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225-010
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. Originated: Delivered to:5-Nov-25Alaska Oil & Gas Conservation Commiss05Nov25-NR ! "# $$%$ !&$$'($)*%+ ($)*%,- .WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3T-730 50-103-20907-00-00 225-010 Kuparuk River WL TTiX-IPROF FINAL FIELD 6-Oct-253J-03 50-029-21399-00-00 185-164 Kuparuk River WL PPROF FINAL FIELD 7-Oct-252X-01 50-029-20963-00-00 183-084 Kuparuk River WL IPROF FINAL FIELD 10-Oct-252Z-07 50-029-20946-00-00 183-064 Kuparuk River WL CBP FINAL FIELD 11-Oct-252Z-03 50-029-20964-00-00 183-085 Kuparuk River WL IPROF FINAL FIELD 14-Oct-253R-17 50-029-22242-00-00 192-005 Kuparuk River WL LDL FINAL FIELD 16-Oct-253S-722 50-103-20886-00-00 224-066 Kuparuk River WL TTiX-IPROF FINAL FIELD 20-Oct-252U-06 50-029-21282-00-00 185-019 Kuparuk River WL RBP FINAL FIELD 25-Oct-253T-731 50-103-20905-00-00 224-156 Kuparuk River WL Cutter FINAL FIELD 2-Nov-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1 Please return via courier or sign/scan and email a copy to Schlumberger. " 2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8 " ! - +" 8 # !(3 . 8 ) "3 8 # !9 3 : 8" +8 6 8 8 " 8 # !;" " 3 - 3 " 3 ""+ 3 + < +3!% T41052T41053T41054T41055T41056T41057T41058T41059T410603T-73050-103-20907-00-00225-010Kuparuk RiverWLTTiX-IPROFFINAL FIELD6-Oct-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.11.05 12:45:23 -09'00' T40407 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' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, September 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 3T-730 KUPARUK RIV UNIT 3T-730 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 09/22/2025 3T-730 50-103-20907-00-00 225-010-0 W SPT 4084 2250100 1500 8 8 8 8 0 0 0 0 INITAL P Guy Cook 8/13/2025 An initial test for a new injector. Testing was completed with a Little Red Services pump truck and calibrated gauges. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 3T-730 Inspection Date: Tubing OA Packer Depth 890 2000 1930 1920IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC250813141429 BBL Pumped:1 BBL Returned:1 Monday, September 22, 2025 Page 1 of 1 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 14036 feet feet true vertical 4151 feet feet Effective Depth measured 14036 feet 4937 feet true vertical 4151 feet 4084 feet Perforation depth Measured depth feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 5080' MD 4,110' TVD Packers and SSSV (type, measured and true vertical depth) HES TNT Production Packer 4,937' MD 4,084' 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 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: 325-304 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. Completions Engineer Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 Gas-Mcf MD 13,822' - 5342' MD 48 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 1245 1275 (gas lift)1900 0 1714 (DHG)0 1578 (DHG) 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 905 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL025528/ADL025544 KRU / Coyote ConocoPhillips Alaska, Inc. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 225-010 50-103-20907-00-00 P.O. Box 100360 Anchorage, Alaska 99501-03603. Address: 3T-730 3,250,851 lbs 16/20 LWC, 54,000 lbs 100M, 20,825 bbls of fluid, and final pressure @ DHG of 2,755 psi Length 119 2625 119Conductor Surface Production 20" x 34" 10-3/4" Size 119 7-5/8" 11590 7-5/8" measured TVD Production Liner 3943 866 8450 Casing Structural 3796 4110 4-1/2" 4205 5074 14026 4151 Plugs Junk measured 13822-13832 4151 2636 2472 Burst Collapse 2474 4790 7870 5209 6885 10860 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard @conocophillips.com Reason: I am the author of this document Location: Date: 2025.07.01 14:50:38-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard By Grace Christianson at 9:49 am, Jul 02, 2025 RBDMS JSB 071025 VTL 7/30/2025 CDW 07/02/2025 DSR-7/21/25 Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set GLD, pull catcher & RBP 3T-730 6/18/2025 rogerba Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread Conductor 20 19.12 39.0 119.0 119.0 94.00 Landing ring Surface 10 3/4 9.95 39.4 2,635.5 2,472.1 45.50 L-80 Hydril 563 Liner 7 5/8 6.88 38.0 14,025.5 4,151.1 29.70 L-80 Hydril 563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 36.7 Set Depth … 5,080.2 String Max No… 4 1/2 Set Depth … 4,110.7 Tubing Description Tubing – Completion Upper Wt (lb/ft) 12.60 Grade L-80 Top Connection Hydril 563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 36.7 36.7 0.00 Hanger 10.850 4" H-Type BPV profile - StreamFlow DMLX 3.900 2,000.0 1,890.8 31.28 GLM 4.500 KBG-4-5 Camco KBG-4-5 3.865 3,341.0 3,130.5 27.03 GLM 4.500 KBG-4-5 Camco KBG-4-5 3.865 4,757.5 4,032.8 71.54 GLM 4.500 KBG-4-5 Camco KBG-4-5 3.865 4,827.6 4,054.3 72.97 Gauge Mandrel 4.500 HES OPSIS 3.922 4,936.8 4,083.6 76.30 PACKER 6.362 HES TNT 3.878 5,004.8 4,098.0 79.19 Nipple 4.500 SLB OSDB-6 3.750 5,059.3 4,107.4 80.83 Glass disc sub 4.500 5,500 psi SHEAR burst disk - sheared 5/16/25 Arsenal 3.900 5,071.1 4,109.3 81.19 Locator 6.360 Nominal shear = 14,260 lbs Baker WLEG 3.900 5,071.7 4,109.4 81.21 Locator 5.620 Nominal shear = 14,260 lbs Baker WLEG 3.900 5,077.0 4,110.2 81.37 Shoe - Mule 5.190 Indexing Mule Shoe HES 3.880 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 2,000.0 1,890.8 31.28 1 GAS LIFT GLV BK 1 1,360.0 6/17/2025 SLB Other 0.188 3,341.0 3,130.5 27.03 2 GAS LIFT GLV BK 1 1,450.0 6/17/2025 SLB Other 0.313 4,757.5 4,032.8 71.54 3 GAS LIFT OV BTM 1 6/17/2025 SLB Other 0.313 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 5,074.0 4,109.7 81.28 XO Reducing 8.510 5.75" No Go located 0.50ft down from top. Transition assembly component #4 Tenaris 5.750 5,084.1 4,111.2 81.58 XO Reducing 7.040 Transition assembly component #2 Tenaris 6.184 5,343.6 4,136.1 86.91 Sleeve - Frac #17 5.500 **OPENED 6/2/25** 109280-C110-W563-000219 AU Limitless Frac Sleeve 3.500 5,843.1 4,142.3 89.90 Sleeve - Frac #16 5.500 **OPENED 6/2/25** 109280-C110-W563-000218 AU Limitless Frac Sleeve 3.500 6,425.6 4,142.9 89.94 Sleeve - Frac #15 5.500 **OPENED 6/2/25** 109280-C110-W563-000217 AU Limitless Frac Sleeve 3.500 6,923.4 4,142.9 89.95 Sleeve - Frac #14 5.500 **OPENED 6/2/25** 109280-C110-W563-000216 AU Limitless Frac Sleeve 3.500 7,461.6 4,145.5 89.79 Sleeve - Frac #13 5.500 **OPENED 6/2/25** 109280-C110-W563-000215 AU Limitless Frac Sleeve 3.500 7,960.3 4,149.4 89.94 Sleeve - Frac #12 5.500 **OPENED 6/2/25** 109280-C110-W563-000214 AU Limitless Frac Sleeve 3.500 8,376.3 4,151.2 89.69 Sleeve - Frac #11 5.500 **OPENED 6/1/25** 109280-C110-W563-000213 AU Limitless Frac Sleeve 3.500 8,874.5 4,154.0 89.82 Sleeve - Frac #10 5.500 **OPENED 6/1/25** 109280-C110-W563-000212 AU Limitless Frac Sleeve 3.500 9,369.9 4,155.2 89.89 Sleeve - Frac #9 5.500 **OPENED 6/1/25** 109280-C110-W563-000211 AU Limitless Frac Sleeve 3.500 9,868.4 4,155.4 89.93 Sleeve - Frac #8 5.500 **OPENED 6/1/25** 109280-C110-W563-000210 AU Limitless Frac Sleeve 3.500 10,367.1 4,155.7 90.04 Sleeve - Frac #7 5.500 **OPENED 6/1/25** 109280-C110-W563-000206 AU Limitless Frac Sleeve 3.500 10,863.9 4,156.4 90.09 Sleeve - Frac #6 5.500 **OPENED 6/1/25** 109280-C110-W563-000205 AU Limitless Frac Sleeve 3.500 11,359.3 4,156.3 90.03 Sleeve - Frac #5 5.500 **OPENED 5/31/25** 109280-C110-W563-000204 AU Limitless Frac Sleeve 3.500 11,894.4 4,155.8 90.01 Sleeve - Frac #4 5.500 **OPENED 5/31/25** 109280-C110-W563-000201 AU Limitless Frac Sleeve 3.500 12,435.4 4,154.9 89.99 Sleeve - Frac #3 5.500 **OPENED 5/31/25** 109280-C110-W563-000188 AU Limitless Frac Sleeve 3.500 12,852.0 4,154.2 90.12 Sleeve - Frac #2 5.500 **OPENED 5/31/25** 109280-C110-W563-000160 AU Limitless Frac Sleeve 3.500 HORIZONTAL, 3T-730, 6/27/2025 12:51:41 PM M D (ft K B) -2,661.1 -440.9 -33.1 -24.0 -20.0 -16.7 -13.1 -3.6 0.0 38.1 39.4 81.4 163.1 1,989.8 2,016.7 2,633.2 3,331.0 3,357.9 4,520.0 4,764.4 4,827.8 4,926.8 4,952.4 5,006.9 5,061.0 5,071.9 5,076.1 5,084.0 5,113.8 5,346.1 5,845.5 6,425.5 6,923.6 7,460.0 7,959.0 8,374.7 8,378.9 8,877.0 9,372.4 9,868.4 10,367.1 10,862.5 11,357.6 11,892.7 12,434.1 12,850.4 12,854.7 13,352.0 13,847.4 13,892.4 13,937.0 14,021.7 TV D (ftK B) -2,661.1 -440.9 -33.1 -24.0 -20.0 -16.7 -13.1 -3.6 0.0 38.1 39.4 81.4 163.1 1,882.4 1,905.4 2,470.0 3,121.4 3,145.4 3,949.2 4,034.7 4,054.0 4,080.6 4,086.4 4,098.2 4,107.2 4,109.0 4,109.7 4,111.0 4,115.4 4,136.1 4,142.3 4,142.9 4,142.9 4,145.5 4,149.4 4,151.2 4,151.2 4,154.0 4,155.1 4,155.4 4,155.7 4,156.4 4,156.3 4,155.8 4,154.9 4,154.3 4,154.3 4,153.2 4,151.5 4,151.4 4,151.3 4,151.1 Incl (°) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.9 31.6 30.8 19.5 26.8 27.4 66.5 71.7 73.0 75.9 77.0 79.3 80.9 81.2 81.3 81.6 82.3 86.9 89.9 89.9 90.0 89.8 89.9 89.7 89.7 89.8 89.9 89.9 90.0 90.1 90.0 90.0 90.0 90.1 90.1 90.2 90.1 90.1 90.1 90.2 Vertical schematic (actual) Des:IPERF ; Depth MD:13,822. 0-13,832.0; Date:5/28/2 025 3-51; Shoe - Float; 4.500; 3.410; 14,021.6; 3.85 3-50; Casing Jts; 4.500; 3.958; 13,938.7; 82.91 3-49; Collar - Landing; 4.500; 3.738; 13,937.5; 1.27 3-48; Casing Jts; 4.500; 3.958; 13,896.2; 41.27 3-47; Alpha Pressure Sleeve - Trigger #15; 5.620; 3.010; 13,892.5; 3.69 3-46; Casing Jts; 4.500; 3.958; 13,851.1; 41.40 3-45; Alpha Pressure Sleeve - Trigger #16; 5.620; 3.010; 13,847.4; 3.69 3-44; Casing Jts; 4.500; 3.958; 13,352.1; 495.27 3-43; Sleeve - Frac #1; 5.500; 3.500; 13,349.5; 2.65 3-42; Casing Jts; 4.500; 3.958; 12,854.6; 494.86 3-41; Sleeve - Frac #2; 5.500; 3.500; 12,852.0; 2.65 3-40; Casing Jts; 4.500; 3.958; 12,438.1; 413.93 3-39; Sleeve - Frac #3; 5.500; 3.500; 12,435.4; 2.65 3-38; Casing Jts; 4.500; 3.958; 11,897.0; 538.40 3-37; Sleeve - Frac #4; 5.500; 3.500; 11,894.4; 2.65 3-36; Casing Jts; 4.500; 3.958; 11,361.9; 532.46 3-35; Sleeve - Frac #5; 5.500; 3.500; 11,359.2; 2.65 3-34; Casing Jts; 4.500; 3.958; 10,866.6; 492.66 3-33; Sleeve - Frac #6; 5.500; 3.500; 10,863.9; 2.65 3-32; Casing Jts; 4.500; 3.958; 10,369.7; 494.22 3-31; Sleeve - Frac #7; 5.500; 3.500; 10,367.1; 2.65 3-30; Casing Jts; 4.500; 3.958; 9,871.1; 496.00 3-29; Sleeve - Frac #8; 5.500; 3.500; 9,868.4; 2.65 3-28; Casing Jts; 4.500; 3.958; 9,372.5; 495.87 3-27; Sleeve - Frac #9; 5.500; 3.500; 9,369.9; 2.65 3-26; Casing Jts; 4.500; 3.958; 8,877.1; 492.80 3-25; Sleeve - Frac #10; 5.500; 3.500; 8,874.4; 2.65 3-24; Casing Jts; 4.500; 3.958; 8,378.9; 495.54 3-23; Sleeve - Frac #11; 5.500; 3.500; 8,376.3; 2.65 3-22; Casing Jts; 4.500; 3.958; 7,963.0; 413.27 3-21; Sleeve - Frac #12; 5.500; 3.500; 7,960.3; 2.65 3-20; Casing Jts; 4.500; 3.958; 7,464.2; 496.11 3-19; Sleeve - Frac #13; 5.500; 3.500; 7,461.6; 2.65 3-18; Casing Jts; 4.500; 3.958; 6,926.1; 535.49 3-17; Sleeve - Frac #14; 5.500; 3.500; 6,923.4; 2.65 3-16; Casing Jts; 4.500; 3.958; 6,428.2; 495.23 3-15; Sleeve - Frac #15; 5.500; 3.500; 6,425.6; 2.65 3-14; Casing Jts; 4.500; 3.958; 5,845.7; 579.82 3-13; Sleeve - Frac #16; 5.500; 3.500; 5,843.1; 2.65 3-12; Casing Jts; 4.500; 3.958; 5,346.2; 496.88 3-11; Sleeve - Frac #17; 5.500; 3.500; 5,343.6; 2.65 3-10; Casing Jts; 4.500; 3.958; 5,095.6; 247.96 3-9; Casing Pup Joint; 4.500; 3.958; 5,087.9; 7.70 3-8; XO Reducing; 7.040; 6.184; 5,084.1; 3.79 3-7; Casing Pup Joint; 7.000; 6.184; 5,076.1; 8.02 1-34; Shoe - Mule; 5.190; 3.880; 5,076.9; 3.25 1-33; Tubing - Pup Joint; 4.500; 3.920; 5,073.6; 3.343-6; XO Reducing; 8.510; 5.750; 5,074.0; 2.07 1-32; Locator; 5.620; 3.900; 5,071.7; 1.87 1-31; Locator; 6.360; 3.900; 5,071.1; 0.62 3-5; Casing Pup Joint; 7.625; 6.765; 5,064.2; 9.82 1-30; Tubing - Pup Joint; 4.500; 3.920; 5,061.1; 10.00 1-29; Glass disc sub; 4.500; 3.900; 5,059.3; 1.83 1-28; Tubing; 4.500; 3.958; 5,016.8; 42.47 1-27; Tubing - Pup Joint; 4.500; 3.958; 5,006.8; 10.00 1-26; Nipple; 4.500; 3.750; 5,004.8; 2.06 1-25; Tubing - Pup Joint; 4.500; 3.958; 4,994.8; 10.00 1-24; Tubing; 4.500; 3.958; 4,952.3; 42.49 1-23; Tubing - Pup Joint; 4.500; 3.958; 4,942.3; 10.00 1-22; PACKER; 6.362; 3.878; 4,936.8; 5.43 1-21; Tubing - Pup Joint; 4.500; 3.958; 4,926.8; 9.99 1-20; Tubing; 4.500; 3.958; 4,841.9; 84.99 1-19; Tubing - Pup Joint; 4.500; 3.097; 4,831.9; 10.00 1-18; Gauge Mandrel; 4.500; 3.922; 4,827.6; 4.24 1-17; Tubing - Pup Joint; 4.500; 3.906; 4,817.6; 10.00 1-16; Tubing; 4.500; 3.958; 4,774.5; 43.09 1-15; Tubing - Pup Joint; 4.500; 3.958; 4,764.5; 10.00 1-14; GLM; 4.500; 3.865; 4,757.5; 7.05 1-13; Tubing - Pup Joint; 4.500; 3.958; 4,747.5; 10.00 3-4; Casing Jts; 7.625; 6.765; 4,205.3; 858.85 3-3; Casing Pup Joint - 7-5/8" L80 PUP; 7.625; 6.875; 4,197.5; 7.86 1-12; Tubing; 4.500; 3.958; 3,358.0; 1,389.43 1-11; Tubing - Pup Joint; 4.500; 3.958; 3,348.1; 10.00 1-10; GLM; 4.500; 3.865; 3,341.0; 7.06 1-9; Tubing - Pup Joint; 4.500; 3.958; 3,331.0; 10.01 1-8; Tubing; 4.500; 3.958; 2,016.8; 1,314.22 2-5; Shoe - Float; 10.750; 9.950; 2,633.1; 2.38 2-4; Casing Jts; 10.750; 9.950; 2,547.7; 85.44 2-3; Float Collar; 10.750; 9.950; 2,544.5; 3.16 3-2; Casing Jts; 7.625; 6.875; 38.6; 4,158.93 1-7; Tubing - Pup Joint; 4.500; 3.833; 2,007.0; 9.73 1-6; GLM; 4.500; 3.865; 2,000.0; 7.04 1-5; Tubing - Pup Joint; 4.500; 3.833; 1,990.0; 10.00 2-2; Casing Jts; 10.750; 9.950; 40.3; 2,504.221-4; Tubing; 4.500; 3.958; 91.1; 1,898.93 1-3; Tubing - Pup Joint; 4.500; 3.833; 81.3; 9.75 1-1; Conductor; 20.000; 19.124; 39.0; 80.00 1-2; Tubing; 4.500; 3.958; 40.8; 40.48 2-1; Casing Hanger; 10.750; 9.950; 39.4; 0.91 1-1; Hanger; 10.850; 3.900; 36.7; 4.10 3-1; Casing Hanger; 10.850; 6.860; 37.9; 0.61 KUP PROD KB-Grd (ft) 39.00 RR Date 5/2/2025 Other Elev… 3T-730 ... TD Act Btm (ftKB) 14,036.0 Well Attributes Field Name COYOTE Wellbore API/UWI 501032090700 Wellbore Status PROD Max Angle & MD Incl (°) 90.54 MD (ftKB) 5,751.96 WELLNAME WELLBORE3T-730 Annotation End DateH2S (ppm) DateComment Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 13,349.5 4,153.2 90.19 Sleeve - Frac #1 5.500 **OPENED 5/31/25** AU Limitless Frac Sleeve 3.500 13,847.4 4,151.4 90.06 Alpha Pressure Sleeve - Trigger #16 5.620 Baker Alpha Sleeve #16 3.010 13,892.5 4,151.4 90.05 Alpha Pressure Sleeve - Trigger #15 5.620 Baker Alpha Sleeve #15 3.010 13,937.5 4,151.3 90.12 Collar - Landing 4.500 Citadel Landing Collar w 2.5" ID Latch down seat 3.738 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 13,822.0 13,832.0 4,151.5 4,151.4 5/28/2025 6.0 IPERF 2.875" HSD 10', 6 SPF, 60° PHASE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 39.4 2,641.0 39.4 2,477.3 Surface String Cement 4/15/2025 4,520.0 14,025.5 3,949.3 4,151.1 Production String 1 Cement Pump total of 650 of 13.5 PPG cement (60 BBL clean lead cement, 530 BBL with LCM, 60 BBL clean tail cement) Plugs bumped as expected. Floats held. No losses during job. 4/30/2025 HORIZONTAL, 3T-730, 6/27/2025 12:51:42 PM M D (ft K B) -2,661.1 -440.9 -33.1 -24.0 -20.0 -16.7 -13.1 -3.6 0.0 38.1 39.4 81.4 163.1 1,989.8 2,016.7 2,633.2 3,331.0 3,357.9 4,520.0 4,764.4 4,827.8 4,926.8 4,952.4 5,006.9 5,061.0 5,071.9 5,076.1 5,084.0 5,113.8 5,346.1 5,845.5 6,425.5 6,923.6 7,460.0 7,959.0 8,374.7 8,378.9 8,877.0 9,372.4 9,868.4 10,367.1 10,862.5 11,357.6 11,892.7 12,434.1 12,850.4 12,854.7 13,352.0 13,847.4 13,892.4 13,937.0 14,021.7 TV D (ftK B) -2,661.1 -440.9 -33.1 -24.0 -20.0 -16.7 -13.1 -3.6 0.0 38.1 39.4 81.4 163.1 1,882.4 1,905.4 2,470.0 3,121.4 3,145.4 3,949.2 4,034.7 4,054.0 4,080.6 4,086.4 4,098.2 4,107.2 4,109.0 4,109.7 4,111.0 4,115.4 4,136.1 4,142.3 4,142.9 4,142.9 4,145.5 4,149.4 4,151.2 4,151.2 4,154.0 4,155.1 4,155.4 4,155.7 4,156.4 4,156.3 4,155.8 4,154.9 4,154.3 4,154.3 4,153.2 4,151.5 4,151.4 4,151.3 4,151.1 Incl (°) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.9 31.6 30.8 19.5 26.8 27.4 66.5 71.7 73.0 75.9 77.0 79.3 80.9 81.2 81.3 81.6 82.3 86.9 89.9 89.9 90.0 89.8 89.9 89.7 89.7 89.8 89.9 89.9 90.0 90.1 90.0 90.0 90.0 90.1 90.1 90.2 90.1 90.1 90.1 90.2 Vertical schematic (actual) Des:IPERF ; Depth MD:13,822. 0-13,832.0; Date:5/28/2 025 3-51; Shoe - Float; 4.500; 3.410; 14,021.6; 3.85 3-50; Casing Jts; 4.500; 3.958; 13,938.7; 82.91 3-49; Collar - Landing; 4.500; 3.738; 13,937.5; 1.27 3-48; Casing Jts; 4.500; 3.958; 13,896.2; 41.27 3-47; Alpha Pressure Sleeve - Trigger #15; 5.620; 3.010; 13,892.5; 3.69 3-46; Casing Jts; 4.500; 3.958; 13,851.1; 41.40 3-45; Alpha Pressure Sleeve - Trigger #16; 5.620; 3.010; 13,847.4; 3.69 3-44; Casing Jts; 4.500; 3.958; 13,352.1; 495.27 3-43; Sleeve - Frac #1; 5.500; 3.500; 13,349.5; 2.65 3-42; Casing Jts; 4.500; 3.958; 12,854.6; 494.86 3-41; Sleeve - Frac #2; 5.500; 3.500; 12,852.0; 2.65 3-40; Casing Jts; 4.500; 3.958; 12,438.1; 413.93 3-39; Sleeve - Frac #3; 5.500; 3.500; 12,435.4; 2.65 3-38; Casing Jts; 4.500; 3.958; 11,897.0; 538.40 3-37; Sleeve - Frac #4; 5.500; 3.500; 11,894.4; 2.65 3-36; Casing Jts; 4.500; 3.958; 11,361.9; 532.46 3-35; Sleeve - Frac #5; 5.500; 3.500; 11,359.2; 2.65 3-34; Casing Jts; 4.500; 3.958; 10,866.6; 492.66 3-33; Sleeve - Frac #6; 5.500; 3.500; 10,863.9; 2.65 3-32; Casing Jts; 4.500; 3.958; 10,369.7; 494.22 3-31; Sleeve - Frac #7; 5.500; 3.500; 10,367.1; 2.65 3-30; Casing Jts; 4.500; 3.958; 9,871.1; 496.00 3-29; Sleeve - Frac #8; 5.500; 3.500; 9,868.4; 2.65 3-28; Casing Jts; 4.500; 3.958; 9,372.5; 495.87 3-27; Sleeve - Frac #9; 5.500; 3.500; 9,369.9; 2.65 3-26; Casing Jts; 4.500; 3.958; 8,877.1; 492.80 3-25; Sleeve - Frac #10; 5.500; 3.500; 8,874.4; 2.65 3-24; Casing Jts; 4.500; 3.958; 8,378.9; 495.54 3-23; Sleeve - Frac #11; 5.500; 3.500; 8,376.3; 2.65 3-22; Casing Jts; 4.500; 3.958; 7,963.0; 413.27 3-21; Sleeve - Frac #12; 5.500; 3.500; 7,960.3; 2.65 3-20; Casing Jts; 4.500; 3.958; 7,464.2; 496.11 3-19; Sleeve - Frac #13; 5.500; 3.500; 7,461.6; 2.65 3-18; Casing Jts; 4.500; 3.958; 6,926.1; 535.49 3-17; Sleeve - Frac #14; 5.500; 3.500; 6,923.4; 2.65 3-16; Casing Jts; 4.500; 3.958; 6,428.2; 495.23 3-15; Sleeve - Frac #15; 5.500; 3.500; 6,425.6; 2.65 3-14; Casing Jts; 4.500; 3.958; 5,845.7; 579.82 3-13; Sleeve - Frac #16; 5.500; 3.500; 5,843.1; 2.65 3-12; Casing Jts; 4.500; 3.958; 5,346.2; 496.88 3-11; Sleeve - Frac #17; 5.500; 3.500; 5,343.6; 2.65 3-10; Casing Jts; 4.500; 3.958; 5,095.6; 247.96 3-9; Casing Pup Joint; 4.500; 3.958; 5,087.9; 7.70 3-8; XO Reducing; 7.040; 6.184; 5,084.1; 3.79 3-7; Casing Pup Joint; 7.000; 6.184; 5,076.1; 8.02 1-34; Shoe - Mule; 5.190; 3.880; 5,076.9; 3.25 1-33; Tubing - Pup Joint; 4.500; 3.920; 5,073.6; 3.343-6; XO Reducing; 8.510; 5.750; 5,074.0; 2.07 1-32; Locator; 5.620; 3.900; 5,071.7; 1.87 1-31; Locator; 6.360; 3.900; 5,071.1; 0.62 3-5; Casing Pup Joint; 7.625; 6.765; 5,064.2; 9.82 1-30; Tubing - Pup Joint; 4.500; 3.920; 5,061.1; 10.00 1-29; Glass disc sub; 4.500; 3.900; 5,059.3; 1.83 1-28; Tubing; 4.500; 3.958; 5,016.8; 42.47 1-27; Tubing - Pup Joint; 4.500; 3.958; 5,006.8; 10.00 1-26; Nipple; 4.500; 3.750; 5,004.8; 2.06 1-25; Tubing - Pup Joint; 4.500; 3.958; 4,994.8; 10.00 1-24; Tubing; 4.500; 3.958; 4,952.3; 42.49 1-23; Tubing - Pup Joint; 4.500; 3.958; 4,942.3; 10.00 1-22; PACKER; 6.362; 3.878; 4,936.8; 5.43 1-21; Tubing - Pup Joint; 4.500; 3.958; 4,926.8; 9.99 1-20; Tubing; 4.500; 3.958; 4,841.9; 84.99 1-19; Tubing - Pup Joint; 4.500; 3.097; 4,831.9; 10.00 1-18; Gauge Mandrel; 4.500; 3.922; 4,827.6; 4.24 1-17; Tubing - Pup Joint; 4.500; 3.906; 4,817.6; 10.00 1-16; Tubing; 4.500; 3.958; 4,774.5; 43.09 1-15; Tubing - Pup Joint; 4.500; 3.958; 4,764.5; 10.00 1-14; GLM; 4.500; 3.865; 4,757.5; 7.05 1-13; Tubing - Pup Joint; 4.500; 3.958; 4,747.5; 10.00 3-4; Casing Jts; 7.625; 6.765; 4,205.3; 858.85 3-3; Casing Pup Joint - 7-5/8" L80 PUP; 7.625; 6.875; 4,197.5; 7.86 1-12; Tubing; 4.500; 3.958; 3,358.0; 1,389.43 1-11; Tubing - Pup Joint; 4.500; 3.958; 3,348.1; 10.00 1-10; GLM; 4.500; 3.865; 3,341.0; 7.06 1-9; Tubing - Pup Joint; 4.500; 3.958; 3,331.0; 10.01 1-8; Tubing; 4.500; 3.958; 2,016.8; 1,314.22 2-5; Shoe - Float; 10.750; 9.950; 2,633.1; 2.38 2-4; Casing Jts; 10.750; 9.950; 2,547.7; 85.44 2-3; Float Collar; 10.750; 9.950; 2,544.5; 3.16 3-2; Casing Jts; 7.625; 6.875; 38.6; 4,158.93 1-7; Tubing - Pup Joint; 4.500; 3.833; 2,007.0; 9.73 1-6; GLM; 4.500; 3.865; 2,000.0; 7.04 1-5; Tubing - Pup Joint; 4.500; 3.833; 1,990.0; 10.00 2-2; Casing Jts; 10.750; 9.950; 40.3; 2,504.221-4; Tubing; 4.500; 3.958; 91.1; 1,898.93 1-3; Tubing - Pup Joint; 4.500; 3.833; 81.3; 9.75 1-1; Conductor; 20.000; 19.124; 39.0; 80.00 1-2; Tubing; 4.500; 3.958; 40.8; 40.48 2-1; Casing Hanger; 10.750; 9.950; 39.4; 0.91 1-1; Hanger; 10.850; 3.900; 36.7; 4.10 3-1; Casing Hanger; 10.850; 6.860; 37.9; 0.61 KUP PROD 3T-730 ... WELLNAME WELLBORE3T-730 Page 10/29 3T-730 Report Printed: 7/1/2025 Operations Summary (with Timelog Depths) Job: INITIAL COMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 5/31/2025 07:45 5/31/2025 09:45 2.00 COMPZN, STIM PUMP P EQUALIZE TO 550 PSI, OPEN AT 370 PSI ESTABLISH RATE TO 10 BPM, STAGE INTO DFIT. PERFORMED DFIT AT 10 BPM, SHUT IN MONITOR PSI FOR 15 MIN. CLOSURE 2255 PSI PERFORMED SRT IN 1 BBL INCREMENTS TO A MAX RATE OF 10 BPM STAGE 1 THROUGH PERFERATIONS AT 13822' - 13832'. TOTAL CLEAN VOLUME PUMPED 1282 BBL, TOTAL PROPPANT PLACED 201956 LB, 100 MESH 3000 LB, 16/20 198956 LB, AVG SURFACE PSI 2010, AVG BHP 3708 PSI, AVG RATE 20.0 BPM 5/31/2025 09:45 5/31/2025 11:00 1.25 COMPZN, STIM PUMP P LAUNCHED DART 1 FOR STAGE 2 @ 1507 JSV, LANDED 9 BBL EARLY @ 1701 JSV, SURFACE PEAK 5212 PSI, SURFACE DIFFERENTIAL 3329 PSI, BHP PEAK 5270 PSI, BHP DIFFERENTIAL 2012 PSI, TOTAL CLEAN VOLUME PUMPED 1176 BBL, TOTAL PROPPANT PLACED 204651 LB, 100 MESH 3000 LB, 16/20 201651 LB, AVG SURFACE PSI 1936, AVG BHP 3663 PSI, AVG RATE 20.1 BPM 5/31/2025 11:00 5/31/2025 12:30 1.50 COMPZN, STIM PUMP P LAUNCHED DART 2 FOR STAGE 3 @ 2907 JSV, LANDED 9 BBL EARLY @ 3094 JSV, SURFACE PEAK 3989 PSI, SURFACE DIFFERENTIAL 2197 PSI, BHP PEAK 5530 PSI, BHP DIFFERENTIAL 2336 PSI, TOTAL CLEAN VOLUME PUMPED 1196 BBL, TOTAL PROPPANT PLACED 205975 LB, 100 MESH 3000 LB, 16/20 202975 LB, AVG SURFACE PSI 1886, AVG BHP 3609 PSI, AVG RATE 20.2 BPM 5/31/2025 12:30 5/31/2025 13:45 1.25 COMPZN, STIM PUMP P LAUNCHED DART 3 FOR STAGE 4 @ 4329 JSV, LANDED 9 BBL EARLY @ 4509 JSV, SURFACE PEAK 4004 PSI, SURFACE DIFFERENTIAL 2203 PSI, BHP PEAK 5097 PSI, BHP DIFFERENTIAL 1892 PSI, TOTAL CLEAN VOLUME PUMPED 1814 BBL, TOTAL PROPPANT PLACED 203732 LB, 100 MESH 3000 LB, 16/20 200732 LB, AVG SURFACE PSI 1971, AVG BHP 3657 PSI, AVG RATE 20.3 BPM 5/31/2025 13:45 5/31/2025 15:00 1.25 COMPZN, STIM PUMP P LAUNCHED DART 4 FOR STAGE 5 @ 6368 JSV, LANDED 8 BBL EARLY @ 6541 JSV, SURFACE PEAK 3709 PSI, SURFACE DIFFERENTIAL 1860 PSI, BHP PEAK 5213 PSI, BHP DIFFERENTIAL 1967 PSI, TOTAL CLEAN VOLUME PUMPED 1182 BBL, TOTAL PROPPANT PLACED 204052 LB, 100 MESH 3000 LB, 16/20 201052 LB, AVG SURFACE PSI 1888, AVG BHP 3626 PSI, AVG RATE 20.3 BPM Rig: HES Frac Equipment RIG RELEASE DATE 5/30/2025 Page 11/29 3T-730 Report Printed: 7/1/2025 Operations Summary (with Timelog Depths) Job: INITIAL COMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 5/31/2025 15:00 5/31/2025 16:15 1.25 COMPZN, STIM PUMP P LAUNCHED DART 5 FOR STAGE 6 @ 7775 JSV, LANDED 8 BBL EARLY @ 7940 JSV, SURFACE PEAK 3823 PSI, SURFACE DIFFERENTIAL 2042 PSI, BHP PEAK 5332 PSI, BHP DIFFERENTIAL 2145 PSI, TOTAL CLEAN VOLUME PUMPED 1332 BBL, TOTAL PROPPANT PLACED 202611 LB, 100 MESH 3000 LB, 16/20 199611 LB, AVG SURFACE PSI 1759, AVG BHP 3503 PSI, AVG RATE 19.96 BPM 5/31/2025 16:15 5/31/2025 16:15 COMPZN, STIM PUMP P ISIP-2738 PSI 5 MIN-2728 PSI 10 MIN-2719 PSI 15 MIN-2712 PSI FREEZE PROTECT TUBING, 31 BBLS DIESEL 5/31/2025 16:15 5/31/2025 16:15 COMPZN, STIM PUMP P EQUIPMENT MAINTNENACE, PICKUP CHEMICALS, SPOT CHECK IRON FOR WEAR, LOAD CHEMICALS. 6/1/2025 00:00 6/1/2025 06:30 6.50 COMPZN, STIM WAIT P MIX CHEMICALS, START EQUIPMENT FOR DAY SHIFT, WATER TESTING, LOAD PROPPANT, LOAD/HEAT SW 6/1/2025 06:30 6/1/2025 07:00 0.50 COMPZN, STIM WAIT P PJSM 6/1/2025 07:00 6/1/2025 11:00 4.00 COMPZN, STIM WAIT T BLENDER ISSUE - CAN BUS MOD NOT COMMUNICATING WITH ENGINE ECU. TRIPS RIG SAVER, DECK ENGINE WILL NOT START RIG OUT AND SWAP BLENDERS 6/1/2025 11:00 6/1/2025 11:52 0.88 COMPZN, STIM WAIT P FLOOD/PRIME EQUIPMENT, BUCKET TEST LA'S, HIGH CAL /LOW CAL DENSOMETER, FUNCTION TEST ePRV'S PT MAX-9450 PT 5 MIN-9311 VERIFY AND LOAD DARTS. MIX GEL AND PULL CHEMICALS ON BLENDER 6/1/2025 11:52 6/1/2025 13:04 1.20 COMPZN, STIM PUMP P EQUALIZE TO 1200 PSI, OPEN AT 511 PSI ESTABLISH RATE TO 20 BPM LAUNCHED DART 6 FOR STAGE 7 @ 22 JSV, LANDED 9 BBL EARLY @ 178 JSV, SURFACE PEAK 3644 PSI, SURFACE DIFFERENTIAL 1718 PSI, BHP PEAK 5107 PSI, BHP DIFFERENTIAL PSI, 1821 TOTAL CLEAN VOLUME PUMPED 1179 BBL, TOTAL PROPPANT PLACED 202483 LB, 100 MESH 3000 LB, 16/20 199483 LB, AVG SURFACE PSI 1780, AVG BHP 3478 PSI, AVG RATE 20.1 BPM Rig: HES Frac Equipment RIG RELEASE DATE 5/30/2025 Page 12/29 3T-730 Report Printed: 7/1/2025 Operations Summary (with Timelog Depths) Job: INITIAL COMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 6/1/2025 13:04 6/1/2025 14:14 1.16 COMPZN, STIM PUMP P LAUNCHED DART 7 FOR STAGE 8 @ 1404 JSV, LANDED 7 BBL EARLY @ 1555 JSV, SURFACE PEAK 4999 PSI, SURFACE DIFFERENTIAL 3231 PSI, BHP PEAK 6387 PSI, BHP DIFFERENTIAL 3284 PSI, TOTAL CLEAN VOLUME PUMPED 1192 BBL, TOTAL PROPPANT PLACED 203256 LB, 100 MESH 3000 LB, 16/20 200256 LB, AVG SURFACE PSI 1733, AVG BHP 3425 PSI, AVG RATE 20.2 BPM 6/1/2025 14:14 6/1/2025 15:24 1.16 COMPZN, STIM PUMP P LAUNCHED DART 8 FOR STAGE 9 @ 2819 JSV, LANDED 6 BBL EARLY @ 2963 JSV, SURFACE PEAK 4208 PSI, SURFACE DIFFERENTIAL 2534 PSI, BHP PEAK 5671 PSI, BHP DIFFERENTIAL 2634 PSI, TOTAL CLEAN VOLUME PUMPED 1178 BBL, TOTAL PROPPANT PLACED 202816 LB, 100 MESH 3000 LB, 16/20 199816 LB, AVG SURFACE PSI 1740, AVG BHP 3455 PSI, AVG RATE 20.2 BPM 6/1/2025 15:24 6/1/2025 16:35 1.19 COMPZN, STIM PUMP P LAUNCHED DART 9 FOR STAGE 10 @ 4220 JSV, LANDED 7 BBL EARLY @ 4356 JSV, SURFACE PEAK 4146 PSI, SURFACE DIFFERENTIAL 2475 PSI, BHP PEAK 5821 PSI, BHP DIFFERENTIAL 2756 PSI, TOTAL CLEAN VOLUME PUMPED 1219 BBL, TOTAL PROPPANT PLACED 203045 LB, 100 MESH 3000 LB, 16/20 200045 LB, AVG SURFACE PSI 1676, AVG BHP 3361 PSI, AVG RATE 20.2 BPM 6/1/2025 16:35 6/1/2025 17:44 1.15 COMPZN, STIM PUMP P LAUNCHED DART 10 FOR STAGE 11 @ 5664 JSV, LANDED 5 BBL EARLY @ 5794 JSV, SURFACE PEAK 3398 PSI, SURFACE DIFFERENTIAL 1734 PSI, BHP PEAK 4741 PSI, BHP DIFFERENTIAL 1680 PSI, TOTAL CLEAN VOLUME PUMPED 1196 BBL, TOTAL PROPPANT PLACED 202098 LB, 100 MESH 3000 LB, 16/20 199098 LB, AVG SURFACE PSI 1565, AVG BHP 3270 PSI, AVG RATE 20.4 BPM 6/1/2025 17:44 6/1/2025 18:44 1.00 COMPZN, STIM PUMP P LAUNCHED DART 11 FOR STAGE 12 @ 7082 JSV, LANDED 5 BBL EARLY @ 7204 JSV, SURFACE PEAK 2950 PSI, SURFACE DIFFERENTIAL 1349 PSI, BHP PEAK 4418 PSI, BHP DIFFERENTIAL 1376 PSI, TOTAL CLEAN VOLUME PUMPED 1038 BBL, TOTAL PROPPANT PLACED 152999 LB, 100 MESH 3000 LB, 16/20 149999 LB, AVG SURFACE PSI 1565, AVG BHP 3275 PSI, AVG RATE 20.5 BPM 6/1/2025 18:44 6/1/2025 19:26 0.70 COMPZN, STIM PUMP P ISIP-2774 PSI 5 MIN-2756 PSI 10 MIN-2745 PSI 15 MIN-2738 PSI FREEZE PROTECT TUBING, 31 BBL DIESEL 6/1/2025 19:26 6/1/2025 23:59 4.55 COMPZN, STIM WAIT P PUMP MAINTENANCE, SWAP GEL BULKER, SPOT CHECK IRON FOR WEAR Rig: HES Frac Equipment RIG RELEASE DATE 5/30/2025 Page 13/29 3T-730 Report Printed: 7/1/2025 Operations Summary (with Timelog Depths) Job: INITIAL COMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 6/2/2025 00:00 6/2/2025 06:30 6.50 COMPZN, STIM WAIT P SPOT CHECK HARDLINE FOR WEAR AT CONNECTIONS, COMPLETE PUMP MAINTENANCE, START EQUIPMENT FOR DAY SHIFT, LOAD PROPPANT, LOAD/HEAT SW 6/2/2025 06:30 6/2/2025 07:00 0.50 COMPZN, STIM WAIT P PJSM 6/2/2025 07:00 6/2/2025 08:15 1.25 COMPZN, STIM WAIT P BUCKET TEST LA'S, HIGH CAL/LOW CAL DENSOMETER, FLOOD/PRIME EQUIPMENT, FUNCTION TEST ePRV'S, PT MAX 9420, PT 5 MIN 9309 PSI. GOOD TEST GREASE TREE AND LAUNCH VALVES LOAD CHEMICALS ON BLENDER/MIX GEL, VERIFY AND LOAD DARTS 6/2/2025 08:15 6/2/2025 10:27 2.20 COMPZN, STIM PUMP P EQUALIZE TO 420 PSI, OPEN AT 440 PSI ESTABLISH RATE TO 10 BPM, STAGE INTO DFIT LAUNCHED DART 12 FOR STAGE 13 @ 22 JSV, LANDED 8 BBL EARLY @ 143 JSV, SURFACE PEAK 3844 PSI, SURFACE DIFFERENTIAL 2456 PSI, BHP PEAK 5582 PSI, BHP DIFFERENTIAL 2598 PSI PERFORMED DFIT AT 10 BPM, SHUT IN MONITOR PSI FOR 1 HR. CLOSURE 2467 PSI TOTAL CLEAN VOLUME PUMPED 1061 BBL, TOTAL PROPPANT PLACED 152878 LB, 100 MESH 3000 LB, 16/20 149878 LB, AVG SURFACE PSI 1469, AVG BHP 3146 PSI, AVG RATE 20.2 BPM 6/2/2025 10:27 6/2/2025 11:33 1.10 COMPZN, STIM PUMP P LAUNCHED DART 13 FOR STAGE 14 @ 1230 JSV, LANDED 5 BBL EARLY @ 1339 JSV, SURFACE PEAK 4322 PSI, SURFACE DIFFERENTIAL 2803 PSI, BHP PEAK 5929 PSI, BHP DIFFERENTIAL 2970 PSI, TOTAL CLEAN VOLUME PUMPED 927 BBL, TOTAL PROPPANT PLACED 153269 LB, 100 MESH 3000 LB, 16/20 150269 LB, AVG SURFACE PSI 1408, AVG BHP 3085 PSI, AVG RATE 20.2 BPM 6/2/2025 11:33 6/2/2025 12:27 0.90 COMPZN, STIM PUMP P LAUNCHED DART 14 FOR STAGE 15 @ 2325 JSV, LANDED 4 BBL EARLY @ 2426 JSV, SURFACE PEAK 3832 PSI, SURFACE DIFFERENTIAL 2413 PSI, BHP PEAK 4847 PSI, BHP DIFFERENTIAL 1946 PSI, TOTAL CLEAN VOLUME PUMPED 917 BBL, TOTAL PROPPANT PLACED 152114 LB, 100 MESH 3000 LB, 16/20 149114 LB, AVG SURFACE PSI 1363, AVG BHP 3059 PSI, AVG RATE 20.3 BPM Rig: HES Frac Equipment RIG RELEASE DATE 5/30/2025 Page 14/29 3T-730 Report Printed: 7/1/2025 Operations Summary (with Timelog Depths) Job: INITIAL COMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 6/2/2025 12:27 6/2/2025 13:21 0.90 COMPZN, STIM PUMP P LAUNCHED DART 15 FOR STAGE 16 @ 3409 JSV, LANDED 4 BBL EARLY @ 3503 JSV, SURFACE PEAK 4081 PSI, SURFACE DIFFERENTIAL 2727 PSI, BHP PEAK 5312 PSI, BHP DIFFERENTIAL 2434 PSI, TOTAL CLEAN VOLUME PUMPED 929 BBL, TOTAL PROPPANT PLACED 152976 LB, 100 MESH 3000 LB, 16/20 149976 LB, AVG SURFACE PSI 1508, AVG BHP 3230 PSI, AVG RATE 20.2 BPM 6/2/2025 13:21 6/2/2025 14:15 0.90 COMPZN, STIM PUMP P LAUNCHED DART 16 FOR STAGE 17 @ 4508 JSV, LANDED 4 BBL EARLY @ 4593 JSV, SURFACE PEAK 3992 PSI, SURFACE DIFFERENTIAL 2533 PSI, BHP PEAK 5478 PSI, BHP DIFFERENTIAL 2523 PSI, TOTAL CLEAN VOLUME PUMPED ### BBL, TOTAL PROPPANT PLACED 154315 LB, 100 MESH 3000 LB, 16/20 151315 LB, AVG SURFACE PSI 1294, AVG BHP 2998 PSI, AVG RATE 20.3 BPM 6/2/2025 14:15 6/2/2025 15:00 0.75 COMPZN, STIM PUMP P LAUNCHED DART 17 FOR STAGE 18 @ 5594 JSV, LANDED 0 BBL EARLY @ 5675 JSV, SURFACE PEAK 3105 PSI, SURFACE DIFFERENTIAL 1822 PSI, BHP PEAK 4659 PSI, BHP DIFFERENTIAL 1809 PSI, TOTAL CLEAN VOLUME PUMPED 966 BBL, TOTAL PROPPANT PLACED 152231 LB, 100 MESH 3000 LB, 16/20 149231 LB, AVG SURFACE PSI 1211, AVG BHP 2931 PSI, AVG RATE 19.8 BPM 6/2/2025 15:00 6/2/2025 15:42 0.70 COMPZN, STIM PUMP P ISIP-2775 PSI 5 MIN-2764 PSI 10 MIN-2760 PSI 15 MIN-2755 PSI FREEZE PROTECT TUBING, 31 BBLS DIESEL 6/2/2025 15:42 6/2/2025 23:59 8.29 COMPZN, STIM RURD P BLOW DOWN/CLEAN UP EQUIPMENT, RIG DOWN STAND PIPE, BREAK BACK TREATING LINE IN PREPARATION FOR COIL ON 3T- 731. EQUIPMENT MAINTENANCE 6/3/2025 06:00 6/3/2025 07:00 1.00 COMPZN, STIM TRAV P TRAVEL KCC TO 3T 6/3/2025 07:00 6/3/2025 12:00 5.00 COMPZN, STIM RURD P RIG DOWN DART REVOLVER AND LAUNCHER, NIPPLE DOWN GOADHEAD, REMOVED IRON AROUND WELL. REMOVED IA/OA INTRAGALS AND HARDLINE. 6/13/2025 05:30 6/13/2025 06:15 0.75 TRAV P MORNING MEETING, CONFER w/ CWG, PICK UP WELL FILE, SYNC CPU, TRAVEL TO WLB FOR TOOLS, TRAVEL TO 3T NOTIFY DSO. 6/13/2025 06:15 6/13/2025 08:00 1.75 RURD P ARRIVE AND INSPECT LOCATION, START EQUIPMENT, PJSM, R/U 2.675" RLR (3.5" wheels), TS= RS, QC, 5', QC, KJ, 5', QC, OJ, QC, KJ, LSS (oal= 27'), CHECK RLR PINS AND WHEELS, STACK PCE, AWAIT SCAFFOLDING CREW TO ARRIVE AND INSPECT SCAFFOLDING, STAB ON TO WELL, R/U LRS, PT w/ LRS TO 2500# Rig: HES Frac Equipment RIG RELEASE DATE 5/30/2025 Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 05/31/2025 Job End Date: 06/02/2025 State: Alaska County: Harrison Bay API Number: 50-103-20907-00-00 Operator Name:ConocoPhillips Company/Burlington Resources Well Name and Number: 3T-730 Latitude: 70.420259 Longitude: -150.265952 Datum: NAD27 Federal Well: NO Indian Well: NO True Vertical Depth: 4156 Total Base Water Volume (gal)*: 825971.8 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 LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPT 2002-2054 ResMetrics Tracer OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant In fracfocus.org 07/02/2025 CDW 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 65.35500 None Corundum 1302-74-5 60.00000 18.11433 None Mullite 1302-93-8 40.00000 12.07622 None Sodium chloride 7647-14-5 5.00000 3.43974 None Crystalline silica, quartz 14808-60-7 100.00000 0.50311 None Guar gum 9000-30-0 100.00000 0.21048 None Water 7732-18-5 100.00000 0.19712 None EDTA/Copper chelate Proprietary 30.00000 0.04101 None Ethanol 64-17-5 60.00000 0.03769 None Monoethanolamine borate 26038-87-9 100.00000 0.03397 None Heavy aromatic petroleum naphtha 64742-94-5 30.00000 0.01885 None Oxyalkylated nonyl phenolic resin Proprietary 30.00000 0.01885 None Ammonium persulfate 7727-54-0 100.00000 0.01616 None Sodium hydroxide 1310-73-2 30.00000 0.01475 None Ethylene glycol 107-21-1 30.00000 0.01019 None Ammonium chloride 12125-02-9 5.00000 0.00684 None Oxyalkylated phenolic resin Proprietary 10.00000 0.00628 None Oxylated phenolic resin Proprietary 30.00000 0.00485 None Poly(oxy-1,2-ethanediyl), alpha-(4-nonylphenyl)- omega-hydroxy-, branched 127087-87-0 5.00000 0.00314 None Naphthalene 91-20-3 5.00000 0.00314 None Ammonia 7664-41-7 1.00000 0.00137 None 2-Bromo-2-nitro-1,3- propanediol 52-51-7 100.00000 0.00134 None Glycol Ether Proprietary 85.00000 0.00107 None 1,2,4 Trimethylbenzene 95-63-6 1.00000 0.00063 None Sodium chloride 7647-14-5 1.00000 0.00049 None Confidential Proprietary 20.00000 0.00038 None Ethylene Glycol 107-21-1 20.00000 0.00026 None C.I. pigment Orange 5 3468-63-1 1.00000 0.00016 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) Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-05-31 Alaska HARRISON BAY 50-103-20907-00-00 CONOCOPHILLIPS 3T 730 -150.26909532 70.41994878 NAD83 none Oil 4200 825971.8 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 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 OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%65.35500%7037280 Corundum 1302-74-5 60.00%18.11433%1950511 Mullite 1302-93-8 40.00%12.07622%1300341 Sodium chloride 7647-14-5 5.00%3.43974%370384 Crystalline silica, quartz 14808-60-7 100.00%0.50311%54174 Guar gum 9000-30-0 100.00%0.21048%22664 Water 7732-18-5 100.00%0.19712%21226 EDTA/Copper chelate Proprietary 30.00%0.04101%4417 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%0.03769%4059 Monoethanolamine borate 26038-87-9 100.00%0.03397%3658 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01885%2030 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01885%2030 Ammonium persulfate 7727-54-0 100.00%0.01616%1740 Sodium hydroxide 1310-73-2 30.00%0.01475%1589 Ethylene glycol 107-21-1 30.00%0.01019%1098 Ammonium chloride 12125-02-9 5.00%0.00684%737 Oxyalkylated phenolic resin Proprietary 10.00%0.00628%677 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxylated phenolic resin Proprietary 30.00%0.00485%522 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Naphthalene 91-20-3 5.00%0.00314%339 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00314%339 Ammonia 7664-41-7 1.00%0.00137%148 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00134%144 Glycol Ether Proprietary 85.00%0.00107%116 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00063%68 Sodium chloride 7647-14-5 1.00%0.00049%53 Confidential Proprietary 20.00%0.00038%42 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ethylene Glycol 107-21-1 20.00%0.00026%29 C.I. pigment Orange 5 3468-63-1 1.00%0.00016%18 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%4 * 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: Sales Order# Prepared By: William Martin Derek Osselburn Nanook Crew 0910106491 Intervals 1-18 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. 3T-730 Conoco Phillips Harrison Bay County, AK Post Job Report Stimulation Treatment API: 50-103-20907 Prepared for: Madeline Woodard June 2, 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 Interval 17 Plots Interval 18 Plots Appendix Well Summary Chemical Summary Planned Design Water Straps 5.31 Water Straps 6.1 Water Straps 6.2 Water Analysis 5.31 Water Analysis 6.1 Water Analysis 6.2 Real-Time QC Event Log 5.31 Event Log 6.1 Event Log 6.2 Prejob Break 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 14 Zone 15 Zone 16 Zone 17 Zone 18 Sand Sieve Analysis 101 - 104 97 - 100 3 4 - 7 8 44 - 47 48 - 51 52 - 55 9 - 27 28 29 - 39 40 - 43 56 - 59 60 - 67 88 - 96 68 - 71 72 - 75 76 - 79 80 - 83 84 - 87 105 - 108 109 - 112 113 - 116 117 118 119 120 - 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 151 152 146 147 148 149 150 Conoco Phillips - 3T-730 TOC 2 794,205 gallons of 27# Delta Frac 88,525 gallons of 27# Linear 8,452 gallons of Seawater 6,780 gallons of Freeze Protect 3,250,000 pounds of Wanli 16/20 Ceramic 54,000 pounds of 100M 787,058 gallons of 27# Delta Frac 74,000 gallons of 27# Linear 8,386 gallons of Seawater 5,208 gallons of Freeze Protect 3,250,851 pounds of Wanli 16/20 Ceramic 54,000 pounds of 100M Thank you, 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 May 31, 2025 a stimulation treatment was performed in the Coyote formation on the 3T-730 well in Harrison Bay County, AK. The 3T-730 was a 18 stage Horizontal Sleeve Design. The proposed treatment consisted of: The actual treatment fully completed 18 of 18 stages. 0 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: The alpha sleeve could not be opened in pre-frac operations so Interval 1 was pumped through perforations. All darts shifted as programmed and all intervals were pumped to completion. In interval 4, after briefly pumping 16/20 at 2ppg, the sand screws were cut and the well flushed to repair the ADP. Upon resuming interval 4, pad was pumped again and the interval was pumped to completion. 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. MO-67 was pumped raw from the downhole blender. William Martin Senior Technical Professional Conoco Phillips - 3T-730 Executive Summary 3 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDEBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE 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 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In-1-2 Freeze Protect Prime Up Pressure Test 5.0 1,000 1,008 24 241-3 Shut-In Shut-In-1-4 27# Linear DFIT 10.0 840 1,039 25 25 1.00 2.00 27.00 2.00 0.151-5 Shut-In Shut-In-1-6 27# Linear Step Rate Test 15.0 8,400 2,332 56 56 1.00 2.00 27.00 2.00 0.151-7 27# Delta Frac Establish Stable Fluid 15.0 8,400 3,463 82 82 0.45 1.00 0.65 2.00 27.00 2.00 0.151-8 27# Delta Frac Pad 20.0 8,930 8,463 202 202 0.45 1.00 0.65 2.00 27.00 2.00 0.151-9 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,971 142 145 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.151-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,578 61 66 5,200 4,760 0.45 1.00 0.65 2.00 27.00 2.00 0.151-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,210 100 117 17,000 16,198 0.45 1.00 0.65 2.00 27.00 2.00 0.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,124 98 124 24,900 24,575 0.45 1.00 0.65 2.00 27.00 2.00 0.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,473 154 201 45,500 44,258 0.45 1.00 0.65 2.00 27.00 2.00 0.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,768 137 186 46,400 46,299 0.45 1.00 0.65 2.00 27.00 2.00 0.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,976 95 133 36,000 36,266 0.45 1.00 0.65 2.00 27.00 2.00 0.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,232 101 131 25,000 28,825 0.45 1.00 0.65 2.00 27.00 2.00 0.151-17 27# Linear Spacer and Dart Drop 20.0 1,470 1,201 29 29 1.00 2.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20.0 2,100 1,489 35 35 1.00 2.00 27.00 2.00 0.152-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 975 23 23 0.45 1.00 0.65 2.00 27.00 2.00 0.152-3 27# Delta Frac Pad 20.0 8,930 8,549 204 204 0.45 1.00 0.65 2.00 27.00 2.00 0.152-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,980 142 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.152-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,580 61 66 5,200 4,766 0.45 1.00 0.65 2.00 27.00 2.00 0.152-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,228 101 119 17,000 17,105 0.45 1.00 0.65 2.00 27.00 2.00 0.152-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,116 98 125 24,900 25,338 0.45 1.00 0.65 2.00 27.00 2.00 0.152-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,460 154 202 45,500 45,461 0.45 1.00 0.65 2.00 27.00 2.00 0.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,773 137 186 46,400 45,896 0.45 1.00 0.65 2.00 27.00 2.00 0.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,973 95 133 36,000 35,827 0.45 1.00 0.65 2.00 27.00 2.00 0.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,064 97 119 25,000 21,245 0.45 1.00 0.65 2.00 27.00 2.00 0.152-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,186 28 28 1.00 2.00 27.00 2.00 0.153-1 27# Linear Pre-Pad 20.0 2,100 1,815 43 43 1.00 2.00 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,076 26 26 0.45 1.00 0.65 2.00 27.00 2.00 0.153-3 27# Delta Frac Pad 20.0 8,930 8,590 205 205 0.45 1.00 0.65 2.00 27.00 2.00 0.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,993 143 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,782 66 72 5,200 5,147 0.45 1.00 0.65 2.00 27.00 2.00 0.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,224 101 117 17,000 15,695 0.45 1.00 0.65 2.00 27.00 2.00 0.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,125 98 124 24,900 24,695 0.45 1.00 0.65 2.00 27.00 2.00 0.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,467 154 202 45,500 45,048 0.45 1.00 0.65 2.00 27.00 2.00 0.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,766 137 186 46,400 46,219 0.45 1.00 0.65 2.00 27.00 2.00 0.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,972 95 133 36,000 36,510 0.45 1.00 0.65 2.00 27.00 2.00 0.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,249 101 130 25,000 27,344 0.45 1.00 0.65 2.00 27.00 2.00 0.153-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,193 28 28 1.00 2.00 27.00 2.00 0.154-1 27# Linear Pre-Pad 20.0 2,100 1,602 38 38 1.00 2.00 27.00 2.00 0.154-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,167 28 28 0.45 1.00 0.65 2.00 27.00 2.00 0.154-3 27# Delta Frac Pad 20.0 8,930 8,851 211 211 0.45 1.00 0.65 2.00 27.00 2.00 0.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,975 142 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.154-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 1,605 38 39 892 0.45 1.00 0.65 2.00 27.00 2.00 0.154-6 Seawater Flush 10.0 8,452 8,386 200 2000.154-7 Shut-In Shut-In-4-8 27# Delta Frac Establish Stable Fluid 15.0 8,400 1,564 37 37 0.45 1.00 0.65 2.00 27.00 2.00 0.154-9 27# Delta Frac Pad 20.0 14,930 14,676 349 349 0.45 1.00 0.65 2.00 27.00 2.00 0.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,573 61 66 5,200 4,653 0.45 1.00 0.65 2.00 27.00 2.00 0.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,199 100 117 17,000 16,413 0.45 1.00 0.65 2.00 27.00 2.00 0.154-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,126 98 124 24,900 24,703 0.45 1.00 0.65 2.00 27.00 2.00 0.154-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,469 154 202 45,500 44,750 0.45 1.00 0.65 2.00 27.00 2.00 0.154-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,777 138 187 46,400 46,524 0.45 1.00 0.65 2.00 27.00 2.00 0.154-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,983 95 133 36,000 35,767 0.45 1.00 0.65 2.00 27.00 2.00 0.154-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,097 98 126 25,000 27,075 0.45 1.00 0.65 2.00 27.00 2.00 0.154-17 27# Linear Spacer and Dart Drop 20.0 1,470 1,151 27 27 1.00 2.00 27.00 2.00 0.155-1 27# Linear Pre-Pad 20.0 2,100 1,659 40 40 1.00 2.00 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 757 18 18 0.45 1.00 0.65 2.00 27.00 2.00 0.155-3 27# Delta Frac Pad 20.0 8,930 8,663 206 206 0.45 1.00 0.65 2.00 27.00 2.00 0.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,978 142 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,573 61 67 5,200 4,934 0.45 1.00 0.65 2.00 27.00 2.00 0.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,216 100 118 17,000 16,387 0.45 1.00 0.65 2.00 27.00 2.00 0.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,118 98 124 24,900 24,456 0.45 1.00 0.65 2.00 27.00 2.00 0.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,466 154 202 45,500 45,182 0.45 1.00 0.65 2.00 27.00 2.00 0.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,776 138 186 46,400 45,766 0.45 1.00 0.65 2.00 27.00 2.00 0.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,972 95 133 36,000 35,999 0.45 1.00 0.65 2.00 27.00 2.00 0.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,293 102 132 25,000 28,325 0.45 1.00 0.65 2.00 27.00 2.00 0.155-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,160 28 28 1.00 2.00 27.00 2.00 0.156-1 27# Linear Pre-Pad 15.0 2,100 1,910 45 45 1.00 2.00 27.00 2.00 0.156-2 27# Delta Frac Establish Stable Fluid 15.0 2,100 605 14 14 0.45 1.00 0.65 2.00 27.00 2.00 0.156-3 27# Delta Frac Pad 20.0 8,930 8,755 208 208 0.45 1.00 0.65 2.00 27.00 2.00 0.156-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,983 142 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.156-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,755 66 72 5,200 6,112 0.45 1.00 0.65 2.00 27.00 2.00 0.156-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,230 101 119 17,000 17,134 0.45 1.00 0.65 2.00 27.00 2.00 0.156-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,148 99 125 24,900 25,088 0.45 1.00 0.65 2.00 27.00 2.00 0.156-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,469 154 202 45,500 45,462 0.45 1.00 0.65 2.00 27.00 2.00 0.156-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,774 137 187 46,400 46,458 0.45 1.00 0.65 2.00 27.00 2.00 0.156-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,968 94 133 36,000 35,838 0.45 1.00 0.65 2.00 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 3,641 87 112 25,000 23,410 0.45 1.00 0.65 2.00 27.00 2.00 0.156-12 27# Linear Flush 20.0 7,680 7,690 183 183 1.00 2.00 27.00 2.00 0.156-13 Freeze Protect Freeze Protect 20.0 1,260 630 15 156-14 Shut-In Shut-In 5.0-Interval 1Coyote@ 13891.01 - 13895.01 ft 104.8 °FInterval 2Coyote@ 13348 - 13352 ft 104.9 °FInterval 3Coyote@ 12850.49 - 12854.49 ft 104.9 °FInterval 4Coyote@ 12433.91 - 12437.91 ft 104.9 °FInterval 6Coyote@ 11357.75 - 11361.75 ft 104.9 °FInterval 5Coyote@ 11892.86 - 11896.86 ft 104.9 °FLiquid Additives Dry Additives50-103-209070910106491Conoco Phillips - 3T-730Actual Design4 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDEBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE 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 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-2090709101064917-1 Shut-In Shut-In-7-2 Freeze Protect Prime Up Pressure Test 5.0 1,000 1,050 25 257-3 Shut-In Shut-In-7-4 27# Linear Spacer and Dart Drop 15.0 1,260 1,230 29 29 1.00 2.00 27.00 2.00 0.157-5 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,131 27 27 0.45 1.00 0.65 2.00 27.00 2.00 0.157-6 27# Delta Frac Pad 20.0 8,930 8,686 207 207 0.45 1.00 0.65 2.00 27.00 2.00 0.157-7 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,979 142 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,857 68 75 5,200 6,880 0.45 1.00 0.65 2.00 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,229 101 118 17,000 16,126 0.45 1.00 0.65 2.00 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,120 98 124 24,900 24,066 0.45 1.00 0.65 2.00 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,477 154 203 45,500 45,523 0.45 1.00 0.65 2.00 27.00 2.00 0.157-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,781 138 187 46,400 46,798 0.45 1.00 0.65 2.00 27.00 2.00 0.157-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,969 95 133 36,000 36,438 0.45 1.00 0.65 2.00 27.00 2.00 0.157-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 3,957 94 119 25,000 23,575 0.45 1.00 0.65 2.00 27.00 2.00 0.157-15 27# Linear Spacer and Dart Drop 20.0 1,470 1,104 26 26 1.00 2.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20.0 2,100 1,723 41 41 1.00 2.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,119 27 27 0.45 1.00 0.65 2.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20.0 8,930 8,734 208 208 0.45 1.00 0.65 2.00 27.00 2.00 0.158-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,006 143 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.158-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,576 61 68 5,200 6,539 0.45 1.00 0.65 2.00 27.00 2.00 0.158-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,246 101 119 17,000 16,894 0.45 1.00 0.65 2.00 27.00 2.00 0.158-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,105 98 123 24,900 24,036 0.45 1.00 0.65 2.00 27.00 2.00 0.158-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,488 154 203 45,500 45,236 0.45 1.00 0.65 2.00 27.00 2.00 0.158-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,777 138 187 46,400 46,376 0.45 1.00 0.65 2.00 27.00 2.00 0.158-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,966 94 133 36,000 36,169 0.45 1.00 0.65 2.00 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,114 98 124 25,000 24,994 0.45 1.00 0.65 2.00 27.00 2.00 0.158-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,210 29 29 1.00 2.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20.0 2,100 1,759 42 42 1.00 2.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 693 17 17 0.45 1.00 0.65 2.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20.0 8,930 8,671 206 206 0.45 1.00 0.65 2.00 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,980 142 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,584 62 68 5,200 6,524 0.45 1.00 0.65 2.00 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,269 102 120 17,000 17,117 0.45 1.00 0.65 2.00 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,131 98 124 24,900 24,137 0.45 1.00 0.65 2.00 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,479 154 202 45,500 45,265 0.45 1.00 0.65 2.00 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,775 138 187 46,400 47,009 0.45 1.00 0.65 2.00 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,978 95 133 36,000 36,345 0.45 1.00 0.65 2.00 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,013 96 120 25,000 23,427 0.45 1.00 0.65 2.00 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,160 28 28 1.00 2.00 27.00 2.00 0.1510-1 27# Linear Pre-Pad 20.0 2,100 1,662 40 40 1.00 2.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 2,624 62 62 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-3 27# Delta Frac Pad 20.0 8,930 8,547 204 204 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,974 142 145 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,571 61 68 5,200 6,694 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,236 101 119 17,000 17,002 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,142 99 125 24,900 24,535 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,483 154 202 45,500 44,923 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,782 138 187 46,400 46,610 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,981 95 133 36,000 36,295 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 4,023 96 121 25,000 23,973 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,164 28 28 1.00 2.00 27.00 2.00 0.1511-1 27# Linear Pre-Pad 20.0 2,100 2,009 48 48 1.00 2.00 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,128 27 27 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-3 27# Delta Frac Pad 20.0 8,930 8,759 209 209 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,107 145 149 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,600 2,572 61 68 5,200 6,784 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,250 4,214 100 118 17,000 16,460 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,150 4,114 98 123 24,900 23,717 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,500 6,467 154 203 45,500 45,857 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,772 137 187 46,400 46,750 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,947 94 132 36,000 35,936 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,500 3,947 94 120 25,000 24,041 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,216 29 29 1.00 2.00 27.00 2.00 0.1512-1 27# Linear Pre-Pad 20.0 2,100 1,825 43 43 1.00 2.00 27.00 2.00 0.1512-2 27# Delta Frac Establish Stable Fluid 15.0 2,100 1,673 40 40 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-3 27# Delta Frac Pad 20.0 5,165 5,072 121 121 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,129 146 149 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 1,971 47 53 4,000 5,508 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,185 76 90 12,800 12,989 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,089 74 93 18,600 18,428 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,780 114 150 33,600 34,294 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,314 103 141 34,800 35,733 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,971 71 100 27,000 27,190 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 2,789 66 83 19,200 15,430 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-12 27# Linear Flush 20.0 5,773 5,781 138 138 1.00 2.00 27.00 2.00 0.1512-13 Freeze Protect Freeze Protect 5.0 1,260 840 20 2012-14 Shut-In Shut-In-Interval 7Coyote@ 10862.44 - 10866.44 ft 104.9 °FInterval 8Coyote@ 10365.57 - 10369.57 ft 104.9 °FInterval 9Coyote@ 9866.92 - 9870.92 ft 104.9 °FInterval 10Coyote@ 9368.4 - 9372.4 ft 104.9 °FInterval 11Coyote@ 8872.95 - 8876.95 ft 104.9 °FInterval 12Coyote@ 8374.76 - 8378.76 ft 104.8 °FConoco Phillips - 3T-730Actual Design5 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDEBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE 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 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-20907091010649113-1 Shut-In Shut-In-13-2 Freeze Protect Prime Up Pressure Test 5.0 1,000 840 20 2013-3 Shut-In Shut-In-13-4 27# Linear Spacer and Dart Drop 10.0 1,260 1,091 26 26 1.00 2.00 27.00 2.00 0.1513-5 27# Linear Displacement 15.0 5,087 4,975 118 118 1.00 2.00 27.00 2.00 0.1513-6 27# Linear DFIT 10.0 840 837 20 20 1.00 2.00 27.00 2.00 0.1513-7 27# Delta Frac Shut-In- 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-8 27# Delta Frac Establish Stable Fluid 20.0 2,100 2,022 48 48 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-9 27# Delta Frac Pad 20.0 5,165 4,880 116 116 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-10 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,974 142 145 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 1,970 47 52 4,000 5,222 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,179 76 90 12,800 13,209 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,066 73 93 18,600 18,481 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,802 114 151 33,600 34,967 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,322 103 140 34,800 34,835 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,962 71 99 27,000 26,420 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 3,311 79 97 19,200 16,735 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-18 27# Linear Spacer and Dart Drop 20.0 1,470 1,183 28 28 1.00 2.00 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20.0 2,100 1,970 47 47 1.00 2.00 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 953 23 23 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-3 27# Delta Frac Pad 20.0 5,165 5,063 121 121 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,971 142 145 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 1,971 47 52 4,000 4,879 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,191 76 90 12,800 12,809 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,077 73 92 18,600 17,945 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,789 114 149 33,600 33,113 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,330 103 141 34,800 35,501 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,968 71 99 27,000 26,998 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 3,474 83 103 19,200 19,014 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,164 28 28 1.00 2.00 27.00 2.00 0.1515-1 27# Linear Pre-Pad 20.0 2,100 2,072 49 49 1.00 2.00 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 582 14 14 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-3 27# Delta Frac Pad 20.0 5,165 5,023 120 120 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,992 143 146 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 2,020 48 53 4,000 4,697 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,265 78 91 12,800 12,795 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,101 74 93 18,600 17,663 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,776 114 150 33,600 34,019 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,319 103 141 34,800 36,132 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,968 71 100 27,000 27,494 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 3,169 75 93 19,200 16,301 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,209 29 29 1.00 2.00 27.00 2.00 0.1516-1 27# Linear Pre-Pad 20.0 2,100 1,903 45 45 1.00 2.00 27.00 2.00 0.1516-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,196 28 28 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-3 27# Delta Frac Pad 20.0 5,165 5,091 121 121 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,087 145 148 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 2,228 53 58 4,000 5,072 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,197 76 89 12,800 12,408 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,060 73 93 18,600 18,502 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,771 114 150 33,600 34,613 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,322 103 141 34,800 36,312 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,967 71 101 27,000 28,288 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 2,986 71 87 19,200 14,773 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,210 29 29 1.00 2.00 27.00 2.00 0.1517-1 27# Linear Pre-Pad 20.0 2,100 2,063 49 49 1.00 2.00 27.00 2.00 0.1517-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 541 13 13 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-3 27# Delta Frac Pad 20.0 5,165 5,065 121 121 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,957 142 145 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 1,970 47 52 4,000 4,629 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,204 76 90 12,800 13,286 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,078 73 93 18,600 18,898 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,817 115 152 33,600 35,226 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,318 103 139 34,800 34,547 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,970 71 99 27,000 26,969 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 3,352 80 99 19,200 17,837 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,196 28 28 1.00 2.00 27.00 2.00 0.1518-1 27# Linear Pre-Pad 20.0 2,100 1,975 47 47 1.00 2.00 27.00 2.00 0.1518-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 552 13 13 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-3 27# Delta Frac Pad 20.0 5,165 5,010 119 119 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,971 142 145 3,000 3,000 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,000 1,979 47 52 4,000 4,659 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 3,200 3,130 75 88 12,800 12,355 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 3,100 3,071 73 92 18,600 18,020 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 4,800 4,770 114 150 33,600 34,038 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 4,350 4,381 104 143 34,800 36,132 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 3,000 2,967 71 100 27,000 27,273 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,920 2,905 69 87 19,200 16,748 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-12 27# Linear Flush 20.0 3,835 3,882 92 92 1.00 2.00 27.00 2.00 0.1518-13 Freeze Protect Freeze Protect 5.0 1,260 840 20 2018-14 Shut-In Shut-In-Interval 17Coyote@ 5841.59 - 5845.59 ft 104.7 °FInterval 16Coyote@ 6424.06 - 6428.06 ft 104.7 °FInterval 13Coyote@ 7958.84 - 7962.84 ft 104.8 °FInterval 14Coyote@ 7460.08 - 7464.08 ft 104.8 °FInterval 18Coyote@ 5342.06 - 5346.06 ft 104.7 °FInterval 15Coyote@ 6921.94 - 6925.94 ft 104.7 °FConoco Phillips - 3T-730Actual Design6 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDEBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE 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 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-209070910106491897,962 874,652 20,825 24,332 3,304,000 3,301,242Design Total (gal)Actual Total (gal)Design Total (lbs)Calculated Total (lbs)Ticket Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6794,205 787,058 3,250,000 3,247,242 3,250,851(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)88,525 74,000 54,000 54,000 54,000 Initial Design Material Volume 357.4 882.7 516.2 1,765.5 23,833.7 1,765.5 133.78,452 8,386 - - - Actual Design Material Volume 354.2 861.1 511.6 1,722.1 23,248.6 1,722.1 130.46,780 5,208 -2310 - - - Physical Material Volume Pumped 360 890 500 1,765 22664 1,740 144- - - - - Physical Material Volume Deviance 2% 3% -2% 2% -3% 1% 10%--** IFS numbers for proppant are taken from software calculations based on multiple variablesMicroMotion Volume Pumped 344 856 494 1,714 22,655 1,717 ---** Proppant is billed from Weight Ticket volumesMicroMotion Volume Deviance -3% -1% -3% 0% -3% 0% -------Fluid Type27# Delta Frac27# LinearSeawaterFreeze Protect-Proppant TypeWanli 16/20 Ceramic100M--Conoco Phillips - 3T-730Actual Design7 Conoco Phillips Coyote3T-73050-103-20907*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 14,036 8,972 8,430Total14,0368,972ft1.08ft105.0ftft1.08ft104.9ftTop 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)Toe13,891 13,895 4,1511Coyote104.8-------------13,348 13,352 4,1532Coyote104.99:38:55 AM 9:48:15 AM 1,507 1,710 1,7019.11,883 4,212 2,329 3,258 5,270 2,012 20.612,850 12,8544,1543Coyote104.910:48:43 AM 10:57:38 AM 2,908 3,104 3,0958.61,792 3,989 2,197 3,194 5,530 2,336 20.612,43412,438 4,1554Coyote104.911:59:07 AM 12:07:43 PM 4,329 4,518 4,5099.21,801 4,004 2,203 3,201 5,097 1,896 20.911,893 11,897 4,1565Coyote104.91:57:12 PM 2:05:26 PM 6,369 6,550 6,5419.01,849 3,709 1,860 3,246 5,213 1,967 20.911,358 11,362 4,1566Coyote104.93:06:41 PM 3:14:31 PM 7,776 7,949 7,9399.91,781 3,823 2,042 3,187 5,332 2,145 20.510,862 10,866 4,1567Coyote104.911:54:28 AM 12:03:31 PM 22 187 1789.31,926 3,644 1,718 3,286 5,107 1,821 20.410,366 10,370 4,1568Coyote104.91:04:47 PM 1:12:02 PM 1,404 1,562 1,5556.81,768 4,999 3,231 3,103 6,387 3,284 20.89,867 9,871 4,1559Coyote104.92:14:41 PM 2:21:38 PM 2,819 2,969 2,9636.21,674 4,208 2,534 3,037 5,671 2,634 20.59,368 9,372 4,15510Coyote104.93:24:19 PM 3:30:47 PM 4,222 4,365 4,3568.61,671 4,146 2,475 3,065 5,821 2,756 20.78,873 8,877 4,15411Coyote104.94:35:36 PM 4:41:50 PM 5,664 5,799 5,7945.01,664 3,398 1,734 3,061 4,741 1,680 20.98,375 8,379 4,15112Coyote104.85:44:54 PM 5:50:51 PM 7,080 7,207 7,2043.51,601 2,950 1,349 3,042 4,418 1,376 20.97,959 7,963 4,14913Coyote104.88:18:15 AM 8:25:56 AM 22 143 1358.11,388 3,844 2,456 2,984 5,582 2,598 15.57,460 7,464 4,14614Coyote104.810:26:27 AM 10:31:38 AM 1,231 1,345 1,3386.51,519 4,322 2,803 2,959 5,929 2,970 20.76,922 6,926 4,14315Coyote104.711:20:34 AM 11:25:23 AM 2,326 2,431 2,4265.31,419 3,832 2,413 2,901 4,847 1,946 21.06,424 6,428 4,14316Coyote104.712:13:57 PM 12:18:28 PM 3,409 3,507 3,5033.81,354 4,081 2,727 2,878 5,312 2,434 20.95,842 5,846 4,14217Coyote104.71:08:24 PM 1:12:24 PM 4,509 4,598 4,5925.91,459 3,992 2,533 2,955 5,478 2,523 20.9Heel5,342 5,346 4,13618Coyote104.72:01:57 PM 2:05:44 PM 5,597 5,678 5,6753.31,283 3,105 1,822 2,850 4,659 1,809 21.0Temp. Gradient (°F/100 ft)BHST (°F)TVD at Bottom PerfMD at Bottom Perf4,15613,895KOPAvg. TVDTotal MD78910112345617181213141516Sleeve/Perf DepthSleeves121.1113.5105.3Interval #1Max Pressure (psi)8,500Isolation TypeCemented LinerTreatment TubularsCustomerFormationLeaseAPIDateTemperature DataTemp. Gradient (°F/100 ft)BHST (°F)Directional Data4,1512,23714,036Directional Data2,2375/31/2025KOPTemperature Data8,214 195.67,9487,6027,260Displacement to Top Sleeve/Perf (gal)(BBLS)8,879 211.48,532 203.1189.2181.0172.95,3535,0874,7684,4254,1066,9436,6266,3075,9885,6723,7343,415165.3157.8150.2142.6135.0127.597.888.981.3Conoco Phillips - 3T-730 Wellbore Information8 5/31/25 7:41 5/31/25 9:38 118 min -bpm -psi -psi -bbl 21.1 bpm 2,509 psi 4,125 psi 20.0 bpm 2,137 psi 2,010 psi 3,708 psi 1,050 hhp 351 psi 14 psi 17 psi 10.22 ppg 5 5 28 % 27 % 18 cP 89.2 F 8.8 DFIT 9.522 bpm 1431 psi 2963 psi 9.622 bpm 1543 psi 3065 psi 2405 psi 0.579 psi/ft 2346 psi 2302 psi 2248 psi 201,181 lbs 3,000 lbs 204,181 lbs 204,181 lbs Minifrac Max Surface Pressure: 100M Pumped: Final 15 min: Proppant in Formation: Minifrac Max DH Pressure: Final 5 min: Dart/Ball Early : Average pH: Minifrac Average Rate: Pump Time: Pad Percentage Actual Wanli 16/20 Ceramic Pumped: Diagnostic method Average Visc: Average Temp: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Rate: Max Surface Pressure: Max BH Pressure: Interval Summary 3T-730 - Coyote - Interval 1 Interval Summary Start Date/Time: End Date/Time: Average Missile Pressure: Open Well Pressure: Initial OA Pressure: 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: Minifrac Max Rate: ISDP: Final Fracture Gradient: Final 10 min: Proppant Summary Minifrac Average Pressure: Minifrac Average DH Pressure: Total Proppant Pumped* : Conoco Phillips - 3T-730 Interval Summary 9 49,258 gal 1,173 bbls 4,572 gal 109 bbls 1,008 gal 24 bbls 8,463 gal 202 bbls 5,971 gal 142 bbls 31,361 gal 747 bbls 1,201 gal 29 bbls 2,332 gal 56 bbls 3,463 gal 82 bbls 1,039 gal 25 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pad Volume: 27# Delta Frac Volume: 27# Linear Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: A DFIT was pumped through the perforations. Closure was found the be 2,255 psi after analyzing pressure decline for 30 minutes. A SRT was pumped. Interval pumped to completion. DFIT Volume: Freeze Protect Volume: Madeline Woodard Daniel Faur William Martin Fluid Summary (by fluid description) Fluid Summary (by stage description) 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: Cody Strong Derek Osselburn Conoco Phillips - 3T-730 Interval Summary 10 5/31/25 9:38 5/31/25 10:48 70 min 20.6 bpm 4,212 psi 5,270 psi 9 bbl 21.1 bpm 2,404 psi 4,008 psi 20.1 bpm 2,061 psi 1,936 psi 3,663 psi 1,014 hhp 20 psi 20 psi 10.25 ppg 5 5 28 % 27 % 18 cP 90.4 F 8.8 195,638 lbs 3,000 lbs 198,638 lbs 198,638 lbs 46,698 gal 1,112 bbls 2,675 gal 64 bbls 1,489 gal 35 bbls 8,549 gal 204 bbls 5,980 gal 142 bbls 31,194 gal 743 bbls 1,186 gal 28 bbls 975 gal 23 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pad Volume: Pre-Pad Volume: Pad Percentage Design Pad Percentage Actual Proppant in Formation: Fluid Summary (by fluid description) Fluid Summary (by stage description) 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: 3T-730 - 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: Proppant Summary 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: 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.Daniel Faur William Martin Cody Strong Derek Osselburn Madeline Woodard Conoco Phillips - 3T-730 Interval Summary 11 5/31/25 10:48 5/31/25 11:59 70 min 20.6 bpm 3,989 psi 5,530 psi 9 bbl 20.9 bpm 2,377 psi 3,972 psi 20.2 bpm 2,008 psi 1,886 psi 3,609 psi 993 hhp 23 psi 23 psi 10.19 ppg 5 5 28 % 27 % 18 cP 81.8 F 8.8 200,658 lbs 3,000 lbs 203,658 lbs 203,658 lbs 47,244 gal 1,125 bbls 3,008 gal 72 bbls 1,815 gal 43 bbls 8,590 gal 205 bbls 5,993 gal 143 bbls 31,585 gal 752 bbls 1,193 gal 28 bbls 1,076 gal 26 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant Summary Spacer and Dart Drop Volume: Wanli 16/20 Ceramic Pumped: Pad Volume: Interval Summary Average Missile HHP: Average Temp: Average Missile Pressure: Average Surface Pressure: Average BH Pressure: Pumps Starting Stage: Pumps Ending Stage: Average pH: 27# Linear Volume: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Pad Percentage Design Pad Percentage Actual Average Visc: Initial OA Pressure: Initial Surface Pressure (Breakdown): Start Date/Time: 3T-730 - 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: Establish Stable Fluid Volume: 27# Delta Frac Volume: William Martin Cody Strong Derek Osselburn 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. Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) Proppant Laden Fluid Volume: Madeline Woodard Daniel Faur Conoco Phillips - 3T-730 Interval Summary 12 5/31/25 11:59 5/31/25 13:57 118 min 20.9 bpm 4,004 psi 5,097 psi 9 bbl 20.9 bpm 2,361 psi 3,950 psi 20.3 bpm 2,104 psi 1,971 psi 3,657 psi 1,045 hhp 23 psi 23 psi 10.44 ppg 5 5 42 % 41 % 17.7 cP 89.8 F 8.74 200,777 lbs 3,000 lbs 203,777 lbs 203,777 lbs 65,062 gal 1,549 bbls 2,753 gal 66 bbls 8,386 gal 200 bbls 1,602 gal 38 bbls 23,527 gal 560 bbls 5,975 gal 142 bbls 32,829 gal 782 bbls 1,151 gal 27 bbls 8,386 gal 200 bbls 2,731 gal 65 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Spacer and Dart Drop Volume: Fluid Summary (by fluid description) Seawater 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: 27# Delta Frac Volume: 27# Linear Volume: Average Rate: Average Missile Pressure: Average BH Pressure: Average Missile HHP: Pumps Ending Stage: Pad Percentage Actual Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Flush Volume: Interval Summary Start Date/Time: Initial Surface Pressure (Breakdown): End Date/Time: Pump Time: 3T-730 - Coyote - Interval 4 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: Shortly after starting 16/20, the ADP mixing bowl seal ruptured. The well had to be flushed on Seawater. After resuming, pad was pumped again and the normal 16/20 sand stages followed. Interval pumped to completion. Derek Osselburn Pre-Pad Volume: Pad Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Fluid Summary (by stage description) Establish Stable Fluid Volume: Interval Status: Madeline Woodard Daniel Faur William Martin Cody Strong Conoco Phillips - 3T-730 Interval Summary 13 5/31/25 13:57 5/31/25 15:06 69 min 20.9 bpm 3,709 psi 5,213 psi 9 bbl 21.1 bpm 2,466 psi 3,912 psi 20.2 bpm 2,017 psi 1,888 psi 3,626 psi 1,001 hhp 23 psi 23 psi 10.19 ppg 5 5 28 % 27 % 18.11 cP 86.44 F 8.79 201,049 lbs 3,000 lbs 204,049 lbs 204,049 lbs 46,812 gal 1,115 bbls 2,819 gal 67 bbls 1,659 gal 40 bbls 8,663 gal 206 bbls 5,978 gal 142 bbls 31,414 gal 748 bbls 1,160 gal 28 bbls 757 gal 18 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Missile Pressure: Max OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Temp: Initial Surface Pressure (Breakdown): Max Rate: Pump Time: Cody Strong Interval pumped to completion. Pumps Starting Stage: Pumps Ending 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.Madeline Woodard Daniel Faur Derek Osselburn Total Proppant Pumped* : Initial Rate (Breakdown): Pre-Pad Volume: Establish Stable Fluid Volume: 27# Delta Frac Volume: Spacer and Dart Drop Volume: Proppant Laden Fluid Volume: Interval Status: Average pH: Pad Percentage Actual 3T-730 - 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: 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: End Date/Time: Max BH Pressure: Average Surface Pressure: Conoco Phillips - 3T-730 Interval Summary 14 5/31/25 15:06 5/31/25 16:24 78 min 20.5 bpm 3,823 psi 5,332 psi 10 bbl 20.5 bpm 2,771 psi 4,141 psi 20.0 bpm 1,886 psi 1,759 psi 3,503 psi 923 hhp 24 psi 24 psi 10.39 ppg 5 5 28 % 27 % 18 cP 81.11 F 8.82 2738 psi 0.659 psi/ft 2728 psi 886 2719 psi 877 2712 psi 870 199,502 lbs 3,000 lbs 202,502 lbs 202,502 lbs 46,328 gal 1,103 bbls 9,600 gal 229 bbls 630 gal 15 bbls 1,910 gal 45 bbls 8,755 gal 208 bbls 5,983 gal 142 bbls 30,985 gal 738 bbls 7,690 gal 183 bbls 630 gal 15 bbls 605 gal 14 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Max Proppant Concentration: Pad Percentage Actual Proppant Laden Fluid Volume: Freeze Protect Volume: End Date/Time: Max Surface Pressure: Max BH Pressure: Max OA Pressure: Flush Volume: Pad Volume: Wanli 16/20 Ceramic Pumped: Pad Percentage Design Average Temp: Total Proppant Pumped* : Final Fracture Gradient: Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : Initial OA Pressure: Start Date/Time: Average Surface Pressure: Average BH Pressure: 100M Pumped: Pumps Ending Stage: Pre-Pad Volume: Conditioning Pad Volume: Interval Status: Average Visc: 27# Delta Frac Volume: 27# Linear Volume: Proppant in Formation: Interval pumped to completion. Final 15 min: William Martin Cody Strong 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 Daniel Faur 3T-730 - Coyote - Interval 6 Interval Summary Average pH: Final 5 min: Final 10 min: Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Establish Stable Fluid Volume: Pumps Starting Stage: Max Rate: Average Missile Pressure: Freeze Protect Volume: ISDP: Average Rate: Pump Time: Initial Rate (Breakdown): Average Missile HHP: Conoco Phillips - 3T-730 Interval Summary 15 6/1/25 11:51 6/1/25 13:04 73 min 20.4 bpm 3,644 psi 5,107 psi 9 bbl 20.8 bpm 2,145 psi 3,790 psi 20.1 bpm 1,907 psi 1,780 psi 3,478 psi 939 hhp 484 psi 101 psi 105 psi 10.39 ppg 5 4 28 % 27 % 19 cP 90 F 8.9 199,406 lbs 3,000 lbs 202,406 lbs 202,406 lbs 47,186 gal 1,123 bbls 2,334 gal 56 bbls 1,050 gal 25 bbls 8,686 gal 207 bbls 5,979 gal 142 bbls 31,390 gal 747 bbls 2,334 gal 56 bbls 1,131 gal 27 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant in Formation: Proppant Laden Fluid Volume: Average Visc: Average BH Pressure: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Conditioning Pad Volume: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max OA Pressure: Total Proppant Pumped* : Average Temp: Average Missile HHP: Average pH: Max Proppant Concentration: Pad Volume: Spacer and Dart Drop Volume: 3T-730 - Coyote - Interval 7 End Date/Time: Dart/Ball Early : Pad Percentage Actual Initial OA Pressure: Pad Percentage Design Pumps Starting Stage: Proppant Summary Open Well Pressure: Pumps Ending Stage: 100M Pumped: Pump Time: Max Rate: Initial BH Pressure (Breakdown): Start Date/Time: Interval Summary Interval Status: Shortly after dropping the ball, a pump started cavitating causing pressure to bounce. The pump rate was swapped around and the interval was pumped to completion. Fluid Summary (by fluid description) Madeline Woodard 27# Delta Frac Volume: Daniel Faur Establish Stable Fluid Volume: Freeze Protect Volume: William Martin Derek Osselburn Fluid Summary (by stage description) Cody Strong 27# Linear Volume: Conoco Phillips - 3T-730 Interval Summary 16 6/1/25 13:04 6/1/25 14:14 70 min 20.8 bpm 4,999 psi 6,387 psi 7 bbl 20.8 bpm 3,216 psi 4,578 psi 20.2 bpm 1,865 psi 1,733 psi 3,425 psi 925 hhp 105 psi 109 psi 10.33 ppg 4 4 28 % 27 % 20.11 cP 93.44 F 8.83 200,244 lbs 3,000 lbs 203,244 lbs 203,244 lbs 47,131 gal 1,122 bbls 2,933 gal 70 bbls 1,723 gal 41 bbls 8,734 gal 208 bbls 6,006 gal 143 bbls 31,272 gal 745 bbls 1,210 gal 29 bbls 1,119 gal 27 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: After cleaning the screws, A pump started cavitating causing rate and pressure to fluctuate briefly. Interval pumped to completion. Proppant Laden Fluid Volume: Max OA Pressure: Pumps Ending Stage: Max BH Pressure: Dart/Ball Early : End Date/Time: Pump Time: Average pH: Average Surface Pressure: 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. Initial OA Pressure: Average Rate: Max Proppant Concentration: Average BH Pressure: Initial Surface Pressure (Breakdown): Start Date/Time: Initial BH Pressure (Breakdown): Average Missile Pressure: Initial Rate (Breakdown): Max Surface Pressure: Proppant Summary Establish Stable Fluid Volume: Max Rate: Fluid Summary (by fluid description) Interval Summary 3T-730 - Coyote - Interval 8 Pad Volume: Average Visc: Total Proppant Pumped* : 27# Linear Volume: Conditioning Pad Volume: Average Missile HHP: Fluid Summary (by stage description) Pad Percentage Actual Pad Percentage Design Spacer and Dart Drop Volume: Proppant in Formation: Average Temp: Pre-Pad Volume: Wanli 16/20 Ceramic Pumped: 100M Pumped: 27# Delta Frac Volume: Interval Status: William Martin Daniel Faur Cody Strong Derek Osselburn Madeline Woodard Conoco Phillips - 3T-730 Interval Summary 17 6/1/25 14:14 6/1/25 15:24 70 min 20.5 bpm 4,208 psi 5,671 psi 6 bbl 21.0 bpm 3,824 psi 5,156 psi 20.2 bpm 1,877 psi 1,740 psi 3,455 psi 927 hhp 108 psi 111 psi 10.46 ppg 4 4 28 % 27 % 20 cP 92.4 F 8.77 199,824 lbs 3,000 lbs 202,824 lbs 202,824 lbs 46,573 gal 1,109 bbls 2,919 gal 70 bbls 1,759 gal 42 bbls 8,671 gal 206 bbls 5,980 gal 142 bbls 31,229 gal 744 bbls 1,160 gal 28 bbls 693 gal 17 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: Pad Volume: Average Missile HHP: Initial OA Pressure: Average Rate: 100M Pumped: Pad Percentage Actual Max OA Pressure: Interval pumped to completion. Proppant in Formation: Derek Osselburn Average BH Pressure: Average Missile Pressure: 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: Pre-Pad Volume: Establish Stable Fluid Volume: Spacer and Dart Drop Volume: 27# Delta Frac Volume: 27# Linear Volume: 3T-730 - Coyote - Interval 9 Conditioning Pad Volume: Proppant Laden Fluid Volume: Initial BH Pressure (Breakdown): Fluid Summary (by stage description) Average pH: 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 Cody Strong Average Temp: Max Proppant Concentration: Pumps Starting Stage: Average Surface Pressure: Madeline Woodard Daniel Faur Conoco Phillips - 3T-730 Interval Summary 18 6/1/25 15:24 6/1/25 16:34 70 min 20.7 bpm 4,146 psi 5,821 psi 9 bbl 21.0 bpm 2,053 psi 3,686 psi 20.2 bpm 1,816 psi 1,676 psi 3,361 psi 900 hhp 111 psi 111 psi 10.12 ppg 4 4 28 % 27 % 20 cP 90.2 F 8.81 200,032 lbs 3,000 lbs 203,032 lbs 203,032 lbs 48,363 gal 1,152 bbls 2,826 gal 67 bbls 1,662 gal 40 bbls 8,547 gal 204 bbls 5,974 gal 142 bbls 31,218 gal 743 bbls 1,164 gal 28 bbls 2,624 gal 62 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Surface Pressure: Establish Stable Fluid Volume: Spacer and Dart Drop Volume: Proppant Laden Fluid Volume: Interval Status: Pre-Pad Volume: Pad Volume: Conditioning Pad Volume: 100M Pumped: Average Temp: Max Surface Pressure: Max BH Pressure: Pumps Ending Stage: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Proppant Summary Average Missile Pressure: Average Rate: Fluid Summary (by stage description) William Martin Max Rate: Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) 27# Linear Volume: Average Missile HHP: Wanli 16/20 Ceramic Pumped: Initial OA Pressure: Max Proppant Concentration: After cleaning the screws, A pump started cavitating causing rate and pressure to fluctuate briefly. Interval pumped to completion. Interval Summary Pump Time: Start Date/Time: 3T-730 - Coyote - Interval 10 End Date/Time: 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: Cody Strong 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 Daniel Faur Conoco Phillips - 3T-730 Interval Summary 19 6/1/25 16:34 6/1/25 17:44 70 min 20.9 bpm 3,398 psi 4,741 psi 5 bbl 21.0 bpm 1,925 psi 3,470 psi 20.4 bpm 1,700 psi 1,565 psi 3,270 psi 851 hhp 109 psi 109 psi 10.33 ppg 4 4 28 % 27 % 20 cP 93.6 F 8.8 199,545 lbs 3,000 lbs 202,545 lbs 202,545 lbs 47,027 gal 1,120 bbls 3,225 gal 77 bbls 2,009 gal 48 bbls 8,759 gal 209 bbls 6,107 gal 145 bbls 31,033 gal 739 bbls 1,128 gal 27 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Max Surface Pressure: Proppant Laden Fluid Volume: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Average Missile Pressure: Start Date/Time: Interval Status: Average Missile HHP: 27# Linear Volume: Pumps Starting Stage: 100M Pumped: Conditioning Pad Volume: Max BH Pressure: Average Rate: Average BH Pressure: William Martin 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: 3T-730 - Coyote - Interval 11 End Date/Time: Max Proppant Concentration: Average Visc: Average Temp: Max Rate: Wanli 16/20 Ceramic Pumped: Average pH: Pad Percentage Actual Initial OA Pressure: Cody Strong 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: Fluid Summary (by stage description) Establish Stable Fluid Volume: Pre-Pad Volume: Pad Volume: Interval pumped to completion. Madeline Woodard Daniel Faur Conoco Phillips - 3T-730 Interval Summary 20 6/1/25 17:44 6/1/25 18:44 59 min 20.9 bpm 2,950 psi 4,418 psi 3 bbl 21.1 bpm 2,155 psi 3,553 psi 20.5 bpm 1,700 psi 1,565 psi 3,275 psi 852 hhp 108 psi 109 psi 10.39 ppg 4 4 28 % 28 % 20 cP 93.8 F 8.81 2774 psi 0.668 psi/ft 2756 psi 2745 psi 2738 psi 149,572 lbs 3,000 lbs 152,572 lbs 152,572 lbs 35,973 gal 857 bbls 7,606 gal 181 bbls 1,825 gal 43 bbls 5,072 gal 121 bbls 6,129 gal 146 bbls 23,099 gal 550 bbls 1,673 gal 40 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant in Formation: Final 15 min: Final 5 min: Total Proppant Pumped* : 100M Pumped: Max Surface Pressure: ISDP: Final 10 min: Wanli 16/20 Ceramic Pumped: Pumps Ending Stage: Pad Percentage Design Pre-Pad Volume: Proppant Laden Fluid Volume: Average Temp: Interval Status: Establish Stable Fluid Volume: 27# Linear Volume: Daniel Faur Pad Volume: Conditioning Pad Volume: Proppant Summary Fluid Summary (by fluid description) 27# Delta Frac Volume: Fluid Summary (by stage description) Start Date/Time: Average Rate: Average Missile Pressure: Final Fracture Gradient: Pad Percentage Actual Initial Rate (Breakdown): Average BH Pressure: Interval pumped to completion. William Martin Average Surface Pressure: Dart/Ball Early : Max BH Pressure: Average Visc: Cody Strong 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 Max OA Pressure: Average pH: Max Rate: Initial OA Pressure: End Date/Time: Pumps Starting Stage: Max Proppant Concentration: Pump Time: 3T-730 - Coyote - Interval 12 Interval Summary Initial BH Pressure (Breakdown): Average Missile HHP: Initial Surface Pressure (Breakdown): Conoco Phillips - 3T-730 Interval Summary 21 6/2/25 8:15 6/2/25 10:26 131 min 15.5 bpm 3,844 psi 5,582 psi 8 bbl 21.1 bpm 1,724 psi 3,320 psi 20.2 bpm 1,595 psi 1,469 psi 3,146 psi 788 hhp 420 psi 89 psi 90 psi 10.42 ppg 4 4 28 % 27 % 20 cP 90.3 F 8.81 DFIT 10.570 bpm 1495 psi 3179 psi 15.4 bpm 2319 psi 3959 psi 2682 psi 0.646 psi/ft 2647 psi 2624 psi 2601 psi 149,869 lbs 3,000 lbs 152,869 lbs 152,869 lbs 36,488 gal 869 bbls 8,086 gal 193 bbls 840 gal 20 bbls 4,880 gal 116 bbls 5,974 gal 142 bbls 23,612 gal 562 bbls 2,274 gal 54 bbls 2,022 gal 48 bbls 837 gal 20 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Freeze Protect Volume: Establish Stable Fluid Volume: Interval Status: 100M Pumped: Proppant in Formation: 27# Delta Frac Volume: Max Rate: Wanli 16/20 Ceramic Pumped: Average BH Pressure: Pumps Ending Stage: Open Well Pressure: Diagnostic method Minifrac Average Rate: Average Temp: Pad Volume: Average Surface Pressure: Start Date/Time: Pumps Starting Stage: Average Rate: Final 5 min: Final 10 min: Pad Percentage Design Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Surface Pressure: Max Proppant Concentration: ISDP: Final Fracture Gradient: Proppant Summary Dart/Ball Early : Minifrac Max Rate: Max BH Pressure: Minifrac Max Surface Pressure: Initial BH Pressure (Breakdown): Average Missile Pressure: Minifrac Max DH Pressure: Pump Time: 3T-730 - Coyote - Interval 13 *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: Madeline Woodard Daniel Faur Max OA Pressure: Average Visc: Average pH: Initial OA Pressure: Average Missile HHP: Interval Summary End Date/Time: Total Proppant Pumped* : Conditioning Pad Volume: Pad Percentage Actual Minifrac Average Pressure: Minifrac Average DH Pressure: Proppant Laden Fluid Volume: Final 15 min: Fluid Summary (by stage description) DFIT Volume: A DFIT was pumped after seating the dart for interval 13. Pressure Decline was monitored for 64 min and closure was found to be 2,467 psi. William Martin Cody Strong Derek Osselburn Fluid Summary (by fluid description) 27# Linear Volume: Conoco Phillips - 3T-730 Interval Summary 22 6/2/25 10:26 6/2/25 11:20 54 min 20.7 bpm 4,322 psi 5,929 psi 7 bbl 21.0 bpm 2,511 psi 3,915 psi 20.2 bpm 1,535 psi 1,408 psi 3,085 psi 761 hhp 94 psi 94 psi 10.60 ppg 4 4 28 % 27 % 22 cP 90.6 F 8.83 150,259 lbs 3,000 lbs 153,259 lbs 153,259 lbs 35,787 gal 852 bbls 3,134 gal 75 bbls 1,970 gal 47 bbls 5,063 gal 121 bbls 5,971 gal 142 bbls 23,800 gal 567 bbls 1,164 gal 28 bbls 953 gal 23 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Rate: Average Missile Pressure: Pumps Ending Stage: Interval Status: Initial BH Pressure (Breakdown): Establish Stable Fluid Volume: Average Surface Pressure: Pad Percentage Design Pad Percentage Actual 100M Pumped: William Martin Madeline Woodard End Date/Time: Average Temp: Dart/Ball Early : Max Surface Pressure: Max OA Pressure: Max Proppant Concentration: Initial Rate (Breakdown): Proppant Summary Daniel Faur Interval pumped to completion. Pump Time: Average pH: Wanli 16/20 Ceramic Pumped: Fluid Summary (by stage description) Cody Strong 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. Max Rate: Max BH Pressure: 3T-730 - Coyote - Interval 14 Average Visc: Initial OA Pressure: Interval Summary Start Date/Time: Average Missile HHP: Pumps Starting Stage: Average BH Pressure: Initial Surface Pressure (Breakdown): Total Proppant Pumped* : 27# Linear Volume: Proppant Laden Fluid Volume: Pad Volume: Proppant in Formation: Fluid Summary (by fluid description) 27# Delta Frac Volume: Pre-Pad Volume: Spacer and Dart Drop Volume: Conditioning Pad Volume: Conoco Phillips - 3T-730 Interval Summary 23 6/2/25 11:20 6/2/25 12:13 53 min 21.0 bpm 3,832 psi 4,847 psi 5 bbl 21.4 bpm 2,111 psi 3,555 psi 20.3 bpm 1,495 psi 1,363 psi 3,059 psi 743 hhp 94 psi 97 psi 10.32 ppg 4 3 28 % 27 % 22 cP 92.8 F 8.78 149,101 lbs 3,000 lbs 152,101 lbs 152,101 lbs 35,215 gal 838 bbls 3,281 gal 78 bbls 2,072 gal 49 bbls 5,023 gal 120 bbls 5,992 gal 143 bbls 23,618 gal 562 bbls 1,209 gal 29 bbls 582 gal 14 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Rate: Start Date/Time: 27# Delta Frac Volume: Pre-Pad Volume: Proppant Laden Fluid Volume: Madeline Woodard Daniel Faur Pumps Starting Stage: Proppant Summary Total Proppant Pumped* : Proppant in Formation: Spacer and Dart Drop Volume: Average Temp: Fluid Summary (by fluid description) Average Visc: Average pH: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: 27# Linear Volume: Max Surface Pressure: Fluid Summary (by stage description) Initial Rate (Breakdown): Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: 100M Pumped: Pump Time: Average Missile HHP: During 7ppg proppant, rate was swapped to the spare pump due to a leaking packing. Interval pumped to completion. Dart/Ball Early : 3T-730 - 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): Initial BH Pressure (Breakdown): Average BH Pressure: *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: William Martin Cody Strong Derek Osselburn Conditioning Pad Volume: Interval Status: Pad Volume: Conoco Phillips - 3T-730 Interval Summary 24 6/2/25 12:13 6/2/25 13:08 54 min 20.9 bpm 4,081 psi 5,312 psi 4 bbl 21.0 bpm 2,917 psi 4,369 psi 20.2 bpm 1,639 psi 1,508 psi 3,230 psi 811 hhp 97 psi 101 psi 10.45 ppg 3 3 28 % 27 % 22 cP 94.6 F 8.77 149,968 lbs 3,000 lbs 152,968 lbs 152,968 lbs 35,905 gal 855 bbls 3,113 gal 74 bbls 1,903 gal 45 bbls 5,091 gal 121 bbls 6,087 gal 145 bbls 23,531 gal 560 bbls 1,210 gal 29 bbls 1,196 gal 28 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Fluid Summary (by stage description) Total Proppant Pumped* : Interval Status: Interval pumped to completion. Wanli 16/20 Ceramic Pumped: Average Temp: Proppant in Formation: 100M Pumped: 27# Delta Frac Volume: 27# Linear Volume: Pre-Pad Volume: Pad Volume: Average Surface Pressure: Fluid Summary (by fluid description) Spacer and Dart Drop Volume: Pumps Starting Stage: Start Date/Time: Average BH Pressure: Average Rate: Conditioning Pad Volume: Proppant Laden Fluid Volume: Interval Summary Pad Percentage Actual Initial OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Missile HHP: Max OA Pressure: 3T-730 - Coyote - Interval 16 Max Rate: End Date/Time: Max BH Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Average pH: Pumps Ending Stage: Max Surface Pressure: Average Missile Pressure: Proppant Summary Establish Stable Fluid Volume: Max Proppant Concentration: Pad Percentage Design Average Visc: Pump Time: William Martin Cody Strong 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 Daniel Faur Conoco Phillips - 3T-730 Interval Summary 25 6/2/25 13:08 6/2/25 14:01 54 min 20.9 bpm 3,992 psi 5,478 psi 6 bbl 21.0 bpm 2,394 psi 3,821 psi 20.3 bpm 1,428 psi 1,294 psi 2,998 psi 711 hhp 101 psi 104 psi 10.14 ppg 3 3 28 % 27 % 22 cP 90.7 F 8.8 151,392 lbs 3,000 lbs 154,392 lbs 154,392 lbs 35,272 gal 840 bbls 3,259 gal 78 bbls 2,063 gal 49 bbls 5,065 gal 121 bbls 5,957 gal 142 bbls 23,709 gal 565 bbls 1,196 gal 28 bbls 541 gal 13 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: Average Visc: Average Temp: Max OA Pressure: Average Surface Pressure: Max Rate: Initial OA Pressure: Max BH Pressure: Initial Surface Pressure (Breakdown): Pumps Starting Stage: Average Missile HHP: Pump Time: Max Surface Pressure: Initial BH Pressure (Breakdown): Pumps Ending Stage: Pad Percentage Design Pad Percentage Actual Average BH Pressure: Total Proppant Pumped* : Conditioning Pad Volume: Proppant Laden Fluid Volume: Pre-Pad Volume: Fluid Summary (by stage description) Interval pumped to completion. William Martin Cody Strong Derek Osselburn Establish Stable Fluid Volume: Madeline Woodard Daniel Faur Start Date/Time: End Date/Time: Max Proppant Concentration: 100M Pumped: Fluid Summary (by fluid description) Spacer and Dart Drop Volume: Average Missile Pressure: Initial Rate (Breakdown): Dart/Ball Early : Wanli 16/20 Ceramic Pumped: 3T-730 - Coyote - Interval 17 Interval Summary Average pH: Proppant Summary Average Rate: Pad Volume: Proppant in Formation: 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. 27# Linear Volume: Conoco Phillips - 3T-730 Interval Summary 26 6/2/25 14:01 6/2/25 14:59 57 min 21.0 bpm 3,105 psi 4,659 psi 3 bbl 20.9 bpm 2,083 psi 3,604 psi 19.8 bpm 1,346 psi 1,211 psi 2,931 psi 654 hhp 103 psi 106 psi 10.34 ppg 3 2 28 % 27 % 22 cP 89.8 F 8.8 2775 psi 0.671 psi/ft 2764 psi 2760 psi 2755 psi 149,225 lbs 3,000 lbs 152,225 lbs 152,225 lbs 34,736 gal 827 bbls 5,857 gal 139 bbls 840 gal 20 bbls 1,975 gal 47 bbls 5,010 gal 119 bbls 5,971 gal 142 bbls 23,203 gal 552 bbls 3,882 gal 92 bbls 840 gal 20 bbls 552 gal 13 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Total Proppant Pumped* : Proppant in Formation: Final 5 min: Wanli 16/20 Ceramic Pumped: Establish Stable Fluid Volume: Final Fracture Gradient: Final 10 min: 27# Linear Volume: Max Rate: Max BH Pressure: Initial Surface Pressure (Breakdown): 27# Delta Frac Volume: Proppant Laden 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. Flush Volume: Pad Volume: Madeline Woodard Initial OA Pressure: Max OA Pressure: Start Date/Time: Average Surface Pressure: Fluid Summary (by stage description) Initial Rate (Breakdown): Average Rate: Conditioning Pad Volume: Daniel Faur William Martin Cody Strong Derek Osselburn 3T-730 - Coyote - Interval 18 Pump Time: Interval Status: Freeze Protect Volume: Max Surface Pressure: Freeze Protect Volume: 100M Pumped: Final 15 min: During the 10 ppg sand stage, debris went through the pumps and rate fluctuated greatly. Pump 458 was shut in and rate increased on the remaining pumps. Interval pumped to completion. Pre-Pad Volume: Average Visc: Average Missile Pressure: Fluid Summary (by fluid description) End Date/Time: Dart/Ball Early : Initial BH Pressure (Breakdown): Pad Percentage Design Max Proppant Concentration: Pad Percentage Actual Average BH Pressure: Pumps Starting Stage: Pumps Ending Stage: Average Missile HHP: Interval Summary Average Temp: Average pH: ISDP: Proppant Summary Conoco Phillips - 3T-730 Interval Summary 27 CustomerFormationLeaseAPIDateWell SummaryWanli 16/20 Ceramic 100M Total ProppantBH PressureRate Visc Temp pH BH Pressure Rate gal bbl gal bbl gal bbl gal bbl gal bbl lbs lbs lbs13708 20.0 18 89.2 8.8 4125 21.1 49,258 1,173 4,572 109 1,008 24 54,838 1,306 201,181 3,000 204,181 23663 20.1 18 90 8.8 4008 21.1 46,698 1,112 2,675 64 49,373 1,176 195,638 3,000 198,638 33609 20.2 18 82 8.8 3972 20.9 47,244 1,125 3,008 72 50,252 1,196 200,658 3,000 203,658 43657 20.3 18 90 8.7 3950 20.9 65,062 1,549 2,753 66 8,386 200 76,201 1,814 200,777 3,000 203,777 53626 20.2 18 86 8.8 3912 21.1 46,812 1,115 2,819 67 49,631 1,182 201,049 3,000 204,049 63503 20.0 18 81 8.8 4141 20.5 46,328 1,103 9,600 229 630 15 56,558 1,347 199,502 3,000 202,502 73478 20.1 19 90 8.9 3790 20.8 47,186 1,123 2,334 56 1,050 25 50,570 1,204 199,406 3,000 202,406 83425 20.2 20 93 8.8 4578 20.8 47,131 1,122 2,933 70 50,064 1,192 200,244 3,000 203,244 93455 20.2 20 92 8.8 5156 21.0 46,573 1,109 2,919 70 49,492 1,178 199,824 3,000 202,824 103361 20.2 20 90 8.8 3686 21.0 48,363 1,152 2,826 67 51,189 1,219 200,032 3,000 203,032 113270 20.4 20 94 8.8 3470 21.0 47,027 1,120 3,225 77 50,252 1,196 199,545 3,000 202,545 123275 20.5 20 94 8.8 3553 21.1 35,973 857 7,606 181 840 20 44,419 1,058 149,572 3,000 152,572 133146 20.2 20 90 8.8 3320 21.1 36,488 869 8,086 193 840 20 45,414 1,081 149,869 3,000 152,869 143085 20.2 22 91 8.8 3915 21.0 35,787 852 3,134 75 38,921 927 150,259 3,000 153,259 153059 20.3 22 93 8.8 3555 21.4 35,215 838 3,281 78 38,496 917 149,101 3,000 152,101 163230 20.2 22 95 8.8 4369 21.0 35,905 855 3,113 74 39,018 929 149,968 3,000 152,968 Minimum34736 827 2334 56 8386 200 630 15 38496 917 149101 3000 152101 Average43725 1041 4111 98 8386 200 868 21 48592 1157 180402 3000 183402 Maximum65062 1549 9600 229 8386 200 1050 25 76201 1814 201181 3000 204181 Wanli 16/20 Ceramic 100M Total ProppantPressure Rate Visc Temp pH Pressure Rate gal bbl gal bbl gal bbl gal bbl gal bbl lbs lbs TotalPlanned794,205 18,910 88,525 2,108 8,452 201 6,780 161 897,962 21,380 3,250,000 54,000 3,304,000Recorded3503 20.2 19 89 8.81 5156 21.4 787,058 18,739 74,000 1,762 8,386 200 5,208 124 874,65220,8253,247,242 54,000 3,301,242Weight Tickets3,250,851 54,000 3,304,851** Proppant is billed from Weight Ticket volumesMay 31, 202550-103-209073T-730CoyoteConoco Phillips IntervalAverage MaxSeawaterAverage MaxSeawater27# Delta Frac 27# Linear27# Delta Frac 27# Linear** IFS numbers for proppant are taken from software calculations based on Total FluidFluidsProppantsFluidsProppantsTotal FluidFreeze ProtectFreeze ProtectConoco Phillips - 3T-730 Fluid System-Proppant Summary28 <-Paste Interval 1 Plots HereePRV Test - 5.31.255/31/202507:1107:1207:1307:1407:1507:1607:175/31/202507:18Time01000200030004000500060007000Treating 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 IA07:11:26 07:12:5507:15:57 07:17:39TP TP620.9 753.1847.1 1580TPP TPP686.8 842.7909.0 1669IGKP IGKP850.0 850.0850.0 1100Conoco Phillips - 3T-730 Interval 1 Plots29 <-Paste Interval 1 Plots HerePressure Test - 5.31.255/31/202507:2007:2207:2407:2607:285/31/202507:30Time010002000300040005000600070008000900010000Treating 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 - Pass07:19:40 07:19:5607:23:34 07:28:40TP TP1401 13989359 9234TPP TPP125.1 10959463 9304IGKP IGKP9300 25.009400 9400PKP PKP800.0 500.49200 9200Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 1 Plots30 <-Paste Interval 1 Plots HereBlender Chemical Plot - Bucket Test 5.31.255/31/202506:5507:0007:0507:1007:155/31/202507:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA2Conoco Phillips - 3T-730 Interval 1 Plots31 <-Paste Interval 1 Plots HereADP Chemical Plots - Bucket Test 5.31.255/31/202506:09:2006:09:4006:10:0006:10:2006:10:4006:11:005/31/202506:11:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB1Conoco Phillips - 3T-730 Interval 1 Plots32 Treatment Plot - Interval 01 DFIT5/31/202507:4007:4507:5007:555/31/202508:00Time0100020003000400050006000A0102030405060708090100B012345678910C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD54Conoco Phillips - 3T-730 Interval 1 Plots33 Halliburton Pumping Diagnostic Analysis ToolkitMinifrac - G Function1234567G(Time)21502200225023002350240024502500A0102030405060D050100150200250300350E (0.002, 0) (m = 48.56) (3.936, 191) (Y = 0) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime6.44GBP2204SP2204DP195.6FE77.40Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 1 Plots34 Treatment Plot - Interval 01 SRT5/31/202508:1608:1808:2008:2208:245/31/202508:26Time0100020003000400050006000A0102030405060708090100B012345678910C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD727262524232221201918Global Event Log18192021222324252627Intersection IntersectionStep 1 Step 2Step 2 Step 3Step 4 Step 5Step 6 Step 7Step 8 Step 908:17:17 08:18:2408:19:23 08:20:2708:21:26 08:22:2308:23:26 08:24:2408:25:22 08:26:19TP TP862.8 925.3963.9 986.71005 10251026 10411076 1138SR SR1.094 1.9742.936 3.9274.901 5.9856.950 7.8608.836 9.799GBP GBP2619 26652712 27502778 28132834 28642892 2934Conoco Phillips - 3T-730 Interval 1 Plots35 Treatment Plot - Interval 015/31/202508:2008:4009:0009:205/31/202509:40Time0100020003000400050006000A0102030405060708090100B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321171615141312111098762Conoco Phillips - 3T-730 Interval 1 Plots36 Blender Chemical Plot - Interval 015/31/202508:2008:3008:4008:5009:0009:1009:2009:305/31/202509:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321171615141312111098762Conoco Phillips - 3T-730 Interval 1 Plots37 ADP Chemical Plots - Interval 015/31/202508:2008:3008:4008:5009:0009:1009:2009:305/31/202509:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321171615141312111098762Conoco Phillips - 3T-730 Interval 1 Plots38 Net Pressure Plot - Interval 01567892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 05/31/25 08:10:56 1Time-70.31NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 1 Plots39 <-Paste Interval 2 Plots HereTreatment Plot - Interval 025/31/202509:4010:0010:2010:405/31/202511:00Time0100020003000400050006000A0102030405060708090100B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32112111098765432132Conoco Phillips - 3T-730 Interval 2 Plots40 <-Paste Interval 2 Plots HereBlender Chemical Plot - Interval 025/31/202509:4009:5010:0010:1010:2010:3010:405/31/202510:50Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA32112111098765432132Conoco Phillips - 3T-730 Interval 2 Plots41 <-Paste Interval 2 Plots HereADP Chemical Plots - Interval 025/31/202509:4009:5010:0010:1010:2010:3010:405/31/202510:50Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211732Conoco Phillips - 3T-730 Interval 2 Plots42 <-Paste Interval 2 Plots HereNet Pressure Plot - Interval 026789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 05/31/25 09:40:56 1Time-160.31NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 2 Plots43 <-Paste Interval 3 Plots HereTreatment Plot - Interval 035/31/202511:0011:2011:405/31/202512:00Time0100020003000400050006000A0102030405060708090100B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32112111098765432143Conoco Phillips - 3T-730 Interval 3 Plots44 <-Paste Interval 3 Plots HereBlender Chemical Plot - Interval 035/31/202510:5011:0011:1011:2011:3011:4011:505/31/202512:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211243Conoco Phillips - 3T-730 Interval 3 Plots45 <-Paste Interval 3 Plots HereADP Chemical Plots - Interval 035/31/202510:5011:0011:1011:2011:3011:4011:505/31/202512:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211243Conoco Phillips - 3T-730 Interval 3 Plots46 <-Paste Interval 3 Plots HereNet Pressure Plot - Interval 036789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 05/31/25 10:50:56 1Time-230.31NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 3 Plots47 <-Paste Interval 4 Plots HereTreatment Plot - Interval 045/31/202512:0012:2012:4013:0013:2013:405/31/202514:00Time0100020003000400050006000A0102030405060708090100B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32117161514131211109876543211254Conoco Phillips - 3T-730 Interval 4 Plots48 <-Paste Interval 4 Plots HereBlender Chemical Plot - Interval 045/31/202512:0012:2012:4013:0013:2013:405/31/202514:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321171615141312111098765432154Conoco Phillips - 3T-730 Interval 4 Plots49 <-Paste Interval 4 Plots HereADP Chemical Plots - Interval 045/31/202512:0012:2012:4013:0013:2013:405/31/202514:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB32117161514131211109876543211254Conoco Phillips - 3T-730 Interval 4 Plots50 <-Paste Interval 4 Plots HereNet Pressure Plot - Interval 0467892345678910100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 05/31/25 12:00:00 1Time-299.37NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 4 Plots51 <-Paste Interval 5 Plots HereTreatment Plot - Interval 055/31/202514:0014:1014:2014:3014:4014:5015:005/31/202515:10Time0100020003000400050006000A0102030405060708090100B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32112111098765432165Conoco Phillips - 3T-730 Interval 5 Plots52 <-Paste Interval 5 Plots HereBlender Chemical Plot - Interval 055/31/202514:0014:1014:2014:3014:4014:5015:005/31/202515:10Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211765Conoco Phillips - 3T-730 Interval 5 Plots53 <-Paste Interval 5 Plots HereADP Chemical Plots - Interval 055/31/202514:0014:1014:2014:3014:4014:5015:005/31/202515:10Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211765Conoco Phillips - 3T-730 Interval 5 Plots54 <-Paste Interval 5 Plots HereNet Pressure Plot - Interval 059234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 05/31/25 13:55:00 1Time-414.37NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 5 Plots55 <-Paste Interval 6 Plots HereTreatment Plot - Interval 065/31/202515:2015:4016:005/31/202516:20Time0100020003000400050006000A0102030405060708090100B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD1211109876543216Conoco Phillips - 3T-730 Interval 6 Plots56 <-Paste Interval 6 Plots HereBlender Chemical Plot - Interval 065/31/202515:1015:2015:3015:4015:5016:0016:105/31/202516:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA121110987654321126Conoco Phillips - 3T-730 Interval 6 Plots57 <-Paste Interval 6 Plots HereADP Chemical Plots - Interval 065/31/202515:1015:2015:3015:4015:5016:0016:105/31/202516:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB121110987654321126Conoco Phillips - 3T-730 Interval 6 Plots58 <-Paste Interval 6 Plots HereNet Pressure Plot - Interval 069234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 05/31/25 15:05:00 1Time-484.37NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 31-May-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 6 Plots59 <-Paste Interval 7 Plots HereePRV Test - 6.1.256/1/202511:1111:1211:1311:1411:1511:1611:176/1/202511:18Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)26543Global Event Log3456Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA11:11:21 11:13:2511:16:41 11:17:39TP TP1217 583.9499.6 891.1TPP TPP1302 711.0596.1 988.6IGKP IGKP900.0 900.0900.0 900.0Conoco Phillips - 3T-730 Interval 7 Plots60 <-Paste Interval 7 Plots HerePressure Test - 6.1.256/1/202511:2011:2211:2411:266/1/202511:28Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)10987Global Event Log78910Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Pass11:19:45 11:19:5211:22:57 11:27:57TP TP608.5 678.89452 9320TPP TPP648.8 771.19548 9394IGKP IGKP9325 93009500 9500PKP PKP500.4 667.69500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 7 Plots61 <-Paste Interval 7 Plots HereBlender Chemical Plot - Bucket Test 6.1.256/1/202511:1611:1811:2011:2211:246/1/202511:26Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABAConoco Phillips - 3T-730 Interval 7 Plots62 <-Paste Interval 7 Plots HereADP Chemical Plots - Bucket Test 6.1.256/1/202510:30:0010:30:3010:31:0010:31:3010:32:0010:32:3010:33:0010:33:306/1/202510:34:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)ABConoco Phillips - 3T-730 Interval 7 Plots63 Treatment Plot - Interval 076/1/202511:5012:0012:1012:2012:3012:4012:5013:006/1/202513:10Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211514131211109876548Conoco Phillips - 3T-730 Interval 7 Plots64 Blender Chemical Plot - Interval 076/1/202512:0012:1012:2012:3012:4012:506/1/202513:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA211514131211109876548Conoco Phillips - 3T-730 Interval 7 Plots65 ADP Chemical Plots - Interval 076/1/202511:5012:0012:1012:2012:3012:4012:506/1/202513:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211514131211109876548Conoco Phillips - 3T-730 Interval 7 Plots66 Net Pressure Plot - Interval 073456789234567810Time (min)2345678923456789100100010000Net Gauge BH Pres (psi)Slope of Net Pressure (psi/min) Closure Pressure = 2255 psi 0 Time = 06/01/25 12:00:00 1Time399.95NetPr1083Slope-15.79Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 7 Plots67 <-Paste Interval 8 Plots HereTreatment Plot - Interval 086/1/202513:2013:4014:006/1/202514:20Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211598Conoco Phillips - 3T-730 Interval 8 Plots68 <-Paste Interval 8 Plots HereBlender Chemical Plot - Interval 086/1/202513:1013:2013:3013:4013:5014:006/1/202514:10Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211598Conoco Phillips - 3T-730 Interval 8 Plots69 <-Paste Interval 8 Plots HereADP Chemical Plots - Interval 086/1/202513:1013:2013:3013:4013:5014:006/1/202514:10Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211598Conoco Phillips - 3T-730 Interval 8 Plots70 <-Paste Interval 8 Plots HereNet Pressure Plot - Interval 082345678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 06/01/25 13:10:24 1Time-137.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 8 Plots71 <-Paste Interval 9 Plots HereTreatment Plot - Interval 096/1/202514:2014:3014:4014:5015:0015:1015:206/1/202515:30Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321109Conoco Phillips - 3T-730 Interval 9 Plots72 <-Paste Interval 9 Plots HereBlender Chemical Plot - Interval 096/1/202514:2014:3014:4014:5015:0015:106/1/202515:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA2112111098765432112109Conoco Phillips - 3T-730 Interval 9 Plots73 <-Paste Interval 9 Plots HereADP Chemical Plots - Interval 096/1/202514:2014:3014:4014:5015:0015:106/1/202515:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB21121110987654321109Conoco Phillips - 3T-730 Interval 9 Plots74 <-Paste Interval 9 Plots HereNet Pressure Plot - Interval 92345678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 06/01/25 14:20:00 1Time-206.65NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 9 Plots75 <-Paste Interval 10 Plots HereTreatment Plot - Interval 106/1/202515:4016:0016:206/1/202516:40Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321121110Conoco Phillips - 3T-730 Interval 10 Plots76 <-Paste Interval 10 Plots HereBlender Chemical Plot - Interval 106/1/202515:3015:4015:5016:0016:1016:2016:306/1/202516:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211110Conoco Phillips - 3T-730 Interval 10 Plots77 <-Paste Interval 10 Plots HereADP Chemical Plots - Interval 106/1/202515:3015:4015:5016:0016:1016:206/1/202516:30Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321121110Conoco Phillips - 3T-730 Interval 10 Plots78 <-Paste Interval 10 Plots HereNet Pressure Plot - Interval 102345678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 06/01/25 15:29:00 1Time-275.65NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 10 Plots79 <-Paste Interval 11 Plots HereTreatment Plot - Interval 116/1/202516:4016:5017:0017:1017:2017:3017:406/1/202517:50Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211211Conoco Phillips - 3T-730 Interval 11 Plots80 <-Paste Interval 11 Plots HereBlender Chemical Plot - Interval 116/1/202516:4016:5017:0017:1017:2017:306/1/202517:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA21121110987654321121211Conoco Phillips - 3T-730 Interval 11 Plots81 <-Paste Interval 11 Plots HereADP Chemical Plots - Interval 116/1/202516:4016:5017:0017:1017:2017:306/1/202517:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB211211109876543211211Conoco Phillips - 3T-730 Interval 11 Plots82 <-Paste Interval 11 Plots HereNet Pressure Plot - Interval 112345678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 06/01/25 16:40:00 1Time-346.65NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 11 Plots83 <-Paste Interval 12 Plots HereTreatment Plot - Interval 126/1/202517:5018:0018:1018:2018:306/1/202518:40Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD1211109876543211212Conoco Phillips - 3T-730 Interval 12 Plots84 <-Paste Interval 12 Plots HereBlender Chemical Plot - Interval 126/1/202517:5018:0018:1018:2018:306/1/202518:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA1211109876543211212Conoco Phillips - 3T-730 Interval 12 Plots85 <-Paste Interval 12 Plots HereADP Chemical Plots - Interval 126/1/202517:5018:0018:1018:2018:306/1/202518:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB1211109876543211212Conoco Phillips - 3T-730 Interval 12 Plots86 <-Paste Interval 12 Plots HereNet Pressure Plot - Interval 122345678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2255 psi 0 Time = 06/01/25 17:49:00 1Time-415.65NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 01-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 12 Plots87 <-Paste Interval 13 Plots HereePRV Test - 6.2.256/2/202507:0007:0207:046/2/202507:06Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)6543Global Event Log3456Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA06:59:16 07:00:4107:03:54 07:05:54TP TP712.0 662.21166 1551TPP TPP659.1 641.9483.4 1527IGKP IGKP850.0 850.0850.0 1300Conoco Phillips - 3T-730 Interval 13 Plots88 <-Paste Interval 13 Plots HerePressure Test - 6.2.256/2/202507:0807:1007:1207:1407:1607:1807:2007:226/2/202507:24Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)1110987Global Event Log7891011Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - PassGrease the Wellhead07:08:34 07:08:3907:16:40 07:21:1307:23:07TP TP1427 14259431 931621.40TPP TPP820.4 853.89512 937519.08IGKP IGKP25.00 93009500 95009500PKP PKP500.4 858.79451 94519451Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 13 Plots89 <-Paste Interval 13 Plots HereBlender Chemical Plot - Bucket Test 6.2.256/2/202506:5006:5507:0007:056/2/202507:10Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA2Conoco Phillips - 3T-730 Interval 13 Plots90 <-Paste Interval 13 Plots HereTreatment Plot - Interval 13 DFIT6/2/202508:1508:2008:2508:3008:3508:4008:456/2/202508:50Time010002000300040005000A0102030405060708090100B012345678910C0255075100125150DTreating 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 - 3T-730 Interval 13 Plots91 Halliburton Pumping Diagnostic Analysis ToolkitMinifrac - G Function24681012G(Time)2300240025002600270028002900A0102030405060D0100200300400E (0.002, 0) (m = 37.13) (10.6, 393.4) (Y = 0) (Y = 445.4) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime10.01GBP2423SP2423DP258.0FE84.19Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 13 Plots92 Treatment Plot - Interval 136/2/202509:3009:4009:5010:0010:1010:206/2/202510:30Time010002000300040005000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD43211817161514131211109814Conoco Phillips - 3T-730 Interval 13 Plots93 Blender Chemical Plot - Interval 136/2/202509:3009:4009:5010:0010:1010:206/2/202510:30Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211817161514131211109814Conoco Phillips - 3T-730 Interval 13 Plots94 ADP Chemical Plots - Interval 136/2/202509:4009:5010:0010:1010:206/2/202510:30Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211817161514131211109814Conoco Phillips - 3T-730 Interval 13 Plots95 Net Pressure Plot - Interval 134567892345610Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2665 psi 0 Time = 06/02/25 09:28:16 1-136.040.0000.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 13 Plots96 <-Paste Interval 14 Plots HereTreatment Plot - Interval 146/2/202510:3010:4010:5011:0011:106/2/202511:20Time010002000300040005000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321181514Conoco Phillips - 3T-730 Interval 14 Plots97 <-Paste Interval 14 Plots HereBlender Chemical Plot - Interval 146/2/202510:3010:4010:5011:0011:106/2/202511:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321181514Conoco Phillips - 3T-730 Interval 14 Plots98 <-Paste Interval 14 Plots HereADP Chemical Plots - Interval 146/2/202510:3010:4010:5011:0011:106/2/202511:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321181514Conoco Phillips - 3T-730 Interval 14 Plots99 <-Paste Interval 14 Plots HereNet Pressure Plot - Interval 1434567892345610Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2665 psi 0 Time = 06/02/25 10:28:16 1-196.040.0000.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 14 Plots100 <-Paste Interval 15 Plots HereTreatment Plot - Interval 156/2/202511:2011:3011:4011:5012:0012:106/2/202512:20Time010002000300040005000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321121615Conoco Phillips - 3T-730 Interval 15 Plots101 <-Paste Interval 15 Plots HereBlender Chemical Plot - Interval 156/2/202511:2011:3011:4011:5012:006/2/202512:10Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321121615Conoco Phillips - 3T-730 Interval 15 Plots102 <-Paste Interval 15 Plots HereADP Chemical Plots - Interval 156/2/202511:2011:3011:4011:5012:006/2/202512:10Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321121615Conoco Phillips - 3T-730 Interval 15 Plots103 <-Paste Interval 15 Plots HereNet Pressure Plot - Interval 1534567892345610Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2665 psi 0 Time = 06/02/25 11:22:00 1-249.780.0000.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 15 Plots104 <-Paste Interval 16 Plots HereTreatment Plot - Interval 166/2/202512:2012:3012:4012:5013:006/2/202513:10Time010002000300040005000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211716Conoco Phillips - 3T-730 Interval 16 Plots105 <-Paste Interval 16 Plots HereBlender Chemical Plot - Interval 166/2/202512:2012:3012:4012:5013:006/2/202513:10Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321121716Conoco Phillips - 3T-730 Interval 16 Plots106 <-Paste Interval 16 Plots HereADP Chemical Plots - Interval 166/2/202512:2012:3012:4012:5013:006/2/202513:10Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321121716Conoco Phillips - 3T-730 Interval 16 Plots107 <-Paste Interval 16 Plots HereNet Pressure Plot - Interval 1634567892345610Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2665 psi 0 Time = 06/02/25 12:15:00 1-302.780.0000.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 16 Plots108 <-Paste Interval 17 Plots HereTreatment Plot - Interval 176/2/202513:1013:2013:3013:4013:506/2/202514:00Time010002000300040005000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211817Conoco Phillips - 3T-730 Interval 17 Plots109 <-Paste Interval 17 Plots HereBlender Chemical Plot - Interval 176/2/202513:1013:2013:3013:4013:506/2/202514:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321121817Conoco Phillips - 3T-730 Interval 17 Plots110 <-Paste Interval 17 Plots HereADP Chemical Plots - Interval 176/2/202513:1013:2013:3013:4013:506/2/202514:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB11211109876543211817Conoco Phillips - 3T-730 Interval 17 Plots111 <-Paste Interval 17 Plots HereNet Pressure Plot - Interval 1734567892345610Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2665 psi 0 Time = 06/02/25 13:09:00 1-356.780.0000.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 17 Plots112 <-Paste Interval 18 Plots HereTreatment Plot - Interval 186/2/202514:1014:2014:3014:4014:506/2/202515:00Time010002000300040005000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD12111098765432118Conoco Phillips - 3T-730 Interval 18 Plots113 <-Paste Interval 18 Plots HereBlender Chemical Plot - Interval 186/2/202514:1014:2014:3014:4014:506/2/202515:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA1211109876543211218Conoco Phillips - 3T-730 Interval 18 Plots114 <-Paste Interval 18 Plots HereADP Chemical Plots - Interval 186/2/202514:1014:2014:3014:4014:506/2/202515:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB12111098765432118Conoco Phillips - 3T-730 Interval 18 Plots115 <-Paste Interval 18 Plots HereNet Pressure Plot - Interval 1834567892345610Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2665 psi 0 Time = 06/02/25 14:02:00 1-409.780.0000.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jun-2025Sales Order #: 0910106491Well Description: 3T-730 3T-730UWI: 50-103-20907Conoco Phillips - 3T-730 Interval 18 Plots116 Sales Order# - - - - - - - - - - Prepared for: Madeline Woodard June 2, 2025 Harrison Bay County, AK 0910106491 Conoco Phillips 3T-730 Intervals 1-18 Coyote Coyote Formation API: 50-103-20907 Real-Time QC Well Summary Stimulation Treatment Appendix Chemical Summary Planned Design Water Straps Water Analysis Event Log Sand Sieve Fann 15 Minute Field Break Test Conoco Phillips - 3T-730 Appendix 117 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 5/31/2025 203,000 204,181 1,544 13061,523 28.0 26.5 2692 5/31/2025 203,000 198,638 1,200 11761,387 28.0 26.9 2633 5/31/2025 203,000 203,658 1,200 11961,413 28.0 26.6 2674 5/31/2025 203,000 203,777 1,957 18142,031 41.9 41.5 257 Flush after Conditioning Pad for ADP Mixing Bowl5 5/31/2025 203,000 204,049 1,200 11821,398 28.0 26.8 2696 5/31/2025 203,000 202,502 1,378 13471,562 28.0 27.2 2707 6/1/2025 203,000 202,406 1,204 12041,419 28.0 26.9 2678 6/1/2025 203,000 203,244 1,200 11921,408 28.0 27.0 2699 6/1/2025 203,000 202,824 1,200 11781,394 28.0 26.9 26910 6/1/2025 203,000 203,032 1,200 12191,434 28.0 26.7 26911 6/1/2025 203,000 202,545 1,200 11961,412 28.0 27.3 27012 6/1/2025 153,000 152,572 1,066 10581,220 28.0 27.6 27213 6/2/2025 153,000 152,869 1,078 10811,244 28.0 26.6 26714 6/2/2025 153,000 153,259 933 9271,090 28.0 26.8 26515 6/2/2025 153,000 152,101 933 9171,078 28.0 26.9 26516 6/2/2025 153,000 152,968 933 9291,092 28.0 27.2 26817 6/2/2025 153,000 154,392 933 9171,081 28.0 26.8 26818 6/2/2025 153,000 152,225 1,020 9871,148 28.0 27.1 270 3T-730 Interval HighlightsConoco Phillips - 3T-730Well Summary118 CustomerConoco Phillips FormationCoyoteLease3T-730API50-103-20907DateInterval Summary - Chemicals BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)Prime Up0000000135 55 36 115 1506 111 36216 51 32 90 1254 101 0323 51 31 104 1271 103 0426 76 28 154 1698 155 0522 51 31 101 1327 101 0613 56 27 76 1528 109 0734 49 41 109 1427 96 54819 48 29 103 1307 97 0927 48 27 95 1275 95 01020 50 30 97 1447 99 01120 47 28 96 1287 96 01215 43 20 82 1011 77 01313 50 25 105 1307 100 541417 45 25 90 991 90 01515 40 22 75 969 74 01616 40 22 91 1144 76 01715 40 22 75 1011 76 01814 50 24 107 904 84 0Total 360 890 500 1765 22664 1740 144w/o Prime Up360 890 500 1765 22664 1740 144Interval5/31/2025Dry AdditivesLiquid AdditivesConoco Phillips - 3T-730 Chemical Summary119 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDERBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In1:39:27 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:39:27 1-3 Shut-In Shut-In1:34:41 1-4 27# Linear DFIT 10 840 20 20 0:02:00 1:34:41 1.00 2.00 27.00 2.00 0.151-5 Shut-In Shut-In1:32:41 1-6 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 1:32:41 1.00 2.00 27.00 2.00 0.151-7 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:21 0.45 1.00 0.65 2.00 27.00 2.00 0.151-8 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 27.00 2.00 0.151-9 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.151-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.151-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.151-17 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.152-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.152-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 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 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.152-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.152-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.152-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.152-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.152-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.153-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.153-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 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 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.153-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.154-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:02:15 1.00 2.00 27.00 2.00 0.154-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:59:45 0.45 1.00 0.65 2.00 27.00 2.00 0.154-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:57:15 0.45 1.00 0.65 2.00 27.00 2.00 0.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:46:37 0.45 1.00 0.65 2.00 27.00 2.00 0.154-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 62 67 1:39:19 0.45 1.00 0.65 2.00 27.00 2.00 0.154-6 Seawater Flush 10 8,452 201 201 0:20:07 1:39:19 0.154-7 Shut-In Shut-In1:19:11 4-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:11 0.45 1.00 0.65 2.00 27.00 2.00 0.154-9 27# Delta Frac Pad 20 14,930 355 355 0:17:46 1:05:51 0.45 1.00 0.65 2.00 27.00 2.00 0.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.154-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.154-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.154-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.154-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.0000 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.154-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.154-17 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.155-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.155-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 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 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.155-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.156-1 27# Linear Pre-Pad 15 2,100 50 50 0:03:20 1:21:35 1.00 2.00 27.00 2.00 0.156-2 27# Delta Frac Establish Stable Fluid 15 2,100 50 50 0:03:20 1:18:15 0.45 1.00 0.65 2.00 27.00 2.00 0.156-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:14:55 0.45 1.00 0.65 2.00 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 1:04:17 0.45 1.00 0.65 2.00 27.00 2.00 0.156-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:56:59 0.45 1.00 0.65 2.00 27.00 2.00 0.156-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:53:36 0.45 1.00 0.65 2.00 27.00 2.00 0.156-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:47:37 0.45 1.00 0.65 2.00 27.00 2.00 0.156-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:41:19 0.45 1.00 0.65 2.00 27.00 2.00 0.156-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:31:07 0.45 1.00 0.65 2.00 27.00 2.00 0.156-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:21:42 0.45 1.00 0.65 2.00 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:14:59 0.45 1.00 0.65 2.00 27.00 2.00 0.156-12 27# Linear Flush 20 7,680 183 183 0:09:09 0:10:39 1.00 2.00 27.00 2.00 0.156-13 Freeze Protect Freeze Protect 20 1,260 30 30 0:01:30 0:01:30 6-14 Shut-In Shut-In 5Interval 1Coyote@ 13891.01 - 13895.01 ft 104.8 °FInterval 2Coyote@ 13348 - 13352 ft 104.9 °FInterval 3Coyote@ 12850.49 - 12854.49 ft 104.9 °FInterval 4Coyote@ 12433.91 - 12437.91 ft 104.9 °FInterval 5Coyote@ 11892.86 - 11896.86 ft 104.9 °FInterval 6Coyote@ 11357.75 - 11361.75 ft 104.9 °F5/31/25Liquid Additives Dry Additives50-103-209070910106491Conoco Phillips - 3T-730Planned Design120 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDERBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)5/31/25Liquid Additives Dry Additives50-103-2090709101064917-1 Shut-In Shut-In1:15:17 7-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:15:17 7-3 Shut-In Shut-In1:10:31 7-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:10:31 1.00 2.00 27.00 2.00 0.157-5 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.157-6 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 27.00 2.00 0.157-7 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.157-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.157-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.157-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.157-15 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 27.00 2.00 0.158-4 27# Delta Frac Conditioning Pad 100M 0.5000 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.158-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.158-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.158-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.158-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.158-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.158-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.158-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 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 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1510-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 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 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1510-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1511-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:11:01 1.00 2.00 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.65 2.00 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 0:55:23 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1511-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1512-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:06:56 1.00 2.00 27.00 2.00 0.1512-2 27# Delta Frac Establish Stable Fluid 15 2,100 50 50 0:03:20 1:04:26 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 1:01:06 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:54:57 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:47:39 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:45:03 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:40:33 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:35:51 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:28:18 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:21:14 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:16:12 0.45 1.00 0.65 2.00 27.00 2.00 0.1512-12 27# Linear Flush 20 5,773 137 137 0:06:52 0:12:52 1.00 2.00 27.00 2.00 0.1512-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 12-14 Shut-In Shut-InInterval 9Coyote@ 9866.92 - 9870.92 ft 104.9 °FInterval 10Coyote@ 9368.4 - 9372.4 ft 104.9 °FInterval 11Coyote@ 8872.95 - 8876.95 ft 104.9 °FInterval 7Coyote@ 10862.44 - 10866.44 ft 104.9 °FInterval 8Coyote@ 10365.57 - 10369.57 ft 104.9 °FInterval 12Coyote@ 8374.76 - 8378.76 ft 104.8 °FConoco Phillips - 3T-730Planned Design121 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.41994879LEASE3T-730SALES ORDERBHST (°F)105LONG-150.2690953FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)5/31/25Liquid Additives Dry Additives50-103-20907091010649113-1 Shut-In Shut-In1:10:19 13-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:10:19 13-3 Shut-In Shut-In1:05:33 13-4 27# Linear Spacer and Dart Drop 10 1,260 30 30 0:03:00 1:05:33 1.00 2.00 27.00 2.00 0.1513-5 27# Linear Displacement 15 5,087 121 121 0:08:05 1:02:33 1.00 2.00 27.00 2.00 0.1513-6 27# Linear DFIT 10 840 20 20 0:02:00 0:54:29 1.00 2.00 27.00 2.00 0.1513-7 27# Delta Frac Shut-In0:52:29 13-8 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 0:52:29 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-9 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:50 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1513-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 0:54:59 1.00 2.00 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 0:52:29 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.65 2.00 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 0:43:50 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1514-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1515-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 0:54:59 1.00 2.00 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 0:52:29 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.65 2.00 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 0:43:50 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1515-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1516-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 0:54:59 1.00 2.00 27.00 2.00 0.1516-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 0:52:29 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.65 2.00 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 0:43:50 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1516-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1517-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 0:54:59 1.00 2.00 27.00 2.00 0.1517-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 0:52:29 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:50 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.65 2.00 27.00 2.00 0.1517-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1518-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:03:48 1.00 2.00 27.00 2.00 0.1518-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:01:18 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:52:39 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:45:20 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:42:44 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:38:14 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:33:32 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:26:00 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:18:56 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:13:54 0.45 1.00 0.65 2.00 27.00 2.00 0.1518-12 27# Linear Flush 20 3,835 91 91 0:04:34 0:10:34 1.00 2.00 27.00 2.00 0.1518-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 18-14 Shut-In Shut-In897,962 21,442 24,957 3,304,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6794,2053,250,000(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)88,52554,000Initial Design Material Volume 357.4 882.7 516.2 1,765.5 23,833.7 1,765.5 133.78,452-6,780-21:36:39 Interval 13Coyote@ 7958.84 - 7962.84 ft 104.8 °FInterval 14Coyote@ 7460.08 - 7464.08 ft 104.8 °FInterval 15Coyote@ 6921.94 - 6925.94 ft 104.7 °FInterval 16Coyote@ 6424.06 - 6428.06 ft 104.7 °FInterval 17Coyote@ 5841.59 - 5845.59 ft 104.7 °FInterval 18Coyote@ 5342.06 - 5346.06 ft 104.7 °FProppant TypeWanli 16/20 Ceramic100M--Fluid Type27# Delta Frac27# LinearSeawaterFreeze ProtectConoco Phillips - 3T-730Planned Design122 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Atigan 3J 50 9,119 217 100 10 1,627 392 Atigan 3J 100 18,981 452 100 10 1,627 393 Atigan 3J 99 18,788 447 102 10 1,627 394 Atigan 3J 101 19,175 457 106 10 1,627 395 Atigan 3J 100 18,981 452 104 10 1,627 396 Atigan 3J 102 19,368 461 100 10 1,627 397 Atigan 3J 100 18,981 452 90 99 18,788 4478 Atigan 3J 98 18,595 443 94 96 18,208 4349 Atigan 3J 101 19,175 457 93 97 18,401 43810 Atigan 3J 98 18,595 443 96 95 18,014 42911 Atigan 3J 95 18,014 429 95 92 17,434 41512 Atigan 3J 100 18,981 452 91 94 17,821 42413 Wichita 3J 101 20,370 485 94 36 6,762 16114 Wichita 3J 98 19,740 470 93 10 1,890 4515 Wichita 3J 101 20,370 485 94 10 1,890 4516 Wichita 3J 96 19,320 460 91 10 1,890 4517 Wichita 3J 103 20,790 495 98 10 1,890 4518 Wichita 3J 101 20,370 485 99 10 1,890 4519 Wichita 3J 103 20,790 495 103 10 1,890 4520 Wichita 3J 105 21,000 500 104 10 1,890 4521 Wichita 3J 104 21,000 500 103 10 1,890 4522 Wichita 3J 104 21,000 500 105 10 1,890 4523 Wichita 3J 104 21,000 500 96 10 1,890 4524 Wichita 3J 102 20,580 490 95 10 1,890 4525 Wichita 3J 101 20,370 485 95 10 1,890 45Gallons Barrels Gallons Barrels Gallons Barrels483,454 11,511 147,870 3,521 335,584 7,990Conoco Phillips 3T-7305/31/2025Coyote0910106491General Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips - 3T-730Water Straps 5.31 123 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Atigan 3J 99 18,788 447 100 10 1,627 392 Atigan 3J 101 19,175 457 100 10 1,627 393 Atigan 3J 103 19,562 466 102 10 1,627 394 Atigan 3J 99 18,788 447 106 10 1,627 395 Atigan 3J 100 18,981 452 104 10 1,627 396 Atigan 3J 101 19,175 457 100 10 1,627 397 Atigan 3J 99 18,788 447 90 77 14,532 3468 Atigan 3J 96 18,208 434 94 80 15,113 3609 Atigan 3J 97 18,401 438 93 90 17,047 40610 Atigan 3J 95 18,014 429 96 75 14,146 33711 Atigan 3J 92 17,434 415 95 82 15,500 36912 Atigan 3J 96 18,208 434 91 92 17,434 41513 Wichita 3J 99 19,950 475 94 100 20,160 48014 Wichita 3J 96 19,320 460 93 102 20,580 49015 Wichita 3J 103 20,790 495 94 90 18,060 43016 Wichita 3J 100 20,160 480 91 60 11,760 28017 Wichita 3J 104 21,000 500 98 20 3,780 9018 Wichita 3J 104 21,000 500 99 10 1,890 4519 Wichita 3J 103 20,790 495 103 10 1,890 4520 Wichita 3J 105 21,000 500 104 10 1,890 4521 Wichita 3J 106 21,000 500 103 10 1,890 4522 Wichita 3J 106 21,000 500 105 10 1,890 4523 Wichita 3J 104 21,000 500 96 10 1,890 4524 Wichita 3J 105 21,000 500 95 10 1,890 4525 Wichita 3J 105 21,000 500 95 10 1,890 45Gallons Barrels Gallons Barrels Gallons Barrels492,531 11,727 192,994 4,595 299,537 7,132General Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips 3T-7306/1/2025Coyote0910106491Conoco Phillips - 3T-730Water Straps 6.1124 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Atigan 3J 102 19,368 461 99 10 1,627 392 Atigan 3J 102 19,368 461 98 10 1,627 393 Atigan 3J 101 19,175 457 97 10 1,627 394 Atigan 3J 90 17,047 406 101 10 1,627 395 Atigan 3J 100 18,981 452 100 10 1,627 396 Atigan 3J 102 19,368 461 101 10 1,627 397 Atigan 3J 72 13,565 323 82 72 13,565 3238 Atigan 3J 73 13,759 328 86 73 13,759 3289 Atigan 3J 70 13,178 314 91 70 13,178 31410 Atigan 3J 68 12,792 305 90 68 12,792 30511 Atigan 3J 68 12,792 305 87 68 12,792 30512 Atigan 3J 72 13,565 323 87 72 13,565 32313 Wichita 3J 100 20,160 480 96 100 20,160 48014 Wichita 3J 83 16,590 395 94 83 16,590 39515 Wichita 3J 75 14,910 355 75 14,910 35516 Wichita 3J 75 14,910 355 75 14,910 35517 Wichita 3J 75 14,910 355 75 14,910 35518 Wichita 3J 104 21,000 500 98 104 21,000 50019 Wichita 3J 104 21,000 500 94 10 21,000 4520 Wichita 3J 103 20,790 495 100 10 20,790 4521 Wichita 3J 105 21,000 500 98 10 21,000 4522 Wichita 3J 105 21,000 500 96 10 21,000 4523 Wichita 3J 106 21,000 500 95 10 1,890 4524 Wichita 3J 106 21,000 500 100 10 1,890 4525 Wichita 3J 106 21,000 500 99 10 1,890 45Gallons Barrels Gallons Barrels Gallons Barrels442,230 10,529 205,125 4,884 237,106 5,645General Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips 3T-7306/2/2025Coyote0910106491Conoco Phillips - 3T-730Water Straps 6.2125 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 1.022 0 16,440 1,600 2,800 440 3,240 17,3242 N 1.022 0 21,220 1,600 3,160 40 3,200 16,0243 N 1.022 0 16,440 1,200 2,960 320 3,280 15,3074 N 1.020 0 19,450 1,200 2,680 760 3,440 5,3265 N 1.020 0 19,450 1,200 2,800 480 3,280 14,9636 N 1.030 0 21,220 1,600 2,560 1,760 4,320 4,7228 N 1.032 0 23,190 1,600 2,320 3,160 5,480 4,8439 N 1.028 0 21,220 1,600 1,880 1,240 3,120 8,49210 N 1.028 0 21,220 1,600 1,880 1,000 2,880 11,08811 N 1.028 0 19,450 1,200 2,840 240 3,080 60,61312 N 1.028 0 19,450 1,600 1,520 1,120 2,640 3,36513 N 1.028 0 19,450 1,600 2,120 880 3,000 2,11014 N 1.016 0 21,220 1,200 2,200 600 2,800 22,98315 N 1.030 0 19,450 1,600 1,480 1,560 3,040 46,03416 N 1.026 0 21,220 1,600 2,440 80 2,520 27,10817 N 1.026 0 19,450 1,600 2,880 1,040 3,920 13,82618 N 1.026 0 17,870 1,600 2,400 880 3,280 3,97819 N 1.022 0 21,220 1,200 2,800 560 3,360 7,23120 N 1.022 0 17,870 1,200 2,880 920 3,800 3,84621 N 1.020 0 23,190 1,200 3,280 560 3,840 3,14822 N 1.022 0 17,870 1,200 2,560 1,000 3,560 13,12823 n 1.028 0 30,780 1,600 1,840 1,360 3,200 21,29124 N 1.024 0 17,870 1,200 2,240 1,120 3,360 25,49225 N 1.024 0 23,190 1,200 2,160 1,520 3,680 54,307Average 1.025 0 16,313 1417 1,956 755 2,711 20.4 7.29 7.60 8.71 - 16,940Maximum 1.032 0 30,780 1,600 3,280 3,160 5,480 23.0 7.50 7.85 8.80 - 60,613Minimum 1.016 0 16,440 1,200 1,480 40 2,520 19.00 7.10 7.40 8.60 - 2,110Range 0.016 0 14,340 400 1,800 3,120 2,960 4.0 0.40 0.45 0.20 - 58,502112.020.0 7.1 7.6 8.6113.020.0 7.3 7.4 8.720.0 7.44 7.71 8.80YYY8.8 y112.019.0 7.5 7.9 8.7 Y120.023.0 7.1 7.4114.0Well Name:3T-730Water Source:CPF3Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3T-730Water Analysis 5.31126 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 1.024 0 21,220 1,200 2,720 800 3,520 5,7762 N 1.022 0 23,190 1,200 2,920 680 3,600 12,5793 N 1.022 0 19,450 1,200 3,200 80 3,280 10,4834 N 1.020 0 19,450 1,200 2,560 720 3,280 2,3875 N 1.020 0 17,870 1,200 2,760 440 3,200 2,7096 N 1.022 0 17,870 1,200 2,480 640 3,120 3,53814 N 1.022 0 17,870 1,200 2,560 1,280 3,840 3,14715 N 1.020 0 21,220 1,200 2,920 1,040 3,960 5,22316 N 1.020 0 19,450 1,200 2,520 1,320 3,840 1,88017 N 1.020 0 17,870 1,200 2,480 1,480 3,960 2,69518 N 1.022 0 19,450 1,200 2,600 1,240 3,840 2,38219 N 1.020 0 19,450 1,200 2,440 1,040 3,480 1,16320 N 1.020 0 21,220 1,200 2,800 640 3,440 90121 N 1.022 0 17,870 1,200 2,520 1,200 3,720 81422 N 1.022 0 19,450 1,200 2,480 1,120 3,600 2,59123 N 1.020 0 17,870 1,200 2,600 680 3,280 2,70024 N 1.020 0 19,450 1,200 2,360 920 3,280 3,46725 N 1.022 0 17,870 1,200 2,400 800 3,200 2,353Average 1.021 0 19,338 1200 2,629 896 3,524 21.8 7.15 7.53 8.81 - 3,710Maximum 1.024 0 23,190 1,200 3,200 1,480 3,960 22.0 7.30 7.54 8.92 - 12,579Minimum 1.020 0 17,870 1,200 2,360 440 3,120 22.00 7.03 7.51 8.71 - 814Range 0.004 0 5,320 0 840 1,040 840 0.0 0.27 0.03 0.21 - 11,7658.8 Y11922.0 7.1 7.5 8.8 Y11822.0 7.0 7.58.9 Y11622.0 7.3 7.5 8.7 Y11821.0 7.2 7.5Well Name:3T-731Water Source:CPF3Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3T-730Water Analysis 6.1127 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 1.022 0 34,050 1,600 2,760 520 3,280 9522 1.022 0 19,450 1,600 2,520 1,320 3,840 1,8603 1.022 0 17,870 1,600 2,520 1,440 3,960 1,3124 1.022 0 16,440 1,600 2,480 960 3,440 1,1065 1.020 0 19,450 1,600 2,120 1,240 3,360 1,1216 1.020 0 19,450 1,600 2,480 600 3,080 2,84620 1.022 0 24,480 1,600 2,320 1,400 3,720 1,68521 1.020 0 22,570 1,600 2,240 1,560 3,800 2,47722 1.022 0 17,790 1,600 2,080 840 2,920 6,00923 1.020 0 17,790 1,600 1,760 2,000 3,760 18,09824 1.022 0 19,240 1,600 1,760 1,520 3,280 12,44325 1.022 0 22,570 1,600 1,880 1,440 3,320 3,066Average 1.021 0 20,929 1600 2,243 1237 3,480 23.0 7.04 7.44 8.66 - 4,415Maximum 1.022 0 34,050 1,600 2,760 2,000 3,960 25.0 7.09 7.54 8.72 - 18,098Minimum 1.020 0 17,790 1,600 1,760 600 2,920 21.00 7.09 7.54 8.60 - 952Range 0.002 0 16,260 0 1,000 1,400 1,040 4.0 0.00 0.00 0.12 - 17,1468.7 Y11521.0 7.1 7.5 8.6 Y12125.0 7.0 7.3Well Name:3T-730Water Source:CPF3Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3T-730Water Analysis 6.2128 Linear Linear XL XL XL Lip time Linear Linear XL XL XL Lip time Interval Stage Visc pHTemp °FpH min Interval Stage Visc pHTemp °FpHmin 1 Pad 17 7.01 90 8.8 0 11 Pad 20 7 93 8.63 0 .50# 18 7.02 92 8.87 0 18 Avg Linear Visc .50# 21 7.01 95 8.75 0 20 Avg Linear Visc 2.00# 18 7.02 90 8.9 0 89.2 Avg XLTemp 2.00# 20 7 97 8.76 0 93.6 Avg XLTemp 4.00# 18 7.01 89 8.86 0 8.8 Avg XL pH 4.00# 20 7 95 8.76 0 8.80 Avg XL pH 6.00# 17 7 90 8.83 0 6.00# 20 6.9 93 8.81 0 7.00# 18 7.01 90 8.86 0 7.00# 21 6.9 95 8.83 0 8.00# 18 7 88 8.8 0 8.00# 20 6.9 93 8.82 0 9.00# 18 7.01 89 8.8 0 9.00# 21 7 92 8.92 0 10.00# 18 7 85 8.9 0 10.00# 20 7 89 8.9 0 2 Pad 18 7 85 8.67 0 12 Pad 21 7.01 98 8.7 0 .50# 18 7.01 102 8.84 0 .50# 21 7 98 8.74 0 2.00# 18 7 87 8.87 0 2.00# 20 6.99 97 8.79 0 4.00# 18 7 91 8.8 0 18 Avg Linear Visc 4.00# 21 7 95 8.82 0 20 Avg Linear Visc 6.00# 18 7 93 8.8 0 90.4 Avg XLTemp 6.00# 20 7 95 8.85 0 93.8 Avg XLTemp 7.00# 18 7.01 91 8.81 0 8.8 Avg XL pH 7.00# 20 6.98 86 8.82 0 8.81 Avg XL pH 8.00# 17 6.99 89 8.85 0 8.00# 19 6.99 89 8.85 0 9.00# 18 6.97 88 8.81 0 9.00# 20 7 95 8.85 0 10.00# 18 7 88 8.86 0 10.00# 20 7.01 91 8.84 0 3 Pad 18 7 81 8.67 0 13 Pad197.04968.74 0 .50# 18 7.01 84 8.74 0 .50# 19 7.01 99 8.73 0 2.00# 18 7.12 85 8.76 0 2.00# 4.00# 18 7.01 84 8.74 0 18 Avg Linear Visc 4.00# 20 7.01 95 8.71 0 20 Avg Linear Visc 6.00# 18 7 82 8.72 0 81.8 Avg XLTemp 6.00# 22 7.01 91 8.78 0 90.3 Avg XLTemp 7.00# 18 6.99 82 8.77 0 8.8 Avg XL pH 7.00# 19 7.01 89 8.85 0 8.81 Avg XL pH 8.00# 18 7 80 8.9 0 8.00# 22 7 89 8.92 0 9.00# 18 7 78 8.77 0 9.00# 20 7 80 8.9 0 10.00# 18 7.02 80 8.8 0 10.00# 19 7 83 8.85 0 4 Pad 18 7.02 91 8.68 0 14 Pad 22 7 99 8.72 0 .50# 18 7 92 8.8 0 .50# 22 7.05 90 8.8 0 Pad 16 7.01 93 8.67 0 2.00# 22 7.03 93 8.73 0 2.00# 17 7 92 8.78 0 17.70 Avg Linear Visc 4.00# 22 7.05 93 8.83 0 22 Avg Linear Visc 4.00# 18 7 93 8.77 0 89.80 Avg XLTemp 6.00# 21 7.05 91 8.8 0 90.6 Avg XLTemp 6.00# 18 7.01 92 8.66 0 8.74 Avg XL pH 7.00# 22 7 85 8.9 0 8.83 Avg XL pH 7.00# 18 7 87 8.8 0 8.00# 22 7.01 89 8.9 0 8.00# 18 6.99 87 8.74 0 9.00# 22 7 87 8.89 0 9.00# 18 7 85 8.77 0 10.00# 21 7 88 8.9 0 10.00# 18 6.99 86 8.75 0 5 Pad 18 7 88 8.6 0 15 Pad 22 7.1 100 8.69 0 .50# 18 7.02 92 8.75 0 .50# 21 7.1 102 8.84 0 2.00# 19 7.01 93 8.77 0 2.00# 22 7.05 93 8.83 0 4.00# 18 7 92 8.76 0 18.11 Avg Linear Visc 4.00# 22 7.12 95 8.69 0 22 Avg Linear Visc 6.00# 18 7 85 8.78 0 86.44 Avg XLTemp 6.00# 22 7.07 96 8.71 0 92.8 Avg XLTemp 7.00# 18 7.02 86 8.79 0 8.79 Avg XL pH 7.00# 22 7.12 97 8.78 0 8.78 Avg XL pH 8.00# 18 6.96 83 8.82 0 8.00# 23 7.1 85 8.78 0 9.00# 18 7.01 80 8.92 0 9.00# 22 7.12 83 8.85 0 10.00# 18 7.02 79 8.9 0 10.00# 22 7..14 84 8.85 0 6 Pad 18 7.02 93 8.6 0 16 Pad 24 7..14 91 8.67 0 .50# 18 6.99 87 8.82 0 .50# 21 7.13 95 8.74 0 2.00# 18 7 83 8.9 0 2.00# 22 7.12 96 8.8 0 4.00# 18 6.99 84 8.8 0 18.00 Avg Linear Visc 4.00# 21 7.14 96 8.8 0 22 Avg Linear Visc 6.00# 18 7.01 83 8.86 0 81.11 Avg XLTemp 6.00# 22 7.15 95 8.82 0 91.4 Avg XLTemp 7.00# 18 7 80 8.82 0 8.82 Avg XL pH 7.00# 21 7.14 95 8.87 0 8.79 Avg XL pH 8.00# 18 7.03 73 8.83 0 8.00# 22 7.13 86 8.8 0 9.00# 18 7.01 72 8.91 0 9.00# 21 7.12 84 8.77 0 10.00# 18 7.02 75 8.80 0 10.00# 22 7.14 85 8.81 0 7 Pad 18 7.01 93 8.67 0 17 Pad217.15928.62 0 .50# 20 7.11 97 8.74 0 .50# 21 7.13 96 8.8 0 2.00# 17 7.15 97 8.75 0 2.00# 22 7.14 96 8.8 0 4.00# 19 7.11 94 8.84 0 19 Avg Linear Visc 4.00# 21 7.14 94 8.82 0 22 Avg Linear Visc 6.00# 19 7.14 88 8.99 0 90.0 Avg XLTemp 6.00# 22 7.14 96 8.85 0 90.7 Avg XLTemp 7.00# 19 7.12 89 8.93 0 8.9 Avg XL pH 7.00# 22 7.13 88 8.81 0 8.80 Avg XL pH 8.00# 20 7.11 88 8.92 0 8.00# 22 7.14 85 8.85 0 9.00# 21 7.13 81 8.92 0 9.00# 21 7.15 84 8.86 0 10.00# 21 7.11 83 8.97 0 10.00# 22 7.1 85 8.81 0 8 Pad 21 7.1 100 8.7 0 18 Pad 22 7.11 96 8.6 0 .50# 20 7.11 99 8.82 0 .50# 22 7.11 96 8.7 0 2.00# 20 7.09 97 8.82 0 2.00# 22 7.14 95 8.8 0 4.00# 20 7.11 95 8.81 0 20.11 Avg Linear Visc 4.00# 22 7.14 95 8.87 0 22 Avg Linear Visc 6.00# 20 7.12 92 8.8 0 93.44 Avg XLTemp 6.00# 22 7.13 89 8.8 0 89.8 Avg XLTemp 7.00# 20 7.12 90 8.83 0 8.83 Avg XL pH 7.00# 22 7.11 86 8.75 0 8.8 Avg XL pH 8.00# 20 7.1 92 8.84 0 8.00# 22 7.12 81 8.83 0 9.00# 20 7.09 85 8.95 0 9.00# 21 7.1 85 8.85 0 10.00# 20 7 91 8.9 0 10.00# 22 7.1 85 8.79 0 9 Pad 20 7.01 96 8.65 0 19 Pad .50# 21 7 91 8.82 0 .50# 2.00# 20 7 95 8.72 0 2.00# 4.00# 20 7.01 98 8.62 0 20 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 20 7 94 8.8 0 92.4 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 20 7 94 8.8 0 8.77 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 21 6.99 95 8.86 0 8.00# 9.00# 20 7.01 84 8.84 0 9.00# 10.00# 20 6.99 85 8.8 0 10.00# 10 Pad 20 7 93 8.61 0 20 Pad .50# 20 6.99 91 8.8 0 .50# 2.00# 20 7 93 8.82 0 2.00# 4.00# 20 6.99 91 8.83 0 20 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 20 7 85 8.85 0 90.2 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 20 7 90 8.84 0 8.81 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 20 7 89 8.87 0 . 8.00# 9.00# 20 7 90 8.8 0 9.00# 10.00# 20 6.99 90 8.85 0 10.00# Customer:CONOCO PHILLIPS Wellname & #:3T-730 Date:May 31, 2025 Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Conoco Phillips - 3T-730 Real-Time QC 129 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:09:40 (05/31/25) Start Job Starting Job 0 107 -3 0 0 1 06:09:40 (05/31/25) Next Treatment Treatment Interval 1 0 107 -3 0 0 2 6:50:16 Other Loop Test 0 0 -1 0 1714 3 6:55:59 Prime Pumps Prime Pumps 0 239 307 0 1714 4 7:11:25 Pressure Test ePRV - Primary Tubing 0 621 687 0 1714 5 7:12:54 Pressure Test ePRV - Primary IA 0 753 843 0 1714 6 7:15:56 Pressure Test ePRV - Secondary Tubing 0 847 909 0 1714 7 7:17:38 Pressure Test ePRV - Secondary IA 0 1580 1669 0 1714 8 7:19:39 Pressure Test Pressure Test - Global 0 1401 125 0 1714 9 7:19:55 Pressure Test Pressure Test - Locals 0 1398 1095 0 1714 10 7:23:34 Pressure Test Pressure Test - Max 0 9359 9463 0 1714 11 7:28:39 Pressure Test Pressure Test - Pass 0 9234 9304 0 1714 12 7:41:07 Open Well Open Well 0 350 315 0 1805 13 7:42:35 Other Start DFIT 4.49 1495 1562 8.6 2989 14 7:44:51 ISIP ISIP 24.73 700 660 0 2405 15 7:49:49 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 24.73 664 675 0 2346 16 7:54:49 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 24.73 563 587 0 2302 17 7:59:48 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 24.73 515 544 0 2248 18 8:17:16 Other Step 1 26.03 863 917 1.1 2619 19 8:18:23 Other Step 2 28.21 925 960 2 2665 20 8:19:23 Other Step 2 31.06 964 1001 2.9 2712 21 8:20:27 Other Step 3 35.12 987 1032 3.9 2750 22 8:21:26 Other Step 4 39.87 1005 1045 4.9 2778 23 8:22:22 Other Step 5 45.52 1025 1065 6 2813 24 8:23:25 Other Step 6 52.77 1026 1065 6.9 2834 25 8:24:24 Other Step 7 60.48 1041 1080 7.9 2864 26 8:25:22 Other Step 8 68.85 1076 1118 8.8 2892 27 8:26:19 Other Step 9 78.27 1138 1196 9.8 2934 28 8:31:16 Start Pad Start Pad 157.71 1818 1909 20 3416 29 8:32:05 Other 1st Tracer Drop 174.43 1884 1970 20.1 3433 30 8:34:33 Alarm Delta Stage At Top Perf = 4 223.73 2064 2194 19.8 3516 31 8:35:48 Alarm Delta Stage At Top Perf = 6 248.48 2149 2285 20 3572 32 8:38:33 Alarm Delta Stage At Top Perf = 7 303.97 2147 2260 20.3 3537 33 8:42:37 Alarm Delta Stage At Top Perf = 8 386.49 2174 2284 20.2 3563 34 8:52:38 Alarm Delta Stage At Top Perf = 9 588.22 1969 2072 20 3496 35 8:59:56 Alarm Delta Stage At Top Perf = 10 733.58 1852 1994 19.8 3633 36 9:03:19 Alarm Delta Stage At Top Perf = 11 800.49 1861 2003 19.8 3695 37 9:04:37 Other 2nd Tracer Drop 826.16 1872 2025 19.7 3710 38 9:09:20 Alarm Delta Stage At Top Perf = 12 918.74 1904 2023 19.7 3780 39 9:15:42 Alarm Delta Stage At Top Perf = 13 1044.01 1909 2039 19.6 3801 40 9:26:04 Alarm Delta Stage At Top Perf = 14 1246.72 1995 2143 20.2 3935 41 9:30:27 Other 3rd Tracer Drop 1335.1 1996 2112 20.1 3953 42 9:35:26 Alarm Delta Stage At Top Perf = 15 1435.37 2057 2136 20.1 4015 43 9:38:55 Drop Ball Drop Dart for Interval 02 1506.96 2420 2470 21 4091 2 09:38:55 (05/31/25) Next Treatment Treatment Interval 2 1506.96 2425 2473 21 4086 44 9:41:28 Alarm Delta Stage At Top Perf = 16 1560.68 2344 2392 21.1 3920 45 9:41:55 Other 1st Tracer Drop 1569.83 2291 2400 21.1 3869 46 9:47:53 Alarm Delta Stage At Top Perf = 17 1693.19 1887 1993 20.6 3252 47 9:48:14 Ball on Seat Dart on Seat 1700.39 1883 1984 20.6 3258 48 9:48:19 Break Formation Break Formation 1702.11 3740 3939 20.6 5270 49 9:49:17 Alarm Delta Stage At Top Perf = 1 1721.93 2601 2652 20.5 3888 50 9:51:00 Alarm Delta Stage At Top Perf = 2 1757.2 2238 2359 20.5 3625 51 9:52:08 Alarm Delta Stage At Top Perf = 3 1780.49 2245 2331 20.5 3603 52 10:02:07 Alarm Delta Stage At Top Perf = 4 1984.13 1934 2029 20 3425 53 10:09:27 Alarm Delta Stage At Top Perf = 5 2129.55 1798 1927 19.7 3524 54 10:12:52 Alarm Delta Stage At Top Perf = 6 2196.8 1772 1901 19.7 3581 55 10:16:42 Other 2nd Tracer Drop 2272.08 1784 1913 19.6 3648 56 10:18:57 Alarm Delta Stage At Top Perf = 7 2316.18 1812 1953 19.6 3690 57 10:25:23 Alarm Delta Stage At Top Perf = 8 2442.26 1853 1966 19.5 3727 58 10:35:39 Alarm Delta Stage At Top Perf = 9 2646.18 1910 2033 20 3812 59 10:42:54 Other 3rd Tracer Drop 2790.84 1892 2037 19.9 3875 60 10:45:04 Alarm Delta Stage At Top Perf = 10 2833.97 1935 2096 19.9 3910 3 10:48:42 (05/31/25) Next Treatment Treatment Interval 3 2908.36 2308 2443 20.7 3974 61 10:48:42 Drop Ball Drop Dart for Interval 03 2908.36 2308 2444 20.7 3975 62 10:51:13 Alarm Delta Stage At Top Perf = 11 2960.65 2292 2387 21 3862 63 10:57:32 Ball on Seat Dart on Seat 3092.83 1792 1892 20.6 3194 64 10:57:37 Break Formation Break Formation 3094.89 3720 3794 20.6 5181 65 10:57:42 Alarm Delta Stage At Top Perf = 12 3096.6 3972 4157 20.6 5474 66 10:58:37 Alarm Delta Stage At Top Perf = 1 3115.39 2417 2492 20.5 3799 67 11:00:44 Alarm Delta Stage At Top Perf = 2 3158.81 2265 2387 20.5 3672 68 11:01:59 Alarm Delta Stage At Top Perf = 3 3184.48 2252 2356 20.5 3648 69 11:12:00 Alarm Delta Stage At Top Perf = 4 3388.83 1849 1972 20.2 3372 70 11:19:20 Alarm Delta Stage At Top Perf = 5 3535.31 1731 1846 19.8 3443 71 11:22:58 Alarm Delta Stage At Top Perf = 6 3607.1 1696 1808 19.7 3519 72 0.475069444 Other 2nd Tracer Drop 3629.46 1711 1852 19.7 3545 73 11:28:54 Alarm Delta Stage At Top Perf = 7 3725.06 1774 1903 20 3631 74 11:35:09 Alarm Delta Stage At Top Perf = 8 3850.54 1791 1957 20 3684 75 11:45:20 Alarm Delta Stage At Top Perf = 9 4054.07 1795 1991 19.9 3750 76 11:50:36 Other 3rd Tracer Drop 4158.98 1810 1937 19.9 3768 77 11:54:47 Alarm Delta Stage At Top Perf = 10 4242.19 1858 1985 20 3831 78 11:59:06 Drop Ball Drop Dart for Interval 4 4329.71 2257 2355 20.6 3895 4 11:59:07 (05/31/25) Next Treatment Treatment Interval 4 4329.71 2257 2352 20.6 3895 79 12:01:06 Alarm Delta Stage At Top Perf = 11 4370.95 2248 2332 20.7 3813 80 12:02:30 Other 1st Tracer Drop 4400.17 2061 2164 20.9 3621 81 12:07:23 Alarm Delta Stage At Top Perf = 12 4502.2 1796 1899 20.9 3184 82 12:07:43 Ball on Seat Dart on Seat 4508.83 1801 1903 20.9 3201 83 12:07:47 Break Formation Break Formation 4510.22 3619 3727 20.9 5096 84 12:08:45 Alarm Delta Stage At Top Perf = 1 4530.68 2860 2955 20.8 4212 85 12:10:35 Alarm Delta Stage At Top Perf = 2 4568.86 2545 2640 20.8 3919 86 12:11:55 Alarm Delta Stage At Top Perf = 3 4596.66 2437 2531 20.9 3838 87 12:21:51 Other ADP Mixing Bowl Seal 4802.6 1912 1971 20.6 3428 88 12:22:05 Alarm Delta Stage At Top Perf = 4 4807.33 1138 1175 15.4 2797 89 12:34:00 Alarm Delta Stage At Top Perf = 5 4953.13 1570 1580 13.2 3086 90 12:36:59 ISIP ISIP 4990.96 825 824 0 2646 91 12:45:44 Other Replace Mixing Bowl Seal & Mix Gel 4990.96 799 812 0 2618 92 12:48:13 Alarm Delta Stage At Top Perf = 6 4992.41 1189 1263 6.9 2910 93 12:58:44 Alarm Delta Stage At Top Perf = 7 5192.1 1874 1983 20.7 3277 94 12:59:19 Alarm Delta Stage At Top Perf = 8 5204.2 1860 1975 20.8 3259 95 13:00:31 Alarm Delta Stage At Top Perf = 9 5229.1 1939 2051 20.8 3354 96 13:11:37 Other Offloading Gel 5457.86 1867 1975 20.1 3429 97 13:17:39 Alarm Delta Stage At Top Perf = 10 5578.73 1935 2119 19.8 3548 98 13:21:00 Alarm Delta Stage At Top Perf = 11 5645.09 2005 2158 19.8 3647 99 13:24:26 Other 2nd Tracer Drop 5713.09 2136 2303 20 3800 100 13:26:56 Alarm Delta Stage At Top Perf = 12 5763.26 2055 2172 20.1 3876 101 13:33:11 Alarm Delta Stage At Top Perf = 13 5888.63 1918 2047 20 3786 102 13:43:21 Alarm Delta Stage At Top Perf = 14 6092.14 1867 1992 20 3798 103 13:49:13 Other 3rd Tracer Drop 6209.41 1887 2039 20 3821 104 13:52:49 Alarm Delta Stage At Top Perf = 15 6280.74 1905 2001 19.8 3851 5 13:57:10 (05/31/25) Next Treatment Treatment Interval 5 6368.88 2244 2359 20.6 3915 105 13:57:11 Drop Ball Drop Dart for Interval 05 6369.22 2247 2359 20.6 3908 106 13:59:02 Alarm Delta Stage At Top Perf = 16 6407.35 2276 2403 20.6 3873 107 14:05:09 Alarm Delta Stage At Top Perf = 17 6534.89 1853 1978 20.9 3240 108 14:05:26 Ball on Seat Dart on Seat 6540.47 1849 1944 20.9 3246 109 14:05:36 Break Formation Break Formation 6543.94 3660 3848 20.8 5198 110 14:06:28 Alarm Delta Stage At Top Perf = 1 6562.29 2508 2605 20.8 3873 111 14:07:20 Other 1st Tracer Drop 6580.32 2307 2414 20.9 3671 112 14:08:22 Alarm Delta Stage At Top Perf = 2 6601.84 2337 2491 20.8 3802 113 14:09:14 Alarm Delta Stage At Top Perf = 3 6619.84 2400 2512 20.8 3776 114 14:19:12 Alarm Delta Stage At Top Perf = 4 6826.16 1993 2101 20.5 3498 115 14:26:25 Alarm Delta Stage At Top Perf = 5 6972.05 1805 1976 20 3513 116 14:29:45 Alarm Delta Stage At Top Perf = 6 7038.53 1721 1848 20 3530 117 14:32:57 Other 2nd Tracer Drop 7101.99 1722 1894 19.9 3562 118 14:35:42 Alarm Delta Stage At Top Perf = 7 7157 1737 1847 19.9 3606 119 14:42:00 Alarm Delta Stage At Top Perf = 8 7282.24 1770 1867 19.8 3645 120 14:52:11 Alarm Delta Stage At Top Perf = 9 7485.78 1775 1959 19.9 3699 121 14:58:00 Other 3rd Tracer Drop 7601.76 1766 1939 19.9 3742 122 15:01:37 Alarm Delta Stage At Top Perf = 10 7673.74 1780 1960 19.9 3785 6 15:06:39 (05/31/25) Next Treatment Treatment Interval 6 7775.81 2199 2326 20.8 3863 123 15:06:40 Drop Ball Drop Dart for Interval 6 7776.16 2200 2325 20.8 3861 124 15:07:45 Alarm Delta Stage At Top Perf = 11 7798.76 2274 2368 20.8 3857 125 15:09:44 Other 1st Tracer Drop 7840.26 2039 2121 21.1 3626 126 15:14:11 Alarm Delta Stage At Top Perf = 12 7932.56 1775 1898 20.5 3177 127 15:14:30 Ball on Seat Dart on Seat 7939.06 1781 1887 20.5 3187 128 15:14:36 Break Formation Break Formation 7941.11 3813 3922 20.5 5331 129 15:15:32 Alarm Delta Stage At Top Perf = 1 7960.18 2420 2513 20.4 3790 130 15:17:45 Alarm Delta Stage At Top Perf = 2 8005.55 2141 2262 20.5 3550 131 15:18:27 Alarm Delta Stage At Top Perf = 3 8019.91 2135 2221 20.5 3537 132 15:28:38 Alarm Delta Stage At Top Perf = 4 8228.24 1802 1885 20.2 3302 133 15:35:57 Alarm Delta Stage At Top Perf = 5 8374.85 1661 1776 19.9 3374 134 15:39:34 Alarm Delta Stage At Top Perf = 6 8446.56 1610 1731 19.8 3424 135 15:41:51 Other 2nd Tracer Drop 8491.76 1624 1759 19.8 3451 136 15:45:38 Alarm Delta Stage At Top Perf = 7 8566.48 1608 1760 19.7 3513 137 15:52:02 Alarm Delta Stage At Top Perf = 8 8692.68 1663 1811 19.7 3557 138 16:02:26 Alarm Delta Stage At Top Perf = 9 8896.83 1680 1834 19.6 3614 139 16:08:24 Other 3rd Tracer Drop 9013.24 1654 1819 19.6 3645 140 16:12:05 Alarm Delta Stage At Top Perf = 10 9085.48 1694 1850 19.5 3664 141 16:18:45 Alarm Delta Stage At Top Perf = 11 9219.5 2075 2183 20.4 3667 142 16:24:20 ISIP ISIP 9331.08 981 983 0 2738 143 16:29:21 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 9331.08 365 339 0 2728 144 16:34:24 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 9331.08 131 97 0 2719 145 16:39:23 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 9331.08 224 286 0 2712 Event Log 5.31.25 Conoco Phillips - 3T-730 Event Log 5.31 130 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 10:02:24 (06/01/25) Start Job Starting Job 0 -10 1 3.7 2105 1 10:02:24 (06/01/25) Next Treatment Treatment Interval 1 0 -10 1 3.7 2105 7 10:20:48 (06/01/25) Next Treatment Treatment Interval 7 0.26 -11 1 0 2102 2 11:01:27 Prime Pumps Prime Pumps 0.26 -13 3 0 2095 3 11:11:21 Pressure Test ePRV - Primary Tubing 0.26 1217 1302 0 2093 4 11:13:24 Pressure Test ePRV - Primary IA 0.26 584 711 0 2093 5 11:16:41 Pressure Test ePRV - Secondary Tubing 0.26 500 596 0 2093 6 11:17:39 Pressure Test ePRV - Secondary IA 0.26 891 989 0 2092 7 11:19:44 Pressure Test Pressure Test - Global 0.26 609 649 0 2092 8 11:19:52 Pressure Test Pressure Test - Locals 0.26 679 771 0 2092 9 11:22:57 Pressure Test Pressure Test - Max 0.26 9452 9548 0 2092 10 11:27:57 Pressure Test Pressure Test - Pass 0.26 9320 9394 0 2091 11 11:51:46 Open Well Open Well 0.26 484 477 0 2121 12 11:54:27 Drop Ball Drop Dart for Interval 07 22.88 1748 1735 13.1 3186 13 12:03:25 Alarm Delta Stage At Top Perf = 2 176.3 1926 2040 20.4 3280 14 12:03:26 Alarm Delta Stage At Top Perf = 4 176.64 1926 2036 20.4 3285 15 12:03:31 Ball on Seat Dart on Seat 178 1926 2031 20.4 3286 16 12:03:37 Break Formation Break Formation 180.03 3564 3748 20.3 5107 17 12:04:52 Alarm Delta Stage At Top Perf = 5 205.77 2130 2262 20.3 3545 18 12:06:12 Alarm Delta Stage At Top Perf = 6 232.94 2092 2227 20.4 3465 19 12:16:23 Alarm Delta Stage At Top Perf = 7 439.97 1910 2012 20.2 3330 20 12:23:42 Alarm Delta Stage At Top Perf = 8 586.82 1698 1823 20 3366 21 12:27:28 Alarm Delta Stage At Top Perf = 9 661.85 1645 1790 19.9 3405 22 12:30:07 Other 2nd Tracer Drop 714.2 1630 1783 19.9 3440 23 12:33:27 Alarm Delta Stage At Top Perf = 10 780.25 1653 1795 19.8 3478 24 12:39:45 Alarm Delta Stage At Top Perf = 11 905.1 1642 1809 19.8 3533 25 12:50:01 Alarm Delta Stage At Top Perf = 12 1109.44 1668 1853 19.9 3587 26 12:56:29 Other 3rd Tracer Drop 1237.91 1672 1855 19.8 3613 27 12:59:32 Alarm Delta Stage At Top Perf = 13 1298.67 1699 1883 19.8 3645 8 13:04:44 (06/01/25) Next Treatment Treatment Interval 8 1403.21 2095 2197 20.5 3699 28 13:04:46 Drop Ball Drop Dart for Interval 04 1403.9 2104 2205 20.5 3709 29 13:05:50 Alarm Delta Stage At Top Perf = 14 1425.76 2133 2190 20.5 3689 30 13:11:37 Alarm Delta Stage At Top Perf = 15 1545.77 1765 1862 20.8 3096 31 13:12:02 Ball on Seat Dart on Seat 1554.43 1768 1885 20.8 3103 32 13:12:08 Break Formation Break Formation 1556.51 4995 5144 20.7 6348 33 13:12:53 Alarm Delta Stage At Top Perf = 1 1572.04 2972 3048 20.7 4240 34 13:14:52 Alarm Delta Stage At Top Perf = 2 1613.14 2330 2456 20.7 3660 35 13:16:09 Alarm Delta Stage At Top Perf = 3 1639.8 2264 2339 20.7 3570 36 13:26:12 Alarm Delta Stage At Top Perf = 4 1847.65 1830 1959 20.4 3260 37 13:33:26 Alarm Delta Stage At Top Perf = 5 1994.79 1659 1779 20.3 3312 38 13:36:48 Alarm Delta Stage At Top Perf = 6 2062.7 1611 1711 20.2 3352 39 13:40:01 Other 2nd Tracer Drop 2127.52 1592 1741 20.1 3374 40 13:42:45 Alarm Delta Stage At Top Perf = 7 2182.42 1575 1737 20.1 3406 41 13:48:58 Alarm Delta Stage At Top Perf = 8 2306.84 1611 1776 20 3440 42 13:59:10 Alarm Delta Stage At Top Perf = 9 2511.25 1581 1673 20 3484 43 14:07:19 Other 3rd Tracer Drop 2674.22 1586 1775 20 3534 44 14:08:36 Alarm Delta Stage At Top Perf = 10 2699.82 1590 1723 20 3541 45 14:14:41 Drop Ball Drop Dart for Interval 9 2819.18 1984 2125 20.5 3606 9 14:14:42 (06/01/25) Next Treatment Treatment Interval 9 2819.52 1984 2119 20.5 3611 46 14:15:05 Alarm Delta Stage At Top Perf = 11 2827.84 2018 2111 20.6 3590 47 14:21:11 Alarm Delta Stage At Top Perf = 12 2953.59 1655 1787 20.6 3036 48 14:21:38 Ball on Seat Dart on Seat 2962.49 1674 1779 20.5 3037 49 14:21:48 Break Formation Break Formation 2965.9 4190 4362 20.4 5660 50 14:22:35 Alarm Delta Stage At Top Perf = 1 2982.18 3465 3568 20.4 4774 51 14:24:39 Alarm Delta Stage At Top Perf = 2 3024.24 2561 2680 20.4 3926 52 14:25:27 Alarm Delta Stage At Top Perf = 3 3040.51 2395 2494 20.4 3734 53 14:35:34 Alarm Delta Stage At Top Perf = 4 3246.96 1854 1977 20.2 3287 54 14:42:53 Alarm Delta Stage At Top Perf = 5 3393.93 1645 1806 20 3323 55 14:46:17 Alarm Delta Stage At Top Perf = 6 3461.7 1597 1712 19.9 3350 56 14:52:21 Alarm Delta Stage At Top Perf = 7 3582.26 1567 1718 19.8 3416 57 14:58:40 Alarm Delta Stage At Top Perf = 8 3707.44 1538 1701 19.8 3428 58 15:08:55 Alarm Delta Stage At Top Perf = 9 3911.48 1558 1683 20.2 3482 59 15:18:20 Alarm Delta Stage At Top Perf = 10 4100.9 1559 1731 20.1 3536 10 15:24:18 (06/01/25) Next Treatment Treatment Interval 10 4221.82 1981 2098 20.7 3590 60 15:24:18 Drop Ball Drop Dart for Interval 10 4221.82 1982 2109 20.7 3604 61 15:24:35 Alarm Delta Stage At Top Perf = 11 4228.03 1989 2085 20.7 3593 62 15:30:26 Alarm Delta Stage At Top Perf = 12 4349.4 1653 1770 20.7 3061 63 15:30:46 Ball on Seat Dart on Seat 4355.95 1671 1798 20.7 3065 64 15:30:51 Break Formation Break Formation 4358.01 4100 4222 20.6 5793 65 15:31:46 Alarm Delta Stage At Top Perf = 1 4376.93 1912 2006 20.6 3280 66 15:33:40 Alarm Delta Stage At Top Perf = 2 4416.29 1864 1990 20.7 3254 67 15:36:42 Alarm Delta Stage At Top Perf = 3 4478.81 1892 2012 20.7 3282 68 15:46:33 Alarm Delta Stage At Top Perf = 4 4682.5 1797 1932 20.5 3228 69 15:53:46 Alarm Delta Stage At Top Perf = 5 4829.45 1883 2047 20.3 3367 70 0.664664352 Alarm Delta Stage At Top Perf = 6 4897.07 1852 2009 20.1 3448 71 16:03:02 Alarm Delta Stage At Top Perf = 7 5016.39 1597 1733 20.1 3435 72 16:09:17 Alarm Delta Stage At Top Perf = 8 5142.12 1532 1663 20.1 3398 73 16:19:26 Alarm Delta Stage At Top Perf = 9 5345.94 1515 1672 20.1 3430 74 16:27:37 Other 3rd Tracer Drop 5509.89 1548 1689 20 3458 75 16:28:53 Alarm Delta Stage At Top Perf = 10 5535.2 1479 1650 20 3468 76 16:35:35 Drop Ball Drop Dart for Interval 11 5663.83 1926 2017 20.5 3528 11 16:35:38 (06/01/25) Next Treatment Treatment Interval 11 5664.85 1929 2048 20.5 3529 77 16:35:40 Alarm Delta Stage At Top Perf = 11 5665.63 1930 2043 20.5 3537 78 16:39:44 Other 1st Tracer Drop 5750.04 1615 1737 20.9 3134 79 16:41:34 Break Formation Break Formation 5788.06 1638 1803 20.9 3070 80 16:41:50 Ball on Seat Dart on Seat 5793.62 1664 1773 20.9 3061 81 16:41:54 Alarm Delta Stage At Top Perf = 12 5795.01 3351 3427 20.9 4739 82 16:42:43 Alarm Delta Stage At Top Perf = 1 5812.41 1937 2035 20.9 3271 83 16:45:00 Alarm Delta Stage At Top Perf = 2 5860.07 1830 1950 20.9 3197 84 16:46:17 Alarm Delta Stage At Top Perf = 3 5886.92 1843 1943 20.9 3190 85 16:56:17 Alarm Delta Stage At Top Perf = 4 6095.37 1725 1830 20.6 3135 86 17:03:35 Alarm Delta Stage At Top Perf = 5 6245.04 1525 1679 20.4 3198 87 17:06:54 Alarm Delta Stage At Top Perf = 6 6312.59 1530 1668 20.3 3240 88 17:12:45 Alarm Delta Stage At Top Perf = 7 6431.2 1458 1631 20.2 3281 89 17:18:53 Alarm Delta Stage At Top Perf = 8 6555.25 1473 1597 20.2 3316 90 17:29:02 Alarm Delta Stage At Top Perf = 9 6759.85 1445 1594 20.1 3356 91 17:37:20 Other 3rd Tracer Drop 6926.61 1447 1581 20.1 3381 92 17:38:26 Alarm Delta Stage At Top Perf = 10 6948.7 1443 1575 20.1 3404 93 17:44:53 Drop Ball Drop Dart for Interval 11 7079.57 1774 1896 20.7 3439 94 17:45:00 Alarm Delta Stage At Top Perf = 11 7082.33 1796 1969 20.7 3445 12 17:45:06 (06/01/25) Next Treatment Treatment Interval 12 7084.4 1817 1942 20.7 3469 95 17:49:22 Other 1st Tracer Drop 7173.25 1563 1675 21 3071 96 17:50:25 Alarm Delta Stage At Top Perf = 12 7195.23 1581 1715 20.9 3033 97 17:50:50 Ball on Seat Dart on Seat 7203.93 1601 1751 20.9 3042 98 17:50:54 Break Formation Break Formation 7205.32 2950 2999 20.9 4411 99 17:51:48 Alarm Delta Stage At Top Perf = 1 7224.1 2088 2171 20.9 3437 100 17:53:53 Alarm Delta Stage At Top Perf = 2 7267.58 1994 2105 20.8 3394 101 17:55:47 Alarm Delta Stage At Top Perf = 3 7307.2 2014 2097 20.8 3394 102 0.751099537 Alarm Delta Stage At Top Perf = 4 7428.27 1768 1902 20.9 3179 103 18:08:54 Alarm Delta Stage At Top Perf = 5 7578.82 1551 1658 20.4 3203 104 18:11:28 Alarm Delta Stage At Top Perf = 6 7630.71 1454 1614 20.3 3234 105 18:13:08 Other 2nd Tracer Drop 7664.59 1421 1568 20.3 3231 106 18:15:54 Alarm Delta Stage At Top Perf = 7 7721.02 1408 1546 20.3 3252 107 18:20:32 Alarm Delta Stage At Top Perf = 8 7814.88 1417 1537 20.2 3282 108 18:28:03 Alarm Delta Stage At Top Perf = 9 7966.46 1396 1558 20.2 3302 109 18:32:21 Other 3rd Tracer Drop 8053.06 1362 1500 20.1 3305 110 18:35:06 Alarm Delta Stage At Top Perf = 10 8108.4 1353 1490 20.1 3318 111 18:40:00 Alarm Delta Stage At Top Perf = 11 8209.24 1759 1847 20.6 3344 112 18:44:02 ISIP ISIP 8290.59 808 885 0 2774 113 18:49:06 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 8290.59 12 293 0 2756 114 18:54:08 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 8290.59 -6 90 0 2745 115 18:59:08 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 8290.59 -18 70 0 2738 Event Log 6.1.25 Conoco Phillips - 3T-730 Event Log 6.1 131 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:21:16 (06/02/25) Start Job Starting Job 0 0 0 0 0 1 06:21:16 (06/02/25) Next Treatment Treatment Interval 1 0 0 0 0 0 13 06:22:49 (06/02/25) Next Treatment Treatment Interval 13 0 12 0 0 2032 2 6:52:58 Prime Pumps Prime Pumps 0 185 207 0 2018 3 6:59:16 Pressure Test ePRV - Primary Tubing 0 712 659 0 2016 4 7:00:41 Pressure Test ePRV - Primary IA 0 662 642 0 2015 5 7:03:53 Pressure Test ePRV - Secondary Tubing 0 1166 483 0 2014 6 7:05:54 Pressure Test ePRV - Secondary IA 0 1551 1527 0 2013 7 7:08:33 Pressure Test Pressure Test - Global 0 1427 820 0 2012 8 7:08:38 Pressure Test Pressure Test - Locals 0 1425 854 0 2012 9 7:16:39 Pressure Test Pressure Test - Max 0 9431 9512 0 2008 10 7:21:12 Pressure Test Pressure Test - Pass 0 9316 9375 0 2007 11 7:23:07 Other Grease the Wellhead 0 21 19 0 2006 12 8:15:14 Open Well Open Well 0 423 431 0 2084 13 8:18:15 Drop Ball Drop Dart for Interval 13 21.81 1515 1493 11.3 3078 14 8:25:50 Alarm Delta Stage At Top Perf = 3 133.48 1384 1422 15.5 2992 15 8:25:51 Alarm Delta Stage At Top Perf = 4 133.73 1384 1418 15.5 2986 16 8:25:56 Ball on Seat Dart on Seat 134.77 1388 1430 15.5 2984 17 8:26:00 Break Formation Break Formation 136.06 3842 3655 15.5 5571 18 8:26:29 Other Start DFIT 142.96 1626 1652 10.7 3245 19 8:28:06 Alarm Delta Stage At Top Perf = 5 159.59 1329 1367 10.1 3035 20 8:28:40 ISIP ISIP 164.6 815 789 0 2682 21 8:33:39 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 164.6 781 791 0 2647 22 8:38:39 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 164.6 657 673 0 2624 23 8:43:40 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 164.6 535 557 0 2601 24 9:32:16 Open Well Open Well 164.6 521 571 0 2381 25 9:36:09 Start Pad Start Pad 220.63 1513 1634 20.5 3093 26 9:38:58 Alarm Delta Stage At Top Perf = 6 278.14 1548 1665 20.3 2975 27 9:39:57 Alarm Delta Stage At Top Perf = 8 298.36 1571 1696 20.4 2984 28 9:42:18 Alarm Delta Stage At Top Perf = 9 346.24 1687 1776 20.3 3030 29 9:48:01 Alarm Delta Stage At Top Perf = 10 462.48 1682 1811 20.4 3074 30 9:55:18 Alarm Delta Stage At Top Perf = 11 608.78 1489 1599 19.9 3120 31 9:57:56 Alarm Delta Stage At Top Perf = 12 660.97 1411 1546 19.8 3150 32 9:59:42 Other 2nd Tracer Drop 695.6 1371 1525 19.8 3153 33 10:02:30 Alarm Delta Stage At Top Perf = 13 751.23 1362 1461 19.7 3183 34 10:07:13 Alarm Delta Stage At Top Perf = 14 844.65 1334 1483 20 3212 35 10:14:52 Alarm Delta Stage At Top Perf = 15 997.59 1318 1510 20 3231 36 10:19:45 Other 3rd Tracer Drop 1094.95 1316 1450 20 3231 37 10:21:56 Alarm Delta Stage At Top Perf = 16 1138.75 1347 1492 19.9 3255 14 10:26:26 (06/02/25) Next Treatment Treatment Interval 14 1230.37 1679 1827 20.6 3285 38 10:26:26 Drop Ball Drop Dart for Interval 14 1230.37 1679 1826 20.6 3285 39 10:26:28 Alarm Delta Stage At Top Perf = 17 1231.18 1680 1816 20.6 3278 40 10:31:08 Alarm Delta Stage At Top Perf = 18 1328.14 1483 1594 20.8 2968 41 10:31:13 Other 1st Tracer Drop 1329.87 1477 1603 20.8 2969 42 10:31:37 Ball on Seat Dart on Seat 1338.16 1519 1634 20.7 2959 43 10:31:42 Break Formation Break Formation 1339.54 4315 4498 20.7 5892 44 10:32:30 Alarm Delta Stage At Top Perf = 1 1356.38 2153 2269 20.6 3513 45 10:34:45 Alarm Delta Stage At Top Perf = 2 1403.21 1798 1917 20.8 3138 46 10:35:50 Alarm Delta Stage At Top Perf = 3 1425.7 1764 1870 20.7 3096 47 10:41:40 Alarm Delta Stage At Top Perf = 4 1546.28 1640 1758 20.7 3042 48 10:48:52 Alarm Delta Stage At Top Perf = 5 1692.62 1404 1526 20.1 3032 49 10:51:27 Alarm Delta Stage At Top Perf = 6 1744.33 1338 1470 20 3054 50 10:54:05 Other 2nd Tracer Drop 1796.75 1228 1374 20 3052 51 10:55:58 Alarm Delta Stage At Top Perf = 7 1834.71 1232 1432 20 3070 52 11:00:38 Alarm Delta Stage At Top Perf = 8 1927.63 1271 1366 20 3086 53 11:08:11 Alarm Delta Stage At Top Perf = 9 2078.23 1232 1372 19.9 3113 54 11:13:25 Other 3rd Tracer Drop 2182.36 1203 1329 19.9 3120 55 11:15:20 Alarm Delta Stage At Top Perf = 10 2220.34 1211 1346 19.8 3134 56 11:20:18 Alarm Delta Stage At Top Perf = 11 2320.83 1545 1631 20.5 3171 57 11:20:34 Drop Ball Drop Dart for Interval 15 2326.31 1568 1670 20.5 3173 15 11:20:34 (06/02/25) Next Treatment Treatment Interval 15 2326.31 1568 1670 20.5 3173 58 11:23:52 Other 1st Tracer Drop 2394.39 1329 1422 21 2922 59 11:24:52 Alarm Delta Stage At Top Perf = 12 2415.38 1392 1478 21 2896 60 11:25:22 Ball on Seat Dart on Seat 2425.87 1419 1542 21 2901 61 11:25:27 Break Formation Break Formation 2427.62 3142 3377 20.9 4847 62 11:26:11 Alarm Delta Stage At Top Perf = 1 2442.92 2094 2220 20.9 3521 63 11:28:33 Alarm Delta Stage At Top Perf = 2 2492.38 1770 1882 20.9 3102 64 11:29:12 Alarm Delta Stage At Top Perf = 3 2505.98 1737 1857 20.9 3078 65 11:34:57 Alarm Delta Stage At Top Perf = 4 2625.85 1642 1748 20.8 3020 66 0.487546296 Alarm Delta Stage At Top Perf = 5 2772.28 1406 1528 20.4 3035 67 11:44:40 Alarm Delta Stage At Top Perf = 6 2825.18 1376 1529 20.2 3048 68 11:49:15 Alarm Delta Stage At Top Perf = 7 2917.13 1247 1422 20 3054 69 11:52:10 Other Pump 670 Packing - Swap Rate 2975.44 1216 1264 19.4 3020 70 11:54:00 Alarm Delta Stage At Top Perf = 8 3010.52 1197 1365 20.1 3058 71 12:01:36 Alarm Delta Stage At Top Perf = 9 3161.8 1145 1296 19.9 3069 72 12:08:46 Alarm Delta Stage At Top Perf = 10 3304.18 1115 1287 19.8 3090 73 12:13:46 Alarm Delta Stage At Top Perf = 11 3405.37 1459 1556 20.6 3109 74 12:13:56 Drop Ball Drop Dart for Interval 16 3408.79 1473 1594 20.6 3113 16 12:14:02 (06/02/25) Next Treatment Treatment Interval 16 3410.85 1486 1596 20.6 3111 75 12:17:54 Alarm Delta Stage At Top Perf = 12 3490.93 1328 1445 21 2888 76 12:18:28 Ball on Seat Dart on Seat 3502.47 1354 1476 20.9 2878 77 12:18:32 Break Formation Break Formation 3504.21 3520 3714 20.6 5312 78 12:19:18 Alarm Delta Stage At Top Perf = 1 3519.98 2696 2785 20.7 4147 79 12:21:28 Alarm Delta Stage At Top Perf = 2 3564.97 2428 2527 20.8 3776 80 12:22:51 Alarm Delta Stage At Top Perf = 3 3593.72 2332 2438 20.8 3704 81 12:28:43 Alarm Delta Stage At Top Perf = 4 3714.72 1869 1959 20.5 3288 82 12:36:03 Alarm Delta Stage At Top Perf = 5 3863.75 1538 1684 20.1 3162 83 12:38:58 Alarm Delta Stage At Top Perf = 6 3922.11 1404 1524 19.9 3134 84 12:43:28 Alarm Delta Stage At Top Perf = 7 4011.7 1275 1424 19.9 3133 85 12:48:08 Alarm Delta Stage At Top Perf = 8 4104.86 1217 1355 20 3133 86 12:55:46 Alarm Delta Stage At Top Perf = 9 4256.93 1175 1307 19.9 3131 87 13:02:59 Alarm Delta Stage At Top Perf = 10 4399.83 1154 1300 19.7 3143 88 13:08:00 Alarm Delta Stage At Top Perf = 11 4501.58 1551 1621 20.6 3165 17 13:08:22 (06/02/25) Next Treatment Treatment Interval 17 4508.78 1570 1676 20.6 3163 89 13:08:23 Drop Ball Drop Dart for Interval 17 4509.13 1575 1699 20.6 3176 90 13:11:55 Alarm Delta Stage At Top Perf = 12 4582.31 1420 1559 20.9 2972 91 13:12:23 Ball on Seat Dart on Seat 4592.07 1459 1578 20.9 2955 92 13:12:28 Break Formation Break Formation 4593.81 3825 4000 20.8 5318 93 13:13:15 Alarm Delta Stage At Top Perf = 1 4610.08 2061 2221 20.8 3475 94 13:15:36 Alarm Delta Stage At Top Perf = 2 4659.03 1920 2046 20.9 3219 95 13:16:13 Alarm Delta Stage At Top Perf = 3 4671.9 1920 2054 20.8 3225 96 13:22:01 Alarm Delta Stage At Top Perf = 4 4792.59 1607 1729 20.8 3029 97 13:29:06 Alarm Delta Stage At Top Perf = 5 4938.12 1316 1466 20.3 2976 98 0.563657407 Alarm Delta Stage At Top Perf = 6 4990.06 1263 1413 20.1 2966 99 13:36:11 Alarm Delta Stage At Top Perf = 7 5080.78 1124 1260 20 2948 100 13:40:54 Alarm Delta Stage At Top Perf = 8 5175.2 1036 1219 20 2949 101 13:48:34 Alarm Delta Stage At Top Perf = 9 5328.57 1042 1193 20 2951 102 13:54:58 Other 3rd Tracer Drop 5456.02 1027 1169 19.9 2966 103 13:55:39 Alarm Delta Stage At Top Perf = 10 5469.61 1031 1176 19.8 2968 104 14:00:38 Alarm Delta Stage At Top Perf = 11 5569.81 1200 1314 20.6 2981 18 14:01:56 (06/02/25) Next Treatment Treatment Interval 18 5596.56 1358 1472 20.6 2981 105 14:01:56 Drop Ball Drop Dart for Interval 18 5596.56 1359 1472 20.6 2981 106 14:05:05 Alarm Delta Stage At Top Perf = 12 5661.63 1248 1393 20.9 2860 107 14:05:43 Ball on Seat Dart on Seat 5674.9 1283 1389 21 2850 108 14:05:48 Break Formation Break Formation 5676.29 3104 3196 21 4651 109 14:06:27 Alarm Delta Stage At Top Perf = 1 5690.22 1826 1953 20.9 3342 110 14:08:42 Alarm Delta Stage At Top Perf = 2 5737.12 1653 1763 20.8 3047 111 14:09:20 Alarm Delta Stage At Top Perf = 3 5750.32 1659 1780 20.9 3026 112 14:15:04 Alarm Delta Stage At Top Perf = 4 5869.51 1529 1630 20.7 2931 113 14:22:11 Alarm Delta Stage At Top Perf = 5 6015.85 1328 1462 20.3 2919 114 14:24:44 Alarm Delta Stage At Top Perf = 6 6067.58 1241 1378 20.2 2912 115 14:29:07 Alarm Delta Stage At Top Perf = 7 6155.86 1094 1239 20.1 2906 116 14:30:29 Other 2nd Tracer Drop 6182.95 1058 1191 20.1 2907 117 14:33:45 Alarm Delta Stage At Top Perf = 8 6248.78 1027 1207 20 2907 118 14:41:18 Alarm Delta Stage At Top Perf = 9 6399.8 991 1150 20 2910 119 14:48:33 Alarm Delta Stage At Top Perf = 10 6543.92 835 1020 19.6 2981 120 14:48:46 Other Debris through Multiple Pumps 6547.85 990 1128 19.6 2927 121 14:53:24 Other More Debris in Pumps 6636.36 1114 1172 15.6 2931 122 14:53:34 Start Flush Start Flush 6638.75 860 1043 15.6 2884 123 14:54:01 Alarm Delta Stage At Top Perf = 11 6644.67 1196 1320 14.3 2932 124 14:59:04 ISIP ISIP 6731.16 774 795 0 2775 125 15:04:05 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 6731.16 6 145 0 2764 126 15:09:01 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 6731.16 51 72 0 2760 127 15:14:15 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 6731.16 38 56 0 2755 Event Log 6.2.25 Conoco Phillips - 3T-730 Event Log 6.2 132 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) -->3826 1975 1481 1852 2247 1605 1728 1753 1852 1605 1926 1753 1481 1234 1185 1136 987 741 494 420 173 74 0 0 0 0 0 0Dial Reading155 80 60 75 91 65 70 71 75 65 78 71 60 50 48 46 40 30 20 17 7 3Test #2 (cp) -->0000000000000000000000000000Dial ReadingTest #3 (cp) -->0000000000000000000000000000Dial ReadingTest #4 (cp) -->0000000000000000000000000000Dial Reading0.45 2.00 0.00105 8.70 1.00 27.00 2.00 0.50Temp 0F PH LOSURF-300D WG-36 CAT3 MO-67 CL-28M BC-140X2 OptiFlo-II OptiFlo-IIID. LundgrenHydration Visc: 24 93Temperature was held at 105 degres for the duration of the testAll chemical concentrations below are in gallons per thousand / pounds per thousandWater pH: 7.12Torok Hydration pH: 7.263T-730 Stage(s): Break Test105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/30/2025ConocoPhillips Project No:05001000150020002500300035004000450000:00 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 Tests30# Opti II @ 2.0 and CAT-3 @ 2.030# Opti II @ 2.0 and CAT-3 @ 2.030# Opti II @ 2.0 and CAT-3 @ 2.0Fluid is broken at 200cpConoco Phillips - 3T-730Prejob Break Test133 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 1105 Water Source: cpf3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/31/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH: 7.30Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-392 8.87 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350000:00 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 - 3T-730Zone 1134 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 2105 Water Source: cpf3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/31/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH: 7.30Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-3102 8.84 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300035004000450000:00 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 - 3T-730Zone 2135 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 3105 Water Source: CPF 3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/31/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-384 8.74 1.00 0.45 27 0.65 2.00 2.000500100015002000250030003500400000:00 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 - 3T-730Zone 3136 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad.50 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 4105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/31/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-391 8.80 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300035004000450000:00 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 - 3T-730Zone 4 137 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad.50 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 5105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/31/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-392 8.75 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350000:00 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 - 3T-730Zone 5138 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad.50 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 6105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 5/31/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-387 8.82 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350040004500500000:00 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 - 3T-730Zone 6139 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 7105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/1/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-397 8.74 1.00 0.45 27 0.65 2.00 2.000500100015002000250030003500400000:00 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 - 3T-730Zone 7 140 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 8Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/1/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-399 8.82 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300035004000450000:00 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 - 3T-730Zone 8141 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 9Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/1/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-396 8.65 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300000:00 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 - 3T-730Zone 9142 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 10Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/1/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-391 8.80 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300035004000450000:00 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 - 3T-730Zone 10143 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 11Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/1/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-395 8.75 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350000:00 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 - 3T-730Zone 11144 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 12Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/1/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-398 8.74 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300035004000450000:00 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 - 3T-730Zone 12145 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 13Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-399 8.73 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350000:00 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 - 3T-730Zone 13146 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 14Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-390 8.80 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300035004000450000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 14 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3T-730Zone 14147 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 15Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-3102 8.84 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350040004500500000:00 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 - 3T-730Zone 15148 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 16Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-395 8.74 1.00 0.45 27 0.65 2.00 2.000500100015002000250030003500400000:00 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 - 3T-730Zone 16149 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 17Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-396 8.80 1.00 0.45 27 0.65 2.00 2.00050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 17 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3T-730Zone 17150 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3T-730 Stage(s): 18Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 6/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 WG-36 MO-67 Optiflo-II CAT-396 8.70 1.00 0.45 27 0.65 2.00 2.0005001000150020002500300000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 18 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3T-730Zone 18151 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% 16 340.1 346 5.9 5.9% 18 303.3 390 86.7 86.7% 20 296.5 299 2.5 2.5% 25 419.4 420 0.6 0.6% 30 281.5 283 1.5 1.5% 40 407.6 410.4 2.8 2.8% Pan 306.6 306.6 0 0.0% 0.00% <1.0% Total: 100 100% Total Sample Size Seive Weight Seive Weight 100.0 g Sieve Size Before Sand With sand WT. rtn'd % rtn'd % API Spec 12 355 355 0 0.0% 0.00% <0.1% 16 340.1 346 5.9 5.9% 18 303.2 389.8 86.6 86.6% 20 296.5 299.1 2.6 2.6% 25 419.4 420 0.6 0.6% 30 281.5 282.9 1.4 1.4% 40 407.6 410.3 2.7 2.7% Pan 306.6 306.6 0 0.0% 0.00% <1.0% Total: 99.8 100% Total Sample Size Seive Weight Seive Weight 100.0 g Sieve Size Before Sand With sand WT. rtn'd % rtn'd % API Spec 12 355 355 0 0.0% 0.00% <0.1% 16 340.2 344 3.8 3.8% 18 303.3 391 87.7 87.7% 20 296.5 300 3.5 3.5% 25 419.2 419.7 0.5 0.5% 30 281.5 284 2.5 2.5% 40 407.6 409.7 2.1 2.1% Pan 306.6 306.6 0 0.0% 0.00% <1.0% Total: 100.1 100% Conoco Phillips 3T-730 16/20 Proppant 5/31/2025 Ceramic Proppant Sieves Sample: 16 / 20 - 5/31/2025 91.30% >/= 90% Sample: 16 / 20 - 06/01/2025 91.20% >/= 90% Sample: 16 / 20 - 06/02/2025 94.20% >/= 90% Conoco Phillips - 3T-730 Sand Sieve Analysis 152 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: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 14036 Casing Collapse Structural Conductor Surface 2474 Production 4789 Production 4789 Production 9210 Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng CO 819 4151 14036 4151 1448 5/28/2025 1402613159 4-1/2" 4151 HES TNT Production Packer 5074 Perforation Depth MD (ft): 4205 869 4-1/2" 41107-5/8" 20" 10-3/4" 119 7-5/8"4205 2636 5209 119 2472 3796 119 2636 L-80 TVD Burst 5,080 10860 MD 6885 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528/ADL025544 KRU 225-010 P.O. Box 100360 Anchorage, Alaska 99501-0360 50-103-20907-00-00 ConocoPhillips Alaska, Inc. AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): 4,937' MD / 4,084' 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 3T-730 Coyote Coyote Completions Engineer Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 Length Size Proposed Pools: 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 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: 2025.05.14 11:23:50-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard 325-304 By Grace Christianson at 7:44 am, May 15, 2025 CDW 05/21/2025 SFD 5/23/2025 DSR-6/3/25 X Fracture Stimulate Approve variance request to 20 AAC 25.283(a)(6)(A)(ii). Frac contained within target reservoir but Coyote not cemented to 20 AAC 25.030(d)(5). VTL 5/27/2025 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.05 08:02:52 -08'00'06/05/25 RBDMS JSB 060525 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). May 9, 2025 VIA E-MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3T-730 Well ADL 025528 & ADL 025544 Kuparuk River Unit, Alaska CPAI Contract No. 203828 Pursuant to 20 AAC 25.283, ConocoPhillips Alaska, Inc. (“CPAI”) as Operator of the Kuparuk River Unit, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing in accordance with 20 AAC 25.280 (“Application”) for the 3T- 730 Well (the “Well”). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about May 13, 2025. The Well is currently planned to be drilled as a directional horizontal well on lease ADL 025528 and ADL 025544 as depicted on Exhibit 1, and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 3,632’ 5,135’ T12N R7E 1 Umiat Top Open Interval 4,415’ 741’ T12N R7E 2 Umiat Bottomhole 2,918’ 4,757’ T12N R7E 13 Umiat Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well (“Notification Area”), which includes the reservoir section. Exhibit 2 is a list of the names and addresses of all owners, landowners, surface owners, and operators of record at the time of this Application for all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, Ryan C. King, CPL Staff Land Negotiator Attachments: Exhibits 1 & 2 Ryan C. King, CPL Staff Land Negotiator Land & Business Development P.O. Box 100630 Anchorage, AK 99510-0360 Office: 907-265-6106 Fax: 907-263-4966 ryan.c.king@cop.com BCC: Madeline Woodard Brian Buck 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 Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Section 2 – Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032069500 3S-620 ACTIVE Oil Yes Yes KUP KRU KUPARUK RIVER UNIT 501032069900 MORAINE 1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032046000 3S-19 SUSP Suspended Yes - Suspended Yes - Suspended KUP TOROK TOROK 501032073500 3S-613 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil No No KUP TOROK TOROK 501032087800 3S-626 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032088200 3T-621 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032088700 3T-603 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032089000 3T-608 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032089600 3T-612 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032089900 3T-616 ACTIVE Oil YEs Yes KUP TOROK TOROK 501032089970 3T-616PB1 PROP Proposed Yes Yes KUP TOROK TOROK 501032089971 3T-616PB2 PROP Proposed Yes Yes KUP COYOTE COYOTE 501032090500 3T-731 ACTIVE Oil yes Yes KUP COYOTE COYOTE 501032091100 3S-721 PROP Proposed Yes Yes NAK OU OOOGURUK UNIT 501032066070 NDST-02PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK NAK NORTH ALASKA EXPLORATION 501032064500 NUNA 1 SUSP Suspended Yes - Suspended Yes - Suspended NAK NAK NORTH ALASKA EXPLORATION 501032064570 NUNA 1PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK OU OOOGURUK UNIT 501032066000 NDST-02 SUSP Suspended Yes - Suspended Yes - Suspended 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. CBL (05/01/2025) SLB & CPAI interpretation has moderate cement coverage to 4265 ft MD/3829 ft TVD - CDW 05/15/2025 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 4/15/2025-4/16/2025 shows that the original job pumped as designed. The cement job was pumped with 430 barrels of 11.0 ppg lead cement and 57 barrels 15.8 ppg tail cement, displaced with 9.8 ppg mud. The plug bumped at 1055 psi and the floats held. 323 bbls of cement returned to surface. The 7-5/8” x 4-1/2” casing cement report on 4/30/2025 shows that the job was pumped with 60 barrels of 13.5ppg clean cement, 530 bbls of 13.5ppg cement with Bridge Maker II, and 60 bbls of 13.5ppg clean tail cement. The cement was displaced with 9.7ppg CI brine. The plug bumped and pressure was held at 1150 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. No losses were observed during the job. A cement bond log indicated the cement top at 4,520’ MD / 3,949’ TVD (507’ MD / 153’ TVD above the Coyote). Summary The 10-3/4” casing is cemented in accordance with 20 AAC 25.030. The 7-5/8” x 4-1/2” production casing cement does not meet 20 AAC 25.030, since the TOC is only 153’ TVD above the Coyote (shallowest hydrocarbon bearing zone). Based on engineering evaluation of the well referenced in this application and given the cement isolation is above the top of the Coyote, ConocoPhillips has determined that this well can be successfully fractured within its design limits. Request for Variance ConocoPhillips is requesting a variance to code 20 AAC 25.283 (a) (6) (A) (ii) given that the cement outside the production casing and above the top of reservoir does not meet 20 AAC 25.030 (d) (5) based on the following justification: 1. Given that the uppermost frac sleeve is located at 5,843ft MD/4142ft TVD, this results in 816ft MD/40ft TVD of cement placed from the sleeve to the top of the Coyote, and ConocoPhillips' estimated fracture half-length of approximately 250 ft, combined with the significant permeability difference between the Coyote reservoir and the overburden, ensures that the hydraulic fracture will remain confined within the reservoir. This containment minimizes the risk of unintended migration of fracturing fluids into adjacent formations or freshwater aquifers. 2. The proposed variance aligns with the intent of Code 20 AAC 25.283 (a) (6) (A) (ii), which aims to ensure safe and effective hydraulic fracturing operations. By establishing that the fracture will be contained within the reservoir. ggj the cement top at 4,520’ MD / 3,949’ TVD (507’ MD / 153’ TVD above the Coyote). Recommend approval of variance request CDW 05/15/2025. Frac contained within target reservoir.Request for Variance ppg 323 bbls of cement,p returned to surface SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 4/17/2025 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 5/1/2025 the 7-5/8” x 4-1/2” tapered casing was pressure tested to 3,850 psi for 30 minutes. On 5/2/2025 the 4-1/2” tubing was pressure tested to 4,550 psi for 30 minutes. On 5/2/2025 the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes. On 5/11/2025 the 4-1/2” tubing was 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. 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 4,075 SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2,474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 P-110S 11,590 9,210 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the gross Coyote interval, has an average thickness greater than 100 ft TVD over the course of the lateral section of well 3T-730, from where it intersects the top formation at 5,027’ MD to TD of the well. At the heel of the well it has a gross thickness of ~93’ thickening to ~191’ 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 ~270 ’ TVD in the vicinity of the 3T-730 wellbore. The top of the confining intervals starts at ~3,725’ TVDSS (4,173’ 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 2,641’ 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 ~350’ 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 ~900’ TVD in the vicinity of the 3T-730 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 ~4,138 ft TVDSS at the heel, and ~4,214’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1,674 – 1,795 psi at a depth of 4,051’ 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-612: The 7-5/8” intermediate casing was cemented with 303bbls of 15.8 ppg Class G cement. The plug bumped and floats held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,270’MD / 3,832’ TVD / 3,768’ TVDSS. 3S-615: The 7-5/8” intermediate casing was cemented with 200 barrels of 15.3 ppg lead cement with BMII and 33 barrels of 15.3 ppg tail cement. The plug bumped and floats held. No losses observed during the job. A cement bond log indicates competent cement with a cement top @ 5,620 MD / 3,340’ TVD / 3,279’ TVDSS. 3S-625: The 7-5/8” intermediate casing was cemented with 297 barrels of 15.3ppg cement with BMII. The plug did not bump and 50% of shoe track volume was pumped, floats did hold. Losses totaled 21 barrels during the job. A cement bond log indicates competent cement with a cement top @ 7,850’ MD (3,970’ TVD / 3,908’ TVDSS). 3S-721: The 7-5/8” intermediate casing was cemented with 72 barrels of 15.3ppg cement. The plug bumped and floats held. Full returns were observed during the job. A cement bond log indicates competent cement with a cement top @ 7,850’ MD / 3,970’ TVD / 3,908’ TVDSS. 3T-731: The 7-5/8” x 4-1/2” production casing was cemented with 50 barrels of 14.8ppg clean cement, 540 bbls of 14.8ppg cement with Bridge Maker II, and 50 bbls of 14.8ppg clean cement. The plug bumped and floats held. Losses were observed during the job. A cement bond log indicated the cement top at 12,750’ MD. A remedial cement job was pumped with 50 bbls of 14.8ppg clean cement, 217 bbls of 14.8ppg cement w/ Bridge Maker II, and 253 bbls of 14.8ppg clean cement through the perforation at 12,725’ MD. The cement was over displaced and 520bbls of fluid was lost during the job. After cement reached 500 psi compressive strength, the cement top was logged at 4,010’ MD / 3,717’ TVD (834’ MD / 389’ TVD above the Coyote). Moraine 1: The well was abandoned with 849 sx of 15.8ppg Class G cement in three separate plugs. The top cement plug was then tagged at 3,687’ MD/3,643’ TVD/3,600’ TVDSS with 15klbs. This tag is above the Coyote top at 4,127’ MD. A cement retainer was then set at 2,362’ MD and 21bbls of 15.8ppg Class G slurry was pumped below and 3 bbls above the retainer. A final plug was laid above a CIBP set at 508’ MD to surface using 11ppg AS1 cement. 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 three faults transect the Coyote reservoir within one half mile radius of the 3T-730 wellbore trajectory. The trace of one of these faults was projected to intersect the 3T-730 wellbore at an approximate depth of 11,250’ MD, however it was not readily apparent on LWD logs. This fault is the same fault that was interpreted to be encountered at 11,700’ MD in the 3T-731 wellbore. It has an interpreted ~W – E strike and is downthrown to the south. In the 3T-731 well it has an interpreted throw of 10-20’. The other two faults interpreted within ½ mile of the 3T-730 do not have traces that were expected to intersect the 3T-730 wellbore. These include a fault that intersected the 3T-731 wellbore at ~5,500’ MD. This fault is interpreted to have minimal throw at that location (< 5 feet). The fault has an interpreted W – E strike and is downthrown to the South. That fault has no mapped offset at the Top Coyote based on seismic in the area where it is picked in the 3T-731 wellbore. The remaining fault is east of the 3T-731 wellbore. This fault is a west to 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 these faults are interpreted to lose throw into the confining intervals above and below the Coyote reservoir. They should not affect overburden integrity and therefore their presence should not interfere with containment. If there is any indication that a propagated fracture has intersected the mapped fault (or any other faults unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3T-730 was completed in 2025 as a horizontal injector 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). CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In1:53:12 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:53:12 1-3 Shut-In Shut-In1:48:26 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 1:48:26 1.00 2.00 27.00 2.000.151-5 27# Linear Alpha Sleeve Shift 5 1,260 30 30 0:06:00 1:42:26 1.00 2.00 27.00 2.000.151-6 27# Linear DFIT 10 1,680 40 40 0:04:00 1:36:26 1.00 2.00 27.00 2.000.151-7 Shut-In Shut-In1:32:26 1-8 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 1:32:26 1.00 2.00 27.00 2.000.151-9 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:06 0.45 1.00 0.80 2.00 27.00 2.000.151-10 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:05:46 0.45 1.00 0.80 2.00 27.00 2.000.151-11 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:08 0.45 1.00 0.80 2.00 27.00 2.000.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:47:50 0.45 1.00 0.80 2.00 27.00 2.000.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:27 0.45 1.00 0.80 2.00 27.00 2.000.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:28 0.45 1.00 0.80 2.00 27.00 2.000.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:11 0.45 1.00 0.80 2.00 27.00 2.000.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:21:58 0.45 1.00 0.80 2.00 27.00 2.000.151-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:33 0.45 1.00 0.80 2.00 27.00 2.000.151-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:05:50 0.45 1.00 0.80 2.00 27.00 2.000.151-19 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.000.152-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.152-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.152-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.152-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.152-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.152-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.152-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.000.152-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.153-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.000.153-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.153-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.000.153-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.154-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.000.154-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.154-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.154-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.154-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.154-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.154-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.154-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.000.154-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.155-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:31:49 1.00 2.00 27.00 2.000.155-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:29:19 0.45 1.00 0.80 2.00 27.00 2.000.155-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:19:19 0.45 1.00 0.80 2.00 27.00 2.000.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:08:41 0.45 1.00 0.80 2.00 27.00 2.000.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 1:01:23 0.45 1.00 0.80 2.00 27.00 2.000.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:58:00 0.45 1.00 0.80 2.00 27.00 2.000.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:52:01 0.45 1.00 0.80 2.00 27.00 2.000.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:45:44 0.45 1.00 0.80 2.00 27.00 2.000.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:35:31 0.45 1.00 0.80 2.00 27.00 2.000.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:26:06 0.45 1.00 0.80 2.00 27.00 2.000.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:19:23 0.45 1.00 0.80 2.00 27.00 2.000.155-12 27# Linear Flush 20 7,602 181 181 0:09:03 0:15:03 1.00 2.00 27.00 2.000.155-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 5-14 Shut-In Shut-InLiquid AdditivesDry AdditivesInterval 1Coyote@ 13891.01 - 13895.01 ft - °FInterval 2Coyote@ 13348 - 13352 ft - °FInterval 3Coyote@ 12850.49 - 12854.49 ft - °FInterval 4Coyote@ 12433.91 - 12437.91 ft - °FInterval 5Coyote@ 11892.86 - 11896.86 ft - °FConoco Phillips - 3S-723Planned Design1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives6-1 Shut-In Shut-In1:37:38 6-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:37:38 6-3 Shut-In Shut-In1:32:53 6-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:32:53 1.00 2.00 27.00 2.00 0.156-5 27# Linear Displace Dart to Seat 15 7,260 173 173 0:11:31 1:30:53 1.00 2.00 27.00 2.00 0.156-6 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:21 0.45 1.00 0.80 2.00 27.00 2.00 0.156-7 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.00 0.156-8 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.156-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.156-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.156-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.156-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.156-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.156-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.156-16 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.157-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.00 0.157-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 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 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.157-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.0000 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.157-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.157-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.157-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.00 0.158-4 27# Delta Frac Conditioning Pad 100M 0.5000 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.158-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.158-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.158-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.158-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.158-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.158-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.158-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 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 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.15Interval 9Coyote@ 9866.92 - 9870.92 ft - °FInterval 6Coyote@ 11357.75 - 11361.75 ft - °FInterval 7Coyote@ 10862.44 - 10866.44 ft - °FInterval 8Coyote@ 10365.57 - 10369.57 ft - °FConoco Phillips - 3S-723Planned Design2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives10-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.1510-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 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 27.00 2.000.1511-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:29:31 1.00 2.00 27.00 2.000.1511-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:27:01 0.45 1.00 0.80 2.00 27.00 2.000.1511-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:17:01 0.45 1.00 0.80 2.00 27.00 2.000.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:06:23 0.45 1.00 0.80 2.00 27.00 2.000.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:59:05 0.45 1.00 0.80 2.00 27.00 2.000.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:55:42 0.45 1.00 0.80 2.00 27.00 2.000.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:49:44 0.45 1.00 0.80 2.00 27.00 2.000.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:43:26 0.45 1.00 0.80 2.00 27.00 2.000.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:33:14 0.45 1.00 0.80 2.00 27.00 2.000.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:23:48 0.45 1.00 0.80 2.00 27.00 2.000.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:17:05 0.45 1.00 0.80 2.00 27.00 2.000.1511-12 27# Linear Flush 20 5,672 135 135 0:06:45 0:12:45 1.00 2.00 27.00 2.000.1511-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 11-14 Shut-In Shut-InInterval 10Coyote@ 9368.4 - 9372.4 ft - °FInterval 11Coyote@ 8872.95 - 8876.95 ft - °FConoco Phillips - 3S-723Planned Design3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives12-1 Shut-In Shut-In1:26:34 12-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:26:34 12-3 Shut-In Shut-In1:21:49 12-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:21:49 1.00 2.00 27.00 2.00 0.1512-5 27# Linear Displace Dart to Seat 15 5,353 127 127 0:08:30 1:19:49 1.00 2.00 27.00 2.00 0.1512-6 27# Linear DFIT 5 1,680 40 40 0:08:00 1:11:19 1.00 2.00 27.00 2.00 0.1512-7 Shut-In Shut-In1:03:19 12-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:03:19 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-9 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1513-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1515-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1516-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1516-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.15Interval 12Coyote@ 8374.76 - 8378.76 ft - °FInterval 13Coyote@ 7958.84 - 7962.84 ft - °FInterval 14Coyote@ 7460.08 - 7464.08 ft - °FInterval 15Coyote@ 6921.94 - 6925.94 ft - °FInterval 16Coyote@ 6424.06 - 6428.06 ft - °FConoco Phillips - 3S-723Planned Design4 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives17-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1517-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.000.1517-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 27.00 2.000.1517-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:50 0.45 1.00 0.80 2.00 27.00 2.000.1517-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.000.1517-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.000.1517-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.000.1517-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.000.1517-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.000.1517-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.000.1517-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.000.1517-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1518-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:48 1.00 2.00 27.00 2.000.1518-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:08:18 0.45 1.00 0.80 2.00 27.00 2.000.1518-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:52:09 0.45 1.00 0.80 2.00 27.00 2.000.1518-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:44:50 0.45 1.00 0.80 2.00 27.00 2.000.1518-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:42:14 0.45 1.00 0.80 2.00 27.00 2.000.1518-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:37:44 0.45 1.00 0.80 2.00 27.00 2.000.1518-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:33:02 0.45 1.00 0.80 2.00 27.00 2.000.1518-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:25:30 0.45 1.00 0.80 2.00 27.00 2.000.1518-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:18:26 0.45 1.00 0.80 2.00 27.00 2.000.1518-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:13:24 0.45 1.00 0.80 2.00 27.00 2.000.1518-12 27# Linear Flush 20 3,415 81 81 0:04:04 0:10:04 1.00 2.00 27.00 2.000.1518-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 18-14 Shut-In Shut-In984,196 23,433 26,943 3,304,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6877,9753,250,000(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)99,44154,000Initial Design Material Volume 395.1 977.4 702.4 1,954.8 26,390.2 1,954.8 146.6-6,780- 0.3028 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) ppm ppm ppm-Max Additive Rate 0.4 0.8 0.7 1.7 22.7 1.7 0.1-Min Additive RateFluid Type27# Delta Frac27# LinearSeawaterFreeze Protect----Proppant TypeWanli 16/20 Ceramic100M---Interval 17Coyote@ 5841.59 - 5845.59 ft - °FInterval 18Coyote@ 5342.06 - 5346.06 ft - °F23:31:34 Conoco Phillips - 3S-723Planned Design5 Stage Job Size (lb) Top MD (ft) Top TVD (ft) Propped Half- Length (ft) Fracture Height (ft) Avg Fracture Width (in) 1 203,000 13,891 4,001 580 150 0.364 2 203,000 13,348 3,996 600 155 0.370 3 203,000 12,850 3,998 610 155 0.368 4 203,000 12,434 3,999 600 155 0.369 5 203,000 11,893 4,000 580 155 0.372 6 203,000 11,358 4,001 590 155 0.369 7 203,000 10,862 4,001 580 155 0.369 8 203,000 10,366 4,001 570 155 0.373 9 203,000 9,867 4,001 550 155 0.370 10 203,000 9,368 4,000 570 155 0.371 11 203,000 8,873 4,000 570 155 0.371 12 153,000 8,375 4,069 480 85 0.331 13 153,000 7,959 4,066 470 85 0.323 14 153,000 7,460 4,044 530 105 0.329 15 153,000 6,922 4,041 540 105 0.329 16 153,000 6,424 4,038 530 105 0.331 17 153,000 5,842 4,043 540 100 0.328 18 153,000 5,342 4,136 530 100 0.316 Disclaimer Notice: KRU 3T-730 This model was generated using commercially available modeling software and is based on engineering estimates of reservoir properties. Conoco Phillips is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-05-13 Alaska HARRISON BAY 50-103-20907-00-00 CONOCOPHILLIPS 3T 730 -150.26909532 70.41994878 NAD83 none Oil 4200 929045.2 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone Produced Water (Density 8.5)Operator Base Fluid Density = 8.50 SEAWATER (SG 8.52)Operator Base Fluid Density = 8.52 BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Calcium Chloride Customer Salt Solution Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%67.22257%7911206 Corundum 1302-74-5 60.00%16.56941%1950000 Mullite 1302-93-8 40.00%11.04627%1300000 Sodium chloride 7647-14-5 5.00%3.53803%416380 Calcium Chloride 10043-52-4 100.00%0.57611%67800 Crystalline silica, quartz 14808-60-7 100.00%0.46178%54346 Guar gum 9000-30-0 100.00%0.22424%26390 Water 7732-18-5 100.00%0.21320%25091 EDTA/Copper chelate Proprietary 30.00%0.04156%4892 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%0.03786%4456 Water 7732-18-5 100.00%0.03611%4250 Monoethanolamine borate 26038-87-9 100.00%0.03410%4014 Sodium hydroxide 1310-73-2 30.00%0.01895%2231 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01893%2228 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01893%2228 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ammonium persulfate 7727-54-0 100.00%0.01661%1955 Ethylene glycol 107-21-1 30.00%0.01023%1204 Ammonium chloride 12125-02-9 5.00%0.00693%816 Oxyalkylated phenolic resin Proprietary 10.00%0.00631%743 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxylated phenolic resin Proprietary 30.00%0.00498%587 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Walnut hulls NA 100.00%0.00425%500 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Flow Insurance Copper Proprietary 100.00%0.00413%486 Patina Energy Product Stewardship test@patinae nergy.com 6692416025 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00315%372 Naphthalene 91-20-3 5.00%0.00315%372 Ammonia 7664-41-7 1.00%0.00139%164 Polyamine Proprietary 30.00%0.00127%150 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00124%146 Glycol Ether Proprietary 85.00%0.00104%123 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ammonium acetate 631-61-8 100.00%0.00078%92 Sodium chloride 7647-14-5 1.00%0.00063%75 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00063%75 Confidential Proprietary 20.00%0.00037%44 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ethylene Glycol 107-21-1 20.00%0.00025%30 Acetic acid 64-19-7 30.00%0.00023%28 Hemicellulase 9025-56-3 5.00%0.00021%25 C.I. pigment Orange 5 3468-63-1 1.00%0.00017%20 Cured acrylic resin Proprietary 1.00%0.00004%5 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00004%5 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%5 * 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 direct ed 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: SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) After the fracture stimulation, ConocoPhillips (“CPAI”) plans to flowback the well for cleanup purposes for an estimated 7 to 14 days. The flowback liquids will be routed through a portable test separator then onto either CPF3 or Drill Site 3T’s facilities. Once the well’s flowback liquids meet CPF3 criteria all liquids will be routed to CPF3. CPAI plans to limit the flowback time to what is necessary to achieve conforming production liquids. 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: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 14036 Casing Collapse Structural Conductor Surface 2474 Production 4789 Production 4789 Production 9210 Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng CO 819 4151 14036 4151 1448 5/28/2025 1402613159 4-1/2" 4151 HES TNT Production Packer 5074 Perforation Depth MD (ft): 4205 869 4-1/2" 41107-5/8" 20" 10-3/4" 119 7-5/8"4205 2636 5209 119 2472 3796 119 2636 L-80 TVD Burst 5,080 10860 MD 6885 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528/ADL025544 KRU 225-010 P.O. Box 100360 Anchorage, Alaska 99501-0360 50-103-20907-00-00 ConocoPhillips Alaska, Inc. AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): 4,937' MD / 4,084' 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 3T-730 Coyote Coyote Completions Engineer Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 Length Size Proposed Pools: 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 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: 2025.05.14 11:23:50-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard 325-304 By Grace Christianson at 7:44 am, May 15, 2025 CDW 05/21/2025 SFD 5/23/2025 X Fracture Stimulate Approve variance request to 20 AAC 25.283(a)(6)(A)(ii). Frac contained within target reservoir but Coyote not cemented to 20 AAC 25.030(d)(5). VTL 5/27/2025 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.30 14:27:12 -08'00'05/30/25 RBDMS JSB 060225 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). May 9, 2025 VIA E-MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3T-730 Well ADL 025528 & ADL 025544 Kuparuk River Unit, Alaska CPAI Contract No. 203828 Pursuant to 20 AAC 25.283, ConocoPhillips Alaska, Inc. (“CPAI”) as Operator of the Kuparuk River Unit, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing in accordance with 20 AAC 25.280 (“Application”) for the 3T- 730 Well (the “Well”). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about May 13, 2025. The Well is currently planned to be drilled as a directional horizontal well on lease ADL 025528 and ADL 025544 as depicted on Exhibit 1, and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 3,632’ 5,135’ T12N R7E 1 Umiat Top Open Interval 4,415’ 741’ T12N R7E 2 Umiat Bottomhole 2,918’ 4,757’ T12N R7E 13 Umiat Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well (“Notification Area”), which includes the reservoir section. Exhibit 2 is a list of the names and addresses of all owners, landowners, surface owners, and operators of record at the time of this Application for all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, Ryan C. King, CPL Staff Land Negotiator Attachments: Exhibits 1 & 2 Ryan C. King, CPL Staff Land Negotiator Land & Business Development P.O. Box 100630 Anchorage, AK 99510-0360 Office: 907-265-6106 Fax: 907-263-4966 ryan.c.king@cop.com BCC: Madeline Woodard Brian Buck 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 Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Section 2 – Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032069500 3S-620 ACTIVE Oil Yes Yes KUP KRU KUPARUK RIVER UNIT 501032069900 MORAINE 1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032046000 3S-19 SUSP Suspended Yes - Suspended Yes - Suspended KUP TOROK TOROK 501032073500 3S-613 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil No No KUP TOROK TOROK 501032087800 3S-626 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032088200 3T-621 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032088700 3T-603 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032089000 3T-608 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032089600 3T-612 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032089900 3T-616 ACTIVE Oil YEs Yes KUP TOROK TOROK 501032089970 3T-616PB1 PROP Proposed Yes Yes KUP TOROK TOROK 501032089971 3T-616PB2 PROP Proposed Yes Yes KUP COYOTE COYOTE 501032090500 3T-731 ACTIVE Oil yes Yes KUP COYOTE COYOTE 501032091100 3S-721 PROP Proposed Yes Yes NAK OU OOOGURUK UNIT 501032066070 NDST-02PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK NAK NORTH ALASKA EXPLORATION 501032064500 NUNA 1 SUSP Suspended Yes - Suspended Yes - Suspended NAK NAK NORTH ALASKA EXPLORATION 501032064570 NUNA 1PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK OU OOOGURUK UNIT 501032066000 NDST-02 SUSP Suspended Yes - Suspended Yes - Suspended 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. CBL (05/01/2025) SLB & CPAI interpretation has moderate cement coverage to 4265 ft MD/3829 ft TVD - CDW 05/15/2025 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 4/15/2025-4/16/2025 shows that the original job pumped as designed. The cement job was pumped with 430 barrels of 11.0 ppg lead cement and 57 barrels 15.8 ppg tail cement, displaced with 9.8 ppg mud. The plug bumped at 1055 psi and the floats held. 323 bbls of cement returned to surface. The 7-5/8” x 4-1/2” casing cement report on 4/30/2025 shows that the job was pumped with 60 barrels of 13.5ppg clean cement, 530 bbls of 13.5ppg cement with Bridge Maker II, and 60 bbls of 13.5ppg clean tail cement. The cement was displaced with 9.7ppg CI brine. The plug bumped and pressure was held at 1150 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. No losses were observed during the job. A cement bond log indicated the cement top at 4,520’ MD / 3,949’ TVD (507’ MD / 153’ TVD above the Coyote). Summary The 10-3/4” casing is cemented in accordance with 20 AAC 25.030. The 7-5/8” x 4-1/2” production casing cement does not meet 20 AAC 25.030, since the TOC is only 153’ TVD above the Coyote (shallowest hydrocarbon bearing zone). Based on engineering evaluation of the well referenced in this application and given the cement isolation is above the top of the Coyote, ConocoPhillips has determined that this well can be successfully fractured within its design limits. Request for Variance ConocoPhillips is requesting a variance to code 20 AAC 25.283 (a) (6) (A) (ii) given that the cement outside the production casing and above the top of reservoir does not meet 20 AAC 25.030 (d) (5) based on the following justification: 1. Given that the uppermost frac sleeve is located at 5,843ft MD/4142ft TVD, this results in 816ft MD/40ft TVD of cement placed from the sleeve to the top of the Coyote, and ConocoPhillips' estimated fracture half-length of approximately 250 ft, combined with the significant permeability difference between the Coyote reservoir and the overburden, ensures that the hydraulic fracture will remain confined within the reservoir. This containment minimizes the risk of unintended migration of fracturing fluids into adjacent formations or freshwater aquifers. 2. The proposed variance aligns with the intent of Code 20 AAC 25.283 (a) (6) (A) (ii), which aims to ensure safe and effective hydraulic fracturing operations. By establishing that the fracture will be contained within the reservoir. ggj the cement top at 4,520’ MD / 3,949’ TVD (507’ MD / 153’ TVD above the Coyote). Recommend approval of variance request CDW 05/15/2025. Frac contained within target reservoir.Request for Variance ppg 323 bbls of cement,p returned to surface SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 4/17/2025 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 5/1/2025 the 7-5/8” x 4-1/2” tapered casing was pressure tested to 3,850 psi for 30 minutes. On 5/2/2025 the 4-1/2” tubing was pressure tested to 4,550 psi for 30 minutes. On 5/2/2025 the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes. On 5/11/2025 the 4-1/2” tubing was 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. 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 4,075 SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2,474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 P-110S 11,590 9,210 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the gross Coyote interval, has an average thickness greater than 100 ft TVD over the course of the lateral section of well 3T-730, from where it intersects the top formation at 5,027’ MD to TD of the well. At the heel of the well it has a gross thickness of ~93’ thickening to ~191’ 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 ~270 ’ TVD in the vicinity of the 3T-730 wellbore. The top of the confining intervals starts at ~3,725’ TVDSS (4,173’ 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 2,641’ 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 ~350’ 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 ~900’ TVD in the vicinity of the 3T-730 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 ~4,138 ft TVDSS at the heel, and ~4,214’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1,674 – 1,795 psi at a depth of 4,051’ 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-612: The 7-5/8” intermediate casing was cemented with 303bbls of 15.8 ppg Class G cement. The plug bumped and floats held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,270’MD / 3,832’ TVD / 3,768’ TVDSS. 3S-615: The 7-5/8” intermediate casing was cemented with 200 barrels of 15.3 ppg lead cement with BMII and 33 barrels of 15.3 ppg tail cement. The plug bumped and floats held. No losses observed during the job. A cement bond log indicates competent cement with a cement top @ 5,620 MD / 3,340’ TVD / 3,279’ TVDSS. 3S-625: The 7-5/8” intermediate casing was cemented with 297 barrels of 15.3ppg cement with BMII. The plug did not bump and 50% of shoe track volume was pumped, floats did hold. Losses totaled 21 barrels during the job. A cement bond log indicates competent cement with a cement top @ 7,850’ MD (3,970’ TVD / 3,908’ TVDSS). 3S-721: The 7-5/8” intermediate casing was cemented with 72 barrels of 15.3ppg cement. The plug bumped and floats held. Full returns were observed during the job. A cement bond log indicates competent cement with a cement top @ 7,850’ MD / 3,970’ TVD / 3,908’ TVDSS. 3T-731: The 7-5/8” x 4-1/2” production casing was cemented with 50 barrels of 14.8ppg clean cement, 540 bbls of 14.8ppg cement with Bridge Maker II, and 50 bbls of 14.8ppg clean cement. The plug bumped and floats held. Losses were observed during the job. A cement bond log indicated the cement top at 12,750’ MD. A remedial cement job was pumped with 50 bbls of 14.8ppg clean cement, 217 bbls of 14.8ppg cement w/ Bridge Maker II, and 253 bbls of 14.8ppg clean cement through the perforation at 12,725’ MD. The cement was over displaced and 520bbls of fluid was lost during the job. After cement reached 500 psi compressive strength, the cement top was logged at 4,010’ MD / 3,717’ TVD (834’ MD / 389’ TVD above the Coyote). Moraine 1: The well was abandoned with 849 sx of 15.8ppg Class G cement in three separate plugs. The top cement plug was then tagged at 3,687’ MD/3,643’ TVD/3,600’ TVDSS with 15klbs. This tag is above the Coyote top at 4,127’ MD. A cement retainer was then set at 2,362’ MD and 21bbls of 15.8ppg Class G slurry was pumped below and 3 bbls above the retainer. A final plug was laid above a CIBP set at 508’ MD to surface using 11ppg AS1 cement. 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 three faults transect the Coyote reservoir within one half mile radius of the 3T-730 wellbore trajectory. The trace of one of these faults was projected to intersect the 3T-730 wellbore at an approximate depth of 11,250’ MD, however it was not readily apparent on LWD logs. This fault is the same fault that was interpreted to be encountered at 11,700’ MD in the 3T-731 wellbore. It has an interpreted ~W – E strike and is downthrown to the south. In the 3T-731 well it has an interpreted throw of 10-20’. The other two faults interpreted within ½ mile of the 3T-730 do not have traces that were expected to intersect the 3T-730 wellbore. These include a fault that intersected the 3T-731 wellbore at ~5,500’ MD. This fault is interpreted to have minimal throw at that location (< 5 feet). The fault has an interpreted W – E strike and is downthrown to the South. That fault has no mapped offset at the Top Coyote based on seismic in the area where it is picked in the 3T-731 wellbore. The remaining fault is east of the 3T-731 wellbore. This fault is a west to 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 these faults are interpreted to lose throw into the confining intervals above and below the Coyote reservoir. They should not affect overburden integrity and therefore their presence should not interfere with containment. If there is any indication that a propagated fracture has intersected the mapped fault (or any other faults unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3T-730 was completed in 2025 as a horizontal injector 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). CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In1:53:12 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:53:12 1-3 Shut-In Shut-In1:48:26 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 1:48:26 1.00 2.00 27.00 2.000.151-5 27# Linear Alpha Sleeve Shift 5 1,260 30 30 0:06:00 1:42:26 1.00 2.00 27.00 2.000.151-6 27# Linear DFIT 10 1,680 40 40 0:04:00 1:36:26 1.00 2.00 27.00 2.000.151-7 Shut-In Shut-In1:32:26 1-8 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 1:32:26 1.00 2.00 27.00 2.000.151-9 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:06 0.45 1.00 0.80 2.00 27.00 2.000.151-10 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:05:46 0.45 1.00 0.80 2.00 27.00 2.000.151-11 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:08 0.45 1.00 0.80 2.00 27.00 2.000.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:47:50 0.45 1.00 0.80 2.00 27.00 2.000.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:27 0.45 1.00 0.80 2.00 27.00 2.000.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:28 0.45 1.00 0.80 2.00 27.00 2.000.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:11 0.45 1.00 0.80 2.00 27.00 2.000.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:21:58 0.45 1.00 0.80 2.00 27.00 2.000.151-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:33 0.45 1.00 0.80 2.00 27.00 2.000.151-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:05:50 0.45 1.00 0.80 2.00 27.00 2.000.151-19 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.000.152-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.152-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.152-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.152-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.152-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.152-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.152-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.000.152-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.153-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.000.153-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.153-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.000.153-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.154-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.000.154-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.154-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.154-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.154-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.154-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.154-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.154-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.000.154-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.155-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:31:49 1.00 2.00 27.00 2.000.155-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:29:19 0.45 1.00 0.80 2.00 27.00 2.000.155-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:19:19 0.45 1.00 0.80 2.00 27.00 2.000.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:08:41 0.45 1.00 0.80 2.00 27.00 2.000.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 1:01:23 0.45 1.00 0.80 2.00 27.00 2.000.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:58:00 0.45 1.00 0.80 2.00 27.00 2.000.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:52:01 0.45 1.00 0.80 2.00 27.00 2.000.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:45:44 0.45 1.00 0.80 2.00 27.00 2.000.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:35:31 0.45 1.00 0.80 2.00 27.00 2.000.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:26:06 0.45 1.00 0.80 2.00 27.00 2.000.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:19:23 0.45 1.00 0.80 2.00 27.00 2.000.155-12 27# Linear Flush 20 7,602 181 181 0:09:03 0:15:03 1.00 2.00 27.00 2.000.155-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 5-14 Shut-In Shut-InLiquid AdditivesDry AdditivesInterval 1Coyote@ 13891.01 - 13895.01 ft - °FInterval 2Coyote@ 13348 - 13352 ft - °FInterval 3Coyote@ 12850.49 - 12854.49 ft - °FInterval 4Coyote@ 12433.91 - 12437.91 ft - °FInterval 5Coyote@ 11892.86 - 11896.86 ft - °FConoco Phillips - 3S-723Planned Design1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives6-1 Shut-In Shut-In1:37:38 6-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:37:38 6-3 Shut-In Shut-In1:32:53 6-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:32:53 1.00 2.00 27.00 2.00 0.156-5 27# Linear Displace Dart to Seat 15 7,260 173 173 0:11:31 1:30:53 1.00 2.00 27.00 2.00 0.156-6 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:21 0.45 1.00 0.80 2.00 27.00 2.00 0.156-7 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.00 0.156-8 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.156-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.156-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.156-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.156-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.156-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.156-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.156-16 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.157-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.00 0.157-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 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 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.157-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.0000 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.157-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.157-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.157-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.00 0.158-4 27# Delta Frac Conditioning Pad 100M 0.5000 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.158-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.158-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.158-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.158-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.158-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.158-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.158-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 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 0:55:23 0.45 1.00 0.80 2.00 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.15Interval 9Coyote@ 9866.92 - 9870.92 ft - °FInterval 6Coyote@ 11357.75 - 11361.75 ft - °FInterval 7Coyote@ 10862.44 - 10866.44 ft - °FInterval 8Coyote@ 10365.57 - 10369.57 ft - °FConoco Phillips - 3S-723Planned Design2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives10-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:31 1.00 2.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:16:01 0.45 1.00 0.80 2.00 27.00 2.000.1510-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:06:01 0.45 1.00 0.80 2.00 27.00 2.000.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:23 0.45 1.00 0.80 2.00 27.00 2.000.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:48:05 0.45 1.00 0.80 2.00 27.00 2.000.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:44:42 0.45 1.00 0.80 2.00 27.00 2.000.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:38:43 0.45 1.00 0.80 2.00 27.00 2.000.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:32:26 0.45 1.00 0.80 2.00 27.00 2.000.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:13 0.45 1.00 0.80 2.00 27.00 2.000.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:48 0.45 1.00 0.80 2.00 27.00 2.000.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:06:05 0.45 1.00 0.80 2.00 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 27.00 2.000.1511-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:29:31 1.00 2.00 27.00 2.000.1511-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:27:01 0.45 1.00 0.80 2.00 27.00 2.000.1511-3 27# Delta Frac Pad 20 8,930 213 213 0:10:38 1:17:01 0.45 1.00 0.80 2.00 27.00 2.000.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:06:23 0.45 1.00 0.80 2.00 27.00 2.000.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,600 62 67 5,200 0:03:23 0:59:05 0.45 1.00 0.80 2.00 27.00 2.000.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,250 101 119 17,000 0:05:59 0:55:42 0.45 1.00 0.80 2.00 27.00 2.000.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,150 99 125 24,900 0:06:18 0:49:44 0.45 1.00 0.80 2.00 27.00 2.000.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,500 155 203 45,500 0:10:12 0:43:26 0.45 1.00 0.80 2.00 27.00 2.000.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:33:14 0.45 1.00 0.80 2.00 27.00 2.000.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:23:48 0.45 1.00 0.80 2.00 27.00 2.000.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,500 60 86 25,000 0:04:20 0:17:05 0.45 1.00 0.80 2.00 27.00 2.000.1511-12 27# Linear Flush 20 5,672 135 135 0:06:45 0:12:45 1.00 2.00 27.00 2.000.1511-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 11-14 Shut-In Shut-InInterval 10Coyote@ 9368.4 - 9372.4 ft - °FInterval 11Coyote@ 8872.95 - 8876.95 ft - °FConoco Phillips - 3S-723Planned Design3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives12-1 Shut-In Shut-In1:26:34 12-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:26:34 12-3 Shut-In Shut-In1:21:49 12-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:21:49 1.00 2.00 27.00 2.00 0.1512-5 27# Linear Displace Dart to Seat 15 5,353 127 127 0:08:30 1:19:49 1.00 2.00 27.00 2.00 0.1512-6 27# Linear DFIT 5 1,680 40 40 0:08:00 1:11:19 1.00 2.00 27.00 2.00 0.1512-7 Shut-In Shut-In1:03:19 12-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:03:19 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-9 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1512-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1513-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1513-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1514-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1515-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1515-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1515-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1516-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1516-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 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 0:43:50 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.00 0.1516-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.15Interval 12Coyote@ 8374.76 - 8378.76 ft - °FInterval 13Coyote@ 7958.84 - 7962.84 ft - °FInterval 14Coyote@ 7460.08 - 7464.08 ft - °FInterval 15Coyote@ 6921.94 - 6925.94 ft - °FInterval 16Coyote@ 6424.06 - 6428.06 ft - °FConoco Phillips - 3S-723Planned Design4 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT LEASE3T-730SALES ORDERBHST (°F)LONGFORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives17-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:29 1.00 2.00 27.00 2.00 0.1517-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:59 0.45 1.00 0.80 2.00 27.00 2.000.1517-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:59 0.45 1.00 0.80 2.00 27.00 2.000.1517-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:43:50 0.45 1.00 0.80 2.00 27.00 2.000.1517-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:31 0.45 1.00 0.80 2.00 27.00 2.000.1517-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:56 0.45 1.00 0.80 2.00 27.00 2.000.1517-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:25 0.45 1.00 0.80 2.00 27.00 2.000.1517-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:43 0.45 1.00 0.80 2.00 27.00 2.000.1517-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:11 0.45 1.00 0.80 2.00 27.00 2.000.1517-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:07 0.45 1.00 0.80 2.00 27.00 2.000.1517-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:05 0.45 1.00 0.80 2.00 27.00 2.000.1517-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.1518-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:48 1.00 2.00 27.00 2.000.1518-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:08:18 0.45 1.00 0.80 2.00 27.00 2.000.1518-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:52:09 0.45 1.00 0.80 2.00 27.00 2.000.1518-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:44:50 0.45 1.00 0.80 2.00 27.00 2.000.1518-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:42:14 0.45 1.00 0.80 2.00 27.00 2.000.1518-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:37:44 0.45 1.00 0.80 2.00 27.00 2.000.1518-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:33:02 0.45 1.00 0.80 2.00 27.00 2.000.1518-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:25:30 0.45 1.00 0.80 2.00 27.00 2.000.1518-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:18:26 0.45 1.00 0.80 2.00 27.00 2.000.1518-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:13:24 0.45 1.00 0.80 2.00 27.00 2.000.1518-12 27# Linear Flush 20 3,415 81 81 0:04:04 0:10:04 1.00 2.00 27.00 2.000.1518-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 18-14 Shut-In Shut-In984,196 23,433 26,943 3,304,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6877,9753,250,000(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)99,44154,000Initial Design Material Volume 395.1 977.4 702.4 1,954.8 26,390.2 1,954.8 146.6-6,780- 0.3028 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) ppm ppm ppm-Max Additive Rate 0.4 0.8 0.7 1.7 22.7 1.7 0.1-Min Additive RateFluid Type27# Delta Frac27# LinearSeawaterFreeze Protect----Proppant TypeWanli 16/20 Ceramic100M---Interval 17Coyote@ 5841.59 - 5845.59 ft - °FInterval 18Coyote@ 5342.06 - 5346.06 ft - °F23:31:34 Conoco Phillips - 3S-723Planned Design5 WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS E-Delivery3T-731 50-103-20905-00-00 224-156 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 10-Apr-25 13T-730 50-103-20907-00-00 225-010 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 30-Apr-25 1Transmittal Receipt________________________________ X____________________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.aurana@slb.comSLB Auditor - A Transmittal Receipt signature confirms that a package (box, envelope, etc.) has been received and the contents of the package have been verified to match the media noted above. The specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this point.# Schlumberger-PrivateT40406T404073T-73050-103-20907-00-00225-010KUPARUK RIVERMWD/LWD/DDVISION ServiceFINAL FIELD30-Apr-251Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.05.14 09:03:24 -08'00' KƌŝŐŝŶĂƚĞĚ͗ĞůŝǀĞƌĞĚƚŽ͗8-May-25ůĂƐŬĂKŝůΘ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐ08May25-NRddE͗DĞƌĞĚŝƚŚ'ƵŚůϯϯϯt͘ϳƚŚǀĞ͕͘^ƵŝƚĞϭϬϬϲϬϬ ϱϳƚŚWůĂĐĞŶĐŚŽƌĂŐĞ͕ůĂƐŬĂϵϵϱϬϭͲϯϱϯϵŶĐŚŽƌĂŐĞ͕<ϵϵϱϭϴ;ϵϬϳͿϮϳϯͲϭϳϬϬŵĂŝŶ;ϵϬϳͿϮϳϯͲϰϳϲϬĨĂdžt >>ED W/η^ Zs/ KZ Zη &/ >ED ^ Zs/ ^Z/Wd/KE >/s Z> ^Z/Wd/KE ddzW d >K'' 3S-610 501-032-0875-00-00 223-126 Kuparuk River WL TTIX-FSI FINAL FIELD 24-Apr-253B-12 50-029-21370-00-00 185-116 Kuparuk River WL WFL FINAL FIELD 27-Apr-253T-730 50-103-20907-00-00 225-010 Kuparuk River WL TTiX-SCMT FINAL FIELD 1-May-25CD4-24 50-103-20602-00-00 209-097 Colville River WL Packer Setting FINAL FIELD 4-May-25CD1-01A 50-103-20299-01-00 212-099 Colville River WL RST FINAL FIELD 5-May-25dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺyͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺWƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞWůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉLJƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘EƌĂĂƐĐŚΛƐůď͘ĐŽŵ^>ƵĚŝƚŽƌͲdZE^D/dd>d dZE^D/dd>ηĞůŝǀĞƌLJZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽdž͕ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚ͘dŚĞƉĂĐŬĂŐĞǁŝůůďĞŚĂŶĚůĞĚͬĚĞůŝǀĞƌĞĚƉĞƌƐƚĂŶĚĂƌĚĐŽŵƉĂŶLJƌĞĐĞƉƚŝŽŶƉƌŽĐĞĚƵƌĞƐ͘dŚĞƉĂĐŬĂŐĞΖƐĐŽŶƚĞŶƚƐŚĂǀĞŶŽƚďĞĞŶǀĞƌŝĨŝĞĚďƵƚƐŚŽƵůĚďĞĂƐƐƵŵĞĚƚŽĐŽŶƚĂŝŶƚŚĞĂďŽǀĞŶŽƚĞĚŵĞĚŝĂ͘η^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞT40398T40399T40400T40401T404023T-73050-103-20907-00-00225-010Kuparuk RiverWLTTiX-SCMTFINAL FIELD1-May-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.05.08 14:16:08 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-18 HAPPY VALLEY B-18 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 B-18 50-231-20121-00-00 225-001-0 N SPT 2691 2250010 2500 0 2630 2611 2602 0 0 0 0 OTHER P Brian Bixby 3/25/2025 MIT-T post completion HAK 169 Rig 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:HAPPY VALLEY B-18 Inspection Date: Tubing OA Packer Depth 0 0 0 0IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB250403191811 BBL Pumped:1.5 BBL Returned:1.5 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 9 9 9 9 99 999 9 9 9 *DVSURGXFHU MIT-T James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:46:36 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-18 HAPPY VALLEY B-18 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 B-18 50-231-20121-00-00 225-001-0 N SPT 2691 2250010 2500 0 230 227 225 0 0 0 0 OTHER P Brian Bixby 3/25/2025 MIT-IA Post Completion HAK 169 Rig 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:HAPPY VALLEY B-18 Inspection Date: Tubing OA Packer Depth 0 2620 2615 2615IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB250403192106 BBL Pumped:2 BBL Returned:2 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 999 99 9 9 9 9 9 9 *DVSURGXFHU James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:44:04 -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?KRU 3T-730 Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Chris Brillon Contact Email:Brian.T.Broussard@conocophillips.com Contact Phone: 907-263-4090 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 4/2/2025 Perforation Depth MD (ft): BurstMD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528 / ADL025544 225-010 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20907-00-00 ConocoPhillips Alaska Inc Proposed Pools: AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size Kuparuk River Field Coyote Oil Pool Wells Engineering Manager Brian Broussard Subsequent Form Required: Suspension Expiration Date: TVD m n P 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-175 By Grace Christianson at 1:11 pm, Mar 27, 2025 X Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available Diverter variance per 20 AAC 25.035(h)(2) contingent on AOGCC review of KRU 3T-731 surface hole drilling reports and gas log. VTL 4/10/2025 PLEASE NOTE: running 7-5/8" rams will be required while running 7-5/8" casing. X DSR-4/3/25A.Dewhurst 10APR25 10-407 *&: 4/10/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.10 10:28:09 -08'00' RBDMS JSB 041025 ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage , Alaska 99510-0360 Telephone 907-276-1215 March 19, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry for PTD# 225-010 Well Name: 3T-730 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Sundry to an Approved Program for the onshore Coyote producer 3T-730, which is planned to spud on 4/2/2025. It is requested to revert to a single stage cement job on the 7-5/8” x 4-1/2” production casing due to the possibility of debris from the stage cementer posing significant risk to being able to complete the wellbore. Upon running the tapered production string as per the original PTD, cement will be pumped to at least 250’ TVD above the Coyote in a single stage. Please find attached the information required 1. Form 10-403 2. Proposed drilling program 3. Proposed completion diagram Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Brian Broussard at 907-263-4090 (brian.t.broussard@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-730 Well File / Jenna Taylor ATO 1804 Will Earhart ATO1552 Brian Broussard Chris Brillon ATO 1548 Drilling Engineer Pat Perfetta ATO 1462 Brian Broussard I am the author of this document 2025.03.26 09:07:34 -08'00' Brian Broussard 3T-730 AOGCC 10-403 Sundry 3/19/2025 3T-730 AOGCC 10-403 Sundry 1 | 3 1. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. Pick up and run in hole with 9 7/8” x 8 3/4” drilling BHA to drill the production hole section. 2. Chart casing pressure test to 3,000 psi for 30 minutes. 3. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 4. Drill 9 7/8” hole to 4838’MD / 4,087 . Close underreamer and drill 8 3/4” to production section TD in the Coyote Reservoir. (LWD Program: GR/RES/Den/Neu). 5. Pull out of hole with drilling BHA. 6. Run tapered 7 5/8” x 4 1/2” casing with frac sleeves and toe valve. Displace to corrosion inhibited brine. 7. Pump single stage cement job to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4,000 psi (charted). Pump 3-5 bbls of diesel down OA. 8. WOC to reach 100psi compressive strength. Rig up wireline and log TOC. If casing not pressure tested on plug bump, pressure test to 4,000 psi. 9. Run 4 1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. Test hanger seals to 5,000 psi 10. Pressure test against the glass plug to set production packer, test tubing to 4,550 psi, chart test. 11. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 12. Install HP-BPV and test to 1500 psi. 13. Nipple down BOP. 14. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 15. Freeze protect down tubing and annulus. 16. Secure well. Rig down and move out. Please note – This well will be frac’d 2. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.7 33.7 L80 P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 4 1/2 8 3/4 12.6 P110-S Hyd563 Cemented with frac sleeves *7 5/8” x 4 1/2” run together as a tapered string, utilizing a crossover joint 3T-730 AOGCC 10-403 Sundry 3/19/2025 3T-730 AOGCC 10-403 Sundry 2 | 3 10 3/4” Surface Casing run to 2,620 ’ MD / 2,501 ’ TVD Cement: Cement 2,620 MD to 2,120 (500’ of tail) with Class G + Add's @ 15.8 PPG, and from 2,120' to surface with 11.0 ppg Arctic Lite Crete. Assume 250% excess annular volume in permafrost and 50% excess below the permafrost (1,763 ’ MD), zero excess in 20” conductor. Lead 2,439ft3 => 840 sx of 11.0 ppg Class G + Add's @ 2.92 ft3 /sk Tail 316 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk 7 5/8” x 4 1/2 Production Casing (Tapered String) run to 13,948 MD / 4,171 TVD Top of slurry is designed to be at 4,201 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. Assume 40% excess in 9 7/8” hole and 15% excess in 8 3/4” hole. L 7 5/8 Tail 192 ft3 => 144 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk assuming 40% excess in 9 7/8” hole 4 1/2 Tail 3,218 ft3 => 2,427 sx of 14.8 ppg Class G + Add's @ 1.33 ft3/sk assuming 15% excess in 8 3/4” hole Total Cmt 3420 ft3 => 2571 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk 3T-730 AOGCC 10-403 Sundry 3/19/2025 3T-730 AOGCC 10-403 Sundry 3 | 3 3. Proposed Completion Schematic CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Loepp, Victoria T (OGC) To:Loepp, Victoria T (OGC) Subject:FW: [EXTERNAL]RE: 3T-730 - Permit 225-010 - Change of Scope Request - Production Cementing Date:Thursday, April 10, 2025 8:58:00 AM Attachments:image001.png image002.png From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Wednesday, March 26, 2025 8:57 AM To: Broussard, Brian T <Brian.T.Broussard@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Earhart, Will C <William.C.Earhart@conocophillips.com>; Dodson, Kate <Kate.Dodson@conocophillips.com> Subject: [EXTERNAL]RE: 3T-730 - Permit 225-010 - Change of Scope Request - Production Cementing 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. Brian, Please submit a change of approved program for this change. Victoria Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent: Monday, March 17, 2025 3:29 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Earhart, Will C <William.C.Earhart@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dodson, Kate <Kate.Dodson@conocophillips.com> Subject: 3T-730 - Permit 225-010 - Change of Scope Request - Production Cementing Hello, I am requesting a change of scope to the 3T-730 to change the Production1 section cement job from 2 stages to 1 stage, in line with the approved scope change on the 3T-731. If approved, I will submit a sundry with updated details. As with the 3T-731, it was determined that the added risk of the stage tool needed to pump the second stage of the cement job was less desirable than pumping a single stage cement job. The proposed steps below will be followed in the single stage cement operation: Pump Corrosion Inhibited NaCl brine ahead of the cement, with sufficient volume to fill the annulus above the Top of Cement. Pump 14.8 ppg cement with sufficient volume to cover 250’ TVD above the Coyote Inject 3-5 bbl of diesel down the 10-3/4” x 7-5/8” annulus (OA), equal to 50-100’ of annular height to protect the annular fluid from surface temperature effects. This would result in a fully freeze protected annulus. Below is an updated schematic with the proposed changes. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Dewhurst, Andrew D (OGC) To:Broussard, Brian T Cc:Loepp, Victoria T (OGC); Guhl, Meredith D (OGC); Zwarich, Nola R; Dodson, Kate; Earhart, Will C; AOGCC Records (CED sponsored) Subject:RE: Diverter Waiver Supporting Documentation for 3T-730 Date:Thursday, March 20, 2025 1:39:37 PM Attachments:image001.png Brian, Thank you. This satisfies the diverter variance condition of approval for KRU 3T-730. Andy From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent: Friday, 14 March, 2025 16:00 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com>; Dodson, Kate <Kate.Dodson@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com> Subject: Diverter Waiver Supporting Documentation for 3T-730 Hello Andy, Attached is the requested surface hole drill and BROOH data from the 3T-731. We got to surface this morning, which is why the timelog summary ends at midnight. Average gas %: .048% Max gas %: 1.22% @ 2,306’ MD The gas monitoring system was calibrated at the beginning of the surface section. I confirmed with our geologist that there were no abnormalities in the formations drilled in the surface hole. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 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 ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, Alaska, 99510 Re: Kuparuk River Field, Coyote Oil Pool, KRU 3T-730 ConocoPhillips Alaska Inc. Permit to Drill Number: 225-010 Surface Location: 1645' FSL, 145' FWL, NWSW S1 T12N R7E Bottomhole Location: 2342.7317' FSL, 519.43905' FWL, SENW S13 T12N R7E 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 27 day of February, 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.27 11:10:02 -09'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 13948.4 TVD: 4171 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: 3/9/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2940' to ADL025528 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-467354 y- 6003373 Zone- 4 12 to Same Pool: 4285' to 3S-701A 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42"20" 94 H-40 Welded 81 39 39 120 120 13.5"10.75" 45.5 L-80 Hyd563 2581 39 39 2620 2501 9.875"7.625" 29.7 L80 Hyd563 3999 39 39 4038 3702 9.875"7.625" 33.7 P110S Hyd563 800 4038 3702 4838 4087 8.75"4.5" 12.6 P110-S Hyd563 9110 4838 4087 13948 4171 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: Brian Broussard Chris Brillon Contact Email:Brian.T.Broussard@cop.com Wells Engineering Manager Contact Phone:907-263-4090 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Coyote Oil Pool 1645' FSL, 145' FWL, NWSW S1 T12N R7E ADL025528 / ADL025544 (including stage data) 849' FSL, 4546' FWL, SWSW S2 T12N R7E LONS 01-013 2342.7317' FSL, 519.43905' FWL, SENW S13 T12N R7E 2560 / 2560 GL / BF Elevation above MSL (ft): 1865 1376 18. Casing Program: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc 59-52-180 KRU 3T-730 840sks 11ppg Lead, 280sks 15.8ppg Tai 1st stage: 2571sks 14.8ppg 2nd Stage: 235sks 11.0 ppg Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Casing Length Size Cement Volume MD Total Depth MD (ft):Total Depth TVD (ft):Plugs (measured):Effect. Depth MD (ft):Effect. Depth TVD (ft): Surface Conductor/Structural Liner Production Intermediate Perforation Depth MD (ft):Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. s N yp L l R S os N s Noo s N o D s s sD 0 o p G S S 20 S s No s No S G E s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) VTL 2/27/25 By Grace Christianson (grace.christianson@alaska.gov) at 2:59 pm, Feb 04, 2025 A.Dewhurst 25FEB25 DSR-2/18/25 225-010 Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available XDiverter variance per 20 AAC 25.035(h)(2) contingent on AOGCC review of KRU 3T-731 surface hole drilling reports and gas log. 50-103-20907-00-00 *&: 2/27/2025 2/27/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.27 11:10:17 -09'00' RBDMS JSB 022825 <ZhϯdͲϳϯϬ Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. .58'67 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage , Alaska 99510-0360 Telephone 907-276-1215 January 28, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-730 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Injector well from the 3T drilling pad. The intended spud date for this well is 3/9/2025. It is intended that Doyon 142 be used to drill the well. 3T-730 will utilize a 13 1/2” surface hole drilled to TD and 10 3/4” casing will be set and cemented to surface. The 9 7/8” hol e will be drilled to ~5408’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 1/2” tapered casing string will be set and cemented from TD to secure the production casing and cover 250’ TVD above any hydrocarbon-bearing zones (Coyote) per AOGCC regulations. The well will be completed as a cemented, fracture stimulated Injector with 7 5/8” x 4 1/2” casing with frac sleeves. The 4 1/2” upper completion will include a production packer with GLM’s and a downhole guage tied back to surface. A variance is requested for a BOPE test interval of 21 days for this project. Doyon 142 is a strong participant in the CPAI BOPE 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 3T-730. At 3T, there has not been a significant indication of shallow gas hydrates to date, through the surface hole interval. An additional variance is requested to the casing ram requirement under 20AAC 25.035(e)(1) is granted for well 3T- 730. Being a 2 string well, COPA has determined the risk of inducing and/or handling a kick during the short duration of running the 7 5/8” casing is low. At the time in which the 7 5/8” casing will be picked up, the reservoir section will have been open, and pressures known and observed for over a week. If a kick were to be induced, the 4 1/2” casing will be within the reservoir section, and the well would be able to be controlled from the source. During the 7 5/8” casing run, a kick joint made up of 7-5/8” casing and 5” drill pipe will be available in the pipe shed, to be made up to the 7 5/8” casing, and run in hole to allow the full use of our annular and both 3-1/2” x 6” VBR’s to control any potential influx that is encountered. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1.Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a) 2.Proposed drilling program 3.Proposed drilling fluids program summary 4.Proposed completion diagram 5.Pressure information as required by 20 ACC 25.005 (c) (4) (a-c) 6.Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) Information pertinent to the application that is presently on file at the AOGCC: 1.Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2.A description of the drilling fluids handling system. 3.Diagram of riser set up. Recommend granting variance contingent on review of surface hole at future KRU 3T-731. AOGCC review of existing offset wells confirms CPAI analysis. -A.Dewhurst 25FEB25 variance of the diverter requirement If you have any questions or require further information, please contact Brian Broussard at 907-263-4090 (brian.t.broussard@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-730 Well File / Jenna Taylor ATO 1804 Will Earhart 1/0/1900 Brian Broussard Chris Brillon ATO 1548 Drilling Engineer Pat Perfetta ATO 1462 Brian Broussard I am the author of this document 2025.01.28 15:17:33 -09'00' Brian Broussard 3T-730 Well Plan Application for Permit to Drill Table of Contents 1. Well Name ............................................................................................................................. 2 2. Location Summary ................................................................................................................ 2 3. Proposed Drilling Program .................................................................................................... 2 4. BOP and Diverter Information .............................................................................................. 3 5. Procedure for Conducting Formation Integrity Tests ........................................................... 5 6. Casing and Cementing Program ............................................................................................ 5 7. Drilling Fluid Program ........................................................................................................... 6 8. Abnormally Pressured Formation Information..................................................................... 7 9. Seismic Analysis .................................................................................................................... 7 10. Seabed Condition Analysis .................................................................................................... 7 11. Evidence of Bonding ............................................................................................................. 7 12. Discussion of Mud and Cuttings Disposal and Annular Disposal .......................................... 7 13. Drilling Hazards Summary ..................................................................................................... 8 14. Proposed Completion Schematic ........................................................................................ 10 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 3T-730 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1,645 FSL, 145 FWL, NWSW S1 T12N R7E, UM NAD27 Northing: 6003373 Easting: 467354 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 849‘ FSL, 4546‘ FWL, SWSW S2 T12N R7E, UM NAD27 Northing: 6002581 Easting: 466472 Measured Depth, RKB: 4,789 Total Vertical Depth, RKB: 4,075 Total Vertical Depth, SS: 4,024 Total Depth (Toe) 2343‘ FSL, 519‘ FWL, SENW S13 T12N R7E, UM NAD27 Northing: 5993510 Easting: 467692 Measured Depth, RKB: 13,948 Total Vertical Depth, RKB: 4,171 Total Vertical Depth, SS: 4,120 Please see attached well stick diagram for the current planned development of the pad. Pad Layout Well Plat Attachment – 3T-730 Area of Review (AOR) An Area of Review plot is show below of the 3T-730 injector planned wellpath and offset wells. 3T-616 and Moraine 1 are the existing offset wells to the 3T-730. (Note: the 3T-616 is in the process of being drilled at the time of this application, with the current status as having intermediate casing set and cemented) 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD KRU 3T-616 update: Coyote isolated by 7-5/8" intermediat e casing cement. The Coyote top is 6,502’ MD / 4,120’ TVD. TOC from CBL is 5,041’ MD / 3,422’ TVD, which is 1,461’ MD / 698’ TVD above Coyote. - A.Dewhurst 20FEB25 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 142 onto 3T-730 2. Rig up and test riser, dewater cellar as needed. 3. Drill 13 1/2” hole to the surface casing point as per the directional plan. 4. Run and cement 10 3/4” surface casing to surface. 5. Install BOPE and MPD equipment. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8” x 8 3/4” drilling BHA to drill the production hole section. 8. Chart casing pressure test to 3,000 psi for 30 minutes. 9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 10. Drill 9 7/8” hole to 4838’MD / 4,087’ TVD . Close underreamer and drill 8 3/4” to production section TD in the Coyote Reservoir. (LWD Program: GR/RES/Den/Neu). 11. Pull out of hole with drilling BHA. 12. Run tapered 7 5/8” x 4 1/2” casing with frac sleeves and toe valve. Pump two stage cement job to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached), with second stage bringing cement to surface. Pressure test casing if possible on plug bump to 4,000 psi (charted). 13. Drill out stage tool while WOC to reach 100psi compressive strength. Rig up wireline and log TOC. If casing not pressure tested on plug bump, pressure test to 4,000psi. 14. Run 4 1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. Test hanger seals to 5,000 psi 15. Pressure test against the glass plug to set production packer, test tubing to 4,550 psi, chart test. 16. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 17. Install HP-BPV and test to 1500 psi. 18. Nipple down BOP. 19. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 20. Freeze protect down tubing and annulus. 21. Secure well. Rig down and move out. Please note – This well will be frac’d 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 4. BOP and Diverter Information Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP schematics on file for Doyon 142. Doyon 142 will use a BOPE stack equipped with an annular preventer, 2 sets of variable rams in upper and lower cavities, and blind/shear rams in the middle cavity, while drilling and running casing in the production section of 3T-730. 3T-730 has a MASP of 1,376 psi in the production hole section using the methodology in section 6 MASP calculations. With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2. Per 20AAC 25.035.e.1.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing being used, except that pipe rams need not be sized to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type Production Drilling & Casing: x Annular Preventer (iii) x 3-1/2” x 6” VBR’s x Blind/Shear Rams (ii) x 3-1/2” x 6” VBR’s (i) *A kick joint will be readily available to make up to the 7-5/8” casing if an influx is encountered, to allow RIH with the casing string and utilizing our annular and both 3-1/2” x 6” VBR’s 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD MASP Calculations Requirements of 20 AAC 25.005(c)(4) (A) maximum downhole pressure and maximum potential surface pressure; Maximum Potential Surface Pressure (MPSP) is determined as the lesser of: Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 1 Method 2 ܯܲܵܲ = [(ܨܩ × 0.052 )െܩܽݏ ܩݎܽ݀݅݁݊ݐ] × ܸܶܦ ܯܲܵܲ = ܨܲܲ െ (ܩܽݏ ܩݎܽ݀݅݁݊ݐ) × ܸܶܦ Where: FG – Fracture gradient at the casing seat in lb/gal 0.052 – Conversion from lb/gal to psi/ft Gas Gradient – 0.1 psi/ft TVD – True Vertical Depth of casing seat in ft RKB Where: FPP – Formation Pore Pressure at the next casing point Gas Gradient – 0.1 psi/ft The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: Section Hole Size Previous CSG Section TD MPSP psi MPSP MPSP Size MD TVD FG ppg Pore Pressure ppg | psi MD TVD Pore Pressure ppg | psi Method 1 psi Method 2 psi SURF 13 1/2 20 120 120 10.9 8.6 54 2,620 2,501 8.6 1,119 56 56 869 PROD 9 7/8 x 8 3/4 10 3/4 2,620 2,501 12.5 8.6 1,119 13,948 4,171 8.6 1,865 1,376 1,376 1,448 (B) data on potential gas zones; The wellbore is not expected to penetrate any shallow gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out casing shoe and perform LOT test or FIT in accordance with the LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.7 33.7 L80 P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 2nd stage ~200’ below surface casing to surface 4 1/2 8 3/4 12.6 P110-S Hyd563 Cemented liner with frac sleeves *7 5/8” x 4 1/2” run together as a tapered string, utilizing a crossover joint 10 3/4” Surface Casing run to 2,620 ’ MD / 2,501 ’ TVD Cement Plan: Cement 2,620 MD to 2,120 (500’ of tail) with Class G + Add's @ 15.8 PPG, and from 2,120' to surface with 11.0 ppg Arctic Lite Crete. Assume 250% excess annular volume in permafrost and 50% excess below the permafrost (1,763 ’ MD), zero excess in 20” conductor. Lead 2,439ft3 => 840 sx of 11.0 ppg Class G + Add's @ 2.92 ft3 /sk Tail 316 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk 7 5/8” x 4 1/2 Production Casing (Tapered String) run to 13,948 MD / 4,171 TVD Top of slurry is designed to be at 4,201 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. Assume 40% excess in 9 7/8” hole and 15% excess in 8 3/4” hole. Lead 7 5/8 Tail 192 ft3 => 144 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk assuming 40% excess in 9 7/8” hole 4 1/2 Tail 3,218 ft3 => 2,427 sx of 14.8 ppg Class G + Add's @ 1.33 ft3/sk assuming 15% excess in 8 3/4” hole Total Cmt 3420 ft3 => 2571 sx of 14.8 ppg Class G + Add's @ 1.33 ft3 /sk 2nd Stage – 7-5/8” x 10-3/4” surface casing, from 2,799’ (~200’ below surface shoe) to surface 7 5/8 CH 632 ft3 => 217 sx of 11 ppg Class G + Add's @ 2.92ft3 /sk assuming 10% excess in cased hole 7-5/8 OH 54 ft3 => 18sx of 11 ppg Class G + Add's @ 2.92 ft3 /sk assuming 25% excess in open hole Total Cmt 686ft3 => 235 sx of 11 ppg Class G + Add's @ 2.92 ft3 /sk 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 7. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Production Hole Size in. 13 1/2 9 7/8 x 8 3/4 Casing Size in. 10 3/4 7 5/8 x 4 1/2 Density PPG 9.0 – 10.5 9.0 – 10.0 PV cP 20-50 7-12 YP lb./100 ft2 30 - 80 15 - 30 Funnel Viscosity s/qt. 250 – 300 35-50 Initial Gels lb./100 ft2 30 - 50 5- 10 10 Minute Gels lb./100 ft2 50 - 70 7 - 15 API Fluid Loss cc/30 min. N.C. – 15.0 < 6.0 HPHT Fluid Loss cc/30 min. N/A < 10.0 pH 9.5 – 10.0 9.5 – 10.5 Surface Hole: A water-based spud mud will be used for the surface interval. Mud engineer to perform regular mud checks to maintain proper specifications The mud weight will be maintained at ч9.8 ppg by use of solids control system and dilutions where necessary. Production Hole: The horizontal production interval will be drilled with an inhibited fresh water polymer mud system weighted to 9.0 – 10.0 ppg. MPD will be utilized for adding backpressure during connections if necessary for wellbore stability. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 8. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 9. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 11. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 12. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 13. Drilling Hazards Summary 13 1/2" Hole - 10 3/4” Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low Follow real time surveys very closely, gyro survey as needed to ensure survey accuracy. Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Hole Swabbing on Trips Medium Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts/Hole Sloughing Medium Cool mud temperatures, minimize circulating times when possible Running sands and gravels Medium Maintain planned mud properties, increase mud weight, use weighted sweeps 9 7/8 x 8 3/4” Hole - 7 5/8 x 4 1/2” Production Casing - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Medium Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material Sloughing shale / Tight hole / Stuck Pipe Low Good hole cleaning, pre-treatment with LCM, stabilized BHA, maintain planned mud weights and adjust as needed, real time equivalent circulating density (ECD) monitoring Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Medium Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Casing to Bottom Medium Properly clean hole on the trip out with BHA, perform clean out run if necessary, monitor T&D real time Insufficient TOC to cover Coyote formation Medium Pre job modeling of pump rates and ECD’s. Proper mud conditioning prior to the job. Monitoring losses and adjusting pump rates as needed during the job. To be posted in Rig Floor Doghouse Prior to Spud 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD Well Proximity Risks: 3T is a multi-well pad, with only a few existing wells. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: x Reservoir Pressure: Unlikely to encounter any abnormal pressure, however, the rig will be prepared to weight up if required. x Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. x The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the primary intermediate cement job will be replanned to cover the zone as per the agency regulations. x Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. x Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 3T-730 AOGCC 10-401 APD 1/28/2025 3T-730 AOGCC 10-401 APD 14. Proposed Completion Schematic 39 500 500 800 800 1000 1000 1500 1500 2000 2000 3000 3000 5000 5000 10000 10000 13950 3T-730 wp08.1 Plan Summary 0 4 Dogleg Severity0 2500 5000 7500 10000 12500 Measured Depth 10-3/4" Surface Casing 7" Intermediate Casing 4-1/2" Production Liner 30.0 30.0 60.0 60.0 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 849 897 945 993 1040 1087 1133 1178 NDST-02 849 897 945 993 1040 1087 1133 1178 5010015020025030035040045050055060065070075080085089994999910491098114811981247129713461396144614961548160016521703 1754 1804 1852 1899 1946 1992 3T-731 wp09 2250 True Vertical Depth0 1500 3000 4500 6000 7500 9000 Vertical Section at 177.78° 10-3/4" Surface Casing 7" Intermediate Casing 4-1/2" Production Liner 15 30 45 Centre to Centre Separation0 425 850 1275 1700 2125 2550 2975 Measured Depth Equivalent Magnetic Distance DDI 6.842 SURVEY PROGRAM Date: 2019-05-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.10 1900.00 3T-730 wp08.1 (3T-730) r.5 SDI_URSA1 1900.00 2610.00 3T-730 wp08.1 (3T-730) MWD+IFR2+SAG+MS 2610.00 5150.00 3T-730 wp08.1 (3T-730) MWD+IFR2+SAG+MS 5150.00 13948.35 3T-730 wp08.1 (3T-730) MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 2501.10 2619.59 10-3/4" Surface Casing4130.66 5150.00 7" Intermediate Casing 4171.10 13948.40 4-1/2" Production Liner Mag Model & Date: BGGM2024 20-Mar-25 Magnetic North is 13.83° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.61° 57181.21nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 450.00 1.50 322.00 449.98 1.55 -1.21 1.00 322.00 -1.59 Start Build 2.50 4 1381.78 24.79 322.00 1351.10 167.41 -130.79 2.50 0.00 -172.34 Start 110.15 hold at 1381.78 MD 5 1491.93 24.79 322.00 1451.10 203.81 -159.23 0.00 0.00 -209.82 Start DLS 3.75 TFO -121.38 6 1842.15 20.98 289.20 1774.99 282.64 -264.12 3.75 -121.38 -292.65 Start 709.11 hold at 1842.15 MD 7 2551.26 20.98 289.20 2437.07 366.14 -503.91 0.00 0.00 -385.36 Start DLS 3.75 TFO -116.66 8 4958.16 81.00 174.00 4110.20 -960.74 -864.47 3.75 -116.66 926.58 Start Build 3.00 9 5158.16 87.00 174.00 4131.10 -1158.46 -843.69 3.00 0.00 1124.96 3T-730 I14 T1 041124 Start 20.00 hold at 5158.16 MD 10 5178.16 87.00 174.00 4132.15 -1178.32 -841.60 0.00 0.00 1144.89 Start DLS 1.50 TFO -36.34 11 5408.31 89.78 171.95 4138.61 -1406.62 -813.48 1.50 -36.34 1374.10 Start 8540.09 hold at 5408.31 MD 1213948.40 89.78 171.95 4171.10 -9862.60 381.72 0.00 0.00 9869.98 3T-730 I14 T2 032824 TD at 13948.40 FORMATION TOP DETAILS TVDPath Formation 1376.10 Top Ugnu 1701.10 Base Perm 2025.10 Top WSak 2425.10 Base WSak 2580.10 C-80 3589.10 Anomalous Zone 3891.10 C-35 4075.10 Top Coyote By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by Accepted by Approved by Plan 12+39.1 @ 51.10usft (D142) -15000150030004500True Vertical Depth0 1500 3000 4500 6000 7500 9000Vertical Section at 177.78°10-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner10002000300040005000600070008000900010000110001200013000139490°21°30°60°90°3T-730 wp08.1Top UgnuBase PermTop WSakBase WSakC-80Anomalous ZoneC-35Top CoyoteHole Size Transition3T-730 wp08.116:09, January 23 2025Section View -10000-8000-6000-4000-20000South(-)/North(+)-8000 -6000 -4000 -2000 0 2000 4000 6000West(-)/East(+)3T-730 I14 T2 0328243T-730 I14 T1 04112410-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner500100015002000250030003500400041713T-730 wp08.13T-730 wp08.1While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.8:20, January 23 20253ODQ9LHZ 0.000.751.502.253.003.754.505.256.006.757.50Separation Factor0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Measured Depth (1500 usft/in)3T-731/3T-731 wp09Plan: 3S-741 (P15)/3S-741 (P15) wp0STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3T PadWell: 3T-730Wellbore: 3T-730Design: 3T-730 wp08.1 0 35 Centre to Centre Separation0 500 1000 1500 2000 2500 Partial Measured Depth 3T-731 wp09Equivalent Magnetic Distance 3T-730 wp08.1 Ladder View 0 150 300 Centre to Centre Separation0 2500 5000 7500 10000 12500 Measured Depth3T-6213T-731 wp09Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 39.10 1900.00 3T-730 wp08.1 (3T-730) r.5 SDI_URSA1 1900.00 2610.00 3T-730 wp08.1 (3T-730) MWD+IFR2+SAG+MS 2610.00 5150.00 3T-730 wp08.1 (3T-730) MWD+IFR2+SAG+MS 5150.0013948.35 3T-730 wp08.1 (3T-730) MWD+IFR2+SAG+MS 16:17, January 23 2025 CASING DETAILS TVD MD Name 2501.10 2619.59 10-3/4" Surface Casing 4130.66 5150.00 7" Intermediate Casing 4171.10 13948.40 4-1/2" Production Liner 39 500 500 800 800 1000 1000 1500 1500 2000 2000 3000 3000 5000 5000 10000 10000 13950 3T-730 wp08.1 TC View 30 30 60 60 90 90 120 120 150 150 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 39110210309 408 507 605 703 800 897 993 1087 1178 1267 1352 NDST-02 39110210309 408 507 605 703 800 897 993 1087 1178 1267 1352 610711 811912 1012 1111 1210 1308 1406 15051600 1696 1790 1883 1976 2066 3T-621 100200300400500600700800899999109811981297 1396 149616001703 1804 1900 1992 2083 2171 3T-731 wp09 1289 1387 14861580 1675 1768 1860 1956 2051 3T-620 wp05 v5 39100200300400500599 698 796 894 991 1088 1184 1280 1375 1473 1571 1671 1771 1871 1969 2067 2164 2260 2355 2449 2541 2627 3T-622 wp05 v5 39100200300400500599 698 797 896 994 1091 1188 1285 1381 1478 1578 1679 1781 1881 1979 2075 2171 2265 2357 2448 3T-623 wp05 v5 39100200300400500599 699 797 896 993 1091 1187 1283 1377 1475 1575 16791783 1886 1984 2081 2178 2273 2367 2459 2549 3T-624 wp05 v5 39100200300400500600 699 798 896 994 1092 1188 1284 1379 1476 1578 16831789 1891 1988 2084 2178 3T-625 wp05 v5 39100200300400500600 699 798 896 994 1091 1187 1283 1377 1473 1576 1683 17913T-626 wp05 v5 39100200300400500 599 696 792 884 974 1060 3T-627 wp05 v5 39100200300400500600 699 798 895 992 1088 1183 1277 1369 1464 3T-628 wp05 v5 39100200300400500 600 699 797 894 991 1086 1179 1271 1362 3T-629 wp05 v5 SURVEY PROGRAM Date: 2019-05-03T00:00:00 Validated: Yes Version: From To Tool 39.10 1900.00 r.5 SDI_URSA1 1900.00 2610.00 MWD+IFR2+SAG+MS 2610.00 5150.00 MWD+IFR2+SAG+MS 5150.00 13948.35 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 2501.10 2619.59 10-3/4" Surface Casing 4130.66 5150.00 7" Intermediate Casing 4171.10 13948.40 4-1/2" Production Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 450.00 1.50 322.00 449.98 1.55 -1.21 1.00 322.00 -1.59 Start Build 2.50 4 1381.78 24.79 322.00 1351.10 167.41 -130.79 2.50 0.00 -172.34 Start 110.15 hold at 1381.78 MD 5 1491.93 24.79 322.00 1451.10 203.81 -159.23 0.00 0.00 -209.82 Start DLS 3.75 TFO -121.38 6 1842.15 20.98 289.20 1774.99 282.64 -264.12 3.75 -121.38 -292.65 Start 709.11 hold at 1842.15 MD 7 2551.26 20.98 289.20 2437.07 366.14 -503.91 0.00 0.00 -385.36 Start DLS 3.75 TFO -116.66 8 4958.16 81.00 174.00 4110.20 -960.74 -864.47 3.75 -116.66 926.58 Start Build 3.00 9 5158.16 87.00 174.00 4131.10 -1158.46 -843.69 3.00 0.00 1124.96 3T-730 I14 T1 041124 Start 20.00 hold at 5158.16 MD 10 5178.16 87.00 174.00 4132.15 -1178.32 -841.60 0.00 0.00 1144.89 Start DLS 1.50 TFO -36.34 11 5408.31 89.78 171.95 4138.61 -1406.62 -813.48 1.50 -36.34 1374.10 Start 8540.09 hold at 5408.31 MD 1213948.40 89.78 171.95 4171.10 -9862.60 381.72 0.00 0.00 9869.98 3T-730 I14 T2 032824 TD at 13948.40 3T-730 wp08.1AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 1900.00 r.5 SDI_URSA11900.00 2610.00 MWD+IFR2+SAG+MS2610.00 5150.00 MWD+IFR2+SAG+MS5150.00 13948.35 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2501.102619.5910-3/4" Surface Casing4130.665150.007" Intermediate Casing4171.1013948.404-1/2" Production Liner55101015152020252530300901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [10 usft/in]99310401087NDST-029931040108750100150200250300350400450500550600650700750800850899949999185218993T-731 wp09202720753T-623 wp05 v510913T-626 wp05 v56496997487988478959443T-628 wp05 v539501001502002503003504004505005506006496997487978463T-629 wp05 v539 500500 800800 10001000 15001500 20002000 30003000 50005000 1000010000 13950From Colour To MD39.10 To 2700.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00450.00 322.00 322.001381.78 322.00 0.001491.93 322.00 0.001842.15 289.20 -121.382551.26 289.20 0.004958.16 174.00 -116.665158.16 174.00 0.005178.16 174.00 0.005408.31 171.95 -36.3413948.40 171.95 0.00 3T-730 wp08.1AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 1900.00 r.5 SDI_URSA11900.00 2610.00 MWD+IFR2+SAG+MS2610.00 5150.00 MWD+IFR2+SAG+MS5150.00 13948.35 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2501.102619.5910-3/4" Surface Casing4130.665150.007" Intermediate Casing4171.1013948.404-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]26272668270827462784282028543T-622 wp05 v5261926573T-623 wp05 v526372679272027603T-624 wp05 v539 500500 800800 10001000 15001500 20002000 30003000 50005000 1000010000 13950From Colour To MD2600.00 To 5200.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00450.00 322.00 322.001381.78 322.00 0.001491.93 322.00 0.001842.15 289.20 -121.382551.26 289.20 0.004958.16 174.00 -116.665158.16 174.00 0.005178.16 174.00 0.005408.31 171.95 -36.3413948.40 171.95 0.00 3T-730 wp08.1AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 1900.00 r.5 SDI_URSA11900.00 2610.00 MWD+IFR2+SAG+MS2610.00 5150.00 MWD+IFR2+SAG+MS5150.00 13948.35 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2501.102619.5910-3/4" Surface Casing4130.665150.007" Intermediate Casing4171.1013948.404-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]39 500500 800800 10001000 15001500 20002000 30003000 50005000 1000010000 13950From Colour To MD5100.00 To 13950.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00450.00 322.00 322.001381.78 322.00 0.001491.93 322.00 0.001842.15 289.20 -121.382551.26 289.20 0.004958.16 174.00 -116.665158.16 174.00 0.005178.16 174.00 0.005408.31 171.95 -36.3413948.40 171.95 0.00 3T-730 wp08.1Spider Plot9:46, January 23 202539.10 To 13948.98Northing (6500 usft/in)Easting (6500 usft/in)354 0455055Moraine 135404550NDST-0235404550NDST-02PB135404550Nuna 135404550Nuna 1PB1354045503S-612354045503S-613354045503S-615354045503S-62535403S-719 (P02) wp0535403S-721 (I03) wp0435403S-740 (I15) wp0335403S-741 (P15) wp02354045503T-603354045503T-608354045503T-612354045503T-616354045503T-616 wp17.13540455 0553T-62135403T-731 wp093 5 4 0 4 5503T-601 wp05 v53 5 4 0 4 5503T-602 wp05 v5354045503T-604 wp05 v5354045503T-605 (ST) wp09354045503T-605PH wp03354045503T-606 wp08354045503T-607 wp05354045503T-609 wp06354045503T-610 wp05354045503T-611 wp06354045503T-613 wp07.135404 5503T-614 wp0635404 5 503T-615 wp05354045503T-617 wp0535404 5 503T-618 wp05 v5354045503T-619 wp07.135404 5 503T-620 wp05 v5354045503T-622 wp05 v535404 5 503T-623 wp05 v5354045503T-624 wp05 v5354045503T-625 wp05 v535404 5 503T-626 wp05 v5354045503T-627 wp05 v53 5 40 45 503T-628 wp05 v5354045503T-629 wp05 v535403T-730 wp08.1 3T-730 wp08.1Spider Plot9:47, January 23 202539.10 To 13948.98Northing (2500 usft/in)Easting (2500 usft/in)25283 033353840434548505355Moraine 12528303335NDST-022528303335NDST-02PB125283033353840434548Nuna 1252830333538404345485053Nuna 1PB12528303335384043454850533S-6122 5 2 8 3 0 33353840434548503S-6132 5 28303335384043454850533S-6152 5 2 8 30 33 35384043454850533S-625252830333538403S-719 (P02) wp052 5 2 8 30 333538403S-721 (I03) wp04252830333538403S-740 (I15) wp0325283033353 8 403S-741 (P15) wp0225283033353T-6032528303335383T-60825283033353840434548503T-612252830333538404 3 4548503T-616252830333538404 3 4548503T-616 wp17.1252830333538404345485 053553T-6212 52830333538403T-731 wp092 5 2 8 3 0 3 3 3 5 3 8 4 0 4 3 4 5483T-601 wp05 v52 5 2 8 3 0 3 3 3 5 3 8 4 0 4 3 4 548503T-602 wp05 v5252830333538403T-604 wp05 v525283033353T-605 (ST) wp0925283033353T-605PH wp03252830333538403T-606 wp08252830333538403T-607 wp05252830333538403T-609 wp06252830333538403T-610 wp0525283033353840434548503T-611 wp0625283033353T-613 wp07.125283033353840434 5 48503T-614 wp0625283033353T-615 wp0525283033353840434548503T-617 wp05252830333538404850533T-618 wp05 v5252830333538403T-619 wp07.125283033353840434 5 48503T-620 wp05 v525283033353840434548503T-622 wp05 v525283033353840434 5 483T-623 wp05 v525283033353840434548503T-624 wp05 v525283033353840434548503T-625 wp05 v525283033353840433T-626 wp05 v52528303335384043454 8 503T-627 wp05 v52528 30 3 3 35 3 8 4 0 43 4 5 483T-628 wp05 v525283033353840434548503T-629 wp05 v5252 83 0333538403T-730 wp08.1 3T-730 wp08.1Spider Plot9:48, January 23 202539.10 To 13948.98Northing (450 usft/in)Easting (450 usft/in)NDST-02NDST-02PB1Nuna 1Nuna 1PB13S-6123S-6153T-6033T-608253T-6122527293T-6162527293T-616 wp17.13T-6212 5272931 33353739413T-731 wp093T-601 wp05 v52 53T-602 wp05 v3T-604 wp05 v53T-605 (ST) wp093T-605PH wp033T-606 wp083T-607 wp053T-609 wp063T-610 wp053T-611 wp063T-613 wp07.125273T-614 wp063T-615 wp053T-617 wp053T-618 wp05 v53T-619 wp07.13T-620 wp05 v52527293T-622 wp05 v525273T-623 wp05 v52527293T-624 wp05 v52527293T-625 wp05 v525273T-626 wp05 v52527293T-627 wp05 v52527 2 93T-628 wp05 v52527293T-629 wp05 v5252 72 93133353739413T-730 wp08.1 3T-730 wp08.1Spider Plot9:49, January 23 202539.10 To 13948.98Northing (90 usft/in)Easting (90 usft/in)8101214NDST-028101214NDST-02PB1141618Nuna 1141618Nuna 1PB1203T-61281012141618203T-621246810121416182022242 628 30323T-731 wp09183T-615 wp05183T-617 wp0516183T-618 wp05 v5141618203T-619 wp07.112141618203T-620 wp05 v510121416182022243T-622 wp05 v5810121416182022243T-623 wp05 v56810121416182022243T-624 wp05 v52468101214161820223T-625 wp05 v52468101214161820223T-626 wp05 v52468103T-627 wp05 v52468101214161820223T-628 wp05 v52468 101214 161820223T-629 wp05 v524681012141618202224262 8 30323T-730 wp08.1 3T-730 wp08.1Moraine 1NDST-02PB1Nuna 1PB13S-6123S-6133S-6153S-6253T-6163T-6213T-731 wp093T-605PH wp033T-615 wp053-D View3T-730 wp08.19:55, January 23 2025 3T-730 wp08.1Moraine 1Nuna 1PB13S-6123S-6133S-6153S-6253T-6163T-6213T-731 wp093T-614 wp063T-615 wp053T-618 wp05 v53T-620 wp05 v53T-623 wp05 v53T-626 wp05 v53-D View3T-730 wp08.19:57, January 23 2025 3T-730 wp08.1Moraine 13T-6163T-731 wp093-D View3T-730 wp08.110:17, January 23 2025 -10000-7500-5000-250002500South(-)/North(+) (2500 usft/in)-7500 -5000 -2500 0 2500 5000 7500 10000 12500West(-)/East(+) (2500 usft/in)4 1 2 0414041604180Mora in e 1 NDST-02NDST-02PB14120414041604180Nuna 14120414041604180Nuna 1PB141204140416041803S-61241204140416041803S-61341204140416041803S-6154120414041604180 3S-62541204140416041803S-719 (P02) wp0541204140416041803S-721 (I03) wp044120414041603S-740 (I15) wp0341204140416041803S-741 (P15) wp023T-6033T-60841204140416041803T-6124 1 2 0414041604180 3T-6164 1 2 0414041604180 3T-616 wp17.13 T -6 2 1 41204140416041803T-731 wp094 1 2 04140416041803T-601 wp05 v54 1 2 04140416041803T-602 wp05 v53T-604 wp05 v53T-605 (ST) wp093T-605PH wp033T-606 wp083T-607 wp053T-609 wp063T-610 wp0541204140416041803T-611 wp063T-613 wp07.141204140416041803T-614 wp063T-615 wp0541204140416041803T-617 wp053T-618 wp05 v53T-619 wp07.13T-620 wp05 v541204140416041803T-622 wp05 v541204140416041803T-623 wp05 v541204140416041803T-624 wp05 v541204140416041803T-625 wp05 v54120414041603T-626 wp05 v541204140416041803T-627 wp05 v54 120414041604180 3T-628 wp05 v541204140416041803T-629 wp05 v54120414041603T-730 wp08.13T-730 wp08.1Quarter Mile View10:03, January 23 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-730 I14 T1 041124 4131.10 Circle (Radius: 100.00)3T-730 I14 T2 032824 4171.10 Circle (Radius: 100.00)3T-730 I14 T1 QM 4131.10 Circle (Radius: 1320.00)3T-730 I14 T2 QM 4171.10 Circle (Radius: 1320.00) -10000-7500-5000-250002500South(-)/North(+) (2500 usft/in)-7500 -5000 -2500 0 2500 5000 7500 10000 12500West(-)/East(+) (2500 usft/in)4 1 2 0414041604180 M o r a in e 1 41204140416041803S-721 (I03) wp0441204140416041803S-741 (P15) wp024 1 2 0414041604180 3T-61641204140416041803T-731 wp0910-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner4120414041603T-730 wp08.13T-730 wp08.1Quarter Mile View10:10, January 23 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-730 I14 T1 041124 4131.10 Circle (Radius: 100.00)3T-730 I14 T2 032824 4171.10 Circle (Radius: 100.00)3T-730 I14 T1 QM 4131.10 Circle (Radius: 1320.00)3T-730 I14 T2 QM 4171.10 Circle (Radius: 1320.00) -2000200400600800South(-)/North(+) (200 usft/in)-1200 -1000 -800 -600 -400 -200 0 200West(-)/East(+) (200 usft/in)NDST-02NDST-02PB1Nuna 1Nuna 1PB13S-6123T-6163 T -6 2 1 24802 5 002520 3T-731 wp093T-609 wp063T-610 wp052480250025203T-611 wp063T-613 wp07.13T-614 wp063T-615 wp052480250025203T-617 wp052480250025203T-618 wp05 v52480250025203T-619 wp07.12480250025203T-620 wp05 v52480250025203T-622 wp05 v52480250025203T-623 wp05 v52480250025203T-624 wp05 v52480250025203T-625 wp05 v52480250025203T-626 wp05 v53T-627 wp05 v52480250025203T-628 wp05 v52480250025203T-629 wp05 v52480250025203T-61210-3/4" Surface Casing2480250025203T-730 wp08.13T-730 wp08.1Surface Casing 500 radius16:58, January 23 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-730 I14 T1 041124 4131.10 Circle (Radius: 100.00)3T-730 I14 T2 032824 4171.10 Circle (Radius: 100.00)3T-730 I14 T1 QM 4131.10 Circle (Radius: 1320.00)3T-730 I14 T2 QM 4171.10 Circle (Radius: 1320.00)3T-730 Srf Csg 2501.10 Circle (Radius: 500.00) -2000200400600800South(-)/North(+) (200 usft/in)-1200 -1000 -800 -600 -400 -200 0 200West(-)/East(+) (200 usft/in)24802 5 002520 3T-731 wp092480250025203T-61210-3/4" Surface Casing2480250025203T-730 wp08.13T-730 wp08.1Surface Casing 500 radius17:02, January 23 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-730 I14 T1 041124 4131.10 Circle (Radius: 100.00)3T-730 I14 T2 032824 4171.10 Circle (Radius: 100.00)3T-730 Srf Csg 2501.10 Circle (Radius: 500.00) 3T-730 wp08.1 Surface Location 3T-730 wp08.1 Surface Location # Schlumberger-Confidential 3T-730 wp08.1 Surface Casing 3T-730 wp08.1 Surface Casing # Schlumberger-Confidential 3T-730 wp08.1 Top Coyote 3T-730 wp08.1 Top Coyote # Schlumberger-Confidential 3T-730 wp08.1 Intermediate Csg 3T-730 wp08.1 Intermediate Csg # Schlumberger-Confidential 3T-730 wp08.1 TD 3T-730 wp08.1 TD # Schlumberger-Confidential Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. COYOTE OIL KRU 3T-730 KUPARUK RIVER 225-010 1 Dewhurst, Andrew D (OGC) From:Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent:Tuesday, 25 February, 2025 09:44 To:Dewhurst, Andrew D (OGC) Cc:Loepp, Victoria T (OGC); Guhl, Meredith D (OGC); Zwarich, Nola R Subject:RE: [EXTERNAL]KRU 3T-730 PTD (225-010): Question Hi Andy, We are still on the 3T-616, so I don’t have anything to share on the 3T-731 yet. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, February 25, 2025 9:16 AM To: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com> Subject: RE: [EXTERNAL]KRU 3T-730 PTD (225-010): Question Brian, Thank you for this. Has the KRU 3T-731 well TD’d the surface hole? If so, would you also provide the same informaƟon for it? Thanks, Andy From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent: Monday, 24 February, 2025 15:12 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com > Subject: RE: [EXTERNAL]KRU 3T-730 PTD (225-010): Question Hi Andy, 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. 2 Thanks for reviewing the application. The gas monitoring system was repaired and calibrated before starting the surface section of this well. I’ve attached the time log and EDR data from the 3T-616 surface hole drill and BROOH. This surface section saw an average of .12% gas, with a maximum of 1.4% at 2,814’ MD. I also conƱrmed with our Geophysicist that there were no abnormalities in the surface log data. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, February 20, 2025 3:43 PM To: Broussard, Brian T <Brian.T.Broussard@conocophillips.com > Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com > Subject: [EXTERNAL]KRU 3T-730 PTD (225-010): Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Brian, I am compleƟng my review of the KRU 3T-730 PTD and have one quesƟon: x Regarding the diverter variance: during the review of KRU 3T-731 PTD, I discussed with MaƩ Smith some quesƟonable shallow gas readings at 3T-612 (~350 units while the BHA was sƟll in the conductor). He menƟoned that they then calibrated the gas readings before drilling 3T-616. Did 3T-616 see any elevated gas in the surface hole secƟon? Would you please send a copy of the total gas log and daily reports as support? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 WELL PERMIT CHECKLIST Company ConocoPhillips Alaska, Inc. Well Name:KUPARUK RIV UNIT 3T-730 Initial Class/Type SER / PEND GeoArea 890 Unit 11160 On/Off Shore On Program SERField & Pool Well bore seg Annular DisposalPTD#:2250100 KUPARUK RIVER, COYOTE OIL - 490120 NA1Permit fee attached Yes ADL025528 and ADL0255442Lease number appropriate Yes3Unique well name and number Yes KUPARUK RIVER, COYOTE OIL - 490120 - governed by CO 6184Well located in a defined pool Yes5Well located proper distance from drilling unit boundary NA6Well located proper distance from other wells Yes7Sufficient acreage available in drilling unit Yes8If deviated, is wellbore plat included Yes9Operator only affected party Yes10Operator has appropriate bond in force Yes11Permit can be issued without conservation order Yes12Permit can be issued without administrative approval Yes13Can permit be approved before 15-day wait Yes Area Injection Order No. 4514Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes15All wells within 1/4 mile area of review identified (For service well only) No16Pre-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) Yes 81 '18 Conductor string provided Yes SC set at 2620' MD19Surface casing protects all known USDWs Yes 196% excess20CMT vol adequate to circulate on conductor & surf csg Yes21CMT vol adequate to tie-in long string to surf csg Yes cemented production liner22CMT will cover all known productive horizons Yes23Casing designs adequate for C, T, B & permafrost Yes24Adequate tankage or reserve pit NA25If a re-drill, has a 10-403 for abandonment been approved Yes26Adequate wellbore separation proposed Yes27If diverter required, does it meet regulations Yes Max reservoir pressure is 1865 psig(8.6 ppg EMW);will drill w/ 9-10 ppg EMW28Drilling fluid program schematic & equip list adequate Yes29BOPEs, do they meet regulation Yes MPSP is 1376 psig; will test BOPs to 5000 psig initially and 3000 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 shutdown Yes33Is presence of H2S gas probable Yes34Mechanical condition of wells within AOR verified (For service well only) Yes H2S not anticipated35Permit can be issued w/o hydrogen sulfide measures Yes Expected reservoir pressure is 8.5-8.8 ppg EMW.36 Data presented on potential overpressure zones NA37Seismic analysis of shallow gas zones NA38Seabed condition survey (if off-shore) NA39Contact name/phone for weekly progress reports [exploratory only] Appr ADD Date 2/20/2025 Appr VTL Date 2/24/2025 Appr ADD Date 2/20/2025 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date *&:JLC 2/27/2025
