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224-105
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 NDBi-016 50103208920000 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 NDBi-016 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 NDBi-016 50103208920000 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 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 ؐNDBi-016 Lithotrak Caliper data 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 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, December 13, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Oil Search (Alaska), LLC NDBi-016 PIKKA NDBi-016 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 12/13/2024 NDBi-016 50-103-20892-00-00 224-105-0 N SPT 4042 2241050 1500 3087 3758 3763 3765 0 0 0 0 OTHER P Adam Earl 10/12/2024 Pre frac MIT IA 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PIKKA NDBi-016 Inspection Date: Tubing OA Packer Depth 420 4496 4450 4434IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE241014124432 BBL Pumped:9.9 BBL Returned:9.8 Friday, December 13, 2024 Page 1 of 1 9 9 9 9 99 999 9 9 9 99 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.12.13 14:52:52 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Well Cleanup Oil Search Alaska, LLC Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 18,625 feet N/A feet true vertical 4,092 feet N/A feet Effective Depth measured 18,030 feet See attached rpt feet true vertical 4,122 feet See attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" P-110S 12,700' 4,041' Packers and SSSV (type, measured and true vertical depth) See attached packer report 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Scott Leahy Contact Email:scott.leahy@santos.com Authorized Title: Completions Specialist Contact Phone: 907-330-4595 324-556 Sr Pet Eng: 9,210 Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 3121 Gas-Mcf MD 128' See attached report 0 Size 128' 2,375' 1101 01230 0 00 278 Tieback 11,590 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-105 50-103-20892-00-00 601 W 5th Avenue Anchorage, AK 99501 3. Address: N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 393016, 393020, 391455, 393018, 393010 Pikka / Nanushuk Oil Pool Pikka NDBi-016 Plugs Junk measured See attached report Length 128' 2,759' 10,206' 2,759'Conductor Surface Intermediate 20"x34" 13-3/8" 9-5/8" measured TVD Production Liner 2,609' 12,700' 5,203' Casing Structural 2,302' 4,041' 4-1/2" 2,609' 12,700' 18,030' 4,122' 4,750 9,210 5,020 6,870 6,870 11,590 12,855' 4,065' Burst Collapse 2,260 4,750 p k ft t Fra O s 224 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov S i li 12/10/2024 By Grace Christianson at 11:49 am, Dec 10, 2024 Page 1 of 1 Packer Set Depths - NDBi-016 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole SLZXP Liner Top Hanger Packer w/centralizer 12,690.2 4,039.8 Original Hole HES Zoneguard OH Packer #15 13,040.0 4,094.6 Original Hole HES Zoneguard OH Packer #14 13,107.6 4,104.5 Original Hole HES Zoneguard OH Packer #13 13,487.0 4,126.8 Original Hole HES Zoneguard OH Packer #12 13,989.2 4,127.2 Original Hole HES Zoneguard OH Packer #11 14,531.3 4,127.0 Original Hole HES Zoneguard OH Packer #10 14,990.1 4,127.8 Original Hole HES Zoneguard OH Packer #9 15,409.1 4,122.2 Original Hole HES Zoneguard OH Packer #8 15,517.8 4,122.1 Original Hole HES Zoneguard OH Packer #7 15,749.1 4,122.2 Original Hole HES Zoneguard OH Packer #6 15,856.0 4,122.2 Original Hole HES Zoneguard OH Packer #5 16,272.5 4,122.1 Original Hole HES Zoneguard OH Packer #4 16,894.0 4,122.0 Original Hole HES Zoneguard OH Packer #3 17,395.4 4,122.0 Original Hole HES Zoneguard OH Packer #2 17,730.2 4,121.9 Original Hole HES Zoneguard OH Packer #1 17,838.3 4,121.9 Frac Ops Summary Report - AOGCC Well Name NDBi-016 Primary Job Type Fracture Treatment Start Date End Date Summary 10/23/2024 10/24/2024 Install Ball Launcher. RU Frac Treating Lines to Goat Head. Load Proppant. Fill and Heat Frac Tanks. 10/24/2024 10/25/2024 Perform Lab Testing. Continue to Prep for Stages 1-5 10/25/2024 10/26/2024 Wait on Flowback Operations 10/26/2024 10/27/2024 Wait on Flowback Operations 10/27/2024 10/28/2024 Wait on Flowback Operations. Prime Up and Pressure Test. 10/28/2024 10/29/2024 Frac Stages 1-5 Finish RU of Frac equipment, prime up, pressure test. Pump Freeze Protect fluid past wellhead with 40 bbls WF125. Pump Check with 240 bbls WF125 DataFrac: 250 bbls WF125ST Fluid at 40bpm. Frac Stage 1: 1,757 bbls slurry (YF125ST fluid), 221,814 lbs 16/20 CarboLite (1, 2, 4, 6, 8, 9ppa), 1,522 bbls clean fluid at 40bpm, Comments: Changed final step from 10ppa to 9ppa due to Net Pressure. Frac Stage 2: 1,977 bbls slurry (YF125ST fluid), 21,344 lbs 40/70 CarboLite (1, 3ppa), 227,461 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,714 bbls clean fluid at 40bpm, Comments: Added a 1ppa and 3ppa Scour. Frac Stage 3: 1,625 bbls slurry (YF125ST fluid), 243,257 lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,368 bbls clean fluid at 40bpm, Comments: As per design. Frac Stage 4: 1,917 bbls slurry (YF125ST fluid), 15,570 lbs 40/70 CarboLite (1, 3ppa), 235,691 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,651 bbls clean fluid at 40bpm, Comments: As per design. Frac Stage 5: 2,253 bbls slurry (YF125ST fluid), 15,618 lbs 40/70 CarboLite (1, 3ppa), 229,525 lbs 16/20 CarboLite (1, 3, 5, 7, 9, 10ppa), 1,994 bbls clean fluid at 40bpm, Comments: Added a 1ppa and 3ppa Scour. TLTR (Stages 1-5) 8,779 bbls 10/29/2024 10/30/2024 Fill and Heat Frac Tanks. Perform Equipment Maintenance. 10/30/2024 10/31/2024 Continue to Heat and Fill Frac Tanks. 10/31/2024 11/1/2024 RU Remaining Equipment for Frac Page 1 of 2 Frac Ops Summary Report - AOGCC Start Date End Date Summary 11/1/2024 11/2/2024 Frac Stages 6-9 Finish RU of Frac equipment, prime up, pressure test. Pump Freeze Protect fluid past wellhead with 40 bbls WF125ST. Drop Ball and Pump Down with 226 bbls of WF125ST. Pump Check with 100 bbls WF125ST. Frac Stage 6: 1,647 bbls slurry (YF125ST fluid), 15,601 lbs 40/70 CarboLite (1, 3ppa), 161,020 lbs 16/20 Carbolite (1, 2, 4, 6, 8ppa), 1,460 bbls clean fluid at 40bpm, Comments: Cut prop after 8ppa due to gel mixing and prop delivery problems. Frac Stage 7: 1,893 bbls slurry (YF125ST fluid), 16,127 lbs 40/70 CarboLite (1, 3ppa), 228,253 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,635 bbls clean fluid at 40bpm, Comments: As per design. Frac Stage 8: 1,853 bbls slurry (YF125ST fluid), 15,020 lbs 40/70 CarboLite (1, 3ppa), 227,056 lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,597 bbls clean fluid at 40bpm, Comments: As per design. Frac Stage 9: 1,838 bbls slurry (YF125ST fluid), 257,068 lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,567bbls clean fluid at 40bpm, Comments: As per design. Pump 45 bbls Freeze Protect. TLTR (Stages 6-9) 6,585 bbls TLTR (Total for Well) 15,364 bbls 11/2/2024 11/3/2024 RD Frac Treating Lines. RD Cameron Ball Launcher. Install Tree Cap and Secure Well. Page 2 of 2 Flowback Ops Summary Report - AOGCC Well Name NDBi-016 Primary Job Type Flowback/Testing Start Date End Date Summary 11/6/2024 11/7/2024 Wait on weather and open up well for Well Clean-up operations as per procedure. 11/7/2024 11/8/2024 Continue to flow well as per Well Clean-up procedure on Choke 128/64" 11/8/2024 11/9/2024 Continue to flow well as per Well Clean-up procedure on Choke 128/64" 11/9/2024 11/10/2024 Continue to flow well as per Well Clean-up procedure on Choke 128/64" 11/10/2024 11/11/2024 Continue to flow well as per Well Clean-up procedure on Choke 128/64" Perform step-down rate on choke 52/64" for 5hrs and choke 44/64" for 5hrs. Performed hard shutdown at midnight. 11/11/2024 11/12/2024 Complete injection of flowback fluid into NDBi-014. Flush and Freeze protect NDBi-014. Rig down and stage Flowback equipment in preparation for NDB-025 Page 1 of 1 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 5.0 gal F103 Surfactant 1.0 Gal/mGal 658.0 gal J450 Stabilizing Agent 0.6 Gal/mGal 355.0 gal J475 Breaker J475 6.0 lb/mGal 3,847.2 lbm J511 Stabilizing Agent 1.8 lb/mGal 1,158.0 lbm J532 Crosslinker 2.3 Gal/mGal 1,494.0 gal J580 Gel J580 27.2 lb/mGal 17,387.5 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 46.6 gal M002 Additive 0.0 lb/mGal 1.0 lbm M117 Clay Control Agent 356.4 lb/mGal 228,007.3 lbm M275 Bactericide 0.3 lb/mGal 209.1 lbm S522-1620 Propping Agent varied concentrations 2,135,184.0 lbm S522-4070 Propping Agent varied concentrations 99,962.0 lbm 67.51205 % 29.06480 % 2.87595 % 0.22553 % 0.08895 % 0.04453 % 0.04002 % 0.03938 % 0.03215 % 0.01506 % 0.01338 % 0.01338 % 0.01229 % 0.00951 % 0.00667 % 0.00192 % 0.00136 % 0.00107 % 0.00057 % 0.00027 % 0.00026 % 0.00025 % 0.00025 % 0.00016 % 0.00014 % 0.00009 % 0.00005 % 0.00005 % 0.00004 % 0.00003 % 0.00003 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % 100 % * 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. 7632-00-0 Sodium nitrite 2634-33-5 1,2-benzisothiazolin-3-one Total 9004-32-4 Sodium carboxymethylcellulose 11138-66-2 Xanthan Gum 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9005-65-6 Sorbitan monooleate, ethoxylated 64-19-7 Acetic acid (impurity) 68308-89-4 Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 36089-45-9 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-propenoate 1310-73-2 Sodium hydroxide 1338-41-6 Sorbitan stearate 532-32-1 Sodium benzoate 127-08-2 Acetic acid, potassium salt (impurity) 14808-60-7 Quartz, Crystalline silica 14464-46-1 Cristobalite 63148-62-9 Dimethyl siloxanes and silicones 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 9000-90-2 Amylase, alpha 14807-96-6 Magnesium silicate hydrate (talc) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 10377-60-3 Magnesium nitrate 111-42-2 2,2'-Iminodiethanol 9002-84-0 poly(tetrafluoroethylene) 91053-39-3 Diatomaceous earth, calcined 112-42-5 1-undecanol (impurity) 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 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 50-70-4 Sorbitol 7647-14-5 Sodium chloride 102-71-6 2,2`,2"-nitrilotriethanol 7727-54-0 Diammonium peroxodisulphate 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF125ST:WF125 639,705 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-1974 Fluid Name & Volume Concentration Volume Disclosure Type: Post-Job Well Completed: Date Prepared: 11/14/2024 State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDBi-016 Basin/Field: Pikka Page: 1 / 1 Updated 11/20/2024INPUTOct-28-2024AK TSCA StatusNorth SlopeTBDPost622,11873.00000%7,690,215Trade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SME Tracerco Carrier Fluid Soy Methyl Ester 67784-80-9 100 0.0009259718 71.2092260000T-758 Tracerco Chemical Tracer 3,4-Difluorobenzophenone 85118-07-6 100 0.0000057336 0.4409240000T-729 Tracerco Chemical Tracer 1,4-Dibromo-2,5-dimethyl benzene 1074-24-4 100 0.0000286679 2.2046200000T-716 Tracerco Chemical Tracer 1,3,5-Tribromobenzene 626-39-1 100 0.0000057336 0.4409240000T-731 Tracerco Chemical Tracer 1-Bromo-3,5-dichlorobenzene 19752-55-7 100 0.0000057336 0.4409240000T-164C Tracerco Chemical Tracer 1-Iodonaphthalene 90-14-2 100 0.0000057336 0.4409240000T-784 Tracerco Chemical Tracer 2,4,6-Tribromoanisole 607-99-8 100 0.0000057336 0.4409240000T-168A Tracerco Chemical Tracer 1-Chloro-4-iodobenzene 637-87-6 100 0.0000057336 0.4409240000T-718 Tracerco Chemical Tracer 4-Chlorobenzophenone 134-85-0 100 0.0000086004 0.6613860000T-750 Tracerco Chemical Tracer 1,4-Dibromo-2-fluorobenzene 1435-52-5 100 0.0000057336 0.4409240000Water Tracerco Carrier Fluid Water 7732-18-5 100 0.0007625651 58.6428920000T-158c Tracerco Chemical Tracer Sodium-2,6-Difluorobenzoate 6185-28-0 100 0.0000100338 0.7716170000T-805 Tracerco Chemical Tracer Sodium-2,4-Dichlorobenzoate 38402-11-8 100 0.0000100338 0.7716170000T-920 Tracerco Chemical Tracer Sodium-5-chloro-2-fluorobenzoate 1382106-78-6 100 0.0000100338 0.7716170000T-176a Tracerco Chemical Tracer Sodium-2,3,4-trifluorobenzoate 402955-41-3 100 0.0000100338 0.7716170000T-803 Tracerco Chemical Tracer Sodium-4-chlorobenzoate 3686-66-6 100 0.0000100338 0.7716170000T-257a Tracerco Chemical Tracer Sodium-3,5-di(Trifluoromethyl)benzoate 87441-96-1 100 0.0000100338 0.7716170000T-801 Tracerco Chemical Tracer Sodium-2-chlorobenzoate 17264-74-3 100 0.0000100338 0.7716170000T-926 Tracerco Chemical Tracer Sodium-4-chloro-3-methylbenzoate 1431868-21-1 100 0.0000100338 0.7716170000T-912 Tracerco Chemical Tracer Sodium-2-chloro-5-fluorobenzoate 1382106-79-7 100 0.0000100338 0.7716170000County:API Number:Operator Name: Santos AKWell Name and Number: NDBi-016Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco FracCAT Treatment Report Well : NDBi-016 Stages 1-5 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : October 28, 2024 Prepared by Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure (All Zones) Initial Wellhead Pressure (psi) 70 Initial BHP at Gauge (psi) 1,954 Final Surface ISIP (psi) 973 Final ISIP at Gauge (psi) 2,763 Surface Shut in Pressure(psi) 3,141 BH Shut in Pressure (psi) 3,191 Maximum Treating Pressure (psi) 7,863 BH Gauge at 12,573 ft MD, 4,022 ft TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 10,057.4 Total Proppant Pumped (lb) (per Load Tickets) 1,227,380 Total YF125ST Past Wellhead (bb) 7,785.0 Total Proppant in Formation (lb) 1,227,380 Total WF125 Past Wellhead (bbl) 981.5 Total S522 - 16/20 CarboLite per Load Tickets (lb) 1,181,420 Total Freeze Protect Past Wellhead (bbl) 11.0 Total S522 - 40/70 CarboLite per Load Tickets (lb) 45,960 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 371 371 M275 (lb) 132.0 132.9 J450 (gal) 199 199 J753 (gal) 37.1 29.10 J580 (lb) 10,527 10,515.5 J475 (lb) 2200 2197.2 J532 (gal) 833 833 J134 (lb) 0 0 J511 (lb) 720 654 D206 (gal) 3 3 M002 (lbs) 0.5 0.48 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. Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Summary On October 28, 2024, SLB successfully performed a hydraulic fracturing treatment on Stages 1-5 of NDBi-016. The initial design called for the completion of stages 1-5, with total of 1,164,745lbs of proppant in 9,408bbl of slurry. By physical load cell count on SAHARA #10, a total of 1,227,380 pounds of proppant was pumped and 1,227,380 was placed into formation in 10,057.4 bbl of slurry. Stage 1 consisted of a PAD, and 6 proppant steps 1-2-4-6-8-9 PPA; Stages 2 and 4 consisted of a PAD, Scour steps 1-3 PPA 40/70 CarboLite and 6 proppant steps 1-2-4-6-8-10 PPA; Stages 3 consisted of a PAD, and 6 proppant steps 1-3-5-7-9-10 PPA. Stage 5 consisted of a PAD, Scour steps 1-3 PPA 40/70 CarboLite and 6 proppant steps 1-3-5-7-9-10 PPA. Pump trips were staggered from 7,600 to 8,200 psi. The GORV was set to 8,500 psi. Summary of Stages 1-5 Material Actual Design Slurry Volume (bbl)10,057.4 9,408 Clean Fluid Volume(bbl) 8,766.5 8,123 Proppant (lb) 1,227,380 1,164,745 09:35:31 10:17:11 10:58:51 11:40:31 12:22:11 13:03:51 13:45:31 14:27:11 15:08:51 15:50:31 16:32:11 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-018 Stg 1-5 10-27-2024 0 Stage 4Stage 3Stage 2Stage 1DFITPump Check Displ PT Santos NDBi-016 Stg 1-5 10-28-2024 Stage 5 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Displacement PT, Pump Check, DFIT. P-Sleeve was activated on October 28th at surface pressure 7,863 psi with Freeze protect fluid. Then Frac crew performed PT displacementfollowed by 10min,Pump Check followed by 30min SD and DFIT test followed by 60min SD. A summary of the stage and pressures as follows: Summary of Stage Displacement PT, Pump Check and DFIT Total Proppant Pumped (lb) 0 Max pumping Rate (bpm) 40.1 Total Proppant in Formation (lb) 0 Average Pumping Rate (bpm) 24.9 Total Slurry Pumped (bbl) 529.0 Maximum Treating Pressure (psi) 7,863 YF125ST Pumped (bbl) 0 Average Treating Pressure (psi) 3,754 WF125 Pumped (bbl) 518.0 Average Water Temperature (F) 85.4 Freeze Protect (bbl) displaced downhole 11.0 Average Viscosity (cP) 20.5 09:35:31 09:47:11 09:58:51 10:10:31 10:22:11 10:33:51 10:45:31 10:57:11 11:08:51 11:20:31 11:32:11 11:43:51 11:55:31 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-018 Displacement PT, Pump Check, DFIT 10-27-2024 PT Displ Pump Check DFIT Santos NDBi-016 Displacement PT, Pump Check, DFIT 10-28-2024 0 P-Sleeve activation Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displacem ent PT 11.0 3.9 2.8 FP 462 0 0 0 2 Displacem ent PT 29.7 3.9 7.8 WF125 1247 0 0 0 3 Pump Check 240 33.6 8 WF125 10079 0 0 0 4 DFIT 248.3 37.3 7.3 WF125 10428 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1,2 Displacement PT 3.9 4.3 1723 7863 74 3 Pump Check 33.6 40.1 5594 6788 523 4 DFIT 37.3 40 3946 4374 616 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 7:21:52 Priming Pumps 46 0 0.0 4.0 0.0 2 7:51:44 Tested Pump Trips 1274 0 0.0 0.0 0.0 3 7:52:57 Mid Pressure Test 5120 1 0.0 0.0 0.0 4 7:57:29 Mixing 25# Gel 7829 0 0.0 0.0 0.0 5 7:58:07 High Pressure Test 9570 0 0.0 0.0 0.0 6 8:04:18 Good Test 8931 0 0.0 0.0 0.0 7 9:26:07 Safety Meeting @ 9 AM Completed 1223 200 0.0 0.0 0.0 8 9:26:47 Radio Check 1221 199 0.0 0.0 0.0 9 9:40:29 Open Well 67 200 0.0 0.0 0.0 10 9:42:28 LRS Pressuring Up IA To 3,000 PSI 69 201 0.0 0.0 0.0 11 9:53:03 Start Displacement Automatically 74 3376 0.0 0.0 0.0 12 9:53:03 Start P-Sleeve Automatically 74 3376 0.0 0.0 0.0 13 9:53:32 Started Pumping 74 3371 0.0 0.0 0.0 14 9:55:25 Toe Sleeve shifted 4541 3576 6.4 4.1 0.0 15 10:04:17 Stopped Pumping 967 3576 40.7 2.4 0.0 16 10:04:28 SD for 5 min 848 3574 40.7 0.0 0.0 17 10:15:06 Started Pumping 464 3589 40.7 0.0 0.0 18 10:15:08 Start Pump Check Manually 465 3589 40.7 0.0 0.0 19 10:23:08 Stopped Pumping 146 3522 280.9 14.0 0.0 20 10:23:43 SD for 30 min 863 3606 280.9 0.0 0.0 21 10:52:42 Started Pumping 463 3621 280.9 0.0 0.0 22 10:52:54 Start DFIT Manually 645 3641 280.9 2.0 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 23 10:53:30 Stage at Perfs: Displacement PT 2052 3715 284.7 13.1 0.0 24 10:55:06 Stage at Perfs: Pump Check 4382 3748 326.1 37.4 0.0 25 12:00:25 Radio Check 596 3538 529.5 0.0 0.0 26 12:04:05 Ball/Collet#1 is loaded to Ball Launcher 583 3528 529.5 0.0 0.0 27 12:08:07 Started Pumping 568 3517 529.5 0.0 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Stage 1 When the rate was slowed to 18 bpm there was clear indication that Ball/Collet#1 was seated. The treating pressure on PAD was around 3,970psi before the Collet/Ball#1 shifted the sleeve. Then treating pressure on PAD was around 3,450psiand stayed stable until 2 PPA was started entering the formation. Since that moment, pressure was gradually increased from 3,450 to 5,949 psi. Due to change of pressure trend behavior, concentration of last proppant step was decreased from 10 PPA to 9PPA. Slurry rate remained steady at 40bpm until it was slowed down for the Collet/Ball#2 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #1 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,639 3,165 2,622 Bottomhole Pressure 3,491 3,843 3,433 Summary of Stage 1 Total Proppant Pumped (lb) 226,349 Max pumping Rate (bpm) 40.6 Total Proppant in Formation (lb) 226,349 Average Pumping Rate (bpm) 34.2 CarboLite 40/70 (lb) per Load Tickets 0 Maximum Treating Pressure (psi) 5,949 CarboLite 16/20 (lb) per Load Tickets 226,349 Average Treating Pressure (psi) 3,870 Total Slurry Pumped (bbl) 1,756.4 Average Water Temperature (F) 81.0 YF125ST Pumped (bbl) 1,521.6 Average Viscosity (cP) 20.6 WF125 Pumped (bbl) 0 12:02:04 12:10:24 12:18:44 12:27:04 12:35:24 12:43:44 12:52:04 13:00:24 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-016 Stage 1 10-28-2024 Collet/Ball#1 hit the sleeve Drop Rate for Ball/Collet#1 Collet/Ball#2 hit the sleeve Drop Rate for Ball/Collet#2 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step #Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Line out XL 60.3 19.6 3.9 YF125ST 2533 0 0 0 2 Drop Collet#1 3 20 0.1 YF125ST 126 0 0 0 3 PAD st1 237.8 38.4 6.3 YF125ST 9982 0 0 0 4 Slow For Seat 51.1 21.1 2.7 YF125ST 2146 0 0 0 5 Resume Pad 16.9 27 0.6 YF125ST 705 0 0 0 6 1.0 PPA 190 39.6 4.8 YF125ST 7656 CarboLite 16/20 1 0.9 7370 7 2.0 PPA 220 39.7 5.5 YF125ST 8557 CarboLite 16/20 2.1 1.8 15698 8 4.0 PPA 240 39.7 6 YF125ST 8637 CarboLite 16/20 4.1 3.8 33123 9 6.0 PPA 240 39.7 6 YF125ST 7979 CarboLite 16/20 6.2 5.9 48275 10 8.0 PPA 239.6 39.8 6 YF125ST 7440 CarboLite 16/20 8.3 7.9 60250 11 9.0 PPA 224.2 39.8 5.6 YF125ST 6746 CarboLite 16/20 9.4 9 61633 12 Clear Lines & Spacer 30.5 39.8 0.8 YF125ST 1276 0 0 0 13 Drop Collet#2 3 39.8 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Line out XL 19.6 39.7 2276 2715 602 2 Drop Collet#1 20 20 2427 2489 2411 3 PAD st1 38.4 40 3973 4166 2400 4 Slow For Seat 21.1 39.9 2620 4102 1893 5 Resume Pad 27 34.5 3344 3565 2530 6 1.0 PPA 39.6 39.9 3601 3701 3430 7 2.0 PPA 39.7 39.8 3502 3607 3473 8 4.0 PPA 39.7 39.9 3514 3580 3467 9 6.0 PPA 39.7 39.9 3751 4005 3578 10 8.0 PPA 39.8 40.2 4598 5127 4009 11 9.0 PPA 39.8 40.3 5643 5926 5128 12 Clear Lines & Spacer 39.8 40.6 5531 5949 5362 13 Drop Collet#2 39.8 39.8 5534 5550 5526 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 12:08:07 Started Pumping 568 3517 529.5 0.0 0.0 2 12:08:09 Start Line out XL Manually 569 3517 529.5 0.0 0.0 3 12:08:09 Start Stage1 Automatically 569 3517 529.5 0.0 0.0 4 12:10:48 Stage at Perfs: DFIT 2382 3597 36.2 20.5 0.0 5 12:10:57 XL sample is good 2281 3595 39.3 20.6 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 6 12:12:11 Start Drop Collet#1 Manually 2381 3627 60.6 20.1 0.0 7 12:12:20 Start PAD st1 Manually 2534 3629 63.6 20.0 0.0 8 12:18:15 Stage at Perfs: XL tub Flush 4106 3703 285.7 40.0 0.0 9 12:18:39 Start Slow For Seat Automatically 3286 3670 301.6 39.9 0.0 10 12:20:01 Collet#1 Hit the Sleeve 2727 3654 329.2 18.0 0.0 11 12:20:36 Stage at Perfs: Drop Collet#1 2617 3655 339.7 18.0 0.0 12 12:20:46 Stage at Perfs: PAD st1 2554 3691 342.7 18.0 0.0 13 12:21:18 Start Resume Pad Manually 2520 3673 352.3 18.0 0.0 14 12:21:55 Start 1.0 PPA Manually 3646 3762 369.4 36.3 0.0 15 12:21:55 Started Pumping Prop 3646 3762 369.4 36.3 0.0 16 12:26:43 Start 2.0 PPA Automatically 3607 3729 559.9 39.9 1.0 17 12:27:15 Stage at Perfs: PAD st1 3584 3743 581.1 39.6 2.0 18 12:28:32 Stage at Perfs: Slow For Seat 3474 3766 632.0 39.6 1.7 19 12:28:57 Stage at Perfs: Resume Pad 3461 3761 648.6 39.7 1.8 20 12:32:15 Start 4.0 PPA Automatically 3475 3718 779.4 39.6 1.8 21 12:33:46 Stage at Perfs: 1.0 PPA 3496 3749 839.6 39.7 4.0 22 12:38:18 Start 6.0 PPA Automatically 3584 3697 1019.9 39.8 4.0 23 12:39:17 Stage at Perfs: 2.0 PPA 3646 3710 1058.8 39.8 5.8 24 12:44:20 Start 8.0 PPA Automatically 4025 3759 1259.5 39.5 5.9 25 12:45:21 Stage at Perfs: 4.0 PPA 4274 3724 1299.6 40.2 8.2 26 12:50:21 Start 9.0 PPA Manually 5128 3728 1499.0 40.0 7.9 27 12:50:31 9 ppa requested instead of 10ppa 5155 3729 1505.6 39.7 8.8 28 12:51:22 Stage at Perfs: 6.0 PPA 5480 3744 1539.2 39.8 8.9 29 12:55:59 Start Clear Lines & Spacer Manually 5906 3682 1723.2 40.6 2.9 30 12:56:01 Stopped Pumping Prop 5824 3674 1724.5 40.7 1.5 31 12:56:45 Start Drop Collet#2 Manually 5555 3668 1753.7 39.8 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Stage 2 Once the Collet/Ball#2 shifted the sleeve the pressure transition from Stage 1 to 2 was atypical. Consequently, the decision was made to continue pumping at a Rate of 18 bpm to wait when pressure fell and pump Scour 1-3 PPA 40/70 CarboLite before continuing with the planned design schedule. The treating pressure on PAD was around 4,860 psi. The pressure then slowly decreased to 3,330 psi while 1-3PPA Scour 40/70 Carbolite was going into the formation. While pumping 1-3 PPA Scour step the frozen chunks of sand were observed and affected the rate and pressure while were passing the pumps. After that, the pressure was gradually increasing from 3,330 to 6,044 psi. Slurry rate remained steady at 40bpm until it was slowed down for the Collet/Ball#3 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #2 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,513 4,165 5,545 Bottomhole Pressure 3,278 4,471 6,293 Summary of Stage 2 Total Proppant Pumped (lb) 250,787 Max pumping Rate (bpm) 41.0 Total Proppant in Formation (lb) 250,787 Average Pumping Rate (bpm) 36.8 CarboLite 40/70 (lb) per Load Tickets 18,674 Maximum Treating Pressure (psi) 6,044 CarboLite 16/20 (lb) per Load Tickets 232,113 Average Treating Pressure (psi) 4,152 Total Slurry Pumped (bbl) 1,976.7 Average Water Temperature (F) 79.9 YF125ST Pumped (bbl) 1,713.9 Average Viscosity (cP) 20.9 WF125 Pumped (bbl) 0 13:02:39 13:10:59 13:19:19 13:27:39 13:35:59 13:44:19 13:52:39 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-016 Stage 2 10-28-2024 0 Drop Rate for Ball/Collet#3 Collet/Ball#3 hit the sleeve Drop Rate for Ball/Collet#2 Collet/Ball#2 hit the sleeve Frozen sand passed through pumps Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st2 230 39.9 5.8 YF125ST 9660 0 0 0 2 Slow For Seat 61.7 20.7 3.2 YF125ST 2600 0 0 0 3 Resume Pad 7.6 20.8 0.4 YF125ST 323 0 0 0 4 1.0 PPA Scour 60.6 36.7 1.7 YF125ST 2446 CarboLite 40/70 1 0.8 1780 5 3.0 PPA Scour 181.6 39.8 4.6 YF125ST 6773 CarboLite 40/70 3.1 2.9 16894 6 Resume Pad 50 39.5 1.3 YF125ST 2098 0 0 0 7 1.0 PPA 190 39.9 4.8 YF125ST 7659 CarboLite 16/20 1.1 0.9 7344 8 2.0 PPA 220 39.7 5.5 YF125ST 8502 CarboLite 16/20 2.1 2 16941 9 4.0 PPA 240 39.8 6 YF125ST 8581 CarboLite 16/20 4.1 3.9 34417 10 6.0 PPA 240 39.8 6 YF125ST 7981 CarboLite 16/20 6.2 5.9 48229 11 8.0 PPA 240 39.7 6 YF125ST 7457 CarboLite 16/20 8.4 7.9 60285 12 10.0 PPA 220.4 39.7 5.5 YF125ST 6445 CarboLite 16/20 10.1 9.9 64897 13 Clear Lines & Spacer 31.8 39.8 0.8 YF125ST 1331 0 0 0 14 Drop Collet#3 3 39.5 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st2 39.9 40.0 4861 5762 3786 2 Slow For Seat 20.7 40.0 3451 5484 1672 3 Resume Pad 20.8 25.1 3978 4253 3680 4 1.0 PPA Scour 36.7 39.9 3935 4477 3485 5 3.0 PPA Scour 39.8 40.0 3486 3508 3449 6 Resume Pad 39.5 40.2 3450 3578 3315 7 1.0 PPA 39.9 40.9 3536 3749 3422 8 2.0 PPA 39.7 40.1 3375 3423 3348 9 4.0 PPA 39.8 40.1 3455 3553 3393 10 6.0 PPA 39.8 40.0 3687 3862 3553 11 8.0 PPA 39.7 40.4 4263 4728 3857 12 10.0 PPA 39.7 40.1 5461 5992 4734 13 Clear Lines & Spacer 39.8 41.0 5625 6044 5408 14 Drop Collet#3 39.5 39.6 5567 5583 5546 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 12:56:50 Start PAD st2 Automatically 5657 3668 0.0 39.9 0.0 2 12:56:50 Start Propped Frac Automatically 5657 3668 0.0 39.9 0.0 3 12:56:50 Start Stage2 Automatically 5657 3668 0.0 39.9 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 4 12:57:22 Stage at Perfs: 10.0 PPA 5607 3674 21.2 39.8 0.0 5 13:02:36 Start Slow For Seat Automatically 3373 3660 230.2 40.1 0.0 6 13:03:15 Stage at Perfs: Clear Lines & Spacer 2335 3625 245.3 17.9 0.0 7 13:04:06 Collet#2 Hit the Sleeve 2833 3659 260.5 17.8 0.0 8 13:04:58 Stage at Perfs: Drop Collet#2 4602 3735 275.8 17.8 0.0 9 13:05:09 Stage at Perfs: PAD st2 4585 3728 279.1 17.7 0.0 10 13:05:50 Start Resume Pad Manually 3756 3680 291.2 17.8 0.0 11 13:06:12 Start 1.0 PPA Scour Manually 4201 3703 299.5 27.4 0.0 12 13:06:12 Started Pumping Prop 4201 3703 299.5 27.4 0.0 13 13:06:42 1 ppa scour 40-70 4239 3711 315.3 34.8 1.0 14 13:07:50 Start 3.0 PPA Scour Manually 3465 3692 359.7 39.9 1.0 15 13:08:01 3 ppa scour 40-70 3462 3699 367.0 39.9 1.2 16 13:11:25 Stage at Perfs: Resume PAD 3508 3718 502.1 39.9 3.0 17 13:12:24 Start Resume Pad Manually 3449 3725 541.3 39.9 0.5 18 13:12:26 Stopped Pumping Prop 3446 3724 542.6 40.3 0.4 19 13:13:09 Stage at Perfs: 1.0 PPA Scour 3497 3723 571.1 38.4 0.0 20 13:13:40 Start 1.0 PPA Manually 3635 3742 591.3 39.7 0.0 21 13:13:42 Started Pumping Prop 3547 3740 592.6 39.7 0.0 22 13:14:41 Stage at Perfs: 3.0 PPA Scour 3587 3744 631.6 40.9 0.9 23 13:18:26 Start 2.0 PPA Automatically 3428 3692 781.7 40.1 1.0 24 13:19:13 Stage at Perfs: Resume PAD 3387 3697 812.9 39.5 2.0 25 13:20:29 Stage at Perfs: 1.0 PPA 3357 3704 863.1 39.7 2.0 26 13:21:26 Ball/Collet#3 is loaded to Ball Launcher 3365 3708 900.8 39.6 2.0 27 13:23:58 Start 4.0 PPA Automatically 3418 3718 1001.4 39.9 2.0 28 13:25:17 Stage at Perfs: 2.0 PPA 3387 3724 1053.6 39.8 4.0 29 13:30:00 Start 6.0 PPA Automatically 3556 3731 1241.7 39.9 3.9 30 13:30:48 Stage at Perfs: 4.0 PPA 3604 3733 1273.4 39.4 5.8 31 13:36:02 Start 8.0 PPA Automatically 3863 3741 1481.6 40.0 5.8 32 13:36:51 Stage at Perfs: 6.0 PPA 3967 3742 1513.9 39.5 7.5 33 13:42:05 Start 10.0 PPA Automatically 4747 3759 1721.9 39.5 7.9 34 13:42:09 Activated Extend Stage 4748 3759 1724.5 39.5 8.1 35 13:42:53 Stage at Perfs: 8.0 PPA 5039 3770 1753.4 39.8 10.2 36 13:47:37 Deactivated Extend Stage 6030 3690 1941.7 39.9 3.0 37 13:47:37 Start Clear Lines & Spacer Manually 6030 3690 1941.7 39.9 3.0 38 13:47:39 Stopped Pumping Prop 6019 3688 1943.0 40.5 1.9 39 13:48:25 Start Drop Collet#3 Manually 5581 3679 1973.5 39.6 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Stage 3 Once the Collet/Ball#3 shifted the sleeve the pressure transition from Stage 2 to 3 was typical. Treating pressure on PAD was around 3,390 psi and gradually decreased to 3,091 psi. Once 1PPA started entering formation, treating pressure was gradually increased from 3,091 to 5,752 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#4 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #3 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,489 3,020 2,616 Bottomhole Pressure 3,195 3,508 3,324 Summary of Stage 3 Total Proppant Pumped (lb) 248,230 Max pumping Rate (bpm) 40.9 Total Proppant in Formation (lb) 248,230 Average Pumping Rate (bpm) 36.1 CarboLite 40/70 (lb) per Load Tickets 0 Maximum Treating Pressure (psi) 5,955 CarboLite 16/20 (lb) per Load Tickets 248,230 Average Treating Pressure (psi) 4,006 Total Slurry Pumped (bbl) 1,624.8 Average Water Temperature (F) 81.3 YF125ST Pumped (bbl) 1,367.8 Average Viscosity (cP) 21.0 WF125 Pumped (bbl) 0 13:53:56 13:58:56 14:03:56 14:08:56 14:13:56 14:18:56 14:23:56 14:28:56 14:33:56 14:38:56 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-016 Stage 3 10-28-2024 0 Collet/Ball#3 hit the sleeve Drop Rate for Ball/Collet#4 Collet/Ball#4 hit the sleeve Drop Rate for Ball/Collet#3 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st3 221 39.9 5.5 YF125ST 9282 0 0 0 2 Slow For Seat 48.7 22.1 2.5 YF125ST 2065 0 0 0 3 Resume Pad 11.2 18.1 0.6 YF125ST 468 0 0 0 4 1.0 PPA 190 38.6 5 YF125ST 7647 CarboLite 16/20 1.1 0.9 7278 5 3.0 PPA 215 39.7 5.4 YF125ST 7998 CarboLite 16/20 3.2 2.9 23693 6 5.0 PPA 240 39.7 6 YF125ST 8269 CarboLite 16/20 5.3 4.9 41587 7 7.0 PPA 240 39.7 6 YF125ST 7707 CarboLite 16/20 7.1 6.9 54525 8 9.0 PPA 220 39.6 5.6 YF125ST 6618 CarboLite 16/20 9.2 8.9 60245 9 10.0 PPA 205.9 39.6 5.2 YF125ST 6010 CarboLite 16/20 10.2 9.9 60902 10 Clear Lines & Spacer 30 40.1 0.8 YF125ST 1257 0 0 0 11 Drop Collet#4 3 39.8 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st3 39.9 40.1 4882 5955 3671 2 Slow For Seat 22.1 40.0 2523 3649 1638 3 Resume Pad 18.1 18.1 2664 2683 2644 4 1.0 PPA 38.6 40.0 3232 3512 2683 5 3.0 PPA 39.7 39.9 3162 3225 3098 6 5.0 PPA 39.7 39.9 3293 3409 3195 7 7.0 PPA 39.7 40.0 3561 3873 3409 8 9.0 PPA 39.6 40.0 4462 5099 3875 9 10.0 PPA 39.6 40.1 5498 5737 5103 10 Clear Lines & Spacer 40.1 40.9 5429 5752 5271 11 Drop Collet#4 39.8 39.8 5365 5375 5357 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 13:48:30 Start PAD st3 Automatically 5692 3682 0.0 39.7 0.0 2 13:48:30 Start Propped Frac Automatically 5692 3682 0.0 39.7 0.0 3 13:48:30 Start Stage3 Automatically 5692 3682 0.0 39.7 0.0 4 13:48:55 Stage at Perfs: 10.0 PPA 5955 3693 16.6 39.9 0.0 5 13:54:02 Start Slow For Seat Automatically 3595 3661 221.1 39.9 0.0 7 13:54:40 Stage at Perfs: Clear Lines & Spacer 2342 3624 236.4 18.0 0.0 8 13:55:33 Collet#3 Hit the Sleeve 2795 3673 252.4 18.1 0.0 9 13:56:26 Stage at Perfs: Drop Collet#3 2649 3651 268.3 18.0 0.0 11 13:56:30 Start Resume Pad Manually 2646 3639 269.5 18.0 0.0 13 13:56:37 Stage at Perfs: PAD st3 2648 3647 271.6 18.1 0.0 15 13:57:07 Start 1.0 PPA Manually 2682 3652 280.6 17.9 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 16 13:57:07 Started Pumping Prop 2682 3652 280.6 17.9 0.0 17 14:02:06 Start 3.0 PPA Automatically 3210 3737 471.1 39.8 1.0 18 14:02:26 Stage at Perfs: Resume PAD 3208 3743 484.3 39.5 2.8 19 14:03:39 Stage at Perfs: 1.0 PPA 3106 3758 532.6 39.7 3.0 21 14:07:05 Ball/Collet#4 is loaded to Ball Launcher 3192 3702 668.9 39.7 2.9 22 14:07:31 Start 5.0 PPA Automatically 3190 3707 686.1 39.6 3.0 23 14:08:44 Stage at Perfs: 3.0 PPA 3229 3720 734.3 39.6 5.0 24 14:13:33 Start 7.0 PPA Automatically 3413 3749 925.7 39.8 5.0 25 14:14:09 Stage at Perfs: 5.0 PPA 3484 3751 949.4 39.5 7.0 26 14:19:36 Start 9.0 PPA Automatically 3879 3749 1165.7 39.6 6.9 27 14:20:11 Stage at Perfs: 7.0 PPA 3964 3752 1188.8 39.7 9.1 28 14:25:09 Start 10.0 PPA Automatically 5116 3773 1385.7 39.8 9.2 29 14:25:14 Activated Extend Stage 5126 3765 1389.0 40.0 9.1 30 14:26:14 Stage at Perfs: 9.0 PPA 5346 3678 1428.7 39.2 10.1 31 14:30:21 Deactivated Extend Stage 5751 3689 1591.5 40.5 3.1 32 14:30:21 Start Clear Lines & Spacer Manually 5751 3689 1591.5 40.5 3.1 33 14:30:23 Stopped Pumping Prop 5748 3690 1592.9 40.8 1.3 34 14:30:25 Activated Extend Stage 5709 3687 1594.3 40.9 0.0 35 14:31:06 Deactivated Extend Stage 5398 3677 1621.6 39.8 0.0 36 14:31:06 Start Drop Collet#4 Manually 5398 3677 1621.6 39.8 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Stage 4 Once the Collet/Ball#4 shifted the sleeve the pressure transition from Stage 3 to 4 was typical. Treating pressure on PAD was around 3,340 psi and slowly fell to about 3,020 psi while 1-3 PPA Scour 40/70 CarboLite and 1 PPA 16/20 CarboLite were going into the formation. After that the treating pressure was gradually increasing from 3,020 to 6,307 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#5 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #4 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,484 3,064 2,695 Bottomhole Pressure 3,152 3,542 3,357 Summary of Stage 4 Total Proppant Pumped (lb) 254,130 Max pumping Rate (bpm) 41.0 Total Proppant in Formation (lb) 254,130 Average Pumping Rate (bpm) 37.9 CarboLite 40/70 (lb) per Load Tickets 13,623 Maximum Treating Pressure (psi) 6,307 CarboLite 16/20 (lb) per Load Tickets 240,507 Average Treating Pressure (psi) 3,871 Total Slurry Pumped (bbl) 1,917.1 Average Water Temperature (F) 82.4 YF125ST Pumped (bbl) 1,651.3 Average Viscosity (cP) 21.1 WF125 Pumped (bbl) 0 14:36:37 14:40:47 14:44:57 14:49:07 14:53:17 14:57:27 15:01:37 15:05:47 15:09:57 15:14:07 15:18:17 15:22:27 15:26:37 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-016 Stage 4 10-28-2024 0 Collet/Ball#5 hit the sleeve Drop Rate for Ball/Collet#5 Collet/Ball#4 hit the sleeve Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step #Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st4 213 39.9 5.3 YF125ST 8946 0 0 0 2 Slow For Seat 50.4 20.6 2.7 YF125ST 2117 0 0 0 3 1.0 PPA Scour 60 36.6 1.6 YF125ST 2417 CarboLite 40/70 1.1 0.8 1740 4 3.0 PPA Scour 130.7 39.6 3.3 YF125ST 4889 CarboLite 40/70 3.2 2.8 11883 5 Resume Pad 50 40.1 1.2 YF125ST 2099 0 0 0 6 1.0 PPA 190 39.7 4.8 YF125ST 7657 CarboLite 16/20 1 0.9 7400 7 2.0 PPA 220 39.6 5.6 YF125ST 8507 CarboLite 16/20 2.1 1.9 16840 8 4.0 PPA 240 39.7 6 YF125ST 8596 CarboLite 16/20 4.3 3.9 34085 9 6.0 PPA 240 39.8 6 YF125ST 7975 CarboLite 16/20 6.3 5.9 48354 10 8.0 PPA 240 39.7 6 YF125ST 7459 CarboLite 16/20 8.5 7.9 60245 11 10.0 PPA 249.9 39.7 6.3 YF125ST 7304 CarboLite 16/20 10.9 9.9 73583 12 Clear Lines & Spacer 30.1 39.4 0.8 YF125ST 1261 0 0 0 13 Drop Collet#5 3 38.7 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st4 39.9 40.1 4604 5653 3469 2 Slow For Seat 20.6 39.9 2475 3412 1670 3 1.0 PPA Scour 36.6 39.9 3252 3498 3107 4 3.0 PPA Scour 39.6 39.9 3116 3188 3064 5 Resume Pad 40.1 40.4 3233 3314 3181 6 1.0 PPA 39.7 40.0 3264 3332 3120 7 2.0 PPA 39.6 39.7 3057 3116 3037 8 4.0 PPA 39.7 40.0 3099 3204 3024 9 6.0 PPA 39.8 40.1 3355 3611 3205 10 8.0 PPA 39.7 40.0 4011 4550 3611 11 10.0 PPA 39.7 40.1 5535 6275 4552 12 Clear Lines & Spacer 39.4 41.0 5739 6307 5424 13 Drop Collet#5 38.7 38.7 5589 5616 5540 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:31:11 Start PAD st4 Automatically 5507 3685 0.0 39.8 0.0 2 14:31:11 Start Propped Frac Automatically 5507 3685 0.0 39.8 0.0 3 14:31:11 Start Stage4 Automatically 5507 3685 0.0 39.8 0.0 4 14:31:47 Stage at Perfs: Clear lines & Spacer 5394 3680 23.9 39.9 0.0 5 14:36:31 Start Slow For Seat Automatically 2106 3631 212.9 38.8 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 7 14:37:18 Stage at Perfs: Drop Collet#4 2390 3630 229.4 17.8 0.0 8 14:38:07 Collet#4 Hit the Sleeve 2879 3660 244.0 17.9 0.0 9 14:38:59 Stage at Perfs: PAD st4 2689 3646 259.4 17.8 0.0 10 14:39:10 Stage at Perfs: Slow for seat 3520 3647 262.8 20.4 0.0 12 14:39:10 Start 1.0 PPA Scour Manually 3520 3647 262.8 20.4 0.0 13 14:39:10 Started Pumping Prop 3520 3647 262.8 20.4 0.0 14 14:40:49 Start 3.0 PPA Scour Automatically 3106 3667 323.0 39.9 1.0 17 14:44:07 Start Resume Pad Manually 3192 3680 453.5 40.0 0.5 18 14:44:09 Stopped Pumping Prop 3176 3677 454.8 40.0 0.3 19 14:44:28 Stage at Perfs: Resume PAD 3208 3675 467.6 40.5 0.0 20 14:45:22 Start 1.0 PPA Automatically 3328 3676 503.7 40.0 0.0 21 14:45:22 Started Pumping Prop 3328 3676 503.7 40.0 0.0 22 14:45:43 Stage at Perfs: 1.0 PPA Scour 3294 3677 517.6 39.6 0.9 23 14:47:14 Stage at Perfs: 3.0 PPA Scour 3288 3690 577.6 39.6 1.0 24 14:50:10 Start 2.0 PPA Automatically 3107 3686 694.0 39.7 1.0 25 14:50:32 Stage at Perfs: Resume PAD 3108 3683 708.6 39.6 1.9 26 14:51:15 Ball/Collet#5 is loaded to Ball Launcher 3067 3686 736.9 39.6 2.0 27 14:51:48 Stage at Perfs: 1.0 PPA 3051 3691 758.6 39.4 2.0 28 14:55:43 Start 4.0 PPA Automatically 3045 3701 913.8 39.7 1.8 29 14:56:36 Stage at Perfs: 2.0 PPA 3067 3707 948.7 39.7 4.2 30 15:01:46 Start 6.0 PPA Automatically 3208 3715 1154.0 39.8 3.9 31 15:02:08 Stage at Perfs: 4.0 PPA 3234 3718 1168.5 39.8 6.3 32 15:07:48 Start 8.0 PPA Automatically 3614 3723 1393.9 40.0 5.9 33 15:08:10 Stage at Perfs: 6.0 PPA 3658 3722 1408.6 39.8 7.8 34 15:13:51 Start 10.0 PPA Automatically 4568 3734 1634.0 39.8 7.6 35 15:13:53 Activated Extend Stage 4578 3736 1635.3 39.6 7.5 36 15:14:13 Stage at Perfs: 8.0 PPA 4625 3736 1648.5 39.3 9.9 37 15:20:08 Deactivated Extend Stage 6307 3754 1883.3 40.4 3.1 38 15:20:08 Start Clear Lines & Spacer Manually 6307 3754 1883.3 40.4 3.1 39 15:20:10 Stopped Pumping Prop 6303 3756 1884.7 40.9 1.2 41 15:20:16 Stage at Perfs:10.0 PPA 6017 3751 1888.8 41.3 0.0 43 15:20:54 Start Drop Collet#5 Manually 5655 3705 1913.5 38.7 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Stage 5 Once the Collet/Ball#5 shifted the sleeve the pressure transition from Stage 4 to 5 was atypical. Consequently, the decision was made to continue pumping at a Rate of 18 bpm to wait when pressure fell and pump Scour 1-3 PPA 40/70 CarboLite before continuing with the planned design schedule. Treating pressure on PAD was around 3,605 psi and slowly fell to about 3,174 psi while 1-3 PPA Scour 40/70 CarboLite was going into the formation. After that the treating pressure was gradually increasing from 3,174 to 5,648 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#6 to seat. After the Collet/Ball#6 shifted the sleeve, Overflush PCM step was pumped followed by hard shutdown with an ISIP of 973 psi. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #5 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,236 3,437 3,456 Bottomhole Pressure 3,113 3,832 4,303 Summary of Stage 5 Total Proppant Pumped (lb) 247,884 Max pumping Rate (bpm) 41.2 Total Proppant in Formation (lb) 247,884 Average Pumping Rate (bpm) 35.9 CarboLite 40/70 (lb) per Load Tickets 13,663 Maximum Treating Pressure (psi) 5,924 CarboLite 16/20 (lb) per Load Tickets 234,221 Average Treating Pressure (psi) 3,828 Total Slurry Pumped (bbl) 2,253.4 Average Water Temperature (F) 84.9 YF125ST Pumped (bbl) 1,530.4 Average Viscosity (cP) 21.4 WF125 Pumped (bbl) 463.5 15:24:41 15:33:01 15:41:21 15:49:41 15:58:01 16:06:21 16:14:41 16:23:01 16:31:21 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDBi-016 Stage 5 10-28-2024 0 Drop Rate for Ball/Collet#6 Collet/Ball#5 hit the sleeve Drop Rate for Ball/Collet#5 Collet/Ball#6 hit the sleeve Close Well Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step #Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st5 202 40.3 5 YF125ST 8483 0 0 0 2 Slow For Seat 52.8 20.4 2.8 YF125ST 2218 0 0 0 3 Resume Pad 6.5 17.7 0.4 YF125ST 272 0 0 0 4 1.0 PPA Scour 59.8 34.6 1.8 YF125ST 2415 CarboLite 40/70 1 0.8 1618.0 5 3.0 PPA Scour 138 39.6 3.5 YF125ST 5189 CarboLite 40/70 3 2.6 12045.0 6 Resume Pad 51.3 40.5 1.3 YF125ST 2154 0 0 0 7 1.0 PPA 180 39.7 4.5 YF125ST 7260 CarboLite 16/20 1.1 0.9 6881 8 3.0 PPA 200 39.7 5 YF125ST 7510 CarboLite 16/20 3 2.7 20404 9 5.0 PPA 230 39.8 5.8 YF125ST 7922 CarboLite 16/20 5.4 4.9 39911 10 7.0 PPA 230 39.8 5.8 YF125ST 7391 CarboLite 16/20 7.2 6.9 52143 11 9.0 PPA 215 39.8 5.4 YF125ST 6468 CarboLite 16/20 9.7 8.9 58867 12 10.0 PPA 190.1 39.6 4.8 YF125ST 5558 CarboLite 16/20 10.2 9.9 56015 13 Clear Lines & Spacer 31.4 40.1 0.8 YF125ST 1312 0 0 0 14 Drop Collet#6 3 39.6 0.1 YF125ST 126 0 0 0 15 LG Flush 196 39.8 4.9 WF125 8233 0 0 0 16 Slow For Seat 37.8 20.8 2 WF125 1587 0 0 0 17 MT PCM 229.7 38.8 6 WF125 9649 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st5 40.3 41.2 4840 5924 3484 2 Slow For Seat 20.4 39.9 2729 4130 1496 3 Resume Pad 17.7 17.7 3130 3184 3080 4 1.0 PPA Scour 34.6 39.9 3677 4000 3056 5 3.0 PPA Scour 39.6 39.9 3420 3509 3360 6 Resume Pad 40.5 40.9 3398 3443 3340 7 1.0 PPA 39.7 40.1 3337 3438 3216 8 3.0 PPA 39.7 39.9 3201 3253 3179 9 5.0 PPA 39.8 40 3373 3506 3252 10 7.0 PPA 39.8 40.1 3777 4186 3507 11 9.0 PPA 39.8 40.1 4545 4865 4194 12 10.0 PPA 39.6 40.1 5182 5590 4865 13 Clear Lines & Spacer 40.1 41.2 5308 5648 5122 14 Drop Collet#6 39.6 39.6 5275 5285 5260 15 LG Flush 39.8 40 4628 5508 3416 16 Slow For Seat 20.8 40 2067 3188 1696 17 MT PCM 38.8 39.9 3099 3195 592 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 15:20:59 Start PAD st5 Automatically 5692 3744 0.0 39.1 0.0 2 15:20:59 Start Propped Frac Automatically 5692 3744 0.0 39.1 0.0 3 15:20:59 Start Stage5 Automatically 5692 3744 0.0 39.1 0.0 4 15:26:00 Start Slow For Seat Automatically 2177 3600 202.4 38.9 0.0 6 15:26:54 Stage at Perfs: Clear lines & Spacer 2204 3586 220.9 17.8 0.0 7 15:27:31 Collet#5 Hit the Sleeve 2948 3628 231.8 17.7 0.0 8 15:28:37 Stage at Perfs: Drop Collet#5 3292 3632 251.2 17.7 0.0 9 15:28:47 Deactivated Extend Stage 3173 3627 254.2 17.7 0.0 10 15:28:47 Start Resume Pad Manually 3173 3627 254.2 17.7 0.0 11 15:28:48 Stage at Perfs: PAD st5 3165 3626 254.5 17.7 0.0 14 15:29:09 Start 1.0 PPA Scour Manually 2989 3617 260.7 17.8 0.0 15 15:29:09 Started Pumping Prop 2989 3617 260.7 17.8 0.0 16 15:29:13 Activated Extend Stage 3306 3618 261.9 17.8 0.0 17 15:29:23 1ppa scour 40-70 3809 3644 265.3 24.0 0.3 18 15:30:55 Deactivated Extend Stage 3448 3627 320.5 39.9 1.0 19 15:30:55 Start 3.0 PPA Scour Manually 3448 3627 320.5 39.9 1.0 20 15:30:57 Activated Extend Stage 3398 3629 321.8 39.9 1.0 21 15:31:17 3ppa scour 40-70 3419 3624 335.1 39.8 2.4 22 15:34:05 Stage at Perfs: Resume PAD 3390 3624 446.0 39.7 2.9 23 15:34:24 Deactivated Extend Stage 3358 3632 458.5 39.9 1.1 24 15:34:24 Start Resume Pad Manually 3358 3632 458.5 39.9 1.1 25 15:34:26 Stopped Pumping Prop 3368 3631 459.9 40.1 0.5 26 15:34:28 Activated Extend Stage 3336 3625 461.2 40.1 0.0 27 15:35:22 Stage at Perfs: 1.0 PPA Scour 3385 3623 497.8 40.5 0.0 28 15:35:32 Stage at Perfs: 3.0 PPA Scour 3416 3627 504.5 40.1 0.0 29 15:35:40 Deactivated Extend Stage 3421 3623 509.9 40.1 0.0 30 15:35:40 Start 1.0 PPA Manually 3421 3623 509.9 40.1 0.0 31 15:35:45 Started Pumping Prop 3438 3625 513.2 40.0 0.0 32 15:37:02 Stage at Perfs: Slow For seat 3398 3630 564.0 39.6 1.0 33 15:37:50 Ball/Collet#6 is loaded to Ball Launcher 3338 3629 595.7 39.7 0.9 34 15:40:13 Start 3.0 PPA Automatically 3210 3626 690.3 39.7 1.0 35 15:40:31 Stage at Perfs: Resume PAD 3176 3625 702.2 39.3 2.4 36 15:41:49 Stage at Perfs: 1.0 PPA 3205 3633 753.4 39.9 2.6 37 15:45:15 Start 5.0 PPA Automatically 3257 3637 890.3 40.0 3.0 38 15:46:21 Stage at Perfs: 3.0 PPA 3295 3641 933.9 39.8 5.0 39 15:51:02 Start 7.0 PPA Automatically 3513 3630 1120.5 40.0 4.8 40 15:51:22 Stage at Perfs: 5.0 PPA 3530 3627 1133.8 39.7 7.1 41 15:56:48 Start 9.0 PPA Automatically 4215 3626 1350.0 39.5 7.2 42 15:57:09 Stage at Perfs: 7.0 PPA 4221 3628 1363.8 39.6 9.1 43 16:02:13 Start 10.0 PPA Automatically 4865 3620 1565.3 39.6 9.1 44 16:02:14 Activated Extend Stage 4874 3616 1566.0 39.6 9.1 45 16:02:56 Stage at Perfs: 9.0 PPA 4941 3618 1593.7 39.4 10.0 46 16:07:01 Deactivated Extend Stage 5636 3611 1755.6 40.2 2.5 47 16:07:01 Start Clear Lines & Spacer Manually 5636 3611 1755.6 40.2 2.5 48 16:07:02 Stopped Pumping Prop 5640 3614 1756.3 40.4 1.4 49 16:07:04 Activated Extend Stage 5627 3612 1757.7 40.8 0.0 50 16:07:47 Deactivated Extend Stage 5285 3602 1786.3 39.6 0.0 51 16:07:47 Start Drop Collet#6 Manually 5285 3602 1786.3 39.6 0.0 52 16:07:52 Start LG Flush Automatically 5408 3607 1789.6 39.6 0.0 Client: Santos Well: NDBi-016 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 53 16:08:21 Stage at Perfs: 10.0 PPA 5361 3607 1808.8 39.7 0.0 54 16:12:47 Start Slow For Seat Automatically 1696 3539 1985.4 37.6 0.0 55 16:13:25 Stage at Perfs: Clear lines and spacer 2095 3548 1998.6 17.6 0.0 56 16:14:09 Collet#6 Hit the Sleeve 2277 3560 2011.6 17.7 0.0 57 16:14:47 Start MT PCM Manually 1896 3542 2022.8 17.7 0.0 58 16:14:54 Activated Extend Stage 2660 3586 2024.9 19.9 0.0 59 16:15:06 Stage at Perfs: Drop Collet#6 2815 3565 2029.9 29.7 0.0 60 16:15:12 Stage at Perfs: LG Flush 2903 3566 2033.0 32.4 0.0 61 16:20:09 Stage at Perfs: Slow for seat 3146 3613 2228.6 39.7 0.0 62 16:20:48 Stopped Pumping 592 3552 2252.4 11.2 0.0 63 16:24:49 Shut the welll 37 3537 2252.4 0.0 0.0 64 16:25:17 Shut the welll 19 3534 2252.4 0.0 0.0 65 16:28:29 Fanning out pumps 19 3512 2252.4 0.0 0.0 11:50:49 13:14:09 14:37:29 16:00:49 17:24:09 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 22 24 Treating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con Stage 6 Stage 7 Stage 8 Stage 9Pump Ball to Seat Main Treatment © Schlumberger 1994-2017 Santos NDBi-016, Stages 6-9 11-01-2024 12:53:25 13:10:05 13:26:45 13:43:25 14:00:05 Time - hh:mm:ss 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 22 24 Treating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con Drop Rate to Seat Ball Ball Hit Cut Prop at Sahara Due to Ice Plug Main Treatment © Schlumberger 1994-2017 Santos NDBi-016, Stage 6 11-01-2024 Average Water Temperature (F) WF125 Pumped (bbl)Average Viscosity (cP) 13:46:49 14:03:29 14:20:09 14:36:49 14:53:29 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 22 24 Treating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con Drop Rate to Seat Ball Ball Hit Main Treatment © Schlumberger 1994-2017 Santos NDBi-016, Stage 7 11-01-2024 14:34:41 14:51:21 15:08:01 15:24:41 15:41:21 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 22 24 Treating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con Drop Rate to Seat Ball Ball Hit Main Treatment © Schlumberger 1994-2017 Santos NDBi-016, Stage 8 11-01-2024 15:24:24 15:41:04 15:57:44 16:14:24 16:31:04 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 22 24 Treating Pressure Annulus Pressure BHP Slurry Rate Prop Con BH Prop Con Lower Rate to Start Freeze Protect Shutdown Close Wellhead Main Treatment © Schlumberger 1994-2017 Santos NDBi-016, Stage 9 11-01-2024 (lb) NDBi-016 Well Schematic GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,609' MD 13-3/8" 68 ppf L-80 Surface Casing2,759' MD / 9-5/8", 47ppf L-80 Intermediate Liner12,855' MD 4-½, 12.6ppf P-110S Production Liner 18,030' MD 4-½ Liner Hanger Liner Top Packer 12,669' MD Archer C-Flex Two-Stage Cementing Tool (50' MD below TS 790 top) ~4,927' MD TOC First Stage Cement Job - 250' TVD above Nanushuk ~9070' MD 16" Hole Size 12-1/4" Hole Size As Drilled - 09.23.2446.70 RKB Bottom Flange 9-5/8" Tieback and Seal Assembly2,609' MD 8-½ Openhole 18,625' MD 1 2 3 4 5 6 7 8 9 # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1544 1511 24 3.813 4.790 2 GasliftMandrel 1.5" 2141 2005 43 3.865 7.650 3 X Landing Nipple 2213 2056 46 3.813 4.790 4 X Landing Nipple 12511 4012 81 3.813 4.776 5 D/HPsi TempGauge 12573 4022 81 3.905 6.000 6 X Landing Nipple 12596 4025 81 3.813 4.776 7 Tieback Seal Assy 12700 4041 81 3.860 5.220 8 9.625"x 4.5" LH/Packer 12669 4042 81 6.040 8.480 9 #15Openhole Packer 13033 4094 81 3.912 8.000 10 #14Openhole Packer 13101 4104 82 3.912 8.000 11 Stage 9 FracSleeve 13251 4119 86 3.735 5.632 12 #13Openhole Packer 13480 4127 90 3.912 8.000 13 Stage 8 FracSleeve 13754 4127 90 3.735 5.630 14 #12Openhole Packer 13983 4127 90 3.912 8.000 15 Stage 7 FracSleeve 14256 4127 90 3.735 5.635 16 #11Openhole Packer 14525 4127 90 3.913 8.000 17 Stage 6 FracSleeve 14837 4128 90 3.735 5.628 18 #10Openhole Packer 14983 4128 90 3.913 8.000 19 Stage 5 FracSleeve 15256 4122 90 3.735 5.635 20 #9Openhole Packer 15403 4122 90 3.912 8.000 21 #8Openhole Packer 15511 4122 90 3.912 8.000 22 #7Openhole Packer 15742 4122 90 3.918 8.000 23 #6Openhole Packer 15849 4122 90 3.918 8.000 24 Stage 4 FracSleeve 15998 4122 90 3.735 5.630 25 #5Openhole Packer 16266 4122 90 3.918 8.000 26 Stage 3 FracSleeve 16536 4122 90 3.735 5.632 27 #4Openhole Packer 16887 4122 90 3.918 8.000 28 Stage 2 FracSleeve 17119 4122 90 3.735 5.632 29 #3Openhole Packer 17388 4122 90 3.918 8.000 30 Stage 1 FracSleeve 17619 4122 90 3.735 5.634 31 #2Openhole Packer 17724 4122 90 3.918 8.000 32 #1Openhole Packer 17832 4122 90 3.898 8.000 33 #2Toe Sleeve 17940 4122 90 3.500 5.750 34 #1Toe Sleeve 17952 4122 90 3.500 5.750 35 WIV Collar 18014 4122 90 0.870 5.610 36 Float Collar 18027 4122 90 3.980 5.220 37 Eccentricshoe 18029 4122 90 3.290 5.190 Fault 1: 15,568' MD Fault 2: 18,080' MD WELL TEST Doc No: Rev No: Issued:-- GREEN Key BLUE Level 1 Group YELLOW Level 2 Global Product line or Function GREEN Level 3 Local Regional/Area/Country Completed by Name Checked by Name Approved by Name Index Santos Pikka Development - Well Clean-Up and Shut-in/Build-up NDBi-016 Cover ................................................................................................................................................. 1 Index ............................................................................................................................................ 2 - 3 1. Introduction ............................................................................................................................. 4 - 8 2. Points of Contact .................................................................................................................... 9 - 10 3. Nomenclature ....................................................................................................................... 11- 13 4. Test Summary_ Well Clean-up Flow Period ........................................................................... 14 - 18 5. Test Data Report_ Well Clean-up Flow Period ....................................................................... 19 - 22 6. Test Data Plots_ Well Clean-up Flow Period ................................................................................. 23 Bottom Hole Plot ............................................................................................................................... 24 Well Head / Choke Plot ..................................................................................................................... 25 Well Head vs Bottom Hole Conditions Plot ........................................................................................ 26 Production Rate (Test Separator Flow Meter) Plot ........................................................................... 27 Production Rate (Tank Farm Strap) Plot ........................................................................................... 28 Cumulative (Test Separator Flow Meter) Plot ................................................................................... 29 Cumulative (Tank Farm Strap) Plot ................................................................................................... 30 Production Ratio Plot ........................................................................................................................ 31 Test Separator Plot ............................................................................................................................ 32 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 2 Index Santos Pikka Development - Well Clean-Up and Shut-in/Build-up NDBi-016 7. Tank Farm Rates & Volumes ................................................................................................. 33 - 37 8. Injection Well NDBi-014 Data ................................................................................................ 38 42 Well Head Bottom Hole Plot .......................................................................................................... 43 Injection Rate - Cumulative Plot ........................................................................................................ 44 9. Test Summary_Bottom Hole Shut-in / Build-up Period ............................................................ 45-46 10. Test Data Report_ Bottom Hole Shut-in / Build-up Period ...................................................... 47-51 Bottom Hole_Shut-in / Build-up Plot ................................................................................................. 52 11. Sequence of ..................................................................................................... 53 - 72 12. Combined Meter Shrinkage Factor (CMSF) .......................................................................... 73 - 74 13. Diagrams ................................................................................................................................... 75 Process and Instrumentation Diagram (P&ID) ............................................................................ 76 -84 Safety Analysis Function Evaluation (SAFE) Chart ..................................................................... 85 - 87 General Arrangement Diagram (GAD) ....................................................................................... 88 - 91 Process Flow Diagram (PFD) ...................................................................................................... 92 - 96 This report is based on sound engineering practices, but because of variable well conditions and other information which must be relied upon, Expro Americas, Inc. makes no warranty, expressed or implied, as to the accuracy of the data or any calculations or opinions expressed herein. You agree that Expro Americas, Inc. shall not be liable for any loss of damage whether due to negligence or otherwise arising out of or in connection with such data, calculations, or opinions. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 3 Santos Pikka Development NDBi-016 SECTION 1 INTRODUCTION WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 4 Introduction November th, 2024 Santos Pikka Development NDBi-016 Nanushuk 3 Reservoir Well Type: Injector To Whom It May Concern: Please find enclosed the well clean-up and shut-in/build-up report, plots, and associated data for the referenced well NDBi-016. The well clean-up flow period(s) and well shut-in / build up period(s) are defined as following: Well Clean-Up Flow Period: Start of Flow Period: November 6th, 2024 12:17:00 End of Flow Period: November 11th, 2024 00:00:00 Well Shut-In & Build-Up Period: Start of Build-Up Period: November 11th, 2024 00:00:00 End of Build-Up Period: November 16th, 2024 06:00:00 Note: NDBi-016 was continuously monitored, and downhole data reports were sent out daily as per requested time frequency. For the End of Well Report, the above dates are captured in the test summary and plotted. Expro conducted well testing / well clean-up operations within the facility start-up at Nanushuk Drill site B (ND-B) on the North Slope Basin of Alaska. ND-B, as part of the Pikka Unit, is located 52 miles west of Deadhorse and approximately 6 miles from Nuiqsut. The flowback operations comprised of a well clean-up period and one main Shut-in/Build-up period. During the well clean-up period, well effluent was routed through Expros Surface Test Equipment to measure and record the flowing parameters of the well. Effluent from the well was first routed through Expros Ball Catcher which was designed to retrieve metallic spheres deployed during frac operations without interrupting the flow of the well. Once effluent exited the Ball Catcher, well fluids entered the Expro DPI CyFi Desander, which was composed of two vessels that could operate in series or parallel, for the purpose of separating solids from the produced fluids. This vessel was equipped with an isolated drain line routed to a horizontal Atmospheric 400 bbl Sand Tank to facilitate disposal of accumulated solids. Pressure differential across the Expro DPI CyFi Desander was monitored in real-time utilizing Expros Data Acquisition system (DAQ) and gave indication of an accumulation of sand in the vessel. Fluid samples taken upstream of the Expro DPI CyFi Desander alerted to the presence of sediment in the flow stream throughout the well clean-up period. Monitoring the Expro DPI CyFi Desander System differential pressure along with fluid samples alerted personnel to the presence of solids and to act accordingly by dumping sands to the 400 bbl Atmospheric Horizontal Sand Tank. The disposal feature on the Expro DPI CyFi Desander was utilized multiple times during the clean-up period which equated to an approximate total of 6.24 bbls of sand accumulated in the 400 bbls Atmospheric horizontal Sand Tank. Effluent exiting the Expro DPI CyFi Desander unit was next routed through Expros Choke Manifold. The choke served as the primary flow control device and regulated pressures and fluid rates into the downstream equipment. Occasionally well debris would accumulate in the flow cavity of the adjustable choke and cause a disruption. To free the adjustable choke of debris and re-establish the desirable flow parameters, the adjustable choke was slightly WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 5 Introduction turned in and out called Rocking the Choke. Prior to flow operations, a baseline thickness reading was identified on surface test flowline piping for critical erosion points and those selected areas were marked. During flowing operations, Expro Well Test team performed thickness checks on these selected points for critical erosion when sand/solids were observed during sparging of the Expro DPI CyFi Desander. After effluent passed through the Expro Choke Manifold, it was heated by flowing through Expro Line Heater which was equipped with an in-line adjustable choke. During the flow clean up, when solids were present, Expro bypassed the line heater to protect the integrity of the internal coils. Well effluent next entered the Expro Test Separator. Effluent entering the test separator underwent two-phase separation: liquid (water + oil) and gas. The separators liquid was metered (oil and water) utilizing a turbine meter with Expros flow totalizer transmitter for determining a total liquid flow rate. The total liquid flow rates acquired were then modified utilizing basic sediment and water (BS&W) values, creating individualized oil and water rates. These oil and water rates subsequently created oil and water cumulative values. Gas exiting the separator was metered via a Coriolis Flow Meter before being routed to Expros Gas Scrubber. The gas scrubber was used for further separation and aided in removing any remaining liquid/condensate from the gas. Dry gas exited the gas scrubber via a 4 temporary test header to a 100 flare stack for disposal through flaring. Liquid exiting the test separator flowed through a turbine flow meter and was then routed to Expros tank farm. The tank farm consisted of ten 367 bbl tanks and was used to determine liquid flow rates (oil + water). The well fluids were diverted between two tanks with flow into one of the 367 bbl tanks for 30 minutes, then, flow was diverted into another 367 bbl tank for 30 minutes. This cycle continued until the tank levels were at 80% volume capacity. Manual tank strap volumes were recorded every 30 minutes and reported to the DAQ operator for inclusion into liquid flow rate calculations. The liquid flow rates calculated from tank straps were entered into an tank volume spreadsheet calculator along with BS&W values to deduce oil and water rates and cumulatives. Once the tanks reached the maximum level of 294 bbls, and an acceptable fluid Reid Vapour Test (RVP) was confirmed, Magtec pumped the fluid from each tank through a filter skid to a Little Red Services (LRS) triplex pump. LRS injected the fluid into disposal well NDBi-014, with the option to switch injection into well NDBi-030. Note that approximately 1500 bbls of initial fluid returned from well NDBi-016 was transferred from the tanks directly to Worley Vac Truck and transported to an offsite disposal well. A Meter Factor is a ratio acquired by dividing the actual measured volume of a liquid by the amount of volume measured by a meter. Utilizing the production tank farm, multiple Combined Meter Shrinkage Factors (CMSF) were calculated for the separator total liquid flow turbine meter during the flow clean-up periods. Immediately prior to diverting into a production tank, an initial manual tank strap volume and fluid temperature was recorded. When the effluent was routed into the gauging tank, the initial cumulative value from the turbine meter fluid totalizer was recorded. After a designated time allotment (30 min), effluent was routed into another production tank and the turbine meter fluid totalizer final volume is recorded. After another designated time allotment, the final manual strap volume and temperature is recorded. The time between diverting from the gauging production tank and the manual strap is performed allows extra gas to break out of the oil and accounts for the shrinkage in the calculation. Initial and Final tank volumes are adjusted to standard conditions using recorded temperatures and then compared to the meter volumes to create the Combined Meter Shrinkage Factor (CMSF). Provided below are actions taken by the Expro Well Test Crew during the Clean-up flow period of the well test to achieve accurate separator total liquid flow meter rates compared to tank strap rates. Dates and times of each WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 6 Introduction combined meter shrinkage factor are included such that the associated time interval can be referenced in the well test data and sequence of . Combined Meter and Shrinkage Factors (CMSF) were calculated and applied as necessary to ensure the accuracy of the Separator Liquid Turbine Meter compared to the Tank Strap Calculations. The first Combined Meter Shrinkage Factor of 0.933 was applied on November 6th, 2024. See section 12 of this report for a complete list of CMSFs calculated and applied into our DAQ software calculations during flowback operations. Throughout the well test, Basic Sediment and Water (BS&W) readings were taken downstream of the Expro Choke Manifold to determine the percentage of water and its properties including the pH, salinity, and weight. Oil API sampling was performed using a densitometer. BS&W samples were also taken upstream of the Expro DPI and at the Expro Test Separator oil leg to monitor for solids and to determine separation efficiency. Gas samples were taken from the Expro Test Separator gas line to determine Gas Specific Gravity and the concentration of CO2 and H2S. Daily oil and water samples were collected at twice per shift frequency downstream of the Expro Choke Manifold for Tracerco analysis. Once the clean-up flow period was complete, the well was immediately shut-in to commence the build-up period. During this time, the Schlumberger (SLB) down-hole gauge remained connected to Expros data logging system to collect downhole pressure and temperature data while personnel began rigging down the surface test equipment from the wellhead. On November 16th at 06:00, Expro completed the Build-Up data for the purposes of this report, but Schlumbergers downhole gauge communication interface remained connected to Expros data acquisition system for additional continuous monitoring and reporting. For the purposes of this report, Expros primary reference for determining liquid rates and cumulative values is tank strap readings taken at the tank farm. Expros separator turbine flow meters are used as reference for confirming liquid flow rates and liquid cumulative values throughout the well test. Expros primary reference for gas rates and gas cumulative values was the Coriolis Flow Meter (located in the gas line of the Expro Test Separator) and gas calculations from Expros data acquisition (DAQ) software. On November 7th, 2024 at 09:42, moisture in the air supply system and freezing temperatures caused a hydrate plug to form in a hose between the air supply source and our ESD panel. Subsequently, air supply pressure to the ESD panel was lost causing a Fail-Safe Closure of the ESD devices and the well Shut-in at the Wellhead SDV and Expros SSV. To mitigate re-occurrence in the future, Expro will implement the following listed below: Install a data cquisition pressure transducer on the air supply going to the ESD panel. This pressure can then be continuously monitored from the data acquisition computer and alarms set to alert the operator of any drop in pressure. On the air supply tee in the heated choke manifold house, install a check valve before the air supply hose to the ESD panel. This will allow air to be trapped in the hose supplying the ESD panel if this scenario ever reoccurs. This trapped pressure will keep the ESD system active while the issue is resolved. Lastly, we will install an external air dryer on the air source. Removing the moisture from the air supply can eliminate the risk of hydrates forming. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 7 Introduction Data from the flow period described above is provided in this report. This includes a well test summary report with general comments. For a more detailed log outside of the flowing periods, please see the Sequence of section. Information from the well test summary report is also displayed in a graphical format. We appreciate your business and look forward to providing our services for your future testing needs. For all inquiries, please refer to the Points of Contact in Section 2 of this report. Disclaimer: Expro Well Testing will do its best efforts to furnish customers with accurate information and interpretations as a part of, and incident to, the services provided. However, Expro cannot and does not warrant the accuracy or correctness of such information or interpretations. Under no circumstances should any such information or interpretation be relied upon as the sole basis for any decision regarding drilling, completion, production, financing, or any procedure involving any risk to the safety of any drilling venture, drilling rig or its crew or any other third party. These calculations are based on certain data, assumptions and applied mathematical methods. Inaccurate well data, changing well conditions, tolerance variations of mechanical components, mechanical malfunctions and other factors may affect these calculations. In no event will Expro be liable for failure to obtain any results or for any damages, including, but not limited to, indirect, special, or consequential damages, whether due to negligence or otherwise arising out of or in connection with such use of data, calculations, recommendations, or opinions provided by Expro. Sincerely, WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 8 Santos Pikka Development NDBi-016 SECTION 2 POINTS OF CONTACT WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 9 Points of Contact Terry Park AK Operations Sales & Supervisor Terry. Park@expro.com Office: (907) 351-7952 Matt Purcell AK Operations Supervisor Matt.Purcell@expro.com Office: (907) 335-6618 Andres Arana Lead Engineer North & Latin America Andres.Arana@expro.com Office: (337) 572-2473 Sharon Oyao Well Test Field Engineer Sharon.Oyao@expro.com Office: (907) 382-8773 Roger Ihde Well Test Supervisor Roger.Ihde@expro.com Office: (907) 715-1827 Travis Stacey Well Test Sr. DAQ Specialist Travis.Stacey@expro.com Office: (709) 743-0294 Jacques Guillot GOM & AK Operations Manager Jacques.Guillot@expro.com Office: (337) 839-6409 Ryan McMaster AK Operations Supervisor Ryan.McMaster@expro.com Office: (907) 398-1585 Stan Becnel NAM Product Line Manager Stan.Becnel@expro.com Office: (337) 839-6535 Austin Stewart Well Test Supervisor Austin.Stewart@expro.com Office: (907) 830-3241 Frank Tower Well Test Supervisor Frank.Tower@expro.com Office: (206) 743-2861 Yehia Elzeny Well Test Sr. DAQ Specialist Yehia.Elzeny@expro.com Office: (907) 229-3996 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 10 Santos Pikka Development NDBi-016 SECTION 3 NOMENCLATURE WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 11 Nomenclature: Abbreviation Meaning Abbreviation Meaning ADJ Adjustable HP High Pressure API American Petroleum Institute I/A Inner Annulus BHP Bottom Hole Pressure JRA Job Risk Assessment BHT Bottom Hole Temperature JSA Job Safety Assessment BPCV Back Pressure Control Valve KCl Potassium Chloride BS&W Basic Sediment & Water KWV Kill Wing Valve Chl Chloride LDHI Low Dosage Hydrate Inhibitor CIM Chemical Injection Mandrel LOTO Lock-out Tag-out CIV Chemical Injection Valve LP Low Pressure CO2 Carbon Dioxide LRS Little Red Services C/T Coil Tubing LSH Level Safety High CRU Colville River Unit LSL Level Safety Low DAQ Data Acquisition MeOH Methanol DCP Downstream Choke Pressure MF Meter Factor DCT Downstream Choke Temperature MV Master Valve DHSIT Downhole Shut-In Tool N2 Nitrogen Diff Differential N/R Not Recorded DW Disposal Well NDB Nanashuk Drilling B Production EB Emulsion Breaker | Demulsifier NDBi Nanashuk Drilling B Injection EDGE Expros Data Acquisition Software O/A Outer Annulus E-Line Wireline PLT Production Logging Tool ESD Emergency Shut Down Pos Positive FWD Forward POOH Pull out of Hole FWV Flow Wing Valve Pres Pressure GOR Gas Oil Ratio PSD Process Shut Down HES Halliburton Energy Services PSH Pressure Safety High H2O Water PSL Pressure Safety Low H2S Hydrogen Sulfide PSV Pressure Safety Valve WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 12 Nomenclature: Abbreviation Meaning Abbreviation Meaning P-Tank Pressurized Tank TBT Toolbox Talk PVT Pressure Volume - Temperature Temp Temperature RIH Run in Hole UCP Upstream Choke Pressure Sal Water Salinity UCT Upstream Choke Temperature SDV Shutdown Valve US / DS Upstream / Downstream Sep Separator Vac Vacuum Truck SG Specific Gravity WGR Water Gas Ratio S/L Slick Line WHP Well Head Pressure SLB Schlumberger WHT Well Head Temperature SSV Surface Safety Valve WST Well Stimulation Tool STE Surface Well Test Equipment WT Well Test WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 13 Santos Pikka Development NDBi-016 SECTION 4 TEST SUMMARY WELL CLEAN-UP FLOW WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 14 Test Summary Notes: Unless otherwise stated, the above readings were taken just before shut-in. Flow rates and GORs are average values during the last hour (or most stable period) on each choke size. Throughout the report reference is made to Separator and Standard/Stock Tank (Stb) oil rates. The separator rate refers to the oil metered at separator conditions. The standard/stock tank rate is the metered rate corrected for shrinkage at standard conditions of 14.73 psi, 60°F. Santos Pikka Development NDBi-016 Clean-up Flow Period Well Clean-up Flow Test Start of 12 Hour Averaged Stable Flow Period: November 10th, 2024 01:00:00 End of 12 Hour Averaged Stable Flow Period: November 10th, 2024 13:00:00 On November 6th, 2024 @ 12:11 the NDBi-016 well was opened at the Flow Wing Valve (FWV) on the Wellhead to a closed Expro choke manifold. At 12:17 the choke was opened to flow through the Expro Surface Test Equipment (STE) on a 20/64ths adjustable choke bean. Well NDBi-016 was opened on a 128/64ths adjustable choke on November 10th, 2024 @ 13:30 and flowed until November 10th, 2024 @ 14:00. The contents of this summary was deducted from 12 hours of stabilized flow at the end of the flow period. Prior to a hard shut-in at the choke manifold, the well was beaned down to and flowed for a 5-hour period on each a 52/64ths adjustable choke on November 10th, 2024 @ 14:00 to November 10th, 2024 @ 19:00 and a 44/64ths adjustable choke on November 10th, 2024 @ 19:00 to November 11th, 2024 @ 00:00. Provided below is a summary of the 12-hour flow period with the highest choke size flowing at stable conditions. Data was collected every 30 minutes, and the following table represents manual sample readings recorded at specific times during the 12-hour period. At the end of this summary the average flow rates and GORs are presented for the 12-hour period while the volume cumulative values are totals at the end of the well clean-up flowback. WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 15 Test Summary Notes: Unless otherwise stated, the above readings were taken just before shut-in. Flow rates and GORs are average values during the last hour (or most stable period) on each choke size. Throughout the report reference is made to Separator and Standard/Stock Tank (Stb) oil rates. The separator rate refers to the oil metered at separator conditions. The standard/stock tank rate is the metered rate corrected for shrinkage at standard conditions of 14.73 psi, 60°F. Santos Pikka Development NDBi-016 Clean-up Flow Period Date & Time Choke Size (1/64ths) Water Cut @ Choke (%) Solids, Mud & Carbolite BS&W (%) Salinity (ppm) Acid Base (pH) Gas Gravity (SG) CO2 (%) H2S (ppm) Oil Gravity SG (Water=1) Oil API (API) Demulsifier (EB) (gal/day) Defoamer (gal/day) 10-Nov-24 01:00128 8 0 29,000 8 0.696 0.1 0 0.877 29.8 10 16 10-Nov-24 01:30128 10 0 29,000 8 0.696 0.1 0 0.877 29.8 10 16 10-Nov-24 02:00128 12 0 29,000 8 0.696 0.1 0 0.877 29.8 10 16 10-Nov-24 02:30128 10 0 29,000 8 0.696 0.1 0 0.877 29.8 10 16 10-Nov-24 03:00128 9 0 29,000 8 0.696 0.1 0 0.877 29.8 10 16 10-Nov-24 03:30128 9 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 04:00128 10 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 04:30128 9 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 05:00128 9 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 05:30128 10 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 06:00128 9 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 06:30128 12 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 07:00128 10 0 29,000 8 0.698 0.1 0 0.874 30.4 10 16 WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 16 Test Summary Notes: Unless otherwise stated, the above readings were taken just before shut-in. Flow rates and GORs are average values during the last hour (or most stable period) on each choke size. Throughout the report reference is made to Separator and Standard/Stock Tank (Stb) oil rates. The separator rate refers to the oil metered at separator conditions. The standard/stock tank rate is the metered rate corrected for shrinkage at standard conditions of 14.73 psi, 60°F. Date & Time Choke Size (1/64th) Water Cut @ Choke (%) Solids, Mud & Carbolite BS&W (%) Salinity (ppm) Acid Base (pH) Gas Gravity (SG) CO2 (%) H2S (ppm) Oil Gravity SG (Water=1) Oil API (API) Demulsifier (EB) (gal/day) Defoamer (gal/day) 10-Nov-24 07:30128 7.95 0.05 29,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 08:00128 8 0 28,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 08:30128 9 0 28,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 09:00128 8 0 28,000 8 0.698 0.1 0 0.874 30.4 10 16 10-Nov-24 09:30128 8 0 28,000 8 0.698 0.1 0 0.877 29.9 10 16 10-Nov-24 10:00128 8 0 28,000 8 0.696 0.1 0 0.877 29.9 10 16 10-Nov-24 10:30128 8 0 28,000 8 0.696 0.1 0 0.877 29.9 10 16 10-Nov-24 11:00128 8 0 29,000 8 0.696 0.1 0 0.877 29.9 10 16 10-Nov-24 11:30128 8 0 29,000 8 0.696 0.1 0 0.877 29.9 10 16 10-Nov-24 12:00128 8 0 29,000 8 0.696 0.1 0 0.877 29.9 10 16 10-Nov-24 12:30128 8 0 29,000 8 0.696 0.1 0 0.877 29.9 10 16 10-Nov-24 13:00128 8 0 29,000 8 0.696 0.1 0 0.877 29.9 10 16 WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 17 Test Summary Notes: Unless otherwise stated, the above readings were taken just before shut-in. Flow rates and GORs are average values during the last hour (or most stable period) on each choke size. Throughout the report reference is made to Separator and Standard/Stock Tank (Stb) oil rates. The separator rate refers to the oil metered at separator conditions. The standard/stock tank rate is the metered rate corrected for shrinkage at standard conditions of 14.73 psi, 60°F. Santos Pikka Development NDBi-016 Clean-up Flow Test. Average Total Gas Rate (Formation + N2) 1.8156 MMscf/day Cumulative Total Gas (Formation + N2) 5.2654 MMscf Average N2 Rate 0.00 MMscf/day Cumulative N2 0 MMscf Average Oil Rate - Meter 4,485.72 Cumulative Oil - Meter 13,546.57 Stb Average Oil Rate - Tanks 4,503.96 Stb/day Cumulative Oil - Tanks 13,556.85 Stb Average Water Rate - Meter 440.66 Stb/day Cumulative Water - Meter 4,800.20 Stb Average Water Rate - Tanks 446.06 Stb/day Cumulative Water - Tanks 4,760.48 Stb Average Sol/Mud/Car Rate 0.10 Stb/day Cumulative Sol/Mud/Carbo 21.39 Stb @ Flowmeter @ Flowmeter Average Sol/Mud/Car Rate 0.10 Stb/day Cumulative Sol/Mud/Carbo 21.73 Stb @ Strap Tanks @ Strap Tanks Average Total Fluid Rate 4,926.44 Stb/day Cumulative Total Fluid 18,346.77 Stb @ Flowmeter @ Flowmeter Average Total Fluid Rate @ Strap Tanks 4,950.12 Stb/day Cumulative Total Fluid @ Strap tanks 18,339.05 Stb Average GOR (Total) (Formation + N2) 395.36 scf/stb % Frac Water Recovered 32.00 % Note: Well Clean-up: Flow rates and GOR are average values during the most stable flow period taken between November 10th, 2024 at 01:00hrs through November 10th, 2024 at 13:00hrs. Average Formation GOR can be assumed to be the same as Total GOR because Nitrogen was not Injected. Average Formation Gas Rate assumed to be the same as Total Gas Rate because Nitrogen was not Injected. All Cumulative Values including % Frac Water Recovered are totals at the end of the well clean-up flowback. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 18 Santos Pikka Development NDBi-016 SECTION 5 TEST DATA REPORT WELL CLEAN-UP FLOW WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 19 START DATE:END DATE:Time DPI Heater GOR Frac WaterTime & Date COMMENTS BHP BHT I/A Pressure O/A Pressure Well Head PressureWell Head TemperatureU/S Choke PressureU/S Choke TemperatureD/S Choke PressureD/S Choke TemperatureChoke Size U/S DPI Solids, Mud & Carbolite D/S Heater PressureSeparator PressureGas Temperature Oil Temperature Corrected API WaterSalinity pH Gas S.G CO2 H2S Total Choke BS&W(Solids, Mud, Carbolite & Water)Solids, Mud & Carbolite @ ChokeWater Cut @ Choke Separator Oil Leg BS&W (2-Phase)Nitrogen Injection RateTotal Gas Rate (N2+Formation)Nitrogen InjectionCumulative Total Gas Cumulative (N2+Formation)Total GOR Solids, Mud & Carbolite RateSolids, Mud, & Carbolite CumulativeOil Rate Oil Cumulative Water RateWater CumulativeTotal Fluid RateTotal Fluid CumulativeTank Farm StrapSolids, Mud & Carbolite RateTank Farm StrapSolids, Mud, & Carbolite CumulativeTank Farm StrapOil RateTank Farm StrapOil CumulativeTank Farm StrapWater RateTank Farm StrapWater CumulativeTank Farm Strap Total Rate (Tank 1 - Tank 10)Tank Farm Strap Total Cumulative(Tank 1 - Tank 10)Percentage of Frac Water RecoveredDefoamer(D/S of Choke Manifold Data Header)Methanol (MeOH)(Separator Gas Line)Demulsifier(D/S of Choke Manifold Data Header)H2S Scavenger(U/S of Choke Manifold Data Header)(mm-dd-yyyy hh:mm) (psig)(F)(psig) (psig) (psig)(F)(psig)(F)(psig)(F)(64ths) (%) (psig) (psig)(F) (F)(API@60°)(ppm) (pH) (Air = 1) (%) (ppm) (%) (%) (%) (%) (MMscf/d) (MMscf/d) (MMscf) (MMscf) (scf/stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb)(stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (%) (gal/d) (gal/d) (gal/d) (gal/d)11/06/2024 11:3011:45 Verified Valve Alignment to Flow Through Ballcatcher, DPI and Choke to Tank #1. Bypassed Line Heater and Test Separator.1839.71 99.89 0.00 0.00 1.69 107.67 1.59 56.49 0.00 49.16 0 0.00 0.00 57.61 58.63 0.00 0 0 0 011/06/2024 12:0012:11 Opened Wellhead NDBi-016 Production Wing Valve (PWV) to closed Expro Choke Manifold.12:15Initial Bottomhole Pressure 1837.45 PSI; Initial Bottomhole Temperature 99.98 °F; Initial SITHP 268.2 PSI.12:17 Opened Well on Expro 20/64ths adjustable Choke as per Santos WSS. 1839.66 99.89 0.00 0.00 0.21 104.26 1.79 54.74 0.00 49.36 0 0.00 0.00 58.33 59.19 0.00 0 0 0 011/06/2024 12:30Observed Clean Diesel at surface. Commenced Choke BS&W sampling.1789.48 100.52 0.00 0.00 205.47 53.04 205.47 50.27 3.67 54.87 20 0.00 0.00 59.00 59.59 0.00 0.00 934.08 8.43 0.00 0.00 934.08 8.43 0.00 0 0 0 011/06/2024 13:00Increased Expro adjustable Choke to 24/64ths as per Santos WSS.1785.23 100.66 0.00 32.94 123.83 50.40 131.59 44.17 6.40 46.81 24 0.04 0.00 59.13 59.27 0.00 0.00 0.00 0.00 0.00 934.08 27.89 0.00 0.00 934.08 27.89 0.00 0 0 0 011/06/2024 13:30BS&W at Choke Manifold Showed 100% Diesel.1776.17 100.88 0.00 99.74 50.17 51.31 55.26 43.67 4.27 43.87 24 0.00 0.00 58.17 58.47 0.00 0.00 0.00 0.00 0.00 1085.76 50.51 0.00 0.00 1085.76 50.51 0.00 0 0 0 011/06/2024 14:0014:09 Diverted flow through 24/64ths Fixed Choke Manifold to inspect adjustable Stem and Seat. 14:15 Diverted flow through 24/64ths adjustable choke. 1799.59 100.87 0.00 144.99 26.10 53.46 31.19 44.76 0.51 45.34 24 0.00 0.00 56.81 57.38 0.00 0.00 0.00 0.05 0.00 506.35 61.06 0.00 0.00 506.40 61.06 0.00 0 0 0 011/06/2024 14:30 1784.59 100.95 0.00 166.08 22.21 49.23 25.12 41.48 5.22 44.20 24 0.18 0.00 55.45 56.34 0.10 0.10 0.00 0.00 0.00 506.70 71.62 0.00 0.00 506.70 71.62 0.00 0 0 0 011/06/2024 15:00Increased Expro adjustable Choke to 28/64ths as per Santos WSS.1794.92 100.97 0.00 193.15 47.44 51.26 45.98 42.37 8.67 43.17 28 0.74 0.00 54.20 55.32 0.00 0.00 0.00 0.00 0.00 578.96 83.68 0.00 0.00 578.96 83.68 0.00 0 0 0 011/06/2024 15:30Rocked Expro Choke. 15:34 Rocked Expro Choke. 15:45 Commenced Water Salinity, Water Weight and pH sampling as per Santos Well Program.1756.61 101.09 0.00 189.62 89.65 49.71 91.28 43.22 7.79 43.42 28 0.75 0.00 53.16 54.46 0.00 0.00 0.00 0.40 0.01 764.23 99.60 31.44 0.66 796.07 100.26 0.0044 0 0 0 011/06/2024 16:00Rocked Expro Choke. 1735.91 101.18 0.00 184.86 236.65 52.80 207.27 43.86 33.01 44.50 32 7.55 0.00 52.20 53.85 43000 9 4.00 0.05 3.95 5.32 0.12 881.47 117.96 632.99 13.84 1519.77 131.92 0.0923 0 0 0 011/06/2024 16:30Oil @ Surface.1683.74 101.28 0.00 142.26 263.19 54.74 238.40 44.82 53.04 43.78 32 28.87 0.00 51.51 53.40 43000 9 42.00 0.35 41.65 7.60 0.28 243.16 123.03 1269.01 40.28 1519.77 163.59 0.2685 0 0 0 011/06/2024 17:0017:07 Commenced Chemical Injection of Defoamer and Demulsifier at 10 gal/day at the Downstream Choke Data Header.1698.76 101.32 0.00 132.36 265.81 54.75 240.86 45.05 39.99 43.55 36 16.97 0.00 50.90 52.81 46000 8 84.00 0.50 83.50 1.63 0.31 564.49 134.79 519.44 51.10 1085.55 186.20 0.3407 0 0 0 011/06/2024 17:3017:49 Dumping Gas from Separator to Flare. Metering Gas through 0.5" Coriolis Meter.17:51Flare lit.17:54Began dumping Fluid from Separator. Metering Fluid through 2" Line (1.5" Turbine Meter).17:54Cumulative Volumes 159.56 bbls Oil, 69.78 bbls Water and 0.31 bbls Solids was enetered into the DAQ software to account for the volumes not metered due to the Separator being bypassed.1689.25 101.37 0.00 163.71 309.42 55.91 302.93 44.39 34.82 44.82 36 16.37 0.00 50.42 52.25 46000 8 48.00 0.15 47.85 0.00 0.0000 0.0000 0.0000 0.0000 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.31 856.86 152.64 481.99 61.14 1338.85 214.10 0.4076 10 0 10 011/06/2024 18:00Increased Expro adjustable Choke to 40/64ths as per Santos WSS.Commenced Chemical Injection of Methanol at 10 gal/day at Separator Gas Line.1608.23 101.43 0.00 79.07 309.92 56.74 269.07 46.34 125.91 47.08 40 102.64 103.15 49.72 51.79 48000 8 0.709 36.00 0.00 36.00 36.00 0.0000 0.2178 0.0000 0.0045 755.04 0.00 0.31 288.55 165.57 162.31 73.16 450.87 238.73 0.00 0.31 683.90 166.89 582.58 73.28 1266.48 240.48 0.4877 10 10 10 011/06/2024 18:30Increased Expro adjustable Choke to 44/64ths as per Santos WSS.1613.84 101.48 0.00 26.19 207.04 56.36 174.54 46.06 127.07 46.64 44 116.61 118.48 49.83 47.12 48000 8 0.668 46.00 0.00 46.00 46.00 0.0000 0.5629 0.0000 0.0163 424.60 0.00 0.31 1326.05 193.19 1129.60 96.70 2455.65 289.89 0.00 0.31 1482.14 197.77 833.70 90.65 2315.85 288.73 0.6447 10 10 10 011/06/2024 19:00Increased Expro adjustable Choke to 48/64ths as per Santos WSS.Collected Tracerco Sample.19:05Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter.19:21 Gas Rate too low to be measured by 3" Coriolis Meter. Diverted Gas Flow through 0.5'' Coriolis Meter.1622.90 101.51 0.00 84.07 231.57 60.18 208.22 50.68 163.57 51.88 48 0.00 130.08 126.51 49.46 49.02 40000 8 0.668 36.00 0.00 36.00 36.00 0.0000 0.4400 0.0000 0.0254 229.98 0.00 0.31 1912.72 233.05 1075.90 119.11 2988.62 352.16 0.00 0.31 2252.52 244.69 461.36 100.26 2713.88 345.27 0.79 10 10 10 011/06/2024 19:30Increased Expro adjustable Choke to 52/64ths as per Santos WSS.1614.76 101.54 0.00 63.57 249.03 60.62 189.07 51.80 127.18 52.21 52 0.00 97.46 97.96 50.73 49.84 40000 8 0.668 17.00 0.00 17.00 17.00 0.0000 0.5666 0.0000 0.0372 218.29 0.00 0.31 2595.62 287.12 531.63 130.18 3127.25 417.31 0.00 0.31 2373.74 294.15 521.07 111.12 2894.81 405.57 0.87 10 10 10 011/06/2024 20:00Increased Expro adjustable Choke to 56/64ths as per Santos WSS.1598.57 101.55 0.00 61.26 205.17 59.74 162.44 50.70 126.00 52.48 56 0.00 103.04 104.21 49.63 52.08 38000 8 0.668 18.00 0.00 18.00 18.00 0.0000 0.5000 0.0000 0.0477 210.63 0.00 0.31 2374.13 336.58 521.15 141.04 2895.28 477.62 0.00 0.31 2200.05 339.98 550.01 122.57 2750.07 462.87 0.94 10 10 10 011/06/2024 20:30Increased Expro adjustable Choke to 60/64ths as per Santos WSS.Observed well slugging.20:33Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter.20:48 Lowered Separator Pressure.1562.75 101.55 0.00 28.74 271.11 60.95 213.62 52.44 174.89 53.83 60 0.00 154.84 156.13 50.28 52.99 38000 8 0.668 20.00 0.00 20.00 20.00 0.0000 0.5671 0.0000 0.0595 209.22 0.00 0.31 2711.02 393.05 677.75 155.17 3388.77 548.22 0.00 0.31 1512.54 371.49 1925.05 162.68 3437.58 534.48 1.03 10 10 10 011/06/2024 21:00Increased Expro adjustable Choke to 64/64ths as per Santos WSS.1550.61 101.56 0.00 17.49 209.09 61.78 153.46 53.29 127.10 54.11 64 0.00 92.54 90.75 52.47 52.51 28.4 39000 8 0.668 0.00 0.0 64.00 0.00 64.00 56.00 0.0000 0.6722 0.0000 0.0735 471.73 0.00 0.31 1425.89 422.74 1814.76 193.00 3240.65 615.74 0.00 0.31 1762.94 408.22 1385.17 191.54 3148.10 600.07 1.29 10 10 10 011/06/2024 21:3021:31 Diverted Liquid Flow from 1.5'' Turbine Meter through 2'' Turbine Meter.21:39 Observed Well Slugging.1530.31 101.58 0.00 0.00 213.13 63.37 146.80 54.38 117.61 56.54 64 0.00 89.79 89.83 54.20 53.55 28.4 39000 8 0.680 0.10 0.0 44.00 0.00 44.00 44.00 0.0000 0.6489 0.0000 0.0870 334.91 0.00 0.31 1937.70 463.11 1522.48 224.72 3460.18 687.82 0.00 0.31 1997.42 449.83 1331.61 219.28 3329.03 669.42 1.50 10 10 10 011/06/2024 22:0022:01 Gas Rate too low to be measured. Diverted Gas Flow from 3'' Coriolis meter through 0.5'' Coriolis Meter.1527.49 101.59 0.00 0.00 229.30 64.15 156.71 55.24 120.79 56.90 64 0.00 84.71 83.28 54.70 54.29 28.4 34000 8 0.680 0.10 0.0 40.00 0.00 40.00 40.00 0.0000 0.6177 0.0000 0.0999 304.31 0.00 0.31 2030.05 505.40 1353.37 252.91 3383.42 758.31 7.96 0.48 1846.89 488.31 1329.44 246.98 3184.29 735.76 1.69 10 10 10 011/06/2024 22:3022:31 Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter.22:35 Lowered Separator Pressure. 1530.08 101.58 0.00 3.11 248.29 64.91 173.85 56.53 137.76 57.61 64 0.00 103.22 102.23 54.36 54.91 28.4 34000 8 0.680 0.10 0.0 42.00 0.25 41.75 41.75 0.0000 0.4797 0.0000 0.1099 253.38 8.13 0.48 1893.63 544.84 1357.24 281.20 3250.86 826.04 6.22 0.61 1680.44 523.32 1425.26 276.67 3111.92 800.60 1.87 10 10 10 011/06/2024 23:00 1506.70 101.57 0.00 0.00 218.79 64.69 142.08 55.55 108.24 58.00 64 0.00 70.48 68.34 55.50 55.12 28.4 32000 8 0.680 0.10 0.0 46.00 0.20 45.80 45.80 0.0000 0.8535 0.0000 0.1276 443.90 7.09 0.63 1922.73 584.90 1624.74 315.04 3547.48 899.94 3.26 0.68 1726.03 559.28 1527.37 308.49 3256.66 868.44 2.10 10 10 10 011/06/2024 23:30Applied CMSF 0.933.1498.31 101.56 0.00 0.00 220.76 65.26 143.27 57.13 106.26 58.20 64 0.00 72.19 71.95 56.06 55.33 28.4 32000 8 0.680 0.10 0.0 47.00 0.10 46.90 46.90 0.0000 0.8885 0.0000 0.1461 477.22 3.51 0.70 1861.84 623.69 1644.45 349.30 3506.28 972.99 3.29 0.74 1909.85 599.07 1379.70 337.23 3292.84 937.04 2.33 10 10 10 011/07/2024 00:00 1492.97 101.56 0.00 0.00 218.79 65.67 141.18 56.64 106.92 58.84 64 0.00 71.68 72.09 56.54 55.97 28.4 34000 8 0.680 0.10 0.0 42.00 0.10 41.90 41.90 0.0000 0.9029 0.0000 0.1650 477.96 3.25 0.77 1889.01 663.04 1362.30 377.68 3251.30 1040.73 0.00 0.74 1432.93 628.92 1823.73 375.23 3256.66 1004.89 2.52 10 10 10 011/07/2024 00:3000:46 Observed Well Slugging.1488.94 101.56 0.00 0.00 216.30 65.54 138.66 56.67 105.57 58.42 64 0.00 72.67 69.93 56.46 56.35 28.4 34000 8 0.680 0.10 0.0 56.00 0.00 56.00 56.00 0.0000 0.9331 0.0000 0.1844 648.90 0.00 0.77 1438.12 693.00 1830.33 415.82 3268.45 1108.82 3.44 0.82 1787.54 666.16 1646.60 409.53 3437.58 1076.51 2.77 10 10 10 011/07/2024 01:00Collected Tracerco Sample.1476.26 101.55 0.00 0.00 222.55 65.77 145.42 57.27 110.59 58.87 64 0.00 70.92 69.49 57.11 57.25 28.4 34000 8 0.680 0.10 0.0 48.00 0.10 47.90 47.90 0.0000 0.8796 0.0000 0.2027 523.15 3.23 0.84 1681.59 728.03 1546.03 448.03 3227.62 1176.06 3.43 0.89 2026.04 708.37 1404.49 438.79 3433.96 1148.05 2.99 10 10 10 011/07/2024 01:30 1469.08 101.55 0.00 0.00 219.90 66.16 144.05 56.81 108.32 58.98 64 0.00 72.38 69.72 58.24 58.15 28.4 34000 8 0.680 0.10 0.0 41.00 0.10 40.90 40.90 0.0000 0.9539 0.0000 0.2226 494.17 3.27 0.90 1930.68 768.25 1336.12 475.87 3266.80 1244.12 4.94 0.99 2074.49 751.59 1213.41 464.07 3292.84 1216.65 3.17 10 10 10 011/07/2024 02:00 1461.63 101.54 0.00 0.00 228.58 66.64 152.89 57.80 113.60 59.65 64 0.00 72.89 71.40 59.25 59.10 28.4 36000 8 0.680 0.10 0.0 37.00 0.15 36.85 36.85 0.0000 0.9468 0.0000 0.2423 460.53 4.88 1.00 2056.35 811.08 1199.94 500.88 3256.29 1311.96 3.22 1.06 2224.62 797.93 996.24 484.83 3224.09 1283.82 3.34 10 10 10 011/07/2024 02:30 1451.37 101.54 0.00 0.00 233.28 67.05 152.13 58.81 111.49 59.89 64 0.00 70.37 69.26 59.81 59.66 28.4 36000 8 0.680 0.10 0.0 31.00 0.10 30.90 30.90 0.0000 0.9837 0.0000 0.2628 431.47 3.30 1.07 2280.28 858.58 1019.69 522.13 3299.96 1380.71 0.00 1.06 2084.26 841.36 1172.40 509.25 3256.66 1351.66 3.48 10 10 10 011/07/2024 03:00 1444.92 101.57 0.00 0.00 238.48 67.53 156.57 58.07 115.42 60.14 64 0.00 73.65 73.72 59.44 59.36 28.4 34000 8 0.680 0.10 0.0 36.00 0.00 36.00 36.00 0.0000 1.0016 0.0000 0.2837 473.09 0.00 1.07 2117.55 902.68 1191.12 546.96 3308.67 1449.64 0.00 1.06 1997.42 882.97 1331.61 536.99 3329.03 1421.02 3.65 10 10 10 011/07/2024 03:3003:54 Observed Well Slugging.1612.51 101.62 0.00 0.00 284.91 68.90 185.23 59.89 129.74 61.35 64 0.00 77.59 73.89 60.00 59.50 30.1 34000 8 0.683 0.10 0.0 40.00 0.00 40.00 40.00 0.0000 1.1115 0.0000 0.3068 487.78 0.00 1.07 2279.55 950.16 1519.70 578.64 3799.25 1528.79 0.00 1.06 2477.95 934.59 1393.85 566.03 3871.80 1501.68 3.86 10 10 10 011/07/2024 04:00Increased Expro adjustable Choke to 72/64ths as per Santos WSS.04:01 Increased Expro adjustable Choke to 82/64ths as per Santos WSS.04:02 Increased Expro adjustable Choke to 92/64ths as per Santos WSS.04:03 Increased Expro adjustable Choke to 102/64ths as per Santos WSS.04:04 Increased Expro adjustable Choke to 128/64ths as per Santos WSS.1692.85 101.54 0.00 0.00 133.85 69.08 102.79 59.94 88.13 61.47 72 0.00 67.71 68.44 59.50 59.91 30.1 31000 8 0.683 0.10 0.0 36.00 0.00 36.00 36.00 0.0000 0.8127 0.0000 0.3238 385.69 0.00 1.07 2107.90 994.06 1185.69 603.35 3293.59 1597.41 0.00 1.06 2403.78 984.67 889.07 584.55 3292.84 1570.28 4.02 10 10 10 011/07/2024 04:3004:50 Observed Well Slugging.1662.52 101.48 0.00 0.00 196.85 70.11 92.60 62.31 84.89 64.11 128 0.00 65.14 67.48 61.82 62.93 30.1 31000 8 0.683 0.10 0.0 27.00 0.00 27.00 27.00 0.0000 0.2938 0.0000 0.3299 112.69 0.00 1.07 2607.66 1048.37 964.48 623.46 3572.14 1671.83 0.00 1.06 2697.60 1040.87 1101.84 607.51 3799.43 1649.44 4.16 10 10 10 011/07/2024 05:00Gas Rate too low to be measured 3'' Coriolis Meter. Diverted flow through 0.5'' Coriolis Meter.05:03 Sparged Separator; Trace Solids Observed.05:08 Lowered Separator Pressure.05:15 Diverted Gas flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter.1682.17 101.45 0.00 0.00 159.55 72.61 96.36 64.26 88.02 65.68 128 0.00 67.37 68.14 61.93 63.42 30.1 32000 8 0.683 0.10 0.0 29.00 0.00 29.00 29.00 0.0000 0.1636 0.0000 0.3333 69.58 0.00 1.07 2351.27 1097.34 960.38 643.48 3311.64 1740.82 8.23 1.23 1712.28 1076.54 1572.33 640.27 3292.84 1718.04 4.29 10 10 10 011/07/2024 05:30 1674.63 101.43 0.00 0.00 213.93 70.35 105.99 62.55 93.44 63.98 128 0.00 63.12 62.94 62.65 64.36 30.1 32000 8 0.683 0.10 0.0 48.00 0.25 47.75 47.75 0.0000 0.6244 0.0000 0.3463 326.21 9.17 1.26 1916.25 1137.22 1751.21 680.01 3667.46 1817.23 7.45 1.38 2124.43 1120.80 1595.18 673.50 3727.06 1795.68 4.53 10 10 10 011/07/2024 06:0006:02 Diverted Gas Flow from 3'' Coriolis Meter through 0.5'' Coriolis Meter.1690.34 101.40 0.00 0.00 196.71 73.48 103.07 67.02 94.52 67.29 128 0.00 65.42 65.34 63.24 64.52 30.1 34000 8 0.683 0.10 0.0 43.00 0.20 42.80 42.80 0.0000 0.1142 0.0000 0.3487 60.91 6.56 1.40 1876.99 1176.29 1404.46 709.30 3281.46 1885.59 13.75 1.67 1100.03 1143.72 2323.81 721.91 3437.58 1867.30 4.73 10 10 10 011/07/2024 06:3006:41 Observed Well Slugging.1689.25 101.36 0.00 0.00 192.54 73.18 117.62 66.47 109.28 67.32 128 0.00 83.94 85.50 60.10 65.16 30.1 34000 8 0.683 0.10 0.0 68.00 0.40 67.60 67.60 0.0000 0.3715 0.0000 0.3564 345.22 13.32 1.68 1079.04 1198.71 2251.34 756.26 3330.38 1954.97 8.96 1.86 1146.34 1167.60 2427.02 772.47 3582.32 1941.93 5.04 10 10 10 011/07/2024 07:00Collected Tracerco sample.1689.87 101.34 0.00 0.00 174.09 74.32 89.09 68.81 76.54 68.82 128 0.00 54.09 54.85 57.30 65.20 30.1 36000 8 0.683 0.10 0.0 68.00 0.25 67.75 67.75 0.0000 0.2774 0.0000 0.3622 290.88 7.41 1.83 955.41 1218.58 2007.11 798.11 2962.52 2016.69 6.08 1.98 972.66 1187.86 2060.81 815.41 3039.55 2005.26 5.32 10 10 10 011/07/2024 07:30 1715.88 101.34 0.00 0.00 182.75 73.99 105.87 67.09 98.33 67.98 128 0.00 72.83 73.81 55.38 65.45 30.1 36000 8 0.683 0.10 0.0 68.00 0.20 67.80 67.80 0.0000 0.3993 0.0000 0.3705 362.76 6.86 1.98 1103.78 1241.51 2324.10 846.60 3427.88 2088.11 5.59 2.10 857.22 1205.72 2864.25 875.08 3727.06 2082.90 5.64 10 10 10 011/07/2024 08:00 1716.49 101.30 0.00 0.00 207.62 74.85 120.18 67.68 112.95 69.63 128 0.00 83.58 83.84 54.51 66.66 30.1 34000 8 0.683 0.10 0.0 77.00 0.15 76.85 76.85 0.0000 0.3330 0.0000 0.3775 394.63 5.48 2.09 846.32 1259.09 2809.48 905.18 3655.80 2164.27 5.97 2.22 955.29 1225.63 3019.10 937.98 3980.36 2165.83 6.03 10 10 10 011/07/2024 08:30 1721.22 101.28 0.00 0.00 165.98 75.17 107.66 67.57 101.75 69.30 128 0.00 67.41 67.04 53.18 66.78 30.1 34000 8 0.683 0.10 0.0 76.00 0.15 75.85 75.85 0.0000 0.3867 0.0000 0.3855 455.48 5.29 2.20 852.10 1276.78 2676.27 961.00 3528.37 2237.78 17.01 2.58 903.07 1244.44 2481.32 989.67 3401.40 2236.69 6.41 10 10 10 011/07/2024 09:00 1713.42 101.26 0.00 0.00 213.85 76.43 102.93 69.48 90.05 70.22 128 0.00 58.02 58.79 52.27 67.41 30.1 33000 8 0.683 0.10 0.0 73.00 0.05 72.95 72.95 0.0000 0.3157 0.0000 0.3921 331.14 1.77 2.24 955.91 1296.64 2577.96 1014.76 3533.87 2311.40 0.00 2.58 724.06 1259.52 2424.04 1040.17 3148.10 2302.28 6.77 10 10 10 011/07/2024 09:3009:42 Air Supply was lost to Hydraulic ESD Panel causing Fail Safe Close of ESD System. Well Shut-in at WH SSV and Expro SSV. 09:45Discontinued all Chemical Injection.1715.36 101.26 0.00 0.00 191.35 75.46 111.69 69.10 101.20 70.07 128 0.00 74.29 74.15 51.95 67.03 28.2 33000 8 0.714 0.10 0.0 77.00 0.00 77.00 77.00 0.0000 0.3803 0.0000 0.4000 461.36 0.00 2.24 827.16 1313.81 2769.18 1072.51 3596.34 2386.32 0.00 2.58 1432.93 1289.38 2547.43 1093.24 3980.36 2385.20 7.15 10 10 10 011/07/2024 10:00 1786.71 101.16 0.00 0.00 154.44 87.00 24.66 59.53 14.19 68.09 128 0.00 10.73 12.91 51.13 66.62 28.2 33000 8 0.714 0.10 0.0 64.00 0.00 64.00 64.00 0.0000 0.1550 0.0000 0.4032 267.65 0.00 2.24 580.27 1325.87 1031.59 1094.03 1611.85 2419.90 0.00 2.58 495.01 1299.69 880.02 1111.58 1375.03 2413.85 7.29 0 0 0 011/07/2024 10:30 1796.64 101.08 0.00 0.00 363.51 99.52 361.62 54.41 12.53 62.36 0 0.00 9.17 11.45 50.86 65.74 28.2 33000 8 0.714 0.10 0.0 64.00 0.00 64.00 64.00 0.0000 0.0000 0.0000 0.4032 0.00 0.00 2.24 11.28 1326.11 20.05 1094.45 31.33 2420.55 0.00 2.58 0.00 1299.69 0.00 1111.58 0.00 2413.85 7.30 0 0 0 011/07/2024 11:0011:06 Opened Well on 64/64ths adjustable Choke as per Santos WSS.1802.37 100.99 0.00 0.00 424.78 107.60 426.45 54.03 12.20 56.49 0 0.00 9.07 11.19 50.52 63.86 28.2 33000 8 0.714 0.10 0.0 64.00 0.00 64.00 64.00 0.0000 0.0000 0.0000 0.4032 0.00 2.24 0.00 1326.11 0.00 1094.45 0.00 2420.55 0.00 2.58 0.00 1299.69 0.00 1111.58 0.00 2413.85 7.30 0 0 0 011/07/2024 11:30 1738.36 101.27 0.00 0.00 239.35 68.93 170.82 61.22 138.28 62.07 64 0.00 100.15 100.73 50.80 60.09 28.2 33000 8 0.714 0.10 0.0 64.00 0.00 64.00 64.00 0.0000 0.4252 0.0000 0.4121 460.83 0.00 2.24 925.16 1345.33 1644.73 1128.76 2569.89 2474.09 2.61 2.63 937.92 1319.23 1664.80 1146.26 2605.33 2468.12 7.53 10 10 10 011/07/2024 12:00 1748.27 101.25 0.00 0.00 92.06 72.18 59.14 64.86 44.72 66.60 64 0.00 31.61 33.10 49.61 62.43 28.2 34000 8 0.714 0.10 0.0 64.00 0.10 63.90 63.90 0.0000 0.2903 0.0000 0.4182 242.44 3.32 2.31 1198.35 1370.28 2121.18 1172.97 3319.53 2543.25 0.00 2.63 2077.02 1362.50 890.15 1164.81 2967.18 2529.94 7.82 10 10 10 011/07/2024 12:30Increased Expro adjustable Choke to 68/64ths as per Santos WSS.1725.53 101.26 0.00 0.00 203.63 74.07 130.63 67.36 100.94 69.30 68 0.00 72.25 72.46 50.08 65.61 28.2 34000 8 0.714 0.10 0.0 30.00 0.00 30.00 30.00 0.0000 0.1774 0.0000 0.4218 80.08 0.00 2.31 2215.12 1416.42 949.34 1192.76 3164.45 2609.18 0.00 2.63 965.42 1382.61 2363.61 1214.05 3329.03 2599.30 8.10 10 10 10 011/07/2024 13:00Collected Tracerco Sample.13:00-13:14 Increased Expro adjustable Choke from 68/64ths to 128/64ths over 14 minutes as perSantos WSS (4/64ths per minute).1719.29 101.27 0.00 0.00 215.20 74.70 135.57 67.33 114.22 69.88 72 0.00 85.93 86.45 49.63 66.01 28.2 33000 8 0.714 0.10 0.0 71.00 0.00 71.00 71.00 0.0000 0.3541 0.0000 0.4292 327.32 0.00 2.31 1084.37 1438.95 2654.84 1248.12 3739.21 2687.08 0.00 2.63 728.77 1397.80 3106.85 1278.77 3835.62 2679.20 8.43 10 10 10 011/07/2024 13:30 1710.32 101.27 0.00 0.00 217.27 75.44 129.30 69.22 121.38 70.72 128 0.00 90.01 90.05 49.60 66.82 28.2 33000 8 0.714 0.10 0.0 81.00 0.00 81.00 81.00 0.0000 0.3616 0.0000 0.4368 494.53 0.00 2.31 733.82 1454.19 3128.39 1313.35 3862.21 2767.54 0.00 2.63 1567.54 1430.45 2557.56 1332.06 4125.10 2765.14 8.78 10 10 10 011/07/2024 14:0014:05 Sparged Separator; Light Solids Observed.1703.88 101.28 0.00 0.00 238.48 75.71 147.87 69.20 140.14 70.98 128 0.00 108.98 108.98 49.74 67.41 28.2 33000 8 0.714 0.10 0.0 62.00 0.00 62.00 62.00 0.0000 0.4157 0.0000 0.4454 249.41 0.00 2.31 1671.10 1488.91 2726.54 1370.24 4397.64 2859.16 0.00 2.63 1750.63 1466.93 2519.21 1384.54 4269.84 2854.10 9.17 10 10 10 011/07/2024 14:30 1699.55 101.28 0.00 0.00 239.97 75.65 150.34 69.51 143.09 71.02 128 0.00 112.01 111.78 49.71 67.45 28.2 33000 8 0.714 0.10 0.0 59.00 0.00 59.00 59.00 0.0000 0.4462 0.0000 0.4547 240.01 0.00 2.31 1863.96 1527.65 2682.29 1426.22 4546.25 2953.87 0.00 2.63 2084.26 1510.35 2257.95 1431.58 4342.21 2944.56 9.57 10 10 10 011/07/2024 15:00 1696.81 101.28 0.00 0.00 243.53 75.47 153.94 68.71 146.69 71.04 128 0.05 117.58 117.36 49.65 67.61 28.2 32000 8 0.714 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.4660 0.0000 0.4644 215.46 0.00 2.31 2167.54 1572.71 2348.17 1475.24 4515.71 3047.95 0.00 2.63 2049.52 1553.05 2220.32 1477.84 4269.84 3033.52 9.83 10 10 10 011/07/2024 15:30 1692.76 101.28 0.00 0.00 248.95 75.82 157.35 69.58 149.71 71.22 128 0.05 118.75 118.44 49.63 67.69 29.3 32000 8 0.676 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.5024 0.0000 0.4749 231.55 0.00 2.31 2174.72 1617.91 2355.95 1524.42 4530.68 3142.34 0.00 2.63 2257.95 1600.09 2446.11 1528.80 4704.06 3131.52 10.16 10 10 10 011/07/2024 16:00Applied CMSF 0.942.1693.01 101.27 0.00 0.00 253.45 76.07 159.28 69.58 151.91 71.33 128 0.05 119.42 119.50 49.60 67.85 29.3 31000 8 0.676 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.5138 0.0000 0.4856 237.27 0.00 2.31 2170.66 1663.03 2351.55 1573.52 4522.21 3236.55 0.00 2.63 2223.21 1646.40 2408.48 1578.97 4631.69 3228.01 10.49 10 10 10 011/07/2024 16:30Collected Composition Sample.1690.10 101.27 0.00 0.00 255.96 75.90 162.68 70.46 155.38 71.45 128 0.05 122.94 122.85 50.16 67.94 29.3 31000 8 0.676 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.5196 0.0000 0.4964 237.99 0.00 2.31 2188.64 1708.51 2371.02 1623.03 4559.66 3331.54 0.00 2.63 2442.49 1697.29 2442.49 1629.86 4884.99 3329.78 10.82 10 10 10 011/07/2024 17:00 1687.76 101.27 0.00 0.00 255.90 76.19 164.57 70.41 157.27 71.48 128 0.05 124.52 124.83 50.24 68.05 29.3 32000 8 0.676 0.10 0.0 50.00 0.00 50.00 50.00 0.0000 0.5336 0.0000 0.5075 231.74 0.00 2.31 2308.02 1756.49 2308.02 1671.22 4616.05 3427.71 0.00 2.63 2362.16 1746.50 2559.01 1683.17 4921.17 3432.31 11.14 10 10 10 011/07/2024 17:30 1685.59 101.27 0.00 0.00 259.34 75.92 164.65 69.80 158.09 71.36 128 0.05 126.70 127.62 50.23 68.05 29.3 32000 8 0.676 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.5405 0.0000 0.5188 244.53 0.00 2.31 2215.84 1802.53 2400.49 1721.35 4616.33 3523.88 0.00 2.63 2188.47 1792.09 2370.85 1732.57 4559.32 3527.29 11.47 10 10 10 011/07/2024 18:00 1683.29 101.27 0.00 0.00 260.46 75.93 169.35 70.15 163.94 71.37 128 0.05 133.21 133.77 50.29 68.02 29.3 31000 8 0.676 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.5504 0.0000 0.5303 248.12 0.00 2.31 2224.11 1848.75 2409.45 1771.67 4633.55 3620.42 0.00 2.63 2101.63 1835.88 2276.77 1780.00 4378.40 3618.51 11.80 10 10 10 011/07/2024 18:30 1680.10 101.28 0.00 0.00 264.00 75.73 172.87 69.55 164.13 70.83 128 0.05 133.36 133.37 50.16 67.86 29.3 31000 8 0.676 0.10 0.0 52.00 0.00 52.00 52.00 0.0000 0.5637 0.0000 0.5420 261.75 0.00 2.31 2159.16 1893.61 2339.09 1820.52 4498.25 3714.13 0.00 2.63 2263.02 1883.02 2006.82 1821.81 4269.84 3707.46 12.12 10 10 10 011/07/2024 19:00Gas remained entrained in oil causing higher liquid rates being measured across Turbine Meters.Increased Chemical Injection of Defoamer to 16 gal/day.Applied CMSF 0.650 to compensate for high Liquid Rates caused by reduced Gas Breakout Rate.Collected Tracerco Sample.19:16Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter.19:16 Lowered Separator Pressure. 1675.48 101.28 0.00 0.00 273.32 75.78 175.60 70.33 167.60 70.82 128 0.05 137.35 137.23 50.10 67.73 29.3 30000 8 0.676 0.10 0.0 47.00 0.00 47.00 47.00 0.0000 0.5688 0.0000 0.5539 241.61 0.00 2.31 2359.34 1942.66 2092.24 1864.21 4451.58 3806.87 0.00 2.63 2232.98 1929.54 2145.41 1866.50 4378.40 3798.68 12.43 16 10 10 011/07/2024 19:30Gas Breakout returned to normal rate.Applied CMSF 0.914.Increased Separator Pressure.1654.43 101.29 0.00 0.00 270.67 75.72 135.13 69.11 122.86 70.97 128 0.05 78.96 77.98 68.41 67.87 29.3 30000 8 0.676 0.10 0.0 49.00 0.00 49.00 49.00 0.0000 0.8549 0.0000 0.5717 378.58 0.00 2.31 2262.30 1989.70 2173.58 1909.58 4435.89 3899.29 0.00 2.63 2358.91 1978.69 2091.86 1910.08 4450.77 3891.40 12.85 16 10 10 011/07/2024 20:00 1660.03 101.30 0.00 0.00 252.26 76.02 122.91 70.19 111.06 71.22 128 0.05 69.66 68.87 69.04 67.82 29.3 32000 8 0.676 0.10 0.0 47.00 0.00 47.00 47.00 0.0000 0.9991 0.0000 0.5925 468.89 0.00 2.31 2133.20 2034.09 1891.71 1949.04 4024.91 3983.14 0.00 2.63 2535.13 2031.50 1553.79 1942.45 4088.91 3976.59 13.14 16 10 10 011/07/2024 20:30 1657.63 101.31 0.00 0.00 266.29 75.88 136.17 70.40 124.21 70.94 128 0.05 77.19 78.20 68.91 68.11 29.3 32000 8 0.676 0.10 0.0 38.00 0.00 38.00 38.00 0.0000 1.0105 0.0000 0.6135 384.91 0.00 2.31 2627.60 2088.79 1610.46 1982.64 4238.06 4071.43 10.77 2.86 2583.62 2085.33 1711.65 1978.11 4306.03 4066.30 13.21 16 10 10 011/07/2024 21:00 1657.56 101.32 0.00 0.00 261.57 75.61 135.09 70.53 123.76 71.17 128 0.05 77.80 76.05 69.21 67.77 29.3 32000 8 0.676 0.10 0.0 40.00 0.25 39.75 39.75 0.0000 1.0396 0.0000 0.6352 416.88 10.36 2.52 2495.98 2140.74 1646.72 2017.00 4142.70 4157.74 21.35 3.30 2519.21 2137.81 1729.29 2014.14 4269.84 4155.25 13.45 16 10 10 011/07/2024 21:30 1654.43 101.32 0.00 0.00 266.03 75.66 142.06 70.57 128.94 71.31 128 0.05 79.14 75.78 69.18 67.94 29.8 32000 8 0.692 0.10 0.0 41.00 0.50 40.50 40.50 0.0000 1.0203 0.0000 0.6565 410.96 20.88 2.96 2485.30 2192.46 1691.67 2052.29 4176.97 4244.76 31.48 3.96 2434.53 2188.53 1731.46 2050.21 4197.47 4242.70 13.68 16 10 10 011/07/2024 22:00Applied CMSF 0.939.1650.67 101.33 0.00 0.00 264.82 75.42 135.73 70.17 126.36 71.21 128 1.00 80.08 78.44 69.13 67.86 29.8 30000 8 0.692 0.10 0.0 42.00 0.75 41.25 41.25 0.0000 1.0485 0.0000 0.6783 434.55 30.83 3.60 2415.27 2242.73 1695.83 2087.68 4111.10 4330.41 34.16 4.67 2561.90 2241.90 1673.78 2085.08 4269.84 4331.66 13.92 16 10 10 011/07/2024 22:30Sparged Separator; Trace Solids Observed.22:40Bypassed Ball Catcher.1651.83 101.33 0.00 0.00 255.20 75.48 135.47 69.42 124.56 71.26 128 1.00 76.81 74.04 68.67 67.84 29.8 30000 8 0.692 0.10 0.0 40.00 0.80 39.20 39.20 0.0000 1.0563 0.0000 0.7003 413.03 33.68 4.30 2559.83 2296.01 1650.42 2122.11 4210.24 4418.12 42.70 5.56 2476.51 2293.50 1750.63 2121.55 4269.84 4420.61 14.15 16 10 10 0Fluid Properties BS&W PropertiesSeparatorPROJECT DESIGN NUMBER:LOCATION / FIELD:WELL NUMBER:Chemical Injection RatesRates and Cumulatives (Test Separator Flow Meters @ Stock Conditions)Rates and Cumulatives (Based on BS&W %)(Tank Farm Straps)Well Head Choke Gas Properties Gas Rates & CumulativesNDBi-016 WELL CLEAN-UP DATA SHEETWT-XAK-0127.4PIKKA - NDB NDBi-01606-Nov-2024 @ 12:1711-Nov-2024 @ 00:00Santos Adam Phillips / Jack Landry | Pere KeniyeJose Gonzalez / Dan BonnarAustin Stewart | Frank TowerSharon Oyao / Travis Stacey | Yehia ElzenyCLIENT:SANTOS WELL TEST LEAD:SANTOS REP/SUPERVISORS:EXPRO SUPERVISORS :EXPRO DAQ ENGINEERS:WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 20 START DATE:END DATE:Time DPI Heater GOR Frac WaterTime & Date COMMENTS BHP BHT I/A Pressure O/A Pressure Well Head PressureWell Head TemperatureU/S Choke PressureU/S Choke TemperatureD/S Choke PressureD/S Choke TemperatureChoke Size U/S DPI Solids, Mud & Carbolite D/S Heater PressureSeparator PressureGas Temperature Oil Temperature Corrected API WaterSalinity pH Gas S.G CO2 H2S Total Choke BS&W(Solids, Mud, Carbolite & Water)Solids, Mud & Carbolite @ ChokeWater Cut @ Choke Separator Oil Leg BS&W (2-Phase)Nitrogen Injection RateTotal Gas Rate (N2+Formation)Nitrogen InjectionCumulative Total Gas Cumulative (N2+Formation)Total GOR Solids, Mud & Carbolite RateSolids, Mud, & Carbolite CumulativeOil Rate Oil Cumulative Water RateWater CumulativeTotal Fluid RateTotal Fluid CumulativeTank Farm StrapSolids, Mud & Carbolite RateTank Farm StrapSolids, Mud, & Carbolite CumulativeTank Farm StrapOil RateTank Farm StrapOil CumulativeTank Farm StrapWater RateTank Farm StrapWater CumulativeTank Farm Strap Total Rate (Tank 1 - Tank 10)Tank Farm Strap Total Cumulative(Tank 1 - Tank 10)Percentage of Frac Water RecoveredDefoamer(D/S of Choke Manifold Data Header)Methanol (MeOH)(Separator Gas Line)Demulsifier(D/S of Choke Manifold Data Header)H2S Scavenger(U/S of Choke Manifold Data Header)(mm-dd-yyyy hh:mm) (psig)(F)(psig) (psig) (psig)(F)(psig)(F)(psig)(F)(64ths) (%) (psig) (psig)(F) (F)(API@60°)(ppm) (pH) (Air = 1) (%) (ppm) (%) (%) (%) (%) (MMscf/d) (MMscf/d) (MMscf) (MMscf) (scf/stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb)(stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (%) (gal/d) (gal/d) (gal/d) (gal/d)Fluid Properties BS&W PropertiesSeparatorPROJECT DESIGN NUMBER:LOCATION / FIELD:WELL NUMBER:Chemical Injection RatesRates and Cumulatives (Test Separator Flow Meters @ Stock Conditions)Rates and Cumulatives (Based on BS&W %)(Tank Farm Straps)Well Head Choke Gas Properties Gas Rates & CumulativesNDBi-016 WELL CLEAN-UP DATA SHEETWT-XAK-0127.4PIKKA - NDB NDBi-01606-Nov-2024 @ 12:1711-Nov-2024 @ 00:00Santos Adam Phillips / Jack Landry | Pere KeniyeJose Gonzalez / Dan BonnarAustin Stewart | Frank TowerSharon Oyao / Travis Stacey | Yehia ElzenyCLIENT:SANTOS WELL TEST LEAD:SANTOS REP/SUPERVISORS:EXPRO SUPERVISORS :EXPRO DAQ ENGINEERS:11/07/2024 23:00 1640.42 101.34 0.00 0.00 276.41 76.11 149.68 68.99 137.27 71.56 128 0.25 79.61 76.30 68.99 68.24 29.8 30000 8 0.692 0.10 0.0 42.00 1.00 41.00 41.00 0.0000 1.0635 0.0000 0.7225 414.87 43.49 5.21 2566.13 2349.41 1783.24 2159.32 4349.37 4508.73 43.42 6.46 2344.79 2342.35 1953.99 2162.26 4342.21 4511.07 14.40 16 10 10 011/07/2024 23:3023:34 Diverted Flow through Ball Catcher.1638.86 101.35 0.00 0.00 262.13 76.53 133.52 70.62 119.95 72.08 128 0.25 83.58 78.69 70.03 69.42 29.8 30000 8 0.692 0.10 0.0 46.00 1.00 45.00 45.00 0.0000 1.0976 0.0000 0.7453 463.80 43.09 6.11 2369.71 2398.72 1938.85 2199.78 4308.56 4598.49 42.70 7.35 2391.11 2392.16 1836.03 2200.51 4269.84 4600.03 14.67 16 10 10 011/08/2024 00:00Lowered Separator Pressure.1637.54 101.34 0.00 0.00 268.52 75.85 139.77 69.37 127.97 71.79 128 0.25 74.90 73.63 70.03 69.63 29.8 30000 8 0.692 0.10 0.0 44.00 1.00 43.00 43.00 0.0000 1.1038 0.0000 0.7683 446.94 43.38 7.01 2472.80 2450.17 1865.44 2238.71 4338.24 4688.87 43.42 8.26 2865.86 2451.87 1432.93 2230.37 4342.21 4690.49 14.93 16 10 10 011/08/2024 00:30 1636.84 101.34 0.00 0.00 260.38 76.19 134.34 69.21 121.71 71.57 128 0.05 69.13 66.42 69.93 69.31 29.8 30000 8 0.692 0.10 0.0 34.00 1.00 33.00 33.00 0.0000 1.1546 0.0000 0.7924 389.85 44.24 7.93 2963.76 2511.87 1459.76 2269.16 4423.52 4781.03 43.42 9.16 2735.59 2508.86 1563.20 2262.93 4342.21 4780.95 15.13 16 10 10 011/08/2024 01:00Collected Tracerco Sample.1631.05 101.34 0.00 0.00 272.92 76.24 143.93 70.24 133.17 71.77 128 0.70 71.76 66.82 70.22 69.52 29.8 30000 8 0.692 0.10 0.0 37.00 1.00 36.00 36.00 0.0000 1.1553 0.0000 0.8164 410.42 44.02 8.85 2817.20 2570.51 1584.67 2302.22 4401.87 4872.73 43.78 10.08 2627.04 2563.59 1707.57 2298.51 4378.40 4872.17 15.35 16 10 10 011/08/2024 01:30 1628.81 101.34 0.00 0.00 292.57 76.73 145.82 70.61 132.43 72.10 128 0.90 70.69 67.90 70.57 69.73 29.8 30000 8 0.692 0.10 0.0 40.00 1.00 39.00 39.00 0.0000 1.1583 0.0000 0.8406 429.15 44.29 9.77 2701.73 2626.74 1727.33 2338.26 4429.06 4965.01 48.56 11.09 2074.85 2606.82 2291.17 2346.24 4414.58 4964.14 15.59 16 10 10 011/08/2024 02:0001:32 Bypassed DPI Unit Side A; Flowing through DPI Side B.1621.47 101.35 0.00 0.00 268.18 76.44 149.68 71.34 138.22 71.90 128 0.90 70.28 66.83 70.62 69.92 29.8 30000 8 0.692 0.10 0.0 53.00 1.10 51.90 51.90 0.0000 1.2589 0.0000 0.8668 557.73 51.71 10.85 2261.19 2673.77 2439.83 2389.18 4701.03 5062.94 53.41 12.20 1869.32 2645.76 2528.03 2398.91 4450.77 5056.87 15.93 16 10 10 011/08/2024 02:30 1623.08 101.34 0.00 0.00 244.65 76.08 140.51 70.19 128.67 71.97 128 0.90 69.55 66.28 70.67 70.11 29.8 30000 8 0.692 0.10 0.0 53.00 1.10 51.90 51.90 0.0000 1.2227 0.0000 0.8923 550.13 50.92 11.91 2226.60 2720.07 2402.51 2439.31 4629.11 5159.38 47.04 13.18 2116.83 2689.86 2540.19 2451.83 4704.06 5154.87 16.26 16 10 10 011/08/2024 03:00 1617.30 101.35 0.00 0.00 269.92 76.03 145.36 70.34 132.04 71.59 128 0.20 74.82 69.76 70.11 69.58 29.8 30000 8 0.692 0.10 0.0 55.00 1.00 54.00 54.00 0.0000 1.2301 0.0000 0.9179 582.62 45.98 12.87 2115.30 2764.06 2483.17 2491.13 4598.47 5255.19 22.43 13.65 1660.17 2724.45 2804.34 2510.25 4486.95 5248.35 16.61 16 10 10 011/08/2024 03:30 1612.72 101.35 0.00 0.00 273.78 76.41 154.48 70.37 140.11 72.19 128 0.20 74.51 70.42 70.81 69.76 29.6 32000 8 0.700 0.10 0.0 63.00 0.50 62.50 62.50 0.0000 1.2798 0.0000 0.9446 714.83 23.93 13.37 1794.77 2801.36 2991.28 2553.54 4786.04 5354.89 48.13 14.65 2117.55 2768.56 2646.94 2565.40 4812.62 5348.61 17.02 16 10 10 011/08/2024 04:004:05 Sparged Separator; Trace Solids Observed.1611.31 101.34 0.00 0.00 289.21 76.57 157.58 70.75 143.41 71.99 128 0.20 71.83 66.95 70.51 69.92 29.6 30000 8 0.700 0.10 0.0 56.00 1.00 55.00 55.00 0.0000 1.2553 0.0000 0.9707 592.19 47.20 14.35 2124.01 2845.52 2596.01 2607.71 4720.02 5453.23 47.76 15.64 2722.57 2825.28 2006.10 2607.19 4776.43 5448.12 17.38 16 10 10 011/08/2024 04:30 1608.93 101.35 0.00 0.00 273.76 76.34 156.81 70.48 143.43 71.49 128 0.20 76.35 71.49 70.73 69.85 29.6 30000 8 0.700 0.10 0.0 43.00 1.00 42.00 42.00 0.0000 1.2762 0.0000 0.9973 472.94 46.58 15.32 2701.49 2901.74 1956.25 2648.53 4657.74 5550.26 46.32 16.61 2454.80 2876.42 2130.58 2651.58 4631.69 5544.61 17.66 16 10 10 011/08/2024 05:00 1607.31 101.35 0.00 0.00 263.05 76.65 148.23 71.01 134.24 71.96 128 0.50 72.35 68.94 71.07 69.95 29.6 30000 8 0.700 0.10 0.0 47.00 1.00 46.00 46.00 0.0000 1.2739 0.0000 1.0238 505.09 46.77 16.29 2525.57 2954.28 2151.41 2693.42 4676.98 5647.70 23.70 17.10 3081.16 2940.62 1635.39 2685.65 4740.25 5643.37 17.96 16 10 10 011/08/2024 05:30 1604.97 101.33 0.00 0.00 274.67 76.36 158.38 70.40 144.17 71.46 128 0.50 73.68 67.88 70.06 69.64 29.6 30000 8 0.700 0.10 0.0 35.00 0.50 34.50 34.50 0.0000 1.2868 0.0000 1.0506 413.53 23.77 16.79 3114.30 3019.11 1640.36 2727.65 4754.66 5746.76 23.88 17.60 3343.50 3010.27 1409.05 2715.00 4776.43 5742.88 18.18 16 10 10 011/08/2024 06:00 1601.91 101.32 0.00 0.00 270.43 75.75 152.17 71.05 138.48 71.38 128 0.05 68.63 67.31 70.06 69.58 29.6 30000 8 0.700 0.10 0.0 30.00 0.50 29.50 29.50 0.0000 1.3378 0.0000 1.0785 394.92 24.04 17.29 3389.52 3089.69 1418.31 2757.23 4807.83 5846.92 24.42 18.11 2100.54 3054.03 2760.02 2772.50 4884.99 5844.65 18.38 16 10 10 011/08/2024 06:30 1600.99 101.32 0.00 0.00 304.40 76.67 174.34 71.70 160.74 71.57 128 0.05 72.15 65.89 70.19 69.36 29.6 30000 8 0.700 0.10 0.0 57.00 0.50 56.50 56.50 0.0000 1.2934 0.0000 1.1055 618.12 24.10 17.79 2096.73 3133.28 2723.34 2814.06 4820.06 5947.34 11.85 18.36 2796.75 3112.30 1931.65 2812.75 4740.25 5943.40 18.76 16 10 10 011/08/2024 07:00Collected Tracerco Sample.1597.01 101.32 0.00 0.00 305.77 75.47 151.06 70.47 136.14 71.06 128 0.06 69.55 65.91 69.66 69.30 29.6 30000 8 0.700 0.10 0.0 41.00 0.25 40.75 40.75 0.0000 1.2819 0.0000 1.1322 459.17 11.79 18.04 2794.69 3191.44 1922.09 2854.16 4716.77 6045.60 9.41 18.55 2869.48 3172.08 1825.18 2850.77 4704.06 6041.40 19.03 16 10 10 011/08/2024 07:30 1598.16 101.31 0.00 0.00 281.80 76.51 151.31 71.33 137.46 71.33 128 0.05 74.25 69.26 70.03 68.95 29.6 30000 8 0.700 0.10 0.0 39.00 0.20 38.80 38.80 0.0000 1.3290 0.0000 1.1599 462.58 9.40 18.23 2875.67 3251.30 1823.14 2892.20 4698.81 6143.50 9.48 18.75 2464.93 3223.43 2265.84 2897.97 4740.25 6140.16 19.28 16 10 10 011/08/2024 08:008:05 Diverted Flow through DPI Side A; Flowing through DPI Side A and Side B in Series.1593.94 101.31 0.00 0.00 288.95 76.47 157.23 71.24 143.60 71.35 128 0.05 75.07 69.13 70.20 68.94 29.6 30000 8 0.700 0.10 0.0 48.00 0.20 47.80 47.80 0.0000 1.3042 0.0000 1.1870 536.82 9.32 18.43 2432.96 3301.91 2227.88 2938.68 4660.83 6240.60 2.37 18.80 4266.22 3312.31 471.65 2907.80 4740.25 6238.91 19.59 16 10 10 011/08/2024 08:30 1595.90 101.31 0.00 0.00 271.25 76.17 134.18 70.48 121.12 70.86 128 0.10 69.24 66.74 69.77 68.37 29.6 30000 8 0.700 0.10 0.0 10.00 0.05 9.95 9.95 0.0000 1.3103 0.0000 1.2143 339.72 2.14 18.47 3857.25 3382.27 426.20 2947.57 4283.45 6329.83 10.58 19.02 2878.89 3372.29 1344.19 2935.80 4233.66 6327.11 19.65 16 10 10 011/08/2024 09:00 1593.32 101.31 0.00 0.00 302.39 75.77 154.12 70.19 139.39 70.31 128 0.00 73.28 67.54 69.16 68.32 29.6 30000 8 0.700 0.10 0.0 32.00 0.25 31.75 31.75 0.0000 1.3259 0.0000 1.2420 428.90 11.33 18.71 3093.33 3446.67 1439.02 2977.59 4532.36 6424.26 2.24 19.07 3589.56 3447.07 895.15 2954.45 4486.95 6420.59 19.85 16 10 10 011/08/2024 09:30 1590.57 101.31 0.00 0.00 297.55 76.14 151.93 70.40 136.95 71.41 128 0.05 75.68 70.35 70.09 68.34 29.5 30000 8 0.714 0.10 0.0 20.00 0.05 19.95 19.95 0.0000 1.2504 0.0000 1.2680 352.07 2.22 18.75 3552.38 3520.66 885.32 2996.05 4437.70 6516.71 6.78 19.21 3075.73 3511.15 1440.62 2984.47 4523.14 6514.82 19.97 16 10 10 011/08/2024 10:00 1590.69 101.30 0.00 0.00 280.27 75.89 143.41 69.19 129.17 70.18 128 0.00 72.47 68.48 69.16 68.23 29.5 30000 8 0.714 0.10 0.0 32.00 0.15 31.85 31.85 0.0000 1.3182 0.0000 1.2955 429.55 6.76 18.89 3070.70 3584.60 1435.10 3025.98 4505.80 6610.58 4.52 19.30 3256.66 3579.00 1261.95 3010.76 4523.14 6609.06 20.17 16 10 10 011/08/2024 10:30 1587.96 101.29 0.00 0.00 306.73 76.46 157.66 69.42 142.54 70.27 128 0.05 76.62 70.88 69.32 68.66 29.5 30000 8 0.714 0.10 0.0 28.00 0.10 27.90 27.90 0.0000 1.2626 0.0000 1.3218 391.98 4.47 18.99 3222.50 3651.70 1246.99 3051.99 4469.49 6703.70 4.56 19.40 3100.34 3643.59 1454.42 3041.06 4559.32 6704.04 20.35 16 10 10 011/08/2024 11:0011:05 Sparged Separator; Trace Solids Observed.1594.11 101.30 0.00 0.00 278.44 76.42 145.28 69.56 133.67 70.45 128 0.00 74.48 71.54 69.46 67.94 29.5 30000 8 0.714 0.10 0.0 32.00 0.10 31.90 31.90 0.0000 1.2962 0.0000 1.3488 430.34 4.43 19.08 3013.87 3714.46 1411.79 3081.44 4425.66 6795.90 4.41 19.49 2428.02 3694.17 1982.15 3082.35 4414.58 6796.01 20.54 16 10 10 011/08/2024 11:30 1585.38 101.29 0.00 0.00 296.50 75.91 147.23 68.69 133.76 70.22 128 0.00 73.58 68.75 69.00 68.10 29.5 30000 8 0.714 0.10 0.0 45.00 0.10 44.90 44.90 0.0000 1.2943 0.0000 1.3757 558.23 4.21 19.17 2321.27 3762.76 1891.56 3120.91 4212.84 6883.67 2.17 19.53 3473.77 3766.54 866.27 3100.40 4342.21 6886.47 20.81 16 10 10 011/08/2024 12:00 1591.09 101.29 0.00 0.00 286.26 76.41 147.71 69.79 135.32 70.59 128 0.00 74.68 68.21 69.32 68.16 29.5 29000 8 0.714 0.1 0.0 20.00 0.05 19.95 19.95 0.0000 1.2964 0.0000 1.4028 365.39 2.22 19.21 3548.83 3836.68 884.44 3139.35 4433.27 6976.03 2.19 19.58 3327.58 3835.86 1048.63 3122.25 4378.40 6977.69 20.93 16 10 10 011/08/2024 12:30Applied CMSF 0.953.1587.74 101.29 0.00 0.00 269.92 75.54 130.47 69.38 123.94 70.70 128 0.00 71.79 67.41 69.66 68.56 29.5 29000 8 0.714 0.10 0.0 24.00 0.05 23.95 23.95 0.0000 1.2145 0.0000 1.4281 383.38 2.08 19.26 3168.98 3902.68 997.99 3160.16 4166.97 7062.84 0.00 19.58 3245.08 3903.47 1024.76 3143.60 4269.84 7066.65 21.07 16 10 10 011/08/2024 13:00Collected Tracerco Sample.1592.90 101.29 0.00 0.00 265.22 75.17 137.72 68.73 124.32 69.52 128 0.00 72.19 70.87 68.68 67.57 29.5 29000 8 0.714 0.10 0.0 24.00 0.00 24.00 24.00 0.0000 1.2724 0.0000 1.4546 382.61 0.00 19.26 3326.71 3971.96 1050.54 3182.07 4377.26 7154.03 0.00 19.58 3660.12 3979.72 645.90 3157.05 4306.03 7156.36 21.21 16 10 10 011/08/2024 13:30 1587.07 101.28 0.00 0.00 267.59 75.14 132.74 68.41 121.02 69.98 128 0.00 71.53 69.39 69.05 68.05 29.5 29000 8 0.714 0.10 0.0 15.00 0.00 15.00 15.00 0.0000 1.2798 0.0000 1.4812 345.15 0.00 19.26 3708.30 4049.21 654.41 3195.71 4362.71 7244.92 0.00 19.58 3487.88 4052.39 818.14 3174.10 4306.03 7246.06 21.35 16 10 10 011/08/2024 14:00 1590.86 101.28 0.00 0.00 293.63 75.05 150.50 70.07 136.84 69.86 128 0.00 72.86 67.68 68.60 67.89 29.5 29000 8 0.714 0.10 0.0 19.00 0.00 19.00 19.00 0.0000 1.2427 0.0000 1.5071 370.33 0.00 19.26 3356.27 4119.11 787.27 3212.13 4143.55 7331.24 2.17 19.63 3300.08 4121.14 1039.96 3195.76 4342.21 7336.53 21.41 16 10 10 011/08/2024 14:30 1593.10 101.29 0.00 0.00 278.76 74.87 143.79 69.46 132.98 69.93 128 0.00 73.13 68.08 68.70 67.15 29.5 29000 8 0.714 0.10 0.0 24.00 0.05 23.95 23.95 0.0000 1.1853 0.0000 1.5318 368.82 2.11 19.30 3214.82 4186.07 1012.43 3233.24 4227.25 7419.31 0.00 19.63 3386.92 4191.70 846.73 3213.40 4233.66 7424.73 21.55 16 10 10 011/08/2024 15:00 1587.81 101.27 0.00 0.00 278.97 73.57 145.52 68.30 132.06 68.61 128 0.00 71.77 68.48 68.07 67.28 29.5 29000 8 0.714 0.10 0.0 20.00 0.00 20.00 20.00 0.0000 1.3350 0.0000 1.5596 394.09 0.00 19.30 3388.40 4256.65 847.10 3250.91 4235.50 7507.55 0.00 19.63 3341.33 4261.31 783.77 3229.73 4125.10 7510.67 21.67 16 10 10 011/08/2024 15:30 1589.31 101.28 0.00 0.00 280.17 73.88 137.44 68.87 124.34 69.43 128 0.00 72.35 69.27 68.97 67.65 29.9 29000 8 0.714 0.10 0.0 19.00 0.00 19.00 19.00 0.0000 1.2079 0.0000 1.5848 360.68 0.00 19.30 3349.50 4326.41 785.69 3267.29 4135.19 7593.70 0.00 19.63 3312.02 4330.31 776.89 3245.91 4088.91 7595.85 21.78 16 10 10 011/08/2024 16:00Diverted Tanks Late causing Erroneous Manual Tank Strap Rate. 1590.92 101.27 0.00 0.00 243.77 73.10 128.56 67.46 117.82 68.03 128 0.00 68.60 66.34 67.56 66.71 29.9 28000 8 0.714 0.10 0.0 21.00 0.00 21.00 21.00 0.0000 1.3183 0.0000 1.6122 390.28 0.00 19.30 3378.72 4396.79 898.14 3286.02 4276.87 7682.80 0.00 19.63 2915.07 4389.34 920.55 3266.80 3835.62 7675.76 21.91 16 10 10 011/08/2024 16:3016:35 Sparged Separator; No Solids Observed.1587.27 101.27 0.00 0.00 288.25 73.61 147.35 68.80 135.04 69.08 128 0.00 70.61 67.27 68.20 67.14 29.9 28000 8 0.714 0.10 0.0 24.00 0.00 24.00 24.00 0.0000 1.1700 0.0000 1.6366 374.37 0.00 19.30 3126.08 4461.89 987.18 3306.60 4113.26 7768.49 0.00 19.63 3312.02 4458.34 776.89 3282.98 4088.91 7760.95 22.04 16 10 10 011/08/2024 17:00 1590.08 101.27 0.00 0.00 270.25 73.30 136.55 67.78 124.12 67.88 128 0.00 69.97 67.16 67.69 66.18 29.9 28000 8 0.714 0.10 0.0 19.00 0.00 19.00 19.00 0.0000 1.2905 0.0000 1.6635 389.18 0.00 19.30 3316.54 4530.97 777.95 3322.82 4094.50 7853.80 0.00 19.63 3080.07 4522.51 972.66 3303.25 4052.73 7845.38 22.15 16 10 10 011/08/2024 17:30 1583.15 101.27 0.00 0.00 284.53 73.77 148.07 68.56 135.93 68.95 128 0.00 73.10 69.02 67.72 66.87 29.9 28000 8 0.714 0.10 0.0 24.00 0.00 24.00 24.00 0.0000 1.3252 0.0000 1.6911 407.27 0.00 19.30 3254.88 4598.76 1027.86 3344.26 4282.73 7943.02 0.00 19.63 3352.91 4592.36 736.00 3318.58 4088.91 7930.57 22.29 16 10 10 011/08/2024 18:00 1577.71 101.26 0.00 0.00 281.36 74.58 148.15 68.46 135.99 69.66 128 0.00 72.74 69.14 68.28 66.93 29.9 29000 8 0.714 0.10 0.0 18.00 0.00 18.00 18.00 0.0000 1.2703 0.0000 1.7176 360.25 0.00 19.30 3526.71 4672.22 774.16 3360.40 4300.87 8032.62 0.00 19.63 3441.93 4664.07 755.54 3334.32 4197.47 8018.01 22.40 16 10 10 011/08/2024 18:30 1585.02 101.28 0.00 0.00 259.34 74.39 132.86 67.12 121.38 68.52 128 0.00 70.91 66.76 67.45 66.37 29.9 29000 8 0.714 0.10 0.0 18.00 0.00 18.00 18.00 0.0000 1.2771 0.0000 1.7442 362.21 0.00 19.30 3526.31 4745.68 774.07 3376.54 4300.38 8122.21 0.00 19.63 3415.87 4735.23 853.97 3352.11 4269.84 8106.97 22.51 16 10 10 011/08/2024 19:00Collected Tracerco Sample.1580.41 101.27 0.00 0.00 280.39 73.91 146.70 67.96 134.32 68.87 128 0.00 73.57 69.09 67.93 66.98 29.9 28000 8 0.714 0.10 0.0 20.00 0.00 20.00 20.00 0.0000 1.3172 0.0000 1.7716 380.13 0.00 19.30 3465.98 4817.87 866.50 3394.60 4332.48 8212.47 0.00 19.63 3371.36 4805.47 1007.03 3373.09 4378.40 8198.18 22.63 16 10 10 011/08/2024 19:30 1577.11 101.26 0.00 0.00 278.64 73.88 145.84 68.33 133.89 68.99 128 0.00 78.74 72.62 68.12 67.01 29.9 28000 8 0.714 0.10 0.0 23.00 0.00 23.00 23.00 0.0000 1.2838 0.0000 1.7984 396.21 0.00 19.30 3240.98 4885.37 968.08 3414.79 4209.06 8300.16 0.00 19.63 3079.35 4869.62 1081.93 3395.63 4161.29 8284.88 22.76 16 10 10 011/08/2024 20:00 1574.94 101.26 0.00 0.00 307.37 74.33 163.72 69.00 149.11 69.01 128 0.00 79.22 72.87 67.77 66.64 29.9 28000 8 0.714 0.10 0.0 26.00 0.00 26.00 26.00 0.0000 1.3034 0.0000 1.8255 404.05 0.00 19.30 3226.86 4952.57 1133.76 3438.44 4360.62 8391.01 0.00 19.63 3401.76 4940.49 904.27 3414.47 4306.03 8374.59 22.92 16 10 10 011/08/2024 20:3020:50 Sparged Separator; Trace Solids Observed.1568.42 101.26 0.00 0.00 317.78 74.39 164.33 69.10 148.53 69.15 128 0.00 78.30 71.94 68.17 66.75 29.9 28000 8 0.714 0.10 0.0 21.00 0.00 21.00 21.00 0.0000 1.3520 0.0000 1.8537 374.09 0.00 19.30 3614.80 5027.86 960.90 3458.47 4575.70 8486.33 0.00 19.63 3256.66 5008.34 1266.48 3440.86 4523.14 8468.82 23.06 16 10 10 011/08/2024 21:00 1562.65 101.25 0.00 0.00 309.88 74.18 157.94 68.38 143.09 69.21 128 0.00 77.03 70.07 67.83 66.50 29.9 28000 8 0.714 0.10 0.0 28.00 0.00 28.00 28.00 0.0000 1.4310 0.0000 1.8835 426.81 0.00 19.30 3354.19 5097.71 1304.41 3485.68 4658.59 8583.39 0.00 19.63 2917.97 5069.13 1641.36 3475.05 4559.32 8563.80 23.24 16 10 10 011/08/2024 21:30 1560.48 101.25 0.00 0.00 310.05 74.19 156.95 68.98 140.79 69.16 128 0.00 75.65 69.41 68.07 66.80 29.0 28000 8 0.690 0.10 0.0 36.00 0.00 36.00 36.00 0.0000 1.4707 0.0000 1.9141 484.26 0.00 19.30 3038.94 5160.98 1709.40 3521.33 4748.34 8682.31 0.00 19.63 2894.08 5129.42 1773.79 3512.00 4667.88 8661.05 23.48 16 10 10 011/08/2024 22:00Applied CMSF 0.920.1558.90 101.25 0.00 0.00 311.41 74.24 160.85 69.34 145.43 69.56 128 0.00 77.22 72.07 68.15 66.99 29.0 29000 8 0.690 0.10 0.0 38.00 0.00 38.00 38.00 0.0000 1.4824 0.0000 1.9450 501.68 0.00 19.30 2957.05 5222.54 1812.38 3559.13 4769.43 8781.68 0.00 19.63 3659.04 5205.65 972.66 3532.27 4631.69 8757.55 23.73 16 10 10 011/08/2024 22:30 1557.86 101.25 0.00 0.00 311.63 74.63 161.43 69.27 143.60 69.68 128 0.00 76.74 70.97 68.06 67.02 29.0 29000 8 0.690 0.10 0.0 21.00 0.00 21.00 21.00 0.0000 1.4801 0.0000 1.9759 410.43 0.00 19.30 3606.93 5297.67 958.80 3579.12 4565.73 8876.79 0.00 19.63 3454.23 5277.61 1213.65 3557.55 4667.88 8854.79 23.86 16 10 10 011/08/2024 23:00 1555.44 101.25 0.00 0.00 311.41 74.64 158.28 69.21 142.70 69.73 128 0.00 73.63 68.30 68.20 66.90 29.0 29000 8 0.690 0.10 0.0 26.00 0.00 26.00 26.00 0.0000 1.4844 0.0000 2.0068 438.17 0.00 19.30 3388.80 5368.25 1190.66 3603.95 4579.46 8972.20 0.00 19.63 3669.17 5354.06 1034.89 3579.11 4704.06 8952.79 24.03 16 10 10 011/08/2024 23:30 1554.16 101.25 0.00 0.00 309.96 75.18 159.40 68.88 144.28 69.94 128 0.00 76.29 69.86 68.22 67.09 29.0 29000 8 0.690 0.10 0.0 22.00 0.00 22.00 22.00 0.0000 1.4954 0.0000 2.0379 421.19 0.00 19.30 3551.22 5442.21 1001.63 3624.84 4552.85 9067.05 0.00 19.63 3705.35 5431.25 926.34 3598.41 4631.69 9049.29 24.17 16 10 10 011/09/2024 00:00 1553.22 101.25 0.00 0.00 314.99 74.52 156.43 69.06 141.99 69.77 128 0.00 78.66 72.96 68.11 66.98 29.0 29000 8 0.690 0.10 0.0 20.00 0.00 20.00 20.00 0.0000 1.4933 0.0000 2.0691 407.77 0.00 19.30 3662.97 5518.51 915.74 3643.93 4578.71 9162.44 0.00 19.63 3810.29 5510.63 893.77 3617.03 4704.06 9147.29 24.29 16 10 10 011/09/2024 00:30 1551.77 101.24 0.00 0.00 311.65 74.80 159.28 67.84 145.49 69.57 128 0.00 76.95 70.04 67.90 66.66 29.0 29000 8 0.690 0.10 0.0 19.00 0.00 19.00 19.00 0.0000 1.5130 0.0000 2.1006 409.57 0.00 19.30 3694.88 5595.47 866.70 3662.00 4561.58 9257.47 0.00 19.63 3334.82 5580.11 1296.87 3644.05 4631.69 9243.78 24.41 16 10 10 011/09/2024 01:00Collected Tracerco Sample.1549.78 101.24 0.00 0.00 322.30 74.78 157.35 68.35 146.83 69.65 128 0.00 79.55 71.30 67.83 66.60 29.0 29000 8 0.690 0.10 0.0 28.00 0.00 28.00 28.00 0.0000 1.4991 0.0000 2.1318 456.05 0.00 19.30 3288.42 5663.95 1278.83 3688.67 4567.25 9352.63 0.00 19.63 3520.09 5653.44 1111.61 3667.21 4631.69 9340.28 24.59 16 10 10 011/09/2024 01:30 1548.74 101.24 0.00 0.00 309.94 75.16 158.58 68.27 145.14 69.69 128 0.00 79.36 72.72 68.01 66.51 29.0 29000 8 0.690 0.10 0.0 24.00 0.00 24.00 24.00 0.0000 1.5153 0.0000 2.1634 437.57 0.00 19.30 3464.10 5736.10 1093.93 3711.48 4558.02 9447.58 0.00 19.63 3705.35 5730.64 926.34 3686.51 4631.69 9436.77 24.74 16 10 10 011/09/2024 02:00 1546.98 101.24 0.00 0.00 317.74 75.07 163.93 68.35 147.77 69.74 128 0.00 78.85 70.36 68.01 66.74 29.0 29000 8 0.690 0.10 0.0 20.00 0.00 20.00 20.00 0.0000 1.5246 0.0000 2.1951 414.62 0.00 19.30 3677.73 5812.71 919.43 3730.65 4597.17 9543.36 0.00 19.63 3407.55 5801.63 1260.33 3712.76 4667.88 9534.02 24.87 16 10 10 011/09/2024 02:30 1545.52 101.24 0.00 0.00 314.65 75.30 158.66 68.28 143.87 69.69 128 0.00 77.01 71.05 68.39 67.68 29.0 29000 8 0.690 0.10 0.0 27.00 0.00 27.00 27.00 0.0000 1.5293 0.0000 2.2270 459.89 0.00 19.30 3326.66 5881.98 1230.41 3756.31 4557.07 9638.30 0.00 19.63 3630.09 5877.25 1146.34 3736.65 4776.43 9633.53 25.04 16 10 10 011/09/2024 03:0003:04 Sparged Separator; Trace Solids Observed.1542.43 101.24 0.00 0.00 316.90 75.11 158.42 68.36 147.45 69.81 128 0.00 78.94 72.00 68.33 68.02 29.0 28000 8 0.690 0.10 0.0 24.00 0.00 24.00 24.00 0.0000 1.5549 0.0000 2.2594 445.42 0.00 19.30 3492.05 5954.71 1102.75 3779.31 4594.80 9734.02 0.00 19.63 3386.92 5947.81 1317.14 3764.09 4704.06 9731.53 25.19 16 10 10 011/09/2024 03:30 1544.19 101.24 0.00 0.00 318.54 75.40 165.49 68.66 149.01 69.96 128 0.00 79.39 72.92 68.52 67.29 29.4 28000 8 0.700 0.10 0.0 28.00 0.00 28.00 28.00 0.0000 1.4985 0.0000 2.2906 459.63 0.00 19.30 3261.59 6022.63 1268.40 3805.76 4529.98 9828.40 0.00 19.63 3612.72 6023.08 1018.97 3785.32 4631.69 9828.02 25.37 16 10 10 011/09/2024 04:00 1541.69 101.24 0.00 0.00 314.00 75.07 163.56 67.14 146.68 69.74 128 0.00 77.18 71.99 68.09 66.90 29.4 28000 8 0.700 0.10 0.0 22.00 0.00 22.00 22.00 0.0000 1.4963 0.0000 2.3218 421.57 0.00 19.30 3550.34 6096.58 1001.38 3826.65 4551.72 9923.22 0.00 19.63 3216.85 6090.10 1378.65 3814.04 4595.51 9923.76 25.51 16 10 10 011/09/2024 04:30 1540.52 101.24 0.00 0.00 316.03 75.10 163.02 68.22 146.13 69.86 128 0.00 77.72 71.99 68.01 66.79 29.4 28000 8 0.700 0.10 0.0 30.00 0.00 30.00 30.00 0.0000 1.5192 0.0000 2.3534 471.92 0.00 19.30 3220.82 6163.65 1380.35 3855.44 4601.17 10019.08 0.00 19.63 3427.45 6161.50 1204.24 3839.13 4631.69 10020.25 25.70 16 10 10 011/09/2024 05:00Applied CMSF 0.929.1539.02 101.23 0.00 0.00 318.06 74.92 163.12 68.91 147.45 69.57 128 0.00 77.05 71.45 68.06 66.79 29.4 29000 8 0.700 0.10 0.0 26.00 0.00 26.00 26.00 0.0000 1.5120 0.0000 2.3849 445.81 0.00 19.30 3392.87 6234.31 1192.09 3880.30 4584.95 10114.60 0.00 19.63 3360.87 6231.52 1307.01 3866.35 4667.88 10117.50 25.87 16 10 10 011/09/2024 05:30 1538.69 101.23 0.00 0.00 318.52 74.72 160.89 68.63 146.89 69.46 128 0.00 77.04 71.85 67.85 66.77 29.4 29000 8 0.700 0.10 0.0 28.00 0.00 28.00 28.00 0.0000 1.5175 0.0000 2.4166 458.20 0.00 19.30 3313.23 6303.30 1288.48 3907.17 4601.71 10210.47 0.00 19.63 3547.59 6305.43 1120.29 3889.69 4667.88 10214.75 26.05 16 10 10 011/09/2024 06:00 1535.81 101.23 0.00 0.00 319.33 74.24 164.99 68.86 148.86 69.25 128 0.00 80.08 73.49 67.85 66.29 29.4 29000 8 0.700 0.10 0.0 24.00 0.00 24.00 24.00 0.0000 1.5203 0.0000 2.4482 434.41 0.00 19.30 3500.60 6376.21 1105.45 3930.22 4606.05 10306.43 0.00 19.63 3669.17 6381.87 1034.89 3911.25 4704.06 10312.75 26.20 16 10 10 011/09/2024 06:30 1535.29 101.23 0.00 0.00 317.78 74.72 162.60 68.30 147.69 69.33 128 0.00 79.24 71.84 67.61 66.18 29.4 29000 8 0.700 0.10 0.0 22.00 0.00 22.00 22.00 0.0000 1.5327 0.0000 2.4802 424.24 0.00 19.30 3613.82 6451.48 1019.28 3951.47 4633.10 10402.95 0.00 19.63 4171.42 6468.77 568.83 3923.11 4740.25 10411.51 26.34 16 10 10 011/09/2024 07:00Collected Tracerco Sample.7:20 Bypassed DPI Unit Side A; Flowing through DPI Unit Side B.7:25 Bypassed Ballcatcher.1533.47 101.23 0.00 0.00 315.57 74.21 163.00 68.66 147.22 69.19 128 0.05 75.58 70.64 67.32 66.24 29.4 30000 8 0.700 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.5264 0.0000 2.5120 377.35 0.00 19.30 4045.31 6535.75 551.63 3962.97 4596.94 10498.72 0.00 19.63 3860.23 6549.20 735.28 3938.42 4595.51 10507.24 26.42 16 10 10 011/09/2024 07:30 1526.85 101.22 0.00 0.00 301.97 74.79 173.31 68.60 155.79 69.63 128 0.00 79.91 73.04 67.74 66.24 29.4 30000 8 0.700 0.10 0.0 16.00 0.00 16.00 16.00 0.0000 1.5574 0.0000 2.5444 392.38 0.00 19.30 3969.59 6618.44 756.11 3978.73 4725.71 10597.17 0.00 19.63 4232.21 6637.37 688.96 3952.78 4921.17 10609.77 26.52 16 10 10 011/09/2024 08:00Applied CMSF 0.948.1521.93 101.22 0.00 0.00 304.52 75.02 175.14 68.31 157.49 69.92 128 0.00 80.83 73.70 67.93 66.70 29.4 29000 8 0.700 0.10 0.0 14.00 0.00 14.00 14.00 0.0000 1.6227 0.0000 2.5782 376.15 0.00 19.30 4314.32 6708.31 702.33 3993.38 5016.65 10701.69 0.00 19.63 4458.00 6730.24 607.91 3965.44 5065.91 10715.31 26.62 16 10 10 011/09/2024 08:30 1519.02 101.22 0.00 0.00 307.13 74.68 176.87 69.08 158.81 69.92 128 0.00 79.27 71.83 67.82 66.72 29.4 29000 8 0.700 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6610 0.0000 2.6128 367.05 0.00 19.30 4525.76 6802.59 617.15 4006.24 5142.91 10808.83 0.00 19.63 4224.97 6818.26 804.76 3982.21 5029.73 10820.10 26.71 16 10 10 011/09/2024 09:00 1517.10 101.22 0.00 0.00 307.03 74.36 177.61 69.24 159.23 69.79 128 0.00 83.41 73.03 68.06 66.62 29.4 29000 8 0.700 0.10 0.0 16.00 0.00 16.00 16.00 0.0000 1.6812 0.0000 2.6478 389.51 0.00 19.30 4316.72 6892.51 822.23 4023.38 5138.95 10915.89 0.00 19.63 4387.80 6909.67 714.29 3997.09 5102.10 10926.39 26.82 16 10 10 011/09/2024 09:30 1515.14 101.22 0.00 0.00 306.67 74.43 178.01 68.82 159.05 70.06 128 0.00 81.19 71.29 68.01 66.81 29.6 29000 8 0.700 0.10 0.0 14.00 0.00 14.00 14.00 0.0000 1.6703 0.0000 2.6826 379.02 0.00 19.30 4407.41 6984.32 717.49 4038.34 5124.90 11022.66 0.00 19.63 4183.00 6996.82 738.18 4012.47 4921.17 11028.91 26.92 16 10 10 011/09/2024 10:00 1513.65 101.22 0.00 0.00 306.17 74.44 173.89 69.02 156.54 70.01 128 0.00 79.57 70.88 67.93 66.86 29.6 29000 8 0.700 0.10 0.0 15.00 0.00 15.00 15.00 0.0000 1.6652 0.0000 2.7173 383.02 0.00 19.30 4348.16 7074.90 767.32 4054.34 5115.49 11129.24 0.00 19.63 4458.00 7089.70 607.91 4025.13 5065.91 11134.45 27.03 16 10 10 011/09/2024 10:30 1512.71 101.22 0.00 0.00 305.52 74.36 174.13 68.11 157.01 69.84 128 0.00 80.35 72.36 67.87 66.73 29.6 29000 8 0.700 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6721 0.0000 2.7522 372.48 0.00 19.30 4489.34 7168.42 612.18 4067.10 5101.52 11235.52 0.00 19.63 4325.57 7179.81 704.16 4039.80 5029.73 11239.24 27.11 16 10 10 011/09/2024 11:00 1511.82 101.22 0.00 0.00 304.68 74.40 174.78 69.02 157.01 69.69 128 0.00 80.52 71.96 67.88 66.62 29.6 29000 8 0.700 0.10 0.0 14.00 0.00 14.00 14.00 0.0000 1.6746 0.0000 2.7870 381.35 0.00 19.30 4391.79 7259.91 714.94 4082.00 5106.73 11341.91 0.00 19.63 4394.32 7271.36 599.23 4052.29 4993.54 11343.27 27.21 16 10 10 011/09/2024 11:30 1510.61 101.22 0.00 0.00 308.20 74.51 177.65 68.69 158.56 69.93 128 0.00 81.75 73.31 67.93 66.78 29.6 29000 8 0.700 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6567 0.0000 2.8216 370.67 0.00 19.30 4469.89 7353.02 609.53 4094.71 5079.43 11447.73 0.00 19.63 4508.66 7365.29 557.25 4063.90 5065.91 11448.81 27.30 16 10 10 011/09/2024 12:00 1509.13 101.22 0.00 0.00 305.22 74.45 175.84 68.88 158.78 69.89 128 0.00 81.53 73.98 68.00 66.53 29.6 29000 8 0.700 0.10 0.0 11.00 0.00 11.00 11.00 0.0000 1.6697 0.0000 2.8563 367.74 0.00 19.30 4540.76 7447.61 561.22 4106.41 5101.98 11554.02 0.00 19.63 4426.16 7457.50 603.57 4076.47 5029.73 11553.60 27.37 16 10 10 011/09/2024 12:30 1507.97 101.22 0.00 0.00 306.75 74.49 176.00 69.03 158.26 69.91 128 0.00 80.52 73.32 67.98 66.55 29.6 29000 8 0.700 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6665 0.0000 2.8911 371.53 0.00 19.30 4485.91 7541.06 611.72 4119.16 5097.63 11660.22 0.00 19.63 4508.66 7551.43 557.25 4088.08 5065.91 11659.14 27.46 16 10 10 011/09/2024 13:00Collected Tracerco Sample.1506.87 101.21 0.00 0.00 305.81 74.47 174.46 69.22 156.40 70.05 128 0.00 78.06 71.60 67.69 66.52 29.6 29000 8 0.700 0.10 0.0 11.00 0.00 11.00 11.00 0.0000 1.6628 0.0000 2.9257 367.48 0.00 19.30 4524.98 7635.33 559.27 4130.81 5084.25 11766.14 0.00 19.63 4344.38 7641.94 649.16 4101.60 4993.54 11763.17 27.53 16 10 10 011/09/2024 13:30 1505.94 101.21 0.00 0.00 309.99 74.51 179.48 68.97 162.37 69.93 128 0.00 82.94 74.30 67.59 66.32 29.6 29000 8 0.700 0.10 0.0 13.00 0.00 13.00 13.00 0.0000 1.6815 0.0000 2.9607 378.81 0.00 19.30 4439.32 7727.81 663.35 4144.64 5102.66 11872.45 0.00 19.63 4344.38 7732.45 649.16 4115.13 4993.54 11867.20 27.63 16 10 10 011/09/2024 14:00 1504.38 101.21 0.00 0.00 306.19 74.44 174.72 68.80 157.78 69.73 128 0.00 78.97 71.17 67.77 66.28 29.6 29000 8 0.700 0.10 0.0 13.00 0.00 13.00 13.00 0.0000 1.6884 0.0000 2.9959 380.04 0.00 19.30 4443.25 7820.37 663.93 4158.48 5107.18 11978.85 0.00 19.63 4438.82 7824.92 663.27 4128.95 5102.10 11973.49 27.72 16 10 10 011/09/2024 14:30 1503.18 101.21 0.00 0.00 311.39 74.48 180.73 68.76 163.41 69.92 128 0.00 86.74 75.79 67.70 66.44 29.6 29000 8 0.700 0.10 0.0 13.00 0.00 13.00 13.00 0.0000 1.6713 0.0000 3.0307 377.18 0.00 19.30 4431.54 7912.68 662.18 4172.29 5093.73 12084.97 0.00 19.63 4675.84 7922.34 462.45 4138.58 5138.28 12080.54 27.81 16 10 10 011/09/2024 15:00 1501.48 101.21 0.00 0.00 308.84 74.38 174.80 68.64 156.92 69.69 128 0.00 78.91 70.72 67.61 66.24 29.6 29000 8 0.700 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.7040 0.0000 3.0662 366.35 0.00 19.30 4651.44 8009.58 460.03 4181.87 5111.47 12191.46 0.00 19.63 4508.66 8016.27 557.25 4150.19 5065.91 12186.08 27.88 16 10 10 011/09/2024 15:30 1501.84 101.21 0.00 0.00 304.88 75.24 174.98 68.83 157.97 69.56 128 0.00 84.37 74.02 67.93 66.26 29.6 29000 8 0.700 0.10 0.0 11.00 0.00 11.00 11.00 0.0000 1.6874 0.0000 3.1014 374.23 0.00 19.30 4509.33 8103.52 557.33 4193.49 5066.66 12297.01 0.00 19.63 4494.19 8109.90 499.35 4160.59 4993.54 12290.11 27.96 16 10 10 011/09/2024 16:00 1500.25 101.21 0.00 0.00 299.96 75.24 176.12 68.89 157.66 69.56 128 0.00 83.09 73.40 67.91 66.53 29.6 28000 8 0.700 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.6825 0.0000 3.1364 369.06 0.00 19.30 4559.22 8198.50 506.58 4204.05 5065.80 12402.55 0.00 19.63 4394.32 8201.44 599.23 4173.08 4993.54 12394.15 28.02 16 10 10 011/09/2024 16:3016:42 Sparged Separator; Trace Solids Observed.1498.52 101.21 0.00 0.00 303.40 74.73 174.58 69.10 156.79 69.18 128 0.00 81.92 72.74 67.61 66.39 29.6 28000 8 0.700 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6977 0.0000 3.1718 380.18 0.00 19.30 4465.96 8291.53 609.00 4216.74 5074.96 12508.28 2.48 19.68 4263.33 8290.26 691.55 4187.48 4957.36 12497.42 28.11 16 10 10 011/09/2024 17:00 1498.52 101.20 0.00 0.00 315.37 74.49 179.08 68.72 162.35 69.27 128 0.00 85.93 75.28 67.93 66.41 29.6 28000 8 0.700 0.10 0.0 13.95 0.00 13.95 13.95 0.0000 1.7028 0.0000 3.2073 399.90 0.00 19.30 4258.56 8380.24 690.38 4231.14 4948.94 12611.38 0.00 19.68 4396.49 8381.86 488.50 4197.66 4884.99 12599.20 28.21 16 10 10 011/09/2024 17:30 1496.42 101.20 0.00 0.00 312.58 74.67 177.45 68.26 159.49 69.22 128 0.00 83.08 74.87 67.88 66.57 29.6 28000 8 0.700 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.6697 0.0000 3.2421 369.54 0.00 19.30 4518.69 8474.38 502.08 4241.60 5020.77 12715.98 0.00 19.68 4444.25 8474.45 549.29 4209.10 4993.54 12703.23 28.27 16 10 10 011/09/2024 18:00 1496.52 101.20 0.00 0.00 309.74 75.46 175.66 68.50 159.56 69.74 128 0.00 82.76 73.15 67.88 66.01 29.6 28000 8 0.700 0.10 0.0 11.00 0.00 11.00 11.00 0.0000 1.7100 0.0000 3.2777 376.87 0.00 19.30 4537.59 8568.91 560.83 4253.29 5098.41 12822.20 0.00 19.68 4544.12 8569.12 449.42 4218.47 4993.54 12807.26 28.35 16 10 10 011/09/2024 18:30 1494.86 101.20 0.00 0.00 304.56 74.64 174.66 68.29 155.58 69.27 128 0.00 81.58 72.08 67.51 66.30 29.6 28000 8 0.700 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.7228 0.0000 3.3136 370.75 0.00 19.30 4647.10 8665.72 459.60 4262.87 5106.71 12928.59 0.00 19.68 4559.32 8664.10 506.59 4229.02 5065.91 12912.80 28.41 16 10 10 011/09/2024 19:00Collected Tracerco Sample.1494.59 101.20 0.00 0.00 309.80 74.42 177.45 68.56 160.11 69.60 128 0.00 82.51 73.41 68.12 67.13 29.6 29000 8 0.700 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.6685 0.0000 3.3484 369.97 0.00 19.30 4510.21 8759.67 501.13 4273.32 5011.35 13032.99 0.00 19.68 4035.36 8748.17 885.81 4247.48 4921.17 13015.32 28.48 16 10 10 011/09/2024 19:30 1495.14 101.20 0.00 0.00 313.88 74.77 179.00 69.33 160.32 69.95 128 0.00 80.91 72.48 68.06 66.49 29.6 29000 8 0.700 0.10 0.0 18.00 0.00 18.00 18.00 0.0000 1.7016 0.0000 3.3838 409.68 0.00 19.30 4154.19 8846.20 911.90 4292.33 5066.08 13138.53 24.97 20.20 3645.29 8824.11 1323.29 4275.04 4993.54 13119.36 28.61 16 10 10 011/09/2024 20:00 1492.30 101.20 0.00 0.00 314.30 74.49 183.88 68.12 166.34 68.69 128 0.00 82.72 72.47 67.05 66.33 29.6 29000 8 0.700 0.10 0.0 27.00 0.50 26.50 26.50 0.0000 1.7266 0.0000 3.4198 460.07 25.54 19.83 3754.26 8924.39 1353.58 4320.56 5107.84 13244.95 24.97 20.72 4044.77 8908.38 923.81 4294.29 4993.54 13223.39 28.80 16 10 10 011/09/2024 20:30 1490.62 101.20 0.00 0.00 308.04 74.50 176.08 68.16 157.44 69.13 128 0.00 82.10 74.57 67.85 66.61 29.6 29000 8 0.700 0.10 0.0 19.00 0.50 18.50 18.50 0.0000 1.7495 0.0000 3.4562 415.97 25.81 20.37 4206.57 9012.01 954.86 4340.47 5161.43 13352.48 25.51 21.25 4336.78 8998.73 739.80 4309.70 5102.10 13329.68 28.93 16 10 10 011/09/2024 21:0021:15 Diverted Flow through DPI Side A; Flowing through DPI Side A and Side B in Series.1488.74 101.19 0.00 0.00 305.40 74.64 177.83 67.59 159.36 69.35 128 0.00 81.74 72.02 67.92 67.21 29.6 29000 8 0.700 0.10 0.0 15.00 0.50 14.50 14.50 0.0000 1.7255 0.0000 3.4922 397.73 25.37 20.90 4339.03 9102.39 735.86 4355.81 5074.89 13458.20 0.00 21.25 4103.39 9084.22 962.52 4329.75 5065.91 13435.22 29.03 16 10 10 011/09/2024 21:3021:58 Observed Well Slugging.1493.29 101.20 0.00 0.00 331.28 74.42 168.15 67.15 150.46 68.64 128 0.00 78.98 71.99 67.31 66.63 29.8 29000 8 0.696 0.10 0.0 19.00 0.00 19.00 19.00 0.0000 1.6991 0.0000 3.5276 434.01 0.00 20.90 3915.78 9183.96 918.52 4374.96 4834.29 13558.92 0.00 21.25 4035.36 9168.29 885.81 4348.21 4921.17 13537.75 29.16 16 10 10 011/09/2024 22:00 1497.75 101.20 0.00 0.00 305.67 74.28 135.29 64.80 119.33 68.31 128 0.00 68.65 66.90 66.91 66.33 29.8 29000 8 0.696 0.10 0.0 18.00 0.00 18.00 18.00 0.0000 1.6483 0.0000 3.5619 438.35 0.00 20.90 3760.79 9262.29 825.54 4392.17 4586.33 13654.47 8.76 21.43 3240.01 9235.79 1129.63 4371.74 4378.40 13628.96 29.28 16 10 10 011/09/2024 22:30 1498.64 101.21 0.00 0.00 317.44 74.46 164.35 66.10 149.46 68.69 128 0.00 78.74 71.31 67.23 66.47 29.8 29000 8 0.696 0.10 0.0 26.00 0.20 25.80 25.80 0.0000 1.6197 0.0000 3.5957 459.74 9.50 21.10 3524.41 9335.69 1225.47 4417.73 4749.88 13753.42 0.00 21.43 3605.12 9310.89 845.65 4389.36 4450.77 13721.69 29.45 16 10 10 0WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 21 START DATE:END DATE:Time DPI Heater GOR Frac WaterTime & Date COMMENTS BHP BHT I/A Pressure O/A Pressure Well Head PressureWell Head TemperatureU/S Choke PressureU/S Choke TemperatureD/S Choke PressureD/S Choke TemperatureChoke Size U/S DPI Solids, Mud & Carbolite D/S Heater PressureSeparator PressureGas Temperature Oil Temperature Corrected API WaterSalinity pH Gas S.G CO2 H2S Total Choke BS&W(Solids, Mud, Carbolite & Water)Solids, Mud & Carbolite @ ChokeWater Cut @ Choke Separator Oil Leg BS&W (2-Phase)Nitrogen Injection RateTotal Gas Rate (N2+Formation)Nitrogen InjectionCumulative Total Gas Cumulative (N2+Formation)Total GOR Solids, Mud & Carbolite RateSolids, Mud, & Carbolite CumulativeOil Rate Oil Cumulative Water RateWater CumulativeTotal Fluid RateTotal Fluid CumulativeTank Farm StrapSolids, Mud & Carbolite RateTank Farm StrapSolids, Mud, & Carbolite CumulativeTank Farm StrapOil RateTank Farm StrapOil CumulativeTank Farm StrapWater RateTank Farm StrapWater CumulativeTank Farm Strap Total Rate (Tank 1 - Tank 10)Tank Farm Strap Total Cumulative(Tank 1 - Tank 10)Percentage of Frac Water RecoveredDefoamer(D/S of Choke Manifold Data Header)Methanol (MeOH)(Separator Gas Line)Demulsifier(D/S of Choke Manifold Data Header)H2S Scavenger(U/S of Choke Manifold Data Header)(mm-dd-yyyy hh:mm) (psig)(F)(psig) (psig) (psig)(F)(psig)(F)(psig)(F)(64ths) (%) (psig) (psig)(F) (F)(API@60°)(ppm) (pH) (Air = 1) (%) (ppm) (%) (%) (%) (%) (MMscf/d) (MMscf/d) (MMscf) (MMscf) (scf/stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb)(stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (stb/d) (stb) (%) (gal/d) (gal/d) (gal/d) (gal/d)Fluid Properties BS&W PropertiesSeparatorPROJECT DESIGN NUMBER:LOCATION / FIELD:WELL NUMBER:Chemical Injection RatesRates and Cumulatives (Test Separator Flow Meters @ Stock Conditions)Rates and Cumulatives (Based on BS&W %)(Tank Farm Straps)Well Head Choke Gas Properties Gas Rates & CumulativesNDBi-016 WELL CLEAN-UP DATA SHEETWT-XAK-0127.4PIKKA - NDB NDBi-01606-Nov-2024 @ 12:1711-Nov-2024 @ 00:00Santos Adam Phillips / Jack Landry | Pere KeniyeJose Gonzalez / Dan BonnarAustin Stewart | Frank TowerSharon Oyao / Travis Stacey | Yehia ElzenyCLIENT:SANTOS WELL TEST LEAD:SANTOS REP/SUPERVISORS:EXPRO SUPERVISORS :EXPRO DAQ ENGINEERS:11/09/2024 23:0023:23 Sparged Separator; Trace Solids Observed.1496.44 101.20 0.00 0.00 319.71 74.49 166.62 66.70 148.77 68.70 128 0.00 77.59 70.87 67.18 66.50 29.8 29000 8 0.696 0.10 0.0 19.00 0.00 19.00 19.00 0.0000 1.6306 0.0000 3.6296 425.15 0.00 21.10 3835.93 9415.59 899.79 4436.49 4735.72 13852.08 7.00 21.58 4247.77 9399.39 413.11 4397.97 4667.88 13818.93 29.58 16 10 10 011/09/2024 23:30Applied CMSF 0.933.1496.40 101.20 0.00 0.00 320.81 74.37 168.59 65.78 150.64 68.77 128 0.00 78.23 71.95 67.18 66.41 29.8 29000 8 0.696 0.10 0.0 9.00 0.15 8.85 8.85 0.0000 1.6369 0.0000 3.6637 385.02 7.00 21.24 4251.68 9504.17 412.81 4445.09 4664.49 13949.26 4.63 21.67 3844.30 9479.48 782.76 4414.27 4631.69 13915.43 29.63 16 10 10 011/10/2024 00:00 1495.72 101.20 0.00 0.00 320.47 74.60 167.38 66.75 150.58 68.70 128 0.00 80.98 73.94 67.23 66.55 29.8 29000 8 0.696 0.10 0.0 17.00 0.10 16.90 16.90 0.0000 1.6412 0.0000 3.6979 423.07 4.67 21.34 3879.88 9584.98 789.05 4461.54 4668.93 14046.53 0.00 21.67 4044.05 9563.73 551.46 4425.76 4595.51 14011.17 29.74 16 10 10 011/10/2024 00:30 1496.27 101.20 0.00 0.00 315.25 74.63 163.12 67.10 147.47 68.37 128 0.00 76.82 70.85 66.80 66.12 29.8 29000 8 0.696 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6496 0.0000 3.7323 401.53 0.00 21.34 4108.45 9670.57 560.24 4473.22 4668.70 14143.79 0.00 21.67 4294.45 9653.20 373.43 4433.54 4667.88 14108.42 29.82 16 10 10 011/10/2024 01:00 Collected Tracerco Sample. 1495.02 101.20 0.00 0.00 319.69 74.54 168.41 66.38 151.07 68.53 128 0.00 80.28 72.59 67.07 66.21 29.8 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.6444 0.0000 3.7665 382.14 0.00 21.34 4303.28 9760.22 374.20 4481.02 4677.48 14241.24 0.00 21.67 4266.22 9742.08 474.02 4443.42 4740.25 14207.17 29.87 16 10 10 011/10/2024 01:30 1494.51 101.20 0.00 0.00 318.08 74.22 164.91 66.37 149.77 68.16 128 0.00 78.09 72.04 66.77 66.00 29.8 29000 8 0.696 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.6669 0.0000 3.8013 394.05 0.00 21.34 4230.28 9848.34 470.03 4490.82 4700.31 14339.16 0.00 21.67 4171.42 9828.98 568.83 4455.27 4740.25 14305.93 29.94 16 10 10 011/10/2024 02:00 1494.71 101.20 0.00 0.00 321.58 74.71 169.45 67.64 152.38 68.80 128 0.00 80.75 73.36 67.36 66.46 29.8 29000 8 0.696 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.6157 0.0000 3.8349 395.89 0.00 21.34 4081.54 9933.37 556.57 4502.42 4638.12 14435.79 0.00 21.67 4201.09 9916.50 466.79 4464.99 4667.88 14403.17 30.02 16 10 10 011/10/2024 02:30 1494.05 101.20 0.00 0.00 323.31 74.53 169.37 66.44 151.53 68.58 128 0.00 78.54 72.69 67.07 66.18 29.8 29000 8 0.696 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.6439 0.0000 3.8692 390.15 0.00 21.34 4213.87 10021.16 468.21 4512.18 4682.07 14533.33 0.00 21.67 4346.55 10007.06 429.88 4473.95 4776.43 14502.68 30.08 16 10 10 011/10/2024 03:0003:02 Bypassed DPI Unit Side A; Flowing through DPI Unit Side B.1489.97 101.19 0.00 0.00 309.82 74.36 178.07 67.53 158.93 68.63 128 0.00 79.56 72.68 66.94 66.02 29.8 29000 8 0.696 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.6634 0.0000 3.9038 386.34 0.00 21.34 4305.75 10110.85 425.84 4521.05 4731.59 14631.91 0.00 21.67 4218.82 10094.95 521.43 4484.81 4740.25 14601.44 30.14 16 10 10 011/10/2024 03:30 1484.94 101.18 0.00 0.00 314.73 74.66 180.40 67.17 160.50 69.07 128 0.00 79.12 73.35 67.31 66.46 30.4 29000 8 0.698 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.7289 0.0000 3.9398 379.87 0.00 21.34 4551.54 10205.67 450.15 4530.44 5001.70 14736.11 0.00 21.67 4494.19 10188.58 499.35 4495.22 4993.54 14705.47 30.20 16 10 10 011/10/2024 04:0004:03 Sparged Separator; No Solids Observed.1482.21 101.18 0.00 0.00 316.15 74.59 180.95 67.40 160.81 68.93 128 0.00 82.98 74.14 67.29 66.41 30.4 29000 8 0.698 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.7776 0.0000 3.9769 391.83 0.00 21.34 4537.01 10300.19 504.11 4540.94 5041.13 14841.13 0.00 21.67 4577.05 10283.93 452.68 4504.65 5029.73 14810.25 30.27 16 10 10 011/10/2024 04:30 1477.10 101.18 0.00 0.00 303.78 74.47 168.61 67.06 150.25 68.80 128 0.00 77.88 70.53 67.23 66.39 30.4 29000 8 0.698 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.7868 0.0000 4.0141 410.93 0.00 21.34 4348.44 10390.78 430.07 4549.91 4778.51 14940.69 0.00 21.67 4412.41 10375.86 436.39 4513.74 4848.80 14911.27 30.33 16 10 10 011/10/2024 05:00 1479.06 101.18 0.00 0.00 317.88 74.80 181.83 67.42 163.93 69.13 128 0.00 82.28 74.81 67.50 66.59 30.4 29000 8 0.698 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.7789 0.0000 4.0512 400.54 0.00 21.34 4441.51 10483.31 439.27 4559.06 4880.78 15042.37 0.00 21.67 4396.49 10467.45 488.50 4523.92 4884.99 15013.04 30.39 16 10 10 011/10/2024 05:3005:32 Diverted Flow through DPI Side A; Flowing through DPI Side A and Side B in Series.1477.98 101.18 0.00 0.00 325.01 74.62 181.57 67.76 162.95 69.02 128 0.00 82.53 74.00 67.40 66.47 30.4 29000 8 0.698 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.7876 0.0000 4.0884 400.39 0.00 21.34 4464.83 10576.32 496.09 4569.40 4960.92 15145.72 0.00 21.67 4478.27 10560.75 442.91 4533.14 4921.17 15115.57 30.46 16 10 10 011/10/2024 06:00 Bypassed DPI Unit Side A; Flowing through DPI Unit Side B. 1482.19 101.19 0.00 0.00 324.61 74.09 185.75 67.83 164.50 68.26 128 0.00 81.99 73.46 66.86 65.78 30.4 29000 8 0.698 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.7289 0.0000 4.1244 408.60 0.00 21.34 4231.60 10664.47 418.51 4578.13 4650.10 15242.60 0.00 21.67 4107.73 10646.33 560.15 4544.81 4667.88 15212.81 30.52 16 10 10 011/10/2024 06:30 1477.76 101.18 0.00 0.00 314.24 74.39 178.96 67.89 159.38 68.75 128 0.00 81.40 72.94 67.05 65.80 30.4 29000 8 0.698 0.10 0.0 12.00 0.00 12.00 12.00 0.0000 1.7873 0.0000 4.1617 402.74 0.00 21.34 4438.15 10756.93 605.20 4590.74 5043.35 15347.67 0.00 21.67 4657.02 10743.35 517.45 4555.59 5174.47 15320.62 30.58 16 10 10 011/10/2024 07:00 Collected Tracerco Sample. 1474.91 101.18 0.00 0.00 309.72 74.39 173.43 67.70 152.64 69.73 128 0.00 81.72 71.90 67.40 66.13 30.4 29000 8 0.698 0.10 0.0 10.00 0.00 10.00 10.00 0.0000 1.7931 0.0000 4.1990 396.21 0.00 21.34 4525.81 10851.21 502.87 4601.22 5028.68 15452.43 2.51 21.73 4627.35 10839.75 399.86 4563.92 5029.73 15425.40 30.67 16 10 10 011/10/2024 07:30 1473.22 101.18 0.00 0.00 311.71 74.47 179.72 68.35 162.11 70.08 128 0.00 83.09 72.57 67.21 66.18 30.4 29000 8 0.698 0.10 0.0 8.00 0.05 7.95 7.95 0.0000 1.7956 0.0000 4.2364 388.65 2.51 21.39 4620.36 10947.46 399.04 4609.54 5019.41 15557.00 0.00 21.73 4594.06 10935.46 399.48 4572.25 4993.54 15529.43 30.73 16 10 10 011/10/2024 08:00 1472.60 101.17 0.00 0.00 315.75 74.58 183.12 69.02 163.77 70.33 128 0.00 84.47 74.04 67.42 66.20 30.4 28000 8 0.698 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8115 0.0000 4.2742 389.54 0.00 21.39 4650.63 11044.35 404.40 4617.97 5055.03 15662.32 0.00 21.73 4577.05 11030.82 452.68 4581.68 5029.73 15634.22 30.78 16 10 10 011/10/2024 08:30 1470.86 101.17 0.00 0.00 322.52 74.40 183.50 68.96 163.76 70.24 128 0.00 84.49 74.85 67.45 66.33 30.4 28000 8 0.698 0.10 0.0 9.00 0.00 9.00 9.00 0.0000 1.8128 0.0000 4.3119 395.87 0.00 21.39 4579.59 11139.75 452.93 4627.41 5032.52 15767.16 0.00 21.73 6924.38 11175.08 602.12 4594.22 7526.50 15791.02 30.85 16 10 10 011/10/2024 09:00 1469.93 101.17 0.00 0.00 318.06 74.34 181.49 67.49 161.10 70.18 128 0.00 83.99 74.20 67.45 66.30 30.4 28000 8 0.698 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8157 0.0000 4.3498 391.16 0.00 21.39 4642.01 11236.46 403.65 4635.82 5045.66 15872.28 0.00 21.73 2330.32 11223.62 202.64 4598.44 2532.96 15843.79 30.90 16 10 10 011/10/2024 09:30 1468.74 101.17 0.00 0.00 317.88 74.47 182.27 68.82 163.81 70.39 128 0.00 83.99 72.60 67.32 66.35 29.9 28000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8217 0.0000 4.3877 392.00 0.00 21.39 4647.35 11333.27 404.12 4644.25 5051.47 15977.52 0.00 21.73 4693.93 11321.41 408.17 4606.95 5102.10 15950.09 30.96 16 10 10 011/10/2024 10:00 1467.60 101.17 0.00 0.00 317.86 74.41 181.25 68.90 162.03 70.27 128 0.00 81.09 73.95 67.42 66.27 29.9 28000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8274 0.0000 4.4258 392.88 0.00 21.39 4651.54 11430.18 404.48 4652.68 5056.02 16082.85 0.00 21.73 4727.22 11419.90 411.06 4615.51 5138.28 16057.13 31.01 16 10 10 011/10/2024 10:30 1467.70 101.17 0.00 0.00 314.77 74.77 179.20 68.77 159.56 70.29 128 0.00 82.57 75.55 67.45 66.32 29.9 28000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8362 0.0000 4.4640 394.41 0.00 21.39 4655.73 11527.17 404.85 4661.11 5060.57 16188.28 0.00 21.73 4627.35 11516.30 402.38 4623.89 5029.73 16161.92 31.07 16 10 10 011/10/2024 11:00 1466.65 101.17 0.00 0.00 322.04 74.67 182.21 68.46 163.25 70.37 128 0.00 82.41 72.88 67.29 66.31 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8355 0.0000 4.5023 394.97 0.00 21.39 4647.40 11623.99 404.12 4669.54 5051.52 16293.52 0.00 21.73 4660.64 11613.40 405.27 4632.34 5065.91 16267.46 31.13 16 10 10 011/10/2024 11:30 1465.45 101.17 0.00 0.00 318.14 74.66 184.22 68.88 165.74 70.50 128 0.00 81.01 74.90 67.51 66.31 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8398 0.0000 4.5406 395.21 0.00 21.39 4655.50 11720.97 404.83 4677.97 5060.33 16398.95 0.00 21.73 4660.64 11710.49 405.27 4640.78 5065.91 16373.00 31.18 16 10 10 011/10/2024 12:0012:02 Sparged Separator; Trace Solids Observed.1465.26 101.17 0.00 0.00 318.32 74.72 181.99 68.50 163.06 70.46 128 0.00 81.00 73.55 67.32 66.31 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8406 0.0000 4.5790 395.04 0.00 21.39 4659.46 11818.04 405.17 4686.42 5064.63 16504.46 0.00 21.73 4760.51 11809.67 413.96 4649.40 5174.47 16480.80 31.24 16 10 10 011/10/2024 12:30 1464.34 101.16 0.00 0.00 317.74 75.18 181.49 68.35 161.55 70.88 128 0.00 81.41 71.82 67.59 66.63 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8327 0.0000 4.6171 416.06 0.00 21.39 4405.14 11909.81 383.06 4694.40 4788.20 16604.21 0.00 21.73 4460.90 11902.61 387.90 4657.48 4848.80 16581.82 31.29 16 10 10 011/10/2024 13:00 Collected Tracerco Sample. 1462.96 101.16 0.00 0.00 328.97 75.86 182.72 67.99 165.85 71.17 128 0.00 85.12 74.21 67.56 66.55 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8549 0.0000 4.6558 398.51 0.00 21.39 4654.68 12006.78 404.75 4702.84 5059.44 16709.62 0.00 21.73 4627.35 11999.01 402.38 4665.87 5029.73 16686.60 31.35 16 10 10 011/10/2024 13:30 1462.38 101.16 0.00 0.00 321.56 75.79 179.88 67.79 162.11 71.21 128 0.00 82.07 73.54 67.42 66.31 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8588 0.0000 4.6945 398.26 0.00 21.39 4667.60 12104.02 405.88 4711.30 5073.47 16815.31 0.00 21.73 4594.06 12094.72 399.48 4674.19 4993.54 16790.63 31.40 16 10 10 011/10/2024 14:00Decreased Expro adjustable Choke to 52/64ths as per Santos WSS.1461.81 101.16 0.00 0.00 322.52 75.55 184.46 67.84 164.32 71.22 52 0.00 85.40 73.95 67.61 66.36 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.8551 0.0000 4.7332 398.13 0.00 21.39 4659.67 12201.09 405.19 4719.74 5064.86 16920.83 0.00 21.73 4660.64 12191.82 405.27 4682.63 5065.91 16896.17 31.46 16 10 10 011/10/2024 14:30 1492.58 101.20 0.00 0.00 362.40 73.68 300.50 67.15 131.01 68.28 52 0.00 74.19 69.82 66.36 65.43 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.5069 0.0000 4.7646 435.10 0.00 21.39 3463.38 12273.24 301.16 4726.02 3764.55 16999.26 0.00 21.73 3495.48 12264.64 303.95 4688.97 3799.43 16975.33 31.50 16 10 10 011/10/2024 15:00 1501.21 101.20 0.00 0.00 348.26 73.46 288.40 68.22 132.83 67.83 52 0.00 77.56 73.16 65.99 64.55 29.9 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.4140 0.0000 4.7940 414.36 0.00 21.39 3412.54 12344.33 296.74 4732.20 3709.29 17076.54 0.00 21.73 3537.45 12338.34 225.79 4693.67 3763.25 17053.73 31.54 16 10 10 011/10/2024 15:30 1503.26 101.20 0.00 0.00 344.36 73.24 281.09 68.03 129.19 67.80 52 0.00 75.03 71.95 65.72 64.44 29.6 29000 8 0.696 0.10 0.0 6.00 0.00 6.00 6.00 0.0000 1.3872 0.0000 4.8229 394.94 0.00 21.39 3512.59 12417.51 224.21 4736.87 3736.80 17154.39 0.00 21.73 3609.46 12413.53 189.97 4697.63 3799.43 17132.89 31.57 16 10 10 011/10/2024 16:00 1504.91 101.20 0.00 0.00 343.90 72.87 281.31 67.85 129.67 67.61 52 0.00 75.81 71.29 65.64 64.46 29.6 29000 8 0.696 0.10 0.0 5.00 0.00 5.00 5.00 0.0000 1.3744 0.0000 4.8515 387.18 0.00 21.39 3549.79 12491.47 186.83 4740.77 3736.62 17232.23 0.00 21.73 3537.45 12487.23 225.79 4702.33 3763.25 17211.29 31.60 16 10 10 011/10/2024 16:30 1505.19 101.19 0.00 0.00 345.40 73.25 281.05 67.25 131.05 67.62 52 0.00 75.73 72.36 65.66 64.46 29.6 29000 8 0.696 0.10 0.0 6.00 0.00 6.00 6.00 0.0000 1.3704 0.0000 4.8801 391.58 0.00 21.39 3499.80 12564.38 223.39 4745.42 3723.20 17309.80 0.00 21.73 3462.19 12559.36 301.06 4708.60 3763.25 17289.69 31.63 16 10 10 011/10/2024 17:00 1506.29 101.19 0.00 0.00 343.60 72.85 281.45 66.73 129.13 67.46 52 0.00 75.99 71.17 65.38 64.20 29.6 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.3763 0.0000 4.9088 398.91 0.00 21.39 3450.38 12636.26 300.03 4751.67 3750.42 17387.93 0.00 21.73 3528.77 12632.87 306.85 4715.00 3835.62 17369.60 31.67 16 10 10 011/10/2024 17:30 1506.96 101.19 0.00 0.00 345.47 72.64 280.79 66.60 128.66 67.34 52 0.00 75.75 71.44 65.35 64.11 29.6 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.3793 0.0000 4.9375 399.75 0.00 21.39 3450.55 12708.14 300.05 4757.93 3750.60 17466.07 0.00 21.73 3495.48 12705.70 303.95 4721.33 3799.43 17448.75 31.71 16 10 10 011/10/2024 18:00 1507.11 101.19 0.00 0.00 348.34 72.82 284.50 67.32 130.97 67.32 52 0.00 74.94 71.18 65.16 64.08 29.6 29000 8 0.696 0.10 0.0 8.00 0.00 8.00 8.00 0.0000 1.3779 0.0000 4.9662 397.91 0.00 21.39 3462.98 12780.29 301.13 4764.20 3764.10 17544.49 0.00 21.73 3537.45 12779.39 225.79 4726.03 3763.25 17527.15 31.75 16 10 10 011/10/2024 18:30 1506.86 101.19 0.00 0.00 347.29 73.03 283.18 66.35 132.14 67.31 52 0.00 75.16 70.79 65.24 63.97 29.6 29000 8 0.696 0.10 0.0 6.00 0.00 6.00 6.00 0.0000 1.3822 0.0000 4.9950 391.57 0.00 21.39 3529.86 12853.82 225.31 4768.90 3755.17 17622.72 0.00 21.73 3499.82 12852.31 263.43 4731.52 3763.25 17605.55 31.78 16 10 10 011/10/2024 19:00Decreased Expro adjustable Choke to 44/64ths as per Santos WSS.Collected Tracerco sample.1507.56 101.19 0.00 0.00 347.90 72.78 312.20 66.16 115.47 67.05 44 0.00 74.93 71.46 65.03 63.86 29.6 29000 8 0.696 0.10 0.0 7.00 0.00 7.00 7.00 0.0000 1.3853 0.0000 5.0239 396.67 0.00 21.39 3492.55 12926.58 262.88 4774.38 3755.43 17700.96 0.00 21.73 3571.47 12926.71 227.97 4736.27 3799.43 17684.71 31.82 16 10 10 011/10/2024 19:30 1523.87 101.21 0.00 0.00 364.81 72.26 324.98 65.15 114.44 65.74 44 0.00 74.79 71.34 64.28 63.29 29.6 29000 8 0.696 0.10 0.0 6.00 0.00 6.00 6.00 0.0000 1.2002 0.0000 5.0489 412.43 0.00 21.39 2910.07 12987.21 185.75 4778.25 3095.82 17765.46 0.00 21.73 2987.44 12988.95 124.48 4738.86 3111.92 17749.54 31.84 16 10 10 011/10/2024 20:00 1528.54 101.21 0.00 0.00 354.71 72.11 314.87 64.54 113.29 65.78 44 0.00 72.08 69.47 63.86 62.64 29.6 29000 8 0.696 0.10 0.0 4.00 0.00 4.00 4.00 0.0000 1.1773 0.0000 5.0734 399.45 0.00 21.39 2947.32 13048.61 122.80 4780.81 3070.12 17829.42 0.00 21.73 2952.70 13050.47 123.03 4741.43 3075.73 17813.62 31.87 16 10 10 011/10/2024 20:30 1530.19 101.21 0.00 0.00 356.98 70.91 317.06 64.92 110.93 65.21 44 0.00 72.44 69.89 63.62 62.37 29.6 29000 8 0.696 0.10 0.0 4.00 0.00 4.00 4.00 0.0000 1.1575 0.0000 5.0975 389.28 0.00 21.39 2973.43 13110.56 123.89 4783.39 3097.32 17893.95 0.00 21.73 3093.83 13114.92 162.83 4744.82 3256.66 17881.46 31.88 16 10 10 011/10/2024 21:00 1531.03 101.21 0.00 0.00 352.50 71.04 317.04 65.71 114.90 65.00 44 0.00 73.87 71.79 63.51 61.96 29.6 29000 8 0.696 0.10 0.0 5.00 0.00 5.00 5.00 0.0000 1.1503 0.0000 5.1215 391.97 0.00 21.39 2934.58 13171.69 154.45 4786.60 3089.03 17958.30 0.00 21.73 3022.18 13177.88 125.92 4747.44 3148.10 17947.05 31.91 16 10 10 011/10/2024 21:30 1532.08 101.21 0.00 0.00 356.45 70.96 317.46 65.02 114.51 65.01 44 0.00 73.49 71.09 63.27 61.94 29.9 29000 8 0.698 0.10 0.0 4.00 0.00 4.00 4.00 0.0000 1.1484 0.0000 5.1454 385.04 0.00 21.39 2982.53 13233.83 124.27 4789.19 3106.80 18023.02 0.00 21.73 2883.23 13237.95 120.13 4749.94 3003.36 18009.62 31.92 16 10 10 011/10/2024 22:00 1532.19 101.20 0.00 0.00 359.63 70.70 316.38 64.10 115.77 64.90 44 0.00 73.25 70.83 63.03 61.88 29.9 29000 8 0.698 0.10 0.0 4.00 0.00 4.00 4.00 0.0000 1.1503 0.0000 5.1694 386.23 0.00 21.39 2978.28 13295.88 124.09 4791.78 3102.37 18087.66 0.00 21.73 3018.56 13300.84 93.36 4751.89 3111.92 18074.45 31.94 16 10 10 011/10/2024 22:30 1533.36 101.20 0.00 0.00 359.11 70.69 315.90 64.71 113.34 65.02 44 0.00 72.13 70.04 63.16 61.90 29.9 29000 8 0.698 0.10 0.0 3.00 0.00 3.00 3.00 0.0000 1.1510 0.0000 5.1933 381.92 0.00 21.39 3013.75 13358.66 93.21 4793.72 3106.96 18152.38 0.00 21.73 3053.66 13364.45 94.44 4753.86 3148.10 18140.04 31.95 16 10 10 011/10/2024 23:00 1533.21 101.20 0.00 0.00 359.09 70.58 316.56 65.12 115.08 64.69 44 0.00 74.21 72.18 63.16 61.77 29.9 29000 8 0.698 0.10 0.0 3.00 0.00 3.00 3.00 0.0000 1.1514 0.0000 5.2173 383.17 0.00 21.39 3005.06 13421.27 92.94 4795.66 3098.00 18216.93 0.00 21.73 3123.86 13429.53 96.61 4755.87 3220.47 18207.13 31.97 16 10 10 011/10/2024 23:30 1534.11 101.20 0.00 0.00 360.89 70.93 317.80 64.89 115.10 64.96 44 0.00 72.35 69.64 62.87 61.66 29.9 29000 8 0.698 0.10 0.0 3.00 0.00 3.00 3.00 0.0000 1.1569 0.0000 5.2414 382.19 0.00 21.39 3026.94 13484.33 93.62 4797.61 3120.56 18281.94 0.00 21.73 3022.18 13492.50 125.92 4758.49 3148.10 18272.72 31.98 16 10 10 011/11/2024 00:00NDBi-016 Shut-in at Choke Manifold.00:01 Discontinued all Chemical Injection.00:02 Closed Wellhead Master Valve (23.5 turns).1534.85 101.20 0.00 0.00 374.94 70.89 375.98 64.64 70.18 64.79 0 0.00 63.58 65.51 62.76 61.57 29.9 29000 8 0.698 0.10 0.0 4.00 0.00 4.00 4.00 0.0000 1.1496 0.0000 5.2654 384.83 0.00 21.39 2987.38 13546.57 124.47 4800.20 3111.85 18346.77 0.00 21.73 3088.76 13556.85 95.53 4760.48 3184.29 18339.05 32.00 16 10 10 0WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 22 Santos Pikka Development NDBi-016 SECTION 6 TEST DATA PLOTS WELL CLEAN-UP WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 23 0.0016.0032.0048.0064.0080.0096.00112.00128.00144.00160.000200400600800100012001400160018002000Pressure (psig)Santos - Pikka Development - NDBi-016_Well Clean-Up FlowBottom Hole Plot I/A Pressure BHP BHTChoke SizeTemperature (°F) / Size (64ths)WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 24 014284256708498112126140050100150200250300350400450500Temperature (°F) / Size (64ths)Pressure (psig)Santos - Pikka Development - NDBi-016_Well Clean-Up FlowWell Head / Choke PlotWell Head PressureU/S Choke PressureD/S Choke PressureWell Head TemperatureU/S Choke TemperatureD/S Choke TemperatureChoke SizeWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 25 01530456075901051201351500200400600800100012001400160018002000Temperature (°F) / Size (64ths)Pressure (psig)Santos - Pikka Development - NDBi-016_Well Clean-Up FlowWell Head vs Bottom Hole Conditions Plot I/A PressureWell Head Pressure BHP BHTWell Head TemperatureChoke SizeWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 26 0.05.010.015.020.025.030.035.040.045.050.055.005001000150020002500300035004000450050005500Gas Rate (MMscf/day) / Solids Rate (stb/day) Fluid Rate (bbl/day)Santos - Pikka Development - NDBi-016_Well Clean-Up Flow Production Rate Plot - Flow MeterOil RateTotal Fluid RateWater RateTotal Gas Rate (N2+Formation)Solids, Mud & Carbolite RateNitrogen Injection RateWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 27 0.07.014.021.028.035.042.049.056.0010002000300040005000600070008000Gas Rate (MMscf/day) / Solids Rate (stb/day) Fluid Rate (bbl/day)Santos - Pikka Development - NDBi-016_Well Clean-Up Flow Production Rate Plot - Tank StrapOil RateTotal Fluid RateWater RateTotal Gas Rate (N2+Formation)Solids, Mud & Carbolite RateNitrogen Injection RateWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 28 0.02.55.07.510.012.515.017.520.022.525.002000400060008000100001200014000160001800020000Gas Cumulative (MMscf) / Solids Cumulative (stb)Fluid Cumulative (bbls)Santos - Pikka Development - NDBi-016_Well Clean-Up Flow Cumulative Plot - Flow MeterOil CumulativeWater CumulativeTotal Fluid CumulativeTotal Gas Cumulative (N2+Formation)Nitrogen Injection Solids, Mud, & Carbolite CumulativeWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 29 0.02.44.87.29.612.014.416.819.221.624.002000400060008000100001200014000160001800020000Gas Cumulative (MMscf) / Solids Cumulative (stb)Fluid Cumulative (bbls)Santos - Pikka Development - NDBi-016_Well Clean-Up Flow Cumulative Plot - Tank StrapOil CumulativeWater CumulativeTotal Fluid CumulativeTotal Gas Cumulative (N2+Formation)Nitrogen Injection Solids, Mud, & Carbolite CumulativeWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 30 0.012.024.036.048.060.072.084.096.00100200300400500600700800BSW (%) / Frac Water Recovery (%)GOR (scf/stb)Santos - Pikka Development - NDBi-016_Well Clean-Up Flow Production Ratio PlotTotal GORSolids, Mud & Carbolite @ ChokeWater Cut @ ChokePercentage of Frac Water RecoveredTotal Choke BS&W WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 31 01224364860720306090120150180Temperature (°F)Pressure (psig)Santos - Pikka Development - NDBi-016_Well Clean-Up FlowTest Separator PlotD/S Heater PressureSeparator PressureOil TemperatureGas TemperatureWT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 32 Santos Pikka Development NDBi-016 SECTION 7 TANK FARM RATES AND VOLUMES WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 33 Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining (mm/dd/yyyy hh:mm:ss) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (bbls/d) (bbls) (bbls/min) (bbls) (bbls/min) (bbls)11-6-2024 11:30 1.4 5.3 288.8 0.8 3.0 291.0 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 0.00 0.00 0.0 0.0 0.0 0.011-6-2024 12:00 1.4 5.3 288.8 0.8 3.0 291.0 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 0.00 0.00 0.0 0.0 0.0 0.011-6-2024 12:30 1.4 5.3 288.8 0.8 3.0 291.0 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 0.00 0.00 0.0 0.0 0.0 0.011-6-2024 13:00 9.0 33.2 260.9 0.8 3.0 291.0 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 934.08 27.89 0.0 0.0 0.0 0.011-6-2024 13:30 9.0 33.2 260.9 7.0 25.6 268.4 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 1085.55 50.51 0.0 0.0 0.0 0.011-6-2024 14:00 11.9 43.7 250.3 7.0 25.6 268.4 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 506.59 61.06 0.0 0.0 0.0 0.011-6-2024 14:30 11.9 43.7 250.3 9.8 36.2 257.9 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 506.59 71.62 0.0 0.0 0.0 0.011-6-2024 15:00 15.2 55.8 238.3 9.8 36.2 257.9 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 578.96 83.68 0.0 0.0 0.0 0.011-6-2024 15:30 15.2 55.8 238.3 14.4 52.8 241.3 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 796.07 100.26 0.0 0.0 0.0 0.011-6-2024 16:00 15.2 55.8 238.3 14.4 52.8 241.3 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 796.07 100.26 0.0 0.0 0.0 0.011-6-2024 16:30 23.8 87.4 206.6 23.0 84.4 209.6 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 1519.77 163.59 0.0 0.0 0.0 0.011-6-2024 17:00 23.8 87.4 206.6 23.0 84.4 209.6 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 1085.55 186.20 0.0 0.0 0.0 0.011-6-2024 17:30 29.9 110.1 184.0 30.6 112.3 181.7 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 1338.85 214.10 0.0 0.0 0.0 0.011-6-2024 18:00 37.1 136.4 157.6 30.6 112.3 181.7 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 1266.48 240.48 0.0 0.0 0.0 0.011-6-2024 18:30 37.1 136.4 157.6 43.7 160.6 133.5 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 2315.85 288.73 0.0 0.0 0.0 0.011-6-2024 19:00 52.5 193.0 101.1 43.7 160.6 133.5 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 2713.88 345.27 0.0 0.0 0.0 0.011-6-2024 19:30 52.5 193.0 101.1 60.1 220.9 73.2 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 2894.81 405.57 0.0 0.0 0.0 0.011-6-2024 20:00 68.1 250.3 43.8 60.1 220.9 73.2 0.6 2.3 291.8 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 2750.07 462.87 0.0 0.0 0.0 0.011-6-2024 20:30 68.1 250.3 43.8 60.1 220.9 73.2 20.1 73.9 220.2 1.4 5.3 288.8 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3437.58 534.48 0.0 0.0 0.0 0.011-6-2024 21:00 68.1 250.3 43.8 60.1 220.9 73.2 20.1 73.9 220.2 19.3 70.9 223.2 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3148.10 600.07 0.0 0.0 0.0 0.011-6-2024 21:30 68.1 250.3 43.8 60.1 220.9 73.2 39.0 143.2 150.8 19.3 70.9 223.2 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3329.03 669.42 0.0 0.0 0.0 0.011-6-2024 22:00 68.1 250.3 43.8 60.1 220.9 73.2 39.0 143.2 150.8 37.3 137.2 156.9 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3184.29 735.76 0.0 0.0 0.0 0.011-6-2024 22:30 68.1 250.3 43.8 60.1 220.9 73.2 56.6 208.1 86.0 37.3 137.2 156.9 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3111.92 800.60 0.0 0.0 0.0 0.011-6-2024 23:00 68.1 250.3 43.8 60.1 220.9 73.2 56.6 208.1 86.0 55.8 205.0 89.0 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3256.66 868.44 0.0 0.0 0.0 0.011-6-2024 23:30 2.1 7.5 286.5 60.1 220.9 73.2 75.3 276.7 17.4 55.8 205.0 89.0 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3292.84 937.04 0.0 0.0 0.0 0.011-7-2024 0:00 2.1 7.5 286.5 60.1 220.9 73.2 75.3 276.7 17.4 74.2 272.9 21.2 0.8 3.0 291.0 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3256.66 1004.89 0.0 0.0 0.0 0.011-7-2024 0:30 2.1 7.5 286.5 1.6 6.0 288.0 75.3 276.7 17.4 74.2 272.9 21.2 20.3 74.6 219.4 0.4 1.5 292.6 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3437.58 1076.51 0.0 0.0 0.0 0.011-7-2024 1:00 2.1 7.5 286.5 1.6 6.0 288.0 75.3 276.7 17.4 74.2 272.9 21.2 20.3 74.6 219.4 19.9 73.1 220.9 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3433.96 1148.05 0.0 0.0 0.0 0.011-7-2024 1:30 2.1 7.5 286.5 1.6 6.0 288.0 75.3 276.7 17.4 74.2 272.9 21.2 39.0 143.2 150.8 19.9 73.1 220.9 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3292.84 1216.65 0.0 0.0 0.0 0.011-7-2024 2:00 2.1 7.5 286.5 1.6 6.0 288.0 75.3 276.7 17.4 74.2 272.9 21.2 39.0 143.2 150.8 38.1 140.2 153.8 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3224.09 1283.82 0.0 0.0 0.0 0.011-7-2024 2:30 2.1 7.5 286.5 1.6 6.0 288.0 75.3 276.7 17.4 74.2 272.9 21.2 57.4 211.1 83.0 38.1 140.2 153.8 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3256.66 1351.66 0.0 0.0 0.0 0.011-7-2024 3:00 2.1 7.5 286.5 1.6 6.0 288.0 2.5 9.0 285.0 74.2 272.9 21.2 57.4 211.1 83.0 57.0 209.6 84.5 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3329.03 1421.02 0.0 0.0 0.0 0.011-7-2024 3:30 2.1 7.5 286.5 1.6 6.0 288.0 2.5 9.0 285.0 74.2 272.9 21.2 79.4 291.7 2.3 57.0 209.6 84.5 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3871.80 1501.68 0.0 0.0 0.0 0.011-7-2024 4:00 2.1 7.5 286.5 1.6 6.0 288.0 2.5 9.0 285.0 20.5 75.4 218.7 79.4 291.7 2.3 57.0 209.6 84.5 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3871.80 1501.68 0.0 0.0 0.0 0.011-7-2024 4:30 23.6 86.7 207.4 1.6 6.0 288.0 2.5 9.0 285.0 20.5 75.4 218.7 79.4 291.7 2.3 75.7 278.2 15.9 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3799.43 1649.44 0.0 0.0 0.0 0.011-7-2024 5:00 23.6 86.7 207.4 20.3 74.6 219.4 2.5 9.0 285.0 4.1 15.1 279.0 79.4 291.7 2.3 75.7 278.2 15.9 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3292.84 1718.04 0.0 0.0 0.0 0.011-7-2024 5:30 44.7 164.3 129.7 20.3 74.6 219.4 2.5 9.0 285.0 4.1 15.1 279.0 79.4 291.7 2.3 75.7 278.2 15.9 0.8 3.0 291.0 0.8 3.0 291.0 0.6 2.3 291.8 0.8 3.0 291.0 3727.06 1795.68 0.0 0.0 0.0 0.011-7-2024 6:00 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.079.4291.74 2.375.7278.17 15.90.83.02 291.00.83.02 291.00.62.26 291.80.83.02 291.0 3437.58 1867.30 0.0 0.0 0.0 0.011-7-2024 6:30 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.921.177.65 216.40.83.02 291.00.62.26 291.80.83.02 291.0 3582.32 1941.93 0.0 0.0 0.0 0.011-7-2024 7:00 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.921.177.65 216.418.066.34 227.70.62.26 291.80.83.02 291.0 3039.55 2005.26 0.0 0.0 0.0 0.011-7-2024 7:30 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.942.2155.29 138.818.066.34 227.70.62.26 291.80.83.02 291.0 3727.06 2082.90 0.0 0.0 0.0 0.011-7-2024 8:00 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.942.2155.29 138.840.6149.26 144.80.62.26 291.80.83.02 291.0 3980.36 2168.84 0.00 0.00 0.00 0.0011-7-2024 8:30 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.961.5226.16 67.940.6149.26 144.80.62.26 291.80.83.02 291.0 3401.40 2236.69 0.00 0.00 0.00 0.0011-7-2024 9:00 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.961.5226.16 67.958.4214.85 79.20.62.26 291.80.83.02 291.0 3148.10 2296.25 0.00 0.00 0.00 0.0011-7-2024 9:30 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.012.947.49 246.675.7278.17 15.984.1309.08 0.058.4214.85 79.20.62.26 291.80.83.02 291.0 3980.36 2385.20 0.00 0.00 0.00 0.0011-7-2024 10:00 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.00.83.02 291.075.7278.17 15.984.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 0.00 2413.85 0.00 0.00 0.00 0.0011-7-2024 10:30 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 0.00 2413.85 0.00 0.00 0.00 0.0011-7-2024 11:00 44.7164.34 129.739.8146.25 147.82.59.05 285.04.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 0.00 2413.85 0.00 0.00 0.00 0.0011-7-2024 11:30 59.5218.62 75.439.8146.25 147.82.59.05 285.04.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 3256.66 2468.12 0.00 0.00 0.00 0.0011-7-2024 12:00 59.5218.62 75.456.6208.06 86.02.59.05 285.04.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 2967.18 2529.94 2.34 31.53 0.00 0.0011-7-2024 12:30 78.3287.97 6.156.6208.06 86.02.59.05 285.04.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 3329.03 2599.30 3.16 106.05 0.00 0.0011-7-2024 13:00 78.3287.97 6.178.3287.97 6.12.59.05 285.04.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 3835.62 2679.20 2.29 191.96 0.00 0.0011-7-2024 13:30 78.3287.97 6.178.3287.97 6.125.894.99 199.14.115.08 279.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 4125.10 2765.14 2.29 260.73 0.00 0.0011-7-2024 14:00 78.3287.97 6.178.3287.97 6.125.894.99 199.128.3104.03 190.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 4269.84 2854.10 2.75 333.89 0.00 0.0011-7-2024 14:30 78.3287.97 6.178.3287.97 6.150.5185.45 108.628.3104.03 190.00.83.02 291.06.222.62 271.484.1309.08 0.066.2243.50 50.60.62.26 291.80.83.02 291.0 4342.21 2944.56 2.76 416.74 0.00 0.0011-7-2024 15:00 78.3287.97 6.178.3287.97 6.150.5185.45 108.652.5192.99 101.10.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.40.62.26 291.80.83.02 291.0 4269.84 3033.52 2.74 499.72 0.00 0.0011-7-2024 15:30 78.3287.97 6.178.3287.97 6.177.1283.45 10.652.5192.99 101.10.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.40.62.26 291.80.83.02 291.0 4704.06 3131.52 2.75 582.15 0.00 0.0011-7-2024 16:00 78.3287.97 6.178.3287.97 6.177.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.40.62.26 291.80.83.02 291.0 4631.69 3228.01 2.75 664.82 0.00 0.0011-7-2024 16:30 78.3287.97 6.178.3287.97 6.177.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.428.3104.03 190.00.83.02 291.0 4884.99 3329.78 2.77 750.77 0.00 0.0011-7-2024 17:00 78.3287.97 6.178.3287.97 6.177.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.428.3104.03 190.028.7105.54 188.5 4921.17 3432.31 2.78 830.43 0.00 0.0011-7-2024 17:30 78.3287.97 6.178.3287.97 6.177.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.454.1199.02 95.028.7105.54 188.5 4559.32 3527.29 3.51 933.31 0.00 0.00Fluid Injection Cumulative into NDBi-014Fluid Injection Rate into NDBi-030TANK 611-NOV-2024 @ 00:00 hrs.TANK 2 TANK 3 TANK 4 TANK 5 NDBi-016NDBi-016 WELL CLEAN-UP_TANK FARM TO INJECTION WELL NDBi-014 & NDBi-030Well:Tank Strap Fluid RateTank Strap Fluid CumulativeStart Data:End Date:Date & TimeFluid Injection Rate into NDBi-014Fluid Injection Cumulative into NDBi-030TANK 106-NOV-2024 @ 12:17 hrs.TANK 7 TANK 8 TANK 9 TANK 10WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 34 Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining (mm/dd/yyyy hh:mm:ss) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (bbls/d) (bbls) (bbls/min) (bbls) (bbls/min) (bbls)Fluid Injection Cumulative into NDBi-014Fluid Injection Rate into NDBi-030TANK 611-NOV-2024 @ 00:00 hrs.TANK 2 TANK 3 TANK 4 TANK 5 NDBi-016NDBi-016 WELL CLEAN-UP_TANK FARM TO INJECTION WELL NDBi-014 & NDBi-030Well:Tank Strap Fluid RateTank Strap Fluid CumulativeStart Data:End Date:Date & TimeFluid Injection Rate into NDBi-014Fluid Injection Cumulative into NDBi-030TANK 106-NOV-2024 @ 12:17 hrs.TANK 7 TANK 8 TANK 9 TANK 1011-7-2024 18:00 6.624.12 269.910.739.20 254.977.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.454.1199.02 95.053.5196.76 97.3 4378.40 3618.51 3.48 1037.30 0.00 0.0011-7-2024 18:30 6.624.12 269.910.739.20 254.977.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.478.3287.97 6.153.5196.76 97.3 4269.84 3707.46 3.49 1140.99 0.00 0.0011-7-2024 19:00 6.624.12 269.910.739.20 254.977.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.478.3287.97 6.178.3287.97 6.1 4378.40 3798.68 3.47 1240.60 0.00 0.0011-7-2024 19:30 32.2118.36 175.710.739.20 254.977.1283.45 10.678.8289.48 4.60.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.478.3287.97 6.178.3287.97 6.1 4450.77 3891.40 3.53 1349.56 0.00 0.0011-7-2024 20:00 32.2118.36 175.710.739.20 254.99.233.92 260.113.549.75 244.30.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.458.9216.36 77.759.5218.62 75.4 4088.91 3976.59 3.48 1451.61 0.00 0.0011-7-2024 20:30 56.6208.06 86.010.739.20 254.99.233.92 260.113.549.75 244.30.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.458.9216.36 77.759.5218.62 75.4 4306.03 4066.30 3.48 1451.61 0.00 0.0011-7-2024 21:00 56.6208.06 86.057.6211.83 82.29.233.92 260.113.549.75 244.30.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.437.9139.46 154.639.6145.49 148.6 4269.84 4155.25 3.48 1660.09 0.00 0.0011-7-2024 21:30 56.6208.06 86.057.6211.83 82.233.0121.37 172.713.549.75 244.30.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.437.9139.46 154.639.6145.49 148.6 4197.47 4242.70 3.51 1762.85 0.00 0.0011-7-2024 22:00 56.6208.06 86.057.6211.83 82.233.0121.37 172.737.7138.71 155.40.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.437.9139.46 154.639.6145.49 148.6 4269.84 4331.66 3.47 1864.71 0.00 0.0011-7-2024 22:30 56.6208.06 86.057.6211.83 82.257.2210.33 83.737.7138.71 155.40.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.437.9139.46 154.639.6145.49 148.6 4269.84 4420.61 3.47 1970.59 0.00 0.0011-7-2024 23:00 27.5101.02 193.032.0117.60 176.557.2210.33 83.762.3229.17 64.90.83.02 291.06.222.62 271.47.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4342.21 4511.07 3.47 2070.32 0.00 0.0011-7-2024 23:30 27.5101.02 193.032.0117.60 176.557.2210.33 83.762.3229.17 64.925.091.97 202.16.222.62 271.47.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4269.84 4600.03 3.07 2169.08 0.00 0.0011-8-2024 0:00 27.5101.02 193.032.0117.60 176.557.2210.33 83.762.3229.17 64.925.091.97 202.130.8113.08 181.07.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4342.21 4690.49 3.01 2260.28 0.00 0.0011-8-2024 0:30 11.542.22 251.812.144.48 249.657.2210.33 83.762.3229.17 64.949.6182.43 111.630.8113.08 181.07.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4342.21 4780.95 0.00 2260.28 0.00 0.0011-8-2024 1:00 11.542.22 251.812.144.48 249.657.2210.33 83.762.3229.17 64.949.6182.43 111.655.6204.29 89.87.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4378.40 4872.17 2.98 2350.99 0.00 0.0011-8-2024 1:30 11.542.22 251.812.144.48 249.657.2210.33 83.762.3229.17 64.974.7274.40 19.755.6204.29 89.87.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4414.58 4964.14 3.02 2446.17 0.00 0.0011-8-2024 2:00 11.542.22 251.812.144.48 249.611.542.22 251.816.058.80 235.374.7274.40 19.780.8297.02 0.07.427.14 266.96.222.62 271.410.739.20 254.911.943.72 250.3 4450.77 5056.87 3.01 2539.02 0.00 0.0011-8-2024 2:30 11.542.22 251.812.144.48 249.611.542.22 251.816.058.80 235.374.7274.40 19.780.8297.02 0.034.0125.14 168.96.222.62 271.410.739.20 254.911.943.72 250.3 4704.06 5154.87 2.99 2623.27 0.00 0.0011-8-2024 3:00 11.542.22 251.812.144.48 249.611.542.22 251.816.058.80 235.374.7274.40 19.780.8297.02 0.034.0125.14 168.931.6116.09 178.010.739.20 254.911.943.72 250.3 4486.95 5248.35 2.98 2710.14 0.00 0.0011-8-2024 3:30 11.542.22 251.812.144.48 249.611.542.22 251.816.058.80 235.353.3196.00 98.153.3196.00 98.161.3225.40 68.731.6116.09 178.010.739.20 254.911.943.72 250.3 4812.62 5348.61 3.04 2800.52 0.00 0.0011-8-2024 4:00 11.542.22 251.812.144.48 249.611.542.22 251.816.058.80 235.353.3196.00 98.153.3196.00 98.161.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4776.43 5448.12 3.02 2893.29 0.00 0.0011-8-2024 4:30 37.7138.71 155.412.144.48 249.611.542.22 251.816.058.80 235.331.8116.85 177.228.5104.79 189.361.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4631.69 5544.61 3.01 3004.28 0.00 0.0011-8-2024 5:00 37.7138.71 155.439.0143.23 150.811.542.22 251.816.058.80 235.311.140.71 253.48.430.91 263.261.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4740.25 5643.37 3.01 3004.28 0.00 0.0011-8-2024 5:30 37.7138.71 155.439.0143.23 150.811.542.22 251.816.058.80 235.311.140.71 253.48.430.91 263.261.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4776.43 5742.88 3.01 3004.28 0.00 0.0011-8-2024 6:00 64.8238.22 55.866.7245.00 49.111.542.22 251.816.058.80 235.311.140.71 253.48.430.91 263.261.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4884.99 5844.65 3.02 3250.04 0.00 0.0011-8-2024 6:30 64.8238.22 55.866.7245.00 49.138.4140.97 153.116.058.80 235.311.140.71 253.48.430.91 263.261.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4740.25 5943.40 3.02 3342.35 0.00 0.0011-8-2024 7:00 64.8238.22 55.866.7245.00 49.138.4140.97 153.142.7156.80 137.311.140.71 253.48.430.91 263.261.3225.40 68.758.7215.60 78.510.739.20 254.911.943.72 250.3 4704.06 6041.40 3.00 3435.80 0.00 0.0011-8-2024 7:30 64.8238.22 55.866.7245.00 49.165.2239.73 54.342.7156.80 137.311.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.410.739.20 254.911.943.72 250.3 4740.25 6140.16 2.98 3524.93 0.00 0.0011-8-2024 8:00 64.8238.22 55.866.7245.00 49.165.2239.73 54.369.5255.56 38.511.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.410.739.20 254.911.943.72 250.3 4740.25 6238.91 3.01 3615.60 0.00 0.0011-8-2024 8:30 64.8238.22 55.866.7245.00 49.165.2239.73 54.369.5255.56 38.511.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.434.7127.40 166.711.943.72 250.3 4233.66 6327.11 0.00 3615.60 0.00 0.0011-8-2024 9:00 1.66.03 288.066.7245.00 49.165.2239.73 54.369.5255.56 38.511.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.434.7127.40 166.737.3137.20 156.9 4486.95 6420.59 3.02 3760.30 0.00 0.0011-8-2024 9:30 1.66.03 288.066.7245.00 49.165.2239.73 54.369.5255.56 38.511.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.460.3221.63 72.437.3137.20 156.9 4523.14 6514.82 3.03 3854.56 0.00 0.0011-8-2024 10:00 1.66.03 288.066.7245.00 49.165.2239.73 54.369.5255.56 38.511.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.460.3221.63 72.463.0231.43 62.6 4523.14 6609.06 3.03 3945.36 0.00 0.0011-8-2024 10:30 1.66.03 288.066.7245.00 49.165.2239.73 54.369.5255.56 38.511.140.71 253.48.430.91 263.27.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4559.52 6704.04 3.00 4035.78 0.00 0.0011-8-2024 11:00 1.66.03 288.066.7245.00 49.165.2239.73 54.369.5255.56 38.536.1132.68 161.48.430.91 263.27.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4414.58 6796.01 2.99 4125.14 0.00 0.0011-8-2024 11:30 1.66.03 288.066.7245.00 49.165.2239.73 54.369.5255.56 38.536.1132.68 161.433.0121.37 172.77.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4342.21 6886.47 2.99 4215.15 0.00 0.0011-8-2024 12:00 1.66.03 288.010.337.69 256.412.746.74 247.315.255.79 238.360.9223.90 70.233.0121.37 172.77.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4378.40 6977.69 2.99 4303.12 0.00 0.0011-8-2024 12:30 1.66.03 288.010.337.69 256.412.746.74 247.315.255.79 238.360.9223.90 70.257.2210.33 83.77.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4269.84 7066.65 2.97 4391.02 0.00 0.0011-8-2024 13:00 1.66.03 288.010.337.69 256.412.746.74 247.315.255.79 238.385.3313.60 0.057.2210.33 83.77.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4306.03 7156.36 3.00 4482.20 0.00 0.0011-8-2024 13:30 1.66.03 288.010.337.69 256.412.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4306.03 7246.06 2.99 4574.48 0.00 0.0011-8-2024 14:00 26.396.49 197.610.337.69 256.412.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4342.21 7336.53 2.99 4662.77 0.00 0.0011-8-2024 14:30 26.396.49 197.634.2125.89 168.212.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.473.0268.37 25.776.1279.68 14.4 4233.66 7424.73 2.99 4753.18 0.00 0.0011-8-2024 15:00 49.6182.43 111.634.2125.89 168.212.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.410.739.20 254.911.943.72 250.3 4125.10 7510.67 3.02 4842.86 0.00 0.0011-8-2024 15:30 49.6182.43 111.657.4211.08 83.012.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.410.739.20 254.911.943.72 250.3 4088.91 7595.85 3.05 4934.89 0.00 0.0011-8-2024 16:00 71.4262.34 31.757.4211.08 83.012.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.410.739.20 254.911.943.72 250.3 3835.62 7675.76 3.00 5023.70 0.00 0.0011-8-2024 16:30 71.4262.34 31.780.6296.27 0.012.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.07.025.63 268.46.222.62 271.410.739.20 254.911.943.72 250.3 4088.91 7760.95 3.02 5114.09 0.00 0.0011-8-2024 17:00 71.4262.34 31.780.6296.27 0.012.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.029.9110.06 184.06.222.62 271.410.739.20 254.911.943.72 250.3 4052.73 7845.38 3.00 5203.57 0.00 0.0011-8-2024 17:30 71.4262.34 31.780.6296.27 0.012.746.74 247.315.255.79 238.385.3313.60 0.081.6300.03 0.029.9110.06 184.029.3107.80 186.310.739.20 254.911.943.72 250.3 4088.91 7930.57 3.00 5294.04 0.00 0.0011-8-2024 18:00 71.4262.34 31.780.6296.27 0.012.746.74 247.315.255.79 238.311.943.72 250.39.434.68 259.453.7197.51 96.629.3107.80 186.310.739.20 254.911.943.72 250.3 4197.47 8018.01 3.00 5294.04 0.00 0.0011-8-2024 18:30 71.4262.34 31.780.6296.27 0.012.746.74 247.315.255.79 238.311.943.72 250.39.434.68 259.453.7197.51 96.653.5196.76 97.310.739.20 254.911.943.72 250.3 4269.84 8106.97 3.06 5474.03 0.00 0.0011-8-2024 19:00 71.4262.34 31.780.6296.27 0.012.746.74 247.315.255.79 238.311.943.72 250.39.434.68 259.478.5288.73 5.353.5196.76 97.310.739.20 254.911.943.72 250.3 4378.40 8198.18 3.06 5570.83 0.00 0.0011-8-2024 19:30 38.1140.22 153.839.8146.25 147.812.746.74 247.315.255.79 238.311.943.72 250.39.434.68 259.478.5288.73 5.377.1283.45 10.610.739.20 254.911.943.72 250.3 4161.29 8284.88 3.07 5658.29 0.00 0.0011-8-2024 20:00 38.1140.22 153.839.8146.25 147.837.1136.45 157.615.255.79 238.311.943.72 250.39.434.68 259.478.5288.73 5.377.1283.45 10.610.739.20 254.911.943.72 250.3 4306.03 8374.59 3.05 5750.10 0.00 0.0011-8-2024 20:30 9.233.92 260.110.739.20 254.937.1136.45 157.640.8150.02 144.011.943.72 250.39.434.68 259.478.5288.73 5.377.1283.45 10.610.739.20 254.911.943.72 250.3 4523.14 8468.82 3.07 5841.99 0.00 0.0011-8-2024 21:00 9.233.92 260.110.739.20 254.963.0231.43 62.640.8150.02 144.011.943.72 250.39.434.68 259.478.5288.73 5.377.1283.45 10.610.739.20 254.911.943.72 250.3 4559.32 8563.80 3.14 5933.38 0.00 0.0011-8-2024 21:30 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.811.943.72 250.39.434.68 259.478.5288.73 5.377.1283.45 10.610.739.20 254.911.943.72 250.3 4667.88 8661.05 3.08 6025.03 0.00 0.0011-8-2024 22:00 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.838.1140.22 153.89.434.68 259.446.3170.37 123.745.1165.85 128.210.739.20 254.911.943.72 250.3 4631.69 8757.55 3.08 6116.14 0.00 0.0011-8-2024 22:30 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.838.1140.22 153.835.9131.92 162.130.4111.57 182.527.7101.77 192.310.739.20 254.911.943.72 250.3 4667.88 8854.79 3.08 6213.25 0.00 0.0011-8-2024 23:00 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.864.8238.22 55.835.9131.92 162.130.4111.57 182.527.7101.77 192.310.739.20 254.911.943.72 250.3 4704.06 8952.79 3.07 6308.17 0.00 0.0011-8-2024 23:30 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.864.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.410.739.20 254.911.943.72 250.3 4631.69 9049.29 3.02 6393.08 0.00 0.0011-9-2024 0:00 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.864.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.437.3137.20 156.911.943.72 250.3 4704.06 9147.29 3.06 6486.08 0.00 0.00WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 35 Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining (mm/dd/yyyy hh:mm:ss) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (bbls/d) (bbls) (bbls/min) (bbls) (bbls/min) (bbls)Fluid Injection Cumulative into NDBi-014Fluid Injection Rate into NDBi-030TANK 611-NOV-2024 @ 00:00 hrs.TANK 2 TANK 3 TANK 4 TANK 5 NDBi-016NDBi-016 WELL CLEAN-UP_TANK FARM TO INJECTION WELL NDBi-014 & NDBi-030Well:Tank Strap Fluid RateTank Strap Fluid CumulativeStart Data:End Date:Date & TimeFluid Injection Rate into NDBi-014Fluid Injection Cumulative into NDBi-030TANK 106-NOV-2024 @ 12:17 hrs.TANK 7 TANK 8 TANK 9 TANK 1011-9-2024 0:30 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.864.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.437.3137.20 156.938.1140.22 153.8 4631.69 9243.78 3.06 6486.08 0.00 0.0011-9-2024 1:00 9.233.92 260.110.739.20 254.963.0231.43 62.667.3247.26 46.864.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.463.6233.70 60.438.1140.22 153.8 4631.69 9340.28 3.04 6604.27 0.00 0.0011-9-2024 1:30 9.233.92 260.110.739.20 254.927.199.51 194.631.8116.85 177.264.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.463.6233.70 60.464.4236.71 57.4 4631.69 9436.77 3.03 6695.14 0.00 0.0011-9-2024 2:00 35.7131.17 162.910.739.20 254.97.427.14 266.911.943.72 250.364.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.463.6233.70 60.464.4236.71 57.4 4667.88 9534.02 3.03 6786.03 0.00 0.0011-9-2024 2:30 35.7131.17 162.937.7138.71 155.47.427.14 266.911.943.72 250.364.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.463.6233.70 60.464.4236.71 57.4 4776.43 9633.53 3.05 6877.19 0.00 0.0011-9-2024 3:00 62.3229.17 64.937.7138.71 155.47.427.14 266.911.943.72 250.364.8238.22 55.862.1228.42 65.612.345.23 248.811.140.71 253.463.6233.70 60.464.4236.71 57.4 4704.06 9731.53 3.04 6968.36 0.00 0.0011-9-2024 3:30 62.3229.17 64.964.0235.20 58.97.427.14 266.911.943.72 250.335.3129.66 164.432.0117.60 176.512.345.23 248.811.140.71 253.463.6233.70 60.464.4236.71 57.4 4631.69 9828.02 3.03 7069.20 0.00 0.0011-9-2024 4:00 75.5277.42 16.676.3280.43 13.67.427.14 266.911.943.72 250.335.3129.66 164.432.0117.60 176.512.345.23 248.811.140.71 253.463.6233.70 60.464.4236.71 57.4 4486.95 9921.50 3.03 7148.50 0.00 0.0011-9-2024 4:30 75.5277.42 16.676.3280.43 13.67.427.14 266.911.943.72 250.335.3129.66 164.432.0117.60 176.538.6141.72 152.311.140.71 253.463.6233.70 60.464.4236.71 57.4 4631.69 10020.25 3.04 7259.26 0.00 0.0011-9-2024 5:00 75.5277.42 16.676.9282.70 11.47.427.14 266.911.943.72 250.312.144.48 249.69.434.68 259.438.6141.72 152.336.7134.94 159.163.6233.70 60.464.4236.71 57.4 4667.88 10117.50 3.04 7330.83 0.00 0.0011-9-2024 5:30 75.5277.42 16.676.9282.70 11.47.427.14 266.911.943.72 250.312.144.48 249.69.434.68 259.465.0238.97 55.136.7134.94 159.139.8146.25 147.841.2151.53 142.5 4667.88 10214.75 3.03 7421.90 0.00 0.0011-9-2024 6:00 75.5277.42 16.676.9282.70 11.47.427.14 266.911.943.72 250.312.144.48 249.69.434.68 259.465.0238.97 55.163.4232.94 61.131.6116.09 178.032.2118.36 175.7 4704.06 10312.75 3.02 7513.09 0.00 0.0011-9-2024 6:30 75.5277.42 16.676.9282.70 11.47.427.14 266.911.943.72 250.312.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.411.140.71 253.412.345.23 248.8 4776.43 10411.51 3.02 7605.89 0.00 0.0011-9-2024 7:00 75.5277.42 16.676.9282.70 11.433.4122.88 171.211.943.72 250.312.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.411.140.71 253.412.345.23 248.8 4595.51 10507.24 3.06 7698.18 0.00 0.0011-9-2024 7:30 75.5277.42 16.676.9282.70 11.433.4122.88 171.239.8146.25 147.812.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.411.140.71 253.412.345.23 248.8 4921.17 10609.77 3.07 7788.50 0.00 0.0011-9-2024 8:00 75.5277.42 16.676.9282.70 11.462.1228.42 65.639.8146.25 147.812.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.411.140.71 253.412.345.23 248.8 5065.91 10715.31 3.07 7881.19 0.00 0.0011-9-2024 8:30 75.5277.42 16.676.9282.70 11.462.1228.42 65.668.3251.03 43.012.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.411.140.71 253.412.345.23 248.8 5029.73 10820.10 3.07 7881.19 0.00 0.0011-9-2024 9:00 11.341.46 252.612.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.411.140.71 253.412.345.23 248.8 5101.92 10926.39 3.19 8071.17 0.00 0.0011-9-2024 9:30 11.341.46 252.612.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.439.0143.23 150.812.345.23 248.8 4921.17 11028.91 3.19 8167.19 0.00 0.0011-9-2024 10:00 11.341.46 252.612.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.439.0143.23 150.812.345.23 248.8 5065.91 11134.45 3.19 8263.43 0.00 0.0011-9-2024 10:30 11.341.46 252.612.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.467.5248.02 46.041.0150.77 143.3 5029.73 11239.24 3.18 8359.23 0.00 0.0011-9-2024 11:00 11.341.46 252.612.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.478.3287.97 6.176.9282.70 11.467.5248.02 46.069.3254.80 39.3 4993.54 11343.27 3.17 8453.46 0.00 0.0011-9-2024 11:30 11.341.46 252.612.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.381.6300.03 0.083.9308.33 0.0 5065.92 11448.81 3.19 8549.71 0.00 0.0011-9-2024 12:00 39.8146.25 147.812.545.99 248.176.1279.68 14.483.3306.07 0.012.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.381.6300.03 0.083.9308.33 0.0 5029.73 11553.60 3.21 8646.11 0.00 0.0011-9-2024 12:30 39.8146.25 147.841.2151.53 142.52.910.55 283.58.631.66 262.412.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.381.6300.03 0.083.9308.33 0.0 5065.91 11659.14 3.21 8739.66 0.00 0.0011-9-2024 13:00 68.1250.28 43.841.2151.53 142.52.910.55 283.58.631.66 262.412.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.381.6300.03 0.083.9308.33 0.0 4993.54 11763.17 3.21 8835.47 0.00 0.0011-9-2024 13:30 68.1250.28 43.869.5255.56 38.52.910.55 283.58.631.66 262.412.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.381.6300.03 0.083.9308.33 0.0 4993.54 11867.20 3.21 8932.59 0.00 0.0011-9-2024 14:00 82.4303.05 0.084.1309.08 0.02.910.55 283.58.631.66 262.412.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.381.6300.03 0.083.9308.33 0.0 5138.28 11973.49 3.20 9031.23 0.00 0.0011-9-2024 14:30 82.4303.05 0.084.1309.08 0.032.0117.60 176.58.631.66 262.412.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.313.349.00 245.114.854.28 239.8 5138.28 12080.54 3.20 9127.49 0.00 0.0011-9-2024 15:00 82.4303.05 0.084.1309.08 0.032.0117.60 176.537.3137.20 156.912.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.313.349.00 245.114.854.28 239.8 5065.91 12186.08 3.21 9225.03 0.00 0.0011-9-2024 15:30 82.4303.05 0.084.1309.08 0.060.3221.63 72.437.3137.20 156.912.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.313.349.00 245.114.854.28 239.8 4993.54 12290.11 3.21 9320.99 0.00 0.0011-9-2024 16:00 82.4303.05 0.084.1309.08 0.060.3221.63 72.465.6241.23 52.812.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.313.349.00 245.114.854.28 239.8 4993.54 12394.15 3.20 9416.30 0.00 0.0011-9-2024 16:30 82.4303.05 0.084.1309.08 0.074.2272.90 21.279.8293.25 0.812.144.48 249.69.434.68 259.414.252.02 242.011.943.72 250.313.349.00 245.114.854.28 239.8 4957.44 12497.42 3.00 9507.96 0.00 0.0011-9-2024 17:00 82.4303.05 0.084.1309.08 0.074.2272.90 21.279.8293.25 0.812.144.48 249.69.434.68 259.441.8153.79 140.311.943.72 250.313.349.00 245.114.854.28 239.8 4884.96 12599.19 3.02 9595.65 0.00 0.0011-9-2024 17:30 12.746.74 247.313.951.26 242.874.2272.90 21.279.8293.25 0.812.144.48 249.69.434.68 259.441.8153.79 140.340.2147.76 146.313.349.00 245.114.854.28 239.8 4993.54 12703.23 3.01 9688.51 0.00 0.0011-9-2024 18:00 12.746.74 247.313.951.26 242.874.2272.90 21.279.8293.25 0.812.144.48 249.69.434.68 259.470.1257.82 36.240.2147.76 146.313.349.00 245.114.854.28 239.8 4993.54 12807.26 3.02 9777.54 0.00 0.0011-9-2024 18:30 12.746.74 247.313.951.26 242.845.3166.60 127.549.6182.43 111.612.144.48 249.69.434.68 259.470.1257.82 36.268.9253.30 40.813.349.00 245.114.854.28 239.8 5065.91 12912.80 3.02 9868.14 0.00 0.0011-9-2024 19:00 40.6149.26 144.813.951.26 242.845.3166.60 127.549.6182.43 111.612.144.48 249.69.434.68 259.470.1257.82 36.268.9253.30 40.813.349.00 245.114.854.28 239.8 4921.17 13015.32 3.00 9959.89 0.00 0.0011-9-2024 19:30 40.6149.26 144.842.2155.29 138.820.575.39 218.724.690.46 203.612.144.48 249.69.434.68 259.470.1257.82 36.268.9253.30 40.813.349.00 245.114.854.28 239.8 4993.54 13119.36 3.00 10049.28 0.00 0.0011-9-2024 20:00 68.9253.30 40.842.2155.29 138.810.739.20 254.915.657.29 236.812.144.48 249.69.434.68 259.470.1257.82 36.268.9253.30 40.813.349.00 245.114.854.28 239.8 4993.54 13223.39 2.97 10138.93 0.00 0.0011-9-2024 20:30 68.9253.30 40.871.2261.59 32.510.739.20 254.915.657.29 236.812.144.48 249.69.434.68 259.470.1257.82 36.268.9253.30 40.813.349.00 245.114.854.28 239.8 5102.10 13329.68 3.00 10230.27 0.00 0.0011-9-2024 21:00 68.9253.30 40.871.2261.59 32.510.739.20 254.915.657.29 236.812.144.48 249.69.434.68 259.470.1257.82 36.268.9253.30 40.842.0154.54 139.514.854.28 239.8 5065.91 13435.22 2.99 10319.63 0.00 0.0011-9-2024 21:30 68.9253.30 40.871.2261.59 32.510.739.20 254.915.657.29 236.812.144.48 249.69.434.68 259.443.5159.82 134.234.9128.16 165.942.0154.54 139.542.7156.80 137.3 4921.17 13537.75 3.24 10411.77 0.00 0.0011-9-2024 22:00 68.9253.30 40.871.2261.59 32.510.739.20 254.915.657.29 236.812.144.48 249.69.434.68 259.425.091.97 202.123.084.43 209.666.9245.76 48.342.7156.80 137.3 4378.40 13628.96 3.28 10509.48 0.00 0.0011-9-2024 22:30 51.9190.73 103.354.6200.53 93.510.739.20 254.915.657.29 236.812.144.48 249.69.434.68 259.425.091.97 202.123.084.43 209.666.9245.76 48.368.3251.03 43.0 4450.77 13721.69 3.26 10607.45 0.00 0.0011-9-2024 23:00 51.9190.73 103.354.6200.53 93.510.739.20 254.915.657.29 236.838.6141.72 152.39.434.68 259.425.091.97 202.123.084.43 209.666.9245.76 48.368.3251.03 43.0 4667.88 13818.93 3.25 10705.13 0.00 0.0011-9-2024 23:30 51.9190.73 103.354.6200.53 93.510.739.20 254.915.657.29 236.838.6141.72 152.335.7131.17 162.925.091.97 202.123.084.43 209.666.9245.76 48.368.3251.03 43.0 4631.69 13915.43 3.26 10802.86 0.00 0.0011-10-2024 0:00 23.485.94 208.123.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.635.7131.17 162.920.976.89 217.220.776.14 217.966.9245.76 48.368.3251.03 43.0 4595.51 14011.17 0.00 10898.74 0.00 0.0011-10-2024 0:30 23.485.94 208.123.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.662.1228.42 65.620.976.89 217.220.776.14 217.966.9245.76 48.368.3251.03 43.0 4667.88 14108.42 3.20 10930.20 0.00 0.0011-10-2024 1:00 23.485.94 208.123.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.662.1228.42 65.647.8175.65 118.420.776.14 217.966.9245.76 48.368.3251.03 43.0 4740.25 14207.17 3.25 11027.93 0.00 0.0011-10-2024 1:30 23.485.94 208.123.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.662.1228.42 65.647.8175.65 118.447.6174.89 119.240.6149.26 144.840.8150.02 144.0 4740.25 14305.93 3.25 11123.94 0.00 0.0011-10-2024 2:00 23.485.94 208.123.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.662.1228.42 65.674.2272.90 21.247.6174.89 119.219.370.86 223.220.575.39 218.7 4667.88 14403.17 3.30 11220.89 0.00 0.0011-10-2024 2:30 23.485.94 208.123.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.662.1228.42 65.674.2272.90 21.274.7274.40 19.719.370.86 223.220.575.39 218.7 4776.43 14502.68 3.25 11318.88 0.00 0.0011-10-2024 3:00 50.2184.69 109.423.887.45 206.610.739.20 254.915.657.29 236.864.6237.46 56.662.1228.42 65.674.2272.90 21.274.7274.40 19.719.370.86 223.220.575.39 218.7 4740.25 14601.44 3.24 11415.35 0.00 0.0011-10-2024 3:30 50.2184.69 109.452.1191.48 102.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.474.2272.90 21.274.7274.40 19.719.370.86 223.220.575.39 218.7 4993.54 14705.47 3.25 11513.40 0.00 0.0011-10-2024 4:00 78.8289.48 4.652.1191.48 102.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.474.2272.90 21.274.7274.40 19.719.370.86 223.220.575.39 218.7 5029.73 14810.25 3.24 11610.60 0.00 0.0011-10-2024 4:30 78.8289.48 4.679.6292.50 1.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.474.2272.90 21.274.7274.40 19.719.370.86 223.220.575.39 218.7 4848.80 14911.27 3.24 11707.70 0.00 0.0011-10-2024 5:00 78.8289.48 4.679.6292.50 1.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.450.0183.94 110.144.3162.83 131.247.0172.63 121.420.575.39 218.7 4884.99 15013.04 3.24 11804.80 0.00 0.0011-10-2024 5:30 78.8289.48 4.679.6292.50 1.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.247.0172.63 121.448.4177.91 116.2 4921.17 15115.57 3.24 11901.91 0.00 0.0011-10-2024 6:00 78.8289.48 4.679.6292.50 1.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.248.4177.91 116.2 4667.88 15212.81 3.24 11999.30 0.00 0.0011-10-2024 6:30 78.8289.48 4.679.6292.50 1.610.739.20 254.915.657.29 236.825.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 5174.47 15320.62 3.24 12096.75 0.00 0.00WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 36 Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining Level Volume Space Remaining (mm/dd/yyyy hh:mm:ss) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (%) (bbls) (bbls) (bbls/d) (bbls) (bbls/min) (bbls) (bbls/min) (bbls)Fluid Injection Cumulative into NDBi-014Fluid Injection Rate into NDBi-030TANK 611-NOV-2024 @ 00:00 hrs.TANK 2 TANK 3 TANK 4 TANK 5 NDBi-016NDBi-016 WELL CLEAN-UP_TANK FARM TO INJECTION WELL NDBi-014 & NDBi-030Well:Tank Strap Fluid RateTank Strap Fluid CumulativeStart Data:End Date:Date & TimeFluid Injection Rate into NDBi-014Fluid Injection Cumulative into NDBi-030TANK 106-NOV-2024 @ 12:17 hrs.TANK 7 TANK 8 TANK 9 TANK 1011-10-2024 7:00 78.8289.48 4.679.6292.50 1.639.2143.99 150.115.657.29 236.825.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 5029.73 15425.40 3.24 12194.08 0.00 0.0011-10-2024 7:30 78.8289.48 4.679.6292.50 1.639.2143.99 150.143.9161.33 132.725.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 4993.54 15529.43 3.22 12290.66 0.00 0.0011-10-2024 8:00 78.8289.48 4.679.6292.50 1.667.7248.77 45.343.9161.33 132.725.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 5029.73 15634.22 3.22 12388.53 0.00 0.0011-10-2024 8:30 10.739.20 254.911.943.72 250.367.7248.77 45.372.2265.36 28.725.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 4993.54 15738.25 3.24 12485.72 0.00 0.0011-10-2024 9:00 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.025.091.97 202.121.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 5065.91 15843.79 3.24 12582.93 0.00 0.0011-10-2024 9:30 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.053.9198.26 95.821.980.66 213.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 5102.10 15950.09 3.22 12680.15 0.00 0.0011-10-2024 10:00 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.053.9198.26 95.851.1187.71 106.423.485.94 208.120.976.89 217.273.4269.88 24.277.7285.71 8.4 5138.28 16057.13 3.26 12778.09 0.00 0.0011-10-2024 10:30 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.082.4303.05 0.051.1187.71 106.423.485.94 208.120.976.89 217.211.542.22 251.812.746.74 247.3 5029.73 16161.92 3.26 12876.02 0.00 0.0011-10-2024 11:00 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.082.4303.05 0.079.8293.25 0.823.485.94 208.120.976.89 217.211.542.22 251.812.746.74 247.3 5065.91 16267.46 3.24 12973.84 0.00 0.0011-10-2024 11:30 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.082.4303.05 0.079.8293.25 0.852.1191.48 102.620.976.89 217.211.542.22 251.812.746.74 247.3 5065.91 16373.00 3.24 13071.19 0.00 0.0011-10-2024 12:00 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.082.4303.05 0.079.8293.25 0.852.1191.48 102.650.2184.69 109.411.542.22 251.812.746.74 247.3 5174.47 16480.80 3.23 13168.64 0.00 0.0011-10-2024 12:30 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.082.4303.05 0.079.8293.25 0.879.6292.50 1.650.2184.69 109.411.542.22 251.812.746.74 247.3 4848.80 16581.82 3.24 13262.61 0.00 0.0011-10-2024 13:00 10.739.20 254.911.943.72 250.382.0301.54 0.086.5318.13 0.082.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 5029.73 16686.60 3.24 13357.82 0.00 0.0011-10-2024 13:30 39.0143.23 150.811.943.72 250.313.549.75 244.319.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 4993.54 16790.63 3.25 13456.69 0.00 0.0011-10-2024 14:00 39.0143.23 150.840.6149.26 144.813.549.75 244.319.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 5065.91 16896.17 3.24 13555.45 0.00 0.0011-10-2024 14:30 60.5222.39 71.740.6149.26 144.813.549.75 244.319.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3799.43 16975.33 3.23 13654.13 0.00 0.0011-10-2024 15:00 60.5222.39 71.761.9227.66 66.413.549.75 244.319.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3763.25 17053.73 3.00 13746.25 0.00 0.0011-10-2024 15:30 82.0301.54 0.061.9227.66 66.413.549.75 244.319.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3799.43 17132.89 3.01 13836.63 0.00 0.0011-10-2024 16:00 82.0301.54 0.061.9227.66 66.413.549.75 244.319.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3763.25 17211.29 3.00 13926.29 0.00 0.0011-10-2024 16:30 82.0301.54 0.061.9227.66 66.434.9128.16 165.919.370.86 223.282.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3763.25 17289.69 3.00 14014.84 0.00 0.0011-10-2024 17:00 82.0301.54 0.061.9227.66 66.434.9128.16 165.941.0150.77 143.382.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3835.62 17369.60 3.00 14106.60 0.00 0.0011-10-2024 17:30 82.0301.54 0.061.9227.66 66.456.4207.31 86.841.0150.77 143.382.4303.05 0.079.8293.25 0.879.6292.50 1.678.8289.48 4.611.542.22 251.812.746.74 247.3 3799.43 17448.75 3.02 14196.83 0.00 0.0011-10-2024 18:00 82.0301.54 0.061.9227.66 66.456.4207.31 86.862.3229.17 64.912.345.23 248.89.836.19 257.931.0113.83 180.228.3104.03 190.011.542.22 251.812.746.74 247.3 3763.25 17527.15 3.02 14286.05 0.00 0.0011-10-2024 18:30 82.0301.54 0.061.9227.66 66.477.7285.71 8.462.3229.17 64.912.345.23 248.89.836.19 257.931.0113.83 180.228.3104.03 190.011.542.22 251.812.746.74 247.3 3763.25 17605.55 3.00 14376.57 0.00 0.0011-10-2024 19:00 82.0301.54 0.061.9227.66 66.477.7285.71 8.483.9308.33 0.012.345.23 248.89.836.19 257.931.0113.83 180.228.3104.03 190.011.542.22 251.812.746.74 247.3 3799.43 17684.71 3.03 14466.32 0.00 0.0011-10-2024 19:30 82.0301.54 0.061.9227.66 66.477.7285.71 8.483.9308.33 0.029.9110.06 184.09.836.19 257.912.545.99 248.110.538.45 255.611.542.22 251.812.746.74 247.3 3111.92 17749.54 3.03 14556.68 0.00 0.0011-10-2024 20:00 82.0301.54 0.061.9227.66 66.477.7285.71 8.483.9308.33 0.029.9110.06 184.027.3100.26 193.812.545.99 248.110.538.45 255.611.542.22 251.812.746.74 247.3 3075.73 17813.62 3.01 14646.88 0.00 0.0011-10-2024 20:30 43.5159.82 134.244.7164.34 129.777.7285.71 8.483.9308.33 0.048.4177.91 116.227.3100.26 193.812.545.99 248.110.538.45 255.611.542.22 251.812.746.74 247.3 3256.66 17881.46 3.00 14737.04 0.00 0.0011-10-2024 21:00 43.5159.82 134.244.7164.34 129.777.7285.71 8.483.9308.33 0.048.4177.91 116.245.1165.85 128.212.545.99 248.110.538.45 255.611.542.22 251.812.746.74 247.3 3148.10 17947.05 3.00 14827.60 0.00 0.0011-10-2024 21:30 23.887.45 206.620.976.89 217.277.7285.71 8.483.9308.33 0.065.4240.48 53.645.1165.85 128.212.545.99 248.110.538.45 255.611.542.22 251.812.746.74 247.3 3003.36 18009.62 3.00 14919.79 0.00 0.0011-10-2024 22:00 13.349.00 245.114.252.02 242.077.7285.71 8.483.9308.33 0.065.4240.48 53.662.8230.68 63.412.545.99 248.110.538.45 255.611.542.22 251.812.746.74 247.3 3111.92 18074.45 3.00 15007.37 0.00 0.0011-10-2024 22:30 13.349.00 245.114.252.02 242.077.7285.71 8.483.9308.33 0.065.4240.48 53.662.8230.68 63.430.4111.57 182.510.538.45 255.611.542.22 251.812.746.74 247.3 3148.10 18140.04 3.00 15097.74 0.00 0.0011-10-2024 23:00 13.349.00 245.114.252.02 242.077.7285.71 8.483.9308.33 0.065.4240.48 53.662.8230.68 63.430.4111.57 182.528.7105.54 188.511.542.22 251.812.746.74 247.3 3220.47 18207.13 3.00 15187.88 0.00 0.0011-10-2024 23:30 13.349.00 245.114.252.02 242.049.4181.68 112.454.1199.02 95.065.4240.48 53.662.8230.68 63.448.2177.16 116.928.7105.54 188.511.542.22 251.812.746.74 247.3 3148.10 18272.72 3.00 15278.07 0.00 0.0011-11-2024 0:00 13.349.00 245.114.252.02 242.030.8113.08 181.035.7131.17 162.965.4240.48 53.662.8230.68 63.448.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.00 15368.26 0.00 0.0011-11-2024 0:30 13.349.00 245.114.252.02 242.025.894.99 199.127.9102.52 191.565.4240.48 53.662.8230.68 63.448.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.02 15408.28 0.00 0.0011-11-2024 1:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.765.4240.48 53.662.8230.68 63.448.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.00 15498.34 0.00 0.0011-11-2024 1:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.765.4240.48 53.662.8230.68 63.448.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.01 15588.67 0.00 0.0011-11-2024 2:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.765.4240.48 53.662.8230.68 63.448.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.01 15679.21 0.00 0.0011-11-2024 2:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.723.084.43 209.625.894.99 199.148.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.02 15769.20 0.00 0.0011-11-2024 3:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.848.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 3184.29 18339.05 3.01 15859.54 0.00 0.0011-11-2024 3:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.848.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 0.00 18339.05 3.02 15938.55 0.00 0.0011-11-2024 4:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.848.2177.16 116.946.8171.88 122.211.542.22 251.812.746.74 247.3 0.00 18339.05 3.02 16028.42 0.00 0.0011-11-2024 4:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 3.01 16117.37 0.00 0.0011-11-2024 5:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 3.02 16205.79 0.00 0.0011-11-2024 5:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 3.00 16298.97 0.00 0.0011-11-2024 6:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 3.02 16389.29 0.00 0.0011-11-2024 6:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 3.02 16389.29 0.00 0.0011-11-2024 7:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 1.51 16526.42 0.00 0.0011-11-2024 7:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 1.50 16571.09 0.00 0.0011-11-2024 8:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 8:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 9:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 9:30 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 10:00 13.349.00 245.114.252.02 242.015.255.79 238.318.066.34 227.714.854.28 239.813.951.26 242.823.084.43 209.621.378.40 215.711.542.22 251.812.746.74 247.3 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 10:30 0.83.02 291.00.83.02 291.00.83.02 291.01.24.52 289.51.03.77 290.31.24.52 289.50.83.02 291.00.83.02 291.00.83.02 291.00.83.02 291.0 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 11:00 0.83.02 291.00.83.02 291.00.83.02 291.01.24.52 289.51.03.77 290.31.24.52 289.50.83.02 291.00.83.02 291.00.83.02 291.00.83.02 291.0 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 11:30 0.83.02 291.00.83.02 291.00.83.02 291.01.24.52 289.51.03.77 290.31.24.52 289.50.83.02 291.00.83.02 291.00.83.02 291.00.83.02 291.0 0.00 18339.05 0.00 16583.80 0.00 0.0011-11-2024 12:00 0.83.02 291.00.83.02 291.00.83.02 291.01.24.52 289.51.03.77 290.31.24.52 289.50.83.02 291.00.83.02 291.00.83.02 291.00.83.02 291.0 0.00 18339.05 0.00 16583.80 0.00 0.00WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 37 Santos Pikka Development NDBi-016 SECTION 8 INJECTION WELL NDBi-014 DATA WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 38 Date & Time BHP BHT WHPi IAPi OAPi Injection Rate Injection Cumulative (mm-dd-yyyy hh:mm:ss)(psig) (°F) (psig) (psig) (psig) (bbls/min) (bbls) 11-07-2024 11:30:00 11:42 2061.36 100.30 0.00 0.00 0.00 0.00 0.00 11-07-2024 12:00:00 2338.62 98.09 522.26 0.00 0.00 2.34 31.53 11-07-2024 12:30:00 12:48 2448.69 93.15 618.34 2.99 0.00 3.16 106.05 11-07-2024 13:00:00 2385.11 90.15 460.09 1.88 0.00 2.29 191.96 11-07-2024 13:30:00 2403.42 87.91 472.10 0.86 0.00 2.29 260.73 11-07-2024 14:00:00 2448.02 84.94 527.77 0.00 0.00 2.75 333.89 11-07-2024 14:30:00 2455.12 81.64 725.00 0.00 0.00 2.76 416.74 11-07-2024 15:00:00 2458.64 79.78 824.56 0.00 0.00 2.74 499.72 11-07-2024 15:30:00 2490.83 81.10 652.14 0.00 0.00 2.75 582.15 11-07-2024 16:00:00 2561.55 80.02 639.41 0.00 0.00 2.75 664.82 11-07-2024 16:30:00 2570.97 78.17 639.71 0.00 0.00 2.77 750.77 11-07-2024 17:00:00 2530.70 76.48 628.64 0.00 0.00 2.78 830.43 11-07-2024 17:30:00 17:51 2587.83 73.97 926.37 0.00 0.00 3.51 933.31 11-07-2024 18:00:00 2600.34 75.23 891.75 0.00 0.00 3.48 1037.30 11-07-2024 18:30:00 2690.61 76.51 809.93 0.00 0.00 3.49 1140.99 11-07-2024 19:00:00 2709.95 73.59 809.00 0.02 0.00 3.47 1240.60 11-07-2024 19:30:00 19:50 2655.69 72.51 938.52 0.00 0.00 3.53 1349.56 11-07-2024 20:00:00 2640.30 72.31 942.53 0.00 0.00 3.48 1451.61 11-07-2024 20:30:00 2703.68 75.18 826.53 1.78 0.00 3.48 1451.61 11-07-2024 21:00:00 2729.20 73.00 827.95 3.39 0.00 3.48 1660.09 11-07-2024 21:30:00 21:55 2664.30 72.36 1004.78 2.23 0.00 3.51 1762.85 11-07-2024 22:00:00 2651.01 74.13 970.88 3.05 0.00 3.47 1864.71 11-07-2024 22:30:00 2727.47 75.50 876.59 5.67 0.00 3.47 1970.59 11-07-2024 23:00:00 2718.26 73.35 1003.64 4.69 0.00 3.47 2070.32 11-07-2024 23:30:00 23:38 2652.76 73.63 1036.58 3.85 0.00 3.07 2169.08 11-08-2024 00:00:00 00:04 2691.31 76.04 924.49 5.61 0.00 3.01 2260.28 11-08-2024 00:30:00 00:36 2322.77 78.19 494.23 2.14 0.00 0.00 2260.28 11-08-2024 01:00:00 2661.98 76.28 835.79 4.85 0.00 2.98 2350.99 11-08-2024 01:30:00 2693.84 75.69 1008.33 4.95 0.00 3.02 2446.17 11-08-2024 02:00:00 02:07 2677.40 75.12 1061.64 4.87 0.00 3.01 2539.02 11-08-2024 02:30:00 2710.50 77.08 930.78 4.75 0.00 2.99 2623.27 11-08-2024 03:00:00 2720.43 76.09 878.33 5.65 0.00 2.98 2710.14 11-08-2024 03:30:00 2724.77 75.06 939.66 5.61 0.00 3.04 2800.52 11-08-2024 04:00:00 2712.58 74.53 1050.70 4.65 0.00 3.02 2893.29 11-08-2024 04:30:00 04:55 2720.06 74.98 1104.81 5.57 0.00 3.01 3004.28 11-08-2024 05:00:00 2750.18 76.54 1098.58 7.24 0.00 3.01 3004.28 11-08-2024 05:30:00 2751.09 77.08 922.58 8.12 0.00 2.98 3161.85 11-08-2024 06:00:00 2748.92 75.33 1015.21 6.44 0.00 3.02 3250.04 11-08-2024 06:30:00 2730.72 74.42 1098.27 5.77 0.00 3.02 3342.35 11-08-2024 07:00:00 07:10 2723.70 76.00 1108.02 7.80 0.00 3.00 3435.80 11-08-2024 07:30:00 2758.85 76.72 971.52 9.70 0.00 2.98 3524.93 11-08-2024 08:00:00 2762.25 76.24 1077.38 9.86 0.00 3.01 3615.60 11-08-2024 08:30:00 08:32 08:45 2638.51 75.10 961.12 9.18 0.00 0.00 3615.60 11-08-2024 09:00:00 2716.95 77.05 924.89 6.64 0.00 3.02 3760.30 11-08-2024 09:30:00 2756.63 76.19 860.89 8.46 0.00 3.03 3854.56 11-08-2024 10:00:00 2755.05 74.64 1009.34 6.68 0.00 3.03 3945.36 11-08-2024 10:30:00 2713.58 73.74 1081.33 5.75 0.00 3.00 4035.78 11-08-2024 11:00:00 2712.48 75.42 1095.47 6.60 0.00 2.99 4125.14 11-08-2024 11:30:00 2760.81 76.20 1143.63 8.40 0.00 2.99 4215.15 11-08-2024 12:00:00 12:03 2764.67 76.62 1147.92 9.26 0.00 2.99 4303.12 11-08-2024 12:30:00 2770.69 76.97 954.98 8.34 0.00 2.97 4391.02 11-08-2024 13:00:00 2767.55 75.79 1027.90 7.42 0.00 3.00 4482.20 11-08-2024 13:30:00 2764.28 74.44 1130.01 5.57 0.00 2.99 4574.48 11-08-2024 14:00:00 2740.20 75.84 1122.86 6.52 0.00 2.99 4662.77 11-08-2024 14:30:00 14:45 2777.76 76.49 1161.27 7.34 0.00 2.99 4753.18 11-08-2024 15:00:00 2785.63 76.87 1015.49 7.44 0.00 3.02 4842.86 11-08-2024 15:30:00 2783.48 77.06 997.79 6.60 0.00 3.05 4934.89 NDBi-014 NDBi-014 INJECTION DATA_NDBi-016 WELL CLEAN-UP COMMENTS Pikka Development ND-B November 7th, 2024 @ 11:42 November 11th, 2024 @ 07:39 Location: Injection Start Date: Injection End Date: WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 39 Date & Time BHP BHT WHPi IAPi OAPi Injection Rate Injection Cumulative (mm-dd-yyyy hh:mm:ss)(psig) (°F) (psig) (psig) (psig) (bbls/min) (bbls) NDBi-014 NDBi-014 INJECTION DATA_NDBi-016 WELL CLEAN-UP COMMENTS Pikka Development ND-B November 7th, 2024 @ 11:42 November 11th, 2024 @ 07:39 Location: Injection Start Date: Injection End Date: 11-08-2024 16:00:00 2779.55 74.77 1108.86 5.65 0.00 3.00 5023.70 11-08-2024 16:30:00 2745.96 75.31 1123.10 5.73 0.00 3.02 5114.09 11-08-2024 17:00:00 2785.74 76.15 1163.25 6.68 0.00 3.00 5203.57 11-08-2024 17:30:00 17:50 2791.28 76.49 1170.27 7.56 0.00 3.00 5294.04 11-08-2024 18:00:00 2799.97 76.76 1067.04 7.48 0.00 3.00 5294.04 11-08-2024 18:30:00 2799.96 76.87 1094.79 6.76 0.00 3.06 5474.03 11-08-2024 19:00:00 2800.61 74.65 1150.76 5.79 0.00 3.06 5570.83 11-08-2024 19:30:00 2804.95 75.95 1164.86 5.71 0.00 3.07 5658.29 11-08-2024 20:00:00 2822.50 76.19 1183.28 6.36 0.00 3.05 5750.10 11-08-2024 20:30:00 20:35 2826.93 76.32 1187.79 6.42 0.00 3.07 5841.99 11-08-2024 21:00:00 2828.13 76.42 1094.61 6.54 0.00 3.14 5933.38 11-08-2024 21:30:00 2827.53 75.38 1143.43 4.77 0.00 3.08 6025.03 11-08-2024 22:00:00 2813.96 75.35 1172.64 5.55 0.00 3.08 6116.14 11-08-2024 22:30:00 2832.05 76.05 1192.67 5.21 0.00 3.08 6213.25 11-08-2024 23:00:00 23:18 2837.05 76.26 1199.66 5.05 0.00 3.07 6308.17 11-08-2024 23:30:00 2838.61 76.43 1128.45 5.01 0.00 3.02 6393.08 11-09-2024 00:00:00 2757.70 76.49 1024.23 3.93 0.00 3.06 6486.08 11-09-2024 00:30:00 2737.00 77.10 1061.66 1.38 0.00 3.06 6486.08 11-09-2024 01:00:00 2784.62 76.43 1147.42 2.53 0.00 3.04 6604.27 11-09-2024 01:30:00 2810.80 76.72 1179.81 3.65 0.00 3.03 6695.14 11-09-2024 02:00:00 2817.76 76.87 1189.12 5.01 0.00 3.03 6786.03 11-09-2024 02:30:00 2818.42 76.92 1131.82 5.37 0.00 3.05 6877.19 11-09-2024 03:00:00 2817.13 75.52 1155.25 4.81 0.00 3.04 6968.36 11-09-2024 03:30:00 2821.08 76.09 1189.00 3.89 0.00 3.03 7069.20 11-09-2024 04:00:00 04:13 2841.00 76.47 1216.52 5.61 0.00 3.03 7148.50 11-09-2024 04:30:00 2839.79 76.68 1114.25 5.61 0.00 3.04 7259.26 11-09-2024 05:00:00 2830.54 76.81 1158.72 5.63 0.00 3.04 7330.83 11-09-2024 05:30:00 2830.74 75.61 1197.82 4.65 0.00 3.03 7421.90 11-09-2024 06:00:00 06:25 2846.15 76.32 1218.13 4.55 0.00 3.02 7513.09 11-09-2024 06:30:00 2852.45 76.53 1199.34 5.37 0.00 3.02 7605.89 11-09-2024 07:00:00 2846.25 76.59 1174.46 4.49 0.00 3.06 7698.18 11-09-2024 07:30:00 2842.12 74.73 1194.79 4.45 0.00 3.07 7788.50 11-09-2024 08:00:00 08:22 2855.59 76.02 1222.30 4.33 0.00 3.07 7881.19 11-09-2024 08:30:00 2871.51 76.19 1248.04 5.15 0.00 3.07 7881.19 11-09-2024 09:00:00 09:02 09:20 2871.12 76.25 1248.06 5.17 0.00 3.19 8071.17 11-09-2024 09:30:00 09:58 2865.72 76.31 1188.32 5.05 0.00 3.19 8167.19 11-09-2024 10:00:00 2862.72 74.96 1214.04 4.97 0.00 3.19 8263.43 11-09-2024 10:30:00 2864.77 75.73 1238.02 5.05 0.00 3.18 8359.23 11-09-2024 11:00:00 2881.29 76.05 1257.71 5.09 0.00 3.17 8453.46 11-09-2024 11:30:00 2877.93 76.16 1256.02 6.03 0.00 3.19 8549.71 11-09-2024 12:00:00 12:15 2875.35 76.22 1241.15 6.20 0.00 3.21 8646.11 11-09-2024 12:30:00 2874.87 76.20 1236.96 7.30 0.00 3.21 8739.66 11-09-2024 13:00:00 2886.08 76.05 1250.71 7.62 0.00 3.21 8835.47 11-09-2024 13:30:00 2889.52 75.98 1261.42 8.00 0.00 3.21 8932.59 11-09-2024 14:00:00 14:19 2892.12 76.03 1265.42 8.10 0.00 3.20 9031.23 11-09-2024 14:30:00 2890.05 76.14 1246.94 8.28 0.00 3.20 9127.49 11-09-2024 15:00:00 2886.93 76.21 1251.57 8.44 0.00 3.21 9225.03 11-09-2024 15:30:00 2890.84 76.02 1257.91 8.52 0.00 3.21 9320.99 11-09-2024 16:00:00 2897.89 76.09 1268.73 8.70 0.00 3.20 9416.30 11-09-2024 16:30:00 2878.77 76.22 1245.66 8.68 0.00 3.00 9507.96 11-09-2024 17:00:00 17:06 2876.79 76.36 1245.72 8.78 0.00 3.02 9595.65 11-09-2024 17:30:00 2873.84 76.43 1218.19 8.80 0.00 3.01 9688.51 11-09-2024 18:00:00 2871.27 76.50 1222.66 8.84 0.00 3.02 9777.54 11-09-2024 18:30:00 2877.12 76.13 1241.39 8.88 0.00 3.02 9868.14 11-09-2024 19:00:00 2881.00 76.29 1252.05 8.92 0.00 3.00 9959.89 11-09-2024 19:30:00 19:52 2880.07 76.43 1252.01 8.84 0.00 3.00 10049.28 11-09-2024 20:00:00 2877.56 76.55 1186.87 8.62 0.00 2.97 10138.93 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 40 Date & Time BHP BHT WHPi IAPi OAPi Injection Rate Injection Cumulative (mm-dd-yyyy hh:mm:ss)(psig) (°F) (psig) (psig) (psig) (bbls/min) (bbls) NDBi-014 NDBi-014 INJECTION DATA_NDBi-016 WELL CLEAN-UP COMMENTS Pikka Development ND-B November 7th, 2024 @ 11:42 November 11th, 2024 @ 07:39 Location: Injection Start Date: Injection End Date: 11-09-2024 20:30:00 2873.81 76.60 1215.72 8.24 0.00 3.00 10230.27 11-09-2024 21:00:00 2868.83 75.31 1242.85 7.02 0.00 2.99 10319.63 11-09-2024 21:30:00 21:44 2889.86 76.23 1277.01 7.44 0.00 3.24 10411.77 11-09-2024 22:00:00 2894.62 76.33 1214.28 7.12 0.00 3.28 10509.48 11-09-2024 22:30:00 2892.16 76.38 1246.20 6.07 0.00 3.26 10607.45 11-09-2024 23:00:00 2894.70 75.64 1276.09 6.68 0.00 3.25 10705.13 11-09-2024 23:30:00 23:40 2905.46 76.02 1287.50 6.48 0.00 3.26 10802.86 11-10-2024 00:00:00 00:20 2796.63 76.13 1066.64 4.53 0.00 0.00 10898.74 11-10-2024 00:30:00 2798.77 77.33 1151.06 2.61 0.00 3.20 10930.20 11-10-2024 01:00:00 2845.04 75.56 1220.43 3.45 0.00 3.25 11027.93 11-10-2024 01:30:00 01:53 2873.90 76.26 1254.76 4.17 0.00 3.25 11123.94 11-10-2024 02:00:00 2881.60 76.37 1235.77 3.91 0.00 3.30 11220.89 11-10-2024 02:30:00 2881.46 76.40 1248.22 2.02 0.00 3.25 11318.88 11-10-2024 03:00:00 03:26 2887.27 75.74 1262.34 0.18 0.00 3.24 11415.35 11-10-2024 03:30:00 2894.83 76.14 1267.45 0.04 0.00 3.25 11513.40 11-10-2024 04:00:00 2894.05 76.17 1268.39 1.82 0.00 3.24 11610.60 11-10-2024 04:30:00 2894.18 76.08 1267.47 2.57 0.00 3.24 11707.70 11-10-2024 05:00:00 05:28 2896.49 76.09 1270.96 2.55 0.00 3.24 11804.80 11-10-2024 05:30:00 2899.01 76.08 1272.74 3.41 0.00 3.24 11901.91 11-10-2024 06:00:00 2898.90 76.07 1272.64 2.47 0.00 3.24 11999.30 11-10-2024 06:30:00 2899.61 76.03 1274.19 1.88 0.00 3.24 12096.75 11-10-2024 07:00:00 2900.58 76.04 1275.91 3.07 0.00 3.24 12194.08 11-10-2024 07:30:00 2901.77 76.03 1277.07 3.23 0.00 3.22 12290.66 11-10-2024 08:00:00 2901.94 76.02 1277.27 3.43 0.00 3.22 12388.53 11-10-2024 08:30:00 2902.63 76.01 1278.32 3.57 0.00 3.24 12485.72 11-10-2024 09:00:00 2903.55 76.01 1280.20 3.65 0.00 3.24 12582.93 11-10-2024 09:30:00 2905.64 76.00 1283.77 4.63 0.00 3.22 12680.15 11-10-2024 10:00:00 2906.22 75.98 1283.95 4.69 0.00 3.26 12778.09 11-10-2024 10:30:00 10:36 2905.98 75.98 1284.01 4.75 0.00 3.26 12876.02 11-10-2024 11:00:00 2904.60 75.99 1276.95 3.91 0.00 3.24 12973.84 11-10-2024 11:30:00 2905.03 75.87 1280.60 4.93 0.00 3.24 13071.19 11-10-2024 12:00:00 2910.16 75.89 1287.76 3.99 0.00 3.23 13168.64 11-10-2024 12:30:00 2912.05 75.92 1289.54 4.97 0.00 3.24 13262.61 11-10-2024 13:00:00 13:15 2911.24 75.93 1287.68 4.87 0.00 3.24 13357.82 11-10-2024 13:30:00 2910.75 75.93 1283.21 3.07 0.00 3.25 13456.69 11-10-2024 14:00:00 2910.60 75.93 1286.84 2.19 0.00 3.24 13555.45 11-10-2024 14:30:00 2913.19 75.88 1291.39 2.31 0.00 3.23 13654.13 11-10-2024 15:00:00 2892.49 76.03 1261.68 2.27 0.00 3.00 13746.25 11-10-2024 15:30:00 2889.57 76.11 1257.55 2.33 0.00 3.01 13836.63 11-10-2024 16:00:00 16:08 2887.53 76.15 1255.86 2.39 0.00 3.00 13926.29 11-10-2024 16:30:00 2885.58 76.16 1251.47 2.35 0.00 3.00 14014.84 11-10-2024 17:00:00 2886.37 76.19 1254.18 3.35 0.00 3.00 14106.60 11-10-2024 17:30:00 2892.78 76.12 1261.44 3.43 0.00 3.02 14196.83 11-10-2024 18:00:00 2894.92 76.17 1264.18 4.41 0.00 3.02 14286.05 11-10-2024 18:30:00 18:57 2893.48 76.18 1261.74 4.61 0.00 3.00 14376.57 11-10-2024 19:00:00 2892.05 76.20 1259.25 4.75 0.00 3.03 14466.32 11-10-2024 19:30:00 2891.52 76.21 1261.25 3.07 0.00 3.03 14556.68 11-10-2024 20:00:00 2892.90 76.14 1263.16 2.35 0.00 3.01 14646.88 11-10-2024 20:30:00 2893.94 76.20 1265.12 3.43 0.00 3.00 14737.04 11-10-2024 21:00:00 2894.34 76.20 1265.30 4.39 0.00 3.00 14827.60 11-10-2024 21:30:00 21:52 2893.24 76.20 1267.73 4.43 0.00 3.00 14919.79 11-10-2024 22:00:00 2893.33 76.21 1262.12 4.59 0.00 3.00 15007.37 11-10-2024 22:30:00 2892.49 76.22 1262.08 2.87 0.00 3.00 15097.74 11-10-2024 23:00:00 2891.38 76.17 1261.98 2.02 0.00 3.00 15187.88 11-10-2024 23:30:00 2895.64 76.16 1266.37 2.87 0.00 3.00 15278.07 11-11-2024 00:00:00 2807.66 76.15 1096.61 2.12 0.00 3.00 15368.26 11-11-2024 00:30:00 00:51 2826.50 77.27 1179.57 2.21 0.00 3.02 15408.28 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 41 Date & Time BHP BHT WHPi IAPi OAPi Injection Rate Injection Cumulative (mm-dd-yyyy hh:mm:ss)(psig) (°F) (psig) (psig) (psig) (bbls/min) (bbls) NDBi-014 NDBi-014 INJECTION DATA_NDBi-016 WELL CLEAN-UP COMMENTS Pikka Development ND-B November 7th, 2024 @ 11:42 November 11th, 2024 @ 07:39 Location: Injection Start Date: Injection End Date: 11-11-2024 01:00:00 2857.15 76.78 1227.49 2.33 0.00 3.00 15498.34 11-11-2024 01:30:00 2866.59 76.62 1237.44 1.36 0.00 3.01 15588.67 11-11-2024 02:00:00 2870.21 76.50 1242.61 1.12 0.00 3.01 15679.21 11-11-2024 02:30:00 2873.54 76.43 1246.68 0.08 0.00 3.02 15769.20 11-11-2024 03:00:00 03:08 2873.38 76.37 1246.38 0.00 0.00 3.01 15859.54 11-11-2024 03:30:00 2856.38 76.76 1218.65 0.00 0.00 3.02 15938.55 11-11-2024 04:00:00 2863.76 76.56 1233.61 0.00 0.00 3.02 16028.42 11-11-2024 04:30:00 2865.76 76.44 1240.58 0.00 0.00 3.01 16117.37 11-11-2024 05:00:00 2878.25 76.32 1244.11 0.00 0.00 3.02 16205.79 11-11-2024 05:30:00 2877.72 76.22 1248.44 0.00 0.00 3.00 16298.97 11-11-2024 06:00:00 2879.13 76.12 1251.87 0.00 0.00 3.02 16389.29 11-11-2024 06:30:00 2838.76 76.09 1165.74 0.00 0.00 3.02 16479.64 11-11-2024 07:00:00 2720.33 77.02 1046.03 0.00 0.00 1.51 16526.42 11-11-2024 07:30:00 07:39 2688.42 77.53 1020.58 0.00 0.00 1.50 16571.09 11-11-2024 08:00:00 13:08 13:22 2508.32 78.53 826.31 0.00 0.00 0.00 16583.80 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 42 0.0015.0030.0045.0060.0075.0090.00105.000500100015002000250030003500Pressure (psig)Santos - Pikka Development - NDBi-016Injection Well NDBi-014Well Head - Bottom Hole Conditions PlotBHPWHPiBHTIAPiOAPiPressure (psig) / Temperature (°F)WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 43 0.002250.004500.006750.009000.0011250.0013500.0015750.0018000.000.00.51.01.52.02.53.03.54.0Rate (bbls/min)Santos - Pikka Development - NDBi-016Injection Well NDBi-014Injection Rate - Cumulative Plot Injection Rate Injection CumulativeCumulative (bbls)WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 44 Santos Pikka Development NDBi-016 SECTION 9 TEST SUMMARY SHUT-IN / BUILD-UP PERIOD WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 45 Build-Up Summary Notes: Unless otherwise stated, the above readings were taken just before shut-in. Flow rates and GORs are average values during the last hour (or most stable period) on each choke size. Throughout the report reference is made to Separator and Standard/Stock Tank (Stb) oil rates. The separator rate refers to the oil metered at separator conditions. The standard/stock tank rate is the metered rate corrected for shrinkage at standard conditions of 14.73 psi, 60°F. Santos Pikka Development NDBi-016 Shut-in / Build-up Period Duration of Monitored Build-up = 126 hrs. Shut-in / Build-up Period Start of Build-up Period: November 11th, 2024 00:00:00 End of Build-up Period: November 16th, 2024 06:00:00 During the Main Shut-In/Build-up period, data was collected in one second and 30-minute intervals through 3rd Party Downhole Gauge Schlumberger (SLB). Provided below are the initial and final data point values that were recorded during the Shut-in / Build- up Period. These values include Bottom-Hole Pressure and Bottom-Hole Temperature. Initial Data Values (Shut-in / Build-up Period): November 11th, 2024 @ 00:00:00 BH Pressure BH Temperature (psig) (°F) 1534.850 101.203 End Data Values (Shut-in / Build-up Period): November 16th, 2024 @ 06:00:00 BH Pressure BH Temperature (psig) (°F) 1786.47 100.078 Note: NDBi-016 is continuously logged & monitored, with data reports distributed daily. For the End of Well Report, the above dates equivalent to 126 hrs (5.25 days) is captured in the build-up summary and plotted. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 46 Santos Pikka Development NDBi-016 SECTION 10 TEST DATA REPORT SHUT-IN / BUILD-UP WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 47 Well:NDBi-016 Start Data:11-Nov-2024 @ 00:00 End Date:16-Nov-2024 @ 06:00 (mm-dd-yyyy hh:mm:ss)(psig) (°F) 11-11-2024 0:00:00 1534.85 101.203 11-11-2024 0:30:00 1615.11 101.106 11-11-2024 1:00:00 1624.68 100.999 11-11-2024 1:30:00 1631.37 100.944 11-11-2024 2:00:00 1636.75 100.893 11-11-2024 2:30:00 1641.95 100.868 11-11-2024 3:00:00 1646.03 100.834 11-11-2024 3:30:00 1649.66 100.828 11-11-2024 4:00:00 1652.83 100.819 11-11-2024 4:30:00 1655.94 100.812 11-11-2024 5:00:00 1658.75 100.803 11-11-2024 5:30:00 1661.35 100.796 11-11-2024 6:00:00 1663.73 100.783 11-11-2024 6:30:00 1666.02 100.771 11-11-2024 7:00:00 1668.20 100.758 11-11-2024 7:30:00 1670.34 100.746 11-11-2024 8:00:00 1672.33 100.731 11-11-2024 8:30:00 1674.30 100.713 11-11-2024 9:00:00 1676.12 100.702 11-11-2024 9:30:00 1677.92 100.692 11-11-2024 10:00:00 1679.67 100.681 11-11-2024 10:30:00 1681.32 100.666 11-11-2024 11:00:00 1682.95 100.659 11-11-2024 11:30:00 1684.57 100.647 11-11-2024 12:00:00 1686.11 100.638 11-11-2024 12:30:00 1687.59 100.627 11-11-2024 13:00:00 1689.11 100.618 11-11-2024 13:30:00 1690.52 100.609 11-11-2024 14:00:00 1691.91 100.598 11-11-2024 14:30:00 1693.27 100.589 11-11-2024 15:00:00 1694.58 100.584 11-11-2024 15:30:00 1695.89 100.575 11-11-2024 16:00:00 1697.16 100.566 11-11-2024 16:30:00 1698.43 100.558 11-11-2024 17:00:00 1699.66 100.548 11-11-2024 17:30:00 1700.87 100.542 11-11-2024 18:00:00 1702.05 100.537 11-11-2024 18:30:00 1703.20 100.530 11-11-2024 19:00:00 1704.32 100.526 11-11-2024 19:30:00 1705.46 100.519 11-11-2024 20:00:00 1706.53 100.513 11-11-2024 20:30:00 1707.60 100.506 11-11-2024 21:00:00 1708.65 100.501 11-11-2024 21:30:00 1709.69 100.495 11-11-2024 22:00:00 1710.70 100.490 11-11-2024 22:30:00 1711.72 100.483 11-11-2024 23:00:00 1712.69 100.477 11-11-2024 23:30:00 1713.68 100.474 11-12-2024 0:00:00 1714.63 100.467 11-12-2024 0:30:00 1715.56 100.463 11-12-2024 1:00:00 1716.50 100.459 11-12-2024 1:30:00 1717.40 100.452 11-12-2024 2:00:00 1718.29 100.447 11-12-2024 2:30:00 1719.18 100.443 11-12-2024 3:00:00 1720.04 100.440 11-12-2024 3:30:00 1720.89 100.436 11-12-2024 4:00:00 1721.74 100.429 11-12-2024 4:30:00 1722.57 100.425 11-12-2024 5:00:00 1723.38 100.422 11-12-2024 5:30:00 1724.17 100.418 11-12-2024 6:00:00 1724.95 100.416 11-12-2024 6:30:00 1725.73 100.413 11-12-2024 7:00:00 1726.49 100.405 11-12-2024 7:30:00 1727.24 100.400 11-12-2024 8:00:00 1727.96 100.395 11-12-2024 8:30:00 1728.71 100.395 11-12-2024 9:00:00 1729.43 100.391 11-12-2024 9:30:00 1730.14 100.387 11-12-2024 10:00:00 1730.85 100.382 11-12-2024 10:30:00 1731.53 100.384 11-12-2024 11:00:00 1732.22 100.377 11-12-2024 11:30:00 1732.89 100.373 11-12-2024 12:00:00 1733.55 100.368 11-12-2024 12:30:00 1734.20 100.362 11-12-2024 13:00:00 1734.84 100.360 11-12-2024 13:30:00 1735.48 100.353 11-12-2024 14:00:00 1736.10 100.351 11-12-2024 14:30:00 1736.71 100.350 11-12-2024 15:00:00 1737.32 100.346 11-12-2024 15:30:00 1737.92 100.346 11-12-2024 16:00:00 1738.51 100.341 NDBi-016 DOWNHOLE_SHUT-IN / BUILD-UP PERIOD Date & Time BHP BHT COMMENTS NDBi-016 Shut-in WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 48 Well:NDBi-016 Start Data:11-Nov-2024 @ 00:00 End Date:16-Nov-2024 @ 06:00 (mm-dd-yyyy hh:mm:ss)(psig) (°F) NDBi-016 DOWNHOLE_SHUT-IN / BUILD-UP PERIOD Date & Time BHP BHT COMMENTS 11-12-2024 16:30:00 1739.09 100.339 11-12-2024 17:00:00 1739.67 100.339 11-12-2024 17:30:00 1740.23 100.341 11-12-2024 18:00:00 1740.79 100.337 11-12-2024 18:30:00 1741.34 100.337 11-12-2024 19:00:00 1741.89 100.335 11-12-2024 19:30:00 1742.43 100.339 11-12-2024 20:00:00 1742.96 100.335 11-12-2024 20:30:00 1743.48 100.328 11-12-2024 21:00:00 1744.00 100.328 11-12-2024 21:30:00 1744.51 100.323 11-12-2024 22:00:00 1745.02 100.324 11-12-2024 22:30:00 1745.51 100.321 11-12-2024 23:00:00 1746.01 100.315 11-12-2024 23:30:00 1746.49 100.319 11-13-2024 0:00:00 1746.97 100.319 11-13-2024 0:30:00 1747.45 100.319 11-13-2024 1:00:00 1747.92 100.315 11-13-2024 1:30:00 1748.38 100.314 11-13-2024 2:00:00 1748.84 100.315 11-13-2024 2:30:00 1749.30 100.314 11-13-2024 3:00:00 1749.74 100.317 11-13-2024 3:30:00 1750.19 100.314 11-13-2024 4:00:00 1750.63 100.312 11-13-2024 4:30:00 1751.06 100.306 11-13-2024 5:00:00 1751.49 100.299 11-13-2024 5:30:00 1751.91 100.297 11-13-2024 6:00:00 1752.33 100.297 11-13-2024 6:30:00 1752.74 100.294 11-13-2024 7:00:00 1753.15 100.294 11-13-2024 7:30:00 1753.55 100.296 11-13-2024 8:00:00 1753.96 100.290 11-13-2024 8:30:00 1754.35 100.292 11-13-2024 9:00:00 1754.74 100.287 11-13-2024 9:30:00 1755.13 100.287 11-13-2024 10:00:00 1755.51 100.285 11-13-2024 10:30:00 1755.89 100.274 11-13-2024 11:00:00 1756.27 100.281 11-13-2024 11:30:00 1756.64 100.281 11-13-2024 12:00:00 1757.01 100.272 11-13-2024 12:30:00 1757.37 100.274 11-13-2024 13:00:00 1757.73 100.278 11-13-2024 13:30:00 1758.08 100.272 11-13-2024 14:00:00 1758.43 100.269 11-13-2024 14:30:00 1758.78 100.272 11-13-2024 15:00:00 1759.12 100.276 11-13-2024 15:30:00 1759.47 100.270 11-13-2024 16:00:00 1759.81 100.270 11-13-2024 16:30:00 1760.14 100.270 11-13-2024 17:00:00 1760.47 100.278 11-13-2024 17:30:00 1760.80 100.278 11-13-2024 18:00:00 1761.13 100.274 11-13-2024 18:30:00 1761.45 100.276 11-13-2024 19:00:00 1761.77 100.270 11-13-2024 19:30:00 1762.08 100.267 11-13-2024 20:00:00 1762.40 100.263 11-13-2024 20:30:00 1762.71 100.269 11-13-2024 21:00:00 1763.02 100.272 11-13-2024 21:30:00 1763.32 100.261 11-13-2024 22:00:00 1763.62 100.252 11-13-2024 22:30:00 1763.92 100.252 11-13-2024 23:00:00 1764.21 100.254 11-13-2024 23:30:00 1764.51 100.252 11-14-2024 0:00:00 1764.80 100.251 11-14-2024 0:30:00 1765.09 100.254 11-14-2024 1:00:00 1765.37 100.247 11-14-2024 1:30:00 1765.66 100.251 11-14-2024 2:00:00 1765.94 100.247 11-14-2024 2:30:00 1766.22 100.249 11-14-2024 3:00:00 1766.50 100.249 11-14-2024 3:30:00 1766.77 100.251 11-14-2024 4:00:00 1767.04 100.245 11-14-2024 4:30:00 1767.31 100.240 11-14-2024 5:00:00 1767.58 100.236 11-14-2024 5:30:00 1767.84 100.240 11-14-2024 6:00:00 1768.11 100.234 11-14-2024 6:30:00 1768.37 100.231 11-14-2024 7:00:00 1768.63 100.231 11-14-2024 7:30:00 1768.88 100.227 11-14-2024 8:00:00 1769.13 100.231 11-14-2024 8:30:00 1769.39 100.231 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 49 Well:NDBi-016 Start Data:11-Nov-2024 @ 00:00 End Date:16-Nov-2024 @ 06:00 (mm-dd-yyyy hh:mm:ss)(psig) (°F) NDBi-016 DOWNHOLE_SHUT-IN / BUILD-UP PERIOD Date & Time BHP BHT COMMENTS 11-14-2024 9:00:00 1769.64 100.231 11-14-2024 9:30:00 1769.89 100.234 11-14-2024 10:00:00 1770.13 100.233 11-14-2024 10:30:00 1770.37 100.227 11-14-2024 11:00:00 1770.62 100.225 11-14-2024 11:30:00 1770.85 100.216 11-14-2024 12:00:00 1771.09 100.213 11-14-2024 12:30:00 1771.33 100.215 11-14-2024 13:00:00 1771.57 100.213 11-14-2024 13:30:00 1771.80 100.211 11-14-2024 14:00:00 1772.03 100.211 11-14-2024 14:30:00 1772.25 100.209 11-14-2024 15:00:00 1772.48 100.211 11-14-2024 15:30:00 1772.71 100.207 11-14-2024 16:00:00 1772.93 100.207 11-14-2024 16:30:00 1773.15 100.202 11-14-2024 17:00:00 1773.38 100.200 11-14-2024 17:30:00 1773.59 100.204 11-14-2024 18:00:00 1773.81 100.204 11-14-2024 18:30:00 1774.02 100.198 11-14-2024 19:00:00 1774.24 100.200 11-14-2024 19:30:00 1774.45 100.191 11-14-2024 20:00:00 1774.66 100.191 11-14-2024 20:30:00 1774.87 100.186 11-14-2024 21:00:00 1775.08 100.189 11-14-2024 21:30:00 1775.29 100.186 11-14-2024 22:00:00 1775.50 100.182 11-14-2024 22:30:00 1775.70 100.186 11-14-2024 23:00:00 1775.91 100.189 11-14-2024 23:30:00 1776.11 100.184 11-15-2024 0:00:00 1776.31 100.175 11-15-2024 0:30:00 1776.51 100.177 11-15-2024 1:00:00 1776.71 100.173 11-15-2024 1:30:00 1776.91 100.166 11-15-2024 2:00:00 1777.11 100.159 11-15-2024 2:30:00 1777.30 100.157 11-15-2024 3:00:00 1777.50 100.161 11-15-2024 3:30:00 1777.69 100.166 11-15-2024 4:00:00 1777.89 100.173 11-15-2024 4:30:00 1778.08 100.170 11-15-2024 5:00:00 1778.27 100.166 11-15-2024 5:30:00 1778.46 100.162 11-15-2024 6:00:00 1778.65 100.166 11-15-2024 6:30:00 1778.83 100.164 11-15-2024 7:00:00 1779.02 100.162 11-15-2024 7:30:00 1779.21 100.153 11-15-2024 8:00:00 1779.39 100.155 11-15-2024 8:30:00 1779.57 100.155 11-15-2024 9:00:00 1779.75 100.152 11-15-2024 9:30:00 1779.93 100.150 11-15-2024 10:00:00 1780.11 100.144 11-15-2024 10:30:00 1780.28 100.146 11-15-2024 11:00:00 1780.46 100.144 11-15-2024 11:30:00 1780.63 100.146 11-15-2024 12:00:00 1780.81 100.143 11-15-2024 12:30:00 1780.98 100.137 11-15-2024 13:00:00 1781.15 100.135 11-15-2024 13:30:00 1781.32 100.143 11-15-2024 14:00:00 1781.49 100.146 11-15-2024 14:30:00 1781.66 100.139 11-15-2024 15:00:00 1781.83 100.139 11-15-2024 15:30:00 1781.99 100.137 11-15-2024 16:00:00 1782.16 100.130 11-15-2024 16:30:00 1782.32 100.130 11-15-2024 17:00:00 1782.48 100.128 11-15-2024 17:30:00 1782.65 100.126 11-15-2024 18:00:00 1782.81 100.123 11-15-2024 18:30:00 1782.97 100.123 11-15-2024 19:00:00 1783.13 100.117 11-15-2024 19:30:00 1783.29 100.116 11-15-2024 20:00:00 1783.45 100.119 11-15-2024 20:30:00 1783.61 100.123 11-15-2024 21:00:00 1783.76 100.117 11-15-2024 21:30:00 1783.91 100.114 11-15-2024 22:00:00 1784.07 100.114 11-15-2024 22:30:00 1784.22 100.119 11-15-2024 23:00:00 1784.38 100.114 11-15-2024 23:30:00 1784.53 100.110 11-16-2024 0:00:00 1784.68 100.105 11-16-2024 0:30:00 1784.83 100.110 11-16-2024 1:00:00 1784.99 100.103 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 50 Well:NDBi-016 Start Data:11-Nov-2024 @ 00:00 End Date:16-Nov-2024 @ 06:00 (mm-dd-yyyy hh:mm:ss)(psig) (°F) NDBi-016 DOWNHOLE_SHUT-IN / BUILD-UP PERIOD Date & Time BHP BHT COMMENTS 11-16-2024 1:30:00 1785.14 100.103 11-16-2024 2:00:00 1785.28 100.098 11-16-2024 2:30:00 1785.44 100.105 11-16-2024 3:00:00 1785.59 100.096 11-16-2024 3:30:00 1785.74 100.092 11-16-2024 4:00:00 1785.88 100.094 11-16-2024 4:30:00 1786.03 100.094 11-16-2024 5:00:00 1786.18 100.087 11-16-2024 5:30:00 1786.32 100.078 11-16-2024 6:00:00 1786.47 100.078 Finished Build-up for purposes of completing End of Well Report (EOWR). WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 51 100.0100.3100.6100.9101.2101.5101.81500155016001650170017501800Pressure (psig)Bottom Hole Data_Build-up Period_NDBi-016BHPBHTTemperature (°F)WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 52 Santos Pikka Development NDBi-016 SECTION 11 SEQUENCE OF WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 53 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss 06/Nov/2024 08:00:00 06/Nov/2024 10:30:00 06/Nov/2024 11:30:00 06/Nov/2024 11:45:00 06/Nov/2024 12:11:00 06/Nov/2024 12:11:00 06/Nov/2024 12:15:00 06/Nov/2024 12:17:00 06/Nov/2024 12:19:00 06/Nov/2024 12:30:00 06/Nov/2024 12:30:00 06/Nov/2024 12:31:00 06/Nov/2024 13:00:00 06/Nov/2024 13:00:00 06/Nov/2024 13:01:00 06/Nov/2024 13:30:00 06/Nov/2024 13:31:00 06/Nov/2024 14:00:00 06/Nov/2024 14:01:00 06/Nov/2024 14:09:00 06/Nov/2024 14:15:00 06/Nov/2024 14:30:00 06/Nov/2024 14:31:00 06/Nov/2024 14:31:00 06/Nov/2024 15:00:00 06/Nov/2024 15:01:00 06/Nov/2024 15:30:00 06/Nov/2024 15:30:00 06/Nov/2024 15:31:00 06/Nov/2024 15:34:00 06/Nov/2024 15:45:00 06/Nov/2024 15:54:00 06/Nov/2024 16:00:00 06/Nov/2024 16:00:00 06/Nov/2024 16:01:00 06/Nov/2024 16:18:00 06/Nov/2024 16:30:00 06/Nov/2024 16:31:00 06/Nov/2024 16:31:00 06/Nov/2024 17:00:00 06/Nov/2024 17:00:00 06/Nov/2024 17:01:00 06/Nov/2024 17:07:00 06/Nov/2024 17:30:00 06/Nov/2024 17:31:00 06/Nov/2024 17:49:00 06/Nov/2024 17:51:00 06/Nov/2024 17:54:00 06/Nov/2024 17:54:00 06/Nov/2024 17:55:00 06/Nov/2024 18:00:00 06/Nov/2024 18:00:00 06/Nov/2024 18:00:00 06/Nov/2024 18:01:00 06/Nov/2024 18:01:00 06/Nov/2024 18:30:00 06/Nov/2024 18:30:00 06/Nov/2024 18:31:00 06/Nov/2024 18:31:00 Commenced Chemical Injection of Defoamer and Demulsifier at 10 gal/day at the Downstream Choke Data Header . BS&W Sample at Choke Manifold Showed 100% Diesel and Trace Solids. Observed Dirty Diesel at Tank Farm Manifold. Increased Expro adjustable Choke to 28/64ths as per Santos WSS. BS&W Sample at Choke Manifold Showed 100% Diesel and Trace Solids. Rocked Expro Choke. Diverted Flow from Tank 2 to Tank 1. Commenced Water Salinity, Water Weight and pH sampling as per Santos Well Program. Water Salinity 40,000 ppm; Water pH 8; Water Weight 8.54 ppg. Commenced Chemical Injection of Methanol at 10 gal/day at the Separator Gas Line. BS&W Sample at Choke Manifold Showed 46% Water, 54% Oil and Trace Solids. Gas S.G = 0.668 Increased Expro adjustable Choke to 44/64ths as per Santos WSS. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 36% Water, 64% Oil and Trace Solids. Oil 64%. Began dumping Fluid from Separator. Metering through 2" Line (1.5" Turbine Meter). Cumulative Volumes 159.56 bbls Oil, 69.78 bbls Water and 0.31 bbls Solids was entered into the DAQ software to account for the volumes not metered due to the Separator being bypassed. Dumped DPI Unit Side A & Side B. Observed Light Solids on both sides. Increased Expro adjustable Choke to 40/64ths as per Santos WSS. Diverted Flow from Tank 1 to Tank 2. Fluid received at Tank Farm Manifold. Observed Clean Diesel at surface. OPERATIONS NDBi-016 - Well Clean-Up Flow Performed Pre-Flow Safety Meeting with Santos, LRS, Magtec and Worley prior to opening Well NDBi-016. Walked the Line and Verified Valve Alignment with Santos WSS as per Pre-Flow Checklist. Verified valve alignment lined up to flow through Ballcatcher, DPI, and Choke with returns to Tank #1. Bypassed Line Heater and Test Separator. Initial Bottomhole Pressure 1837.45 PSI; Initial Bottomhole Temperature 99.98 °F; Initial SITHP 268.2 PSI. Entered Initial Tank Straps into DAQ and Verified all Manual Inputs correct prior to opening NDBi-016 BS&W Sample at Choke Manifold Showed 100% Diesel and Trace Solids. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 99.9% Diesel and 0.1% Fine Solids. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 36% Water, 64% Oil and Trace Solids. Dumping gas from Separator to Flare. Metering Gas through 0.5" Coriolis Meter. Flare lit. Rocked Expro Choke. Oil to Surface. Water Salinity 46,000 ppm; Water pH 8; Water Weight 8.55 ppg. BS&W Sample at Choke Manifold Showed 83.5% Water, 16% Oil and 0.5% Solids. Increased Expro adjustable Choke to 36/64ths as per Santos WSS. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 3.95% Water and 0.05% Solids. Dirty Diesel 96%. Rocked Expro Choke. Rocked Expro Choke. Increased Expro adjustable Choke to 32/64ths as per Santos WSS. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 41.65% Water and 0.35% Solids. Dirty Diesel 58%. Diverted flow through 24/64ths Fixed Choke Manifold to inspect Adjustable Stem and Seat. Diverted flow through 24/64ths Adjustable Choke. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 47.85% Water, 52% Oil and 0.15% Solids. SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 Commenced Choke BS&W sampling. BS&W Sample at Choke Manifold Showed 100% Diesel. Increased Expro adjustable Choke to 24/64ths as per Santos WSS. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 100% Diesel and Trace Solids. Diverted Flow from Tank 2 to Tank 1. Opened Wellhead NDBi-016 Master Valve (23.5 turns). Opened Wellhead NDBi-016 Production Wing Valve (PWV) to closed Expro Choke Manifold (23.5 turns). Opened Well on a 20/64ths adjustable Choke as per Santos WSS. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 54 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 06/Nov/2024 18:32:00 06/Nov/2024 18:59:00 06/Nov/2024 19:00:00 06/Nov/2024 19:00:00 06/Nov/2024 19:00:00 06/Nov/2024 19:01:00 06/Nov/2024 19:01:00 06/Nov/2024 19:05:00 06/Nov/2024 19:21:00 06/Nov/2024 19:29:00 06/Nov/2024 19:30:00 06/Nov/2024 19:30:00 06/Nov/2024 19:31:00 06/Nov/2024 19:31:00 06/Nov/2024 19:58:00 06/Nov/2024 19:59:00 06/Nov/2024 20:00:00 06/Nov/2024 20:00:00 06/Nov/2024 20:01:00 06/Nov/2024 20:29:00 06/Nov/2024 20:29:00 06/Nov/2024 20:30:00 06/Nov/2024 20:30:00 06/Nov/2024 20:30:00 06/Nov/2024 20:31:00 06/Nov/2024 20:31:00 06/Nov/2024 20:33:00 06/Nov/2024 20:48:00 06/Nov/2024 20:59:00 06/Nov/2024 20:59:00 06/Nov/2024 21:00:00 06/Nov/2024 21:00:00 06/Nov/2024 21:01:00 06/Nov/2024 21:01:00 06/Nov/2024 21:01:00 06/Nov/2024 21:01:00 06/Nov/2024 21:18:00 06/Nov/2024 21:28:00 06/Nov/2024 21:28:00 06/Nov/2024 21:30:00 06/Nov/2024 21:31:00 06/Nov/2024 21:31:00 06/Nov/2024 21:31:00 06/Nov/2024 21:39:00 06/Nov/2024 21:58:00 06/Nov/2024 22:00:00 06/Nov/2024 22:01:00 06/Nov/2024 22:01:00 06/Nov/2024 22:29:00 06/Nov/2024 22:30:00 06/Nov/2024 22:30:00 06/Nov/2024 22:31:00 06/Nov/2024 22:31:00 06/Nov/2024 22:31:00 06/Nov/2024 22:35:00 06/Nov/2024 22:58:00 06/Nov/2024 22:59:00 06/Nov/2024 23:00:00 06/Nov/2024 23:01:00 06/Nov/2024 23:18:00 06/Nov/2024 23:29:00 Finished Fluid Transfer from Tank 1 to Truck# 82302. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Water Salinity 32,000 ppm; Water pH 8; Water Weight 8.54 ppg. Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter. Lowered Separator Pressure. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed No Solids. Diverted Flow from Tank 4 to Tank 3. BS&W Sample at Choke Manifold Showed 41.75% Water, 58% Oil and 0.25% Solids. Gas Rate too low to be measured by 3" Coriolis Meter. Diverted Gas Flow through 0.5'' Coriolis Meter. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 3 to Tank 4. Began Fluid Transfer from Tank 1 to Vac Truck# 82302. RVP 5.5. BS&W Sample at Choke Manifold Showed 45.80% Water, 54% Oil and 0.2% Solids. BS&W Sample at Choke Manifold Showed 46.90% Water, 53% Oil and 0.1% Solids. BS&W Sample at Choke Manifold Showed 40% Water, 60% Oil and Trace Solids. Water Salinity 34,000 ppm; Water pH 8; Water Weight 8.55 ppg. Diverted Liquid Flow from 1.5'' Turbine Meter through 2'' Turbine Meter . Observed Well Slugging. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 4 to Tank 3. Oil API 28.4 @ 60°F (Oil SG 0.885). Informed Santos WSS BHP @ 1534 psi. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed No Solids. Diverted Flow from Tank 3 to Tank 4. Upstream DPI BS&W Sample Showed No Solids. Diverted Flow from Tank 4 to Tank 3. Increased Expro adjustable Choke to 64/64ths as per Santos WSS. BS&W Sample at Choke Manifold Showed 44% Water, 56% Oil and Trace Solids. H2S 0 ppm; CO2 0.1%. Gas S.G 0.680. Observed Well Slugging. BS&W Sample at Choke Manifold Showed 56% Water and Trace Solids. Oil 44%. Water Salinity 39,000 ppm; Water pH 8; Water Weight 8.52 ppg. Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter Lowered Separator Pressure. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 1 to Tank 3. BS&W Sample at Choke Manifold Showed 20% Water, 80% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. Increased Expro adjustable Choke to 60/64ths as per Santos WSS. Diverted Flow from Tank 3 to Tank 4. Increased Expro adjustable Choke to 52/64ths as per Santos WSS. Water Salinity 38,000 ppm; Water pH 8; Water Weight 8.53 ppg. BS&W Sample at Choke Manifold Showed 18% Water, 82% Oil, and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. Increased Expro adjustable Choke to 56/64ths as per Santos WSS. BS&W Sample at Choke Manifold Showed 17% Water, 83% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter. Gas Rate too low to be measured by 3" Coriolis Meter. Diverted Gas Flow through 0.5'' Coriolis Meter. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 2 to Tank 1. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Dumped DPI Unit Side A & Side B. Observed Light Solids on both sides. Diverted Flow from Tank 1 to Tank 2. Increased Expro adjustable Choke to 48/64ths as per Santos WSS. Collected Tracerco Sample. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 55 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 06/Nov/2024 23:30:00 06/Nov/2024 23:30:00 06/Nov/2024 23:31:00 06/Nov/2024 23:31:00 06/Nov/2024 23:54:00 06/Nov/2024 23:59:00 06/Nov/2024 23:59:00 07/Nov/2024 00:00:00 07/Nov/2024 00:01:00 07/Nov/2024 00:23:00 07/Nov/2024 00:29:00 07/Nov/2024 00:30:00 07/Nov/2024 00:31:00 07/Nov/2024 00:46:00 07/Nov/2024 00:54:00 07/Nov/2024 00:59:00 07/Nov/2024 00:59:00 07/Nov/2024 01:00:00 07/Nov/2024 01:00:00 07/Nov/2024 01:01:00 07/Nov/2024 01:29:00 07/Nov/2024 01:30:00 07/Nov/2024 01:31:00 07/Nov/2024 01:31:00 07/Nov/2024 01:55:00 07/Nov/2024 01:59:00 07/Nov/2024 01:59:00 07/Nov/2024 02:00:00 07/Nov/2024 02:01:00 07/Nov/2024 02:23:00 07/Nov/2024 02:29:00 07/Nov/2024 02:30:00 07/Nov/2024 02:31:00 07/Nov/2024 02:59:00 07/Nov/2024 03:00:00 07/Nov/2024 03:01:00 07/Nov/2024 03:01:00 07/Nov/2024 03:01:00 07/Nov/2024 03:01:00 07/Nov/2024 03:12:00 07/Nov/2024 03:17:00 07/Nov/2024 03:29:00 07/Nov/2024 03:29:00 07/Nov/2024 03:30:00 07/Nov/2024 03:31:00 07/Nov/2024 03:31:00 07/Nov/2024 03:54:00 07/Nov/2024 03:58:00 07/Nov/2024 04:00:00 07/Nov/2024 04:00:00 07/Nov/2024 04:00:00 07/Nov/2024 04:00:00 07/Nov/2024 04:02:00 07/Nov/2024 04:03:00 07/Nov/2024 04:04:00 07/Nov/2024 04:05:00 07/Nov/2024 04:29:00 07/Nov/2024 04:29:00 07/Nov/2024 04:30:00 07/Nov/2024 04:31:00 07/Nov/2024 04:31:00 Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 36% Water, 64% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 6 to Tank 5. Gas S.G 0.683. H2S 0 ppm; CO2 0.1%. BS&W Sample at Choke Manifold Showed 40% Water, 60% Oil and Trace Solids. Began Fluid Transfer from Tank 4 to Truck# 82302. RVP 5. Increased Expro adjustable Choke to 128/64ths as per Santos WSS. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 29% Water, 71% Oil and Trace Solids. Increased Expro adjustable Choke to 72/64ths as per Santos WSS. Diverted Flow from Tank 6 to Tank 1. Increased Expro adjustable Choke to 72/64ths as per Santos WSS. Increased Expro adjustable Choke to 82/64ths as per Santos WSS. Increased Expro adjustable Choke to 102/64ths as per Santos WSS. BS&W Sample at Choke Manifold Showed 56% Water, 44% Oil and Trace Solids. Finished Fluid Transfer from Tank 2 to Truck #82342. Began Fluid Transfer from Tank 3 to Truck #82342. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 5 to Tank 6. Finished Fluid Transfer from Tank 3 to Truck #82342. Water Salinity 34,000 ppm; Water pH 8; Water Weight 8.54 ppg. Began Fluid Transfer from Tank 2 to Truck# 82342. RVP= 5.5 Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed No Solids. Diverted Flow from Tank 4 to Tank 5. Observed well slugging. Diverted Flow from Tank 3 to Tank 4. Applied CMSF 0.933. BS&W Sample at Choke Manifold Showed 41.90% Water, 58% Oil and 0.1% Solids. BS&W Sample at Choke Manifold Showed 47.90% Water, 52% Oil and 0.1% Solids. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 30.90% Water, 69% Oil and 0.10% Solids. Finished Fluid Transfer from Tank 3 to Truck #82338. Began Fluid Transfer from Tank 4 to Truck #82338. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 5 to Tank 6. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 36.85% Water, 63% Oil and 0.15% Solids. Water Salinity 36,000 ppm; Water pH 8; Water Weight 8.52 ppg. Began Fluid Transfer from Tank 3 to Truck# 82338. RVP 5. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed No Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed No Solids. Diverted Flow from Tank 6 to Tank 5. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 40.90% Water, 59% Oil and 0.1% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. BS&W Sample at Choke Manifold Showed 36% Water, 64% Oil and Trace Solids. Water Salinity 31,000 ppm; Water pH 8; Water Weight 8.51 ppg. Observed Well Slugging. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 6 to Tank 1. Oil API 30.1 @ 60°F (Oil SG 0.876). Finished Fluid Transfer from Tank 4 to Truck #82338. Flare Drain Free of Fluid. Increased Expro adjustable Choke to 92/64ths as per Santos WSS. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 56 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 07/Nov/2024 04:50:00 07/Nov/2024 04:59:00 07/Nov/2024 05:00:00 07/Nov/2024 05:00:00 07/Nov/2024 05:01:00 07/Nov/2024 05:01:00 07/Nov/2024 05:02:00 07/Nov/2024 05:03:00 07/Nov/2024 05:08:00 07/Nov/2024 05:15:00 07/Nov/2024 05:30:00 07/Nov/2024 05:30:00 07/Nov/2024 05:30:00 07/Nov/2024 05:31:00 07/Nov/2024 05:31:00 07/Nov/2024 06:00:00 07/Nov/2024 06:00:00 07/Nov/2024 06:00:00 07/Nov/2024 06:01:00 07/Nov/2024 06:02:00 07/Nov/2024 06:03:00 07/Nov/2024 06:30:00 07/Nov/2024 06:30:00 07/Nov/2024 06:30:00 07/Nov/2024 06:31:00 07/Nov/2024 06:31:00 07/Nov/2024 06:35:00 07/Nov/2024 06:41:00 07/Nov/2024 07:00:00 07/Nov/2024 07:00:00 07/Nov/2024 07:00:00 07/Nov/2024 07:00:00 07/Nov/2024 07:01:00 07/Nov/2024 07:30:00 07/Nov/2024 07:30:00 07/Nov/2024 07:30:00 07/Nov/2024 07:31:00 07/Nov/2024 07:31:00 07/Nov/2024 08:00:00 07/Nov/2024 08:00:00 07/Nov/2024 08:01:00 07/Nov/2024 08:01:00 07/Nov/2024 08:19:00 07/Nov/2024 08:30:00 07/Nov/2024 08:31:00 07/Nov/2024 08:31:00 07/Nov/2024 08:31:00 07/Nov/2024 09:00:00 07/Nov/2024 09:00:00 07/Nov/2024 09:00:00 07/Nov/2024 09:01:00 07/Nov/2024 09:01:00 07/Nov/2024 09:01:00 07/Nov/2024 09:01:00 07/Nov/2024 09:01:00 07/Nov/2024 09:18:00 07/Nov/2024 09:30:00 07/Nov/2024 09:30:00 07/Nov/2024 09:31:00 07/Nov/2024 09:31:00 07/Nov/2024 09:31:00 BS&W Sample at Choke Manifold Showed 64% Water, 36% Oil and Trace Solids. Water Salinity 33,000 ppm; Water pH 8; Water Weight 8.50 ppg. H2S 0 ppm; CO2 0.1%. Increased Separator Pressure. Began Fluid Transfer from Tank 5 Truck #86057. RVP 5. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 7 to Tank 8. Upstream DPI BS&W Sample Showed Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 8 to Tank 7. BS&W Sample at Choke Manifold Showed 77% Water, 23% Oil and Trace Solids. Oil API 28.2 @ 60°F (Oil SG 0.886). Gas S.G 0.714. Flare Drain Free of Fluid. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. BS&W Sample at Choke Manifold Showed 72.95% Water, 27% Oil and 0.25% Solids. Water Salinity 33,000 ppm; Water pH 8; Water Weight 8.49 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 8 to Tank 7. BS&W Sample at Choke Manifold Showed 75.85% Water, 24% Oil and 0.15% Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 7 to Tank 8. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 76.85% Water, 23% Oil and 0.15% Solids. Water Salinity 34,000 ppm; Water pH 8; Water Weight 8.49 ppg. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Observed Well Slugging. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 8 to Tank 7. Upstream DPI BS&W Sample Showed Trace Solids. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 67.80% Water, 32% Oil and 0.20% Solids. Finished Fluid Transfer fromTank 5 to Truck #82302. Diverted Flow from Tank 7 to Tank 8. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 67.75% Water, 32% Oil and 0.25% Solids. Flare Drain Free of Fluid. Water Salinity 36,000 ppm; Water pH 8; Water Weight 8.46 ppg. Water Salinity 34,000 ppm; Water pH 8; Water Weight 8.52 ppg. BS&W Sample at Choke Manifold Showed 42.80% Water, 57% Oil and 0.20% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 67.6% Water, 32% and 0.40% Solids. Diverted Gas Flow from 3'' Coriolis Meter through 0.5'' Coriolis Meter. Diverted Flow from Tank 2 to Tank 7. Lowered Separator Pressure. Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter. Diverted Flow from Tank 1 to Tank 2. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Gas Rate too low to be measured by 3" Coriolis Meter. Diverted Gas Flow through 0.5'' Coriolis Meter. Diverted Flow from Tank 2 to Tank 1. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 47.75% Water, 52% Oil and 0.25% Solids. Finished Fluid Transfer from Tank 4 to Truck #82302. Began Fluid Transfer from Tank #5 to Truck #82302. Sparged Expro Separator; Trace Solids Observed. Observed Well Slugging. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 57 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 07/Nov/2024 09:33:00 07/Nov/2024 09:42:00 07/Nov/2024 09:45:00 07/Nov/2024 09:53:00 07/Nov/2024 10:30:00 07/Nov/2024 10:40:00 07/Nov/2024 11:06:00 07/Nov/2024 11:07:00 07/Nov/2024 11:16:00 07/Nov/2024 11:30:00 07/Nov/2024 11:30:00 07/Nov/2024 11:31:00 07/Nov/2024 11:31:00 07/Nov/2024 11:31:00 07/Nov/2024 11:42:00 07/Nov/2024 12:00:00 07/Nov/2024 12:00:00 07/Nov/2024 12:00:00 07/Nov/2024 12:01:00 07/Nov/2024 12:01:00 07/Nov/2024 12:30:00 07/Nov/2024 12:30:00 07/Nov/2024 12:30:00 07/Nov/2024 12:31:00 07/Nov/2024 12:31:00 07/Nov/2024 12:31:00 07/Nov/2024 12:48:00 07/Nov/2024 13:00:00 07/Nov/2024 13:00:00 07/Nov/2024 13:00:00 07/Nov/2024 13:00:00 07/Nov/2024 13:00:00 07/Nov/2024 13:01:00 07/Nov/2024 13:01:00 07/Nov/2024 13:01:00 07/Nov/2024 13:02:00 07/Nov/2024 13:03:00 07/Nov/2024 13:04:00 07/Nov/2024 13:05:00 07/Nov/2024 13:06:00 07/Nov/2024 13:07:00 07/Nov/2024 13:08:00 07/Nov/2024 13:09:00 07/Nov/2024 13:10:00 07/Nov/2024 13:11:00 07/Nov/2024 13:12:00 07/Nov/2024 13:13:00 07/Nov/2024 13:14:00 07/Nov/2024 13:30:00 07/Nov/2024 13:30:00 07/Nov/2024 13:30:00 07/Nov/2024 13:31:00 07/Nov/2024 13:31:00 07/Nov/2024 13:31:00 07/Nov/2024 14:00:00 07/Nov/2024 14:00:00 07/Nov/2024 14:00:00 07/Nov/2024 14:01:00 07/Nov/2024 14:01:00 07/Nov/2024 14:30:00 07/Nov/2024 14:30:00 BS&W Sample at Choke Manifold Showed 59% Water, 41% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 3 to Tank 4. Water Salinity 33,000 ppm; Water pH 8; Water Weight 8.48 ppg. BS&W Sample at Choke Manifold Showed 62% Water, 38% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 4 to Tank 3. Injection Rate into NDBi-014 @ 2.75 bpm. Total Volume Injected 333.89 bbls. Increased Expro adjustable Choke to 124/64ths as per Santos WSS. Increased Expro adjustable Choke to 128/64ths as per Santos WSS. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 3 to Tank 4. Injection Rate into NDBi-014 @ 2.29 bpm. Total Volume Injected 260.73 bbls. Upstream DPI BS&W Sample Showed Trace Solids. Increased Expro adjustable Choke to 116/64ths as per Santos WSS. Increased Expro adjustable Choke to 120/64ths as per Santos WSS. Increased Expro adjustable Choke to 96/64ths as per Santos WSS. Increased Expro adjustable Choke to 100/64ths as per Santos WSS. Increased Expro adjustable Choke to 104/64ths as per Santos WSS. Increased Expro adjustable Choke to 108/64ths as per Santos WSS. Increased Expro adjustable Choke to 112/64ths as per Santos WSS. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 81% Water, 19% Oil and Trace Solids. Increased Expro adjustable Choke to 80/64ths as per Santos WSS. Increased Expro adjustable Choke to 84/64ths as per Santos WSS. Increased Expro adjustable Choke to 88/64ths as per Santos WSS. Increased Expro adjustable Choke to 92/64ths as per Santos WSS. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 2 to Tank 3. Increased Expro adjustable Choke to 72/64ths as per Santos WSS. Collected Tracerco Sample. Injection Rate into NDBi-014 @ 2.29 bpm. Total Volume Injected 191.96 bbls. Increased Expro adjustable Choke to 76/64ths as per Santos WSS. Injection Rate into NDBi-014 @ 3.16 bpm. Total Volume Injected 106.05 bbls. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. BS&W Sample at Choke Manifold Showed 71% Water, 29% Oil and Trace Solids. Water Salinity 33,000 ppm; Water pH 8; Water Weight 8.47 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Reduced NDBi-014 Injection Rate to 2.3 bpm. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 2 to Tank 1. Injection Rate into NDBi-014 @ 2.34 bpm. Total Volume Injected 31.53 bbls. BS&W Sample at Choke Manifold Showed 70% Water, 30% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 1 to Tank 2. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 1 to Tank 2. Water Salinity 34,000 ppm; Water pH 8; Water Weight 8.5 ppg. BS&W Sample at Choke Manifold Showed 63.9% Water, 36% Oil and 0.1% Solids. Upstream DPI BS&W Sample Showed Trace Solids. Began Injecting Tank 7 and Tank 8 into NDBi-014 Injection Well. Diverted Flow from Tank 8 to Tank 1. Completed shipping fluid from Tank 6 to Vac Truck 86057. Opened Well on a 64/64ths adjustable Choke as per Santos WSS. Fluid at the Tank Farm Manifold. Flare lit. Began Fluid Transfer from Tank 6 to Truck #86057. RVP 5. Air Supply was lost to Hydraulic ESD Panel causing Fail Safe Close of ESD System. Well Shut-in at WH SSV and Expro SSV. Discontinued all Chemical Injections. Finished Fluid Transfer from Tank 5 to Truck #86057. Began Fluid Transfer from Tank 6 to Truck #86057 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 58 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 07/Nov/2024 14:30:00 07/Nov/2024 14:31:00 07/Nov/2024 14:31:00 07/Nov/2024 14:31:00 07/Nov/2024 14:45:00 07/Nov/2024 14:45:00 07/Nov/2024 15:00:00 07/Nov/2024 15:00:00 07/Nov/2024 15:00:00 07/Nov/2024 15:00:00 07/Nov/2024 15:01:00 07/Nov/2024 15:01:00 07/Nov/2024 15:01:00 07/Nov/2024 15:01:00 07/Nov/2024 15:01:00 07/Nov/2024 15:30:00 07/Nov/2024 15:30:00 07/Nov/2024 15:30:00 07/Nov/2024 15:30:00 07/Nov/2024 15:31:00 07/Nov/2024 15:31:00 07/Nov/2024 15:31:00 07/Nov/2024 16:00:00 07/Nov/2024 16:00:00 07/Nov/2024 16:00:00 07/Nov/2024 16:00:00 07/Nov/2024 16:01:00 07/Nov/2024 16:01:00 07/Nov/2024 16:06:00 07/Nov/2024 16:30:00 07/Nov/2024 16:30:00 07/Nov/2024 16:30:00 07/Nov/2024 16:31:00 07/Nov/2024 16:31:00 07/Nov/2024 17:00:00 07/Nov/2024 17:00:00 07/Nov/2024 17:00:00 07/Nov/2024 17:01:00 07/Nov/2024 17:01:00 07/Nov/2024 17:01:00 07/Nov/2024 17:15:00 07/Nov/2024 17:30:00 07/Nov/2024 17:30:00 07/Nov/2024 17:30:00 07/Nov/2024 17:31:00 07/Nov/2024 17:51:00 07/Nov/2024 18:00:00 07/Nov/2024 18:01:00 07/Nov/2024 18:01:00 07/Nov/2024 18:30:00 07/Nov/2024 18:31:00 07/Nov/2024 18:31:00 07/Nov/2024 18:59:00 07/Nov/2024 19:00:00 07/Nov/2024 19:00:00 07/Nov/2024 19:00:00 07/Nov/2024 19:00:00 07/Nov/2024 19:01:00 07/Nov/2024 19:16:00 07/Nov/2024 19:16:00 07/Nov/2024 19:29:00 Diverted Gas Flow from 0.5'' Coriolis Meter through 3'' Coriolis Meter. Lowered Separator Pressure. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Gas remained entrained in oil causing higher liquid rates being measured across turbine meters. Increased Chemical Injection of Defoamer to 16 gal/day. Applied CMSF 0.650 to compensate for high Liquid Rates caused by reduced Gas Breakout Rate. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 49% Water, 51% Oil and Trace Solids. Diverted Flow from Tank 9 to Tank 10. BS&W Sample at Choke Manifold Showed 47% Water, 53% Oil and Trace Solids. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.48 ppg. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 10 to Tank 1. Injection Rate into NDBi-014 @ 3.51 bpm. Total Volume Injected 933.31 bbls. Water Salinity 31,000 ppm; Water pH 8; Water Weight 8.45 ppg. Added Tank 3 and Tank 4 into NDBi-014 injection and Removed Tank 1 and Tank 2. Diverted Flow from Tank 10 to Tank 9. BS&W Sample at Choke Manifold Showed 52% Water, 48% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Increased NDBi-014 Injection Rate to 3.5 bpm. Upstream DPI BS&W Sample Showed 0.05% Solids. Flare Drain Free of Fluid. Diverted Flow from Tank 9 to Tank 10. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Water Salinity 32,000 ppm; Water pH 8; Water Weight 8.47 ppg. BS&W Sample at Choke Manifold Showed 50% Water, 50% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 10 to Tank 9. Injection Rate into NDBi-014 @ 2.78 bpm. Total Volume Injected 830.43 bbls. BS&W Sample at Choke Manifold Showed 52% Water, 48% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 52% Water, 48% Oil and Trace Solids. Upstream DPI BS&W Sample Showed 0.05% Solids. Sparged Separator; Light Solids Observed. Diverted Flow from Tank 9 to Tank 10. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Collected Composition Sample. Upstream DPI BS&W Sample Showed 0.05% Solids. Diverted Flow from Tank 4 to Tank 9. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Injection Rate into NDBi-014 @ 2.75 bpm. Total Volume Injected 664.82 bbls. Applied CMSF 0.942. Recorded Flare Heat Index Readings. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 3 to Tank 4. Injection Rate into NDBi-014 @ 2.75 bpm. Total Volume Injected 582.15 bbls. Water Salinity 31,000 ppm; Water pH 8; Water Weight 8.47 ppg. BS&W Sample at Choke Manifold Showed 52% Water, 48% Oil and Trace Solids. Injection Rate into NDBi-014 @ 2.74 bpm. Total Volume Injected 499.72 bbls. Upstream DPI BS&W Sample Showed 0.05% Solids. Oil API 29.3 @ 60°F (Oil SG 0.88). Gas S.G 0.676. H2S 0 ppm; CO2 0.1%. BS&W Sample at Choke Manifold Showed 52% Water, 48% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 52% Water, 48% Oil and Trace Solids. Flare Drain Free of Fluid. Gas Scrubber Drain Free of Fluid. Diverted Flow from Tank 4 to Tank 3. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Added Tank 1 and Tank 2 into NDBi-014 Injection and Removed Tank 7 and Tank 8. Injection Rate into NDBi-014 @ 2.76 bpm. Total Volume Injected 416.74 bbls. Water Salinity 32,000 ppm; Water pH 8; Water Weight 8.49 ppg. Upstream DPI BS&W Sample Showed 0.05% Solids. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 59 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 07/Nov/2024 19:30:00 07/Nov/2024 19:30:00 07/Nov/2024 19:31:00 07/Nov/2024 19:31:00 07/Nov/2024 19:31:00 07/Nov/2024 19:42:00 07/Nov/2024 19:50:00 07/Nov/2024 20:00:00 07/Nov/2024 20:01:00 07/Nov/2024 20:29:00 07/Nov/2024 20:30:00 07/Nov/2024 20:31:00 07/Nov/2024 20:59:00 07/Nov/2024 21:00:00 07/Nov/2024 21:01:00 07/Nov/2024 21:01:00 07/Nov/2024 21:01:00 07/Nov/2024 21:01:00 07/Nov/2024 21:30:00 07/Nov/2024 21:31:00 07/Nov/2024 21:31:00 07/Nov/2024 21:31:00 07/Nov/2024 21:34:00 07/Nov/2024 21:55:00 07/Nov/2024 22:00:00 07/Nov/2024 22:00:00 07/Nov/2024 22:00:00 07/Nov/2024 22:01:00 07/Nov/2024 22:30:00 07/Nov/2024 22:30:00 07/Nov/2024 22:31:00 07/Nov/2024 22:31:00 07/Nov/2024 22:33:00 07/Nov/2024 22:40:00 07/Nov/2024 22:59:00 07/Nov/2024 23:00:00 07/Nov/2024 23:01:00 07/Nov/2024 23:29:00 07/Nov/2024 23:30:00 07/Nov/2024 23:31:00 07/Nov/2024 23:34:00 07/Nov/2024 23:38:00 07/Nov/2024 23:39:00 08/Nov/2024 00:00:00 08/Nov/2024 00:00:00 08/Nov/2024 00:01:00 08/Nov/2024 00:01:00 08/Nov/2024 00:04:00 08/Nov/2024 00:04:00 08/Nov/2024 00:29:00 08/Nov/2024 00:30:00 08/Nov/2024 00:31:00 08/Nov/2024 00:31:00 08/Nov/2024 00:31:00 08/Nov/2024 00:36:00 08/Nov/2024 01:00:00 08/Nov/2024 01:00:00 08/Nov/2024 01:00:00 08/Nov/2024 01:00:00 08/Nov/2024 01:01:00 08/Nov/2024 01:29:00 Collected Tracerco Sample. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed 0.9% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow through Ball Catcher. Added Tank 3 and Tank 4 into NDBi-014 injection and Removed Tank 1 and Tank 2. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed 0.25% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Bypassed Ball Catcher. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 4 to Tank 5. BS&W Sample at Choke Manifold Showed 45% Water, 54% Oil and 1% Solids. Applied CMSF 0.939. BS&W Sample at Choke Manifold Showed 39.20% Water, 60% Oil and 0.80% Solids. Diverted Flow from Tank 3 to Tank 4. Sparged Separator; Trace Solids Observed. BS&W Sample at Choke Manifold Showed 41% Water, 58% Oil and 1% Solids. Magtech Injection Pump Online. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 39% Water, 60% Oil and 1% Solids. Magtech Injection Pump Offline; Collecting Data. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 36% Water, 63% Oil and 1% Solids. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.44 ppg. Upstream DPI BS&W Sample Showed 0.7% Solids. Diverted Flow from Tank 6 to Tank 5. Lowered Separator Pressure. BS&W Sample at Choke Manifold Showed 33% Water, 66% Oil and 1% Solids. Upstream DPI BS&W Sample Showed 0.05% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 4 to Tank 3. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 2 to Tank 3. BS&W Sample at Choke Manifold Showed 40.5% Water, 59% Oil and 0.5% Solids. Gas S.G 0.692. H2S 0 ppm; CO2 0.1%. Oil API 29.8 @ 60°F (Oil SG 0.877). BS&W Sample at Choke Manifold Showed 41.25% Water, 58% Oil and 0.75% Solids. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 38% Water, 62% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 39.75% Water, 60% Oil and 0.25% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Inspected Ball Catcher; Trace of Solids Observed. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 43% Water, 56% Oil and 1% Solids. Water Salinity 32,000 ppm; Water pH 8; Water Weight 8.46 ppg. Increased Separator Pressure. Added Tank 9 and Tank 10 into NDBi-014 injection and Removed Tank 3 and Tank4. Diverted Flow from Tank 1 to Tank 2. Gas Breakout returned to normal rate. Applied CMSF 0.914. BS&W Sample at Choke Manifold Showed 47% Water, 53% Oil and Trace Solids. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.46 ppg. Upstream DPI BS&W Sample Showed 1% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Added Tank 1 and Tank 2 into NDBi-014 injection and Removed Tank 9 and Tank10. Diverted Flow from Tank 3 to Tank 4. Upstream DPI BS&W Sample Showed 0.05% Solids. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 60 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 08/Nov/2024 01:30:00 08/Nov/2024 01:31:00 08/Nov/2024 01:31:00 08/Nov/2024 01:32:00 08/Nov/2024 02:00:00 08/Nov/2024 02:01:00 08/Nov/2024 02:03:00 08/Nov/2024 02:07:00 08/Nov/2024 02:28:00 08/Nov/2024 02:29:00 08/Nov/2024 02:30:00 08/Nov/2024 02:31:00 08/Nov/2024 02:31:00 08/Nov/2024 03:00:00 08/Nov/2024 03:00:00 08/Nov/2024 03:01:00 08/Nov/2024 03:01:00 08/Nov/2024 03:01:00 08/Nov/2024 03:01:00 08/Nov/2024 03:01:00 08/Nov/2024 03:30:00 08/Nov/2024 03:31:00 08/Nov/2024 03:31:00 08/Nov/2024 03:59:00 08/Nov/2024 04:00:00 08/Nov/2024 04:01:00 08/Nov/2024 04:05:00 08/Nov/2024 04:30:00 08/Nov/2024 04:31:00 08/Nov/2024 04:31:00 08/Nov/2024 04:41:00 08/Nov/2024 04:55:00 08/Nov/2024 04:59:00 08/Nov/2024 05:00:00 08/Nov/2024 05:01:00 08/Nov/2024 05:30:00 08/Nov/2024 05:31:00 08/Nov/2024 05:31:00 08/Nov/2024 05:31:00 08/Nov/2024 06:00:00 08/Nov/2024 06:00:00 08/Nov/2024 06:00:00 08/Nov/2024 06:01:00 08/Nov/2024 06:15:00 08/Nov/2024 06:30:00 08/Nov/2024 06:30:00 08/Nov/2024 06:31:00 08/Nov/2024 06:31:00 08/Nov/2024 06:31:00 08/Nov/2024 07:00:00 08/Nov/2024 07:00:00 08/Nov/2024 07:00:00 08/Nov/2024 07:00:00 08/Nov/2024 07:01:00 08/Nov/2024 07:01:00 08/Nov/2024 07:10:00 08/Nov/2024 07:30:00 08/Nov/2024 07:30:00 08/Nov/2024 07:30:00 08/Nov/2024 07:31:00 08/Nov/2024 07:31:00 Flare Drain Free of Fluid. Diverted Flow from Tank 3 to Tank 4. Injection Rate into NDBi-014 @ 2.98 bpm. Total Volume Injected 3524.93 bbls. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.48 ppg. BS&W Sample at Choke Manifold Showed 47.8% Water, 52% Oil and 0.2% Solids. Upstream DPI BS&W Sample Showed 0.05% Solids. Added Tank 1 and Tank 2 into NDBi-014 injection and Removed Tank 7 and Tank 8. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 4 to Tank 3. Injection Rate into NDBi-014 @ 3.0 bpm. Total Volume Injected 3435.8 bbls. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 38.8% Water, 61% Oil and 0.2% Solids. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 3342.35 bbls. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.48 ppg. BS&W Sample at Choke Manifold Showed 40.75% Water, 59% Oil and 0.25% Solids. Upstream DPI BS&W Sample Showed 0.06% Solids. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 55% Water, 44% Oil and 1% Solids. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 2 to Tank 3. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 3250.04 bbls. BS&W Sample at Choke Manifold Showed 56.5% Water, 43% Oil and 0.5% Solids. Gas Scrubber Drain Free of Fluid. Diverted Flow from Tank 3 to Tank 4. BS&W Sample at Choke Manifold Showed 34.5% Water, 65% Oil and 0.5% Solids. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 29.5% Water, 70% Oil and 0.5% Solids. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.43 ppg. Upstream DPI BS&W Sample Showed 0.05% Solids. BS&W Sample at Choke Manifold Showed 46% Water, 53% Oil and 1% Solids. Upstream DPI BS&W Sample Showed 0.5% Solids. Flare Drain Free of Fluid. Added Tank 7 and Tank 8 into NDBi-014 injection and Removed Tank 5 and Tank 6. Dumped DPI Unit Side B. Observed Trace Solids. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 54% Water, 45% Oil and 1% Solids. Upstream DPI BS&W Sample Showed 0.2% Solids. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 2 to Tank 1. Diverted Flow from Tank 8 to Tank 7. Bypassed DPI Unit Side A; Flowing through DPI Side B. Diverted Flow from Tank 6 to Tank 7. BS&W Sample at Choke Manifold Showed 56.80% Water, 42% Oil and 1.20% Solids. Dumped DPI Unit Side B. Observed Trace Solids. Added Tank 5 and Tank 6 into NDBi-014 injection and Removed Tank 3 and Tank 4. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 51.90% Water, 47% Oil and 1.10% Solids. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.43 ppg. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.43 ppg. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 8 to Tank 1. BS&W Sample at Choke Manifold Showed 42% Water, 57% Oil and 1% Solids. Sparged Separator; Trace Solids Observed. Injection Rate into NDBi-014 @ 2.98 bpm; Total Volume Injected 2710.14 bbls. BS&W Sample at Choke Manifold Showed 62.5% Water, 37% Oil and 0.50% Solids. Water Salinity 32,000 ppm; Water pH 8; Water Weight 8.43 ppg. Diverted Flow from Tank 1 to Tank 2. Oil API 29.6 @ 60°F (Oil SG 0.878). Gas S.G 0.70. H2S 0 ppm; CO2 0.1%. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 61 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 08/Nov/2024 08:00:00 08/Nov/2024 08:00:00 08/Nov/2024 08:00:00 08/Nov/2024 08:01:00 08/Nov/2024 08:01:00 08/Nov/2024 08:05:00 08/Nov/2024 08:20:00 08/Nov/2024 08:30:00 08/Nov/2024 08:30:00 08/Nov/2024 08:30:00 08/Nov/2024 08:31:00 08/Nov/2024 08:31:00 08/Nov/2024 08:31:00 08/Nov/2024 08:32:00 08/Nov/2024 08:45:00 08/Nov/2024 09:00:00 08/Nov/2024 09:00:00 08/Nov/2024 09:00:00 08/Nov/2024 09:01:00 08/Nov/2024 09:01:00 08/Nov/2024 09:01:00 08/Nov/2024 09:01:00 08/Nov/2024 09:01:00 08/Nov/2024 09:30:00 08/Nov/2024 09:30:00 08/Nov/2024 09:30:00 08/Nov/2024 09:30:00 08/Nov/2024 09:31:00 08/Nov/2024 09:31:00 08/Nov/2024 09:31:00 08/Nov/2024 10:00:00 08/Nov/2024 10:00:00 08/Nov/2024 10:00:00 08/Nov/2024 10:01:00 08/Nov/2024 10:01:00 08/Nov/2024 10:15:00 08/Nov/2024 10:30:00 08/Nov/2024 10:30:00 08/Nov/2024 10:30:00 08/Nov/2024 10:31:00 08/Nov/2024 10:31:00 08/Nov/2024 10:31:00 08/Nov/2024 11:00:00 08/Nov/2024 11:00:00 08/Nov/2024 11:00:00 08/Nov/2024 11:01:00 08/Nov/2024 11:05:00 08/Nov/2024 11:30:00 08/Nov/2024 11:30:00 08/Nov/2024 11:30:00 08/Nov/2024 11:31:00 08/Nov/2024 11:31:00 08/Nov/2024 11:46:00 08/Nov/2024 12:00:00 08/Nov/2024 12:00:00 08/Nov/2024 12:00:00 08/Nov/2024 12:01:00 08/Nov/2024 12:01:00 08/Nov/2024 12:03:00 08/Nov/2024 12:30:00 08/Nov/2024 12:30:00 Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Diverted Flow from Tank 5 to Tank 6. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. BS&W Sample at Choke Manifold Showed 23.95% Water, 76% Oil and 0.05% Solids. Upstream DPI BS&W Sample Showed Trace Solids. Added Tank 9 and Tank 10 into NDBi-014 Injection and Removed Tank 2, Tank 3 and Tank4. Diverted Flow from Tank 6 to Tank 5. Dumped DPI Unit Side A & Side B. Observed Heavy Carbolite on Side A and Moderate Carbolite on Side B. Injection Rate into NDBi-014 @ 2.99 bpm. Total Volume Injected 4215.15 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 19.95% Water, 80% Oil and 0.05% Solids. Santos Released Nitrogen Pumper and Crew. Injection Rate into NDBi-014 @ 2.99 bpm. Total Volume Injected 4303.12 bbls. Diverted Flow from Tank 5 to Tank 6. Injection Rate into NDBi-014 @ 2.99 bpm. Total Volume Injected 4125.14 bbls. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. BS&W Sample at Choke Manifold Showed 44.9% Water, 55% Oil and 0.1% Solids. Sparged Separator; Trace Solids Observed. Diverted Flow from Tank 6 to Tank 5. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on both Sides. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 4035.78 bbls. Diverted Flow from Tank 10 to Tank 5. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 31.9% Water, 68% Oil and 0.1% Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on both Sides. Diverted Flow from Tank 10 to Tank 9 (15 min Flow). Injection Rate into NDBi-014 @ 3.03 bpm. Total Volume Injected 3945.36 bbls. BS&W Sample at Choke Manifold Showed 27.9% Water, 72% Oil and 0.1% Solids. Upstream DPI BS&W Sample Showed 0.05% Solids. Diverted Flow from Tank 9 to Tank 10 (15 min Flow). Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Injection Rate into NDBi-014 @ 3.03 bpm. Total Volume Injected 3854.56 bbls. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 31.85% Water, 68% Oil and 0.15% Solids. Upstream DPI BS&W Sample Showed Trace Solids. H2S 0 ppm; CO2 0.1%. Oil API 29.5 @ 60°F (Oil SG 0.879). BS&W Sample at Choke Manifold Showed 19.95% Water, 80% Oil and 0.05% Solids. Upstream DPI BS&W Sample Showed 0.05% Solids. Diverted Flow from Tank 9 to Tank 10. Gas Scrubber Drain Free of Fluid. Added Tank 3 and Tank 4 into NDBi-014 injection and Removed Tank 1. Added Tank 2 into NDBi-014 injection (Remained Isolated When thought to be added to Injection @ 07:10). Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Diverted Flow from Tank 10 to Tank 9. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 3709.54 bbls. Gas S.G 0.714. Diverted Flow from Tank 9 to Tank 10. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on both Sides. Injection Pump offline due to pump prime issue (Tanks Emptied Quicker Than Anticipated). BS&W Sample at Choke Manifold Showed 31.75% Water, 68% Oil and 0.25% Solids. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.46 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Injection Rate into NDBi-014 @ 3.01 bpm. Total Volume Injected 3615.6 bbls. Diverted Flow from Tank 4 to Tank 9. BS&W Sample at Choke Manifold Showed 9.95% Water, 90% Oil and 0.05% Solids. Upstream DPI BS&W Sample Showed 0.1% Solids. Diverted Flow through DPI Side A. Flowing through DPI Side A and Side B in Series. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on both Sides. Dumped DPI Unit Side B. Observed Heavy Carbolite. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 62 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 08/Nov/2024 12:30:00 08/Nov/2024 12:30:00 08/Nov/2024 12:31:00 08/Nov/2024 12:31:00 08/Nov/2024 12:45:00 08/Nov/2024 13:00:00 08/Nov/2024 13:00:00 08/Nov/2024 13:00:00 08/Nov/2024 13:00:00 08/Nov/2024 13:01:00 08/Nov/2024 13:15:00 08/Nov/2024 13:30:00 08/Nov/2024 13:30:00 08/Nov/2024 13:30:00 08/Nov/2024 13:30:00 08/Nov/2024 13:31:00 08/Nov/2024 13:31:00 08/Nov/2024 14:00:00 08/Nov/2024 14:00:00 08/Nov/2024 14:00:00 08/Nov/2024 14:01:00 08/Nov/2024 14:05:00 08/Nov/2024 14:30:00 08/Nov/2024 14:30:00 08/Nov/2024 14:30:00 08/Nov/2024 14:30:00 08/Nov/2024 14:31:00 08/Nov/2024 14:31:00 08/Nov/2024 14:45:00 08/Nov/2024 15:00:00 08/Nov/2024 15:00:00 08/Nov/2024 15:00:00 08/Nov/2024 15:01:00 08/Nov/2024 15:01:00 08/Nov/2024 15:01:00 08/Nov/2024 15:01:00 08/Nov/2024 15:01:00 08/Nov/2024 15:30:00 08/Nov/2024 15:30:00 08/Nov/2024 15:30:00 08/Nov/2024 15:31:00 08/Nov/2024 15:31:00 08/Nov/2024 15:31:00 08/Nov/2024 15:40:00 08/Nov/2024 16:00:00 08/Nov/2024 16:00:00 08/Nov/2024 16:00:00 08/Nov/2024 16:01:00 08/Nov/2024 16:01:00 08/Nov/2024 16:30:00 08/Nov/2024 16:30:00 08/Nov/2024 16:30:00 08/Nov/2024 16:31:00 08/Nov/2024 16:31:00 08/Nov/2024 16:31:00 08/Nov/2024 16:35:00 08/Nov/2024 17:00:00 08/Nov/2024 17:00:00 08/Nov/2024 17:00:00 08/Nov/2024 17:01:00 08/Nov/2024 17:01:00 Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Diverted Flow from Tank 7 to Tank 8. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 5203.57 bbls. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 2 to Tank 7. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 5114.09 bbls. BS&W Sample at Choke Manifold Showed 19% Water, 81% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.44 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Sparged Separator; No Solids Observed. Diverted Flow from Tank 1 to Tank 2. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 5023.7 bbl. BS&W Sample at Choke Manifold Showed 24% Water, 76% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. BS&W Sample at Choke Manifold Showed 24% Water, 76% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 21% Water, 79% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Gas Scrubber Drain Free of Fluid. Dumped DPI Unit Side A & Side B. Observed Heavy Carbolite on Side A and Light Carbolite on Side B. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 4842.86 bbls. Oil API 29.9 @ 60°F (Oil SG 0.877). H2S 0 ppm; CO2 0.1%. Gas S.G 0.714. BS&W Sample at Choke Manifold Showed 19% Water, 81% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.45 ppg. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Injection Rate into NDBi-014 @ 3.05 bpm. Total Volume Injected 4934.89 bbls. Injection Rate into NDBi-014 @ 2.99 bpm. Total Volume Injected 4753.18 bbls. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on both Sides. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 20% Water, 80% Oil and Trace Solids. Added Tank 5 and Tank 6 into NDBi-014 injection and Removed Tank 9 and Tank 10. Diverted Flow from Tank 1 to Tank 2. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Diverted Flow from Tank 1 to Tank 2. Injection Rate into NDBi-014 @ 2.99 bpm. Total Volume Injected 4662.77 bbls. Gas Scrubber Drain Free of Fluid. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 23.95% Water, 76% Oil and 0.05% Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Heavy Carbolite on Side A and Moderate Carbolite on Side B. Diverted Flow from Tank 6 to Tank 1. Injection Rate into NDBi-014 @ 2.99 bpm. Total Volume Injected 4574.48 bbls. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 19% Water, 81% Oil and Trace Solids. Diverted Flow from Tank 5 to Tank 6. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 4482.2 bbls. Dumped DPI Unit Side A & Side B. Observed Heavy Carbolite on Side A and Moderate Carbolite on Side B. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 15% Water, 85% Oil and Trace Solids. Recorded Flare Heat Index Readings. Injection Rate into NDBi-014 @ 2.97 bpm. Total Volume Injected 4391.02 bbls. Applied CMSF 0.953. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 24% Water, 76% Oil and Trace Solids. Flare Drain Free of Fluid. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 63 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 08/Nov/2024 17:15:00 08/Nov/2024 17:30:00 08/Nov/2024 17:30:00 08/Nov/2024 17:30:00 08/Nov/2024 17:31:00 08/Nov/2024 17:31:00 08/Nov/2024 17:50:00 08/Nov/2024 18:00:00 08/Nov/2024 18:00:00 08/Nov/2024 18:01:00 08/Nov/2024 18:09:00 08/Nov/2024 18:30:00 08/Nov/2024 18:31:00 08/Nov/2024 18:31:00 08/Nov/2024 18:33:00 08/Nov/2024 19:00:00 08/Nov/2024 19:00:00 08/Nov/2024 19:01:00 08/Nov/2024 19:01:00 08/Nov/2024 19:05:00 08/Nov/2024 19:11:00 08/Nov/2024 19:30:00 08/Nov/2024 19:31:00 08/Nov/2024 19:31:00 08/Nov/2024 19:31:00 08/Nov/2024 19:59:00 08/Nov/2024 20:00:00 08/Nov/2024 20:01:00 08/Nov/2024 20:30:00 08/Nov/2024 20:31:00 08/Nov/2024 20:31:00 08/Nov/2024 20:35:00 08/Nov/2024 20:59:00 08/Nov/2024 21:00:00 08/Nov/2024 21:01:00 08/Nov/2024 21:01:00 08/Nov/2024 21:01:00 08/Nov/2024 21:01:00 08/Nov/2024 21:05:00 08/Nov/2024 21:30:00 08/Nov/2024 21:30:00 08/Nov/2024 21:31:00 08/Nov/2024 21:31:00 08/Nov/2024 21:34:00 08/Nov/2024 22:00:00 08/Nov/2024 22:00:00 08/Nov/2024 22:00:00 08/Nov/2024 22:01:00 08/Nov/2024 22:01:00 08/Nov/2024 22:29:00 08/Nov/2024 22:30:00 08/Nov/2024 22:31:00 08/Nov/2024 22:31:00 08/Nov/2024 22:34:00 08/Nov/2024 23:00:00 08/Nov/2024 23:01:00 08/Nov/2024 23:02:00 08/Nov/2024 23:02:00 08/Nov/2024 23:18:00 08/Nov/2024 23:29:00 08/Nov/2024 23:30:00 Dumped DPI Unit Side A & Side B. Observed light Solids on Side A and trace Solids on Side B. Upstream DPI BS&W Sample Showed Trace Solids. Added Tank 3 and Tank 4 into NDBi-014 injection and Removed Tank 7 and Tank 8. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 6 to Tank 9. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 22% Water, 78% Oil and Trace Solids. Applied CMSF 0.920. BS&W Sample at Choke Manifold Showed 21% Water, 79% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 26% Water, 74% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed trace Carbolite on both Sides. BS&W Sample at Choke Manifold Showed 38% Water, 62% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 5 to Tank 6. Dumped DPI Unit Side A & Side B. Observed trace Solids on Side A and Light Solids on Side B. Oil API 29 @ 60°F (Oil SG 0.882). Gas S.G 0.690. H2S 0 ppm; CO2 0.1%. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 4 to Tank 5. BS&W Sample at Choke Manifold Showed 28% Water, 72% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.46 ppg. Added Tank 7 and Tank 8 into NDBi-014 injection and Removed Tank 1 and Tank 2. Dumped DPI Unit Side A & Side B. Observed trace Carbolite on both Sides. Diverted Flow from Tank 3 to Tank 4. BS&W Sample at Choke Manifold Showed 36% Water, 64% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed trace Carbolite on Side A and Light Carbolite on Side B. Diverted Flow from Tank 3 to Tank 4. BS&W Sample at Choke Manifold Showed 21% Water, 79% Oil and Trace Solids. Diverted Flow from Tank 4 to Tank 3. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed light Solids on Side A and trace Solids on Side B. Flare Drain Free of Fluid. Diverted Flow from Tank 8 to Tank 3. BS&W Sample at Choke Manifold Showed 26% Water, 74% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.47 ppg. BS&W Sample at Choke Manifold Showed 20% Water, 80% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.47 ppg. Dumped DPI Unit Side A & Side B. Observed trace Carbolite on Side A and Light Carbolite on Side B. Diverted Flow from Tank 7 to Tank 8. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 23% Water, 77% Oil and Trace Solids. Diverted Flow from Tank 7 to Tank 8. Dumped DPI Unit Side A & Side B. Observed trace Carbolite on both Sides. BS&W Sample at Choke Manifold Showed 18% Water, 82% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 8 to Tank 7. Diverted Flow from Tank 8 to Tank 7. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 5294.04 bbls. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 18% Water, 82% Oil and Trace Solids. Added Tank 1 and Tank 2 into NDBi-014 injection and Removed Tank 5 and Tank 6. Flare Drain Free of Fluid. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 64 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 08/Nov/2024 23:31:00 08/Nov/2024 23:31:00 09/Nov/2024 00:00:00 09/Nov/2024 00:01:00 09/Nov/2024 00:01:00 09/Nov/2024 00:02:00 09/Nov/2024 00:06:00 09/Nov/2024 00:07:00 09/Nov/2024 00:23:00 09/Nov/2024 00:30:00 09/Nov/2024 00:31:00 09/Nov/2024 00:31:00 09/Nov/2024 01:00:00 09/Nov/2024 01:00:00 09/Nov/2024 01:01:00 09/Nov/2024 01:01:00 09/Nov/2024 01:30:00 09/Nov/2024 01:30:00 09/Nov/2024 01:31:00 09/Nov/2024 01:31:00 09/Nov/2024 02:00:00 09/Nov/2024 02:01:00 09/Nov/2024 02:01:00 09/Nov/2024 02:30:00 09/Nov/2024 02:31:00 09/Nov/2024 02:31:00 09/Nov/2024 03:00:00 09/Nov/2024 03:00:00 09/Nov/2024 03:01:00 09/Nov/2024 03:01:00 09/Nov/2024 03:01:00 09/Nov/2024 03:02:00 09/Nov/2024 03:04:00 09/Nov/2024 03:30:00 09/Nov/2024 03:31:00 09/Nov/2024 03:31:00 09/Nov/2024 03:45:00 09/Nov/2024 03:59:00 09/Nov/2024 04:00:00 09/Nov/2024 04:01:00 09/Nov/2024 04:13:00 09/Nov/2024 04:30:00 09/Nov/2024 04:31:00 09/Nov/2024 04:31:00 09/Nov/2024 05:00:00 09/Nov/2024 05:00:00 09/Nov/2024 05:01:00 09/Nov/2024 05:01:00 09/Nov/2024 05:03:00 09/Nov/2024 05:30:00 09/Nov/2024 05:31:00 09/Nov/2024 05:31:00 09/Nov/2024 06:00:00 09/Nov/2024 06:00:00 09/Nov/2024 06:00:00 09/Nov/2024 06:01:00 09/Nov/2024 06:15:00 09/Nov/2024 06:25:00 09/Nov/2024 06:30:00 09/Nov/2024 06:30:00 09/Nov/2024 06:31:00 Added Tank 1 and Tank 2 into NDBi-014 injection and Removed Tank 9 and Tank10. Diverted Flow from Tank 8 to Tank 3. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 7605.89 bbls. Water Salinity 30,000 ppm; Water pH 8; Water Weight 8.45 ppg. Dumped DPI Unit Side A & Side B. Observed Light Carbolite on both Sides. Diverted Flow from Tank 8 to Tank 7 (15 min Flow). Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 7513.09 bbls. BS&W Sample at Choke Manifold Showed 22% Water, 78% Oil and Trace Solids. Diverted Flow from Tank 7 to Tank 8 (15 min Flow). Applied CMSF 0.929. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 24% Water, 76% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 28% Water, 72% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 30% Water, 70% Oil and Trace Solids. Added Tank 9 and Tank 10 into NDBi-014 injection and Removed Tank 5 and Tank 6. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 26% Water, 74% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Diverted Flow from Tank 8 to Tank 7. BS&W Sample at Choke Manifold Showed 22% Water, 78% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 1 to Tank 2 (15 min Flow). Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 2 to Tank 7. H2S 0 ppm; CO2 0.1%. Gas S.G 0.70. Oil API 29.4 @ 60°F (Oil SG 0.879). Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Sparged Separator; Trace Solids Observed. Diverted Flow from Tank 2 to Tank 1 (15 min Flow). Added Tank 5 and Tank 6 into NDBi-014 injection and Removed Tank 3 and Tank 4. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 24% Water, 76% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 1 to Tank 2. Injection Rate into NDBi-014 @ 3.04 bpm; Total Volume Injected 6968.36 bbls. Diverted Flow from Tank 10 to Tank 1. BS&W Sample at Choke Manifold Showed 20% Water, 80% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 27% Water, 73% Oil and Trace Solids. Diverted Flow from Tank 9 to Tank 10. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 24% Water, 76% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Upstream DPI BS&W Sample Showed Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Magtech Injection Pump Online. Diverted Flow from Tank 10 to Tank 9. BS&W Sample at Choke Manifold Showed 28% Water, 72% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 9 to Tank 10. BS&W Sample at Choke Manifold Showed 19% Water, 81% Oil and Trace Solids. Magtech Injection Pump Offline; Performing Maintenance. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Flare Drain Free of Fluid. BS&W Sample at Choke Manifold Showed 20% Water, 80% Oil and Trace Solids. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 65 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 09/Nov/2024 06:31:00 09/Nov/2024 06:31:00 09/Nov/2024 07:00:00 09/Nov/2024 07:00:00 09/Nov/2024 07:00:00 09/Nov/2024 07:00:00 09/Nov/2024 07:01:00 09/Nov/2024 07:15:00 09/Nov/2024 07:20:00 09/Nov/2024 07:25:00 09/Nov/2024 07:30:00 09/Nov/2024 07:30:00 09/Nov/2024 07:31:00 09/Nov/2024 07:31:00 09/Nov/2024 07:31:00 09/Nov/2024 07:45:00 09/Nov/2024 08:00:00 09/Nov/2024 08:00:00 09/Nov/2024 08:01:00 09/Nov/2024 08:22:00 09/Nov/2024 08:30:00 09/Nov/2024 08:31:00 09/Nov/2024 08:31:00 09/Nov/2024 08:31:00 09/Nov/2024 08:45:00 09/Nov/2024 09:00:00 09/Nov/2024 09:00:00 09/Nov/2024 09:00:00 09/Nov/2024 09:01:00 09/Nov/2024 09:01:00 09/Nov/2024 09:01:00 09/Nov/2024 09:01:00 09/Nov/2024 09:02:00 09/Nov/2024 09:20:00 09/Nov/2024 09:30:00 09/Nov/2024 09:30:00 09/Nov/2024 09:31:00 09/Nov/2024 09:31:00 09/Nov/2024 09:31:00 09/Nov/2024 09:58:00 09/Nov/2024 10:00:00 09/Nov/2024 10:00:00 09/Nov/2024 10:00:00 09/Nov/2024 10:01:00 09/Nov/2024 10:30:00 09/Nov/2024 10:30:00 09/Nov/2024 10:31:00 09/Nov/2024 10:31:00 09/Nov/2024 10:31:00 09/Nov/2024 11:00:00 09/Nov/2024 11:00:00 09/Nov/2024 11:00:00 09/Nov/2024 11:01:00 09/Nov/2024 11:15:00 09/Nov/2024 11:30:00 09/Nov/2024 11:30:00 09/Nov/2024 11:31:00 09/Nov/2024 11:31:00 09/Nov/2024 11:31:00 09/Nov/2024 12:00:00 09/Nov/2024 12:00:00 Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 10 to Tank 1. Injection Rate into NDBi-014 @ 3.19 bpm. Total Volume Injected 8549.71 bbls. BS&W Sample at Choke Manifold Showed 11% Water, 89% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 1 to Tank 2. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Trace Solids. Injection Rate into NDBi-014 @ 3.17 bpm. Total Volume Injected 8453.46 bbls. Diverted Flow from Tank 10 to Tank 9 (15 min Flow). BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Diverted Flow from Tank 9 to Tank 10 (15 min Flow). Injection Rate into NDBi-014 @ 3.19 bpm. Total Volume Injected 8263.43 bbls. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Diverted Flow from Tank 9 to Tank 10. Injection Rate into NDBi-014 @ 3.18 bpm. Total Volume Injected 8359.23 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. BS&W Sample at Choke Manifold Showed 14% Water, 86% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 15% Water, 85% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Finished transferring 250 bbls from Tank 3 and Tank 4 to Worley Truck #86092. Dumped DPI Unit Side B. Observed Light Solids. Diverted Flow from Tank 10 to Tank 9. Oil API 29.6 @ 60°F (Oil SG 0.878). Added Tank 7 and Tank 8 into NDBi-014 injection and Removed Tank 1 and Tank 2. Began transferring Tank 3 and Tank 4 to Worley Truck #86092. Diverted Flow from Tank 9 to Tank 10. Injection Rate into NDBi-014 @ 3.19 bpm. Total Volume Injected 8071.17 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Diverted Flow from Tank 4 to Tank 9. Injection Rate into NDBi-014 @ 3.19 bpm. Total Volume Injected 8071.17 bbls. BS&W Sample at Choke Manifold Showed 14% Water, 86% Oil and Trace Solids. Gas S.G 0.700. H2S 0 ppm; CO2 0.1%. BS&W Sample at Choke Manifold Showed 16% Water, 84% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.48 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 3 to Tank 4 (15 min Flow). Dumped DPI Unit Side B. Observed Light Solids. Gas Scrubber Drain Free of Fluid. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 3 to Tank 4. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Increased NDBi-014 Injection Rate to 3.2 bpm. Diverted Flow from Tank 4 to Tank 3 (15min Flow). Upstream DPI BS&W Sample Showed Trace Solids. Bypassed DPI Unit Side A. Bypassed Ball Catcher. Diverted Flow from Tank 4 to Tank 3. Injection Rate into NDBi-014 @ 3.07 bpm. Total Volume Injected 7788.50 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 14% Water, 86% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Light Carbolite on Side A and Trace Carbolite on Side B. Diverted Flow from Tank 3 to Tank 4. Injection Rate into NDBi-014 @ 3.06 bpm. Total Volume Injected 7698.18 bbls. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 16% Water, 84% Oil and Trace Solids. Flare Drain Free of Fluid. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Upstream DPI BS&W Sample Showed 0.05% Solids. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 66 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 09/Nov/2024 12:00:00 09/Nov/2024 12:01:00 09/Nov/2024 12:15:00 09/Nov/2024 12:30:00 09/Nov/2024 12:30:00 09/Nov/2024 12:31:00 09/Nov/2024 12:31:00 09/Nov/2024 12:31:00 09/Nov/2024 13:00:00 09/Nov/2024 13:00:00 09/Nov/2024 13:00:00 09/Nov/2024 13:00:00 09/Nov/2024 13:01:00 09/Nov/2024 13:30:00 09/Nov/2024 13:30:00 09/Nov/2024 13:31:00 09/Nov/2024 13:31:00 09/Nov/2024 13:45:00 09/Nov/2024 14:00:00 09/Nov/2024 14:00:00 09/Nov/2024 14:00:00 09/Nov/2024 14:01:00 09/Nov/2024 14:15:00 09/Nov/2024 14:15:00 09/Nov/2024 14:19:00 09/Nov/2024 14:30:00 09/Nov/2024 14:30:00 09/Nov/2024 14:31:00 09/Nov/2024 14:31:00 09/Nov/2024 14:31:00 09/Nov/2024 15:00:00 09/Nov/2024 15:00:00 09/Nov/2024 15:00:00 09/Nov/2024 15:01:00 09/Nov/2024 15:01:00 09/Nov/2024 15:01:00 09/Nov/2024 15:30:00 09/Nov/2024 15:30:00 09/Nov/2024 15:31:00 09/Nov/2024 15:31:00 09/Nov/2024 15:31:00 09/Nov/2024 15:45:00 09/Nov/2024 16:00:00 09/Nov/2024 16:00:00 09/Nov/2024 16:00:00 09/Nov/2024 16:01:00 09/Nov/2024 16:05:00 09/Nov/2024 16:15:00 09/Nov/2024 16:30:00 09/Nov/2024 16:30:00 09/Nov/2024 16:31:00 09/Nov/2024 16:31:00 09/Nov/2024 16:42:00 09/Nov/2024 17:00:00 09/Nov/2024 17:00:00 09/Nov/2024 17:00:00 09/Nov/2024 17:01:00 09/Nov/2024 17:06:00 09/Nov/2024 17:30:00 09/Nov/2024 17:31:00 09/Nov/2024 18:00:00 Added Tank 3 and Tank 4 into NDBi-014 injection and Removed Tank 1 and Tank 2. Diverted Flow from Tank 8 to Tank 7. BS&W Sample at Choke Manifold Showed 11% Water, 89% Oil and Trace Solids. Diverted Flow from Tank 7 to Tank 8. Sparged Separator; Trace Solids Observed. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 7 to Tank 8. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 9595.65 bbls. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Reduced NDBi-014 Injection Rate to 3.0 bpm. Diverted Flow from Tank 3 to Tank 4 (15 min Flow). Diverted Flow from Tank 4 to Tank 7. Injection Rate into NDBi-014 @ 3.01 bpm. Total Volume Injected 9507.96 bbls. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 13.95% Water, 86% Oil and 0.05% Solids. Upstream DPI BS&W Sample Showed Trace Solids. Flare Drain Free of Fluid. Dumped DPI Unit Side B. Observed Trace Solids. Injection Rate into NDBi-014 @ 3.2 bpm. Total Volume Injected 9416.30 bbls. Diverted Flow from Tank 4 to Tank 3 (15min Flow). BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Oil API 29.6 @ 60°F (Oil SG 0.878). BS&W Sample at Choke Manifold Showed 11% Water, 89% Oil and Trace Solids. Diverted Flow from Tank 3 to Tank 4. Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 9320.99 bbls. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 4 to Tank 3. Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 9225.03 bbls. H2S 0 ppm; CO2 0.1%. Flare Drain Free of Fluid. Gas Scrubber Drain Free of Fluid. Added Tank 1 and Tank 2 into NDBi-014 injection and Removed Tank 9 and Tank10. Diverted Flow from Tank 3 to Tank 4. Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 9127.49 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 13% Water, 87% Oil and Trace Solids. Diverted Flow from Tank 1 to Tank 2 (15 min Flow). Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 2 to Tank 3. Injection Rate into NDBi-014 @ 3.2 bpm. Total Volume Injected 9031.23 bbls. BS&W Sample at Choke Manifold Showed 13% Water, 87% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Light Solids. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 13% Water, 87% Oil and Trace Solids. Diverted Flow from Tank 2 to Tank 1 (15 min Flow). Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 8932.59 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. BS&W Sample at Choke Manifold Showed 11% Water, 89% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 8835.47 bbls. Diverted Flow from Tank 1 to Tank 2. Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 8646.11 bbls. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Finished transferring 250 bbls from Tank 3 and Tank 4 to Worley Truck #86057. Diverted Flow from Tank 2 to Tank 1. Injection Rate into NDBi-014 @ 3.21 bpm. Total Volume Injected 8739.66 bbls. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 67 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 09/Nov/2024 18:00:00 09/Nov/2024 18:01:00 09/Nov/2024 18:30:00 09/Nov/2024 18:31:00 09/Nov/2024 18:31:00 09/Nov/2024 18:34:00 09/Nov/2024 18:35:00 09/Nov/2024 19:00:00 09/Nov/2024 19:00:00 09/Nov/2024 19:01:00 09/Nov/2024 19:05:00 09/Nov/2024 19:30:00 09/Nov/2024 19:31:00 09/Nov/2024 19:31:00 09/Nov/2024 19:31:00 09/Nov/2024 19:52:00 09/Nov/2024 20:00:00 09/Nov/2024 20:00:00 09/Nov/2024 20:01:00 09/Nov/2024 20:30:00 09/Nov/2024 20:31:00 09/Nov/2024 21:00:00 09/Nov/2024 21:01:00 09/Nov/2024 21:01:00 09/Nov/2024 21:01:00 09/Nov/2024 21:01:00 09/Nov/2024 21:05:00 09/Nov/2024 21:15:00 09/Nov/2024 21:15:00 09/Nov/2024 21:21:00 09/Nov/2024 21:29:00 09/Nov/2024 21:30:00 09/Nov/2024 21:31:00 09/Nov/2024 21:31:00 09/Nov/2024 21:36:00 09/Nov/2024 21:44:00 09/Nov/2024 21:57:00 09/Nov/2024 21:58:00 09/Nov/2024 22:00:00 09/Nov/2024 22:01:00 09/Nov/2024 22:29:00 09/Nov/2024 22:30:00 09/Nov/2024 22:31:00 09/Nov/2024 22:31:00 09/Nov/2024 22:32:00 09/Nov/2024 23:00:00 09/Nov/2024 23:00:00 09/Nov/2024 23:01:00 09/Nov/2024 23:23:00 09/Nov/2024 23:25:00 09/Nov/2024 23:28:00 09/Nov/2024 23:30:00 09/Nov/2024 23:30:00 09/Nov/2024 23:31:00 09/Nov/2024 23:40:00 09/Nov/2024 23:59:00 10/Nov/2024 00:00:00 10/Nov/2024 00:00:00 10/Nov/2024 00:01:00 10/Nov/2024 00:20:00 10/Nov/2024 00:27:00 Magtech Injection Pump Offline; Pump Preventative Maintenance. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Magtech Injection Pump Online. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Added Tank 7 and Tank 8 into NDBi-014 injection. Dumped DPI Unit Side A & Side B. Observed Light Solids on Side A and Trace Solids on Side B. Applied CMSF 0.933. BS&W Sample at Choke Manifold Showed 16.90% Water, 83% Oil and 0.10% Solids. Added Tank 9 and Tank 10 into NDBi-014 Injection and Removed Tank 1,2,7 and Tank 8. Dumped DPI Unit Side A & Side B. Observed Light Solids on Side A and Trace Solids on Side B. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side A & Side B. Observed Light Solids on Side A and Trace Solids on Side B. Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 8.85% Water, 91% Oil and 0.15% Solids. Sparged Expro separator, Observed Trace Solids. Diverted Flow from Tank 9 to Tank 10. BS&W Sample at Choke Manifold Showed 25.8% Water, 74% Oil and 0.2% Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on Side A and Moderate Solids on Side B. Diverted Flow from Tank 10 to Tank 5. BS&W Sample at Choke Manifold Showed 19% Water, 81% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 18% Water, 82% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Added Tank 1 and Tank 2 into NDBi-014 injection and Removed Tank 7 and Tank 8. Dumped DPI Unit Side A & Side B. Observed Light Solids on Side A and Trace Solids on Side B. Observed Well Slugging. Inspected DPI unit side B. Dumped DPI Unit Side B. Observed Heavy Solids. Diverted Flow back to Side A & Side B on DPI unit. Injection Rate increased NDBi-014 @ 3.25 bpm. Dumped DPI unit side A & side B. Observed Moderate Solids on A & B. Diverted Flow from Tank 10 to Tank 9. BS&W Sample at Choke Manifold Showed 14.5% Water, 85% Oil and 0.5% Solids. Diverted Flow from Tank 9 to Tank 10. BS&W Sample at Choke Manifold Showed 19% Water, 81% Oil and Trace Solids. Oil API 29.8 @ 60°F (Oil SG 0.877). Gas S.G 0.696. H2S 0 ppm; CO2 0.1%. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 1 to Tank 2. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 18.5% Water, 81% Oil and 0.5% Solids. Diverted Flow from Tank 2 to Tank 9. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 18% Water, 82% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 26.5% Water, 73% Oil and 0.5% Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 8 to Tank 1. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. Dumped DPI Unit Side B. Observed Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 1 to Tank 2. Dumped DPI Unit Side B. Observed Trace Solids. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Added Tank 7 and Tank 8 into NDBi-014 injection and Removed Tank 3 and Tank 4. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 68 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 10/Nov/2024 00:30:00 10/Nov/2024 00:31:00 10/Nov/2024 00:31:00 10/Nov/2024 00:35:00 10/Nov/2024 00:57:00 10/Nov/2024 01:00:00 10/Nov/2024 01:00:00 10/Nov/2024 01:01:00 10/Nov/2024 01:30:00 10/Nov/2024 01:30:00 10/Nov/2024 01:31:00 10/Nov/2024 01:31:00 10/Nov/2024 01:53:00 10/Nov/2024 01:58:00 10/Nov/2024 02:00:00 10/Nov/2024 02:01:00 10/Nov/2024 02:27:00 10/Nov/2024 02:30:00 10/Nov/2024 02:31:00 10/Nov/2024 02:34:00 10/Nov/2024 03:00:00 10/Nov/2024 03:00:00 10/Nov/2024 03:01:00 10/Nov/2024 03:01:00 10/Nov/2024 03:01:00 10/Nov/2024 03:01:00 10/Nov/2024 03:02:00 10/Nov/2024 03:26:00 10/Nov/2024 03:27:00 10/Nov/2024 03:30:00 10/Nov/2024 03:31:00 10/Nov/2024 03:32:00 10/Nov/2024 03:57:00 10/Nov/2024 04:00:00 10/Nov/2024 04:01:00 10/Nov/2024 04:03:00 10/Nov/2024 04:28:00 10/Nov/2024 04:30:00 10/Nov/2024 04:31:00 10/Nov/2024 04:31:00 10/Nov/2024 04:51:00 10/Nov/2024 05:00:00 10/Nov/2024 05:01:00 10/Nov/2024 05:02:00 10/Nov/2024 05:14:00 10/Nov/2024 05:19:00 10/Nov/2024 05:28:00 10/Nov/2024 05:30:00 10/Nov/2024 05:31:00 10/Nov/2024 05:31:00 10/Nov/2024 05:32:00 10/Nov/2024 05:45:00 10/Nov/2024 06:00:00 10/Nov/2024 06:00:00 10/Nov/2024 06:00:00 10/Nov/2024 06:01:00 10/Nov/2024 06:25:00 10/Nov/2024 06:30:00 10/Nov/2024 06:30:00 10/Nov/2024 06:30:00 10/Nov/2024 06:30:00 Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 12096.75 bbls. Dumped DPI Unit Side B. Observed Moderate Carbolite. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 9 to Tank 10. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 11999.30 bbls. Bypassed DPI Unit Side A. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Gas Scrubber Drain Free of Fluid. Diverted Flow from Tank 10 to Tank 3. Added Tank 1 and Tank 2 into NDBi-014 Injection and Removed Tank 7 and Tank 8. Diverted Flow from Tank 10 to Tank 9. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted flow back to both sides A and B on DPI unit. Dumped DPI Unit Side A & Side B. Observed Moderate Carbolite on Side A and Light Carbolite on Side B. Dumped DPI Unit Side B. Observed Moderate Solids. Diverted Flow from Tank 9 to Tank 10. Dumped DPI Unit Side B. Observed Light Solids. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Moderate Solids. Diverted Flow from Tank 1 to Tank 2. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Sparged Separator; No Solids Observed. Dumped DPI Unit Side B. Observed Heavy Solids. Diverted Flow from Tank 2 to Tank 9. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Diverted Flow from Tank 2 to Tank 1. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Light Solids. Oil API 30.4 @ 60°F (Oil SG 0.874). Gas S.G 0.698. H2S 0 ppm; CO2 0.1%. Bypassed DPI Unit Side A. Flowing through DPI Side B. Added Tank 7 and Tank 8 into NDBi-014 Injection and Removed Tank 5 and Tank 6. Dumped DPI Unit Side B. Observed Trace Solids. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 1 to Tank 2. Injection Rate into NDBi-014 @ 3.24 bpm; Total Volume Injected 11415.35 bbls. BS&W Sample at Choke Manifold Showed 11% Water, 89% Oil and Trace Solids. Added Tank 5 and Tank 6 into NDBi-014 Injection and Removed Tank 9 and Tank 10. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Trace Solids on both Sides. Diverted Flow from Tank 8 to Tank 1. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Dumped DPI Unit Side A & Side B. Observed Light Solids on Side A and Trace Solids on Side B. Diverted Flow from Tank 8 to Tank 7. BS&W Sample at Choke Manifold Showed 12% Water, 88% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Flare Drain Free of Fluid. Diverted Flow from Tank 7 to Tank 8. Collected Tracerco Sample. Diverted Flow from Tank 6 to Tank 7. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.45 ppg. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 69 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 10/Nov/2024 06:31:00 10/Nov/2024 06:31:00 10/Nov/2024 07:00:00 10/Nov/2024 07:00:00 10/Nov/2024 07:00:00 10/Nov/2024 07:00:00 10/Nov/2024 07:01:00 10/Nov/2024 07:30:00 10/Nov/2024 07:30:00 10/Nov/2024 07:30:00 10/Nov/2024 07:30:00 10/Nov/2024 07:31:00 10/Nov/2024 07:31:00 10/Nov/2024 07:45:00 10/Nov/2024 08:00:00 10/Nov/2024 08:00:00 10/Nov/2024 08:00:00 10/Nov/2024 08:01:00 10/Nov/2024 08:30:00 10/Nov/2024 08:30:00 10/Nov/2024 08:30:00 10/Nov/2024 08:30:00 10/Nov/2024 08:31:00 10/Nov/2024 08:31:00 10/Nov/2024 08:45:00 10/Nov/2024 09:00:00 10/Nov/2024 09:00:00 10/Nov/2024 09:00:00 10/Nov/2024 09:01:00 10/Nov/2024 09:01:00 10/Nov/2024 09:01:00 10/Nov/2024 09:01:00 10/Nov/2024 09:30:00 10/Nov/2024 09:30:00 10/Nov/2024 09:30:00 10/Nov/2024 09:30:00 10/Nov/2024 09:31:00 10/Nov/2024 09:31:00 10/Nov/2024 10:00:00 10/Nov/2024 10:00:00 10/Nov/2024 10:00:00 10/Nov/2024 10:01:00 10/Nov/2024 10:30:00 10/Nov/2024 10:30:00 10/Nov/2024 10:30:00 10/Nov/2024 10:30:00 10/Nov/2024 10:36:00 10/Nov/2024 11:00:00 10/Nov/2024 11:00:00 10/Nov/2024 11:00:00 10/Nov/2024 11:01:00 10/Nov/2024 11:15:00 10/Nov/2024 11:30:00 10/Nov/2024 11:30:00 10/Nov/2024 11:30:00 10/Nov/2024 11:30:00 10/Nov/2024 11:31:00 10/Nov/2024 11:31:00 10/Nov/2024 12:00:00 10/Nov/2024 12:00:00 10/Nov/2024 12:00:00 Diverted Flow from Tank 7 to Tank 8. Injection Rate into NDBi-014 @ 3.23 bpm. Total Volume Injected 13168.64 bbls. Dumped DPI Unit Side B. Observed Light Carbolite. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 7 to Tank 8. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 13071.19 bbls. Upstream DPI BS&W Sample Showed Trace Carbolite. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Added Tank 3 and Tank 4 into NDBi-014 injection and Removed Tank 9 and Tank 10. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 6 to Tank 7. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 12973.84 bbls. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Flare Drain Free of Fluid. Dumped DPI Unit Side B. Observed Moderate Carbolite. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 5 to Tank 6. Upstream DPI BS&W Sample Showed Trace Carbolite. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Moderate Carbolite. Injection Rate into NDBi-014 @ 3.26 bpm. Total Volume Injected 12778.09 bbls. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Gas S.G 0.696. H2S 0 ppm; CO2 0.1%. Oil API 29.9 @ 60°F (Oil SG 0.877). Dumped DPI Unit Side B. Observed Moderate Carbolite. Injection Rate into NDBi-014 @ 3.22 bpm. Total Volume Injected 12680.15 bbls. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 3 to Tank 4 (15 min Flow). Dumped DPI Unit Side B. Observed Moderate Carbolite. Diverted Flow from Tank 4 to Tank 5. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 12582.93 bbls. Diverted Flow from Tank 4 to Tank 3 (15min Flow). Upstream DPI BS&W Sample Showed 0.25% Carbolite. Dumped DPI Unit Side B. Observed Moderate Carbolite. Injection Rate into NDBi-014 @ 3.22 bpm. Total Volume Injected 12388.53 bbls. BS&W Sample at Choke Manifold Showed 9% Water, 91% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Moderate Carbolite. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 12485.72 bbls. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Injection Rate into NDBi-014 @ 3.26 bpm. Total Volume Injected 12876.02 bbls. Diverted Flow from Tank 5 to Tank 6. Injection Rate into NDBi-014 @ 3.22 bpm. Total Volume Injected 12290.66 bbls. Upstream DPI BS&W Sample Showed Trace Carbolite. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 28,000 ppm; Water pH 8; Water Weight 8.47 ppg. Flare Drain Free of Fluid. Diverted Flow from Tank 3 to Tank 4. Dumped DPI Unit Side B. Observed Moderate Carbolite. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 12194.08 bbls. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 7.95% Water, 92% Oil and 0.05% Solids. Dumped DPI Unit Side B. Observed Moderate Carbolite. Diverted Flow from Tank 4 to Tank 3. BS&W Sample at Choke Manifold Showed 10% Water, 90% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. Diverted Flow from Tank 3 to Tank 4. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 70 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 10/Nov/2024 12:01:00 10/Nov/2024 12:02:00 10/Nov/2024 12:30:00 10/Nov/2024 12:30:00 10/Nov/2024 12:30:00 10/Nov/2024 12:30:00 10/Nov/2024 12:31:00 10/Nov/2024 12:31:00 10/Nov/2024 13:00:00 10/Nov/2024 13:00:00 10/Nov/2024 13:00:00 10/Nov/2024 13:00:00 10/Nov/2024 13:01:00 10/Nov/2024 13:15:00 10/Nov/2024 13:30:00 10/Nov/2024 13:30:00 10/Nov/2024 13:30:00 10/Nov/2024 13:30:00 10/Nov/2024 13:30:00 10/Nov/2024 13:31:00 10/Nov/2024 13:31:00 10/Nov/2024 14:00:00 10/Nov/2024 14:00:00 10/Nov/2024 14:00:00 10/Nov/2024 14:00:00 10/Nov/2024 14:00:00 10/Nov/2024 14:01:00 10/Nov/2024 14:30:00 10/Nov/2024 14:30:00 10/Nov/2024 14:30:00 10/Nov/2024 14:30:00 10/Nov/2024 14:31:00 10/Nov/2024 14:31:00 10/Nov/2024 14:38:00 10/Nov/2024 15:00:00 10/Nov/2024 15:00:00 10/Nov/2024 15:00:00 10/Nov/2024 15:01:00 10/Nov/2024 15:01:00 10/Nov/2024 15:01:00 10/Nov/2024 15:30:00 10/Nov/2024 15:30:00 10/Nov/2024 15:30:00 10/Nov/2024 15:30:00 10/Nov/2024 15:31:00 10/Nov/2024 15:31:00 10/Nov/2024 15:45:00 10/Nov/2024 16:00:00 10/Nov/2024 16:00:00 10/Nov/2024 16:00:00 10/Nov/2024 16:01:00 10/Nov/2024 16:08:00 10/Nov/2024 16:30:00 10/Nov/2024 16:30:00 10/Nov/2024 16:30:00 10/Nov/2024 16:30:00 10/Nov/2024 16:31:00 10/Nov/2024 16:31:00 10/Nov/2024 17:00:00 10/Nov/2024 17:00:00 10/Nov/2024 17:00:00 Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 14106.6 bbls. Dumped DPI Unit Side B. Observed Light Carbolite. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 14014.84 bbls. Diverted Flow from Tank 3 to Tank 4. Upstream DPI BS&W Sample Showed Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Diverted Flow from Tank 4 to Tank 3. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 2 to Tank 3. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 13926.29 bbls. BS&W Sample at Choke Manifold Showed 6% Water, 94% Oil and Trace Solids. Added Tank 7 and Tank 8 into NDBi-014 Injection and Removed Tank 5 and Tank 6. Dumped DPI Unit Side B. Observed Light Carbolite. Injection Rate into NDBi-014 @ 3.01 bpm. Total Volume Injected 13836.63 bbls. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 5% Water, 95% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Gas Scrubber Drain Free of Fluid. Injection Rate into NDBi-014 @ 3.00 bpm. Total Volume Injected 13746.25 bbls. BS&W Sample at Choke Manifold Showed 6% Water, 94% Oil and Trace Solids. H2S 0 ppm; CO2 0.1%. Oil API 29.6 @ 60°F (Oil SG 0.878). Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 1 to Tank 2. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Reduced NDBi-014 Injection Rate to 3.0 bpm. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 2 to Tank 1. Decreased Expro adjustable Choke to 52/64ths as per Santos WSS. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 1 to Tank 2. Injection Rate into NDBi-014 @ 3.23 bpm. Total Volume Injected 13654.13 bbls. Upstream DPI BS&W Sample Showed Trace Carbolite. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Recorded Flare Heat Index Readings. Diverted Flow from Tank 2 to Tank 1. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 13555.45 bbls. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Added Tank 5 and Tank 6 into NDBi-014 injection and Removed Tank 3 and Tank 4. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 1 to Tank 2. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 8 to Tank 1. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 13357.82 bbls. Collected Tracerco Sample. Dumped DPI Unit Side B. Observed Light Carbolite. Injection Rate into NDBi-014 @ 3.25 bpm. Total Volume Injected 13456.69 bbls. Upstream DPI BS&W Sample Showed Trace Carbolite. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Sparged Separator; Trace Solids Observed. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 7 to Tank 8. Injection Rate into NDBi-014 @ 3.24 bpm. Total Volume Injected 13262.61 bbls. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 71 Customer: Field: Location: Well Name: Start Date: End Date: DATE / TIME dd/mmm/yyyy hh:mm:ss OPERATIONS SEQUENCE OF Pikka Development NDB NDBi-016 6-Nov-24 11-Nov-24 10/Nov/2024 17:01:00 10/Nov/2024 17:15:00 10/Nov/2024 17:30:00 10/Nov/2024 17:30:00 10/Nov/2024 17:30:00 10/Nov/2024 17:31:00 10/Nov/2024 17:31:00 10/Nov/2024 18:00:00 10/Nov/2024 18:01:00 10/Nov/2024 18:03:00 10/Nov/2024 18:29:00 10/Nov/2024 18:30:00 10/Nov/2024 18:31:00 10/Nov/2024 18:31:00 10/Nov/2024 18:35:00 10/Nov/2024 18:55:00 10/Nov/2024 18:57:00 10/Nov/2024 19:00:00 10/Nov/2024 19:00:00 10/Nov/2024 19:00:00 10/Nov/2024 19:01:00 10/Nov/2024 19:28:00 10/Nov/2024 19:30:00 10/Nov/2024 19:31:00 10/Nov/2024 19:35:00 10/Nov/2024 19:58:00 10/Nov/2024 20:00:00 10/Nov/2024 20:01:00 10/Nov/2024 20:30:00 10/Nov/2024 20:31:00 10/Nov/2024 20:31:00 10/Nov/2024 20:31:00 10/Nov/2024 20:56:00 10/Nov/2024 21:00:00 10/Nov/2024 21:01:00 10/Nov/2024 21:01:00 10/Nov/2024 21:01:00 10/Nov/2024 21:01:00 10/Nov/2024 21:30:00 10/Nov/2024 21:31:00 10/Nov/2024 21:34:00 10/Nov/2024 21:52:00 10/Nov/2024 21:58:00 10/Nov/2024 22:00:00 10/Nov/2024 22:01:00 10/Nov/2024 22:30:00 10/Nov/2024 22:31:00 10/Nov/2024 22:31:00 10/Nov/2024 22:31:00 10/Nov/2024 22:57:00 10/Nov/2024 23:00:00 10/Nov/2024 23:01:00 10/Nov/2024 23:30:00 10/Nov/2024 23:31:00 10/Nov/2024 23:31:00 10/Nov/2024 23:31:00 10/Nov/2024 23:55:00 11/Nov/2024 00:00:00 11/Nov/2024 00:00:00 11/Nov/2024 00:01:00 11/Nov/2024 00:02:00 Closed Wellhead Master Valve (23.5 turns). Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Trace Solids. NDBi-016 Shut-in at Choke Manifold. Injection Rate into NDBi-014 @ 3.0 bpm; Total Injection Volume 15368.26 bbls. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 8 to Tank 7. BS&W Sample at Choke Manifold Showed 3% Water, 97% Oil and Trace Solids. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 4% Water, 96% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Trace Solids. Diverted Flow from Tank 6 to Tank 7. BS&W Sample at Choke Manifold Showed 3% Water, 97% Oil and Trace Solids. Diverted Flow from Tank 7 to Tank 8. BS&W Sample at Choke Manifold Showed 3% Water, 97% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. H2S 0 ppm; CO2 0.1%. Oil API 29.9 @ 60°F (Oil SG 0.877). Diverted Flow from Tank 5 to Tank 6. BS&W Sample at Choke Manifold Showed 4% Water, 96% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Added Tank 3 and Tank 4 into NDBi-014 Injection and Removed Tank 1 and Tank 2. Upstream DPI BS&W Sample Showed Trace Solids. BS&W Sample at Choke Manifold Showed 5% Water, 95% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 4% Water, 96% Oil and Trace Solids. BS&W Sample at Choke Manifold Showed 4% Water, 96% Oil and Trace Solids. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Trace Carbolite. Diverted Flow from Tank 6 to Tank 5. BS&W Sample at Choke Manifold Showed 4% Water, 96% Oil and Trace Solids. Diverted Flow from Tank 5 to Tank 6. Gas S.G 0.698. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.47 ppg. Added Tank 1 and Tank 2 into NDBi-014 Injection and Removed Tank 7 and Tank 8. Decreased Expro adjustable Choke to 44/64ths as per Santos WSS. Diverted Flow from Tank 4 to Tank 5. Collected Tracerco Sample. BS&W Sample at Choke Manifold Showed 6% Water, 94% Oil and Trace Solids. Diverted Flow from Tank 5 to Tank 6. Dumped DPI Unit Side B. Observed Trace Carbolite. Diverted Flow from Tank 3 to Tank 4. BS&W Sample at Choke Manifold Showed 7% Water, 93% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.48 ppg. Upstream DPI BS&W Sample Showed Trace Solids. Dumped DPI Unit Side B. Observed Trace Carbolite. Injection Rate into NDBi-014 @ 3.02 bpm. Total Volume Injected 14196.83 bbls. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Water Salinity 29,000 ppm; Water pH 8; Water Weight 8.46 ppg. Diverted Flow from Tank 4 to Tank 3. BS&W Sample at Choke Manifold Showed 6% Water, 94% Oil and Trace Solids. Dumped DPI Unit Side B. Observed Trace Carbolite. Dumped DPI Unit Side B. Observed Trace Carbolite. BS&W Sample at Choke Manifold Showed 8% Water, 92% Oil and Trace Solids. Flare Drain Free of Fluid. Dumped DPI Unit Side B. Observed Light Carbolite. Diverted Flow from Tank 3 to Tank 4. Discontinued all Chemical Injections. WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 72 Santos Pikka Development NDBi-016 SECTION 12 COMBINED METER & SHRINKAGE FACTOR (CMSF) WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 73 Combined Meter & Shrinkage FactorClient: Well No:Field: Test:MF # Date Time Choke Tank TankT Tank vcf Corrected dTank Meter Meter Counts dMeter CMSFCMSF Applied64ths bbls °F @ 60°F Volume bbls bbls bblsTimeStart23:00 208.06 50.5 1.005209.05162.97Finish23:30 276.67 55.2 1.002277.33236.18Applied 23:30Start15:30 192.99 67.0 0.997192.312567.40Finish16:00 289.49 70.0 0.995288.042669.07Applied 16:00Start19:00 24.12 65.0 0.99824.063279.55Finish19:30 116.85 69.0 0.996116.323421.51Applied 19:00Start19:30 39.20 67.0 0.99739.063421.51Finish20:00 122.88 69.7 0.995122.283512.52Applied 19:30Start21:30 49.75 65.0 0.99849.633801.77Finish22:00 138.71 68.0 0.996138.163896.07Applied 22:00Start12:00 121.37 67.9 0.996120.896727.46Finish12:30 210.33 68.8 0.996209.406820.37Applied 12:30Start21:30 43.72 65.0 0.99843.618517.49Finish22:00 140.22 67.0 0.997139.738621.96Applied 22:00Start4:30 37.69 65.0 0.99837.609973.39Finish5:00 134.94 66.0 0.997134.5410077.78Applied 05:00Start7:30 122.88 63.9 0.998122.6410599.32Finish8:00 228.42 65.1 0.997227.8410712.22Applied 08:00Start23:00 34.68 64.0 0.99834.6114049.77Finish23:30 131.17 66.2 0.997130.7614152.78Applied 23:30Note:Santos NDBi-016PIKKA DevelopmentWell Clean-UpTank Readings Test Separator1 6-Nov-24 6468.292"73.210.9332 7-Nov-24 12895.732"101.670.9420.95350.6504 7-Nov-24 12883.222"91.010.9143 7-Nov-24 12892.262"141.968-Nov-24 12888.512"92.910.9390.9208 9-Nov-24 12896.942"104.390.9297 8-Nov-24 12896.122"104.4767-Nov-24 12888.532"94.300.9331. Tank corrected volume = tank reading x VCF2. CMSF = delta volume tank / delta meter10 9-Nov-24 12896.152"103.01112.900.9489 9-Nov-24 128107.052"WT-XAK-0127.4_NDBi-016_Rev Awww.expro.com Page 74 Santos Pikka Development NDBi-016 SECTION 13 DIAGRAMS WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 75 Santos Pikka Development NDBi-016 P&ID Process & Instrumentation Diagram WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 76 PIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITORUNCONTROLLED COPY UNCONTROLLED COPYPIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITOR UNCONTROLLED COPYPIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITOR PIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITORUNCONTROLLED COPY PIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITORUNCONTROLLED COPY PIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITORUNCONTROLLED COPY PIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITORUNCONTROLLED COPY PIPEWORK IDENTIFICATIONREF MAWP REF DESCRIPTION115,000 PSIGFF FLUID FLOW210,000 PSIGOF OIL FLOW37,500 PSIGGF GAS FLOW45,000 PSIGWF WATER FLOW52,000 PSIGDF DIESEL FLOW61,440 PSIGSH STEAM FLOW71,000 PSIGV VENT LINE8 285 PSIG RF RELIEF LINE9250 PSIG CI CHEM. INJECTION10 125 PSIG A PIPE11 150 PSIG B HOSEABBREVIATIONSSYM DESCRIPTION SYM DESCRIPTIONBP BLEED PORT N.C. NORMALLY CLOSEDBPV BACK PRESSURE VALVE N.O. NORMALLY OPENEDCI CHEMICAL INJECTION PI PRESSURE INDICATORDP DIFFERENTIAL PRESSURE PIC PRESSURE CONTROLLERDPT DIFF. PRESS. TRANSDUCER PIT PRESSURE TRANSDUCERCC CORROSION COUPON PR PRESSURE RECORDERF.C. FAIL SAFE CLOSED PSE RUPTURE DISCFM FLOW METER PSH HIGH PRESSURE PILOTF.O. FAIL SAFE OPEN PSL LOW PRESSURE PILOTFRT FLOW METER TRANSDUCER PSV PRESSURE SAFETY VALVEFSV FLOW CHECK VALVE SDT SAND DETECTIONLC LEVEL CONTROLLER SDVSHUTDOWN VALVE (ESD)LCV LEVEL CONTROL VALVE SP SAMPLE POINTLG LEVEL GAUGE TI TEMPERATURE INDICATORLSH LEVEL SAFETY HIGH TIT TEMP. TRANSDUCERLSL LEVEL SAFETY LOW TSE TEMPERATIRE SAFETY ELEMENTAUTHORDATEREVMAXIMUM FLOWING PARAMETERSAS PER CLIENT QUESTIONAIREPHASE RATE SGOILGASWATERCITHP (PSIG)EXPECTED FTHP (PSIG)FTHT (deg F)MAXIMUM TUBING TEST PRESSURE(PSIG)CO2 (%)H2S (PPM)OFPAGEREVISION HISTORYDATE REV # REASON FOR ISSUE BY CHK APRV9/17/2024 A ADDITIONAL STORAGE TANKS & UTILIZE HP HEADER SO AS RM10/21/2024 BMOVE HP TEST HEADER TIE-IN TO VALVE HPPV-05 NEARWELL NDBi-019SO RI RM11/16/2024 C ADDED NDBi-030 INJECTION WELL SO AS RMDRAWING NUMBERTEMPORARY PIPEWORK TEMPERATURECONSTRAINTSCOFLEXIP HOSE -4F TO +266FHAMMER UNION PIPEWORK -20F TO +250FHUBBED PIPEWORK -20F TO +350FSYM DESCRIPTIONSYM DESCRIPTION SYM DESCRIPTIONPNEUMATIC LINEHYDRAULIC LINESTRAIGHTENINGREGULATORROXAR SAM ACOUSTICFLAME ARRESTORFLOW CHECKVANESVALVECONTROL VALVEOPEN CLOSEDCLAMP CONNECTIONAIR SUPPLYSAFETY VALVERUPTURE DISCCONNECTIONFLANGEVALVESAFETY VALVEFIXED CHOKEADJ. CHOKEHAMMER UNIONSWAGEVALVECHOKE INLINEDEVICE SYMBOLSSAND MONITORUNCONTROLLED COPY Santos Pikka Development NDBi-016 SAFE CHART Safety Analysis Function Evaluation Chart WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 85 A A SO AS RM REV CREATE CHECK APPROVE 1 1 1 1 1 1 FSV 102A 1 1 1 1 1 1 FSV 102A 1 1 PSL 002 PSHH 003 1 1 1 1 1 1 PSV 003 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 PSE 102 1 1 1 1 1 1 1 1 1 PSE 103 1 1 1 1 LSH 102 FSV (GAS) DIESEL FIRED LINE HEATER BAP 101 PSV A.10c.6 PSH FLOWLINE CHOKE MANIFOLD TO HEATER FAQ 002 FSV A.1d.2 PSH A.1a.2 PSL 002 PSV A.1c.2 FLOWLINE WELL HEAD TO CHOKE MANIFOLD FAQ 001 DATE DESCRIPTION A.1c.2 FSV A.1d.2 A.1a.2 PSL 001 PSH PSV SDVSDVADDITIONAL STORAGE TANKS & TRANSFER PUMP CHANGE DESCRIPTION ALT. DEVICE IF APPLICABLESAC. REF. NO.IDENTIFICATION ALTERNATIVE PROTECTION SHUTDOWN ORCONTROL DEVICE I.D.WT-XAK-80127.4 SAFETY ANALYSIS FUNCTION EVALUATION (S.A.F.E.) CHART Santos - Pikka Development - Well Clean-Up Campaign RevisionDocument No. Project 9/17/2024 FUNCTIONPERFORMEDESDDEVICE I.D. PROCESS COMPONENT 12SHUT IN EXPRO / WELLSHUT IN EXPRO / WELLSHUTDOWN HEATER DAQ VISUAL ALARMLOCAL ALARMDAQ AUDIBLE ALARMPRESSURE RELIEFMINIMIZE BACKFLOWVACUUM / PRESS. RELIEF VENT101 LSH A.5c.2 VENT SHELL 101 A.10a.4 PSL 101 PSV A.10c.4 A.10a.2 PSL A.10b.3 102 PSV LSL (H2O) A.4e.2 LSL (OIL) A.4e.2 FSV (H2O)102D FSV (OIL)102B, 102C 102E FLOWLINE HEATER TO HP HORIZONTAL SEPARATOR FAQ 003 PSH 003 PSL 101 PSV 003 FSV 102A HP HORIZONTAL TEST SEPARATOR MBD GAS SCRUBBER MBF 103 PSH A.4a.5 PSL A.4b.4 PSV A.4c.6 LSHH 103 LSL A.4e.2 A.4f.2FSV (GAS) PSH 102 LSHH 102 PSHH 102 102 PSL 102 D/S 2,000 PSI COILS LSL A.5d.2 TSH PSH A.5e.3 U/S 5,000 PSI COILS VPSV WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 86 A A SO AS RM REV CREATE CHECK APPROVE Q DATE DESCRIPTION SDVSDVADDITIONAL STORAGE TANKS & TRANSFER PUMP CHANGE DESCRIPTION ALT. DEVICE IF APPLICABLESAC. REF. NO.IDENTIFICATION ALTERNATIVE PROTECTION SHUTDOWN ORCONTROL DEVICE I.D.WT-XAK-80127.4 SAFETY ANALYSIS FUNCTION EVALUATION (S.A.F.E.) CHART Santos - Pikka Development - Well Clean-Up Campaign RevisionDocument No. Project 9/17/2024 FUNCTIONPERFORMEDESDDEVICE I.D. PROCESS COMPONENT 12SHUT IN EXPRO / WELLSHUT IN EXPRO / WELLSHUTDOWN HEATER DAQ VISUAL ALARMLOCAL ALARMDAQ AUDIBLE ALARMPRESSURE RELIEFMINIMIZE BACKFLOWVACUUM / PRESS. RELIEF VENT1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 105A, 105B POSITIVE DISP. CHEMICAL PUMP PBA 105 106 PSH A.7b.4 PSL A.7d.4 PSV 105, 106 FSV 106A, 106B FSV 367 BBL ATMOSPHERIC TANK (INJECTION TANK FARM TANK 1 - TANK 10) *Note 1 BBJ 801 802 803 804 805 806 807 808 809 810 VENT 801, 802, 803, 804, 805, 806, 807, 808, 809, 810 VPSV 801, 802, 803, 804, 805, 806, 807, 808, 809, 810 LSH A.5c.2 LSL A.5d.3 367 BBL ATMOSPHERIC DIESEL TANK (WELL TEST BERM TANK D) *Note 1 BBJ 811 VENT 811 VPSV 811 LSH A.5c.2 LSL A.5d.3 400 BBL SAND / DRAIN TANK AND RELIEF TANK ABJ 401 402 VENT 401, 402 VPSV A.5b.2 LSH A.5c.2 LSL A.5d.4 MANUAL ESD PULL STATION EMERGENCY SHUT DOWN Notes: 1. Fill operations for Atmospheric Tanks (BBJ-801 through BBJ-816) is continously operated and manned. POSITIVE DISP. CHEMICAL PUMP PBA 109 110 111 PSH A.7b.4 PSL A.7d.4 PSV 109, 110, 111 FSV 109A, 110A, 111A FSV 109B, 110B, 111B 400/367 BBL ATMOSPHERIC TANK (STORAGE TANK FARM S1 - S5) *Note 1 BBJ 812 813 814 815 816 VENT 812, 813, 814, 815, 816 VPSV 812, 813, 814, 815, 816 LSH A.5c.2 LSL A.5d.3 TRANSFER PUMP (WELL TEST TANK FARM) PBA 112 PSH A.7b.5 PSL A.7d.5 PSV 112 FSV 112 WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 87 Santos Pikka Development NDBi-016 GAD General Arrangement Drawing WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 88 UNCONTROLLED COPY UNCONTROLLED COPY UNCONTROLLED COPY Santos Pikka Development NDBi-016 PFD Process Flow Diagram WT-XAK-0127.4_NDBi-016_Rev A www.expro.com Page 92 4-1/16" 10K PSISSVESD PanelAir SupplyShut Down SignalESD Stations LoopESD Pilots LoopOil to Diverter ManifoldZZZ-110Indirect Fired Line Heater BAP-1015K/2K PSISP-101AArctic Mobile Well Test Trailer10K PSI Choke Manifold3" 150210K PSI Data HeaderFrom Well Head Connection 4-1/16 5K DSA ToExpro 4-1/16 10K3" 150210K PSI Data Header400 BBL Atmospheric Tank Sand / Relief TankABJ-401Defoamer Chemical InjectionPBA-110DemulsifierChemical InjectionPBA-1091,440 PSI Gas ScrubberMBF-103Bleed Trailer100' Flare StackPropane TanksRemote Ignition Panel10K PSI Ball CatcherSP-001BSP-001CSP-001ACI 106CI1053" 1502 10K PSI Data Header1,440 PSI HP SeparatorMBD-102Sample Ports (SP): SP-103A Oil API (Anton Paar)SP-103B Oil Sampling (TracerCo)SP-103C Oil Sampling for LabAnalysis 100mL After 1 Day ofCrude to SurfaceSP-105 H2S Sampling (Gastec)SP-106A CO2 Sampling (Gastec)SP-106B Gas SG (Ranarex)SP-103ASP-105SP-106ASP-106BSP-103BSample Ports (SP): SP-001A BS&W samplingwith few drops of EBSP-001B BS&W samplingwithout few drops of EBSP-001C Sample pull in1000mL Nalgene Bottle STEAM LINEWATER LINESTEAM LINEWATER LINEAB C D1234AB C D1234AB C D1234AB C D1234LEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINELEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINEWELL TESTINGPROCESS & FLOW DIAGRAMPage 01 of 04Santos Pikka NDB Well Clean-Up CampaignNameChristopher CarterRyan Mcmaster Sharon OyaoDate8/19/20248/20/2024Prep.Rev.APP. WT-XAK-30127.3_Rev E8/20/2024IDUNCONTROLLED COPYUNCONTROLLED COPY10K PSI Choke Manifold3" 150210K PSI Data HeaderTo Atmospheric TankSand/Relief Tank ABJ-40210K PSI CyFl Desander/Filter Dual Pod Single Skid MAJ-104Diaphragm PumpMethanol (MeOH) Chemical Injection PBA-105**Contingency**H2S Scavenger Chemical InjectionPBA-1114" FIG 1502Demulsifier Chemical Injection PBA-106(Contingency)Sample Ports (SP):SP-101A Choke BS&W (Adj.Side) with few drops of EBSP-101B Water pH UsingStripsSP-101C Water Salinity viaRefractometerSP-101D Water Sampling(TracerCo)SP-101E Water for LabAnalysis; 3x 1L Nalgen forlast 12 Hours of FlowSP-101BSP-101CSP-101DSP-101ESP-103CFlare Low Test Header Cold VentSTEAM LINEWATER LINESTEAM LINEWATER LINEAB C D1234AB C D1234AB C D1234AB C D1234LEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINELEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINEWELL TESTINGPROCESS & FLOW DIAGRAMPage 02 of 04Santos Pikka NDB Well Clean-Up CampaignNameChristopher CarterRyan Mcmaster Sharon OyaoDate8/19/20248/20/2024Prep.Rev.APP. WT-XAK-30127.3_Rev E8/20/2024IDUNCONTROLLED COPYUNCONTROLLED COPY``From Diesel Vac Truck400 BBL Atmospheric TankSand/Drain and Relief TankABJ-402367 BBL Atmospheric Tank Tank DDiesel StorageBBJ-811To Diverter Manifold ZZZ-112From Separator / Scrubber WELL TESTINGPROCESS & FLOW DIAGRAMPage 04 of 04Santos Pikka Development NDB-024 WellNameSharon OyaoDateRev A_DR 02Prep.Rev.APP. WT-XAK-30127.2_Rev A_DR 02ID STEAM LINEWATER LINESTEAM LINEWATER LINEAB C D1234AB C D1234AB C D1234AB C D1234LEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINELEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINEWELL TESTINGPROCESS & FLOW DIAGRAMPage 03 of 04Santos Pikka NDB Well Clean-Up CampaignNameChristopher CarterRyan Mcmaster Sharon OyaoDate8/19/20248/20/2024Prep.Rev.APP. WT-XAK-30127.3_Rev E8/20/2024IDT1 - 367 BBL Atmospheric TankBBJ-801T2 - 367 BBL Atmospheric Tank BBJ-802T3 - 367 BBL Atmospheric TankBBJ-803T4 - 367 BBL Atmospheric TankBBJ-804T5 - 367 BBL Atmospheric Tank BBJ-805Diverter Manifold 1 InletZZZ-110Cold VentCold VentCold VentCold VentCold VentUNCONTROLLED COPYUNCONTROLLED COPYTo Diverter Manifold ZZZ-112To Diverter Manifold ZZZ-111From Separator STEAM LINEWATER LINESTEAM LINEWATER LINEAB C D1234AB C D1234AB C D1234AB C D1234LEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINELEGENDITEMDESCRIPTIONWELL EFFLUENTOIL LINEGAS LINERELIEF LINEAIR LINEHYDRAULIC LINECHEMICAL LINEWELL TESTINGPROCESS & FLOW DIAGRAMPage 04 of 04Santos Pikka NDB Well Clean-Up CampaignNameChristopher CarterRyan Mcmaster Sharon OyaoDate8/19/20248/20/2024Prep.Rev.APP. WT-XAK-30127.3_Rev E8/20/2024IDUNCONTROLLED COPYUNCONTROLLED COPY T6 - 367 BBL Atmospheric TankBBJ-806T7 - 367 BBL Atmospheric Tank BBJ-807T8 - 367 BBL Atmospheric TankBBJ-808T9 - 367 BBL Atmospheric TankBBJ-809T10 - 367 BBL Atmospheric Tank BBJ-810Diverter Manifold 2 Inlet ZZZ-111Cold VentCold VentCold VentCold VentCold VentFromDiverter Manifold 1 InletZZZ-110From A-TanksBBJ-801BBJ-802BBJ-803BBJ-804BBJ-805Diverter Manifold 1 -Suction ZZZ-112Diverter Manifold 2 -Suction ZZZ-113To TTLA / Vac Truck 1To TTLA / Vac Truck 2FromDiesel TankBBJ-811Disposal Injection Pump 1LRS Triplex Magtec Transfer Pump & Filtration UnitFilter PodsTo Injection Well NDBi-014 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-016 (50-103-20892-0000) 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: 10/16/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Gavin Gluyas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 224-105 T39676 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.21 08:54:34 -08'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDBi-016 Definitive Compass Survey Report - NAD27.pdf ؒ NDBi-016 Definitive Compass Survey Report - NAD83.pdf ؒ NDBi-016 Definitive Survey - NAD27.txt ؒ NDBi-016 Definitive Survey - NAD83.txt ؒ NDBi-016 Definitive Survey Report.xlsx ؒ NDBi-016 Plan View .pdf ؒ NDBi-016 Vertical Section .pdf ؒ جؐؐؐLog Digital Data and Plots (LWD) ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐAP ؒ ؒ ؒ NDBi-016_AP_R01_RM.las ؒ ؒ ؒ NDBi-016_AP_R02_RM.las ؒ ؒ ؒ NDBi-016_AP_R03_RM.las ؒ ؒ ؒ NDBi-016_AP_R04_RM.las ؒ ؒ ؒ ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-016_DMD_RM_18652ft.las ؒ ؒ NDBi-016_DMT_R01_RM.las ؒ ؒ NDBi-016_DMT_R02_RM.las ؒ ؒ NDBi-016_DMT_R03_RM.las ؒ ؒ NDBi-016_DMT_R04_RM.las ؒ ؒ ؒ جؐؐؐGeoscience deliverables ؒ ؒ جؐؐؐImageTrak-Acoustic image ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft.dlis ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_200MD.cgm ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_200MD.meta ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_200MD.PDF ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_240MD.cgm ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_240MD.meta ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_240MD.PDF ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_40MD.cgm ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_40MD.meta ؒ ؒ ؒ NDBi-016_LWD_R03_PROCESSED_ITK_IMAGE_12860_18652ft_40MD.PDF ؒ ؒ ؒ ؒ ؒ ؤؐؐؐSoundTrak- Acoustic Data ؒ ؒ جؐؐؐCBL LETTER OF TRANSMITTAL ؒ ؒ ؒ NDBi-016_9_625_Liner_Baker_Hughes_CBL_Final Report.pdf ؒ ؒ ؒ NDBi-016_LWD_SDTK_CBL_8506_12850.las ؒ ؒ ؒ NDBi-016_LWD_SDTK_CBL_8506_12856.cgm ؒ ؒ ؒ NDBi-016_LWD_SDTK_CBL_8506_12856.dlis ؒ ؒ ؒ NDBi-016_LWD_SDTK_CBL_8506_12856.PDF ؒ ؒ ؒ NDBi-016_LWD_SDTK_CBL_8506_12856_dlis.txt ؒ ؒ ؒ ؒ ؒ ؤؐؐؐTOC ؒ ؒ NDBi-016_LWD_SDTK_TOC_8506_12856.cgm ؒ ؒ NDBi-016_LWD_SDTK_TOC_8506_12856.dlis ؒ ؒ NDBi-016_LWD_SDTK_TOC_8506_12856.las ؒ ؒ NDBi-016_LWD_SDTK_TOC_8506_12856.PDF ؒ ؒ NDBi-016_LWD_SDTK_TOC_8506_12856_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphic Images ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_2MD.cgm ؒ ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_2TVD.cgm ؒ ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_5MD.cgm ؒ ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_5TVD.cgm ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-016_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-016_DMD_RM_18652ft.cgm ؒ ؒ NDBi-016_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_2MD.pdf ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_2TVD.pdf ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_5MD.pdf ؒ ؒ NDBi-016_LWD_GR_Res_Den_Neu_Cal_RM_18652ft_5TVD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDBi-016_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDBi-016_DMD_RM_18652ft.pdf ؒ NDBi-016_DMT_RM.pdf LETTER OF TRANSMITTAL ؒ ؤؐؐؐMudlog NoMudlogServices.txt 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Well Cleanup 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?NDBi-016 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): 18,625' 4,092' 18,030' 4,122' N/A N/A Casing Collapse Conductor Surface 2260 Intermediate 4750 Tie-Back 4750 Production 9210 Liner 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone: 907-330-4595 Authorized Title: Completions Specialist Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): See attached packer report Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 393016, 393020, 391455, 393018, 393010 224-105 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20892-00-00 Oil Search Alaska, LLC Length Size Proposed Pools: 128' 128' P-110S TVD Burst 12,700' 11590 MD 6870 5020 6870 2,375' 4,065' 2,302' 2,759' 12,855' 4,041'4-1/2" 128' 20"x34" 13-3/8" 9-5/8" 2,759' Tieback2,609' 10,206' 12,700 Perforation Depth MD (ft): 2,609' 12,700' 4-1/2" 10/5/24 18,030'5,203' 4-1/2" 12.6ppf 4,122' See attached packer report m ns 2 6 5 6 tc N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 09/26/2024 324-556 By Grace Christianson at 3:57 pm, Sep 26, 2024 Fracture Stimulate 10/5/24 SFD 10/14/2024 CDW 10/08/2024 DSR-9/27/24 10-404 BJM 10/14/24JLC 10/14/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.15 03:18:13 -08'00'10/15/24 RBDMS JSB 101524 Page 1 of 1 Packer Set Depths - NDBi-016 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole SLZXP Liner Top Hanger Packer w/centralizer 12,690.2 4,039.8 Original Hole HES Zoneguard OH Packer #15 13,040.0 4,094.6 Original Hole HES Zoneguard OH Packer #14 13,107.6 4,104.5 Original Hole HES Zoneguard OH Packer #13 13,487.0 4,126.8 Original Hole HES Zoneguard OH Packer #12 13,989.2 4,127.2 Original Hole HES Zoneguard OH Packer #11 14,531.3 4,127.0 Original Hole HES Zoneguard OH Packer #10 14,990.1 4,127.8 Original Hole HES Zoneguard OH Packer #9 15,409.1 4,122.2 Original Hole HES Zoneguard OH Packer #8 15,517.8 4,122.1 Original Hole HES Zoneguard OH Packer #7 15,749.1 4,122.2 Original Hole HES Zoneguard OH Packer #6 15,856.0 4,122.2 Original Hole HES Zoneguard OH Packer #5 16,272.5 4,122.1 Original Hole HES Zoneguard OH Packer #4 16,894.0 4,122.0 Original Hole HES Zoneguard OH Packer #3 17,395.4 4,122.0 Original Hole HES Zoneguard OH Packer #2 17,730.2 4,121.9 Original Hole HES Zoneguard OH Packer #1 17,838.3 4,121.9 12,690.2 13,040.0 Page 1 of 20 NDBi-016 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachment B 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBDi-016. At the NDBi-016 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 NDBi-016 location. 4. Plan for freshwater sampling – There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information – Attachment C 6. Assessment of casing and cementing operations – Attachment C 7. Casing and tubing pressure test information – Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachments D and I 9. Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 978 feet (ft) total vertical depth subsea (TVDSS)/ 978 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: 978 to 2,370 ft TVDSS/1,392 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: 2,370 to 3,049 ft TVDSS/ 679 ft thick Hydrocarbon Zone: 2,430 to 3,049 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,049 to 3,722 ft TVDSS/ 673 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: 3,772 to 4,726 ft TVDSS/ 954 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Lower Confining Zone Name: Torok Formation Depth/Thickness: 4,726 to 5,625 ft TVDSS/899 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is composed primarily of shale (Hue Shale) with some thin interbedded siltstones. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. 10.Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) MAWP (psi) Stages 1-9 3,800 4,000 8,500 8,000 9,000 8,900 Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft 11.Mechanical condition of wells transecting the confining zones –NDB-024, NDB- 032, and NDBi-018, are within 1/2-mile radius of NDBi-016. Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones. Please see Attachment B Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 17,619 4,122 205 406 40 6,930 10 2 17,119 4,122 222 371 40 6,736 10 3 16,536 4,122 244 282 40 6,537 10 4 15,998 4,122 244 289 40 6,312 10 5 15,256 4,122 227 331 40 6,044 10 6 14,837 4,128 227 323 40 5,920 10 7 14,256 4,127 233 307 40 5,673 10 8 13,754 4,127 233 301 40 5,484 10 9 13,251 4,119 243 270 40 5,390 10 Fractures are estimated to propagate along wellbore longitudinally at ~330o. 6,930 13.Detailed proposed fracturing program –Attachments F & K 14.Well Clean Up procedure –Attachment G Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment H Section (d) Pressure Relieve Valve –Attachment I Proposed Wellbore Schematic –Attachment J Attachment A Oil Search (Alaska), LLC a subsidiary of Santos Limited 900 E. Benson Blvd Anchorage, Alaska 99508 PO Box 240927 Anchorage, Alaska 99524 (T) +1 907 375 4642 — santos.com 1/2 September 25, 2024 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLC’s Sundry Application for a Fracture Stimulation for the Proposed NDBi-016 Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDBi-016 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC PO Box 240927 Anchorage, AK 99524 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDBi-016 well trajectory and fracture stimulation. Please contact me should you require additional information. Sincerely, Tim Jones Land Manager Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL PO Box 240927 Anchorage, AK 99524 Repsol E&P USA LLC CERTIFIED MAIL Attn: Jeremy McKee 2455 Technology Forest Blvd. The Woodlands, TX 77381 ADL 392984 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393019 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393018 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 29.67% DNR - 70.33% ADL 393020 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393015 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 31.69% DNR - 68.31% ADL 393016 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 393007 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 34.35% DNR - 65.65% ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% ADL 393011 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 25.71% DNR - 74.29% ADL 393010 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 38.54% DNR - 61.46% U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N006E28 U012N006E20 U012N006E21 U012N006E31 U011N006E06 U012N006E19 U012N006E30 NDBi-016 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD .5-MILE BUFFER TARGET BOTTOM HOLE SURFACE LOCATION WELL TRAJECTORY LEASES BOUNDARY TOWNSHIP SECTION DATE: 8/19/2024. REV: 1.0. By: JB 0 1,000 2,000 Feet Document name: AP-DRL-GEN_assorted GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 200 400 Meters PIKKA DEVELOPMENT NDBi016 WELL AREA Attachment B SM_NDB_021 SM_NDB_025 SM_NDB_016 SM_NDB_015 NDB Pad SM_NDB_005 SM_NDB_999 SM_NDB_014 WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityNDB-024 ACTIVE9-5/8" 47ppf10,255 (Nanushuk)3,768 (Nanushuk)8,725 (Top of 1st stage cement)3,429 logopen hole liner for productionTOC 8,725 & packer @ 11,294'Stage 1 - Lead: 100 bbls of 13.0ppg EconoCem Type I/II. Tail: 80 bbls of 15.3ppg VersaCem Type I/II. Stage 2 - Lead: 240 bbls of 13.0ppg EconoCem Type I/II. Tail: 170 bbls of 15.3ppg VersaCem Type I/II. 11/12/23, 9-5/8" casing pressure tested to 3,800 psi for 30 minutesNDB-032 ACTIVE9-5/8" 47ppf4952 (Nanushuk)3,795 (Nanushuk) 2417 2,165 logopen hole liner for productionTOC 2,417' & packer @ 6,104'9-5/8” x 13-3/8” Primary cement jobPump 93 bbls 11.8 ppg Tuned Spacer @ 4 bpm and 350 psi. Release bottom pump down plug and pump 300 bbls 12 ppg ExtendaCem lead @ 4.5 bpm. Pump 45 bbls 15.3 ppg VersaCem type I/II tail @ 2.5 bpm. Release top pump down plug, chase with 2 bbls of cement then 10 bbls of water washup from Halliburton. Perform displacement with rig pumps. 264 bbls displaced with 11.5 ppg mud at 7 bpm. Swap to 11.8 ppg Tuned Spacer, 38 bbls at 7 bpm. Btm pump down dart latch up confirmed at 54 bbls displaced, 819 psi. Btm liner wiper plug latch up confirmed @ 342 bbls displaced, 570 psi. Top pump down dart latch up confirmed @ 39 bbls displaced. Reduce rate to 4 BPM prior to plug bump: Final circulating pressure 550 PSI -Total displacement volume 315 bbls (measured by strokes @ 96% pump efficiency) 3127 stk’s (Calculated 3277 stk’s). Total losses from cement exit shoe to cement in place: 0 bbls. Circulate out cement 11 BPM 880 PSI-observed 72bbls of cement/OBM contaminated returns, estimated 65% cement 35% OBM, and 211bbls of OBM/Tuned Spacer interface. 09/02/23, 9-5/8" casing pressure tested to 3910 psi for 30 minutesNDBi-018 ACTIVE9-5/8" 47ppf6,912' (Nanushuk)3,748' (Nanushuk) 5,860'3,410Logopen hole liner for productionTOC 5,860' & Packer @ 8,103'9-5/8” x 13-3/8” Primary cement job Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 4 bpm with 440 psi. Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 4 bpm, initial circulating pressure 533 psi. Land dart at 53 bbls away latch at calculated strokes, clear indication of latch and release at 1,000 psi. Continue to chase with 112 bbls 15.3 ppg Versacem Tail Cement Type I/II. Pump total of 165 bbls at average of 4 bpm, 530 psi, excess volume 30%. Release top pump down plug, chase with 20 bbls of water from Halliburton. No losses observed while pumping cement. Perform displacement with rig pumps, displace with 12 ppg OBM at 4 bpm, ICP 395 psi, FCP 600 psi. Top pump down dart latch up confirmed at 29 bbls displaced. Continue to displace with 11.8 ppg OBM, reduce rate to 3 bpm prior to plug bump: Final circulating pressure 600 psi. pressured up 500 psi over FCP 1,100 psi held 5 min, bled off checked floats. Floats held.- Total displacement volume 448 bbls (measured by strokes at 96% pump efficiency). CIP @ 22:00 hrs.- Total losses from cement exit shoe to cement in place: 18 bbls Cement Evaluation Results: The top of cement was found to be 1,052’ above the Top of the Nanushuk Pool (6,912’ MD) at 5,860’ MD. Cement isolation from the top of cement down to the casing shoe was found to be in partial to good, mostly good, and ranging down to partial coverage in some areas. Not Pressure tested. Scheduled for 2nd week of October 2024 Sufficient separation that no interference is expected. SFD Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensil e (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design x 13-3/8” Casing Shoe: 2,759’ MD x 9-5/8” x 13-3/8” Liner top: 2,609’ MD x 9-5/8” Liner Shoe: 12,855’ MD x 9-5/8” Archer Cflex Mechanical Stage tool: 4,927’ MD Geology x Top of Tuluvak TS 790 formation at 4,849’ MD. Significant hydrocarbons are contained only within the upper Tuluvak in the Tuluvak Sand (3,038’ MD). x Top of the Nanushuk picked at 10,940’ MD. Top significant hydrocarbon in the Nanushuk was picked at 11,268’ MD in the NT8 Cement Job Planning/Execution See attached cementing reports starting on the next page for a summary of the work performed. Observations For the 1st stage of the cement job, we have adequate isolation in the upper Nanushuk formations across the hydrocarbon-bearing formations (top hydrocarbon estimated within NT8 at ~11,268’ MD). This is supported by the CBL log, which indicates good cement throughout the first stage and a TOC at ’9,058 MD.TOC at ’9,058 MD. Nanushuk picked at 10,940’ MD Top significant hydrocarbon in the p Nanushuk was picked at 11,268’ MD p, For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. Our assessment is that we have adequate isolation across hydrocarbon-bearing formations in the upper Nanushuk formations, as well as adequate isolation for frac operations. The 2 nd stage cement job yielded adequate isolation below, across and above the Tuluvak significant hydrocarbons. Page 1 of 1 Cement - NDBi-016 Surface Casing Cement Surface Casing Cement, Casing, 8/20/2024 05:45 Type Casing Cementing Start Date 8/20/2024 Cementing End Date 8/20/2024 Wellbore Original Hole String Surface Casing, 2,759.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Total displacement volume 379 bbls (measured by strokes at 96% pump efficiency). Observed 203 bbls of cement and 130 bbls of Spacer and Interface returned to surface. Total losses from cement exit shoe to cement in place ~8 bbls Comment Cement 13-3/8” Surface Casing as follows: -PJSM with cementers, rig crew and trucking lead. -Fill lines with 5 bbls water and conduct low pressure test, followed by 4,000 psi high pressure test, no leaks: Good test. -Drop 1st Bottom Non-Rotating Plug. -Pump 80 bbls of 10.5 ppg Tuned Spacer at 4 bpm, 160 psi, full returns. -Release 2nd Bottom Non-Rotating Plug. -Pump 404 bbls of 11.0 ppg ArcticCem lead cement at 5 bpm, Excess Volume 200% (895 sacks, yield 2.53 cu ft/sk), slight losses during pumping. -Pump 69 bbls of 15.3 ppg Type I/II tail at 4.1 bpm, Excess Volume 50% (312 sacks, yield 1.24 cu ft/sk). -Drop top plug and chase with 20 bbls water from cementers. -Perform displacement with rig pumps and 9.8 ppg water base mud. -80 bbls displaced at 6 bpm: ICP 200 psi, FCP 200 psi, starting to see slight losses. -289 bbls displaced at 5 bpm: ICP 218 psi, FCP 682 psi with full returns. -Reduce rate to 3 bpm, 570 psi, 30 bbls prior to plug bump, final circulating pressure 580 psi prior to plug bump. -Bump plug, increase pressure to 1060 psi, check floats: Good. -CIP at 10:45 hrs -Total displacement volume 379 bbls (measured by strokes at 96% pump efficiency). -Observed 203 bbls total of cement returns to surface. -Observed 130 bbls of spacer and interface to surface. -Total losses from cement exit shoe to cement in place: ~8 bbls. 1, 0.0-2,764.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 2,764.0 Full Return? No Vol Cement Ret (bbl) 203.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 5 Avg Pump Rate (bbl/min) 5 Final Pump Pressure (psi) 570.0 Plug Bump Pressure (psi) 580.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Tuned Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 0.0 Percent Excess Pumped (%) Yield (ft³/sack) 1.72 Mix H20 Ratio (gal/sack) 11.51 Free Water (%) 0.00 Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Lead Fluid Type Lead Fluid Description ArcticCem Amount (sacks) 895 Class ArcticCem Volume Pumped (bbl) 404.0 Estimated Top (ftKB) 0.0 Percent Excess Pumped (%) 200.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) 0.00 Density (lb/gal) 11.00 Plastic Viscosity (cP) 14.3 Thickening Time (hr) 13.50 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 36.00 Tail Fluid Type Tail Fluid Description Tail Amount (sacks) 312 Class Type I/II Volume Pumped (bbl) 69.0 Estimated Top (ftKB) 0.0 Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) 0.30 Density (lb/gal) 15.30 Plastic Viscosity (cP) 24.8 Thickening Time (hr) 6.30 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 14.25 y returned to surface. Page 1 of 1 Cement - NDBi-016 Intermediate Liner Cement - 1st Stage Intermediate Liner Cement - 1st Stage, Casing, 9/6/2024 04:15 Type Casing Cementing Start Date 9/6/2024 Cementing End Date 9/6/2024 Wellbore Original Hole String Intermediate Liner, 12,855.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Baker Soundtrack LWD Cement Evaluation Results 1st Stage was logged with the Baker Soundtrack LWD tool. TOC was picked at 9058' MD. Reference the CBL Report in the attachments for a detailed analysis of cement bond log results. Comment Conduct 1st Stage Cement Job of 9-5/8” Liner Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A downhole at 3.5 bpm, full returns -Release bottom pump down plug for bottom plug, pump 255 bbls 15.3 ppg Versacem Tail Cement Type I/II (1182 sacks, yield 1.237 cu ft/sk), excess volume 30%, at 4 bpm, average circulating pressure 500 psi. -Release top pump down plug, chase with 20 bbls of washup from Halliburton. -Perform displacement with rig pumps, displace with 12.0 ppg OBM at 4 bpm, ICP 375 psi, full returns throughout. -Continue to displace with 12.0 ppg OBM, reduce rate to 3 bpm as cement exits shoe and maintain to plug bump: Final circulating pressure 630 psi. -Bump plug, attempt to pressure up to 1100 psi, started to bleed by at 1080 psi. Bring on pumps to bring up hold pressure second time and target 1200 psi but breakover at 1160 psi, fell back off. Crew check on surface lines and line-up, no leaks. Pressure bled to 205 psi, held solid and no more bleed. Hold for 7 minutes, open up to check floats, floats held. -Total displacement volume 785 bbls (measured by strokes at 96% pump efficiency). -Total losses from cement exit shoe to cement in place: 7 bbls. -CIP 10:20 hrs. 1, 9,350.0-12,855.0ftKB Top Depth (ftKB) 9,350.0 Bottom Depth (ftKB) 12,855.0 Full Return? No Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 630.0 Plug Bump Pressure (psi) 1,100.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer with Surfactant B and Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail Cement Type I/II Amount (sacks) 1,182 Class I/II Volume Pumped (bbl) 255.0 Estimated Top (ftKB) 9,350.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 5.75 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 10.25 9058' MD. Page 1 of 1 Cement - NDBi-016 Intermediate Liner Cement - 2nd Stage Intermediate Liner Cement - 2nd Stage, Casing, 9/6/2024 22:43 Type Casing Cementing Start Date 9/6/2024 Cementing End Date 9/7/2024 Wellbore Original Hole String Intermediate Liner, 12,855.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 100 bbls clean cement circulated off liner top and returned to surface Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 4,934’ (center of circulation port) as follows: -Mix and pump 80 bbls of 12.5 ppg Mud Flush at 3.5 bpm, 190 psi 100% returns (both spacers with Surfactant B and Musol A) -Mix and pump 80 bbls of 13.5 Tuned Spacer at 3.5 bpm, 195 psi, full returns -Mix and pump 251 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm initial, ICP 380 psi, FCP 425 psi at 3 bpm -Excess Volume 100% (1140 sacks, yield 1.237 cu ft/sk) -Displace to calculated volume of 101 bbls to Archer Stage Collar -Begin displacing with 20 bbls fresh water from cementing unit -Continue to displace with 81 bbls 11.8 ppg OBM using rig pumps -Stage up to 3 bpm, 448 psi ICP, 100% returns; FCP at 3 bpm 517 psi. -0 bbls lost during displacement -CIP at 01:35 hrs. -No Losses during cement job or displacement -100 bbls clean cement, 140 bbls spacer, 20 bbls interface returned to surface (260 bbls total). 2, 2,625.0-4,927.0ftKB Top Depth (ftKB) 2,625.0 Bottom Depth (ftKB) 4,927.0 Full Return? Yes Vol Cement Ret (bbl) 100.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 516.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Pump MUD FLUSH Spacer 8# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Spacer Fluid Type Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 0.00 Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem (Type I/II ) Amount (sacks) 1,141 Class Type I/II Volume Pumped (bbl) 251.0 Estimated Top (ftKB) 2,609.0 Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 140.3 Thickening Time (hr) 6.25 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 19.75 C 100 bbls clean cement circulated off liner top and returned to surface Attachment D Attachment E Attachment F Well NameNDBi-1609/23/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbFPcWF 253.54040168016804040d Pump CheckWF25 4024028010080117602402800280eDFITWF25 40250530 10500 22260 250 5300 5300 530 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Line out XL XL 25214040 5701680 168000 4057020Drop Stage 1 Ball/Collet FP 021343 573126 18060016/20-CL357330Stage 1 PADXL 2540 238281 8119996 1180200 23881140Slow for Seat XL 251850331 8612100 1390200 5086150Resume PadXL 2540 12343 873504 1440600 1287361FlatXL 2540 190533 10637980 223867642 764216/20-CL182 105572FlatXL 2540 220753 12839240 3162616978 2461916/20-CL202 125784FlatXL 2540 240993 152310080 4170634257 5887616/20-CL204 146196FlatXL 2540 2401233 176310080 5178647792 10666816/20-CL190 1651108FlatXL 2540 2401473 200310080 6186659558 16622616/20-CL177 18281110FlatXL 2540 2001673 22038400 7026658233 22445916/20-CL139 1967120Clear Surface LinesXL 2540 151688 2218630 708960224459 151982130Spacer XL 2540151703 2233630 715260224459 151997140Drop Stage 2 Ball/Collet FP 04031706 2236126 716520 224459 3 2000150Stage 2 PADXL 2540 2301936 24669660 813120 224459 230 2230160Slow for Seat XL 2518501986 25162100 834120224459 502280170Resume PadXL 2540 202006 2536840 842520224459 202300181FlatXL 2540 1902196 27267980 922327642 23210116/20-CL182 2481192FlatXL 2540 2202416 29469240 10147216978 24907816/20-CL202 2684204FlatXL 2540 2402656 318610080 11155234257 28333516/20-CL204 2888216FlatXL 2540 2402896 342610080 12163247792 33112716/20-CL190 3077228FlatXL 2540 2403136 366610080 13171259558 39068516/20-CL177 32542310FlatXL 2540 2003336 38668400 14011258233 44891816/20-CL139 3393240Clear Surface LinesXL 2540 153351 3881630 1407420448918 153408250Spacer XL 2540153366 3896630 1413720448918 153423260Drop Stage 3 Ball/Collet FP 04033369 3899126 1414980 448918 3 3426270Stage 3 PADXL 2540 2213590 41209282 1507800 448918 221 3647280Slow for Seat XL 2518503640 41702100 1528800448918 503697290Resume PadXL 2540 93649 4179378 1532580 448918 9 3706301FlatXL 2540 1903839 43697980 1612387642 45656016/20-CL182 3888313FlatXL 2540 2154054 45849030 17026823915 48047516/20-CL190 4078325FlatXL 2540 2404294 482410080 18034841270 52174516/20-CL197 4274FLUIDNeat WaterCOMMENTSSD monitor 30 minPrime and Pressure TestOpen well and open initiator sleeveDisplace PT - Shut down 5 minLoad Stage 1 ball/collet, SD monitor 1H, line up for XL Well NameNDBi-1609/23/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water337FlatXL 2540 2404534 506410080 19042853874 57561816/20-CL183 4458349FlatXL 2540 2204754 52849240 19966859475 63509316/20-CL157 46153510FlatXL 2540 2004954 54848400 20806858233 69332716/20-CL139 4754360Clear Surface LinesXL 2540 154969 5499630 2086980693327 154769370Spacer XL 2540154984 5514630 2093280693327 154784380Drop Stage 4 Ball/Collet FP 04034987 5517126 2094540 693327 3 4787390Stage 4 PADXL 2540 2135200 57308946 2184000 693327 213 5000400Slow for Seat XL 2518505250 57802100 2205000693327 505050410Resume PadXL 2540 15251 578142 2205420 693327 1 5051421ScourXL 2540 605311 58412520 2230622413 69574040/70- CL57 5108433ScourXL 2540 1205431 59615040 22810213348 70908840/70- CL106 5214440Resume PadXL 2540 505481 60112100 2302020709088 505264451FlatXL 2540 1905671 62017980 2381827642 71673016/20-CL182 5446462FlatXL 2540 2205891 64219240 24742216978 73370716/20-CL202 5648474FlatXL 2540 2406131 666110080 25750234257 76796416/20-CL204 5852486FlatXL 2540 2406371 690110080 26758247792 81575616/20-CL190 6042498FlatXL 2540 2406611 714110080 27766259558 87531416/20-CL177 62195010FlatXL 2540 2006811 73418400 28606258233 93354716/20-CL139 6357510Clear Surface LinesXL 2540 156826 7356630 2866920933547 156372520Spacer XL 2540156841 7371630 2873220933547 156387530Drop Stage 5 Ball/Collet FP 04036844 7374126 2874480 933547 3 6390540Stage 5 PADXL 2540 2027046 75768484 2959320 933547 202 6592550Slow for Seat XL 2518507096 76262100 2980320933547 506642560Resume PadXL 2540 87104 7634336 2983680 933547 8 6650571FlatXL 2540 1807284 78147560 3059287240 94078616/20-CL172 6823583FlatXL 2540 2007484 80148400 31432822247 96303316/20-CL177 6999595FlatXL 2540 2307714 82449660 32398839550 100258316/20-CL188 7188607FlatXL 2540 2307944 84749660 33364851629 105421216/20-CL176 7363619FlatXL 2540 2158159 86899030 34267858123 111233616/20-CL154 75176210FlatXL 2540 1808339 88697560 35023852410 116474516/20-CL125 7642630Clear Surface LinesXL 2540 158354 8884630 3508680 1164745 15 7657640Spacer XL 2540158369 8899630 3514980 1164745 15 7672650Drop Stage 6 Ball/Collet FP 04038372 8902126 3516240 1164745 3 7675660LG FlushWF 2540 1968568 90988232 3598560 1164745 196 7871670Slow for seat WF 2518508618 91482100 3619560 1164745 50 7921680Overflush/ MT PCMWF 254020088189348840037035601164745200812169Linear FlushWF 252018819934942 3926581812270Linear FlushWF 252018820935042 39270018123713000 feet MD + Surface EqmtFP20 588878 94082423 395123TOTALS9408 3951231164745 Well NameNDBi-1609/23/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbDisplace PT- Shut down 10 minWF 253.54040168016804040cPump Ball to SeatWF25 4226266949211172226266dPump CheckWF25 40100366420015372100366 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Stage 6 PADXL 25402252255919450248220022559121ScourXL 2540602856512520273422413241340/70-CL5764833ScourXL 2540 120405 7715040 3238213348 1576140/70-CL106 75440Resume PADXL 2540 50455 8212100 344820 15761 50 80451FlatXL 2540 190645 10117980 424627642 2340316/20-CL182 98663FlatXL 2540 215860 12269030 5149223915 4731916/20-CL190 117675FlatXL 2540 2401100 146610080 6157241270 8858816/20-CL197 137387FlatXL 2540 2401340 170610080 7165253874 14246216/20-CL183 155699FlatXL 2540 2201560 19269240 8089259475 20193716/20-CL157 17131010FlatXL 2540 2001760 21268400 8929258233 26017016/20-CL139 1852110Clear Surface LinesXL 2540 151775 2141630 899220260170 151867120Spacer XL 2540151790 2156630 905520260170 151882130Drop Stage 7 Ball/Collet FP 04031793 2159126 906780 260170 3 1885140Stage 7XL 2540 1871980 23467854 985320 260170 187 2072150Slow for Seat XL 2518502030 23962100 1006320260170 502122160Resume PadXL 2540 12031 239742 1006740 260170 1 2123171ScourXL 2540 602091 24572520 1031942413 26258340/70- CL57 2180183ScourXL 2540 1202211 25775040 10823413348 27593140/70- CL106 2286190Resume PADXL 2540 502261 26272100 1103340275931 502336201FlatXL 2540 1902451 28177980 1183147642 28357316/20-CL182 2518212FlatXL 2540 2202671 30379240 12755416978 30055116/20-CL202 2720224FlatXL 2540 2402911 327710080 13763434257 33480816/20-CL204 2924236FlatXL 2540 2403151 351710080 14771447792 38259916/20-CL190 3114248FlatXL 2540 2403391 375710080 15779459558 44215716/20-CL177 32912510FlatXL 2540 2003591 39578400 16619458233 50039016/20-CL139 3430260Clear Surface LinesXL 2540 153606 3972630 1668240500390 153445270Spacer XL 2540153621 3987630 1674540500390 153460280Drop Stage 8 Ball/Collet FP 04033624 3990126 1675800 500390 3 3463290Stage 8XL 2540 1793803 41697518 1750980 500390 179 3642300Slow for Seat XL 2518503853 42192100 1771980500390 503692310Resume PadXL 2540 13854 422042 1772400 500390 1 3693321ScourXL 2540 603914 42802520 1797602413 50280340/70- CL57 3750333ScourXL 2540 1204034 44005040 18480013348 51615240-70- CL106 3856340Resume PADXL 2540 504084 44502100 1869000516152 503906FLUIDNeat WaterCOMMENTSStart XL- Stage to Stage 6Prime and Pressure TestDrop Ball-SD 10 minutes Well NameNDBi-1609/23/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water351FlatXL 2540 1904274 46407980 1948807642 52379316/20-CL182 4088362FlatXL 2540 2204494 48609240 20412016978 54077116/20-CL202 4290374FlatXL 2540 2404734 510010080 21420034257 57502816/20-CL204 4494386FlatXL 2540 2404974 534010080 22428047792 62282016/20-CL190 4684398FlatXL 2540 2405214 558010080 23436059558 68237716/20-CL177 48614010FlatXL 2540 2005414 57808400 24276058233 74061116/20-CL139 5000410Clear Surface LinesXL 2540 155429 5795630 2433900740611 155015420Spacer XL 2540155444 5810630 2440200740611 155030430Drop Stage 9 Ball/Collet FP 04035447 5813126 2441460 740611 3 5033440Stage 9XL 2540 1715618 59847182 2513280 740611 171 5204450Slow for Seat XL 2518505668 60342100 2534280740611 505254460Resume PadXL 2540 295697 60631218 2546460740611 295283471FlatXL 2540 1905887 62537980 2626267642 74825216/20-CL182 5465483FlatXL 2540 2156102 64689030 27165623915 77216816/20-CL190 5655495FlatXL 2540 2406342 670810080 28173641270 81343716/20-CL197 5851507FlatXL 2540 2406582 694810080 29181653874 86731116/20-CL183 6034519FlatXL 2540 2206802 71689240 30105659475 92678616/20-CL157 61925210FlatXL 25401906992735879803090365532198210816/20-CL132632353Linear FlushWF 254025 7017 73831050 30840625 634854Linear FlushWF 2540127 7144 75105334 313740127 6475553000 feet MD + Surface EqmtFP20 487192 75581995 315735TOTALS7518 315735982108 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 595.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 297.5 gal J475 Breaker J475 6.0 lb/mGal 3,570.3 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,190.1 lbm J532 Crosslinker 2.3 Gal/mGal 1,362.4 gal J580 Gel J580 25.0 lb/mGal 14,876.2 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 29.8 gal M117 Clay Control Agent 339.0 lb/mGal 201,711.3 lbm M275 Bactericide 0.3 lb/mGal 178.5 lbm S522-1620 Propping Agent varied concentrations 2,083,809.0 lbm S522-4070 Propping Agent varied concentrations 63,044.0 lbm ~ 68 % ~ 30 % < 5 % < 1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.1 % <0.001 % <0.0001 % <0.0001 % <0.0001 % <0.0001 % <0.0001 % <0.0001 % <0.0001 % <0.0001 % Total 100 %Total Client:Oil Search Alaska Well:NDBI-016 Basin/Field:Pikka State:Alaska County/Parish:North Slope Borough Case: Disclosure Type:Pre-Job Well Completed: Date Prepared:9/25/2024 Report ID:RPT-1952 Fluid Name & Volume Concentration Volume CAS Number Chemical Name Mass Fraction YF125 ST:WF125 595,048 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. * 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. - Water (Including Mix Water Supplied by Client)* 66402-68-4 7447-40-7 9000-30-0 7647-14-5 7727-54-0 56-81-5 102-71-6 1303-96-4 50-70-4 67-63-0 111-76-2 34398-01-1 25038-72-6 68131-39-5 9025-56-3 112-42-5 91053-39-3 7631-86-9 9002-84-0 14807-96-6 10377-60-3 55965-84-9 7786-30-3 127-08-2 9000-90-2 14808-60-7 14464-46-1 64-19-7 532-32-1 24634-61-5 92797-42-7 Ceramic materials and wares, chemicals Potassium chloride Guar gum Sodium chloride Diammonium peroxodisulphate 1, 2, 3 - Propanetriol 2,2`,2"-nitrilotriethanol Sodium tetraborate decahydrate Sorbitol Propan-2-ol 2-butoxyethanol Ethoxylated C11 Alcohol Vinylidene chloride/methylacrylate copolymer Ethoxylated Alcohol Hemicellulase 1-undecanol (impurity) Diatomaceous earth, calcined Silicon Dioxide (Impurity) poly(tetrafluoroethylene) Magnesium silicate hydrate (talc) Magnesium nitrate 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one Magnesium chloride Acetic acid, potassium salt (impurity) Amylase, alpha Bauxite (Al2O3.xH2O), calcined Quartz, Crystalline silica Cristobalite Acetic acid (impurity) Sodium benzoate Potassium (E,E)-hexa-2,4-dienoate # SLB-Private Page: 1 / 1 Updated 7/18/2024INPUTTBDAK TSCA Status TBDPre Trade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SMETracercoCarrier FluidSoy Methyl Ester67784-80-9100#VALUE!71.2092260000T-758TracercoChemical Tracer3,4-Difluorobenzophenone85118-07-6100#VALUE!0.4409240000T-729TracercoChemical Tracer1,4-Dibromo-2,5-dimethyl benzene1074-24-4100#VALUE!2.2046200000T-716TracercoChemical Tracer1,3,5-Tribromobenzene626-39-1100#VALUE!0.4409240000T-731TracercoChemical Tracer1-Bromo-3,5-dichlorobenzene19752-55-7100#VALUE!0.4409240000T-164CTracercoChemical Tracer1-Iodonaphthalene90-14-2100#VALUE!0.4409240000T-784TracercoChemical Tracer2,4,6-Tribromoanisole607-99-8100#VALUE!0.4409240000T-168ATracercoChemical Tracer1-Chloro-4-iodobenzene637-87-6100#VALUE!0.4409240000T-718TracercoChemical Tracer4-Chlorobenzophenone134-85-0100#VALUE!0.6613860000T-750TracercoChemical Tracer1,4-Dibromo-2-fluorobenzene1435-52-5100#VALUE!0.4409240000WaterTracercoCarrier FluidWater7732-18-5100#VALUE!58.6428920000T-158cTracercoChemical TracerSodium-2,6-Difluorobenzoate6185-28-0100#VALUE!0.7716170000T-805TracercoChemical TracerSodium-2,4-Dichlorobenzoate38402-11-8100#VALUE!0.7716170000T-920TracercoChemical TracerSodium-5-chloro-2-fluorobenzoate1382106-78-6100#VALUE!0.7716170000T-176aTracercoChemical TracerSodium-2,3,4-trifluorobenzoate402955-41-3100#VALUE!0.7716170000T-803TracercoChemical TracerSodium-4-chlorobenzoate3686-66-6100#VALUE!0.7716170000T-257aTracercoChemical TracerSodium-3,5-di(Trifluoromethyl)benzoate87441-96-1100#VALUE!0.7716170000T-801TracercoChemical TracerSodium-2-chlorobenzoate17264-74-3100#VALUE!0.7716170000T-926TracercoChemical TracerSodium-4-chloro-3-methylbenzoate1431868-21-1100#VALUE!0.7716170000T-912TracercoChemical TracerSodium-2-chloro-5-fluorobenzoate1382106-79-7100#VALUE!0.7716170000County:API Number:Operator Name: Santos AKWell Name and Number: NDBi-016Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState:Approved For Tracerco Attachment G NDBi-016 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: x Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. x Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. x Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. x Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. x Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 g Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas g(),qgppg for the duration of the development well flowback work. Total volume of gas per the flowback programp outlined in Table 1 is approximately 15 MMscf. Attachment H NDBi-016 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 10.0 ppg NaCl/KCl brine to surface. 3. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 4. Pressure up to close the WIV at 1,980 psi. 5. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 6. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. 7. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi for 10 minutes. 8. Release running tool from liner hanger. 9. Circulate 9.4 ppg NaCl Corrosion Inhibited brine with biocide to surface at 10 bpm pump rate. 10.POOH with liner hanger running tool. 11.Prepare to run upper completion. NDBi-016 4-1/2” Upper Completion Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 2. Land tubing hanger. 3. MIT-T to 3,500 psi. (Post drilling rig move, MIT-T to be tested to 5,700 psi) a. (8,900 psi MAWP – 3,800 psi IA hold) * 1.1 = 5,610 psi 4. MIT-IA to 4,000 psi. (Post drilling rig move, MIT-IA to be tested to 4,300 psi with AOGCC witness notification) 5. Shear circulation valve. 6. Reverse circulate freeze protect and U-Tube. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k frac tree. 9. RDMO NDBi-016 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment I Attachment J Attachment K FracCADE* STIMULATION PROPOSAL Operator :Oil Search Well :NDBi-016 Field :Pikka Formation :Nanushuk Stages 1 to 9 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 : 09-25-2024 FAX No. : 1 907 659 2538 Prepared by : Laura Acosta Phone : E-Mail Address :NTrevino2@slb.com * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. 1 SLB Private Attachment K Section 1: Zone Data (Stage 1; 17619 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 4031.7 10.0 0.73 2937 1.46E+06 0.220 2500 Shale 4041.7 15.0 0.70 2814 1.76E+06 0.220 2500 Nanushuk 3 SS 4056.7 15.3 0.68 2756 1.90E+06 0.220 2000 Top Nan 4072.0 6.0 0.65 2633 8.39E+05 0.270 1000 SHALE 4078.0 2.0 0.70 2861 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4080.0 1.5 0.63 2587 8.19E+05 0.270 1500 DIRTY-SANDSTONE 4081.5 2.0 0.64 2618 1.22E+06 0.260 1500 CLEAN-SANDSTONE 4083.5 13.0 0.63 2564 8.69E+05 0.270 1000 CLEAN-SANDSTONE 4096.5 1.5 0.62 2527 1.00E+06 0.270 1000 CLEAN-SANDSTONE 4098.0 4.0 0.64 2632 7.07E+05 0.280 1000 CLEAN-SANDSTONE 4102.0 9.0 0.61 2493 1.17E+06 0.270 1000 CLEAN-SANDSTONE 4111.0 7.0 0.65 2662 7.69E+05 0.270 1000 CLEAN-SANDSTONE 4118.0 5.5 0.61 2501 1.28E+06 0.260 1000 CLEAN-SANDSTONE 4123.5 13.0 0.65 2668 6.92E+05 0.280 1000 DIRTY-SANDSTONE 4136.5 2.5 0.68 2820 1.75E+06 0.260 1500 DIRTY-SANDSTONE 4139.0 12.5 0.64 2652 1.11E+06 0.270 1500 DIRTY-SANDSTONE 4151.5 4.0 0.70 2893 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4155.5 2.5 0.64 2677 8.22E+05 0.270 1500 SHALE 4158.0 2.0 0.70 2916 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4160.0 4.0 0.65 2713 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4164.0 4.0 0.63 2627 8.38E+05 0.270 1000 SHALE 4168.0 4.0 0.69 2873 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4172.0 6.0 0.64 2684 1.13E+06 0.270 1500 SHALE 4178.0 2.0 0.70 2930 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4180.0 2.0 0.62 2571 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4182.0 6.5 0.66 2783 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4188.5 4.0 0.62 2579 8.99E+05 0.270 1500 DIRTY-SANDSTONE 4192.5 3.5 0.65 2713 9.29E+05 0.270 1500 SHALE 4196.0 2.0 0.70 2942 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4198.0 12.5 0.64 2701 1.56E+06 0.260 1500 DIRTY-SANDSTONE 4210.5 2.0 0.65 2750 1.40E+06 0.260 1500 SHALE 4212.5 2.0 0.69 2903 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4214.5 2.0 0.65 2744 1.24E+06 0.260 1500 SHALE 4216.5 8.0 0.70 2958 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4224.5 2.0 0.63 2645 9.33E+05 0.270 1500 SHALE 4226.5 4.0 0.70 2964 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4230.5 6.0 0.66 2782 1.43E+06 0.260 1500 SHALE 4236.5 8.0 0.70 2972 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4244.5 6.5 0.65 2768 1.47E+06 0.260 1500 SHALE 4251.0 6.0 0.70 2981 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4257.0 2.0 0.64 2728 8.38E+05 0.270 1000 SHALE 4259.0 2.0 0.69 2935 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4261.0 4.0 0.66 2820 1.47E+06 0.260 1500 SHALE 4265.0 2.0 0.70 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4267.0 6.0 0.67 2851 1.55E+06 0.260 1500 SHALE 4273.0 12.0 0.69 2948 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4285.0 2.5 0.63 2709 1.21E+06 0.270 1500 SHALE 4287.5 20.0 0.70 3011 2.67E+06 0.230 2500 Zone Name Poisson’s Ratio Formation Mechanical Properties 2 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4031.7 10.0 0.001 1.0 1881 4041.7 15.0 0.001 1.0 1886 4056.7 15.3 0.005 10.0 1890 4072.0 6.0 56.445 22.0 1882 4078.0 2.0 0.001 1.0 1884 4080.0 1.5 109.347 15.0 1885 4081.5 2.0 4.377 15.0 1886 4083.5 13.0 42.829 22.0 1887 4096.5 1.5 11.097 22.0 1893 4098.0 4.0 91.857 22.0 1894 4102.0 9.0 4.906 22.0 1896 4111.0 7.0 12.361 22.0 1900 4118.0 5.5 2.537 22.0 1903 4123.5 13.0 61.847 22.0 1906 4136.5 2.5 0.081 15.0 1912 4139.0 12.5 22.858 15.0 1913 4151.5 4.0 0.018 15.0 1919 4155.5 2.5 94.329 15.0 1920 4158.0 2.0 0.001 1.0 1922 4160.0 4.0 45.186 15.0 1922 4164.0 4.0 24.865 15.0 1924 4168.0 4.0 0.001 1.0 1926 4172.0 6.0 6.405 15.0 1928 4178.0 2.0 0.001 1.0 1931 4180.0 2.0 13.686 15.0 1932 4182.0 6.5 0.229 15.0 1933 4188.5 4.0 49.420 15.0 1936 4192.5 3.5 63.759 15.0 1938 4196.0 2.0 0.001 1.0 1939 4198.0 12.5 1.337 15.0 1940 4210.5 2.0 1.843 15.0 1946 4212.5 2.0 0.001 1.0 1947 4214.5 2.0 4.320 15.0 1948 4216.5 8.0 0.001 1.0 1949 4224.5 2.0 91.060 15.0 1952 4226.5 4.0 0.001 1.0 1953 4230.5 6.0 4.551 15.0 1955 4236.5 8.0 0.001 1.0 1958 4244.5 6.5 7.953 15.0 1962 4251.0 6.0 0.001 1.0 1965 4257.0 2.0 24.687 15.0 1967 4259.0 2.0 0.001 1.0 1968 4261.0 4.0 2.159 10.0 1969 4265.0 2.0 0.001 1.0 1971 4267.0 6.0 1.534 10.0 1972 4273.0 12.0 0.001 1.0 1975 4285.0 2.5 5.632 10.0 1980 4287.5 20.0 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 3 SLB Private Attachment K Section 2: Propped Fracture Schedule (Stage 1; 17619 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 Flush 40 YF125ST 267.4 25 0 Please note that this pumping schedule is under-displaced by 1 bbl. 1,662.9 bbl of YF125ST 225010 lb of % PAD Clean 21.5 % PAD Dirty 18.4 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 12600.0 12600 300 300 0 0 4232 7.5 7.5 1.0 PPA 7645.4 20245 190 490 7645 7645 4248 4.8 12.3 2.0 PPA 8496.3 28742 220 710 16993 24638 4358 5.5 17.8 4.0 PPA 8578.3 37320 240 950 34313 58951 4848 6.0 23.8 6.0 PPA 7983.6 45304 240 1190 47902 106853 5665 6.0 29.8 8.0 PPA 7466.0 52770 240 1430 59728 166581 6389 6.0 35.8 10.0 PPA 5842.9 58613 200 1630 58429 225010 6798 5.0 40.8 Flush 11230.8 69843 267 1897 0 225010 6147 6.7 47.4 Carbolite 16/20 Proppant Totals Carbolite 16/20 Pad Percentages Job Execution Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 406 ft with an average conductivity (Kfw) of 16133.1 md.ft. Job Description Fluid Name Prop. Type and Mesh 4 SLB Private Attachment K 6798 Section 3: Propped Fracture Simulation (Stage 1; 17619 ft MD) Initial Fracture Top TVD 4036.3 ft Initial Fracture Bottom TVD 4241.5 ft Propped Fracture Half-Length 406 ft EOJ Hyd Height at Well 205.3 ft Average Propped Width 0.182 in Net Pressure 424 psi Max Surface Pressure 6930 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) 0 101.5 9.1 0.232 118.5 2.01 259.7 21297 101.5 203 7 0.214 176.7 1.9 292.8 19263 203 304.5 5.3 0.179 153.3 1.61 348.2 15781 304.5 406 1.6 0.118 96.9 1.11 377.4 9814 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. 5 SLB Private Attachment K 6930 psi Section 4: Zone Data (Stage 2; 17119 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 4036.1 10.0 0.73 2937 1.46E+06 0.220 2500 Shale 4046.1 15.0 0.70 2817 1.76E+06 0.220 2500 Nanushuk 3 SS 4061.1 15.3 0.68 2759 1.90E+06 0.220 2000 Top Nan 4076.4 6.0 0.65 2633 8.39E+05 0.270 1000 SHALE 4082.4 2.0 0.70 2861 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4084.4 1.5 0.63 2587 8.19E+05 0.270 1500 DIRTY-SANDSTONE 4085.9 2.0 0.64 2618 1.22E+06 0.260 1500 CLEAN-SANDSTONE 4087.9 13.0 0.63 2564 8.69E+05 0.270 1000 CLEAN-SANDSTONE 4100.9 1.5 0.62 2527 1.00E+06 0.270 1000 CLEAN-SANDSTONE 4102.4 4.0 0.64 2632 7.07E+05 0.280 1000 CLEAN-SANDSTONE 4106.4 9.0 0.61 2495 1.17E+06 0.270 1000 CLEAN-SANDSTONE 4115.4 7.0 0.65 2662 7.69E+05 0.270 1000 CLEAN-SANDSTONE 4122.4 5.5 0.61 2504 1.28E+06 0.260 1000 CLEAN-SANDSTONE 4127.9 13.0 0.65 2668 6.92E+05 0.280 1000 DIRTY-SANDSTONE 4140.9 2.5 0.68 2820 1.75E+06 0.260 1500 DIRTY-SANDSTONE 4143.4 12.5 0.64 2652 1.11E+06 0.270 1500 DIRTY-SANDSTONE 4155.9 4.0 0.70 2893 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4159.9 2.5 0.64 2677 8.22E+05 0.270 1500 SHALE 4162.4 2.0 0.70 2916 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4164.4 4.0 0.65 2713 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4168.4 4.0 0.63 2627 8.38E+05 0.270 1000 SHALE 4172.4 4.0 0.69 2876 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4176.4 6.0 0.64 2684 1.13E+06 0.270 1500 SHALE 4182.4 2.0 0.70 2930 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4184.4 2.0 0.62 2574 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4186.4 6.5 0.66 2783 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4192.9 4.0 0.61 2579 8.99E+05 0.270 1500 DIRTY-SANDSTONE 4196.9 3.5 0.65 2713 9.29E+05 0.270 1500 SHALE 4200.4 2.0 0.70 2942 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4202.4 12.5 0.64 2701 1.56E+06 0.260 1500 DIRTY-SANDSTONE 4214.9 2.0 0.65 2750 1.40E+06 0.260 1500 SHALE 4216.9 2.0 0.69 2906 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4218.9 2.0 0.65 2747 1.24E+06 0.260 1500 SHALE 4220.9 8.0 0.70 2958 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4228.9 2.0 0.63 2648 9.33E+05 0.270 1500 SHALE 4230.9 4.0 0.70 2964 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4234.9 6.0 0.66 2782 1.43E+06 0.260 1500 SHALE 4240.9 8.0 0.70 2972 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4248.9 6.5 0.65 2768 1.47E+06 0.260 1500 SHALE 4255.4 6.0 0.70 2981 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4261.4 2.0 0.64 2728 8.38E+05 0.270 1000 SHALE 4263.4 2.0 0.69 2938 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4265.4 4.0 0.66 2820 1.47E+06 0.260 1500 SHALE 4269.4 2.0 0.70 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4271.4 6.0 0.67 2851 1.55E+06 0.260 1500 SHALE 4277.4 12.0 0.69 2951 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4289.4 2.5 0.63 2712 1.21E+06 0.270 1500 SHALE 4291.9 20.0 0.70 3011 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 6 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4036.1 10.0 0.001 1.0 1881 4046.1 15.0 0.001 1.0 1886 4061.1 15.3 0.005 10.0 1890 4076.4 6.0 56.445 22.0 1882 4082.4 2.0 0.001 1.0 1884 4084.4 1.5 109.347 15.0 1885 4085.9 2.0 4.377 15.0 1886 4087.9 13.0 42.829 22.0 1887 4100.9 1.5 11.097 22.0 1893 4102.4 4.0 91.857 22.0 1894 4106.4 9.0 4.906 22.0 1896 4115.4 7.0 12.361 22.0 1900 4122.4 5.5 2.537 22.0 1903 4127.9 13.0 61.847 22.0 1906 4140.9 2.5 0.081 15.0 1912 4143.4 12.5 22.858 15.0 1913 4155.9 4.0 0.018 15.0 1919 4159.9 2.5 94.329 15.0 1920 4162.4 2.0 0.001 1.0 1922 4164.4 4.0 45.186 15.0 1922 4168.4 4.0 24.865 15.0 1924 4172.4 4.0 0.001 1.0 1926 4176.4 6.0 6.405 15.0 1928 4182.4 2.0 0.001 1.0 1931 4184.4 2.0 13.686 15.0 1932 4186.4 6.5 0.229 15.0 1933 4192.9 4.0 49.420 15.0 1936 4196.9 3.5 63.759 15.0 1938 4200.4 2.0 0.001 1.0 1939 4202.4 12.5 1.337 15.0 1940 4214.9 2.0 1.843 15.0 1946 4216.9 2.0 0.001 1.0 1947 4218.9 2.0 4.320 15.0 1948 4220.9 8.0 0.001 1.0 1949 4228.9 2.0 91.060 15.0 1952 4230.9 4.0 0.001 1.0 1953 4234.9 6.0 4.551 15.0 1955 4240.9 8.0 0.001 1.0 1958 4248.9 6.5 7.953 15.0 1962 4255.4 6.0 0.001 1.0 1965 4261.4 2.0 24.687 15.0 1967 4263.4 2.0 0.001 1.0 1968 4265.4 4.0 2.159 10.0 1969 4269.4 2.0 0.001 1.0 1971 4271.4 6.0 1.534 10.0 1972 4277.4 12.0 0.001 1.0 1975 4289.4 2.5 5.632 10.0 1980 4291.9 20.0 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 7 SLB Private Attachment K Section 5: Propped Fracture Schedule (Stage 2; 17119 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 FLUSH 40 YF125ST 259.8 25 0 Please note that this pumping schedule is under-displaced by 1 bbl. 1,655.3 bbl of YF125ST 225010 lb of % PAD Clean 21.5 % PAD Dirty 18.4 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 12600.0 12600 300 300 0 0 4138 7.5 7.5 1.0 PPA 7645.4 20245 190 490 7645 7645 4161 4.8 12.3 2.0 PPA 8496.3 28742 220 710 16993 24638 4260 5.5 17.8 4.0 PPA 8578.3 37320 240 950 34313 58951 4727 6.0 23.8 6.0 PPA 7983.6 45304 240 1190 47902 106853 5516 6.0 29.8 8.0 PPA 7466.0 52770 240 1430 59728 166581 6215 6.0 35.8 10.0 PPA 5842.9 58613 200 1630 58429 225010 6621 5.0 40.8 FLUSH 10910.9 69523 260 1890 0 225010 5922 6.5 47.2 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 371.1 ft with an average conductivity (Kfw) of 15636.3 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 8 SLB Private Attachment K Section 6: Propped Fracture Simulation (Stage 2; 17119 ft MD) Initial Fracture Top TVD 4037.7 ft Initial Fracture Bottom TVD 4259.5 ft Propped Fracture Half-Length 371.1 ft EOJ Hyd Height at Well 221.9 ft Average Propped Width 0.176 in Net Pressure 251 psi Max Surface Pressure 6736 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 92.8 9 0.198 129.2 1.61 280.6 18270 92.8 185.5 7 0.198 192.1 1.69 298.9 17887 185.5 278.3 5.6 0.191 165.4 1.71 321.5 16888 278.3 371.1 2.2 0.125 130.5 1.16 547.5 10455 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 9 SLB Private Attachment K Section 7: Zone Data (Stage 3; 16536 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 4044.8 10.0 0.73 2937 1.46E+06 0.220 1000 Shale 4054.8 15.0 0.70 2823 1.76E+06 0.220 1000 Nanushuk 3 SS 4069.8 15.3 0.68 2765 1.90E+06 0.220 1000 Top Nan CS 4085.1 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4104.6 2.0 0.69 2837 2.67E+06 0.230 2500 Nan CS 4106.6 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4108.1 4.5 0.62 2532 6.44E+05 0.280 1000 Nan DS 4112.6 3.5 0.69 2843 1.77E+06 0.260 1500 Nan DS 4116.1 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4130.6 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4132.1 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4144.6 2.0 0.65 2690 1.40E+06 0.260 1500 Nan CS 4146.6 9.0 0.61 2520 8.54E+05 0.270 1000 Nan DS 4155.6 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4162.6 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4171.6 3.5 0.65 2720 1.69E+06 0.260 1500 Nan DS 4175.1 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4180.1 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4182.1 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4192.6 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4196.1 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4198.1 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4203.6 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4207.1 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4210.6 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4216.1 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4226.6 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4228.1 5.0 0.63 2671 1.14E+06 0.270 1500 Nan DS 4233.1 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4235.1 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4239.1 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4241.1 10.0 0.63 2662 9.81E+05 0.270 1500 Nan DS 4251.1 4.0 0.65 2782 1.63E+06 0.260 1500 Nan DS 4255.1 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4259.1 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4268.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4270.6 9.5 0.70 2975 1.69E+06 0.260 1500 Nan DS 4280.1 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4282.1 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4284.1 2.0 0.64 2725 1.09E+06 0.270 1500 Shale 4286.1 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4288.1 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4292.1 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4311.6 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4313.6 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4315.6 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4323.6 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4331.6 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 10 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4044.8 10.0 0.001 1.0 1890 4054.8 15.0 0.001 1.0 1898 4069.8 15.3 0.005 10.0 1905 4085.1 19.5 30.655 23.7 1915 4104.6 2.0 5.000 10.0 1924 4106.6 1.5 2.095 16.9 1925 4108.1 4.5 48.388 26.6 1926 4112.6 3.5 0.478 12.4 1928 4116.1 14.5 15.008 17.7 1930 4130.6 1.5 3.661 17.6 1937 4132.1 12.5 34.723 23.9 1937 4144.6 2.0 1.697 15.6 1943 4146.6 9.0 54.319 24.4 1944 4155.6 7.0 3.610 14.8 1948 4162.6 9.0 22.986 20.4 1952 4171.6 3.5 0.835 14.0 1956 4175.1 5.0 65.392 23.4 1957 4180.1 2.0 0.006 10.5 1960 4182.1 10.5 100.832 25.6 1961 4192.6 3.5 17.434 20.5 1966 4196.1 2.0 161.343 26.3 1967 4198.1 5.5 4.627 18.4 1968 4203.6 3.5 5.075 14.8 1971 4207.1 3.5 8.651 19.4 1972 4210.6 5.5 10.205 16.0 1974 4216.1 10.5 17.356 20.1 1977 4226.6 1.5 3.106 14.8 1982 4228.1 5.0 52.863 20.6 1982 4233.1 2.0 2.277 14.1 1985 4235.1 4.0 122.778 23.1 1986 4239.1 2.0 0.333 12.5 1987 4241.1 10.0 39.939 21.2 1988 4251.1 4.0 0.748 13.3 1993 4255.1 4.0 0.009 10.9 1995 4259.1 9.5 5.399 16.7 1997 4268.6 2.0 160.618 24.9 2001 4270.6 9.5 0.033 11.5 2002 4280.1 2.0 6.733 16.2 2007 4282.1 2.0 0.001 1.0 2008 4284.1 2.0 29.480 19.6 2009 4286.1 2.0 0.001 1.0 2009 4288.1 4.0 8.473 16.6 2010 4292.1 19.5 0.001 1.0 2012 4311.6 2.0 2.185 16.4 2021 4313.6 2.0 0.001 1.0 2022 4315.6 8.0 2.645 15.9 2023 4323.6 8.0 2.026 14.4 2027 4331.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 11 SLB Private Attachment K Section 8: Propped Fracture Schedule (Stage 3; 16536 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 280.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 3.0 PPA 40 YF125ST 190.0 25 3 5.0 PPA 40 YF125ST 196.9 25 5 7.0 PPA 40 YF125ST 183.7 25 7 9.0 PPA 40 YF125ST 157.8 25 9 10.0 PPA 40 YF125ST 139.1 25 10 FLUSH 40 YF125ST 250.9 25 0 Please note that this pumping schedule is under-displaced by 1 bbl. 1,580.6 bbl of YF125ST 245046 lb of % PAD Clean 21.1 % PAD Dirty 17.7 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 11760.0 11760 280 280 0 0 4068 7.0 7.0 1.0 PPA 7645.4 19405 190 470 7645 7645 4064 4.8 11.8 3.0 PPA 7982.0 27387 215 685 23946 31591 4269 5.4 17.1 5.0 PPA 8270.3 35658 240 925 41351 72943 4955 6.0 23.1 7.0 PPA 7716.2 43374 240 1165 54013 126956 5655 6.0 29.1 9.0 PPA 6629.0 50003 220 1385 59661 186617 6194 5.5 34.6 10.0 PPA 5842.9 55846 200 1585 58429 245046 6464 5.0 39.6 FLUSH 10537.9 66384 251 1836 0 245046 5760 6.3 45.9 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 281.7 ft with an average conductivity (Kfw) of 18750.5 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 12 SLB Private Attachment K Section 9: Propped Fracture Simulation (Stage 3; 16536 ft MD) Initial Fracture Top TVD 4048.8 ft Initial Fracture Bottom TVD 4292.9 ft Propped Fracture Half-Length 281.7 ft EOJ Hyd Height at Well 244.1 ft Average Propped Width 0.216 in Net Pressure 171 psi Max Surface Pressure 6537 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 70.4 9.8 0.226 154.5 1.95 273.4 20078 70.4 140.8 9.1 0.235 222.3 2.08 274 20387 140.8 211.3 8.5 0.234 207.9 2.08 273.8 20500 211.3 281.7 4.2 0.177 174.1 1.59 347.6 15160 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 13 SLB Private Attachment K Section 10: Zone Data (Stage 4; 15998 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 4050.8 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4060.8 15.0 0.70 2827 1.76E+06 0.220 1000 Nanushuk 3 SS 4075.8 15.3 0.68 2769 1.90E+06 0.220 1000 Top Nan CS 4091.1 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4110.6 2.0 0.69 2841 2.67E+06 0.230 2500 Nan CS 4112.6 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4114.1 4.5 0.62 2536 6.44E+05 0.280 1000 Nan DS 4118.6 3.5 0.69 2847 1.77E+06 0.260 1500 Nan DS 4122.1 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4136.6 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4138.1 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4150.6 2.0 0.65 2694 1.40E+06 0.260 1500 Nan CS 4152.6 9.0 0.61 2523 8.54E+05 0.270 1000 Nan DS 4161.6 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4168.6 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4177.6 3.5 0.65 2720 1.69E+06 0.260 1500 Nan DS 4181.1 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4186.1 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4188.1 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4198.6 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4202.1 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4204.1 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4209.6 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4213.1 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4216.6 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4222.1 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4232.6 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4234.1 5.0 0.63 2671 1.14E+06 0.270 1500 Nan DS 4239.1 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4241.1 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4245.1 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4247.1 10.0 0.63 2666 9.81E+05 0.270 1500 Nan DS 4257.1 4.0 0.65 2785 1.63E+06 0.260 1500 Nan DS 4261.1 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4265.1 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4274.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4276.6 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4286.1 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4288.1 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4290.1 2.0 0.64 2729 1.09E+06 0.270 1500 Shale 4292.1 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4294.1 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4298.1 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4317.6 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4319.6 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4321.6 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4329.6 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4337.6 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 14 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4050.8 10.0 0.001 1.0 1890 4060.8 15.0 0.001 1.0 1898 4075.8 15.3 0.005 10.0 1905 4091.1 19.5 30.655 23.7 1915 4110.6 2.0 5.000 10.0 1924 4112.6 1.5 2.095 16.9 1925 4114.1 4.5 48.388 26.6 1926 4118.6 3.5 0.478 12.4 1928 4122.1 14.5 15.008 17.7 1930 4136.6 1.5 3.661 17.6 1937 4138.1 12.5 34.723 23.9 1937 4150.6 2.0 1.697 15.6 1943 4152.6 9.0 54.319 24.4 1944 4161.6 7.0 3.610 14.8 1948 4168.6 9.0 22.986 20.4 1952 4177.6 3.5 0.835 14.0 1956 4181.1 5.0 65.392 23.4 1957 4186.1 2.0 0.006 10.5 1960 4188.1 10.5 100.832 25.6 1961 4198.6 3.5 17.434 20.5 1966 4202.1 2.0 161.343 26.3 1967 4204.1 5.5 4.627 18.4 1968 4209.6 3.5 5.075 14.8 1971 4213.1 3.5 8.651 19.4 1972 4216.6 5.5 10.205 16.0 1974 4222.1 10.5 17.356 20.1 1977 4232.6 1.5 3.106 14.8 1982 4234.1 5.0 52.863 20.6 1982 4239.1 2.0 2.277 14.1 1985 4241.1 4.0 122.778 23.1 1986 4245.1 2.0 0.333 12.5 1987 4247.1 10.0 39.939 21.2 1988 4257.1 4.0 0.748 13.3 1993 4261.1 4.0 0.009 10.9 1995 4265.1 9.5 5.399 16.7 1997 4274.6 2.0 160.618 24.9 2001 4276.6 9.5 0.033 11.5 2002 4286.1 2.0 6.733 16.2 2007 4288.1 2.0 0.001 1.0 2008 4290.1 2.0 29.480 19.6 2009 4292.1 2.0 0.001 1.0 2009 4294.1 4.0 8.473 16.6 2010 4298.1 19.5 0.001 1.0 2012 4317.6 2.0 2.185 16.4 2021 4319.6 2.0 0.001 1.0 2022 4321.6 8.0 2.645 15.9 2023 4329.6 8.0 2.026 14.4 2027 4337.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 15 SLB Private Attachment K Section 11: Propped Fracture Schedule (Stage 4; 15998 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 264.0 25 0 1.0 PPA Scou 40 YF125ST 57.5 25 1 3.0 PPA Scou 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 FLUSH 40 YF125ST 242.7 25 0 Please note that this pumping schedule is under-displaced by 1 bbl. 1,815.7 bbl of YF125ST 225010 lb of 15764 lb of % PAD Clean 16.8 % PAD Dirty 14.5 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 11088.0 11088 264 264 0 0 3968 6.6 6.6 1.0 PPA Scou 2414.3 13502 60 324 2414 2414 3962 1.5 8.1 3.0 PPA Scou 4449.7 17952 120 444 13349 15764 4029 3.0 11.1 Resume PAD 2100.0 20052 50 494 0 15764 4188 1.3 12.4 1.0 PPA 7645.4 27697 190 684 7645 23409 4283 4.8 17.1 2.0 PPA 8496.3 36194 220 904 16993 40402 4135 5.5 22.6 4.0 PPA 8578.3 44772 240 1144 34313 74715 4491 6.0 28.6 6.0 PPA 7983.6 52756 240 1384 47902 122617 5139 6.0 34.6 8.0 PPA 7466.0 60222 240 1624 59728 182345 5793 6.0 40.6 10.0 PPA 5842.9 66065 200 1824 58429 240774 6189 5.0 45.6 FLUSH 10193.6 76258 243 2067 0 240774 5686 6.1 51.7 Job Execution Step Name Pad Percentages Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 40/70 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 288.6 ft with an average conductivity (Kfw) of 17863.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 16 SLB Private Attachment K Section 12: Propped Fracture Simulation (Stage 4; 15998 ft MD) Initial Fracture Top TVD 4055.3 ft Initial Fracture Bottom TVD 4299 ft Propped Fracture Half-Length 288.6 ft EOJ Hyd Height at Well 243.7 ft Average Propped Width 0.207 in Net Pressure 202 psi Max Surface Pressure 6312 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 72.1 8.7 0.267 213 2.31 217.9 24023 72.1 144.3 7.3 0.256 213 2.26 236.9 22656 144.3 216.4 6 0.215 209.9 1.94 280.6 18628 216.4 288.6 2 0.103 197.3 1.04 531.3 8007 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 17 SLB Private Attachment K Section 13: Zone Data (Stage 5; 15256 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 4015.8 10.0 0.73 2937 1.46E+06 0.220 1000 Shale 4025.8 15.0 0.70 2803 1.76E+06 0.220 1000 Nanushuk 3 SS 4040.8 15.3 0.68 2745 1.90E+06 0.220 1000 Top Nan CS 4056.1 19.5 0.64 2595 9.00E+05 0.270 1000 Nan SS 4075.6 2.0 0.69 2817 2.67E+06 0.230 2500 Nan CS 4077.6 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4079.1 4.5 0.62 2514 6.44E+05 0.280 1000 Nan DS 4083.6 3.5 0.69 2823 1.77E+06 0.260 1500 Nan DS 4087.1 14.5 0.67 2726 1.39E+06 0.260 1500 Nan CS 4101.6 1.5 0.66 2706 1.15E+06 0.270 1000 Nan CS 4103.1 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4115.6 2.0 0.65 2672 1.40E+06 0.260 1500 Nan CS 4117.6 9.0 0.61 2502 8.54E+05 0.270 1000 Nan DS 4126.6 7.0 0.67 2755 1.40E+06 0.260 1500 Nan DS 4133.6 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4142.6 3.5 0.66 2720 1.69E+06 0.260 1500 Nan DS 4146.1 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4151.1 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4153.1 10.5 0.63 2607 7.36E+05 0.270 1000 Nan CS 4163.6 3.5 0.65 2705 1.10E+06 0.270 1000 Nan CS 4167.1 2.0 0.63 2614 6.70E+05 0.280 1000 Nan CS 4169.1 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4174.6 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4178.1 3.5 0.65 2701 1.19E+06 0.270 1500 Nan DS 4181.6 5.5 0.70 2928 1.42E+06 0.260 1500 Nan CS 4187.1 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4197.6 1.5 0.67 2811 1.38E+06 0.260 1500 Nan DS 4199.1 5.0 0.64 2671 1.14E+06 0.270 1500 Nan DS 4204.1 2.0 0.67 2809 1.56E+06 0.260 1500 Nan DS 4206.1 4.0 0.64 2688 8.96E+05 0.270 1500 Nan DS 4210.1 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4212.1 10.0 0.63 2644 9.81E+05 0.270 1500 Nan DS 4222.1 4.0 0.65 2763 1.63E+06 0.260 1500 Nan DS 4226.1 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4230.1 9.5 0.66 2784 1.33E+06 0.260 1500 Nan DS 4239.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4241.6 9.5 0.70 2975 1.69E+06 0.260 1500 Nan DS 4251.1 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4253.1 2.0 0.71 3002 2.67E+06 0.230 2500 Nan DS 4255.1 2.0 0.64 2707 1.09E+06 0.270 1500 Shale 4257.1 2.0 0.71 3005 2.67E+06 0.230 2500 Nan DS 4259.1 4.0 0.67 2844 1.29E+06 0.260 1500 Shale 4263.1 19.5 0.71 3015 2.67E+06 0.230 2500 Nan DS 4282.6 2.0 0.66 2820 1.36E+06 0.260 1500 Shale 4284.6 2.0 0.71 3024 2.67E+06 0.230 2500 Nan DS 4286.6 8.0 0.67 2855 1.37E+06 0.260 1500 Nan DS 4294.6 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4302.6 20.0 0.71 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 18 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4015.8 10.0 0.001 1.0 1890 4025.8 15.0 0.001 1.0 1898 4040.8 15.3 0.005 10.0 1905 4056.1 19.5 30.655 23.7 1915 4075.6 2.0 5.000 10.0 1924 4077.6 1.5 2.095 16.9 1925 4079.1 4.5 48.388 26.6 1926 4083.6 3.5 0.478 12.4 1928 4087.1 14.5 15.008 17.7 1930 4101.6 1.5 3.661 17.6 1937 4103.1 12.5 34.723 23.9 1937 4115.6 2.0 1.697 15.6 1943 4117.6 9.0 54.319 24.4 1944 4126.6 7.0 3.610 14.8 1948 4133.6 9.0 22.986 20.4 1952 4142.6 3.5 0.835 14.0 1956 4146.1 5.0 65.392 23.4 1957 4151.1 2.0 0.006 10.5 1960 4153.1 10.5 100.832 25.6 1961 4163.6 3.5 17.434 20.5 1966 4167.1 2.0 161.343 26.3 1967 4169.1 5.5 4.627 18.4 1968 4174.6 3.5 5.075 14.8 1971 4178.1 3.5 8.651 19.4 1972 4181.6 5.5 10.205 16.0 1974 4187.1 10.5 17.356 20.1 1977 4197.6 1.5 3.106 14.8 1982 4199.1 5.0 52.863 20.6 1982 4204.1 2.0 2.277 14.1 1985 4206.1 4.0 122.778 23.1 1986 4210.1 2.0 0.333 12.5 1987 4212.1 10.0 39.939 21.2 1988 4222.1 4.0 0.748 13.3 1993 4226.1 4.0 0.009 10.9 1995 4230.1 9.5 5.399 16.7 1997 4239.6 2.0 160.618 24.9 2001 4241.6 9.5 0.033 11.5 2002 4251.1 2.0 6.733 16.2 2007 4253.1 2.0 0.001 1.0 2008 4255.1 2.0 29.480 19.6 2009 4257.1 2.0 0.001 1.0 2009 4259.1 4.0 8.473 16.6 2010 4263.1 19.5 0.001 1.0 2012 4282.6 2.0 2.185 16.4 2021 4284.6 2.0 0.001 1.0 2022 4286.6 8.0 2.645 15.9 2023 4294.6 8.0 2.026 14.4 2027 4302.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 19 SLB Private Attachment K Section 14: Propped Fracture Schedule (Stage 5; 15256 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 260.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 FLUSH 40 WF125 231.4 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1253.5 of YF125ST 231800 lb of % PAD Clean 20.7 % PAD Dirty 17.4 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 260.0 260 260 260 0 0 3810 6.5 6.5 1.0 PPA 172.5 432 180 440 7243 7243 3819 4.5 11.0 3.0 PPA 176.8 609 200 640 22275 29518 3981 5.0 16.0 5.0 PPA 188.7 798 230 870 39628 69147 4567 5.8 21.8 7.0 PPA 176.1 974 230 1100 51763 120909 5232 5.8 27.5 9.0 PPA 154.2 1128 215 1315 58305 179214 5724 5.4 32.9 10.0 PPA 125.2 1253 180 1495 52586 231800 5978 4.5 37.4 FLUSH 231.4 1485 231 1726 0 231800 5913 5.8 43.2 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 330.5 ft with an average conductivity (Kfw) of 17843.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 20 SLB Private Attachment K Section 15: Propped Fracture Simulation (Stage 5; 15256 ft MD) Initial Fracture Top TVD 4022.8 ft Initial Fracture Bottom TVD 4250.2 ft Propped Fracture Half-Length 330.5 ft EOJ Hyd Height at Well 227.4 ft Average Propped Width 0.201 in Net Pressure 391 psi Max Surface Pressure 6044 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 82.6 9.5 0.228 132.2 1.98 274.8 20847 82.6 165.2 9.1 0.246 208.7 2.22 258.3 22184 165.2 247.9 7.2 0.202 176.3 1.86 302.5 17951 247.9 330.5 2.8 0.137 103.6 1.33 361.3 11618 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 21 SLB Private Attachment K Section 16: Zone Data (Stage 6; 14837 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 4020.8 10.0 0.73 2937 1.46E+06 0.220 1000 Shale 4030.8 15.0 0.70 2807 1.76E+06 0.220 1000 Nanushuk 3 SS 4045.8 15.3 0.68 2748 1.90E+06 0.220 1000 Top Nan CS 4061.1 19.5 0.64 2595 9.00E+05 0.270 1000 Nan SS 4080.6 2.0 0.69 2820 2.67E+06 0.230 2500 Nan CS 4082.6 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4084.1 4.5 0.62 2517 6.44E+05 0.280 1000 Nan DS 4088.6 3.5 0.69 2826 1.77E+06 0.260 1500 Nan DS 4092.1 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4106.6 1.5 0.66 2706 1.15E+06 0.270 1000 Nan CS 4108.1 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4120.6 2.0 0.65 2675 1.40E+06 0.260 1500 Nan CS 4122.6 9.0 0.61 2505 8.54E+05 0.270 1000 Nan DS 4131.6 7.0 0.67 2755 1.40E+06 0.260 1500 Nan DS 4138.6 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4147.6 3.5 0.66 2720 1.69E+06 0.260 1500 Nan DS 4151.1 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4156.1 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4158.1 10.5 0.63 2607 7.36E+05 0.270 1000 Nan CS 4168.6 3.5 0.65 2705 1.10E+06 0.270 1000 Nan CS 4172.1 2.0 0.63 2614 6.70E+05 0.280 1000 Nan CS 4174.1 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4179.6 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4183.1 3.5 0.65 2701 1.19E+06 0.270 1500 Nan DS 4186.6 5.5 0.70 2928 1.42E+06 0.260 1500 Nan CS 4192.1 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4202.6 1.5 0.67 2811 1.38E+06 0.260 1500 Nan DS 4204.1 5.0 0.63 2671 1.14E+06 0.270 1500 Nan DS 4209.1 2.0 0.67 2809 1.56E+06 0.260 1500 Nan DS 4211.1 4.0 0.64 2688 8.96E+05 0.270 1500 Nan DS 4215.1 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4217.1 10.0 0.63 2647 9.81E+05 0.270 1500 Nan DS 4227.1 4.0 0.65 2766 1.63E+06 0.260 1500 Nan DS 4231.1 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4235.1 9.5 0.66 2784 1.33E+06 0.260 1500 Nan DS 4244.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4246.6 9.5 0.70 2975 1.69E+06 0.260 1500 Nan DS 4256.1 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4258.1 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4260.1 2.0 0.64 2710 1.09E+06 0.270 1500 Shale 4262.1 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4264.1 4.0 0.67 2844 1.29E+06 0.260 1500 Shale 4268.1 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4287.6 2.0 0.66 2820 1.36E+06 0.260 1500 Shale 4289.6 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4291.6 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4299.6 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4307.6 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 22 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4020.8 10.0 0.001 1.0 1890 4030.8 15.0 0.001 1.0 1898 4045.8 15.3 0.005 10.0 1905 4061.1 19.5 30.655 23.7 1915 4080.6 2.0 5.000 10.0 1924 4082.6 1.5 2.095 16.9 1925 4084.1 4.5 48.388 26.6 1926 4088.6 3.5 0.478 12.4 1928 4092.1 14.5 15.008 17.7 1930 4106.6 1.5 3.661 17.6 1937 4108.1 12.5 34.723 23.9 1937 4120.6 2.0 1.697 15.6 1943 4122.6 9.0 54.319 24.4 1944 4131.6 7.0 3.610 14.8 1948 4138.6 9.0 22.986 20.4 1952 4147.6 3.5 0.835 14.0 1956 4151.1 5.0 65.392 23.4 1957 4156.1 2.0 0.006 10.5 1960 4158.1 10.5 100.832 25.6 1961 4168.6 3.5 17.434 20.5 1966 4172.1 2.0 161.343 26.3 1967 4174.1 5.5 4.627 18.4 1968 4179.6 3.5 5.075 14.8 1971 4183.1 3.5 8.651 19.4 1972 4186.6 5.5 10.205 16.0 1974 4192.1 10.5 17.356 20.1 1977 4202.6 1.5 3.106 14.8 1982 4204.1 5.0 52.863 20.6 1982 4209.1 2.0 2.277 14.1 1985 4211.1 4.0 122.778 23.1 1986 4215.1 2.0 0.333 12.5 1987 4217.1 10.0 39.939 21.2 1988 4227.1 4.0 0.748 13.3 1993 4231.1 4.0 0.009 10.9 1995 4235.1 9.5 5.399 16.7 1997 4244.6 2.0 160.618 24.9 2001 4246.6 9.5 0.033 11.5 2002 4256.1 2.0 6.733 16.2 2007 4258.1 2.0 0.001 1.0 2008 4260.1 2.0 29.480 19.6 2009 4262.1 2.0 0.001 1.0 2009 4264.1 4.0 8.473 16.6 2010 4268.1 19.5 0.001 1.0 2012 4287.6 2.0 2.185 16.4 2021 4289.6 2.0 0.001 1.0 2022 4291.6 8.0 2.645 15.9 2023 4299.6 8.0 2.026 14.4 2027 4307.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 23 SLB Private Attachment K Section 17: Propped Fracture Schedule (Stage 6; 14837 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 225.0 25 0 1.0 PPA Scou 40 YF125ST 57.5 25 1 3.0 PPA Scou 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 3.0 PPA 40 YF125ST 190.0 25 3 5.0 PPA 40 YF125ST 196.9 25 5 7.0 PPA 40 YF125ST 183.7 25 7 9.0 PPA 40 YF125ST 157.8 25 9 10.0 PPA 40 YF125ST 139.1 25 10 FLUSH 40 YF125ST 226.0 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1,714.1 bbl of YF125ST 245046 lb of 15764 lb of % PAD Clean 15.1 % PAD Dirty 12.8 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 225.0 225 225 225 0 0 3748 5.6 5.6 1.0 PPA Scou 57.5 282 60 285 2414 2414 3748 1.5 7.1 3.0 PPA Scou 105.9 388 120 405 13349 15764 3793 3.0 10.1 Resume PAD 50.0 438 50 455 0 15764 3967 1.3 11.4 1.0 PPA 182.0 620 190 645 7645 23409 4021 4.8 16.1 3.0 PPA 190.0 811 215 860 23946 47355 3942 5.4 21.5 5.0 PPA 196.9 1007 240 1100 41351 88706 4530 6.0 27.5 7.0 PPA 183.7 1191 240 1340 54013 142720 5166 6.0 33.5 Job Execution Step Name Pad Percentages Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 40/70 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 323.3 ft with an average conductivity (Kfw) of 19959.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 24 SLB Private Attachment K Section 18: Propped Fracture Simulation (Stage 6; 14837 ft MD) Initial Fracture Top TVD 4028.2 ft Initial Fracture Bottom TVD 4255 ft Propped Fracture Half-Length 323.3 ft EOJ Hyd Height at Well 226.8 ft Average Propped Width 0.223 in Net Pressure 432 psi Max Surface Pressure 5920 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 80.8 9.6 0.32 186.3 2.84 196.2 29789 80.8 161.6 8.3 0.299 186.3 2.7 207.9 27358 161.6 242.5 5.9 0.226 185.4 2.07 270.1 20292 242.5 323.3 0.9 0.073 134.9 0.82 399.8 5463 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 25 SLB Private Attachment K Section 19: Zone Data (Stage 7; 14256 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 4028.8 10.0 0.73 2937 1.46E+06 0.220 1000 Shale 4038.8 15.0 0.70 2812 1.76E+06 0.220 1000 Nanushuk 3 SS 4053.8 15.3 0.68 2754 1.90E+06 0.220 1000 Top Nan CS 4069.1 19.5 0.64 2595 9.00E+05 0.270 1000 Nan SS 4088.6 2.0 0.69 2826 2.67E+06 0.230 2500 Nan CS 4090.6 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4092.1 4.5 0.62 2522 6.44E+05 0.280 1000 Nan DS 4096.6 3.5 0.69 2832 1.77E+06 0.260 1500 Nan DS 4100.1 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4114.6 1.5 0.66 2706 1.15E+06 0.270 1000 Nan CS 4116.1 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4128.6 2.0 0.65 2680 1.40E+06 0.260 1500 Nan CS 4130.6 9.0 0.61 2510 8.54E+05 0.270 1000 Nan DS 4139.6 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4146.6 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4155.6 3.5 0.65 2720 1.69E+06 0.260 1500 Nan DS 4159.1 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4164.1 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4166.1 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4176.6 3.5 0.65 2705 1.10E+06 0.270 1000 Nan CS 4180.1 2.0 0.63 2614 6.70E+05 0.280 1000 Nan CS 4182.1 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4187.6 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4191.1 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4194.6 5.5 0.70 2928 1.42E+06 0.260 1500 Nan CS 4200.1 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4210.6 1.5 0.67 2811 1.38E+06 0.260 1500 Nan DS 4212.1 5.0 0.63 2671 1.14E+06 0.270 1500 Nan DS 4217.1 2.0 0.67 2809 1.56E+06 0.260 1500 Nan DS 4219.1 4.0 0.64 2688 8.96E+05 0.270 1500 Nan DS 4223.1 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4225.1 10.0 0.63 2652 9.81E+05 0.270 1500 Nan DS 4235.1 4.0 0.65 2771 1.63E+06 0.260 1500 Nan DS 4239.1 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4243.1 9.5 0.66 2784 1.33E+06 0.260 1500 Nan DS 4252.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4254.6 9.5 0.70 2975 1.69E+06 0.260 1500 Nan DS 4264.1 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4266.1 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4268.1 2.0 0.64 2715 1.09E+06 0.270 1500 Shale 4270.1 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4272.1 4.0 0.67 2844 1.29E+06 0.260 1500 Shale 4276.1 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4295.6 2.0 0.66 2820 1.36E+06 0.260 1500 Shale 4297.6 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4299.6 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4307.6 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4315.6 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 26 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4028.8 10.0 0.001 1.0 1890 4038.8 15.0 0.001 1.0 1898 4053.8 15.3 0.005 10.0 1905 4069.1 19.5 30.655 23.7 1915 4088.6 2.0 5.000 10.0 1924 4090.6 1.5 2.095 16.9 1925 4092.1 4.5 48.388 26.6 1926 4096.6 3.5 0.478 12.4 1928 4100.1 14.5 15.008 17.7 1930 4114.6 1.5 3.661 17.6 1937 4116.1 12.5 34.723 23.9 1937 4128.6 2.0 1.697 15.6 1943 4130.6 9.0 54.319 24.4 1944 4139.6 7.0 3.610 14.8 1948 4146.6 9.0 22.986 20.4 1952 4155.6 3.5 0.835 14.0 1956 4159.1 5.0 65.392 23.4 1957 4164.1 2.0 0.006 10.5 1960 4166.1 10.5 100.832 25.6 1961 4176.6 3.5 17.434 20.5 1966 4180.1 2.0 161.343 26.3 1967 4182.1 5.5 4.627 18.4 1968 4187.6 3.5 5.075 14.8 1971 4191.1 3.5 8.651 19.4 1972 4194.6 5.5 10.205 16.0 1974 4200.1 10.5 17.356 20.1 1977 4210.6 1.5 3.106 14.8 1982 4212.1 5.0 52.863 20.6 1982 4217.1 2.0 2.277 14.1 1985 4219.1 4.0 122.778 23.1 1986 4223.1 2.0 0.333 12.5 1987 4225.1 10.0 39.939 21.2 1988 4235.1 4.0 0.748 13.3 1993 4239.1 4.0 0.009 10.9 1995 4243.1 9.5 5.399 16.7 1997 4252.6 2.0 160.618 24.9 2001 4254.6 9.5 0.033 11.5 2002 4264.1 2.0 6.733 16.2 2007 4266.1 2.0 0.001 1.0 2008 4268.1 2.0 29.480 19.6 2009 4270.1 2.0 0.001 1.0 2009 4272.1 4.0 8.473 16.6 2010 4276.1 19.5 0.001 1.0 2012 4295.6 2.0 2.185 16.4 2021 4297.6 2.0 0.001 1.0 2022 4299.6 8.0 2.645 15.9 2023 4307.6 8.0 2.026 14.4 2027 4315.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 27 SLB Private Attachment K Section 20: Propped Fracture Schedule (Stage 7; 14256 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 238.0 25 0 1.0 PPA Scou 40 YF125ST 57.5 25 1 3.0 PPA Scou 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 FLUSH 40 YF125ST 216.2 25 0 Please note that this pumping schedule is under-displaced by 1 bbl. 1763.1 bbl of YF125ST 225010 lb of 15763 lb of % PAD Clean 15.4 % PAD Dirty 13.2 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 238.0 238 238 238 0 0 3625 6.0 6.0 1.0 PPA Scou 57.5 295 60 298 2413 2413 3631 1.5 7.5 3.0 PPA Scou 105.9 401 120 418 13349 15763 3712 3.0 10.5 Resume PAD 50.0 451 50 468 0 15763 3883 1.3 11.7 1.0 PPA 182.0 633 190 658 7645 23408 3906 4.8 16.5 2.0 PPA 202.3 836 220 878 16993 40401 3768 5.5 22.0 4.0 PPA 204.2 1040 240 1118 34313 74714 4136 6.0 28.0 6.0 PPA 190.1 1230 240 1358 47902 122615 4712 6.0 34.0 8.0 PPA 177.8 1408 240 1598 59728 182344 5267 6.0 40.0 10.0 PPA 139.1 1547 200 1798 58429 240773 5579 5.0 45.0 FLUSH 216.2 1763 216 2014 0 240773 5100 5.4 50.4 Job Execution Step Name Pad Percentages Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 40/70 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 306.9 ft with an average conductivity (Kfw) of 17873.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 28 SLB Private Attachment K Section 21: Propped Fracture Simulation (Stage 7; 14256 ft MD) Initial Fracture Top TVD 4034.7 ft Initial Fracture Bottom TVD 4267.6 ft Propped Fracture Half-Length 306.9 ft EOJ Hyd Height at Well 232.9 ft Average Propped Width 0.205 in Net Pressure 280 psi Max Surface Pressure 5673 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 76.7 8.8 0.281 193.8 2.49 268.4 25448 76.7 153.5 7.5 0.26 193.8 2.32 295 23074 153.5 230.2 5.6 0.2 194.3 1.78 361.1 17491 230.2 306.9 1.7 0.101 169.6 0.96 508.8 8216 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 29 SLB Private Attachment K Section 22: Zone Data (Stage 8; 13754 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 4036.0 10.0 0.73 2937 1.46E+06 0.220 1000 Shale 4046.0 15.0 0.70 2817 1.76E+06 0.220 1000 Nanushuk 3 SS 4061.0 15.3 0.68 2759 1.90E+06 0.220 1000 Top Nan CS 4076.3 19.5 0.64 2595 9.00E+05 0.270 1000 Nan SS 4095.8 2.0 0.69 2831 2.67E+06 0.230 2500 Nan CS 4097.8 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4099.3 4.5 0.62 2527 6.44E+05 0.280 1000 Nan DS 4103.8 3.5 0.69 2837 1.77E+06 0.260 1500 Nan DS 4107.3 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4121.8 1.5 0.66 2706 1.15E+06 0.270 1000 Nan CS 4123.3 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4135.8 2.0 0.65 2685 1.40E+06 0.260 1500 Nan CS 4137.8 9.0 0.61 2514 8.54E+05 0.270 1000 Nan DS 4146.8 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4153.8 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4162.8 3.5 0.65 2720 1.69E+06 0.260 1500 Nan DS 4166.3 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4171.3 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4173.3 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4183.8 3.5 0.65 2705 1.10E+06 0.270 1000 Nan CS 4187.3 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4189.3 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4194.8 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4198.3 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4201.8 5.5 0.70 2928 1.42E+06 0.260 1500 Nan CS 4207.3 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4217.8 1.5 0.67 2811 1.38E+06 0.260 1500 Nan DS 4219.3 5.0 0.63 2671 1.14E+06 0.270 1500 Nan DS 4224.3 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4226.3 4.0 0.64 2688 8.96E+05 0.270 1500 Nan DS 4230.3 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4232.3 10.0 0.63 2657 9.81E+05 0.270 1500 Nan DS 4242.3 4.0 0.65 2776 1.63E+06 0.260 1500 Nan DS 4246.3 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4250.3 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4259.8 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4261.8 9.5 0.70 2975 1.69E+06 0.260 1500 Nan DS 4271.3 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4273.3 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4275.3 2.0 0.64 2720 1.09E+06 0.270 1500 Shale 4277.3 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4279.3 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4283.3 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4302.8 2.0 0.66 2820 1.36E+06 0.260 1500 Shale 4304.8 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4306.8 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4314.8 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4322.8 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 30 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4036.0 10.0 0.001 1.0 1890 4046.0 15.0 0.001 1.0 1898 4061.0 15.3 0.005 10.0 1905 4076.3 19.5 30.655 23.7 1915 4095.8 2.0 5.000 10.0 1924 4097.8 1.5 2.095 16.9 1925 4099.3 4.5 48.388 26.6 1926 4103.8 3.5 0.478 12.4 1928 4107.3 14.5 15.008 17.7 1930 4121.8 1.5 3.661 17.6 1937 4123.3 12.5 34.723 23.9 1937 4135.8 2.0 1.697 15.6 1943 4137.8 9.0 54.319 24.4 1944 4146.8 7.0 3.610 14.8 1948 4153.8 9.0 22.986 20.4 1952 4162.8 3.5 0.835 14.0 1956 4166.3 5.0 65.392 23.4 1957 4171.3 2.0 0.006 10.5 1960 4173.3 10.5 100.832 25.6 1961 4183.8 3.5 17.434 20.5 1966 4187.3 2.0 161.343 26.3 1967 4189.3 5.5 4.627 18.4 1968 4194.8 3.5 5.075 14.8 1971 4198.3 3.5 8.651 19.4 1972 4201.8 5.5 10.205 16.0 1974 4207.3 10.5 17.356 20.1 1977 4217.8 1.5 3.106 14.8 1982 4219.3 5.0 52.863 20.6 1982 4224.3 2.0 2.277 14.1 1985 4226.3 4.0 122.778 23.1 1986 4230.3 2.0 0.333 12.5 1987 4232.3 10.0 39.939 21.2 1988 4242.3 4.0 0.748 13.3 1993 4246.3 4.0 0.009 10.9 1995 4250.3 9.5 5.399 16.7 1997 4259.8 2.0 160.618 24.9 2001 4261.8 9.5 0.033 11.5 2002 4271.3 2.0 6.733 16.2 2007 4273.3 2.0 0.001 1.0 2008 4275.3 2.0 29.480 19.6 2009 4277.3 2.0 0.001 1.0 2009 4279.3 4.0 8.473 16.6 2010 4283.3 19.5 0.001 1.0 2012 4302.8 2.0 2.185 16.4 2021 4304.8 2.0 0.001 1.0 2022 4306.8 8.0 2.645 15.9 2023 4314.8 8.0 2.026 14.4 2027 4322.8 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 31 SLB Private Attachment K Section 23: Propped Fracture Schedule (Stage 8; 13754 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 230.0 25 0 1.0 PPA Scou 40 YF125ST 57.5 25 1 3.0 PPA Scou 40 YF125ST 106.0 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 FLUSH 40 YF125ST 208.5 25 0 Please note that this pumping schedule is under-displaced by 1 bbl. 1747.5 bbl of YF125ST 225011 lb of 15763 lb of % PAD Clean 14.9 % PAD Dirty 12.8 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 230.0 230 230 230 0 0 3530 5.8 5.8 1.0 PPA Scou 57.5 287 60 290 2413 2413 3535 1.5 7.2 3.0 PPA Scou 106.0 393 120 410 13350 15763 3611 3.0 10.2 Resume PAD 50.0 443 50 460 0 15763 3773 1.3 11.5 1.0 PPA 182.0 625 190 650 7645 23408 3798 4.7 16.2 2.0 PPA 202.3 828 220 870 16992 40400 3661 5.5 21.7 4.0 PPA 204.2 1032 240 1110 34312 74712 4009 6.0 27.7 6.0 PPA 190.1 1222 240 1350 47904 122616 4558 6.0 33.7 8.0 PPA 177.8 1400 240 1590 59728 182344 5091 6.0 39.7 10.0 PPA 139.1 1539 200 1790 58430 240774 5391 5.0 44.7 FLUSH 208.5 1747 209 1999 0 240774 4954 5.2 50.0 Job Execution Step Name Pad Percentages Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 40/70 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 300.5 ft with an average conductivity (Kfw) of 18338.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 32 SLB Private Attachment K Section 24: Propped Fracture Simulation (Stage 8; 13754 ft MD) Initial Fracture Top TVD 4042.1 ft Initial Fracture Bottom TVD 4274.9 ft Propped Fracture Half-Length 300.5 ft EOJ Hyd Height at Well 232.7 ft Average Propped Width 0.21 in Net Pressure 287 psi Max Surface Pressure 5484 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 75.1 8.7 0.286 195.7 2.54 211.4 25987 75.1 150.3 7.5 0.266 195.7 2.38 231 23648 150.3 225.4 5.6 0.21 196.2 1.88 281.1 18407 225.4 300.5 2 0.101 182.7 0.96 486.3 8110 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 33 SLB Private Attachment K Section 25: Zone Data (Stage 9; 13251 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 4043.0 10.0 0.73 2937 1.46E+06 0.220 1000 Shale 4053.0 15.0 0.70 2822 1.76E+06 0.220 1000 Nanushuk 3 SS 4068.0 15.3 0.68 2763 1.90E+06 0.220 1000 Top Nan CS 4083.3 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4102.8 2.0 0.69 2836 2.67E+06 0.230 2500 Nan CS 4104.8 1.5 0.65 2655 1.29E+06 0.260 1000 Nan CS 4106.3 4.5 0.62 2531 6.44E+05 0.280 1000 Nan DS 4110.8 3.5 0.69 2842 1.77E+06 0.260 1500 Nan DS 4114.3 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4128.8 1.5 0.66 2706 1.15E+06 0.270 1000 Nan CS 4130.3 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4142.8 2.0 0.65 2689 1.40E+06 0.260 1500 Nan CS 4144.8 9.0 0.61 2519 8.54E+05 0.270 1000 Nan DS 4153.8 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4160.8 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4169.8 3.5 0.65 2720 1.69E+06 0.260 1500 Nan DS 4173.3 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4178.3 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4180.3 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4190.8 3.5 0.65 2705 1.10E+06 0.270 1000 Nan CS 4194.3 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4196.3 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4201.8 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4205.3 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4208.8 5.5 0.70 2928 1.42E+06 0.260 1500 Nan CS 4214.3 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4224.8 1.5 0.67 2811 1.38E+06 0.260 1500 Nan DS 4226.3 5.0 0.63 2671 1.14E+06 0.270 1500 Nan DS 4231.3 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4233.3 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4237.3 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4239.3 10.0 0.63 2661 9.81E+05 0.270 1500 Nan DS 4249.3 4.0 0.65 2780 1.63E+06 0.260 1500 Nan DS 4253.3 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4257.3 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4266.8 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4268.8 9.5 0.70 2975 1.69E+06 0.260 1500 Nan DS 4278.3 2.0 0.66 2812 1.37E+06 0.260 1500 Shale 4280.3 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4282.3 2.0 0.64 2724 1.09E+06 0.270 1500 Shale 4284.3 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4286.3 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4290.3 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4309.8 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4311.8 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4313.8 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4321.8 8.0 0.66 2841 1.56E+06 0.260 1500 Shale 4329.8 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 34 SLB Private Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4043.0 10.0 0.001 1.0 1890 4053.0 15.0 0.001 1.0 1898 4068.0 15.3 0.005 10.0 1905 4083.3 19.5 30.655 23.7 1915 4102.8 2.0 5.000 10.0 1924 4104.8 1.5 2.095 16.9 1925 4106.3 4.5 48.388 26.6 1926 4110.8 3.5 0.478 12.4 1928 4114.3 14.5 15.008 17.7 1930 4128.8 1.5 3.661 17.6 1937 4130.3 12.5 34.723 23.9 1937 4142.8 2.0 1.697 15.6 1943 4144.8 9.0 54.319 24.4 1944 4153.8 7.0 3.610 14.8 1948 4160.8 9.0 22.986 20.4 1952 4169.8 3.5 0.835 14.0 1956 4173.3 5.0 65.392 23.4 1957 4178.3 2.0 0.006 10.5 1960 4180.3 10.5 100.832 25.6 1961 4190.8 3.5 17.434 20.5 1966 4194.3 2.0 161.343 26.3 1967 4196.3 5.5 4.627 18.4 1968 4201.8 3.5 5.075 14.8 1971 4205.3 3.5 8.651 19.4 1972 4208.8 5.5 10.205 16.0 1974 4214.3 10.5 17.356 20.1 1977 4224.8 1.5 3.106 14.8 1982 4226.3 5.0 52.863 20.6 1982 4231.3 2.0 2.277 14.1 1985 4233.3 4.0 122.778 23.1 1986 4237.3 2.0 0.333 12.5 1987 4239.3 10.0 39.939 21.2 1988 4249.3 4.0 0.748 13.3 1993 4253.3 4.0 0.009 10.9 1995 4257.3 9.5 5.399 16.7 1997 4266.8 2.0 160.618 24.9 2001 4268.8 9.5 0.033 11.5 2002 4278.3 2.0 6.733 16.2 2007 4280.3 2.0 0.001 1.0 2008 4282.3 2.0 29.480 19.6 2009 4284.3 2.0 0.001 1.0 2009 4286.3 4.0 8.473 16.6 2010 4290.3 19.5 0.001 1.0 2012 4309.8 2.0 2.185 16.4 2021 4311.8 2.0 0.001 1.0 2022 4313.8 8.0 2.645 15.9 2023 4321.8 8.0 2.026 14.4 2027 4329.8 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 35 SLB Private Attachment K Section 26: Propped Fracture Schedule (Stage 9; 13251 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 182.0 25 1 3.0 PPA 40 YF125ST 190.0 25 3 5.0 PPA 40 YF125ST 196.9 25 5 7.0 PPA 40 YF125ST 183.7 25 7 9.0 PPA 40 YF125ST 157.8 25 9 10.0 PPA 40 YF125ST 132.2 25 10 FLUSH 40 WF125 201.9 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1292.7 bbl of YF125ST 201.9 bbl of WF125 242124 lb of % PAD Clean 19.3 % PAD Dirty 16.2 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3641 6.3 6.3 1.0 PPA 182.0 432 190 440 7645 7645 3640 4.8 11.0 3.0 PPA 190.0 622 215 655 23946 31591 3820 5.4 16.4 5.0 PPA 196.9 819 240 895 41351 72943 4386 6.0 22.4 7.0 PPA 183.7 1003 240 1135 54013 126956 4896 6.0 28.4 9.0 PPA 157.8 1161 220 1355 59661 186617 5210 5.5 33.9 10.0 PPA 132.2 1293 190 1545 55508 242124 5356 4.8 38.6 FLUSH 201.9 1495 202 1747 0 242124 5277 5.0 43.7 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 270.3 ft with an average conductivity (Kfw) of 19423.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 36 SLB Private Attachment K Section 27: Propped Fracture Simulation (Stage 9; 13251 ft MD) Initial Fracture Top TVD 4047.3 ft Initial Fracture Bottom TVD 4290.1 ft Propped Fracture Half-Length 270.3 ft EOJ Hyd Height at Well 242.8 ft Average Propped Width 0.223 in Net Pressure 181 psi Max Surface Pressure 5390 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 67.6 9.9 0.246 156.6 2.13 204 22093 67.6 135.1 8.9 0.245 222.2 2.16 214.1 21458 135.1 202.7 8.3 0.236 208.5 2.12 218.6 20677 202.7 270.3 3.8 0.175 173 1.6 269.5 15011 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 37 SLB Private Attachment K Santos USA and Baker Hughes Confidential Page 1 © 2018 Baker Hughes, LLC - All rights reserved. LLWD Qualitative Cement Bond Log Evaluation Report Well Name, Section: NDBi-016, 9 5/8” Liner Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: Reservoir Technical Services Alaska Version: Preliminary Report Santos USA and Baker Hughes Confidential Page 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Tool Diagram .......................................................................................................................................................................................................... 7 Methodology of LWD Cement Bond Log Evaluation .................................................................................................................8 Log Screen Captures ...................................................................................................................................................................................... 13 Santos USA and Baker Hughes Confidential Page 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMER THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. Santos USA and Baker Hughes Confidential Page 4 Executive Summary Cement Bond Logging with LWD Acoustic (Sonic) tool SoundTrak was performed after drilling of 8 ½” section. Logs were acquired while pulling out of hole across 9 5/8” liner in upward direction. The objective and plan were to cover with CBL logs to evaluate the first stage cementing from the 9 5/8” Liner shoe to the planned TOC of 9350’ MD. Cement Bond Index (BI) curve was computed and presented in the log plot showing color gradation from good cement bond (brown) to poor cement (blue). The following values were used by interpreter to differentiate intervals of good bond (curve value above 0.8) to partial (0.2 to 0.8) and poor (lower than 0.2). Summaries of initial pre-job logging plan and Cement Bond Index interpretation are outlined below. Logging Plan Summary A dedicated run, BHA#4 was made to log the top cement. Run in hole to 12,900ft MD, Down link to the SoundTrak tool and start logging while coming out to the liner shoe at 12,856ft MD to initiate top of cement mode and to log the cement in the 9 5/8” Liner at 400 gpm and 60-120 rpm (per Bakerhughes recommendation). x Log cement from 9-5/8” shoe (12,900’ MD) to 9,350’ MD planned top of cement. Log up at 1,200 fph. x Log free pipe from 9,350’ to 8,500’ MD (850’ of free pipe) at 1,200 fph. LWD logging was optimized to gain higher efficiency and reduce overall rig time by modifying acquisition parameters and logging at 1200 ft/hr entire well interval. Santos USA and Baker Hughes Confidential Page 5 Interpretation Summary The Intermediate section was drilled and 9 5/8” Casing shoe was set at 12,856ft. A dedicated run, BHA#4 was made to log the cement top. Run in hole to 12,900ft MD, started logging while coming out to the liner shoe at 12,856ft MD. Following observations are summarized below by interval. Please note that Bond Index curve (BI) and color coding in combination with other data on the log can be used for more detailed interval inspection to draw conclusions on zonal isolation of narrower intervals. Overall, 3 main zones were defined as listed below, with more detailed interpretation within each zone presented in the table that follows. - 8,506’-9,058’: Poor to no cement presence above 9,058ft. - 9,058’-9,234’: Poor to partial presence above 9,234ft. - 9,234’ to 12,842’ Partial to Good. Mostly Good, with some intervals of partial cement presence. For more detailed description of each interval please refer to the table below summarizing Interpretation results. 9,058’-9,234’: Poor to partial presence above 9,234ft. Santos USA and Baker Hughes Confidential Page 6 Santos USA and Baker Hughes Confidential Page 7 Tool Diagram Santos USA and Baker Hughes Confidential Page 8 Methodology of LWD Cement Bond Log Evaluation Before the arrival of more advanced Wireline technologies offering azimuthal coverage of the casing to cement and cement to formation bonding, oil and gas operators have been relying on traditional non-azimuthal CBL, Cement Bond Log, technique, that is being run successfully to date. Wireline Acoustic (Sonic) tool’s CBL measurement principle relies on detecting and measuring first “casing ringing” amplitude reflected from the casing wall. The idea is that free pipe (with cement absence) would “ring” freely creating high Casing Ringing Amplitude, whereas well cemented casing would result in dampened first arrival and thus indicate well cemented pipe. Traditional Wireline tool relies on the arrival of the sound detected at the receiver spaced at 3 ft for CBL Amplitude and for the one from the 5 ft spaced receiver for VDL (Variable Density Log). Figure 1: Traditional Wireline CBL technique Santos USA and Baker Hughes Confidential Page 9 LWD Acoustic (Sonic) tool is using the same principle for CBL measurement. It is also non- azimuthal. However, the one difference is that receiver spacing is longer and all measurements are based on the 10.7 ft receiver spacing for CBL Amplitude. See figures below for the main principle behind cemented vs free pipe detection in traditional CBL measurement. Figure 2: CBL concept in "free" pipe Figure 3: CBL concept in cemented pipe Santos USA and Baker Hughes Confidential Page 10 Figure 4: General CBL concept and corresponding log example Figure 5: LWD Acoustic (Sonic) tool and LWD CBL concept Current traditional offering of LWD Acoustic (Sonic) tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling trip typically on the way out of casing after drilling is completed. Santos USA and Baker Hughes Confidential Page 11 Baker Hughes offers both traditional TOC service and a more advanced workflow of providing Cement Bond Index. This Cement Bond Index is a relative Cement Quality Indicator helping operators to still acquire positive zonal isolation information in wells where running Wireline could be challenging and / or would otherwise increase overall rig time. To convert casing amplitude to cement bond index (BI), two reference points are required: -Free casing - 100% bonded point Figure 6: Cement Bond Index computation concept Traditionally as part of the CBL logging deliverable, Bond Index (BI) is computed and displayed in the log. Values above 80% BI are typically seen as “good" cement, whereas values below 80% are typically seen as either "poor," contaminated or channeled cement. Note however, that the TR spacing (10.66 ft) for LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality check must be carried out to validate the data, because If the casing amplitude in these well bonded intervals is below noise level, the 100% bonded reference point might be incorrect and the “BI” could be over-estimated, reducing quantitative precision of the measurement. Additionally, Cement Evaluation with LWD SoundTrak tool would be ideal in standard cements with slurry density of equal or greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. For example, detection of behind casing open hole DT from waveforms could confirm that proper cement is present. Santos USA and Baker Hughes Confidential Page 12 Furthermore, adding this service can increase operational efficiency since it can be done in the same drilling trip on the way out and logging speed for top of cement detection and CBL evaluation can be as high as ~1500 ft/hr still providing good data quality. With combination of casing mode semblance (SV) and formation arrival in correlogram, TOC can be detected in Real-Time. Good agreement between RT and memory TOC can be seen in the figure below. Figure 7: LWD capability of Real-Time Top of Cement acquisition This method has limitations though as it has no azimuthal coverage and can not identify micro channeling. It is not a replacement for quantitative cement evaluation tools such as SBT, InTex, or CICM Santos USA and Baker Hughes Confidential Page 13 Log Screen Captures Following figures contain interpretation observations, however Bond Index curve and color coding can be used for more detailed interval inspection to draw conclusions on zonal isolation. Please refer to the tables on pages 6 for more detailed interpretation. Figure 8: Interval 1 of LWD CBL logging General Interpretation Comments: 8,500’ to 9,050’ poor to no cement in that interval. Santos USA and Baker Hughes Confidential Page 14 Figure 9: Interval 2 of LWD CBL Logging General Interpretation Comments: 9,050’ to 9,140’ partial cement presence in that interval. 9,140’ to 9,230’ Partial to poor Cement presence. 9,230’ to 9,600’ Partial to good Cement presence Santos USA and Baker Hughes Confidential Page 15 Figure 10: Interval 3 of LWD CBL Logging General Interpretation Comments: 9,600’ to 10,200’ Very Good to Partial cement presence. Mostly very good, with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 16 Figure 11: Interval 4 of LWD CBL Logging General Interpretation Comments: 10,200’ to 10,800’ Partial to Good. Mostly Good, with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 17 Figure 2: Interval 5 of LWD CBL Logging General Interpretation Comments: 10,800’ to 11,400’ Very Good presence with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 18 Figure 123: Interval 6 of LWD CBL Logging General Interpretation Comments: 11,400’ to 12,000’ Very Good presence with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 19 Figure 14: Interval 7 of LWD CBL Logging General Interpretation Comments: 12,000’ to 12,700’. Very Good cement presence. Santos USA and Baker Hughes Confidential Page 20 Figure 15: Interval 8 of LWD CBL Logging General Interpretation Comments: 12,600’ to TD. Very Good cement presence. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Kelsey, Todd (Todd) To:AOGCC Data (CED sponsored) Cc:Davies, Stephen F (OGC); Leahy, Scott (Scott); Shearer, Michael (Todd); Koh, Shannon (Shannon); Guhl, Meredith D (OGC); Villarreal, Aimee (Aimee) Subject:Preliminary data submittal for PIKKA NDBi-016 frac sundry Date:Thursday, October 10, 2024 2:37:51 PM Attachments:2024.10.10 - AOGCC NDBi-016 Frac Sundry.zip You don't often get email from todd.kelsey@santos.com. Learn why this is important All – as requested by Steve Davies, please find attached the field quality LWD and survey data for PIKKA NDBi-016, to be used in the frac sundry application. This data is to be superseded by the final data submittal, and should be considered temporary only. Please let me know if you have any questions. Thanks, Todd Todd Kelsey Subsurface Data & Applications Manager t: +1 907 375 4600 | m: +1 907 223 3878 | e: todd.kelsey@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 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Leahy, Scott (Scott) To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC); Senden, Robert (Ty); Shearer, Michael (Todd) Subject:RE: Pikka NDBi-016 (Permit 224-105, Sundry 324-556) - Question Date:Thursday, October 10, 2024 3:10:28 PM Hello Steve, According to our Subsurface group (for well NDBi-016), Fault 1 (SM_NDB_015) terminates 225-600ft below the Top Seabee and Fault 2 (SM_NDB_005) terminates 200-500ft below the Top Seabee. These distances were measured from the uppermost fault tip observed on seismic to the Top Seabee surface. Per the fracture modeling, we do not believe that the fracture would breach containment from the Seabee as the fracture height growth is modeled at <250 ft for all stages simulated. Moreover, the placement of the fracture ports is >300 feet away from the fault locations, limiting the potential of the fracture intersecting the fault plane. Todd Kelsey has supplied the data for NDBi-016 that you requested in a separate email. I noticed that he sent over NDB-025 as well. I haven’t submitted the Sundry for NDB-025 but I plan to on 10/14 as we should land the completion this weekend. Our requested turn around for NDB-025 will be shorter than the last few wells. We are targeting 10/31 for a start date with fracturing NDB-025. Regards, Scott Leahy – Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Ave Anchorage, Alaska 99501 m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, October 8, 2024 5:40 PM To: Leahy, Scott (Scott) <Scott.Leahy@santos.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: ![EXT]: Pikka NDBi-016 (Permit 224-105, Sundry 324-556) - Question Scott, I’m part of the team that is reviewing the Sundry Application to hydraulically fracture NDBi-016. I have two questions so far: 1. Has Santos submitted field-quality copies of the open-hole well logs in .las and .pdf format for this well? If not, please submit them as soon as is practical. 2. The application describes two faults that intersect the wellbore, one at 15,568’ MD and one at 18,080’ MD. According to the wellbore schematic drawing, the first fault will be isolated on either side by two open-hole packers, but the second will not. Both faults are described as extending upward to the into the Seabee that will provide upper confinement. Given the estimated vertical displacement of about 40’ for both faults, will either of them interfere with containment of the hydraulic fracturing fluids? Please describe. Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). 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Please consider the environment before printing this email ϮϬϮϱ͘Ϯϴϯ,LJĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚWŝŬŬĂEŝͲϬϭϲ;WdEŽ͘ϮϮϰͲϭϬϱ͖^ƵŶĚƌLJEŽ͘ϯϮϰͲϱϱϲͿWĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍K' WĂŐĞϭ KĐƚŽďĞƌϭϰ͕ϮϬϮϰ;ĂͿƉƉůŝĐĂƚŝŽŶĨŽƌ^ƵŶĚƌLJƉƉƌŽǀĂů;ĂͿ;ϭͿĨĨŝĚĂǀŝƚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϮͿWůĂƚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϮͿ;ͿtĞůůůŽĐĂƚŝŽŶWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘tĞůůƚƌĂǀĞƌƐĞƐ^ĞĐƚŝŽŶϰdϭϭE͕ZϬϲ ͖^ĞĐƚŝŽŶƐϯϯ͕ϯϮ͕Ϯϵ͕ϯϬ͕ĂŶĚϭϵŽĨdϭϮE͕ZϬϲ ͕hD͘^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϮͿ;Ϳ ĂĐŚǁĂƚĞƌǁĞůůǁŝƚŚŝŶЪŵŝůĞEŽŶĞ͗ĐĐŽƌĚŝŶŐƚŽƚŚĞtĂƚĞƌ ƐƚĂƚĞŵĂƉĂǀĂŝůĂďůĞƚŚƌŽƵŐŚEZ͛ƐůĂƐŬĂDĂƉƉĞƌĂƉƉůŝĐĂƚŝŽŶ;ĂĐĐĞƐƐĞĚŽŶůŝŶĞKĐƚŽďĞƌϳ͕ϮϬϮϰͿ͕ƚŚĞƌĞĂƌĞŶŽǁĞůůƐĂƌĞƵƐĞĚĨŽƌĚƌŝŶŬŝŶŐǁĂƚĞƌƉƵƌƉŽƐĞƐĂƌĞŬŶŽǁŶƚŽůŝĞǁŝƚŚŝŶЪŵŝůĞŽĨƚŚĞƐƵƌĨĂĐĞůŽĐĂƚŝŽŶŽĨEŝͲϬϭϲ͘ dŚĞƌĞĂƌĞŶŽƐƵďƐƵƌĨĂĐĞǁĂƚĞƌƌŝŐŚƚƐŽƌƚĞŵƉŽƌĂƌLJƐƵďƐƵƌĨĂĐĞǁĂƚĞƌƌŝŐŚƚƐǁŝƚŚŝŶϭϯͲϭͬϮŵŝůĞƐŽĨƚŚĞƐƵƌĨĂĐĞůŽĐĂƚŝŽŶŽĨEŝͲϬϭϲ͘^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϮͿ;Ϳ/ĚĞŶƚŝĨLJĂůůǁĞůůƚLJƉĞƐǁŝƚŚŝŶЪŵŝůĞzĞƐ͘ dŚƌĞĞ ǁĞůůƐ ǁŝƚŚŝŶ Ъ ŵŝůĞ ŽĨ EͲϬϭϲ ƚƌĂŶƐĞĐƚ ƚŚĞĐŽŶĨŝŶŝŶŐnjŽŶĞ͗EͲϬϭϴ͕EͲϬϮϰ͕ĂŶĚEͲϬϯϮ͘^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϯͿ&ƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐ͗ŐĞŽůŽŐŝĐĂůŶĂŵĞ͖ŵĞĂƐƵƌĞĚĂŶĚƚƌƵĞǀĞƌƚŝĐĂůĚĞƉƚŚEŽŶĞ͘EŽĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐĂƌĞƉƌĞƐĞŶƚǁŝƚŚŝŶƚŚĞWŝŬŬĂhŶŝƚƉĞƌƐĂůŝŶŝƚLJĐĂůĐƵůĂƚŝŽŶƐƉƌŽǀŝĚĞĚďLJƚŚĞŽƉĞƌĂƚŽƌŽŶƵŐ͘Ϯϭ͕ϮϬϮϯ ĂƐƉĂƌƚŽĨƚŚĞŝƌ^ƵŶĚƌLJƉƉůŝĐĂƚŝŽŶƚŽŚLJĚƌĂƵůŝĐĂůůLJĨƌĂĐƚƵƌĞŶĞĂƌďLJǁĞůůEͲϬϮϰ;ƐĞĞK'͛ƐtĞůů,ŝƐƚŽƌLJ&ŝůĞϮϮϯͲϬϳϲ͕ Ɖ͘ϭϬϭͲϭϬϳ ŽĨ^ƵŶĚƌLJƉƉůŝĐĂƚŝŽŶϯϮϯͲϱϵϭͿ͘WŝĐŬĞƚƚWůŽƚǁĞůůͲůŽŐĂŶĂůLJƐĞƐǁĞƌĞƉĞƌĨŽƌŵĞĚŽŶƚŚƌĞĞǁĞůůƐǁŝƚŚŝŶƚŚĞƵŶŝƚƚŚĂƚŚĂǀĞǁŝƌĞůŝŶĞůŽŐĐŽǀĞƌĂŐĞĨƌŽŵƐƵƌĨĂĐĞƚŚƌŽƵŐŚƚŚĞĨƌĂĐƚƵƌŝŶŐŝŶƚĞƌǀĂů͗ŽůǀŝůůĞZŝǀĞƌϭ͕dŝůůϭ͕ĂŶĚWŝŬŬĂtͲϬϮ͘ ƐƚŝŵĂƚĞĚƐĂůŝŶŝƚLJǀĂůƵĞƐĨŽƌĐůĞĂŶ͕ƉŽƌŽƵƐϭϬϬйǁĂƚĞƌͲƐĂƚƵƌĂƚĞĚƐĂŶĚƐďĞŶĞĂƚŚƚŚĞďĂƐĞŽĨƚŚĞƉĞƌŵĂĨƌŽƐƚůĂLJĞƌŝŶƚŚĞƐĞƚŚƌĞĞǁĞůůƐĂƌĞ͗ŽůǀŝůůĞZŝǀĞƌϭ;ϭϵϮͲϭϱϯͿΕϮϬ͕ϬϬϬŵŐͬůďĞƚǁĞĞŶϭ͕ϰϬϬĂŶĚϮ͕ϬϬϬ͛D;Ͳϭ͕ϯϱϰ͛ƚŽϭ͕ϵϱϰΖds^^͖ďĂƐĞŽĨƉĞƌŵĂĨƌŽƐƚϭ͕ϯϱϬ͛ D ;Ͳϭ͕ϯϭϯ͛ds^^ͿͿ͖dŝůůϭ;ϭϵϯͲϬϬϰͿϭϲ͕ϳϬϬ ƚŽ ΕϮϯ͕ϬϬϬ ŵŐͬůďĞƚǁĞĞŶϭ͕ϰϬϬ͛ ĂŶĚ ϭ͕ϱϬϬ͛ D;Ͳϭ͕ϰϲϯ͛ ƚŽ Ͳϭ͕ϯϲϯ͛ ds^^͖ ďĂƐĞ ŽĨ ƉĞƌŵĂĨƌŽƐƚϭ͕ϯϱϬ͛ D^&ϭϬͬϳͬϮϬϮϰ ϮϬϮϱ͘Ϯϴϯ,LJĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚWŝŬŬĂEŝͲϬϭϲ;WdEŽ͘ϮϮϰͲϭϬϱ͖^ƵŶĚƌLJEŽ͘ϯϮϰͲϱϱϲͿWĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍K' WĂŐĞϮ KĐƚŽďĞƌϭϰ͕ϮϬϮϰ;Ͳϭ͕ϯϬϱ͛ ds^^ͿͿ͖ ĂŶĚtͲϬϮ ;ϮϮϯͲϬϯϵͿΕϮϭ͕ϱϬϬ ŵŐͬůďĞƚǁĞĞŶϭ͕ϱϱϬ͛ĂŶĚϭ͕ϲϱϬ͛D;Ͳϭ͕ϰϬϴ͛ƚŽͲϭ͕ϰϴϲ͛ds^^͖ďĂƐĞŽĨƉĞƌŵĂĨƌŽƐƚΕϭ͕ϭϳϬ͛D;ΕͲϭ͕ϬϴϬ͛ds^^Ϳ͘;ĂͿ;ϰͿĂƐĞůŝŶĞǁĂƚĞƌƐĂŵƉůŝŶŐƉůĂŶEŽŶĞƌĞƋƵŝƌĞĚ͗EŽĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐĂƌĞƉƌĞƐĞŶƚ͘^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϱͿĂƐŝŶŐĂŶĚĐĞŵĞŶƚŝŶŐŝŶĨŽƌŵĂƚŝŽŶWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘WƌŽƉŽƐĞĚƐĐŚĞŵĂƚŝĐĂƚƚĂĐŚĞĚ͕ĂƐďƵŝůƚŶŽƚŐĞŶĞƌĂƚĞĚƚŽĚĂƚĞ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϲͿĂƐŝŶŐĂŶĚĐĞŵĞŶƚŝŶŐŽƉĞƌĂƚŝŽŶĂƐƐĞƐƐŵĞŶƚ^ƵƌĨĂĐĞĐĂƐŝŶŐƐĞƚĂƚϮ͕ϳϱϵ͛DǁĂƐĐĞŵĞŶƚĞĚǁŝƚŚϴďĂƌƌĞůƐŽĨ ůŽƐƐĞƐ ĂŶĚ ϮϬϯ ďĂƌƌĞůƐ ŽĨ ĐĞŵĞŶƚƌĞƚƵƌŶƐ ŽďƐĞƌǀĞĚĂƚƐƵƌĨĂĐĞ͘/ŶƚĞƌŵĞĚŝĂƚĞ ůŝŶĞƌ ;ϵͲϱͬϴ͟Ϳ ǁĂƐ ƐĞƚ Ăƚ ϭϮ͕ϴϱϱ͛ D ĂŶĚĐĞŵĞŶƚĞĚŝŶƚǁŽƐƚĂŐĞƐ͘&ŝƌƐƚƐƚĂŐĞĐŽŶƐŝƐƚĞĚŽĨϮϱϱďĂƌƌĞůƐŽĨĐĞŵĞŶƚƉƵŵƉĞĚǁŝƚŚϳďĂƌƌĞůƐŽĨůŽƐƐĞƐ͘WůƵŐďƵŵƉĞĚĂŶĚĨůŽĂƚƐŚĞůĚ͘dŽƉŽĨĐĞŵĞŶƚǁĂƐĚĞƚĞƌŵŝŶĞĚďLJƚŚĞŽƉĞƌĂƚŽƌĂƚ ϵ͕Ϭϱϴ͛ D ƵƐŝŶŐ Ă ĂŬĞƌ ^ŽƵŶĚƚƌĂĐŬ>t ƚŽŽů͘ŽŶƐĞƌǀĂƚŝǀĞĂƐƐĞƐƐŵĞŶƚŽĨƚŚĞ^ŽƵŶĚdƌĂŬƐŚŽǁƐdKĂƚϵϮϯϰ ĨƚǁŝƚŚƉĂƌƚŝĂůƚŽŐŽŽĚĐĞŵĞŶƚŽďƐĞƌǀĞĚ͘dŚĞƐĞĐŽŶĚƐƚĂŐĞŽĨƚŚĞůŝŶĞƌǁĂƐĐĞŵĞŶƚĞĚǁŝƚŚϮϱϭďĂƌƌĞůƐƚŚƌŽƵŐŚĂĐŽůůĂƌĂƚϰ͕ϵϯϰ͛DǁŝƚŚŶŽůŽƐƐĞƐĂŶĚϭϬϭďĂƌƌĞůƐŽĨĐĞŵĞŶƚƌĞƚƵƌŶƐĂƚƚŚĞƐƵƌĨĂĐĞ͘EŽŝƐƐƵĞƐǁŝƚŚĐĞŵĞŶƚĨŽƌƚŚĞƵƉĐŽŵŝŶŐƐƚŝŵƵůĂƚŝŽŶ͘ϰͲϭͬϮ͟ ůŝŶĞƌͬƚƵďŝŶŐĂŶĐŚŽƌĞĚǁŝƚŚŽƉĞŶŚŽůĞƉĂĐŬĞƌƐĂŶĚůŝŶĞƌƚŽƉƉĂĐŬĞƌ;ƚŽĐĞŵĞŶƚĞĚϵͲϱͬϴ͟ůŝŶĞƌͿtϭϬͬϬϴͬϮϬϮϰ^&ϭϬͬϴͬϮϬϮϰ;ĂͿ;ϲͿ;ͿĂƐŝŶŐĐĞŵĞŶƚĞĚďĞůŽǁůŽǁĞƌŵŽƐƚĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌĂŶĚĐŽŶĨŽƌŵƐƚŽϮϬϮϱ͘ϬϯϬEŽĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐƉƌĞƐĞŶƚ͘;^ĞĞ^ĞĐƚŝŽŶ;ĂͿ;ϯͿ͕ĂďŽǀĞ͘Ϳ^&ϭϬͬϳͬϮϬϮϰ;ĂͿ;ϲͿ;Ϳ ĂĐŚŚLJĚƌŽĐĂƌďŽŶnjŽŶĞŝƐŝƐŽůĂƚĞĚzĞƐ͘dƵůƵǀĂŬ͗K'ĐŽŶƐŝĚĞƌƐƚŚĞƵƉƉĞƌdƵůƵǀĂŬďĞƚǁĞĞŶϯϬϯϴ͛DĂŶĚƚŚĞd^ϳϵϬ DĂƌŬĞƌĂƚϰϴϰϵ͛ DƚŽďĞĂƌƐŝŐŶŝĨŝĐĂŶƚ ϮϬϮϱ͘Ϯϴϯ,LJĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚWŝŬŬĂEŝͲϬϭϲ;WdEŽ͘ϮϮϰͲϭϬϱ͖^ƵŶĚƌLJEŽ͘ϯϮϰͲϱϱϲͿWĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍K' WĂŐĞϯ KĐƚŽďĞƌϭϰ͕ϮϬϮϰŚLJĚƌŽĐĂƌďŽŶƐ͘dŚĞƐĞĐŽŶĚƐƚĂŐĞĐŽůůĂƌ ŽĨƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞůŝŶĞƌǁĂƐƐĞƚďĞŶĞĂƚŚƚŚĞd^ϳϵϬ ŵĂƌŬĞƌĂƚϰ͕ϵϯϰ͛ DĂŶĚĐĞŵĞŶƚĞĚǁŝƚŚϮϱϭďĂƌƌĞůƐǁŝƚŚŶŽůŽƐƐĞƐĂŶĚϭϬϬďĂƌƌĞůƐŽĨĐĞŵĞŶƚƌĞƚƵƌŶƐƌĞƉŽƌƚĞĚĂƚƚŚĞƐƵƌĨĂĐĞ͘EĂŶƵƐŚƵŬ͗/ŶƚĞƌǀĂů ƚŽƉ ŝƐ ϭϬ͕ϵϰϬ͛ D͕ ĂŶĚ ƚŚĞ ƚŽƉ ŽĨƐŝŐŶŝĨŝĐĂŶƚŚLJĚƌŽĐĂƌďŽŶƐůŝĞƐŝŶ ƚŚĞEdϴ ŝŶƚĞƌǀĂůĂƚϭϭ͕Ϯϲϴ͛D͘ŽƚŚĂƌĞĐŽǀĞƌĞĚďLJŵŽƐƚůLJŐŽŽĚĐĞŵĞŶƚǁŝƚŚƐŽŵĞŝŶƚĞƌƐƉĞƌƐĞĚŝŶƚĞƌǀĂůƐŽĨƉĂƌƚŝĂů ĐĞŵĞŶƚĨƌŽŵϵ͕ϱϴϳ͛DƚŽƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐ ƐŚŽĞ Ăƚ ϭϮ͕ϴϱϱ͛ D͘^Ž͕ ĐĞŵĞŶƚŝƐŽůĂƚĞƐĞĂĐŚŚLJĚƌŽĐĂƌďŽŶnjŽŶĞ͘^&ϭϬͬϭϰͬϮϬϮϰtϭϬͬϭϭͬϮϬϮϰ;ĂͿ;ϳͿWƌĞƐƐƵƌĞƚĞƐƚ͗ŝŶĨŽƌŵĂƚŝŽŶĂŶĚƉƌĞƐƐƵƌĞͲƚĞƐƚƉůĂŶƐĨŽƌĐĂƐŝŶŐĂŶĚƚƵďŝŶŐŝŶƐƚĂůůĞĚŝŶǁĞůůWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ϰϯϬϬƉƐŝD/d/ƉůĂŶŶĞĚ͕ϱϳϬϬƉƐŝD/ddƉůĂŶ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϴͿWƌĞƐƐƵƌĞƌĂƚŝŶŐƐĂŶĚƐĐŚĞŵĂƚŝĐƐ͗ǁĞůůďŽƌĞ͕ǁĞůůŚĞĂĚ͕KW ͕ƚƌĞĂƚŝŶŐŚĞĂĚWƌŽǀŝĚĞĚ ǁŝƚŚ ĂƉƉůŝĐĂƚŝŽŶ͘ ϭϬ< ƉƐŝ ǁĞůůŚĞĂĚ ŵĂdž͘ ĨƌĂĐ͘WƌĞƐƐƵƌĞϴϵϬϬƉƐŝ͘WƵŵƉŬŶŽĐŬŽƵƚϴϬϬϬĂŶĚ'KZsϴϱϬϬƉƐŝ͕͘ůŝŶĞƐƚĞƐƚϵϬϬϬƉƐŝ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϵͿ;Ϳ&ƌĂĐƚƵƌŝŶŐĂŶĚĐŽŶĨŝŶŝŶŐnjŽŶĞƐ͗ůŝƚŚŽůŽŐŝĐĚĞƐĐƌŝƉƚŝŽŶĨŽƌĞĂĐŚnjŽŶĞ;ĂͿ;ϵͿ;Ϳ'ĞŽůŽŐŝĐĂůŶĂŵĞŽĨĞĂĐŚnjŽŶĞ;ĂͿ;ϵͿ;ͿĂŶĚ;ĂͿ;ϵͿ;ͿDĞĂƐƵƌĞĚĂŶĚƚƌƵĞǀĞƌƚŝĐĂůĚĞƉƚŚƐ;ĂͿ;ϵͿ; Ϳ&ƌĂĐƚƵƌĞƉƌĞƐƐƵƌĞĨŽƌĞĂĐŚnjŽŶĞhƉƉĞƌŽŶĨŝŶŝŶŐŽŶĞƐ͗ďŽƵƚϲϳϬ͛ ƚƌƵĞǀĞƌƚŝĐĂůƚŚŝĐŬŶĞƐƐ;dsdͿŽĨĐůĂLJƐƚŽŶĞ͕ƐŚĂůĞĂŶĚǀŽůĐĂŶŝĐ ƚƵĨĨĂƐƐŝŐŶĞĚƚŽ ƚŚĞ^ĞĂďĞĞŚĂǀŝŶŐĂŶĞƐƚŝŵĂƚĞĚĨƌĂĐƚƵƌĞŐƌĂĚŝĞŶƚŽĨϭϯ͘ϳƉƉŐ Dt;Ϭ͘ϳϭƉƐŝͬĨƚͿ͘&ƌĂĐƚƵƌŝŶŐŽŶĞ͗WĞƌĨŽƌĂƚĞĚnjŽŶĞůŝĞƐǁŝƚŚŝŶĂƐƵďĚŝǀŝƐŝŽŶŽĨƚŚĞEĂŶƵƐŚƵŬ&ŽƌŵĂƚŝŽŶĐŽŵƉƌŝƐŝŶŐĨŝŶĞͲŐƌĂŝŶĞĚƐĂŶĚ͕ƐŝůƚĂŶĚƐŚĂůĞƚŚĂƚŝƐ ĂďŽƵƚϵϱϬ͛ dsdŝŶ ƚŚŝƐĂƌĞĂĂŶĚŚĂƐĂŶĞƐƚŝŵĂƚĞĚĨƌĂĐƚƵƌĞŐƌĂĚŝĞŶƚŽĨϭϮ͘ϯƚŽϭϮ͘ϳƉƉŐ Dt;Ϭ͘ϲϰƚŽϬ͘ϲϲƉƐŝͬĨƚͿ͘>ŽǁĞƌŽŶĨŝŶŝŶŐŽŶĞƐ͗>ŽǁĞƌdŽƌŽŬƐŝůƚƐƚŽŶĞĂŶĚƐŚĂůĞƚŚĂƚŝƐĂďŽƵƚϭ͕ϮϬϬ͛ ƚŚŝĐŬŝŶƚŚŝƐĂƌĞĂǁŝƚŚĂŶĞƐƚŝŵĂƚĞĚĨƌĂĐƚƵƌĞŐƌĂĚŝĞŶƚŽĨϭϯ͘ϯƉƉŐ Dt;Ϭ͘ϲϵƉƐŝͬĨƚͿ͘^&ϭϬͬϴͬϮϬϮϰ;ĂͿ;ϭϬͿ>ŽĐĂƚŝŽŶ͕ŽƌŝĞŶƚĂƚŝŽŶ͕ƌĞƉŽƌƚŽŶŵĞĐŚĂŶŝĐĂůĐŽŶĚŝƚŝŽŶŽĨĞĂĐŚǁĞůůƚŚĂƚŵĂLJƚƌĂŶƐĞĐƚƚŚĞĐŽŶĨŝŶŝŶŐnjŽŶĞƐĂŶĚ/ƚŝƐŚŝŐŚůLJƵŶůŝŬĞůLJƚŚĂƚĂŶLJŽĨƚŚĞǁĞůůƐŽƌǁĞůůďŽƌĞƐǁŝƚŚŝŶĂЪͲŵŝůĞƌĂĚŝƵƐ ǁŝůů ŝŶƚĞƌĨĞƌĞǁŝƚŚŚLJĚƌĂƵůŝĐ ĨƌĂĐƚƵƌŝŶŐĨůƵŝĚƐtϭϬͬϬϴͬϮϬϮϰ ϮϬϮϱ͘Ϯϴϯ,LJĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚWŝŬŬĂEŝͲϬϭϲ;WdEŽ͘ϮϮϰͲϭϬϱ͖^ƵŶĚƌLJEŽ͘ϯϮϰͲϱϱϲͿWĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍K' WĂŐĞϰ KĐƚŽďĞƌϭϰ͕ϮϬϮϰƐƵĨĨŝĐŝĞŶƚŝŶĨŽƌŵĂƚŝŽŶƚŽĚĞƚĞƌŵŝŶĞǁĞůůƐǁŝůůŶŽƚŝŶƚĞƌĨĞƌĞǁŝƚŚĐŽŶƚĂŝŶŵĞŶƚŽĨŚLJĚƌĂƵůŝĐĨƌĂĐƚƵƌŝŶŐĨůƵŝĚǁŝƚŚŝŶЪŵŝůĞŽĨƚŚĞƉƌŽƉŽƐĞĚǁĞůůďŽƌĞƚƌĂũĞĐƚŽƌLJĨƌŽŵƚŚŝƐŽƉĞƌĂƚŝŽŶďĞĐĂƵƐĞŽĨĐĞŵĞŶƚŝƐŽůĂƚŝŽŶĂŶĚͬŽƌƐĞƉĂƌĂƚŝŽŶĚŝƐƚĂŶĐĞ͘Kŝů^ĞĂƌĐŚŚĂƐĚĞƚĂŝůĞĚƚŚĞϯǁĞůůƐEͲϬϮϰ͕EͲϬϯϮ͕ĂŶĚEͲϬϭϴĂŶĚƉƌŽǀŝĚĞĚĐĞŵĞŶƚĚĞƚĂŝůƐĂŶĚdKǀĞƌŝĨŝĐĂƚŝŽŶƐ͘;ĂͿ;ϭϭͿ&ĂƵůƚƐĂŶĚĨƌĂĐƚƵƌĞƐ͕^ƵĨĨŝĐŝĞŶƚŝŶĨŽƌŵĂƚŝŽŶƚŽĚĞƚĞƌŵŝŶĞŶŽŝŶƚĞƌĨĞƌĞŶĐĞǁŝƚŚĐŽŶƚĂŝŶŵĞŶƚŽĨƚŚĞŚLJĚƌĂƵůŝĐĨƌĂĐƚƵƌŝŶŐĨůƵŝĚǁŝƚŚŝŶЪŵŝůĞŽĨƚŚĞƉƌŽƉŽƐĞĚǁĞůůďŽƌĞƚƌĂũĞĐƚŽƌLJzĞƐ͘dŚĞŽƉĞƌĂƚŽƌŚĂƐŝĚĞŶƚŝĨŝĞĚƐĞǀĞŶĨĂƵůƚƐǁŝƚŚŝŶĂЪͲŵŝůĞƌĂĚŝƵƐŽĨEŝͲϬϭϲ͘&ŝǀĞĨĂƵůƚƐĂƌĞůŽĐĂƚĞĚĂƚĚŝƌĞĐƚŝŽŶƐĂŶĚĚŝƐƚĂŶĐĞƐƐƵĐŚƚŚĂƚŝƚŝƐƵŶůŝŬĞůLJƚŚĂƚƚŚĞLJǁŝůůďĞŝŶƚĞƌƐĞĐƚĞĚďLJƚŚĞŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞƐ͕ǁŚŝĐŚĂƌĞĞdžƉĞĐƚĞĚƚŽŐƌŽǁĂůŽŶŐĂŶĂnjŝŵƵƚŚŽĨĂƉƉƌŽdžŝŵĂƚĞůLJϯϯϬΣ ;ĞƐƐĞŶƚŝĂůůLJƉĂƌĂůůĞůǁŝƚŚƚŚĞǁĞůůďŽƌĞͿ͘dǁŽĨĂƵůƚƐŚĂǀĞďĞĞŶŝĚĞŶƚŝĨŝĞĚŝŶEͲϬϭϲ͕ĂŶĚƚŚĞLJůŝĞĂƚϭϱ͕ϱϲϴ͛ ĂŶĚϭϴ͕ϬϴϬ͛ D͘dŚĞƐĞĨĂƵůƚƐŚĂǀĞǀĞƌƚŝĐĂůĚŝƐƉůĂĐĞŵĞŶƚƐŽĨĂďŽƵƚϰϬ͕͛ĂnjŝŵƵƚŚƐŽĨĂďŽƵƚϱΣƚŽϭϬΣ͕ĂŶĚĞdžƚĞŶĚƵƉǁĂƌĚŝŶƚŽƚŚĞƵƉƉĞƌͲĐŽŶĨŝŶŝŶŐ^ĞĂďĞĞ͘ĐĐŽƌĚŝŶŐ ƚŽ ƚŚĞŽƉĞƌĂƚŽƌ͛ƐƐĞŝƐŵŝĐ ŝŶƚĞƌƉƌĞƚĂƚŝŽŶ͕ďŽƚŚĨĂƵůƚƐƚĞƌŵŝŶĂƚĞďĞƚǁĞĞŶϮϬϬΖĂŶĚϲϬϬΖďĞůŽǁƚŚĞƚŽƉŽĨƚŚĞƵƉƉĞƌͲĐŽŶĨŝŶŝŶŐ^ĞĂďĞĞ͕ǁŚŝĐŚ ŝƐ ĂďŽƵƚ ϲϳϬΖ ƚŚŝĐŬ ŝŶ ƚŚŝƐĂƌĞĂ͘KƉĞƌĂƚŽƌĚŽĞƐŶŽƚďĞůŝĞǀĞƚŚĂƚƚŚĞŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞƐǁŝůůďƌĞĂĐŚ^ĞĂďĞĞĐŽŶƚĂŝŶŵĞŶƚĂƐĨƌĂĐƚƵƌĞŐƌŽǁƚŚŚĞŝŐŚƚŝƐŵŽĚĞůĞĚĂƚůĞƐƐƚŚĂŶϮϱϬ͛ĨŽƌĂůůƐƚĂŐĞƐƐŝŵƵůĂƚĞĚ͘^ƚĂŐĞϭĨƌĂĐƐůĞĞǀĞĂƚϭϳ͕ϲϭϵ͛DǁŝůůďĞůŽĐĂƚĞĚϰϲϭ͛ĨƌŽŵƚŚĞ&ĂƵůƚĂƚϭϴ͕ϬϴϬ͛ D͕ĂŶĚƐĞƉĂƌĂƚĞĚĨƌŽŵƚŚĞĨĂƵůƚďLJƚǁŽŽƉĞŶͲŚŽůĞƉĂĐŬĞƌƐƉůĂĐĞĚĂƚĂďŽƵƚϭϳ͕ϳϮϰ͛ ĂŶĚϭϳ͕ϴϯϮ͛ D͘dŚĞŵŽĚĞůĞĚŚĂůĨͲůĞŶŐƚŚŽĨƚŚĞ^ƚĂŐĞϭ ĨƌĂĐƚƵƌĞŝƐ ϰϬϲ͛͘ dŚĞƐĞĐŽŶĚĨĂƵůƚĂƚϭϱ͕ϱϲϴ͛DǁŝůůďĞŝƐŽůĂƚĞĚŽŶĞŝƚŚĞƌƐŝĚĞďLJƚǁŽŽƉĞŶͲŚŽůĞƉĂĐŬĞƌƐĨƌŽŵƚŚĞ^ƚĂŐĞϰĨƌĂĐƐůĞĞǀĞƉůĂĐĞĚĂƚϭϱ͕Ϯϱϲ͛;ϯϭϮ͛ ĂǁĂLJͿĂŶĚƚŚĞ^ƚĂŐĞϱĨƌĂĐƐůĞĞǀĞƉůĂĐĞĚĂƚϭϱ͕ϵϵϴ͛ D;ϰϯϬ͛ ĂǁĂLJͿ͘dŚĞŵŽĚĞůĞĚŚĂůĨͲůĞŶŐƚŚƐŽĨƚŚĞ^ƚĂŐĞϰĂŶĚ^ƚĂŐĞϱĨƌĂĐƚƵƌĞƐĂƌĞϮϴϵ͛ĂŶĚϯϯϭ͕͛ƌĞƐƉĞĐƚŝǀĞůLJ͘/ƚŝƐƵŶůŝŬĞůLJƚŚĂƚĂŶLJĨĂƵůƚƐǁŝůůŝŶƚĞƌĨĞƌĞǁŝƚŚĐŽŶƚĂŝŶŵĞŶƚŽĨ ŝŶũĞĐƚĞĚ ĨƌĂĐƚƵƌŝŶŐ ĨůƵŝĚƐ͘ ,ŽǁĞǀĞƌ͕ ŝĨ ƚŚĞƌĞ ĂƌĞŝŶĚŝĐĂƚŝŽŶƐƚŚĂƚĂĨƌĂĐƚƵƌĞŚĂƐŝŶƚĞƌƐĞĐƚĞĚĂĨĂƵůƚŽƌŶĂƚƵƌĂůͲ^&ϭϬͬϭϰͬϮϬϮϰ ϮϬϮϱ͘Ϯϴϯ,LJĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚWŝŬŬĂEŝͲϬϭϲ;WdEŽ͘ϮϮϰͲϭϬϱ͖^ƵŶĚƌLJEŽ͘ϯϮϰͲϱϱϲͿWĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍K' WĂŐĞϱ KĐƚŽďĞƌϭϰ͕ϮϬϮϰĨƌĂĐƚƵƌĞŝŶƚĞƌǀĂůĚƵƌŝŶŐĨƌĂĐŽƉĞƌĂƚŝŽŶƐ͕ƚŚĞŽƉĞƌĂƚŽƌǁŝůůŐŽƚŽĨůƵƐŚĂŶĚƚĞƌŵŝŶĂƚĞƚŚĞƐƚĂŐĞŝŵŵĞĚŝĂƚĞůLJ͘;ĂͿ;ϭϮͿWƌŽƉŽƐĞĚƉƌŽŐƌĂŵĨŽƌĨƌĂĐƚƵƌŝŶŐŽƉĞƌĂƚŝŽŶWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϭϮͿ;Ϳ ƐƚŝŵĂƚĞĚǀŽůƵŵĞWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ϭϳ<ďďůƚŽƚĂůĚŝƌƚLJǀŽů͘Ϯ͘ϰDůďƚŽƚĂůƉƌŽƉƉĂŶƚtϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϭϮͿ;ͿĚĚŝƚŝǀĞƐ͗ŶĂŵĞƐ͕ƉƵƌƉŽƐĞƐ͕ĐŽŶĐĞŶƚƌĂƚŝŽŶƐWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϭϮͿ;ͿŚĞŵŝĐĂůŶĂŵĞĂŶĚ^ŶƵŵďĞƌŽĨĞĂĐŚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘^ĐŚůƵŵďĞƌŐĞƌĚŝƐĐůŽƐƵƌĞƉƌŽǀŝĚĞĚ͘dƌĂĐĞƌĐŽĚŝƐĐůŽƐƵƌĞƉƌŽǀŝĚĞĚ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϭϮͿ;Ϳ/ŶĞƌƚƐƵďƐƚĂŶĐĞƐ͕ǁĞŝŐŚƚŽƌǀŽůƵŵĞŽĨĞĂĐŚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘tϭϬͬϬϴͬϮϬϮϰ;ĂͿ;ϭϮͿ; 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Thompson, Jacob (Jacob); D&C WSS NDB Cc:Regg, James B (OGC) Subject:RE: 13 3/8 casing test NDBi-016 8/21/24 Date:Wednesday, August 21, 2024 12:03:00 PM Jacob, No need to repeat this test. The regs require the casing test to be 50% of rated casing burst, which is 5020 psi X 50% = 2510 psi. Your final test pressure after 30 minutes was 2600 psi which is greater than the regulatory requirement. The test passes the criteria of <10% pressure loss and stabilization, so Oil Search does not need to repeat the test. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Sent: Wednesday, August 21, 2024 11:39 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: Fwd: 13 3/8 casing test NDBi-016 8/21/24 Bryan, Attached is our casing test results for the NDBi-018 13-3/8" surface casing. The rest was successful in establishing stabilization criteria. However, the values recorded on the chart recorder fall slightly below the target pressure of 2,600 psi. The digital readout showed the pressure stabilizing at the target pressure of 2,600 psi for the last 10 mins. We are requesting approval to proceed with the given test results and not repeat the casing test. The rig is currently tripping in the hole with the drilling BHA. If we do not receive approval we will retest the casing. Thank you, Jacob Jacob Thompson From: Buzby, Brian (Brian) <Brian.Buzby@contractor.santos.com> Sent: Wednesday, August 21, 2024 10:47:11 AM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: 13 3/8 casing test NDBi-016 8/21/24 Here you are Jacob Brian Buzby – Well Site Supervisor Parker 272Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) xxx-xxx | m: +1 (907) 355-4253 Brian.buzby@contractor.santos.com https://www.santos.com/ 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 isstrictly 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 Garret Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 900 E Benson Boulevard Anchorage, AK, 99508 Re: Pikka Field, Nanushuk Oil Pool, Pikka NDBi-016 Oil Search Alaska, LLC Permit to Drill Number: 224-105 Surface Location: 2450’ FSL, 2820’ FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 1124’ FSL, 810’ FEL, Sec 19, T12N, R6E, UM Dear Mr. Staudinger: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. Proposed dry ditch sample interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30'). This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this day of August 2024. 7 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.07 16:22:19 -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: 18,737'TVD:4,093' 4a. Location of Well (Governmental Section): 7. Property Designation: ADL 392984, Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1818’ FSL, 3388’ FEL, Sec 29, T12N, R6E, UM 08/20/24 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 1124’ FSL, 810’ FEL, Sec 19, T12N, R6E, UM 5,066' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 70' 15. Distance to Nearest Well Open Surface: x-422424 y- 5,972,834.19 Zone- 4 23' to Same Pool:1,800' 16. Deviated wells: Kickoff depth: N/A feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42' 20"x34" 215# X-52 Welded 80' Surface Surface 128' 54' 16" 13-3/8" 68# L-80 TXP BTC 2,684' Surface Surface 2,684' 2,342' 12-1/4" 9-5/8" 47# L-80 HYD 563 10,453' 2,534' 2,260' 12,987' 4,093' Tie Back 9-5/8" 47# L-80 HYD 563 2,534' Surface Surface 2,534' 2,260' 8-1/2" 4-1/2" 12.6# P-110S HYD 563 5,910' 12,827' 4,061' 18,737' 4,093' Tubing 4-1/2" 12.6# P-110S HYD 563 12,827' Surface Surface 12,827' 4,061' 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 3,733 acres 18.Casing Program: NDBi-016 Pikka / Nanushuk Oil Pool Uncemented N/A Commission Use Only See cover letter for other requirements. LONS 19-003 900 E Benson Boulevard, Suite 500, Anchorage, AK 99508 Oil Search Alaska, LLC 2450’ FSL, 2820’ FEL, Sec 4, T11N, R6E, UM 393016, 393020, 391455, 393018, 393010 IS000361277U STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1,872 Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface See attachment 6 See attachment 6 1,460 LengthCasing Top - Setting Depth - BottomSpecifications Total Depth MD (ft): Total Depth TVD (ft): Conductor/Structural 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): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): See attachment 6 Effect. Depth MD (ft): Effect. Depth TVD (ft): s N ype of W L l R L 1b S Class: os N s No s N o D s s sD o well is p G S S 20 S S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Senior Drilling Engineer 7/17/2024 By Grace Christianson at 9:22 am, Jul 24, 2024 An AOGCC Injection Order is required prior to beginning injection operations. Pikka 50-103-20892-00-00224-105 110 DSR-7/29/24A.Dewhurst 07AUG24BJM 8/7/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.07 16:22:32 -08'00'08/07/24 08/07/24 RBDMS JSB 080824 NDBi-016 (PTD 224-105) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨApproval 1.KWƚĞƐƚƚŽϯϱϬϬƉƐŝ͕ŶŶƵůĂƌƚĞƐƚƚŽϯϬϬϬƉƐŝ͘ 2.>Kdͬ&/dƌĞƐƵůƚƐƚŽďĞƐƵďŵŝƩĞĚƚŽK'ǁŝƚŚŝŶϰϴŚŽƵƌƐŽĨŽďƚĂŝŶŝŶŐƚŚĞĚĂƚĂ͘ ϯ͘ /ĨDWǁŝůůďĞƵƐĞĚ͕Kŝů^ĞĂƌĐŚŵƵƐƚƐƵďŵŝƚKWĂŶĚDWƐƚĂĐŬƵƉĚŝĂŐƌĂŵĂŶĚŇŽǁͬĐŚŽŬĞ ĚŝĂŐƌĂŵƐĂŶĚŽďƚĂŝŶƐĞƉĂƌĂƚĞĂƉƉƌŽǀĂůĨƌŽŵK'ƚŽƵƐĞDW͘ 4.EŽƟĨLJK'ŝĨĐĞŵĞŶƚũŽďƐĚŽŶŽƚŐŽĂĐĐŽƌĚŝŶŐƚŽƉůĂŶŽƌŝĨũŽďƉĂƌĂŵĞƚĞƌƐĂƌĞŶŽƚĂƐ ĞdžƉĞĐƚĞĚ;ůŽƐƐĞƐŽĐĐƵƌ͕ƵŶĞdžƉĞĐƚĞĚůŝŌƉƌĞƐƐƵƌĞƐŽĐĐƵƌ͕ĐĞŵĞŶƚŝƐŶŽƚĐŝƌĐƵůĂƚĞĚŽīƚŚĞƚŽƉŽĨ ƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞůŝŶĞƌ͕ĞƚĐ͘Ϳ. 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NDBi-016 is planned to be a horizontal injector targeting the Nanushuk 3. The approximate spud date is anticipated to be August 20th, 2024. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~81 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8” tieback will be run to the top of the 9-5/8” liner. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand and the lateral will be drilled to TD. The well will be completed as a stimulated 4-1/2” liner with frac sleeves and isolation packers. The production liner will be tied back to surface with a 4-1/2” tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (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, Application for Permit to Drill NDBi-016 Well Table of Contents 1. Well Name......................................................................................................................................3 2. Location Summary..........................................................................................................................3 3. Blowout Prevention Equipment Information.................................................................................4 4. Drilling Hazards Information...........................................................................................................5 5. Procedure for Conducting Formation Integrity Tests.....................................................................6 6. Casing and Cementing Program.....................................................................................................6 7. Diverter System Information..........................................................................................................7 8. Drilling Fluid Program.....................................................................................................................7 9. Abnormally Pressured Formation Information..............................................................................8 10. Seismic Analysis............................................................................................................................8 11. Seabed Condition Analysis............................................................................................................8 12. Evidence of Bonding.....................................................................................................................8 13. Proposed Drilling Program ...........................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................11 15. Proposed Variance Request........................................................................................................11 Attachments..................................................................................................................................................13 Attachment 1: Location Maps..........................................................................................................14 Attachment 2: Directional Plan........................................................................................................15 Attachment 3: BOPE Equipment ......................................................................................................16 Attachment 4: Drilling Hazards.........................................................................................................17 Attachment 5: Leak Off Test Procedure...........................................................................................19 Attachment 6: Cement Summary.....................................................................................................20 Attachment 7: Prognosed Formation Tops......................................................................................22 Attachment 8: Well Schematic.........................................................................................................23 Attachment 9: Formation Evaluation Program................................................................................24 Attachment 10: Wellhead & Tree Diagram......................................................................................25 Attachment 11: Injector Area of Review..........................................................................................26 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDBi-016. This will be a development injection 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 2450’ FSL, 2820’ FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,834 E 422,424 Rig KB Elevation 47’ above GL Ground Level 23’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 1818’ FSL, 3388’ FEL, Sec 29, T12N, R6E, UM NAD 27 Coordinate System N 5,982,823 E 416,659 Measured Depth, Rig KB (MD) 13,405’ Total Vertical Depth, Rig KB (TVD) 4,151’ Total vertical Depth, Subsea (TVDSS) 4,081’ Location at Bottom of Productive Interval Reference to Government Section Lines 1124’ FSL, 810’ FEL, Sec 19, T12N, R6E, UM NAD 27 Coordinate System N 5,987,432’ E 413,994’ Measured Depth, Rig KB (MD) 18,737’ Total Vertical Depth, Rig KB (TVD) 4,092’ Total vertical Depth, Subsea (TVDSS) 4,022’ (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 NDBi-016 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Parker 272 BOP Equipment: BOP Equipment x NOV Shaffer Spherical annular BOP, 13-5/8” x 5000 psi x NOV T3 6012 double gate, 13-5/8” x 5000 psi x Mud cross, 13-5/8” x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets x Choke Line, 3-1/8” x 5000 psi with 3-1/8” manual and HCR valve x Kill Line, 2-1/16” x 5000 psi with 3-1/8” manual and HCR valve x NOV T3 6012 single gate, 13-5/8” x 5000 psi Choke Manifold x 3-1/8” x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit x NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,865 psi in the Nanushuk 3 at 4,082’ TVD (8.8ppg EMW Nanushuk 3 formation to section TD) Maximum surface pressure 1,457 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,082’ 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 annular pressure during frac job] Integrity Test – 12-1/4” hole FIT after drilling 20’-50’ of new hole to 15.0ppg. (13.5 ppg LOT required for Kick Tolerance.) 13-3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by 50% of Casing Burst] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,872 psi in the Nanushuk 3.2 at 4,117’ TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,460 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,117’ 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 annular pressure during frac job] Integrity Test – 8-1/2” hole FIT after drilling 20’-50’ of new hole to 14.0 ppg. (10.5 ppg EMW LOT Required for infinite kick tolerance.) 9-5/8” Liner Test 4,000 psi surface pressure [Test pressure driven by annular pressure during frac job] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be over-pressured at 10.2ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 54’ 16” 13-3/8” 68# L-80 TXP BTC 2,684’ Surface 2,684’ / 2,342’ 12-1/4” 9-5/8” 47# L-80 HYD 563 10,453’ 2,534’ 12,987’ / 4,093’ Tie Back 9-5/8” 47# L-80 HYD 563 2,534’ Surface 2,534’ / 2,260’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 5,910’ 12,827’ 18,737’ / 4,093’ Tubing 4-1/2” 12.6# P-110S HYD 563 12,827’ Surface 12,827’ / 4,061’ Please refer to Attachment 6: Cement Summary for further details. 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line Please refer to Attachment 3: BOPE Equipment for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Intermediate Hole Production Hole Mud Type Water based Spud Mud Mineral Oil Based Mud Mineral Oil Based Mud Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 9.5 – 10 ppg 100-300 seconds ALAP 30-80 < 10 ml/30min n/a 8.6-10.5 <35 11.0*-12.0 ppg 50-80 seconds ALAP 15-30 n/a < 5 ml/30min n/a n/a 9.0*-10ppg 50-80 seconds ALAP 10-20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. *Managed Pressure Drilling may be used for the intermediate and/or production hole on NDBi-016 if the MPD system is installed and fully operational on the rig. If MPD is utilized, mud weights may be reduced for these hole sections. 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 NDBi-016 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 NDBi-016 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program NDBi-016 1. Drill 20” conductor to ~128’ MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools and diverter over the 20” conductor. Verify that the diverter line is at least 75’ away from a potential source of ignition and beyond the drill rig substructure. 4. Function test diverter and knife valve as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing diverter test. 5. Pick up 5-7/8” drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16” motor BHA with MWD and LWD tools. 6. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 7. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 8. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 9. ND diverter and NU casing head and spacer spool. NU BOPE (configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 9-5/8” Fixed Rams). Test rams to 3500 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing BOP test. 10. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 11. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment 12. If Managed Pressure Drilling is utilized, install MPD bearing assembly and displace well to MOBM. 13. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test. 14. Directionally drill 12-1/4” intermediate hole section to TD. 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. 16. Set liner hanger and release running tool. Cement 9-5/8” liner with 1st stage cement job If MPD is used, submit updated BOP/MPD stack-up and flow diagram. Obtain approval from AOGCC before using MPD. MPD not planned per G. Staudinger 8/6/24 -bjm 13-3/8" 68# L80 burst rating = 5020 psi. -bjm as per cement program. Monitor returns during displacement until plug bump. 17. Un-sting from liner hanger and POOH and LD liner running tools. 18. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Sting into second stage tool pump secondary stage, SO and set liner top packer. POOH and lay down running tool. 19. Run 9-5/8” tie-back string. Freeze protect the 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 20. Pressure test 13-3/8” x 9-5/8” to 2600 psi for 30 min. 21. Pressure test the 9-5/8” liner and tieback to 3500 psi for 30 min. 22. Make up 8-1/2” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to production hole MOBM. 23. Drill out shoe track and 20 - 50’ of new formation. Perform formation integrity test. 24. Directionally drill 8-1/2” hole section as per well plan to TD. Perform wiper trips as required. 25. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary 26. RU and run 4-1/2” production liner with liner hanger / liner top packer and downhole jewelry to TD. 27. Set and pressure test the 9-5/8” x 4-1/2” IA to liner top packer to 4,000 psi for 10 min. Release the running tool. 28. Circulate corrosion inhibited brine. 29. POOH and LD liner running tool. 30. RU and run 4-1/2” upper completion and downhole jewelry with TEC wire. Space out seals. 31. Land tubing hanger. 32. 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. 33. Reverse circulate freeze protect and U-Tube. 34. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. 35. 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. 15. Proposed Variance Request 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire annular space from the casing shoe to above shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the significant hydrocarbon zone in the Nanushuk formation (primary job), and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. The primary cement job will target a top of cement 500’ MD or 250’ TVD, whichever is greater, above the top of the Nanushuk. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the intermediate liner is not achievable without exceeding the fracture gradient and compromising cement placement and zonal isolation. The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be designed to: 1) provide suitable and safe operating conditions for the total measured depth proposed; 2) confine fluids to the wellbore; 3) prevent migration of fluids from one stratum to another; 4) ensure control of well pressures encountered; 5) protect against thaw subsidence and freezeback effects within permafrost; 6) prevent contamination of freshwater; 7) protect significant hydrocarbon zones; and 8) provide well control until the next casing is set, considering all factors relevant to well control including formation fracture gradients, formation pressures, casing setting depths, and proposed total depth. The formation interval between the top of stage one and the bottom of stage two includes the Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with very low permeability and contain no significant hydrocarbons. Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,640’ TVD. The Tuluvak formation below 2,640’ TVD is not a significant hydrocarbon zone. A stage collar placement is proposed 50’ MD below the TS 790 formation marker (Upper Tuluvak). This stage collar depth will isolate any potential gas based on offset well data. The TS 875 and TS 870 clinoform is between the TS 880 clinoform and TS 790 top. The TS 875 and TS 870 clinoforms are shale dominated, very low net to gross, have no vertical permeability, and represents a seal to the hydrocarbon bearing TS 880. Moving the cementing stage tool to be placed at 50’ MD below the TS 790 formation marker allows placement of higher quality cement that provides better isolation across the significant hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will add risk to the primary objective of cement isolation across the significant hydrocarbon zone which is only located in the upper portion of the Tuluvak (TS 880). The increased risk is due to: 1) Cementing the entire Tuluvak would require large cement jobs that jeopardize cement isolation across the upper Tuluvak. 2) Large cement jobs likely require the use of lighter weight cement across the significant hydrocarbon zone. Recommend granting requested variance to allow a two-stage cementing operation. Recommend granting variance from pool rules to isolate significant hydrocarbons as proposed above (base defined from TS790 maker). -A.Dewhurst 07AUG24 Attachments Attachment 1: Location Maps U012N0U012N005E13 U012N006E27 U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N006E28 U012N006E20 U012N006E22 U012N006E21 U012N006E31 U011N006E06 U012N006E19 U012N006E30 ADL 392984 ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393007 ADL 393008 ADL 391322 ADL 391445 ADL 391455 ADL 393011 ADL 393010 DW-02 NDB-024 NDB-032 NDB-051 NDBi-014 NDBi-018 NDBi-030 NDBi-043 NDBi-044 QUGRUK 301 QUGRUK 3A Maxar OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDBI-016 PLANNED TRAJECTORY OTHER DRILLED NDB WELLS NDBI-016 SURFACE LOCATION NDBI-016 BOTTOM HOLE 0.25-MILE BUFFER 0.5-MILE BUFFER PRODUCTION INTERVAL NDB DRILLED WELLS BOTTOM HOLES DEV EXPLORATION WELLS BOTTOM HOLES OTHER WELL TRAJECTORIES BY OTHERS DATE: 6/13/2024. By: JN 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi16_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDBi-016 WELL OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD OTHER NDB WELLS WELL HEAD DIVERTER (50-ft) RIG OUTLINES DATE: 6/13/2024. By: JB 0204010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi16_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDBi-016 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.33559653 Ͳ150.6325192 N 70° 20' 08.01473" W 150° 37' 57.0691" 5,972,582.20 1,562,456.98 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.33591466 Ͳ150.629386 N 70° 20' 09.2982" W 150° 37' 46.7923" 5,972,834.19 422,424.18 State Plane NAD83 Zone 4 (as-built) StatePlane NAD27 Zone 4 (as-built) 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 2 447.0 0.00 0.00 447.0 0.0 0.0 0.00 0.00 0.0 Start Build 2.50 3 987.0 13.50 340.00 982.0 59.5 -21.7 2.50 340.00 62.2 Start 160.0 hold at 987.0 MD 4 1147.0 13.50 340.00 1137.6 94.6 -34.4 0.00 0.00 99.0 Start DLS 3.00 TFO -11.72 5 3405.3 80.99 329.03 2585.1 1461.6 -788.5 3.00 -11.72 1659.4 Start 9422.7 hold at 3405.3 MD 6 12827.9 80.99 329.03 4061.4 9440.9 -5577.8 0.00 0.00 10965.5 Start DLS 3.00 TFO 175.98 7 12991.2 76.10 329.38 4093.8 9578.3 -5659.8 3.00 175.98 11125.5 Start 66.8 hold at 12991.2 MD 813058.1 76.10 329.38 4109.9 9634.1 -5692.8 0.00 0.00 11190.4 Start Turn 0.00 9 13405.6 90.00 329.38 4151.8 9930.3 -5868.1 4.00 0.00 11534.5 NDBi-16 Heel Rev 2.0 Start DLS 0.00 TFO -90.00 10 18399.4 90.00 329.37 4151.8 14227.5 -8412.1 0.00 -90.00 16528.3 NDBi-016 Build Rev 0.0 Start DLS 5.99 TFO -0.53 11 18737.0 110.23 329.17 4092.8 14511.7 -8581.1 5.99 -0.53 16859.0 NDBi-16 TD Rev 0.0 TD at 18737.0 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 Plan: NDBi-016 Rev G.0 Plan Summary 0 3 Dogleg Severity0 3000 6000 9000 12000 15000 18000 Measured Depth 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 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] 7075100125150175200225250275300325350375400425450475500524549574599624648673697721745 Plan: NDB-011 Rev A.0 475075100125150175200225250275300325350375400425450475500525550575600625650675700725750775800824849874899924949974999102410491074109911241149117311981223Plan: NDB-013 Rev B.0 70751001251501752002252502753003253503754004254504755005255505756006256506757007257507768018268518769029279529771002102710521077110211261151117612021227125312791304133013561382Plan: NDB-015 Rev A.0 475075100125150175200225250275300325350375400425450475500524549574598623647Plan:NDB-021 Rev A.0 475075100125150175200225250275300325350375400425450475500525550575600625650675700725750775800825851876901926951977100210271051107611011125Plan: NDBi-012 Rev A.1 475075100125150175200225250275300325350375400425450475499524549573598622646670694718742765788812835 857 880 NDBi-014 4750751001251501752002252502753003253503754004254504755005255505756006256506757007257507758008248498748999249489739981023104810731098112311481173119712221247127212961321134613701395142014441469149415181543156815921617164116661690171517401764178918131838186218871911193619601985200920342058208321072131215621802205222922532278230223272351237524002424Plan: NDBi-018 Rev I.0 7075100125150175200225250275300325350375400425450475500524549574598622647671695718742765 788Plan: NDBi-019 Rev A.0 70751001251501752002252502753003253503754004254504755005255505756006256516767017267517778028278538789039299549791004102910541079Plan: NDBi-020 Rev A.0 47507510012515017520022525027530032535037540042545047550052555057560062565067570072575077580082584987489992494997399810231048107310981123114811731198122212471272129613211346137113951420144514691494151915431568159216171642166616911715174017641789181418381863188719121936196119852010203420582083210721322156218122052229225422782303232723512376240024242449Plan: NDBi-018 Rev I.0 0 2250 True Vertical Depth0 2500 5000 7500 10000 12500 15000 17500 Vertical Section at 329.40° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 0 28 55 Centre to Centre Separation0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.114 SURVEY PROGRAM Date: 2021-02-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 700.0 Plan: NDBi-016 Rev G.0 (NDBi-016)SDI_URSA1_I4 700.0 1900.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+Sag 700.0 2684.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 2684.0 3884.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS 2684.0 4000.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 4000.0 4700.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+Sag 4700.0 5900.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+Sag 4700.0 12987.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 12987.0 14187.0 Plan: NDBi-016 Rev G.0 (NDBi-016)2_MWD+IFR2+Sag 12987.0 18737.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag Surface Location North / 5972582.20 East / 1562456.98 Elevation / 22.8 CASING DETAILS TVD MD Name 128.0 128.020" Conductor Casing 2342.0 2684.013-3/8" Surface Casing 4092.8 12987.09-5/8" Intermediate Liner 4092.8 18737.14-1/2" Production Liner Mag Model & Date: BGGM2023 31-Dec-24 Magnetic North is 13.96° East of True North (Magnetic Decl Mag Dip & Field Strength: 80.54° 57140.88198948nT FORMATION TOP DETAILS TVDPathFormation 1047.8 Upper SB 1147.8Base Ice Bearing Permafrost 1393.8Base Permafrost 1762.8Middle SB 2141.8 MCU 2439.8 T Shale 2499.8 T Sand 2799.8 TS_790 3118.8 Seabee 3791.8Nanushuk 3830.8NT8 MFS 3846.8 NT7 MFS3916.8NT6 MFS 3971.8NT5 MFS 4009.8NT4 MFS 4082.8NT3 MFS 4102.8NT3.2 PB 4116.8NT3.2 Reservoir 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 Parker 272 as Planned @ 69.8usft Standard Planning Report - Geographic 14 June, 2024 Plan: Plan: NDBi-016 Rev G.0 Santos NAD27 Conversion Pikka NDB NDBi-016 NDBi-016 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka, North Slope Alaska, United States Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: NDB Map Slot Radius:0.9 usft usft usft " 5,972,909.70 423,383.56 20 70° 20' 10.138 N 150° 37' 17.796 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: NDBi-016 Wellhead Elevation:0.5 0.0 0.0 5,972,834.19 422,424.18 0.0 70° 20' 9.298 N 150° 37' 45.792 W 22.8 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDBi-016 Model NameMagnetics IFR 31/12/2024 24.73 80.61 57,282.48983899 Phase:Version: Audit Notes: Design Plan: NDBi-016 Rev G.0 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 329.400.00.047.0 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 2 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 14/06/2024 Depth To (usft) Depth From (usft) SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISC Plan: NDBi-016 Rev G.0 (NDBi-0147.0 700.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-016 Rev G.0 (NDBi-02700.0 1,900.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-016 Rev G.0 (NDBi-03700.0 2,684.0 3_MWD+IFR2+MS H021Ma: IIFR dec & multi-s Plan: NDBi-016 Rev G.0 (NDBi-042,684.0 3,884.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-016 Rev G.0 (NDBi-052,684.0 4,000.0 3_MWD+Sag A002Mb/ISC4: BGGM dec + Plan: NDBi-016 Rev G.0 (NDBi-064,000.0 4,700.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-016 Rev G.0 (NDBi-074,700.0 5,900.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-016 Rev G.0 (NDBi-084,700.0 12,987.0 2_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-016 Rev G.0 (NDBi-0912,987.0 14,187.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-016 Rev G.0 (NDBi-01012,987.0 18,737.0 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 0.000.000.000.000.00.0447.00.000.00447.0 340.000.002.502.50-21.759.5982.0340.0013.50987.0 0.000.000.000.00-34.494.61,137.6340.0013.501,147.0 -11.72-0.492.993.00-788.51,461.62,585.1329.0380.993,405.3 0.000.000.000.00-5,577.89,440.94,061.4329.0380.9912,827.9 175.980.22-2.993.00-5,659.89,578.34,093.8329.3876.1012,991.2 0.000.000.000.00-5,692.89,634.14,109.9329.3876.1013,058.1 0.000.000.004.00-5,868.19,930.34,151.8329.3890.0013,405.6 -90.000.000.000.00-8,412.114,227.54,151.8329.3790.0018,399.4 -0.53-0.065.995.99-8,581.114,511.74,092.8329.17110.2318,737.0 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 3 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: 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 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W 100.0 0.00 100.0 0.0 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W 128.0 0.00 128.0 0.0 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W 300.0 0.00 300.0 0.0 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W 400.0 0.00 400.0 0.0 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W 447.0 0.00 447.0 0.0 0.00.00 422,424.185,972,834.19 70° 20' 9.298 N 150° 37' 45.792 W Start Build 2.50 500.0 1.33 500.0 0.6 -0.2340.00 422,423.985,972,834.77 70° 20' 9.304 N 150° 37' 45.799 W 600.0 3.83 599.9 4.8 -1.7340.00 422,422.485,972,839.01 70° 20' 9.345 N 150° 37' 45.843 W 700.0 6.33 699.5 13.1 -4.8340.00 422,419.545,972,847.35 70° 20' 9.427 N 150° 37' 45.932 W 800.0 8.83 798.6 25.5 -9.3340.00 422,415.165,972,859.78 70° 20' 9.549 N 150° 37' 46.063 W 900.0 11.33 897.1 41.9 -15.3340.00 422,409.355,972,876.28 70° 20' 9.711 N 150° 37' 46.238 W 987.0 13.50 982.0 59.5 -21.7340.00 422,403.145,972,893.91 70° 20' 9.883 N 150° 37' 46.425 W Start 160.0 hold at 987.0 MD 1,000.0 13.50 994.7 62.4 -22.7340.00 422,402.135,972,896.78 70° 20' 9.911 N 150° 37' 46.455 W 1,054.7 13.50 1,047.8 74.3 -27.1340.00 422,397.895,972,908.81 70° 20' 10.029 N 150° 37' 46.583 W Upper Schrader Bluff 1,100.0 13.50 1,091.9 84.3 -30.7340.00 422,394.385,972,918.79 70° 20' 10.127 N 150° 37' 46.688 W 1,147.0 13.50 1,137.6 94.6 -34.4340.00 422,390.735,972,929.14 70° 20' 10.229 N 150° 37' 46.798 W Start DLS 3.00 TFO -11.72 1,157.5 13.81 1,147.8 96.9 -35.3339.73 422,389.905,972,931.47 70° 20' 10.251 N 150° 37' 46.823 W Base Ice Bearing Permafrost 1,200.0 15.06 1,189.0 106.8 -39.0338.76 422,386.255,972,941.42 70° 20' 10.349 N 150° 37' 46.933 W 1,300.0 18.02 1,284.8 133.2 -49.8336.99 422,375.765,972,967.87 70° 20' 10.608 N 150° 37' 47.247 W 1,400.0 20.99 1,379.1 163.7 -63.2335.70 422,362.675,972,998.57 70° 20' 10.909 N 150° 37' 47.639 W 1,415.8 21.46 1,393.8 169.0 -65.6335.53 422,360.365,973,003.81 70° 20' 10.960 N 150° 37' 47.708 W Base Permafrost Transition 1,500.0 23.96 1,471.5 198.4 -79.3334.73 422,346.985,973,033.43 70° 20' 11.250 N 150° 37' 48.107 W 1,600.0 26.95 1,561.7 237.2 -97.9333.95 422,328.765,973,072.34 70° 20' 11.631 N 150° 37' 48.651 W 1,700.0 29.93 1,649.7 279.8 -119.0333.33 422,308.065,973,115.22 70° 20' 12.050 N 150° 37' 49.269 W 1,800.0 32.92 1,735.0 326.3 -142.7332.80 422,284.915,973,161.92 70° 20' 12.507 N 150° 37' 49.959 W 1,833.3 33.91 1,762.8 342.6 -151.1332.64 422,276.675,973,178.32 70° 20' 12.668 N 150° 37' 50.204 W Middle Schrader Bluff 1,900.0 35.91 1,817.5 376.5 -168.7332.35 422,259.405,973,212.34 70° 20' 13.001 N 150° 37' 50.719 W 2,000.0 38.90 1,896.9 430.2 -197.1331.97 422,231.605,973,266.33 70° 20' 13.529 N 150° 37' 51.548 W 2,100.0 41.89 1,973.1 487.3 -227.7331.63 422,201.565,973,323.74 70° 20' 14.090 N 150° 37' 52.442 W 2,200.0 44.88 2,045.7 547.6 -260.5331.33 422,169.395,973,384.42 70° 20' 14.684 N 150° 37' 53.400 W 2,300.0 47.88 2,114.7 611.0 -295.4331.06 422,135.175,973,448.19 70° 20' 15.308 N 150° 37' 54.419 W 2,340.9 49.10 2,141.8 637.8 -310.2330.95 422,120.615,973,475.12 70° 20' 15.571 N 150° 37' 54.853 W MCU 2,400.0 50.87 2,179.8 677.4 -332.2330.81 422,098.995,973,514.89 70° 20' 15.960 N 150° 37' 55.496 W 2,500.0 53.87 2,240.9 746.4 -371.0330.58 422,060.955,973,584.33 70° 20' 16.639 N 150° 37' 56.628 W 2,600.0 56.86 2,297.7 818.0 -411.5330.37 422,021.155,973,656.33 70° 20' 17.343 N 150° 37' 57.813 W 2,684.0 59.38 2,342.0 879.9 -446.9330.21 421,986.455,973,718.63 70° 20' 17.952 N 150° 37' 58.845 W 13-3/8" Surface Casing 2,700.0 59.86 2,350.1 891.9 -453.8330.18 421,979.715,973,730.67 70° 20' 18.070 N 150° 37' 59.046 W 2,800.0 62.85 2,398.1 968.0 -497.5329.99 421,936.745,973,807.17 70° 20' 18.818 N 150° 38' 0.324 W 2,896.2 65.73 2,439.8 1,043.0 -541.0329.82 421,894.065,973,882.60 70° 20' 19.555 N 150° 38' 1.594 W Tuluvak Shale 2,900.0 65.85 2,441.4 1,046.0 -542.7329.82 421,892.355,973,885.61 70° 20' 19.585 N 150° 38' 1.645 W 3,000.0 68.84 2,479.9 1,125.6 -589.2329.65 421,846.675,973,965.77 70° 20' 20.369 N 150° 38' 3.003 W 3,057.5 70.57 2,499.8 1,172.1 -616.5329.56 421,819.885,974,012.53 70° 20' 20.826 N 150° 38' 3.800 W Tuluvak Sand 3,100.0 71.84 2,513.5 1,206.8 -636.9329.49 421,799.825,974,047.44 70° 20' 21.167 N 150° 38' 4.397 W 3,200.0 74.84 2,542.2 1,289.3 -685.7329.33 421,751.935,974,130.39 70° 20' 21.978 N 150° 38' 5.821 W 3,300.0 77.83 2,565.8 1,372.8 -735.4329.18 421,703.145,974,214.40 70° 20' 22.799 N 150° 38' 7.272 W 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 4 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 3,400.0 80.83 2,584.3 1,457.1 -785.8329.03 421,653.575,974,299.23 70° 20' 23.628 N 150° 38' 8.745 W 3,405.3 80.99 2,585.1 1,461.6 -788.5329.03 421,650.945,974,303.70 70° 20' 23.672 N 150° 38' 8.823 W Start 9422.7 hold at 3405.3 MD 3,500.0 80.99 2,600.0 1,541.8 -836.6329.03 421,603.625,974,384.42 70° 20' 24.461 N 150° 38' 10.230 W 3,600.0 80.99 2,615.7 1,626.5 -887.5329.03 421,553.685,974,469.62 70° 20' 25.294 N 150° 38' 11.715 W 3,700.0 80.99 2,631.3 1,711.2 -938.3329.03 421,503.735,974,554.81 70° 20' 26.127 N 150° 38' 13.200 W 3,800.0 80.99 2,647.0 1,795.8 -989.1329.03 421,453.795,974,640.01 70° 20' 26.960 N 150° 38' 14.685 W 3,900.0 80.99 2,662.7 1,880.5 -1,039.9329.03 421,403.845,974,725.20 70° 20' 27.792 N 150° 38' 16.170 W 4,000.0 80.99 2,678.3 1,965.2 -1,090.8329.03 421,353.905,974,810.40 70° 20' 28.625 N 150° 38' 17.656 W 4,100.0 80.99 2,694.0 2,049.9 -1,141.6329.03 421,303.955,974,895.59 70° 20' 29.458 N 150° 38' 19.141 W 4,200.0 80.99 2,709.7 2,134.6 -1,192.4329.03 421,254.015,974,980.79 70° 20' 30.291 N 150° 38' 20.626 W 4,300.0 80.99 2,725.3 2,219.3 -1,243.3329.03 421,204.065,975,065.98 70° 20' 31.123 N 150° 38' 22.111 W 4,400.0 80.99 2,741.0 2,303.9 -1,294.1329.03 421,154.125,975,151.18 70° 20' 31.956 N 150° 38' 23.596 W 4,500.0 80.99 2,756.7 2,388.6 -1,344.9329.03 421,104.175,975,236.38 70° 20' 32.789 N 150° 38' 25.082 W 4,600.0 80.99 2,772.3 2,473.3 -1,395.7329.03 421,054.235,975,321.57 70° 20' 33.622 N 150° 38' 26.567 W 4,700.0 80.99 2,788.0 2,558.0 -1,446.6329.03 421,004.285,975,406.77 70° 20' 34.454 N 150° 38' 28.052 W 4,775.4 80.99 2,799.8 2,621.8 -1,484.9329.03 420,966.645,975,470.98 70° 20' 35.082 N 150° 38' 29.172 W TS_790 4,800.0 80.99 2,803.7 2,642.7 -1,497.4329.03 420,954.345,975,491.96 70° 20' 35.287 N 150° 38' 29.538 W 4,900.0 80.99 2,819.3 2,727.3 -1,548.2329.03 420,904.405,975,577.16 70° 20' 36.120 N 150° 38' 31.023 W 5,000.0 80.99 2,835.0 2,812.0 -1,599.0329.03 420,854.455,975,662.35 70° 20' 36.953 N 150° 38' 32.509 W 5,100.0 80.99 2,850.7 2,896.7 -1,649.9329.03 420,804.515,975,747.55 70° 20' 37.785 N 150° 38' 33.994 W 5,200.0 80.99 2,866.3 2,981.4 -1,700.7329.03 420,754.565,975,832.74 70° 20' 38.618 N 150° 38' 35.480 W 5,300.0 80.99 2,882.0 3,066.1 -1,751.5329.03 420,704.625,975,917.94 70° 20' 39.451 N 150° 38' 36.965 W 5,400.0 80.99 2,897.7 3,150.8 -1,802.4329.03 420,654.675,976,003.13 70° 20' 40.283 N 150° 38' 38.451 W 5,500.0 80.99 2,913.3 3,235.4 -1,853.2329.03 420,604.735,976,088.33 70° 20' 41.116 N 150° 38' 39.936 W 5,600.0 80.99 2,929.0 3,320.1 -1,904.0329.03 420,554.785,976,173.52 70° 20' 41.949 N 150° 38' 41.422 W 5,700.0 80.99 2,944.7 3,404.8 -1,954.8329.03 420,504.845,976,258.72 70° 20' 42.782 N 150° 38' 42.908 W 5,800.0 80.99 2,960.3 3,489.5 -2,005.7329.03 420,454.895,976,343.91 70° 20' 43.614 N 150° 38' 44.394 W 5,900.0 80.99 2,976.0 3,574.2 -2,056.5329.03 420,404.955,976,429.11 70° 20' 44.447 N 150° 38' 45.879 W 6,000.0 80.99 2,991.7 3,658.9 -2,107.3329.03 420,355.005,976,514.31 70° 20' 45.280 N 150° 38' 47.365 W 6,100.0 80.99 3,007.3 3,743.5 -2,158.2329.03 420,305.065,976,599.50 70° 20' 46.112 N 150° 38' 48.851 W 6,200.0 80.99 3,023.0 3,828.2 -2,209.0329.03 420,255.115,976,684.70 70° 20' 46.945 N 150° 38' 50.337 W 6,300.0 80.99 3,038.7 3,912.9 -2,259.8329.03 420,205.175,976,769.89 70° 20' 47.778 N 150° 38' 51.823 W 6,400.0 80.99 3,054.3 3,997.6 -2,310.6329.03 420,155.225,976,855.09 70° 20' 48.610 N 150° 38' 53.309 W 6,500.0 80.99 3,070.0 4,082.3 -2,361.5329.03 420,105.285,976,940.28 70° 20' 49.443 N 150° 38' 54.795 W 6,600.0 80.99 3,085.7 4,166.9 -2,412.3329.03 420,055.335,977,025.48 70° 20' 50.276 N 150° 38' 56.281 W 6,700.0 80.99 3,101.3 4,251.6 -2,463.1329.03 420,005.395,977,110.67 70° 20' 51.108 N 150° 38' 57.767 W 6,800.0 80.99 3,117.0 4,336.3 -2,514.0329.03 419,955.445,977,195.87 70° 20' 51.941 N 150° 38' 59.253 W 6,811.5 80.99 3,118.8 4,346.0 -2,519.8329.03 419,949.705,977,205.67 70° 20' 52.037 N 150° 38' 59.424 W Seabee 6,900.0 80.99 3,132.7 4,421.0 -2,564.8329.03 419,905.505,977,281.06 70° 20' 52.774 N 150° 39' 0.739 W 7,000.0 80.99 3,148.3 4,505.7 -2,615.6329.03 419,855.565,977,366.26 70° 20' 53.606 N 150° 39' 2.225 W 7,100.0 80.99 3,164.0 4,590.4 -2,666.4329.03 419,805.615,977,451.45 70° 20' 54.439 N 150° 39' 3.711 W 7,200.0 80.99 3,179.7 4,675.0 -2,717.3329.03 419,755.675,977,536.65 70° 20' 55.272 N 150° 39' 5.197 W 7,300.0 80.99 3,195.3 4,759.7 -2,768.1329.03 419,705.725,977,621.85 70° 20' 56.104 N 150° 39' 6.683 W 7,400.0 80.99 3,211.0 4,844.4 -2,818.9329.03 419,655.785,977,707.04 70° 20' 56.937 N 150° 39' 8.170 W 7,500.0 80.99 3,226.7 4,929.1 -2,869.8329.03 419,605.835,977,792.24 70° 20' 57.770 N 150° 39' 9.656 W 7,600.0 80.99 3,242.3 5,013.8 -2,920.6329.03 419,555.895,977,877.43 70° 20' 58.602 N 150° 39' 11.142 W 7,700.0 80.99 3,258.0 5,098.4 -2,971.4329.03 419,505.945,977,962.63 70° 20' 59.435 N 150° 39' 12.629 W 7,800.0 80.99 3,273.7 5,183.1 -3,022.2329.03 419,456.005,978,047.82 70° 21' 0.268 N 150° 39' 14.115 W 7,900.0 80.99 3,289.3 5,267.8 -3,073.1329.03 419,406.055,978,133.02 70° 21' 1.100 N 150° 39' 15.602 W 8,000.0 80.99 3,305.0 5,352.5 -3,123.9329.03 419,356.115,978,218.21 70° 21' 1.933 N 150° 39' 17.088 W 8,100.0 80.99 3,320.7 5,437.2 -3,174.7329.03 419,306.165,978,303.41 70° 21' 2.766 N 150° 39' 18.574 W 8,200.0 80.99 3,336.3 5,521.9 -3,225.5329.03 419,256.225,978,388.60 70° 21' 3.598 N 150° 39' 20.061 W 8,300.0 80.99 3,352.0 5,606.5 -3,276.4329.03 419,206.275,978,473.80 70° 21' 4.431 N 150° 39' 21.548 W 8,400.0 80.99 3,367.7 5,691.2 -3,327.2329.03 419,156.335,978,558.99 70° 21' 5.263 N 150° 39' 23.034 W 8,500.0 80.99 3,383.3 5,775.9 -3,378.0329.03 419,106.385,978,644.19 70° 21' 6.096 N 150° 39' 24.521 W 8,600.0 80.99 3,399.0 5,860.6 -3,428.9329.03 419,056.445,978,729.38 70° 21' 6.929 N 150° 39' 26.007 W 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 5 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: 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 80.99 3,414.7 5,945.3 -3,479.7329.03 419,006.495,978,814.58 70° 21' 7.761 N 150° 39' 27.494 W 8,800.0 80.99 3,430.3 6,029.9 -3,530.5329.03 418,956.555,978,899.78 70° 21' 8.594 N 150° 39' 28.981 W 8,900.0 80.99 3,446.0 6,114.6 -3,581.3329.03 418,906.605,978,984.97 70° 21' 9.426 N 150° 39' 30.468 W 9,000.0 80.99 3,461.7 6,199.3 -3,632.2329.03 418,856.665,979,070.17 70° 21' 10.259 N 150° 39' 31.954 W 9,100.0 80.99 3,477.3 6,284.0 -3,683.0329.03 418,806.715,979,155.36 70° 21' 11.092 N 150° 39' 33.441 W 9,200.0 80.99 3,493.0 6,368.7 -3,733.8329.03 418,756.775,979,240.56 70° 21' 11.924 N 150° 39' 34.928 W 9,300.0 80.99 3,508.7 6,453.4 -3,784.7329.03 418,706.835,979,325.75 70° 21' 12.757 N 150° 39' 36.415 W 9,400.0 80.99 3,524.3 6,538.0 -3,835.5329.03 418,656.885,979,410.95 70° 21' 13.589 N 150° 39' 37.902 W 9,500.0 80.99 3,540.0 6,622.7 -3,886.3329.03 418,606.945,979,496.14 70° 21' 14.422 N 150° 39' 39.389 W 9,600.0 80.99 3,555.7 6,707.4 -3,937.1329.03 418,556.995,979,581.34 70° 21' 15.255 N 150° 39' 40.876 W 9,700.0 80.99 3,571.3 6,792.1 -3,988.0329.03 418,507.055,979,666.53 70° 21' 16.087 N 150° 39' 42.363 W 9,800.0 80.99 3,587.0 6,876.8 -4,038.8329.03 418,457.105,979,751.73 70° 21' 16.920 N 150° 39' 43.850 W 9,900.0 80.99 3,602.7 6,961.5 -4,089.6329.03 418,407.165,979,836.92 70° 21' 17.752 N 150° 39' 45.337 W 10,000.0 80.99 3,618.3 7,046.1 -4,140.5329.03 418,357.215,979,922.12 70° 21' 18.585 N 150° 39' 46.824 W 10,100.0 80.99 3,634.0 7,130.8 -4,191.3329.03 418,307.275,980,007.32 70° 21' 19.417 N 150° 39' 48.311 W 10,200.0 80.99 3,649.7 7,215.5 -4,242.1329.03 418,257.325,980,092.51 70° 21' 20.250 N 150° 39' 49.799 W 10,300.0 80.99 3,665.3 7,300.2 -4,292.9329.03 418,207.385,980,177.71 70° 21' 21.083 N 150° 39' 51.286 W 10,400.0 80.99 3,681.0 7,384.9 -4,343.8329.03 418,157.435,980,262.90 70° 21' 21.915 N 150° 39' 52.773 W 10,500.0 80.99 3,696.7 7,469.5 -4,394.6329.03 418,107.495,980,348.10 70° 21' 22.748 N 150° 39' 54.260 W 10,600.0 80.99 3,712.3 7,554.2 -4,445.4329.03 418,057.545,980,433.29 70° 21' 23.580 N 150° 39' 55.748 W 10,700.0 80.99 3,728.0 7,638.9 -4,496.3329.03 418,007.605,980,518.49 70° 21' 24.413 N 150° 39' 57.235 W 10,800.0 80.99 3,743.7 7,723.6 -4,547.1329.03 417,957.655,980,603.68 70° 21' 25.245 N 150° 39' 58.723 W 10,900.0 80.99 3,759.3 7,808.3 -4,597.9329.03 417,907.715,980,688.88 70° 21' 26.078 N 150° 40' 0.210 W 11,000.0 80.99 3,775.0 7,893.0 -4,648.7329.03 417,857.765,980,774.07 70° 21' 26.910 N 150° 40' 1.698 W 11,100.0 80.99 3,790.7 7,977.6 -4,699.6329.03 417,807.825,980,859.27 70° 21' 27.743 N 150° 40' 3.185 W 11,107.2 80.99 3,791.8 7,983.7 -4,703.2329.03 417,804.255,980,865.36 70° 21' 27.802 N 150° 40' 3.291 W Nanushuk 11,200.0 80.99 3,806.3 8,062.3 -4,750.4329.03 417,757.875,980,944.46 70° 21' 28.575 N 150° 40' 4.673 W 11,300.0 80.99 3,822.0 8,147.0 -4,801.2329.03 417,707.935,981,029.66 70° 21' 29.408 N 150° 40' 6.160 W 11,356.1 80.99 3,830.8 8,194.5 -4,829.7329.03 417,679.925,981,077.44 70° 21' 29.875 N 150° 40' 6.994 W NT8 MFS 11,400.0 80.99 3,837.7 8,231.7 -4,852.0329.03 417,657.995,981,114.85 70° 21' 30.240 N 150° 40' 7.648 W 11,458.2 80.99 3,846.8 8,281.0 -4,881.6329.03 417,628.915,981,164.45 70° 21' 30.725 N 150° 40' 8.514 W NT7 MFS 11,500.0 80.99 3,853.3 8,316.4 -4,902.9329.03 417,608.045,981,200.05 70° 21' 31.073 N 150° 40' 9.135 W 11,600.0 80.99 3,869.0 8,401.0 -4,953.7329.03 417,558.105,981,285.25 70° 21' 31.905 N 150° 40' 10.623 W 11,700.0 80.99 3,884.7 8,485.7 -5,004.5329.03 417,508.155,981,370.44 70° 21' 32.738 N 150° 40' 12.111 W 11,800.0 80.99 3,900.3 8,570.4 -5,055.4329.03 417,458.215,981,455.64 70° 21' 33.570 N 150° 40' 13.599 W 11,900.0 80.99 3,916.0 8,655.1 -5,106.2329.03 417,408.265,981,540.83 70° 21' 34.403 N 150° 40' 15.086 W 11,905.0 80.99 3,916.8 8,659.3 -5,108.7329.03 417,405.765,981,545.10 70° 21' 34.445 N 150° 40' 15.161 W NT6 MFS 12,000.0 80.99 3,931.7 8,739.8 -5,157.0329.03 417,358.325,981,626.03 70° 21' 35.235 N 150° 40' 16.574 W 12,100.0 80.99 3,947.3 8,824.5 -5,207.8329.03 417,308.375,981,711.22 70° 21' 36.068 N 150° 40' 18.062 W 12,200.0 80.99 3,963.0 8,909.1 -5,258.7329.03 417,258.435,981,796.42 70° 21' 36.900 N 150° 40' 19.550 W 12,256.1 80.99 3,971.8 8,956.6 -5,287.2329.03 417,230.435,981,844.18 70° 21' 37.367 N 150° 40' 20.384 W NT5 MFS 12,300.0 80.99 3,978.7 8,993.8 -5,309.5329.03 417,208.485,981,881.61 70° 21' 37.733 N 150° 40' 21.038 W 12,400.0 80.99 3,994.4 9,078.5 -5,360.3329.03 417,158.545,981,966.81 70° 21' 38.565 N 150° 40' 22.526 W 12,498.6 80.99 4,009.8 9,162.0 -5,410.5329.03 417,109.295,982,050.82 70° 21' 39.386 N 150° 40' 23.993 W NT4 MFS 12,500.0 80.99 4,010.0 9,163.2 -5,411.2329.03 417,108.595,982,052.00 70° 21' 39.398 N 150° 40' 24.014 W 12,600.0 80.99 4,025.7 9,247.9 -5,462.0329.03 417,058.655,982,137.20 70° 21' 40.230 N 150° 40' 25.502 W 12,700.0 80.99 4,041.4 9,332.5 -5,512.8329.03 417,008.705,982,222.39 70° 21' 41.063 N 150° 40' 26.990 W 12,800.0 80.99 4,057.0 9,417.2 -5,563.6329.03 416,958.765,982,307.59 70° 21' 41.895 N 150° 40' 28.478 W 12,827.9 80.99 4,061.4 9,440.9 -5,577.8329.03 416,944.805,982,331.40 70° 21' 42.128 N 150° 40' 28.894 W Start DLS 3.00 TFO 175.98 12,900.0 78.83 4,074.0 9,501.8 -5,614.3329.18 416,909.015,982,392.64 70° 21' 42.726 N 150° 40' 29.960 W 12,942.9 77.55 4,082.8 9,537.8 -5,635.7329.27 416,887.915,982,428.92 70° 21' 43.081 N 150° 40' 30.589 W NT3 MFS 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 6 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 12,987.0 76.23 4,092.8 9,574.8 -5,657.7329.37 416,866.385,982,466.09 70° 21' 43.444 N 150° 40' 31.231 W 9-5/8" Intermediate Liner 12,991.2 76.10 4,093.8 9,578.3 -5,659.8329.38 416,864.325,982,469.64 70° 21' 43.479 N 150° 40' 31.292 W Start 66.8 hold at 12991.2 MD 13,000.0 76.10 4,095.9 9,585.6 -5,664.1329.38 416,860.065,982,477.02 70° 21' 43.551 N 150° 40' 31.419 W 13,028.6 76.10 4,102.8 9,609.5 -5,678.2329.38 416,846.175,982,501.06 70° 21' 43.786 N 150° 40' 31.833 W NT3.2 PB 13,058.1 76.10 4,109.9 9,634.1 -5,692.8329.38 416,831.865,982,525.81 70° 21' 44.028 N 150° 40' 32.259 W Start Turn 0.00 13,088.2 77.30 4,116.8 9,659.4 -5,707.7329.38 416,817.205,982,551.17 70° 21' 44.275 N 150° 40' 32.696 W NT3.2 Top Reservoir 13,100.0 77.78 4,119.4 9,669.3 -5,713.6329.38 416,811.425,982,561.17 70° 21' 44.373 N 150° 40' 32.869 W 13,200.0 81.78 4,137.1 9,754.0 -5,763.7329.38 416,762.195,982,646.35 70° 21' 45.206 N 150° 40' 34.336 W 13,300.0 85.78 4,147.9 9,839.5 -5,814.3329.38 416,712.465,982,732.40 70° 21' 46.046 N 150° 40' 35.818 W 13,400.0 89.78 4,151.8 9,925.5 -5,865.2329.38 416,662.475,982,818.88 70° 21' 46.891 N 150° 40' 37.308 W 13,405.6 90.00 4,151.8 9,930.3 -5,868.1329.38 416,659.695,982,823.70 70° 21' 46.939 N 150° 40' 37.391 W Start DLS 0.00 TFO -90.00 13,500.0 90.00 4,151.8 10,011.5 -5,916.2329.38 416,612.435,982,905.45 70° 21' 47.737 N 150° 40' 38.800 W 13,600.0 90.00 4,151.8 10,097.6 -5,967.1329.38 416,562.395,982,992.03 70° 21' 48.583 N 150° 40' 40.291 W 13,700.0 90.00 4,151.8 10,183.6 -6,018.0329.38 416,512.365,983,078.60 70° 21' 49.429 N 150° 40' 41.783 W 13,800.0 90.00 4,151.8 10,269.7 -6,069.0329.38 416,462.325,983,165.17 70° 21' 50.275 N 150° 40' 43.274 W 13,900.0 90.00 4,151.8 10,355.8 -6,119.9329.38 416,412.285,983,251.73 70° 21' 51.121 N 150° 40' 44.766 W 14,000.0 90.00 4,151.8 10,441.8 -6,170.8329.38 416,362.245,983,338.30 70° 21' 51.967 N 150° 40' 46.258 W 14,100.0 90.00 4,151.8 10,527.9 -6,221.8329.38 416,312.205,983,424.87 70° 21' 52.813 N 150° 40' 47.749 W 14,200.0 90.00 4,151.8 10,613.9 -6,272.7329.38 416,262.165,983,511.44 70° 21' 53.659 N 150° 40' 49.241 W 14,300.0 90.00 4,151.8 10,700.0 -6,323.7329.38 416,212.125,983,598.01 70° 21' 54.505 N 150° 40' 50.733 W 14,400.0 90.00 4,151.8 10,786.0 -6,374.6329.38 416,162.085,983,684.58 70° 21' 55.351 N 150° 40' 52.225 W 14,500.0 90.00 4,151.8 10,872.1 -6,425.5329.38 416,112.045,983,771.15 70° 21' 56.197 N 150° 40' 53.717 W 14,600.0 90.00 4,151.8 10,958.1 -6,476.5329.38 416,062.005,983,857.72 70° 21' 57.043 N 150° 40' 55.209 W 14,700.0 90.00 4,151.8 11,044.2 -6,527.4329.38 416,011.965,983,944.28 70° 21' 57.888 N 150° 40' 56.701 W 14,800.0 90.00 4,151.8 11,130.2 -6,578.4329.38 415,961.925,984,030.85 70° 21' 58.734 N 150° 40' 58.193 W 14,900.0 90.00 4,151.8 11,216.3 -6,629.3329.38 415,911.875,984,117.42 70° 21' 59.580 N 150° 40' 59.685 W 15,000.0 90.00 4,151.8 11,302.4 -6,680.2329.38 415,861.835,984,203.99 70° 22' 0.426 N 150° 41' 1.177 W 15,100.0 90.00 4,151.8 11,388.4 -6,731.2329.38 415,811.795,984,290.55 70° 22' 1.272 N 150° 41' 2.669 W 15,200.0 90.00 4,151.8 11,474.5 -6,782.1329.38 415,761.745,984,377.12 70° 22' 2.118 N 150° 41' 4.161 W 15,300.0 90.00 4,151.8 11,560.5 -6,833.1329.38 415,711.705,984,463.69 70° 22' 2.964 N 150° 41' 5.654 W 15,400.0 90.00 4,151.8 11,646.6 -6,884.0329.37 415,661.665,984,550.25 70° 22' 3.810 N 150° 41' 7.146 W 15,500.0 90.00 4,151.8 11,732.6 -6,934.9329.37 415,611.615,984,636.82 70° 22' 4.655 N 150° 41' 8.638 W 15,600.0 90.00 4,151.8 11,818.7 -6,985.9329.37 415,561.575,984,723.38 70° 22' 5.501 N 150° 41' 10.131 W 15,700.0 90.00 4,151.8 11,904.7 -7,036.8329.37 415,511.525,984,809.95 70° 22' 6.347 N 150° 41' 11.623 W 15,800.0 90.00 4,151.8 11,990.8 -7,087.8329.37 415,461.475,984,896.51 70° 22' 7.193 N 150° 41' 13.116 W 15,900.0 90.00 4,151.8 12,076.8 -7,138.7329.37 415,411.435,984,983.08 70° 22' 8.039 N 150° 41' 14.608 W 16,000.0 90.00 4,151.8 12,162.9 -7,189.7329.37 415,361.385,985,069.64 70° 22' 8.884 N 150° 41' 16.101 W 16,100.0 90.00 4,151.8 12,248.9 -7,240.6329.37 415,311.335,985,156.21 70° 22' 9.730 N 150° 41' 17.594 W 16,200.0 90.00 4,151.8 12,335.0 -7,291.5329.37 415,261.295,985,242.77 70° 22' 10.576 N 150° 41' 19.086 W 16,300.0 90.00 4,151.8 12,421.0 -7,342.5329.37 415,211.245,985,329.34 70° 22' 11.422 N 150° 41' 20.579 W 16,400.0 90.00 4,151.8 12,507.1 -7,393.4329.37 415,161.195,985,415.90 70° 22' 12.268 N 150° 41' 22.072 W 16,500.0 90.00 4,151.8 12,593.1 -7,444.4329.37 415,111.145,985,502.46 70° 22' 13.113 N 150° 41' 23.565 W 16,600.0 90.00 4,151.8 12,679.2 -7,495.3329.37 415,061.095,985,589.03 70° 22' 13.959 N 150° 41' 25.057 W 16,700.0 90.00 4,151.8 12,765.2 -7,546.3329.37 415,011.045,985,675.59 70° 22' 14.805 N 150° 41' 26.550 W 16,800.0 90.00 4,151.8 12,851.3 -7,597.2329.37 414,960.995,985,762.15 70° 22' 15.651 N 150° 41' 28.043 W 16,900.0 90.00 4,151.8 12,937.3 -7,648.2329.37 414,910.945,985,848.72 70° 22' 16.497 N 150° 41' 29.536 W 17,000.0 90.00 4,151.8 13,023.4 -7,699.1329.37 414,860.895,985,935.28 70° 22' 17.342 N 150° 41' 31.029 W 17,100.0 90.00 4,151.8 13,109.4 -7,750.1329.37 414,810.845,986,021.84 70° 22' 18.188 N 150° 41' 32.523 W 17,200.0 90.00 4,151.8 13,195.5 -7,801.0329.37 414,760.795,986,108.40 70° 22' 19.034 N 150° 41' 34.016 W 17,300.0 90.00 4,151.8 13,281.5 -7,852.0329.37 414,710.745,986,194.96 70° 22' 19.880 N 150° 41' 35.509 W 17,400.0 90.00 4,151.8 13,367.5 -7,902.9329.37 414,660.685,986,281.53 70° 22' 20.725 N 150° 41' 37.002 W 17,500.0 90.00 4,151.8 13,453.6 -7,953.9329.37 414,610.635,986,368.09 70° 22' 21.571 N 150° 41' 38.495 W 17,600.0 90.00 4,151.8 13,539.6 -8,004.8329.37 414,560.585,986,454.65 70° 22' 22.417 N 150° 41' 39.989 W 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 7 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 17,700.0 90.00 4,151.8 13,625.7 -8,055.8329.37 414,510.525,986,541.21 70° 22' 23.262 N 150° 41' 41.482 W 17,800.0 90.00 4,151.8 13,711.7 -8,106.7329.37 414,460.475,986,627.77 70° 22' 24.108 N 150° 41' 42.976 W 17,900.0 90.00 4,151.8 13,797.8 -8,157.7329.37 414,410.425,986,714.33 70° 22' 24.954 N 150° 41' 44.469 W 18,000.0 90.00 4,151.8 13,883.8 -8,208.6329.37 414,360.365,986,800.89 70° 22' 25.800 N 150° 41' 45.963 W 18,100.0 90.00 4,151.8 13,969.9 -8,259.6329.37 414,310.315,986,887.45 70° 22' 26.645 N 150° 41' 47.456 W 18,200.0 90.00 4,151.8 14,055.9 -8,310.5329.37 414,260.255,986,974.01 70° 22' 27.491 N 150° 41' 48.950 W 18,300.0 90.00 4,151.8 14,142.0 -8,361.5329.37 414,210.205,987,060.57 70° 22' 28.337 N 150° 41' 50.443 W 18,399.4 90.00 4,151.8 14,227.5 -8,412.1329.37 414,160.465,987,146.57 70° 22' 29.177 N 150° 41' 51.927 W Start DLS 5.99 TFO -0.53 18,400.0 90.04 4,151.8 14,228.0 -8,412.4329.37 414,160.145,987,147.13 70° 22' 29.182 N 150° 41' 51.937 W 18,500.0 96.03 4,146.5 14,313.9 -8,463.3329.31 414,110.135,987,233.50 70° 22' 30.026 N 150° 41' 53.429 W 18,600.0 102.02 4,130.8 14,398.7 -8,513.8329.25 414,060.595,987,318.88 70° 22' 30.860 N 150° 41' 54.908 W 18,700.0 108.01 4,105.0 14,481.7 -8,563.2329.20 414,012.065,987,402.32 70° 22' 31.675 N 150° 41' 56.356 W 18,737.0 110.23 4,092.8 14,511.7 -8,581.1329.17 413,994.455,987,432.56 70° 22' 31.971 N 150° 41' 56.881 W TD at 18737.0 Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing128.0128.0 20 20 13-3/8" Surface Casing2,342.02,684.0 13-3/8 16 9-5/8" Intermediate Liner4,092.812,987.0 9-5/8 12-1/4 4-1/2" Production Liner4,092.818,737.1 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,054.7 Upper Schrader Bluff 0.001,047.8 1,157.5 Base Ice Bearing Permafrost1,147.8 1,415.8 Base Permafrost Transition 0.001,393.8 1,833.3 Middle Schrader Bluff1,762.8 2,340.9 MCU2,141.8 2,896.2 Tuluvak Shale2,439.8 3,057.5 Tuluvak Sand2,499.8 4,775.4 TS_7902,799.8 6,811.5 Seabee3,118.8 11,107.2 Nanushuk3,791.8 11,356.1 NT8 MFS3,830.8 11,458.2 NT7 MFS3,846.8 11,905.0 NT6 MFS3,916.8 12,256.1 NT5 MFS3,971.8 12,498.6 NT4 MFS4,009.8 12,942.9 NT3 MFS4,082.8 13,028.6 NT3.2 PB4,102.8 13,088.2 NT3.2 Top Reservoir4,116.8 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 8 Santos Ltd Planning Report - Geographic Well NDBi-016Local Co-ordinate Reference:Database:EDM Parker 272 as Planned @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 as Planned @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-016Well: NDBi-016Wellbore: Plan: NDBi-016 Rev G.0Design: Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 447.0 447.0 0.0 0.0 Start Build 2.50 987.0 982.0 59.5 -21.7 Start 160.0 hold at 987.0 MD 1,147.0 1,137.6 94.6 -34.4 Start DLS 3.00 TFO -11.72 3,405.3 2,585.1 1,461.6 -788.5 Start 9422.7 hold at 3405.3 MD 12,827.9 4,061.4 9,440.9 -5,577.8 Start DLS 3.00 TFO 175.98 12,991.2 4,093.8 9,578.3 -5,659.8 Start 66.8 hold at 12991.2 MD 13,058.1 4,109.9 9,634.1 -5,692.8 Start Turn 0.00 13,405.6 4,151.8 9,930.3 -5,868.1 Start DLS 0.00 TFO -90.00 18,399.4 4,151.8 14,227.5 -8,412.1 Start DLS 5.99 TFO -0.53 18,737.0 4,092.8 14,511.7 -8,581.1 TD at 18737.0 14/06/2024 10:50:40 COMPASS 5000.17 Build Page 9 03000600090001200015000South(-)/North(+)-15000 -12000 -9000 -6000 -3000 0 3000 6000West(-)/East(+)NDBi-016 Build Rev 0.0NDBi-16 TD Rev 0.0NDBi-16 Heel Rev 2.092%20" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner4-1/2" Production LinerPlan: NDBi-016 Rev G.0Plan: NDBi-016 Rev G.010:25, June 14 2024 -95009501900285038004750True Vertical Depth0 2500 5000 7500 10000 12500 15000 17500Vertical Section at 329.40°20" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner4-1/2" Production Liner1000200030004000500060007000800090001000011000120001300014000 15000 16000 170001800018737 0°30°60°81°90°Plan: N D Bi-016 R e v G. 0 Upper Schrader BluffBase Ice Bearing PermafrostBase Permafrost TransitionMiddle Schrader BluffMCUTuluvak ShaleTuluvak SandTS_790SeabeeNanushukNT8 MFSNT7 MFSNT6 MFSNT5 MFSNT4 MFSNT3 MFSNT3.2 PBNT3.2 Top ReservoirPlan: NDBi-016 Rev G.010:27, June 14 2024 Northing (6000 usft/in)Easting (6000 usft/in)Northing (6000 usft/in)Easting (6000 usft/in)DW-02Plan: NDB-010 Rev A.1NDB-010L1 Rev B.0Plan: NDB-011 Rev A.0Plan: NDB-013 Rev B.0Plan: NDB-015 Rev A.0Plan:NDB-021 Rev A.0Plan NDB-022 Rev A.0NDB-024NDB-024PB1Plan: NDB-25 Rev E.0Plan: NDB-027 Rev B.0NDB-032Plan: NDB-04 Rev A.0Plan: NDB-05 Rev A.0Plan: NDB-09 Rev A.0Plan: NDBi-012 Rev A.1NDBi-014Plan: NDBi-018 Rev I.0Plan: NDBi-019 Rev A.0Plan: NDBi-020 Rev A.0Plan: NDBi-026 Rev A.0Plan NDBi-028 Rev A.0NDBi-030Plan: NDBi-06 Rev A.0Plan: NDBi-07 Rev A.0Plan: NDBi-018 Rev I.0Plan: NDBi-016 Rev G.0NDANDBNPF10:37, June 14 2024 14 June, 2024 Anticollision Summary Report Santos Pikka NDB NDBi-016 NDBi-016 Plan: NDBi-016 Rev G.0 Santos Ltd Anticollision Summary Report Well NDBi-016 - Slot B-16Local Co-ordinate Reference:SantosCompany: Parker 272 as Planned @ 69.8usftTVD Reference:PikkaProject: Parker 272 as Planned @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-016Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-016 Database:EDM Offset DatumReference Design:Plan: NDBi-016 Rev G.0 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 2,069.0usft Plan: NDBi-016 Rev G.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 14/06/2024 SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)47.0 700.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag700.0 1,900.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag700.0 2,684.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+MS H021Ma: IIFR dec & multi-station analysis2,684.0 3,884.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,684.0 4,000.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+Sag A002Mb/ISC4: BGGM dec + sag corrections4,000.0 4,700.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag4,700.0 5,900.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag4,700.0 12,987.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 2_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag12,987.0 14,187.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag12,987.0 18,737.0 Plan: NDBi-016 Rev G.0 (NDBi-016) 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 NDB CCDW-02 - DW-02 - DW-02 2,144.0 2,554.4 355.3 331.9 21.276 ESDW-02 - DW-02 - DW-02 2,150.0 2,559.7 355.4 331.8 21.134 SFDW-02 - DW-02 - DW-02 2,450.0 2,817.3 410.0 378.7 17.639 CCNDB-010 - NDB-010 - Plan: NDB-010 Rev A.1 425.0 425.0 120.2 110.8 23.063 ESNDB-010 - NDB-010 - Plan: NDB-010 Rev A.1 500.0 499.9 120.3 110.6 22.206 SFNDB-010 - NDB-010 - Plan: NDB-010 Rev A.1 14,475.0 14,761.8 1,802.1 1,351.4 5.016 CCNDB-010 - NDB-010L1 - NDB-010L1 Rev B.0 425.0 425.0 120.2 111.2 24.207 ESNDB-010 - NDB-010L1 - NDB-010L1 Rev B.0 475.0 475.0 120.2 111.1 23.851 SFNDB-010 - NDB-010L1 - NDB-010L1 Rev B.0 14,475.0 14,878.5 1,802.1 1,393.2 5.535 CCNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 425.0 425.2 99.7 90.4 19.147 ESNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 525.0 525.2 99.8 90.2 18.221 SFNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 700.0 698.3 102.7 92.4 17.157 CCNDB-013 - NDB-013 - Plan: NDB-013 Rev B.0 378.0 378.0 60.0 51.1 11.953 ESNDB-013 - NDB-013 - Plan: NDB-013 Rev B.0 400.0 400.0 60.0 51.1 11.891 SFNDB-013 - NDB-013 - Plan: NDB-013 Rev B.0 18,737.0 18,851.8 1,801.3 1,200.6 3.758 CCNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 474.3 474.6 19.3 9.8 3.241 ESNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 500.0 500.2 19.3 9.7 3.205 SFNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 550.0 550.0 19.6 9.9 3.181 CCNDB-021 - NDB-021 - Plan:NDB-021 Rev A.0 327.9 328.1 100.5 91.5 20.138 ESNDB-021 - NDB-021 - Plan:NDB-021 Rev A.0 450.0 450.0 100.6 91.3 19.274 SFNDB-021 - NDB-021 - Plan:NDB-021 Rev A.0 600.0 595.9 103.2 93.3 18.272 CCNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 549.6 549.4 120.5 110.7 21.612 ESNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 575.0 574.0 120.6 110.7 21.319 SFNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 18,737.0 18,486.0 1,798.8 1,218.1 3.882 CCNDB-024 - NDB-024 - NDB-024 600.0 598.8 158.5 149.2 29.570 ESNDB-024 - NDB-024 - NDB-024 601.1 599.9 158.5 149.2 29.563 SFNDB-024 - NDB-024 - NDB-024 18,225.0 18,029.0 1,796.2 1,238.2 4.036 CCNDB-024 - NDB-024PB1 - NDB-024PB1 600.0 598.8 158.5 149.0 29.540 ESNDB-024 - NDB-024PB1 - NDB-024PB1 601.1 599.9 158.5 149.0 29.534 SFNDB-024 - NDB-024PB1 - NDB-024PB1 3,525.0 3,181.0 553.1 492.8 11.965 CCNDB-025 - NDB-025 - Plan: NDB-25 Rev E.0 400.0 400.0 180.0 170.8 35.010 ESNDB-025 - NDB-025 - Plan: NDB-25 Rev E.0 550.0 549.5 180.1 170.4 32.968 14/06/2024 10:07:30 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 2 Santos Ltd Anticollision Summary Report Well NDBi-016 - Slot B-16Local Co-ordinate Reference:SantosCompany: Parker 272 as Planned @ 69.8usftTVD Reference:PikkaProject: Parker 272 as Planned @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-016Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-016 Database:EDM Offset DatumReference Design:Plan: NDBi-016 Rev G.0 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 NDB SFNDB-025 - NDB-025 - Plan: NDB-25 Rev E.0 875.0 848.7 203.0 192.0 30.719 CC, ESNDB-027 - NDB-027 - Plan: NDB-027 Rev B.0 604.6 603.4 220.3 210.9 41.895 SFNDB-027 - NDB-027 - Plan: NDB-027 Rev B.0 5,800.0 5,277.8 1,567.1 1,409.9 12.650 CCNDB-032 - NDB-032 - NDB-032 1,124.4 1,121.4 311.6 300.0 44.679 ESNDB-032 - NDB-032 - NDB-032 1,150.0 1,145.3 311.6 299.9 43.813 SFNDB-032 - NDB-032 - NDB-032 11,750.0 12,381.0 1,840.7 1,477.7 6.374 CCNDB-04 - NDB-04 - Plan: NDB-04 Rev A.0 327.9 328.1 239.9 230.8 48.689 ESNDB-04 - NDB-04 - Plan: NDB-04 Rev A.0 350.0 350.1 239.9 230.7 48.279 SFNDB-04 - NDB-04 - Plan: NDB-04 Rev A.0 4,700.0 3,949.7 1,831.4 1,740.6 25.897 CCNDB-05 - NDB-05 - Plan: NDB-05 Rev A.0 327.9 328.1 219.9 210.9 44.600 ESNDB-05 - NDB-05 - Plan: NDB-05 Rev A.0 375.0 374.6 220.0 210.8 43.788 SFNDB-05 - NDB-05 - Plan: NDB-05 Rev A.0 4,700.0 4,123.6 1,498.0 1,395.2 18.694 CCNDB-09 - NDB-09 - Plan: NDB-09 Rev A.0 327.9 328.1 139.8 130.7 28.169 ESNDB-09 - NDB-09 - Plan: NDB-09 Rev A.0 400.0 400.0 139.8 130.6 27.362 SFNDB-09 - NDB-09 - Plan: NDB-09 Rev A.0 5,800.0 5,300.7 1,524.4 1,384.9 13.889 CCNDBi-012 - NDBi-012 - Plan: NDBi-012 Rev A.1 396.4 396.4 80.1 70.8 15.372 ESNDBi-012 - NDBi-012 - Plan: NDBi-012 Rev A.1 475.0 474.9 80.2 70.6 14.809 SFNDBi-012 - NDBi-012 - Plan: NDBi-012 Rev A.1 9,625.0 9,123.9 2,067.7 1,793.4 9.498 CCNDBi-014 - NDBi-014 - NDBi-014 379.4 379.3 39.9 30.9 7.710 ESNDBi-014 - NDBi-014 - NDBi-014 400.0 399.9 39.9 30.9 7.676 SFNDBi-014 - NDBi-014 - NDBi-014 450.0 449.8 40.1 31.0 7.621 CCNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev I.0 553.2 552.8 39.9 30.6 7.366 CCNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev I.0 558.2 557.8 39.8 30.3 7.112 ESNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev I.0 575.0 574.6 39.9 30.6 7.303 ESNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev I.0 575.0 574.5 39.8 30.3 7.067 Normal Operations, SFNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev I.0 12,900.0 13,105.0 122.1 35.1 1.775 Normal Operations, SFNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev I.0 12,900.0 13,104.6 122.1 35.3 1.779 CCNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 327.9 328.1 60.4 51.4 11.902 ESNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 425.0 425.1 60.5 51.2 11.448 SFNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 550.0 549.0 61.9 52.1 11.015 CCNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 416.3 416.6 80.5 71.2 15.427 Caution - Monitor Closely,NDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 18,737.0 18,393.3 135.3 16.8 1.435 CCNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 561.0 559.7 200.5 190.7 36.357 ESNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 575.0 573.0 200.5 190.7 36.086 SFNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 10,125.0 9,568.8 2,065.8 1,754.4 8.353 CCNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 327.9 328.1 240.7 231.6 48.863 ESNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 500.0 499.6 240.8 231.3 45.363 SFNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 750.0 722.6 254.0 243.6 42.259 CCNDBi-030 - NDBi-030 - NDBi-030 527.2 525.8 278.7 269.5 55.126 ESNDBi-030 - NDBi-030 - NDBi-030 550.0 547.9 278.7 269.5 54.724 SFNDBi-030 - NDBi-030 - NDBi-030 5,800.0 5,312.4 1,691.7 1,534.4 13.653 CCNDBi-06 - NDBi-06 - Plan: NDBi-06 Rev A.0 425.0 425.2 199.9 190.6 38.859 ESNDBi-06 - NDBi-06 - Plan: NDBi-06 Rev A.0 475.0 474.7 199.9 190.4 37.935 SFNDBi-06 - NDBi-06 - Plan: NDBi-06 Rev A.0 5,800.0 5,290.3 1,797.7 1,661.0 16.726 CCNDBi-07 - NDBi-07 - Plan: NDBi-07 Rev A.0 327.9 328.1 179.8 170.8 36.382 ESNDBi-07 - NDBi-07 - Plan: NDBi-07 Rev A.0 375.0 374.8 179.9 170.7 35.717 SFNDBi-07 - NDBi-07 - Plan: NDBi-07 Rev A.0 5,800.0 5,204.7 1,773.8 1,637.3 16.537 14/06/2024 10:07:30 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 3 Santos Ltd Anticollision Summary Report Well NDBi-016 - Slot B-16Local Co-ordinate Reference:SantosCompany: Parker 272 as Planned @ 69.8usftTVD Reference:PikkaProject: Parker 272 as Planned @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-016Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-016 Database:EDM Offset DatumReference Design:Plan: NDBi-016 Rev G.0 Offset TVD Reference: 0 500 1000 1500 2000 Centre to Centre Separation0 3500 7000 10500 14000 17500 21000 Measured Depth Ladder Plot DW-02, DW-02, DW-02 V0 NDB-010, NDB-010, Plan: NDB-010 Rev A.1 V0 NDB-010, NDB-010L1, NDB-010L1 Rev B.0 V0 NDB-011, NDB-011, Plan: NDB-011 Rev A.0 V0 NDB-013, NDB-013, Plan: NDB-013 Rev B.0 V0 NDB-015, NDB-015, Plan: NDB-015 Rev A.0 V0 NDB-021, NDB-021, Plan:NDB-021 Rev A.0 V0 NDB-022, NDB-022, Plan NDB-022 Rev A.0 V0 NDB-024, NDB-024, NDB-024 V0 NDB-024, NDB-024PB1, NDB-024PB1 V0 NDB-025, NDB-025, Plan: NDB-25 Rev E.0 V0 NDB-027, NDB-027, Plan: NDB-027 Rev B.0 V0 NDB-032, NDB-032, NDB-032 V0 NDB-04, NDB-04, Plan: NDB-04 Rev A.0 V0 NDB-05, NDB-05, Plan: NDB-05 Rev A.0 V0 NDB-09, NDB-09, Plan: NDB-09 Rev A.0 V0 NDBi-012, NDBi-012, Plan: NDBi-012 Rev A.1 V0 NDBi-014, NDBi-014, NDBi-014 V0 NDBi-018, NDBi-018, Plan: NDBi-018 Rev I.0 V0 NDBi-019, NDBi-019, Plan: NDBi-019 Rev A.0 V0 NDBi-020, NDBi-020, Plan: NDBi-020 Rev A.0 V0 NDBi-026, NDBi-026, Plan: NDBi-026 Rev A.0 V0 NDBi-028, NDBi-028, Plan NDBi-028 Rev A.0 V0 NDBi-030, NDBi-030, NDBi-030 V0 NDBi-06, NDBi-06, Plan: NDBi-06 Rev A.0 V0 NDBi-07, NDBi-07, Plan: NDBi-07 Rev A.0 V0 NDBi-018, NDBi-018, Plan: NDBi-018 Rev I.0 V0 L E G E N D Coordinates are relative to: NDBi-016 - Slot B-16 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 as Planned @ 69.8usft 14/06/2024 10:07:30 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 4 Santos Ltd Anticollision Summary Report Well NDBi-016 - Slot B-16Local Co-ordinate Reference:SantosCompany: Parker 272 as Planned @ 69.8usftTVD Reference:PikkaProject: Parker 272 as Planned @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-016Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-016 Database:EDM Offset DatumReference Design:Plan: NDBi-016 Rev G.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 Separation Factor0 3500 7000 10500 14000 17500 Measured Depth Stop Drilling Caution - Monitor Closely Normal Operations Separation Factor Plot DW-02, DW-02, DW-02 V0 NDB-010, NDB-010, Plan: NDB-010 Rev A.1 V0 NDB-010, NDB-010L1, NDB-010L1 Rev B.0 V0 NDB-011, NDB-011, Plan: NDB-011 Rev A.0 V0 NDB-013, NDB-013, Plan: NDB-013 Rev B.0 V0 NDB-015, NDB-015, Plan: NDB-015 Rev A.0 V0 NDB-021, NDB-021, Plan:NDB-021 Rev A.0 V0 NDB-022, NDB-022, Plan NDB-022 Rev A.0 V0 NDB-024, NDB-024, NDB-024 V0 NDB-024, NDB-024PB1, NDB-024PB1 V0 NDB-025, NDB-025, Plan: NDB-25 Rev E.0 V0 NDB-027, NDB-027, Plan: NDB-027 Rev B.0 V0 NDB-032, NDB-032, NDB-032 V0 NDB-04, NDB-04, Plan: NDB-04 Rev A.0 V0 NDB-05, NDB-05, Plan: NDB-05 Rev A.0 V0 NDB-09, NDB-09, Plan: NDB-09 Rev A.0 V0 NDBi-012, NDBi-012, Plan: NDBi-012 Rev A.1 V0 NDBi-014, NDBi-014, NDBi-014 V0 NDBi-018, NDBi-018, Plan: NDBi-018 Rev I.0 V0 NDBi-019, NDBi-019, Plan: NDBi-019 Rev A.0 V0 NDBi-020, NDBi-020, Plan: NDBi-020 Rev A.0 V0 NDBi-026, NDBi-026, Plan: NDBi-026 Rev A.0 V0 NDBi-028, NDBi-028, Plan NDBi-028 Rev A.0 V0 NDBi-030, NDBi-030, NDBi-030 V0 NDBi-06, NDBi-06, Plan: NDBi-06 Rev A.0 V0 NDBi-07, NDBi-07, Plan: NDBi-07 Rev A.0 V0 NDBi-018, NDBi-018, Plan: NDBi-018 Rev I.0 V0 L E G E N D Coordinates are relative to: NDBi-016 - Slot B-16 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 as Planned @ 69.8usft 14/06/2024 10:07:30 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 0 30 60 Centre to Centre Separation0450900135018002250 Partial Measured DepthPlan: NDB-013 Rev B.0Plan: NDB-015 Rev A.0NDBi-014Plan: NDBi-018 Rev I.0Plan: NDBi-019 Rev A.0Plan: NDBi-018 Rev I.0Equivalent Magnetic Distance Plan: NDBi-016 Rev G.0 Ladder View 0 150 300 Centre to Centre Separation0 3000 6000 9000 12000 15000 18000 Measured DepthPlan: NDB-010 Rev A.1NDB-010L1 Rev B.0Plan: NDB-011 Rev A.0Plan: NDB-013 Rev B.0Plan: NDB-015 Rev A.0Plan:NDB-021 Rev A.0Plan NDB-022 Rev A.0NDB-024NDB-024PB1Plan: NDB-25 Rev E.0Plan: NDB-027 Rev B.0NDB-032Plan: NDB-04 Rev A.0Plan: NDB-05 Rev A.0Plan: NDB-09 Rev A.0Plan: NDBi-012 Rev A.1NDBi-014Plan: NDBi-018 Rev I.0Plan: NDBi-019 Rev A.0Plan: NDBi-020 Rev A.0Plan: NDBi-026 Rev A.0Plan NDBi-028 Rev A.0NDBi-030Plan: NDBi-06 Rev A.0Plan: NDBi-07 Rev A.0Plan: NDBi-018 Rev I.0Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 47.0 700.0 Plan: NDBi-016 Rev G.0 (NDBi-016)SDI_URSA1_I4 700.0 1900.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+Sag 700.0 2684.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 2684.0 3884.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS 2684.0 4000.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 4000.0 4700.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+Sag 4700.0 5900.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+Sag 4700.012987.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 12987.014187.0 Plan: NDBi-016 Rev G.0 (NDBi-016)2_MWD+IFR2+Sag 12987.018737.0 Plan: NDBi-016 Rev G.0 (NDBi-016)3_MWD+IFR2+MS+Sag 10:14, June 14 2024 CASING DETAILS TVD MD Name 128.0 128.020" Conductor Casing 2342.0 2684.013-3/8" Surface Casing 4092.8 12987.09-5/8" Intermediate Liner 4092.8 18737.14-1/2" Production Liner Plan: NDBi-016 Rev G.0AC FlipbookSURVEY PROGRAMDepth From Depth To Tool47.0 700.0 SDI_URSA1_I4700.0 1900.0 3_MWD+IFR2+Sag700.0 2684.0 3_MWD+IFR2+MS+Sag2684.0 3884.0 3_MWD+IFR2+MS2684.0 4000.0 3_MWD+IFR2+MS+Sag4000.0 4700.0 3_MWD+Sag4700.0 5900.0 3_MWD+IFR2+Sag4700.0 12987.0 3_MWD+IFR2+MS+Sag12987.0 14187.0 2_MWD+IFR2+Sag12987.0 18737.0 3_MWD+IFR2+MS+SagCASING DETAILSTVD MD Name128.0 128.020" Conductor Casing2342.0 2684.013-3/8" Surface Casing4092.8 12987.09-5/8" Intermediate Liner4092.8 18737.14-1/2" Production Liner1515303045456060757590900901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [30 usft/in]7075100125150175200225250275300325350375400425450475500524549574599624648673Plan: NDB-011 Rev A.0475075100125150175200225250275300325350375400425450475500525550575600625650675700725750775800824849874899924949974999102410491074109911241149Plan: NDB-013 Rev B.07075100125150175200225250275300325350375400425450475500525550575600625650675700725750776801826851876902927952977100210271052107711021126115111761202122712531279130413301356Plan: NDB-015 Rev A.0475075100125150175200225250275300325350375400425450475500524549Plan:NDB-021 Rev A.04750751001251501752002252502753003253503754004254504755005255505756006256506757007257507758008258518769019269519771002102710511076Plan: NDBi-012 Rev A.1475075100125150175200225250275300325350375400425450475499524549573598622646670694718742765788812835857NDBi-0144750751001251501752002252502753003253503754004254504755005255505756006256506757007257507758008248498748999249489739981023104810731098112311481173119712221247127212961321134613701395142014441469149415181543156815921617164116661690171517401764178918131838186218871911193619601985200920342058208321072131215621802205Plan: NDBi-018 Rev I.07075100125150175200225250275300325350375400425450475500524549574598622647671695718742765Plan: NDBi-019 Rev A.0707510012515017520022525027530032535037540042545047550052555057560062565167670172675177780282785387890392995497910041029Plan: NDBi-020 Rev A.04750751001251501752002252502753003253503754004254504755005255505756006256506757007257507758008258498748999249499739981023104810731098112311481173119812221247127212961321134613711395142014451469149415191543156815921617164216661691171517401764178918141838186318871912193619611985201020342058208321072132215621812205Plan: NDBi-018 Rev I.047 300300 500500 750750 10001000 12501250 15001500 17501750 20002000 25002500 30003000 35003500 45004500 55005500 65006500 75007500 85008500 95009500 1100011000 1200012000 1300013000 1400014000 1500015000 1600016000 1700017000 18000From Colour To MD47.0 To 18737.0MD Azi TFace47.0 0.00 0.00447.0 0.00 0.00987.0 340.00 340.001147.0 340.00 0.003405.3 329.03 -11.7212827.9 329.03 0.0012991.2 329.38 175.9813058.1 329.38 0.0013405.6 329.38 0.0018399.4 329.37 -90.0018737.0 329.17 -0.53 Attachment 3: BOPE Equipment 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#FORWARD 13-5/8" X 5,000#13-5/8" X 5,000#30"13-5/8" X 5,000#186"13-5/8" X 5,000#DUTCH LOCK DOWN ChokeLinefromBOPPressureGauge1502PressureSensorPressureTransducerBill ofMaterialItemDescriptionToPanicLineItemDescriptionA3Ͳ1/8”– 5,000psi W.P.RemoteHydraulicOperatedChokeB3Ͳ1/8”–5,000psiW.P.AdjustableManualChoke1–14 3Ͳ1/8”– 5,000psi W.P.ManualGateValve1521/16”5 000 i WP152Ͳ1/16”–5,000psiW.P.ManualGateValveToMudGasLegendBlindSpareToTigerTankSeparatorValveNormally OpenValveNormally Closed Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (trained drilling personnel). 12-1/4” Intermediate Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Wellbore Instability / Washouts / Hole Enlargement Drill with oil-based mud, maintain mud in specifications, use sufficient mud weight to hold back formations. Managed Pressure Drilling may be utilized if equipment is operational to minimize pressure cycles on formation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Hole Cleaning in 81q Sail Conduct hydraulics modeling and control ROP limits based on cuttings returns and observed ECD’s compared to model. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Operational complexity with Mechanical two stage cement equipment The 2nd stage of the cement job will be conducted through a mechanically shifted sleeve. This will require the LTP to not be set until the 2nd stage is pumped giving a higher complexity leading to complications with setting the LTP. 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. Managed Pressure Drilling may be utilized if equipment is operational to minimize pressure cycles on formation. Drilling out of zone due to two fault crossings Incorporate inclination changes prior to anticipated fault crossings to allow for open hole sidetrack points * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 TXP-BTC Surface Casing Basis Lead Open hole volume + 200% excess in permafrost / 50% excess below permafrost Lead TOC Surface Tail Open hole volume + 50% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Tuned Spacer Lead 11.0ppg Lead: 392 bbls, 2201 cuft, 870 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 69 bbls, 387 cuft, 312 sks HalCem Type I/II – 1.24 cuft/sk Temp BHST 53° F Verification Method Cement returns to surface Notes Job will be mixed on the fly NDBi-016 13-3/8" SURFACE CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 2599 2684 85 0.14973 12.7 TAIL LENGTH 2184 2684 500 0.07491 37.5 TAIL EXCESS 50% 18.7 LEAD TOP TO BASE OF PERM 1430 2184 754 0.07491 56.5 EXCESS FACTOR FOR ABOVE 50% 28.2 PERMAFROST ANNULUS (Lead) 128 1430 1302 0.07491 97.5 EXCESS FACTOR FOR ABOVE 200% 195.1 CASED HOLE ANNULUS 46 128 82 0.18620 15.3 Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + excess Lead TOC Stage 1: 250’ TVD above top Nanushuk Stage 2: N/A Tail Open hole volume + excess + 85 ft shoe track Tail TOC Stage 1: 1000 ft above casing shoe Stage 2: Top of the 9-5/8” Liner Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead Stage 1: 30% Open Hole Excess 13.0ppg Lead: 184 bbls, 1033cuft, 561sks ExtendaCem – 1.84 cuft/sk Stage 2: N/A Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 79 bbls, 444cuft, 358sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 100% Open Hole Excess Verified cement calcs. -bjm Verified cement calcs. -bjm 15.3ppg Tail: 248 bbls, 1392cuft, 1122sks VersaCem Type I/II – 1.24 cuft/sk Temp BHST 94° F Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1 st Stage Cement Job Only. -2ndStage Cement Job will not be logged, assuming job parameters are as expected (No losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) -2ndStage bond evaluation does not affect 1st Stage bond evaluation and frac decision. - Logging of 1 st Stage cement will demonstrate isolation of injection fluids in the Nanushuk reservoir, as well as isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -2ndStage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. NDBi-016 9.625" Production Liner - 1st Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 12902 12987 85 0.07321 6.2 TAIL LENGTH 11987 12987 1000 0.05578 55.8 TAIL EXCESS 30% 16.7 LEAD LENGTH 9450 11987 2537 0.05578 141.5 LEAD EXCESS 30% 42.5 NDBi-016 9.625" Production Liner - 2nd Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME TAIL LENGTH 2684 4825 2141 0.05578 119.4 TAIL EXCESS 100% 119.4 Liner Lap 13-3/8" 68# x 9-5/8" 47# LNR 2534 2684 150 0.05974 9.0 Attachment 7: Prognosed Formation Tops NDBi-016 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1055 1048 978 100 7.2 Permafrost Base Transition 1415 1394 1324 100 7.3 Middle Schrader Bluff 1833 1763 1693 100 7.6 MCU (Lower Schrader Bluff) 2340 2141 2072 100 7.8 Tuluvak Shale 2896 2440 2370 100 7.9 Tuluvak Sand 3057 2500 2430 100 10.2 TS 790 4775 2800 2730 100 9.4 Seabee 6811 3118 3049 100 9.2 Nanushuk 11107 3791 3722 100 8.9 NT7 MFS 11458 3846 3777 100 8.9 NT6 MFS 11905 3916 3847 100 8.9 NT5 MFS 12256 3971 3902 100 8.8 NT4 MFS 12498 4009 3940 100 8.8 NT3 MFS 12942 4082 4013 100 8.8 Nanushuk 3.2 (NT3) 13088 4116 4047 100 8.8 Attachment 8: Well Schematic Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole LWD Gamma Ray Resistivity 8-1/2” Production Hole LWD Gamma Ray Resistivity Sonic (9-5/8” Liner Cement Evaluation Only) Density Neutron Image Log Mudlogging No mudlogging is planned for NDBi-016 Attachment 10: Wellhead & Tree Diagram Attachment 11: Injector Area of Review Wells within ¼ mile of proposed injection well. Distance Annulus integrity Area of Review Information NDBi-018 (planned well) 325’ N/A NDBi-018 is a planned well and is schedule to be drilled as the well prior to NDBi-016. The toe of NDBi- 018 will be within ¼ mile of the heel of NDBi-016 in the proposed injection zone within the reservoir. NDBi-018 9-5/8” liner cementing information will be submitted to the AOGCC as part of the frac sundry, including the CBL of the 1st stage cement job. The 4- 1/2” liner is uncemented with frac sleeves and isolation packers. AS BUILT CERTIFICATION 3230 "C" Street, Ste. 201 Anchorage, Alaska 99503 PHONE: (907) 272-5451 FAX : (907) 272-9065 http://www.LOUNSBURYINC.com Certificate of Authorization No. AECC391 DATE: SHEET: FIELD BOOK: DRAWING NAME: DRAWN: CHECKED: GRID: OF SCALE: NORTH SLOPE BOROUGH PROJECT LOCATION: STATE OF ALASKA PIKKA UNIT AS BUILT SURVEY WELL 16 ND-B PAD CONDUCTORS WITHIN SECTION 4, TOWNSHIP 11 NORTH, RANGE 6 EAST, UMIAT MERIDIAN VICINITY MAP N 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Wednesday, 7 August, 2024 13:16 To:Staudinger, Garret (Garret) Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC) Subject:RE: Pikka NDEBi-016 PTD (224-105): Question Thank you From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Wednesday, 7 August, 2024 12:58 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: Pikka NDEBi-016 PTD (224-105): Question Andy, At this Ɵme, there are no plans to pre-produce NDBi-016 with the excepƟon of the Ňowback for well clean-up. Thanks, 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: Wednesday, August 7, 2024 12:37 PM To: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: ![EXT]: Pikka NDEBi-016 PTD (224-105): Question Garret, Are there plans to pre-produce NDBi-016 before injecƟon operaƟons? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-105 NANUSHUK OILPIKKA Pikka NDBi-016 WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDBi-016Initial Class/TypeSER / PENDGeoArea890Unit11580On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241050PIKKA, NANUSHUK OIL - 600100NA1 Permit fee attachedYes ADL392984, ADL393016, ADL393020, ADL391455, ADL393018, and ADL3930102 Lease number appropriateYes3 Unique well name and numberYes PIKKA, NANUSHUK OIL - 600100 - governed by CO 8074 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNo AIO REQUIRED before injection operations begin.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes15 All wells within 1/4 mile area of review identified (For service well only)Yes Brief flowback for well clean-up16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1460 psi, BOP rated to 5000 psi (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 shutdownNo33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S measures not required: None anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Tuluvak (with shallow gas) pressures anticipated to be 10.2 ppg EMW. Nanushuk reservoir at 8.9 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/7/2024ApprBJMDate8/6/2024ApprADDDate8/7/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/7/2024
