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LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Well clean up data for 19 wells Details are provided on following pages with well name and API table as reference. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/20/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.21 09:00:44 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043A 50103208590100 NDBi-044 50103208650000 NDBi-046L1 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 جؐؐؐNDB-010 ؒ Santos_Pikka_NDB-010_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-010_End of Well Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-010_Rev A (1).pdf ؒ جؐؐؐNDB-011 ؒ Santos_Pikka_NDB-011_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-011_End of Well Data Report_30 Min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-011_Rev A (1).pdf ؒ جؐؐؐNDB-014 ؒ Santos_Pikka_NDBi-014_End of Well Clean-up Data Report_30 Minute_Final Data.xlsx ؒ Santos_Pikka_NDBi-014__End of Well Clean-up Data Report_1 Minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-014_Rev A_Signed.pdf ؒ جؐؐؐNDB-024 ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_ 30-min_Final (2).xlsx ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_1-min_Final (2).xlsx ؒ WT-XAK-0127.2_End of Well Clean-Up Data Report_NDB-024_Rev A_Signed.pdf 225-061 T41152 225-048 T41153 223-076 T39828 223-105 T39831 NDB-037 50103208950000 LETTER OF TRANSMITTAL ؒ جؐؐؐNDB-025 ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf ؒ جؐؐؐNDB-031 ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf ؒ جؐؐؐNDB-032 ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-037 ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-048 ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-051 ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf ؒ جؐؐؐNDBi-016 ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf ؒ جؐؐؐNDBi-018 ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf ؒ جؐؐؐNDBi-030 224-006 T41154 225-028 T41155 224-124 T41156 224-143 T41157 224-105 T41158 224-085 T41159 224-013 T39830 223-006 T39829 223-120 T39832 NDB-037 LETTER OF TRANSMITTAL ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf ؒ جؐؐؐNDBi-036 ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf ؒ جؐؐؐNDBi-043A ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf ؒ جؐؐؐNDBi-044 ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf ؒ جؐؐؐNDBi-046L1 ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf ؒ جؐؐؐNDBi-049 ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf ؒ ؤؐؐؐNDBi-050 Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf 225-012 T41160 224-119 T41161 224-154 T41162 223-052 T39834 223-087 T39835 224-029 T39837 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Baker Hughes has provided us with LithTrak Azimuthal Caliper data for all 22 previous wells. Details are provided on following pages with well name and API table as reference. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/18/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.19 08:30:05 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDB-027 50103209220000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043 50103208590000 NDBi-044 50103208650000 NDBi-046 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 DW-02 50103208550000 PWD-02 50103208790000 جؐؐؐDW-02 Lithotrak Caliper data ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.dlis ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.las ؒ جؐؐؐNDB-010 Lithotrak Caliper data ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.dlis ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.las ؒ جؐؐؐNDB-011 Lithotrak Caliper data ؒ جؐؐؐ12.25 in ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.dlis ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.las ؒ ؒ ؒ ؤؐؐؐ8.5 in ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.dlis 223-039 T41107 225-061 T41108 225-048 T41109 NDB-037 50103208950000 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.las ؒ جؐؐؐNDB-024 Lithotrak Caliper data ؒ جؐؐؐRun 6 ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.dlis ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.las ؒ ؒ ؒ ؤؐؐؐRun 7 ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.dlis ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.las ؒ جؐؐؐNDB-025 Lithotrak Caliper data ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.dlis ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.las ؒ جؐؐؐNDB-027 Lithotrak Caliper data ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.dlis ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.las ؒ جؐؐؐNDB-031 Lithotrak Caliper data ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.dlis ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.las ؒ جؐؐؐNDB-032 Lithotrak Caliper data ؒ جؐؐؐRun 3 ؒ ؒ SANTOS_NDB-032_BHP_12_25_2598_6224ft_Run3.las ؒ ؒ SANTOS_NDB_032_BHP_12_25_2598_6224ft_Run3.dlis ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.dlis ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.las ؒ جؐؐؐNDB-037 Lithotrak Caliper data ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.dlis ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.las ؒ جؐؐؐNDB-048 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.dlis ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 223-076 T41110 224-006 T41111 225-066 T41112 225-028 T41113 223-060 T41114 224-124 T41115 224-143 T41116 NDB-037 Lithotrak Caliper data LETTER OF TRANSMITTAL ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.dlis ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.las ؒ جؐؐؐNDB-051 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.dlis ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.dlis ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.las ؒ جؐؐؐNDBi-014 Lithotrak Caliper data ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.dlis ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.las ؒ جؐؐؐNDBi-016 Lithotrak Caliper data ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4.las ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4_1.dlis ؒ جؐؐؐNDBi-018 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.dlis ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.dlis ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.las ؒ جؐؐؐNDBi-030 Lithotrak Caliper data ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.dlis ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.las ؒ جؐؐؐNDBi-036 Lithotrak Caliper data ؒ جؐؐؐRun 4 ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.dlis ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.las ؒ ؒ ؒ ؤؐؐؐRun 6 ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.dlis ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.las ؒ 224-013 T41117 223-105 T41118 224-105 T41119 224-085 T41120 223-120 T41121 225-012 T41122 LETTER OF TRANSMITTAL جؐؐؐNDBi-043 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.dlis ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.dlis ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.las ؒ جؐؐؐNDBi-044 Lithotrak Caliper data ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.dlis ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.las ؒ جؐؐؐNDBi-046 Lithotrak Caliper data ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.dlis ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.las ؒ جؐؐؐNDBi-049 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.dlis ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.dlis ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.las ؒ جؐؐؐNDBi-050 Lithotrak Caliper data ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.dlis ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.las ؒ ؤؐؐؐPWD-02 Lithotrak Caliper data SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.dlis SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.las 223-051 T41123 223-087 T41124 224-028 T41125 224-119 T41126 224-154 T41127 224-009 T41128 CDW 07/28/2025 BJM 9/25/25 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-037 JBR 07/18/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:5 4/5" test joint used for testing. The upper kelly failed on the high. The component was serviced and passed the retest. The gas alarm slave panel was down and every detector except the rig floor's detectors were not operational. I did not witness the retest of the detectors, but was sent video's of them operating after I left location. I did tell the company rep and the rig reps that they were not allowed to do any well work until the gas alarms were functioning properly. I gave them the okay to go to work after seeing the videos and speaking with the rig representative. The rams with the 9 5/8" solids were not tested as they were not going to be needed. Test Results TEST DATA Rig Rep:S. Clark/N. WherlyOperator:Oil Search (Alaska), LLC Operator Rep:B. Buzby/J. Witlatch Rig Owner/Rig No.:Parker 272 PTD#:2241240 DATE:5/1/2025 Type Operation:WRKOV Annular: 250/3600Type Test:INIT Valves: 250/3600 Rams: 250/3600 Test Pressures:Inspection No:bopGDC250502181511 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7 MASP: 1466 Sundry No: 325-125 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 FP Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 P #1 Rams 1 3.5"x5.5" VB P #2 Rams 1 Blind/Shear P #3 Rams 1 9 5/8" Solid NT #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5000 P HCR Valves 2 3 1/8" 5000 P Kill Line Valves 2 3 1/8", 2 1/16 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2100 200 PSI Attained P9 Full Pressure Attained P63 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2300 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator F FMeth Gas Detector F FH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P27 #1 Rams P7 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 9 9 9 9999 9 9 99 9 9 9 9 9 9 9 FP F F F F upper kelly failed every detector except the rig floor's detectors were not operational rams with the 9 5/8" solids were not tested as they were not going to be needed. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Oil Search Alaska, LLC Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 601 W 5th Avenue, Anchorage, AK 99501 7.Property Designation (Lease Number): 8.Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,776 feet N/A feet true vertical 4,066' feet N/A feet Effective Depth measured 10,729' feet see attached rpt feet true vertical 4,066' feet see attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4 1/2" P-110S 17,769' 4,142' Packers and SSSV (type, measured and true vertical depth) see attached packer report 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Authorized Title: Contact Name:Rob Williams Contact Email:rob.williams@santos.com Contact Phone: 325-125 Sr Pet Eng: 9210 psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 128' 0 Size 128' 2,398' 000 0 00 0 9-5/8" 11590 psi 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-124 50-103-20895-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393020, 393019, 393018 Nanushuk Oil Pool Pikka / NDB-037 Plugs Junk measured Length 128' 2,812' 10,862' 2,812'Surface Intermediate Tieback 20"x34" 13-3/8" 9-5/8" measured TVD Production Liner 2,644' 17,769' 10,729' Casing Conductor 2,318' 4,142' 4-1/2" 2,644' 17,769' 10,729' 4,066' 4750 psi 9210 psi 5020 psi 6870 psi 6870 psi 11590 psi 10,862' 4,105' Burst Collapse 2260 psi 4750 psi p k ft t Fra O s O 224 6.A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov WK-XQH By Grace Christianson at 2:51 pm, Jun 04, 2025 BJM 9/19/25 DSR-6/18/25 RBDMS JSB 061325 Page 1 of 1 Packer Set Depths - NDB-037 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole SLZXP Liner Top Hanger Packer w/centralizer 10,716.9 4,062.8 Original Hole HES Zoneguard OH Packer #15 10,979.7 4,133.4 Original Hole HES Zoneguard OH Packer #14 11,046.9 4,146.0 Original Hole HES Zoneguard OH Packer #13 11,463.2 4,167.0 Original Hole HES Zoneguard OH Packer #12 11,530.3 4,166.9 Original Hole HES Zoneguard OH Packer #11 12,028.8 4,164.0 Original Hole HES Zoneguard OH Packer #10 12,570.1 4,162.0 Original Hole HES Zoneguard OH Packer #9 13,109.7 4,160.1 Original Hole HES Zoneguard OH Packer #8 13,733.0 4,158.0 Original Hole HES Zoneguard OH Packer #7 14,185.3 4,154.5 Original Hole HES Zoneguard OH Packer #6 14,724.7 4,152.1 Original Hole HES Zoneguard OH Packer #5 15,262.8 4,151.0 Original Hole HES Zoneguard OH Packer #4 15,801.5 4,148.7 Original Hole HES Zoneguard OH Packer #3 16,257.8 4,146.8 Original Hole HES Zoneguard OH Packer #2 16,878.2 4,144.7 Original Hole HES Zoneguard OH Packer #1 17,375.0 4,143.1 Well Intervention_RWO Ops Summary - AOGCC Page 1 of 1 Well Name Wellbore Name PTD Start Drill Date End Drill Date Well Name NDB-037 Wellbore Name Original Hole PTD # 224-124 StartDrill Date 4/30/2025 End Drill Date 5/4/2025 Job Type Start Date End Date Summary WOV 4/30/2025 5/1/2025 No Accidents, No Incidents, No Spills. Circulate out diesel freeze protect by pumping 270 bbls of 9.4 ppg NaCl inhibited brine w/ biocide down IA, through open EGL at 3,097' and up Tubing. Combo test T x IA to 2,500 psi. Good test. Set TWC and test to 2,500 psi, good test. Pre-Rig Operations concluded at 22:00 hrs. WOV 5/1/2025 5/2/2025 No Accidents, No Incidents, No Spills. MIRU over NDB-037. Accept rig for operations at 07:30 hrs on 5/1/2025. ND Frac Tree. NU 13-5/8" BOPE. Start testing 13-5/8" BOPE at 16:00 hrs to 250 psi low, 3,600 psi high for 5 minutes each, total of 21 valves tested, all tests successful. Finish testing at 21:30 hrs on 5/1/2025. Test witnessed by AOGCC Rep Guy Cook. RD testing equip. RU 4-1/2" handling tools. WOV 5/2/2025 5/3/2025 No Accidents, No Incidents, No Spills. Rig up to pull 4-1/2” Upper Completion assembly. Slip & cut drill line. Troubleshoot Fire & Gas Alarm system, download new Fire & Gas program. Pull TWC & Hanger. Lay down 4-1/2" 12.6# P-110S HYD 563 Upper Completion assembly from 10,729' to 7,599' MD. Replace Sage Rider EGL valve #2 assembly. Run 4-1/2" 12.6# P-110S HYD 563 Upper Completion assembly from 7,599’ to 8,332’ MD. WOV 5/3/2025 5/4/2025 No Accidents, No Incidents, No Spills. Run 4-1/2" 12.6# P-110S HYD 563 Upper Completion assembly from 8,332' to 10,576' MD. Splice TEC wire. Perform space out. Terminate control line. Pressure test MIT-T to 3,500 psi for 30 mins, good test. Pressure test MIT-IA to 4,000 psi for 30 mins, good test. Pump freeze protect. Install TWC & pressure test to 2,500 psi for 10 mins, good test. N/D BOPE. WOV 5/4/2025 5/4/2025 No Accidents, No Incidents, No Spills. Terminate control lines through wellhead. Nipple up 10k Frac tree with FMC rep. Complete all rig move checklists. Prepare to move to NDB-031. ****Release rig from NDB-037 on 5/4/2025 at 06:00 hrs. NDB-037 Well SchematicRWO - Final 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2644' MD 13-3/8" 68 ppf L-80 Surface Casing2,812' MD 9-5/8", 47ppf L-80 Production Liner10862 MD 4-½”, 12.6ppf P-110S Production Liner 17,769' MD 4-½” Liner Hanger/ Packer10695' MD GL 9-5/8" 68 ppf L-80 Tieback2644' MD 05.07.2025 Archer C-Flex Two-Stage Cementing Tool4,672 MD 8 7 3 4 5 6 1 2 8-½” Openhole 17,776'' MD 46.60' RKB – Bottom Flange TOC First Stage Cement 7,985’MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1516 1484 24 3.813 4.790 2 Gaslift Mandrel 1.5" 2150 2009 43 3.865 7.650 3 X Landing Nipple 2220 2059 45 3.813 4.790 4 EGL Gauge 3165 2528 73 3.892 6.198 5 X Landing Nipple 10410 3975 74 3.813 4.776 6 SSD NERA Gaslift 10473 3993 74 3.813 7.000 7 EGL Valve 10538 4011 73 3.860 5.818 8 D/H Psi-Temp Gauge 10606 4031 73 3.905 6.000 9 X Landing Nipple 10629 4037 73 3.813 4.776 10 Tieback Seal Assy 10729 4066 73 3.908 5.220 11 9.625" x 4.5" LH/Packer 10695 4057 73 6.040 8.480 12 #15 Openhole Packer 10973 4132 78 3.918 8.000 13 #14 Openhole Packer 11040 4145 80 3.918 8.000 14 Stg 13 - Collet Sleeve 12 11188 4163 86 3.735 5.632 15 #13 Openhole Packer 11457 4167 90 3.918 8.000 16 #12 Openhole Packer 11524 4167 90 3.918 8.000 17 Stg 12 - Collet Sleeve 11 11754 4165 90 3.735 5.632 18 #11 Openhole Packer 12022 4164 90 3.918 8.000 19 Stg 11 - Collet Sleeve 10 12294 4163 90 3.735 5.632 20 #10 Openhole Packer 12564 4162 90 3.918 8.000 21 Stg 10 - Collet Sleeve 9 12834 4161 90 3.735 5.630 22 #9 Openhole Packer 13103 4160 90 3.918 8.000 23 Stg 9 - Collet Sleeve 8 13375 4159 90 3.735 5.635 24 #8 Openhole Packer 13726 4158 90 3.918 8.000 25 Stg 8 - Collet Sleeve 7 13915 4157 90 3.735 5.632 26 #7 Openhole Packer 14179 4155 90 3.918 8.000 27 Stg 7 - Collet Sleeve 6 14449 4153 90 3.735 5.632 28 #6 Openhole Packer 14718 4152 90 3.918 8.000 29 Stg 6 - Collet Sleeve 5 14988 4152 90 3.735 5.635 30 #5 Openhole Packer 15256 4151 90 3.918 8.000 31 Stg 5 - Collet Sleeve 4 15526 4150 90 3.735 5.630 32 #4 Openhole Packer 15795 4149 90 3.918 8.000 33 Stg 4 -Collet Sleeve 3 16065 4148 90 3.735 5.630 34 #3 Openhole Packer 16251 4147 90 3.918 8.000 35 Stg 3 - Collet Sleeve 2 16603 4146 90 3.735 5.632 36 #2 Openhole Packer 16872 4145 90 3.918 8.000 37 Stg 2 - Collet Sleeve 1 17142 4144 90 3.735 5.634 38 #1 Openhole Packer 17368 4143 90 3.918 8.000 39 Stg 1 - #2 Toe Sleeve 17679 4142 90 3.500 5.750 40 Stg 1 - #1 Toe Sleeve 17691 4142 90 3.500 5.750 41 WIV Collar 17753 4142 90 0.870 5.610 42 Float Collar 17766 4142 90 3.980 5.220 43 Eccentric shoe 17768 4142 90 3.290 5.190 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?Pikka / NDB-037 Yes No 9. Property Designation (Lease Number): 10. Field: Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,776'N/A Casing Collapse Conductor Surface 2,260 Intermediate 4,750 Tieback 4,750 Production 9,210 Tubing 9,210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): See attached packer report See attached packer report 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:Rob Williams Contact Email:rob.williams@santos.com Contact Phone: 907 343 9737 Authorized Title: Senior Drilling 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 4,142' 17,769' 4,142' 1466 N/A Subsequent Form Required: Suspension Expiration Date: 6,870 5,020 6,870 Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393020, 393019, 393018 Pikka 224-124 601 W 5th Avenue, Anchorage, AK 99501 50-103-20895-00-00 Oil Search Alaska, LLC Proposed Pools: 128' 128' P-110S TVD Burst 10,729' 11,590 MD 2,398' 4,105' 2,318' 2,812' 10,862' 4,142'17,769' 128' 20"x34" 13-3/8" 9-5/8" 2,812' 9-5/8"2,644' 8,218' 2,644' N/A 7074' 4-1/2" N/A 4-1/2" 6th May 2025 10,729'10,729' 4-1/2" 4,066' Perforation Depth MD (ft): 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 WK0DUFK 325-125 By Gavin Gluyas at 2:20 pm, Mar 04, 2025 BJM 4/3/25 X BOP test to 3600 psi. Annular test to 3000 psi SFD 4/4/2025 6th May 2025 10-404 DSR-3/10/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.04 09:43:19 -08'00'04/04/25 RBDMS JSB 040825 Page 1 of 1 04 March 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Sundry Application Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-037 Dear Sir/Madam, Oil Search (Alaska), LLC hereby submits an Application for Sundry Approval to perform a workover on production well NDB-037 to repair the integrity to the production tubing. Pressure communication was observed between the IA and production tubing. Integrity diagnostics were completed with slickline and E- line. The electronic gas lift (EGL) valve located at 3097’ MD was found to be leaking. It is proposed to use Parker Drilling Rig 272 to pull the tubing in order to replace the leaking EGL valve with a 4-1/2” pup joint. Please find enclosed for your review Form 10-403 Application for Sundry Approval in addition to a workover operations summary including current and proposed schematics. If there are any questions and/or additional information desired, please contact me at (907) 343-9737 or rob.williams@santos.com. Respectfully, Rob Williams Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-403 Application for Sundry Approval NDB-037 Workover Operations Summary Page 1 of 1 Packer Set Depths - NDB-037 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole SLZXP Liner Top Hanger Packer w/centralizer 10,716.9 4,062.8 Original Hole HES Zoneguard OH Packer #15 10,979.7 4,133.4 Original Hole HES Zoneguard OH Packer #14 11,046.9 4,146.0 Original Hole HES Zoneguard OH Packer #13 11,463.2 4,167.0 Original Hole HES Zoneguard OH Packer #12 11,530.3 4,166.9 Original Hole HES Zoneguard OH Packer #11 12,028.8 4,164.0 Original Hole HES Zoneguard OH Packer #10 12,570.1 4,162.0 Original Hole HES Zoneguard OH Packer #9 13,109.7 4,160.1 Original Hole HES Zoneguard OH Packer #8 13,733.0 4,158.0 Original Hole HES Zoneguard OH Packer #7 14,185.3 4,154.5 Original Hole HES Zoneguard OH Packer #6 14,724.7 4,152.1 Original Hole HES Zoneguard OH Packer #5 15,262.8 4,151.0 Original Hole HES Zoneguard OH Packer #4 15,801.5 4,148.7 Original Hole HES Zoneguard OH Packer #3 16,257.8 4,146.8 Original Hole HES Zoneguard OH Packer #2 16,878.2 4,144.7 Original Hole HES Zoneguard OH Packer #1 17,375.0 4,143.1 Sundry Application NDB-037 Well 1. NDB-037 Current Status NDB-037 well failed MIT-IA integrity test. Communication was observed from the inner annulus to the tubing string. Integrity diagnostics were completed with Slickline and E-line. Electric Gaslift Valve (EGL valve) located at 3,097' MD was found to be leaking. 2. Workover Operations Summary 1. Open EGL Valve at 3097’ MD – reverse circulate freeze protect out of the well. 2. Pressure test tubing and lower completion against closed 4-1/2” liner down to WIV to 2500psi. 3. Install TWC valve. Pressure test to 2500psi. 4. MIRU Parker Rig 272. [dependent on timing and execution efficiencies Rig 272 may be MIRU before/after/during Steps 1-5]. 5. Nipple down 10k Frac Tree. 6. Nipple up BOP and test to 3600psi. 7. Recover TWC valve. 8. MU THRT, engage tubing hanger and pick up string above liner top. 9. Pull tubing string to ~3200’ MD. 10. Replace EGL gauge TEC wire, splice SLB P/T Gauge TEC wire and replace leaking EGL valve with 4-1/2” pup joint. 11. Run in hole with 4-1/2” 12.6ppf P110S upper completion as per schematic. 12. Land tubing hanger. 13. MIT-T to 3,500 psi. 14. MIT-IA to 4,000 psi. 15. Shear circulation valve. 16. Reverse circulate freeze protect and U-Tube. 17. Install TWCV into the tubing hanger and pressure test to 2500psi. 18. Nipple down BOP stack and install 10k frac tree. 19. RDMO. 3. MASP & BOP Pressure Test, Workover Fluid Details 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,878 psi in the Nanushuk 3.2 at 4,120’ TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,466 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,120’ TVD) Planned BOP test pressure Rams test to 3,600 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Planned Workover Fluid 9.2-9.4ppg NaCl Brine (93-136psi overbalanced to Nanushuk 3.2 at 4,120’ TVD) [Tertiary barrier only] 4. Current and Proposed Schematics NDB-037 Well SchematicAs-Drilled 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2644' MD 13-3/8" 68 ppf L-80 Surface Casing2,812' MD 9-5/8", 47ppf L-80 Production Liner10862 MD 4-½”, 12.6ppf P-110S Production Liner 17,769' MD 4-½” Liner Hanger/ Packer10695' MD GL 9-5/8" 68 ppf L-80 Tieback2644' MD 27.Feb.2025 Archer C-Flex Two-Stage Cementing Tool4,672 MD 9 8 3 4 5 6 7 1 2 8-½” Openhole 17,776'' MD 46.60' RKB – Bottom Flange TOC First Stage Cement 7,985’MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1516 1484 24 3.813 4.790 2 Gaslift Mandrel 1.5" 2150 2009 43 3.865 7.650 3 X Landing Nipple 2220 2059 45 3.813 4.790 4 EGL Valve 3097 2507 71 3.909 6.188 5 EGL Gauge 3165 2528 73 3.892 6.198 6 X Landing Nipple 10410 3975 74 3.813 4.776 7 SSD NERA Gaslift 10473 3993 74 3.813 7.000 8 EGL Valve 10538 4011 73 3.860 5.818 9 D/H Psi-Temp Gauge 10606 4031 73 3.905 6.000 10 X Landing Nipple 10629 4037 73 3.813 4.776 11 Tieback Seal Assy 10729 4066 73 3.908 5.220 12 9.625" x 4.5" LH/Packer 10695 4057 73 6.040 8.480 13 #15 Openhole Packer 10973 4132 78 3.918 8.000 14 #14 Openhole Packer 11040 4145 80 3.918 8.000 15 Stg 13 - Collet Sleeve 12 11188 4163 86 3.735 5.632 16 #13 Openhole Packer 11457 4167 90 3.918 8.000 17 #12 Openhole Packer 11524 4167 90 3.918 8.000 18 Stg 12 - Collet Sleeve 11 11754 4165 90 3.735 5.632 19 #11 Openhole Packer 12022 4164 90 3.918 8.000 20 Stg 11 - Collet Sleeve 10 12294 4163 90 3.735 5.632 21 #10 Openhole Packer 12564 4162 90 3.918 8.000 22 Stg 10 - Collet Sleeve 9 12834 4161 90 3.735 5.630 23 #9 Openhole Packer 13103 4160 90 3.918 8.000 24 Stg 9 - Collet Sleeve 8 13375 4159 90 3.735 5.635 25 #8 Openhole Packer 13726 4158 90 3.918 8.000 26 Stg 8 - Collet Sleeve 7 13915 4157 90 3.735 5.632 27 #7 Openhole Packer 14179 4155 90 3.918 8.000 28 Stg 7 - Collet Sleeve 6 14449 4153 90 3.735 5.632 29 #6 Openhole Packer 14718 4152 90 3.918 8.000 30 Stg 6 - Collet Sleeve 5 14988 4152 90 3.735 5.635 31 #5 Openhole Packer 15256 4151 90 3.918 8.000 32 Stg 5 - Collet Sleeve 4 15526 4150 90 3.735 5.630 33 #4 Openhole Packer 15795 4149 90 3.918 8.000 34 Stg 4 -Collet Sleeve 3 16065 4148 90 3.735 5.630 35 #3 Openhole Packer 16251 4147 90 3.918 8.000 36 Stg 3 - Collet Sleeve 2 16603 4146 90 3.735 5.632 37 #2 Openhole Packer 16872 4145 90 3.918 8.000 38 Stg 2 - Collet Sleeve 1 17142 4144 90 3.735 5.634 39 #1 Openhole Packer 17368 4143 90 3.918 8.000 40 Stg 1 - #2 Toe Sleeve 17679 4142 90 3.500 5.750 41 Stg 1 - #1 Toe Sleeve 17691 4142 90 3.500 5.750 42 WIV Collar 17753 4142 90 0.870 5.610 43 Float Collar 17766 4142 90 3.980 5.220 44 Eccentric shoe 17768 4142 90 3.290 5.190 NDB-037 Well SchematicRWO - Proposed 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2644' MD 13-3/8" 68 ppf L-80 Surface Casing2,812' MD 9-5/8", 47ppf L-80 Production Liner10862 MD 4-½”, 12.6ppf P-110S Production Liner 17,769' MD 4-½” Liner Hanger/ Packer10695' MD GL 9-5/8" 68 ppf L-80 Tieback2644' MD 02.17.2025 Archer C-Flex Two-Stage Cementing Tool4,672 MD 8 7 3 4 5 6 1 2 8-½” Openhole 17,776'' MD 46.60' RKB – Bottom Flange TOC First Stage Cement 7,985’MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1516 1484 24 3.813 4.790 2 Gaslift Mandrel 1.5" 2150 2009 43 3.865 7.650 3 X Landing Nipple 2220 2059 45 3.813 4.790 4 EGL Gauge 3165 2528 73 3.892 6.198 5 X Landing Nipple 10410 3975 74 3.813 4.776 6 SSD NERA Gaslift 10473 3993 74 3.813 7.000 7 EGL Valve 10538 4011 73 3.860 5.818 8 D/H Psi-Temp Gauge 10606 4031 73 3.905 6.000 9 X Landing Nipple 10629 4037 73 3.813 4.776 10 Tieback Seal Assy 10729 4066 73 3.908 5.220 11 9.625" x 4.5" LH/Packer 10695 4057 73 6.040 8.480 12 #15 Openhole Packer 10973 4132 78 3.918 8.000 13 #14 Openhole Packer 11040 4145 80 3.918 8.000 14 Stg 13 - Collet Sleeve 12 11188 4163 86 3.735 5.632 15 #13 Openhole Packer 11457 4167 90 3.918 8.000 16 #12 Openhole Packer 11524 4167 90 3.918 8.000 17 Stg 12 - Collet Sleeve 11 11754 4165 90 3.735 5.632 18 #11 Openhole Packer 12022 4164 90 3.918 8.000 19 Stg 11 - Collet Sleeve 10 12294 4163 90 3.735 5.632 20 #10 Openhole Packer 12564 4162 90 3.918 8.000 21 Stg 10 - Collet Sleeve 9 12834 4161 90 3.735 5.630 22 #9 Openhole Packer 13103 4160 90 3.918 8.000 23 Stg 9 - Collet Sleeve 8 13375 4159 90 3.735 5.635 24 #8 Openhole Packer 13726 4158 90 3.918 8.000 25 Stg 8 - Collet Sleeve 7 13915 4157 90 3.735 5.632 26 #7 Openhole Packer 14179 4155 90 3.918 8.000 27 Stg 7 - Collet Sleeve 6 14449 4153 90 3.735 5.632 28 #6 Openhole Packer 14718 4152 90 3.918 8.000 29 Stg 6 - Collet Sleeve 5 14988 4152 90 3.735 5.635 30 #5 Openhole Packer 15256 4151 90 3.918 8.000 31 Stg 5 - Collet Sleeve 4 15526 4150 90 3.735 5.630 32 #4 Openhole Packer 15795 4149 90 3.918 8.000 33 Stg 4 -Collet Sleeve 3 16065 4148 90 3.735 5.630 34 #3 Openhole Packer 16251 4147 90 3.918 8.000 35 Stg 3 - Collet Sleeve 2 16603 4146 90 3.735 5.632 36 #2 Openhole Packer 16872 4145 90 3.918 8.000 37 Stg 2 - Collet Sleeve 1 17142 4144 90 3.735 5.634 38 #1 Openhole Packer 17368 4143 90 3.918 8.000 39 Stg 1 - #2 Toe Sleeve 17679 4142 90 3.500 5.750 40 Stg 1 - #1 Toe Sleeve 17691 4142 90 3.500 5.750 41 WIV Collar 17753 4142 90 0.870 5.610 42 Float Collar 17766 4142 90 3.980 5.220 43 Eccentric shoe 17768 4142 90 3.290 5.190 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: Well Cleanup 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?Pikka NDB-037 Yes No 9. Property Designation (Lease Number): 10. Field: Pikka Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,776' 4,142' 17,769' 4,142' N/A N/A Casing Collapse Conductor Surface 2260 Intermediate 4750 Tie-Back 4750 Production 9210 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:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone: 907-330-4595 Authorized Title: Completions Specialist 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 01/18/25 17,769'7,074' 4-1/2" 12.6ppf 4,142' See attached packer report 2,644' 8,218' 10,729' Perforation Depth MD (ft): 2,644' 10,729' 4-1/2" 4,063' 2,812' 10,862' 4-1/2" 128' 20"x34" 13-3/8" 9-5/8" 2,812' Tieback MD 6870 5020 6870 2,398' 4,102' 2,318' Length Size Proposed Pools: 128' 128' P-110S TVD Burst 10,729' 11590 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 393023, 391455, 393019, 393018 224-124 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20895-00-00 Oil Search Alaska, LLC AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): See attached packer report Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY 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 12/17/2024 By Grace Christianson at 7:58 am, Dec 18, 2024 324-704 SFD 1/15/2025 Fracture Stimulate 01/18/25 CDW 01/08/2025 393020, 391445 SFD DSR-12/20/24BJM 1/22/25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.23 09:47:19 -09'00'01/23/25 RBDMS JSB 012425 Page 1 of 1 Packer Set Depths - NDB-037 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole SLZXP Liner Top Hanger Packer w/centralizer 10,716.9 4,062.8 Original Hole HES Zoneguard OH Packer #15 10,979.7 4,133.4 Original Hole HES Zoneguard OH Packer #14 11,046.9 4,146.0 Original Hole HES Zoneguard OH Packer #13 11,463.2 4,167.0 Original Hole HES Zoneguard OH Packer #12 11,530.3 4,166.9 Original Hole HES Zoneguard OH Packer #11 12,028.8 4,164.0 Original Hole HES Zoneguard OH Packer #10 12,570.1 4,162.0 Original Hole HES Zoneguard OH Packer #9 13,109.7 4,160.1 Original Hole HES Zoneguard OH Packer #8 13,733.0 4,158.0 Original Hole HES Zoneguard OH Packer #7 14,185.3 4,154.5 Original Hole HES Zoneguard OH Packer #6 14,724.7 4,152.1 Original Hole HES Zoneguard OH Packer #5 15,262.8 4,151.0 Original Hole HES Zoneguard OH Packer #4 15,801.5 4,148.7 Original Hole HES Zoneguard OH Packer #3 16,257.8 4,146.8 Original Hole HES Zoneguard OH Packer #2 16,878.2 4,144.7 Original Hole HES Zoneguard OH Packer #1 17,375.0 4,143.1 Page 1 of 19 NDB-037 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachment B 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBD-037. At the NDB-037 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifer (typically found down to 400 ft depth) are located at the NDB-037 location. 4. Plan for freshwater sampling – There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information – Attachment C 6. Assessment of casing and cementing operations – Attachment C 7. Casing and tubing pressure test information – Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachments D and I 9. Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 975 feet (ft) total vertical depth subsea (TVDSS)/ 975 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 975 to 2,361 ft TVDSS/1,386 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelf setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,361 to 3,071 ft TVDSS/ 710 ft thick Hydrocarbon Zone: 2,421 to 3,071 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,071 to 3,730 ft TVDSS/ 659 ft thick Lithological Description: The Seabee Fm in the Pikka Unit area consists predominantly of claystone, shale, and volcanic tuff deposited in a deep marine setting. The base of the Seabee Fm grades into a condensed organic shale and provides an excellent seal and confining interval above the Nanushuk Fm reservoirs and also acts as a thick second overlying confining unit. Nanushuk Formation Depth/Thickness: 3,730 to 4,684 ft TVDSS/ 954 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Lower Confining Zone Name: Torok Formation Depth/Thickness: 4,684 to 5,583 ft TVDSS/899 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is composed primarily of shale (Hue Shale) with some thin interbedded siltstones. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. 10.Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) MAWP (psi) Stages 1-13 3,800 4,100 8,200 7,400 8,800 8,500 Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft 11.Mechanical condition of wells transecting the confining zones –Fiord 3A, Qugruk 3A, Qugruk 301, NDBi-044, NDBi-030, NDBi-043, NDB-025 are within 1/2-mile radius of NDB-037. Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones. No known faults within ½ mile radius of NDB-037. Please See Attachment B. Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 17,679/17,691 4,142 207 339 40 6,985 10 2 17,142 4,144 219 366 40 6,788 10 3 16,603 4,146 207 375 40 6,685 12 4 16,065 4,148 221 347 40 6,490 12 5 15,526 4,150 235 332 40 6,242 12 6 14,988 4,152 236 312 40 5,936 10 7 14,449 4,153 231 301 40 5,818 12 8 13,915 4,157 231 310 40 5,636 12 9 13,375 4,159 231 304 40 5,414 12 10 12,834 4,161 234 315 40 5,193 12 11 12,294 4,163 234 282 40 4,967 12 12 11,754 4,165 234 280 40 4,779 12 13 11,188 4,163 237 258 40 4,616 12 No known faults within ½ mile radius of NDB-037. Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. 13.Detailed proposed fracturing program –Attachments F & K 14.Well Clean Up procedure –Attachment G Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment H Section (d) Pressure Relieve Valve –Attachment I Proposed Wellbore Schematic –Attachment J Attachment A 3WbFRAGZk^Mk k 4dTFZ[k0>TEWeTGZ[k:`ZI>CFk4dTGZ[k >TEk4XGZ?^WZ[k :GGk'N[^ZNA`^NWTk1N[^k %WQbNQQFk 9NbGZk!ZF>k 3WZ^Mk:QWXFk$>[NTk!Q>[P>k )+6 # /!'6+ 1* 6 6 656 6 -!'.0  + 1* 6 6 6 62(64$,3%6 6 6 66 6 -"'.0 + 1* 6 6 9G k 3W^NCGkWIk 4XFZ>^NWT[k`TEFZkk!!&k kWIk 4NQk:G>ZCMk!Q>[P>k 00&[k:`TEZhk !XXQNC>^NWTkIWZk>k*Z>C^`ZGk:^NS`Q>^NWTkIWZk^MGk 7ZWXW[FEk 3'$k=FQQk 'G>Zk4eTFZk 1>TEWdTFZk :`ZJ>CGk4eTGZk>TEWZk4XGZ>^WZk 4NQk:G>ZCMk !Q>[P>k 11%k4:"kN[k>XXQgNTLkIWZk>k:`TEZgk!XXQNC>^NWTk`TEGZkk!!%k k^Wk XGZIWZSk>kIZ>C^`ZGk[^NR`Q>^NWTkWIk^MGkXZWXW[FEk3'$kdFQQ k;MN[k3W^NCGkN[kAGNTLk[GT^kAhk CGZ^NKGEkS>NQk^WkSFG^k^MFkTW^NKC>^NWTkZFY`NZGSFT^[k`TEFZkk!!%k >k!k>TEkk!"%k >k$ k ;MGkCWSXQG^Gk>XXQNC>^NWTkN[k>b>NQ>AQFk IWZk ZFcNGek`XWTkZFY`F[^ k,IkgW`kdN[Mk^WkZGbNGdk^MGk >XXQNC>^NWTkXQF>[FkCWT^?D^k;NSk-WTF[k0>TEk2>T>LGZk>^k^MGkIWQQWdNTL k ;NSk-WTG[k 1>TEk2>T>LGZk 4NQk:G>ZCMk !Q>[P>k10%k 84k$Wfk k !TCMWZ>LGk!/k k 'NZFC^ k k ^NS OWTG[ [>T^W[ CWRk 4:!k^MZW`LMk>k[F>ZCMkWIk^MGk X`AQNCkZGCWZEkM>[kNEGT^NINGEkgW`k>[k>Tk4eTGZk0>TEWdTGZk :`ZI>CGk5dTGZkWZk4XFZ>^WZk>[kEGINTFEkNTk!4+&%kZFLaQ>^NWT[kdN^MNTkjkSNQGkWIk^MFkXZWXW[FEk 3'$kdGQQk^Z>OGC^WZhk>TEkIZ>C^`ZGk[^NS`Q>^NWT k7QF>[GkCWT^>C^k;NSk[MW`QEkgW`kZGY`NZFk >EEN^NWT>QkNTIWZS>^NWT k :NTCGZFQgk .>DWBk6eHU\k %WSSGZDN>Qk#V@Qi]_k (N[^ZNA`^NWTk1N[^ k!Q>[P>k'NbN[NWTkWIk4NQk>TEk+>[k !ZD^NDk:QWXGk 9FLNWT?Qk&WZX k /``PXNPk%WZX k 4NQk:F>ZDMk!Q>[P>k10&k 9FX[WQk)7k <:!k 00&k 6 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL PO Box 240927 Anchorage, AK 99524 Repsol E&P USA LLC CERTIFIED MAIL Attn: Jeremy McKee 2455 Technology Forest Blvd. The Woodlands, TX 77381 ADL 392991 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.58% DNR - 58.42% ADL 392984 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392968 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392958 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 36.31% DNR - 63.69% ADL 392970 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.29% DNR - 59.71% ADL 393021 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 19.22% DNR - 80.78% ADL 393019 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393018 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 29.67% DNR - 70.33% ADL 393020 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393015 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 31.69% DNR - 68.31% ADL 393016 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% ADL 393011 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 25.71% DNR - 74.29% ADL 393010 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 38.54% DNR - 61.46% U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N005E25 U012N006E28 U012N005E36 U012N006E20 U011N005E01 U012N006E2 U012N005E24 U012N006E31 U011N006E06 U012N006E19 U012N006E30 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD TARGET BOTTOM HOLE SURFACE LOCATION WELL TRAJECTORY .5-MILE BUFFER SANTOS LEASES SECTIONS DATE: 10/24/2024. By: JB 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDB37_well_ownership q GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDB37 WELL AREA Attachment B WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityNDBi-030 ACTIVE 9-5/8" 47ppf 9653 (Nanushuk) 3,796 (Nanushuk) 9950 3,831 logopen hole liner for productionTOC 9,950' & packer @ 11,014'1.9-5/8” x 13-3/8” Primary cement joba.Pump 80 bbls 12.5 ppg tuned spacer, 206bbls 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail. Planned TOC was ~8,450’ MD. b.Liner wiper plug system failure. When lower liner wiper plug landed on landing collar, plug bumped leaving all cement inside 9-5/8" liner. A cleanout run was required to drill out all cement and the landing collar was drilled out. c.A cement retainer was run in the hole and set at 11,160’ MD and a second cement job was pumped through the shoe. Diĸculty establishing good circulation due to 80 bbls of water based 12.5ppg spacer left against formation from initial cement job.d.78bbls 12.5 ppg tuned spacer and 205 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail was circulated through the retainer, and 3 bbls were placed on top of the retainer. Lost 110 bbls after cement entered annulus. 2.9-5/8” 2nd Stage Cement Joba.RIH and open up the Archer CŇex cement tool. Establish circulaƟon and pump 80 bbls 12.5 ppg MudŇush Spacer, 78 bbls 13.5 ppg Tuned spacer 252 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. No losses pumping cement and 26 bbls were lost while displacing. The LTP was set and 50 bbls of cement was circulated to surface while circulating with the Cflex running tool. 3.9-5/8” Cement EvaluaƟon Loga.Baker SoundTrak CBL tool was used to log cement aŌer drilling out cement retainer and Ňoat shoe. The 9-5/8”1st stage cement was logged showing the TOC of the primary job at 9,950' MD. Top of hydrocarbon bearing zone in the Nanushuk was in the NT7 at 10,240' MD.03/26/24, 9-5/8" casing pressure tested to 4150 psi for 30 minutesNDB-025 ACTIVE 9-5/8" 47ppf 6,180' (Nanushuk) 3,758' (Nanushuk) 4,500'3,066'Logopen hole liner for productionTOC 4,500MD' & Packer @ 8,285'For the primary cement job, there is isolation in the upper Nanushuk formations across the hydrocarbon-bearing formations, and well above the planned TOC at 5,567’ MD (250’ TVD above top Nanushuk). This is supported by the CBL log, which indicates good cement throughout the first stage and an estimated TOC at 4,500’ MD. It should be noted that a clear TOC was not logged with the Sonic tool, as partial cement presence was still evident at the top of the logged interval (9-5/8” shoe to 4,500’ MD). The transition from good cement to partial cement was noted at 4,820’ to 4,500’ MD.oTOC was called at 4,500’ MD, as this is the top of the logged interval.oApproval to proceed without a clear TOC on the CBL was received from Mel Rixse with the AOGCC on 10/11/2024.10/31/24, 9-5/8" casing pressure tested to 3,940 psi for 30 minutesFiord 3A Abandonded9-5/8" 53.5ppf to 1,805' MD. 8-1/2 Openhole to TD at 9,148' MDOpen Hole abandoment plugs in reservoir. Cased hole abandonment plugs above hydrocarbon bearing zones.Estimate of Plug 1 from TD to 8,430' MD covering Hydrocarbon Bearning Zone-J-4 (8,770'-8,810'). Estimate of Plug 2 top at 8,010 MD covering Hydrocarbon Bearing Zone-Albian (8,110'-8,130'). For Cement plug 3, A 20 BBL HI Vis pill was placed at 2750 and a cement plug was placed over Hydrocarbon Bearning Zone, K-5 (2,490'-2,700'). Plug 3 was tagged at 2,391'. Cement plug 4 base set at 1905 MD with with cement retainer set at 1,730' MD. Estimated top of cement 4 plug is 1,619' MD. Bridge plug set at 300' MD and covered with surface cement plug rom 35'-300'. Well is fully abandoned. 04/1995Top of hydrocarbon bearing zone in the Nanushuk was in the NT7 at 10,240'MD.oTOC was called at 4,500’ MD, as this is the top of the logged intervalTOC of the primary job at 9,950' MD** * In NDB-030, the top of the HC- bearing zone in the Nanushuk is 10,240' MD (-3,817' TVDSS). SFD * ** The Nanushuk interval is not cement-isolated in plugged and abandoned well Fiord 3A. However, within the Nanushuk opened by Fiord 3A, the strata equivalent to the fracturing interval in NDB-037 lie between 2,200' and 2,300' to the northwest of NDB-037. Such separation is sufficient that Fiord 3A will not interfere with containment of the fluids injected into NDB-037 during the proposed fracturing operations. The Tuluvak is not a significant hydrocarbon-bearing zone in Fiord 3A. The upper half of the Tuluvak is cement- isolated by Plug 3 in Fiord 3A, but the lower half is not. A 750-foot-thick interval of Seabee Shale separates the base of the Tuluvak from the underlying Nanushuk in Fiord 3A. Over the long term, it is anticipated that collapse of the Seabee Shale surrounding casing in Fiord 3A will preclude any out-of- zone migration of fluids during the proposed fracturing opertions in NDB -037. SFD WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityNDBi-043 ACTIVE 9-5/8" 47ppf 4,955 (Nanushuk) 3,795 (Nanushuk) 2,792 2,730 log open hole liner for injectionTOC 2,792 MD' & packer @ 6,071'Lead: 277bbls of 12ppg Tail: 44bbls of 15.3ppg8/21/23, 9-5/8" casing pressure tested to 4,200 psi for 30 minutesQ-301 Abandoned 9-5/8" 47# L-80 4042 (Nanushuk) 3841 (Nanushuk) 3810'3683'logAbandoned with Cased hole cement plugsTOC 3,810' MDQ-301 was an exploration/appraisal well that was drilled in 2015. Itwas hydraulic fractured in the Nanushuk reservoir, flowed back, andplugged and abandoned in the same winter season.• The Nanushuk formation top was identified at 4042’ MD, withNanushuk target formation at 4631’ MD.• 9-5/8” Intermediate casing is set at 5241’ MD in the Nanushukreservoir. The primary cement job has the TOC at 3810’ MD (96.7 bbls13.9ppg Extended Class G), with a second stage cement job from3008’ MD to surface (187 bbls of 12.2ppg Extended Type I/II).• The 4-1/2” production liner in the Nanushuk reservoir is set at 7495’MD. The liner was P&A with a cement retainer set at 4503’ MD and 48bbls squeezed below the retainer (4-1/2” liner volume).• 3 cement abandonment plugs were set in the 9-5/8” casing:1. 1st Plug (300’ above cement retainer): 18 bbls of 15.8 ppg cementlaid above the cement retainer at 4503’.2. 2nd Plug (300’ across 13-3/8” casing shoe): A 9-5/8” bridge plug wasset at 2207’ MD (100’ below the surface casing shoe) with 19.1 bbls of15.6ppg Class G cement plug laid on top of it.Well is fully abandoned. Q3A Abandoned Open Hole 4678 (Nanushuk) 4192' (Nanushuk)4678' 4177' Tag TOC set down 15k with DP.Open Hole Abandonment PlugTOC 4,177' MD• The 8-1/2” open hole section was abandoned with two open hole plugs:1st plug (open hole plug): An open hole balanced cement plugwas attempted to be laid in the well from 10,420’ MD by pumping a136 bbls of 15.8 ppg cement. Cement was pumped with fullreturns, but while laying in the balanced plug in the well the stringincluding the drill pipe and 4-1/2” 2,000’ 12.6 ppf tubing stingerbecame stuck at 10,383’ MD. The pipe was severed at 6,243’ MD.TOC was estimated to be at 8,003’ MD in the annulus and 8,650’MD inside the drill pipe.2.) 2nd plug (open hole balanced plug): A second open holebalanced plug was placed in the well by circulating 73 bbls of 15.8ppg class G cement into the hole at 4950’ MD. TOC was confirmedat 4,177’ MD by tagging and placing 15k WOB several timesWell is fully abandoned. NDBi-044 ACTIVE 9-5/8" 47ppf 9678 (Nanushuk) 3,804 (Nanushuk) 7964 3,496 log open hole liner for productionTOC 7,964' & packer @ 10,823' 1.9-5/8” x 13-3/8” Primary cement job a.Pump 80 bbls 12.5 ppg tuned spacer, 131 bbls 13.0 ppg 400 sxs 1.84 Ō^3/sx EconoCem Tpe I-II lead cement, and 80 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail. Planned TOC was ~8,350’ MD. b.No returns while displacing cement job. Wiper dart #2 was lodged in the liner running tool when it was recovered. The follow liner wiper plug was then found just below the 9-5/8” x 13-3/8” Liner top. A cleanout run was required to push the follow liner wiper plug to bottom and the shoe track was drilled out. Dynamic losses were encountered while drilling the float equipment indicating the lost circulation zone had not been isolated. c.A cement retainer was run in the hole and set at 11,010’ MD and a second cement job was pumped through the shoe d.15bbls 12.0 ppg tuned spacer and 95 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail were circulated through the retainer, and 5 bbls were placed on top of the retainer. 2.9-5/8” Secondary Cement Job a.RIH and open up the Archer CŇex cement tool. Establish circulaƟon and pump 80 bbls 12.5 ppg Tuned spacer 214 bbls 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail. 129 bbls were lost while displacing. The LTP was set and 263 bbls of contaminated mud / cement/ spacer was circulated to surface while circulating with the Cflex running tool. An additional 5 bbls of cement was circulated out off the top of the liner when circulating with the liner running too at the top of the liner. 3.9-5/8” Cement EvaluaƟon Logs a.HES Cast tool was run in the hole on a welltec tractor. The 9-5/8” cement was logged. Showing the TOC of the primary job at 7,964' MD. 01/30/24, 9-5/8" casing pressure tested to 4284 psi for 30 minutes Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensil e (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design x 13-3/8” Casing Shoe: 2,812’ MD x 9-5/8” x 13-3/8” Liner top: 2,644’ MD x 9-5/8” Liner Shoe: 10,862 MD x 9-5/8” Archer Cflex Mechanical Stage tool: 4,672’ MD Geology x Top of Tuluvak TS 790 formation at 4,598’ MD. Significant hydrocarbons are contained only within the upper Tuluvak in the Tuluvak Sand (3,091 MD). x Top of the Nanushuk picked at 9,704 MD. Cement Job Planning/Execution See attached cementing reports starting on the next page for a summary of the work performed. Observations -For the 1st stage of the cement job, we have adequate isolation in the upper Nanushuk formations across the hydrocarbon-bearing formations (top hydrocarbon estimated within NT8 at ~9,950’ MD). This is supported by the CBL log, which indicates good cement throughout the first stage and a TOC at 7,985’ MD. -For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. -Our assessment is that we have adequate isolation across hydrocarbon-bearing formations in the upper Nanushuk formations, as well as adequate isolation for frac operations. The 2 nd stage cement job yielded adequate isolation below, across and above the Tuluvak significant hydrocarbons. Attachment D Attachment E Attachment F Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbFPcWF 253.54040168016804040d Pump CheckWF25 4028032011760134402803200320eDFITWF25 40250570 10500 23940 250 5700 5700 570 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Line out XL XL 25214040 6101680 168000 4061020Stage 1 PAD (PS)XL 2540 225265 8359450 1113000CSG-IV225 83531ScourXL 2540 60325 8952520 136502413 241340/70-CL57 89243ScourXL 2540 120445 10155040 1869013348 1576140/70-CL106 99850Resume PadXL 2540 50495 10652100 207900 15761 50 104861FlatXL 2540 180675 12457560 283507239 23000CSG-IV172 122173FlatXL 2540 200875 14458400 3675022238 45238CSG-IV176 139785FlatXL 2540 2301105 16759660 4641039525 84762CSG-IV188 158597FlatXL 2540 2301335 19059660 5607051585 136348CSG-IV175 1761109FlatXL 2540 2151550 21209030 6510058065 194412CSG-IV154 19151110FlatXL 2540 1801730 23007560 7266052353 246765CSG-IV125 2039120Clear Surface LinesXL 2540 151745 2315630 732900246765 152054130Spacer XL 2540151760 2330630 739200246765 152069140Drop Ball/Collet #1 FP 04031763 2333126 740460 246765 3 2072150Stage 2 PAD (CS#1)XL 2540 2301993 25639660 837060 246765 230 2302160Slow for Seat XL 2518502043 26132100 858060246765 502352170Resume PadXL 2540 12044 261442 858480 246765 1 2353181ScourXL 2540 602104 26742520 883682413 24917840/70-CL57 2411193ScourXL 2540 1202224 27945040 9340813348 26252640/70-CL106 2517200Resume PadXL 2540 502274 28442100 955080262526 502567211FlatXL 2540 1902464 30347980 1034887641 270167CSG-IV182 2748223FlatXL 2540 2152679 32499030 11251823905 294073CSG-IV190 2938235FlatXL 2540 2402919 348910080 12259841243 335316CSG-IV196 3135247FlatXL 2540 2403159 372910080 13267853828 389144CSG-IV183 3318259FlatXL 2540 2203379 39499240 14191859415 448559CSG-IV157 34752610FlatXL 2540 1903569 41397980 14989855261 503820CSG-IV132 3606270Clear Surface LinesXL 2540 153584 4154630 1505280503820 153621280Spacer XL 2540153599 4169630 1511580503820 153636290Drop Ball/Collet #2 FP 04033602 4172126 1512840 503820 3 3639300Stage 3 PAD (CS#2)XL 2540 2223824 43949324 1606080 503820 222 3861310Slow for Seat XL 2518503874 44442100 1627080503820 503911320Resume PadXL 2540 13875 444542 1627500 503820 1 3912FLUIDNeat WaterCOMMENTSSD monitor 30 minPrime and Pressure TestOpen well and open initiator sleeveDisplace PT - Shut down 5 minLoad Stage 1 ball/collet, SD monitor 1H, line up for XL Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water331FlatXL 2540 1604035 46056720 1694706434 510254CSG-IV153 4066342FlatXL 2540 1804215 47857560 17703013887 524141CSG-IV165 4231354FlatXL 2540 2004415 49858400 18543028532 552673CSG-IV170 4401366FlatXL 2540 2004615 51858400 19383039797 592470CSG-IV158 4559378FlatXL 2540 2004815 53858400 20223049585 642056CSG-IV148 47063810FlatXL 2540 2005015 55858400 21063058170 700225CSG-IV138 48453912FlatXL 2540 1805195 57657560 21819059183 759409CSG-IV117 4962400Clear Surface LinesXL 2540 155210 5780630 2188200759409 154977410Spacer XL 2540155225 5795630 2194500759409 154992420Drop Ball/Collet #3 FP 04035228 5798126 2195760 759409 3 4995430Stage 4 PAD (CS#3)XL 2540 2145442 60128988 2285640 759409 214 5209440Slow for Seat XL 2518505492 60622100 2306640759409 505259450Resume PadXL 2540 65498 6068252 2309160 759409 6 5265461FlatXL 2540 1605658 62286720 2376366434 765843CSG-IV153 5418472FlatXL 2540 1805838 64087560 24519613887 779730CSG-IV165 5584484FlatXL 2540 2006038 66088400 25359628532 808262CSG-IV170 5754496FlatXL 2540 2006238 68088400 26199639797 848059CSG-IV158 5911508FlatXL 2540 2006438 70088400 27039649585 897644CSG-IV148 60595110FlatXL 2540 2006638 72088400 27879658170 955814CSG-IV138 61985212FlatXL 2540 1806818 73887560 28635659183 1014997CSG-IV117 6315530Clear Surface LinesXL 2540 156833 7403630 2869860 1014997 15 6330540Spacer XL 2540156848 7418630 2876160 1014997 15 6345550Drop Ball/Collet #4 FP 04036851 7421126 2877420 1014997 3 6348560Stage 5 PAD (CS#4)XL 2540 2067057 76278652 2963940 1014997 206 6554570Slow for Seat XL 2518507107 76772100 2984940 1014997 50 6604580Resume PadXL 2540 447151 77211848 3003420 1014997 44 6648591FlatXL 2540 1807331 79017560 3079027239 1022236CSG-IV172 6820602FlatXL 2540 2007531 81018400 31630215430 1037666CSG-IV184 7004614FlatXL 2540 2207751 83219240 32554231385 1069051CSG-IV187 7191626FlatXL 2540 2207971 85419240 33478243777 1112828CSG-IV174 7365638FlatXL 2540 2208191 87619240 34402254544 1167371CSG-IV162 75276410FlatXL 2540 2008391 89618400 35242258170 1225541CSG-IV138 76656512FlatXL 2540 1808571 91417560 35998259183 1284725CSG-IV117 7783660Clear Surface LinesXL 2540 158586 9156630 3606120 1284725 15 7798670Spacer XL 2540158601 9171630 3612420 1284725 15 7813680Drop Ball/Collet #5 FP 04038604 9174126 3613680 1284725 3 7816690LG FlushWF 2540 1988802 93728316 3696840 1284725 198 8014700Slow for seat WF 2518508852 94222100 3717840 1284725 50 8064710Overflush/ MT PCMWF 254020090529622840038018401284725200826472Linear FlushWF 252019053917542 4041661826573Linear FlushWF 252019054917642 40420818266743000 feet MD + Surface EqmtFP20 589112 92342423 406631 Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat WaterTOTALS9682 4066311284725SD and obtain ISIP & 15 min SIP. Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbWF 253.54000000cPump Ball to SeatWF25 422522594509450225225dPump CheckWF25 401001004200136501003250 3250 325 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Line out XL XL 25404040 2651680 168000 4036520Stage 6 PAD (CS#5)XL 2540 250290 51510500 1218000CSG-IV250 61531ScourXL 2540 60350 5752520 147002413 241340/7057 67243ScourXL 2540 120470 6955040 1974013348 1576140/70106 77850Resume PadXL 2540 50520 7452100 218400 15761 50 82861FlatXL 2540 190710 9357980 298207641 23402CSG-IV182 101073FlatXL 2540 210920 11458820 3864023349 46752CSG-IV185 119685FlatXL 2540 2351155 13809870 4851040384 87135CSG-IV192 138897FlatXL 2540 2351390 16159870 5838052707 139842CSG-IV179 1567109FlatXL 2540 2201610 18359240 6762059415 199257CSG-IV157 17241110FlatXL 2540 1901800 20257980 7560055261 254519CSG-IV132 1856120Clear Surface LinesXL 2540 151815 2040630 762300254519 151871130Spacer XL 2540151830 2055630 768600254519 151886140Drop Ball/Collet #6 FP 04031833 2058126 769860 254519 3 1889150Stage 7 PAD (CS#6)XL 2540 1902023 22487980 849660 254519 190 2079160Slow for Seat XL 2518502073 22982100 870660254519 502129170Resume PadXL 2540 102083 2308420 874860254519 102139181FlatXL 2540 1502233 24586300 937866032 260551CSG-IV144 2283192FlatXL 2540 1752408 26337350 10113613501 274052CSG-IV161 2443204FlatXL 2540 1902598 28237980 10911627106 301157CSG-IV161 2605216FlatXL 2540 1902788 30137980 11709637807 338964CSG-IV150 2755228FlatXL 2540 1902978 32037980 12507647106 386070CSG-IV140 28952310FlatXL 2540 1903168 33937980 13305655261 441332CSG-IV132 30262412FlatXL 2540 1603328 35536720 13977652608 493939CSG-IV104 3131250Clear Surface LinesXL 2540 153343 3568630 1404060493939 153146260Spacer XL 2540153358 3583630 1410360493939 153161270Drop Ball/Collet #7 FP 04033361 3586126 1411620 493939 3 3164280Stage 8 PAD (CS#7)XL 2540 1813542 37677602 1487640 493939 181 3345290Slow for Seat XL 2518503592 38172100 1508640493939 503395300Resume PadXL 2540 193611 3836798 1516620493939 193414311FlatXL 2540 1603771 39966720 1583826434 500373CSG-IV153 3567322FlatXL 2540 1803951 41767560 16594213887 514260CSG-IV165 3732334FlatXL 2540 2004151 43768400 17434228532 542792CSG-IV170 3902FLUIDNeat WaterCOMMENTSPrime and Pressure TestDisplace PT - Shut down 10 minDrop Ball-SD 10 minutesLoad ball/collet#6 (Stage 7), Stage to Line out XL Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water346FlatXL 2540 2004351 45768400 18274239797 582589CSG-IV158 4060358FlatXL 2540 2004551 47768400 19114249585 632174CSG-IV148 42083610FlatXL 2540 2004751 49768400 19954258170 690344CSG-IV138 43463712FlatXL 2540 1804931 51567560 20710259183 749528CSG-IV117 4464380Clear Surface LinesXL 2540 154946 5171630 2077320749528 154479390Spacer XL 2540154961 5186630 2083620749528 154494400Drop Ball/Collet #8 FP 04034964 5189126 2084880 749528 3 4497410Stage 9 PAD (CS#8)XL 2540 1735137 53627266 2157540 749528 173 4670420Slow for Seat XL 2518505187 54122100 2178540749528 504720430Resume PadXL 2540 275214 54391134 2189880749528 274747441FlatXL 2540 1605374 55996720 2257086434 755962CSG-IV153 4900452FlatXL 2540 1805554 57797560 23326813887 769849CSG-IV165 5065464FlatXL 2540 2005754 59798400 24166828532 798381CSG-IV170 5235476FlatXL 2540 2005954 61798400 25006839797 838178CSG-IV158 5393488FlatXL 2540 2006154 63798400 25846849585 887763CSG-IV148 55404910FlatXL 2540 2006354 65798400 26686858170 945933CSG-IV138 56795012FlatXL 2540 1806534 67597560 27442859183 1005116CSG-IV117 5796510Clear Surface LinesXL 2540 156549 6774630 2750580 1005116 15 5811520Spacer XL 2540156564 6789630 2756880 1005116 15 5826530Drop Ball/Collet #9 FP 04036567 6792126 2758140 1005116 3 5829540Stage 10 PAD (CS#9)XL 2540 1656732 69576930 2827440 1005116 165 5994550Slow for Seat XL 2518506782 70072100 2848440 1005116 50 6044560Resume PadXL 2540 606842 70672520 2873640 1005116 60 6104571FlatXL 2540 1807022 72477560 2949247239 1012355CSG-IV172 6277582FlatXL 2540 2007222 74478400 30332415430 1027785CSG-IV184 6460594FlatXL 2540 2207442 76679240 31256431385 1059170CSG-IV187 6647606FlatXL 2540 2207662 78879240 32180443777 1102947CSG-IV174 6821618FlatXL 2540 2207882 81079240 33104454544 1157490CSG-IV162 69836210FlatXL 2540 2008082 83078400 33944458170 1215660CSG-IV138 71226312FlatXL 2540 1808262 84877560 34700459183 1274844CSG-IV117 7239640Clear Surface LinesXL 2540 158277 8502630 3476340 1274844 15 7254650Spacer XL 2540158292 8517630 3482640 1274844 15 7269660Drop Ball/Collet #10 FP 04038295 8520126 3483900 1274844 3 7272670LG FlushWF 2540 1578452 86776594 3549840 1274844 157 7429680Slow for seat WF 2518508502 87272100 3570840 1274844 50 7479690Overflush/ MT PCMWF 254020087028927840036548401274844200767970LG FlushWF 252018703872842 3791761768071LG FlushWF 252018704872942 37921817681723000 feet MD + Surface EqmtFP20 588762 87872423 381641TOTALS9087 3816411274844SD and obtain ISIP & 15 min SIP. Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbWF 253.54000000cPump Ball to SeatWF25 419019079807980190190dPump CheckWF25 401001004200121801002900 2900 290 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Line out XL XL 25404040 2301680 168000 4033020Stage 11 PAD (CS#10)XL 2540 210250 4408820 1050000CSG-IV210 54031ScourXL 2540 60310 5002520 130202413 241340/7057 59743ScourXL 2540 120430 6205040 1806013348 1576140/70106 70350Resume PadXL 2540 50480 6702100 201600 15761 50 75361FlatXL 2540 140620 8105880 260405630 21391CSG-IV134 88772FlatXL 2540 160780 9706720 3276012344 33735CSG-IV147 103484FlatXL 2540 180960 11507560 4032025679 59414CSG-IV153 118796FlatXL 2540 1801140 13307560 4788035817 95231CSG-IV142 1329108FlatXL 2540 1801320 15107560 5544044627 139858CSG-IV133 14621110FlatXL 2540 1701490 16807140 6258049444 189302CSG-IV118 15801212FlatXL 2540 1501640 18306300 6888049320 238622CSG-IV98 1678130Clear Surface LinesXL 2540 151655 1845630 695100238622 151693140Spacer XL 2540151670 1860630 701400238622 151708150Drop Ball/Collet #11 FP 04031673 1863126 702660 238622 3 1711160Stage 12 PAD (CS#11)XL 2540 1491822 20126258 765240 238622 149 1860170Slow for Seat XL 2518501872 20622100 786240238622 501910180Resume PadXL 2540 11873 206342 786660 238622 1 1911191ScourXL 2540 601933 21232520 811862413 24103540/7057 1968203ScourXL 2540 1202053 22435040 8622613348 25438340/70106 2074210Resume PadXL 2540 502103 22932100 883260254383 502124221FlatXL 2540 1502253 24436300 946266032 260415CSG-IV144 2268232FlatXL 2540 1752428 26187350 10197613501 273916CSG-IV161 2429244FlatXL 2540 1902618 28087980 10995627106 301022CSG-IV161 2590256FlatXL 2540 1902808 29987980 11793637807 338829CSG-IV150 2740268FlatXL 2540 1902998 31887980 12591647106 385935CSG-IV140 28802710FlatXL 2540 1903188 33787980 13389655261 441196CSG-IV132 30122812FlatXL 2540 1603348 35386720 14061652608 493804CSG-IV104 3116290Clear Surface LinesXL 2540 153363 3553630 1412460493804 153131300Spacer XL 2540153378 3568630 1418760493804 153146310Drop Ball/Collet #12 FP 04033381 3571126 1420020 493804 3 3149320Stage 13 PAD (CS#12)XL 2540 1393520 37105838 1478400 493804 139 3288330Slow for Seat XL 2518503570 37602100 1499400493804 503338FLUIDNeat WaterCOMMENTSPrime and Pressure TestDisplace PT - Shut down 10 minDrop Ball-SD 10 minutesLoad ball/collet#11 (Stage 12), Stage to Line out XL Well NameNDB-03711/05/24 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water340Resume PadXL 2540 113581 3771462 1504020493804 113349351ScourXL 2540 603641 38312520 1529222413 49621740/7057 3406363ScourXL 2540 1203761 39515040 15796213348 50956540/70106 3512370Resume PadXL 2540 503811 40012100 1600620509565 503562381FlatXL 2540 1753986 41767350 1674127038 516603CSG-IV168 3730392FlatXL 2540 1904176 43667980 17539214658 531261CSG-IV175 3904404FlatXL 2540 1904366 45567980 18337227106 558366CSG-IV161 4066416FlatXL 2540 1904556 47467980 19135237807 596173CSG-IV150 4216428FlatXL 2540 1904746 49367980 19933247106 643280CSG-IV140 43564310FlatXL 2540 954841 50313990 20332227631 670910CSG-IV66 44224410FlatXL 2540 954936 51263990 20731227661 69857112/1866 44884512FlatXL 25401605096528667202140325267275124312/18105459246XLFlushXL 254020 5116 5306840 22705220 461247LG FlushWF 254090 5206 53963780 23083290 4702483000 feet MD + Surface EqmtFP20 585264 54542423 233255TOTALS5554 233255751243SD and obtain ISIP & 15 min SIP. Additive Additive Description F103 Surfactant 1.0 Gal/mGal 865.5 gal J450 Stabilizing Agent 0.5 Gal/mGal 432.7 gal J475 Breaker J475 6.0 lb/mGal 5,193.0 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,731.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,939.7 gal J580 Gel J580 25.0 lb/mGal 21,637.4 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 43.3 gal M117 Clay Control Agent 339.0 lb/mGal 293,388.0 lbm M275 Bactericide 0.3 lb/mGal 259.6 lbm S522-1218 Propping Agent varied concentrations 80,333.0 lbm S522-1620 Propping Agent varied concentrations 2,947,757.0 lbm S522-4070 Propping Agent varied concentrations 94,566.0 lbm S901 Proppant with Scale Inhibitor S901 varied concentrations 188,155.0 lbm ~ 66 % ~ 31 % ~ 3 % < 1 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % 100 % State:Alaska County/Parish:North Slope Borough Case: Client:Oil Search Alaska Well:NDB-037 Basin/Field:Pikka Report ID:RPT-1968 Fluid Name & Volume Concentration Volume Disclosure Type:Pre-Job Well Completed: Date Prepared:11/12/2024 CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF125 ST:WF125 865,494 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate 7647-14-5 Sodium chloride 102-71-6 2,2`,2"-nitrilotriethanol 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum 1303-96-4 Sodium tetraborate decahydrate 50-70-4 Sorbitol 67-63-0 Propan-2-ol 7727-54-0 Diammonium peroxodisulphate 56-81-5 1, 2, 3 - Propanetriol 9003-35-4 Phenolic resin 68131-39-5 Ethoxylated Alcohol 9025-56-3 Hemicellulase 91053-39-3 Diatomaceous earth, calcined 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 9002-84-0 poly(tetrafluoroethylene) 10377-60-3 Magnesium nitrate 111-42-2 2,2'-Iminodiethanol 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 14807-96-6 Magnesium silicate hydrate (talc) 9000-90-2 Amylase, alpha 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 127-08-2 Acetic acid, potassium salt (impurity) Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate # SLB-Private Page: 1 / 1 Updated 11/03/2024INPUTTBDAK TSCA StatusNorthSlope AKTBDPre750,00073.00000%8,555,670Trade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SME Tracerco Carrier Fluid Soy Methyl Ester 67784-80-9 100 0.0011131751 95.2395840000T-731 Tracerco Chemical Tracer 1-Bromo-3,5-dichlorobenzene 19752-55-7 100 0.0000051536 0.4409240000T-162A Tracerco Chemical Tracer 1,4-Dibromobenzene 106-37-6 100 0.0000128840 1.1023100000T-748 Tracerco Chemical Tracer 1-Bromo-2-chlorobenzene 694-80-4 100 0.0000257679 2.2046200000T-165G Tracerco Chemical Tracer 2-Bromofluorene 1133-80-8 100 0.0000103072 0.8818480000T-706 Tracerco Chemical Tracer 1-Bromo-4-chlorobenzen 106-39-8 100 0.0000257679 2.2046200000T-776 Tracerco Chemical Tracer 1,4-Dibromonaphthalene 83-53-4 100 0.0000077304 0.6613860000T-165C Tracerco Chemical Tracer 9-Bromophenanthrene 573-17-1 100 0.0000077304 0.6613860000T-751 Tracerco Chemical Tracer Bis(4-bromophenyl)ether 2050-47-7 100 0.0000180376 1.5432340000T-160B Tracerco Chemical Tracer 3,5-Dibromotoluene 1611-92-3 100 0.0000128840 1.1023100000T-163B Tracerco Chemical Tracer 1,2-Diiodobenzene 615-42-9 100 0.0000051536 0.4409240000T-784 Tracerco Chemical Tracer 2,4,6-Tribromoanisole 607-99-8 100 0.0000051536 0.4409240000T-160D Tracerco Chemical Tracer 2,4,5-Tribromotoluene 3278-88-4 100 0.0000077304 0.6613860000T-719 Tracerco Chemical Tracer 3,4-Dichlorobenzophenone 6284-79-3 101 0.0000051536 0.4409240000T-750 Tracerco Chemical Tracer 1,4-Dibromo-2-fluorobenzene 1435-52-5 100 0.0002576794 22.0462000000T-721 Tracerco Chemical Tracer 4,4'-Dichlorobenzophenone 90-98-2 100 0.0002576794 22.0462000000T-734 Tracerco Chemical Tracer 1-Bromo-2-(trifluoromethyl)benzene392-83-6 100 0.0002576794 22.0462000000Water Tracerco Carrier Fluid Water 7732-18-5 100 0.0010551972 90.2791890000T-801 Tracerco Chemical Tracer Sodium-2-chlorobenzoate 17264-74-3 100 0.0000090188 0.7716170000T-913 Tracerco Chemical Tracer Sodium-2-chloro-6-fluorobenzoate 1382106-10-6 100 0.0000090188 0.7716170000T-804 Tracerco Chemical Tracer Sodium-2,3-dichlorobenzoate 118537-84-1 100 0.0000090188 0.7716170000T-808 Tracerco Chemical Tracer Sodium-3,4-dichlorobenzoate 17274-10-1 100 0.0000090188 0.7716170000T-176a Tracerco Chemical Tracer Sodium-2,3,4-trifluorobenzoate 402955-41-3 100 0.0000090188 0.7716170000T-912 Tracerco Chemical Tracer Sodium-2-chloro-5-fluorobenzoate 1382106-79-7 100 0.0000090188 0.7716170000T-920 Tracerco Chemical Tracer Sodium-5-chloro-2-fluorobenzoate 1382106-78-6 101 0.0000090188 0.7716170000T-925 Tracerco Chemical Tracer Sodium-4-fluoro-3-methylbenzoate 1431868-18-6 100 0.0000090188 0.7716170000T-158e Tracerco Chemical Tracer Sodium-3,5-Difluorobenzoate 530141-39-0 100 0.0000090188 0.7716170000T-257a Tracerco Chemical Tracer Sodium-3,5-di(Trifluoromethyl)benzoate 87441-96-1 100 0.0000090188 0.7716170000T-914 Tracerco Chemical Tracer Sodium-2-chloro-4,5-difluorobenzoate 1421761-16-1 100 0.0000090188 0.7716170000Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)County:API Number:Operator Name: Santos AKWell Name and Number: NDB-037 - 13 stagesHydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState:Approved For Tracerco T-928 Tracerco Chemical Tracer Sodium-2-fluoro-4-methylbenzoate 1708942-19-1 100 0.0000090188 0.7716170000T-916 Tracerco Chemical Tracer Sodium-3-chloro-2,4-difluorobenzoate 1396762-34-7 100 0.0000090188 0.7716170000 Attachment G NDB-037 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: x Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. x Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. x Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. x Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. x Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 g Attachment H NDB-037 4-1/2” Production Liner Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P-110S TSH563 lower completions per tally. 2. Circulate out 9.8 ppg OBM with 9.8 ppg NaCl brine to surface. 3. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 4. Pressure up to close the WIV at 1,980 psi. 5. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 6. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. 7. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi for 10 minutes. 8. Release running tool from liner hanger. 9. Circulate 9.4 ppg NaCl Corrosion Inhibited brine with biocide to surface at 10 bpm pump rate. 10.POOH with liner hanger running tool. 11.Prepare to run upper completion. NDB-037 4-1/2” Upper Completion Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 2. Land tubing hanger. 3. MIT-T to 3,500 psi. (Post drilling rig move, MIT-T to be tested to 5,200 psi) a. (8,500 psi MAWP – 3,800 psi IA hold) * 1.1 = 5,200 psi 4. MIT-IA to 4,000 psi. (Post drilling rig move, MIT-IA to be tested to 4,300 psi) 5. Shear circulation valve. 6. Reverse circulate freeze protect and U-Tube. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k frac tree. 9. RDMO NDB-037 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment I Attachment J Attachment K FracCADE* STIMULATION PROPOSAL Operator :Oil Search Well :NDB-037 Field :Pikka Formation :Nanushuk Stages 1 to 13 County : North Slope State : Alaska Country : United States Prepared for : Scott Leahy Service Point : Prudhoe Bay, Alaska Business Phone : 1 907 659 2434 Date Prepared : 11-13-2024 FAX No. : 1 907 659 2538 Prepared by : Laura Acosta Phone : E-Mail Address :NTrevino2@slb.com * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. 1 SLB Private Attachment K Section 1: Zone Data (Stage 1; 17679 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4053.6 10.0 0.72 2937 1.46E+06 0.220 2500 Shale 4063.6 15.0 0.70 2829 1.76E+06 0.220 2500 Nanushuk 3 SS 4078.6 15.3 0.68 2770 1.90E+06 0.220 2000 Top Nan 4093.9 6.0 0.64 2630 8.39E+05 0.270 1000 Shale 4099.9 2.0 0.70 2858 2.67E+06 0.230 2500 Nan DS 4101.9 1.5 0.63 2584 8.19E+05 0.270 1500 Nan DS 4103.4 2.0 0.64 2615 1.22E+06 0.260 1500 Nan CS 4105.4 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4118.4 1.5 0.61 2524 1.00E+06 0.270 1000 Nan CS 4119.9 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4123.9 9.0 0.61 2506 1.17E+06 0.270 1000 Nan CS 4132.9 7.0 0.64 2659 7.69E+05 0.270 1000 Nan CS 4139.9 5.5 0.61 2543 1.28E+06 0.260 1000 Nan CS 4145.4 13.0 0.64 2665 6.92E+05 0.280 1000 Nan DS 4158.4 2.5 0.68 2824 1.75E+06 0.260 1500 Nan DS 4160.9 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4173.4 4.0 0.69 2889 1.69E+06 0.260 1500 Nan DS 4177.4 2.5 0.64 2675 8.22E+05 0.270 1500 Shale 4179.9 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4181.9 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4185.9 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4189.9 4.0 0.70 2921 2.67E+06 0.230 2500 Nan DS 4193.9 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4199.9 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4201.9 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4203.9 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4210.4 4.0 0.61 2582 8.99E+05 0.270 1500 Nan DS 4214.4 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4217.9 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4219.9 12.5 0.64 2696 1.56E+06 0.260 1500 Nan DS 4232.4 2.0 0.65 2747 1.40E+06 0.260 1500 Shale 4234.4 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4236.4 2.0 0.65 2759 1.24E+06 0.260 1500 Shale 4238.4 8.0 0.69 2923 2.67E+06 0.230 2500 Nan DS 4246.4 2.0 0.63 2689 9.33E+05 0.270 1500 Shale 4248.4 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4252.4 6.0 0.65 2749 1.43E+06 0.260 1500 Shale 4258.4 8.0 0.70 2967 2.67E+06 0.230 2500 Nan DS 4266.4 6.5 0.65 2766 1.47E+06 0.260 1500 Shale 4272.9 6.0 0.69 2946 2.67E+06 0.230 2500 Nan DS 4278.9 2.0 0.64 2726 8.38E+05 0.270 1000 Shale 4280.9 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4282.9 4.0 0.65 2785 1.47E+06 0.260 1500 Shale 4286.9 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4288.9 6.0 0.66 2849 1.55E+06 0.260 1500 Shale 4294.9 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4306.9 2.5 0.64 2754 1.21E+06 0.270 1500 Shale 4309.4 20.0 0.69 2976 2.67E+06 0.230 2500 Zone Name Poisson’ s Ratio Formation Mechanical Properties 2 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4053.6 10.0 0.001 1.0 1881 4063.6 15.0 0.001 1.0 1886 4078.6 15.3 0.005 10.0 1890 4093.9 6.0 56.445 22.0 1882 4099.9 2.0 0.001 1.0 1884 4101.9 1.5 109.347 15.0 1885 4103.4 2.0 4.377 15.0 1886 4105.4 13.0 42.829 22.0 1887 4118.4 1.5 11.097 22.0 1893 4119.9 4.0 91.857 22.0 1894 4123.9 9.0 4.906 22.0 1896 4132.9 7.0 12.361 22.0 1900 4139.9 5.5 2.537 22.0 1903 4145.4 13.0 61.847 22.0 1906 4158.4 2.5 0.081 15.0 1912 4160.9 12.5 22.858 15.0 1913 4173.4 4.0 0.018 15.0 1919 4177.4 2.5 94.329 15.0 1920 4179.9 2.0 0.001 1.0 1922 4181.9 4.0 45.186 15.0 1922 4185.9 4.0 24.865 15.0 1924 4189.9 4.0 0.001 1.0 1926 4193.9 6.0 6.405 15.0 1928 4199.9 2.0 0.001 1.0 1931 4201.9 2.0 13.686 15.0 1932 4203.9 6.5 0.229 15.0 1933 4210.4 4.0 49.420 15.0 1936 4214.4 3.5 63.759 15.0 1938 4217.9 2.0 0.001 1.0 1939 4219.9 12.5 1.337 15.0 1940 4232.4 2.0 1.843 15.0 1946 4234.4 2.0 0.001 1.0 1947 4236.4 2.0 4.320 15.0 1948 4238.4 8.0 0.001 1.0 1949 4246.4 2.0 91.060 15.0 1952 4248.4 4.0 0.001 1.0 1953 4252.4 6.0 4.551 15.0 1955 4258.4 8.0 0.001 1.0 1958 4266.4 6.5 7.953 15.0 1962 4272.9 6.0 0.001 1.0 1965 4278.9 2.0 24.687 15.0 1967 4280.9 2.0 0.001 1.0 1968 4282.9 4.0 2.159 10.0 1969 4286.9 2.0 0.001 1.0 1971 4288.9 6.0 1.534 10.0 1972 4294.9 12.0 0.001 1.0 1975 4306.9 2.5 5.632 10.0 1980 4309.4 20.0 0.001 1.0 1982 Nan DS Nan DS Shale Nan CS Nan CS Nan CS Nan CS Nan CS Nan CS Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan Shale Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Shale Nan DS Shale Nan DS Shale 3 SLB Private Attachment K Section 2: Propped Fracture Schedule (Stage 1; 17679 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 225.0 25 0 1.0 PPA Scour 40 YF125ST 57.5 25 1 3.0 PPA Scour 40 YF125ST 106.1 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 269.3 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1701.3 of YF125ST 0 bbl of WF125 231800 lb of 15780 lb of % PAD Clean 15.7 % PAD Dirty 13.3 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 9450.0 9450 225 225 0 0 4233 5.6 5.6 1.0 PPA Scou 2414.3 11864 60 285 2414 2414 4233 1.5 7.1 3.0 PPA Scou 4455.1 16319 120 405 13365 15780 4307 3.0 10.1 Resume PAD 2100.0 18419 50 455 0 15780 4417 1.3 11.4 1.0 PPA 7243.0 25662 180 635 7243 23023 4597 4.5 15.9 3.0 PPA 7425.1 33088 200 835 22275 45298 4548 5.0 20.9 5.0 PPA 7925.7 41013 230 1065 39628 84926 5181 5.8 26.6 7.0 PPA 7394.7 48408 230 1295 51763 136689 5951 5.8 32.4 9.0 PPA 6478.3 54886 215 1510 58305 194994 6518 5.4 37.8 10.0 PPA 5258.6 60145 180 1690 52586 247580 6876 4.5 42.3 Flush 11311.2 71456 269 1960 0 247580 6222 6.7 49.0 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 339.2 ft with an average conductivity (Kfw) of 19956.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Pad Percentages Job Execution Step Name 0 Carbolite 40/70 Carbolite 40/70 0 Carbolite 16/20 + 6wt% ScaleGuard IV 0 Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV 4 SLB Private Attachment K Section 3: Propped Fracture Simulation (Stage 1; 17679 ft MD) Initial Fracture Top TVD 4059.2 ft Initial Fracture Bottom TVD 4266.1 ft Propped Fracture Half-Length 339.2 ft EOJ Hyd Height at Well 207 ft Average Propped Width 0.224 in Net Pressure 414 psi Max Surface Pressure 6985 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 84.8 9.4 0.283 118.1 2.45 241.2 26189 84.8 169.6 7.8 0.264 177.8 2.34 268.6 23982 169.6 254.4 6 0.227 162.7 2.06 318.7 20352 254.4 339.2 2.3 0.143 128.2 1.3 427.9 12240 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 5 SLB Private Attachment K Section 4: Zone Data (Stage 2; 17139 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4053.6 10.0 0.72 2937 1.46E+06 0.220 2500 Shale 4063.6 15.0 0.70 2829 1.76E+06 0.220 2500 Nanushuk 3 SS 4078.6 15.3 0.68 2770 1.90E+06 0.220 2000 Top Nan 4093.9 6.0 0.64 2630 8.39E+05 0.270 1000 Shale 4099.9 2.0 0.70 2858 2.67E+06 0.230 2500 Nan DS 4101.9 1.5 0.63 2584 8.19E+05 0.270 1500 Nan DS 4103.4 2.0 0.64 2615 1.22E+06 0.260 1500 Nan CS 4105.4 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4118.4 1.5 0.61 2524 1.00E+06 0.270 1000 Nan CS 4119.9 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4123.9 9.0 0.61 2506 1.17E+06 0.270 1000 Nan CS 4132.9 7.0 0.64 2659 7.69E+05 0.270 1000 Nan CS 4139.9 5.5 0.61 2543 1.28E+06 0.260 1000 Nan CS 4145.4 13.0 0.64 2665 6.92E+05 0.280 1000 Nan DS 4158.4 2.5 0.68 2824 1.75E+06 0.260 1500 Nan DS 4160.9 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4173.4 4.0 0.69 2889 1.69E+06 0.260 1500 Nan DS 4177.4 2.5 0.64 2675 8.22E+05 0.270 1500 Shale 4179.9 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4181.9 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4185.9 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4189.9 4.0 0.70 2921 2.67E+06 0.230 2500 Nan DS 4193.9 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4199.9 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4201.9 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4203.9 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4210.4 4.0 0.61 2582 8.99E+05 0.270 1500 Nan DS 4214.4 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4217.9 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4219.9 12.5 0.64 2696 1.56E+06 0.260 1500 Nan DS 4232.4 2.0 0.65 2747 1.40E+06 0.260 1500 Shale 4234.4 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4236.4 2.0 0.65 2759 1.24E+06 0.260 1500 Shale 4238.4 8.0 0.69 2923 2.67E+06 0.230 2500 Nan DS 4246.4 2.0 0.63 2689 9.33E+05 0.270 1500 Shale 4248.4 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4252.4 6.0 0.65 2749 1.43E+06 0.260 1500 Shale 4258.4 8.0 0.70 2967 2.67E+06 0.230 2500 Nan DS 4266.4 6.5 0.65 2766 1.47E+06 0.260 1500 Shale 4272.9 6.0 0.69 2946 2.67E+06 0.230 2500 Nan DS 4278.9 2.0 0.64 2726 8.38E+05 0.270 1000 Shale 4280.9 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4282.9 4.0 0.65 2785 1.47E+06 0.260 1500 Shale 4286.9 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4288.9 6.0 0.66 2849 1.55E+06 0.260 1500 Shale 4294.9 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4306.9 2.5 0.64 2754 1.21E+06 0.270 1500 Shale 4309.4 20.0 0.69 2976 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 6 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4053.6 10.0 0.001 1.0 1881 4063.6 15.0 0.001 1.0 1886 4078.6 15.3 0.005 10.0 1890 4093.9 6.0 56.445 22.0 1882 4099.9 2.0 0.001 1.0 1884 4101.9 1.5 109.347 15.0 1885 4103.4 2.0 4.377 15.0 1886 4105.4 13.0 42.829 22.0 1887 4118.4 1.5 11.097 22.0 1893 4119.9 4.0 91.857 22.0 1894 4123.9 9.0 4.906 22.0 1896 4132.9 7.0 12.361 22.0 1900 4139.9 5.5 2.537 22.0 1903 4145.4 13.0 61.847 22.0 1906 4158.4 2.5 0.081 15.0 1912 4160.9 12.5 22.858 15.0 1913 4173.4 4.0 0.018 15.0 1919 4177.4 2.5 94.329 15.0 1920 4179.9 2.0 0.001 1.0 1922 4181.9 4.0 45.186 15.0 1922 4185.9 4.0 24.865 15.0 1924 4189.9 4.0 0.001 1.0 1926 4193.9 6.0 6.405 15.0 1928 4199.9 2.0 0.001 1.0 1931 4201.9 2.0 13.686 15.0 1932 4203.9 6.5 0.229 15.0 1933 4210.4 4.0 49.420 15.0 1936 4214.4 3.5 63.759 15.0 1938 4217.9 2.0 0.001 1.0 1939 4219.9 12.5 1.337 15.0 1940 4232.4 2.0 1.843 15.0 1946 4234.4 2.0 0.001 1.0 1947 4236.4 2.0 4.320 15.0 1948 4238.4 8.0 0.001 1.0 1949 4246.4 2.0 91.060 15.0 1952 4248.4 4.0 0.001 1.0 1953 4252.4 6.0 4.551 15.0 1955 4258.4 8.0 0.001 1.0 1958 4266.4 6.5 7.953 15.0 1962 4272.9 6.0 0.001 1.0 1965 4278.9 2.0 24.687 15.0 1967 4280.9 2.0 0.001 1.0 1968 4282.9 4.0 2.159 10.0 1969 4286.9 2.0 0.001 1.0 1971 4288.9 6.0 1.534 10.0 1972 4294.9 12.0 0.001 1.0 1975 4306.9 2.5 5.632 10.0 1980 4309.4 20.0 0.001 1.0 1982 Nan CS Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS Nan DS Nan CS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Shale Nan DS Shale 7 SLB Private Attachment K Section 5: Propped Fracture Schedule (Stage 2; 17139 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 280.0 25 0 1.0 PPA Scou 40 YF125ST 57.5 25 1 3.0 PPA Scou 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 3.0 PPA 40 YF125ST 190.0 25 3 5.0 PPA 40 YF125ST 196.9 25 5 7.0 PPA 40 YF125ST 183.7 25 7 9.0 PPA 40 YF125ST 157.8 25 9 10.0 PPA 40 YF125ST 132.2 25 10 Flush 40 YF125ST 261.1 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1797.2 of YF125ST 0 bbl of WF125 242124 lb of 15758 lb of % PAD Clean 18.2 % PAD Dirty 15.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 11760.0 11760 280 280 0 0 4136 7.0 7.0 1.0 PPA Scou 2414.3 14174 60 340 2414 2414 4136 1.5 8.5 3.0 PPA Scou 4447.8 18622 120 460 13343 15758 4168 3.0 11.5 Resume PAD 2100.0 20722 50 510 0 15758 4333 1.3 12.8 1.0 PPA 7645.4 28368 190 700 7645 23403 4515 4.8 17.5 3.0 PPA 7982.0 36350 215 915 23946 47349 4420 5.4 22.9 5.0 PPA 8270.3 44620 240 1155 41351 88701 5006 6.0 28.9 7.0 PPA 7716.2 52336 240 1395 54013 142714 5812 6.0 34.9 9.0 PPA 6629.0 58965 220 1615 59661 202375 6361 5.5 40.4 10.0 PPA 5550.8 64516 190 1805 55508 257882 6675 4.8 45.1 Flush 10965.7 75481 261 2066 0 257882 6024 6.5 51.7 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 365.6 ft with an average conductivity (Kfw) of 18597.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name 8 SLB Private Attachment K Section 6: Propped Fracture Simulation (Stage 2; 17139 ft MD) Initial Fracture Top TVD 4058 ft Initial Fracture Bottom TVD 4276.9 ft Propped Fracture Half-Length 365.6 ft EOJ Hyd Height at Well 219 ft Average Propped Width 0.21 in Net Pressure 396 psi Max Surface Pressure 6788 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 91.4 9.1 0.255 173.9 2.16 254.2 23432 91.4 182.8 7.5 0.248 196.1 2.16 271 22071 182.8 274.2 5.9 0.218 172.1 1.96 316.8 19650 274.2 365.6 2.6 0.134 146.2 1.22 419.4 11314 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 9 SLB Private Attachment K Section 7: Zone Data (Stage 3; 16599 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4054.3 10.0 0.72 2937 1.46E+06 0.220 2500 Shale 4064.3 15.0 0.70 2830 1.76E+06 0.220 2500 Nanushuk 3 SS 4079.3 15.3 0.68 2771 1.90E+06 0.220 2000 Top Nan 4094.6 6.0 0.64 2630 8.39E+05 0.270 1000 Shale 4100.6 2.0 0.70 2858 2.67E+06 0.230 2500 Nan DS 4102.6 1.5 0.63 2584 8.19E+05 0.270 1500 Nan DS 4104.1 2.0 0.64 2615 1.22E+06 0.260 1500 Nan CS 4106.1 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4119.1 1.5 0.61 2524 1.00E+06 0.270 1000 Nan CS 4120.6 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4124.6 9.0 0.61 2506 1.17E+06 0.270 1000 Nan CS 4133.6 7.0 0.64 2659 7.69E+05 0.270 1000 Nan CS 4140.6 5.5 0.61 2543 1.28E+06 0.260 1000 Nan CS 4146.1 13.0 0.64 2665 6.92E+05 0.280 1000 Nan DS 4159.1 2.5 0.68 2825 1.75E+06 0.260 1500 Nan DS 4161.6 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4174.1 4.0 0.69 2890 1.69E+06 0.260 1500 Nan DS 4178.1 2.5 0.64 2675 8.22E+05 0.270 1500 Shale 4180.6 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4182.6 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4186.6 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4190.6 4.0 0.70 2921 2.67E+06 0.230 2500 Nan DS 4194.6 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4200.6 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4202.6 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4204.6 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4211.1 4.0 0.61 2583 8.99E+05 0.270 1500 Nan DS 4215.1 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4218.6 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4220.6 12.5 0.64 2697 1.56E+06 0.260 1500 Nan DS 4233.1 2.0 0.65 2747 1.40E+06 0.260 1500 Shale 4235.1 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4237.1 2.0 0.65 2759 1.24E+06 0.260 1500 Shale 4239.1 8.0 0.69 2923 2.67E+06 0.230 2500 Nan DS 4247.1 2.0 0.63 2689 9.33E+05 0.270 1500 Shale 4249.1 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4253.1 6.0 0.65 2749 1.43E+06 0.260 1500 Shale 4259.1 8.0 0.70 2967 2.67E+06 0.230 2500 Nan DS 4267.1 6.5 0.65 2766 1.47E+06 0.260 1500 Shale 4273.6 6.0 0.69 2947 2.67E+06 0.230 2500 Nan DS 4279.6 2.0 0.64 2726 8.38E+05 0.270 1000 Shale 4281.6 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4283.6 4.0 0.65 2786 1.47E+06 0.260 1500 Shale 4287.6 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4289.6 6.0 0.66 2849 1.55E+06 0.260 1500 Shale 4295.6 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4307.6 2.5 0.64 2754 1.21E+06 0.270 1500 Shale 4310.1 20.0 0.69 2977 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 10 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4054.3 10.0 0.001 1.0 1881 4064.3 15.0 0.001 1.0 1886 4079.3 15.3 0.005 10.0 1890 4094.6 6.0 56.445 22.0 1882 4100.6 2.0 0.001 1.0 1884 4102.6 1.5 109.347 15.0 1885 4104.1 2.0 4.377 15.0 1886 4106.1 13.0 42.829 22.0 1887 4119.1 1.5 11.097 22.0 1893 4120.6 4.0 91.857 22.0 1894 4124.6 9.0 4.906 22.0 1896 4133.6 7.0 12.361 22.0 1900 4140.6 5.5 2.537 22.0 1903 4146.1 13.0 61.847 22.0 1906 4159.1 2.5 0.081 15.0 1912 4161.6 12.5 22.858 15.0 1913 4174.1 4.0 0.018 15.0 1919 4178.1 2.5 94.329 15.0 1920 4180.6 2.0 0.001 1.0 1922 4182.6 4.0 45.186 15.0 1922 4186.6 4.0 24.865 15.0 1924 4190.6 4.0 0.001 1.0 1926 4194.6 6.0 6.405 15.0 1928 4200.6 2.0 0.001 1.0 1931 4202.6 2.0 13.686 15.0 1932 4204.6 6.5 0.229 15.0 1933 4211.1 4.0 49.420 15.0 1936 4215.1 3.5 63.759 15.0 1938 4218.6 2.0 0.001 1.0 1939 4220.6 12.5 1.337 15.0 1940 4233.1 2.0 1.843 15.0 1946 4235.1 2.0 0.001 1.0 1947 4237.1 2.0 4.320 15.0 1948 4239.1 8.0 0.001 1.0 1949 4247.1 2.0 91.060 15.0 1952 4249.1 4.0 0.001 1.0 1953 4253.1 6.0 4.551 15.0 1955 4259.1 8.0 0.001 1.0 1958 4267.1 6.5 7.953 15.0 1962 4273.6 6.0 0.001 1.0 1965 4279.6 2.0 24.687 15.0 1967 4281.6 2.0 0.001 1.0 1968 4283.6 4.0 2.159 10.0 1969 4287.6 2.0 0.001 1.0 1971 4289.6 6.0 1.534 10.0 1972 4295.6 12.0 0.001 1.0 1975 4307.6 2.5 5.632 10.0 1980 4310.1 20.0 0.001 1.0 1982 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Shale Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS 11 SLB Private Attachment K Section 8: Propped Fracture Schedule (Stage 3; 16599 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 270.0 25 0 1.0 PPA 40 YF125ST 153.3 25 1 2.0 PPA 40 YF125ST 165.5 25 2 4.0 PPA 40 YF125ST 170.2 25 4 6.0 PPA 40 YF125ST 158.4 25 6 8.0 PPA 40 YF125ST 148.1 25 8 10.0 PPA 40 YF125ST 139.1 25 10 12.0 PPA 40 YF125ST 118.0 25 12 Flush 40 YF125ST 252.9 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1575.5 bbl of YF125ST 0 bbl of WF125 256538 lb of % PAD Clean 20.4 % PAD Dirty 17.0 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 11340.0 11340 270 270 0 0 4026 6.8 6.8 1.0 PPA 6438.2 17778 160 430 6438 6438 4041 4.0 10.8 2.0 PPA 6951.5 24730 180 610 13903 20341 4130 4.5 15.3 4.0 PPA 7148.6 31878 200 810 28594 48936 4506 5.0 20.3 6.0 PPA 6653.0 38531 200 1010 39918 88854 5230 5.0 25.3 8.0 PPA 6221.7 44753 200 1210 49774 138627 5925 5.0 30.3 10.0 PPA 5842.9 50596 200 1410 58429 197056 6364 5.0 35.3 12.0 PPA 4956.8 55553 180 1590 59482 256538 6582 4.5 39.8 Flush 10620.2 66173 253 1843 0 256538 6017 6.3 46.1 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 375.4 ft with an average conductivity (Kfw) of 19897.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 12 SLB Private Attachment K Section 9: Propped Fracture Simulation (Stage 3; 16599 ft MD) Initial Fracture Top TVD 4059.8 ft Initial Fracture Bottom TVD 4266.5 ft Propped Fracture Half-Length 375.4 ft EOJ Hyd Height at Well 206.7 ft Average Propped Width 0.224 in Net Pressure 393 psi Max Surface Pressure 6685 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 93.9 11.1 0.274 140 2.35 227.2 25187 93.9 187.7 8.6 0.257 174.1 2.26 249.2 23122 187.7 281.6 6.5 0.219 152.1 1.94 292.8 19391 281.6 375.4 2.4 0.16 131.8 1.47 367 13710 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 13 SLB Private Attachment K Section 10: Zone Data (Stage 4; 16058 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4054.4 10.0 0.72 2937 1.46E+06 0.220 2500 Shale 4064.4 15.0 0.70 2830 1.76E+06 0.220 2500 Nanushuk 3 SS 4079.4 15.3 0.68 2771 1.90E+06 0.220 2000 Top Nan 4094.7 6.0 0.64 2630 8.39E+05 0.270 1000 Shale 4100.7 2.0 0.70 2858 2.67E+06 0.230 2500 Nan DS 4102.7 1.5 0.63 2584 8.19E+05 0.270 1500 Nan DS 4104.2 2.0 0.64 2615 1.22E+06 0.260 1500 Nan CS 4106.2 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4119.2 1.5 0.61 2524 1.00E+06 0.270 1000 Nan CS 4120.7 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4124.7 9.0 0.61 2506 1.17E+06 0.270 1000 Nan CS 4133.7 7.0 0.64 2659 7.69E+05 0.270 1000 Nan CS 4140.7 5.5 0.61 2543 1.28E+06 0.260 1000 Nan CS 4146.2 13.0 0.64 2665 6.92E+05 0.280 1000 Nan DS 4159.2 2.5 0.68 2825 1.75E+06 0.260 1500 Nan DS 4161.7 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4174.2 4.0 0.69 2890 1.69E+06 0.260 1500 Nan DS 4178.2 2.5 0.64 2675 8.22E+05 0.270 1500 Shale 4180.7 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4182.7 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4186.7 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4190.7 4.0 0.70 2921 2.67E+06 0.230 2500 Nan DS 4194.7 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4200.7 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4202.7 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4204.7 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4211.2 4.0 0.61 2583 8.99E+05 0.270 1500 Nan DS 4215.2 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4218.7 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4220.7 12.5 0.64 2697 1.56E+06 0.260 1500 Nan DS 4233.2 2.0 0.65 2747 1.40E+06 0.260 1500 Shale 4235.2 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4237.2 2.0 0.65 2759 1.24E+06 0.260 1500 Shale 4239.2 8.0 0.69 2924 2.67E+06 0.230 2500 Nan DS 4247.2 2.0 0.63 2689 9.33E+05 0.270 1500 Shale 4249.2 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4253.2 6.0 0.65 2750 1.43E+06 0.260 1500 Shale 4259.2 8.0 0.70 2967 2.67E+06 0.230 2500 Nan DS 4267.2 6.5 0.65 2766 1.47E+06 0.260 1500 Shale 4273.7 6.0 0.69 2947 2.67E+06 0.230 2500 Nan DS 4279.7 2.0 0.64 2726 8.38E+05 0.270 1000 Shale 4281.7 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4283.7 4.0 0.65 2786 1.47E+06 0.260 1500 Shale 4287.7 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4289.7 6.0 0.66 2849 1.55E+06 0.260 1500 Shale 4295.7 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4307.7 2.5 0.64 2754 1.21E+06 0.270 1500 Shale 4310.2 20.0 0.69 2977 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 14 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4054.4 10.0 0.001 1.0 1881 4064.4 15.0 0.001 1.0 1886 4079.4 15.3 0.005 10.0 1890 4094.7 6.0 56.445 22.0 1882 4100.7 2.0 0.001 1.0 1884 4102.7 1.5 109.347 15.0 1885 4104.2 2.0 4.377 15.0 1886 4106.2 13.0 42.829 22.0 1887 4119.2 1.5 11.097 22.0 1893 4120.7 4.0 91.857 22.0 1894 4124.7 9.0 4.906 22.0 1896 4133.7 7.0 12.361 22.0 1900 4140.7 5.5 2.537 22.0 1903 4146.2 13.0 61.847 22.0 1906 4159.2 2.5 0.081 15.0 1912 4161.7 12.5 22.858 15.0 1913 4174.2 4.0 0.018 15.0 1919 4178.2 2.5 94.329 15.0 1920 4180.7 2.0 0.001 1.0 1922 4182.7 4.0 45.186 15.0 1922 4186.7 4.0 24.865 15.0 1924 4190.7 4.0 0.001 1.0 1926 4194.7 6.0 6.405 15.0 1928 4200.7 2.0 0.001 1.0 1931 4202.7 2.0 13.686 15.0 1932 4204.7 6.5 0.229 15.0 1933 4211.2 4.0 49.420 15.0 1936 4215.2 3.5 63.759 15.0 1938 4218.7 2.0 0.001 1.0 1939 4220.7 12.5 1.337 15.0 1940 4233.2 2.0 1.843 15.0 1946 4235.2 2.0 0.001 1.0 1947 4237.2 2.0 4.320 15.0 1948 4239.2 8.0 0.001 1.0 1949 4247.2 2.0 91.060 15.0 1952 4249.2 4.0 0.001 1.0 1953 4253.2 6.0 4.551 15.0 1955 4259.2 8.0 0.001 1.0 1958 4267.2 6.5 7.953 15.0 1962 4273.7 6.0 0.001 1.0 1965 4279.7 2.0 24.687 15.0 1967 4281.7 2.0 0.001 1.0 1968 4283.7 4.0 2.159 10.0 1969 4287.7 2.0 0.001 1.0 1971 4289.7 6.0 1.534 10.0 1972 4295.7 12.0 0.001 1.0 1975 4307.7 2.5 5.632 10.0 1980 4310.2 20.0 0.001 1.0 1982 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Shale Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS 15 SLB Private Attachment K Section 11: Propped Fracture Schedule (Stage 4; 16058 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 270.0 25 0 1.0 PPA 40 YF125ST 153.3 25 1 2.0 PPA 40 YF125ST 165.5 25 2 4.0 PPA 40 YF125ST 170.2 25 4 6.0 PPA 40 YF125ST 158.4 25 6 8.0 PPA 40 YF125ST 148.1 25 8 10.0 PPA 40 YF125ST 139.1 25 10 12.0 PPA 40 YF125ST 118.0 25 12 Flush 40 YF125ST 244.6 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1567.3 bbl of YF125ST 0 bbl of WF125 256538 lb of % PAD Clean 20.4 % PAD Dirty 17.0 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 11340.0 11340 270 270 0 0 3925 6.8 6.8 1.0 PPA 6438.2 17778 160 430 6438 6438 3940 4.0 10.8 2.0 PPA 6951.5 24730 180 610 13903 20341 4018 4.5 15.3 4.0 PPA 7148.6 31878 200 810 28594 48936 4372 5.0 20.3 6.0 PPA 6653.0 38531 200 1010 39918 88854 5065 5.0 25.3 8.0 PPA 6221.7 44753 200 1210 49774 138627 5735 5.0 30.3 10.0 PPA 5842.9 50596 200 1410 58429 197056 6156 5.0 35.3 12.0 PPA 4956.8 55553 180 1590 59482 256538 6374 4.5 39.8 Flush 10274.0 65827 245 1835 0 256538 5773 6.1 45.9 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 346.5 ft with an average conductivity (Kfw) of 18813.3 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 16 SLB Private Attachment K Section 12: Propped Fracture Simulation (Stage 4; 16058 ft MD) Initial Fracture Top TVD 4058.1 ft Initial Fracture Bottom TVD 4279.2 ft Propped Fracture Half-Length 346.5 ft EOJ Hyd Height at Well 221.1 ft Average Propped Width 0.216 in Net Pressure 262 psi Max Surface Pressure 6490 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 86.6 11.5 0.256 152.9 2.16 228.6 23223 86.6 173.3 8.9 0.255 190.6 2.22 243.7 22464 173.3 259.9 6.5 0.209 168.1 1.85 301.5 18284 259.9 346.5 2.6 0.153 156.7 1.4 396.9 12736 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 17 SLB Private Attachment K Section 13: Zone Data (Stage 5; 15518 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4054.7 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4064.7 15.0 0.70 2830 1.76E+06 0.220 1000 Nanushuk 3 SS 4079.7 15.3 0.68 2771 1.90E+06 0.220 1000 Top Nan CS 4095.0 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4114.5 2.0 0.69 2844 2.67E+06 0.230 2500 Nan CS 4116.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4118.0 4.5 0.62 2538 6.44E+05 0.280 1000 Nan DS 4122.5 3.5 0.69 2850 1.77E+06 0.260 1500 Nan DS 4126.0 14.5 0.66 2720 1.39E+06 0.260 1500 Nan CS 4140.5 1.5 0.65 2700 1.15E+06 0.270 1000 Nan CS 4142.0 12.5 0.64 2638 8.82E+05 0.270 1000 Nan DS 4154.5 2.0 0.65 2697 1.40E+06 0.260 1500 Nan CS 4156.5 9.0 0.61 2526 8.54E+05 0.270 1000 Nan DS 4165.5 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4172.5 9.0 0.65 2698 1.13E+06 0.270 1500 Nan DS 4181.5 3.5 0.64 2686 1.69E+06 0.260 1500 Nan DS 4185.0 5.0 0.64 2659 7.57E+05 0.270 1000 Nan DS 4190.0 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4192.0 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4202.5 3.5 0.64 2699 1.10E+06 0.270 1000 Nan CS 4206.0 2.0 0.62 2608 6.70E+05 0.280 1000 Nan CS 4208.0 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4213.5 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4217.0 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4220.5 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4226.0 10.5 0.64 2687 1.17E+06 0.270 1000 Nan DS 4236.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4238.0 5.0 0.62 2638 1.14E+06 0.270 1500 Nan DS 4243.0 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4245.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4249.0 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4251.0 10.0 0.63 2669 9.81E+05 0.270 1500 Nan DS 4261.0 4.0 0.65 2788 1.63E+06 0.260 1500 Nan DS 4265.0 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4269.0 9.5 0.65 2778 1.33E+06 0.260 1500 Nan DS 4278.5 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4280.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4290.0 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4292.0 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4294.0 2.0 0.64 2732 1.09E+06 0.270 1500 Shale 4296.0 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4298.0 4.0 0.66 2838 1.29E+06 0.260 1500 Shale 4302.0 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4321.5 2.0 0.65 2814 1.36E+06 0.260 1500 Shale 4323.5 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4325.5 8.0 0.66 2849 1.37E+06 0.260 1500 Nan DS 4333.5 8.0 0.65 2806 1.56E+06 0.260 1500 Shale 4341.5 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 18 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4054.7 10.0 0.001 1.0 1890 4064.7 15.0 0.001 1.0 1898 4079.7 15.3 0.005 10.0 1905 4095.0 19.5 30.655 23.7 1915 4114.5 2.0 5.000 10.0 1924 4116.5 1.5 2.095 16.9 1925 4118.0 4.5 48.388 26.6 1926 4122.5 3.5 0.478 12.4 1928 4126.0 14.5 15.008 17.7 1930 4140.5 1.5 3.661 17.6 1937 4142.0 12.5 34.723 23.9 1937 4154.5 2.0 1.697 15.6 1943 4156.5 9.0 54.319 24.4 1944 4165.5 7.0 3.610 14.8 1948 4172.5 9.0 22.986 20.4 1952 4181.5 3.5 0.835 14.0 1956 4185.0 5.0 65.392 23.4 1957 4190.0 2.0 0.006 10.5 1960 4192.0 10.5 100.832 25.6 1961 4202.5 3.5 17.434 20.5 1966 4206.0 2.0 161.343 26.3 1967 4208.0 5.5 4.627 18.4 1968 4213.5 3.5 5.075 14.8 1971 4217.0 3.5 8.651 19.4 1972 4220.5 5.5 10.205 16.0 1974 4226.0 10.5 17.356 20.1 1977 4236.5 1.5 3.106 14.8 1982 4238.0 5.0 52.863 20.6 1982 4243.0 2.0 2.277 14.1 1985 4245.0 4.0 122.778 23.1 1986 4249.0 2.0 0.333 12.5 1987 4251.0 10.0 39.939 21.2 1988 4261.0 4.0 0.748 13.3 1993 4265.0 4.0 0.009 10.9 1995 4269.0 9.5 5.399 16.7 1997 4278.5 2.0 160.618 24.9 2001 4280.5 9.5 0.033 11.5 2002 4290.0 2.0 6.733 16.2 2007 4292.0 2.0 0.001 1.0 2008 4294.0 2.0 29.480 19.6 2009 4296.0 2.0 0.001 1.0 2009 4298.0 4.0 8.473 16.6 2010 4302.0 19.5 0.001 1.0 2012 4321.5 2.0 2.185 16.4 2021 4323.5 2.0 0.001 1.0 2022 4325.5 8.0 2.645 15.9 2023 4333.5 8.0 2.026 14.4 2027 4341.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 19 SLB Private Attachment K Section 14: Propped Fracture Schedule (Stage 5; 15518 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 183.9 25 2 4.0 PPA 40 YF125ST 187.2 25 4 6.0 PPA 40 YF125ST 174.2 25 6 8.0 PPA 40 YF125ST 162.9 25 8 10.0 PPA 40 YF125ST 139.1 25 10 12.0 PPA 40 YF125ST 118.0 25 12 Flush 40 YF125ST 236.4 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1674.3 bbl of YF125ST 0 bbl of WF125 270716 lb of % PAD Clean 20.9 % PAD Dirty 17.4 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 12600.0 12600 300 300 0 0 3841 7.5 7.5 1.0 PPA 7243.0 19843 180 480 7243 7243 3853 4.5 12.0 2.0 PPA 7723.9 27567 200 680 15448 22691 3924 5.0 17.0 4.0 PPA 7863.4 35430 220 900 31454 54145 4286 5.5 22.5 6.0 PPA 7318.3 42749 220 1120 43910 98055 4974 5.5 28.0 8.0 PPA 6843.9 49593 220 1340 54751 152805 5600 5.5 33.5 10.0 PPA 5842.9 55435 200 1540 58429 211234 5977 5.0 38.5 12.0 PPA 4956.8 60392 180 1720 59482 270716 6152 4.5 43.0 Flush 9928.5 70321 236 1956 0 270716 5602 5.9 48.9 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 331.7 ft with an average conductivity (Kfw) of 18588.2 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 20 SLB Private Attachment K Section 15: Propped Fracture Simulation (Stage 5; 15518 ft MD) Initial Fracture Top TVD 4061.4 ft Initial Fracture Bottom TVD 4296.6 ft Propped Fracture Half-Length 331.7 ft EOJ Hyd Height at Well 235.1 ft Average Propped Width 0.213 in Net Pressure 263 psi Max Surface Pressure 6242 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 82.9 11.3 0.252 189.9 2.18 254.1 22602 82.9 165.8 9.5 0.249 209.4 2.21 264.1 22031 165.8 248.7 8 0.223 186.1 1.98 279.8 19436 248.7 331.7 2.8 0.138 168.6 1.29 555.4 11389 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 21 SLB Private Attachment K Section 16: Zone Data (Stage 6; 14981 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4054.7 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4064.7 15.0 0.70 2830 1.76E+06 0.220 1000 Nanushuk 3 SS 4079.7 15.3 0.68 2771 1.90E+06 0.220 1000 Top Nan CS 4095.0 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4114.5 2.0 0.69 2844 2.67E+06 0.230 2500 Nan CS 4116.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4118.0 4.5 0.62 2538 6.44E+05 0.280 1000 Nan DS 4122.5 3.5 0.69 2850 1.77E+06 0.260 1500 Nan DS 4126.0 14.5 0.66 2720 1.39E+06 0.260 1500 Nan CS 4140.5 1.5 0.65 2700 1.15E+06 0.270 1000 Nan CS 4142.0 12.5 0.64 2638 8.82E+05 0.270 1000 Nan DS 4154.5 2.0 0.65 2697 1.40E+06 0.260 1500 Nan CS 4156.5 9.0 0.61 2526 8.54E+05 0.270 1000 Nan DS 4165.5 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4172.5 9.0 0.65 2698 1.13E+06 0.270 1500 Nan DS 4181.5 3.5 0.64 2686 1.69E+06 0.260 1500 Nan DS 4185.0 5.0 0.64 2659 7.57E+05 0.270 1000 Nan DS 4190.0 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4192.0 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4202.5 3.5 0.64 2699 1.10E+06 0.270 1000 Nan CS 4206.0 2.0 0.62 2608 6.70E+05 0.280 1000 Nan CS 4208.0 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4213.5 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4217.0 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4220.5 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4226.0 10.5 0.64 2687 1.17E+06 0.270 1000 Nan DS 4236.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4238.0 5.0 0.62 2638 1.14E+06 0.270 1500 Nan DS 4243.0 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4245.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4249.0 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4251.0 10.0 0.63 2669 9.81E+05 0.270 1500 Nan DS 4261.0 4.0 0.65 2788 1.63E+06 0.260 1500 Nan DS 4265.0 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4269.0 9.5 0.65 2778 1.33E+06 0.260 1500 Nan DS 4278.5 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4280.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4290.0 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4292.0 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4294.0 2.0 0.64 2732 1.09E+06 0.270 1500 Shale 4296.0 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4298.0 4.0 0.66 2838 1.29E+06 0.260 1500 Shale 4302.0 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4321.5 2.0 0.65 2814 1.36E+06 0.260 1500 Shale 4323.5 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4325.5 8.0 0.66 2849 1.37E+06 0.260 1500 Nan DS 4333.5 8.0 0.65 2806 1.56E+06 0.260 1500 Shale 4341.5 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 22 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4054.7 10.0 0.001 1.0 1890 4064.7 15.0 0.001 1.0 1898 4079.7 15.3 0.005 10.0 1905 4095.0 19.5 30.655 23.7 1915 4114.5 2.0 5.000 10.0 1924 4116.5 1.5 2.095 16.9 1925 4118.0 4.5 48.388 26.6 1926 4122.5 3.5 0.478 12.4 1928 4126.0 14.5 15.008 17.7 1930 4140.5 1.5 3.661 17.6 1937 4142.0 12.5 34.723 23.9 1937 4154.5 2.0 1.697 15.6 1943 4156.5 9.0 54.319 24.4 1944 4165.5 7.0 3.610 14.8 1948 4172.5 9.0 22.986 20.4 1952 4181.5 3.5 0.835 14.0 1956 4185.0 5.0 65.392 23.4 1957 4190.0 2.0 0.006 10.5 1960 4192.0 10.5 100.832 25.6 1961 4202.5 3.5 17.434 20.5 1966 4206.0 2.0 161.343 26.3 1967 4208.0 5.5 4.627 18.4 1968 4213.5 3.5 5.075 14.8 1971 4217.0 3.5 8.651 19.4 1972 4220.5 5.5 10.205 16.0 1974 4226.0 10.5 17.356 20.1 1977 4236.5 1.5 3.106 14.8 1982 4238.0 5.0 52.863 20.6 1982 4243.0 2.0 2.277 14.1 1985 4245.0 4.0 122.778 23.1 1986 4249.0 2.0 0.333 12.5 1987 4251.0 10.0 39.939 21.2 1988 4261.0 4.0 0.748 13.3 1993 4265.0 4.0 0.009 10.9 1995 4269.0 9.5 5.399 16.7 1997 4278.5 2.0 160.618 24.9 2001 4280.5 9.5 0.033 11.5 2002 4290.0 2.0 6.733 16.2 2007 4292.0 2.0 0.001 1.0 2008 4294.0 2.0 29.480 19.6 2009 4296.0 2.0 0.001 1.0 2009 4298.0 4.0 8.473 16.6 2010 4302.0 19.5 0.001 1.0 2012 4321.5 2.0 2.185 16.4 2021 4323.5 2.0 0.001 1.0 2022 4325.5 8.0 2.645 15.9 2023 4333.5 8.0 2.026 14.4 2027 4341.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 23 SLB Private Attachment K Section 17: Propped Fracture Schedule (Stage 6; 14981 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 57.5 25 1 3.0 PPA 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 3.0 PPA 40 YF125ST 185.6 25 3 5.0 PPA 40 YF125ST 192.8 25 5 7.0 PPA 40 YF125ST 179.9 25 7 9.0 PPA 40 YF125ST 157.8 25 9 10.0 PPA 40 YF125ST 132.2 25 10 Flush 40 YF125ST 228.2 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1721.9 bbl of YF125ST 0 bbl of WF125 239581 lb of 15756 lb of % PAD Clean 16.7 % PAD Dirty 14.2 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3744 6.3 6.3 1.0 PPA 57.5 307 60 310 2413 2413 3749 1.5 7.8 3.0 PPA 105.9 413 120 430 13343 15756 3802 3.0 10.8 Resume PAD 50.0 463 50 480 0 15756 3964 1.3 12.0 1.0 PPA 182.0 645 190 670 7645 23402 4050 4.8 16.8 3.0 PPA 185.6 831 210 880 23389 46791 3954 5.3 22.0 5.0 PPA 192.8 1024 235 1115 40490 87281 4533 5.9 27.9 7.0 PPA 179.9 1204 235 1350 52888 140169 5195 5.9 33.8 9.0 PPA 157.8 1362 220 1570 59661 199830 5631 5.5 39.3 10.0 PPA 132.2 1494 190 1760 55508 255337 5856 4.8 44.0 Flush 228.2 1722 228 1988 0 255337 5388 5.7 49.7 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 312.1 ft with an average conductivity (Kfw) of 18457.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name 24 SLB Private Attachment K Section 18: Propped Fracture Simulation (Stage 6; 14981 ft MD) Initial Fracture Top TVD 4061.4 ft Initial Fracture Bottom TVD 4296.8 ft Propped Fracture Half-Length 312.1 ft EOJ Hyd Height at Well 235.5 ft Average Propped Width 0.212 in Net Pressure 275 psi Max Surface Pressure 5936 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 78 9.4 0.261 190.4 2.26 263.7 23549 78 156.1 8.4 0.26 213.8 2.31 273.7 23024 156.1 234.1 6.8 0.221 196.8 1.98 308.8 19487 234.1 312.1 2.1 0.119 182.5 1.11 534.9 9757 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 25 SLB Private Attachment K Section 19: Zone Data (Stage 7; 14441 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4057.6 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4067.6 15.0 0.70 2832 1.76E+06 0.220 1000 Nanushuk 3 SS 4082.6 15.3 0.68 2773 1.90E+06 0.220 1000 Top Nan CS 4097.9 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4117.4 2.0 0.69 2846 2.67E+06 0.230 2500 Nan CS 4119.4 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4120.9 4.5 0.62 2540 6.44E+05 0.280 1000 Nan DS 4125.4 3.5 0.69 2852 1.77E+06 0.260 1500 Nan DS 4128.9 14.5 0.66 2722 1.39E+06 0.260 1500 Nan CS 4143.4 1.5 0.65 2702 1.15E+06 0.270 1000 Nan CS 4144.9 12.5 0.64 2640 8.82E+05 0.270 1000 Nan DS 4157.4 2.0 0.65 2699 1.40E+06 0.260 1500 Nan CS 4159.4 9.0 0.61 2527 8.54E+05 0.270 1000 Nan DS 4168.4 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4175.4 9.0 0.65 2700 1.13E+06 0.270 1500 Nan DS 4184.4 3.5 0.64 2688 1.69E+06 0.260 1500 Nan DS 4187.9 5.0 0.64 2661 7.57E+05 0.270 1000 Nan DS 4192.9 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4194.9 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4205.4 3.5 0.64 2701 1.10E+06 0.270 1000 Nan CS 4208.9 2.0 0.62 2610 6.70E+05 0.280 1000 Nan CS 4210.9 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4216.4 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4219.9 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4223.4 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4228.9 10.5 0.64 2689 1.17E+06 0.270 1000 Nan DS 4239.4 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4240.9 5.0 0.62 2639 1.14E+06 0.270 1500 Nan DS 4245.9 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4247.9 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4251.9 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4253.9 10.0 0.63 2670 9.81E+05 0.270 1500 Nan DS 4263.9 4.0 0.65 2790 1.63E+06 0.260 1500 Nan DS 4267.9 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4271.9 9.5 0.65 2780 1.33E+06 0.260 1500 Nan DS 4281.4 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4283.4 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4292.9 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4294.9 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4296.9 2.0 0.64 2733 1.09E+06 0.270 1500 Shale 4298.9 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4300.9 4.0 0.66 2840 1.29E+06 0.260 1500 Shale 4304.9 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4324.4 2.0 0.65 2816 1.36E+06 0.260 1500 Shale 4326.4 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4328.4 8.0 0.66 2851 1.37E+06 0.260 1500 Nan DS 4336.4 8.0 0.65 2808 1.56E+06 0.260 1500 Shale 4344.4 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 26 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4057.6 10.0 0.001 1.0 1890 4067.6 15.0 0.001 1.0 1898 4082.6 15.3 0.005 10.0 1905 4097.9 19.5 30.655 23.7 1915 4117.4 2.0 5.000 10.0 1924 4119.4 1.5 2.095 16.9 1925 4120.9 4.5 48.388 26.6 1926 4125.4 3.5 0.478 12.4 1928 4128.9 14.5 15.008 17.7 1930 4143.4 1.5 3.661 17.6 1937 4144.9 12.5 34.723 23.9 1937 4157.4 2.0 1.697 15.6 1943 4159.4 9.0 54.319 24.4 1944 4168.4 7.0 3.610 14.8 1948 4175.4 9.0 22.986 20.4 1952 4184.4 3.5 0.835 14.0 1956 4187.9 5.0 65.392 23.4 1957 4192.9 2.0 0.006 10.5 1960 4194.9 10.5 100.832 25.6 1961 4205.4 3.5 17.434 20.5 1966 4208.9 2.0 161.343 26.3 1967 4210.9 5.5 4.627 18.4 1968 4216.4 3.5 5.075 14.8 1971 4219.9 3.5 8.651 19.4 1972 4223.4 5.5 10.205 16.0 1974 4228.9 10.5 17.356 20.1 1977 4239.4 1.5 3.106 14.8 1982 4240.9 5.0 52.863 20.6 1982 4245.9 2.0 2.277 14.1 1985 4247.9 4.0 122.778 23.1 1986 4251.9 2.0 0.333 12.5 1987 4253.9 10.0 39.939 21.2 1988 4263.9 4.0 0.748 13.3 1993 4267.9 4.0 0.009 10.9 1995 4271.9 9.5 5.399 16.7 1997 4281.4 2.0 160.618 24.9 2001 4283.4 9.5 0.033 11.5 2002 4292.9 2.0 6.733 16.2 2007 4294.9 2.0 0.001 1.0 2008 4296.9 2.0 29.480 19.6 2009 4298.9 2.0 0.001 1.0 2009 4300.9 4.0 8.473 16.6 2010 4304.9 19.5 0.001 1.0 2012 4324.4 2.0 2.185 16.4 2021 4326.4 2.0 0.001 1.0 2022 4328.4 8.0 2.645 15.9 2023 4336.4 8.0 2.026 14.4 2027 4344.4 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 27 SLB Private Attachment K Section 20: Propped Fracture Schedule (Stage 7; 14441 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 143.7 25 1 2.0 PPA 40 YF125ST 160.9 25 2 4.0 PPA 40 YF125ST 161.7 25 4 6.0 PPA 40 YF125ST 150.5 25 6 8.0 PPA 40 YF125ST 140.7 25 8 10.0 PPA 40 YF125ST 132.2 25 10 12.0 PPA 40 YF125ST 104.9 25 12 Flush 40 YF125ST 220.0 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1464.6 bbl of YF125ST 0 bbl of WF125 240305 lb of % PAD Clean 20.1 % PAD Dirty 16.7 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 10500.0 10500 250 250 0 0 3645 6.3 6.3 1.0 PPA 6035.8 16536 150 400 6036 6036 3654 3.8 10.0 2.0 PPA 6758.4 23294 175 575 13517 19553 3715 4.4 14.4 4.0 PPA 6791.2 30085 190 765 27165 46717 4059 4.8 19.1 6.0 PPA 6320.4 36406 190 955 37922 84640 4685 4.8 23.9 8.0 PPA 5910.6 42316 190 1145 47285 131924 5249 4.8 28.6 10.0 PPA 5550.8 47867 190 1335 55508 187432 5581 4.8 33.4 12.0 PPA 4406.1 52273 160 1495 52873 240305 5738 4.0 37.4 Flush 9239.5 61513 220 1715 0 240305 5186 5.5 42.9 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 301.3 ft with an average conductivity (Kfw) of 18495.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 28 SLB Private Attachment K Section 21: Propped Fracture Simulation (Stage 7; 14441 ft MD) Initial Fracture Top TVD 4065.3 ft Initial Fracture Bottom TVD 4295.9 ft Propped Fracture Half-Length 301.3 ft EOJ Hyd Height at Well 230.6 ft Average Propped Width 0.212 in Net Pressure 259 psi Max Surface Pressure 5818 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 75.3 11.3 0.248 185.3 2.14 248.6 22257 75.3 150.6 9.6 0.248 207.5 2.2 253.4 21834 150.6 225.9 7.9 0.216 188.1 1.9 280.7 18938 225.9 301.3 3.5 0.148 163.8 1.39 394.3 12303 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 29 SLB Private Attachment K Section 22: Zone Data (Stage 8; 13906 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4064.2 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4074.2 15.0 0.70 2837 1.76E+06 0.220 1000 Nanushuk 3 SS 4089.2 15.3 0.68 2778 1.90E+06 0.220 1000 Top Nan CS 4104.5 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4124.0 2.0 0.69 2850 2.67E+06 0.230 2500 Nan CS 4126.0 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4127.5 4.5 0.62 2544 6.44E+05 0.280 1000 Nan DS 4132.0 3.5 0.69 2856 1.77E+06 0.260 1500 Nan DS 4135.5 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4150.0 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4151.5 12.5 0.64 2644 8.82E+05 0.270 1000 Nan DS 4164.0 2.0 0.65 2703 1.40E+06 0.260 1500 Nan CS 4166.0 9.0 0.61 2531 8.54E+05 0.270 1000 Nan DS 4175.0 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4182.0 9.0 0.65 2704 1.13E+06 0.270 1500 Nan DS 4191.0 3.5 0.64 2692 1.69E+06 0.260 1500 Nan DS 4194.5 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4199.5 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4201.5 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4212.0 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4215.5 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4217.5 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4223.0 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4226.5 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4230.0 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4235.5 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4246.0 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4247.5 5.0 0.62 2643 1.14E+06 0.270 1500 Nan DS 4252.5 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4254.5 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4258.5 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4260.5 10.0 0.63 2674 9.81E+05 0.270 1500 Nan DS 4270.5 4.0 0.65 2794 1.63E+06 0.260 1500 Nan DS 4274.5 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4278.5 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4288.0 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4290.0 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4299.5 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4301.5 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4303.5 2.0 0.64 2738 1.09E+06 0.270 1500 Shale 4305.5 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4307.5 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4311.5 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4331.0 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4333.0 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4335.0 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4343.0 8.0 0.65 2813 1.56E+06 0.260 1500 Shale 4351.0 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 30 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4064.2 10.0 0.001 1.0 1890 4074.2 15.0 0.001 1.0 1898 4089.2 15.3 0.005 10.0 1905 4104.5 19.5 30.655 23.7 1915 4124.0 2.0 5.000 10.0 1924 4126.0 1.5 2.095 16.9 1925 4127.5 4.5 48.388 26.6 1926 4132.0 3.5 0.478 12.4 1928 4135.5 14.5 15.008 17.7 1930 4150.0 1.5 3.661 17.6 1937 4151.5 12.5 34.723 23.9 1937 4164.0 2.0 1.697 15.6 1943 4166.0 9.0 54.319 24.4 1944 4175.0 7.0 3.610 14.8 1948 4182.0 9.0 22.986 20.4 1952 4191.0 3.5 0.835 14.0 1956 4194.5 5.0 65.392 23.4 1957 4199.5 2.0 0.006 10.5 1960 4201.5 10.5 100.832 25.6 1961 4212.0 3.5 17.434 20.5 1966 4215.5 2.0 161.343 26.3 1967 4217.5 5.5 4.627 18.4 1968 4223.0 3.5 5.075 14.8 1971 4226.5 3.5 8.651 19.4 1972 4230.0 5.5 10.205 16.0 1974 4235.5 10.5 17.356 20.1 1977 4246.0 1.5 3.106 14.8 1982 4247.5 5.0 52.863 20.6 1982 4252.5 2.0 2.277 14.1 1985 4254.5 4.0 122.778 23.1 1986 4258.5 2.0 0.333 12.5 1987 4260.5 10.0 39.939 21.2 1988 4270.5 4.0 0.748 13.3 1993 4274.5 4.0 0.009 10.9 1995 4278.5 9.5 5.399 16.7 1997 4288.0 2.0 160.618 24.9 2001 4290.0 9.5 0.033 11.5 2002 4299.5 2.0 6.733 16.2 2007 4301.5 2.0 0.001 1.0 2008 4303.5 2.0 29.480 19.6 2009 4305.5 2.0 0.001 1.0 2009 4307.5 4.0 8.473 16.6 2010 4311.5 19.5 0.001 1.0 2012 4331.0 2.0 2.185 16.4 2021 4333.0 2.0 0.001 1.0 2022 4335.0 8.0 2.645 15.9 2023 4343.0 8.0 2.026 14.4 2027 4351.0 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 31 SLB Private Attachment K Section 23: Propped Fracture Schedule (Stage 8; 13906 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 153.3 25 1 2.0 PPA 40 YF125ST 165.5 25 2 4.0 PPA 40 YF125ST 170.2 25 4 6.0 PPA 40 YF125ST 158.4 25 6 8.0 PPA 40 YF125ST 148.1 25 8 10.0 PPA 40 YF125ST 139.1 25 10 12.0 PPA 40 YF125ST 118.0 25 12 Flush 40 YF125ST 211.8 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1514.5 bbl of YF125ST 0 bbl of WF125 256538 lb of % PAD Clean 19.2 % PAD Dirty 15.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 10500.0 10500 250 250 0 0 3553 6.3 6.3 1.0 PPA 6438.2 16938 160 410 6438 6438 3556 4.0 10.3 2.0 PPA 6951.5 23890 180 590 13903 20341 3627 4.5 14.8 4.0 PPA 7148.6 31038 200 790 28594 48936 3955 5.0 19.8 6.0 PPA 6653.0 37691 200 990 39918 88854 4510 5.0 24.8 8.0 PPA 6221.7 43913 200 1190 49774 138627 5053 5.0 29.8 10.0 PPA 5842.9 49756 200 1390 58429 197056 5379 5.0 34.8 12.0 PPA 4956.8 54713 180 1570 59482 256538 5538 4.5 39.3 Flush 8897.2 63610 212 1782 0 256538 5046 5.3 44.5 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 310 ft with an average conductivity (Kfw) of 19400.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 32 SLB Private Attachment K Section 24: Propped Fracture Simulation (Stage 8; 13906 ft MD) Initial Fracture Top TVD 4071.9 ft Initial Fracture Bottom TVD 4303 ft Propped Fracture Half-Length 310 ft EOJ Hyd Height at Well 231.1 ft Average Propped Width 0.222 in Net Pressure 265 psi Max Surface Pressure 5636 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 77.5 11 0.263 186.8 2.28 242.7 23743 77.5 155 9.7 0.262 207.1 2.33 251.1 23252 155 232.5 8.1 0.24 192 2.15 267.1 20944 232.5 310 3.3 0.135 165.1 1.26 558.3 11092 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 33 SLB Private Attachment K Section 25: Zone Data (Stage 9; 13365 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4068.1 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4078.1 15.0 0.70 2839 1.76E+06 0.220 1000 Nanushuk 3 SS 4093.1 15.3 0.68 2780 1.90E+06 0.220 1000 Top Nan CS 4108.4 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4127.9 2.0 0.69 2853 2.67E+06 0.230 2500 Nan CS 4129.9 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4131.4 4.5 0.62 2546 6.44E+05 0.280 1000 Nan DS 4135.9 3.5 0.69 2859 1.77E+06 0.260 1500 Nan DS 4139.4 14.5 0.66 2728 1.39E+06 0.260 1500 Nan CS 4153.9 1.5 0.65 2709 1.15E+06 0.270 1000 Nan CS 4155.4 12.5 0.64 2647 8.82E+05 0.270 1000 Nan DS 4167.9 2.0 0.65 2706 1.40E+06 0.260 1500 Nan CS 4169.9 9.0 0.61 2534 8.54E+05 0.270 1000 Nan DS 4178.9 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4185.9 9.0 0.65 2707 1.13E+06 0.270 1500 Nan DS 4194.9 3.5 0.64 2694 1.69E+06 0.260 1500 Nan DS 4198.4 5.0 0.64 2668 7.57E+05 0.270 1000 Nan DS 4203.4 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4205.4 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4215.9 3.5 0.64 2708 1.10E+06 0.270 1000 Nan CS 4219.4 2.0 0.62 2617 6.70E+05 0.280 1000 Nan CS 4221.4 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4226.9 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4230.4 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4233.9 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4239.4 10.5 0.64 2695 1.17E+06 0.270 1000 Nan DS 4249.9 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4251.4 5.0 0.62 2646 1.14E+06 0.270 1500 Nan DS 4256.4 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4258.4 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4262.4 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4264.4 10.0 0.63 2677 9.81E+05 0.270 1500 Nan DS 4274.4 4.0 0.65 2797 1.63E+06 0.260 1500 Nan DS 4278.4 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4282.4 9.5 0.65 2787 1.33E+06 0.260 1500 Nan DS 4291.9 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4293.9 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4303.4 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4305.4 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4307.4 2.0 0.64 2740 1.09E+06 0.270 1500 Shale 4309.4 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4311.4 4.0 0.66 2847 1.29E+06 0.260 1500 Shale 4315.4 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4334.9 2.0 0.65 2823 1.36E+06 0.260 1500 Shale 4336.9 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4338.9 8.0 0.66 2858 1.37E+06 0.260 1500 Nan DS 4346.9 8.0 0.65 2815 1.56E+06 0.260 1500 Shale 4354.9 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 34 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4068.1 10.0 0.001 1.0 1890 4078.1 15.0 0.001 1.0 1898 4093.1 15.3 0.005 10.0 1905 4108.4 19.5 30.655 23.7 1915 4127.9 2.0 5.000 10.0 1924 4129.9 1.5 2.095 16.9 1925 4131.4 4.5 48.388 26.6 1926 4135.9 3.5 0.478 12.4 1928 4139.4 14.5 15.008 17.7 1930 4153.9 1.5 3.661 17.6 1937 4155.4 12.5 34.723 23.9 1937 4167.9 2.0 1.697 15.6 1943 4169.9 9.0 54.319 24.4 1944 4178.9 7.0 3.610 14.8 1948 4185.9 9.0 22.986 20.4 1952 4194.9 3.5 0.835 14.0 1956 4198.4 5.0 65.392 23.4 1957 4203.4 2.0 0.006 10.5 1960 4205.4 10.5 100.832 25.6 1961 4215.9 3.5 17.434 20.5 1966 4219.4 2.0 161.343 26.3 1967 4221.4 5.5 4.627 18.4 1968 4226.9 3.5 5.075 14.8 1971 4230.4 3.5 8.651 19.4 1972 4233.9 5.5 10.205 16.0 1974 4239.4 10.5 17.356 20.1 1977 4249.9 1.5 3.106 14.8 1982 4251.4 5.0 52.863 20.6 1982 4256.4 2.0 2.277 14.1 1985 4258.4 4.0 122.778 23.1 1986 4262.4 2.0 0.333 12.5 1987 4264.4 10.0 39.939 21.2 1988 4274.4 4.0 0.748 13.3 1993 4278.4 4.0 0.009 10.9 1995 4282.4 9.5 5.399 16.7 1997 4291.9 2.0 160.618 24.9 2001 4293.9 9.5 0.033 11.5 2002 4303.4 2.0 6.733 16.2 2007 4305.4 2.0 0.001 1.0 2008 4307.4 2.0 29.480 19.6 2009 4309.4 2.0 0.001 1.0 2009 4311.4 4.0 8.473 16.6 2010 4315.4 19.5 0.001 1.0 2012 4334.9 2.0 2.185 16.4 2021 4336.9 2.0 0.001 1.0 2022 4338.9 8.0 2.645 15.9 2023 4346.9 8.0 2.026 14.4 2027 4354.9 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 35 SLB Private Attachment K Section 26: Propped Fracture Schedule (Stage 9; 13365 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 153.3 25 1 2.0 PPA 40 YF125ST 165.5 25 2 4.0 PPA 40 YF125ST 170.2 25 4 6.0 PPA 40 YF125ST 158.4 25 6 8.0 PPA 40 YF125ST 148.1 25 8 10.0 PPA 40 YF125ST 139.1 25 10 12.0 PPA 40 YF125ST 118.0 25 12 Flush 40 YF125ST 203.6 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1506.3 bbl of YF125ST 256538 lb of % PAD Clean 19.2 % PAD Dirty 15.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 10500.0 10500 250 250 0 0 3452 6.3 6.3 1.0 PPA 6438.2 16938 160 410 6438 6438 3455 4.0 10.3 2.0 PPA 6951.5 23890 180 590 13903 20341 3516 4.5 14.8 4.0 PPA 7148.6 31038 200 790 28594 48936 3822 5.0 19.8 6.0 PPA 6653.0 37691 200 990 39918 88854 4344 5.0 24.8 8.0 PPA 6221.7 43913 200 1190 49774 138627 4865 5.0 29.8 10.0 PPA 5842.9 49756 200 1390 58429 197056 5176 5.0 34.8 12.0 PPA 4956.8 54713 180 1570 59482 256538 5324 4.5 39.3 Flush 8551.0 63264 204 1774 0 256538 4880 5.1 44.3 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 304 ft with an average conductivity (Kfw) of 19579.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 36 SLB Private Attachment K Section 27: Propped Fracture Simulation (Stage 9; 13365 ft MD) Initial Fracture Top TVD 4075.9 ft Initial Fracture Bottom TVD 4306.9 ft Propped Fracture Half-Length 304 ft EOJ Hyd Height at Well 231 ft Average Propped Width 0.224 in Net Pressure 264 psi Max Surface Pressure 5414 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 76 11.1 0.263 186.2 2.28 243.4 23736 76 152 9.8 0.264 207.7 2.35 250.8 23424 152 228 8 0.23 187.8 2.03 275.7 20161 228 304 3.7 0.15 163.3 1.4 460 12290 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 37 SLB Private Attachment K Section 28: Zone Data (Stage 10; 12823 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4071.7 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4081.7 15.0 0.70 2842 1.76E+06 0.220 1000 Nanushuk 3 SS 4096.7 15.3 0.68 2783 1.90E+06 0.220 1000 Top Nan CS 4112.0 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4131.5 2.0 0.69 2856 2.67E+06 0.230 2500 Nan CS 4133.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4135.0 4.5 0.62 2549 6.44E+05 0.280 1000 Nan DS 4139.5 3.5 0.69 2862 1.77E+06 0.260 1500 Nan DS 4143.0 14.5 0.66 2731 1.39E+06 0.260 1500 Nan CS 4157.5 1.5 0.65 2711 1.15E+06 0.270 1000 Nan CS 4159.0 12.5 0.64 2649 8.82E+05 0.270 1000 Nan DS 4171.5 2.0 0.65 2708 1.40E+06 0.260 1500 Nan CS 4173.5 9.0 0.61 2536 8.54E+05 0.270 1000 Nan DS 4182.5 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4189.5 9.0 0.65 2709 1.13E+06 0.270 1500 Nan DS 4198.5 3.5 0.64 2697 1.69E+06 0.260 1500 Nan DS 4202.0 5.0 0.64 2670 7.57E+05 0.270 1000 Nan DS 4207.0 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4209.0 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4219.5 3.5 0.64 2710 1.10E+06 0.270 1000 Nan CS 4223.0 2.0 0.62 2619 6.70E+05 0.280 1000 Nan CS 4225.0 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4230.5 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4234.0 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4237.5 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4243.0 10.5 0.64 2698 1.17E+06 0.270 1000 Nan DS 4253.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4255.0 5.0 0.62 2648 1.14E+06 0.270 1500 Nan DS 4260.0 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4262.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4266.0 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4268.0 10.0 0.63 2679 9.81E+05 0.270 1500 Nan DS 4278.0 4.0 0.65 2799 1.63E+06 0.260 1500 Nan DS 4282.0 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4286.0 9.5 0.65 2789 1.33E+06 0.260 1500 Nan DS 4295.5 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4297.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4307.0 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4309.0 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4311.0 2.0 0.64 2742 1.09E+06 0.270 1500 Shale 4313.0 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4315.0 4.0 0.66 2849 1.29E+06 0.260 1500 Shale 4319.0 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4338.5 2.0 0.65 2825 1.36E+06 0.260 1500 Shale 4340.5 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4342.5 8.0 0.66 2860 1.37E+06 0.260 1500 Nan DS 4350.5 8.0 0.65 2817 1.56E+06 0.260 1500 Shale 4358.5 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 38 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4071.7 10.0 0.001 1.0 1890 4081.7 15.0 0.001 1.0 1898 4096.7 15.3 0.005 10.0 1905 4112.0 19.5 30.655 23.7 1915 4131.5 2.0 5.000 10.0 1924 4133.5 1.5 2.095 16.9 1925 4135.0 4.5 48.388 26.6 1926 4139.5 3.5 0.478 12.4 1928 4143.0 14.5 15.008 17.7 1930 4157.5 1.5 3.661 17.6 1937 4159.0 12.5 34.723 23.9 1937 4171.5 2.0 1.697 15.6 1943 4173.5 9.0 54.319 24.4 1944 4182.5 7.0 3.610 14.8 1948 4189.5 9.0 22.986 20.4 1952 4198.5 3.5 0.835 14.0 1956 4202.0 5.0 65.392 23.4 1957 4207.0 2.0 0.006 10.5 1960 4209.0 10.5 100.832 25.6 1961 4219.5 3.5 17.434 20.5 1966 4223.0 2.0 161.343 26.3 1967 4225.0 5.5 4.627 18.4 1968 4230.5 3.5 5.075 14.8 1971 4234.0 3.5 8.651 19.4 1972 4237.5 5.5 10.205 16.0 1974 4243.0 10.5 17.356 20.1 1977 4253.5 1.5 3.106 14.8 1982 4255.0 5.0 52.863 20.6 1982 4260.0 2.0 2.277 14.1 1985 4262.0 4.0 122.778 23.1 1986 4266.0 2.0 0.333 12.5 1987 4268.0 10.0 39.939 21.2 1988 4278.0 4.0 0.748 13.3 1993 4282.0 4.0 0.009 10.9 1995 4286.0 9.5 5.399 16.7 1997 4295.5 2.0 160.618 24.9 2001 4297.5 9.5 0.033 11.5 2002 4307.0 2.0 6.733 16.2 2007 4309.0 2.0 0.001 1.0 2008 4311.0 2.0 29.480 19.6 2009 4313.0 2.0 0.001 1.0 2009 4315.0 4.0 8.473 16.6 2010 4319.0 19.5 0.001 1.0 2012 4338.5 2.0 2.185 16.4 2021 4340.5 2.0 0.001 1.0 2022 4342.5 8.0 2.645 15.9 2023 4350.5 8.0 2.026 14.4 2027 4358.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 39 SLB Private Attachment K Section 29: Propped Fracture Schedule (Stage 10; 12823 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 275.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 183.9 25 2 4.0 PPA 40 YF125ST 187.2 25 4 6.0 PPA 40 YF125ST 174.2 25 6 8.0 PPA 40 YF125ST 162.9 25 8 10.0 PPA 40 YF125ST 139.1 25 10 12.0 PPA 40 YF125ST 118.0 25 12 Flush 40 YF125ST 195.3 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1606.3 bbl of YF125ST 0 bbl of WF125 270716 lb of % PAD Clean 19.5 % PAD Dirty 16.2 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 11550.0 11550 275 275 0 0 3352 6.9 6.9 1.0 PPA 7243.0 18793 180 455 7243 7243 3358 4.5 11.4 2.0 PPA 7723.9 26517 200 655 15448 22691 3425 5.0 16.4 4.0 PPA 7863.4 34380 220 875 31454 54145 3747 5.5 21.9 6.0 PPA 7318.3 41699 220 1095 43910 98055 4255 5.5 27.4 8.0 PPA 6843.9 48543 220 1315 54751 152805 4731 5.5 32.9 10.0 PPA 5842.9 54385 200 1515 58429 211234 5002 5.0 37.9 12.0 PPA 4956.8 59342 180 1695 59482 270716 5121 4.5 42.4 Flush 8204.3 67547 195 1890 0 270716 4712 4.9 47.3 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 315.3 ft with an average conductivity (Kfw) of 19730.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Job Execution Step Name 40 SLB Private Attachment K Section 30: Propped Fracture Simulation (Stage 10; 12823 ft MD) Initial Fracture Top TVD 4079.1 ft Initial Fracture Bottom TVD 4313 ft Propped Fracture Half-Length 315.3 ft EOJ Hyd Height at Well 233.9 ft Average Propped Width 0.225 in Net Pressure 266 psi Max Surface Pressure 5193 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 78.8 11.2 0.265 188.8 2.29 250.8 23837 78.8 157.6 9.4 0.263 210.2 2.34 257.5 23311 157.6 236.5 8.1 0.242 187.1 2.17 274.8 21044 236.5 315.3 3.7 0.144 168.3 1.35 526.4 12010 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 41 SLB Private Attachment K Section 31: Zone Data (Stage 11; 12282 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4075.7 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4085.7 15.0 0.70 2845 1.76E+06 0.220 1000 Nanushuk 3 SS 4100.7 15.3 0.68 2785 1.90E+06 0.220 1000 Top Nan CS 4116.0 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4135.5 2.0 0.69 2858 2.67E+06 0.230 2500 Nan CS 4137.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4139.0 4.5 0.62 2551 6.44E+05 0.280 1000 Nan DS 4143.5 3.5 0.69 2864 1.77E+06 0.260 1500 Nan DS 4147.0 14.5 0.66 2733 1.39E+06 0.260 1500 Nan CS 4161.5 1.5 0.65 2714 1.15E+06 0.270 1000 Nan CS 4163.0 12.5 0.64 2652 8.82E+05 0.270 1000 Nan DS 4175.5 2.0 0.65 2711 1.40E+06 0.260 1500 Nan CS 4177.5 9.0 0.61 2538 8.54E+05 0.270 1000 Nan DS 4186.5 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4193.5 9.0 0.65 2712 1.13E+06 0.270 1500 Nan DS 4202.5 3.5 0.64 2699 1.69E+06 0.260 1500 Nan DS 4206.0 5.0 0.64 2672 7.57E+05 0.270 1000 Nan DS 4211.0 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4213.0 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4223.5 3.5 0.64 2713 1.10E+06 0.270 1000 Nan CS 4227.0 2.0 0.62 2621 6.70E+05 0.280 1000 Nan CS 4229.0 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4234.5 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4238.0 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4241.5 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4247.0 10.5 0.64 2700 1.17E+06 0.270 1000 Nan DS 4257.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4259.0 5.0 0.62 2651 1.14E+06 0.270 1500 Nan DS 4264.0 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4266.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4270.0 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4272.0 10.0 0.63 2682 9.81E+05 0.270 1500 Nan DS 4282.0 4.0 0.65 2802 1.63E+06 0.260 1500 Nan DS 4286.0 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4290.0 9.5 0.65 2792 1.33E+06 0.260 1500 Nan DS 4299.5 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4301.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4311.0 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4313.0 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4315.0 2.0 0.64 2745 1.09E+06 0.270 1500 Shale 4317.0 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4319.0 4.0 0.66 2852 1.29E+06 0.260 1500 Shale 4323.0 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4342.5 2.0 0.65 2828 1.36E+06 0.260 1500 Shale 4344.5 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4346.5 8.0 0.66 2863 1.37E+06 0.260 1500 Nan DS 4354.5 8.0 0.65 2820 1.56E+06 0.260 1500 Shale 4362.5 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 42 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4075.7 10.0 0.001 1.0 1890 4085.7 15.0 0.001 1.0 1898 4100.7 15.3 0.005 10.0 1905 4116.0 19.5 30.655 23.7 1915 4135.5 2.0 5.000 10.0 1924 4137.5 1.5 2.095 16.9 1925 4139.0 4.5 48.388 26.6 1926 4143.5 3.5 0.478 12.4 1928 4147.0 14.5 15.008 17.7 1930 4161.5 1.5 3.661 17.6 1937 4163.0 12.5 34.723 23.9 1937 4175.5 2.0 1.697 15.6 1943 4177.5 9.0 54.319 24.4 1944 4186.5 7.0 3.610 14.8 1948 4193.5 9.0 22.986 20.4 1952 4202.5 3.5 0.835 14.0 1956 4206.0 5.0 65.392 23.4 1957 4211.0 2.0 0.006 10.5 1960 4213.0 10.5 100.832 25.6 1961 4223.5 3.5 17.434 20.5 1966 4227.0 2.0 161.343 26.3 1967 4229.0 5.5 4.627 18.4 1968 4234.5 3.5 5.075 14.8 1971 4238.0 3.5 8.651 19.4 1972 4241.5 5.5 10.205 16.0 1974 4247.0 10.5 17.356 20.1 1977 4257.5 1.5 3.106 14.8 1982 4259.0 5.0 52.863 20.6 1982 4264.0 2.0 2.277 14.1 1985 4266.0 4.0 122.778 23.1 1986 4270.0 2.0 0.333 12.5 1987 4272.0 10.0 39.939 21.2 1988 4282.0 4.0 0.748 13.3 1993 4286.0 4.0 0.009 10.9 1995 4290.0 9.5 5.399 16.7 1997 4299.5 2.0 160.618 24.9 2001 4301.5 9.5 0.033 11.5 2002 4311.0 2.0 6.733 16.2 2007 4313.0 2.0 0.001 1.0 2008 4315.0 2.0 29.480 19.6 2009 4317.0 2.0 0.001 1.0 2009 4319.0 4.0 8.473 16.6 2010 4323.0 19.5 0.001 1.0 2012 4342.5 2.0 2.185 16.4 2021 4344.5 2.0 0.001 1.0 2022 4346.5 8.0 2.645 15.9 2023 4354.5 8.0 2.026 14.4 2027 4362.5 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 43 SLB Private Attachment K Section 32: Propped Fracture Schedule (Stage 11; 12282 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 210.0 25 0 1.0 PPA 40 YF125ST 57.5 25 1 3.0 PPA 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 134.1 25 1 2.0 PPA 40 YF125ST 147.1 25 2 4.0 PPA 40 YF125ST 153.2 25 4 6.0 PPA 40 YF125ST 142.6 25 6 8.0 PPA 40 YF125ST 133.3 25 8 10.0 PPA 40 YF125ST 118.2 25 10 12.0 PPA 40 YF125ST 98.3 25 12 Flush 40 YF125ST 187.1 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1537.4 bbl of YF125ST 0 bbl of WF125 223682 lb of 15756 lb of % PAD Clean 15.6 % PAD Dirty 13.1 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 8820.0 8820 210 210 0 0 3254 5.3 5.3 1.0 PPA 2412.9 11233 60 270 2413 2413 3255 1.5 6.8 3.0 PPA 4447.8 15681 120 390 13343 15756 3299 3.0 9.8 Resume PAD 2100.0 17781 50 440 0 15756 3416 1.3 11.0 1.0 PPA 5633.5 23414 140 580 5633 21390 3483 3.5 14.5 2.0 PPA 6179.1 29593 160 740 12358 33748 3342 4.0 18.5 4.0 PPA 6433.7 36027 180 920 25735 59483 3585 4.5 23.0 6.0 PPA 5987.7 42015 180 1100 35926 95409 4026 4.5 27.5 8.0 PPA 5599.5 47614 180 1280 44796 140205 4486 4.5 32.0 10.0 PPA 4966.5 52581 170 1450 49665 189870 4775 4.3 36.3 12.0 PPA 4130.7 56711 150 1600 49568 239438 4897 3.8 40.0 Flush 7858.1 64570 187 1787 0 239438 4560 4.7 44.7 Job Execution Step Name Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 282.1 ft with an average conductivity (Kfw) of 19353 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV 44 SLB Private Attachment K Section 33: Propped Fracture Simulation (Stage 11; 12282 ft MD) Initial Fracture Top TVD 4083.5 ft Initial Fracture Bottom TVD 4316.9 ft Propped Fracture Half-Length 282.1 ft EOJ Hyd Height at Well 233.5 ft Average Propped Width 0.222 in Net Pressure 272 psi Max Surface Pressure 4967 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 70.5 10.4 0.28 144 2.43 253.8 25404 70.5 141 8.7 0.266 208.3 2.35 272.9 23587 141 211.6 6.8 0.23 198.2 2.05 306.4 19932 211.6 282.1 2.8 0.128 161.7 1.23 431.1 10656 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 45 SLB Private Attachment K Section 34: Zone Data (Stage 12; 11741 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4075.7 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4085.7 15.0 0.70 2845 1.76E+06 0.220 1000 Nanushuk 3 SS 4100.7 15.3 0.68 2785 1.90E+06 0.220 1000 Top Nan CS 4116.0 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4135.5 2.0 0.69 2858 2.67E+06 0.230 2500 Nan CS 4137.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4139.0 4.5 0.62 2551 6.44E+05 0.280 1000 Nan DS 4143.5 3.5 0.69 2864 1.77E+06 0.260 1500 Nan DS 4147.0 14.5 0.66 2733 1.39E+06 0.260 1500 Nan CS 4161.5 1.5 0.65 2714 1.15E+06 0.270 1000 Nan CS 4163.0 12.5 0.64 2652 8.82E+05 0.270 1000 Nan DS 4175.5 2.0 0.65 2711 1.40E+06 0.260 1500 Nan CS 4177.5 9.0 0.61 2538 8.54E+05 0.270 1000 Nan DS 4186.5 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4193.5 9.0 0.65 2712 1.13E+06 0.270 1500 Nan DS 4202.5 3.5 0.64 2699 1.69E+06 0.260 1500 Nan DS 4206.0 5.0 0.64 2672 7.57E+05 0.270 1000 Nan DS 4211.0 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4213.0 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4223.5 3.5 0.64 2713 1.10E+06 0.270 1000 Nan CS 4227.0 2.0 0.62 2621 6.70E+05 0.280 1000 Nan CS 4229.0 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4234.5 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4238.0 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4241.5 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4247.0 10.5 0.64 2700 1.17E+06 0.270 1000 Nan DS 4257.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4259.0 5.0 0.62 2651 1.14E+06 0.270 1500 Nan DS 4264.0 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4266.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4270.0 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4272.0 10.0 0.63 2682 9.81E+05 0.270 1500 Nan DS 4282.0 4.0 0.65 2802 1.63E+06 0.260 1500 Nan DS 4286.0 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4290.0 9.5 0.65 2792 1.33E+06 0.260 1500 Nan DS 4299.5 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4301.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4311.0 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4313.0 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4315.0 2.0 0.64 2745 1.09E+06 0.270 1500 Shale 4317.0 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4319.0 4.0 0.66 2852 1.29E+06 0.260 1500 Shale 4323.0 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4342.5 2.0 0.65 2828 1.36E+06 0.260 1500 Shale 4344.5 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4346.5 8.0 0.66 2863 1.37E+06 0.260 1500 Nan DS 4354.5 8.0 0.65 2820 1.56E+06 0.260 1500 Shale 4362.5 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 46 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4075.7 10.0 0.001 1.0 1890 4085.7 15.0 0.001 1.0 1898 4100.7 15.3 0.005 10.0 1905 4116.0 19.5 30.655 23.7 1915 4135.5 2.0 5.000 10.0 1924 4137.5 1.5 2.095 16.9 1925 4139.0 4.5 48.388 26.6 1926 4143.5 3.5 0.478 12.4 1928 4147.0 14.5 15.008 17.7 1930 4161.5 1.5 3.661 17.6 1937 4163.0 12.5 34.723 23.9 1937 4175.5 2.0 1.697 15.6 1943 4177.5 9.0 54.319 24.4 1944 4186.5 7.0 3.610 14.8 1948 4193.5 9.0 22.986 20.4 1952 4202.5 3.5 0.835 14.0 1956 4206.0 5.0 65.392 23.4 1957 4211.0 2.0 0.006 10.5 1960 4213.0 10.5 100.832 25.6 1961 4223.5 3.5 17.434 20.5 1966 4227.0 2.0 161.343 26.3 1967 4229.0 5.5 4.627 18.4 1968 4234.5 3.5 5.075 14.8 1971 4238.0 3.5 8.651 19.4 1972 4241.5 5.5 10.205 16.0 1974 4247.0 10.5 17.356 20.1 1977 4257.5 1.5 3.106 14.8 1982 4259.0 5.0 52.863 20.6 1982 4264.0 2.0 2.277 14.1 1985 4266.0 4.0 122.778 23.1 1986 4270.0 2.0 0.333 12.5 1987 4272.0 10.0 39.939 21.2 1988 4282.0 4.0 0.748 13.3 1993 4286.0 4.0 0.009 10.9 1995 4290.0 9.5 5.399 16.7 1997 4299.5 2.0 160.618 24.9 2001 4301.5 9.5 0.033 11.5 2002 4311.0 2.0 6.733 16.2 2007 4313.0 2.0 0.001 1.0 2008 4315.0 2.0 29.480 19.6 2009 4317.0 2.0 0.001 1.0 2009 4319.0 4.0 8.473 16.6 2010 4323.0 19.5 0.001 1.0 2012 4342.5 2.0 2.185 16.4 2021 4344.5 2.0 0.001 1.0 2022 4346.5 8.0 2.645 15.9 2023 4354.5 8.0 2.026 14.4 2027 4362.5 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 47 SLB Private Attachment K Section 35: Propped Fracture Schedule (Stage 12; 11741 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 200.0 25 0 1.0 PPA 40 YF125ST 57.5 25 1 3.0 PPA 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 143.7 25 1 2.0 PPA 40 YF125ST 160.9 25 2 4.0 PPA 40 YF125ST 161.7 25 4 6.0 PPA 40 YF125ST 150.5 25 6 8.0 PPA 40 YF125ST 140.7 25 8 10.0 PPA 40 YF125ST 132.2 25 10 12.0 PPA 40 YF125ST 104.9 25 12 Flush 40 YF125ST 178.9 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1586.8 bbl of YF125ST 0 bbl of WF125 240305 lb of 15756 lb of % PAD Clean 14.2 % PAD Dirty 11.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 8400.0 8400 200 200 0 0 3166 5.0 5.0 1.0 PPA 2412.9 10813 60 260 2413 2413 3162 1.5 6.5 3.0 PPA 4447.8 15261 120 380 13343 15756 3219 3.0 9.5 Resume PAD 2100.0 17361 50 430 0 15756 3371 1.3 10.8 1.0 PPA 6035.8 23397 150 580 6036 21792 3374 3.8 14.5 2.0 PPA 6758.4 30155 175 755 13517 35309 3225 4.4 18.9 4.0 PPA 6791.2 36946 190 945 27165 62474 3476 4.8 23.6 6.0 PPA 6320.4 43267 190 1135 37922 100396 3946 4.8 28.4 8.0 PPA 5910.6 49177 190 1325 47285 147681 4367 4.8 33.1 10.0 PPA 5550.8 54728 190 1515 55508 203188 4609 4.8 37.9 12.0 PPA 4406.1 59134 160 1675 52873 256061 4711 4.0 41.9 Flush 7512.0 66646 179 1854 0 256061 4369 4.5 46.3 Job Execution Step Name Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IVCarbolite 16/20 + 6wt% ScaleGuard IVCarbolite 16/20 + 6wt% ScaleGuard IVCarbolite 16/20 + 6wt% ScaleGuard IVCarbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 279.6 ft with an average conductivity (Kfw) of 20776.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV 48 SLB Private Attachment K Section 36: Propped Fracture Simulation (Stage 12; 11741 ft MD) Initial Fracture Top TVD 4083.3 ft Initial Fracture Bottom TVD 4316.9 ft Propped Fracture Half-Length 279.6 ft EOJ Hyd Height at Well 233.6 ft Average Propped Width 0.237 in Net Pressure 283 psi Max Surface Pressure 4779 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 69.9 10.5 0.299 146.1 2.6 250.3 27257 69.9 139.8 8.9 0.281 208.5 2.47 271.4 24980 139.8 209.7 6.9 0.247 198.7 2.18 301.4 21455 209.7 279.6 2.8 0.143 156.8 1.36 411.4 12091 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 49 SLB Private Attachment K SLB Private Attachment K Section 37: Zone Data (Stage 13; 11200 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4079.4 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4089.4 15.0 0.70 2847 1.76E+06 0.220 1000 Nanushuk 3 SS 4104.4 15.3 0.68 2788 1.90E+06 0.220 1000 Top Nan CS 4119.7 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4139.2 2.0 0.69 2861 2.67E+06 0.230 2500 Nan CS 4141.2 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4142.7 4.5 0.62 2553 6.44E+05 0.280 1000 Nan DS 4147.2 3.5 0.69 2867 1.77E+06 0.260 1500 Nan DS 4150.7 14.5 0.66 2736 1.39E+06 0.260 1500 Nan CS 4165.2 1.5 0.65 2716 1.15E+06 0.270 1000 Nan CS 4166.7 12.5 0.64 2654 8.82E+05 0.270 1000 Nan DS 4179.2 2.0 0.65 2713 1.40E+06 0.260 1500 Nan CS 4181.2 9.0 0.61 2541 8.54E+05 0.270 1000 Nan DS 4190.2 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4197.2 9.0 0.65 2714 1.13E+06 0.270 1500 Nan DS 4206.2 3.5 0.64 2702 1.69E+06 0.260 1500 Nan DS 4209.7 5.0 0.64 2675 7.57E+05 0.270 1000 Nan DS 4214.7 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4216.7 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4227.2 3.5 0.64 2715 1.10E+06 0.270 1000 Nan CS 4230.7 2.0 0.62 2624 6.70E+05 0.280 1000 Nan CS 4232.7 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4238.2 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4241.7 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4245.2 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4250.7 10.5 0.64 2703 1.17E+06 0.270 1000 Nan DS 4261.2 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4262.7 5.0 0.62 2653 1.14E+06 0.270 1500 Nan DS 4267.7 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4269.7 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4273.7 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4275.7 10.0 0.63 2684 9.81E+05 0.270 1500 Nan DS 4285.7 4.0 0.65 2804 1.63E+06 0.260 1500 Nan DS 4289.7 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4293.7 9.5 0.65 2794 1.33E+06 0.260 1500 Nan DS 4303.2 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4305.2 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4314.7 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4316.7 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4318.7 2.0 0.64 2747 1.09E+06 0.270 1500 Shale 4320.7 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4322.7 4.0 0.66 2854 1.29E+06 0.260 1500 Shale 4326.7 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4346.2 2.0 0.65 2830 1.36E+06 0.260 1500 Shale 4348.2 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4350.2 8.0 0.66 2865 1.37E+06 0.260 1500 Nan DS 4358.2 8.0 0.65 2822 1.56E+06 0.260 1500 Shale 4366.2 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 50 SLB Private Attachment K SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4079.4 10.0 0.001 1.0 1890 4089.4 15.0 0.001 1.0 1898 4104.4 15.3 0.005 10.0 1905 4119.7 19.5 30.655 23.7 1915 4139.2 2.0 5.000 10.0 1924 4141.2 1.5 2.095 16.9 1925 4142.7 4.5 48.388 26.6 1926 4147.2 3.5 0.478 12.4 1928 4150.7 14.5 15.008 17.7 1930 4165.2 1.5 3.661 17.6 1937 4166.7 12.5 34.723 23.9 1937 4179.2 2.0 1.697 15.6 1943 4181.2 9.0 54.319 24.4 1944 4190.2 7.0 3.610 14.8 1948 4197.2 9.0 22.986 20.4 1952 4206.2 3.5 0.835 14.0 1956 4209.7 5.0 65.392 23.4 1957 4214.7 2.0 0.006 10.5 1960 4216.7 10.5 100.832 25.6 1961 4227.2 3.5 17.434 20.5 1966 4230.7 2.0 161.343 26.3 1967 4232.7 5.5 4.627 18.4 1968 4238.2 3.5 5.075 14.8 1971 4241.7 3.5 8.651 19.4 1972 4245.2 5.5 10.205 16.0 1974 4250.7 10.5 17.356 20.1 1977 4261.2 1.5 3.106 14.8 1982 4262.7 5.0 52.863 20.6 1982 4267.7 2.0 2.277 14.1 1985 4269.7 4.0 122.778 23.1 1986 4273.7 2.0 0.333 12.5 1987 4275.7 10.0 39.939 21.2 1988 4285.7 4.0 0.748 13.3 1993 4289.7 4.0 0.009 10.9 1995 4293.7 9.5 5.399 16.7 1997 4303.2 2.0 160.618 24.9 2001 4305.2 9.5 0.033 11.5 2002 4314.7 2.0 6.733 16.2 2007 4316.7 2.0 0.001 1.0 2008 4318.7 2.0 29.480 19.6 2009 4320.7 2.0 0.001 1.0 2009 4322.7 4.0 8.473 16.6 2010 4326.7 19.5 0.001 1.0 2012 4346.2 2.0 2.185 16.4 2021 4348.2 2.0 0.001 1.0 2022 4350.2 8.0 2.645 15.9 2023 4358.2 8.0 2.026 14.4 2027 4366.2 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 51 SLB Private Attachment K SLB Private Attachment K Section 38: Propped Fracture Schedule (Stage 13; 11200 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 200.0 25 0 1.0 PPA 40 YF125ST 57.5 25 1 3.0 PPA 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 167.7 25 1 2.0 PPA 40 YF125ST 174.7 25 2 4.0 PPA 40 YF125ST 161.7 25 4 6.0 PPA 40 YF125ST 150.5 25 6 8.0 PPA 40 YF125ST 140.7 25 8 10.0 PPA 40 YF125ST 66.1 25 10 10.0 PPA 40 YF125ST 66.1 25 10 12.0 PPA 40 YF125ST 103.2 25 12 Flush 40 YF125ST 170.6 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1614.7 bbl of YF125ST 0 bbl of WF125 189596 lb of 15,758 lb of 52030 lb of % PAD Clean 13.8 % PAD Dirty 11.7 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 8400.0 8400 200 200 0 0 3073 5.0 5.0 1.0 PPA 2414.3 10814 60 260 2414 2414 3067 1.5 6.5 3.0 PPA 4447.8 15262 120 380 13343 15758 3116 3.0 9.5 Resume PAD 2100.0 17362 50 430 0 15758 3255 1.3 10.8 1.0 PPA 7041.8 24404 175 605 7042 22800 3225 4.4 15.1 2.0 PPA 7337.7 31742 190 795 14675 37475 3125 4.8 19.9 4.0 PPA 6791.2 38533 190 985 27165 64640 3375 4.8 24.6 6.0 PPA 6320.4 44853 190 1175 37922 102562 3794 4.8 29.4 8.0 PPA 5910.6 50764 190 1365 47285 149847 4195 4.8 34.1 10.0 PPA 2775.4 53539 95 1460 27754 177601 4404 2.4 36.5 10.0 PPA 2775.4 56315 95 1555 27754 205354 4460 2.4 38.9 12.0 PPA 4335.8 60650 160 1715 52030 257384 4522 4.0 42.9 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 258.2 ft with an average conductivity (Kfw) of 26872 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 12/18 Carbolite 40/70 Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 12/18 Job Execution Step Name 52 SLB Private Attachment K SLB Private Attachment K 53 SLB Private Attachment K SLB Private Attachment K Section 39: Propped Fracture Simulation (Stage 13; 11200 ft MD) Initial Fracture Top TVD 4085.5 ft Initial Fracture Bottom TVD 4322.8 ft Propped Fracture Half-Length 258.2 ft EOJ Hyd Height at Well 237.3 ft Average Propped Width 0.253 in Net Pressure 216 psi Max Surface Pressure 4616 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 64.6 10.4 0.333 161.6 2.91 241.5 46283 64.6 129.1 8.7 0.308 219.5 2.73 269.2 31884 129.1 193.7 6.6 0.263 207.4 2.38 310.1 23152 193.7 258.2 2.3 0.136 163.5 1.32 485.3 11252 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 54 SLB Private Attachment K Santos USA and Baker Hughes Confidential Page 1 © 2018 Baker Hughes, LLC - All rights reserved. LLWD Qualitative Cement Bond Log Evaluation Report Well Name, Section: NDB-037, 9 5/8” Liner Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: Reservoir Technical Services Alaska Version: Preliminary Report Santos USA and Baker Hughes Confidential Page 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Tool Diagram .......................................................................................................................................................................................................... 7 Methodology of LWD Cement Bond Log Evaluation .................................................................................................................8 Log Screen Captures ...................................................................................................................................................................................... 13 Santos USA and Baker Hughes Confidential Page 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMER THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. Santos USA and Baker Hughes Confidential Page 4 Executive Summary Cement Bond Logging with LWD Acoustic (Sonic) tool SoundTrak was performed after drilling of 8 ½” section. Logs were acquired while pulling out of hole across 9 5/8” liner in upward direction. The objective and plan were to cover with CBL logs to evaluate the first stage cementing from the 9 5/8” Liner shoe to the planned TOC of 8,400’ MD. Cement Bond Index (BI) curve was computed and presented in the log plot showing color gradation from good cement bond (brown) to poor cement (blue). The following values were used by interpreter to differentiate intervals of good bond (curve value above 0.8) to partial (0.2 to 0.8) and poor (lower than 0.2). Summaries of initial pre-job logging plan and Cement Bond Index interpretation are outlined below. Logging Plan Summary Down link to the SoundTrak tool after drilling of 8 ½” open hole and upon coming to the liner shoe at 10,862’ MD to initiate top of cement mode and continue backreaming out of hole to log the cement in the 9 5/8” Liner at 400 gpm and 120 rpm (per Bakerhughes recommendation). x Log cement from 9-5/8” shoe (10,862’ MD) to 8,400’ MD planned top of cement. Log up at 1,200 fph. x Log free pipe from 8,400’ to 7,360’ MD (1,040’ of free pipe) at 1,200 fph. LWD logging was optimized to gain higher efficiency and reduce overall rig time by modifying acquisition parameters and logging at 1200 ft/hr entire well interval. Santos USA and Baker Hughes Confidential Page 5 Interpretation Summary The Intermediate was drilled and a 9 5/8” Casing shoe was set at 10,862ft. After drilling 8 ½” to TD, a Logging up was performed to capture cement Bond on the 9 5/8” casing. Following observations are summarized below by interval. Please note that Bond Index curve (BI) and color coding in combination with other data on the log can be used for more detailed interval inspection to draw conclusions on zonal isolation of narrower intervals. Overall, 6 main zones were defined as listed below, with more detailed interpretation within each zone presented in the table that follows. - 7,357’-7,985’: Poor to no cement presence above 7,985’. - 7,985’-8,350’: Poor to partial Cement presence. - 8,350’-8,580’: Good to partial Cement presence. Mostly Good. - 8,580’ to 9,120’ Very Good Cement presence. - 9,120’ to 9,700’ Good Cement presence with some partial presence Interval. Mostly Good. - 9,700’ to TD Very Good cement presence throughout this interval. For more detailed description of each interval please refer to the table below summarizing Interpretation results. Santos USA and Baker Hughes Confidential Page 6 Santos USA and Baker Hughes Confidential Page 7 Tool Diagram Santos USA and Baker Hughes Confidential Page 8 Methodology of LWD Cement Bond Log Evaluation Before the arrival of more advanced Wireline technologies offering azimuthal coverage of the casing to cement and cement to formation bonding, oil and gas operators have been relying on traditional non-azimuthal CBL, Cement Bond Log, technique, that is being run successfully to date. Wireline Acoustic (Sonic) tool’s CBL measurement principle relies on detecting and measuring first “casing ringing” amplitude reflected from the casing wall. The idea is that free pipe (with cement absence) would “ring” freely creating high Casing Ringing Amplitude, whereas well cemented casing would result in dampened first arrival and thus indicate well cemented pipe. Traditional Wireline tool relies on the arrival of the sound detected at the receiver spaced at 3 ft for CBL Amplitude and for the one from the 5 ft spaced receiver for VDL (Variable Density Log). Figure 1: Traditional Wireline CBL technique Santos USA and Baker Hughes Confidential Page 9 LWD Acoustic (Sonic) tool is using the same principle for CBL measurement. It is also non- azimuthal. However, the one difference is that receiver spacing is longer and all measurements are based on the 10.7 ft receiver spacing for CBL Amplitude. See figures below for the main principle behind cemented vs free pipe detection in traditional CBL measurement. Figure 2: CBL concept in "free" pipe Figure 3: CBL concept in cemented pipe Santos USA and Baker Hughes Confidential Page 10 Figure 4: General CBL concept and corresponding log example Figure 5: LWD Acoustic (Sonic) tool and LWD CBL concept Current traditional offering of LWD Acoustic (Sonic) tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling trip typically on the way out of casing after drilling is completed. Santos USA and Baker Hughes Confidential Page 11 Baker Hughes offers both traditional TOC service and a more advanced workflow of providing Cement Bond Index. This Cement Bond Index is a relative Cement Quality Indicator helping operators to still acquire positive zonal isolation information in wells where running Wireline could be challenging and / or would otherwise increase overall rig time. To convert casing amplitude to cement bond index (BI), two reference points are required: -Free casing - 100% bonded point Figure 6: Cement Bond Index computation concept Traditionally as part of the CBL logging deliverable, Bond Index (BI) is computed and displayed in the log. Values above 80% BI are typically seen as “good" cement, whereas values below 80% are typically seen as either "poor," contaminated or channeled cement. Note however, that the TR spacing (10.66 ft) for LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality check must be carried out to validate the data, because If the casing amplitude in these well bonded intervals is below noise level, the 100% bonded reference point might be incorrect and the “BI” could be over-estimated, reducing quantitative precision of the measurement. Additionally, Cement Evaluation with LWD SoundTrak tool would be ideal in standard cements with slurry density of equal or greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. For example, detection of behind casing open hole DT from waveforms could confirm that proper cement is present. Santos USA and Baker Hughes Confidential Page 12 Furthermore, adding this service can increase operational efficiency since it can be done in the same drilling trip on the way out and logging speed for top of cement detection and CBL evaluation can be as high as ~1500 ft/hr still providing good data quality. With combination of casing mode semblance (SV) and formation arrival in correlogram, TOC can be detected in Real-Time. Good agreement between RT and memory TOC can be seen in the figure below. Figure 7: LWD capability of Real-Time Top of Cement acquisition This method has limitations though as it has no azimuthal coverage and can not identify micro channeling. It is not a replacement for quantitative cement evaluation tools such as SBT, InTex, or CICM Santos USA and Baker Hughes Confidential Page 13 Log Screen Captures Following figures contain interpretation observations, however Bond Index curve and color coding can be used for more detailed interval inspection to draw conclusions on zonal isolation. Please refer to the tables on pages 6 for more detailed interpretation. Figure 8: Interval 1 of LWD CBL logging General Interpretation Comments: 7,357’ to 7,700’ poor to no cement in that interval. Santos USA and Baker Hughes Confidential Page 14 Figure 9: Interval 2 of LWD CBL Logging General Interpretation Comments: 7,700’ to 7,985’ poor cement presence in that interval. 7,985’ to 8,350’ Partial to poor Cement presence. Santos USA and Baker Hughes Confidential Page 15 Figure 10: Interval 3 of LWD CBL Logging General Interpretation Comments: 8,350’ to 8,585’ Good to Partial cement presence. 8,585’ to 8,800’ Very good cement presence. Santos USA and Baker Hughes Confidential Page 16 Figure 11: Interval 4 of LWD CBL Logging General Interpretation Comments: 8,800’ to 9,120’ Very Good Cement Presence. 9,120’-9,400’ Partial to Good. Mostly Good, with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 17 Figure 12: Interval 5 of LWD CBL Logging General Interpretation Comments: 9,400’-9,700’ Partial to Good. Mostly Good, with some intervals of partial cement presence. 9,700’ to 10,000’ Very Good cement presence through this interval. Santos USA and Baker Hughes Confidential Page 18 Figure 13: Interval 6 of LWD CBL Logging General Interpretation Comments: 10,000’ to 10,600’ Very Good presence throughout the interval. Santos USA and Baker Hughes Confidential Page 19 Figure 14: Interval 7 of LWD CBL Logging General Interpretation Comments: 10,600’ to TD. Very Good cement presence. WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityNDBi-043/ NDBi-043A ACTIVE 9-5/8" 47ppf 4,955 (Nanushuk) 3,795 (Nanushuk) 2,792 2,730 log open hole liner for injectionTOC 2,792 MD' & packer @ 6,071'Cement 9-5/8" intermediate liner as follows: Pump 80 bbls of 11.8 ppg tuned spacer at 5 bpm, 300 psi. Drop bottom drill pipe wiper dart. Pump 277 bbls of 12 ppg ld cement-665 sks, yld 2.35 @ 3-5 bpm. Pump 44 bbls of 15.3 ppg tail -200 sks, yld 1.24 @ 3-5 bpm. Drop top drill pipe wiper dart and kick out with 10 bbls water. Perform displacement with rig pumps at 5-8 bpm. ICP 185 psi 3% return flow. FCP 800 psi 8% return flow. Displacement fluid: 261 bbls of 11.2 ppg MOBM, 30 bbls of 11.8 ppg tuned spacer, 27 bbls 11.2 ppg MOBM. Latch up confirmed at 40 bbls displaced. Reduce rate to 3 bpm prior to plug bump. Final circulating pressure 340 psi. Plug bumped on calculated volume. Total displacement volume 317 bbls. Check floats- good. CIP 2320. Total losses from cement exit shoe to cement in place- 0 bbls. 8/21/23, 9-5/8" casing pressure tested to 4,200 psi for 30 minutes NDBi-043 Well Schematic 20" Insulated Conductor80' MD 9-5/8" Liner Hanger and Liner Top Packer2331' MD 13-3/8" 68 ppf L-80 Surface Casing2502' MD 9-5/8", 47ppf L-80 Production Liner6237' MD 4-½”, 12.6ppf P-110S Production Liner13207' MD Plug Back TD10947' MDKOP10136' MD 4-½” Liner Hanger/Top Packer6071' MD GL 46.6' RKB – Bottom Flange 08/19/2023 #CompletionItem Depth(MD') Depth(TVD') Inc ID" OD" 1XLandingNipple 1431 1408 23 3.813 4.773 2GLMw/1.5"Pocket 1486 1458 24 3.958 7.575 3XLandingNipple 1550 1516 26 3.813 4.773 4XLandingNipple 5938 4262 75 3.813 4.773 5P/TD.H.Gauge 5993 4275 77 3.958 5.500 6XLandingNipple 6008 4279 77 3.813 4.773 7TiebackSealAssy 6104 4298 79 3.890 5.280 8 9.625"x4.5"LH/Packer 6071 4292 78 6.040 8.430 9#13OpenholePacker 6757 4355 91 3.918 8.000 10 Stage11ͲFracSleeve 6980 4350 91 3.735 5.627 11 #12OpenholePacker 7244 4344 91 3.918 8.000 12 Stage10ͲFracSleeve 7465 4340 91 3.735 5.627 13 #11OpenholePacker 7728 4334 91 3.918 8.000 14 Stage9ͲFracSleeve 8075 4326 91 3.735 5.627 15 #10OpenholePacker 8378 4320 91 3.918 8.000 16 Stage8ͲFracSleeve 8602 4315 91 3.735 5.627 17 #9OpenholePacker 8864 4309 91 3.918 8.000 18 Stage7ͲFracSleeve 9130 4304 91 3.735 5.627 19 #8OpenholePacker 9351 4299 91 3.918 8.000 20 Stage6ͲFracSleeve 9658 4292 91 3.735 5.627 21 #7OpenholePacker 9879 4287 91 3.918 8.000 22 #6OpenholePacker 10351 4277 91 3.918 8.000 23 Stage5ͲFracSleeve 10823 4267 91 3.735 5.627 24 #5OpenholePacker 11085 4261 91 3.918 8.000 25 Stage4ͲFracSleeve 11351 4256 91 3.735 5.627 26 #4OpenholePacker 11655 4249 91 3.918 8.000 27 Stage3ͲFracSleeve 11839 4245 91 3.735 5.627 28 #3OpenholePacker 12101 4239 91 3.918 8.000 29 Stage2ͲFracSleeve 12325 4234 91 3.735 5.627 30 #2OpenholePacker 12587 4229 91 3.918 8.000 31 Stage1ͲFracSleeve 12851 4223 91 3.735 5.627 32 #1OpenholePacker 13073 4218 91 3.918 8.000 33 #2ToeSleeve 13133 4217 91 3.500 5.875 34 #1ToeSleeve 13141 4217 91 3.500 5.875 35 WIVCollar 13196 4216 91 5.620 36 Eccentricshoe 13205 4215 91 3.930 5.220 1 2 3 4 5 6 7 8 9 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:Leahy, Scott (Scott) To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC); Davis, Rachel (Rachel); Senden, Robert (Ty) Subject:RE: Pikka NDB-037 (PTD 224-124, Sundry 324-704) - Question Date:Friday, January 3, 2025 10:21:37 AM Attachments:NDBi-043 Schematic 8.19.23 Final.pdf Appendix B Supplement 3.pdf Good Morning Steve, Wells NDBi-043 and NDBi-043A share the same casing and cementing information. NDBi-043 had a toe up trajectory to the top of the Nan 3.2 while in the lateral and then the drilling team backed out and continued to drill until TD. I’ve attached the schematic for NDB-043/043A for your reference. In addition, I updated the mechanical condition description and attached it for your reference. Thanks, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Ave Anchorage, Alaska 99501 m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, January 2, 2025 4:18 PM To: Leahy, Scott (Scott) <Scott.Leahy@santos.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: ![EXT]: RE: Pikka NDB-037 (PTD 224-124, Sundry 324-704) - Question Scott, Just following up to see if you’ve had a chance to review my question, below. I’d like to keep this application moving through AOGCC’s review process. Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov From: Davies, Stephen F (OGC) Sent: Monday, December 30, 2024 12:10 PM To: scott.leahy@santos.com Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Pikka NDB-037 (PTD 224-124, Sundry 324-704) - Question Scott, I’m reviewing Oil Search’s Sundry Application to hydraulically fracture NDB-037. The map shown on Attachment B shows NDB-043 and NDB-043A within the Area of Review (AOR) surrounding NDB-037, but those wells are not included in the associated table. If these wells do indeed lie within the AOR, could you please update that table to include reports of their mechanical conditions? 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 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 January 14, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 12/26/2024 (a)(2) Plat Provided with application. SFD 12/26/2024 (a)(2)(A) Well location Provided with application. Well lies in Sections 4 and 5 of T11N, R06E, UM, and continues through Sections 32, 31, and 30 of T12N, R06E, UM. SFD 12/26/2024 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online December 26, 2024), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of NDB-037. There are no subsurface water rights or temporary subsurface water rights within 14 miles of the surface location of NDB-037. SFD 12/26/2024 (a)(2)(C) Identify all well types within ½ mile Provided with application. SFD 12/26/2024 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Pikka Unit per salinity calculations provided by the operator on Aug. 21, 2023 as part of their Sundry Application to hydraulically fracture nearby well NDB-024 (see AOGCC’s Well History File 223-076, p. 101-107 of Sundry Application 323-591). Pickett Plot well-log analyses were performed on three wells within the unit that have wireline log coverage from surface through the fracturing interval: Colville River 1, Till 1, and Pikka DW-02. Estimated salinity values for clean, porous 100% water-saturated sands beneath the base of the permafrost layer in these three wells are: Colville River 1 (192-153) ~20,000 mg/l between 1,400 and 2,000’ MD(-1,354’ to 1,954' TVDSS; base of permafrost 1,350’ MD (-1,313’ TVDSS)); Till 1 (193-004) 16,700 to ~23,000 mg/l between 1,400’ and 1,500’ MD SFD 12/26/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 January 14, 2025 (-1,463’ to -1,363’ TVDSS; base of permafrost 1,350’ MD (-1,305’ TVDSS)); and DW-02 (223-039) ~21,500 mg/l between 1,550’ and 1,650’ MD (-1,408’ to -1,486’ TVDSS; base of permafrost ~1,170’ MD (~-1,080’ TVDSS). (a)(4) Baseline water sampling plan None required: No freshwater aquifers are present. SFD 12/26/2024 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. CDW 01/08/2025 (a)(6) Casing and cementing operation assessment Surface casing was set at 2,812’ MD (-2,328’ TVDSS) and cemented with 165 bbls clean cement returns reported to surface. The two-stage cement job for intermediate 9-5/8” casing went as planned. Stage 2 was pumped through an Archer Cementing tool at 4,672’ MD (-2,760’ TVDSS). Vendor’s cementing report indicates 80 bbls clean cement circulated off liner top and returned to surface. Stage 1 cement pumped through casing shoe at 10,862’ MD (-4,035’ TVDSS). Vendor’s CBL interpretation is TOC at 7,985’ MD (-3,397’ TVDSS). AOGCC’s (SFD) interpretation of the CBL places the top of consistent, excellent-quality cement at 8,415’ MD (-3,480’ TVDSS), which isolates the fracturing interval (top of frac interval at 10,945’ MD (-4,072’ TVDSS). SFD 12/27/2024 CDW 01/08/2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers are present. (See Section (a)(3), above.) SFD 12/26/2024 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates each hydrocarbon zone. Surface casing was set at 2,812’ MD (-2,328’ TVDSS) and cemented with 165 bbls clean cement returns reported to surface. 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 January 14, 2025 As described in Section (a)(6) above, the two-stage cement job for the 9-5/8” casing occurred as planned. Stage 2 was pumped through an Archer Cementing tool at 4,672’ MD (-2,760’ TVDSS). The vendor’s cementing report indicates 80 bbls clean cement circulated off liner top (at 2,644’ MD, -2,248’ TVDSS) and returned to surface, so Stage 2 cement isolates the Tuluvak interval from below the TS 790 marker (4,598’ MD, -2,745’ TVDSS) to the top of the Tuluvak Sand at 3,091’ MD (-2,435’ TVDSS). Stage 1 cement was pumped through the 9-5/8” casing shoe at 10,862’ MD (-4,035’ TVDSS). The vendor’s CBL interpretation is TOC at 7,985’ MD (-3,397’ TVDSS). AOGCC’s (SFD’s) interpretation of the CBL places the top of consistent, excellent-quality cement at 8,415’ MD (-3,480’ TVDSS). The top of the fracturing interval lies at 10,945’ MD (-4,072’ TVDSS), so Stage 1 cement isolates the fracturing interval from any overlying strata. SFD 12/27/2024 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4300 psi MITIA planned, 5200 psi MITT plan. CDW 01/08/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree plan. max. frac. Pressure 8500 psi. Pump knock out 7400 and GORV 8200 psi., lines test 8800 psi. CDW 01/08/2025 (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: About 659’ true vertical thickness (TVT) of claystone, shale and volcanic tuff assigned to the Seabee having an estimated fracture gradient of 13.7 ppg EMW (0.71 psi/ft). Fracturing Zone: Perforated zone lies within a subdivision of the Nanushuk Formation comprising fine-grained sand, silt and shale that is about 954’ TVT in this area and has an estimated fracture gradient of 11.7 to 12.7 ppg EMW (0.61 to 0.66 psi/ft). SFD 12/26/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 January 14, 2025 Lower Confining Zones: Lower Torok siltstone and shale that is about 1,200’ thick in this area with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft). (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. Fiord 3A (195-042): This well is plugged and abandoned. The Nanushuk interval is not cement-isolated in Fiord 3A. However, within the Nanushuk opened by Fiord 3A, the strata equivalent to the fracturing interval in NDB-037 lie between 2,200' and 2,300' to the northwest of NDB-037. Such separation is sufficient that Fiord 3A will not interfere with containment of the fluids injected into NDB-037 during the proposed fracturing operations. Surface casing was set in Fiord 3 at 1,805’ MD (-1,757’ TVDSS) and cemented to surface according to AOGCC’s (SFD’s) calculations, which assume 30% hole washout. Fiord 3A was kicked off at 1,807’ MD and drilled to TD of 9,147’ MD (-6,990’ TVDSS). Four cement plugs placed in Fiord 3A isolate the lower Torok, HRZ, Kuparuk, Alpine, Nuiqsut, and the upper half of the Tuluvak. The Tuluvak is not a significant hydrocarbon-bearing zone in Fiord 3A. The upper half of the Tuluvak is cement-isolated by Plug 3 in Fiord 3A, but the lower half is not. A 750-foot-thick interval of Seabee Shale separates the base of the Tuluvak from the underlying Nanushuk in Fiord 3A. Over the long term, it is anticipated that collapse of the Seabee Shale surrounding casing in Fiord 3A will preclude any out-of-zone migration of fluids. Qugruk 3A (213-031): This well is plugged and abandoned. Cement isolates the Nanushuk fracturing zone. Kicked off SFD 1/14/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 January 14, 2025 from Qugruk 3 and drilled to Nuiqsut. Cement plugs set across Nuiqsut, Alpine, Kup C, and Nanushuk 3 reservoir sand. Plug 2 is set from 4,177’ to 4,950’ MD (-3,913’ to -4,282’ TVDSS) across the Nanushuk 3 reservoir sand (4,489’ to 4,684’ MD, or -4,050’ to -4,150’ TVDSS). (Plugging details are provided within Operator’s application for Pikka NDB-014 (PTD No. 223-105; Sundry No. 324-085.) Qugruk 301 (PTD 214-199): This well is plugged and abandoned. AOGCC’s calculated tops of cement indicate isolation of Tuluvak, Schrader Bluff and West Sak strata. USIT log interpretation is Nanushuk reservoir is adequately isolated. The apparent cement top on the USIT log is 3,820’ MD (-3,633’ TVDSS), which isolates the Nanushuk reservoir sand, the top of which lies at 4,042’ MD (-3,777’ TVDSS). Pikka NDB-025 (224-006): Cement isolates the Nanushuk and the fracturing hydrocarbon zone. Second-stage cement--that was pumped with full cement returns and no losses--isolates the upper Tuluvak between the top of the Tuluvak Sand and the TS 790 Marker. Interpretation of the LWD Acoustic cement evaluation log indicates the Nanushuk is covered by mostly good to very cement with some interspersed intervals of partial cement below 4,728’ MD to the intermediate liner shoe at 8,435’ MD. Pikka NDB-030 (223-120): Cement appears sufficient in NDB-030 to isolate the Nanushuk reservoir. The CBL indicates the top of good-quality first-stage cement is a 10-foot-thick interval at 9,950’ MD (-3,761’ TVDSS). In NDB-030, the top of the potentially HC-bearing zone in the Nanushuk is 10,240' MD (-3,817' TVDSS). The proposed fracturing interval equivalent Nanushuk reservoir sand—located at 11,280’ MD—and a possible hydrocarbon-bearing interval between 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 January 14, 2025 10,690’ and 10,842’ MD are both isolated from overlying strata by intervals of good to excellent cement from 10,450’ to 10,695’ MD and from 10,840’ to 11,022’ MD. NDB-043 (Pilot Hole): Nanushuk is isolated by fair-quality cement that should be sufficient to contain hydraulic fracturing fluids. In NDB-043, the Nanushuk reservoir interval appears adequately cement isolated, but the overlying Tuluvak sand—a significant hydrocarbon-bearing interval—is not cement isolated. AOGCC’s consultant interprets the Tuluvak is covered by poor to patchy cement and the underlying Nanushuk is isolated by fair-quality cement that should be sufficient to contain hydraulic fracturing fluids. This pilot wellbore drilled to determine reservoir thickness was abandoned. Pikka NDB-043A (223-052): Nanushuk injection interval is cement-isolated. This horizontal wellbore kicked off from NDB-043 within the Nanushuk reservoir. Cementing records and operator evaluations indicate the Nanushuk injection interval is cement-isolated; however, the overlying Tuluvak Sand at 2,894’ MD (-2,440’ TVDSS)--a significant hydrocarbon-bearing interval--is not cement isolated. NDB-044 (223-087): In AOGCC’s opinion, the aggregate footages of fair- and poor-quality cement across the Tuluvak and Nanushuk indicate that cement very likely isolates the Nanushuk 3 reservoir interval and will not interfere with confinement of frac fluids for the planned operation. Intermediate hole was drilled through the Tuluvak Interval and intermediate casing was set and cemented in two stages. Stage 1 saw no returns while displacing cement. A cement retainer was run and a second cement job was pumped through the shoe. The Stage 2 cementing tool was set at the 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 January 14, 2025 base of the Upper Tuluvak, but 129 of 214 bbls of cement were lost while displacing. A Haliburton CAST tool was run beneath the top of the Nanushuk interval but above the Nanushuk 3 reservoir. According to Haliburton’s cement evaluation report, there is no good quality cement within either of the two intermediate cement stages, but—in AOGCC’s opinion—the aggregate footages of fair- and poor-quality cement across the Tuluvak and Nanushuk indicate that cement very likely isolates the Nanushuk 3 reservoir interval and will not interfere with confinement of frac fluids for the planned operation. (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 None. Per page 6 of the application and the fault map on Attachment B, the operator has not identified any faults within a ½-mile radius of the fracturing interval within NDBi-037. It is unlikely that any faults or fractures will interfere with containment of 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. SFD 12/27/2024 (a)(12) Proposed program for fracturing operation Provided with application. CDW 01/08/2025 (a)(12)(A) Estimated volume Provided with application. 25K bbl total dirty vol. 3M lb total proppant CDW 01/08/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 01/08/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger and Tracerco disclosures provided. CDW 01/08/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 01/08/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 8 January 14, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 6985 psi. Max. 8500 psi allowable treating pressure. Max pressure is 7400 psi to 8200 psi to Pump shutdown. With 3800 psi back pressure IA (IA popoff set 4100 psi), max tubing differential should be 4700 psi. CDW 01/08/2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures range from 258' to 375' according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will range from 207' to 237' TVD, with the shallowest modeled TVD of about 4,060’ and deepest modeled TVD of about 4,325’. Induced fractures will remain within the Nanushuk interval and below the overlying confining Seabee Shale that is about 660’ thick in this area. (The boundary between Nanushuk and overlying Seabee lies at 9,704’ MD, -3,733’ TVDSS in NDBi-037). SFD 12/27/2024 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Provided with application. Gas flaring requested. Same water cut% limits as previous Pikka fracs. Volumes to cleanup and disposal criteria same as previous fracs. CDW 01/08/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3800 psi back pressure, plan to test to 4300 psi, popoff set as 4100 psi. CDW 01/08/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be anchored with a retrievable packer set at approx. 10695 ft with sleeves from 11,188 ft. 9-5/8” production liner cemented 2 stage. Cement from stage tool at 4672 ft to liner top of 2644 ft. TOC first stage 7985 ft to shoe of 10862 ft. TOC verified with USIT/CBL conservatively shows good cement at area of interest (packer plus 100 ft) so no cement concerns. 13-3/8 surface casing cemented to surface CDW 01/08/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDBi-037 (PTD No. 224-124; Sundry No. 324-704) Paragraph Sub-Paragraph Section Complete? AOGCC Page 9 January 14, 2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 5200 psi. Max pressure differential is estimated as 4700 psi (8500 with 3800 psi backpressure) so test of 5200 psi satisfies 110% CDW 01/08/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 8800 psi line pressure test, pump knock out 7400 psi with max. global kickout 8200 psi. IA PRV set as 4100 psi. CDW 01/08/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 01/08/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 4100 psi. Surface annulus open. Frac pressures continuously monitored. CDW 01/08/2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 01/08/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required. No freshwater aquifers present. (See Section (a)(3), above.) SFD 12/26/2024 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Not applicable: This well is not confidential. SFD 12/26/2024 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-037 (50-103-20895-0000) Re-submittal of the LWD folder with correct APIs- Details on following pages. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 12/12/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Gavin Gluyas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 224-124 T39806 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.12 13:01:15 -09'00' LETTER OF TRANSMITTAL جؐؐؐLog Digital Data and Plots (LWD) ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐAP ؒ ؒ ؒ NDB-037_AP_R01_RM.las ؒ ؒ ؒ NDB-037_AP_R02_RM.las ؒ ؒ ؒ NDB-037_AP_R03_RM.las ؒ ؒ ؒ ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.las ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_5MD.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-037_DMD_RM_17776ft.las ؒ ؒ NDB-037_DMT_R01_RM.las ؒ ؒ NDB-037_DMT_R02_RM.las ؒ ؒ NDB-037_DMT_R03_RM.las ؒ ؒ ؒ جؐؐؐGeoscience Deliverables ؒ ؒ ؤؐؐؐSoundTrak- Acoustic Data ؒ ؒ جؐؐؐCBL ؒ ؒ ؒ NDB-037_9_625_Liner_Baker_Hughes_CBL_Final Report.pdf ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.cgm ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.dlis ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.las ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.PDF ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779_dlis.txt ؒ ؒ ؒ ؒ ؒ ؤؐؐؐTOC ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.cgm ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.dlis ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.las ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.PDF ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphic Images ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2MD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2TVD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5TVD.cgm ؒ ؒ ؒ LETTER OF TRANSMITTAL ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDB-037_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-037_DMD_RM_17776ft.cgm ؒ ؒ NDB-037_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2MD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2TVD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5TVD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-037_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-037_DMD_RM_17776ft.pdf ؒ NDB-037_DMT_RM.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-037 (50-103-20895-0000) Re-submittal of the LWD folder with correct APIs- Details on following pages. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 12/10/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Gavin Gluyas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 224-124 T39806 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.11 08:02:15 -09'00' LETTER OF TRANSMITTAL جؐؐؐLog Digital Data and Plots (LWD) ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐAP ؒ ؒ ؒ NDB-037_AP_R01_RM.las ؒ ؒ ؒ NDB-037_AP_R02_RM.las ؒ ؒ ؒ NDB-037_AP_R03_RM.las ؒ ؒ ؒ ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.las ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_5MD.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-037_DMD_RM_17776ft.las ؒ ؒ NDB-037_DMT_R01_RM.las ؒ ؒ NDB-037_DMT_R02_RM.las ؒ ؒ NDB-037_DMT_R03_RM.las ؒ ؒ ؒ جؐؐؐGeoscience Deliverables ؒ ؒ ؤؐؐؐSoundTrak- Acoustic Data ؒ ؒ جؐؐؐCBL ؒ ؒ ؒ NDB-037_9_625_Liner_Baker_Hughes_CBL_Final Report.pdf ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.cgm ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.dlis ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.las ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.PDF ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779_dlis.txt ؒ ؒ ؒ ؒ ؒ ؤؐؐؐTOC ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.cgm ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.dlis ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.las ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.PDF ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphic Images ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2MD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2TVD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5TVD.cgm ؒ ؒ ؒ LETTER OF TRANSMITTAL ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDB-037_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-037_DMD_RM_17776ft.cgm ؒ ؒ NDB-037_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2MD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2TVD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5TVD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-037_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-037_DMD_RM_17776ft.pdf ؒ NDB-037_DMT_RM.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-037 (50-103-20895-0000) Final Well data Submittal - Details on following pages. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 12/4/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Gavin Gluyas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 224-124 T39806 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.04 13:59:41 -09'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-037 Definitive Compass Survey Report - NAD27.pdf ؒ NDB-037 Definitive Compass Survey Report - NAD83.pdf ؒ NDB-037 Definitive Survey - NAD27.txt ؒ NDB-037 Definitive Survey - NAD83.txt ؒ NDB-037 Definitive Survey Report.xlsx ؒ جؐؐؐLog Digital Data and Plots (LWD) ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐAP ؒ ؒ ؒ NDB-037_AP_R01_RM.las ؒ ؒ ؒ NDB-037_AP_R02_RM.las ؒ ؒ ؒ NDB-037_AP_R03_RM.las ؒ ؒ ؒ ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.las ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_5MD.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-037_DMD_RM_17776ft.las ؒ ؒ NDB-037_DMT_R01_RM.las ؒ ؒ NDB-037_DMT_R02_RM.las ؒ ؒ NDB-037_DMT_R03_RM.las ؒ ؒ ؒ جؐؐؐGeoscience Deliverables ؒ ؒ ؤؐؐؐSoundTrak- Acoustic Data ؒ ؒ جؐؐؐCBL ؒ ؒ ؒ NDB-037_9_625_Liner_Baker_Hughes_CBL_Final Report.pdf ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.cgm ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.dlis ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.las ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779.PDF ؒ ؒ ؒ NDB-037_LWD_SDTK_CBL_7364_10779_dlis.txt ؒ ؒ ؒ ؒ ؒ ؤؐؐؐTOC ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.cgm ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.dlis ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.las ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779.PDF ؒ ؒ NDB-037_LWD_SDTK_TOC_7364_10779_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphic Images LETTER OF TRANSMITTAL ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2MD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2TVD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.cgm ؒ ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5TVD.cgm ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDB-037_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-037_DMD_RM_17776ft.cgm ؒ ؒ NDB-037_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2MD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_2TVD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5MD.pdf ؒ ؒ NDB-037_LWD_GR_Res_Den_Neu_Cal_RM_17776ft_5TVD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-037_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-037_DMD_RM_17776ft.pdf ؒ NDB-037_DMT_RM.pdf ؒ ؤؐؐؐMudlog NoMudlogServices.txt 1 Gluyas, Gavin R (OGC) From:Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent:Wednesday, November 6, 2024 4:17 PM To:McLellan, Bryan J (OGC); Davies, Stephen F (OGC) Cc:Leahy, Scott (Scott); Senden, Robert (Ty); Tirpack, Robert (Robert); Davis, Rachel (Rachel); Wallace, Chris D (OGC); Dewhurst, Andrew D (OGC); Conwell, Russell (Russell) Subject:NDB-037 (PTD 224-124) Intermediate 9-5/8" Cement Bond Log Attachments:NDB-037 Final geographic_awp.xlsx; NDB-037 Schematic 11.06.24.pdf; Reporting - Cement - NDB-037 - 2024-11-06 17.52.45.pdf; NDB-037_9_625 _Liner_Baker_Hughes_CBL_Final Report.pdf Bryan / Steve, We just received the final 9-5/8” intermediate Casing CBL report from Baker. I’ve attached the Wellview Cementing Reports, Baker Final CBL Report, schematic and directional survey. Below is a high-level summary: Well Design - 9-5/8” Liner Top at 2,644’ MD - 13-3/8” Casing Shoe at 2,812’ MD - CFLEX Stage Tool at 4,672’ MD - 9-5/8” Shoe at 10,862’ MD Geology - TS790 at 4,598’ MD. - Top of the Nanushuk was picked at 9,704’ MD. o Top significant hydrocarbon in the Nanushuk was picked at 9,950’ MD in the NT8. Cement Job Planning / Execution - 1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeƟng TOC 250’ TVD above top of Nanushuk to 8,400’ MD. - During execuƟon of the 1st stage cement, we lost a reported 70 bbls aŌer cement turned the corner, although liŌ pressure conƟnued to increase during the displacement (ICP 424 psi, FCP 627 psi). - 2nd Stage of cement job planned with CFLEX ~74’ below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeƟng TOC at the 9-5/8” liner top. - During execuƟon of the 2nd stage cement, no losses were encountered and we saw good liŌ pressure. An esƟmated 125 bbls of spacer and 80 bbls of cement observed at surface off the top of liner. Observations / Conclusions - For the 1st stage of the cement job, we have adequate isolaƟon in the upper Nanushuk formaƟons across the hydrocarbon-bearing formaƟons (top hydrocarbon esƟmated within NT8 at ~9,950’ MD). This is supported by the CBL log, which indicates good cement throughout the first stage and a TOC at 7,985’ MD. - For the 2nd stage of the cement job, based on job execuƟon results, cement isolaƟon was achieved across the significant hydrocarbon zone within the upper Tuluvak formaƟon. 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 - Our assessment is that we have adequate isolaƟon across hydrocarbon-bearing formaƟons in the upper Nanushuk formaƟons, as well as adequate isolaƟon for frac operaƟons. The 2nd stage cement job yielded adequate isolaƟon below, across and above the Tuluvak significant hydrocarbons. Let me know if you have any questions. Thanks, Garret Garret Staudinger Senior Drilling Engineer m: +1 (907) 440 6892 | e: garret.staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email Vert Uncert 1sd [ft] 0.00 0.00 Start MD End MD Survey Date[ft][ft] 46.60 657.71 10/Oct/2024 657.71 691.06 13/Oct/2024 691.06 764.36 10/Oct/2024 764.36 2747.69 13/Oct/2024 2747.69 3909.39 21/Oct/2024 3909.39 4004.36 21/Oct/2024 4004.36 4193.73 21/Oct/2024 4193.73 4287.99 21/Oct/2024 4287.99 7038.07 21/Oct/2024 7038.07 7132.79 22/Oct/2024 7132.79 10828.02 22/Oct/2024 10828.02 17776.00 31/Oct/2024 MD TVD North East Grid East Grid North Latitude Longitude Shape[ft][ft][ft][ft][US ft][US ft] N/A 4141.43 9729.49 -11541.78 1550613.00 5982322.00 70°21'42.6394"N 150°43'46.3899"W point N/A 4166.43 4147.17 -8238.95 1553857.00 5976706.00 70°20'47.7791"N 150°42'9.6284"W polygon Start MD End MD Interval Start TVD End TVD Start N/S Start E/W End N/S End E/W[ft][ft][ft][ft][ft][ft][ft][ft][ft] MD Inclination Azimuth TVD TVDSS North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Major Semi Minor Semi Vert Semi Minor Azim Comments[ft][°][°][ft][ft][ft][ft][US ft][US ft][°/100ft][°][°/100ft][°/100ft][ft][ft][ft][ft][°] 0.00 0.00 354.02 0.00 -69.43 0.00 0.00 1562051.39 5972473.37 70°20'7.0354"N 150°38'8.8817"W 0.00 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 46.60 0.00 354.02 46.60 -22.83 0.00 0.00 1562051.39 5972473.37 70°20'7.0354"N 150°38'8.8817"W 0.00 0 0.00 0.00 0.00 0.85 0.85 0.00 0.00 128.73 0.09 354.02 128.73 59.30 0.06 -0.01 1562051.38 5972473.43 70°20'7.0360"N 150°38'8.8819"W 0.11 1.42 0.11 0.00 0.05 0.87 0.87 2.30 84.02 183.94 0.18 354.73 183.94 114.51 0.19 -0.02 1562051.37 5972473.56 70°20'7.0373"N 150°38'8.8822"W 0.16 -33.898 0.16 1.29 0.14 0.90 0.90 2.31 84.16 279.31 0.35 337.50 279.31 209.88 0.61 -0.14 1562051.25 5972473.98 70°20'7.0414"N 150°38'8.8859"W 0.19 -13.844 0.18 -18.07 0.50 0.99 0.98 2.32 260.86 373.60 1.85 326.25 373.58 304.15 2.14 -1.10 1562050.31 5972475.52 70°20'7.0565"N 150°38'8.9138"W 1.60 -4.996 1.59 -11.93 2.22 1.11 1.09 2.33 254.80 468.12 4.22 323.44 467.96 398.53 6.21 -4.02 1562047.44 5972479.62 70°20'7.0964"N 150°38'8.9991"W 2.51 -7.135 2.51 -2.97 7.07 1.27 1.23 2.35 248.87 562.89 5.98 321.33 562.35 492.92 12.86 -9.18 1562042.34 5972486.33 70°20'7.1619"N 150°38'9.1498"W 1.87 -8.274 1.86 -2.23 15.31 1.44 1.39 2.37 246.11 657.71 7.58 319.57 656.50 587.07 21.48 -16.32 1562035.29 5972495.02 70°20'7.2466"N 150°38'9.3584"W 1.70 4.615 1.69 -1.86 26.33 1.62 1.58 2.40 246.72 691.06 8.03 319.83 689.55 620.12 24.93 -19.25 1562032.40 5972498.50 70°20'7.2806"N 150°38'9.4439"W 1.35 -57.605 1.35 0.78 30.79 1.66 1.61 2.40 243.97 764.36 8.36 316.41 762.10 692.67 32.71 -26.23 1562025.51 5972506.34 70°20'7.3570"N 150°38'9.6477"W 0.80 -10.76 0.45 -4.67 41.13 1.67 1.63 2.43 245.65 857.15 10.52 314.17 853.63 784.20 43.49 -36.96 1562014.89 5972517.24 70°20'7.4632"N 150°38'9.9610"W 2.36 -4.96 2.33 -2.41 56.29 1.71 1.67 2.46 243.64 921.57 13.11 313.18 916.68 847.25 52.59 -46.51 1562005.44 5972526.44 70°20'7.5526"N 150°38'10.2398"W 4.03 4.303 4.02 -1.54 69.45 1.77 1.73 2.47 240.89 975.54 14.15 313.50 969.13 899.70 61.32 -55.75 1561996.28 5972535.27 70°20'7.6385"N 150°38'10.5099"W 1.93 148.699 1.93 0.59 82.15 1.85 1.81 2.49 247.34 1069.53 13.81 314.37 1060.33 990.90 77.08 -72.11 1561980.10 5972551.19 70°20'7.7934"N 150°38'10.9875"W 0.43 -25.075 -0.36 0.93 104.81 2.04 1.97 2.54 291.66 1164.77 15.01 312.22 1152.57 1083.14 93.31 -89.37 1561963.01 5972567.60 70°20'7.9531"N 150°38'11.4916"W 1.38 -16.119 1.26 -2.26 128.47 2.32 2.16 2.59 301.95 1259.20 17.55 309.80 1243.21 1173.78 110.65 -109.36 1561943.20 5972585.14 70°20'8.1236"N 150°38'12.0756"W 2.78 -22.529 2.69 -2.56 154.93 2.67 2.39 2.64 304.47 1353.33 19.38 307.53 1332.49 1263.06 129.25 -132.65 1561920.11 5972603.98 70°20'8.3065"N 150°38'12.7558"W 2.09 -28.931 1.94 -2.41 184.73 3.08 2.65 2.70 305.14 1448.44 21.78 304.01 1421.53 1352.10 148.73 -159.80 1561893.17 5972623.75 70°20'8.4982"N 150°38'13.5486"W 2.84 -20.777 2.52 -3.70 218.04 3.57 2.92 2.76 304.94 1543.06 24.60 301.46 1508.50 1439.07 168.83 -191.16 1561862.02 5972644.18 70°20'8.6959"N 150°38'14.4645"W 3.16 -7.601 2.98 -2.69 254.97 4.12 3.21 2.83 304.15 1637.83 28.02 300.49 1593.44 1524.01 190.43 -227.18 1561826.24 5972666.14 70°20'8.9083"N 150°38'15.5164"W 3.64 9.122 3.61 -1.02 296.43 4.76 3.51 2.90 303.11 1732.38 31.15 301.46 1675.65 1606.22 214.47 -267.19 1561786.49 5972690.60 70°20'9.1447"N 150°38'16.6849"W 3.35 -5.864 3.31 1.03 342.51 5.50 3.80 2.98 302.27 1827.14 33.69 300.99 1755.64 1686.21 240.79 -310.63 1561743.32 5972717.37 70°20'9.4036"N 150°38'17.9537"W 2.69 -31.485 2.68 -0.50 392.70 6.34 4.10 3.08 301.72 1921.89 36.27 298.35 1833.27 1763.84 267.64 -357.83 1561696.41 5972744.71 70°20'9.6676"N 150°38'19.3323"W 3.16 -27.871 2.72 -2.79 446.09 7.26 4.39 3.20 301.18 2016.57 38.93 296.13 1908.28 1838.85 294.05 -409.20 1561645.33 5972771.65 70°20'9.9273"N 150°38'20.8325"W 3.15 -22.643 2.81 -2.34 502.39 8.28 4.67 3.34 300.43 2111.29 41.84 294.32 1980.42 1910.99 320.17 -464.72 1561590.09 5972798.35 70°20'10.1842"N 150°38'22.4540"W 3.31 -10.5 3.07 -1.91 561.67 9.40 4.95 3.49 299.54 2205.86 44.81 293.54 2049.21 1979.78 346.47 -524.03 1561531.06 5972825.27 70°20'10.4429"N 150°38'24.1862"W 3.19 2.287 3.14 -0.82 623.97 10.63 5.22 3.66 298.64 2301.06 48.17 293.72 2114.75 2045.32 374.15 -587.27 1561468.12 5972853.60 70°20'10.7150"N 150°38'26.0334"W 3.53 4.284 3.53 0.19 690.16 11.98 5.48 3.84 297.86 Actual Wellpath Geographic Report - including Position Uncertainty Report by Baker Hughes Operator Area Wellpath Wellbore last revised S i d e t r a c k f r o m User Calculation method Field Facility Slot Well Wellbore NDB B-37 NDB-037 NDB-037 NDB-037_awp 10/10/2024 (none) Zillrobw Minimum curvature 69.43 ft 69.43 ft E 0.00 ft N 0.00 ft Magnetic North is 14.00 degrees East of True North 2.00Std Dev WellArchitectDB Projection System North Reference Scale Convergence at Slot Horizontal Reference Point Vertical Reference Point MD Reference Point Field Vertical Reference Rig on B-37 (RT) To Facility Vertical Datum Rig on B-37 (RT) To Mean Sea Level Rig on B-37 (RT) to Ground Level at Slot (B-37) Section Origin X Section Origin Y 05/Nov/2024 at 00:49 using WellArchitect 6.0 Santos Alaska Pikka NAD83 / TM Alaska SP, Zone 4 (5004), US feet True 0.999907 0.60 West Slot Rig on B-37 (RT) Rig on B-37 (RT) Mean Sea Level 69.43 ft 310.13° included 46.60 ft Local East Grid North Longitude Section Azimuth Surface Position Uncertainty Ellipse Starting MD Declination Ellipse Confidence Limit Database Grid East [US ft] 1562051.39 1563416.33 1563416.33 Slot Location Facility Reference Pt Field Reference Pt Local North [ft] -198.56 Horiz Uncert 1sd [ft] 0.30 0.30 [US ft] 5972473.37 5972657.91 5972657.91 Latitude 70°20'7.0354"N 70°20'8.9895"N 70°20'8.9895"N Positional Uncertainty Model Log Name / Comment Wellbore 150°38'8.8817"W 150°37'29.0730"W 150°37'29.0730"W [ft] -1363.10 SDI URSA1 gyroMWD ISCWSA Rev4 (SAG)16" Surface Hole w/Motor/Ontrak/Gyro NDB-037 OWSG MWD rev2 + IFR2 + Sag + Multi-Station Correction 16" Surface Hole with Ontrak/Motor NDB-037 SDI URSA1 gyroMWD ISCWSA Rev4 (SAG)16" Surface Hole w/Motor/Ontrak/Gyro NDB-037 OWSG MWD rev2 + IFR2 + Sag + Multi-Station Correction 16" Surface Hole with Ontrak/Motor NDB-037 OWSG MWD rev2 (IFR2, SAG)OWSG MWD+ SAG NDB-037 BH Drift Indicator - Estimated Azimuth (Standard)BHI Drift Indicator NDB-037 OWSG MWD rev2 (MS+IFR2, SAG)12.25" Hole ATK/OTK NDB-037 BH Drift Indicator - Estimated Azimuth (Standard)BH Drift Indicator NDB-037 OWSG MWD rev2 (MS+IFR2, SAG)12 1/4" Hole ATK/OTK NDB-037 OWSG MWD rev2 (MS+IFR2, SAG)8.5" Hole ATK/OTK/SDTK NDB-037 OWSG MWD rev2 (MS+IFR2, SAG)12.25 Hole ATK/OTK NDB-037 OWSG MWD rev2 (IFR2, SAG)Intermediate Hole MWD+Sag NDB-037 NDB-037 Heel Rev 2.0 String / Diameter Wellbore Target Name Comment NBD-037 Toe Rev 2.0 Page 1 of 3 # Baker Hughes Confidential 2395.74 51.08 294.00 2176.07 2106.64 403.33 -653.23 1561402.48 5972883.46 70°20'11.0019"N 150°38'27.9598"W 3.08 7.532 3.07 0.30 759.40 13.42 5.73 4.05 297.26 2490.96 54.02 294.48 2233.97 2164.54 434.36 -722.14 1561333.89 5972915.21 70°20'11.3071"N 150°38'29.9727"W 3.11 -4 3.09 0.50 832.10 14.98 5.96 4.28 296.82 2585.08 57.27 294.21 2287.07 2217.64 466.39 -792.93 1561263.45 5972947.97 70°20'11.6220"N 150°38'32.0401"W 3.46 -0.308 3.45 -0.29 906.86 16.61 6.19 4.52 296.49 2679.95 60.51 294.19 2336.08 2266.65 499.68 -867.01 1561189.73 5972982.03 70°20'11.9493"N 150°38'34.2038"W 3.42 6.735 3.42 -0.02 984.95 18.35 6.39 4.78 296.21 2747.69 61.93 294.38 2368.70 2299.27 524.10 -921.12 1561135.88 5973007.01 70°20'12.1894"N 150°38'35.7844"W 2.11 48.247 2.10 0.28 1042.07 19.64 6.53 4.98 296.05 2847.53 64.64 297.69 2413.59 2344.16 563.26 -1001.22 1561056.21 5973047.00 70°20'12.5745"N 150°38'38.1239"W 4.02 -39.973 2.71 3.32 1128.55 20.74 7.25 4.78 296.00 2903.40 65.93 296.51 2436.95 2367.52 586.37 -1046.40 1561011.27 5973070.59 70°20'12.8018"N 150°38'39.4435"W 3.00 -8.971 2.31 -2.11 1177.99 20.96 7.29 4.79 296.02 2962.25 67.57 296.23 2460.18 2390.75 610.39 -1094.84 1560963.09 5973095.11 70°20'13.0379"N 150°38'40.8585"W 2.82 -16.118 2.79 -0.48 1230.51 21.26 7.32 4.82 296.06 3057.44 70.31 295.39 2494.38 2424.95 649.05 -1174.81 1560883.54 5973134.60 70°20'13.4181"N 150°38'43.1941"W 2.99 -26.492 2.88 -0.88 1316.57 21.91 7.39 4.89 296.09 3151.56 73.12 293.93 2523.91 2454.48 686.33 -1256.02 1560802.73 5973172.72 70°20'13.7845"N 150°38'45.5662"W 3.33 -23.012 2.99 -1.55 1402.68 22.75 7.45 4.99 296.06 3246.10 75.54 292.87 2549.44 2480.01 722.47 -1339.55 1560719.59 5973209.73 70°20'14.1399"N 150°38'48.0062"W 2.78 -12.616 2.56 -1.12 1489.85 23.77 7.52 5.12 295.95 3340.98 77.24 292.48 2571.77 2502.34 758.02 -1424.64 1560634.89 5973246.16 70°20'14.4893"N 150°38'50.4915"W 1.84 -4.457 1.79 -0.41 1577.81 24.95 7.59 5.29 295.77 3436.08 78.75 292.36 2591.55 2522.12 793.49 -1510.62 1560549.28 5973282.53 70°20'14.8381"N 150°38'53.0032"W 1.59 -55.829 1.59 -0.13 1666.42 26.29 7.65 5.48 295.55 3531.45 78.93 292.09 2610.00 2540.57 828.89 -1597.24 1560463.05 5973318.82 70°20'15.1860"N 150°38'55.5332"W 0.34 -90.048 0.19 -0.28 1755.46 27.74 7.72 5.71 295.32 3625.30 78.93 291.59 2628.03 2558.60 863.15 -1682.73 1560377.93 5973353.97 70°20'15.5228"N 150°38'58.0305"W 0.52 -96.841 0.00 -0.53 1842.91 29.28 7.79 5.95 295.09 3720.01 78.83 290.73 2646.29 2576.86 896.70 -1769.40 1560291.63 5973388.42 70°20'15.8525"N 150°39'0.5620"W 0.90 -68.396 -0.11 -0.91 1930.79 30.91 7.86 6.22 294.82 3815.42 78.90 290.55 2664.72 2595.29 929.69 -1857.00 1560204.38 5973422.33 70°20'16.1769"N 150°39'3.1210"W 0.20 -87.706 0.07 -0.19 2019.04 32.63 7.94 6.50 294.54 3909.39 78.93 289.81 2682.78 2613.35 961.51 -1943.56 1560118.17 5973455.04 70°20'16.4895"N 150°39'5.6493"W 0.77 -90.001 0.03 -0.79 2105.72 34.38 8.02 6.79 294.25 4004.36 78.93 289.80 2701.02 2631.59 993.08 -2031.25 1560030.82 5973487.53 70°20'16.7999"N 150°39'8.2109"W 0.01 161.887 0.00 -0.01 2193.12 35.31 8.25 6.88 294.19 4099.06 78.90 289.81 2719.23 2649.80 1024.57 -2118.68 1559943.73 5973519.93 70°20'17.1093"N 150°39'10.7650"W 0.03 90.05 -0.03 0.01 2280.27 35.59 8.32 7.03 294.15 4193.73 78.90 290.33 2737.45 2668.02 1056.45 -2205.94 1559856.82 5973552.71 70°20'17.4226"N 150°39'13.3139"W 0.54 83.471 0.00 0.55 2367.53 36.45 8.39 7.06 293.99 4287.99 78.96 290.86 2755.55 2686.12 1088.99 -2292.53 1559770.58 5973586.15 70°20'17.7424"N 150°39'15.8435"W 0.56 96.045 0.06 0.56 2454.71 37.10 8.47 7.13 293.86 4383.65 78.93 291.15 2773.90 2704.47 1122.64 -2380.18 1559683.30 5973620.72 70°20'18.0731"N 150°39'18.4038"W 0.30 90.055 -0.03 0.30 2543.42 37.33 8.54 7.28 293.84 4478.47 78.93 291.72 2792.10 2722.67 1156.65 -2466.80 1559597.05 5973655.62 70°20'18.4073"N 150°39'20.9342"W 0.59 -90.098 0.00 0.60 2631.56 37.75 8.61 7.31 293.81 4573.46 78.93 290.70 2810.34 2740.91 1190.38 -2553.70 1559510.50 5973690.25 70°20'18.7387"N 150°39'23.4729"W 1.05 95.488 0.00 -1.07 2719.75 38.30 8.68 7.36 293.77 4668.08 78.90 291.02 2828.53 2759.10 1223.44 -2640.47 1559424.10 5973724.22 70°20'19.0636"N 150°39'26.0077"W 0.33 -90.025 -0.03 0.34 2807.40 38.97 8.76 7.44 293.70 4762.68 78.90 290.76 2846.75 2777.32 1256.54 -2727.20 1559337.73 5973758.22 70°20'19.3889"N 150°39'28.5413"W 0.27 75.719 0.00 -0.27 2895.04 39.76 8.83 7.54 293.62 4857.54 78.93 290.88 2864.98 2795.55 1289.63 -2814.21 1559251.07 5973792.21 70°20'19.7140"N 150°39'31.0832"W 0.13 90.006 0.03 0.13 2982.90 40.65 8.91 7.66 293.53 4951.56 78.93 290.94 2883.04 2813.61 1322.56 -2900.41 1559165.24 5973826.04 70°20'20.0375"N 150°39'33.6012"W 0.06 -84.574 0.00 0.06 3070.02 41.64 8.99 7.80 293.43 5047.06 78.96 290.62 2901.35 2831.92 1355.81 -2988.04 1559077.97 5973860.20 70°20'20.3643"N 150°39'36.1613"W 0.33 -98.329 0.03 -0.34 3158.46 42.74 9.08 7.96 293.32 5142.37 78.89 290.13 2919.66 2850.23 1388.38 -3075.72 1558990.64 5973893.68 70°20'20.6842"N 150°39'38.7229"W 0.51 89.22 -0.07 -0.51 3246.49 43.92 9.17 8.14 293.20 5236.68 78.90 290.82 2937.82 2868.39 1420.75 -3162.42 1558904.29 5973926.95 70°20'21.0022"N 150°39'41.2557"W 0.72 -81.329 0.01 0.73 3333.64 45.18 9.26 8.34 293.07 5331.69 78.93 290.62 2956.09 2886.66 1453.74 -3249.62 1558817.44 5973960.84 70°20'21.3263"N 150°39'43.8034"W 0.21 92.157 0.03 -0.21 3421.58 46.51 9.35 8.55 292.96 5426.12 78.89 291.76 2974.25 2904.82 1487.23 -3336.02 1558731.40 5973995.24 70°20'21.6554"N 150°39'46.3276"W 1.19 84.362 -0.04 1.21 3509.22 47.91 9.44 8.78 292.86 5520.55 78.93 292.17 2992.42 2922.99 1521.89 -3421.96 1558645.84 5974030.79 70°20'21.9959"N 150°39'48.8383"W 0.43 99.177 0.04 0.43 3597.27 49.37 9.53 9.02 292.79 5615.80 78.87 292.55 3010.76 2941.33 1557.45 -3508.40 1558559.78 5974067.25 70°20'22.3452"N 150°39'51.3638"W 0.40 -79.198 -0.06 0.40 3686.28 50.89 9.62 9.28 292.74 5711.37 78.90 292.39 3029.18 2959.75 1593.29 -3595.06 1558473.51 5974103.99 70°20'22.6973"N 150°39'53.8956"W 0.17 -90.013 0.03 -0.17 3775.64 52.47 9.71 9.55 292.69 5805.92 78.90 292.25 3047.38 2977.95 1628.53 -3680.89 1558388.07 5974140.12 70°20'23.0434"N 150°39'56.4032"W 0.15 -90.026 0.00 -0.15 3863.97 54.09 9.80 9.82 292.65 5899.73 78.90 291.98 3065.44 2996.01 1663.19 -3766.17 1558303.16 5974175.66 70°20'23.3839"N 150°39'58.8949"W 0.28 -86.929 0.00 -0.29 3951.51 55.73 9.89 10.11 292.60 5994.49 78.93 291.42 3083.66 3014.23 1697.57 -3852.58 1558217.13 5974210.94 70°20'23.7216"N 150°40'1.4193"W 0.58 -97.282 0.03 -0.59 4039.74 57.43 9.99 10.40 292.55 6089.55 78.90 291.18 3101.94 3032.51 1731.46 -3939.49 1558130.58 5974245.73 70°20'24.0544"N 150°40'3.9587"W 0.25 -90.049 -0.03 -0.25 4128.03 59.18 10.09 10.71 292.48 6183.95 78.90 290.67 3120.11 3050.68 1764.54 -4026.01 1558044.42 5974279.71 70°20'24.3794"N 150°40'6.4866"W 0.53 144.981 0.00 -0.54 4215.51 60.94 10.19 11.02 292.41 6279.42 78.83 290.72 3138.55 3069.12 1797.64 -4113.64 1557957.15 5974313.72 70°20'24.7045"N 150°40'9.0469"W 0.09 81.556 -0.07 0.05 4303.84 62.75 10.29 11.34 292.34 6374.04 78.89 291.13 3156.83 3087.40 1830.80 -4200.36 1557870.79 5974347.78 70°20'25.0301"N 150°40'11.5805"W 0.43 -67.833 0.06 0.43 4391.51 64.58 10.39 11.67 292.27 6468.24 78.93 291.03 3174.95 3105.52 1864.05 -4286.61 1557784.90 5974381.93 70°20'25.3566"N 150°40'14.1007"W 0.11 -93.309 0.04 -0.11 4478.89 66.42 10.50 12.00 292.21 6563.64 78.89 290.31 3193.30 3123.87 1897.09 -4374.20 1557697.66 5974415.88 70°20'25.6812"N 150°40'16.6599"W 0.74 -92.175 -0.04 -0.75 4567.16 68.31 10.60 12.34 292.15 6658.10 78.87 289.76 3211.52 3142.09 1928.85 -4461.28 1557610.93 5974448.54 70°20'25.9930"N 150°40'19.2042"W 0.57 -92.674 -0.02 -0.58 4654.21 70.21 10.71 12.68 292.07 6753.65 78.86 289.54 3229.97 3160.54 1960.37 -4549.57 1557522.98 5974480.99 70°20'26.3025"N 150°40'21.7839"W 0.23 79.035 -0.01 -0.23 4742.03 72.15 10.82 13.03 291.99 6848.82 78.90 289.75 3248.33 3178.90 1991.77 -4637.52 1557435.38 5974513.29 70°20'26.6107"N 150°40'24.3536"W 0.22 87.37 0.04 0.22 4829.51 74.09 10.93 13.38 291.91 6942.95 78.93 290.40 3266.43 3197.00 2023.47 -4724.28 1557348.96 5974545.90 70°20'26.9221"N 150°40'26.8887"W 0.68 81.738 0.03 0.69 4916.28 76.04 11.04 13.74 291.84 7038.07 78.96 290.61 3284.66 3215.23 2056.18 -4811.72 1557261.87 5974579.51 70°20'27.2431"N 150°40'29.4436"W 0.22 -117.002 0.03 0.22 5004.21 78.01 11.15 14.10 291.79 7132.79 78.93 290.55 3302.83 3233.40 2088.85 -4898.75 1557175.20 5974613.10 70°20'27.5640"N 150°40'31.9866"W 0.07 104.304 -0.03 -0.06 5091.82 79.18 11.25 14.28 291.77 7227.29 78.90 290.67 3321.00 3251.57 2121.50 -4985.55 1557088.75 5974646.64 70°20'27.8845"N 150°40'34.5229"W 0.13 90.031 -0.03 0.13 5179.22 79.58 11.34 14.29 291.77 7322.19 78.90 290.99 3339.27 3269.84 2154.61 -5072.59 1557002.07 5974680.66 70°20'28.2096"N 150°40'37.0661"W 0.33 86.477 0.00 0.34 5267.11 79.94 11.43 14.31 291.77 7416.70 78.93 291.48 3357.44 3288.01 2188.20 -5159.04 1556915.99 5974715.15 70°20'28.5394"N 150°40'39.5922"W 0.51 102.23 0.03 0.52 5354.86 80.36 11.52 14.33 291.77 7511.72 78.86 291.81 3375.74 3306.31 2222.60 -5245.70 1556829.69 5974750.44 70°20'28.8771"N 150°40'42.1247"W 0.35 73.469 -0.07 0.35 5443.29 80.84 11.62 14.37 291.77 7606.59 78.93 292.05 3394.01 3324.58 2257.36 -5332.06 1556743.71 5974786.11 70°20'29.2184"N 150°40'44.6482"W 0.26 94.017 0.07 0.25 5531.73 81.38 11.72 14.43 291.77 7701.11 78.90 292.49 3412.19 3342.76 2292.52 -5417.90 1556658.25 5974822.15 70°20'29.5635"N 150°40'47.1565"W 0.46 91.855 -0.03 0.47 5620.01 81.97 11.81 14.49 291.78 7795.58 78.89 292.81 3430.38 3360.95 2328.22 -5503.45 1556573.09 5974858.74 70°20'29.9140"N 150°40'49.6565"W 0.33 -83.749 -0.01 0.34 5708.43 82.62 11.91 14.57 291.79 7890.58 78.93 292.44 3448.65 3379.22 2364.08 -5589.50 1556487.43 5974895.50 70°20'30.2661"N 150°40'52.1712"W 0.38 44.466 0.04 -0.39 5797.34 83.33 12.01 14.66 291.80 7985.16 78.96 292.47 3466.79 3397.36 2399.53 -5675.29 1556402.02 5974931.84 70°20'30.6142"N 150°40'54.6781"W 0.04 -90.033 0.03 0.03 5885.79 84.09 12.11 14.76 291.81 8079.97 78.96 292.13 3484.95 3415.52 2434.84 -5761.38 1556316.31 5974968.05 70°20'30.9608"N 150°40'57.1941"W 0.35 -98.947 0.00 -0.36 5974.37 84.90 12.22 14.87 291.81 8175.24 78.90 291.74 3503.24 3433.81 2469.77 -5848.11 1556229.96 5975003.88 70°20'31.3037"N 150°40'59.7285"W 0.41 -86.75 -0.06 -0.41 6063.19 85.77 12.32 14.99 291.82 8269.74 78.93 291.21 3521.41 3451.98 2503.72 -5934.41 1556144.03 5975038.72 70°20'31.6369"N 150°41'2.2504"W 0.55 -99.284 0.03 -0.56 6151.06 86.68 12.42 15.12 291.82 8364.15 78.89 290.96 3539.57 3470.14 2537.05 -6020.86 1556057.94 5975072.95 70°20'31.9641"N 150°41'4.7766"W 0.26 -80.366 -0.04 -0.26 6238.63 87.64 12.53 15.27 291.81 8459.24 78.90 290.90 3557.88 3488.45 2570.38 -6108.01 1555971.15 5975107.19 70°20'32.2912"N 150°41'7.3235"W 0.06 33.199 0.01 -0.06 6326.75 88.65 12.64 15.42 291.81 8554.48 78.96 290.94 3576.17 3506.74 2603.76 -6195.32 1555884.21 5975141.47 70°20'32.6187"N 150°41'9.8749"W 0.08 108.768 0.06 0.04 6415.02 89.71 12.74 15.58 291.80 8649.03 78.93 291.03 3594.30 3524.87 2636.99 -6281.96 1555797.93 5975175.60 70°20'32.9449"N 150°41'12.4069"W 0.10 -98.71 -0.03 0.10 6502.68 90.80 12.85 15.76 291.79 8742.30 78.90 290.83 3612.23 3542.80 2669.69 -6367.45 1555712.79 5975209.19 70°20'33.2657"N 150°41'14.9053"W 0.21 85.437 -0.03 -0.21 6589.12 91.92 12.96 15.94 291.78 8836.90 78.93 291.21 3630.42 3560.99 2702.99 -6454.10 1555626.49 5975243.39 70°20'33.5925"N 150°41'17.4378"W 0.40 115.449 0.03 0.40 6676.84 93.10 13.07 16.13 291.77 8932.15 78.86 291.36 3648.77 3579.34 2736.92 -6541.19 1555539.77 5975278.22 70°20'33.9255"N 150°41'19.9830"W 0.17 35.032 -0.07 0.16 6765.29 94.32 13.18 16.33 291.76 9027.70 78.93 291.41 3667.17 3597.74 2771.10 -6628.50 1555452.84 5975313.32 70°20'34.2610"N 150°41'22.5345"W 0.09 -83.797 0.07 0.05 6854.08 95.59 13.30 16.54 291.75 9122.75 78.96 291.13 3685.40 3615.97 2804.94 -6715.43 1555366.27 5975348.06 70°20'34.5930"N 150°41'25.0751"W 0.29 -95.661 0.03 -0.29 6942.36 96.88 13.41 16.75 291.75 9217.21 78.93 290.82 3703.51 3634.08 2838.13 -6802.00 1555280.07 5975382.15 70°20'34.9187"N 150°41'27.6050"W 0.32 -98.71 -0.03 -0.33 7029.93 98.20 13.53 16.98 291.74 9311.98 78.90 290.62 3721.73 3652.30 2871.03 -6888.98 1555193.44 5975415.95 70°20'35.2415"N 150°41'30.1472"W 0.21 148.231 -0.03 -0.21 7117.65 99.56 13.64 17.21 291.72 9406.06 78.71 290.74 3740.00 3670.57 2903.63 -6975.33 1555107.45 5975449.44 70°20'35.5613"N 150°41'32.6707"W 0.24 137.645 -0.20 0.13 7204.67 100.93 13.76 17.44 291.70 9501.69 78.42 291.01 3758.95 3689.52 2937.03 -7062.90 1555020.23 5975483.75 70°20'35.8889"N 150°41'35.2303"W 0.41 117.414 -0.30 0.28 7293.16 102.36 13.88 17.69 291.69 9596.09 77.35 293.14 3778.77 3709.34 2971.71 -7148.43 1554935.08 5975519.32 70°20'36.2292"N 150°41'37.7299"W 2.48 90.718 -1.13 2.26 7380.90 103.80 14.00 17.94 291.69 9690.97 77.33 296.29 3799.57 3730.14 3010.41 -7232.51 1554851.41 5975558.90 70°20'36.6091"N 150°41'40.1876"W 3.24 92.818 -0.02 3.32 7470.13 105.25 14.12 18.20 291.73 9785.86 77.17 300.23 3820.52 3751.09 3054.22 -7314.01 1554770.38 5975603.55 70°20'37.0392"N 150°41'42.5700"W 4.05 103.412 -0.17 4.15 7560.68 106.71 14.24 18.46 291.82 9880.29 76.56 302.92 3841.98 3772.55 3102.36 -7392.35 1554692.56 5975652.51 70°20'37.5119"N 150°41'44.8601"W 2.85 89.994 -0.65 2.85 7651.61 108.16 14.36 18.73 291.95 9973.97 76.58 306.08 3863.74 3794.31 3153.96 -7467.44 1554618.03 5975704.88 70°20'38.0187"N 150°41'47.0553"W 3.28 102.101 0.02 3.37 7742.28 109.58 14.49 19.00 292.12 10069.72 75.90 309.46 3886.52 3817.09 3210.91 -7540.94 1554545.13 5975762.59 70°20'38.5781"N 150°41'49.2045"W 3.50 108.611 -0.71 3.53 7835.18 111.01 14.64 19.28 292.33 10164.71 75.04 312.15 3910.36 3840.93 3270.99 -7610.54 1554476.17 5975823.39 70°20'39.1683"N 150°41'51.2397"W 2.89 95.411 -0.91 2.83 7927.12 112.40 14.80 19.56 292.57 10259.48 74.89 313.86 3934.95 3865.52 3333.42 -7677.47 1554409.90 5975886.51 70°20'39.7816"N 150°41'53.1971"W 1.75 105.223 -0.16 1.80 8018.53 113.75 14.98 19.85 292.84 10354.29 74.40 315.76 3960.05 3890.62 3397.84 -7742.33 1554345.72 5975951.60 70°20'40.4146"N 150°41'55.0940"W 2.00 101.552 -0.52 2.00 8109.64 115.10 15.18 20.14 293.12 10449.16 73.77 319.10 3986.07 3916.64 3465.02 -7804.04 1554284.72 5976019.41 70°20'41.0746"N 150°41'56.8991"W 3.45 96.927 -0.66 3.52 8200.12 116.40 15.40 20.43 293.42Page 2 of 3 # Baker Hughes Confidential 10543.47 73.35 323.02 4012.77 3943.34 3535.36 -7860.88 1554228.63 5976090.33 70°20'41.7658"N 150°41'58.5621"W 4.01 93.411 -0.45 4.16 8288.92 117.63 15.64 20.72 293.75 10637.97 73.20 326.03 4039.98 3970.55 3609.05 -7913.40 1554176.89 5976164.56 70°20'42.4901"N 150°42'0.0988"W 3.05 90.588 -0.16 3.19 8376.57 118.79 15.90 21.02 294.10 10732.86 73.19 328.12 4067.41 3997.98 3685.29 -7962.77 1554128.32 5976241.31 70°20'43.2394"N 150°42'1.5437"W 2.11 91.215 -0.01 2.20 8463.45 119.91 16.20 21.32 294.47 10828.02 73.17 329.26 4094.95 4025.52 3763.11 -8010.10 1554081.81 5976319.61 70°20'44.0043"N 150°42'2.9292"W 1.15 8.677 -0.02 1.20 8549.80 121.00 16.52 21.63 294.84 10926.96 75.84 329.68 4121.38 4051.95 3845.23 -8058.53 1554034.24 5976402.23 70°20'44.8115"N 150°42'4.3468"W 2.73 16.095 2.70 0.42 8639.76 122.09 15.47 21.91 294.87 11023.59 79.56 330.77 4141.96 4072.53 3927.17 -8105.40 1553988.24 5976484.64 70°20'45.6168"N 150°42'5.7189"W 4.00 13.778 3.85 1.13 8728.40 122.38 15.63 21.92 294.96 11117.54 83.29 331.69 4155.97 4086.54 4008.59 -8150.10 1553944.39 5976566.51 70°20'46.4171"N 150°42'7.0276"W 4.09 3.97 3.97 0.98 8815.06 122.68 15.86 21.94 295.07 11212.67 86.60 331.92 4164.35 4094.92 4092.09 -8194.86 1553900.51 5976650.47 70°20'47.2379"N 150°42'8.3383"W 3.49 -15.842 3.48 0.24 8903.10 123.00 16.16 21.97 295.20 11308.91 89.95 330.97 4167.24 4097.81 4176.57 -8240.84 1553855.42 5976735.42 70°20'48.0683"N 150°42'9.6844"W 3.62 -75.964 3.48 -0.99 8992.71 123.35 16.52 22.00 295.33 11403.92 90.15 330.17 4167.16 4097.73 4259.32 -8287.52 1553809.61 5976818.65 70°20'48.8816"N 150°42'11.0512"W 0.87 -129.289 0.21 -0.84 9081.74 123.71 16.92 22.04 295.48 11498.82 90.06 330.06 4166.99 4097.56 4341.60 -8334.81 1553763.19 5976901.41 70°20'49.6904"N 150°42'12.4356"W 0.15 -60.46 -0.09 -0.12 9170.92 124.09 17.37 22.09 295.63 11594.35 90.40 329.46 4166.60 4097.17 4424.13 -8382.92 1553715.95 5976984.43 70°20'50.5015"N 150°42'13.8441"W 0.72 73.3 0.36 -0.63 9260.90 124.49 17.87 22.15 295.79 11689.27 90.43 329.56 4165.92 4096.49 4505.92 -8431.08 1553668.65 5977066.71 70°20'51.3055"N 150°42'15.2541"W 0.11 -97.124 0.03 0.11 9350.44 124.91 18.40 22.22 295.96 11784.84 90.40 329.32 4165.22 4095.79 4588.22 -8479.67 1553620.93 5977149.50 70°20'52.1143"N 150°42'16.6768"W 0.25 97.222 -0.03 -0.25 9440.63 125.36 18.96 22.29 296.15 11879.19 90.31 330.03 4164.64 4095.21 4669.66 -8527.31 1553574.15 5977231.42 70°20'52.9147"N 150°42'18.0715"W 0.76 -102.029 -0.10 0.75 9529.54 125.81 19.55 22.37 296.34 11974.80 90.18 329.42 4164.23 4094.80 4752.22 -8575.51 1553526.82 5977314.48 70°20'53.7263"N 150°42'19.4828"W 0.65 -83.657 -0.14 -0.64 9619.61 126.29 20.17 22.47 296.54 12069.89 90.31 328.25 4163.82 4094.39 4833.59 -8624.72 1553478.47 5977396.35 70°20'54.5259"N 150°42'20.9236"W 1.24 175.601 0.14 -1.23 9709.68 126.80 20.81 22.56 296.75 12165.11 90.18 328.26 4163.42 4093.99 4914.56 -8674.81 1553429.22 5977477.84 70°20'55.3218"N 150°42'22.3904"W 0.14 90 -0.14 0.01 9800.17 127.32 21.46 22.67 296.97 12260.50 90.18 328.33 4163.12 4093.69 4995.72 -8724.95 1553379.95 5977559.50 70°20'56.1194"N 150°42'23.8581"W 0.07 -86.877 0.00 0.07 9890.81 127.87 22.12 22.79 297.19 12355.50 90.21 327.78 4162.79 4093.36 5076.33 -8775.21 1553330.53 5977640.63 70°20'56.9116"N 150°42'25.3298"W 0.58 -87.545 0.03 -0.58 9981.19 128.44 22.79 22.91 297.42 12450.56 90.24 327.08 4162.42 4092.99 5156.44 -8826.38 1553280.20 5977721.26 70°20'57.6989"N 150°42'26.8281"W 0.74 94.184 0.03 -0.74 10071.95 129.04 23.46 23.04 297.66 12545.31 90.21 327.49 4162.05 4092.62 5236.16 -8877.59 1553229.84 5977801.50 70°20'58.4824"N 150°42'28.3274"W 0.43 93.433 -0.03 0.43 10162.49 129.65 24.13 23.17 297.91 12640.57 90.18 327.99 4161.73 4092.30 5316.71 -8928.44 1553179.84 5977882.58 70°20'59.2740"N 150°42'29.8161"W 0.53 89.997 -0.03 0.52 10253.28 130.28 24.82 23.32 298.16 12736.34 90.18 329.69 4161.42 4091.99 5398.66 -8977.99 1553131.15 5977965.03 70°21'0.0795"N 150°42'31.2672"W 1.78 -63.435 0.00 1.78 10343.99 130.93 25.52 23.47 298.43 12831.35 90.24 329.57 4161.08 4091.65 5480.63 -9026.02 1553083.98 5978047.49 70°21'0.8851"N 150°42'32.6739"W 0.14 -105.945 0.06 -0.13 10433.55 131.58 26.23 23.63 298.70 12925.81 90.12 329.15 4160.78 4091.35 5561.90 -9074.16 1553036.70 5978129.25 70°21'1.6838"N 150°42'34.0837"W 0.46 -64.178 -0.13 -0.44 10522.74 132.25 26.94 23.79 298.97 13021.92 90.27 328.84 4160.45 4091.02 5644.28 -9123.67 1552988.06 5978212.14 70°21'2.4934"N 150°42'35.5335"W 0.36 103.495 0.16 -0.32 10613.68 132.96 27.66 23.96 299.25 13116.63 90.21 329.09 4160.06 4090.63 5725.43 -9172.50 1552940.08 5978293.79 70°21'3.2910"N 150°42'36.9635"W 0.27 92.417 -0.06 0.26 10703.32 133.67 28.36 24.14 299.54 13211.84 90.15 330.51 4159.76 4090.33 5807.72 -9220.39 1552893.06 5978376.56 70°21'4.0997"N 150°42'38.3662"W 1.49 -94.899 -0.06 1.49 10792.97 134.40 29.07 24.33 299.83 13307.38 90.12 330.16 4159.53 4090.10 5890.74 -9267.68 1552846.65 5978460.06 70°21'4.9156"N 150°42'39.7512"W 0.37 -83.332 -0.03 -0.37 10882.63 135.14 29.79 24.52 300.13 13402.15 90.21 329.39 4159.26 4089.83 5972.62 -9315.38 1552799.81 5978542.43 70°21'5.7204"N 150°42'41.1485"W 0.82 64.983 0.09 -0.81 10971.89 135.90 30.50 24.71 300.43 13497.53 90.28 329.54 4158.85 4089.42 6054.77 -9363.84 1552752.21 5978625.08 70°21'6.5278"N 150°42'42.5678"W 0.17 -127.569 0.07 0.16 11061.89 136.69 31.20 24.92 300.73 13591.44 90.18 329.41 4158.47 4089.04 6135.67 -9411.54 1552705.37 5978706.46 70°21'7.3228"N 150°42'43.9649"W 0.17 -89.999 -0.11 -0.14 11150.49 137.48 31.88 25.12 301.04 13686.20 90.18 328.88 4158.18 4088.75 6217.02 -9460.14 1552657.63 5978788.30 70°21'8.1223"N 150°42'45.3883"W 0.56 22.067 0.00 -0.56 11240.08 138.31 32.56 25.34 301.34 13781.25 90.55 329.03 4157.57 4088.14 6298.45 -9509.16 1552609.47 5978870.23 70°21'8.9226"N 150°42'46.8241"W 0.42 102.306 0.39 0.16 11330.04 139.15 33.23 25.56 301.66 13876.50 90.43 329.58 4156.76 4087.33 6380.35 -9557.78 1552561.71 5978952.63 70°21'9.7275"N 150°42'48.2482"W 0.59 -79.379 -0.13 0.58 11420.01 140.02 33.90 25.78 301.97 13971.48 90.46 329.42 4156.02 4086.59 6462.19 -9605.98 1552514.37 5979034.96 70°21'10.5318"N 150°42'49.6603"W 0.17 -97.43 0.03 -0.17 11509.61 140.89 34.56 26.01 302.29 14067.06 90.40 328.96 4155.30 4085.87 6544.27 -9654.93 1552466.28 5979117.55 70°21'11.3385"N 150°42'51.0943"W 0.49 -89.999 -0.06 -0.48 11599.95 141.80 35.22 26.25 302.61 14162.06 90.40 328.73 4154.64 4085.21 6625.57 -9704.08 1552417.99 5979199.34 70°21'12.1374"N 150°42'52.5339"W 0.24 92.909 0.00 -0.24 11689.92 142.72 35.86 26.49 302.92 14256.82 90.37 329.32 4154.00 4084.57 6706.82 -9752.85 1552370.08 5979281.08 70°21'12.9359"N 150°42'53.9625"W 0.62 89.998 -0.03 0.62 11779.57 143.65 36.49 26.73 303.24 14352.64 90.37 329.88 4153.38 4083.95 6789.46 -9801.34 1552322.46 5979364.22 70°21'13.7481"N 150°42'55.3830"W 0.58 -114.904 0.00 0.58 11869.91 144.61 37.12 26.98 303.57 14447.17 90.24 329.60 4152.88 4083.45 6871.11 -9848.97 1552275.68 5979446.36 70°21'14.5505"N 150°42'56.7785"W 0.33 95.906 -0.14 -0.30 11958.96 145.56 37.74 27.24 303.89 14542.47 90.21 329.89 4152.50 4083.07 6953.43 -9896.99 1552228.54 5979529.16 70°21'15.3595"N 150°42'58.1853"W 0.31 180 -0.03 0.30 12048.73 146.54 38.36 27.49 304.21 14637.89 90.06 329.89 4152.28 4082.85 7035.97 -9944.86 1552181.54 5979612.20 70°21'16.1707"N 150°42'59.5878"W 0.16 -81.326 -0.16 0.00 12138.53 147.54 38.97 27.76 304.54 14733.38 90.15 329.30 4152.10 4082.67 7118.33 -9993.18 1552134.08 5979695.05 70°21'16.9800"N 150°43'1.0037"W 0.63 95.355 0.09 -0.62 12228.56 148.56 39.57 28.03 304.86 14828.36 90.12 329.62 4151.88 4082.45 7200.13 -10041.45 1552086.68 5979777.34 70°21'17.7840"N 150°43'2.4177"W 0.34 -101.31 -0.03 0.34 12318.18 149.59 40.15 28.30 305.18 14923.36 90.09 329.47 4151.71 4082.28 7282.02 -10089.60 1552039.39 5979859.72 70°21'18.5887"N 150°43'3.8285"W 0.16 -85.169 -0.03 -0.16 12407.78 150.64 40.72 28.57 305.50 15018.91 90.15 328.76 4151.51 4082.08 7364.02 -10138.65 1551991.20 5979942.23 70°21'19.3946"N 150°43'5.2656"W 0.75 -102.529 0.06 -0.74 12498.13 151.71 41.29 28.85 305.82 15114.12 90.09 328.49 4151.31 4081.88 7445.31 -10188.22 1551942.49 5980024.02 70°21'20.1934"N 150°43'6.7179"W 0.29 87.709 -0.06 -0.28 12588.43 152.81 41.83 29.14 306.13 15209.30 90.12 329.24 4151.13 4081.70 7526.78 -10237.43 1551894.14 5980105.99 70°21'20.9940"N 150°43'8.1598"W 0.79 -18.435 0.03 0.79 12678.56 153.91 42.37 29.42 306.44 15303.95 90.24 329.20 4150.84 4081.41 7608.10 -10285.86 1551846.56 5980187.80 70°21'21.7931"N 150°43'9.5790"W 0.13 93.121 0.13 -0.04 12768.01 155.03 42.89 29.71 306.75 15399.05 90.21 329.75 4150.46 4081.03 7690.02 -10334.17 1551799.12 5980270.21 70°21'22.5982"N 150°43'10.9944"W 0.58 -77.005 -0.03 0.58 12857.74 156.15 43.42 30.01 307.06 15494.08 90.24 329.62 4150.09 4080.66 7772.05 -10382.13 1551752.02 5980352.74 70°21'23.4043"N 150°43'12.4000"W 0.14 -90 0.03 -0.14 12947.28 157.29 43.94 30.30 307.37 15589.77 90.24 329.52 4149.69 4080.26 7854.56 -10430.60 1551704.42 5980435.74 70°21'24.2151"N 150°43'13.8202"W 0.10 36.87 0.00 -0.10 13037.52 158.45 44.45 30.60 307.68 15684.35 90.28 329.55 4149.26 4079.83 7936.08 -10478.55 1551657.33 5980517.75 70°21'25.0163"N 150°43'15.2254"W 0.05 -94.863 0.04 0.03 13126.73 159.62 44.95 30.91 307.98 15779.67 90.24 329.08 4148.83 4079.40 8018.05 -10527.19 1551609.55 5980600.22 70°21'25.8218"N 150°43'16.6509"W 0.49 96.115 -0.04 -0.49 13216.75 160.81 45.43 31.21 308.28 15874.61 90.21 329.36 4148.45 4079.02 8099.62 -10575.78 1551561.82 5980682.28 70°21'26.6234"N 150°43'18.0746"W 0.30 79.992 -0.03 0.29 13306.47 162.01 45.91 31.52 308.58 15969.05 90.24 329.53 4148.08 4078.65 8180.94 -10623.79 1551514.67 5980764.09 70°21'27.4225"N 150°43'19.4816"W 0.18 82.647 0.03 0.18 13395.59 163.22 46.37 31.83 308.87 16064.58 90.28 329.84 4147.65 4078.22 8263.41 -10672.01 1551467.32 5980847.05 70°21'28.2329"N 150°43'20.8948"W 0.33 -92.934 0.04 0.32 13485.61 164.44 46.84 32.15 309.16 16159.39 90.24 329.06 4147.22 4077.79 8345.06 -10720.20 1551419.99 5980929.19 70°21'29.0353"N 150°43'22.3071"W 0.82 94.513 -0.04 -0.82 13575.08 165.68 47.29 32.46 309.45 16253.85 90.21 329.44 4146.85 4077.42 8426.24 -10768.49 1551372.55 5981010.86 70°21'29.8330"N 150°43'23.7226"W 0.40 -89.999 -0.03 0.40 13664.33 166.93 47.73 32.78 309.73 16348.45 90.21 329.08 4146.50 4077.07 8507.55 -10816.85 1551325.05 5981092.66 70°21'30.6320"N 150°43'25.1397"W 0.38 -89.999 0.00 -0.38 13753.70 168.19 48.16 33.10 310.01 16443.86 90.21 328.72 4146.15 4076.72 8589.24 -10866.13 1551276.63 5981174.86 70°21'31.4348"N 150°43'26.5841"W 0.38 89.999 0.00 -0.38 13844.04 169.48 48.58 33.43 310.29 16539.25 90.21 329.35 4145.80 4076.37 8671.04 -10915.21 1551228.41 5981257.16 70°21'32.2385"N 150°43'28.0225"W 0.66 113.199 0.00 0.66 13934.28 170.78 48.99 33.76 310.56 16634.40 90.18 329.42 4145.48 4076.05 8752.92 -10963.66 1551180.82 5981339.54 70°21'33.0432"N 150°43'29.4428"W 0.08 91.717 -0.03 0.07 14024.11 172.08 49.40 34.09 310.83 16728.88 90.15 330.42 4145.21 4075.78 8834.68 -11011.02 1551134.33 5981421.77 70°21'33.8466"N 150°43'30.8309"W 1.06 -77.005 -0.03 1.06 14113.01 173.38 49.80 34.42 311.09 16825.12 90.21 330.16 4144.90 4075.47 8918.26 -11058.71 1551087.51 5981505.85 70°21'34.6680"N 150°43'32.2291"W 0.28 -84.644 0.06 -0.27 14203.35 174.70 50.21 34.76 311.36 16920.16 90.24 329.84 4144.53 4075.10 9000.57 -11106.23 1551040.86 5981588.64 70°21'35.4768"N 150°43'33.6221"W 0.34 -120.964 0.03 -0.34 14292.73 176.03 50.61 35.09 311.63 17015.15 90.15 329.69 4144.21 4074.78 9082.64 -11154.07 1550993.89 5981671.19 70°21'36.2833"N 150°43'35.0242"W 0.18 -86.566 -0.09 -0.16 14382.20 177.37 50.99 35.43 311.88 17110.76 90.18 329.19 4143.93 4074.50 9164.97 -11202.68 1550946.15 5981754.02 70°21'37.0923"N 150°43'36.4492"W 0.52 -84.093 0.03 -0.52 14472.43 178.73 51.36 35.77 312.14 17206.09 90.21 328.90 4143.61 4074.18 9246.72 -11251.71 1550897.98 5981836.27 70°21'37.8956"N 150°43'37.8866"W 0.31 -94.763 0.03 -0.30 14562.61 180.11 51.72 36.12 312.38 17301.14 90.18 328.54 4143.28 4073.85 9327.95 -11301.06 1550849.48 5981918.01 70°21'38.6938"N 150°43'39.3332"W 0.38 90 -0.03 -0.38 14652.70 181.50 52.07 36.46 312.62 17395.74 90.18 328.57 4142.99 4073.56 9408.66 -11350.41 1550800.98 5981999.22 70°21'39.4868"N 150°43'40.7798"W 0.03 55.304 0.00 0.03 14742.45 182.90 52.41 36.80 312.85 17490.98 90.27 328.70 4142.61 4073.18 9489.98 -11399.99 1550752.27 5982081.04 70°21'40.2859"N 150°43'42.2330"W 0.17 142.125 0.09 0.14 14832.77 184.31 52.74 37.15 313.09 17586.32 90.18 328.77 4142.24 4072.81 9571.47 -11449.47 1550703.64 5982163.04 70°21'41.0867"N 150°43'43.6835"W 0.12 33.69 -0.09 0.07 14923.12 185.73 53.07 37.50 313.31 17680.85 90.27 328.83 4141.87 4072.44 9652.33 -11498.43 1550655.53 5982244.40 70°21'41.8812"N 150°43'45.1191"W 0.11 102.094 0.10 0.06 15012.68 187.15 53.39 37.85 313.54 17749.53 90.18 329.25 4141.60 4072.17 9711.23 -11533.77 1550620.82 5982303.65 70°21'42.4599"N 150°43'46.1549"W 0.63 0 -0.13 0.61 15077.65 188.19 53.62 38.11 313.70 17776.00 90.18 329.25 4141.51 4072.08 9733.97 -11547.30 1550607.52 5982326.54 70°21'42.6834"N 150°43'46.5517"W 0.00 N/A 0.00 0.00 15102.66 188.58 53.71 38.21 313.76 Projection to bit Page 3 of 3 # Baker Hughes Confidential NDB-037 Well SchematicDraft 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2644' MD 13-3/8" 68 ppf L-80 Surface Casing2,812' MD 9-5/8", 47ppf L-80 Production Liner10862 MD 4-½”, 12.6ppf P-110S Production Liner 17,769' MD 4-½” Liner Hanger/ Packer10681' MD GL 9-5/8" 68 ppf L-80 Tieback2644' MD 11.06.2024 Archer C-Flex Two-Stage Cementing Tool~4,672 MD 9 8 3 4 5 6 7 1 2 8-½” Openhole 17,776'' MD 46.60' RKB – Bottom Flange TOC First Stage Cement 7,985’MD #CompletionItem TopDepth(MD') Depth(TVD') Inc ID" OD" 1XLandingNipple 1502 1471 23 3.813 4.790 2 GasliftMandrel 1.5" 2095 1968 41 3.865 7.650 3XLandingNipple 2165 2020 44 3.813 4.790 4EGLValve 3042 2489 70 3.909 6.188 5EGLGauge 3110 2511 72 3.892 6.198 6XLandingNipple 10396 3971 74 3.813 4.776 7SSDNERAGaslift 10459 3989 74 3.813 7.000 8EGLValve 10524 4007 73 3.860 5.818 9D/HPsiͲTempGauge 10592 4027 73 3.905 6.000 10 X LandingNipple 10615 4033 73 3.813 4.776 11 TiebackSealAssy 10715 4062 73 3.908 5.220 12 9.625"x4.5"LH/Packer 10681 4052 73 6.030 8.430 13 #15OpenholePacker 10959 4129 77 3.918 8.000 14 #14OpenholePacker 11027 4143 80 3.918 8.000 15 Stg13ͲColletSleeve12 11174 4162 85 3.735 5.624 16 #13OpenholePacker 11444 4167 90 3.918 8.000 17 #12OpenholePacker 11511 4167 90 3.918 8.000 18 Stg12ͲColletSleeve11 11741 4166 90 3.735 5.624 19 #11OpenholePacker 11993 4164 90 3.918 8.000 20 Stg11ͲColletSleeve10 12265 4163 90 3.735 5.624 21 #10OpenholePacker 12534 4162 90 3.918 8.000 22 Stg10ͲColletSleeve9 12807 4161 90 3.735 5.624 23 #9OpenholePacker 13076 4160 90 3.918 8.000 24 Stg9ͲColletSleeve8 13348 4159 90 3.735 5.624 25 #8OpenholePacker 13617 4158 90 3.918 8.000 26 Stg8ͲColletSleeve7 13889 4157 90 3.735 5.624 27 #7OpenholePacker 14158 4155 90 3.918 8.000 28 Stg7ͲColletSleeve6 14431 4153 90 3.735 5.625 29 #6OpenholePacker 14700 4152 90 3.918 8.000 30 Stg6ͲColletSleeve5 14972 4152 90 3.735 5.624 31 #5OpenholePacker 15241 4151 90 3.918 8.000 32 Stg5ͲColletSleeve4 15513 4150 90 3.735 5.624 33 #4OpenholePacker 15783 4149 90 3.918 8.000 34 Stg4Ͳ ColletSleeve3 16055 4148 90 3.735 5.624 35 #3OpenholePacker 16324 4147 90 3.918 8.000 36 Stg3ͲColletSleeve2 16596 4146 90 3.735 5.624 37 #2OpenholePacker 16865 4145 90 3.918 8.000 38 Stg2ͲColletSleeve117137 4144 90 3.735 5.624 39 #1OpenholePacker 17413 4143 90 3.918 8.000 40 Stg1Ͳ#2ToeSleeve 17679 4142 90 3.500 5.750 41 Stg1Ͳ#1ToeSleeve 17691 4142 90 3.500 5.750 42 WIVCollar 17753 4142 90 0.870 5.610 43 FloatCollar 17766 4142 90 3.980 5.220 44 Eccentricshoe 17768 4142 90 3.900 5.190 Page 1 of 1 Cement - NDB-037 Intermediate Casing Cement - 1st Stage Intermediate Casing Cement - 1st Stage, Casing, 10/28/2024 10:45 Type Casing Cementing Start Date 10/28/2024 Cementing End Date 10/28/2024 Wellbore Original Hole String Intermediate Liner, 10,862.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Baker Soundtrack LWD Cement Evaluation Results 1st stage was logged with Baker Soundtrak LWD tool. TOC was picked at 7,985' MD. Reference the CBL Report in the attachments for a detailed analysis of cement bond log results. Comment PJSM with Third party and rig personnel for 1st stage cement job. - Pump 5 bbls water & Pressure test cement lines to 1,000 psi low 5000 psi High. - Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 3.5 bpm with 550 psi, - Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 3.5 bpm, initial circulating pressure 472 psi. - Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II; 10 bbls neat cement, 60 bbls LCM cement with 5 lb/bbl Bridgemaker II, 115 bbls neat cement. Pump total of 185 bbls (840 sacks, yield 1.237 cu ft/sk) at average of 4 bpm, 275 psi, excess volume 30% - Release top pump down plug, chase with 20 bbls of water from Halliburton. - Lost 18 bbls while pumping cement - Perform displacement with rig pumps, displace with 11.8 ppg OBM at 4 bpm, ICP 424 psi, FCP 625 psi. - Top pump down dart latch up confirmed at 32 bbls displaced. - Continue to displace with 11.8 ppg OBM, reduce rate to 3 bpm prior cement turning corner: Final circulating pressure 627psi. pressured up 500 psi over FCP 1,200 psi held 5 min, bled off checked floats. Floats held. - Total displacement volume 627 bbls (measured by strokes at 96% pump efficiency). CIP @ 15:49 hrs. - Total losses from cement exit shoe to cement in place: 70 bbls 1, 8,400.0-10,867.0ftKB Top Depth (ftKB) 8,400.0 Bottom Depth (ftKB) 10,867.0 Full Return? No Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 627.0 Plug Bump Pressure (psi) 1,200.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer w/4# Red Dye, 65 gal Surfactant B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail (Type 1/2) w/5lb/bbl Bridgemaker II LCM Amount (sacks) 840 Class Type I/II Volume Pumped (bbl) 185.0 Estimated Top (ftKB) 8,400.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 5.75 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 12.50 Page 1 of 1 Cement - NDB-037 Intermediate Casing Cement - 2nd stage Intermediate Casing Cement - 2nd stage, Casing, 10/29/2024 05:30 Type Casing Cementing Start Date 10/29/2024 Cementing End Date 10/29/2024 Wellbore Original Hole String Intermediate Liner, 10,862.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 80 bbls clean cement circulated off liner top and returned to surface. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 4,672' as follows: - Mix and pump 80 bbls of 12.5 ppg Mud Flush at 4 bpm, ICP 306 psi, FCP 230 psi, 11 bbls lost during this phase (both spacers with Surfactant B and Musol A) - Mix and pump 80 bbls of 15.5 Tuned Spacer at 3 bpm, 175 psi psi, full returns - Mix and pump 217 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4.0 bpm, ICP 212 psi, FCP 405 psi, No fluid lost during this phase - Excess Volume 100% (985 sacks, yield 1.237 cu ft/sk) - Begin displacing with 20 bbls fresh water from cementing unit - Continue to displace with 81.4 bbls 12.0 ppg OBM using rig pumps - Displace to calculated volume of 101.43 bbls to Archer Stage Collar - Displace at 4 bpm, 526 psi ICP, 635 FCP before slowing rate, 100% returns; FCP at 3 bpm 540 psi. - Down on pumps, 309 psi held on drill pipe - 0 bbls lost during displacement - CIP at 08:00 hrs - No losses while pumping cement or during displacement. - 80 bbls clean cement, 125 bbls spacer, 35 bbls interface returned to surface (240 bbls total). 2, 2,643.0-4,671.0ftKB Top Depth (ftKB) 2,643.0 Bottom Depth (ftKB) 4,671.0 Full Return? Yes Vol Cement Ret (bbl) 80.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 405.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Mud Flush w/ 8#'s Red Dye and 65 Gal of Surf B & 65 Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Spacer Fluid Type Spacer Fluid Description Tuned Spacer w/ 4#'s Red Dye and 65 Gal of Surf B & 65 Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) Density (lb/gal) 15.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem (Type 1/2) Amount (sacks) 985 Class Type I/II Volume Pumped (bbl) 217.0 Estimated Top (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 140.3 Thickening Time (hr) 6.25 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 25.50 Santos USA and Baker Hughes Confidential Page 1 © 2018 Baker Hughes, LLC - All rights reserved. LLWD Qualitative Cement Bond Log Evaluation Report Well Name, Section: NDB-037, 9 5/8” Liner Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: Reservoir Technical Services Alaska Version: Preliminary Report Santos USA and Baker Hughes Confidential Page 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Tool Diagram .......................................................................................................................................................................................................... 7 Methodology of LWD Cement Bond Log Evaluation .................................................................................................................8 Log Screen Captures ...................................................................................................................................................................................... 13 Santos USA and Baker Hughes Confidential Page 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMER THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. Santos USA and Baker Hughes Confidential Page 4 Executive Summary Cement Bond Logging with LWD Acoustic (Sonic) tool SoundTrak was performed after drilling of 8 ½” section. Logs were acquired while pulling out of hole across 9 5/8” liner in upward direction. The objective and plan were to cover with CBL logs to evaluate the first stage cementing from the 9 5/8” Liner shoe to the planned TOC of 8,400’ MD. Cement Bond Index (BI) curve was computed and presented in the log plot showing color gradation from good cement bond (brown) to poor cement (blue). The following values were used by interpreter to differentiate intervals of good bond (curve value above 0.8) to partial (0.2 to 0.8) and poor (lower than 0.2). Summaries of initial pre-job logging plan and Cement Bond Index interpretation are outlined below. Logging Plan Summary Down link to the SoundTrak tool after drilling of 8 ½” open hole and upon coming to the liner shoe at 10,862’ MD to initiate top of cement mode and continue backreaming out of hole to log the cement in the 9 5/8” Liner at 400 gpm and 120 rpm (per Bakerhughes recommendation). x Log cement from 9-5/8” shoe (10,862’ MD) to 8,400’ MD planned top of cement. Log up at 1,200 fph. x Log free pipe from 8,400’ to 7,360’ MD (1,040’ of free pipe) at 1,200 fph. LWD logging was optimized to gain higher efficiency and reduce overall rig time by modifying acquisition parameters and logging at 1200 ft/hr entire well interval. Santos USA and Baker Hughes Confidential Page 5 Interpretation Summary The Intermediate was drilled and a 9 5/8” Casing shoe was set at 10,862ft. After drilling 8 ½” to TD, a Logging up was performed to capture cement Bond on the 9 5/8” casing. Following observations are summarized below by interval. Please note that Bond Index curve (BI) and color coding in combination with other data on the log can be used for more detailed interval inspection to draw conclusions on zonal isolation of narrower intervals. Overall, 6 main zones were defined as listed below, with more detailed interpretation within each zone presented in the table that follows. - 7,357’-7,985’: Poor to no cement presence above 7,985’. - 7,985’-8,350’: Poor to partial Cement presence. - 8,350’-8,580’: Good to partial Cement presence. Mostly Good. - 8,580’ to 9,120’ Very Good Cement presence. - 9,120’ to 9,700’ Good Cement presence with some partial presence Interval. Mostly Good. - 9,700’ to TD Very Good cement presence throughout this interval. For more detailed description of each interval please refer to the table below summarizing Interpretation results. Santos USA and Baker Hughes Confidential Page 6 Santos USA and Baker Hughes Confidential Page 7 Tool Diagram Santos USA and Baker Hughes Confidential Page 8 Methodology of LWD Cement Bond Log Evaluation Before the arrival of more advanced Wireline technologies offering azimuthal coverage of the casing to cement and cement to formation bonding, oil and gas operators have been relying on traditional non-azimuthal CBL, Cement Bond Log, technique, that is being run successfully to date. Wireline Acoustic (Sonic) tool’s CBL measurement principle relies on detecting and measuring first “casing ringing” amplitude reflected from the casing wall. The idea is that free pipe (with cement absence) would “ring” freely creating high Casing Ringing Amplitude, whereas well cemented casing would result in dampened first arrival and thus indicate well cemented pipe. Traditional Wireline tool relies on the arrival of the sound detected at the receiver spaced at 3 ft for CBL Amplitude and for the one from the 5 ft spaced receiver for VDL (Variable Density Log). Figure 1: Traditional Wireline CBL technique Santos USA and Baker Hughes Confidential Page 9 LWD Acoustic (Sonic) tool is using the same principle for CBL measurement. It is also non- azimuthal. However, the one difference is that receiver spacing is longer and all measurements are based on the 10.7 ft receiver spacing for CBL Amplitude. See figures below for the main principle behind cemented vs free pipe detection in traditional CBL measurement. Figure 2: CBL concept in "free" pipe Figure 3: CBL concept in cemented pipe Santos USA and Baker Hughes Confidential Page 10 Figure 4: General CBL concept and corresponding log example Figure 5: LWD Acoustic (Sonic) tool and LWD CBL concept Current traditional offering of LWD Acoustic (Sonic) tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling trip typically on the way out of casing after drilling is completed. Santos USA and Baker Hughes Confidential Page 11 Baker Hughes offers both traditional TOC service and a more advanced workflow of providing Cement Bond Index. This Cement Bond Index is a relative Cement Quality Indicator helping operators to still acquire positive zonal isolation information in wells where running Wireline could be challenging and / or would otherwise increase overall rig time. To convert casing amplitude to cement bond index (BI), two reference points are required: -Free casing - 100% bonded point Figure 6: Cement Bond Index computation concept Traditionally as part of the CBL logging deliverable, Bond Index (BI) is computed and displayed in the log. Values above 80% BI are typically seen as “good" cement, whereas values below 80% are typically seen as either "poor," contaminated or channeled cement. Note however, that the TR spacing (10.66 ft) for LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality check must be carried out to validate the data, because If the casing amplitude in these well bonded intervals is below noise level, the 100% bonded reference point might be incorrect and the “BI” could be over-estimated, reducing quantitative precision of the measurement. Additionally, Cement Evaluation with LWD SoundTrak tool would be ideal in standard cements with slurry density of equal or greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. For example, detection of behind casing open hole DT from waveforms could confirm that proper cement is present. Santos USA and Baker Hughes Confidential Page 12 Furthermore, adding this service can increase operational efficiency since it can be done in the same drilling trip on the way out and logging speed for top of cement detection and CBL evaluation can be as high as ~1500 ft/hr still providing good data quality. With combination of casing mode semblance (SV) and formation arrival in correlogram, TOC can be detected in Real-Time. Good agreement between RT and memory TOC can be seen in the figure below. Figure 7: LWD capability of Real-Time Top of Cement acquisition This method has limitations though as it has no azimuthal coverage and can not identify micro channeling. It is not a replacement for quantitative cement evaluation tools such as SBT, InTex, or CICM Santos USA and Baker Hughes Confidential Page 13 Log Screen Captures Following figures contain interpretation observations, however Bond Index curve and color coding can be used for more detailed interval inspection to draw conclusions on zonal isolation. Please refer to the tables on pages 6 for more detailed interpretation. Figure 8: Interval 1 of LWD CBL logging General Interpretation Comments: 7,357’ to 7,700’ poor to no cement in that interval. Santos USA and Baker Hughes Confidential Page 14 Figure 9: Interval 2 of LWD CBL Logging General Interpretation Comments: 7,700’ to 7,985’ poor cement presence in that interval. 7,985’ to 8,350’ Partial to poor Cement presence. Santos USA and Baker Hughes Confidential Page 15 Figure 10: Interval 3 of LWD CBL Logging General Interpretation Comments: 8,350’ to 8,585’ Good to Partial cement presence. 8,585’ to 8,800’ Very good cement presence. Santos USA and Baker Hughes Confidential Page 16 Figure 11: Interval 4 of LWD CBL Logging General Interpretation Comments: 8,800’ to 9,120’ Very Good Cement Presence. 9,120’-9,400’ Partial to Good. Mostly Good, with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 17 Figure 12: Interval 5 of LWD CBL Logging General Interpretation Comments: 9,400’-9,700’ Partial to Good. Mostly Good, with some intervals of partial cement presence. 9,700’ to 10,000’ Very Good cement presence through this interval. Santos USA and Baker Hughes Confidential Page 18 Figure 13: Interval 6 of LWD CBL Logging General Interpretation Comments: 10,000’ to 10,600’ Very Good presence throughout the interval. Santos USA and Baker Hughes Confidential Page 19 Figure 14: Interval 7 of LWD CBL Logging General Interpretation Comments: 10,600’ to TD. Very Good cement presence. 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:McLellan, Bryan J (OGC) To:Staudinger, Garret (Garret) Subject:RE: NDB-037 10-401 PTD Application Date:Wednesday, October 2, 2024 5:21:00 PM Attachments:image005.png Garret, Yes, this change is approved. I’ll attach this email to the wellfile. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Wednesday, October 2, 2024 1:24 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDB-037 10-401 PTD Application Bryan, Just wanted to check that you received this email and if there are any issues from your end. We received the approved permit for this well the day after I sent this, but just want to make sure you have this for your records. Let me know if you have any questions. Thanks, Garret Staudinger Senior Drilling Engineer m: +1 (907) 440-6892 From: Staudinger, Garret (Garret) Sent: Thursday, September 26, 2024 10:57 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Conwell, Russell (Russell) <Russell.Conwell@santos.com> Subject: RE: NDB-037 10-401 PTD Application Hey Bryan, I wanted to let you know that we plan to reduce excess cement through the permafrost on NDB-037 surface casing cement. We are reducing from 200% to 150% based on excess volumes we have got back to surface on all our offset wells on NDB pad. This will reduce overall cement volume by ~50 bbls. Revised cement calcs for the PTD are below. Please replace the cement info in the permit application with this information. Surface Casing Cement Casing Size 13-3/8” 68# L-80 TXP-BTC Surface Casing Basis Lead Open hole volume + 150% excess in permafrost / 50% excess below permafrost Lead TOC Surface Tail Open hole volume + 50% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Tuned Spacer Lead 11.0ppg Lead: 357 bbls, 2004 cuft, 792 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 69 bbls, 387 cuft, 312 sks HalCem Type I/II – 1.24 cuft/sk Temp BHST 53° F Verification Method Cement returns to surface Notes Job will be mixed on the fly NDB-037 13-3/8" SURFACE CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 2723 2808 85 0.14973 12.7 TAIL LENGTH 2308 2808 500 0.07491 37.5 TAIL EXCESS 50%18.7 LEAD TOP TO BASE OF PERMA 1419 2308 889 0.07491 66.6 EXCESS FACTOR FOR ABOVE 50%33.3 PERMAFROST ANNULUS(Lead) 128 1419 1291 0.07491 96.7 EXCESS FACTOR FOR ABOVE 150%145.1 CASED HOLE ANNULUS 46 128 82 0.18620 15.3 Let me know if you have any questions. Thanks, Garret Staudinger Senior Drilling Engineer m: +1 (907) 440-6892 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, September 16, 2024 9:53 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Conwell, Russell (Russell) <Russell.Conwell@santos.com>; Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Subject: FW: NDB-037 10-401 PTD Application Good Morning Bryan, You should be receiving the NDB-037 PTD application today. I just wanted to let you know that we’ve had a recent shift in our well schedule, and this well (NDB-037) will be moving ahead of another PTD application (NDBi-049) that is currently on your desk. Please prioritize the NDB-037 well for your review. Additionally, there will likely be some changes to the NDBi-049 PTD application, since MPD should be fully operational for that well. We will likely be sending a revised application for NDBi-049 in the coming weeks. I’d also like to take this opportunity to introduce a new Senior Drilling Engineer on our team (Russell Conwell), who just arrived last week from Australia. He will be taking the NDBi-049 well, so will be the point of contact for questions on that well. Here is his contact information: Russell Conwell russell.conwell@santos.com 907-615-2234 Another note – Jake Thompson has elected to leave Santos, so his last week here will be this week. Please feel free to reach out with any questions. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Sent: Monday, September 16, 2024 9:22 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: NDB-037 10-401 PTD Application Good morning, Please see attached the 10-401 PTD Application for well NDB-037. Thank you, Rachel Davis Technical Assistant t:1 (907) 375-4678 | e: rachel.davis@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution,copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 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.govMark Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 601 W 5th Avenue Anchorage, AK, 99501 Re: Pikka Field, Nanushuk Oil Pool, Pikka NDBi-037 Oil Search Alaska, LLC Permit to Drill Number: 224-124 Surface Location: 2344’ FSL, 3226’ FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 1500’ FSL, 1474’ FEL, Sec 30, T12N, R6E, UM Dear Mr. Staudinger: 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. Proposed dry ditch sample interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30'). 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 26th day of September 2024 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.26 11:40:23 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 17,776'TVD:4,142' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 10/1/24 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 6,150' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 70' 15. Distance to Nearest Well Open Surface: x-422019 y- 5,972,725.38 Zone- 4 23' to Same Pool:1,800' 16. Deviated wells: Kickoff depth: N/A feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90.22 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 128' 16" 13-3/8" 68# L-80 TXP BTC 2,808' Surface Surface 2,808' 2,398' 12-1/4" 9-5/8" 47# L-80 HYD 563 8,206' 2,658' 2,324' 10,864' 4,104' Tie Back 9-5/8" 47# L-80 HYD 563 2,658' Surface Surface 2,658' 2,324' 8-1/2" 4-1/2" 12.6# P-110S HYD 563 7,061' 10,715' 4,060' 17,776' 4,142' Tubing 4-1/2" 12.6# P-110S HYD 563 10,715' Surface Surface 10,715' 4,060' 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: Mark Staudinger Mark Staudinger Contact Email:mark.staudinger@santos.com Senior Drilling Engineer Contact Phone:1-520-273-6643 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 NDB-037 Pikka / Nanushuk Oil Pool See attachment 6 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): IS000361277U STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 See attachment 6 1,465 1110’ FSL, 830’ FEL, Sec 31, T12N, R6E, UM 1500’ FSL, 1474’ FEL, Sec 30, T12N, R6E, UM LONS 19-003 601 W 5th Avenue, Anchorage, AK 99501 Oil Search Alaska, LLC 2344’ FSL, 3226’ FEL, Sec 4, T11N, R6E, UM ADL 392984, 391445, 393020, 393019, 393018 3099 18. Casing Program: Top - Setting Depth - BottomSpecifications 1,877 GL / BF Elevation above MSL (ft): Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface See attachment 6 Uncemented N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): Conductor/Structural LengthCasing Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): s N ype of W L l R L 1b S Class: os N s No s N o D s s sD o well is p G S S 20 S S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Senior Drilling Engineer 9/11/2024 By Grace Christianson at 10:16 am, Sep 16, 2024 Pikka See attached conditions of approval. 50-103-20895-00-00 DSR-9/25/24A.Dewhurst 19SEP24 Variance from pool rules granted to isolate significant hydrocarbons as proposed. -A.Dewhurst 19SEP24 BJM 9/25/24 224-124 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.26 11:40:36 -08'00'09/26/24 09/26/24 RBDMS JSB 093024 NDB-037 (PTD 224-124) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨApproval 1.KWƚĞƐƚƚŽϯ6ϬϬƉƐŝ͕ŶŶƵůĂƌƚĞƐƚƚŽϯϬϬϬƉƐŝ͘ 2.>Kdͬ&/dƌĞƐƵůƚƐƚŽďĞƐƵďŵŝƩĞĚƚŽK'ǁŝƚŚŝŶϰϴŚŽƵƌƐŽĨŽďƚĂŝŶŝŶŐƚŚĞĚĂƚĂ͘ 3./ĨDWǁŝůůďĞƵƐĞĚ͕Kŝů^ĞĂƌĐŚŵƵƐƚŵĂŝŶƚĂŝŶŵƵĚĚĞŶƐŝƚLJŝŶĞdžĐĞƐƐŽĨƚŚĞŚŝŐŚĞƐƚĂŶƟĐŝƉĂƚĞĚ ƌĞƐĞƌǀŽŝƌ Dt. 4.EŽƟĨLJK'ŝĨĐĞŵĞŶƚũŽďƐĚŽŶŽƚŐŽĂĐĐŽƌĚŝŶŐƚŽƉůĂŶŽƌŝĨũŽďƉĂƌĂŵĞƚĞƌƐĂƌĞŶŽƚĂƐ ĞdžƉĞĐƚĞĚ;ůŽƐƐĞƐŽĐĐƵƌ͕ƵŶĞdžƉĞĐƚĞĚůŝŌƉƌĞƐƐƵƌĞƐŽĐĐƵƌ͕ĐĞŵĞŶƚŝƐŶŽƚĐŝƌĐƵůĂƚĞĚŽīƚŚĞƚŽƉŽĨ ƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞůŝŶĞƌ͕ĞƚĐ͘Ϳ. Cement ƚŽďĞůŽŐŐĞĚŝĨũŽďĚŽĞƐŶŽƚŐŽĂĐĐŽƌĚŝŶŐƚŽƉůĂŶ͘ 5.sĂƌŝĂŶĐĞƚŽϮϬϮϱ͘ϬϯϬ;ĚͿ;ϱͿĨŽƌϮ-ƐƚĂŐĞŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐ ĐĞŵĞŶƚŽƉĞƌĂƟŽŶĂŶĚŐĂƉŝŶ ĐĞŵĞŶƚĐŽǀĞƌĂŐĞŝƐĂƉƉƌŽǀĞĚ͕ǁŝƚŚƐƚĂŐĞĐŽůůĂƌƉůĂĐĞŵĞŶƚĂƐĨŽůůŽǁƐ ;ƌĞĨĞƌĞŶĐĞƐĞĐƟŽŶϭϱŝŶ WdĂƉƉůŝĐĂƟŽŶͿ: a.^ƚĂŐĞĐŽůůĂƌŵƵƐƚďĞƉůĂĐĞĚŶŽƐŚĂůůŽǁĞƌƚŚĂŶϱϬΖDďĞůŽǁƚŚĞďĂƐĞŽĨƚŚĞhƉƉĞƌ dƵůƵǀĂŬĂƐĚĞĮŶĞĚďLJƚŚĞd^ϳϵϬŚŽƌŝnjŽŶ͘ ď͘ ^ƵďŵŝƚϭϮ-ϭͬϰΗK,ůŽŐƐƚŽK'ĂƐƐŽŽŶĂƐƉƌĂĐƟĐĂůĂŌĞƌdŽĨŚŽůĞƐĞĐƟŽŶ͘ dŚĞ d^ϳϵϬŵĂƌŬĞƌŝƐǁĞůů-ĞƐƚĂďůŝƐŚĞĚŝŶƚŚĞĂƌĞĂŽĨEƉĂĚĂŶĚƚŚĞƌĞĨŽƌĞKŝů^ĞĂƌĐŚĚŽĞƐ ŶŽƚŶĞĞĚƚŽƐĞĞŬK'ĂƉƉƌŽǀĂůŽĨƚŚĞŝƌƉŝĐŬŽĨƚŚĞd^ϳϵϬďĞĨŽƌĞƌƵŶŶŝŶŐϵ-ϱͬϴ͟ ĐĂƐŝŶŐ͘ 6.dŚĞ>t-^ŽŶŝĐůŽŐǁŝůůŽŶůLJďĞĂĐĐĞƉƚĞĚĨŽƌĐĞŵĞŶƚĞǀĂůƵĂƟŽŶǁŚĞŶƚŚĞĨŽůůŽǁŝŶŐĐŽŶĚŝƟŽŶƐ are met: a.KŝůƐĞĂƌĐŚƚŽƉƌŽǀŝĚĞĂǁƌŝƩĞŶůŽŐĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶƚŽƚŚĞK'ĂůŽŶŐǁŝƚŚƚŚĞ ůŽŐĂƐƐŽŽŶĂƐƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘dŚĞĞǀĂůƵĂƟŽŶŝƐƚŽŝŶĚŝ ĐĂƚĞƚŚĞŝŶƚĞƌǀĂůƐŽĨ ĐŽŵƉĞƚĞŶƚĐĞŵĞŶƚƚŚĂƚKŝůƐĞĂƌĐŚŝƐƵƐŝŶŐƚŽŵĞĞƚƚŚĞŽďũĞĐƟǀĞƌĞƋƵŝƌĞŵĞŶƚƐĨŽƌ aŶŶƵůĂƌŝƐŽůĂƟŽŶĂŶĚƌĞƐĞƌǀŽŝƌŝƐŽůĂƟŽŶ͕ĂŶĚƚŽŝŶĚŝĐĂƚĞƚŚĞůŽĐĂƟŽŶŽĨĐŽŶĮŶŝŶŐnjŽŶĞƐ͕ ŚLJĚƌŽĐĂƌďŽŶ-ďĞĂƌŝŶŐnjŽŶĞƐ͕ŽǀĞƌƉƌĞƐƐƵƌĞĚnjŽŶĞƐĂŶĚĨƌĞƐŚǁĂƚĞƌ͕ŝĨƉƌĞƐĞŶƚ͘WƌŽǀŝĚŝŶŐ ƚŚĞůŽŐǁŝƚŚŽƵƚĂŶĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶŝƐŶŽƚĂĐĐĞƉƚĂďůĞ͘ ď͘ >tƐŽŶŝĐůŽŐƐŵƵƐƚƐŚŽǁĨƌĞĞƉŝƉĞĂŶĚdŽƉŽĨĞŵĞŶƚ͘ dŚĞůŽŐŵƵƐƚďĞƌƵŶĂĐƌŽƐƐƚŚĞ ƚĂƌŐĞƚnjŽŶĞƐĂŶĚĂƚĂĚĞƉƚŚƚŽĞŶƐƵƌĞƚŚĞĨƌĞĞƉŝƉĞĂďŽǀĞƚŚĞdKŝƐĐĂƉƚƵƌĞĚĂƐǁĞůůĂƐ ƚŚĞdK͘/ĨƚŚĞůŽŐŐĞĚŝŶƚĞƌǀĂůĚŽĞƐŶŽƚĐĂƉƚƵƌĞƚŚĞdKĂŶĚĨƌĞĞƉŝƉĞĂďŽǀĞŝƚ͕ ŝƚǁŝůů ŶĞĞĚƚŽďĞƌĞ-ƌƵŶ͕ƵŶůĞƐƐƚŚĞĐĞŵĞŶƚǁĂƐƉůĂŶŶĞĚƚŽĐŽǀĞƌƚŚĞĞŶƟƌĞůĞŶŐƚŚŽĨůŝŶĞƌŽƌ ĐĂƐŝŶŐ͘ Đ͘ KŝůƐĞĂƌĐŚǁŝůůƉƌŽǀŝĚĞĂĐĞŵĞŶƚũŽďƐƵŵŵĂƌLJƌĞƉŽƌƚĂŶĚĞǀĂůƵĂƟŽŶĂůŽŶŐǁŝƚŚƚŚĞ ĐĞŵĞŶƚůŽŐĂŶĚĞǀĂůƵĂƟŽŶƚŽƚŚĞK'ǁŚĞŶƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘ d.ĞƉĞŶĚŝŶŐŽŶƚŚĞĐĞŵĞŶƚũŽďƌĞƐƵůƚƐŝŶĚŝĐĂƚĞĚďLJƚŚĞĐĞŵĞŶƚũŽďƌĞƉŽƌƚ͕ƚŚĞůŽŐƐĂŶĚ ƚŚĞ&/d͕ƌĞŵĞĚŝĂůŵĞĂƐƵƌĞƐŽƌĂĚĚŝƟŽŶĂůůŽŐŐŝŶŐŵĂLJďĞƌĞƋƵŝƌĞĚ͘ Page 1 of 1 10 September 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-037 Dear Sir/Madam, Oil Search (Alaska), LLC hereby applies for a Permit to Drill an onshore development well from the NDB drilling pad on the North Slope of Alaska. NDB-037 is planned to be a horizontal producer targeting the Nanushuk 3. The approximate spud date is anticipated to be October 12th, 2024. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~79 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8” tieback will be run to the top of the 9-5/8” liner. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand and the lateral will be drilled to TD. The well will be completed as a stimulated 4-1/2” liner with frac sleeves and isolation packers. The production liner will be tied back to surface with a 4-1/2” tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (520) 273-6643 or Mark.Staudinger@santos.com. Respectfully, Mark Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, Mark Staudinger Application for Permit to Drill NDB-037 Well Table of Contents 1. Well Name......................................................................................................................................3 2. Location Summary..........................................................................................................................3 3. Blowout Prevention Equipment Information.................................................................................4 4. Drilling Hazards Information...........................................................................................................5 5. Procedure for Conducting Formation Integrity Tests.....................................................................6 6. Casing and Cementing Program.....................................................................................................6 7. Diverter System Information..........................................................................................................7 8. Drilling Fluid Program.....................................................................................................................7 9. Abnormally Pressured Formation Information..............................................................................8 10. Seismic Analysis............................................................................................................................8 11. Seabed Condition Analysis............................................................................................................8 12. Evidence of Bonding.....................................................................................................................8 13. Proposed Drilling Program ...........................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................11 15. Proposed Variance Request........................................................................................................11 Attachments..................................................................................................................................................13 Attachment 1: Location Maps..........................................................................................................14 Attachment 2: Directional Plan........................................................................................................15 Attachment 3: BOPE Equipment ......................................................................................................16 Attachment 4: Drilling Hazards.........................................................................................................17 Attachment 5: Leak Off Test Procedure...........................................................................................19 Attachment 6: Cement Summary.....................................................................................................20 Attachment 7: Prognosed Formation Tops......................................................................................22 Attachment 8: Well Schematic.........................................................................................................23 Attachment 9: Formation Evaluation Program................................................................................24 Attachment 10: Wellhead & Tree Diagram......................................................................................25 Attachment 11: Managed Pressure Drilling.....................................................................................26 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDB-037. This will be a development production well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 2344’ FSL, 3226’ FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,725 E 422,019 Rig KB Elevation 47’ above GL Ground Level 23’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 1110’ FSL, 830’ FEL, Sec 31, T12N, R6E, UM NAD 27 Coordinate System N 5,976,958 E 413,824 Measured Depth, Rig KB (MD) 11,290’ Total Vertical Depth, Rig KB (TVD) 4,167’ Total vertical Depth, Subsea (TVDSS) 4,097’ Location at Bottom of Productive Interval Reference to Government Section Lines 1500’ FSL, 1474’ FEL, Sec 30, T12N, R6E, UM NAD 27 Coordinate System N 5,982,574’ E 410,580’ Measured Depth, Rig KB (MD) 17,776’ Total Vertical Depth, Rig KB (TVD) 4,142’ Total vertical Depth, Subsea (TVDSS) 4,072’ (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 2: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for NDB-037 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Parker 272 BOP Equipment: BOP Equipment x NOV Shaffer Spherical annular BOP, 13-5/8” x 5000 psi x NOV T3 6012 double gate, 13-5/8” x 5000 psi x Mud cross, 13-5/8” x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets x Choke Line, 3-1/8” x 5000 psi with 3-1/8” manual and HCR valve x Kill Line, 2-1/16” x 5000 psi with 3-1/8” manual and HCR valve x NOV T3 6012 single gate, 13-5/8” x 5000 psi Choke Manifold x 3-1/8” x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit x NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,868 psi in the Nanushuk 3 at 4,094’ TVD (8.8ppg EMW Nanushuk 3 formation to section TD) Maximum surface pressure 1,459 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,094’ TVD) Planned BOP test pressure Rams test to 3,600 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 12-1/4” hole FIT after drilling 20’-50’ of new hole to 15.0ppg. (13.4 ppg LOT required for Kick Tolerance.) 13-3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by 50% of Casing Burst] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,878 psi in the Nanushuk 3.2 at 4,120’ TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,466 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,120’ TVD) Planned BOP test pressure Rams test to 3,600 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 8-1/2” hole FIT after drilling 20’-50’ of new hole to 14.0 ppg. (10.7 ppg EMW LOT Required for infinite kick tolerance.) 9-5/8” Liner Test 4,000 psi surface pressure [Test pressure driven by annular pressure during frac job] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be over-pressured at 10.2ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. (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 refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 128’ 16” 13-3/8” 68# L-80 TXP BTC 2,808’ Surface 2,808’ / 2,398’ 12-1/4” 9-5/8” 47# L-80 HYD 563 8,206’ 2,658’ 10,864’ / 4,104’ Tie Back 9-5/8” 47# L-80 HYD 563 2,658’ Surface 2,658’ / 2,324’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 7,061’ 10,715’ 17,776’ / 4,142’ Tubing 4-1/2” 12.6# P-110S HYD 563 10,715’ Surface 10,715’ / 4,060’ Please refer to Attachment 6: Cement Summary for further details. 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line Please refer to Attachment 3: BOPE Equipment for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Intermediate Hole Production Hole Mud Type Water based Spud Mud Mineral Oil Based Mud Mineral Oil Based Mud Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 9.0 – 9.5 ppg 100-300 seconds ALAP 30-80 < 10 ml/30min n/a 8.6-10.5 <35 11.0* - 12.0 ppg 50-80 seconds ALAP 15-30 n/a < 5 ml/30min n/a n/a 9.2* – 10.0 ppg 50-80 seconds ALAP 10-20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. *Managed Pressure Drilling may be used for the intermediate and/or production hole on NDB-037 if the MPD system is installed and fully operational on the rig. If MPD is utilized, mud weights may be reduced for these hole sections. For further information on MPD rig up and operation, reference Attachment 11. *Managed Pressure Drilling may be used for the intermediate and/or production hole on NDB-037 if the MPD system is installed and fully operational on the rig. If MPD is utilized, mud weights may be reduced for these hole sections. For further information on MPD rig up and operation, reference Attachment 11. MPD system use is approved on the condition that mud weight exceeds the highest anticipated reservoir EMW to be encountered, per 20 AAC 25.033. -bjm 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDB-037 Well is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Oil Search Alaska is on file with the Commission. 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to NDB-037 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program NDB-037 1. Drill 20” conductor to ~128’ MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools and diverter over the 20” conductor. Verify that the diverter line is at least 75’ away from a potential source of ignition and beyond the drill rig substructure. 4. Function test diverter and knife valve as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing diverter test. 5. Pick up 5-7/8” drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16” motor BHA with MWD and LWD tools. 6. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 7. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 8. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 9. ND diverter and NU casing head and spacer spool. NU BOPE (configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 9-5/8” Fixed Rams). Test rams to 3600 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing BOP test. 10. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 11. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment 12. Displace well to MOBM. 13. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test. 14. If Managed Pressure Drilling is utilized, install MPD bearing assembly. 15. Directionally drill 12-1/4” intermediate hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH. 16. Run 9-5/8” production liner as per casing tally then RIH on 5-7/8” DP. Circulate and condition mud prior to commencing cement job. 17. Set liner hanger and release running tool. Cement 9-5/8” liner with 1st stage cement job as per cement program. Monitor returns during displacement until plug bump. 18. Un-sting from liner hanger and POOH and LD liner running tools. 19. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Sting into second stage tool pump secondary stage, SO and set liner top packer. POOH and lay down running tool. 20. Run 9-5/8” tie-back string. Freeze protect the 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 21. Pressure test 13-3/8” x 9-5/8” to 2600 psi for 30 min. 22. Pressure test the 9-5/8” liner and tieback to 3500 psi for 30 min. 23. Make up 8-1/2” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to production hole MOBM. 24. Drill out shoe track and 20 - 50’ of new formation. Perform formation integrity test. 25. If Managed Pressure Drilling is utilized, install MPD bearing assembly. 26. Directionally drill 8-1/2” hole section as per well plan to TD. Perform wiper trips as required. 27. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary 28. Run cleanout/string mill assembly to dress the 9-5/8” CFLEX tool. 29. RU to run 4-1/2” production liner with liner hanger/top packer and downhole jewelry to TD. 30. Circulate MOBM out of open hole with brine with biocide. Spotting tail end of the spacer near the liner hanger/packer. 31. Close WIV collar and set open hole hydraulic set packers and liner hanger/top packer. 32. Pressure test 9-5/8” x 4-1/2” IA to liner top packer to 3,500 psi for 10 mins. 33. Release the running tool. 34. Pull one stand and circulate spacer train and corrosion inhibited/biocide brine and safelube. 35. POOH and lay down the running tool. 36. Prepare and run the 4-1/2” upper completion and downhole jewelry. 37. Land tubing hanger. 38. Pressure test tubing to 3,500 psi for 30 mins for MIT-T. 39. Decrease tubing pressure to 3,000 psi. Pressure up on annulus to 4,000 psi for 30 mins for MIT-IA. Bleed pressure on tubing and shear circulation valve. 40. Reverse circulate freeze protect through the sheared circulation valve at the gaslift mandrel and U-Tube. 41. Install TWC and pressure test to 2,500 psi for 10 mins from direction of flow. 42. ND BOP, NU 10k frac tree. 43. Secure well and prepare for rig move. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. Water-based and oil-based drilling muds and cuttings will typically be hauled directly offsite via truck as it is generated. Contractual arrangements have been made with other operators on the North Slope to utilize their waste injection/disposal facilities (Class 1 and Class 2) at Prudhoe Bay, Kuparuk and Milne Point. If waste cannot be hauled directly offsite, it may be stored temporarily in drilling waste cuttings bins or a bermed cuttings storage cell in accordance with a drilling waste temporary storage plan approved by Alaska Department of Conservation (ADEC) Solid Waste Program until it can be transported for proper disposal. In the event the Oil Search Alaska NGI (Nanushuk Grind & Inject) facility is operational, cuttings will be hauled via truck as generated, process at NGI, and disposed of into the DW-02 Class 1 disposal well. The NGI facility is located on NDB. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Request 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire annular space from the casing shoe to above shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the significant hydrocarbon zone in the Nanushuk formation (primary job), and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. The primary cement job will target a top of cement 500’ MD or 250’ TVD, whichever is greater, above the top of the Nanushuk. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the intermediate liner is not achievable without exceeding the fracture gradient and compromising cement placement and zonal isolation. The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be designed to: 1) provide suitable and safe operating conditions for the total measured depth proposed; 2) confine fluids to the wellbore; 3) prevent migration of fluids from one stratum to another; 4) ensure control of well pressures encountered; 5) protect against thaw subsidence and freezeback effects within permafrost; 6) prevent contamination of freshwater; 7) protect significant hydrocarbon zones; and 8) provide well control until the next casing is set, considering all factors relevant to well control including formation fracture gradients, formation pressures, casing setting depths, and proposed total depth. The formation interval between the top of stage one and the bottom of stage two includes the Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with very low permeability and contain no significant hydrocarbons. Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,640’ TVD. The Tuluvak formation below 2,640’ TVD is not a significant hydrocarbon zone. A stage collar placement is proposed 50’ MD below the TS 790 formation marker (Upper Tuluvak). This stage collar depth will isolate any potential gas based on offset well data. The TS 875 and TS 870 clinoform is between the TS 880 clinoform and TS 790 top. The TS 875 and TS 870 clinoforms are shale dominated, very low net to gross, have no vertical permeability, and represents a seal to the hydrocarbon bearing TS 880. Moving the cementing stage tool to be placed at 50’ MD below the TS 790 formation marker allows placement of higher quality cement that provides better isolation across the significant hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will add risk to the primary objective of cement isolation across the significant hydrocarbon zone which is only located in the upper portion of the Tuluvak (TS 880). The increased risk is due to: 1) Cementing the entire Tuluvak would require large cement jobs that jeopardize cement isolation across the upper Tuluvak. 2) Large cement jobs likely require the use of lighter weight cement across the significant hydrocarbon zone. Recommend granting requested variance to permit two-stage cementing operation. Recommend granting variance from pool rules to isolate significant hydrocarbons as proposed above (base of significant HC zone defined from TS790 maker). -A.Dewhurst 19SEP24 Attachments Attachment 1: Location Maps DW-02 NDB-024 NDB-032 NDB-051 NDBi-014 NDBi-018 NDBi-030 NDBi-043 NDBi-044 NDB-037 ADL 392977 ADL 392991 ADL 392985 ADL 392984 ADL 392968 ADL 392958 ADL 392970 ADL 393022 ADL 393021 ADL 393023 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393007 ADL 391445 ADL 391455 ADL 393011ADL 393010 U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N005E25 U012N006E28 U012N005E36 U012N006E20 U011N005E01 U012N006E21U012N005E24 U011N005E12 U011N006E09U011N006E08 U012N006E31 U011N006E06 U012N006E19 U012N006E30 U011N006E07 FIORD 3A FIORD 3 QUGRUK 3 QUGRUK 301 QUGRUK 3A OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDB-037 TRAJECTORY OTHER DRILLED NDB WELLS NDB-037 SURFACE LOCATION NDBI-037 BOTTOM HOLE 0.25-MILE BUFFER 0.5-MILE BUFFER PRODUCTION INTERVAL NDB DRILLED WELLS BOTTOM HOLES WELL TRAJECTORIES BY OTHERS BOTTOM HOLES OTHER EXPLORATION WELLS SECTIONS SANTOS LEASES DATE: 8/30/2024. By: JB 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB37_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDB37 WELL OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD OTHER NDB WELLS WELL HEAD RIG OUTLINES DIVERTER (50-ft) DATE: 8/30/2024. By: JB 0204010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB37_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDB-037 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.3353 -150.6358 N 70° 20' 07.0354" W 150° 38' 08.8817" 5,972,473.37 1,562,051.39 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.3356 -150.6327 N 70° 20' 08.1866" W 150° 37' 57.6049" 5,972,725.38 422,018.58 State Plane NAD83 Zone 4 (as-built) StatePlane NAD27 Zone 4 (as-built) Attachment 2: Directional Plan Standard Planning Report - Geographic 10 September, 2024 Plan: Plan: NDB-037 Rev C.1 Santos NAD27 Conversion Pikka NDB NDB-037 NDB-037 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka, North Slope Alaska, United States Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: NDB Map Slot Radius:0.9 usft usft usft " 5,972,909.70 423,383.56 20 70° 20' 10.138 N 150° 37' 17.796 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: NDB-037 Wellhead Elevation:0.5 0.0 0.0 5,972,725.38 422,018.58 70° 20' 8.187 N 150° 37' 57.605 W 22.8 usft usft usft usft usft usft usft °-0.60Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDB-037 Model NameMagnetics IGRF2000 31/12/2004 24.73 80.61 57,282.29376177 Phase:Version: Audit Notes: Design Plan: NDB-037 Rev C.1 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 310.130.00.047.0 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 2 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 10/09/2024 Depth To (usft) Depth From (usft) SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISC Plan: NDB-037 Rev C.1 (NDB-03147.0 900.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-037 Rev C.1 (NDB-032900.0 2,100.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-037 Rev C.1 (NDB-033900.0 2,808.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-037 Rev C.1 (NDB-0342,808.0 3,850.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-037 Rev C.1 (NDB-0352,808.0 3,850.0 3_MWD_Interp Azi+Sag H003Mb: Interpolated azimu Plan: NDB-037 Rev C.1 (NDB-0363,850.0 4,400.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-037 Rev C.1 (NDB-0374,400.0 5,200.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-037 Rev C.1 (NDB-0384,400.0 10,864.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-037 Rev C.1 (NDB-03910,864.0 12,064.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-037 Rev C.1 (NDB-031010,864.0 17,776.4 Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.00.047.00.000.0047.0 0.000.000.000.000.00.0347.00.000.00347.0 330.000.002.002.00-7.813.6646.5330.006.00647.0 -24.94-4.242.402.50-48.561.0994.1315.0014.501,000.6 0.000.000.000.00-75.087.51,139.3315.0014.501,150.6 -25.69-1.082.943.00-1,421.2744.72,571.0291.2678.893,340.7 0.000.000.000.00-7,070.82,942.73,761.5291.2678.899,518.6 103.523.06-0.473.00-7,976.63,704.64,075.0329.3973.0010,765.1 0.000.000.000.00-8,025.33,786.94,104.2329.3973.0010,865.1 0.000.000.004.00-8,238.64,147.34,166.8329.3990.0011,290.1 NDB-037 Heel Rev 1.240.073.003.00-8,242.34,153.64,166.8329.3990.2211,297.5 0.000.000.000.00-11,541.09,729.94,141.8329.3990.2217,776.4 NDB-037 Toe Rev2 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 3 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 47.0 0.00 47.0 0.0 0.00.00 422,018.585,972,725.38 70° 20' 8.187 N 150° 37' 57.605 W 100.0 0.00 100.0 0.0 0.00.00 422,018.585,972,725.38 70° 20' 8.187 N 150° 37' 57.605 W 128.0 0.00 128.0 0.0 0.00.00 422,018.585,972,725.38 70° 20' 8.187 N 150° 37' 57.605 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,018.585,972,725.38 70° 20' 8.187 N 150° 37' 57.605 W 300.0 0.00 300.0 0.0 0.00.00 422,018.585,972,725.38 70° 20' 8.187 N 150° 37' 57.605 W 347.0 0.00 347.0 0.0 0.00.00 422,018.585,972,725.38 70° 20' 8.187 N 150° 37' 57.605 W Start Build 2.00 400.0 1.06 400.0 0.4 -0.2330.00 422,018.345,972,725.81 70° 20' 8.191 N 150° 37' 57.612 W 500.0 3.06 499.9 3.5 -2.0330.00 422,016.575,972,728.94 70° 20' 8.221 N 150° 37' 57.665 W 600.0 5.06 599.7 9.7 -5.6330.00 422,013.105,972,735.11 70° 20' 8.282 N 150° 37' 57.768 W 647.0 6.00 646.5 13.6 -7.8330.00 422,010.885,972,739.05 70° 20' 8.320 N 150° 37' 57.834 W Start DLS 2.50 TFO -24.94 700.0 7.22 699.1 18.7 -11.1325.55 422,007.665,972,744.23 70° 20' 8.371 N 150° 37' 57.930 W 800.0 9.60 798.0 30.3 -20.0320.29 421,998.895,972,755.93 70° 20' 8.485 N 150° 37' 58.189 W 900.0 12.03 896.2 44.4 -32.4317.12 421,986.625,972,770.11 70° 20' 8.623 N 150° 37' 58.552 W 1,000.0 14.49 993.6 60.9 -48.4315.01 421,970.855,972,786.76 70° 20' 8.785 N 150° 37' 59.017 W 1,000.6 14.50 994.1 61.0 -48.5315.00 421,970.765,972,786.86 70° 20' 8.786 N 150° 37' 59.020 W Start 150.0 hold at 1000.6 MD 1,052.9 14.50 1,044.8 70.3 -57.7315.00 421,961.585,972,796.23 70° 20' 8.878 N 150° 37' 59.291 W Upper Schrader Bluff 1,100.0 14.50 1,090.4 78.6 -66.1315.00 421,953.345,972,804.65 70° 20' 8.960 N 150° 37' 59.534 W 1,145.9 14.50 1,134.8 86.7 -74.2315.00 421,945.305,972,812.86 70° 20' 9.039 N 150° 37' 59.772 W Base Ice Bearing Permafrost 1,150.6 14.50 1,139.3 87.5 -75.0315.00 421,944.485,972,813.69 70° 20' 9.048 N 150° 37' 59.796 W Start DLS 3.00 TFO -25.69 1,200.0 15.85 1,187.0 96.5 -84.4312.65 421,935.235,972,822.74 70° 20' 9.136 N 150° 38' 0.069 W 1,300.0 18.64 1,282.5 115.8 -106.8308.91 421,912.955,972,842.27 70° 20' 9.325 N 150° 38' 0.725 W 1,400.0 21.48 1,376.5 136.6 -134.1306.13 421,885.945,972,863.39 70° 20' 9.530 N 150° 38' 1.521 W 1,418.7 22.02 1,393.8 140.7 -139.7305.69 421,880.385,972,867.50 70° 20' 9.570 N 150° 38' 1.684 W Base Permafrost Transition 1,500.0 24.37 1,468.6 159.0 -166.0303.98 421,854.275,972,886.05 70° 20' 9.750 N 150° 38' 2.452 W 1,600.0 27.27 1,558.6 182.7 -202.5302.26 421,818.045,972,910.18 70° 20' 9.984 N 150° 38' 3.518 W 1,700.0 30.19 1,646.2 207.8 -243.4300.84 421,777.345,972,935.73 70° 20' 10.231 N 150° 38' 4.715 W 1,800.0 33.13 1,731.4 234.3 -288.8299.66 421,732.275,972,962.62 70° 20' 10.491 N 150° 38' 6.039 W 1,810.1 33.42 1,739.8 237.0 -293.6299.55 421,727.485,972,965.41 70° 20' 10.518 N 150° 38' 6.180 W Middle Schrader Bluff 1,900.0 36.07 1,813.7 261.9 -338.4298.65 421,682.975,972,990.78 70° 20' 10.762 N 150° 38' 7.487 W 2,000.0 39.02 1,892.9 290.7 -392.1297.77 421,629.585,973,020.12 70° 20' 11.046 N 150° 38' 9.056 W 2,100.0 41.98 1,969.0 320.6 -449.8297.00 421,572.235,973,050.57 70° 20' 11.339 N 150° 38' 10.740 W 2,200.0 44.94 2,041.5 351.4 -511.2296.31 421,511.085,973,082.05 70° 20' 11.643 N 150° 38' 12.535 W 2,300.0 47.91 2,110.5 383.2 -576.3295.69 421,446.315,973,114.47 70° 20' 11.955 N 150° 38' 14.437 W 2,356.6 49.59 2,147.8 401.5 -614.8295.36 421,408.085,973,133.22 70° 20' 12.135 N 150° 38' 15.559 W MCU 2,400.0 50.88 2,175.5 415.7 -644.9295.12 421,378.085,973,147.74 70° 20' 12.275 N 150° 38' 16.440 W 2,500.0 53.85 2,236.6 449.0 -716.8294.60 421,306.595,973,181.77 70° 20' 12.602 N 150° 38' 18.538 W 2,600.0 56.83 2,293.5 482.9 -791.7294.12 421,232.035,973,216.47 70° 20' 12.936 N 150° 38' 20.727 W 2,700.0 59.80 2,346.0 517.4 -869.5293.67 421,154.615,973,251.74 70° 20' 13.275 N 150° 38' 22.999 W 2,800.0 62.78 2,394.0 552.3 -949.9293.25 421,074.545,973,287.48 70° 20' 13.618 N 150° 38' 25.348 W 2,808.0 63.02 2,397.7 555.1 -956.5293.22 421,068.025,973,290.35 70° 20' 13.645 N 150° 38' 25.539 W 13-3/8" Surface Casing 2,884.0 65.28 2,430.8 581.9 -1,019.4292.91 421,005.385,973,317.80 70° 20' 13.909 N 150° 38' 27.377 W Tuluvak Shale 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 4 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 2,900.0 65.76 2,437.4 587.6 -1,032.8292.85 420,992.035,973,323.59 70° 20' 13.965 N 150° 38' 27.769 W 3,000.0 68.73 2,476.1 623.1 -1,117.9292.47 420,907.325,973,359.99 70° 20' 14.314 N 150° 38' 30.254 W 3,041.7 69.98 2,490.8 637.9 -1,154.0292.31 420,871.395,973,375.23 70° 20' 14.460 N 150° 38' 31.309 W Tuluvak Sand 3,100.0 71.71 2,509.9 658.7 -1,205.0292.10 420,820.645,973,396.56 70° 20' 14.664 N 150° 38' 32.797 W 3,200.0 74.70 2,538.8 694.5 -1,293.8291.74 420,732.225,973,433.21 70° 20' 15.016 N 150° 38' 35.391 W 3,300.0 77.68 2,562.7 730.2 -1,384.1291.40 420,642.315,973,469.84 70° 20' 15.367 N 150° 38' 38.029 W 3,340.7 78.89 2,571.0 744.7 -1,421.2291.26 420,605.355,973,484.71 70° 20' 15.509 N 150° 38' 39.113 W Start 6178.1 hold at 3340.7 MD 3,400.0 78.89 2,582.4 765.8 -1,475.4291.26 420,551.345,973,506.37 70° 20' 15.716 N 150° 38' 40.697 W 3,500.0 78.89 2,601.7 801.3 -1,566.9291.26 420,460.275,973,542.90 70° 20' 16.066 N 150° 38' 43.368 W 3,600.0 78.89 2,620.9 836.9 -1,658.3291.26 420,369.215,973,579.42 70° 20' 16.416 N 150° 38' 46.039 W 3,700.0 78.89 2,640.2 872.5 -1,749.8291.26 420,278.145,973,615.95 70° 20' 16.766 N 150° 38' 48.710 W 3,800.0 78.89 2,659.5 908.1 -1,841.2291.26 420,187.085,973,652.47 70° 20' 17.115 N 150° 38' 51.382 W 3,900.0 78.89 2,678.7 943.7 -1,932.7291.26 420,096.015,973,688.99 70° 20' 17.465 N 150° 38' 54.053 W 4,000.0 78.89 2,698.0 979.2 -2,024.1291.26 420,004.955,973,725.52 70° 20' 17.815 N 150° 38' 56.724 W 4,100.0 78.89 2,717.3 1,014.8 -2,115.6291.26 419,913.885,973,762.04 70° 20' 18.164 N 150° 38' 59.395 W 4,200.0 78.89 2,736.6 1,050.4 -2,207.0291.26 419,822.825,973,798.56 70° 20' 18.514 N 150° 39' 2.067 W 4,300.0 78.89 2,755.8 1,086.0 -2,298.5291.26 419,731.755,973,835.09 70° 20' 18.864 N 150° 39' 4.738 W 4,400.0 78.89 2,775.1 1,121.5 -2,389.9291.26 419,640.695,973,871.61 70° 20' 19.213 N 150° 39' 7.409 W 4,500.0 78.89 2,794.4 1,157.1 -2,481.4291.26 419,549.625,973,908.13 70° 20' 19.563 N 150° 39' 10.081 W 4,538.6 78.89 2,801.8 1,170.9 -2,516.6291.26 419,514.485,973,922.23 70° 20' 19.698 N 150° 39' 11.112 W TS_790 4,600.0 78.89 2,813.6 1,192.7 -2,572.8291.26 419,458.565,973,944.66 70° 20' 19.912 N 150° 39' 12.752 W 4,700.0 78.89 2,832.9 1,228.3 -2,664.3291.26 419,367.495,973,981.18 70° 20' 20.262 N 150° 39' 15.424 W 4,800.0 78.89 2,852.2 1,263.9 -2,755.7291.26 419,276.435,974,017.71 70° 20' 20.612 N 150° 39' 18.095 W 4,900.0 78.89 2,871.4 1,299.4 -2,847.1291.26 419,185.365,974,054.23 70° 20' 20.961 N 150° 39' 20.766 W 5,000.0 78.89 2,890.7 1,335.0 -2,938.6291.26 419,094.305,974,090.75 70° 20' 21.311 N 150° 39' 23.438 W 5,100.0 78.89 2,910.0 1,370.6 -3,030.0291.26 419,003.235,974,127.28 70° 20' 21.660 N 150° 39' 26.109 W 5,200.0 78.89 2,929.3 1,406.2 -3,121.5291.26 418,912.165,974,163.80 70° 20' 22.010 N 150° 39' 28.781 W 5,300.0 78.89 2,948.5 1,441.7 -3,212.9291.26 418,821.105,974,200.32 70° 20' 22.359 N 150° 39' 31.453 W 5,400.0 78.89 2,967.8 1,477.3 -3,304.4291.26 418,730.035,974,236.85 70° 20' 22.709 N 150° 39' 34.124 W 5,500.0 78.89 2,987.1 1,512.9 -3,395.8291.26 418,638.975,974,273.37 70° 20' 23.058 N 150° 39' 36.796 W 5,600.0 78.89 3,006.3 1,548.5 -3,487.3291.26 418,547.905,974,309.89 70° 20' 23.408 N 150° 39' 39.467 W 5,700.0 78.89 3,025.6 1,584.1 -3,578.7291.26 418,456.845,974,346.42 70° 20' 23.757 N 150° 39' 42.139 W 5,800.0 78.89 3,044.9 1,619.6 -3,670.2291.26 418,365.775,974,382.94 70° 20' 24.107 N 150° 39' 44.811 W 5,900.0 78.89 3,064.2 1,655.2 -3,761.6291.26 418,274.715,974,419.47 70° 20' 24.456 N 150° 39' 47.483 W 6,000.0 78.89 3,083.4 1,690.8 -3,853.1291.26 418,183.645,974,455.99 70° 20' 24.806 N 150° 39' 50.154 W 6,100.0 78.89 3,102.7 1,726.4 -3,944.5291.26 418,092.585,974,492.51 70° 20' 25.155 N 150° 39' 52.826 W 6,200.0 78.89 3,122.0 1,761.9 -4,036.0291.26 418,001.515,974,529.04 70° 20' 25.505 N 150° 39' 55.498 W 6,297.8 78.89 3,140.8 1,796.7 -4,125.4291.26 417,912.495,974,564.74 70° 20' 25.846 N 150° 39' 58.110 W Seabee 6,300.0 78.89 3,141.2 1,797.5 -4,127.4291.26 417,910.455,974,565.56 70° 20' 25.854 N 150° 39' 58.170 W 6,400.0 78.89 3,160.5 1,833.1 -4,218.9291.26 417,819.385,974,602.08 70° 20' 26.203 N 150° 40' 0.842 W 6,500.0 78.89 3,179.8 1,868.7 -4,310.3291.26 417,728.325,974,638.61 70° 20' 26.553 N 150° 40' 3.514 W 6,600.0 78.89 3,199.0 1,904.3 -4,401.8291.26 417,637.255,974,675.13 70° 20' 26.902 N 150° 40' 6.185 W 6,700.0 78.89 3,218.3 1,939.8 -4,493.2291.26 417,546.195,974,711.65 70° 20' 27.252 N 150° 40' 8.857 W 6,800.0 78.89 3,237.6 1,975.4 -4,584.7291.26 417,455.125,974,748.18 70° 20' 27.601 N 150° 40' 11.529 W 6,900.0 78.89 3,256.9 2,011.0 -4,676.1291.26 417,364.065,974,784.70 70° 20' 27.950 N 150° 40' 14.201 W 7,000.0 78.89 3,276.1 2,046.6 -4,767.6291.26 417,272.995,974,821.23 70° 20' 28.300 N 150° 40' 16.873 W 7,100.0 78.89 3,295.4 2,082.2 -4,859.0291.26 417,181.925,974,857.75 70° 20' 28.649 N 150° 40' 19.545 W 7,200.0 78.89 3,314.7 2,117.7 -4,950.5291.26 417,090.865,974,894.27 70° 20' 28.998 N 150° 40' 22.217 W 7,300.0 78.89 3,333.9 2,153.3 -5,041.9291.26 416,999.795,974,930.80 70° 20' 29.348 N 150° 40' 24.889 W 7,400.0 78.89 3,353.2 2,188.9 -5,133.4291.26 416,908.735,974,967.32 70° 20' 29.697 N 150° 40' 27.562 W 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 5 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 7,500.0 78.89 3,372.5 2,224.5 -5,224.8291.26 416,817.665,975,003.84 70° 20' 30.046 N 150° 40' 30.234 W 7,600.0 78.89 3,391.7 2,260.0 -5,316.3291.26 416,726.605,975,040.37 70° 20' 30.395 N 150° 40' 32.906 W 7,700.0 78.89 3,411.0 2,295.6 -5,407.7291.26 416,635.535,975,076.89 70° 20' 30.745 N 150° 40' 35.578 W 7,800.0 78.89 3,430.3 2,331.2 -5,499.2291.26 416,544.475,975,113.41 70° 20' 31.094 N 150° 40' 38.250 W 7,900.0 78.89 3,449.6 2,366.8 -5,590.6291.26 416,453.405,975,149.94 70° 20' 31.443 N 150° 40' 40.922 W 8,000.0 78.89 3,468.8 2,402.4 -5,682.1291.26 416,362.345,975,186.46 70° 20' 31.792 N 150° 40' 43.595 W 8,100.0 78.89 3,488.1 2,437.9 -5,773.5291.26 416,271.275,975,222.99 70° 20' 32.142 N 150° 40' 46.267 W 8,200.0 78.89 3,507.4 2,473.5 -5,865.0291.26 416,180.215,975,259.51 70° 20' 32.491 N 150° 40' 48.939 W 8,300.0 78.89 3,526.6 2,509.1 -5,956.4291.26 416,089.145,975,296.03 70° 20' 32.840 N 150° 40' 51.612 W 8,400.0 78.89 3,545.9 2,544.7 -6,047.9291.26 415,998.085,975,332.56 70° 20' 33.189 N 150° 40' 54.284 W 8,500.0 78.89 3,565.2 2,580.2 -6,139.3291.26 415,907.015,975,369.08 70° 20' 33.538 N 150° 40' 56.956 W 8,600.0 78.89 3,584.5 2,615.8 -6,230.7291.26 415,815.955,975,405.60 70° 20' 33.887 N 150° 40' 59.629 W 8,700.0 78.89 3,603.7 2,651.4 -6,322.2291.26 415,724.885,975,442.13 70° 20' 34.237 N 150° 41' 2.301 W 8,800.0 78.89 3,623.0 2,687.0 -6,413.6291.26 415,633.825,975,478.65 70° 20' 34.586 N 150° 41' 4.974 W 8,900.0 78.89 3,642.3 2,722.6 -6,505.1291.26 415,542.755,975,515.18 70° 20' 34.935 N 150° 41' 7.646 W 9,000.0 78.89 3,661.5 2,758.1 -6,596.5291.26 415,451.685,975,551.70 70° 20' 35.284 N 150° 41' 10.319 W 9,100.0 78.89 3,680.8 2,793.7 -6,688.0291.26 415,360.625,975,588.22 70° 20' 35.633 N 150° 41' 12.991 W 9,200.0 78.89 3,700.1 2,829.3 -6,779.4291.26 415,269.555,975,624.75 70° 20' 35.982 N 150° 41' 15.664 W 9,300.0 78.89 3,719.3 2,864.9 -6,870.9291.26 415,178.495,975,661.27 70° 20' 36.331 N 150° 41' 18.336 W 9,400.0 78.89 3,738.6 2,900.4 -6,962.3291.26 415,087.425,975,697.79 70° 20' 36.680 N 150° 41' 21.009 W 9,500.0 78.89 3,757.9 2,936.0 -7,053.8291.26 414,996.365,975,734.32 70° 20' 37.029 N 150° 41' 23.682 W 9,518.6 78.89 3,761.5 2,942.7 -7,070.8291.26 414,979.395,975,741.12 70° 20' 37.095 N 150° 41' 24.180 W 9,518.8 78.89 3,761.5 2,942.7 -7,071.0291.26 414,979.215,975,741.20 70° 20' 37.095 N 150° 41' 24.185 W Start DLS 3.00 TFO 103.52 9,600.0 78.33 3,777.6 2,973.1 -7,144.5293.68 414,906.025,975,772.37 70° 20' 37.394 N 150° 41' 26.334 W 9,700.0 77.67 3,798.3 3,014.7 -7,233.0296.67 414,817.955,975,814.88 70° 20' 37.802 N 150° 41' 28.921 W 9,706.8 77.62 3,799.8 3,017.7 -7,238.9296.88 414,812.075,975,817.93 70° 20' 37.831 N 150° 41' 29.094 W Nanushuk 9,800.0 77.04 3,820.2 3,060.8 -7,319.0299.68 414,732.445,975,861.84 70° 20' 38.254 N 150° 41' 31.435 W 9,900.0 76.45 3,843.2 3,111.2 -7,402.3302.70 414,649.725,975,913.09 70° 20' 38.749 N 150° 41' 33.868 W 9,949.1 76.17 3,854.8 3,137.5 -7,442.1304.19 414,610.235,975,939.77 70° 20' 39.007 N 150° 41' 35.031 W NT8 MFS 10,000.0 75.89 3,867.1 3,165.8 -7,482.6305.74 414,570.025,975,968.52 70° 20' 39.285 N 150° 41' 36.216 W 10,100.0 75.37 3,891.9 3,224.4 -7,559.7308.79 414,493.555,976,027.95 70° 20' 39.861 N 150° 41' 38.469 W 10,150.6 75.12 3,904.8 3,255.6 -7,597.4310.33 414,456.195,976,059.47 70° 20' 40.167 N 150° 41' 39.571 W NT7 MFS 10,200.0 74.89 3,917.6 3,287.0 -7,633.3311.85 414,420.535,976,091.24 70° 20' 40.475 N 150° 41' 40.624 W 10,295.4 74.47 3,942.8 3,350.1 -7,700.3314.79 414,354.265,976,155.03 70° 20' 41.095 N 150° 41' 42.581 W NT6 MFS 10,300.0 74.45 3,944.0 3,353.2 -7,703.4314.93 414,351.155,976,158.20 70° 20' 41.126 N 150° 41' 42.673 W 10,400.0 74.06 3,971.2 3,423.0 -7,769.7318.02 414,285.615,976,228.65 70° 20' 41.812 N 150° 41' 44.612 W 10,434.9 73.93 3,980.8 3,448.1 -7,791.9319.10 414,263.675,976,254.03 70° 20' 42.059 N 150° 41' 45.262 W NT5 MFS 10,500.0 73.71 3,998.9 3,496.1 -7,832.0321.12 414,224.085,976,302.40 70° 20' 42.530 N 150° 41' 46.434 W 10,600.0 73.40 4,027.3 3,572.4 -7,890.1324.23 414,166.745,976,379.25 70° 20' 43.280 N 150° 41' 48.135 W 10,608.9 73.38 4,029.8 3,579.3 -7,895.1324.51 414,161.855,976,386.23 70° 20' 43.348 N 150° 41' 48.281 W NT4 MFS 10,700.0 73.14 4,056.0 3,651.5 -7,944.0327.35 414,113.745,976,458.99 70° 20' 44.058 N 150° 41' 49.711 W 10,765.1 73.00 4,075.0 3,704.6 -7,976.6329.39 414,081.635,976,512.35 70° 20' 44.579 N 150° 41' 50.667 W 10,765.4 73.00 4,075.1 3,704.8 -7,976.8329.39 414,081.505,976,512.57 70° 20' 44.581 N 150° 41' 50.671 W Start 100.0 hold at 10765.4 MD 10,800.0 73.00 4,085.2 3,733.3 -7,993.6329.39 414,064.945,976,541.24 70° 20' 44.861 N 150° 41' 51.164 W 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 6 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 10,829.4 73.00 4,093.8 3,757.5 -8,007.9329.39 414,050.885,976,565.58 70° 20' 45.099 N 150° 41' 51.583 W NT3 MFS 10,864.0 73.00 4,103.9 3,786.0 -8,024.8329.39 414,034.335,976,594.23 70° 20' 45.379 N 150° 41' 52.076 W 9-5/8" Intermediate Liner 10,865.1 73.00 4,104.2 3,786.9 -8,025.3329.39 414,033.805,976,595.15 70° 20' 45.388 N 150° 41' 52.092 W 10,865.4 73.01 4,104.3 3,787.1 -8,025.5329.39 414,033.675,976,595.37 70° 20' 45.390 N 150° 41' 52.096 W Start Turn 0.00 10,900.0 74.40 4,114.0 3,815.7 -8,042.4329.39 414,017.055,976,624.14 70° 20' 45.671 N 150° 41' 52.591 W 10,922.0 75.28 4,119.8 3,834.0 -8,053.2329.39 414,006.415,976,642.56 70° 20' 45.851 N 150° 41' 52.908 W NT3.2 Top Reservoir 11,000.0 78.40 4,137.6 3,899.3 -8,091.9329.39 413,968.445,976,708.28 70° 20' 46.493 N 150° 41' 54.040 W 11,100.0 82.40 4,154.2 3,984.2 -8,142.1329.39 413,919.145,976,793.63 70° 20' 47.327 N 150° 41' 55.509 W 11,200.0 86.40 4,164.0 4,069.8 -8,192.7329.39 413,869.375,976,879.78 70° 20' 48.169 N 150° 41' 56.992 W 11,290.1 90.00 4,166.8 4,147.3 -8,238.6329.39 413,824.335,976,957.74 70° 20' 48.930 N 150° 41' 58.334 W 11,290.4 90.01 4,166.8 4,147.5 -8,238.7329.39 413,824.195,976,957.97 70° 20' 48.933 N 150° 41' 58.339 W Start DLS 3.00 TFO 0.00 11,297.5 90.22 4,166.8 4,153.6 -8,242.3329.39 413,820.645,976,964.12 70° 20' 48.993 N 150° 41' 58.444 W 11,297.7 90.22 4,166.8 4,153.9 -8,242.5329.39 413,820.515,976,964.35 70° 20' 48.995 N 150° 41' 58.448 W Start 6478.9 hold at 11297.7 MD 11,300.0 90.22 4,166.8 4,155.8 -8,243.6329.39 413,819.385,976,966.31 70° 20' 49.014 N 150° 41' 58.482 W 11,400.0 90.22 4,166.4 4,241.9 -8,294.5329.39 413,769.375,977,052.89 70° 20' 49.860 N 150° 41' 59.972 W 11,500.0 90.22 4,166.0 4,328.0 -8,345.4329.39 413,719.365,977,139.48 70° 20' 50.706 N 150° 42' 1.463 W 11,600.0 90.22 4,165.6 4,414.0 -8,396.4329.39 413,669.355,977,226.06 70° 20' 51.552 N 150° 42' 2.953 W 11,700.0 90.22 4,165.3 4,500.1 -8,447.3329.39 413,619.345,977,312.65 70° 20' 52.398 N 150° 42' 4.444 W 11,800.0 90.22 4,164.9 4,586.2 -8,498.2329.39 413,569.325,977,399.23 70° 20' 53.244 N 150° 42' 5.935 W 11,900.0 90.22 4,164.5 4,672.2 -8,549.1329.39 413,519.315,977,485.82 70° 20' 54.090 N 150° 42' 7.425 W 12,000.0 90.22 4,164.1 4,758.3 -8,600.0329.39 413,469.305,977,572.40 70° 20' 54.935 N 150° 42' 8.916 W 12,100.0 90.22 4,163.7 4,844.4 -8,650.9329.39 413,419.295,977,658.99 70° 20' 55.781 N 150° 42' 10.407 W 12,200.0 90.22 4,163.3 4,930.4 -8,701.8329.39 413,369.285,977,745.57 70° 20' 56.627 N 150° 42' 11.897 W 12,300.0 90.22 4,162.9 5,016.5 -8,752.8329.39 413,319.275,977,832.16 70° 20' 57.473 N 150° 42' 13.388 W 12,400.0 90.22 4,162.6 5,102.6 -8,803.7329.39 413,269.265,977,918.74 70° 20' 58.319 N 150° 42' 14.879 W 12,500.0 90.22 4,162.2 5,188.6 -8,854.6329.39 413,219.255,978,005.33 70° 20' 59.165 N 150° 42' 16.370 W 12,600.0 90.22 4,161.8 5,274.7 -8,905.5329.39 413,169.245,978,091.91 70° 21' 0.011 N 150° 42' 17.861 W 12,700.0 90.22 4,161.4 5,360.8 -8,956.4329.39 413,119.235,978,178.50 70° 21' 0.857 N 150° 42' 19.351 W 12,800.0 90.22 4,161.0 5,446.8 -9,007.3329.39 413,069.225,978,265.08 70° 21' 1.702 N 150° 42' 20.842 W 12,900.0 90.22 4,160.6 5,532.9 -9,058.2329.39 413,019.215,978,351.67 70° 21' 2.548 N 150° 42' 22.333 W 13,000.0 90.22 4,160.2 5,619.0 -9,109.1329.39 412,969.205,978,438.25 70° 21' 3.394 N 150° 42' 23.824 W 13,100.0 90.22 4,159.9 5,705.1 -9,160.1329.39 412,919.195,978,524.83 70° 21' 4.240 N 150° 42' 25.315 W 13,200.0 90.22 4,159.5 5,791.1 -9,211.0329.39 412,869.175,978,611.42 70° 21' 5.086 N 150° 42' 26.806 W 13,300.0 90.22 4,159.1 5,877.2 -9,261.9329.39 412,819.165,978,698.00 70° 21' 5.932 N 150° 42' 28.298 W 13,400.0 90.22 4,158.7 5,963.3 -9,312.8329.39 412,769.155,978,784.59 70° 21' 6.778 N 150° 42' 29.789 W 13,500.0 90.22 4,158.3 6,049.3 -9,363.7329.39 412,719.145,978,871.17 70° 21' 7.623 N 150° 42' 31.280 W 13,600.0 90.22 4,157.9 6,135.4 -9,414.6329.39 412,669.135,978,957.76 70° 21' 8.469 N 150° 42' 32.771 W 13,700.0 90.22 4,157.6 6,221.5 -9,465.5329.39 412,619.125,979,044.34 70° 21' 9.315 N 150° 42' 34.262 W 13,800.0 90.22 4,157.2 6,307.5 -9,516.5329.39 412,569.115,979,130.93 70° 21' 10.161 N 150° 42' 35.754 W 13,900.0 90.22 4,156.8 6,393.6 -9,567.4329.39 412,519.105,979,217.51 70° 21' 11.007 N 150° 42' 37.245 W 14,000.0 90.22 4,156.4 6,479.7 -9,618.3329.39 412,469.095,979,304.10 70° 21' 11.853 N 150° 42' 38.736 W 14,100.0 90.22 4,156.0 6,565.7 -9,669.2329.39 412,419.085,979,390.68 70° 21' 12.698 N 150° 42' 40.228 W 14,200.0 90.22 4,155.6 6,651.8 -9,720.1329.39 412,369.075,979,477.27 70° 21' 13.544 N 150° 42' 41.719 W 14,300.0 90.22 4,155.2 6,737.9 -9,771.0329.39 412,319.065,979,563.85 70° 21' 14.390 N 150° 42' 43.210 W 14,400.0 90.22 4,154.9 6,823.9 -9,821.9329.39 412,269.055,979,650.44 70° 21' 15.236 N 150° 42' 44.702 W 14,500.0 90.22 4,154.5 6,910.0 -9,872.8329.39 412,219.045,979,737.02 70° 21' 16.082 N 150° 42' 46.193 W 14,600.0 90.22 4,154.1 6,996.1 -9,923.8329.39 412,169.025,979,823.61 70° 21' 16.928 N 150° 42' 47.685 W 14,700.0 90.22 4,153.7 7,082.1 -9,974.7329.39 412,119.015,979,910.19 70° 21' 17.773 N 150° 42' 49.177 W 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 7 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 14,800.0 90.22 4,153.3 7,168.2 -10,025.6329.39 412,069.005,979,996.78 70° 21' 18.619 N 150° 42' 50.668 W 14,900.0 90.22 4,152.9 7,254.3 -10,076.5329.39 412,018.995,980,083.36 70° 21' 19.465 N 150° 42' 52.160 W 15,000.0 90.22 4,152.5 7,340.3 -10,127.4329.39 411,968.985,980,169.94 70° 21' 20.311 N 150° 42' 53.652 W 15,100.0 90.22 4,152.2 7,426.4 -10,178.3329.39 411,918.975,980,256.53 70° 21' 21.156 N 150° 42' 55.143 W 15,200.0 90.22 4,151.8 7,512.5 -10,229.2329.39 411,868.965,980,343.11 70° 21' 22.002 N 150° 42' 56.635 W 15,300.0 90.22 4,151.4 7,598.5 -10,280.1329.39 411,818.955,980,429.70 70° 21' 22.848 N 150° 42' 58.127 W 15,400.0 90.22 4,151.0 7,684.6 -10,331.1329.39 411,768.945,980,516.28 70° 21' 23.694 N 150° 42' 59.619 W 15,500.0 90.22 4,150.6 7,770.7 -10,382.0329.39 411,718.935,980,602.87 70° 21' 24.540 N 150° 43' 1.110 W 15,600.0 90.22 4,150.2 7,856.8 -10,432.9329.39 411,668.925,980,689.45 70° 21' 25.385 N 150° 43' 2.602 W 15,700.0 90.22 4,149.8 7,942.8 -10,483.8329.39 411,618.915,980,776.04 70° 21' 26.231 N 150° 43' 4.094 W 15,800.0 90.22 4,149.5 8,028.9 -10,534.7329.39 411,568.905,980,862.62 70° 21' 27.077 N 150° 43' 5.586 W 15,900.0 90.22 4,149.1 8,115.0 -10,585.6329.39 411,518.895,980,949.21 70° 21' 27.923 N 150° 43' 7.078 W 16,000.0 90.22 4,148.7 8,201.0 -10,636.5329.39 411,468.875,981,035.79 70° 21' 28.768 N 150° 43' 8.570 W 16,100.0 90.22 4,148.3 8,287.1 -10,687.5329.39 411,418.865,981,122.38 70° 21' 29.614 N 150° 43' 10.062 W 16,200.0 90.22 4,147.9 8,373.2 -10,738.4329.39 411,368.855,981,208.96 70° 21' 30.460 N 150° 43' 11.554 W 16,300.0 90.22 4,147.5 8,459.2 -10,789.3329.39 411,318.845,981,295.55 70° 21' 31.306 N 150° 43' 13.047 W 16,400.0 90.22 4,147.1 8,545.3 -10,840.2329.39 411,268.835,981,382.13 70° 21' 32.151 N 150° 43' 14.539 W 16,500.0 90.22 4,146.8 8,631.4 -10,891.1329.39 411,218.825,981,468.72 70° 21' 32.997 N 150° 43' 16.031 W 16,600.0 90.22 4,146.4 8,717.4 -10,942.0329.39 411,168.815,981,555.30 70° 21' 33.843 N 150° 43' 17.523 W 16,700.0 90.22 4,146.0 8,803.5 -10,992.9329.39 411,118.805,981,641.89 70° 21' 34.689 N 150° 43' 19.015 W 16,800.0 90.22 4,145.6 8,889.6 -11,043.8329.39 411,068.795,981,728.47 70° 21' 35.534 N 150° 43' 20.508 W 16,900.0 90.22 4,145.2 8,975.6 -11,094.8329.39 411,018.785,981,815.05 70° 21' 36.380 N 150° 43' 22.000 W 17,000.0 90.22 4,144.8 9,061.7 -11,145.7329.39 410,968.775,981,901.64 70° 21' 37.226 N 150° 43' 23.492 W 17,100.0 90.22 4,144.4 9,147.8 -11,196.6329.39 410,918.765,981,988.22 70° 21' 38.072 N 150° 43' 24.985 W 17,200.0 90.22 4,144.1 9,233.8 -11,247.5329.39 410,868.755,982,074.81 70° 21' 38.917 N 150° 43' 26.477 W 17,300.0 90.22 4,143.7 9,319.9 -11,298.4329.39 410,818.735,982,161.39 70° 21' 39.763 N 150° 43' 27.970 W 17,400.0 90.22 4,143.3 9,406.0 -11,349.3329.39 410,768.725,982,247.98 70° 21' 40.609 N 150° 43' 29.462 W 17,500.0 90.22 4,142.9 9,492.0 -11,400.2329.39 410,718.715,982,334.56 70° 21' 41.454 N 150° 43' 30.955 W 17,600.0 90.22 4,142.5 9,578.1 -11,451.1329.39 410,668.705,982,421.15 70° 21' 42.300 N 150° 43' 32.447 W 17,700.0 90.22 4,142.1 9,664.2 -11,502.1329.39 410,618.695,982,507.73 70° 21' 43.146 N 150° 43' 33.940 W 17,776.4 90.22 4,141.8 9,729.9 -11,541.0329.39 410,580.495,982,573.88 70° 21' 43.792 N 150° 43' 35.080 W TD at 17776.6 Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Design Targets LongitudeLatitude Dip Angle (°) Dip Dir. (°) NDB-037 Toe Rev2.0 4,141.8 5,982,573.88 410,580.499,729.9 -11,541.00.00 0.00 70° 21' 43.792 N 150° 43' 35.080 W - plan hits target center - Point NDB-037 Heel Rev 2.4,166.8 5,976,957.74 413,824.334,147.3 -8,238.60.00 0.00 70° 20' 48.930 N 150° 41' 58.334 W - plan hits target center - Polygon -131.2Point 1 5,976,822.73 414,191.314,166.8 368.4 True 5,968.0Point 2 5,982,958.56 410,646.064,166.8 -3,240.8 True 5,713.5Point 3 5,982,708.57 410,213.074,166.8 -3,671.2 True -385.7Point 4 5,976,572.74 413,758.334,166.8 -62.0 True 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 8 Santos Ltd Planning Report - Geographic Well NDB-037Local Co-ordinate Reference:Database:EDM Parker 272 As Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 As Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-037Well: NDB-037Wellbore: Plan: NDB-037 Rev C.1Design: Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing128.0128.0 20 20 13-3/8" Surface Casing2,397.72,808.0 13-3/8 16 9-5/8" Intermediate Liner4,103.910,864.0 9-5/8 12-1/4 4-1/2" Production Liner17,776.6 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,052.9 Upper Schrader Bluff1,044.8 1,145.9 Base Ice Bearing Permafrost 0.001,134.8 1,418.7 Base Permafrost Transition 0.001,393.8 1,810.1 Middle Schrader Bluff 0.001,739.8 2,356.6 MCU 0.002,147.8 2,884.0 Tuluvak Shale 0.002,430.8 3,041.7 Tuluvak Sand2,490.8 4,538.6 TS_790 0.002,801.8 6,297.8 Seabee 0.003,140.8 9,706.8 Nanushuk 0.003,799.8 9,949.1 NT8 MFS 0.003,854.8 10,150.6 NT7 MFS 0.003,904.8 10,295.4 NT6 MFS 0.003,942.8 10,434.9 NT5 MFS 0.003,980.8 10,608.9 NT4 MFS 0.004,029.8 10,829.4 NT3 MFS 0.004,093.8 10,922.0 NT3.2 Top Reservoir 0.004,119.8 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 347.0 347.0 0.0 0.0 Start Build 2.00 647.0 646.5 13.6 -7.8 Start DLS 2.50 TFO -24.94 1,000.6 994.1 61.0 -48.5 Start 150.0 hold at 1000.6 MD 1,150.6 1,139.3 87.5 -75.0 Start DLS 3.00 TFO -25.69 3,340.7 2,571.0 744.7 -1,421.2 Start 6178.1 hold at 3340.7 MD 9,518.8 3,761.5 2,942.7 -7,071.0 Start DLS 3.00 TFO 103.52 10,765.4 4,075.1 3,704.8 -7,976.8 Start 100.0 hold at 10765.4 MD 10,865.4 4,104.3 3,787.1 -8,025.5 Start Turn 0.00 11,290.4 4,166.8 4,147.5 -8,238.7 Start DLS 3.00 TFO 0.00 11,297.7 4,166.8 4,153.9 -8,242.5 Start 6478.9 hold at 11297.7 MD 17,776.4 4,141.8 9,729.9 -11,541.0 TD at 17776.6 10/09/2024 16:34:35 COMPASS 5000.17 Build Page 9 Attachment 3: BOPE Equipment 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#FORWARD 13-5/8" X 5,000#13-5/8" X 5,000#30"13-5/8" X 5,000#186"13-5/8" X 5,000#DUTCH LOCK DOWN ChokeLinefromBOPPressureGauge1502PressureSensorPressureTransducerBill ofMaterialItemDescriptionToPanicLineItemDescriptionA3Ͳ1/8”– 5,000psi W.P.RemoteHydraulicOperatedChokeB3Ͳ1/8”–5,000psiW.P.AdjustableManualChoke1–14 3Ͳ1/8”– 5,000psi W.P.ManualGateValve1521/16”5 000 i WP152Ͳ1/16”–5,000psiW.P.ManualGateValveToMudGasLegendBlindSpareToTigerTankSeparatorValveNormally OpenValveNormally Closed Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (trained drilling personnel). 12-1/4” Intermediate Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Wellbore Instability / Washouts / Hole Enlargement Drill with oil-based mud, maintain mud in specifications, use sufficient mud weight to hold back formations. Managed Pressure Drilling may be utilized if equipment is operational to minimize pressure cycles on formation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Hole Cleaning in 79q Sail Conduct hydraulics modeling and control ROP limits based on cuttings returns and observed ECD’s compared to model. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Operational complexity with Mechanical two stage cement equipment The 2nd stage of the cement job will be conducted through a mechanically shifted sleeve. This will require the LTP to not be set until the 2nd stage is pumped giving a higher complexity leading to complications with setting the LTP. 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. Managed Pressure Drilling may be utilized if equipment is operational to minimize pressure cycles on formation. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 TXP-BTC Surface Casing Basis Lead Open hole volume + 200% excess in permafrost / 50% excess below permafrost Lead TOC Surface Tail Open hole volume + 50% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Tuned Spacer Lead 11.0ppg Lead: 405 bbls, 2276 cuft, 898 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 69 bbls, 387 cuft, 312 sks HalCem Type I/II – 1.24 cuft/sk Temp BHST 53° F Verification Method Cement returns to surface Notes Job will be mixed on the fly NDB-037 13-3/8" SURFACE CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 2723 2808 85 0.14973 12.7 TAIL LENGTH 2308 2808 500 0.07491 37.5 TAIL EXCESS 50% 18.7 LEAD TOP TO BASE OF PERMA 1419 2308 889 0.07491 66.6 EXCESS FACTOR FOR ABOVE 50% 33.3 PERMAFROST ANNULUS(Lead) 128 1419 1291 0.07491 96.7 EXCESS FACTOR FOR ABOVE 200% 193.4 CASED HOLE ANNULUS 46 128 82 0.18620 15.3 Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + excess Lead TOC Stage 1: 250’ TVD above top Nanushuk Stage 2: N/A Tail Open hole volume + excess + 85 ft shoe track Tail TOC Stage 1: 1000 ft above casing shoe Stage 2: Top of the 9-5/8” Liner Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead Stage 1: 30% Open Hole Excess 13.0ppg Lead: 106 bbls, 596cuft, 324sks ExtendaCem – 1.84 cuft/sk Stage 2: N/A Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 79 bbls, 442cuft, 357sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 100% Open Hole Excess Verified cement calcs. -bjm 15.3ppg Tail: 208 bbls, 1166cuft, 940sks VersaCem Type I/II – 1.24 cuft/sk Temp BHST 94° F Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1 st Stage Cement Job Only. -2ndStage Cement Job will not be logged, assuming job parameters are as expected (No losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) -2ndStage bond evaluation does not affect 1st Stage bond evaluation and frac decision. - Logging of 1 st Stage cement will demonstrate isolation of injection fluids in the Nanushuk reservoir, as well as isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -2ndStage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. NDB-037 9.625" Production Liner - 1st Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 10779 10864 85 0.07321 6.2 TAIL LENGTH 9864 10864 1000 0.05578 55.8 TAIL EXCESS 30% 16.7 LEAD LENGTH 8400 9864 1464 0.05578 81.7 LEAD EXCESS 30% 24.5 NDB-037 9.625" Production Liner - 2nd Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME TAIL LENGTH 2808 4589 1781 0.05578 99.3 TAIL EXCESS 100% 99.3 Liner Lap 13-3/8" 68# x 9-5/8" 47# LNR 2658 2808 150 0.05974 9.0 Attachment 7: Prognosed Formation Tops NDB-037 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1053 1045 -975 100 7.2 Permafrost Base Transition 1419 1394 -1324 100 7.3 Middle Schrader Bluff 1810 1740 -1670 100 7.6 MCU (Lower Schrader Bluff) 2357 2148 -2078 100 7.8 Tuluvak Shale 2884 2431 -2361 100 7.9 Tuluvak Sand 3042 2491 -2421 100 10.2 TS 790 4539 2802 -2731 100 9.4 Seabee 6298 3141 -3071 100 9.2 Nanushuk 9707 3800 -3730 100 8.9 NT7 MFS 10151 3905 -3835 100 8.9 NT6 MFS 10296 3943 -3873 100 8.9 NT5 MFS 10435 3981 -3911 100 8.8 NT4 MFS 10609 4030 -3960 100 8.8 NT3 MFS 10830 4094 -4024 100 8.8 Nanushuk 3.2 (NT3) 10922 4120 -4050 100 8.8 Attachment 8: Well Schematic Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole LWD Gamma Ray Resistivity 8-1/2” Production Hole LWD Gamma Ray Resistivity Sonic (9-5/8” Liner Cement Evaluation Only) Density Neutron Mudlogging No mudlogging is planned for NDB-037 Attachment 10: Wellhead & Tree Diagram Attachment 11: Managed Pressure Drilling Managed Pressure Drilling (MPD) may be implemented on NDB-037, depending on timing and if the system is operational during well drilling operations. The MPD system will be provided from Beyond Energy Services and Technology, and system will have an integrated piping and choke manifold on the Parker 272 rig. The only MPD equipment located outside of the rig will be the nitrogen rack. In terms of MPD operations, if the system is commissioned and operational during rig operations on NDB- 037, then the base plan would be to trial the MPD system at that time. As per the current timing, it is likely the system would only be operational during the Production section of that well, but if installation timing accelerates, it could be used on the Intermediate section as well. The primary goal is to get the crews familiar with MPD equipment and operations. For this well, the base plan would be to use our conventional mud weights, and only utilize MPD to trap back-pressure on connections, minimizing pressure swings on the formation. By using conventional mud weights, this would allow for all tripping and liner running operations to be done without MPD or performing any fluid swaps, if desired. The mud weights may be reduced slightly (within the limits specified in the Drilling Fluids Section) if MPD is operational to better evaluate wellbore stability impacts at different mud weights. See below for a schematic of the BOP/MPD stack with the choke flow diagram. 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 nogreater 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. Pikka NDB-037 224-124 PIKKA NANUSHUK OIL WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-037Initial Class/TypeDEV / PENDGeoArea890Unit11580On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241240PIKKA, NANUSHUK OIL - 600100NA1 Permit fee attachedYes ADL392984, ADL391445, ADL393020, ADL393019, and ADL3930182 Lease number appropriateYes3 Unique well name and numberYes PIKKA, NANUSHUK OIL - 600100 - governed by CO 8074 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 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 proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1465 psi, BOP rated to 5k psi (BOP test to 3600 psi)30 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)Yes H2S is not anticipated35 Permit can be issued w/o hydrogen sulfide measuresYes Tuluvak (with shallow gas) pressures anticipated to be 10.2 ppg EMW. Nanushuk reservoir at 8.8 ppg EMW36 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]ApprADDDate9/19/2024ApprBJMDate9/25/2024ApprADDDate9/19/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&: JLC 9/26/2024
