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HomeMy WebLinkAbout224-034Originated: Delivered to:9-Dec-24 Alaska Oil & Gas Conservation Commiss 09Dec24-NR ATTN: Meredith Guhl 333 W. 7th Ave., Suite 100 600 E 57th Place Anchorage, Alaska 99501-3539 Anchorage, AK 99518 (907) 273-1700 main (907)273-4760 fax WELL NAME API # SERVICE ORDER #FIELD NAME SERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED 1R-03A 50-029-21406-01-00 200-021 Kuparuk River WL IPROF FINAL FIELD 8-Nov-24 3S-718 50-103-20884-00-00 224-034 Kuparuk River WL TTiX PPROF FINAL FIELD 20-Nov-24 2B-11 50-029-21089-00-00 184-035 Kuparuk River WL IPROF FINAL FIELD 22-Nov-24 3S-617 50-103-20864-00-00 223-085 Kuparuk River WL IPROF FINAL FIELD 30-Nov-24 3M-22 50-029-21740-00-00 187-067 Kuparuk River WL LDL FINAL FIELD 2-Dec-24 1J-156 50-029-23311-00-00 206-067 Kuparuk River WL IPROF FINAL FIELD 2-Dec-24 2H-11 50-103-20052-00-00 185-261 Kuparuk River WL IPROF FINAL FIELD 4-Dec-24 Transmittal Receipt ________________________________ X_________________________________ Print Name Signature Date Please return via courier or sign/scan and email a copy to Schlumberger. Nraasch@slb.com SLB Auditor - TRANSMITTAL DATE TRANSMITTAL # 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-Private T39843 T39844 T39845 T39846 T39847 T39848 T39849 3S-718 50-103-20884-00-00 224-034 Kuparuk River WL TTiX PPROF FINAL FIELD 20-Nov-24 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.10 08:20:31 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17716 feet feet true vertical 4194 feet feet Effective Depth measured 17716 feet 9050 / 9176 feet true vertical 4194 feet 4179 / 4206 feet Perforation depth Measured depth feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 9,190' MD 4209' TVD HES TNT 9,050' MD 4,179' TVD Packers and SSSV (type, measured and true vertical depth) Baker LTP 9,176' MD 4,206' 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: 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 Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 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. Madeline Woodard 7.625" 11590 7.625" P.O. Box 100360 Anchorage, Alaska, 99510-03603. Address: KRU 3S-718 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf MD 9,584-17,532' MD measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 10.75" 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL380107, ADL025546, ADL380106 KRU Undefined Pool ConocoPhillips Alaska, Inc. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-034 50-103-20884-00-00 Size 129 measured TVD Production Liner 8387 973 8535 Casing Structural 3994 4240 4.5" 8387 9360 17711 4194 Plugs Junk measured Length 129 3942 129 madeline.e.woodard@cop.com 907-265-6086Senior Completions Engineer 3942 2596 Burst Collapse 2470 4790 7850 5210 6890 10860 5.1MMlbs 16/20 Wanli LWC proppant, 75,000 lbs 100M, 5466 psi downhole Conductor Surface Intermediate 20" p k ft t Fra O s O 224 6. A G L PG , C Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Sundry Number or N/A if C.O. Exempt: 324-468 By Grace Christianson at 1:12 pm, Sep 30, 2024 Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard @conocophillips.com Reason: I am the author of this document Location: Date: 2024.09.30 12:11:17-08'00' Foxit PDF Editor Version: 13.0.0 Madeline Woodard                                          Page 4/8 3S-718 Report Printed: 9/26/2024 Well History Left START DATE is from Daily Ops and Right Start Date represents the Job Start Start Date Last 24hr Sum Network/Order Number Rig Supervisor Job Type Start Date Primary Wellbore Affected 9/7/2024 COMPLETE RUNNING ALL HARDLINE. SETTING UP DAS SYSTEM. 10458411 TUCKER, LONNY,Wells Supervisor INITIAL COMPLETION 9/4/2024 3S-718 9/6/2024 COMPLETE RUNNING HARDLINE INSIDE EQUIPMENT BERM AND TANK FARM. EQUIPMENT POWERED UP. 10458411 TUCKER, LONNY,Wells Supervisor INITIAL COMPLETION 9/4/2024 3S-718 9/5/2024 ALL FLOWBACK EQUIPMENT AND TANKS ARE ON LOCATION. CONTINUE RIGGING UP HARDLINE AND FUNCTION TESTING EQUIPMENT. 10458411 TUCKER, LONNY,Wells Supervisor INITIAL COMPLETION 9/4/2024 3S-718 9/4/2024 EXPRO CREW ARRIVE ON LOCATION, PERFORM WALKDOWN. LAY DOWN EQUIPMENT CONTAINMENT AND RIG MATTS. 10458411 TUCKER, LONNY,Wells Supervisor INITIAL COMPLETION 9/4/2024 3S-718 9/2/2024 CONTINUED TOPPING OFF TANK FARM, RIG DOWN LAUNCHER, GOAT HEAD, FRONT YARD IRON. BROKE IRON BACK TO VALVE HOUSE FOR 3S-722. 10451695 BURKETT, CHAD,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 9/1/2024 COMPLETED STAGES 14-17 STIM, DFIT PERFORMED AFTER SLEEVE SHIFT ON STAGE 16, TOTAL CLEAN VOLUME DAY, 7,119 BBL, TOTAL PROPPANT DAY, 1,224, 218 LB.RESMETRIC TRACER ADDED PER DESIGN, PROTECNICS TRACER DURING THE SAND STAGES. DURING FLUSH ON STAGE 17 PRESSURE ROSE AND KICKED OUT THE PUMPS AT 6816 PSI ON SURFACE AND 9340 PSI ON THE DOWNHOLE GAUGE, INJECTION WAS UNABLE TO BE RESTABLISHED,ALL SURFACE LINES WERE FLUSHED AND A TOTAL OF23,360 LBS OF PROPPANT WAS LEFT IN THE WELLBORE, SLURY TOP AT~ 4255' STAGE 14 DART SEAT 1 BBL EARLY DIFFERENTIAL 3450 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1668 BBL, TOTAL PROPPANT PLACED 309,932 AVG PSI 2780, AVG RATE 19.8 BPM STAGE 15 DART SEAT 2 BBL LATE DIFFERENTIAL 3707 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2032 BBL, TOTAL PROPPANT PLACED 304,883 , AVG PSI 2044, AVG RATE 19.9 BPM STAGE 16 DART SEAT 0 BBL EARLY/LATE DIFFERENTIAL 3222 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1652 BBL, TOTAL PROPPANT PLACED 303,601 , AVG PSI 2278, AVG RATE 20 BPM STAGE 17 DART SEAT 6 BBL LATE DIFFERENTIAL 4185 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1767 BBL, TOTAL PROPPANT PLACED 305,802 , AVG PSI 2011 AVG RATE 19.9 BPM 10451695 BURKETT, CHAD,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 Page 5/8 3S-718 Report Printed: 9/26/2024 Well History Left START DATE is from Daily Ops and Right Start Date represents the Job Start Start Date Last 24hr Sum Network/Order Number Rig Supervisor Job Type Start Date Primary Wellbore Affected 8/31/2024 COMPLETED STAGES 10-13 STIM, DFIT PERFORMED AFTER SLEEVE SHIFT ON STAGE 12, TOTAL CLEAN VOLUME FOR THE DAY 7,225 BBL, TOTAL PROPPANT 1,226,641 LB.RESMETRIC TRACER ADDED PER DESIGN PROTECNICS TRACER STARTED ON STAGE 11DURING THE SAND STAGES STAGE 10 DART SEAT 1 BBL EARLY DIFFERENTIAL 4298PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1790 BBL, TOTAL PROPPANT PLACED 305099, AVG PSI 2780, AVG RATE 20 BPM STAGE 11 DART SEAT 2 BBL LATE DIFFERENTIAL 4511 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1637 BBL, TOTAL PROPPANT PLACED 304918 , AVG PSI 3384, AVG RATE 19.7 BPM STAGE 12 DART SEAT 0 BBL EARLY/LATE DIFFERENTIAL 3943 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1986 BBL, TOTAL PROPPANT PLACED 311663 , AVG PSI 2509, AVG RATE 19.8 BPM STAGE 13 DART SEAT 2 BBL LATE DIFFERENTIAL 3820 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1812 BBL, TOTAL PROPPANT PLACED 304961 , AVG PSI 3204 AVG RATE 19.7 BPM 10451695 BURKETT, CHAD,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/30/2024 COMPLETED STAGE 6 DFIT, STAGES 6-9 STIM TOTAL CLEAN VOLUME FOR THE DAY 7428 BBL, TOTAL PROPPANT 1,217,083 LB.RESMETRIC TRACER ADDED PER DESIGN STAGE 6 DART SEAT 6 BBL EARLY DIFFERENTIAL 4285 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2086 BBL, TOTAL PROPPANT PLACED 305683, AVG PSI 2698, AVG RATE19.6 BPM STAGE 7 DART SEAT 0 BBL EARLY DIFFERENTIAL 3827 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1706 BBL, TOTAL PROPPANT PLACED 303712 , AVG PSI 2605, AVG RATE 19.9 6BPM STAGE 8 DART SEAT 5 BBL EARLY DIFFERENTIAL 4651 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1703 BBL, TOTAL PROPPANT PLACED 304132 , AVG PSI 2900, AVG RATE 19.8 BPM STAGE 9 DART SEAT 0 BBL EARLY DIFFERENTIAL 3817 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1933 BBL, TOTAL PROPPANT PLACED 303556 , AVG PSI 2377 AVG RATE 120 BPM 10451695 BURKETT, CHAD,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/29/2024 COMPLETED STAGES 2-5, AND MINI FRAC RESMETRIC TRACER ADDED PER DESIGN STAGE 2 DART SEAT 8 BBL EARLY DIFFERENTIAL 4200 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2013 BBL, TOTAL PROPPANT PLACED 304442, AVG PSI 2417, AVG RATE19.6 BPM STAGE 3 DART SEAT 19 BBL EARLY DIFFERENTIAL 4043 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 1583 BBL, TOTAL PROPPANT PLACED 266572 , AVG PSI 2142, AVG RATE 19.8 BPM STAGE 4 DART SEAT 0 BBL EARLY DIFFERENTIAL 4643 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2194 BBL, TOTAL PROPPANT PLACED 304973 , AVG PSI 2116, AVG RATE 16.9 BPM STAGE 5 DART SEAT 2 BBL EARLY DIFFERENTIAL 4144 PSI SURFACE, TOTAL CLEAN VOLUME PUMPED 2785 BBL, TOTAL PROPPANT PLACED 303876 , AVG PSI 2563 AVG RATE 19.7BPM 10451695 BURKETT, CHAD,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 Page 6/8 3S-718 Report Printed: 9/26/2024 Well History Left START DATE is from Daily Ops and Right Start Date represents the Job Start Start Date Last 24hr Sum Network/Order Number Rig Supervisor Job Type Start Date Primary Wellbore Affected 8/28/2024 COMPLETE DIAGNOSTIC PUMPING, DFIT AND SRT. STIMULATE STAGE 1 PER DESIGN w/ 5174 LBS OF 100 MESH & 302161 LBS OF 16/20 PROPPANT UP TO 11.6 PPG. 3449 BBL FLUID PUMPED. (PATINA AND RESMETRIC TRACER ADDED PER SCHEDULE) 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/27/2024 HES-ON STAND BY FOR APPROVAL TO PUMP THE PW, AWAITING GLOBAL HSE. CONTINUE TO LOAD SW 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/26/2024 HES-ON STAND BY UNTIL THEIR GLOBAL DECIDES PATH FWD WITH PW LOIL-CONTINUE UNLOADING SAND CONTAINERS AND ASSIST HES WITH LOADING WATER PW-PROCESS WATER AS DIRECTED INTO TEST TANKS 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/25/2024 HES-LOAD GEL, VERIFIY EQUIPMENT COMMS WITH VAN, PATCH LINER. ON STAND BY AWAITING DECISION FOR WATER LOIL-EMPTYING SAND CONTAINERS, PREP SAND FOR JOB PW-PROCESS WATER INTO 3 TEST TANKS WITH NEW OIL REMOVAL CHEMICAL, SHUT DOWN FOR LAB ANALYSIS 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/24/2024 FRAC-FUNCTION TEST BACKSIDE EQUIPMENT, SPOT DATA VAN PW-UNIT DOWN DUE TO OIL IN WATER PER HES, DETERMINED BY TOWN TO ADD CHEMICAL TO REMOVE THE OIL FROM WATER. TBIRD PICKING UP CHEMICAL AND NEEDED HARDWARE TO RIG UP IN UNIT LOIL-UNLOADING SAND CONTAINERS, LOAD REMAINING BULKERS 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/23/2024 FRAC-FINSH RIGGING UP TO WELL, HANG DART LAUNCH, RIG IN IA/OA, SPOT CHEMICALS LOIL-FINISH OFFLOADING SAND PW-WORKING THROUGH OIL IN WATER ISSUES THAT HES WILL ACCEPT 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/22/2024 FRAC-RIG UP BACKSIDE EQUIPMENT, SPOT GEL TRUCK. PW-BEGAN TREATING WATER AROUND 1600 LOIL-LOADING SAND, MOVER FULL, 512 BAGS STAGED FOR JOB 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/20/2024 Frac-Rig up hardline from missile to near well, spot open top and prv tanks Lynden- Staging sand on 3S from 3T, rigging up test tank lines 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/20/2024 SET 4.5'' SLIP STOP CATCHER @ 3323' RKB, REPLACED ST#1 @ 3239' RKB W/ 1'' INCONEL BOTTOM LATCH DMY VLV, OBTAINED PASSING MITT & MITIA, PULLED 4.5'' SLIPSTOP CATCHER @ 3323' RKB. READY FOR FRAC 10458411 ROGERS, BRENT,Wells Supervisor INITIAL COMPLETION 8/19/2024 3S-718 8/19/2024 ATTEMPT TO SET 4.5'' SLIP STOP CATCHER. JOB IN PROGRESS 10458411 ROGERS, BRENT,Wells Supervisor INITIAL COMPLETION 8/19/2024 3S-718 8/14/2024 Frac-Mob pumps from DH to 3S, spot/rig up missile and pumps 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/12/2024 Frac-Spot backside equipment and sand equipment 10451695 FAUR, DAN,Wells Supervisor INITIAL COMPLETION 8/4/2024 3S-718 8/9/2024 N/U FMC 10K frac tree and test to 10,000 psi for 15 min. Pull HP-BPV. R/U LRS and freeze protect well with 90 bbls diesel. Secure well and release rig at 12:00 Hrs. R/D and prep for move to 3S-722. 10451694 Michael Tucker,Drilling Supervisor DRILLING ORIGINAL 7/13/2024 3S-718 Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pulled SOV, set Inconel top sub DMY 3S-718 8/20/2024 rogerba Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread Conductor 20 18.50 39.0 119.0 119.0 78.85 X65 Welded Surface 10 3/4 9.95 38.5 3,942.2 2,595.8 45.50 L-80 Hydril 563 Intermediate 7 5/8 6.87 37.6 9,360.3 4,240.6 29.70 L-80 Hydril 563 Liner 4 1/2 3.96 9,176.3 17,711.0 4,193.8 12.60 P110S Hydril 563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 36.1 Set Depth … 9,189.9 String Max No… 4 1/2 Set Depth … 4,208.7 Tubing Description Tubing – Completion Upper Wt (lb/ft) 12.60 Grade L-80 Top Connection Hydril 563 MS ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 36.1 36.1 0.00 Stream Flo Hanger W/4" H- BPV 10.850 Stream Flo DMLX 3.900 3,239.5 2,364.9 76.06 Mandrel – GAS LIFT 6.015 Camco KBGM 3.865 8,066.4 3,884.4 69.29 Mandrel – GAS LIFT 6.013 Camco KBGM 3.865 8,836.4 4,126.5 74.66 HES Opsis Gauge 5.675 HES Opsis DHG Gauge 3.920 8,943.1 4,153.8 75.63 Sleeve - Sliding 5.500 NEXA-2 Up to open 3.813 9,050.0 4,179.1 77.00 Packer 6.375 HES TNT 3.856 9,116.3 4,193.6 77.79 Nipple - DB 3.75" 5.207 Camco 3.75" DB Nipple 3.750 9,169.1 4,204.5 78.33 Sub - Shear Out - SOS 5.450 Arsenal Glass Burst Disk 3.833 9,180.7 4,206.8 78.43 Locator 5.290 Locator Above no go 3.890 9,181.3 4,207.0 78.44 Locator 5.630 Locator 3.890 9,186.6 4,208.0 78.49 Shoe - Mule 4.500 HES Indexing mule shoe 3.910 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 4,255.0 2,687.3 73.00 SAND top of 12# proppant laden crosslink gel, after fluid break proppant top ~5328' 9/1/2024 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 3,239.5 2,364.9 76.06 1 GAS LIFT DMY BTM 1 8/20/2024 Incon el top sub CAMCO KBG-4-5 8,066.4 3,884.4 69.29 2 GAS LIFT DV BK-2 1 8/8/2024 CAMCO KBG-4-5 1.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,176.3 4,206.0 78.40 Packer 6.550 Baker ZXP LTP W/11.26' x 5.75" ID tie back sleeve 4.800 9,196.2 4,209.9 78.57 Nipple - RS 6.060 Baker RS packoff seal nipple 4.250 9,206.9 4,212.1 78.66 XO Reducing 6.050 XO - 4.5"x5.5" 3.900 9,584.5 4,271.9 83.54 Sleeve - Frac #16 5.500 AU Limitless Single point closable 3.500 10,042.2 4,272.2 93.39 Sleeve - Frac #15 5.500 AU Limitless Single point closable 3.500 10,458.8 4,256.8 90.98 Sleeve - Frac #14 5.500 AU Limitless Single point closable 3.500 11,069.3 4,251.0 90.44 Sleeve - Frac #13 5.500 AU Limitless Single point closable 3.500 11,524.5 4,247.4 90.40 Sleeve - Frac #12 5.500 AU Limitless Single point closable 3.500 12,025.0 4,243.3 90.48 Sleeve - Frac #11 5.500 AU Limitless Single point closable 3.500 12,604.6 4,238.9 90.47 Sleeve - Frac #10 5.500 AU Limitless Single point closable 3.500 13,061.2 4,235.3 90.51 Sleeve - Frac #9 5.500 AU Limitless Single point closable 3.500 HORIZONTAL, 3S-718, 9/26/2024 3:25:07 PM M D (ft KB ) -17,015.4 -3,943.9 -3,881.2 -3,745.1 -402.2 -323.5 -281.8 -26.9 -24.0 -20.0 -18.0 -15.4 -13.1 -10.2 -3.9 -1.6 36.1 38.4 40.0 118.4 155.8 3,239.5 3,857.6 4,254.9 8,083.3 8,836.3 8,943.2 9,049.9 9,116.5 9,170.9 9,183.1 9,198.5 9,226.4 9,360.2 9,586.0 10,042.3 10,461.0 11,071.5 11,527.6 12,604.7 13,061.0 13,519.7 14,509.5 15,006.9 15,503.9 15,998.4 16,541.7 17,035.8 17,535.4 17,624.0 20,000.0 Vertical schematic (actual) Perf; 20,000.0-20,002.0 Float Shoe; 17,707.2-17,711.0; 3.85; 4-45; 5.200; 3.410 Liner; 17,624.0-17,707.2; 83.19; 4-44; 4.500; 3.958Collar - Landing; 17,622.3-17,624.0; 1.70; 4-43; 5.190; 3.890 Liner; 17,580.7-17,622.3; 41.58; 4-42; 4.500; 3.958 Sleeve - Setting; 17,577.0-17,580.7; 3.69; 4-41; 5.640; 3.000 Liner; 17,535.4-17,577.0; 41.60; 4-40; 4.500; 3.958 Sleeve - Setting; 17,531.7-17,535.4; 3.70; 4-39; 5.610; 3.020 Liner; 17,034.8-17,531.7; 496.87; 4-38; 4.500; 3.958 Sleeve - Frac #1; 17,032.5-17,034.8; 2.31; 4-37; 5.500; 3.500 Liner; 16,541.2-17,032.5; 491.31; 4-36; 4.500; 3.958 Sleeve - Frac #2; 16,538.9-16,541.2; 2.31; 4-35; 5.500; 3.500 Liner; 16,000.6-16,538.9; 538.24; 4-34; 4.500; 3.958 Sleeve - Frac #3; 15,998.3-16,000.6; 2.31; 4-33; 5.500; 3.500 Liner; 15,506.0-15,998.3; 492.35; 4-32; 4.500; 3.958 Sleeve - Frac #4; 15,503.7-15,506.0; 2.31; 4-31; 5.500; 3.500 Liner; 15,009.6-15,503.7; 494.09; 4-30; 4.500; 3.958 Sleeve - Frac #5; 15,007.3-15,009.6; 2.31; 4-29; 5.500; 3.500 Liner; 14,511.9-15,007.3; 495.42; 4-28; 4.500; 3.958 Sleeve - Frac #6; 14,509.5-14,511.9; 2.31; 4-27; 5.500; 3.500 Liner; 14,016.8-14,509.5; 492.75; 4-26; 4.500; 3.958 Sleeve - Frac #7; 14,014.5-14,016.8; 2.31; 4-25; 5.500; 3.500 Liner; 13,519.7-14,014.5; 494.83; 4-24; 4.500; 3.958 Sleeve - Frac #8; 13,517.4-13,519.7; 2.31; 4-23; 5.500; 3.500 Liner; 13,063.5-13,517.4; 453.86; 4-22; 4.500; 3.958 Sleeve - Frac #9; 13,061.2-13,063.5; 2.31; 4-21; 5.500; 3.500 Liner; 12,606.9-13,061.2; 454.27; 4-20; 4.500; 3.958 Sleeve - Frac #10; 12,604.6-12,606.9; 2.31; 4-19; 5.500; 3.500 Liner; 12,027.3-12,604.6; 577.25; 4-18; 4.500; 3.958 Sleeve - Frac #11; 12,025.0-12,027.3; 2.31; 4-17; 5.500; 3.500 Liner; 11,526.8-12,025.0; 498.19; 4-16; 4.500; 3.958 Sleeve - Frac #12; 11,524.5-11,526.8; 2.31; 4-15; 5.500; 3.500 Liner; 11,071.6-11,524.5; 452.91; 4-14; 4.500; 3.958 Sleeve - Frac #13; 11,069.3-11,071.6; 2.31; 4-13; 5.500; 3.500 Liner; 10,461.1-11,069.3; 608.24; 4-12; 4.500; 3.958 Sleeve - Frac #14; 10,458.8-10,461.1; 2.31; 4-11; 5.500; 3.500 Liner; 10,044.5-10,458.8; 414.25; 4-10; 4.500; 3.958 Sleeve - Frac #15; 10,042.2-10,044.5; 2.31; 4-9; 5.500; 3.500 Liner; 9,586.8-10,042.2; 455.42; 4-8; 4.500; 3.958 Sleeve - Frac #16; 9,584.5-9,586.8; 2.31; 4-7; 5.500; 3.500 Liner; 9,212.5-9,584.5; 372.02; 4-6; 4.500; 3.958 Float Shoe; 9,357.2-9,360.3; 3.08; 3-7; 7.625; 6.875 Casing Jts; 9,272.1-9,357.2; 85.14; 3-6; 7.625; 6.875 Float Collar; 9,269.4-9,272.1; 2.71; 3-5; 7.625; 6.875 Casing Jts; 9,226.3-9,269.4; 43.07; 3-4; 7.625; 6.875 Liner Pup Joint; 9,208.6-9,212.5; 3.83; 4-5; 4.500; 3.958 XO Reducing; 9,206.9-9,208.6; 1.69; 4-4; 6.050; 3.900 Hanger; 9,198.5-9,206.9; 8.44; 4-3; 6.450; 4.800 Nipple - RS; 9,196.2-9,198.5; 2.33; 4-2; 6.060; 4.250 Shoe - Mule; 9,186.6-9,189.9; 3.30; 1-36; 4.500; 3.910 Packer; 9,176.3-9,196.2; 19.87; 4-1; 6.550; 4.800 Tubing - Pup Joint; 9,183.2-9,186.6; 3.41; 1-35; 4.500; 3.958 Locator; 9,181.3-9,183.2; 1.88; 1-34; 5.630; 3.890Locator; 9,180.7-9,181.3; 0.62; 1-33; 5.290; 3.890 Tubing - Pup Joint; 9,171.0-9,180.7; 9.72; 1-32; 4.500; 3.958 Sub - Shear Out - SOS; 9,169.1-9,171.0; 1.83; 1-31; 5.450; 3.833 Tubing; 9,127.6-9,169.1; 41.49; 1-30; 4.500; 3.958 Tubing - Pup Joint; 9,117.9-9,127.6; 9.72; 1-29; 4.500; 3.958 Nipple - DB 3.75"; 9,116.3-9,117.9; 1.61; 1-28; 5.207; 3.750 Tubing - Pup Joint; 9,106.6-9,116.3; 9.71; 1-27; 4.500; 3.958 Tubing; 9,065.1-9,106.6; 41.48; 1-26; 4.500; 3.958 Tubing - Pup Joint; 9,055.4-9,065.1; 9.71; 1-25; 4.500; 3.958 Packer; 9,050.0-9,055.4; 5.43; 1-24; 6.375; 3.856 Tubing - Pup Joint; 9,040.6-9,050.0; 9.38; 1-23; 4.500; 3.958 Tubing; 8,957.8-9,040.6; 82.86; 1-22; 4.500; 3.958 Tubing - Pup Joint; 8,948.0-8,957.8; 9.72; 1-21; 4.500; 3.958 Sleeve - Sliding; 8,943.1-8,948.0; 4.95; 1-20; 5.500; 3.813 Tubing - Pup Joint; 8,933.3-8,943.1; 9.75; 1-19; 4.500; 3.958 Tubing; 8,850.4-8,933.3; 82.97; 1-18; 4.500; 3.958 Tubing - Pup Joint; 8,840.6-8,850.4; 9.71; 1-17; 4.500; 3.958 HES Opsis Gauge; 8,836.4-8,840.6; 4.25; 1-16; 5.675; 3.920 Tubing - Pup Joint; 8,826.7-8,836.4; 9.74; 1-15; 4.500; 3.958Casing Jts; 8,387.0-9,226.3; 839.27; 3-3; 7.625; 6.765 Tubing; 8,083.2-8,826.7; 743.49; 1-14; 4.500; 3.958 Tubing - Pup Joint; 8,073.4-8,083.2; 9.75; 1-13; 4.500; 3.958 Mandrel – GAS LIFT; 8,066.4-8,073.4; 6.98; 1-12; 6.013; 3.865 Tubing - Pup Joint; 8,056.7-8,066.4; 9.72; 1-11; 4.500; 3.958 Tubing; 3,256.2-8,056.7; 4,800.51; 1-10; 4.500; 3.958 Casing Jts; 38.2-8,387.0; 8,348.85; 3-2; 7.625; 6.875 Float Shoe; 3,939.8-3,942.2; 2.39; 2-8; 10.750; 9.950 Casing Jts; 3,857.5-3,939.8; 82.33; 2-7; 10.750; 9.950 Float Collar; 3,854.3-3,857.5; 3.18; 2-6; 10.750; 9.950 Tubing - Pup Joint; 3,246.5-3,256.2; 9.73; 1-9; 4.500; 3.958 Mandrel – GAS LIFT; 3,239.5-3,246.5; 7.02; 1-8; 6.015; 3.865 Tubing - Pup Joint; 3,229.7-3,239.5; 9.74; 1-7; 4.500; 3.958 Casing Jts; 155.9-3,854.3; 3,698.37; 2-5; 10.750; 9.950 Tubing; 127.0-3,229.7; 3,102.77; 1-6; 4.500; 3.958 Casing Jts A; 118.3-155.9; 37.60; 2-4; 10.750; 9.950 Tubing; 85.5-127.0; 41.48; 1-5; 4.500; 3.958 Casing Jts B; 78.8-118.3; 39.49; 2-3; 10.750; 9.950 Space out Pups ; 81.6-85.5; 3.91; 1-4; 4.500; 3.833 Casing Jts; 39.0-119.0; 80.00; 1-1; 20.000; 18.500 Tubing; 40.1-81.6; 41.45; 1-3; 4.500; 3.958 Casing Jts C; 39.5-78.8; 39.36; 2-2; 10.750; 9.950 Hanger; 38.6-39.5; 0.93; 2-1; 18.940; 9.950 Tubing - Pup Joint; 36.8-40.1; 3.28; 1-2; 4.500; 3.833 Hanger; 37.6-38.2; 0.60; 3-1; 7.625; 6.875 Stream Flo Hanger W/4" H-BPV; 36.1-36.8; 0.74; 1-1; 10.850; 3.900 KUP PROD KB-Grd (ft) 39.00 RR Date 8/9/2024 Other Elev… 3S-718 ... TD Act Btm (ftKB) 17,716.0 Well Attributes Field Name Wellbore API/UWI 501032088400 Wellbore Status PROD Max Angle & MD Incl (°) 93.82 MD (ftKB) 9,884.41 WELLNAME WELLBORE3S-718 Annotation End DateH2S (ppm) DateComment Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 13,517.4 4,231.7 90.43 Sleeve - Frac #8 5.500 AU Limitless Single point closable 3.500 14,014.5 4,227.3 90.58 Sleeve - Frac #7 5.500 AU Limitless Single point closable 3.500 14,509.6 4,224.6 89.81 Sleeve - Frac #6 5.500 AU Limitless Single point closable 3.500 15,007.3 4,225.1 89.97 Sleeve - Frac #5 5.500 AU Limitless Single point closable 3.500 15,503.7 4,223.5 90.79 Sleeve - Frac #4 5.500 AU Limitless Single point closable 3.500 15,998.3 4,216.4 90.77 Sleeve - Frac #3 5.500 AU Limitless Single point closable 3.500 16,538.9 4,208.4 90.82 Sleeve - Frac #2 5.500 AU Limitless Single point closable 3.500 17,032.5 4,201.2 90.94 Sleeve - Frac #1 5.500 AU Limitless Single point closable 3.500 17,531.7 4,194.8 90.50 Sleeve - Setting 5.610 Alpha Baker Alpha Sleeve Trigger #15 8386 psi Nom 3.020 17,577.0 4,194.4 90.36 Sleeve - Setting 5.640 Alpha Baker Alpha Sleeve Trigger #15 8911 psi Nom 3.000 17,622.3 4,194.2 90.28 Collar - Landing 5.190 Alpha Type II Baker landing collar 3.890 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 20,000.0 20,002.0 Stimulation Intervals Top (ftKB) Btm (ftKB) Inter val Num ber Type Subtype Start Date Proppant Designed (lb) Proppant Total (lb) Vol Clean Total (bbl) Vol Slurry Total (bbl) 17,532.0 17,534.7 1 Hydraulic fracture 8/28/2024 308,000.0 307,335.0 3,482.33 3,808.82 17,033.0 17,035.7 2 Hydraulic fracture 8/29/2024 304,000.0 304,442.0 2,030.14 2,353.52 16,539.0 16,541.7 3 Hydraulic fracture 8/29/2024 304,000.0 305,209.0 1,733.86 2,058.04 15,998.0 16,000.7 4 Hydraulic fracture 8/29/2024 304,000.0 304,973.0 2,194.19 2,518.14 15,504.0 15,506.7 5 Hydraulic fracture 8/29/2024 304,000.0 303,876.0 2,802.48 3,125.25 15,007.0 15,009.7 6 Hydraulic fracture 8/30/2024 304,000.0 305,683.0 2,085.52 2,410.22 14,510.0 14,512.7 7 Hydraulic fracture 8/30/2024 304,000.0 303,712.0 1,706.05 2,028.65 14,014.0 14,016.7 8 Hydraulic fracture 8/30/2024 304,000.0 304,132.0 1,702.60 2,025.65 13,517.0 13,519.7 9 Hydraulic fracture 8/30/2024 304,000.0 303,556.0 1,948.26 2,270.69 13,061.0 13,063.7 10 Hydraulic fracture 8/31/2024 304,000.0 305,099.0 1,807.00 2,131.08 12,605.0 12,607.7 11 Hydraulic fracture 8/31/2024 304,000.0 304,918.0 3,106.00 3,364.54 12,025.0 12,027.7 12 Hydraulic fracture 8/31/2024 304,000.0 311,663.0 1,985.07 2,316.11 11,525.0 11,527.7 13 Hydraulic fracture 8/31/2024 304,000.0 304,901.0 1,812.00 2,135.87 11,069.0 11,071.7 14 Hydraulic fracture 9/1/2024 304,000.0 305,802.0 1,766.71 2,091.54 10,459.0 10,461.7 15 Hydraulic fracture 9/1/2024 304,000.0 303,601.0 1,651.71 1,974.21 10,042.0 10,044.7 16 Hydraulic fracture 9/1/2024 304,000.0 304,883.0 1,971.98 2,295.83 9,584.0 9,586.7 17 Hydraulic fracture 9/1/2024 303,680.0 285,972.0 1,670.83 1,999.41 Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 38.5 3,947.0 38.5 2,597.3 Surface String Cement Pump 546 bbls lead 10.7 ppg 58 bbls tail 15.8 ppg with 292 bbls cement retrns to surface 7/19/2024 HORIZONTAL, 3S-718, 9/26/2024 3:25:09 PM M D (ft KB ) -17,015.4 -3,943.9 -3,881.2 -3,745.1 -402.2 -323.5 -281.8 -26.9 -24.0 -20.0 -18.0 -15.4 -13.1 -10.2 -3.9 -1.6 36.1 38.4 40.0 118.4 155.8 3,239.5 3,857.6 4,254.9 8,083.3 8,836.3 8,943.2 9,049.9 9,116.5 9,170.9 9,183.1 9,198.5 9,226.4 9,360.2 9,586.0 10,042.3 10,461.0 11,071.5 11,527.6 12,604.7 13,061.0 13,519.7 14,509.5 15,006.9 15,503.9 15,998.4 16,541.7 17,035.8 17,535.4 17,624.0 20,000.0 Vertical schematic (actual) Perf; 20,000.0-20,002.0 Float Shoe; 17,707.2-17,711.0; 3.85; 4-45; 5.200; 3.410 Liner; 17,624.0-17,707.2; 83.19; 4-44; 4.500; 3.958Collar - Landing; 17,622.3-17,624.0; 1.70; 4-43; 5.190; 3.890 Liner; 17,580.7-17,622.3; 41.58; 4-42; 4.500; 3.958 Sleeve - Setting; 17,577.0-17,580.7; 3.69; 4-41; 5.640; 3.000 Liner; 17,535.4-17,577.0; 41.60; 4-40; 4.500; 3.958 Sleeve - Setting; 17,531.7-17,535.4; 3.70; 4-39; 5.610; 3.020 Liner; 17,034.8-17,531.7; 496.87; 4-38; 4.500; 3.958 Sleeve - Frac #1; 17,032.5-17,034.8; 2.31; 4-37; 5.500; 3.500 Liner; 16,541.2-17,032.5; 491.31; 4-36; 4.500; 3.958 Sleeve - Frac #2; 16,538.9-16,541.2; 2.31; 4-35; 5.500; 3.500 Liner; 16,000.6-16,538.9; 538.24; 4-34; 4.500; 3.958 Sleeve - Frac #3; 15,998.3-16,000.6; 2.31; 4-33; 5.500; 3.500 Liner; 15,506.0-15,998.3; 492.35; 4-32; 4.500; 3.958 Sleeve - Frac #4; 15,503.7-15,506.0; 2.31; 4-31; 5.500; 3.500 Liner; 15,009.6-15,503.7; 494.09; 4-30; 4.500; 3.958 Sleeve - Frac #5; 15,007.3-15,009.6; 2.31; 4-29; 5.500; 3.500 Liner; 14,511.9-15,007.3; 495.42; 4-28; 4.500; 3.958 Sleeve - Frac #6; 14,509.5-14,511.9; 2.31; 4-27; 5.500; 3.500 Liner; 14,016.8-14,509.5; 492.75; 4-26; 4.500; 3.958 Sleeve - Frac #7; 14,014.5-14,016.8; 2.31; 4-25; 5.500; 3.500 Liner; 13,519.7-14,014.5; 494.83; 4-24; 4.500; 3.958 Sleeve - Frac #8; 13,517.4-13,519.7; 2.31; 4-23; 5.500; 3.500 Liner; 13,063.5-13,517.4; 453.86; 4-22; 4.500; 3.958 Sleeve - Frac #9; 13,061.2-13,063.5; 2.31; 4-21; 5.500; 3.500 Liner; 12,606.9-13,061.2; 454.27; 4-20; 4.500; 3.958 Sleeve - Frac #10; 12,604.6-12,606.9; 2.31; 4-19; 5.500; 3.500 Liner; 12,027.3-12,604.6; 577.25; 4-18; 4.500; 3.958 Sleeve - Frac #11; 12,025.0-12,027.3; 2.31; 4-17; 5.500; 3.500 Liner; 11,526.8-12,025.0; 498.19; 4-16; 4.500; 3.958 Sleeve - Frac #12; 11,524.5-11,526.8; 2.31; 4-15; 5.500; 3.500 Liner; 11,071.6-11,524.5; 452.91; 4-14; 4.500; 3.958 Sleeve - Frac #13; 11,069.3-11,071.6; 2.31; 4-13; 5.500; 3.500 Liner; 10,461.1-11,069.3; 608.24; 4-12; 4.500; 3.958 Sleeve - Frac #14; 10,458.8-10,461.1; 2.31; 4-11; 5.500; 3.500 Liner; 10,044.5-10,458.8; 414.25; 4-10; 4.500; 3.958 Sleeve - Frac #15; 10,042.2-10,044.5; 2.31; 4-9; 5.500; 3.500 Liner; 9,586.8-10,042.2; 455.42; 4-8; 4.500; 3.958 Sleeve - Frac #16; 9,584.5-9,586.8; 2.31; 4-7; 5.500; 3.500 Liner; 9,212.5-9,584.5; 372.02; 4-6; 4.500; 3.958 Float Shoe; 9,357.2-9,360.3; 3.08; 3-7; 7.625; 6.875 Casing Jts; 9,272.1-9,357.2; 85.14; 3-6; 7.625; 6.875 Float Collar; 9,269.4-9,272.1; 2.71; 3-5; 7.625; 6.875 Casing Jts; 9,226.3-9,269.4; 43.07; 3-4; 7.625; 6.875 Liner Pup Joint; 9,208.6-9,212.5; 3.83; 4-5; 4.500; 3.958 XO Reducing; 9,206.9-9,208.6; 1.69; 4-4; 6.050; 3.900 Hanger; 9,198.5-9,206.9; 8.44; 4-3; 6.450; 4.800 Nipple - RS; 9,196.2-9,198.5; 2.33; 4-2; 6.060; 4.250 Shoe - Mule; 9,186.6-9,189.9; 3.30; 1-36; 4.500; 3.910 Packer; 9,176.3-9,196.2; 19.87; 4-1; 6.550; 4.800 Tubing - Pup Joint; 9,183.2-9,186.6; 3.41; 1-35; 4.500; 3.958 Locator; 9,181.3-9,183.2; 1.88; 1-34; 5.630; 3.890Locator; 9,180.7-9,181.3; 0.62; 1-33; 5.290; 3.890 Tubing - Pup Joint; 9,171.0-9,180.7; 9.72; 1-32; 4.500; 3.958 Sub - Shear Out - SOS; 9,169.1-9,171.0; 1.83; 1-31; 5.450; 3.833 Tubing; 9,127.6-9,169.1; 41.49; 1-30; 4.500; 3.958 Tubing - Pup Joint; 9,117.9-9,127.6; 9.72; 1-29; 4.500; 3.958 Nipple - DB 3.75"; 9,116.3-9,117.9; 1.61; 1-28; 5.207; 3.750 Tubing - Pup Joint; 9,106.6-9,116.3; 9.71; 1-27; 4.500; 3.958 Tubing; 9,065.1-9,106.6; 41.48; 1-26; 4.500; 3.958 Tubing - Pup Joint; 9,055.4-9,065.1; 9.71; 1-25; 4.500; 3.958 Packer; 9,050.0-9,055.4; 5.43; 1-24; 6.375; 3.856 Tubing - Pup Joint; 9,040.6-9,050.0; 9.38; 1-23; 4.500; 3.958 Tubing; 8,957.8-9,040.6; 82.86; 1-22; 4.500; 3.958 Tubing - Pup Joint; 8,948.0-8,957.8; 9.72; 1-21; 4.500; 3.958 Sleeve - Sliding; 8,943.1-8,948.0; 4.95; 1-20; 5.500; 3.813 Tubing - Pup Joint; 8,933.3-8,943.1; 9.75; 1-19; 4.500; 3.958 Tubing; 8,850.4-8,933.3; 82.97; 1-18; 4.500; 3.958 Tubing - Pup Joint; 8,840.6-8,850.4; 9.71; 1-17; 4.500; 3.958 HES Opsis Gauge; 8,836.4-8,840.6; 4.25; 1-16; 5.675; 3.920 Tubing - Pup Joint; 8,826.7-8,836.4; 9.74; 1-15; 4.500; 3.958Casing Jts; 8,387.0-9,226.3; 839.27; 3-3; 7.625; 6.765 Tubing; 8,083.2-8,826.7; 743.49; 1-14; 4.500; 3.958 Tubing - Pup Joint; 8,073.4-8,083.2; 9.75; 1-13; 4.500; 3.958 Mandrel – GAS LIFT; 8,066.4-8,073.4; 6.98; 1-12; 6.013; 3.865 Tubing - Pup Joint; 8,056.7-8,066.4; 9.72; 1-11; 4.500; 3.958 Tubing; 3,256.2-8,056.7; 4,800.51; 1-10; 4.500; 3.958 Casing Jts; 38.2-8,387.0; 8,348.85; 3-2; 7.625; 6.875 Float Shoe; 3,939.8-3,942.2; 2.39; 2-8; 10.750; 9.950 Casing Jts; 3,857.5-3,939.8; 82.33; 2-7; 10.750; 9.950 Float Collar; 3,854.3-3,857.5; 3.18; 2-6; 10.750; 9.950 Tubing - Pup Joint; 3,246.5-3,256.2; 9.73; 1-9; 4.500; 3.958 Mandrel – GAS LIFT; 3,239.5-3,246.5; 7.02; 1-8; 6.015; 3.865 Tubing - Pup Joint; 3,229.7-3,239.5; 9.74; 1-7; 4.500; 3.958 Casing Jts; 155.9-3,854.3; 3,698.37; 2-5; 10.750; 9.950 Tubing; 127.0-3,229.7; 3,102.77; 1-6; 4.500; 3.958 Casing Jts A; 118.3-155.9; 37.60; 2-4; 10.750; 9.950 Tubing; 85.5-127.0; 41.48; 1-5; 4.500; 3.958 Casing Jts B; 78.8-118.3; 39.49; 2-3; 10.750; 9.950 Space out Pups ; 81.6-85.5; 3.91; 1-4; 4.500; 3.833 Casing Jts; 39.0-119.0; 80.00; 1-1; 20.000; 18.500 Tubing; 40.1-81.6; 41.45; 1-3; 4.500; 3.958 Casing Jts C; 39.5-78.8; 39.36; 2-2; 10.750; 9.950 Hanger; 38.6-39.5; 0.93; 2-1; 18.940; 9.950 Tubing - Pup Joint; 36.8-40.1; 3.28; 1-2; 4.500; 3.833 Hanger; 37.6-38.2; 0.60; 3-1; 7.625; 6.875 Stream Flo Hanger W/4" H-BPV; 36.1-36.8; 0.74; 1-1; 10.850; 3.900 KUP PROD 3S-718 ... WELLNAME WELLBORE3S-718 Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 8,295.0 9,364.0 3,963.6 4,241.2 Intermediate String 1 Cement Perform cement job for 7-5/8”" intermediate casing as per Halliburton program. Pump 60 bbls tuned 10.5 ppg spacer with BMII @ 4 bpm/ 250 psi 26% F/O. Drop #2 bottom plug. Cement wet @ 00:20 hrs. Pump 41 bbls 15.3 ppg primary cmt with BM11 @ 2-3 bpm 190 psi 25% f/o. Pump 25 bbls 15.3 ppg primary cmt without BM11 @ 2 bpm 90 psi 22% f/o. Drop top plug. Pump 20 bbls fresh H2O. Swap to rig pumps and displace with 398 bbls @ 6 bpm 456 psi 30% f/o. Cont. displacement @ 3 bpm 580 psi 13% f/o. Bump plug 4042 strokes. Pressure up to 1080 psi hold for 5 min. Bleed off/ check floats. Floats held. CIP @ 02:18 hrs. 7/28/2024 9,176.3 17,711.0 4,206.0 4,193.8 4 1/2" Liner Cement Pump 55 BBL of 10.5 PPG spacer @ 4.5 BPM / 1155 PSI. Pump 202 BBL of 15.3 PPG cement slurry at 4.5 BPM / 908 PSI. Slow to 3 BPM (438 PSI) cement pump rate @ 60 BBL cement away. Shut down & drop Baker drill pipe dart plug. Line up top drive to rig pumps and displace cement with 125 BBL of 9.3 PPG mud @ 5 BPM / 1883 PSI for 1252 STKS (Observed Dart latch @ 824 STKS). Pump 18 BBL of 10.5 PPG spacer. Continue mud displacement with 225 BBL of 9.3 PPG mud @ 5 BPM / 1578 PSI. Slow riate to 3 BPM @ 1950 stks. Observe plug bump @ 2104 STKS. Pressure up to 1600 PSI for 5 minutes. Verify floats holding (good). Note: Cement in place at 12:45 hrs. 8/6/2024 HORIZONTAL, 3S-718, 9/26/2024 3:25:10 PM M D (ft KB ) -17,015.4 -3,943.9 -3,881.2 -3,745.1 -402.2 -323.5 -281.8 -26.9 -24.0 -20.0 -18.0 -15.4 -13.1 -10.2 -3.9 -1.6 36.1 38.4 40.0 118.4 155.8 3,239.5 3,857.6 4,254.9 8,083.3 8,836.3 8,943.2 9,049.9 9,116.5 9,170.9 9,183.1 9,198.5 9,226.4 9,360.2 9,586.0 10,042.3 10,461.0 11,071.5 11,527.6 12,604.7 13,061.0 13,519.7 14,509.5 15,006.9 15,503.9 15,998.4 16,541.7 17,035.8 17,535.4 17,624.0 20,000.0 Vertical schematic (actual) Perf; 20,000.0-20,002.0 Float Shoe; 17,707.2-17,711.0; 3.85; 4-45; 5.200; 3.410 Liner; 17,624.0-17,707.2; 83.19; 4-44; 4.500; 3.958Collar - Landing; 17,622.3-17,624.0; 1.70; 4-43; 5.190; 3.890 Liner; 17,580.7-17,622.3; 41.58; 4-42; 4.500; 3.958 Sleeve - Setting; 17,577.0-17,580.7; 3.69; 4-41; 5.640; 3.000 Liner; 17,535.4-17,577.0; 41.60; 4-40; 4.500; 3.958 Sleeve - Setting; 17,531.7-17,535.4; 3.70; 4-39; 5.610; 3.020 Liner; 17,034.8-17,531.7; 496.87; 4-38; 4.500; 3.958 Sleeve - Frac #1; 17,032.5-17,034.8; 2.31; 4-37; 5.500; 3.500 Liner; 16,541.2-17,032.5; 491.31; 4-36; 4.500; 3.958 Sleeve - Frac #2; 16,538.9-16,541.2; 2.31; 4-35; 5.500; 3.500 Liner; 16,000.6-16,538.9; 538.24; 4-34; 4.500; 3.958 Sleeve - Frac #3; 15,998.3-16,000.6; 2.31; 4-33; 5.500; 3.500 Liner; 15,506.0-15,998.3; 492.35; 4-32; 4.500; 3.958 Sleeve - Frac #4; 15,503.7-15,506.0; 2.31; 4-31; 5.500; 3.500 Liner; 15,009.6-15,503.7; 494.09; 4-30; 4.500; 3.958 Sleeve - Frac #5; 15,007.3-15,009.6; 2.31; 4-29; 5.500; 3.500 Liner; 14,511.9-15,007.3; 495.42; 4-28; 4.500; 3.958 Sleeve - Frac #6; 14,509.5-14,511.9; 2.31; 4-27; 5.500; 3.500 Liner; 14,016.8-14,509.5; 492.75; 4-26; 4.500; 3.958 Sleeve - Frac #7; 14,014.5-14,016.8; 2.31; 4-25; 5.500; 3.500 Liner; 13,519.7-14,014.5; 494.83; 4-24; 4.500; 3.958 Sleeve - Frac #8; 13,517.4-13,519.7; 2.31; 4-23; 5.500; 3.500 Liner; 13,063.5-13,517.4; 453.86; 4-22; 4.500; 3.958 Sleeve - Frac #9; 13,061.2-13,063.5; 2.31; 4-21; 5.500; 3.500 Liner; 12,606.9-13,061.2; 454.27; 4-20; 4.500; 3.958 Sleeve - Frac #10; 12,604.6-12,606.9; 2.31; 4-19; 5.500; 3.500 Liner; 12,027.3-12,604.6; 577.25; 4-18; 4.500; 3.958 Sleeve - Frac #11; 12,025.0-12,027.3; 2.31; 4-17; 5.500; 3.500 Liner; 11,526.8-12,025.0; 498.19; 4-16; 4.500; 3.958 Sleeve - Frac #12; 11,524.5-11,526.8; 2.31; 4-15; 5.500; 3.500 Liner; 11,071.6-11,524.5; 452.91; 4-14; 4.500; 3.958 Sleeve - Frac #13; 11,069.3-11,071.6; 2.31; 4-13; 5.500; 3.500 Liner; 10,461.1-11,069.3; 608.24; 4-12; 4.500; 3.958 Sleeve - Frac #14; 10,458.8-10,461.1; 2.31; 4-11; 5.500; 3.500 Liner; 10,044.5-10,458.8; 414.25; 4-10; 4.500; 3.958 Sleeve - Frac #15; 10,042.2-10,044.5; 2.31; 4-9; 5.500; 3.500 Liner; 9,586.8-10,042.2; 455.42; 4-8; 4.500; 3.958 Sleeve - Frac #16; 9,584.5-9,586.8; 2.31; 4-7; 5.500; 3.500 Liner; 9,212.5-9,584.5; 372.02; 4-6; 4.500; 3.958 Float Shoe; 9,357.2-9,360.3; 3.08; 3-7; 7.625; 6.875 Casing Jts; 9,272.1-9,357.2; 85.14; 3-6; 7.625; 6.875 Float Collar; 9,269.4-9,272.1; 2.71; 3-5; 7.625; 6.875 Casing Jts; 9,226.3-9,269.4; 43.07; 3-4; 7.625; 6.875 Liner Pup Joint; 9,208.6-9,212.5; 3.83; 4-5; 4.500; 3.958 XO Reducing; 9,206.9-9,208.6; 1.69; 4-4; 6.050; 3.900 Hanger; 9,198.5-9,206.9; 8.44; 4-3; 6.450; 4.800 Nipple - RS; 9,196.2-9,198.5; 2.33; 4-2; 6.060; 4.250 Shoe - Mule; 9,186.6-9,189.9; 3.30; 1-36; 4.500; 3.910 Packer; 9,176.3-9,196.2; 19.87; 4-1; 6.550; 4.800 Tubing - Pup Joint; 9,183.2-9,186.6; 3.41; 1-35; 4.500; 3.958 Locator; 9,181.3-9,183.2; 1.88; 1-34; 5.630; 3.890Locator; 9,180.7-9,181.3; 0.62; 1-33; 5.290; 3.890 Tubing - Pup Joint; 9,171.0-9,180.7; 9.72; 1-32; 4.500; 3.958 Sub - Shear Out - SOS; 9,169.1-9,171.0; 1.83; 1-31; 5.450; 3.833 Tubing; 9,127.6-9,169.1; 41.49; 1-30; 4.500; 3.958 Tubing - Pup Joint; 9,117.9-9,127.6; 9.72; 1-29; 4.500; 3.958 Nipple - DB 3.75"; 9,116.3-9,117.9; 1.61; 1-28; 5.207; 3.750 Tubing - Pup Joint; 9,106.6-9,116.3; 9.71; 1-27; 4.500; 3.958 Tubing; 9,065.1-9,106.6; 41.48; 1-26; 4.500; 3.958 Tubing - Pup Joint; 9,055.4-9,065.1; 9.71; 1-25; 4.500; 3.958 Packer; 9,050.0-9,055.4; 5.43; 1-24; 6.375; 3.856 Tubing - Pup Joint; 9,040.6-9,050.0; 9.38; 1-23; 4.500; 3.958 Tubing; 8,957.8-9,040.6; 82.86; 1-22; 4.500; 3.958 Tubing - Pup Joint; 8,948.0-8,957.8; 9.72; 1-21; 4.500; 3.958 Sleeve - Sliding; 8,943.1-8,948.0; 4.95; 1-20; 5.500; 3.813 Tubing - Pup Joint; 8,933.3-8,943.1; 9.75; 1-19; 4.500; 3.958 Tubing; 8,850.4-8,933.3; 82.97; 1-18; 4.500; 3.958 Tubing - Pup Joint; 8,840.6-8,850.4; 9.71; 1-17; 4.500; 3.958 HES Opsis Gauge; 8,836.4-8,840.6; 4.25; 1-16; 5.675; 3.920 Tubing - Pup Joint; 8,826.7-8,836.4; 9.74; 1-15; 4.500; 3.958Casing Jts; 8,387.0-9,226.3; 839.27; 3-3; 7.625; 6.765 Tubing; 8,083.2-8,826.7; 743.49; 1-14; 4.500; 3.958 Tubing - Pup Joint; 8,073.4-8,083.2; 9.75; 1-13; 4.500; 3.958 Mandrel – GAS LIFT; 8,066.4-8,073.4; 6.98; 1-12; 6.013; 3.865 Tubing - Pup Joint; 8,056.7-8,066.4; 9.72; 1-11; 4.500; 3.958 Tubing; 3,256.2-8,056.7; 4,800.51; 1-10; 4.500; 3.958 Casing Jts; 38.2-8,387.0; 8,348.85; 3-2; 7.625; 6.875 Float Shoe; 3,939.8-3,942.2; 2.39; 2-8; 10.750; 9.950 Casing Jts; 3,857.5-3,939.8; 82.33; 2-7; 10.750; 9.950 Float Collar; 3,854.3-3,857.5; 3.18; 2-6; 10.750; 9.950 Tubing - Pup Joint; 3,246.5-3,256.2; 9.73; 1-9; 4.500; 3.958 Mandrel – GAS LIFT; 3,239.5-3,246.5; 7.02; 1-8; 6.015; 3.865 Tubing - Pup Joint; 3,229.7-3,239.5; 9.74; 1-7; 4.500; 3.958 Casing Jts; 155.9-3,854.3; 3,698.37; 2-5; 10.750; 9.950 Tubing; 127.0-3,229.7; 3,102.77; 1-6; 4.500; 3.958 Casing Jts A; 118.3-155.9; 37.60; 2-4; 10.750; 9.950 Tubing; 85.5-127.0; 41.48; 1-5; 4.500; 3.958 Casing Jts B; 78.8-118.3; 39.49; 2-3; 10.750; 9.950 Space out Pups ; 81.6-85.5; 3.91; 1-4; 4.500; 3.833 Casing Jts; 39.0-119.0; 80.00; 1-1; 20.000; 18.500 Tubing; 40.1-81.6; 41.45; 1-3; 4.500; 3.958 Casing Jts C; 39.5-78.8; 39.36; 2-2; 10.750; 9.950 Hanger; 38.6-39.5; 0.93; 2-1; 18.940; 9.950 Tubing - Pup Joint; 36.8-40.1; 3.28; 1-2; 4.500; 3.833 Hanger; 37.6-38.2; 0.60; 3-1; 7.625; 6.875 Stream Flo Hanger W/4" H-BPV; 36.1-36.8; 0.74; 1-1; 10.850; 3.900 KUP PROD 3S-718 ... WELLNAME WELLBORE3S-718 Hydraulic Fracturing Fluid Product Component Information Disclosure 2024-08-28 Alaska HARRISON BAY 50-103-20884-00-00 CONOCOPHILLIPS 3S 718 -150.19740000 70.39410000 NAD83 none Oil 4285 1421185 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone Produced Water (Density 8.5) Operator Base Fluid Density = 8.50 SEAWATER (SG 8.52) Operator Base Fluid Density = 8.52 AS-7 ANTI- SLUDGING AGENT Halliburton Anti-sludging Agent BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator FE-1A ACIDIZING COMPOSITION Halliburton Additive FE-2A Halliburton Additive HAI-404M Halliburton Corrosion Inhibitor HYDROCHLORI C ACID, 10-30% Halliburton Solvent LoSurf-300D Halliburton Non-ionic Surfactant LVT-200 Baker Hughes Additive MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker SP BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Calcium Chloride Customer Salt Solution Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer Potassium Formate Brine MI Swaco Completion/Stimulati on WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 100.00%58.36527%10130096 Corundum 1302-74-5 65.00%19.09642%3314447 Mullite 1302-93-8 45.00%13.22060%2294617 Water 7732-18-5 100.00%11.26136%1954565 Sodium chloride 7647-14-5 5.00%0.56307%97729 Crystalline silica, quartz 14808-60-7 100.00%0.43681%75815 Guar gum 9000-30-0 100.00%0.22420%38913 Water 7732-18-5 100.00%0.20178%35022 Ethanol 64-17-5 60.00%0.03689%6403 EDTA/Copper chelate Proprietary 30.00%0.03349%5813 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 Monoethanolamine borate 26038-87-9 100.00%0.02944%5111 Ammonium acetate 631-61-8 100.00%0.02483%4311 Ammonium persulfate 7727-54-0 100.00%0.02449%4250 Sodium hydroxide 1310-73-2 30.00%0.02197%3813 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01844%3202 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01844%3202 Ethylene glycol 107-21-1 30.00%0.00883%1534 Walnut hulls NA 100.00%0.00749%1300 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Acetic acid 64-19-7 60.00%0.00745%1294 Oxylated phenolic resin Proprietary 30.00%0.00735%1275 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxyalkylated phenolic resin Proprietary 10.00%0.00615%1068 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ammonium chloride 12125-02-9 5.00%0.00558%969 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00307%534 Naphthalene 91-20-3 5.00%0.00307%534 Flow Insurance Copper Proprietary 100.00%0.00254%442 Patina Energy Product Stewardship test@patinae nergy.com 7205324886 Polyamine Proprietary 30.00%0.00225%390 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00123%214 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: Ammonia 7664-41-7 1.00%0.00112%194 Sodium chloride 7647-14-5 1.00%0.00073%128 Glycol Ether Proprietary 85.00%0.00067%116 ResMetrics Product Stewardship info@resmetr ics.com 8325921900 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00061%107 Hemicellulase 9025-56-3 5.00%0.00037%65 C.I. pigment Orange 5 3468-63-1 1.00%0.00024%43 Confidential Proprietary 20.00%0.00024%42 ResMetrics Product Stewardship info@resmetr ics.com 8325921900 Ethylene Glycol 107-21-1 20.00%0.00016%29 Cured acrylic resin Proprietary 1.00%0.00007%13 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00007%13 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%6 Isopropanol 67-63-0 30.00%0.00000%0 Methanol 67-56-1 30.00%0.00000%0 Acetic anhydride 108-24-7 100.00%0.00000%0 Morpholine 110-91-8 5.00%0.00000%0 Aldehyde Proprietary 30.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ethoxylated alcohol Proprietary 60.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ethoxylated alcohols Proprietary 10.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ethoxylated alkyl amines Proprietary 5.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Calcium Chloride 10043-52-4 100.00%0.00000%0 Citric acid 77-92-9 60.00%0.00000%0 1-(Benzyl)quinolinium chloride 15619-48-4 10.00%0.00000%0 Polyethoxylated fatty amine salt 61791-26-2 10.00%0.00000%0 Potassium acetate 127-08-2 1.00%0.00000%0 Potassium Formate 590-29-4 100.00%0.00000%0 Ammonium phosphate 7722-76-1 1.00%0.00000%0 Benzenesulfonic acid, dodecyl-, compd. with morpholine 12068-08-5 60.00%0.00000%0 Benzylheteropolycycle salt Proprietary 10.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Sodium iodide 7681-82-5 1.00%0.00000%0 Sodium persulfate 7775-27-1 100.00%0.00000%0 Sodium sulfate 7757-82-6 0.10%0.00000%0 Cycloaliphatic alkyoxylate Proprietary 30.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Distillates (petroleum), hydrotreated light 64742-47-8 100.00%0.00000%0 Hydrochloric acid 7647-01-0 60.00%0.00000%0 Fatty acids, tall oil Proprietary 10.00%0.00000%0 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 * 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 supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 08/28/2024 Job End Date: 09/01/2024 State: Alaska County: Harrison Bay API Number: 50-103-20884-00-00 Operator Name:ConocoPhillips Company/Burlington Resources Well Name and Number: 3S-718 Latitude: 70.394404 Longitude: -150.194325 Datum: NAD27 Federal Well: NO Indian Well: NO True Vertical Depth: 4285 Total Base Water Volume (gal)*: 1421185 Total Base Non Water Volume: 0 Water Source Percent Produced Water 80.80% Other, < 1000TDS 19.20% Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Comments AS-7 ANTISLUDGING AGENT Halliburton Anti-sludging Agent BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide Calcium Chloride ConocoPhillips Salt Solution CAT-3 ACTIVATOR Halliburton Activator Ceramic Proppant - Wanli Wanli Proppant FE-1A ACIDIZING COMPOSITION Halliburton Additive FE-2A Halliburton Additive Flow Insurance Copper Patina Energy Tracer HAI-404M Halliburton Corrosion Inhibitor HYDROCHLORIC ACID, 10-30%Halliburton Solvent LoSurf-300D Halliburton Non-ionic Surfactant LVT-200 Baker Hughes Additive MO-67 Halliburton pH Control OPT 2002-2054 ResMetrics Tracer OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker Potassium Formate Brine MI Swaco Completion/Stimulation WPT 1001-1052 ResMetrics Tracer SP BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Items above are Trade Names. Items below are the individual ingredients. Water 7732-18-5 100.00000 69.82841 Corundum 1302-74-5 65.00000 15.09642 Mullite 1302-93-8 45.00000 13.22060 Sodium chloride 7647-14-5 5.00000 0.56307 Crystalline silica, quartz 14808-60- 7 100.00000 0.43681 Guar gum 9000-30-0 100.00000 0.22420 Ethanol 64-17-5 60.00000 0.03689 EDTA/Copper chelate Proprietary 30.00000 0.03349 Monoethanolamine borate 26038-87- 9 100.00000 0.02944 Ammonium acetate 631-61-8 100.00000 0.02483 Ammonium persulfate 7727-54-0 100.00000 0.02449 Sodium hydroxide 1310-73-2 30.00000 0.02197 Heavy aromatic petroleum naphtha 64742-94- 5 30.00000 0.01844 Oxyalkylated nonyl phenolic resin Proprietary 30.00000 0.01844 Ethylene glycol 107-21-1 30.00000 0.00883 Walnut hulls 84012-43- 1 100.00000 0.00749 Acetic acid 64-19-7 60.00000 0.00745 Oxylated phenolic resin Proprietary 30.00000 0.00735 Oxyalkylated phenolic resin Proprietary 10.00000 0.00615 Ammonium chloride 12125-02- 9 5.00000 0.00558 Poly(oxy-1,2- ethanediyl), alpha-(4- nonylphenyl)-omega- hydroxy-, branched 127087- 87-0 5.00000 0.00307 Naphthalene 91-20-3 5.00000 0.00307 Flow Insurance Copper Proprietary 100.00000 0.00254 Polyamine Proprietary 30.00000 0.00225 2-Bromo-2-nitro-1,3- propanediol 52-51-7 100.00000 0.00123 Ammonia 7664-41-7 1.00000 0.00112 Sodium chloride 7647-14-5 1.00000 0.00073 Glycol Ether Proprietary 85.00000 0.00067 1,2,4 Trimethylbenzene 95-63-6 1.00000 0.00061 Hemicellulase enzyme 9025-56-3 5.00000 0.00037 C.I. pigment Orange 5 3468-63-1 1.00000 0.00024 Confidential Proprietary 20.00000 0.00024 Ethylene glycol 107-21-1 20.00000 0.00016 C.I. Pigment red 5 6410-41-9 1.00000 0.00007 Cured acrylic resin Proprietary 1.00000 0.00007 2,7- Naphthalenedisulfonic acid, 3-hydroxy-4-(4- sulfor-1-naphthalenyl) azo -, trisodium salt 915-67-3 0.10000 0.00003 * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) t>>ED W/η ^Zs/KZZ η&/>ED ^Zs/ ^Z/Wd/KE >/sZ>^Z/Wd/KE ddzW d>K'' K>KZ WZ/Ed^ ͲĞůŝǀĞƌLJ 3S-718 50-103-20884-00-00 224-034 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 5-Aug-24 1 dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚ ͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ yͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ WƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞ WůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉLJƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘ ďŚĂƚƚĂĐŚĂƌLJĂΛƐůď͘ĐŽŵ ^>ƵĚŝƚŽƌͲ dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽdž͕ ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚĂŶĚƚŚĞĐŽŶƚĞŶƚƐŽĨƚŚĞƉĂĐŬĂŐĞ ŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚƚŽŵĂƚĐŚƚŚĞŵĞĚŝĂŶŽƚĞĚĂďŽǀĞ͘dŚĞƐƉĞĐŝĨŝĐ ĐŽŶƚĞŶƚŽĨƚŚĞƐĂŶĚͬŽƌŚĂƌĚĐŽƉLJƉƌŝŶƚƐŵĂLJŽƌŵĂLJŶŽƚŚĂǀĞďĞĞŶ ǀĞƌŝĨŝĞĚĨŽƌĐŽƌƌĞĐƚŶĞƐƐŽƌƋƵĂůŝƚLJůĞǀĞůĂƚƚŚŝƐƉŽŝŶƚ͘ η^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞ 224-034 T39517 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.05 13:04:17 -08'00' 224-034 T39511 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.29 14:33:06 -08'00' odd-03� SAMPLE TRANSMITTAL TO: AOGCC 333 WEST 7T" SUITE 100 ANCH. AK. 99501 279-1433 OPERATOR: CPAI SAMPLE TYPE: Dry Cuttings SAMPLES SENT: 3 S-718 3497-17716 SENT BY: M. McCRACKEN DATE: 08/23/2024 AIR BILL: N/A CPAL CPA12024082302 CHARGE CODE: N/A NAME: 3S-718 NUMBER OF BOXES: 3 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 RECI0 /� ATTN: MIKE McCRACKEN �" Mike.mccracken@conocophillips.com AUG Z 2 22 (Z RECEIVED: A0- r-, CC 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A Yes No 9. Property Designation (Lease Number):10. Field: Undefined Pool 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17716 Casing Collapse Structural Conductor Surface 2470 Intermediate 4790 Production 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 8/25/2024 177118535 4-1/2" 4194 Halliburton TNT Production Packer Baker ZXP Liner top packer (LTP) Perforation Depth MD (ft): 8387 973 4.5" 7.625" 20" 10.75" 129 7.625"8387 3942 129 2596 3994 129 3942 42409360 L-80 TVD Burst 9190 10860 MD 6890 5210 ConocoPhillips Alaska, Inc. Length Size Proposed Pools: Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL380107, ADL025546, ADL380106 KRU 224-034 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20884-00-00 PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): TNT Pkr: 9,050 ' MD / 4,179' TVD LTP: 9,176' MD / 4,206' TVD 1,456 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: KRU 3S-718 madeline.e.woodard@cop.com 907-265-6086 Madeline Woodard Senior Completions Engineer 4194 17716 4194 m n P 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:28 pm, Aug 14, 2024 Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E=madeline.e.woodard@ conocophillips.com Reason: I am the author of this document Location: Date: 2024.08.14 15:23:16-08'00' Foxit PDF Editor Version: 13.0.0 Madeline Woodard 324-468 X 10-404 A.Dewhurst 16AUG24 DSR-8/21/24 CDW 08/16/2024 8/25/2024 VTL 8/22/2024SFD for GCW 8/23/2024 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.23 08:44:53 -08'00'08/23/24 RBDMS JSB 082324 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). August 12, 2024 VIA CERTIFIED MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3S-718 Well ADL 380106, ADL 380107 Kuparuk River Unit, Alaska CPAI Contract No. 203828 Pursuant to 20 AAC 25.283, ConocoPhillips Alaska, Inc. (“CPAI”), as Operator of the Kuparuk River Unit, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing in accordance with 20 AAC 25.280 ("Application") for the 3S- 718 Well (the "Well"). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about August 12, 2024. The Well is currently planned to be drilled as a directional horizontal well on leases ADL 380106 and ADL 380107 as depicted on Exhibit 1, and has locations as follows: Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well (“Notification Area”), which includes the reservoir section. Exhibit 2 is a list of the names and addresses of all owners, landowners, surface owners, and operators of record at the time of this Application for all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, Ryan C. King, CPL Staff Land Negotiator Attachments: Exhibits 1 & 2 Location FNL FEL Township Range Section Meridian Surface 2541’ 1144’ T12N R8E 18 Umiat Top Open Interval 1860’ 9’ T12N R8E 17 Umiat Bottomhole 4544’ 1089’ T12N R8E 5 Umiat Ryan C. King, CPL Staff Land Negotiator Land & Business Development P.O. Box 100630 Anchorage, AK 99510-0360 Office: 907-265-6106 Fax: 907-263-4966 ryan.c.king@cop.com BCC: Madeline Woodard Brian Buck Jason Lyons John Evans Patrick Perfetta Exhibit 1 Exhibit 2 List of the names and addresses of all owners, landowners and operators of all properties within the Notification Area. Operator & Owner: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO 1376 Anchorage, Alaska 99510 Attn: GKA Asset Development Manager Owner (Non-Operator): ConocoPhillips Alaska, Inc. II 700 G Street, Suite ATO 1376 Anchorage, Alaska 99510 Attn: GKA Asset Development Manager Chevron U.S.A. Inc 1400 Smith Street Room 45104 Houston, TX 77002 Attn: Gary Selisker ExxonMobil Alaska Production Inc. PO Box 196601 Anchorage, AK 99519 Attn: Todd Griffith Landowners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Surface Owner: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Section 2 – Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer KUP COYOTR01 TRACT OPERATION COYOTR01 501032045602 3S-24B PA Plugged and Abandoned KUP COYOTR02 TRACT OPERATION COYOTR02 501032084700 3S-701 PA Plugged and Abandoned KUP COYOTR02 TRACT OPERATION COYOTR02 501032084701 3S-701A ACTIVE Injector Produced Water KUP COYOTR03 TRACT OPERATION COYOTR03 501032084800 3S-704 ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032043900 3S-14 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044000 3S-10 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044400 3S-15 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044500 3S-16 ACTIVE Injector Miscible Water Alternating Gas KUP KRU KUPARUK RIVER UNIT 501032044600 3S-22 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044800 3S-17 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044801 3S-17A PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045000 3S-08 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045001 3S-08A PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045002 3S-08B PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045003 3S-08C ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032045060 3S-08CL1 ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032045070 3S-08CL1PB1 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045200 3S-21 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045300 3S-23 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045301 3S-23A SUSP Suspended KUP KRU KUPARUK RIVER UNIT 501032045400 3S-06 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045401 3S-06A PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045600 3S-24 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045601 3S-24A PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045800 3S-03 SUSP Suspended KUP KRU KUPARUK RIVER UNIT 501032046000 3S-19 SUSP Suspended KUP KRU KUPARUK RIVER UNIT 501032036100 PALM 1 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032036101 3S-26 PA Plugged and Abandoned Yes. Well is P&A Yes. Well is P&A KUP KRU KUPARUK RIVER UNIT 501032043000 3S-07 ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032043200 3S-09 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP KRU KUPARUK RIVER UNIT 501032043300 3S-18 PA Plugged and Abandoned KUP MORTR02 TRACT OPERATION MORTR02 501032069500 3S-620 ACTIVE Oil KUP MORTR03 TRACT OPERATION MORTR03 501032073500 3S-613 ACTIVE Injector Produced Water KUP MORTR04 TRACT OPERATION MORTR04 501032077400 3S-611 ACTIVE Oil KUP MORTR04 TRACT OPERATION MORTR04 501032077470 3S-611PB1 PROP Proposed KUP MORTR04 TRACT OPERATION MORTR04 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas KUP MORTR05 TRACT OPERATION MORTR05 501032084200 3S-625 ACTIVE Injector Produced Water KUP MORTR05 TRACT OPERATION MORTR05 501032084400 3S-615 ACTIVE Oil KUP MORTR06 TRACT OPERATION MORTR06 501032086800 3S-624 ACTIVE Oil KUP MORTR07 TRACT OPERATION MORTR07 501032087000 3S-606 ACTIVE Well KUP MORTR08 TRACT OPERATION MORTR08 501032087500 3S-610 ACTIVE Oil KUP MORTR09 TRACT OPERATION MORTR09 501032086400 3S-617 ACTIVE Injector Produced Water 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. SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: The 10-3/4” casing cement pump report on 7/19/2024 shows that the original job pumped as designed. The cement job was pumped with 546 barrels of 10.7 ppg lead cement and 58 barrels 15.8 ppg tail cement, displaced with 9.8 ppg mud. The plug bumped at 1002 psi and the floats held. Cement returned to surface. The 7-5/8” casing cement report on 7/28/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 66 barrels of 15.3 ppg cement. The plugs bumped with pressure increasing to 1080 psi and held for 5 minutes. Floats held. A cement bond log indicates competent cement with a cement top @ 7,651’ MD (3,736’ TVD). The 4-1/2” liner cement report on 8/6/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 202 barrels of 15.3 ppg cement. The cement was displaced with 9.3 ppg mud and the plugs bumped at 1,600 psi and held for 5 minutes. Floats held. 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. ppg Cement returned to surface. SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 7/21/2024 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 7/28/2024 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes. On 8/7/2024 the 7-5/8” casing, 4-1/2” production liner, and liner top packer were pressure tested to 3,850 psi for 30 minutes. On 8/8/2024 the 4-1/2” tubing was pressure tested to 4,550 psi for 30 minutes. On 8/8/2024 the 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,075 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7-5/8" Annulus pressure test 3,850 4-1/2" Tubing pressure Test 4,075 Electronic PRV 8,075 Highest pump trip 7,575 7,075 4,550 SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2,474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 P-110S 11,590 9,210 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the gross Coyote interval, has an average thickness greater than 600 ft TVD over the course of the lateral section of well 3S-718, from where it intersects the top formation at 9,201’ MD to TD of the well. The Coyote interval is comprised of thinly interbedded sandstone and siltstone layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and are of the size range from silt to very fine sand. The estimated fracture pressure for the Coyote interval is approximately 12.9-16.1 ppg. The overlying confining interval is represented by distal toe of slope (deep marine) claystone with thin siltstone beds of the Cretaceous Seabee Formation. This interval is present in thicknesses of more than 350’ TVD across the area. The top of the confining intervals starts at ~3,454’ TVDSS (7,036’ MD). Currently, there is no data of the fracture gradient of the overlying Seabee formation, however, CPAI estimates the fracture closure pressure gradient to be 0.67 psi/ft based on diagnostic fracture injection testing (DFIT). The fracture gradient of the overlying Seabee formation will be greater than the fracture closure pressure gradient of 0.67 psi/ft. The lower confining interval of the Coyote comprises slope to basin floor mudstones of the Torok formation, which are present in thicknesses greater than 300’ TVD across the area. This same confining zone forms the upper confining interval of the Kuparuk River Unit, Torok Oil Pool. The estimated fracture gradient for this section ranges from 15-18 ppg. The base of the gross Coyote interval is estimated from seismic to be at 4,900 ft TVDSS at the heel, and 4,700’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1,800 – 1,840 psi at a depth of 4,150’ TVDSS. SECTION 10 – LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing & Cement assessments for all wells that transect the confining zone: 3S-26: This well has been plugged and abandoned per state regulations with AOGCC witness of cement at surface for all strings and marker plate in place as of 10/29/2023. Perforate, wash, and cement operations were performed with a CBL completed to show good cement through the interval of 4,706’ MD to 4,850’ MD. A CIBP was placed at 4,833’ MD with cement tagged at 3,786’ MD and pressure tested to 1,500 psi. Cement was then placed from 3,770’ MD to surface with returns observed at surface. Source: 201-040 - Laserfiche WebLink (alaska.gov) 3S-09: This well is an active Kuparuk injector. The cement report from 12/15/2002 shows that 63 bbls of 15.8ppg Class G cement was pumped and no losses were observed during the job. However, the top of cement is below the Coyote formation. The outer annulus of this well (7” x 9-5/8”) will be monitored during the stimulation of 3S- 718. Given the longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic fractures will intersect the 3S-09 in the Coyote sand. ppg However, the top of cement is below p the Coyote formation. The uncemented Coyote at KRU 3S-09 does not appear to be within a 1/2 mile radius of the KRU 3S-718 well path, but the proposed monitoring is advisable -A.Dewhurst 16AUG24 SECTION 11 – LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(11) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that two faults transect the Coyote reservoir within one half mile radius of the 3S-718 wellbore trajectory. One of these faults intersects the 3S-718 wellbore trajectory at its heel. This fault is interpreted to have approximately 8’ of throw at this location (9,201’ MD). This fault has a SW – NE strike and is downthrown to the SE. The second fault does not intersect the 3S-718 wellbore or any other nearby well trajectories. It is interpreted to have an offset of ~25’ and has a SW – NE strike like the fault that intersects the 3S-718 well. The interpreted faults should not affect overburden integrity and therefore their presence should not interfere with containment. 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) 3S-718 was completed in 2024 as a horizontal producer in the Coyote formation. The well was completed with a 4.5” tubing upper completion and a 4.5” liner with a dart 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, a dart will be dropped to shift open the 2nd stage sleeve and isolate the first stage. The 2nd stage will then be pumped and a dart will be dropped for each subsequent stage. These darts will provide isolation from the previous stage and allow fracturing from the toe of the well towards the heel. Proposed Procedure: Halliburton Pumping Services: 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre- existing conditions. 2. Ensure the frac tree was tested to 10,000 psi on the rig. 3. Ensure all pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to ~2,000’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100ºF seawater. 6. MIRU HES Frac Equipment. 7. PT Surface lines to 10,000 psi using a Pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Bring up pumps and increase annulus pressure to 3,500 psi as the tubing pressures up. 10. Pump the frac job per the attached Halliburton pump schedule at 20-22 bpm with a maximum expected treating pressure of 8,500 psi. 11. RDMO Halliburton Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. The well is ready for post-frac well prep/production tree installation and flowback (after Slickline and Coiled Tubing Cleanout). 8,500 Max tubing pressure limited to 7,636 psi by the requirement to test to 110% of differential pressure .283(c)(2). 4,550 psi MITT, 3500 psi IA backpressure. CDW 08/16/2024 Stage Job Size (lb) Top MD (ft) Top TVD (ft) Propped Half- Length (ft) Fracture Height (ft) Avg Fracture Width (in) 1 304,000 17,532 3,975 760 220 0.55 2 304,000 17,033 4,071 755 130 0.394 3 304,000 16,539 4,078 725 130 0.374 4 304,000 15,998 4,006 580 210 0.344 5 304,000 15,504 4,023 770 200 0.338 6 304,000 15,007 4,015 610 210 0.323 7 304,000 14,510 4,105 780 120 0.385 8 304,000 14,014 4,097 780 130 0.374 9 304,000 13,517 4,102 760 130 0.396 10 304,000 13,061 4,105 740 130 0.385 11 304,000 12,605 4,084 720 155 0.382 12 304,000 12,025 4,043 680 200 0.432 13 304,000 11,525 4,027 740 220 0.397 14 304,000 11,069 4,051 680 200 0.387 15 304,000 10,459 4,062 690 195 0.389 16 304,000 10,042 4,152 770 120 0.419 17 304,000 9,584 4,108 740 205 0.446 Disclaimer Notice: KRU 3S-718 This model was generated using commercially available modeling software and is based on engineering estimates of reservoir properties. Conoco Phillips is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.3941017LEASE3S-718SALES ORDERBHST (°F)105LONG-150.19746FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In2:43:38 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:43:38 1-3 Shut-In Shut-In2:38:52 1-4 30# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 2:38:52 1.00 0.35 30.00 3.00 0.151-5 30# Linear Scour 100M 0.50 20 8,000 190 195 4,000 0:09:44 2:32:52 1.00 0.35 30.00 3.00 0.151-6 30# Linear Displacement 20 12,046 287 287 0:14:20 2:23:07 1.00 0.35 30.00 3.00 0.151-7 30# Linear Step Rate Test 20 8,400 200 200 0:10:00 2:08:47 1.00 0.35 30.00 3.00 0.151-8 30# Linear DFIT 20 1,680 40 40 0:02:00 1:58:47 1.00 0.35 30.00 3.00 0.151-9 Shut-In Shut-In1:56:47 1-10 Shut-In Shut-In1:56:47 1-11 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:56:47 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.151-12 30# Delta Frac Pad 20 19,125 455 455 0:22:46 1:43:27 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.151-13 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.151-14 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.151-15 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.151-16 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.151-17 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.151-18 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.151-19 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.151-20 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.151-21 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.152-1 30# Delta Frac Minifrac - Treatment 20 13,563 323 323 0:16:09 2:25:47 0.45 1.00 1.00 0.50 0.35 30.00 1.00 3.00 0.152-2 30# Linear Minifrac - Flush 20 11,727 279 279 0:13:58 2:09:39 1.00 0.50 0.35 30.00 3.00 0.152-3 Shut-In Shut-In1:55:41 2-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:55:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.152-5 30# Delta Frac Pad 20 18,200 433 433 0:21:40 1:42:21 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.152-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.152-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.152-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.152-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.152-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.152-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.152-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 0.50 0.35 30.00 2.003.00 0.152-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 0.50 0.35 30.00 2.003.00 0.152-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 0.50 0.35 30.00 1.00 3.00 0.153-1 30# Delta Frac Pad 20 17,600 419 419 0:20:57 1:57:13 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:36:16 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:26:32 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.153-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:21:31 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:12:31 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:03:07 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:47:53 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:33:45 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:23:40 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-10 30# Delta Frac Flush 20 11,412 272 272 0:13:35 0:17:05 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.153-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 3-12 Shut-In Shut-InLiquid AdditivesDry Additives50-103-20884Interval 1Coyote@ 17532 - 17534.65 ft 104 °FInterval 2Coyote@ 17033 - 17035.65 ft 104.1 °FInterval 3Coyote@ 16539 - 16541.65 ft 104.2 °FConoco Phillips - 3S-718Planned Design1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.3941017LEASE3S-718SALES ORDERBHST (°F)105LONG-150.19746FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-208844-1 Shut-In Shut-In1:58:39 4-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:39 4-3 Shut-In Shut-In1:53:54 4-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:54 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.154-5 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.154-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.154-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.154-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.154-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.154-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.154-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.154-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.154-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.154-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-2 30# Delta Frac Conditioning Pad 100M 0.500 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.155-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.155-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:54:59 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:35:06 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:25:22 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.156-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:20:22 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:11:21 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:01:57 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:46:43 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:32:35 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:22:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.156-10 30# Linear Flush 20 10,432 248 248 0:12:25 0:15:55 1.00 0.35 30.00 3.00 0.156-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 6-12 Shut-In Shut-In7-1 Shut-In Shut-In1:58:39 7-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:39 7-3 Shut-In Shut-In1:53:54 7-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:54 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.157-5 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.157-6 30# Delta Frac Conditioning Pad 100M 0.5000 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.157-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.157-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.157-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.157-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.157-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.157-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.157-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.157-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.158-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.158-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:53:51 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:33:58 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:24:14 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.000.159-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:19:13 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:10:13 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:00:49 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:45:35 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:31:27 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:21:22 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.159-10 30# Linear Flush 20 9,480 226 226 0:11:17 0:14:47 1.00 0.35 30.00 3.00 0.159-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 9-12 Shut-In Shut-InInterval 9Coyote@ 13517 - 13519.65 ft 104.4 °FInterval 4Coyote@ 15998 - 16000.65 ft 104.3 °FInterval 5Coyote@ 15504 - 15506.65 ft 104.3 °FInterval 6Coyote@ 15007 - 15009.65 ft 104.4 °FInterval 7Coyote@ 14510 - 14512.65 ft 104.4 °FInterval 8Coyote@ 14014 - 14016.65 ft 104.4 °FConoco Phillips - 3S-718Planned Design2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.3941017LEASE3S-718SALES ORDERBHST (°F)105LONG-150.19746FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2088410-1 Shut-In Shut-In1:58:39 10-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:39 10-3 Shut-In Shut-In1:53:54 10-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:54 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1510-5 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1510-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1510-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1510-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1510-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1510-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.000.1510-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.000.1510-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1510-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.000.1510-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1511-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1511-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1511-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1511-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1511-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1511-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1511-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1511-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1511-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1511-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1512-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:52:43 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1512-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:32:50 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1512-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:23:05 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1512-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:18:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1512-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:09:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1512-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:59:41 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1512-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:44:27 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1512-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:30:19 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1512-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:20:14 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1512-10 30# Linear Flush 20 8,526 203 203 0:10:09 0:13:39 1.00 0.35 30.00 3.00 0.1512-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 12-12 Shut-In Shut-In13-1 Shut-In Shut-In1:58:39 13-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:39 13-3 Shut-In Shut-In1:53:54 13-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:54 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-5 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1513-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1513-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1513-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1514-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1514-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1514-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1514-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1514-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1514-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1514-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1514-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1514-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1514-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1515-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:51:31 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1515-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:31:38 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1515-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:21:54 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1515-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:16:54 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1515-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:07:53 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1515-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:58:29 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1515-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:43:15 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1515-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:29:07 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1515-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:19:03 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1515-10 30# Linear Flush 20 7,525 179 179 0:08:58 0:12:28 1.00 0.35 30.00 3.00 0.1515-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 15-12 Shut-In Shut-InInterval 12Coyote@ 12025 - 12027.65 ft 104.6 °FInterval 13Coyote@ 11525 - 11527.65 ft 104.6 °FInterval 14Coyote@ 11069 - 11071.65 ft 104.6 °FInterval 15Coyote@ 10459 - 10461.65 ft 104.7 °FInterval 10Coyote@ 13061 - 13063.65 ft 104.5 °FInterval 11Coyote@ 12605 - 12607.65 ft 104.5 °FConoco Phillips - 3S-718Planned Design3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.3941017LEASE3S-718SALES ORDERBHST (°F)105LONG-150.19746FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2088416-1 Shut-In Shut-In1:58:39 16-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:39 16-3 Shut-In Shut-In1:53:54 16-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:54 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1516-5 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:40:34 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1516-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1516-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1516-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1516-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1516-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.00 2.00 0.35 30.00 1.003.000.1516-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.00 2.00 0.35 30.00 1.003.000.1516-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1516-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.00 2.00 0.35 30.00 1.003.000.1516-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1517-1 30# Delta Frac Pad 20 16,700 398 398 0:19:53 1:50:51 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1517-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:30:58 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1517-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:21:14 0.45 1.00 1.00 2.00 0.35 30.00 1.00 3.00 0.1517-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:16:14 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1517-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:07:13 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1517-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:57:49 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1517-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:42:35 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1517-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:28:27 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1517-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:18:23 0.45 1.00 1.00 2.00 0.35 30.00 1.003.00 0.1517-10 30# Linear Flush 20 6,966 166 166 0:08:18 0:11:48 1.00 0.35 30.00 3.00 0.1517-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 17-12 Shut-In Shut-In1,382,274 32,911 38,405 5,172,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-61,281,4095,100,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)86,04472,000Initial Design Material Volume 576.6 1,367.5 1,281.4 2,531.7 478.6 41,023.6 1,291.2 4,102.4 205.1-14,820- 0.2673 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 0.4 0.8 0.8 1.7 0.3 25.2 1.7 2.5 0.1-Min Additive RateFluid Type30# Delta Frac30# LinearProduced WaterFreeze Protect----Proppant TypeWanli 16/20 Ceramic100M---Interval 16Coyote@ 10042 - 10044.65 ft 104.9 °FInterval 17Coyote@ 9584 - 9586.65 ft 104.9 °F9:06:05 Conoco Phillips - 3S-718Planned Design4 SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) After the fracture stimulation, ConocoPhillips (“CPAI”) plans to flowback the well for cleanup purposes for an estimated 7 to 14 days. Expro will be the flowback company utilized for the flowback. The flowback liquids will be routed through a portable test separator then onto either CPF3 or Drill Site 3S’s facilities. Once the well’s flowback liquids meet CPF3 criteria all liquids will be routed to CPF3. CPAI plans to limit the flowback time to what is necessary to achieve conforming production liquids. Hydraulic Fracturing Fluid Product Component Information Disclosure 2024-08-09 Alaska HARRISON BAY 50-103-20884-00-00 CONOCOPHILLIPS 3S 718 -150.19740000 70.39410000 NAD83 none Oil 4285 1367464 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone Produced Water (Density 8.5)Operator Base Fluid Density = 8.50 SEAWATER (SG 8.52)Operator Base Fluid Density = 8.52 AS-7 ANTI- SLUDGING AGENT Halliburton Anti-sludging Agent BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator FE-1A ACIDIZING COMPOSITION Halliburton Additive FE-2A Halliburton Additive HAI-404M Halliburton Corrosion Inhibitor HYDROCHLORI C ACID, 10-30%Halliburton Solvent LoSurf-300D Halliburton Non-ionic Surfactant LVT-200 Baker Hughes Additive MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker SP BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Calcium Chloride Customer Salt Solution Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer Potassium Formate Brine MI Swaco Completion/Stimulatio n WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 100.00%68.69690%11623359 Corundum 1302-74-5 65.00%19.59246%3315000 Mullite 1302-93-8 45.00%13.56401%2295000 Crystalline silica, quartz 14808-60-7 100.00%0.43025%72798 Water 7732-18-5 100.00%0.28141%47614 Guar gum 9000-30-0 100.00%0.24246%41023 Calcium Chloride 10043-52-4 100.00%0.05910%10000 EDTA/Copper chelate Proprietary 30.00%0.03743%6333 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%0.03711%6280 Monoethanolamine borate 26038-87-9 100.00%0.03462%5859 Hydrochloric acid 7647-01-0 60.00%0.03429%5802 Ammonium acetate 631-61-8 100.00%0.02600%4399 Ammonium persulfate 7727-54-0 100.00%0.02424%4102 Sodium hydroxide 1310-73-2 30.00%0.02405%4070 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01856%3140 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01856%3140 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Ethylene glycol 107-21-1 30.00%0.01039%1758 Potassium Formate 590-29-4 100.00%0.00875%1480 Acetic acid 64-19-7 60.00%0.00812%1374 Walnut hulls NA 100.00%0.00763%1291 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Oxylated phenolic resin Proprietary 30.00%0.00727%1231 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Ammonium chloride 12125-02-9 5.00%0.00624%1056 Oxyalkylated phenolic resin Proprietary 10.00%0.00619%1047 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Naphthalene 91-20-3 5.00%0.00309%524 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00309%524 Flow Insurance Copper Proprietary 100.00%0.00261%442 Patina Energy Product Stewardship test@patinae nergy.com 7205324886 Polyamine Proprietary 30.00%0.00229%388 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Ammonia 7664-41-7 1.00%0.00125%212 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00121%205 Sodium chloride 7647-14-5 1.00%0.00080%136 Methanol 67-56-1 30.00%0.00077%131 Glycol Ether Proprietary 85.00%0.00068%116 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00062%105 Acetic anhydride 108-24-7 100.00%0.00053%90 Water 7732-18-5 100.00%0.00050%86 Distillates (petroleum), hydrotreated light 64742-47-8 100.00%0.00041%70 Hemicellulase 9025-56-3 5.00%0.00038%65 Citric acid 77-92-9 60.00%0.00037%63 Ethoxylated alcohol Proprietary 60.00%0.00031%52 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Benzenesulfonic acid, dodecyl-, compd. with morpholine 12068-08-5 60.00%0.00031%52 Confidential Proprietary 20.00%0.00024%42 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 C.I. pigment Orange 5 3468-63-1 1.00%0.00024%42 Ethylene Glycol 107-21-1 20.00%0.00017%29 Isopropanol 67-63-0 30.00%0.00015%25 Aldehyde Proprietary 30.00%0.00015%25 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Cycloaliphatic alkyoxylate Proprietary 30.00%0.00015%25 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Cured acrylic resin Proprietary 1.00%0.00008%13 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00008%13 Sodium persulfate 7775-27-1 100.00%0.00006%10 Polyethoxylated fatty amine salt 61791-26-2 10.00%0.00005%9 Benzylheteropolycycle salt Proprietary 10.00%0.00005%9 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 1-(Benzyl)quinolinium chloride 15619-48-4 10.00%0.00005%9 Ethoxylated alcohols Proprietary 10.00%0.00005%9 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Fatty acids, tall oil Proprietary 10.00%0.00005%9 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%6 Morpholine 110-91-8 5.00%0.00003%5 Sodium chloride 7647-14-5 5.00%0.00003%5 Ethoxylated alkyl amines Proprietary 5.00%0.00002%5 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Potassium acetate 127-08-2 1.00%0.00001%1 Sodium iodide 7681-82-5 1.00%0.00000%1 Ammonium phosphate 7722-76-1 1.00%0.00000%1 Sodium sulfate 7757-82-6 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 supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. Production Type: True Vertical Depth (TVD): Total Water Volume (gal)*: MSDS and Non-MSDS Ingredients are listed below the green line Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Fracture Date State: County: API Number: Operator Name: Hydraulic Fracturing Fluid Product Component Information Disclosure ProTechnics Division 6510 West Sam Houston Parkway North Houston, Texas 77041 Phone: (346) 328-9474 North Slope ATTN: Jeremiah Diaz Hydraulic Fracturing Fluid Product Component Information Disclosure Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Comments Ingredient Volume Pumped Mass of Additive Pumped S.G Manufacturer Contact ZeroWash Tracer ProTechnics Diagnostics Ceramic Proppant proprietary 14.00% Water (major) 7732-18-5 70.00%Core Laboratories Methanol (major) 67-56-1 30.00%ProTechnics Division Dipropylene glycol methyl ether (minor) 34590-94-8 1.00%HSE (346) 328-9474 Xanthan gum (minor) 11138-66-2 1.00%ATTN: Jeremiah Diaz Jeremiah.Diaz@corelab.com One ingredient in the Chemical Frac Tracer additive (Sodium Salt) and one ingredient in the ZeroWash Tracer additive (Ceramic Proppant) is trade secret. For any questions contact regulatory compliance at (346) 328-9474 State:Alaska County: COP Well Name and Number:3S-718 API Number: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, Coyote Undefined Oil Pool, KRU 3S-718 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-034 Surface Location 2743.79' FSL, 3661.89' FWL, SENE S18 T12N R8E Bottomhole Location: 907.29' FSL, 4157.49' FWL, SENW S5 T12N R8E 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, Brett W. Huber, Sr. Chair, Commissioner DATED this day of May 2024. 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: 17695.53 TVD: 4194 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 5/15/2024 Total Depth:9. Acres in Property:14. Distance to Nearest Property: 1122' to ADL025532 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 64.1 15. Distance to Nearest Well Open Surface: x-476115 y- 5993880 Zone- 4 25 to Same Pool: 10770' to 3S-704 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 80 39.1 39.1 119.1 119.1 13.5" 10.75" 45.5 L-80 Hyd563 3902.9 39.1 39.1 3942 2604 9.875" 7.625" 29.7 L80 Hyd563 8606.9 39.1 39.1 8646 4806 9.875" 7.625" 33.7 P110S Hyd563 800 8646 4806 9446 4261 6.5" 4.5" 12.6 P110S Hyd563 8399.53 9296 5091 17695.53 4194 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Brian Broussard Chris Brillon Contact Email:brian.t.broussard@cop.com Wells Engineering Manager Contact Phone:907-263-4090 Date: Permit to Drill API Number: Permit Approval Number: Date: 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 Conductor/Structural Surface Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Casing Length Size Cement Volume MD 990sks 10.7ppg, 280sks 15.8ppg 310sks 15.3ppg 900 sx 15.3 ppg w/ frac sleeves 18. Casing Program: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips 59-52-180 3S-718 Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Conditions of approval : 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Coyote Oil Reservoir 2743.79' FSL, 3661.89' FWL, SENE S18 T12N R8E ADL380107 / ADL025546 / ADL380106 (including stage data) 3068.5' FSL, 19.12' FWL, NWSE S16 T12N R8E LONS 01-013 907.29' FSL, 4157.49' FWL, SENW S5 T12N R8E 2448 / 2560 / 2437 GL / BF Elevation above MSL (ft): 1916 1496 Stratigraphic Test No Mud log req'd: Yes No No Directional svy req'd: Yes No Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Single Well Gas Hydrates No Inclination-only svy req'd: Yes No Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal No No Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 9:12 am, May 10, 2024 50-103-20884-00-00 Undefined Oil Diverter variance request granted per 20 AAC 20.035(h)(2), based on offset analysis of KRU 3S-08 and mudlogs from KRU 3S-620, and Palm-1. -A.Dewhurst 30APR24 A.Dewhurst 10MAY24 Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig Waiver for CPAI Rotary BOPE Test Frequency applies according to order OTH-21-018 extension attached 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 1456 224-034 VTL 5/13/2024 10:03 am, May 10, 2024 1876 X DSR-5/13/24 KRU Alaska, Inc. JLC 5/13/2024 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. 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov March 2, 2023 Mr. Luke Lawrence Wells Manager ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Re: Docket Number: OTH-21-018 CPAI Rotary Rig BOPE Test Frequency Dear Mr. Lawrence: By letter dated January 12, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested a continuance of the waiver granted under Docket OTH-21-018 allowing certain CPAI rotary drilling rigs to test blowout prevention equipment (BOPE) on a 21-day test schedule. The Alaska Oil and Gas Conservation Commission (AOGCC) grants CPAI’s request for a limited duration and scope. OTH-21-018 approved the 21-day test interval for a 1-year period which expired on January 25, 2023. The AOGCC approved an extension to the pilot program by electronic mail on February 6, 2023, to accommodate review of the July-December 2022 BOPE Between Wells Maintenance Report (received January 27, 2023, and revised February 3, 2023). AOGCC met with CPAI on February 22, 2023 to discuss the Between Wells Maintenance Report and BOPE performance of the CPAI-operated rigs during 2022 in considering the requested continuance.1 During the past year, CPAI-operated rigs Doyon 25 and Doyon 26 were authorized to participate in the pilot – the other rigs working for CPAI failed to meet the conditions for testing BOPE at 21- day intervals.2 CPAI’s request to continue the pilot project allowing BOPE testing on a 21-day interval is approved for drilling rigs Doyon 25 and Doyon 26, with the following conditions: - The pilot test duration is for ONE year from the approval date of this letter, subject to potential extension and expansion to include other CPAI operated rigs with at least 3 months of continuous rig work and AOGCC review of a rig’s BOPE system reliability. 1 AOGCC approval of the Between Wells Maintenance program has enabled CPAI workover rigs to extend the interval between BOPE tests from every 7 days to not exceeding 14 days and was also part of the justification for allowing certain rigs to test BOPE on a 21-day interval. CPAI data shows the BWM has reduced the number of component failures during BOPE testing by replacing components that indicate suspect integrity before those components fail during testing. 2 Doyon 26 has additionally been approved (Permit-to-Drill) to test BOPE on an event-basis instead of at pre- determined time intervals while drilling specific sections in an ultra-extended reach well. Docket Number: OTH-21-018 March 2, 2023 Page 2 of 2 - CPAI must continue to implement the BWM program as approved by AOGCC. - Development drilling wells only are included in this approval. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. - 48-hour advance notice for a BOPE test shall be provided to AOGCC for opportunity to witness. If you have questions regarding this, please contact Jim Regg at (907) 793-1236. Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: Greg Hobbs (CPAI) Mike Kneale (CPAI) Victoria Loepp (AOGCC) AOGCC Inspectors (email) ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 May 9, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3S-718 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Producer well from the 3S drilling pad. The intended spud date for this well is 5/15/2024. It is intended that Doyon 142 be used to drill the well. 3S-718 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 set in the Coyote reservoir. A 7 5/8” casing string will be set and cemented from TD to secure the shoe and cover 250’TVD above any hydrocarbon-bearing zones (Coyote). The production interval will be comprised of a 6 1/2” horizontal hole that will be geo-steered in the Coyote formation. The well will be completed as a cemented, fracture stimulated Producer with 4 1/2” liner and frac sleeves. The upper completion will include a production packer with GLM’s. It is requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well 3S-718. At 3S, there has not been a significant indication of shallow gas hydrates though the surface hole interval. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a) 2. 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 Brian Broussard at 907-263-4090 (brian.t.broussard@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3S-718 Well File / Jenna Taylor ATO 1560 David Lee ATO 1552 Brian Broussard Chris Brillon ATO 1548 Drilling Engineer Patrick Perfetta ATO 1462 variance of the diverter requirement Application for Permit to Drill, 3S-718 Saved: 9-May-24 3S-718 PTD Page 1 of 9 Printed: 9-May-24 3S-718 Application for Permit to Drill Document Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) ........................................................................................................ 2 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) ......................................................................................... 2 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)) ............................................................. 4 5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) ..................................................................................... 5 6. MASP Calculations (Requirements of 20 AAC 25.005(c)(4)) ................................................................................ 5 7. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5)) ............................ 6 8. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) ........................................................... 6 9. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) .................................................................................. 7 10. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ........................................ 8 11. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ................................................................................... 8 12. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ................................................................... 8 13. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) ............................................................................. 8 14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005 (c)(14)) ......... 8 15. Drilling Hazards Summary ................................................................................................................................. 8 16. Proposed Completion Schematic ..................................................................................................................... 10 1. Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted will be designated as 3S-718 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 2,744 FSL, 3,662 FWL, SENE S18 T12N R8E, UM NAD 1927 Northings: 5993880 Eastings:476115 RKB Elevation 64.1’AMSL Pad Elevation 25’AMSL Top of Productive Horizon (Heel) 3068.5‘ FSL, 19.12‘ FWL, NWSE S16 T12N R8E, UM NAD 1927 Northings: 5994186 Eastings: 482558 Measured Depth, RKB: 9,446 Total Vertical Depth, RKB: 4,261 Total Vertical Depth, SS: 4,197 Total Depth (Toe) 907.29‘ FSL, 4157.49‘ FWL, SENW S5 T12N R8E, UM NAD 1927 Northings: 6002587 Eastings: 481412 Measured Depth, RKB: 17,696 Total Vertical Depth, RKB: 4,194 Total Vertical Depth, SS: 4,130 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 3S-718 2. Rig up and test riser, dewater cellar as needed. 3. Drill 13 1/2” hole to the surface casing point as per the directional plan. 4. Run and cement 10 3/4” surface casing to surface. 5. Install BOPE and MPD equipment. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8” 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 12.5 ppg EMW. 10. Drill 9 7/8” hole to section TD, setting pipe in the Coyote Reservoir. (LWD Program: GR/RES/Den/Neu/Image Log). 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 16 ppg. Minimum required leak-off value is 11.5 ppg EMW. 16. Drill 6 1/2” hole to section TD (LWD Program: GR/RES/Den/Neu/Deep RES). 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 liner hanger to TD. Cement into place 19. Run 4 1/2” upper completion with production packer, landing nipple, 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 3S-718. 3S-718 has a MASP of 1,456 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)) It is requested that a variance of the diverter requirement under 20 AAC 25.035(h)(2) is granted. At 3S, there has not been significant indication of shallow gas or gas hydrates through the surface hole interval. There is 1 previously drilled well (3S-08) within 500’ of the proposed 3S-718 surface shoe location. This well did not encounter any significant indication of shallow gas or gas hydrates. 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) 20 119.1 / 119.1 10.9 54 56 10 3/4 3,942 / 2,604 12.5 1,164 1,432 7 5/8 9,446 / 4,261 13.5 1,906 1,456 4 1/2 17,696 / 4,194 13.0 1,876 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 Recommend approving variance based on review of drilling reports from KRU 3S-08 and mudlogs of KRU 3S-620 and Palm-1. -A.Dewhurst 30APR24 All formations anticipated to be normally pressured. See attached emails. -A.Dewhurst 30APR24 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 119.1 = 56 psi OR ASP = FPP – (0.1 x D) = 1,164 – (0.1 x 2,604 ) = 904 psi 2. Drilling below 10.75” surface casing ASP = [(FG x 0.052) – 0.1] D = [(12.5 x 0.052) – 0.1] x 2,604 = 1,432 psi OR ASP = FPP – (0.1 x D) = 1,906 – (0.1 x 4,261 ) = 1,479 psi 3. Drilling below 7.625” intermediate casing ASP = [(FG x 0.052) – 0.1] D = [(13.0 x 0.052) – 0.1] x 4,261 = 2,565 psi OR ASP = FPP – (0.1 x D) = 1,876 – (0.1 x 4,194 )= 1,456 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 Cemented liner with frac sleeves Cementing Calculations 10 3/4” Surface Casing run to 3,942 ’ MD / 2,604 ’ TVD Cement 3,942 MD to 3,442 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 3,442' to surface with 10.7 ppg Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,848 ’ MD), zero excess in 20” conductor. Lead slurry from 3,442’ MD to surface with Arctic Lite Crete @ 10.7 ppg Total Volume = 2,886ft3 => 990 sx of 10.7 ppg Class G + Add's @ 2.92 ft3 /sk Tail slurry from 3,942 MD to 3,442’ MD with 15.8 ppg Class G + Add's Total Volume = 321 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.165 ft3/sk 7 5/8” Intermediate Casing run to 9446’ MD / 4,261 ’ TVD Top of slurry is designed to be at 8,250 ’ MD, which is 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 9,446 MD to 8,250’ MD with 15.3 ppg Class G + Add's Total Volume = 383 ft3 => 310 sx of 15.3 ppg Class G + Add's @ 1.237 ft3/sk 4.5” Production Liner run to 17,696 ’ MD / 4,194 ’ TVD Top of slurry is designed to be at 9,296’ MD, which is at the liner top hanger set a minimum of 150’ inside the intermediate casing. Assume 10% excess annular hole volume, and 0% excess cased hole volume. Tail slurry from 17,696 ’ MD to 9,296 MD with 15.3 ppg Class G + Add's Total Volume = 1,105 ft3 => 900 sx of 15.3 ppg Class G + Add's@ 1.2342 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 – 10.0 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 to base perm 200-300 to TD 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 10.0 ppg by use of solids control system and dilutions where necessary. Intermediate: Inhibited water-based mud drill-in fluid. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight at 9-10 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 maintained at 10 ppg before pulling out of the hole. Production Hole: The horizontal production interval will be drilled with an inhibited water-based mud drill-in fluid weighted to 9 – 10 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: 3S is a multi-well pad. 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: Offset injection has the potential to increase reservoir pressure over predicted. Although this is unlikely, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. H2S on 3S pad – There have been elevated H2S levels noted on the 3S pad post drilling. Lift gas from CPF3 facility has ~200- 250ppm H2S in it. The rig will have H2S sensors which will be tested, escape packs staged around the rig, and personal monitors will be worn by the core crew members. A detailed emergency operating procedure will be communicated to all personnel, in the event H2S is encountered 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 1.00 3 400.00 1.00 121.00 399.99 -0.45 0.75 1.00 121.00 -0.51 Start Build 2.00 4 500.00 3.00 121.00 499.93 -2.25 3.74 2.00 0.00 -2.56 Start Build 3.00 51781.48 41.44 121.00 1664.10 -247.21 411.42 3.00 0.00 -282.12 Start 133.41 hold at 1781.48 MD 61914.89 41.44 121.00 1764.10 -292.69 487.11 0.00 0.00 -334.03 Start DLS 3.75 TFO -39.03 7 2888.18 72.74 97.91 2291.25 -530.60 1249.47 3.75 -39.03 -637.48 Start 3845.56 hold at 2888.18 MD 8 6733.74 72.74 97.91 3432.48 -1035.66 4886.90 0.00 0.00-1457.64 Start DLS 3.75 TFO -102.67 99471.67 82.00 351.90 4264.94 585.69 6426.81 3.75 -102.67 23.33 Start Build 2.50 109671.67 87.00 351.90 4284.10 782.72 6398.79 2.50 0.00 222.05 3S-718 P05 T1 031424 Start 20.00 hold at 9671.67 MD 11 9691.67 87.00 351.90 4285.15 802.50 6395.97 0.00 0.00 242.00 Start Build 1.50 129949.67 90.87 351.90 4289.94 1057.83 6359.65 1.50 0.00 499.53 Start 3675.00 hold at 9949.67 MD 1313624.67 90.87 351.90 4234.14 4695.79 5842.15 0.00 0.004168.74 Start DLS 1.00 TFO 179.98 1413655.43 90.56 351.90 4233.76 4726.24 5837.82 1.00 179.984199.45 Start 4040.11 hold at 13655.43 MD 1517695.53 90.56 351.90 4194.10 8725.89 5268.88 0.00 0.008233.47 3S-718 P05 T2 031424 TD at 17695.53 39 500 500 700 700 900 900 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 17700 3S-718 wp06 Plan Summary 0 3 0 2500 5000 7500 10000 12500 15000 17500 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] 1315 3S-03 509 610 709 807 3S-16 108 208 307 407 5063S-17 108 208 307 407 5063S-17A 108208308 407 506 3S-18 108 208308 3S-19 904 9963S-613 708 806 9023S-615 40101201301401 501 601 698 3S-617 971972973974963S-719 (P02) wp05 697 3S-7xx (I15) wp02 0 2500 -1500 0 1500 3000 4500 6000 7500 9000 Vertical Section at 355.00° 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 0 30 60 300 600 900 1200 1500 1800 2100 Measured Depth Equivalent Magnetic Distance DDI 7.214 SURVEY PROGRAM Date: 2022-02-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.10 1400.00 3S-718 wp06 (3S-718) r.5 SDI_URSA1 1400.00 3940.00 3S-718 wp06 (3S-718) MWD+IFR2+SAG+MS 3940.00 9440.00 3S-718 wp06 (3S-718) MWD+IFR2+SAG+MS 9440.00 17695.53 3S-718 wp06 (3S-718) MWD+IFR2+SAG+MS Elevation / 25.00 CASING DETAILS TVD MD Name 2604.00 3942.03 10-3/4" Surface Casing 4261.29 9446.007-5/8" Intermediate Casing 4194.10 17695.53 4-1/2" Production Liner Mag Model & Date: BGGM2023 25-May-24 Magnetic North is 14.22° East of True North (Magnetic Declinati Mag Dip & Field Strength: 80.63° 57210.56nT FORMATION TOP DETAILS TVDPath Formation 1461.10 Top Ugnu 1714.10 Base Permafrost 2026.10 Top West Sak 2451.10 Base West Sak 2718.10 Campanian Sand (C-80) 3509.10 C-50 4215.10 Fault 4221.10 Top Coyote (Nanushuk), K3 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 25+39.1 @ 64.10usft (D142) True Vertical Depth90001 00 00 11 0 0 0 1 20 00 13 000 140 00 15 00 0 160 00 17 00 017696 90°91° 91 ° 3S-718 wp06 South(-)/North(+) 0.000.501.001.502.002.503.003.504.004.505.005.50Separation Factor0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000Measured Depth (2000 usft/in)3S-03/3S-033S-08/3S-083S-08/3S-08A3S-08/3S-08C3S-722/3S-722 wpSTOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: 3S-718Wellbore: 3S-718Design: 3S-718 wp06 0 35 0 500 1000 1500 2000 2500 Partial Measured Depth Equivalent Magnetic Distance 3S-718 wp06 Ladder View 0 150 300 0 3000 6000 9000 12000 15000 18000 Measured Depth Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 39.10 1400.00 3S-718 wp06 (3S-718) r.5 SDI_URSA1 1400.00 3940.00 3S-718 wp06 (3S-718) MWD+IFR2+SAG+MS 3940.00 9440.00 3S-718 wp06 (3S-718) MWD+IFR2+SAG+MS 9440.0017695.53 3S-718 wp06 (3S-718) MWD+IFR2+SAG+MS 10:51, May 07 2024 CASING DETAILS TVD MD Name 2604.00 3942.03 10-3/4" Surface Casing 4261.29 9446.00 7-5/8" Intermediate Casing 4194.10 17695.53 4-1/2" Production Liner 39 500 500 700 700 900 900 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 17700 3S-718 wp06 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] 1054 1101 1148 1192 1235 1276 131513531388 1422 1453 3S-03 1048 1096 1142 1186 1228 1268 1306 3S-06 1048 1096 1142 1186 1228 1268 1306 58 108158208258308359410461 513 565 617 668 3S-10 58108158208258308359409459 510 560 609 658 705 752 797 842 884 3S-14 57107157207257307358408458 508 557 606 654 701 748 793 837 879 920 3S-15 57107157207 257307358408458509559610660709758 807 855 902 949 995 1040 1084 1128 1170 3S-16 58108158208258307357407 456 506 554 602 649 695 740 783 825 866 3S-17 58108158208258307357407 456 506 554 602 649 695 740 783 825 866 58108158208258 308358407457506555602650 696 741 784 827 868 3S-18 58 108158208258308358407456505553600 647 692 736 778 820 3S-19 57107157207257307356 406 454 503 551 600 648 695 742 789 834 3S-21 57107157207257307356406455504552600647694741786 830 873 3S-22 59 109 159209259309358407455503 550 595 640 683 3S-23 56 106 156206256306356405453500 547 593 638 681 58108158 208258308357406454 501 548 3S-24 58108158 208258308357406454 501 548 58108158 208258308357406454 502 548 541041542042543043534024504985455926393S-26 54104154204254304353402450498545592639PALM 1 3950100150200250300351402454 506559612664715 766 815 864 912 959 1004 1048 1091 1133 1173 3S-610 4050100150200250300 351402454505557609 659 710 759 807 855 901 945 988 1029 1068 3S-611 4050100150200250300 351402454505557609 659 710 759 807 855 901 945 988 1029 1068 4050100150 200250300351402453504555606 656 705 753 800 845 890 934 976 10173S-612 3950100150200250300350401452503555606658708758 80885690495199610391081112211601198 3S-613 4053103153203253303354404455505556607658708757806854902948994103710791120 1160 3S-615 4051101151201251301351401451501551601650 698 746 793 838 884 928 971 1013 1054 3S-617 62 112162 212262312361411461510559 608656703750 795 840 884 928 3S-620 4051101151201251 301350399447496543 589 635 680 7253S-624 4053103153203253303352402450498545592639 3S-625 39 50100150200250300349398446 493 540 112111631203 1242 1280 1316 1350 3S-701 112111631203 1242 1280 1316 1350 9359831029 1074111811611203124312821319 135413863S-704 47971471972472973473964454945435926406897387878358849329811029107811261174122212701318136614141461 3S-722 wp05 985103410831131 1177122212661309135113921432147015071544 3S-705 (I12) wp08 4051101151201251301352402453504554 605 654 703 751 797 842 886 928 969 3S-714 wp07 4797147197247297347397447496546595 643692740787834881 927 972 1017 1059 3S-719 (P02) wp05 4797147197247297347397446495543591639685 731 776820 8633S-721 (I03) wp04 4797147197247297348398449499550 600 649 698 745 791 836 879 921 961 3S-723 wp04 4797147197247297348398449499549599649697744 791 836 880 922 963 1003 3S-7xx (I15) wp02 39 50100150200250300349398446 493 5403S-626 50100150200250300349398446494 540 3S-626 wp07.1 SURVEY PROGRAM Date: 2022-02-15T00:00:00 Validated: Yes Version: From To Tool 39.10 1400.00 r.5 SDI_URSA1 1400.00 3940.00 MWD+IFR2+SAG+MS 3940.00 9440.00 MWD+IFR2+SAG+MS 9440.00 17695.53 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 2604.00 3942.03 10-3/4" Surface Casing 4261.29 9446.00 7-5/8" Intermediate Casing 4194.10 17695.53 4-1/2" Production Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 400.00 1.00 121.00 399.99 -0.45 0.75 1.00 121.00 -0.51 Start Build 2.00 4 500.00 3.00 121.00 499.93 -2.25 3.74 2.00 0.00 -2.56 Start Build 3.00 5 1781.48 41.44 121.00 1664.10 -247.21 411.42 3.00 0.00 -282.12 Start 133.41 hold at 1781.48 MD 6 1914.89 41.44 121.00 1764.10 -292.69 487.11 0.00 0.00 -334.03 Start DLS 3.75 TFO -39.03 7 2888.18 72.74 97.91 2291.25 -530.60 1249.47 3.75 -39.03 -637.48 Start 3845.56 hold at 2888.18 MD 8 6733.74 72.74 97.91 3432.48 -1035.66 4886.90 0.00 0.00 -1457.64 Start DLS 3.75 TFO -102.67 9 9471.67 82.00 351.90 4264.94 585.69 6426.81 3.75 -102.67 23.33 Start Build 2.50 10 9671.67 87.00 351.90 4284.10 782.72 6398.79 2.50 0.00 222.05 3S-718 P05 T1 031424 Start 20.00 hold at 9671.67 MD 11 9691.67 87.00 351.90 4285.15 802.50 6395.97 0.00 0.00 242.00 Start Build 1.50 12 9949.67 90.87 351.90 4289.94 1057.83 6359.65 1.50 0.00 499.53 Start 3675.00 hold at 9949.67 MD 1313624.67 90.87 351.90 4234.14 4695.79 5842.15 0.00 0.00 4168.74 Start DLS 1.00 TFO 179.98 1413655.43 90.56 351.90 4233.76 4726.24 5837.82 1.00 179.98 4199.45 Start 4040.11 hold at 13655.43 MD 1517695.53 90.56 351.90 4194.10 8725.89 5268.88 0.00 0.00 8233.47 3S-718 P05 T2 031424 TD at 17695.53 Northing (5000 usft/in)556 0 Northing (2000 usft/in)5560 Northing (550 usft/in)5460 28 Northing (75 usft/in)28 South(-)/North(+) (2000 usft/in)420042604280 -1250-1000-750-500-2500South(-)/North(+) (250 usft/in)1500 1750 2000 2250 2500 2750 3000 3250 3500West(-)/East(+) (250 usft/in)260026203S-083S-08A 3S-08B3S-08CL126002620260026203S-718 wp06Surface Casing 500 ft r12:40, May 07 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3S-718 P05 T1 031424 4284.10 Circle (Radius: 100.00)3S-718 P05 T2 031424 4194.10 Circle (Radius: 100.00)3S-718 Srf Csg 500'r 2601.10 Circle (Radius: 500.00)3S-718 T1 QM 4284.10 Circle (Radius: 1320.00)3S-718 T2 QM 4194.10 Circle (Radius: 1320.00) 3S-718wp06 Surface Location 3S-718wp06 Surface Location # Schlumberger-Confidential 3S-718wp06 Surface Casing 3S-718wp06 Surface Casing # Schlumberger-Confidential 3S-718wp06 Top Coyote 3S-718wp06 Top Coyote # Schlumberger-Confidential 3S-718wp06 Intermediate Csg 3S-718wp06 Intermediate Csg # Schlumberger-Confidential 3S-718wp06 TD 3S-718wp06 TD # Schlumberger-Confidential Certificate Of Completion Envelope Id: 6E97AE1A12504E7F8AFD0E92B610F12D Status: Completed Subject: Complete with DocuSign: 3S-718_PTD_UPDATED_Unsigned.pdf Source Envelope: Document Pages: 59 Signatures: 2 Envelope Originator: Certificate Pages: 5 Initials: 0 Brian Broussard AutoNav: Enabled EnvelopeId Stamping: Disabled Time Zone: (UTC-06:00) Central Time (US & Canada) 925 N Eldridge Pkwy Houston, TX 77079 Brian.T.Broussard@conocophillips.com IP Address: 138.32.8.5 Record Tracking Status: Original 5/9/2024 2:13:43 PM Holder: Brian Broussard Brian.T.Broussard@conocophillips.com Location: DocuSign Signer Events Signature Timestamp Brian Broussard brian.t.broussard@conocophillips.com Security Level: Email, Account Authentication (None) Signature Adoption: Pre-selected Style Using IP Address: 138.32.8.5 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By selecting the check-box next to ‘I agree to use electronic records and signatures’, you confirm that: You can access and read this Electronic Record and Signature Disclosure; and You can print on paper this Electronic Record and Signature Disclosure, or save or send this Electronic Record and Disclosure to a location where you can print it, for future reference and access; and Until or unless you notify ConocoPhillips as described above, you consent to receive exclusively through electronic means all notices, disclosures, authorizations, acknowledgements, and other documents that are required to be provided or made available to you by ConocoPhillips during the course of your relationship with ConocoPhillips. 1 Dewhurst, Andrew D (OGC) From:Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent:Thursday, May 9, 2024 13:56 To:AOGCC Permitting (CED sponsored) Cc:Hobbs, Greg S; Taylor, Jenna; Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Lee, David L; Brillon, Chris L; Perfetta, Patrick J Subject:3S-718 PTD - Updated Submission Attachments:3S-718 (P05) wp06 [canvas].txt; 3S-718_PTD_UPDATED_Final.pdf Hello, Attached is a fully updated PTD Application for the 3S-718, as requested by Andrew. As discussed, the Top of Cement was updated in the PTD Amendment sent several days ago, which caused a discrepancy with the original PTD application. The new application re ects the proper cement volumes, and there were no other signi cant changes in the application. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Thursday, May 9, 2024 08:50 To:Broussard, Brian T; AOGCC Permitting (CED sponsored) Cc:Hobbs, Greg S; Taylor, Jenna; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Lee, David L; Brillon, Chris L; Perfetta, Patrick J Subject:RE: 3S-718 PTD Amendment Submissions Brian, Would you please submit a complete and revised PTD that includes the details to the updated cement calcula ons and direc onal plan to the processing email address? Thanks, Andy From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent: Wednesday, May 8, 2024 09:37 To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc:Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Lee, David L <David.L.Lee@conocophillips.com>; Brillon, Chris L <Chris.L.Brillon@conocophillips.com>; Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com> Subject: 3S-718 PTD Amendment Submissions Hello, Attached is the Amended PTD application for the 3S-718 on Doyon 142, which has been updated with the As-Built Conductor survey. Please let me know if you have any questions. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 Some people who received this message don't often get email from brian.t.broussard@conocophillips.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Tuesday, April 30, 2024 09:39 To:Broussard, Brian T; Hobbs, Greg S Cc:Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Loepp, Victoria T (OGC); Davies, Stephen F (OGC) Subject:RE: [EXTERNAL]KRU 3S-718 PTD (224-034): Questions Brian, Thank you. Andy From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent: Tuesday, April 30, 2024 09:35 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL]KRU 3S-718 PTD (224-034): Questions Andrew, Thanks for reviewing the application. You referenced the 3S-617 but con rming that this is the application for the 3S-718. I have responded to your questions in red in the original email. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, April 29, 2024 5:45 PM To: Broussard, Brian T <Brian.T.Broussard@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL]KRU 3S-718 PTD (224-034): Questions CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. You don't often get email from brian.t.broussard@conocophillips.com . Learn why this is important 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 Brian, I am comple ng the review of the KRU 3S-617 and have two ques ons: In the Drilling Hazards Summary, I see that abnormal reservoir pressure risk for the target Coyote is Low. What exactly is the risk (overpressure from o set injec on, etc.)? Would you also con rm that there are no other permeable forma ons that are abnormally pressured? o The risk for abnormal reservoir pressure in the Coyote target is identi ed as a precaution due to this target having few wells drilled in it. We do not expect any actual pressure anomalies from o set wells. There is 1 injector and 1 producer in the Coyote formation on the 3S pad, but both laterals are over 2 miles away. o There are no abnormally pressured formations identi ed. The entire wellbore is expected to be normally pressured. The BHL on the 10-401 page shows S5 T12N R5E. Would you con rm that is a typo and should instead read R8E? o You are correct. This is a typo and it should read R8E Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conserva on Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 1 Dewhurst, Andrew D (OGC) From:Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent:Monday, May 6, 2024 08:24 To:Guhl, Meredith D (OGC) Cc:Hobbs, Greg S; Taylor, Jenna; Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Lee, David L; Brillon, Chris L; Perfetta, Patrick J Subject:RE: [EXTERNAL]RE: 3S-718 PTD Submission Good morning, We are expecting to have the 3S-718 as-built conductor report to you tomorrow. We are planning to move to the well in about a week, but we were unable to set the conductor earlier due to SIMOPs. We appreciate your patience. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 From: Broussard, Brian T Sent: Tuesday, April 16, 2024 8:22 AM To: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Cc:Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Lee, David L <David.L.Lee@conocophillips.com>; Brillon, Chris L <Chris.L.Brillon@conocophillips.com>; Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com> Subject: RE: [EXTERNAL]RE: 3S-718 PTD Submission Hi Meredith, I’ve attached the well le in .txt format. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 Some people who received this message don't often get email from brian.t.broussard@conocophillips.com. Learn why this is important 2 From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Tuesday, April 16, 2024 8:10 AM To: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com >; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Lee, David L <David.L.Lee@conocophillips.com >; Brillon, Chris L <Chris.L.Brillon@conocophillips.com >; Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com > Subject: [EXTERNAL]RE: 3S-718 PTD Submission CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Brian, Please provide the prosed direc onal survey in excel or text format. Minimum info needed is MD, Inclina on, and Azimuth. Thanks, Meredith From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com > Sent: Tuesday, April 16, 2024 6:32 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com >; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Lee, David L <David.L.Lee@conocophillips.com >; Brillon, Chris L <Chris.L.Brillon@conocophillips.com >; Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com> Subject: 3S-718 PTD Submission Hello, Please nd attached PTD application for the upcoming 3S-718 well on Doyon 142. Please let me know if you have any questions. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 Some people who received this message don't often get email from brian.t.broussard@conocophillips.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KRU 3S-718 224-034 KUPARUK RIVER COYOTE UNDF OIL WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name: KUPARUK RIV UNIT 3S-718Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgram DEVField & PoolWell bore segAnnular DisposalPTD#:2240340KUPARUK RIVER, COYOTE UNDF OIL - 490120NA1 Permit fee attachedYes ADL380107, ADL025546, and ADL3801062 Lease number appropriateYes3 Unique well name and numberYes KUPARUK RIVER, COYOTE UNDF OIL - 490120 - governed by Statewide Regs4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes SC set at 3942' MD19 Surface casing protects all known USDWsYes 125% excess planned20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes Production liner will be cemented with frac sleeves22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes Anti-collision analysis complete; no major risk failures26 Adequate wellbore separation proposedYes Divereter variance granted per 20 AAC 25.035(h)(2)27 If diverter required, does it meet regulationsYes Max formation pressure is 1876 psig(EMW 8.6 ppg ); Will drill w/ 9.0-1.0 ppg EMW28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP is 1456 psig; BOPs will be tested to 5000 psig initially & 4000 psig subsequently30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No Measures required. Lift gas from CPF3 facility has ~200ppm35 Permit can be issued w/o hydrogen sulfide measuresYes All formations anticipated to be normally pressured36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate4/29/2024ApprVTLDate5/13/2024ApprADDDate4/30/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 5/13/2024