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225-035
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 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. 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-703 225-035 DATE: 09/26/2025 Transmitted: 3S-703 Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM 225-035 T40926 CC: 3S-703 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.26 12:28:44 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13420 feet feet true vertical 4206 feet feet Effective Depth measured 13420 feet 5173 feet true vertical 3206 feet 4116 feet Perforation depth Measured depth feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# L-80 5,315' MD 4,145' TVD Packers and SSSV (type, measured and true vertical depth)Production Pkr HES TNT 5,173' MD 4,116' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Coyote Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 325-379 Sr Pet Eng: 9210 Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Madeline Woodard madeline.e.woodard@cop.com 907-265-6086Completions Engineer Gas-Mcf 650 10755864 1303 (DHG) 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 13276' MD - 5691' MD 260 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 2155 (DHG)0 Production 20" 10-3/4" Size 120 7-5/8" 11590 7-5/8"7870 4500 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL380107 / ADL380106 KRU / Coyote Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 225-035 50-103-20913-00-00 P.O. Box 100360 Anchorage, Alaska, 99510-0360 3. Address: 3S-703 4,532,666lbs of Wanli LWC proppant, 45,000 lbs 100M natural sand, average bottom hole treating pressure of 3500 psi, final BHG pressure 2714 psi Length 80 2727 120Conductor Surface 10860 measured TVD Production Production 4866 456 8087 Casing Structural 4023 4145 4-1/2" 4866 5322 13409 4206 Plugs Junk measured 2727 MD 2542 Burst Collapse 2474 4789 ConocoPhillips Alaska, Inc. 5209 6885 p k ft t Fra O s O 225 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 4:06 pm, Aug 11, 2025 Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard @conocophillips.com Reason: I am the author of this document Location: Date: 2025.08.11 16:02:10-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard CDW 08/12/2025 RBDMS JSB 081425 DSR-9/11/25 Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 07/07/2025 Job End Date: 07/16/2025 State: Alaska County: Harrison Bay API Number: 50-103-20913-00-00 Operator Name:ConocoPhillips Company/Burlington Resources Well Name and Number: 3S-703 Latitude: 70.394597 Longitude: -150.191959 Datum: NAD83 Federal Well: NO Indian Well: NO True Vertical Depth: 4206 Total Base Water Volume (gal)*: 1162513.1 Total Base Non Water Volume: 0 Water Source Percent Other, > 1000TDS 100.00% Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Comments BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator Ceramic Proppant - Wanli Wanli Proppant CLA- WEB(TM)Halliburton Clay Stabilizer Flow Insurance Copper Patina Energy Tracer LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPT 2002-2054 ResMetrics Tracer OPTIFLO-II DELAYED Halliburton Breaker RELEASE BREAKER Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant SEAWATER (SG 8.52)Operator Base Fluid WG-36 GELLING AGENT Halliburton Gelling Agent WPT 1001- 1052 ResMetrics Tracer Items above are Trade Names. Items below are the individual ingredients. Water 7732-18-5 95.00000 65.71466 None Corundum 1302-74-5 60.00000 18.04387 None Mullite 1302-93-8 40.00000 12.02925 None Sodium chloride 7647-14-5 5.00000 3.45867 None Crystalline silica, quartz 14808-60-7 100.00000 0.30016 None Guar gum 9000-30-0 100.00000 0.22188 None Water 7732-18-5 100.00000 0.11410 None Ethanol 64-17-5 60.00000 0.03676 None Monoethanolamine borate 26038-87-9 100.00000 0.03404 None Ammonium salt Proprietary 60.00000 0.02293 None EDTA/Copper chelate Proprietary 30.00000 0.01975 None Heavy aromatic petroleum naphtha 64742-94-5 30.00000 0.01838 None Oxyalkylated nonyl phenolic resin Proprietary 30.00000 0.01838 None Ammonium persulfate 7727-54-0 100.00000 0.01599 None Ethylene glycol 107-21-1 30.00000 0.01021 None Oxyalkylated phenolic resin Proprietary 10.00000 0.00613 None Oxylated phenolic resin Proprietary 30.00000 0.00480 None Sodium hydroxide 1310-73-2 30.00000 0.00432 None Ammonium chloride 12125-02-9 5.00000 0.00329 None Poly(oxy-1,2-ethanediyl), alpha-(4-nonylphenyl)- omega-hydroxy-, branched 127087-87-0 5.00000 0.00306 None Naphthalene 91-20-3 5.00000 0.00306 None 2-Bromo-2-nitro-1,3- propanediol 52-51-7 100.00000 0.00131 None Glycol Ether Proprietary 85.00000 0.00072 None Ammonia 7664-41-7 1.00000 0.00066 None 1,2,4 Trimethylbenzene 95-63-6 1.00000 0.00061 None Sodium chloride 7647-14-5 1.00000 0.00053 None Flow Insurance Copper Proprietary 100.00000 0.00029 None Confidential Proprietary 20.00000 0.00026 None Ethylene Glycol 107-21-1 20.00000 0.00018 None C.I. pigment Orange 5 3468-63-1 1.00000 0.00016 None Quaternary amine Proprietary 0.10000 0.00004 None Amine salts Proprietary 0.10000 0.00004 None 2,7-Naphthalenedisulfonic acid, 3-hydroxy-4-(4- sulfor-1-naphthalenyl) azo -, trisodium salt 915-67-3 0.10000 0.00003 None * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) Confidential Proprietary Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-07-07 Alaska HARRISON BAY 50-103-20913-00-00 CONOCOPHILLIPS 3S 703 -150.19509417 70.39429476 NAD83 none Oil 4206 1162513.1 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone SEAWATER (SG 8.52) Operator Base Fluid Density = 8.52 BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator CLA-WEB(TM) Halliburton Clay Stabilizer LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%65.71466%9904612 Corundum 1302-74-5 60.00%18.04387%2719600 Mullite 1302-93-8 40.00%12.02925%1813067 Sodium chloride 7647-14-5 5.00%3.45867%521296 Crystalline silica, quartz 14808-60-7 100.00%0.30016%45241 Guar gum 9000-30-0 100.00%0.22188%33442 Water 7732-18-5 100.00%0.11410%17198 Ethanol 64-17-5 60.00%0.03676%5541 Monoethanolamine borate 26038-87-9 100.00%0.03404%5131 Ammonium salt Proprietary 60.00%0.02293%3456 Denise Tuck, Halliburton, 3000 N. Sam Houston Pkwy E., Houston, TX 77032, 281-871- 6226 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 EDTA/Copper chelate Proprietary 30.00%0.01975%2978 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01838%2771 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01838%2771 Ammonium persulfate 7727-54-0 100.00%0.01599%2410 Ethylene glycol 107-21-1 30.00%0.01021%1540 Oxyalkylated phenolic resin Proprietary 10.00%0.00613%924 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxylated phenolic resin Proprietary 30.00%0.00480%723 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Sodium hydroxide 1310-73-2 30.00%0.00432%652 Ammonium chloride 12125-02-9 5.00%0.00329%497 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00306%462 Naphthalene 91-20-3 5.00%0.00306%462 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00131%198 Glycol Ether Proprietary 85.00%0.00072%109 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ammonia 7664-41-7 1.00%0.00066%100 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00061%93 Sodium chloride 7647-14-5 1.00%0.00053%80 Flow Insurance Copper Proprietary 100.00%0.00029%45 Patina Energy Julie Harrish julie@patinae nergy.com 8327140836 Confidential Proprietary 20.00%0.00026%39 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ethylene Glycol 107-21-1 20.00%0.00018%27 C.I. pigment Orange 5 3468-63-1 1.00%0.00016%25 Quaternary amine Proprietary 0.10%0.00004%6 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Amine salts Proprietary 0.10%0.00004%6 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%6 * Total Water Volume sources may include fresh water, produced water, and/or recycled water _ ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.5 All component information listed was obtained from the supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. Production Type: True Vertical Depth (TVD): Total Water Volume (gal)*: MSDS and Non-MSDS Ingredients are listed below the green line Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Fracture Date State: County: API Number: Operator Name: Page 1/2 3S-703 Report Printed: 8/11/2025 Daily Operations Summary Job: INITIAL COMPLETION Daily Operations Start Date Last 24hr Sum 6/29/2025 DRIFY w/ 3.69'' GAUGE LIGHTLY TAG CERAMIC DISK @ 5294' RKB, SET 4-1/2 SS CATCHER @ 2390' RKB, PULL 1'' SOV @ 2262' RKB, SET 1'' INCONEL TOP SUB DMY, SET IN ST#1 @ 2262' RKB, LRS PERFORM MIT-T TO 4200 PSI (FAILED TEST), LRS PERFORM MIT-IA TO 3850 PSI (INCONCLUSIVE), JOB INPROGRESS 6/30/2025 TAP DOWN ON 1'' DMY IN ST#1 @ 2262' RKB, LRS PERFORM MIT-T TO 4200 PSI (GOOD TEST), LRS PERFORM MIT-IA TO 3850 PSI (GOOD TEST), PULL 4-1/2 SS CATCHER @ 2390' RKB, READY FOR FRAC 7/5/2025 BEGIN RIGGING UP TO 3S-703, COMPLETED RIG UP 7/6/2025 LOADING CHEMS,GEL,AND PROPPANT 7/7/2025 BROKE THE ARSENAL DISC SHIFTED THE ALPHA SLEEVE, SHOWED A SHIFT SIGNATURE NO INJECTIVITY, SHIFTED THE 16 ALPHA SLEEVE SHOWED SHIFT SIGNATURE NO INJECTIVITY, ELINE CALLED TO PERF BETWEEN THE ALPHA SLEEVE NIPPLED UP 10K TO 5K ADAPTER AND A 5K OTIS FLANGE 7/8/2025 SLB ELINE RIH WITH 2.5" X 10' HSD POWERFLOW 2506 HMX GUN CONVEYED WITH TRACTOR, TOOL SAT DOWN IN DEVIATION AT 5050', TRACTOR DOWN PAST TO 12,164FT (12,190' CORRECTED), MAKE MULTIPLE ATTEMPTS TO GET BY AT VARIOUS SPEEDS, UNABLE TO PASS 12,190' CCL (12,210' BOTTOM OF TOOL), INFORM CONOCO REP, CONTINUE MAKING MULTIPLE ATTEMPTS TO PUSH PAST WITH NO SUCCESS. PERFORM AN UPLOG TO ABOVE SLEEVE #3 AT 11,746.9FT, DEPTH SHIFT TO CONFIRM SITTING DEPTH, ENGAGE TRACTORS AND TRACTOR DOWN TO SAME SITTING DEPTH, CONFIRM DEPTH OF BOTTOM OF THE TOOL TO BE AT APPROX 12,210' RKB (APPROX 4~5 FEET BELOW SLEEVE #2 AT 12,205' RKB). CONFER WITH TOWN, DECSION MADE TO POOH. 7/9/2025 JOB CONTINUED. POOH, RIG DOWN AND MOVE OVER, RELEASE NES CRANE. 7/9/2025 STANDBY, TRAVEL, AOL, MIRU, PERFORM WEEKLY BOP TEST. JOB IN PROGRESS. 7/10/2025 HIT LOCK UP AT 11,876' CTMD. PUMP LUBE 776, MAKE ANOTHER RUN AT IT. MAKE IT TO 11,650', WIPER TO SURFACE, PIN HOLE PIPE 487', LD BHA, TRIM 800' COIL, MU 2.13" BHA, RIH HARD TAG @ 12,688' CTMD. MOTOR WORK AT 12,959.9', 13,003', 13,005', 13,010', AND 13,028'. BHA PLUGGED UP. POOH TO INSPECT TOOLS. JOB IN PROGRESS. 7/11/2025 MILL FROM 13,028' DOWN TO 13.200' CTMD, HAD ISSUES WITH KEEPING UP WITH FLUIDS AND RETURNS. GOT HUNG UP FOR FEW HOURS. OOH MAKE UP VENTURI, TAG AT 12693' VENTURI DOWN TO 13,205' CTMD HARD TAG. OOH, GOT BACK BIG CHUNKS OF CEMENT IN VENTURI. PICS IN ATTACHMENTS. JOB IN PROGRESS. 7/12/2025 MILL FROM 13,208 DOWN TO 13,250', RAN OUT OF PUSH, PULL WIPER TRIP TO 8,000', RBIH TO LOCK UP. POOH PU VENTURI. VENTURI DOWN TO 13.250' OOH VENTURI HAD CUP FULL OF CEMENT CHUNKS AGAIN. HAND WELL BACK TO FRAC. COIL JOB COMPLETE. 7/13/2025 STIMULATE STAGE 1- 3 PER DESIGN w/ 9000 LBS OF 100 MESH & 900747 LBS OF 16/20 PROPPANT UP TO 10 PPG, TOTAL JOB PROPPANT 900447 LB, JOB CLEAN VOLUME PUMPED 6102 BBL (PATINA COPPER TRACER AND RESMETRICS TRACER ADDED PER SCHEDULE) STAGE 3 DART SEAT OBSERVED, NO ISOLATION TO STAGE 2. BU DART DROPPED 7/14/2025 STIMULATE STAGE 4- 7 PER DESIGN w/ 12000 LBS OF 100 MESH & 1199515 LBS OF 16/20 PROPPANT UP TO 10 PPG, TOTAL JOB PROPPANT 1211515 LB, JOB CLEAN VOLUME PUMPED 7231 BBL (RESMETRICS TRACER ADDED PER SCHEDULE) 7/15/2025 STIMULATE STAGE 8- 11 PER DESIGN w/ 12000 LBS OF 100 MESH & 1203082 LBS OF 16/20 PROPPANT UP TO 10 PPG, TOTAL JOB PROPPANT 1215082 LB, JOB CLEAN VOLUME PUMPED 7612 BBL (RESMETRICS TRACER ADDED PER SCHEDULE) STAGE 10 - DART SEAT OBSERVED, NO ISOLATION WITH STAGE 9 SEEN ON PT ARRAY, FLUSHED WELL WITH LINEAR GEL AND LOAD BU DART. GKA 16/20 - 225000LBS WNS 16/20 - 978082 LBS 7/16/2025 STIMULATE STAGE 12- 16 PER DESIGN w/ 12000 LBS OF 100 MESH & 1199963 LBS OF 16/20 PROPPANT UP TO 10 PPG, JOB CLEAN VOLUME PUMPED 7602 BBL (RESMETRICS TRACER ADDED PER SCHEDULE) TOTAL JOB PROPPANT-WNS PROP 1211963 LB STAGE 14 - DART 13-A SEAT OBSERVED, NO ISOLATION SEEN BETWEEN STAGES 13/14, PUMP LINEAR FLUSH AND LOAD/LAUNCH BU. DART PUMPED DOWN AT 20 BPM. DART 13 B - DART SEAT OBSERVED, NO ISOLATION SEEN BETWEEN STAGES 13/14, PUMP LINEAR FLUSH AND LOAD/LAUNCH ADDITIONAL BU DART. PUMPED DOWN AT 20 BPM. DART 13 C - DART SEAT OBSERVED, NO ISOLATION BETWEEN STAGES 13/14, PRESSURE OBSERVED INTO STAGE 12. PUMP DART IN LINEAR AT 15 BPM . STAGE SKIPPED 7/17/2025 RIG DOWN DART LAUNCHER/REVOLVER, DROP EQUALIZATION LINE, RIG DOWN IA/OA, RIG DOWN FRONT YARD HARDLINE, BREAK BACK HARDLINE TO NEXT JOB 3S-723, MOVE IA AND BLEED OFF TANKS, MOVE EQUIPMENT FOR RIG MOVE 7/18/2025 DRIFT 3.75" TO DB NIPPLE @ 5,240' RKB, B&F TBG & DB NIPPLE @ 5,240' RKB, SET 3.75" DBP & BAITED PRONG IN DB NIPPLE @ 5,240' RKB, PERFORM PASSING MIT-T 2500#, PERFORM PASSING DRAWDOWN TEST TO 0# ON TBG & IA, PULL 1" BTM INT-DMY FROM STA #1 @ 2,262' RKB. JOB COMPLETE 7/19/2025 (MISC) TEST BPV TO 1510 PSI (PASSED), T-POT (PASSED), SWAP FRAC TREE TO PRODUCTION TREE WITH CROSS OVER (COMPLETE), TEST PRODUCTION TREE (PASSED) 7/20/2025 SET 1" BK-GLV IN STA #1 @ 2,262' RKB, PULL 1" INCONEL INT-DMY & SET BK-GLV IN STA #3 @ 4,058' RKB, PULL 1" INCONEL INT-DMY & SET BK-OV IN STA #4 @ 4,997' RKB, PRESSURE TEST GASLIFT DESIGN 1500#. JOB IN PROGRESS 7/21/2025 BAIL ~1.5 GAL OF SAND OFF BAITED P-PRONG @ 5,230' RKB, PULL BAITED P-PRONG FROM 3.75" DBP @ 5,240' RKB. JOB IN PROGRESS 7/22/2025 RUN MULTIPLE PUMP BAILERS & 1.75'' SAMPLE BAILER TO DB PLUG @ 5240' RKB, PULL DB PLUG BODY @ 5240' RKB. WELL READY FOR COIL 7/25/2025 MOBILIZE SLB CTU#11 TO PAD. SPOT UP / RIG UP. PERFORM INITIAL BOP TEST.STANDING BY FOR FLUIDS Rig: EXPRO 001 Page 2/2 3S-703 Report Printed: 8/11/2025 Daily Operations Summary Job: INITIAL COMPLETION Daily Operations Start Date Last 24hr Sum 7/26/2025 PICK UP BHA#1 WAVE FORCE MOTOR AND 3.4" SW BALL MILL.. STAND BY FOR FULL FLUIDS INVENTORY. ONCE INVENTORIED STAND BY FOR GAS LIFT LINE COMMISSIONING 14:00. STAND BY FOR GAS TO REACH THE OV.WHP 1380 IA 1353 OA 22 RIH 7/27/2025 MIDNIGHT DEPTH 4400' DRY TAGGED DART #15 AT 5649' CTMD CAME ONLINE WITH PUMP AND DIDN'T SEE ANYTHING GAS INJECTION 1 MMSCFD DIDN'T SEE DART #14 AT 6190' NO DART #13 AT 6689' AT 7191' DART #12 MILLED THROUGH IN 13 MIN. MIL ON DART #11 FOR 5 HRS, LOSE RETURNS, WIPER TRIP TO SURFACE. RBIH AND MILL DART #11 IN TOTAL OF 6 HRS, MILL DART #10 IN 27 MIN, #9 IN 12 MIN, #8 IN 47 MIN, #7 IN 42 MIN., #6 IN 90 MINS STACKING WT PULL WIPER TRIP TO 4000' AT MIDNIGHT MILLING ON DART #4 7/28/2025 AT MIDNIGHT MILLING ON DART #4 TOOK 120 MIN, DART # 3 - 52 MIN. DART #2, - 3 MIN. RR=2.2 BPM GAS RATE 0.9 MMSCFD DHG 1871 STARTED STACKING -8.7 PULL A WIPER FROM 12,352' TO 4,000' CTMD, ABOVE THE OV - CLEAN TRIP. RBIH AND MILL DART IN SLEEVE #1, WASH IN HOLE TO JUST ABOVE ALPHA SLEEVE 13,167' CTMD. SWAB WIPER TO SURFACE. 7/28/2025 SUPPORT CTU, TAKING RETURNS AS NEEDED FOR MOST OF THE DAY.CTCO COMPLETE CTU BEGIN POOH RDMO. EXPRO REMOVES SCHLUMBERGER VX METER FROM RIG UP. EXPRO RE-PRESSURE TESTS INLET HARDLINE. SCHLUMBERGER CTU IS CLEAR OF THE WELLHEAD. 23:16 EXPRO START FLOWBACK OPERATIONS. 7/29/2025 UNLOADING THE WELL PER PROCEDURE.LIQUID AND GAS RETURNS ARE BEING SENT TO PRODUCTION. ESTABLISH A CONSISTANT RATE AT 00:29 AM. HOLD RATE RATE FOR 12 HOURS. PRODUCED WATER WEIGHT OF 8.5 PPG WITH A SALINITY OF 34,000 PPM (SEAWATER) 7/30/2025 UNLOADING THE WELL PER PROCEDURE.LIQUID AND GAS RETURNS ARE BEING SENT TO PRODUCTION.17:55 INCREASED INLET CHOKE TO 48/64TH. 19:42 INCREASED INLET CHOKE TO 52/64TH.21:17 INCREASED INLET CHOKE TO 56/64TH.02:26 INCREASED INLET CHOKE TO 60/64TH.03:57 INCREASED TO 64/64TH.PRODUCED WATER WEIGHT OF 8.44 PPG, SALINITY OF 20,000 PPM. 7/31/2025 DRAWING DOWN THE WELL PER PROCEDURE.LIQUID AND GAS RETURNS ARE BEING SENT TO PRODUCTION.THE WELL IS PRODUCING TRACE -.5% SOLIDS (FORMATION SAND) ALONG WITH OCCASIONAL PROPPANT THAT IS BEING CAPTURED IN THE SAND TRAP.NO DART DEBRIS WAS RECOVERED YESTERDAY. WATER WEIGHT OF 8.38 PPG, SALINITY OF 18,000 PPM. 8/1/2025 EXPRO HAS BEEN HOLDING THE 76 /64 CHOKE SETTING FOR THE PAST 36 HOURS .THIS IS DUE TO THE WELL PRODUCING HEAVY TO MODERATE PROPPANT RETURNS. THE EXPRO SAND TRAP AND VESSEL ARE KEEPING UP WITH THE SOLIDS. AS A PRECAUTION EXPRO HAS BEEN RUNNING VELOCITY CALCULATIONS AND PERFORMING UT CHECKS ON HIGH WEAR AREAS..LIQUID AND GAS RETURNS ARE BEING SENT TO PRODUCTION.THE WELL IS ALSO PRODUCING TRACE -.5% SOLIDS (FORMATION SAND) .NO DART DEBRIS WAS RECOVERED YESTERDAY. WATER WEIGHT OF 8.39 PPG, SALINITY OF 16,000 PPM. SHUT IN LIFT GAS AT 09:00 AM.AS OF THIS MORNING 30 BBLS OF PROPPANT HAS BEEN RECOVERED IN THE EXPRO SOLIDS TANK DURRING THE FLOWBACK.. 8/2/2025 EXPRO CONTINUES HOLDING THE 76 /64 CHOKE SETTING FOR THE PAST 63 HOURS .THE WELL CONTINUES PRODUCING MODERATE PROPPANT RETURNS. THE EXPRO SAND TRAP AND VESSEL ARE KEEPING UP WITH THE SOLIDS. AS A PRECAUTION EXPRO HAS BEEN RUNNING VELOCITY CALCULATIONS AND PERFORMING UT CHECKS ON HIGH WEAR AREAS..LIQUID AND GAS RETURNS ARE BEING SENT TO PRODUCTION.THE WELL IS ALSO PRODUCING TRACE -.25% SOLIDS (FORMATION SAND) .NO DART DEBRIS WAS RECOVERED YESTERDAY. WATER WEIGHT OF 8.30 PPG, SALINITY OF 14,000 PPM. 8/3/2025 EXPRO CONTINUES HOLDING THE 76 /64 CHOKE SETTING DUE TO LIGHT TO MODERATE PROPPANT RETURNS FOR THE MAJORITY OF THE DAY.21:00 BHP STARTED TO INCREASE.22:00 PROPPANT RETURNS INCREASED BACK TO HEAVY RETURNS.22:00 FLUID RETURNS STARTING TO INCREASE.01:30 PROPPANT RETURNS ARE BACK TO MODERATE WHERE THEY CURRENTLY REMAIN. THE EXPRO SAND TRAP AND VESSEL ARE KEEPING UP WITH THE SOLIDS. AS A PRECAUTION EXPRO HAS BEEN RUNNING VELOCITY CALCULATIONS AND PERFORMING UT CHECKS ON HIGH WEAR AREAS..LIQUID AND GAS RETURNS ARE BEING SENT TO PRODUCTION.NO DART DEBRIS WAS RECOVERED YESTERDAY. WATER WEIGHT OF 8.30 PPG, SALINITY OF 15,000 PPM. 8/4/2025 EXPRO MONITORING SOLIDS RETURNS, OPENING CHOKE BASED ON SOLIDS, CURRENTLY AT 54/64TH'S. 8/5/2025 EXPRO MONITORING SOLIDS RETURNS, OPENING CHOKE BASED ON SOLIDS, CURRENTLY AT 54/64TH'S. HOLDING 54/64TH'S DUE TO EROSION VELOCITIES 8/6/2025 EXPRO MONITORING SOLIDS RETURNS, OPENING CHOKE BASED ON SOLIDS, ATTEMPTING TO OPEN CHOKE AND MONITORING EROSION VELOCITIES 8/7/2025 EXPRO MONITORING SOLIDS RETURNS, OPENING CHOKE BASED ON SOLIDS, ATTEMPTING TO OPEN CHOKE AND MONITORING EROSION VELOCITIES 8/8/2025 EXPRO MONITORING SOLIDS RETURNS, OPENING CHOKE BASED ON SOLIDS, INCREASING INLET CHOKE AS WELL ALLOWS WITH SOLIDS CONTENTS 8/9/2025 EXPRO MONITORING SOLIDS RETURNS, CHOKE IS FULL OPEN, STARTED BYPASSING ALL THE EQUIPMENT POSSIBLE 8/10/2025 EXPRO MONITORING SOLIDS RETURNS, CHOKE IS FULL OPEN, ALL EQUIPMENT BYPASSED THAT CAN BE Rig: EXPRO 001 Sales Order# Prepared By: William Martin Derek Osselburn Nanook Crew 0910181328 Intervals 1-16 Coyote Notice: Although the information contained in this report is based on sound engineering practices, the copyright owner(s) does (do) not accept any responsibility whatsoever, in negligence or otherwise, for any loss or damage arising from the possession or use of the report whether in terms of correctness or otherwise. The application, therefore, by the user of this report or any part thereof, is solely at the user’s own risk. 3S-703 Conoco Phillips Harrison Bay County, AK Post Job Report Stimulation Treatment API: 50-103-20913 Prepared for: Madeline Woodard July 16, 2025 Coyote Formation 27# Delta Frac Table of Contents Section Page(s) Executive Summary Actual Design Wellbore Information Interval Summary Fluid System-Proppant Summary Interval 1 Plots Interval 2 Plots Interval 3 Plots Interval 4 Plots Interval 5 Plots Interval 6 Plots Interval 7 Plots Interval 8 Plots Interval 9 Plots Interval 10 Plots Interval 11 Plots Interval 12 Plots Interval 13 Plots Interval 14 Plots Interval 15 Plots Interval 16 Plots Appendix Well Summary Chemical Summary Planned Design Water Straps 7.13.25 Water Straps 7.14.25 Water Straps 7.15.25 Water Straps 7.16.25 Water Analysis 7.04.25 Water Analysis 7.14.25 Water Analysis 7.15.25 Water Analysis 7.16.25 Real-Time QC Event Log 7.07 Event Log 7.12 Event Log 7.13 Event Log 7.14 Event Log 7.15 Event Log 7.16 Prejob Break Test - 105 F Fann 15-min Test Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7 Zone 8 Zone 9 Zone 10 Zone 11 Zone 12 Zone 13 Zone 15 Zone 16 Sand Sieve Analysis 103 - 106 73 - 82 83 - 86 87 - 90 91 - 94 95 - 102 110 - 113 107 - 109 3 4 - 7 8 49 - 52 53 - 60 61 - 64 9 - 25 26 27 - 44 45 - 48 65 - 68 69 - 72 114 - 117 118 119 120 121 - 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 155 156 150 151 152 153 154 Conoco Phillips - 3S-703 TOC 2 1,220,144 gallons of 27# Delta Frac 104,876 gallons of 27# Linear 13,140 gallons of Seawater 4,800,000 pounds of Wanli 16/20 Ceramic 48,000 pounds of 100M 1,072,592 gallons of 27# Delta Frac 124,962 gallons of 27# Linear 26,144 gallons of Seawater 4,532,666 pounds of Wanli 16/20 Ceramic 45,000 pounds of 100M Thank you, William Martin Senior Technical Professional Halliburton maintains a continuous quality improvement process and appreciates any comments or suggestions that you may have. Halliburton again thanks you for the opportunity to perform service work on this well. We hope to be your solutions provider for future projects. EngineeringExecutiveSummary On July 07, 2025 a stimulation treatment was performed in the Coyote formation on the 3S-703 well in Harrison Bay County, AK. The 3S-703 was a 16 stage Horizontal Sleeve Design. The proposed treatment consisted of: The actual treatment fully completed 15 of 16 stages. 1 stages were skipped, 0 stage screened out and 0 stages were cut short of design. The actual treatment consisted of: A more detailed description of the actual treatment can be found in the attached reports. The following comments were provided to summarize events and changes to the proposed treatment: 3S-703 had fiber data and a pressure and temperature array at each sleeve that was monitored real time. The alpha sleeve was opened but pressure increased within 5 bbls of opening the sleeve and injection could not be established. A coiled tubing clean out run was performed and then frac established good injection. A back up dart had to be dropped on interval 03 and interval 10 because the pressure array indicated the sleeves did not open. The pressure array indicated that the primary dart did not open interval 14, 2 back up darts were dropped without any indication that the sleeve opened so the zone was skipped. Intervals 15 and 16 were pumped with adjusted designs to be more aggressive. Halliburton is strongly committed to quality control on location. Before and after each job all chemicals, proppants, and fluid volumes are measured to assure the highest level of quality control. Tank fluid analysis, crosslink time, and break tests are performed before each job in order to optimize the performance of the treatment fluids. A 27# Delta 140 Fluid system was pumped throughout the job. The supplied sea water had varying densities due to seasonal changes in supply at the Seawater Treatment Plant. Water with similar density and chloride readings were pumped together. Cla- Web was added to the fluid formulation as a clay control additive. MO-67 was pumped at a dilution ratio of 1 part MO and 2 parts water from the downhole blender. pH was monitored closely and MO-67 adjusted frequently to acheive desired pH. Conoco Phillips - 3S-703 Executive Summary 3 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In-1-2 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.151-3 Shut-In Shut-In-1-4 27# Linear Arsenal Sleeve Shift 5.0 1,260 1,350 32 32 1.00 1.00 0.50 27.00 2.00 0.151-5 Shut-In Shut-In-1-6 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.151-7 Seawater Injection Test 12.0 2,100 21,104 502 5020.151-8 Shut-In Shut-In-1-9 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.151-10 27# Linear DFIT 10.0 840 817 19 19 1.00 1.00 0.50 27.00 2.00 0.151-11 Shut-In Shut-In600 -1-12 27# Linear Step Rate Test 15.0 8,400 2,326 55 55 1.00 1.00 0.50 27.00 2.00 0.151-13 27# Delta Frac Establish Stable Fluid 15.0 8,400 4,026 96 96 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-14 27# Delta Frac Pad 20.0 16,430 16,493 393 393 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-15 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,057 144 147 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,852 92 99 7,700 6,300 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,397 152 180 25,600 25,176 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,204 148 188 37,200 36,888 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-19 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,697 231 308 67,900 70,082 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-20 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,697 207 288 69,600 73,335 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-21 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,991 143 206 54,000 57,514 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-22 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 4,775 114 147 38,000 30,433 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.151-23 27# Linear Spacer and Dart Drop 20.0 1,470 1,494 36 36 1.00 1.00 0.50 27.00 2.00 0.152-1 27# Linear Pre-Pad 20.0 2,100 2,195 52 52 1.00 1.00 0.50 27.00 2.00 0.152-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 3,002 71 71 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-3 27# Delta Frac Pad 20.0 16,430 16,478 392 392 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,006 143 146 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,849 92 99 7,700 7,085 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,390 152 180 25,600 25,437 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,206 148 189 37,200 37,297 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,705 231 308 67,900 69,431 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,695 207 286 69,600 71,307 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,988 143 203 54,000 54,965 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,145 123 160 38,000 34,411 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.152-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,346 32 32 1.00 1.00 0.50 27.00 2.00 0.153-1 27# Linear Pre-Pad 20.0 2,100 2,104 50 50 1.00 1.00 0.50 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 6,861 163 163 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-3 27# Delta Frac Pad 20.0 16,430 3,441 82 82 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-4 27# Linear Displacement 20.0 8,642 9,526 227 227 1.00 1.00 0.50 27.00 2.00 0.153-5 27# Linear Spacer and Dart Drop 15.0 1,260 2,091 50 50 1.00 1.00 0.50 27.00 2.00 0.153-6 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,925 46 46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-7 27# Delta Frac Pad 20.0 16,430 17,232 410 410 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-8 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,008 143 146 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,842 91 95 7,700 3,218 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,400 152 180 25,600 25,094 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,200 148 187 37,200 35,866 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,699 231 306 67,900 68,141 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,700 207 286 69,600 71,476 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,998 143 204 54,000 55,154 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,717 136 178 38,000 37,649 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-16 27# Linear Flush 20.0 8,663 8,695 207 207 1.00 1.00 0.50 27.00 2.00 0.153-17 Seawater Freeze Protect 5.0 1,260 -0.153-18 Shut-In Shut-In-50-103-209130910181328Liquid Additives Dry AdditivesInterval 1Coyote@ 13275.89 - 13279.89 ft 104.5 °FInterval 2Coyote@ 12711.31 - 12715.31 ft 104.5 °FInterval 3Coyote@ 12205.54 - 12209.54 ft 104.5 °FConoco Phillips - 3S-703Actual Design4 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)50-103-209130910181328Liquid Additives Dry Additives4-1 Shut-In Shut-In-4-2 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.154-3 Shut-In Shut-In-4-4 27# Linear Spacer and Dart Drop 15.0 1,260 1,260 30 30 1.00 1.00 0.50 27.00 2.00 0.154-5 27# Delta Frac Establish Stable Fluid 15.0 8,400 3,215 77 77 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.154-6 27# Delta Frac Pad 20.0 16,430 17,245 411 411 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.154-7 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,018 143 147 3,000 3,000 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,848 92 99 7,700 6,849 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,404 152 179 25,600 24,351 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,198 148 187 37,200 36,119 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,696 231 306 67,900 68,461 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,704 207 286 69,600 71,740 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,999 143 204 54,000 55,851 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,811 138 181 38,000 38,322 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.154-15 27# Linear Spacer and Dart Drop 20.0 1,470 1,311 31 31 1.00 1.00 0.50 27.00 2.00 0.155-1 27# Linear Pre-Pad 20.0 2,100 2,092 50 50 1.00 1.00 0.50 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,611 38 38 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.155-3 27# Delta Frac Pad 20.0 16,430 16,387 390 390 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,191 147 151 3,000 3,000 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,861 92 100 7,700 7,013 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,403 152 177 25,600 22,344 0.45 1.00 0.52 1.00 0.50 27.00 2.00 0.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,206 148 185 37,200 33,788 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,701 231 305 67,900 67,162 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,710 207 287 69,600 72,608 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,999 143 205 54,000 56,711 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 6,165 147 191 38,000 40,518 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.155-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,400 33 33 1.00 1.00 0.50 27.00 2.00 0.156-1 27# Linear Pre-Pad 20.0 2,100 2,115 50 50 1.00 1.00 0.50 27.00 2.00 0.156-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,555 37 37 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.156-3 27# Delta Frac Pad 20.0 16,430 16,557 394 394 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.156-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,003 143 146 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.156-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,854 92 99 7,700 6,926 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.156-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,406 153 180 25,600 24,715 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.156-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,200 148 188 37,200 36,266 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.156-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,714 231 308 67,900 69,520 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.156-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,694 207 288 69,600 73,893 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.156-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,999 143 205 54,000 56,770 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,130 122 156 38,000 30,292 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.156-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,606 38 38 1.00 1.00 0.50 27.00 2.00 0.157-1 27# Linear Pre-Pad 20.0 2,100 2,113 50 50 1.00 1.00 0.50 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 2,073 49 49 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-3 27# Delta Frac Pad 20.0 16,430 16,448 392 392 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,026 143 147 3,000 3,000 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,862 92 101 7,700 8,208 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,397 152 182 25,600 26,700 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,201 148 189 37,200 37,223 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,700 231 308 67,900 70,138 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,700 207 285 69,600 70,624 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,997 143 203 54,000 54,996 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,488 131 165 38,000 31,544 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-12 27# Linear Flush 20.0 6,433 6,441 153 153 1.00 1.00 0.50 27.00 2.00 0.157-13 Seawater Freeze Protect 5.0 1,260 -0.157-14 Shut-In Shut-In-Interval 4Coyote@ 11746.86 - 11750.86 ft 104.5 °FInterval 6Coyote@ 10695.48 - 10699.48 ft 104.5 °FInterval 7Coyote@ 10195.85 - 10199.85 ft 104.5 °FInterval 5Coyote@ 11198.38 - 11202.38 ft 104.5 °FConoco Phillips - 3S-703Actual Design5 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)50-103-209130910181328Liquid Additives Dry Additives8-1 Shut-In Shut-In-8-2 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.158-3 Shut-In Shut-In-8-4 27# Linear Spacer and Dart Drop 15.0 1,260 1,837 44 44 1.00 1.00 0.50 27.00 2.00 0.158-5 27# Linear Displace Dart to Seat 15.0 6,224 5,607 134 134 1.00 1.00 0.50 27.00 2.00 0.158-6 27# Linear DFIT 5.0 840 830 20 20 1.00 1.00 0.50 27.00 2.00 0.158-7 Shut-In Shut-In-8-8 27# Delta Frac Establish Stable Fluid 15.0 8,400 1,688 40 40 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.158-9 27# Delta Frac Pad 20.0 16,430 16,495 393 393 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.158-10 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,018 143 147 3,000 3,000 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,858 92 99 7,700 6,261 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.158-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 3,698 88 115 25,600 24,679 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.158-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,209 148 189 37,200 37,210 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.158-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,702 231 304 67,900 66,208 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.158-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,698 207 282 69,600 67,886 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.158-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 6,003 143 203 54,000 54,671 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.158-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,966 142 190 38,000 43,559 0.45 1.00 0.40 1.00 0.50 27.00 2.00 0.158-18 27# Linear Spacer and Dart Drop 20.0 1,470 1,394 33 33 1.00 1.00 0.50 27.00 2.00 0.159-1 27# Linear Pre-Pad 20.0 2,100 2,220 53 53 1.00 1.00 0.50 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,558 37 37 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-3 27# Delta Frac Pad 20.0 16,430 16,475 392 392 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,009 143 146 3,000 3,000 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,851 92 100 7,700 7,464 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,401 152 180 25,600 25,067 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,197 148 188 37,200 36,504 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,696 231 307 67,900 69,246 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,700 207 286 69,600 71,691 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,995 143 204 54,000 55,847 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,660 135 173 38,000 35,106 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,401 33 33 1.00 1.00 0.50 27.00 2.00 0.1510-1 27# Linear Pre-Pad 20.0 2,100 2,104 50 50 1.00 1.00 0.50 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,154 27 27 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1510-3 27# Delta Frac Pad 20.0 4,064 4,064 97 97 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1510-4 27# Linear Displacement 20.0 5,560 5,629 134 134 1.00 1.00 0.50 27.00 2.00 0.1510-5 Shut-In Shut-In-10-6 27# Linear Spacer and Dart Drop 20.0 1,260 2,349 56 56 1.00 1.00 0.50 27.00 2.00 0.1510-7 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,677 40 40 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1510-8 27# Delta Frac Pad 20.0 16,430 16,436 391 391 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1510-9 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,087 145 148 3,000 3,000 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,904 93 102 7,700 7,782 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,395 152 179 25,600 24,226 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.1510-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,200 148 188 37,200 36,327 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.1510-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,695 231 306 67,900 68,258 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.1510-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,665 206 285 69,600 71,225 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.1510-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,997 143 203 54,000 55,004 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.1510-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,588 133 174 38,000 37,228 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.1510-17 27# Linear Spacer and Dart Drop 20.0 1,470 1,521 36 36 1.00 1.00 0.50 27.00 2.00 0.1511-1 27# Linear Pre-Pad 20.0 2,100 2,034 48 48 1.00 1.00 0.50 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,396 33 33 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-3 27# Delta Frac Pad 20.0 16,430 16,351 389 389 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,022 143 147 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,900 93 100 7,700 6,627 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,422 153 181 25,600 25,346 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,198 148 189 37,200 37,237 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,711 231 309 67,900 70,853 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,691 207 286 69,600 71,482 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 6,002 143 205 54,000 56,377 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,481 131 168 38,000 34,045 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-12 27# Linear Flush 20.0 5,237 5,154 123 123 1.00 1.00 0.50 27.00 2.00 0.1511-13 Seawater Freeze Protect 5.0 1,260 -0.1511-14 Shut-In Shut-In-Interval 8Coyote@ 9737.14 - 9741.14 ft 104.5 °FInterval 9Coyote@ 9197.51 - 9201.51 ft 104.5 °FInterval 10Coyote@ 8698.18 - 8702.18 ft 104.4 °FInterval 11Coyote@ 8192.39 - 8196.39 ft 104.4 °FConoco Phillips - 3S-703Actual Design6 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)50-103-209130910181328Liquid Additives Dry Additives12-1 Shut-In Shut-In-12-2 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.1512-3 Shut-In Shut-In-12-4 27# Linear Spacer and Dart Drop 15.0 1,260 2,423 58 58 1.00 1.00 0.50 27.00 2.00 0.1512-5 27# Delta Frac Establish Stable Fluid 15.0 8,400 2,099 50 50 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.1512-6 27# Delta Frac Pad 20.0 16,430 16,488 393 393 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.1512-7 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,011 143 146 3,000 3,000 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,937 94 102 7,700 7,246 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,415 153 179 25,600 24,247 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,195 148 187 37,200 35,389 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,902 236 312 67,900 69,061 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,707 207 284 69,600 69,870 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 6,000 143 203 54,000 54,787 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 5,908 141 184 38,000 39,681 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1512-15 27# Linear Spacer and Dart Drop 20.0 1,470 1,499 36 36 1.00 1.00 0.50 27.00 2.00 0.1513-1 27# Linear Pre-Pad 20.0 2,100 2,350 56 56 1.00 1.00 0.50 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,047 25 25 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-3 27# Delta Frac Pad 20.0 16,430 16,544 394 394 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,819 162 166 3,000 3,000 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 3,850 3,847 92 99 7,700 6,810 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 6,400 6,396 152 180 25,600 24,949 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 6,200 6,283 150 190 37,200 36,918 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,700 231 303 67,900 65,078 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,703 207 282 69,600 68,236 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,995 143 202 54,000 53,964 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 3,800 6,187 147 194 38,000 41,933 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.1513-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,058 25 25 1.00 1.00 0.50 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20.0 2,100 2,267 54 54 1.00 1.00 0.50 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 710 17 17 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-3 27# Delta Frac Pad 20.0 2,036 48 48 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-4 27# Linear Displacement 20.0 5,332 127 127 1.00 1.00 0.50 27.00 2.00 0.1514-5 Shut-In Shut-In-14-6 27# Linear Spacer and Dart Drop 20.0 2,787 66 66 1.00 1.00 0.50 27.00 2.00 0.1514-7 27# Delta Frac Establish Stable Fluid 20.0 1,384 33 33 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-8 27# Delta Frac Pad 20.0 3,145 75 75 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-9 27# Linear Displacement 20.0 4,005 95 95 1.00 1.00 0.50 27.00 2.00 0.1514-10 Shut-In Shut-In-14-11 27# Linear Spacer and Dart Drop 20.0 1,361 32 32 1.00 1.00 0.50 27.00 2.00 0.1514-12 27# Linear Displacement 20.0 5,970 142 142 1.00 1.00 0.50 27.00 2.00 0.1514-13 Shut-In Shut-In-14-14 27# Linear Spacer and Dart Drop 20.0 1,597 38 38 1.00 1.00 0.50 27.00 2.00 0.1514-15 27# Delta Frac Establish Stable Fluid 20.0- 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-16 27# Delta Frac Pad 20.0 15,430 - 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-17 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 - 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 - 4,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-19 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 - 12,800 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-20 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 8,200 - 49,200 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-21 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 - 67,900 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-22 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 - 69,600 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-23 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 - 54,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-24 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 4,250 - 42,500 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-25 27# Linear Spacer and Dart Drop 20.0 1,470 - 1.00 1.00 0.50 27.00 2.00 0.1515-1 27# Linear Displacement 20.0 2,100 4,100 98 98 1.00 1.00 0.50 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20.0 8,400 1,668 40 40 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-3 27# Delta Frac Pad 20.0 15,430 15,418 367 367 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,013 143 146 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 2,009 48 52 4,000 3,421 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,206 76 89 12,800 11,511 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 8,200 8,200 195 246 49,200 45,650 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,704 231 305 67,900 67,234 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,683 207 285 69,600 71,040 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 6,006 143 205 54,000 56,154 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 4,250 6,448 154 204 42,500 45,495 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,638 39 39 1.00 1.00 0.50 27.00 2.00 0.1516-1 27# Linear Pre-Pad 20.0 2,100 2,626 63 63 1.00 1.00 0.50 27.00 2.00 0.1516-2 27# Delta Frac Establish Stable Fluid 15.0 8,400 1,600 38 38 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-3 27# Delta Frac Pad 20.0 7,700 7,747 184 184 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,013 143 146 3,000 3,000 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 2,007 48 51 4,000 3,080 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,206 76 90 12,800 12,281 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 8,200 8,198 195 250 49,200 49,720 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 9,700 9,692 231 309 67,900 70,784 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 8,700 8,709 207 290 69,600 74,530 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 6,000 5,973 142 204 54,000 55,911 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 4,250 5,669 135 173 42,500 34,886 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-12 27# Linear Flush 20.0 3,637 3,587 85 85 1.00 1.00 0.50 27.00 2.00 0.1516-13 Seawater Freeze Protect 5.0 1,260 -0.1516-14 Shut-In Shut-In-1,338,160 1,223,698 29,736 34,144 4,848,000 4,544,193Design Total (gal)Actual Total (gal)Design Total (lbs)Calculated Total (lbs)Ticket Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-61,220,144 1,072,592 4,800,000 4,499,193 4,532,666(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)104,876 124,962 48,000 45,000 45,000 Initial Design Material Volume 549.1 1,325.0 721.8 1,325.0 662.5 35,775.5 2,650.0 200.713,140 26,144 - - - Actual Design Material Volume 486.9 1,197.6 618.2 1,197.6 598.8 32,334.0 2,395.1 183.6- - - Physical Material Volume Pumped 505 1,215 615 1,190 620 33442 2,410 198- - - - - Physical Material Volume Deviance 4% 1% -1% -1% 4% 3% 1% 8%--** IFS numbers for proppant are taken from software calculations based on multiple variablesMicroMotion Volume Pumped 489 1,209 619 1,208 606 31,735 2,414 ---** Proppant is billed from Weight Ticket volumesMicroMotion Volume Deviance 0% 1% 0% 1% 1% -2% 1% ---Interval 15Coyote@ 6190.67 - 6194.67 ft 104.3 °F-Fluid Type27# Delta Frac27# LinearSeawaterFreeze Protect-Proppant TypeWanli 16/20 Ceramic100M-----Interval 12Coyote@ 7733.6 - 7737.6 ft 104.3 °FInterval 16Coyote@ 5690.56 - 5694.56 ft 104.2 °FInterval 13Coyote@ 7191.9 - 7195.9 ft 104.3 °FInterval 14Coyote@ 6689.2 - 6693.2 ft 104.3 °FConoco Phillips - 3S-703Actual Design7 Conoco Phillips Coyote3S-70350-103-20913*Exceeds 80% of burst pressure*Description OD (in) ID (in) Wt (#) GradeFUF (gal/ft)MD Top (ft)MD Btm (ft) Volume (gal)Tubular Burst Pressure (psi)Tubing4.5 3.958 12.6 L-80 0.6392 0 13,395 8,562 8,430Total13,3958,562ft1.06ft104.5ftft1.06ft104.5ftTop MD (ft)Btm MD (ft)Average TVD (ft)Interval # Formation DescriptorAverage Interval Temperature (F)Ball Drop Time (HH:MM)Ball Hit Time (HH:MM)JSV Drop (bbl)JSV Slow Down (bbl)JSV Hit (bbl)Early (bbl)Surface Seat Pressure (psi)Surface Peak Pressure (psi)Surface Differential (psi)BH Seat Pressure (psi)BH Peak Pressure (psi)BH Differential (psi)Rate at Shift (bpm)Toe13,276 13,280 4,2081Coyote104.5alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha12,711 12,715 4,2052Coyote104.51:34:16 PM 1:42:54 PM 2,163 2,356 2,33422.52,085 5,151 3,066 3,468 6,443 2,975 15.112,206 12,210 4,2053Coyote104.53:18:13 PM 4:04:25 PM 4,835 5,021 5,00911.82,267 4,679 2,412 3,614 6,020 2,406 14.811,747 11,751 4,2064Coyote104.58:33:39 AM 8:42:31 AM 29 208 1989.82,306 5,332 3,026 3,467 6,399 2,932 15.011,198 11,202 4,2065Coyote104.510:18:19 AM 10:26:16 AM 2,139 2,309 2,29217.42,016 5,542 3,526 3,271 6,835 3,564 14.910,695 10,699 4,2066Coyote104.512:04:10 PM 12:11:57 PM 4,251 4,414 4,40013.81,889 4,687 2,798 3,107 5,940 2,833 15.010,196 10,200 4,2067Coyote104.51:48:22 PM 1:55:44 PM 6,341 6,496 6,48214.21,717 6,382 4,665 3,115 7,855 4,740 14.99,737 9,741 4,2068Coyote104.58:07:39 AM 8:14:59 AM 27 175 16510.21,589 4,694 3,105 3,165 5,936 2,771 15.29,198 9,202 4,2049Coyote104.510:40:12 AM 10:46:17 AM 2,254 2,394 2,38113.01,893 5,733 3,840 3,201 6,964 3,763 20.88,698 8,702 4,20010Coyote104.412:22:33 PM 12:59:50 PM 4,695 4,827 4,8216.42,357 5,437 3,080 3,631 6,431 2,800 20.78,192 8,196 4,19311Coyote104.42:34:54 PM 2:40:17 PM 6,773 6,898 6,88611.71,692 4,142 2,450 3,047 5,468 2,421 21.07,734 7,738 4,19212Coyote104.37:04:13 AM 7:09:25 AM 44 162 1538.71,749 4,804 3,055 3,025 5,940 2,915 20.77,192 7,196 4,19013Coyote104.38:45:18 AM 8:49:59 AM 2,132 2,241 2,23011.51,508 4,416 2,908 2,973 5,834 2,861 20.96,689 6,693 4,18714Coyote104.310:27:40 AM No Shift 4,785 4,887 No ShiftNo ShiftNo Shift No Shift No Shift No Shift No Shift No Shift No Shift6,191 6,195 4,18515Coyote104.311:54:47 AM 12:00:21 PM 4,971 5,065 5,0587.21,200 3,862 2,662 2,811 5,430 2,619 15.4Heel5,691 5,695 4,17516Coyote104.21:37:30 PM 1:42:10 PM 7,054 7,141 7,1373.61,239 4,171 2,932 2,843 5,651 2,808 15.386.6155.2148.2140.0132.4124.7117.74,9434,5974,2763,9573,6376,5176,2245,8795,5605,2377,802 185.87,5097,1586,837Displacement to Top Sleeve/Perf (gal)(BBLS)8,486 202.08,125 193.5178.8170.4162.8Interval #1Max Pressure (psi)8,500Isolation TypeCemented LinerTreatment TubularsCustomerFormationLeaseAPIDateTemperature DataTemp. Gradient (°F/100 ft)BHST (°F)Directional Data4,1982,23713,395Directional Data2,2377/7/2025KOPTemperature DataSleeve/Perf DepthSleeves109.5101.894.27891011234561213141516Temp. Gradient (°F/100 ft)BHST (°F)TVD at Bottom PerfMD at Bottom Perf4,20813,280KOPAvg. TVDTotal MDConoco Phillips - 3S-703 Wellbore Information8 7/13/25 10:59 7/13/25 13:34 155 min alpha bpm alpha psi alpha psi alpha bbl 21.2 bpm 3,251 psi 4,537 psi 20.2 bpm 2,981 psi 2,749 psi 4,319 psi 1,475 hhp 613 psi 3 psi 20 psi 11.07 ppg 6 6 28 % 28 % 22 cP 82 F 8.6 DFIT 4.992 bpm 1583 psi 3219 psi 5.103 bpm 1625 psi 3292 psi 2928 psi 0.696 psi/ft 2728 psi 2618 psi 2541 psi 299,728 lbs 3,000 lbs 302,728 lbs 302,728 lbs 72,189 gal 1,719 bbls 5,987 gal 143 bbls 23,624 gal 562 bbls Total Proppant Pumped* : Fluid Summary (by fluid description) Proppant Summary Minifrac Average Pressure: Minifrac Average DH Pressure: Average Visc: Average Temp: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Rate: Max Surface Pressure: Max BH Pressure: Interval Summary 3S-703 - Coyote - Interval 1 Interval Summary Start Date/Time: End Date/Time: Average Surface Pressure: Average Rate: Max OA Pressure: Pumps Starting Stage: Pad Percentage Design Average Missile HHP: Initial BH Pressure (Breakdown): Average BH Pressure: Pumps Ending Stage: Max Proppant Concentration: Pump Time: ISDP: Final Fracture Gradient: Final 10 min: Minifrac Max Surface Pressure: 100M Pumped: Final 15 min: Proppant in Formation: 27# Delta Frac Volume: 27# Linear Volume: Seawater Volume: Minifrac Max DH Pressure: Final 5 min: Dart/Ball Early : Average pH: Minifrac Average Rate: Pad Percentage Actual Wanli 16/20 Ceramic Pumped: Diagnostic method Average Missile Pressure: Minifrac Max Rate: Open Well Pressure: Initial OA Pressure: Conoco Phillips - 3S-703 Interval Summary 9 16,493 gal 393 bbls 6,057 gal 144 bbls 45,613 gal 1,086 bbls 1,494 gal 36 bbls 2,326 gal 55 bbls 4,026 gal 96 bbls 817 gal 19 bbls 1,350 gal 32 bbls 21,104 gal 502 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep:Dan Faur William Martin Fluid Summary (by stage description) Injection Test Volume: Establish Stable Fluid Volume: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Step Rate Test Volume: Spacer and Dart Drop Volume: Interval Status: Ryan Knight Derek Osselburn The Arsenal Disk was burst at 7,402 psi DH and the Alpha Sleeve was shifted at 8,029 psi DH. A DFIT was started after the Alpha Sleeve was opened but pressure increased and kicked out all of the pumps. Injection could not be established. On 7/12 after a coil clean out, a successful injection test was pumped. On 7/13 a DFIT was pumped to start the day, Closure was found to be 2,734 psi after monitoring decline for 28 minutes. A step rate was pumped starting at a rate of 0.6 bpm. In Pad, pump 454 was neutraled for a mechanical issue that was resolved. In 8ppg, there was a rate fluctuation due to debris in a pump. Interval 1 pumped to completion. DFIT Volume: Arsenal Sleeve Shift Volume: Madeline Woodard Conditioning Pad Volume: Proppant Laden Fluid Volume: Pad Volume: Conoco Phillips - 3S-703 Interval Summary 10 7/13/25 13:34 7/13/25 15:18 104 min 15.1 bpm 5,151 psi 6,443 psi 22 bbl 21.2 bpm 3,046 psi 4,402 psi 20.5 bpm 2,752 psi 2,530 psi 4,088 psi 1,379 hhp 19 psi 38 psi 10.80 ppg 6 6 28 % 27 % 21 cP 88 F 8.7 299,933 lbs 3,000 lbs 302,933 lbs 302,933 lbs 71,464 gal 1,702 bbls 3,541 gal 84 bbls 2,195 gal 52 bbls 16,478 gal 392 bbls 6,006 gal 143 bbls 45,978 gal 1,095 bbls 1,346 gal 32 bbls 3,002 gal 71 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: Interval pumped to completion. *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Dan Faur William Martin Ryan Knight Derek Osselburn Madeline Woodard Wanli 16/20 Ceramic Pumped: 100M Pumped: Total Proppant Pumped* : 27# Delta Frac Volume: 27# Linear Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Spacer and Dart Drop Volume: Establish Stable Fluid Volume: Proppant Summary Interval Summary Start Date/Time: End Date/Time: Pump Time: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Average Surface Pressure: 3S-703 - Coyote - Interval 2 Average BH Pressure: Average Missile HHP: Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: Pumps Starting Stage: Pumps Ending Stage: Average Visc: Average Temp: Average pH: Pad Percentage Design Pad Percentage Actual Proppant in Formation: Fluid Summary (by fluid description) Fluid Summary (by stage description) Pre-Pad Volume: Pad Volume: Conoco Phillips - 3S-703 Interval Summary 11 7/13/25 15:18 7/13/25 17:48 150 min 14.8 bpm 4,679 psi 6,020 psi 12 bbl 20.8 bpm 2,930 psi 4,299 psi 20.2 bpm 2,528 psi 2,315 psi 3,884 psi 1,252 hhp 38 psi 523 psi 10.74 ppg 5 4 40 % 31 % 20 cP 95 F 8.6 2883 psi 0.686 psi/ft 2841 psi 2821 psi 2805 psi 296,598 lbs 3,000 lbs 299,598 lbs 299,598 lbs 82,023 gal 1,953 bbls 22,416 gal 534 bbls 2,104 gal 50 bbls 20,673 gal 492 bbls 6,008 gal 143 bbls 46,556 gal 1,108 bbls 9,526 gal 227 bbls 2,091 gal 50 bbls 8,695 gal 207 bbls 8,786 gal 209 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Establish Stable Fluid Volume: 27# Delta Frac Volume: William Martin Ryan Knight Derek Osselburn Interval Status: Upon resuming XL after dropping the dart, the establish stable fluid stage was extended to swap from low salinity to high salinity tanks and esure XL was good. After seating the first dart for interval 03. Treating pressure was high from friction and P3 from the pressure array indicated that the sleeve didn't open. XL was flushed from the well with gel and the back up dart was loaded. The back up dart landed and P3 indicated the sleeve opened. In 7ppg, rate was dropped briefly to get out of pump 454 for the preload bladder. The interval was pumped to completion. *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) Proppant Laden Fluid Volume: Flush Volume: Madeline Woodard Dan Faur 3S-703 - Coyote - Interval 3 End Date/Time: Max BH Pressure: Average Rate: Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Max Surface Pressure: Pump Time: Initial Rate (Breakdown): Fluid Summary (by stage description) Pre-Pad Volume: Conditioning Pad Volume: Initial Surface Pressure (Breakdown): Start Date/Time: Average BH Pressure: Pumps Starting Stage: Pumps Ending Stage: Average pH: Final 5 min: 27# Linear Volume: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Pad Percentage Design Pad Percentage Actual Final Fracture Gradient: Average Visc: Initial OA Pressure: ISDP: Interval Summary Average Missile HHP: Average Temp: Average Missile Pressure: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Pad Volume: Proppant Summary Spacer and Dart Drop Volume: Displacement Volume: Final 10 min: Final 15 min: Conoco Phillips - 3S-703 Interval Summary 12 7/14/25 8:31 7/14/25 10:18 107 min 15.0 bpm 5,332 psi 6,399 psi 10 bbl 21.1 bpm 2,979 psi 4,293 psi 20.3 bpm 2,685 psi 2,460 psi 3,938 psi 1,333 hhp 759 psi 102 psi 186 psi 10.46 ppg 5 5 28 % 28 % 23 cP 82 F 8.85 301,693 lbs 3,000 lbs 304,693 lbs 304,693 lbs 73,138 gal 1,741 bbls 2,571 gal 61 bbls 840 gal 20 bbls 17,245 gal 411 bbls 6,018 gal 143 bbls 46,660 gal 1,111 bbls 2,571 gal 61 bbls 3,215 gal 77 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Madeline Woodard Dan Faur William Martin Ryan Knight Interval pumped to completion. Derek Osselburn Pad Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Fluid Summary (by stage description) Establish Stable Fluid Volume: Interval Status: Max BH Pressure: Proppant Summary Wanli 16/20 Ceramic Pumped: Total Proppant Pumped* : Pad Percentage Design Average Surface Pressure: Pumps Starting Stage: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Average Visc: Average Temp: Average pH: Initial OA Pressure: Initial Surface Pressure (Breakdown): End Date/Time: Pump Time: 3S-703 - Coyote - Interval 4 Interval Summary Start Date/Time: Average Rate: Average Missile Pressure: Average BH Pressure: Average Missile HHP: Pumps Ending Stage: Pad Percentage Actual Initial BH Pressure (Breakdown): Open Well Pressure: Dart/Ball Early : Max Rate: 27# Linear Volume: 27# Delta Frac Volume: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Initial Rate (Breakdown): Proppant in Formation: Max Surface Pressure: Fluid Summary (by fluid description) Seawater Volume: Spacer and Dart Drop Volume: Conoco Phillips - 3S-703 Interval Summary 13 7/14/25 10:18 7/14/25 12:04 106 min 14.9 bpm 5,542 psi 6,835 psi 17 bbl 21.0 bpm 3,021 psi 4,167 psi 20.1 bpm 2,528 psi 2,332 psi 3,801 psi 1,248 hhp 189 psi 432 psi 10.76 ppg 5 5 28 % 27 % 22 cP 90.56 F 8.67 300,144 lbs 3,000 lbs 303,144 lbs 303,144 lbs 71,234 gal 1,696 bbls 3,492 gal 83 bbls 2,092 gal 50 bbls 16,387 gal 390 bbls 6,191 gal 147 bbls 47,045 gal 1,120 bbls 1,400 gal 33 bbls 1,611 gal 38 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: End Date/Time: Max BH Pressure: Average Surface Pressure: Interval Summary Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Wanli 16/20 Ceramic Pumped: Conditioning Pad Volume: 27# Linear Volume: 100M Pumped: 3S-703 - Coyote - Interval 5 Average BH Pressure: Initial OA Pressure: Max Proppant Concentration: Start Date/Time: Pad Percentage Design Average Rate: Proppant in Formation: Pad Volume: William Martin Average Missile HHP: Average Visc: Max Surface Pressure: Average pH: Pad Percentage Actual Establish Stable Fluid Volume: 27# Delta Frac Volume: Spacer and Dart Drop Volume: Proppant Laden Fluid Volume: Interval Status: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Madeline Woodard Dan Faur Derek Osselburn Pump Time: Ryan Knight Interval 5 had high initial pressure after the sleeve shifted but the fiber indicated flow was going to the correct sleeve. In 8ppg proppant, rate fluctuated due to debris going through a pump. Interval pumped to completion. Pumps Starting Stage: Pumps Ending Stage: Average Missile Pressure: Max OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Temp: Initial Surface Pressure (Breakdown): Max Rate: Total Proppant Pumped* : Initial Rate (Breakdown): Pre-Pad Volume: Conoco Phillips - 3S-703 Interval Summary 14 7/14/25 12:04 7/14/25 13:48 104 min 15.0 bpm 4,687 psi 5,940 psi 14 bbl 21.1 bpm 2,825 psi 4,146 psi 20.2 bpm 2,520 psi 2,310 psi 3,748 psi 1,245 hhp 461 psi 602 psi 10.63 ppg 5 5 28 % 28 % 21.78 cP 93.67 F 8.67 298,382 lbs 3,000 lbs 301,382 lbs 301,382 lbs 70,112 gal 1,669 bbls 3,721 gal 89 bbls 2,115 gal 50 bbls 16,557 gal 394 bbls 6,003 gal 143 bbls 45,997 gal 1,095 bbls 1,606 gal 38 bbls 1,555 gal 37 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pump Time: Initial Rate (Breakdown): Average Missile HHP: 3S-703 - Coyote - Interval 6 Interval Summary Average pH: Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Establish Stable Fluid Volume: Pumps Starting Stage: Max Rate: Average Missile Pressure: Average Rate: Proppant in Formation: Average Surface Pressure: Average BH Pressure: 100M Pumped: Pumps Ending Stage: Pre-Pad Volume: Conditioning Pad Volume: Interval Status: Average Visc: Initial OA Pressure: Start Date/Time: 27# Delta Frac Volume: 27# Linear Volume: Pad Volume: Wanli 16/20 Ceramic Pumped: Pad Percentage Design Average Temp: Total Proppant Pumped* : Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : After cutting sand, rate fluctuations due to a pump cavitating while cleaning up. Interval pumped to completion. William Martin Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Madeline Woodard Dan Faur Proppant Laden Fluid Volume: End Date/Time: Max Surface Pressure: Max BH Pressure: Max OA Pressure: Spacer and Dart Drop Volume: Max Proppant Concentration: Pad Percentage Actual Conoco Phillips - 3S-703 Interval Summary 15 7/14/25 13:48 7/14/25 15:39 111 min 14.9 bpm 6,382 psi 7,855 psi 14 bbl 21.3 bpm 3,575 psi 4,797 psi 20.3 bpm 2,474 psi 2,270 psi 3,740 psi 1,232 hhp 553 psi 605 psi 10.25 ppg 5 5 28 % 27 % 21 cP 90.4 F 8.7 2825 psi 0.672 psi/ft 2787 psi 2771 psi 2759 psi 299,433 lbs 3,000 lbs 302,433 lbs 302,433 lbs 70,892 gal 1,688 bbls 8,554 gal 204 bbls 2,113 gal 50 bbls 16,448 gal 392 bbls 6,026 gal 143 bbls 46,345 gal 1,103 bbls 6,441 gal 153 bbls 2,073 gal 49 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: Interval 07 had a high initial pressure. There was also an abnormal pressure spike shortly after getting back to 20 bpm after slowing down for the dart. Interval pumped to completion. Fluid Summary (by fluid description) Madeline Woodard 27# Delta Frac Volume: Dan Faur Establish Stable Fluid Volume: William Martin Derek Osselburn Fluid Summary (by stage description) Ryan Knight 27# Linear Volume: Interval Summary Final Fracture Gradient: Pump Time: Max Rate: Initial BH Pressure (Breakdown): Start Date/Time: Dart/Ball Early : Pad Percentage Actual Initial OA Pressure: Pad Percentage Design Pumps Starting Stage: Final 5 min: Proppant Summary Pumps Ending Stage: Flush Volume: Pre-Pad Volume: Pad Volume: 100M Pumped: ISDP: Average pH: Max Proppant Concentration: Final 10 min: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max OA Pressure: Average BH Pressure: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Average Visc: Conditioning Pad Volume: Final 15 min: Total Proppant Pumped* : *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Average Temp: Average Missile HHP: 3S-703 - Coyote - Interval 7 End Date/Time: Proppant in Formation: Proppant Laden Fluid Volume: Conoco Phillips - 3S-703 Interval Summary 16 7/15/25 8:05 7/15/25 10:40 155 min 15.2 bpm 4,694 psi 5,936 psi 10 bbl 21.1 bpm 2,487 psi 3,819 psi 20.2 bpm 2,345 psi 2,079 psi 3,578 psi 1,159 hhp 492 psi 18 psi 256 psi 10.74 ppg 5 5 28 % 28 % 22 cP 91.67 F 8.83 DFIT 5.004 bpm 1251 psi 2976 psi 5.938 bpm 1274 psi 2998 psi 2744 psi 0.652 psi/ft 2705 psi 2673 psi 2637 psi 300,474 lbs 3,000 lbs 303,474 lbs 303,474 lbs 68,335 gal 1,627 bbls 9,668 gal 230 bbls 840 gal 20 bbls 5,607 gal 134 bbls 16,495 gal 393 bbls 6,018 gal 143 bbls 44,134 gal 1,051 bbls 3,231 gal 77 bbls 1,688 gal 40 bbls 830 gal 20 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: 27# Delta Frac Volume: Seawater Volume: Diagnostic method Interval Status: William Martin Dan Faur Ryan Knight Derek Osselburn Madeline Woodard Wanli 16/20 Ceramic Pumped: 100M Pumped: Proppant Summary Minifrac Average Rate: Establish Stable Fluid Volume: Interval Summary 3S-703 - Coyote - Interval 8 Fluid Summary (by fluid description) Pad Volume: Average Visc: Total Proppant Pumped* : 27# Linear Volume: Final 5 min: Final Fracture Gradient: Final 15 min: Conditioning Pad Volume: Average Missile HHP: Fluid Summary (by stage description) Pad Percentage Actual Pad Percentage Design Max Rate: Initial Surface Pressure (Breakdown): Start Date/Time: Initial BH Pressure (Breakdown): Minifrac Average Pressure: Minifrac Average DH Pressure: DFIT Volume: Average pH: Minifrac Max Surface Pressure: Average Surface Pressure: Pumps Starting Stage: ISDP: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Spacer and Dart Drop Volume: Proppant in Formation: Displace Dart to Seat Volume: Final 10 min: Average Temp: Pumps Ending Stage: A DFIT was pumped after seating the dart for interval 08. Pressure Decline was monitored for 44 minutes and closure was found to be 2,564 psi. Interval pumped to completion. Proppant Laden Fluid Volume: Average Missile Pressure: Initial Rate (Breakdown): Max Surface Pressure: Average Rate: Max Proppant Concentration: Average BH Pressure: Minifrac Max DH Pressure: Max OA Pressure: Open Well Pressure: Initial OA Pressure: Max BH Pressure: Dart/Ball Early : End Date/Time: Pump Time: Minifrac Max Rate: Conoco Phillips - 3S-703 Interval Summary 17 7/15/25 10:40 7/15/25 12:22 102 min 20.8 bpm 5,733 psi 6,964 psi 13 bbl 21.3 bpm 2,282 psi 3,625 psi 20.5 bpm 2,203 psi 1,964 psi 3,415 psi 1,109 hhp 256 psi 469 psi 10.49 ppg 5 5 28 % 27 % 22 cP 94.6 F 8.73 300,925 lbs 3,000 lbs 303,925 lbs 303,925 lbs 70,542 gal 1,680 bbls 3,621 gal 86 bbls 2,220 gal 53 bbls 16,475 gal 392 bbls 6,009 gal 143 bbls 46,500 gal 1,107 bbls 1,401 gal 33 bbls 1,558 gal 37 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Start Date/Time: End Date/Time: Pump Time: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. William Martin Ryan Knight Average Temp: Max Proppant Concentration: Pumps Starting Stage: Average Surface Pressure: Madeline Woodard Dan Faur Pre-Pad Volume: Establish Stable Fluid Volume: Spacer and Dart Drop Volume: 27# Delta Frac Volume: 27# Linear Volume: 3S-703 - Coyote - Interval 9 Conditioning Pad Volume: Proppant Laden Fluid Volume: Initial BH Pressure (Breakdown): Fluid Summary (by stage description) Average pH: Fluid Summary (by fluid description) Interval Summary Dart/Ball Early : Average Visc: Pad Percentage Design Total Proppant Pumped* : Max Surface Pressure: Max BH Pressure: Initial Rate (Breakdown): Max Rate: Pumps Ending Stage: Initial Surface Pressure (Breakdown): Proppant Summary Wanli 16/20 Ceramic Pumped: Average Missile Pressure: Max OA Pressure: Derek Osselburn Proppant in Formation: Average BH Pressure: Interval pumped to completion Interval Status: Pad Volume: Average Missile HHP: Initial OA Pressure: Average Rate: 100M Pumped: Pad Percentage Actual Conoco Phillips - 3S-703 Interval Summary 18 7/15/25 12:22 7/15/25 14:34 132 min 20.7 bpm 5,437 psi 6,431 psi 6 bbl 21.2 bpm 2,613 psi 3,686 psi 20.6 bpm 2,260 psi 2,027 psi 3,448 psi 1,139 hhp 470 psi 592 psi 10.44 ppg 5 5 31 % 31 % 22 cP 95.7 F 8.68 300,050 lbs 3,000 lbs 303,050 lbs 303,050 lbs 75,862 gal 1,806 bbls 11,603 gal 276 bbls 2,104 gal 50 bbls 20,500 gal 488 bbls 6,087 gal 145 bbls 46,444 gal 1,106 bbls 5,629 gal 134 bbls 3,870 gal 92 bbls 2,831 gal 67 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Madeline Woodard Dan Faur Initial BH Pressure (Breakdown): Pad Percentage Actual Pumps Starting Stage: Dart/Ball Early : 27# Delta Frac Volume: Average Visc: Pad Percentage Design Max OA Pressure: Average pH: Average BH Pressure: Interval Summary Pump Time: Start Date/Time: 3S-703 - Coyote - Interval 10 End Date/Time: While seating the dart for interval 10, the pressure array indicated that the sleeve for interval 10 was not opened. XL was displaced out of the well and the job shut down to load the backup dart. The sleeve was successfully shifted with the back up dart. Stage pumped to completion. 27# Linear Volume: Average Missile HHP: Wanli 16/20 Ceramic Pumped: Initial OA Pressure: Max Proppant Concentration: Displacement Volume: Proppant Laden Fluid Volume: 100M Pumped: Pre-Pad Volume: Pad Volume: Conditioning Pad Volume: Initial Surface Pressure (Breakdown): Proppant Summary Average Missile Pressure: Average Rate: Average Temp: Max Surface Pressure: Max BH Pressure: Pumps Ending Stage: Max Rate: Average Surface Pressure: Establish Stable Fluid Volume: Spacer and Dart Drop Volume: Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) Initial Rate (Breakdown): Interval Status: Fluid Summary (by stage description) William Martin Conoco Phillips - 3S-703 Interval Summary 19 7/15/25 14:34 7/15/25 16:20 106 min 21.0 bpm 4,142 psi 5,468 psi 12 bbl 21.4 bpm 2,218 psi 3,676 psi 20.6 bpm 2,110 psi 1,870 psi 3,317 psi 1,064 hhp 591 psi 669 psi 11.38 ppg 5 5 28 % 27 % 22 cP 97.5 F 8.68 2757 psi 0.658 psi/ft 2736 psi 2719 psi 2702 psi 301,967 lbs 3,000 lbs 304,967 lbs 304,967 lbs 70,174 gal 1,671 bbls 7,188 gal 171 bbls 2,034 gal 48 bbls 16,351 gal 389 bbls 6,022 gal 143 bbls 46,405 gal 1,105 bbls 5,154 gal 123 bbls 1,396 gal 33 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Fluid Summary (by stage description) Establish Stable Fluid Volume: Pre-Pad Volume: Pad Volume: After cutting sand, rate fluctuated due to a pump cavitating before recovering to normal rate. Interval pumped to completion. Madeline Woodard Dan Faur Flush Volume: Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Pad Percentage Design Average Surface Pressure: Max OA Pressure: Max BH Pressure: Average Rate: Average BH Pressure: Interval Summary Proppant Summary Fluid Summary (by fluid description) Total Proppant Pumped* : Proppant in Formation: Pumps Ending Stage: Pump Time: Initial BH Pressure (Breakdown): Dart/Ball Early : 27# Delta Frac Volume: 3S-703 - Coyote - Interval 11 End Date/Time: Max Proppant Concentration: Average Visc: Average Temp: Final 5 min: Final 15 min: Max Rate: Wanli 16/20 Ceramic Pumped: Average pH: Pad Percentage Actual Initial OA Pressure: William Martin Pumps Starting Stage: ISDP: 100M Pumped: Conditioning Pad Volume: Proppant Laden Fluid Volume: Final Fracture Gradient: Final 10 min: Start Date/Time: Interval Status: Average Missile HHP: 27# Linear Volume: Average Missile Pressure: Max Surface Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Conoco Phillips - 3S-703 Interval Summary 20 7/16/25 7:00 7/16/25 8:45 105 min 20.7 bpm 4,804 psi 5,940 psi 9 bbl 21.4 bpm 2,170 psi 3,362 psi 20.7 bpm 2,005 psi 1,755 psi 3,239 psi 1,015 hhp 405 psi 120 psi 120 psi 10.37 ppg 5 5 28 % 27 % 23 cP 88.6 F 8.77 300,281 lbs 3,000 lbs 303,281 lbs 303,281 lbs 71,662 gal 1,706 bbls 3,922 gal 93 bbls 840 gal 20 bbls 16,488 gal 393 bbls 6,011 gal 143 bbls 47,064 gal 1,121 bbls 3,922 gal 93 bbls 2,099 gal 50 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pumps Starting Stage: Max Proppant Concentration: Pump Time: 3S-703 - Coyote - Interval 12 Interval Summary Initial BH Pressure (Breakdown): Average Missile HHP: Initial Surface Pressure (Breakdown): Max OA Pressure: Average pH: Max Rate: Open Well Pressure: Initial OA Pressure: End Date/Time: Dart/Ball Early : Max BH Pressure: Average Visc: Ryan Knight Dan Faur Average Surface Pressure: Start Date/Time: Average Rate: Average Missile Pressure: Pad Percentage Actual Initial Rate (Breakdown): Average BH Pressure: Interval pumped to completion William Martin Proppant Summary Fluid Summary (by fluid description) 27# Delta Frac Volume: Fluid Summary (by stage description) Establish Stable Fluid Volume: 27# Linear Volume: Max Surface Pressure: Interval Status: Pad Volume: Conditioning Pad Volume: Spacer and Dart Drop Volume: Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Madeline Woodard Wanli 16/20 Ceramic Pumped: Pumps Ending Stage: Pad Percentage Design Seawater Volume: Proppant in Formation: Proppant Laden Fluid Volume: Average Temp: Total Proppant Pumped* : 100M Pumped: Conoco Phillips - 3S-703 Interval Summary 21 7/16/25 8:45 7/16/25 10:27 102 min 20.9 bpm 4,416 psi 5,834 psi 11 bbl 21.5 bpm 1,901 psi 3,306 psi 20.7 bpm 1,877 psi 1,630 psi 3,122 psi 951 hhp 110 psi 294 psi 10.68 ppg 5 5 28 % 28 % 22 cP 88.4 F 8.75 297,888 lbs 3,000 lbs 300,888 lbs 300,888 lbs 71,521 gal 1,703 bbls 3,408 gal 81 bbls 0 gal 0 bbls 0 gal 0 bbls 0 gal 0 bbls 2,350 gal 56 bbls 16,544 gal 394 bbls 6,819 gal 162 bbls 47,111 gal 1,122 bbls 0 gal 0 bbls 1,058 gal 25 bbls 1,047 gal 25 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Conditioning Pad Volume: Pad Percentage Actual Proppant Laden Fluid Volume: Fluid Summary (by stage description) Interval pumped to completion. William Martin Ryan Knight Derek Osselburn Fluid Summary (by fluid description) 27# Linear Volume: Interval Summary End Date/Time: Average Missile HHP: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Spacer and Dart Drop Volume: Pad Percentage Design Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Surface Pressure: Max Proppant Concentration: Madeline Woodard Dan Faur Total Proppant Pumped* : Initial BH Pressure (Breakdown): Average Missile Pressure: Pump Time: 3S-703 - Coyote - Interval 13 Max BH Pressure: Average Visc: Average pH: Initial OA Pressure: Pumps Ending Stage: Average Surface Pressure: Start Date/Time: Displace Dart to Seat Volume: Pumps Starting Stage: Average Rate: Proppant Summary Dart/Ball Early : Freeze Protect Volume: Max OA Pressure: Average Temp: Pad Volume: Max Rate: Wanli 16/20 Ceramic Pumped: Average BH Pressure: 100M Pumped: Pre-Pad Volume: Seawater Volume: Proppant in Formation: Displacement Volume: 27# Delta Frac Volume: Establish Stable Fluid Volume: Interval Status: Conoco Phillips - 3S-703 Interval Summary 22 7/16/25 10:27 7/16/25 11:54 87 min 0 lbs 0 lbs 0 lbs 0 lbs 7,275 gal 173 bbls 23,319 gal 555 bbls 2,267 gal 54 bbls 5,181 gal 123 bbls 15,307 gal 364 bbls 5,745 gal 137 bbls 2,094 gal 50 bbls Skipped Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Spacer and Dart Drop Volume: Total Proppant Pumped* : 27# Linear Volume: Displacement Volume: Pad Volume: Proppant in Formation: Fluid Summary (by fluid description) 27# Delta Frac Volume: Pre-Pad Volume: Interval Summary Start Date/Time: William Martin Madeline Woodard 3S-703 - Coyote - Interval 14 Wanli 16/20 Ceramic Pumped: Pump Time: 100M Pumped: Dan Faur The sleeve for interval 14 could not be opened after dropping 3 darts. The first dart had a landing signature but the DH pressure array indicated that the sleeve did not opened. A backup dart was dropped, but again there was no indication of the sleeve shifting. After the 3rd dart was dropped, DH pressure from interval 12 increased indicating flow was going into that sleeve. The decision was made to skip interval 14. End Date/Time: Fluid Summary (by stage description) Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Proppant Summary Interval Status: Establish Stable Fluid Volume: Conoco Phillips - 3S-703 Interval Summary 23 7/16/25 11:54 7/16/25 13:37 103 min 15.4 bpm 3,862 psi 5,430 psi 7 bbl 21.5 bpm 2,133 psi 3,721 psi 20.5 bpm 1,726 psi 1,478 psi 3,018 psi 868 hhp 372 psi 416 psi 10.68 ppg 5 5 28 % 27 % 22 cP 90 F 8.78 300,505 lbs 3,000 lbs 303,505 lbs 303,505 lbs 67,355 gal 1,604 bbls 5,738 gal 137 bbls 15,418 gal 367 bbls 6,013 gal 143 bbls 44,256 gal 1,054 bbls 4,100 gal 98 bbls 1,638 gal 39 bbls 1,668 gal 40 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval 15 was pumped with a more aggressive proppant design with the same pad % of 28%. Interval pumped to completion. Dart/Ball Early : 3S-703 - Coyote - Interval 15 Interval Summary Average Missile Pressure: Pad Percentage Actual Pumps Ending Stage: Pad Percentage Design End Date/Time: Max BH Pressure: Max Rate: Initial Surface Pressure (Breakdown): Average Missile HHP: Initial BH Pressure (Breakdown): Average BH Pressure: Pump Time: Fluid Summary (by fluid description) Interval Status: William Martin Ryan Knight Derek Osselburn Pad Volume: Conditioning Pad Volume: Fluid Summary (by stage description) Max Surface Pressure: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Proppant Summary Total Proppant Pumped* : Proppant in Formation: Spacer and Dart Drop Volume: Average Temp: Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: Average Visc: Average pH: Initial Rate (Breakdown): 100M Pumped: Proppant Laden Fluid Volume: Displacement Volume: 27# Linear Volume: Pumps Starting Stage: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Establish Stable Fluid Volume: Madeline Woodard Dan Faur Start Date/Time: 27# Delta Frac Volume: Average Rate: Conoco Phillips - 3S-703 Interval Summary 24 7/16/25 13:37 7/16/25 15:09 92 min 15.3 bpm 4,171 psi 5,651 psi 4 bbl 21.8 bpm 1,833 psi 3,317 psi 20.6 bpm 1,545 psi 1,290 psi 2,896 psi 780 hhp 405 psi 420 psi 10.41 ppg 5 5 20 % 19 % 22 cP 88.1 F 8.79 2752 psi 0.659 psi/ft 2734 psi 2723 psi 2714 psi 301,192 lbs 3,000 lbs 304,192 lbs 304,192 lbs 58,814 gal 1,400 bbls 6,213 gal 148 bbls 2,626 gal 63 bbls 7,747 gal 184 bbls 6,013 gal 143 bbls 43,454 gal 1,035 bbls 3,587 gal 85 bbls 1,600 gal 38 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Final 10 min: William Martin Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Madeline Woodard Dan Faur Establish Stable Fluid Volume: Max Proppant Concentration: Pad Percentage Design Average Visc: Pump Time: Average Temp: Proppant in Formation: Average pH: Pumps Starting Stage: Start Date/Time: Average BH Pressure: Average Rate: Interval Summary Pad Percentage Actual Initial OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Missile HHP: Max OA Pressure: Conditioning Pad Volume: Proppant Laden Fluid Volume: ISDP: Pumps Ending Stage: Max Surface Pressure: End Date/Time: Max BH Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Wanli 16/20 Ceramic Pumped: Pre-Pad Volume: Pad Volume: Average Surface Pressure: Fluid Summary (by fluid description) Flush Volume: 100M Pumped: 27# Delta Frac Volume: 27# Linear Volume: Final 15 min: Average Missile Pressure: Final 5 min: Proppant Summary Max Rate: 3S-703 - Coyote - Interval 16 Final Fracture Gradient: Interval Status: Pad percentage was decreased to 20% with a more aggressive proppant design. Interval pumped to completion. Fluid Summary (by stage description) Total Proppant Pumped* : Conoco Phillips - 3S-703 Interval Summary 25 CustomerFormationLeaseAPIDateWell SummaryWanli 16/20 Ceramic 100M Total ProppantBH Pressure Rate Visc Temp pH BH Pressure Rate gal bbl gal bbl gal bbl gal bbl lbs lbs lbs14319 20.2 22 82 8.6 4537 21.2 72,189 1,719 5,987 143 23,624 562 101,800 2,424 299,728 3,000 302,728 24088 20.5 21 88 8.7 4402 21.2 71,464 1,702 3,541 84 75,005 1,786 299,933 3,000 302,933 33884 20.2 20 95 8.6 4299 20.8 82,023 1,953 22,416 534 104,439 2,487 296,598 3,000 299,598 43938 20.3 23 82 8.9 4293 21.1 73,138 1,741 2,571 61 840 20 76,549 1,823 301,693 3,000 304,693 53801 20.1 22 91 8.7 4167 21.0 71,234 1,696 3,492 83 74,726 1,779 300,144 3,000 303,144 63748 20.2 22 94 8.7 4146 21.1 70,112 1,669 3,721 89 73,833 1,758 298,382 3,000 301,382 73740 20.3 21 90 8.7 4797 21.3 70,892 1,688 8,554 204 79,446 1,892 299,433 3,000 302,433 83578 20.2 22 92 8.8 3819 21.1 68,335 1,627 9,668 230 840 20 78,843 1,877 300,474 3,000 303,474 93415 20.5 22 95 8.7 3625 21.3 70,542 1,680 3,621 86 74,163 1,766 300,925 3,000 303,925 103448 20.6 22 96 8.7 3686 21.2 75,862 1,806 11,603 276 87,465 2,083 300,050 3,000 303,050 113317 20.6 22 98 8.7 3676 21.4 70,174 1,671 7,188 171 77,362 1,842 301,967 3,000 304,967 123239 20.7 23 89 8.8 3362 21.4 71,662 1,706 3,922 93 840 20 76,424 1,820 300,281 3,000 303,281 133122 20.7 22 88 8.8 3306 21.5 71,521 1,703 3,408 81 74,929 1,784 297,888 3,000 300,888 140 0.0 0 0 0.0 0 0.0 7,275 173 23,319 555 30,594 728 153018 20.5 22 90 8.8 3721 21.5 67,355 1,604 5,738 137 73,093 1,740 300,505 3,000 303,505 162896 20.6 22 88 8.8 3317 21.8 58,814 1,400 6,213 148 65,027 1,548 301,192 3,000 304,192 Minimum7275 173 2571 61 840 20 30594 728 296598 3000 299598 Average67037 1596 7810 186 6536 156 76481 1821 299946 3000 302946 Maximum82023 1953 23319 555 23624 562 104439 2487 301967 3000 304967 Wanli 16/20 Ceramic 100M Total ProppantPressure Rate Visc Temp pH Pressure Rate gal bbl gal bbl gal bbl gal bbl lbs lbs TotalPlanned1,220,144 29,051 104,876 2,497 13,140 313 1,338,160 31,861 4,800,000 48,000 4,848,000Recorded3710 20.3 22 91 8.71 4797 21.8 1,072,592 25,538 124,962 2,975 26,144 622 1,223,698 29,136 4,499,193 45,000 4,544,193Weight Tickets4,532,666 45,000 4,577,666** Proppant is billed from Weight Ticket volumes** IFS numbers for proppant are taken from software calculations based on Total FluidFluids ProppantsFluids ProppantsTotal FluidAverage MaxSeawater27# Delta Frac 27# Linear27# Delta Frac 27# LinearIntervalAverage MaxSeawaterJuly 07, 202550-103-209133S-703CoyoteConoco Phillips Conoco Phillips - 3S-703 Fluid System-Proppant Summary26 <-Paste Interval 1 Plots HereePRV Test - 7.7.257/7/202508:0708:0808:0908:1008:1108:1208:1308:147/7/202508:15Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)7654Global Event Log4567Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA08:08:06 08:10:4008:12:40 08:14:07TP TP884.7 948.9668.1 739.2TPP TPP939.0 945.8705.6 916.3IGKP IGKP1500 15001500 1500Conoco Phillips - 3S-703 Interval 1 Plots27 <-Paste Interval 1 Plots HerePressure Test - 7.7.257/7/202508:2808:3008:3208:3408:3608:3808:407/7/202508:42Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)1312Global Event Log1213Intersection IntersectionPressure Test - Max Pressure Test - Pass08:34:16 08:39:54TP TP9540 9514TPP TPP9603 9562IGKP IGKP9500 9500PKP PKP9500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 07-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 1 Plots28 <-Paste Interval 1 Plots HereTreatment Plot - Arsenal & Alpha7/7/202509:0909:1009:1109:1209:137/7/202509:14Time010002000300040005000600070008000900010000A0102030405060708090100B012345678910C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD517161514Global Event Log14151617Intersection IntersectionOpen Well Arsenal Burst DiskAlpha Sleeve Shift Start DFIT09:08:45 09:09:5209:10:56 09:11:09TP TP815.5 55036058 2367GBP GBP2570 74028029 4170Conoco Phillips - 3S-703 Interval 1 Plots29 <-Paste Interval 1 Plots HereTreatment Plot - Interval 01 Injection Attempts7/7/202509:3010:0010:3011:0011:307/7/202512:00Time0200040006000800010000A0102030405060708090100B012345678910C0255075100125DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCADConoco Phillips - 3S-703 Interval 1 Plots30 ePRV Test - 7.12.257/12/202516:5917:0017:0117:0217:0317:0417:057/12/202517:06Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)7654Global Event Log4567Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Seconday Tubing ePRV - Secondary IA17:00:10 17:02:2417:04:21 17:05:15TP TP923.9 823.6939.4 695.8TPP TPP978.3 899.21013 883.2IGKP IGKP1500 15001500 1500Conoco Phillips - 3S-703 Interval 1 Plots31 Pressure Test - 7.12.257/12/202517:3617:3817:4017:4217:4417:467/12/202517:48Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)1413Global Event Log1314Intersection IntersectionPressure Test - Max Pressure Test - Pass17:40:21 17:44:12TP TP9528 9525TPP TPP9521 9482IGKP IGKP9500 9500PKP PKP9500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 12-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 1 Plots32 Treatment Plot - Toe Sleeve Injection Test 7.127/12/202518:0018:2018:407/12/202519:00Time010002000300040005000600070008000900010000A0102030405060708090100B012345678910C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD7Conoco Phillips - 3S-703 Interval 1 Plots33 ePRV Test - 7.13.257/13/202510:2410:2510:2610:277/13/202510:28Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)111098Global Event Log891011Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA10:23:51 10:24:5510:26:37 10:27:40TP TP913.5 838.1738.2 777.1TPP TPP965.6 873.2797.1 933.3IGKP IGKP2000 20002000 2000Conoco Phillips - 3S-703 Interval 1 Plots34 Pressure Test - 7.13.257/13/202510:3010:3110:3210:3310:3410:3510:3610:377/13/202510:38Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)915141312Global Event Log12131415Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Max10:30:02 10:30:0910:31:38 10:36:38TP TP303.5 326.69528 9493TPP TPP350.7 383.09536 9457IGKP IGKP25.00 95009500 9500PKP PKP500.4 252.49500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 13-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 1 Plots35 Blender Chemical Plot - Bucket Test 7.13.257/13/202510:0010:0510:1010:1510:2010:2510:307/13/202510:35Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA9Conoco Phillips - 3S-703 Interval 1 Plots36 ADP Chemical Plots - Bucket Test 7.13.257/13/202509:34:3009:35:0009:35:3009:36:0009:36:307/13/202509:37:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)ABConoco Phillips - 3S-703 Interval 1 Plots37 Treatment Plot - Interval 01 DFIT7/13/202510:5511:0011:0511:1011:1511:207/13/202511:25Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD121110Conoco Phillips - 3S-703 Interval 1 Plots38 Halliburton Pumping Diagnostic Analysis ToolkitMinifrac - G Function0.51.01.52.02.53.03.5G(Time)2500260027002800290030003100A020406080100120140160180200D050100150200250300350E (0.0023, 0) (m = 101.29) (1.6059, 162.4) (Y = 0) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime2.24GBP2683SP2683DP222.1FE54.15Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 13-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 1 Plots39 Treatment Plot - Interval 01 Step Rate Test7/13/202511:3511:407/13/202511:45Time0100020003000400050006000A010203040B012345678910C0255075100125DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD13343332313029282726252423Global Event Log232425262728293031323334Intersection IntersectionOpen Well Step 1Step 2 Step 3Step 4 Step 5Step 6 Step 7Step 8 Step 9Step 10 Step 1111:32:16 11:35:3611:37:13 11:38:2811:39:45 11:41:0511:42:25 11:43:4611:45:00 11:46:1811:47:52 11:48:23SR SR0.000 0.6411.156 1.7692.356 2.9453.528 4.1224.705 5.2985.881 7.016GBP GBP2448 29183010 30553082 31143153 31943247 33003344 3443Conoco Phillips - 3S-703 Interval 1 Plots40 Treatment Plot - Interval 017/13/202511:4012:0012:2012:4013:0013:207/13/202513:40Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD7212423222120191817161514132Conoco Phillips - 3S-703 Interval 1 Plots41 Blender Chemical Plot - Interval 017/13/202511:4012:0012:2012:4013:0013:207/13/202513:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA7212423222120191817161514132Conoco Phillips - 3S-703 Interval 1 Plots42 ADP Chemical Plots - Interval 017/13/202511:4012:0012:2012:4013:0013:207/13/202513:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB7212423222120191817161514132Conoco Phillips - 3S-703 Interval 1 Plots43 Net Pressure Plot - Interval 014567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2731 psi 0 Time = 07/13/25 11:30:51 1Time-244.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 13-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 1 Plots44 <-Paste Interval 2 Plots HereTreatment Plot - Interval 027/13/202513:4014:0014:2014:4015:0015:2015:407/13/202516:00Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD76543232116151413121110987212432Conoco Phillips - 3S-703 Interval 2 Plots45 <-Paste Interval 2 Plots HereBlender Chemical Plot - Interval 027/13/202513:4014:0014:2014:4015:007/13/202515:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA232116151413121110987212432Conoco Phillips - 3S-703 Interval 2 Plots46 <-Paste Interval 2 Plots HereADP Chemical Plots - Interval 027/13/202513:4014:0014:2014:4015:007/13/202515:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB232116151413121110987212432Conoco Phillips - 3S-703 Interval 2 Plots47 <-Paste Interval 2 Plots HereNet Pressure Plot - Interval 024567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2731 psi 0 Time = 07/13/25 13:38:51 1Time-372.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 13-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 2 Plots48 <-Paste Interval 3 Plots HereTreatment Plot - Interval 037/13/202515:2015:4016:0016:2016:4017:0017:207/13/202517:40Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD171615141312111098765432321163Conoco Phillips - 3S-703 Interval 3 Plots49 <-Paste Interval 3 Plots HereBlender Chemical Plot - Interval 037/13/202515:2015:4016:0016:2016:4017:0017:207/13/202517:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA171615141312111098765432321163Conoco Phillips - 3S-703 Interval 3 Plots50 <-Paste Interval 3 Plots HereADP Chemical Plots - Interval 037/13/202515:2015:4016:0016:2016:4017:0017:207/13/202517:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB171615141312111098765432321163Conoco Phillips - 3S-703 Interval 3 Plots51 <-Paste Interval 3 Plots HereNet Pressure Plot - Interval 033456789100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2731 psi 0 Time = 07/13/25 15:38:51 1Time-492.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 13-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 3 Plots52 <-Paste Interval 4 Plots HereePRV Test - 7.13.257/13/202510:2410:2510:2610:277/13/202510:28Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)111098Global Event Log891011Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA10:23:51 10:24:5510:26:37 10:27:40TP TP913.5 838.1738.2 777.1TPP TPP965.6 873.2797.1 933.3IGKP IGKP2000 20002000 2000Conoco Phillips - 3S-703 Interval 4 Plots53 <-Paste Interval 4 Plots HerePressure Test - 7.13.257/13/202510:3010:3110:3210:3310:3410:3510:3610:377/13/202510:38Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)915141312Global Event Log12131415Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Max10:30:02 10:30:0910:31:38 10:36:38TP TP303.5 326.69528 9493TPP TPP350.7 383.09536 9457IGKP IGKP25.00 95009500 9500PKP PKP500.4 252.49500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 13-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 4 Plots54 <-Paste Interval 4 Plots HereBlender Chemical Plot - Bucket Test 7.13.257/13/202510:0010:0510:1010:1510:2010:2510:307/13/202510:35Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA9Conoco Phillips - 3S-703 Interval 4 Plots55 <-Paste Interval 4 Plots HereADP Chemical Plots - Bucket Test 7.13.257/13/202509:34:3009:35:0009:35:3009:36:0009:36:307/13/202509:37:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)ABConoco Phillips - 3S-703 Interval 4 Plots56 Treatment Plot - Interval 047/14/202508:4009:0009:2009:4010:007/14/202510:20Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211514131211109876545Conoco Phillips - 3S-703 Interval 4 Plots57 Blender Chemical Plot - Interval 047/14/202508:4009:0009:2009:4010:007/14/202510:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA211514131211109876545Conoco Phillips - 3S-703 Interval 4 Plots58 ADP Chemical Plots - Interval 047/14/202508:4009:0009:2009:4010:007/14/202510:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB211514131211109876545Conoco Phillips - 3S-703 Interval 4 Plots59 Net Pressure Plot - Interval 0423456789100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2723 psi 0 Time = 07/14/25 08:30:00 1Time-89.57NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 14-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 4 Plots60 <-Paste Interval 5 Plots HereTreatment Plot - Interval 057/14/202510:2010:4011:0011:2011:407/14/202512:00Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211565Conoco Phillips - 3S-703 Interval 5 Plots61 <-Paste Interval 5 Plots HereBlender Chemical Plot - Interval 057/14/202510:2010:4011:0011:2011:407/14/202512:00Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA3211211109876543211565Conoco Phillips - 3S-703 Interval 5 Plots62 <-Paste Interval 5 Plots HereADP Chemical Plots - Interval 057/14/202510:2010:4011:0011:2011:407/14/202512:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB3211211109876543211565Conoco Phillips - 3S-703 Interval 5 Plots63 <-Paste Interval 5 Plots HereNet Pressure Plot - Interval 0567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2723 psi 0 Time = 07/14/25 10:20:00 1Time-199.57NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 14-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 5 Plots64 <-Paste Interval 6 Plots HereTreatment Plot - Interval 067/14/202512:2012:4013:0013:2013:407/14/202514:00Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211276Conoco Phillips - 3S-703 Interval 6 Plots65 <-Paste Interval 6 Plots HereBlender Chemical Plot - Interval 067/14/202512:0012:2012:4013:0013:207/14/202513:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA3211211109876543211276Conoco Phillips - 3S-703 Interval 6 Plots66 <-Paste Interval 6 Plots HereADP Chemical Plots - Interval 067/14/202512:0012:2012:4013:0013:207/14/202513:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB3211211109876543211276Conoco Phillips - 3S-703 Interval 6 Plots67 <-Paste Interval 6 Plots HereNet Pressure Plot - Interval 067892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2723 psi 0 Time = 07/14/25 12:05:00 1Time-304.57NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 14-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 6 Plots68 <-Paste Interval 7 Plots HereTreatment Plot - Interval 077/14/202514:0014:2014:4015:0015:207/14/202515:40Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD1211109876543217Conoco Phillips - 3S-703 Interval 7 Plots69 <-Paste Interval 7 Plots HereBlender Chemical Plot - Interval 077/14/202514:0014:2014:4015:0015:207/14/202515:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA121110987654321127Conoco Phillips - 3S-703 Interval 7 Plots70 <-Paste Interval 7 Plots HereADP Chemical Plots - Interval 077/14/202514:0014:2014:4015:0015:207/14/202515:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB121110987654321127Conoco Phillips - 3S-703 Interval 7 Plots71 <-Paste Interval 7 Plots HereNet Pressure Plot - Interval 072345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2723 psi 0 Time = 07/14/25 13:45:00 1Time-404.57NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 14-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 7 Plots72 <-Paste Interval 8 Plots HereePRV Test - 7.15.257/15/202507:1607:1807:2007:2207:247/15/202507:26Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)7654Global Event Log4567Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA07:17:08 07:18:0507:19:30 07:25:45TP TP1108 886.4870.6 1006TPP TPP1142 890.1973.2 1055IGKP IGKP1500 15001500 1500Conoco Phillips - 3S-703 Interval 8 Plots73 <-Paste Interval 8 Plots HerePressure Test - 7.15.257/15/202507:3107:3207:3307:3407:3507:3607:377/15/202507:38Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)111098Global Event Log891011Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Pass07:31:18 07:31:2407:32:48 07:36:58TP TP529.0 548.69546 9470TPP TPP592.9 602.79541 9439IGKP IGKP25.00 95009500 9500PKP PKP500.4 95.119500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 15-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 8 Plots74 <-Paste Interval 8 Plots HereBlender Chemical Plot - Bucket Test 7.157/15/202506:5006:5507:0007:0507:1007:1507:207/15/202507:25Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAAConoco Phillips - 3S-703 Interval 8 Plots75 <-Paste Interval 8 Plots HereADP Chemical Plots - Bucket Test 7.15.257/15/202506:04:0006:04:2006:04:4006:05:0006:05:2006:05:4006:06:007/15/202506:06:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)ABConoco Phillips - 3S-703 Interval 8 Plots76 Treatment Plot - Interval 08 DFIT7/15/202508:1008:2008:3008:407/15/202508:50Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD7654Conoco Phillips - 3S-703 Interval 8 Plots77 Halliburton Pumping Diagnostic Analysis ToolkitInterval 06 DFIT - G Function12345G(Time)24502500255026002650270027502800A020406080100120140160180200D0100200300400E (1.248, 106.9) (m = 86.25) (5.033, 433.4) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime4.91GBP2513SP2513DP235.9FE72.25Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 15-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-209138Conoco Phillips - 3S-703 Interval 8 Plots78 Treatment Plot - Interval 087/15/202509:0009:2009:4010:0010:207/15/202510:40Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321181716151413121110989Conoco Phillips - 3S-703 Interval 8 Plots79 Blender Chemical Plot - Interval 087/15/202509:0009:2009:4010:0010:207/15/202510:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA321181716151413121110989Conoco Phillips - 3S-703 Interval 8 Plots80 ADP Chemical Plots - Interval 087/15/202509:0009:2009:4010:0010:207/15/202510:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB321181716151413121110989Conoco Phillips - 3S-703 Interval 8 Plots81 Net Pressure Plot - Interval 087892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/15/25 08:50:54 1Time-137.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 15-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 8 Plots82 <-Paste Interval 9 Plots HereTreatment Plot - Interval 097/15/202510:4011:0011:2011:4012:007/15/202512:20Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD432112111098765432118109Conoco Phillips - 3S-703 Interval 9 Plots83 <-Paste Interval 9 Plots HereBlender Chemical Plot - Interval 097/15/202510:4011:0011:2011:4012:007/15/202512:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA32112111098765432118109Conoco Phillips - 3S-703 Interval 9 Plots84 <-Paste Interval 9 Plots HereADP Chemical Plots - Interval 097/15/202510:4011:0011:2011:4012:007/15/202512:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB32112111098765432118109Conoco Phillips - 3S-703 Interval 9 Plots85 <-Paste Interval 9 Plots HereNet Pressure Plot - Interval 0923456789100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/15/25 10:30:54 1Time-237.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 15-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 9 Plots86 <-Paste Interval 10 Plots HereTreatment Plot - Interval 107/15/202512:2012:4013:0013:2013:4014:0014:207/15/202514:40Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD211716151413121110987654321121110Conoco Phillips - 3S-703 Interval 10 Plots87 <-Paste Interval 10 Plots HereBlender Chemical Plot - Interval 107/15/202512:2012:4013:0013:2013:4014:007/15/202514:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA211716151413121110987654321121110Conoco Phillips - 3S-703 Interval 10 Plots88 <-Paste Interval 10 Plots HereADP Chemical Plots - Interval 107/15/202512:2012:4013:0013:2013:4014:0014:207/15/202514:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB3211716151413121110987654321121110Conoco Phillips - 3S-703 Interval 10 Plots89 <-Paste Interval 10 Plots HereNet Pressure Plot - Interval 1023456789100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/15/25 12:45:54 1Time-372.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 15-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 10 Plots90 <-Paste Interval 11 Plots HereTreatment Plot - Interval 117/15/202514:4015:0015:2015:4016:007/15/202516:20Time0100020003000400050006000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD1211109876543211711Conoco Phillips - 3S-703 Interval 11 Plots91 <-Paste Interval 11 Plots HereBlender Chemical Plot - Interval 117/15/202514:4015:0015:2015:4016:007/15/202516:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA1211109876543211711Conoco Phillips - 3S-703 Interval 11 Plots92 <-Paste Interval 11 Plots HereADP Chemical Plots - Interval 117/15/202514:4015:0015:2015:4016:007/15/202516:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB1211109876543211711Conoco Phillips - 3S-703 Interval 11 Plots93 <-Paste Interval 11 Plots HereNet Pressure Plot - Interval 112Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/15/25 12:45:54 1Time-372.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 15-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 11 Plots94 <-Paste Interval 12 Plots HereePRV Test - 7.16.257/16/202506:0906:1006:1106:1206:137/16/202506:14Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)8765Global Event Log5678Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA06:09:08 06:10:1706:11:57 06:13:39TP TP756.5 501.4558.0 779.4TPP TPP790.9 559.2641.9 629.3IGKP IGKP1500 15001500 1500Conoco Phillips - 3S-703 Interval 12 Plots95 <-Paste Interval 12 Plots HerePressure Test - 7.16.257/16/202506:1606:1706:1806:1906:2006:2106:2206:237/16/202506:24Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)1211109Global Event Log9101112Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Pass06:15:53 06:15:5906:17:54 06:22:33TP TP402.7 418.39562 9479TPP TPP432.9 460.59552 9448IGKP IGKP25.00 95009500 9500PKP PKP500.4 335.19500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 16-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 12 Plots96 <-Paste Interval 12 Plots HereBlender Chemical Plot - Bucket Test 7.16.257/16/202505:5506:0006:0506:1006:157/16/202506:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAAConoco Phillips - 3S-703 Interval 12 Plots97 <-Paste Interval 12 Plots HereADP Chemical Plots - Bucket Test 7.16.257/16/202505:43:0005:43:2005:43:4005:44:0005:44:2005:44:4005:45:007/16/202505:45:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)ABConoco Phillips - 3S-703 Interval 12 Plots98 Treatment Plot - Interval 127/16/202507:0007:2007:4008:0008:207/16/202508:40Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32115141312111098765413Conoco Phillips - 3S-703 Interval 12 Plots99 Blender Chemical Plot - Interval 127/16/202507:0007:2007:4008:0008:207/16/202508:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA32115141312111098765413Conoco Phillips - 3S-703 Interval 12 Plots100 ADP Chemical Plots - Interval 127/16/202507:0007:2007:4008:0008:207/16/202508:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB32115141312111098765413Conoco Phillips - 3S-703 Interval 12 Plots101 Net Pressure Plot - Interval 12234567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/16/25 07:00:00 1Time-39.75NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 16-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 12 Plots102 <-Paste Interval 13 Plots HereTreatment Plot - Interval 137/16/202509:0009:2009:4010:007/16/202510:20Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321151413Conoco Phillips - 3S-703 Interval 13 Plots103 <-Paste Interval 13 Plots HereBlender Chemical Plot - Interval 137/16/202509:0009:2009:4010:007/16/202510:20Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA4321121110987654321151413Conoco Phillips - 3S-703 Interval 13 Plots104 <-Paste Interval 13 Plots HereADP Chemical Plots - Interval 137/16/202509:0009:2009:4010:007/16/202510:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB4321121110987654321151413Conoco Phillips - 3S-703 Interval 13 Plots105 <-Paste Interval 13 Plots HereNet Pressure Plot - Interval 13567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/16/25 08:44:00 1Time-143.75NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 16-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 13 Plots106 <-Paste Interval 14 Plots HereTreatment Plot - Interval 147/16/202510:4011:0011:2011:407/16/202512:00Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD4321141312111098764321121514Conoco Phillips - 3S-703 Interval 14 Plots107 <-Paste Interval 14 Plots HereBlender Chemical Plot - Interval 147/16/202510:4011:0011:2011:407/16/202512:00Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA21141312111098764321121514Conoco Phillips - 3S-703 Interval 14 Plots108 <-Paste Interval 14 Plots HereADP Chemical Plots - Interval 147/16/202510:4011:0011:207/16/202511:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB1141312111098764321121514Conoco Phillips - 3S-703 Interval 14 Plots109 <-Paste Interval 15 Plots HereTreatment Plot - Interval 157/16/202512:0012:2012:4013:0013:207/16/202513:40Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32113121110987654321141615Conoco Phillips - 3S-703 Interval 15 Plots110 <-Paste Interval 15 Plots HereBlender Chemical Plot - Interval 157/16/202512:0012:2012:4013:0013:207/16/202513:40Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA32113121110987654321141615Conoco Phillips - 3S-703 Interval 15 Plots111 <-Paste Interval 15 Plots HereADP Chemical Plots - Interval 157/16/202512:0012:2012:4013:0013:207/16/202513:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB3211312111098765432114131615Conoco Phillips - 3S-703 Interval 15 Plots112 <-Paste Interval 15 Plots HereNet Pressure Plot - Interval 15567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/16/25 11:55:00 1Time-334.75NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 16-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 15 Plots113 <-Paste Interval 16 Plots HereTreatment Plot - Interval 167/16/202513:4014:0014:2014:407/16/202515:00Time01000200030004000500060007000A010203040B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD12111098765432116Conoco Phillips - 3S-703 Interval 16 Plots114 <-Paste Interval 16 Plots HereBlender Chemical Plot - Interval 167/16/202513:4014:0014:2014:407/16/202515:00Time0.00.51.01.52.02.53.0A012345BCAT-3 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)LoSurf-300 Conc (gal/Mgal)MO-67 Conc (gal/Mgal)AABAA1211109876543211316Conoco Phillips - 3S-703 Interval 16 Plots115 <-Paste Interval 16 Plots HereADP Chemical Plots - Interval 167/16/202513:4014:0014:2014:407/16/202515:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)CLA-Web Conc (gal/Mgal)AB1211109876543211316Conoco Phillips - 3S-703 Interval 16 Plots116 <-Paste Interval 16 Plots HereNet Pressure Plot - Interval 16567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2564 psi 0 Time = 07/16/25 13:37:00 1Time-436.75NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 16-Jul-2025Sales Order #: 0910181328Well Description: 3S-703 3S-703UWI: 50-103-20913Conoco Phillips - 3S-703 Interval 16 Plots117 Sales Order# - - - - - - - - - - Event Log Sand Sieve Fann 15 Minute Field Break Test Real-Time QC Well Summary Stimulation Treatment Appendix Chemical Summary Planned Design Water Straps Water Analysis Prepared for: Madeline Woodard July 16, 2025 Harrison Bay County, AK 0910181328 Conoco Phillips 3S-703 Intervals 1-16 Coyote Coyote Formation API: 50-103-20913 Conoco Phillips - 3S-703 Appendix 118 Interval DateDesigned Proppant (lbs)Proppant in Formation (lbs)Designed Fluid (bbl)Vol Clean (bbl)Vol Slurry (bbl)Pad Percentage Design Pad Percentage Actual Proppant Aggressiveness (lb/bbl Clean)Notes1 7/13/2025 303,000 302,728 2,204 2424 2,757 27.8 27.6 2762 7/13/2025 303,000 302,933 1,882 1786 2,120 27.8 27.4 2743 7/13/2025 303,000 299,598 2,910 2487 2,817 28.0 30.8 268 Backup Dart Dropped4 7/14/2025 303,000 304,693 1,886 1823 2,158 27.8 27.8 2725 7/14/2025 303,000 303,144 1,882 1779 2,113 27.8 27.2 2686 7/14/2025 303,000 301,382 1,732 1758 2,090 27.8 27.5 2727 7/14/2025 303,000 302,433 2,030 1892 2,225 27.8 27.3 2718 7/15/2025 303,000 303,474 2,054 1877 2,212 27.8 28.1 2869 7/15/2025 303,000 303,925 1,882 1766 2,101 27.8 27.2 27210 7/15/2025 303,000 303,050 2,341 2083 2,417 27.8 27.3 271 Backup Dart Dropped11 7/15/2025 303,000 304,967 2,002 1842 2,178 27.8 27.2 27312 7/16/2025 303,000 303,281 1,886 1820 2,154 28.0 27.1 26813 7/16/2025 303,000 300,888 1,882 1784 2,116 27.8 27.8 26614 7/16/2025 303,000 1,796 728 728 Skipped - No Sleeve Shift After 3 Darts15 7/16/2025 303,000 303,505 1,796 1740 2,075 27.8 27.0 285 More Aggressive Prop Design - Same Pad%16 7/16/2025 303,000 304,192 1,694 1548 1,884 19.8 19.5 291 More Aggressive Prop Design - 20% Pad 3S-703 Interval HighlightsConoco Phillips - 3S-703Well Summary119 CustomerConoco Phillips FormationCoyoteLease3S-703API50-103-20913DateInterval Summary - Chemicals BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)Prime Up00000000130 95 35 96 62 2163 157 36232 71 59 67 33 1954 151 0343 74 56 72 50 2860 212 0440 70 49 89 43 2247 142 48531 82 33 67 37 2001 152 0629 76 41 69 38 1982 150 0735 57 42 70 37 2157 156 0832 86 42 93 35 2316 162 57935 78 33 81 35 2169 152 01035 88 56 89 44 2481 178 01128 73 39 67 36 2055 158 01240 89 32 77 38 2328 154 571335 85 35 62 34 2047 152 0143 30 3 29 15 840 60 01532 83 34 87 43 2108 146 01625 78 26 75 40 1734 128 0Total 505 1215 615 1190 620 33442 2410 198w/o Prime Up505 1215 615 1190 620 33442 2410 198Interval7/7/2025Dry AdditivesLiquid AdditivesConoco Phillips - 3S-703 Chemical Summary120 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Cum. PropTreatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lb)1-1 Shut-In Shut-In2:31:10 1-2 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:31:10 0.151-3 Shut-In Shut-In2:26:25 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 2:26:25 1.00 1.00 0.50 27.00 2.00 0.151-5 Shut-In Shut-In2:20:25 1-6 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:20:25 0.151-7 Seawater Injection Test 12 2,100 50 50 0:04:10 2:15:39 0.151-8 Shut-In Shut-In2:11:29 1-9 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:11:29 0.151-10 Shut-In Shut-In2:06:43 1-11 27# Linear DFIT 10 840 20 20 0:02:00 2:06:43 1.00 1.00 0.50 27.00 2.00 0.151-12 Shut-In Shut-In2:04:43 1-13 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 2:04:43 1.00 1.00 0.50 27.00 2.00 0.151-14 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.151-15 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.151-16 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 30001-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 107001-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 363001-19 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 735001-20 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 1414001-21 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 2110001-22 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 2650001-23 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 3030001-24 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030002-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 1.00 0.50 27.00 2.00 0.152-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.152-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.152-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 30002-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 107002-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 363002-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 735002-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 1414002-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 2110002-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 2650002-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 3030002-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030003-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:46:58 1.00 1.00 0.50 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 2:44:28 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 2:34:28 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-4 27# Linear Displacement 20 8,642 206 206 0:10:17 2:14:54 1.00 0.60 1.00 0.50 27.00 2.00 0.153-5 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 2:04:37 1.00 0.60 1.00 0.50 27.00 2.00 0.153-6 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 2:02:37 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.153-7 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:52:37 0.45 1.00 0.75 1.00 0.50 27.00 2.00 0.153-8 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:33:04 0.45 1.00 0.75 1.00 0.50 27.00 2.00 0.15 30003-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:25:45 0.45 1.00 0.75 1.00 0.50 27.00 2.00 0.15 107003-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:20:45 0.45 1.00 0.75 1.00 0.50 27.00 2.000.15 363003-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 1:11:45 0.45 1.00 0.75 1.00 0.50 27.00 2.000.15 735003-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 1:02:21 0.45 1.00 0.75 1.00 0.50 27.00 2.000.15 1414003-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:47:07 0.45 1.00 0.75 1.00 0.50 27.00 2.000.15 2110003-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:32:58 0.45 1.00 0.75 1.00 0.50 27.00 2.000.15 2650003-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:22:54 0.45 1.00 0.75 1.00 0.50 27.00 2.000.15 3030003-16 27# Linear Flush 20 8,663 206 206 0:10:19 0:16:19 1.00 1.00 0.50 27.00 2.00 0.15 3030003-17 Seawater Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 0.15 3030003-18 Shut-In Shut-In3030007/7/25Liquid Additives Dry Additives50-103-209130910181328Interval 1Coyote@ 13275.89 - 13279.89 ft 104.5 °FInterval 2Coyote@ 12711.31 - 12715.31 ft 104.5 °FInterval 3Coyote@ 12205.54 - 12209.54 ft 104.5 °FConoco Phillips - 3S-703Planned Design121 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Cum. PropTreatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lb)7/7/25Liquid Additives Dry Additives50-103-2091309101813284-1 Shut-In Shut-In1:58:09 4-2 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:09 0.154-3 Shut-In Shut-In1:53:23 4-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:53:23 1.00 1.00 0.50 27.00 2.00 0.154-5 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.80 1.00 0.50 27.00 2.00 0.154-6 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.154-7 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 30004-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 107004-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 363004-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 735004-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 1414004-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 2110004-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 2650004-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.45 1.00 0.50 27.00 2.000.15 3030004-15 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030005-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 1.00 0.50 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.155-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 30005-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.45 1.00 0.50 27.00 2.00 0.15 107005-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.15 363005-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.52 1.00 0.50 27.00 2.00 0.15 735005-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.55 1.00 0.50 27.00 2.00 0.15 1414005-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.50 1.00 0.50 27.00 2.00 0.15 2110005-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.50 1.00 0.50 27.00 2.000.15 2650005-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.50 1.00 0.50 27.00 2.000.15 3030005-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030006-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:43:03 1.00 1.00 0.50 27.00 2.00 0.156-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:40:33 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.156-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.156-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30006-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 107006-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 363006-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 735006-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 1414006-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 2110006-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.70 1.00 0.50 27.00 2.000.15 2650006-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.70 1.00 0.50 27.00 2.000.15 3030006-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030007-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:02:28 1.00 1.00 0.50 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:59:58 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:49:58 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.157-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:30:24 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 30007-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.0000 20 3,850 92 100 7,700 0:05:00 1:23:06 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 107007-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:18:06 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 363007-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 1:09:05 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 735007-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:59:41 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 1414007-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:44:27 0.45 1.00 0.70 1.00 0.50 27.00 2.00 0.15 2110007-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:30:19 0.45 1.00 0.70 1.00 0.50 27.00 2.000.15 2650007-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:20:15 0.45 1.00 0.70 1.00 0.50 27.00 2.000.15 3030007-12 27# Linear Flush 20 6,433 153 153 0:07:40 0:13:40 1.00 1.00 0.50 27.00 2.00 0.15 3030007-13 Seawater Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 0.15 3030007-14 Shut-In Shut-In303000Interval 4Coyote@ 11746.86 - 11750.86 ft 104.5 °FInterval 5Coyote@ 11198.38 - 11202.38 ft 104.5 °FInterval 6Coyote@ 10695.48 - 10699.48 ft 104.5 °FInterval 7Coyote@ 10195.85 - 10199.85 ft 104.5 °FConoco Phillips - 3S-703Planned Design122 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Cum. PropTreatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lb)7/7/25Liquid Additives Dry Additives50-103-2091309101813288-1 Shut-In Shut-In2:12:02 8-2 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:12:02 0.158-3 Shut-In Shut-In2:07:16 8-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 2:07:16 1.00 1.00 0.50 27.00 2.00 0.158-5 27# Linear Displace Dart to Seat 15 6,224 148 148 0:09:53 2:05:16 1.00 1.00 0.50 27.00 2.00 0.158-6 27# Linear DFIT 5 840 20 20 0:04:00 1:55:23 1.00 1.00 0.50 27.00 2.00 0.158-7 Shut-In Shut-In1:51:23 8-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.158-9 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.158-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30008-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 107008-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 363008-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 735008-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 1414008-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 2110008-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 2650008-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 3030008-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030009-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 1.00 0.50 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.159-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30009-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 107009-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 363009-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 735009-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1414009-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 2110009-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 2650009-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 3030009-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 30300010-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:13:31 1.00 1.00 0.50 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 2:11:01 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1510-3 27# Delta Frac Pad 20 4,064 97 97 0:04:50 2:01:01 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1510-4 27# Linear Displacement 20 5,560 132 132 0:06:37 1:56:10 1.00 1.00 0.50 27.00 2.00 0.1510-5 Shut-In Shut-In1:49:33 10-6 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 1:49:33 1.00 1.00 0.50 27.00 2.00 0.1510-7 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1510-8 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1510-9 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300010-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1070010-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 3630010-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 7350010-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 14140010-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 21100010-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26500010-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300010-17 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 3030002:01:02 2:01:02 11-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:01:02 1.00 1.00 0.50 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:58:32 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:48:32 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:28:59 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300011-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:21:40 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1070011-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:16:40 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 3630011-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 1:07:40 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 7350011-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:58:16 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 14140011-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:43:02 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 21100011-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:28:54 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26500011-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:18:49 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300011-12 27# Linear Flush 20 5,237 125 125 0:06:14 0:12:14 1.00 1.00 0.50 27.00 2.00 0.15 30300011-13 Seawater Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 0.15 30300011-14 Shut-In Shut-In303000Interval 9Coyote@ 9197.51 - 9201.51 ft 104.5 °FInterval 10Coyote@ 8698.18 - 8702.18 ft 104.4 °FInterval 11Coyote@ 8192.39 - 8196.39 ft 104.4 °FInterval 8Coyote@ 9737.14 - 9741.14 ft 104.5 °FConoco Phillips - 3S-703Planned Design123 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)105LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6Cum. PropTreatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lb)7/7/25Liquid Additives Dry Additives50-103-20913091018132812-1 Shut-In Shut-In1:58:09 12-2 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:09 0.1512-3 Shut-In Shut-In1:53:23 12-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:53:23 1.00 1.00 0.50 27.00 2.00 0.1512-5 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1512-6 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1512-7 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300012-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1070012-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 3630012-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 7350012-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 14140012-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 21100012-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26500012-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300012-15 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 30300013-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 1.00 0.50 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1513-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1513-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300013-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1070013-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 181 25,600 0:09:01 1:06:11 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 3630013-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 189 37,200 0:09:24 0:57:11 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 7350013-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:47:47 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 14140013-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:32:33 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 21100013-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:18:25 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26500013-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 132 38,000 0:06:35 0:08:20 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300013-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 30300014-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:46:16 1.00 1.00 0.50 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:43:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-3 27# Delta Frac Pad 201:33:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-4 27# Linear Displacement 201:33:46 1.00 1.00 0.50 27.00 2.00 0.1514-5 Shut-In Shut-In1:33:46 14-6 27# Linear Spacer and Dart Drop 201:33:46 1.00 1.00 0.50 27.00 2.00 0.1514-7 27# Delta Frac Establish Stable Fluid 201:33:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-8 27# Delta Frac Pad 201:33:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-9 27# Linear Displacement 201:33:46 1.00 1.00 0.50 27.00 2.00 0.1514-10 Shut-In Shut-In1:33:46 14-11 27# Linear Spacer and Dart Drop 201:33:46 1.00 1.00 0.50 27.00 2.00 0.1514-12 27# Linear Displacement 201:33:46 1.00 1.00 0.50 27.00 2.00 0.1514-13 Shut-In Shut-In1:33:46 14-14 27# Linear Spacer and Dart Drop 201:33:46 1.00 1.00 0.50 27.00 2.00 0.1514-15 27# Delta Frac Establish Stable Fluid 201:33:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-16 27# Delta Frac Pad 20 15,430 367 367 0:18:22 1:33:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1514-17 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:15:24 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300014-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 1:08:06 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 700014-19 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 1:05:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1980014-20 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 8,200 195 249 49,200 0:12:26 1:01:00 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 6900014-21 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:48:34 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 13690014-22 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:33:20 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 20650014-23 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:19:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26050014-24 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 4,250 101 148 42,500 0:07:22 0:09:07 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300014-25 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 30300015-1 27# Linear Displacement 20 2,100 50 50 0:02:30 1:46:16 1.00 1.00 0.50 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:43:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-3 27# Delta Frac Pad 20 15,430 367 367 0:18:22 1:33:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1515-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:15:24 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300015-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 1:08:06 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15700015-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 1:05:30 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1980015-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 8,200 195 249 49,200 0:12:26 1:01:00 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 6900015-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:48:34 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 13690015-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:33:20 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 20650015-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:19:11 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26050015-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 4,250 101 148 42,500 0:07:22 0:09:07 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300015-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 0.50 27.00 2.00 0.15 30300016-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:48:59 1.00 1.00 0.50 27.00 2.00 0.1516-2 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:46:29 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-3 27# Delta Frac Pad 20 7,700 183 183 0:09:10 1:33:09 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.1516-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:23:59 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 300016-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 1:16:41 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15700016-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 1:14:05 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 1980016-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 8,200 195 249 49,200 0:12:26 1:09:34 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 6900016-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 306 67,900 0:15:14 0:57:08 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 13690016-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 284 69,600 0:14:08 0:41:54 0.45 1.00 0.60 1.00 0.50 27.00 2.000.15 20650016-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 202 54,000 0:10:04 0:27:46 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 26050016-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 4,250 101 148 42,500 0:07:22 0:17:42 0.45 1.00 0.60 1.00 0.50 27.00 2.00 0.15 30300016-12 27# Linear Flush 20 3,637 87 87 0:04:20 0:10:20 1.00 1.00 0.50 27.00 2.00 0.15 30300016-13 Seawater Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 0.15 30300016-14 Shut-In Shut-In3030001,338,160 31,861 37,204 4,848,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6 Cum. Prop1,220,1444,800,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)104,87648,000Initial Design Material Volume 549.1 1,325.0 721.8 1,325.0 662.5 35,775.5 2,650.0 200.713,140--Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 CAT-3 Cla-Web WG-36 OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm-Max Additive Rate 0.4 0.8 0.7 0.8 0.4 22.7 1.7 0.1-Min Additive Rate0.0Fluid Type27# Delta Frac27# LinearSeawaterFreeze Protect----Proppant TypeWanli 16/20 Ceramic100M---Interval 12Coyote@ 7733.6 - 7737.6 ft 104.3 °FInterval 13Coyote@ 7191.9 - 7195.9 ft 104.3 °FInterval 14Coyote@ 6689.2 - 6693.2 ft 104.3 °FInterval 15Coyote@ 6190.67 - 6194.67 ft 104.3 °FInterval 16Coyote@ 5690.56 - 5694.56 ft 104.2 °F8:10:17 Conoco Phillips - 3S-703Planned Design124 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 100 20,160 480 103 10 1,890 452 Wichita 3J 100 20,160 480 103 10 1,890 453 Wichita 3J 100 20,160 480 100 10 1,890 454 Wichita 3J 99 19,950 475 96 10 1,890 455 Wichita 3J 99 19,950 475 99 10 1,890 456Wichita 3J 000 95 0007 Wichita 3J 99 19,950 475 96 10 1,890 458 Atigan 3J 105 19,949 475 95 10 1,627 399 Atigan 3J 104 19,755 470 102 10 1,627 3910 Atigan 3J 105 19,949 475 101 10 1,627 3911 Atigan 3J 105 19,949 475 100 10 1,627 3912 Atigan 3J 105 19,949 475 98 10 1,627 3913 Atigan 3J 104 19,755 470 98 45 8,078 19214 Atigan 3J 105 19,949 475 97 105 19,949 47515 Atigan 3J 105 19,949 475 100 105 19,949 47516 Atigan 3J 105 19,949 475 99 105 19,949 47517 Atigan 3J 105 19,949 475 95 105 19,949 47518 Atigan 3J 105 19,949 475 96 105 19,949 47519 Atigan 3J 105 19,949 475 95 105 19,949 47520 Atigan 3J 105 19,949 475 102 10 1,627 3921 Atigan 3J 105 19,949 475 101 10 1,627 3922 Atigan 3J 105 19,949 475 100 10 1,627 3923 Atigan 3J 105 19,949 475 98 10 1,627 3924 Atigan 3J 102 19,368 461 101 10 1,627 39Gallons Barrels Gallons Barrels Gallons Barrels458,491 10,916 155,381 3,700 303,110 7,217Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):475 475 475 475Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips 3S-7037/13/2025Coyote0910181328Conoco Phillips - 3S-703Water Straps 7.13.25 125 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 102 20,580 490 102 15 2,856 682 Wichita 3J 105 21,000 500 101 15 2,856 683 Wichita 3J 100 20,160 480 100 15 2,856 684 Wichita 3J 99 19,950 475 98 15 2,856 685 Wichita 3J 101 20,370 485 98 15 2,856 686 Wichita 3J 100 20,160 480 97 15 2,856 687 Wichita 3J 102 20,580 490 100 15 2,856 688 Atigan 3J 105 19,949 475 98 15 2,540 609 Atigan 3J 105 19,949 475 110 15 2,540 6010 Atigan 3J 105 19,949 475 103 15 2,540 6011 Atigan 3J 105 19,949 475 103 15 2,540 6012 Atigan 3J 105 19,949 475 102 15 2,540 6013 Atigan 3J 105 19,949 475 103 105 19,949 47514 Atigan 3J 105 19,949 475 105 105 19,949 47515 Atigan 3J 105 19,949 475 101 105 19,949 47516 Atigan 3J 105 19,949 475 100 105 19,949 47517 Atigan 3J 105 19,949 475 103 105 19,949 47518 Atigan 3J 105 19,949 475 103 105 19,949 47519 Atigan 3J 105 19,949 475 100 15 2,540 6020 Atigan 3J 105 19,949 475 96 15 2,540 6021 Atigan 3J 105 19,949 475 99 15 2,540 6022 Atigan 3J 105 19,949 475 95 15 2,540 6023 Atigan 3J 105 19,949 475 96 15 2,540 6024 Atigan 3J 104 19,755 470 95 15 2,540 60Gallons Barrels Gallons Barrels Gallons Barrels481,735 11,470 167,622 3,991 314,113 7,479Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):478 478 478 478Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips 3S-7037/14/2025Coyote0910181328Conoco Phillips - 3S-703Water Straps 7.14.25126 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 101 20,370 485 103 15 2,856 682 Wichita 3J 102 20,580 490 106 15 2,856 683 Wichita 3J 100 20,160 480 102 15 2,856 684 Wichita 3J 100 20,160 480 101 15 2,856 685 Wichita 3J 100 20,160 480 102 15 2,856 686 Wichita 3J 100 20,160 480 103 15 2,856 687 Wichita 3J 100 20,160 480 102 15 2,856 688 Atigan 3J 105 19,949 475 104 15 2,540 609 Atigan 3J 100 18,981 452 105 15 2,540 6010 Atigan 3J 105 19,949 475 104 15 2,540 6011 Atigan 3J 105 19,949 475 104 15 2,540 6012 Atigan 3J 105 19,949 475 101 15 2,540 6013 Atigan 3J 105 19,949 475 103 105 19,949 47514 Atigan 3J 105 19,949 475 100 105 19,949 47515 Atigan 3J 103 19,562 466 100 103 19,562 46616 Atigan 3J 103 19,562 466 100 103 19,562 46617 Atigan 3J 102 19,368 461 100 102 19,368 46118 Atigan 3J 104 19,755 470 104 15 2,540 6019 Atigan 3J 105 19,949 475 108 15 2,540 6020 Atigan 3J 105 19,949 475 105 15 2,540 6021 Atigan 3J 105 19,949 475 106 15 2,540 6022 Atigan 3J 105 19,949 475 107 15 2,540 6023 Atigan 3J 105 19,949 475 106 15 2,540 6024 Atigan 3J 105 19,949 475 105 15 2,540 60Gallons Barrels Gallons Barrels Gallons Barrels478,363 11,390 148,858 3,544 329,505 7,845Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):475 475 475 475Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips 3S-7037/15/2025Coyote0910181328Conoco Phillips - 3S-703Water Straps 7.15.25127 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 102 20,580 490 93 15 2,856 682 Wichita 3J 100 20,160 480 92 15 2,856 683 Wichita 3J 100 20,160 480 95 15 2,856 684 Wichita 3J 98 19,740 470 93 15 2,856 685 Wichita 3J 98 19,740 470 93 15 2,856 686 Wichita 3J 97 19,530 465 94 15 2,856 687 Wichita 3J 98 19,740 470 94 15 2,856 688 Atigan 3J 105 19,949 475 95 15 2,540 609 Atigan 3J 104 19,755 470 96 15 2,540 6010 Atigan 3J 104 19,755 470 94 15 2,540 6011 Atigan 3J 105 19,949 475 93 15 2,540 6012 Atigan 3J 105 19,949 475 93 15 2,540 6013 Atigan 3J 99 18,788 447 94 105 19,949 47514 Atigan 3J 103 19,562 466 96 103 19,562 46615 Atigan 3J 105 19,949 475 96 105 19,949 47516 Atigan 3J 105 19,949 475 93 105 19,949 47517 Atigan 3J 105 19,949 475 95 105 19,949 47518 Atigan 3J 105 19,949 475 92 15 2,540 6019 Atigan 3J 103 19,562 466 93 15 2,540 6020 Atigan 3J 104 19,755 470 92 15 2,540 6021 Atigan 3J 105 19,949 475 93 15 2,540 6022 Atigan 3J 105 19,949 475 94 15 2,540 6023 Atigan 3J 105 19,949 475 92 15 2,540 6024 Atigan 3J 104 19,755 470 91 15 2,540 60Gallons Barrels Gallons Barrels Gallons Barrels476,069 11,335 149,825 3,567 326,243 7,768Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):472 472 472 472Conoco Phillips 3S-7037/16/2025Coyote0910181328Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips - 3S-703Water Straps 7.16.25128 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.000 98 0 2,496 200 520 80 600 18 6.97 7.15 8.60 Y 35,3942 N 1.000 97 0 2,130 200 280 160 440 18 7.05 7.45 8.78 Y 35,8813 N 1.002 97 0 2,306 200 320 280 600 17 7.11 7.40 8.78 Y 36,9514 N 1.002 94 0 3,176 200 440 360 800 18 7.13 7.30 8.75 Y 39,5275 N 1.002 97 0 3,176 200 360 360 720 18 7.20 7.26 8.60 Y 43,6266 N 1.010 96 0 14,650 800 800 880 1,680 19 7.20 7.26 8.59 Y 3,5237 N 1.010 94 0 10,650 800 960 1,000 1,960 18 7.14 7.30 8.69 Y 3,2538 N 1.010 97 0 12,480 800 800 1,000 1,800 18 7.10 7.45 8.76 Y 2,1259 N 1.012 96 0 14,650 800 880 1,320 2,200 17 7.15 7.25 8.80 Y 2,22510 N 1.012 98 0 14,650 800 960 1,240 2,200 18 7.14 7.29 8.90 Y 27,06611 N 1.010 95 0 11,530 800 800 1,000 1,800 19 7.15 7.26 8.73 Y 3,69212 N 1.010 99 0 11,530 800 800 1,000 1,800 18 7.17 7.29 8.71 Y 4,21713 N 1.010 97 0 9,070 800 800 1,040 1,840 19 7.16 7.30 8.69 Y 6,88814 N 1.012 98 0 10,650 800 800 720 1,520 18 7.12 7.27 8.70 Y 4,22115 N 1.010 96 0 13,520 800 800 1,000 1,800 18 7.14 7.28 8.80 Y 3,82816 N 1.012 96 0 11,530 800 680 1,400 2,080 17 7.14 7.25 8.75 Y 2,88817 N 1.010 95 0 20,380 800 880 1,200 2,080 19 7.14 7.25 8.70 Y 2,75718 N 1.000 97 0 2,496 200 560 1,600 2,160 18 7.15 7.24 8.67 Y 3,23619 N 1.002 94 0 2,930 200 520 1,640 2,160 18 7.16 7.23 8.71 Y 2,49620 N 1.002 96 0 2,930 200 520 1,560 2,080 18 7.19 7.20 8.69 Y 2,59421 N 1.002 94 0 2,306 200 520 1,560 2,080 18 7.20 7.21 8.76 Y 3,40122 N 1.002 98 0 3,176 200 520 1,560 2,080 17 7.16 7.25 8.79 Y 3,76023 N 1.002 95 0 2,306 200 680 1,480 2,160 18 7.17 7.26 8.80 Y 6,73324 N 1.000 95 0 15,880 800 560 1,560 2,120 19 7.16 7.29 8.81 Y 19,653Average 1.006 0 8,358 525 657 1042 1,698 18.0 7.14 7.28 8.73 - 12,497Maximum 1.012 0 20,380 800 960 1,640 2,200 19.0 7.20 7.45 8.90 - 43,626Minimum 1.000 0 2,130 200 280 80 440 17.00 6.97 7.15 8.59 - 2,125Range 0.012 0 18,250 600 680 1,560 1,760 2.0 0.23 0.30 0.31 - 41,501Well Name:3S-703Water Source:3JAlaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3S-703Water Analysis 7.04.25129 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.005 0 2,930 400 520 120 640 43,1472 N 1.005 0 2,930 400 600 40 640 72,0663 N 1.003 0 2,130 200 520 80 600 84,3344 N 1.004 0 3,448 200 560 160 720 71,6545 N 1.050 0 4,076 400 680 0 680 73,6416 N 1.004 0 3,448 400 520 80 600 81,8657 N 1.008 0 5,838 400 920 0 920 54,6928 N 1.012 0 7,122 400 1,120 200 1,320 72,7979 N 1.010 0 6,434 400 1,000 40 1,040 54,44610 N 1.008 0 5,838 400 840 680 1,520 70,46211 N 1.008 0 6,434 800 1,000 80 1,080 66,66912 N 1.006 0 5,838 400 680 240 920 65,08020 N 1.008 0 5,316 400 720 80 800 82,52721 N 1.004 0 7,122 400 720 160 880 72,15822 N 1.006 0 5,316 400 720 360 1,080 49,20923 N 1.004 0 5,316 200 960 0 960 72,15924 N 1.004 0 4,444 400 640 320 960 65,103Average 1.009 0 4,940 388 748 155 904 20.3 7.09 7.36 8.80 - 67,765Maximum 1.050 0 7,122 800 1,120 680 1,520 21.0 7.11 7.46 8.82 - 84,334Minimum 1.003 0 2,130 200 520 0 600 19.00 7.08 7.25 8.78 - 43,147Range 0.047 0 4,992 600 600 680 920 2.0 0.03 0.21 0.04 - 41,1878.82 Y9421 7.09 7.378.81 Y9321 7.11 7.25 8.78 Y10719 7.08 7.46Well Name:3S-703Water Source:3JAlaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3S-703Water Analysis 7.14.25130 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.008 0 4,444 200 600 200 800 6,5662 N 1.008 0 5,316 200 760 40 800 7,2873 N 1.004 0 3,176 200 600 40 640 43,7964 N 1.004 0 4,444 400 720 80 800 42,1285 N 1.006 0 5,316 200 840 0 840 16,9546 N 1.004 0 4,076 200 640 120 760 26,0377 N 1.004 0 2,496 200 520 120 640 6,3468 N 1.002 0 2,704 200 560 120 680 9,8919 N 1.002 0 2,930 200 560 0 560 13,11110 N 1.002 0 2,930 200 560 320 880 23,86911 N 1.002 0 2,496 200 520 40 560 26,02212 N 1.004 0 3,746 400 600 40 640 28,53219 N 1.000 0 2,130 200 280 240 520 20,20520 N 1.002 0 2,306 200 480 0 480 21,63821 N 1.002 0 2,306 200 440 40 480 20,31222 N 1.002 0 2,496 200 520 0 520 19,39723 N 1.002 0 2,306 200 400 80 480 14,13724 N 1.000 0 2,130 200 400 80 480 17,611Average 1.003 0 3,208 222 556 87 642 20.0 6.97 7.38 8.82 - 20,213Maximum 1.008 0 5,316 400 840 320 880 20.0 7.07 7.42 8.84 - 43,796Minimum 1.000 0 2,130 200 280 0 480 20.00 6.82 7.34 8.80 - 6,346Range 0.008 0 3,186 200 560 320 400 0.0 0.25 0.08 0.04 - 37,4498.84 Y110.7020.0 7.07 7.428.80 Y112.0020.0 7.02 7.34 8.82 Y106.3020.0 6.82 7.39Well Name:3S-703Water Source:3JAlaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3S-703Water Analysis 7.15.25131 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.004 0 1,814 200 480 0 480 8,5942 N 1.004 0 1,814 200 400 0 400 7,8083 N 1.006 0 1,814 200 320 160 480 10,1744 N 1.002 0 1,814 200 480 0 480 29,3675 N 1.004 0 1,966 200 520 0 520 48,0356 N 1.004 0 1,966 200 440 0 440 15,2307 N 1.002 0 1,674 200 360 160 520 13,3108 N 1.002 0 1,966 200 320 80 400 11,5189 N 1.004 0 1,966 200 320 120 440 15,12810 N 1.004 0 1,814 200 280 240 520 9,26811 N 1.004 0 2,130 200 280 120 400 11,19312 N 1.004 0 2,130 200 440 0 440 11,67418 N 1.004 0 2,306 200 360 0 360 69,13419 N 1.004 0 1,966 200 320 200 520 77,09220 N 1.002 0 1,304 200 400 0 400 16,03621 N 1.002 0 1,814 200 360 40 400 20,40722 N 1.004 0 1,814 200 280 40 320 12,52923 N 1.002 0 1,966 200 280 80 360 15,16524 N 1.004 0 2,130 200 240 80 320 16,177Average 1.003 0 1,904 200 362 69 432 21.3 6.95 7.45 8.62 - 21,992Maximum 1.006 0 2,306 200 520 240 520 22.0 7.00 7.54 8.63 - 77,092Minimum 1.002 0 1,304 200 240 0 320 20.00 6.92 7.39 8.61 - 7,808Range 0.004 0 1,002 0 280 240 200 2.0 0.08 0.15 0.02 - 69,283Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Well Name:3S-703Water Source:3J8.63 Y106.0021.0 6.97 7.46 8.62 Y106.0020.00 6.92 7.408.61 Y107.0022.0 7.00 7.54 8.63 Y105.0022.0 6.92 7.39Conoco Phillips - 3S-703Water Analysis 7.16.25132 Linear Linear XL XL XL Lip time Linear Linear XL XL XL Lip time Interval Stage Visc pH Temp °F pH min Interval Stage Visc pH Temp °F pH min 1 Pad 19 7.09 79 8.5 0 11 Pad217.01998.61 0 .50# 22 7.11 84 8.58 0 22 Avg Linear Visc .50# 22 7 99 8.68 0 22 Avg Linear Visc 2.00# 24 7.12 85 8.63 0 82.0 Avg XLTemp 2.00# 22 7.05 99 8.67 0 97.5 Avg XLTemp 4.00# 23 7.15 85 8.66 0 8.6 Avg XL pH 4.00# 22 7.03 98 8.69 0 8.68 Avg XL pH 6.00# 23 7.3 84 8.67 0 6.00# 22 7.05 98 8.68 0 7.00# 22 7.03 80 8.67 0 7.00# 22 7.05 96.1 8.67 0 8.00# 22 7.08 81 8.71 0 8.00# 22 7.01 96 8.74 0 9.00# 22 7.33 80 8.69 0 9.00# 22 7.03 96 8.65 0 10.00# 22 7.35 80 8.65 0 10.00# 22 7.04 96 8.73 0 2 Pad 22 7.3 85 8.6 0 12 Pad246.95878.63 .50# 21 7.25 86 8.76 0 .50# 23 6.98 89 8.77 2.00# 19 7.15 93 8.71 0 2.00# 24 6.98 90 8.83 4.00# 20 7..21 88 8.72 0 21 Avg Linear Visc 4.00# 22 7 90 8.8 23 Avg Linear Visc 6.00# 22 7.25 86 8.75 0 88.0 Avg XLTemp 6.00# 22 6.97 89 8.8 88.6 Avg XLTemp 7.00# 22 7.23 87 8.73 0 8.7 Avg XL pH 7.00# 22 7.02 90 8.79 8.77 Avg XL pH 8.00# 22 7.26 88 8.7 0 8.00# 22 7.03 88 8.8 9.00# 22 7.25 89 8.72 0 9.00# 22 7.05 86 8.73 10.00# 21 7.25 90 8.67 0 10.00# 22 7.1 88 8.81 79 3 Pad 22 7.28 91 8.54 0 13 Pad227.05918.66 0 .50# 20 7.25 95 8.59 0 .50# 22 7.01 90 8.77 0 2.00# 20 7.21 98 8.55 0 2.00# 22 7.03 90 8.76 0 4.00# 20 7.09 99 8.58 0 20 Avg Linear Visc 4.00# 21 7.05 90 8.79 0 22 Avg Linear Visc 6.00# 20 7 94 8.6 0 95.0 Avg XLTemp 6.00# 22 7.04 90 8.81 0 88.4 Avg XLTemp 7.00# 20 7.45 96 8.82 0 8.6 Avg XL pH 7.00# 22 7.01 84 8.78 0 8.75 Avg XL pH 8.00# 20 7 96 8.65 0 8.00# 21 7.05 89 8.71 0 9.00# 20 7.02 92 8.67 0 9.00# 22 7.04 85 8.72 0 10.00# 21 7.01 94 8.68 0 10.00# 22 7.04 87 8.78 0 4 Pad 23 6.95 89 9 0 14 Pad207.05928.65 .50# 23 7 94 8.91 0 .50# 2.00# 23 7.01 97 8.87 0 2.00# 4.00# 22 7.03 98 8.86 0 22.33 Avg Linear Visc 4.00# 20 Avg Linear Visc 6.00# 22 7.05 91 8.88 0 91.89 Avg XLTemp 6.00# 92.0 Avg XLTemp 7.00# 22 7.15 92 8.83 0 8.85 Avg XL pH 7.00# 8.65 Avg XL pH 8.00# 22 7.05 88 8.8 0 8.00# 9.00# 22 7.02 90 8.78 0 9.00# 10.00# 22 7.06 88 8.73 0 10.00# 5 Pad 22 7.18 93 8.7 0 15 Pad227.01918.68 0 .50# 22 6.9 90 8.7 0 .50# 22 7.02 90 8.77 0 2.00# 22 6.92 88 8.64 0 2.00# 22 7.04 91 8.78 0 4.00# 22 6.95 91 8.65 0 21.89 Avg Linear Visc 4.00# 22 7 92 8.8 0 22 Avg Linear Visc 6.00# 22 7.02 90 8.65 0 90.56 Avg XLTemp 6.00# 22 7.01 90 8.79 0 90.0 Avg XLTemp 7.00# 22 6.95 91 8.67 0 8.67 Avg XL pH 7.00# 22 7.01 90 8.82 0 8.78 Avg XL pH 8.00# 21 6.9 88 8.66 0 8.00# 22 7.03 89 8.81 0 9.00# 22 6.96 91 8.67 0 9.00# 22 7.05 89 8.79 0 10.00# 22 6.9 93 8.65 0 10.00# 22 7.03 88 8.82 0 6 Pad 20 6.9 89 8.6 0 16 Pad227.01888.65 0 .50# 21 7.07 95 8.64 0 .50# 22 7.01 87 8.8 0 2.00# 22 7.06 97 8.65 0 2.00# 22 7.02 88 8.8 0 4.00# 23 7.06 99 8.63 0 21.78 Avg Linear Visc 4.00# 22 7.01 90 8.79 0 22 Avg Linear Visc 6.00# 22 7.04 95 8.69 0 93.67 Avg XLTemp 6.00# 22 7 91 8.82 0 88.1 Avg XLTemp 7.00# 22 6.99 98 8.71 0 8.67 Avg XL pH 7.00# 21 7.05 89 8.84 0 8.79 Avg XL pH 8.00# 22 6.86 90 8.65 0 8.00# 22 7.04 87 8.83 0 9.00# 22 6.89 92 8.69 0 9.00# 22 7.02 87 8.8 0 10.00# 22 6.92 88 8.80 0 10.00# 22 7.02 86 8.81 0 7 Pad 22 6.92 92 8.69 0 17 Pad .50# 20 6.89 88 8.71 0 .50# 2.00# 20 6.88 91 8.73 0 2.00# 4.00# 20 6.82 92 8.75 0 21 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 21 6.82 92 8.79 0 90.4 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 22 7.05 90 8.72 0 8.7 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 22 7.05 92 8.71 0 8.00# 9.00# 22 6.85 90 8.73 0 9.00# 10.00# 22 7.05 87 8.76 0 10.00# 8 Pad 21 7 94 8.77 0 18 Pad .50# 22 6.96 93 8.8 0 .50# 2.00# 23 7 97 8.82 0 2.00# 4.00# 22 7.02 100 8.88 0 22.00 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 22 6.97 94 8.83 0 91.67 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 22 6.98 87 8.8 0 8.83 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 22 6.97 88 8.82 0 8.00# 9.00# 22 7.05 86 8.87 0 9.00# 10.00# 22 6.99 86 8.89 0 10.00# 9 Pad 22 7.08 94 8.75 0 19 Pad .50# 22 7.1 93 8.76 0 .50# 2.00# 22 7.08 96 8.78 0 2.00# 4.00# 22 7.08 96 8.81 0 22 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 22 7.07 94 8.75 0 94.6 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 22 7.05 94 8.74 0 8.73 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 22 7.06 95 8.67 0 8.00# 9.00# 22 7 93 8.66 0 9.00# 10.00# 22 7.05 96 8.67 0 10.00# 10 Pad 21 7.04 94 8.64 0 20 Pad .50# 22 6.96 96 8.64 0 .50# 2.00# 22 7 96 8.6 0 2.00# 4.00# 22 7.05 96 8.74 0 22 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 22 7.08 95 8.7 0 95.7 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 22 7.09 95 8.69 0 8.68 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 22 7.08 99 8.69 0 . 8.00# 9.00# 22 7.01 96 8.68 0 9.00# 10.00# 22 7 94 8.73 0 10.00# Customer:CONOCO PHILLIPS Wellname & #:3S-703 Date:July 13, 2025 Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Conoco Phillips - 3S-703 Real-Time QC 133 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:33:19 (07/07/25) Start Job Starting Job 0 11 -1 0 2040 1 06:33:19 (07/07/25) Next Treatment Treatment Interval 1 0 11 -1 0 2040 2 7:37:42 Other Loop Test 7.7.25 0 7 -2 0 2063 3 7:48:03 Other Prime Pumps 0 7 141 0 2063 4 8:08:06 Pressure Test ePRV - Primary Tubing 0 885 939 0 2062 5 8:10:39 Other ePRV - Primary IA 0 949 946 0 2062 6 8:12:39 Pressure Test ePRV - Secondary Tubing 0 668 706 0 2062 7 8:14:07 Pressure Test ePRV - Secondary IA 0 739 916 0 2062 8 8:16:19 Pressure Test Pressure Test - Global 0 150 166 0 2062 9 8:16:26 Pressure Test Pressure Test - Locals 0 171 197 0 2062 10 8:17:23 Other Pressure Test - Max 0 8882 9002 0 2062 11 8:24:15 Other Pop-off Bypassing 0 6905 6884 0 2062 12 8:34:16 Pressure Test Pressure Test - Max 0 9540 9603 0 2061 13 8:39:54 Pressure Test Pressure Test - Pass 0 9514 9562 0 2061 14 9:08:44 Open Well Open Well 0 815 805 0 2570 15 9:09:52 Other Arsenal Burst Disk 1.11 5503 5607 1.8 7402 16 9:10:56 Other Alpha Sleeve Shift 3.35 6058 6190 2.2 8029 17 9:11:08 Other Start DFIT 3.85 2367 2353 2.3 4170 18 9:12:10 Other Injection Could not Be Established 7.32 6837 6938 0 8644 19 9:48:18 Other Bleed off on Surface 10.23 8992 9031 0 10833 20 10:04:11 Other Bleed Down on Surface 15.1 8955 8990 0 10788 21 10:31:45 Other Bleed Off on Surface 19.99 8945 8978 0 10778 22 10:59:33 Other Bleed Down on Surface 24.9 8935 8968 0 10776 23 11:22:24 Other Bleed Off on Surface 29.89 8661 8696 0 10503 24 11:57:37 Other Bleed on Off Surface 34.85 8619 8641 0 10443 25 6:21:21 End Job Ending Job 36.08 22 -2 0 1772 Event Log 7.07.25 Conoco Phillips - 3S-703 Event Log 7.07 134 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 15:21:39 (07/12/25) Start Job Starting Job 0 0 0 0 0 1 15:21:39 (07/12/25) Next Treatment Treatment Interval 1 0 0 0 0 0 2 15:24:20 Other Customer Gave us Well 0 0 0 0 1566 3 16:19:52 Prime Pumps Prime Pumps 0 1 4 0 1569 4 17:00:10 Pressure Test ePRV - Primary Tubing 0 924 978 0 1570 5 17:02:24 Pressure Test ePRV - Primary IA 0 824 899 0 1570 6 17:04:21 Pressure Test ePRV - Seconday Tubing 0 939 1013 0 1571 7 17:05:14 Pressure Test ePRV - Secondary IA 0 696 883 0 1571 8 17:06:22 Pressure Test Pressure Test - Global 0 123 124 0 1571 9 17:06:49 Pressure Test Pressure Test - Locals 0 1518 1548 0 1571 10 17:10:18 Pressure Test Pressure Test - Max 0 9533 9505 0 1571 11 17:15:26 Pressure Test Pressure Test - Pass 0 9496 9449 0 1571 12 17:22:39 Other Leaking Chiksan 0 204 205 0 1576 13 17:40:20 Pressure Test Pressure Test - Max 0 9528 9521 0 1575 14 17:44:12 Pressure Test Pressure Test - Pass 0 9525 9482 0 1575 15 17:49:33 Open Well Open Well 0 64 56 0 1583 16 18:27:02 Alarm Delta Stage At Top Perf = 7 199.32 2289 2360 5.2 4085 17 19:09:39 ISIP ISIP 502.56 1077 1097 0 2909 18 19:14:40 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 502.56 1037 1048 0 2825 19 19:19:39 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 506.98 103 70 0 2788 20 19:24:40 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 506.98 13 28 0 2762 Event Log 7.12.25 Conoco Phillips - 3S-703 Event Log 7.12 135 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:10:19 (07/13/25) Other Crew Arrived on Location ---- ---- ---- ---- ---- 2 6:35:51 Start Job Starting Job 0 0 0 0 0 1 06:35:51 (07/13/25) Next Treatment Treatment Interval 1 0 0 0 0 1 3 7:00:07 Pre-Job Safety Meeting Pre-Job Safety Meeting 0 29 -6 0 2149 4 7:08:48 Other Waiting on hardline and Scaffolders 0 28 -6 0 2147 5 8:48:47 Other Frac Began Rigging Up DME 0 18 -2 0 2122 6 10:01:22 Other Loop Test 0 0 -1 0 2106 7 10:05:28 Prime Pumps Prime Pumps 0 41 75 0 2106 8 10:23:50 Pressure Test ePRV - Primary Tubing 0 913 966 0 2102 9 10:24:55 Pressure Test ePRV - Primary IA 0 838 873 0 2102 10 10:26:36 Pressure Test ePRV - Secondary Tubing 0 738 797 0 2101 11 10:27:39 Pressure Test ePRV - Secondary IA 0 777 933 0 2101 12 10:30:01 Pressure Test Pressure Test - Global 0 304 351 0 2101 13 10:30:08 Pressure Test Pressure Test - Locals 0 327 383 0 2101 14 10:31:38 Pressure Test Pressure Test - Max 0 9528 9536 0 2100 15 10:36:37 Pressure Test Pressure Test - Max 0 9493 9457 0 2099 16 10:59:06 Open Well Open Well 0 613 608 0 2212 17 11:04:20 ISIP ISIP 19.45 1214 1232 0 2928 18 11:04:42 Shut In Well Shut In Well 19.45 1221 1230 0 2890 19 11:09:23 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 19.45 1190 1202 0 2728 20 11:11:11 Other Closure 19.45 1184 1199 0 2683 21 11:14:22 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 19.45 1177 1194 0 2618 22 11:19:23 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 19.45 1169 1188 0 2541 23 11:32:15 Open Well Open Well 19.45 786 782 0 2448 24 11:35:35 Other Step 1 21.22 1209 1241 0.6 2918 25 11:37:12 Other Step 2 22.97 1314 1340 1.2 3010 26 11:38:27 Other Step 3 25.15 1357 1383 1.8 3055 27 11:39:45 Other Step 4 28.13 1392 1419 2.4 3082 28 11:41:05 Other Step 5 32.08 1428 1455 2.9 3114 29 11:42:25 Other Step 6 36.71 1462 1493 3.5 3153 30 11:43:45 Other Step 7 42.14 1506 1544 4.1 3194 31 11:45:00 Other Step 8 47.88 1559 1591 4.7 3247 32 11:46:17 Other Step 9 54.7 1596 1626 5.3 3300 33 11:47:52 Other Step 10 63.95 1621 1657 5.9 3344 34 11:48:23 Other Step 11 67.36 1698 1770 7 3443 35 11:55:31 Start Pad Start Pad 170.69 2175 2328 15.1 3759 36 11:58:19 Alarm Delta Stage At Top Perf = 11 225.27 2613 2798 20.7 3902 37 11:59:15 Alarm Delta Stage At Top Perf = 13 244.59 2661 2863 20.7 3940 38 12:02:19 Alarm Delta Stage At Top Perf = 14 307.8 2838 3026 20.6 4091 39 12:06:34 Alarm Delta Stage At Top Perf = 15 395.88 3172 3368 20.7 4430 40 12:08:31 Other Neutral Pump 358 - Mechanical Issue 435.87 3210 3408 20.6 4483 41 12:25:52 Alarm Delta Stage At Top Perf = 16 788.64 3055 3276 20.5 4361 42 12:33:04 Alarm Delta Stage At Top Perf = 17 935.21 2825 3095 20.4 4340 43 12:37:59 Alarm Delta Stage At Top Perf = 18 1035.07 2762 3018 20.2 4335 44 12:46:53 Alarm Delta Stage At Top Perf = 19 1215.23 2608 2868 20.2 4327 45 12:49:34 Other 2nd Tracer Drop 1269.39 2566 2828 20.2 4305 46 12:56:13 Alarm Delta Stage At Top Perf = 20 1403.6 2591 2865 20.2 4334 47 12:59:37 Other Debris in Pump 454 1472.21 2601 2860 20.2 4344 48 13:11:40 Alarm Delta Stage At Top Perf = 21 1711.46 2592 2843 19.8 4397 49 13:26:12 Alarm Delta Stage At Top Perf = 22 1999.47 2641 2905 19.8 4451 50 13:27:13 Other 3rd Tracer Drop 2019.58 2634 2881 19.8 4447 2 13:34:15 (07/13/25) Next Treatment Treatment Interval 2 2163.14 3074 3200 20.9 4531 51 13:34:15 Drop Ball Drop Dart for Interval 2 2163.14 3074 3201 20.9 4531 52 13:35:50 Alarm Delta Stage At Top Perf = 23 2196.24 3004 3124 20.9 4466 53 13:41:11 Other Slow Down For Dart 2307.54 1837 1966 16.1 3266 54 13:42:53 Ball on Seat Dart on Seat 2333.49 2085 2270 15.1 3468 55 13:43:03 Break Formation Break Formation 2335.75 5151 5347 15 6325 56 13:43:34 Alarm Delta Stage At Top Perf = 24 2343.76 2799 2960 15 4084 57 13:45:31 Alarm Delta Stage At Top Perf = 1 2379.4 2907 3051 20.8 4119 58 13:48:01 Alarm Delta Stage At Top Perf = 2 2431.36 2703 2919 20.8 4008 59 13:51:27 Alarm Delta Stage At Top Perf = 7 2502.84 2652 2843 20.8 3958 60 13:51:54 Other Drop 1st Tracer 2511.85 2652 2833 20.8 3954 61 14:10:21 Alarm Delta Stage At Top Perf = 8 2895.14 2532 2747 20.7 3906 62 14:17:25 Alarm Delta Stage At Top Perf = 9 3041.14 2400 2626 20.6 3954 63 14:22:17 Alarm Delta Stage At Top Perf = 10 3141.28 2440 2684 20.5 4030 64 14:31:05 Alarm Delta Stage At Top Perf = 11 3321.5 2473 2715 20.4 4137 65 14:33:44 Other 2nd Tracer Drop 3375.24 2458 2714 20.4 4152 66 14:40:20 Alarm Delta Stage At Top Perf = 12 3510.32 2508 2747 20.4 4202 67 14:55:27 Alarm Delta Stage At Top Perf = 13 3817.89 2509 2773 20.4 4235 68 15:09:30 Alarm Delta Stage At Top Perf = 14 4103.5 2568 2811 20.3 4310 69 15:11:36 Other 3rd Tracer Drop 4146.07 2538 2783 20.3 4307 70 15:18:12 Drop Ball Drop Dart for Interval 03 4282.08 2959 3120 20.9 4378 3 15:18:15 (07/13/25) Next Treatment Treatment Interval 3 4283.12 2961 3127 20.9 4379 71 15:19:01 Alarm Delta Stage At Top Perf = 15 4299.11 2971 3145 20.9 4385 72 15:21:46 Other Swapping to Semi Seawater tanks 4356.74 2583 2704 21.2 4099 73 15:24:50 Other Slow Down For Dart 4421.27 2143 2360 21.1 3590 74 15:27:14 Ball on Seat Dart on Seat 4458.93 1989 2086 15.5 3302 75 15:27:16 Alarm Delta Stage At Top Perf = 16 4459.45 2116 2172 15.5 3529 76 15:27:45 Break Formation Break Formation 4466.91 4613 4738 15.4 6078 77 15:29:21 Alarm Delta Stage At Top Perf = 1 4491.54 3260 3388 15.4 4634 78 15:32:35 Alarm Delta Stage At Top Perf = 2 4541.42 3330 3489 15.5 4685 79 15:34:27 Alarm Delta Stage At Top Perf = 3 4570.22 3353 3508 15.5 4684 80 15:35:06 Alarm Delta Stage At Top Perf = 2 4580.29 3378 3532 15.4 4711 81 15:42:25 Alarm Delta Stage At Top Perf = 3 4714.88 3060 3169 20.8 4598 82 15:45:52 Alarm Delta Stage At Top Perf = 4 4786.75 2658 2767 20.9 4170 83 15:51:47 Other Load Back Up Dart 4805.3 981 1025 0 2821 84 15:55:19 Drop Ball Drop Back Up Dart for Interval 03 4834.55 2811 2929 20.5 4323 85 16:04:25 Ball on Seat Dart on Seat 5008.67 2267 2439 14.8 3614 86 16:04:31 Break Formation Break Formation 5010.4 4578 4743 14.8 6012 87 16:04:45 Alarm Delta Stage At Top Perf = 5 5013.84 2626 2717 14.7 3889 88 16:07:25 Alarm Delta Stage At Top Perf = 6 5063.52 2359 2517 20.7 3644 89 16:09:38 Alarm Delta Stage At Top Perf = 7 5109.38 2361 2534 20.7 3660 90 16:29:31 Alarm Delta Stage At Top Perf = 8 5519.81 2219 2405 20.5 3610 91 16:36:42 Alarm Delta Stage At Top Perf = 9 5666.04 2166 2377 20.3 3727 92 16:41:37 Alarm Delta Stage At Top Perf = 10 5765.75 2237 2461 20.1 3805 93 16:50:35 Alarm Delta Stage At Top Perf = 11 5945.99 2245 2489 20 3897 94 16:54:19 Other Pump 454 Preload Bladder 6020.1 2034 2318 15.4 3881 95 17:00:07 Alarm Delta Stage At Top Perf = 12 6133.13 2292 2508 20 3974 96 17:15:25 Alarm Delta Stage At Top Perf = 13 6439.02 2357 2626 20 4092 97 17:29:46 Alarm Delta Stage At Top Perf = 14 6724.84 2366 2620 19.9 4117 98 17:32:03 Other 3rd Tracer Drop 6770.2 2370 2595 19.9 4128 99 17:39:52 Alarm Delta Stage At Top Perf = 15 6928.47 2922 3057 20.6 4281 100 17:48:31 ISIP ISIP 7104.85 1113 1177 0 2883 101 17:53:32 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 7104.85 -37 40 0 2841 102 17:58:28 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 7104.85 123 235 0 2821 103 18:03:31 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 7104.85 -12 54 0 2805 Event Log 7.13.25 Conoco Phillips - 3S-703 Event Log 7.13 136 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:09:28 (07/14/25) Start Job Starting Job 0 0 0 0 0 1 06:09:28 (07/14/25) Next Treatment Treatment Interval 1 0 0 0 0 0 4 06:10:22 (07/14/25) Next Treatment Treatment Interval 4 0 -20 3 0 0 2 6:52:36 Other Loop Test 0 2 1 16.3 2164 3 7:24:50 Pressure Test ePRV - Primary Tubing 0 514 630 0 2157 4 7:27:13 Pressure Test ePRV - Primary IA 0 1096 1116 0 2156 5 7:29:09 Pressure Test ePRV- Seconday Tubing 0 303 326 0 2156 6 7:30:37 Pressure Test ePRV - Secondary IA 0 250 278 0 2155 7 7:39:30 Pressure Test Pressure Test - Max 0 9482 9457 0 2154 8 7:42:38 Pressure Test Pressure Test - Popoff Passing 0 8994 8928 0 2153 9 7:49:02 Pressure Test Pressure Test - Global 0 586 634 0 2152 10 7:49:07 Pressure Test Pressure Test - Local 0 607 663 0 2152 11 7:52:01 Pressure Test Pressure Test - Max 0 9508 9482 0 2151 12 7:56:24 Pressure Test Pressure Test - Pass 0 9426 9378 0 2150 13 8:31:28 Open Well Open Well 0 759 739 0 2402 14 8:33:39 Drop Ball Drop Dart for Interval 04 29.09 2471 2585 20.8 3614 15 8:39:51 Other Slow Down For Dart 157.03 2424 2671 20.4 3674 16 8:42:31 Ball on Seat Dart on Seat 197.71 2308 2460 15 3467 17 8:42:38 Break Formation Break Formation 199.45 5239 5427 14.9 6396 18 8:42:43 Alarm Delta Stage At Top Perf = 4 200.69 4058 4236 14.9 5449 19 8:48:17 Alarm Delta Stage At Top Perf = 5 307.33 2511 2716 20.5 3683 20 8:48:59 Alarm Delta Stage At Top Perf = 6 321.68 2497 2695 20.5 3682 21 9:08:19 Alarm Delta Stage At Top Perf = 7 717.9 2510 2727 20.5 3768 22 9:15:29 Alarm Delta Stage At Top Perf = 8 864.27 2381 2594 20.4 3820 23 9:20:21 Alarm Delta Stage At Top Perf = 9 963.71 2393 2622 20.4 3875 24 9:29:09 Alarm Delta Stage At Top Perf = 10 1142.92 2401 2641 20.3 3981 25 9:38:23 Alarm Delta Stage At Top Perf = 11 1330.42 2444 2685 20.3 4057 26 9:42:46 Other 2nd Tracer Drop 1419.42 2434 2666 20.3 4059 27 9:53:29 Alarm Delta Stage At Top Perf = 12 1636.63 2492 2724 20.3 4146 28 10:07:41 Alarm Delta Stage At Top Perf = 13 1923.05 2510 2763 20.1 4194 29 10:17:46 Alarm Delta Stage At Top Perf = 14 2127.5 2951 3074 20.7 4287 5 10:18:18 (07/14/25) Next Treatment Treatment Interval 5 2138.56 2975 3115 20.7 4282 30 10:18:18 Drop Ball Drop Dart for Interval 05 2138.56 2975 3115 20.7 4283 31 10:26:16 Ball on Seat Dart on Seat 2292.28 2016 2172 14.9 3271 32 10:26:29 Break Formation Break Formation 2295.5 5530 5683 14.8 6831 33 10:26:49 Alarm Delta Stage At Top Perf = 15 2300.43 4619 4747 14.8 5835 34 10:28:55 Alarm Delta Stage At Top Perf = 1 2331.57 2955 3094 14.9 4075 35 10:31:55 Alarm Delta Stage At Top Perf = 2 2381.24 2955 3093 20.7 4008 36 10:39:57 Other first tracer drop 2547.28 2545 2738 20.7 3723 37 10:40:13 Alarm Delta Stage At Top Perf = 3 2553.15 2542 2704 20.7 3722 38 10:52:42 Alarm Delta Stage At Top Perf = 4 2809.89 2331 2516 20.4 3604 39 11:00:06 Alarm Delta Stage At Top Perf = 5 2960.66 2205 2416 20.3 3652 40 11:05:01 Alarm Delta Stage At Top Perf = 6 3060.44 2253 2462 20.2 3704 41 11:13:48 Alarm Delta Stage At Top Perf = 7 3237.67 2260 2458 20.2 3790 42 11:22:59 Alarm Delta Stage At Top Perf = 8 3422.57 2285 2498 20.2 3862 43 11:38:12 Alarm Delta Stage At Top Perf = 9 3727.78 2299 2499 20.1 3929 44 11:52:30 Alarm Delta Stage At Top Perf = 10 4015.04 2299 2536 20 3967 45 11:55:30 Other 3rd Tracer Drop 4075.04 2272 2474 20 3947 46 12:02:41 Alarm Delta Stage At Top Perf = 11 4220.56 2679 2877 20.6 4080 47 12:04:10 Drop Ball Drop Dart for Interval 06 4250.79 2790 2944 20.6 4062 6 12:04:13 (07/14/25) Next Treatment Treatment Interval 6 4252.16 2789 2947 20.6 4068 48 12:11:56 Ball on Seat Ball on Seat 4399.57 1889 2045 15 3107 49 12:12:05 Break Formation Break Formation 4401.81 4679 4812 14.9 5896 50 12:12:15 Alarm Delta Stage At Top Perf = 12 4404.3 2800 2902 14.9 3952 51 12:14:18 Alarm Delta Stage At Top Perf = 1 4437.78 2465 2651 20.7 3560 52 12:16:43 Alarm Delta Stage At Top Perf = 2 4488.03 2397 2577 20.8 3562 53 12:18:30 Alarm Delta Stage At Top Perf = 3 4524.98 2442 2617 20.7 3605 54 12:37:41 Alarm Delta Stage At Top Perf = 4 4919.26 2563 2766 20.4 3693 55 12:44:52 Alarm Delta Stage At Top Perf = 5 5065.27 2375 2581 20.3 3700 56 12:49:47 Alarm Delta Stage At Top Perf = 6 5165.11 2410 2618 20.3 3767 57 12:58:41 Alarm Delta Stage At Top Perf = 7 5344.94 2390 2631 20.2 3846 58 13:07:59 Alarm Delta Stage At Top Perf = 8 5532.36 2336 2548 20.1 3882 59 13:23:20 Alarm Delta Stage At Top Perf = 9 5840.19 2157 2372 20.1 3820 60 13:37:42 Alarm Delta Stage At Top Perf = 10 6128.69 2158 2369 20.1 3855 61 13:48:01 Alarm Delta Stage At Top Perf = 11 6334.26 2594 2711 20.6 3927 62 13:48:21 Drop Ball Drop Dart for Interval 7 6341.14 2575 2690 20.7 3914 7 13:48:25 (07/14/25) Next Treatment Treatment Interval 7 6342.18 2573 2701 20.7 3936 63 13:55:40 Alarm Delta Stage At Top Perf = 12 6480.64 1716 1871 14.9 3115 64 13:55:44 Ball on Seat Dart on Seat 6481.39 1717 1872 14.9 3115 65 13:55:57 Break Formation Break Formation 6484.85 6382 6481 14.7 7849 66 13:58:21 Alarm Delta Stage At Top Perf = 1 6520.17 3449 3562 14.8 4644 67 14:01:13 Alarm Delta Stage At Top Perf = 2 6570.65 3298 3435 20.4 4464 68 14:03:37 Alarm Delta Stage At Top Perf = 3 6619.73 2983 3131 20.5 4186 69 14:22:42 Alarm Delta Stage At Top Perf = 4 7011.66 2233 2416 20.4 3521 70 14:29:50 Alarm Delta Stage At Top Perf = 5 7157.66 2071 2274 20.4 3550 71 14:34:50 Alarm Delta Stage At Top Perf = 6 7259.45 2116 2308 20.4 3604 72 14:43:48 Alarm Delta Stage At Top Perf = 7 7441.43 2125 2381 20.2 3659 73 14:53:10 Alarm Delta Stage At Top Perf = 8 7630.06 2179 2422 20.1 3739 74 15:08:27 Alarm Delta Stage At Top Perf = 9 7938.12 2180 2398 20.2 3779 75 15:22:35 Alarm Delta Stage At Top Perf = 10 8223.08 2187 2412 20.1 3819 76 15:32:36 Alarm Delta Stage At Top Perf = 11 8426.48 2512 2664 20.8 3847 77 15:39:28 ISIP ISIP 8567.69 964 1033 0 2825 78 15:44:27 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 8567.69 36 57 0 2787 79 15:49:26 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 8567.69 47 73 0 2771 80 15:54:30 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 8567.69 21 39 0 2759 Event Log 7.14.25 Conoco Phillips - 3S-703 Event Log 7.14 137 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 05:42:54 (07/15/25) Start Job Starting Job 0 14 0 0 2087 1 05:42:54 (07/15/25) Next Treatment Treatment Interval 1 0 14 0 0 2087 8 05:47:55 (07/15/25) Next Treatment Treatment Interval 8 0 14 0 0 2086 2 6:48:24 Other Loop Test 0 14 -1 0 2076 3 7:02:58 Prime Pumps Prime Pumps 0 2 125 0 2074 4 7:17:07 Pressure Test ePRV - Primary Tubing 0 1108 1142 0 2072 5 7:18:05 Pressure Test ePRV - Primary IA 0 886 890 0 2072 6 7:19:29 Pressure Test ePRV - Secondary Tubing 0 871 973 0 2071 7 7:25:44 Pressure Test ePRV - Secondary IA 0 1006 1055 0 2070 8 7:31:18 Pressure Test Pressure Test - Global 0 529 593 0 2070 9 7:31:24 Pressure Test Pressure Test - Locals 0 549 603 0 2070 10 7:32:47 Pressure Test Pressure Test - Max 0 9546 9541 0 2069 11 7:36:58 Pressure Test Pressure Test - Pass 0 9470 9439 0 2069 12 8:05:20 Open Well Open Well 0 492 478 0 2125 13 8:05:30 Start Pumping Start Pumping 0 492 499 0.1 2197 14 8:07:38 Drop Ball Drop Dart for Interval 08 27.11 2520 2662 20.9 3652 15 8:14:59 Ball on Seat Dart on Seat 165.15 1589 1724 15.2 3165 16 8:15:08 Break Formation Break Formation 167.42 3899 4060 15.1 5927 17 8:15:18 Alarm Delta Stage At Top Perf = 4 170.19 2435 2551 15.1 3934 18 8:19:41 ISIP ISIP 196.99 912 916 0 2744 19 8:20:10 Stop Pumping Stop Pumping 196.99 939 968 0 2739 20 8:24:42 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 196.99 892 916 0 2705 21 8:29:42 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 196.99 814 838 0 2673 22 8:34:42 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 196.99 728 750 0 2637 23 8:57:52 Start Pumping Start Pumping 196.99 569 625 0 2411 24 9:00:02 Alarm Delta Stage At Top Perf = 5 213.97 2084 2276 18.8 3634 25 9:06:30 Alarm Delta Stage At Top Perf = 6 347.42 2218 2516 20.6 3448 26 9:07:28 Alarm Delta Stage At Top Perf = 8 367.34 2269 2543 20.6 3493 27 9:09:25 Alarm Delta Stage At Top Perf = 9 407.47 2331 2589 20.6 3528 28 9:28:35 Alarm Delta Stage At Top Perf = 10 800.12 2217 2461 20.5 3482 29 9:35:39 Alarm Delta Stage At Top Perf = 11 944.72 2028 2292 20.4 3458 30 9:40:33 Alarm Delta Stage At Top Perf = 12 1044.87 2046 2321 20.5 3515 31 9:49:23 Alarm Delta Stage At Top Perf = 13 1224.37 1994 2296 20.3 3603 32 9:58:43 Alarm Delta Stage At Top Perf = 14 1413.41 2021 2316 20.3 3652 33 10:13:43 Alarm Delta Stage At Top Perf = 15 1717.41 1965 2258 20.3 3646 34 10:27:39 Alarm Delta Stage At Top Perf = 16 1999.4 1983 2270 20.2 3690 35 10:37:42 Alarm Delta Stage At Top Perf = 17 2202.41 2074 2336 20.7 3780 36 10:40:11 Drop Ball Drop Dart for Interval 09 2253.61 2476 2682 20.7 3795 37 10:40:16 Stop Pumping Stop Pumping 2255.34 2480 2677 20.7 3798 9 10:40:17 (07/15/25) Next Treatment Treatment Interval 9 2255.68 2481 2677 20.7 3794 38 10:40:18 Start Pumping Start Pumping 2256.03 2485 2678 20.7 3802 39 10:46:16 Ball on Seat Dart on Seat 2380.42 1893 2077 20.8 3201 40 10:46:21 Break Formation Break Formation 2382.5 5731 5810 20.7 6938 41 10:46:28 Alarm Delta Stage At Top Perf = 18 2384.91 2589 2787 20.6 4098 42 10:48:04 Alarm Delta Stage At Top Perf = 1 2418.09 1958 2190 20.8 3141 43 10:50:37 Alarm Delta Stage At Top Perf = 2 2470.99 2048 2302 20.7 3242 44 10:52:24 Alarm Delta Stage At Top Perf = 3 2507.88 2157 2376 20.6 3331 45 11:11:25 Alarm Delta Stage At Top Perf = 4 2900.49 2064 2307 20.7 3323 46 11:18:30 Alarm Delta Stage At Top Perf = 5 3046.62 1947 2217 20.5 3340 47 11:23:24 Alarm Delta Stage At Top Perf = 6 3147.08 1965 2219 20.5 3382 48 11:32:11 Alarm Delta Stage At Top Perf = 7 3327.08 1952 2198 20.5 3447 49 11:41:22 Alarm Delta Stage At Top Perf = 8 3514.75 1901 2148 20.4 3458 50 11:56:25 Alarm Delta Stage At Top Perf = 9 3821.91 1850 2109 20.3 3471 51 12:10:29 Alarm Delta Stage At Top Perf = 10 4108.03 1875 2102 20.3 3522 52 12:20:30 Alarm Delta Stage At Top Perf = 11 4312.56 2040 2259 21.1 3568 53 12:22:32 Drop Ball Drop Dart for Interval 4355.09 2276 2457 20.8 3571 10 12:22:37 (07/15/25) Next Treatment Treatment Interval 10 4356.83 2279 2463 20.8 3613 54 12:28:23 Alarm Delta Stage At Top Perf = 12 4478.19 1674 1854 21.1 3067 55 12:28:35 Ball on Seat Dart on Seat 4482.42 1688 1875 21.1 3052 56 12:28:59 Break Formation Break Formation 4490.83 3682 3880 20.9 5111 57 12:30:04 Alarm Delta Stage At Top Perf = 1 4513.13 2829 2971 20.9 4020 58 12:31:00 Other Cut XL'ers 4532.65 2715 2906 20.9 3922 59 12:32:22 Alarm Delta Stage At Top Perf = 2 4561.49 2717 2867 20.8 3947 60 12:35:59 Alarm Delta Stage At Top Perf = 3 4636.77 2441 2580 20.8 3945 61 12:37:25 Other Shut Down to Load Back Up Dart 4665.25 625 614 0 2494 62 12:53:47 Drop Ball Drop BU Dart Interval 11 4694.43 2368 2492 20.8 3859 63 12:55:40 Alarm Delta Stage At Top Perf = 4 4733.71 2214 2353 21.2 3726 64 12:59:49 Alarm Delta Stage At Top Perf = 6 4820.28 2356 2586 20.7 3625 65 12:59:49 Ball on Seat Dart on Seat 4820.28 2357 2587 20.7 3631 66 12:59:55 Break Formation Break Formation 4822.35 5393 5694 20.6 6431 67 13:02:31 Alarm Delta Stage At Top Perf = 7 4876.06 2534 2724 20.7 3567 68 13:04:26 Alarm Delta Stage At Top Perf = 8 4915.79 2610 2847 20.7 3667 69 13:23:21 Alarm Delta Stage At Top Perf = 9 5307.28 2303 2497 20.7 3447 70 13:30:33 Alarm Delta Stage At Top Perf = 10 5455.54 1920 2166 20.5 3274 71 13:35:29 Alarm Delta Stage At Top Perf = 11 5557.05 1916 2149 20.6 3371 72 13:44:13 Alarm Delta Stage At Top Perf = 12 5736.31 1907 2143 20.5 3398 73 13:53:22 Alarm Delta Stage At Top Perf = 13 5923.95 1893 2122 20.5 3434 74 14:08:19 Alarm Delta Stage At Top Perf = 14 6229.84 1854 2136 20.4 3468 75 14:22:17 Alarm Delta Stage At Top Perf = 15 6514.85 1852 2114 20.4 3491 76 14:32:15 Alarm Delta Stage At Top Perf = 16 6718.29 1896 2152 20.9 3551 77 14:34:53 Drop Ball Drop Drop for Interval 11 6773.41 2258 2443 20.9 3538 11 14:34:54 (07/15/25) Next Treatment Treatment Interval 11 6773.76 2263 2447 20.9 3546 78 14:40:11 Alarm Delta Stage At Top Perf = 17 6884.55 1697 1900 20.9 3070 79 14:40:16 Ball on Seat Dart on Seat 6885.95 1692 1894 21 3047 80 14:40:20 Break Formation Break Formation 6887.69 4054 4274 20.9 5468 81 14:41:55 Alarm Delta Stage At Top Perf = 1 6920.74 2165 2377 20.9 3352 82 14:44:15 Alarm Delta Stage At Top Perf = 2 6969.3 2144 2374 20.8 3318 83 14:48:15 Alarm Delta Stage At Top Perf = 3 7052.53 2152 2381 20.8 3299 84 15:04:36 Alarm Delta Stage At Top Perf = 4 7391.89 2080 2289 20.8 3287 85 15:11:41 Alarm Delta Stage At Top Perf = 5 7538.71 1915 2160 20.6 3251 86 15:16:32 Alarm Delta Stage At Top Perf = 6 7638.91 1837 2088 20.7 3244 87 15:25:19 Alarm Delta Stage At Top Perf = 7 7819.86 1766 2026 20.5 3287 88 15:34:31 Alarm Delta Stage At Top Perf = 8 8008.55 1751 2010 20.5 3322 89 15:49:38 Alarm Delta Stage At Top Perf = 9 8317.61 1755 2022 20.5 3356 90 16:03:37 Alarm Delta Stage At Top Perf = 10 8603.3 1720 1950 20.4 3358 91 16:11:44 Other Pumps Cavitating 8768.23 1672 1951 20.4 3404 92 16:13:46 Alarm Delta Stage At Top Perf = 11 8808.61 1850 2014 19.1 3436 93 16:14:47 Start Flush Start Flush 8829.42 2027 2233 21.2 3441 94 16:20:39 Stop Pumping Stop Pumping 8952.13 1346 1661 20.8 3079 95 16:20:46 ISIP ISIP 8952.13 881 995 0 2757 96 16:25:45 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 8952.13 448 566 0 2736 97 16:30:43 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 8952.13 -14 42 0 2719 98 16:35:50 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 8952.13 23 73 0 2702 Event Log 7.15.25 Conoco Phillips - 3S-703 Event Log 7.15 138 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 05:29:17 (07/16/25) Start Job Starting Job 0 0 0 0 0 1 05:29:17 (07/16/25) Next Treatment Treatment Interval 1 0 0 0 0 0 2 5:30:02 Pre-Job Safety Meeting Pre-Job Safety Meeting 0 1 -1 0 0 12 05:30:59 (07/16/25) Next Treatment Treatment Interval 12 0 1 -1 0 0 3 5:47:22 Other Loop Test 0 0 -1 0 1995 4 6:00:04 Prime Pumps Prime Pumps 0 186 247 0 1993 5 6:09:08 Pressure Test ePRV - Primary Tubing 0 757 791 0 1992 6 6:10:17 Pressure Test ePRV - Primary IA 0 501 559 0 1992 7 6:11:57 Pressure Test ePRV - Secondary Tubing 0 558 642 0 1992 8 6:13:38 Pressure Test ePRV - Secondary IA 0 779 629 0 1991 9 6:15:53 Pressure Test Pressure Test - Global 0 403 433 0 1991 10 6:15:58 Pressure Test Pressure Test - Locals 0 418 461 0 1991 11 6:17:54 Pressure Test Pressure Test - Max 0 9562 9552 0 1991 12 6:22:33 Pressure Test Pressure Test - Pass 0 9479 9448 0 1990 13 6:25:16 Other Bring on Chems and Mix Gel 0 12 14 0 1990 14 7:00:34 Open Well Open Well 0 405 392 0 2027 15 7:00:42 Start Pumping Start Pumping 0 397 391 0 2022 16 7:04:12 Drop Ball Drop Dart for Interval 12 44.39 2071 2195 21 3181 17 7:08:45 Alarm Delta Stage At Top Perf = 4 139.56 1761 1954 20.8 3077 18 7:09:25 Ball on Seat Ball on Seat 153.42 1749 1961 20.7 3025 19 7:09:30 Break Formation Break Formation 155.14 4800 4990 20.6 5934 20 7:11:32 Alarm Delta Stage At Top Perf = 5 197.22 2036 2234 20.7 3145 21 7:13:57 Alarm Delta Stage At Top Perf = 6 247.19 2165 2396 20.6 3296 22 7:32:56 Alarm Delta Stage At Top Perf = 7 639.55 1961 2173 20.7 3159 23 7:40:01 Alarm Delta Stage At Top Perf = 8 785.71 1842 2104 20.6 3178 24 7:44:59 Alarm Delta Stage At Top Perf = 9 887.95 1697 1965 20.6 3189 25 7:53:43 Alarm Delta Stage At Top Perf = 10 1067.37 1647 1917 20.7 3236 26 8:02:44 Alarm Delta Stage At Top Perf = 11 1253.94 1637 1906 20.7 3260 27 8:17:51 Alarm Delta Stage At Top Perf = 12 1566.09 1607 1873 20.6 3275 28 8:31:39 Alarm Delta Stage At Top Perf = 13 1850.35 1606 1902 20.6 3311 29 8:41:33 Alarm Delta Stage At Top Perf = 14 2053.65 1638 1898 20.7 3333 30 8:45:18 Drop Ball Drop Dart for Interval 13 2131.77 2000 2154 21 3342 13 08:45:25 (07/16/25) Next Treatment Treatment Interval 13 2134.22 2008 2167 21 3344 31 8:49:58 Ball on Seat Ball on Seat 2229.75 1508 1715 20.9 2973 32 8:49:59 Alarm Delta Stage At Top Perf = 15 2230.45 1684 1858 20.9 3193 33 8:50:03 Break Formation Break Formation 2231.49 4416 4802 20.8 5834 34 8:51:42 Alarm Delta Stage At Top Perf = 1 2266.13 1631 1846 20.8 2977 35 8:54:23 Alarm Delta Stage At Top Perf = 2 2321.83 1746 1964 20.8 2964 36 8:55:35 Alarm Delta Stage At Top Perf = 3 2346.77 1863 2049 20.8 3078 37 9:14:36 Alarm Delta Stage At Top Perf = 4 2740.72 1795 2004 20.7 3052 38 9:22:35 Alarm Delta Stage At Top Perf = 5 2906.1 1680 1941 20.7 3062 39 9:27:24 Alarm Delta Stage At Top Perf = 6 3005.64 1622 1859 20.7 3093 40 9:36:08 Alarm Delta Stage At Top Perf = 7 3185.65 1570 1821 20.6 3147 41 9:45:21 Alarm Delta Stage At Top Perf = 8 3375.96 1532 1806 20.7 3148 42 9:59:58 Alarm Delta Stage At Top Perf = 9 3678.45 1505 1781 20.6 3157 43 10:13:40 Alarm Delta Stage At Top Perf = 10 3961.04 1492 1778 20.5 3185 44 10:23:33 Alarm Delta Stage At Top Perf = 11 4163.41 1489 1788 20.5 3212 45 10:27:39 Drop Ball Drop Dart for Interval 14 4249.19 1887 2030 21 3218 14 10:27:42 (07/16/25) Next Treatment Treatment Interval 14 4250.24 1896 2053 21 3226 46 10:31:58 Ball on Seat Ball on Seat 4339.95 1495 1707 20.9 2948 47 10:32:08 Other Kicked 2 Pumps Out 4343.23 143 373 14.5 3004 48 10:32:40 Alarm Delta Stage At Top Perf = 12 4349.14 1381 1554 10.7 2942 49 10:35:00 Alarm Delta Stage At Top Perf = 1 4374.28 1408 1588 10.9 2863 50 10:37:55 Alarm Delta Stage At Top Perf = 2 4428.33 1881 2002 21 3213 51 10:38:43 Alarm Delta Stage At Top Perf = 3 4445.15 1887 2009 21 3295 52 10:41:01 Alarm Delta Stage At Top Perf = 4 4493.48 1716 1823 21 3214 53 10:41:17 Other Shut In To Load BU Dart 4496.55 1036 1119 0 2805 54 10:54:54 Drop Ball Drop Back Up Dart for Interval 14 4539.85 2206 2315 21 3708 55 10:58:45 Alarm Delta Stage At Top Perf = 6 4620.61 2224 2434 20.8 3685 56 10:59:27 Ball on Seat Dart on Seat 4635.17 2168 2353 20.8 3544 57 10:59:48 Other No DH indication of Sleeve Shift 4638.21 896 964 0 2706 58 11:04:54 Alarm Delta Stage At Top Perf = 7 4687.05 2702 2837 20.8 4051 59 11:06:28 Alarm Delta Stage At Top Perf = 8 4719.78 2797 2906 20.9 4236 60 11:08:40 Other Shut In To Load 2nd Back Up Dart 4765.76 1326 1427 20.7 3966 61 11:22:34 Drop Ball Drop 3rd Dart for Interval 14 4784.47 2173 2264 15.3 3784 62 11:23:14 Alarm Delta Stage At Top Perf = 9 4794.68 2136 2229 15.3 3744 63 11:28:43 Ball on Seat Dart on Seat 4878.62 2073 2157 15.3 3692 64 11:29:28 Alarm Delta Stage At Top Perf = 11 4890.45 1191 1289 15.5 2791 65 11:31:33 Alarm Delta Stage At Top Perf = 12 4922.53 1208 1310 15.4 2829 66 11:34:29 Other Shut in Well to Analyze 4940.66 852 899 0 2677 67 11:51:43 Open Well Open Well 4940.66 805 854 0 2635 68 11:54:47 Drop Ball Drop Dart for Interval 15 4971.28 1190 1284 15.4 2795 15 11:55:20 (07/16/25) Next Treatment Treatment Interval 15 4979.77 1194 1289 15.4 2808 69 12:00:23 Alarm Delta Stage At Top Perf = 13 5057.45 1200 1292 15.4 2814 70 12:00:24 Ball on Seat Dart on Seat 5057.71 1200 1293 15.4 2811 71 12:00:26 Alarm Delta Stage At Top Perf = 14 5058.22 2815 2438 15.4 3811 72 12:00:31 Break Formation Break Formation 5059.5 3599 3671 15.3 5401 73 12:02:41 Alarm Delta Stage At Top Perf = 1 5096.18 2075 2168 20.9 3572 74 12:07:22 Alarm Delta Stage At Top Perf = 2 5193.82 1880 2095 20.9 3138 75 12:08:55 Alarm Delta Stage At Top Perf = 3 5226.12 1885 2074 20.8 3109 76 12:09:16 Alarm Delta Stage At Top Perf = 4 5233.41 1863 2053 20.8 3093 77 12:26:55 Alarm Delta Stage At Top Perf = 5 5600.74 1640 1857 20.9 2963 78 12:33:57 Alarm Delta Stage At Top Perf = 6 5746.72 1476 1727 20.7 2953 79 12:36:29 Alarm Delta Stage At Top Perf = 7 5799.03 1426 1665 20.6 2960 80 12:40:48 Alarm Delta Stage At Top Perf = 8 5887.94 1346 1606 20.6 2975 81 12:52:41 Alarm Delta Stage At Top Perf = 9 6133.33 1323 1604 20.6 2988 82 13:07:30 Alarm Delta Stage At Top Perf = 10 6438.53 1273 1570 20.6 2996 83 13:21:24 Alarm Delta Stage At Top Perf = 11 6723.6 1333 1639 20.4 3027 84 13:31:27 Alarm Delta Stage At Top Perf = 12 6928.52 1346 1669 20.3 3045 85 13:37:29 Drop Ball Drop Dart for Interval 16 7054.2 1738 1864 21.1 3040 16 13:37:32 (07/16/25) Next Treatment Treatment Interval 16 7054.9 1740 1879 21.1 3055 86 13:41:23 Alarm Delta Stage At Top Perf = 13 7124.61 1287 1360 15.5 2888 87 13:42:09 Ball on Seat Dart on Seat 7136.22 1239 1330 15.4 2843 88 13:42:15 Break Formation Break Formation 7137.76 3732 3866 15.3 5641 89 13:43:51 Alarm Delta Stage At Top Perf = 1 7163.73 1809 2056 20.5 3296 90 13:46:51 Alarm Delta Stage At Top Perf = 2 7226.15 1727 1962 20.8 2965 91 13:48:41 Alarm Delta Stage At Top Perf = 3 7264.32 1732 1980 20.8 2988 92 13:57:33 Alarm Delta Stage At Top Perf = 4 7448.74 1587 1799 20.8 2903 93 14:04:33 Alarm Delta Stage At Top Perf = 5 7594.1 1397 1648 20.8 2887 94 14:07:05 Alarm Delta Stage At Top Perf = 6 7646.62 1350 1615 20.6 2899 95 14:11:27 Alarm Delta Stage At Top Perf = 7 7736.54 1231 1512 20.6 2900 96 14:23:36 Alarm Delta Stage At Top Perf = 8 7986.39 1134 1404 20.6 2847 97 14:38:38 Alarm Delta Stage At Top Perf = 9 8295.12 1111 1375 20.5 2867 98 14:52:47 Alarm Delta Stage At Top Perf = 10 8584.7 1112 1404 20.5 2885 99 15:02:45 Alarm Delta Stage At Top Perf = 11 8788.4 1138 1411 20.4 2916 100 15:09:58 ISIP ISIP 8938.66 881 977 0 2752 101 15:14:57 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 8938.66 55 76 0 2734 102 15:20:01 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 8938.66 -19 25 0 2723 103 15:24:58 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 8938.66 18 62 0 2714 104 16:24:37 End Job Ending Job 8938.66 -3803 7 0 2710 Event Log 7.16.25 Conoco Phillips - 3S-703 Event Log 7.16 139 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Test #1Test #2Test #3Test #4time (hr:min) -->00:00 01:00 02:00 03:00 04:00 05:00 10:00 15:00 20:00 25:00 30:00 45:00 1:00 1:15 1:30 1:45 2:00 2:15 2:30 2:45 3:00 3:30 4:00 4:30 5:00 5:30 6:00 6:30Test #1 (cp) -->2716 1358 1358 1111 1308 1333 1506 1580 1333 1259 1308 1037 667 543 296 247 99 74 49 0 0 0 0 0 0 0 0 0Dial Reading110555545535461645451534227221210 4 3 2Test #2 (cp) -->0000000000000000000000000000Dial ReadingTest #3 (cp) -->0000000000000000000000000000Dial ReadingTest #4 (cp) -->0000000000000000000000000000Dial Reading95 8.89 1.00 25.00 0.12 0.45 2.00 1.00 0.50 SeawaterTemp 0F PH LOSURF-300D WG-36 MO-67 BC-140X2 OptiFlo-II CAT-3 Cla-WebD. MartinezHydration Visc: 19 88Temperature was held at 115 degres for the duration of the testAll chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:3S-703 Stage(s): Break Test105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/6/2025ConocoPhillips Project No:05001000150020002500300000:00 02:00 04:00 10:00 20:00 30:00 1:00 1:30 2:00 2:30 3:00 4:00 5:00 6:00Viscosity (cp)Time (min:sec)Prejob Crosslink Break Tests25# - Opti II @ 2.0 and CAT-3 @ 1.0Fluid is broken at 200cpConoco Phillips - 3S-703Prejob Break Test - 105 F140 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 1105 Water Source: 1JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/13/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3684 8.60 1.00 0.45 1.00 0.60 2.00 0.50 27050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Fann 15-min Test Zone 1141 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 2105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/13/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3688 8.76 1.00 0.45 1.00 0.60 2.00 0.50 2705001000150020002500300000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 2 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 2142 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 3105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/13/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3695 8.56 1.00 0.45 1.00 0.60 2.00 0.50 270500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 3 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 3143 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 4105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/14/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3694 8.89 1.00 0.45 1.00 0.60 2.00 0.50 27050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 4 Crosslink Tests.50 ppg0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 4 144 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 5105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/14/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3690 8.70 1.00 0.45 1.00 0.45 2.00 0.50 270500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 5 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 5145 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 6105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/14/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3687 8.82 1.00 0.45 1.00 0.60 2.00 0.50 2705001000150020002500300035004000450000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 6 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 6146 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 7105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/14/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3688 8.71 1.00 0.45 1.00 0.70 2.00 0.50 27050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 7 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 7 147 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 8105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/15/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3693 8.80 1.00 0.45 1.00 0.50 2.00 0.50 270500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 8 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 8148 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 9105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/15/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3693 8.76 1.00 0.45 1.00 0.50 2.00 0.50 270500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 9 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 9149 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 10105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/15/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3696 8.64 1.00 0.45 1.00 0.70 2.00 0.50 270500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 10 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 10150 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 11105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/15/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3699 8.68 1.00 0.45 1.00 0.60 2.00 0.50 27050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 11 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 11151 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 12105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/16/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3689 8.77 1.00 0.45 1.00 0.50 2.00 0.50 27050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 12 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 12152 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 13105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/16/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3690 8.77 1.00 0.45 1.00 0.50 2.00 0.50 2705001000150020002500300035004000450000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 13 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 13153 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 15105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/16/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3690 8.77 1.00 0.45 1.00 0.60 2.00 0.50 270500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 15 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 15154 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-703 Stage(s): 16105 Water Source: 3JALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/16/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT3 MO-67 Optiflo-II ClaWeb WG-3687 8.80 1.00 0.45 1.00 0.60 2.00 0.50 27050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 16 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-703Zone 16155 Company: Well: Sand Type Date Tested Total Sample Size Seive Weight Seive Weight 100.0 g Sieve Size Before Sand With sand WT. rtn'd % rtn'd % API Spec 12 355.0 355 0 0.0% 0.00% <0.1% 16 340.1 343 2.9 2.9% 18 303.3 396.8 93.5 93.5% 20 296.5 298.9 2.4 2.4% 25 419.4 419.7 0.3 0.3% 30 281.5 281.7 0.2 0.2% 40 407.6 407.9 0.3 0.3% Pan 306.6 306.7 0.1 0.1% 0.10% <1.0% Total: 99.7 100% Conoco Phillips 3S-703 16/20 Proppant 7/6/2025 Ceramic Proppant Sieves Sample: 16 / 20 - 7/6/2025 96.40% >/= 90% Conoco Phillips - 3S-703 Sand Sieve Analysis 156 Originated: Delivered to:31-Jul-25Alaska Oil & Gas Conservation Commiss31Jul25-NRATTN: Meredith Guhl333 W. 7th Ave., Suite 100 600 E 57th Place Anchorage, Alaska 99501-3539Anchorage, AK 99518(907) 273-1700 main (907)273-4760 faxWELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTIONDATA TYPE DATE LOGGED3S-703 50-029237-61-00-00 223-056 Kuparuk River WL TTiX-HSD FINAL FIELD 8-Jul-253T-731 50-103209-05-00-00 224-156 Kuparuk River WL TTiX FSI & SCMT FINAL FIELD 12-Jul-253T-603 50-103208-87-00-00 224-074 Kuparuk River WL Caliper & Perforation FINAL FIELD 14-Jul-253S-606 50-103208-70-00-00 223-111 Kuparuk River WL TTiX- IPROF FINAL FIELD 21-Jul-25Transmittal Receipt________________________________X__________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.Nraasch@slb.comSLB Auditor - TRANSMITTAL DATETRANSMITTAL #A Delivery Receipt signature confirms that a package (box, envelope, etc.) has been received. The package will be handled/delivered per standard company reception procedures. The package's contents have not been verified but should be assumed to contain the above noted media.# Schlumberger-Private225-035T40727T40728T40729T407303S-70350-029237-61-00-0025-035Kuparuk RiverWLTTiX-HSDFINAL FIELD8-Jul-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.08.01 08:56:13 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: Coyote Coyote 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13420 Casing Collapse Structural Conductor Surface 2474 Production 4789 Production 7870 Production 9210 Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 4206 13420 4206 1484 3S-703 Completions Engineer Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 CO 819 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): 5173' MD / 4116' TVD Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL380107 / ADL380106 KRU 225-035 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20913-00-00 ConocoPhillips Alaska Inc. Length Size Proposed Pools: L-80 TVD Burst 5315 10860 MD 6885 5209 120 2542 4023 120 2727 41457-5/8" 20" 10-3/4" 80 7-5/8"4866 2727 5322 Perforation Depth MD (ft): 4866 456 4-1/2" 7/6/2025 134098087 4-1/2" 4206 HES TNT Production Packer m n P s 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:06 am, Jul 08, 2025 Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.07.04 11:49:40-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard 325-404 This sundry updates the chemical disclosure. VTL 7/8/2025 All conditions of approval on approved fracture stimulation sundry(325-379) apply. A.Dewhurst 08JUL25 7/6/2025 10-404 CDW 07/08/2025 DSR-7/8/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.08 12:24:52 -08'00'07/08/25 RBDMS JSB 070925 Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-06-14 Alaska HARRISON BAY 50-103-20913-00-00 CONOCOPHILLIPS 3S 703 -150.19509417 70.39429476 NAD83 none Oil 4206 1306841.35 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone 2% KCL WATER Operator Base Fluid Density = 8.34 Produced Water (Density 8.5)Operator Base Fluid Density = 8.50 SEAWATER (SG 8.52)Operator Base Fluid Density = 8.52 BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator CL-28M CROSSLINKER Halliburton Crosslinker CLA-WEB(TM) Halliburton Clay Stabilizer LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Calcium Chloride Customer Salt Solution Flow Insurance Brass Patina Energy Tracer Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%66.51786%11087429 Corundum 1302-74-5 60.00%17.27826%2880000 Mullite 1302-93-8 40.00%11.51884%1920000 Sodium chloride 7647-14-5 5.00%3.50094%583549 Crystalline silica, quartz 14808-60-7 100.00%0.29050%48422 Water 7732-18-5 100.00%0.25017%41700 Guar gum 9000-30-0 100.00%0.21870%36453 Water 7732-18-5 100.00%0.21090%35155 Calcium Chloride 10043-52-4 100.00%0.05999%10000 EDTA/Copper chelate Proprietary 30.00%0.04053%6756 Denise Tuck, Halliburton, 3000 N. Sam Houston Pkwy E., Houston, TX 77032, 281-871- 6226 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ethanol 64-17-5 60.00%0.03693%6156 Monoethanolamine borate 26038-87-9 100.00%0.03371%5619 Water 7732-18-5 100.00%0.02550%4250 Ammonium salt Proprietary 60.00%0.02207%3679 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01847%3078 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01847%3078 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ammonium persulfate 7727-54-0 100.00%0.01620%2700 Sodium hydroxide 1310-73-2 30.00%0.01170%1951 Ethylene glycol 107-21-1 30.00%0.01011%1686 Ammonium chloride 12125-02-9 5.00%0.00675%1126 Oxyalkylated phenolic resin Proprietary 10.00%0.00616%1026 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Potassium chloride 7447-40-7 2.00%0.00500%834 Oxylated phenolic resin Proprietary 30.00%0.00486%810 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Flow Insurance Brass Proprietary 100.00%0.00381%636 Patina Energy Product Stewardship test@patinae nergy.com 7205324886 Borate salts Proprietary 60.00%0.00381%636 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00308%513 Naphthalene 91-20-3 5.00%0.00308%513 Walnut hulls NA 100.00%0.00300%500 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Flow Insurance Copper Proprietary 100.00%0.00291%486 Patina Energy Product Stewardship test@patinae nergy.com 6692416025 Ammonia 7664-41-7 1.00%0.00135%226 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00122%203 Production Type: True Vertical Depth (TVD): Total Water Volume (gal)*: MSDS and Non-MSDS Ingredients are listed below the green line Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Fracture Date State: County: API Number: Operator Name: Polyamine Proprietary 30.00%0.00090%150 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Sodium chloride 7647-14-5 1.00%0.00076%127 Glycol Ether Proprietary 85.00%0.00065%109 ResMetrics Product Stewardship info@resmetr ics.com 8325921900 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00062%103 Ammonium acetate 631-61-8 100.00%0.00055%92 Potassium chloride 7447-40-7 5.00%0.00032%53 Inorganic mineral 1317-65-3 5.00%0.00032%53 Confidential Proprietary 20.00%0.00023%39 ResMetrics Product Stewardship info@resmetr ics.com 8325921900 Acetic acid 64-19-7 30.00%0.00017%28 C.I. pigment Orange 5 3468-63-1 1.00%0.00016%27 Ethylene Glycol 107-21-1 20.00%0.00016%27 Hemicellulase 9025-56-3 5.00%0.00015%25 Polymer Proprietary 1.00%0.00006%11 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Calcium magnesium carbonate 16389-88-1 1.00%0.00006%11 Gluteraldehyde 111-30-8 1.00%0.00006%11 Inorganic mineral Proprietary 1.00%0.00006%11 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Amine salts Proprietary 0.10%0.00004%7 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Quaternary amine Proprietary 0.10%0.00004%7 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%6 Cured acrylic resin Proprietary 1.00%0.00003%5 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00003%5 Sodium bisulfate 7681-38-1 0.10%0.00001%2 Methanesulfonic acid, 1-hydroxy-, sodium salt 870-72-4 0.10%0.00001%2 2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00000%1 5-Chloro-2-methyl-3(2H)- Isothaiazolone 26172-55-4 0.01%0.00000%1 Magensium chloride 7786-30-3 0.01%0.00000%1 Magnesium nitrate 10377-60-3 0.01%0.00000%1 * Total Water Volume sources may include fresh water, produced water, and/or recycled water _ ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.5 All component information listed was obtained from the supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-IIOPTIFLO-HTE BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In2:19:29 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:19:29 1-3 Shut-In Shut-In2:14:43 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 2:14:43 1.00 2.00 0.50 27.00 2.00 0.151-5 27# Linear DFIT 10 1,680 40 40 0:04:00 2:08:43 1.00 2.00 0.50 27.00 2.00 0.151-6 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 2:04:43 1.00 2.00 0.50 27.00 2.00 0.151-7 Shut-In Shut-In1:51:23 1-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.151-9 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.151-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.151-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.151-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.151-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.152-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:25:00 1.00 2.00 0.50 27.00 2.00 0.152-2 27# Delta Frac Minifrac - Establish Fluid 20 8,400 200 200 0:10:00 2:22:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.152-3 27# Delta Frac Minifrac - Treatment 20 12,415 296 296 0:14:47 2:12:30 0.45 1.0000 0.50 2.00 0.50 27.00 2.00 0.152-4 27# Linear Flush 20 8,125 193 193 0:09:40 1:57:44 1.00 2.00 0.50 27.00 2.00 0.152-5 Shut-In Shut-In1:48:03 2-6 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.152-7 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.152-8 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.152-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.152-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.152-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.152-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.152-16 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.153-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:04:06 1.00 2.00 0.50 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 2:01:36 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:51:36 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:32:02 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:24:44 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:19:44 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:10:43 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:01:19 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:46:05 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:31:57 0.45 1.00 0.50 2.00 0.50 27.00 2.000.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:21:52 0.45 1.00 0.50 2.00 0.50 27.00 2.000.153-12 27# Linear Flush 20 7,802 186 186 0:09:17 0:15:17 1.00 2.00 0.50 27.00 2.00 0.153-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 3-14 Shut-In Shut-InInterval 1Coyote@ 13275.89 - 13279.89 ft - °FInterval 2Coyote@ 12711.31 - 12715.31 ft - °FInterval 3Coyote@ 12205.54 - 12209.54 ft - °FLiquid AdditivesDry Additives50-103-20913Conoco Phillips - 3S-703Planned Design1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-IIOPTIFLO-HTE BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-209134-1 Shut-In Shut-In2:15:04 4-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:15:04 4-3 Shut-In Shut-In2:10:18 4-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 2:10:18 1.00 2.00 0.50 27.00 2.00 0.154-5 27# Linear Displace Dart to Seat 15 7,509 179 179 0:11:55 2:08:18 1.00 2.00 0.50 27.00 2.00 0.154-6 27# Linear DFIT 10 2,100 50 50 0:05:00 1:56:23 1.00 2.00 0.50 27.00 2.00 0.154-7 Shut-In Shut-In1:51:23 4-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.154-9 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.154-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.154-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.154-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.154-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.154-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.154-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.0000 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.154-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.154-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.155-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 2.00 0.50 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.155-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.156-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 2.00 0.50 27.00 2.00 0.156-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.156-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.156-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.157-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:02:34 1.00 2.00 0.50 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 2:00:04 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:50:04 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:30:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.0000 20 3,850 92 100 7,700 0:05:00 1:23:12 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:18:12 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:09:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:59:47 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:44:33 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:30:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:20:21 0.45 1.00 0.50 2.00 0.50 27.00 2.000.157-12 27# Linear Flush 20 6,517 155 155 0:07:46 0:13:46 1.00 2.00 0.50 27.00 2.00 0.157-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 7-14 Shut-In Shut-InInterval 4Coyote@ 11746.86 - 11750.86 ft - °FInterval 5Coyote@ 11198.38 - 11202.38 ft - °FInterval 6Coyote@ 10695.48 - 10699.48 ft - °FInterval 7Coyote@ 10195.85 - 10199.85 ft - °FConoco Phillips - 3S-703Planned Design2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-IIOPTIFLO-HTE BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-209138-1 Shut-In Shut-In2:13:02 8-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:13:02 8-3 Shut-In Shut-In2:08:16 8-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 2:08:16 1.00 2.00 0.50 27.00 2.00 0.158-5 27# Linear Displace Dart to Seat 15 6,224 148 148 0:09:53 2:06:16 1.00 2.00 0.50 27.00 2.00 0.158-6 27# Linear DFIT 10 2,100 50 50 0:05:00 1:56:23 1.00 2.00 0.50 27.00 2.00 0.158-7 Shut-In Shut-In1:51:23 8-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.158-9 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.158-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.158-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.158-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.158-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.158-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.158-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.158-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.158-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.159-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 2.00 0.50 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.159-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.1510-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 2.00 0.50 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1510-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1510-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.1511-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:01:02 1.00 2.00 0.50 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:58:32 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1511-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:48:32 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:28:59 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:21:40 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:16:40 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:07:40 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:58:16 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:43:02 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:28:54 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:18:49 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1511-12 27# Linear Flush 20 5,237 125 125 0:06:14 0:12:14 1.00 2.00 0.50 27.00 2.00 0.1511-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 11-14 Shut-In Shut-InInterval 9Coyote@ 9197.51 - 9201.51 ft - °FInterval 10Coyote@ 8698.18 - 8702.18 ft - °FInterval 11Coyote@ 8192.39 - 8196.39 ft - °FInterval 8Coyote@ 9737.14 - 9741.14 ft - °FConoco Phillips - 3S-703Planned Design3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-IIOPTIFLO-HTE BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2091312-1 Shut-In Shut-In2:11:00 12-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:11:00 12-3 Shut-In Shut-In2:06:14 12-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 2:06:14 1.00 2.00 0.50 27.00 2.00 0.1512-5 27# Linear Displace Dart to Seat 15 4,943 118 118 0:07:51 2:04:14 1.00 2.00 0.50 27.00 2.00 0.1512-6 27# Linear DFIT 10 2,100 50 50 0:05:00 1:56:23 1.00 2.00 0.50 27.00 2.00 0.1512-7 Shut-In Shut-In1:51:23 12-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:23 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1512-9 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1512-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1512-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1512-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1512-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1512-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1512-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1512-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1512-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.1513-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 2.00 0.50 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1513-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1513-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1513-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1513-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1513-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1513-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1513-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1513-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1513-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:33 1.00 2.00 0.50 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:48:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1514-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:38:03 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1514-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:18:30 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:11:11 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:06:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:57:11 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:47 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:33 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:25 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:20 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1514-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 0.50 27.00 2.00 0.1515-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:59:31 1.00 2.00 0.50 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:57:01 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1515-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:47:01 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1515-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:27:27 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:20:09 0.45 1.00 0.50 2.00 0.50 27.00 2.00 0.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:15:09 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:06:08 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:56:44 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:41:30 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:27:22 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:17:18 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1515-12 27# Linear Flush 20 3,957 94 94 0:04:43 0:10:43 1.00 2.00 0.50 27.00 2.00 0.1515-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 15-14 Shut-In Shut-InInterval 12Coyote@ 7733.6 - 7737.6 ft - °FInterval 13Coyote@ 7191.9 - 7195.9 ft - °FInterval 14Coyote@ 6689.2 - 6693.2 ft - °FInterval 15Coyote@ 6190.67 - 6194.67 ft - °FConoco Phillips - 3S-703Planned Design4 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39429477LEASE3S-703SALES ORDERBHST (°F)LONG-150.1950942FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-IIOPTIFLO-HTE BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2091316-1 Shut-In Shut-In2:17:30 16-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:17:30 16-3 Shut-In Shut-In2:12:45 16-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 2:12:45 1.00 2.00 0.50 27.00 2.000.1516-5 27# Linear Displace Dart to Seat 15 3,637 87 87 0:05:46 2:10:45 1.00 2.00 0.50 27.00 2.000.1516-6 27# Linear DFIT 10 2,100 50 50 0:05:00 2:04:58 1.00 2.00 0.50 27.00 2.000.1516-7 Shut-In Shut-In1:59:58 16-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:59:58 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-9 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:46:38 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:27:05 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:19:46 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:14:46 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:05:46 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:56:22 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:41:08 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:26:59 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:16:55 0.45 1.00 0.50 2.00 0.50 27.00 2.000.1516-18 27# Linear Flush 20 3,637 87 87 0:04:20 0:10:20 1.00 2.00 0.50 27.00 2.000.1516-19 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 16-20 Shut-In Shut-In1,361,433 32,415 37,564 4,848,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-II OPTIFLO-HTE BE-61,228,4954,800,000(gal) (gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)121,63848,000Initial Design Material Volume 552.8 1,350.1 614.2 2,700.3 675.1 36,453.6 2,700.3 202.5-11,300- 0.2836 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 Cla-Web WG-36 OPTIFLO-II OPTIFLO-HTE BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 0.4 0.8 0.4 1.7 0.4 22.7 1.7 1.7 0.1-Min Additive Rate8:51:39 Interval 16Coyote@ 5690.56 - 5694.56 ft - °FProppant TypeWanli 16/20 Ceramic100M---Fluid Type27# Delta Frac27# LinearSeawaterFreeze Protect----Conoco Phillips - 3S-703Planned Design5 From:Woodard, Madeline E To:Loepp, Victoria T (OGC) Cc:Wallace, Chris D (OGC); Lee, David L; Hobbs, Greg S Subject:RE: [EXTERNAL]RE: 3S-703 Sundry 325-379 Date:Monday, July 7, 2025 4:48:52 PM Victoria & Chris, I am just curious if this was approved by a Commissioner today? We have not received communication if it was. Thanks, Madeline From: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> Sent: Friday, July 4, 2025 1:36 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Lee, David L <David.L.Lee@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: Re: [EXTERNAL]RE: 3S-703 Sundry 325-379 Hi Victoria, Sorry I was just writing a note back to Chris. We can wait until Monday to get Commissioner approval. Thanks, Madeline From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Friday, July 4, 2025 1:28:37 PM To: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: Re: [EXTERNAL]RE: 3S-703 Sundry 325-379 Madeline, Is a verbal approval needed this weekend? Victoria Sent from my iPhone On Jul 4, 2025, at 11:55ௗAM, Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> wrote: Chris & Victoria, Please see the 3S-703 10-403 application to change the approved program for 3S-703 sundry 325-379. The application includes a new chemical disclosure with HES product Cla-Web and new pump schedule showing the concentration we will pump during the stimulation. I think this fits the needs of what was outlined below for an approved sundry. HES said that they have submitted the CAS information previously to AOGCC for this product. Please let us know if you do not have it and we will coordinate with HES for that information to be mailed in by Denise Tuck. Thanks, Madeline From: Woodard, Madeline E Sent: Thursday, July 3, 2025 2:17 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]RE: 3S-705 Chris, Thanks for the information. We are working two options for clay inhibition and have decided to get testing completed over the next couple of days to get that sorted. We will submit a new chemical disclosure and pump schedule dependent on the best option for our fluid formulation once the testing is complete. Thanks, Madeline From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, July 3, 2025 8:57 AM To: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> Subject: [EXTERNAL]RE: 3S-705 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, A new chemical disclosure could include your new clay inhibitor, and we would just replace/insert that into the 10-403. If the sundry is already approved, we would review your submission, review your management of change process and any other 10-403 changes eg, volumes page, etc, procedure steps and if we can we would either approve via email/verbal to document AOGCC’s approval of the changes. If the inhibitor has been previously used on fracs in Alaska we probably have the Chemical Abstract Number (CAS) information. If it is a new chemical and potentially proprietary, CPAI/Halliburton should review our regulations and proceed accordingly. We also would like access to the safety data sheet / materials safety data sheet (either generic off internet, or if a proprietary development chemical – confidential submission for our files in case of emergency etc as per OSHA/DOT requirements). AOGCC regulations require a full chemical disclosure (all the components of the fluids/solids entering the formation during the frac) in the 10-403 as per 20 AAC 25.283(a)(12) (C) chemical ingredient name of, and the Chemical Abstracts Service (CAS) registry number assigned to, each base fluid and additive to be used; the actual or maximum concentration of each chemical ingredient in each base fluid and additive used must be provided in percent by mass; the actual or maximum concentration of each chemical ingredient in the hydraulic fracturing fluid must be provided in percent by mass; freeze-protect fluids pumped before or after hydraulic fracturing may not be included; If CPAI/Halliburton wants to claim proprietary/confidentiality, AOGCC has the process as established by regulation to accommodate this as per 20 AAC 25.283(k) Any information required to be filed under this section that the filing party believes to be a confidential trade secret shall be separately filed in an envelope clearly marked "confidential" along with a list of the documents that the party believes to be wholly or partially nondisclosable as trade secrets, and the specific legal authority and specific facts supporting nondisclosure. The commission will review the information, and will maintain it as confidential. If the commission receives a request under AS 40.25.100 - 40.25.295 (Alaska Public Records Act) for disclosure of the information, the commission will promptly forward the request to the party claiming confidentiality. Not later than five business days after receiving the request, the party claiming confidentiality shall file with the commission an affidavit verifying that the documents remain wholly or partially confidential, identifying any portions of the document that are not confidential, and setting out the specific facts and legal authority supporting nondisclosure. After reviewing the affidavit, in accordance with and within the time allowed to respond under 2 AAC 96.325, the commission will determine whether to provide the party making the public records request the requested documents or the list of nondisclosable documents, the specific legal authority and facts supporting nondisclosure, and the affidavit provided by the party claiming confidentiality. The commission will notify the party claiming confidentiality if an appeal is requested under AS 40.25.123(e) and 2 AAC 96.340, or if judicial relief is sought under AS 40.25.124 or 40.25.125. (l) Upon written request of the operator, the 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. commission may modify a deadline in this section upon a showing of good cause, approve a variance from any other requirement of this section if the variance provides at least an equally effective means of complying with the requirement, or approve a waiver of a requirement of this section if the waiver will not promote waste, is based on sound engineering and geoscience principles, will not jeopardize the ultimate recovery of hydrocarbons, will not jeopardize correlative rights, and will not result in an increased risk to health, safety, or the environment, including freshwater. We have worked through this proprietary chemical disclosure information previously with Halliburton (Denise Tuck) and other providers and I can assist them directly if required. We can provide an example/format of the required information we have determined satisfies a proprietary claim which is similar to Federal and other states requirements. As part of our due diligence, AOGCC will review the CAS numbers provided in the chemical disclosure to ensure the frac chemicals are not in conflict with EPA guidance on the prohibition of diesel fuel fracs. EPA guidance labels diesel fuel fracs as containing CAS numbers: 68334-30-5 Diesel Fuel 68476-34-6 Diesel Fuel No. 2 68476-30-2 Fuel Oil No. 2 68476-31-3 Fuel Oil No. 4 8008-20-6 Kerosene Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793- 1250 or chris.wallace@alaska.gov. From: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Sent: Thursday, July 3, 2025 8:28 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> Subject: 3S-705 Victoria and Chris, I tried calling you earlier today to enquire about the possibility of adding a chemical to our frac fluids cocktail. When we tested the water quality this morning, the water analysis showed we have very low salinity levels, most likely because the sea water we collected was actually water that melted from snow. The low salinity brings the situation of interacting with the swelling clays located in the reservoir; and we wanted to enquire if AOGCC would be in agreement to allow ConocoPhillip to add a clay stabilizer to the frac fluids as this was not captured in the chemical disclosure. Going around with Halliburton, came to our attention that we don't have any clay inhibitors on the slope, and we don't have any compatibility testing with current frac fluids, therefore it was decided to carry on with the job without any additional additive. However, in the meantime we will be performing compatibility tests so that we could pump in 3S-703 if the water quality continues to show to be "fresh". Could you please provide us some guidance on what you would require from us to get it amended to the chemical disclosure already submitted for 3S-703? Thanks in advance for your help! Rodrigo Ruysschaert | Completions Engineer | ConocoPhillips O: + 1 907-263-3709| M: +1 907 621 0671 | 700 G Street, ATO-1554, Anchorage, AK 99501 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: Coyote Coyote 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13420 Casing Collapse Structural Conductor Surface 2474 Production 4789 Production 7870 Production 9210 Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7/4/2025 134098087 4-1/2" 4206 HES TNT Production Packer 5322 Perforation Depth MD (ft): 4866 456 4-1/2" 41457-5/8" 20" 10-3/4" 80 7-5/8"4866 2727 MD 6885 5209 120 2542 4023 120 2727 Length Size Proposed Pools: L-80 TVD Burst 5315 10860 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL380107 / ADL380106 KRU 225-035 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20913-00-00 ConocoPhillips Alaska Inc. AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): 5173' MD / 4116' TVD Perforation Depth TVD (ft): 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 4206 13420 4206 1484 3S-703 Completions Engineer Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 CO 819 m n P s 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:28 pm, Jun 24, 2025 Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.06.23 16:32:07-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard SFD 7/1/2025 7/4/2025 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test tubing PRV, IA PRV, and pump trips to the set pressures detailed in the section 7 table. 5173' MD JJL 6/27/25 3S-723 and 3S-16 to be monitored during 3S-703 frac. 325-379 Fracture Stimulate CDW 06/30/2025 10-404 DSR-6/30/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.01 15:28:53 -08'00'07/01/25 RBDMS JSB 070225 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). June 11, 2025 VIA E-MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3S-703 Well ADL 380107 & ADL 380106 Kuparuk River Unit, Alaska CPAI Contract No. 203828 Pursuant to 20 AAC 25.283, ConocoPhillips Alaska, Inc. (“CPAI”) as Operator of the Kuparuk River Unit, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing in accordance with 20 AAC 25.280 (“Application”) for the 3S- 703 Well (the “Well”). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about June 11, 2025. The Well is currently planned to be drilled as a directional horizontal well on lease ADL 380107 and ADL 380106 as depicted on Exhibit 1, and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 2,484’ 841’ T12N R8E 18 Umiat Top Open Interval 1,335’ 2,794’ T12N R8E 18 Umiat Bottomhole 3,820’ 3,956’ T12N R8E 6 Umiat Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well (“Notification Area”), which includes the reservoir section. Exhibit 2 is a list of the names and addresses of all owners, landowners, surface owners, and operators of record at the time of this Application for all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, Ryan C. King, CPL Staff Land Negotiator Attachments: Exhibits 1 & 2 Ryan C. King, CPL Staff Land Negotiator Land & Business Development P.O. Box 100630 Anchorage, AK 99510-0360 Office: 907-265-6106 Fax: 907-263-4966 ryan.c.king@cop.com BCC: Madeline Woodard Brian Buck Jason C. Parker John Evans Patrick Perfetta Exhibit 1 Exhibit 2 List of the names and addresses of all owners, landowners, surface owners, and operators of record of all properties within the Notification Area. Operator & Owner: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO-1480 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attn: GKA Asset Development Manager Owner (Non-Operator): ConocoPhillips Alaska, Inc. II ExxonMobil Alaska Production Inc. 700 G Street, Suite ATO 1226 PO Box 196601 Anchorage, Alaska 99510 Anchorage, AK 99519 Attn: GKA Asset Development Manager Attn: Todd Griffith Landowners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Surface Owner: State of Alaska AKFF 085283 – Gertrude Ahsogeak (Deceased) Department of Natural Resources Bureau of Indian Affairs Division of Oil and Gas 3601 C Street, Suite 1258 550 West 7th Avenue, Suite 1100 Anchorage, AK 99503 Anchorage, AK 99501 Attention: Derek Nottingham, Director Section 2 – Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer KUP KRU KUPARUK RIVER UNIT 501032043200 3S-09 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP KRU KUPARUK RIVER UNIT 501032044500 3S-16 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032073500 3S-613 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water Yes Yes KUP COYOTE COYOTE 501032084701 3S-701A ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032086400 3S-617 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032087000 3S-606 ACTIVE Injector Produced Water Yes Yes KUP COYOTE COYOTE 501032088600 3S-722 ACTIVE Injector Produced Water Yes Yes KUP KRU KUPARUK RIVER UNIT 501032043000 3S-07 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032069500 3S-620 ACTIVE Oil Yes Yes KUP KRU KUPARUK RIVER UNIT 501032045003 3S-08C ACTIVE Oil Yes Yes KUP KRU KUPARUK RIVER UNIT 501032045060 3S-08CL1 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032090300 3S-714 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032090600 3S-602 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032091000 3S-723 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032091100 3S-721 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032084800 3S-704 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032086800 3S-624 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087800 3S-626 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032088400 3S-718 ACTIVE Oil Yes Yes KUP KRU KUPARUK RIVER UNIT 501032036100 PALM 1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032036101 3S-26 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032043300 3S-18 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032043900 3S-14 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044000 3S-10 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044400 3S-15 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044600 3S-22 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044800 3S-17 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044801 3S-17A PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045000 3S-08 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045001 3S-08A PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045002 3S-08B PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045070 3S-08CL1PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045200 3S-21 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045300 3S-23 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045400 3S-06 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045401 3S-06A PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045600 3S-24 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045601 3S-24A PA Plugged and Abandoned Yes - P&A Yes - P&A KUP COYOTE COYOTE 501032045602 3S-24B PA Plugged and Abandoned Yes - P&A Yes - P&A KUP COYOTE COYOTE 501032084700 3S-701 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032077470 3S-611PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045301 3S-23A SUSP Suspended Yes - Suspended Yes - Suspended KUP KRU KUPARUK RIVER UNIT 501032045800 3S-03 SUSP Suspended Yes - Suspended Yes - Suspended KUP KRU KUPARUK RIVER UNIT 501032046000 3S-19 SUSP Suspended Yes - Suspended Yes - Suspended SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), “That portions of the aquifers on the North Slope described by a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field”. SECTION 4 – PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283(a)(4) There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5 – DETAILED CEMENTING AND CASING INFORMATION 20 AAC 25.283(a)(5) See Wellbore schematic for casing and cement details. 5173 ft MD packer CDW 06/30/2025 SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: The 10-3/4” casing cement pump report on 5/18/2025 shows that the original job pumped as designed. The cement job was pumped with 466 barrels of 11.0 ppg lead cement and 58 barrels 15.8 ppg tail cement, displaced with 9.5 ppg mud. The plug bumped at 1750 psi, but unable to hold pressure. No total cement returns were reported, but 120bbls was reported back to surface mid-job. The 7-5/8” x 4-1/2” casing cement report on 5/29/2025 shows that the job was pumped with 137 barrels of 11.0ppg lead cement and 502 bbls of 15.3ppg tail cement. The cement was displaced with 9.5ppg CI brine. The plug bumped and pressure was held at 1500 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. 26bbls of fluid was lost during the job. A cement bond log indicated the cement top at 2,720’ MD / 2,537’ TVD / 2,472’ TVDSS (2357’ MD / 1556’ TVD above the Coyote). Summary All casing is cemented in accordance with 20 AAC 25.030. SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 5/19/2025 the 10-3/4” casing was pressure tested to 3,700 psi for 30 minutes On 5/30/2025 the 7-5/8” x 4-1/2” tapered casing was pressure tested to 4,000 psi for 30 minutes. On 6/1/2025 the 4-1/2” tubing was pressure tested to 4,550 psi for 30 minutes. On 6/1/2025 the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes. The 4-1/2” tubing will be pressure tested to 4,200 psi for 30 minutes and the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes post-rig. 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 4,200 SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2,474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 P-110S 11,590 9,210 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the gross Coyote interval, has an average thickness greater than 400 ft TVD over the course of the lateral section of well 3S-703, from where it intersects the top formation at 5,077’ MD to TD of the well. At the heel of the well it has a gross thickness of ~580’ thinning to ~225’ at the toe of the well. The Coyote interval is comprised of thinly interbedded sandstone and siltstone layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and are of the size range from silt to very fine sand. The estimated fracture pressure for the Coyote interval is approximately 12.9-16.1 ppg based on FIT/LOT data. 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 ~220’ TVT in the vicinity of the 3S-703 wellbore. The top of the confining intervals starts at ~3,812’ TVDSS (4,541’ MD). It should be noted that slope to basin shales and siltstones are present from the top of the Seabee formation to the surface casing shoe at 2,737’ MD. This interval acts as a continuation of the upper confining interval. Currently, there is limited data of the fracture gradient of the overlying Seabee formation, however, further data collection is planned. CPAI has completed a LOT in the overlying confining interval at 3,944’ TVDSS to 14.0ppg (0.728 psi/ft). CPAI also 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 and the leak off point of 0.73 psi/ft, per the figure below. Based on our dynamic fracture modeling, the fracture could propagate into the overlying interval, which was observed in the 3S-24B vertical well. The log results from the 3S-24B showed 34’ of potential fracture growth into the overburden compared to the ~220’ of TVT of the overlying zone. Additionally, geomechanical testing completed on the overburden core proved there is no remaining conductivity within a fracture that propagates into the overlying zone due to proppant embedment and interaction of the frac fluid with the rock. Post-frac injection will be at or below the fracture closure pressure (Pc) of the overlying seal which is less than the fracture propagation pressure (FPP). We have also lowered the lateral landing depth for the horizontal wells based on thickness of the gross package to be deeper than the perforation in the 3S-24B vertical well. The lower confining interval of the Coyote comprises slope to basin floor mudstones of the Torok formation, which are present in thicknesses of ~670’ TVT in the vicinity of the 3S-703 wellbore. This same confining zone forms the upper confining interval of the Kuparuk River Unit, Torok Oil Pool. The estimated fracture gradient for this section ranges from 15-18 ppg. The base of the gross Coyote interval is estimated from seismic to be at ~4,606 ft TVDSS at the heel, and ~4,280’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1,675 – 1,780 psi at a depth of 4,028’ 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 the following assessments for each well’s mechanical condition, seismic, 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 are listed in the AOR submitted with this sundry application. A summary of the condition of each well is listed below: 3S-03: This well has been plugged and abandoned per state regulations with AOGCC witness of cement at surface for all strings and marker plate in place as of 3/31/2025. Perforate, wash, and cement operations were performed with a CBL completed to show good cement through the interval of 5,130’ MD to 4,980’ MD (3963’ - 3,857’ TVDSS). A CIBP was placed at 5,157’ MD and 63bbls of cement pumped across perforations. Cement was tagged with slickline at 4,714’ MD and pressure tested to 1,500 psi, witnessed by AOGCC. A second CIBP was set inside the casing at 5,130’ CTMD and 80bbls of 15.8ppg Class G cement was pumped. TOC was tagged at 3,027’ MD with slickline and an MIT performed to 1,700 psi, both witnessed by AOGCC. A final cement plug of 142bbls of 15.8ppg Class G cement was pumped from 3,021’ MD to surface. The OA was abandoned with 108 bbls of 15.8 ppg Permafrost Cement. 3S-06/-06A: This well was plugged and abandoned with final abandonment completed in 2023. The 3S-06 wellbore was abandoned in 2003 with an abandonment plug set from 8,907’-8,451’ MD. A kick off plug was then set at 7,315’-6,700’ MD and the 3S-06A wellbore was kicked off at 6,580’ MD after tagging the kick off plug at 6,497’ MD/4,582’ TVD/4,525’ TVDSS. For the final abandonment, a cement retainer was set at 7,932’ MD via coil tubing and 27 bbls of cement was pumped below the retainer and 1 bbl on top of the retainer. Cement was tagged at 7,933’ SLMD and a passing MIT-T was performed and witnessed by AOGCC on 8/12/2022. The tubing was then cut at 7,841’ MD and the tubing pulled out of hole. A bridge plug was set at 5,750’ MD in the 7” casing and the 7” casing was perforated from 5,720-5,570’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,459’ MD in the 7” casing and a MIT to 1,700 psi, witnessed by AOGCC on 11/24/2022. Multiple attempts to clean out cement to the bottom perforation were made, but coil kept tagging up on fill after clean out was completed. Due to continued issues with fill across the original perforations, 8.7bbls of 15.8ppg cement was placed at 5,738’ CTMD. Cement was milled down to 5,540’ MD.E-line then came in and perforated the 7” casing again from 5,540’-5,390’ MD and cemented with 73bbls of 15.8ppg Class G cement. The TOC was tagged at 5,215’ SLMD and a MIT-T completed at 1,660 psi, witnessed by AOGCC on 9/6/2023. TOC was determined in the annulus at 5,390’ MD / 3,943’ TVD / 3,887’ TVDSS via log. The top cement job was performed on 9/30/2023 with 231 bbls of 15.8ppg cement from 5,570’ CTMD to surface. The 7” x 9-5/8” OA was cemented via down squeeze with 108bbls of 15.8ppg Permafrost cement (surface to 9-5/8” shoe) on 11/5/2022.The final abandonment was completed on 10/16/2023, witnessed by AOGCC. 3S-14: This well was recently plugged and abandoned with final abandonment completed in 2024. A cement retainer was set at 6,234’ MD via coil tubing and 32 bbls of cement was pumped below the retainer and 1 bbl on top of the retainer. Cement was tagged at 6,082’ MD and a passing MIT-T was performed and witnessed by AOGCC on 5/16/2023. The tubing was then cut at 6,092’ MD and the tubing pulled out of hole. A bridge plug was set at 4,653’ MD in the 7” casing and the 7” casing was perforated from 4,627-4,477’ MD. Coil was utilized to perf wash and cement with 71bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 4,293’ SLMD in the 7” casing. TOC was determined in the annulus at 4,561’ MD / 4,090’ TVD / 4,035’ TVDSS via log. Coil was used to pump 40 bbls of 15.8ppg cement in the 7” casing from 4,590’ to 3,546’ MD. The TOC was tagged at 3,514’ MD and a MIT-T performed to 1,720 psi, witnessed by AOGCC on 12/26/2023. The top cement job was performed on 12/29/2023 with 160 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface from 3,463’ CTMD. The 7” x 9-5/8” OA was cemented via down squeeze with 104bbls of 15.8ppg KRU 3S-14 (202-221): Uppermost Coyote is isolated, remainder is not. Closest approach to 3S-703 is 1900' E of horizontal section within Coyote. Separation distance and location will preclude interference with fracturing fluids in 3S-703. SFD KRU 3S-06 (203-057) and KRU 3S-06A (203-088): Uppermost Coyote is isolated, remainder is not. Closest approach to 3S-703 is 1900' E of horizontal section within Coyote. Separation distance and location will preclude interference with fracturing fluids . SFD KRU 3S-03 (203-091): Closest approach to 3S-703 is about 3,000' S at the top of Coyote. Separation distance and location will preclude interference with fracturing fluids. SFD Permafrost cement followed by 52bbls of 15.8ppg cement (surface to 9-5/8” shoe) on 9/15/2023.The final abandonment was completed on 1/18/2024, witnessed by AOGCC. 3S-15: This wellbore was P&A’d in 2020. A cement retainer was set at 7,790’ MD via coil tubing and 25.6 bbls of cement was pumped below the retainer and 1 bbl on top of the retainer to isolate the original zone of interest (Kuparuk C sand). Cement was tagged at 7,749’ MD’ MD and a passing MIT-T was performed and witnessed by AOGCC on 6/18/2020. The tubing was then punched from 7,692’-7,696’ MD and 294 bbls of 15.8ppg Class G cement was circulated down the tubing and up the IA. A cement top off was completed for the tubing, IA, and OA, 8 bbls of Portland Type I/II Class G 15.6ppg cement was pumped down the OA, 0.2bbls Portland Type I/II Class G 15.6ppg cement was pumped down the IA, and 0.2 bbls of Portland Type I/II Class G 15.6ppg cement was pumped down the tubing. The 9-5/8” x 7” OA was abandoned with 120bbls of 15.8ppg Permafrost cement from the surface to the surface shoe depth of 3,561’ MD. The excavation and final abandonment was completed on 9/10/2020, witnessed by AOGCC. 3S-16: The 7" intermediate casing (5,907’ MD / 5,839’ TVD) cement report on 2/3/2003 shows that the job was pumped as designed with 38 bbls of 15.8ppg Class G cement. The cement was displaced with 11.8 ppg mud at 7bpm. Plugs bumped and pressure was held at 1,160 psi, floats held, and full returns were observed through the job. The Coyote is not currently isolated on 3S-16. The 3S-703 well path is oriented along the measured maximum horizontal stress to create longitudinal fractures along the wellbore. Although there is potential the fracture deviates from longitudinal due to uncertainty in the orientation of the maximum horizontal stress, ConocoPhillips thinks the risk of loss of containment of frac fluids to the 3S-16 wellbores is low. The 3S-16 OA will be monitored during the stimulation of 3S-703. If any changes in OA pressure outside of the recent trends are observed, 3S-703 will go to flush immediately. 3S-17/17A: 3S-17 was originally drilled in 2003 and the main wellbore was abandoned on 4/28/2003 with two plugs. One plug was set from 8,906’-8,561’ MD with 33bbls of 15.8ppg class G cement and the other was set from 6,771’-6200’ MD and was tagged at 6,120’ MD/4,250’ TVDSS with the kick off BHA for the 3S-17A wellbore. Plug and Abandonment operations on 3S-17 and 3S-17A (sidetrack from 3S-17 on 4/29/2003), began on 7/30/2022 and were completed 9/25/2023. A cement retainer was set at 8,333’ MD via coil tubing and 27 bbls of cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 8,324’ SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 8/13/2022. The tubing was then cut at 8,273’ MD and the tubing pulled out of hole. A bridge plug was set at 5,883’ MD in the 7” casing and the 7” casing was perforated from 5,707’-5,857’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,513’ SLMD in the 7” casing and a MIT-T performed to 1500 psi, witnessed by AOGCC. TOC was determined in the annulus at 5,707’ MD / 4,022’ TVD / 3,965’ TVDSS via log. Coil was used to pump 22 bbls of 15.8ppg cement in the 7” casing. The TOC was tagged at 5,273’ MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC. The top cement job was performed on 9/5/2023 with 223 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface. The 7” x 9-5/8” OA was cemented via down squeeze with 115bbls of 15.8ppg Permafrost cement (surface to 9-5/8” shoe) on 5/18/2023.The final abandonment was completed on 9/25/23, witnessed by AOGCC. 3S-18: 3S-18 was originally drilled in 2002 targeting the Kuparuk. This well was recently plugged and abandoned with final abandonment completed in 2024. A cement retainer was set at 6,566’ MD via coil tubing and 19 bbls of cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 6,316’ MD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 5/12/2023. The tubing was then cut at 6,283’ MD and the tubing pulled out of hole. A bridge plug was set at 4,737’ MD in the 7” casing and the 7” casing was perforated from 4,711-4,561’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 4,377’ SLMD in the 7” casing. TOC was determined in the annulus at 4,561’ MD / 4,000’ TVD / 3,944’ TVDSS via log. Coil was used to pump 40 bbls of 15.8ppg cement in the 7” casing from 4,736’ to 3,686’ CTMD. The TOC was tagged at 3,655’ SLMD and a MIT-T performed to 1,700 psi, witnessed by AOGCC on 2/4/2024. The top cement job was performed on 2/9/2024 with 158 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface from 3,678’ CTMD. The 7” x 9- 5/8” OA was cemented via down squeeze with 104bbls of 15.8ppg Permafrost cement (surface to 9-5/8” shoe) on 9/20/2023.The final abandonment was completed on 3/31/2024, witnessed by AOGCC. KRU 3S-17 & 17A (PTD 203-015; 203-080) P&A: Patchy cement across Coyote. Closest approach to 3S-703 is 1300' to W. Separation distance and location preclude interference.SFD of top Coyote intercept. Separation distance and location will likely preclude interference with fracturing fluids. SFD KRU 3S-18 (202-206) P&A: Only the uppermost 50’ of Coyote is isolated, remainder is not isolated. Closest approach is 550' SW of top Coyote intercept in 3S-703. Location will preclude interference with fracturing fluids in 3S-703. SFD Closest approach to 3S-703 is 110' W at 315 degrees azimuth to the Stage 13 sleeve in the horizontal section within Coyote reservoir. Induced fractures are expected to parallel the 3S-703 well bore, which has an azimuth of about 355 degrees, so separation distance and location will likely preclude interference with frac fluids. CPAI will monitor all stages closely during operations and if communication is indicated, go to flush immediately. SFD KRU 3S-15 (PTD 202-254): Plugged and Abandoned. Coyote does not appear to be covered by cement. , The 3S-16 OA p will be monitored during the stimulation of 3S-703. If any changes in OA pressure outside of the recent trends g are observed, 3S-703 will go to flush immediately. KRU 3S-16 (203-007): Coyote not isolated. Closest approach to 3S-703 is 1870' SE 3S-22: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-22, commencing operations on 5/1/2023 and completing the Plug and Abandonment on 3/25/24. Original drilling did not cover the zone of interest. A CBL was run prior to the P&A showing the original cement height at 6255' MD. A cement retainer was set at 7,690’ MD via coil tubing and 32 bbls of 15.8ppg cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 7,418’ SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 5/12/2023. The tubing was then cut at 7,420’ MD and the tubing pulled out of hole. A CIBP was set at 5,467’ MD in the 7” casing and the 7” casing was perforated from 5,291’-5,441’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,107’ SLMD in the 7” casing and TOC was determined in the annulus at 5,291’ MD / 4,018’ TVD / 3,960’ TVDSS via log. Coil was used to pump 38 bbls of 15.8ppg cement in the 7” casing. The TOC was tagged at 4,445’ MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC. The top cement job was performed on 2/28/2024 with 193 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface. The final abandonment was completed on 3/25/24, witnessed by AOGCC. 3S-602: The 7-5/8” casing cement report on 03/08/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 104 barrels of 14.0 ppg lead cement, followed with 31 barrels of 15.3 ppg tail cement. This was displaced with 322 barrels of 9.5 ppg BaraECD NAF. The plugs bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 4,500 MD (3,610’ TVD/3,542’ TVDSS), which is 497’ TVD above the Coyote. 3S-606: The 7-5/8” casing cement report on 2/11/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 111 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 29 barrels of 15.3 ppg without BMII. The plugs bumped, pressure increased to 1500 psi and held for 5 minutes. A cement bond log indicates competent cement with a cement top @ 3,950 MD (3,164’ TVD/3,098’ TVDSS), which is 938’ TVD above the Coyote. 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 bump, pressure held at 1140 psi indicating that floats are competent. A cement bond log indicates competent cement with a cement top @ 3,549 MD (3,156’ TVD / 3,092’ TVDSS), which is 932’ TVD above the Coyote. 3S-617: The 7-5/8” casing cement report on 11/5/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 142 barrels of 15.3 ppg. The plug was not bumped. Pressure was being monitored and no pressure built up indicating that the floats held. A cement bond log indicates competent cement with a cement top @ 3,841’ MD (3,157’ TVD/3,092’ TVDSS), which is 934’ TVD above the Coyote. 3S-624: The 7-5/8” casing cement report on 12/24/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 125 barrels of 15.3ppg primary cement with LCM and 22 barrels of 15.3ppg primary cement without LCM. The plug was bumped and the floats held. A cement bond log indicates competent cement with a cement top @ 3,435’ MD (2,778’ TVD/2,715’ TVDSS), which is 1,315’ TVD above the Coyote. 3S-626: The 7-5/8” casing cement report on 06/01/2024 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped in two stages utilizing a stage tool. The first stage cement job had 188 bbls of 15.3 ppg cement. Plug bumped and floats held. The second stage cement job had 42 bbls of 15.3 ppg cement. Plug bumped and all indications are the stage tool at 6807’ MD closed. A cement bond log run on 06/03/24 indicates competent cement with cement top at 5,908’ MD/3,775’ TVD/3,711’ TVDSS. Due to issues with the freeze protect of the OA, a RWO was performed. The 7-5/8" fish was successfully recovered down to the original cut made with Doyon 142 at 2020 ft MD. A new 7-5/8” casing with a sealing is isolated by cement. Closest approach to 3S-703 is 2050' SW of top Coyote intercept. Separation distance and location preclude interference with frac fluids. SFD KRU 3S-610 (223-126): Coyote isolated by cement. Closest approach to 3S-703 is 650' W of top Coyote intercept. Isolation precludes interference. SFD KRU 3S-22 (203-011): P&A: Only the uppermost portion of the Coyote KRU 3S-624 (223-104): Coyote isolated by cement. Closest approach to 3S-703 is 300' W of top Coyote intercept. Isolation precludes interference. SFD KRU 3S-617 (223-085): Coyote isolated by cement. Closest approach to 3S-703 is 620' W of top Coyote intercept. Isolation precludes interference. SFD KRU 3S-606 (223-111): Coyote isolated by cement. Closest approach to 3S-703 is 620' E of top Coyote intercept. Isolation precludes interference. SFD KRU 3S-602 (225-003): Coyote isolated by cement. Closest approach to 3S-703 is 2050' SW of top Coyote intercept. Isolation precludes interference. SFD overshot and cementer was installed, and cement was pumped through the cementer to the surface. The 7-5/8" packoff was then installed and tested to 3840 psi, confirming its integrity. 3S-705: The 7-5/8” x 4-1/2” casing cement report on 6/18/2025 shows that the job was pumped with 115 barrels of 11.0ppg lead cement and 516 bbls of 15.3ppg tail cement. The cement was displaced with 9.5ppg CI brine. The plug bumped and pressure was held at 1500 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. 20bbls of fluid was lost during the job. A cement bond log indicated the cement top at 2,730’ MD / 2,573’ TVD / 2,508’ TVDSS (2862’ MD / 1514’ TVD above the Coyote). 3S-714: The 7-5/8" Casing cement report on 2/7/2025 shows that the job was pumped as designed with 57bbls of 15.3ppg cement. Plugs bumped and pressured up to 1902psi and held. Floats checked and were holding. A cement bond log indicates competent cement with a cement top @ 5530’ MD (3765’ TVD/3,702’ TVDSS), which is 327’ TVD above the Coyote. 3S-723: The 7-5/8” x 4-1/2” casing cement report on 4/12/2025 shows that the job was pumped as designed. The cement job was pumped with 669 BBLs of 15.3 ppg cement with 1 ppb Cemnet after 1st 50 BBLs of cement. During the cement displacement, flow out was observed to be decreasing. Plugs bumped and floats held, but a total of 70bbls of fluid was lost during the job. A cement bond log indicates competent cement with a cement top @ 5056' MD / 4061' TVD with partially bonded cement up to 4,800’ MD. The 5056’ MD / 4061’ TVD top of cement is 116’ MD / 39’ TVD above the Coyote. This well is currently being flowed back. The DHG of this well will be monitored during the stimulation of 3S-703. If any pressure anomalies are observed on the 3S-723 DHG, the 3S-703 stimulation will be flushed immediately. Palm 1: Three abandonment plugs were placed on 2/21/2001. The three plugs were set as balanced plugs at the following depths: 5,900’-6,620' MD MD with 2755sx of 15.8ppg Class G cement, 5,880'-5,200’ MD with 275sx of 15.8ppg Class G cement, and 4,700'-4,100' MD (3900’ TVDSS) of 250sx of 15.8ppg Class G Cement. The middle abandonment plug was tagged with 20klbs at 5,247' MD/4827 TVDSS, witnessed by AOGCC. A kick off plug was then set at 3,100'-2,660' MD with 300sx (50bbls) of 17.2ppg Class G cement. The kick off plug was tagged at 2,553’ MD/2492’ TVDSS (1546’ TVD above the Coyote). p The DHG of this well will beyyg monitored during the stimulation of 3S-703. If any pressure anomaliesf are observed on the 3S-723 DHG, the g 3S-703 stimulation will be flushed immediately. KRU 3S-26 fka PALM 1 (201-005): Uppermost Coyote is isolated, remainder is not. Closest approach is about 1,400' SE of top Coyote intercept. Separation distance and location will preclude interference with fracturing fluids in 3S-703. SFD KRU 3S-705 (PTD 225-047) Coyote is isolated by cement. Closest approach to 3S-703 is 1365' SW of top Coyote intercept. Isolation precludes interference. SFD KRU 3S-723 (225-016): Coyote interval cement job wasn't great but it is likely sufficient. Closest approach to 3S-703 is 750' SW of top Coyote intercept. Cement, separation distance and direction will likely preclude interference. SFD KRU 3S-626 (224-0070): Closest approach to 3S-703 is 2275' W of horizontal section within Coyote. Separation distance and location preclude interference with frac fluids. SFD KRU 3S-714 (224-151): Coyote isolated by cement. Closest approach to 3S-703 is 1670' SW of top Coyote intercept. Isolation precludes interference. SFD 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-703 wellbore trajectory. This fault is west of the toe of the 3S-703 wellbore. This fault is a west - east striking feature. It is questionable as to whether it is an actual fault at the top Coyote level. If it exists, it has minimal throw at the top Coyote (5 to 10 feet). It has maximum potential offset of ~65’ in the Seabee section ~370’ above the Coyote. It loses throw both upward and downward from this point to near zero at the Coyote level and upward to no throw within in the slope deposits of the upper Seabee formation ~650’ above top Coyote. As this fault is interpreted to lose throw into the confining interval above the Coyote reservoir. it 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-703 was completed in 2025 as a horizontal producer in the Coyote formation. The well was completed with a 4.5” tubing upper completion and a 7-5/8” x 4-1/2” tapered casing string with dart actuated sliding sleeves in the lateral. Injection will be established into the well and the first stage treated. A dart will be dropped for stage 2 to initiate treatment. Once each stage is complete, a dart will be dropped for each subsequent stage. These darts will provide isolation from the previous stage and allow fracturing from the toe of the well towards the heel. Proposed Procedure: Halliburton Pumping Services: 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre- existing conditions. 2. Ensure the frac tree was tested to 10,000 psi on the rig. 3. Ensure all pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to ~2,000’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100ºF seawater. 6. MIRU HES Frac Equipment. 7. PT Surface lines to 10,000 psi using a pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Bring up pumps and increase annulus pressure to 3,500 psi as the tubing pressures up. 10. Pump the frac job per the attached Halliburton pump schedule at 20-22 bpm with a maximum expected treating pressure of 7,075 psi. 11. RDMO Halliburton Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. The well is ready for post-frac well prep/production tree installation and flowback (after Slickline and Coiled Tubing Cleanout). Originated: Delivered to:6-Jun-25Alaska Oil & Gas Conservation Commiss06Jun25-NR , <)*(*$''' 8:)* 81&) :)*%$+ +*#6 1$!>> ''>+*#6 1>> ;A>:C:' :/A>:C:' .:=EWELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3T-730 501-03-20907-00-00 225-010 Kuparuk River WL TTiX HSD FINAL FIELD 27-May-253S-703 501-03-20913-00-00 225-035 Kuparuk River WL TTiX-IBC-CBL FINAL FIELD 31-May-253T-603 501-03-20887-00-00 224-074 Kuparuk River WL TTiX FSI FINAL FIELD 20-May-25Transmittal ReceiptFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFF 4FFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFF%)/ &6) ) Please return via courier or sign/scan and email a copy to Schlumberger.!+*G!$28+#/&7<)# TRANSMITTAL DATETRANSMITTAL # $ B + )!6) +#=/!)*)+6 A2#E1 $# 1 )+8C*!2 + <8 * +6 0$$2 *<$ << $ < !)<<+#/B + )##+ < !8 * +6 H!+#) )!* #)2 = <2)!*#$<2 !!/ <)#+#))* 2# #) </ <8D&+*$/2 6 %) T40532T40533T405343S-703501-03-20913-00-00225-035Kuparuk RiverWLTTiX-IBC-CBLFINAL FIELD31-May-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.06.06 13:07:43 -08'00' T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA Jun 05, 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-703 Kuparuk River API #: 50-103-20913-00-00 Permit No: 225-035 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 AKGGREDTSupport@ConocoPhillips.onmicrosoft.com Luis G Arismendi Luis.arismendi@bakerhughes.com 225-035 T40530 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.05 09:29:50 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3S-703 JBR 07/21/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 7 5/8", 5" and 4.5" test joints used for testing. 22 charge bottles with 1000 psi on each. Test Results TEST DATA Rig Rep:C. Bali/J. FetterlyOperator:ConocoPhillips Alaska, Inc.Operator Rep:R. Reinhardt/P. Angelle Rig Owner/Rig No.:Doyon 25 PTD#:2250350 DATE:5/19/2025 Type Operation:DRILL Annular: 250/2500Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopGDC250520103632 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6 MASP: 1484 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.NA 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 P #1 Rams 1 7 5/8" Solids P #2 Rams 1 Blinds 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 P2000 200 PSI Attained P12 Full Pressure Attained P88 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1841 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P23 #1 Rams P5 #2 Rams P5 #3 Rams P5 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 9 9 9 9 9999 9 9 7HVWFKDUWVHTXHQFHDWWDFKHGMEU %23(7HVW'R\RQ .58637' $2*&&,QVS5SWERS*'& #01&5FTU%PZPO ,36415% "0($$*OTQ3QUCPQ(%$ 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-703 Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-035 Surface Location: 2468 FNL, 852' FEL, S18 T12N R8E, UM Bottomhole Location: 1487 FSL, 779' FWL, S6 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, Jessie L. Chmielowski Commissioner DATED this 9th day of May 2025. . Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.09 14:20:57 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 13,438' TVD: 4,206' 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): 65 15. Distance to Nearest Well Open Surface: x- 476408 y- 5993947 Zone- 4 25.5 to Same Pool: 1614' to 3S-714 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 94# H40 Welded 92 40 40 92 92 13-1/2" 10-3/4" 45.5# L80 H563 2654 40 40 2694 2525 9-7/8" x 8-3/4" 7-5/8" 29.7# L80 H563 4480 40 40 4520 3880 9-7/8" x 8-3/4" 7-5/8" 33.7# P110-S H563 800 4520 3880 5320 4151 8-3/4" 4-1/2" 12.6# P110-S H563 8104 5320 4151 13438 4206 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: Trevor Kelley Authorized Name: David Lee on behalf of Chris Brillon Contact Email: Trevor.Kelley@cop.com Authorized Title: Wells Engineering Manager Contact Phone:281-513-6789 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng KRU 3S-703 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 1460 FNL, 2018' FWL, S18 T12N R8E, UM 1487 FSL, 779' FWL, S6 T12N R8E, UM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 18. Casing Program:Top - Setting Depth - BottomSpecifications 1899 Kuparuk River Field Coyote Oil Pool 5/21/2025 762' to ADL025528 P.O. Box 100360 Anchorage, Alaska, 99510-0360 ConocoPhillips Alaska Inc 2468 FNL, 852' FEL, S18 T12N R8E, UM ADL380107 / ADL380106 59-52-180 Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): (including stage data) Cement to surface with 4 yds slurry 1123 sx if 11.0 ppg DeepCRETE + 272 sx of 15.8 ppg Class G 342 sx of 11.0 ppg CRETE + 2042 sx of 15.3 ppg Class G Casing Cement Volume MDSize Authorized Signature: Production Liner Intermediate 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Effect. Depth MD (ft): Conductor/Structural Length Effect. Depth TVD (ft): 2448 / 2437 1484 Stratigraphic Test No Mud log req'd: Yes No No Directional svy req'd: Yes No Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Single Well Gas Hydrates No Inclination-only svy req'd: Yes No Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal No No Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 4:09 pm, May 01, 2025 4:09 pm, May 01, 2025 SFD 1484 Variance of the diverter requirement under 20AAC 25.035(h)(2) is granted. SFD DSR-5/1/25 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 Review results of cement evaluation logs with AOGCC as soon as available SFD 5/07/2025 225-035 5/12/2025 50-103-20913-00-00 X VTL 5/9/2025 ($8 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.09 14:21:09 -08'00' 05/09/25 05/09/25 RBDMS JSB 051425 <Zhϯ^ͲϳϬϯ Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. .58'66 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage , Alaska 99510-0360 Telephone 907-276-1215 May 1, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3S-703 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Producer well from the 3S drilling pad. The intended spud date for this well is May 14, 2025. It is intended that Doyon 25 be used to drill the well. 3S-703 will utilize a 13-1/2"” surface hole drilled to TD and 10-3/4" casing will be set and cemented to surface. The 9 7/8” hole will be drilled to ~5320’ MD, where the underreamer will be closed and the 8-3/4" horizontal section will be drilled and geosteered in the Coyote formation. A 7 5/8” x 4 ½” tapered casing string will be set and cemented from TD to secure the production casing and cover a 500’ or 250’ TVD above any hydrocarbon-bearing zones (Coyote) per AOGCC regulations. The well will be completed as a cemented, fracture stimulated producer with 7 5/8” x 4 1/2” casing with frac sleeves and fiber optic cable. The 4 ½” upper completion will include a production packer with GLM’s and a downhole guage tied back to surface. A variance is requested for a BOPE test interval of 21 days for this project. Doyon 25 is a strong participant in the CPAI BOPE between well maintenance program, reflected by low failure rates in BOP tests since its entry into the CPAI fleet. The variance allows effective drilling and completion of problematic zones, or longer intervals during the well construction. It is also requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well 3S-703. At 3S , there has not been a significant indication of shallow gas hydrates to date, through the surface hole interval. 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 Trevor Kelley at 281-513-6789 (Trevor.Kelley@cop.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3S-703 Well File / Jenna Taylor ATO 1804 Will Earhart ATO 1552 Trevor Kelley Chris Brillon ATO 1548 Drilling Engineer Pat Perfetta ATO-06-662 Recommend granting requesed variance. 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WKK,ĂŶĚůĂLJĚŽǁŶĚƌŝůůŝŶŐ,͘ ϭϯ͘ ZƵŶƚĂƉĞƌĞĚϳϱͬϴ͟džϰͲϭͬϮ͟ĐĂƐŝŶŐǁŝƚŚĨŝďĞƌŽƉƚŝĐĐĂďůĞĂŶĚĐĞŵĞŶƚƚŽĂŵŝŶŝŵƵŵŽĨϮϱϬ͛dsŽƌϱϬϬ͛DĂďŽǀĞĂŶLJ ŚLJĚƌŽĐĂƌďŽŶďĞĂƌŝŶŐnjŽŶĞƐ;ĐĞŵĞŶƚŝŶŐƐĐŚĞŵĂƚŝĐĂƚƚĂĐŚĞĚͿ͘WƌĞƐƐƵƌĞƚĞƐƚĐĂƐŝŶŐ͕ŝĨƉŽƐƐŝďůĞ͕ŽŶƉůƵŐďƵŵƉƚŽϰϬϬϬƉƐŝ͘ ϭϰ͘ ZhǁŝƌĞůŝŶĞĂŶĚůŽŐdK͘/ĨĐĂƐŝŶŐǁĂƐŶŽƚƉƌĞƐƐƵƌĞƚĞƐƚĞĚŽŶƉůƵŐďƵŵƉ͕ƉƌĞƐƐƵƌĞƚĞƐƚƚŽϰϬϬϬƉƐŝ͘ ϭϱ͘ ZhƚŽƌƵŶƵƉƉĞƌĐŽŵƉůĞƚŝŽŶ͘ ϭϲ͘ ZƵŶϰͲϭͬϮ͟ƵƉƉĞƌĐŽŵƉůĞƚŝŽŶǁŝƚŚŐůĂƐƐƉůƵŐ͕ƉƌŽĚƵĐƚŝŽŶƉĂĐŬĞƌ͕ĚŽǁŶŚŽůĞŐĂƵŐĞ͕ĂŶĚŐĂƐůŝĨƚŵĂŶĚƌĞůƐ͘^ƉĂĐĞŽƵƚĂŶĚ ůĂŶĚƚƵďŝŶŐŚĂŶŐĞƌ͘ ϭϳ͘ WƌĞƐƐƵƌĞƚĞƐƚŚĂŶŐĞƌƐĞĂůƐƚŽϱ͕ϬϬϬƉƐŝ͘ ϭϴ͘ WƌĞƐƐƵƌĞƚĞƐƚĂŐĂŝŶƐƚƚŚĞŐůĂƐƐƉůƵŐƚŽƐĞƚƉƌŽĚƵĐƚŝŽŶƉĂĐŬĞƌ͕ƚĞƐƚƚƵďŝŶŐƚŽϰ͕ϱϱϬƉƐŝ͕ĐŚĂƌƚƚĞƐƚ͘ ϭϵ͘ ůĞĞĚƚƵďŝŶŐƉƌĞƐƐƵƌĞƚŽϮϮϬϬƉƐŝĂŶĚƚĞƐƚ/ƚŽϯ͕ϴϱϬƉƐŝ͕ĐŚĂƌƚƚĞƐƚ͘ ϮϬ͘ /ŶƐƚĂůů,WͲWsĂŶĚƚĞƐƚƚŽϭϱϬϬƉƐŝ͘ Ϯϭ͘ EŝƉƉůĞĚŽǁŶKW͘ ϮϮ͘ /ŶƐƚĂůůƚƵďŝŶŐŚĞĂĚĂĚĂƉƚĞƌĂƐƐĞŵďůLJ͘EͬhƚƌĞĞĂŶĚƚĞƐƚƚŽϭϬ͕ϬϬϬƉƐŝͬϭϬŵŝŶƵƚĞƐ͘ Ϯϯ͘ &ƌĞĞnjĞƉƌŽƚĞĐƚĚŽǁŶƚƵďŝŶŐĂŶĚĂŶŶƵůƵƐ͘ Ϯϰ͘ ^ĞĐƵƌĞǁĞůů͘ZŝŐĚŽǁŶĂŶĚŵŽǀĞŽƵƚ͘ WůĞĂƐĞŶŽƚĞʹdŚŝƐǁĞůůǁŝůůďĞĨƌĂĐ͛Ě <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϱͬϭͬϮϬϮϱ <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϱͮϭϭ ϰ͘ KWĂŶĚŝǀĞƌƚĞƌ/ŶĨŽƌŵĂƚŝŽŶ ZĞƋƵŝƌĞŵĞŶƚƐŽĨϮϬϮϱ͘ϬϬϱ;ĐͿ;ϯΘϳͿ WůĞĂƐĞƌĞĨĞƌĞŶĐĞKWĂŶĚĚŝǀĞƌƚĞƌƐĐŚĞŵĂƚŝĐƐŽŶĨŝůĞĨŽƌŽLJŽŶϮϱ /ƚŝƐƌĞƋƵĞƐƚĞĚƚŚĂƚĂǀĂƌŝĂŶĐĞŽĨƚŚĞĚŝǀĞƌƚĞƌƌĞƋƵŝƌĞŵĞŶƚƵŶĚĞƌϮϬϮϱ͘Ϭϯϱ;ŚͿ;ϮͿŝƐŐƌĂŶƚĞĚ͘ƚϯ^͕ ƚŚĞƌĞŚĂƐŶŽƚďĞĞŶƐŝŐŶŝĨŝĐĂŶƚŝŶĚŝĐĂƚŝŽŶŽĨƐŚĂůůŽǁŐĂƐŽƌŐĂƐ ŚLJĚƌĂƚĞƐƚŚƌŽƵŐŚƚŚĞƐƵƌĨĂĐĞŚŽůĞŝŶƚĞƌǀĂů͘ dŚĞƌĞĂƌĞϴƉƌĞǀŝŽƵƐůLJĚƌŝůůĞĚǁĞůůƐ;ϯ^Ͳϭϰ͕ϯ^ͲϲϬϲ͕ϯ^ͲϲϭϬ͕ϯ^Ͳϲϭϭ͕ϯ^ͲϲϭϮ͕ϯ^Ͳϲϭϳ͕ϯ^ͲϲϮϰ͕ϯ^ͲϳϮϯͿǁŝƚŚŝŶ ϱϬϬ͛ŽĨƚŚĞƉƌŽƉŽƐĞĚ<Zhϯ^ͲϳϬϯƐƵƌĨĂĐĞƐŚŽĞůŽĐĂƚŝŽŶ͘EŽŶĞŽĨƚŚĞƐĞǁĞůůƐĞŶĐŽƵŶƚĞƌĞĚĂŶLJƐŝŐŶŝĨŝĐĂŶƚ ŝŶĚŝĐĂƚŝŽŶŽĨƐŚĂůůŽǁŐĂƐŽƌŐĂƐŚLJĚƌĂƚĞƐ͘ ϱ͘ D^WĂůĐƵůĂƚŝŽŶƐ ZĞƋƵŝƌĞŵĞŶƚƐŽĨϮϬϮϱ͘ϬϬϱ;ĐͿ;ϰͿ ;ͿŵĂdžŝŵƵŵĚŽǁŶŚŽůĞƉƌĞƐƐƵƌĞĂŶĚŵĂdžŝŵƵŵƉŽƚĞŶƚŝĂůƐƵƌĨĂĐĞƉƌĞƐƐƵƌĞ͖ DĂdžŝŵƵŵWŽƚĞŶƚŝĂů^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ;DW^WͿŝƐĚĞƚĞƌŵŝŶĞĚĂƐƚŚĞůĞƐƐĞƌŽĨ͗ DĞƚŚŽĚϭ͗ƐƵƌĨĂĐĞƉƌĞƐƐƵƌĞĂƚďƌĞĂŬĚŽǁŶŽĨƚŚĞĨŽƌŵĂƚŝŽŶĐĂƐŝŶŐƐĞĂƚǁŝƚŚĂŐĂƐŐƌĂĚŝĞŶƚƚŽƚŚĞƐƵƌĨĂĐĞ DĞƚŚŽĚϮ͗ĨŽƌŵĂƚŝŽŶƉŽƌĞƉƌĞƐƐƵƌĞĂƚƚŚĞŶĞdžƚĐĂƐŝŶŐƉŽŝŶƚůĞƐƐĂŐĂƐŐƌĂĚŝĞŶƚƚŽƚŚĞƐƵƌĨĂĐĞ DĞƚŚŽĚϭDĞƚŚŽĚϮ ܯܲܵܲ ൌ ሾሺܨܩൈ ͲǤͲͷʹሻ െ ܩܽݏܩݎܽ݀݅݁݊ݐሿ ൈ ܸܶܦ ܯܲܵܲ ൌ ܨܲܲ െ ሺܩܽݏܩݎܽ݀݅݁݊ݐሻ ൈ ܸܶܦ tŚĞƌĞ͗ &'ʹ&ƌĂĐƚƵƌĞŐƌĂĚŝĞŶƚĂƚƚŚĞĐĂƐŝŶŐƐĞĂƚŝŶůďͬŐĂů Ϭ͘ϬϱϮʹŽŶǀĞƌƐŝŽŶĨƌŽŵůďͬŐĂůƚŽƉƐŝͬĨƚ 'ĂƐ'ƌĂĚŝĞŶƚʹϬ͘ϭƉƐŝͬĨƚ dsʹdƌƵĞsĞƌƚŝĐĂůĞƉƚŚŽĨĐĂƐŝŶŐƐĞĂƚŝŶĨƚZ< tŚĞƌĞ͗ &WWʹ&ŽƌŵĂƚŝŽŶWŽƌĞWƌĞƐƐƵƌĞĂƚƚŚĞŶĞdžƚĐĂƐŝŶŐƉŽŝŶƚ 'ĂƐ'ƌĂĚŝĞŶƚʹϬ͘ϭƉƐŝͬĨƚ dŚĞĨŽůůŽǁŝŶŐƉƌĞƐĞŶƚƐĚĂƚĂƵƐĞĚĨŽƌĐĂůĐƵůĂƚŝŽŶŽĨDĂdžŝŵƵŵWŽƚĞŶƚŝĂů^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ;DW^WͿǁŚŝůĞ ĚƌŝůůŝŶŐ͗ ^ĞĐƚŝŽŶ,ŽůĞ^ŝnjĞ WƌĞǀŝŽƵƐ^'^ĞĐƚŝŽŶdDW^W ƉƐŝ DW^WDW^W ^ŝnjĞDds&' ƉƉŐ WŽƌĞWƌĞƐƐƵƌĞ ƉƉŐͮƉƐŝDdsWŽƌĞWƌĞƐƐƵƌĞ ƉƉŐͮƉƐŝ DĞƚŚŽĚϭ ƉƐŝ DĞƚŚŽĚϮ ƉƐŝ ^hZ&ϭϯͲϭͬϮΗ ϮϬΗ ϭϮϬ ϭϮϬ ϭϯ͘Ϯ ϴ͘ϳ ϱϰ Ϯϲϵϰ ϮϱϮϱ ϴ͘ϳ ϭ͕ϭϰϮ ϳϬϳϬϴϵϬ WZKϵͲϳͬϴΗdžϴͲϯͬϰΗ ϭϬͲϯͬϰΗ Ϯϲϵϰ ϮϱϮϱ ϭϰ ϴ͘ϴ ϭ͕ϭϰϮ ϱϯϮϬ ϰϭϱϭ ϴ͘ϴ ϭ͕ϴϵϵ ϭ͕ϰϴϯ ϭ͕ϱϴϲϭ͕ϰϴϰ ΎDĂdžŝŵƵŵƉŽƚĞŶƚŝĂůƉŽƌĞƉƌĞƐƐƵƌĞŝŶƚŚĞ^ƵƐŝƚŶĂ^ĂŶĚŝĨƉƌĞƐĞŶƚ ;ͿĚĂƚĂŽŶƉŽƚĞŶƚŝĂůŐĂƐnjŽŶĞƐ͖ dŚĞƉůĂŶŶĞĚǁĞůůďŽƌĞŝƐŶŽƚĞdžƉĞĐƚĞĚƚŽƉĞŶĞƚƌĂƚĞĂŶLJƐŚĂůůŽǁŐĂƐnjŽŶĞƐ͘ ;ͿĚĂƚĂĐŽŶĐĞƌŶŝŶŐƉŽƚĞŶƚŝĂůĐĂƵƐĞƐŽĨŚŽůĞƉƌŽďůĞŵƐƐƵĐŚĂƐĂďŶŽƌŵĂůůLJŐĞŽͲƉƌĞƐƐƵƌĞĚƐƚƌĂƚĂ͕ůŽƐƚ ĐŝƌĐƵůĂƚŝŽŶnjŽŶĞƐ͕ĂŶĚnjŽŶĞƐƚŚĂƚŚĂǀĞĂƉƌŽƉĞŶƐŝƚLJĨŽƌĚŝĨĨĞƌĞŶƚŝĂůƐƚŝĐŬŝŶŐ͖ WůĞĂƐĞƐĞĞƌŝůůŝŶŐ,ĂnjĂƌĚƐ^ƵŵŵĂƌLJ Recommend granting requesed variance. Surface casing shoe will be set at a location that is surrounded by the surface casing shoes of several previously drilled wells. SFD <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϱͬϭͬϮϬϮϱ <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϲͮϭϭ ϲ͘ WƌŽĐĞĚƵƌĞĨŽƌŽŶĚƵĐƚŝŶŐ&ŽƌŵĂƚŝŽŶ/ŶƚĞŐƌŝƚLJdĞƐƚƐ ZĞƋƵŝƌĞŵĞŶƚƐŽĨϮϬϮϱ͘ϬϬϱ;ĐͿ;ϱͿ ƌŝůůŽƵƚĐĂƐŝŶŐƐŚŽĞĂŶĚƉĞƌĨŽƌŵ>KdƚĞƐƚŽƌ&/dŝŶĂĐĐŽƌĚĂŶĐĞ ǁŝƚŚƚŚĞ>Kdͬ&/dƉƌŽĐĞĚƵƌĞƚŚĂƚ ŽŶŽĐŽWŚŝůůŝƉƐůĂƐŬĂŚĂƐŽŶĨŝůĞǁŝƚŚƚŚĞŽŵŵŝƐƐŝŽŶ͘ ϳ͘ ĂƐŝŶŐĂŶĚĞŵĞŶƚŝŶŐWƌŽŐƌĂŵ ZĞƋƵŝƌĞŵĞŶƚƐŽĨϮϬϮϱ͘ϬϬϱ;ĐͿ;ϲͿ ĂƐŝŶŐĂŶĚĞŵĞŶƚŝŶŐWƌŽŐƌĂŵ K ;ŝŶͿ ,ŽůĞ^ŝnjĞ ;ŝŶͿ tĞŝŐŚƚ ;ůďͬĨƚͿ'ƌĂĚĞŽŶŶ͘ĞŵĞŶƚWƌŽŐƌĂŵ ϮϬ ϰϮ ϵϰ ,ϰϬ tĞůĚĞĚ ĞŵĞŶƚĞĚƚŽƐƵƌĨĂĐĞǁŝƚŚ ϭϬLJĚƐƐůƵƌƌLJ ϭϬͲϯͬϰΗ ϭϯͲϭͬϮΗ ϰϱ͘ϱη >ϴϬ ,ϱϲϯ ĞŵĞŶƚƚŽ^ƵƌĨĂĐĞ ϳͲϱͬϴΗ ϵͲϳͬϴΗ Ϯϵ͘ϳη ϯϯ͘ϳη >ϴϬ WϭϭϬͲ^,ϱϲϯ ϮϱϬ͛dsŽƌϱϬϬ͛D͕ǁŚŝĐŚĞǀĞƌŝƐŐƌĞĂƚĞƌ͕ĂďŽǀĞ ŚŝŐŚĞƐƚƐŝŐŶŝĨŝĐĂŶƚŚLJĚƌŽĐĂƌďŽŶďĞĂƌŝŶŐnjŽŶĞ ϰͲϭͬϮΗ ϴͲϯͬϰΗ ϭϮ͘ϲη WϭϭϬͲ^ ,ϱϲϯ ϭϬͲϯͬϰΗ^ƵƌĨĂĐĞĂƐŝŶŐƌƵŶƚŽϮϲϵϰΖDͬϮϱϮϱΖdsĞŵĞŶƚWůĂŶ͗ ĞŵĞŶƚĨƌŽŵϮϲϵϰ͛DƚŽϮϭϵϰ͛;ϱϬϬ͛ŽĨƚĂŝůͿǁŝƚŚĞĞƉZ d нĚĚƐΛϭϱ͘ϴƉƉŐ͕ĂŶĚĨƌŽŵϮϭϵϰΖƚŽ ƐƵƌĨĂĐĞǁŝƚŚϭϭ͘ϬƉƉŐĞĞƉZ d ͘ƐƐƵŵĞϮϬϬйĞdžĐĞƐƐĂŶŶƵůĂƌǀŽůƵŵĞŝŶƉĞƌŵĂĨƌŽƐƚĂŶĚϱϬйĞdžĐĞƐƐ ďĞůŽǁƚŚĞƉĞƌŵĂĨƌŽƐƚ;ϭϳϭϳ͛DͿ͕njĞƌŽĞdžĐĞƐƐŝŶϮϬ͟ĐŽŶĚƵĐƚŽƌ͘ >ĞĂĚϯϴϰďďůƐсхϭϭϮϯƐdžŽĨϭϭ͘ϬƉƉŐĞĞƉZ d нĚĚΖƐΛϭ͘ϵϮĨƚϹͬƐŬ dĂŝůϱϲďďůƐсхϮϳϮƐdžŽĨϭϱ͘ϴƉƉŐůĂƐƐ'нĚĚΖƐΛϭ͘ϭϲĨƚϹͬƐŬ ϳͲϱͬϴΗdžϰͲϭͬϮ͟WƌŽĚƵĐƚŝŽŶĂƐŝŶŐƌƵŶƚŽϭϯϰϯϴΖDͬϰϮϬϲΖdsĞŵĞŶƚWůĂŶ͗ WƌŝŵĂƌLJĐĞŵĞŶƚũŽďĐŽŶƐŝƐƚƐŽĨĂϭϭ͘ϬƉƉŐůĞĂĚĂŶĚϭϱ͘ϯƉƉŐƚĂŝůƐůƵƌƌLJĚĞƐŝŐŶĞĚƚŽďĞĂƚϰϰϲϲ͛D͕ǁŚŝĐŚ ŝƐϮϱϬΖdsĂďŽǀĞƚŚĞƉƌŽŐŶŽƐĞĚƐŚĂůůŽǁĞƐƚŚLJĚƌŽĐĂƌďŽŶďĞĂƌŝŶŐnjŽŶĞdŽƉŽLJŽƚĞ͕<ϯ͘/ĨĂƐŚĂůůŽǁĞƌ ŚLJĚƌŽĐĂƌďŽŶnjŽŶĞŽĨƉƌŽĚƵĐŝďůĞǀŽůƵŵĞƐ͕ŝƐĞŶĐŽƵŶƚĞƌĞĚǁŚŝůĞĚƌ ŝůůŝŶŐ͕ĂůŽŶŐĞƌƉƌŝŵĂƌLJũŽďŽƌĂϮ ŶĚƐƚĂŐĞ ĐĞŵĞŶƚũŽďǁŝůůďĞƉĞƌĨŽƌŵĞĚƚŽŝƐŽůĂƚĞƚŚŝƐnjŽŶĞ͘ƐƐƵŵĞϮϬйĞ džĐĞƐƐĂŶŶƵůĂƌǀŽůƵŵĞ͘ >ĞĂĚϭϭϳďďůƐсхϯϰϮƐdžŽĨϭϭ͘ϬƉƉŐZ d нĚĚΖƐΛϭ͘ϵϮĨƚϹͬƐŬ dĂŝůϰϱϱďďůƐсхϮϬϰϮƐdžŽĨϭϱ͘ϯƉƉŐůĂƐƐ'нĚĚΖƐΛϭ͘ϮϱĨƚϹͬƐŬ <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϱͬϭͬϮϬϮϱ <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϳͮϭϭ ϴ͘ ƌŝůůŝŶŐ&ůƵŝĚWƌŽŐƌĂŵ ;ZĞƋƵŝƌĞŵĞŶƚƐŽĨϮϬϮϱ͘ϬϬϱ;ĐͿ;ϴͿͿ ^ƵƌĨĂĐĞWƌŽĚƵĐƚŝŽŶ ,ŽůĞ^ŝnjĞŝŶϭϯͲϭͬϮΗ ϵͲϳͬϴΗϴͲϯͬϰΗ ĂƐŝŶŐ^ŝnjĞŝŶϭϬͲϯͬϰΗϳͲϱͬϴΗϰͲϭͬϮΗ ĞŶƐŝƚLJƉƉŐϵͲϵ͘ϴƉƉŐ ϵ͘ϱͲϭϬ͘ϬƉƉŐ ϵ͘ϱͲϭϬ͘ϬƉƉŐ WsĐW>W ϭϬͲϯϬ ϭϬͲϯϬ zWůďͬ͘ϭϬϬĨƚϮϯϱͲϱϬ ϴͲϭϲ ϴͲϭϲ &ƵŶŶĞůsŝƐĐŽƐŝƚLJƐͬƋƚϭϱϬͲϯϬϬ ϰϬͲϲϱ ϰϬͲϲϱ /ŶŝƚŝĂů'ĞůƐůďͬ͘ϭϬϬĨƚϮϱϬ Eͬ Eͬ ϭϬDŝŶƵƚĞ'ĞůƐůďͬ͘ϭϬϬĨƚϮϲϬ Eͬ Eͬ W/&ůƵŝĚ>ŽƐƐĐĐͬϯϬŵŝŶфϰϱ Eͬ Eͬ ,W,d&ůƵŝĚ>ŽƐƐĐĐͬϯϬŵŝŶŶͬĂ фϰ фϰ Ɖ,ϴ͘ϱͲϵ͘ϱ 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ϯ^ͲϳϬϯǁĞůůŚĂƐŽŶĞĐůŽƐĞĂƉƉƌŽĂĐŚǁŝƚŚƚŚĞĂďĂŶĚŽŶĞĚϯ^ͲϭϱǁĞůů͘ ƌŝůůŝŶŐƌĞĂZŝƐŬƐ͗ x ZĞƐĞƌǀŽŝƌWƌĞƐƐƵƌĞ͗ hŶůŝŬĞůLJƚŽĞŶĐŽƵŶƚĞƌĂŶLJĂďŶŽƌŵĂůƉƌĞƐƐƵƌĞŚŽǁĞǀĞƌ͕ƚŚĞƌŝŐǁŝůůďĞƉƌĞƉĂƌĞĚƚŽǁĞŝŐŚƚƵƉŝĨ ƌĞƋƵŝƌĞĚ͘ tĞĂŬƐĂŶĚƐƚƌŝŶŐĞƌƐĐŽƵůĚďĞƉƌĞƐĞŶƚŝŶƚŚĞŽǀĞƌďƵƌĚĞŶ͘>DŵĂƚĞƌŝĂůǁŝůůďĞĂǀĂŝůĂďůĞƚŽƐĞĂůŝŶ ůŽƐƐĞƐŝŶƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞƐĞĐƚŝŽŶ͘ x >ŽƐƚŝƌĐƵůĂƚŝŽŶ͗ ^ƚĂŶĚĂƌĚ>DŵĂƚĞƌŝĂůĂŶĚǁĞůůďŽƌĞƐƚƌĞŶŐƚŚĞŶŝŶŐƉŝůůƐĂƌĞĞdžƉĞĐƚĞĚƚŽďĞĞĨĨĞĐƚŝǀĞŝŶĚĞĂůŝŶŐ ǁŝƚŚůŽƐƚĐŝƌĐƵůĂƚŝŽŶŝĨŶĞĞĚĞĚ͘ x ^ǁĂďďĞĚ<ŝĐŬƐ 'ŽŽĚĚƌŝůůŝŶŐƉƌĂĐƚŝĐĞƐǁŝůůďĞƐƚƌĞƐƐĞĚƚŽŵŝŶŝŵŝnjĞƚŚĞƉŽƚĞŶƚŝĂůŽĨƚĂŬŝŶŐƐǁĂďďĞĚŬŝĐŬƐ͘ <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϱͬϭͬϮϬϮϱ <Zhϯ^ͲϳϬϯK'ϭϬͲϰϬϭW ϭϭͮϭϭ ϭϱ͘ WƌŽƉŽƐĞĚŽŵƉůĞƚŝŽŶ^ĐŚĞŵĂƚŝĐ 40 500 500 800 800 1200 1200 1500 1500 2000 2000 2500 2500 3000 3000 5000 5000 8000 8000 10000 10000 15000 3S-703 (P12) wp05.1 Plan Summary 3S-703 (P12) wp05.1 3S-705 (I12) wp09 3S-714 3S-723 3S-18 3S-07 3S-14 3S-701A 3S-701 3S-739 (I11) wp03 3S-613 3S-606 3S-611 3S-611PB1 3S-03 3S-718 3S-735 (P11) wp04 3S-26 PALM 1 3S-719 (P02) wp05 3S-612 3S-610 3S-624 3S-722 3S-16 3S-08A 3S-08CL1 3S-08CL1PB1 3S-09 3S-704 3S-602 3S-15 3S-08C 3S-08 3S-08B 3S-615 3S-10 3S-620 3S-617 3S-06A 3S-06 0 4 Dogleg Severity0 2000 4000 6000 8000 10000 12000 14000 Measured Depth 10-3/4" Surface Casing 7" 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-705 (I12) wp09 3S-723 3S-07 3S-701A3S-701 3S-606 3S-16 3S-08A 3S-08CL1 3S-08CL1PB1 3S-09 3S-704 3S-08C 3S-08 3S-08B 3S-06A 3S-063S-602 0 4500 True Vertical Depth0 2000 4000 6000 8000 10000 12000 Vertical Section at 341.05° 10-3/4" Surface Casing 7" Intermediate Casing 4-1/2" Production Liner 0 28 55 Centre to Centre Separation0 2000 4000 6000 8000 10000 12000 14000 Measured Depth Equivalent Magnetic Distance DDI 6.663 SURVEY PROGRAM Date: 2019-05-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 40.00 1497.80 3S-703 (P12) wp05.1 (3S-703)r.5 SDI_URSA1 1497.80 2705.11 3S-703 (P12) wp05.1 (3S-703)MWD+IFR2+SAG+MS 2705.11 13437.62 3S-703 (P12) wp05.1 (3S-703) MWD+IFR2+SAG+MS Surface Location North / 5993697.74 East / 1616439.62 Ground / 25.50 CASING DETAILS TVD MD Name 2532.00 2705.11 10-3/4" Surface Casing 4104.05 5112.00 7" Intermediate Casing 4205.50 13437.00 4-1/2" Production Liner Mag Model & Date:BGGM2024 01-Apr-25 Magnetic North is 13.80° East of True North (Magnetic Declination) Mag Dip & Field Strength:80.60°57178.22nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 40.00 0.00 0.00 40.00 0.00 0.00 0.00 0.00 0.00 2 200.00 0.00 0.00 200.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 300.00 1.00 120.00 299.99 -0.44 0.76 1.00 120.00 -0.66 Start DLS 1.00 TFO 40.00 4 400.00 1.88 140.00 399.96 -2.13 2.57 1.00 40.00 -2.85 Start Build 1.25 5 500.00 3.13 140.00 499.87 -5.48 5.37 1.25 0.00 -6.92 Start 200.00 hold at 500.00 MD 6 700.00 3.13 140.00 699.57 -13.84 12.39 0.00 0.00 -17.11 Start Drop -2.50 7 825.17 0.00 0.00 824.68 -16.46 14.59 2.50 180.00 -20.30 Start Build 2.50 8 2228.15 35.07 273.50 2141.66 8.93 -400.82 2.50 273.50 138.61 Start 1048.20 hold at 2228.15 MD 9 3276.36 35.07 273.50 2999.52 45.67 -1002.04 0.00 0.00 368.61 Start DLS 3.50 TFO 78.93 10 5524.57 87.00 348.00 4168.03 1403.56 -2050.39 3.50 78.93 1993.35 Start 200.00 hold at 5524.57 MD 11 5724.57 87.00 348.00 4178.50 1598.92 -2091.91 0.00 0.00 2191.61 Start 50.00 hold at 5724.57 MD 12 5774.57 87.00 348.00 4181.12 1647.76 -2102.30 0.00 0.00 2241.18 Start DLS 2.00 TFO 54.77 13 6022.39 89.86 352.05 4187.90 1891.66 -2145.19 2.00 54.77 2485.79 Start 7415.22 hold at 6022.39 MD 14 13437.62 89.86 352.05 4205.50 9235.54 -3171.16 0.00 0.00 9764.81 TD at 13437.62 FORMATION TOP DETAILS TVDPath Formation 1444.50 Top Ugnu 1715.50 Base Permafrost 2025.50 Top West Sak 2463.50 Base West Sak 2673.50 Campanian Sand (C-80) 3468.50 C-50 3894.50 C-35 4102.50 Top Coyote (Top Nanushuk), K3 Plan: 25.5+40 @ 65.50usft (Doyon 25) Project: Kuparuk River Unit_2 Site: Kuparuk 3S Pad Well: Plan: 3S-703 (P12) Wellbore: 3S-703 Design: 3S-703 (P12) wp05.1 0500010000South(-)/North(+) (2500 usft/in)-15000 -10000 -5000 0 5000West(-)/East(+) (2500 usft/in)3S-703 P12 T1 13203S-703 P12 T2 13203S -0 33S-063S-06A3 S -0 7 3S-083S-08A 3S-08B3 S -0 8 C 3S-08CL13S-08CL1PB13S-093S-103S-143S-153S -163S-183 S -2 6 PALM 13S-6023S-602 wp06.23S-6063S-6103S-6113S-611PB13S-6123S-6133S-6153S-6173S-6243S-7013S-701A3S-7043S-7143S-7183S-7223S-723 wp053S-705 (I12) wp093S-719 (P02) wp053S-727 (P23A) wp033S-728 (I09) wp043S-729 (I22A) wp033S-730 (P10) wp043S-731 (P07) wp043S-733 (I07) wp043S-735 (P11) wp033S-736 (I04) wp033S-739 (I11) wp03500100015002000250030003500400042083S-703 (P12) wp05.1 Plan View with offset wells Project: Kuparuk River Unit_2 Site: Kuparuk 3S Pad Well: Plan: 3S-703 (P12) Wellbore: 3S-703 Design: 3S-703 (P12) wp05.1 0500010000South(-)/North(+) (2500 usft/in)-15000 -10000 -5000 0 5000West(-)/East(+) (2500 usft/in)3S-703 P12 T1 13203S-703 P12 T2 1320500100015002000250030003500400042083S-703 (P12) wp05.1 Plan View 019003800True Vertical Depth (950 usft/in)0 3000 6000 9000 12000Vertical Section at 341.05° (1500 usft/in)10-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner10002000300040005000600070008000900010000110001200013000Plan: 3S-703 (P12)/3S-703 (P12) wp05.1Start Build 1.00Start DLS 1.00 TFO 40.00Start Build 1.25Start 200.00 hold at 500.00 MDStart Drop -2.50Start Build 2.50Start 1048.20 hold at 2228.15 MDStart DLS 3.50 TFO 78.93Start 200.00 hold at 5524.57 MDStart 50.00 hold at 5724.57 MDStart DLS 2.00 TFO 54.77Start 7415.22 hold at 6022.39 MDTD at 13437.62Section View Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-703 (P12)Wellbore: 3S-703Design: 3S-703 (P12) wp05.1 ! 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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. KRU 3S-703 COYOTE OIL 225-035 KUPARUK RIVER WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3S-703Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250350Field & Pool:KUPARUK RIVER, COYOTE OIL - 490120NA1Permit fee attachedNoSurf Loc & Top Prod Int lie in ADL0380107; TD lies within ADL0380106.2Lease number appropriateYes3Unique well name and numberYesKUPARUK RIVER, COYOTE OIL - 490120 - governed by CO 6184Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes92'18Conductor string providedYesSC set at 2694' MD19Surface casing protects all known USDWsYes152% excess planned20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYesDiverter variance granted27If diverter required, does it meet regulationsYesMax reservoir pressure is 1899 psig(8.8 ppg EMW); will drill w/ 9.5-10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1484 psig; will test BOPs to 5000 psig initially and 3500 psig subsequently30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)NoH2S measures required: KRU 3S-718 reported 50 ppm H2S on 11/15/2024.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.439 to 0.453 psi/ft (8.5 to 8.7 ppg EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability.37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate07-May-25ApprVTLDate08-May-25ApprSFDDate07-May-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&: JLC 5/9/2025
