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224-074
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-603 224-074 DATE:10/01/2025 Transmitted: 3T-603 Via SFTP Transmittall instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-603 - e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | 224-074 T40933 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.01 14:34:50 -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-603,3T-616 DATE: 08/04/2025 Transmitted: Halliburton PixStar Data Via SFTP 224-074 T40731 224-138 T40732 Transmittal instructions: please promptly sign, scan, and e-mail to AKGGREDTSupport@ConocoPhillips.onmicrosoft.COM CC: 3T-603, 3T-616 e-transmittal well folder Receipt: Date: Alaska/IT-Data Services |ConocoPhillips Alaska | Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.05 08:21:08 -08'00' Originated: Delivered to:31-Jul-25Alaska Oil & Gas Conservation Commiss31Jul25-NRATTN: Meredith Guhl333 W. 7th Ave., Suite 100 600 E 57th Place Anchorage, Alaska 99501-3539Anchorage, AK 99518(907) 273-1700 main (907)273-4760 faxWELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTIONDATA TYPE DATE LOGGED3S-703 50-029237-61-00-00 223-056 Kuparuk River WL TTiX-HSD FINAL FIELD 8-Jul-253T-731 50-103209-05-00-00 224-156 Kuparuk River WL TTiX FSI & SCMT FINAL FIELD 12-Jul-253T-603 50-103208-87-00-00 224-074 Kuparuk River WL Caliper & Perforation FINAL FIELD 14-Jul-253S-606 50-103208-70-00-00 223-111 Kuparuk River WL TTiX- IPROF FINAL FIELD 21-Jul-25Transmittal Receipt________________________________X__________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.Nraasch@slb.comSLB Auditor - TRANSMITTAL DATETRANSMITTAL #A Delivery Receipt signature confirms that a package (box, envelope, etc.) has been received. The package will be handled/delivered per standard company reception procedures. The package's contents have not been verified but should be assumed to contain the above noted media.# Schlumberger-Private225-035T40727T40728T40729T407303T-60350-103208-87-00-00224-074Kuparuk RiverWLCaliper & PerforationFINAL FIELD14-Jul-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.08.01 08:56:13 -08'00' C:\Users\grgluyas\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\4MY18Q6V\2025-07-13_22650_KRU_3T-603_CaliperSurvey_LogData_Transmittal.docx DELIVERABLE DISCRIPTION Ticket # Field Well # API # Log Description Log Date 22650 KRU 3T-603 50-103-20887-00 Caliper Survey w/ Log Data 13-Jul-25 DELIVERED TO Company & Address DIGITAL FILE # of Copies LOG PRINTS # of Prints CD’s # of Copies 1 AOGCC Attn: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Ak. 99501-3539 Delivered By: CPAI Sharefile ______________________________ _____________________________________ Date received Signature ______________________________ ______________________________________ PLEASE RETURN COPY VIA EMAIL TO: DIANE.WILLIAMS@READCASEDHOLE.COM READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM 224-074 T40684 7/24/2025 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.24 13:38:31 -08'00' Originated: Delivered to:6-Jun-25Alaska Oil & Gas Conservation Commiss06Jun25-NR , <)*(*$''' 8:)* 81&) :)*%$+ +*#6 1$!>> ''>+*#6 1>> ;A>:C:' :/A>:C:' .:=EWELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3T-730 501-03-20907-00-00 225-010 Kuparuk River WL TTiX HSD FINAL FIELD 27-May-253S-703 501-03-20913-00-00 225-035 Kuparuk River WL TTiX-IBC-CBL FINAL FIELD 31-May-253T-603 501-03-20887-00-00 224-074 Kuparuk River WL TTiX FSI FINAL FIELD 20-May-25Transmittal ReceiptFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFF 4FFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFFF%)/ &6) ) Please return via courier or sign/scan and email a copy to Schlumberger.!+*G!$28+#/&7<)# TRANSMITTAL DATETRANSMITTAL # $ B + )!6) +#=/!)*)+6 A2#E1 $# 1 )+8C*!2 + <8 * +6 0$$2 *<$ << $ < !)<<+#/B + )##+ < !8 * +6 H!+#) )!* #)2 = <2)!*#$<2 !!/ <)#+#))* 2# #) </ <8D&+*$/2 6 %) T40532T40533T405343T-603501-03-20887-00-00224-074Kuparuk RiverWLTTiX FSIFINAL FIELD20-May-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.06.06 13:07:43 -08'00' 224-066: T39789 224-074: T39790 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.20 08:09:32 -09'00' 39789224 066: T3 39790224-074: T3 a Q y I o-,L-`{ SAMPLE TRANSMITTAL TO: AOGCC 333 WEST 7T" SUITE 100 ANCH. AK. 99501 279-1433 OPERATOR: CPAI SAMPLE TYPE: Dry Cuttings SAMPLES SENT: 3T-603 3020 - 21228 4 Boxes SENT BY: M. McCRACKEN C qO'� DATE: 11 /01 /2024 AIR BILL: N/A CPAI: CPA12024110101 CHARGE CODE: N/A NAME: 3T-603 NUMBER OF BOXES: 4 Boxes UPON RECEIPT OF THESE SAMPLES, PLEASE NOTE ANY DISCREPANCIES AND RETURN A SIGNED COPY OF THIS FORM TO: CONOCOPHILLIPS, ALASKA 700 G ST ATO-380 ANCHORAGE, AK. 99510 ATTN: MIKE McCRACKEN Mike.mccracken@conocophillips.com RECEIVED:� EAVE® 1`10V G 1 2024 AOGCC 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: ______________________ ConocoPhillips Alaska, Inc. 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 21228 feet feet true vertical 5163 feet feet Effective Depth measured 21223 feet 9141 / 9255 feet true vertical 5163 feet 4954 / 4991 feet Perforation depth Measured depth NA feet True Vertical depth NA feet Tubing (size, grade, measured and true vertical depth)4.5" 12.6# L80 9263.5' MD 4942' TVD Baker SLZXP 9255' MD 4991' TVD Packers and SSSV (type, measured and true vertical depth)HAL TNT 9141' MD 4954' 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: Torok Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Manabu Nozaki 11/5/2024 Contact Name:Manabu Nozaki Contact Email:Manabu.Nozaki@ConocoPhillips.com Authorized Title:Completions Engineer Contact Phone:907-265-6519 324-587 Sr Pet Eng: 9210 Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 9,738' MD to 21165.37' MD Size 119 52102955.6 7-5/8" 11590 7-5/8" 4790 7850 6890 10860 TBD N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-074 50-103-20887-00-00 P.O. Box 100360 Anchorage, AK 99510-03603. Address: Job logs attached 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025528 / ADL 393883 Kuparuk Field / Torok Oil Pool KRU 3T-603 Plugs Junk measured 4,487,559 lbs 16/20 WanLi Light weight ceramic proppant, 96,000 lbs of 100 Mesh, and 3600 psi avg treating pressure/4900 psi avg BHG pressure. Length 81.3 2916.9 119Conductor Surface Intermediate 20" 10-3/4" measured TVD Intermediate Liner 8378.7 1012.6 11968 Casing Structural 4675.2 5040.7 4-1/2" 8415.9 9428.5 21223 5163 2448.3 Burst Collapse 2470 p k ft t Fra O s O 224 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:06 am, Nov 06, 2024 Prepared By: William Martin Gregory Koester Nannook Crew Intervals 1-23 Moraine 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 users own risk. 3T-603 Conoco Phillips Harrison Bay County, AK Post Job Report Stimulation Treatment API: 50-103-20887 Prepared for: Manabu Nozaki November 2, 2024 A-Sand Formation 35# Hybor G 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 Interval 19 Plots Interval 20 Plots Interval 21 Plots Interval 22 Plots Interval 23 Plots Appendix Well Summary Chemical Summary Planned Design Water Straps 10.24 Water Straps 10.25 Water Straps 10.26 Water Straps 10.31 Water Straps 11.1 Water Straps 11.2 Water Analysis 10.23 Water Analysis 10.24 Water Analysis 10.25 Water Analysis 10.26 Water Analysis 11.1 Water Analysis 11.2 Real Time QC Event Log 10.23 Event Log 10.24 Event Log 10.25 Event Log 10.26 Event Log 10.31 Event Log 11.1 Event Log 11.2 Prejob Break Test Hybrid Prejob Break Test Hybor Fann 15 Min. 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 Zone 19 Zone 20 Zone 21 Sand Sieve Analysis 11 37 38 39 51 52 55 3 4 9 10 116 119 74 78 79 82 108 115 56 62 63 66 67 73 83 86 87 95 96 99 100 103 104 107 120 124 125 128 129 137 138 142 143 146 147 154 155 158 159 162 163 166 167 168 169 170 175 176 177 178 179 180 181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 218 219 213 214 215 216 217 Conoco Phillips 3T 603 TOC 2 1,491,829 gallons of 35# Hybor G 122,706 gallons of 35# Linear 2,940 gallons of Seawater 15,983 gallons of Freeze Protect 280,968 gallons of 30# Hybor G-i 23,194 gallons of 30# Linear 4,490,600 pounds of Wanli 16/20 Ceramic 85,857 pounds of 100M 1,597,831 gallons of 35# Hybor G 114,591 gallons of 35# Linear 1,439 gallons of Seawater 21,874 gallons of Freeze Protect 26,642 gallons of 30# Linear 4,487,559 pounds of Wanli 16/20 Ceramic 96,000 pounds of 100M Thank you, William Martin Senior Technical Professional Halliburton maintains a continuous quality improvement process and appreciates any comments or suggestions that you may have. Halliburton again thanks you for the opportunity to perform service work on this well. We hope to be your solutions provider for future projects. Engineering Executive Summary On October 23, 2024 a stimulation treatment was performed in the A-Sand formation on the 3T-603 well in Harrison Bay County, AK. The 3T-603 was a 23 stage Horizontal Sleeve Design. The proposed treatment consisted of: The actual treatment fully completed 22 of 23 stages. 0 stages were skipped, 0 stage screened out and 1 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 primary ball and back up ball for interval 22 were dropped without seeing a seat signature within a wellbore volume. The decision was made to skip interval 22 and drop ball 23. Shortly after dropping the ball for interval 23, ball 22 seated and the sleeve shifted. Ball 23 did not seat after a wellbore volume so the decision was made to start proppant. During 4 ppg proppant, after pumping 50,000 lbs in interval 22, the ball for interval 23 seated and shifted. Sand was cut and the back up ball for interval 23 was dropped to ensure fluid was entering through the sleeve for interval 23. The back up ball for interval 23 stacked in the sleeve, and interval 23 was pumped to completion. The sleeves for interval 6, 15, and 18 did not initially shift and kicked all pumps out. In each case the sleeves ended up shifting within an hour of holding pressure against them. Rate was dropped to 30bpm to launch the balls from the ball dropper as per CoP site representative request. 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. Pre-Job testing indicated that the water tank temperature needed to be at least 110F for lip times within 2/3 pipe time for the pure Hybor G system. 160 gal of MO-67 was diluted with a 1:1 ratio for the first day on pumping. 285 gal of the diluted MO were pumped downhole for intervals 1 through 4. The remainder of the well was pumped with raw MO. The initial 19 stages were pumped with a 35# Hybor G fluid and the final 4 intervals were pumped with a 30# Hybor G hybrid fluid with BC-140X2. Conoco Phillips 3T 603 Executive Summary 3 Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 1Moraine@ 21163.37 - 21167.71 ft 139.1 °FInterval 2Moraine@ 20679.73 - 20684.07 ft 139.3 °FInterval 3Moraine@ 20205.12 - 20209.46 ft 139.4 °FInterval 4Moraine@ 19727.34 - 19731.68 ft 139.5 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 6Moraine@ 18773.85 - 18778.19 ft 139.5 °FInterval 7Moraine@ 18297.55 - 18301.89 ft 139.3 °FInterval 8Moraine@ 17822.99 - 17827.33 ft 139 °FInterval 5Moraine@ 19251.26 - 19255.6 ft 139.6 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 9Moraine@ 17345.78 - 17350.12 ft 138.6 °FInterval 10Moraine@ 16868.38 - 16872.72 ft 138.8 °FInterval 11Moraine@ 16389.59 - 16393.93 ft 139.2 °FInterval 12Moraine@ 15912.53 - 15916.87 ft 139.4 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 15Moraine@ 13840.6 - 13844.94 ft 138.9 °FInterval 16Moraine@ 13322.69 - 13327.03 ft 138.9 °FInterval 13Moraine@ 15437.33 - 15441.67 ft 139.6 °FInterval 14Moraine@ 14360.98 - 14365.32 ft 139.1 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 18Moraine@ 12287.43 - 12291.77 ft 138.9 °FInterval 19Moraine@ 11766.81 - 11771.15 ft 139 °FInterval 17Moraine@ 12803.74 - 12808.08 ft 138.9 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 20Moraine@ 11248.16 - 11252.5 ft 139 °FInterval 21Moraine@ 10730.86 - 10735.2 ft 139 °FInterval 22Moraine@ 10212.92 - 10217.26 ft 138.8 °FInterval 23Moraine@ 9736.08 - 9740.42 ft 138.3 °F Conoco PhillipsMoraine3T6035010320887*Exceeds80% of burst pressure*Description OD (in) ID (in) Wt (#) GradeFUF(gal/ft)MD Top(ft)MD Btm (ft) Volume (gal)Tubular BurstPressure (psi)Tubing4.5 3.958 12.6 L80 0.6392 0 8,148 5,208 8,430Tubing4.5 3.958 12.6 L80 0.6392 8,148 22,000 8,854 8,430Total22,00014,062ft1.55ft139.6ftft1.55ft139.6ftTop MD(ft)Btm MD (ft)AverageTVD (ft)Interval # Formation DescriptorAverage IntervalTemperature (F)Ball Drop Time(HH:MM)Ball Hit Time(HH:MM)JSV Drop(bbl)JSV SlowDown (bbl)JSV Hit (bbl)Early (bbl)Surface SeatPressure (psi)Surface PeakPressure (psi)Surface Differential (psi)BH SeatPressure (psi)BH PeakPressure (psi)BHDifferential(psi)Rate at Shift(bpm)Toe21,163 21,168 5,1041Moraine139.120,680 20,6845,1172Moraine139.312:27:00 PM 12:40:00 PM 3,645 3,920 3,94019.72,825 6,090 3,265 4,489 7,586 3,097 13.420,205 20,209 5,1213Moraine139.41:58:00 PM 2:06:00 PM 6,534 6,802 6,81724.52,547 5,796 3,249 4,238 7,326 3,088 11.719,727 19,732 5,1314Moraine139.54:13:00 PM 4:23:00 PM 9,924 10,18410,20816.22,173 5,383 3,210 3,946 6,842 2,896 12.319,251 19,256 5,1345Moraine139.61:11:00 PM 1:26:00 PM 33 286 31313.22,125 5,319 3,194 3,548 6,398 2,850 12.218,77418,778 5,1286Moraine139.52:19:00 PM 2:27:00 PM 2,221 2,467 2,48818.72,524 7,577 5,053 4,153 9,543 5,390 12.518,298 18,302 5,1187Moraine139.34:46:00 PM 4:56:00 PM 4,843 5,081 5,10516.52,750 7,158 4,408 4,408 9,112 4,704 12.617,823 17,827 5,0948Moraine139.05:45:00 PM 5:53:00 PM 6,668 6,899 6,92019.22,197 4,603 2,406 3,869 6,150 2,281 12.417,346 17,350 5,0739Moraine138.611:53:00 AM 12:17:00 PM 26 250 27416.01,581 3,936 2,355 3,440 5,511 2,071 10.516,868 16,873 5,08610Moraine138.81:53:00 PM 2:01:00 PM 2,341 2,558 2,57918.72,795 5,527 2,732 4,416 6,866 2,450 12.716,390 16,3945,10811Moraine139.22:45:00 PM 2:52:00 PM 4,145 4,354 4,37915.43,276 5,550 2,274 4,583 6,926 2,343 17.615,913 15,917 5,12512Moraine139.43:36:00 PM 3:42:00 PM 5,938 6,140 6,15921.22,432 6,370 3,938 3,980 7,835 3,855 12.515,437 15,442 5,13713Moraine139.67:17:00 PM 7:32:00 PM 24 219 24910.41,340 3,032 1,692 2,890 4,595 1,705 12.514,361 14,365 5,10514Moraine139.18:42:00 PM 8:48:00 PM 2,593 2,772 2,79615.61,739 4,365 2,626 3,402 6,079 2,677 11.613,841 13,845 5,09415Moraine138.99:36:00 PM 9:43:00 PM 4,381 4,552 4,58110.62,680 7,567 4,887 3,924 9,189 5,265 12.113,323 13,327 5,09216Moraine138.912:05:00 AM 12:11:00 AM 6,909 7,072 7,10110.82,239 3,365 1,126 3,768 4,799 1,031 12.112,80412,808 5,08917Moraine138.94:00:00 PM 4:13:00 PM 27 182 21111.41,254 2,884 1,630 3,043 4,644 1,601 10.512,287 12,292 5,09118Moraine138.96:11:00 PM 6:17:00 PM 2,474 2,621 2,65011.02,338 7,499 5,161 3,757 9,356 5,599 12.611,767 11,771 5,09619Moraine139.07:54:00 PM 7:59:00 PM 4,667 4,806 4,82917.12,103 6,649 4,546 3,741 8,183 4,442 13.311,248 11,253 5,09820Moraine139.011:54:00 AM 12:31:00 PM 492 623 6567.21,774 5,524 3,750 3,110 6,974 3,864 12.710,731 10,735 5,09921Moraine139.01:22:00 PM 1:28:00 PM 2,460 2,583 2,6185.32,412 5,086 2,674 3,578 6,178 2,600 12.610,213 10,217 5,08422Moraine138.82:15:00 PM 2:51:00 PM 4,286 4,401 4,852410.62,281 6,868 4,587 3,345 7,969 4,624 16.7Heel9,736 9,740 5,05523Moraine138.32:48:00 PM 3:23:00 PM 4,808 4,916 5,694737.82,851 6,668 3,817 4,083 8,134 4,051 37.4202.8194.9187.0179.1171.2278.5271.2264.0256.7249.4242.2163.3155.4148.26,2238,1847,8547,5217,1906,8596,52810,1719,8689,1808,8478,51611,69611,39211,08710,78210,47612,915 307.512,61012,30512,000Displacement to TopSleeve/Perf (gal)(BBLS)13,528 322.113,218 314.7300.2293.0285.72223Interval #1Max Pressure (psi)8,500Isolation TypeSwell PackerTreatment TubularsCustomerFormationLeaseAPIDateTemperature DataTemp. Gradient(°F/100 ft)BHST(°F)Directional Data5,1032,23722,000Directional Data2,23710/23/2024KOPTemperature DataSleeve/Perf Depth Sleeves234.9218.6210.678910112345617181920211213141516Temp. Gradient(°F/100 ft)BHST(°F)TVD at Bottom PerfMD at Bottom Perf5,13721,168KOPAvg. TVDTotal MDConoco Phillips3T603 Wellbore Information 10 10/24/24 10:27 10/24/24 12:30 123 min -bpm -psi -psi -bbl 38.2 bpm 4,876 psi 6,304 psi 29.8 bpm 3,640 psi 3,617 psi 5,080 psi 2,660 hhp 560 psi 166 psi 744 psi 5.07 ppg 6 4 35 % 42 % 27 cP 118.6 F 9.1 DFIT 12.360 bpm 2590 psi 4029 psi 20.17 bpm 4114 psi 4988 psi 2881 psi 0.565 psi/ft 202,974 lbs 0 lbs 202,974 lbs 202,974 lbs 140,977 gal 3,357 bbls 3,077 gal 73 bbls 1,439 gal 34 bbls 4,200 gal 100 bbls Total Proppant Pumped* : Fluid Summary (by fluid description) Proppant Summary Minifrac Average Pressure: Minifrac Average DH Pressure: Freeze Protect Volume: Average Visc: Average Temp: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Rate: Max Surface Pressure: Max BH Pressure: Interval Summary 3T-603 - Moraine - Interval 1 Interval Summary Start Date/Time: End Date/Time: Average Surface Pressure: Average Rate: Max OA Pressure: Pumps Starting Stage: Pad Percentage Design Average Missile HHP: Initial BH Pressure (Breakdown): Average BH Pressure: Pumps Ending Stage: Max Proppant Concentration: Pump Time: ISDP: Final Fracture Gradient: Minifrac Max Surface Pressure: 100M Pumped: Proppant in Formation: 35# Hybor G Volume: 35# Linear Volume: Seawater Volume: Minifrac Max DH Pressure: Dart/Ball Early : Average pH: Minifrac Average Rate: Pad Percentage Actual Wanli 16/20 Ceramic Pumped: Diagnostic method Average Missile Pressure: Minifrac Max Rate: Open Well Pressure: Initial OA Pressure: Conoco Phillips 3T 603 Interval Summary 11 4,876 41,850 gal 996 bbls 16,116 gal 384 bbls 73,014 gal 1,738 bbls 1,591 gal 38 bbls 3,077 gal 73 bbls 8,406 gal 200 bbls 1,173 gal 28 bbls 266 gal 6 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep:Chad Burkett Willie Martin 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 Ball Drop Volume: Interval Status: Nathan Brzezinski Gregory Koester On October 23, the Arsenal Disk was burst at 9,397 psi BHG and then the Alpha Sleeve was shifted at 8,078 psi BHG. After shifting the Alpha Sleeve pressure was monitored for 20 min. A DFIT was pumped and an ISIP of 0.609 psi/ft before shutting down for the day to heat water up. While pumping in Pad, rate fluctuated due to pump issues, rate was dropped to 15bpm until the pumps were fixed. During 4 ppg 16/20 Another pump shut down due to mechanical issues but it was regained. 100 Mesh was not pumped due to the castle arm coming off the tracks. DFIT Volume: Arsenal Sleeve Shift Volume: Manabu Nozaki Conditioning Pad Volume: Proppant Laden Fluid Volume: Pad Volume: Conoco Phillips 3T 603 Interval Summary 12 10/24/24 12:30 10/24/24 13:58 88 min 13.4 bpm 6,090 psi 7,586 psi 20 bbl 37.6 bpm 4,976 psi 6,323 psi 33.5 bpm 4,228 psi 4,217 psi 5,614 psi 3,474 hhp 703 psi 725 psi 6.05 ppg 4 4 35 % 36 % 28 cP 115.2 F 8.8 203,545 lbs 0 lbs 203,545 lbs 203,545 lbs 112,244 gal 2,672 bbls 26,826 gal 639 bbls 15,964 gal 380 bbls 67,736 gal 1,613 bbls 1,718 gal 41 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: During Interval 02, 100 Mesh gate was still not fixed and the 0.25 ppg stage was pumped with 16/20. During the job, rate was fluctuating due to pump issues. A minifrac was initially planned for interval 02 but it was moved to interval 03 due to fluctuating rate. *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.Chad Burkett Willie Martin Nathan Brzezinski Gregory Koester Manabu Nozaki Wanli 16/20 Ceramic Pumped: 100M Pumped: Total Proppant Pumped* : 35# Hybor G Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Spacer and Ball Drop Volume: Proppant Summary Interval Summary Start Date/Time: End Date/Time: Pump Time: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Average Surface Pressure: 3T-603 - Moraine - Interval 2 Average BH Pressure: Average Missile HHP: Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: Pumps Starting Stage: Pumps Ending Stage: Average Visc: Average Temp: Average pH: Pad Percentage Design Pad Percentage Actual Proppant in Formation: Fluid Summary (by fluid description) Fluid Summary (by stage description) Pad Volume: Conoco Phillips 3T 603 Interval Summary 13 4,976 6,090 10/24/24 13:58 10/24/24 16:13 135 min 11.7 bpm 5,796 psi 7,326 psi 25 bbl 37.2 bpm 4,749 psi 6,260 psi 34.7 bpm 4,178 psi 4,123 psi 5,536 psi 3,552 hhp 677 psi 743 psi 7.15 ppg 4 4 35 % 43 % 29 cP 118.1 F 8.8 MiniFrac 33.260 bpm 3865 psi 5131 psi 37.13 bpm 4335 psi 5391 psi 3074 psi 0.600 psi/ft 3015 psi 2988 psi 2966 psi 199,179 lbs 4,120 lbs 203,299 lbs 203,299 lbs Total Proppant Pumped* : Proppant in Formation: 3T-603 - Moraine - 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): Initial Surface Pressure (Breakdown): Start Date/Time: Pad Percentage Design Pad Percentage Actual Final Fracture Gradient: Minifrac Average DH Pressure: Average Visc: Initial OA Pressure: Diagnostic method Minifrac Max DH Pressure: ISDP: Minifrac Max Rate: Average Missile HHP: Average Temp: Average Missile Pressure: Average Surface Pressure: Average BH Pressure: Pumps Starting Stage: Pumps Ending Stage: Average pH: Minifrac Average Rate: Minifrac Average Pressure: Final 5 min: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Minifrac Max Surface Pressure: Interval Summary Wanli 16/20 Ceramic Pumped: Proppant Summary Final 10 min: Final 15 min: Conoco Phillips 3T 603 Interval Summary 14 125,120 gal 2,979 bbls 13,237 gal 315 bbls 23,538 gal 560 bbls 16,855 gal 401 bbls 45,555 gal 1,085 bbls 4,268 gal 102 bbls 13,237 gal 315 bbls 21,667 gal 516 bbls 13,237 gal 315 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Establish Stable Fluid Volume: 35# Hybor G Volume: Willie Martin Nathan Brzezinski Gregory Koester Interval Status: While preparing to drop the ball, the blender lost prime. rate was decreased so the blender could regain prime, the well was overflushed 22 bbl. The Stage was pumped to completion. *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Fluid Summary (by fluid description) Proppant Laden Fluid Volume: Manabu Nozaki Chad Burkett Minifrac - Treatment Volume: Minifrac - Flush Volume: Fluid Summary (by stage description) Conditioning Pad Volume: 35# Linear Volume: Pad Volume: Spacer and Ball Drop Volume: Conoco Phillips 3T 603 Interval Summary 15 10/24/24 16:13 10/24/24 17:19 66 min 12.3 bpm 5,383 psi 6,842 psi 16 bbl 37.4 bpm 5,152 psi 6,354 psi 35.6 bpm 4,049 psi 3,980 psi 5,412 psi 3,531 hhp 636 psi 672 psi 7.38 ppg 4 4 34 % 34 % 27 cP 108 F 8.8 3215 psi 0.627 psi/ft 3138 psi 3105 psi 3076 psi 200,841 lbs 3,447 lbs 204,288 lbs 204,288 lbs 71,127 gal 1,694 bbls 13,826 gal 329 bbls 1,273 gal 30 bbls 12,528 gal 298 bbls 14,447 gal 344 bbls 44,152 gal 1,051 bbls 13,826 gal 329 bbls 1,273 gal 30 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Manabu Nozaki Chad Burkett Willie Martin Nathan Brzezinski During the 7.0 ppg sand stage, a pump was neutralled due to a mechanical issue. During flush, rate was dropped to regain prime in the ADP. The interval was pumped to completion. Gregory Koester Pad Volume: Conditioning Pad Volume: Freeze Protect Volume: Proppant Laden Fluid Volume: Fluid Summary (by stage description) Interval Status: Max BH Pressure: Proppant Summary Wanli 16/20 Ceramic Pumped: Total Proppant Pumped* : Pad Percentage Design Average Surface Pressure: Pumps Starting Stage: Final Fracture Gradient: Final 5 min: 100M Pumped: ISDP: Max OA Pressure: Max Proppant Concentration: Average Visc: Final 10 min: Final 15 min: Average Temp: Average pH: Initial OA Pressure: Initial Surface Pressure (Breakdown): End Date/Time: Pump Time: 3T-603 - Moraine - Interval 4 Interval Summary Start Date/Time: Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Flush Volume: Average Rate: Average Missile Pressure: Average BH Pressure: Average Missile HHP: Pumps Ending Stage: Pad Percentage Actual 35# Linear 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: Freeze Protect Volume: Fluid Summary (by fluid description) 35# Hybor G Volume: Conoco Phillips 3T 603 Interval Summary 16 5,152 10/25/24 13:07 10/25/24 14:19 72 min 12.2 bpm 5,319 psi 6,398 psi 13 bbl 37.7 bpm 5,159 psi 6,390 psi 35.8 bpm 4,243 psi 4,177 psi 5,520 psi 3,724 hhp 457 psi 232 psi 724 psi 7.29 ppg 6 6 33 % 33 % 34 cP 108.8 F 9.2 197,574 lbs 4,447 lbs 202,021 lbs 202,021 lbs 82,557 gal 1,966 bbls 1,673 gal 40 bbls 1,273 gal 30 bbls 8,856 gal 211 bbls 16,624 gal 396 bbls 44,102 gal 1,050 bbls 3,143 gal 75 bbls 11,505 gal 274 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: End Date/Time: Max BH Pressure: Average Surface Pressure: Interval Summary Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Wanli 16/20 Ceramic Pumped: Conditioning Pad Volume: Freeze Protect Volume: 35# Linear Volume: 100M Pumped: 3T-603 - Moraine - Interval 5 Average BH Pressure: Initial OA Pressure: Max Proppant Concentration: Start Date/Time: Pad Percentage Design Average Rate: Proppant in Formation: Pad Volume: Willie Martin Average Missile HHP: Open Well Pressure: Average Visc: Max Surface 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. Average pH: Pad Percentage Actual Manabu Nozaki Chad Burkett Gregory Koester Spacer and Ball Drop Volume: Pump Time: Nathan Brzezinski Interval 5 was pumped as per design. Pumps Starting Stage: Pumps Ending Stage: Average Missile Pressure: Max OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Temp: Initial Surface Pressure (Breakdown): Max Rate: Establish Stable Fluid Volume: 35# Hybor G Volume: Total Proppant Pumped* : Initial Rate (Breakdown): Proppant Laden Fluid Volume: Interval Status: Conoco Phillips 3T 603 Interval Summary 17 10/25/24 14:19 10/25/24 16:46 147 min 12.5 bpm 7,577 psi 9,543 psi 19 bbl 37.3 bpm 6,575 psi 6,209 psi 27.8 bpm 4,069 psi 4,029 psi 35,266 psi 2,769 hhp 724 psi 77 psi 7.08 ppg 6 6 41 % 39 % 34 cP 112.4 F 9.2 3147 psi 0.614 psi/ft 199,039 lbs 4,926 lbs 203,965 lbs 203,965 lbs 85,258 gal 2,030 bbls 15,486 gal 369 bbls 17,203 gal 410 bbls 16,125 gal 384 bbls 44,198 gal 1,052 bbls 15,486 gal 369 bbls 1,428 gal 34 bbls 6,304 gal 150 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pump Time: Initial Rate (Breakdown): Average Missile HHP: 3T-603 - Moraine - Interval 6 Interval Summary Average pH: Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Establish Stable Fluid Volume: Displacement Volume: Pumps Starting Stage: Max Rate: Average Missile Pressure: ISDP: Average Rate: Proppant in Formation: Average Visc: Average Surface Pressure: Average BH Pressure: 100M Pumped: Pumps Ending Stage: Conditioning Pad Volume: Interval Status: 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 : While seating the ball for interval 6, the sleeve did not shift. Pressure was bled off on surface and pressured up again. After shutting the well, the sleeve shifted. The well was flushed with gel and a shut down was called to get ISIP. Pad and 100Mesh were re pumped and the stage was pumped to completion. Willie Martin Nathan Brzezinski Gregory Koester *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. Manabu Nozaki Chad Burkett Proppant Laden Fluid Volume: End Date/Time: Max Surface Pressure: Max BH Pressure: Max OA Pressure: Spacer and Ball Drop Volume: Max Proppant Concentration: Pad Percentage Actual Initial OA Pressure: Start Date/Time: 35# Hybor G Volume: 35# Linear Volume: Conoco Phillips 3T 603 Interval Summary 18 7,577 6,575 10/25/24 16:46 10/25/24 17:45 59 min 12.6 bpm 7,158 psi 9,112 psi 16 bbl 37.3 bpm 6,694 psi 8,241 psi 32.9 bpm 4,436 psi 4,386 psi 5,847 psi 3,578 hhp 730 psi 757 psi 7.13 ppg 6 6 31 % 30 % 30 cP 116.1 F 9.1 198,359 lbs 4,180 lbs 202,539 lbs 202,539 lbs 67,854 gal 1,616 bbls 6,944 gal 165 bbls 15,212 gal 362 bbls 44,267 gal 1,054 bbls 1,431 gal 34 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: During 7.0 ppg 16/20, sand concentration dropped due to having to bin swap on the besser. The stage was pumped to completion. Fluid Summary (by fluid description) Manabu Nozaki Spacer and Ball Drop Volume: 35# Hybor G Volume: Chad Burkett Willie Martin Gregory Koester Fluid Summary (by stage description) Nathan Brzezinski Interval Summary Pump Time: Max Rate: Initial BH Pressure (Breakdown): Start Date/Time: Pumps Ending Stage: Pad Volume: 100M Pumped: Average pH: Max Proppant Concentration: Dart/Ball Early : Pad Percentage Actual Initial OA Pressure: Pad Percentage Design Pumps Starting Stage: Proppant Summary Proppant in Formation: Proppant Laden Fluid Volume: Average Visc: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max OA Pressure: Total Proppant Pumped* : *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Average BH Pressure: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Average Temp: Average Missile HHP: 3T-603 - Moraine - Interval 7 End Date/Time: Conditioning Pad Volume: Conoco Phillips 3T 603 Interval Summary 19 7,158 6,694 10/25/24 17:45 10/25/24 18:45 60 min 12.4 bpm 4,603 psi 6,150 psi 19 bbl 37.3 bpm 4,428 psi 5,609 psi 35.7 bpm 3,913 psi 3,842 psi 5,257 psi 3,425 hhp 707 psi 744 psi 7.15 ppg 5 5 30 % 30 % 30 cP 116.5 F 9.1 3166 psi 0.622 psi/ft 3088 psi 3017 psi 2973 psi 201,806 lbs 3,906 lbs 205,712 lbs 205,712 lbs 66,429 gal 1,582 bbls 12,637 gal 301 bbls 1,273 gal 30 bbls 5,882 gal 140 bbls 16,514 gal 393 bbls 44,033 gal 1,048 bbls 12,637 gal 301 bbls 1,273 gal 30 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Willie Martin Chad Burkett Nathan Brzezinski Gregory Koester Manabu Nozaki 35# Hybor G Volume: Interval Status: Interval 08 was pumped as per design. Proppant Laden Fluid Volume: Wanli 16/20 Ceramic Pumped: 100M Pumped: Proppant Summary Freeze Protect Volume: Interval Summary 3T-603 - Moraine - Interval 8 Fluid Summary (by fluid description) Pad Volume: Average Visc: Total Proppant Pumped* : 35# Linear Volume: Final 5 min: Final Fracture Gradient: Final 15 min: Conditioning Pad Volume: Average Missile HHP: Fluid Summary (by stage description) Pad Percentage Actual Pad Percentage Design Initial Surface Pressure (Breakdown): Start Date/Time: Initial BH Pressure (Breakdown): Average pH: Average Surface Pressure: Max Rate: Pumps Starting Stage: ISDP: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Proppant in Formation: Final 10 min: Average Temp: Average Missile Pressure: Initial Rate (Breakdown): Max Surface Pressure: Pumps Ending Stage: Average Rate: Max Proppant Concentration: Average BH Pressure: Max OA Pressure: Initial OA Pressure: Max BH Pressure: Dart/Ball Early : End Date/Time: Pump Time: Freeze Protect Volume: Flush Volume: Conoco Phillips 3T 603 Interval Summary 20 10/26/24 11:50 10/26/24 13:53 123 min 10.5 bpm 3,936 psi 5,511 psi 16 bbl 38.0 bpm 4,682 psi 5,858 psi 32.8 bpm 3,913 psi 3,821 psi 5,245 psi 3,141 hhp 376 psi 172 psi 726 psi 7.45 ppg 6 6 30 % 29 % 28 cP 121 F 9.4 DFIT 10.480 bpm 2126 psi 3916 psi 10.49 bpm 2228 psi 4020 psi 3086 psi 0.608 psi/ft 204,330 lbs 4,342 lbs 208,672 lbs 208,672 lbs Start Date/Time: End Date/Time: Pump Time: Average Temp: Max Proppant Concentration: Pumps Starting Stage: Average Surface Pressure: Minifrac Average Pressure: 3T-603 - Moraine - Interval 9 Minifrac Max Rate: Minifrac Max Surface Pressure: Minifrac Average Rate: Initial BH Pressure (Breakdown): Diagnostic method Average pH: Minifrac Average DH Pressure: Total Proppant Pumped* : Max Surface Pressure: Max BH Pressure: Initial Rate (Breakdown): Max Rate: Pumps Ending Stage: Initial Surface Pressure (Breakdown): ISDP: Proppant Summary Wanli 16/20 Ceramic Pumped: Average Missile Pressure: Interval Summary Open Well Pressure: Minifrac Max DH Pressure: Dart/Ball Early : Average Visc: Pad Percentage Design Max OA Pressure: Proppant in Formation: Initial OA Pressure: Average Rate: Final Fracture Gradient: 100M Pumped: Pad Percentage Actual Average Missile HHP: Average BH Pressure: Conoco Phillips 3T 603 Interval Summary 21 76,255 gal 1,816 bbls 12,796 gal 305 bbls 1,470 gal 35 bbls 10,188 gal 243 bbls 5,602 gal 133 bbls 15,959 gal 380 bbls 45,161 gal 1,075 bbls 2,961 gal 71 bbls 7,577 gal 180 bbls 1,603 gal 38 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: *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. Willie Martin Nathan Brzezinski Manabu Nozaki Chad Burkett Establish Stable Fluid Volume: Spacer and Ball Drop Volume: 35# Hybor G Volume: 35# Linear Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Freeze Protect Volume: Fluid Summary (by stage description) Fluid Summary (by fluid description) Interval Status: Displace Ball to Seat Volume: Pad Volume: Gregory Koester DFIT Volume: A DFIT was pumped after seating the ball for interval 09. Closure was found to be 2,740 psi. Early in interval 09 rate was fluctuating due to a pump mechanical issue. The stage was pumped to completion. Conoco Phillips 3T 603 Interval Summary 22 10/26/24 13:53 10/26/24 14:45 52 min 12.7 bpm 5,527 psi 6,866 psi 19 bbl 37.2 bpm 6,003 psi 7,364 psi 35.3 bpm 4,329 psi 4,275 psi 5,652 psi 3,750 hhp 727 psi 755 psi 7.15 ppg 5 5 30 % 28 % 29 cP 121 F 9.4 199,724 lbs 3,974 lbs 203,698 lbs 203,698 lbs 66,640 gal 1,587 bbls 5,643 gal 134 bbls 14,514 gal 346 bbls 44,604 gal 1,062 bbls 1,879 gal 45 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Nathan Brzezinski Gregory Koester *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. Manabu Nozaki Chad Burkett Initial BH Pressure (Breakdown): Pad Percentage Actual Pumps Starting Stage: Dart/Ball Early : 35# Hybor G Volume: Average Visc: Pad Percentage Design Max OA Pressure: Average pH: Average BH Pressure: Average Surface Pressure: Interval Summary Pump Time: Start Date/Time: 3T-603 - Moraine - Interval 10 End Date/Time: Interval 10 was pumped as per design. Average Missile HHP: Wanli 16/20 Ceramic Pumped: Initial OA Pressure: Max Proppant Concentration: Proppant Laden Fluid Volume: 100M Pumped: Pad Volume: Conditioning Pad Volume: Average Temp: Initial Surface Pressure (Breakdown): Proppant Summary Average Missile Pressure: Average Rate: Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) Max Surface Pressure: Max BH Pressure: Pumps Ending Stage: Max Rate: Initial Rate (Breakdown): Interval Status: Spacer and Ball Drop Volume: Fluid Summary (by stage description) Willie Martin Conoco Phillips 3T 603 Interval Summary 23 10/26/24 14:45 10/26/24 15:36 51 min 17.6 bpm 5,550 psi 6,926 psi 15 bbl 37.2 bpm 5,901 psi 7,013 psi 36.1 bpm 4,030 psi 3,980 psi 5,318 psi 3,564 hhp 715 psi 745 psi 7.22 ppg 5 5 30 % 29 % 30 cP 118 F 9.3 199,300 lbs 3,952 lbs 203,252 lbs 203,252 lbs 66,172 gal 1,576 bbls 6,094 gal 145 bbls 14,924 gal 355 bbls 43,503 gal 1,036 bbls 1,651 gal 39 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Fluid Summary (by stage description) Pad Volume: Interval 11 was pumped to completion. Manabu Nozaki Chad Burkett Nathan Brzezinski Gregory Koester *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Pad Percentage Design Average Surface Pressure: Max OA Pressure: Max BH Pressure: Average Rate: Average BH Pressure: Interval Summary Proppant Summary Fluid Summary (by fluid description) Total Proppant Pumped* : Proppant in Formation: Pumps Ending Stage: Pump Time: Initial BH Pressure (Breakdown): Dart/Ball Early : 35# Hybor G Volume: 3T-603 - Moraine - 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: Willie Martin Pumps Starting Stage: 100M Pumped: Conditioning Pad Volume: Proppant Laden Fluid Volume: Start Date/Time: Interval Status: Average Missile HHP: Initial Rate (Breakdown): Average Missile Pressure: Initial Surface Pressure (Breakdown): Max Surface Pressure: Spacer and Ball Drop Volume: Conoco Phillips 3T 603 Interval Summary 24 10/26/24 15:36 10/26/24 16:35 59 min 12.5 bpm 6,370 psi 7,835 psi 21 bbl 37.9 bpm 6,126 psi 7,328 psi 35.4 bpm 4,018 psi 3,977 psi 5,311 psi 3,483 hhp 697 psi 749 psi 7.10 ppg 5 5 30 % 29 % 28 cP 116 F 9.3 3166 psi 0.618 psi/ft 3046 psi 2964 psi 2959 psi 200,145 lbs 3,898 lbs 204,043 lbs 204,043 lbs 65,580 gal 1,561 bbls 11,405 gal 272 bbls 588 gal 14 bbls 5,802 gal 138 bbls 16,004 gal 381 bbls 43,774 gal 1,042 bbls 11,405 gal 272 bbls 588 gal 14 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pumps Starting Stage: Max Proppant Concentration: Pump Time: 3T-603 - Moraine - Interval 12 Interval Summary Initial BH Pressure (Breakdown): Average Missile HHP: Initial Surface Pressure (Breakdown): Max OA Pressure: Average pH: Max Rate: Initial OA Pressure: End Date/Time: Dart/Ball Early : Max BH Pressure: Average Visc: Nathan Brzezinski Chad Burkett Average Surface Pressure: Freeze Protect Volume: Start Date/Time: Average Rate: Average Missile Pressure: Final Fracture Gradient: Pad Percentage Actual Initial Rate (Breakdown): Average BH Pressure: Interval 12 was pumped to completion. Willie Martin Proppant Summary Fluid Summary (by fluid description) 35# Hybor G Volume: Fluid Summary (by stage description) 100M Pumped: 35# Linear Volume: Freeze Protect Volume: Max Surface Pressure: ISDP: Interval Status: Pad Volume: Flush Volume: Conditioning Pad Volume: Gregory Koester *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. Manabu Nozaki Final 15 min: Final 5 min: Total Proppant Pumped* : Final 10 min: Wanli 16/20 Ceramic Pumped: Pumps Ending Stage: Pad Percentage Design Proppant in Formation: Proppant Laden Fluid Volume: Average Temp: Conoco Phillips 3T 603 Interval Summary 25 10/31/24 19:13 10/31/24 20:42 89 min 12.5 bpm 3,032 psi 4,595 psi 10 bbl 37.6 bpm 3,853 psi 5,009 psi 33.8 bpm 3,952 psi 3,161 psi 4,448 psi 3,259 hhp 640 psi 52 psi 634 psi 7.10 ppg 5 5 28 % 23 % 29 cP 103.6 F 9.4 201,773 lbs 4,483 lbs 206,256 lbs 206,256 lbs 98,289 gal 2,340 bbls 1,443 gal 34 bbls 1,273 gal 30 bbls 6,091 gal 145 bbls 16,535 gal 394 bbls 68,720 gal 1,636 bbls 2,628 gal 63 bbls 5,758 gal 137 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant Laden Fluid Volume: Fluid Summary (by stage description) During 6.0 ppg 16/20, the blender lost suction so rate was dropped and the sand screws were cut. Once suction pressure was re-established, XL was turned back on and sand stepped up from 1 ppg to 7 ppg. Willie Martin Nathan Brzezinski Gregory Koester Fluid Summary (by fluid description) 35# Linear Volume: Manabu Nozaki Dan Faur Interval Summary End Date/Time: Average Missile HHP: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Pad Percentage Design Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Surface Pressure: Max Proppant Concentration: Conditioning Pad Volume: Spacer and Ball Drop Volume: Pad Percentage Actual Total Proppant Pumped* : Average Visc: Initial OA Pressure: Average Surface Pressure: Initial BH Pressure (Breakdown): Average Missile Pressure: Pump Time: 3T-603 - Moraine - Interval 13 Max BH Pressure: Pumps Ending Stage: Open Well Pressure: Pumps Starting Stage: Average Rate: Proppant Summary Dart/Ball Early : Freeze Protect Volume: Max OA Pressure: Average pH: Average Temp: Pad Volume: Start Date/Time: Max Rate: Wanli 16/20 Ceramic Pumped: Average BH Pressure: 100M Pumped: Proppant in Formation: 35# Hybor G Volume: Establish Stable Fluid Volume: Interval Status: Conoco Phillips 3T 603 Interval Summary 26 10/31/24 20:42 10/31/24 21:36 54 min 11.6 bpm 4,365 psi 6,079 psi 16 bbl 36.3 bpm 4,903 psi 6,171 psi 32.9 bpm 3,383 psi 3,413 psi 4,726 psi 2,730 hhp 633 psi 696 psi 7.20 ppg 4 4 30 % 29 % 26 cP 101.3 F 9.3 200,031 lbs 3,944 lbs 203,975 lbs 203,975 lbs 65,966 gal 1,571 bbls 5,634 gal 134 bbls 15,362 gal 366 bbls 43,261 gal 1,030 bbls 1,709 gal 41 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Conditioning Pad Volume: The average rate while pumping the stage was 35 bpm due to lack of hp. Interval 14 was pumped to completion. Fluid Summary (by stage description) Nathan Brzezinski Gregory Koester *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 Surface Pressure (Breakdown): Total Proppant Pumped* : Proppant Laden Fluid Volume: Pad Volume: Proppant in Formation: Fluid Summary (by fluid description) 35# Hybor G Volume: Spacer and Ball Drop Volume: Interval Summary Start Date/Time: 3T-603 - Moraine - Interval 14 Willie Martin Manabu Nozaki Dan Faur Max Rate: Max BH Pressure: Wanli 16/20 Ceramic Pumped: Pump Time: Average pH: End Date/Time: Average Temp: Dart/Ball Early : Max Surface Pressure: Average Missile HHP: Pumps Starting Stage: Average BH Pressure: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Initial Rate (Breakdown): Average Visc: Initial OA Pressure: Proppant Summary Pad Percentage Actual Interval Status: Initial BH Pressure (Breakdown): Average Surface Pressure: Pad Percentage Design Average Rate: Average Missile Pressure: Pumps Ending Stage: Conoco Phillips 3T 603 Interval Summary 27 10/31/24 21:36 11/1/24 0:05 149 min 12.1 bpm 7,567 psi 9,189 psi 11 bbl 35.5 bpm 3,333 psi 4,600 psi 31.9 bpm 2,834 psi 2,797 psi 4,201 psi 2,217 hhp 672 psi 720 psi 7.46 ppg 4 4 41 % 31 % 28 cP 108.6 F 9.3 200,005 lbs 3,459 lbs 203,464 lbs 203,464 lbs 97,068 gal 2,311 bbls 5,708 gal 136 bbls 23,059 gal 549 bbls 55,447 gal 1,320 bbls 1,919 gal 46 bbls 10,935 gal 260 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: While seating the ball for interval 15, the sleeve did not initially shift. After pressuring up on the well for 40 minutes the sleeve shifted. During 6 ppg the ADP lost suction, rate had to be dropped and sand screws cut until the blender could regain prime. Max sand Conc was 6.5 ppg. Dart/Ball Early : 3T-603 - Moraine - 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 Rate (Breakdown): Average Missile HHP: Initial BH Pressure (Breakdown): Average BH Pressure: Pump Time: Fluid Summary (by fluid description) Interval Status: Nathan Brzezinski Gregory Koester Pad Volume: Conditioning Pad Volume: Max Surface Pressure: Fluid Summary (by stage description) Willie Martin Spacer and Ball Drop Volume: Average Surface Pressure: Average Visc: Average pH: Wanli 16/20 Ceramic Pumped: Proppant Summary Total Proppant Pumped* : Proppant in Formation: Average Temp: Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: 100M Pumped: Proppant Laden Fluid Volume: Pumps Starting Stage: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Establish Stable Fluid Volume: Manabu Nozaki Dan Faur Start Date/Time: 35# Hybor G Volume: Average Rate: Conoco Phillips 3T 603 Interval Summary 28 11/1/24 0:05 11/1/24 1:08 63 min 12.1 bpm 3,365 psi 4,799 psi 11 bbl 33.1 bpm 3,505 psi 4,866 psi 32.2 bpm 2,866 psi 2,852 psi 4,249 psi 2,259 hhp 711 psi 743 psi 7.17 ppg 4 4 30 % 29 % 28 cP 111.3 F 9.3 3088 psi 0.606 psi/ft 3048 psi 3015 psi 2983 psi 200,818 lbs 3,912 lbs 204,730 lbs 204,730 lbs 64,670 gal 1,540 bbls 9,720 gal 231 bbls 1,273 gal 30 bbls 5,608 gal 134 bbls 15,389 gal 366 bbls 43,673 gal 1,040 bbls 9,720 gal 231 bbls 1,273 gal 30 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Willie Martin Nathan Brzezinski Gregory Koester *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. Manabu Nozaki Dan Faur Max Proppant Concentration: Pad Percentage Design Average Visc: Pump Time: Final 10 min: Average Surface Pressure: Average Temp: Proppant in Formation: Average pH: Pumps Starting Stage: Start Date/Time: Average BH Pressure: Average Rate: End Date/Time: Max BH Pressure: Fluid Summary (by fluid description) Interval Summary Pad Percentage Actual Initial OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Missile HHP: Max OA Pressure: Conditioning Pad Volume: Proppant Laden Fluid Volume: ISDP: Pumps Ending Stage: Max Surface Pressure: Pad Volume: Freeze Protect Volume: Wanli 16/20 Ceramic Pumped: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Flush Volume: Freeze Protect Volume: 100M Pumped: 35# Hybor G Volume: 35# Linear Volume: Final 15 min: Average Missile Pressure: Final 5 min: Proppant Summary Max Rate: 3T-603 - Moraine - Interval 16 Final Fracture Gradient: Interval Status: Interval 16 was pumped at 33 bpm due to horsepower limitations. The Interval was pumped to completion. Fluid Summary (by stage description) Total Proppant Pumped* : Conoco Phillips 3T 603 Interval Summary 29 11/1/24 15:57 11/1/24 18:11 134 min 10.5 bpm 2,884 psi 4,644 psi 11 bbl 37.2 bpm 3,398 psi 4,380 psi 32.6 bpm 2,888 psi 2,879 psi 4,194 psi 2,306 hhp 434 psi 109 psi 717 psi 7.35 ppg 6 6 30 % 26 % 26 cP 111.6 F 9.3 DFIT 10.470 bpm 2013 psi 3771 psi 10.52 bpm 2195 psi 3976 psi 3167 psi 0.622 psi/ft 2750 psi 2518 psi 2375 psi 3T-603 - Moraine - Interval 17 Interval Summary Average pH: ISDP: Final Fracture Gradient: Average Rate: Final 5 min: Average Missile Pressure: Open Well Pressure: Diagnostic method Initial Rate (Breakdown): Dart/Ball Early : Minifrac Average DH Pressure: Final 10 min: Minifrac Average Rate: Minifrac Average Pressure: Minifrac Max Rate: Minifrac Max Surface Pressure: Minifrac Max DH Pressure: End Date/Time: Max Proppant Concentration: Average BH Pressure: Start Date/Time: Pumps Ending Stage: Pad Percentage Design Pad Percentage Actual Final 15 min: Max Surface Pressure: Initial BH Pressure (Breakdown): 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: Conoco Phillips 3T 603 Interval Summary 30 199,928 lbs 4,760 lbs 204,688 lbs 204,688 lbs 83,864 gal 1,997 bbls 10,520 gal 250 bbls 3,360 gal 80 bbls 7,885 gal 188 bbls 5,521 gal 131 bbls 12,840 gal 306 bbls 43,513 gal 1,036 bbls 2,679 gal 64 bbls 20,340 gal 484 bbls 1,606 gal 38 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant Summary Displace Ball to Seat Volume: Pad Volume: Proppant in Formation: Wanli 16/20 Ceramic Pumped: 35# Hybor G 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. Freeze Protect Volume: 35# Linear Volume: Dan Faur 100M Pumped: Spacer and Ball Drop Volume: Total Proppant Pumped* : Conditioning Pad Volume: Proppant Laden Fluid Volume: Fluid Summary (by fluid description) Establish Stable Fluid Volume: Fluid Summary (by stage description) While establishing stable fluid, the MO-67 LA pump and the CL-28 LA pump had issues maintaining steady rate. Pumps were shut down to troubleshoot the LA's for 15 minutes. The interval was resumed and pumped to completion. Willie Martin Nathan Brzezinski Gregory Koester DFIT Volume: Interval Status: Conoco Phillips 3T 603 Interval Summary 31 11/1/24 18:11 11/1/24 19:54 103 min 12.6 bpm 7,499 psi 9,356 psi 11 bbl 37.2 bpm 3,168 psi 4,453 psi 35.8 bpm 2,899 psi 2,833 psi 4,170 psi 2,545 hhp 702 psi 717 psi 7.20 ppg 6 6 37 % 36 % 28 cP 108.7 F 9.3 200,268 lbs 3,257 lbs 203,525 lbs 203,525 lbs 83,144 gal 1,980 bbls 11,826 gal 282 bbls 18,097 gal 431 bbls 44,153 gal 1,051 bbls 2,071 gal 49 bbls 6,997 gal 167 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Willie Martin Proppant Summary 100M Pumped: Nathan Brzezinski While seating the ball for interval 18, the sleeve did not shift. The well was bled off on surface and then repressurized. After 30 minutes the sleeve shifted and interval 18 was pumped to completion. Gregory Koester Dan Faur Interval Summary Average Temp: Average pH: Average BH Pressure: Pumps Starting Stage: Pumps Ending Stage: Start Date/Time: Average Surface Pressure: Dart/Ball Early : Initial BH Pressure (Breakdown): Pad Percentage Design Max Proppant Concentration: Pad Percentage Actual Average Missile Pressure: Max Rate: Average Missile HHP: Max BH Pressure: Initial Surface Pressure (Breakdown): 3T-603 - Moraine - Interval 18 Pump Time: Interval Status: Initial Rate (Breakdown): Average Rate: Conditioning Pad Volume: Spacer and Ball Drop Volume: End Date/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. Pad Volume: Initial OA Pressure: Max OA Pressure: Max Surface Pressure: Wanli 16/20 Ceramic Pumped: Establish Stable Fluid Volume: Proppant Laden Fluid Volume: Total Proppant Pumped* : Proppant in Formation: 35# Hybor G Volume: Average Visc: Fluid Summary (by stage description) Fluid Summary (by fluid description) Conoco Phillips 3T 603 Interval Summary 32 7,499 11/1/24 19:54 11/1/24 21:09 75 min 13.3 bpm 6,649 psi 8,183 psi 17 bbl 37.1 bpm 5,685 psi 7,003 psi 35.0 bpm 2,751 psi 2,648 psi 3,991 psi 2,363 hhp 705 psi 740 psi 7.22 ppg 6 5 28 % 28 % 28 cP 111.6 F 9.3 3191 psi 0.626 psi/ft 3113 psi 3080 psi 3055 psi 200,587 lbs 3,624 lbs 204,211 lbs 204,211 lbs 78,617 gal 1,872 bbls 8,771 gal 209 bbls 2,520 gal 60 bbls 5,839 gal 139 bbls 14,994 gal 357 bbls 45,408 gal 1,081 bbls 8,771 gal 209 bbls 2,520 gal 60 bbls 12,376 gal 295 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Final Fracture Gradient: Final 5 min: ISDP: Establish Stable Fluid Volume: Dan Faur Average Temp: Final 10 min: Final 15 min: Average Missile Pressure: Average pH: Average BH Pressure: Total Proppant Pumped* : 35# Linear Volume: Proppant Laden Fluid Volume: Fluid Summary (by stage description) 35# Hybor G Volume: Gregory Koester Fluid Summary (by fluid description) Freeze Protect Volume: Pad Volume: Wanli 16/20 Ceramic Pumped: Freeze Protect Volume: Interval Summary Average Visc: Start Date/Time: End Date/Time: Dart/Ball Early : Pumps Starting Stage: Max Rate: Initial Rate (Breakdown): Max BH Pressure: Average Rate: Pad Percentage Actual Max Surface Pressure: Pump Time: Initial OA Pressure: Initial BH Pressure (Breakdown): Max OA Pressure: Flush Volume: Proppant in Formation: 100M Pumped: Conditioning Pad Volume: Average Missile HHP: Max Proppant Concentration: Pumps Ending Stage: 3T-603 - Moraine - Interval 19 Initial Surface Pressure (Breakdown): Average Surface Pressure: Pad Percentage Design Proppant Summary During 3 ppg, a suction hose started leaking, the job was shut down to identify the issue and isolate the pump. XL was resumed and the sand stepped up to 4 ppg to continue the zone. The interval was pumped to completion. Willie Martin Nathan Brzezinski Conoco Phillips 3T 603 Interval Summary 33 11/2/24 11:51 11/2/24 13:22 91 min 12.7 bpm 5,524 psi 6,974 psi 7 bbl 37.5 bpm 5,672 psi 6,794 psi 34.6 bpm 3,361 psi 3,258 psi 4,421 psi 2,847 hhp 403 psi 96 psi 691 psi 6.68 ppg 6 6 35 % 32 % 23 cP 114 F 9 198,624 lbs 4,797 lbs 203,421 lbs 203,421 lbs 2,100 gal 50 bbls 82,965 gal 1,975 bbls 10,317 gal 246 bbls 7,695 gal 183 bbls 17,310 gal 412 bbls 44,147 gal 1,051 bbls 7,890 gal 188 bbls 4,138 gal 99 bbls 12,102 gal 288 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Total Proppant Pumped* : Proppant in Formation: Displacement Volume: Conditioning Pad Volume: Interval Summary Start Date/Time: End Date/Time: Pad Volume: Max BH Pressure: Average Rate: Average Missile Pressure: Average Surface Pressure: Average pH: Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Proppant Summary Wanli 16/20 Ceramic Pumped: 100M Pumped: Pumps Ending Stage: Average BH Pressure: Pump Time: Pad Percentage Design Average Temp: Fluid Summary (by fluid description) Fluid Summary (by stage description) Max OA Pressure: Pad Percentage Actual 30# Hybor G-i Volume: Average Missile HHP: Open Well Pressure: Initial OA Pressure: 3T-603 - Moraine - Interval 20 Gregory Koester *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Dan Faur Max Surface Pressure: Proppant Laden Fluid Volume: Spacer and Ball Drop Volume: Max Proppant Concentration: Average Visc: 30# Linear Volume: Freeze Protect Volume: Interval Status: Willie Martin Nathan Brzezinski Initial Rate (Breakdown): Pumps Starting Stage: Establish Stable Fluid Volume: The initial ball for interval 20 did not seat so the back-up ball was dropped. After the ball was seated, the stage was resumed as planned. In the higher sand concentrations, proppant concentration was fluctuating due to chunky proppant found in the hopper. Conoco Phillips 3T 603 Interval Summary 34 11/2/24 13:22 11/2/24 14:51 89 min 12.6 bpm 5,086 psi 6,178 psi 5 bbl 37.4 bpm 5,439 psi 6,617 psi 35.7 bpm 3,336 psi 3,194 psi 4,226 psi 2,917 hhp 689 psi 738 psi 7.32 ppg 6 6 42 % 41 % 24 cP 113.1 F 9 201,196 lbs 5,219 lbs 206,415 lbs 206,415 lbs 85,579 gal 2,038 bbls 2,744 gal 65 bbls 15,650 gal 373 bbls 21,158 gal 504 bbls 44,235 gal 1,053 bbls 1,201 gal 29 bbls 3,215 gal 77 bbls 2,864 gal 68 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Summary Proppant Summary Wanli 16/20 Ceramic Pumped: Fluid Summary (by fluid description) Fluid Summary (by stage description) Conditioning Pad Volume: Proppant Laden Fluid Volume: Spacer and Ball Drop Volume: 30# Linear Volume: Start Date/Time: End Date/Time: 30# Hybor G-i Volume: Pump Time: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: *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: Max OA Pressure: Proppant in Formation: Pad Volume: 100M Pumped: Average Missile HHP: Pumps Ending Stage: Average Visc: Max BH Pressure: Pad Percentage Design Average pH: Average BH Pressure: Pumps Starting Stage: Willie Martin Average Temp: Average Missile Pressure: Average Surface Pressure: Pad Percentage Actual Average Rate: Max Proppant Concentration: 3T-603 - Moraine - Interval 21 Nathan Brzezinski Gregory Koester Dan Faur Interval Status: Max Surface Pressure: Total Proppant Pumped* : Establish Stable Fluid Volume: Interval 21 was pumped to completion however the ball for interval 22 did not seat so extra fluid was pumped after the proppant stages. Displacement Volume: Conoco Phillips 3T 603 Interval Summary 35 11/2/24 14:51 11/2/24 15:27 36 min 16.7 bpm 6,868 psi 7,969 psi -411 bbl 37.7 bpm 4,514 psi 5,687 psi 27.0 bpm 3,923 psi 3,815 psi 4,948 psi 2,597 hhp 720 psi 822 psi 4.47 ppg 6 6 54 % 45 % 23 cP 109.5 F 9 46,811 lbs 3,604 lbs 50,415 lbs 50,415 lbs 49,226 gal 1,172 bbls 969 gal 23 bbls 8,510 gal 203 bbls 14,569 gal 347 bbls 26,147 gal 623 bbls 969 gal 23 bbls 0 gal 0 bbls Cut Short Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant in Formation: Proppant Laden Fluid Volume: 30# Hybor G-i Volume: Total Proppant Pumped* : *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Fluid Summary (by fluid description) Fluid Summary (by stage description) Pad Volume: Establish Stable Fluid Volume: The ball for interval 22 did not seat at volume, so the decision was originally made to skip interval 22 and the ball for interval 23 was dropped. After dropping the ball for interval 23, the ball for interval 22 hit. The ball for stage 23 did not end up initally seating so proppant was started. During 4.5 ppg 16/20 the ball for interval 23 seated. Willie Martin Nathan Brzezinski Gregory Koester Interval Summary Dart/Ball Early : Average Missile Pressure: Initial OA Pressure: Average Surface Pressure: Max OA Pressure: Max Surface Pressure: Average Missile HHP: Average BH Pressure: Max BH Pressure: Max Rate: Start Date/Time: End Date/Time: Pump Time: Average Rate: Pad Percentage Actual Pumps Starting Stage: Pumps Ending Stage: Pad Percentage Design Average Visc: Average Temp: Initial BH Pressure (Breakdown): Average pH: Conditioning Pad Volume: Proppant Summary Dan Faur Wanli 16/20 Ceramic Pumped: Max Proppant Concentration: Initial Surface Pressure (Breakdown): 3T-603 - Moraine - Interval 22 Interval Status: 100M Pumped: Initial Rate (Breakdown): 30# Linear Volume: Displacement Volume: Conoco Phillips 3T 603 Interval Summary 36 11/2/24 15:27 11/2/24 16:52 85 min 37.4 bpm 6,668 psi 8,134 psi -738 bbl 37.1 bpm 5,005 psi 6,102 psi 26.5 bpm 3,116 psi 3,016 psi 4,311 psi 2,021 hhp 708 psi 715 psi 7.14 ppg 6 6 24 % 26 % 26 cP 109.3 F 9.1 0.641 psi/ft 3113 psi 3055 psi 3013 psi 192,742 lbs 5,065 lbs 197,807 lbs 197,807 lbs 1,273 gal 30 bbls 64,851 gal 1,544 bbls 12,612 gal 300 bbls 18,032 gal 429 bbls 42,479 gal 1,011 bbls 5,127 gal 122 bbls 7,485 gal 178 bbls 1,273 gal 30 bbls 4,340 gal 103 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep:Dan Faur Interval Status: Nathan Brzezinski Willie Martin Gregory Koester Dart/Ball Early : Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Final 10 min: Final 5 min: 100M Pumped: Average Missile Pressure: Average Missile HHP: Max Proppant Concentration: Interval Summary Pad Percentage Actual Initial Surface Pressure (Breakdown): Max Rate: Pumps Ending Stage: Max OA Pressure: Pad Percentage Design Average BH Pressure: Pump Time: End Date/Time: Average Visc: Average Temp: Final 15 min: Final Fracture Gradient: Total Proppant Pumped* : *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Max BH Pressure: Average Rate: Max Surface Pressure: Initial OA Pressure: Pumps Starting Stage: Initial BH Pressure (Breakdown): 3T-603 - Moraine - Interval 23 Initial Rate (Breakdown): Start Date/Time: Average pH: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Freeze Protect Volume: Establish Stable Fluid Volume: Proppant in Formation: 30# Hybor G-i Volume: 30# Linear Volume: The ball for interval 23 unexpectedly seated while pumping 4.5 ppg into the previous zone after it was thought we were already fracking into interval 23. The back up ball for interval 23 was dropped to confirm we were pumping into interval 23. The stage was pumped to completion. Displacement Volume: Flush Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Freeze Protect Volume: Conoco Phillips 3T 603 Interval Summary 37 Event Log Sieve Analysis Fann 15 Minute Field Break Test Real Time QC Well Summary Stimulation Treatment Appendix Chemical Summary Planned Design Water Straps Water Analysis Prepared for: Manabu Nozaki November 2, 2024 Harrison Bay County, AK Conoco Phillips 3T-603 Intervals 1-23 Moraine A-Sand Formation API: 50-103-20887 Conoco Phillips 3T 603 Appendix 167 Interval Date Designed Proppant (lbs) Proppant in Formation (lbs) Designed Fluid (bbl) Vol Clean (bbl) Vol Slurry (bbl) Pad Percentage Design Pad Percentage Actual Proppant Aggressivness (lb/bbl Clean) Fluid System 1 10/24/2024 204,000 202,974 3,217 3564 3,780 35.0 41.5 115 Hybor 2 10/24/2024 204,000 203,545 2,533 2672 2,889 35.0 35.9 123 Hybor 3 10/24/2024 204,000 203,299 2,711 3294 3,510 35.0 42.7 184 Hybor 4 10/24/2024 204,000 204,288 1,981 2053 2,270 34.0 33.8 191 Hybor 5 10/25/2024 204,000 202,021 1,898 2036 2,250 33.0 32.7 188 Hybor 6 10/25/2024 204,000 203,965 2,477 2399 2,615 41.4 38.7 189 Hybor 7 10/25/2024 204,000 202,539 1,585 1616 1,831 31.0 29.6 188 Hybor 8 10/25/2024 204,000 205,712 1,852 1913 2,131 30.0 29.9 192 Hybor 9 10/26/2024 204,000 208,672 2,154 2155 2,377 30.0 28.6 190 Hybor 10 10/26/2024 204,000 203,698 1,560 1587 1,803 30.0 27.5 188 Hybor 11 10/26/2024 204,000 203,252 1,560 1576 1,791 30.0 28.8 192 Hybor 12 10/26/2024 204,000 204,043 1,823 1847 2,064 30.0 29.4 192 Hybor 13 10/31/2024 204,000 206,256 1,909 2405 2,624 28.4 22.7 123 Hybor 14 10/31/2024 204,000 203,975 1,560 1571 1,787 30.0 28.9 194 Hybor 15 11/1/2024 204,000 203,464 2,236 2311 2,527 40.5 31.0 151 Hybor 16 11/1/2024 204,000 204,730 1,783 1801 2,019 30.0 28.7 193 Hybor 17 11/1/2024 204,000 204,688 2,055 2327 2,545 30.0 26.2 193 Hybor 18 11/1/2024 204,000 203,525 1,944 1980 2196 36.8 36.2 191 Hybor 19 11/1/2024 204,000 204,211 1,991 2141 2358 28.0 27.9 186 Hybor 20 11/2/2024 204,000 203,421 2,384 2271 2487 35.1 32.2 189 Hybor Hybrid 21 11/2/2024 204,000 206,415 2,058 2103 2322 42.2 41.0 191 Hybor Hybrid 22 11/2/2024 204,000 50,415 1,049 1195 1249 54.0 45.2 75 Hybor Hybrid 23 11/2/2024 204,000 197,807 1,817 1875 2085 24.1 26.3 191 Hybor Hybrid 3T 603 Interval Highlights Conoco Phillips 3T 603 Well Summary 168 Customer Conoco Phillips Formation Moraine Lease 3T 603 API 50 103 20887 Date Interval Summary Chemicals CL 28M BC 140X2 Losurf 300D MO 67 WG 36 OPTIFLO III OPTIFLO II BE 6 (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs) Prime Up 0 0 0 0 0 0 0 0 1 276 0 141 76 4863 282 333 75 2 224 0 112 79 3774 225 291 0 3 238 0 132 83 4291 265 270 0 4 157 0 95 47 2504 28 206 75 5 166 0 80 30 2967 165 193 0 6 121 0 90 35 3473 199 221 0 7 120 0 60 25 2247 133 160 0 8 108 0 75 20 2466 53 176 54 9 165 0 95 25 3208 178 219 0 10 145 0 54 25 2272 133 179 0 11 120 0 85 25 2284 132 182 0 12 105 0 65 25 2436 335 189 60 13 240 0 105 45 3646 199 250 0 14 150 0 55 25 2370 132 166 0 15 165 0 95 25 3338 192 216 0 16 105 0 65 20 2616 77 168 39 17 210 0 100 55 3312 188 230 0 18 170 0 75 20 2955 166 216 0 19 150 0 80 25 2808 196 204 30 20 72 30 105 20 2961 186 208 0 21 70 15 55 20 2305 182 207 0 22 24 9 34 9 1097 68 68 0 23 47 11 106 11 3414 214 217 0 Total 3348 65 1959 770 67607 3928 4769 333 w/o Prime Up 3348 65 1959 770 67607 3928 4769 333 Interval 10/23/2024 Dry AdditivesLiquid Additives Conoco Phillips 3T 603 Chemical Summary 169 Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 1Moraine@ 21163.37 - 21167.71 ft 139.1 °FInterval 2Moraine@ 20679.73 - 20684.07 ft 139.3 °FInterval 3Moraine@ 20205.12 - 20209.46 ft 139.4 °FInterval 4Moraine@ 19727.34 - 19731.68 ft 139.5 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 5Moraine@ 19251.26 - 19255.6 ft 139.6 °FInterval 6Moraine@ 18773.85 - 18778.19 ft 139.5 °FInterval 7Moraine@ 18297.55 - 18301.89 ft 139.3 °FInterval 8Moraine@ 17822.99 - 17827.33 ft 139 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 12Moraine@ 15912.53 - 15916.87 ft 139.4 °FInterval 9Moraine@ 17345.78 - 17350.12 ft 138.6 °FInterval 10Moraine@ 16868.38 - 16872.72 ft 138.8 °FInterval 11Moraine@ 16389.59 - 16393.93 ft 139.2 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 13Moraine@ 15437.33 - 15441.67 ft 139.6 °FInterval 14Moraine@ 14360.98 - 14365.32 ft 139.1 °FInterval 15Moraine@ 13840.6 - 13844.94 ft 138.9 °FInterval 16Moraine@ 13322.69 - 13327.03 ft 138.9 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 17Moraine@ 12803.74 - 12808.08 ft 138.9 °FInterval 18Moraine@ 12287.43 - 12291.77 ft 138.9 °FInterval 19Moraine@ 11766.81 - 11771.15 ft 139 °F Crosslinker Crosslinker Surfactant Buffer Gel Breaker Breaker BiocideInterval 21Moraine@ 10730.86 - 10735.2 ft 139 °FInterval 22Moraine@ 10212.92 - 10217.26 ft 138.8 °FInterval 23Moraine@ 9736.08 - 9740.42 ft 138.3 °FInterval 20Moraine@ 11248.16 - 11252.5 ft 139 °F Customer: Well: Date: Formation: SO#: Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels 1 Atigan CPF3 91 17,047 406 124 12 1,992 47 2 Wichita CPF3 97 19,530 465 126 12 2,268 54 3 Wichita CPF3 93 18,480 440 121 12 2,268 54 4 Wichita CPF3 96 19,320 460 125 12 2,268 54 5 Wichita CPF3 99 19,950 475 122 12 2,268 54 6 Wichita CPF3 90 18,060 430 128 12 2,268 54 7 Wichita CPF3 93 18,690 445 130 12 2,268 54 8 Atigan CPF3 98 18,595 443 82 12 1,992 47 9 Wichita CPF3 101 20,370 485 98 12 2,268 54 10 Wichita CPF3 92 18,480 440 129 12 2,268 54 11 Atigan CPF3 96 18,208 434 134 12 1,992 47 12 Atigan CPF3 85 16,080 383 135 12 1,992 47 13 Wichita CPF3 97 19,530 465 141 12 2,268 54 14 Wichita CPF3 89 17,850 425 138 12 2,268 54 15 Wichita CPF3 97 19,530 465 141 12 2,268 54 16 Atigan CPF3 92 17,434 415 137 12 1,992 47 17 Atigan CPF3 89 16,854 401 146 12 1,992 47 18 Atigan CPF3 101 19,175 457 138 12 1,992 47 19 Atigan CPF3 109 20,722 493 122 12 1,992 47 20 Atigan CPF3 101 19,175 457 114 28 4,912 117 21 Atigan CPF3 104 19,755 470 118 40 7,102 169 22 Wichita CPF3 104 21,000 500 107 40 7,602 181 23 Atigan CPF3 93 17,627 420 124 55 10,159 242 24 Atigan CPF3 93 17,627 420 127 70 13,178 314 25 Wichita CPF3 93 18,690 445 92 70 13,860 330 Gallons Barrels Gallons Barrels Gallons Barrels Gallons Barrels 467,778 11,138 97,699 2,326 109,620 2610 479,700 11,421 Location Summary Starting Volume Ending Volume On the Fly Flowing Total Used General Beginning Strap Ending Strap Conoco Phillips 3T 603 9/13/2024 A Sand 0909650292 Conoco Phillips 3T 603 Water Straps 10.24 176 Customer: Well: Date: Formation: SO#: Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels 1 Atigan CPF3 104 19,755 470 131 12 1,992 47 2 Wichita CPF3 104 21,000 500 132 12 2,268 54 3 Wichita CPF3 104 21,000 500 133 12 2,268 54 4 Wichita CPF3 104 21,000 500 131 12 2,268 54 5 Wichita CPF3 104 21,000 500 130 12 2,268 54 6 Wichita CPF3 104 21,000 500 138 12 2,268 54 7 Wichita CPF3 104 21,000 500 12 2,268 54 8 Atigan CPF3 106 20,142 480 12 1,992 47 9 Wichita CPF3 102 20,580 490 12 2,268 54 10 Wichita CPF3 11 Atigan CPF3 12 Atigan CPF3 13 Wichita CPF3 14 Wichita CPF3 15 Wichita CPF3 16 Atigan CPF3 17 Atigan CPF3 85 16,080 383 29 5,095 121 18 Atigan CPF3 105 19,949 475 72 13,565 323 19 Atigan CPF3 104 19,755 470 133 104 19,755 470 20 Atigan CPF3 104 19,755 470 131 104 19,755 470 21 Atigan CPF3 104 19,755 470 128 62 11,616 277 22 Wichita CPF3 104 21,000 500 134 32 6,048 144 23 Atigan CPF3 102 19,368 461 132 32 5,642 134 24 Atigan CPF3 104 19,755 470 134 12 1,992 47 25 Wichita CPF3 104 21,000 500 133 12 2,268 54 Gallons Barrels Gallons Barrels Gallons Barrels Gallons Barrels 362,894 8,640 105,596 2,514 0 0 257,298 6,126 Location Summary Starting Volume Ending Volume On the Fly Flowing Total Used General Beginning Strap Ending Strap Conoco Phillips 3T 603 9/13/2024 A Sand 0909650292 Conoco Phillips 3T 603 Water Straps 10.25 177 Customer: Well: Date: Formation: SO#: Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels 1 Atigan CPF3 104 19,755 470 131 12 1,992 47 2 Wichita CPF3 104 21,000 500 132 12 2,268 54 3 Wichita CPF3 104 21,000 500 133 12 2,268 54 4 Wichita CPF3 104 21,000 500 131 12 2,268 54 5 Wichita CPF3 104 21,000 500 130 12 2,268 54 6 Wichita CPF3 104 21,000 500 138 12 2,268 54 7 Wichita CPF3 104 21,000 500 12 2,268 54 8 Atigan CPF3 96 18,208 434 12 1,992 47 9 Wichita CPF3 96 19,320 460 58 11,340 270 10 Wichita CPF3 11 Atigan CPF3 12 Atigan CPF3 13 Wichita CPF3 14 Wichita CPF3 15 Wichita CPF3 101 20,370 485 101 20,370 485 16 Atigan CPF3 104 19,755 470 53 9,743 232 17 Atigan CPF3 102 19,368 461 55 10,159 242 18 Atigan CPF3 104 19,755 470 12 1,992 47 19 Atigan CPF3 104 19,755 470 133 12 1,992 47 20 Atigan CPF3 101 19,175 457 131 12 1,992 47 21 Atigan CPF3 62 11,616 277 12 1,992 47 Gallons Barrels Gallons Barrels Gallons Barrels Gallons Barrels 313,077 7,454 77,172 1,837 0 0 235,905 5,617 Conoco Phillips 3T 603 9/13/2024 A Sand 0909650292 General Beginning Strap Ending Strap Location Summary Starting Volume Ending Volume On the Fly Flowing Total Used Conoco Phillips 3T 603 Water Straps 10.26 178 Customer: Well: Date: Formation: SO#: Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels 1 Atigan CPF3 92 17,434 415 121 12 1,992 47 2 Wichita CPF3 95 19,110 455 124 12 2,268 54 3 Wichita CPF3 101 20,370 485 117 12 2,268 54 4 Wichita CPF3 101 20,370 485 121 12 2,268 54 5 Wichita CPF3 103 20,790 495 125 12 2,268 54 6 Wichita CPF3 100 20,160 480 127 12 2,268 54 7 Wichita CPF3 102 20,580 490 120 12 2,268 54 8 Atigan CPF3 102 19,368 461 126 12 1,992 47 9 Wichita CPF3 100 20,160 480 129 12 2,268 54 10 Wichita CPF3 100 20,160 480 128 12 2,268 54 11 Atigan CPF3 102 19,368 461 131 102 19,368 461 12 Atigan CPF3 101 19,175 457 130 101 19,175 457 13 Wichita CPF3 100 20,160 480 119 100 20,160 480 14 Wichita CPF3 100 20,160 480 125 100 20,160 480 15 Wichita CPF3 100 20,160 480 126 100 20,160 480 16 Atigan CPF3 105 19,949 475 122 105 19,949 475 17 Atigan CPF3 103 19,562 466 112 103 19,562 466 18 Atigan CPF3 100 18,981 452 118 100 18,981 452 19 Atigan CPF3 100 18,981 452 118 100 18,981 452 20 Atigan CPF3 102 19,368 461 125 102 19,368 461 21 Atigan CPF3 100 18,981 452 118 100 18,981 452 22 Wichita CPF3 100 20,160 480 118 100 20,160 480 23 Atigan CPF3 102 19,368 461 116 102 19,368 461 24 Atigan CPF3 105 19,949 475 113 105 19,949 475 25 Wichita CPF3 97 19,530 465 118 12 2,268 54 Gallons Barrels Gallons Barrels Gallons Barrels Gallons Barrels 492,355 11,723 298,719 7,112 0 0 193,636 4,610 Location Summary Starting Volume Ending Volume On the Fly Flowing Total Used General Beginning Strap Ending Strap Conoco Phillips 3T 603 9/13/2024 A Sand 0909650292 Conoco Phillips 3T 603 Water Straps 10.31 179 Customer: Well: Date: Formation: SO#: Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels 1 Atigan CPF3 95 18,014 429 121 12 1,992 47 2 Wichita CPF3 95 19,110 455 124 12 2,268 54 3 Wichita CPF3 102 20,580 490 117 12 2,268 54 4 Wichita CPF3 102 20,580 490 121 12 2,268 54 5 Wichita CPF3 88 17,640 420 0 0 6 Wichita CPF3 88 17,640 420 0 0 7 Wichita CPF3 0 0 0 0 8 Atigan CPF3 101 19,175 457 126 101 19,175 457 9 Wichita CPF3 101 20,370 485 129 101 20,370 485 10 Wichita CPF3 100 20,160 480 128 100 20,160 480 11 Atigan CPF3 100 18,981 452 131 100 18,981 452 12 Atigan CPF3 101 19,175 457 130 101 19,175 457 13 Wichita CPF3 100 20,160 480 119 100 20,160 480 14 Wichita CPF3 100 20,160 480 125 100 20,160 480 15 Wichita CPF3 100 20,160 480 126 100 20,160 480 16 Atigan CPF3 105 19,949 475 122 105 19,949 475 17 Atigan CPF3 103 19,562 466 112 103 19,562 466 18 Atigan CPF3 100 18,981 452 118 100 18,981 452 19 Atigan CPF3 100 18,981 452 118 100 18,981 452 20 Atigan CPF3 102 19,368 461 125 102 19,368 461 21 Atigan CPF3 100 18,981 452 118 50 9,119 217 22 Wichita CPF3 100 20,160 480 118 12 2,268 54 23 Atigan CPF3 101 19,175 457 116 101 19,175 457 24 Atigan CPF3 87 16,467 392 113 87 16,467 392 25 Wichita CPF3 87 17,430 415 118 87 17,430 415 Gallons Barrels Gallons Barrels Gallons Barrels Gallons Barrels 460,960 10,975 328,437 7,820 0 0 132,523 3,155 Conoco Phillips 3T 603 9/13/2024 A Sand 0909650292 General Beginning Strap Ending Strap Location Summary Starting Volume Ending Volume On the Fly Flowing Total Used Conoco Phillips 3T 603 Water Straps 11.1 180 Customer: Well: Date: Formation: SO#: Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels 1 Atigan CPF3 104 19,755 470 127 12 1,992 47 2 Wichita CPF3 104 21,000 500 128 12 2,268 54 3 Wichita CPF3 104 21,000 500 129 12 2,268 54 4 Wichita CPF3 84 16,800 400 131 12 2,268 54 5 Wichita CPF3 83 16,590 395 12 2,268 54 6 Wichita CPF3 82 16,380 390 12 2,268 54 7 Wichita CPF3 84 16,800 400 12 2,268 54 8 Atigan CPF3 104 19,755 470 128 12 1,992 47 9 Wichita CPF3 104 21,000 500 128 12 2,268 54 10 Wichita CPF3 104 21,000 500 124 12 2,268 54 11 Atigan CPF3 104 19,755 470 122 12 1,992 47 12 Atigan CPF3 104 19,755 470 126 12 1,992 47 13 Wichita CPF3 104 21,000 500 126 50 9,660 230 14 Wichita CPF3 104 21,000 500 126 99 19,950 475 15 Wichita CPF3 104 21,000 500 128 100 20,160 480 16 Atigan CPF3 107 20,336 484 118 75 14,146 337 17 Atigan CPF3 86 16,273 387 110 75 14,146 337 18 Atigan CPF3 86 16,273 387 115 75 14,146 337 19 Atigan CPF3 52 9,535 227 115 12 1,992 47 20 Atigan CPF3 32 5,642 134 121 12 1,992 47 21 Atigan CPF3 78 14,726 351 125 12 1,992 47 22 Wichita CPF3 72 14,280 340 130 12 2,268 54 23 Atigan CPF3 78 14,726 351 128 12 1,992 47 24 Atigan CPF3 51 9,327 222 131 12 1,992 47 25 Wichita CPF3 68 13,440 320 127 12 2,268 54 Gallons Barrels Gallons Barrels Gallons Barrels Gallons Barrels 427,148 10,170 132,815 3,162 0 0 294,333 7,008 Conoco Phillips 3T 603 9/13/2024 A Sand 0909650292 General Beginning Strap Ending Strap Location Summary Starting Volume Ending Volume On the Fly Flowing Total Used Conoco Phillips 3T 603 Water Straps 11.2 181 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl)Sulfate(SO42)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPostCrosslinkpHCrosslink Bacteria°F mg/L mg/L mg/L mg/L mg/L mg/L cP(Y/N) BQ ValueTank #H2Spresent?Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal HardnessMinus CalciumTitration FANN35 Probe Probe ProbeMycometer1 N 1.014 81.0 0 17,790 800 1,400 1,560 2,960 33.0 7.06 7.64 9.10 Y 184,4492 N 1.014 85.0 0 11,910 800 1,960 2,040 4,000 34.0 7.10 7.32 9.10 Y 292,8773 N 1.012 88.0 0 15,230 800 3,200 0 3,200 34.0 6.90 7.43 9.20 Y 248,9144 N 1.018 90.5 0 15,160 400 2,640 960 3,600 27.0 7.20 7.31 9.35 Y 155,0475 N 1.016 87.2 0 21,120 800 2,400 800 3,200 26.0 7.05 7.25 9.32 Y 183,0966 N 1.018 90.2 0 23,030 800 2,240 200 2,440 26.0 7.02 7.27 9.33 Y 200,4447 N 1.018 85.1 0 16,440 800 2,920 280 3,200 25.0 7.20 7.41 9.30 Y 249,9148 N 1.018 88.1 0 23,030 800 2,000 0 2,000 27.0 7.05 7.14 9.30 Y 173,9449 N 1.014 94.6 0 15,160 800 2,680 200 2,880 30.0 7.02 7.15 9.27 Y 279,76610 N 1.018 91.5 0 11,910 800 1,960 800 2,760 29.0 7.00 7.18 9.28 Y 191,25011 N 1.016 90.6 0 11,910 800 2,960 80 3,040 28.0 7.10 7.21 9.30 Y 206,21012 N 1.018 90.6 0 12,910 800 1,760 1,280 3,040 30.0 7.08 7.19 9.25 Y 214,39813 N 1.018 93.5 0 15,160 800 3,040 0 3,040 24.0 7.10 7.20 9.55 Y 24,74014 N 1.016 93.0 0 13,980 800 2,800 280 3,080 33.0 7.10 7.20 9.20 Y 158,26415 N 1.014 120.0 0 15,160 800 1,680 320 2,000 24.0 7.20 7.00 9.35 Y 173,42516 N 1.016 120.0 0 11,910 800 1,560 680 2,240 25.0 7.27 7.48 9.34 Y 92,26417 N 1.016 122.0 0 11,910 800 1,640 440 2,080 27.0 7.20 7.43 9.75 Y 249,10218 N 1.014 133.0 0 12,910 400 1,680 560 2,240 30.0 7.00 7.39 9.40 Y 117,41619 N 1.016 143.0 0 12,910 800 1,640 640 2,280 29.0 7.20 7.58 9.38 Y 138,61520 N 1.016 129.0 0 11,910 800 1,760 480 2,240 32.0 7.05 7.45 9.40 Y 197,08221 N 1.016 155.0 0 12,910 800 1,760 520 2,280 30.0 7.02 7.30 9.17 Y 203,49322 N 1.014 128.0 0 12,910 800 1,800 680 2,480 33.0 7.00 7.35 9.20 Y 124,72123 N 1.014 118.0 0 12,910 800 1,640 360 2,000 34.0 7.00 7.35 9.26 Y 181,67924 N 1.014 102.0 0 12,910 800 1,440 560 2,000 35.0 7.10 7.54 9.20 Y 164,912Average 1.016 0 14,712 767 2,107 572 2,678 29.4 7.08 7.32 9.30183,584Maximum 1.018 0 23,030 800 3,200 2,040 4,000 35.0 7.27 7.64 9.75292,877Minimum 1.012 0 11,910 400 1,440 0 2,000 24.00 7.00 7.00 9.1724,740Range 0.006 0 11,120 400 1,760 2,040 2,000 11.0 0.27 0.64 0.58268,136Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco PhillipsWell Name:3T603Water Source:CPF3Conoco Phillips3T603 Water Analysis 10.23 182 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl)Sulfate(SO42)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPostCrosslinkpHCrosslink Bacteria°F mg/L mg/L mg/L mg/L mg/L mg/L cP(Y/N) BQ ValueTank #H2Spresent?Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal HardnessMinus CalciumTitration FANN35 Probe Probe ProbeMycometer1 N 1.014 131.0 0 19,410 800 2,360 0 2,360 186,4282 N 1.018 132.0 0 33,390 800 2,000 480 2,480 10,0473 N 1.018 133.0 0 13,980 800 2,200 320 2,520 2,4184 N 1.018 130.5 0 16,440 800 2,160 560 2,720 20,0485 N 1.016 130.0 0 27,570 800 2,360 160 2,520 8716 N 1.010 138.0 0 25,170 800 2,400 200 2,600 8897 N 1.018 130.0 0 14,270 800 2,200 80 2,280 7,66119 N 1.014 133.0 0 14,270 800 2,200 560 2,760 1,78820 N 1.012 131.0 0 19,470 800 2,120 200 2,320 3,19021 N 1.018 128.0 0 17,850 800 2,120 680 2,800 1,91022 N 1.020 134.0 0 19,410 800 1,800 600 2,400 3,15023 N 1.014 132.0 0 27,570 800 2,120 40 2,160 2,45124 N 1.014 134.0 0 27,570 800 2,320 0 2,320 1,09925 N 1.018 133.0 0 25,170 800 2,440 0 2,440 1,260Average 1.016 0 21,539 800 2,200 277 2,477 33.3 7.11 7.25 9.3017,372Maximum 1.020 0 33,390 800 2,440 680 2,800 34.0 7.18 7.27 9.45186,428Minimum 1.010 0 14,270 800 1,800 0 2,160 33.00 7.03 7.23 9.14871Range 0.010 0 19,120 0 640 680 640 1.0 0.15 0.04 0.31185,557Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco PhillipsWell Name:3T603Water Source:CPF333.0 7.03 7.23 9.14 Y34.0 7.18 7.25 9.45 Y33.0 7.11 7.27 9.30 YConoco Phillips3T603 Water Analysis 10.24 183 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl)Sulfate(SO42)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPostCrosslinkpHCrosslink Bacteria°F mg/L mg/L mg/L mg/L mg/L mg/L cP(Y/N) BQ ValueTank #H2Spresent?Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal HardnessMinus CalciumTitration FANN35 Probe Probe ProbeMycometer1 N 1.012 134.0 0 21,060 800 1,840 320 2,160 127,3182 N 1.012 131.0 0 22,800 800 1,960 280 2,240 4,3153 N 1.014 132.0 0 18,010 800 1,640 320 1,960 8884 N 1.012 129.0 0 16,660 800 1,880 160 2,040 1,8055 N 1.010 137.0 0 22,800 800 1,640 720 2,360 5926 N 1.012 138.0 0 22,800 800 1,560 480 2,040 40215 N 1.014 128.0 0 21,060 800 1,440 680 2,120 43116 N 1.014 130.0 0 31,860 800 1,360 560 1,920 22217 N 1.012 129.0 0 34,880 800 1,560 680 2,240 165Average 1.012 0 23,548 800 1,653 467 2,120 32.3 7.05 7.39 9.5315,126Maximum 1.014 0 34,880 800 1,960 720 2,360 35.0 7.16 7.46 9.60127,318Minimum 1.010 0 21,060 800 1,360 480 1,920 35.00 7.16 7.46 9.60165Range 0.004 0 13,820 0 600 240 440 0.0 0.00 0.00 0.00127,153Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco PhillipsWell Name:3T603Water Source:CPF329.0 6.90 7.38 9.60 Y33.0 7.10 7.33 9.40 Y35.0 7.16 7.46 9.60 YConoco Phillips3T603 Water Analysis 10.25 184 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl)Sulfate(SO42)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPostCrosslinkpHCrosslink Bacteria°F mg/L mg/L mg/L mg/L mg/L mg/L cP(Y/N) BQ ValueTank #H2Spresent?Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal HardnessMinus CalciumTitration FANN35 Probe Probe ProbeMycometer1 1.014 126.0 0 14,270 800 1,440 560 2,000 55,9092 N 1.012 126.0 0 14,270 800 1,160 1,120 2,280 1,7113 N 1.016 126.0 0 47,220 800 1,960 0 1,960 4634 N 1.012 126.0 0 42,400 800 1,560 640 2,200 4765 N 1.012 112.0 0 34,880 800 1,600 320 1,920 6026 N 1.012 112.0 0 24,710 800 1,640 0 1,640 9617 N 1.012 112.0 0 42,400 800 1,360 600 1,960 1,0218 N 1.014 112.0 0 22,800 800 1,560 480 2,040 59,8729 N 1.014 112.0 0 42,400 800 1,880 80 1,960 20,14510 N 1.012 112.0 0 47,220 800 1,560 480 2,040 50,68411 N 1.016 127.0 0 24,710 800 1,720 280 2,000 1,37412 N 1.012 127.0 0 24,710 800 1,920 120 2,040 5,83813 N 1.018 127.0 0 14,270 800 800 1,360 2,160 1,18614 N 1.016 127.0 0 14,270 800 1,400 880 2,280 257,40615 N 1.016 127.0 0 14,270 800 720 1,560 2,280 6,61016 N 1.018 108.0 0 15,420 800 1,000 1,160 2,160 67317 N 1.018 108.0 0 14,270 800 1,000 1,200 2,200 48118 N 1.016 108.0 0 15,420 800 880 1,360 2,240 72319 N 1.016 108.0 0 14,270 800 960 1,320 2,280 51820 N 1.016 108.0 0 15,420 800 880 1,480 2,360 80521 N 1.014 107.0 0 14,270 800 920 1,280 2,200 82122 N 1.014 107.0 0 15,420 800 960 1,360 2,320 4,44323 N 1.014 107.0 0 14,270 800 1,440 960 2,400 3,82224 N 1.016 107.0 0 19,470 800 1,440 760 2,200 75525 N 1.014 107.0 0 180,010 800 1,200 1,200 2,400 8,742Average 1.015 0 29,722 800 1,318 822 2,141 23.4 7.21 7.42 9.0719,442Maximum 1.018 0 180,010 800 1,960 1,560 2,400 24.0 7.38 7.45 9.23257,406Minimum 1.012 0 14,270 800 720 0 1,640 23.00 7.15 7.40 8.89463Range 0.006 0 165,740 0 1,240 1,560 760 1.0 0.23 0.05 0.34256,943Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco PhillipsWell Name:3T603Water Source:CPF323.0 7.20 7.40 9.23 Y22.0 7.10 7.45 9.10 Y24.0 7.23 7.42 9.05 Y24.0 7.15 7.40 8.89 Y24.0 7.38 7.45 9.10 YConoco Phillips3T603 Water Analysis 10.26 185 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl)Sulfate(SO42)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPostCrosslinkpHCrosslink Bacteria°F mg/L mg/L mg/L mg/L mg/L mg/L cP(Y/N) BQ ValueTank #H2Spresent?Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal HardnessMinus CalciumTitration FANN35 Probe Probe ProbeMycometer1 N 1.012 133.0 0 16,270 800 1,920 400 2,320 26,4972 N 1.012 133.0 0 16,270 800 2,000 280 2,280 9773 N 1.012 133.0 0 15,010 800 2,200 400 2,600 13,7654 N 1.012 133.0 0 15,010 800 2,160 120 2,280 7,0055 N 1.016 133.0 0 15,010 800 2,360 240 2,600 5248 N 1.012 129.0 0 13,860 800 2,200 80 2,280 3,9279 N 1.016 129.0 0 15,010 800 2,160 600 2,760 2,05210 N 1.017 129.0 0 13,850 800 2,360 0 2,360 2,19525 N 1.012 129.0 0 15,010 800 2,320 0 2,320 549Average 1.013 0 15,033 800 2,187 236 2,422 27.5 7.15 7.38 9.416,388Maximum 1.017 0 16,270 800 2,360 600 2,760 28.0 7.20 7.41 9.5426,497Minimum 1.012 0 13,850 800 2,160 0 2,280 28.00 7.10 7.34 9.27524Range 0.004 0 2,420 0 200 600 480 0.0 0.10 0.07 0.2725,973Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco PhillipsWell Name:3T603Water Source:CPF328.0 7.10 7.34 9.27 Y27.0 7.20 7.41 9.54 YConoco Phillips3T603 Water Analysis 11.1 186 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl)Sulfate(SO42)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPostCrosslinkpHCrosslink Bacteria°F mg/L mg/L mg/L mg/L mg/L mg/L cP(Y/N) BQ ValueTank #H2Spresent?Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal HardnessMinus CalciumTitration FANN35 Probe Probe ProbeMycometer1 N 1.016 125.0 0 14,270 800 1,680 520 2,200 16,6972 N 1.016 125.0 0 14,270 800 1,840 280 2,120 5803 N 1.014 125.0 0 15,420 800 1,840 80 1,920 1,1894 N 1.014 128.0 0 14,270 800 1,560 160 1,720 3605 N 1.014 128.0 0 15,420 800 1,840 480 2,320 2606 N 1.014 128.0 0 14,270 800 1,960 160 2,120 146Average 1.015 0 14,653 800 1,787 280 2,067 26.0 7.05 7.55 8.853,205Maximum 1.016 0 15,420 800 1,960 520 2,320 27.0 7.20 7.65 8.9016,697Minimum 1.014 0 14,270 800 1,840 160 2,120 0.00 0.00 0.00 0.00146Range 0.002 0 1,150 0 120 360 200 27.0 7.20 7.65 8.9016,550Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco PhillipsWell Name:3T603Water Source:CPF327.0 7.20 7.65 8.90 Y25.0 6.90 7.45 8.80 YConoco Phillips3T603 Water Analysis 11.2 187 Linear Linear XL XL XL Lip time Linear Linear XL XL XL Lip time Interval Stage Visc pH Temp °F pH min Interval Stage Visc pH Temp °F pH min 1 Pad 35 7.7 110 8.88 2 13 Pad 32 9.3 98 9.2 2 0.25# 28 7.5 112 8.9 2 27 Avg Linear Visc 0.25# 28 9.4 103 9.3 2 29 Avg Linear Visc 1.00# 25 7.5 120 8.7 4 118.6 Avg XLTemp 1.00# 103.6 Avg XLTemp 2.00# 27 7.6 120 8.7 3 8.1 Avg XL pH 2.00# 28 9.4 113 9.3 2 9.4 Avg XL pH 3.00# 22 7.4 128 8.9 3 3.00# 4.00# 26 7.4 120 8.76 3 4.00# 28 9.8 101 9.7 2 5.00# 27 7.2 120 8.81 3 4.50# 3 5.00# 30 9.7 103 9.6 3 5.50# 6.00# 28 9.2 97 9.1 3 6.50# 7.00# 27 9.3 95 9.3 4 2 Pad 30 7.1 116 8.6 2 14 Pad 27 9.4 96 9.3 3 0.25# 32 7..1 120 8.9 2 0.25# 28 9.4 98 9.3 3 1.00# 30 6.9 123 8.7 3 1.00# 2.00# 29 7.1 118 8.8 3 29 Avg Linear Visc 2.00# 20 9.3 101 9.3 3 26 Avg Linear Visc 3.00# 26 7.2 120 8.7 3 118.1 Avg XLTemp 3.00# 101.3 Avg XLTemp 4.00# 27 7.2 116 8.8 3 8.8 Avg XL pH 4.00# 25 9.3 102 9.3 3 9.3 Avg XL pH 5.00# 27 7.2 116 8.7 3 4.50# 6.00# 27 7.2 116 8.8 3 5.00# 27 9.4 106 9.4 3 5.50# 6.00# 28 9.4 93 9.3 3 6.50# 7.00# 28 9.4 113 9.3 3 3 Pad 27 7.14 113 8.9 3 15 Pad 28 9.3 111 9.3 3 0.25# 28 7.5 114 8.8 3 0.25# 32 9.1 115 8.9 2 1.00# 27 7 118 8.8 2 1.00# 2.00# 28 7.1 117 8.7 2 28 Avg Linear Visc 2.00# 27 9.4 103 9.3 3 28 Avg Linear Visc 3.00# 27 7.2 118 8.7 2 115.2 Avg XLTemp 3.00# 108.6 Avg XLTemp 4.00# 28 7.11 116 8.8 2 8.8 Avg XL pH 4.00# 27 9.4 115 9.3 3 9.3 Avg XL pH 4.50# 27 7.2 115 8.8 2 4.50# 5.00# 27 7.08 114 8.9 2 5.00# 24 9.4 103 9.4 3 5.50# 27 7.2 114 8.7 2 5.50# 6.00# 28 7.1 115 8.8 2 6.00# 27 9.5 103 9.5 3 6.50# 28 7.1 114 8.8 2 6.50# 7.00# 28 7.1 114 8.9 2 7.00# 28 9.4 110 9.4 3 4 Pad 27 7.12 99 8.8 3 16 Pad 28 9.3 112 9.3 3 0.25# 27 7.12 99 8.78 3 0.25# 23 9.2 123 9.1 2 1.00# 28 7.14 110 8.75 3 1.00# 2.00# 27 7.14 110 8.91 3 27 Avg Linear Visc 2.00# 25 9.4 110 9.3 2 28 Avg Linear Visc 3.00# 27 7.1 112 8.76 3 108.0 Avg XLTemp 3.00# 111.3 Avg XLTemp 4.00# 28 7.1 110 8.8 3 8.8 Avg XL pH 4.00# 27 9.5 115 9.3 2 9.3 Avg XL pH 4.50# 27 7.2 111 8.9 3 4.50# 5.00# 27 7.1 110 8.9 3 5.00# 28 9.3 100 9.2 3 5.50# 28 7.2 110 8.8 3 5.50# 6.00# 28 7.14 110 8.8 3 6.00# 32 9.4 110 9.3 2 6.50# 28 7.21 108 8.78 4 6.50# 7.00# 27 7.2 107 8.77 4 7.00# 33 9.4 109 9.3 2 5 Pad 31 7.5 98 8.5 3 17 Pad 25 9.2 110 9.1 2 0.25# 33 9.4 105 9.3 2 0.25# 25 9.6 115 9.5 2 1.00# 35 9.3 115 9.3 2 1.00# 2.00# 35 9.2 114 9.35 2 34 Avg Linear Visc 2.00# 27 9.3 113 9.2 2 26 Avg Linear Visc 3.00# 108.8 Avg XLTemp 3.00# 111.6 Avg XLTemp 4.00# 32 9.3 112 9.2 2 9.2 Avg XL pH 4.00# 27 9.3 110 9.2 2 9.3 Avg XL pH 4.50# 4.50# 5.00# 33 9.3 101 9.3 2 5.00# 26 9.3 113 9.3 2 5.50# 5.50# 6.00# 35 9.5 110 9.4 2 6.00# 26 9.3 113 9.3 2 6.50# 6.50# 7.00# 35 9.4 115 9.2 2 7.00# 26 9.4 107 9.4 2 6 Pad 31 9.2 107 9.1 2 18 Pad 26 9.4 107 9.4 2 0.25# 35 9.3 120 9.2 2 0.25# 27 9.3 96 9.2 3 1.00# 35 9.2 115 9.16 3 1.00# 2.00# 35 9.2 115 9.16 3 34 Avg Linear Visc 2.00# 29 9.3 110 9.2 2 28 Avg Linear Visc 3.00# 112.4 Avg XLTemp 3.00# 108.7 Avg XLTemp 4.00# 34 9.2 116 9.2 3 9.2 Avg XL pH 4.00# 29 9.5 110 9.4 2 9.3 Avg XL pH 4.50# 4.50# 5.00# 34 9.20 113 9.20 2 5.00# 28 9.4 113 9.3 2 5.50# 5.50# 6.00# 35 9.2 100 9.2 4 6.00# 27 9.3 116 9.2 2 6.50# 6.50# 7.00# 34 9.2 113 9.2 4 7.00# 27 9.5 109 9.4 2 7 Pad 36 9.2 113 9.2 2 19 Pad 27 9.4 109 9.3 2 0.25# 34 9.3 120 8.9 3 0.25# 32 9.4 108 9.3 2 1.00# 1.00# 2.00# 28 9.3 121 9.2 3 30 Avg Linear Visc 2.00# 27 9.3 111 9.2 2 28 Avg Linear Visc 3.00# 116.1 Avg XLTemp 3.00# 111.6 Avg XLTemp 4.00# 30 9.2 117 9.2 4 9.1 Avg XL pH 4.00# 27 9.3 113 9.3 2 9.3 Avg XL pH 4.50# 4.50# 5.00# 25 9.3 115 9.2 4 5.00# 27 9.3 110 9.2 2 5.50# 5.50# 6.00# 30 9 114 9 4 6.00# 27 9.3 115 9.2 2 6.50# 6.50# 7.00# 28 9 113 9 3 7.00# 28 9.3 115 9.3 2 8 Pad 28 9 118 9 3 20 Pad 27 9 116 8.8 0 0.25# 32 9 122 9 3 0.25# 25 9.1 115 8.9 0 1.00# 1.00# 2.00# 32 9.3 120 9.2 2 30 Avg Linear Visc 2.00# 25 9.1 115 9 0 23 Avg Linear Visc 3.00# 116.5 Avg XLTemp 3.00# 114.4 Avg XLTemp 4.00# 28 9.3 113 9.2 2 9.1 Avg XL pH 4.00# 15 9.1 115 9 0 9.0 Avg XL pH 4.50# 4.50# 5.00# 30 9.1 114 9 3 5.00# 23 9.23 110 9.14 0 5.50# 5.50# 6.00# 30 9.1 112 9.1 4 6.00# 23 9.21 115 9.1 0 6.50# 6.50# 7.00# 29 8.8 107 8.9 4 7.00# 22 9.22 115 9.1 0 9 Pad 32 9.1 114 9.1 2 21 Pad 22 9.2 120 9.15 0 0.25# 32 9.5 113 9.4 2 0.25# 20 9.29 120 9.2 0 1.00# 1.00# 2.00# 29 9.3 119 9.2 3 28 Avg Linear Visc 2.00# 24 9.1 115 9 0 24 Avg Linear Visc 3.00# 115.7 Avg XLTemp 3.00# 113.1 Avg XLTemp 4.00# 24 9.4 117 9.3 3 9.3 Avg XL pH 4.00# 25 9 110 8.9 0 9.0 Avg XL pH 4.50# 4.50# 5.00# 24 9.4 117 9.3 3 5.00# 25 9 107 8.9 0 5.50# 29 9.4 115 9.3 3 5.50# 6.00# 26 9.2 115 9.2 3 6.00# 25 8.9 110 8.8 0 6.50# 6.50# 7.00# 29 9.3 114 9.2 3 7.00# 25 9 110 8.9 0 10 Pad 30 9.4` 115 9.3 3 22 Pad 24 9.1 107 8.8 0 0.25# 29 9.4 125 9.2 2 0.25# 22 9.1 110 9.1 0 1.00# 1.00# 2.00# 29 9.4 118 9.4 2 29 Avg Linear Visc 2.00# 24 9 110 8.9 0 23 Avg Linear Visc 3.00# 121.0 Avg XLTemp 3.00# 109.5 Avg XLTemp 4.00# 28 9.4 128 9.5 2 9.4 Avg XL pH 4.00# 23 9.1 111 9.1 0 9.0 Avg XL pH 4.50# 4.50# 5.00# 26 9.4 119 9.4 3 5.00# 5.50# 5.50# 6.00# 29 9.4 121 9.3 2 6.00# 6.50# 6.50# 7.00# 30 9.4 118 9.3 2 7.00# 11 Pad 30 9.4 118 9.3 2 23 Pad 25 9.1 110 9.1 0 0.25# 30 9.4 125 9.3 2 30 Avg Linear Visc 0.25# 24 9.3 112 9.2 0 1.00# 118.0 Avg XLTemp 1.00# 2.00# 31 9.4 110 9.3 2 9.3 Avg XL pH 2.00# 25 9.21 107 9 0 26 Avg Linear Visc 3.00# 3.00# 109.3 Avg XLTemp 4.00# 31 9.4 120 9.3 2 4.00# 25 9.27 112 9.2 0 9.1 Avg XL pH 4.50# 4.50# 5.00# 28 9.4 117 9.3 2 5.00# 27 9.3 107 9.2 0 5.50# 5.50# 6.00# 30 9.4 115 9.3 2 6.00# 27 9.2 108 9.14 0 6.50# 6.50# 7.00# 28 9.4 115 9.3 2 7.00# 12 Pad 28 9.42 120 9.3 2 Comments 24 Pad 0.25# 29 9.41 126 9.16 2 0.25# 1.00# 1.00# 2.00# 29 9.4 120 9.3 2 28 Avg Linear Visc 2.00# #DIV/0! Avg Linear Visc 3.00# 115.9 Avg XLTemp 3.00# #DIV/0! Avg XLTemp 4.00# 29 9.56 115 9.5 2 9.3 Avg XL pH 4.00# #DIV/0! Avg XL pH 4.50# 4.50# 5.00# 28 9.4 104 9.36 2 5.00# 5.50# 5.50# 6.00# 30 9.4 116 9.4 2 6.00# 6.50# 6.50# 7.00# 25 9.5 110 9.3 3 7.00# Customer:ConocoPhillips Alaska, Inc. Wellname & #:3T-603 Date:October 23, 2024 Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Conoco Phillips 3T603 Real Time QC 188 Seq No. Time Activity Code Comment JobSlurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 05:57:16 (10/23/24) Other Crew Arrived on Location 2 7:12:17 Other Water Tank Temps Were Too Low To Start 3 7:29:23 Other Pre Job Safety Meeting 4 7:45:46 Other Begin Reheating Water 5 9:00:03 Start Job Starting Job 0 7 2 0 2034 1 09:00:03 (10/23/24) Next Treatment Treatment Interval 1 0 7 2 0 2034 6 10:48:23 Other Prime Pumps 0 547 194 0 2033 7 10:58:20 Other Replace High Pressure Seal on DME 0 36 1 0 2033 8 11:13:45 Other Fired Up Second Water Heater 0 10 9 0 2033 9 11:18:14 Other Prime Pumps Again 0 12 1 0 2033 10 11:37:49 Pressure Test ePRV Primary Tubing 0 1099 1150 0 2032 11 11:40:08 Pressure Test ePRV Primary IA 0 1638 255 0 2032 12 11:41:57 Pressure Test ePRV Secondary Tubing 0 1676 394 0 2032 13 11:43:06 Pressure Test ePRV Secondary IA 0 1723 431 0 2032 14 11:48:34 Pressure Test Pressure Test Local Kickouts 0 665 683 0 2032 15 11:51:18 Pressure Test Pressure Test Global Kickouts 0 707 682 0 2032 16 12:02:12 Pressure Test Pressure Test Begin 0 9527 9504 0 2032 17 12:08:20 Pressure Test Pressure Test Pass 0 9422 9373 0 2032 18 13:51:58 Other Prime Up SeaWater 0 71 61 0 2031 19 14:07:58 Open Well Open Well 0 188 84 0 2134 20 14:36:36 Other Arsenal Disk Burst 4.21 7291 7221 0 9397 21 14:41:06 Other Alpha Sleeve Shift 6.32 6004 5988 0 8078 22 15:15:48 ISIP ISIP 132.83 956 479 0 2881 23 6:11:37 End Job Ending Job 132.83 21 11 0 2179 Event Log 10.23 Conoco Phillips 3T 603 Event Log 10.23 189 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BHPres 1 05:58:35 (10/24/24) Other Crew Arrived to Location 2 6:28:31 Start Job Starting Job 0 0 0 0 0 1 06:28:31 (10/24/24) Next Treatment Treatment Interval 1 0 0 0 0 0 3 6:31:00 Pre Job Safety Meeting Pre Job Safety Meeting 6.57 20 11 2.6 2176 4 6:45:32 Other Begin Function Test Equipment 39.61 20 11 1.6 2174 5 8:12:30 Other Flood Brine 0 23 13 0 2162 6 8:15:58 Prime Pumps Prime Pumps 0 115 131 0 2161 7 8:30:55 Pressure Test ePRV Primary Tubing 0 646 689 0 2159 8 8:32:30 Pressure Test ePRV Primary IA 0 808 535 0 2159 9 8:35:20 Pressure Test ePRV SecondaryTubing 0 877 902 0 2159 10 8:36:33 Pressure Test ePRV Secondary IA 0 917 355 0 2159 11 8:41:45 Pressure Test Pressure Test Global 0 924 186 0 2158 12 8:42:21 Pressure Test Pressure Test Locals 0 924 562 0 2158 13 8:50:00 Pressure Test Pressure Test Begin 0 9768 9753 0 2157 14 8:55:25 Pressure Test Pressure Test Pass 0 9554 9516 0 2156 15 9:04:06 Other Peform Loop Test 0 31 6 0 2155 16 9:12:06 Other BringOn Chemicals and Mix Gel 0 29 7 0 2154 17 9:15:54 Other LRS IA Pop off Pop 0 29 8 0 2209 18 10:02:33 Other Troubleshoot WAM Skid Leaking Port 0 28 13 0 2283 19 10:27:50 Open Well Open Well 0 560 539 0 2317 20 10:30:56 Other Step 1 7.19 1202 1191 3.2 2982 21 10:32:42 Other Step 2 14.1 1192 1181 4.2 3002 22 10:34:29 Other Step 3 23.11 1242 1222 5.4 3058 23 10:36:03 Other Step 4 32.97 1327 1288 6.6 3124 24 10:37:54 Other Step 5 46.78 1409 1374 7.6 3196 25 10:38:58 Other Step 6 55.76 1599 1553 8.9 3313 26 10:50:21 Other Start Pad 273.4 2837 2849 20.6 4299 27 10:53:10 Alarm Delta Stage At Top Perf = 11 350.61 4004 4044 32.9 5213 28 10:55:15 Alarm Delta Stage At Top Perf = 12 423.65 4090 4156 36.4 5322 29 11:01:04 Alarm Delta Stage At Top Perf = 13 624.31 4069 4144 35.5 5313 30 11:02:37 Other Pump 670 Shut Off 681.05 4181 4211 37.2 5395 31 11:10:06 Other 100Mesh Gate Popped Off 913.98 4166 4197 37.7 5394 32 11:11:28 Other Dropped Rate To Trouble Shoot 100 Mesh Idea 964.84 4131 4150 37.7 5385 33 11:34:00 Alarm Delta Stage At Top Perf = 14 1621.92 4092 4113 37.3 5407 34 11:44:24 Alarm Delta Stage At Top Perf = 15 2009.22 3998 4023 37.2 5401 35 11:52:24 Alarm Delta Stage At Top Perf = 16 2306.66 4088 4118 37.2 5540 36 12:04:58 Alarm Delta Stage At Top Perf = 17 2773.14 4201 4237 37.1 5693 37 12:14:25 Other Pump 623 Neutralled 3122.38 4311 4355 37.2 5815 38 12:18:51 Alarm Delta Stage At Top Perf = 18 3256.66 3654 3679 30.2 5296 39 12:29:00 Alarm Delta Stage At Top Perf = 19 3592.2 4740 4764 37.6 6246 2 12:30:32 (10/24/24) Next Treatment Treatment Interval 2 3645.79 3748 3747 29 5313 40 12:30:32 Drop Ball Drop Ball 02 3645.79 3759 3760 29 5304 41 12:40:06 Ball on Seat Ball 2 on Seat 3939.96 2825 2758 19.2 4489 42 12:40:19 Break Formation Break Formation 3943.18 6090 6150 13.5 7586 43 12:41:00 Alarm Delta Stage At Top Perf = 20 3952.38 2981 2990 13.1 4597 44 12:43:26 Alarm Delta Stage At Top Perf = 1 3990.43 3588 3623 23.7 5027 45 13:06:03 Alarm Delta Stage At Top Perf = 6 4628.78 4477 4494 37.5 5714 46 13:16:55 Alarm Delta Stage At Top Perf = 7 5014.08 4502 4505 37.3 5830 47 13:25:08 Alarm Delta Stage At Top Perf = 8 5320.35 4477 4494 37.3 5856 48 13:35:49 Alarm Delta Stage At Top Perf = 9 5708.63 4268 4289 37 5753 49 13:45:59 Alarm Delta Stage At Top Perf = 10 6085.09 4311 4343 37 5837 50 13:53:32 Alarm Delta Stage At Top Perf = 11 6363.63 4494 4540 36.8 6036 3 13:58:18 (10/24/24) Next Treatment Treatment Interval 3 6534.89 4008 4009 30.9 5536 51 13:58:18 Drop Ball Drop Ball 3 6534.89 4008 4009 30.9 5536 52 13:58:19 Other Start MiniFrac 6535.92 4013 4017 30.9 5540 53 13:59:53 Alarm Delta Stage At Top Perf = 12 6587.36 4914 4938 37 6291 54 14:06:32 Ball on Seat Ball 3 on Seat 6816.65 2547 2499 11.7 4238 55 14:06:48 Break Formation Break Formation 6819.78 5735 5750 11.7 7326 56 14:07:43 Alarm Delta Stage At Top Perf = 13 6830.66 2886 2857 11.9 4457 57 14:09:51 Alarm Delta Stage At Top Perf = 1 6871.9 3718 3744 30.4 5090 58 14:14:45 Other Begin Displacement 7050.76 3940 3937 37.1 5257 59 14:23:30 ISIP ISIP 7365.93 1023 51 0 3074 60 14:28:30 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 7365.93 1027 20 0 3015 61 14:33:30 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 7365.93 982 5 0 2988 62 14:38:29 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 7365.93 955 19 0 2966 63 14:57:47 Alarm Delta Stage At Top Perf = 2 7387.94 2816 2880 18.2 4425 64 15:10:39 Alarm Delta Stage At Top Perf = 4 7702.93 3970 4020 37.2 5170 65 15:15:51 Alarm Delta Stage At Top Perf = 5 7896.21 4344 4400 37.1 5538 66 15:30:59 Alarm Delta Stage At Top Perf = 6 8457.1 4347 4380 37.1 5627 67 15:41:55 Alarm Delta Stage At Top Perf = 7 8862.51 3998 4066 37.1 5490 68 15:43:15 Alarm Delta Stage At Top Perf = 8 8911.88 4080 4154 37 5575 69 15:45:20 Alarm Delta Stage At Top Perf = 9 8988.99 4223 4299 37 5731 70 15:48:14 Alarm Delta Stage At Top Perf = 10 9096.2 4351 4428 37 5858 71 15:52:47 Alarm Delta Stage At Top Perf = 11 9264.31 4404 4471 36.9 5917 72 15:56:28 Alarm Delta Stage At Top Perf = 12 9400.25 4479 4555 36.9 6004 73 16:01:01 Alarm Delta Stage At Top Perf = 13 9568.21 4572 4645 36.9 6092 74 16:05:12 Alarm Delta Stage At Top Perf = 14 9722.69 4660 4742 36.9 6196 75 16:07:35 Other Dropped Rate Due to the Blender Losing Prime 9810.66 4702 4725 36.8 6218 76 16:11:43 Alarm Delta Stage At Top Perf = 15 9891.57 2719 2762 17.7 4388 4 16:13:34 (10/24/24) Next Treatment Treatment Interval 4 9923.5 3134 3152 18.9 4713 77 16:13:35 Drop Ball Drop Ball 04 9924.13 3133 3151 18.9 4713 78 16:16:43 Alarm Delta Stage At Top Perf = 16 10005.98 4014 4024 30.5 5417 79 16:20:58 Alarm Delta Stage At Top Perf = 17 10152.14 3791 3830 36.6 5138 80 16:23:07 Ball on Seat Ball 4 on Seat 10208.15 2168 2180 12.3 3946 81 16:23:22 Break Formation Break Formation 10211.22 5307 5362 12.2 6842 82 16:26:08 Alarm Delta Stage At Top Perf = 1 10253.6 2875 2929 26.2 4352 83 16:34:19 Alarm Delta Stage At Top Perf = 2 10551.27 3564 3619 37.1 4907 84 16:43:45 Alarm Delta Stage At Top Perf = 3 10899.53 3630 3718 36.8 5158 85 16:45:00 Alarm Delta Stage At Top Perf = 4 10945.55 3749 3834 36.8 5275 86 16:46:39 Alarm Delta Stage At Top Perf = 5 11006.22 3866 3949 36.7 5404 87 16:49:28 Alarm Delta Stage At Top Perf = 6 11109.74 4028 4114 36.7 5562 88 16:53:00 Alarm Delta Stage At Top Perf = 7 11239.41 4149 4227 36.7 5675 89 16:56:46 Alarm Delta Stage At Top Perf = 8 11377.55 4255 4333 36.6 5785 90 17:01:19 Alarm Delta Stage At Top Perf = 9 11544.07 4389 4477 36.6 5908 91 17:05:37 Alarm Delta Stage At Top Perf = 10 11700.66 4533 4621 36.5 6044 92 17:06:34 Other Pump 621 Mechanical Issue 11735.95 4564 4651 36.5 6080 93 17:09:24 Start Flush Start Flush 11831.36 4804 4879 37.2 6232 94 17:10:22 Alarm Delta Stage At Top Perf = 11 11868.1 5020 5070 37.4 6300 95 17:13:45 Alarm Delta Stage At Top Perf = 12 11989.67 4498 4520 32.9 5677 96 17:19:06 ISIP ISIP 12160.62 1311 150 0 3215 97 17:24:07 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 12160.62 1138 52 0 3138 98 17:29:06 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 12160.62 148 60 0 3105 99 17:34:09 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 12160.62 124 83 0 3076 Event Log 10.24 Conoco Phillips 3T 603 Event Log 10.24 190 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:59:56 (10/25/24) Other Crew Arrived on Location 2 7:03:55 Other Waiting on Water 3 7:57:25 Start Job StartingJob 0 0 0 0 0 1 07:57:25 (10/25/24) Next Treatment Treatment Interval 1 0 0 0 0 0 4 10:17:19 Pre JobSafety Meeting Pre JobSafety Meeting 0 52 34 0 2275 5 10:22:17 Other Iron Spot Check 0 53 35 0 2274 6 11:17:35 Other Pull on Brine 0 5 37 0 2268 7 11:34:10 Prime Pumps Prime Pumps 0 279 117 0 2266 8 11:58:03 Pressure Test ePRV Primary Tubing 0 554 553 0 2264 9 11:59:26 Pressure Test ePRV Primary IA 0 569 604 0 2264 10 12:02:16 Pressure Test ePRV Secondary Tubing 0 687 820 0 2263 11 12:04:22 Pressure Test ePRV Secondary IA 0 731 387 0 2263 12 12:08:23 Pressure Test Pressure Test Global 0 726 188 0 2263 13 12:09:09 Pressure Test Pressure Test Locals 0 830 984 0 2263 14 12:15:19 Pressure Test Pressure Test Begin 0 9473 9532 0 2262 15 12:20:53 Pressure Test Pressure Test Pass 0 9393 9423 0 2261 16 12:26:09 Other Bring onChemicals and Mix Gel 0 5 31 0 2261 5 13:03:28 (10/25/24) Next Treatment Treatment Interval 5 0 184 88 0 2257 17 13:07:31 Open Well Open Well 0 458 428 0 2265 18 13:09:18 Other Load Ball 5 3.02 1076 1153 7.2 2842 19 13:11:13 Drop Ball Drop Ball 5 33.19 3095 3177 19.9 4238 20 13:22:55 Start Pad Start Pad 268.5 2757 2801 20.3 4283 21 13:26:03 Ball on Seat Ball 5 on Seat 312.76 2125 2196 12.2 3548 22 13:26:18 Break Formation Break Formation 315.79 5280 5392 12.1 6325 23 13:26:39 Alarm Delta Stage At Top Perf = 4 320.02 2175 2287 12.1 3527 24 13:28:53 Alarm Delta Stage At Top Perf = 5 360.08 3278 3381 27.7 4426 25 13:29:05 Other Truck Finished Offloading 365.8 3368 3456 29.1 4479 26 13:36:35 Alarm Delta Stage At Top Perf = 6 634.65 4120 4185 37.3 5339 27 13:42:14 Alarm Delta Stage At Top Perf = 7 845.57 3976 4036 37.3 5249 28 13:53:07 Alarm Delta Stage At Top Perf = 8 1247.3 3939 4030 37.2 5395 29 13:54:27 Alarm Delta Stage At Top Perf = 9 1296.84 4049 4142 37.2 5492 30 13:56:12 Alarm Delta Stage At Top Perf = 10 1361.8 4115 4187 37.1 5567 31 13:59:05 Alarm Delta Stage At Top Perf = 11 1468.75 4229 4325 37.1 5679 32 14:02:44 Alarm Delta Stage At Top Perf = 12 1603.93 4374 4432 37 5784 33 14:06:34 Alarm Delta Stage At Top Perf = 13 1745.97 4513 4563 37.1 5932 34 14:10:49 Alarm Delta Stage At Top Perf = 14 1903.56 4612 4683 37 6024 35 14:15:13 Alarm Delta Stage At Top Perf = 15 2066.42 4753 4812 37 6126 6 14:19:23 (10/25/24) NextTreatment Treatment Interval 6 2220.48 5059 5107 37.6 6279 36 14:19:23 Drop Ball Drop Ball 6 2221.11 5061 5110 37.6 6280 37 14:19:44 Alarm Delta Stage At Top Perf = 16 2234.26 5119 5166 37.6 6296 38 14:22:59 Alarm Delta Stage At Top Perf = 17 2356.54 4914 4923 37.7 6177 39 14:27:35 Ball on Seat Ball 6 on Seat 2488.29 2524 2551 12.5 4153 40 14:28:11 Break Formation Break Formation 2493.62 7285 7333 0 9356 41 14:50:18 Other Bleed Pressureon Surface 2493.99 7720 7658 0 9777 42 15:08:31 Shut In Well Shut In Well 2495.62 7732 7597 0 9783 43 15:20:58 Alarm Delta Stage At Top Perf = 18 2501.1 5199 5473 3 4878 44 15:22:51 Other StartGel 2506.81 5882 6083 3 5502 45 15:32:35 Alarm Delta Stage At Top Perf = 1 2536.31 5734 5690 5.9 5874 46 15:43:06 Alarm Delta Stage At Top Perf = 2 2759.3 4248 4384 36.4 5388 47 15:44:49 Alarm Delta Stage At Top Perf = 3 2822.65 4071 4129 37 5172 48 15:45:45 ISIP ISIP 2850.87 1300 97 0 3147 49 15:51:54 Alarm Delta Stage At Top Perf = 4 2926.06 2387 2426 20.2 3918 50 15:52:39 Alarm Delta Stage At Top Perf = 3 2941.23 2392 2425 20.2 3934 51 16:01:53 Alarm Delta Stage At Top Perf = 4 3191.06 3712 3753 37.1 4958 52 16:05:56 Alarm Delta Stage At Top Perf = 5 3341.29 3878 3931 37 5123 53 16:10:59 Alarm Delta Stage At Top Perf = 6 3527.75 3991 4038 37.1 5271 54 16:19:49 Alarm Delta Stage At Top Perf = 7 3854.17 3788 3862 37 5284 55 16:21:09 Alarm Delta Stage At Top Perf = 8 3903.48 3869 3936 37 5357 56 16:22:55 Alarm Delta Stage At Top Perf = 9 3968.8 3950 4024 37 5435 57 16:25:50 Alarm Delta Stage At Top Perf = 10 4076.49 4070 4140 36.8 5560 58 16:29:29 Alarm Delta Stage At Top Perf = 11 4211.48 4200 4264 37 5672 59 16:33:20 Alarm Delta Stage At Top Perf = 12 4353.76 4322 4398 36.9 5779 60 16:37:36 Alarm Delta Stage At Top Perf = 13 4511.08 4453 4530 36.9 5926 61 16:41:59 Alarm Delta Stage At Top Perf = 14 4672.58 4560 4648 36.8 6016 7 16:46:35 (10/25/24) Next Treatment Treatment Interval 7 4836.29 3699 3741 29.5 5274 62 16:46:42 Alarm Delta Stage At Top Perf = 15 4839.74 3710 3753 29.5 5273 63 16:46:47 Drop Ball Drop Ball 7 4842.2 3719 3762 29.5 5274 64 16:49:07 Other Pump 670 Neutralled 4921.39 3889 3875 30 5569 65 16:50:36 Alarm Delta Stage At Top Perf = 16 4962.81 3613 3636 27.7 5075 66 16:56:51 Ball on Seat Ball 7 on Seat 5105.21 2750 2791 12.7 4408 67 16:57:13 Break Formation Break Formation 5109.62 7109 7155 12.4 9054 68 16:57:20 Alarm Delta Stage At Top Perf = 17 5110.5 6355 6385 4.4 8244 69 17:00:41 Alarm Delta Stage At Top Perf = 1 5144.85 5091 5111 16.9 6560 70 17:08:08 Alarm Delta Stage At Top Perf = 2 5310.37 6227 6235 26.9 7774 71 17:18:51 Alarm Delta Stage At Top Perf = 3 5689.82 4151 4197 37.1 5603 72 17:19:49 Alarm Delta Stage At Top Perf = 4 5726.28 3993 4035 37.1 5453 73 17:21:34 Alarm Delta Stage At Top Perf = 5 5791.23 3821 3885 37.1 5307 74 17:24:29 Alarm Delta Stage At Top Perf = 6 5899.48 3836 3910 37.1 5316 75 17:28:08 Alarm Delta Stage At Top Perf = 7 6034.83 3920 3995 37.1 5396 76 17:31:58 Alarm Delta Stage At Top Perf = 8 6176.85 3997 4079 37 5473 77 17:36:14 Alarm Delta Stage At Top Perf = 9 6334.01 4075 4143 37 5542 78 17:40:37 Alarm Delta Stage At Top Perf = 10 6496.59 4163 4237 36.9 5642 79 17:41:48 Other Ben Swap OnThe Besser 6540.23 4196 4282 36.9 5657 80 17:45:19 Alarm Delta Stage At Top Perf = 11 6664.97 3292 3339 29.5 4913 8 17:45:25 (10/25/24) NextTreatment Treatment Interval 8 6667.44 3303 3355 29.4 4923 81 17:45:25 Drop Ball Drop Ball 8 6667.44 3304 3355 29.4 4923 82 17:48:36 Alarm Delta Stage At Top Perf = 12 6780.2 4329 4366 37.2 5625 83 17:53:00 Ball on Seat Ball 8 on Seat 6919.4 2197 2229 12.3 3869 84 17:53:11 Break Formation Break Formation 6921.67 4533 4614 12.4 5984 85 17:54:28 Alarm Delta Stage At Top Perf = 13 6938.25 2673 2727 16.5 4202 86 17:55:49 Alarm Delta Stage At Top Perf = 1 6968.43 3584 3669 30.3 4953 87 17:59:55 Alarm Delta Stage At Top Perf = 2 7108.42 3694 3772 32.7 5152 88 18:10:42 Alarm Delta Stage At Top Perf = 3 7505.91 3661 3754 36.9 5177 89 18:12:02 Alarm Delta Stage At Top Perf = 4 7555.12 3697 3781 36.9 5204 90 18:13:48 Alarm Delta Stage At Top Perf = 5 7620.35 3704 3784 36.9 5218 91 18:16:44 Alarm Delta Stage At Top Perf = 6 7728.57 3757 3841 36.8 5256 92 18:20:25 Alarm Delta Stage At Top Perf = 7 7864.39 3792 3880 36.9 5284 93 18:24:19 Alarm Delta Stage At Top Perf = 8 8008.13 3842 3925 36.8 5330 94 18:28:20 Alarm Delta Stage At Top Perf = 9 8155.87 3943 4037 36.8 5427 95 18:32:45 Alarm Delta Stage At Top Perf = 10 8318.62 4036 4124 36.8 5513 96 18:36:47 Start Flush Start Flush 8466.91 4045 4109 37.1 5593 97 18:37:30 Alarm Delta Stage At Top Perf = 11 8493.56 4161 4232 37.2 5579 98 18:40:47 Alarm Delta Stage At Top Perf = 12 8615.65 4426 4481 37.2 5551 99 18:44:53 Alarm Delta Stage At Top Perf = 13 8767.69 777 791 17.6 4096 100 18:45:03 ISIP ISIP 8767.85 1433 1474 0 3166 101 18:49:58 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 8767.85 270 324 0 3088 102 18:55:00 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 8767.85 24 16 0 3017 103 19:00:02 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 8767.85 57 38 0 2973 104 19:05:05 Shut In Pressure @ 20 Minutes Shut In Pressure @ 20 Minutes 8767.85 169 191 0 2833 105 19:10:01 Shut In Pressure @ 25 Minutes Shut In Pressure @ 25 Minutes 8767.85 199 229 0 2764 Event Log 10.25 Conoco Phillips 3T 603 Event Log 10.25 191 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:58:53 (10/26/24) Other Crew Arrived on Location 2 7:04:44 Other Waiting on Water 12 of 20 Tanks Loaded 3 7:43:38 Other Begin Function Test Equipment 4 9:26:14 Start Job Starting Job 0 0 0 0 0 1 09:26:14 (10/26/24) Next Treatment Treatment Interval 1 0 0 0 0 0 5 9:48:45 Other Bring on Brine 12.81 124 34 0 0 6 9:58:18 Prime Pumps Prime Pumps 12.81 54 351 0 0 7 10:12:03 Pressure Test ePRV Primary Tubing 12.81 180 318 0 2190 8 10:25:11 Pressure Test ePRV Secondary IA 12.81 420 505 0 2188 9 10:27:08 Pressure Test ePRV Secondary Tubing 12.81 450 537 0 2188 10 10:28:37 Pressure Test ePRV Primary IA 12.81 493 580 0 2188 11 10:31:18 Pressure Test Pressure Test Global 12.81 527 221 0 2188 12 10:34:28 Pressure Test Pressure Test Local 12.81 522 525 0 2188 13 10:40:42 Pressure Test Pressure Test Begin 12.81 9389 9469 0 2187 14 10:45:41 Pressure Test Pressure Test Pass 12.81 9323 9374 0 2187 15 10:58:27 Pre Job Safety Meeting Pre Job Safety Meeting 12.81 1 30 0 2186 16 11:14:30 Other Bring OnChemicals and Mix Gel 12.81 8 32 0 2184 9 11:43:59 (10/26/24) Next Treatment Treatment Interval 9 12.81 11 32 0 2188 17 11:50:57 Open Well Open Well 12.81 376 421 0 2209 18 11:53:45 Drop Ball Drop Ball9 26.83 1559 1687 10.2 3289 19 12:17:25 Ball on Seat Ball 9 on Seat 274.06 1581 1655 10.5 3440 20 12:17:48 Break Formation Break Formation 278.26 2170 2244 10.5 3912 21 12:17:50 Other Start DFIT 278.6 2133 2199 10.5 3853 22 12:20:20 Alarm Delta Stage At Top Perf = 4 304.8 2137 2214 10.5 3924 23 12:21:46 ISIP ISIP 317.48 1108 1107 0 3086 24 12:51:17 Open Well Open Well 317.48 488 482 0 2494 25 12:53:16 Alarm Delta Stage At Top Perf = 5 328.85 2711 2812 15.4 4353 26 13:01:12 Start Pad Start Pad 487.46 2917 2994 20.2 4465 27 13:04:12 Alarm Delta Stage At Top Perf = 6 572.04 4547 4636 36.9 5671 28 13:05:13 Alarm Delta Stage At Top Perf = 8 609.68 4581 4669 37 5710 29 13:10:05 Alarm Delta Stage At Top Perf = 9 790.36 4625 4705 37.5 5806 30 13:13:40 Alarm Delta Stage At Top Perf = 10 924.06 4524 4602 37.2 5759 31 13:24:43 Alarm Delta Stage At Top Perf = 11 1309.35 3950 4084 36.3 5446 32 13:26:12 Alarm Delta Stage At Top Perf = 12 1362.82 3803 3917 36 5289 33 13:29:43 Alarm Delta Stage At Top Perf = 13 1480.9 3257 3289 29.9 4849 34 13:32:30 Alarm Delta Stage At Top Perf = 14 1583.87 3904 4042 37 5388 35 13:36:07 Alarm Delta Stage At Top Perf = 15 1715.62 3851 3971 36.3 5344 36 13:40:04 Alarm Delta Stage At Top Perf = 16 1858.21 3833 3936 35.8 5323 37 13:44:19 Alarm Delta Stage At Top Perf = 17 2009.78 3817 3908 35 5304 38 13:48:52 Alarm Delta Stage At Top Perf = 18 2168.97 3761 3887 34.6 5315 39 13:53:54 Alarm Delta Stage At Top Perf = 19 2339.63 3735 3803 31.9 5141 40 13:53:57 Drop Ball Drop Ball 10 2341.23 3740 3810 31.9 5147 10 13:54:00 (10/26/24) Next Treatment Treatment Interval 10 2342.82 3744 3815 31.9 5148 41 13:57:10 Alarm Delta Stage At Top Perf = 20 2450.03 4409 4477 36.9 5618 42 14:01:11 Ball on Seat Ball 10 on Seat 2578.83 2795 2845 12.6 4416 43 14:01:21 Break Formation Break Formation 2580.94 5489 5555 12.7 6801 44 14:01:30 Alarm Delta Stage At Top Perf = 21 2583.05 4064 4081 12.7 5575 45 14:03:58 Alarm Delta Stage At Top Perf = 1 2629.68 5614 5697 29.3 6924 46 14:08:02 Alarm Delta Stage At Top Perf = 2 2764.48 5398 5469 34.5 6799 47 14:17:35 Alarm Delta Stage At Top Perf = 3 3114.39 4112 4160 36.8 5547 48 14:18:56 Alarm Delta Stage At Top Perf = 4 3164.11 3966 4008 36.8 5419 49 14:21:34 Alarm Delta Stage At Top Perf = 5 3261.14 3908 3960 36.8 5354 50 14:25:01 Alarm Delta Stage At Top Perf = 6 3388.6 3930 3989 37 5386 51 14:28:35 Alarm Delta Stage At Top Perf = 7 3519.83 3877 3938 37 5320 52 14:32:20 Alarm Delta Stage At Top Perf = 8 3658.35 3906 3969 36.9 5357 53 14:36:34 Alarm Delta Stage At Top Perf = 9 3814.6 3907 3987 36.9 5367 54 14:40:48 Alarm Delta Stage At Top Perf = 10 3970.6 4039 4108 36.9 5456 55 14:45:39 Drop Ball Drop Ball 11 4145.2 3606 3657 30.7 5031 56 14:45:40 Alarm Delta Stage At Top Perf = 11 4145.71 3607 3659 30.7 5031 11 14:45:41 (10/26/24) Next Treatment Treatment Interval 11 4146.23 3611 3663 30.7 5026 57 14:48:46 Alarm Delta Stage At Top Perf = 12 4255.62 4447 4510 36.9 5558 58 14:52:29 Ball on Seat Ball 11 on Seat 4378.96 3276 3271 17.7 4583 59 14:52:35 Alarm Delta Stage At Top Perf = 13 4380.66 4768 4795 16.5 5696 60 14:52:43 Break Formation Break Formation 4382.85 5400 5431 16.2 6770 61 14:54:49 Alarm Delta Stage At Top Perf = 1 4425.7 5409 5444 30.3 6532 62 14:58:50 Alarm Delta Stage At Top Perf = 2 4570.46 5187 5218 37.1 6360 63 15:08:33 Alarm Delta Stage At Top Perf = 3 4930.66 4037 4081 37 5400 64 15:09:54 Alarm Delta Stage At Top Perf = 4 4980.59 3891 3933 37 5288 65 15:11:38 Alarm Delta Stage At Top Perf = 5 5044.69 3747 3792 36.9 5175 66 15:14:35 Alarm Delta Stage At Top Perf = 6 5153.73 3594 3650 36.9 5044 67 15:18:15 Alarm Delta Stage At Top Perf = 7 5289.05 3521 3588 36.9 4988 68 15:22:07 Alarm Delta Stage At Top Perf = 8 5431.64 3544 3597 36.9 4982 69 15:26:23 Alarm Delta Stage At Top Perf = 9 5588.72 3613 3673 36.8 5047 70 15:30:48 Alarm Delta Stage At Top Perf = 10 5751.07 3652 3721 36.7 5083 71 15:35:44 Alarm Delta Stage At Top Perf = 11 5928.31 3038 3084 29.4 4593 12 15:36:04 (10/26/24) Next Treatment Treatment Interval12 5938.09 3092 3140 29.3 4600 72 15:36:04 Drop Ball Drop Ball12 5938.09 3093 3140 29.3 4600 73 15:38:54 Alarm Delta Stage At Top Perf = 12 6037.38 3927 3984 37 5162 74 15:42:29 Ball on Seat Ball 12 on Seat 6158.89 2432 2461 12.5 3980 75 15:42:48 Break Formation Break Formation 6163.01 6368 6384 12.3 7835 76 15:43:24 Alarm Delta Stage At Top Perf = 13 6170.43 3535 3496 12.4 4842 77 15:45:43 Alarm Delta Stage At Top Perf = 1 6210.03 5857 5899 26 7130 78 15:50:20 Alarm Delta Stage At Top Perf = 2 6348.29 5844 5833 30.9 7144 79 16:00:54 Alarm Delta Stage At Top Perf = 3 6733.62 3692 3706 37 5101 80 16:02:14 Alarm Delta Stage At Top Perf = 4 6783.01 3520 3558 37 4963 81 16:03:59 Alarm Delta Stage At Top Perf = 5 6847.83 3458 3494 37 4893 82 16:06:54 Alarm Delta Stage At Top Perf = 6 6955.77 3426 3471 37 4877 83 16:10:35 Alarm Delta Stage At Top Perf = 7 7091.91 3398 3446 36.9 4856 84 16:14:27 Alarm Delta Stage At Top Perf = 8 7234.55 3437 3488 36.9 4882 85 16:18:44 Alarm Delta Stage At Top Perf = 9 7392.38 3507 3561 36.8 4940 86 16:23:09 Alarm Delta Stage At Top Perf = 10 7554.76 3556 3612 36.7 4982 87 16:26:01 Other Mover Shut 7659.27 3575 3637 36.7 4993 88 16:27:54 Alarm Delta Stage At Top Perf = 11 7729.85 3849 3905 37.8 5119 89 16:31:11 Alarm Delta Stage At Top Perf = 12 7852.33 3945 4015 37.2 5077 90 16:33:44 ISIP ISIP 7946.53 3410 3470 37 4423 91 16:35:01 ISIP ISIP 7988.21 1491 1521 0 3166 92 16:39:57 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 7988.21 99 16 0 3046 93 16:44:59 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 7988.21 9 43 0 2964 94 16:49:58 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 7988.21 6 36 0 2903 Event Log 10.26 Conoco Phillips 3T 603 Event Log 10.26 192 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 15:28:06 (10/31/24) Other Slickline BeginsDemobilization 2 15:37:48 Other Begin Rig UpDart Dropper 3 15:56:10 Start Job Starting Job 0 0 0 0 0 1 15:56:10 (10/31/24) NextTreatment Treatment Interval 1 0 0 0 0 0 13 15:56:38 (10/31/24) NextTreatment Treatment Interval 13 0 79 39 0 0 4 16:48:36 Other Bucket Test ADP 0 90 39 0 2132 5 17:29:17 Pre Job Safety Meeting Pre Job Safety Meeting 0 107 40 0 2132 6 18:14:12 Prime Pumps Prime Pumps 0 74 61 0 2132 7 18:29:33 Pressure Test ePRV Primary Tubing 0 698 429 0 2132 8 18:30:42 Pressure Test ePRV Primary IA 0 843 678 0 2132 9 18:32:53 Pressure Test ePRV Secondary Tubing 0 983 989 0 2131 10 18:34:17 Pressure Test ePRV Secondary IA 0 1023 414 0 2131 11 18:38:27 Pressure Test Pressure Test Locals 0 1018 210 0 2131 12 18:39:22 Pressure Test Pressure Test Global 0 1169 1170 0 2131 13 18:45:03 Pressure Test Pressure Test Begin 0 9498 9406 0 2131 14 18:49:58 Pressure Test Pressure Test Pass 0 9375 9261 0 2131 15 19:13:35 Open Well Open Well 0 639 530 0 2129 16 19:17:41 Drop Ball Drop Ball 13 25.73 2037 2001 15.6 3173 17 19:26:48 Start Pad Start Pad 171.72 1675 1630 16.2 3224 18 19:32:05 Ball on Seat Ball 13 on Seat 248.49 1340 1290 12.5 2890 19 19:32:21 Break Formation Break Formation 251.61 3032 3067 12.4 4595 20 19:33:15 Alarm Delta Stage At Top Perf = 4 262.76 2579 2504 12.4 4073 21 19:35:16 Alarm Delta Stage At Top Perf = 5 297.62 2882 2929 25.1 4224 22 19:39:18 Alarm Delta Stage At Top Perf = 6 434.62 3487 3589 37.2 4590 23 19:43:10 Alarm Delta Stage At Top Perf = 7 579.96 3463 3556 37.5 4525 24 19:53:53 Alarm Delta Stage At Top Perf = 8 978.87 3308 3476 37 4604 25 19:55:14 Alarm Delta Stage At Top Perf = 9 1028.82 3327 3480 37 4622 26 19:57:00 Alarm Delta Stage At Top Perf = 10 1094.15 3359 3518 37 4639 27 19:59:57 Alarm Delta Stage At Top Perf = 11 1203.26 3407 3579 37 4710 28 20:03:38 Alarm Delta Stage At Top Perf = 12 1339.42 3461 3636 37 4749 29 20:07:30 Alarm Delta Stage At Top Perf = 13 1482.34 3517 3703 37 4812 30 20:11:52 Alarm Delta Stage At Top Perf = 14 1643.63 3587 3776 36.9 4868 31 20:13:57 Other Drop Rate Blender Lost Suction 1717.69 1067 1014 16.4 3371 32 20:19:37 Alarm Delta Stage At Top Perf = 15 1806.34 3008 3055 26.6 4388 33 20:35:40 Alarm Delta Stage At Top Perf = 16 2372.64 2918 3030 35.1 4270 34 20:42:13 Drop Ball Drop Ball 14 2594.03 2753 2758 26.8 4180 14 20:42:13 (10/31/24) NextTreatment Treatment Interval 14 2594.03 2754 2757 26.8 4183 35 20:45:41 Alarm Delta Stage At Top Perf = 17 2695.17 3310 3363 33.7 4543 36 20:48:37 Ball on Seat Ball 14 on Seat 2795.17 1739 1653 20.1 3402 37 20:48:56 Break Formation Break Formation 2799.73 4365 4360 11.6 6048 38 20:49:14 Alarm Delta Stage At Top Perf = 18 2803.17 3574 3499 11.4 5169 39 20:50:15 Alarm Delta Stage At Top Perf = 19 2814.66 3250 3185 11.3 4793 40 20:51:59 Alarm Delta Stage At Top Perf = 1 2842.91 4665 4639 23.6 5995 41 20:56:17 Alarm Delta Stage At Top Perf = 2 2977.04 4498 4512 33 5758 42 21:06:59 Alarm Delta Stage At Top Perf = 3 3347.42 3259 3240 34.9 4617 43 21:08:25 Alarm Delta Stage At Top Perf = 4 3397.54 3169 3148 35 4549 44 21:10:17 Alarm Delta Stage At Top Perf = 5 3462.92 3062 3032 35 4444 45 21:13:22 Alarm Delta Stage At Top Perf = 6 3570.89 3003 2971 35 4394 46 21:17:16 Alarm Delta Stage At Top Perf = 7 3707.4 3002 2960 35 4389 47 21:21:21 Alarm Delta Stage At Top Perf = 8 3850.18 3029 2988 35 4413 48 21:25:51 Alarm Delta Stage At Top Perf = 9 4007.63 3108 3078 35.1 4461 49 21:30:32 Alarm Delta Stage At Top Perf = 10 4171.62 3264 3229 35 4550 50 21:35:33 Alarm Delta Stage At Top Perf = 11 4347.07 3079 2999 33.7 4524 15 21:36:43 (10/31/24) NextTreatment Treatment Interval 15 4381.97 3048 2978 29.8 4314 51 21:36:44 Drop Ball Drop Ball 15 4382.47 3049 2980 29.8 4309 52 21:39:02 Alarm Delta Stage At Top Perf = 12 4460.01 3550 3477 35.4 4662 53 21:43:26 Alarm Delta Stage At Top Perf = 13 4580.37 2677 2595 12.1 3919 54 21:43:27 Ball on Seat Ball 15 on Seat 4580.37 2680 2597 12.1 3924 55 21:43:52 Break Formation Break Formation 4584.8 7403 7279 3.2 9088 56 22:07:03 Other Bleed Off on Surface 4586.07 6642 6457 0 8549 57 22:36:35 Alarm Delta Stage At Top Perf = 1 4621.68 6608 6462 2.8 5399 58 22:54:42 Alarm Delta Stage At Top Perf = 2 4757.73 3108 3036 15.1 4687 59 22:59:20 Alarm Delta Stage At Top Perf = 3 4827.97 2378 2328 15.2 3765 60 23:08:11 Alarm Delta Stage At Top Perf = 4 5088.13 3055 3140 35.4 4228 61 23:12:00 Alarm Delta Stage At Top Perf = 5 5223.54 2933 3029 35.5 4167 62 23:21:52 Alarm Delta Stage At Top Perf = 6 5571.12 2839 2883 35.1 4169 63 23:23:28 Alarm Delta Stage At Top Perf = 7 5627.15 2811 2847 35 4202 64 23:25:39 Alarm Delta Stage At Top Perf = 8 5703.62 2818 2850 35 4249 65 23:28:43 Alarm Delta Stage At Top Perf = 9 5810.96 2860 2892 35 4310 66 23:32:37 Alarm Delta Stage At Top Perf = 10 5947.27 2886 2912 35 4342 67 23:36:40 Alarm Delta Stage At Top Perf = 11 6088.8 2937 2969 34.9 4398 68 23:41:25 Alarm Delta Stage At Top Perf = 12 6254.64 3000 3032 34.9 4453 69 23:43:40 Other Blender LostSuction 6333.21 2997 3021 34.9 4426 70 23:48:40 Alarm Delta Stage At Top Perf = 13 6418.89 2323 2309 15.6 3923 71 0:05:08 Drop Ball Drop Ball 16 6909.33 2829 2828 29.7 4253 16 00:05:10 (11/01/24) NextTreatment Treatment Interval 16 6909.83 2835 2830 29.7 4253 72 0:06:22 Alarm Delta Stage At Top Perf = 14 6947.73 3333 3349 35.2 4591 73 0:11:32 Alarm Delta Stage At Top Perf = 16 7095.89 2189 2173 12.1 3750 74 0:11:57 Ball on Seat Ball 16 on Seat 7100.93 2239 2227 12.1 3768 75 0:12:12 Break Formation Break Formation 7103.75 3127 3105 12 4692 76 0:14:34 Alarm Delta Stage At Top Perf = 1 7142.11 3458 3444 26.4 4787 77 0:18:45 Alarm Delta Stage At Top Perf = 2 7275.61 3262 3263 33.1 4603 78 0:30:00 Alarm Delta Stage At Top Perf = 3 7646.49 2711 2718 32.8 4194 79 0:31:31 Alarm Delta Stage At Top Perf = 4 7696.29 2647 2654 32.8 4150 80 0:33:30 Alarm Delta Stage At Top Perf = 5 7761.41 2619 2635 32.8 4108 81 0:36:48 Alarm Delta Stage At Top Perf = 6 7869.71 2619 2637 32.8 4102 82 0:40:57 Alarm Delta Stage At Top Perf = 7 8005.83 2616 2635 32.8 4112 83 0:45:19 Alarm Delta Stage At Top Perf = 8 8149.1 2693 2717 32.8 4138 84 0:50:06 Alarm Delta Stage At Top Perf = 9 8306.02 2758 2778 32.8 4197 85 0:55:03 Alarm Delta Stage At Top Perf = 10 8468.17 2793 2814 32.7 4220 86 1:00:24 Alarm Delta Stage At Top Perf = 11 8643.3 2787 2821 32.8 4238 87 1:01:10 Start Flush Start Flush 8667.97 2828 2843 32.9 4249 88 1:04:07 Alarm Delta Stage At Top Perf = 12 8765.36 3036 3074 33 4277 89 1:08:18 ISIP ISIP 8898.92 1365 286 0 3088 90 1:13:02 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 8898.92 99 45 0 3048 91 1:18:05 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 8898.92 52 10 0 3015 92 1:22:57 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 8898.92 46 14 0 2995 Event Log 10.31 Conoco Phillips 3T 603 Event Log 10.31 193 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 12:58:06 (11/01/24) Other Crew Arrived on Location 2 13:00:14 Pre Job Safety Meeting Pre Job Safety Meeting 3 13:15:04 Other Turn on and Begin Function Testing Equipment 4 13:47:21 Start Job Starting Job 0 0 0 0 0 1 13:47:21 (11/01/24) Next Treatment Treatment Interval 1 0 0 0 0 0 17 14:00:33 (11/01/24) Next Treatment Treatment Interval 17 5.48 4 2 0 2194 5 15:00:20 Prime Pumps Prime Pumps 5.48 152 172 0 2186 6 15:14:45 Pressure Test ePRV Primary Tubing 5.48 332 343 0 2185 7 15:16:21 Pressure Test ePRV Primary IA 5.48 744 268 0 2185 8 15:19:12 Pressure Test ePRV Secondary Tubing 5.48 843 884 0 2184 9 15:20:50 Pressure Test ePRV Secondary IA 5.48 866 289 0 2184 10 15:24:23 Pressure Test Pressure Test Global 5.48 858 159 0 2184 11 15:24:42 Pressure Test Pressure Test Locals 5.48 858 160 0 2184 12 15:29:56 Pressure Test Pressure Test Begin 5.48 9497 9444 0 2183 13 15:34:53 Pressure Test Pressure Test Pass 5.48 9336 9271 0 2183 14 15:57:50 Open Well Open Well 5.48 430 367 0 2193 15 15:59:52 Other Load Ball 17 14.2 1677 1710 12.9 3145 16 16:00:40 Drop Ball Drop Ball 17 25.55 1601 1601 14.6 3047 17 16:13:21 Ball on Seat Ball 17 on Seat 210.51 1254 1218 10.6 3043 18 16:13:29 Break Formation Break Formation 211.75 2884 2934 10.6 4644 19 16:14:01 Other Start DFIT 217.53 2078 2036 10.5 3837 20 16:15:09 Alarm Delta Stage At Top Perf = 4 229.42 2017 1980 10.5 3782 21 16:17:30 Alarm Delta Stage At Top Perf = 5 254.01 1973 1941 10.5 3718 22 16:17:49 ISIP ISIP 255.95 1154 978 0 3167 23 16:22:57 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 255.95 981 702 0 2750 24 16:27:56 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 255.95 881 415 0 2518 25 16:32:55 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 255.95 799 216 0 2375 26 16:49:22 Open Well Open Well 256.01 500 491 0.8 2362 27 16:59:48 Alarm Delta Stage At Top Perf = 6 442.1 2230 2204 20.3 3765 28 17:01:43 Alarm Delta Stage At Top Perf = 8 481.02 2245 2222 20.3 3728 29 17:07:46 Other Shut Down to Trouble Shoot LA 4 on the ADP 603.34 2564 2539 20.2 3982 30 17:23:06 Start Pad Start Pad 735.75 2664 2619 14.9 4152 31 17:30:08 Alarm Delta Stage At Top Perf = 9 964.91 2983 2984 36.8 4182 32 17:33:42 Alarm Delta Stage At Top Perf = 10 1096.13 3006 3011 36.8 4204 33 17:42:09 Alarm Delta Stage At Top Perf = 11 1407.17 2873 2898 36.9 4238 34 17:43:40 Alarm Delta Stage At Top Perf = 12 1463.1 2856 2872 36.8 4223 35 17:45:26 Alarm Delta Stage At Top Perf = 13 1528.18 2815 2852 36.8 4210 36 17:48:23 Alarm Delta Stage At Top Perf = 14 1636.84 2807 2846 36.8 4210 37 17:52:05 Alarm Delta Stage At Top Perf = 15 1773.06 2833 2865 36.8 4219 38 17:55:57 Alarm Delta Stage At Top Perf = 16 1915.3 2820 2862 36.8 4220 39 18:00:15 Alarm Delta Stage At Top Perf = 17 2073.35 2845 2905 36.7 4250 40 18:04:41 Alarm Delta Stage At Top Perf = 18 2236.15 2906 2938 36.7 4273 41 18:09:28 Alarm Delta Stage At Top Perf = 19 2411.53 2938 2978 36.9 4302 18 18:11:17 (11/01/24) Next Treatment Treatment Interval 18 2470.65 2556 2549 28.9 3981 42 18:11:24 Drop Ball Drop Ball 18 2474.02 2563 2558 28.9 3988 43 18:13:06 Alarm Delta Stage At Top Perf = 20 2527.95 3128 3153 36.8 4321 44 18:17:15 Alarm Delta Stage At Top Perf = 21 2643.36 2263 2258 12.6 3736 45 18:17:45 Ball on Seat Ball 18 on Seat 2649.64 2338 2346 12.6 3757 46 18:18:06 Break Formation Break Formation 2653.93 6943 6896 4.1 9201 47 18:44:30 Other Bleed Pressure on Surface 2658.69 3103 3357 0 6437 48 18:53:53 Alarm Delta Stage At Top Perf = 1 2687.6 4229 4167 13.2 4328 49 19:03:18 Start Pad Start Pad 2827.41 2425 2412 15 4017 50 19:03:19 Alarm Delta Stage At Top Perf = 2 2827.66 2423 2410 15 4012 51 19:05:19 Alarm Delta Stage At Top Perf = 3 2878.65 2813 2979 36.7 3977 52 19:09:48 Alarm Delta Stage At Top Perf = 4 3044.97 2837 2964 37.2 3994 53 19:13:36 Alarm Delta Stage At Top Perf = 5 3186.42 2945 2975 37.2 4110 54 19:23:57 Alarm Delta Stage At Top Perf = 6 3570.4 2727 2783 36.9 4095 55 19:25:18 Alarm Delta Stage At Top Perf = 7 3620.26 2774 2826 36.9 4136 56 19:27:05 Alarm Delta Stage At Top Perf = 8 3685.99 2788 2844 36.8 4174 57 19:30:32 Alarm Delta Stage At Top Perf = 9 3812.93 2809 2869 36.8 4216 58 19:34:13 Alarm Delta Stage At Top Perf = 10 3948.39 2808 2884 36.7 4248 59 19:38:11 Alarm Delta Stage At Top Perf = 11 4094.06 2832 2907 36.7 4258 60 19:42:27 Alarm Delta Stage At Top Perf = 12 4250.54 2871 2960 36.6 4292 61 19:46:55 Alarm Delta Stage At Top Perf = 13 4413.99 2945 3026 36.5 4337 62 19:51:46 Alarm Delta Stage At Top Perf = 14 4591.16 3018 3107 36.6 4388 63 19:54:03 Drop Ball Drop Ball 19 4666.37 2540 2567 28.4 4037 19 19:54:04 (11/01/24) Next Treatment Treatment Interval 19 4666.84 2545 2569 28.4 4040 64 19:55:20 Alarm Delta Stage At Top Perf = 15 4705.74 3094 3175 35.7 4359 65 19:59:15 Alarm Delta Stage At Top Perf = 16 4826.67 2081 2108 13.2 3717 66 19:59:26 Ball on Seat Ball 19 on Seat 4829.09 2103 2132 13.3 3741 67 19:59:43 Break Formation Break Formation 4832.84 6584 6642 13.1 8181 68 20:02:14 Alarm Delta Stage At Top Perf = 1 4876.34 4989 5064 27.6 6366 69 20:06:11 Alarm Delta Stage At Top Perf = 2 5015.04 4159 4196 36.9 5472 70 20:14:36 Other Hole on Pump 254 Hose 5326.19 3186 3256 38.7 4588 71 20:25:24 Alarm Delta Stage At Top Perf = 3 5376.36 3534 3667 28.5 4472 72 20:26:53 Alarm Delta Stage At Top Perf = 4 5426.65 3407 3550 36.3 4481 73 20:28:41 Alarm Delta Stage At Top Perf = 5 5492.23 2833 2973 36.5 4164 74 20:41:30 Alarm Delta Stage At Top Perf = 6 5957.97 2507 2603 36.1 4000 75 20:44:51 Alarm Delta Stage At Top Perf = 7 6079.04 2427 2522 36.1 3923 76 20:48:48 Alarm Delta Stage At Top Perf = 8 6221.59 2453 2547 36.1 3936 77 20:53:11 Alarm Delta Stage At Top Perf = 9 6379.65 2478 2583 36 3951 78 20:57:43 Alarm Delta Stage At Top Perf = 10 6542.92 2494 2606 36.1 3966 79 21:02:41 Alarm Delta Stage At Top Perf = 11 6722.39 2605 2727 36.3 3993 80 21:03:38 Start Flush Start Flush 6756.52 2673 2780 36.8 4025 81 21:05:53 Alarm Delta Stage At Top Perf = 12 6840.34 2908 2990 37 4081 82 21:09:22 ISIP ISIP 6964.79 1361 1427 0 3191 83 21:14:14 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 6964.79 56 38 0 3113 84 21:19:14 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 6964.79 46 34 0 3080 85 21:24:15 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 6964.79 27 4 0 3055 Event Log 11.1 Conoco Phillips 3T 603 Event Log 11.1 194 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 08:59:26 (11/02/24) Other Crew Arrived on Location 2 9:15:42 Pre JobSafety Meeting Pre JobSafety Meeting 3 9:29:43 Other Begin Function Test Equipment 4 10:03:01 Start Job StartingJob 0 0 0 0 0 1 10:03:01 (11/02/24) Next Treatment Treatment Interval 1 0 0 0 0 0 20 10:07:21 (11/02/24) Next Treatment Treatment Interval 20 18.23 85 32 4.2 2204 5 10:32:11 Other Ensure no Leaks on Blender Repair 23.32 92 32 0 2201 6 10:35:56 Other Loop Test 23.32 92 32 0 2201 7 10:48:04 Prime Pumps Prime Pumps 23.32 124 180 0 2199 8 11:00:34 Pressure Test ePRV Primary Tubing 23.32 289 302 0 2198 9 11:02:23 Pressure Test ePRV Primary IA 23.32 875 271 0 2198 10 11:10:03 Pressure Test ePRV Secondary Tubing 23.32 900 262 0 2197 11 11:13:09 Pressure Test ePRV Secondary IA 23.32 911 289 0 2197 12 11:16:51 Pressure Test Pressure Test Global 23.32 906 186 0 2196 13 11:17:20 Pressure Test Pressure Test Locals 23.32 906 186 0 2196 14 11:22:36 Pressure Test Pressure Test Begin 23.32 9531 9488 0 2196 15 11:27:41 Pressure Test Pressure Test Pass 23.32 9362 9309 0 2195 16 11:51:06 Open Well Open Well 23.32 403 356 0 2183 17 11:53:01 Other Load Ball 20 32.97 1218 1286 14.4 2690 18 11:54:22 Drop Ball Drop Ball 20 52.77 1412 1458 15.6 2858 19 12:00:01 Other Pressure Anamoly 165.3 1770 1754 20.1 3275 20 12:03:45 Alarm Delta Stage At Top Perf = 1 219.25 1381 1467 12.9 2985 21 12:04:09 Alarm Delta Stage At Top Perf = 4 224.41 1404 1498 12.9 2972 22 12:05:50 Start Pad Start Pad 246.09 1564 1690 12.9 2935 23 12:06:39 Alarm Delta Stage At Top Perf = 5 256.57 1655 1801 12.8 2942 24 12:19:41 Alarm Delta Stage At Top Perf = 6 458.22 2200 2230 16.6 3799 25 12:21:45 Other Drop Back Up Ball for Interval 20 492.54 1999 2030 16.6 3607 26 12:22:45 Alarm Delta Stage At Top Perf = 7 510.41 2040 2111 19.6 3587 27 12:27:44 Other Pressure Anomaly 609.42 1947 2035 20 3471 28 12:31:00 Ball on Seat Ball 20 onSeat 654.91 1774 1877 12.7 3110 29 12:31:17 Break Formation Break Formation 658.49 5436 5518 12.5 6950 30 12:34:01 Alarm Delta Stage At Top Perf = 8 698.22 5305 5367 19 6506 31 12:35:12 Alarm Delta Stage At Top Perf = 9 723.53 5322 5372 23.9 6491 32 12:37:58 Alarm Delta Stage At Top Perf = 10 810.8 5455 5495 36.7 6517 33 12:41:31 Alarm Delta Stage At Top Perf = 11 942.03 4287 4341 37.2 5348 34 12:52:44 Alarm Delta Stage At Top Perf = 12 1359.68 3141 3247 37.1 4327 35 12:54:03 Alarm Delta Stage At Top Perf = 13 1408.51 2987 3084 37.1 4157 36 12:55:49 Alarm Delta Stage At Top Perf = 14 1473.98 2797 2915 37 4004 37 12:58:45 Alarm Delta Stage At Top Perf = 15 1582.64 2705 2829 37 3912 38 13:02:26 Alarm Delta Stage At Top Perf = 16 1719.03 2676 2814 37 3870 39 13:06:19 Alarm Delta Stage At Top Perf = 17 1862.82 2660 2797 37 3881 40 13:07:59 Other Chunky Proppant 1923.82 2654 2786 37 3868 41 13:10:57 Alarm Delta Stage At Top Perf = 18 2034.09 2660 2783 36.9 3872 42 13:15:18 Alarm Delta Stage At Top Perf = 19 2194.51 2651 2807 36.8 3855 43 13:20:02 Alarm Delta Stage At Top Perf = 20 2368.84 2723 2868 36.9 3903 44 13:22:46 Drop Ball Drop Ball for interval 21 2460.96 2530 2631 28.4 3698 21 13:22:47 (11/02/24) NextTreatment Treatment Interval 21 2460.96 2535 2633 28.4 3695 45 13:23:28 Alarm Delta Stage At Top Perf = 21 2482.04 2887 2960 33.4 3869 46 13:28:16 Alarm Delta Stage At Top Perf = 22 2612.75 2388 2507 12.6 3572 47 13:28:39 Ball on Seat Ball 21 onSeat 2617.37 2412 2525 12.6 3578 48 13:28:51 Break Formation Break Formation 2620.08 5028 5128 12.5 6178 49 13:30:52 Alarm Delta Stage At Top Perf = 1 2653.58 4934 5021 25.4 6096 50 13:34:48 Alarm Delta Stage At Top Perf = 2 2789.03 4767 4864 36.9 5745 51 13:45:04 Alarm Delta Stage At Top Perf = 3 3170.06 3196 3353 37 4196 52 13:46:28 Alarm Delta Stage At Top Perf = 4 3221.93 3129 3284 37 4118 53 13:48:21 Alarm Delta Stage At Top Perf = 5 3291 2971 3147 37 3995 54 13:49:52 Other Drop Rate to HelpSuction on Blenders 3347.07 2937 3096 36.9 3939 55 13:51:29 Alarm Delta Stage At Top Perf = 6 3400 2872 3052 34 3839 56 13:55:58 Alarm Delta Stage At Top Perf = 7 3565.56 2659 2819 36.9 3841 57 13:59:32 Alarm Delta Stage At Top Perf = 8 3697.06 2808 2984 36.8 3809 58 14:03:55 Alarm Delta Stage At Top Perf = 9 3854.46 2899 3048 35.7 3869 59 14:08:39 Alarm Delta Stage At Top Perf = 10 4028.33 2753 2924 36.7 3755 60 14:13:24 Alarm Delta Stage At Top Perf = 11 4202.06 2684 2857 36.6 3837 61 14:15:54 Drop Ball Drop Ball 22 4285.81 2481 2611 28.6 3648 22 14:15:55 (11/02/24) Next Treatment Treatment Interval 22 4286.28 2483 2612 28.6 3647 62 14:16:53 Alarm Delta Stage At Top Perf = 12 4316.62 2961 3076 36.6 3861 63 14:21:04 Alarm Delta Stage At Top Perf = 13 4431.17 2352 2483 12.7 3585 64 14:24:17 Alarm Delta Stage At Top Perf = 1 4471.38 2354 2394 12.6 3558 65 14:32:46 Drop Ball Drop Ball 22 Back Up 4578.35 1994 2030 12.6 3602 66 14:34:12 Alarm Delta Stage At Top Perf = 2 4598.94 2024 2078 16.4 3635 67 14:42:28 Alarm Delta Stage At Top Perf = 3 4726.81 1795 1917 12.7 3349 68 14:45:22 Alarm Delta Stage At Top Perf = 4 4763.47 1817 1937 12.7 3140 69 14:47:36 Alarm Delta Stage At Top Perf = 5 4792.1 2002 2134 12.6 3193 70 14:48:52 Drop Ball Drop Ball 23 4807.98 2131 2258 12.7 3255 23 14:48:53 (11/02/24) Next Treatment Treatment Interval 23 4808.19 2132 2258 12.7 3256 71 14:51:48 Alarm Delta Stage At Top Perf = 6 4851.74 2276 2381 16.7 3344 72 14:59:28 Ball on Seat Ball 23 onSeat 4954.85 3674 3757 12.1 4790 73 14:59:34 Break Formation Break Formation 4956.06 3030 3093 12.1 4204 74 15:00:13 Alarm Delta Stage At Top Perf = 18 4963.94 3361 3471 12.1 4488 75 15:01:48 Alarm Delta Stage At Top Perf = 1 4983.15 3458 3557 12.1 4551 76 15:10:09 Alarm Delta Stage At Top Perf = 2 5189.56 4366 4463 37.4 5430 77 15:19:32 Alarm Delta Stage At Top Perf = 3 5540.39 3509 3624 37.3 4707 78 15:20:52 Alarm Delta Stage At Top Perf = 4 5590.22 3066 3187 37.4 4296 79 15:22:46 Alarm Delta Stage At Top Perf = 5 5661.21 2919 3038 37.4 4148 80 15:25:40 Alarm Delta Stage At Top Perf = 6 5769.05 5376 5494 36.9 6745 81 15:30:19 Alarm Delta Stage At Top Perf = 7 5902.52 2337 2417 30.5 3412 82 15:43:59 Drop Ball Drop Ball 23 Back Up 6142.38 1757 1833 15.7 3398 83 15:48:28 Alarm Delta Stage At Top Perf = 8 6212.83 1608 1676 15.7 3334 84 15:52:45 Ball on Seat Ball 23 onSeat 6274.43 1573 1678 12.9 3290 85 15:56:14 Alarm Delta Stage At Top Perf = 9 6318.89 4251 4372 12.7 5874 86 15:56:21 Alarm Delta Stage At Top Perf = 10 6320.37 4258 4378 12.7 5869 87 15:57:29 Alarm Delta Stage At Top Perf = 11 6334.76 4385 4515 12.7 5909 88 16:05:17 Alarm Delta Stage At Top Perf = 12 6438.08 4734 4820 14.4 5928 89 16:18:41 Alarm Delta Stage At Top Perf = 13 6872.94 4091 4183 37 5367 90 16:20:02 Alarm Delta Stage At Top Perf = 14 6922.85 3737 3847 37 4984 91 16:21:50 Alarm Delta Stage At Top Perf = 15 6989.37 3083 3188 37 4290 92 16:24:46 Alarm Delta Stage At Top Perf = 16 7097.98 2668 2798 37 3901 93 16:28:27 Alarm Delta Stage At Top Perf = 17 7234.35 2538 2664 37 3729 94 16:32:21 Alarm Delta Stage At Top Perf = 18 7378.36 2599 2746 36.9 3692 95 16:36:40 Alarm Delta Stage At Top Perf = 19 7535.98 2533 2738 34.4 3655 96 16:41:22 Alarm Delta Stage At Top Perf = 20 7698.41 2600 2735 34.2 3693 97 16:46:26 Alarm Delta Stage At Top Perf = 21 7871.76 2611 2739 34.5 3690 98 16:47:33 Start Flush Start Flush 7910.59 2636 2736 34.9 3699 99 16:49:59 Alarm Delta Stage At Top Perf = 22 7995.16 2670 2690 34.8 3704 100 16:52:46 ISIP ISIP 8088.88 1431 999 0 3242 101 16:57:53 Shut In Pressure @ 5 Minutes Shut In Pressure @ 5 Minutes 8088.88 0 38 0 3113 102 17:02:54 Shut In Pressure @ 10 Minutes Shut In Pressure @ 10 Minutes 8088.88 288 320 0 3055 103 17:07:38 Shut In Pressure @ 15 Minutes Shut In Pressure @ 15 Minutes 8088.88 88 19 0 3013 Event Log 11.2 Conoco Phillips 3T 603 Event Log 11.2 195 050010001500200025003000350000:00 02:00 04:00 10:00 20:00 30:00 1:00 1:30 2:00 2:30 3:00 4:00 5:00 6:00 7:00 8:00Viscosity (cp)Time (min:sec)Prejob Crosslink Break Tests30# Opti II @ 2.0 and Opti III @ 2.030 # Opti II @ 2.0 and Opti III @ 2.0 v230 # Opti II @ 3.0 and Opti III @ 2.0Fluid is broken at 200cp 050010001500200025003000350000:00 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 @ 1.0 and Opti III @ 2.030 # Opti II @ 2.0 and Opti III @ 2.0 v130 # Opti II @ 2.0 and Opti III @ 2.0 v235 # Opti II @ 2.0 and Opti III @ 2.035 # Opti II @ 1.0 and Opti III @ 2.035 # Opti II @ 4.0 and Opti III @ 2.0Fluid is broken at 200cp 02004006008001000120014001600180000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsMini Frac0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 050010001500200025003000350000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink Tests0.5 ppg1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 050010001500200025003000350000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 0500100015002000250000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 050010001500200025003000350000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 050010001500200025003000350000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 0500100015002000250000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink Tests.25 ppg1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 0500100015002000250000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink Tests0.25 ppg1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 0500100015002000250000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink Tests0.5 ppg1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 0500100015002000250000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 020040060080010001200140016001800200000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink Tests0.5 ppg1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 05001000150020002500300000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 0500100015002000250000:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad1 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cp 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 12 355.4 355.4 0 0.0% 0.00% <0.1% 16 340.5 345.74 5.24 5.2% 18 673.1 762 88.9 88.9% 20 296.8 302.02 5.22 5.2% 25 419.8 419.84 0.04 0.0% 30 281.8 281.81 0.01 0.0% 40 408.2 408.22 0.02 0.0% Pan 306.8 306.81 0.01 0.0% 0.01% <1.0% Total: 99.44 99% Total Sample Size Seive Weight Seive Weight 100.0 g Sieve Size Before Sand With sand WT. rtn'd % rtn'd % API Spec 12 355.4 355.4 0 0.0% 0.00% <0.1% 16 340.5 345.79 5.29 5.3% 18 673.1 759.77 86.67 86.7% 20 296.8 303.66 6.86 6.9% 25 419.8 419.94 0.14 0.1% 30 281.8 281.92 0.12 0.1% 40 408.2 408.23 0.03 0.0% Pan 306.8 306.85 0.05 0.1% 0.05% <1.0% Total: 99.16 99% Conoco Phillips 3T 603 16/20 Proppant 10/22/2024 Ceramic Proppant Sieves Sample: 16/20 10/22/2024 94.17% >/= 90% Sample: 16/20 10/26/2024 93.79% >/= 90% Conoco Phillips 3T 603 Sand Sieve Analysis 219 Hydraulic Fracturing Fluid Product Component Information Disclosure 2024-10-23 Alaska HARRISON BAY 50-103-20890-00-00 CONOCOPHILLIPS 3T 603 -150.26542197 70.42076262 NAD83 none Oil 5137 2023124 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 CL-28M CROSSLINKER Halliburton Crosslinker LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker OPTIFLO-III DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant SAND, COMMON BROWN 100 MESH Halliburton Proppant Flow Insurance Copper Patina Energy Tracer Ingredients Water 7732-18-5 100.00%78.50956%17237017 Corundum 1302-74-5 65.00%13.28569%2916914 Mullite 1302-93-8 45.00%9.19778%2019402 Sodium chloride 7647-14-5 5.00%3.92548%861851 Crystalline silica, quartz 14808-60-7 100.00%0.44495%97691 Guar gum 9000-30-0 100.00%0.30793%67607 Water 7732-18-5 100.00%0.12809%28122 Borate salts Proprietary 60.00%0.09689%21274 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%0.04069%8934 Ammonium persulfate 7727-54-0 100.00%0.03961%8697 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.02034%4467 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.02034%4467 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxylated phenolic resin Proprietary 30.00%0.01188%2610 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Sodium hydroxide 1310-73-2 30.00%0.00909%1996 Potassium chloride 7447-40-7 5.00%0.00807%1773 Inorganic mineral 1317-65-3 5.00%0.00807%1773 Oxyalkylated phenolic resin Proprietary 10.00%0.00678%1489 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Naphthalene 91-20-3 5.00%0.00339%745 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00339%745 Monoethanolamine borate 26038-87-9 100.00%0.00301%661 Flow Insurance Copper Proprietary 100.00%0.00201%442 Patina Energy Product Stewardship test@patinae nergy.com 7205324886 Calcium magnesium carbonate 16389-88-1 1.00%0.00161%355 Gluteraldehyde 111-30-8 1.00%0.00161%355 Inorganic mineral Proprietary 1.00%0.00161%355 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Polymer Proprietary 1.00%0.00161%355 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00152%333 Ethylene glycol 107-21-1 30.00%0.00090%199 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00068%149 Sodium chloride 7647-14-5 1.00%0.00030%67 C.I. pigment Orange 5 3468-63-1 1.00%0.00022%48 Methanesulfonic acid, 1-hydroxy-, sodium salt 870-72-4 0.10%0.00016%36 Sodium bisulfate 7681-38-1 0.10%0.00016%36 Magnesium nitrate 10377-60-3 0.01%0.00002%4 5-Chloro-2-methyl-3(2H)- Isothaiazolone 26172-55-4 0.01%0.00002%4 2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00002%4 Magensium chloride 7786-30-3 0.01%0.00002%4 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00000%1 * Total Water Volume sources may include fresh water, produced water, and/or recycled water _ ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.4 All component information listed was obtained from the suppliers Material Safety Data Sheets (MSDS). As such, the Operator isnot 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 Administrations (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 issubject to 29 CFR 1910.1200(i) and Appendix D. Production Type: True Vertical Depth (TVD): Total Water Volume (gal)*: MSDS and Non-MSDS Ingredients are listed below the green line Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Fracture Date State: County: API Number: Operator Name: Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 1] REPORT DATE: [ 10/16/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 34,350.00 Cumulative Cost (Cost) 34,350.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary START SPOTTING EQUIPMENT 24hr Forecast COMPLETE TANK FARM General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile CAMPBELL, JAMES Frac Supervisor 661-203-1472 BROWN, KYLE Frac Supervisor 330-708-4522 CHERRY, JACOB Supervisor 907-953-9294 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 06:00 06:30 0.50 COMPZN, STIM RURD P TAILGATE MEETING 06:30 10:30 4.00 COMPZN, STIM RURD P PREP/CLEAR LOCATION FOR CONTAINMENT, 10:30 18:00 7.50 COMPZN, STIM RURD P SPOT TANKS 1-14 Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 2] REPORT DATE: [ 10/17/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 34,350.00 Cumulative Cost (Cost) 68,700.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUE BUILDING TANK FARM 24hr Forecast FINISH TANK FARM General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile BROWN, KYLE Frac Supervisor 330-708-4522 CHERRY, JACOB Supervisor 907-953-9294 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 06:00 06:30 0.50 COMPZN, STIM RURD P TAILGATE MEETING 06:30 13:30 7.00 COMPZN, STIM RURD P CONTINUE SPOTTING TANKS 15-24, LAID AND SEAMED 2nd CONTAINMENT SHEET, SPOTTED HEATERS, 13:30 16:30 3.00 COMPZN, STIM RURD P ROUND-TRIPPED TANKS FROM 3S TO THE WASH BAY FOR TANK FARM COMPLETION 16:30 21:00 4.50 COMPZN, STIM RURD P SPOTTED TANKS 20-24 Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 3] REPORT DATE: [ 10/18/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 45,750.00 Cumulative Cost (Cost) 114,450.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary COMPLETED THE TANK FARM, BEGAN HAULING/HEATING WATER 24hr Forecast SPOT FRAC EQUIPMENT General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 06:00 06:30 0.50 COMPZN, STIM RURD P TAILGATE MEETING 06:30 10:00 3.50 COMPZN, STIM RURD P PICKED UP FINAL TANK FROM THE WASH BAY, PREPPED FOR TANK SPOTTING 10:00 18:00 8.00 COMPZN, STIM RURD P SPOTTED FINAL TANK, WATER HEATER, PRESSURE TESTED MANIFOLD, INSTALLED HEAT DUCTING ON TANK MANIFOLD, ERECTED CONTAINMENT WALLS 18:00 23:59 5.99 COMPZN, STIM RURD P RECEIVED FIRST WATER TRUCK @ 5:10, HEATING/LOADING WATER Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 4] REPORT DATE: [ 10/19/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 49,600.00 Cumulative Cost (Cost) 164,050.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUED HAULING/HEATING WATER, SPOT FRAC EQUIPMENT, RIG IN PUMPS 24hr Forecast RUN HARD LINE General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM RURD P LOADING/HEATING WATER 06:00 08:00 2.00 COMPZN, STIM RURD P TRIP BLENDER AND HP TO LOCATION 08:00 18:00 10.00 COMPZN, STIM RURD P SPOT EQUIPMENT, RUN HARD LINE FROM PUMPS TO HIGH PRESSURE MANIFOLD, CONTINUE LOADING/HEATING WATER 18:00 20:00 2.00 COMPZN, STIM RURD P CONTINUE LOADING/HEATING WATER 20:00 22:00 2.00 COMPZN, STIM RURD T AT CPF3 WATER LOADING DOCK, DRIVER OVERFILLED TRUCK SPILLING~80 BBL OF SEAWATER RUNNING ACROSS THE ROAD TO THE TUNDRA, SECURITY WAS NOTIFIED SRT WAS DEPLOYED ENVIRONMENTAL WAS CONTACTED, TOTAL AREA ON PAD 80'X100' AREA AFFECTED ON TUNDRA 100'X100' 22:00 23:59 1.99 COMPZN, STIM RURD P CONTINUE HAULING/HEATING WATER Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 5] REPORT DATE: [ 10/20/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 49,600.00 Cumulative Cost (Cost) 213,650.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUED HAULING/HEATING WATER, CONTINUED RIGGING IN RUNNING THE 2 4" TREATING LINE 24hr Forecast RUN HARD LINE General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM RURD P HAULING/HEATING WATER 06:00 07:00 1.00 COMPZN, STIM RURD T SPILL ON 3J, LOADING HOSE HAND VALVE WAS NOT FULLY CLOSED, SECURITY, SRT AND ENVIRONMENTAL CONTACTED, ESTIMATED AMOUNT 15-20 BBL LOADING STATION SHUT DOWN FOR CLEANUP, 07:00 07:30 0.50 COMPZN, STIM RURD P TAILGATE MEETING 07:30 10:30 3.00 COMPZN, STIM RURD T STARTED PREPARATIONS FOR RIGGING IN 4" IRON, CRANE WAS NOT FUNCTIONING 10:30 12:00 1.50 COMPZN, STIM RURD P STARTED RUNNING 4" IRON, CPF 3 WATER LOADING STATION SHUT DOWN, INTERNAL PIPING ISSUE 12:00 18:00 6.00 COMPZN, STIM RURD P CONTINUED RUNNING 4" IRON, CPF 3 WATER LOADING STATION SHUT DOWN, INTERNAL PIPING ISSUE 18:00 23:59 5.99 COMPZN, STIM RURD P CONTINUE RIGGIG IN 4" IRON Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 6] REPORT DATE: [ 10/21/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 49,600.00 Cumulative Cost (Cost) 263,250.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUED RIGGING IN, RUNNING THE 2 4" TREATING LINES, START PROPPANT LOADING 24hr Forecast COMPLETE RIG IN General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM RURD P CONTINUED RIGGING IN HARD LINE 06:00 18:00 12.00 COMPZN, STIM RURD P CONTINUED RIGGING IN HARD LINE, SPOTTED TCC, DELIVERED THE LAST OF THE TANKS TO THE WASH BAY 18:00 23:59 5.99 COMPZN, STIM RURD P CONTINUED RIGGING IN HARD LINE, STARTED LOADING PROPPANT Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 7] REPORT DATE: [ 10/22/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 78,750.00 Cumulative Cost (Cost) 342,000.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUE RIGGING IN, NIPPLE UP LAUNCHER STACK, COMPLETE PROPPANT LOADING 24hr Forecast PUMP STAGES 1-4 General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM RURD P CONTINUE LOADING PROPPANT, CONTINUE RUNNING HARD LINE 06:00 12:00 6.00 COMPZN, STIM RURD P CONTINUE LOADING PROPPANT, CONTINUE RUNNING HARD LINE, LOAD BRINE, 12:00 18:00 6.00 COMPZN, STIM RURD P STAB ON LAUNCHER STACK, BUILD SCAFFOLDING, TIE IN RISERS, RIG IN LAUNCHER HARD LINE, SPOT FRAC SHACK 18:00 23:59 5.99 COMPZN, STIM RURD P CONTINUE LOADING PROPPANT, CONTINUE RUNNING HARD LINE TO THE LAUNCHER PUMP, LOAD THE LAST 2 LOADS OF WATER, TOP OFF TRUCKS AND STAGE THEM AT 3G, LOAD THE SHOWER TRAILER WITH FRESH WATER, INSTALL RESTRAINTS Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 8] REPORT DATE: [ 10/23/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 79,750.00 Cumulative Cost (Cost) 421,750.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUED LOADING PROPPANT, DURING WATER STRAPPING THE WTAER TEMP WAS FOUND TO BE TO LOW FOR THE FLUID SYSTEM USE, REHEATING TANKS, PRIME AND TEST, RUPTURE GLASS DISC, SHIFT ALPHA SLEEVE, PUMP THE DFIT. 24hr Forecast PUMP STAGES 1-4 General Remarks INITIAL T/I/O 187/150/136 FINAL T/I/O 885/700/132 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM RURD P CONTINUE LOADING PROPPANT 06:00 07:30 1.50 COMPZN, STIM RURD P CREW ARRIVED ON LOCATION , TAIL GATE MEETING, STARTED CHECKING TANK TEMPS, FOUND THE TEMPS WERE TO LOW. 07:30 08:00 0.50 COMPZN, STIM RURD P SAFETY MEETING 08:00 09:00 1.00 COMPZN, STIM RURD P PRE PRIME PREPERATIONS, START REHEATING TANKS 09:00 11:00 2.00 COMPZN, STIM RURD P PRIME PUMPS, LEAK ON DME HIGH PRESSURE SEAL REPLACED 11:00 12:00 1.00 COMPZN, STIM RURD P FUNCTION TESTED PRV'S, PRESSURE TESTED TO 9530, HELD FOR 5 MINUTES, ENDING 9343, GOOD TEST 12:00 14:12 2.20 COMPZN, STIM RURD P BLEW EQUIPMENT DOWN, DECISION WAS MADE TO COMPLETE THE DFIT, PRIMED EQUIPMENT 14:12 15:18 1.10 COMPZN, STIM PUMP P WELL OPEN, OPENING PSI 187, ESTABLISHED INJECTION, RAISED PSI TO 6000 PSI NO DISC BURST, RAISED PSI TO 6300 PSI NO BURST, RAISING PSI TO 6800 PSI RAISE PSI TO 7292, DISC BROKE, PRESSURING UP TOM SHIFT THE ALPHA S\LEEVE. SLEEVE SHIFTED @ 6005, 8092 BH PSI SHUT IN 20 MINUTES FOR PSI MONITORING, RESUMED PUMPING THE DFIT, WALKED RATE UP TO 20BPM, HELD FOR 2 MINUTES, HARD SHUT DOWN, SHUT IN IA, AND HYDRAULIC VALVE. 15:18 15:48 0.50 COMPZN, STIM PUMP P ISIP, PRESSURE MONITORING FOR 30 MINUTES 15:48 17:00 1.20 COMPZN, STIM PUMP P LRS PUMP 35 BBL FREEZE PROTECT 17:00 23:59 6.99 COMPZN, STIM WAIT T CONTINUE REHEATING WATER Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 8] REPORT DATE: [ 10/23/2024] Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 9] REPORT DATE: [ 10/24/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 821,455.64 Cumulative Cost (Cost) 1,243,205.64 Weather Temperature (°F) Road Condition Wind Last 24hr Summary ALPHA STAGE COMPLETED AS DESIGNED TOTAL CLEAN VOLUME PUMPED 3,464 BBL, TOTAL PROPPANT PLACED 202,974, AVG PSI 3,617 AVG RATE 29.8 BPM STAGE 2 COMPLETED AS DESIGNED BALL 2.116 SEAT 20 BBL EARLY,BREAKDOWN 6,090 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2,672 BBL, TOTAL PROPPANT PLACED 203,545, AVG PSI 4,217 AVG RATE 33.5 BPM STAGE 3 COMPLETED AS DESIGNED, BALL 2.148 SEAT 25 BBL EARLY,BREAKDOWN 5,796 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 3,294 BBL, TOTAL PROPPANT PLACED 203,299, AVG PSI 4,749 AVG RATE 34.7 BPM STAGE 4 COMPLETED AS DESIGNED, BALL 2.181 SEAT 16 BBL EARLY BREAKDOWN 5,383 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2,023 BBL, TOTAL PROPPANT PLACED 204,288, AVG PSI 3,980 AVG RATE 35.6 BPM LRS COMPLETED 35 BBL FREEZE PROTECT 24hr Forecast PUMP STAGES 5-8 General Remarks INITIAL T/I/O 580/573/166 FINAL T/I/O 1022/700/572 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM WAIT P REHEAT WATER TANKS 06:00 06:30 0.50 COMPZN, STIM WAIT P TAILGATE MEETING, FUNCTION TEST EQUIPMENT 06:30 07:00 0.50 COMPZN, STIM WAIT P SAFETY MEETING 07:00 08:00 1.00 COMPZN, STIM WAIT P CONTINUE FUNCTION TESTING EQUIPMENT, REPLACE HASKLE PUMP ON PUMP 08:00 09:00 1.00 COMPZN, STIM WAIT P PRIME PUMPS, FUNCTION TEST ePRV, PRESSURE TEST PRESSURE START 9767, PRESSURE END 9564, HELD FOR 5 MINUTES GOOD TEST. 09:00 10:00 1.00 COMPZN, STIM WAIT P LOAD BALLS FOR STAGE 2- 2.116, STAGE 3-2.148, STAGE 4-2.181, STAGE 5 -2.214 , MIX GEL, PRIME CHEMS. 10:00 10:24 0.40 COMPZN, STIM WAIT T WILLIE'S WAM SKID LEAKING 10:24 12:42 2.30 COMPZN, STIM PUMP P EQUALIZE TO 1000 PSI, WELL OPEN @ 580 PSI, ESTABLISH INJECTION, START INTERVAL WITH THE STEP RATE TEST, STAGE PUMPED TO DESIGN, TOTAL CLEAN VOLUME PUMPED 3464 TOTAL SLURRY VOLUME 3940 BBL, TOTAL PROPPANT PLACED 202,974 16/20 AVG PSI 3,617 AVG RATE 29.8 BBL BALL 1 LAUNCHED @ 3645 BBL JSV 12:42 14:03 1.35 COMPZN, STIM PUMP P BALL1 INTERVAL 2 ON SEAT @ 3940 JSV 19 BBL EARLY, SURFACE 2825 PS, PEAK 6090 PSI 3265 PSI DIFERENTIAL, BH 4489 PSI, BH PEAK, 7586, DIFF: 3097 PSI, STAGE 2 COMPLETED AS DESIGNED, TOTAL CLEAN VOLUME PUMPED 2672 BBL TOTAL SLURRY VOLUME 2,877 BBL , TOTAL PROPPANT PLACED 203,545 16/20 AVG PSI 4217 AVG RATE 33.5 BBL BALL LAUNCHED @ 6534 BBL 14:03 16:21 2.30 COMPZN, STIM PUMP P BALL 2 INTERVAL 3 ON SEAT @ 6,817 BBL JSV SURFACE, SEAT 2,547 PSI, SURFACE BREAK 7,387 PSI DIFF.4,840 PSI,BH SEAT 4,238PSI, BH PEAK: 7,326PSI DIFF: 3,088 PSI PUMPED THE MINI FRAC, FLUSHED, OBSERVED PRESSURE FOR 30 MINUTES, RESUMED PUMPING INTERVAL 3 PUMPED TO DESIGN, TOTAL CLEAN VOLUME 3,294 BBL PUMPED TOTAL SLURRY VOLUME 3,391 BBL, TOTAL PROPPANT PLACED 203,299 4,120 LB 100 MESH, 199,179 16/20 AVG PSI 4,749 AVG RATE 37.2 BBL BALL 3 2.181 LAUNCHED @ 9925BBL JSV Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 9] REPORT DATE: [ 10/24/2024] Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 16:21 17:21 1.00 COMPZN, STIM PUMP P BALL 3 INTERVAL 4 LANDED @ 10208, 16 BBL EARLY, BALL ON SEAT, BH @ 3,950 PSI, BREAK BH 6,842 DIFFERENTIAL 2,892 PSI, STAGE PUMPED TO DESIGN, TOTAL CLEAN VOLUME PUMPED 2023 TOTAL SLURRY VOLUME 2321 BBL, TOTAL PROPPANT PLACED 204,288, 100 MESH 3447 LB 16/20 200,841 AVG PSI 3,980 AVG RATE 35.6 BBL 17:21 18:21 1.00 COMPZN, STIM PUMP P ISIP 30 MINUTES, LRS RIGGING OFF IA TYING INTO THE TUBING.FOR FREEZE PROTECT 18:21 19:21 1.00 COMPZN, STIM PUMP P LRS PUMPING 35 BBL FREEZE PROTECT 19:21 23:59 4.64 COMPZN, STIM WAIT P HAULING/HEATING WATER Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 10] REPORT DATE: [ 10/25/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 946,478.70 Cumulative Cost (Cost) 2,189,684.34 Weather Temperature (°F) Road Condition Wind Last 24hr Summary STAGE 5 COMPLETED AS DESIGNED BALL, 2.214" ON SEAT 13 BBL EARLY,BREAKDOWN 5319 BHP, TOTAL CLEAN VOLUME PUMPED 2,036 BBL, TOTAL PROPPANT PLACED 203,965, AVG PSI 4069 AVG RATE 37.7 BPM STAGE 6 COMPLETED AS DESIGNED BALL, 2.247" ON SEAT 16 BBL EARLY, NO SHIFT, PRESSURED OUT, SHIFTED ON STATIC BH PSI AFTER SHUT IN, 9756 BH, TOTAL CLEAN VOLUME PUMPED 2,399 BBL, TOTAL PROPPANT PLACED 203,965, AVG PSI 4069 AVG RATE 37.3 BPM STAGE 7 COMPLETED AS DESIGNED BALL, 2.280" ON SEAT 16 BBL EARLY, BREAKDOWN 9112BHP, TOTAL CLEAN VOLUME PUMPED1,616 BBL, TOTAL PROPPANT PLACED 202,539 AVG PSI 4386 PSI, AVG RATE 32.9 STAGE 8 COMPLETED AS DESIGNED, BALL 2.314" ON SEAT 19 BBL EARLY, BREAKDOWN 6150BHP, TOTAL CLEAN VOLUME PUMPED 1,883 BBL, TOTAL PROPPANT PLACED 205,712 AVG PSI3,842 PSI, AVG RATE 35.7 BBL LRS PUMPED 35 BBL FREEZE PROTECT 24hr Forecast General Remarks INITIAL T/I/O 580/0/216 FINAL T/I/O 670/700/572 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM WAIT P HAUL/ HEAT WATER, FIXED PUMP 621 RADIATOR, MAINTENACED PUMPS 245, 563 06:00 10:00 4.00 COMPZN, STIM WAIT P WORKING ON TRANSFER PUMPS ON BLENDER AND ADP, CHECKING EQUIPMENT CONTINUED TO HAUL/HEAT WATER LACKING 100BBL TO START COMPLETED IRON INSPECTION. 10:00 10:30 0.50 COMPZN, STIM WAIT P SITE SAFETY MEETING 10:30 12:24 1.90 COMPZN, STIM WAIT P PRIME EQUIPMENT, FUNCTION TEST ePRV'S PRESSURE TEST, TEST START@ 9526 PSI TRUCK SIDE 9473 PSI WELL SIDE, ENDING PSI 9398 WELL SIDE, 9433 PUMP SIDE, GOOD TEST 12:24 13:00 0.60 COMPZN, STIM WAIT P LOAD BALLS FOR STAGES 5-2.214, 6-2.247, 7- 2.28,8-2.314, MIX GEL LOAD CHEMS , 13:00 14:28 1.47 COMPZN, STIM PUMP P EQUALIZE TO 1000 PSI, OPEN WELL, OPENING PSI 437. ESTABLISH INJECTION, LAUNCH BALL 4-2.214" at 33 BBL JSV BALL LANDED @ 313 JSV 13 BBL EARLY BH Seat: 4489, BH Peak, 7586, Diff: 3097. STAGE PUMPED AS DESIGNED LAUNCHED STAGE 6 BALL 2.247" @ 2221 JSV 14:28 15:22 0.90 COMPZN, STIM PUMP T BALL 5 LANDED AT 2488 BBL JSV, 16 BBL EARLY, GOOD SEAT NO SHIFT, PRESSURED UP TO 8000PSI SURFACE NO SHIFT, BLED DOWN TO 5000 PSI AND RAISED PSI TO 8000, NO SHIFT, SHUT IN TO CLEAN UP SURFACE, DHG GAUGE SHOWED A SHIFT. 15:22 16:46 1.40 COMPZN, STIM PUMP P EQUALIZED TO 1500, OPENED WELL SLOWLY WALKED RATE UP WITH GEL WATER, ONCE THE XL CLEARED WELL BORE PRESSURE BROKE OVER CAME UP TO 37 BPM, PERFORMED HARD SHUT DOWN, RESUMED STAGE TO DESIGN, TOTAL CLEAN VOLUME PUMPED 20399 BBL TOTAL SLURRY VOLUME 285 BBL , TOTAL PROPPANT PLACED 203,695 100 MESH 4,926 LB, 199,03916/20 LB AVG PSI 4,029 AVG RATE 27.8 BBLSTAGE 7 BALL LAUNCHED @ 4,838 JSV 16:46 17:46 1.00 COMPZN, STIM PUMP P BALL 6 ON SEAT @ 5105 JSV 16 BBL EARLY, BH 4489 PSI, BH PEAK, 9112 PSI, BH DIFF: 4704 PSI, STAGE 7 COMPLETED AS DESIGNED, TOTAL CLEAN VOLUME PUMPED 1616 BBL TOTAL SLURRY VOLUME 1804 BBL , TOTAL PROPPANT PLACED 202,539, 100 MESH 4180 LB, 198,359 16/20 AVG PSI 4386 AVG RATE 32.9 BBL STAGE 8 BALL LAUNCHED @ 6666 BBL JSV Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 10] REPORT DATE: [ 10/25/2024] Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 17:46 18:46 1.00 COMPZN, STIM PUMP P BALL 7 ON SEAT @ 6920 JSV 19 BBL EARLY, BH PEAK, 6150 PSI, BH DIFF: 2281 PSI, STAGE 78 COMPLETED AS DESIGNED, TOTAL CLEAN VOLUME PUMPED 1803 BBL, TOTAL SLURRY VOLUME 1847 BBL , TOTAL PROPPANT PLACED 205,712, 100 MESH 3906 LB, 201,806 16/20 AVG PSI 3842 AVG RATE 37.3 BBL 18:46 19:10 0.40 COMPZN, STIM PUMP P ISIP, ISIP 3166 5 3088 10 3017 15 2973 20 2833 25 2764 19:10 20:40 1.50 COMPZN, STIM PUMP P LRS PUMPED 35 BBL FREEZE PROTECT 20:40 23:59 3.32 COMPZN, STIM WAIT P CONTINUE HAULING/ HEATING WATER, RELOADING PROPPANT, PLOAD CHEMS, RELOAD GEL Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 11] REPORT DATE: [ 10/26/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 945,663.30 Cumulative Cost (Cost) 3,135,347.64 Weather Temperature (°F) Road Condition Wind Last 24hr Summary STAGE 9 COMPLETED AS DESIGNED BALL, 2.348" ON SEAT 16 BBL EARLY,BREAKDOWN 5,511 BHP, TOTAL CLEAN VOLUME PUMPED 2,121 BBL, TOTAL PROPPANT PLACED 208,672 AVG SURFACE PSI 3821 PSI AVG RATE 32.8 BPM STAGE 10 COMPLETED AS DESIGNED BALL, 2.383" ON SEAT 17 BBL EARLY,BREAKDOWN 6,866 BHP, TOTAL CLEAN VOLUME PUMPED 1,587 BBL, TOTAL PROPPANT PLACED 203,698, AVG SURFACE PSI 4,275 AVG RATE 35.3 BPM STAGE 11 COMPLETED AS DESIGNED BALL, 2.418" ON SEAT 17 BBL EARLY,BREAKDOWN 6,926 BHP, TOTAL CLEAN VOLUME PUMPED 1,576 BBL, TOTAL PROPPANT PLACED 203,252, AVG SURFACE PSI 3980 AVG RATE 36.1 BPM STAGE 12 COMPLETED AS DESIGNED BALL 2,453" ON SEAT 19 BBL EARLY, BREAKDOWN 7835 BHP, TOTAL CLEAN VOLUME PUMPED 1,833 BBL, TOTAL PROPPANT PLACED 204,043 AVG SURFACE PSI 3977, AVG RATE 35.4 24hr Forecast General Remarks INITIAL T/I/O 580/7/114 FINAL T/I/O 670/700/572 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 06:00 6.00 COMPZN, STIM WAIT P HAUL/HEAT WATER, LOAD CHEMS, LOAD GEL, PUMP MAINTENANCE 06:00 07:30 1.50 COMPZN, STIM WAIT P WAITING ON WATER 07:30 09:00 1.50 COMPZN, STIM WAIT T DURING TANK FILLING AN 8" HOSE HAD A MECHANICAL FAILURE, SPITIING THE SIDE OPEN, SPILL VOLUME IS RECORDED AS 7BBL, DURING THE HOSE REPLACEMENT NATE WAS PRICKED WITH ONE OF THE BROKEN WIRES, HE WAS TAKEN TO THE MEDIC, WOUND WAS IRAGATED, HE WAS RELEASED BACK TO WORK.. 09:00 10:00 1.00 COMPZN, STIM WAIT P WAITING ON WATER 10:00 10:45 0.75 COMPZN, STIM WAIT P PRIME EQUIPMENT, TEST ePRV'S PRESSURE TEST, PSI START 9400, WELL, 9469 PUMP,5 MINUTE ENDING 9322 WELL, 9372 WELL, GOOD TEST. 10:45 11:15 0.50 COMPZN, STIM WAIT P SAFETY MEETING 11:15 11:51 0.60 COMPZN, STIM WAIT P LOAD BALL 8, 2.348" 9, 2.383", 10, 2.418, 11, 2.453, 12 2.489, MIX GEL, PULL ON CHEMS 11:51 14:01 2.18 COMPZN, STIM PUMP P EQUALIZE TO 1000 PSI, OPEN WELL, OPENING PSI 426, LAUNCHED BALL@ 10 BPM, BALL 8 @ 26 JSV BALL LANDED @ 274 JSV, 16 BBL EARLY, BH Peak: 5511 psi, BH Seat: 3440, BH Diff: 2071 psi, MAINTAINED 10 BPM, PUMPED DFIT, HARD SHUT DOWN, RESUMED PUMPING @12:50, STAGE PUMPED PER DESIGN TOTALCLEAN VOLUME JSV 2581, TOTAL PROPPANT PUMPED 208,672 LB, 100 MESH 4,342 LB, 204,330 16/20 AVG PSI 4682, AVG RATE 32.8 BPM BALL 9 LAUNCHED @ 2340 JSV 14:01 14:55 0.90 COMPZN, STIM PUMP P BALL 9 LANDED @ 2580 17 BBL EARLY, BH Diff: 2450 psi, BH Peak: 6866, BH Seat: 4416, STAGE PUMPED PER DESIGN TOTAL CLEAN VOLUME 1587 BBL JSV 1782, TOTAL PROPPANT PUMPED 203,698 LB, 100 MESH 3,974 LB, 199,724 16/20 AVG PSI 4272, AVG RATE 35.3 BPM BALL 10 LAUNCHED @ 4145 JSV 14:55 15:43 0.80 COMPZN, STIM PUMP P BALL 10 LANDED @ 4379 15 BBL EARLY, BH Diff: 2342 psi, BH Peak: 6926, BH Seat: 4583, STAGE PUMPED PER DESIGN TOTAL CLEAN VOLUME 1576 BBL JSV 1782, TOTAL PROPPANT PUMPED 203,252 LB, 100 MESH 3,952 LB, 199,724 16/20 AVG PSI 4272, AVG RATE 35.3 BPM BALL 11 LAUNCHED @ 5937 JSV Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 11] REPORT DATE: [ 10/26/2024] Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 15:43 16:34 0.85 COMPZN, STIM PUMP P BALL 11 LANDED @ 6160 19 BBL EARLY BH Diff: 3855 psi, BH Peak: 7835 psi, BH Seat 3980 psi, STAGE PUMPED PER DESIGN TOTAL CLEAN VOLUME 1833 BBL JSV 2050, TOTAL PROPPANT PUMPED 204,043 LB, 100 MESH 3,898 LB, 200,145 16/20 AVG PSI 3977, AVG RATE 35.4 BPM 16:34 17:04 0.50 COMPZN, STIM PUMP P ISIP 3166 BHP 5 MIN. 3046 BHP 10 MIN.2964 BHP 15 MIN. 2903 BHP 17:04 17:34 0.50 COMPZN, STIM WAIT P FAN OUT DOWNED PUMPS, FREEZE PROTECT LINES, FAN OUT BLOW DOWN, 17:34 18:04 0.50 COMPZN, STIM PUMP P LRS FREEZE PROTECT, 35 BBL 18:04 23:59 5.91 COMPZN, STIM WAIT P HAUL/ HEAT WATER, LOAD PROPPANT Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 94.0 94.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 12] REPORT DATE: [ 10/28/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 64,504.00 Cumulative Cost (Cost) 3,199,851.64 Weather Temperature (°F) Road Condition Wind Last 24hr Summary NIPPLE UP THE LAUNCHER STACK, FLOOD LINES, PRIME PT, WHEN LRS WAS TRYING TO RAISE THE IA PRESSURE TO THE 3500, @ 16 BBL NO PSI INCREASE WAS OBSERVED, SHUT DOWN OPERATIONS, BASE LINED THE DH GAUGE AND THE IA DOWN HOLE GAUGE, BEGAN PUMPING WITH PSI WAS TRACKING LB FOR LB ON THE DOWNHOLE GAUGES, SHUT DOWN CLOSED IN, 24hr Forecast General Remarks INITIAL T/I/O 250/150/150 FINAL T/I/O 211/211/150 ZX Code Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 15:01 16:01 1.00 COMPZN, STIM WAIT P NIPPLE UP LAUNCHER, PRIME UP PT. 16:01 17:01 1.00 COMPZN, STIM WAIT P LOAD BALLS, MIX GEL, LOAD CHEMS 17:01 18:01 1.00 COMPZN, STIM WAIT T WHEN BRINGING UP THE IA PSI, 16 BBL WAS PUMPED WITH NO PSI CHANGE, STOPPED PUMPING FOR PSI STABILIZING, RATE WAS BROUGHT BACK ON , THE DOWN HOLE IA ,LAND TUBING GAUGES MATCHED, ANTHER 5 BBL WAS PUMPED WITH NO INCREASE, IA WAS CHECKED FOR BEING FLUID PACKED, ALL FLUID WAS RECOVERED. Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 94.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 13] REPORT DATE: [ 10/31/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 856,128.94 Cumulative Cost (Cost) 4,055,980.58 Weather Temperature (°F) Road Condition Wind Last 24hr Summary NIPPLE UP DART LAUNCHER, PRIME/TEST PRV'S AND PT TOTAL PROP-818491 LBS JCV - 8028 BBL STAGE 13, BALL 12 - 2.453" ON SEAT 249 BBL, 9 BBL EARLY, DIFFERENTIAL 1750PSI, JCV PUMPED 2399 BBL, PROPPANT PLACED 206256 LBS, 100 MESH 4483 LBS, 16/20 201773 LBS, AVG PSI 3637, AVG RATE 37.6 BBL STAGE 14, BALL 13 - 2.489" ON SEAT 2796 BBL, 15 BBL EARLY, DIFFERENTIAL 2677 PSI, JCV PUMPED 1571 BBL, JSV PUMPED TOTAL PROPPANT PLACED 204012 LBS, 100 MESH 3944 LBS, 16/20 200068 LBS, AVG PSI 3383, AVG RATE 32.9 BBL UNABLE TO REACH DESIGNED 37 BPM DUE TO PUMP ISSUES, LIMITED TO 35 BPM STAGE 15, BALL 14 - 2.525" ON SEAT 4581 BBL, 10 BBL EARLY, DIFFERENTIAL 5265 PSI, JCV PUMPED 2311 BBL, TOTAL PROPPANT PLACED 203672 LBS, 100 MESH 3459 LBS, 16/20 200213 LBS, AVG PSI 2217, AVG RATE 31.9 BBL. SAW BALL LAND IN SEAT, NO SLEEVE SHIFT/BREAK OVER. BUMPED PRESSURE AGAINST SLEEVE MULTIPLE TIMES UNTIL SHIFT OBSERVED. DURING 6LB STAGE BLENDER LOST SUCTION, SAND CUT. ONCE RATE REESTABLISHED, STEPPED PROP UP IN 1LB INCREMENTS BASED ON JOB PROP TO GET BACK ON SCHEDULE UNABLE TO REACH DESIGNED 37 BPM DUE TO PUMP ISSUES, LIMITED TO 35 BPM 24hr Forecast General Remarks INITIAL T/I/O=644/610/50 FINAL T/I/O=1127/700/558 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 16:00 18:00 2.00 COMPZN, STIM RURD P NIPPLE UP DART LAUNCHER AND RIG UP ACID PUMP 18:00 19:00 1.00 COMPZN, STIM WAIT P PRIME, PT, TEST PRV'S. MEASURE AND LOAD BALLS. PULL ON CHEMICALS AND MIX GEL. PT MAX PSI 9498/5 MIN 9372 PSI - GOOD TEST 19:00 20:15 1.25 COMPZN, STIM PUMP P STAGE 13, BALL 12 - 2.489" ON SEAT 249 BBL, 9 BBL EARLY, DIFFERENTIAL 1750PSI, JCV PUMPED 2399 BBL, PROPPANT PLACED 206256 LBS, 100 MESH 4483 LBS, 16/20 201773 LBS, AVG PSI 3637, AVG RATE 37.6 BBL DURING 6LB STAGE BLENDER LOST SUCTION, SAND CUT. ONCE RATE REESTABLISHED, STEPPED PROP UP IN 1LB INCREMENTS BASED ON JOB PROP 20:15 21:30 1.25 COMPZN, STIM PUMP P STAGE 14, BALL 13 - 2.525" ON SEAT 2796 BBL, 15 BBL EARLY, DIFFERENTIAL 2677 PSI, JCV PUMPED 1571 BBL, TOTAL PROPPANT PLACED 204012 LBS, 100 MESH 3944 LBS, 16/20 200068 LBS, AVG PSI 3383, AVG RATE 32.9 BBL UNABLE TO REACH DESIGNED 37 BPM DUE TO PUMP ISSUES, LIMITED TO 35 BPM 21:30 22:15 0.75 COMPZN, STIM PUMP T VISIBLE BALL ON SEAT, NO BREAK OVER. PRESSURED UP 6 TIMES ALONG WITH BLEEDING OFF THROUGH HES CHOKE. TO ATTEMPT SHIFT 22:15 23:59 1.74 COMPZN, STIM PUMP P STAGE 15, BALL 14 - 2.561" ON SEAT 4581 BBL, 10 BBL EARLY, DIFFERENTIAL 5265 PSI, JCV PUMPED 2311 BBL, TOTAL PROPPANT PLACED 203672 LBS, 100 MESH 3459 LBS, 16/20 200213 LBS, AVG PSI 2217, AVG RATE 31.9 BBL DURING 6LB STAGE BLENDER LOST SUCTION, SAND CUT. ONCE RATE REESTABLISHED, STEPPED PROP UP IN 1LB INCREMENTS BASED ON JOB PROP UNABLE TO REACH DESIGNED 37 BPM DUE TO PUMP ISSUES, LIMITED TO 35 BPM Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 94.0 Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 13] REPORT DATE: [ 10/31/2024] Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) SEAWATER 6,257.0 6,257.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 14] REPORT DATE: [ 11/1/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 1,141,593.63 Cumulative Cost (Cost) 5,197,574.21 Weather Temperature (°F) Road Condition Wind Last 24hr Summary STAGE 16, BALL 15 - 2.563" ON SEAT 7101 BBL, 11 BBL EARLY, DIFFERENTIAL 1031 PSI, JCV PUMPED 1771 BBL, TOTAL PROPPANT PLACED 204796 LBS, 100 MESH 3912 LBS, 16/20 200884 LBS, AVG PSI 2866, AVG RATE 32.3 BBL UNABLE TO REACH DESIGNED 37 BPM DUE TO PUMP ISSUES, LIMITED TO 33 BPM LRS FREEZE PROTECT 35 BBLS EQUALIZE TO 1000 PSI, WELL OPEN AT 435 PSI. ESTABLISH RATE TO 15 BPM. STAGE 17, BALL 16 - 2.635" ON SEAT 211 BBL, 10 BBL EARLY, DIFFERENTIAL 1601 PSI. JCV PUMPED 2247 BBL, TOTAL PROPPANT PLACED 204812 LBS, 100 MESH 4760 LBS, 16/20 200052 LBS, AVG PSI 2306 PSI, AVG RATE 32.6 BBL. PUMP DFIT, MONITOR FOR 30 MIN. STAGE 18, BALL 17 - 2.672" ON SEAT 2650 BBL, 5 BBL EARLY, DIFFERENTIAL 5599 PSI, JCV PUMPED 1980 BBL, TOTAL PROPPANT PLACED 203574 LBS, 100 MESH 3257 LBS, 16/20 200317 LBS, AVG PSI 2899 PSI, AVG RATE 35.8 BBL STAGE 19, BALL 18 - 2.710" ON SEAT 4829 BBL, 15 BBL EARLY, DIFFERENTIAL 4442 PSI, JCV PUMPED 2247 BBL, TOTAL PROPPANT PLACED 204262 LBS, 100 MESH 3624 LBS, 16/20 200638 LBS, AVG PSI 2751 PSI, AVG RATE 35.0 BPM 24hr Forecast PUMP STAGES 20-23 General Remarks INITIAL T/I/O=435/0/109 FINAL T/I/O=1118/700/671 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 01:15 1.25 COMPZN, STIM PUMP P STAGE 16, BALL 15 - 2.528" ON SEAT 7101 BBL, 11 BBL EARLY, DIFFERENTIAL 1031 PSI, JCV PUMPED 1771 BBL, TOTAL PROPPANT PLACED 204796 LBS, 100 MESH 3912 LBS, 16/20 200884 LBS, AVG PSI 2866, AVG RATE 32.3 BBL UNABLE TO REACH DESIGNED 37 BPM DUE TO PUMP ISSUES, LIMITED TO 33 BPM 01:15 01:30 0.25 COMPZN, STIM PUMP P ISIP-3088 PSI 5 MIN-3048 PSI 10 MIN-3015 PSI 15 MIN-2983 PSI 01:30 03:00 1.50 COMPZN, STIM PUMP P LRS FREEZE PROTECT TUBING-35BBL DIESEL 03:00 13:00 10.00 COMPZN, STIM WAIT P LOAD SAND, WATER, HES WORK ON PUMP MAINTENANCE 13:00 16:15 3.25 COMPZN, STIM WAIT P PJSM, PRIME, PT, TEST PRV'S. MEASURE AND LOAD BALLS PT MAX -9498 PSI 5 MIN - 9335 PSI GOOD TEST 16:15 18:15 2.00 COMPZN, STIM PUMP P EQUALIZE TO 1000 PSI, WELL OPEN AT 435 PSI. ESTABLISH RATE TO 15 BPM. STAGE 17, BALL 16 - 2.635" ON SEAT 211 BBL, 10 BBL EARLY, DIFFERENTIAL 1601 PSI. PUMP DFIT, MONITOR FOR 30 MIN. JCV PUMPED 2247 BBL, TOTAL PROPPANT PLACED 204812 LBS, 100 MESH 4760 LBS, 16/20 200052 LBS, AVG PSI 2306 PSI, AVG RATE 32.6 BPM 18:15 18:45 0.50 COMPZN, STIM PUMP T STAGE 18 BALL, VISIBLE BALL IN SEAT, NO SLEEVE SHIFT SEEN. ALLOW LEAK OFF AND CONTINUE TO PRESSURE UP. 18:45 20:00 1.25 COMPZN, STIM PUMP P STAGE 18, BALL 17 - 2.672" ON SEAT 2650 BBL, 5 BBL EARLY, DIFFERENTIAL 5599 PSI, JCV PUMPED 1980 BBL, TOTAL PROPPANT PLACED 203574 LBS, 100 MESH 3257 LBS, 16/20 200317 LBS, AVG PSI 2899 PSI, AVG RATE 35.8 BPM 20:00 21:15 1.25 COMPZN, STIM PUMP P STAGE 19, BALL 18 - 2.710" ON SEAT 4829 BBL, 15 BBL EARLY, DIFFERENTIAL 4442 PSI, JCV PUMPED 1951 BBL, TOTAL PROPPANT PLACED 204262 LBS, 100 MESH 3624 LBS, 16/20 200638 LBS, AVG PSI 2751 PSI, AVG RATE 35.0 BPM Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 14] REPORT DATE: [ 11/1/2024] Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 21:15 21:30 0.25 COMPZN, STIM PUMP P ISIP-3191 PSI 5 MIN-3113 PSI 10 MIN-3080 PSI 15 MIN-3055 PSI 21:30 22:30 1.00 COMPZN, STIM PUMP P LRS FREEZE PROTECT -35 BBL 22:30 23:59 1.49 COMPZN, STIM RURD P HES BLOW DOWN EQUIPMENT, LOAD WATER, LOAD SAND, LOAD CHEMICALS Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 70.0 164.0 SEAWATER 8,084.0 14,341.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 15] REPORT DATE: [ 11/2/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 799,117.73 Cumulative Cost (Cost) 5,996,691.94 Weather Temperature (°F) Road Condition Wind Last 24hr Summary EQUALIZE TO 1100 PSI, OPENING 397 PSI. ESTABLISH INJECTION TO 15 BPM STAGE 20, BALL 19 - 2.749" ON SEAT 656 BBL, 7 BBL EARLY, DIFFERENTIAL 3750 PSI, JCV PUMPED BBL, TOTAL PROPPANT PLACED 203445 LBS, 100 MESH 4797 LBS, 16/20 198648 LBS, AVG PSI 3361 PSI, AVG RATE 34.6 BPM NO BALL SIGNATURE SEEN, PUMPED EXTRA 100 BBL PAST EXPECTED VOLUME OF 218 JSV. BU LAUNCHED AT 492 JSV STAGE 21, BALL 20 - 2.787" ON SEAT BBL, 5 BBL EARLY, DIFFERENTIAL 2600 PSI, JCV PUMPED 2103 BBL, TOTAL PROPPANT PLACED 205465 LBS, 100 MESH 4212 LBS, 16/20 201253 LBS, AVG PSI 3336 PSI, AVG RATE 35.7 BBL STAGE 22, BALL 21 - 2.826" NO BALL SIGNATURE SEEN, PUMPED EXTRA 140 BBL PAST EXPECTED VOLUME OF 4440 JSV. BU LAUNCHED AT 4580 JSV BU BALL LANDING NOT SEEN, PUMPED EXTRA 73 BBL PAST EXPECTED VOLUME OF 4735 JSV. BU BALL LANDING NOT OBSERVED. MOVED TO STAGE 23. AFTER DROPPING THE BALL FOR STAGE 23, THE BALL FOR STAGE 22 LANDED, CONTINUED PUMPING AS PER DESIGN. DURING 4.5PPG STAGE THE BALL FOR STAGE 23 LANDED 411 BBL LATE JCV PUMPED 1195 BBL, TOTAL PROPPANT PLACED 47175 LBS, 100 MESH 3604 LBS, 16/20 43571 LBS, AVG PSI 3923 PSI, AVG RATE 27.0 BPM STAGE 23, BALL - 2.866" ON SEAT BBL, 738 BBL LATE, DIFFERENTIAL 1466 PSI, JCV PUMPED 1844 BBL, TOTAL PROPPANT PLACED 197807 LBS, 100 MESH 5065 LBS, 16/20 192742 LBS, AVG PSI 3116 PSI, AVG RATE 26.5 BPM BALL SEAT OBSERVED UNEXPECTEDLY WHILE PUMPING 4.5 PPG IN WHAT WAS THOUGHT TO BE STAGE 23., BU BALL DROPPED TO CONFIRM PUMPING INTO CORRECT STAGE. STAGE PUMPED TO DESIGN, LRS FREEZE PROTECT 35 BBL 24hr Forecast General Remarks INITIAL T/I/O=397/0/98 FINAL T/I/O=1220/700/626 ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 09:00 9.00 COMPZN, STIM WAIT P LOAD WATER, SAND CHEMICALS. HES CHANGE BLENDER DISCHARGE MANIFOLD (WASHED), REPLACED WASHED DISCHARGE HOSES THAT WERE RUN TO THE MANIFOLD TRAILER. COMPLETE PUMP MAINTENANCE ON 3 PUMPS 09:00 12:00 3.00 COMPZN, STIM WAIT P PJSM, PRIME, PRESSURE TEST AND TEST PRV'S PT PSI MAX - 9531 5 MIN PSI-9363 GOOD TEST MEASURE AND LOAD BALLS. MIX GEL 12:00 13:30 1.50 COMPZN, STIM PUMP P EQUALIZE TO 1100 PSI, OPENING 397 PSI. ESTABLISH INJECTION TO 15 BPM STAGE 20, BALL 19 - 2.749" ON SEAT 656 BBL, 7 BBL EARLY, DIFFERENTIAL 3750 PSI, JCV PUMPED BBL, TOTAL PROPPANT PLACED 203445 LBS, 100 MESH 4797 LBS, 16/20 198648 LBS, AVG PSI 3361 PSI, AVG RATE 34.6 BPM NO BALL SIGNATURE SEEN, PUMPED EXTRA 100 BBL PAST EXPECTED VOLUME OF 218 JSV. BU LAUNCHED AT 492 JSV 13:30 14:30 1.00 COMPZN, STIM PUMP P STAGE 21, BALL 20 - 2.787" ON SEAT BBL, 5 BBL EARLY, DIFFERENTIAL 2600 PSI, JCV PUMPED 2103 BBL, TOTAL PROPPANT PLACED 205465 LBS, 100 MESH 4212 LBS, 16/20 201253 LBS, AVG PSI 3336 PSI, AVG RATE 35.7 BBL Page 2/2 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 15] REPORT DATE: [ 11/2/2024] Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 14:30 15:00 0.50 COMPZN, STIM PUMP P STAGE 22, BALL 21 - 2.826" NO BALL SIGNATURE SEEN, PUMPED EXTRA 140 BBL PAST EXPECTED VOLUME OF 4440 JSV. BU LAUNCHED AT 4580 JSV BU BALL LANDING NOT SEEN, PUMPED EXTRA 73 BBL PAST EXPECTED VOLUME OF 4735 JSV. BU BALL LANDING NOT OBSERVED. MOVED TO STAGE 23. AFTER DROPPING THE BALL FOR STAGE 23, THE BALL FOR STAGE 22 LANDED, CONTINUED PUPING AS DESIGNED. DURING 4.5PPG STAGE THE BALL FOR STAGE 23 LANDED 411 BBL LATE STAGE 22, BALL 21 - 2.787" , JCV PUMPED 1195 BBL, TOTAL PROPPANT PLACED 47175 LBS, 100 MESH 3604 LBS, 16/20 43571 LBS, AVG PSI 3923 PSI, AVG RATE 27.0 BPM 15:00 17:00 2.00 COMPZN, STIM PUMP P STAGE 23, BALL - 2.866" ON SEAT BBL, 738 BBL LATE, DIFFERENTIAL 1466 PSI, JCV PUMPED 1844 BBL, TOTAL PROPPANT PLACED 197807 LBS, 100 MESH 5065 LBS, 16/20 192742 LBS, AVG PSI 3116 PSI, AVG RATE 26.5 BPM BALL SEAT OBSERVED UNEXPECTEDLY WHILE PUMPING 4.5 PPG IN WHAT WAS THOUGHT TO BE STAGE 23., BU BALL DROPPED TO CONFIRM PUMPING INTO CORRECT STAGE 17:00 17:15 0.25 COMPZN, STIM PUMP P ISIP-3242 PSI 5 MIN-3113 PSI 10 MIN-3055 PSI 15 MIN-3013 PSI 17:15 18:45 1.50 COMPZN, STIM PUMP P LRS FREEZE PROTECT-35 BBL HES BLOW DOWN AND CLEAN UP EQUIPMENT 18:45 21:45 3.00 COMPZN, STIM RURD P RIG DOWN DART LAUNCH STACK AND DROP HES STAND PIPES, PREPARE WELL FOR SL 21:45 23:59 2.24 COMPZN, STIM RURD P RIG DOWN EQUIPMENT Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 35.0 199.0 SEAWATER 7,363.0 21,704.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 16] REPORT DATE: [ 11/3/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 62,300.00 Cumulative Cost (Cost) 6,058,991.94 Weather Temperature (°F) Road Condition Wind Last 24hr Summary HES RIG DOWN DART LAUNCH,EMPTY FRAC TANKS. HES TRIP EQUIPMENT BACK TO SHOP FOR MAINTENACE. 24hr Forecast General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 00:00 18:00 18.00 COMPZN, STIM RURD P HES TRIP EQUIPMENT BACK TO SHOP FOR MAINTENANCE, CONTINUE TO VAC OUT TANK BOTTOMS. 18:00 19:00 1.00 COMPZN, STIM TRAV P CREW TRAVEL 3T TO KCC. NO NIGHTSHIFT/OFFLINE Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 199.0 SEAWATER 21,704.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC Other In Hole Des Run Date OD (in) Top (ftKB) Btm (ftKB) PLUG 11/3/2024 00:00 3.760 5,951.0 5,958.0 CATCHER 11/3/2024 00:00 3.720 5,947.0 5,951.0 Page 1/1 3T-603 Report Printed: 11/5/2024 Daily STIM Report REPORT # [ 17] REPORT DATE: [ 11/4/2024] API / UWI 5010320887 Original KB/RT Elevation (ft) 51.00 Ground Elevation (ft) 12.00 Original Spud Date 9/10/2024 Primary Job Type INITIAL COMPLETION Secondary Job Type STIMULATION Total AFE (Cost) 7,119,210.00 AFE / RFE / Maint.# WCD.K43.2001.00.03.01. FR Network/Order Number 10458789 AFE+Supp Amt (Cost) 7,119,210.00 Daily Cost Total (Cost) 62,300.00 Cumulative Cost (Cost) 6,121,291.94 Weather Temperature (°F) Road Condition Wind Last 24hr Summary HES TRIP EQUIPMENT BACK TO SHOP FOR MAINTENANCE. FINISH VAC OUT TANK BOTTOMS. UNABLE TO BREAK IRON FROM 603 TO 608 DUE TO WEATHER/UNABLE TO STAND CRANE 24hr Forecast General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile KOESTER, GREG Frac Supervisor 814-746-0764 LAWSON, JACOB Supervisor 971-606-0075 BRZEZINSKI, NATHEN Frac Supervisor 814-553-0901 Time Log Start Time End Time Dur (hr) Phase Activity Code Time P- T-X Operation 06:00 07:00 1.00 COMPZN, STIM TRAV P CREW TRAVEL KCC TO 3T 07:00 17:00 10.00 COMPZN, STIM RURD P CREW TRIP EQUIPMENT BACK TO SHOP FOR MAINTENANCE. FINISH VAC TANK BOTTOMS. UNABLE TO BREAK BACK IRON FROM 603 TO 608 DUE TO WEATHER, COULD NOT STAND CRANE DUE TO WIND 17:00 18:00 1.00 COMPZN, STIM TRAV P CREW TRAVEL 3T TO KCC Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 199.0 SEAWATER 21,704.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/16/2024 06:00 10/16/2024 18:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/17/2024 06:00 10/17/2024 21:00 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/18/2024 06:00 10/18/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/19/2024 00:00 10/19/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/20/2024 00:00 10/20/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/21/2024 00:00 10/21/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/22/2024 00:00 10/22/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/23/2024 00:00 10/23/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/24/2024 00:00 10/24/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/25/2024 00:00 10/25/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/26/2024 00:00 10/26/2024 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 10/28/2024 15:01 10/28/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 10/31/2024 16:00 10/31/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/1/2024 00:00 11/1/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/2/2024 00:00 11/2/2024 23:59 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/3/2024 00:00 11/3/2024 18:00 FRAC HES Frac Equipment FAUR, DAN,Wells Supervisor 11/4/2024 06:00 11/4/2024 18:00 FRAC t >>ED W/η ^ Zs/ KZ Z η &/ >ED ^ Zs/ ^Z/Wd/KE >/s Z> ^Z/Wd/KE ddzW d >K'' K>KZ WZ/Ed^ ͲĞůŝǀĞƌLJ 3T-603 50-103-20887-00-00 224-074 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 4-Oct-24 1 GMTU MT7-83 50-103-20891-01-00 224-102 EATER MOOSES TOO MEMORY Top of Cement PROCESSED 20-Oct-24 1 dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚ ͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ yͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ WƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞ WůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉLJƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘ ďŚĂƚƚĂĐŚĂƌLJĂΛƐůď͘ĐŽŵ ^>ƵĚŝƚŽƌͲ dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽdž͕ ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚĂŶĚƚŚĞĐŽŶƚĞŶƚƐŽĨƚŚĞƉĂĐŬĂŐĞ ŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚƚŽŵĂƚĐŚƚŚĞŵĞĚŝĂŶŽƚĞĚĂďŽǀĞ͘dŚĞƐƉĞĐŝĨŝĐ ĐŽŶƚĞŶƚŽĨƚŚĞƐĂŶĚͬŽƌŚĂƌĚĐŽƉLJƉƌŝŶƚƐŵĂLJŽƌŵĂLJŶŽƚŚĂǀĞďĞĞŶ ǀĞƌŝĨŝĞĚĨŽƌĐŽƌƌĞĐƚŶĞƐƐŽƌƋƵĂůŝƚLJůĞǀĞůĂƚƚŚŝƐƉŽŝŶƚ͘ η^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞ 224-074: T39712 224-102: T39713 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.24 08:59:58 -08'00' 3T-603 50-103-20887-00-00 224-074 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 4-Oct-24 1 224-074: T39712 224 102 T39713 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-603 Yes No 9.Property Designation (Lease Number): 10. Field: Torok Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 21228 5163 21223 5163 2305 None None Casing Collapse Structural Conductor Surface 2470 Intermediate 4790 Intermediate 7850 Liner 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:Manabu Nozaki Manabu Nozaki Contact Email:Manabu.Nozaki@cop.com Contact Phone: 907-265-6519 Authorized Title: Staff Completions Engineer Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 1012.6 4-1/2" 10/19/2024 2122311968 4-1/2" 5163 Halliburton TNT Prod Packer Baker SLZXP, No SSSV L-80 10860 Perforation Depth TVD (ft):Perforation Depth MD (ft): 5040.77-5/8" 20" 10-3/4" 81.3 7-5/8"8378.7 2916.9 9428.5 8415.9 MD PRESENT WELL CONDITION SUMMARY 6890 5210 119.0 2448.3 4675.2 119.0 2955.6 TVD Burst MPSP (psi): Plugs (MD): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528 / ADL393883 224-074 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20887-00-00 ConocoPhillips Alaska Inc. Kuparuk Field Will perfs require a spacing exception due to property boundaries? Current Pools: Size Proposed Pools: 10/8/2024 Length AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): TNT Packer: 9141' MD/ 4954' TVD SLZXP: 9255' MD / 4991' TVD Subsequent Form Required: Suspension Expiration Date: 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: Perforate Reppair Well Exploratory Stratigraphic Development Service BOP Test Mechanical Integrity Test No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 324-587 By Grace Christianson at 9:24 am, Oct 09, 2024 CDW 10/09/2024 DSR-10/10/24 Fracture Stimulate X VTL 10/21/2024 10/19/2024 10/22/2024 SFD 10/17/2024 10-404 ($8 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.21 11:36:12 -08'00'10/21/24 RBDMS JSB 102224 Section 1 - Affidavit 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283(a)(1). Section 2 – Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) 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 MORTR04 TRACT OPERATION MORTR04 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas KUP MORTR04 TRACT OPERATION MORTR04 501032077400 3S-611 ACTIVE Oil KUP MORTR09 TRACT OPERATION MORTR09 501032086400 3S-617 ACTIVE Injector Produced Water Yes Yes KUP MORTR06 TRACT OPERATION MORTR06 501032086800 3S-624 ACTIVE Oil Yes Yes KUP MORTR07 TRACT OPERATION MORTR07 501032087000 3S-606 ACTIVE Injector Produced Water Yes Yes KUP MORTR08 TRACT OPERATION MORTR08 501032087500 3S-610 ACTIVE Oil Yes Yes KUP MORTR10 TRACT OPERATION MORTR10 501032087800 3S-626 ACTIVE Oil KUP MORTR10 TRACT OPERATION MORTR10 501032087870 3S-626PB1 ACTIVE Oil KUP MORTR11 TRACT OPERATION MORTR11 501032088200 3T-621 ACTIVE Oil NAK NAK NORTH ALASKA EXPLORATION 501032004700 COLV DELTA 2 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK NAK NORTH ALASKA EXPLORATION 501032064500 NUNA 1 SUSP Suspended NAK NAK NORTH ALASKA EXPLORATION 501032064570 NUNA 1PB1 PA Plugged and Abandoned NAK OU OOOGURUK UNIT 501032066000 NDST-02 SUSP Suspended Yes - Suspended Yes - Suspended NAK OU OOOGURUK UNIT 501032066070 NDST-02PB1 PA Plugged and Abandoned Yes- P&A Yes - Suspended NAK OU OOOGURUK UNIT 507032062200 ODSN-17 ACTIVE Oil Yes Yes NAK OU OOOGURUK UNIT 507032062260 ODSN-17L1 ACTIVE Oil Yes Yes NAK OU OOOGURUK UNIT 507032066000 ODST-47 ACTIVE Oil Yes Yes 3T-603 Frac Sundry Well - Wells within 1/2 Mile Buffer of Well Track SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), “That portions of the aquifers on the North Slope described by a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field”. SECTION 4 – PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283(a)(4) There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5 –DETAILED CEMENTING AND CASING INFORMATION 20 AAC 25.283(a)(5) All casing is cemented and tested in accordance with 20 AAC 25.030. See Wellbore schematic for casing details. Intermediate TOC SonicScope 5692'/3579' TVD Surface Casing 10.75" 45.5# L80 H563 2956'/2448' TVD Cemented to Surface 20" Insulated Conductor 119' -Cemented to Surface Upper Completion 1. 4-1/2" x 1" KBMG4 GLM (4x - 1 SOV, 3DV) 2. HES Opsis Downhole Gauge 3. ESP Assembly 4. Sliding Sleeve (3.813" ID) 5. Chem Injection Mandrel 6. HES TNT Packer 7. Arsenal 5500 psi Glass Disk 8. Locator/SAMS 3T-603 Moraine Producer Production TOL SLZXP LTP/HGR 9255'/4991' TVD Base Perm 1698'/1622' TVD Top Coyote 7020'/4113' TVD Top Torok Oil Pool (Moraine) 9406'/5034' TVD Production Liner 4.5" 12.6# P110S H563 21223'/5164' TVD Intermediate Casing 7.625" 29.7# L80 H563 9429'/5041' TVD (33.7# P110S H563 8452'-9294') GL SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: 10-3/4” casing cement pump report on 9/13/2024 shows that the original job pumped as designed. The cement job was pumped with 428 barrels of 10.7 ppg lead cement with BMII LCM and 57 barrels 15.8 ppg tail cement, displaced with WBM. The plug bumped, bled off pressure and positive indication that the floats held. Cement returns came to surface. The 7-5/8” casing cement report on 9/20/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 136 barrels of 14.0 ppg lead cement with BMII, followed with 31 barrels of 15.3 ppg tail cement, displaced with 408.5 barrels of 9.5 ppg FWP. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,692 MD (3,578.6’ TVD). Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 9/14/2024 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 9/20/2024 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes. On 10/11/2024 the 4-1/2” tubing was pressure tested to 4,550 psi. On 10/11/2024 The 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,050 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 4,550 Electronic PRV 8,050 Highest pump trip 7,550 SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 9/14/2024 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 9/20/2024 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes. The 4-1/2” tubing will be pressure tested to 4,550 psi. The 7-5/8” casing by 4-1/2” tubing annulus will be pressure tested to 3,850 psi. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,000 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 4,550 Electronic PRV 8,000 Highest pump trip 7,500 SUPERCEDED SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up 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 Torok Oil Pool, has an average thickness of approximately 263 ft TVD over the course of the lateral section of well 3T-603, from where it intersects the top formation at 9,405’ MD to TD of the well. The Torok Oil Pool is comprised of thinly interbedded sandstone, siltstone, and silty shale layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and very fine grained. The silty shales are composed of clay-rich, moderately to poorly sorted silt and clay. The estimated fracture pressure for the Moraine interval is approximately 12.5-13.5 ppg. The overlying confining interval of the Torok Formation consists of mudstones and siltstones with an average thickness of approximately 833’ TVD along the 3T-603 trajectory. The top of the Torok confining interval in the well starts at 4,166’ TVDSS (7,278’ MD). The estimated fracture gradient of the overlying Torok formation is approximately 0.82 psi/ft. The underlying confining zone below the Base Moraine consists of lower Torok, HRZ, and Kalubik shales totaling approximately 500’ TVD. The estimated fracture gradient for this section ranges from 15-18 ppg, with the gradient increasing down section. The Base Moraine is estimated from seismic to be at 5,240 ft TVDSS at the heel, and 5206 ft TVDSS at the toe of the well. The estimated formation pressure within the Torok Oil Pool is 2,285psi at a depth of 5,200’ TVDSS. SECTION 10 – LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing & Cement assessments for all wells that transect the confining zone: 3S-617: The 7-5/8” casing cement report on 11/5/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 142 barrels of 15.3 ppg. The plug was not bumped. Pressure was being monitored and no pressure built up indicating that the floats held. A cement bond log indicates competent cement with a cement top @ 3,841’ MD (3,157’ TVD). 3S-624: The 7-5/8” casing cement report on 12/24/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 125 barrels of 15.3ppg primary cement with LCM and 22 barrels of 15.3ppg primary cement without LCM. The plug was bumped and the floats held. A cement bond log indicates competent cement with a cement top @ 3,435’ MD (2,778’ TVD). 3S-606: The 7-5/8” casing cement report on 2/11/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 111 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 29 barrels of 15.3 ppg without BMII. The plug was bumped, pressure increased to 1500 psi and held for 5 minutes. A cement bond log indicates competent cement with a cement top @ 3,950 MD (3,164’ TVD). 3S-610: The 7-5/8” casing cement report on 3/23/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 201 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 22 barrels of 15.3 ppg without BMII. The plug did not get bumped, pressure head at 1,140 psi indicating that floats are competent. A cement bond log indicates competent cement with a cement top @ 3,549 MD (3,156’ TVD). Colville Delta 2: The well was plugged and abandoned on 3/16/1986. According to Plugging & Location Clearance Report, Set retainer at 6160’ 173 ft3 with 121 ft3 on top of the retainer. Set at 4,790’, squeeze 288 ft3. Drilled retainer 4790’. Set retainer at 4770’, squeeze 115 ft3. Drilled to 5500’ and set retainer at 5,000’, squeeze 161 ft3 with 10 sx on top of retainer. 23 ft3 plug from 140’ to 40’. TOC at 85’. 11 ft3 from 85’ to surface. Cement annulus with 310 ft3. Cut off casing head. Welded Plat on 95/8 STUB. Welded Plate on 7” STUB with well info. Source: 185-210 – Laserfiche WebLink (state.ak.us) NDST-02: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, the 7-5/8” casing was cemented on 2/8/2013. The cement report indicates that the job was pumped with 60 bbl of 15.8ppg Premium Cement with 3% Halad (R)-344 low fluid loss control. Full circulation was seen throughout the entire job. Frac operations could not be completed because a lodged ball damaged the tubing, and 60 bbl of CaCO3 was spotted on 4/13/2013. On 4/14/2013, XX plug was set in nipple at 4,550’ WLMD. ConocoPhillips Alaska Inc. re-entered on 1/3/2023, pulled the XX plug at 8,360’ CTMD (restriction) instead of at the nipple and performed injectivity test at 0.5 bpm on 1/21/2023. Source: 212-163- Laserfiche WebLink (state.ak.us) NDST-02PB1: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, on 1/30/2013, the bottom plug was pumped with 254 sxs of Premium Cement. TOC was tagged at 8,012’ MD. On 1/31/2013, the top plug was pumped with 60 bbl of 17ppg Premium Class G Cement was pumped. Tagged firm cement at 5,236’ MD. Source: 212-163- Laserfiche WebLink (state.ak.us) ODSN-17 and ODSN-17L1: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, on 9/27/2010, while displacing the 7" liner cement job, the plugs landed early but did not hold much pressure, and pumping was continued past the estimated stroke count and shoe track volume (the overdisplacement volume was estimated to be 28 bbls). This resulted in a wet shoe. This was confirmed by pumping mud from surface. On 10/1/2010, the squeeze job (15 bbls of 15.8ppg cement, 13 bbls of SW, 102 bbls of 10.1ppg mud) was performed as planned. Source: 210-093-Laserfiche WebLink (state.ak.us) / 210-140-Laserfiche WebLink (state.ak.us) ODST-47: According to the Pioneer Natural Resources job log on the AOGCC webiste, on 9/13/2012, the 7-5/8" casing cement job (55 bbls of Premium Class G tail cement at 15.8ppg) was pumped with partial returns (74 bbls) and the post job cement analysis showed ~70 psi of lift pressure. The cement bond log shows 52' of strong bond and 95' with partial bond of a total of 147' bonding. According to the Caelus Natural Resources job log on the AOGCC website, on 4/7/2019, the squeeze job (200 bbls in the formation and 9 bbls in the lateral tubular) was performed. The top of cement was at 12,223' CTM. Source: 212-103-Laserfiche WebLink (state.ak.us) 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 a fault transects the Torok Oil Pool reservoir within one half mile radius of the 3T-603 wellbore trajectory. The fault intersects the 3T-603 well trajectories at 14,882’ MD, it is interpreted to have offset the toe section of the 3T-603 well upwards by about 30ft. The fault trace is below seismic resolution, but an initial strike interpretation is shown in Plat 1. The fault is interpreted to not affect overburden integrity and therefore its presence will not interfere with containment. This section of the trajectory has been blanked off and will not be fractured during well completions. If there is any indication that a 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-603 is completed in October 2024 as a horizontal producer in the Torok formation. The well is completed with a 4.5” tubing upper completion and a 4.5” liner with a ball actuated sliding sleeve lower completion. The first stage will be pumped through a toe initiator valve in the toe of the lateral. After the 1st stage frac balls will be dropped to shift open the 2nd stage sleeve and isolate the first stage. The 2nd stage will then be pumped and a third ball drop (progressively getting larger) after each remaining stage, these balls will provide isolation from the previous stage and allow fracturing from the toe of the well towards the heel. 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 is 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 2,180’ MD/ 1,995’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 30 clean insulated Frac tanks (450 bbls usable volume per tank), with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 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. Perform DFIT after opening the Alpha Sleeve according to the attached pump schedule. Ensure sufficient volume is pumped to load the well with Frac fluid, prior to shut down. Resume pumping to pump Frac Stage 1. 11. Perform minifrac test after opening the frac sleeve for Stage 2. Resume pumping to pump Frac Stage 2. 12. Pump Frac Stages 3 through 23 by following attached pump schedule at ~37bpm with a maximum expected treating pressure of 7,000 psi. 13. The well is ready for Post Frac well prep/production tree installation and flowback (after Slickline and Coiled Tubing Cleanout). SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) Flowback will be initiated through a de-sander unit until the fluids clean up at which time it will be turned over to production for initial clean up production. From:Nozaki, Manabu To:AOGCC Permitting (CED sponsored); Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Wallace, Chris D (OGC) Cc:Hobbs, Greg S; Metzgar, Kyle N; Conklin, Amy A; Taylor, Jenna; Nozaki, Manabu Subject:RE: [EXTERNAL]RE: 3T-603 (PTD 224-074) Frac Sundry Application Date:Friday, October 18, 2024 1:48:24 PM Attachments:3T-603 Frac Sundry_Rev1.pdf AOGCC Team, We made a few changes on the frac design (the changes are highlighted by red font in the attached file): Frac Stages 1-22: Using the delayed cross-linker only Maximum Predicted Treating Pressure from 7000 psi to 7050 psi Electronic PRV Set Pressure from 8,000 to 8,050 psi Highest Pump Trip Pressure from 7500 to 7550 psi. There is no change on the chemical disclosure due to this change. The tubing pressure test is still good against the MPTP. Due to some operational delays, we would like to start the frac operation on 10/22/2024. Best Regards, Manabu Nozaki | Completions Engineer, Alaska Wells | ConocoPhillips O: +1-907-265-6519 | M: +1-907-917-9567 | ATO-1578, Anchorage, AK, USA Email: Manabu.Nozaki@ConocoPhillips.com 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-603 (PTD No. 224-074; Sundry No. 324-587) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 October 21, 2024 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 10/9/2024 (a)(2) Plat Provided with application. SFD 10/9/2024 (a)(2)(A) Well location Provided with application. Well lies in Section 1 of T12N, R7E, and sections 35, 26, and 23 of T13N, R7E, UM. SFD 10/9/2024 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online October 9, 2024), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of 3T-603. There are no subsurface water rights or temporary subsurface water rights within 5miles of the surface location of 3T-603. The toe of 3T-603 will lie 1.6 miles from three water wells drilled to depths of 93, 99, and 102 feet on Eni’s Oooguruk Production Pad in Section 11, T13N, R7E, UM. SFD 10/9/2024 (a)(2)(C) Identify all well types within ½ mile Yes: 13 wells, two lateral wellbores, and 3 plugged-back wellbores as shown in the application. SFD 10/9/2024 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. Well 3T-603 will lie within acreage that was formerly located inside the Oooguruk Unit before being purchased by CPAI and included within the 12th Expansion of the KRU. According to page 17 of EPA’s UIC Class 1 Permit Number AK11009-B for Oooguruk Unit disposal wells DW-1 and DW-2: “The requirement to monitor the strata overlying the confining zone for fluid movement is waived since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet “No USDW” criteria).” Further support is found in Conclusion 14 of AIO 33 for the nearby Oooguruk-Kuparuk Oil Pool also states: “Formation water salinity calculations by the Commission using log data from four exploratory SFD 10/17/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-603 (PTD No. 224-074; Sundry No. 324-587) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 October 21, 2024 wells and methods compatible with the Rwa method endorsed by the EPA confirm that there are no aquifers within the Affected Area that could serve as underground sources of drinking water.” In addition, a quick-look analysis of a prominent sand from 1942’ to 1966’ MD, which is just above the surface casing shoe, in the nearby Colville Delta 3 well yielded a TDS value of about 11,500 mg/l. (a)(4) Baseline water sampling plan None required. SFD 10/10/2024 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. CDW 10/09/2024 (a)(6) Casing and cementing operation assessment 10-3/4” surface casing cemented with returns to surface. 7-5/8” intermediate casing cemented from shoe at 9429 ft to TOC of 5692 ft (SonicScope). Consistent, very good-quality cement is present below about 5,900’ MD / 3,662’ TVD. 4-1/2” uncemented liner secured with liner top packer at 9255 ft. No cement concerns for this well and upcoming stimulation. CDW 10/09/2024 SFD 10/9/2024 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers are present. (See Section(a)(3), above.) SFD 10/10/2024 (a)(6)( B) Each hydrocarbon zone is isolated Yes: see cementing (a)(6) above. Yes see (a)(9) frac zone lithological descriptions. Top of Coyote at 7020/4113 ft TVD is covered by the 7-5/8” casing cemented from shoe. Top of Torok (Moraine) at 9406/5034 ft TVD is isolated via the 7-5/8” casing cement and the 4-1/2” liner hanger/packer. CDW 10/09/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-603 (PTD No. 224-074; Sundry No. 324-587) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 October 21, 2024 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3,850 psi MITIA planned, 4,550 psi MITT plan. CDW 10/09/2024 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree. max. frac. pressure 7000 psi. Pump knock out 7500 psi and GORV 8000 psi.,tree test 10K psi. Lines test 10K psi. CDW 10/09/2024 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: Torok Formation mudstone and siltstone having about 830’ of true vertical thickness (TVT). Fracture gradient is expected to range from about 0.82 psi/ft (15.8 ppg EMW). Fracturing Zone: Torok Oil Pool interbedded very fine-grained sandstone, siltstone and silty shale between 9,405’ and the total depth of the well 21,228’ MD (5,034’ to 5,163’ TVD). Fracture gradient expected to range from about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). Lower confining zones: Lower Torok, HRZ shale, and Kalubik shale that have an aggregate TVT about 500’. Fracture gradient expected to range from about 0.78 to 0.94 psi/ft (15 to 18 ppg EMW). SFD 10/9/2024 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. CPAI has identified and described mechanical condition and isolation for the 10 wells and sidetracks within ½ mile of 3T-603 that penetrate the confining intervals. CDW 10/09/2024 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Yes. The operator has identified one fault within a ½-mile radius of 3T-603. This fault intersects the well at 14,882’ MD (5,167’ TVD) and has about 30’ of vertical displacement. This fault is not visible on seismic, so its orientation is uncertain. The limited vertical extent of the fault, and the fact that it is SFD 10/10/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-603 (PTD No. 224-074; Sundry No. 324-587) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 October 21, 2024 not visible in the 3D seismic data set suggests that it is a relatively minor fault of limited upward extent. This section of the well will be blanked off, and packers will isolate the fault from fracturing operations, so it is unlikely that the fault will interfere with containment of the injected fracturing fluids. However, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. (a)(12) Proposed program for fracturing operation Provided with application. CDW 10/09/2024 (a)(12)(A) Estimated volume Provided with application. 47,254 bbl total dirty vol. 4.69M lb total proppant. 23 stage. CDW 10/09/2024 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 10/09/2024 (a)(12)(C) Chemical name and CAS number of each Provided with application. Halliburton disclosure provided, Patina Energy chemicals. Proprietary chemicals on file with AOGCC. CDW 10/09/2024 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 10/09/2024 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7000 psi. Max. 7000 psi allowable treating pressure. Max pressure is 7500 psi to 8000 psi to Pump shutdown. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 3500 psi. CDW 10/09/2024 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures range from 350’ to 670’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will range from 175’ to 230’, with a shallowest TVD of about SFD 10/14/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-603 (PTD No. 224-074; Sundry No. 324-587) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 October 21, 2024 4,853’ and deepest TVD of about 4,924’. So, the induced fractures may penetrate into--but not through--the overlying confining Torok siltstone/mudstone that is about 830’ thick in this area. (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 10/09/2024 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3500 psi back pressure, plan to test to 3850 psi, popoff set as 3600 psi CDW 10/09/2024 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing See provided schematic. 4.5” tubing will be anchored with a liner hanger/packer set at approx. 9255 ft with shallowest frac sleeve at 10919 ft. TOC in 7” casing determined as 5692 ft by SonicScope. Liner hanger and packer within cemented zone so at area of interest - no cement concerns. CDW 10/09/2024 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4550 psi. Max pressure differential is estimated as 3500 psi (7000 with 3500 psi backpressure) so test of 4550 psi satisfies 110% CDW 10/09/2024 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device Max frac surface pressure 7000 psi. 10,000 psi line pressure test, pump knock out 7500 and 8000 psi to global electronic PRV. IA PRV set as 3600 psi. CDW 10/09/2024 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 10/09/2024 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 10/09/2024 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated CDW 10/09/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-603 (PTD No. 224-074; Sundry No. 324-587) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 October 21, 2024 increases caused by pressure or thermal transfer, the operator shall: (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). SFD 10/14/2024 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. SFD 10/10/2024 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3T-603 JBR 10/17/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Annular Failed and had to be replaced. I did not witness the re-tests. Annular re-test chart sent to J. Regg. Via email Test Results TEST DATA Rig Rep:Zac Coleman/Shane MiOperator:ConocoPhillips Alaska, Inc.Operator Rep:Keith Herring/Byron Marmo Rig Owner/Rig No.:Doyon 142 PTD#:2240740 DATE:9/22/2024 Type Operation:DRILL Annular: 250/3500Type Test:OTH Valves: 250/4000 Rams: 250/4000 Test Pressures:Inspection No:bopAGE240924110356 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7 MASP: 1789 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8 F #1 Rams 1 3 1/2 X 6 P #2 Rams 1 Blind/Shear P #3 Rams 1 3 1/2 X 6 P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8 P HCR Valves 2 3 1/8 P Kill Line Valves 3 3 1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1750 200 PSI Attained P10 Full Pressure Attained P58 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1975 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P18 #1 Rams P8 #2 Rams P8 #3 Rams P8 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P2 9 9 9999 9 9 GD\%23(WHVWLQWHUYDO WHVWFKDUWVDWWDFKHG Annular Failed 2240740 %23(7HVW'R\RQ .587 37' $2*&&,QVSERS$*( Test Bope 4” and 4.5” 250/3500 On The Annular Both Test Joints 250/4000 On Everything Else 14 1. 4.5” TJ, Annular 250/3500 2. 4.5” TJ, UPR’s CMV’s #’s 1, 12, 13, 14, Rig floor kill line valve, Upper IBOP, 4” Dart 250/4000 3. CMV’s #’s 9, 11, Mezz Kill line valve, Lower IBOP, 4” TIW #1 250/4000 4. CMV’s #’s 8, 10, HCR Kill, TIW #2 250/4000 5. CMV’s #’s 6, 7, Manual Kill 250/4000 6. Super Choke / 250/2000 7. Manual Choke / 250/2000 8. CMV’s #’s 2, 5 250/4000 9. HCR Choke 250/4000 10. Manual Choke 250/4000 Remove 4.5” Test Joint 11. CMV’s #’s 3, 4, Blind rams, 250/4000 Install 4” Test joint 12. 4” TJ 3-1/2” X 6” UPR VBR’s, 250/4000 13. 4” TJ 3-1/2” X 6” LPR VBR’s 250/4000 Koomey Draw Down %23(7HVW'R\RQ .587 37' $2*&&,QVSERS$*( DOYON RIG 142 ACCUMULATOR DRAW DOWN WORKSHEET WELL: 3T-603 DATE: 9/21/24 ACCUMULATOR PSI 3000 MANIFOLD PSI 1500 FUNCTION RAMS/ANNULAR/ HCR'S, DON'T FUNCTION BLINDS! FUNCTION ONE RAM TWICE LET PRSSURE STABILIZE AND RECORD BACK UP NITROGEN BOTTLE'S ACCUMULATOR PSI 1750 NITROGEN BOTTLE'S PSI BOTTLE # 1 2000 BOTTLE # 2 2000 BOTTLE # 3 2000 BOTTLE # 4 2000 BOTTLE # 5 2000 BOTTLE # 6 1850 AVG FOR 6 BOTTLE'S =1975 TURN ON ELEC. PUMP, SEC FOR 200 PSI =10 TURN ON AIR PUMP'S TIME FOR FULL CHARGE =58 Annular 18 UPR 8 Blind/ Shear 8 LPR 8 KILL HCR 2 Choke HCR 1 .587 37' $2*&&,QVSERS$*( #01&5FTU%PZPO -PXFS1JQF3BNT ,365 15% "0($$*OTQCPQ"(& Z -PXFS1JQF3BNT #01&5FTU%PZPO "OOVMBS ,365 15% "0($$*OTQCPQ"(& "OOVMBS 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 Billon Wells Engineering Manager ConocoPhillips Alaska, Inc. PO Box 100306 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Torok Oil Pool, KRU 3T-603 ConocoPhillips Alaska, Inc. Permit to Drill Number: 224-074 Surface Location: 1998' FSL, 679' FWL, NWSW, Sec. 1, T12N, R7E Bottomhole Location: 4557' FSL, 1241' FWL, NENW, Sec. 23, T13N, 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 19DATED this ___ day of July 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.19 09:28:50 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 21222 TVD: 5154 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 7/25/2024 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 6519' to ADL393884 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-6003724 y- 467890 Zone- 4 12 to Same Pool: 281' to 3S-624 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 3064 39 39 3103 2535 9.875" 7.625" 29.7 L80 Hyd563 8405 39 39 8444 4806 9.875" 7.625" 33.7 P110S Hyd563 800 8444 4806 9244 4985 6.5" 4.5" 12.6 P110S Hyd563 12128 9094 5091 21222 5154 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Matt Smith Chris Brillon Contact Email:matt.smith2@cop.com Wells Engineering Manager Contact Phone:907-263-4324 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Perforation Depth MD (ft): Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. Intermediate Production Liner Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Surface Conductor/Structural Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Casing Length Size Cement Volume MD Total Depth MD (ft): Total Depth TVD (ft): 930sks 10.7ppg, 280sks 15.8ppg 700sks 15.3ppg STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips 59-52-180 3T-603 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1998' FSL, 679' FWL, NWSW S1 T12N R7E ADL025528 / ADL393883 (including stage data) 3594' FSL, 4118' FWL, SENE S35 T13N R7E LONS 01-013 4557' FSL, 1241' FWL, NENW S23 T13N R7E 2560 / 5760 GL / BF Elevation above MSL (ft): 2305 1789 18. Casing Program: Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 9:28 am, May 31, 2024 A.Dewhurst 21JUN24 KRU Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available DSR-6/4/24 X VTL 7/17/2024 50-103-20887-00-00 Alaska, Inc. 224-074 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.19 09:29:08 -08'00'07/19/24 RBDMS JSB 072424 <ZhϯdͲϲϬϯ 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. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 May 31, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-603 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Moraine Producer well from the 3T drilling pad. The intended spud date for this well is 7/25/2024. It is intended that Doyon 142 be used to drill the well. 3T-603 will utilize a 13 1/2” surface hole drilled to TD and 10 3/4” casing will be set and cemented to surface. As noted in section 4 of the attached proposed drilling program, the low maximum anticipated surface pressure of the well allows use of a three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii). The fourth preventer will contain solid body pipe rams that will be sized for the intermediate casing string. The 9 7/8” intermediate hole will be drilled and topset the Moraine reservoir. A 7 5/8” casing string will be set and cemented from TD to secure the shoe and cover 500’MD or 250’TVD above any hydrocarbon-bearing zones (Coyote). The production interval will be comprised of a 6 1/2” horizontal hole that will be landed and geo-steered in the Moraine formation. The well will be completed as an uncemented, fracture stimulated Producer with 4 1/2” liner, frac sleeves and swell packers. The upper completion will include a production packer with GLM’s, chem injection line and an ESP, and tied back to surface. 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. A proposed drilling program 3. A proposed completion diagram 4. A drilling fluids program summary 5. Pressure information as required by 20 ACC 25.035 (d)(2) 6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Matt Smith at 907-263-4324 (matt.smith2@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-603 Well File / Jenna Taylor ATO 1560 David Lee ATO 1552 Matt Smith Chris Brillon ATO 1548 Drilling Engineer Roland Kirschner ATO 636 Digitally signed by Matthew SmithDN: CN=Matthew Smith, E=matt.smith2 @conocophillips.com, C=US Reason: I am the author of this documentLocation: Date: 2024.05.31 07:24:47-08'00' Foxit PDF Editor Version: 13.0.0 Matthew Smith g the low maximum anticipated surface pressure of the well allows use of app gpg , three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii) Moraine Producer Application for Permit to Drill, 3T-603 Saved: 31-May-24 3T-603 PTD Page 1 of 9 Printed: 31-May-24 3T-603 Application for Permit to Drill Document Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) ........................................................................................................ 1 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) ......................................................................................... 1 3. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) ........................................................................ 3 4. Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(3)) ............................................................. 3 5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) ..................................................................................... 4 6. MASP Calculations (Requirements of 20 AAC 25.005(c)(4)) ................................................................................ 4 7. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5)) ............................ 5 8. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) ........................................................... 5 9. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) .................................................................................. 6 10. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ........................................ 7 11. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ................................................................................... 7 12. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ................................................................... 7 13. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) ............................................................................. 7 14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005 (c)(14)) ......... 7 15. Drilling Hazards Summary ................................................................................................................................. 7 16. Proposed Completion Schematic ....................................................................................................................... 9 1. Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted will be designated as 3T-603 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 1,998 FSL, 679 FWL, NWSW S1 T12N R7E, UM NAD 1927 Northings: 467890 Eastings:6003724 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 3594‘ FSL, 4118‘ FWL, SENE S35 T13N R7E, UM NAD 1927 Northings: 469771 Eastings: 6010591 Measured Depth, RKB: 9,244 Total Vertical Depth, RKB:4,985 Total Vertical Depth, SS:4,934 Total Depth (Toe) 4557‘ FSL, 1241‘ FWL, NENW S23 T13N R7E, UM NAD 1927 Northings: 466931 Eastings: 6022125 Measured Depth, RKB:21,222 Total Vertical Depth, RKB:5,154 Total Vertical Depth, SS:5,103 Pad Layout 3. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) The proposed drilling program is listed below. Please refer to Attachment 3: Completion Schematic. 1. MIRU Doyon 142 onto 3T-603 2. Rig up and test diverter and 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” drilling BHA to drill the intermediate hole section. 8. Chart casing pressure test to 3000 psi for 30 minutes. 9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 10. Drill 9 7/8” hole to section TD, setting pipe above the Moraine Reservoir. (LWD Program: GR/RES/Den/Neu/Sonic). 11. Run 7 5/8” casing and cement to a minimum of 500’ MD or 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4000 psi. 12. Test BOPE to 250 psi low / 4,000 psi high (24-48 Regulatory notice). 13. Pick up and run in hole with 6 1/2” drilling BHA. Log top of cement with sonic tool in recorded mode. 14. Chart casing pressure test to 4,000 psi for 30 minutes if not tested on plug bump. 15. Drill out shoe track and 20 feet of new formation. Perform LOT to a maximum of 14.5 ppg. Minimum required leak- off value is 11.0 ppg EMW. 16. Drill 6 1/2” hole to section TD (LWD Program: GR/RES/Den/Neu/Sonic). 17. Pull out of hole with drilling BHA. Review cement job details and sonic log TOC. 18. Run 4 1/2” liner with toe valve, frac sleeves and swell packers and liner hanger to TD. 19. Run 4 1/2” upper completion with glass plug, production packer, chemical injection mandrel with cap string, sliding sleeve, ESP, downhole gauge, and gas lift mandrels. Space out and land tubing hanger with pre-installed and pre- tested BPV. 20. Pressure test hanger seals to 3,850 psi. 21. Pressure test against the glass plug to set production packer, test tubing to 3,850 psi, chart test. 22. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 23. Install HP-BPV and test to 2500 psi. 24. Nipple down BOP. 25. Install tubing head adapter assembly. N/U tree and test to 5000 psi/10 minutes. 26. Freeze protect down tubing and annulus. 27. Secure well. Rig down and move out. Please note – This well will be frac’d 4. Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(3)) Please reference BOP schematics on file for Doyon 142. Doyon 142 will use a BOPE stack equipped with an annular preventer, fixed 7 5/8” solid body rams, blind/shear rams and variable rams while drilling and running casing in the intermediate section of 3T-603. 3T-603 has a MASP of 1,790 psi in the intermediate 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.a.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing begin used, except that pipe rams need not be sixed to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type Intermediate Drilling/Casing Production Proposed Configuration: Proposed Configuration: Annular Preventer (iii) Annular Preventer 7 5/8” fixed rams during drilling Intermediate VBRs in Upper Cavity Blind/Shear Rams (ii) Blind/Shear Rams VBRs (i) VBRs in Lower Cavity 5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) A diverter will be utilized as there are no offset wells with surface shoes within 500’ of 3T-603. However, no hydrates are anticipated, and 3T-621 was recently drilled with no indications of hydrates occurring. 6. MASP Calculations (Requirements of 20 AAC 25.005(c)(4)) The following presents data used for calculation of anticipated surface pressure (ASP) during drilling of this well: Casing Size (in) Csg Setting Depth MD/TVD(ft) Fracture Gradient (ppg) Pore pressure (psi) ASP Drilling (psi) 20 97 / 97 10.9 54 56 10 3/4 3,103 / 2,535 12.5 1,134 1,394 7 5/8 9244 / 4,985 13.5 2,229 1,790 4 1/2 21,222 / 5,154 13.0 2,305 n/a PROCEDURE FOR CALCULATING ANTICPATED SURFACE PRESSURE (ASP) ASP is determined as the lesser of 1) surface pressure at breakdown of the formation casing seat with a gas gradient to the surface, or 2) formation pore pressure at the next casing point less a gas gradient to the surface as follows: 1) ASP = [(FG x 0.052) - 0.1]*D Where: ASP = Anticipated Surface pressure in psi FG = Fracture gradient at the casing seat in lb/gal 0.052 = Conversion from lb./gal to psi/ft 0.1 = Gas gradient in psi/ft D = true Vertical depth of casing seat in ft RKB OR 2) ASP = FPP – (0.1 x D) Where: FPP = Formation Pore Pressure at the next casing point FPP = 0.4525 x TVD 1. ASP CALCULATIONS 1. Drilling below 20” conductor ASP = [(FG x 0.052) – 0.1] D = [(10.9 x 0.052) – 0.1] x 97 = 56 psi OR ASP = FPP – (0.1 x D) = 1,134 – (0.1 x 2,535 ) = 880 psi 2. Drilling below 10.75” surface casing ASP = [(FG x 0.052) – 0.1] D = [(12.5 x 0.052) – 0.1] x 2,535 = 1,394 psi OR ASP = FPP – (0.1 x D) = 2,229 – (0.1 x 4,985 ) = 1,731 psi 3. Drilling below 7.625” intermediate casing ASP = [(FG x 0.052) – 0.1] D = [(13.0 x 0.052) – 0.1] x 4,985 = 3,001 psi OR ASP = FPP – (0.1 x D) = 2,305 – (0.1 x 5,154 )= 1,790 psi (B) data on potential gas zones; The well bore 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 7. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5)) Drill out the casing shoe and perform LOT/FIT as per the procedure that ConocoPhillips Alaska has on file with the Commission. 8. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.70 33.70 L80 P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 4 1/2 6 1/2 12.60 P110S Hyd563 Unemented liner with frac sleeves and swell packers Cementing Calculations 10 3/4” Surface Casing run to 3,103 ’ MD / 2,535 ’ TVD Cement 3,103 MD to 2,603 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 2,603' to surface with 10.7 ppg Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,745 ’ MD), zero excess in 20” conductor. Lead slurry from 2,603’ MD to surface with Arctic Lite Crete @ 10.7 ppg Total Volume = 2,690ft3 => 930 sx of 10.7 ppg Class G + Add's @ 2.92 ft3 /sk Tail slurry from 3,103 MD to 2,603’ MD with 15.8 ppg Class G + Add's Total Volume = 316 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk 7 5/8” Intermediate Casing run to 9244’ MD / 4,985 ’ TVD Top of slurry is designed to be at 6,481 ’ MD, which is 500’MD or 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. If a shallower hydrocarbon zone of producible volumes, is encountered while drilling, a 2-stage cement job will be performed to isolate this zone. Assume 40% excess annular volume. Tail slurry from 9,244 MD to 6,481’ MD with 15.3 ppg Class G + Add's Total Volume = 851 ft3 => 700 sx of 15.3 ppg Class G + Add's @ 1.23 ft3/sk 9. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate Production Hole Size in. 13 1/2 9 7/8 6 1/2 Casing Size in. 10 3/4 7 5/8 4 1/2 Density PPG 9.0 – 10.5 9.0 – 9.8 9.0 – 10.0 PV cP 20-50 8-15 7-12 YP lb./100 ft2 30 - 80 20 - 30 15 - 25 Funnel Viscosity s/qt. 250 – 300 40-60 35-50 Initial Gels lb./100 ft2 30 - 50 8 - 15 5- 10 10 Minute Gels lb./100 ft2 50 - 70 <20 7 - 15 API Fluid Loss cc/30 min. N.C. – 15.0 < 10.0 < 6.0 HPHT Fluid Loss cc/30 min. N/A N/A < 10.0 pH 9.0 – 10.0 9.0 – 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 N10.0 ppg by use of solids control system and dilutions where necessary. Intermediate: Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight at or below 9.5 ppg for formation stability and be prepared to add loss circulation material if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important. The mud will be weighted up to 9.5 ppg before pulling out of the hole. Production Hole: The horizontal production interval will be drilled with a NAF mud system weighted to 9.0 – 10.0 ppg. MPD will be available for adding backpressure during connections if necessary. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 10. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 12. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) N/A - Application is not for an offshore well. 13. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 14. 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. 15. 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 Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts/Hole Sloughing Low Cool mud temperatures, minimize circulating times when possible Running sands and gravels Low Maintain planned mud properties, increase mud weight, use weighted sweeps 9 7/8” Hole /7 5/8” Liner - Casing Interval Event Risk Level Mitigation Strategy 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 Lost circulation Moderate Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, Liner will be in place at TD Abnormal Reservoir Pressure (Coyote / K3) Low Well control drills, check for flow during connections, increase mud weight if necessary 6 1/2” Hole / 4 1/2” Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Moderate Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material Hole swabbing on trips Moderate 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 Moderate Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Liner to Bottom Moderate Properly clean hole on the trip out with BHA, perform clean out run if necessary, utilize super sliders for weight transfer if needed, monitor T&D real time Well Proximity Risks: 3T is a multi-well pad, with only a few existing wells. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Unlikely to encounter any abnormal pressure, however, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the primary intermediate cement job will be replanned to cover the zone as per the agency regulations. Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. Unlikely to encounter any abnormal pressure LCM material will be available 16. Proposed Completion Schematic 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 1.50 3 400.00 1.50 16.00 399.99 1.26 0.36 1.50 16.00 1.12 Start DLS 2.50 TFO 0.00 4 1684.99 33.62 16.00 1609.10 369.11 105.84 2.50 0.00 329.14 Start 120.09 hold at 1684.99 MD 5 1805.08 33.62 16.00 1709.10 433.04 124.17 0.00 0.00 386.15 Start Build 2.50 6 3103.57 66.09 16.00 2535.10 1374.47 394.12 2.50 0.00 1225.63 Start 20.00 hold at 3103.57 MD 7 3123.57 66.09 16.00 2543.21 1392.05 399.16 0.00 0.00 1241.30 Start DLS 1.00 TFO -72.06 8 3174.33 66.24 15.47 2563.72 1436.74 411.76 1.00 -72.06 1281.21 Start 5617.36 hold at 3174.33 MD 9 8791.69 66.24 15.47 4826.61 6391.81 1783.35 0.00 0.00 5712.45 Start DLS 3.00 TFO -63.11 10 9859.74 83.00 347.00 5114.35 7405.91 1794.81 3.00 -63.11 6689.03 Start Build 2.00 11 10059.74 87.00 347.00 5131.78 7600.00 1750.00 2.00 0.00 6888.10 Start DLS 1.00 TFO -52.42 1210208.39 87.91 345.82 5138.38 7744.34 1715.11 1.00 -52.42 7036.56 Start 1728.87 hold at 10208.39 MD 1311937.26 87.91 345.82 5201.52 9419.43 1291.90 0.00 0.00 8764.10 Start DLS 1.50 TFO -8.73 1412078.42 90.00 345.50 5204.10 9556.16 1256.95 1.50 -8.73 8905.22 3T-603 T1.5 042224 Start DLS 0.02 TFO -5.71 1515578.42 90.60 345.44 5185.77 12944.15 378.86 0.02 -5.7112405.03 Start DLS 1.50 TFO 93.65 1615903.52 90.29 350.31 5183.25 13261.89 310.59 1.50 93.6512729.62 Start 1048.84 hold at 15903.52 MD 1716952.36 90.29 350.31 5177.98 14295.74 134.00 0.00 0.0013773.95 Start DLS 1.50 TFO -87.17 1817239.81 90.50 346.00 5176.00 14577.00 75.00 1.50 -87.1714060.89 Start DLS 1.50 TFO -94.76 1917393.73 90.31 343.70 5174.91 14725.55 34.78 1.50 -94.7614214.79 Start 3828.52 hold at 17393.73 MD 2021222.25 90.31 343.70 5154.34 18400.12 -1039.80 0.00 0.0018042.27 3T-603 T2 052224 TD at 21222.25 39 500 500 700 700 900 900 1200 1200 1600 1600 2000 2000 3000 3000 5000 5000 8000 8000 13000 13000 21201 3T-603 wp13 Plan Summary 0 3 Dogleg Severity0 3500 7000 10500 14000 17500 21000 Measured Depth 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 15 15 30 30 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [30 usft/in] 39100200300401 501 601 3T-602 wp05 v5 39100200300400499598698797 895 994 1093 11923T-604 wp05 v5 0 3250 True Vertical Depth0 2750 5500 8250 11000 13750 16500 Vertical Section at 345.00° 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 0 30 60 Centre to Centre Separation275 550 825 1100 1375 1650 1925 Measured Depth DDI 7.035 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.10 300.00 3T-603 wp13 (3T-603) INC 300.00 3100.00 3T-603 wp13 (3T-603) MWD+IFR2+SAG+MS 3100.00 9240.00 3T-603 wp13 (3T-603) MWD+IFR2+SAG+MS 9240.00 21222.25 3T-603 wp13 (3T-603) MWD+IFR2+SAG+MS Elevation / 12.00 CASING DETAILS TVD MD Name 2535.10 3103.57 10-3/4" Surface Casing 4985.10 9244.17 7-5/8" Intermediate Casing 5154.34 21222.24 4-1/2" Production Liner Mag Model & Date: BGGM2023 15-Sep-24 Magnetic North is 14.09° East of True North (Magnetic Declinat Mag Dip & Field Strength: 80.63° 57201.92nT FORMATION TOP DETAILS TVDPath Formation 1381.10 Top Ugnu C 1601.10 Top Ugnu B 1659.10 Base Perm 1700.10 Top Ugnu A 1993.10 Top West Sak 2515.10 Base West Sak 2586.10 C-80 2644.10 C-50 3782.10 C-35 4146.10 Top Coyote (Nanushuk), K3 4205.10 Base Coyote (Nanushuk) 5005.10 Top Torok (Moraine) 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 SLB DE Checked by SLB DEC Mgr Accepted by SLB PSD Approved by CoP DE Plan 12+39.1 @ 51.10usft (D142) -25000250050007500True Vertical Depth0 2500 5000 7500 10000 12500 15000 17500Vertical Section at 345.00°10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner10002000300040005000600070008000900010000110001200013000 14000 15000 16 000 1700 0 18 000 19000 20000 2100021222 0°30°60°66°88°90°90 ° 9 0° 3T-603 wp13 Top Ugnu CTop Ugnu BBase PermTop Ugnu ATop West SakBase West SakC-80C-50C-35Top Coyote (Nanushuk), K3Base Coyote (Nanushuk)Top Torok (Moraine)3T-603 wp1314:48, May 30 2024Section View 035007000105001400017500South(-)/North(+)-14000 -10500 -7000 -3500 0 3500 7000 10500 14000West(-)/East(+)3T-603 T1 0319243T-603 T2 0522243T-603 T1.5 04222410-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner50010001500200025003000350040004500500051543T-603 wp133T-603 wp13While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.14:51, May 30 20243ODQ9LHZ 0 35 Centre to Centre Separation0 500 1000 1500 2000 2500 Partial Measured Depth3T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-603 wp13 Ladder View 0 150 300 Centre to Centre Separation0 3500 7000 10500 14000 17500 21000 Measured Depth3S-6243T-608 wp123T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-606 wp06 v53T-607 wp05 v53T-609 wp06 v53T-610 wp05 v53T-611 wp06 v53T-612 wp08 v53T-613 wp05 v53T-614 wp05 v5SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 39.10 300.00 3T-603 wp13 (3T-603) INC 300.00 3100.00 3T-603 wp13 (3T-603) MWD+IFR2+SAG+MS 3100.00 9240.00 3T-603 wp13 (3T-603) MWD+IFR2+SAG+MS 9240.00 21222.25 3T-603 wp13 (3T-603) MWD+IFR2+SAG+MS 15:17, May 30 2024 CASING DETAILS TVD MD Name 2535.10 3103.57 10-3/4" Surface Casing 4985.10 9244.177-5/8" Intermediate Casing 5154.34 21222.24 4-1/2" Production Liner 0.000.751.502.253.003.754.505.256.006.757.50Separation Factor0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 16250 17500 18750 20000 21250Measured Depth (2500 usft/in)NDST-02/NDST-02PB13S-617/3S-6173S-624/3S-6243T-608/3T-608 wpPlan: 3T-605 (05) CPlan: 3T-606 (06) Boundary (P)/3T-606 wp06 v5Plan: 3T-607 (07) Childs (P)/3T-607 wp05 v5ODST-47/ODST-47STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3T PadWell: 3T-603Wellbore: 3T-603Design: 3T-603 wp13 39 500 500 700 700 900 900 1200 1200 1600 1600 2000 2000 3000 3000 5000 5000 8000 8000 13000 13000 21223 3T-603 wp13 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] 39501001502002503003493984464955435916396867347818298769239701017 1063 3T-608 wp12 3950100150200250300351401452502553603654704754804854904953 1002 1051 1100 1149 1197 1245 1293 1341 3T-601 wp05 v5 3950100150200250300351401451501551601651 700 749 798 847 895 943 990 1037 1083 1129 1174 3T-602 wp05 v5 39501001502002503003504004504995495986486987477978468959459941044109311421192124112901339138814371487153515841633168217311781183018781926197420232071211821662214226223092357 3T-604 wp05 v5 3950100150200250300350400449498547597646695744794843892941990103910881137118612351285133413831432148015291578162716751725177518241872192119692018206621142162221122592307235524032451249925472595264326912739278628342882 3T-605 wp05 v5 3950100150200250300350399448497546594643691739787835883 930 978 1025 1073 1120 1167 1214 1261 1307 1354 1400 1446 1492 3T-606 wp06 v5 395010015020025030035039944749654559364169073878683488293097810261074112111681216126313101357 3T-607 wp05 v5 3950100150200250300349398446494542589637684732779826873920 3T-609 wp06 v5 39501001502002503003493984454935405886356837303T-610 wp05 v5 3950100150200250300349397445 3T-611 wp06 v5 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: From To Tool 39.10 300.00 INC 300.00 3100.00 MWD+IFR2+SAG+MS 3100.00 9240.00 MWD+IFR2+SAG+MS 9240.00 21222.25 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 2535.10 3103.57 10-3/4" Surface Casing4985.10 9244.17 7-5/8" Intermediate Casing5154.34 21222.24 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 1.50 3 400.00 1.50 16.00 399.99 1.26 0.36 1.50 16.00 1.12 Start DLS 2.50 TFO 0.00 4 1684.99 33.62 16.00 1609.10 369.11 105.84 2.50 0.00 329.14 Start 120.09 hold at 1684.99 MD 5 1805.08 33.62 16.00 1709.10 433.04 124.17 0.00 0.00 386.15 Start Build 2.50 6 3103.57 66.09 16.00 2535.10 1374.47 394.12 2.50 0.00 1225.63 Start 20.00 hold at 3103.57 MD 7 3123.57 66.09 16.00 2543.21 1392.05 399.16 0.00 0.00 1241.30 Start DLS 1.00 TFO -72.06 8 3174.33 66.24 15.47 2563.72 1436.74 411.76 1.00 -72.06 1281.21 Start 5617.36 hold at 3174.33 MD 9 8791.69 66.24 15.47 4826.61 6391.81 1783.35 0.00 0.00 5712.45 Start DLS 3.00 TFO -63.11 10 9859.74 83.00 347.00 5114.35 7405.91 1794.81 3.00 -63.11 6689.03 Start Build 2.00 11 10059.74 87.00 347.00 5131.78 7600.00 1750.00 2.00 0.00 6888.10 Start DLS 1.00 TFO -52.42 1210208.39 87.91 345.82 5138.38 7744.34 1715.11 1.00 -52.42 7036.56 Start 1728.87 hold at 10208.39 MD 1311937.26 87.91 345.82 5201.52 9419.43 1291.90 0.00 0.00 8764.10 Start DLS 1.50 TFO -8.73 1412078.42 90.00 345.50 5204.10 9556.16 1256.95 1.50 -8.73 8905.22 3T-603 T1.5 042224 Start DLS 0.02 TFO -5.71 1515578.42 90.60 345.44 5185.77 12944.15 378.86 0.02 -5.7112405.03 Start DLS 1.50 TFO 93.65 1615903.52 90.29 350.31 5183.25 13261.89 310.59 1.50 93.6512729.62 Start 1048.84 hold at 15903.52 MD 1716952.36 90.29 350.31 5177.98 14295.74 134.00 0.00 0.0013773.95 Start DLS 1.50 TFO -87.17 1817239.81 90.50 346.00 5176.00 14577.00 75.00 1.50 -87.1714060.89 Start DLS 1.50 TFO -94.76 1917393.73 90.31 343.70 5174.91 14725.55 34.78 1.50 -94.7614214.79 Start 3828.52 hold at 17393.73 MD 20 21222.25 90.31 343.70 5154.34 18400.12 -1039.80 0.00 0.0018042.27 3T-603 T2 052224 TD at 21222.25 3T-603 wp13AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 300.00 INC300.00 3100.00 MWD+IFR2+SAG+MS3100.00 9240.00 MWD+IFR2+SAG+MS9240.00 21222.25 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2535.103103.5710-3/4" Surface Casing4985.109244.177-5/8" Intermediate Casing5154.3421222.244-1/2" Production Liner55101015152020252530300901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [10 usft/in]39501001502002503003514014515015516016513T-602 wp05 v53950100150200250300350400450499549598648698747797846895945994104410931142119212413T-604 wp05 v539 500500 700700 900900 12001200 16001600 20002000 30003000 50005000 80008000 1300013000 21223From Colour To MD39.10 To 3200.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00400.00 16.00 16.001684.99 16.00 0.001805.08 16.00 0.003103.57 16.00 0.003123.57 16.00 0.003174.33 15.47 -72.068791.69 15.47 0.009859.74 347.00 -63.1110059.74 347.00 0.0010208.39 345.82 -52.4211937.26 345.82 0.0012078.42 345.50 -8.7315578.42 345.44 -5.7115903.52 350.31 93.6516952.36 350.31 0.0017239.81 346.00 -87.1717393.73 343.70 -94.7621222.25 343.70 0.00 3T-603 wp13AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 300.00 INC300.00 3100.00 MWD+IFR2+SAG+MS3100.00 9240.00 MWD+IFR2+SAG+MS9240.00 21222.25 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2535.103103.5710-3/4" Surface Casing4985.109244.177-5/8" Intermediate Casing5154.3421222.244-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]896390009039907991073S-624312031673216326533143363341234613510356036093T-605 wp05 v539 500500 700700 900900 12001200 16001600 20002000 30003000 50005000 80008000 1300013000 21223From Colour To MD3100.00 To 9400.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00400.00 16.00 16.001684.99 16.00 0.001805.08 16.00 0.003103.57 16.00 0.003123.57 16.00 0.003174.33 15.47 -72.068791.69 15.47 0.009859.74 347.00 -63.1110059.74 347.00 0.0010208.39 345.82 -52.4211937.26 345.82 0.0012078.42 345.50 -8.7315578.42 345.44 -5.7115903.52 350.31 93.6516952.36 350.31 0.0017239.81 346.00 -87.1717393.73 343.70 -94.7621222.25 343.70 0.00 3T-603 wp13AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 300.00 INC300.00 3100.00 MWD+IFR2+SAG+MS3100.00 9240.00 MWD+IFR2+SAG+MS9240.00 21222.25 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2535.103103.5710-3/4" Surface Casing4985.109244.177-5/8" Intermediate Casing5154.3421222.244-1/2" Production Liner75751501502252253003003753754504500901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [150 usft/in]1749139 500500 700700 900900 12001200 16001600 20002000 30003000 50005000 80008000 1300013000 21223From Colour To MD9300.00 To 21223.00MD Azi TFace39.10 0.00 0.00300.00 0.00 0.00400.00 16.00 16.001684.99 16.00 0.001805.08 16.00 0.003103.57 16.00 0.003123.57 16.00 0.003174.33 15.47 -72.068791.69 15.47 0.009859.74 347.00 -63.1110059.74 347.00 0.0010208.39 345.82 -52.4211937.26 345.82 0.0012078.42 345.50 -8.7315578.42 345.44 -5.7115903.52 350.31 93.6516952.36 350.31 0.0017239.81 346.00 -87.1717393.73 343.70 -94.7621222.25 343.70 0.00 3T-603 wp13Spider Plot16:47, May 30 202439.10 To 21222.25Northing (6500 usft/in)Easting (6500 usft/in)454749515355575961636567Colville Delta 245474951NDST-024547495153NDST-02PB1454749513S-617454749513S-6244 54749515 35557596163ODSN-174 54749515 355575961ODSN-17L145474951ODST-47454749513T-608 wp1245474951535 5 3T-6214 54749513T-601 wp05 v54 5474951 533T-602 wp05 v5454749513T-604 wp05 v5454749513T-605 wp05 v5454749513T-606 wp06 v5454749513T-607 wp05 v5454749513T-609 wp06 v5454749513T-610 wp05 v5454749513T-611 wp06 v5454749513T-612 wp08 v5454749513T-613 wp05 v54 54749 513T-614 wp05 v54 54 749513T-615 wp05 v5454749513T-616 wp05 v5454749513T-617 wp05 v54 54 749513T-618 wp05 v5454749513T-619 wp06 v54 54 749513T-620 wp05 v5454749513T-622 wp05 v54 54 749513T-623 wp05 v5454749513T-624 wp05 v5454749513T-625 wp05 v54 54 749513T-626 wp05 v5454 749 513T-627 wp05 v54 547 493T-628 wp05 v54547493T-629 wp05 v53T-730 (I14) wp083T-731 (P14) wp084547493T-603 wp13 3T-603 wp13Spider Plot16:48, May 30 202439.10 To 21222.25Northing (1500 usft/in)Easting (1500 usft/in)2527293133353739414345474951NDST-02252729313335373941434547495153NDST-02PB13S-6173S-62425272931333537394143454749513T-608 wp122527293133353739414345474951535 5 3T-6212 5 2 7 2 9 3 1 3 3 3 5 3 7 3 9 4 1 4 3 4 54749513T-601 wp05 v52 5 2 7 2 9 3 1 3 3 3 5 3 7 3 9 4 1 4 3 4 54749513T-602 wp05 v525272931333537394143454749513T-604 wp05 v525272931333537394143454749513T-605 wp05 v525272931333537394143454749513T-606 wp06 v525272931333537394143454749513T-607 wp05 v525272931333537394143454749513T-609 wp06 v525272931333537394143454749513T-610 wp05 v525272931333537394143454749513T-611 wp06 v525272931333537394143454749513T-612 wp08 v525272931333537394143453T-613 wp05 v53T-614 wp05 v5252729313335373T-615 wp05 v53T-616 wp05 v525272931333537394143454749513T-617 wp05 v5252729313335373T-618 wp05 v525272931333537394143453T-619 wp06 v5252729313335373T-620 wp05 v5252729313335373941433T-622 wp05 v52527293133353T-623 wp05 v52527293133353739624 wp05 v525272931333537393T-625 wp05 v525272931333T-626 wp05 v53T-627 wp05 v52527 2 9 3 1 3 3 3 5 3T-628 wp05 v5252729313335373T-629 wp05 v5252 7293 1333537393T-730 (I14) wp082 527293133 353739413T-731 (P14) wp08252729313335373941434547493T-603 wp13 3T-603 wp13Spider Plot16:56, May 30 202439.10 To 21222.25Northing (300 usft/in)Easting (300 usft/in)15171921NDST-0215171921NDST-02PB11517192123252729313T-608 wp12151719213T-621151 71 9 2 1 2 3 2 5 2 7 3T-601 wp05 v51 5 1 7 1 9 2 1 2 3 2 5 3T-602 wp05 v5151719212325273T-604 wp05 v5151719212325273T-605 wp05 v515171921232527293T-606 wp06 v515171921232527293T-607 wp05 v51517192123252729313T-609 wp06 v515171921232527293T-610 wp05 v515171921232527293133353T-611 wp06 v5151719212325273T-612 wp08 v515171921232527293T-613 wp05 v5153T-614 wp05 v51517192123253T-615 wp05 v5153T-616 wp05 v515171921232527293T-617 wp05 v51517192123253T-618 wp05 v51517192123253T-619 wp06 v515171921233T-620 wp05 v51517192123253T-622 wp05 v515171921233T-623 wp05 v515171921233T-624 wp05 v5151719213T-625 wp05 v5151719213T-626 wp05 v53T-627 wp05 v5151719213T-628 wp05 v515171921233T-629 wp05 v51517192123252 7 293T-730 (I14) wp0815171921232 52 72931 3335373T-731 (P14) wp081517192123253T-603 wp13 3T-603 wp13Spider Plot16:58, May 30 202439.10 To 21222.25Northing (60 usft/in)Easting (60 usft/in)246810121416183T-608 wp12246810121416 3T-601 wp05 v524 6 8 1 0 1 2 1 4 3T-602 wp05 v52468101214163T-604 wp05 v52468101214163T-605 wp05 v5246810121416183T-606 wp06 v5246810121416183T-607 wp05 v5810121416183T-609 wp06 v5810121416183T-610 wp05 v512143T-611 wp06 v524681012143T-603 wp13 3T-603 wp13Colville Delta 2NDST-02NDST-02PB13S-6173S-624ODSN-17ODSN-17L1ODST-473T-608 wp123T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-606 wp06 v53T-607 wp05 v53T-610 wp05 3T-63T-616 wp05 v53-D View3T-603 wp1317:03, May 30 2024 3T-603 wp13Colville Delta 2NDST-02NDST-02PB13S-6173S-624ODSN-17ODSN-17L1ODST-473T-608 wp123T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-605 wp05 v53T-606 wp06 v53T-607 wp05 v53T-610 wp05 v53-D View3T-603 wp1317:04, May 30 2024 750010000125001500017500South(-)/North(+) (2500 usft/in)-7500 -5000 -2500 0 2500 5000 7500 10000West(-)/East(+) (2500 usft/in)49505000505051005150Colville Delta 249505000505051005150NDST-0249505000505051005150NDST-02PB13S-6173S-624ODSN-17ODSN-17L149505000505051005150ODST-47495050005050510051503T-608 wp123T-601 wp05 v53T-602 wp05 v5495050005050510051503T-604 wp05 v5495050005050510051503T-605 wp05 v5495050005050510051503T-606 wp06 v5495050005050510051503T-607 wp05 v5495050005050510051503T-609 wp06 v5495050005050510051503T-610 wp05 v53T-611 wp06 v53T-612 wp08 v5495050005050510051503T-613 wp05 v53T-616 wp05 v53T-617 wp05 v5510051503T-619 wp06 v53T-622 wp05 v5495050005050510051503T-603 wp133T-603 wp13Quarter Mile View17:09, May 30 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-603 T1.5 042224 5204.10 Circle (Radius: 100.00)3T-603 T2 052224 5154.34 Circle (Radius: 100.00)3T-603 T1 031924 5131.78 Circle (Radius: 100.00)3T-603 T1 QM 5131.78 Circle (Radius: 1350.00)3T-603 T1.5 QM 5204.10 Circle (Radius: 1350.00)3T-603 T2 QM 5154.34 Circle (Radius: 1320.00) 750010000125001500017500South(-)/North(+) (2500 usft/in)-7500 -5000 -2500 0 2500 5000 7500 10000West(-)/East(+) (2500 usft/in)49505000505051005150Colville Delta 23S-6173S-62449505000505051005150ODST-47495050005050510051503T-608 wp12495050005050510051503T-605 wp05 v5495050005050510051503T-603 wp133T-603 wp13Quarter Mile View17:12, May 30 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-603 T1.5 042224 5204.10 Circle (Radius: 100.00)3T-603 T2 052224 5154.34 Circle (Radius: 100.00)3T-603 T1 031924 5131.78 Circle (Radius: 100.00)3T-603 T1 QM 5131.78 Circle (Radius: 1350.00)3T-603 T1.5 QM 5204.10 Circle (Radius: 1350.00)3T-603 T2 QM 5154.34 Circle (Radius: 1320.00) WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-603 T1.5 042224 5204.10 Circle (Radius: 100.00)3T-603 T2 052224 5154.34 Circle (Radius: 100.00)3T-603 Srf Csg 2535.10 Circle (Radius: 500.00)3T-603 T1 031924 5131.78 Circle (Radius: 100.00)3T-603 T1 QM 5131.78 Circle (Radius: 1350.00)3T-603 T1.5 QM 5204.10 Circle (Radius: 1350.00)3T-603 T2 QM 5154.34 Circle (Radius: 1320.00)3T-603 wp13Surface Casing 500'r7501000125015001750South(-)/North(+) (250 usft/in)-250 0 250 500 750 1000 1250 1500West(-)/East(+) (250 usft/in)2520NDST-022520NDST-02PB1252025403T-608 wp122 5 2 025403T-601 wp05 v5252025403T-604 wp05 v5252025403T-605 wp05 v5252025403T-606 wp06 v5252025403T-607 wp05 v5252025403T-609 wp06 v5252025403T-610 wp05 v510-3/4" Surface Casing252025403T-603 wp1317:28, May 30 2024 3T-603wp13 Surface Location 3T-603wp13 Surface Location #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-603wp13 Surface Casing 3T-603wp13 Surface Casing #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-603wp13 Intermediate Csg 3T-603wp13 Intermediate Csg #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-603wp13 Top Torok (Moraine) 3T-603wp13 Top Torok (Moraine) #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 3T-603wp13 TD 3T-603wp13 TD #^ĐŚůƵŵďĞƌŐĞƌͲŽŶĨŝĚĞŶƚŝĂů 1 Dewhurst, Andrew D (OGC) From:Smith, Matt <Matt.Smith2@conocophillips.com> Sent:Friday, June 21, 2024 7:07 AM To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC) Subject:Re: [EXTERNAL]RE: KRU- 3T-603 (PTD 224-074) - Additional Information Needed Hi Steve, apologies for the delayed response. Anticipated gradient is 0.44psi/ft, ~2300psi at ~5200' TVD. We do not anticipate H2S, but we do have sensors on the rig. Thanks, Matt Smith 432-269-6432 From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, June 20, 2024 1:33 PM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]RE: KRU- 3T-603 (PTD 224-074) - Additional Information Needed CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Matt, I’m just checking to see if you received my request, below. I’d like to keep this application moving through AOGCC’s review process. Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov From: Davies, Stephen F (OGC) Sent: Tuesday, June 18, 2024 9:46 AM To: Smith, Matt <Matt.Smith2@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: KRU- 3T-603 (PTD 224-074) - Additional Information Needed Matt, 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 I’m reviewing CPAI’s Permit to Drill application for this well, and I’d like to request additional information: x Please confirm the expected pressure gradient from base conductor to TD of the well. x This will be the first well drilled to the northernmost portion of the reservoir. Is H2S anticipated? I believe the rig will have H2S sensors and alarms. Correct? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KUPARUK RIVER KUPARUK RIVER, TOROK OIL KRU 3T-603 224-074 WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3T-603Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240740KUPARUK RIVER, TOROK OIL - 490169NA1Permit fee attachedYesSurface Location lies within ADL0025528; Top Prod Int & TD lie within ADL0393883.2Lease number appropriateYes3Unique well name and numberYesKUPARUK RIVER, TOROK OIL - 490169 - governed by CO 725A4Well located in a defined poolYesTD will lie 723' south of the northern KRU boundary line.5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes81' conductor driven18Conductor string providedYesSC set at 3103' MD19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgNoProductive interval will be completed with uncemented liner with frac sleeves and swell packers22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesAnti-collision analysis complete; no major risk failures26Adequate wellbore separation proposedYes27If diverter required, does it meet regulationsYesMax Reservoir pressure is 2305 psig(8.9 ppg EMW); will drill w/ 9.0-10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1789 psig; will test BOPs to 5000 psig initially and 4000 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 shutdownYes33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)NoMeasures required: Previously untapped portion of reservoir; H2S is present in 3S-Pad wells to south.35Permit can be issued w/o hydrogen sulfide measuresYesReservoir anticipated to be normally pressured (8.6 ppg EMW)36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/18/2024ApprVTLDate7/15/2024ApprADDDate6/21/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 7/19/2024
