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Home My WebLink About223-076 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-024 NDB-024 50103208620000 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 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-024 50103208620000 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-024 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 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: CT CO & Flowback 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-024 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): 18,029'N/A Casing Collapse Structural Conductor 2260 psi Surface 4750 psi Intermediate 4750 psi Production 9210 psi Liner 9210 psi 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:Jose Gonzalez Jose Gonzalez Contact Email:jose.gonzalez@contractor.santos.com Contact Phone: 346-413-9028 Authorized Title: Sr. Completions Engineer Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 04/01/25 18020'6691' 4-1/2" 12.6ppf 4160' see attached packer report Perforation Depth MD (ft): 2456' 11329' 4-1/2" 128' 20" 13-3/8" 9-5/8" 2675' Tie Back2456' 11463' 4115' 2070' 2675' 11463' 4079'4-1/2" 11329' Proposed Pools: 128' 128' P-110S TVD Burst 11329' 11590 psi MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 393020, 391445, 393018, 391445 223-076 601 W 5th Avenue, Anchorage AK 99501 50-103-20862-00-00 Oil Search Alaska, LLC AOGCC USE ONLY 11590 psi Tubing Grade: Tubing MD (ft): see attached packer report Perforation Depth TVD (ft): Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 4,160' 18,022' 4,160' N/A Subsequent Form Required: Suspension Expiration Date: 6870 psi 5020 psi 6870 psi 2153' 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 and the procedure approved h Feb 4th, 2025 By Gavin Gluyas at 11:39 am, Feb 04, 2025 325-057 CT BOP test to 3000 psi (?) BJM 2/12/25 (?) 1501 psi per J Gonzalez -bjm. SFD 2/18/2025 391455 SFD 10-404 (?) X SFD DSR-2/18/25*&: 2/18/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.18 15:26:50 -09'00' RBDMS JSB 022525 Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Avenue Anchorage, Alaska 99501 PO Box 240927 Anchorage, Alaska 99524 (T) +1 907 375 4642 —santos.com 1/1 February 4th, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval –NDB-024 Coiled Tubing Clean Out and Flow Back Dear Sir/Madam, Please find attached Form 10-403 Application for Sundry Approval to perform a coiled tubing clean out, followed by a short flow back on the mentioned well. This well was originally fractured in December 2023 and flowed back in January 2024. However, post flow back chemical tracer analysis, suggested that stages one to four (out of a total of 12) were not contributing to flow. A proppant bridge was suspected to be impairing flow above those stages. However, during early 2024, a coiled tubing unit with the appropriate OD to reach the target depth was not available, and the well was left shut in. Currently, such a unit is available and there is opportunity for this operation in our project schedule. Therefore, the intended objective of this intervention is clean the wellbore to stage one, or as deep as possible, to remove any existing obstructions. Then, flow the well back to induce contribution from all the 12 stimulated stages. The flow may be started by pumping N2 down the coiled tubing. The total fluid volume to be flowed back, including January 2024 operations, will not exceed the maximum allowed which is two times the volume injected during the frac stimulation. Procedures for both operations are attached, including a current wellbore schematic. Yours sincerely, Jose Gonzalez Sr. Completion Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited Page 1 of 1 Well Name: NDB-024 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,316.4 4,076.3 OH Packer #14 11,615.3 4,151.4 OH Packer #13 11,679.3 4,164.1 OH Packer #12 12,415.8 4,203.2 OH Packer #11 12,988.5 4,203.9 OH Packer #10 13,602.3 4,204.5 OH Packer #9 14,052.1 4,204.6 OH Packer #8 14,502.9 4,200.9 OH Packer #7 15,076.2 4,191.7 OH Packer #6 15,565.3 4,183.9 OH Packer #5 16,013.7 4,176.9 OH Packer #4 16,501.8 4,171.8 OH Packer #3 16,994.8 4,167.2 OH Packer #2 17,523.4 4,163.5 OH Packer #1 17,891.5 4,160.8 Santos Ltd CT Cleanout - 14 January 2025 Page 1 Coiled Tubing Clean Out Program - NDB-024 Version 1: 01/13/2025 NDB-024 AOGCC PTD # 223-076 API# 50-103-20862-00-00 NDB-024 Cost Coding Network 600074880 Activity 0008 Prepared by:Jose Gonzalez Sr. Completions Engineer Date Approved By:Ty Senden Sr. Engineering Manager, Completions Date Santos Ltd CT Cleanout - 14 January 2025 Page 2 1. Overview: x The well was hydraulically fractured in Dec. 2023 and flowed back in Jan. 2024. Chemical tracer results during initial flow back suggest stages 1 to 4 were not contributing to flow. Therefore, the objective of this operation is to perform a CT clean out to below stage 1, followed by a short flow back to remove any residual solids or frac fluid. 2. Well Status x During April 2024, a slick line conveyed micro-seismic string was pumped down to ~10,700 ft to monitor the fracturing job performed on NDB-032. After the frac was monitored, the MS string was recovered without issues. x Prior to the MS monitoring, a CT CO was performed to ~ 12,065 ft as the first attempt to run the MS string was not successful due to a proppant obstruction before the target depth. Therefore, potential proppant accumulation could still exist below that depth. x The well has been shut in and freeze protected since April 2024without any other downhole interventions x 5k production tree is installed and will require the 5K flow-cross installed above the Swab valve 3. Well Information Basic Well Data Well Type:PRODUCTION PBTD:4160' TVD / 18011' MD Reservoir Name:Nanushuk 3 Current Reservoir Pressure:1840 psi (Jan 2025) Reservoir Temperature: 98° F Crude Oil API Gravity:28° to 30° Gas Gravity ~0.7 H2S Content:7 - 8 ppm (seen on samples at end of flowback) CO2 Content:0 - 0.6% Max. Fluid Rate During Flowback:~4900 BLPD Max. Oil Rate During Flowback:~4600 BOPD Max. Gas Rate During Flowback:~1.3 MMscf/day Santos Ltd CT Cleanout - 14 January 2025 Page 3 Wellbore Schematic: Santos Ltd CT Cleanout - 14 January 2025 Page 4 4. Cleanout Preparation The cleanout work will include two runs that will be performed consecutively. 1. 1 st run will be with an agitated wash nozzle BHA. Target depth is ~17,700 ft (below stage #1). 2. 2nd run will be to N2 lift well just before start of flowback. 1. General: 1. Notify LRS of hardline needs prior to mobilization, approximate lengths to well from CTU and distance to choke and return tanks 2. Install additional swab valve and 5k flow cross above swab valve. (Additional swab is required to leave well flowing after N2 lift while rigging down coil). 3. Call out LRS Transport of 60/40 MEOH, triplex, and neat methanol pup trailer when temperatures are below freezing. 4. Call out three 1,000 bbl Hydrera tanks. Load Hydrera tanks at 90% volume with 120°F seawater or 2% KCL w/ friction reducers. 5. Have vac trucks load 120°F Seawater or 2% KCL from seawater injection plant (SIP) or Hot Water Plant in Prudhoe Bay and Shear in 0.03% by volume (3.8 gallons per 300 bbls) of MI DR204 friction reducer. Send loaded Vac truck to MI Mud Plant and load 1.3% by volume (163.8 gallons per 300 bbls) of Safelube metal to metal friction reducer with defoamer & biocide. Vac truck will need to roll agitators to mix into solution. 6. Rig in and berm 3 x 500 bbl open tops and 1 gas buster Magtec coil return tanks w/ a contingency of recirculating from the back of the 500 bbl open top tanks. 7. Spot in MagTec Arctic Cuttings Box (ACB) by return tanks so carbo-lite can be transferred from return tank to ACB during coil cleanout. 8. Worley will need to supply three transports, one for diesel, one for 60/40 methanol and one for PowerVis gel. Load the diesel transport with 290 bbls of Arctic Grade diesel for freeze protection, one vac truck with 300 bbl of 60/40 methanol, and a vac truck with200 bbls of PowerVis gel (Mix PowerVis at 2.0 ppb in 120°F 3% KCl water from MI mud plant). 9. Have ~ 600 gal. of neat methanol available for pumping down coil BOP’s during cleanout. 10. Have an air compressor, bleed tank and field triplex available. 11. Have manlift available that is large enough to reach coil injector if needed. 12. Request vac trucks to be on standby from Worley to take fluid returns during coil cleanout operations. 13. Inform Worley for the upcoming need for a super sucker/Cusco to clean out return tanks and transfer into ACB or haul to DS-4. Santos Ltd CT Cleanout - 14 January 2025 Page 5 2. Tank Farm: 1. Return tanks will be managed and strapped by Magtec crew every 15-minutes with verbal confirmation from ops cab of tank volumes 2. Supply tanks will be strapped by LRS and verified by Magtec/Worley before filling, all tanks must be low enough in volume to accept the entire vac truck load with 20% contingency volume figured in. If filling from recirculation system, constant monitoring is required while filling U/R supply tanks to prevent over filling. 3. Transports of 60/40, Diesel, Gel and neat MEOH will all be managed by LRS 3. Crane: 1. Notify Worley of scope of work at least 48 hours in advance and allow time for a lift plan to be written. A walk through of the rig up may be required showing crane placement in relation to injector and lubricator sections and the wellhead. 2. Worley shall provide a written lift plan for each coil job and specific for the orientation of the rig up. This shall be reviewed in the PJSM for both shifts and at any personnel change. 4. Expro: 1.Expro will need to be tied into the wellhead prior to the N2 lift. The lifting plan shall be discussed and a PJSM held with the coil crew and Expro prior to starting to cover all SIMOPS of the operation.NOTE: This is only applicable to the N2 lift run. 5. N2: 1. N2 lift will be performed down CT for three – four hours, with 400 – 500 scf/min. One transport of N2 and one cryogenic pump will be required.After coil is at surface one pump may be released.NOTE: Consult with completions group in Anchorage before releasing equipment or personnel. Santos Ltd CT Cleanout - 14 January 2025 Page 6 5. Coil Tubing Operations Operational Steps Run #1 – Agitated wash Nozzle 1. Bullhead 165 bbls of SW with Safelube at 2 bpm to preload tubing with FR. 2. Perform BOP test as per relevant CT standards 3. Pull test connector to 35,000# for 5 mins 4. Pressure test coil string to 4500 psi 5. Bleed pressure of coil, verify 0 psi in electronics before opening needle valve on test plate. 6. Make up agitated wash nozzle assembly to 2-3/8” string (Attachment A) 7. Shell test to 2500 psi, check swivel, strippers and slobber hose for leaks or drainage 8. Open well and start RIH with Slick Seawater while pumping at 0.25 bpm while RIH maintaining 1:1 9. Perform weight checks every 3000’ 10. At ~11,700’ or 80° inclination, increase pump rate to max rate circ pressure will allow at 4000 psi. 11. Monitor returns for carbo-lite 12. If high concentration of solids encountered, take ~100’ bites, PUH ~300’ and repeat until ~500’ of hole gained before performing short trip to top of build section at ~2000’. 13.Continue RIH with coil cleaning out to below frac stage #1 @ ~17,700’. NOTE: Coil lockup model in Attachment C. 14. Once at target depth, send 20 bbl gel pill and chase gel OOH by chart below for AV speeds. 15. Once at surface, shut well in and prepare for next run. Note: DNE 4000 psi circulation pressure on coil string while moving pipe without bypassing micromotion Pump Rate Tubing Size AV’s for 2-3/8” coil Max POOH speed 1 4.5” 103 fpm 50 fpm 2.0 4.5” 206 fpm 100 fpm 2.5 4.5” 258 fpm 130 fpm 3.0 4.5”309 fpm 150 fpm Santos Ltd CT Cleanout - 14 January 2025 Page 7 Operational Steps Run #2 – N2 lift 1. Perform BOP test as per relevant CT standards 2. Pull test connector to 35,000# for 5 mins 3. Pressure test coil string to 4500 psi 4. Bleed pressure of coil, verify 0 psi in electronics before opening needle valve on test plate. 5. Make up N2 lift assembly to 2-3/8” coil (Attachment B) 6. RIH with CT after cooling down N2 Pumps starts. 7. Start injecting N2 down coil at 400 scf/min when BHA is at 1000’. Continue RIH down to ~11,000’ taking returns to enclosed coil tank. a.DNE 250 psi downstream pressure at the choke or more than 200 bbls fluid volume in tank. 8. At ~12,000’ increase N2 rate to 500 scf/min for approximately 4 hrs. NOTE: Once N2 is seen at surface, swap returns to EXPRO. 9. Start POOH with coil at 60 fpm to surface. Time operation to stop pumping N2 when BHA is at ~ 1000’. 10. Once coil is at surface, remove fusible cap and hand well over to EXPRO. Have coil standby for 12 hours to monitor well returns. 11. The objective is to ramp well up to target rate determined by Sub-Surface and maintain steady production for at least 24-hours 12. Allow coil to bleed down to enclosed tank. 13. RDMO coil once approval is obtained from Completions Manager. Santos Ltd CT Cleanout - 14 January 2025 Page 8 Attachments A. Coil BHA #2 –Agitated Nozzle BHA Santos Ltd CT Cleanout - 14 January 2025 Page 9 B. Coil BHA #2 –N2 Lift BHA Santos LtdCT Cleanout - 14 January 2025Page 10C. CT lockup model Santos LtdCT Cleanout - 14 January 2025Page 11 NNDB-024 Clean Up Procedures WELL INFORMATION NDB-024 Well Information Basic Well Data Well Number: NDB-024 Well Type: PRODUCER Total Depth: 4204' TVD / 18029' MD Frac Date: November 18, 2023 (last frac day) Rig Name: Parker 272 Reservoir Data All data points below are to be considered estimates. Reservoir Name: Nanushuk 3 Expected Reservoir Pressure: 1840 psi (at gauge depth – Jan 2024) Reservoir Temperature: 98 °F Crude Oil API Gravity: 28° to 30° @ 60 oF Gas Gravity 0.7 Bubble Point Pressure: 1630 psi (at gauge depth) H2S Content: 7 - 8 ppm (seen on samples at end of first flowback) CO2 Content: 0 - 0.6% Estimated Oil Production Rate: Max. ~ 5000 Bbl/d Estimated Fluids Production Rate: Max. ~ 5300 Bbl/d (Max. flowback rate = ~5300 Bbl/d) GOR ~ 350 scf/stb Flowback Contact Information Flowback Point of Contact Jose Gonzalez (346) 413-9028 jose.gonzalez@contractor.santos.com On-Site Supervisor 24/7 coverage (907) 602-2132 comp.super.well@santos.com Adam Phillips adam.phillips@contractor.santos.com Craig Stevens craig.stevens@contractor.santos.com Jack Landry jack.landry@contractor.santos.com Pere Keniye Pere.Keniye@contractor.santos.com 2 CCOMPLETION SCHEMATIC 3 66 PRIMARY HAZARDS THAT ARE IDENTIFIED Risk Assessment Matrix: Risk Assessment Matrix INS-003376.pdf 4 FFLOWBACK TIMELINE Operation Stage Duration (hours) Comments Clean-Up ~96 Open well via adjustable choke, adjust as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to proppant pack and to minimize erosion to surface equipment. Do Not Exceed 50 psi/hr of Bottom Hole Draw Down Rate or allow the Bottom Hole Pressure to fall below the expected Bubble Point (at gauge depth) psi without the prior approval of Subsurface Engineering. Note: Only during initial hours of flow can use 100 psi/hr of BH Draw Down as a maximum The Santos Subsurface Engineer will determine targeted rates as well as determine when the well is clean. TOTAL PRODUCED FLUIDS NOT TO EXCEED: 37,000 BBLS WITHOUT APPROVAL FROM SUBSURFACE ENGINEERING NOTE: 20,091 BBL ALREADY FLOWED BACK DURING JAN 2024 Shut-in ~240 Shut in monitor via downhole gauge ~336 Rate # Flow Rate BBL/D Duration (Hours) Clean-up 1 0 - 5000 ~96 Summary SI 0 ~240 Rates and periods are indicative and will depend on clean-up, drawdown, and reservoir properties Hydrate Mitigation NA Well rate will be brought up to at least 2000 Bbl/d within the first ~12 hours of flow. TABLE 1 The Santos on-site Flowback Supervisor is the single point of contact for Expro well flow operations. All communication and direction related to changes to the procedure must be made through the Santos Supervisor. Expro well clean-up operations will be conducted in accordance with Expro Operational Standards/Guidelines and the Santos/Expro bridging documentation. 5 MMOBILIZE AND RIG UP Objective: x Incident free operations. x Move in and rig up the tank farm (already rigged up) and flowback equipment. x Pressure test surface equipment and lines to tank farm. Safety: x A Flowback / Clean Up Design to include Process Flow/Lay Out Diagram, P&ID, & Safety System. x SOPs pertaining to mobilization, rigging up, and pressure testing will be reviewed by Santos Flowback Supervisor, Santos Well Site Supervisor, and Expro Crew prior to commencing rig up. x A safety meeting with the Santos Flowback Supervisor and flowback personnel shall be held at the beginning of each shift change to discuss ongoing & upcoming well clean-up activities as well as pad SimOps. SimOps: x Prior to opening the well, a SimOps meeting with Santos Supervisors and personnel from all Service Companies engaged in operations on site discuss ongoing activities, forecasted operations, appropriate emergency notification and response procedures. Installation of Tank Farm: To view risk identification and mitigation involved in this process please reference. Rig Up and Rig Down Risk Assessment INS-011019.pdf 1. Magtec and Expro personnel will assemble Tank Farm containment berms as per Pad Lay Out and Containment Lay Out Plans. 2. Spot Tanks in containment utilizing a crane (minimum 45 ton) with loader assist, MagTec personnel will oversee the proper placement of tanks, cat walks, landings, and stairs. Expro will oversee the rigging up of flow-to and suction manifold lines. Rig up will be as per approved P&ID. Installation of Expro Flowback Equipment: To view risk identification and mitigation involved in this process please reference. Rig Up and Rig Down Risk Assessment INS-011019.pdf. 1. Expro personnel will assemble Flowback Equipment, Flare, Sand Trap Containment, piping, tank farm layout as per agreed Pad Lay Out. NOTE: Ensure proper access is maintained to move in, and spot well test equipment i.e., identified wall sections to be left open. 2. Santos Flowback Supervisor will inspect all equipment, and flow iron to ensure proper inspections, certifications, and pressure rating prior to beginning rig-up. 3. Spot equipment as per approved layout plan. 4. Complete and secure all Containment Berms. 6 5. Expro to rig up interconnecting equipment, & piping as per Expro procedures, per approved P&ID. Pressure Test of Expro Flowback Equipment: To view risk identification and mitigation involved in this process please reference. Pressure Testing INS-002660.pdf Rig Up and Rig Down Risk Assessment INS-011019.pdf. 6. A documented low-pressure air test of 100 - 120 psi will be performed and held for 10 minutes on surface lines and equipment prior to pressure testing with fluids. Cap the gas line to the flare/incinerator and test line with air to 120 psi for 15 minutes. NOTE: Nitrogen must be used for air test if hydrocarbons are present. NOTE: Diesel will be the pressure test medium for all pressure testing with fluid unless otherwise directed by the Santos Flowback Supervisor. 7. Pressure test all Expro equipment and hardline upstream of the choke manifold to 4,500 psi and hold 15 minutes. Pressure Test all downstream flow iron (with exception of flare) to 1000 psi and hold 15 minutes. NOTE: All pressure tests shall be performed using a calibrated gauge and recorded on a chart or electronically. 8. Upon successful completion of pressure testing, there will be no need to blowdown all lines to the designated gauge tank. 9. Expro will Identify critical erosion points on surface equipment, mark and number these points on the equipment and begin an erosion monitoring log. Perform and log a base line thickness test of all points. Monitor erosion points during flow as per Expro procedures. As a reference, here is the baseline taken in Nov 2023 Critical Points Map_Santos Baseline_20-Nov-2023 (1).pdf 10. Function test all the ESD system. All stations must be tested and documented on the timing of shut in of the ESD valve. Expro_Emergency Shutdown Checklist__INS-002050.pdf NOTE: Maximum allowable closure time of the surface ESD valve is 30 seconds or less from activation. 11. Complete the securing and heat tracing of flow and flare lines as applicable. 12. Clean work area and prepare to open well. References: Expro Hazop: Santos Expro Hazard Analysis A_DR 01.xlsx Santos QA/QC of Expro Equip: Expro Maintenance Documents.xlsx Expro Well Test Well Site Management Standard: Well Test Site Management Standard INS-009724.pdf Expro Torque Check Sheet: INS-002444_Torque Check Sheet.docx 7 CCLEAN-UP & SHUT-IN Objectives: 1. Incident free operations. 2. Ensure that all Expro metering equipment has been properly calibrated and documented. 3. Test the Emergency Shut Down system (ESD) from all stations to include pressure pilots. Expro_Emergency Shutdown Checklist INS-002050.pdf 4. Flowback recoverable frac fluid and proppant until clean reservoir fluid is obtained. 5. Flow and record all clean-up fluids to designated gauge tanks for disposal injection. 6. Flow and record clean hydrocarbons to gauge tanks as applicable. Safety: x A Santos Unit Work Permit must be active prior to opening well. x Hold a safety / SimOps meeting with all contractors involved in flowback operations to ensure everyone understands the sequence of events and risks involved. Discuss responsibilities, operation of ESD system, emergency response, and muster points. x Expro SOP’s pertaining to Flowing Operations, Solids Control, Sampling, and Fluid Transfers will be reviewed by the Santos Flowback Supervisor, and Expro Crew prior to opening well. x Baseline thickness reading have been taken at all identified critical erosion points of the surface equipment, continual thickness monitoring will occur during flowing operations and documented. Any components nearing minimal wall thickness will be flagged and replaced during shut in periods. x H2S contingencies: If a consistent H2S concentration of 10 ppm or higher is measured, personnel must suit up with SCBA or shut the well in if proper equipment and training is not available. If concentration exceeds 50 ppm in the gas phase, a full BA cascade system must be installed. Refer to Santos SMS-D&C-OS01-TS10 – Onshore Hydrogen Sulfide and contingency procedures. SimOps: x Ensure personnel involved in concurrent activities are aware of flowback operations, associated risk, have emergency contact and response information. x Non-essential personnel will be kept clear of the flow back area during operations. Well Cleanup - Operational Summary: x Estimated Time: ~96 hours or as dictated by Santos Subsurface Engineer. x Target Maximum Clean-up Flow Rate: Up to 5300 BPD w/ 2.0 mmscf/d x Choke Setting: Use adjustable choke to achieve a stable flow rate while controlling solids production. Watch BS&W and adjust drawdown rate as directed by the Santos Flowback Supervisor. Choke changes will be based on well performance and bottoms up solids production. 8 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 3,000 psi, bleed down as necessary and record amount of fluid recovered from the annular while bleeding down. x N2 Injection/Gas Lift Rate (if required): In the event of N2 injection or other means of gas lift, it is imperative that the injection rate is accounted for in the reported produced gas rates and volumes. Ensure the proper injection rates and units of measure are communicated i.e. scf/minute vs scf/day and utilized in the data acquisition system. Total volume of gas injected for lift must be recorded for each well as it will be utilized in the rolling year total gas produced report that is required by the state. o NOTE: When(if) the well is switched from CT operations to flowback operations, adjust choke size to match WH conditions while returning N2. Then, continue with choke schedule as required. x Methanol Injection Rate: MeOH will be injected to prevent the formation of hydrates only if well has remained shut-in more than 8 days after the frac and flowing wellhead temperature does not reach 57F before formation gas comes to surface. If flowback commences more than 8 days after the frac, CT will be directed to spot MeOH as a precaution. x Tank Farm: The tank farm will consist of a total of 11 tanks at 367 Bbl each. One of them will be used for diesel, and the rest for flowback / disposal purposes. These can only be filled to 80% which is a total volume available of 2936 Bbl for flowback / disposal. There is also another tank at the separator site for additional meter factor tests, if needed. NOTE: Before well is opened for flowback, a Town Hall Meeting / Safety meeting must be held including all parties involved (Expro, LRS, & Worley, etc.) with the clean-up including any other vendor that is associated with SimOps on the pad. Operational Procedures: 1. The Santos Flowback Supervisor, and the Expro Supervisor will confirm the Expro pre-flow check list has been properly completed and that the ESD system and pressure pilots are functioning as per the Expro (API RP 14C compliant) safety system design. 2. The Santos Flowback Supervisor, and the Expro Supervisor will walk the lines to ensure correct line up of valves and manifolds and to verify proper flowline restraints are in place and properly installed. 3. Confirm the data acquisition and remote data transmission system are functioning properly. 4. Open the well to the closed Expro choke manifold. Record the tubing pressure and monitor the well for 5 minutes before proceeding. NOTE: Count and record the number of turns to open and close all gate valves. 9 5. Bring the well on slowly using the Expro adjustable choke, adjust as necessary to achieve a stabilized flow rate. Bypass the separator until there is sufficient pressure to direct flow through it. a. If the deep electronic gas lift system is used, once opened, start displacing the IA with N2 at ~400 scf/min to the GL system depth receiving returns up tubing and into tank farm opening the Expro adjustable choke progressively starting at least at 32/64”. b. After the IA is displaced, continue pumping N2 (rate and total volume to be adjusted based on well response. However, it is estimated to range from 400 to 750 scf/m and a maximum of 3 N2 transports). Continue bringing the well on adjusting choke as necessary to achieve a stabilized flow rate and as per flowback plan. Bypass the separator until there is sufficient pressure to direct flow through it. NOTE: After there is sufficient pressure to operate the separator, at no time will flow be directed to bypass the separator except for blowing down the sand trap or after consultation and approval from the Santos Flowback Supervisor. 6. Flow well as per applicable Expro procedures, make choke changes as directed by Santos Flowback Supervisor. Monitor solids production and make solids dumps as needed. Ensure Liquid Rates and Pwf (flowing downhole pressure) remain within parameters as dictated by the Santos Reservoir Engineer. a. Note: Be aware of keeping rates within the range of respective meter NOTE: It is important to ensure that choke sizes are not increased until bottoms up has occurred, and the solids production rate has been established and are on the decline. Great care should be taken to recognize that increasing the choke size rapidly could result in an unmanageable volume of solids at surface resulting in potential screening out of equipment, formation shock, damage to proppant pack, and excessive erosion of surface equipment. 7. When proppant is observed at surface, begin the thickness check of critical erosion points and log results as per Expro procedures. 8. In addition to data acquisition, log as a minimum the following parameters every hour on a manual data sheet. Use agreed upon template for data reporting. a. Date/Time b. Downhole Pressures & Temperatures c. Wellhead Pressure & Temperature d. Annulus Pressure e. Separator Pressure & Temperature f. Gas, Oil, and Water Rates g. Cumulative Gas, Oil, and Water Totals h. BS&W Data i. Oil API Gravity (hourly) j. Gas Gravity (hourly) k. H2O% Chlorides (salinity) (hourly or as H2O production allows) l. H2S, & Co2 (hourly, if 3 consecutive reads of 0 are achieved, sampling will be performed every 12 hours) m. Nitrogen Lift Rate if Applicable n. Tank Levels o. Differential Pressure across Choke Manifold p. Estimated Proppant Rate q. Estimate Proppant Volume Dumped from Sand Trap 10 9. The well can be considered clean when the Subsurface Engineer determines the BS&W and water rate is within the clean criteria and rates are reasonably stable. 10. When the decision has been made to shut-in the well, and upon direction from the Santos Flowback Supervisor, shut in the well as quick as possible (hard shut in) at the FWV and continue logging downhole pressures. Maintain the well shut period for the allocated time or until the Santos Subsurface Engineer has determined that sufficient data has been received. NOTE: Ensure the inner annulus is bleed down to İİ 1000psi prior to Shut-in, DO NOT BLEED THE INNER ANNULUS AFTER THE SHUT-IN PERIOD HAS BEGAN. Crew & Responsibilities: Expro Personnel: Expro Personnel Roles and Responsibilities.docx Worley’s Personnel: Responsible for loading & unloading of vac trucks per their Fluid transfer guidelines. Magtec Personnel: Responsible for assisting in changing / checking & monitoring the filter screens in the filter pod canister and assist with any other task as directed. LRS: Responsible for injection of hydrocarbons into DW-02, or any other disposal or injection well. x The Expro twice daily report along with the downhole data will be emailed @ 06:00 & 18:00 hrs. daily to the Santos email distribution list. x A 24 hrs. average summary will be uploaded into WellView before 06:00 x The Santos Flowback Supervisor will reconcile the fluid at 12pm & 12am. This shall include fluid (Oil & H2O) stored in all tanks + what LRS has injected this total should equal what Expro has on the report as Cumm total produced + or - 5%. References: Expro_Pre-Flowing Checklist_INS-002053.pdf Gas Scrubber Draining Operations INS-002197.pdf Indirect Heater Procedure INS-003217.pdf Sand Trap Operations Procedure INS-002196.pdf Solids Management INS-007890.docx Surface Sampling INS-002691.pdf Flow Back Operations – Reporting Structure.pptx SMS-D&C-OS01-TS10_Onshore_Hydrogen_Sulphide.pdf Worley: EC-P08-BASE-FLD-018-WI-Fluid Transfer Guidlines.pdf Santos OS01-TS17 Standard: SMS-D&C-OS01-TS17_Onshore_Well_Testing.pdf Santos Well Testing Standard: Well Testing.pdf 11 SSURFACE SAMPLING PROGRAM TABLE 2 Flow Period Sample Type Lab Analysis Number / Frequency Surface Sampling Location Volume Sampling Container Collection Vendor Comments Produced Fluid BS&W Every 30 minutes SP-001A 100 ml Centrifuge Tube Expro As per Expro procedure note any chemical used Oil API Gravity 2 per shift SP-103A 5 ml Nalgene Bottle Expro Anton Paar DMA35 or equivalent required Water PH Hourly SP-104A NA NA Expro Perform hourly or as H20 production allows Water Chlorides Hourly SP-104B NA NA Expro Perform hourly or as H20 production allows Glass Sample Tube H2S Hourly SP-105A N/A H2S Tubes Expro Hourly to start, reduce to every 12 hrs. if no H2S observed after 3 consecutive reads. Glass Sample Tube CO2 Hourly SP-105B N/A CO2 Tubes Expro Hourly to start, reduce to every 12 hrs. if no H2S observed after 3 consecutive reads. Gas Gas Gravity (Ranarex)Hourly SP-105C N/A N/A Expro Twice per shift @ start up until it's stays constant then once per shift. Flow Period Sample Type Lab Analysis Number / Frequency Surface Sampling Location Volume Sampling Container Collection Vendor Comments Oil Composition Corelab Once Sep oil leg 100 ml Nalgene Bottle Expro Oil sample after 1 day of crude to surface (must be chemical free) Oil & H20 ion analysis Corelab Once Sep Oil / H20 Leg 100 ml Nalgene Bottle Expro Oil & Water sample near end of peak rate/1st step- down (must be chemical free) Water Quantify proppant scale inhibator Once Sep water eg 1 liter Nalgene Bottle Expro 3 - one liter samples of water from the last 12 hours of flow. Document date, time flow rate, H2O & chloride on sample tag Produced Fluid Tracer Sampling Tracerco Tracer Sampling procedure Separator Oil/H2O Leg NA NA Expro Take one water and one oil sample every 6 hours.Clean UpSurface Sampling Program Samples for 3rd party lab analysis Lab Samples 12 RRIG DOWN & DEMOBILIZE Objectives: 1. Incident free operations. 2. Evacuate all surface equipment and lines of Hydrocarbon and De-pressure. 3. Rig down all flowback interconnecting equipment, flow lines, and tank farm (if applicable). 4. Load out equipment for wash bay or Deadhorse point of origin as applicable. Safety: x Hold a safety / SimOps meeting with all contractors involved in flowback operations to ensure everyone understands the sequence of events and risks involved. Discuss responsibilities, operation of ESD system, emergency response, and muster points. SimOps: x Ensure personnel involved in concurrent activities are aware of flowback operations, associated risk, and have emergency contact and response information. x Non-essential personnel will be kept clear of flowback area during operations. Operational Procedures: To view risk identification and mitigation involved in this process please reference. Rig Up and Rig Down Risk Assessment INS-011019.pdf 1. Rig down and demobilize equipment as per Expro procedures. 2. Confirm the absence of Trapped Pressure on every pipe run prior to breaking the first union. 3. Ensure that drip liners and absorbent are on hand and utilized throughout the rig down process. 4. Break down containment berms and prepare materials for transport. 5. Complete the end of job inspection to ensure all equipment is removed and site is clean. 6. Santos Flowback Supervisor will review the end of job inspection and perform a final walk down of the site. 7. Santos Flowback Supervisor will release flowback and Tank Farm Personnel. APPROVALS NAME SIGNATURE DATE Robert (Ty) Senden: Sr. Eng. Manager, Completions Jose (Jose) Gonzalez: Sr. Completions Engineer From:Senden, Robert (Ty) To:McLellan, Bryan J (OGC) Subject:NDB-024 (PTD 223-076) Operational Update Date:Tuesday, December 17, 2024 7:33:59 AM Attachments:image002.png NDB-024_Daily Pressure Recording.pdf Bryan, Thanks for reaching out and inquiring about well NDB-024. I’ll respond in the same order as the original bulleted list below: 1. Daily gas readings began on February 6, 2024, the day after we completed flowing back the well. Although the well shelter hadn’t been installed at that time, all our frac and flowback work had been completed so we began the LEL monitoring without a wellhouse installed. Readings continued with and without the well shelter on until October 6, 2024, well beyond the required duration. The daily data is attached. 2. We will commence another round of monitoring once the well (and field) begin long term production. 3. Gas level readings (LEL) were collected and tracked on the daily pressure chart for the required duration. 4. We’ve never seen any LEL readings during our monitoring period. 5. The monitoring never indicated any LEL readings therefore, eliminating the need for a permanently installed monitoring system. 6. Until first production, and startup of our Well Integrity Management System (WIMS), our pressure monitoring will continue with visual inspections and readings from analog pressure gauges. I believe these responses satisfy your questions. If not, please let me know and I will provide supplemental information. Thank you, Ty Senden Senior Completions Engineering Manager 907-982-3996 | ty.senden@santos.com From: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Sent: Tuesday, December 3, 2024 3:18 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Senden, Robert (Ty) <Ty.Senden@santos.com> Cc: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com>; Johnson, Vernon (Vern) <Vern.Johnson@santos.com> Subject: RE: NDB-024 (PTD 223-076) Operational Update Bryan, Thank you for the note. Jared is no longer employed with Santos. Ty Senden, the Completions Manager, will be leading this effort. The 14-day time constraint is noted. Regards, Rob Robert Tirpack Senior Drilling Engineering Manager m: (907) 903-9454 | e: robert.tirpack@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, December 3, 2024 1:59 PM To: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Operational Update Jared, The AOGCC requests a well integrity status update for this well, including the results of the gas monitoring that’s been done to date and tracked in Peloton WIMS per the monitoring plan below. This request for information is being made under 20 AAC 25.300 and is required within 14 days of this request. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent: Wednesday, October 18, 2023 11:15 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Subject: RE: NDB-024 (PTD 223-076) Operational Update Bryan, The status of the conductor on Pikka NDB-024 is currently static. There is no detectible gas migration coming from the conductor into the cellar, this is with current drilling operations and circulation taking place on the well. Once the rig moves off the well and completed, the well will be part of the daily visual checks currently being done by our DHD/roustabout crew. Full automation will not be in place until first production in two years, so until then we will continue with daily visual inspections with analogue pressure readings. Below is what we propose to monitor, that is also outlined within our WIMS for the development. o Daily gas LEL readings within the shelter shall be monitored for one month after the rig has released the well. o Monitoring will repeat once the well in placed onto production, incase heat from produced fluids acerbate the hydrate gas migration. Gas level readings shall be tracked on the daily pressure/inspection chart for the well with a calibrated four gas monitor. o If 50% LEL atmosphere is achieved, the enclosure must be ventilated, and access only granted with hot work permits outside of daily inspections. o If the atmospheric conditions inside the enclosure are consistently poor and not trending towards a complete stop over the one-month monitoring period, a permanent Class I Div I, LEL monitoring system must be placed within the wellhouse that can alert outside workers of potentially harmful conditions inside of the enclosure and the enclosure shall be ventilated. The results of the monitoring will be tracked in Peloton WIMS and seen on the well integrity dashboard (this is our well integrity monitoring program). Let me know if you have any further questions. Jared Brake Well Integrity & Well Intervention Engineer t: 1 (907) 375-4673 | m: 1 (832) 330-4359| e: jared.brake@contractor.santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Sent: Tuesday, October 17, 2023 10:59 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Staudinger, Garret (Garret) <Garret.Staudinger@santos.com>; Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Subject: RE: NDB-024 (PTD 223-076) Operational Update Bryan – Jared Brake is our Well Integrity Engineer. He is working up the long tern gas monitoring plan response. Will have something for you tomorrow. Regards, Rob Robert Tirpack Senior Drilling and Completions Engineering Manager m: (907) 903-9454 | e: robert.tirpack@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 17, 2023 6:27 AM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Operational Update Garret, What is Oilsearch’s plan for presenting the AOGCC with a long-term gas monitoring strategy? 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: Friday, October 13, 2023 5:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: Re: NDB-024 (PTD 223-076) Operational Update Thanks Bryan, good to hear. Appreciate the quick response. Regards, Garret From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, October 13, 2023 2:23:47 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: ![EXT]: Re: NDB-024 (PTD 223-076) Operational Update Garrett, Based on the discussions on Tuesday between Santos and AOGCC, the AOGCC will not require additional remedial cementing on NDB-24 at this time, on the condition that Santos implements a plan for long term gas monitoring acceptable to the commission. Regards Bryan Mclellan Sent from my iPhone On Oct 13, 2023, at 4:08 PM, Staudinger, Garret (Garret) 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. <Garret.Staudinger@santos.com> wrote: Bryan, I just called and left you a voicemail. Just wanted to let you know that we are currently coming out of the hole with the drilling BHA and will be running the 9-5/8" intermediate liner this weekend. I was hoping that you could provide some guidance on what we need to prepare for based on the results from our meeting on Tuesday about any remedial work. Appreciate your time and look forward to hearing from you soon. Regards, Garret Get Outlook for iOS 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 addressedand may be confidential or contain privileged information. If you are not the intended recipient you are hereby notifiedthat 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 Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 02/01/24 N/A 0 N/A N/A Shut in Crown Valve, HMV and LMV 02/02/24 N/A 0 N/A N/A 02/03/24 N/A 0 N/A N/A 02/04/24 N/A 0 N/A N/A 02/05/24 N/A 0 N/A N/A 02/06/24 N/A 0 N/A 0 02/07/24 N/A 0 N/A 0 02/08/24 N/A 0 N/A 0 02/09/24 N/A 0 N/A 0 02/10/24 N/A 0 N/A 0 02/11/24 N/A 0 N/A 0 02/12/24 N/A 0 N/A 0 02/13/24 N/A 0 N/A 0 02/14/24 N/A 0 N/A 0 02/15/24 N/A 0 N/A 0 02/16/24 N/A 460 N/A 0 Performed MIT-IA to 3,000 psi. Bled down to 460 psi on IA 02/17/24 N/A 290 N/A 0 Test tubing and casing hanger. 02/18/24 N/A 290 N/A 0 02/19/24 500 290 N/A 0 Open SSV to check tubing pressure. 02/20/24 450 290 N/A 0 02/21/24 500 290 N/A 0 02/22/24 550 290 N/A 0 02/23/24 525 290 N/A 0 02/24/24 525 290 N/A 0 Wireline work in progress 02/25/24 588 N/A N/A 0 Wireline work in progress 02/26/24 N/A 225 N/A 0 02/27/24 N/A 150 N/A 0 02/28/24 N/A 150 N/A 0 02/29/24 N/A 150 N/A 0 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 03/01/24 N/A 150 N/A 0 03/02/24 225 125 N/A 0 03/03/24 225 150 N/A 0 03/04/24 225 150 N/A 0 03/05/24 225 150 N/A 0 03/06/24 225 150 N/A 0 03/07/24 225 125 N/A 0 03/08/24 250 125 N/A 0 03/09/24 250 125 N/A 0 03/10/24 250 125 N/A 0 03/11/24 250 100 N/A 0 03/12/24 250 150 N/A 0 03/13/24 250 100 N/A 0 03/14/24 250 100 N/A 0 03/15/24 250 150 N/A 0 03/16/24 250 100 N/A 0 03/17/24 250 100 N/A 0 03/18/24 250 100 N/A 0 03/19/24 250 100 N/A 0 03/20/24 250 100 N/A 0 03/21/24 250 100 N/A 0 03/22/24 250 100 N/A 0 03/23/24 250 100 N/A 0 03/24/24 250 100 N/A 0 03/25/24 400 50 N/A 0 03/26/24 400 50 N/A 0 03/27/24 400 50 N/A 0 03/28/24 400 50 N/A 0 03/29/24 0 Coil on well 03/30/24 0 Coil on well 03/31/24 0 Coil on well Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 04/01/24 0 0 Coil on well 04/02/24 0 0 Coil on well 04/03/24 0 0 0 04/04/24 0 0 0 04/05/24 0 0 0 04/06/24 0 0 0 04/07/24 0 0 0 04/08/24 0 0 0 04/09/24 0 0 0 04/10/24 0 0 0 04/11/24 50 0 0 04/12/24 50 0 0 04/13/24 0 0 E-Line on well 04/14/24 0 0 E-Line on well 04/15/24 50 0 0 04/16/24 50 0 0 04/17/24 50 0 0 04/18/24 50 0 0 04/19/24 0 50 0 0 04/20/24 0 50 0 0 04/21/24 0 50 0 0 04/22/24 0 50 0 0 04/23/24 0 50 0 0 04/24/24 0 50 0 0 04/25/24 0 50 0 0 04/26/24 50 0 0 04/27/24 50 0 0 04/28/24 50 0 0 04/29/24 50 0 0 04/30/24 50 0 0 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 05/01/24 50 NA 0 05/02/24 50 NA 0 05/03/24 50 NA 0 05/04/24 50 NA 0 05/05/24 50 NA 0 05/06/24 50 NA 0 05/07/24 50 NA 0 05/08/24 50 NA 0 05/09/24 50 NA 0 05/10/24 50 NA 0 05/11/24 50 NA 0 05/12/24 50 NA 0 05/13/24 50 NA 0 05/14/24 50 NA 0 05/15/24 50 NA 0 05/16/24 50 NA 0 05/17/24 50 NA 0 05/18/24 50 NA 0 05/19/24 50 NA 0 05/20/24 50 NA 0 05/21/24 50 NA 0 05/22/24 50 NA 0 05/23/24 50 NA 0 05/24/24 50 NA 0 05/25/24 50 NA 0 05/26/24 50 NA 0 05/27/24 50 NA 0 05/28/24 50 NA 0 05/29/24 50 NA 0 05/30/24 50 NA 0 05/31/24 50 NA 0 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 06/01/24 25 NA 0 06/02/24 25 NA 0 06/03/24 25 NA 0 06/04/24 25 NA 0 06/05/24 30 NA 0 06/06/24 30 NA 0 06/07/24 30 NA 0 06/08/24 25 NA 0 06/09/24 25 NA 0 06/10/24 25 NA 0 06/11/24 25 NA 0 06/12/24 25 NA 0 06/13/24 25 NA 0 06/14/24 20 NA 0 06/15/24 25 NA 0 06/16/24 30 NA 0 06/17/24 30 NA 0 06/18/24 30 NA 0 06/19/24 30 NA 0 06/20/24 30 NA 0 06/21/24 30 NA 0 06/22/24 30 NA 0 06/23/24 30 NA 0 06/24/24 40 NA 0 06/25/24 30 NA 0 06/26/24 10 NA 0 06/27/24 20 NA 0 06/28/24 20 NA 0 06/29/24 20 NA 0 06/30/24 20 NA 0 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 07/01/24 20 N/A 07/02/24 20 N/A 0 07/03/24 20 N/A 07/04/24 20 N/A 07/05/24 20 N/A 07/06/24 20 N/A 0 07/07/24 20 N/A 07/08/24 20 N/A 0 07/09/24 25 N/A 0 07/10/24 25 N/A 07/11/24 25 N/A 0 07/12/24 350 25 N/A 0 07/13/24 350 25 N/A 0 07/14/24 350 25 N/A 0 07/15/24 350 25 N/A 0 07/16/24 350 25 N/A 0 07/17/24 350 25 N/A 0 07/18/24 350 20 N/A 0 07/19/24 350 20 N/A 0 07/20/24 350 20 N/A 0 07/21/24 350 20 N/A 0 07/22/24 350 20 N/A 0 07/23/24 350 20 N/A 0 07/24/24 350 20 N/A 0 07/25/24 350 20 N/A 0 07/26/24 350 20 N/A 0 07/27/24 350 20 N/A 0 07/28/24 350 20 N/A 0 07/29/24 07/30/24 07/31/24 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 08/01/24 350 20 N/A 0 08/02/24 350 20 N/A 0 08/03/24 350 20 N/A 0 08/04/24 350 20 N/A 0 08/05/24 350 20 N/A 0 08/06/24 350 20 N/A 0 08/07/24 350 20 N/A 0 08/08/24 350 20 N/A 0 08/09/24 350 20 N/A 0 08/10/24 350 20 N/A 0 08/11/24 350 20 N/A 0 08/12/24 350 20 N/A 0 08/13/24 350 20 N/A 0 08/14/24 350 20 N/A 0 08/15/24 350 20 N/A 0 08/16/24 350 20 N/A 0 08/17/24 0 10 N/A 0 Bleed tree to 0 psi. 08/18/24 0 10 N/A 0 08/19/24 100 10 N/A 0 08/20/24 300 10 N/A 0 08/21/24 650 10 N/A 0 08/22/24 50 10 N/A 0 08/23/24 0 20 N/A 0 Bleed off tree to 0 psi. SSV and swab closed. 08/24/24 0 20 N/A 0 08/25/24 0 10 N/A 0 08/26/24 0 10 N/A 0 08/27/24 150 10 N/A 0 08/28/24 400 10 N/A 0 08/29/24 300 10 N/A 0 08/30/24 0 10 N/A 0 08/31/24 0 25 N/A 0 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 09/01/24 0 NA 0 SSV closed 09/02/24 0 NA 0 09/03/24 0 NA 0 09/04/24 0 NA 0 09/05/24 0 NA 0 09/06/24 0 NA 0 09/07/24 0 NA 0 09/08/24 0 NA 0 09/09/24 0 NA 0 09/10/24 0 NA 0 09/11/24 0 NA 0 09/12/24 0 NA 0 09/13/24 0 NA 0 09/14/24 0 NA 0 09/15/24 0 NA 0 09/16/24 0 NA 0 09/17/24 0 NA 0 09/18/24 0 NA 0 09/19/24 0 NA 0 09/20/24 0 NA 0 09/21/24 0 NA 0 09/22/24 0 NA 0 09/23/24 0 NA 0 09/24/24 0 NA 0 09/25/24 0 NA 0 09/26/24 0 NA 0 09/27/24 0 NA 0 09/28/24 0 NA 0 09/29/24 0 NA 0 09/30/24 0 NA 0 Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. Well: NDB-024 PTD: 223-076 Date: Tbg Pressure (psi) IA Pressure (psi) OA Pressure (psi)LEL Reading Comments 10/01/24 0 0 0 0 10/02/24 0 0 0 0 10/03/24 0 0 0 0 10/04/24 0 0 0 0 10/05/24 0 0 0 0 10/06/24 0 0 0 0 10/07/24 0 0 0 Stopped reading LEL as of today 10/08/24 0 0 0 10/09/24 0 0 0 10/10/24 0 0 0 10/11/24 0 0 0 10/12/24 0 0 0 10/13/24 0 0 0 10/14/24 0 0 0 10/15/24 0 0 SSV closed 10/16/24 0 0 SSV closed 10/17/24 0 0 SSV closed 10/18/24 0 0 SSV closed 10/19/24 0 0 SSV closed 10/20/24 0 0 SSV closed 10/21/24 0 0 SSV closed 10/22/24 0 0 SSV closed 10/23/24 0 0 SSV closed 10/24/24 0 0 SSV closed 10/25/24 0 0 SSV closed 10/26/24 0 0 SSV closed 10/27/24 0 0 SSV closed 10/28/24 0 0 SSV closed 10/29/24 0 0 SSV closed 10/30/24 0 0 SSV closed Well Status : OA is cemented to surface and does not require monitoring. Well has been Frac'd, Flowed back. LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 1 PDF file NDB-024 (50-103-20862-0000) Well clean up report 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: 12/5/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl 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: 223-076 T39828 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.06 08:11:09 -09'00' From:Brake, Jared (Jared) To:McLellan, Bryan J (OGC) Cc:Tirpack, Robert (Robert); Staudinger, Garret (Garret) Subject:RE: NDB-024 (PTD 223-076) Operational Update Date:Wednesday, October 18, 2023 11:14:54 AM Attachments:image002.png Bryan, The status of the conductor on Pikka NDB-024 is currently static. There is no detectible gas migration coming from the conductor into the cellar, this is with current drilling operations and circulation taking place on the well. Once the rig moves off the well and completed, the well will be part of the daily visual checks currently being done by our DHD/roustabout crew. Full automation will not be in place until first production in two years, so until then we will continue with daily visual inspections with analogue pressure readings. Below is what we propose to monitor, that is also outlined within our WIMS for the development. o Daily gas LEL readings within the shelter shall be monitored for one month after the rig has released the well. o Monitoring will repeat once the well in placed onto production, incase heat from produced fluids acerbate the hydrate gas migration. Gas level readings shall be tracked on the daily pressure/inspection chart for the well with a calibrated four gas monitor. o If 50% LEL atmosphere is achieved, the enclosure must be ventilated, and access only granted with hot work permits outside of daily inspections. o If the atmospheric conditions inside the enclosure are consistently poor and not trending towards a complete stop over the one-month monitoring period, a permanent Class I Div I, LEL monitoring system must be placed within the wellhouse that can alert outside workers of potentially harmful conditions inside of the enclosure and the enclosure shall be ventilated. The results of the monitoring will be tracked in Peloton WIMS and seen on the well integrity dashboard (this is our well integrity monitoring program). Let me know if you have any further questions. Jared Brake Well Integrity & Well Intervention Engineer t: 1 (907) 375-4673 | m: 1 (832) 330-4359| e: jared.brake@contractor.santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Sent: Tuesday, October 17, 2023 10:59 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Staudinger, Garret (Garret) <Garret.Staudinger@santos.com>; Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Subject: RE: NDB-024 (PTD 223-076) Operational Update Bryan – Jared Brake is our Well Integrity Engineer. He is working up the long tern gas monitoring plan response. Will have something for you tomorrow. Regards, Rob Robert Tirpack Senior Drilling and Completions Engineering Manager m: (907) 903-9454 | e: robert.tirpack@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 17, 2023 6:27 AM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Operational Update Garret, What is Oilsearch’s plan for presenting the AOGCC with a long-term gas monitoring strategy? 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: Friday, October 13, 2023 5:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: Re: NDB-024 (PTD 223-076) Operational Update Thanks Bryan, good to hear. Appreciate the quick response. Regards, Garret From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, October 13, 2023 2:23:47 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: ![EXT]: Re: NDB-024 (PTD 223-076) Operational Update Garrett, Based on the discussions on Tuesday between Santos and AOGCC, the AOGCC will not require additional remedial cementing on NDB-24 at this time, on the condition that Santos implements a plan for long term gas monitoring acceptable to the commission. Regards 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. Bryan Mclellan Sent from my iPhone On Oct 13, 2023, at 4:08 PM, Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> wrote: Bryan, I just called and left you a voicemail. Just wanted to let you know that we are currently coming out of the hole with the drilling BHA and will be running the 9-5/8" intermediate liner this weekend. I was hoping that you could provide some guidance on what we need to prepare for based on the results from our meeting on Tuesday about any remedial work. Appreciate your time and look forward to hearing from you soon. Regards, Garret Get Outlook for iOS 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 notifiedthat 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 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 223-076 Type Inj N Tubing 500 500 500 500 Type Test P Packer TVD 4071 BBL Pump 9.7 IA 0 3005 2935 2891 Interval O Test psi 3000 BBL Return 0.0 OA 0 0 0 0 Result F Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 223-076 Type Inj N Tubing 500 500 500 500 Type Test P Packer TVD 4071 BBL Pump 0.8 IA 2891 3005 2975 2955 Interval O Test psi 3000 BBL Return 0.0 OA 0 0 0 0 Result F Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 223-076 Type Inj N Tubing 500 500 500 500 Type Test P Packer TVD BBL Pump 0.3 IA 2955 3013 2997 2984 Interval O Test psi BBL Return 1.0 OA 0 0 0 0 Result F Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Oil Search (Santos) Pikka / NOP / NDB Not Witnessed Brad Gathman 02/16/24 Notes:MIT-IA for suspect IA communication. Notes: Notes: Notes: NDB-024 NDB-024 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:2nd attempt NDB-024 Notes:3rd attempt Notes: Form 10-426 (Revised 01/2017)2024-0216_MITP_Pikka_NDB-024_3tests                J. Regg; 5/10/2024 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Thursday, March 21, 2024 2:53 PM To:Brake, Jared (Jared) Cc:Regg, James B (OGC) Subject:RE: NDB-024 passing MIT for AnnComm Attachments:MIT NDB-024 02-25-24.xlsx Jared, AƩached is a revised report correcƟng the formaƫng. Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent: Monday, February 26, 2024 6:55 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; Miller, Nicklaus (Nick) <Nick.Miller@santos.com>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: NDB‐024 passing MIT for AnnComm Folks, The annular communicaƟon was repaired on NDB‐024 and a passing MIT‐IA was observed post GLV Dummy change out. We found damaged packing on the dummy valve that allowed for a small linear leak from the IA to tubing. AƩached is a copy of the passing MIT test performed yesterday 2/25/2024. Jared Brake Well Integrity & Well IntervenƟon Engineer You don't often get email from jared.brake@contractor.santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Pikka NDB-24PTD 2230760 J. Regg; 4/1/2024 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2230760 Type Inj N Tubing 1847 2337 2676 2670 Type Test P Packer TVD 4071 BBL Pump 6.7 IA 107 3107 3052 3031 Interval O Test psi 1500 BBL Return 5.9 OA 1 1 1 1 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Oil Search (Santos) Pikka / NDB Pere Keniye & Jared Brake 02/25/24 Notes:MIT-IA post GLV Dummy change out for annular communication. Test passed after valve swap. Notes: Notes: Notes: NDB-024 Form 10-426 (Revised 01/2017)2024-0225_MITP_Pikka_NDB-024       1-Oil Producer J. Reggf; 4/1/2024 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-024 (50-103-20862-0000) Supplemental submittal Details on the 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: 1/30/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl 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: PTD: 223-076 T38449 1/30/2024 Kayla Junke Digitally signed by Kayla Junke Date: 2024.01.30 12:51:02 -09'00' LETTER OF TRANSMITTAL Baker Geoscience │ ├───CGM │ │ NDB-024_LWD_R07_MEM_PROCESSED_ITK_IMAGE_11487_17969ft_1_240.cgm │ │ NDB-024_LWD_R07_MEM_PROCESSED_ITK_IMAGE_11487_17969ft_1_600.cgm │ │ │ ├───DLIS │ │ NDB-024_LWD_R06_RM_PROCESSED_LTK_IMAGE_2990_11310ft.dlis │ │ NDB-024_LWD_R07_MEMORY_PROCESSED_LTK_IMAGE_11460_17950ft_.dlis │ │ NDB-024_LWD_R07_MEM_PROCESSED_ITK_IMAGE_11460_17950ft.dlis │ │ │ ├───LAS │ │ NDB-024_LWD_RM_18029ft_with Baker LWD image data.las │ │ │ ├───PDF │ │ NDB-024_LWD_R06_RM_PROCESSED_LTK_IMAGE_2990_11310ft_1_240.PDF │ │ NDB-024_LWD_R07_MEMORY_PROCESSED_LTK_IMAGE_11460_17950ft_1_240.PDF │ │ NDB-024_LWD_R07_MEMORY_PROCESSED_LTK_IMAGE_11460_17950ft_1_600.PDF │ │ NDB-024_LWD_R07_MEM_PROCESSED_ITK_IMAGE_11487_17969ft_1_240.PDF │ │ NDB-024_LWD_R07_MEM_PROCESSED_ITK_IMAGE_11487_17969ft_1_600.PDF │ │ │ └───TIFF │ NDB-024_LWD_R06_RM_PROCESSED_LTK_IMAGE_2990_11310ft_1_240.tif │ ├───Mudlogging Geoisotopes │ NDB-024_G5_GEOISOTOPES_Corrected data_11465-18029ft.las │ NDB-024_G5_GEOSITOPES_Composite_11465-18029 ft_1inch.pdf │ NDB-024_GasRpt_Final.xlsx │ └───NDB-024_Sperry_Logging_Final Data └───LWD ├───CGM │ NDB-024 Deep Resistivity LWD Final MD.cgm │ NDB-024 Deep Resistivity LWD Final TVD.cgm │ ├───Definitive Survey │ NDB-024 Surveys from Santos.xlsx │ ├───EMF │ NDB-024 Deep Resistivity LWD Final MD.emf │ NDB-024 Deep Resistivity LWD Final TVD.emf │ LETTER OF TRANSMITTAL ├───LWD Data │ NDB-024 LWD Resistivity Final.las │ NDB-024_EarthStar_Images.dlis │ NDB-024_EarthStar_Images.ver │ NDB-024_Stratastar_Images.dlis │ NDB-024_Stratastar_Images.ver │ ├───PDF │ NDB-024 Deep Resistivity LWD Final MD.pdf │ NDB-024 Deep Resistivity LWD Final TVD.pdf │ └───TIFF NDB-024 Deep Resistivity LWD Final MD.tif NDB-024 Deep Resistivity LWD Final TVD.tif LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-024PB1 (50-103-20862-7000) 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: 11/30/2023 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl 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: PTD: 223-076 T38163 12/1/2023 Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.01 09:57:29 -09'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-024PB1 Final Compass Survey - NAD27.pdf ؒ NDB-024PB1 Final Compass Survey.pdf ؒ NDB-024PB1-NAD27.txt ؒ NDB-024PB1.txt ؒ NDB-024PB1.xlsx ؒ جؐؐؐLog Digital Data and Plots (LWD) ؒ ؤؐؐؐLWD ؒ جؐؐؐDigital Data ؒ ؒ NDB-024PB1_AP_R01_RM_20230918.las ؒ ؒ NDB-024PB1_AP_R04_RM_20231001.las ؒ ؒ NDB-024PB1_DMD_RM_3181ft.las ؒ ؒ NDB-024PB1_DMT_R01_RM_20230918.las ؒ ؒ NDB-024PB1_DMT_R04_RM_20231001.las ؒ ؒ NDB-024PB1_LWD_RM_3181ft.las ؒ ؒ ؒ ؤؐؐؐGraphics ؒ NDB-024PB1_AP_RM_20231002.cgm ؒ NDB-024PB1_AP_RM_20231002.pdf ؒ NDB-024PB1_DMD_RM_3181ft.cgm ؒ NDB-024PB1_DMD_RM_3181ft.pdf ؒ NDB-024PB1_DMT_RM_2023102.cgm ؒ NDB-024PB1_DMT_RM_2023102.pdf ؒ NDB-024PB1_LWD_RM_3181ft_2MD.cgm ؒ NDB-024PB1_LWD_RM_3181ft_2MD.pdf ؒ NDB-024PB1_LWD_RM_3181ft_2TVD.cgm ؒ NDB-024PB1_LWD_RM_3181ft_2TVD.pdf ؒ NDB-024PB1_LWD_RM_3181ft_5MD.cgm ؒ NDB-024PB1_LWD_RM_3181ft_5MD.pdf ؒ NDB-024PB1_LWD_RM_3181ft_5TVD.cgm ؒ NDB-024PB1_LWD_RM_3181ft_5TVD.pdf ؒ ؤؐؐؐMudlog جؐؐؐGeological Reports (compilation in PDF) ؒ NDB-024 & NDB-024PB1 Geological Reports.pdf ؒ ؤؐؐؐMudlogging final data NDB-024PB1_DrillGas_depth_3181ft MD.las LETTER OF TRANSMITTAL NDB-024PB1_GasRatioLog_2''_3181ft MD.pdf NDB-024PB1_GasRatioLog_5''_3181ft MD.pdf NDB-024PB1_Mudlog_2''_3181ft MD.pdf NDB-024PB1_Mudlog_5''_3181ft MD.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-024 (50-103-20862-0000) 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: 11/30/2023 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl 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: PTD: 223-076 T38162 12/1/2023 Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.01 09:56:23 -09'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-024 - NAD27.txt ؒ NDB-024 Final Compass Survey - NAD27.pdf ؒ NDB-024 Final Compass Survey.pdf ؒ NDB-024 Plan View.pdf ؒ NDB-024 Vertical Section.pdf ؒ NDB-024.txt ؒ NDB-024.xlsx ؒ جؐؐؐLog Digital Data (LWD and WL) ؒ جؐؐؐCement Evaluation Logs ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_CBL.cgm ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_CBL.dlis ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_CBL.las ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_CBL.PDF ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_CBL_dlis.txt ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_TOC.cgm ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_TOC.dlis ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_TOC.las ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_TOC.PDF ؒ ؒ NDB-024_LWD_R07_1250ft_11470ft_SDTK_MEM_TOC_dlis.txt ؒ ؒ ؒ ؤؐؐؐLWD ؒ جؐؐؐDigital Data ؒ ؒ NDB-024_AP_R05_RM_20231002.las ؒ ؒ NDB-024_AP_R06_RM_20231014.las ؒ ؒ NDB-024_AP_R07_RM_20231027.las ؒ ؒ NDB-024_DMD_RM_18092ft.las ؒ ؒ NDB-024_DMT_R05_RM_20231002.las ؒ ؒ NDB-024_DMT_R06_RM_20231014.las ؒ ؒ NDB-024_DMT_R07_RM_20231027.las ؒ ؒ NDB-024_LWD_RM_18029ft.las ؒ ؒ ؒ ؤؐؐؐGraphics ؒ NDB-024_AP_RM_20231027.cgm ؒ NDB-024_AP_RM_20231027.pdf ؒ NDB-024_DMD_RM_18092ft.cgm ؒ NDB-024_DMD_RM_18092ft.pdf ؒ NDB-024_DMT_RM_20231027.cgm LETTER OF TRANSMITTAL ؒ NDB-024_DMT_RM_20231027.pdf ؒ NDB-024_LWD_RM_18029ft_2MD.cgm ؒ NDB-024_LWD_RM_18029ft_2MD.pdf ؒ NDB-024_LWD_RM_18029ft_2TVD.cgm ؒ NDB-024_LWD_RM_18029ft_2TVD.pdf ؒ NDB-024_LWD_RM_18029ft_5MD.cgm ؒ NDB-024_LWD_RM_18029ft_5MD.pdf ؒ NDB-024_LWD_RM_18029ft_5TVD.cgm ؒ NDB-024_LWD_RM_18029ft_5TVD.pdf ؒ ؤؐؐؐMudlog جؐؐؐGeological Reports (compilation in PDF) ؒ NDB-024 & NDB-024PB1 Geological Reports.pdf ؒ جؐؐؐMudlogging final data ؒ NDB-024_DrillGas_depth_with Litho_18029ft MD_Final.las ؒ NDB-024_G5_Corrected Composite_11465-18029 ft_2inch.pdf ؒ NDB-024_GasRatioLog_2''_18029ft MD.pdf ؒ NDB-024_GasRatioLog_5''_18029ft MD.pdf ؒ NDB-024_LithologyFinal.xlsx ؒ NDB-024_Mudlog_2''_18029ft MD.pdf ؒ NDB-024_Mudlog_5''_18029ft MD.pdf ؒ ؤؐؐؐOil, Gas and Gas Hydrate Shows List Show Report Geolog_NDB-024_11891-11951_#2.pdf Show Report Geolog_NDB-024_11986-12056_#3.pdf Show Report Geolog_NDB-024_12740-12800_#4.pdf Show Report Geolog_NDB-024_13170-13220_#5.pdf Show Report Geolog_NDB-024_13620-13680_#6.pdf Show Report Geolog_NDB-024_15500-15550_#7.pdf Show Report Geolog_NDB-024_15785-15825_#8.pdf Show Report Geolog_NDB-024_16405-16445_#9.pdf Show Report Geolog_NDB-024_16628-16678_#10.pdf Show Report Geolog_NDB-024_16935-16995_#11.pdf Show Report Geolog_NDB-024_17060-17120_#12.pdf Show Report Geolog_NDB-024_17495-17545_#13.pdf Show Report Geolog_NDB-024_17950-18000_#14.pdf Show Report Geolog_NDB-024_4400-4430_#01.pdf aa3--off RECEIVE® LETTER OF TRANSMITTAL NUv 0 6 2023 /661 Santos J (6Co Z- Psl DATE: 11/14/2023 From: Shannon Koh Meredith Guhl Santos AOGCC P.O. Box 240927 333 W. 7th Avenue, Suite 100 Anchorage, AK 99524-0927 Anchorage, AK 99501 TRANSMISSION TYPE: TRANSMISSION METHOD: NExternal Request ❑CD ❑ Thumb Drive ❑Internal Request ❑Email ❑SharePoint/Teams ❑ Hardcopy NOther — Dry cutting samples REASON FOR TRANSMITTAL: ❑To Be Returned ❑Approved El Information Only ❑Approved with Comments ❑For Your Review ❑With Our Comments El For Approval NFor Your Use ❑Other COMMENTS: DETAIL CITY DESCRIPTION NDB-024 (50-103-20862-0000) 1018 38 50 125'-2000' 9 boxes of washed and dried cutting samples 2of8 46 50' 2000'-4300' 3 of 8 44 50 4300'-6500' 4018 45 50 6500'-8750' Washed and Dried 5 of 8 50 50' 8750'-11200' 6 of 8 47 50' 11200'-13506 7 of B 40 50 13500'-15500' 8 of 8 1 51 50 15500'-18029" NDB-024 P131 (50-103-20862-7000) l e 1 I 5 I Washed and Dried 1 50 1 2687'--3181' 123�MS' `( 12 Received by: Date: leas n and return one copy to: Santos ATTN:Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com GEOLOGwNing but ,KQS i Dr1Hin� Soiutior,; Lab Studies innovation Hub 0 6 2023 Santos DRILL CUTTINGS SAMP� 1 S WELL NAME: NDB-024 WELL API : 50-103-20862-00-00 Date Drilled FROM: 9/16/2023 ITO 10/25/23 Area/Location : North Slope Borough OVEN DRIED SAMPLES (SET C) Box 1 Box 2 Box 3 Box 4 Box 5 Box 6 Box 7 Box 8 1 150 2050 4350 6550 8800 11250 13550 15550 2 200 2100 4400 6600 8850 11300 13600 15600 3 250 2150 4450 6650 8900 11350 13650 15650 4 300 2200 4500 6700 8950 11400 13700 15700 5 350 2250 4550 6750 9000 11450 13750 15750 6 400 2300 4600 6800 9050 11500 13800 15800 7 450 2350 4650 6850 9100 11550 13850 15850 8 500 2400 4700 6900 9150 11600 13900 15900 9 550 2450 4750 6950 9200 11650 13950 15950 10 600 2500 4800 7000 9250 11700 14000 16000 11 650 2550 4850 7050 9300 11750 14050 16050 12 700 2600 4900 7100 9350 11800 14100 16100 13 750 2650 4950 7150 9400 11850 14150 16150 14 800 2700 5000 7200 9450 11900 14200 16200 15 850 2750 5050 7250 9500 11950 14250 16250 16 900 2800 5100 7300 9550 12000 14300 16300 17 950 2850 5150 7350 9600 12050 14350 16350 18 1000 2900 5200 7400 9650 12100 14400 16400 19 1050 2950 5250 7450 9700 12150 14450 16450 20 1100 3000 5300 7500 9750 12200 14500 16500 21 1 1150 3050 5350 7550 9800 12250 14550 16550 22 1200 3100 5400 7600 9850 12300 14600 16600 23 1250 3150 5450 7650 9900 12350 14650 16650 24 1300 3200 5500 7700 9950 12400 14700 16700 25 1350 3250 5550 7750 10000 12450 14750 16750 26 1400 3300 5600 7800 10050 12500 14800 16800 27 1450 3350 5650 7850 10100 12550 14850 16850 28 1500 3400 5700 7900 10150 12600 14900 16900 29 1550 3450 5750 7950 10200 12650 14950 16950 30 1600 3500 5800 8000 10250 12700 15000 17000 31 1650 3550 5850 8050 10300 12750 15050 17050 32 1700 3600 5900 8100 10350 12800 15100 17100 33 1750 3650 5950 8150 10400 12850 15150 17150 34 1800 3700 6000 8200 10450 12900 15200 17200 35 1850 3750 6050 8250 10500 12950 15250 17250 36 1900 3800 6100 8300 10550 13000 15300 17300 37 1 1950 3850 6150 8350 10600 13050 15350 17350 38 2000 3900 6200 8400 10650 13100 15400 17400 39 3950 1 6250 8450 10700 13150 15450 17450 40 1 4000 6300 8500 10750 13200 15500 17500 41 4050 6350 8550 10800 13250 17550 42 4100 6400 8600 10850 13300 17600 43 4150 6450 8650 10900 13350 17650 44 4200 6500 8700 10950 13400 17700 45 4250 8750 11000 13450 17750 46 4300 11050 13500 17800 47 11100 17850 48 11150 17900 49 11200 17950 50 18000 51 18029 52 53 54 55 56 Preparation Date: 10/26/2023 Prepared By: Geolog Contact lab327g eolog.com GEOLOG Surface Logging Servkes DrIling Solutlons Lab Studies Innwa2lon Hub DRILL CUTTINGS SAMPLE MANIFEST Santos WELL NAME: NDB-024 WELL API : 50-103-20862-00-00 Date Drilled : FROM: 9/16/2023 TO 10/25/23 Area/Location North Slope Borough OVEN DRIED SAMPLES (SET C) Box 1 Box 2 Box 3 Box 4 Box 5 Box 6 Box 7 Box 8 1 2750 2 2800 3 2850 4 2900 5 2950 6 3000 7 3050 8 3100 9 3181 Preparation Date: 10/26/2023 Prepared By. Geolog Contact: lab327C&geoloq.com From:McLellan, Bryan J (OGC) To:Staudinger, Garret (Garret) Subject:RE: NDB-024 (PTD 223-076) 9-5/8" Intermediate Tieback Operational Change Date:Tuesday, October 17, 2023 5:53:00 AM Garret, Oilsearch has approval to proceed with the change to the approved PTD, to cement the 9-5/8” tieback as outlined in your emails below. 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: Monday, October 16, 2023 2:33 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDB-024 (PTD 223-076) 9-5/8" Intermediate Tieback Operational Change Bryan, We are planning 170 bbls of 15.8ppg Type I/II (Yield 1.15cuft/sk) cement for the tieback. Updated proposed schematic is attached. Thanks, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, October 16, 2023 9:13 AM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) 9-5/8" Intermediate Tieback Operational Change Garret, Please send cement volumes, type of cement and updated proposed wellbore diagram. 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. 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: Friday, October 6, 2023 9:56 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDB-024 (PTD 223-076) 9-5/8" Intermediate Tieback Operational Change Bryan, I wanted to let you know that we are planning to cement our 9-5/8” intermediate tieback when we run it (after the 9-5/8” intermediate liner run). The 13-3/8” casing has a restriction at ~1065’ MD from what we believe is due to very hard formation behind pipe potentially causing a micro dog leg. We are able to pass full gauge tools through this, but have to work long, stiff, large OD assemblies through this area. Because of this, we elected to run the tri-mill window milling assembly (20’ long and 12.25” OD) as a drift run prior to running the whipstock. We had to work these mills through this area to get it to cleanly pass through. The whipstock (40’ long and 11.5” OD) also took weight to get through this area, but we were able to get it through. This is the same depth at we had to work our casing through on the surface pipe run and eventually caused the failed connection that resulted in the issues on the surface cement job. Cementing the 9-5/8” tieback will be done as a mitigation to prevent any long term integrity issues through this section, as cementing is most easily and effectively completed during well construction while we still have good integrity in our surface casing. Please let me know if you have any questions. Thanks, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | 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 923Disclaimer: 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 NDB-024 GL 20" Insulated Conductor128' MD 9-5/8" Liner Top Packer2,456' MD Top of 13-3/8" Whipstock2,675' MD 1-½” GLM Shear Valve~2,400' MD 4-½” X-Nipple~2,440' MD 4-½” X-Nipple~11,284' MD 9-5/8", 47ppf L-80 Production Liner11,591' MD 4-½”, 12.6ppf P-110S Production Liner 18,045' MD 4-½” Liner Hanger and Liner Top Packer11,441' MD 4-½” 12.6ppf P-110S Completion w/ Tieback Seals11,436' MD 4-½” X-Nipple~11,424' MD 4-½” Openhole Packers one every 500' -700' with Frac Ports Toe Sleeve Shutoff Collar *Quantity of openhole packer and frac sleeve may change 4-½” Gaslift Sliding Sleeve (Contingency)~11,376' MD Archer C-Flex Two-Stage Cementing Tool5,550' MD TOC First Stage Cement Job - 250' TVD above Nanushuk~9,100' MD 16" Hole Size 12-1/4" Hole Size 8-1/2" Hole Size 4-½” Gaslift w/ Downhole Psi/Temp Gauge~11,328' MD 13-3/8" Casing Fish 2847'-3181' MD 13-3/8" 68ppf L80 Casing Severed at 2837' NDB-024 PB1 Updated 10/16/2023 9-5/8" ES Cementer2,446' MD 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 Clean Up 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:N/A 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?NDB-024 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): 3181' Casing Collapse Structural Conductor Surface 2260 Intermediate 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: 1-907-646-7063 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 2287' Subsequent Form Required: Suspension Expiration Date: 6870 5020 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 Length Size AOGCC USE ONLY 11590 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, 393020, 391455, 393018, 391445 223-076 900 E Benson Boulevard, Anchorage, AK 99508 50-103-20862-00-00 Oil Search Alaska, LLC TVD Burst 11590 MD 4163'11441 11591 Proposed Pools: 9-5/8"11591 2675 128' 2153 4143 128' 2675 10/28/23 180506609 4065' 20"x34" 13-3/8" 128' Perforation Depth MD (ft): 11441 4-1/2" 4-1/2" 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 S ilit 10/04/2023 By Grace Christianson at 8:43 am, Oct 05, 2023 Fracture Stimulate 10/28/23 See new 10-403. 11/1/2023 323-591 10- 407 BJM 11/8/23 CDW 11/08/2023 SFD 11/8/2023 DSR-11/6/23*&:JLC 11/14/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.14 14:32:02 -09'00'11/14/23 Page 1 of 22 NDB-024 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 – Attachments B and F 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-024. At the NDB-024 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- 024 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 – Assessment of casing and cementing operations will be performed after cementing operations are complete. 7. Casing and tubing pressure test information – Pressure testing will be performed upon completion of the well’s lateral section.Attachment J 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachment D 9. a-d Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 1,020 feet (ft) total vertical depth subsea (TVDSS)/1,020 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: 1,020 to 2,300 ft TVDSS/1,280 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: 2,300 to 3,150 ft TVDSS/850 ft thick 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. Seabee Formation Depth/Thickness: 3,150 to 3,750 ft TVDSS/600 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: 3,750 to 4,690 ft TVDSS/940 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 (Exhibit B-10). 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. Upper Confining Zone Name: Upper Torok Formation (Hue Shale) Depth/Thickness: 4,690 to 5,590 ft TVDSS/900 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 nearly devoid of sand and is composed primarily of shale (Hue Shale) with some thin interbedded siltstones, thereby forming an excellent overlying confining seal above the Lower Torok injection zone. 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. Lower Confining Zone Name: Highly Radioactive Zone (HRZ) Hue Shale Depth/Thickness: 6,075 to 6,245 ft TVDSS/170 ft thick Lithological Description: Below the sandy interval of the Lower Torok is the Lower Torok arresting zone, which is approximately 100 feet thick and composed of siltstone and shale. This, in turn, is underlain by the HRZ (Hue Shale) Fm confining interval, which is approximately up to 225-foot-thick condensed marine shale. These units will provide an excellent underlying confining seal. e. Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Stages 1-11 3300 3600 8400 7600 Surface Line Pressure Test 9000 psi. CDW 11/1/2023 Fracture gradient values for each stage are listed in detail within Appendix G. 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: Sale gradient- 0.69 psi/ft 10.Mechanical condition of wells transecting the confining zones – NDB-032 and NDBi-043 are within 1/2-mile radius of NDB-024. Please see Attachment B as reference. Location of faults and fractures in wellbore ½ mile radius – Based on the seismic and well data covering the NDB-024 location, there could be a fault crossing in the NT7/6 within the intermediate hole section. Intersection with fault plane in the intermediate hole section is near a fault tip out. A potential reservoir fault crossing in the lateral also exists at approximately 13000’ MD. This fault plane is near a fault tip out and the incidence angle is low. The fault within the lateral will Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Max Pressure (psi) Max Prop Conc. (PPA) 1 17765 4165.2 217 405.1 40 6933 8 2 17278 4172.9 217.4 417.5 40 6813 8 3 16790 4180.5 215.8 407.2 40 6663 8 4 16302 4188.1 241.6 283.8 40 6591 10 5 15814 4195.6 230.8 310.8 40 6386 10 6 15285 4203.9 232 322.3 40 6199 10 7 14756 4212.1 227 311.3 40 6096 12 8 14227 4219.3 231.2 329.7 40 5899 12 9 13698 4219.3 230.9 323.6 40 5584 10 10 12533 4219.3 233.6 263.2 40 5127 10 11 12045 4219.1 239.9 297.7 40 5015 12 .Mechanical condition of wells transecting the confining zones – be isolated with zonal isolation packers and the frac ports will be placed > 450’ away from the fault intersection with the wellbore. 11.Suspected fault or fracture that may transect the confining zones. There is a suspected fault or fracture expected to transect the production section or reservoir confining zone (NT3 MFS) for NDB-024. 12.Detailed proposed fracturing program –Attachments G & H 13.Well Clean Up procedure –Attachment I Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment J Section (d) Pressure Relieve Valve –Attachment K Proposed Wellbore Schematic –Attachment L Attachment A AD L 3 9 2 9 9 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 1 . 5 8 % D N R - 5 8 . 4 2 % AD L 3 9 2 9 6 3 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 8 4 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 6 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 5 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 6 . 3 1 % D N R - 6 3 . 6 9 % AD L 3 9 2 9 7 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 0 . 2 9 % D N R - 5 9 . 7 1 % AD L 3 9 3 0 2 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 1 9 . 2 2 % D N R - 8 0 . 7 8 % AD L 3 9 3 0 1 9 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 % D N R - 6 6 . 9 % AD L 3 9 3 0 1 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 9 . 6 7 % D N R - 7 0 . 3 3 % AD L 3 9 3 0 2 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 6 . 5 9 % D N R - 7 3 . 4 1 % AD L 3 9 3 0 1 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 1 . 6 9 % D N R - 6 8 . 3 1 % AD L 3 9 3 0 1 7 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 3 0 1 6 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 7 % D N R - 6 6 . 8 3 % AD L 3 9 3 0 0 7 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 4 . 3 5 % D N R - 6 5 . 6 5 % AD L 3 9 3 0 0 8 Su r f a c e O w n e r s : Ku u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 8 . 2 9 % D N R - 7 1 . 7 1 % AD L 3 9 1 3 2 2 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 8 . 2 5 % D N R - 7 1 . 7 5 % AD L 3 9 1 4 4 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 1 . 9 8 % D N R - 5 8 . 0 2 % AD L 3 9 1 4 5 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 6 . 4 % D N R - 5 3 . 6 % AD L 3 9 3 0 1 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 5 . 7 1 % D N R - 7 4 . 2 9 % AD L 3 9 3 0 1 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 8 . 5 4 % D N R - 6 1 . 4 6 % OI L S E A R C H ( A L A S K A ) , L L C A S U B S I D I A R Y O F S A N T O S L T D ND B 0 2 4 W E L L A R E A TA R G E T BO T T O M H O L E SU R F A C E L O C A T I O N WE L L T R A J E C T O R Y LE A S E S B O U N D A R Y KU U K P I K B O U N D A R Y .5 - M I L E B U F F E R TO W N S H I P SE C T I O N DA T E : 7 / 1 4 / 2 0 2 3 . R E V : 1 . 0 . B y : J B 0 5 0 0 1 , 0 0 0 US F e e t Pr o j e c t : A P - D R L - G E N _ a s s o r t e d La y o u t : A P - D R L - P E - M _ N D B 0 2 4 _ w e l l _ o w n e r s h i p GC S : N A D 1 9 8 3 S t a t e P l a n e A l a s k a 4 F I P S 5 0 0 4 F e e t 0 2 0 0 4 0 0 Me t e r s PI K K A P R O J E C T ND B Attachment B Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensile (klbs) ID (in) Drift ID (in) Connectio n 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 – STAGE 1 Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess Lead TOC 250’ TVD above top Nanushuk Tail Open hole volume + 30% excess + 80 ft shoe track Tail TOC 1000 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead 13.0ppg Lead: 110bbls, 617cuft, 335sks EconoCem, Yield: 1.84 cuft/sk Tail 15.3ppg Tail: 80bbls, 449cuft, 365sks VersaCem Type I/II – 1.23 cuft/sk Temp BHST 94° F Verification Method Sonic LWD Log Notes Job will be mixed on the fly Intermediate Liner Cement – STAGE 2 Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 50% excess + 150’ liner lap + 200’ above liner top Lead TOC Top of the 9-5/8” Liner Tail Open hole volume + 50% excess Tail TOC 4500 ft MD (~2050 ft MD above two stage cementing stage collar) Total Cement Volume Spacer ~80 bbls of 12.0 ppg Clean Spacer Lead 13.0ppg Lead: 137bbls, 769cuft, 418sks EconoCem, Yield: 1.84 cuft/sk Tail 15.3ppg Tail: 172bbls, 965cuft, 785sks VersaCem Type I/II – 1.23 cuft/sk Temp BHST 74° F Verification Method Cement returns off top of liner Notes Job will be mixed on the fly First Stage Cement Job 1. Pump the cement job as per Halliburton Cementing Program. a) Cement job is planned to be pumped as follows: i. 12.5ppg Tuned Spacer ii. Release lead Pump Down Plug (PDP) iii. 13.0ppg Lead EconoCem Slurry iv. 15.3ppg Tail Type I/II Slurry v. Release follow PDP vi. 5-10 bbls water to clean cementing lines vii. Final displacement with 12.0 ppg VersaClean b) Final volumes and rates will be detailed in the Halliburton Cement Program. Displacement will be performed with the rig pumps. Follow outlined displacement rates unless operations issues are encountered (lost circulation, surface constraints, etc). c) Lead Liner Wiper Plug shears at 1,000 psi, Follow Liner Wiper Plug shears at 1,200 psi. Ensure pump rate is >3bpm when Pump Down Plugs reach Liner Wiper Plugs. d) Slow pump rate to 3 bpm as follow wiper plug nears bump. Bump the wiper plug with 500psi over pump pressure to ensure proper plug seat. Bleed pressure to verify floats are holding. Second Stage Cement Job 2. Pump the cement job as per Halliburton Cementing Program. a) Cement job is planned to be pumped as follows: i. 12.5ppg Tuned Spacer ii. 13.0ppg Lead EconoCem Slurry iii. 15.3ppg Tail Type I/II Slurry iv. Final displacement with 12.0 ppg VersaClean b) Final volumes and rates will be detailed in the Halliburton Cement Program. Displacement will be performed with the rig pumps. Follow outlined displacement rates unless operations issues are encountered (lost circulation, surface constraints, etc). c) Slow pump rate to 3 bpm at end of calculated displacement. Attachment D Attachment E Redacted Attachment G FracCADE* STIMULATION PROPOSAL Operator :Santos Well :NDB-24 Field :Pikka Formation :Nanushuk Stages 1 to 11 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 : 09-25-2023 FAX No. : 1 907 659 2538 Prepared by : Laura Acosta Phone : E-Mail Address :NTrevino2@slb.com * Mark of Schlumberger +1832-454-1427 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. # SLB-Private 1 of 45 Attachment G Section 1: Zone Data (Stage 1; 17765 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 4102.0 3.0 0.72 2937 1.46E+06 0.220 2500 Shale 4112.0 4.6 0.70 2863 1.76E+06 0.220 2500 Nanushuk 3 SS 4127.0 4.7 0.68 2803 1.90E+06 0.220 2000 Top Nan 4142.3 1.8 0.63 2630 8.39E+05 0.273 1000 SHALE 4148.3 0.6 0.69 2858 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4150.3 0.5 0.62 2584 8.19E+05 0.273 1500 DIRTY-SANDSTONE 4151.8 0.6 0.63 2615 1.22E+06 0.265 1500 CLEAN-SANDSTONE 4153.8 4.0 0.62 2562 8.69E+05 0.272 1000 CLEAN-SANDSTONE 4166.8 0.5 0.61 2524 1.00E+06 0.269 1000 CLEAN-SANDSTONE 4168.3 1.2 0.63 2630 7.07E+05 0.276 1000 CLEAN-SANDSTONE 4172.3 2.7 0.61 2535 1.17E+06 0.266 1000 CLEAN-SANDSTONE 4181.3 2.1 0.64 2659 7.69E+05 0.274 1000 CLEAN-SANDSTONE 4188.3 1.7 0.61 2543 1.28E+06 0.264 1000 CLEAN-SANDSTONE 4193.8 4.0 0.63 2665 6.92E+05 0.276 1000 DIRTY-SANDSTONE 4206.8 0.8 0.67 2817 1.75E+06 0.256 1500 DIRTY-SANDSTONE 4209.3 3.8 0.63 2649 1.11E+06 0.267 1500 DIRTY-SANDSTONE 4221.8 1.2 0.68 2891 1.69E+06 0.257 1500 DIRTY-SANDSTONE 4225.8 0.8 0.63 2675 8.22E+05 0.273 1500 SHALE 4228.3 0.6 0.69 2913 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4230.3 1.2 0.64 2710 1.16E+06 0.266 1500 DIRTY-SANDSTONE 4234.3 1.2 0.62 2624 8.38E+05 0.273 1000 SHALE 4238.3 1.2 0.69 2921 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4242.3 1.8 0.63 2682 1.13E+06 0.267 1500 SHALE 4248.3 0.6 0.69 2927 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4250.3 0.6 0.61 2614 1.08E+06 0.268 1500 DIRTY-SANDSTONE 4252.3 2.0 0.65 2781 1.69E+06 0.257 1500 DIRTY-SANDSTONE 4258.8 1.2 0.60 2576 8.99E+05 0.271 1500 DIRTY-SANDSTONE 4262.8 1.1 0.64 2711 9.29E+05 0.271 1500 SHALE 4266.3 0.6 0.69 2939 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4268.3 3.8 0.63 2698 1.56E+06 0.259 1500 DIRTY-SANDSTONE 4280.8 0.6 0.64 2747 1.40E+06 0.262 1500 SHALE 4282.8 0.6 0.69 2951 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4284.8 0.6 0.65 2790 1.24E+06 0.265 1500 SHALE 4286.8 2.4 0.69 2956 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4294.8 0.6 0.63 2690 9.33E+05 0.271 1500 SHALE 4296.8 1.2 0.69 2961 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4300.8 1.8 0.65 2780 1.43E+06 0.261 1500 SHALE 4306.8 2.4 0.69 2969 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4314.8 2.0 0.64 2766 1.47E+06 0.261 1500 SHALE 4321.3 1.8 0.69 2979 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4327.3 0.6 0.63 2726 8.38E+05 0.273 1000 SHALE 4329.3 0.6 0.69 2983 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4331.3 1.2 0.65 2817 1.47E+06 0.261 1500 SHALE 4335.3 0.6 0.69 2987 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4337.3 1.8 0.66 2849 1.55E+06 0.259 1500 SHALE 4343.3 3.7 0.69 2996 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4355.3 0.8 0.63 2754 1.21E+06 0.265 1500 SHALE 4357.8 6.1 0.69 3009 2.67E+06 0.232 2500 Zone Name Poisson’s Ratio Formation Mechanical Properties # SLB-Private 2 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4102.0 3.0 0.001 1.0 1881 4112.0 4.6 0.001 1.0 1886 4127.0 4.7 0.005 10.0 1890 4142.3 1.8 56.445 22.0 1882 4148.3 0.6 0.001 1.0 1884 4150.3 0.5 109.347 15.0 1885 4151.8 0.6 4.377 15.0 1886 4153.8 4.0 42.829 22.0 1887 4166.8 0.5 11.097 22.0 1893 4168.3 1.2 91.857 22.0 1894 4172.3 2.7 4.906 22.0 1896 4181.3 2.1 12.361 22.0 1900 4188.3 1.7 2.537 22.0 1903 4193.8 4.0 61.847 22.0 1906 4206.8 0.8 0.081 15.0 1912 4209.3 3.8 22.858 15.0 1913 4221.8 1.2 0.018 15.0 1919 4225.8 0.8 94.329 15.0 1920 4228.3 0.6 0.001 1.0 1922 4230.3 1.2 45.186 15.0 1922 4234.3 1.2 24.865 15.0 1924 4238.3 1.2 0.001 1.0 1926 4242.3 1.8 6.405 15.0 1928 4248.3 0.6 0.001 1.0 1931 4250.3 0.6 13.686 15.0 1932 4252.3 2.0 0.229 15.0 1933 4258.8 1.2 49.420 15.0 1936 4262.8 1.1 63.759 15.0 1938 4266.3 0.6 0.001 1.0 1939 4268.3 3.8 1.337 15.0 1940 4280.8 0.6 1.843 15.0 1946 4282.8 0.6 0.001 1.0 1947 4284.8 0.6 4.320 15.0 1948 4286.8 2.4 0.001 1.0 1949 4294.8 0.6 91.060 15.0 1952 4296.8 1.2 0.001 1.0 1953 4300.8 1.8 4.551 15.0 1955 4306.8 2.4 0.001 1.0 1958 4314.8 2.0 7.953 15.0 1962 4321.3 1.8 0.001 1.0 1965 4327.3 0.6 24.687 15.0 1967 4329.3 0.6 0.001 1.0 1968 4331.3 1.2 2.159 10.0 1969 4335.3 0.6 0.001 1.0 1971 4337.3 1.8 1.534 10.0 1972 4343.3 3.7 0.001 1.0 1975 4355.3 0.8 5.632 10.0 1980 4357.8 6.1 0.001 1.0 1982 SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE # SLB-Private 3 of 45 Attachment G Section 2: Propped Fracture Schedule (Stage 1; 17765 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 13650.0 22 0 1.0 PPA 40 YF122ST 5029.9 22 1 2.0 PPA 40 YF122ST 5406.8 22 2 3.0 PPA 40 YF122ST 5940.1 22 3 4.0 PPA 40 YF122ST 6076.3 22 4 5.0 PPA 40 YF122ST 5858.1 22 5 6.0 PPA 40 YF122ST 5655.1 22 6 7.0 PPA 40 YF122ST 4018.8 22 7 8.0 PPA 40 YF122ST 3421.9 22 8 Flush 40 WF122 11366.2 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1310.9 bbl of YF122ST 270.6 bbl of WF122 176697 lb of % PAD Clean 24.8 % PAD Dirty 21.7 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 325.0 325 325 325 0 0 4435 8.1 8.1 1.0 PPA 119.8 445 125 450 5030 5030 4448 3.1 11.3 2.0 PPA 128.7 573 140 590 10814 15843 4488 3.5 14.8 3.0 PPA 141.4 715 160 750 17820 33664 4749 4.0 18.8 4.0 PPA 144.7 860 170 920 24305 57969 5188 4.3 23.0 5.0 PPA 139.5 999 170 1090 29291 87259 5635 4.3 27.3 6.0 PPA 134.6 1134 170 1260 33930 121190 6055 4.3 31.5 7.0 PPA 95.7 1229 125 1385 28132 149322 6349 3.1 34.6 8.0 PPA 81.5 1311 110 1495 27375 176697 6550 2.8 37.4 Flush 270.6 1582 271 1766 0 176697 6741 6.8 44.1 Carbolite 16/20 + 4wt% ScaleGuard IV Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Pad Percentages Job Execution Step Name Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 405.1 ft with an average conductivity (Kfw) of 11904.2 md.ft. Job Description Fluid Name Prop. Type and Mesh # SLB-Private 4 of 45 Attachment G Section 3: Propped Fracture Simulation (Stage 1; ft MD) Initial Fracture Top TVD 4107.4 ft Initial Fracture Bottom TVD 4324.3 ft Propped Fracture Half-Length 405.1 ft EOJ Hyd Height at Well 217 ft Average Propped Width 0.139 in Net Pressure 347 psi Max Surface Pressure 6933 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) 0 101.3 7 0.154 112.6 1.35 234.6 13700 101.3 202.5 5.4 0.148 163.8 1.28 261.1 12732 202.5 303.8 4.9 0.147 154.9 1.31 263.6 12455 303.8 405.1 2 0.114 106.6 1.01 253.5 9532 Simulation Results by Fracture Segment 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. # SLB-Private 5 of 45 Attachment G 6933 psi Section 4: Zone Data (Stage 2; 17278 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 4102.6 3.0 0.72 2937 1.46E+06 0.220 2500 Shale 4112.6 4.6 0.70 2863 1.76E+06 0.220 2500 Nanushuk 3 SS 4127.6 4.7 0.68 2804 1.90E+06 0.220 2000 Top Nan 4142.9 1.8 0.63 2630 8.39E+05 0.273 1000 SHALE 4148.9 0.6 0.69 2858 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4150.9 0.5 0.62 2585 8.19E+05 0.273 1500 DIRTY-SANDSTONE 4152.4 0.6 0.63 2616 1.22E+06 0.265 1500 CLEAN-SANDSTONE 4154.4 4.0 0.62 2562 8.69E+05 0.272 1000 CLEAN-SANDSTONE 4167.4 0.5 0.61 2525 1.00E+06 0.269 1000 CLEAN-SANDSTONE 4168.9 1.2 0.63 2630 7.07E+05 0.276 1000 CLEAN-SANDSTONE 4172.9 2.7 0.61 2535 1.17E+06 0.266 1000 CLEAN-SANDSTONE 4181.9 2.1 0.64 2659 7.69E+05 0.274 1000 CLEAN-SANDSTONE 4188.9 1.7 0.61 2544 1.28E+06 0.264 1000 CLEAN-SANDSTONE 4194.4 4.0 0.63 2666 6.92E+05 0.276 1000 DIRTY-SANDSTONE 4207.4 0.8 0.67 2818 1.75E+06 0.256 1500 DIRTY-SANDSTONE 4209.9 3.8 0.63 2650 1.11E+06 0.267 1500 DIRTY-SANDSTONE 4222.4 1.2 0.68 2891 1.69E+06 0.257 1500 DIRTY-SANDSTONE 4226.4 0.8 0.63 2675 8.22E+05 0.273 1500 SHALE 4228.9 0.6 0.69 2914 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4230.9 1.2 0.64 2711 1.16E+06 0.266 1500 DIRTY-SANDSTONE 4234.9 1.2 0.62 2624 8.38E+05 0.273 1000 SHALE 4238.9 1.2 0.69 2921 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4242.9 1.8 0.63 2682 1.13E+06 0.267 1500 SHALE 4248.9 0.6 0.69 2927 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4250.9 0.6 0.61 2615 1.08E+06 0.268 1500 DIRTY-SANDSTONE 4252.9 2.0 0.65 2781 1.69E+06 0.257 1500 DIRTY-SANDSTONE 4259.4 1.2 0.60 2576 8.99E+05 0.271 1500 DIRTY-SANDSTONE 4263.4 1.1 0.64 2711 9.29E+05 0.271 1500 SHALE 4266.9 0.6 0.69 2940 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4268.9 3.8 0.63 2699 1.56E+06 0.259 1500 DIRTY-SANDSTONE 4281.4 0.6 0.64 2748 1.40E+06 0.262 1500 SHALE 4283.4 0.6 0.69 2951 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4285.4 0.6 0.65 2791 1.24E+06 0.265 1500 SHALE 4287.4 2.4 0.69 2956 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4295.4 0.6 0.63 2690 9.33E+05 0.271 1500 SHALE 4297.4 1.2 0.69 2961 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4301.4 1.8 0.65 2780 1.43E+06 0.261 1500 SHALE 4307.4 2.4 0.69 2970 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4315.4 2.0 0.64 2766 1.47E+06 0.261 1500 SHALE 4321.9 1.8 0.69 2979 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4327.9 0.6 0.63 2726 8.38E+05 0.273 1000 SHALE 4329.9 0.6 0.69 2983 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4331.9 1.2 0.65 2818 1.47E+06 0.261 1500 SHALE 4335.9 0.6 0.69 2987 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4337.9 1.8 0.66 2849 1.55E+06 0.259 1500 SHALE 4343.9 3.7 0.69 2996 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4355.9 0.8 0.63 2754 1.21E+06 0.265 1500 SHALE 4358.4 6.1 0.69 3009 2.67E+06 0.232 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 6 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4102.6 3.0 0.001 1.0 1881 4112.6 4.6 0.001 1.0 1886 4127.6 4.7 0.005 10.0 1890 4142.9 1.8 56.445 22.0 1882 4148.9 0.6 0.001 1.0 1884 4150.9 0.5 109.347 15.0 1885 4152.4 0.6 4.377 15.0 1886 4154.4 4.0 42.829 22.0 1887 4167.4 0.5 11.097 22.0 1893 4168.9 1.2 91.857 22.0 1894 4172.9 2.7 4.906 22.0 1896 4181.9 2.1 12.361 22.0 1900 4188.9 1.7 2.537 22.0 1903 4194.4 4.0 61.847 22.0 1906 4207.4 0.8 0.081 15.0 1912 4209.9 3.8 22.858 15.0 1913 4222.4 1.2 0.018 15.0 1919 4226.4 0.8 94.329 15.0 1920 4228.9 0.6 0.001 1.0 1922 4230.9 1.2 45.186 15.0 1922 4234.9 1.2 24.865 15.0 1924 4238.9 1.2 0.001 1.0 1926 4242.9 1.8 6.405 15.0 1928 4248.9 0.6 0.001 1.0 1931 4250.9 0.6 13.686 15.0 1932 4252.9 2.0 0.229 15.0 1933 4259.4 1.2 49.420 15.0 1936 4263.4 1.1 63.759 15.0 1938 4266.9 0.6 0.001 1.0 1939 4268.9 3.8 1.337 15.0 1940 4281.4 0.6 1.843 15.0 1946 4283.4 0.6 0.001 1.0 1947 4285.4 0.6 4.320 15.0 1948 4287.4 2.4 0.001 1.0 1949 4295.4 0.6 91.060 15.0 1952 4297.4 1.2 0.001 1.0 1953 4301.4 1.8 4.551 15.0 1955 4307.4 2.4 0.001 1.0 1958 4315.4 2.0 7.953 15.0 1962 4321.9 1.8 0.001 1.0 1965 4327.9 0.6 24.687 15.0 1967 4329.9 0.6 0.001 1.0 1968 4331.9 1.2 2.159 10.0 1969 4335.9 0.6 0.001 1.0 1971 4337.9 1.8 1.534 10.0 1972 4343.9 3.7 0.001 1.0 1975 4355.9 0.8 5.632 10.0 1980 4358.4 6.1 0.001 1.0 1982 SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE CLEAN-SANDSTONE Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE CLEAN-SANDSTONE # SLB-Private 7 of 45 Attachment G Section 5: Propped Fracture Schedule (Stage 2; 17278 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 14700.0 22 0 1.0 PPA 40 YF122ST 5030.0 22 1 2.0 PPA 40 YF122ST 5793.0 22 2 3.0 PPA 40 YF122ST 6682.6 22 3 4.0 PPA 40 YF122ST 6433.7 22 4 5.0 PPA 40 YF122ST 6202.7 22 5 6.0 PPA 40 YF122ST 5987.7 22 6 7.0 PPA 40 YF122ST 4501.1 22 7 8.0 PPA 40 YF122ST 3733.0 22 8 Flush 40 WF122 11054.6 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1406.3 bbl of YF122ST 263.2 bbl of WF122 190710 lb of % PAD Clean 24.9 % PAD Dirty 21.8 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 350.0 350 350 350 0 0 4350 8.8 8.8 1.0 PPA 119.8 470 125 475 5030 5030 4356 3.1 11.9 2.0 PPA 137.9 608 150 625 11586 16616 4408 3.8 15.6 3.0 PPA 159.1 767 180 805 20048 36664 4694 4.5 20.1 4.0 PPA 153.2 920 180 985 25735 62399 5112 4.5 24.6 5.0 PPA 147.7 1068 180 1165 31014 93412 5493 4.5 29.1 6.0 PPA 142.6 1210 180 1345 35926 129338 5871 4.5 33.6 7.0 PPA 107.2 1317 140 1485 31508 160846 6195 3.5 37.1 8.0 PPA 88.9 1406 120 1605 29864 190710 6407 3.0 40.1 Flush 263.2 1669 263 1868 0 190710 6586 6.6 46.7 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 417.5 ft with an average conductivity (Kfw) of 12602.9 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 8 of 45 Attachment G Section 6: Propped Fracture Simulation (Stage 2; 17278 ft MD) Initial Fracture Top TVD 4108.1 ft Initial Fracture Bottom TVD 4325.6 ft Propped Fracture Half-Length 417.5 ft EOJ Hyd Height at Well 217.4 ft Average Propped Width 0.146 in Net Pressure 378 psi Max Surface Pressure 6813 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) 0 104.4 6.8 0.159 120.9 1.33 239.5 14196 104.4 208.7 5.4 0.157 171.8 1.37 255.4 13467 208.7 313.1 5.1 0.163 155.7 1.46 247.1 14037 313.1 417.5 2.3 0.114 110.4 1.01 319.4 9457 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 # SLB-Private 9 of 45 Attachment G Section 7: Zone Data (Stage 3; 16790 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 4106.1 3.0 0.71 2937 1.46E+06 0.220 2500 Shale 4116.1 4.6 0.70 2866 1.76E+06 0.220 2500 Nanushuk 3 SS 4131.1 4.7 0.68 2806 1.90E+06 0.220 2000 Top Nan 4146.4 1.8 0.63 2633 8.39E+05 0.273 1000 SHALE 4152.4 0.6 0.69 2861 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4154.4 0.5 0.62 2587 8.19E+05 0.273 1500 DIRTY-SANDSTONE 4155.9 0.6 0.63 2618 1.22E+06 0.265 1500 CLEAN-SANDSTONE 4157.9 4.0 0.62 2564 8.69E+05 0.272 1000 CLEAN-SANDSTONE 4170.9 0.5 0.61 2527 1.00E+06 0.269 1000 CLEAN-SANDSTONE 4172.4 1.2 0.63 2632 7.07E+05 0.276 1000 CLEAN-SANDSTONE 4176.4 2.7 0.61 2538 1.17E+06 0.266 1000 CLEAN-SANDSTONE 4185.4 2.1 0.64 2662 7.69E+05 0.274 1000 CLEAN-SANDSTONE 4192.4 1.7 0.61 2546 1.28E+06 0.264 1000 CLEAN-SANDSTONE 4197.9 4.0 0.63 2668 6.92E+05 0.276 1000 DIRTY-SANDSTONE 4210.9 0.8 0.67 2820 1.75E+06 0.256 1500 DIRTY-SANDSTONE 4213.4 3.8 0.63 2652 1.11E+06 0.267 1500 DIRTY-SANDSTONE 4225.9 1.2 0.68 2893 1.69E+06 0.257 1500 DIRTY-SANDSTONE 4229.9 0.8 0.63 2677 8.22E+05 0.273 1500 SHALE 4232.4 0.6 0.69 2916 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4234.4 1.2 0.64 2713 1.16E+06 0.266 1500 DIRTY-SANDSTONE 4238.4 1.2 0.62 2627 8.38E+05 0.273 1000 SHALE 4242.4 1.2 0.69 2924 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4246.4 1.8 0.63 2684 1.13E+06 0.267 1500 SHALE 4252.4 0.6 0.69 2930 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4254.4 0.6 0.61 2617 1.08E+06 0.268 1500 DIRTY-SANDSTONE 4256.4 2.0 0.65 2783 1.69E+06 0.257 1500 DIRTY-SANDSTONE 4262.9 1.2 0.60 2579 8.99E+05 0.271 1500 DIRTY-SANDSTONE 4266.9 1.1 0.64 2713 9.29E+05 0.271 1500 SHALE 4270.4 0.6 0.69 2942 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4272.4 3.8 0.63 2701 1.56E+06 0.259 1500 DIRTY-SANDSTONE 4284.9 0.6 0.64 2750 1.40E+06 0.262 1500 SHALE 4286.9 0.6 0.69 2954 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4288.9 0.6 0.65 2793 1.24E+06 0.265 1500 SHALE 4290.9 2.4 0.69 2958 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4298.9 0.6 0.63 2692 9.33E+05 0.271 1500 SHALE 4300.9 1.2 0.69 2964 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4304.9 1.8 0.65 2782 1.43E+06 0.261 1500 SHALE 4310.9 2.4 0.69 2972 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4318.9 2.0 0.64 2768 1.47E+06 0.261 1500 SHALE 4325.4 1.8 0.69 2981 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4331.4 0.6 0.63 2728 8.38E+05 0.273 1000 SHALE 4333.4 0.6 0.69 2986 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4335.4 1.2 0.65 2820 1.47E+06 0.261 1500 SHALE 4339.4 0.6 0.69 2990 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4341.4 1.8 0.66 2851 1.55E+06 0.259 1500 SHALE 4347.4 3.7 0.69 2999 2.67E+06 0.232 2500 DIRTY-SANDSTONE 4359.4 0.8 0.63 2756 1.21E+06 0.265 1500 SHALE 4361.9 6.1 0.69 3011 2.67E+06 0.232 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 10 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4106.1 3.0 0.001 1.0 1881 4116.1 4.6 0.001 1.0 1886 4131.1 4.7 0.005 10.0 1890 4146.4 1.8 56.445 22.0 1882 4152.4 0.6 0.001 1.0 1884 4154.4 0.5 109.347 15.0 1885 4155.9 0.6 4.377 15.0 1886 4157.9 4.0 42.829 22.0 1887 4170.9 0.5 11.097 22.0 1893 4172.4 1.2 91.857 22.0 1894 4176.4 2.7 4.906 22.0 1896 4185.4 2.1 12.361 22.0 1900 4192.4 1.7 2.537 22.0 1903 4197.9 4.0 61.847 22.0 1906 4210.9 0.8 0.081 15.0 1912 4213.4 3.8 22.858 15.0 1913 4225.9 1.2 0.018 15.0 1919 4229.9 0.8 94.329 15.0 1920 4232.4 0.6 0.001 1.0 1922 4234.4 1.2 45.186 15.0 1922 4238.4 1.2 24.865 15.0 1924 4242.4 1.2 0.001 1.0 1926 4246.4 1.8 6.405 15.0 1928 4252.4 0.6 0.001 1.0 1931 4254.4 0.6 13.686 15.0 1932 4256.4 2.0 0.229 15.0 1933 4262.9 1.2 49.420 15.0 1936 4266.9 1.1 63.759 15.0 1938 4270.4 0.6 0.001 1.0 1939 4272.4 3.8 1.337 15.0 1940 4284.9 0.6 1.843 15.0 1946 4286.9 0.6 0.001 1.0 1947 4288.9 0.6 4.320 15.0 1948 4290.9 2.4 0.001 1.0 1949 4298.9 0.6 91.060 15.0 1952 4300.9 1.2 0.001 1.0 1953 4304.9 1.8 4.551 15.0 1955 4310.9 2.4 0.001 1.0 1958 4318.9 2.0 7.953 15.0 1962 4325.4 1.8 0.001 1.0 1965 4331.4 0.6 24.687 15.0 1967 4333.4 0.6 0.001 1.0 1968 4335.4 1.2 2.159 10.0 1969 4339.4 0.6 0.001 1.0 1971 4341.4 1.8 1.534 10.0 1972 4347.4 3.7 0.001 1.0 1975 4359.4 0.8 5.632 10.0 1980 4361.9 6.1 0.001 1.0 1982SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE CLEAN-SANDSTONE Shale Shale Nanushuk 3 SS Top Nan SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE CLEAN-SANDSTONE Formation Transmissibility Properties Zone Name # SLB-Private 11 of 45 Attachment G Section 8: Propped Fracture Schedule (Stage 3; 16790 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 13650.0 22 0 1.0 PPA 40 YF122ST 5029.9 22 1 2.0 PPA 40 YF122ST 6758.4 22 2 3.0 PPA 40 YF122ST 7425.1 22 3 4.0 PPA 40 YF122ST 7148.6 22 4 5.0 PPA 40 YF122ST 6891.9 22 5 6.0 PPA 40 YF122ST 6653.0 22 6 7.0 PPA 40 YF122ST 4822.6 22 7 8.0 PPA 40 YF122ST 4355.2 22 8 Flush 40 WF122 10700.4 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1493.7 bbl of YF122ST 254.8 bbl of WF122 212394 lb of % PAD Clean 21.8 % PAD Dirty 19.0 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 325.0 325 325 325 0 0 4255 8.1 8.1 1.0 PPA 119.8 445 125 450 5030 5030 4260 3.1 11.3 2.0 PPA 160.9 606 175 625 13517 18547 4332 4.4 15.6 3.0 PPA 176.8 782 200 825 22275 40822 4685 5.0 20.6 4.0 PPA 170.2 953 200 1025 28594 69416 5042 5.0 25.6 5.0 PPA 164.1 1117 200 1225 34460 103876 5394 5.0 30.6 6.0 PPA 158.4 1275 200 1425 39918 143794 5756 5.0 35.6 7.0 PPA 114.8 1390 150 1575 33758 177552 6071 3.8 39.4 8.0 PPA 103.7 1494 140 1715 34841 212394 6267 3.5 42.9 Flush 254.8 1748 255 1970 0 212394 6429 6.4 49.2 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 407.2 ft with an average conductivity (Kfw) of 14440.6 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 12 of 45 Attachment G Section 9: Propped Fracture Simulation (Stage 3; 16790 ft MD) Initial Fracture Top TVD 4112.2 ft Initial Fracture Bottom TVD 4328 ft Propped Fracture Half-Length 407.2 ft EOJ Hyd Height at Well 215.8 ft Average Propped Width 0.166 in Net Pressure 393 psi Max Surface Pressure 6663 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) 0 101.8 6.9 0.179 203.2 1.5 231.3 16145 101.8 203.6 5.5 0.177 175 1.52 246.9 15467 203.6 305.4 5.3 0.184 150.5 1.64 245.9 16154 305.4 407.2 2.8 0.132 140.9 1.18 256.4 11102 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 # SLB-Private 13 of 45 Attachment G Section 10: Zone Data (Stage 4; 16302 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 4107.7 3.0 0.71 2937 1.46E+06 0.220 1000 Shale 4117.7 4.6 0.70 2867 1.76E+06 0.220 1000 Nanushuk 3 SS 4132.7 4.7 0.68 2807 1.90E+06 0.220 1000 Top Nan CS 4148.0 5.9 0.62 2595 9.00E+05 0.270 1000 Nan SS 4167.5 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4169.5 0.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4171.0 1.4 0.62 2571 6.44E+05 0.280 1000 Nan DS 4175.5 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4179.0 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4193.5 0.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4195.0 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4207.5 0.6 0.65 2731 1.40E+06 0.260 1500 Nan CS 4209.5 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4218.5 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4225.5 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4234.5 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4238.0 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4243.0 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4245.0 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4255.5 1.1 0.64 2705 1.10E+06 0.270 1000 Nan CS 4259.0 0.6 0.61 2614 6.70E+05 0.280 1000 Nan CS 4261.0 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4266.5 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4270.0 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4273.5 1.7 0.68 2928 1.42E+06 0.260 1500 Nan CS 4279.0 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4289.5 0.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4291.0 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4296.0 0.6 0.65 2809 1.56E+06 0.260 1500 Nan DS 4298.0 1.2 0.63 2688 8.96E+05 0.270 1500 Nan DS 4302.0 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4304.0 3.0 0.63 2702 9.81E+05 0.270 1500 Nan DS 4314.0 1.2 0.65 2823 1.63E+06 0.260 1500 Nan DS 4318.0 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4322.0 2.9 0.64 2784 1.33E+06 0.260 1500 Nan DS 4331.5 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4333.5 2.9 0.69 2975 1.69E+06 0.260 1500 Nan DS 4343.0 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4345.0 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4347.0 0.6 0.64 2765 1.09E+06 0.270 1500 Shale 4349.0 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4351.0 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4355.0 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4374.5 0.6 0.64 2820 1.36E+06 0.260 1500 Shale 4376.5 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4378.5 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4386.5 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4394.5 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 14 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4107.7 3.0 0.001 1.0 1890 4117.7 4.6 0.001 1.0 1898 4132.7 4.7 0.005 10.0 1905 4148.0 5.9 30.655 23.7 1915 4167.5 0.6 5.000 10.0 1924 4169.5 0.5 2.095 16.9 1925 4171.0 1.4 48.388 26.6 1926 4175.5 1.1 0.478 12.4 1928 4179.0 4.4 15.008 17.7 1930 4193.5 0.5 3.661 17.6 1937 4195.0 3.8 34.723 23.9 1937 4207.5 0.6 1.697 15.6 1943 4209.5 2.7 54.319 24.4 1944 4218.5 2.1 3.610 14.8 1948 4225.5 2.7 22.986 20.4 1952 4234.5 1.1 0.835 14.0 1956 4238.0 1.5 65.392 23.4 1957 4243.0 0.6 0.006 10.5 1960 4245.0 3.2 100.832 25.6 1961 4255.5 1.1 17.434 20.5 1966 4259.0 0.6 161.343 26.3 1967 4261.0 1.7 4.627 18.4 1968 4266.5 1.1 5.075 14.8 1971 4270.0 1.1 8.651 19.4 1972 4273.5 1.7 10.205 16.0 1974 4279.0 3.2 17.356 20.1 1977 4289.5 0.5 3.106 14.8 1982 4291.0 1.5 52.863 20.6 1982 4296.0 0.6 2.277 14.1 1985 4298.0 1.2 122.778 23.1 1986 4302.0 0.6 0.333 12.5 1987 4304.0 3.0 39.939 21.2 1988 4314.0 1.2 0.748 13.3 1993 4318.0 1.2 0.009 10.9 1995 4322.0 2.9 5.399 16.7 1997 4331.5 0.6 160.618 24.9 2001 4333.5 2.9 0.033 11.5 2002 4343.0 0.6 6.733 16.2 2007 4345.0 0.6 0.001 1.0 2008 4347.0 0.6 29.480 19.6 2009 4349.0 0.6 0.001 1.0 2009 4351.0 1.2 8.473 16.6 2010 4355.0 5.9 0.001 1.0 2012 4374.5 0.6 2.185 16.4 2021 4376.5 0.6 0.001 1.0 2022 4378.5 2.4 2.645 15.9 2023 4386.5 2.4 2.026 14.4 2027 4394.5 6.1 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 # SLB-Private 15 of 45 Attachment G Section 11: Propped Fracture Schedule (Stage 4; 16302 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 12600.0 22 0 1.0 PPA 40 YF122ST 7243.0 22 1 3.0 PPA 40 YF122ST 6682.6 22 3 5.0 PPA 40 YF122ST 8614.9 22 5 7.0 PPA 40 YF122ST 7233.9 22 7 9.0 PPA 40 YF122ST 6779.6 22 9 10.0 PPA 40 YF122ST 5842.9 22 10 Flush 40 WF122 10430.1 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1309.5 bbl of YF122ST 248.3 bbl of WF122 240448 lb of % PAD Clean 22.9 % PAD Dirty 19.2 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 300.0 300 300 300 0 0 4199 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 4182 4.5 12.0 3.0 PPA 159.1 632 250 730 20048 27291 4310 4.5 16.5 5.0 PPA 205.1 837 225 955 43074 70365 5059 6.3 22.8 7.0 PPA 172.2 1009 225 1180 50637 121003 5769 5.6 28.4 9.0 PPA 161.4 1170 200 1380 61017 182019 6229 5.6 34.0 10.0 PPA 139.1 1309 248 1628 58429 240448 6467 5.0 39.0 Flush 248.3 1558 0 1628 0 240448 6404 6.2 45.2 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 283.8 ft with an average conductivity (Kfw) of 18628.9 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 16 of 45 Attachment G Section 12: Propped Fracture Simulation (Stage 4; 16302 ft MD) Initial Fracture Top TVD 4114.8 ft Initial Fracture Bottom TVD 4356.4 ft Propped Fracture Half-Length 283.8 ft EOJ Hyd Height at Well 241.6 ft Average Propped Width 0.215 in Net Pressure 187 psi Max Surface Pressure 6591 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 71 9.6 0.225 150.2 1.91 192.1 19945 71 141.9 8.9 0.236 210.4 2.06 191.9 20750 141.9 212.9 8.8 0.235 205.1 2.1 190.6 20385 212.9 283.8 4 0.175 167.7 1.55 256.2 14836 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 # SLB-Private 17 of 45 Attachment G Section 13: Zone Data (Stage 5; 15814 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 4107.3 3.0 0.71 2937 1.46E+06 0.220 1000 Shale 4117.3 4.6 0.70 2867 1.76E+06 0.220 1000 Nanushuk 3 SS 4132.3 4.7 0.68 2807 1.90E+06 0.220 1000 Top Nan CS 4147.6 5.9 0.62 2595 9.00E+05 0.270 1000 Nan SS 4167.1 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4169.1 0.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4170.6 1.4 0.62 2570 6.44E+05 0.280 1000 Nan DS 4175.1 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4178.6 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4193.1 0.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4194.6 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4207.1 0.6 0.65 2731 1.40E+06 0.260 1500 Nan CS 4209.1 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4218.1 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4225.1 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4234.1 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4237.6 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4242.6 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4244.6 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4255.1 1.1 0.64 2705 1.10E+06 0.270 1000 Nan CS 4258.6 0.6 0.61 2614 6.70E+05 0.280 1000 Nan CS 4260.6 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4266.1 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4269.6 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4273.1 1.7 0.68 2928 1.42E+06 0.260 1500 Nan CS 4278.6 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4289.1 0.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4290.6 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4295.6 0.6 0.65 2809 1.56E+06 0.260 1500 Nan DS 4297.6 1.2 0.63 2688 8.96E+05 0.270 1500 Nan DS 4301.6 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4303.6 3.0 0.63 2701 9.81E+05 0.270 1500 Nan DS 4313.6 1.2 0.65 2822 1.63E+06 0.260 1500 Nan DS 4317.6 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4321.6 2.9 0.64 2784 1.33E+06 0.260 1500 Nan DS 4331.1 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4333.1 2.9 0.69 2975 1.69E+06 0.260 1500 Nan DS 4342.6 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4344.6 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4346.6 0.6 0.64 2765 1.09E+06 0.270 1500 Shale 4348.6 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4350.6 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4354.6 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4374.1 0.6 0.64 2820 1.36E+06 0.260 1500 Shale 4376.1 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4378.1 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4386.1 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4394.1 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 18 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4107.3 3.0 0.001 1.0 1890 4117.3 4.6 0.001 1.0 1898 4132.3 4.7 0.005 10.0 1905 4147.6 5.9 30.655 23.7 1915 4167.1 0.6 5.000 10.0 1924 4169.1 0.5 2.095 16.9 1925 4170.6 1.4 48.388 26.6 1926 4175.1 1.1 0.478 12.4 1928 4178.6 4.4 15.008 17.7 1930 4193.1 0.5 3.661 17.6 1937 4194.6 3.8 34.723 23.9 1937 4207.1 0.6 1.697 15.6 1943 4209.1 2.7 54.319 24.4 1944 4218.1 2.1 3.610 14.8 1948 4225.1 2.7 22.986 20.4 1952 4234.1 1.1 0.835 14.0 1956 4237.6 1.5 65.392 23.4 1957 4242.6 0.6 0.006 10.5 1960 4244.6 3.2 100.832 25.6 1961 4255.1 1.1 17.434 20.5 1966 4258.6 0.6 161.343 26.3 1967 4260.6 1.7 4.627 18.4 1968 4266.1 1.1 5.075 14.8 1971 4269.6 1.1 8.651 19.4 1972 4273.1 1.7 10.205 16.0 1974 4278.6 3.2 17.356 20.1 1977 4289.1 0.5 3.106 14.8 1982 4290.6 1.5 52.863 20.6 1982 4295.6 0.6 2.277 14.1 1985 4297.6 1.2 122.778 23.1 1986 4301.6 0.6 0.333 12.5 1987 4303.6 3.0 39.939 21.2 1988 4313.6 1.2 0.748 13.3 1993 4317.6 1.2 0.009 10.9 1995 4321.6 2.9 5.399 16.7 1997 4331.1 0.6 160.618 24.9 2001 4333.1 2.9 0.033 11.5 2002 4342.6 0.6 6.733 16.2 2007 4344.6 0.6 0.001 1.0 2008 4346.6 0.6 29.480 19.6 2009 4348.6 0.6 0.001 1.0 2009 4350.6 1.2 8.473 16.6 2010 4354.6 5.9 0.001 1.0 2012 4374.1 0.6 2.185 16.4 2021 4376.1 0.6 0.001 1.0 2022 4378.1 2.4 2.645 15.9 2023 4386.1 2.4 2.026 14.4 2027 4394.1 6.1 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 # SLB-Private 19 of 45 Attachment G Section 14: Propped Fracture Schedule (Stage 5; 15814 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 11550.0 22 0 1.0 PPA 40 YF122ST 6035.8 22 1 3.0 PPA 40 YF122ST 7425.1 22 3 5.0 PPA 40 YF122ST 8270.3 22 5 7.0 PPA 40 YF122ST 6912.4 22 7 9.0 PPA 40 YF122ST 6478.3 22 9 10.0 PPA 40 YF122ST 5550.8 22 10 Flush 40 WF122 10117.9 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1243.4 bbl of YF122ST 240.9 bbl of WF122 231862 lb of % PAD Clean 22.1 % PAD Dirty 18.5 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 275.0 275 275 275 0 0 4075 6.9 6.9 1.0 PPA 143.7 419 150 425 6036 6036 4079 3.8 10.6 3.0 PPA 176.8 595 200 625 22275 28311 4243 5.0 15.6 5.0 PPA 196.9 792 240 865 41351 69663 4876 6.0 21.6 7.0 PPA 164.6 957 215 1080 48387 118049 5564 5.4 27.0 9.0 PPA 154.2 1111 215 1295 58305 176354 6042 5.4 32.4 10.0 PPA 132.2 1243 190 1485 55508 231862 6270 4.8 37.1 Flush 240.9 1484 241 1726 0 231862 6212 6.0 43.1 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 310.8 ft with an average conductivity (Kfw) of 17249.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 20 of 45 Attachment G Section 15: Propped Fracture Simulation (Stage 5; 15814 ft MD) Initial Fracture Top TVD 4117.4 ft Initial Fracture Bottom TVD 4348.1 ft Propped Fracture Half-Length 310.8 ft EOJ Hyd Height at Well 230.8 ft Average Propped Width 0.199 in Net Pressure 267 psi Max Surface Pressure 6386 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 77.7 10.1 0.22 135.8 1.9 194.7 19560 77.7 155.4 9.3 0.223 206.8 1.97 190.6 19541 155.4 233.1 8.6 0.208 190.9 1.82 195 18160 233.1 310.8 4.5 0.153 144.2 1.42 256.8 12737 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 # SLB-Private 21 of 45 Attachment G Section 16: Zone Data (Stage 6; 15285 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 4112.5 3.0 0.71 2937 1.46E+06 0.220 1000 Shale 4122.5 4.6 0.70 2870 1.76E+06 0.220 1000 Nanushuk 3 SS 4137.5 4.7 0.68 2810 1.90E+06 0.220 1000 Top Nan CS 4152.8 5.9 0.62 2595 9.00E+05 0.270 1000 Nan SS 4172.3 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4174.3 0.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4175.8 1.4 0.62 2574 6.44E+05 0.280 1000 Nan DS 4180.3 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4183.8 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4198.3 0.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4199.8 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4212.3 0.6 0.65 2734 1.40E+06 0.260 1500 Nan CS 4214.3 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4223.3 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4230.3 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4239.3 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4242.8 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4247.8 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4249.8 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4260.3 1.1 0.63 2705 1.10E+06 0.270 1000 Nan CS 4263.8 0.6 0.61 2614 6.70E+05 0.280 1000 Nan CS 4265.8 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4271.3 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4274.8 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4278.3 1.7 0.68 2928 1.42E+06 0.260 1500 Nan CS 4283.8 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4294.3 0.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4295.8 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4300.8 0.6 0.65 2809 1.56E+06 0.260 1500 Nan DS 4302.8 1.2 0.62 2688 8.96E+05 0.270 1500 Nan DS 4306.8 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4308.8 3.0 0.63 2705 9.81E+05 0.270 1500 Nan DS 4318.8 1.2 0.65 2826 1.63E+06 0.260 1500 Nan DS 4322.8 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4326.8 2.9 0.64 2784 1.33E+06 0.260 1500 Nan DS 4336.3 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4338.3 2.9 0.69 2975 1.69E+06 0.260 1500 Nan DS 4347.8 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4349.8 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4351.8 0.6 0.64 2765 1.09E+06 0.270 1500 Shale 4353.8 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4355.8 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4359.8 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4379.3 0.6 0.64 2820 1.36E+06 0.260 1500 Shale 4381.3 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4383.3 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4391.3 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4399.3 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 22 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4112.5 3.0 0.001 1.0 1890 4122.5 4.6 0.001 1.0 1898 4137.5 4.7 0.005 10.0 1905 4152.8 5.9 30.655 23.7 1915 4172.3 0.6 5.000 10.0 1924 4174.3 0.5 2.095 16.9 1925 4175.8 1.4 48.388 26.6 1926 4180.3 1.1 0.478 12.4 1928 4183.8 4.4 15.008 17.7 1930 4198.3 0.5 3.661 17.6 1937 4199.8 3.8 34.723 23.9 1937 4212.3 0.6 1.697 15.6 1943 4214.3 2.7 54.319 24.4 1944 4223.3 2.1 3.610 14.8 1948 4230.3 2.7 22.986 20.4 1952 4239.3 1.1 0.835 14.0 1956 4242.8 1.5 65.392 23.4 1957 4247.8 0.6 0.006 10.5 1960 4249.8 3.2 100.832 25.6 1961 4260.3 1.1 17.434 20.5 1966 4263.8 0.6 161.343 26.3 1967 4265.8 1.7 4.627 18.4 1968 4271.3 1.1 5.075 14.8 1971 4274.8 1.1 8.651 19.4 1972 4278.3 1.7 10.205 16.0 1974 4283.8 3.2 17.356 20.1 1977 4294.3 0.5 3.106 14.8 1982 4295.8 1.5 52.863 20.6 1982 4300.8 0.6 2.277 14.1 1985 4302.8 1.2 122.778 23.1 1986 4306.8 0.6 0.333 12.5 1987 4308.8 3.0 39.939 21.2 1988 4318.8 1.2 0.748 13.3 1993 4322.8 1.2 0.009 10.9 1995 4326.8 2.9 5.399 16.7 1997 4336.3 0.6 160.618 24.9 2001 4338.3 2.9 0.033 11.5 2002 4347.8 0.6 6.733 16.2 2007 4349.8 0.6 0.001 1.0 2008 4351.8 0.6 29.480 19.6 2009 4353.8 0.6 0.001 1.0 2009 4355.8 1.2 8.473 16.6 2010 4359.8 5.9 0.001 1.0 2012 4379.3 0.6 2.185 16.4 2021 4381.3 0.6 0.001 1.0 2022 4383.3 2.4 2.645 15.9 2023 4391.3 2.4 2.026 14.4 2027 4399.3 6.1 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 # SLB-Private 23 of 45 Attachment G Section 17: Propped Fracture Schedule (Stage 6; 15285 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 12600.0 22 0 1.0 PPA 40 YF122ST 7645.4 22 1 3.0 PPA 40 YF122ST 7053.9 22 3 5.0 PPA 40 YF122ST 8959.5 22 5 7.0 PPA 40 YF122ST 7716.2 22 7 9.0 PPA 40 YF122ST 7231.6 22 9 10.0 PPA 40 YF122ST 5842.9 22 10 Flush 40 WF122 9779.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1358.3 bbl of YF122ST 232.8 bbl of WF122 251131 lb of % PAD Clean 22.1 % PAD Dirty 18.5 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 300.0 300 300 300 0 0 3989 7.5 7.5 1.0 PPA 182.0 482 190 490 7645 7645 3979 4.8 12.3 3.0 PPA 167.9 650 190 680 21162 28807 4088 4.8 17.0 5.0 PPA 213.3 863 260 940 44797 73604 4741 6.5 23.5 7.0 PPA 183.7 1047 240 1180 54013 127617 5440 6.0 29.5 9.0 PPA 172.2 1219 240 1420 65085 192702 5877 6.0 35.5 10.0 PPA 139.1 1358 200 1620 58429 251131 6078 5.0 40.5 Flush 232.8 1591 233 1853 0 251131 6024 5.8 46.3 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 322.3 ft with an average conductivity (Kfw) of 18117.9 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 24 of 45 Attachment G Section 18: Propped Fracture Simulation (Stage 6; 15285 ft MD) Initial Fracture Top TVD 4122.3 ft Initial Fracture Bottom TVD 4354.3 ft Propped Fracture Half-Length 322.3 ft EOJ Hyd Height at Well 232 ft Average Propped Width 0.208 in Net Pressure 273 psi Max Surface Pressure 6199 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 80.6 10.1 0.226 132.6 1.95 198.3 20132 80.6 161.1 9.3 0.232 203.2 2.05 193.3 20439 161.1 241.7 8.5 0.216 191.9 1.89 197.1 18776 241.7 322.3 4.3 0.166 145.3 1.53 251.1 13927 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 # SLB-Private 25 of 45 Attachment G Section 19: Zone Data (Stage 7; 14756 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 4114.7 3.0 0.71 2937 1.46E+06 0.220 1000 Shale 4124.7 4.6 0.70 2872 1.76E+06 0.220 1000 Nanushuk 3 SS 4139.7 4.7 0.68 2812 1.90E+06 0.220 1000 Top Nan CS 4155.0 5.9 0.62 2595 9.00E+05 0.270 1000 Nan SS 4174.5 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4176.5 0.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4178.0 1.4 0.62 2575 6.44E+05 0.280 1000 Nan DS 4182.5 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4186.0 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4200.5 0.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4202.0 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4214.5 0.6 0.65 2736 1.40E+06 0.260 1500 Nan CS 4216.5 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4225.5 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4232.5 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4241.5 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4245.0 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4250.0 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4252.0 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4262.5 1.1 0.63 2705 1.10E+06 0.270 1000 Nan CS 4266.0 0.6 0.61 2614 6.70E+05 0.280 1000 Nan CS 4268.0 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4273.5 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4277.0 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4280.5 1.7 0.68 2928 1.42E+06 0.260 1500 Nan CS 4286.0 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4296.5 0.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4298.0 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4303.0 0.6 0.65 2809 1.56E+06 0.260 1500 Nan DS 4305.0 1.2 0.62 2688 8.96E+05 0.270 1500 Nan DS 4309.0 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4311.0 3.0 0.63 2706 9.81E+05 0.270 1500 Nan DS 4321.0 1.2 0.65 2827 1.63E+06 0.260 1500 Nan DS 4325.0 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4329.0 2.9 0.64 2784 1.33E+06 0.260 1500 Nan DS 4338.5 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4340.5 2.9 0.68 2975 1.69E+06 0.260 1500 Nan DS 4350.0 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4352.0 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4354.0 0.6 0.63 2765 1.09E+06 0.270 1500 Shale 4356.0 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4358.0 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4362.0 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4381.5 0.6 0.64 2820 1.36E+06 0.260 1500 Shale 4383.5 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4385.5 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4393.5 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4401.5 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 26 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4114.7 3.0 0.001 1.0 1890 4124.7 4.6 0.001 1.0 1898 4139.7 4.7 0.005 10.0 1905 4155.0 5.9 30.655 23.7 1915 4174.5 0.6 5.000 10.0 1924 4176.5 0.5 2.095 16.9 1925 4178.0 1.4 48.388 26.6 1926 4182.5 1.1 0.478 12.4 1928 4186.0 4.4 15.008 17.7 1930 4200.5 0.5 3.661 17.6 1937 4202.0 3.8 34.723 23.9 1937 4214.5 0.6 1.697 15.6 1943 4216.5 2.7 54.319 24.4 1944 4225.5 2.1 3.610 14.8 1948 4232.5 2.7 22.986 20.4 1952 4241.5 1.1 0.835 14.0 1956 4245.0 1.5 65.392 23.4 1957 4250.0 0.6 0.006 10.5 1960 4252.0 3.2 100.832 25.6 1961 4262.5 1.1 17.434 20.5 1966 4266.0 0.6 161.343 26.3 1967 4268.0 1.7 4.627 18.4 1968 4273.5 1.1 5.075 14.8 1971 4277.0 1.1 8.651 19.4 1972 4280.5 1.7 10.205 16.0 1974 4286.0 3.2 17.356 20.1 1977 4296.5 0.5 3.106 14.8 1982 4298.0 1.5 52.863 20.6 1982 4303.0 0.6 2.277 14.1 1985 4305.0 1.2 122.778 23.1 1986 4309.0 0.6 0.333 12.5 1987 4311.0 3.0 39.939 21.2 1988 4321.0 1.2 0.748 13.3 1993 4325.0 1.2 0.009 10.9 1995 4329.0 2.9 5.399 16.7 1997 4338.5 0.6 160.618 24.9 2001 4340.5 2.9 0.033 11.5 2002 4350.0 0.6 6.733 16.2 2007 4352.0 0.6 0.001 1.0 2008 4354.0 0.6 29.480 19.6 2009 4356.0 0.6 0.001 1.0 2009 4358.0 1.2 8.473 16.6 2010 4362.0 5.9 0.001 1.0 2012 4381.5 0.6 2.185 16.4 2021 4383.5 0.6 0.001 1.0 2022 4385.5 2.4 2.645 15.9 2023 4393.5 2.4 2.026 14.4 2027 4401.5 6.1 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 # SLB-Private 27 of 45 Attachment G Section 20: Propped Fracture Schedule (Stage 7; 14756 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 11550.0 22 0 1.0 PPA 40 YF122ST 6035.8 22 1 2.0 PPA 40 YF122ST 6372.2 22 2 4.0 PPA 40 YF122ST 6433.7 22 4 6.0 PPA 40 YF122ST 5987.7 22 6 8.0 PPA 40 YF122ST 5599.5 22 8 10.0 PPA 40 YF122ST 5258.6 22 10 12.0 PPA 40 YF122ST 3855.3 22 12 Flush 40 WF122 9441.0 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1216.5 bbl of YF122ST 224.8 bbl of WF122 224087 lb of % PAD Clean 22.6 % PAD Dirty 19.0 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 275.0 275 275 275 0 0 3882 6.9 6.9 1.0 PPA 143.7 419 150 425 6036 6036 3882 3.8 10.6 2.0 PPA 151.7 570 165 590 12744 18780 3947 4.1 14.8 4.0 PPA 153.2 724 180 770 25735 44515 4274 4.5 19.3 6.0 PPA 142.6 866 180 950 35926 80442 4857 4.5 23.8 8.0 PPA 133.3 1000 180 1130 44796 125238 5437 4.5 28.3 10.0 PPA 125.2 1125 180 1310 52586 177824 5782 4.5 32.8 12.0 PPA 91.8 1216 140 1450 46264 224087 5934 3.5 36.3 Flush 224.8 1441 225 1675 0 224087 5918 5.6 41.9 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 311.3 ft with an average conductivity (Kfw) of 16524.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 28 of 45 Attachment G Section 21: Propped Fracture Simulation (Stage 7; 14756 ft MD) Initial Fracture Top TVD 4126.5 ft Initial Fracture Bottom TVD 4353.5 ft Propped Fracture Half-Length 311.3 ft EOJ Hyd Height at Well 227 ft Average Propped Width 0.191 in Net Pressure 269 psi Max Surface Pressure 6096 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 77.8 11.1 0.234 132.3 2.03 180.5 20883 77.8 155.6 9.4 0.224 202.7 2 187.1 19606 155.6 233.4 7.7 0.19 186.4 1.68 206 16413 233.4 311.3 3.6 0.129 152.8 1.16 262.5 10621 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 # SLB-Private 29 of 45 Attachment G Section 22: Zone Data (Stage 8; 14227 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 4121.0 3.0 0.71 2937 1.46E+06 0.220 1000 Shale 4131.0 4.6 0.70 2876 1.76E+06 0.220 1000 Nanushuk 3 SS 4146.0 4.7 0.68 2816 1.90E+06 0.220 1000 Top Nan CS 4161.3 5.9 0.62 2595 9.00E+05 0.270 1000 Nan SS 4180.8 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4182.8 0.5 0.63 2655 1.29E+06 0.260 1000 Nan CS 4184.3 1.4 0.62 2579 6.44E+05 0.280 1000 Nan DS 4188.8 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4192.3 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4206.8 0.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4208.3 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4220.8 0.6 0.65 2740 1.40E+06 0.260 1500 Nan CS 4222.8 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4231.8 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4238.8 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4247.8 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4251.3 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4256.3 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4258.3 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4268.8 1.1 0.63 2705 1.10E+06 0.270 1000 Nan CS 4272.3 0.6 0.61 2614 6.70E+05 0.280 1000 Nan CS 4274.3 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4279.8 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4283.3 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4286.8 1.7 0.68 2928 1.42E+06 0.260 1500 Nan CS 4292.3 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4302.8 0.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4304.3 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4309.3 0.6 0.65 2809 1.56E+06 0.260 1500 Nan DS 4311.3 1.2 0.62 2688 8.96E+05 0.270 1500 Nan DS 4315.3 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4317.3 3.0 0.63 2710 9.81E+05 0.270 1500 Nan DS 4327.3 1.2 0.65 2831 1.63E+06 0.260 1500 Nan DS 4331.3 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4335.3 2.9 0.64 2784 1.33E+06 0.260 1500 Nan DS 4344.8 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4346.8 2.9 0.68 2975 1.69E+06 0.260 1500 Nan DS 4356.3 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4358.3 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4360.3 0.6 0.63 2765 1.09E+06 0.270 1500 Shale 4362.3 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4364.3 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4368.3 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4387.8 0.6 0.64 2820 1.36E+06 0.260 1500 Shale 4389.8 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4391.8 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4399.8 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4407.8 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 30 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4121.0 3.0 0.001 1.0 1890 4131.0 4.6 0.001 1.0 1898 4146.0 4.7 0.005 10.0 1905 4161.3 5.9 30.655 23.7 1915 4180.8 0.6 5.000 10.0 1924 4182.8 0.5 2.095 16.9 1925 4184.3 1.4 48.388 26.6 1926 4188.8 1.1 0.478 12.4 1928 4192.3 4.4 15.008 17.7 1930 4206.8 0.5 3.661 17.6 1937 4208.3 3.8 34.723 23.9 1937 4220.8 0.6 1.697 15.6 1943 4222.8 2.7 54.319 24.4 1944 4231.8 2.1 3.610 14.8 1948 4238.8 2.7 22.986 20.4 1952 4247.8 1.1 0.835 14.0 1956 4251.3 1.5 65.392 23.4 1957 4256.3 0.6 0.006 10.5 1960 4258.3 3.2 100.832 25.6 1961 4268.8 1.1 17.434 20.5 1966 4272.3 0.6 161.343 26.3 1967 4274.3 1.7 4.627 18.4 1968 4279.8 1.1 5.075 14.8 1971 4283.3 1.1 8.651 19.4 1972 4286.8 1.7 10.205 16.0 1974 4292.3 3.2 17.356 20.1 1977 4302.8 0.5 3.106 14.8 1982 4304.3 1.5 52.863 20.6 1982 4309.3 0.6 2.277 14.1 1985 4311.3 1.2 122.778 23.1 1986 4315.3 0.6 0.333 12.5 1987 4317.3 3.0 39.939 21.2 1988 4327.3 1.2 0.748 13.3 1993 4331.3 1.2 0.009 10.9 1995 4335.3 2.9 5.399 16.7 1997 4344.8 0.6 160.618 24.9 2001 4346.8 2.9 0.033 11.5 2002 4356.3 0.6 6.733 16.2 2007 4358.3 0.6 0.001 1.0 2008 4360.3 0.6 29.480 19.6 2009 4362.3 0.6 0.001 1.0 2009 4364.3 1.2 8.473 16.6 2010 4368.3 5.9 0.001 1.0 2012 4387.8 0.6 2.185 16.4 2021 4389.8 0.6 0.001 1.0 2022 4391.8 2.4 2.645 15.9 2023 4399.8 2.4 2.026 14.4 2027 4407.8 6.1 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 # SLB-Private 31 of 45 Attachment G Section 23: Propped Fracture Schedule (Stage 8; 14227 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 12600.0 22 0 1.0 PPA 40 YF122ST 6438.2 22 1 2.0 PPA 40 YF122ST 6951.5 22 2 4.0 PPA 40 YF122ST 7327.3 22 4 6.0 PPA 40 YF122ST 6819.3 22 6 8.0 PPA 40 YF122ST 6532.8 22 8 10.0 PPA 40 YF122ST 6135.0 22 10 12.0 PPA 40 YF122ST 4956.8 22 12 Flush 38.7 WF122 9060.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1375.3 bbl of YF122ST 215.7 bbl of WF122 263661 lb of % PAD Clean 21.8 % PAD Dirty 18.2 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 300.0 300 300 300 0 0 3795 7.5 7.5 1.0 PPA 153.3 453 160 460 6438 6438 3785 4.0 11.5 2.0 PPA 165.5 619 180 640 13903 20341 3824 4.5 16.0 4.0 PPA 174.5 793 205 845 29309 49651 4152 5.1 21.1 6.0 PPA 162.4 956 205 1050 40916 90567 4759 5.1 26.3 8.0 PPA 155.5 1111 210 1260 52262 142829 5296 5.3 31.5 10.0 PPA 146.1 1257 210 1470 61350 204179 5601 5.3 36.8 12.0 PPA 118.0 1375 180 1650 59482 263661 5730 4.5 41.3 Flush 215.7 1591 216 1866 0 263661 5738 5.6 46.8 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 329.7 ft with an average conductivity (Kfw) of 18525.5 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 32 of 45 Attachment G Section 24: Propped Fracture Simulation (Stage 8; 14227 ft MD) Initial Fracture Top TVD 4132 ft Initial Fracture Bottom TVD 4363.1 ft Propped Fracture Half-Length 329.7 ft EOJ Hyd Height at Well 231.2 ft Average Propped Width 0.212 in Net Pressure 279 psi Max Surface Pressure 5899 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 82.4 11.5 0.252 186.4 2.18 176.3 22630 82.4 164.8 9.8 0.245 207.5 2.17 184 21657 164.8 247.3 8.4 0.215 183.8 1.88 201.1 18717 247.3 329.7 3.3 0.149 162.9 1.38 292.6 12276 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 # SLB-Private 33 of 45 Attachment G Section 25: Zone Data (Stage 9; 13698 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 4123.0 3.0 0.71 2937 1.46E+06 0.220 1000 Shale 4133.0 4.6 0.70 2878 1.76E+06 0.220 1000 Nanushuk 3 SS 4148.0 4.7 0.68 2818 1.90E+06 0.220 1000 Top Nan CS 4163.3 5.9 0.62 2595 9.00E+05 0.270 1000 Nan SS 4182.8 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4184.8 0.5 0.63 2655 1.29E+06 0.260 1000 Nan CS 4186.3 1.4 0.62 2580 6.44E+05 0.280 1000 Nan DS 4190.8 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4194.3 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4208.8 0.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4210.3 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4222.8 0.6 0.65 2741 1.40E+06 0.260 1500 Nan CS 4224.8 2.7 0.60 2558 8.54E+05 0.270 1000 Nan DS 4233.8 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4240.8 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4249.8 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4253.3 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4258.3 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4260.3 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4270.8 1.1 0.63 2705 1.10E+06 0.270 1000 Nan CS 4274.3 0.6 0.61 2614 6.70E+05 0.280 1000 Nan CS 4276.3 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4281.8 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4285.3 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4288.8 1.7 0.68 2928 1.42E+06 0.260 1500 Nan CS 4294.3 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4304.8 0.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4306.3 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4311.3 0.6 0.65 2809 1.56E+06 0.260 1500 Nan DS 4313.3 1.2 0.62 2688 8.96E+05 0.270 1500 Nan DS 4317.3 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4319.3 3.0 0.63 2711 9.81E+05 0.270 1500 Nan DS 4329.3 1.2 0.65 2833 1.63E+06 0.260 1500 Nan DS 4333.3 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4337.3 2.9 0.64 2784 1.33E+06 0.260 1500 Nan DS 4346.8 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4348.8 2.9 0.68 2975 1.69E+06 0.260 1500 Nan DS 4358.3 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4360.3 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4362.3 0.6 0.63 2765 1.09E+06 0.270 1500 Shale 4364.3 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4366.3 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4370.3 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4389.8 0.6 0.64 2820 1.36E+06 0.260 1500 Shale 4391.8 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4393.8 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4401.8 2.4 0.64 2841 1.56E+06 0.260 1500 Shale 4409.8 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 34 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4123.0 3.0 0.001 1.0 1890 4133.0 4.6 0.001 1.0 1898 4148.0 4.7 0.005 10.0 1905 4163.3 5.9 30.655 23.7 1915 4182.8 0.6 5.000 10.0 1924 4184.8 0.5 2.095 16.9 1925 4186.3 1.4 48.388 26.6 1926 4190.8 1.1 0.478 12.4 1928 4194.3 4.4 15.008 17.7 1930 4208.8 0.5 3.661 17.6 1937 4210.3 3.8 34.723 23.9 1937 4222.8 0.6 1.697 15.6 1943 4224.8 2.7 54.319 24.4 1944 4233.8 2.1 3.610 14.8 1948 4240.8 2.7 22.986 20.4 1952 4249.8 1.1 0.835 14.0 1956 4253.3 1.5 65.392 23.4 1957 4258.3 0.6 0.006 10.5 1960 4260.3 3.2 100.832 25.6 1961 4270.8 1.1 17.434 20.5 1966 4274.3 0.6 161.343 26.3 1967 4276.3 1.7 4.627 18.4 1968 4281.8 1.1 5.075 14.8 1971 4285.3 1.1 8.651 19.4 1972 4288.8 1.7 10.205 16.0 1974 4294.3 3.2 17.356 20.1 1977 4304.8 0.5 3.106 14.8 1982 4306.3 1.5 52.863 20.6 1982 4311.3 0.6 2.277 14.1 1985 4313.3 1.2 122.778 23.1 1986 4317.3 0.6 0.333 12.5 1987 4319.3 3.0 39.939 21.2 1988 4329.3 1.2 0.748 13.3 1993 4333.3 1.2 0.009 10.9 1995 4337.3 2.9 5.399 16.7 1997 4346.8 0.6 160.618 24.9 2001 4348.8 2.9 0.033 11.5 2002 4358.3 0.6 6.733 16.2 2007 4360.3 0.6 0.001 1.0 2008 4362.3 0.6 29.480 19.6 2009 4364.3 0.6 0.001 1.0 2009 4366.3 1.2 8.473 16.6 2010 4370.3 5.9 0.001 1.0 2012 4389.8 0.6 2.185 16.4 2021 4391.8 0.6 0.001 1.0 2022 4393.8 2.4 2.645 15.9 2023 4401.8 2.4 2.026 14.4 2027 4409.8 6.1 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 # SLB-Private 35 of 45 Attachment G Section 26: Propped Fracture Schedule (Stage 9; 13698 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 12600.0 22 0 1.0 PPA 40 YF122ST 7645.4 22 1 3.0 PPA 40 YF122ST 7053.9 22 3 5.0 PPA 40 YF122ST 8959.5 22 5 7.0 PPA 40 YF122ST 7716.2 22 7 9.0 PPA 40 YF122ST 7231.6 22 9 10.0 PPA 40 YF122ST 5842.9 22 10 Flush 40 WF122 8722.1 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1358.3 bbl of YF122ST 207.7 bbl of WF122 251131 lb of % PAD Clean 22.1 % PAD Dirty 18.5 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 300.0 300 300 300 0 0 3691 7.5 7.5 1.0 PPA 182.0 482 190 490 7645 7645 3682 4.8 12.3 3.0 PPA 167.9 650 190 680 21162 28807 3802 4.8 17.0 5.0 PPA 213.3 863 260 940 44797 73604 4413 6.5 23.5 7.0 PPA 183.7 1047 240 1180 54013 127617 4939 6.0 29.5 9.0 PPA 172.2 1219 240 1420 65085 192702 5289 6.0 35.5 10.0 PPA 139.1 1358 200 1620 58429 251131 5464 5.0 40.5 Flush 207.7 1566 208 1828 0 251131 5460 5.2 45.7 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 323.6 ft with an average conductivity (Kfw) of 18060.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 36 of 45 Attachment G Section 27: Propped Fracture Simulation (Stage 9; 13698 ft MD) Initial Fracture Top TVD 4134 ft Initial Fracture Bottom TVD 4364.9 ft Propped Fracture Half-Length 323.6 ft EOJ Hyd Height at Well 230.9 ft Average Propped Width 0.208 in Net Pressure 274 psi Max Surface Pressure 5584 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 80.9 10.1 0.227 136.6 1.96 198.2 20179 80.9 161.8 9.3 0.233 206.7 2.06 193.1 20478 161.8 242.7 8.5 0.218 190.8 1.91 197.7 19137 242.7 323.6 4.2 0.161 144 1.5 261.6 13626 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 # SLB-Private 37 of 45 Attachment G Section 28: Zone Data (Stage 10; 12533 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 4096.0 3.0 0.72 2937 1.46E+06 0.220 1000 Shale 4106.0 4.6 0.70 2859 1.76E+06 0.220 1000 Nanushuk 3 SS 4121.0 4.7 0.68 2799 1.90E+06 0.220 1000 Top Nan CS 4136.3 5.9 0.63 2595 9.00E+05 0.270 1000 Nan SS 4155.8 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4157.8 0.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4159.3 1.4 0.62 2564 6.44E+05 0.280 1000 Nan DS 4163.8 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4167.3 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4181.8 0.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4183.3 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4195.8 0.6 0.65 2724 1.40E+06 0.260 1500 Nan CS 4197.8 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4206.8 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4213.8 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4222.8 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4226.3 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4231.3 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4233.3 3.2 0.62 2607 7.36E+05 0.270 1000 Nan CS 4243.8 1.1 0.64 2705 1.10E+06 0.270 1000 Nan CS 4247.3 0.6 0.62 2614 6.70E+05 0.280 1000 Nan CS 4249.3 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4254.8 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4258.3 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4261.8 1.7 0.69 2928 1.42E+06 0.260 1500 Nan CS 4267.3 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4277.8 0.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4279.3 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4284.3 0.6 0.66 2809 1.56E+06 0.260 1500 Nan DS 4286.3 1.2 0.63 2688 8.96E+05 0.270 1500 Nan DS 4290.3 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4292.3 3.0 0.63 2694 9.81E+05 0.270 1500 Nan DS 4302.3 1.2 0.65 2815 1.63E+06 0.260 1500 Nan DS 4306.3 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4310.3 2.9 0.65 2784 1.33E+06 0.260 1500 Nan DS 4319.8 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4321.8 2.9 0.69 2975 1.69E+06 0.260 1500 Nan DS 4331.3 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4333.3 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4335.3 0.6 0.64 2765 1.09E+06 0.270 1500 Shale 4337.3 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4339.3 1.2 0.66 2844 1.29E+06 0.260 1500 Shale 4343.3 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4362.8 0.6 0.65 2820 1.36E+06 0.260 1500 Shale 4364.8 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4366.8 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4374.8 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4382.8 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 38 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4096.0 3.0 0.001 1.0 1890 4106.0 4.6 0.001 1.0 1898 4121.0 4.7 0.005 10.0 1905 4136.3 5.9 30.655 23.7 1915 4155.8 0.6 5.000 10.0 1924 4157.8 0.5 2.095 16.9 1925 4159.3 1.4 48.388 26.6 1926 4163.8 1.1 0.478 12.4 1928 4167.3 4.4 15.008 17.7 1930 4181.8 0.5 3.661 17.6 1937 4183.3 3.8 34.723 23.9 1937 4195.8 0.6 1.697 15.6 1943 4197.8 2.7 54.319 24.4 1944 4206.8 2.1 3.610 14.8 1948 4213.8 2.7 22.986 20.4 1952 4222.8 1.1 0.835 14.0 1956 4226.3 1.5 65.392 23.4 1957 4231.3 0.6 0.006 10.5 1960 4233.3 3.2 100.832 25.6 1961 4243.8 1.1 17.434 20.5 1966 4247.3 0.6 161.343 26.3 1967 4249.3 1.7 4.627 18.4 1968 4254.8 1.1 5.075 14.8 1971 4258.3 1.1 8.651 19.4 1972 4261.8 1.7 10.205 16.0 1974 4267.3 3.2 17.356 20.1 1977 4277.8 0.5 3.106 14.8 1982 4279.3 1.5 52.863 20.6 1982 4284.3 0.6 2.277 14.1 1985 4286.3 1.2 122.778 23.1 1986 4290.3 0.6 0.333 12.5 1987 4292.3 3.0 39.939 21.2 1988 4302.3 1.2 0.748 13.3 1993 4306.3 1.2 0.009 10.9 1995 4310.3 2.9 5.399 16.7 1997 4319.8 0.6 160.618 24.9 2001 4321.8 2.9 0.033 11.5 2002 4331.3 0.6 6.733 16.2 2007 4333.3 0.6 0.001 1.0 2008 4335.3 0.6 29.480 19.6 2009 4337.3 0.6 0.001 1.0 2009 4339.3 1.2 8.473 16.6 2010 4343.3 5.9 0.001 1.0 2012 4362.8 0.6 2.185 16.4 2021 4364.8 0.6 0.001 1.0 2022 4366.8 2.4 2.645 15.9 2023 4374.8 2.4 2.026 14.4 2027 4382.8 6.1 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 # SLB-Private 39 of 45 Attachment G Section 29: Propped Fracture Schedule (Stage 10; 12533 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 10500.0 22 0 1.0 PPA 40 YF122ST 5432.3 22 1 3.0 PPA 40 YF122ST 5568.8 22 3 5.0 PPA 40 YF122ST 5168.9 22 5 7.0 PPA 40 YF122ST 6751.6 22 7 9.0 PPA 40 YF122ST 5725.0 22 9 10.0 PPA 40 YF122ST 5550.8 22 10 Flush 40 WF122 7976.7 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1064.2 bbl of YF122ST 189.9 bbl of WF122 202278 lb of % PAD Clean 23.5 % PAD Dirty 19.6 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 3498 6.3 6.3 1.0 PPA 129.3 379 135 385 5432 5432 3480 3.4 9.6 3.0 PPA 132.6 512 150 535 16707 22139 3543 3.8 13.4 5.0 PPA 123.1 635 150 685 25845 47983 3953 3.8 17.1 7.0 PPA 160.8 796 210 895 47261 95245 4507 5.3 22.4 9.0 PPA 136.3 932 190 1085 51525 146770 4883 4.8 27.1 10.0 PPA 132.2 1064 190 1275 55508 202278 5023 4.8 31.9 Flush 189.9 1254 190 1465 0 202278 5044 4.7 36.6 Job Execution Step Name Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 263.2 ft with an average conductivity (Kfw) of 17341 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV # SLB-Private 40 of 45 Attachment G Section 30: Propped Fracture Simulation (Stage 10; 12533 ft MD) Initial Fracture Top TVD 4104.8 ft Initial Fracture Bottom TVD 4338.4 ft Propped Fracture Half-Length 263.2 ft EOJ Hyd Height at Well 233.6 ft Average Propped Width 0.202 in Net Pressure 199 psi Max Surface Pressure 5127 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 65.8 9.9 0.218 146.4 1.88 186.9 19296 65.8 131.6 9.2 0.225 204.9 1.97 185.6 19453 131.6 197.4 9.3 0.229 201.5 2.05 179.5 19804 197.4 263.2 4.3 0.146 157.8 1.34 336.6 12071 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 # SLB-Private 41 of 45 Attachment G Section 31: Zone Data (Stage 11; 12045 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 4096.9 3.0 0.72 2937 1.46E+06 0.220 1000 Shale 4106.9 4.6 0.70 2860 1.76E+06 0.220 1000 Nanushuk 3 SS 4121.9 4.7 0.68 2800 1.90E+06 0.220 1000 Top Nan CS 4137.2 5.9 0.63 2595 9.00E+05 0.270 1000 Nan SS 4156.7 0.6 0.69 2880 2.67E+06 0.230 2500 Nan CS 4158.7 0.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4160.2 1.4 0.62 2564 6.44E+05 0.280 1000 Nan DS 4164.7 1.1 0.69 2886 1.77E+06 0.260 1500 Nan DS 4168.2 4.4 0.65 2726 1.39E+06 0.260 1500 Nan CS 4182.7 0.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4184.2 3.8 0.63 2641 8.82E+05 0.270 1000 Nan DS 4196.7 0.6 0.65 2724 1.40E+06 0.260 1500 Nan CS 4198.7 2.7 0.61 2558 8.54E+05 0.270 1000 Nan DS 4207.7 2.1 0.65 2755 1.40E+06 0.260 1500 Nan DS 4214.7 2.7 0.64 2705 1.13E+06 0.270 1500 Nan DS 4223.7 1.1 0.64 2720 1.69E+06 0.260 1500 Nan DS 4227.2 1.5 0.63 2665 7.57E+05 0.270 1000 Nan DS 4232.2 0.6 0.69 2925 1.80E+06 0.250 1500 Nan CS 4234.2 3.2 0.61 2607 7.36E+05 0.270 1000 Nan CS 4244.7 1.1 0.64 2705 1.10E+06 0.270 1000 Nan CS 4248.2 0.6 0.62 2614 6.70E+05 0.280 1000 Nan CS 4250.2 1.7 0.65 2768 1.30E+06 0.260 1000 Nan DS 4255.7 1.1 0.69 2939 1.53E+06 0.260 1500 Nan DS 4259.2 1.1 0.63 2701 1.19E+06 0.270 1500 Nan DS 4262.7 1.7 0.69 2928 1.42E+06 0.260 1500 Nan CS 4268.2 3.2 0.63 2693 1.17E+06 0.270 1000 Nan DS 4278.7 0.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4280.2 1.5 0.62 2671 1.14E+06 0.270 1500 Nan DS 4285.2 0.6 0.66 2809 1.56E+06 0.260 1500 Nan DS 4287.2 1.2 0.63 2688 8.96E+05 0.270 1500 Nan DS 4291.2 0.6 0.67 2876 1.66E+06 0.260 1500 Nan DS 4293.2 3.0 0.63 2695 9.81E+05 0.270 1500 Nan DS 4303.2 1.2 0.65 2816 1.63E+06 0.260 1500 Nan DS 4307.2 1.2 0.69 2974 1.75E+06 0.260 1500 Nan DS 4311.2 2.9 0.65 2784 1.33E+06 0.260 1500 Nan DS 4320.7 0.6 0.61 2649 7.82E+05 0.270 1000 Nan DS 4322.7 2.9 0.69 2975 1.69E+06 0.260 1500 Nan DS 4332.2 0.6 0.65 2812 1.37E+06 0.260 1500 Shale 4334.2 0.6 0.69 3002 2.67E+06 0.230 2500 Nan DS 4336.2 0.6 0.64 2765 1.09E+06 0.270 1500 Shale 4338.2 0.6 0.69 3005 2.67E+06 0.230 2500 Nan DS 4340.2 1.2 0.65 2844 1.29E+06 0.260 1500 Shale 4344.2 5.9 0.69 3015 2.67E+06 0.230 2500 Nan DS 4363.7 0.6 0.65 2820 1.36E+06 0.260 1500 Shale 4365.7 0.6 0.69 3024 2.67E+06 0.230 2500 Nan DS 4367.7 2.4 0.65 2855 1.37E+06 0.260 1500 Nan DS 4375.7 2.4 0.65 2841 1.56E+06 0.260 1500 Shale 4383.7 6.1 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private 42 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4096.9 3.0 0.001 1.0 1890 4106.9 4.6 0.001 1.0 1898 4121.9 4.7 0.005 10.0 1905 4137.2 5.9 30.655 23.7 1915 4156.7 0.6 5.000 10.0 1924 4158.7 0.5 2.095 16.9 1925 4160.2 1.4 48.388 26.6 1926 4164.7 1.1 0.478 12.4 1928 4168.2 4.4 15.008 17.7 1930 4182.7 0.5 3.661 17.6 1937 4184.2 3.8 34.723 23.9 1937 4196.7 0.6 1.697 15.6 1943 4198.7 2.7 54.319 24.4 1944 4207.7 2.1 3.610 14.8 1948 4214.7 2.7 22.986 20.4 1952 4223.7 1.1 0.835 14.0 1956 4227.2 1.5 65.392 23.4 1957 4232.2 0.6 0.006 10.5 1960 4234.2 3.2 100.832 25.6 1961 4244.7 1.1 17.434 20.5 1966 4248.2 0.6 161.343 26.3 1967 4250.2 1.7 4.627 18.4 1968 4255.7 1.1 5.075 14.8 1971 4259.2 1.1 8.651 19.4 1972 4262.7 1.7 10.205 16.0 1974 4268.2 3.2 17.356 20.1 1977 4278.7 0.5 3.106 14.8 1982 4280.2 1.5 52.863 20.6 1982 4285.2 0.6 2.277 14.1 1985 4287.2 1.2 122.778 23.1 1986 4291.2 0.6 0.333 12.5 1987 4293.2 3.0 39.939 21.2 1988 4303.2 1.2 0.748 13.3 1993 4307.2 1.2 0.009 10.9 1995 4311.2 2.9 5.399 16.7 1997 4320.7 0.6 160.618 24.9 2001 4322.7 2.9 0.033 11.5 2002 4332.2 0.6 6.733 16.2 2007 4334.2 0.6 0.001 1.0 2008 4336.2 0.6 29.480 19.6 2009 4338.2 0.6 0.001 1.0 2009 4340.2 1.2 8.473 16.6 2010 4344.2 5.9 0.001 1.0 2012 4363.7 0.6 2.185 16.4 2021 4365.7 0.6 0.001 1.0 2022 4367.7 2.4 2.645 15.9 2023 4375.7 2.4 2.026 14.4 2027 4383.7 6.1 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 # SLB-Private 43 of 45 Attachment G Section 32: Propped Fracture Schedule (Stage 11; 12045 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (gal) (lb/mgal) (PPA) PAD 40 YF122ST 12600.0 22 0 1.0 PPA 40 YF122ST 7041.8 22 1 2.0 PPA 40 YF122ST 7723.9 22 2 4.0 PPA 40 YF122ST 7148.6 22 4 6.0 PPA 40 YF122ST 7484.6 22 6 8.0 PPA 40 YF122ST 6999.4 22 8 10.0 PPA 40 YF122ST 5040.4 22 10 12.0 PPA 40 YF122ST 4064.8 22 12 Flush 40 WF122 7664.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1383.4 bbl of YF122ST 182.5 bbl of WF122 151987 lb of 99182 lb of % PAD Clean 21.7 % PAD Dirty 18.2 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 300.0 300 300 300 0 0 3401 7.5 7.5 1.0 PPA 167.7 468 175 475 7042 7042 3377 4.4 11.9 2.0 PPA 183.9 652 200 675 15448 22490 3432 5.0 16.9 4.0 PPA 170.2 822 200 875 28594 51084 3724 5.0 21.9 6.0 PPA 178.2 1000 225 1100 44908 95992 4229 5.6 27.5 8.0 PPA 166.7 1167 225 1325 55995 151987 4636 5.6 33.1 10.0 PPA 120.0 1287 175 1500 50404 202391 4820 4.4 37.5 12.0 PPA 96.8 1383 150 1650 48778 251169 4914 3.8 41.3 Flush 182.5 1566 182 1832 0 251169 4940 4.6 45.8 Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 297.7 ft with an average conductivity (Kfw) of 24840.5 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Pad Percentages Carbolite 12/18 Carbolite 12/18 Fluid Totals Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Job Execution Step Name # SLB-Private 44 of 45 Attachment G Section 33: Propped Fracture Simulation (Stage 11; 12045 ft MD) Initial Fracture Top TVD 4104.3 ft Initial Fracture Bottom TVD 4344.2 ft Propped Fracture Half-Length 297.7 ft EOJ Hyd Height at Well 239.9 ft Average Propped Width 0.217 in Net Pressure 212 psi Max Surface Pressure 5015 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 74.4 10.8 0.26 152.2 2.25 221 35722 74.4 148.8 8.9 0.251 210.6 2.21 236.8 33404 148.8 223.3 8 0.236 202 2.13 204 22132 223.3 297.7 3.4 0.132 153.1 1.23 416.2 10790 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 # SLB-Private 45 of 45 Attachment G Attachment H Additive Additive Description F103 Surfactant 1.0 Gal/mGal 732.5 gal J450 Stabilizing Agent 0.5 Gal/mGal 366.2 gal J475 Breaker J475 6.0 lb/mGal 4,394.9 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,465.0 lbm J532 Crosslinker 2.4 Gal/mGal 1,782.1 gal J580 Gel J580 22.0 lb/mGal 16,114.6 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 36.6 gal M275 Bactericide 0.3 lb/mGal 183.1 lbm S522-1218 Propping Agent varied concentrations 99,182.0 lbm S522-1620 Propping Agent varied concentrations 2,300,530.6 lbm S901 Proppant with Scale Inhibitor S901 varied concentrations 95,855.4 lbm ~ 71 % ~ 29 % < 1 % < 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 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % 100 %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 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) 9002-84-0 poly(tetrafluoroethylene) 14807-96-6 Magnesium silicate hydrate (talc) 10377-60-3 Magnesium nitrate 112-42-5 1-undecanol (impurity) 91053-39-3 Diatomaceous earth, calcined 7631-86-9 Silicon Dioxide (Impurity) 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 9025-56-3 Hemicellulase 67-63-0 Propan-2-ol 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 1303-96-4 Sodium tetraborate decahydrate 9003-35-4 Phenolic resin 50-70-4 Sorbitol 56-81-5 1, 2, 3 - Propanetriol 102-71-6 2,2`,2"-nitrilotriethanol 7727-54-0 Diammonium peroxidisulphate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF122 ST:WF122 732,480 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Report ID:RPT-1703 Fluid Name & Volume Concentration Volume Disclosure Type:Pre-Job Well Completed: Date Prepared:9/26/2023 State:Alaska County/Parish:North Slope Borough Case: Client:Oil Search Alaska Well:NDB-024 Basin/Field:Pikka # SLB-Private Page: 1 / 1 Attachment I NDB-024 Well Clean-up Summary TABLE OF FLOW PERIODS Flow / Build Up Table Duration (hours)Purpose / Remarks Clean-Up As Required ~48 - 72 Bring well on slowly (16/64th) via adjustable choke, adjust as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to proppant pack and to minimize erosion to surface equipment. The Santos Subsurface Engineer will determine when the well is clean and advise choke changes/rates for initial flow period. Stabilized Flow 72 Rate #Flow Rate BBL/D Duration (hours) Clean-up 1 500-3000 72 Stabilized Flow 2 1500 - 4800 72 SI 0 168 NOTE: Stabilized flow period may be extended (TBD) Final Build-Up Period 168 Surface equipment will be rigged down during this SI period Table 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 clean-up flowback work. Total volume of gas per the well test program listed above are approximately 8.6 MMscf. Well Cleanup - Operational Summary: x Estimates Time: 24 – 72 hours or as dictated by Santos Reservoir Engineer. x Target Clean-up Flow Rate: 50 – 3000 BPD w/ some gas x Target Post Clean-up Flow Rate:Up to 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 Engineer or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flareg(),qgp the produced gas for the duration of the development well clean-up flowback work. pg p p Total volume of gas per the well test program listed above are approximately 8.6 MMscf. x Proppant Production:Proppant production is expected and will manage 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 N2 Injection Rate: As per contingency N2 well kick-off procedures if required. x Methanol Injection Rate: MeoH will be injected into the well via the inner annulus or tubing to prevent the formation of hydrates. Injection rates will vary based on produced water volumes. x Sampling: As per sampling table 2 below Table 2 Stabilized Flow- Operational Summary: x Estimates Time: 72 hours or as directed by Santos Subsurface Engineer. x Main Flow Period:Up to 4800 BPD & up to 2.4 mmscf/d x Choke Setting: Bring the well on slowly using the adjustable choke, Santos Reservoir Engineer will advise drawdown targets based on observation from initial flow. Step open choke until desired flow rate is achieved, then switch to a positive choke. The Santos Reservoir Engineer & Santos Well Test Supervisor will advise target rates and choke changes. Surface Sampling Program Flow Period Sample Type Lab Analysis Number / Frequency Location Volume Sampling Container Collection Vendor Comments Cl e a n U p BS&W, API, WC Hourly Choke 100 ml Centrifuge Tube Expro Utilize EB as necessary, document in job log Oil API Gravity 2 per shift Separator 1000 ml Nalgene Bottle Expro Salinity H2O % Chlorides Hourly Separator NA NA Expro Perform hourly or as H2O production allows Ranarex Gas Gravity Hourly Separator NA NA Expro Glass Sample Tube H2S, CO2 Hourly Separator NA NA Expro Hourly to start, reduce to every 12 hrs if no H2S observed after 3 consecutive reads. x Proppant Production:Minimal proppant production is expected. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure will be 2,000 psi., bleed as required. x Sampling: As per sampling 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. Attachment J NDB-024 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 10.0 ppg OBM with 9.4 ppg NaCl brine to surface. 3. Flow check for 10 minutes. 4. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 5. Pressure up to close the WIV at 1,980 psi. 6. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 7. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. 8. Before releasing, pressure test the IA to top liner hanger/packer to 3,000 psi. 9. Release running tool from liner hanger. 10.Circulate 9.4 ppg NaCl brine to surface at 10 bpm pump rate. 11.POOH with liner hanger running tool. 12.Prepare to run upper completion. NDB-024 4-1/2” Upper Completion Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 2. Forward circulate 735 bbls of 9.4 ppg inhibited NaCl brine before installing tubing hanger. 3. Land tubing hanger. 4. MIT-T to 4,000 psi. (Post Rig Move, MIT-T will be tested to 6,000 psi) a. (8,700 psi MAWP – 3,300 psi IA hold) * 1.1 = 5,940 psi 5. MIT-IA to 3,500 psi. (Post Rig, MIT-IA to be tested again to 3,800 psi with AOGCC notification) 6. Shear circulation valve. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k psi frac tree. (Rig to start rigging down) 9. Pull the TWCV 10.Reverse circulate freeze protect and U-Tube. 11.Install TWCV check into the tubing hanger and pressure test from direction of flow. 12.RDMO 3,800 p 3,000 10k psi frac tree. 6,000 p (8,700 psi MAWP – NDB-024 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 flowback as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment K Surface line pressure test 9000 psi. IA PRV set at 3600 psi. Held IA 3300 psi. Pump Trip pressure 7600 psi, GORV 8400 psi. CDW 11/1/2023 Attachment L Schematic is not finalized. 1 Davies, Stephen F (OGC) From:Davies, Stephen F (OGC) Sent:Monday, October 16, 2023 11:11 AM To:Leahy, Scott (Scott) Cc:Dewhurst, Andrew D (OGC) Subject:RE: NDB-024 (PTD 223-076, Sundry 323-545) - Request for Additional Information Thank you, ScoƩ. I appreciate your help. Thanks Again and Be Well, Steve Davies AOGCC CONFIDENTIALITYNOTICE: This eͲmail message, including any aƩachments, contains informaƟon from the Alaska Oil and Gas ConservaƟon Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain conĮdenƟal and/or privileged informaƟon. The unauthorized review, use or disclosure of such informaƟon may violate state or federal law. If you are an unintended recipient of this eͲmail, please delete it, without Įrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907Ͳ793Ͳ1224 or steve.davies@alaska.gov. From: Leahy, Scott (Scott) <Scott.Leahy@santos.com> Sent: Monday, October 16, 2023 11:08 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: NDBͲ024 (PTD 223Ͳ076, Sundry 323Ͳ545) Ͳ Request for Additional Information Steve, I’ve aƩached the survey that you requested last week. With regards to your email from this morning, I’ve asked the subsurface team to weigh in. I’ll follow up with you once I hear back from them. Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, October 12, 2023 2:07 PM To: Leahy, Scott (Scott) <Scott.Leahy@santos.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: ![EXT]: RE: NDBͲ024 (PTD 223Ͳ076, Sundry 323Ͳ545) Ͳ Request for Additional Information 2 ScoƩ, I neglected to request the latest direcƟonal data for NDBͲ024 to ensure that calculated TVD and TVDss values are correct. All I need are MD, AZ, and INCL data in spreadsheet or tabͲ or commaͲdelimited text format. Thanks, Steve Davies AOGCC From: Leahy, Scott (Scott) <Scott.Leahy@santos.com> Sent: Thursday, October 12, 2023 1:15 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: NDBͲ024 (PTD 223Ͳ076, Sundry 323Ͳ545) Ͳ Request for Additional Information Steve, I’ve aƩached the mud/well logs in pdf and digital as requested. Also, Subsurface provided a slide which has a map of the faults and verƟcal displacement. They have asked that this remain conĮdenƟal, and I’d like to request that the map provided in my earlier email today, along with AƩachment F either be omiƩed or have conĮdenƟality applied to it. You don't often get email from scott.leahy@santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Redacted 4 Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From: Leahy, Scott (Scott) Sent: Thursday, October 12, 2023 10:24 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: NDBͲ024 (PTD 223Ͳ076, Sundry 323Ͳ545) Ͳ Request for Additional Information Stephen, I’ve asked the subsurface department to comment on the mud logs/well logs. I’ll relay what they report once I hear from them. As for the cementing operations, we are still acitivity drilling this well and had planned to share this information once we are finished cementing all the strings. I’ve included an additional structure map below to compliment the map provided in attachment F. I’ll try to include this version for subsequent Sundry’s. The frac azimuth should be longitudinal along the wellbore (~330 o). Point 10 denotes where the subsurface group expects for the fault to cross the lateral and also states the planned minimum distance from the frac port to the fault. As you likely know, we’ve had a few delays on NDBͲ24 and I expect we are now delayed for fracturing operations. My best guess right now would be the week of 11/5 before we’d be ready to frac. Redacted 7 Thanks for your help with this, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITYNOTICE: This eͲmail message, including any aƩachments, contains informaƟon from the Alaska Oil and Gas ConservaƟon Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain conĮdenƟal and/or privileged informaƟon. The unauthorized review, use or disclosure of such informaƟon may violate state or federal law. If you are an unintended recipient of this eͲmail, please delete it, without Įrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907Ͳ793Ͳ1224 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 1 Davies, Stephen F (OGC) From:Leahy, Scott (Scott) <Scott.Leahy@santos.com> Sent:Monday, October 23, 2023 3:59 PM To:Wallace, Chris D (OGC); Roby, David S (OGC); Davies, Stephen F (OGC) Cc:Rixse, Melvin G (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: Sundry application for NDB-024 (PTD 223-076, Sundry 323-545) Attachments:NDB-24 Stg 8_11_20230918.pdf; NDB-24 Stg 1_3_20230918.pdf; NDB-24 Stg 4_7_20230918.pdf Chris/Dave/Steve, OperaƟonsareprogressingwithNDBͲ24andweplantostartrunningthelowercompleƟonlaterthisweek(~Friday).I knowIhaveoutstandinginformaƟontoprovidetoSteve,cemenƟngoperaƟonssummary,whichIplantoprovidewithin thenextday.IsthereotherinformaƟonthatisrequiredforĮnalreview? I’veaƩacheddailyfracschedulesprocedurestocomplimentAppendixGofthesundrysubmission. Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From:Leahy,Scott(Scott) Sent:Monday,October16,20233:49PM To:Wallace,ChrisD(OGC)<chris.wallace@alaska.gov> Cc:Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;Roby, DavidS(OGC)<dave.roby@alaska.gov> Subject:RE:SundryapplicationforNDBͲ024(PTD223Ͳ076 Chris, x A10KfractreewillbeusedonNDBͲ24andthesurfaceironwithinSchlumberger’srigͲupwillconsistprimarilyof 4”1002(10Kpsirated)ironwithsome3”1502(15Kpsirated).Thesurfacelineswillbetestedtoapproximately 9,000psi,300psihigherthantheMAWPof8,700psi.Wouldyouobjecttohavingthepressuretestvalue addedtothetableinpart“e”asshownbelowforfuturesubmiƩals? Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) 2 Stages 1-11 3300 3600 8400 7600 9000 x I’veincludedamapshowingtheoīsetofwellsNDBͲ032andNDBiͲ043fromNDBͲ24.ThetoeofNDBͲ032is approximately639feetfromthehorizontallateralofNDBͲ24.Thefrac½lengthfromthestageclosesttothe heelonNDBͲ024isesƟmatedat297.7’.NDBiͲ43isfurtherawayatapproximately2,418’.Giventhatthe esƟmatedfraclengthislessthanthedistancebetweenthelateralsofthewells,doyousƟllrequiretheother supporƟngdocumentaƟonthatyououtlined? x Asyoupointedout,thestageͲbyͲstagefracschedulesummaryisnotedwithintheSchlumbergerFracCADE report.AfracprogramprocedurewillbesuppliedtotheĮeldforeachjobdaybutthiswasnotcreatedfor submiƩalwiththeSundry.WouldyoupreferthattheseOilSearchbasedproceduresaccompanytheSundry? Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From:Wallace,ChrisD(OGC)<chris.wallace@alaska.gov> Sent:Thursday,October12,202312:24PM To:Leahy,Scott(Scott)<Scott.Leahy@santos.com> Cc:Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;Roby, DavidS(OGC)<dave.roby@alaska.gov> Subject:![EXT]:RE:SundryapplicationforNDBͲ024(PTD223Ͳ076 ScoƩ, WearereviewingtheproposedfracsundryandIhavesomeaddiƟonalquesƟonsbeforewecanevaluatetheĮnal compleƟon: (a)(8)pressureraƟngs–lookslikea10KfractreeismenƟonedstep8(UppercompleƟonSecƟonSummaryProcedure) butIcannotĮndasurfacelinestestpressure/raƟng? (a)(10)and(11)mechanicalcondiƟonofNDBͲ032andNDBiͲ043isnotdiscussedjustidenƟĮed.Wearelookingforyour evaluaƟonofthewellswithsupporƟnginfosowecandetermineifthesewellsinterferewiththeproposed frac?CementevaluaƟon,logsrun,topofcement,referencetoproposedfrachalflengthcomparedtodistanceto nearbywellsetc. (a)(12)fracprogram.IseetheSchlumbergerFracCADEbutisthereanOilSearchfracprocedure? (d)surfacelinepressuretest–youcouldmaybeaddthistothe(a)(12)ortheAƩachmentKinfo? ThanksandRegards, ChrisWallace,Sr.PetroleumEngineer,AlaskaOilandGasConservationCommission,333West7thAvenue,Anchorage,AK99501, (907)793Ͳ1250(phone),(907)276Ͳ7542(fax),chris.wallace@alaska.gov 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, 3 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From:Leahy,Scott(Scott)<Scott.Leahy@santos.com> Sent:Thursday,October12,202311:44AM To:Roby,DavidS(OGC)<dave.roby@alaska.gov> Cc:Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Davies, StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,Andrew D(OGC)<andrew.dewhurst@alaska.gov> Subject:RE:SundryapplicationforNDBͲ024(PTD223Ͳ076 HelloDave, I’veincludedresponsesinREDaŌeryourquesƟonsbelow.LetmeknowifyouhavefurtherclariĮcaƟons. Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From:Roby,DavidS(OGC)<dave.roby@alaska.gov> Sent:Monday,October9,20233:52PM To:Leahy,Scott(Scott)<Scott.Leahy@santos.com> Cc:Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Davies, StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,Andrew D(OGC)<andrew.dewhurst@alaska.gov> Subject:![EXT]:SundryapplicationforNDBͲ024(PTD223Ͳ076 HiScoƩ, IhaveaquesƟonrelatedtothereferencedsundryapplicaƟon.InaƩachmentIitsaystheesƟmatedwellcleanupƟme willbe“24Ͳ72hoursorasdictatedbySantosReservoirEngineer.”AretherespeciĮccriteriarelatedtoBS&W,orother factors,that’lldeterminewhenthecleanupperiodiscomplete?SpeciĮccriteriaforthecompleƟonoftheiniƟalcleanup periodwouldbeatargetof<10%WC,minimalsolids,andstabilizingŇowrate. Youdon'toftengetemailfromscott.leahy@santos.com.Learnwhythisisimportant 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. 4 Also,inTable1itsayscleanupis48Ͳ72hoursbutintheoperaƟonalsummaryitsaysthe24Ͳ72hoursIciteabove,which iscorrect?Myapologiesforthediscrepancyonthis.WeanƟcipatearangeinthecleanupperiodtobebetween48Ͳ72 hours,butthisƟmeframecouldbelongerdependingonBS&Wandstabilizedrate. Similarly,itsaysstabilizedŇowperiodwillbeapproximately72hoursbutmaybeextendedbythereservoir engineer.AretherespeciĮcŇowproperƟesthat’lldeterminewhenthestabilizedperiodends?ThecriteriaforĮnal cleanupduringthestabilizedŇowperiodisreachingatargetof<2Ͳ3%WCand<1%solids. Also,what’sthemaximumperiodofƟmethatthecleanupandstabilizedŇowmaylast??StabilizedŇowperiod duraƟonisanesƟmateandcouldbereplacedwithatotalcleanͲupvolumeequaltotheTLTR(totalloadto recover).TLTRisdeĮnedastotalcleanŇuidvolumeusedduringfracphasetotransport/placeproppantandeīecƟvely sƟmulatethelateral. Finally,what’stheplanfordisposiƟonoftheŇuidsproducedduringthestabilizedŇowperiod?Thevolumethatdoes notexceedtheTLTRwillbedisposedofinDWͲ02.AnycleanͲupvolumeexceedingTLTRwillbesenttoahydrocarbon recyclingfacility. Thanksinadvance. Regards, DaveRoby SeniorReservoirEngineer AlaskaOilandGasConservationCommission (907)793Ͳ1232 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 We l l N a m e ND B - 2 4 09 / 1 8 / 2 3 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T U s a b l e J 7 5 3 E n c a p s . # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m W a t e r B r e a k e r B r e a k e r Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) 0 ( g / M g a l ) ( # / M g a l ) a FP b FP 2. 5 6 c WF 2 5 3. 5 40 40 16 8 0 16 8 0 40 40 - 4 0 dP u m p C h e c k WF 25 4 0 24 0 28 0 40 3. 5 6 0 1 1 7 6 0 0 4 0 - 4 0 0 0 d Pu m p D a t a F R A C p a d XL 2 5 40 30 0 58 0 1 2 6 0 0 2 4 3 6 0 3 0 0 3 4 0 - 3 4 0 2 . 5 6 e Di s p l a c e D F ( a d d s u r f a c e l i n e s t o d i s p . ) WF 2 5 40 27 0 85 0 1 1 3 4 0 3 5 7 0 0 2 7 0 6 1 0 - 6 1 0 2 . 5 6 f Sh u t d o w n a n d m o n i t o r 1 . 5 - 2 H 8 5 0 0 3 5 7 0 0 0 6 1 0 - 6 1 0 0 0 h Lo a d S t a g e 1 b a l l / c o l l e t , 8 5 0 0 3 5 7 0 0 0 6 1 0 - 6 1 0 0 0 85 0 0 3 5 7 0 0 0 6 1 0 - 6 1 0 0 0 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T C L E A N V O L U M E C o n v . E n c a p s . S T A G E AV E R A G E FL U I D RA T E ST A G E CU M TO T J O B ST A G E CU M ST A G E CU M Si z e o r St a g e Cu m Re m a i n Br e a k e r Br e a k e r # PP A TY P E (B P M ) (B B L ) (B B L ) (B B L ) (G A L ) (G A L ) (L B S ) (L B S ) Ty p e (B B L ) (B B L ) Wa t e r (g / M g a l ) (# / M g a l ) 1 0 Li n e o u t X L X L 2 5 21 40 40 89 0 16 8 0 37 3 8 0 0 0 40 65 0 -6 5 0 2. 5 0 6. 0 2 0 Dr o p S t a g e 1 B a l l / C o l l e t X L 2 5 21 3 43 89 3 12 6 37 5 0 6 0 0 16 / 2 0 - C S G - I V 3 65 3 -6 5 3 2. 5 0 6. 0 3 0 St a g e 1 P A D XL 2 5 30 2 4 0 28 3 1 1 3 3 10 0 8 0 4 7 5 8 6 00 2 4 0 8 9 3 -8 9 3 2. 5 0 6 . 0 4 0 Sl o w f o r S e a t X L 2 5 17 50 33 3 1 1 8 3 21 0 0 4 9 6 8 6 00 5 0 9 4 3 -9 4 3 2. 5 0 6 . 0 5 0 Re s u m e P a d XL 2 5 40 3 5 36 8 1 2 1 8 14 7 0 5 1 1 5 6 00 3 5 9 7 8 -9 7 8 2. 5 0 6 . 0 6 1 Fl a t XL 2 5 40 1 2 5 49 3 1 3 4 3 52 5 0 5 6 4 0 6 50 2 8 5 0 2 8 16 / 2 0 - C S G - I V 12 0 1 0 9 8 -1 0 9 8 2. 5 0 6 . 0 7 2 Fl a t XL 2 5 40 1 4 0 63 3 1 4 8 3 58 8 0 6 2 2 8 6 10 8 0 4 1 5 8 3 1 16 / 2 0 - C S G - I V 12 9 1 2 2 6 -1 2 2 6 2. 5 0 6 . 0 8 3 Fl a t XL 2 5 40 1 6 0 79 3 1 6 4 3 67 2 0 6 9 0 0 6 17 7 9 8 3 3 6 2 9 16 / 2 0 - C S G - I V 14 1 1 3 6 8 -1 3 6 8 2. 5 0 6 . 0 9 4 Fl a t XL 2 5 40 1 7 0 96 3 1 8 1 3 71 4 0 7 6 1 4 6 24 2 6 5 5 7 8 9 4 16 / 2 0 - C S G - I V 14 4 1 5 1 2 -1 5 1 2 2. 5 0 6 . 0 10 5 Fl a t XL 2 5 40 1 7 0 11 3 3 1 9 8 3 71 4 0 8 3 2 8 6 29 2 3 3 8 7 1 2 7 16 / 2 0 - C S G - I V 13 9 1 6 5 1 -1 6 5 1 3. 5 0 6 . 0 11 6 Fl a t XL 2 5 40 1 7 0 13 0 3 2 1 5 3 71 4 0 9 0 4 2 6 33 8 5 3 1 2 0 9 7 9 16 / 2 0 - C S G - I V 13 4 1 7 8 6 -1 7 8 6 3. 5 0 6 . 0 12 7 Fl a t XL 2 5 40 1 2 5 14 2 8 2 2 7 8 52 5 0 9 5 6 7 6 28 0 5 9 1 4 9 0 3 9 16 / 2 0 - C S G - I V 95 1 8 8 1 -1 8 8 1 3. 5 0 6 . 0 13 8 Fl a t XL 2 5 40 1 1 0 15 3 8 2 3 8 8 46 2 0 1 0 0 2 9 6 27 2 9 7 1 7 6 3 3 6 16 / 2 0 - C S G - I V 81 1 9 6 2 -1 9 6 2 3. 5 0 6 . 0 14 0 Cl e a r S u r f a c e L i n e s FP 0 40 2 0 15 5 8 2 4 0 8 84 0 1 0 1 1 3 6 0 1 7 6 3 3 6 2 0 1 9 8 2 -1 9 8 2 2. 5 0 6 . 0 15 0 Sp a c e r XL 2 5 40 5 15 6 3 2 4 1 3 21 0 1 0 1 3 4 6 0 1 7 6 3 3 6 5 1 9 8 7 -1 9 8 7 2. 5 0 6 . 0 16 0 Dr o p S t a g e 2 B a l l / C o l l e t X L 2 5 40 3 15 6 6 2 4 1 6 12 6 1 0 1 4 7 2 0 1 7 6 3 3 6 3 1 9 9 0 -1 9 9 0 2. 5 0 6 . 0 17 0 St a g e 2 XL 2 5 40 2 3 2 17 9 8 2 6 4 8 97 4 4 1 1 1 2 1 6 0 1 7 6 3 3 6 2 3 2 2 2 2 2 -2 2 2 2 2. 5 0 6 . 0 18 0 Sl o w f o r S e a t XL 2 5 17 50 18 4 8 2 6 9 8 21 0 0 1 1 3 3 1 6 0 1 7 6 3 3 6 5 0 2 2 7 2 -2 2 7 2 2. 5 0 6 . 0 19 0 Re s u m e P a d XL 2 5 40 6 8 19 1 6 2 7 6 6 28 5 6 1 1 6 1 7 2 0 1 7 6 3 3 6 6 8 2 3 4 0 -2 3 4 0 2. 5 0 6 . 0 20 1 Fl a t XL 2 5 40 1 2 5 20 4 1 2 8 9 1 52 5 0 1 2 1 4 2 2 50 2 8 1 8 1 3 6 3 16 / 2 0 - C S G - I V 12 0 2 4 6 0 -2 4 6 0 2. 5 0 6 . 0 21 2 Fl a t XL 2 5 40 1 5 0 21 9 1 3 0 4 1 63 0 0 1 2 7 7 2 2 11 5 7 6 1 9 2 9 3 9 16 / 2 0 - C S G - I V 13 8 2 5 9 8 -2 5 9 8 2. 5 0 6 . 0 22 3 Fl a t XL 2 5 40 1 8 0 23 7 1 3 2 2 1 75 6 0 1 3 5 2 8 2 20 0 2 2 2 1 2 9 6 1 16 / 2 0 - C S G - I V 15 9 2 7 5 7 -2 7 5 7 2. 5 0 6 . 0 23 4 Fl a t XL 2 5 40 1 8 0 25 5 1 3 4 0 1 75 6 0 1 4 2 8 4 2 25 6 9 3 2 3 8 6 5 4 16 / 2 0 - C S G - I V 15 3 2 9 1 0 -2 9 1 0 2. 5 0 6 . 0 24 5 Fl a t XL 25 40 1 8 0 27 3 1 3 5 8 1 75 6 0 1 5 0 4 0 2 30 9 5 2 2 6 9 6 0 6 16 / 2 0 - C S G - I V 14 7 3 0 5 7 -3 0 5 7 3. 5 0 6 . 0 25 6 Fl a t XL 2 5 40 1 8 0 29 1 1 3 7 6 1 75 6 0 1 5 7 9 6 2 35 8 4 4 3 0 5 4 5 0 16 / 2 0 - C S G - I V 14 2 3 1 9 9 -3 1 9 9 3. 5 0 6 . 0 26 7 Fl a t FP 0 40 1 4 0 30 5 1 3 9 0 1 58 8 0 1 6 3 8 4 2 31 4 2 6 3 3 6 8 7 6 16 / 2 0 - C S G - I V 10 7 3 3 0 6 -3 3 0 6 3. 5 0 6 . 0 27 8 Fl a t XL 25 40 1 2 0 31 7 1 4 0 2 1 50 4 0 1 6 8 8 8 2 29 7 7 9 3 6 6 6 5 5 16 / 2 0 - C S G - I V 89 3 3 9 5 -3 3 9 5 3. 5 0 6 . 0 28 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 31 9 1 4 0 4 1 84 0 1 6 9 7 2 2 0 3 6 6 6 5 5 2 0 3 4 1 5 -3 4 1 5 2. 5 0 6 . 0 29 0 Sp a c e r XL 2 5 40 5 31 9 6 4 0 4 6 21 0 1 6 9 9 3 2 0 3 6 6 6 5 5 5 3 4 2 0 -3 4 2 0 2. 5 0 6 . 0 30 0 Dr o p S t a g e 3 B a l l / C o l l e t XL 2 5 40 3 31 9 9 4 0 4 9 12 6 1 7 0 0 5 8 0 3 6 6 6 5 5 3 3 4 2 3 -3 4 2 3 2. 5 0 6 . 0 31 0 St a g e 3 XL 2 5 40 2 2 5 34 2 4 4 2 7 4 94 5 0 1 7 9 5 0 8 0 3 6 6 6 5 5 2 2 5 3 6 4 8 -3 6 4 8 2. 5 0 6 . 0 32 0 Sl o w f o r S e a t XL 2 5 17 50 34 7 4 4 3 2 4 21 0 0 1 8 1 6 0 8 0 3 6 6 6 5 5 5 0 3 6 9 8 -3 6 9 8 2. 5 0 6 . 0 33 0 Re s u m e P a d XL 2 5 40 5 0 35 2 4 4 3 7 4 21 0 0 1 8 3 7 0 8 0 3 6 6 6 5 5 5 0 3 7 4 8 -3 7 4 8 2. 5 0 6 . 0 34 1 Fl a t XL 2 5 40 1 2 5 36 4 9 4 4 9 9 52 5 0 1 8 8 9 5 8 50 2 8 3 7 1 6 8 2 16 / 2 0 - C S G - I V 12 0 3 8 6 7 -3 8 6 7 2. 5 0 6 . 0 35 2 Fl a t XL 2 5 40 1 7 5 38 2 4 4 6 7 4 73 5 0 1 9 6 3 0 8 13 5 0 5 3 8 5 1 8 7 16 / 2 0 - C S G - I V 16 1 4 0 2 8 -4 0 2 8 2. 5 0 6 . 0 FL U I D Ne a t W a t e r CO M M E N T S Sh u t D o w n , l i n e u p f o r X L Pr i m e a n d P r e s s u r e T e s t Op e n w e l l a n d o p e n i n i t i a t o r s l e e v e Di s p l a c e P T - S h u t d o w n 1 0 m i n Pa d t o 4 p p a Gr e a t e r t h a n 4 p p a We l l N a m e ND B - 2 4 09 / 1 8 / 2 3 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T U s a b l e J 7 5 3 E n c a p s . # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m W a t e r B r e a k e r B r e a k e r Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) 0 ( g / M g a l ) ( # / M g a l ) FL U I D Ne a t W a t e r 36 3 Fl a t XL 2 5 40 2 0 0 40 2 4 4 8 7 4 84 0 0 2 0 4 7 0 8 22 2 4 7 4 0 7 4 3 4 16 / 2 0 - C S G - I V 17 7 4 2 0 5 -4 2 0 5 2. 5 0 6 . 0 37 4 Fl a t XL 2 5 40 2 0 0 42 2 4 5 0 7 4 84 0 0 2 1 3 1 0 8 28 5 4 7 4 3 5 9 8 2 16 / 2 0 - C S G - I V 17 0 4 3 7 5 -4 3 7 5 2. 5 0 6 . 0 38 5 Fl a t XL 2 5 21 2 0 0 44 2 4 5 2 7 4 84 0 0 2 2 1 5 0 8 34 3 9 1 4 7 0 3 7 3 16 / 2 0 - C S G - I V 16 4 4 5 3 8 -4 5 3 8 3. 5 0 6 . 0 39 6 Fl a t XL 2 5 21 2 0 0 46 2 4 5 4 7 4 84 0 0 2 2 9 9 0 8 39 8 2 7 5 1 0 1 9 9 16 / 2 0 - C S G - I V 15 8 4 6 9 6 -4 6 9 6 3. 5 0 6 . 0 40 7 Fl a t XL 25 40 1 5 0 47 7 4 5 6 2 4 63 0 0 2 3 6 2 0 8 33 6 7 1 5 4 3 8 7 0 16 / 2 0 - C S G - I V 11 5 4 8 1 1 -4 8 1 1 3. 5 0 6 . 0 41 8 Fl a t XL 2 5 14 1 4 0 49 1 4 5 7 6 4 58 8 0 2 4 2 0 8 8 34 7 4 2 5 7 8 6 1 2 16 / 2 0 - C S G - I V 10 3 4 9 1 4 -4 9 1 4 3. 5 0 6 . 0 42 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 49 3 4 5 7 8 4 84 0 2 4 2 9 2 8 0 5 7 8 6 1 2 2 0 4 9 3 4 -4 9 3 4 2. 5 0 6 . 0 43 0 Sp a c e r XL 2 5 40 5 49 3 9 5 7 8 9 21 0 2 4 3 1 3 8 0 5 7 8 6 1 2 5 4 9 3 9 -4 9 3 9 2. 5 0 6 . 0 44 0 Dr o p S t a g e 4 B a l l / C o l l e t XL 2 5 40 3 49 4 2 5 7 9 2 12 6 2 4 3 2 6 4 0 5 7 8 6 1 2 3 4 9 4 2 -4 9 4 2 2. 5 0 6 . 0 45 0 XL F l u s h XL 2 5 40 5 0 49 9 2 5 8 4 2 21 0 0 2 4 5 3 6 4 0 5 7 8 6 1 2 5 0 4 9 9 2 -4 9 9 2 4. 0 0 6 . 0 46 0 LG F l u s h XL 2 5 40 16 7 51 5 9 6 0 0 9 70 1 4 2 5 2 3 7 8 0 5 7 8 6 1 2 1 6 7 5 1 5 9 -5 1 5 9 4. 0 0 6 . 0 47 0 Sl o w f o r s e a t XL 2 5 40 50 52 0 9 6 0 5 9 21 0 0 2 5 4 4 7 8 0 5 7 8 6 1 2 5 0 5 2 0 9 -5 2 0 9 4. 0 0 6 . 0 48 0 Ov e r f l u s h ( e m p t y P C M ) XL 2 5 40 1 0 0 53 0 9 6 1 5 9 42 0 0 2 5 8 6 7 8 0 5 7 8 6 1 2 1 0 0 5 3 0 9 -5 3 0 9 4. 0 0 6 . 0 0 25 8 6 7 8 0 53 0 9 -5 3 0 9 49 Li n e a r F l u s h WF 2 5 20 15 3 1 0 6 1 6 0 42 2 4 8 6 4 0 15 3 1 0 -5 3 1 0 4. 0 6 . 0 50 Li n e a r F l u s h WF 2 5 20 15 3 1 1 6 1 6 1 42 2 4 8 6 8 2 15 3 1 1 -5 3 1 1 4. 0 0 . 0 51 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 5 8 53 6 9 6 2 1 9 24 3 3 2 5 1 1 1 5 TO T A L S 62 1 9 25 1 1 1 5 57 8 6 1 2 We l l N a m e ND B - 2 4 09 / 1 8 / 2 3 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T U s a b l e J 7 5 3 E n c a p s . # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m W a t e r B r e a k e r B r e a k e r Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) 0 ( g / M g a l ) ( # / M g a l ) a FP b FP 2. 5 6 c WF 2 5 3. 5 40 40 16 8 0 16 8 0 40 40 - 4 0 d 40 3. 5 6 Pu m p B a l l t o S e a t WF 2 5 4 25 0 10 5 0 0 0 2 5 0 2 9 0 - 2 9 0 2 . 5 6 d In c r e a s e R a t e a n d s t a r t X L - S t a g e t o S t a g e 4 P A D XL 2 5 40 40 40 1 6 8 0 1 6 8 0 4 0 3 3 0 - 3 3 0 2 . 5 6 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T C L E A N V O L U M E C o n v . E n c a p s . S T A G E AV E R A G E FL U I D RA T E ST A G E CU M TO T J O B ST A G E CU M ST A G E CU M Si z e o r St a g e Cu m Re m a i n Br e a k e r Br e a k e r # PP A TY P E (B P M ) (B B L ) (B B L ) (B B L ) (G A L ) (G A L ) (L B S ) (L B S ) Ty p e (B B L ) (B B L ) Wa t e r (g / M g a l ) (# / M g a l ) 1 0 St a g e 4 P A D XL 2 5 40 21 7 21 7 25 7 91 1 4 10 7 9 4 0 0 21 7 54 7 -5 4 7 2. 5 0 6. 0 2 0 Sl o w f o r S e a t X L 2 5 17 50 26 7 30 7 21 0 0 12 8 9 4 0 0 16 / 2 0 - C S G - I V 50 59 7 -5 9 7 2. 5 0 6. 0 3 0 Re s u m e P a d XL 2 5 40 3 3 30 0 3 4 0 13 8 6 1 4 2 8 0 00 3 3 6 3 0 -6 3 0 2. 5 0 6 . 0 4 1 Fl a t XL 2 5 40 1 8 0 48 0 5 2 0 75 6 0 2 1 8 4 0 72 4 0 7 2 4 0 16 / 2 0 - C S G - I V 17 2 8 0 2 -8 0 2 2. 5 0 6 . 0 5 3 Fl a t XL 2 5 40 1 8 0 66 0 7 0 0 75 6 0 2 9 4 0 0 20 0 2 2 2 7 2 6 2 16 / 2 0 - C S G - I V 15 9 9 6 1 -9 6 1 2. 5 0 6 . 0 6 5 Fl a t XL 2 5 40 2 4 0 90 0 9 4 0 10 0 8 0 3 9 4 8 0 41 2 7 0 6 8 5 3 1 16 / 2 0 - C S G - I V 19 7 1 1 5 8 -1 1 5 8 3. 5 0 6 . 0 7 7 Fl a t XL 2 5 40 2 1 5 11 1 5 1 1 5 5 90 3 0 4 8 5 1 0 48 2 6 2 1 1 6 7 9 3 16 / 2 0 - C S G - I V 16 4 1 3 2 2 -1 3 2 2 3. 5 0 6 . 0 8 9 Fl a t XL 2 5 40 2 1 5 13 3 0 1 3 7 0 90 3 0 5 7 5 4 0 58 1 2 3 1 7 4 9 1 7 16 / 2 0 - C S G - I V 15 4 1 4 7 6 -1 4 7 6 3. 5 0 6 . 0 9 10 Fl a t XL 2 5 40 1 9 0 15 2 0 1 5 6 0 79 8 0 6 5 5 2 0 55 3 2 1 2 3 0 2 3 8 16 / 2 0 - C S G - I V 13 2 1 6 0 7 -1 6 0 7 3. 5 0 6 . 0 10 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 15 4 0 1 5 8 0 84 0 6 6 3 6 0 0 2 3 0 2 3 8 2 0 1 6 2 7 -1 6 2 7 2. 5 0 6 . 0 11 0 Sp a c e r X L 2 5 40 5 15 4 5 1 5 8 5 21 0 6 6 5 7 0 0 2 3 0 2 3 8 5 1 6 3 2 -1 6 3 2 2. 5 0 6 . 0 12 0 Dr o p S t a g e 5 B a l l / C o l l e t X L 2 5 40 3 15 4 8 1 5 8 8 12 6 6 6 6 9 6 0 2 3 0 2 3 8 3 1 6 3 5 -1 6 3 5 2. 5 0 6 . 0 13 0 St a g e 5 XL 2 5 40 2 1 0 17 5 8 1 7 9 8 88 2 0 7 5 5 1 6 0 2 3 0 2 3 8 2 1 0 1 8 4 5 -1 8 4 5 2. 5 0 6 . 0 14 0 Sl o w f o r S e a t F P 0 40 5 0 18 0 8 1 8 4 8 21 0 0 7 7 6 1 6 0 2 3 0 2 3 8 5 0 1 8 9 5 -1 8 9 5 2. 5 0 6 . 0 15 0 Re s u m e P a d XL 2 5 40 4 0 18 4 8 1 8 8 8 16 8 0 7 9 2 9 6 0 2 3 0 2 3 8 4 0 1 9 3 5 -1 9 3 5 2. 5 0 6 . 0 16 1 Fl a t XL 2 5 40 1 8 0 20 2 8 2 0 6 8 75 6 0 8 6 8 5 6 72 4 0 2 3 7 4 7 8 16 / 2 0 - C S G - I V 17 2 2 1 0 8 -2 1 0 8 2. 5 0 6 . 0 17 3 Fl a t XL 2 5 40 1 8 0 22 0 8 2 2 4 8 75 6 0 9 4 4 1 6 20 0 2 2 2 5 7 5 0 0 16 / 2 0 - C S G - I V 15 9 2 2 6 7 -2 2 6 7 2. 5 0 6 . 0 18 5 Fl a t XL 2 5 17 2 5 0 24 5 8 2 4 9 8 10 5 0 0 1 0 4 9 1 6 42 9 8 9 3 0 0 4 8 9 16 / 2 0 - C S G - I V 20 5 2 4 7 1 -2 4 7 1 3. 5 0 6 . 0 19 7 Fl a t XL 2 5 40 2 2 5 26 8 3 2 7 2 3 94 5 0 1 1 4 3 6 6 50 5 0 6 3 5 0 9 9 5 16 / 2 0 - C S G - I V 17 2 2 6 4 3 -2 6 4 3 3. 5 0 6 . 0 20 9 Fl a t XL 2 5 40 2 2 5 29 0 8 2 9 4 8 94 5 0 1 2 3 8 1 6 60 8 2 7 4 1 1 8 2 2 16 / 2 0 - C S G - I V 16 1 2 8 0 4 -2 8 0 4 3. 5 0 6 . 0 21 10 Fl a t XL 2 5 40 2 0 0 31 0 8 3 1 4 8 84 0 0 1 3 2 2 1 6 58 2 3 3 4 7 0 0 5 5 16 / 2 0 - C S G - I V 13 9 2 9 4 3 -2 9 4 3 3. 5 0 6 . 0 22 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 31 2 8 3 1 6 8 84 0 1 3 3 0 5 6 0 4 7 0 0 5 5 2 0 2 9 6 3 -2 9 6 3 2. 5 0 6 . 0 23 0 Sp a c e r X L 2 5 40 5 31 3 3 3 1 7 3 21 0 1 3 3 2 6 6 0 4 7 0 0 5 5 5 2 9 6 8 -2 9 6 8 2. 5 0 6 . 0 24 0 Dr o p S t a g e 6 B a l l / C o l l e t X L 2 5 40 3 31 3 6 3 1 7 6 12 6 1 3 3 3 9 2 0 4 7 0 0 5 5 3 2 9 7 1 -2 9 7 1 2. 5 0 6 . 0 25 0 St a g e 6 XL 2 5 40 2 0 2 33 3 8 3 3 7 8 84 8 4 1 4 1 8 7 6 0 4 7 0 0 5 5 2 0 2 3 1 7 3 -3 1 7 3 2. 5 0 6 . 0 26 0 Sl o w f o r S e a t F P 0 40 5 0 33 8 8 3 4 2 8 21 0 0 1 4 3 9 7 6 0 4 7 0 0 5 5 5 0 3 2 2 3 -3 2 2 3 2. 5 0 6 . 0 27 0 Re s u m e P a d XL 2 5 40 4 8 34 3 6 3 4 7 6 20 1 6 1 4 5 9 9 2 0 4 7 0 0 5 5 4 8 3 2 7 1 -3 2 7 1 2. 5 0 6 . 0 28 1 Fl a t XL 2 5 40 1 9 0 36 2 6 3 6 6 6 79 8 0 1 5 3 9 7 2 76 4 2 4 7 7 6 9 7 16 / 2 0 - C S G - I V 18 2 3 4 5 3 -3 4 5 3 2. 5 0 6 . 0 29 3 Fl a t XL 2 5 40 1 9 0 38 1 6 3 8 5 6 79 8 0 1 6 1 9 5 2 21 1 3 5 4 9 8 8 3 2 16 / 2 0 - C S G - I V 16 8 3 6 2 0 -3 6 2 0 2. 5 0 6 . 0 30 5 Fl a t XL 2 5 40 2 6 0 40 7 6 4 1 1 6 10 9 2 0 1 7 2 8 7 2 44 7 0 9 5 4 3 5 4 1 16 / 2 0 - C S G - I V 21 3 3 8 3 3 -3 8 3 3 3. 5 0 6 . 0 31 7 Fl a t XL 2 5 40 2 4 0 43 1 6 4 3 5 6 10 0 8 0 1 8 2 9 5 2 53 8 7 4 5 9 7 4 1 4 16 / 2 0 - C S G - I V 18 3 4 0 1 7 -4 0 1 7 3. 5 0 6 . 0 32 9 Fl a t XL 2 5 17 2 4 0 45 5 6 4 5 9 6 10 0 8 0 1 9 3 0 3 2 64 8 8 2 6 6 2 2 9 6 16 / 2 0 - C S G - I V 17 2 4 1 8 8 -4 1 8 8 3. 5 0 6 . 0 33 10 Fl a t XL 2 5 40 2 0 0 47 5 6 4 7 9 6 84 0 0 2 0 1 4 3 2 58 2 3 3 7 2 0 5 2 9 16 / 2 0 - C S G - I V 13 9 4 3 2 7 -4 3 2 7 3. 5 0 6 . 0 34 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 47 7 6 4 8 1 6 84 0 2 0 2 2 7 2 0 7 2 0 5 2 9 2 0 4 3 4 7 -4 3 4 7 2. 5 0 6 . 0 35 0 Sp a c e r X L 2 5 40 5 47 8 1 4 8 2 1 21 0 2 0 2 4 8 2 0 7 2 0 5 2 9 5 4 3 5 2 -4 3 5 2 2. 5 0 6 . 0 36 0 Dr o p S t a g e 7 B a l l / C o l l e t X L 2 5 40 3 47 8 4 4 8 2 4 12 6 2 0 2 6 0 8 0 7 2 0 5 2 9 3 4 3 5 5 -4 3 5 5 2. 5 0 6 . 0 37 0 St a g e 7 XL 2 5 40 1 9 4 49 7 8 5 0 1 8 81 4 8 2 1 0 7 5 6 0 7 2 0 5 2 9 1 9 4 4 5 4 9 -4 5 4 9 2. 5 0 6 . 0 38 0 Sl o w f o r S e a t X L 2 5 21 5 0 50 2 8 5 0 6 8 21 0 0 2 1 2 8 5 6 0 7 2 0 5 2 9 5 0 4 5 9 9 -4 5 9 9 2. 5 0 6 . 0 39 0 Re s u m e P a d XL 2 5 21 3 1 50 5 9 5 0 9 9 13 0 2 2 1 4 1 5 8 0 7 2 0 5 2 9 3 1 4 6 3 0 -4 6 3 0 2. 5 0 6 . 0 40 1 Fl a t XL 2 5 40 1 5 0 52 0 9 5 2 4 9 63 0 0 2 2 0 4 5 8 60 3 3 7 2 6 5 6 2 16 / 2 0 - C S G - I V 14 4 4 7 7 4 -4 7 7 4 2. 5 0 6 . 0 Pa d t o 4 p p a Gr e a t e r t h a n 4 p p a FL U I D Ne a t W a t e r CO M M E N T S Pr i m e a n d P r e s s u r e T e s t Op e n W e l l a n d l i n e u p t o d r o p b a l l Dr o p B a l l a n d d i s p l a c e P T p a s t W H SD 1 0 m i n u t e s - L o a d S t a g e 5 B a l l / C o l l e t We l l N a m e ND B - 2 4 09 / 1 8 / 2 3 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T U s a b l e J 7 5 3 E n c a p s . # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m W a t e r B r e a k e r B r e a k e r Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) 0 ( g / M g a l ) ( # / M g a l ) FL U I D Ne a t W a t e r 41 2 Fl a t XL 2 5 14 1 6 5 53 7 4 5 4 1 4 69 3 0 2 2 7 3 8 8 12 7 3 3 7 3 9 2 9 5 16 / 2 0 - C S G - I V 15 2 4 9 2 5 -4 9 2 5 2. 5 0 6 . 0 42 4 Fl a t XL 2 5 40 1 8 0 55 5 4 5 5 9 4 75 6 0 2 3 4 9 4 8 25 6 9 3 7 6 4 9 8 8 16 / 2 0 - C S G - I V 15 3 5 0 7 8 -5 0 7 8 2. 5 0 6 . 0 43 6 Fl a t XL 2 5 40 1 8 0 57 3 4 5 7 7 4 75 6 0 2 4 2 5 0 8 35 8 4 4 8 0 0 8 3 2 16 / 2 0 - C S G - I V 14 2 5 2 2 0 -5 2 2 0 3. 5 0 6 . 0 44 8 Fl a t XL 2 5 40 1 8 0 59 1 4 5 9 5 4 75 6 0 2 5 0 0 6 8 44 6 6 8 8 4 5 5 0 0 16 / 2 0 - C S G - I V 13 3 5 3 5 3 -5 3 5 3 3. 5 0 6 . 0 45 10 Fl a t XL 2 5 40 1 8 0 60 9 4 6 1 3 4 75 6 0 2 5 7 6 2 8 52 4 1 0 8 9 7 9 1 0 16 / 2 0 - C S G - I V 12 5 5 4 7 8 -5 4 7 8 4. 0 0 6 . 0 46 12 Fl a t XL 2 5 40 1 4 0 62 3 4 6 2 7 4 58 8 0 2 6 3 5 0 8 46 0 8 8 9 4 3 9 9 8 16 / 2 0 - C S G - I V 91 5 5 6 9 -5 5 6 9 4. 0 0 6 . 0 47 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 62 5 4 6 2 9 4 84 0 2 6 4 3 4 8 0 9 4 3 9 9 8 2 0 5 5 8 9 -5 5 8 9 4. 0 0 6 . 0 48 0 Sp a c e r X L 2 5 40 5 62 5 9 6 2 9 9 21 0 2 6 4 5 5 8 0 9 4 3 9 9 8 5 5 5 9 4 -5 5 9 4 4. 0 0 6 . 0 49 0 Dr o p S t a g e 8 B a l l / C o l l e t X L 2 5 40 3 62 6 2 6 3 0 2 12 6 2 6 4 6 8 4 0 9 4 3 9 9 8 3 5 5 9 7 -5 5 9 7 2. 5 0 6 . 0 50 0 XL F l u s h XL 2 5 40 5 0 63 1 2 6 3 5 2 21 0 0 2 6 6 7 8 4 0 9 4 3 9 9 8 5 0 5 6 4 7 -5 6 4 7 4. 0 0 6 . 0 51 0 LG F l u s h WF 2 5 40 1 3 6 64 4 8 6 4 8 8 57 1 2 2 7 2 4 9 6 0 9 4 3 9 9 8 1 3 6 5 7 8 3 -5 7 8 3 4. 0 0 6 . 0 52 0 Sl o w f o r s e a t W F 2 5 17 5 0 64 9 8 6 5 3 8 21 0 0 2 7 4 5 9 6 0 9 4 3 9 9 8 5 0 5 8 3 3 -5 8 3 3 4. 0 0 6 . 0 53 0 Ov e r f l u s h ( e m p t y P C M ) WF 2 5 40 1 0 0 65 9 8 6 6 3 8 42 0 0 2 7 8 7 9 6 0 9 4 3 9 9 8 1 0 0 5 9 3 3 -5 9 3 3 4. 0 0 6 . 0 0 27 8 7 9 6 0 59 3 3 -5 9 3 3 54 Li n e a r F l u s h WF 2 5 20 16 5 9 9 6 3 0 0 42 2 9 1 0 1 8 15 9 3 4 -5 9 3 4 4. 0 6 . 0 55 Li n e a r F l u s h WF 2 5 20 16 6 0 0 6 3 0 1 42 2 9 1 0 6 0 15 9 3 5 -5 9 3 5 4. 0 0 . 0 56 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 5 8 66 5 8 6 3 5 9 24 3 3 2 9 3 4 9 3 TO T A L S 69 8 8 29 3 4 9 3 94 3 9 9 8 We l l N a m e ND B - 2 4 09 / 1 8 / 2 3 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T U s a b l e J 7 5 3 E n c a p s . # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m W a t e r B r e a k e r B r e a k e r Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) 0 ( g / M g a l ) ( # / M g a l ) a FP b FP 2. 5 6 c WF 2 5 3. 5 40 40 16 8 0 16 8 0 40 40 - 4 0 d 40 3. 5 6 Pu m p B a l l t o S e a t WF 2 5 4 20 0 84 0 0 0 2 0 0 2 4 0 - 2 4 0 2 . 5 6 d In c r e a s e R a t e a n d s t a r t X L - S t a g e t o S t a g e 8 P A D XL 2 5 40 40 40 1 6 8 0 1 6 8 0 4 0 2 8 0 - 2 8 0 2 . 5 6 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T C L E A N V O L U M E C o n v . E n c a p s . S T A G E AV E R A G E FL U I D RA T E ST A G E CU M TO T J O B ST A G E CU M ST A G E CU M Si z e o r St a g e Cu m Re m a i n Br e a k e r Br e a k e r # PP A TY P E (B P M ) (B B L ) (B B L ) (B B L ) (G A L ) (G A L ) (L B S ) (L B S ) Ty p e (B B L ) (B B L ) Wa t e r (g / M g a l ) (# / M g a l ) 1 0 St a g e 8 P A D XL 2 5 40 30 0 30 0 34 0 12 6 0 0 14 2 8 0 0 0 30 0 58 0 -5 8 0 2. 5 0 6. 0 2 1 Fl a t XL 2 5 40 16 0 46 0 50 0 67 2 0 21 0 0 0 64 3 5 64 3 5 16 / 2 0 - C S G - I V 15 3 73 3 -7 3 3 2. 5 0 6. 0 3 2 Fl a t XL 2 5 40 1 8 0 64 0 6 8 0 75 6 0 2 8 5 6 0 13 8 9 1 2 0 3 2 6 16 / 2 0 - C S G - I V 16 5 8 9 9 -8 9 9 2. 5 0 6 . 0 4 4 Fl a t XL 2 5 40 2 0 5 84 5 8 8 5 86 1 0 3 7 1 7 0 29 2 6 1 4 9 5 8 7 16 / 2 0 - C S G - I V 17 4 1 0 7 3 -1 0 7 3 2. 5 0 6 . 0 5 6 Fl a t XL 2 5 40 2 0 5 10 5 0 1 0 9 0 86 1 0 4 5 7 8 0 40 8 2 2 9 0 4 0 9 16 / 2 0 - C S G - I V 16 2 1 2 3 5 -1 2 3 5 3. 5 0 6 . 0 6 8 Fl a t XL 2 5 40 2 1 0 12 6 0 1 3 0 0 88 2 0 5 4 6 0 0 52 1 1 3 1 4 2 5 2 2 16 / 2 0 - C S G - I V 15 5 1 3 9 0 -1 3 9 0 3. 5 0 6 . 0 7 10 Fl a t XL 2 5 40 2 1 0 14 7 0 1 5 1 0 88 2 0 6 3 4 2 0 61 1 4 5 2 0 3 6 6 7 16 / 2 0 - C S G - I V 14 6 1 5 3 5 -1 5 3 5 3. 5 0 6 . 0 8 12 Fl a t XL 2 5 40 1 8 0 16 5 0 1 6 9 0 75 6 0 7 0 9 8 0 59 2 5 6 2 6 2 9 2 3 16 / 2 0 - C S G - I V 11 8 1 6 5 3 -1 6 5 3 3. 5 0 6 . 0 9 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 16 7 0 1 7 1 0 84 0 7 1 8 2 0 0 2 6 2 9 2 3 2 0 1 6 7 3 -1 6 7 3 2. 5 0 6 . 0 10 0 Sp a c e r X L 2 5 40 5 16 7 5 1 7 1 5 21 0 7 2 0 3 0 0 2 6 2 9 2 3 5 1 6 7 8 -1 6 7 8 2. 5 0 6 . 0 11 0 Dr o p S t a g e 9 B a l l / C o l l e t X L 2 5 40 3 16 7 8 1 7 1 8 12 6 7 2 1 5 6 0 2 6 2 9 2 3 3 1 6 8 1 -1 6 8 1 2. 5 0 6 . 0 12 0 St a g e 9 XL 2 5 40 1 7 8 18 5 6 1 8 9 6 74 7 6 7 9 6 3 2 0 2 6 2 9 2 3 1 7 8 1 8 5 9 -1 8 5 9 2. 5 0 6 . 0 13 0 Sl o w f o r S e a t F P 0 17 5 0 19 0 6 1 9 4 6 21 0 0 8 1 7 3 2 0 2 6 2 9 2 3 5 0 1 9 0 9 -1 9 0 9 2. 5 0 6 . 0 14 0 Re s u m e P a d XL 2 5 40 7 2 19 7 8 2 0 1 8 30 2 4 8 4 7 5 6 0 2 6 2 9 2 3 7 2 1 9 8 1 -1 9 8 1 2. 5 0 6 . 0 15 1 Fl a t XL 2 5 40 1 9 0 21 6 8 2 2 0 8 79 8 0 9 2 7 3 6 76 4 2 2 7 0 5 6 5 16 / 2 0 - C S G - I V 18 2 2 1 6 3 -2 1 6 3 2. 5 0 6 . 0 16 3 Fl a t XL 2 5 40 1 9 0 23 5 8 2 3 9 8 79 8 0 1 0 0 7 1 6 21 1 3 5 2 9 1 7 0 0 16 / 2 0 - C S G - I V 16 8 2 3 3 1 -2 3 3 1 2. 5 0 6 . 0 17 5 Fl a t XL 2 5 40 2 6 0 26 1 8 2 6 5 8 10 9 2 0 1 1 1 6 3 6 44 7 0 9 3 3 6 4 0 9 16 / 2 0 - C S G - I V 21 3 2 5 4 4 -2 5 4 4 3. 5 0 6 . 0 18 7 Fl a t XL 2 5 40 2 4 0 28 5 8 2 8 9 8 10 0 8 0 1 2 1 7 1 6 53 8 7 4 3 9 0 2 8 2 16 / 2 0 - C S G - I V 18 3 2 7 2 7 -2 7 2 7 3. 5 0 6 . 0 19 9 Fl a t XL 2 5 40 2 4 0 30 9 8 3 1 3 8 10 0 8 0 1 3 1 7 9 6 64 8 8 2 4 5 5 1 6 4 16 / 2 0 - C S G - I V 17 2 2 8 9 8 -2 8 9 8 3. 5 0 6 . 0 20 10 Fl a t XL 2 5 40 2 0 0 32 9 8 3 3 3 8 84 0 0 1 4 0 1 9 6 58 2 3 3 5 1 3 3 9 7 16 / 2 0 - C S G - I V 13 9 3 0 3 7 -3 0 3 7 3. 5 0 6 . 0 21 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 33 1 8 3 3 5 8 84 0 1 4 1 0 3 6 0 5 1 3 3 9 7 2 0 3 0 5 7 -3 0 5 7 2. 5 0 6 . 0 22 0 Sp a c e r X L 2 5 40 5 33 2 3 3 3 6 3 21 0 1 4 1 2 4 6 0 5 1 3 3 9 7 5 3 0 6 2 -3 0 6 2 2. 5 0 6 . 0 23 0 Dr o p S t a g e 1 0 B a l l / C o l l e t X L 2 5 40 3 33 2 6 3 3 6 6 12 6 1 4 1 3 7 2 0 5 1 3 3 9 7 3 3 0 6 5 -3 0 6 5 2. 5 0 6 . 0 24 0 St a g e 1 0 XL 2 5 40 1 6 0 34 8 6 3 5 2 6 67 2 0 1 4 8 0 9 2 0 5 1 3 3 9 7 1 6 0 3 2 2 5 -3 2 2 5 2. 5 0 6 . 0 25 0 Sl o w f o r S e a t F P 0 17 5 0 35 3 6 3 5 7 6 21 0 0 1 5 0 1 9 2 0 5 1 3 3 9 7 5 0 3 2 7 5 -3 2 7 5 2. 5 0 6 . 0 26 0 Re s u m e P a d XL 2 5 40 4 0 35 7 6 3 6 1 6 16 8 0 1 5 1 8 7 2 0 5 1 3 3 9 7 4 0 3 3 1 5 -3 3 1 5 2. 5 0 6 . 0 27 1 Fl a t XL 2 5 40 1 3 5 37 1 1 3 7 5 1 56 7 0 1 5 7 5 4 2 54 3 0 5 1 8 8 2 7 16 / 2 0 - C S G - I V 12 9 3 4 4 4 -3 4 4 4 2. 5 0 6 . 0 28 3 Fl a t XL 2 5 40 1 5 0 38 6 1 3 9 0 1 63 0 0 1 6 3 8 4 2 16 6 8 5 5 3 5 5 1 2 16 / 2 0 - C S G - I V 13 2 3 5 7 7 -3 5 7 7 2. 5 0 6 . 0 29 5 Fl a t XL 2 5 40 1 5 0 40 1 1 4 0 5 1 63 0 0 1 7 0 1 4 2 25 7 9 3 5 6 1 3 0 6 16 / 2 0 - C S G - I V 12 3 3 7 0 0 -3 7 0 0 3. 5 0 6 . 0 30 7 Fl a t XL 2 5 40 2 1 0 42 2 1 4 2 6 1 88 2 0 1 7 8 9 6 2 47 1 3 9 6 0 8 4 4 5 16 / 2 0 - C S G - I V 16 0 3 8 6 0 -3 8 6 0 3. 5 0 6 . 0 31 9 Fl a t XL 2 5 40 1 9 0 44 1 1 4 4 5 1 79 8 0 1 8 6 9 4 2 51 3 6 5 6 5 9 8 1 0 16 / 2 0 - C S G - I V 13 6 3 9 9 6 -3 9 9 6 3. 5 0 6 . 0 32 10 Fl a t XL 2 5 40 1 9 0 46 0 1 4 6 4 1 79 8 0 1 9 4 9 2 2 55 3 2 1 7 1 5 1 3 1 16 / 2 0 - C S G - I V 13 2 4 1 2 8 -4 1 2 8 3. 5 0 6 . 0 33 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 46 2 1 4 6 6 1 84 0 1 9 5 7 6 2 0 7 1 5 1 3 1 2 0 4 1 4 8 -4 1 4 8 2. 5 0 6 . 0 34 0 Sp a c e r X L 2 5 40 5 46 2 6 4 6 6 6 21 0 1 9 5 9 7 2 0 7 1 5 1 3 1 5 4 1 5 3 -4 1 5 3 2. 5 0 6 . 0 35 0 Dr o p S t a g e 1 1 B a l l / C o l l e t X L 2 5 40 3 46 2 9 4 6 6 9 12 6 1 9 6 0 9 8 0 7 1 5 1 3 1 3 4 1 5 6 -4 1 5 6 2. 5 0 6 . 0 36 0 St a g e 1 1 XL 2 5 40 1 5 3 47 8 2 4 8 2 2 64 2 6 2 0 2 5 2 4 0 7 1 5 1 3 1 1 5 3 4 3 0 9 -4 3 0 9 2. 5 0 6 . 0 37 0 Sl o w f o r S e a t X L 2 5 17 5 0 48 3 2 4 8 7 2 21 0 0 2 0 4 6 2 4 0 7 1 5 1 3 1 5 0 4 3 5 9 -4 3 5 9 2. 5 0 6 . 0 38 0 Re s u m e P a d XL 2 5 40 9 7 49 2 9 4 9 6 9 40 7 4 2 0 8 6 9 8 0 7 1 5 1 3 1 9 7 4 4 5 6 -4 4 5 6 2. 5 0 6 . 0 39 1 Fl a t XL 2 5 40 1 7 5 51 0 4 5 1 4 4 73 5 0 2 1 6 0 4 8 70 3 9 7 2 2 1 7 0 16 / 2 0 - C S G - I V 16 8 4 6 2 3 -4 6 2 3 2. 5 0 6 . 0 40 2 Fl a t XL 2 5 40 2 0 0 53 0 4 5 3 4 4 84 0 0 2 2 4 4 4 8 15 4 3 4 7 3 7 6 0 4 16 / 2 0 - C S G - I V 18 4 4 8 0 7 -4 8 0 7 2. 5 0 6 . 0 Pa d t o 4 p p a Gr e a t e r t h a n 4 p p a FL U I D Ne a t W a t e r CO M M E N T S Pr i m e a n d P r e s s u r e T e s t Op e n W e l l a n d l i n e u p t o d r o p b a l l Dr o p B a l l a n d d i s p l a c e P T p a s t W H SD 1 0 m i n u t e s - L o a d S t a g e 9 B a l l / C o l l e t We l l N a m e ND B - 2 4 09 / 1 8 / 2 3 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T U s a b l e J 7 5 3 E n c a p s . # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m W a t e r B r e a k e r B r e a k e r Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) 0 ( g / M g a l ) ( # / M g a l ) FL U I D Ne a t W a t e r 41 4 Fl a t XL 2 5 40 2 0 0 55 0 4 5 5 4 4 84 0 0 2 3 2 8 4 8 28 5 4 7 7 6 6 1 5 1 16 / 2 0 - C S G - I V 17 0 4 9 7 7 -4 9 7 7 2. 5 0 6 . 0 42 6 Fl a t XL 2 5 40 2 2 5 57 2 9 5 7 6 9 94 5 0 2 4 2 2 9 8 44 8 0 5 8 1 0 9 5 6 16 / 2 0 - C S G - I V 17 8 5 1 5 5 -5 1 5 5 3. 5 0 6 . 0 43 8 Fl a t XL 2 5 40 2 2 5 59 5 4 5 9 9 4 94 5 0 2 5 1 7 4 8 55 8 3 5 8 6 6 7 9 2 16 / 2 0 - C S G - I V 16 6 5 3 2 1 -5 3 2 1 3. 5 0 6 . 0 44 10 Fl a t XL 2 5 40 1 7 5 61 2 9 6 1 6 9 73 5 0 2 5 9 0 9 8 50 9 5 4 9 1 7 7 4 6 12 / 1 8 - C L 12 1 5 4 4 2 -5 4 4 2 3. 5 0 6 . 0 45 12 Fl a t XL 2 5 40 1 5 0 62 7 9 6 3 1 9 63 0 0 2 6 5 3 9 8 49 3 8 0 9 6 7 1 2 6 12 / 1 8 - C L 98 5 5 4 0 -5 5 4 0 4. 0 0 6 . 0 0 26 9 5 9 8 0 56 4 0 -5 6 4 0 54 XL F l u s h WF 2 5 40 20 6 3 9 9 6 3 3 9 84 0 2 8 0 5 1 8 20 5 6 6 0 -5 6 6 0 4. 0 6 . 0 55 Li n e a r F l u s h WF 2 5 40 10 0 6 4 9 9 6 4 3 9 42 0 0 2 8 4 7 1 8 10 0 5 7 6 0 -5 7 6 0 4. 0 0 . 0 56 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 5 8 65 5 7 6 4 9 7 24 3 3 2 8 7 1 5 1 TO T A L S 68 3 7 28 7 1 5 1 96 7 1 2 6 ADL 392984ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393007 ADL 391445 ADL 391455 ADL 393011ADL 393010 U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N006E28 U012N006E20 U012N006E21 U012N006E31 U011N006E06 U012N006E19 U012N006E30 DW-02 N D B - 0 3 2 N D B i - 0 4 3 N D B - 0 2 4 FIORD 3 QUGRUK 301 QUGRUK 3A 6 3 9 f t 211 2 ft 21 9 7 f t 24 1 8 f t Maxar OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELL SHL PLANNED BOTTOM HOLE NDB-024 HEEL PLANNED TRAJECTORY NDB-024 TRAJECTORY OTHER DRILLED WELLS PRODUCTION INTERVAL NDB-024 WELL OTHER WELLS EXPLORATION SHL BOTTOM HOLES WELL TRAJECTORY OTHER .5-MILE BUFFER SANTOS LEASES MEASURE LINE FAULT LINE DATE: 10/16/2023. By: JN 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL_GEN-M_NDB24_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDB-024 WELL Fault 1 Fault 4 Fault 3 Fault 2 1 Davies, Stephen F (OGC) From:Leahy, Scott (Scott) <Scott.Leahy@santos.com> Sent:Thursday, October 12, 2023 11:44 AM To:Roby, David S (OGC) Cc:Wallace, Chris D (OGC); Rixse, Melvin G (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: Sundry application for NDB-024 (PTD 223-076 HelloDave, I’veincludedresponsesinREDaŌeryourquesƟonsbelow.LetmeknowifyouhavefurtherclariĮcaƟons. Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From:Roby,DavidS(OGC)<dave.roby@alaska.gov> Sent:Monday,October9,20233:52PM To:Leahy,Scott(Scott)<Scott.Leahy@santos.com> Cc:Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Davies, StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,Andrew D(OGC)<andrew.dewhurst@alaska.gov> Subject:![EXT]:SundryapplicationforNDBͲ024(PTD223Ͳ076 HiScoƩ, IhaveaquesƟonrelatedtothereferencedsundryapplicaƟon.InaƩachmentIitsaystheesƟmatedwellcleanupƟme willbe“24Ͳ72hoursorasdictatedbySantosReservoirEngineer.”AretherespeciĮccriteriarelatedtoBS&W,orother factors,that’lldeterminewhenthecleanupperiodiscomplete?SpeciĮccriteriaforthecompleƟonoftheiniƟalcleanup periodwouldbeatargetof<10%WC,minimalsolids,andstabilizingŇowrate. You don't often get email from scott.leahy@santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Also,inTable1itsayscleanupis48Ͳ72hoursbutintheoperaƟonalsummaryitsaysthe24Ͳ72hoursIciteabove,which iscorrect?Myapologiesforthediscrepancyonthis.WeanƟcipatearangeinthecleanupperiodtobebetween48Ͳ72 hours,butthisƟmeframecouldbelongerdependingonBS&Wandstabilizedrate. Similarly,itsaysstabilizedŇowperiodwillbeapproximately72hoursbutmaybeextendedbythereservoir engineer.AretherespeciĮcŇowproperƟesthat’lldeterminewhenthestabilizedperiodends?ThecriteriaforĮnal cleanupduringthestabilizedŇowperiodisreachingatargetof<2Ͳ3%WCand<1%solids. Also,what’sthemaximumperiodofƟmethatthecleanupandstabilizedŇowmaylast??StabilizedŇowperiod duraƟonisanesƟmateandcouldbereplacedwithatotalcleanͲupvolumeequaltotheTLTR(totalloadto recover).TLTRisdeĮnedastotalcleanŇuidvolumeusedduringfracphasetotransport/placeproppantandeīecƟvely sƟmulatethelateral. Finally,what’stheplanfordisposiƟonoftheŇuidsproducedduringthestabilizedŇowperiod?Thevolumethatdoes notexceedtheTLTRwillbedisposedofinDWͲ02.AnycleanͲupvolumeexceedingTLTRwillbesenttoahydrocarbon recyclingfacility. Thanksinadvance. Regards, DaveRoby SeniorReservoirEngineer AlaskaOilandGasConservationCommission (907)793Ͳ1232 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 1 Davies, Stephen F (OGC) From:Leahy, Scott (Scott) <Scott.Leahy@santos.com> Sent:Thursday, October 12, 2023 1:15 PM To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC) Subject:RE: NDB-024 (PTD 223-076, Sundry 323-545) - Request for Additional Information Attachments:NDB-024_Mudlog_11465ft MD.pdf; NDB-024_DrillGas_ASCII_depth_11465ft.las Steve, I’veaƩachedthemud/welllogsinpdfanddigitalasrequested.Also,Subsurfaceprovidedaslidewhichhasamapofthe faultsandverƟcaldisplacement.TheyhaveaskedthatthisremainconĮdenƟal,andI’dliketorequestthatthemap providedinmyearlieremailtoday,alongwithAƩachmentFeitherbeomiƩedorhaveconĮdenƟalityappliedtoit. You don't often get email from scott.leahy@santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Redacted 3 Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7063 | m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From:Leahy,Scott(Scott) Sent:Thursday,October12,202310:24AM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:RE:NDBͲ024(PTD223Ͳ076,Sundry323Ͳ545)ͲRequestforAdditionalInformation Stephen, I’veaskedthesubsurfacedepartmenttocommentonthemudlogs/welllogs.I’llrelaywhattheyreportonceIhear fromthem. Asforthecementingoperations,wearestillacitivitydrillingthiswellandhadplannedtosharethisinformationoncewe arefinishedcementingallthestrings. I’veincludedanadditionalstructuremapbelowtocomplimentthemapprovidedinattachmentF.I’lltrytoincludethis versionforsubsequentSundry’s.Thefracazimuthshouldbelongitudinalalongthewellbore(~330o).Point10denotes wherethesubsurfacegroupexpectsforthefaulttocrossthelateralandalsostatestheplannedminimumdistancefrom thefracporttothefault. Asyoulikelyknow,we’vehadafewdelaysonNDBͲ24andIexpectwearenowdelayedforfracturingoperations.My bestguessrightnowwouldbetheweekof11/5beforewe’dbereadytofrac. Redacted 6 Thanksforyourhelpwiththis, SteveDavies SeniorPetroleumGeologist AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.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 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Monday, August 21, 2023 3:50 PM To:Davies, Stephen F (OGC) Subject:Shallow Aquifer Salinity - Pikka NDBi-043A (PTD 223-052; Sundry 323-411) Attachments:NDB pad shallow salinity petrophysical analysis.pdf Steve, Seeattachedanalysisthatexaminesthe3wellswithinthePikkaUnitwithadequatewirelinelogsforsalinity analysisandreportssalinitiesbetween16,700Ͳ23,000ppmNaClEquivalentwithintheSchraderBluffshallowsand. Ilookforwardtoyourresponseandappreciateyourtime. Thankyou, NicklausMiller 406Ͳ690Ͳ2896 GetOutlookforiOS 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 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. Salinity CalculaƟons Within the Pikka Unit there are 3 wells that have wireline logs from the surface through the reservoir zone (the vintage exploraƟon wells, Colville River 1 and Till 1, and the recently-drilled disposal well, DW-02). No sands with calculated saliniƟes of less than 10,000 ppm NaCl equivalent saliniƟes were present in either of these two wells below the permafrost zone. SaliniƟes were calculated using PickeƩ Plots. PickeƩ Plots are a graphical soluƟon to the Archie equaƟon and require the presence of clean, porous, 100% water saturated sands and some knowledge of the rock properƟes in those sands: ܴ௪௔ ൌ ׎௠ כܴ௧ Rwa ResisƟvity of water necessary to make zone 100% water bearing ׎ Porosity in decimal (calculated from logs) Rt FormaƟon resisƟvity (from logs) m CementaƟon exponent (from core analysis) a Tortuosity (assumed to be 1.0 per Archie correlaƟon) There is no cementaƟon exponent (m) available for the shallow intervals in the wells included in this study. However, analogs indicaƟon that m = 1.8 is a reasonable assumpƟon. Porosity was calculated from the density log and Rt was read from the deepest-reading resisƟvity log available in each well in the shallow hole secƟon. ResisƟvity to salinity conversions were done using the Gen-6 ResisƟvity of NaCl Water SoluƟons chart (previously Gen-9) from the SLB Chartbook. Well Name StraƟgraphic Interval Approx. Depth Range Salinity (ppm NaCl equiv.) DW-02 Schrader Bluī 1550-1650’md ~21,500ppm Colville River 1 Schrader Bluī 1550-1700’md ~20,000ppm Till 1 Schrader Bluī 1400-1500’md ~16,700ppm Till 1 Schrader Bluī 1500-2000’md ~23,000ppm 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Monday, August 14, 2023 2:50 PM To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC); Thompson, Jacob (Jacob) Subject:RE: Pikka NDBi-043A (PTD 223-052; Sundry 323-411) - Additional Information Needed for Fracturing Application Review Steve, TwoofourinternalPetrophysicistsareworkingonthisrequestbutneedsomeaddiƟonalclarity.Canyouprovideusan exampleanalysisfromanotherAlaskanĮeldorotheroperatorfromtheNorthSlope? Thanks, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,August14,20232:37PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Thompson,Jacob(Jacob)<Jacob.Thompson@santos.com> Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview ThankyouNick.Per20AAC25.990DeĮniƟon27,freshwaterhasaTDSconcentraƟonoflessthan10,000mg/lsoI’m hesitanttoacceptsuchablanketstatement.Ifyouallhaveanystandardpetrophysicalanalysesfortheshallowaquifers neartheNDBDrillSite,couldyoupleaseprovidethem? ThanksagainandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Sent:Monday,August14,20231:46PM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> 2 Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Thompson,Jacob(Jacob)<Jacob.Thompson@santos.com> Subject:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Steve, Seebelowscreenshotthatdetails/documentsshallowaquiferĮndingsfromPetrophysicistWayneCampaign.I’ve requestedtheenƟrepresentaƟonandwillshareitwithyouoncereceivedonmyend. NOTE:TargetfracdatehasbeenmovedtoAugust24th. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,August14,202310:05AM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> 3 Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview Nick, I’mconƟnuingtoreviewthisapplicaƟontofractureNDBͲ043A.TwoquesƟons: 1. Inyourcommentsconcerningshallowaquifersalinity,youmenƟonthe“2018PetrophysicsCoursebyNorth SlopePetrophysicistWayneCampaign”andthatOilsearchhasstandardpetrophysicalanalysisforthese aquifers.CouldOilSearchpleaseprovidecopiesofthesedocumentssincetheyarecitedasevidenceforthe absenceoffreshwater? 2. IsAugust18thsƟllthetargetdateforbeginningfracturingoperaƟons? ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Sent:Friday,August11,202310:05AM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Steve, SeebelowanswersinRED. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,July31,20235:49PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, 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. 4 MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview Nick, InaddiƟontothedatarequestedbelow,IhaveafewaddiƟonalitemsthatareneededorcommentsregardingthe geologyͲrelatedporƟonofAOGCC’sreview: x PleaseprovideinformaƟontosupportaĮndingthattherearenofreshwateraquifersbeneaththebaseof permafrostinthisareausingwatersampleanalysesorTDSesƟmatescalculatedfromwelllogdatarecordedin nearbywells(e.g.,DWͲ02andQugruk301).Wedonothaveanywatersampleanalysisfromthisintervalwithin thePikkaUnitbeneathbasepermafrostbutwedohavestandardpetrophysicalanalysis.Thepetrophysicaldata wehavedoesnotsuggesttherearefreshwateraquifersbelowpermafrostwithinourunit.Valuespresentedin the2018PetrophysicsCoursebyNorthSlopePetrophysicistWayneCampaignreferencesanAOGCCshallow aquiferdocumentaƟonstaƟngthatmostsaliniƟesareinexcessof12KppmNaClandaddsthatthereareno shallowfreshwateraquifersonthenorthslope. x IftheĮnal,archivalͲqualitydataforOilSearch’snearbywellDWͲ02havenotyetbeensubmiƩedtoAOGCC, pleaseprovideĮeldͲqualitycopiesofthemudlogandcementevaluaƟonlogs(electronicimagein.pdfor.pds format),LWDlogsfortheenƟrewell(in.lasorASCIItableformat),copiesofallcementreports,andpreliminary direcƟonalsurveydata(inspreadsheetorASCIItableformat).SubmiƩed8/8/23. x ForfutureapplicaƟons,itwouldgreatlyspeedAOGCC’sreviewiftheapplicaƟoncontainedasummaryof fracturegradientvalues(orrangesofvalues)fortheupperconĮning,fracturing,andlowerconĮningintervalsin unitsofpsi/ŌorppgEMW. UpperconĮning:shalegradient0.68psi/Ō Fracturing:sandgradient0.61psi/Ō LowerconĮning:shalegradient0.68psi/Ō x PleaseprovidesuĸcientcemenƟnginformaƟontodemonstratethattheiniƟalNDBͲ043wellboreisisolatedand willnotprovideaconduitforŇuidstomigrateoutofthefracturingintervalinNDBͲ043A.CBLwillberunaŌer lowercompleƟonisinstalled.EsƟmatedAugust14,2023. x ToaidAOGCC’sreviewoffutureapplicaƟons,pleasesuperimposethewellpathandtheAORoutline(asshown onAƩachmentB)onthelocalfaultmap(asshownonAƩachmentF).InfutureapplicaƟons,pleasealso describeOilSearch’sinterpretaƟonoftheorientaƟonofthecurrentregionalstressĮeldandthelikelydirecƟon ofpropagaƟonfortheinducedhydraulicfractures.Requestreceived,willmakeappropriatechangesand addiƟonsonfutureapplicaƟons. ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Staudinger, Garret (Garret) Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Rixse, Melvin G (OGC); Tirpack, Robert (Robert); Lambe, Steven (Steven) Subject:Re: NDB-24 (PTD 223-076) surface casing cement Date:Thursday, September 28, 2023 6:38:30 PM Garret, Oilsearch has approval to proceed with the plan outlined in your email below. If the Halliburton logs provide answers about the source of gas, the isolation scanner won’t be required. Thanks Bryan Sent from my iPhone On Sep 28, 2023, at 6:18 PM, Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> wrote: Bryan, Oil Search Alaska has reviewed the requirement outlined in the below email and offer the following update and path forward to address concerns related to the cement integrity of the NDB-024 surface casing. Operational Update: Schlumberger’s E-line Conveyed Isolation Scanner failed surface checks, and we are currently sourcing another tool from out of state. Current estimated arrival is unknown. No tractor that can be run inside the 13-3/8” casing is currently available in Alaska. We are evaluating options to source tractors if necessary. Halliburton E-Line Acoustic Conformance Xaminer (ACX) tool is available and can be run immediately. This tool has been used in the past to detect the location of shallow annular gas. Halliburton’s segmented sonic bond log is available and can be run to evaluate the location and quality of the tail cement / squeeze cement. Engineering Analysis / Justification To address your concerns listed below we have broken this out into three distinct items: 1. Source of gas bubbling in annulus The Halliburton ACX tool will be used to determine location and source of hydrate gas in the annulus This tool has successfully been used for this application on the slope with other operators 2. Cement isolation behind surface casing The Halliburton segmented sonic bond long will be used to determine presence of 15.3-15.8ppg cement behind the 13-3/8” surface casing This log will be run as deep as possible without a tractor If the 15.8ppg squeeze cement is detected deep in the well, there is good indication that cement exists between the parted casing and cement 3. Isolation between Tuluvak and other permeable formations for life of well considerations Isolation will be proven with both the cement sonic log and the FIT performed after the window is milled in the 13-3/8” casing After milling the window and 20’ of new hole, a formation integrity test will be run. We will target an FIT of 13.3ppg. This will prove that any formation that window is in communication with can hold full Tuluvak pressure without the risk of cross-flow between permeable zones. The Tuluvak pore pressure is estimated at 1326 psi @ 2525’ TVD (10.1ppg). During long term production of this well, if Tuluvak gas migrates to a shallower formation without being allowed to expand, the maximum pressure seen at the window would be an 11.9ppg equivalent (worst case scenario). For this reason, if we achieve an FIT of 13.3ppg, this would ensure that any formation that is exposed to the window can withstand Tuluvak pressure. Proposed Plan Forward: 1. Rig up HES E-Line and run ACX examiner. Log the 13-3/8” casing attempting to identify the source of the shallow gas bubbling in the 13-3/8” conductor. 2. Run the Halliburton segmented bond log as deep as possible and log cement to surface. 3. MU whipstock milling assembly and set whipstock. Mill window and 20’ of new formation. Perform FIT to 13.3ppg. 4. Submit results of logs and FIT to AOGCC Approval is requested to proceed ahead with the proposed plan forward. Additionally, we are requesting to not run an isolation scanner log assuming success of our above outlined plan forward. Please let me know if you have any questions, or feel free to give me a call if you have any questions. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, September 28, 2023 1:00 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: ![EXT]: NDB-24 (PTD 223-076) surface casing cement Garret, Based on your phone call today, we understand that a cement log that can detect 11 ppg cement may not be available until this Saturday and there is a Segmented sonic bond log available now that can identify the location of the 15.7ppg tail cement and the squeezed cement in the 13-3/8” casing. The AOGCC will require a cement log before run before sidetracking to determine the location of cement relative to the planned window depth. For this, the Segmented sonic log or Isolation Scanner are both acceptable. The AOGCC will also require a log to determine the quality of the 11 ppg lead cement in an attempt to identify the source of gas bubbling during and after the primary cement job to inform approval of the next well in the drilling program. The Isolation scanner is acceptable for this purpose and can be run at a later time, before tubing is run in the well. In summary, if the isolation scanner is not available before milling the window, two logs will be required. Alternatively, AOGCC will consider running only one log (isolation scanner) after milling the window, if Oilsearch submits a geologic and engineering analysis to demonstrate why the cement location above the sidetrack window would not have any impact on the drilling phase or future life cycle of the well. The analysis should include an assumption that the Tuluvak may not properly isolated with cement on the intermediate liner, and the base of cement on the 13-3/8” casing is unknown, and permeable zones above the surface casing shoe are uncemented, taking PPFG considerations into account. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> 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 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 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A NDB-024 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): 3181'2837' Casing Collapse Structural Conductor Surface 2260 psi Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Yes Date: GAS WAG GSTOR SPLUG AOGCC Representative: Bryan McLellan GINJ Op Shutdown Abandoned Contact Name:Garret Staudinger Contact Email:garret.staudinger@santos.com Contact Phone: 907-440-6892 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 2287' 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 AOGCC USE ONLY 09/26/23 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, 393020, 391455, 393018, 391445 223-076 900 E Benson Boulevard, Anchorage, AK 99508 50-103-20862-00-00 Oil Search Alaska, LLC Length Size Proposed Pools: TVD BurstMD 5020 psi 128' 2284' 128' 3171' 128' 20"x34" 13-3/8"3171' 2837' 2200' 1494 psi 09/27/23 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 9/27/2023 323-531 By Grace Christianson at 3:45 pm, Sep 27, 2023 X (Parted) SFD 10/2/2023 SFD(2204') DSR-9/28/23 (2837') 10-407 Sidetrack BJM 10/25/23 Also Rixse 9/30 & 10/1/23 emails attached. -bjm *&: Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.10.25 14:11:08 -08'00'10/25/23 RBDMS JSB 102623 Page 1 of 1 27 September 2023 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Sundry Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-024 Dear Sir/Madam, Oil Search (Alaska), LLC hereby applies for a Sundry for program change on NDB-024. NDB- 024 was spudded on September 16th, 2023 using Parker Rig 272. The 16” surface hole was drilled TD of 3,181’ MD above the Tuluvak sand and then 13-3/8” casing was run to 3,171’ MD and cemented. The 13-3/8” casing was later found to be parted at 2,837’ MD. The bottom section of hole will be P&A’d with cement, and a whipstock will be set at 2,750’ MD. The well will be sidetracked and the well will be drilled to the originally proposed direction plan from NDB-024 PTD 223-076. The abandoned section of 16” surface hole will be designated NDB-024 PB1. If there are any questions and/or additional information desired, please contact me at (907) 440- 6892 or garret.staudinger@santos.com. Respectfully, Garret Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-403 Program Change Application for Sundry Schematic Directional Surveys Respectfully, Garret Staudinger 13-3/8” casing was later found to be parted at 2,837’ MD. NDB-024 PB1 Sundry 09.27.23 - 1 - 27-Sep-23 Application for Sundry NDB-024 Well Program Change NDB-024 PB1 Sundry 09.27.23 - 2 - 27-Sep-23 Proposed Drilling ProgramChange The proposed drilling program changes to NDB-024 are listed below. The abandoned 16” hole section will be designated NDB-024 PB1. Current Well Conditions 1. 16” Surface hole drilled to 3181’ MD (77 deg inclination). 2. 13-3/8” surface casing run to 3171’ MD. 3. RIH with fishing BHA (to fish dropped BOP nut) and discovered top plug hung up at damaged connection at 2837’ MD. 4. Cleanout run made to 3040’ MD to drill plugs and float collar. 5. RIH with test packer to 2824’ MD (above damaged connection). Test 13-3/8” casing to 2600 psi for 30 min – good test. 6. RIH with test packer to 3077’ MD (above float collar). Test 13-3/8” casing and shut down test after 275 psi – failed test. 7. Attempt to come out of hole and unable to work packer past 2837’ MD. 8. RIH and push casing fish (~335’ long) to TD, ~10’ MD. 9. Pick up hole with test packer and unable to work past parted casing at 2837’ MD. Proposed Program Changes 1. Run wireline down drill pipe and sever top connection of test packer with severing tool. 2. Run 13-3/8” Cement Retainer Squeeze Packer and set at ~2750’ MD. 3. Sting into cement retainer and perform injectivity test. 4. Pump cement and squeeze 100 bbls (561 cuft, 482 sks) of 15.8ppg HalCem cement (yield 1.165 cuft/sk). 5. Squeeze 50-70 bbls away, and perform hesitation squeeze as required. Targeting squeeze pressure is 500 psi above initial injectivity pressure. 6. RU wireline and run ultrasonic CBL to as deep as possible without a tractor (65 deg inclination at ~2500’). Submit results to AOGCC. 7. MU 13-3/8” whipstock BHA and set on cement retainer. 8. Mill window and 20-50’ of new hole. 9. Perform LOT. Minimum 13.3ppg LOT required for Kick Tolerance. Shut down pumps at maximum 16.5ppg EMW FIT achieved. 10. Displace well to 12.0ppg MOBM. POOH and LD milling BHA. 11. PU drilling BHA and drill ahead 12-1/4” intermediate hole section per original directional plan. 12. Continue with operations as proposed in NDB-024 PTD 223-076. unable to work past parted casing at 2837’ MD. See attached emails for approval to proceed. -bjm Ve r t U n c e r t 1 s d [f t ] 0. 0 0 0. 0 0 St a r t M D E n d M D Su r v e y D a t e [f t ] [ f t ] 46 . 6 3 5 0 9 . 0 0 18 / S e p / 2 0 2 3 50 9 . 0 0 3 1 8 1 . 0 0 18 / S e p / 2 0 2 3 MD T V D N o r t h E a s t G r i d E a s t G r i d N o r t h L a t i t u d e L o n git u d e S h a pe [f t ] [ f t ] [ f t ] [ f t ] [ U S f t ] [ U S f t ] N/ A 4 1 6 1 . 4 6 1 3 1 3 1 . 4 5 - 9 6 7 4 . 9 1 1 5 5 2 7 6 6 . 0 0 5 9 8 5 7 7 1 . 0 0 7 0 ° 2 2 ' 1 6 . 8 1 2 7 " N 1 5 0 ° 4 2 ' 4 4 . 6 1 0 9 " W po i n t N/ A 4 2 1 9 . 4 6 7 9 8 5 . 4 0 - 6 6 2 8 . 8 6 1 5 5 5 7 5 8 . 0 0 5 9 8 0 5 9 4 . 0 0 7 0 ° 2 1 ' 2 6 . 2 3 3 1 " N 1 5 0 ° 4 1 ' 1 5 . 3 6 2 6 " W po l y g o n N/ A 4 2 1 9 . 4 6 9 8 7 8 . 0 2 - 7 7 4 8 . 7 4 1 5 5 4 6 5 8 . 0 0 5 9 8 2 4 9 8 . 0 0 7 0 ° 2 1 ' 4 4 . 8 3 6 8 " N 1 5 0 ° 4 1 ' 4 8 . 1 6 0 4 " W po i n t N/ A 4 2 3 9 . 4 6 7 9 8 5 . 4 0 - 6 6 2 8 . 8 6 1 5 5 5 7 5 8 . 0 0 5 9 8 0 5 9 4 . 0 0 7 0 ° 2 1 ' 2 6 . 2 3 3 1 " N 1 5 0 ° 4 1 ' 1 5 . 3 6 2 6 " W po l y g o n St a r t M D E n d M D I n t e r v a l S t a r t T V D E n d T V D S t a r t N / S S t a r t E / W E n d N / S E n d E / W [f t ] [ f t ] [ f t ] [ f t ] [ f t ] [ f t ] [ f t ] [ f t ] [ f t ] 46 . 6 3 1 2 8 . 0 0 8 1 . 3 7 4 6 . 6 3 1 2 8 . 0 0 0 . 0 0 0 . 0 0 0 . 1 0 0 46 . 6 3 3 1 7 1 . 3 0 3 1 2 4 . 6 7 4 6 . 6 3 2 2 8 4 . 8 2 0 . 0 0 0 . 0 0 1 3 5 1 . 3 2 - 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2 . 1 8 1 5 6 2 3 0 0 . 6 4 5 9 7 2 5 5 2 . 7 8 7 0 ° 2 0 ' 7 . 8 4 2 0 " N 1 5 0 ° 3 8 ' 1 . 6 2 6 2 " W 3 . 8 2 - 9 . 7 5 2 3 . 8 2 2 . 6 4 1 0 . 9 6 1 . 3 8 1 . 2 9 2 . 3 6 7 4 . 3 2 57 9 . 2 0 9 . 1 9 3 4 8 . 3 2 5 7 8 . 1 6 5 0 8 . 7 0 2 1 . 3 6 - 3 . 9 1 1 5 6 2 2 9 9 . 0 2 5 9 7 2 5 6 2 . 1 5 7 0 ° 2 0 ' 7 . 9 3 4 0 " N 1 5 0 ° 3 8 ' 1 . 6 7 6 6 " W 4 . 0 3 - 1 7 . 6 8 8 3 . 9 9 - 4 . 2 7 1 9 . 5 1 1 . 4 8 1 . 3 5 2 . 3 6 7 5 . 51 67 3 . 0 8 1 2 . 4 1 3 4 3 . 6 0 6 7 0 . 3 6 6 0 0 . 9 0 3 8 . 3 8 - 8 . 2 7 1 5 6 2 2 9 4 . 8 3 5 9 7 2 5 7 9 . 2 1 7 0 ° 2 0 ' 8 . 1 0 1 4 " N 1 5 0 ° 3 8 ' 1 . 8 0 4 1 " W 3 . 5 5 - 4 2 . 7 0 2 3 . 4 3 - 5 . 0 3 3 5 . 8 1 1 . 5 8 1 . 4 4 2 . 3 8 2 5 5. 0 0 77 6 . 0 3 1 4 . 4 4 3 3 6 . 4 7 7 7 0 . 5 0 7 0 1 . 0 4 6 0 . 7 7 - 1 6 . 5 2 1 5 6 2 2 8 6 . 8 1 5 9 7 2 6 0 1 . 6 8 7 0 ° 2 0 ' 8 . 3 2 1 5 " N 1 5 0 ° 3 8 ' 2 . 0 4 5 0 " W 2 . 5 4 - 3 2 . 8 8 1 . 9 7 - 6 . 9 3 5 8 . 7 2 1 . 7 5 1 . 6 6 2 . 4 0 2 5 4. 3 9 87 0 . 9 5 1 6 . 5 8 3 3 1 . 7 4 8 6 1 . 9 6 7 9 2 . 5 0 8 3 . 5 5 - 2 7 . 6 6 1 5 6 2 2 7 5 . 9 1 5 9 7 2 6 2 4 . 5 8 7 0 ° 2 0 ' 8 . 5 4 5 6 " N 1 5 0 ° 3 8 ' 2 . 3 7 0 4 " W 2 . 6 2 - 4 2 . 4 2 3 2 . 2 5 - 4 . 9 8 8 3 . 6 7 1 . 9 6 1 . 9 4 2 . 4 3 2 75 . 3 3 96 5 . 9 0 1 9 . 4 6 3 2 4 . 2 5 9 5 2 . 2 6 8 8 2 . 8 0 1 0 8 . 3 3 - 4 3 . 3 2 1 5 6 2 2 6 0 . 5 1 5 9 7 2 6 4 9 . 5 1 7 0 ° 2 0 ' 8 . 7 8 9 3 " N 1 5 0 ° 3 8 ' 2 . 8 2 7 7 " W 3 . 8 9 - 2 4 . 4 2 1 3 . 0 3 - 7 . 8 9 1 1 2 . 9 1 2 . 3 2 2 . 2 0 2 . 4 6 3 2 7 . 4 0 10 4 6 . 0 0 2 2 . 1 8 3 2 1 . 0 1 1 0 2 7 . 1 2 9 5 7 . 6 6 1 3 0 . 9 1 - 6 0 . 6 4 1 5 6 2 2 4 3 . 4 4 59 7 2 6 7 2 . 2 8 7 0 ° 2 0 ' 9 . 0 1 1 5 " N 1 5 0 ° 3 8 ' 3 . 3 3 3 4 " W 3 . 6 9 - 2 1 . 3 9 4 3 . 4 0 - 4 . 0 4 1 4 1 . 3 6 2 . 7 3 2 . 4 5 2 . 4 9 3 2 7 . 0 5 U p p e r S c h r a d d e r B l u f f 10 6 1 . 2 8 2 2 . 7 1 3 2 0 . 4 8 1 0 4 1 . 2 4 9 7 1 . 7 8 1 3 5 . 4 3 - 6 4 . 3 3 1 5 6 2 2 3 9 . 7 9 5 9 7 2 6 7 6 . 8 3 7 0 ° 2 0 ' 9 . 0 5 5 9 " N 1 5 0 ° 3 8 ' 3 . 4 4 1 2 " W 3 . 6 9 0 . 4 8 4 3 . 4 4 - 3 . 4 9 1 4 7 . 1 9 2 . 7 7 2 . 4 8 2 . 4 9 3 2 6 . 6 5 11 5 5 . 7 8 2 4 . 6 9 3 2 0 . 5 2 1 1 2 7 . 7 7 1 0 5 8 . 3 1 1 6 4 . 7 4 - 8 8 . 4 9 1 5 6 2 2 1 5 . 9 4 5 9 7 2 7 0 6 . 3 9 7 0 ° 2 0 ' 9 . 3 4 4 1 " N 1 5 0 ° 3 8 ' 4 . 1 4 6 8 " W 2 . 1 0 1 1 . 9 0 3 2 . 1 0 0 . 0 4 1 8 5 . 1 2 3 . 3 0 2 . 7 6 2 . 54 3 2 4 . 1 2 11 6 4 . 0 0 2 4 . 8 2 3 2 0 . 5 9 1 1 3 5 . 2 4 1 0 6 5 . 7 8 1 6 7 . 4 0 - 9 0 . 6 7 1 5 6 2 2 1 3 . 7 8 5 9 7 2 7 0 9 . 0 7 7 0 ° 2 0 ' 9 . 3 7 0 3 " N 1 5 0 ° 3 8 ' 4 . 2 1 0 6 " W 1 . 6 3 1 1 . 8 4 3 1 . 6 0 0 . 8 0 1 8 8 . 5 5 3 . 6 0 2 . 9 1 2 . 56 3 2 3 . 1 2 B a s e I c e B e a r i n g P e r m a f r o s t 12 5 0 . 1 5 2 6 . 2 0 3 2 1 . 2 4 1 2 1 2 . 9 8 1 1 4 3 . 5 2 1 9 6 . 2 0 - 1 1 4 . 0 6 1 5 6 2 1 9 0 . 7 0 5 9 7 2 7 3 8 . 1 1 7 0 ° 2 0 ' 9 . 6 5 3 6 " N 1 5 0 ° 3 8 ' 4 . 8 9 3 7 " W 1 . 6 3 7 . 1 8 3 1 . 6 0 0 . 7 6 2 2 5 . 6 1 3 . 8 8 3 . 0 4 2 . 61 3 2 2 . 5 0 13 4 4 . 9 0 2 8 . 3 9 3 2 1 . 8 2 1 2 9 7 . 1 8 1 2 2 7 . 7 2 2 3 0 . 2 2 - 1 4 1 . 0 8 1 5 6 2 1 6 4 . 0 3 5 9 7 2 7 7 2 . 4 1 7 0 ° 2 0 ' 9 . 9 8 8 2 " N 1 5 0 ° 3 8 ' 5 . 6 8 2 9 " W 2 . 3 3 1 . 6 8 6 2 . 3 1 0 . 6 1 2 6 9 . 0 3 4 . 5 2 3 . 3 2 2 . 69 3 2 1 . 7 1 14 3 9 . 1 8 3 1 . 4 0 3 2 1 . 9 9 1 3 7 8 . 9 1 1 3 0 9 . 4 5 2 6 7 . 2 0 - 1 7 0 . 0 7 1 5 6 2 1 3 5 . 4 4 5 9 7 2 8 0 9 . 6 8 7 0 ° 2 0 ' 1 0 . 3 5 1 8 " N 1 5 0 ° 3 8 ' 6 . 5 2 9 5 " W 3 . 1 9 8 . 9 4 8 3 . 1 9 0 . 1 8 3 1 6 . 0 0 5 . 2 4 3 . 6 2 2 .7 8 3 2 1 . 3 3 14 5 4 . 0 0 3 1 . 7 6 3 2 2 . 1 0 1 3 9 1 . 5 3 1 3 2 2 . 0 7 2 7 3 . 3 2 - 1 7 4 . 8 4 1 5 6 2 1 3 0 . 7 3 5 9 7 2 8 1 5 . 8 5 7 0 ° 2 0 ' 1 0 . 4 1 2 0 " N 1 5 0 ° 3 8 ' 6 . 6 6 8 9 " W 2 . 4 7 8 . 8 5 6 2 . 4 4 0 . 7 3 3 2 3 . 7 5 5 . 6 8 3 . 7 9 2 .8 2 3 2 1 . 2 1 B a s e P e r m a f r o s t T r a n s i t i o n 15 3 4 . 7 7 3 3 . 7 3 3 2 2 . 6 5 1 4 5 9 . 4 6 1 3 9 0 . 0 0 3 0 7 . 9 2 - 2 0 1 . 5 1 1 5 6 2 1 0 4 . 4 3 5 9 7 2 8 5 0 . 7 3 7 0 ° 2 0 ' 1 0 . 7 5 2 4 " N 1 5 0 ° 3 8 ' 7 . 4 4 7 8 " W 2 . 4 7 - 9 . 5 0 8 2 . 4 4 0 . 6 8 3 6 7 . 4 3 6 . 0 3 3 . 9 2 2. 8 8 3 2 1 . 1 8 16 2 9 . 1 8 3 6 . 8 5 3 2 1 . 7 8 1 5 3 6 . 5 1 1 4 6 7 . 0 5 3 5 1 . 0 1 - 2 3 4 . 9 4 1 5 6 2 0 7 1 . 4 6 5 9 7 2 8 9 4 . 1 6 7 0 ° 2 0 ' 1 1 . 1 7 6 1 " N 1 5 0 ° 3 8 ' 8 . 4 2 4 0 " W 3 . 3 5 - 2 4 . 7 0 1 3 . 3 0 - 0 . 9 2 4 2 1 . 9 5 6 . 9 0 4 . 21 3 . 0 0 3 2 1 . 1 2 17 2 3 . 5 8 3 9 . 3 9 3 1 9 . 9 5 1 6 1 0 . 7 8 1 5 4 1 . 3 2 3 9 6 . 1 9 - 2 7 1 . 7 3 1 5 6 2 0 3 5 . 1 4 5 9 7 2 9 3 9 . 7 1 7 0 ° 2 0 ' 1 1 . 6 2 0 4 " N 1 5 0 ° 3 8 ' 9 . 4 9 8 7 " W 2 . 9 4 7 . 1 1 4 2 . 6 9 - 1 . 9 4 4 8 0 . 1 4 7 . 8 6 4 . 5 0 3. 1 3 3 2 0 . 9 4 18 1 8 . 4 6 4 2 . 0 2 3 2 0 . 4 4 1 6 8 2 . 7 0 1 6 1 3 . 2 4 4 4 3 . 7 2 - 3 1 1 . 3 3 1 5 6 1 9 9 6 . 0 4 5 9 7 2 9 8 7 . 6 5 7 0 ° 2 0 ' 1 2 . 0 8 8 0 " N 15 0 ° 3 8 ' 1 0 . 6 5 5 4 " W 2. 7 9 7 . 2 0 4 2 . 7 7 0 . 5 2 5 4 1 . 9 1 8 . 9 0 4 . 7 8 3 . 2 9 3 2 0 . 6 9 19 1 3 . 0 5 4 4 . 8 1 3 2 0 . 9 4 1 7 5 1 . 4 0 1 6 8 1 . 9 4 4 9 4 . 0 2 - 3 5 2 . 5 1 1 5 6 1 9 5 5 . 3 9 5 9 7 3 0 3 8 . 3 7 7 0 ° 2 0 ' 1 2 . 5 8 2 6 " N 15 0 ° 3 8 ' 1 1 . 8 5 8 0 " W 2. 9 7 9 . 6 8 7 2 . 9 5 0 . 5 3 6 0 6 . 8 2 1 0 . 0 2 5 . 0 6 3 . 4 7 3 2 0 . 5 5 19 3 2 . 0 0 4 5 . 4 3 3 2 1 . 0 9 1 7 6 4 . 7 7 1 6 9 5 . 3 1 5 0 4 . 4 6 - 3 6 0 . 9 5 1 5 6 1 9 4 7 . 0 5 5 9 7 3 0 4 8 . 9 0 7 0 ° 2 0 ' 1 2 . 6 8 5 3 " N 15 0 ° 3 8 ' 1 2 . 1 0 4 8 " W 3. 3 2 9 . 5 8 2 3 . 2 8 0 . 7 8 6 2 0 . 2 4 1 0 . 7 2 5 . 2 1 3 . 5 8 3 2 0 . 5 1 M i d d l e S h r a d d e r B l u f f 20 0 7 . 3 4 4 7 . 9 0 3 2 1 . 6 5 1 8 1 6 . 4 7 1 7 4 7 . 0 1 5 4 7 . 2 7 - 3 9 5 . 1 6 1 5 6 1 9 1 3 . 3 0 5 9 7 3 0 9 2 . 0 5 7 0 ° 2 0 ' 1 3 . 1 0 6 3 " N 15 0 ° 3 8 ' 1 3 . 1 0 3 8 " W 3. 3 2 - 1 0 . 6 3 1 3 . 2 8 0 . 7 5 6 7 4 . 9 9 1 1 . 2 2 5 . 3 2 3 . 6 6 3 2 0 . 5 3 21 0 1 . 7 8 5 0 . 7 5 3 2 0 . 9 6 1 8 7 8 . 0 2 1 8 0 8 . 5 6 6 0 3 . 1 6 - 4 3 9 . 9 4 1 5 6 1 8 6 9 . 1 1 5 9 7 3 1 4 8 . 4 0 7 0 ° 2 0 ' 1 3 . 6 5 6 0 " N 15 0 ° 3 8 ' 1 4 . 4 1 1 8 " W 3. 0 7 - 1 4 . 1 3 5 3 . 0 2 - 0 . 7 3 7 4 6 . 5 5 1 2 . 5 1 5 . 5 7 3 . 8 7 3 2 0 . 5 4 21 9 5 . 9 2 5 3 . 9 0 3 1 9 . 9 8 1 9 3 5 . 5 5 1 8 6 6 . 0 9 6 6 0 . 6 1 - 4 8 7 . 3 7 1 5 6 1 8 2 2 . 2 9 5 9 7 3 2 0 6 . 3 4 7 0 ° 2 0 ' 1 4 . 2 2 1 0 " N 15 0 ° 3 8 ' 1 5 . 7 9 7 1 " W 3. 4 5 - 5 . 1 5 7 3 . 3 5 - 1 . 0 4 8 2 0 . 9 3 1 3 . 8 8 5 . 8 1 4 . 1 0 3 2 0 . 4 9 22 9 0 . 7 3 5 7 . 5 5 3 1 9 . 5 9 1 9 8 8 . 9 3 1 9 1 9 . 4 7 7 2 0 . 4 2 - 5 3 7 . 9 5 1 5 6 1 7 7 2 . 3 4 5 9 7 3 2 6 6 . 6 7 7 0 ° 2 0 ' 1 4 . 8 0 9 2 " N 15 0 ° 3 8 ' 1 7 . 2 7 4 6 " W 3. 8 6 - 3 . 1 8 3 3 . 8 5 - 0 . 4 1 8 9 9 . 0 9 1 5 . 3 6 6 . 0 4 4 . 3 5 3 2 0 . 3 8 23 8 5 . 8 6 6 1 . 3 4 3 1 9 . 3 5 2 0 3 7 . 2 8 1 9 6 7 . 8 2 7 8 2 . 6 8 - 5 9 1 . 1 8 1 5 6 1 7 1 9 . 7 6 5 9 7 3 3 2 9 . 4 7 7 0 ° 2 0 ' 1 5 . 4 2 1 5 " N 15 0 ° 3 8 ' 1 8 . 8 2 9 4 " W 3. 9 9 7 . 7 6 6 3 . 9 8 - 0 . 2 5 9 8 0 . 7 8 1 6 . 9 3 6 . 2 5 4 . 6 2 3 2 0 . 2 6 24 8 1 . 3 7 6 5 . 6 2 3 1 9 . 9 9 2 0 7 9 . 9 2 2 0 1 0 . 4 6 8 4 7 . 8 2 - 6 4 6 . 4 6 1 5 6 1 6 6 5 . 1 6 5 9 7 3 3 9 5 . 1 7 7 0 ° 2 0 ' 1 6 . 0 6 2 1 " N 15 0 ° 3 8 ' 2 0 . 4 4 4 4 " W 4. 5 2 1 . 0 5 1 4 . 4 8 0 . 6 7 1 0 6 6 . 0 2 1 8 . 5 9 6 . 4 4 4 . 9 1 3 2 0 . 1 9 25 7 4 . 5 7 6 8 . 1 5 3 2 0 . 0 4 2 1 1 6 . 5 1 2 0 4 7 . 0 5 9 1 3 . 4 9 - 7 0 1 . 5 4 1 5 6 1 6 1 0 . 7 8 5 9 7 3 4 6 1 . 4 1 7 0 ° 2 0 ' 1 6 . 7 0 7 9 " N 15 0 ° 3 8 ' 2 2 . 0 5 3 3 " W 2. 7 2 - 4 . 0 1 4 2 . 7 1 0 . 0 5 1 1 5 1 . 5 6 2 0 . 2 8 6 . 6 0 5 . 2 1 3 2 0 . 1 6 26 6 0 . 0 0 7 0 . 3 4 3 1 9 . 8 8 2 1 4 6 . 7 8 2 0 7 7 . 3 2 9 7 4 . 6 4 - 7 5 2 . 9 3 1 5 6 1 5 6 0 . 0 3 5 9 7 3 5 2 3 . 0 9 7 0 ° 2 0 ' 1 7 . 3 0 9 4 " N 1 5 0 ° 3 8 ' 2 3 . 5 5 4 5 " W 2. 5 7 - 3 . 9 5 6 2 . 5 7 - 0 . 1 9 1 2 3 1 . 2 8 2 1 . 9 4 6 . 7 4 5 . 5 1 3 2 0 . 1 5 M C U Ac t u a l W e l l p a t h G e o g r a p h i c R e p o r t - i n c l u d i n g P o s i t i o n U n c e r t a i n t y Re p o r t b y B a k e r H u g h e s Op e r a t o r Ar e a We l l p a t h We l l b o r e l a s t r e v i s e d 6L G H W U D F N I U R P Us e r Ca l c u l a t i o n m e t h o d Fi e l d Fa c i l i t y Sl o t We l l We l l b o r e ND B B- 2 4 ND B - 0 2 4 ND B - 0 2 4 P B 1 ND B - 0 2 4 P B 1 09 / 2 7 / 2 0 2 3 (n o n e ) Ab a k a b d 0 1 Mi n i m u m c u r v a t u r e 69 . 4 6 f t 69 . 4 6 f t E 0 . 0 0 f t N 0 . 0 0 f t Ma g n e t i c N o r t h i s 1 4 . 6 3 d e g r e e s E a s t o f T r u e N o r t h 2. 0 0 S t d D e v We l l A r c h i t e c t D B L o c a l Pr o j e c t i o n S y s t e m No r t h R e f e r e n c e Sc a l e Co n v e r g e n c e a t S l o t Ho r i z o n t a l R e f e r e n c e P o i n t Ve r t i c a l R e f e r e n c e P o i n t MD R e f e r e n c e P o i n t Fi e l d V e r t i c a l R e f e r e n c e As D r i l l e d ( R T ) T o F a c i l i t y V e r t i c a l D a t u m As D r i l l e d ( R T ) T o M e a n S e a L e v e l As D r i l l e d ( R T ) t o G r o u n d L e v e l a t S l o t ( B - 2 4 ) Se c t i o n O r i g i n X Se c t i o n O r i g i n Y 27 / S e p / 2 0 2 3 a t 1 1 : 4 1 u s i n g W e l l A r c h i t e c t 6 . 0 Sa n t o s Al a s k a Pi k k a NA D 8 3 / T M A l a s k a S P , Z o n e 4 ( 5 0 0 4 ) , U S f e e t Tr u e 0. 9 9 9 9 0 7 0. 6 0 W e s t Sl o t As D r i l l e d ( R T ) As D r i l l e d ( R T ) Me a n S e a L e v e l 69 . 4 6 f t 32 3 . 6 2 ° in c l u d e d 46 . 6 3 f t Lo c a l E a s t G r i d N o r t h L o n g i t u d e Se c t i o n A z i m u t h Su r f a c e P o s i t i o n U n c e r t a i n t y El l i p s e S t a r t i n g M D De c l i n a t i o n El l i p s e C o n f i d e n c e L i m i t Da t a b a s e Sl o t L o c a t i o n Fa c i l i t y R e f e r e n c e P t Fi e l d R e f e r e n c e P t Lo c a l N o r t h [f t ] -1 2 8 . 6 0 [f t ] -1 1 1 2 . 4 7 Gr i d E a s t [U S f t ] 15 6 2 3 0 2 . 7 0 15 6 3 4 1 6 . 3 3 15 6 3 4 1 6 . 3 3 [U S f t ] 59 7 2 5 4 0 . 7 5 59 7 2 6 5 7 . 9 1 59 7 2 6 5 7 . 9 1 La t i t u d e 70 ° 2 0 ' 7 . 7 2 3 9 " N 70 ° 2 0 ' 8 . 9 8 9 5 " N 70 ° 2 0 ' 8 . 9 8 9 5 " N 15 0 ° 3 8 ' 1 . 5 6 2 5 " W 15 0 ° 3 7 ' 2 9 . 0 7 3 0 " W 15 0 ° 3 7 ' 2 9 . 0 7 3 0 " W Ho r i z U n c e r t 1 s d [f t ] 0. 3 0 0. 3 0 SD I A d K v 1 . 0 5 0 1 S D I G y r o _ 1 6 i n H o l e < 1 0 0 - 5 0 9 > N D B - 0 2 4 P B 1 OW S G M W D r e v 2 ( M S + I F R 2 , S A G ) 0 2 B H O n t r a K _ 1 6 i n H o l e < 5 7 9 - 3 1 0 8 > N D B - 0 2 4 P B 1 Po s i t i o n a l U n c e r t a i n t y M o d e l L o g N a m e / C o m m e n t We l l b o r e NB D - 0 2 4 H e e l v . 1 NB D - 0 2 4 P o s t F a u l t v . 0 NB D - 0 2 4 H e e l v . 0 Ta r g e t N a m e Co m m e n t ND B - 0 2 4 T D v . 0 13 . 3 7 5 i n C a s i n g S u r f a c e ND B - 0 2 4 P B 1 16 i n O p e n H o l e ND B - 0 2 4 P B 1 St r i n g / D i a m e t e r We l l b o r e 20 i n C o n d u c t o r ND B - 0 2 4 P B 1 Pa g e 1 o f 2 26 6 8 . 7 8 7 0 . 5 7 3 1 9 . 8 6 2 1 4 9 . 7 1 2 0 8 0 . 2 5 9 8 0 . 9 7 - 7 5 8 . 2 7 1 5 6 1 5 5 4 . 7 6 5 9 7 3 5 2 9 . 4 7 7 0 ° 2 0 ' 1 7 . 3 7 1 6 " N 1 5 0 ° 3 8 ' 2 3 . 7 1 0 3 " W 2. 5 7 - 5 . 0 7 5 2 . 5 7 - 0 . 1 9 1 2 3 9 . 5 4 2 2 . 0 3 6 . 7 4 5 . 5 3 3 2 0 . 1 4 27 6 4 . 0 4 7 2 . 8 3 3 1 9 . 6 5 2 1 7 9 . 6 2 2 1 1 0 . 1 6 1 0 5 0 . 0 0 - 8 1 6 . 6 9 1 5 6 1 4 9 7 . 0 6 5 9 7 3 5 9 9 . 1 0 7 0 ° 2 0 ' 1 8 . 0 5 0 4 " N 1 5 0 ° 3 8 ' 2 5 . 4 1 7 1 " W 2. 3 8 1 . 7 0 1 2 . 3 7 - 0 . 2 2 1 3 2 9 . 7 7 2 3 . 8 4 6 . 8 7 5 . 8 6 3 2 0 . 1 2 28 5 8 . 7 8 7 4 . 7 8 3 1 9 . 7 1 2 2 0 6 . 0 4 2 1 3 6 . 5 8 1 1 1 9 . 3 6 - 8 7 5 . 5 6 1 5 6 1 4 3 8 . 9 3 5 9 7 3 6 6 9 . 0 6 7 0 ° 2 0 ' 1 8 . 7 3 2 6 " N 15 0 ° 3 8 ' 2 7 . 1 3 6 8 " W 2. 0 6 - 1 . 7 0 6 2 . 0 6 0 . 0 6 1 4 2 0 . 5 3 2 5 . 6 7 6 . 9 9 6 . 2 0 3 2 0 . 0 9 29 5 2 . 7 8 7 5 . 4 3 3 1 9 . 6 9 2 2 3 0 . 2 1 2 1 6 0 . 7 5 1 1 8 8 . 6 4 - 9 3 4 . 3 2 1 5 6 1 3 8 0 . 9 0 5 9 7 3 7 3 8 . 9 5 7 0 ° 2 0 ' 1 9 . 4 1 3 9 " N 15 0 ° 3 8 ' 2 8 . 8 5 3 2 " W 0. 6 9 7 9 . 7 2 6 0 . 6 9 - 0 . 0 2 1 5 1 1 . 1 6 2 7 . 5 1 7 . 1 0 6 . 5 5 3 2 0 . 0 6 30 4 8 . 6 6 7 5 . 5 7 3 2 0 . 4 8 2 2 5 4 . 2 1 2 1 8 4 . 7 5 1 2 5 9 . 8 4 - 9 9 3 . 8 8 1 5 6 1 3 2 2 . 0 9 5 9 7 3 8 1 0 . 7 5 7 0 ° 2 0 ' 2 0 . 1 1 4 1 " N 15 0 ° 3 8 ' 3 0 . 5 9 3 2 " W 0. 8 1 - 1 0 3 . 4 2 0 . 1 5 0 . 8 2 1 6 0 3 . 8 1 2 9 . 4 0 7 . 2 1 6 . 9 2 3 2 0 . 0 7 31 0 8 . 4 8 7 5 . 5 4 3 2 0 . 3 5 2 2 6 9 . 1 3 2 1 9 9 . 6 7 1 3 0 4 . 4 9 - 1 0 3 0 . 7 9 1 5 6 1 2 8 5 . 6 5 5 9 7 3 8 5 5 . 7 8 7 0 ° 2 0 ' 2 0 . 5 5 3 1 " N 15 0 ° 3 8 ' 3 1 . 6 7 1 6 " W 0. 2 2 0 - 0 . 0 5 - 0 . 2 2 1 6 6 1 . 6 4 3 0 . 5 7 7 . 2 8 7 . 1 5 3 2 0 . 0 8 31 8 1 . 0 0 7 5 . 5 4 3 2 0 . 3 5 2 2 8 7 . 2 4 2 2 1 7 . 7 8 1 3 5 8 . 5 5 - 1 0 7 5 . 6 0 1 5 6 1 2 4 1 . 4 1 5 9 7 3 9 1 0 . 3 0 7 0 ° 2 0 ' 2 1 . 0 8 4 8 " N 1 5 0 ° 3 8 ' 3 2 . 9 8 0 7 " W 0. 0 0 N / A 0 . 0 0 0 . 0 0 1 7 3 1 . 7 5 3 2 . 0 1 7 . 3 6 7 . 4 4 3 2 0 . 0 9 T D Pa g e 2 o f 2 NDB-024 GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,570' MD Top of 13-3/8" Whipstock2,720' MD 1-½” GLM Shear Valve~2,400' MD 4-½” X-Nipple~2,440' MD 4-½” X-Nipple~11,284' MD 9-5/8", 47ppf L-80 Production Liner11,591' MD 4-½”, 12.6ppf P-110S Production Liner 18,045' MD 4-½” Liner Hanger and Liner Top Packer11,441' MD 4-½” 12.6ppf P-110S Completion w/ Tieback Seals11,436' MD 4-½” X-Nipple~11,424' MD 4-½” Openhole Packers one every 500' -700' with Frac Ports Toe Sleeve Shutoff Collar *Quantity of openhole packer and frac sleeve may change 4-½” Gaslift Sliding Sleeve (Contingency)~11,376' MD Archer C-Flex Two-Stage Cementing Tool (~2950' TVDss)~6,550' MD TOC First Stage Cement Job - 250' TVD above Nanushuk~9,100' MD 16" Hole Size 12-1/4" Hole Size 8-1/2" Hole Size 4-½” Gaslift w/ Downhole Psi/Temp Gauge~11,328' MD 13-3/8" Casing Fish 2847'-3181' MD 13-3/8" 68ppf L80 Casing Severed at 2837' NDB-024 PB1 Updated 9/27/2023 Proposed Wellbore Diagram -bjm From:Rixse, Melvin G (OGC) To:Staudinger, Garret (Garret); McLellan, Bryan J (OGC) Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Tirpack, Robert (Robert); Lambe, Steven (Steven) Subject:RE: NDB-24 (PTD 223-076) surface casing cement Date:Sunday, October 1, 2023 11:06:21 AM Garret, Thanks for the notification and data. Oil Search is approved to drill ahead with a 13.8 PPGE FIT. AOGCC (Bryan McLellan) will contact Oil Search tomorrow to discuss the shallow section of surface casing that had questionable bonding and let you know of the additional evaluation requests. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Bryan, Davies, Dewhurst, Tirpack Lambe From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Sunday, October 1, 2023 10:16 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Lambe, Steven (Steven) <Steven.Lambe@contractor.santos.com> Subject: RE: NDB-24 (PTD 223-076) surface casing cement Mel, Attached is the casing test and FIT data. Results all looked good. I’ll call shortly to discuss. Thanks, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Saturday, September 30, 2023 11:10 AM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Lambe, Steven (Steven) <Steven.Lambe@contractor.santos.com> Subject: ![EXT]: RE: NDB-24 (PTD 223-076) surface casing cement Garret, As discussed over the phone this morning, Oil Search is approved to drill ahead after setting whipstock and milling the window provided the an FIT of 13.3 PPGE is achieved. I will be available 24/7 and will answer a phone call today and tomorrow. I would like to review the digital FIT and casing test data before drilling ahead. Please call me when you receive this data. My phone is 907- 223-3605. A middle of the night call is not a problem. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Tirpack, Lambe, Dewhurst, Davies, McLellan From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Saturday, September 30, 2023 10:34 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Lambe, Steven (Steven) <Steven.Lambe@contractor.santos.com> Subject: Re: NDB-24 (PTD 223-076) surface casing cement Mel, Based on our conversation this morning on the results from the CBL, can you please confirm that we are approved to drill ahead in the intermediate hole section if we achieve the 13.3ppg FIT? I will send through the results from the FIT after we perform the test which should be around sometime 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. tomorrow morning. Thanks for your time and let me know if you have any questions. Regards, Garret Get Outlook for iOS From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, September 28, 2023 6:38 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Lambe, Steven (Steven) <Steven.Lambe@contractor.santos.com> Subject: ![EXT]: Re: NDB-24 (PTD 223-076) surface casing cement Garret, Oilsearch has approval to proceed with the plan outlined in your email below. If the Halliburton logs provide answers about the source of gas, the isolation scanner won’t be required. Thanks Bryan Sent from my iPhone On Sep 28, 2023, at 6:18 PM, Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> wrote: Bryan, Oil Search Alaska has reviewed the requirement outlined in the below email and offer the following update and path forward to address concerns related to the cement integrity of the NDB-024 surface casing. Operational Update: Schlumberger’s E-line Conveyed Isolation Scanner failed surface checks, and we are currently sourcing another tool from out of state. Current estimated arrival is unknown. No tractor that can be run inside the 13-3/8” casing is currently available in Alaska. We are evaluating options to source tractors if necessary. Halliburton E-Line Acoustic Conformance Xaminer (ACX) tool is available and can be run immediately. This tool has been used in the past to detect the location of shallow annular gas. Halliburton’s segmented sonic bond log is available and can be run to evaluate the location and quality of the tail cement / squeeze cement. Engineering Analysis / Justification To address your concerns listed below we have broken this out into three distinct items: 1. Source of gas bubbling in annulus The Halliburton ACX tool will be used to determine location and source of hydrate gas in the annulus This tool has successfully been used for this application on the slope with other operators 2. Cement isolation behind surface casing The Halliburton segmented sonic bond long will be used to determine presence of 15.3-15.8ppg cement behind the 13-3/8” surface casing This log will be run as deep as possible without a tractor If the 15.8ppg squeeze cement is detected deep in the well, there is good indication that cement exists between the parted casing and cement 3. Isolation between Tuluvak and other permeable formations for life of well considerations Isolation will be proven with both the cement sonic log and the FIT performed after the window is milled in the 13-3/8” casing After milling the window and 20’ of new hole, a formation integrity test will be run. We will target an FIT of 13.3ppg. This will prove that any formation that window is in communication with can hold full Tuluvak pressure without the risk of cross-flow between permeable zones. The Tuluvak pore pressure is estimated at 1326 psi @ 2525’ TVD (10.1ppg). During long term production of this well, if Tuluvak gas migrates to a shallower formation without being allowed to expand, the maximum pressure seen at the window would be an 11.9ppg equivalent (worst case scenario). For this reason, if we achieve an FIT of 13.3ppg, this would ensure that any formation that is exposed to the window can withstand Tuluvak pressure. Proposed Plan Forward: 1. Rig up HES E-Line and run ACX examiner. Log the 13-3/8” casing attempting to identify the source of the shallow gas bubbling in the 13-3/8” conductor. 2. Run the Halliburton segmented bond log as deep as possible and log cement to surface. 3. MU whipstock milling assembly and set whipstock. Mill window and 20’ of new formation. Perform FIT to 13.3ppg. 4. Submit results of logs and FIT to AOGCC Approval is requested to proceed ahead with the proposed plan forward. Additionally, we are requesting to not run an isolation scanner log assuming success of our above outlined plan forward. Please let me know if you have any questions, or feel free to give me a call if you have any questions. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, September 28, 2023 1:00 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: ![EXT]: NDB-24 (PTD 223-076) surface casing cement Garret, Based on your phone call today, we understand that a cement log that can detect 11 ppg cement may not be available until this Saturday and there is a Segmented sonic bond log available now that can identify the location of the 15.7ppg tail cement and the squeezed cement in the 13-3/8” casing. The AOGCC will require a cement log before run before sidetracking to determine the location of cement relative to the planned window depth. For this, the Segmented sonic log or Isolation Scanner are both acceptable. The AOGCC will also require a log to determine the quality of the 11 ppg lead cement in an attempt to identify the source of gas bubbling during and after the primary cement job to inform approval of the next well in the drilling program. The Isolation scanner is acceptable for this purpose and can be run at a later time, before tubing is run in the well. In summary, if the isolation scanner is not available before milling the window, two logs will be required. Alternatively, AOGCC will consider running only one log (isolation scanner) after milling the window, if Oilsearch submits a geologic and engineering analysis to demonstrate why the cement location above the sidetrack window would not have any impact on the drilling phase or future life cycle of the well. The analysis should include an assumption that the Tuluvak may not properly isolated with cement on the intermediate liner, and the base of cement on the 13-3/8” casing is unknown, and permeable zones above the surface casing shoe are uncemented, taking PPFG considerations into account. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> 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 1 Christianson, Grace K (OGC) From:Rixse, Melvin G (OGC) Sent:Saturday, September 30, 2023 11:10 AM To:Staudinger, Garret (Garret); McLellan, Bryan J (OGC) Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Tirpack, Robert (Robert); Lambe, Steven (Steven) Subject:RE: NDB-24 (PTD 223-076) surface casing cement Garret, Asdiscussedoverthephonethismorning,OilSearchisapprovedtodrillaheadaftersettingwhipstockandmilling thewindowprovidedtheanFITof13.3PPGEisachieved.Iwillbeavailable24/7andwillansweraphonecalltodayand tomorrow.IwouldliketoreviewthedigitalFITandcasingtestdatabeforedrillingahead.Pleasecallmewhenyou receivethisdata.Myphoneis907Ͳ223Ͳ3605.Amiddleofthenightcallisnotaproblem. MelRixse SeniorPetroleumEngineer(PE) AlaskaOilandGasConservationCommission 907Ͳ793Ͳ1231Office 907Ͳ297Ͳ8474Cell CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission(AOGCC), StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,useor disclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit, and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactMelRixseat(907Ͳ793Ͳ1231)or(Melvin.Rixse@alaska.gov). cc.Tirpack,Lambe,Dewhurst,Davies,McLellan From:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Sent:Saturday,September30,202310:34AM To:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Tirpack,Robert(Robert)<Robert.Tirpack@santos.com>;Lambe, Steven(Steven)<Steven.Lambe@contractor.santos.com> Subject:Re:NDBͲ24(PTD223Ͳ076)surfacecasingcement Mel, BasedonourconversationthismorningontheresultsfromtheCBL,canyoupleaseconfirmthatweareapprovedto drillaheadintheintermediateholesectionifweachievethe13.3ppgFIT?IwillsendthroughtheresultsfromtheFIT afterweperformthetestwhichshouldbearoundsometimetomorrowmorning. Thanksforyourtimeandletmeknowifyouhaveanyquestions. Regards, Garret GetOutlookforiOS 2 From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Sent:Thursday,September28,20236:38PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>;Tirpack,Robert(Robert)<Robert.Tirpack@santos.com>;Lambe, Steven(Steven)<Steven.Lambe@contractor.santos.com> Subject:![EXT]:Re:NDBͲ24(PTD223Ͳ076)surfacecasingcement Garret, Oilsearchhasapprovaltoproceedwiththeplanoutlinedinyouremailbelow.IftheHalliburtonlogsprovideanswers aboutthesourceofgas,theisolationscannerwon’tberequired. Thanks Bryan SentfrommyiPhone OnSep28,2023,at6:18PM,Staudinger,Garret(Garret)<Garret.Staudinger@santos.com>wrote: Bryan, OilSearchAlaskahasreviewedtherequirementoutlinedinthebelowemailandofferthefollowing updateandpathforwardtoaddressconcernsrelatedtothecementintegrityoftheNDBͲ024surface casing. OperationalUpdate: x Schlumberger’sEͲlineConveyedIsolationScannerfailedsurfacechecks,andwearecurrently sourcinganothertoolfromoutofstate.Currentestimatedarrivalisunknown. x Notractorthatcanberuninsidethe13Ͳ3/8”casingiscurrentlyavailableinAlaska.Weare evaluatingoptionstosourcetractorsifnecessary. x HalliburtonEͲLineAcousticConformanceXaminer(ACX)toolisavailableandcanberun immediately.Thistoolhasbeenusedinthepasttodetectthelocationofshallowannulargas. x Halliburton’ssegmentedsonicbondlogisavailableandcanberuntoevaluatethelocationand qualityofthetailcement/squeezecement. EngineeringAnalysis/Justification Toaddressyourconcernslistedbelowwehavebrokenthisoutintothreedistinctitems: 1. Sourceofgasbubblinginannulus x TheHalliburtonACXtoolwillbeusedtodeterminelocationandsourceofhydrategasin theannulus x Thistoolhassuccessfullybeenusedforthisapplicationontheslopewithother operators 2. Cementisolationbehindsurfacecasing x TheHalliburtonsegmentedsonicbondlongwillbeusedtodeterminepresenceof15.3Ͳ 15.8ppgcementbehindthe13Ͳ3/8”surfacecasing x Thislogwillberunasdeepaspossiblewithoutatractor 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. 3 x Ifthe15.8ppgsqueezecementisdetecteddeepinthewell,thereisgoodindicationthat cementexistsbetweenthepartedcasingandcement 3. IsolationbetweenTuluvakandotherpermeableformationsforlifeofwellconsiderations x IsolationwillbeprovenwithboththecementsoniclogandtheFITperformedafterthe windowismilledinthe13Ͳ3/8”casing x Aftermillingthewindowand20’ofnewhole,aformationintegritytestwillberun.We willtargetanFITof13.3ppg.Thiswillprovethatanyformationthatwindowisin communicationwithcanholdfullTuluvakpressurewithouttheriskofcrossͲflow betweenpermeablezones. x TheTuluvakporepressureisestimatedat1326psi@2525’TVD(10.1ppg).Duringlong termproductionofthiswell,ifTuluvakgasmigratestoashallowerformationwithout beingallowedtoexpand,themaximumpressureseenatthewindowwouldbean 11.9ppgequivalent(worstcasescenario).Forthisreason,ifweachieveanFITof 13.3ppg,thiswouldensurethatanyformationthatisexposedtothewindowcan withstandTuluvakpressure. ProposedPlanForward: 1. RigupHESEͲLineandrunACXexaminer.Logthe13Ͳ3/8”casingattemptingtoidentifythe sourceoftheshallowgasbubblinginthe13Ͳ3/8”conductor. 2. RuntheHalliburtonsegmentedbondlogasdeepaspossibleandlogcementtosurface. 3. MUwhipstockmillingassemblyandsetwhipstock.Millwindowand20’ofnew formation.PerformFITto13.3ppg. 4. SubmitresultsoflogsandFITtoAOGCC Approvalisrequestedtoproceedaheadwiththeproposedplanforward. Additionally,wearerequestingtonotrunanisolationscannerlogassumingsuccessofourabove outlinedplanforward. Pleaseletmeknowifyouhaveanyquestions,orfeelfreetogivemeacallifyouhaveanyquestions. Regards, GarretStaudinger SeniorDrillingEngineer t:+1(907)375Ͳ4666|m:+1(907)440Ͳ6892 From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Sent:Thursday,September28,20231:00PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Dewhurst,AndrewD(OGC) <andrew.dewhurst@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov> Subject:![EXT]:NDBͲ24(PTD223Ͳ076)surfacecasingcement Garret, Basedonyourphonecalltoday,weunderstandthatacementlogthatcandetect11ppgcementmay notbeavailableuntilthisSaturdayandthereisaSegmentedsonicbondlogavailablenowthatcan identifythelocationofthe15.7ppgtailcementandthesqueezedcementinthe13Ͳ3/8”casing. TheAOGCCwillrequireacementlogbeforerunbeforesidetrackingtodeterminethelocationof cementrelativetotheplannedwindowdepth.Forthis,theSegmentedsoniclogorIsolationScanner 4 arebothacceptable.TheAOGCCwillalsorequirealogtodeterminethequalityofthe11ppglead cementinanattempttoidentifythesourceofgasbubblingduringandaftertheprimarycementjobto informapprovalofthenextwellinthedrillingprogram.TheIsolationscannerisacceptableforthis purposeandcanberunatalatertime,beforetubingisruninthewell. Insummary,iftheisolationscannerisnotavailablebeforemillingthewindow,twologswillbe required. Alternatively,AOGCCwillconsiderrunningonlyonelog(isolationscanner)aftermillingthewindow,if Oilsearchsubmitsageologicandengineeringanalysistodemonstratewhythecementlocationabove thesidetrackwindowwouldnothaveanyimpactonthedrillingphaseorfuturelifecycleofthe well.TheanalysisshouldincludeanassumptionthattheTuluvakmaynotproperlyisolatedwithcement ontheintermediateliner,andthebaseofcementonthe13Ͳ3/8”casingisunknown,andpermeable zonesabovethesurfacecasingshoeareuncemented,takingPPFGconsiderationsintoaccount. Regards BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 <image001.jpg> 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 From:McLellan, Bryan J (OGC) To:Staudinger, Garret (Garret) Cc:Tirpack, Robert (Robert); Regg, James B (OGC); Davis, Rachel (Rachel); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Roby, David S (OGC) Subject:RE: NDB-024 (PTD 223-076) Surface Top Job Date:Tuesday, September 26, 2023 4:40:00 PM Garret, Oilsearch has verbal approval to recover drillpipe, pump cement plug and perform cement logging as described below. Send results of log to AOGCC and obtain approval to proceed before sidetracking. Please submit a written sundry application for change of approved program within 3 days. 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: Tuesday, September 26, 2023 3:25 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Subject: RE: NDB-024 (PTD 223-076) Surface Top Job Bryan, Thanks for the note. I wanted to fill you in on current well conditions and our plan forward that will be included in the Sundry. Current Well Conditions 16” Surface hole drilled to 3181’ MD (77 deg inclination) 13-3/8” surface casing run to 3171’ MD Discovered top plug hung up at damaged connection at 2837’ MD Cleanout run made to 3040’ MD to drill plugs and float collar RIH with test packer to 2824’ MD (above damaged connection). Test 13-3/8” casing to 2600 psi for 30 min – good test. RIH with test packer to 3077’ MD (above float collar). Test 13-3/8” casing and shut down test after 275 psi – failed test. Attempt to come out of hole and unable to work packer past 2837’ MD RIH and push casing fish (~335’ long) to TD, ~10’ MD. Pick up hole and unable to work past parted casing at 2837’ MD Currently waiting on wireline Plan Forward Run wireline down drillpipe and sever top connection of test packer Run 13-3/8” Cement Squeeze Packer and set at ~2750’ MD Sting into cement retainer and squeeze 100 bbls of 15.8ppg HalCem cement (yield 1.165 cuft/sk) Squeeze 50-70 bbls away, and perform hesitation squeeze as required Targeting 500 psi squeeze pressure above initial injectivity pressure RU wireline and run ultrasonic CBL to as deep as possible without a tractor (65 deg inclination at ~2500’). Submit results to AOGCC. MU 13-3/8” whipstock BHA and set on cement retainer. Mill window and 20-50’ of new hole. Perform LOT. Minimum 13.3ppg LOT required for Kick Tolerance. Shut down pumps at maximum 16.5ppg EMW FIT achieved. PU drilling BHA, RIH, displace well to 12.0ppg MOBM, drill ahead 12-1/4” intermediate hole section per original directional plan Regarding the analysis of the gas sample collected from the surface casing x conductor annulus, please see the attached slide. We had the mudloggers collect gas samples with a syringe and run it through their gas analyser. The Orange dots on the charts reflect the annular gas sample on B-24, and the blue dots represent gas samples that were analysed during the drilling of DW-02. The B-24 annular gas was nearly 100% methane, and Tuluvak gas consists of higher concentrations of C2-C5. These charts clearly show that B-24 annular gas are hydrates and not Tuluvak gas. Verbal approval is urgently required for this sundry, as we are currently prepping to rig up wireline and could be cementing as soon as late tonight / early tomorrow. I will work to submit a formal sundry within 3 days. Please let me know if you have any questions. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, September 26, 2023 12:41 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Surface Top Job Garret, I’m following up about your call this morning. I understand that it appears the surface casing has parted and the lower section of the well appears to be uncemented. I want to confirm that a sundry is required before plugging back the existing wellbore and sidetracking. Mark the box for “Change approved program”. If approval is urgently required, a plan may be submitted and operations may proceed pending a verbal approval, with written sundry submitted within 3 days. Due to the sustained gas flow up the surface casing x conductor annulus after pumping primary cement job, and the parted casing and failed pressure test, the AOGCC requires a cement log be run across the surface casing from max depth that wireline tools can reach without a tractor to surface, per 20 AAC 25.030(d)(4)(B). The log should be one that can detect lightweight cement. This log to be sent to AOGCC to determine if further remediation is required before sidetracking is permitted. Please include this in the sundry application. Also, the AOGCC requests the analysis results of the gas sample collected from the surface casing x conductor annulus. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Monday, September 25, 2023 3:35 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Bixby, Brian D (OGC) <brian.bixby@alaska.gov> Subject: RE: NDB-024 (PTD 223-076) Surface Top Job Garret, Thanks for your response. A couple follow up questions. 1. How do you know it was hydrate gas that was bubbling? Were any gas samples collected and analyzed? 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: Monday, September 25, 2023 11:04 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Bixby, Brian D (OGC) <brian.bixby@alaska.gov> Subject: RE: NDB-024 (PTD 223-076) Surface Top Job Bryan, An update to you questions below are as follows: 1. The top job pipe was run inside the 13-3/8” x 20” annulus to 80’ from surface (bottom of conductor), where no further progress could be made. Circulation was established until clean water returns were observed at surface. 22 bbls of 15.6ppg Permafrost-C cement was pumped, and good cement returns were observed at surface at 14 bbls into pumping cement. Continued pumping cement and returned 8 bbls cement to surface. Annulus was static after the cement job. Over the course of the next day, small amounts of hydrate gas continued to “burp” out of one of the flutes through a hole the size of a quarter. Less than 1 gallon of cement was burped out of the hole over the course of 20 hours. Gas readings in the cellar were 0% LEL in atmosphere, and the handheld gas detector would register some gas (<20% LEL) every time a burp would occur. Within 24 hours, the hole bridged itself off as the cement set up. From Saturday night / Sunday morning, there has been no gas detected from the annulus flute with a handheld detector. We continue to have a rig hand monitor the annulus on a 24 hour basis, and have not detected any gas from the annulus flutes or outside of the cellar. Cement in the 13-3/8” x 20” annulus has not slumped and remains at the top of the flutes. 2. As discussed, from the initial drilling out of the conductor we have had elevated background gas readings compared to previous wells indicating a higher presence of hydrates that were very shallow. We believe this is the source of the gas as no other hydrocarbon zones were drilled. We are prognosed to be 695’ MD / 174’ TVD above the Tuluvak formation. The NDB Pad is located in the Tarn gas hydrate accumulation as mapped by the USGS. The NDB-024 well is likely in an area with a higher concentration than previous wells. We believe there are several contributing factors on this well that added to the gas percolating up the surface casing by conductor annulus. On the 13-3/8” casing run, we encountered a tight spot at ~1040’ MD. We spent 7 hours circulating and reaming through the tight spot to get through. After we got casing past this spot, we had to ream down nearly every joint to TD. This excessive circulating, combined with the elevated shallow hydrates in this well, contributed to heating up the wellbore and liberating more hydrates. Additionally, during the cement job a Lo-Torq valve on the cement line developed a leak in which we had to reduce our displacement rate from 10 BPM to 6 BPM, as it was safer to continue displacement rather than shut down pumps. All Lo-Torq valves are being sent in for inspection / preventative maintenance to avoid this issue in the future. We are currently investigating wellbore trajectory and drilling practice changes to reduce casing running issues, and cement recipe design modifications and cementing practices to try and mitigate this issue in the future. Please let me know if you have any questions. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, September 25, 2023 9:45 AM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Bixby, Brian D (OGC) <brian.bixby@alaska.gov> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Surface Top Job Garret, Thanks for the verbal update yesterday. Could you send a follow up email with the following: 1. Updated status report describing the results of the cement top job including status of the gas coming from the conductor by surface casing annulus. 2. Oilsearch’s plans to investigate the source of gas, understand the mechanism by which it was allowed to flow into the wellbore to prevent reoccurrence. 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: Friday, September 22, 2023 8:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Bixby, Brian D (OGC) <brian.bixby@alaska.gov> Subject: Re: NDB-024 (PTD 223-076) Surface Top Job Bryan, Appreciate the response. I'll let you know how the top job goes. Thanks, Garret Get Outlook for iOS From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, September 22, 2023 8:15 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Bixby, Brian D (OGC) <brian.bixby@alaska.gov> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Surface Top Job Garret, I spoke to our inspector Brian Bixby. He said they got the washpipe down to the base of the conductor and couldn’t get any deeper. They went in with the washpipe through two different conductor flutes and is pretty sure they got all the contaminated cement out and are now just circulating water. It sounds like the bubbling is intermittent. He was going to watch it for a while and if it is fairly stable, go ahead with the top job using the 15+ ppg permafrost cement. After pumping the cement job, Oilsearch should continue monitoring the cellar and conductor for signs of gas. I’ll discuss with the staff at AOGCC about running a wireline cement log in the surface casing to see where the source of the gas is likely coming in, in case the bubbling is seen outside the wellbore. If so, you wouldn’t need to run the log now, just some time before running tubing. Please keep me updated over the weekend on the results of the top job and if you are observing any gas after pumping. Thanks and regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Friday, September 22, 2023 6:44 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: RE: NDB-024 (PTD 223-076) Surface Top Job Garret, A few questions about your plan. How deep were you able to get the wash pipe? You need to wash all that contaminated cement out before cementing or you’ll just channel through it. Is it still bubbling? How vigorously? Why will the result be any different if you try to cement with gas actively flowing out of the return stream? I think you need to get it to stop bubbling before placing cement. Usually a top job is just designed to fill up the annulus when you don’t get cement quite to surface. It’s a different animal when you are hoping to seal off an active gas leak by pumping cement. 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: Friday, September 22, 2023 6:18 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: Re: NDB-024 (PTD 223-076) Surface Top Job Hey Bryan, Sorry it took so long to get back to you. We aren't planning on running a cement log as I wouldn't expect it to show us much with the lightweight 11.0ppg lead slurry and how long I'd expect it to set up in the permafrost. Additionally, we did see a bit more elevated background gas right out of the conductor with the mudloggers on this well compared to the previous two development wells. I’d would expect that all this elevated background gas is contributing to hydrate gas which is slowly percolating through the highly contaminated cement to surface. Our plan forward is to run top job pipe as deep as possible and cement to surface with a very fast setting premium permafrost cement. We believe this is the best remedial action for a channel. We should be performing this top job tonight, and AOGCC inspector Brian Bixby should be on location to witness soon. Please let me know if you have any questions or concerns. Regards, Garret From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, September 22, 2023 2:34 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: ![EXT]: RE: NDB-024 (PTD 223-076) Surface Top Job Garret, 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. It’s pretty unusual to have gas continuing to flow after you get cement to surface. Have you given any thought into running a cement log to see where this gas is coming from and where is the depth of solid cement? 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: Friday, September 22, 2023 1:53 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: NDB-024 (PTD 223-076) Surface Top Job Bryan, As discussed, we got cement back to surface on the surface casing cement job, but we have experienced hydrate gas continue to percolate up through the cement. It appears we have a channel on one side of the surface casing by conductor annulus that we can get top job pipe down. We are still working to source some top job pipe that will work, but do have a good Permafrost-C 15.6ppg Class G cement that will work really good for this application. I'll keep you updated on when we get some pipe and determine how far down firm cement is. Please let me know if you have any questions. Thanks, Garret Santos Ltd A.B.N. 80 007 550 923 NDB-024 annular gas compared to DW-02 gas samples 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 50.0060.0070.0080.0090.00100.00 C1 mol% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 0.00 2.00 4.00 6.00 8.00 C2 mol% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 0.00 1.00 2.00 3.00 4.00 C3 mol% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 0.00 0.50 1.00 1.50 2.00 2.50 nC4 mol% De p t h – ft M D De p t h – ft M D De p t h – ft M D De p t h – ft M D Tuluvak Interval in DW-02 Tuluvak Interval in DW-02 Tuluvak Interval in DW-02 Tuluvak Interval in DW-02 Sample with low total gas Sample with low total gas Sample with low total gas Sample with low total gas NDB-24 gas nearly 100% methane vs Tuluvak. Consistent with DW-02 shallow gas samples NDB-24 gas very light vs Tuluvak. Consistent with DW-02 shallow gas samples NDB-24 gas very light vs Tuluvak. Consistent with DW-02 shallow gas samples NDB-24 gas very light vs Tuluvak. Consistent with DW-02 shallow gas samples DW-02 Depth C1 mol% B-24 Annular Gas DW-02 Depth C2 mol% B-24 Annular Gas DW-02 Depth C3 mol% B-24 Annular Gas DW-02 Depth nC4 mol% B-24 Annular Gas 2023-0923_Surface_Casing_TopJob_Pikka_NDB-24_bb Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: September 24, 2023 P. I. Supervisor FROM: Brian Bixby SUBJECT: Cement Top Job Petroleum Inspector Pikka NDB-024 Oil Search (Alaska) LLC PTD 2230760 9/22/23 – 9/23/23: I arrived location and met with Brian Buzby, the company man on Parker Rig 272. We talked about what was happening with the well after they had set the 13-3/8 inch surface casing and cemented it. They had good cement to surface during the casing cement job. While rigging down the diverter equipment gas and cement were observed bubbling out of the fluted surface casing hanger. After multiple phone calls and emails with Oil Search and AOGCC engineers it was decided to wash down as far as possible on the 13-3/8 inch by 20-inch annulus and conduct a cement top job. I witnessed washing down the annulus through the hanger flutes with ½-inch conduit to 80 feet (bottom of the conductor). The well was then monitored for about 3 hours while waiting for the cement truck to arrive and rig up. Water was still flowing out of the annulus at approximately 8 to 10 gallons per hour – it was not a consistent flow but instead would flow for a few minutes, stop for 10 to 15 minutes, and then start again. I called Bryan McLellan (AOGCC Engineer) and went over everything that I had witnessed thus far and the reports from the company man on what they had witnessed after the surface casing was landed and cemented. It was decided to go ahead with the cement top job. I witnessed 15.6 ppg cement pumped down the ½-inch conduit which was at approximately 79 feet. The calculated annulus volume is 17 bbls. I watched the returns the entire time they were pumping cement, and it was dirty water until approximately 16 bbls of cement were pumped away when the returns changed to good cement. A total of 20 bbls of 15.6 ppg cement were pumped. I provided videos to AOGCC Engineer Bryan McLelland; Oil Search and Parker also have videos of the annular flow and top job. Attachments: none         STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-024 JBR 10/21/2023 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks: TEST DATA Rig Rep:Rowloand LawsonOperator:Oil Search (Alaska), LLC Operator Rep:Sonny Clark Contractor/Rig No.:Parker 272 PTD#:2230760 DATE:9/16/2023 Well Class:DEV Inspection No:divBDB230918040713 Inspector Brian Bixby Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:0 NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:16 P Vent Line(s) Size:16 P Vent Line(s) Length:111 P Closest Ignition Source:98 P Outlet from Rig Substructure:127 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:24 P Knife Valve Open Time:21 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P2380 200 psi Recharge Time:P14 Full Recharge Time:P49 Nitrogen Bottles (Number of):P14 Avg. Pressure:P2300 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: 0 NAMud System Misc:    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) Cc:Lambe, Steven (Steven); Regg, James B (OGC) Subject:FW: NDB-024 (PTD 223-076) Diverter Line Rig Up Date:Wednesday, September 13, 2023 2:12:00 PM Attachments:272L-01-05-501-1-R1-div-stack-Model Ground RU.pdf AP-DRL-GEN-M_NDB24_well_diverter Rev2.pdf Garret, Oilsearch has approval to modify the diverter stack as proposed in the attached diagram. 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, September 13, 2023 12:37 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Lambe, Steven (Steven) <Steven.Lambe@contractor.santos.com> Subject: NDB-024 (PTD 223-076) Diverter Line Rig Up Bryan, With the increased activities on NDB Pad with respect to SIMOPs and operational constraints, Santos is unable to run the elevated diverter configuration on the next well, NDB-024, as proposed in the original PTD, in the Attachment 3: BOPE Equipment. The Equipment in Section 7, Diverter System Information on page 7, remains the same as in the approved Permit to Drill. We plan to run the diverter pipe on the ground, with the end of the diverter line 110’ from well center. Note the directional orientation of the diverter line has not changed. I have attached an updated diverter rig up for Parker 272, and the proposed diverter line routing. Our future Permit to Drills will articulate both options as we did in our first well, DW-02. Please let me know if you have any questions or concerns, and if there is anything else you need from my end. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | 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 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# OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELLS DIVERTER (110-ft) RIG OUTLINES DATE: 9/12/2023. By: JN 0 20 40 60 8010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB24_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 10 20 30 405 Meters PIKKA DEVELOPMENT NDB24 WELL DIVERTER 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-024 (PTD 223-076) Cementing Stage Tool Location Date:Monday, September 11, 2023 7:45:00 PM Garret, Oilsearch has approval to move the stage tool depth according as needed to cover the hydrocarbon bearing intervals. If the Tuluvak in NDB-024 comes in deeper than expected, you should adjust the stage tool deeper accordingly. Regards Bryan 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: Monday, September 11, 2023 11:22 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDB-024 (PTD 223-076) Cementing Stage Tool Location Bryan, The submitted plan as part of the PTD was to place the stage collar at the base of Tuluvak Sand / Top of Seabee. This corresponded to a depth of ~7100’ MD based on the directional plan. I have met with the subsurface team, and their recent analysis from offset wells show the base of hydrocarbon bearing Tuluvak sand to be ~2950’ TVDss. I am planning to move the stage collar up hole a little bit to place the tool at the bottom of this hydrocarbon bearing interval. This only translates to ~123’ TVD shallower, but it does move the tool nd up ~550’ MD shallower. This reduces a little bit of risk by reducing ECD on the 2 stage job, while still meeting the objectives of isolating the Tuluvak hydrocarbon bearing zone with cement. I’ve attached an updated schematic. Please let me know if you have any questions or concerns. Thanks, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | 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 NDB-024 GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer3,095' MD 13-3/8" 68 ppf L-80 Surface Casing3,245' MD 1-½” GLM Shear Valve~2,400' MD 4-½” X-Nipple~2,440' MD 4-½” X-Nipple~11,284' MD 9-5/8", 47ppf L-80 Production Liner11,591' MD 4-½”, 12.6ppf P-110S Production Liner 18,045' MD 4-½” Liner Hanger and Liner Top Packer11,441' MD 4-½” 12.6ppf P-110S Completion w/ Tieback Seals11,436' MD 4-½” X-Nipple~11,424' MD 4-½” Openhole Packers one every 500' -700' with Frac Ports Toe Sleeve Shutoff Collar *Quantity of openhole packer and frac sleeve may change 4-½” Gaslift Sliding Sleeve (Contingency)~11,376' MD Archer C-Flex Two-Stage Cementing Tool (~2950' TVDss)~6,550' MD TOC First Stage Cement Job - 250' TVD above Nanushuk~9,100' MD 16" Hole Size 12-1/4" Hole Size 8-1/2" Hole Size 4-½” Gaslift w/ Downhole Psi/Temp Gauge~11,328' MD 1 Dewhurst, Andrew D (OGC) From:Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent:Monday, September 11, 2023 13:29 To:Dewhurst, Andrew D (OGC); Lewallen, Anna (Anna) Cc:Davies, Stephen F (OGC); McLellan, Bryan J (OGC); Guhl, Meredith D (OGC) Subject:RE: NDB-024 (PTD 223-076) Cuttings Sample Clarification Sounds good, Andy. Thank you for the response. Garret Staudinger Senior Drilling Engineer t: +1 (907) 375‐4666 | m: +1 (907) 440‐6892 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, September 11, 2023 1:22 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com>; Lewallen, Anna (Anna) <Anna.Lewallen@santos.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: ![EXT]: RE: NDB‐024 (PTD 223‐076) Cuttings Sample Clarification GarreƩ, You are correct. Cuƫngs samples are required for two other wells drilled from this pad (DW‐02 and NDB‐043) and they were not required for NDB‐032. So, cuƫngs samples should not be required for NDB‐024 because, per 20 AAC 25.071(c), such samples would not signiﬁcantly add to the geologic knowledge of the area in light of the informaƟon that is available from other wells in the area. So, you are not required to submit any cuƫngs for NDB‐024. Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793‐1254 From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Friday, September 8, 2023 07:32 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Lewallen, Anna (Anna) <Anna.Lewallen@santos.com> Subject: NDB‐024 (PTD 223‐076) Cuttings Sample Clarification Andy / Bryan, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 I just received the approved PTD yesterday, so appreciate you guys sending it through. I do have a couple quesƟons regarding the dry ditch samples that the AOGCC is requesƟng for this well. The cover leƩer states the following: Page 47 of the approved PTD states: So my quesƟons are as follows: 1) Are dry ditch samples required to be submiƩed to the AOGCC for this well? This is the 4th well on the pad, and Oil Search has submiƩed samples for the ﬁrst 2 wells on the pad. Cuƫngs samples were not required per the PTD on the 3rd well, NDB‐032. 2) If samples are required, we would like to amend the PTD to catch samples in 50 Ō intervals from surface to TD. 30 Ō samples in the upper hole secƟons was a typo from my end (50’ are all we need), and 10 Ō sample intervals in a 6000’ producƟon lateral are not sustainable from an operaƟonal perspecƟve. Please let me know if you have any quesƟons on this, and appreciate the help with this. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375‐4666 | 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 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Mark Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 900 E Benson Boulevard Anchorage, AK, 99508 Re: Pikka Field, Nanushuk Oil Pool, NDB-024 Oil Search Alaska, LLC Permit to Drill Number: 223-076 Surface Location: 2,408’ FSL, 2,975’ FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 4,971’ FSL, 2,052’ FEL, Sec 30, T12N, R6E, UM Dear Mr. Staudinger: Enclosed is the approved application for the permit to drill the above-referenced well. All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this ___ day of September 2023. 7 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.07 15:17:54 -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: 18,050 TVD:4,163 4a. Location of Well (Governmental Section): 7. Property Designation: ADL 392984 Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 5,104’ FSL, 4,298’ FEL, Sec 32, T12N, R6E, UM Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4,971’ FSL, 2,052’ FEL, Sec 30, T12N, R6E, UM 8,092' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 68.7 15. Distance to Nearest Well Open Surface: x- 422270 y- 5972792 Zone- 4 22 to Same Pool:5,851' 16. Deviated wells: Kickoff depth: 350 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 128' 16" 13-3/8" 68# L-80 BTC 3,240' Surface Surface 3,240' 2,297' 12-1/4" 9-5/8" 47# L-80 HYD 563 8,251' 3,090' 2,260' 11,341' 4,100' Tie Back 9-5/8" 47# L-80 HYD 563 3,090' Surface Surface 3,090' 2,265' 8-1/2" 4-1/2" 12.6# P-110S HYD 563 6,859' 11,191' 4,060' 18,050' 4,163' N/A Tubing 4-1/2" 12.6# P-110S HYD 563 11,191' Surface Surface 11,191' 4,065' 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: Garret Staudinger Garret Staudinger Contact Email:garret.staudinger@santos.com Senior Drilling Engineer Contact Phone:907-440-6892 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 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): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Effect. Depth TVD (ft): Conductor/Structural LengthCasing Top - Setting Depth - BottomSpecifications 1,918 GL / BF Elevation above MSL (ft): Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface See Attachment 6 See Attachment 6 N/A Effect. Depth MD (ft):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 1,466 LONS 19-003 900 E Benson Boulevard, Anchorage, AK 99508 Oil Search Alaska, LLC 2,408’ FSL, 2,975’ FEL, Sec 4, T11N, R6E, UM ADL 393020, ADL 391455,ADL 393018 2508 18. Casing Program: NDB-024 Pikka / Nanushuk Oil Pool 09/11/23 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o ll not beduddddddreap DD 612 7 o well is p G S S 20 S S S s No s No S G 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) gg 8/14/2023 By Grace Christianson at 2:55 pm, Aug 14, 2023 24.0 See attached conditions of approval on the following page. 223-076 BJM 9/6/23 A.Dewhurst 21 AUG 2023 DSR-8/21/23 3 A. Dewhurst 21 AUG 2023 71.0 ADL391445 50-103-20862-00-00 *&: 09/07/23 09/07/23 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.09.07 15:18:49 -08'00' NDB-024 (PTD 223-076) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨĂƉƉƌŽǀĂů 1. KWƚĞƐƚƚŽϯϱϬϬƉƐŝ͘ŶŶƵůĂƌƚĞƐƚƚŽϯϬϬϬƉƐŝ͘ 2. 9-ϱͬϴ͟ĞŵĞŶƚŵƵƐƚďĞůŽŐŐĞĚĂĐƌŽƐƐďŽƚŚĮƌƐƚĂŶĚƐĞĐŽŶĚƐƚĂŐĞĐĞŵĞŶƚ ƚŽĚĞŵŽŶƐƚƌĂƚĞ ŝƐŽůĂƟŽŶĂĐƌŽƐƐ. 3. >Kdͬ&/dƌĞƐƵůƚƐƚŽďĞƐƵďŵŝƩĞĚƚŽK'ǁŝƚŚŝŶ24 ŚŽƵƌƐŽĨŽďƚĂŝŶŝŶŐƚŚĞĚĂƚĂ͘ 4. dŚĞ>t-^ŽŶŝĐůŽŐǁŝůůŽŶůǇďĞĂĐĐĞƉƚĞĚǁŚĞŶƚŚĞĨŽůůŽǁŝŶŐĐŽŶĚŝƟŽŶƐĂƌĞŵĞƚ͗ Ă͘ KŝůƐĞĂƌĐŚƚŽƉƌŽǀŝĚĞĂǁƌŝƩĞŶůŽŐĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶƚŽƚŚĞK'ĂůŽŶŐǁŝƚŚƚŚĞ ůŽŐĂƐƐŽŽŶĂƐƚŚĞǇďĞĐŽŵĞĂǀĂŝůĂďůĞ͘dŚĞĞǀĂůƵĂƟŽŶŝƐƚŽŝŶĚŝĐĂƚĞƚŚĞŝŶƚĞƌǀĂůƐŽĨ ĐŽŵƉĞƚĞŶƚĐĞŵĞŶƚƚŚĂƚKŝůƐĞĂƌĐŚŝƐƵƐŝŶŐƚŽŵĞĞƚƚŚĞŽďũĞĐƟǀĞƌĞƋƵŝƌĞŵĞŶƚƐĨŽƌ ĂŶŶƵůĂƌŝƐŽůĂƟŽŶĂŶĚƌĞƐĞƌǀŽŝƌŝƐŽůĂƟŽŶ͕ĂŶĚƚŽŝŶĚŝĐĂƚĞƚŚĞůŽĐĂƟŽŶŽĨĐŽŶĮŶŝŶŐǌŽŶĞƐ͕ ŚǇĚƌŽĐĂƌďŽŶ-ďĞĂƌŝŶŐ ǌŽŶĞƐ͕ŽǀĞƌƉƌĞƐƐƵƌĞĚǌŽŶĞƐĂŶĚĨƌĞƐŚǁĂƚĞƌ͕ŝĨƉƌĞƐĞŶƚ͘WƌŽǀŝĚŝŶŐ ƚŚĞůŽŐǁŝƚŚŽƵƚĂŶĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶŝƐŶŽƚĂĐĐĞƉƚĂďůĞ͘ ď͘ >tƐŽŶŝĐůŽŐƐŵƵƐƚƐŚŽǁĨƌĞĞƉŝƉĞĂŶĚdŽƉŽĨĞŵĞŶƚ͘ dŚĞůŽŐŵƵƐƚďĞƌƵŶĂĐƌŽƐƐƚŚĞ ƚĂƌŐĞƚǌŽŶĞƐĂŶĚĂƚĂĚĞƉƚŚƚŽĞŶƐƵƌĞƚŚĞĨƌĞĞƉŝƉĞĂďŽǀĞƚŚĞdKŝƐĐĂƉƚƵƌĞĚĂƐǁĞůůĂƐ ƚŚĞdK͘/ĨƚŚĞůŽŐŐĞĚŝŶƚĞƌǀĂůĚŽĞƐŶŽƚĐĂƉƚƵƌĞƚŚĞdKĂŶĚĨƌĞĞƉŝƉĞĂďŽǀĞŝƚ͕ ŝƚǁŝůů ŶĞĞĚƚŽďĞƌĞ-ƌƵŶ͕ƵŶůĞƐƐƚŚĞĐĞŵĞŶƚǁĂƐƉůĂŶŶĞĚƚŽĐŽǀĞƌƚŚĞĞŶƟƌĞůĞŶŐƚŚŽĨůŝŶĞƌŽƌ ĐĂƐŝŶŐ. Đ͘ KŝůƐĞĂƌĐŚ ǁŝůůƉƌŽǀŝĚĞĂĐĞŵĞŶƚũŽďƐƵŵŵĂƌǇƌĞƉŽƌƚĂŶĚĞǀĂůƵĂƟŽŶĂůŽŶŐǁŝƚŚƚŚĞ ĐĞŵĞŶƚůŽŐĂŶĚĞǀĂůƵĂƟŽŶƚŽƚŚĞK'ǁŚĞŶƚŚĞǇďĞĐŽŵĞĂǀĂŝůĂďůĞ. d. ĞƉĞŶĚŝŶŐŽŶƚŚĞĐĞŵĞŶƚũŽďƌĞƐƵůƚƐŝŶĚŝĐĂƚĞĚďǇƚŚĞĐĞŵĞŶƚũŽďƌĞƉŽƌƚ͕ƚŚĞůŽŐƐĂŶĚ ƚŚĞ&/d͕ƌĞŵĞĚŝĂůŵĞĂƐƵƌĞƐŽƌĂĚĚŝƟŽŶĂůůŽŐŐŝŶŐŵĂǇďĞƌĞƋƵŝƌĞĚ͘ Page 1 of 1 14 August 2023 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-024 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-024 is planned to be a horizontal producer targeting the Nanushuk 3. The approximate spud date is anticipated to be September 11th, 2023. 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 ~77 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. The well will be completed as a stimulated producer with 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 (907) 440- 6892 or garret.staudinger@santos.com. Respectfully, Garret Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, NDB-024 PTD 8.10.23 - 1 - 13-Jul-23 Application for Permit to Drill NDB-024 Well NDB-024 PTD 8.10.23 - 2 - 13-Jul-23 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 ...........................................................................................................8 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................10 Attachments..................................................................................................................................................11 Attachment 1: Location Maps..........................................................................................................12 Attachment 2: Directional Plan........................................................................................................14 Attachment 3: BOPE Equipment ......................................................................................................31 Attachment 4: Drilling Hazards.........................................................................................................35 Attachment 5: Leak Off Test Procedure...........................................................................................37 Attachment 6: Cement Summary.....................................................................................................38 Attachment 7: Prognosed Formation Tops......................................................................................39 Attachment 8: Well Schematic.........................................................................................................40 Attachment 9: Formation Evaluation Program ................................................................................41 Attachment 10: Wellhead & Tree Diagram......................................................................................42 NDB-024 PTD 8.10.23 - 3 - 13-Jul-23 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-024. 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 2,408’ FSL, 2,975’ FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,792.74 E 422,269.90 Rig KB Elevation 47.0’ above ground level Ground Level 24.0’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 5,104’ FSL, 4,298’ FEL, Sec 32, T12N, R6E, UM NAD 27 Coordinate System N 5,980,845.68 E 415,725.47 Measured Depth, Rig KB (MD) 12,069’ Total Vertical Depth, Rig KB (TVD) 4,241’ Total vertical Depth, Subsea (TVDSS) 4,170’ Location at Bottom of Productive Interval Reference to Government Section Lines 4,971’ FSL, 2,052’ FEL, Sec 30, T12N, R6E, UM NAD 27 Coordinate System N 5,986,022.80 E 412,733.62 Measured Depth, Rig KB (MD) 18,050’ Total Vertical Depth, Rig KB (TVD) 4,163’ Total vertical Depth, Subsea (TVDSS) 4,092’ NDB-024 PTD 8.10.23 - 4 - 13-Jul-23 (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-024 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. NDB-024 PTD 8.10.23 - 5 - 13-Jul-23 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 1,876 psi in the Nanushuk 4 at 4,100’ TVD (8.8ppg EMW top Nanushuk 4 formation to section TD) Maximum surface pressure 1,466 psi from the NT4 (0.10 psi/ft gas gradient to surface, 4,100’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by 9-5/8” Casing Pressure Test] Integrity Test – 12-1/4” hole LOT after drilling 20’-50’ of new hole. 12.3 ppg LOT required for Kick Tolerance, 17 ppg maximum EMW LOT 13-3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by 50% of Casing Burst Pressure] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,918 psi in the Nanushuk 3 at 4,241’ TVD (8.7ppg EMW top NT3 formation to heel target) Maximum surface pressure 1,494 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,241’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by 9-5/8” Casing Pressure Test] Integrity Test – 8-1/2” hole LOT after drilling 20’-50’ of new hole. 9.8 ppg for minimum kick tolerance. 9-5/8” Liner Test 3,500 psi surface pressure [Test pressure driven by Maximum Surface Pressure] (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 overpressured at 10.0ppg 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; NDB-024 PTD 8.10.23 - 6 - 13-Jul-23 Nearby offset Exploration and Appraisal wells in the area suggest that no significant hole problems are to be expected. 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 BTC 3,240’ Surface 3,240’ / 2,297’ 12-1/4” 9-5/8” 47# L-80 HYD 563 8,251’ 3,090’ 11,341’ / 4,100’ Tie Back 9-5/8” 47# L-80 HYD 563 3,090’ Surface 3,090’ / 2,265’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6,859’ 11,191 18,050’ / 4,163’ Tubing 4-1/2” 12.6# P-110S HYD 563 11,191’ Surface 11,191’ / 4,065’ Please refer to Attachment 6: Cement Summary for further details. NDB-024 PTD 8.10.23 - 7 - 13-Jul-23 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 9.5-10.0ppg 100-300 seconds ALAP 30-80 < 10 ml/30min n/a 8.6-10.5 <35 11.5ppg 50-80 seconds ALAP 15-30 n/a < 5 ml/30min n/a n/a 9.5-10.0ppg 50-80 seconds ALAP 15-30 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. NDB-024 PTD 8.10.23 - 8 - 13-Jul-23 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-024 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-024 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program NDB-024 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 NDB-024 PTD 8.10.23 - 9 - 13-Jul-23 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. Circulate and clean well prior to trip. 7. POOH and lay down drilling assembly. 8. 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. 9. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 10. 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 3500 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing BOP test. 11. Pressure test 13-3/8” surface casing to 2600 psi for 30 min. 12. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment. Displace well to 11.5ppg MOBM. 13. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test and submit results to AOGCC. 14. Directionally drill 12-1/4” intermediate hole section to TD ~15’ TVD above the NT3 MFS. Perform wiper trips as required. Circulate and condition hole to run casing. POOH. 15. 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. Set liner hanger and release running tool. 16. Cement 9-5/8” liner with first stage of cement job as per cement program. Monitor returns during displacement and bump plug. POOH and LD liner running tools. 17. RIH with stage collar shifting tool. Shift stage collar open and perform 2 nd stage cement job. Shift stage collar closed and set liner top packer. 18. Circulate cement returns from the top of liner. 19. POOH and LD stage collar shifting tool. 20. Run 9-5/8” tie-back string. Freeze protect 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 21. Pressure test 13-3/8” x 9-5/8” annulus to 2600 psi for 30 min. 22. Pressure test 9-5/8” liner and tieback to 3500 psi for 30 min. 23. Change out lower BOP rams from 9-5/8” fixed to 4-1/2” x 7” VBR and test to 3,500 psi. 24. Make up 8-1/2” RSS BHA with MWD and LWD tools. RIH and log 1 st stage cement with sonic LWD. Clean out to top of float equipment and displace well to 9.2ppg MOBM. 25. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test and submit results to AOGCC. Pressure test 13-3/8” surface casing to 2600 psi for 30 min. RIH and log 1 st stage cement with sonic LWD. Test rams to 3500 psi high and annular to 3000 psi high as per AOGCC regulations. Perform leak off test and submit results to AOGCC. NDB-024 PTD 8.10.23 - 10 - 13-Jul-23 26. Directionally drill 8-1/2” hole section as per well plan to TD. Perform wiper trips as required. POOH. Submit LWD sonic cement evaluation log to AOGCC. 27. RU and run 4-1/2” production liner with frac sleeves and mechanical packers. 28. Run 4-1/2” liner to TD. Set liner hanger and liner top packer and release the running tool. 29. POOH and LD liner running tool. 30. RU and run 4-1/2” upper completion with tech wire. Space out and stab seals inside the polish bore below the 9-5/8” x 4-1/2” liner top packer. 31. Pressure test tubing to 4,000 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 32. Circulate diesel to freeze protect annulus. 33. Install TWC, pressure test to 3,000 psi for 5 mins. ND BOPE, NU dry hole tree. 34. RDMO 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. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. Pressure test tubing to 4,000 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. B Both 1st and 2nd stage cement jobs must be logged. -bjm Submit LWD sonic cement evaluation log to AOGCC. NDB-024 PTD 8.10.23 - 11 - 13-Jul-23 Attachments NDB-024 PTD 8.10.23 - 12 - 13-Jul-23 Attachment 1: Location Maps OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELLS DIVERTER (50-ft) RIG OUTLINES DATE: 7/12/2023. By: JN 0 2040608010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB24_well_diverter q GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 102030405 Meters PIKKA DEVELOPMENT NDB24 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.335-150.63N 70° 20' 07." W 150° 38' 0." 5,972,.1,562,. Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.335-150.63N 70° 20' 0." W 150° 3' ." 5,972,7.422,. State Plane NAD83 Zone 4 StatePlane NAD27 Zone 4 NDB-024 PTD 8.10.23 - 14 - 13-Jul-23 Attachment 2: Directional Plan SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 47.0 0.00 0.00 47.0 0.0 0.0 0.00 0.00 0.0 2 350.0 0.00 0.00 350.0 0.0 0.0 0.00 0.00 0.0 Start Build 3.00 3 550.0 6.00 345.00 549.6 10.1 -2.7 3.00 345.00 9.7 Start DLS 3.00 TFO -26.46 4 2941.9 77.15 319.28 2230.8 1170.3 -918.7 3.00 -26.46 1487.1 Start 8263.8 hold at 2941.9 MD 5 11205.7 77.15 319.28 4069.2 7276.3 -6174.9 0.00 0.00 9520.7 Start DLS 3.00 TFO 110.26 6 11550.6 73.77 329.39 4156.0 7547.0 -6369.4 3.00 110.26 9854.1 Start 100.0 hold at 11550.6 MD 7 11650.6 73.77 329.39 4184.0 7629.6 -6418.3 0.00 0.00 9949.6 Start Build 4.00 8 12069.4 90.52 329.39 4241.0 7985.4 -6628.8 4.00 0.00 10360.9 NDB-024 Heel v.0 Start 2199.2 hold at 12069.4 MD 9 14268.6 90.52 329.39 4221.0 9878.0 -7748.7 0.00 0.00 12548.9 NDB-024 post fault v0 Start DLS 1.50 TFO -2.31 10 14292.6 90.88 329.37 4220.7 9898.6 -7760.9 1.50 -2.31 12572.7 Start 3757.4 hold at 14292.6 MD 11 18049.9 90.88 329.37 4163.0 13131.4 -9674.9 0.00 0.00 16310.7 NDB-024 TD v.0 TD at 18049.9 47 300 300 490 490 670 670 860 860 1040 1040 1230 1230 1400 1400 1600 1600 2200 2200 2800 2800 3400 3400 4000 4000 5000 5000 6500 6500 7500 7500 8500 8500 9500 9500 10500 10500 11500 11500 12500 12500 13500 13500 14500 14500 15500 15500 16500 16500 17500 17500 18500 18500 19500 Plan: NDB-024 Rev A.1 Plan Summary 0 3 Do g l e g S e v e r i t y 0 3000 6000 9000 12000 15000 18000 Measured Depth 20"13-3/8" x 16" 9-5/8" x 12-1/4" 4-1/2" x 8-1/2" 45 45 90 90 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in] 7176101126151176201226251276301326351376401426451476500525549572596619642Rev A.0 71761011261511762012262512763013263513764014264514765015265515766006256496746987237487727978218468708959199449689931018104210671091111611401165118912141238126312871312Rev A.0 485176101126151176201226251276301326351376401426451476500525549573597620644667690713736 759 782 804Plan: NDB-021 Rev A.0 71761011261511762012262512763013263513764014264514765015265515766016256506757007247497747998248488738989239489729971022104710711096112111461171119512201245127012951319134413691394141814431468149315181542156715921617164216661691171617411766179018151840186518901914193919641989201420382063208821132138216321872212223722622287231123362361238624112436246024852510Rev A.0 7176101126151176201226251276301326351376401426451476501525550574598623647670694717740 763 786 809 831Plan: B-25 Rev A.0 71771021271521772022272522773023273523774024274524775025275525776026276536787037287537798048298548809059309559801006103110561081110711321157118212071233125812831308133313591384140914341459148515101535156015851610163616611686171117361761178718121837186218871912193719631988201320382063208821132138216421892214223922642289231423392364239024152440246524902515254025652590261526402665269027152740276527912816284128662891291629412966299130163041 3066309031153140Rev A.0 7176101126151176201226251276301326351376401426451476501526551576602627652678703728754779804830855880906931956982100710321058108311081134115911841209123512601285131013361361138614111437146214871512153715621588Rev A.0 7176101126151176201226251276301326351376401426451475500524549573598622646670 693Rev A.0 11409114331145811480Plan: NDB-032 Rev B.0 4750751001251501752002252502753003253503754004254504755005255505756006256506757007257507758008258508759009259509751000102510501075110011251150117512001225125012751300132513501375140014251450147515001525155015751600162516501675170017251750177518001825185018751900192519501975200020252050207521002125215021752200222522502275230023252350237524002425245024752500252525502575260026252650267527002725275027752800282528502875290029252950297530003025305030753100312531503175320032253250327533003325335033753400342534503475350035253550357536003625365036753700372537503775380038253850387539003925395039754000402540504075410041254150417542004225425042754300432543504375440044254450447545004525455045754600462546504675470047254750477548004825485048754900492549504975500050255050507551005125515051755200522552505275530053255350537554005425545054755500552555505575560056255650567557005725575057755800582558505875590059255950597560006025605060756100612561506175620062256250627563006325635063756400642564506475650065256550657566006625665066756700672567506775680068256850687569006925695069757000702570507075710071257150717572007225725072757300732573507375740074257450747575007525755075757600762576507675770077257750777578007825785078757900792579507975800080258050807581008125815081758200822582508275830083258350837584008425845084758500852585508575860086258650867587008725875087758800882588508875890089258950897590009025905090759100912591509175920092259250927593009325935093759400942594509475950095259550957596009625965096759700972597509775980098259850987599009925995099751000010025100501007510100101251015010175102001022510250102751030010325103501037510400104251045010475105001052510550105751060010625106501067510700107251075010775108001082510850108751090010925109501097511000110251105011075111001112511150111751120011225112501127511300113261135111376114011142611451114761150111526115511157611601116261165111676117011172611751117761180111826118511187611901119261195111976120011202612051120761210112126121511217612201122261225112276123011232612351123761240112426124511247612501125261255112576126011262612651126761270112726127511277612801128261285112876129011292612951129761300113026130511307613101131261315113176132011322613251132761330113326133511337613401134261345113476135011352613551135761360113626136511367613701137261375113776138011382613851138761390113926139511397614001140261405114076141011412614151141761420114226142511427614301143261435114376144011442614451144761450114526145511457614601146261465114676147011472614751147761480114826148511487614901149261495114976150011502615051150761510115126151511517615201152261525115276153011532615351153761540115426154511547615501155261555115576156011562615651156761570115726157511577615801158261585115876159011592615951159761600116026160511607616101161261615116176162011622616251162761630116326163511637616401164261645116476165011652616551165761660116626166511667616701167261675116776168011682616851168761690116926169511697617001170261705117076171011712617151171761720117226172511727617301173261735117376174011742617451174761750117526175511757617601176261765117676177011772617751177761780117826178511787617901179261795117976180011802618050Plan: NDB-024 Rev A.1 0 2250 Tr u e V e r t i c a l D e p t h 0 2250 4500 6750 9000 11250 13500 15750 Vertical Section at 323.62° 20" 13-3/8" x 16" 9-5/8" x 12-1/4"4-1/2" x 8-1/2" 0 28 55 Ce n t r e t o C e n t r e S e p a r a t i o n 0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.014 SURVEY PROGRAM Date: 2021-02-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 300.0 Plan: NDB-024 Rev A.1 (B-24) 2_MWD_Interp Azi 300.0 1800.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+Sag 300.0 3360.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+MS+Sag 47.0 300.0 Plan: NDB-024 Rev A.1 (B-24) SDI_KPR_ADK 3360.0 4860.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+Sag 3360.0 11608.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+MS+Sag 11608.0 13108.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+Sag 11608.0 18049.9 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+MS+Sag Surface Location North / 5972540.75 East / 1562302.70 Elevation / 24.0 CASING DETAILS TVD MD Name 127.0 127.0 20" 2297.1 3240.0 13-3/8" x 16" 4100.9 11341.0 9-5/8" x 12-1/4" 4163.0 18049.9 4-1/2" x 8-1/2" Mag Model & Date: BGGM2023 30-Sep-23 Magnetic North is 14.52° East of True North (Magnetic Declin Mag Dip & Field Strength: 80.59° 57184.51697821nT FORMATION TOP DETAILS TVDPath Formation 1048.0 U. Schrader Bluff 1395.0 Permafrost Base 1744.0 M Schrader Bluff2147.0 MCU 2171.0 TM_BRO_30_392463.0 Tuluvak Shale 2526.0 Tuluvak Sand 2551.0 TM_BRO_30_37 2926.0 TM_BRO_30_38 3171.0 Seabee3835.0 Nanushuk 3912.0 NT6 MFS 3946.0 TM_BRO_150_3 3984.0 NT5 MFS 4030.0 NT4 MFS 4116.0 NT3 MFS 4160.0Nanushuk 3.2 (NT3) 4206.0 TM_ELS_150_3 By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by BHI DE Accepted by BHI PSD Approved by Santos DE Plan: Parker 272 @ 71.0usft 0 2500 5000 7500 10000 12500 So u t h ( - ) / N o r t h ( + ) -15000 -12500 -10000 -7500 -5000 -2500 0 2500 5000 West(-)/East(+) NDB-024 Heel v.0 NDB-024 TD v.0 20" 13-3/8" x 16" 9-5/8" x 12-1/4" 4-1/2" x 8-1/2" Plan: NDB-024 Rev A.1 12:28, July 12 2023 -2500 0 2500 5000 7500 Tr u e V e r t i c a l D e p t h 0 2500 5000 7500 10000 12500 15000 Vertical Section at 323.62° 20" 13-3/8" x 16" 9-5/8" x 12-1/4" 4-1/2" x 8-1/2" 1 0 0 0 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 150 00 16000 17000 18000 1 8050 0° 3 0 ° 60° 77° 90° 91 ° 9 1° Plan: NDB-024 Rev A.1 Upper Schrader Bluff Permafrost Base Middle Schrader Bluff MCU Tuluvak Shale Tuluvak Sand Seabee Nanushuk NT6 MFS NT5 MFS NT4 MFS NT3 MFS Nanushuk 3.2 (NT3) TM_BRO_30_39 TM_BRO_30_37 TM_BRO_30_38 TM_BRO_150_3 TM_ELS_150_3 Plan: NDB-024 Rev A.1 9:08, July 13 2023 Section View No r t h i n g ( 5 5 0 0 u s f t / i n ) Easting (5500 usft/in) No r t h i n g ( 5 5 0 0 u s f t / i n ) Easting (5500 usft/in) Rev A.0 Plan: NDB-032 Rev B.0 Rev A.0 Rev A.0 Rev A.0 Plan: NDBi-014 Rev B.0 Rev A.0 Plan: B-16 Rev A.0 Plan: B-18 Rev A.0 Rev A.0 Rev A.0 Plan: NDB-021 Rev A.0 Plan: B-25 Rev A.0 Rev A.0 Rev A.0 Rev A.0 Plan: NDBi-030 Rev B.1 Plan: Rev A.0 Rev A.0 Rev A.0 Rev A.0 Plan: B-37 Rev A.0 Plan: NDB-024 Rev A.1 ND-B NPF 12:48, July 12 2023 Standard Planning Report - Geographic 13 July, 2023 Plan: Plan: NDB-024 Rev A.1 Santos NAD27 Conversion Pikka Field ND-B B-24 B-24 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.1Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka Field, 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: ND-B Map Slot Radius:7.0 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: B-24 Wellhead Elevation:0.5 0.0 0.0 5,972,792.74 422,269.90 70° 20' 8.875 N 150° 37' 50.286 W 24.0 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) B-24 Model NameMagnetics BGGM2023 30/09/2023 14.52 80.59 57,184.51670033 Phase:Version: Audit Notes: Design Plan: NDB-024 Rev A.1 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 323.620.00.047.0 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 2 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.1Design: Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 13/07/2023 Depth To (usft) Depth From (usft) 2_MWD_Interp Azi H002Mb: Interpolated azim Plan: NDB-024 Rev A.1 (B-24)1 47.0 300.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-024 Rev A.1 (B-24)2 300.0 1,800.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-024 Rev A.1 (B-24)3 300.0 3,360.0 SDI_KPR_ADK SDI Keeper ADK Plan: NDB-024 Rev A.1 (B-24)4 47.0 300.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-024 Rev A.1 (B-24)5 3,360.0 4,860.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-024 Rev A.1 (B-24)6 3,360.0 11,608.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-024 Rev A.1 (B-24)7 11,608.0 13,108.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-024 Rev A.1 (B-24)8 11,608.0 18,049.5 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 0.000.000.000.000.00.0350.00.000.00350.0 345.000.003.003.00-2.710.1549.6345.006.00550.0 -26.45-1.082.973.00-918.61,170.32,230.8319.2877.152,941.8 0.000.000.000.00-6,174.37,276.44,069.2319.2877.1511,205.4 110.262.93-0.983.00-6,368.87,547.04,156.0329.3973.7711,550.2 0.000.000.000.00-6,417.77,629.74,184.0329.3973.7711,650.2 0.000.004.004.00-6,628.27,985.44,241.0329.3990.5212,069.0 NDB-024 Heel v.0 89.220.000.000.00-7,747.99,878.14,221.0329.4090.5214,268.2 NDB-024 post fault -3.00-0.081.501.50-7,760.19,898.74,220.7329.3890.8814,292.2 0.000.000.000.00-9,673.813,131.74,163.0329.3890.8818,049.5 NDB-024 TD v.0 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 3 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.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 0.00.00 422,269.905,972,792.74 70° 20' 8.875 N 150° 37' 50.286 W 100.0 0.00 100.0 0.0 0.00.00 422,269.905,972,792.74 70° 20' 8.875 N 150° 37' 50.286 W 127.0 0.00 127.0 0.0 0.00.00 422,269.905,972,792.74 70° 20' 8.875 N 150° 37' 50.286 W 20" 200.0 0.00 200.0 0.0 0.00.00 422,269.905,972,792.74 70° 20' 8.875 N 150° 37' 50.286 W 300.0 0.00 300.0 0.0 0.00.00 422,269.905,972,792.74 70° 20' 8.875 N 150° 37' 50.286 W 350.0 0.00 350.0 0.0 0.00.00 422,269.905,972,792.74 70° 20' 8.875 N 150° 37' 50.286 W Start Build 3.00 400.0 1.50 400.0 0.6 -0.2345.00 422,269.745,972,793.38 70° 20' 8.881 N 150° 37' 50.291 W 500.0 4.50 499.8 5.7 -1.5345.00 422,268.435,972,798.45 70° 20' 8.931 N 150° 37' 50.330 W 550.0 6.00 549.6 10.1 -2.7345.00 422,267.305,972,802.88 70° 20' 8.974 N 150° 37' 50.365 W Start DLS 3.00 TFO -26.46 600.0 7.37 599.3 15.6 -4.5339.79 422,265.575,972,808.43 70° 20' 9.029 N 150° 37' 50.417 W 700.0 10.23 698.1 29.6 -10.7333.65 422,259.565,972,822.47 70° 20' 9.166 N 150° 37' 50.597 W 800.0 13.14 796.0 47.4 -20.2330.19 422,250.155,972,840.39 70° 20' 9.341 N 150° 37' 50.877 W 900.0 16.09 892.8 69.1 -33.3327.97 422,237.365,972,862.14 70° 20' 9.554 N 150° 37' 51.257 W 1,000.0 19.06 988.1 94.4 -49.6326.43 422,221.255,972,887.67 70° 20' 9.803 N 150° 37' 51.735 W 1,063.7 20.95 1,048.0 112.5 -61.8325.66 422,209.255,972,905.87 70° 20' 9.981 N 150° 37' 52.091 W Upper Schrader Bluff 1,100.0 22.03 1,081.7 123.4 -69.3325.29 422,201.845,972,916.89 70° 20' 10.089 N 150° 37' 52.311 W 1,200.0 25.01 1,173.4 156.1 -92.3324.41 422,179.195,972,949.74 70° 20' 10.410 N 150° 37' 52.982 W 1,300.0 27.99 1,262.9 192.2 -118.5323.70 422,153.375,972,986.11 70° 20' 10.765 N 150° 37' 53.748 W 1,400.0 30.98 1,349.9 231.7 -147.9323.12 422,124.445,973,025.92 70° 20' 11.153 N 150° 37' 54.605 W 1,453.0 32.56 1,395.0 254.0 -164.7322.86 422,107.875,973,048.38 70° 20' 11.373 N 150° 37' 55.095 W Permafrost Base 1,500.0 33.97 1,434.3 274.5 -180.3322.64 422,092.485,973,069.06 70° 20' 11.574 N 150° 37' 55.551 W 1,600.0 36.96 1,515.7 320.5 -215.7322.22 422,057.595,973,115.39 70° 20' 12.026 N 150° 37' 56.584 W 1,700.0 39.95 1,594.0 369.5 -253.9321.86 422,019.855,973,164.81 70° 20' 12.509 N 150° 37' 57.701 W 1,800.0 42.94 1,669.0 421.4 -294.9321.54 421,979.375,973,217.16 70° 20' 13.019 N 150° 37' 58.899 W 1,900.0 45.94 1,740.4 476.1 -338.6321.26 421,936.275,973,272.31 70° 20' 13.557 N 150° 38' 0.175 W 1,905.2 46.09 1,744.0 479.1 -341.0321.24 421,933.945,973,275.27 70° 20' 13.586 N 150° 38' 0.244 W Middle Schrader Bluff 2,000.0 48.93 1,808.0 533.5 -384.8321.00 421,890.655,973,330.11 70° 20' 14.121 N 150° 38' 1.525 W 2,100.0 51.92 1,871.7 593.3 -433.5320.76 421,842.655,973,390.40 70° 20' 14.709 N 150° 38' 2.945 W 2,200.0 54.92 1,931.3 655.4 -484.4320.55 421,792.395,973,453.02 70° 20' 15.320 N 150° 38' 4.432 W 2,300.0 57.91 1,986.6 719.6 -537.4320.35 421,740.025,973,517.78 70° 20' 15.952 N 150° 38' 5.982 W 2,400.0 60.91 2,037.5 785.8 -592.5320.16 421,685.675,973,584.52 70° 20' 16.602 N 150° 38' 7.590 W 2,500.0 63.91 2,083.8 853.7 -649.3319.98 421,629.505,973,653.05 70° 20' 17.271 N 150° 38' 9.251 W 2,600.0 66.90 2,125.4 923.2 -707.9319.81 421,571.665,973,723.19 70° 20' 17.954 N 150° 38' 10.962 W 2,657.0 68.61 2,147.0 963.5 -742.0319.72 421,537.985,973,763.84 70° 20' 18.351 N 150° 38' 11.958 W MCU 2,700.0 69.90 2,162.2 994.2 -768.0319.65 421,512.315,973,794.73 70° 20' 18.652 N 150° 38' 12.717 W 2,726.0 70.68 2,171.0 1,012.9 -783.9319.61 421,496.635,973,813.57 70° 20' 18.836 N 150° 38' 13.181 W TM_BRO_30_39 2,800.0 72.89 2,194.1 1,066.3 -829.5319.49 421,451.615,973,867.49 70° 20' 19.361 N 150° 38' 14.513 W 2,900.0 75.89 2,221.0 1,139.4 -892.1319.34 421,389.735,973,941.27 70° 20' 20.081 N 150° 38' 16.343 W 2,941.9 77.15 2,230.8 1,170.3 -918.7319.28 421,363.515,973,972.42 70° 20' 20.384 N 150° 38' 17.118 W Start 8263.8 hold at 2941.9 MD 3,000.0 77.15 2,243.7 1,213.3 -955.6319.28 421,326.995,974,015.74 70° 20' 20.807 N 150° 38' 18.198 W 3,100.0 77.15 2,266.0 1,287.2 -1,019.2319.28 421,264.175,974,090.29 70° 20' 21.533 N 150° 38' 20.056 W 3,200.0 77.15 2,288.2 1,361.1 -1,082.8319.28 421,201.345,974,164.83 70° 20' 22.260 N 150° 38' 21.914 W 3,240.0 77.15 2,297.1 1,390.6 -1,108.3319.28 421,176.215,974,194.64 70° 20' 22.551 N 150° 38' 22.657 W 13-3/8" x 16" 3,300.0 77.15 2,310.5 1,435.0 -1,146.4319.28 421,138.525,974,239.37 70° 20' 22.987 N 150° 38' 23.772 W 3,400.0 77.15 2,332.7 1,508.8 -1,210.0319.28 421,075.695,974,313.91 70° 20' 23.713 N 150° 38' 25.630 W 3,500.0 77.15 2,354.9 1,582.7 -1,273.6319.28 421,012.875,974,388.45 70° 20' 24.440 N 150° 38' 27.488 W 3,600.0 77.15 2,377.2 1,656.6 -1,337.2319.28 420,950.045,974,462.99 70° 20' 25.166 N 150° 38' 29.346 W 3,700.0 77.15 2,399.4 1,730.5 -1,400.8319.28 420,887.215,974,537.53 70° 20' 25.893 N 150° 38' 31.205 W 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 4 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.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) 3,800.0 77.15 2,421.7 1,804.4 -1,464.4319.28 420,824.395,974,612.07 70° 20' 26.620 N 150° 38' 33.063 W 3,900.0 77.15 2,443.9 1,878.3 -1,528.0319.28 420,761.565,974,686.61 70° 20' 27.346 N 150° 38' 34.921 W 3,985.7 77.15 2,463.0 1,941.6 -1,582.5319.28 420,707.745,974,750.47 70° 20' 27.969 N 150° 38' 36.513 W Tuluvak Shale 4,000.0 77.15 2,466.2 1,952.2 -1,591.6319.28 420,698.745,974,761.15 70° 20' 28.073 N 150° 38' 36.779 W 4,100.0 77.15 2,488.4 2,026.1 -1,655.2319.28 420,635.915,974,835.69 70° 20' 28.799 N 150° 38' 38.638 W 4,200.0 77.15 2,510.7 2,100.0 -1,718.8319.28 420,573.095,974,910.23 70° 20' 29.526 N 150° 38' 40.496 W 4,268.8 77.15 2,526.0 2,150.8 -1,762.6319.28 420,529.845,974,961.54 70° 20' 30.026 N 150° 38' 41.775 W Tuluvak Sand 4,300.0 77.15 2,532.9 2,173.9 -1,782.4319.28 420,510.265,974,984.77 70° 20' 30.253 N 150° 38' 42.355 W 4,381.2 77.15 2,551.0 2,233.9 -1,834.1319.28 420,459.245,975,045.30 70° 20' 30.843 N 150° 38' 43.864 W TM_BRO_30_37 4,400.0 77.15 2,555.2 2,247.8 -1,846.0319.28 420,447.445,975,059.31 70° 20' 30.979 N 150° 38' 44.213 W 4,500.0 77.15 2,577.4 2,321.7 -1,909.6319.28 420,384.615,975,133.85 70° 20' 31.706 N 150° 38' 46.071 W 4,600.0 77.15 2,599.7 2,395.5 -1,973.2319.28 420,321.795,975,208.39 70° 20' 32.432 N 150° 38' 47.930 W 4,700.0 77.15 2,621.9 2,469.4 -2,036.8319.28 420,258.965,975,282.93 70° 20' 33.159 N 150° 38' 49.789 W 4,800.0 77.15 2,644.2 2,543.3 -2,100.4319.28 420,196.145,975,357.47 70° 20' 33.885 N 150° 38' 51.647 W 4,900.0 77.15 2,666.4 2,617.2 -2,164.0319.28 420,133.315,975,432.01 70° 20' 34.612 N 150° 38' 53.506 W 5,000.0 77.15 2,688.7 2,691.1 -2,227.6319.28 420,070.495,975,506.55 70° 20' 35.338 N 150° 38' 55.364 W 5,100.0 77.15 2,710.9 2,765.0 -2,291.2319.28 420,007.665,975,581.09 70° 20' 36.065 N 150° 38' 57.223 W 5,200.0 77.15 2,733.2 2,838.9 -2,354.8319.28 419,944.845,975,655.63 70° 20' 36.791 N 150° 38' 59.082 W 5,300.0 77.15 2,755.4 2,912.8 -2,418.4319.28 419,882.015,975,730.17 70° 20' 37.518 N 150° 39' 0.941 W 5,400.0 77.15 2,777.7 2,986.7 -2,482.0319.28 419,819.195,975,804.71 70° 20' 38.244 N 150° 39' 2.799 W 5,500.0 77.15 2,799.9 3,060.6 -2,545.6319.28 419,756.365,975,879.25 70° 20' 38.971 N 150° 39' 4.658 W 5,600.0 77.15 2,822.2 3,134.5 -2,609.2319.28 419,693.545,975,953.79 70° 20' 39.697 N 150° 39' 6.517 W 5,700.0 77.15 2,844.4 3,208.4 -2,672.8319.28 419,630.715,976,028.33 70° 20' 40.424 N 150° 39' 8.376 W 5,800.0 77.15 2,866.7 3,282.3 -2,736.4319.28 419,567.895,976,102.87 70° 20' 41.150 N 150° 39' 10.235 W 5,900.0 77.15 2,888.9 3,356.1 -2,800.0319.28 419,505.065,976,177.41 70° 20' 41.877 N 150° 39' 12.094 W 6,000.0 77.15 2,911.1 3,430.0 -2,863.6319.28 419,442.245,976,251.96 70° 20' 42.603 N 150° 39' 13.953 W 6,066.8 77.15 2,926.0 3,479.4 -2,906.1319.28 419,400.295,976,301.72 70° 20' 43.088 N 150° 39' 15.194 W TM_BRO_30_38 6,100.0 77.15 2,933.4 3,503.9 -2,927.2319.28 419,379.415,976,326.50 70° 20' 43.330 N 150° 39' 15.812 W 6,200.0 77.15 2,955.6 3,577.8 -2,990.8319.28 419,316.595,976,401.04 70° 20' 44.056 N 150° 39' 17.671 W 6,300.0 77.15 2,977.9 3,651.7 -3,054.4319.28 419,253.765,976,475.58 70° 20' 44.783 N 150° 39' 19.530 W 6,400.0 77.15 3,000.1 3,725.6 -3,118.0319.28 419,190.945,976,550.12 70° 20' 45.509 N 150° 39' 21.390 W 6,500.0 77.15 3,022.4 3,799.5 -3,181.6319.28 419,128.115,976,624.66 70° 20' 46.236 N 150° 39' 23.249 W 6,600.0 77.15 3,044.6 3,873.4 -3,245.2319.28 419,065.295,976,699.20 70° 20' 46.962 N 150° 39' 25.108 W 6,700.0 77.15 3,066.9 3,947.3 -3,308.8319.28 419,002.465,976,773.74 70° 20' 47.689 N 150° 39' 26.967 W 6,800.0 77.15 3,089.1 4,021.2 -3,372.4319.28 418,939.645,976,848.28 70° 20' 48.415 N 150° 39' 28.827 W 6,900.0 77.15 3,111.4 4,095.1 -3,436.0319.28 418,876.815,976,922.82 70° 20' 49.142 N 150° 39' 30.686 W 7,000.0 77.15 3,133.6 4,169.0 -3,499.6319.28 418,813.995,976,997.36 70° 20' 49.868 N 150° 39' 32.545 W 7,100.0 77.15 3,155.9 4,242.8 -3,563.2319.28 418,751.165,977,071.90 70° 20' 50.594 N 150° 39' 34.405 W 7,168.0 77.15 3,171.0 4,293.1 -3,606.5319.28 418,708.455,977,122.58 70° 20' 51.088 N 150° 39' 35.669 W Seabee 7,200.0 77.15 3,178.1 4,316.7 -3,626.8319.28 418,688.345,977,146.44 70° 20' 51.321 N 150° 39' 36.264 W 7,300.0 77.15 3,200.4 4,390.6 -3,690.4319.28 418,625.515,977,220.98 70° 20' 52.047 N 150° 39' 38.124 W 7,400.0 77.15 3,222.6 4,464.5 -3,754.0319.28 418,562.685,977,295.52 70° 20' 52.774 N 150° 39' 39.983 W 7,500.0 77.15 3,244.9 4,538.4 -3,817.6319.28 418,499.865,977,370.06 70° 20' 53.500 N 150° 39' 41.843 W 7,600.0 77.15 3,267.1 4,612.3 -3,881.2319.28 418,437.035,977,444.60 70° 20' 54.226 N 150° 39' 43.703 W 7,700.0 77.15 3,289.4 4,686.2 -3,944.8319.28 418,374.215,977,519.14 70° 20' 54.953 N 150° 39' 45.562 W 7,800.0 77.15 3,311.6 4,760.1 -4,008.4319.28 418,311.385,977,593.68 70° 20' 55.679 N 150° 39' 47.422 W 7,900.0 77.15 3,333.9 4,834.0 -4,072.0319.28 418,248.565,977,668.22 70° 20' 56.406 N 150° 39' 49.282 W 8,000.0 77.15 3,356.1 4,907.9 -4,135.6319.28 418,185.735,977,742.76 70° 20' 57.132 N 150° 39' 51.141 W 8,100.0 77.15 3,378.4 4,981.8 -4,199.2319.28 418,122.915,977,817.30 70° 20' 57.858 N 150° 39' 53.001 W 8,200.0 77.15 3,400.6 5,055.7 -4,262.8319.28 418,060.085,977,891.84 70° 20' 58.585 N 150° 39' 54.861 W 8,300.0 77.15 3,422.8 5,129.6 -4,326.4319.28 417,997.265,977,966.38 70° 20' 59.311 N 150° 39' 56.721 W 8,400.0 77.15 3,445.1 5,203.4 -4,390.0319.28 417,934.435,978,040.92 70° 21' 0.037 N 150° 39' 58.581 W 8,500.0 77.15 3,467.3 5,277.3 -4,453.6319.28 417,871.615,978,115.46 70° 21' 0.764 N 150° 40' 0.441 W 8,600.0 77.15 3,489.6 5,351.2 -4,517.2319.28 417,808.785,978,190.00 70° 21' 1.490 N 150° 40' 2.301 W 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 5 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.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) 8,700.0 77.15 3,511.8 5,425.1 -4,580.8319.28 417,745.965,978,264.54 70° 21' 2.216 N 150° 40' 4.161 W 8,800.0 77.15 3,534.1 5,499.0 -4,644.4319.28 417,683.135,978,339.08 70° 21' 2.943 N 150° 40' 6.021 W 8,900.0 77.15 3,556.3 5,572.9 -4,708.0319.28 417,620.315,978,413.63 70° 21' 3.669 N 150° 40' 7.881 W 9,000.0 77.15 3,578.6 5,646.8 -4,771.6319.28 417,557.485,978,488.17 70° 21' 4.395 N 150° 40' 9.741 W 9,100.0 77.15 3,600.8 5,720.7 -4,835.2319.28 417,494.665,978,562.71 70° 21' 5.122 N 150° 40' 11.601 W 9,200.0 77.15 3,623.1 5,794.6 -4,898.8319.28 417,431.835,978,637.25 70° 21' 5.848 N 150° 40' 13.462 W 9,300.0 77.15 3,645.3 5,868.5 -4,962.4319.28 417,369.015,978,711.79 70° 21' 6.574 N 150° 40' 15.322 W 9,400.0 77.15 3,667.6 5,942.4 -5,026.0319.28 417,306.185,978,786.33 70° 21' 7.301 N 150° 40' 17.182 W 9,500.0 77.15 3,689.8 6,016.3 -5,089.6319.28 417,243.365,978,860.87 70° 21' 8.027 N 150° 40' 19.042 W 9,600.0 77.15 3,712.1 6,090.2 -5,153.2319.28 417,180.535,978,935.41 70° 21' 8.753 N 150° 40' 20.903 W 9,700.0 77.15 3,734.3 6,164.0 -5,216.8319.28 417,117.715,979,009.95 70° 21' 9.480 N 150° 40' 22.763 W 9,800.0 77.15 3,756.6 6,237.9 -5,280.4319.28 417,054.885,979,084.49 70° 21' 10.206 N 150° 40' 24.624 W 9,900.0 77.15 3,778.8 6,311.8 -5,344.0319.28 416,992.065,979,159.03 70° 21' 10.932 N 150° 40' 26.484 W 10,000.0 77.15 3,801.1 6,385.7 -5,407.6319.28 416,929.235,979,233.57 70° 21' 11.658 N 150° 40' 28.344 W 10,100.0 77.15 3,823.3 6,459.6 -5,471.2319.28 416,866.415,979,308.11 70° 21' 12.385 N 150° 40' 30.205 W 10,152.5 77.15 3,835.0 6,498.4 -5,504.7319.28 416,833.405,979,347.27 70° 21' 12.766 N 150° 40' 31.182 W Nanushuk 10,200.0 77.15 3,845.6 6,533.5 -5,534.8319.28 416,803.585,979,382.65 70° 21' 13.111 N 150° 40' 32.066 W 10,300.0 77.15 3,867.8 6,607.4 -5,598.4319.28 416,740.765,979,457.19 70° 21' 13.837 N 150° 40' 33.926 W 10,400.0 77.15 3,890.1 6,681.3 -5,662.0319.28 416,677.935,979,531.73 70° 21' 14.563 N 150° 40' 35.787 W 10,498.6 77.15 3,912.0 6,754.2 -5,724.8319.28 416,615.975,979,605.25 70° 21' 15.280 N 150° 40' 37.622 W NT6 MFS 10,500.0 77.15 3,912.3 6,755.2 -5,725.6319.28 416,615.115,979,606.27 70° 21' 15.290 N 150° 40' 37.648 W 10,600.0 77.15 3,934.6 6,829.1 -5,789.2319.28 416,552.285,979,680.81 70° 21' 16.016 N 150° 40' 39.508 W 10,651.5 77.15 3,946.0 6,867.1 -5,822.0319.28 416,519.955,979,719.17 70° 21' 16.390 N 150° 40' 40.466 W TM_BRO_150_3 10,700.0 77.15 3,956.8 6,903.0 -5,852.8319.28 416,489.465,979,755.35 70° 21' 16.742 N 150° 40' 41.369 W 10,800.0 77.15 3,979.0 6,976.9 -5,916.4319.28 416,426.635,979,829.89 70° 21' 17.468 N 150° 40' 43.230 W 10,822.3 77.15 3,984.0 6,993.3 -5,930.6319.28 416,412.655,979,846.48 70° 21' 17.630 N 150° 40' 43.644 W NT5 MFS 10,900.0 77.15 4,001.3 7,050.7 -5,980.0319.28 416,363.815,979,904.43 70° 21' 18.195 N 150° 40' 45.091 W 11,000.0 77.15 4,023.5 7,124.6 -6,043.6319.28 416,300.985,979,978.97 70° 21' 18.921 N 150° 40' 46.951 W 11,029.0 77.15 4,030.0 7,146.1 -6,062.1319.28 416,282.755,980,000.60 70° 21' 19.132 N 150° 40' 47.491 W NT4 MFS 11,100.0 77.15 4,045.8 7,198.5 -6,107.2319.28 416,238.165,980,053.51 70° 21' 19.647 N 150° 40' 48.812 W 11,200.0 77.15 4,068.0 7,272.4 -6,170.8319.28 416,175.335,980,128.05 70° 21' 20.373 N 150° 40' 50.673 W 11,205.4 77.15 4,069.2 7,276.4 -6,174.3319.28 416,171.965,980,132.05 70° 21' 20.412 N 150° 40' 50.773 W 11,205.7 77.14 4,069.3 7,276.6 -6,174.5319.29 416,171.775,980,132.28 70° 21' 20.414 N 150° 40' 50.779 W Start DLS 3.00 TFO 110.26 11,300.0 76.18 4,091.1 7,347.6 -6,232.6322.02 416,114.335,980,203.84 70° 21' 21.112 N 150° 40' 52.481 W 11,341.0 75.77 4,101.0 7,379.2 -6,256.8323.22 416,090.515,980,235.70 70° 21' 21.423 N 150° 40' 53.188 W 9-5/8" x 12-1/4" 11,400.0 75.19 4,115.8 7,425.4 -6,290.3324.95 416,057.495,980,282.29 70° 21' 21.877 N 150° 40' 54.169 W 11,400.8 75.18 4,116.0 7,426.0 -6,290.7324.97 416,057.085,980,282.89 70° 21' 21.883 N 150° 40' 54.181 W NT3 MFS 11,500.0 74.23 4,142.2 7,505.8 -6,343.6327.90 416,004.985,980,363.18 70° 21' 22.667 N 150° 40' 55.730 W 11,550.2 73.77 4,156.0 7,547.0 -6,368.8329.39 415,980.295,980,404.66 70° 21' 23.072 N 150° 40' 56.466 W 11,550.6 73.77 4,156.1 7,547.4 -6,369.0329.39 415,980.095,980,405.01 70° 21' 23.076 N 150° 40' 56.472 W Start 100.0 hold at 11550.6 MD 11,564.4 73.77 4,160.0 7,558.8 -6,375.7329.39 415,973.465,980,416.48 70° 21' 23.188 N 150° 40' 56.669 W Nanushuk 3.2 (NT3) 11,600.0 73.77 4,169.9 7,588.1 -6,393.1329.39 415,956.385,980,446.04 70° 21' 23.477 N 150° 40' 57.178 W 11,650.2 73.77 4,184.0 7,629.7 -6,417.7329.39 415,932.265,980,487.79 70° 21' 23.885 N 150° 40' 57.897 W 11,650.6 73.79 4,184.1 7,630.0 -6,417.9329.39 415,932.065,980,488.14 70° 21' 23.888 N 150° 40' 57.903 W Start Build 4.00 11,700.0 75.76 4,197.1 7,671.0 -6,442.1329.39 415,908.245,980,529.36 70° 21' 24.291 N 150° 40' 58.613 W 11,738.4 77.30 4,206.0 7,703.1 -6,461.1329.39 415,889.555,980,561.70 70° 21' 24.607 N 150° 40' 59.170 W TM_ELS_150_3 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 6 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.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) 11,800.0 79.76 4,218.2 7,755.1 -6,491.9329.39 415,859.365,980,613.96 70° 21' 25.117 N 150° 41' 0.070 W 11,900.0 83.76 4,232.6 7,840.2 -6,542.3329.39 415,809.865,980,699.62 70° 21' 25.954 N 150° 41' 1.545 W 12,000.0 87.76 4,240.0 7,926.0 -6,593.0329.39 415,759.985,980,785.95 70° 21' 26.798 N 150° 41' 3.032 W 12,069.0 90.52 4,241.0 7,985.4 -6,628.2329.39 415,725.475,980,845.68 70° 21' 27.382 N 150° 41' 4.060 W NDB-024 Geological Polygon - NDB-024 Heel v.0 12,069.4 90.52 4,241.0 7,985.8 -6,628.4329.39 415,725.265,980,846.04 70° 21' 27.385 N 150° 41' 4.066 W Start 2199.2 hold at 12069.4 MD 12,100.0 90.52 4,240.7 8,012.1 -6,643.9329.39 415,709.975,980,872.51 70° 21' 27.644 N 150° 41' 4.522 W 12,200.0 90.52 4,239.8 8,098.1 -6,694.9329.39 415,659.955,980,959.09 70° 21' 28.490 N 150° 41' 6.013 W 12,300.0 90.52 4,238.9 8,184.2 -6,745.8329.39 415,609.925,981,045.66 70° 21' 29.336 N 150° 41' 7.504 W 12,400.0 90.52 4,238.0 8,270.3 -6,796.7329.39 415,559.905,981,132.24 70° 21' 30.182 N 150° 41' 8.995 W 12,500.0 90.52 4,237.1 8,356.3 -6,847.6329.39 415,509.885,981,218.81 70° 21' 31.027 N 150° 41' 10.486 W 12,600.0 90.52 4,236.2 8,442.4 -6,898.5329.39 415,459.865,981,305.39 70° 21' 31.873 N 150° 41' 11.977 W 12,700.0 90.52 4,235.3 8,528.4 -6,949.5329.39 415,409.855,981,391.96 70° 21' 32.719 N 150° 41' 13.468 W 12,800.0 90.52 4,234.4 8,614.5 -7,000.4329.39 415,359.835,981,478.54 70° 21' 33.565 N 150° 41' 14.959 W 12,900.0 90.52 4,233.4 8,700.6 -7,051.3329.39 415,309.815,981,565.12 70° 21' 34.411 N 150° 41' 16.450 W 13,000.0 90.52 4,232.5 8,786.6 -7,102.2329.39 415,259.795,981,651.70 70° 21' 35.257 N 150° 41' 17.941 W 13,100.0 90.52 4,231.6 8,872.7 -7,153.1329.39 415,209.785,981,738.27 70° 21' 36.103 N 150° 41' 19.432 W 13,200.0 90.52 4,230.7 8,958.8 -7,204.0329.39 415,159.765,981,824.85 70° 21' 36.949 N 150° 41' 20.923 W 13,300.0 90.52 4,229.8 9,044.8 -7,255.0329.39 415,109.755,981,911.43 70° 21' 37.795 N 150° 41' 22.415 W 13,400.0 90.52 4,228.9 9,130.9 -7,305.9329.39 415,059.735,981,998.01 70° 21' 38.641 N 150° 41' 23.906 W 13,500.0 90.52 4,228.0 9,217.0 -7,356.8329.39 415,009.725,982,084.59 70° 21' 39.487 N 150° 41' 25.397 W 13,600.0 90.52 4,227.1 9,303.0 -7,407.7329.39 414,959.715,982,171.17 70° 21' 40.333 N 150° 41' 26.888 W 13,700.0 90.52 4,226.2 9,389.1 -7,458.6329.39 414,909.705,982,257.75 70° 21' 41.179 N 150° 41' 28.379 W 13,800.0 90.52 4,225.3 9,475.1 -7,509.5329.39 414,859.685,982,344.33 70° 21' 42.025 N 150° 41' 29.870 W 13,900.0 90.52 4,224.3 9,561.2 -7,560.4329.39 414,809.675,982,430.91 70° 21' 42.871 N 150° 41' 31.361 W 14,000.0 90.52 4,223.4 9,647.3 -7,611.3329.40 414,759.665,982,517.49 70° 21' 43.717 N 150° 41' 32.853 W 14,100.0 90.52 4,222.5 9,733.3 -7,662.2329.40 414,709.655,982,604.07 70° 21' 44.563 N 150° 41' 34.344 W 14,200.0 90.52 4,221.6 9,819.4 -7,713.2329.40 414,659.645,982,690.65 70° 21' 45.408 N 150° 41' 35.835 W 14,268.2 90.52 4,221.0 9,878.1 -7,747.9329.40 414,625.535,982,749.72 70° 21' 45.986 N 150° 41' 36.853 W NDB-024 post fault v0 14,268.6 90.53 4,221.0 9,878.5 -7,748.1329.40 414,625.325,982,750.07 70° 21' 45.989 N 150° 41' 36.859 W Start DLS 1.50 TFO -2.31 14,292.2 90.88 4,220.7 9,898.7 -7,760.1329.38 414,613.555,982,770.45 70° 21' 46.188 N 150° 41' 37.210 W 14,292.6 90.88 4,220.7 9,899.1 -7,760.3329.38 414,613.355,982,770.80 70° 21' 46.192 N 150° 41' 37.216 W Start 3757.4 hold at 14292.6 MD 14,300.0 90.88 4,220.6 9,905.5 -7,764.1329.38 414,609.635,982,777.23 70° 21' 46.254 N 150° 41' 37.327 W 14,400.0 90.88 4,219.1 9,991.5 -7,815.0329.38 414,559.605,982,863.79 70° 21' 47.100 N 150° 41' 38.819 W 14,500.0 90.88 4,217.5 10,077.6 -7,865.9329.38 414,509.565,982,950.35 70° 21' 47.946 N 150° 41' 40.311 W 14,600.0 90.88 4,216.0 10,163.6 -7,916.9329.38 414,459.535,983,036.91 70° 21' 48.791 N 150° 41' 41.803 W 14,700.0 90.88 4,214.4 10,249.7 -7,967.8329.38 414,409.505,983,123.47 70° 21' 49.637 N 150° 41' 43.295 W 14,800.0 90.88 4,212.9 10,335.7 -8,018.7329.38 414,359.465,983,210.03 70° 21' 50.483 N 150° 41' 44.787 W 14,900.0 90.88 4,211.4 10,421.7 -8,069.7329.38 414,309.435,983,296.58 70° 21' 51.329 N 150° 41' 46.279 W 15,000.0 90.88 4,209.8 10,507.8 -8,120.6329.38 414,259.405,983,383.14 70° 21' 52.174 N 150° 41' 47.771 W 15,100.0 90.88 4,208.3 10,593.8 -8,171.5329.38 414,209.375,983,469.70 70° 21' 53.020 N 150° 41' 49.264 W 15,200.0 90.88 4,206.8 10,679.9 -8,222.5329.38 414,159.335,983,556.26 70° 21' 53.866 N 150° 41' 50.756 W 15,300.0 90.88 4,205.2 10,765.9 -8,273.4329.38 414,109.305,983,642.82 70° 21' 54.711 N 150° 41' 52.248 W 15,400.0 90.88 4,203.7 10,852.0 -8,324.3329.38 414,059.275,983,729.38 70° 21' 55.557 N 150° 41' 53.741 W 15,500.0 90.88 4,202.2 10,938.0 -8,375.3329.38 414,009.235,983,815.94 70° 21' 56.403 N 150° 41' 55.233 W 15,600.0 90.88 4,200.6 11,024.0 -8,426.2329.38 413,959.205,983,902.50 70° 21' 57.248 N 150° 41' 56.725 W 15,700.0 90.88 4,199.1 11,110.1 -8,477.1329.38 413,909.175,983,989.06 70° 21' 58.094 N 150° 41' 58.218 W 15,800.0 90.88 4,197.6 11,196.1 -8,528.1329.38 413,859.135,984,075.62 70° 21' 58.940 N 150° 41' 59.710 W 15,900.0 90.88 4,196.0 11,282.2 -8,579.0329.38 413,809.105,984,162.18 70° 21' 59.785 N 150° 42' 1.203 W 16,000.0 90.88 4,194.5 11,368.2 -8,629.9329.38 413,759.075,984,248.73 70° 22' 0.631 N 150° 42' 2.696 W 16,100.0 90.88 4,192.9 11,454.3 -8,680.8329.38 413,709.045,984,335.29 70° 22' 1.477 N 150° 42' 4.188 W 16,200.0 90.88 4,191.4 11,540.3 -8,731.8329.38 413,659.005,984,421.85 70° 22' 2.322 N 150° 42' 5.681 W 16,300.0 90.88 4,189.9 11,626.4 -8,782.7329.38 413,608.975,984,508.41 70° 22' 3.168 N 150° 42' 7.173 W 16,400.0 90.88 4,188.3 11,712.4 -8,833.6329.38 413,558.945,984,594.97 70° 22' 4.013 N 150° 42' 8.666 W 16,500.0 90.88 4,186.8 11,798.4 -8,884.6329.38 413,508.905,984,681.53 70° 22' 4.859 N 150° 42' 10.159 W 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 7 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.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) 16,600.0 90.88 4,185.3 11,884.5 -8,935.5329.38 413,458.875,984,768.09 70° 22' 5.705 N 150° 42' 11.652 W 16,700.0 90.88 4,183.7 11,970.5 -8,986.4329.38 413,408.845,984,854.65 70° 22' 6.550 N 150° 42' 13.144 W 16,800.0 90.88 4,182.2 12,056.6 -9,037.4329.38 413,358.805,984,941.21 70° 22' 7.396 N 150° 42' 14.637 W 16,900.0 90.88 4,180.7 12,142.6 -9,088.3329.38 413,308.775,985,027.77 70° 22' 8.242 N 150° 42' 16.130 W 17,000.0 90.88 4,179.1 12,228.7 -9,139.2329.38 413,258.745,985,114.33 70° 22' 9.087 N 150° 42' 17.623 W 17,100.0 90.88 4,177.6 12,314.7 -9,190.2329.38 413,208.715,985,200.88 70° 22' 9.933 N 150° 42' 19.116 W 17,200.0 90.88 4,176.1 12,400.7 -9,241.1329.38 413,158.675,985,287.44 70° 22' 10.778 N 150° 42' 20.609 W 17,300.0 90.88 4,174.5 12,486.8 -9,292.0329.38 413,108.645,985,374.00 70° 22' 11.624 N 150° 42' 22.102 W 17,400.0 90.88 4,173.0 12,572.8 -9,343.0329.38 413,058.615,985,460.56 70° 22' 12.470 N 150° 42' 23.595 W 17,500.0 90.88 4,171.4 12,658.9 -9,393.9329.38 413,008.575,985,547.12 70° 22' 13.315 N 150° 42' 25.088 W 17,600.0 90.88 4,169.9 12,744.9 -9,444.8329.38 412,958.545,985,633.68 70° 22' 14.161 N 150° 42' 26.581 W 17,700.0 90.88 4,168.4 12,831.0 -9,495.8329.38 412,908.515,985,720.24 70° 22' 15.006 N 150° 42' 28.074 W 17,800.0 90.88 4,166.8 12,917.0 -9,546.7329.38 412,858.475,985,806.80 70° 22' 15.852 N 150° 42' 29.568 W 17,900.0 90.88 4,165.3 13,003.1 -9,597.6329.38 412,808.445,985,893.36 70° 22' 16.698 N 150° 42' 31.061 W 18,000.0 90.88 4,163.8 13,089.1 -9,648.6329.38 412,758.415,985,979.92 70° 22' 17.543 N 150° 42' 32.554 W 18,049.5 90.88 4,163.0 13,131.7 -9,673.8329.38 412,733.625,986,022.80 70° 22' 17.962 N 150° 42' 33.294 W NDB-024 TD v.0 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-024 TD v.0 4,163.0 5,986,022.80 412,733.6213,131.7 -9,673.80.00 0.00 70° 22' 17.962 N 150° 42' 33.294 W - plan hits target center - Point NDB-024 post fault v0 4,221.0 5,982,749.72 414,625.539,878.1 -7,747.90.00 0.00 70° 21' 45.986 N 150° 41' 36.853 W - plan hits target center - Point NDB-024 Geological P 4,241.0 5,980,845.68 415,725.477,985.4 -6,628.23.00 226.00 70° 21' 27.382 N 150° 41' 4.060 W - plan hits target center - Polygon -455.3Point 1 5,980,385.12 416,229.634,238.4 509.0 True 5,244.0Point 2 5,986,117.17 412,908.074,158.4 -2,870.6 True 5,039.9Point 3 5,985,917.03 412,562.294,178.8 -3,214.7 True -659.3Point 4 5,980,185.08 415,883.854,258.8 164.9 True NDB-024 Heel v.0 4,241.0 5,980,845.68 415,725.477,985.4 -6,628.20.00 0.00 70° 21' 27.382 N 150° 41' 4.060 W - plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20"127.0127.0 20 26 13-3/8" x 16"2,297.13,240.0 13-3/8 17-1/2 9-5/8" x 12-1/4"4,101.011,341.0 9-5/8 12-1/4 4-1/2" x 8-1/2"18,049.9 4-1/2 8-1/2 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 8 Planning Report - Geographic Well B-24Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 71.0usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 71.0usftMD Reference:Pikka FieldProject: TrueNorth Reference:ND-BSite: Minimum CurvatureSurvey Calculation Method:B-24Well: B-24Wellbore: Plan: NDB-024 Rev A.1Design: Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,063.7 Upper Schrader Bluff1,048.0 1,453.0 Permafrost Base1,395.0 1,905.2 Middle Schrader Bluff1,744.0 2,657.0 MCU2,147.0 2,726.0 TM_BRO_30_392,171.0 3,985.7 Tuluvak Shale2,463.0 4,268.8 Tuluvak Sand2,526.0 4,381.2 TM_BRO_30_372,551.0 6,066.8 TM_BRO_30_382,926.0 7,168.0 Seabee 0.003,171.0 10,152.5 Nanushuk3,835.0 10,498.6 NT6 MFS3,912.0 10,651.5 TM_BRO_150_33,946.0 10,822.3 NT5 MFS3,984.0 11,029.0 NT4 MFS4,030.0 11,400.8 NT3 MFS4,116.0 11,564.4 Nanushuk 3.2 (NT3)4,160.0 11,738.4 TM_ELS_150_34,206.0 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 350.0 350.0 0.0 0.0 Start Build 3.00 550.0 549.6 10.1 -2.7 Start DLS 3.00 TFO -26.46 2,941.9 2,230.8 1,170.3 -918.7 Start 8263.8 hold at 2941.9 MD 11,205.7 4,069.3 7,276.6 -6,174.5 Start DLS 3.00 TFO 110.26 11,550.6 4,156.1 7,547.4 -6,369.0 Start 100.0 hold at 11550.6 MD 11,650.6 4,184.1 7,630.0 -6,417.9 Start Build 4.00 12,069.4 4,241.0 7,985.8 -6,628.4 Start 2199.2 hold at 12069.4 MD 14,268.6 4,221.0 9,878.5 -7,748.1 Start DLS 1.50 TFO -2.31 14,292.6 4,220.7 9,899.1 -7,760.3 Start 3757.4 hold at 14292.6 MD 18,049.9 TD at 18049.9 13/07/2023 9:12:06AM COMPASS 5000.17 Build 02 Page 9 12 July, 2023 Anticollision Summary Report Santos Pikka Field ND-B B-24 B-24 Plan: NDB-024 Rev A.1 Anticollision Summary Report Well B-24 - Slot B-24Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 71.0usftTVD Reference:Pikka FieldProject: Plan: Parker 272 @ 71.0usftMD Reference:ND-BReference Site: TrueNorth Reference:7.0 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-24Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore B-24 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDB-024 Rev A.1 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Combined Pedal Curve GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.0usft Unlimited Maximum centre distance of 2,000.3usft Plan: NDB-024 Rev A.1 Results Limited by: SigmaWarning Levels Evaluated at:2.79 Added to Error ValuesCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 12/07/2023 2_MWD_Interp Azi H002Mb: Interpolated azimuth47.0 300.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag300.0 1,800.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag300.0 3,360.0 Plan: NDB-024 Rev A.1 (B-24) SDI_KPR_ADK SDI Keeper ADK47.0 300.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag3,360.0 4,860.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag3,360.0 11,608.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag11,608.0 13,108.0 Plan: NDB-024 Rev A.1 (B-24) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,608.0 18,049.9 Plan: NDB-024 Rev A.1 (B-24) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance ND-B CCB-11 - Wellbore #1 - Rev A.0 450.0 449.0 259.5 251.7 33.351 ESB-11 - Wellbore #1 - Rev A.0 550.0 548.6 259.6 251.5 32.083 SFB-11 - Wellbore #1 - Rev A.0 850.0 843.5 280.4 271.0 29.775 CCB-12 - Wellbore #1 - Rev A.0 558.2 557.4 239.4 231.3 29.692 ESB-12 - Wellbore #1 - Rev A.0 575.0 574.2 239.4 231.3 29.496 SFB-12 - Wellbore #1 - Rev A.0 3,400.0 3,234.2 989.3 912.2 12.822 CCB-13 - Wellbore #1 - Rev A.0 612.6 614.9 218.4 210.1 26.351 ESB-13 - Wellbore #1 - Rev A.0 625.0 627.6 218.4 210.1 26.201 SFB-13 - Wellbore #1 - Rev A.0 3,400.0 3,374.4 756.7 674.7 9.236 CCB-14 - NDBi-014 - Plan: NDBi-014 Rev B.0 410.5 410.1 199.7 192.0 25.998 ESB-14 - NDBi-014 - Plan: NDBi-014 Rev B.0 450.0 449.3 199.7 191.9 25.648 SFB-14 - NDBi-014 - Plan: NDBi-014 Rev B.0 750.0 753.4 210.1 201.1 23.323 CCB-15 - Wellbore #1 - Rev A.0 686.0 690.3 176.2 167.7 20.651 ESB-15 - Wellbore #1 - Rev A.0 725.0 729.9 176.3 167.6 20.255 SFB-15 - Wellbore #1 - Rev A.0 3,400.0 3,355.2 631.0 547.8 7.579 CCB-16 - B-16 - Plan: B-16 Rev A.0 673.3 677.8 158.4 149.8 18.457 ESB-16 - B-16 - Plan: B-16 Rev A.0 725.0 731.1 158.5 149.7 17.996 SFB-16 - B-16 - Plan: B-16 Rev A.0 18,049.9 17,982.8 1,800.3 1,349.6 3.995 CCB-18 - B-18 - Plan: B-18 Rev A.0 416.7 415.7 119.7 112.0 15.547 ESB-18 - B-18 - Plan: B-18 Rev A.0 500.0 498.8 119.8 111.9 15.059 SFB-18 - B-18 - Plan: B-18 Rev A.0 12,793.7 13,051.9 1,801.1 1,471.4 5.462 CCB-19 - Wellbore #1 - Rev A.0 390.3 389.3 99.4 91.7 13.003 ESB-19 - Wellbore #1 - Rev A.0 450.0 448.8 99.5 91.6 12.701 SFB-19 - Wellbore #1 - Rev A.0 550.0 547.0 101.4 93.2 12.358 CCB-20 - Wellbore #1 - Rev A.0 328.4 327.4 79.3 71.8 10.547 ESB-20 - Wellbore #1 - Rev A.0 600.0 599.5 79.4 71.2 9.692 SFB-20 - Wellbore #1 - Rev A.0 18,049.9 17,811.0 1,817.7 1,365.3 4.019 CCB-21 - NDB-021 - Plan: NDB-021 Rev A.0 388.6 387.6 59.3 51.6 7.730 ESB-21 - NDB-021 - Plan: NDB-021 Rev A.0 450.0 448.8 59.4 51.5 7.532 SFB-21 - NDB-021 - Plan: NDB-021 Rev A.0 500.0 498.3 60.1 52.0 7.427 CCB-22 - Wellbore #1 - Rev A.0 560.9 560.0 39.3 31.2 4.865 Level 2, ES, SFB-22 - Wellbore #1 - Rev A.0 18,049.9 17,910.3 104.4 4.9 1.049 CCB-25 - NDB-025 - Plan: B-25 Rev A.0 350.0 349.0 20.2 12.7 2.669 ES, SFB-25 - NDB-025 - Plan: B-25 Rev A.0 375.0 374.0 20.2 12.6 2.659 12/07/2023 11:09:41AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 2 Anticollision Summary Report Well B-24 - Slot B-24Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 71.0usftTVD Reference:Pikka FieldProject: Plan: Parker 272 @ 71.0usftMD Reference:ND-BReference Site: TrueNorth Reference:7.0 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-24Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore B-24 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDB-024 Rev A.1 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance ND-B CCB-26 - Wellbore #1 - Rev A.0 570.3 568.5 40.8 32.7 5.050 ESB-26 - Wellbore #1 - Rev A.0 1,800.0 1,786.9 56.3 31.0 2.222 Level 3, SFB-26 - Wellbore #1 - Rev A.0 3,400.0 3,377.1 123.8 40.6 1.488 CCB-27 - Wellbore #1 - Rev A.0 547.2 546.3 60.9 52.8 7.584 ESB-27 - Wellbore #1 - Rev A.0 575.0 573.6 60.9 52.8 7.507 SFB-27 - Wellbore #1 - Rev A.0 3,400.0 3,331.4 370.0 283.5 4.275 CCB-28 - Wellbore #1 - Rev A.0 328.4 327.4 80.9 73.4 10.768 ESB-28 - Wellbore #1 - Rev A.0 400.0 398.9 80.9 73.3 10.632 SFB-28 - Wellbore #1 - Rev A.0 425.0 423.8 81.0 73.4 10.613 CCB-30 - B-30 - Plan: NDBi-030 Rev B.1 549.2 549.3 120.2 112.1 14.959 ESB-30 - B-30 - Plan: NDBi-030 Rev B.1 575.0 574.1 120.2 112.1 14.814 SFB-30 - B-30 - Plan: NDBi-030 Rev B.1 17,250.0 17,544.7 1,810.7 1,361.3 4.029 CCB-31 - B-31 - Plan: Rev A.0 350.0 349.0 141.0 133.5 18.674 ESB-31 - B-31 - Plan: Rev A.0 450.0 448.9 141.1 133.3 18.241 SFB-31 - B-31 - Plan: Rev A.0 550.0 547.9 141.8 133.9 18.026 Level 2, CC, ES, SFB-32 - NDB-032 - Plan: NDB-032 Rev B.0 11,480.0 12,323.0 84.2 9.2 1.123 CCB-33 - Wellbore #1 - Rev A.0 350.0 349.0 181.0 173.4 23.970 ESB-33 - Wellbore #1 - Rev A.0 425.0 423.9 181.0 173.3 23.552 SFB-33 - Wellbore #1 - Rev A.0 575.0 571.6 182.4 174.5 23.120 CCB-34 - Wellbore #1 - Rev A.0 547.1 546.4 201.0 193.0 25.046 ESB-34 - Wellbore #1 - Rev A.0 575.0 572.3 201.1 193.0 24.791 SFB-34 - Wellbore #1 - Rev A.0 3,400.0 3,159.9 723.2 641.6 8.866 CCB-36 - Wellbore #1 - Rev A.0 350.0 349.0 241.1 233.6 31.932 ESB-36 - Wellbore #1 - Rev A.0 475.0 473.9 241.2 233.4 30.931 SFB-36 - Wellbore #1 - Rev A.0 750.0 735.7 244.1 235.8 29.287 CCB-37 - B-37 - Plan: B-37 Rev A.0 546.9 546.1 242.2 234.2 30.175 ESB-37 - B-37 - Plan: B-37 Rev A.0 575.0 571.7 242.3 234.2 29.871 SFB-37 - B-37 - Plan: B-37 Rev A.0 3,400.0 3,013.8 972.3 896.7 12.869 12/07/2023 11:09:41AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 3 NDB-024 PTD 8.10.23 - 31 - 13-Jul-23 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# 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 ChokeLine fromBOP PressureGauge 1502PressureSensorPressureTransducer Bill ofMaterial Item Description To PanicLine Item Description A3Ͳ1/8”– 5,000psi W.P. RemoteHydraulic OperatedChoke B3Ͳ1/8”–5,000psiW.P. AdjustableManual Choke 1–14 3Ͳ1/8”– 5,000psi W.P. ManualGateValve 15 2 1/16”5 000 i WP152Ͳ1/16”–5,000psiW.P. ManualGateValve To MudGas Legend BlindSpare To TigerTankSeparatorValveNormally Open Valve Normally Closed NDB-024 PTD 8.10.23 - 35 - 13-Jul-23 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 (mud loggers, 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. Washouts/Hole Enlargement Drill with oil based mud, maintain mud in specifications, use sufficient mud weight to hold back formations. 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. Fault Crossing Planned fault crossing in the NT7/6 in the intermediate hole with medium risk of loss circulation. Treat losses if needed to ensure good cement job. 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. 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. Fault Crossing In reservoir fault crossing causing potential issue for staying in NDB-024 PTD 8.10.23 - 36 - 13-Jul-23 reservoir if fault throw is larger than anticipated. Mitigation includes landing deeper in the heel to minimize change of getting faulted out of zone after crossing fault. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. NDB-024 PTD 8.10.23 - 37 - 13-Jul-23 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. NDB-024 PTD 8.10.23 - 38 - 13-Jul-23 Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 BTC Surface Casing Basis Lead Open hole volume + 250% excess in permafrost / 40% excess below permafrost Lead TOC Surface Tail Open hole volume + 40% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Clean Spacer Lead 510 bbls, 2863 cuft, 1132 sks of 11.0 ppg ArcticCem, Yield: 2.53 cuft/sk Tail 65 bbls, 365 cuft, 294 sks 15.3 ppg 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 Intermediate Liner Cement – STAGE 1 Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess Lead TOC 250’ TVD above top Nanushuk Tail Open hole volume + 30% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 11.8 ppg Clean Spacer Lead 133 bbls, 318 cuft, 370 sks of 12.0 ppg ExtendaCem, Yield: 2.35 cuft/sk Tail 43 bbls, 241 cuft, 194 sks 15.3 ppg VersaCem Type I/II – 1.24 cuft/sk Temp BHST 94° F Verification Method LWD Sonic log Notes Job will be mixed on the fly Intermediate Liner Cement – STAGE 2 Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess + 150’ liner lap Lead TOC Top of the 9-5/8” Liner Tail Open hole volume + 30% excess Tail TOC 500 ft MD above Two Stage Cementing Stage Collar Total Cement Volume Spacer ~80 bbls of 11.8 ppg Clean Spacer Lead 253 bbls, 1420 cuft, 604 sks of 12.0 ppg ExtendaCem, Yield: 2.35 cuft/sk Tail 36 bbls, 202 cuft, 163 sks 15.3 ppg VersaCem Type I/II – 1.24 cuft/sk Temp BHST 74° F Verification Method Cement returns off top of liner Notes Job will be mixed on the fly verified calc -bjm 747 cuft, 318sks 2.35 yield per G. Staudinger -bjm Verified calc -bjm NDB-024 PTD 8.10.23 - 39 - 13-Jul-23 Attachment 7: Prognosed Formation Tops NDB-024 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1063 1048 -977 100 7.2 Permafrost Base 1453 1395 -1324 100 7.3 Middle Schrader Bluff 1905 1744 -1673 100 7.6 MCU (Lwr. Sch. Bluff) 2657 2147 -2076 100 7.8 Tuluvak Shale 3985 2463 -2392 100 7.9 Tuluvak Sand 4268 2526 -2455 100 10.1 Seabee 7168 3171 -3100 100 9.2 Nanushuk 10152 3835 -3764 100 8.9 NT6 MFS 10499 3912 -3841 100 8.9 NT5 MFS 10822 3984 -3913 100 8.8 NT4 MFS 11029 4030 -3959 100 8.8 NT3 MFS 11401 4116 -4045 100 8.8 NT 3.2 Top Reservoir (NT3) 11565 4160 -4089 100 8.7 NDB-024 PTD 8.10.23 - 40 - 13-Jul-23 Attachment 8: Well Schematic NDB-024 PTD 8.10.23 - 41 - 13-Jul-23 Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole LWD Gamma Ray Resistivity Density Neutron Cased Hole Wireline None 8-1/2” Production Hole LWD Gamma Ray Resistivity Sonic Density Neutron Ultra Deep Resistivity Mudlogging and Sample Program Mudlogging will be utilized from surface to TD on NDB-024. Dried cuttings samples will be collected at a maximum of 30 ft intervals from surface to TD. Cuttings sampling in the production section will be collected at 50 ft intervals. NDB-024 PTD 8.10.23 - 42 - 13-Jul-23 Attachment 10: Wellhead & Tree 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. 223-076 X PIKKA 50-ft (as per Attachment 9) Pikka NDB-024 NANUSHUK OIL -A.Dewhurst WELL PERMIT CHECKLIST Company Oil Search (Alaska), LLC Well Name:PIKKA NDB-024 Initial Class/Type DEV / PEND GeoArea 890 Unit 11580 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2230760 PIKKA, NANUSHUK OIL - 600100 NA1 Permit fee attached Yes ADL0392984, ADL0393020, ADL0391455, ADL0393018, ADL03914452 Lease number appropriate Yes3 Unique well name and number Yes Nanushuk Oil Pool – 600100 Pool Rules order currently in progress.4 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary NA6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 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 provided Yes19 Surface casing protects all known USDWs Yes20 CMT vol adequate to circulate on conductor & surf csg Yes21 CMT vol adequate to tie-in long string to surf csg Yes22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit NA25 If a re-drill, has a 10-403 for abandonment been approved Yes26 Adequate wellbore separation proposed Yes27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP = 1466 psi, BOP rated to 5k, (BOP test to 3500 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 shutdown No33 Is presence of H2S gas probable NA34 Mechanical condition of wells within AOR verified (For service well only) Yes H2S not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measures Yes Tuluvak sands are expected to be over-pressured (10 ppg) and likely gas-bearing.36 Data presented on potential overpressure zones NA37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr ADD Date 8/21/2023 Appr BJM Date 9/5/2023 Appr ADD Date 8/18/2023 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date 1 Dewhurst, Andrew D (OGC) From:Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent:Monday, August 21, 2023 16:02 To:Dewhurst, Andrew D (OGC); Staudinger, Garret (Garret) Cc:McLellan, Bryan J (OGC); Roby, David S (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC) Subject:RE: Pikka NDB-024 (PTD 223-076) Yesconfirmed.PleaseaddADL0391445toBox7oftheapplication. Thanks, Mark MarkStaudinger SeniorDrillingEngineer t:+1(907)375Ͳ4654|m:+1(520)273Ͳ6643|e:Mark.Staudinger@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Sent:Monday,August21,20233:18PM To:Staudinger,Mark(Mark)<Mark.Staudinger@santos.com>;Staudinger,Garret(Garret) <Garret.Staudinger@santos.com> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Roby,DavidS(OGC)<dave.roby@alaska.gov>;Davies, StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov> Subject:![EXT]:RE:PikkaNDBͲ024(PTD223Ͳ076) Mark, Thanks.Pleaseconfirmthefollowing:IwilladdleaseADL0391445toBox7oftheapplication. Andy From:Staudinger,Mark(Mark)<Mark.Staudinger@santos.com> Sent:Monday,August21,202311:26 To:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>; Roby,DavidS(OGC)<dave.roby@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD (OGC)<meredith.guhl@alaska.gov> Cc:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Subject:RE:PikkaNDBͲ024(PTD223Ͳ076) Youdon'toftengetemailfrommark.staudinger@santos.com.Learnwhythisisimportant You don't often get email from mark.staudinger@santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Andy, Garretisoutthisweek.Inresponsetoyourquestionsbelow,thecorrectKBandGLheightsarefromtheDirectional Plan: KB=71.0’ GL=24.0’ ApologiesontheincorrectnumbersontheForm401.Theywerepulledfromanoutdateddocument. I’veattachedaplatshowingthewellboreagainstleaseboundaries. Letmeknowifyouneedanythingelse. Thanks, Mark MarkStaudinger SeniorDrillingEngineer t:+1(907)375Ͳ4654|m:+1(520)273Ͳ6643|e:Mark.Staudinger@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Sent:Saturday,August19,20237:06AM To:Staudinger,Mark(Mark)<Mark.Staudinger@santos.com> Subject:Fwd:PikkaNDBͲ024(PTD223Ͳ076) CanyouhelpoutandrespondtoAndy'snotebelow?Thanksinadvanceforthehelp! Garret From:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Sent:Friday,August18,202311:02:34AM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Roby,DavidS(OGC)<dave.roby@alaska.gov>;Davies, StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov> Subject:![EXT]:PikkaNDBͲ024(PTD223Ͳ076) Garret, IamreviewingthePTDforNDBͲ024andIhavetwoquestions: x WouldyoupleaseconfirmthecorrectGLandKBheights?I’mseeing: KB=68.7'(onForm401) KB=71.0'(fromdirectionalplanandp.3) GL=22'(Form401) GL=24'(fromdirectionalplanandp.3) x Wouldyoupleasesendaplatshowingthewellboreagainsttheleaseboundaries? 3 Thanks, Andy AndrewDewhurst SeniorPetroleumGeologist AlaskaOilandGasConservationCommission 333W.7thAve,Anchorage,AK99501 andrew.dewhurst@alaska.gov Direct:(907)793Ͳ1245 CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservation Commission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation. Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail, pleasedeleteit,withoutfirstsavingorforwardingit,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactAndrewDewhurst at907Ͳ793Ͳ1245orandrew.dewhurst@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 (E"%EE(@2A7&;2<7E;2?:2EE&(EE77@E )E ECEE &>=974AE&' "12??=>A75E 2C=B@E&' "!1# 13B887>?E & ""E- E( E DE & ""E$)*$!E$ E &',$+( /E' E"%E- E " E &'$+)$"E")', E E .& $')$"E( E 6E $))$!E$ (E - E)')$'0E$)'E ! E+'E (")$(E ((E 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:Staudinger, Garret (Garret) To:McLellan, Bryan J (OGC) Subject:RE: NDB-024 minimum LOT value Date:Wednesday, August 30, 2023 12:28:28 PM Attachments:image001.jpg Intermediate will be a LOT, and we will stop at a FIT if it holds 17.0ppg. Production hole will be a LOT, but will stop at a FIT of 15.0ppg. Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, August 30, 2023 12:20 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Subject: ![EXT]: RE: NDB-024 minimum LOT value Thanks. I missed that. Are you planning to take both intermediate and production hole tests to Leakoff? 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, August 30, 2023 12:04 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDB-024 minimum LOT value Hey Bryan, Yup, should be included on page 5 of the PTD application. 12.3ppg LOT is needed for kick tolerance. Let me know if you have any questions. Thanks, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, August 30, 2023 11:59 AM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Subject: ![EXT]: NDB-024 minimum LOT value Garret, Have you determined a minimum LOT value required to drill your intermediate hole section? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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