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Home My WebLink About225-109Originated: Delivered to:TRANSMITTAL DATE 10-Jan-26 Alaska Oil & Gas Conservation Commission TRANSMITTAL #10JAN25-AP01 ATTN: Gavin Gluyas 701 W 8th Avenue Anchorage, AK 99501 (907) 273-1700 m (907)273-4760 fax WELL NAME API # SERVICE ORDER #FIELD NAME SERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED COLOR PRINTS e-TRANS DATE/ CD 3T-611 50-103-20928-00-00 225-109 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 26-Dec-25 1 Path .PDF-Qty .LAS-Qty .DLIS-Qty .PPT-Qty .TXT-Qty .CSV -Qty Data from M/LWD Tools Depth 1 1 NA Trulink/DigiScope - Spliced Time - LWD001 1 1 NA Telescope Time - LWD002 1 1 NA TruLink Time - LWD003 1 1 NA DigiScope Per Well 4 1 1 arcVISION/PeriScope/adnVISION - Spliced LWD001 4 2 2 Telescope LWD002 4 2 2 arcVISION LWD003 4 2 2 PeriScope/adnVISION Real Time Per Well 4 1 1 arcVISION/PeriScope/adnVISION - Spliced 1 NA NA NA 9 1 TeleScope/TruLink/DigiScope Recorded Mode LWD003 RIH 7 1 1 NA NA NA SonicScope - Interpreation report included Recorded Mode LWD003 SOOH 7 1 1 1 NA NA SonicScope - Interpreation report included Anchorage, Alaska 99501-3539 Data Description Formation Evaluation Drilling Mechanics NA NA NA Recorded Mode Survey Well Data Transmittal Receipt ________________________________X____________________________________________ Print Name Signature Date Please return via courier or sign/scan and email a copy to Schlumberger. aurana@slb.com SLB Auditor - A Transmittal Receipt signature confirms that a package (box, envelope, etc.) has been received and the contents of the package have been verified to match the media noted above. The specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this point. # SLB-Private 225-109 T41240 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.12 08:40:00 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?KRU 3T-611 Yes No 9. Property Designation (Lease Number): 10. Field: Torok Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 21780 5060 21779 5060 1784 None None Casing Collapse Structural Conductor Surface 2470 Intermediate 4790 Intermediate 7850 Liner 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Manabu Nozaki Manabu Nozaki Contact Email:Manabu.Nozaki@cop.com Contact Phone:907-265-6519 Authorized Title: Staff Completions Engineer Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 971 4-1/2" 1/21/2026 21779 4-1/2" 5060 Halliburton TNT Prod Packer Baker ZXP, No SSSV L-80 10860 Perforation Depth TVD (ft):Perforation Depth MD (ft): 50097-5/8" 20" 10-3/4" 80 7-5/8"6178 2603 7188 6217 MD PRESENT WELL CONDITION SUMMARY 6890 5210 119 2492 4528 119 2642 TVD Burst MPSP (psi): Plugs (MD): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL393883 / ADL025528 225-109 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20928-00-00 ConocoPhillips Alaska Inc. Kuparuk Field Will perfs require a spacing exception due to property boundaries? Current Pools: Size Proposed Pools: 1/7/2026 Length AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): TNT Packer: 6848' MD / 4865' TVD ZXP: 7020' MD / 4942' TVD Subsequent Form Required: Suspension Expiration Date: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: 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 326-005 By Grace Christianson at 2:30 pm, Jan 07, 2026 10-404 SFD 1/13/2026 DSR-1/16/26 CDW 01/08/2026 Fracture Stimulate X VTL 1/14/2026JLC 1/20/2026 01/20/26 SECTION 1 - AFFIDAVIT 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283(a)(1). SECTION 2 PLAT 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer NAK NAK NORTH ALASKA EXPLORATION 501032064500 NUNA 1 SUSP Suspended Yes - Suspended Yes - Suspended NAK NAK NORTH ALASKA EXPLORATION 501032064570 NUNA 1PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A NAK OU OOOGURUK UNIT 501032066000 NDST-02 SUSP Suspended Yes - Suspended Yes - Suspended NAK OU OOOGURUK UNIT 501032066070 NDST-02PB1 PA Plugged and Abandoned KUP COYOTE COYOTE 501032090500 3T-731 PA Plugged and Abandoned KUP COYOTE COYOTE 501032090502 3T-731B ACTIVE Oil KUP COYOTE COYOTE 501032090700 3T-730 ACTIVE Injector Produced Water KUP TOROK TOROK 501032091400 3T-613 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032091700 3T-605 ACTIVE Oil KUP TOROK TOROK 501032091800 3T-617 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032092100 3T-619 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032092300 3T-622 ACTIVE Oil KUP TOROK TOROK 501032092500 3T-614 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032086400 3S-617 ACTIVE Injector Produced Water KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil KUP TOROK TOROK 501032087800 3S-626 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned KUP TOROK TOROK 501032088200 3T-621 ACTIVE Injector Produced Water KUP TOROK TOROK 501032088700 3T-603 ACTIVE Oil KUP TOROK TOROK 501032089000 3T-608 ACTIVE Injector Produced Water KUP TOROK TOROK 501032089600 3T-612 ACTIVE Injector Produced Water KUP TOROK TOROK 501032089900 3T-616 ACTIVE Oil KUP TOROK TOROK 501032089970 3T-616PB1 PROP Proposed KUP TOROK TOROK 501032089971 3T-616PB2 PROP Proposed KUP TOROK TOROK 5010320774000 3S-611 ACTIVE Oil Yes Yes 3T-611 Frac Sundry Well - Wells within 1/2 Mile Buffer of Well Track 28 wells total, 12 wells frac buffer. CDW 01/08/2026 SECTION 3 FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no known underground sources of drinking water within one-half mile radius of the current or proposed wellbore trajectory. Well 3T-611 lies within acreage that was located inside the former Oooguruk Unit before it was purchased by ConocoPhillips Alaska Inc. and included within the 12th expansion of the KRU. Page 17 of EPA class I UIC permit number AK1I009-B for Oooguruk Unit disposal wells DW-1 and DW-2 (obtained with that purchase) states: The requirement to monitor the strata overlying the confining zone for fluid movement is waived since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet No USDW criteria). 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. Upper Completion 1. 3ea SLB (VanOil) 4.5 x 1" Gas Lift Mandrel 2. HES Opsis Single Downhole Gauge 3. HES 7-5/8" x 4-1/2" TNT Production Packer 4. SLB 3.75" DB Nipple 5. Arsenal Glass Disk (to be shared during frac) 6. HES Self-Aligning Muleshoe with Baker Shear Locator Lower Completion 1. Baker ZXP Packer and Hanger 2. 9ea Interra Frac Sleeves 3. 20ea Baker Frac Sleeves 4. 2ea Baker Alpha Sleeves 5. Citadel MOAS Shoe Base Perm 1575' MD / 1556' TVD Top Coyote 5395' MD / 4084' TVD Top Torok Oil Pool (Moraine) 7155' MD / 4996' TVD Production TOL ZXP LTP/HGR 6.5 Production Hole 21780' MD / 5061' TVD Production Liner 4.5" 12.6# P110S H563 21779' MD / 5061' TVD 3T-611 Moraine Injector Well Plan: As Drilled W. Dai / M. Nozaki Last Update: 12/31/2025 20" 94# H40 Insulated Conductor 119 MD/TVD Cemented to Surface Surface Casing 10.75"45.5# L-80 Hyd563 2642 MD / 2492' TVD Cemented to Surface Int TOC 4110' MD / 3404' TVD Intermediate I Casing 7.625"29.7# L80 Hyd563 + 800' 33.7# P110S Hyd563 heavy heel 7188' MD / 5009' TVD Production Tubing 4.5' 12.6# L80 Hyd563MS (All TVDs are TVDRKBs) 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 report on 12/05/2025 shows that the job was pumped with 340 barrels of 10.5 ppg lead cement and 63.8 barrels 15.8 ppg tail cement. This was displaced with 224.5 bbl 9.8 ppg spud mud. The plug bumped and the floats held. The 7-5/8 casing cement report on 12/13/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 73.6 barrels of 14.0 ppg lead cement, followed with 62.7 barrels of 15.3 ppg tail cement. This was displaced with 318 barrels of 10 ppg NAF. The plug bumped, pressure was bled off, and floats held. According to the CBL log (after reaming the production hole section), the TOC is at 4,110 MD. The 4-1/2 liner cement report on 12/28/2025 shows the job was pumped as per design. The cement job was pumped with 483 barrels of 15.3 ppg cement. The cement was displaced with 278 bbls of 9.5 ppg brine and the plugs bumped and held for 5 minutes. Floats held. Lost full returns. The loss volume was estimated to be 200 bbls. The TOC is calculated to be at 12,420 MD. Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. SECTION 7 PRESSURE TEST INFORMATION AND PLANS TO PRESSURE- TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 12/06/2025 the 10-3/4 casing was pressure tested to 3,000 psi for 30 minutes On 12/13/2025 the 7-5/8 casing was pressure tested to 4,000 psi for 30 minutes. On 12/30/2025 the 4-1/2 tubing was pressure tested to 4,200 psi for 30 minutes. On 12/30/2025 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) 7,050 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7-5/8" Annulus pressure test 3,850 4-1/2" Tubing pressure Test 4,200 Electronic PRV 8,050 Highest pump trip 7,550 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 2474 7-5/8 29.7 L-80 6,885 4,789 7-5/8 33.7 P-110S 10,860 7,870 4-1/2 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the Torok Oil Pool, has an average thickness of approximately 300 ft TVD over the course of the lateral section of well 3T-611, from where it intersects the top formation at 7,155 MD (-4,945 TVDSS) to the TD of the well. The Torok Oil Pool is comprised of thinly interbedded sandstone, siltstone, and silty shale layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and very fine grained. The silty shales are composed of clay-rich, moderately to poorly sorted silt and clay. The estimated fracture pressure for the Moraine interval is approximately 12.5-13.5 ppg. The overlying confining interval of the Torok Formation consists of mudstones and siltstones with a thickness of approximately 820 TVD along the 3T-611 trajectory. The top of the Torok confining interval in the well starts at 5,566 MD (-4,125 TVDSS). The estimated fracture gradient of the overlying Torok formation is approximately 0.82 psi/ft. The underlying confining zone below the Base Moraine consists of lower Torok, HRZ, and Kalubik shales totaling approximately 500 TVD. The estimated fracture gradient for this section ranges from 15-18 ppg, with the gradient increasing down section. The Base Moraine is estimated from seismic to be at -5,175 TVDSS along the length of the well. The estimated formation pressure within the Torok Oil Pool is 2,285psi at a depth of 5,200 TVDSS. SECTION 10 LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing & Cement assessments for all wells that transect the confining zone: Nuna 1: The 7-5/8 casing was cemented in place on 2/16/2012. The cement report indicates that the job was pumped with 40 bbls 15.8ppg Class G cement. The plugs bumped and partial returns were observed during the job. Suspension operations began on 1/18/2023 where a cement retainer was set at 9,062 CTMD and 65bbls of Class G cement was pumped through the retainer. Another retainer was placed at 7,965 MD and 48bbls of 15.8ppg cement was pumped with another 12 bbls laid on top of the retainer. The TOC was tagged at 7,003 MD and a MIT-T performed to 1700 psi, witnessed by AOGCC on 3/1/2023. A tubing cut was completed at 6,960 MD and the 4.5 tubing was then pulled. A CIBP was set at 6,910 MD and tested to 1,200 psi. Cement was laid on top of the retainer and tagged at 6,621 MD two times with 12klbs. Source: 211-155 Laserfiche WebLink Nuna 1 PH: Three abandonment plugs were placed on 2/10/2012. The three plugs were set as balanced plugs at the following depths: 7,347-6,847 MD with 52 bbls of 15.8ppg Class G cement, 6,847-6,285 MD with 60bbls of 15.8ppg Class G cement, and 6,285-5,800 MD with 49bbls of 17.0ppg Class G cement. The top plug was tagged with 25klbs at 5,790 MD/4,192 TVD/4,149 TVDSS prior to kick off for the main wellbore. Source: 211-155 Laserfiche WebLink NDST-02: The 7-5/8 casing was cemented on 2/8/2013. The cement report indicates that the job was pumped with 60 bbls of 15.8ppg Premium Cement with 3% Halad (R)-344 low fluid loss control. Full circulation was seen throughout the entire job. Abandonment operations include: the tubing was cut at 8,316 MD and was removed from the well. On 10/8/2024, coil tubing set a cement retainer at 10,441 MD and pumped 110bbls of 15.8ppg cement into the 4.5 liner. Coil unstung from the retainer and laid an additional 68bbls of 15.8ppg cement on top of the retainer. The cement plug was not tagged due to issues with deviation/thick fluid, but a pressure test was completed to 1700 psi and witness by AOGCC on 10/12/2024 (pg. 2-6 at link). Another attempt to tag the TOC was completed on 2/8/2025 with coil tubing, tagging at 8,812 MD with 4klbs and witnessed by AOGCC. Source: 212-163 Laserfiche WebLink 3T-613: The intermediate casing cement job was pumped with 211 bbls of 14.0ppg lead cement and 59 bbls of 15.3ppg tail cement. Plugs bumped and floats held. Source: 225-036 Laserfiche WebLink 3T-617: The intermediate cement job was pumped with 99 barrels of 14.0 ppg lead cement, followed with 60 barrels of 15.3 ppg tail cement. Plugs bumped and floats held. Source: 225-053 Laserfiche WebLink 3T-619: The intermediate cement job was pumped with 191 barrels of 14.0 ppg lead cement, followed with 61 barrels of 15.3 ppg tail cement. This was displaced with 520 barrels of 10.0 ppg NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 7,652 MD (3,974 TVDRKB). The intermediate column of good cement of 437 MD in combination with the weaker column of cement above in excess of 2600 MD meets regulation (AOGCCs approval on 09/03/2025). Source: 225-063 Laserfiche WebLink 3S-625: The 7-5/8 casing cement report on 9/29/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 297 barrels of 15.3ppg cement with BMII. The cement was displaced with 574 barrels of 9.6ppg LSND drilling mud. The plug did not bump and 50% of shoe track volume was pumped. Losses totaled 21 barrels during the job. Cement floats held. A cement bond log indicates competent cement with a cement top @ 7,850 MD (3,970 TVDRKB / 3,908 TVDSS). Source: 222-079 Laserfiche WebLink 3S-615: The 7-5/8 casing cement report on 11/13/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 200 barrels of 15.3 ppg lead cement with BMII, followed with 33 barrels of 15.3 ppg tail cement, displaced with 524 barrels of 9.6 ppg mud. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,620 MD / 3,340 TVDRKB / 3,279 TVDSS. Source: 222-101 Laserfiche WebLink 3T-614: The intermediate cement job was pumped with 169 barrels of 14.0 ppg lead cement, followed with 59 barrels of 15.3 ppg tail cement. Plugs bumped and floats held. Source: 225-090 Laserfiche WebLink 3S-612: The 7-5/8 casing cement report on 11/4/2018 shows that the job was pumped as designed, indicating competent cementing operations. 12.5 ppg MPII was pumped before dropping bottom plug, this was then chased with 303bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.5 ppg LSND mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,270MD/3,832 TVDRKB/3,768 TVDSS Source: 218-111 Laserfiche WebLink 3S-626: The intermediate casing cement job was pumped via 2 stages. The first stage was pumped with 188bbls of 15.3ppg cement.Plugs bumped and floats held. The second stage consisted of 42bbls of 15.3ppg cement. The plug bumped and floats held. A RWO was performed where the 7-5/8" x 10-3/4" was cemented to surface. The 7-5/8" pack off was installed and tested to 3,840 psi. Source: 224-007 Laserfiche WebLink 3S-611: The intermediate casing cement job was pumped with 270 bbls of 15.3ppg cement. Full returns were observed during the job. Plugs bumped and floats held. Source: 218-103 Laserfiche WebLink 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 four faults transect the Torok Oil Pool reservoir within one half mile radius of the 3T-611 wellbore trajectory shown in Plat 1. Two faults intersect the 3T-611 well trajectory at 20,520 MD (Fault 1) and 20,868 MD (Fault 2) respectively. Both faults are sub-seismic in nature, picked only based on log signature and the occurrence of losses while drilling. They are both sand on sand with orientation and throw uncertain but likely less than 10 of offset in the NE-SW orientation, like other faults in the Moraine interval. Fault 1 is interpreted to be the tip out of a NE-SW, down to the south fault seen in 3T-617 (19,734 MD) as it is on strike with that fault. There is a second fault interpreted in 3T-617 (20,382 MD) that is within the half mile radius, but it is not interpreted to extend and intersect 3T-611. All faults in the ½ mi area of the 3T-611 are difficult to trace on the seismic data, due to a) lack of fine-scale resolution at the Torok Oil Pool level and b) lack of reflectivity in the overlying Torok shales, the result of the monotonous shaly lithology. Faults 1 and 2 are interpreted to be confined to the Moraine interval as they are not explicitly mapped on seismic and are interpreted only on well log correlation. The fault located at 20,382MD in 3T-617 is not interpretable on seismic and therefore also not expected to extend outside the Moraine interval. Since all faults around 3T-611 are interpreted to be contained in the Moraine interval and dont appear to penetrate the overburden into the overlying hydrocarbon bearing Coyote Oil Pool, they are not interpreted to interfere with containment. Even if the faults did intersect the overburden, due to the shaly nature of the overburden and horizontal stress acting on the fault (interpreted to be 15.8 ppg at the faults interpreted mapped orientation) the faults will not interfere with containment. If there is any indication that a fracture has intersected any mapped fault (or any other faults unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. SECTION 12 PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3T-611 was completed in December 2025 as a horizontal injector in the Torok formation. The well is completed with a 4.5 tubing upper completion and a cemented 4.5 liner with 9 dart activated sliding sleeve and 20 ball drop activated sliding sleeve lower completion. The first stage frac will be pumped through a toe initiator valve in the toe of the lateral. After the 1st stage, a ball/dart will be dropped to shift open the 2nd stage sleeve and isolate the first stage. A frac will then be pumped through the 2nd stage. Balls/darts will continue to be dropped to provide isolation from the previous stage and open each subsequent stage. 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 at 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 2,183 MD / 2,119 TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 40 clean insulated Frac tanks (450 bbls usable volume per tank), with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with either seawater or treated produced water. 6. MIRU HES Frac Equipment. 7. PT Surface lines to ~9,500 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 Frac Stages 1 through 30 (skipping Stages 2 thru 4 due to proximity of faults) by following attached pump schedule at ~37 bpm with a maximum expected treating pressure of ~7,050 psi. 11. The well is ready for Post Frac well prep/production tree installation, coiled tubing cleanout and flowback. SECTION 13 POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) Flowback will be initiated through a de-sander unit until the fluids clean up at which time it will be turned over to production for initial clean up production. Frac Design Attachments: Superseded SFD Stage Job Size (lb) Top MD (ft) Top TVD (ft) Propped Half- Length (ft) Fracture Height (ft) Avg Fracture Width (in) 1 203,000 21,647 4,926 240 275 0.192 2 3 4 5 203,000 19,770 4,923 240 275 0.202 6 203,000 19,311 4,926 250 275 0.204 7 203,000 18,812 4,920 260 275 0.207 8 203,000 18,312 4,929 200 265 0.179 9 203,000 17,815 4,922 190 275 0.178 10 203,000 17,314 4,925 190 265 0.18 11 203,000 16,815 4,923 250 275 0.202 12 203,000 16,314 4,923 260 275 0.204 13 203,000 15,814 4,929 210 270 0.18 14 203,000 15,314 4,937 170 260 0.212 15 203,000 14,813 4,935 240 265 0.181 16 203,000 14,312 4,936 230 265 0.188 17 203,000 13,815 4,944 240 260 0.203 18 203,000 13,314 4,950 180 250 0.195 19 203,000 12,814 4,945 180 250 0.189 20 203,000 12,314 4,946 160 250 0.196 21 203,000 11,814 4,953 240 245 0.181 22 203,000 11,313 4,947 270 255 0.210 23 203,000 10,814 4,949 270 255 0.210 24 203,000 10,313 4,947 300 250 0.207 25 203,000 9,813 4,940 160 250 0.191 26 203,000 9,314 4,943 240 255 0.197 27 203,000 8,857 4,952 280 250 0.207 28 203,000 8,399 4,957 320 245 0.214 29 203,000 7,941 4,960 320 245 0.215 30 203,000 7,482 4,933 300 265 0.206 Disclaimer Notice: KRU 3T-611 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 Skipped CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-611SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control 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-In 1:05:11 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:05:11 1-3 Shut-In Shut-In 1:00:25 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 1:00:25 1.00 1.00 27.00 2.00 2.00 0.151-5 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:54:25 1.00 1.00 27.00 2.00 2.00 0.151-6 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-7 27# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-8 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-13 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-14 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-15 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.151-16 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.152-1 Shut-In SKIP DO NOT OPEN3-1 Shut-In SKIP DO NOT OPEN4-1 Shut-In SKIP DO NOT OPEN5-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:46 1.00 1.00 27.00 2.00 2.00 0.155-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:52:25 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-3 27# Hybor G-i Pad 37 8,630 205 205 0:05:33 0:47:00 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.155-12 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.156-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.156-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.156-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.157-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 1:00:03 1.00 1.00 27.00 2.00 2.00 0.157-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:58:42 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:53:17 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:48:23 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:40:34 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:39:13 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:37:28 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:34:33 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:28:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:21:02 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:12:50 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.157-12 27# Linear Flush 37 12,025 286 286 0:07:44 0:07:44 1.00 1.00 27.00 2.00 2.00 0.157-13 Shut-In Shut-InInterval 1Moraine@ 21647 - 21651.34 ft 137.7 °F"Alpha SleeveInterval 2Interval 3Interval 4Interval 5Moraine@ 19770 - 19774.34 ft 138.1 °F"Frac Sleeve 4Interval 6Moraine@ 19311 - 19315.34 ft 138.3 °F"Frac Sleeve 5Interval 7Moraine@ 18812 - 18816.34 ft 138.2 °F"Frac Sleeve 5Liquid Additives Dry AdditivesConoco Phillips - 3T-611 Planned Design 1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-611SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control 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 Additives Dry Additives8-1 Shut-In Shut-In 1:38:27 8-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:38:27 8-3 Shut-In Shut-In 1:33:41 8-4 27# Linear Spacer and Ball Drop 5 1,260 30 30 0:06:00 1:33:41 1.00 1.00 27.00 2.00 2.00 0.158-5 27# Linear Displace Ball to Seat 15 11,705 279 279 0:18:35 1:27:41 1.00 1.00 27.00 2.00 2.00 0.158-6 27# Linear DFIT 10 1,680 40 40 0:04:00 1:09:06 1.00 1.00 27.00 2.00 2.00 0.158-7 Shut-In Shut-In 1:05:06 8-8 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 1:05:06 1.00 1.00 27.00 2.00 2.00 0.158-9 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-10 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-11 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-13 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-14 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-15 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-16 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-17 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-18 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.158-19 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.159-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.159-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.0000 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.159-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1510-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1510-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1510-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1511-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1511-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1511-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1512-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:59:01 1.00 1.00 27.00 2.00 2.00 0.1512-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:57:40 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:52:16 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:47:21 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:39:33 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:38:12 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:36:26 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:33:31 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:27:26 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:20:00 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:11:48 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1512-12 27# Linear Flush 37 10,428 248 248 0:06:43 0:06:43 1.00 1.00 27.00 2.00 2.00 0.1512-13 Shut-In Shut-InInterval 9Moraine@ 17815 - 17819.34 ft 137.8 °F"Frac Sleeve 5Interval 10Moraine@ 17314 - 17318.34 ft 138 °F"Frac Sleeve 5Interval 11Moraine@ 16815 - 16819.34 ft 138.2 °F"Frac Sleeve 5Interval 8Moraine@ 18312 - 18316.34 ft 138 °F"Frac Sleeve 5Interval 12Moraine@ 16314 - 16318.34 ft 138.2 °F"Frac Sleeve 5Conoco Phillips - 3T-611 Planned Design 2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-611SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control 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 Additives Dry Additives13-1 Shut-In Shut-In 1:03:53 13-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:03:53 13-3 Shut-In Shut-In 0:59:07 13-4 27# Linear Spacer and Ball Drop 5 1,260 30 30 0:06:00 0:59:07 1.00 1.00 27.00 2.00 2.00 0.1513-5 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1513-6 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-7 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-8 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-13 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-14 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-15 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1513-16 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1514-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1514-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1514-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1515-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1515-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1515-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1516-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1516-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1516-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1517-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:57:59 1.00 1.00 27.00 2.00 2.00 0.1517-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:56:38 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:51:14 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:46:19 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:38:31 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:37:10 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:35:25 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:32:29 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.0000 37 9,400 224 274 47,000 0:07:26 0:26:24 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:18:58 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:10:47 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1517-12 27# Linear Flush 37 8,831 210 210 0:05:41 0:05:41 1.00 1.00 27.00 2.00 2.00 0.1517-13 Shut-In Shut-InInterval 13Moraine@ 15814 - 15818.34 ft 138.4 °F"Frac Sleeve 5Interval 14Moraine@ 15314 - 15318.34 ft 138.5 °F"Frac Sleeve 5Interval 15Moraine@ 14813 - 14817.34 ft 138.5 °F"Frac Sleeve 5Interval 16Moraine@ 14312 - 14316.34 ft 138.5 °F"Frac Sleeve 5Interval 17Moraine@ 13815 - 13819.34 ft 138.6 °F"Frac Sleeve 5Conoco Phillips - 3T-611 Planned Design 3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-611SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control 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 Additives Dry Additives18-1 Shut-In Shut-In 1:23:23 18-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:23:23 18-3 Shut-In Shut-In 1:18:38 18-5 27# Linear Spacer and Ball Drop 15 1,260 30 30 0:02:00 1:12:38 1.00 1.00 27.00 2.00 2.00 0.1518-6 27# Linear Displace Ball to Seat 15 8,510 203 203 0:13:31 1:10:38 1.00 1.00 27.00 2.00 2.00 0.1518-7 27# Linear DFIT 10 1,680 40 40 0:04:00 0:57:07 1.00 1.00 27.00 2.00 2.00 0.1518-8 Shut-In Shut-In 0:53:07 18-9 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1518-10 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-11 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-12 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-13 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-14 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-15 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-16 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-17 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-18 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-19 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1518-20 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1519-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1519-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1519-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1520-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1520-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1520-12 27# Linear Spacer and Ball Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1521-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1521-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1521-12 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1522-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:56:58 1.00 1.00 27.00 2.00 2.00 0.1522-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:55:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:50:12 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:45:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:37:29 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:36:08 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:34:23 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:31:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:25:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:17:57 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:09:45 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1522-12 27# Linear Flush 37 7,231 172 172 0:04:39 0:04:39 1.00 1.00 27.00 2.00 2.00 0.1522-13 Shut-In Shut-InInterval 18Moraine@ 13314 - 13318.34 ft 138.7 °F"Frac Sleeve 5Interval 19Moraine@ 12814 - 12818.34 ft 138.7 °F"Frac Sleeve 5Interval 20Moraine@ 12314 - 12318.34 ft 138.8 °F"Frac Sleeve 5Interval 21Moraine@ 11814 - 11818.34 ft 139 °F"Frac Sleeve 5Interval 22Moraine@ 11313 - 11317.34 ft 139.2 °F"Frac Sleeve 5Conoco Phillips - 3T-611 Planned Design 4 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-611SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control 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 Additives Dry Additives23-1 Shut-In Shut-In 1:15:00 23-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:15:00 23-3 Shut-In Shut-In 1:10:14 23-4 27# Linear Spacer and Dart Drop 15 1,350 32 32 0:02:09 1:10:14 1.00 1.00 27.00 2.00 2.00 0.1523-5 27# Linear Displace Dart to Seat 15 6,912 165 165 0:10:58 1:08:05 1.00 1.00 27.00 2.00 2.00 0.1523-6 27# Linear DFIT 10 1,680 40 40 0:04:00 0:57:07 1.00 1.00 27.00 2.00 2.00 0.1523-7 Shut-In Shut-In 0:53:07 23-8 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1523-9 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-10 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-11 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-13 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-14 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-15 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-16 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-17 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-18 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1523-19 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1524-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1524-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1524-12 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1525-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1525-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1525-12 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1526-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:07 1.00 1.00 27.00 2.00 2.00 0.1526-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:51:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:46:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1526-12 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1527-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:55:57 1.00 1.00 27.00 2.00 2.00 0.1527-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:54:36 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-3 27# Hybor G-i Pad 37 7,630 182 182 0:04:55 0:49:12 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:44:17 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:36:28 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:35:08 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:33:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:30:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:24:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:16:56 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:08:44 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1527-12 27# Linear Flush 37 5,661 135 135 0:03:39 0:03:39 1.00 1.00 27.00 2.00 2.00 0.1527-13 Shut-In Shut-InInterval 23Moraine@ 10814 - 10818.34 ft 139.1 °F"Frac Sleeve 5Interval 24Moraine@ 10313 - 10317.34 ft 138.9 °F"Frac Sleeve 5Interval 25Moraine@ 9813 - 9817.34 ft 138.7 °F"Frac Sleeve 5Interval 26Moraine@ 9314 - 9318.34 ft 138.6 °F"Frac Sleeve 5Interval 27Moraine@ 8857 - 8861.34 ft 138.9 °F"Frac Sleeve 5Conoco Phillips - 3T-611 Planned Design 5 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-611SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control 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 Additives Dry Additives28-1 Shut-In Shut-In 0:57:32 28-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 0:57:32 28-3 Shut-In Shut-In 0:52:46 28-4 27# Linear Spacer and Dart Drop 10 1,260 30 30 0:03:00 0:52:46 1.00 1.00 27.00 2.00 2.00 0.1528-5 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:49:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-6 27# Hybor G-i Pad 37 6,760 161 161 0:04:21 0:44:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-7 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:40:01 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:32:12 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:30:51 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:29:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,000 167 196 28,000 0:05:20 0:26:10 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,160 170 208 35,800 0:05:39 0:20:51 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-13 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 6,400 152 193 38,400 0:05:15 0:15:11 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-14 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:09:57 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-15 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 8.00 37 4,600 110 149 36,800 0:04:02 0:04:51 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1528-16 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1529-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:51:07 1.00 1.00 27.00 2.00 2.00 0.1529-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:49:46 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-3 27# Hybor G-i Pad 37 6,760 161 161 0:04:21 0:44:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:40:01 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:32:12 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:30:51 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:29:06 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,000 167 196 28,000 0:05:20 0:26:10 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,160 170 208 35,800 0:05:39 0:20:51 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 6,400 152 193 38,400 0:05:15 0:15:11 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:09:57 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 8.00 37 4,600 110 149 36,800 0:04:02 0:04:51 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1529-13 27# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 1.00 27.00 2.00 2.00 0.1530-1 27# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:53:23 1.00 1.00 27.00 2.00 2.00 0.1530-2 27# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:52:02 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-3 27# Hybor G-i Pad 37 6,760 161 161 0:04:21 0:46:38 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-4 27# Hybor G-i Conditioning Pad 16/20 Ceramic 0.25 37 12,000 286 289 3,000 0:07:49 0:42:17 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-5 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:34:28 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-6 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:33:07 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-7 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:31:22 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-8 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,000 167 196 28,000 0:05:20 0:28:26 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-9 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,160 170 208 35,800 0:05:39 0:23:07 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-10 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 6,400 152 193 38,400 0:05:15 0:17:27 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-11 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:12:13 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-12 27# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 8.00 37 4,600 110 149 36,800 0:04:02 0:07:07 1.00 0.50 1.00 0.80 1.00 27.00 2.00 2.00 0.1530-13 27# Linear Flush 37 4,782 114 114 0:03:05 0:03:05 1.00 1.00 27.00 2.00 2.00 0.1530-14 Shut-In Shut-In2,074,846 49,401 55,221 5,481,000Design Total (gal)Design Total (lbs)CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6- 5,481,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)177,396 Initial Design Material Volume 1,881.8 940.9 2,059.2 1,505.4 2,059.2 55,598.3 4,118.4 4,118.4 308.9-6,000 - Whole Units to be ordered1,881,800 - CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm- Max Additive Rate 1.6 0.8 1.6 1.2 1.6 46.6 3.1 3.1 0.2- Min Additive Rate2:22:12 Interval 28Moraine@ 8399 - 8403.34 ft 139.2 °F"Frac Sleeve 5Interval 29Moraine@ 7941 - 7945.34 ft 139.2 °F"Frac Sleeve 5Interval 30Moraine@ 7482 - 7486.34 ft 138.3 °F"Frac Sleeve 5Proppant Type16/20 Ceramic100M---Fluid Type-27# LinearSeawaterFreeze Protect27# Hybor G-i---Conoco Phillips - 3T-611 Planned Design 6 Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-12-30 Alaska HARRISON BAY 50-103-20928-00-00 CONOCOPHILLIPS 3T 611 -150.26582921 70.42067249 NAD83 none Oil 5150 1961585.7 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone SEAWATER Operator Base Fluid Density = 8.34 SEAWATER (SG 8.52) Operator Base Fluid Density = 8.52 BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator CL-28M CROSSLINKER Halliburton Crosslinker CLA-WEB(TM) Halliburton Clay Stabilizer Legend LD-6450 MultiChem Completion/Stimulatio n LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker OPTIFLO-III DELAYED RELEASE BREAKER Halliburton Breaker ResMetrics Oil Phase Tracer ResMetrics Tracer ResMetrics Water Phase Tracer ResMetrics Tracer SP BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant SAND, COMMON BROWN 100 MESH Halliburton Proppant CarboLite 16/20 Carbo Ceramics Proppant Flow Insurance Brass Patina Energy Tracer Patina Energy Flow Insurance Copper Patina Energy Tracer Ingredients Water 7732-18-5 95.00%71.97043%16712702 Ceramic Materials and Wares, Chemicals 66402-68-4 100.00%23.60300%5481000 Sodium chloride 7647-14-5 5.00%3.78792%879616 Guar gum 9000-30-0 100.00%0.23815%55303 Water 7732-18-5 100.00%0.18937%43976 Calcium chloride, dihyrate 10035-04-8 60.00%0.05662%13149 Borate salts Proprietary 60.00%0.05150%11959 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%0.04117%9561 Ethanol 64-17-5 60.00%0.04022%9339 Ammonium persulfate 7727-54-0 100.00%0.03529%8194 Sodium hydroxide 1310-73-2 30.00%0.02059%4782 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.02011%4670 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.02011%4670 Ethylene glycol 107-21-1 70.00%0.01306%3032 Oxylated phenolic resin Proprietary 30.00%0.01059%2459 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Crystalline silica, quartz 14808-60-7 100.00%0.00715%1661 Oxyalkylated phenolic resin Proprietary 10.00%0.00670%1557 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Copolymer of acrylamide and sodium acrylate 25085-02-3 5.00%0.00472%1096 Potassium chloride 7447-40-7 5.00%0.00429%997 Inorganic mineral 1317-65-3 5.00%0.00429%997 Naphthalene 91-20-3 5.00%0.00335%779 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00335%779 Corundum 1302-74-5 60.00%0.00258%600 Mullite 1302-93-8 40.00%0.00172%400 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00132%307 Calcium magnesium carbonate 16389-88-1 1.00%0.00086%200 Inorganic mineral Proprietary 1.00%0.00086%200 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Polymer Proprietary 1.00%0.00086%200 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Gluteraldehyde 111-30-8 1.00%0.00086%200 Glycol Ether Proprietary 80.00%0.00080%187 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Sodium chloride 7647-14-5 1.00%0.00069%160 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00067%156 Proprietary1 Proprietary 20.00%0.00030%71 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Flow Insurance Brass Proprietary 100.00%0.00019%45 Patina Energy Julie Harrish julie@patinae nergy.com 8327140836 Proprietary Non-Hazardous Proprietary 100.00%0.00019%45 Patina Energy Julie Harrish julie@patinae nergy.com 8327140836 C.I. pigment Orange 5 3468-63-1 1.00%0.00018%41 Polymer Proprietary 0.10%0.00009%22 MultiChem Ana Djuric Ana.Djuric@H alliburton.com 281-871- 5747 Methanesulfonic acid, 1-hydroxy-, sodium salt 870-72-4 0.10%0.00009%20 Sodium bisulfate 7681-38-1 0.10%0.00009%20 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00004%10 Ammonium acetate 631-61-8 100.00%0.00004%10 Water 7732-18-5 100.00%0.00004%9 Ammonium salt Proprietary 60.00%0.00002%6 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Acetic acid 64-19-7 30.00%0.00001%3 EDTA/Copper chelate Proprietary 30.00%0.00001%3 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Magnesium nitrate 10377-60-3 0.01%0.00001%2 2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00001%2 5-Chloro-2-methyl-3(2H)- Isothaiazolone 26172-55-4 0.01%0.00001%2 Magensium chloride 7786-30-3 0.01%0.00001%2 Sodium persulfate 7775-27-1 100.00%0.00000%1 Walnut hulls NA 100.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Sodium chloride 7647-14-5 5.00%0.00000%1 Ammonium chloride 12125-02-9 5.00%0.00000%1 Polyamine Proprietary 30.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Ammonia 7664-41-7 1.00%0.00000%1 Hemicellulase 9025-56-3 5.00%0.00000%1 C.I. Pigment Red 5 6410-41-9 1.00%0.00000%1 Cured acrylic resin Proprietary 1.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Amine salts Proprietary 0.10%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Quaternary amine Proprietary 0.10%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 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 1.5 All component information listed was obtained from the suppliers 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 Administrations (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS 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: CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Nozaki, Manabu To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); Starns, Ted C (OGC); Nozaki, Manabu Subject:RE: [EXTERNAL]KRU 3T-611 (PTD 225-109, Sundry 326-005) - Questions Date:Tuesday, January 13, 2026 4:04:15 PM Attachments:image001.png image002.png image003.png image004.png Model Results 3T-611.pdf Hi Steve, Sorry about that. I checked with Halliburton. The depths in the frac modeling result table are wrong (they used the correct depths in the fracturing software model). They updated the table (see attached). Should I revise the sundry application and send it to you? Regards, Manabu From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, January 13, 2026 1:44 PM To: Nozaki, Manabu <Manabu.Nozaki@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov> Subject: [EXTERNAL]KRU 3T-611 (PTD 225-109, Sundry 326-005) - 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. Hello Manabu, I'm reviewing CPAI's Sundry Application to frac stimulate KRU 3T-611. In the Frac Design table, the "Top MD" depths presented for the various Stages don't agree with those presented in Halliburton's Treatment Interval details tables. I also notice that in the Frac Design table that the Top MDs presented for Stages 27 through 30 are the same values, which also don't agree with the values for those Stages presented in Halliburton's table. Can you please clarify this? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793- 1224 or steve.davies@alaska.gov 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-611 (PTD No. 225-109; Sundry No. 326-005) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 January 13, 2026 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 1/12/2026 (a)(2) Plat Provided with application. SFD 1/12/2026 (a)(2)(A) Well location Provided with application. Well lies in Section 1 and 2 of T12N, R07E, UM and Sections 34, 27, and 22 of T13N, R07E, UM. SFD 1/12/2026 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNRs Alaska Mapper application (accessed online 1Jan. 12, 2026), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of KRU 3T-611. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of KRU 3T-611. SFD 1/12/2026 (a)(2)(C) Identify all well types within ½ mile Provided with application. The operator has identified 28 wells within ½ mile radius. SFD 1/12/2026 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None: Well 3T-611 lies within acreage that was located inside the former Oooguruk Unit before it was purchased by CPAI and included within the 12th Expansion of the KRU. According to page 17 of EPA's UIC Class 1 Permit Number AK11009-B for Oooguruk Unit disposal wells DW-1 and DW-2: The requirement to monitor the strata overlying the confining zone for fluid movement is waived since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet No USDW criteria). Additional supporting evidence that there are no potential underground sources of drinking water from other resources: A prominent, water-bearing sand interval between 2,000 and 2,032 MD (-1,905 to -1,934 TVDSS) in 3T-611 correlates to the zone between 1,938' and 1,967' MD (-1,901' to -1,930' TVDSS) in well Colville Delta 3 (PTD 185-SFD 1/12/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-611 (PTD No. 225-109; Sundry No. 326-005) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 January 13, 2026 211, located about 9,900 to the northwest) and between 1,996 and 2,026 MD (-1,914 to -1,943 TVDSS) in Moraine 1 (PTD 214-198, located about 6,600 to the south). These two zones both yielded estimated TDS values greater than 11,000 mg/l. If the shallowest water-bearing sands in Colville Delta 3 and Moraine 1 contain TDS concentrations greater than that of freshwater, it is highly likely that all water-bearing zones lying below also contain higher TDS concentrations. (a)(4) Baseline water sampling plan Not applicable. SFD 1/12/2026 (a)(5) Casing and cementing information Provided with application. As drilled schematic attached, as built not generated to date. CDW 01/08/2026 (a)(6) Casing and cementing operation assessment 10-3/4 surface casing cemented to surface with 340 bbl lead cement and 63.8 bbl tail pumped. 7-5/8 casing cemented with 73.6 bbl lead, 62.7 bbl tail cement. CBL TOC 4110 ft. Log shows adequate bonding in area of the liner lap and sleeve/frac interval is well below shoe No issues with cement for the upcoming stimulation. 4.5 liner top and packer 6848 ft, ZXP 7020 ft. Liner cemented with full losses estimated total losses of 200 bl of 483 bbl cement pumped. TOC calculated as 12420 ft. Uppermost frac sleeve 11431 ft MD. CDW 01/08/2026 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 1/12/2026 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates each hydrocarbon zone. Top Coyote is 5,395 MD (-4,033 TVDSS). Top Moraine is 7,155 MD (-4,945 TVDSS). 7-5/8 intermediate casing is set at 7,118 MD SFD 1/12/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-611 (PTD No. 225-109; Sundry No. 326-005) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 January 13, 2026 (-4,958 TVDSS) and cemented to 4,110 MD (-3,353 TVDSS) as interpreted from a CBL by Schlumberger and confirmed by AOGCC). (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3850 psi MITIA completed, 4200 psi MITT completed. CDW 01/08/2026 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi fractree max. frac. Pressure 7050 psi. Pump knock out 7550 and ePRV 8050 psi., tree test 10000 psi, lines test 9500 psi. CDW 01/08/2026 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: Mudstones and siltstones of the Torok Formation (top at 5,566 MD (-4,125 TVDSS) having thickness of approximately 820 TVD along the well trajectory. Fracture gradient expected to be about 0.82 psi/ft (15.8 ppg EMW). Fracturing Zone: 300 TVT of Torok Oil Pool interbedded very fine-grained sandstone, siltstone and silty shale between 7,155 MD (-4,945 TVDSS) and the total depth of the well 21,780 MD (-5,009 TVDSS). Fracture gradient expected to be about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). Lower confining zone: Lower Torok, HRZ shale, and Kalubik shale that have an aggregate TVT of about 500. From seismic, the base of the Moraine is estimated to be -5,175 TVDSS. Fracture gradient expected to range from about 0.78 to 0.94 psi/ft (15 to 18 ppg EMW). SFD 1/12/2026 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. There are 17 wells (including plug backs) within or just beyond ½ mile of 3T-611 that penetrate the confining intervals. SFD 1/13/2026 CDW 01/08/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-611 (PTD No. 225-109; Sundry No. 326-005) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 January 13, 2026 AOGCC evaluated all wells that may transect the confining zones within the 3T-611 Area of Review and found it highly unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Four faults. It is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. The operator has identified four faults or fracture zones through seismic or well data within a ½-mile radius of KRU 3T-611. None of these faults are expected to interfere with containment of injected fluids due to their being a) confined to the Moraine interval and / or b) sufficiently sealed by in-situ horizontal stress and the overlying confining zones. See application for details. SFD 1/13/2026 (a)(12) Proposed program for fracturing operation Provided with application. CDW 01/08/2026 (a)(12)(A) Estimated volume Provided with application. 27 stages. 55K bbl total dirty vol. 5.48Million lb total proppant. CDW 01/08/2026 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 01/08/2026 (a)(12)(C) Chemical name and CAS number of each Provided with application. Patina, Resmetrics, and Halliburton disclosure provided. CDW 01/08/2026 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 01/08/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-611 (PTD No. 225-109; Sundry No. 326-005) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 January 13, 2026 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7050 psi. Max. 7318 psi allowable treating pressure (Based on 4200 psi MITT and 3500 psi backpressure). Max pressure is 7550 psi to 8050 psi to Pump shutdown. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 3550 psi. CDW 01/08/2026 (a)(12)(F) Fractures height, length, MD and TVD to top, description of fracturing model Provided with application. The modeled half-lengths of the induced fractures range from 160' to 320' according to the Operator's Computer simulation. The modeled heights of the induced fractures range from 245' to 275'. None of the induced fractures are expected to penetrate through the thick confining intervals above or below. SFD 1/13/2026 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. CPF3 or Drill Site 3Ts facilities identified in previous 3T frac sundries. CDW 01/08/2026 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3500 psi back pressure, tested to 3850 psi, popoff set as 3600 psi CDW 01/08/2026 (c) Fracturing string (c)(1) Packer >100 below TOC of production or intermediate casing 4.5 liner top and packer 6848 ft, ZXP 7020 ft. Liner cemented with full losses estimated total losses of 200 bl of 483 bbl cement pumped. TOC calculated as 12420 ft. Uppermost frac sleeve 11431 ft MD. 7-5/8 casing shoe at 7188 ft cemented with 73.6 bbl lead, 62.7 bbl tail cement. CBL TOC 4110 ft. Log shows adequate bonding in area of the liner lap and sleeve/frac interval is well below shoe No issues with cement for the upcoming stimulation. CDW 01/08/2026 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4200 psi. Max pressure differential is estimated as 3550 psi (7050 with 3500 psi backpressure) so test of 4200 psi satisfies > 110% CDW 01/08/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-611 (PTD No. 225-109; Sundry No. 326-005) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 January 13, 2026 (d) Pressure reliefvalveLine pressure <= test pressure, remotely controlled shut-in device 9500 psi line pressure test, pump knock out 7550 psi with max. global kickout 8050 psi. IA PRV set as 3600 psi. CDW 01/08/2026 (e) ConfinementFrac fluids confined to approved formations Provided with application. CDW 01/08/2026 (f) Surface casingpressuresMonitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 01/08/2026 (g) Annuluspressuremonitoring &notification500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 01/08/2026 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report(i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac watersampling planNot required (see Section (a)(3), above). SFD 1/13/2026 (k) ConfidentialinformationClearly marked and specific facts supporting nondisclosure Non-confidential well. SFD 1/13/2026 (l) VariancesrequestedModifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 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, Torok Oil Pool, KRU 3T-611 Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-109 Surface Location: 1910' FSL, 546' FWL, SENE S1 T12N R7E Bottomhole Location: 4540' FSL, 1072' FWL, SENW S22 T13N R7E Dear Mr. Brillon: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 3rd day of November 2025. 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: 22549.3 TVD: 5061 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 12/1/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 740' to ADL355036 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-467756 y- 6003636 Zone- 4 12 to Same Pool: 930' to 3T-616 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 94 H-40 Welded 81 39 39 120 120 13.5" 10.75" 45.5 L80 Hyd563 2558 39 39 2597 0 9.875" 7.625" 29.7 L80 Hyd563 5032 39 39 5071 4842 9.875" 7.625" 33.7 P110-S Hyd563 2100 5071 4841.8 7171 5004 6.5" 4.5" 12.6 P110-S Hyd563 15528.3 7021 5001.35 22549.3 5061 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: Weifeng Dai Chris Brillon Contact Email:Weifeng.Dai@cop.com Wells Engineering Manager Contact Phone:907-265-6936 Date: Permit to Drill API Number: Permit Approval Number: Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Perforation Depth MD (ft): Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. Intermediate Production Liner Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Surface Conductor/Structural Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks 404 bbls 13.5ppg Casing Length Size Cement Volume MD Total Depth MD (ft): Total Depth TVD (ft): 362 bbls 11ppg lead, 56 bbls 15.8 ppg tai 103 bbls 14ppg lead, 32 bbls 15.3ppg tail STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc. 59-52-180 KRU 3T-611 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1910' FSL, 546' FWL, SENE S1 T12N R7E ADL393883 / ADL025528 / ADL025544 / ADL390434 (including stage data) 203' FSL, 4870' FWL, NWSE S34 T13N R7E LONS 01-013 4540' FSL, 1072' FWL, SENW S22 T13N R7E 5760/2560/2560/2556 GL / BF Elevation above MSL (ft): 2346 1828 18. Casing Program: D s s sD S M S S S S 20 A S Se Class:Expl t Deve Deve t Dev D 1b. Prop Stratig y Explor Stratig E l pe of Work: Lateral Reentry rator Name: Lateral R t well is propos Gas Hyy Shale G me and Numbe Gas Hy Sh l G s No This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 225-109 By Grace Christianson at 9:58 am, Oct 15, 2025 VTL 2290 VTL DSR-10/15/25 1784 Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available Cement logs must be reviewed with the AOGCC as soon as available and prior to running the production liner 50-103-20928-00-00 TS 10/29/25 2457 X Variance of the diverter requirement under 20AAC 25.035(h)(2) is approved. VTL 10/31/2025 11/03/25 11/03/25 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. CPAIs request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 October 8, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-611 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Moraine Injector well from the 3T drilling pad. The intended spud date for this well is 12/1/2025. It is intended that Doyon 142 be used to drill the well. 3T-611 will utilize a 13-1/2 surface hole drilled to TD and 10-3/4 casing will be set and cemented to surface. As noted in section 4 of the attached proposed drilling program, the low maximum anticipated surface pressure of the well allows use of a three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii). The fourth preventer will contain solid body pipe rams that will be sized for the intermediate casing string. The 9-7/8 intermediate hole will be drilled and topset the Moraine reservoir. A 7- 5/8 casing string will be set and cemented from TD to secure the shoe and cover 500 or 250TVD above any hydrocarbon- bearing zones (Torok). The production interval will be comprised of a 6-1/2 horizontal hole that will be landed and geo-steered in the Moraine formation. The well will be completed as an cemented, fracture stimulated injector with 4-1/2 liner, and frac sleeves. The upper completion will include a production packer with GLMs and a downhole guage tied back to surface. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a) 2. A proposed drilling program 3. A proposed completion diagram 4. A drilling fluids program summary 5. Pressure information as required by 20 ACC 25.035 (d)(2) 6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) It is requested that a waiver of the diverter requirement under 20 AAC 25.035 (h) (2) is granted. At 3T, there has not been any significant indication of shallow gas or gas hydrates to date through the surface hole interval. A variance is also requested for a BOPE test interval of 21 days for this project. Doyon 142 is a strong participant in the CPAI BOPE between well maintenance program reflected by low failure rates in BOP tests since its entry in the CPAI fleet. The variance allows effective drilling and completion of problematic zones, or longer intervals during the well construction. Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP 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 Weifeng Dai at 907-265-6936 (Weifeng.Dai@conocophillips.com) or Greg Hobbs at 907-263-4749. Sincerely, cc: 3T-611 Well File / Jenna Taylor ATO 1560 Will Earhart ATO 1552 Weifeng Dai Chris Brillon ATO 1548 Drilling Engineer Jenny Doherty ATO 1410 waiver of the diverter requirementf Recommend approving requested variance of the diverter requirement under 20AAC 25.035(h)(2). TS 10/29/25 Application for Permit to Drill, 3T-611 Saved: 8-Oct-25 3T-611 PTD Page 1 of 9 Printed: 8-Oct-25 3T-611 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)) ........................................................................ 4 4. Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(3)) ............................................................. 5 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)) ........................................................... 7 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 3T-611 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 1,910 FSL, 546 FWL, NWSW S1 T12N R7E, UM NAD 1927 Northings: 467756 Eastings:6003636 RKB Elevation 51.1AMSL Pad Elevation 12AMSL Top of Productive Horizon (Heel) 203 FSL, 4870 FWL, SESE S34 T13N R7E, UM NAD 1927 Northings: 465233 Eastings: 6007220 Measured Depth, RKB: 7,144 Total Vertical Depth, RKB: 4,994 Total Vertical Depth, SS: 4,943 Total Depth (Toe) 4540 FSL, 1072 FWL, NWNW S22 T13N R7E, UM NAD 1927 Northings: 451483 Eastings: 6022135 Measured Depth, RKB: 22,549 Total Vertical Depth, RKB: 5,061 Total Vertical Depth, SS: 5,010 Pad Layout 3. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) The proposed drilling program is listed below. Please refer to Attachment 3: Completion Schematic. 1. MIRU Doyon 142 onto 3T-611 2. Rig up and test diverter and riser, dewater cellar as needed. 3. Drill 13 1/2 hole to the surface casing point as per the directional plan (LWD program:GR/RES/GWD). 4. Run and cement 10 3/4 surface casing to surface. 5. Install BOPE with the following equipment/configuration:13-5/8 annular preventer, 7-5/8 FBRs, blind ram and 2- 7/8x5 VBRs. a. See section 4 for ram configuration justification. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8 drilling BHA to drill the intermediate hole section. 8. Chart casing pressure test to 3,000 psi for 30 minutes. 9. Drill out shoe track and 20 of new hole 10. Perform FIT/LOT. Max FIT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 11. Drill 9 7/8 hole to section TD, setting pipe 5 ft TVD into the top Moraine Reservoir. (LWD Program: GR/RES). 12. Run 7 5/8 casing and cement to a minimum of 250 TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4000 psi. 13. Test BOPE to 250 psi low / 4,000 psi high (24-48 Regulatory notice). 14. Pick up and run in hole with 6 1/2 drilling BHA. Log top of cement with sonic tool in recorded mode. 15. Chart casing pressure test to 4,000 psi for 30 minutes if not tested on plug bump. 16. Drill out shoe track and 20 feet of new formation. 17. Perform LOT to a maximum of 16.0 ppg. Minimum acceptable leak-off value is 11.0 ppg EMW. 18. Drill 6 1/2 hole to section TD (LWD Program: GR/RES/Den/Neu/Sonic). 19. Pull out of hole with drilling BHA. Review cement job details and sonic log TOC. 20. Run 4 1/2 liner with toe valve, frac sleeves and liner hanger and packer to TD. 21. Cement 4 1/2 liner from TD to liner top. Pressure test liner and hanger for 30 minutes. 22. Run 4 1/2 upper completion with glass plug, production packer, chemical injection mandrel with cap string, downhole gauge, and gas lift mandrels. Space out and land tubing hanger with pre-installed and pre-tested BPV. 23. Pressure test hanger seals to 3,850 psi. 24. Pressure test against the glass plug to set production packer, test tubing to 3,850 psi, chart test. 25. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 26. Install HP-BPV and test to 2500 psi. 27. Nipple down BOP. 28. Install tubing head adapter assembly. N/U frac tree and test to 10,000 psi/10 minutes. 29. Freeze protect down tubing and annulus. 30. Secure well. Rig down and move out. Please note This well will be fracd 4. Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(3)) Please reference BOP schematics on file for Doyon 142. Doyon 142 will use a BOPE stack equipped with an annular preventer, fixed 7 5/8 solid body rams, blind/shear rams and variable rams while drilling and running casing in the intermediate section of 3T-613. 3T-619 has a MASP of 1,741 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 Annular Preventer (iii) 7 5/8 Fixed Rams Blind/Shear Rams (ii) VBRs (i) Production: Annular Preventer (iii) VBRs (i) Blind/Shear Rams (ii) VBRs (i) 5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) It is requested that a waiver of the diverter requirement under 20 AAC 25.035 (h) (2) is granted. At 3T, 3 penetrations have been completed and one more penetration is planned prior to 3T-613 and there has not been a significant indication of shallow gas or gas hydrates through the surface hole interval. 6. MASP Calculations (Requirements of 20 AAC 25.005(c)(4)) (A) maximum downhole pressure and maximum potential surface pressure; Maximum Potential Surface Pressure (MPSP) is determined as the lesser of: Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 1 Method 2 = [( × 0.052 ) ] × = ( ) × Where: FG Fracture gradient at the casing seat in lb/gal 0.052 Conversion from lb/gal to psi/ft Gas Gradient 0.1 psi/ft TVD True Vertical Depth of casing seat in ft RKB Where: FPP Formation Pore Pressure at the next casing point Gas Gradient 0.1 psi/ft The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: Section Hole Size Previous CSG Section TD MPSP psi MPSP MPSP Size MD TVD FG ppg Pore Pressure ppg | psi MD TVD Pore Pressure ppg | psi Method 1 psi Method 2 psi SURF 13.5 20 119 119 10.9 8.6 53 2,597 2,457 8.6 1,099 56 56 853 INT1 9 7/8 10-3/4 2,597 2,457 13.5 8.6 1,099 7,171 5,004 8.7 2,264 1,479 1,479 1,764 PROD 6 1/2 7-5/8 7,171 5,004 13.0 8.7 2,264 22,549 5,061 8.7 2,290 1,784 2,882 1,784 (B) data on potential gas zones; The planned wellbore is not expected to penetrate any shallow gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary 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 H40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.70 33.70 L80 P110-S Hyd563 250 TVD or 500 MD, whichever is greater, above upper most producing zone (Coyote) 4 1/2 6 1/2 12.60 P110-S Hyd563 Cemented liner with frac sleeves Cementing Calculations 10 3/4 Surface Casing run to 2,597 MD / 2,457 TVD Cement 2,597 MD to 2,097 (500 of tail) with Class G + Add's@ 15.8 PPG, and from 2,097' to surface with 10.7 ppg Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,560 MD), zero excess in 20 conductor. Lead 362 bbls => 697 sx of 11.0 ppg Class G + Add's @ 2.92 ft3 /sk Tail 56 bbls => 272 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk 7 5/8 Intermediate Casing run to 7,171 MD / 5,004 TVD Top of slurry is designed to be at 4,885 MD, which is 500 MD 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. Lead 103 bbls => 374 sx of 14 ppg Class G + Add's @ 1.55 ft3 /sk Tail 32 bbls => 144 sx of 15.3ppg Class G + Add's @ 1.25 ft3/sk 4-1/2 Liner run to 22,549 MD / 5,061 TVD Cement the liner from TD to the liner top using a 13.5 ppg Class G + Adds cement. Assume 20% excess annular volume in the open hole. Tail 404 bbls => 1,379 sx of 13.5 ppg Class G + Add's @ 1.645 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 8.6 9.8 9.0 9.6 9.5 11 PV cP 20-50 8-15 7-12 YP lb./100 ft2 30 - 80 20 - 30 15 - 30 Funnel Viscosity s/qt. 250 300 40-60 35-50 Initial Gels lb./100 ft2 30 - 50 8 - 15 5- 10 10 Minute Gels lb./100 ft2 50 - 70 <20 7 - 15 API Fluid Loss cc/30 min. N.C. 15.0 < 10.0 < 6.0 HPHT Fluid Loss cc/30 min. N/A < 10.0 < 10.0 pH 9.5 10.0 9.5 10.0 9.5 10.5 Surface Hole: A water based spud mud will be used for the surface interval. Mud engineer to perform regular mud checks to maintain proper specifications The mud weight will be maintained at 9.8 ppg by use of solids control system and dilutions where necessary. Intermediate: Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight at or below 9.6 ppg for formation stability and be prepared to add loss circulation material if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important. The mud will be weighted up to 9.5 ppg before pulling out of the hole. Production Hole: The horizontal production interval will be drilled with an NAF mud system weighted to 9.5 11 ppg. MPD will be available for adding backpressure during connections if necessary. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 10. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 12. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) N/A - Application is not for an offshore well. 13. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005 (c)(14)) Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. 15. Drilling Hazards Summary 13 1/2" Hole / 10 3/4 Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low Follow real time surveys very closely, gyro survey as needed to ensure survey accuracy. Gas Hydrates Low If observed control drill, reduce pump rates and circulating time, reduce mud temperatures Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts/Hole Sloughing Low Cool mud temperatures, minimize circulating times when possible Running sands and gravels Low Maintain planned mud properties, increase mud weight, use weighted sweeps 9 7/8 Hole /7 5/8 Liner - Casing Interval Event Risk Level Mitigation Strategy Sloughing shale / Tight hole / Stuck Pipe Low Good hole cleaning, pre-treatment with LCM, stabilized BHA, maintain planned mud weights and adjust as needed, real time equivalent circulating density (ECD) monitoring Lost circulation Moderate Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, Liner will be in place at TD Abnormal Reservoir Pressure (Coyote / K3) Low Well control drills, check for flow during connections, increase mud weight if necessary 6 1/2 Hole / 4 1/2 Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Moderate Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Moderate Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Liner to Bottom Moderate Properly clean hole on the trip out with BHA, perform clean out run if necessary, utilize super sliders for weight transfer if needed, monitor T&D real time Well Proximity Risks: 3T is a multi-well pad, with only a few existing wells. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Unlikely to encounter any abnormal pressure, however, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the primary intermediate cement job will be replanned to cover the zone as per the agency regulations. Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 16. Proposed Completion Schematic 3T-611 AOGCC 10-401 APD 10/8/2025 3T-611 AOGCC 10-401 APD 1 | 2 1. Area for Review 3T-611 Area of Review (AOR) An Area of Review plot is show below of the 3T-611 injector planned wellpath and offset wells. 3T-617, NDST-02, Nuna 1, and Nuna 1 PB1 are the offset wells from the planned 3T-611 injector. 3T-611 AOGCC 10-401 APD 10/8/2025 3T-611 AOGCC 10-401 APD 2 | 2 PTD API Well Name Status Top of Zone-of-Interest Isolating Stage TOC Method TOC Determination Losses (volume, % no reported) Returns verified Zonal Isolation Comments 225-053 50103209180000 3T-617 Producing 4,970 MD (Coyote) Surface and Intermediate Cement Plug/Squeeze. 3,019 MD Ultrasonic CBL None Yes Yes Currently on frac, schedule to be on producing during 3T-611 execution 212-163 50103206600000 NDST-02 Suspended 9,907 MD (Torok) Intermediate RBP at 2,000 8,907 MD Pressure Test RBP to 2,500psi for 30 min None No, balance plug Yes Schedule to P&A by June 2026 211-155 50103206450000 Nuna 1 Suspended 7,945 MD (Torok) Cement Plug 6,621 Physical tag, 12klb WOB None No, balance plug Yes Cement squeeze F/7,003 T/10,205. Tagged TOC and PT to 1,700 psi. Set balance plug on top of CIBP. 211-155 50103206457000 Nuna 1 PB1 P&Ad 6,895 MD (Torok) Open Hole Cement Plugs 5,766 MD Physical Tag, 25klb WOB None No, balance plug Yes Set 3 balance plugs from 7,347 to 5,800. Drilled out cement F/5,600 to 5,766 before sidetracking. 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 18000 18000 22550 3T-611 wp14.1 Plan Summary 0 4 0 3500 7000 10500 14000 17500 21000 Measured Depth 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 30.0 30.0 60.0 60.0 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 39100200300400500600700 3T-608 39100200300 400500600700 800900 1000 1099 1199 1298 3T-612 39 1002003004005006007008009011002 3T-613 100200300400500600700 3T-614 wp14 3910020030040050060070080090110011101120213021402150216021701180119001999209821972296 3T-609 wp08.1 39100200300400500600 700 801 901 1002 1103 3T-610 wp05 0 3000 0 1000 2000 3000 4000 5000 6000 Vertical Section at 341.01° 10-3/4" Surface Casing 7-5/8" Intermediate Casing 18 35 0 425 850 1275 1700 2125 2550 2975 Measured Depth Equivalent Magnetic Distance DDI 7.216 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.00 1600.00 3T-611 wp14.1 (3T-611) r.5 SDI_URSA1 1600.00 2590.00 3T-611 wp14.1 (3T-611) MWD+IFR2+SAG+MS 2590.00 7170.00 3T-611 wp14.1 (3T-611) MWD+IFR2+SAG+MS 7170.00 22549.30 3T-611 wp14.1 (3T-611) MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 2457.00 2596.74 10-3/4" Surface Casing 5004.00 7171.197-5/8" Intermediate Casing 5061.00 22549.30 4-1/2" Production Liner Mag Model & Date: BGGM2025 09-Jan-26 Magnetic North is 13.41° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.59° 57141.83nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.00 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 700.00 2.00 328.00 699.96 2.96 -1.85 1.00 328.00 3.40 Start Build 2.00 4 1509.21 18.18 328.00 1494.00 122.81 -76.74 2.00 0.00 141.10 Start 105.26 hold at 1509.21 MD 5 1614.46 18.18 328.00 1594.00 150.67 -94.15 0.00 0.00 173.10 Start Build 2.00 6 2610.69 38.11 328.00 2468.00 547.20 -341.93 2.00 0.00 628.67 Start 20.00 hold at 2610.69 MD 7 2630.69 38.11 328.00 2483.74 557.67 -348.47 0.00 0.00 640.70 Start DLS 2.50 TFO -13.00 8 3401.97 57.03 322.92 3001.91 1022.03 -672.72 2.50 -13.00 1185.28 Start 3227.53 hold at 3401.97 MD 9 6629.50 57.03 322.92 4758.11 3182.43 -2305.33 0.00 0.00 3759.29 Start DLS 3.00 TFO 45.44 10 7721.17 82.00 345.83 5141.58 4096.91 -2725.25 3.00 45.44 4760.64 Start Build 3.00 11 7921.17 88.00 345.83 5159.00 4290.00 -2774.00 3.00 0.00 4959.08 Start 20.00 hold at 7921.17 MD 12 7941.17 88.00 345.83 5159.70 4309.38 -2778.89 0.00 0.00 4979.00 Start DLS 1.50 TFO -0.02 13 8105.19 90.46 345.83 5161.90 4468.38 -2819.04 1.50 -0.02 5142.41 Start 1976.42 hold at 8105.19 MD 1410081.62 90.46 345.83 5146.02 6384.60 -3302.88 0.00 0.00 7111.80 Start DLS 1.00 TFO 174.22 1510084.66 90.43 345.83 5146.00 6387.55 -3303.63 1.00 174.22 7114.83 3T Eaglek T02 090425 Start DLS 1.00 TFO -177.09 1610095.47 90.32 345.83 5145.93 6398.03 -3306.27 1.00 -177.09 7125.60 Start 6211.02 hold at 10095.47 MD 1716306.49 90.32 345.83 5111.01 12419.89 -4827.05 0.00 0.0013314.63 Start DLS 1.00 TFO 170.64 1816309.23 90.29 345.83 5111.00 12422.55 -4827.72 1.00 170.6413317.37 3T Eaglek T03 090425 Start DLS 1.00 TFO -164.95 1916311.23 90.28 345.83 5110.99 12424.49 -4828.21 1.00 -164.9513319.36 Start 2059.59 hold at 16311.23 MD 2018370.82 90.28 345.83 5101.08 14421.35 -5332.53 0.00 0.0015371.67 Start DLS 1.00 TFO 2.69 21 18384.27 90.41 345.83 5101.00 14434.39 -5335.82 1.00 2.6915385.07 3T Eaglek T04 090425 Start DLS 1.00 TFO -0.39 2218398.32 90.55 345.83 5100.88 14448.01 -5339.26 1.00 -0.3915399.07 Start 4150.98 hold at 18398.32 MD 23 22549.30 90.55 345.83 5061.00 18472.53 -6355.28 0.00 0.0019535.20 3T Eaglek T05 092325 TD at 22549.30 FORMATION TOP DETAILS TVDPath Formation 1343.00 Ugnu C 1542.00 Base Perm 1966.00 West Sak 2371.00 West Sak Base 2586.00 C-80 3735.00 C-35 4081.00 Coyote 4174.00 Coyote Base 4994.00 Top Moraine 5138.00 Lower Moraine By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by Accepted by Approved by plan 39+12 @ 51.00usft (D142) True Vertical Depth11 0 0 0 12000 13 000 14000 1500 0 16000 19000 20000 21000 22000 22550 90 ° 91° 3T-611 wp14.1 South(-)/North(+) Separation Factor 0 35 0 550 1100 1650 2200 2750 Partial Measured Depth Equivalent Magnetic Distance 3T-611 wp14.1 Ladder View 0 150 300 0 3500 7000 10500 14000 17500 21000 Measured Depth Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 39.00 1600.00 3T-611 wp14.1 (3T-611) r.5 SDI_URSA1 1600.00 2590.00 3T-611 wp14.1 (3T-611) MWD+IFR2+SAG+MS 2590.00 7170.00 3T-611 wp14.1 (3T-611) MWD+IFR2+SAG+MS 7170.00 22549.30 3T-611 wp14.1 (3T-611) MWD+IFR2+SAG+MS 12:21, October 01 2025 CASING DETAILS TVD MD Name 2457.00 2596.74 10-3/4" Surface Casing 5004.00 7171.19 7-5/8" Intermediate Casing 5061.00 22549.30 4-1/2" Production Liner 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 18000 18000 22550 3T-611 wp14.1 TC View 30 30 60 60 90 90 120 120 150 150 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 39 50100150200 250300350400450 3T-603 3950100150200250300350400450500550600650700750800849899949999 3T-605 395010015020025030035040045050055060065070075080085090095010001050110011501200124912991349139814481497154715961645 3T-608 3950100150200250 300350400450500550 600650 700 750800850900950100010501099114911991248129813471396144614951544159416431692174217911841189019391989 3T-612 39 50100150200250300350400450500550600650700750800851901951100210521103115312041255130513561407145815091559160816591711176218131865191619682019207121232175 3T-613 501001502002503003504004505005506006507007508008509019511001105211021153120412541305135614071457150815581608165917101761181218641915196620173T-614 wp14 3950100150200250300350400450499549 598 647 697 745 794 842 889 3T-616 3950100150200250300350400450499549 598 647 697 745 794 842 889 3950100150200250300350400450499549 598 647 697 745 794 842 889 39 5010015020025030035040045050055060065070075080085090195110021052110311541204125513061357140814593T-617 39 501001502002503003504004505005506006507007508008509019511002105211031154120412551306135714081459 3950100150200250300350400450500550600650700750 3T-604 wp05 v5 39501001502002503003504004505005506006507007508008498999489971046109511433T-606 wp08 395010015020025030035040045050055060065070075080085190195110011051110111521202125213021352 3T-607 wp05 395010015020025030035040045050055060065070075080085090195110011051 1101115112021252130213521402145215021552160216511701175118011850190019501999204920982148219722462296234523942443249325422591264026892737278528332881 2928 2975 3021 3067 3112 3T-609 wp08.1 39501001502002503003504004505005506006507007508018519019511002105211031153120412541305135614061457150815571607165817091760181018611912 1963 2014 2065 3T-610 wp05 3950100150200250300350400450500550600650700750800850901951100110521103115312041255130613571408145915101560 3T-615 wp09.1 3950100150200250300350400450500550600650700750800850900951100110511102 3T-618 wp07 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: From To Tool 39.00 1600.00 r.5 SDI_URSA1 1600.00 2590.00 MWD+IFR2+SAG+MS 2590.00 7170.00 MWD+IFR2+SAG+MS 7170.00 22549.30 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 2457.00 2596.74 10-3/4" Surface Casing 5004.00 7171.19 7-5/8" Intermediate Casing 5061.00 22549.30 4-1/2" Production Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.00 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 700.00 2.00 328.00 699.96 2.96 -1.85 1.00 328.00 3.40 Start Build 2.00 4 1509.21 18.18 328.00 1494.00 122.81 -76.74 2.00 0.00 141.10 Start 105.26 hold at 1509.21 MD 5 1614.46 18.18 328.00 1594.00 150.67 -94.15 0.00 0.00 173.10 Start Build 2.00 6 2610.69 38.11 328.00 2468.00 547.20 -341.93 2.00 0.00 628.67 Start 20.00 hold at 2610.69 MD 7 2630.69 38.11 328.00 2483.74 557.67 -348.47 0.00 0.00 640.70 Start DLS 2.50 TFO -13.00 8 3401.97 57.03 322.92 3001.91 1022.03 -672.72 2.50 -13.00 1185.28 Start 3227.53 hold at 3401.97 MD 9 6629.50 57.03 322.92 4758.11 3182.43 -2305.33 0.00 0.00 3759.29 Start DLS 3.00 TFO 45.44 10 7721.17 82.00 345.83 5141.58 4096.91 -2725.25 3.00 45.44 4760.64 Start Build 3.00 11 7921.17 88.00 345.83 5159.00 4290.00 -2774.00 3.00 0.00 4959.08 Start 20.00 hold at 7921.17 MD 12 7941.17 88.00 345.83 5159.70 4309.38 -2778.89 0.00 0.00 4979.00 Start DLS 1.50 TFO -0.02 13 8105.19 90.46 345.83 5161.90 4468.38 -2819.04 1.50 -0.02 5142.41 Start 1976.42 hold at 8105.19 MD 1410081.62 90.46 345.83 5146.02 6384.60 -3302.88 0.00 0.00 7111.80 Start DLS 1.00 TFO 174.22 1510084.66 90.43 345.83 5146.00 6387.55 -3303.63 1.00 174.22 7114.83 3T Eaglek T02 090425 Start DLS 1.00 TFO -177.09 1610095.47 90.32 345.83 5145.93 6398.03 -3306.27 1.00 -177.09 7125.60 Start 6211.02 hold at 10095.47 MD 1716306.49 90.32 345.83 5111.01 12419.89 -4827.05 0.00 0.0013314.63 Start DLS 1.00 TFO 170.64 1816309.23 90.29 345.83 5111.00 12422.55 -4827.72 1.00 170.6413317.37 3T Eaglek T03 090425 Start DLS 1.00 TFO -164.95 1916311.23 90.28 345.83 5110.99 12424.49 -4828.21 1.00 -164.9513319.36 Start 2059.59 hold at 16311.23 MD 2018370.82 90.28 345.83 5101.08 14421.35 -5332.53 0.00 0.0015371.67 Start DLS 1.00 TFO 2.69 21 18384.27 90.41 345.83 5101.00 14434.39 -5335.82 1.00 2.6915385.07 3T Eaglek T04 090425 Start DLS 1.00 TFO -0.39 2218398.32 90.55 345.83 5100.88 14448.01 -5339.26 1.00 -0.3915399.07 Start 4150.98 hold at 18398.32 MD 23 22549.30 90.55 345.83 5061.00 18472.53 -6355.28 0.00 0.0019535.20 3T Eaglek T05 092325 TD at 22549.30 Northing (7000 usft/in) Northing (1500 usft/in) Northing (450 usft/in)2224 Northing (70 usft/in) South(-)/North(+) (3500 usft/in) South(-)/North(+) (3500 usft/in) South(-)/North(+) (600 usft/in) South(-)/North(+) (600 usft/in) 3T-611 wp14.1 Surface Location 3T-611 wp14.1 Surface Location # Schlumberger-Confidential 3T-611 wp14.1 Surface Casing 3T-611 wp14.1 Surface Casing # Schlumberger-Confidential 3T-611 wp14.1 Top Moraine 3T-611 wp14.1 Top Moraine # Schlumberger-Confidential 3T-611 wp14.1 Intermediate Csg 3T-611 wp14.1 Intermediate Csg # Schlumberger-Confidential 3T-611 wp14.1 TD 3T-611 wp14.1 TD # Schlumberger-Confidential Certificate Of Completion Envelope Id: D567BE65-A79A-4819-BAAD-679B63A8BD28 Status: Completed Subject: Complete with Docusign: 3T-611 AOGCC Permit Application Package.pdf Source Envelope: Document Pages: 64 Signatures: 1 Envelope Originator: Certificate Pages: 4 Initials: 0 Weifeng Dai AutoNav: Enabled EnvelopeId Stamping: Disabled Time Zone: (UTC-06:00) Central Time (US & Canada) 925 N Eldridge Pkwy Houston, TX 77079 Weifeng.Dai@conocophillips.com IP Address: 138.32.8.5 Record Tracking Status: Original 10/8/2025 5:08:28 PM Holder: Weifeng Dai Weifeng.Dai@conocophillips.com Location: DocuSign Signer Events Signature Timestamp Chris Brillon chris.l.brillon@cop.com Security Level: Email, Account Authentication (None) Signature Adoption: Pre-selected Style Using IP Address: 138.32.8.5 Sent: 10/8/2025 5:10:02 PM Viewed: 10/14/2025 7:28:57 PM Signed: 10/14/2025 7:29:07 PM Electronic Record and Signature Disclosure: Accepted: 10/14/2025 7:28:57 PM ID: 722d501c-8187-4bf3-acf8-fe5b2593c8f0 In Person Signer Events Signature Timestamp Editor Delivery Events Status Timestamp Agent Delivery Events Status Timestamp Intermediary Delivery Events Status Timestamp Certified Delivery Events Status Timestamp Carbon Copy Events Status Timestamp Witness Events Signature Timestamp Notary Events Signature Timestamp Envelope Summary Events Status Timestamps Envelope Sent Hashed/Encrypted 10/8/2025 5:10:02 PM Certified Delivered Security Checked 10/14/2025 7:28:57 PM Signing Complete Security Checked 10/14/2025 7:29:07 PM Completed Security Checked 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From:Dai, Weifeng To:Loepp, Victoria T (OGC); Starns, Ted C (OGC) Subject:RE: [EXTERNAL]FW: KRU 3T-611 MPSP and Res P calcs don"t agree with 10-401 form Date:Wednesday, October 29, 2025 2:31:09 PM Attachments:image001.png Victoria, The MPSP in 10-401 needs to be updated. The figures in the table of the file (page 8 out of 68) is correct, attach here. Again, sorry for missing update number in 10-401. Please let me know if you have any questions. Weifeng Dai ConocoPhillips Alaska Staff Drilling Engineer Cell: 907-346-0324 From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Wednesday, October 29, 2025 12:40 PM To: Starns, Ted C (OGC) <ted.starns@alaska.gov>; Dai, Weifeng <Weifeng.Dai@conocophillips.com> Subject: [EXTERNAL]FW: KRU 3T-611 MPSP and Res P calcs don't agree with 10-401 form 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. Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 _____________________________________________ From: Loepp, Victoria T (OGC) Sent: Wednesday, October 29, 2025 10:53 AM To: Dai, Weifeng <weifeng.dai@conocophillips.com> Subject: KRU 3T-611 MPSP and Res P calcs don't agree with 10-401 form Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 1 Starns, Ted C (OGC) From:Starns, Ted C (OGC) Sent:Wednesday, October 29, 2025 1:16 PM To:Dai, Weifeng Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC) Subject:RE: [EXTERNAL]KRU-3T-611 (PTD 225-109) - Questions Thank you Weifeng. From: Dai, Weifeng <Weifeng.Dai@conocophillips.com> Sent: Wednesday, October 29, 2025 12:37 PM To: Starns, Ted C (OGC) <ted.starns@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL]KRU-3T-611 (PTD 225-109) - Questions Hi Ted, Its a WAG injector, and only ow back, no pre-production. Please reference below for the updated lease info. Apologies for the erroneous info, please feel free to let me know if you have any questions. Weifeng Dai ConocoPhillips Alaska Sta Drilling Engineer Cell: 907-346-0324 From: Starns, Ted C (OGC) <ted.starns@alaska.gov> Sent: Wednesday, October 29, 2025 11:39 AM To: Dai, Weifeng <Weifeng.Dai@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL]KRU-3T-611 (PTD 225-109) - Questions You don't often get email from weifeng.dai@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 CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hello Weifeng, Im wrapping up my review of the 3T-611 PTD and I have a few questions for clari cation. - On the 10-401 the 3T-611 is listed as a Development Oil well, but the application indicates this will be a fracture stimulated injector. Can you please con rm this is planned to be an injector, and if so, if it is planned to be a WAG or a water only injector? o Also, are there any plans for pre-production if it is an injector? - On the property designation on the 10-401 there are four leases listed, but looking at my maps and those provided by CPAI it appears that only two leases are a ected: ADL25528 & ADL393883. o Can you please check which leases are a ected and let me know with the updated acreage? Thank you for the nicely compiled AOR. It was very helpful to see that portion of the application in the format in which it was submitted. Have a nice day Ted Ted Starns Petroleum Geologist AOGCC 907-793-1225 (o ce) Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KUPARUK RIVER TOROK OIL 225-109 KRU 3T-611 WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIVER UNIT 3T-611Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgram SERWell bore segAnnular DisposalPTD#:2251090Field & Pool:KUPARUK RIVER, TOROK OIL - 490169NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes KUPARUK RIVER, TOROK OIL - 490169 - governed by CO 725A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes AIO 039A14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)No16 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)Yes 81' conductor18 Conductor string providedYes SC set at 2597' MD19 Surface casing protects all known USDWsYes 149% excess20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes22 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 approvedYes26 Adequate wellbore separation proposedYes Diverter variance granted per 20 AAC 25.035(h)(2)27 If diverter required, does it meet regulationsYes Max reservoir pressure is 2290 psig(8.7 ppg EMW); will drill w/ 9.0-11.0 ppg EMW28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP is 1784 psig; will test BOPs to 5000 psig initially and 4000 paig 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 shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.447 to 0.452 psi/ft (8.6 to 8.7 ppg EMW)36 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]ApprTCSDate29-Oct-25ApprVTLDate31-Oct-25ApprTCSDate29-Oct-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 11/3/2025