AK 99501 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 March 24, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 3/19/2025 (a)(2) Plat Provided with application. SFD 3/19/2025 (a)(2)(A) Well location Provided with application. Well lies in Sections 18, 19, and 30 of T12N, R8E, UM. SFD 3/19/2025 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online March 19, 2025), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of KRU 3S-714. There are no subsurface water rights or temporary subsurface water rights within 7 miles of the surface location of KRU 3S-714. SFD 3/19/2025 (a)(2)(C) Identify all well types within ½ mile List provided with application. SFD 3/19/2025 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. Aquifers affected by this well are exempt. This well lies within the Kuparuk River Unit (KRU) boundary of 1984 that forms the basis for the aquifer exemption granted by Title 40 CFR 147.102(b)(3) according to a recent opinion by the EPA, which states in part: "In short, EPA finds that the boundary of Alaska’s aquifer exemption at 40 C.F.R. 147.102(b)(3) was determined on May 11, 1984. After a program is approved or promulgated, additions to aquifer exemptions, including boundary expansions to aquifers or parts thereof, submitted as part of a UIC program cannot change unless EPA approves those additions in accordance with EPA’s UIC program regulations (See 40 C.F.R. 144.7(b)(1) and (3)).” (Reference: Email from Evan Osborne, US EPA Region 10, to Steve Davies, AOGCC, dated December 2, 2024.) SFD 3/19/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 March 24, 2025 (a)(4) Baseline water sampling plan None required. SFD 3/19/2025 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. CDW 03/10/2025 (a)(6) Casing and cementing operation assessment 10-3/4” surface cement job pumped with losses experienced. Cemented to surface with returns. 7-5/8” intermediate casing cemented as designed. CBL (ON File at AOGCC digilogs) indicates TOC of 5530 ft. 4.5” liner at 6452 ft MD, 7-5/8” casing shoe at 6639 ft. CDW 03/10/2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Aquifers are exempt in this area. (See Section (a)(3), above.) SFD 3/19/2025 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing shoe is located at 2,803’ MD (-2,481’ TVDSS). Although lost returns were reported at 1400 strokes into displacement, the plug bumped and floats held, and 110 barrels of cement were reported at surface. Intermediate casing was set into the Coyote interval at 6,639’ MD (-4,099’ TVDSS) and cemented. Plug bumped, floats held, and the top of cement from CBL is about 5,530’ MD (-3,725’ TVDSS), with the top of consistent, excellent-quality bond at 5,575’ MD (-3,746’ TVDSS). SFD 3/19/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3850 psi MITIA tested, 4550 psi MITT tested. CDW 03/10/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 March 24, 2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree. max. frac. Pressure indicated as 7075 psi (Corrected max, pressure to 7636 psi surface due to tubing test and backpressure criteria). Pump knock out 7575 and GORV 8075 psi., tree test 10K psi, lines test 10K psi. CDW 03/10/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: Seabee Shale consisting of condensed mudstone and thin siltstone that has an aggregate thickness of about 350’ true vertical thickness (TVT). Fracture gradient is expected to range from about 0.67 to 0.84 psi/ft (12.9 to 16.1 ppg EMW). Fracturing Zone: Coyote interval (top at 6,435' MD, equivalent to –4,054' TVDSS) with an average thickness of more than 500' TVT in this area. This well did not penetrate the base of the Coyote. It consists of thinly interbedded layers of very fine-grained sandstone and siltstone. Fracture-closure gradient is expected to be about 0.67 psi/ft (12.9 ppg EMW) based on diagnostic fracture injection testing (DFIT). Lower confining zones: Underlying Torok Formation mudstone that has an aggregate TVT of 300' in this area but was not penetrated by this well. Fracture gradient expected to range from about 0.78 to 0.94 psi/ft (15 to 18 ppg EMW). SFD 3/19/2025 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. There are 46 wells (and sidetracks etc) within ½ mile radius of KRU 3S-714 and 24 wells within ½ mile of KRU 3S-714 that penetrate the confining intervals. CPAI has evaluated the cement and zonal isolation of these wells and see no impediment to hydraulic fracturing. SFD 3/24/2025 CDW 03/10/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 March 24, 2025 Prioritizing the 24 wells, redrilled wells, and plugged-back welllbores within the ½-mile radius AOR by distance from 3S-714: KRU 3S-22 (203-011) and KRU 3S-21 (203-031) Plugged and Abandoned Service Wells: 3S-22 and 3S-21—which intercept the top of Coyote about 270’ and 300’, respectively, from the similar interception in 3S-417—only the uppermost 6% (34’ / 564’ true vertical thickness) and 9% (34’ / 378’ true vertical thickness), respectively, of the Coyote Interval are cement-isolated behind 7-inch casing with good-quality bonding. However, since this uppermost portion of the Coyote and about 64’ and 54’ true vertical thickness, respectively, of the overlying confining interval are isolated with good-bonding cement in these wells, any frac or subsequent fluids injected should remain confined within the Coyote reservoir. KRU 3S-03 (203-091) Suspended Development Well: In 3S-03, the Coyote reservoir is NOT covered by cement, rather this well was perforated and cement-squeezed across 4980’ to 5130’ MD, a portion of the upper confining interval above the Coyote reservoir. Coyote is isolated by cement from the underlying Kuparuk reservoir by cement. On the cement bond log dated Sept. 5, 2023, the top of good bond for that isolation lies at 6840’ MD (5164’ TVDSS). In 3S-03—which intercepts the top of Coyote about 730’ (horizontally) from the similar interception in 3S-417, and at the base of the induced fractures, the Coyote in 3S-03 lies about 650’ (horizontally) from the 3S-417 wellbore through the reservoir. The induced fractures are expected to propagate parallel to the 3S-417 wellbore, so it is doubtful that SFD 3/24/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 March 24, 2025 confinement fracturing fluids will be affected due to separation distance. KRU 3S-18 (202-206) Plugged and Abandoned Development Well: In 3S-18, the top of Coyote reservoir lies at 4666’ MD (-4031’ TVDSS), and the interception of 3S-18 with that top lies about 1000’ (horizontally) from the similar intercept in 3S-417. Although the Coyote was not originally covered by cement, the uppermost Coyote and the lowermost portion of the overlying confining interval were subsequently perforated between 4561’ and 4711’ MD (-3944’ and -4068’ TVDSS) and squeezed with cement. A follow-up CBL across that perf-and-wash interval indicates top of good-bonding cement is at 4562’ MD and extends to the base of the log at 4707’ MD. The Coyote interval is isolated by cement from the underlying Kuparuk reservoir. A CBL run on Feb. 9, 2012 indicates the top of cement isolating production casing lies at 6422’ MD (-5590’ TVDSS), with consistent, very good bonding below about 6572’ MD (-5737’ TVDSS). The underlying Kuparuk reservoir top lies at 6642’ MD (-5806’ TVDSS). The induced fractures are expected to propagate parallel to the 3S-417 wellbore, so it is doubtful that confinement fracturing fluids will be affected due to separation distance. KRU_3S-704 (222-142) Active Development Well: The interception in 3S-704 lies 1200’ (horizontally) from the similar interception in 3S-714. In 3S-704, the Coyote is reservoir top at 7026’ MD (-4031’ TVDSS) is isolated by 7-5/8" intermediate casing and cement. TOC from CBL lies at about 5,600' MD, with good bonding from about 6000’ MD (3689’ TVDSS) down to the base of the CBL at 6835’ MD and SFD 3/24/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 March 24, 2025 presumably down to the underlying casing shoe at 7316’ MD (-4070’ TVDSS). KRU_3S-701 (222-133) Plugged and Abandoned Exploratory (Delineation) Well: The interception in 3S-701 lies 1300’ (horizontally) from the similar interception in 3S-714. Coyote interval from 4790’ to 5388’ MD (-4031’ to 4329’ TVDSS) in this pilot well is isolated by and abandonment plug pumped from 2088’ to 5597’ MD. The Coyote intervals in the 18 remaining wells, redrilled wells, and plugged-back wellbores within the ½-mile radius Area of Review all lie more than ¼ mile from the 3S-714 wellbore path through the Coyote reservoir. The estimated maximum induced fracture half-length of 450’, the expected fracture growth azimuth of about 350 degrees (approximately parallel with the 3S-714 wellbore in the reservoir, and the separation distances of more than ¼ mile from the Coyote interval open to 3S-714 make it highly unlikely that any of these 18 wells, redrilled wells, and wellbores will interfere with confinement of fracturing fluids. SFD 3/24/2025 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory One. The operator has identified one fault of minimal vertical displacement that may intersect the well at about 11,206' MD. The operator reports that there is no mapped seismic offset at the 3S-714 wellbore, consequently this “fault” does not show any offset at the top or base of the Coyote reservoir. It is not expected to affect overburden integrity of containment of fracturing fluids. However, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. SFD 3/24/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 March 24, 2025 (a)(12) Proposed program for fracturing operation Provided with application. CDW 03/10/2025 (a)(12)(A) Estimated volume Provided with application. 45K bbl total dirty vol. 6M lb total proppant CDW 03/10/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 03/10/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Halliburton and Petina and Resmetrics tracers disclosure provided. CDW 03/10/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 03/10/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7075 psi. Max. 7636 psi allowable treating pressure (based on 4550 psi tubing test and 3500 psi backpressure). Max pressure is 7575 psi to 8075 psi to Pump shutdown. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 4136 psi. CDW 03/10/2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures range from 330’ to 450’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will range from 200’ to 215’ (shallowest TVD of about 3,983’ and deepest TVD of about 4,200’), so induced fractures may penetrate into, but not through, the overlying confining Seabee Shale that is about 350’ thick in this area. SFD 3/19/2025 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 03/10/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3500 psi back pressure, plan to test to 3850 psi, popoff set as 3600 psi CDW 03/10/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 8 March 24, 2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be anchored with a packer set at approx. 6331 ft, liner top of 6452 ft and 7-5/8” casing shoe of 6639 ft. TOC in 7-5/8” casing at 5530 ft (SonicScope on file at AOGCC)- CBL conservatively shows good cement at area of interest so no cement concerns. CDW 03/10/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4550 psi. Max pressure differential is estimated as 4136 psi (7636 with 3500 psi backpressure) so test of 4550 psi satisfies 110% CDW 03/10/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 10K psi line pressure test, pump knock out 7575 psi with max. global kickout 8075 psi. IA PRV set as 3600 psi. CDW 03/10/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 03/10/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 03/10/2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 03/10/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). SFD 3/19/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3S-714 (PTD No. 224-151; Sundry No. 325-126) Paragraph Sub-Paragraph Section Complete? AOGCC Page 9 March 24, 2025 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. SFD 3/19/2025 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA Mar 21, 2025 AOGCC Attention: Meredith Guhl 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject:Final Log Distribution for ConocoPhillips Alaska, Inc. KRU 3S-714 Kuparuk River API #: 50-103-20903-00-00 Permit No: 224-151 Rig: Doyon 25 The final Coil deliverables were uploaded via https://copsftp.sharefile.com/ for the above well. Items delivered: Digital Las Data, Graphic Images CGM/PDF and Survey Files. Thank you. Signature of receiver & date received: Please return transmittal letter to: Hampton, Jerissa Jerissa.Hampton@conocophillips.com Luis G Arismendi Luis.arismendi@bakerhughes.com 224-151 T40237 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.26 08:51:16 -08'00' WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS E-Delivery3S-714 50-103-20903-00-00 224-151 KUPARUK RIVER MEMORY Top Of Cement PROCESSED 19-Feb-25 1Transmittal Receipt________________________________X____________________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.Abhattacharya@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-Private224-151T40180 SAMPLE TRANSMITTAL TO: AOGCC 333 WEST 7T" SUITE 100 ANCH. AK. 99501 279-1433 OPERATOR: CPAI SAMPLE TYPE: Dry Cuttings SAMPLES SENT: 3S-714 6600-16392 4 Boxes SENT BY: M. McCRACKEN DATE: 02/27/2025 AIR BILL: N/A CPAI: CPA12025022701 CHARGE CODE: N/A NAME: 3S-714 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 State of Alaska Mike.mccracken@conocophillips.com Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Ste.100 RECEIVED: Amhom e, AK 99501 '✓ RECEIVED FEB 2 7 2025 AOGCC STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3S-714 JBR 03/19/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 4" and 4.5" test joints used for testing. The annular failed on the 4" test joint. The element was changed out and tested after I left location. I asked them to send me the test charts for these two tests after the new element was installed. Test Results TEST DATA Rig Rep:E. Potter/B. WillardOperator:ConocoPhillips Alaska, Inc.Operator Rep:L. Shirley/A. Negusse Rig Owner/Rig No.:Doyon 25 PTD#:2241510 DATE:2/8/2025 Type Operation:DRILL Annular: 250/3500Type Test:OTH Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopGDC250209070408 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 10 MASP: 1503 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 2 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 F #1 Rams 1 2 7/8"x5" VB P #2 Rams 1 Bllind/Shear P #3 Rams 1 2 7/8"x5" VB P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5000 P HCR Valves 2 3 1/8" 5000 P Kill Line Valves 2 3 1/8" 5000 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1775 200 PSI Attained P14 Full Pressure Attained P110 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1808 ACC Misc NA 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 P17 #1 Rams P7 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9999 9 9 9 &KDUWIRU$QQXODUUHWHVWLVDWWDFKHG Annular Preventer F annular failed on the 4" test joint element was changed out and tested after I left location #01&5FTU"OOVMBS3FUFTU %PZPO,364 15% "0($$*OTQCPQ(%$ CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20250113 1330 Hyd Fracture PTD 224-151 - KRU 3S-714 Date:Monday, January 13, 2025 3:37:35 PM From: Warren, Abby <Abby.Warren@conocophillips.com> Sent: Monday, January 13, 2025 1:37 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: PTD 224-151 - KRU 3S-714 All I was looking over the permit after approval and noticed there was an error. 3S-714 will be hydraulicly fractured. Because the well is an injector, the logs required for cement quality are already required by the current approved permit. The approved sonic scope will confirm the top of cement for injector service and the stimulation. A 10-403 will be submitted for approval prior to fracturing. I apologize for the oversight. Please let me know if there are any questions Thanks, Abby Warren Staff Drilling Engineer C: 907-240-9293 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 3S-714 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-151 Surface Location: 2517 FNL, 1066 FEL, S18 T12N R8E, UM Bottomhole Location: 2450 FNL, 2707 FEL, S18 T12N R8E, 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 AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Gregory C. Wilson Commissioner DATED this 9th day of January 2025. . Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.01.09 13:22:54 -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: 16,392 TVD: 4204 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 39.5 15. Distance to Nearest Well Open Surface: x- 476193 y- 5993898 Zone- 4 24 to Same Pool: 1293' to 3S-704 16. Deviated wells: Kickoff depth: 400 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# H40 Welded 92 40 40 92 92 13-1/2" 10-3/4" 45.5# L80 H563 2747 40 40 2747 2496 9-7/8" 7-5/8" 29.7# L80 H563 5741 40 40 5741 3865 9-7/8" 7-5/8" 33.7# P110S H563 800 5741 3865 6541 4124 6-1/2" 4-1/2" 12.6# P110-S H563 10026 6366 4082 16392 4204 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: Chris Brillon Contact Email:abby.warren@cop.com Wells Engineering Manager Contact Phone: 907-240-9293 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : 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 1924 P.O. Box 100360 Anchorage, Alaska, 99510-0360 2517 FNL, 1066 FEL, S18 T12N R8E, UM ADL380107 / ADL392374 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc 59-52-180 3S-714 2530 FNL, 3992 FEL, S18, T12N, R8E, UM 2450 FNL, 2707 FEL, S18 T12N R8E, UM 2448 / 2459 GL / BF Elevation above MSL (ft): 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Casing Length Size Cement Volume MD Intermediate Surface Conductor/Structural Perforation Depth MD (ft): Perforation Depth TVD (ft): Liner Production If checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: 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: Abby Warren Commission Use Only See cover letter for other requirements. Kuparuk River Field Coyote Oil Pool 1/5/2025 1892' to ADL380107 1115 sx of 15.3 ppg Class G + Add's 196 sx of 15.3 ppg Class G + 17 sx of 15.3 ppg Class G Cement to surface with 4 yds slurry 1148 sx of 11.0 ppg DeepCRETE + 272 sx of 15.8 ppg Class G 1503 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 4:16 pm, Dec 06, 2024 X 224-151 DSR-12/16/24 Service - WAG Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig 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 BOPE testing on a 21-day interval is approved with the attached conditions 50-103-20903-00-00 Diverter variance request granted per 20 AAC 20.035(h)(2), A.Dewhurst 08JAN25MGR09JAN2024 KRU &': &':IRU-/& Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.01.09 13:18:38 -09'00' 01/09/25 01/09/25 RBDMS JSB 011325 KRU 3S-714 PTD224-151 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 ĖŜĺīÍťĖĺĲϠϙĺŘϙèĺĲƱĲĖĲČϙƏĺĲôϙĖŜĺīÍťĖĺĲϙôťèϟϙŘĺŽĖîĖĲČϙťēôϙīĺČϙſĖťēĺŪťϙÍĲϙ 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 tēôϙÍèťŪÍīϙiϙæÍŜôîϙĺĲϙèÍīèŪīÍťĖĺĲŜϙŕŘôîĖèťĖĲČϙÍϙîĖƯôŘôĲťϙ 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. 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 justĖƱèÍťĖĺĲϙſĖťēϙŜŪŕŕĺŘťĖĲČ information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage , Alaska 99510-0360 Telephone 907-276-1215 December 6, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3S-714 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Injector well from the 3S drilling pad. Th e intended spud date for this well is January 5, 2025. It is intended that Doyon 25 be used to drill the well. 3S-714 will utilize a 13-1/2" surface hole drilled to TD and 10-3/4" casing will be set and cemented to surface. As noted in section 4 of the attached proposed drilling program, the low maximum anticipated surface pressure of the well allows use of a three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii). The fourth preventer will contain solid body pipe rams that will be sized for the intermediate casing string. The 9-7/8" intermediate hole will be drilled and topset the Coyote reservoir. A 7-5/8" casing string will be set and cemented from TD to secure the shoe and cover a 500’ MD or 250’ TVD above any hydrocarbon- bearing zones per AOGCC regulations. The 6-1/2" production interval will be drilled horizontally and geo-steered within the Coyote formation. The well will be completed as a cemented, fracture stimulated Injector with 4-1/2" liner with frac sleeves. The upper completion will include a production packer with GLM’s and a downhole guage tied back to surface. It is requested that a variance of the diverter requirement under 20 AAC 25.035 (h)(2) is granted. There has been multiple wells drilled on pad which have not encountered any shallow gas or had any issues related to hydrates. A variance is also requested for a BOPE test interval of 21 days for this project. Doyon 25 supported the CPAI BOPE between well maintenance program through COVID and has maintained 73% first time pass rate along with a 99% effectiveness for all components tested in 2024 to date. The variance allows effective drilling and completion of the long lateral of this well. 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. If you have any questions or require further information, please contact Abby Warren at 907-240-9293 (abby.warren@cop.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3S-714 Well File / Jenna Taylor ATO 1804 David Lee ATO 1552 Abby Warren Chris Brillon ATO 1548 Drilling Engineer Support granting diverter waiver: See page 5. SFD requested that a variance of the diverter requirement under 20 AAC 25.035 (h)(2) is granted 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 1 | 14 3S-714 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 ................................................................................................................ 4 5. MASP Calculations ................................................................................................................................. 6 6. Procedure for Conducting Formation Integrity Tests ............................................................................... 7 7. Casing and Cementing Program .............................................................................................................. 7 8. Drilling Fluid Program ............................................................................................................................ 8 9. Abnormally Pressured Formation Information ........................................................................................ 9 10. Seismic Analysis ..................................................................................................................................... 9 11. Seabed Condition Analysis ..................................................................................................................... 9 12. Evidence of Bonding ............................................................................................................................... 9 13. Discussion of Mud and Cuttings Disposal and Annular Disposal .............................................................. 9 14. Drilling Hazards Summary .................................................................................................................... 10 15. Proposed Completion Schematic .......................................................................................................... 12 16. Area of Review..................................................................................................................................... 13 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 2 | 14 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 3S-714 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 2517 FNL, 1066 FEL, S18 T12N R8E, UM NAD27 Northing: 5993897.77 Easting: 476192.99 RKB Elevation 15.5’ AMSL Pad Elevation 24’ AMSL Top of Productive Horizon (Heel) 2694 FNL, 3996 FEL, S18 T12N R8E, UM NAD27 Northing: 5993731.54 Easting: 473263.43 Measured Depth, RKB:6541‘ MD True Vertical Depth, RKB:4124‘ TVD True Vertical Depth, SS:4085‘ TVDss Total Depth (Toe) 2450 FNL, 2707 FEL, S18 T12N R8E, UM NAD27 Northing: 474552.3 Easting: 5993970.64 Measured Depth, RKB:16392‘ MD True Vertical Depth, RKB:4204‘ TVD True Vertical Depth, SS:4164‘ TVDss Pad Layout 474552.3 See attached emails. -A.Dewhurst 24DEC24 5983970.7 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 3 | 14 Well Plat 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 4 | 14 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 25 onto well over pre-installed 20” insulated conductor. 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, with Spud Mud. (LWD Program: GR/RES/GWD). 4. Run and cement 10-3/4" surface casing to surface. Results of the cement operation will be submitted as soon as possible. 5. Install BOPE with the following equipment/configuration: 13-5/8” annular preventer, 7-5/8"FBR’s, blind ram and 2-7/8” x 5” VBR’s. See section 4 for ram configuration justification. 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" drilling BHA to drill intermediate hole section. 8. Chart casing pressure test to 3500 psi for 30 minutes. 9. Drill out shoe track and 20’ of new hole. 10. Perform LOT. Minimum LOT required to drill ahead is 11 ppg EMW. 11. Drill 9-7/8"hole to section TD (LWD Program : GR/RES/DEN/NEU) 12. Run 7 5/8” casing and cement to a minimum of 250’ TVD or 500’ MD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 3850 psi. 13. Change upper 7-5/8" solid body rams to 2-7/8” x 5” VBR’s. Test BOPE to 250/3,500 psi. (24-48 hr. regulatory notice). 14. Pick up and RIH with 6-1/2” drilling assembly. Log top of cement with sonic tool in recorded mode. 15. Chart casing pressure test to 3,850 psi for 30 minutes if not tested on plug bump. 16. Drill out shoe track and 20 feet of new formation. Perform FIT. Minimum acceptable leak-off for drilling ahead is 10.7 ppg EMW. 17. Drill 6-1/2" horizontal hole to section TD (LWD Program: GR/RES/Den/Neu). 18. Circulate the hole clean and POOH. 19. Run 4-1/2” liner to TD, set liner hanger and packer. 20. Cement 4-1/2” liner from TD to liner top. POOH LD DP. 21. Pressure test well to 3,850 psi. RU to run upper completion. 22. Run 4-1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. 23. Pressure test hanger seals to 5,000 psi. 24. Pressure test against the glass plug to set production packer, test tubing to 4,550 psi, chart test. 25. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 26. Install HP-BPV and test to 1500 psi. 27. Nipple down BOP. 28. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 29. Freeze protect down tubing and annulus. 30. Secure well. Rig down and move out. Please note – This well will be frac’d 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 5 | 14 4. BOP and Diverter Information Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP and diverter schematics on file for Doyon 25 Doyon 25 will use a BOPE stack equipped with an annular preventer, fixed, 7-5/8" solid body rams, blind/shear rams and variable bore rams while drilling and running casing in the intermediate section of 3S-714. 3S-714 has a MASP of 1475 psi in the intermediate hole section using the methodology presented in section 5 MASP calculations. With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2. Per 20 AAC 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 begin 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 Intermediate Drilling/ Casing Annular Preventer (iii) 7-5/8" Fixed Rams Blind/Shear Rams (ii) VBR’s (i) Production: Annular Preventer (iii) VBR’s (i) Blind/Shear Rams (ii) VBR’s (i) It is requested that a variance of the diverter requirement under 20 AAC 25.035(h)(2) is granted. At 3S, there has not been significant indication of shallow gas or gas hydrates through the surface hole interval. There are 7 previously drilled wells (3S-14, 3S-606, 3S-610, 3S-611, 3S-612, 3S-617, 3S-624) within 500’ of Recommend approving variance based on CPAI analysis mentioned above and AOGCC review o f drilling reports from KRU 3S-08 and mudlogs of KRU 3S-620 and Palm-1. -A.Dewhurst 12DEC24 variance of the diverter requirement 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 6 | 14 the proposed 3S-714 surface shoe location. None of these wells encountered any significant indication of shallow gas or gas hydrates. 5. 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 13.2 8.7 54 2747 2496 8.7 1,129 70 70 879 INT1 9-7/8" 10-3/4" 2747 2496 14 8.8 1,142 6541 4124 8.8 1,887 1,475 1,567 1,475 PROD 6-1/2" 7-5/8" 6541 4124 13 8.8 1,887 16392 4204 8.8 1,924 1,504 2,375 1,504 *Maximum potential pore pressure in the Susitna Sand if present (B) data on potential gas zones; The planned 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 Agree: Drilling records for three wells with surface casing shoes lying within 300' of the proposed 3S-714 surface casing shoe location do not contain any mention of shallow gas or gas hydrates. Diverter waivers were also granted for each of those three nearby wells. SFD 12/31/2024 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 7 | 14 6. 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. 7. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H40 Welded Cemented to surface with 10 yds slurry 10-3/4" 13-1/2" 45.5# L80 H563 Cement to Surface 7-5/8" 9-7/8" 29.7# 33.7# L80 P110S H563 250’ TVD or 500’ MD, whichever is greater, above highest significant hydrocarbon bearing zone 4-1/2" 6-1/2" 12.6# P110-S H563 Cement to liner top. 10-3/4" Surface Casing run to 2747' MD/ 2496' TVD Cement Plan: Cement from 2747’ MD to 2247’ (500’ of tail) with DeepCRETE + Adds @ 15.8 ppg, and from 2247' to surface with 11.0 ppg DeepCRETE. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1754’ MD), zero excess in 20” conductor. Lead 393 bbls => 1148 sx of 11.0 ppg DeepCRETE + Add's @ 1.92 ft³/sk Tail 56 bbls => 272 sx of 15.8 ppg Class G + Add's @ 1.16 ft³/sk 7-5/8" Intermediate Casing run to 6541' MD/ 4124' TVD Cement Plan: Primary cement job consists of a 15.3 ppg slurry designed to be at 6541’ MD, which is 250' TVD above the prognosed shallowest hydrocarbon bearing zone Top Coyote, K3. If a shallower hydrocarbon zone of producible volumes, is encountered while drilling, a longer primary job or a 2 nd stage cement job will be performed to isolate this zone. Assume 30% excess annular volume. Lead 44 bbls => 196 sx of 15.3 ppg Ext. Class G + Add's @ 1.25 ft³/sk Tail 4 bbls => 17 sx of 15.3 ppg Class G + Add's @ 1.246 ft³/sk 4-1/2" Production Liner run to 16392' MD/ 4204' TVD Cement Plan: Primary cement job consists of a 15.3 ppg slurry designed to be at 6366' MD/ 4082' TVD, which is at the liner top. Tail 248 bbls => 1115 sx of 15.3 ppg Class G + Add's + Add's @ 1.25 ft³/sk 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 8 | 14 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate Production Hole Size in 13-1/2" 9-7/8" 6-1/2" Casing Size in 10-3/4" 7-5/8" 4-1/2" Density ppg 8.6-9.6 ppg 9.0-10.0 ppg 9.0-10.0 ppg PV cP ALAP 10-30 10-30 YP lb./100 ft2 35-50 8-16 8-16 Funnel Viscosity s/qt 150-300 40 - 65 40-65 Initial Gels lb./100 ft2 50 N/A N/A 10 Minute Gels lb./100 ft2 60 N/A N/A API Fluid Loss cc/30 min <45 N/A N/A HPHT Fluid Loss cc/30 min n/a <4 <4 pH 8.5-9.5 9.5 – 10.0 9.5-10.0 Oil/Water Ratio N/A 65/35 – 70/30 65/35 – 70/30 Surface Hole: A freshwater Spud Mud will be used for the surface interval. Keep flow line viscosity at ± 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight S10.0 ppg by use of solids control system and dilutions where necessary. Intermediate: NAF system will be used. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight from 9.0-10.0 ppg and be prepared to add loss circulations materials as needed. Production Hole: The horizontal production interval will be drilled with NAF system weighted to 9.0-10.0 ppg. MPD will be available for adding backpressure during connections if necessary. Diagram of Doyon 25 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. All fluid densities to be overbalanced to expected pore pressure. - mgr 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 9 | 14 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. 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. 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 10 | 14 14. 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 First well on Pad, traveling cylinder diagrams Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Clay Balling Medium Maintain planned mud parameters and flow rates, Increase mud weight, use weighted sweeps, reduce fluid viscosity, control ROP Abnormal Pressure Low Diverter drills, increased mud weight. Shallow hazard study noted minimal risk Lost Circulation Medium Reduce pump rates, mud rheology, add lost circulation material, use of low density cement slurries, port collar, control pipe running speeds 9-7/8" Hole | 7-5/8" Casing Interval Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, MPD stripping practices Abnormal Pressure in Overburden Formations Low Well control drills, check for flow during connections, increase mud weight. Shallow hazard study noted minimal risk Hole Cleaning Low Monitor ECD and torque/drag trends, control drill and use best hole cleaning practices 6-1/2" Hole | 4-1/2" Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material 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 Low Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well control practices, mud scavengers To be posted in Rig Floor Doghouse Prior to Spud 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 11 | 14 Well Proximity Risks: 3S will be a multi-well pad. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. 3S-714 well has one close approach with the abandoned 3S-14 well. 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. Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Swabbed Kicks Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 12 | 14 15. Proposed Completion Schematic 3S-714 AOGCC 10-401 APD 12/24/2024 3S-714 AOGCC 10-401 APD 13 | 15 16. Area of Review 3S-714 Area of Review (AOR) An Area of Review plot is show below of the 3S-714 injector planned wellpath and offset wells. There are nine wells (3S-03, 3S-21, 3S-22, 3S-701 and 3S-704) within in the quarter mile review for 3S-714. 3S-714 AOGCC 10-401 APD 12/24/2024 3S-714 AOGCC 10-401 APD 14 | 15 3S-714 AOGCC 10-401 APD 12/24/2024 3S-714 AOGCC 10-401 APD 15 | 15 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 13 | 14 16. Area of Review 3S-714 Area of Review (AOR) An Area of Review plot is show below of the 3S-714 injector planned wellpath and offset wells. There are nine wells (3S-03, 3S-21, 3S-23, 3S-24, 3S-613, 3S-615, 3S-625, 3S-701 and 3S-704) within in the quarter mile review for 3S-714. Superseded by updated AOR. See attached emails. -A.Dewhurst 24DEC24 3S-714 AOGCC 10-401 APD 12/6/2024 3S-714 AOGCC 10-401 APD 14 | 14 Superseded by updated AOR. See attached emails. -A.Dewhurst 24DEC24 40 100 100 200 200 500 500 1000 1000 1500 1500 2000 2000 3000 3000 5000 5000 7000 7000 10000 10000 15000 15000 17000 3S-714 wp08 Plan Summary 3S-714 wp08 3S-03 3S-06 3S-06A 3S-07 3S-08 3S-08A3S-08B 3S-08C 3S-08CL1 3S-08CL1PB1 3S-09 3S-10 3S-14 3S-15 3S-163S-17 3S-17A 3S-18 3S-19 3S-21 3S-22 3S-23 3S-23A 3S-24A 3S-24B 3S-26 PALM 1 3S-611PB1 3S-613 3S-620 3S-701 3S-701A 3S-718 3S-722 3S-703 (P12) wp04 3S-705 (I12) wp09 3S-719 (P02) wp05 3S-721 (I03) wp04 3S-723 wp04 3S-732 (I10) wp04 3S-734 (P04) wp03 3S-736 (I04) wp03 3S-738 (I05) wp04 0 4 Dogleg Severity0 2500 5000 7500 10000 12500 15000 Measured Depth 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 50 50 100 100 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in] 3S-09 3S-10 3S-14 3S-15 3S-16 3S-173S-17A 3S-183S-19 3S-610 3S-611 3S-611PB1 3S-612 3S-6133S-615 3S-617 3S-718 3S-719 (P02) wp05 3S-723 wp04 3S-730 (P10) wp04 0 4500 True Vertical Depth0 2000 4000 6000 8000 10000 12000 Vertical Section at 189.20° 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 0 28 55 Centre to Centre Separation0 2250 4500 6750 9000 11250 13500 15750 Measured Depth Equivalent Magnetic Distance DDI 7.147 SURVEY PROGRAM Date: 2024-08-28T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.50 1400.00 3S-714 wp08 (3S-714)r.5 SDI_URSA1 1400.00 2747.83 3S-714 wp08 (3S-714)MWD+IFR2+SAG+MS 2747.83 6540.77 3S-714 wp08 (3S-714) MWD+IFR2+SAG+MS 6540.77 16392.09 3S-714 wp08 (3S-714)MWD+IFR2+SAG+MS Surface Location North / 5993648.30 East / 1616225.06 Ground / 24.00 CASING DETAILS TVD MD Name 2497.00 2747.83 10-3/4" Surface Casing 4124.00 6540.77 7-5/8" Intermediate Casing 4203.50 16392.00 4-1/2" Production LinerMag Model & Date:BGGM2024 01-Dec-24 Magnetic North is 13.96° East of True North (Magnetic Declination) Mag Dip & Field Strength:80.62° 57190.18nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 39.50 0.00 0.00 39.50 0.00 0.00 0.00 0.00 0.00 2 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 500.00 1.00 340.00 499.99 0.82 -0.30 1.00 340.00 -0.76 Start Build 1.50 4 650.00 3.25 340.00 649.88 6.05 -2.20 1.50 0.00 -5.62 Start Build 2.00 5 1699.35 24.24 340.00 1663.50 239.00 -86.99 2.00 0.00 -222.02 Start 109.67 hold at 1699.35 MD 6 1809.02 24.24 340.00 1763.50 281.31 -102.39 0.00 0.00 -261.32 Start DLS 3.75 TFO -52.59 7 3214.38 69.26 297.50 2721.62 900.03 -836.44 3.75 -52.59 -754.74 Start 348.35 hold at 3214.38 MD 8 3562.73 69.26 297.50 2844.99 1050.44 -1125.41 0.00 0.00 -857.02 Start DLS 3.75 TFO -113.37 9 6670.41 80.00 174.00 4149.14 -302.67 -2920.74 3.75 -113.37 765.70 Start Build 3.00 10 6870.41 86.00 174.00 4173.50 -500.00 -2900.00 3.00 0.00 957.18 Start 20.00 hold at 6870.41 MD 11 6890.41 86.00 174.00 4174.90 -519.84 -2897.91 0.00 0.00 976.43 Start DLS 2.00 TFO -25.19 12 7104.23 89.87 172.18 4182.60 -731.92 -2872.21 2.00 -25.19 1181.67 Start 9287.87 hold at 7104.23 MD 13 16392.09 89.87 172.18 4203.50 -9933.42 -1608.70 0.00 0.00 10062.84 TD at 16392.09 FORMATION TOP DETAILS TVDPath Formation 1377.50 Top Ugnu 1713.50 Base Permafrost 2022.50 Top West Sak 2456.50 Base West Sak 2665.50 Campanian Sand (C-80) 3414.50 C-50 3885.50 C-35 4083.50 Top Coyote (Top Nanushuk), K3 Plan: 24+39.5 @ 63.50usft (Doyon 25) Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-714 (I02)Wellbore: 3S-714Design: 3S-714 wp08-12000-60000South(-)/North(+) (3000 usft/in)-12000 -6000 0 6000 12000West(-)/East(+) (3000 usft/in)3S-714 T1 1320 ft3S-714 I02 T1 0411243S-714 I02 T2 0328243S-714 T2 1320 ft3S-705 (I12) wp093S-734 (P04) wp033S-723 wp043S-243S-24A3S-24B3S-729 (I22A) wp033S-213S-721 (I03) wp043S-033S-701A3S-7013S -2 2 3S-719 (P02) wp053S-6133S-6063S-6113S-722 wp07 - approvewd3S-163S-736 (I04) wp033S-7183S-731 (P07) wp043 S -2 6 3S-730 (P10) wp043S-6123S-6103S-6243S-7223S-08CL13S-08CL1PB13S-093S-7043S-193S-17A 3S -08C3S-083S-08B3S-08A 3S-6263S-153S-6203S-23A3S -23 3S-738 (I05) wp043S -073S-143S-6153S-103S-62510-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner500100015002000250030003500 400041923S-714 wp08Plan View with offset wells Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-714 (I02)Wellbore: 3S-714Design: 3S-714 wp08-12000-60000South(-)/North(+) (3000 usft/in)-12000 -6000 0 6000 12000West(-)/East(+) (3000 usft/in)3S-714 T1 1320 ft3S-714 I02 T1 0411243S-714 I02 T2 0328243S-714 T2 1320 ft10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner500100015002000250030003500 400041923S-714 wp08Plan View with offset wells 019003800True Vertical Depth (950 usft/in)0 3000 6000 9000 12000Vertical Section at 189.20° (1500 usft/in)10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner10002000300040005000600070008000900010000110001200013000140001500016000Plan: 3S-714 (I02)/3S-714 wp08Start Build 1.00Start Build 1.50Start Build 2.00Start 109.45 hold at 1686.75 MDStart DLS 3.75 TFO -51.99Start 337.83 hold at 3207.96 MDStart DLS 3.75 TFO -113.45Start Build 3.00Start 20.00 hold at 6863.15 MDStart DLS 2.00 TFO -25.19Start 9287.87 hold at 7096.96 MDTD at 16384.83Section View Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-714 (I02)Wellbore: 3S-714Design: 3S-714 wp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his 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:Warren, Abby To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]KRU 3S-714 (PTD 224-151) - Question Date:Tuesday, December 31, 2024 8:02:35 AM Attachments:image001.png Hi Steve, In many of the 3S wells we do have unloading events, it’s a combination of several factors, the unconsolidated nature of 3S surface hole, our high angles in these surface holes, and lower pump rates when drilling through the permafrost. Prior to the first snippet below we were drilling at 450-500 gpm so I would suspect that the hole was loading up with cuttings, we then brought pumps up, cleaned up the wellbore and continued drilling ahead. Before the second snippet, it was similar, lower pump rate into a higher pump rate, most likely causing a cuttings bed with the lower flow rate and as we brought the pumps up higher the hole unloaded. Please let me know if you have any other questions, Thanks Abby From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, December 30, 2024 3:02 PM To: Warren, Abby <Abby.Warren@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]KRU 3S-714 (PTD 224-151) - Question 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. Abby, I’m working with Andy Dewhurst on CPAI’s Permit to Drill application for KRU 3S-714. Specifically, I’m reviewing CPAI’s request for a diverter waiver and checking the records for nearby wells. In the daily reports for offset well 3S-606 (PTD 223-111), which is 280' to the NNE of 3S-714, I don’t see any mention of gas or hydrates in the Daily Ops Summary reports, but I do see this: Can you please tell me what caused the 3S-606 hole to unload? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov 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:Warren, Abby To:Dewhurst, Andrew D (OGC); Hobbs, Greg S Cc:Loepp, Victoria T (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC) Subject:RE: [EXTERNAL]KRU 3S-714 PTD (224-151): Questions Date:Tuesday, December 24, 2024 8:11:11 AM Attachments:3S-714 Revised AOR.pdf Hi Andrew See Comments below and adjusted table. I revised the AOR portion and have it attached. Let me know if you would like to see other verbiage. Total Depth (Toe)2450 FNL, 2707 FEL, S18 T12N R8E, UM NAD27 Northing: 5983970.7 Easting: 474552.3 Measured Depth, RKB:16392‘ MD True Vertical Depth, RKB:4204‘ TVD True Vertical Depth, SS:4164‘ TVDss Happy Holidays to you all! Thanks Abby From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, December 16, 2024 1:43 PM To: Warren, Abby <Abby.Warren@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXTERNAL]KRU 3S-714 PTD (224-151): 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. Abby, I am completing my review of the KRU 3S-714 PTD and have a few questions: Would you double-check the BHL (NAD27 State Plane) coordinates that are presented in Section 2? It appears that the easting and northings have been swapped. In addition, my calculations are showing a northings value about 10,000’ less. You are correct, Above is a corrected table For Section 16’s Area-of-Review: Would you please confirm that the following wells that were included in the AOR are either not within the ¼-mile radius or do not intersect the Coyote stratigraphic interval: KRU 3S-23A KRU 3S-24B KRU 3S-613 KRU 3S-615 KRU 3S-625 KRU 3S-701A (labelled as 3S-701 in the table) I removed all these in the updated AOR attached Would you please confirm that the following wells should be included in the AOR: KRU 3S-18 (50-103-20433-00-00) – I sat down with our directional planner and ran the scan on my own, it appears this one is outside the ¼ mile by the time we set intermediate casing. Let me know if I am missing it on this one. KRU 3S-22 (50-103-20446-00-00) – added to the attached updated AOR KRU 3S-701 (50-103-20847-00-00) – added to the attached updated AOR Would you make updates to the table for the following wells: KRU 3S-03: identify the casing string that covers the Coyote and if no primary cement isolation, indicate so. Then, in the comments, add a summary of the planned abandonment activity that will provide isolation - added to the attached updated AOR KRU 32-21: was this well also not one that required the perf and wash reservoir abandonment (similar to KRU 3S-03 above). If so, would you update the table to show that as originally drilled, there was no isolation and a remedial cementing job was conducted (with details)? added to the attached updated AOR Thank, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-151 KUPARUK RIVER UNIT KUPARUK RIVER, COYOTE OIL KRU 3S-714 WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3S-714Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241510KUPARUK RIVER, COYOTE OIL - 490120NA1 Permit fee attachedInCmpt ADL380107 and ADL3923742 Lease number appropriateYes3 Unique well name and numberYes Kuparuk River Unit, Coyote Oil Pool, CO 8194 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 4514 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servInCmpt15 All wells within 1/4 mile area of review identified (For service well only)InCmpt16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes SC set at 2747' MD19 Surface casing protects all known USDWsYes 152% excess planned20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes Production liner fully cemented. IC has adequate cement above reservoir22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Doyon 25 has adequate tankage and good trucking support.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes Baker Hughes collision scan shows no wells with HSE risk.26 Adequate wellbore separation proposedYes Diverter variance granted per 20 AAC 20.035(h)(2)27 If diverter required, does it meet regulationsYes Max reservoir pressure is 1924 psig(9.0 ppg EMW): will drill w/ 9.0-10.0 ppg EMW28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP is 1503 psig; will initially test BOPs to 5000 psig; subsuquent test to 3500 psig30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S encounted in other Torok Oil Pool wells on pad, but not anticipating H2S for Coyote35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating pore pressure of 8.8 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]Appr DateApprMGRDate1/9/2025ApprADDDate12/11/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate