Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
223-052
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-043A 50103208590100 LETTER OF TRANSMITTAL ؒ جؐؐؐNDB-025 ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf ؒ جؐؐؐNDB-031 ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf ؒ جؐؐؐNDB-032 ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-037 ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-048 ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-051 ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf ؒ جؐؐؐNDBi-016 ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf ؒ جؐؐؐNDBi-018 ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf ؒ جؐؐؐNDBi-030 224-006 T41154 225-028 T41155 224-124 T41156 224-143 T41157 224-105 T41158 224-085 T41159 224-013 T39830 223-006 T39829 223-120 T39832 LETTER OF TRANSMITTAL ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf ؒ جؐؐؐNDBi-036 ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf ؒ جؐؐؐNDBi-043A ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf ؒ جؐؐؐNDBi-044 ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf ؒ جؐؐؐNDBi-046L1 ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf ؒ جؐؐؐNDBi-049 ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf ؒ ؤؐؐؐNDBi-050 Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf 225-012 T41160 224-119 T41161 224-154 T41162 223-052 T39834 223-087 T39835 224-029 T39837 NDBi-043A LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 1 PDF file NDBi-043 (50-103-20859-0000) NDBi-043A (20-103-20859-0100) Well clean up report Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 907-375-4607 phone shannon.koh@santos.com DATE: 12/5/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 223-051: T39833 223-052: T39834 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.06 08:20:13 -09'00' DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 0 3 - 2 0 8 5 9 - 0 1 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 4 3 A Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 8/ 1 7 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 5 2 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 13 2 1 0 TV D 41 9 5 Cu r r e n t S t a t u s WA G I N 5/ 2 0 / 2 0 2 4 UI C Ye s We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : GR - R E S - N E U - D E N - S o n i , M u d l o g s , C B L Ye s Ye s Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 9/ 1 8 / 2 0 2 3 90 1 3 2 1 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ A P _ R 0 4 _ R M _ 2 0 2 3 0 8 0 4 . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ A P _ R 0 5 _ R M _ 2 0 2 3 0 8 0 4 . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 90 1 3 2 1 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ D M D _ R M _ 1 3 2 1 0 f t . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ D M T _ R 0 4 _ R M _ 2 0 2 3 0 8 0 4 . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ D M T _ R 0 5 _ R M _ 2 0 2 3 0 8 0 4 . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 62 4 0 1 3 2 0 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ G 5 _ G E O I S O T O P E S _ C o r r e c t e d da t a _ 1 3 2 1 0 f t . l a s 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 12 9 1 3 2 0 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ D r i l l G a s _ A S C I I _ d e p t h _ L i t h o l o g y _ 1 3 2 1 0 f t . l as 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A C o m p a s s S u r v e y Re p o r t s . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A N A D 2 7 C o m p a s s Su r v e y R e p o r t s . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A N A D 2 7 . t x t 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A P l a n V i e w C o m p a s s Re p o r t . p d f 38 0 0 1 ED Di g i t a l D a t a Mo n d a y , M a y 2 0 , 2 0 2 4 AO G C C P a g e 1 o f 4 ND B i - , 04 3 A _ G 5 _ G E O I S O T O PE S_Cor r ec ted __ da t a _ 1 3 2 1 0 f t . l a s ND B i - , 043 A _ D M D _ RM_1 3 2 1 0ft . l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 0 3 - 2 0 8 5 9 - 0 1 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 4 3 A Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 8/ 1 7 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 5 2 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 13 2 1 0 TV D 41 9 5 Cu r r e n t S t a t u s WA G I N 5/ 2 0 / 2 0 2 4 UI C Ye s DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A v e r t i c a l S e c t i o n Co m p a s s R e p o r t . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A W A S u r v e y Re p o r t s . x l s x 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A . t x t 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ A P _ R M _ 2 0 2 3 0 8 0 4 . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ D M D _ R M _ 1 3 2 1 0 f t . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ D M T _ R M _ 2 0 2 3 0 8 0 4 . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 2 M D . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 2 T V D . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 5 M D . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 5 T V D . c g m 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ A P _ R M _ 2 0 2 3 0 8 0 4 . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ D M D _ R M _ 1 3 2 1 0 f t . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ D M T _ R M _ 2 0 2 3 0 8 0 4 . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 2 M D . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 2 T V D . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 5 M D . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ R M _ 1 3 2 1 0 f t _ 5 T V D . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 a n d N D B i - 0 4 3 A Mu d l o g g i n g F i n a l R e p o r t . d o c x 38 0 0 1 ED Di g i t a l D a t a Mo n d a y , M a y 2 0 , 2 0 2 4 AO G C C P a g e 2 o f 4 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 0 3 - 2 0 8 5 9 - 0 1 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 4 3 A Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 8/ 1 7 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 5 2 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 13 2 1 0 TV D 41 9 5 Cu r r e n t S t a t u s WA G I N 5/ 2 0 / 2 0 2 4 UI C Ye s DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 a n d N D B i - 0 4 3 A Mu d l o g g i n g F i n a l R e p o r t . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : Mu d l o g g i n g D a i l y R e p o r t s _ C o m p i l a t i o n _ N D B i - 04 3 _ N D B i - 0 4 3 A . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A _ G a s R a t i o L o g _ 1 3 2 1 0 ft _ M D _ 2 i n . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A _ G a s R a t i o L o g _ 1 3 2 1 0 ft _ M D _ 5 i n . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ G a s R p t _ 1 3 _ 2 0 2 3 0 8 0 4 . x l s x 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A _ L i t h o l o g y . x l s x 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A _ M u d L o g _ 1 3 2 1 0 ft _ M D _ 2 i n . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A _ M u d L o g _ 1 3 2 1 0 ft _ M D _ 5 i n . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 04 3 A _ M u d L o g _ G a m m a _ 1 3 2 1 0 f t _ M D . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A S h o w R e p o r t # 1 3 10 2 6 0 - 1 0 3 5 0 . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A S h o w R e p o r t # 1 4 10 5 8 9 - 1 0 6 8 3 . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 4 3 A S h o w R e p o r t # 1 4 10 5 8 9 - 1 0 6 8 3 . x l s m . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : F o r m a t i o n _ T o p s _ T a b l e _ N D B i - 04 3 A . p d f 38 0 0 1 ED Di g i t a l D a t a DF 9/ 1 8 / 2 0 2 3 E l e c t r o n i c F i l e : W e l l s i t e G e o l o g i s t F W R N D B i - 04 3 & N D B i - 0 4 3 A . p d f 38 0 0 1 ED Di g i t a l D a t a DF 2/ 2 3 / 2 0 2 4 90 1 3 2 1 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 04 3 A _ L W D _ G R _ R e s _ D e n s _ N e u _ C a l _ A z i R e s _ 1 32 1 0 . l a s 38 5 3 3 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s_ R M _ 1 3 2 1 0 f t _ 2 M D . c g m 38 5 3 3 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s_ R M _ 1 3 2 1 0 f t _ 2 T V D . c g m 38 5 3 3 ED Di g i t a l D a t a Mo n d a y , M a y 2 0 , 2 0 2 4 AO G C C P a g e 3 o f 4 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 0 3 - 2 0 8 5 9 - 0 1 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 4 3 A Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 8/ 1 7 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 5 2 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 13 2 1 0 TV D 41 9 5 Cu r r e n t S t a t u s WA G I N 5/ 2 0 / 2 0 2 4 UI C Ye s We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 8/ 1 7 / 2 0 2 3 Re l e a s e D a t e : 7/ 7 / 2 0 2 3 DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s_ R M _ 1 3 2 1 0 f t _ 2 M D . p d f 38 5 3 3 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 04 3 A _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s_ R M _ 1 3 2 1 0 f t _ 2 T V D . p d f 38 5 3 3 ED Di g i t a l D a t a 8/ 1 7 / 2 0 2 3 10 1 3 2 1 3 2 1 0 21 8 5 6 Cu t t i n g s Mo n d a y , M a y 2 0 , 2 0 2 4 AO G C C P a g e 4 o f 4 M. G u h l 5/ 2 0 / 2 0 2 4 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:Thompson, Jacob (Jacob) To:Coldiron, Samantha J (OGC) Cc:McLellan, Bryan J (OGC); Tirpack, Robert (Robert); Senden, Robert (Ty); Brake, Jared (Jared); Davis, Rachel (Rachel) Subject:RE: NDBi-043A (PTD 223-052) Waiver Request to Operate Date:Friday, April 12, 2024 1:31:38 PM Attachments:image002.png image003.png image004.png NDBi-043 Schematic 4.12.24 Abandonment.pdf NDBi-043 Schematic 4.12.24 Final.pdf NDB-043A Waiver.pdf You don't often get email from jacob.thompson@santos.com. Learn why this is important Mrs. Coldiron, Oil Search Alaska (OSA) submits the following proposal to meet the conditions stated in the Attached Waiver request: 1. “When the well is permanently plugged and abandoned, the operator will place an internal cement plug from 50’ below the top of the TS 790 to 100’ MD above the 9-5/8” liner top packer, to eliminate the possibility of gas from the Tuluvak migrating inside the wellbore via a leak in the 9-5/8” liner or liner-top packer. The TS 790 top is at 3360’ MD in this well. This cement plug will fill all tubulars and annuli inside the 9-5/8” liner.” Attached is a draft abandonment schematic showing how OSA plans to permanently abandon the NDBi-043A wellbore. The proposed abandonment plan will meet the criteria outlined within the waiver conditions. 2. “The uncemented interval in the Tuluvak will be considered and risk assessed before any alteration of the 9-5/8” intermediate casing or the 13-3/8” surface casing takes place. The risk assessment must be discussed with AOGCC and included in any sundry application submitted for alteration of these casing strings.” The above requirement to complete a risk assessment prior to altering the 9-5/8” Intermediate Liner or 13- 3/8” Surface Casing will be achieved by following the OSA regulatory compliance plan. The regulatory compliance plan will ensure compliance and conformance against AOGCC and OSA regulations and policies. The regulatory compliance plan is outlined within the Santos Alaska Well Integrity Management System (AWIMS) guidelines. Below is a brief overview of the regulatory compliance plan. All Waivered wells will be highlighted as “Waivered” and displayed within the well status dashboard in the Well Integrity tracking software that OSA utilizes. The criteria outlined by the AOGCC will be populated within this dashboard and visible to all future engineers within OSA. Within the digital well file of Peloton WellView, waivered wells will be identified as such in the Well Status tab and will have the waiver requirements listed as well. The paper well file will have the waiver criteria posted with the well schematic. A permanent stencil of “Waivered Well” will be painted on the front of the tubing hanger with an info tube containing information of the waiver permanently attached to the well head. Handover forms will contain the information of Wavered Well, which will be a template for all future handovers between the Intervention/Workover group and Production. The Well Schematic will display “Waivered Well” for a reference to verify criteria prior to any interventions or workovers. This six-step process is the template that Santos will use for any Waivered wells whether an internal Waiver or a Waiver with the AOGCC. 3. “OSA must submit a regulatory compliance plan within 30 days to ensure future compliance with conditions 1 & 2.” This email documents the regulatory compliance plan. 4. “The wellbore diagram in the operator’s wellfile must clearly identify the top of cement outside the 9- 5/8” liner below the top of the Tuluvak hydrocarbon interval. A copy of this diagram must be submitted to the AOGCC for the public record within 30 days.” The wellbore schematic is attached. It identifies the TOC from the Halliburton Advanced Cement Evaluation Results Report dated 9/25/23 by Fanny Haroun and the TS_790. Feel free to reach out if you have any questions. Thank you, Jacob Thompson – Senior Drilling EngineerOil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Tuesday, April 2, 2024 7:50 AM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: ![EXT]: NDBi-043A (PTD 223-052) Waiver Request to Operate Mr. Thompson, Please see the attached letter. Regards, Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 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 orcontain 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 NDBi-043 Well Schematic 20" Insulated Conductor80' MD 9-5/8" Liner Hanger and Liner Top Packer2332' MD 13-3/8" 68 ppf L-80 Surface Casing2502' MD 9-5/8", 47ppf L-80 Production Liner6237' MD 4-½”, 12.6ppf P-110S Production Liner13207' MD Plug Back TD10947' MDKOP10136' MD 4-½” Liner Hanger/Top Packer6071' MD GL 46.6' RKB – Bottom Flange 4/9/2024 #Completion Item Depth (MD') Depth (TVD') Inc ID" OD" 1X Landing Nipple 1431 1408 23 3.813 4.773 2GLM w/ 1.5" Pocket 1486 1458 24 3.958 7.575 3X Landing Nipple 1550 1516 26 3.813 4.773 4X Landing Nipple 5938 4262 75 3.813 4.773 5P/T D.H. Gauge 5993 4275 77 3.958 5.500 6X Landing Nipple 6008 4279 77 3.813 4.773 7Tieback Seal Assy 6104 4298 79 3.890 5.280 8 9.625" x 4.5" LH/Packer 6071 4292 78 6.040 8.430 9#13 Openhole Packer 6757 4355 91 3.918 8.000 10 Stage 11 ‐ Frac Sleeve 6980 4350 91 3.735 5.627 11 #12 Openhole Packer 7244 4344 91 3.918 8.000 12 Stage 10 ‐ Frac Sleeve 7465 4340 91 3.735 5.627 13 #11 Openhole Packer 7728 4334 91 3.918 8.000 14 Stage 9 ‐ Frac Sleeve 8075 4326 91 3.735 5.627 15 #10 Openhole Packer 8378 4320 91 3.918 8.000 16 Stage 8 ‐ Frac Sleeve 8602 4315 91 3.735 5.627 17 #9 Openhole Packer 8864 4309 91 3.918 8.000 18 Stage 7 ‐ Frac Sleeve 9130 4304 91 3.735 5.627 19 #8 Openhole Packer 9351 4299 91 3.918 8.000 20 Stage 6 ‐ Frac Sleeve 9658 4292 91 3.735 5.627 21 #7 Openhole Packer 9879 4287 91 3.918 8.000 22 #6 Openhole Packer 10351 4277 91 3.918 8.000 23 Stage 5 ‐ Frac Sleeve 10823 4267 91 3.735 5.627 24 #5 Openhole Packer 11085 4261 91 3.918 8.000 25 Stage 4 ‐ Frac Sleeve 11351 4256 91 3.735 5.627 26 #4 Openhole Packer 11655 4249 91 3.918 8.000 27 Stage 3 ‐ Frac Sleeve 11839 4245 91 3.735 5.627 28 #3 Openhole Packer 12101 4239 91 3.918 8.000 29 Stage 2 ‐ Frac Sleeve 12325 4234 91 3.735 5.627 30 #2 Openhole Packer 12587 4229 91 3.918 8.000 31 Stage 1 ‐ Frac Sleeve 12851 4223 91 3.735 5.627 32 #1 Openhole Packer 13073 4218 91 3.918 8.000 33 #2 Toe Sleeve 13133 4217 91 3.500 5.875 34 #1 Toe Sleeve 13141 4217 91 3.500 5.875 35 WIV Collar 13196 4216 91 5.620 36 Eccentric shoe 13205 4215 91 3.930 5.220 1 2 3 4 5 6 7 8 9 9-5/8" x 12-¼” TOC2792' MD Waivered Well TS_7903357' MD NDBi-043A Abandonment Schematic 20" Insulated Conductor80' MD 9-5/8" Liner Hanger and Liner Top Packer2332' MD 13-3/8" 68 ppf L-80 Surface Casing2502' MD 9-5/8", 47ppf L-80 Production Liner6237' MD 4-½”, 12.6ppf P-110S Production Liner13207' MD Plug Back TD10947' MDKOP10136' MD 4-½” Liner Hanger/Top Packer6071' MD GL 46.6' RKB – Bottom Flange 4/9/2023 #Completion Item Depth (MD') Depth (TVD') Inc ID" OD" 1X Landing Nipple 1431 1408 23 3.813 4.773 2GLM w/ 1.5" Pocket 1486 1458 24 3.958 7.575 3X Landing Nipple 1550 1516 26 3.813 4.773 4X Landing Nipple 5938 4262 75 3.813 4.773 5P/T D.H. Gauge 5993 4275 77 3.958 5.500 6X Landing Nipple 6008 4279 77 3.813 4.773 7Tieback Seal Assy 6104 4298 79 3.890 5.280 8 9.625" x 4.5" LH/Packer 6071 4292 78 6.040 8.430 9#13 Openhole Packer 6757 4355 91 3.918 8.000 10 Stage 11 ‐ Frac Sleeve 6980 4350 91 3.735 5.627 11 #12 Openhole Packer 7244 4344 91 3.918 8.000 12 Stage 10 ‐ Frac Sleeve 7465 4340 91 3.735 5.627 13 #11 Openhole Packer 7728 4334 91 3.918 8.000 14 Stage 9 ‐ Frac Sleeve 8075 4326 91 3.735 5.627 15 #10 Openhole Packer 8378 4320 91 3.918 8.000 16 Stage 8 ‐ Frac Sleeve 8602 4315 91 3.735 5.627 17 #9 Openhole Packer 8864 4309 91 3.918 8.000 18 Stage 7 ‐ Frac Sleeve 9130 4304 91 3.735 5.627 19 #8 Openhole Packer 9351 4299 91 3.918 8.000 20 Stage 6 ‐ Frac Sleeve 9658 4292 91 3.735 5.627 21 #7 Openhole Packer 9879 4287 91 3.918 8.000 22 #6 Openhole Packer 10351 4277 91 3.918 8.000 23 Stage 5 ‐ Frac Sleeve 10823 4267 91 3.735 5.627 24 #5 Openhole Packer 11085 4261 91 3.918 8.000 25 Stage 4 ‐ Frac Sleeve 11351 4256 91 3.735 5.627 26 #4 Openhole Packer 11655 4249 91 3.918 8.000 27 Stage 3 ‐ Frac Sleeve 11839 4245 91 3.735 5.627 28 #3 Openhole Packer 12101 4239 91 3.918 8.000 29 Stage 2 ‐ Frac Sleeve 12325 4234 91 3.735 5.627 30 #2 Openhole Packer 12587 4229 91 3.918 8.000 31 Stage 1 ‐ Frac Sleeve 12851 4223 91 3.735 5.627 32 #1 Openhole Packer 13073 4218 91 3.918 8.000 33 #2 Toe Sleeve 13133 4217 91 3.500 5.875 34 #1 Toe Sleeve 13141 4217 91 3.500 5.875 35 WIV Collar 13196 4216 91 5.620 36 Eccentric shoe 13205 4215 91 3.930 5.220 1 2 3 4 5 6 7 8 9 Perforations~6061' MD FB P&A Cement Top~6200' MD FB P&A Plug #246' MD Top of Cement2792' MD TS_7903357' MD 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 Jacob Thompson Senior Drilling Engineer Oil Search Alaska, LLC P.O. Box 240927 Anchorage, Alaska 99524-0927 Mr. Thompson, This letter is regarding well NDB-043A (PTD 223-052), in response to Oil Search Alaska, LLC’s (OSA) 2/20/24 request for a decision on operability of the well and 3/21/24 waiver request. The AOGCC has reviewed the evidence presented and finds that competent cement is not present outside the 9-5/8” liner across much of and above the Upper Tuluvak hydrocarbon-bearing interval. The cement job did not go according to plan in that cement was not observed at surface when circulating off the top of the liner. Evidence indicates that the open hole volume was enlarged more than the 30% excess assumed during the job design and execution, resulting in the top of cement at an unknown depth below the top of liner. Cement evaluation logs run across the Intermediate liner (2 logs, Baker LWD Sonic log and Halliburton wireline CAST log) indicate non-existent to poor cement across this interval. The logs do not provide evidence that the hydrocarbons and overpressured zones in the Upper Tuluvak are cemented as required by 20 AAC 25.030(d)(5) and by Pool Rule #6 of Conservation Order (CO) 807. Indication of improper cementing require running a cement quality log and a plan of remedial action per 20 AAC 25.030(d)(B)(i) and (ii). The AOGCC, upon request of the operator OSA, will issue a conditional waiver to 20 AAC 25.030(d)(5), 20 AAC 25.030(d)(5)(B)(ii) and Pool Rule #6 of CO 807, in accordance with the requirements of 20 AAC 25.030(g)and 20 AAC 25.556(d), to allow this well to operate as a service well or development well. A waiver is justified because the risks of fluids migrating from one stratum to another is minimal for the following reasons: 1. Both cement-evaluation logs run in the well indicate cement is present in the annulus outside the 9-5/8” Intermediate liner across the strata below the Upper Tuluvak. This cement will ensure fluid migration from Tuluvak to a deeper strata is not likely. 2. The surface casing shoe, which was subjected to a Formation Integrity Test (FIT) to 16.8 ppg, has sufficient strength to contain a full column of gas from the top of the Tuluvak (estimated to have 10.2 ppg Equivalent Mud Weight (EMW)) to the surface casing shoe. Thus, there is minimal risk of gas migrating above the surface casing shoe. 3. There are no permeable formations between the top of the Tuluvak and the surface casing shoe. NDB-043A (PTD 223-052) Operability Waiver Request April 1, 2024 Page 2 of 2 4. Items 1, 2 and 3 above ensure that the significant hydrocarbon zones within the Tuluvak will be protected and isolated if the surface casing and intermediate casing are not altered and maintain their integrity. 5. Well pressures arising from the Tuluvak will be controlled and confined to the open hole x 9-5/8” casing annulus, as confirmed by a pressure test of the 13-3/8” casing, 9-5/8” liner-top packer and 9-5/8” casing on 7/29/23. Both a negative pressure test and a positive pressure test to 3000 psi were performed successfully. The 16.8 ppg FIT acquired at the surface casing shoe demonstrates integrity sufficient to prevent upward transmission of pressure in this anulus beyond the casing shoe. 6. There is no freshwater present in the NDB pad area. 7. Fluids injected into the Nanushuk Oil Pool will be contained by sufficient cement between the 9-5/8” Intermediate liner shoe and the Tuluvak. The AOGCC’s waiver of 20 AAC 25.030(d)(5) for this well is approved on the conditions that: 1. When the well is permanently plugged and abandoned, the operator will place an internal cement plug from 50’ below the top of the TS 790 to 100’ MD above the 9-5/8” liner top packer, to eliminate the possibility of gas from the Tuluvak migrating inside the wellbore via a leak in the 9-5/8” liner or liner-top packer. The TS 790 top is at 3360’ MD in this well. This cement plug will fill all tubulars and annuli inside the 9-5/8” liner. 2. The uncemented interval in the Tuluvak will be considered and risk assessed before any alteration of the 9-5/8” intermediate casing or the 13-3/8” surface casing takes place. The risk assessment must be discussed with AOGCC and included in any sundry application submitted for alteration of these casing strings. 3. OSA must submit a regulatory compliance plan within 30 days to ensure future compliance with conditions 1 & 2. 4. The wellbore diagram in the operator’s wellfile must clearly identify the top of cement outside the 9-5/8” liner below the top of the Tuluvak hydrocarbon interval. A copy of this diagram must be submitted to the AOGCC for the public record within 30 days. 5. This decision applies only to this well. All other wells will be evaluated on a case- by-case basis. Based on the reasons and conditions listed above, the AOGCC finds that this waiver will not promote waste, is based on sound engineering and geoscience principles, will not jeopardize the ultimate recovery of hydrocarbons, will not jeopardize correlative rights, and will not result in an increased risk to health, safety, or the environment, including fresh water. Sincerely, Brett W. Huber, Sr. Chair, Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.01 21:15:41 -08'00' 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:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:NDBi-043A (PTD 223-052) Waiver Request to Operate Date:Thursday, March 21, 2024 7:48:41 AM Attachments:image007.png image008.png image009.png Mr. McLellan, Oil Seach Alaska a subsidiary of Santos Limited LLC would like to request a wavier to allow operability of the Pikka development injection well NDBi-043A. The NDBi-043A well met requirements outlined in 20 AAC 25.030 Casing and Cementing: Cement job was pumped per plan, cement bond logs identify cement across hydrocarbon zones, the Nanushuk and Tuluvak have been isolated from fresh water sources, each other, and surface, and the Nanushuk was successfully fracd and flowed back without any integrity concerns. The current status of NDBi-043A is fit to operate and complies with AOGCC’s Mission Statement of ensuring greater ultimate recovery and the protection of health, safety, fresh ground waters and the rights of all owners to recover their share of the resource. The requested waiver to operate NDBi-043A is based on Oil Search’s body of evidence shown below. Oil Search Alaska (OSA) offers the following evidence that the NDBi-043A (PTD 223-052) 9-5/8” Liner Cement has met the requirements outlined in 20 AAC 25.030 Casing and Cementing. NDBi-043A has been completed as per the approved PTD and is carrying out post rig stimulation, intervention, and well flow back operations. The well will then be put into long term shut in awaiting the construction of the Nanushuk production facility. After the production facility is operational the well will be put-on long-term injection of both seawater and MI. Oil Search Alaska offers the following evidence that the Tuluvak formation was sufficiently cemented based on volumetric calculations from the resulting cement job and logged cement. During the 9-5/8” liner cement job: the plug bumped, floats held, good lift pressure was noted, no losses were experienced, and presence of cement was identified by both Ultrasonic and LWD logs. Below are details summarizing the cement job. 9-5/8” Liner Cement / Spacer Volumes Pumped 80 bbls 11.8 ppg tuned spacer ahead of cement Lead Cement: 277 bbls of 12.0 ppg cement (30% open hole excess + 200’ over liner top) Tail Cement: 44 bbls 15.3 ppg tail cement (30% open hole excess) Displaced at 5-8 bpm with MOBM Latch up liner dart on volume Pumped 30 bbls 11.5ppg tuned spacer to place spacer in drill pipe across liner top Reduce rate to 3 bpm for plug bump. Bump Plugs on calculated volume with good lift pressure Full returns, zero losses. Liner Hanger & packer set and pressure tested with no issues, good pressure sequences. 95 bbls spacer returned on bottoms up out of the total 110 bbls pumped - 15 bbls tuned spacer estimated below the liner top. All pre-testing of cement blends passed QA/QC testing including appropriate thickening time and compressive strength testing Cement samples gathered the day of the pump job were observed to set up properly NDBi-043A 9-5/8” Liner Cementing Volumetric TOC 110 total bbls of spacer pumped with 95 bbls spacer returned to surface leaving ~15 bbls of spacer in liner lap / open hole. The 15 bbls of spacer below the top of the liner puts 9 bbls in the liner lap and 6 bbls in the casing / open hole. Based on these volumes, TOC is placed at 2,561’ MD / 2,280’ TVD. Shallowest productive sand in Tuluvak is at 2,950’ MD / 2,549’ TVD This gives 389’ MD / 269’ TVD of cement coverage above the top of the Tuluvak’s productive interval. Tuluvak is isolated and has proper coverage Cement below Isolating Nanushuk and Tuluvak Cement Across Tuluvak preventing migration. Isolation from MCU (Lower Schrader Bluff) and Surface Cement above top of tuluvak Gas tight Hydril 563 connections on the 47# L-80 9-5/8” CSG. V0 Rated 13-3/8” x 9-5/8” Liner Top Packer Passing 4,000 psi state witnessed pressure test. Passing no flow / negative test (displacement to 9.2 ppg Production hole fluid.) 13-3/8” surface casing cemented to surface and pressure tested. 13-3/8” FIT to 16.8 ppg EMW. No requirement to down-squeeze in the future Zero risk of broaching the surface casing shoe 13-3/8” Shoe is not exposed to wellbore pressures. Annulus will be monitored as per pool rules. Continuous monitoring through PI System with automated alarms and notifications. Conclusions Industry best practices were followed during well construction. Regulation for cementing hydrocarbon zones have been met. Regulations for isolating hydrocarbon zones have been exceeded. Risk to lower zones must be considered. Primary objective is recovery of economic reserves from the Nanushuk No remedial actions will improve well integrity or isolation of the Tuluvak Perforating and attempting cement squeeze introduces more risk to well integrity. Cement squeezes are unsuccessful when annulus already contains cement. Cement squeeze operations will increases risk of Tuluvak communication. Both the sonic and ultra-sonic bond logs show patchy cement across and above the Tuluvak productive interval. Vendors have confirmed tools were operating in specification Internal and Vendor assessments of the bond interpretations are in agreement Bond logs showing poor cement quality across zones with cement in place has been experienced in the past on the North Slope Bond logs have been problematic in properly reading cement quality with lite weight cement blends Thank you for your time and consideration, Jacob Thompson – Senior Drilling EngineerOil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@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 orcontain 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 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 4 Files NDBi-043A (20-103-20859-0100) جؐؐؐCGM ؒ NDBi-043A_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_13210ft_2MD.cgm ؒ NDBi-043A_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_13210ft_2TVD.cgm ؒ ؤؐؐؐPDF NDBi-043A_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_13210ft_2MD.pdf NDBi-043A_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_13210ft_2TVD.pdf 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: 3/19/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Kayla Junke AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 223-052: T38533 additional Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 07:53:21 -08'00' LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-043 (50-103-20859-0000) NDBi-043A (20-103-20859-0100) NDBi-043_LWD_GR_Res_Dens_Neu_Cal_AziRes_DeepAziRes_10947.las NDBi-043A_LWD_GR_Res_Dens_Neu_Cal_AziRes_13210.las 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: 2/23/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Kayla Junke 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: NDBi-043 PTD: 223-051 T38532 NDBi-043A PTD: 223-052 T38533 2/23/2024 NDBi-043A (20-103-20859-0100) NDBi-043A_LWD_GR_Res_Dens_Neu_Cal_AziRes_13210.las Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.23 14:44:44 -09'00' 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface:2308 FSL, 3342 FEL, S4, T11N, R6E, UM Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): 2613 FSL, 1777 FEL, S5, T11N, R6E, UM GL: 22.8 BF: 46.62 Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 2802 FSL, 5040 FEL, S32, T12N, R6E, UM 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 23. BOTTOM 20"x34" X-65 58' 13-3/8" L-80 2,241' 9-5/8" L-80 4,319' 4-1/2" P-110S 4,195' 4-1/2" P-110S Surface 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Please see attached report from Schlumberger 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate Sr Res EngSr Pet GeoSr Pet Eng Pikka/Nanushuk Oil Pool N/A Oil-Bbl: Water-Bbl: Water-Bbl: PRODUCTION TEST Date of Test: Oil-Bbl: Flow Tubing Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 47# 13,207' 2,127' 4,291' 215# 68# 128' 2,332' 6,237' SIZE DEPTH SET (MD) See attached packer report PACKER SET (MD/TVD) 6,105' 42" 12.6# 16" Grouted to Surface Surface See attached Surf Cement Rpt 12.6# Surface 6,073' 2,502'Surface Surface CASING WT. PER FT.GRADE 08/04/23 CEMENTING RECORD 5,973,039.43 1,411' / 1,390' SETTING DEPTH TVD 5,978,543.75 TOP HOLE SIZE AMOUNT PULLED 418,190.33 414,970.87 TOP SETTING DEPTH MD BOTTOM 50-103-20859-01-00 NDBi-043A ADL 392984, 391445, 393020 LONS 19-003 07/11/23 13,210' / 4,195' 10,132' / 4,282' 69.42 900 E Benson Boulevard, Anchorage, AK 99508 421,902.72 5,972,694.41 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil Search Alaska, LLC WAG Gas 08/17/23 223-052 / 323-411 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD 22.Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperat ure, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. GR-RES-NEU-DEN-Sonic, Mudlogs&%/ Production liner is uncemented8-1/2" TUBING RECORD N/ASurface See attached Int Cement Rpt 4,297' 12-1/4" Tubing 13,207'4-1/2" J GGGG sssssss d 1 0 D yyp dB Pf l L s (atta Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 10:55 am, Oct 16, 2023 Completed 8/17/2023 JSB RBDMS JSB 101723 GBJM 1/11/24 2307 FSL 1938 FWL on the surveyor's plat SFD Yess KOP 10,132' MD (4,282' TVD) SFD SFD 11/8/2023 DSR-11/2/23 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface 1411' 1390' Top of Productive Interval 6830' 4351' 1037' 1033' 1155' 1148' 1411' 1390' 1799' 1735' MCU 2354' 2142' Tuluvak Shale 2805' 2449' Tuluvak Sand 2894' 2510' Seabee 3780' 3121' Nanushuk 4955' 3866' NT8 MFS 4992' 3885' NT7 MFS 5026' 3903' NT6 MFS 5191' 3985' NT5 MFS 5292' 4032' NT4 MFS 5465' 4106' NT3 MFS 6387' 4338' NT3.2 Top Reservoir 6830' 4351' 31. List of Attachments: Summary of daily operations, Packer Set Depths, Cement summaries, Definitive surveys, Wellbore schematic, Frac report 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name:Jake Thompson Digital Signature with Date:Contact Email:jacob.thompson@santos.com Contact Phone:907-854-4377 Authorized Title: Senior Drilling Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. NT3.2 Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and INSTRUCTIONS Upper Schrader Bluff Formation Name at TD: Base Ice Bearing Permafrost Base Permafrost Transition Middle Schrader Bluff Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. N No Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov e foregoing is true and correct to the best : rilling Engineer 10/16/2023 NDBi-043 Well Schematic 20" Insulated Conductor80' MD 9-5/8" Liner Hanger and Liner Top Packer2331' MD 13-3/8" 68 ppf L-80 Surface Casing2502' MD 9-5/8", 47ppf L-80 Production Liner6237' MD 4-½”, 12.6ppf P-110S Production Liner13207' MD Plug Back TD10947' MDKOP10136' MD 4-½” Liner Hanger/Top Packer6071' MD GL 46.6' RKB – Bottom Flange 08/19/2023 # Completion Item Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1431 1408 23 3.813 4.773 2 GLM w/ 1.5" Pocket 1486 1458 24 3.958 7.575 3 X Landing Nipple 1550 1516 26 3.813 4.773 4 X Landing Nipple 5938 4262 75 3.813 4.773 5 P/T D.H. Gauge 5993 4275 77 3.958 5.500 6 X Landing Nipple 6008 4279 77 3.813 4.773 7 Tieback Seal Assy 6104 4298 79 3.890 5.280 8 9.625" x 4.5" LH/Packer 6071 4292 78 6.040 8.430 9 #13 Openhole Packer 6757 4355 91 3.918 8.000 10 Stage 11ͲFrac Sleeve 6980 4350 91 3.735 5.627 11 #12 Openhole Packer 7244 4344 91 3.918 8.000 12 Stage 10ͲFrac Sleeve 7465 4340 91 3.735 5.627 13 #11 Openhole Packer 7728 4334 91 3.918 8.000 14 Stage 9ͲFrac Sleeve 8075 4326 91 3.735 5.627 15 #10 Openhole Packer 8378 4320 91 3.918 8.000 16 Stage 8ͲFrac Sleeve 8602 4315 91 3.735 5.627 17 #9 Openhole Packer 8864 4309 91 3.918 8.000 18 Stage 7ͲFrac Sleeve 9130 4304 91 3.735 5.627 19 #8 Openhole Packer 9351 4299 91 3.918 8.000 20 Stage 6ͲFrac Sleeve 9658 4292 91 3.735 5.627 21 #7 Openhole Packer 9879 4287 91 3.918 8.000 22 #6 Openhole Packer 10351 4277 91 3.918 8.000 23 Stage 5ͲFrac Sleeve 10823 4267 91 3.735 5.627 24 #5 Openhole Packer 11085 4261 91 3.918 8.000 25 Stage 4ͲFrac Sleeve 11351 4256 91 3.735 5.627 26 #4 Openhole Packer 11655 4249 91 3.918 8.000 27 Stage 3ͲFrac Sleeve 11839 4245 91 3.735 5.627 28 #3 Openhole Packer 12101 4239 91 3.918 8.000 29 Stage 2ͲFrac Sleeve 12325 4234 91 3.735 5.627 30 #2 Openhole Packer 12587 4229 91 3.918 8.000 31 Stage 1ͲFrac Sleeve 12851 4223 91 3.735 5.627 32 #1 Openhole Packer 13073 4218 91 3.918 8.000 33 #2 Toe Sleeve 13133 4217 91 3.500 5.875 34 #1 Toe Sleeve 13141 4217 91 3.500 5.875 35 WIV Collar 13196 4216 91 5.620 36 Eccentric shoe 13205 4215 91 3.930 5.220 1 2 3 4 5 6 7 8 9 10136' MD KOP Page 1 of 1 Well Name: NDBi-043 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) OH Packer #13 6,764.2 4,352.0 OH Packer #12 7,251.1 4,342.6 OH Packer #11 7,735.1 4,333.3 OH Packer #10 8,384.8 4,319.8 OH Packer #9 8,871.4 4,309.3 OH Packer #8 9,358.1 4,299.1 OH Packer #7 9,886.1 4,287.7 OH Packer #6 10,358.3 4,280.5 OH Packer #5 11,092.3 4,258.0 OH Packer #4 11,662.0 4,240.3 OH Packer #3 12,108.3 4,228.0 OH Packer #2 12,594.2 4,214.0 OH Packer #1 13,080.4 4,199.2 Page 1 of 1 Well Name: NDBi-043 Cement Surface Casing Cement Surface Casing Cement, Casing, 7/16/2023 09:00 Type Casing Cementing Start Date 7/16/2023 Cementing End Date 7/16/2023 Wellbore Original Hole String Surface, 2,501.9ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Evaluation Results Comment Pump 5 bbls of H2O to flood lines. -Pressure test cement lines to 3500 psi, good test. -Bleed off & line up cementers. -Pump 80 bbls of 10.7 ppg Spacer. -Shut down, drop bottom plug. -Mix and pump 1050 sxs to yield 477 bbls of 11.0 ppg ArcticCem Lead cement. -Tail in 310 sxs to yield 68 bbls of 15.3 ppg Tail cement. -Shut down, drop top plug. -Wash up on the plug w/10 bbls of H20. -Shut down, swap to rig pumps. -Caught cement and began displacement at 10 BPM but had to slow down to avg. displace at 3 bpm due to extremely clabbered returns. -Bump the plug with 920 psi, 500 psi over the last displacement pressure, with 344 bbls 10.5 ppg mud. -Observed FCP at 3 bpm with 420 psi. -70 bbls contaminated cement and 70 bbls of good cement back. -Held 920 psi for 5 mins, bled off pressure & check floats; floats held. -Cement in place at 12:45 hrs. Note: the cement/mud interface was extremely clabbered & locked up in the possum belly. Had to open the conductor valves in the cellar & divert to the cellar. Had to drop the displacement rate to average 3 BPM(some times lower) for last third of displacement. It was difficult for the super suckers to stay up with keeping the cellar pumped. At one point one of the cellar valves plugged up & we began to take returns up the riser to the possum belly. 1, 0.0-2,512.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 2,512.0 Full Return? Yes Vol Cement Ret (bbl) 140.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 6 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 5 Final Pump Pressure (psi) 420.0 Plug Bump Pressure (psi) 420.0 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 PRIME CEMENT SPACER SYSTEM Amount (sacks) 135 Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) 0.0 Yield (ft³/sack) 3.32 Mix H20 Ratio (gal/sack) 21.92 Free Water (%) Density (lb/gal) 10.80 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Lead Fluid Type Lead Fluid Description SBM CEM ARCTICCEM BBL Amount (sacks) 1,050 Class Type I/II Volume Pumped (bbl) 477.0 Estimated Top (ftKB) 0.0 Estimated Bottom Depth (ftKB) 2,000.0 Percent Excess Pumped (%) 350.0 Yield (ft³/sack) 2.56 Mix H20 Ratio (gal/sack) 12.38 Free Water (%) Density (lb/gal) 11.00 Plastic Viscosity (cP) 43.5 Thickening Time (hr) 10.10 1st Compressive Strength (psi) 402.5 Tail Fluid Type Tail Fluid Description SBM CEM HALCEM™ SYS Amount (sacks) 310 Class Type I/II Volume Pumped (bbl) 68.0 Estimated Top (ftKB) 2,000.0 Estimated Bottom Depth (ftKB) 2,512.0 Percent Excess Pumped (%) 40.0 Yield (ft³/sack) 1.25 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Displacement Fluid Type Displacement Fluid Description Fresh water Amount (sacks) Class Volume Pumped (bbl) 10.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) pp -70 bbls contaminated cement and 70 bbls of good cement back. Page 1 of 1 Well Name: NDBi-043 Cement Intermediate Casing Cement Intermediate Casing Cement, Casing, 7/27/2023 19:30 Type Casing Cementing Start Date 7/27/2023 Cementing End Date 7/27/2023 Wellbore Original Hole String Intermediate, 6,237.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Evaluation Results Comment Cement 9-5/8” Intermediate liner as follows: - Fill lines with 10bbls water and pressure test to 4500psi for 5 minutes - Pump 80bbls of 11.8ppg tuned spacer @ 5bpm, 300psi - Drop bottom drill pipe wiper dart - Pump 277bbls of 12ppg lead. 665 sks, Yld 2.35. @ 3-5bpm - Pump 44bbls of 15.3ppg tail. 200 sks, Yld 1.24. @ 3-5bpm - Drop top drill pipe wiper dart -Kick out top dart with 10bbls water. Perform displacement with rig pumps at 5-8bpm: ICP 185psi 3% return flow, FCP 800 psi 8% return flow - Displacement fluid: 261bbls of 11.2ppg MOBM followed by 30bbl of 11.8ppg tuned spacer, followed by 27bbls of 11.2ppg MOBM. - Latch up confirmed at 40bbls displaced - Reduce rate to 3bpm prior to plug bump: final circulating pressure 340psi. Plug bumped on calculated volume. - Total displacement volume 317bbls - Check floats - good -CIP 2320. - Total losses from cement exit shoe to cement in place: 0bbls - Increase pressure to 2200psi to set hanger after plug bump - Set down to 50k to confirm hanger set - While in compression, continue pressuring up to 2500 psi to activate pusher tool and hold 2 minutes - Pressure up to 3500 psi to shear out of HRDE tool and hold 2 minutes - Pressure up to 4000 psi to neutralize pusher tool and hold 5 minutes - Bleed pressure, PU to verify loss of liner weight, new PUW 115k - Continue to PU to expose dog sub, SO to locate top of liner with sub. Break rotation to 20 rpm and SO 65k to set packer (redundant step) - Pressure up 500 psi into string and PU to pull RS packoff, immediately pumping to clean out PBR while also picking up. - Pull above liner top and CBU. No cement identified at surface, slightly contaminated returns observed. 1, 2,502.0-6,240.0ftKB Top Depth (ftKB) 2,502.0 Bottom Depth (ftKB) 6,240.0 Full Return? Yes Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 6 Final Pump Rate (bbl/min) 6 Avg Pump Rate (bbl/min) 6 Final Pump Pressure (psi) 340.0 Plug Bump Pressure (psi) 920.0 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 PRIME CEMENT SPACER SYSTEM Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.41 Mix H20 Ratio (gal/sack) 8.66 Free Water (%) Density (lb/gal) 11.80 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Lead Fluid Type Lead Fluid Description SBM CEM ARCTICCEM BBL Amount (sacks) 665 Class Volume Pumped (bbl) 277.0 Estimated Top (ftKB) 2,502.0 Estimated Bottom Depth (ftKB) 5,740.0 Percent Excess Pumped (%) Yield (ft³/sack) 2.35 Mix H20 Ratio (gal/sack) 13.94 Free Water (%) Density (lb/gal) 12.00 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Tail Fluid Type Tail Fluid Description SBM CEM HALCEM SYS Amount (sacks) 200 Class Volume Pumped (bbl) 44.0 Estimated Top (ftKB) 5,740.0 Estimated Bottom Depth (ftKB) 6,240.0 Percent Excess Pumped (%) Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 15.30 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Displacement Fluid Type Displacement Fluid Description FRESH WATER Amount (sacks) Class Volume Pumped (bbl) 331.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Plug bumped on calculated volume. pp, yppg No cement identified at surface, slightly contaminated returns observed. pp g Pull above liner top and CBU. p Check floats - good - Total losses from cement exit shoe to cement in place: 0bbls Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 8/2/2023 8/3/2023 10,132 102.00 9.25 No accidents, incidents or spills. Backream out of PB1 at 10,799' MD to 10,132' MD. P/U & verify depth with MWD. Conduct open hole sidetrack, begin trough from 10,132' MD back to 10101' MD. Backream & ream 3 passes from 10,132' MD to 10,101' MD. Controlled time-drilling from 10,132' MD to 10,234' MD. 8/3/2023 8/4/2023 10,234 1,645.00 9.30 No accidents, incidents or spills. Drill 8.5" Production Hole from 10234' MD to 10423' MD. Circulate bottoms up once. Short trip from 10423' MD to 10046'. RIH from 10046' MD to 10423' MD, verifying open hole sidetrack at 10132' MD. Continue drilling 8.5" Production Hole from 10423' MD to 11879' MD. Rig Service. 8/4/2023 8/5/2023 11,879 1,331.00 9.20 No accidents, incidents or spills. Drill 8.5" Production Hole from 11879' MD to TD at 13210' MD (4196' TVD). Circulate open hole annular volume 1 time. Turn off ViziTrack MWD tool while circulating. Backream out of hole from 13210' MD to 12700’ MD. Rig Service. 8/5/2023 8/6/2023 13,210 0.00 9.20 No accidents, incidents or spills. Backream out of hole from 12700' MD to 11128' MD. At 11743' MD, encountered spike in torque, circulating pressure & ECD. Work pipe, pick up & down several times to ensure hole is clean. Encountered packoff at 11357' MD, wash down to reduce pressures. Encountered packoff at 11213' MD, reduce circulation rate & clean up wellbore. Encountered packoff at 11128' MD, reduce circulation rate to lower pressures. Continue to backream out of hole from 11128' MD to 10480' MD, while conducting MAD pass logging & following backream plan with entire trip 2-3 fpm to prevent packoffs. 8/6/2023 8/7/2023 13,210 0.00 9.35 No accidents, incidents or spills. Backream conducting MAD pass from 10,475' to 10,088' logging and following Backream plan with entire trip at 2-3 fpm to prevent packoffs. Slight packing off from 10,088' to 10,060'. Once past 10,060' parameters leveled off and trip was clean. Pull to 10,047'. Attempt to resume Backream ops, indications of packoff at 10,045'. Continue with working pipe up and down between 10,060' and 10,080'. Move down with string from 10,134' to 10,320' to work pipe. Work pipe at 10,265'. Implement plan forward of low pump rates, low rpm, varying pickup speed as hole conditions allow. 8/7/2023 8/8/2023 13,210 0.00 9.20 No accidents, incidents or spills. Pulling out of hole from 10,090' across sidetrack area with no real change. Move slow with pump at 1 bpm / 315 psi until BHA and bit are past 10,010'. Torque dropped down to 18-19k again at 9948'. Increase flow to 1.5 bpm / 2360 psi and pull at 180 fph once pressure stabilized at 9884'. Continue pulling at 180 fph from 9755' to 9400'. Pull from 9400' to 8625' at average of 150-180 fph. Pull from 8625' to 7860' at average of 180-200 fph. Pull from 7860' to 7845' at 200 fph. Slow pull rates and vary circulation rates to work string from 7710' to 7675' with erratic torque. Consistent pull from 7675' to 7240'. 8/8/2023 8/9/2023 13,210 0.00 9.25 No accidents, incidents or spills. Encountered pump pressure spike at 7205' MD to 7132' MD, reciprocated pipe to establish circulation on down stroke. Backream out of hole from 7132' MD to 6237' MD, backream speeds from 50-200 ft/hr. Circulate bottoms up 1 time, reciprocated pipe from 6252' MD to 6153' MD. Backream out of hole from 6237' MD to 5970' MD, performing CBL log on 9-5/8" Liner. Change out 5-7/8" Delta saver sub to 5" Delta saver sub. Continue Backream out of hole from 5970' MD to 4353' MD, performing CBL log on 9-5/8" Liner. Rig Service. 8/9/2023 8/10/2023 13,210 0.00 9.20 No accidents, incidents or spills. Backream out of hole from 4353' MD to 1500' MD, performing CBL log on 9-5/8" Liner. Circulate bottoms up at 1500' MD. POOH on elevators from 1501' MD to 455' MD. L/D 8.5" Drilling BHA. Clean & clear rig floor. Rig Service. R/U & M/U BOPE test equip, pull wear ring & set test plug. Test 13-3/8" BOPE with 4-1/2" & 5-7/8" test joints. -Witness to BOP Test was waived by AOGCC Rep Guy Cook at 1000 hrs on 08/09/2023. 8/10/2023 8/11/2023 13,210 0.00 9.70 No accidents, incidents or spills. Finish testing BOPE. P/U & RIH with BHA #5 from surface to 5876' MD. Change out saver sub. RIH from 5876' MD to 6421' MD. Encountered tight hole at 6421' MD, establish circulation & attempt to backream through. Backream from 6377' MD to 6200' MD at reduced rate. Circulate bottoms up at 6200' MD. Attempt to ream through shoe. Packed off at 6240' MD. Pull back in shoe & circulate bottoms up. Contact Santos office for plan forward. Circulate & weight up mud system from 9.2 ppg to 9.7 ppg. 8/11/2023 8/12/2023 13,210 0.00 9.75 No accidents, incidents or spills. Wash down from 6237' MD to 6440' MD. Stage up & circulate until parameters clean up at 6824' MD. Wash down from 6824' MD to 8528' MD. Stage up & circulate until parameters clean up at 8528' MD. Continue to wash down from 8528' MD to 10922' MD. Circulate open hole & liner volume at 10922' MD. Rig Service. Well Name NDBi-043 Wellbore Name Sidetrack 1 PTD # 223-052 Start Drill Date 8/2/2023 End Drill Date 8/18/2023 Page 1 of 2 Well Name NDBi-043 Wellbore Name Sidetrack 1 PTD # 223-052 Start Drill Date 8/2/2023 End Drill Date 8/18/2023 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 8/12/2023 8/13/2023 13,210 0.00 10.00 No accidents, incidents or spills. Circulate annular volume at 10,922' MD. Pump ball down to open Well Commander. Circulate at 10,922' MD. Close Well Commander. Wash down from 10,922' MD to 13,210' MD. Stage up pumps & displace 9.7 ppg MOBM with 10.0 ppg MOBM. Pump ball down to open Well Commander. Circulate 3 bottoms up at 13,210' MD. Close Well Commander. Monitor well for 10 minutes: Static. Backream out of hole from 13,210’ MD to 10,353’ MD. Rig Service. 8/13/2023 8/14/2023 13,210 0.00 10.00 No accidents, incidents or spills. Backream out of hole from 10353’ MD to 6140’ MD. Circulate bottoms up 2 times at 6140' MD. POOH from 6140' MD to BHA. L/D 8.5" Cleanout BHA. Clean & clear rig floor. Rig Service. Slip & cut drill line. Mobilize 4.5" casing handling tools to rig floor. 8/14/2023 8/15/2023 13,210 0.00 10.05 No accidents, incidents or spills. Clean rig floor & skate. R/U 4.5" running equip. RIH with 4.5” P- 110S, TSH Wedge 563 12.6# Lower Completion Assembly from surface to 6237’ MD. Circulate at 9-5/8" shoe at 6237' MD. Continue RIH with 4.5” Lower Completion Assembly from 6237' MD to 7241’ MD. M/U Baker liner hanger & ZXP liner top packer. RIH with 4.5” Lower Completion Assembly on elevators with 5-7/8" drill pipe from 7241' MD to 8637’ MD. Rig Service. 8/15/2023 8/16/2023 13,210 0.00 9.40 No accidents, incidents or spills. RIH 4.5" Lower Completion Assembly on elevators from 8637’ MD to 9806’ MD. Worked pipe from 9806' MD to 9965' MD, encountered obstruction at 9852' MD. RIH with 4.5” Lower Completion Assembly on elevators from 9965’ MD to 13162' MD, worked through multiple tight spots. RIH with 4.5” Lower Completion Assembly from 13162’ MD to 13207’ MD. Circulate & condition mud at 13207'. Displace 10.0 ppg MOBM with 9.4 ppg brine. Drop ball to close WIV collar. Rig Service. 8/16/2023 8/17/2023 13,210 0.00 9.40 No accidents, incidents or spills. Continue to pump ball to seat. Pressured up to 2500 psi, hold for 5 mins to activate SLZXP. Pressure up to 4000 psi to release HRDE on chart. Test back side up to 3000 psi. For 10 mins on chart. Monitor well for 10 minutes = static. POOH on elevators from 6073’ MD to surface. R/U and run HES Wireline. Run cast and Cast-M Tool, Gamma ray CCL tool. RIH to 5925’ MD. Log from 5850’ MD to top of liner @ 2332’ MD. R/D HES Wireline. P/U 4.5" Tubing hanger assembly and perform dummy run to wellhead, mark and L/D landing joint. R/U and Run 4.5”, 12.6#, P110S TSH563 Upper Completion, from surface to 484’ MD. 8/17/2023 8/18/2023 13,210 0.00 9.40 Run 4.5”, 12.6#, P110S TSHW563 Upper Completion, from 484’ MD to 6070' MD. Break circulation while RIH and locate inside the seal bore. Tag out bottom of seal bore @ 6131' MD & mark for space out. Displace with 515 bbls 9.4 ppg corrosion inhibited brine. M/U 2 pups 4.03' and 7.69' below jnt 144. P/U M/U landing joint & hanger. Terminate gauge TEC wire at tubing hanger. RIH 4.5" Tubing Hanger on landing joint and land out. Run in lock down screws. Back out and lay down landing joint. R/U and perform MIT on tubing to 4,000 psi and annulus to 4,000 psi - good test. Bleed tubing pressure to zero and shear GLM, flow check well for 10 min - static, pump fluid both ways to confirm GLM sheared. R/D SLB control line and spool. Reverse circulate 215bbls 6.8 ppg diesel freeze protect. 8/18/2023 8/18/2023 13,210 0.00 9.40 No accidents, incidents or spills. Pressure test surface lines. Reverse circulate 215 bbls diesel @ 2 bpm 150 psi with freeze protect pump. Close blind rams lined up manifolds to U-tube through IA/choke for 1 hr. Drain stack, install 2-way check valve in tubing. Blow down all surface lines. Rig crew prepare for Rig Move. Remove BOP, install on test stump. R/U and pull HP riser. Remove speedhead from wellhead. Install Dry Hole Tree, torque clamp to spec, test hanger seal voids to 5000 psi for 15 min. Clean well head and secure well, install pressure gauges on tubing/annulus. *Rig released from NDBi-043 at 16:00 hrs on 8/18/23. Page 2 of 2 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 8/2/2023 8/3/2023 10,132 102.00 9.25 No accidents, incidents or spills. Backream out of PB1 at 10,799' MD to 10,132' MD. P/U & verify depth with MWD. Conduct open hole sidetrack, begin trough from 10,132' MD back to 10101' MD. Backream & ream 3 passes from 10,132' MD to 10,101' MD. Controlled time-drilling from 10,132' MD to 10,234' MD. 8/3/2023 8/4/2023 10,234 1,645.00 9.30 No accidents, incidents or spills. Drill 8.5" Production Hole from 10234' MD to 10423' MD. Circulate bottoms up once. Short trip from 10423' MD to 10046'. RIH from 10046' MD to 10423' MD, verifying open hole sidetrack at 10132' MD. Continue drilling 8.5" Production Hole from 10423' MD to 11879' MD. Rig Service. 8/4/2023 8/5/2023 11,879 1,331.00 9.20 No accidents, incidents or spills. Drill 8.5" Production Hole from 11879' MD to TD at 13210' MD (4196' TVD). Circulate open hole annular volume 1 time. Turn off ViziTrack MWD tool while circulating. Backream out of hole from 13210' MD to 12700’ MD. Rig Service. 8/5/2023 8/6/2023 13,210 0.00 9.20 No accidents, incidents or spills. Backream out of hole from 12700' MD to 11128' MD. At 11743' MD, encountered spike in torque, circulating pressure & ECD. Work pipe, pick up & down several times to ensure hole is clean. Encountered packoff at 11357' MD, wash down to reduce pressures. Encountered packoff at 11213' MD, reduce circulation rate & clean up wellbore. Encountered packoff at 11128' MD, reduce circulation rate to lower pressures. Continue to backream out of hole from 11128' MD to 10480' MD, while conducting MAD pass logging & following backream plan with entire trip 2-3 fpm to prevent packoffs. 8/6/2023 8/7/2023 13,210 0.00 9.35 No accidents, incidents or spills. Backream conducting MAD pass from 10,475' to 10,088' logging and following Backream plan with entire trip at 2-3 fpm to prevent packoffs. Slight packing off from 10,088' to 10,060'. Once past 10,060' parameters leveled off and trip was clean. Pull to 10,047'. Attempt to resume Backream ops, indications of packoff at 10,045'. Continue with working pipe up and down between 10,060' and 10,080'. Move down with string from 10,134' to 10,320' to work pipe. Work pipe at 10,265'. Implement plan forward of low pump rates, low rpm, varying pickup speed as hole conditions allow. 8/7/2023 8/8/2023 13,210 0.00 9.20 No accidents, incidents or spills. Pulling out of hole from 10,090' across sidetrack area with no real change. Move slow with pump at 1 bpm / 315 psi until BHA and bit are past 10,010'. Torque dropped down to 18-19k again at 9948'. Increase flow to 1.5 bpm / 2360 psi and pull at 180 fph once pressure stabilized at 9884'. Continue pulling at 180 fph from 9755' to 9400'. Pull from 9400' to 8625' at average of 150-180 fph. Pull from 8625' to 7860' at average of 180-200 fph. Pull from 7860' to 7845' at 200 fph. Slow pull rates and vary circulation rates to work string from 7710' to 7675' with erratic torque. Consistent pull from 7675' to 7240'. 8/8/2023 8/9/2023 13,210 0.00 9.25 No accidents, incidents or spills. Encountered pump pressure spike at 7205' MD to 7132' MD, reciprocated pipe to establish circulation on down stroke. Backream out of hole from 7132' MD to 6237' MD, backream speeds from 50-200 ft/hr. Circulate bottoms up 1 time, reciprocated pipe from 6252' MD to 6153' MD. Backream out of hole from 6237' MD to 5970' MD, performing CBL log on 9-5/8" Liner. Change out 5-7/8" Delta saver sub to 5" Delta saver sub. Continue Backream out of hole from 5970' MD to 4353' MD, performing CBL log on 9-5/8" Liner. Rig Service. 8/9/2023 8/10/2023 13,210 0.00 9.20 No accidents, incidents or spills. Backream out of hole from 4353' MD to 1500' MD, performing CBL log on 9-5/8" Liner. Circulate bottoms up at 1500' MD. POOH on elevators from 1501' MD to 455' MD. L/D 8.5" Drilling BHA. Clean & clear rig floor. Rig Service. R/U & M/U BOPE test equip, pull wear ring & set test plug. Test 13-3/8" BOPE with 4-1/2" & 5-7/8" test joints. -Witness to BOP Test was waived by AOGCC Rep Guy Cook at 1000 hrs on 08/09/2023. 8/10/2023 8/11/2023 13,210 0.00 9.70 No accidents, incidents or spills. Finish testing BOPE. P/U & RIH with BHA #5 from surface to 5876' MD. Change out saver sub. RIH from 5876' MD to 6421' MD. Encountered tight hole at 6421' MD, establish circulation & attempt to backream through. Backream from 6377' MD to 6200' MD at reduced rate. Circulate bottoms up at 6200' MD. Attempt to ream through shoe. Packed off at 6240' MD. Pull back in shoe & circulate bottoms up. Contact Santos office for plan forward. Circulate & weight up mud system from 9.2 ppg to 9.7 ppg. 8/11/2023 8/12/2023 13,210 0.00 9.75 No accidents, incidents or spills. Wash down from 6237' MD to 6440' MD. Stage up & circulate until parameters clean up at 6824' MD. Wash down from 6824' MD to 8528' MD. Stage up & circulate until parameters clean up at 8528' MD. Continue to wash down from 8528' MD to 10922' MD. Circulate open hole & liner volume at 10922' MD. Rig Service. Well Name NDBi-043 Wellbore Name Sidetrack 1 PTD # 223-052 Start Drill Date 8/2/2023 End Drill Date 8/14/2023 Page 1 of 2 Well Name NDBi-043 Wellbore Name Sidetrack 1 PTD # 223-052 Start Drill Date 8/2/2023 End Drill Date 8/14/2023 p,, Conduct open hole sidetrack, begin trough from 10,132' MD TD at 13210'MD performing CBL log on 9-5/8" Liner. Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 8/12/2023 8/13/2023 13,210 0.00 10.00 No accidents, incidents or spills. Circulate annular volume at 10,922' MD. Pump ball down to open Well Commander. Circulate at 10,922' MD. Close Well Commander. Wash down from 10,922' MD to 13,210' MD. Stage up pumps & displace 9.7 ppg MOBM with 10.0 ppg MOBM. Pump ball down to open Well Commander. Circulate 3 bottoms up at 13,210' MD. Close Well Commander. Monitor well for 10 minutes: Static. Backream out of hole from 13,210’ MD to 10,353’ MD. Rig Service. 8/13/2023 8/14/2023 13,210 0.00 10.00 No accidents, incidents or spills. Backream out of hole from 10353’ MD to 6140’ MD. Circulate bottoms up 2 times at 6140' MD. POOH from 6140' MD to BHA. L/D 8.5" Cleanout BHA. Clean & clear rig floor. Rig Service. Slip & cut drill line. Mobilize 4.5" casing handling tools to rig floor. Page 2 of 2 Missing liner installation and tubing running. send note to oilsearch. -bjm Frac Ops Summary Report - AOGCC Fracture Treatment, 8/25/2023 00:00 Primary Job Type Fracture Treatment Start Date End Date Summary 8/25/2023 8/26/2023 Continue heating Kcl in frac tans to 100°F. Performed a dry run of the ball launching operations prior to Frac with crews. 8/26/2023 8/27/2023 Pump frac stages 1-4: Frac stage 1: 1406bbls slurry (YF122ST fluid), 203,977lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,193bbls clean fluid at 40bpm as per design Frac stage 2: 1,607bbls slurry (YF122ST fluid), 252,380lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,345bbls clean fluid at 40bpm as per design Frac stage 3: 1,394bbls slurry (YF122ST fluid), 206,198lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10, 12ppa), 1,180bbls clean fluid at 40bpm as per design Frac stage 4: 1,542bbls slurry (YF122ST fluid), 213,168lbs 16/20 carbolite (1, 2, 4, 6, 8, 10, 12ppa)(170,000lbs in formation), Blender issues cut final stage early, 1320bbls clean fluid at 40bpm; screened out with 10ppa on formation with 63% of planned proppant placed 8/27/2023 8/28/2023 Nipple down Launch tree and R/U CT for Screen out clean out Job prep for stages, 5-7. Loading the Sand Chiefs. Total proppant offloaded today way approximately 607k lbs of 16/20 Carbolite. Loaded and mixed Kcl into frac tanks, began heating tanks to 100° F. 8/28/2023 8/29/2023 RIH with 2" Coil to clean out well and R/D CTU. Transfer the last of the 20% KCL into the Frac Tanks. Hooked up water transfer lines and start filling tanks. Mixed up a 200 bbl 25ppt gel pill in the PCM and loaded onto a vac truck for the coiled tubing cleanout. Meet with Environmental to discuss disposal plan for vac trucks after our next pump day. Finished loaded sand chiefs with 907,410 lbs of 16/20 Carbolite. All Frac tanks have been filled. Waiting on LRS to start heating tanks, they were having mechanical issues with their unit. 8/29/2023 8/30/2023 Spot acid on frac ball to dissolve. Unable to get through collet with pulling tool. Cleanout proppant below frac sleeve collet with 2" slim BHA. LRS have been heating tanks all day and were on tank #8 at 6pm. Expected to be done heating by mid-day tomorrow. Lab testing on water samples is currently in progress. Should have results by tomorrow. 8/30/2023 8/31/2023 Attempt to pull frac collet with stage completion pulling tool, but unable to pass through collet. POOH and MU Baker 3.5" GS slick catch hydraulic release spear. Latch collet, but unable to pull above 6134' due to sand. Release collet at 6800' and POOH. RIH with 2.65" JSN BHA and cleanout from 6750' to surface. MU Baker hyraulic release spear and latch collet and pull to surface. Finished heating the remaining frac tanks. All tanks are now heated and lab tests are ongoing. Received changeovers from Deadhorse today to rig up two 3" standpipes for the next Frac. Mixed up another 100 bbls of 25ppt gel for the Coiled Tubing operation. 8/31/2023 9/1/2023 Laydown Baker BHA with Frac Collet. MU 2" slim BHA with 2" Jet Swirl Nozzle. Set 2 additional upright tanks into tank farm. Load supply tanks with slick 3% KCl. Haul off fluid returns to G&I. Preiminary lab tests have all been completed. Just waiting on feedback from Engineers to see if we will make any changes. Final tank straps have been taken on the Frac Tanks and we have confirmed the total volume of 3% KCL with contingency. 9/1/2023 9/2/2023 Load supply tanks with slick 3% KCl (w/ safelube). Haul off fluid returns to G&I. RIH with 2" slim BHA with 2" JSN. Start cleaning wellbore at 7500', taking 500' bites and short trips to ~ 5,000'. Cleanout to 10,454' ctmd, unable to get deeper. Make several attempts to RIH and get deeper with coil, but coil continues to stack out. Checked temperatures on Frac Tanks. All tanks are still around 100 degF. 9/2/2023 9/3/2023 POOH with coil cleanout nozzle. Cut 30' of coil and MU Baker cleanout BHA with Tempress and 2.30" Jet Swirl Nozzle. Re-load tank farm with 3% slick KCl w/ safelube. Haul return fluid from tank farm to G&I. Had an After Action Review meeting for Stages 1-4 with all parties involved. Discussed the previous job and areas where we feel we could improve. Assigned action items to make some improvements. Had a discussion with LRS how we can launch the balls on the next job, possibly using the SLB transport for diesel supply. Added more Biocide to the Frac tanks. Page 1 of 3 Frac Ops Summary Report - AOGCC Start Date End Date Summary 9/3/2023 9/4/2023 Perform Weekly BOP test (Witness waived by AOGCC). RIH with Baker Tempress BHA and 2.30" JSN. Cleanout from 10,454' to 11,457' ctmd with gel sweeps and 3% slick KCl w/ safelube. RIH with Stage Completions 3.5" knock-out tool and push collet #14 into frac sleeve #5 at 10,796' ctmd and shift open. POOH and laydown toolstring. ***Metal piece of Baker disconnect housing broke off and is lost downhole. Size is ~ 1.5" x 0.75". 9/4/2023 9/5/2023 Rigged up Frac Equipment to pump Frac Stages 5-7. Pressure tested surface equipment to 9,200 psi. Achieved successful pressure test and held pre-job safety meeting with everyone involved. Loaded ball for stage 5 and launched it with LRS pump, waited 10 minutes to allow the ball to fall in vertical section. Began pumping 25ppt linear gel at a rate of 4 bpm to seat the ball. Formation began to pressure up and had to shut down pumps. Ball seated and attempted to pump into stage 5 again with no success. Surged the well and tried pumping at a higher rate. Well began to take fluid and ramped up to 40 bpm design rate. Pumped 275 bbls of 25ppt X-Linked gel and displaced with 180 bbls of linear gel for DataFrac. Shut down to monitor pressures. Finished analyzing data and started pumping Stage 5. Pumped pad and 1-3-5-7-9-10 ppa proppant steps. Cut prop and went to flush just as 10ppa slurry was hitting formation. Pressure immediately spiked and popoff valve released at 8,300psi just as clean fluid was about to reach the wellhead. Total volume of proppant left in wellbore is approx. 45,000 lbs. Shut-in well and begin surface clean up. RD frac fleet and get ready for 2” CT cleanout. 9/5/2023 9/6/2023 MIRU Coiled tubing equipment. NU Coil BOP's and RU hardline to choke skid. RIH and cleanout to 3500' ctmd by pumping down coil, taking returns up tubing x coil annulus. Getting heavy proppant returns. POOH and MU reverse out BHA. RIH and cleanout reversing at ~ 9 ft/min. Cleanout to 4300'. Continue to cleanout using 2% KCl water from frac tanks. 9/6/2023 9/7/2023 Coiled tubing reverse cleanout to 10,900' ctmd using 2% KCl frac fluid with gel sweeps followed with 3% slick KCl with safelube. POOH and laydown BHA. MU and RIH with Baker Tempress BHA with Stage Completion Knock out tool. Collet latched into profile, but unable to shift frac sleeve #6 open. POOH and laydown BHA. RIH with Tempress and 2.0" JSN to cleanout. 9/7/2023 9/8/2023 RIH with Baker Tempress BHA and JSN to 12,439' ctmd. Jet with 3% slick KCl with safelube, no indication of sand at surface. POOH and get overpulls with coil at frac sleeve #6 & 11 and also at X nipples at 6,008' and 5,938'. Injectivity test at surface with 1.5 bpm and 350 psi. MU and RIH with Tempress BHA and 3.5" stage completions knock-out sub. Tag collet #13 and shift frac sleeve #6 open. POOH and have multiple overpulls from 7900' - 6000', online with pump taking returns to get through tight spots. POOH to surface. RDMO. 9/8/2023 9/9/2023 Add concentrate KCL to water in tanks and heat water tanks. SLB frac rigged up iron to wellhead, mixed chemicals, tested heated water tanks and rigged in 3 frac pumps. 9/9/2023 9/10/2023 Recordable spill of frac fluid – blender overflowed slinger and containment while trying to flush out sanded off slingers (due to screenout). Finish RU of frac equipment and chemical/water testing. Pump frac stages 6-9: Frac stage 6: 1,692bbls slurry, 186,252lbs 16/20 carboprop (1, 2, 3, 4, 5, 6, 7, 8ppa), 1,498bbs clean fluid at 40bpm as per design Frac stage 7: 1,349bbls slurry, 173,834lbs 16/20 carboprop (1, 3, 5, 7, 9, 10ppa), 1,167bbs clean fluid at 40bpm; reduced 9 and 10ppa stages and pumped 86% planned proppant Frac stage 8: 1,306bbls slurry, 193,107lbs 16/20 carboprop (1, 3, 5, 7, 9, 10ppa), 1,105bbs clean fluid at 35bpm; extended 3 and 7ppa stages and pumped 105% planned proppant Frac stage 9: 568bbls slurry, 23,188lbs 16/20 carboprop (1, 2, 3ppa)(10,000lbs in formation), 544bbs clean fluid at 30bpm; screened out 3ppa stage with 6% of planned proppant placed RD frac treating iron and collet launch tree from wellhead to prep for coiled tubing cleanout. Total Load to Recover (TLTR) stage 6-9 - 4314bbls TLTR stage 1-5 - 7827bbls TLTR for entire well - 12141bbls Page 2 of 3 Frac Ops Summary Report - AOGCC Start Date End Date Summary 9/10/2023 9/11/2023 RU coiled tubing. Perform BOP test (Witness waived by Adam Earl with AOGCC 9/9/23 at 8:10PM via email). RIH with cleanout assembly. Circulate down coil at 2bpm while RIH to 4000'. Reverse circulate at 2.5bpm while RIH. Trace of sand at 5000'. Pump gel pill at 6280' with return to surface at 6980'. RIH to 7654' and then circulate clean. POOH to 6900'. Swap to pumping down coil at 2bpm while RIH to 8050' (tag on stage 9 frac sleeve). POOH to surface while continue to pump down coil. Injection test at surface - 1bpm at 3000psi. Close in well and swap over to knock out sub BHA to shift frac sleeves. Pull test connector to 30k#. Open well and drop collet for stage 10 frac sleeve. RIH and land collet in frac sleeve 10 at 7440'. Pressure up on backside of coil to 2300psi to shift sleeve open with pressure breaking down to 1400psi at 1bpm. POOH to drop collet for stage 11 frac sleeve. 9/11/2023 9/12/2023 RIH with knock out sub BHA 6200'. Circulate down coil and RIH to 6956' to tag on stage 11 frac sleeve. Pressure up on annulus to 3000psi with no shift. Pressure up to 3800psi and gained weight when shifted. Broke over to 2800psi at 1bpm. POOH and close in well. RIH with cleanout BHA to 8040' (Stage 9 frac sleeve) and tag up. Several attempts to wash through with no success. Call out acid from SLB Deadhorse and wait on bottom. Have safety meeting with crew when acid arrived. Pump acid down coil to end of tubing. Stack 7k# on BHA and jet with acid. Immediate gain of weight and able to continue to RIH. RIH through stage 8 frac sleeve with no tag but stacked out on stage 7 frac sleeve at 9105'. Several attempts to pump/soak acid and tagging up before passing through stage 7 frac sleeve. RIH to 9635' and tagged on stage 6 frac sleeve. Circulate acid out of annulus while pumping remaining 10bbls acid down the tubing. Stack weight and circulate acid on stage 6 frac sleeve. Pass through and then circulate remaining acid to annulus. Continue to RIH to 10650' where friction stopped BHA. Pull up to 10000' and circulate acid to surface from annulus. 9/12/2023 9/12/2023 Continued to RIH with cleanout assembly to 10731'. Circulate gel sweep around and POOH. Hand well over to interventions for wellhead swap to production tree in preparation for flowback. Final frac report. Page 3 of 3 Missing liner installation and tubing running. The remaining daily reports are attached to this 10-407. -bjm Flowback Ops Summary Report - AOGCC Testing, 7/26/2023 00:00 Primary Job Type Testing Start Date End Date Summary 7/26/2023 7/27/2023 Expro personnel & equipment travel to location NDB. We identified where they will be, Expro started installing 10x10 timbers for berm area. They were able to complete the north wall of the berm area. 7/27/2023 7/28/2023 Expro continue to build berm, spotted the separator, line heater, SKO & gas scrubber. 7/28/2023 7/29/2023 Expro started running interconnecting pipe in the bermed area. 7/29/2023 7/30/2023 Expro continue running interconnecting pipe in the bermed area. 7/30/2023 7/31/2023 Expro continue running interconnecting pipe in the bermed area, plus outfitting datta headers, etc. 7/31/2023 8/1/2023 Expro continue running interconnecting pipe in the bermed area, plus outfitting datta headers, etc. 8/1/2023 8/2/2023 Expro continue to inspect equipment, ESD system, flare stack, etc 8/2/2023 8/3/2023 Expro continue to inspect equipment, ESD system, flare stack, etc 8/3/2023 8/4/2023 Expro continue to inspect equipment, ESD system, flare stack, etc 8/4/2023 8/5/2023 Expro spotting tanks in tank farm 8/5/2023 8/6/2023 Expro continued rigging up hoses and fittings in tanks farm. 8/6/2023 8/7/2023 Expro continued rigging up hoses and fittings in tanks farm. 8/7/2023 8/8/2023 Expro Departed location 8/8/2023 8/9/2023 Red Book Training and QA Review 8/9/2023 8/10/2023 Review P&ID ad PRV Certs 8/10/2023 8/11/2023 Review hose data package 8/11/2023 8/12/2023 Review hotwork and classified areas as per the Ash Handbook. 8/12/2023 8/13/2023 Drive to Deadhorse to locate chemicals. 8/13/2023 8/14/2023 Verify tanks at Cama'i pad. Review Wellview. 8/14/2023 8/15/2023 WellView Training with Rachel Davis. Expro arriving on location. 9/15/2023 9/16/2023 Open NDBi-043 well to Expro Flowback Kit and begin cleanout with N2 Assist. 9/16/2023 9/17/2023 Continued flowing well. Shut down N2 Injection coil tubing began POOH. 9/17/2023 9/18/2023 Continue flowing well. Opening choke for drawdown. 9/18/2023 9/19/2023 Continue flowing back Well NDBi-043. Begin reducing choke. 9/19/2023 9/20/2023 Began reducing flow rate as per Subsurface instructions. 9/20/2023 9/21/2023 Shut in NDBi-043 and began monitoring BHP and WHP. 9/21/2023 9/22/2023 Expro begins rigging down Flowback spread. Monitoring downhole data. 9/22/2023 9/23/2023 Continue Monitoring downhole data. Expro Rigged off of Wellhead. Page 1 of 2 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 9/23/2023 9/24/2023 Expro preparing equipment to stage at NDB-024. 9/24/2023 9/25/2023 Expro preparing equipment to stage at NDB-024. 9/25/2023 9/26/2023 Expro moved containment and equipment to NDB-024 while monitoring BHP. 9/26/2023 9/27/2023 Expro spotted Equipment in new Flowback area. 9/27/2023 9/28/2023 Expro rig up containment for new tempary tank farm. 9/28/2023 9/29/2023 Spot tanks in temporary tank farm. 9/29/2023 9/30/2023 Continue to monitor down hole pressures and temperatures. 9/30/2023 10/1/2023 Continue to monitor down hole pressures and temperatures. 10:30 Shut down, and rig out down hole logger, end build up recording. Page 2 of 2 FracCAT Treatment Report Well : NDBi-43 Field : Pikka Formation : Nanushuk Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : 08-26-2023 Prepared by Name : Alena Lutskaia Division : SLB Phone : 1 630 780 0058 Pressure (All Zones) Initial Wellhead Pressure (psi)310 Initial BHP at Gauge (psi)2218 Final Surface ISIP (psi)Screenout Final ISIP at Gauge (psi)Screenout Surface Shut in Pressure(psi)693 BH Shut in Pressure (psi)2,469 Maximum Treating Pressure (psi)9,256 BH Gauge at 5,993 MD, 4,275TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl)6,595.6 Total YF122ST Past Wellhead (bbl) 5,245.5 Total WF122 Past Wellhead (bbl)437.6 Total Freeze Protect Past Wellhead (bbl)0 Total Proppant Pumped (lb)875,724 Total Proppant in Formation (lb)865,801 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal)246 244 M275 (lb)102 102 J450 (gal)120 119 J753 (gal)12.0 11.9 J580 (lb)6200 6052 J475 (lb)1320 1310 J532 (gal)545 541 J134 (lb)14 0 J511 (lb)550 547 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 in put 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-43 Formation: Nanushuk District: Prudhoe Other Country: United States SUMMARY The Fracture treatment for the NDBi-43 well, Stages 1-4, at Pikka was performed on August 26, 2023. The treatment consisted of DataFRAC and 4 stages where Ball/Collet was dropped during each stage to prepare the next port for a fracturing treatment. A unique collet with the ball were dropped during the final stage (Stage 4) to prepare the well for stages 5 -7 to be treated. A screen out (SO) occurred during the flush of Stage 4. A total of 890,440 lb of proppant (as measured by load tickets) was pumped in 6,596 bbl of slurry. The stimulation was a 4 stages Ball/Collet and sleeve frac where each consisted of a PAD, 1-10 PPA steps on stages 1-2, 1-12 PPA steps on stage 3 and 1-10 PPA steps on stage 4. The flush for stages 1-4 was the PAD fluid for the next stage. Each stage treated very similar with rate starting at 40bpm and lowered to 17 bpm before Ball/Collet are seated. The treating pressure during the stages was below 5500 psi. The first pump trip was to be set at 8,400 psi and the GORV was set to 8,800 psi. MMaterials AActual DDesign Slurry Volume - All Volumes (bbl)6,595.6 6,924 Clean Fluid - All Volumes (bbl)5,683.1 5,949 Proppant, lb.875,724 926,951 15:32:38 15:49:18 16:05:58 16:22:38 16:39:18 16:55:58 17:12:38 17:29:18 17:45:58 18:02:38 18:19:18 18:35:58 18:52:38 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 08-26-2023 Stage 1 Stage 2 Stage 3 Stage 4 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States DF Stage DF included a pump check that was placed in the schedule to test the equipment and ensure the pumps were job ready, DataFRAC Pad and Displace DF. When the pump check step was started, the toe was activated at 7450 psi, in the end of pumping there was a hard shutdown at the end of the pump check with an ISIP of 815 psi and recording of pressure decline. After DataFRAC there was a hard shutdown at the end of the pump check with an ISIP of 1,940 psi and recording of pressure decline. A summary of the stage and its measured pump schedule is below: SSummaryy ooff Stagee DataFRACC (Toee activation,, pumpp checkk andd DataFRAC) Total Proppant Pumped (lb)0 Max pumping Rate (bpm)40.1 Total Proppant in Formation (lb)0 Average Pumping Rate (bpm)36.8 Total Slurry Pumped (bbl)646.2 Maximum Treating Pressure (psi)3030 (DataFRAC) YF122ST Pumped (bbl)250.0 Average Treating Pressure (psi)2789 (DataFRAC) WF122 Pumped (bbl)396.2 Average Water Temperature (F)78.1 13:18:38 13:35:18 13:51:58 14:08:38 14:25:18 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 Data Frac 08-26-2023 Toe activation DataFRAC Pump Check Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States DDataFRACC -- AAss Measuredd Pumpp Schedule SStepp ##SStepp Name SSlurryy VVolume (bbl) SSlurryy RRate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 Pump Check 201.2 33.4 9.1 WF122 8452 WF122 0.0 0.0 0 2 DF 250.0 37.1 7.8 YF122ST 10500 YF122ST 0.0 0.0 0 3 DF Displace 195.0 39.8 5.0 WF122 8190 WF122 0.0 0.0 0 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 Pump Check 33.4 40.1 4149 6985 298 2 DF 37.1 40.0 2789 3015 256 3 DF Displace 39.8 40.0 2934 3030 578 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 1 Stage 1 consisted of 13 steps: Line out XL, Drop Stage #1 Ball/Collet, PAD, Slow for Seat, Resume PAD, 6 proppant steps (1-10PPA), Clear Surface Lines and Spacer. Pumping was started and once the target rate 40 bbl/min was reached, then Ball/Collet #1 was dropped for the stage #1. There was slight indication of the Ball/Collet hitting the sleeve. Overall, the stage went well, and the treating pressure gradually increased from 3,900 to 5,480 psi. The slurry rate had some fluctuation caused by debris, stage was pumped with starting rate of 40 bpm and reducing to about 17 bpm before collet and ball hit the sleeve. A total of 1,405.7 bbl of slurry was pumped during this stage with 203,977 lb of proppant. Flush at the wellhead was called at 2023 bbl total slurry and after that a spacer was pumped, Ball/Collet # 2 was launched to open Port # 2 at a total slurry volume of 2,065 bbl. There was an indication of the Ball/Collet # 2 hitting at 2,263.2bbl. A summary of the stage and its measured pump schedule is below: SSummaryy off PPressuress Whenn Ball//Collet#1 SSeats Ball/Collet#1 Before Ball/Collet Hit (psi)When Ball/Collet Hit (psi)After Ball/Collet Hit (psi) Wellhead Pressure 1,259 1,490 1,280 Bottomhole Pressure 2,973 3,201 3,014 SSummaryy ooff Stagee 1 Total Proppant Pumped (lb)203,977 Max pumping Rate (bpm)40.1 Total Proppant in Formation (lb)203,977 Average Pumping Rate (bpm)38.4 Total Slurry Pumped (bbl)1405.6 Maximum Treating Pressure (psi)4804 YF122ST Pumped (bbl)1193.2 Average Treating Pressure (psi)2988 WF122 Pumped (bbl)0 Average Water Temperature (F)92.7 15:39:01 15:51:31 16:04:01 16:16:31 16:29:01 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 STG 1 08-26-2023 Drop Rate for Ball/Collet#1 Ball/Collet#1 Hit Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 11 -- AAss Measuredd Pumpp Schedule SStepp ## Stepp Name Slurryy Volume (bbl) Slurryy Rate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 Line out XL 42.1 31.8 1.5 YF122ST 1769 0.0 0.0 0 2 Drop Collet1 3.0 40.0 0.1 YF122ST 126 0.0 0.0 0 3 PAD st1 155.0 40.0 3.9 YF122ST 6510 0.0 0.0 0 4 Slow for Sea 50.0 22.5 2.6 YF122ST 2100 0.0 0.0 0 5 Resume Pad 69.1 23.8 3.1 YF122ST 2904 0.0 0.0 0 6 1.0 PPA 140.0 40.0 3.5 YF122ST 5651 CarboLite 16/20 1.0 0.9 5211 7 3.0 PPA 149.3 40.1 3.7 YF122ST 5566 CarboLite 16/20 3.1 2.9 16077 8 5.0 PPA 150.0 40.0 3.8 YF122ST 5190 CarboLite 16/20 5.1 4.9 25308 9 7.0 PPA 209.0 40.0 5.2 YF122ST 6736 CarboLite 16/20 7.1 6.9 46645 10 9.0 PPA 190.0 40.0 4.7 YF122ST 5740 CarboLite 16/20 9.1 8.9 51160 11 10.0 PPA 219.1 40.0 5.5 YF122ST 6604 CarboLite 16/20 10.1 9.1 59542 12 Spacer 26.0 40.0 0.7 YF122ST 1091 CarboLite 16/20 0.0 0.0 31 13 Drop Collet2 3.0 40.0 0.1 YF122ST 126 CarboLite 16/20 0.0 0.0 3 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 Line out XL 31.8 40.0 2849 3320 878 2 Drop Collet1 40.0 40.0 3305 3306 3303 3 PAD st1 40.0 40.0 3222 3430 3063 4 Slow for Sea 22.5 40.0 1618 3066 1267 5 Resume Pad 23.8 39.6 1735 2799 1268 6 1.0 PPA 40.0 40.1 2662 2862 2519 7 3.0 PPA 40.1 40.1 2352 2520 2204 8 5.0 PPA 40.0 40.1 2344 2501 2230 9 7.0 PPA 40.0 40.1 2858 3178 2465 10 9.0 PPA 40.0 40.1 3588 3958 3169 11 10.0 PPA 40.0 40.1 4058 4270 3870 12 Spacer 40.0 40.0 4323 4417 4251 13 Drop Collet2 40.0 40.0 4406 4804 4389 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 2 Stage 2 consisted of 12 steps: Drop Stage 2 Ball/Collet, Slow for seat, PAD, 6 proppant steps (1-10PPA), clear and spacer. Overall, the stage went well, and the treating pressure gradually increased from 3,670 to 4,680 psi. The slurry rate had some fluctuation, but generally remained about 40bpm until the rate was reduced to about 17 bpm before collet and ball hit the sleeve. A total of 1,607 bbl of slurry was pumped during this stage with 252,380 lb of proppant. Flush at the wellhead was called at 3,632 bbl total slurry and after that a spacer was pumped, Ball/Collet # 3 was launched to open Port3 at a total slurry volume of 3,674 bbl. There was an indication of the Ball/Collet # 3 hitting at 3,856 bbl. A summary of the stage and its measured pump schedule is below: SSummaryy off PPressuress Whenn Ball//Collet#2 SSeats Ball/Collet#2 Before Ball/Collet Hit (psi)When Ball/Collet Hit (psi)After Ball/Collet Hit (psi) Wellhead Pressure 1,859 4,334 1,973 Bottomhole Pressure 3,298 5,352 3,394 SSummaryy ooff Stagee 22 Total Proppant Pumped (lb)252,380 Max pumping Rate (bpm)41.7 Total Proppant in Formation (lb)252,380 Average Pumping Rate (bpm)3280 Total Slurry Pumped (bbl)1607.4 Maximum Treating Pressure (psi)4735 YF122ST Pumped (bbl)1344.5 Average Treating Pressure (psi)3280 WF122 Pumped (bbl)0 Average Water Temperature (F)93.6 16:27:56 16:40:26 16:52:56 17:05:26 17:17:56 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 STG 2 08-26-2023 Ball/Collet#2 Hit Drop Rate for Ball/Collet#2 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 22 -- AAss Measuredd Pumpp Schedule SStepp ## Stepp Name Slurryy Volume (bbl) Slurryy Rate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 PAD st2 157.0 40.0 3.9 YF122ST 6593 CarboLite 16/20 0.0 0.0 7 2 Slow for Sea 50.0 17.8 2.9 YF122ST 2100 0.0 0.0 0 3 Resume PAD 68.0 30.0 2.5 YF122ST 2856 0.0 0.0 0 4 1.0 PPA 150.0 39.3 3.8 YF122ST 6050 CarboLite 16/20 1.1 0.9 5683 5 3.0 PPA 200.0 39.8 5.0 YF122ST 7448 CarboLite 16/20 3.1 2.9 21708 6 5.0 PPA 240.0 39.7 6.0 YF122ST 8292 CarboLite 16/20 5.1 4.9 40819 7 7.0 PPA 214.2 39.5 5.4 YF122ST 6910 CarboLite 16/20 7.1 6.9 47672 8 9.0 PPA 215.0 38.9 5.5 YF122ST 6493 CarboLite 16/20 9.2 8.9 57946 9 10.0 PPA 285.2 38.8 7.4 YF122ST 8551 CarboLite 16/20 10.5 9.2 78501 10 Spacer 25.0 41.5 0.6 YF122ST 1048 CarboLite 16/20 0.1 0.0 39 11 Drop Collet3 3.0 41.7 0.1 YF122ST 126 CarboLite 16/20 0.0 0.0 4 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 PAD st2 40.0 40.1 3901 4735 1692 2 Slow for Sea 17.8 35.5 1769 1873 1316 3 Resume PAD 30.0 39.2 2420 2770 1859 4 1.0 PPA 39.3 39.9 2510 2607 2369 5 3.0 PPA 39.8 40.4 2360 2438 2258 6 5.0 PPA 39.7 40.0 2547 2838 2406 7 7.0 PPA 39.5 39.8 3191 3713 2806 8 9.0 PPA 38.9 39.6 4050 4419 3676 9 10.0 PPA 38.8 40.8 4428 4695 4326 10 Spacer 41.5 41.7 4672 4695 4652 11 Drop Collet3 41.7 41.7 4647 4653 4644 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 3 Stage 3 consisted of 13 steps: Drop Stage 3 Ball/Collet, Slow for Seat, a PAD, 7 proppant steps (1-12PPA), and spacer. Overall, the stage went well, and the treating pressure gradually increased from 3,230 to 4,820 psi. The slurry rate was consistent with starting rate of 40 bpm and reducing to about 17 bpm before collet and ball hit the sleeve. A total of 1,394 bbl of slurry was pumped during this stage with 206,198 lb of proppant. Flush at the wellhead was called at 5,027 bbl total slurry and Ball/Collet # 4 was launched to open Port 4 at a total slurry volume of 5,068 bbl. There was an indication of the Ball/Collet # 4 hitting at 5,242 bbl. A summary of the stage and its measured pump schedule is below: SSummaryy off Pressuress Whenn Ball//Collet#33 SSeats Ball/Collet#3 Before Ball/Collet Hit (psi)When Ball/Collet Hit (psi)After Ball/Collet Hit (psi) Wellhead Pressure 1,803 4,518 2,955 Bottomhole Pressure 3,285 5,785 4,435 SSummaryy ooff Stagee 33 Total Proppant Pumped (lb)206198 Max pumping Rate (bpm)41.8 Total Proppant in Formation (lb)206198 Average Pumping Rate (bpm)38.8 Total Slurry Pumped (bbl)1394.3 Maximum Treating Pressure (psi)4823 YF122ST Pumped (bbl)1179.4 Average Treating Pressure (psi)3440 WF122 Pumped (bbl)0 Average Water Temperature (F)88 17:10:29 17:22:59 17:35:29 17:47:59 18:00:29 Time - hh:mm:ss 1000 2000 3000 4000 5000 6000 7000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 STG 3 08-26-2023 Drop Rate for Ball/Collet#3 Ball/Collet#3 Hit Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 33 -- AAss Measuredd Pumpp Schedule SStepp ## Stepp Name Slurryy Volume (bbl) Slurryy Rate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 PAD st3 150.0 40.3 3.7 YF122ST 6297 CarboLite 16/20 0.0 0.0 64 2 Slow for Sea 50.0 20.6 2.7 YF122ST 2100 0.0 0.0 0 3 Resume PAD 30.0 20.3 1.5 YF122ST 1260 0.0 0.0 0 4 1.0 PPA 140.0 39.4 3.6 YF122ST 5652 CarboLite 16/20 1.0 0.9 5181 5 2.0 PPA 160.0 40.0 4.0 YF122ST 6191 CarboLite 16/20 2.1 1.9 12051 6 4.0 PPA 180.0 39.9 4.5 YF122ST 6457 CarboLite 16/20 4.1 3.9 25170 7 6.0 PPA 179.3 40.0 4.5 YF122ST 5983 CarboLite 16/20 6.2 5.9 35306 8 8.0 PPA 180.0 40.1 4.5 YF122ST 5618 CarboLite 16/20 8.1 7.9 44348 9 10.0 PPA 180.0 39.9 4.5 YF122ST 5276 CarboLite 16/20 10.1 9.9 52170 10 12.0 PPA 117.0 40.0 2.9 YF122ST 3525 CarboLite 16/20 12.2 9.1 31904 11 Spacer 25.0 38.5 0.7 YF122ST 1050 CarboLite 16/20 0.0 0.0 6 12 Drop Collet4 3.0 26.6 0.1 YF122ST 126 0.0 0.0 0 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 PAD st3 40.3 41.8 3834 4644 2702 2 Slow for Sea 20.6 40.3 1839 3785 1397 3 Resume PAD 20.3 31.0 3325 3768 2963 4 1.0 PPA 39.4 40.3 3368 3982 2978 5 2.0 PPA 40.0 40.2 2743 2988 2602 6 4.0 PPA 39.9 40.1 2624 2711 2576 7 6.0 PPA 40.0 40.3 2993 3346 2711 8 8.0 PPA 40.1 41.2 3775 4230 3347 9 10.0 PPA 39.9 40.4 4337 4587 4054 10 12.0 PPA 40.0 41.1 4675 4823 4553 11 Spacer 38.5 40.4 3933 4556 2421 12 Drop Collet4 26.6 27.0 2514 2611 2470 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 4 Stage 4 consisted of 13 steps: Drop Stage 4 Ball/Collet, Slow for seat, PAD, 7 proppant steps (1-10 PPA), and spacer. Overall, the stage went well, and the treating pressure gradually increased from 3,670 to 4,680 psi. The slurry rate was consistent with starting rate of 40 bpm and reducing to about 17 bpm before collet and ball hit the sleeve. The Deck side ram gate of the POD Blender was jammed which led to prop concentration drop from 10 PPA to 7 PPA. The attempt of fixing the POD gate was made but unsuccessfully, so the decision to cut proppant and go to flush was made by the client. During the flush there was a sudden pressure increasewhich ledto a screenout and actuated the popoff. The screenout occurred with about 70 bbl of slurry remaining in tubing; thus, the port area maintained 10 PPA. A total of 1,542 bbl of slurry was pumped during this stage with 213,168 lb of proppant (according to FracCAT totals). Flush at the wellhead was called at 6,476 bbl total slurry and Ball/Collet # 5 was launched to open Port 5 at a total slurry volume of 6,511 bbl. A summary of the stage and its measured pump schedule is below: Summaryy off Pressuress Whenn Ball//Collet#44 Seats Ball/Collet#4 Beforee Ball/Collett Hitt (psi) Whenn Ball/Collett Hitt (psi) Afterr Ball/Collett Hitt (psi) Wellhead Pressure 1,833 4,549 3,630 Bottomhole Pressure 3,314 5,673 3,684 Summaryy ooff Stagee 44 Total Proppant Pumped (lb)213170 Max pumping Rate (bpm)41.6 Total Proppant in Formation (lb)199085 Average Pumping Rate (bpm)37.9 Total Slurry Pumped (bbl)1542.1 Maximum Treating Pressure (psi)9256 YF122ST Pumped (bbl)1278.5 Average Treating Pressure (psi)3592 WF122 Pumped (bbl)41.4 Average Water Temperature (F)93.8 17:44:31 17:54:56 18:05:21 18:15:46 18:26:11 Time - hh:mm:ss 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 STG 4 08-26-2023 Ball/Collet#4 Hit Drop Rate for Ball/Collet#4 Screenout Slow Rate before launch the Ball/Collet POD gate ram jammed Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 44 -- AAss Measuredd Pumpp Schedule SStepp ## Stepp Name Slurryy Volume (bbl) Slurryy Rate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 PAD st4 142.0 36.6 4.0 YF122ST 5964 0.0 0.0 0 2 Slow for Sea 50.0 20.0 2.8 YF122ST 2100 0.0 0.0 0 3 Resume PAD 47.5 24.3 2.0 YF122ST 1995 0.0 0.0 0 4 1.0 PPA 100.0 38.8 2.6 YF122ST 4041 CarboLite 16/20 1.0 0.9 3604 5 2.0 PPA 150.0 40.1 3.7 YF122ST 5807 CarboLite 16/20 2.0 1.9 11250 6 4.0 PPA 220.0 40.1 5.5 YF122ST 7884 CarboLite 16/20 4.1 3.9 30933 7 6.0 PPA 240.0 40.1 6.0 YF122ST 8003 CarboLite 16/20 6.1 5.9 47414 8 8.0 PPA 239.0 39.8 6.0 YF122ST 7451 CarboLite 16/20 8.3 7.9 59060 9 10.0 PPA 220.0 39.6 5.6 YF122ST 6603 CarboLite 16/20 10.5 9.1 60242 10 12.0 PPA 14.2 40.3 0.4 YF122ST 573 CarboLite 16/20 6.6 1.2 667 11 Spacer 25.0 40.9 0.6 YF122ST 1050 -0.0 0.0 0 12 Drop Collet5 3.0 39.2 0.1 YF122ST 126 0.0 0.0 0 13 XL flush 50.0 33.5 1.5 YF122ST 2100 0.0 0.0 0 14 LG Flush 41.4 29.2 2.9 WF122 1738 0.0 0.0 0 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 PAD st4 36.6 40.6 3354 4166 2427 2 Slow for Sea 20.0 40.2 1959 4313 1585 3 Resume PAD 24.3 32.3 5004 5383 4338 4 1.0 PPA 38.8 40.3 4091 4629 3514 5 2.0 PPA 40.1 40.3 3033 3520 2704 6 4.0 PPA 40.1 40.4 2747 2899 2660 7 6.0 PPA 40.1 40.5 3277 3653 2886 8 8.0 PPA 39.8 40.5 3937 4335 3415 9 10.0 PPA 39.6 41.6 4373 4832 3947 10 12.0 PPA 40.3 40.9 4540 4554 4534 11 Spacer 40.9 41.5 4343 4558 3995 12 Drop Collet5 39.2 40.3 2898 3653 2351 13 XL flush 33.5 40.4 3424 3984 2351 14 LG Flush 29.2 40.3 5220 9256 2733 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States DDataFRAC:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 10:42:56 Pressure Test Lines LR 37 20 0.0 2.2 0.0 2 11:40:55 Tested Trips 1572 21 0.0 0.0 0.0 3 11:42:17 Mid Pressure Test 5130 21 0.0 0.0 0.0 4 12:05:29 HP Leak 102 20 0.0 10.9 0.0 5 12:05:43 Priming Pumps 102 21 0.0 10.9 0.0 6 12:12:20 Mid Pressure Test 5106 21 0.0 0.0 0.0 7 12:15:32 High Pressure test 9642 21 0.0 0.0 0.0 8 13:20:44 Open Well 278 3273 0.0 0.0 0.0 9 13:21:00 Start Pump Check Automatically 344 3270 0.0 0.0 0.0 10 13:21:00 Start Propped Frac Automatically 344 3270 0.0 0.0 0.0 11 13:21:00 Start DF1 Automatically 344 3270 0.0 0.0 0.0 12 13:21:09 Started Pumping 330 3274 0.0 0.0 0.0 13 13:30:23 Stage at Perfs: Pump Check 1919 3197 197.8 40.0 0.0 14 13:49:24 Started Pumping 263 3133 201.2 0.0 0.0 15 13:49:25 Start DF Automatically 262 3133 201.2 0.0 0.0 16 13:56:57 Stage at Perfs: DF 2969 3373 398.7 40.0 0.0 17 13:58:16 Start DF Displace Automatically 3021 3439 451.3 39.9 0.0 18 14:03:16 Stopped Pumping 1151 3433 646.2 0.0 0.0 19 15:43:07 Started Pumping 778 3320 646.2 1.7 0.0 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 1:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 15:43:09 Start Line out XL Automatically 878 3329 0.0 4.7 0.0 2 15:43:09 Start Propped Frac Automatically 878 3329 0.0 4.7 0.0 3 15:43:09 Start Stage 1 Automatically 878 3329 0.0 4.7 0.0 4 15:43:26 Stage at Perfs: DF Displace 1708 3340 2.7 13.9 0.0 5 15:44:40 Start Drop Collet1 Manually 3389 3371 42.1 40.0 0.0 6 15:44:45 Start PAD st1 Automatically 3305 3371 45.4 40.0 0.0 7 15:48:33 Stage at Perfs: Line out XL 3066 3514 197.4 40.0 0.0 8 15:48:38 Start Slow for Sea Automatically 3061 3518 200.8 40.0 0.0 9 15:50:33 Stage at Perfs: Drop Collet1 1285 3551 239.1 17.1 0.0 10 15:50:45 Stage at Perfs: PAD st1 1282 3557 242.5 17.1 0.0 11 15:51:12 Start Resume Pad Automatically 1340 3581 250.2 17.0 0.0 12 15:54:18 Start 1.0 PPA Manually 2825 3716 319.2 39.7 0.0 13 15:54:18 Started Pumping Prop 2825 3716 319.2 39.7 0.0 14 15:56:16 Stage at Perfs: Slow for Sea 2621 3581 398.0 40.1 1.0 15 15:57:29 Stage at Perfs: Resume Pad 2523 3332 446.7 40.1 1.0 16 15:57:48 Start 3.0 PPA Automatically 2525 3341 459.4 40.1 1.0 17 15:59:13 Stage at Perfs: 1.0 PPA 2375 3402 516.2 40.1 3.0 18 16:01:32 Start 5.0 PPA Automatically 2263 3503 609.0 40.0 3.0 19 16:02:43 Stage at Perfs: 3.0 PPA 2416 3538 656.2 40.1 5.0 20 16:05:17 Start 7.0 PPA Automatically 2497 3622 758.9 40.0 5.0 21 16:06:28 Stage at Perfs: 5.0 PPA 2591 3694 806.3 40.0 7.0 22 16:10:12 Stage at Perfs: 7.0 PPA 3125 3208 955.8 40.1 7.1 23 16:10:30 Start 9.0 PPA Automatically 3002 3226 967.8 40.0 6.9 24 16:15:15 Start 10.0 PPA Automatically 3870 3379 1157.9 40.0 9.0 25 16:15:25 Stage at Perfs: 9.0 PPA 3857 3389 1164.5 40.0 9.3 26 16:20:10 Stage at Perfs: 10.0 PPA 4141 3508 1354.7 40.1 9.9 27 16:20:43 Start Spacer Manually 4277 3507 1376.7 40.0 0.0 28 16:21:22 Start Drop Collet2 Manually 4389 3530 1402.7 40.1 0.0 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 2:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 16:21:27 Start PAD st2 Automatically 4577 3526 0.0 40.0 0.0 2 16:21:27 Start Propped Frac Automatically 4577 3526 0.0 40.0 0.0 3 16:21:27 Start Stage 2 Automatically 4577 3526 0.0 40.0 0.0 4 16:21:35 Stopped Pumping Prop 4608 3555 5.3 40.0 -0.0 5 16:25:23 Start Slow for Sea Automatically 1037 3121 156.8 25.0 0.0 6 16:26:01 Stage at Perfs: Spacer 1703 3147 167.8 17.0 0.0 7 16:27:32 Stage at Perfs: Drop Collet2 1834 3144 193.7 17.0 0.0 8 16:27:44 Stage at Perfs: PAD st2 1899 3151 197.1 17.0 0.0 9 16:28:18 Start Resume PAD Automatically 1828 3172 206.7 17.0 0.0 10 16:30:49 Start 1.0 PPA Automatically 2588 3212 275.1 39.2 0.0 11 16:30:52 Started Pumping Prop 2524 3233 277.0 39.2 0.0 12 16:32:38 Stage at Perfs: Slow for Sea 2496 3290 345.5 39.5 1.0 13 16:33:54 Stage at Perfs: Resume PAD 2548 3304 395.8 39.9 1.0 14 16:34:38 Start 3.0 PPA Automatically 2357 3353 424.9 39.8 1.0 15 16:35:37 Stage at Perfs: 1.0 PPA 2301 3387 463.9 39.6 3.0 16 16:39:23 Stage at Perfs: 3.0 PPA 2482 3475 614.0 40.0 3.0 17 16:39:40 Start 5.0 PPA Automatically 2443 3499 625.3 39.8 3.0 18 16:44:25 Stage at Perfs: 5.0 PPA 2702 3224 814.2 39.7 4.9 19 16:45:42 Start 7.0 PPA Automatically 2686 3215 865.1 39.5 5.1 20 16:50:29 Stage at Perfs: 7.0 PPA 3460 3238 1054.3 39.4 7.0 21 16:51:07 Start 9.0 PPA Automatically 3635 3230 1079.3 39.4 7.0 22 16:55:58 Stage at Perfs: 9.0 PPA 4419 3246 1268.1 38.8 9.1 23 16:56:38 Start 10.0 PPA Automatically 4348 3262 1294.0 38.9 9.0 24 17:01:31 Stage at Perfs: 10.0 PPA 4426 3175 1483.1 38.5 9.9 25 17:03:59 Start Spacer Manually 4717 3181 1579.1 41.1 0.0 26 17:04:36 Start Drop Collet3 Automatically 4659 3170 1604.7 41.7 0.0 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 3:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 17:04:40 Start PAD st3 Automatically 4633 3187 0.0 41.7 0.0 2 17:04:40 Start Propped Frac Automatically 4633 3187 0.0 41.7 0.0 3 17:04:40 Start Stage 3 Automatically 4633 3187 0.0 41.7 0.0 4 17:05:46 Stopped Pumping Prop 4496 3178 44.3 39.9 0.0 5 17:08:23 Start Slow for Sea Automatically 2008 3141 149.6 39.8 0.0 6 17:08:51 Stage at Perfs: Spacer 1599 3153 160.9 17.7 0.0 7 17:10:19 Stage at Perfs: Drop Collet3 1802 3164 186.3 17.1 0.0 8 17:10:29 Stage at Perfs: PAD st3 1814 3165 189.2 17.1 0.0 9 17:11:06 Start Resume PAD Automatically 3768 3274 199.7 17.0 0.0 10 17:12:36 Start 1.0 PPA Automatically 3543 3210 230.1 32.0 0.0 11 17:12:38 Started Pumping Prop 3591 3218 231.1 32.4 0.0 12 17:15:11 Stage at Perfs: Slow for Sea 3092 3179 331.2 40.2 1.0 13 17:16:09 Start 2.0 PPA Automatically 2963 3160 370.1 40.3 1.0 14 17:16:26 Stage at Perfs: Resume PAD 2921 3155 381.4 40.2 1.9 15 17:17:11 Stage at Perfs: 1.0 PPA 2843 3152 411.4 39.9 2.1 16 17:20:09 Start 4.0 PPA Automatically 2626 3407 530.1 40.0 2.0 17 17:20:42 Stage at Perfs: 2.0 PPA 2641 3404 552.0 39.6 4.0 18 17:24:39 Start 6.0 PPA Automatically 2727 3404 709.7 40.3 3.9 19 17:24:42 Stage at Perfs: 4.0 PPA 2708 3405 711.7 40.2 4.0 20 17:29:08 Start 8.0 PPA Automatically 3368 3424 889.0 40.1 6.0 21 17:29:12 Stage at Perfs: 6.0 PPA 3385 3423 891.7 40.0 6.0 22 17:33:37 Start 10.0 PPA Automatically 4051 3456 1068.9 40.0 8.1 23 17:33:40 Stage at Perfs: 8.0 PPA 4076 3458 1070.9 39.8 8.1 24 17:38:08 Start 12.0 PPA Automatically 4610 3498 1249.2 40.2 9.9 25 17:38:10 Stage at Perfs: 10.0 PPA 4643 3497 1250.5 40.2 9.9 26 17:41:03 Start Spacer Manually 4550 3519 1365.9 40.4 0.0 27 17:41:07 Stopped Pumping Prop 4543 3521 1368.5 40.4 0.1 28 17:41:45 Start Drop Collet4 Automatically 2569 3477 1391.3 26.4 0.0 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 4:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 17:41:51 Start PAD st4 Automatically 2839 3483 0.0 25.9 0.0 2 17:41:51 Start Propped Frac Automatically 2839 3483 0.0 25.9 0.0 3 17:41:51 Start Stage 4 Automatically 2839 3483 0.0 25.9 0.0 4 17:42:26 Launch Ball 2953 3489 15.1 25.6 0.0 5 17:42:34 Collet Away 2864 3488 18.5 25.4 0.0 6 17:43:13 Stage at Perfs: 12.0 PPA 4199 3520 36.9 36.1 0.0 7 17:45:51 Start Slow for Sea Automatically 1337 3480 142.6 38.6 0.0 8 17:46:20 Stage at Perfs: Spacer 1878 3488 153.5 17.9 0.0 9 17:47:49 Stage at Perfs: Drop Collet4 1873 3496 178.9 16.8 0.0 10 17:47:58 Stage at Perfs: PAD st4 1834 3497 181.4 16.9 0.0 11 17:48:36 Start Resume PAD Automatically 4488 3557 192.1 16.9 0.0 12 17:50:36 Start 1.0 PPA Manually 4623 3590 239.4 33.6 0.0 13 17:50:36 Started Pumping Prop 4623 3590 239.4 33.6 0.0 14 17:52:36 Stage at Perfs: Slow for Sea 3671 3577 316.6 40.0 1.0 15 17:53:11 Start 2.0 PPA Automatically 3449 3583 339.9 40.0 1.0 16 17:53:50 Stage at Perfs: Resume PAD 3246 3577 365.9 39.9 2.0 17 17:55:02 Stage at Perfs: 1.0 PPA 2989 3575 413.9 40.0 2.0 18 17:56:55 Start 4.0 PPA Automatically 2694 3578 489.5 40.1 2.0 19 17:57:32 Stage at Perfs: 2.0 PPA 2697 3585 514.3 40.3 4.0 20 18:01:16 Stage at Perfs: 4.0 PPA 2813 3588 663.8 40.0 4.0 21 18:02:25 Start 6.0 PPA Automatically 2898 3603 709.8 39.9 3.9 22 18:06:46 Stage at Perfs: 6.0 PPA 3489 3638 884.0 40.0 6.0 23 18:08:24 Start 8.0 PPA Automatically 3627 3648 949.8 40.5 6.0 24 18:12:48 Stage at Perfs: 8.0 PPA 4234 3684 1123.8 40.3 8.1 25 18:14:25 Start 10.0 PPA Automatically 4327 3694 1188.9 40.4 8.0 26 18:18:52 Stage at Perfs: 10.0 PPA 4782 3733 1363.4 41.3 7.0 27 18:19:58 Start 12.0 PPA Automatically 4517 3740 1408.4 39.6 6.3 28 18:20:19 Start Spacer Manually 4596 3735 1422.6 41.1 -0.1 29 18:20:24 Stopped Pumping Prop 4540 3754 1426.0 41.5 -0.0 30 18:20:51 Launch Collet 3959 3744 1444.4 40.3 0.0 31 18:20:56 Start Drop Collet5 Automatically 2271 3707 1447.7 37.3 0.0 32 18:21:02 Start XL flush Automatically 2384 3713 1451.0 29.4 0.0 33 18:21:17 Collet Away 2692 3711 1457.6 25.1 0.0 34 18:22:33 Start LG Flush Automatically 3912 3753 1500.6 40.2 0.0 35 18:35:59 Stopped Pumping 3281 3662 1541.9 0.0 0.0 FracCAT Treatment Report Well : NDBi-43 Field : Pikka Formation : Nanushuk Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : 09-04-2023 Prepared by Name : Alena Lutskaia Division : SLB Phone : 1 630 780 0058 Pressure (All Zones) Initial Wellhead Pressure (psi)86 Initial BHP at Gauge (psi)1972 Final Surface ISIP (psi)Screenout Final ISIP at Gauge (psi)Screenout Surface Shut in Pressure(psi)100 BH Shut in Pressure (psi)2692 Maximum Treating Pressure (psi)8772 BH Gauge at 5,993 MD, 4,275TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl)2400.5 Total YF125ST Past Wellhead (bbl) 1618.4 Total WF125 Past Wellhead (bbl)521.9 Total Freeze Protect Past Wellhead (bbl)0 Total Proppant Pumped (lb)249,670 Total Proppant in Formation (lb)201,978 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal)101 99.7 M275 (lb)192 84 J450 (gal)44 43.4 J753 (gal)4.9 4.8 J580 (lb)1966 1776.6 J475 (lb)495 487.4 J532 (gal)172 168.9 J134 (lb)10 0 J511 (lb)475 470 D206 (gal)3 3 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 in put 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-43 Formation: Nanushuk District: Prudhoe Other Country: United States SUMMARY The Fracture treatment for the NDBi-43 well, Stage 5-7, at Pikka was performed on September 4, 2023. The treatment Design consisted of DataFRAC and 3 stages where Ball/Collet need to be dropped during each stage to prepare the next port for a fracturing treatment. Screen out (SO) occurred on Stage#5 at the end of 10PPA step when POD’s hopper emptied after the gates shut. A total of 249,670 lb of proppant (as measured by FracCAT) was pumped in 2,400 bbl of slurry. The first pump trip was to be set at 7,500 psi and the GORV was set to 8,300 psi. MMaterials AActuall DDesign Slurry Volume - All Volumes (bbl)2,400.5 5,020 Clean Fluid - All Volumes (bbl)2,140.3 4,807 Proppant, lb.249,670 728,594 15:03:27 16:01:47 17:00:07 17:58:27 18:56:47 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 12000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 Stage 5 09-04-2023 Pumping Ball to Seat DF Stage 5 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States DF Stage DF included a Drop Ball, Pump ball to seat/Pump check, DataFRAC Pad and Displace DF. When we dropped the ball into the well, LRS pumped 3bbl of fluid with Rate 3 BPM, then we shut down for 10min. After 10 min shut down, we opened the well and started pumping Ball to seat with Rate 3.5-4.5 BPM. Treating Pressure was growing to 1st trip pressure, and the decision was made to shut down. After surging the well a few times, linear gel was pumped until the target rate of 40 bpm was achieved. Once we reached target rate and pressure was stable, we moved to DF PAD step. DF PAD was displaced with linear gel. The stage ended in a hard shutdown with an ISIP of 1005 psi and recording of pressure decline. A summary of the stage and its measured pump schedule is below: SSummaryy ooff Stagee DataFRACC (Pumpp balll too seatt // pumpp checkk andd DataFRAC) Total Proppant Pumped (lb)0 Max pumping Rate (bpm)40.5 Total Proppant in Formation (lb)0 Average Pumping Rate (bpm)32.5 Total Slurry Pumped (bbl)796.9 Maximum Treating Pressure (psi)5189 YF125ST Pumped (bbl)275 Average Treating Pressure (psi)3815 WF125 Pumped (bbl)521.9 Average Water Temperature (F)87 Average Viscosity (cP)20 15:05:14 15:26:04 15:46:54 16:07:44 16:28:34 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 Stage 5 DF 09-04-2023 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States DDataFRACC -- AAss Measuredd PPumpp Schedule SStepp ##SStepp Name SSlurryy VVolume (bbl) SSlurryy RRate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 Drop Ball 2.8 3.7 0.8 WF125 116 WF125 0.0 0.0 1 2 Ball To Seat 337.5 22.5 37.8 WF125 14177 WF125 0.0 0.0 118 3 DF Pad 275.0 40.1 6.9 YF125ST 11550 YF125ST 0.0 0.0 96 4 DF Displ 181.6 39.9 4.6 WF125 7628 WF125 0.0 0.0 64 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 Drop Ball 3.7 4.2 334 951 103 2 Ball To Seat 22.5 40.5 3574 7263 147 3 DF Pad 40.1 40.3 4149 4566 3852 4 DF Displ 39.9 40.1 3806 3942 560 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 5 Stage 5 consisted of 9 steps: PAD, 6 proppant steps (1-10PPA), Clear Surface Lines and Spacer. Pumping was started and once the target rate 40 bbl/min was reached the Ball/Collet#6 were loaded to the Wellhead. Overall, the stage went well with slight deviation from design of pumping rate because of pump#4 loss, and the treating pressure gradually increased from 3,180 to 5,000 psi, then at the end of 10PPA step when POD’s hopper emptied after the gates shut treating pressure suddenly increased which led to Screen Out (SO), GORV popped off. A total of 1,603.5 bbl of slurry was pumped during stage #5 with 249,670 lb of proppant (according to FracCAT totals). A summary of the stage as follows: SSummaryy ooff Stagee 5 Total Proppant Pumped (lb)249,670 Max pumping Rate (bpm)40.6 Total Proppant in Formation (lb)201,978 Average Pumping Rate (bpm)38.2 Total Slurry Pumped (bbl)1603.6 Maximum Treating Pressure (psi)8772 YF125ST Pumped (bbl)1343.4 Average Treating Pressure (psi)3649 WF125 Pumped (bbl)0 Average Water Temperature (F)89.3 Average Viscosity (cP)19.6 17:39:53 17:56:33 18:13:13 18:29:53 18:46:33 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 12000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Adjusting rate to bring on pump #4 FracCAT* © Schlumberger 1994-2017 Santos NDBi-43 Stage 5 09-04-2023 Screenout Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States SStagee 55 -- AAss Measuredd Pumpp Schedule SStepp ## Stepp Name Slurryy Volume (bbl) Slurryy Rate (bbl/min) Pumpp Time (min) Fluidd Name Fluidd Volume (gal) Proppantt Name Maxx Propp Conc (PPA) Propp Conc (PPA) Propp Mass (lb) 1 PAD 275.0 34.3 8.9 YF125ST 11550 0.0 0.0 0 2 1.0 PPA 180.0 39.1 4.6 YF125ST 7260 CarboLite 16/20 1.1 0.9 6837 3 3.0 PPA 200.0 39.5 5.1 YF125ST 7450 CarboLite 16/20 3.0 2.9 21666 4 5.0 PPA 250.0 39.2 6.4 YF125ST 8637 CarboLite 16/20 5.1 4.9 42536 5 7.0 PPA 250.0 38.9 6.4 YF125ST 8057 CarboLite 16/20 7.2 6.9 55790 6 9.0 PPA 230.0 39.0 5.9 YF125ST 6947 CarboLite 16/20 9.3 8.9 61956 7 10.0 PPA 211.9 38.6 5.5 YF125ST 6244 CarboLite 16/20 10.3 9.8 60815 8 Spacer 6.7 26.2 0.8 YF125ST 278 CarboLite 16/20 1.8 0.3 70 Stagee Pressuress && Rates Stepp #Stepp Name Averagee Slurryy Rate (bbl/min) Maximumm Slurryy Rate (bbl/min) Averagee Treatingg Pressure (psi) Maximumm Treatingg Pressure (psi) Minimumm Treatingg Pressure (psi) 1 PAD 34.3 40.6 3656 4242 387 2 1.0 PPA 39.1 40.1 3470 3669 2597 3 3.0 PPA 39.5 40.1 3096 3531 2923 4 5.0 PPA 39.2 39.7 3004 3138 2911 5 7.0 PPA 38.9 39.6 3477 3789 3105 6 9.0 PPA 39.0 39.5 4132 4500 3753 7 10.0 PPA 38.6 39.2 4599 6350 4325 8 Spacer 26.2 38.7 7058 7495 4631 Client: Santos Well: NDBi-43 Formation: Nanushuk District: Prudhoe Other Country: United States DDataFRAC:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 13:09:01 High Pressure Test 9036 23 0.0 0.0 0.0 2 14:44:44 Dropped Ball 124 3048 0.0 0.0 0.0 3 14:48:43 Open Well LR pumping 3BBL 3 BMP 86 3014 0.0 0.0 0.0 4 15:00:00 LR Pop Off Leaking 104 3203 0.0 0.0 0.0 5 15:06:54 Start Drop Ball Automatically 104 3217 0.0 0.0 0.0 6 15:06:54 Start Propped Frac Automatically 104 3217 0.0 0.0 0.0 7 15:06:54 Start DF Automatically 104 3217 0.0 0.0 0.0 8 15:07:02 Started Pumping 104 3217 0.0 0.0 0.0 9 15:08:14 Start BallToSeat Manually 1087 3236 2.8 4.2 0.0 10 15:39:26 Stopped Pumping 1036 3250 113.7 0.0 0.0 11 15:46:13 Started Pumping 147 3223 113.7 0.0 0.0 12 15:51:29 Stage at Perfs: Drop Ball 3706 3329 166.6 25.8 0.0 13 15:51:35 Stage at Perfs: BallToSeat 3815 3328 169.2 26.9 0.0 14 15:56:23 Start DF Manually 4575 3427 340.3 40.3 0.0 15 16:00:33 Stage at Perfs: DF 3980 3493 507.3 40.2 0.0 16 16:03:15 Start DF Flush Automatically 3857 3561 615.5 40.1 0.0 17 16:07:26 Stage at Perfs: DF Flush 3923 3663 782.7 40.0 0.0 18 16:07:51 Stopped Pumping 1336 3602 796.9 9.7 0.0 Stagee 5:: Jobb Messages Messagee Log #Time Message Treatingg Pressure (psi) Annuluss Pressure (psi) Totall Slurry (bbl) Slurryy Rate (bbl/min) Prop.. Conc. (PPA) 1 17:43:49 Start PAD Automatically 422 3351 0.0 0.0 0.0 2 17:43:49 Start Propped Frac Automatically 422 3351 0.0 0.0 0.0 3 17:43:49 Start Stage 5 Automatically 422 3351 0.0 0.0 0.0 4 17:50:02 Stage at Perfs: PAD 3817 3480 166.4 40.4 0.0 5 17:52:46 Start 1.0 PPA Automatically 3670 3543 275.6 39.8 0.0 6 17:52:46 Started Pumping Prop 3670 3543 275.6 39.8 0.0 7 17:57:02 Stage at Perfs: 1.0 PPA 3390 3483 441.9 39.9 1.0 8 17:57:22 Start 3.0 PPA Automatically 3428 3482 455.2 40.0 1.0 9 18:01:35 Stage at Perfs: 3.0 PPA 2878 3574 621.7 39.8 3.0 10 18:02:26 Start 5.0 PPA Automatically 3063 3567 655.3 39.6 3.1 11 18:06:40 Stage at Perfs: 5.0 PPA 3017 3545 821.3 39.1 4.9 12 18:08:49 Start 7.0 PPA Automatically 3132 3569 905.6 39.6 5.0 13 18:13:05 Stage at Perfs: 7.0 PPA 3658 3548 1071.9 38.7 7.1 14 18:15:14 Start 9.0 PPA Automatically 3765 3491 1155.1 38.8 7.1 15 18:19:30 Stage at Perfs: 9.0 PPA 4257 3507 1321.5 38.9 8.9 16 18:21:08 Start 10.0 PPA Automatically 4518 3562 1385.1 39.0 8.9 17 18:25:26 Stage at Perfs: 10.0 PPA 4784 3485 1551.3 38.7 10.1 18 18:26:37 Start Spacer Manually 7149 3606 1596.9 39.0 0.6 19 18:27:50 Stopped Pumping Prop 4368 3456 1603.5 0.0 -0.2 20 18:27:50 Stopped Pumping 4368 3456 1603.5 0.0 -0.2 FracCAT Treatment Report Well : NDBi-43 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : September 13, 2023 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 902-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 241 Initial BHP at Gauge (psi) 1982 Final Surface ISIP (psi) Screenout Final ISIP at Gauge (psi) Screenout Surface Shut in Pressure(psi) 375 BH Shut in Pressure (psi) 2800 Maximum Treating Pressure (psi) 8741 BH Gauge at 5,993 MD, 4,275TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 4914.7 Total Proppant Pumped (lb) 576380 Total YF125ST Past Wellhead (bbl) 4182.3 Total Proppant in Formation (lb) 562414 Total WF125 Past Wellhead (bbl) 131.8 Total Freeze Protect Past Wellhead (bbl) 0 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 185 184 M275 (lb) 96 J450 (gal) 93 93 J753 (gal) 509 508 J580 (lb) 4600 4,584 J475 (lb) 1,073 1,070 J532 (gal) 404 403 J134 (lb) 8 0 J511 (lb) 339 338 D206 (gal) 0 0 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-43 Formation : Nanushuk District : Prudhoe Other Country : United States SSummary On September 9, 2023, Schlumberger performed a hydraulic fracturing treatment on Stages 6-9 of NBDi-43. The initial designed c alled for the completion of stages 6-11, but a screenout occurred on the 3PPA step of stage 9. By FracCAT totals, a total of 576,380 pounds of proppant was pumped and 562,414 was placed into formation in 4,915 bbl of slurry. Please note, that due to the screenout on Stage 5, there was only one bin that was a known weight. Combined with the screenout on Stage 9, all proppant weights are calculated from FracCAT. The return weights of proppant will be recorded and forwarded to Santos when the proppant is returned to Deadhorse. Stage 6 consisted of a PAD, and 8 proppant stages from 1-8 PPA. Stage 7 and 8 consisted of a Pad, 1, 3, 5, 7, 9 and 10PPA stag es. Stage 9 consisted of a Pad and 8 proppant stages from 1-8 PPA. Pump trips were staggered from 8,000 to 8,400 psi. The popoff was initially set to 8,800 psi and was lowered to 8,500 psi. The highlight of the stages was that the collet launch sequence greatly improved with the addition of a second line going to the wellhead. The entire sequence took about 6 bbl. When the FS called for the collet to be launched, the Stage Completions hand confirmed the launch within a few seconds. Summary of Stages 6--9 Material Actual Design Slurry Volume (bbl) 4,914.70 5,552 Clean Fluid Volume(bbl) 4,314.10 4,967 Proppant (lb) 576,380 738,126 15:52:38 16:42:38 17:32:38 18:22:38 19:12:38 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 12000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 2 4 6 8 10 12 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDBi-43, Stages 6-9 9/9/2023 Stage 6 Stage 7 Stage 8 Stage 9 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States 16:21:26 16:38:06 16:54:46 17:11:26 17:28:06 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 1 2 3 4 5 6 7 8 9 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDBi-43, Stage 6 9/9/2023 SStage 6 Overall, the stage went well. Treating pressure on PAD was around 2,500 psi and slowly fell to about 2,250 psi once 3ppa was g oing into formation. At this point, the treating pressure gradually increased from 2,200 to 5,480 psi. Slurry rate remained steady at 40 bpm until it was slowed for the collet to seat. A summary of the stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #7 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 1,876 5,434 3,761 Bottomhole Pressure 3,247 6,589 5,062 Summary of Stage 6 Total Proppant Pumped (lb) 186,252 Max pumping Rate (bpm) 40.2 Total Proppant in Formation (lb) 186,252 Average Pumping Rate (bpm) 36.8 Total Slurry Pumped (bbl) 1,692 Maximum Treating Pressure (psi) 3,870 YF125ST Pumped (bbl) 1,366 Average Treating Pressure (psi) 2,492 WF125 Pumped (bbl) 131.8 Average Water Temperature (F) 95 Average Viscosity (cP) 25 Drop rate to shift sleeve Shift Sleeve Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SSttage 6 -- AAs Measured Pump Schedule SStep ## 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 Drop Ball 131.8 4.0 32.8 WF125 5537 0.0 0.0 0 2 XL Check 43.6 21.9 2.3 YF125ST 1832 0.0 0.0 0 3 PAD 290.0 39.5 7.3 YF125ST 12180 0.0 0.0 0 4 1.0 PPA 100.0 40.1 2.5 YF125ST 4029 CarboLite 16/20 1.0 1.0 3888 5 2.0 PPA 130.0 40.1 3.2 YF125ST 5031 CarboLite 16/20 2.0 1.9 9769 6 3.0 PPA 170.0 40.1 4.2 YF125ST 6320 CarboLite 16/20 3.0 3.0 18709 7 4.0 PPA 170.0 40.1 4.2 YF125ST 6085 CarboLite 16/20 4.0 4.0 24093 8 5.0 PPA 170.0 40.1 4.2 YF125ST 5866 CarboLite 16/20 5.1 5.0 29095 9 6.0 PPA 170.0 40.1 4.2 YF125ST 5664 CarboLite 16/20 6.1 6.0 33718 10 7.0 PPA 140.0 40.1 3.5 YF125ST 4511 CarboLite 16/20 7.1 6.9 31259 11 8.0 PPA 125.0 40.1 3.1 YF125ST 3898 CarboLite 16/20 8.1 7.9 30866 12 Spacer 41.5 40.1 1.0 YF125ST 1539 CarboLite 16/20 8.0 3.2 4854 13 Drop Collet 10.0 40.1 0.3 YF125ST 421 0.0 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maxximum Sllurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Drop Ball 4.0 6.6 1184 2037 226 2 XL Check 21.9 30.4 3244 3870 2136 3 PAD 39.5 40.2 2539 2808 2434 4 1.0 PPA 40.1 40.2 2480 2581 2412 5 2.0 PPA 40.1 40.2 2346 2408 2288 6 3.0 PPA 40.1 40.2 2247 2308 2204 7 4.0 PPA 40.1 40.2 2275 2327 2238 8 5.0 PPA 40.1 40.2 2418 2520 2329 9 6.0 PPA 40.1 40.2 2651 2713 2522 10 7.0 PPA 40.1 40.2 2822 3050 2691 11 8.0 PPA 40.1 40.2 3349 3566 3058 12 Spacer 40.1 40.2 3617 3670 3567 13 Drop Collet 40.1 40.1 3659 3726 3638 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States 17:12:38 17:23:03 17:33:28 17:43:53 17:54:18 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 1 2 3 4 5 6 7 8 9 10 11 12 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDBi-43, Stage 7 9/9/2023 Stage 7 Overall, the stage went well. The pressure transition from Stage 6 to 7 was not what would normally be seen in a ball and sleeve type system. Typically, there is a increase in pressure as the sleeves open and you breakdown the new zone. In this case, we saw atypical breakdown pressure response, but pressure fell off gradually instead of over a short period of time. At the breakdown, we saw our highest pressure of the stage and pressure fell off to about 2,500 psi while on 3ppa at surface. Once 3ppa started to go into the formation pressure increased about 800 psi but fell back to 2,500 psi. From this point moving forward, pressures gradually increased until the rate was dropped to slow for the collet to seat. Once the collet seated, treating and bottomhole pressure rapidly dropped and had a water hammer effect with a sharp increase. Once normalized, slurry rate was increased to resume the Pad for stage 8. A summary of the stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #8 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 1,823 5,240 31 Bottomhole Pressure 3,194 6,164 2,491 Summary of Stage 7 Total Proppant Pumped (lb) 173,834 Max pumping Rate (bpm) 40.3 Total Proppant in Formation (lb) 173,834 Average Pumping Rate (bpm) 38.6 Total Slurry Pumped (bbl) 1,348.5 Maximum Treating Pressure (psi) 5,402 YF125ST Pumped (bbl) 1,167.4 Average Treating Pressure (psi) 3,128 WF125 Pumped (bbl) 0 Average Water Temperature (F) 95 Average Viscosity (cP) 25 Drop rate to shift sleeve Shift Sleeve Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 7 -- AAs Measured Pump Schedule SStep ## 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 108.0 35.9 3.4 YF125ST 4536 0.0 0.0 0 2 Slow for Seat 50.0 18.5 2.7 YF125ST 2100 0.0 0.0 0 3 Resume PAD 117.0 36.8 3.2 YF125ST 4914 CarboLite 16/20 0.1 0.0 7 4 1.0 PPA 175.0 40.0 4.4 YF125ST 7088 CarboLite 16/20 1.1 0.8 5957 5 3.0 PPA 200.0 40.0 5.0 YF125ST 7461 CarboLite 16/20 3.1 2.9 21398 6 5.0 PPA 220.0 40.0 5.5 YF125ST 7594 CarboLite 16/20 5.1 5.0 37571 7 7.0 PPA 220.0 40.0 5.5 YF125ST 7091 CarboLite 16/20 7.1 6.9 49076 8 9.0 PPA 116.5 40.0 2.9 YF125ST 3525 CarboLite 16/20 9.2 8.9 31230 9 10.0 PPA 89.3 40.0 2.2 YF125ST 2617 CarboLite 16/20 10.1 9.9 25917 10 Spacer 38.0 40.0 1.0 YF125ST 1489 CarboLite 16/20 10.0 1.8 2666 11 Drop Collet 14.7 40.0 0.4 YF125ST 616 CarboLite 16/20 0.0 0.0 11 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 Treatinng Pressure (psi) 1 PAD 35.9 40.2 3241 3991 1616 2 Slow for Seat 18.5 24.6 3354 5115 1854 3 Resume PAD 36.8 40.3 4897 5402 4159 4 1.0 PPA 40.0 40.1 3449 4152 2973 5 3.0 PPA 40.0 40.1 2559 2969 2410 6 5.0 PPA 40.0 40.1 2631 3040 2444 7 7.0 PPA 40.0 40.1 2788 2985 2550 8 9.0 PPA 40.0 40.0 3033 3169 2911 9 10.0 PPA 40.0 40.0 3277 3350 3163 10 Spacer 40.0 40.1 3369 3431 3338 11 Drop Collet 40.0 40.0 3371 3425 3308 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States 17:47:50 18:00:20 18:12:50 18:25:20 18:37:50 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Pr e s s u r e - p s i 0 10 20 30 40 50 Ra t e - b b l / m i n 0 1 2 3 4 5 6 7 8 9 10 11 12 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDBi-43, Stage 8 9/9/2023 Stage 8 After experiencing the water hammer of the collet shifting the sleeve, stage 8 was the smoothest treating stage of the day. Pr essures behaved as expected when each proppant stage was going into formation. As prop con was increasing bottomhole, pressures slightly increased and pressures decreased throughout the stage. Treating pressure was gradually downward sloping until 5ppa started to go into forma tion. At this point, pressures gradually increased with bottomhole prop con until the rate was lowered to seat the collet for stage 9. A summary of the stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #9 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 2,018 4,686 4,775 Bottomhole Pressure 3,371 6,164 6,235 Summary off Stage 8 Total Proppant Pumped (lb) 193,107 Max pumping Rate (bpm) 40.1 Total Proppant in Formation (lb) 193,107 Average Pumping Rate (bpm) 34.7 Total Slurry Pumped (bbl) 1,305.7 Maximum Treating Pressure (psi) 5,187 YF125ST Pumped (bbl) 1,104.5 Average Treating Pressure (psi) 2,667 WF125 Pumped (bbl) 0 Average Water Temperature (F) 95 Average Viscosity (cP) 25 Drop rate to shift sleeve Shift Sleeve Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 8 -- AAs Measured Pump Schedule SStep ## 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 101.0 37.4 2.9 YF125ST 4237 CarboLite 16/20 0.0 0.0 110 2 Slow for Seat 50.0 20.2 2.5 YF125ST 2097 CarboLite 16/20 0.1 0.0 65 3 Resume PAD 89.2 35.4 2.5 YF125ST 3744 CarboLite 16/20 0.1 0.0 106 4 1.0 PPA 150.0 35.1 4.3 YF125ST 6056 CarboLite 16/20 1.0 0.9 5560 5 3.0 PPA 171.1 35.1 4.9 YF125ST 6315 CarboLite 16/20 5.1 3.1 19803 6 5.0 PPA 190.0 35.1 5.4 YF125ST 6547 CarboLite 16/20 5.1 5.0 32731 7 7.0 PPA 191.3 35.1 5.5 YF125ST 6166 CarboLite 16/20 7.1 6.9 42650 8 9.0 PPA 170.0 35.1 4.8 YF125ST 5133 CarboLite 16/20 9.2 8.9 45829 9 10.0 PPA 150.0 35.1 4.3 YF125ST 4388 CarboLite 16/20 10.1 10.0 43687 10 Spacer 1.0 35.1 0.0 YF125ST 30 CarboLite 16/20 9.9 0.0 299 11 Drop Collet 31.0 35.1 0.9 YF125ST 1210 CarboLite 16/20 10.0 1.9 2259 12 Drop Collet 11.1 35.1 0.3 YF125ST 466 CarboLite 16/20 0.0 0.0 9 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treaating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD 37.4 40.1 3035 3678 1581 2 Slow for Seat 20.2 31.0 2966 5187 1674 3 Resume PAD 35.4 39.2 2793 3086 2692 4 1.0 PPA 35.1 35.1 2624 2727 2574 5 3.0 PPA 35.1 35.1 2470 2632 2375 6 5.0 PPA 35.1 35.1 2324 2451 2266 7 7.0 PPA 35.1 35.1 2344 2460 2293 8 9.0 PPA 35.1 35.1 2714 3045 2444 9 10.0 PPA 35.1 35.1 3131 3156 3047 10 Spacer 35.1 35.1 3148 3148 3148 11 Drop Collet 35.1 35.1 3214 3286 3153 12 Drop Collet 35.1 35.1 3420 3701 3286 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States 18:28:21 18:34:11 18:40:01 18:45:51 18:51:41 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 12000 Pr e s s u r e - p s i 0 10 20 30 40 Ra t e - b b l / m i n 0 1 2 3 4 5 Pr o p C o n - P P A Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDBi-43, Stage 9 9/9/2023 Stage 9 Initially, this stage started to treat like Stage 7 with a long recovery after the sleeve was shifted. Midway through the 1PPA step, the treating pressure started to increase followed by an equally sharp decline. This happened twice while 1ppa was being pumped on surface. When 1ppa started going into formation, pressure increased again with another sharp decline. After that, the pressure increased, keeping a positive slope and at the arrival of 2 PPA to the formation this was more evident. Once the decision was made to start dropping rate, BHP started to run away, and the stage screened out. A summary of the stage and its measured pump schedule is below: Summmary of Stage 9 Total Proppant Pumped (lb) 23,188 Max pumping Rate (bpm) 35.1 Total Proppant in Formation (lb) 9,222 Average Pumping Rate (bpm) 29.4 Total Slurry Pumped (bbl) 568.4 Maximum Treating Pressure (psi) 8,405 YF125ST Pumped (bbl) 544 Average Treating Pressure (psi) 4,237 WF125 Pumped (bbl) 0 Average Water Temperature (F) 95 Average Viscosity (cP) 25 Screenout Dropping Rate to 25 and 20 bpm Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 9 -- AAs Measured Pump Schedule SStep ## 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 93.0 34.1 2.8 YF125ST 3906 CarboLite 16/20 0.0 0.0 0 2 Slow for Seat 50.0 17.9 2.8 YF125ST 2100 0.0 0.0 0 3 Resume PAD 107.0 28.6 3.8 YF125ST 4494 0.0 0.0 0 4 1.0 PPA 100.0 30.1 3.3 YF125ST 4036 CarboLite 16/20 1.0 0.9 3721 5 2.0 PPA 130.0 30.1 4.3 YF125ST 5034 CarboLite 16/20 2.1 1.9 9725 6 3.0 PPA 88.4 29.7 3.0 YF125ST 3290 CarboLite 16/20 4.0 3.0 9741 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 34.1 35.1 3108 3705 1782 2 Slow for Seat 17.9 25.0 3565 5270 1926 3 Resume PAD 28.6 30.1 5240 5494 4474 4 1.0 PPA 30.1 30.1 3949 4443 3536 5 2.0 PPA 30.1 30.1 3740 4854 2942 6 3.0 PPA 29.7 30.1 5629 7116 100 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 6 Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:42:05 Pump 5 Fan not turning 0 1520 0.0 0.0 0.0 2 14:45:03 Swapping to pump 2 on the missile -0 2521 0.0 0.0 0.0 3 15:06:26 Pump 2 Started warming up -1 3150 0.0 0.0 0.0 4 15:11:34 Repriming Pumps 47 3080 0.0 4.0 0.0 5 15:28:32 Pumps Primed Starting PT 57 3055 0.0 0.0 0.0 6 15:34:11 Trip Checked 4631 3049 0.0 0.0 0.0 7 15:45:42 Good PT 964 3202 0.0 0.0 0.0 8 15:45:52 Loading Ball 964 3201 0.0 0.0 0.0 9 15:46:56 Start Drop Ball Automatically 960 3200 0.0 0.0 0.0 10 15:46:56 Start Propped Frac Automatically 960 3200 0.0 0.0 0.0 11 15:46:56 Start Stage 6 Automatically 960 3200 0.0 0.0 0.0 12 15:47:07 Started Pumping 959 3200 0.0 0.0 0.0 13 15:53:13 Open Well 241 3192 0.0 0.0 0.0 14 15:54:54 Start Pumping 241 3190 0.1 2.0 0.0 15 15:55:17 Activated Extend Stage 737 3203 1.4 4.0 0.0 16 16:27:38 Deactivated Extend Stage 2253 3329 131.8 7.6 0.0 17 16:27:38 Start XL Check Manually 2253 3329 131.8 7.6 0.0 18 16:28:27 Activated Extend Stage 2658 3284 140.5 13.4 0.0 19 16:29:30 Stage at Perfs: Drop Ball 3505 3321 162.8 30.4 0.0 20 16:29:55 Deactivated Extend Stage 2540 3301 175.4 30.3 0.0 21 16:29:55 Start PAD Manually 2540 3301 175.4 30.3 0.0 22 16:33:00 Stage at Perfs: XL Check 2460 3315 294.8 40.1 0.0 23 16:34:05 Stage at Perfs: PAD 2458 3261 338.3 40.1 0.0 24 16:36:55 Collet loaded 2569 3372 452.0 40.1 0.0 25 16:37:16 Start 1.0 PPA Automatically 2574 3330 466.0 40.1 0.0 26 16:37:16 Started Pumping Prop 2574 3330 466.0 40.1 0.0 27 16:39:45 Start 2.0 PPA Automatically 2408 3392 565.7 40.1 1.0 28 16:41:20 Stage at Perfs: 1.0 PPA 2343 3452 629.2 40.1 2.0 29 16:42:59 Start 3.0 PPA Automatically 2291 3355 695.5 40.1 2.0 30 16:43:49 Stage at Perfs: 2.0 PPA 2295 3387 728.9 40.1 3.0 31 16:47:03 Stage at Perfs: 3.0 PPA 2250 3340 858.7 40.1 3.0 32 16:47:14 Start 4.0 PPA Automatically 2241 3348 866.0 40.1 3.0 33 16:51:18 Stage at Perfs: 4.0 PPA 2327 3319 1029.2 40.1 4.0 34 16:51:28 Start 5.0 PPA Automatically 2335 3319 1035.9 40.2 4.1 35 16:55:32 Stage at Perfs: 5.0 PPA 2514 3407 1199.1 40.1 5.0 36 16:55:42 Start 6.0 PPA Automatically 2543 3411 1205.8 40.1 5.0 37 16:59:46 Stage at Perfs: 6.0 PPA 2658 3266 1369.0 40.1 6.0 38 16:59:56 Start 7.0 PPA Automatically 2712 3270 1375.7 40.1 6.0 39 17:03:25 Start 8.0 PPA Automatically 3068 3328 1515.5 40.1 7.0 40 17:04:00 Stage at Perfs: 7.0 PPA 3179 3337 1538.9 40.1 8.1 41 17:06:32 Start Spacer Automatically 3577 3377 1640.5 40.1 8.0 42 17:06:47 Activated Extend Stage 3589 3380 1650.5 40.1 8.0 43 17:07:14 Stopped Pumping Prop 3662 3389 1668.6 40.1 0.1 44 17:07:29 Stage at Perfs: 8.0 PPA 3648 3390 1678.6 40.1 0.0 45 17:07:34 Deactivated Extend Stage 3649 3386 1682.0 40.1 0.0 46 17:07:46 Launch collet at 1,686 total slurry 3649 3386 1682.0 40.1 0.0 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 7 Job Messages Message Logg # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 17:07:49 Start PAD Manually 3852 3401 1692.0 40.1 0.0 2 17:07:49 Start Propped Frac Manually 3852 3401 1692.0 40.1 0.0 3 17:07:49 Start Stage 7 Automatically 3852 3401 1692.0 40.1 0.0 4 17:11:12 Start Slow for Seat Automatically 1895 3391 108.0 17.2 0.0 5 17:11:23 Stage at Perfs: Spacer 1903 3392 111.1 17.2 0.0 6 17:13:42 Stage at Perfs: Drop Collet 5033 3335 152.9 23.7 0.0 7 17:13:55 Start Resume PAD Automatically 5076 3336 158.1 24.6 0.0 8 17:14:07 Stage at Perfs: PAD 5339 3343 163.1 25.0 0.0 9 17:16:50 Stage at Perfs: Slow for Seat 4186 3341 263.0 40.1 0.0 10 17:17:01 Started Pumping Prop 4134 3345 270.3 40.1 0.0 11 17:17:09 Start 1.0 PPA Automatically 4128 3342 275.7 40.0 0.0 12 17:18:04 Stage at Perfs: Resume PAD 3748 3346 312.3 40.0 1.0 13 17:20:15 Collet Loaded 3109 3354 399.7 40.0 1.0 14 17:21:01 Stage at Perfs: 1.0 PPA 3018 3356 430.4 40.0 1.0 15 17:21:31 Start 3.0 PPA Automatically 2954 3360 450.4 40.0 1.0 16 17:25:23 Stage at Perfs: 3.0 PPA 2447 3385 605.1 40.0 2.9 17 17:26:31 Start 5.0 PPA Automatically 2448 3389 650.4 40.0 3.0 18 17:30:23 Stage at Perfs: 5.0 PPA 2581 3415 805.1 40.0 5.0 19 17:32:01 Start 7.0 PPA Automatically 2569 3440 870.4 40.0 5.1 20 17:35:53 Stage at Perfs: 7.0 PPA 2935 3326 1025.1 40.0 7.0 21 17:37:31 Start 9.0 PPA Automatically 2971 3349 1090.5 40.0 7.1 22 17:40:25 Start 10.0 PPA Manually 3200 3382 1206.5 40.0 8.9 23 17:41:23 Stage at Perfs: 9.0 PPA 3264 3397 1245.2 40.0 10.1 24 17:42:39 Start Spacer Manually 3370 3415 1295.8 40.0 9.9 25 17:43:01 Activated Extend Stage 3431 3418 1310.5 40.0 0.2 26 17:43:26 WH clear at 3,017 total slurry 3304 3428 1333.9 40.0 0.0 27 17:43:43 Collet launched at 3,023 total slurry 3304 3428 1333.9 40.0 0.0 Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 8 Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 17:43:58 Start PAD Manually 3688 3436 1348.5 39.9 0.0 2 17:43:58 Start Propped Frac Manually 3688 3436 1348.5 39.9 0.0 3 17:43:58 Start Stage 8 Automatically 3688 3436 1348.5 39.9 0.0 4 17:44:17 Stage at Perfs: 10.0 PPA 3648 3445 12.7 40.0 0.0 5 17:46:54 Start Slow for Seat Automatically 1816 3324 101.0 17.1 0.0 6 17:46:57 Stage at Perfs: Spacer 1806 3325 101.9 17.1 0.0 7 17:47:40 Collet hit 2458 3365 139.9 24.4 0.0 8 17:49:24 Start Resume PAD Automatically 2737 3362 151.1 31.8 0.0 9 17:49:31 Stage at Perfs: PAD 2709 3356 154.8 32.1 0.0 10 17:51:08 Activated Extend Stage 2723 3368 212.8 35.2 0.0 11 17:51:55 Deactivated Extend Stage 2729 3374 240.2 35.1 0.0 12 17:51:55 Start 1.0 PPA Manually 2729 3374 240.2 35.1 0.0 13 17:52:07 Stage at Perfs: Slow for Seat 2717 3376 247.3 35.1 0.0 14 17:53:33 Stage at Perfs: Resume PAD 2629 3386 297.6 35.1 1.0 15 17:56:05 Stage at Perfs: 1.0 PPA 2601 3402 386.5 35.1 1.0 16 17:56:12 Start 3.0 PPA Automatically 2605 3401 390.5 35.1 1.0 17 17:57:27 Activated Extend Stage 2522 3408 434.4 35.1 3.0 18 17:59:48 Collet Loaded 2393 3409 516.9 35.1 3.0 19 18:00:22 Stage at Perfs: 3.0 PPA 2415 3413 536.8 35.0 3.0 20 18:01:04 Deactivated Extend Stage 2440 3412 561.3 35.1 5.0 21 18:01:04 Start 5.0 PPA Manually 2440 3412 561.3 35.1 5.0 22 18:05:14 Stage at Perfs: 5.0 PPA 2359 3413 707.5 35.1 5.0 23 18:06:29 Start 7.0 PPA Automatically 2342 3411 751.4 35.1 5.0 24 18:07:21 Activated Extend Stage 2328 3409 781.8 35.1 7.0 25 18:10:39 Stage at Perfs: 7.0 PPA 2374 3406 897.6 35.1 7.0 26 18:11:56 Deactivated Extend Stage 2454 3408 942.6 35.1 7.1 27 18:11:56 Start 9.0 PPA Manually 2454 3408 942.6 35.1 7.1 28 18:16:06 Stage at Perfs: 9.0 PPA 2948 3401 1088.8 35.1 9.0 29 18:16:47 Start 10.0 PPA Automatically 3051 3402 1112.7 35.1 9.0 30 18:20:57 Stage at Perfs: 10.0 PPA 3147 3403 1258.9 35.1 9.9 31 18:21:04 Start Spacer Automatically 3164 3403 1263.0 35.1 9.9 32 18:21:05 Start Drop Collet Manually 3161 3405 1263.6 35.1 9.9 33 18:21:10 Activated Extend Stage 3167 3400 1266.5 35.1 10.2 34 18:21:58 Deactivated Extend Stage 3319 3405 1294.6 35.1 0.0 35 18:21:58 Start Drop Collet Manually 3319 3405 1294.6 35.1 0.0 36 18:21:59 Clear WH at 4,330 total slurry 37 18:22:09 Ball away at 4,336 total slurry Client : Santos Well : NDBi-43 Formation : Nanushuk District : Prudhoe Other Country : United States SStage 9 Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 18:22:17 Start PAD Manually 3707 3419 1305.7 35.1 -0.0 2 18:22:17 Start Propped Frac Manually 3707 3419 1305.7 35.1 -0.0 3 18:22:17 Start Stage 9 Automatically 3707 3419 1305.7 35.1 -0.0 4 18:22:20 Stopped Pumping Prop 3706 3419 1.8 35.1 0.0 5 18:25:07 Start Slow for Seat Automatically 1996 3312 93.1 17.0 0.0 6 18:25:44 Stage at Perfs: Spacer 2052 3308 103.6 17.0 0.0 7 18:25:46 Stage at Perfs: Drop Collet 2038 3312 104.1 17.0 0.0 8 18:27:33 Stage at Perfs: Drop Collet 4910 3394 135.3 21.5 0.0 9 18:27:54 Start Resume PAD Automatically 5272 3401 143.3 25.9 0.0 10 18:28:01 Stage at Perfs: Drop Collet 5250 3404 146.3 25.9 0.0 11 18:31:02 Stage at Perfs: PAD 5090 3428 231.2 30.0 0.0 12 18:31:40 Start 1.0 PPA Automatically 4406 3415 250.3 30.1 0.0 13 18:31:43 Started Pumping Prop 4510 3415 251.8 30.1 0.0 14 18:32:42 Stage at Perfs: Slow for Seat 3799 3401 281.4 30.1 1.0 15 18:33:55 Collet Loaded 4370 3421 318.0 30.1 1.0 16 18:34:59 Start 2.0 PPA Automatically 3959 3415 350.1 30.1 1.0 17 18:36:16 Stage at Perfs: Resume PAD 3191 3399 388.7 30.1 2.0 18 18:39:19 Start 3.0 PPA Automatically 4860 3454 480.4 30.0 2.0 19 18:39:35 Stage at Perfs: 1.0 PPA 4950 3460 488.4 30.0 2.8 20 18:42:04 Drop rate to 25 bpm 21 18:42:13 Drop rate to 20 bpm 22 18:42:27 Blew Popoff 23 18:44:57 Shut Well 107 3221 568.4 0.0 0.1 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 3.0 gal F103 Surfactant 1.0 Gal/mGal 527.7 gal J450 Stabilizing Agent 0.5 Gal/mGal 255.4 gal J475 Breaker J475 5.6 lb/mGal 2,867.4 lbm J511 Stabilizing Agent 2.7 lb/mGal 1,355.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,112.9 gal J580 Gel J580 24.3 lb/mGal 12,412.6 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 26.9 gal M275 Bactericide 0.6 lb/mGal 282.0 lbm S522-1620 Propping Agent varied concentrations 1,630,193.0 lbm 71.86093 % 27.69085 % 0.21032 % 0.04185 % 0.03897 % 0.03832 % 0.03129 % 0.02302 % 0.01402 % 0.01402 % 0.01288 % 0.00925 % 0.00699 % 0.00240 % 0.00145 % 0.00112 % 0.00053 % 0.00048 % 0.00029 % 0.00024 % 0.00024 % 0.00024 % 0.00007 % 0.00005 % 0.00005 % 0.00004 % 0.00004 % 0.00004 % 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 % 2634-33-5 1,2-benzisothiazolin-3-one Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 11138-66-2 Xanthan Gum 7632-00-0 Sodium nitrite 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9005-65-6 Sorbitan monooleate, ethoxylated 9004-32-4 Sodium carboxymethylcellulose 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 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 1338-41-6 Sorbitan stearate 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 127-08-2 Acetic acid, potassium salt (impurity) 9000-90-2 Amylase, alpha 63148-62-9 Dimethyl siloxanes and silicones 14808-60-7 Quartz, Crystalline silica 14464-46-1 Cristobalite 9002-84-0 poly(tetrafluoroethylene) 14807-96-6 Magnesium silicate hydrate (talc) 7786-30-3 Magnesium chloride 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 91053-39-3 Diatomaceous earth, calcined 9025-56-3 Hemicellulase 112-42-5 1-undecanol (impurity) 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 50-70-4 Sorbitol 67-63-0 Propan-2-ol 111-76-2 2-butoxyethanol 7727-54-0 Diammonium peroxidisulphate 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 102-71-6 2,2`,2"-nitrilotriethanol CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF122 ST:WF122:YF125 ST:WF125 509,779 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-1700 Fluid Name & Volume Concentration Volume Disclosure Type:Post-Job Well Completed: Date Prepared:9/25/2023 State:Alaska County/Parish:North Slope Borough Case: Client:Oil Search Alaska Well:NDBi-43 Basin/Field:Pikka # SLB-Private Page: 1 / 1 Santos Definitive Survey Report 11 September, 2023 Design: NDBi-043A Santos NAD27 Conversion Pikka NDB NDBi-043 NDBi-043A Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True 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: Grid Convergence: NDB usft Map usft usft °-0.59Slot Radius:"20 5,972,909.70 423,383.56 7.0 70° 20' 10.138 N 150° 37' 17.796 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: NDBi-043 usft usft 0.0 0.0 5,972,694.41 421,902.72 22.8Wellhead Elevation:0.0 usft0.5 70° 20' 7.870 N 150° 38' 0.979 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDBi-043A Model NameMagnetics BGGM2023 26/06/2023 14.64 80.60 57,193.31905544 Phase:Version: Audit Notes: Design NDBi-043A 1.0 ACTUAL Vertical Section:Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:10,109.3 309.560.00.046.6 11/09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 2 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 11/09/2023 SDI_KPR_ADK SDI Keeper ADK110.1 421.3 01 SDI_Gyro_16in Hole<46-421> (NDBi-04 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag464.2 2,436.0 02 BH OntraK_16in Hole <464-2436> (ND 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,530.2 6,199.2 03 BH OntraK_12.25in Hole <2530-6199> 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag6,282.2 10,109.3 04 BH AzitraK_8.5in Hole <6282-10917> ( 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag10,132.0 13,180.5 01 BH AzitraK_8.5in Hole <10109-13181> MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 46.6 0.00 0.00 46.6 -22.8 0.0 0.0 5,972,694.41 421,902.72 0.00 0.0 110.1 0.08 27.55 110.1 40.7 0.0 0.0 5,972,694.45 421,902.74 0.13 0.0 127.0 0.08 50.47 127.0 57.6 0.1 0.0 5,972,694.47 421,902.76 0.18 0.0 20" Conductor Casing 138.2 0.08 65.48 138.2 68.8 0.1 0.0 5,972,694.47 421,902.77 0.18 0.0 232.6 0.12 56.09 232.6 163.2 0.1 0.2 5,972,694.56 421,902.91 0.05 -0.1 327.3 0.18 46.17 327.3 257.9 0.3 0.4 5,972,694.71 421,903.10 0.07 -0.1 421.3 0.22 95.20 421.3 351.9 0.4 0.7 5,972,694.79 421,903.39 0.18 -0.3 464.2 0.24 113.47 464.2 394.8 0.3 0.8 5,972,694.75 421,903.55 0.18 -0.4 559.3 1.73 153.11 559.3 489.9 -1.0 1.7 5,972,693.38 421,904.37 1.63 -1.9 661.3 5.76 153.19 661.1 591.7 -7.0 4.7 5,972,687.41 421,907.32 3.95 -8.0 764.8 7.41 168.33 763.9 694.5 -18.1 8.4 5,972,676.20 421,910.89 2.30 -18.0 857.1 9.51 184.34 855.2 785.8 -31.6 9.0 5,972,662.75 421,911.38 3.40 -27.0 890.1 10.89 191.88 887.6 818.2 -37.3 8.1 5,972,657.00 421,910.47 5.82 -30.1 920.6 12.11 197.97 917.6 848.2 -43.2 6.6 5,972,651.14 421,908.83 5.63 -32.6 948.7 13.09 203.88 945.0 875.6 -48.9 4.4 5,972,645.45 421,906.57 5.76 -34.5 981.0 13.73 210.89 976.4 907.0 -55.5 0.9 5,972,638.87 421,903.06 5.42 -36.1 1,011.1 14.37 213.19 1,005.6 936.2 -61.7 -3.0 5,972,632.71 421,899.11 2.82 -37.0 1,036.0 14.44 216.29 1,029.7 960.3 -66.8 -6.5 5,972,627.67 421,895.54 3.11 -37.6 Upper Schrader Bluff 11/09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 3 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 1,042.3 14.46 217.07 1,035.8 966.4 -68.1 -7.4 5,972,626.41 421,894.58 3.11 -37.6 1,137.7 13.92 225.34 1,128.2 1,058.8 -85.6 -22.8 5,972,609.01 421,879.07 2.20 -37.0 1,154.0 14.13 225.96 1,144.1 1,074.7 -88.4 -25.6 5,972,606.28 421,876.21 1.58 -36.6 Base Ice Bearing Permafrost 1,233.4 15.17 228.75 1,220.9 1,151.5 -102.0 -40.4 5,972,592.85 421,861.29 1.58 -33.8 1,327.3 18.35 229.96 1,310.8 1,241.4 -119.6 -60.9 5,972,575.45 421,840.55 3.41 -29.2 1,410.0 20.83 230.70 1,388.7 1,319.3 -137.3 -82.3 5,972,557.98 421,819.02 3.02 -24.0 Base Permafrost Transition 1,421.6 21.18 230.79 1,399.6 1,330.2 -139.9 -85.5 5,972,555.38 421,815.77 3.02 -23.2 1,517.4 23.97 236.33 1,488.0 1,418.6 -161.7 -115.1 5,972,533.96 421,785.94 3.66 -14.2 1,610.9 27.02 240.35 1,572.4 1,503.0 -182.7 -149.4 5,972,513.27 421,751.44 3.75 -1.2 1,705.8 30.25 242.45 1,655.7 1,586.3 -204.4 -189.3 5,972,491.97 421,711.29 3.57 15.7 1,798.0 33.42 242.69 1,734.0 1,664.6 -226.8 -232.5 5,972,470.03 421,667.90 3.44 34.8 Middle Schrader Bluff 1,801.6 33.54 242.70 1,737.1 1,667.7 -227.8 -234.3 5,972,469.13 421,666.11 3.44 35.5 1,896.0 36.88 243.61 1,814.2 1,744.8 -252.3 -282.8 5,972,445.08 421,617.31 3.58 57.3 1,990.7 40.24 244.75 1,888.2 1,818.8 -278.0 -336.0 5,972,419.95 421,563.91 3.63 81.9 2,084.8 44.55 246.50 1,957.7 1,888.3 -304.1 -393.8 5,972,394.42 421,505.86 4.75 109.8 2,179.1 47.34 248.27 2,023.3 1,953.9 -330.2 -456.3 5,972,369.03 421,443.02 3.25 141.5 2,275.2 47.28 249.02 2,088.4 2,019.0 -355.9 -522.1 5,972,344.00 421,376.98 0.58 175.8 2,353.0 47.70 247.65 2,141.0 2,071.6 -377.1 -575.4 5,972,323.39 421,323.50 1.41 203.4 MCU (Post DW-02) 2,369.0 47.79 247.37 2,151.8 2,082.4 -381.6 -586.3 5,972,318.97 421,312.49 1.41 209.0 2,436.0 48.07 247.07 2,196.6 2,127.2 -400.9 -632.2 5,972,300.19 421,266.44 0.53 232.1 2,501.0 47.72 247.54 2,240.2 2,170.8 -419.5 -676.7 5,972,282.06 421,221.78 0.75 254.5 13-3/8" Surface Casing 2,530.2 47.57 247.75 2,259.9 2,190.5 -427.7 -696.6 5,972,274.06 421,201.74 0.75 264.7 2,556.9 46.82 247.01 2,278.0 2,208.6 -435.2 -714.7 5,972,266.71 421,183.56 3.46 273.8 11 /09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 4 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 2,651.6 46.34 247.41 2,343.1 2,273.7 -461.9 -778.1 5,972,240.73 421,119.89 0.59 305.7 2,747.3 46.30 247.18 2,409.2 2,339.8 -488.6 -841.9 5,972,214.70 421,055.81 0.18 337.9 2,804.0 46.38 246.79 2,448.3 2,378.9 -504.6 -879.7 5,972,199.05 421,017.87 0.52 356.8 Tuluvak Shale (Post DW-02) 2,842.3 46.44 246.52 2,474.7 2,405.3 -515.6 -905.2 5,972,188.32 420,992.30 0.52 369.4 2,893.0 46.39 246.64 2,509.7 2,440.3 -530.2 -938.9 5,972,174.08 420,958.44 0.20 386.1 Tuluvak Sand (Post DW-02) 2,937.4 46.35 246.75 2,540.3 2,470.9 -542.9 -968.4 5,972,161.67 420,928.80 0.20 400.8 3,030.8 46.38 245.55 2,604.8 2,535.4 -570.2 -1,030.2 5,972,135.00 420,866.72 0.93 431.0 3,125.6 46.40 245.66 2,670.2 2,600.8 -598.6 -1,092.7 5,972,107.30 420,803.92 0.09 461.2 3,225.1 46.45 245.70 2,738.8 2,669.4 -628.3 -1,158.4 5,972,078.30 420,737.93 0.06 492.9 3,313.8 46.37 245.40 2,799.9 2,730.5 -654.9 -1,216.9 5,972,052.32 420,679.18 0.26 521.1 3,409.7 46.45 245.42 2,866.0 2,796.6 -683.8 -1,280.1 5,972,024.08 420,615.72 0.08 551.3 3,504.0 46.47 244.92 2,931.0 2,861.6 -712.5 -1,342.1 5,971,996.02 420,553.38 0.38 580.9 3,599.1 46.46 244.73 2,996.5 2,927.1 -741.8 -1,404.5 5,971,967.35 420,490.71 0.15 610.3 3,693.1 46.44 244.91 3,061.3 2,991.9 -770.8 -1,466.2 5,971,939.01 420,428.75 0.14 639.4 3,779.0 46.30 245.82 3,120.6 3,051.2 -796.7 -1,522.7 5,971,913.68 420,371.97 0.78 666.5 Seabee (Post DW-02) 3,788.7 46.28 245.92 3,127.2 3,057.8 -799.6 -1,529.1 5,971,910.89 420,365.56 0.78 669.5 3,883.5 46.45 250.77 3,192.7 3,123.3 -824.9 -1,592.8 5,971,886.26 420,301.58 3.71 702.6 3,977.7 47.39 254.87 3,257.1 3,187.7 -845.2 -1,658.5 5,971,866.63 420,235.61 3.33 740.3 4,072.6 47.40 257.75 3,321.3 3,251.9 -861.7 -1,726.4 5,971,850.82 420,167.62 2.23 782.1 4,167.6 48.13 260.30 3,385.2 3,315.8 -875.1 -1,795.4 5,971,838.16 420,098.44 2.13 826.8 4,261.4 49.03 264.15 3,447.2 3,377.8 -884.6 -1,865.1 5,971,829.39 420,028.68 3.22 874.5 4,357.6 49.95 265.94 3,509.8 3,440.4 -890.9 -1,938.0 5,971,823.84 419,955.75 1.71 926.6 4,452.2 49.99 268.42 3,570.6 3,501.2 -894.4 -2,010.3 5,971,821.03 419,883.38 2.01 980.1 4,546.5 51.82 271.41 3,630.1 3,560.7 -894.5 -2,083.5 5,971,821.71 419,810.24 3.13 1,036.5 4,639.8 53.25 274.44 3,686.8 3,617.4 -890.7 -2,157.4 5,971,826.27 419,736.38 3.00 1,095.9 11 /09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 5 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 4,736.8 54.66 277.85 3,743.9 3,674.5 -882.3 -2,235.3 5,971,835.50 419,658.53 3.19 1,161.3 4,830.7 56.03 281.43 3,797.3 3,727.9 -869.4 -2,311.5 5,971,849.24 419,582.52 3.46 1,228.3 4,926.3 57.17 285.23 3,849.9 3,780.5 -851.0 -2,389.1 5,971,868.46 419,505.09 3.53 1,299.9 4,954.0 57.63 286.19 3,864.9 3,795.5 -844.6 -2,411.6 5,971,875.01 419,482.71 3.35 1,321.2 Nanushuk 4,991.0 58.26 287.45 3,884.5 3,815.1 -835.6 -2,441.6 5,971,884.39 419,452.80 3.35 1,350.1 NT8 MFS 5,021.2 58.78 288.47 3,900.3 3,830.9 -827.6 -2,466.1 5,971,892.60 419,428.35 3.35 1,374.1 5,025.0 58.84 288.63 3,902.2 3,832.8 -826.6 -2,469.2 5,971,893.65 419,425.31 3.97 1,377.1 NT7 MFS 5,114.8 60.38 292.36 3,947.7 3,878.3 -799.5 -2,541.7 5,971,921.53 419,353.08 3.97 1,450.3 5,190.0 61.34 294.95 3,984.3 3,914.9 -773.1 -2,601.8 5,971,948.52 419,293.21 3.27 1,513.5 NT6 MFS 5,209.3 61.60 295.61 3,993.5 3,924.1 -765.9 -2,617.2 5,971,955.92 419,277.95 3.27 1,529.9 5,291.0 62.99 298.13 4,031.5 3,962.1 -733.2 -2,681.7 5,971,989.28 419,213.79 3.22 1,600.4 NT5 MFS 5,304.8 63.23 298.55 4,037.8 3,968.4 -727.3 -2,692.5 5,971,995.25 419,203.00 3.22 1,612.5 5,398.9 65.19 300.08 4,078.7 4,009.3 -685.8 -2,766.4 5,972,037.49 419,129.60 2.55 1,695.9 5,464.0 66.50 301.87 4,105.3 4,035.9 -655.3 -2,817.3 5,972,068.58 419,079.00 3.21 1,754.6 NT4 MFS 5,492.8 67.08 302.65 4,116.7 4,047.3 -641.1 -2,839.7 5,972,082.96 419,056.74 3.21 1,780.9 5,587.4 68.50 304.92 4,152.4 4,083.0 -592.4 -2,912.5 5,972,132.42 418,984.48 2.68 1,868.0 5,683.8 70.56 306.67 4,186.1 4,116.7 -539.6 -2,985.7 5,972,185.96 418,911.85 2.73 1,958.1 5,777.3 72.35 308.68 4,215.9 4,146.5 -485.4 -3,055.9 5,972,240.90 418,842.22 2.79 2,046.7 5,873.3 74.11 310.20 4,243.6 4,174.2 -427.0 -3,126.8 5,972,299.99 418,771.90 2.38 2,138.6 5,968.1 76.07 312.07 4,268.0 4,198.6 -366.7 -3,195.9 5,972,361.00 418,703.52 2.81 2,230.2 6,062.9 78.25 314.28 4,289.0 4,219.6 -303.6 -3,263.2 5,972,424.87 418,636.86 3.24 2,322.4 6,157.9 80.25 316.36 4,306.8 4,237.4 -237.2 -3,328.8 5,972,491.92 418,571.93 3.01 2,415.2 11 /09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 6 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 6,199.2 81.09 317.45 4,313.5 4,244.1 -207.4 -3,356.7 5,972,522.02 418,544.35 3.30 2,455.7 6,236.0 81.64 318.17 4,319.0 4,249.6 -180.5 -3,381.1 5,972,549.19 418,520.23 2.45 2,491.7 9-5/8" Intermediate Liner 6,282.2 82.34 319.07 4,325.4 4,256.0 -146.1 -3,411.4 5,972,583.83 418,490.35 2.45 2,536.9 6,321.4 83.05 319.83 4,330.4 4,261.0 -116.6 -3,436.7 5,972,613.66 418,465.36 2.64 2,575.2 6,386.0 84.10 322.06 4,337.6 4,268.2 -66.7 -3,477.1 5,972,663.89 418,425.47 3.80 2,638.1 NT3 MFS 6,416.3 84.60 323.10 4,340.6 4,271.2 -42.8 -3,495.4 5,972,688.01 418,407.40 3.80 2,667.5 6,509.9 86.69 326.17 4,347.7 4,278.3 33.3 -3,549.4 5,972,764.70 418,354.17 3.96 2,757.6 6,605.5 88.69 328.12 4,351.6 4,282.2 113.5 -3,601.2 5,972,845.44 418,303.21 2.92 2,848.6 6,700.6 90.16 329.34 4,352.5 4,283.1 194.9 -3,650.6 5,972,927.24 418,254.69 2.01 2,938.5 6,795.1 91.12 329.67 4,351.5 4,282.1 276.2 -3,698.5 5,973,009.13 418,207.61 1.07 3,027.3 6,829.0 91.11 329.75 4,350.8 4,281.4 305.5 -3,715.6 5,973,038.56 418,190.83 0.25 3,059.1 NT3.2 Top Reservoir 6,889.9 91.08 329.90 4,349.7 4,280.3 358.1 -3,746.2 5,973,091.51 418,160.77 0.25 3,116.2 6,984.3 91.21 329.63 4,347.8 4,278.4 439.7 -3,793.8 5,973,173.57 418,114.08 0.32 3,204.8 7,079.3 91.11 328.59 4,345.9 4,276.5 521.2 -3,842.5 5,973,255.57 418,066.18 1.10 3,294.3 7,173.6 91.08 328.46 4,344.1 4,274.7 601.6 -3,891.8 5,973,336.48 418,017.80 0.14 3,383.5 7,267.5 91.05 328.98 4,342.3 4,272.9 681.8 -3,940.5 5,973,417.16 417,969.92 0.55 3,472.1 7,363.0 91.12 328.54 4,340.5 4,271.1 763.5 -3,990.0 5,973,499.34 417,921.24 0.47 3,562.3 7,457.7 91.15 328.36 4,338.6 4,269.2 844.2 -4,039.5 5,973,580.50 417,872.56 0.19 3,651.9 7,552.9 91.12 327.98 4,336.7 4,267.3 925.0 -4,089.8 5,973,661.91 417,823.20 0.40 3,742.1 7,647.7 91.08 327.69 4,334.9 4,265.5 1,005.2 -4,140.2 5,973,742.61 417,773.61 0.31 3,832.1 7,742.3 91.08 327.06 4,333.1 4,263.7 1,084.9 -4,191.2 5,973,822.84 417,723.43 0.67 3,922.2 7,837.2 91.12 327.33 4,331.3 4,261.9 1,164.7 -4,242.6 5,973,903.12 417,672.85 0.29 4,012.6 7,931.5 91.05 327.72 4,329.5 4,260.1 1,244.2 -4,293.2 5,973,983.14 417,623.09 0.42 4,102.2 8,024.8 91.30 328.47 4,327.6 4,258.2 1,323.4 -4,342.5 5,974,062.84 417,574.61 0.85 4,190.7 8,120.8 91.24 329.57 4,325.5 4,256.1 1,405.7 -4,391.9 5,974,145.61 417,526.08 1.15 4,281.2 11 /09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 7 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 8,215.3 91.24 329.71 4,323.4 4,254.0 1,487.2 -4,439.7 5,974,227.61 417,479.19 0.15 4,369.9 8,309.9 91.21 330.07 4,321.4 4,252.0 1,569.0 -4,487.1 5,974,309.92 417,432.60 0.38 4,458.6 8,404.1 91.24 330.48 4,319.4 4,250.0 1,650.8 -4,533.8 5,974,392.22 417,386.73 0.44 4,546.7 8,499.2 91.21 330.10 4,317.4 4,248.0 1,733.4 -4,581.0 5,974,475.28 417,340.48 0.40 4,635.7 8,593.6 91.27 329.09 4,315.3 4,245.9 1,814.8 -4,628.7 5,974,557.12 417,293.59 1.07 4,724.3 8,687.9 91.24 329.50 4,313.3 4,243.9 1,895.9 -4,676.9 5,974,638.70 417,246.28 0.44 4,813.1 8,783.9 91.24 330.04 4,311.2 4,241.8 1,978.8 -4,725.2 5,974,722.09 417,198.85 0.56 4,903.1 8,878.0 91.21 330.39 4,309.2 4,239.8 2,060.4 -4,771.9 5,974,804.20 417,152.98 0.37 4,991.1 8,972.3 91.15 330.07 4,307.2 4,237.8 2,142.3 -4,818.7 5,974,886.58 417,107.00 0.34 5,079.4 9,066.4 91.24 329.97 4,305.3 4,235.9 2,223.8 -4,865.7 5,974,968.51 417,060.86 0.14 5,167.5 9,162.0 91.21 329.95 4,303.2 4,233.8 2,306.5 -4,913.6 5,975,051.77 417,013.86 0.04 5,257.1 9,257.3 91.18 329.54 4,301.2 4,231.8 2,388.8 -4,961.6 5,975,134.56 416,966.72 0.43 5,346.6 9,352.5 91.24 329.57 4,299.2 4,229.8 2,470.8 -5,009.8 5,975,217.06 416,919.38 0.07 5,436.0 9,447.3 91.30 329.14 4,297.1 4,227.7 2,552.4 -5,058.1 5,975,299.07 416,871.93 0.46 5,525.1 9,542.0 91.24 329.04 4,295.0 4,225.6 2,633.6 -5,106.7 5,975,380.81 416,824.15 0.12 5,614.4 9,636.7 91.21 328.52 4,293.0 4,223.6 2,714.6 -5,155.8 5,975,462.32 416,775.90 0.55 5,703.8 9,731.6 91.21 328.56 4,291.0 4,221.6 2,795.5 -5,205.3 5,975,543.70 416,727.26 0.04 5,793.5 9,824.8 91.24 328.88 4,289.0 4,219.6 2,875.2 -5,253.7 5,975,623.85 416,679.70 0.34 5,881.5 9,920.8 91.18 328.98 4,287.0 4,217.6 2,957.4 -5,303.3 5,975,706.56 416,631.04 0.12 5,972.1 10,014.8 91.18 329.44 4,285.0 4,215.6 3,038.1 -5,351.4 5,975,787.81 416,583.76 0.49 6,060.6 10,109.3 91.21 329.59 4,283.1 4,213.7 3,119.5 -5,399.3 5,975,869.70 416,536.69 0.16 6,149.4 10,132.0 91.97 329.84 4,282.4 4,213.0 3,139.1 -5,410.7 5,975,889.40 416,525.46 3.53 6,170.7 10,203.7 90.10 329.69 4,281.1 4,211.7 3,201.0 -5,446.8 5,975,951.70 416,490.02 2.62 6,237.9 10,295.8 90.19 330.38 4,280.9 4,211.5 3,280.8 -5,492.8 5,976,031.96 416,444.85 0.76 6,324.2 10,394.1 90.93 330.26 4,280.0 4,210.6 3,366.3 -5,541.5 5,976,117.87 416,397.06 0.76 6,416.2 10,489.2 91.82 330.07 4,277.7 4,208.3 3,448.7 -5,588.8 5,976,200.83 416,350.63 0.96 6,505.2 10,583.8 91.85 330.25 4,274.6 4,205.2 3,530.7 -5,635.9 5,976,283.30 416,304.46 0.19 6,593.6 11 /09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 8 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 10,679.0 91.85 329.72 4,271.6 4,202.2 3,613.1 -5,683.4 5,976,366.15 416,257.74 0.56 6,682.8 10,773.3 91.82 329.37 4,268.6 4,199.2 3,694.3 -5,731.2 5,976,447.89 416,210.81 0.37 6,771.4 10,867.5 91.91 329.30 4,265.5 4,196.1 3,775.3 -5,779.2 5,976,529.33 416,163.66 0.12 6,859.9 10,962.5 91.91 329.85 4,262.3 4,192.9 3,857.2 -5,827.3 5,976,611.70 416,116.43 0.58 6,949.2 11,056.3 91.88 328.93 4,259.2 4,189.8 3,937.9 -5,875.1 5,976,692.90 416,069.53 0.98 7,037.4 11,151.3 91.88 328.70 4,256.1 4,186.7 4,019.1 -5,924.2 5,976,774.64 416,021.21 0.24 7,127.0 11,245.1 91.85 328.00 4,253.0 4,183.6 4,099.0 -5,973.4 5,976,854.96 415,972.85 0.75 7,215.8 11,341.9 91.61 327.84 4,250.1 4,180.7 4,180.9 -6,024.8 5,976,937.47 415,922.32 0.30 7,307.6 11,436.8 91.88 328.17 4,247.2 4,177.8 4,261.3 -6,075.1 5,977,018.38 415,872.93 0.45 7,397.6 11,531.6 91.85 327.53 4,244.2 4,174.8 4,341.6 -6,125.5 5,977,099.15 415,823.34 0.68 7,487.6 11,626.2 91.58 327.11 4,241.3 4,171.9 4,421.2 -6,176.5 5,977,179.24 415,773.13 0.53 7,577.6 11,721.0 91.61 327.87 4,238.7 4,169.3 4,501.1 -6,227.5 5,977,259.71 415,723.01 0.80 7,667.8 11,815.7 91.61 327.74 4,236.0 4,166.6 4,581.2 -6,277.9 5,977,340.29 415,673.44 0.14 7,757.7 11,911.3 91.61 328.42 4,233.3 4,163.9 4,662.3 -6,328.4 5,977,421.92 415,623.77 0.71 7,848.3 12,006.6 91.51 328.77 4,230.7 4,161.3 4,743.6 -6,378.1 5,977,503.73 415,574.98 0.38 7,938.3 12,100.8 91.58 329.17 4,228.2 4,158.8 4,824.3 -6,426.6 5,977,584.93 415,527.28 0.43 8,027.2 12,194.3 91.64 329.39 4,225.6 4,156.2 4,904.6 -6,474.4 5,977,665.75 415,480.39 0.24 8,115.1 12,289.1 91.58 329.24 4,222.9 4,153.5 4,986.1 -6,522.7 5,977,747.70 415,432.90 0.17 8,204.3 12,384.3 91.64 328.71 4,220.2 4,150.8 5,067.7 -6,571.8 5,977,829.79 415,384.69 0.56 8,294.1 12,478.9 91.70 328.84 4,217.5 4,148.1 5,148.6 -6,620.8 5,977,911.16 415,336.51 0.15 8,383.4 12,573.4 91.76 329.37 4,214.6 4,145.2 5,229.6 -6,669.3 5,977,992.70 415,288.87 0.56 8,472.4 12,669.3 91.73 329.35 4,211.7 4,142.3 5,312.1 -6,718.1 5,978,075.68 415,240.87 0.04 8,562.6 12,763.7 91.73 330.03 4,208.9 4,139.5 5,393.6 -6,765.8 5,978,157.64 415,194.10 0.72 8,651.2 12,858.2 91.76 329.68 4,206.0 4,136.6 5,475.2 -6,813.2 5,978,239.76 415,147.54 0.37 8,739.8 12,952.7 91.73 329.49 4,203.1 4,133.7 5,556.6 -6,861.0 5,978,321.68 415,100.59 0.20 8,828.5 13,047.6 91.73 329.03 4,200.2 4,130.8 5,638.2 -6,909.5 5,978,403.73 415,052.95 0.48 8,917.8 13,142.3 91.73 329.22 4,197.4 4,128.0 5,719.5 -6,958.1 5,978,485.48 415,005.22 0.20 9,007.0 11 /09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 9 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True MD (usft) Inc (°) Azi (azimuth) (°) N/S (usft) E/W (usft) Northing (usft) TVDSS (usft) Easting (usft) Survey TVD (usft) DLeg (°/100usft) V. Sec (usft) 13,180.5 91.79 328.75 4,196.2 4,126.8 5,752.2 -6,977.8 5,978,518.41 414,985.88 1.24 9,043.1 13,206.0 91.79 328.75 4,195.4 4,126.0 5,774.0 -6,991.0 5,978,540.31 414,972.90 0.00 9,067.1 4-1/2" Production Liner 13,210.0 91.79 328.75 4,195.3 4,125.9 5,777.4 -6,993.0 5,978,543.75 414,970.87 0.00 9,070.9 Projection TD Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 4-1/2" Production Liner4,195.413,206.0 4-1/2 6 11/09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 10 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Santos NAD27 Conversion Pikka NDB Santos Definitive Survey Report Well: Wellbore: NDBi-043 NDBi-043A Survey Calculation Method:Minimum Curvature Parker 272 @ 69.4usft Design:NDBi-043A Database:EDM STO Alaska MD Reference:Parker 272 @ 69.4usft North Reference: Well NDBi-043 True Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 2,804.0 2,448.3 Tuluvak Shale (Post DW-02) 1,410.0 1,388.7 Base Permafrost Transition 2,893.0 2,509.7 Tuluvak Sand (Post DW-02) 6,386.0 4,337.6 NT3 MFS 1,154.0 1,144.1 Base Ice Bearing Permafrost 4,991.0 3,884.5 NT8 MFS 1,798.0 1,734.0 Middle Schrader Bluff 2,353.0 2,141.0 MCU (Post DW-02) 4,954.0 3,864.9 Nanushuk 5,291.0 4,031.5 NT5 MFS 5,025.0 3,902.2 NT7 MFS 5,464.0 4,105.3 NT4 MFS 1,036.0 1,029.7 Upper Schrader Bluff 5,190.0 3,984.3 NT6 MFS 6,829.0 4,350.8 NT3.2 Top Reservoir 3,779.0 3,120.6 Seabee (Post DW-02) Measured Depth (usft) Vertical Depth (usft)+E/-W (usft) +N/-S (usft) Local Coordinates Comment Design Annotations 13,210.0 4,195.3 -6,993.05,777.4 Projection TD Approved By:Checked By:Date: 11/09/2023 2:12:13PM COMPASS 5000.17 Build 02 Page 11 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Friday, October 13, 2023 9:25 AM To:Brake, Jared (Jared) Cc:Regg, James B (OGC) Subject:RE: Santos NDBi-043 MIT-IA form Attachments:MIT Pikka NDBi-043A 08-21-23.xlsx; MIT Pikka NDBi-043A 08-21-23 Witnessed.xlsx Jared, AƩached is a revised report separaƟng the two tests (MIT‐IA was witnessed by Adam Earl) and changing the type of test to “P” per the inspector. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent: Thursday, September 14, 2023 2:59 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; Kono, Randy (Randy) <Randy.Kono@santos.com> Subject: Santos NDBi‐043 MIT‐IA form All, AƩached is the State witnessed MIT‐IA & T form for Oil Search (Santos) NDBi‐043 injecƟon well. Jared Brake Well Integrity & Well IntervenƟon Specialist t: 1 (907) 375‐4673 | m: 1 (832) 330‐4359| e: jared.brake@contractor.santos.com Santos.com | Follow us on LinkedIn, Facebook and TwiƩer You don't often get email from jared.brake@contractor.santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Pikka NDB-43PTD 2230520 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2230520 Type Inj N Tubing 2976 3420 3418 3411 Type Test P Packer TVD 4292 BBL Pump 8.5 IA 52 4260 4209 4185 Interval O Test psi 4000 BBL Return 8.4 OA Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Santos - Oil Search (Alaska), LLC Nanashuk / Pikka / NDB Adam Earl Pere Keniye 08/21/23 Notes:Tested as per PTD # 223-0520. Pre-Frac MIT-IA. Note IA same as OA, liner was not ran to surface Notes: Notes: Notes: NDBi - 043A Form 10-426 (Revised 01/2017)2023-0821_MIT_Pikka_NDB-043A J. Regg; 10/13/2023 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2230520 Type Inj N Tubing 10 6208 6142 6115 Type Test P Packer TVD 4292 BBL Pump 3.9 IA 52 215 231 238 Interval O Test psi 6000 BBL Return 3.9 OA Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Santos - Oil Search (Alaska), LLC Nanashuk / Pikka / NDB Pere Keniye 08/21/23 Notes:MIT-T Notes: Notes: Notes: NDBi - 043A Form 10-426 (Revised 01/2017)2023-0821_MIT_Pikka_NDB-043A_tbg Test not witnessed by AOGCC Inspector J. Regg; 10/13/2023 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-043 (50-103-20859-0000) NDBi-043A (20-103-20859-0100) 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 907-375-4607 phone shannon.koh@santos.com DATE: 9/14/2023 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Kayla Junke 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: 9/18/2023 NDBi-043 PTD: 223-051 T38000 NDBi-043A PTD:223-052 T38001 NDBi-043A (20-103-20859-0100) Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.18 15:46:39 -08'00' LETTER OF TRANSMITTAL NDBi-043A (20-103-20859-0100) جؐؐؐAnalyses ؒ NO_DATA.docx ؒ جؐؐؐCore Data - Conventional Core and Sidewall Cores Lab Studies ؒ NO_DATA.docx ؒ جؐؐؐDirectional Survey ؒ NDBi-043A Compass Survey Reports.pdf ؒ NDBi-043A NAD27 Compass Survey Reports.pdf ؒ NDBi-043A NAD27.txt ؒ NDBi-043A Plan View Compass Report.pdf ؒ NDBi-043A vertical Section Compass Report.pdf ؒ NDBi-043A WA Survey Reports.xlsx ؒ NDBi-043A.txt ؒ جؐؐؐLog Digital Data (LWD and WL) ؒ ؤؐؐؐLWD ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐLWD ؒ ؒ ؒ NDBi-043A_LWD_RM_13210ft.las ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-043A_AP_R04_RM_20230804.las ؒ ؒ ؒ NDBi-043A_AP_R05_RM_20230804.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-043A_DMD_RM_13210ft.las ؒ ؒ NDBi-043A_DMT_R04_RM_20230804.las ؒ ؒ NDBi-043A_DMT_R05_RM_20230804.las ؒ ؒ ؒ ؤؐؐؐGraphics Images ؒ جؐؐؐCGM ؒ ؒ NDBi-043A_AP_RM_20230804.cgm ؒ ؒ NDBi-043A_DMD_RM_13210ft.cgm ؒ ؒ NDBi-043A_DMT_RM_20230804.cgm ؒ ؒ NDBi-043A_LWD_RM_13210ft_2MD.cgm ؒ ؒ NDBi-043A_LWD_RM_13210ft_2TVD.cgm ؒ ؒ NDBi-043A_LWD_RM_13210ft_5MD.cgm ؒ ؒ NDBi-043A_LWD_RM_13210ft_5TVD.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ NDBi-043A_AP_RM_20230804.pdf ؒ NDBi-043A_DMD_RM_13210ft.pdf ؒ NDBi-043A_DMT_RM_20230804.pdf PTD:223-052 T38001 LETTER OF TRANSMITTAL ؒ NDBi-043A_LWD_RM_13210ft_2MD.pdf ؒ NDBi-043A_LWD_RM_13210ft_2TVD.pdf ؒ NDBi-043A_LWD_RM_13210ft_5MD.pdf ؒ NDBi-043A_LWD_RM_13210ft_5TVD.pdf ؒ جؐؐؐMudlog ؒ جؐؐؐEOW ؒ ؒ NDBi-043 and NDBi-043A Mudlogging Final Report.docx ؒ ؒ NDBi-043 and NDBi-043A Mudlogging Final Report.pdf ؒ ؒ ؒ جؐؐؐMudlogging Daily Reports ؒ ؒ MudloggingDailyReports_Compilation_NDBi-043_NDBi-043A.pdf ؒ ؒ ؒ جؐؐؐMudlogging final data ؒ ؒ ND Bi-043A_G5_GEOISOTOPES_Corrected data_13210ft.las ؒ ؒ NDBi-043A_DrillGas_ASCII_depth_Lithology_13210ft.las ؒ ؒ NDBi-043A_GasRatioLog_13210 ft_MD_2in.pdf ؒ ؒ NDBi-043A_GasRatioLog_13210 ft_MD_5in.pdf ؒ ؒ NDBi-043A_GasRpt_13_20230804.xlsx ؒ ؒ NDBi-043A_Lithology.xlsx ؒ ؒ NDBi-043A_MudLog_13210 ft_MD_2in.pdf ؒ ؒ NDBi-043A_MudLog_13210 ft_MD_5in.pdf ؒ ؒ NDBi-043A_MudLog_Gamma_13210 ft_MD.pdf ؒ ؒ ؒ ؤؐؐؐOil, Gas and Gas Hydrate Shows List ؒ NDBi-043A Show Report #13 10260-10350.pdf ؒ NDBi-043A Show Report #14 10589-10683.pdf ؒ NDBi-043A Show Report #14 10589-10683.xlsm.pdf ؒ ؤؐؐؐWellsite Geologist Formation_Tops_Table_NDBi-043A.pdf Wellsite Geologist FWR NDBi-043 & NDBi-043A.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Dry cutting samples NDBi-043 (50-103-20859-0000) NDBi-043A (50-103-20859-0100) Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 907-375-4607 phone shannon.koh@santos.com DATE: 8/28/2023 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܈Hardcopy ܆Other 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: Samples received 8/17/2023 Entered into RBDMS 8/29/2023 Meredith Guhl Digitally signed by Meredith Guhl Date: 2023.08.29 14:54:24 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, October 16, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Oil Search (Alaska), LLC NDBi-043A PIKKA NDBi-043A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/16/2023 NDBi-043A 50-103-20859-01-00 223-052-0 N SPT 4292 2230520 4000 2976 3420 3418 3411 OTHER P Adam Earl 8/21/2023 MIT-IA tested as per PTD 2230520 to 4000psi, pre-frac. To pre-produce. OA is not tied back to surface, IA and OA is the same void at surface. 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-043A Inspection Date: Tubing OA Packer Depth 52 4260 4209 4185IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE230823071132 BBL Pumped:8.5 BBL Returned:8.4 Monday, October 16, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 9 9 9 per PTD 2230520 James B. Regg Digitally signed by James B. Regg Date: 2023.10.16 13:45:43 -08'00' 0 C ^"Y o --1 � r O n"i o"i v a fD o� N N fD 0 0 0 X Q, M {l1 N Z z Vf a :3 o p v �^ O ;; W rt D O N c O = N O W v O m D a n (D o D c X O O O O O O p N N N N N N X 3 p d fD A N m A N m O) ti OQ H (D O �Da f"D (D m .. C a aCD �. W a 0- cu Q 0 0 3 M. fz 0- Z CA m O D O �n in w in Ln w = 3 '^ opo fa M O O O O O O '8 N O aq rt y N O O N O O 3 '+ o lD N O L N m O 0 0 O O N - - r.Wi - - - N C UQ Ww NJO 0 W N O rt N O lD N O lD Q N O O O N O P" O O O O ffDD (D n G) c fD a d13 O N .fir dQ C O (AD D a N O H N o � fm rt D v ,�2a3 - oSZ-- r"Ictl+ E= Q A I = n 65(0 LalS Solutlon5 GEOLOGSaub Imo AUG 17 2023 Innwatlon Hub Santos DRILL CUTTINGS SAM L WELL NAME : b7-43A WELL API: 50-103-20859-INMbt Date Drilled : FROM: 08/01/2023 1 08/01/2023 Area/Location : North Slope Borough OVEN DRIED SAMPLES (SETS A, B) Box 1 of 2, & Box 2 of 2 Box 1 of 2 Box 2 of 2 1 10160 12050 2 10190 12100 3 10220 12150 4 10250 12200 5 10280 12250 6 10310 12300 7 10340 12350 8 10370 12400 9 10400 12450 10 10430 12500 11 10460 12550 12 10490 12600 13 10520 12650 14 10550 12700 15 10580 12750 16 10610 12800 17 10640 12850 18 10670 12900 19 10700 12950 20 10730 13000 21 10760 13050 22 10790 13100 23 10820 13150 24 10850 13210 25 10880 26 10910 27 10950 28 11000 29 11050 30 11100 31 11150 32 11200 33 11250 34 11300 35 11350 36 11400 37 11450 38 11500 39 11550 40 11600 41 11650 42 11700 43 11750 44 11800 45 11850 46 11900 47 11950 48 12000 Preparation Date: 05-Aug-23 Prepared By: Geolog Contact: lab3270-geolog.com 1 Davies, Stephen F (OGC) From:Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Sent:Tuesday, August 1, 2023 10:42 AM To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); McLellan, Bryan J (OGC); Davis, Rachel (Rachel); Dewhurst, Andrew D (OGC); Villarreal, Aimee (Aimee); Abakar, Abdou (Abdou) Subject:RE: NDBi-043 PTD Nomenclature questions (PTD 223-051 & 223-052) Steve, After discussing the naming convention with our team in more detail we would like to alter the names associated with the PTD’s to be more in line with what is more typically done. I’ve adjusted the table below to show the naming convention we will be adopting on submission for our well data. Feel free to give me a call if you have any questions. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, August 1, 2023 9:05 AM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: ![EXT]: RE: NDBi‐043 PTD Nomenclature questions (PTD 223‐051 & 223‐052) Jacob, To ensure that the AOGCC’s and Santos’ records agree, please confirm the following: Permit to Drill Number API Number Wellbore Name 223‐051 50‐103‐20859‐00‐00 NDBi‐043 223‐052 50‐103‐20859‐01‐00 NDBi‐043A Thanks and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 2 CONFIDENTIALITY NOTICE: This e‐mail message, including any aƩachments, contains informaƟon from the Alaska Oil and Gas ConservaƟon Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidenƟal and/or privileged informaƟon. The unauthorized review, use or disclosure of such informaƟon may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Sent: Wednesday, July 19, 2023 3:28 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: NDBi‐043 PTD Nomenclature questions (PTD 223‐051 & 223‐052) Steve, Based on your note below the best course of action is to carry on calling the main bore NDBi‐043 from spud to TD. The short section that will test the top of the structure will be designated as a plug back (NDBi‐043 PB1) as it is not accessible in the future and nor is it hitting a down hole target with the intent to enhance injection. We are using it to help place the toe of the wellbore in a more optimal location. Please remove the “A” Designation from your records. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, July 18, 2023 8:12 AM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: ![EXT]: RE: NDBi‐043 PTD Nomenclature questions (PTD 223‐051 & 223‐052) Hi Jacob, Per Alaska regulation 20 AAC 258.050(f), AOGCC assigns Permit to Drill and API Numbers, but well names are assigned by the operator. So, the actual name given to each of the planned wells is up to the operator. However, based on experience with other operators and the development of other fields, the clearest archiving of well history records, well CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 logs, and samples for these planned wells will be best achieved by assigning separate Permit to Drill Numbers to each of these wellbores (223‐051 and 223‐052) and assigning them the API Numbers of 50‐103‐20859‐00‐00 and 50‐103‐20859‐ 01‐00, respectively. Historically, the term “plugback” has been employed to refer to a section of a well that is lost due to mechanical problems or is abandoned in order to correct the course of the well during drilling. In AOGCC’s records, such lost or abandoned wellbore sections are given the suffix of “PB1”, “PB2”, etc. and the right‐most four digits of the API number are assigned the suffix of ‐70‐00, ‐71‐00, etc. So for clarity, my suggested name for the initial well is NDB‐043, otherwise if it is named NDB‐043 PB1 as requested and a section of that initial well is lost or abandoned, this lost wellbore section would be named‐‐following historical practice‐‐NDB‐043 PB1 PB1. The second planned wellbore will be a redrill of the initial wellbore to a separate bottom‐hole location for a different purpose (information gathering vs injection). The generally accepted practice for naming the first redrill of an existing well is to append an “A” to the name of the existing wellbore, resulting in the name of NDB‐043A for the second, redrilled wellbore. So, for clarity and in keeping with that practice, I added an “A” to the well name on the Permit to Drill form for the redrilled wellbore. But again, it is the operator’s prerogative to name each of these wells. So, should there be a desire to change the well name shown on either of these Permits to Drill, the operator can achieve this by simply sending an email to me that specifies the current name of the well and the proposed new name for it (e.g., something like “In AOGCC’s records, please change the name of the well assigned the API Number of 50‐103‐20859‐01‐00 from NDB‐043A to NDB‐043.”). In response, the name of the well will be changed in AOGCC’s databases, and a copy of the name‐change request will be placed in the well history file. Please let me know if you have any additional questions. Thanks and Stay Safe, Steve Davies AOGCC Victoria, Can you please give us direction on the appropriate naming convention below? Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: Thompson, Jacob (Jacob) Sent: Tuesday, July 11, 2023 9:12 AM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Cc: Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: NDBi‐043 PTD Nomenclature questions (PTD 223‐051 & 223‐052) Victoria, 4 As we discussed on the phone we would like to know what the proper naming convention is for the two wellbores. We originally had the wells labeled as NDBi‐043 PB1 (PTD 223‐051) & NDBi‐043 (PTD‐052). The permits were returned to us with the following names NDBi‐043 PB1 (PTD 223‐051) & NDBi‐043A (PTD 223‐052). The way the permits were returned do not designate either wellbore as the main wellbore which is causing a bit of confusion. We’d appreciate it if you could clarify if this is the way that we should document these wellbores. As a side note the well signage at the rig was made with our original naming convention and may need to be adjusted if changes are required. Rachel, Victoria requested the last few reports for DW‐02 and NDBi‐043 PB1. Can you please send her the reports? Thanks, <image001.jpg> Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com <image002.png> <image003.png> <image004.png> https://www.santos.com/ Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email From:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:RE: NDBi-043 permit to drill question Date:Wednesday, June 28, 2023 3:13:24 PM Attachments:image003.jpg image004.png image005.png image006.png image007.jpg image008.png Bryan, NT 3.2 Top Reservoir (NT3) represents the top of or productive interval. Our confining layer extends above this depth all the way to the top of the pool which is the top of the Nanushuk. The planned 9-5/8” liner shoe is expected to be at 6,195’ MD and be fully cemented. This will put our 9-5/8” production liner shoe and our 4-1/2” x 9-5/8” liner top packer (Production packer) well within our confining layer with a long section of cement separating it any other zones. With this I believe we meet the requirements outlined in the excerpt from the proposed pool rules below. Let me know if you have any question or comments. Thanks, NDBi-043 Prognosed Tops Formation MD (ft) TVD KB (ft) TVD Path (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1047 901 972 100 7.3 Permafrost Base 1138 990 1061 100 7.6 Middle Schrader Bluff 1798 1590 1661 100 7.8 MCU (Lwr. Sch. Bluff) 2371 2017 2088 100 7.9 Tuluvak Shale 2861 2354 2425 100 7.9 Tuluvak Sand 2941 2409 2480 100 10 Seabee 3924 3085 3156 100 9.1 Nanushuk (Top Pool) 4964 3735 3806 100 8.9 NT6 MFS 5130 3820 3891 100 8.8 NT5 MFS 5313 3906 3977 100 8.8 NT4 MFS 5454 3966 4037 100 8.8 NT3 MFS 6299 4193 4264 100 8.7 NT 3.2 Top Reservoir (NT3) 6585 4214 4285 100 8.7 Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, June 27, 2023 4:06 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: RE: NDBi-043 permit to drill question Jake, The proposed pool rules, which are not yet approved, have the following language. I think I will just copy variance section for this well. a.Packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300 feet measured depth above the planned packer depth. 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: Monday, June 26, 2023 8:13 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Re: NDBi-043 permit to drill question Bryan, Would it be better to request the possibility of needing the variance by amending the permit to drill, or just asking for it if it comes to fruition during operations? It is expected to be just within the 500', but with the uncertainty outlined in my last email it could easily be required if tops come in differently. Glad to amend the PTD if you feel that is the easiest way forward. Thanks, Jacob Sent via the Samsung Galaxy S22 Ultra 5G, an AT&T 5G smartphone Get Outlook for Android From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, June 26, 2023 5:43:12 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: RE: NDBi-043 permit to drill question Jake, Need to request a variance if packer is more than 500’ MD from top injection zone. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Bryan McLellan 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: Friday, June 23, 2023 12:09 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDBi-043 permit to drill question Bryan, The MD of the first open hole packer is not yet know. It will likely be ~500’ from the shoe or ~6,695’ MD. We are drilling into the shelf edge of the reservoir and since this will be the first well to do so there is a bit of uncertainty as to where the edge of the target sand will be. Below is a cartoon depicting what our approach to our bench one wells will be. Well be putting our intermediate casing ~15’ TVD above the top of the Nanushuk 3 maximum flood surface MFS, and entering the Nan3 clean sand as the sand thickens. Sorry for not having a more concise answer, but it’s a bit complicated. Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 3:35 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: RE: NDBi-043 permit to drill question One more question in addition to the one below… What is the MD of the uppermost OH packer? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Thursday, June 22, 2023 2:36 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: NDBi-043 permit to drill question Jake, Looking over your PTD and have a question. In part 15, proposed variance request, can you spell out what the percent of yield you plan to test to, with assumptions such as fluid density and any other relevant info at the time of applying test pressure? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please 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:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:RE: NDBi-043 Anti-collision scan Date:Friday, June 23, 2023 10:56:16 AM Attachments:image002.jpg image003.png image004.png image005.png image006.jpg B-43_Rev_C.0_CR.pdf Brian, There are no existing wells in the clearance scan area. Just planned well to be drilled later in the development. The attached clearance scan is in NAD83, but that does not change the scan results. The clearance scan indicates a failed result against NDBi-030 however, this is because it has crossed a clearance factor threshold requiring us to perform a risk assessment and secure the well while drilling by. As I mentioned above this well does not exist, but we will have a close approach when we drill the NDBi-030 well. Probably more than you wanted to know but just giving you a heads up. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 3:55 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: NDBi-043 Anti-collision scan Jake, Can you send me the anti-collision scan for the directional plan on this well? I am assuming there are no wellbores nearby, but just checking. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:RE: NDBi-043 permit to drill question Date:Friday, June 23, 2023 10:46:19 AM Attachments:image002.jpg image003.png image004.png image005.png image006.jpg Bryan, We plan to test the inner annulus after the 4-1/2” 12.6# P-110S completion is stung into the tie back receptical of the 4-1/2” Liner top packer. The test will be to 4,000 psi surface pressure with a 9.4 ppg completion brine. This will bring the casing to a 1.21 design factor for burst or ~79% of its internal Yield pressure. We are pressure testing the IA to allow maximum back pressure to be held during the frac, which will be ~3,500 -3,600 psi. We have to pressure test to 4,000 psi to allow room to set pop offs, and mechanical trips safely above the back pressure required for the frac. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 2:36 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: NDBi-043 permit to drill question Jake, Looking over your PTD and have a question. In part 15, proposed variance request, can you spell out what the percent of yield you plan to test to, with assumptions such as fluid density and any other relevant info at the time of applying test pressure? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 REFERENCE WELLPATH IDENTIFICATION Operator Santos Well B-43 Field Pikka API/Legal Facility Pikka Wellbore B-43 Slot B-43 REPORT SETUP INFORMATION Projection System NAD83 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitect® 6.0 North Reference True User Meyedavr Scale 0.999907 Report Generated 4/19/2023 at 3:37:47 PM Convergence at slot 0.60° West Database WellArchitectDB WELLPATH LOCATION Local coordinates Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US ft] Northing[US ft] Latitude Longitude Slot Location -230.73 -1478.65 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W Facility Reference Pt 1563416.33 5972657.91 70°20'8.9895"N 150°37'29.0730"W Field Reference Pt 1563416.33 5972657.91 70°20'8.9895"N 150°37'29.0730"W WELLPATH DATUM Calculation method Minimum Curvature Rig on B-43 (RT) to Facility Vertical Datum 70.80ft Horizontal Reference Pt Slot RigonB-43(RT)toMeanSeaLevel 70.80ft Vertical Reference Pt Rig on B-43 (RT) RigonB-43(RT)toGroundLevelat Slot (B-43) 70.80ft MD Reference Pt Rig on B-43 (RT) Field Vertical Reference Mean Sea Level Closest Approach Clearance Summary Report B-43 Rev C.0 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 1 of 3 POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 2.79 Std Dev Ellipse Start MD 47.00ft Surface Position Uncertainty included Declination 14.80° East of TN Dip Angle 80.59°Mag Field Strength 57197 nT Slot Surface Uncertainty @1SD Horizontal 0.500ft Vertical 0.500ft Facility Surface Uncertainty @1SD Horizontal 20.000ft Vertical 3.000ft Positional Uncertainty values in the WELLPATH DATA table are the projection of the ellipsoid of uncertainty onto the vertical and horizontal planes Page 1 of 3Clearance Summary Report 4/19/2023file:///C:/WellArchitect/B-43_Rev_C.0_CR.xml.html REFERENCE WELLPATH IDENTIFICATION Operator Santos Well B-43 Field Pikka API/Legal Facility Pikka Wellbore B-43 Slot B-43 Closest Approach Clearance Summary Report B-43 Rev C.0 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 2 of 3 PROXIMITY-SCAN RULE Rule Name Santos - Stop Drilling HSE Risk (SF <1.25)Rule Based On Ratio Plane of Rule Closest Approach Threshold Value 1.25 IncludeCasing&HoleSize yes Apply Cone of Safety no SURVEY PROGRAM - Ref Wellbore: B-43 Ref Wellpath: B-43 Rev C.0 Start MD [ft] End MD [ft] Positional Uncertainty Model Log Name/Comment Wellbore 47.00 2591.10 OWSG MWD rev2 (MS+IFR2, SAG) B-43 2591.10 6125.00 OWSG MWD rev2 (MS+IFR2, SAG) B-43 6125.00 13438.44 OWSG MWD rev2 (MS+IFR2, SAG) B-43 Page 2 of 3Clearance Summary Report 4/19/2023file:///C:/WellArchitect/B-43_Rev_C.0_CR.xml.html REFERENCE WELLPATH IDENTIFICATION Operator Santos Well B-43 Field Pikka API/Legal Facility Pikka Wellbore B-43 Slot B-43 CALCULATION RANGE & CUTOFF From:47.00ft MD To:13175.91ft MD C-C Cutoff:(none) Closest Approach Clearance Summary Report B-43 Rev C.0 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 3 of 3 OFFSET WELL CLEARANCE SUMMARY (17 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane Offset Facility Offset Slot Offset Well Offset Wellbore Offset Wellpath Wellbore Status C-C Clearance Distance Rule Separation Ratio Ref MD [ft] Min C-C Clear Dist [ft] Diverging from MD [ft] Ref MD of Min Ratio [ft] Min Ratio Min Ratio Dvrg from [ft] Rule Status Pikka B-30 B-30 B-30 B-30 Rev B.0 Planned 13175.91 87.87 13175.91 13175.91 1.13 13175.91 FAIL Pikka B-44 B-44 B-44 B-44 Rev A.0 Planned 443.97 21.20 13175.91 501.54 2.17 13175.91 PASS Pikka B-40 B-40 B-40 B-40 Rev A.0 Planned 1163.12 37.67 1163.12 1268.07 2.57 6247.00 PASS Pikka B-37 B-37 B-37 B-37 Rev A.0 Planned 47.00 118.98 13175.91 13175.91 3.60 13175.91 PASS Pikka B-34 B-34 B-34 B-34 Rev A.0 Planned 47.00 179.11 11247.00 13175.91 3.61 13175.91 PASS Pikka B-41 B-41 B-41 B-41 Rev A.0 Planned 47.00 38.93 7747.00 521.58 4.40 10247.00 PASS Pikka B-38 B-38 B-38 B-38 Rev A.0 Planned 1233.84 73.00 1233.84 1506.87 4.56 5947.00 PASS Pikka B-45 B-45 B-45 B-45 Rev A.0 Planned 47.00 41.24 347.00 610.75 4.60 6547.00 PASS Pikka B-36 B-36 B-36 B-36 Rev A.0 Planned 47.00 139.02 500.00 2647.13 5.70 2647.13 PASS Pikka B-39 B-39 B-39 B-39 Rev A.0 Planned 47.00 78.99 8847.00 11373.44 6.24 11373.44 PASS Pikka B-33 B-33 B-33 B-33 Rev A.0 Planned 1388.00 162.00 1388.00 2149.11 6.87 2247.00 PASS Pikka B-46 B-46 B-46 B-46 Rev A.0 Planned 484.99 61.19 6347.00 602.91 6.99 8347.00 PASS Pikka B-31 B-31 B-31 B-31 Rev A.0 Planned 1365.16 228.35 1365.16 2647.00 7.34 2647.00 PASS Pikka B-51 B-51 B-51 B-51 Rev A.0 Planned 47.00 161.38 13175.91 12885.06 8.70 13175.91 PASS Pikka B-50 B-50 B-50 B-50 Rev A.0 Planned 457.60 141.35 457.60 2720.90 9.71 7247.00 PASS Pikka B-48 B-48 B-48 B-48 Rev A.0 Planned 519.58 101.27 519.58 667.38 11.61 8147.00 PASS Pikka B-49 B-49 B-49 B-49 Rev A.0 Planned 47.00 121.32 13175.91 2304.35 12.22 13175.91 PASS Page 3 of 3Clearance Summary Report 4/19/2023file:///C:/WellArchitect/B-43_Rev_C.0_CR.xml.html Vert Uncert 1sd [ft] 0.50 3.00 Start MD End MD[ft][ft] 47.00 47.00 47.00 300.00 300.00 2590.00 2590.00 6227.00 6227.00 10132.50 10132.50 13208.38 MD TVD North East Grid East Grid North Latitude Longitude Shape[ft][ft][ft][ft][US ft][US ft] 13208.38 4215.80 5782.33 -6989.08 1555008.00 5978297.00 70°21'3.5573"N 150°41'36.5245"W point N/A 4355.80 224.14 -3678.43 1558260.00 5972705.00 70°20'8.9145"N 150°39'59.6849"W polygon Start MD End MD Interval Start TVD End TVD Start N/S Start E/W End N/S End E/W[ft][ft][ft][ft][ft][ft][ft][ft][ft] 47.00 127.00 80.00 47.00 127.00 0.00 0.00 0.00 0 47.00 2590.00 2543.00 47.00 2308.22 0.00 0.00 -444.61 -746.46 47.00 6227.00 6180.00 47.00 4319.98 0.00 0.00 -184.80 -3377.69 6227.00 10132.50 3905.50 4319.98 4282.33 -184.80 -3377.69 3140.32 -5415.44 10132.50 13208.00 3075.50 4282.33 4215.81 3140.32 -5415.44 5782.01 -6988.89 MD Inclination Azimuth TVD TVDSS North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Major Semi Minor Semi Vert Semi Minor Azim[ft][°][°][ft][ft][ft][ft][US ft][US ft][°/100ft][°][°/100ft][°/100ft][ft][ft][ft][ft][°] 0.00 0.00 165.00 0.00 -70.80 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 47.00 0.00 165.00 47.00 -23.80 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 40.01 40.01 6.08 0.00 147.00 0.00 165.00 147.00 76.20 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 40.02 40.02 6.23 255.00 247.00 0.00 165.00 247.00 176.20 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 40.02 40.02 6.23 255.00 347.00 0.00 165.00 347.00 276.20 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 40.03 40.02 6.51 255.00 447.00 0.00 165.00 447.00 376.20 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 40.03 40.03 6.52 255.00 500.00 0.00 165.00 500.00 429.20 0.00 0.00 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W 0.00 0 0.00 0.00 0.00 40.03 40.03 6.53 75.00 547.00 1.41 165.00 547.00 476.20 -0.56 0.15 1561935.67 5972441.84 70°20'6.7134"N 150°38'12.2516"W 3.00 0 3.00 0.00 -0.56 40.03 40.03 6.53 254.91 647.00 4.41 165.00 646.85 576.05 -5.46 1.46 1561936.94 5972436.92 70°20'6.6651"N 150°38'12.2132"W 3.00 0 3.00 0.00 -5.44 40.04 40.04 6.54 253.77 700.00 6.00 165.00 699.63 628.83 -10.11 2.71 1561938.13 5972432.27 70°20'6.6195"N 150°38'12.1769"W 3.00 86.14 3.00 0.00 -10.07 40.05 40.05 6.55 252.55 747.00 6.26 178.02 746.37 675.57 -15.04 3.43 1561938.80 5972427.33 70°20'6.5709"N 150°38'12.1557"W 3.00 73.19 0.54 27.71 -14.68 40.06 40.05 6.55 252.52 847.00 7.68 200.05 845.65 774.85 -26.76 1.33 1561936.58 5972415.63 70°20'6.4557"N 150°38'12.2171"W 3.00 51.322 1.42 22.03 -23.67 40.07 40.07 6.57 235.30 947.00 9.83 213.89 944.49 873.69 -40.13 -5.72 1561929.39 5972402.34 70°20'6.3242"N 150°38'12.4231"W 3.00 37.638 2.16 13.84 -31.55 40.09 40.09 6.58 193.35 1047.00 12.34 222.49 1042.62 971.82 -55.10 -17.71 1561917.25 5972387.49 70°20'6.1769"N 150°38'12.7731"W 3.00 29.198 2.51 8.60 -38.29 40.12 40.11 6.60 194.28 1047.19 12.35 222.50 1042.80 972.00 -55.13 -17.73 1561917.22 5972387.46 70°20'6.1766"N 150°38'12.7739"W 3.00 29.185 2.62 6.84 -38.30 40.13 40.12 6.60 196.20 1138.75 14.81 227.75 1131.80 1061.00 -70.22 -33.01 1561901.79 5972372.54 70°20'6.0282"N 150°38'13.2201"W 3.00 24.084 2.68 5.73 -43.46 40.15 40.13 6.61 199.16 1147.00 15.03 228.14 1139.77 1068.97 -71.64 -34.59 1561900.20 5972371.13 70°20'6.0142"N 150°38'13.2661"W 3.00 23.708 2.74 4.72 -43.87 40.15 40.13 6.61 199.52 1247.00 17.82 232.08 1235.68 1164.88 -89.70 -56.32 1561878.28 5972353.30 70°20'5.8366"N 150°38'13.9008"W 3.00 19.925 2.79 3.94 -48.28 40.18 40.16 6.63 205.42 1347.00 20.67 234.98 1330.09 1259.29 -109.24 -82.85 1561851.55 5972334.04 70°20'5.6444"N 150°38'14.6755"W 3.00 17.189 2.84 2.90 -51.50 40.23 40.19 6.65 211.06 1447.00 23.55 237.20 1422.73 1351.93 -130.19 -114.10 1561820.09 5972313.42 70°20'5.4384"N 150°38'15.5880"W 3.00 15.133 2.88 2.22 -53.52 40.28 40.22 6.68 216.08 1547.00 26.45 238.95 1513.35 1442.55 -152.51 -149.98 1561783.98 5972291.48 70°20'5.2189"N 150°38'16.6359"W 3.00 13.539 2.91 1.76 -54.35 40.35 40.26 6.70 220.36 1647.00 29.38 240.38 1601.71 1530.91 -176.12 -190.39 1561743.32 5972268.29 70°20'4.9866"N 150°38'17.8161"W 3.00 12.274 2.92 1.43 -53.97 40.44 40.30 6.74 223.97 1747.00 32.32 241.58 1687.55 1616.75 -200.97 -235.24 1561698.23 5972243.92 70°20'4.7422"N 150°38'19.1256"W 3.00 11.25 2.94 1.19 -52.39 40.55 40.34 6.78 226.98 1799.82 33.87 242.13 1731.80 1661.00 -214.58 -260.66 1561672.66 5972230.58 70°20'4.6084"N 150°38'19.8682"W 3.00 10.785 2.94 1.05 -51.07 40.64 40.37 6.82 228.89 1847.00 35.26 242.59 1770.65 1699.85 -226.99 -284.38 1561648.82 5972218.42 70°20'4.4863"N 150°38'20.5608"W 3.00 10.407 2.95 0.97 -49.61 40.68 40.38 6.83 229.51 1947.00 38.22 243.47 1850.78 1779.98 -254.11 -337.69 1561595.23 5972191.87 70°20'4.2196"N 150°38'22.1176"W 3.00 9.706 2.95 0.88 -45.65 40.85 40.42 6.89 231.65 2047.00 41.18 244.23 1927.72 1856.92 -282.24 -395.02 1561537.61 5972164.33 70°20'3.9428"N 150°38'23.7918"W 3.00 9.114 2.96 0.77 -40.50 41.05 40.46 6.97 233.48 2147.00 44.14 244.92 2001.25 1930.45 -311.32 -456.22 1561476.12 5972135.90 70°20'3.6568"N 150°38'25.5789"W 3.00 8.613 2.96 0.68 -34.19 41.30 40.50 7.05 235.05 2220.31 46.32 245.37 2052.88 1982.08 -333.19 -503.44 1561428.68 5972114.53 70°20'3.4417"N 150°38'26.9578"W 3.00 0 2.97 0.62 -28.84 41.51 40.53 7.12 236.06 2247.00 46.32 245.37 2071.31 2000.51 -341.24 -520.98 1561411.05 5972106.67 70°20'3.3625"N 150°38'27.4702"W 0.00 0 0.00 0.00 -26.78 41.60 40.55 7.15 236.39 2347.00 46.32 245.37 2140.38 2069.58 -371.37 -586.72 1561345.01 5972077.22 70°20'3.0661"N 150°38'29.3898"W 0.00 0 0.00 0.00 -19.05 41.94 40.59 7.28 237.49 Planned Wellpath Geographic Report - including Position Uncertainty Report by Baker Hughes Operator Area Wellpath Wellbore last revised S i d e t r a c k f r o m User 70.80 ft 70.80 ft E 0.00 ft 0.60 West Slot As Planned (RT) As Planned (RT) Mean Sea Level 70.80 ft Calculation method Field Facility Slot Well Wellbore Pikka B B-43 NDBi-043 NDBi-043 NDBi-043 Rev D.0 06/20/2023 NDBi-043 PB1 Rev B.0 at 10132.50 MD Abakabd01 Minimum curvature N 0.00 ft Magnetic North is 14.69 degrees East of True North 2.00Std Dev WellArchitectDBLocal Projection System North Reference Scale Convergence at Slot Horizontal Reference Point Vertical Reference Point MD Reference Point Field Vertical Reference As Planned (RT) To Facility Vertical Datum As Planned (RT) To Mean Sea Level As Planned (RT) to Ground Level at Slot (B-43) Section Origin X Section Origin Y 20/Jun/2023 at 16:38 using WellArchitect 6.0 Santos Alaska Pikka NAD83 / TM Alaska SP, Zone 4 (5004), US feet True 0.999907 329.24° included 47.00 ft Local East Grid North Longitude Section Azimuth Surface Position Uncertainty Ellipse Starting MD Declination Ellipse Confidence Limit Database Slot Location Facility Reference Pt Field Reference Pt Local North [ft] -230.73 [ft] -1478.65 Grid East [US ft] 1561935.53 1563416.33 1563416.33 [US ft] 5972442.40 5972657.91 5972657.91 Latitude 70°20'6.7188"N 70°20'8.9895"N 70°20'8.9895"N 150°38'12.2560"W 150°37'29.0730"W 150°37'29.0730"W Horiz Uncert 1sd [ft] 0.50 20.00 BH Drift Indicator - Estimated Azimuth (Standard)NDBi-043 PB1 BH Generic gyro - continuous (Standard)NDBi-043 PB1 Positional Uncertainty Model Log Name / Comment Wellbore OWSG MWD rev2 (MS+IFR2, SAG)NDBi-043 PB1 OWSG MWD rev2 (MS+IFR2, SAG)NDBi-043 OWSG MWD rev2 (MS+IFR2, SAG)NDBi-043 PB1 OWSG MWD rev2 (MS+IFR2, SAG)NDBi-043 PB1 NDBi-043 Heel v.0 String / Diameter Wellbore Target Name Comment NDBi-043 TD v.0 8.5in Open Hole NDBi-043 PB1 8.5in Open Hole NDBi-043 20in Conductor NDBi-043 PB1 13.375in Casing Surface NDBi-043 PB1 9.625in Casing Intermediate NDBi-043 PB1 Page 1 of 3 2373.67 46.32 245.37 2158.80 2088.00 -379.41 -604.25 1561327.40 5972069.37 70°20'2.9870"N 150°38'29.9017"W 0.00 0 0.00 0.00 -17.00 42.18 40.61 7.36 238.05 2447.00 46.32 245.37 2209.45 2138.65 -401.51 -652.45 1561278.97 5972047.78 70°20'2.7696"N 150°38'31.3094"W 0.00 0 0.00 0.00 -11.33 42.33 40.63 7.42 238.34 2547.00 46.32 245.37 2278.52 2207.72 -431.65 -718.19 1561212.93 5972018.33 70°20'2.4731"N 150°38'33.2290"W 0.00 0 0.00 0.00 -3.61 42.75 40.68 7.57 239.00 2647.00 46.32 245.37 2347.59 2276.79 -461.79 -783.93 1561146.89 5971988.88 70°20'2.1767"N 150°38'35.1486"W 0.00 0 0.00 0.00 4.11 43.02 40.76 7.51 239.12 2747.00 46.32 245.37 2416.66 2345.86 -491.92 -849.66 1561080.85 5971959.44 70°20'1.8802"N 150°38'37.0681"W 0.00 0 0.00 0.00 11.84 43.13 40.77 7.55 239.30 2847.00 46.32 245.37 2485.73 2414.93 -522.06 -915.40 1561014.80 5971929.99 70°20'1.5837"N 150°38'38.9877"W 0.00 0 0.00 0.00 19.56 43.28 40.78 7.60 239.55 2861.59 46.32 245.37 2495.80 2425.00 -526.46 -924.99 1561005.17 5971925.70 70°20'1.5404"N 150°38'39.2676"W 0.00 0 0.00 0.00 20.68 43.39 40.78 7.63 239.72 2941.22 46.32 245.37 2550.80 2480.00 -550.46 -977.33 1560952.58 5971902.25 70°20'1.3043"N 150°38'40.7962"W 0.00 0 0.00 0.00 26.83 43.47 40.79 7.66 239.83 2947.00 46.32 245.37 2554.79 2483.99 -552.20 -981.14 1560948.76 5971900.55 70°20'1.2872"N 150°38'40.9072"W 0.00 0 0.00 0.00 27.28 43.48 40.79 7.67 239.84 3047.00 46.32 245.37 2623.86 2553.06 -582.34 -1046.87 1560882.72 5971871.10 70°20'0.9907"N 150°38'42.8267"W 0.00 0 0.00 0.00 35.00 43.71 40.80 7.74 240.15 3147.00 46.32 245.37 2692.93 2622.13 -612.48 -1112.61 1560816.68 5971841.66 70°20'0.6942"N 150°38'44.7462"W 0.00 0 0.00 0.00 42.72 43.98 40.82 7.83 240.46 3247.00 46.32 245.37 2762.00 2691.20 -642.61 -1178.34 1560750.64 5971812.21 70°20'0.3977"N 150°38'46.6657"W 0.00 0 0.00 0.00 50.45 44.30 40.84 7.93 240.77 3347.00 46.32 245.37 2831.07 2760.27 -672.75 -1244.08 1560684.60 5971782.77 70°20'0.1012"N 150°38'48.5852"W 0.00 0 0.00 0.00 58.17 44.64 40.86 8.04 241.07 3447.00 46.32 245.37 2900.14 2829.34 -702.89 -1309.82 1560618.56 5971753.32 70°19'59.8047"N 150°38'50.5046"W 0.00 0 0.00 0.00 65.89 45.03 40.88 8.17 241.35 3547.00 46.32 245.37 2969.21 2898.41 -733.03 -1375.55 1560552.51 5971723.88 70°19'59.5081"N 150°38'52.4240"W 0.00 0 0.00 0.00 73.61 45.45 40.91 8.30 241.60 3647.00 46.32 245.37 3038.28 2967.48 -763.16 -1441.29 1560486.47 5971694.43 70°19'59.2116"N 150°38'54.3435"W 0.00 0 0.00 0.00 81.34 45.91 40.94 8.44 241.84 3747.00 46.32 245.37 3107.34 3036.54 -793.30 -1507.02 1560420.43 5971664.99 70°19'58.9151"N 150°38'56.2629"W 0.00 0 0.00 0.00 89.06 46.40 40.97 8.59 242.05 3806.86 46.32 245.37 3148.69 3077.89 -811.34 -1546.37 1560380.90 5971647.36 70°19'58.7376"N 150°38'57.4117"W 0.00 84.752 0.00 0.00 93.68 46.71 40.99 8.69 242.17 3847.00 46.44 247.03 3176.38 3105.58 -823.07 -1572.96 1560354.20 5971635.92 70°19'58.6222"N 150°38'58.1880"W 3.00 83.61 0.30 4.12 97.20 46.93 41.00 8.76 242.25 3920.34 46.72 250.03 3226.80 3156.00 -842.56 -1622.52 1560304.44 5971616.94 70°19'58.4304"N 150°38'59.6352"W 3.00 81.545 0.39 4.10 105.80 47.41 41.03 8.90 242.52 3947.00 46.85 251.11 3245.06 3174.26 -849.02 -1640.84 1560286.05 5971610.68 70°19'58.3668"N 150°39'0.1701"W 3.00 80.802 0.46 4.07 109.62 47.49 41.04 8.92 242.59 4047.00 47.40 255.14 3313.12 3242.32 -870.27 -1710.94 1560215.74 5971590.16 70°19'58.1576"N 150°39'2.2169"W 3.00 78.063 0.55 4.02 127.21 48.11 41.07 9.10 243.09 4147.00 48.08 259.08 3380.38 3309.58 -886.76 -1783.06 1560143.46 5971574.43 70°19'57.9953"N 150°39'4.3228"W 3.00 75.409 0.69 3.95 149.93 48.77 41.12 9.29 243.76 4247.00 48.90 262.94 3446.66 3375.86 -898.44 -1857.01 1560069.40 5971563.53 70°19'57.8802"N 150°39'6.4820"W 3.00 72.854 0.82 3.85 177.71 49.47 41.16 9.48 244.59 4347.00 49.85 266.69 3511.78 3440.98 -905.28 -1932.57 1559993.77 5971557.48 70°19'57.8127"N 150°39'8.6885"W 3.00 70.411 0.95 3.75 210.48 50.21 41.21 9.68 245.55 4447.00 50.91 270.33 3575.56 3504.76 -907.26 -2009.55 1559916.78 5971556.30 70°19'57.7930"N 150°39'10.9364"W 3.00 68.088 1.06 3.64 248.14 51.00 41.27 9.89 246.64 4547.00 52.09 273.86 3637.83 3567.03 -904.38 -2087.74 1559838.64 5971560.00 70°19'57.8212"N 150°39'13.2195"W 3.00 65.891 1.17 3.53 290.61 51.82 41.33 10.11 247.84 4647.00 53.36 277.27 3698.40 3627.60 -896.65 -2166.91 1559759.56 5971568.56 70°19'57.8970"N 150°39'15.5315"W 3.00 63.823 1.28 3.41 337.75 52.68 41.39 10.34 249.15 4747.00 54.73 280.57 3757.12 3686.32 -884.08 -2246.86 1559679.76 5971581.97 70°19'58.0204"N 150°39'17.8661"W 3.00 61.887 1.37 3.30 389.44 53.58 41.46 10.57 250.54 4847.00 56.19 283.76 3813.83 3743.03 -866.70 -2327.36 1559599.45 5971600.18 70°19'58.1911"N 150°39'20.2169"W 3.00 60.08 1.46 3.18 445.54 54.51 41.54 10.82 252.00 4947.00 57.72 286.83 3868.37 3797.57 -844.58 -2408.19 1559518.87 5971623.14 70°19'58.4084"N 150°39'22.5774"W 3.00 58.403 1.53 3.08 505.89 55.47 41.62 11.07 253.53 4962.84 57.97 287.31 3876.80 3806.00 -840.64 -2421.01 1559506.09 5971627.21 70°19'58.4471"N 150°39'22.9518"W 3.00 58.149 1.58 3.01 515.83 56.05 41.67 11.23 254.45 5047.00 59.33 289.80 3920.59 3849.79 -817.77 -2489.13 1559438.22 5971650.80 70°19'58.6719"N 150°39'24.9413"W 3.00 56.851 1.61 2.96 570.33 56.47 41.71 11.33 255.11 5129.45 60.70 292.18 3961.80 3891.00 -792.18 -2555.79 1559371.83 5971677.08 70°19'58.9233"N 150°39'26.8881"W 3.00 55.664 1.67 2.88 626.41 57.40 41.80 11.58 256.58 5137.64 60.84 292.41 3965.80 3895.00 -789.47 -2562.41 1559365.25 5971679.86 70°19'58.9499"N 150°39'27.0813"W 3.00 55.551 1.69 2.84 632.12 57.44 41.80 11.59 256.65 5147.00 61.00 292.67 3970.35 3899.55 -786.33 -2569.96 1559357.72 5971683.08 70°19'58.9808"N 150°39'27.3020"W 3.00 55.422 1.70 2.83 638.68 57.49 41.81 11.60 256.73 5247.00 62.73 295.45 4017.51 3946.71 -750.37 -2650.46 1559277.61 5971719.88 70°19'59.3342"N 150°39'29.6530"W 3.00 54.111 1.73 2.78 710.76 58.53 41.91 11.88 258.38 5314.48 63.93 297.28 4047.80 3977.00 -723.58 -2704.49 1559223.88 5971747.23 70°19'59.5975"N 150°39'31.2309"W 3.00 53.292 1.78 2.71 761.40 59.43 42.00 12.12 259.78 5347.00 64.52 298.15 4061.94 3991.14 -709.97 -2730.41 1559198.10 5971761.11 70°19'59.7313"N 150°39'31.9880"W 3.00 52.915 1.80 2.66 786.36 59.60 42.02 12.16 260.06 5447.00 66.35 300.76 4103.52 4032.72 -665.24 -2809.58 1559119.41 5971806.66 70°20'0.1709"N 150°39'34.3004"W 3.00 51.829 1.83 2.61 865.29 60.69 42.13 12.45 261.74 5457.70 66.55 301.03 4107.80 4037.00 -660.21 -2818.00 1559111.05 5971811.78 70°20'0.2204"N 150°39'34.5463"W 3.00 51.719 1.86 2.57 873.92 61.30 42.20 12.65 262.69 5547.00 68.22 303.30 4142.14 4071.34 -616.32 -2887.77 1559041.75 5971856.39 70°20'0.6517"N 150°39'36.5841"W 3.00 50.848 1.88 2.54 947.31 61.79 42.26 12.76 263.44 5647.00 70.13 305.77 4177.69 4106.89 -563.33 -2964.75 1558965.33 5971910.18 70°20'1.1726"N 150°39'38.8327"W 3.00 49.968 1.91 2.47 1032.22 62.90 42.39 13.06 265.13 5747.00 72.08 308.18 4210.08 4139.28 -506.42 -3040.31 1558890.37 5971967.87 70°20'1.7320"N 150°39'41.0401"W 3.00 49.186 1.95 2.41 1119.77 64.02 42.52 13.38 266.81 5847.00 74.05 310.55 4239.20 4168.40 -445.75 -3114.26 1558817.08 5972029.31 70°20'2.3285"N 150°39'43.2002"W 3.00 48.499 1.97 2.36 1209.73 65.14 42.67 13.70 268.48 5947.00 76.05 312.86 4265.00 4194.20 -381.47 -3186.38 1558745.64 5972094.33 70°20'2.9603"N 150°39'45.3071"W 3.00 47.901 2.00 2.31 1301.85 66.27 42.82 14.03 270.12 6047.00 78.08 315.13 4287.38 4216.58 -313.78 -3256.48 1558676.26 5972162.75 70°20'3.6258"N 150°39'47.3550"W 3.00 47.392 2.02 2.27 1395.87 67.38 42.97 14.36 271.75 6141.39 80.00 317.25 4305.33 4234.53 -246.90 -3320.61 1558612.83 5972230.28 70°20'4.2833"N 150°39'49.2289"W 3.00 0 2.04 2.24 1486.14 68.43 43.12 14.68 273.26 6147.00 80.00 317.25 4306.31 4235.51 -242.85 -3324.36 1558609.12 5972234.38 70°20'4.3231"N 150°39'49.3384"W 0.00 0 0.00 0.00 1491.54 68.49 43.13 14.70 273.34 6191.39 80.00 317.25 4314.02 4243.22 -210.75 -3354.04 1558579.79 5972266.78 70°20'4.6387"N 150°39'50.2054"W 0.00 47.329 0.00 0.00 1534.30 68.98 43.20 14.86 274.04 6247.00 81.13 318.49 4323.13 4252.33 -170.06 -3390.83 1558543.42 5972307.84 70°20'5.0387"N 150°39'51.2806"W 3.00 47.125 2.04 2.23 1588.08 69.73 43.27 14.71 273.96 6330.73 82.85 320.35 4334.80 4264.00 -107.09 -3444.77 1558490.16 5972371.37 70°20'5.6578"N 150°39'52.8565"W 3.00 46.867 2.05 2.22 1669.78 69.91 43.28 14.73 274.18 6347.00 83.18 320.71 4336.78 4265.98 -94.63 -3455.03 1558480.03 5972383.94 70°20'5.7803"N 150°39'53.1564"W 3.00 46.823 2.05 2.20 1685.74 69.93 43.28 14.73 274.20 6447.00 85.24 322.90 4346.87 4276.07 -16.45 -3516.54 1558419.34 5972462.75 70°20'6.5490"N 150°39'54.9538"W 3.00 46.602 2.06 2.19 1784.38 70.15 43.35 14.75 274.53 6547.00 87.30 325.08 4353.38 4282.58 64.27 -3575.20 1558361.54 5972544.07 70°20'7.3425"N 150°39'56.6680"W 3.00 46.46 2.06 2.18 1883.74 70.38 43.48 14.79 274.95 6617.53 88.76 326.62 4355.80 4285.00 122.60 -3614.77 1558322.58 5972602.80 70°20'7.9160"N 150°39'57.8244"W 3.00 46.407 2.07 2.17 1954.10 70.60 43.63 14.84 275.36 6647.00 89.37 327.26 4356.28 4285.48 147.29 -3630.85 1558306.77 5972627.66 70°20'8.1588"N 150°39'58.2942"W 3.00 46.397 2.07 2.17 1983.54 70.64 43.65 14.84 275.43 6737.40 91.24 329.22 4355.80 4285.00 224.14 -3678.43 1558260.00 5972705.00 70°20'8.9145"N 150°39'59.6849"W 3.00 0 2.07 2.17 2073.92 70.87 43.85 14.90 275.93 6747.00 91.24 329.22 4355.59 4284.79 232.39 -3683.34 1558255.18 5972713.30 70°20'8.9955"N 150°39'59.8285"W 0.00 0 0.00 0.00 2083.51 70.90 43.87 14.91 275.99 6847.00 91.24 329.22 4353.43 4282.63 318.28 -3734.50 1558204.92 5972799.71 70°20'9.8401"N 150°40'1.3239"W 0.00 0 0.00 0.00 2183.49 71.18 44.15 14.99 276.60 6947.00 91.24 329.22 4351.26 4280.46 404.18 -3785.66 1558154.66 5972886.13 70°20'10.6846"N 150°40'2.8194"W 0.00 0 0.00 0.00 2283.47 71.48 44.47 15.08 277.28 7047.00 91.24 329.22 4349.10 4278.30 490.07 -3836.82 1558104.41 5972972.54 70°20'11.5291"N 150°40'4.3150"W 0.00 0 0.00 0.00 2383.44 71.81 44.83 15.18 278.02 7147.00 91.24 329.22 4346.94 4276.14 575.96 -3887.99 1558054.15 5973058.96 70°20'12.3737"N 150°40'5.8105"W 0.00 0 0.00 0.00 2483.42 72.17 45.23 15.30 278.82 7247.00 91.24 329.22 4344.77 4273.97 661.86 -3939.15 1558003.90 5973145.38 70°20'13.2182"N 150°40'7.3061"W 0.00 0 0.00 0.00 2583.40 72.55 45.66 15.43 279.68 7347.00 91.24 329.22 4342.61 4271.81 747.75 -3990.31 1557953.64 5973231.79 70°20'14.0627"N 150°40'8.8017"W 0.00 0 0.00 0.00 2683.37 72.97 46.12 15.57 280.60 7447.00 91.24 329.22 4340.44 4269.64 833.64 -4041.47 1557903.38 5973318.21 70°20'14.9072"N 150°40'10.2974"W 0.00 0 0.00 0.00 2783.35 73.42 46.60 15.73 281.58 7547.00 91.24 329.22 4338.28 4267.48 919.54 -4092.64 1557853.13 5973404.63 70°20'15.7517"N 150°40'11.7931"W 0.00 0 0.00 0.00 2883.33 73.91 47.10 15.90 282.61 7647.00 91.24 329.22 4336.12 4265.32 1005.43 -4143.80 1557802.87 5973491.04 70°20'16.5962"N 150°40'13.2888"W 0.00 0 0.00 0.00 2983.30 74.43 47.62 16.07 283.69 7707.81 91.24 329.22 4334.80 4264.00 1057.66 -4174.91 1557772.31 5973543.59 70°20'17.1098"N 150°40'14.1983"W 0.00 0 0.00 0.00 3044.10 74.87 48.04 16.22 284.60 7747.00 91.24 329.22 4333.95 4263.15 1091.33 -4194.96 1557752.62 5973577.46 70°20'17.4407"N 150°40'14.7846"W 0.00 0 0.00 0.00 3083.28 74.99 48.15 16.26 284.83 7847.00 91.24 329.22 4331.79 4260.99 1177.22 -4246.12 1557702.36 5973663.87 70°20'18.2852"N 150°40'16.2804"W 0.00 0 0.00 0.00 3183.26 75.59 48.68 16.46 286.00 7947.00 91.24 329.22 4329.62 4258.82 1263.11 -4297.29 1557652.10 5973750.29 70°20'19.1297"N 150°40'17.7762"W 0.00 0 0.00 0.00 3283.23 76.23 49.22 16.67 287.21 8047.00 91.24 329.22 4327.46 4256.66 1349.01 -4348.45 1557601.85 5973836.71 70°20'19.9742"N 150°40'19.2721"W 0.00 0 0.00 0.00 3383.21 76.92 49.75 16.88 288.45 8147.00 91.24 329.22 4325.30 4254.50 1434.90 -4399.61 1557551.59 5973923.12 70°20'20.8187"N 150°40'20.7680"W 0.00 0 0.00 0.00 3483.19 77.64 50.28 17.11 289.71 8247.00 91.24 329.22 4323.13 4252.33 1520.79 -4450.77 1557501.34 5974009.54 70°20'21.6632"N 150°40'22.2639"W 0.00 0 0.00 0.00 3583.16 78.42 50.80 17.35 290.99 8347.00 91.24 329.22 4320.97 4250.17 1606.69 -4501.93 1557451.08 5974095.96 70°20'22.5077"N 150°40'23.7599"W 0.00 0 0.00 0.00 3683.14 79.24 51.31 17.59 292.28 8447.00 91.24 329.22 4318.80 4248.00 1692.58 -4553.10 1557400.83 5974182.37 70°20'23.3522"N 150°40'25.2559"W 0.00 0 0.00 0.00 3783.12 80.10 51.81 17.84 293.57 8547.00 91.24 329.22 4316.64 4245.84 1778.48 -4604.26 1557350.57 5974268.79 70°20'24.1967"N 150°40'26.7519"W 0.00 0 0.00 0.00 3883.09 81.01 52.29 18.11 294.85 8647.00 91.24 329.22 4314.48 4243.68 1864.37 -4655.42 1557300.31 5974355.20 70°20'25.0411"N 150°40'28.2480"W 0.00 0 0.00 0.00 3983.07 81.97 52.76 18.37 296.12 8747.00 91.24 329.22 4312.31 4241.51 1950.26 -4706.58 1557250.06 5974441.62 70°20'25.8856"N 150°40'29.7441"W 0.00 0 0.00 0.00 4083.04 82.97 53.20 18.65 297.37 8847.00 91.24 329.22 4310.15 4239.35 2036.16 -4757.75 1557199.80 5974528.04 70°20'26.7301"N 150°40'31.2402"W 0.00 0 0.00 0.00 4183.02 84.02 53.63 18.93 298.59 8947.00 91.24 329.22 4307.98 4237.18 2122.05 -4808.91 1557149.55 5974614.45 70°20'27.5745"N 150°40'32.7364"W 0.00 0 0.00 0.00 4283.00 85.10 54.04 19.22 299.78 9047.00 91.24 329.22 4305.82 4235.02 2207.94 -4860.07 1557099.29 5974700.87 70°20'28.4190"N 150°40'34.2326"W 0.00 0 0.00 0.00 4382.97 86.23 54.43 19.52 300.94 9147.00 91.24 329.22 4303.66 4232.86 2293.84 -4911.23 1557049.03 5974787.29 70°20'29.2634"N 150°40'35.7288"W 0.00 0 0.00 0.00 4482.95 87.40 54.81 19.82 302.06 9247.00 91.24 329.22 4301.49 4230.69 2379.73 -4962.40 1556998.78 5974873.70 70°20'30.1079"N 150°40'37.2251"W 0.00 0 0.00 0.00 4582.93 88.61 55.16 20.12 303.14 9347.00 91.24 329.22 4299.33 4228.53 2465.63 -5013.56 1556948.52 5974960.12 70°20'30.9523"N 150°40'38.7214"W 0.00 0 0.00 0.00 4682.90 89.86 55.50 20.44 304.17 9447.00 91.24 329.22 4297.16 4226.36 2551.52 -5064.72 1556898.27 5975046.53 70°20'31.7968"N 150°40'40.2178"W 0.00 0 0.00 0.00 4782.88 91.14 55.82 20.75 305.16 Page 2 of 3 9547.00 91.24 329.22 4295.00 4224.20 2637.41 -5115.88 1556848.01 5975132.95 70°20'32.6412"N 150°40'41.7141"W 0.00 0 0.00 0.00 4882.86 92.45 56.12 21.08 306.11 9647.00 91.24 329.22 4292.84 4222.04 2723.31 -5167.05 1556797.76 5975219.37 70°20'33.4857"N 150°40'43.2106"W 0.00 0 0.00 0.00 4982.83 93.80 56.41 21.40 307.02 9747.00 91.24 329.22 4290.67 4219.87 2809.20 -5218.21 1556747.50 5975305.78 70°20'34.3301"N 150°40'44.7070"W 0.00 0 0.00 0.00 5082.81 95.18 56.68 21.74 307.88 9847.00 91.24 329.22 4288.51 4217.71 2895.09 -5269.37 1556697.24 5975392.20 70°20'35.1745"N 150°40'46.2035"W 0.00 0 0.00 0.00 5182.79 96.58 56.93 22.07 308.70 9947.00 91.24 329.22 4286.34 4215.54 2980.99 -5320.53 1556646.99 5975478.62 70°20'36.0190"N 150°40'47.7000"W 0.00 0 0.00 0.00 5282.76 98.01 57.18 22.41 309.48 10047.00 91.24 329.22 4284.18 4213.38 3066.88 -5371.69 1556596.73 5975565.03 70°20'36.8634"N 150°40'49.1965"W 0.00 0 0.00 0.00 5382.74 99.47 57.41 22.76 310.22 10132.50 91.24 329.22 4282.33 4211.53 3140.32 -5415.44 1556553.76 5975638.92 70°20'37.5854"N 150°40'50.4761"W 0.00 123.287 0.00 0.00 5468.22 100.74 57.60 23.06 310.83 10232.50 91.24 329.22 4280.16 4209.36 3226.21 -5466.60 1556503.51 5975725.33 70°20'38.4298"N 150°40'51.9727"W 0.00 123.287 0.00 0.00 5568.20 101.68 57.66 23.25 311.06 10332.50 91.24 329.22 4278.00 4207.20 3312.11 -5517.76 1556453.25 5975811.75 70°20'39.2742"N 150°40'53.4694"W 0.00 123.287 0.00 0.00 5668.17 102.00 57.66 23.26 311.11 10432.50 91.24 329.22 4275.84 4205.04 3398.00 -5568.92 1556403.00 5975898.17 70°20'40.1186"N 150°40'54.9661"W 0.00 123.287 0.00 0.00 5768.15 102.35 57.67 23.27 311.17 10532.50 91.24 329.22 4273.67 4202.87 3483.90 -5620.09 1556352.74 5975984.58 70°20'40.9630"N 150°40'56.4628"W 0.00 123.287 0.00 0.00 5868.13 102.74 57.68 23.30 311.25 10632.50 91.24 329.22 4271.51 4200.71 3569.79 -5671.25 1556302.48 5976071.00 70°20'41.8074"N 150°40'57.9595"W 0.00 123.287 0.00 0.00 5968.10 103.16 57.70 23.33 311.35 10732.50 91.24 329.22 4269.35 4198.55 3655.68 -5722.41 1556252.23 5976157.42 70°20'42.6518"N 150°40'59.4563"W 0.00 123.287 0.00 0.00 6068.08 103.61 57.73 23.38 311.46 10832.50 91.24 329.22 4267.18 4196.38 3741.58 -5773.57 1556201.97 5976243.83 70°20'43.4962"N 150°41'0.9531"W 0.00 123.287 0.00 0.00 6168.06 104.10 57.76 23.43 311.58 10932.50 91.24 329.22 4265.02 4194.22 3827.47 -5824.73 1556151.72 5976330.25 70°20'44.3406"N 150°41'2.4499"W 0.00 123.287 0.00 0.00 6268.03 104.61 57.80 23.49 311.72 11032.50 91.24 329.22 4262.86 4192.06 3913.37 -5875.90 1556101.46 5976416.67 70°20'45.1850"N 150°41'3.9468"W 0.00 123.287 0.00 0.00 6368.01 105.16 57.84 23.56 311.87 11132.50 91.24 329.22 4260.69 4189.89 3999.26 -5927.06 1556051.21 5976503.08 70°20'46.0294"N 150°41'5.4437"W 0.00 123.287 0.00 0.00 6467.99 105.74 57.89 23.64 312.04 11232.50 91.24 329.22 4258.53 4187.73 4085.16 -5978.22 1556000.95 5976589.50 70°20'46.8738"N 150°41'6.9406"W 0.00 123.287 0.00 0.00 6567.96 106.35 57.95 23.73 312.21 11332.50 91.24 329.22 4256.37 4185.57 4171.05 -6029.38 1555950.70 5976675.92 70°20'47.7182"N 150°41'8.4376"W 0.00 123.287 0.00 0.00 6667.94 106.99 58.00 23.82 312.39 11432.50 91.24 329.22 4254.20 4183.40 4256.94 -6080.54 1555900.44 5976762.33 70°20'48.5626"N 150°41'9.9346"W 0.00 123.287 0.00 0.00 6767.92 107.66 58.07 23.93 312.59 11532.50 91.24 329.22 4252.04 4181.24 4342.84 -6131.70 1555850.19 5976848.75 70°20'49.4069"N 150°41'11.4316"W 0.00 123.287 0.00 0.00 6867.89 108.37 58.13 24.04 312.79 11632.50 91.24 329.22 4249.88 4179.08 4428.73 -6182.86 1555799.94 5976935.17 70°20'50.2513"N 150°41'12.9286"W 0.00 123.287 0.00 0.00 6967.87 109.10 58.20 24.16 313.00 11732.50 91.24 329.22 4247.71 4176.91 4514.63 -6234.02 1555749.68 5977021.58 70°20'51.0957"N 150°41'14.4257"W 0.00 123.287 0.00 0.00 7067.85 109.86 58.28 24.29 313.21 11832.50 91.24 329.22 4245.55 4174.75 4600.52 -6285.18 1555699.43 5977108.00 70°20'51.9401"N 150°41'15.9228"W 0.00 123.287 0.00 0.00 7167.82 110.64 58.35 24.42 313.43 11932.50 91.24 329.22 4243.39 4172.59 4686.42 -6336.34 1555649.17 5977194.42 70°20'52.7844"N 150°41'17.4200"W 0.00 123.287 0.00 0.00 7267.80 111.46 58.43 24.57 313.66 12032.50 91.24 329.22 4241.23 4170.43 4772.31 -6387.50 1555598.92 5977280.84 70°20'53.6288"N 150°41'18.9172"W 0.00 123.287 0.00 0.00 7367.78 112.30 58.51 24.72 313.89 12132.50 91.24 329.22 4239.06 4168.26 4858.21 -6438.67 1555548.66 5977367.25 70°20'54.4732"N 150°41'20.4144"W 0.00 123.287 0.00 0.00 7467.75 113.17 58.60 24.87 314.12 12232.50 91.24 329.22 4236.90 4166.10 4944.10 -6489.83 1555498.41 5977453.67 70°20'55.3175"N 150°41'21.9116"W 0.00 123.287 0.00 0.00 7567.73 114.07 58.69 25.04 314.35 12332.50 91.24 329.22 4234.74 4163.94 5030.00 -6540.99 1555448.16 5977540.09 70°20'56.1619"N 150°41'23.4089"W 0.00 123.287 0.00 0.00 7667.71 114.99 58.77 25.21 314.59 12432.50 91.24 329.22 4232.58 4161.78 5115.89 -6592.15 1555397.90 5977626.51 70°20'57.0062"N 150°41'24.9062"W 0.00 123.287 0.00 0.00 7767.68 115.94 58.86 25.39 314.83 12532.50 91.24 329.22 4230.41 4159.61 5201.79 -6643.31 1555347.65 5977712.92 70°20'57.8506"N 150°41'26.4035"W 0.00 123.287 0.00 0.00 7867.66 116.92 58.95 25.58 315.07 12632.50 91.24 329.22 4228.25 4157.45 5287.68 -6694.47 1555297.40 5977799.34 70°20'58.6949"N 150°41'27.9009"W 0.00 123.287 0.00 0.00 7967.64 117.91 59.05 25.77 315.30 12732.50 91.24 329.22 4226.09 4155.29 5373.58 -6745.63 1555247.14 5977885.76 70°20'59.5393"N 150°41'29.3983"W 0.00 123.287 0.00 0.00 8067.61 118.94 59.14 25.97 315.54 12832.50 91.24 329.22 4223.93 4153.13 5459.47 -6796.79 1555196.89 5977972.18 70°21'0.3836"N 150°41'30.8957"W 0.00 123.287 0.00 0.00 8167.59 119.98 59.23 26.17 315.78 12932.50 91.24 329.22 4221.76 4150.96 5545.37 -6847.95 1555146.64 5978058.59 70°21'1.2280"N 150°41'32.3932"W 0.00 123.287 0.00 0.00 8267.56 121.05 59.33 26.39 316.01 13032.50 91.24 329.22 4219.60 4148.80 5631.26 -6899.11 1555096.38 5978145.01 70°21'2.0723"N 150°41'33.8907"W 0.00 123.287 0.00 0.00 8367.54 122.14 59.42 26.60 316.25 13132.50 91.24 329.22 4217.44 4146.64 5717.16 -6950.26 1555046.13 5978231.43 70°21'2.9166"N 150°41'35.3882"W 0.00 123.287 0.00 0.00 8467.52 123.26 59.51 26.83 316.48 13208.38 91.24 329.22 4215.80 4145.00 5782.33 -6989.08 1555008.00 5978297.00 70°21'3.5573"N 150°41'36.5245"W 0.00 N/A 0.00 0.00 8543.38 124.12 59.59 27.00 316.66 Page 3 of 3 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: _Flow Test______ 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-043 Yes No 9. Property Designation (Lease Number): 10. Field:Pikka Nanushuk 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13,208 Casing Collapse Structural Conductor Surface 2260 Intermediate Liner 4750 Production Liner 9210 Tubing 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Liner Hanger/Liner Top Packer 6,045' 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:Nicklaus Miller Contact Email: Contact Phone: 406-690-2896 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 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):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, ADL 391445, ADL 393020 223-052 900 E Benson Boulevard, Anchorage, AK 99508 50-103-20859-01-00 Oil Search (Alaska), LLC Length Size Proposed Pools: P-110S TVD Burst 13,175 11590 MD 6870 5020 53' 2,230' 4,249' Surface - 128' Surface - 2,591' 20" 13-3/8" 80' 9-5/8"3430' 2590' Perforation Depth MD (ft): 7130' 4-1/2" 4,145'4-1/2" nick.miller@santos.com 2,440' - 6,195' 4,145 08/18/23 Surface - 6,065'6065' 4-1/2" 12.6 ppf 4225' 6,045' - 13,208' m n P 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Completions Team Lead 7/19/2023 By Grace Christianson at 3:16 pm, Jul 19, 2023 323-411 CDW 08/18/2023 SFD 4320' 8/21/2023 6237' SFD 2502'2242' Fracture Stimulate SFD -Flaring associated with cleanup is authorized under 20 AAC 25.235(d)(6). -Well can be flowed back for frac cleanup purposes but cannot be flow tested without further authorization. DSR-8/14/23 Frac Flow back and flow test is authorized under this sundry. Regular production or injection is not allowed without further authorization from the AOGCC due to lack of cement isolation across the Tuluvak sand. BJM 8/22/23 10-407 *&:JLC 8/23/2023 08/23/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.23 11:44:02 -08'00' RBDMS JSB 082423 Page 1 of 19 NDBi-043 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachments B and F 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBDi-043. At the NDBi-043 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-043 location. 4. Plan for freshwater sampling – There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information – Attachment C 6. Assessment of casing and cementing operations – Assessment of casing and cementing operations will be performed after cementing operations are complete. 7. Casing and tubing pressure test information – Pressure testing will be performed upon completion of the well’s lateral section. Attachment J 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachment D 9. a-d Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 1,020 feet (ft) total vertical depth subsea (TVDSS)/1,020 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Assessment of casing and cementing operations will be performed after cementing operations are complete. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 1,020 to 2,300 ft TVDSS/1,280 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelfal setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,300 to 3,150 ft TVDSS/850 ft thick Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Seabee Formation Depth/Thickness: 3,150 to 3,750 ft TVDSS/600 ft thick Lithological Description: The Seabee Fm in the Pikka Unit area consists predominantly of claystone, shale, and volcanic tuff deposited in a deep marine setting. The base of the Seabee Fm grades into a condensed organic shale and provides an excellent seal and confining interval above the Nanushuk Fm reservoirs and also acts as a thick second overlying confining unit. Nanushuk Formation Depth/Thickness: 3,750 to 4,690 ft TVDSS/940 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east (Exhibit B-10). The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Upper Confining Zone Name: Upper Torok Formation (Hue Shale) Depth/Thickness: 4,690 to 5,590 ft TVDSS/900 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is nearly devoid of sand and is composed primarily of shale (Hue Shale) with some thin interbedded siltstones, thereby forming an excellent overlying confining seal above the Lower Torok injection zone. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. Lower Confining Zone Name: Highly Radioactive Zone (HRZ) Hue Shale Depth/Thickness: 6,075 to 6,245 ft TVDSS/170 ft thick Lithological Description: Below the sandy interval of the Lower Torok is the Lower Torok arresting zone, which is approximately 100 feet thick and composed of siltstone and shale. This, in turn, is underlain by the HRZ (Hue Shale) Fm confining interval, which is approximately up to 225-foot-thick condensed marine shale. These units will provide an excellent underlying confining seal. e. Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Stages 1-11 3500 3700 8800 8400 Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Max Pressure (psi) Max Prop Conc. (PPA) 1 13062 4218.8 231.7 330.6 40 6210 8 2 12633 4228.1 226.5 329.6 40 6230 10 10.Mechanical condition of wells transecting the confining zones –DW-02 is within 1/2-mile radius of NDBi-043. Please see attachment B as reference. Location of faults and fractures in wellbore ½ mile radius – Based on the seismic and well data covering the NDBi-043 location. There could be minor faults where the wellbore could be drilling parallel to fault plane in shallow section above the Tuluvak in surface hole. Minor fault crossing in Tuluvak and NT5/6. Santos does not expect that any hydraulic fractures during the stimulation of NDBi-043 will intersect any faults near the wellbore. None of which are any risk to containment of hydraulic fracturing within the reservoir. If there are indications that a fracture has intersected a fault during fracturing operations, Santos will flush and terminate the stage immediately. 11.Suspected fault or fracture that may transect the confining zones. There are no known (seismically resolvable) faults or fractures expected to transect the production section or reservoir confining zone (NT3 MFS) for NDBi-043. 12.Detailed proposed fracturing program –Attachments G & H 13.Flowback procedure –Attachment I Section (b) Casing Pressure Test –We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment J Section (d) Pressure Relieve Valve –Attachment K Proposed Wellbore Schematic –Attachment L 3 12158 4238.4 238.3 265.7 40 6090 12 4 11643 4249.5 240.4 290.0 40 5810 12 5 11128 4260.7 240.4 358.3 40 5524 10 6 10653 4271.0 253.5 319.8 40 5376 12 7 9825 4288.9 266.2 386.6 40 5090 12 8 9347 4299.2 260.1 386.6 30 3274 10 9 8829 4310.4 286.7 311.2 30 3155 10 10 8311 4321.6 334.5 542.8 25 2607 10 11 7833 4332.0 338.2 400.2 20 2150 10 Attachment A Page 2 of 3 Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC AD L 3 9 2 9 6 3 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 8 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 4 9 . 8 4 % D N R - 5 0 . 1 6 % AD L 3 9 2 9 8 4 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 3 0 2 2 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 3 9 . 4 8 % D N R - 6 0 . 5 2 % AD L 3 9 3 0 2 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 1 9 . 2 2 % D N R - 8 0 . 7 8 % AD L 3 9 3 0 2 3 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 4 4 . 0 8 % D N R - 5 5 . 9 2 % AD L 3 9 3 0 1 9 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 % D N R - 6 6 . 9 % AD L 3 9 3 0 1 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 2 9 . 6 7 % D N R - 7 0 . 3 3 % AD L 3 9 3 0 2 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 6 . 5 9 % D N R - 7 3 . 4 1 % AD L 3 9 3 0 1 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 3 1 . 6 9 % D N R - 6 8 . 3 1 % AD L 3 9 3 0 1 7 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 3 0 1 6 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 7 % D N R - 6 6 . 8 3 % AD L 3 9 1 3 2 2 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 2 8 . 2 5 % D N R - 7 1 . 7 5 % AD L 3 9 1 4 4 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 1 . 9 8 % D N R - 5 8 . 0 2 % AD L 3 9 1 4 5 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : A S R C - 4 6 . 4 % D N R - 5 3 . 6 % OI L S E A R C H ( A L A S K A ) , L L C A S U B S I D I A R Y O F S A N T O S L T D ND B i 0 4 3 W E L L A R E A TA R G E T BO T T O M H O L E SU R F A C E L O C A T I O N WE L L T R A J E C T O R Y LE A S E S B O U N D A R Y KU U K P I K B O U N D A R Y .5 - m i l e B u f f e r TO W N S H I P SE C T I O N DA T E : 7 / 1 3 / 2 0 2 3 . R E V : 1 . 0 . B y : J B 0 4 0 0 8 0 0 US F e e t Pr o j e c t : A P - D R L - G E N _ a s s o r t e d La y o u t : A P - D R L - P E - M _ N D B i 0 4 3 _ w e l l _ o w n e r s h i p GC S : N A D 1 9 8 3 S t a t e P l a n e A l a s k a 4 F I P S 5 0 0 4 F e e t 0 1 0 0 2 0 0 Me t e r s PI K K A P R O J E C T ND B Attachment B Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensile (klbs) ID (in) Drift ID (in) Connection 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 Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess Lead TOC Top of the 9-5/8” Liner. Tail Open hole volume + 30% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 11.8 ppg Clean Spacer Lead 12.0ppg Lead: 247.2bbls, 1388cuft, 583sks ExtendaCem, Yield: 2.38 cuft/sk Tail 15.3ppg Tail: 42.5bbls, 238.5cuft, 194sks VersaCem Type I/II– 1.23 cuft/sk Temp BHST 99° F Verification Method Cement returns off of top of liner, Ultra Sonic Wireline log, and Monopole Sonic Notes Job will be mixed on the fly 1. Pump the cement job as per Halliburton Cementing Program. a) Cement job is planned to be pumped as follows: i. 11.8ppg Tuned Spacer ii. Release lead Pump Down Plug (PDP) iii. 12ppg Lead ExtendaCem Slurry iv. 15.3ppg Tail Type I/II Slurry v. Release follow PDP vi. Final displacement with 11.0 ppg VersaClean b) Final volumes will be detailed in the Halliburton Cement Program. c) Lead Liner Wiper Plug shears at 1,000 psi, Follow Liner Wiper Plug shears at 1,200 psi. Ensure pump rate is >3bpm when Pump Down Plugs reach Liner Wiper Plugs. d) Slow pump rate to 2-3 bpm as follow wiper plug nears bump. Bump the wiper plug with 500psi over pump pressure to ensure proper plug seat. Bleed pressure to verify floats are holding. e)If plug does not bump on schedule, pump an additional volume equal to half the shoe track volume before shutting down (~3.0 bbls ½ shoe track). Attachment D Attachment E Redacted M. Guhl 10/12/2023 Attachment G FracCADE* STIMULATION PROPOSAL Operator :Oil Search Well :NDBi43 Field :Pikka Formation :Nanushuk Stages 1 to 11 County : North Slope State : Alaska Country : United States Prepared for : Scott Leahy Service Point : Prudhoe Bay, Alaska Business Phone : 1 907 659 2434 Date Prepared : 07-17-2023 FAX No. : 1 907 659 2538 Prepared by : Alena Lutskaia Phone : 630-780-0058 E-Mail Address :Alutskaya@slb.com * Mark of Schlumberger 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. Disclaimer Notice: # SLB-PrivatePage 1 of 45 Attachment G Section 1: Zone Data (Stage 1; 13062 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughnes s (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4120.0 10.0 0.712 2937 1.46E+06 0.22 1000 Shale 4130.0 15.0 0.695 2876 1.76E+06 0.22 1000 Nanushuk 3 SS 4145.0 15.3 0.678 2815 1.90E+06 0.22 1000 Top Nan CS 4160.3 19.5 0.622 2595 9.00E+05 0.27 1000 Nan SS 4179.8 2.0 0.689 2880 2.67E+06 0.23 2500 Nan CS 4181.8 1.5 0.635 2655 1.29E+06 0.26 1000 Nan CS 4183.3 4.5 0.616 2578 6.44E+05 0.28 1000 Nan DS 4187.8 3.5 0.689 2886 1.77E+06 0.26 1500 Nan DS 4191.3 14.5 0.649 2726 1.39E+06 0.26 1500 Nan CS 4205.8 1.5 0.643 2706 1.15E+06 0.27 1000 Nan CS 4207.3 12.5 0.627 2641 8.82E+05 0.27 1000 Nan DS 4219.8 2.0 0.649 2739 1.40E+06 0.26 1500 Nan CS 4221.8 9.0 0.605 2558 8.54E+05 0.27 1000 Nan DS 4230.8 7.0 0.651 2755 1.40E+06 0.26 1500 Nan DS 4237.8 9.0 0.638 2705 1.13E+06 0.27 1500 Nan DS 4246.8 3.5 0.64 2720 1.69E+06 0.26 1500 Nan DS 4250.3 5.0 0.627 2665 7.57E+05 0.27 1000 Nan DS 4255.3 2.0 0.687 2925 1.80E+06 0.25 1500 Nan CS 4257.3 10.5 0.612 2607 7.36E+05 0.27 1000 Nan CS 4267.8 3.5 0.634 2705 1.10E+06 0.27 1000 Nan CS 4271.3 2.0 0.612 2614 6.70E+05 0.28 1000 Nan CS 4273.3 5.5 0.647 2768 1.30E+06 0.26 1000 Nan DS 4278.8 3.5 0.687 2939 1.53E+06 0.26 1500 Nan DS 4282.3 3.5 0.63 2701 1.19E+06 0.27 1500 Nan DS 4285.8 5.5 0.683 2928 1.42E+06 0.26 1500 Nan CS 4291.3 10.5 0.627 2693 1.17E+06 0.27 1000 Nan DS 4301.8 1.5 0.653 2811 1.38E+06 0.26 1500 Nan DS 4303.3 5.0 0.62 2671 1.14E+06 0.27 1500 Nan DS 4308.3 2.0 0.652 2809 1.56E+06 0.26 1500 Nan DS 4310.3 4.0 0.623 2688 8.96E+05 0.27 1500 Nan DS 4314.3 2.0 0.666 2876 1.66E+06 0.26 1500 Nan DS 4316.3 10.0 0.627 2709 9.81E+05 0.27 1500 Nan DS 4326.3 4.0 0.654 2831 1.63E+06 0.26 1500 Nan DS 4330.3 4.0 0.686 2974 1.75E+06 0.26 1500 Nan DS 4334.3 9.5 0.642 2784 1.33E+06 0.26 1500 Nan DS 4343.8 2.0 0.61 2649 7.82E+05 0.27 1000 Nan DS 4345.8 9.5 0.684 2975 1.69E+06 0.26 1500 Nan DS 4355.3 2.0 0.646 2812 1.37E+06 0.26 1500 Shale 4357.3 2.0 0.689 3002 2.67E+06 0.23 2500 Nan DS 4359.3 2.0 0.634 2765 1.09E+06 0.27 1500 Shale 4361.3 2.0 0.689 3005 2.67E+06 0.23 2500 Nan DS 4363.3 4.0 0.652 2844 1.29E+06 0.26 1500 Shale 4367.3 19.5 0.689 3015 2.67E+06 0.23 2500 Nan DS 4386.8 2.0 0.643 2820 1.36E+06 0.26 1500 Shale 4388.8 2.0 0.689 3024 2.67E+06 0.23 2500 Nan DS 4390.8 8.0 0.65 2855 1.37E+06 0.26 1500 Nan DS 4398.8 8.0 0.645 2841 1.56E+06 0.26 1500 Shale 4406.8 20.0 0.689 3042 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 2 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4120.0 0.1 0.001 1.0 1890 Shale 4130.0 0.1 0.001 1.0 1898 Nanushuk 3 SS 4145.0 3.8 0.005 10.0 1905 Top Nan CS 4160.3 19.5 30.655 23.7 1915 Nan SS 4179.8 0.8 5 10.0 1924 Nan CS 4181.8 1.5 2.095 16.9 1925 Nan CS 4183.3 4.5 48.388 26.6 1926 Nan DS 4187.8 2.5 0.478 12.4 1928 Nan DS 4191.3 10.1 15.008 17.7 1930 Nan CS 4205.8 1.5 3.661 17.6 1937 Nan CS 4207.3 12.5 34.723 23.9 1937 Nan DS 4219.8 1.4 1.697 15.6 1943 Nan CS 4221.8 9.0 54.319 24.4 1944 Nan DS 4230.8 4.9 3.61 14.8 1948 Nan DS 4237.8 6.3 22.986 20.4 1952 Nan DS 4246.8 2.5 0.835 14.0 1956 Nan DS 4250.3 3.5 65.392 23.4 1957 Nan DS 4255.3 1.4 0.006 10.5 1960 Nan CS 4257.3 10.5 100.832 25.6 1961 Nan CS 4267.8 3.5 17.434 20.5 1966 Nan CS 4271.3 2.0 161.343 26.3 1967 Nan CS 4273.3 5.5 4.627 18.4 1968 Nan DS 4278.8 2.5 5.075 14.8 1971 Nan DS 4282.3 2.5 8.651 19.4 1972 Nan DS 4285.8 3.8 10.205 16.0 1974 Nan CS 4291.3 10.5 17.356 20.1 1977 Nan DS 4301.8 1.0 3.106 14.8 1982 Nan DS 4303.3 3.5 52.863 20.6 1982 Nan DS 4308.3 1.4 2.277 14.1 1985 Nan DS 4310.3 2.8 122.778 23.1 1986 Nan DS 4314.3 1.4 0.333 12.5 1987 Nan DS 4316.3 7.0 39.939 21.2 1988 Nan DS 4326.3 2.8 0.748 13.3 1993 Nan DS 4330.3 2.8 0.009 10.9 1995 Nan DS 4334.3 6.7 5.399 16.7 1997 Nan DS 4343.8 1.4 160.618 24.9 2001 Nan DS 4345.8 6.7 0.033 11.5 2002 Nan DS 4355.3 1.4 6.733 16.2 2007 Shale 4357.3 0.1 0.001 1.0 2008 Nan DS 4359.3 1.4 29.48 19.6 2009 Shale 4361.3 0.1 0.001 1.0 2009 Nan DS 4363.3 2.8 8.473 16.6 2010 Shale 4367.3 0.1 0.001 1.0 2012 Nan DS 4386.8 1.4 2.185 16.4 2021 Shale 4388.8 0.1 0.001 1.0 2022 Nan DS 4390.8 5.6 2.645 15.9 2023 Nan DS 4398.8 5.6 2.026 14.4 2027 Shale 4406.8 0.1 0.001 10.0 2031 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 3 of 45 Attachment G Section 2: Propped Fracture Schedule (Stage 1; 13062 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 300.0 22 0 1.0 PPA 40 YF122ST 95.8 22 1.0 2.0 PPA 40 YF122ST 160.9 22 2.0 3.0 PPA 40 YF122ST 176.8 22 3.0 4.0 PPA 40 YF122ST 170.2 22 4.0 5.0 PPA 40 YF122ST 164.1 22 5.0 6.0 PPA 40 YF122ST 158.4 22 6.0 7.0 PPA 40 YF122ST 114.8 22 7.0 8.0 PPA 40 YF122ST 103.7 22 8.0 Flush 40 WF122 195.1 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1445 bbl of YF122ST 195.1 bbl of WF122 211387 lb of 16/20 C-Lite % PAD Clean 20.8 % PAD Dirty 18.0 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 300.0 300 300 300 0 0 4120 7.5 7.5 1.0 PPA 95.8 396 100 400 4024 4024 4097 2.5 10.0 2.0 PPA 160.9 557 175 575 13517 17541 4232 4.4 14.4 3.0 PPA 176.8 734 200 775 22275 39816 4623 5.0 19.4 4.0 PPA 170.2 904 200 975 28594 68410 4983 5.0 24.4 5.0 PPA 164.1 1068 200 1175 34460 102870 5329 5.0 29.4 6.0 PPA 158.4 1226 200 1375 39918 142788 5681 5.0 34.4 7.0 PPA 114.8 1341 150 1525 33758 176546 5933 3.8 38.2 8.0 PPA 103.7 1445 140 1665 34841 211387 6115 3.5 41.7 Flush 195.1 1640 195.1 1860.1 0 211387 5720 4.9 46.6 Job Execution Job Description Prop. Type and MeshFluid Name Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 330.6 ft with an average conductivity (Kfw) of 13390 md.ft. Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 # SLB-PrivatePage 4 of 45 Attachment G Section 3: Propped Fracture Simulation (Stage 1; 13062 ft MD) Stage 1 MD 13062 ft Initial Fracture Top TVD 4156.0 ft Initial Fracture Bottom TVD 4340.0 ft Propped Fracture Half-Length 330.6 ft EOJ Hyd Height at Well 231.7 ft Average Propped Width 0.171 in Net Pressure 268 psi Max Surface Pressure 6210 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivi ty (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 82.6 7.7 0.189 139.1 1.63 237.9 16546 82.6 165.3 6.7 0.189 205.6 1.67 246 16314 165.3 247.9 6.6 0.178 189.7 1.58 245.8 15328 247.9 330.6 3.4 0.135 134.4 1.26 336.7 11114 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-PrivatePage 5 of 45 Attachment G Section 4: Zone Data (Stage 2; 12633 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughnes s (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4126.1 10.0 0.711 2937 1.46E+06 0.22 1000 Shale 4136.1 15.0 0.695 2880 1.76E+06 0.22 1000 Nanushuk 3 SS 4151.1 15.3 0.678 2820 1.90E+06 0.22 1000 Top Nan CS 4166.4 19.5 0.621 2595 9.00E+05 0.27 1000 Nan SS 4185.9 2.0 0.688 2880 2.67E+06 0.23 2500 Nan CS 4187.9 1.5 0.634 2655 1.29E+06 0.26 1000 Nan CS 4189.4 4.5 0.616 2582 6.44E+05 0.28 1000 Nan DS 4193.9 3.5 0.688 2886 1.77E+06 0.26 1500 Nan DS 4197.4 14.5 0.648 2726 1.39E+06 0.26 1500 Nan CS 4211.9 1.5 0.642 2706 1.15E+06 0.27 1000 Nan CS 4213.4 12.5 0.626 2641 8.82E+05 0.27 1000 Nan DS 4225.9 2.0 0.649 2743 1.40E+06 0.26 1500 Nan CS 4227.9 9.0 0.604 2558 8.54E+05 0.27 1000 Nan DS 4236.9 7.0 0.65 2755 1.40E+06 0.26 1500 Nan DS 4243.9 9.0 0.637 2705 1.13E+06 0.27 1500 Nan DS 4252.9 3.5 0.639 2720 1.69E+06 0.26 1500 Nan DS 4256.4 5.0 0.626 2665 7.57E+05 0.27 1000 Nan DS 4261.4 2.0 0.686 2925 1.80E+06 0.25 1500 Nan CS 4263.4 10.5 0.611 2607 7.36E+05 0.27 1000 Nan CS 4273.9 3.5 0.633 2705 1.10E+06 0.27 1000 Nan CS 4277.4 2.0 0.611 2614 6.70E+05 0.28 1000 Nan CS 4279.4 5.5 0.646 2768 1.30E+06 0.26 1000 Nan DS 4284.9 3.5 0.686 2939 1.53E+06 0.26 1500 Nan DS 4288.4 3.5 0.63 2701 1.19E+06 0.27 1500 Nan DS 4291.9 5.5 0.682 2928 1.42E+06 0.26 1500 Nan CS 4297.4 10.5 0.626 2693 1.17E+06 0.27 1000 Nan DS 4307.9 1.5 0.652 2811 1.38E+06 0.26 1500 Nan DS 4309.4 5.0 0.619 2671 1.14E+06 0.27 1500 Nan DS 4314.4 2.0 0.651 2809 1.56E+06 0.26 1500 Nan DS 4316.4 4.0 0.622 2688 8.96E+05 0.27 1500 Nan DS 4320.4 2.0 0.666 2876 1.66E+06 0.26 1500 Nan DS 4322.4 10.0 0.627 2713 9.81E+05 0.27 1500 Nan DS 4332.4 4.0 0.654 2835 1.63E+06 0.26 1500 Nan DS 4336.4 4.0 0.686 2974 1.75E+06 0.26 1500 Nan DS 4340.4 9.5 0.641 2784 1.33E+06 0.26 1500 Nan DS 4349.9 2.0 0.609 2649 7.82E+05 0.27 1000 Nan DS 4351.9 9.5 0.683 2975 1.69E+06 0.26 1500 Nan DS 4361.4 2.0 0.645 2812 1.37E+06 0.26 1500 Shale 4363.4 2.0 0.688 3002 2.67E+06 0.23 2500 Nan DS 4365.4 2.0 0.633 2765 1.09E+06 0.27 1500 Shale 4367.4 2.0 0.688 3005 2.67E+06 0.23 2500 Nan DS 4369.4 4.0 0.651 2844 1.29E+06 0.26 1500 Shale 4373.4 19.5 0.688 3015 2.67E+06 0.23 2500 Nan DS 4392.9 2.0 0.642 2820 1.36E+06 0.26 1500 Shale 4394.9 2.0 0.688 3024 2.67E+06 0.23 2500 Nan DS 4396.9 8.0 0.649 2855 1.37E+06 0.26 1500 Nan DS 4404.9 8.0 0.644 2841 1.56E+06 0.26 1500 Shale 4412.9 20.0 0.688 3042 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 6 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4126.1 0.1 0.001 1.0 1890 Shale 4136.1 0.1 0.001 1.0 1898 Nanushuk 3 SS 4151.1 3.8 0.005 10.0 1905 Top Nan CS 4166.4 19.5 30.655 23.7 1915 Nan SS 4185.9 0.8 5 10.0 1924 Nan CS 4187.9 1.5 2.095 16.9 1925 Nan CS 4189.4 4.5 48.388 26.6 1926 Nan DS 4193.9 2.5 0.478 12.4 1928 Nan DS 4197.4 10.1 15.008 17.7 1930 Nan CS 4211.9 1.5 3.661 17.6 1937 Nan CS 4213.4 12.5 34.723 23.9 1937 Nan DS 4225.9 1.4 1.697 15.6 1943 Nan CS 4227.9 9.0 54.319 24.4 1944 Nan DS 4236.9 4.9 3.61 14.8 1948 Nan DS 4243.9 6.3 22.986 20.4 1952 Nan DS 4252.9 2.5 0.835 14.0 1956 Nan DS 4256.4 3.5 65.392 23.4 1957 Nan DS 4261.4 1.4 0.006 10.5 1960 Nan CS 4263.4 10.5 100.832 25.6 1961 Nan CS 4273.9 3.5 17.434 20.5 1966 Nan CS 4277.4 2.0 161.343 26.3 1967 Nan CS 4279.4 5.5 4.627 18.4 1968 Nan DS 4284.9 2.5 5.075 14.8 1971 Nan DS 4288.4 2.5 8.651 19.4 1972 Nan DS 4291.9 3.8 10.205 16.0 1974 Nan CS 4297.4 10.5 17.356 20.1 1977 Nan DS 4307.9 1.0 3.106 14.8 1982 Nan DS 4309.4 3.5 52.863 20.6 1982 Nan DS 4314.4 1.4 2.277 14.1 1985 Nan DS 4316.4 2.8 122.778 23.1 1986 Nan DS 4320.4 1.4 0.333 12.5 1987 Nan DS 4322.4 7.0 39.939 21.2 1988 Nan DS 4332.4 2.8 0.748 13.3 1993 Nan DS 4336.4 2.8 0.009 10.9 1995 Nan DS 4340.4 6.7 5.399 16.7 1997 Nan DS 4349.9 1.4 160.618 24.9 2001 Nan DS 4351.9 6.7 0.033 11.5 2002 Nan DS 4361.4 1.4 6.733 16.2 2007 Shale 4363.4 0.1 0.001 1.0 2008 Nan DS 4365.4 1.4 29.48 19.6 2009 Shale 4367.4 0.1 0.001 1.0 2009 Nan DS 4369.4 2.8 8.473 16.6 2010 Shale 4373.4 0.1 0.001 1.0 2012 Nan DS 4392.9 1.4 2.185 16.4 2021 Shale 4394.9 0.1 0.001 1.0 2022 Nan DS 4396.9 5.6 2.645 15.9 2023 Nan DS 4404.9 5.6 2.026 14.4 2027 Shale 4412.9 0.1 0.001 10.0 2031 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 7 of 45 Attachment G Section 5: Propped Fracture Schedule (Stage 2; 12633 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 143.7 22 1.0 3.0 PPA 40 YF122ST 176.8 22 3.0 5.0 PPA 40 YF122ST 196.9 22 5.0 7.0 PPA 40 YF122ST 164.6 22 7.0 9.0 PPA 40 YF122ST 154.2 22 9.0 10.0 PPA 40 YF122ST 132.2 22 10.0 Flush 40 WF122 187.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1243 bbl of YF122ST 187.5 bbl of WF122 231862 lb of 16/20 C-Lite % PAD Clean 22.1 % PAD Dirty 18.5 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 275.0 275 275 275 0 0 4030 6.9 6.9 1.0 PPA 143.7 419 150 425 6036 6036 3998 3.8 10.7 3.0 PPA 176.8 596 200 625 22275 28311 4193 5.0 15.7 5.0 PPA 196.9 792 240 865 41351 69662 4927 6.0 21.7 7.0 PPA 164.6 957 215 1080 48387 118049 5520 5.4 27.1 9.0 PPA 154.2 1111 215 1295 58305 176354 5959 5.4 32.5 10.0 PPA 132.2 1243 190 1485 55508 231862 6179 4.8 37.3 Flush 187.5 1431 187.5 1672.5 0 231862 5764 4.7 42.0 Carbolite 16/20 Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 329.6 ft with an average conductivity (Kfw) of 15920 md.ft. Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Job Execution Job Description Prop. Type and MeshFluid Name # SLB-PrivatePage 8 of 45 Attachment G Section 6: Propped Fracture Simulation (Stage 2; 12633 ft MD) Stage 2 MD 12633 ft Initial Fracture Top TVD 4157.0 ft Initial Fracture Bottom TVD 4347.0 ft Propped Fracture Half-Length 329.6 ft EOJ Hyd Height at Well 226.5 ft Average Propped Width 0.201 in Net Pressure 355 psi Max Surface Pressure 6230 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivi ty (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 82.4 10 0.225 137.9 1.94 194.2 20169 82.4 164.8 8.9 0.229 194.7 2.03 189.5 20367 164.8 247.2 8 0.21 175.6 1.87 194 18568 247.2 329.6 2.9 0.15 120.8 1.41 276.7 12445 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-PrivatePage 9 of 45 Attachment G Section 7: Zone Data (Stage 3; 12158 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughnes s (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4126.2 10.0 0.711 2937 1.46E+06 0.22 1000 Shale 4136.2 15.0 0.695 2880 1.76E+06 0.22 1000 Nanushuk 3 SS 4151.2 15.3 0.678 2820 1.90E+06 0.22 1000 Top Nan CS 4166.5 19.5 0.621 2595 9.00E+05 0.27 1000 Nan SS 4186.0 2.0 0.688 2880 2.67E+06 0.23 2500 Nan CS 4188.0 1.5 0.634 2655 1.29E+06 0.26 1000 Nan CS 4189.5 4.5 0.616 2582 6.44E+05 0.28 1000 Nan DS 4194.0 3.5 0.688 2886 1.77E+06 0.26 1500 Nan DS 4197.5 14.5 0.648 2726 1.39E+06 0.26 1500 Nan CS 4212.0 1.5 0.642 2706 1.15E+06 0.27 1000 Nan CS 4213.5 12.5 0.626 2641 8.82E+05 0.27 1000 Nan DS 4226.0 2.0 0.649 2743 1.40E+06 0.26 1500 Nan CS 4228.0 9.0 0.604 2558 8.54E+05 0.27 1000 Nan DS 4237.0 7.0 0.65 2755 1.40E+06 0.26 1500 Nan DS 4244.0 9.0 0.637 2705 1.13E+06 0.27 1500 Nan DS 4253.0 3.5 0.639 2720 1.69E+06 0.26 1500 Nan DS 4256.5 5.0 0.626 2665 7.57E+05 0.27 1000 Nan DS 4261.5 2.0 0.686 2925 1.80E+06 0.25 1500 Nan CS 4263.5 10.5 0.611 2607 7.36E+05 0.27 1000 Nan CS 4274.0 3.5 0.633 2705 1.10E+06 0.27 1000 Nan CS 4277.5 2.0 0.611 2614 6.70E+05 0.28 1000 Nan CS 4279.5 5.5 0.646 2768 1.30E+06 0.26 1000 Nan DS 4285.0 3.5 0.686 2939 1.53E+06 0.26 1500 Nan DS 4288.5 3.5 0.63 2701 1.19E+06 0.27 1500 Nan DS 4292.0 5.5 0.682 2928 1.42E+06 0.26 1500 Nan CS 4297.5 10.5 0.626 2693 1.17E+06 0.27 1000 Nan DS 4308.0 1.5 0.652 2811 1.38E+06 0.26 1500 Nan DS 4309.5 5.0 0.619 2671 1.14E+06 0.27 1500 Nan DS 4314.5 2.0 0.651 2809 1.56E+06 0.26 1500 Nan DS 4316.5 4.0 0.622 2688 8.96E+05 0.27 1500 Nan DS 4320.5 2.0 0.666 2876 1.66E+06 0.26 1500 Nan DS 4322.5 10.0 0.627 2713 9.81E+05 0.27 1500 Nan DS 4332.5 4.0 0.654 2835 1.63E+06 0.26 1500 Nan DS 4336.5 4.0 0.685 2974 1.75E+06 0.26 1500 Nan DS 4340.5 9.5 0.641 2784 1.33E+06 0.26 1500 Nan DS 4350.0 2.0 0.609 2649 7.82E+05 0.27 1000 Nan DS 4352.0 9.5 0.683 2975 1.69E+06 0.26 1500 Nan DS 4361.5 2.0 0.645 2812 1.37E+06 0.26 1500 Shale 4363.5 2.0 0.688 3002 2.67E+06 0.23 2500 Nan DS 4365.5 2.0 0.633 2765 1.09E+06 0.27 1500 Shale 4367.5 2.0 0.688 3005 2.67E+06 0.23 2500 Nan DS 4369.5 4.0 0.651 2844 1.29E+06 0.26 1500 Shale 4373.5 19.5 0.688 3015 2.67E+06 0.23 2500 Nan DS 4393.0 2.0 0.642 2820 1.36E+06 0.26 1500 Shale 4395.0 2.0 0.688 3024 2.67E+06 0.23 2500 Nan DS 4397.0 8.0 0.649 2855 1.37E+06 0.26 1500 Nan DS 4405.0 8.0 0.644 2841 1.56E+06 0.26 1500 Shale 4413.0 20.0 0.688 3042 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 10 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4126.2 0.1 0.001 1.0 1890 Shale 4136.2 0.1 0.001 1.0 1898 Nanushuk 3 SS 4151.2 3.8 0.005 10.0 1905 Top Nan CS 4166.5 19.5 30.655 23.7 1915 Nan SS 4186.0 0.8 5.000 10.0 1924 Nan CS 4188.0 1.5 2.095 16.9 1925 Nan CS 4189.5 4.5 48.388 26.6 1926 Nan DS 4194.0 2.5 0.478 12.4 1928 Nan DS 4197.5 10.1 15.008 17.7 1930 Nan CS 4212.0 1.5 3.661 17.6 1937 Nan CS 4213.5 12.5 34.723 23.9 1937 Nan DS 4226.0 1.4 1.697 15.6 1943 Nan CS 4228.0 9.0 54.319 24.4 1944 Nan DS 4237.0 4.9 3.610 14.8 1948 Nan DS 4244.0 6.3 22.986 20.4 1952 Nan DS 4253.0 2.5 0.835 14.0 1956 Nan DS 4256.5 3.5 65.392 23.4 1957 Nan DS 4261.5 1.4 0.006 10.5 1960 Nan CS 4263.5 10.5 100.832 25.6 1961 Nan CS 4274.0 3.5 17.434 20.5 1966 Nan CS 4277.5 2.0 161.343 26.3 1967 Nan CS 4279.5 5.5 4.627 18.4 1968 Nan DS 4285.0 2.5 5.075 14.8 1971 Nan DS 4288.5 2.5 8.651 19.4 1972 Nan DS 4292.0 3.8 10.205 16.0 1974 Nan CS 4297.5 10.5 17.356 20.1 1977 Nan DS 4308.0 1.0 3.106 14.8 1982 Nan DS 4309.5 3.5 52.863 20.6 1982 Nan DS 4314.5 1.4 2.277 14.1 1985 Nan DS 4316.5 2.8 122.778 23.1 1986 Nan DS 4320.5 1.4 0.333 12.5 1987 Nan DS 4322.5 7.0 39.939 21.2 1988 Nan DS 4332.5 2.8 0.748 13.3 1993 Nan DS 4336.5 2.8 0.009 10.9 1995 Nan DS 4340.5 6.7 5.399 16.7 1997 Nan DS 4350.0 1.4 160.618 24.9 2001 Nan DS 4352.0 6.7 0.033 11.5 2002 Nan DS 4361.5 1.4 6.733 16.2 2007 Shale 4363.5 0.1 0.001 1.0 2008 Nan DS 4365.5 1.4 29.480 19.6 2009 Shale 4367.5 0.1 0.001 1.0 2009 Nan DS 4369.5 2.8 8.473 16.6 2010 Shale 4373.5 0.1 0.001 1.0 2012 Nan DS 4393.0 1.4 2.185 16.4 2021 Shale 4395.0 0.1 0.001 1.0 2022 Nan DS 4397.0 5.6 2.645 15.9 2023 Nan DS 4405.0 5.6 2.026 14.4 2027 Shale 4413.0 0.1 0.001 10.0 2031 Formation Transmissibility Properties Zone Name # SLB-PrivatePage 11 of 45 Attachment G Section 8: Propped Fracture Schedule (Stage 3; 12158 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 260.0 22 0.0 1.0 PPA 40 YF122ST 134.1 22 1.0 2.0 PPA 40 YF122ST 147.1 22 2.0 4.0 PPA 40 YF122ST 153.2 22 4.0 6.0 PPA 40 YF122ST 142.6 22 6.0 8.0 PPA 40 YF122ST 133.3 22 8.0 10.0 PPA 40 YF122ST 125.2 22 10.0 12.0 PPA 40 YF122ST 98.4 22 12.0 Flush 40 WF122 179.9 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1194 bbl of YF122ST 179.9 bbl of WF122 226602 lb of 16/20 C-Lite % PAD Clean 21.8 % PAD Dirty 18.2 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 260.0 260 260 260 0 0 3921 6.5 6.5 1.0 PPA 134.1 394 140 400 5633 5633 3888 3.5 10.0 2.0 PPA 147.1 541 160 560 12358 17991 3941 4.0 14.0 4.0 PPA 153.2 694 180 740 25735 43726 4310 4.5 18.5 6.0 PPA 142.6 837 180 920 35926 79652 4929 4.5 23.0 8.0 PPA 133.3 970 180 1100 44796 124448 5526 4.5 27.5 10.0 PPA 125.2 1096 180 1280 52586 177034 5870 4.5 32.0 12.0 PPA 98.4 1194 150 1430 49568 226602 6012 3.8 35.8 Flush 179.9 1374 180 1609.9 0 226602 5694 4.5 40.3 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Step Name Pad Percentages Job Execution Job Description Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 265.7 ft with an average conductivity (Kfw) of 18429 md.ft. Fluid Name Fluid Totals Proppant Totals # SLB-PrivatePage 12 of 45 Attachment G Section 9: Propped Fracture Simulation (Stage 3; 12158 ft MD) Stage 3 MD 12158 ft Initial Fracture Top TVD 4155.0 ft Initial Fracture Bottom TVD 4348.0 ft Propped Fracture Half-Length 265.7 ft EOJ Hyd Height at Well 238.3 ft Average Propped Width 0.217 in Net Pressure 164 psi Max Surface Pressure 6090 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivi ty (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 66.4 11.2 0.251 151 2.13 171.2 22697 66.4 132.8 9.4 0.252 209 2.21 177.9 21807 132.8 199.3 8.4 0.242 204.3 2.17 184.8 20972 199.3 265.7 3.4 0.136 159.6 1.22 426.1 11217 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-PrivatePage 13 of 45 Attachment G Section 10: Zone Data (Stage 4; 11643 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughnes s (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4131.6 10.0 0.71 2937 1.46E+06 0.22 1000 Shale 4141.6 15.0 0.695 2884 1.76E+06 0.22 1000 Nanushuk 3 SS 4156.6 15.3 0.678 2823 1.90E+06 0.22 1000 Top Nan CS 4171.9 19.5 0.621 2595 9.00E+05 0.27 1000 Nan SS 4191.4 2.0 0.687 2880 2.67E+06 0.23 2500 Nan CS 4193.4 1.5 0.633 2655 1.29E+06 0.26 1000 Nan CS 4194.9 4.5 0.616 2585 6.44E+05 0.28 1000 Nan DS 4199.4 3.5 0.687 2886 1.77E+06 0.26 1500 Nan DS 4202.9 14.5 0.647 2726 1.39E+06 0.26 1500 Nan CS 4217.4 1.5 0.642 2706 1.15E+06 0.27 1000 Nan CS 4218.9 12.5 0.625 2641 8.82E+05 0.27 1000 Nan DS 4231.4 2.0 0.649 2747 1.40E+06 0.26 1500 Nan CS 4233.4 9.0 0.604 2558 8.54E+05 0.27 1000 Nan DS 4242.4 7.0 0.649 2755 1.40E+06 0.26 1500 Nan DS 4249.4 9.0 0.636 2705 1.13E+06 0.27 1500 Nan DS 4258.4 3.5 0.638 2720 1.69E+06 0.26 1500 Nan DS 4261.9 5.0 0.625 2665 7.57E+05 0.27 1000 Nan DS 4266.9 2.0 0.685 2925 1.80E+06 0.25 1500 Nan CS 4268.9 10.5 0.61 2607 7.36E+05 0.27 1000 Nan CS 4279.4 3.5 0.632 2705 1.10E+06 0.27 1000 Nan CS 4282.9 2.0 0.61 2614 6.70E+05 0.28 1000 Nan CS 4284.9 5.5 0.646 2768 1.30E+06 0.26 1000 Nan DS 4290.4 3.5 0.685 2939 1.53E+06 0.26 1500 Nan DS 4293.9 3.5 0.629 2701 1.19E+06 0.27 1500 Nan DS 4297.4 5.5 0.681 2928 1.42E+06 0.26 1500 Nan CS 4302.9 10.5 0.625 2693 1.17E+06 0.27 1000 Nan DS 4313.4 1.5 0.652 2811 1.38E+06 0.26 1500 Nan DS 4314.9 5.0 0.619 2671 1.14E+06 0.27 1500 Nan DS 4319.9 2.0 0.65 2809 1.56E+06 0.26 1500 Nan DS 4321.9 4.0 0.622 2688 8.96E+05 0.27 1500 Nan DS 4325.9 2.0 0.665 2876 1.66E+06 0.26 1500 Nan DS 4327.9 10.0 0.627 2717 9.81E+05 0.27 1500 Nan DS 4337.9 4.0 0.654 2838 1.63E+06 0.26 1500 Nan DS 4341.9 4.0 0.685 2974 1.75E+06 0.26 1500 Nan DS 4345.9 9.5 0.64 2784 1.33E+06 0.26 1500 Nan DS 4355.4 2.0 0.608 2649 7.82E+05 0.27 1000 Nan DS 4357.4 9.5 0.682 2975 1.69E+06 0.26 1500 Nan DS 4366.9 2.0 0.644 2812 1.37E+06 0.26 1500 Shale 4368.9 2.0 0.687 3002 2.67E+06 0.23 2500 Nan DS 4370.9 2.0 0.632 2765 1.09E+06 0.27 1500 Shale 4372.9 2.0 0.687 3005 2.67E+06 0.23 2500 Nan DS 4374.9 4.0 0.65 2844 1.29E+06 0.26 1500 Shale 4378.9 19.5 0.687 3015 2.67E+06 0.23 2500 Nan DS 4398.4 2.0 0.641 2820 1.36E+06 0.26 1500 Shale 4400.4 2.0 0.687 3024 2.67E+06 0.23 2500 Nan DS 4402.4 8.0 0.648 2855 1.37E+06 0.26 1500 Nan DS 4410.4 8.0 0.644 2841 1.56E+06 0.26 1500 Shale 4418.4 20.0 0.687 3042 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 14 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4131.6 0.1 0.001 1.0 1890 Shale 4141.6 0.1 0.001 1.0 1898 Nanushuk 3 SS 4156.6 3.8 0.005 10.0 1905 Top Nan CS 4171.9 19.5 30.655 23.7 1915 Nan SS 4191.4 0.8 5 10.0 1924 Nan CS 4193.4 1.5 2.095 16.9 1925 Nan CS 4194.9 4.5 48.388 26.6 1926 Nan DS 4199.4 2.5 0.478 12.4 1928 Nan DS 4202.9 10.1 15.008 17.7 1930 Nan CS 4217.4 1.5 3.661 17.6 1937 Nan CS 4218.9 12.5 34.723 23.9 1937 Nan DS 4231.4 1.4 1.697 15.6 1943 Nan CS 4233.4 9.0 54.319 24.4 1944 Nan DS 4242.4 4.9 3.61 14.8 1948 Nan DS 4249.4 6.3 22.986 20.4 1952 Nan DS 4258.4 2.5 0.835 14.0 1956 Nan DS 4261.9 3.5 65.392 23.4 1957 Nan DS 4266.9 1.4 0.006 10.5 1960 Nan CS 4268.9 10.5 100.832 25.6 1961 Nan CS 4279.4 3.5 17.434 20.5 1966 Nan CS 4282.9 2.0 161.343 26.3 1967 Nan CS 4284.9 5.5 4.627 18.4 1968 Nan DS 4290.4 2.5 5.075 14.8 1971 Nan DS 4293.9 2.5 8.651 19.4 1972 Nan DS 4297.4 3.8 10.205 16.0 1974 Nan CS 4302.9 10.5 17.356 20.1 1977 Nan DS 4313.4 1.0 3.106 14.8 1982 Nan DS 4314.9 3.5 52.863 20.6 1982 Nan DS 4319.9 1.4 2.277 14.1 1985 Nan DS 4321.9 2.8 122.778 23.1 1986 Nan DS 4325.9 1.4 0.333 12.5 1987 Nan DS 4327.9 7.0 39.939 21.2 1988 Nan DS 4337.9 2.8 0.748 13.3 1993 Nan DS 4341.9 2.8 0.009 10.9 1995 Nan DS 4345.9 6.7 5.399 16.7 1997 Nan DS 4355.4 1.4 160.618 24.9 2001 Nan DS 4357.4 6.7 0.033 11.5 2002 Nan DS 4366.9 1.4 6.733 16.2 2007 Shale 4368.9 0.1 0.001 1.0 2008 Nan DS 4370.9 1.4 29.48 19.6 2009 Shale 4372.9 0.1 0.001 1.0 2009 Nan DS 4374.9 2.8 8.473 16.6 2010 Shale 4378.9 0.1 0.001 1.0 2012 Nan DS 4398.4 1.4 2.185 16.4 2021 Shale 4400.4 0.1 0.001 1.0 2022 Nan DS 4402.4 5.6 2.645 15.9 2023 Nan DS 4410.4 5.6 2.026 14.4 2027 Shale 4418.4 0.1 0.001 10.0 2031 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 15 of 45 Attachment G Section 11: Propped Fracture Schedule (Stage 4; 11643 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 95.8 22 1.0 2.0 PPA 40 YF122ST 137.9 22 2.0 4.0 PPA 40 YF122ST 187.2 22 4.0 6.0 PPA 40 YF122ST 190.1 22 6.0 8.0 PPA 40 YF122ST 177.8 22 8.0 10.0 PPA 40 YF122ST 153.0 22 10.0 12.0 PPA 40 YF122ST 98.4 22 12.0 Flush 40 WF122 172.2 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1315 bbl of YF122ST 172.2 bbl of WF122 268534 lb of 16/20 C-Lite % PAD Clean 20.9 % PAD Dirty 17.2 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 275.0 275 275 275 0 0 3808 6.9 6.9 1.0 PPA 95.8 371 100 375 4024 4024 3793 2.5 9.4 2.0 PPA 137.9 509 150 525 11586 15610 3817 3.8 13.2 4.0 PPA 187.2 696 220 745 31454 47064 4272 5.5 18.7 6.0 PPA 190.1 886 240 985 47902 94966 4921 6.0 24.7 8.0 PPA 177.8 1064 240 1225 59728 154694 5421 6.0 30.7 10.0 PPA 153.0 1217 220 1445 64272 218966 5685 5.5 36.2 12.0 PPA 98.4 1315 150 1595 49568 268534 5789 3.8 40.0 Flush 172.2 1487 172.2 1767.2 0 268534 5428 4.3 44.3 Carbolite 16/20 Fluid Totals Job Execution Job Description Prop. Type and MeshFluid Name Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 290.0 ft with an average conductivity (Kfw) of 20338 md.ft. Carbolite 16/20 Carbolite 16/20 Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 # SLB-PrivatePage 16 of 45 Attachment G Section 12: Propped Fracture Simulation (Stage 4; 11643 ft MD) Stage 4 MD 11643 ft Initial Fracture Top TVD 4164.0 ft Initial Fracture Bottom TVD 4355.0 ft Propped Fracture Half-Length 290.0 ft EOJ Hyd Height at Well 240.4 ft Average Propped Width 0.240 in Net Pressure 223 psi Max Surface Pressure 5810 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivi ty (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 72.5 11 0.259 145.6 2.21 170.5 23335 72.5 145 9.4 0.261 205.9 2.29 175.6 22762 145 217.5 8.8 0.261 202.5 2.36 177 22814 217.5 290 4.5 0.188 165.3 1.73 223.4 16064 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-PrivatePage 17 of 45 Attachment G Section 13: Zone Data (Stage 5; 11128 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4138.5 10.0 0.71 2942 1.46E+06 0.22 1000 Shale 4148.5 15.0 0.70 2888 1.76E+06 0.22 1000 Siltstone 4163.5 15.3 0.68 2828 1.90E+06 0.22 1000 Top Nan CS 4178.8 17.5 0.63 2636 8.18E+05 0.27 1000 Nan DS 4196.3 2.0 0.60 2537 7.85E+05 0.27 1000 Nan DS 4198.3 5.5 0.63 2666 1.25E+06 0.26 1500 SHALE 4203.8 3.5 0.69 2897 2.67E+06 0.23 2500 Nan DS 4207.3 1.5 0.63 2665 1.10E+06 0.27 1500 Nan DS 4208.8 2.0 0.64 2673 9.14E+05 0.27 1500 Nan CS 4210.8 1.5 0.62 2593 6.70E+05 0.28 1000 Nan CS 4212.3 2.0 0.64 2701 1.25E+06 0.26 1000 Nan CS 4214.3 1.5 0.60 2549 7.72E+05 0.27 1000 SHALE 4215.8 2.0 0.69 2905 2.67E+06 0.23 2500 Nan CS 4217.8 4.5 0.61 2593 8.74E+05 0.27 1000 Nan DS 4222.3 7.0 0.65 2756 1.42E+06 0.26 1500 Nan DS 4229.3 2.5 0.61 2600 7.58E+05 0.27 1000 Nan DS 4231.8 2.0 0.69 2905 1.69E+06 0.26 1500 Nan DS 4233.8 5.0 0.62 2615 9.98E+05 0.27 1500 Nan CS 4238.8 4.5 0.64 2719 1.12E+06 0.27 1000 Nan CS 4243.3 9.5 0.61 2582 7.78E+05 0.27 1000 Nan DS 4252.8 2.5 0.65 2755 1.69E+06 0.26 1500 Nan DS 4255.3 12.0 0.63 2674 9.65E+05 0.27 1500 Nan DS 4267.3 2.5 0.65 2789 1.47E+06 0.26 1500 Nan DS 4269.8 9.5 0.63 2698 1.30E+06 0.26 1500 Nan DS 4279.3 2.0 0.64 2754 1.44E+06 0.26 1500 Nan DS 4281.3 41.0 0.63 2717 1.02E+06 0.27 1500 Nan DS 4322.3 1.5 0.63 2720 8.62E+05 0.27 1000 Nan CS 4323.8 6.0 0.62 2683 7.65E+05 0.28 1000 Nan DS 4329.8 6.0 0.67 2887 1.24E+06 0.26 1500 Nan DS 4335.8 4.0 0.69 2978 1.69E+06 0.26 1500 Nan DS 4339.8 2.0 0.64 2779 1.01E+06 0.27 1500 Nan DS 4341.8 2.0 0.69 2983 1.69E+06 0.26 1500 Nan DS 4343.8 2.0 0.64 2774 1.13E+06 0.27 1500 Nan DS 4345.8 5.5 0.69 2981 1.69E+06 0.26 1500 Nan DS 4351.3 4.0 0.62 2708 9.50E+05 0.27 1000 Nan DS 4355.3 2.0 0.69 2987 1.69E+06 0.26 1500 Nan DS 4357.3 12.0 0.63 2745 9.20E+05 0.27 1000 Nan DS 4369.3 4.0 0.68 2994 1.43E+06 0.26 1500 Nan DS 4373.3 4.0 0.64 2799 1.47E+06 0.26 1500 SHALE 4377.3 2.0 0.69 3016 2.67E+06 0.23 2500 Nan DS 4379.3 1.5 0.65 2837 1.37E+06 0.26 1500 SHALE 4380.8 8.0 0.69 3020 2.67E+06 0.23 2500 Nan DS 4388.8 8.0 0.63 2760 1.13E+06 0.27 1500 Nan DS 4396.8 1.5 0.63 2780 1.42E+06 0.26 1500 SHALE 4398.3 2.0 0.69 3030 2.67E+06 0.23 2500 Nan DS 4400.3 4.0 0.64 2804 1.28E+06 0.26 1500 SHALE 4404.3 2.0 0.69 3034 2.67E+06 0.23 2500 Nan DS 4406.3 6.0 0.63 2790 1.07E+06 0.27 1500 SHALE 4412.3 20.0 0.69 3046 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 18 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4138.5 0.1 0.001 1.0 1913 Shale 4148.5 0.1 0.001 1.0 1918 Siltstone 4163.5 6.1 0.005 10.0 1925 Top Nan CS 4178.8 17.5 39.470 24.9 1932 Nan DS 4196.3 1.4 113.240 25.3 1940 Nan DS 4198.3 3.9 22.020 19.7 1941 SHALE 4203.8 0.1 0.001 1.0 1944 Nan DS 4207.3 1.1 21.670 21.3 1945 Nan DS 4208.8 1.4 159.890 23.6 1946 Nan CS 4210.8 1.5 110.140 27.0 1947 Nan CS 4212.3 2.0 2.870 19.7 1948 Nan CS 4214.3 1.5 94.750 25.5 1949 SHALE 4215.8 0.1 0.001 1.0 1949 Nan CS 4217.8 4.5 44.130 24.1 1950 Nan DS 4222.3 4.9 4.280 17.9 1952 Nan DS 4229.3 1.8 91.630 25.7 1956 Nan DS 4231.8 1.4 0.020 15.0 1957 Nan DS 4233.8 3.5 31.600 22.6 1958 Nan CS 4238.8 4.5 3.110 21.1 1960 Nan CS 4243.3 9.5 131.710 25.4 1962 Nan DS 4252.8 1.8 1.000 15.1 1967 Nan DS 4255.3 8.4 104.140 23.0 1968 Nan DS 4267.3 1.8 2.350 17.3 1974 Nan DS 4269.8 6.7 31.760 19.2 1975 Nan DS 4279.3 1.4 3.790 17.6 1979 Nan DS 4281.3 28.7 72.280 22.4 1980 Nan DS 4322.3 1.1 68.110 24.3 1999 Nan CS 4323.8 6.0 156.150 26.2 2000 Nan DS 4329.8 4.2 40.960 19.9 2003 Nan DS 4335.8 2.8 0.020 15.0 2006 Nan DS 4339.8 1.4 17.850 22.4 2008 Nan DS 4341.8 1.4 0.010 15.0 2009 Nan DS 4343.8 1.4 22.090 21.0 2010 Nan DS 4345.8 3.9 0.020 15.0 2011 Nan DS 4351.3 2.8 63.420 23.1 2013 Nan DS 4355.3 1.4 0.020 15.0 2015 Nan DS 4357.3 8.4 74.620 23.5 2016 Nan DS 4369.3 2.8 11.770 17.8 2022 Nan DS 4373.3 2.8 2.490 17.3 2023 SHALE 4377.3 0.1 0.001 1.0 2025 Nan DS 4379.3 1.1 3.220 18.4 2026 SHALE 4380.8 0.1 0.001 1.0 2027 Nan DS 4388.8 5.6 65.690 21.2 2031 Nan DS 4396.8 1.1 4.800 17.8 2035 SHALE 4398.3 0.1 0.001 1.0 2035 Nan DS 4400.3 2.8 11.980 19.3 2036 SHALE 4404.3 0.1 0.001 1.0 2038 Nan DS 4406.3 4.5 60.610 22.1 2039 SHALE 4412.3 0.1 0.001 1.0 2042 Formation Transmissibility Properties Zone Name # SLB-PrivatePage 19 of 45 Attachment G Section 14: Propped Fracture Schedule (Stage 5; 11128 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 143.7 22 1.0 3.0 PPA 40 YF122ST 176.8 22 3.0 5.0 PPA 40 YF122ST 196.9 22 5.0 7.0 PPA 40 YF122ST 164.6 22 7.0 9.0 PPA 40 YF122ST 154.2 22 9.0 10.0 PPA 40 YF122ST 132.2 22 10.0 Flush 40 WF122 164.6 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1243 bbl of YF122ST 164.6 bbl of WF122 231862 lb of 16/20 C-Lite % PAD Clean 22.1 % PAD Dirty 18.5 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 275.0 275 275 275 0 0 3683 6.9 6.9 1.0 PPA 143.7 419 150 425 6036 6036 3653 3.8 10.6 3.0 PPA 176.8 595 200 625 22275 28311 3814 5.0 15.6 5.0 PPA 196.9 792 240 865 41351 69663 4456 6.0 21.6 7.0 PPA 164.6 957 215 1080 48387 118049 4972 5.4 27.0 9.0 PPA 154.2 1111 215 1295 58305 176354 5326 5.4 32.4 10.0 PPA 132.2 1243 190 1485 55508 231862 5478 4.8 37.1 Flush 164.6 1408 165 1650 0 231862 5121 4.1 41.2 Carbolite 16/20 Carbolite 16/20 Step Name Pad Percentages Job Execution Job Description Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 358.3 ft with an average conductivity (Kfw) of 12647 md.ft. Fluid Name Fluid Totals Proppant Totals # SLB-PrivatePage 20 of 45 Attachment G Section 15: Propped Fracture Simulation (Stage 5; 11128 ft MD) Stage 5 MD 11128 ft Initial Fracture Top TVD 4172 ft Initial Fracture Bottom TVD 4356 ft Propped Fracture Half-Length 358.3 ft EOJ Hyd Height at Well 240.4 ft Average Propped Width 0.166 in Net Pressure 229 psi Max Surface Pressure 5524 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 89.6 10.4 0.204 139.1 1.75 172.5 17936 89.6 179.2 8.9 0.197 211.9 1.75 178.3 16923 179.2 268.7 6.3 0.166 193.2 1.46 203 13867 268.7 358.3 2.6 0.102 155.4 0.95 403.3 8017 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-PrivatePage 21 of 45 Attachment G Section 16: Zone Data (Stage 6; 10653 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4156.9 10.0 0.71 2955 1.46E+06 0.22 1000 Shale 4166.9 15.0 0.70 2901 1.76E+06 0.22 1000 Siltstone 4181.9 15.3 0.68 2841 1.90E+06 0.22 1000 Top Nan CS 4197.2 17.5 0.63 2648 8.18E+05 0.27 1000 Nan DS 4214.7 2.0 0.60 2549 7.85E+05 0.27 1000 Nan DS 4216.7 5.5 0.63 2677 1.25E+06 0.26 1500 SHALE 4222.2 3.5 0.69 2909 2.67E+06 0.23 2500 Nan DS 4225.7 1.5 0.63 2676 1.10E+06 0.27 1500 Nan DS 4227.2 2.0 0.64 2685 9.14E+05 0.27 1500 Nan CS 4229.2 1.5 0.62 2605 6.70E+05 0.28 1000 Nan CS 4230.7 2.0 0.64 2713 1.25E+06 0.26 1000 Nan CS 4232.7 1.5 0.60 2560 7.72E+05 0.27 1000 SHALE 4234.2 2.0 0.69 2917 2.67E+06 0.23 2500 Nan CS 4236.2 4.5 0.61 2605 8.74E+05 0.27 1000 Nan DS 4240.7 7.0 0.65 2768 1.42E+06 0.26 1500 Nan DS 4247.7 2.5 0.61 2611 7.58E+05 0.27 1000 Nan DS 4250.2 2.0 0.69 2917 1.69E+06 0.26 1500 Nan DS 4252.2 5.0 0.62 2627 9.98E+05 0.27 1500 Nan CS 4257.2 4.5 0.64 2730 1.12E+06 0.27 1000 Nan CS 4261.7 9.5 0.61 2593 7.78E+05 0.27 1000 Nan DS 4271.2 2.5 0.65 2767 1.69E+06 0.26 1500 Nan DS 4273.7 12.0 0.63 2685 9.65E+05 0.27 1500 Nan DS 4285.7 2.5 0.65 2801 1.47E+06 0.26 1500 Nan DS 4288.2 9.5 0.63 2710 1.30E+06 0.26 1500 Nan DS 4297.7 2.0 0.64 2765 1.44E+06 0.26 1500 Nan DS 4299.7 41.0 0.63 2729 1.02E+06 0.27 1500 Nan DS 4340.7 1.5 0.63 2732 8.62E+05 0.27 1000 Nan CS 4342.2 6.0 0.62 2695 7.65E+05 0.28 1000 Nan DS 4348.2 6.0 0.67 2899 1.24E+06 0.26 1500 Nan DS 4354.2 4.0 0.69 2991 1.69E+06 0.26 1500 Nan DS 4358.2 2.0 0.64 2790 1.01E+06 0.27 1500 Nan DS 4360.2 2.0 0.69 2996 1.69E+06 0.26 1500 Nan DS 4362.2 2.0 0.64 2786 1.13E+06 0.27 1500 Nan DS 4364.2 5.5 0.69 2994 1.69E+06 0.26 1500 Nan DS 4369.7 4.0 0.62 2720 9.50E+05 0.27 1000 Nan DS 4373.7 2.0 0.69 3000 1.69E+06 0.26 1500 Nan DS 4375.7 12.0 0.63 2756 9.20E+05 0.27 1000 Nan DS 4387.7 4.0 0.68 3007 1.43E+06 0.26 1500 Nan DS 4391.7 4.0 0.64 2810 1.47E+06 0.26 1500 SHALE 4395.7 2.0 0.69 3028 2.67E+06 0.23 2500 Nan DS 4397.7 1.5 0.65 2849 1.37E+06 0.26 1500 SHALE 4399.2 8.0 0.69 3033 2.67E+06 0.23 2500 Nan DS 4407.2 8.0 0.63 2772 1.13E+06 0.27 1500 Nan DS 4415.2 1.5 0.63 2792 1.42E+06 0.26 1500 SHALE 4416.7 2.0 0.69 3043 2.67E+06 0.23 2500 Nan DS 4418.7 4.0 0.64 2816 1.28E+06 0.26 1500 SHALE 4422.7 2.0 0.69 3047 2.67E+06 0.23 2500 Nan DS 4424.7 6.0 0.63 2801 1.07E+06 0.27 1500 SHALE 4430.7 20.0 0.69 3059 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 22 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4156.9 0.1 0.001 1.0 1913 Shale 4166.9 0.1 0.001 1.0 1918 Siltstone 4181.9 6.1 0.005 10.0 1925 Top Nan CS 4197.2 17.5 39.470 24.9 1932 Nan DS 4214.7 1.4 113.240 25.3 1940 Nan DS 4216.7 3.9 22.020 19.7 1941 SHALE 4222.2 0.1 0.001 1.0 1944 Nan DS 4225.7 1.1 21.670 21.3 1945 Nan DS 4227.2 1.4 159.890 23.6 1946 Nan CS 4229.2 1.5 110.140 27.0 1947 Nan CS 4230.7 2.0 2.870 19.7 1948 Nan CS 4232.7 1.5 94.750 25.5 1949 SHALE 4234.2 0.1 0.001 1.0 1949 Nan CS 4236.2 4.5 44.130 24.1 1950 Nan DS 4240.7 4.9 4.280 17.9 1952 Nan DS 4247.7 1.8 91.630 25.7 1956 Nan DS 4250.2 1.4 0.020 15.0 1957 Nan DS 4252.2 3.5 31.600 22.6 1958 Nan CS 4257.2 4.5 3.110 21.1 1960 Nan CS 4261.7 9.5 131.710 25.4 1962 Nan DS 4271.2 1.8 1.000 15.1 1967 Nan DS 4273.7 8.4 104.140 23.0 1968 Nan DS 4285.7 1.8 2.350 17.3 1974 Nan DS 4288.2 6.7 31.760 19.2 1975 Nan DS 4297.7 1.4 3.790 17.6 1979 Nan DS 4299.7 28.7 72.280 22.4 1980 Nan DS 4340.7 1.1 68.110 24.3 1999 Nan CS 4342.2 6.0 156.150 26.2 2000 Nan DS 4348.2 4.2 40.960 19.9 2003 Nan DS 4354.2 2.8 0.020 15.0 2006 Nan DS 4358.2 1.4 17.850 22.4 2008 Nan DS 4360.2 1.4 0.010 15.0 2009 Nan DS 4362.2 1.4 22.090 21.0 2010 Nan DS 4364.2 3.9 0.020 15.0 2011 Nan DS 4369.7 2.8 63.420 23.1 2013 Nan DS 4373.7 1.4 0.020 15.0 2015 Nan DS 4375.7 8.4 74.620 23.5 2016 Nan DS 4387.7 2.8 11.770 17.8 2022 Nan DS 4391.7 2.8 2.490 17.3 2023 SHALE 4395.7 0.1 0.001 1.0 2025 Nan DS 4397.7 1.1 3.220 18.4 2026 SHALE 4399.2 0.1 0.001 1.0 2027 Nan DS 4407.2 5.6 65.690 21.2 2031 Nan DS 4415.2 1.1 4.800 17.8 2035 SHALE 4416.7 0.1 0.001 1.0 2035 Nan DS 4418.7 2.8 11.980 19.3 2036 SHALE 4422.7 0.1 0.001 1.0 2038 Nan DS 4424.7 4.5 60.610 22.1 2039 SHALE 4430.7 0.1 0.001 1.0 2042 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 23 of 45 Attachment G Section 17: Propped Fracture Schedule (Stage 6; 10653 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 260.0 22 0 1.0 PPA 40 YF122ST 134.1 22 1.0 2.0 PPA 40 YF122ST 147.1 22 2.0 4.0 PPA 40 YF122ST 153.2 22 4.0 6.0 PPA 40 YF122ST 142.6 22 6.0 8.0 PPA 40 YF122ST 133.3 22 8.0 10.0 PPA 40 YF122ST 125.2 22 10.0 12.0 PPA 40 YF122ST 98.3 22 12.0 Flush 40 WF122 157.0 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1194 bbl of YF122ST 157 bbl of WF122 226603 lb of 16/20 C-Lite % PAD Clean 21.8 % PAD Dirty 18.2 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 260.0 260 260 260 0 0 3582 6.5 6.5 1.0 PPA 134.1 394 140 400 5633 5633 3556 3.5 10.0 2.0 PPA 147.1 541 160 560 12358 17992 3600 4.0 14.0 4.0 PPA 153.2 694 180 740 25735 43727 3927 4.5 18.5 6.0 PPA 142.6 837 180 920 35926 79653 4493 4.5 23.0 8.0 PPA 133.3 970 180 1100 44796 124449 4973 4.5 27.5 10.0 PPA 125.2 1096 180 1280 52586 177035 5226 4.5 32.0 12.0 PPA 98.3 1194 150 1430 49568 226603 5318 3.8 35.8 Flush 157.0 1351 157 1587 0 226603 5043 3.9 39.7 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 319.8 ft with an average conductivity (Kfw) of 13696 md.ft. Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Job Execution Job Description Prop. Type and MeshFluid Name # SLB-PrivatePage 24 of 45 Attachment G Section 18: Propped Fracture Simulation (Stage 6; 10653 ft MD) Stage 6 MD 10653 ft Initial Fracture Top TVD 4188 ft Initial Fracture Bottom TVD 4373 ft Propped Fracture Half-Length 319.8 ft EOJ Hyd Height at Well 253.5 ft Average Propped Width 0.172 in Net Pressure 148 psi Max Surface Pressure 5376 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 79.9 11.4 0.207 147.9 1.77 162.2 18398 79.9 159.9 8.7 0.199 218.4 1.75 176.1 17178 159.9 239.8 6 0.182 207 1.6 185.8 15238 239.8 319.8 1.9 0.112 170 1.05 430.7 8958 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-PrivatePage 25 of 45 Attachment G Section 19: Zone Data (Stage 7; 9825 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4165.0 21.7 0.71 2965 1.46E+06 0.22 1000 SHALE 4186.7 15.0 0.70 2915 1.76E+06 0.22 1000 SILTSTONE 4201.7 24.1 0.68 2857 1.90E+06 0.22 1000 Top Nan CS 4225.8 7.0 0.63 2654 2.37E+06 0.24 1000 DIRTY-SANDSTONE 4232.8 1.5 0.68 2880 1.50E+06 0.24 1000 SHALE 4234.3 2.0 0.69 2917 2.67E+06 0.23 2500 CLEAN-SANDSTONE 4236.3 10.5 0.62 2622 6.84E+05 0.28 1000 DIRTY-SANDSTONE 4246.8 6.5 0.64 2711 1.02E+06 0.27 1500 DIRTY-SANDSTONE 4253.3 5.5 0.64 2739 1.54E+06 0.26 1500 DIRTY-SANDSTONE 4258.8 5.0 0.62 2662 1.23E+06 0.26 1000 DIRTY-SANDSTONE 4263.8 1.5 0.65 2777 1.41E+06 0.26 1500 DIRTY-SANDSTONE 4265.3 2.0 0.65 2767 1.70E+06 0.26 1500 DIRTY-SANDSTONE 4267.3 1.5 0.60 2576 5.77E+05 0.28 1500 DIRTY-SANDSTONE 4268.8 11.5 0.65 2767 1.31E+06 0.26 1500 DIRTY-SANDSTONE 4280.3 1.8 0.67 2878 1.24E+06 0.27 1500 DIRTY-SANDSTONE 4282.1 2.1 0.68 2929 1.69E+06 0.26 1500 DIRTY-SANDSTONE 4284.2 8.2 0.63 2688 9.65E+05 0.27 1000 DIRTY-SANDSTONE 4292.4 4.9 0.65 2775 1.46E+06 0.26 1500 DIRTY-SANDSTONE 4297.3 1.5 0.67 2890 1.68E+06 0.26 1500 DIRTY-SANDSTONE 4298.8 2.0 0.64 2732 1.51E+06 0.26 1500 SHALE 4300.8 3.5 0.69 2964 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4304.3 1.5 0.65 2814 1.65E+06 0.26 1500 SHALE 4305.8 1.5 0.69 2966 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4307.3 3.5 0.63 2717 1.48E+06 0.26 1500 SHALE 4310.8 5.0 0.69 2971 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4315.8 2.0 0.62 2696 1.12E+06 0.27 1500 SHALE 4317.8 5.0 0.69 2976 2.67E+06 0.23 2500 SHALE 4322.8 3.5 0.69 2979 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4326.3 1.5 0.65 2819 1.31E+06 0.26 1500 SHALE 4327.8 11.0 0.69 2985 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4338.8 2.0 0.62 2695 8.37E+05 0.27 1000 SHALE 4340.8 1.5 0.69 2990 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4342.3 2.0 0.63 2719 9.57E+05 0.27 1000 DIRTY-SANDSTONE 4344.3 4.0 0.69 2984 1.69E+06 0.26 1500 DIRTY-SANDSTONE 4348.3 5.5 0.64 2769 1.20E+06 0.27 1500 DIRTY-SANDSTONE 4353.8 2.0 0.63 2728 9.33E+05 0.27 1000 DIRTY-SANDSTONE 4355.8 6.0 0.69 2992 1.74E+06 0.26 1500 DIRTY-SANDSTONE 4361.8 21.5 0.64 2787 1.08E+06 0.27 1500 DIRTY-SANDSTONE 4383.3 2.0 0.69 3012 1.69E+06 0.26 1500 DIRTY-SANDSTONE 4385.3 4.0 0.65 2842 1.16E+06 0.27 1500 DIRTY-SANDSTONE 4389.3 2.0 0.61 2660 8.76E+05 0.27 1500 SHALE 4391.3 2.0 0.69 3025 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4393.3 4.0 0.64 2828 1.52E+06 0.26 1500 DIRTY-SANDSTONE 4397.3 4.0 0.63 2768 1.12E+06 0.27 1500 DIRTY-SANDSTONE 4401.3 2.0 0.69 3021 1.69E+06 0.26 1500 DIRTY-SANDSTONE 4403.3 7.5 0.64 2824 1.18E+06 0.27 1500 SHALE 4410.8 9.5 0.69 3041 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4420.3 2.0 0.68 3020 1.69E+06 0.26 1500 SHALE 4422.3 50.0 0.69 3085 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 26 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4165.0 0.1 0.010 1.0 1918 SHALE 4186.7 0.1 0.010 1.0 1923 SILTSTONE 4201.7 9.6 0.050 10.0 1929 Top Nan CS 4225.8 7.0 6.009 4.1 1940 DIRTY-SANDSTONE 4232.8 0.6 0.192 12.0 1944 SHALE 4234.3 0.1 0.010 1.0 1944 CLEAN-SANDSTONE 4236.3 10.5 100.314 26.7 1945 DIRTY-SANDSTONE 4246.8 4.6 21.598 22.3 1950 DIRTY-SANDSTONE 4253.3 3.9 1.009 16.6 1953 DIRTY-SANDSTONE 4258.8 3.5 3.544 19.9 1956 DIRTY-SANDSTONE 4263.8 1.1 5.023 17.9 1958 DIRTY-SANDSTONE 4265.3 1.4 0.319 14.9 1959 DIRTY-SANDSTONE 4267.3 1.1 236.504 28.4 1960 DIRTY-SANDSTONE 4268.8 8.1 21.887 19.1 1960 DIRTY-SANDSTONE 4280.3 1.3 50.818 20.1 1966 DIRTY-SANDSTONE 4282.1 1.5 0.026 15.0 1968 DIRTY-SANDSTONE 4284.2 5.7 62.684 23.0 1970 DIRTY-SANDSTONE 4292.4 3.4 4.489 17.4 1970 DIRTY-SANDSTONE 4297.3 1.1 0.488 15.1 1974 DIRTY-SANDSTONE 4298.8 1.4 1.982 16.9 1974 SHALE 4300.8 0.1 0.010 1.0 1975 DIRTY-SANDSTONE 4304.3 1.1 0.552 15.4 1977 SHALE 4305.8 0.1 0.010 1.0 1978 DIRTY-SANDSTONE 4307.3 2.5 3.859 17.2 1978 SHALE 4310.8 0.1 0.010 1.0 1980 DIRTY-SANDSTONE 4315.8 1.4 41.288 21.2 1982 SHALE 4317.8 0.1 0.010 1.0 1983 SHALE 4322.8 0.1 0.010 1.0 1986 DIRTY-SANDSTONE 4326.3 1.1 5.111 19.0 1987 SHALE 4327.8 0.1 0.010 1.0 1988 DIRTY-SANDSTONE 4338.8 1.4 111.829 24.6 1993 SHALE 4340.8 0.1 0.010 1.0 1994 DIRTY-SANDSTONE 4342.3 1.4 102.765 23.1 1995 DIRTY-SANDSTONE 4344.3 2.8 0.016 15.0 1996 DIRTY-SANDSTONE 4348.3 3.9 24.191 20.3 1997 DIRTY-SANDSTONE 4353.8 1.4 33.759 23.4 2000 DIRTY-SANDSTONE 4355.8 4.2 0.015 14.5 2001 DIRTY-SANDSTONE 4361.8 15.1 82.778 21.8 2004 DIRTY-SANDSTONE 4383.3 1.4 0.014 15.0 2014 DIRTY-SANDSTONE 4385.3 2.8 26.711 20.7 2015 DIRTY-SANDSTONE 4389.3 1.4 162.436 24.1 2017 SHALE 4391.3 0.1 0.010 1.0 2018 DIRTY-SANDSTONE 4393.3 2.8 1.983 16.8 2019 DIRTY-SANDSTONE 4397.3 2.8 30.725 21.1 2020 DIRTY-SANDSTONE 4401.3 1.4 0.009 15.0 2022 DIRTY-SANDSTONE 4403.3 2.5 8.533 20.5 2023 SHALE 4410.8 0.1 0.010 1.0 2027 DIRTY-SANDSTONE 4420.3 1.4 15.000 10.0 2096 SHALE 4422.3 0.0 0.010 1.0 2081 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 27 of 45 Attachment G Section 20: Propped Fracture Schedule (Stage 7; 9825 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 95.8 22 1.0 2.0 PPA 40 YF122ST 137.9 22 2.0 4.0 PPA 40 YF122ST 187.2 22 4.0 6.0 PPA 40 YF122ST 190.1 22 6.0 8.0 PPA 40 YF122ST 177.8 22 8.0 10.0 PPA 40 YF122ST 153.0 22 10.0 12.0 PPA 40 YF122ST 98.3 22 12.0 Flush 40 WF122 144.8 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1315 bbl of YF122ST 144.8 bbl of WF122 268534 lb of 16/20 C-Lite % PAD Clean 20.9 % PAD Dirty 17.2 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 275.0 275 275 275 0 0 3490 6.9 6.9 1.0 PPA 95.8 371 100 375 4024 4024 3492 2.5 9.4 2.0 PPA 137.9 509 150 525 11586 15610 3533 3.8 13.1 4.0 PPA 187.2 696 220 745 31454 47064 3871 5.5 18.6 6.0 PPA 190.1 886 240 985 47902 94965 4378 6.0 24.6 8.0 PPA 177.8 1064 240 1225 59728 154694 4774 6.0 30.6 10.0 PPA 153.0 1217 220 1445 64272 218965 4945 5.5 36.1 12.0 PPA 98.3 1315 150 1595 49568 268534 5021 3.8 39.9 Flush 144.8 1460 145 1740 0 268534 4748 3.6 43.5 Job Execution Job Description Prop. Type and MeshFluid Name Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 386.6 ft with an average conductivity (Kfw) of 13456 md.ft. Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Carbolite 16/20 Carbolite 16/20 # SLB-PrivatePage 28 of 45 Attachment G Section 21: Propped Fracture Simulation (Stage 7; 9825 ft MD) Stage 7 MD 9825 ft Initial Fracture Top TVD 4201 ft Initial Fracture Bottom TVD 4402 ft Propped Fracture Half-Length 386.6 ft EOJ Hyd Height at Well 266.2 ft Average Propped Width 0.163 in Net Pressure 323 psi Max Surface Pressure 5090 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 96.7 10.9 0.213 148.8 1.8 155.4 19183 96.7 193.3 8.4 0.196 232 1.7 170.3 17102 193.3 290 6.2 0.15 216.3 1.33 207.9 12908 290 386.6 2.2 0.105 155.6 0.98 288.2 8444 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-PrivatePage 29 of 45 Attachment G Section 22: Zone Data (Stage 8; 9347 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4195.0 21.7 0.71 2986 1.46E+06 0.22 1000 SHALE 4216.7 15.0 0.70 2936 1.76E+06 0.22 1000 SILTSTONE 4231.7 24.1 0.68 2877 1.90E+06 0.22 1000 CLEAN-SANDSTONE 4255.8 3.5 0.61 2591 8.57E+05 0.27 1000 SHALE 4259.3 1.5 0.69 2934 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4260.8 1.5 0.63 2681 9.12E+05 0.27 1000 DIRTY-SANDSTONE 4262.3 3.5 0.66 2822 1.15E+06 0.27 1500 CLEAN-SANDSTONE 4265.8 2.0 0.62 2650 7.24E+05 0.28 1000 SHALE 4267.8 1.5 0.69 2940 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4269.3 14.0 0.64 2728 1.55E+06 0.26 1500 SHALE 4283.3 1.5 0.69 2951 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4284.8 3.5 0.62 2649 1.15E+06 0.27 1500 DIRTY-SANDSTONE 4288.3 1.5 0.69 2941 1.69E+06 0.26 1500 DIRTY-SANDSTONE 4289.8 2.0 0.61 2605 8.10E+05 0.27 1000 DIRTY-SANDSTONE 4291.8 5.0 0.66 2851 1.28E+06 0.26 1500 DIRTY-SANDSTONE 4296.8 10.0 0.63 2700 1.50E+06 0.26 1500 DIRTY-SANDSTONE 4306.8 10.0 0.66 2830 8.70E+05 0.27 1500 DIRTY-SANDSTONE 4316.8 5.0 0.62 2692 1.22E+06 0.27 1500 DIRTY-SANDSTONE 4321.8 8.5 0.69 2969 1.52E+06 0.26 1500 DIRTY-SANDSTONE 4330.3 3.5 0.62 2706 1.47E+06 0.26 1500 SHALE 4333.8 2.5 0.69 2986 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4336.3 1.0 0.65 2814 1.61E+06 0.26 1500 SHALE 4337.3 7.0 0.69 2990 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4344.3 3.5 0.64 2778 9.39E+05 0.27 1000 DIRTY-SANDSTONE 4347.8 4.5 0.69 2996 1.56E+06 0.26 1500 DIRTY-SANDSTONE 4352.3 2.0 0.64 2774 1.35E+06 0.26 1500 DIRTY-SANDSTONE 4354.3 2.0 0.69 2990 1.74E+06 0.26 1500 DIRTY-SANDSTONE 4356.3 5.5 0.62 2714 9.70E+05 0.27 1500 DIRTY-SANDSTONE 4361.8 6.0 0.69 3000 1.65E+06 0.26 1500 DIRTY-SANDSTONE 4367.8 10.0 0.65 2842 1.24E+06 0.26 1500 DIRTY-SANDSTONE 4377.8 2.0 0.65 2852 1.50E+06 0.26 1500 DIRTY-SANDSTONE 4379.8 7.5 0.63 2762 9.80E+05 0.27 1500 DIRTY-SANDSTONE 4387.3 1.5 0.69 3011 1.87E+06 0.25 1500 DIRTY-SANDSTONE 4388.8 3.0 0.61 2690 9.11E+05 0.27 1500 DIRTY-SANDSTONE 4391.8 5.0 0.64 2814 1.76E+06 0.26 1500 SHALE 4396.8 6.0 0.69 3031 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4402.8 2.0 0.66 2886 1.72E+06 0.26 1500 SHALE 4404.8 23.0 0.69 3042 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4427.8 2.0 0.63 2800 1.24E+06 0.26 1500 SHALE 4429.8 2.0 0.69 3052 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4431.8 2.0 0.66 2935 1.68E+06 0.26 1500 SHALE 4433.8 4.5 0.69 3056 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4438.3 10.0 0.63 2817 1.28E+06 0.26 1500 SHALE 4448.3 10.5 0.69 3068 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4458.8 2.0 0.65 2909 1.40E+06 0.26 1500 SHALE 4460.8 19.0 0.69 3079 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4479.8 2.0 0.64 2864 1.44E+06 0.26 1500 SHALE 4481.8 25.0 0.69 3096 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 30 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4195.0 0.0 0.010 1.0 1919 SHALE 4216.7 0.0 0.010 1.0 1929 SILTSTONE 4231.7 9.6 0.050 10.0 1936 CLEAN-SANDSTONE 4255.8 3.5 48.343 24.3 1947 SHALE 4259.3 0.0 0.006 10.0 1949 DIRTY-SANDSTONE 4260.8 1.1 39.757 23.6 1949 DIRTY-SANDSTONE 4262.3 2.5 6.288 20.8 1950 CLEAN-SANDSTONE 4265.8 2.0 71.711 26.2 1952 SHALE 4267.8 0.0 0.006 10.0 1952 DIRTY-SANDSTONE 4269.3 9.8 56.440 16.7 1953 SHALE 4283.3 0.0 0.006 10.0 1960 DIRTY-SANDSTONE 4284.8 2.5 18.893 20.8 1960 DIRTY-SANDSTONE 4288.3 1.1 0.023 15.0 1962 DIRTY-SANDSTONE 4289.8 1.4 115.609 24.9 1963 DIRTY-SANDSTONE 4291.8 3.5 20.857 19.5 1964 DIRTY-SANDSTONE 4296.8 7.0 1.968 17.0 1966 DIRTY-SANDSTONE 4306.8 7.0 74.766 24.2 1971 DIRTY-SANDSTONE 4316.8 3.5 11.675 20.1 1975 DIRTY-SANDSTONE 4321.8 6.0 7.321 16.9 1978 DIRTY-SANDSTONE 4330.3 2.5 3.784 17.3 1982 SHALE 4333.8 0.0 0.006 10.0 1983 DIRTY-SANDSTONE 4336.3 0.7 1.340 15.9 1984 SHALE 4337.3 0.0 0.006 10.0 1985 DIRTY-SANDSTONE 4344.3 2.5 40.985 23.3 1988 DIRTY-SANDSTONE 4347.8 3.2 1.316 14.2 1990 DIRTY-SANDSTONE 4352.3 1.4 4.219 18.6 1992 DIRTY-SANDSTONE 4354.3 1.4 0.015 14.6 1993 DIRTY-SANDSTONE 4356.3 3.9 61.197 22.9 1994 DIRTY-SANDSTONE 4361.8 4.2 0.552 13.9 1996 DIRTY-SANDSTONE 4367.8 7.0 28.233 19.9 1999 DIRTY-SANDSTONE 4377.8 1.4 1.534 17.0 2004 DIRTY-SANDSTONE 4379.8 5.3 79.135 22.8 2005 DIRTY-SANDSTONE 4387.3 1.1 0.006 10.0 2008 DIRTY-SANDSTONE 4388.8 2.1 120.250 23.7 2009 DIRTY-SANDSTONE 4391.8 3.5 0.329 14.3 2010 SHALE 4396.8 0.0 0.006 10.0 2013 DIRTY-SANDSTONE 4402.8 1.4 0.136 14.8 2015 SHALE 4404.8 0.0 0.006 10.0 2016 DIRTY-SANDSTONE 4427.8 1.4 15.982 19.8 2027 SHALE 4429.8 0.0 0.006 10.0 2028 DIRTY-SANDSTONE 4431.8 1.4 0.344 15.1 2029 SHALE 4433.8 0.0 0.006 10.0 2030 DIRTY-SANDSTONE 4438.3 7.0 6.547 19.3 2032 SHALE 4448.3 0.0 0.006 10.0 2036 DIRTY-SANDSTONE 4458.8 1.4 1.897 18.0 2041 SHALE 4460.8 0.0 0.006 10.0 2042 DIRTY-SANDSTONE 4479.8 1.4 4.758 17.7 2051 SHALE 4481.8 0.0 0.006 10.0 2052 Formation Transmissibility Properties Zone Name # SLB-PrivatePage 31 of 45 Attachment G Section 23: Propped Fracture Schedule (Stage 8; 9347 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 30 YF122ST 200.0 22 0 1.0 PPA 30 YF122ST 162.9 22 1.0 3.0 PPA 30 YF122ST 150.3 22 3.0 5.0 PPA 30 YF122ST 192.8 22 5.0 7.0 PPA 30 YF122ST 160.8 22 7.0 9.0 PPA 30 YF122ST 150.7 22 9.0 10.0 PPA 30 YF122ST 132.2 22 10.0 Flush 30 WF122 137.2 22 0.0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1150 bbl of YF122ST 137.2 bbl of WF122 225983 lb of 16/20 C-Lite % PAD Clean 17.4 % PAD Dirty 14.4 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 200.0 200 200 200 0 0 2520 6.7 6.7 1.0 PPA 162.9 363 170 370 6841 6841 2490 5.7 12.3 3.0 PPA 150.3 513 170 540 18934 25775 2487 5.7 18.0 5.0 PPA 192.8 706 235 775 40490 66265 2732 7.8 25.8 7.0 PPA 160.8 867 210 985 47261 113526 2929 7.0 32.8 9.0 PPA 150.7 1017 210 1195 56949 170475 3034 7.0 39.8 10.0 PPA 132.2 1150 190 1385 55508 225983 3064 6.3 46.2 Flush 137.2 1287 137 1522 0 225983 3154 4.6 50.7 Carbolite 16/20 Carbolite 16/20 Step Name Pad Percentages Job Execution Job Description Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 386.6 ft with an average conductivity (Kfw) of 12148 md.ft. Fluid Name Fluid Totals Proppant Totals # SLB-PrivatePage 32 of 45 Attachment G Section 24: Propped Fracture Simulation (Stage 8; 9347 ft MD) Stage 8 MD 9347 ft Initial Fracture Top TVD 4232 ft Initial Fracture Bottom TVD 4393 ft Propped Fracture Half-Length 386.6 ft EOJ Hyd Height at Well 260.1 ft Average Propped Width 0.15 in Net Pressure 340 psi Max Surface Pressure 3274 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 96.7 8.8 0.17 150.1 1.48 173.2 14958 96.7 193.3 7.3 0.171 217.6 1.49 180.7 15105 193.3 290 6.2 0.162 188.5 1.48 195.9 13879 290 386.6 3.3 0.103 142.6 0.98 286.6 8355 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-PrivatePage 33 of 45 Attachment G Section 25: Zone Data (Stage 9; 8829 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4206.3 31.7 0.71 2998 1.46E+06 0.22 1000 SHALE 4238.0 15.0 0.70 2951 1.76E+06 0.22 1000 SILTSTONE 4253.0 24.1 0.68 2892 1.90E+06 0.22 1000 CLEAN-SANDSTONE 4277.1 3.5 0.61 2604 8.57E+05 0.27 1000 SHALE 4280.6 1.5 0.69 2949 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4282.1 1.5 0.63 2694 9.12E+05 0.27 1000 DIRTY-SANDSTONE 4283.6 3.5 0.66 2837 1.15E+06 0.27 1500 CLEAN-SANDSTONE 4287.1 2.0 0.62 2663 7.24E+05 0.28 1000 SHALE 4289.1 1.5 0.69 2955 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4290.6 14.0 0.64 2742 1.55E+06 0.26 1500 SHALE 4304.6 1.5 0.69 2966 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4306.1 3.5 0.62 2662 1.15E+06 0.27 1500 DIRTY-SANDSTONE 4309.6 1.5 0.69 2956 1.69E+06 0.26 1500 DIRTY-SANDSTONE 4311.1 2.0 0.61 2618 8.10E+05 0.27 1000 DIRTY-SANDSTONE 4313.1 5.0 0.66 2865 1.28E+06 0.26 1500 DIRTY-SANDSTONE 4318.1 10.0 0.63 2714 1.50E+06 0.26 1500 DIRTY-SANDSTONE 4328.1 10.0 0.66 2844 8.70E+05 0.27 1500 DIRTY-SANDSTONE 4338.1 5.0 0.62 2706 1.22E+06 0.27 1500 DIRTY-SANDSTONE 4343.1 8.5 0.69 2983 1.52E+06 0.26 1500 DIRTY-SANDSTONE 4351.6 3.5 0.62 2719 1.47E+06 0.26 1500 SHALE 4355.1 2.5 0.69 3001 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4357.6 1.0 0.65 2827 1.61E+06 0.26 1500 SHALE 4358.6 7.0 0.69 3005 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4365.6 3.5 0.64 2791 9.39E+05 0.27 1000 DIRTY-SANDSTONE 4369.1 4.5 0.69 3011 1.56E+06 0.26 1500 DIRTY-SANDSTONE 4373.6 2.0 0.64 2788 1.35E+06 0.26 1500 DIRTY-SANDSTONE 4375.6 2.0 0.69 3004 1.74E+06 0.26 1500 DIRTY-SANDSTONE 4377.6 5.5 0.62 2727 9.70E+05 0.27 1500 DIRTY-SANDSTONE 4383.1 6.0 0.69 3015 1.65E+06 0.26 1500 DIRTY-SANDSTONE 4389.1 10.0 0.65 2856 1.24E+06 0.26 1500 DIRTY-SANDSTONE 4399.1 2.0 0.65 2865 1.50E+06 0.26 1500 DIRTY-SANDSTONE 4401.1 7.5 0.63 2775 9.80E+05 0.27 1500 DIRTY-SANDSTONE 4408.6 1.5 0.69 3026 1.87E+06 0.25 1500 DIRTY-SANDSTONE 4410.1 3.0 0.61 2703 9.11E+05 0.27 1500 DIRTY-SANDSTONE 4413.1 5.0 0.64 2827 1.76E+06 0.26 1500 SHALE 4418.1 6.0 0.69 3045 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4424.1 2.0 0.66 2900 1.72E+06 0.26 1500 SHALE 4426.1 23.0 0.69 3057 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4449.1 2.0 0.63 2813 1.24E+06 0.26 1500 SHALE 4451.1 2.0 0.69 3067 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4453.1 2.0 0.66 2949 1.68E+06 0.26 1500 SHALE 4455.1 4.5 0.69 3070 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4459.6 10.0 0.63 2831 1.28E+06 0.26 1500 SHALE 4469.6 10.5 0.69 3082 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4480.1 2.0 0.65 2923 1.40E+06 0.26 1500 SHALE 4482.1 19.0 0.69 3094 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4501.1 2.0 0.64 2877 1.44E+06 0.26 1500 SHALE 4503.1 25.0 0.69 3110 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 34 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4206.3 0.0 0.010 1.0 1919 SHALE 4238.0 0.0 0.010 1.0 1929 SILTSTONE 4253.0 9.6 0.050 10.0 1936 CLEAN-SANDSTONE 4277.1 3.5 48.343 24.3 1947 SHALE 4280.6 0.0 0.006 10.0 1949 DIRTY-SANDSTONE 4282.1 1.1 39.757 23.6 1949 DIRTY-SANDSTONE 4283.6 2.5 6.288 20.8 1950 CLEAN-SANDSTONE 4287.1 2.0 71.711 26.2 1952 SHALE 4289.1 0.0 0.006 10.0 1952 DIRTY-SANDSTONE 4290.6 9.8 56.440 16.7 1953 SHALE 4304.6 0.0 0.006 10.0 1960 DIRTY-SANDSTONE 4306.1 2.5 18.893 20.8 1960 DIRTY-SANDSTONE 4309.6 1.1 0.023 15.0 1962 DIRTY-SANDSTONE 4311.1 1.4 115.609 24.9 1963 DIRTY-SANDSTONE 4313.1 3.5 20.857 19.5 1964 DIRTY-SANDSTONE 4318.1 7.0 1.968 17.0 1966 DIRTY-SANDSTONE 4328.1 7.0 74.766 24.2 1971 DIRTY-SANDSTONE 4338.1 3.5 11.675 20.1 1975 DIRTY-SANDSTONE 4343.1 6.0 7.321 16.9 1978 DIRTY-SANDSTONE 4351.6 2.5 3.784 17.3 1982 SHALE 4355.1 0.0 0.006 10.0 1983 DIRTY-SANDSTONE 4357.6 0.7 1.340 15.9 1984 SHALE 4358.6 0.0 0.006 10.0 1985 DIRTY-SANDSTONE 4365.6 2.5 40.985 23.3 1988 DIRTY-SANDSTONE 4369.1 3.2 1.316 14.2 1990 DIRTY-SANDSTONE 4373.6 1.4 4.219 18.6 1992 DIRTY-SANDSTONE 4375.6 1.4 0.015 14.6 1993 DIRTY-SANDSTONE 4377.6 3.9 61.197 22.9 1994 DIRTY-SANDSTONE 4383.1 4.2 0.552 13.9 1996 DIRTY-SANDSTONE 4389.1 7.0 28.233 19.9 1999 DIRTY-SANDSTONE 4399.1 1.4 1.534 17.0 2004 DIRTY-SANDSTONE 4401.1 5.3 79.135 22.8 2005 DIRTY-SANDSTONE 4408.6 1.1 0.006 10.0 2008 DIRTY-SANDSTONE 4410.1 2.1 120.250 23.7 2009 DIRTY-SANDSTONE 4413.1 3.5 0.329 14.3 2010 SHALE 4418.1 0.0 0.006 10.0 2013 DIRTY-SANDSTONE 4424.1 1.4 0.136 14.8 2015 SHALE 4426.1 0.0 0.006 10.0 2016 DIRTY-SANDSTONE 4449.1 1.4 15.982 19.8 2027 SHALE 4451.1 0.0 0.006 10.0 2028 DIRTY-SANDSTONE 4453.1 1.4 0.344 15.1 2029 SHALE 4455.1 0.0 0.006 10.0 2030 DIRTY-SANDSTONE 4459.6 7.0 6.547 19.3 2032 SHALE 4469.6 0.0 0.006 10.0 2036 DIRTY-SANDSTONE 4480.1 1.4 1.897 18.0 2041 SHALE 4482.1 0.0 0.006 10.0 2042 DIRTY-SANDSTONE 4501.1 1.4 4.758 17.7 2051 SHALE 4503.1 0.0 0.006 10.0 2052 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 35 of 45 Attachment G Section 26: Propped Fracture Schedule (Stage 9; 8829 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 30 YF122ST 200.0 22 0 1.0 PPA 30 YF122ST 162.9 22 1.0 3.0 PPA 30 YF122ST 150.3 22 3.0 5.0 PPA 30 YF122ST 192.8 22 5.0 7.0 PPA 30 YF122ST 160.8 22 7.0 9.0 PPA 30 YF122ST 150.7 22 9.0 10.0 PPA 30 YF122ST 132.2 22 10.0 Flush 30 WF122 129.6 22 0.0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1150 bbl of YF122ST 129.6 bbl of WF122 225983 lb of 16/20 C-Lite % PAD Clean 17.4 % PAD Dirty 14.4 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 200.0 200 200 200 0 0 2479 6.7 6.7 1.0 PPA 162.9 363 170 370 6841 6841 2441 5.7 12.3 3.0 PPA 150.3 513 170 540 18934 25775 2464 5.7 18.0 5.0 PPA 192.8 706 235 775 40490 66265 2673 7.8 25.8 7.0 PPA 160.8 867 210 985 47261 113526 2825 7.0 32.8 9.0 PPA 150.7 1017 210 1195 56949 170475 2917 7.0 39.8 10.0 PPA 132.2 1150 190 1385 55508 225983 2934 6.3 46.2 Flush 129.6 1279 130 1515 0 225983 3021 4.3 50.5 Carbolite 16/20 Fluid Totals Job Execution Job Description Prop. Type and MeshFluid Name Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 311.2 ft with an average conductivity (Kfw) of 14620 md.ft. Carbolite 16/20 Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 # SLB-PrivatePage 36 of 45 Attachment G Section 27: Propped Fracture Simulation (Stage 9; 8829 ft MD) Stage 9 MD 8829 ft Initial Fracture Top TVD 4236 ft Initial Fracture Bottom TVD 4427 ft Propped Fracture Half-Length 311.2 ft EOJ Hyd Height at Well 286.7 ft Average Propped Width 0.155 in Net Pressure 94 psi Max Surface Pressure 3155 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 77.8 9.8 0.175 169.3 1.46 161.7 15972 77.8 155.6 8.1 0.18 250.2 1.55 168 15876 155.6 233.4 6.2 0.165 230.8 1.47 187 14515 233.4 311.2 2.3 0.107 149.3 0.99 445.4 9107 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-PrivatePage 37 of 45 Attachment G Section 28: Zone Data (Stage 10; 8311 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4226.0 31.7 0.71 3012 1.46E+06 0.22 2500 SHALE 4257.7 15.0 0.70 2964 1.76E+06 0.22 2500 SHALE 4272.7 24.1 0.69 2961 1.90E+06 0.22 2500 SHALE 4296.8 3.5 0.69 2961 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4300.3 1.5 0.62 2673 1.03E+06 0.27 1500 SHALE 4301.8 2.0 0.69 2964 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4303.8 5.0 0.64 2769 1.34E+06 0.26 1500 SHALE 4308.8 6.5 0.69 2970 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4315.3 7.0 0.65 2804 1.46E+06 0.26 1500 DIRTY-SANDSTONE 4322.3 1.5 0.63 2728 1.42E+06 0.26 1500 SHALE 4323.8 2.0 0.69 2979 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4325.8 1.5 0.62 2703 1.18E+06 0.27 1500 SHALE 4327.3 7.0 0.69 2983 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4334.3 3.0 0.65 2818 1.60E+06 0.26 1500 SHALE 4337.3 2.0 0.69 2988 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4339.3 3.0 0.65 2828 1.59E+06 0.26 1500 SHALE 4342.3 5.5 0.69 2993 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4347.8 1.5 0.60 2628 1.20E+06 0.27 1500 SHALE 4349.3 8.5 0.69 2999 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4357.8 3.5 0.64 2773 9.21E+05 0.27 1500 DIRTY-SANDSTONE 4361.3 4.5 0.65 2839 1.74E+06 0.26 1500 SHALE 4365.8 12.0 0.69 3011 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4377.8 2.0 0.64 2798 1.55E+06 0.26 1500 SHALE 4379.8 9.5 0.69 3020 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4389.3 1.5 0.65 2852 1.75E+06 0.26 1500 SHALE 4390.8 2.0 0.69 3025 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4392.8 2.0 0.64 2831 1.00E+06 0.27 1500 SHALE 4394.8 17.0 0.69 3033 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4411.8 4.0 0.63 2777 9.13E+05 0.27 1500 SHALE 4415.8 15.5 0.69 3047 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4431.3 1.5 0.63 2773 1.03E+06 0.27 1500 SHALE 4432.8 2.0 0.69 3054 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4434.8 2.0 0.65 2880 1.67E+06 0.26 1500 SHALE 4436.8 8.0 0.69 3059 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4444.8 5.5 0.66 2928 1.67E+06 0.26 1500 SHALE 4450.3 2.0 0.69 3066 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4452.3 2.0 0.63 2795 1.12E+06 0.27 1500 SHALE 4454.3 21.5 0.69 3076 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4475.8 2.0 0.64 2859 8.77E+05 0.27 1500 SHALE 4477.8 17.5 0.69 3090 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4495.3 3.5 0.65 2915 1.59E+06 0.26 1500 SHALE 4498.8 48.5 0.69 3115 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4547.3 4.0 0.63 2856 1.46E+06 0.26 1500 SHALE 4551.3 2.0 0.69 3136 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4553.3 2.0 0.65 2966 1.55E+06 0.26 1500 SHALE 4555.3 11.5 0.69 3142 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4566.8 10.0 0.64 2934 1.46E+06 0.26 1500 SHALE 4576.8 50.0 0.69 3170 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 38 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure Gas Sat. Oil Sat. Water Sat. (ft)Height (md) (%) (psi) (%) (%) (%) (ft) Shale 4226.0 0.1 0.010 1.0 1921 65 10 25 SHALE 4257.7 0.1 0.010 1.0 1935 65 10 25 SHALE 4272.7 0.1 0.050 10.0 1942 65 10 25 SHALE 4296.8 0.1 0.010 1.0 1953 65 10 25 DIRTY-SANDSTONE 4300.3 1.1 21.752 22.2 1955 65 10 25 SHALE 4301.8 0.1 0.010 1.0 1955 65 10 25 DIRTY-SANDSTONE 4303.8 3.5 4.241 18.7 1956 65 10 25 SHALE 4308.8 0.1 0.010 1.0 1958 65 10 25 DIRTY-SANDSTONE 4315.3 4.9 0.799 17.4 1961 65 10 25 DIRTY-SANDSTONE 4322.3 1.1 3.800 17.9 1965 65 10 25 SHALE 4323.8 0.1 0.010 1.0 1965 65 10 25 DIRTY-SANDSTONE 4325.8 1.1 11.075 20.5 1966 65 10 25 SHALE 4327.3 0.1 0.010 1.0 1967 65 10 25 DIRTY-SANDSTONE 4334.3 2.1 0.357 15.9 1970 65 10 25 SHALE 4337.3 0.1 0.010 1.0 1972 65 10 25 DIRTY-SANDSTONE 4339.3 2.1 0.920 16.1 1973 65 10 25 SHALE 4342.3 0.1 0.010 1.0 1974 65 10 25 DIRTY-SANDSTONE 4347.8 1.1 19.275 20.2 1976 65 10 25 SHALE 4349.3 0.1 0.010 1.0 1977 65 10 25 DIRTY-SANDSTONE 4357.8 2.5 54.122 23.5 1981 65 10 25 DIRTY-SANDSTONE 4361.3 3.2 0.208 14.5 1983 65 10 25 SHALE 4365.8 0.1 0.010 1.0 1985 65 10 25 DIRTY-SANDSTONE 4377.8 1.4 1.323 16.5 1990 65 10 25 SHALE 4379.8 0.1 0.010 1.0 1991 65 10 25 DIRTY-SANDSTONE 4389.3 1.1 0.361 14.4 1996 65 10 25 SHALE 4390.8 0.1 0.010 1.0 1996 65 10 25 DIRTY-SANDSTONE 4392.8 1.4 25.112 22.5 1997 65 10 25 SHALE 4394.8 0.1 0.010 1.0 1998 65 10 25 DIRTY-SANDSTONE 4411.8 2.8 74.241 23.6 2006 65 10 25 SHALE 4415.8 0.1 0.010 1.0 2008 65 10 25 DIRTY-SANDSTONE 4431.3 1.1 29.847 22.2 2015 65 10 25 SHALE 4432.8 0.1 0.010 1.0 2016 65 10 25 DIRTY-SANDSTONE 4434.8 1.4 0.355 15.2 2017 65 10 25 SHALE 4436.8 0.1 0.010 1.0 2018 65 10 25 DIRTY-SANDSTONE 4444.8 3.9 0.306 15.2 2021 65 10 25 SHALE 4450.3 0.1 0.010 1.0 2024 65 10 25 DIRTY-SANDSTONE 4452.3 1.4 33.540 21.1 2025 65 10 25 SHALE 4454.3 2.5 0.010 1.0 2026 65 10 25 DIRTY-SANDSTONE 4475.8 0.1 62.109 24.1 2036 65 10 25 SHALE 4477.8 2.8 0.010 1.0 2037 65 10 25 DIRTY-SANDSTONE 4495.3 0.1 0.629 7.5 2045 65 10 25 SHALE 4498.8 1.4 0.010 1.0 2046 65 10 25 DIRTY-SANDSTONE 4547.3 0.1 15.520 10.0 2069 65 10 25 SHALE 4551.3 0.1 0.010 1.0 2071 65 10 25 DIRTY-SANDSTONE 4553.3 1.4 1.839 16.4 2071 65 10 25 SHALE 4555.3 0.1 0.010 1.0 2072 65 10 25 DIRTY-SANDSTONE 4566.8 7.0 4.688 14.4 2078 65 10 25 SHALE 4576.8 0.1 0.010 1.0 2082 65 10 25 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 39 of 45 Attachment G Section 29: Propped Fracture Schedule (Stage 10; 8311 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 25 YF122ST 175.0 22 0 1.0 PPA 25 YF122ST 134.1 22 1.0 3.0 PPA 25 YF122ST 137.0 22 3.0 5.0 PPA 25 YF122ST 172.3 22 5.0 7.0 PPA 25 YF122ST 145.4 22 7.0 9.0 PPA 25 YF122ST 136.3 22 9.0 10.0 PPA 25 YF122ST 118.2 22 10.0 Flush 25 WF122 122.0 22 0.0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1018 bbl of YF122ST 122 bbl of WF122 203030 lb of 16/20 C-Lite % PAD Clean 17.2 % PAD Dirty 14.2 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 175.0 175 175 175 0 0 2163 7.0 7.0 1.0 PPA 134.1 309 140 315 5633 5633 2134 5.6 12.6 3.0 PPA 137.0 446 155 470 17263 22897 2079 6.2 18.8 5.0 PPA 172.3 618 210 680 36182 59079 2149 8.4 27.2 7.0 PPA 145.4 764 190 870 42760 101840 2207 7.6 34.8 9.0 PPA 136.3 900 190 1060 51525 153365 2224 7.6 42.4 10.0 PPA 118.2 1018 170 1230 49665 203030 2205 6.8 49.2 Flush 122.0 1140 122 1352 0 203030 2413 4.9 54.1 Fluid Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 542.8 ft with an average conductivity (Kfw) of 7333 md.ft. Job Execution Job Description Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Step Name # SLB-PrivatePage 40 of 45 Attachment G Section 30: Propped Fracture Simulation (Stage 10; 8311 ft MD) Stage 10 MD 8311 ft Initial Fracture Top TVD 4247 ft Initial Fracture Bottom TVD 4428 ft Propped Fracture Half-Length 542.8 ft EOJ Hyd Height at Well 334.5 ft Average Propped Width 0.072 in Net Pressure 317 psi Max Surface Pressure 2607 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 135.7 7.5 0.106 165.4 0.89 155.2 9377 135.7 271.4 4.7 0.096 235.6 0.9 179.8 7985 271.4 407.1 2.2 0.065 204.3 0.63 220.5 5237 407.1 542.8 0.1 0.03 142.1 0.31 513.6 1958 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-PrivatePage 41 of 45 Attachment G Section 31: Zone Data (Stage 11; 7833 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in0.5) Shale 4226.0 31.7 0.71 3012 1.46E+06 0.22 2500 SHALE 4257.7 15.0 0.70 2964 1.76E+06 0.22 2500 SHALE 4272.7 24.1 0.69 2961 1.90E+06 0.22 2500 SHALE 4296.8 3.5 0.69 2961 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4300.3 1.5 0.62 2673 1.03E+06 0.27 1500 SHALE 4301.8 2.0 0.69 2964 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4303.8 5.0 0.64 2769 1.34E+06 0.26 1500 SHALE 4308.8 6.5 0.69 2970 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4315.3 7.0 0.65 2804 1.46E+06 0.26 1500 DIRTY-SANDSTONE 4322.3 1.5 0.63 2728 1.42E+06 0.26 1500 SHALE 4323.8 2.0 0.69 2979 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4325.8 1.5 0.62 2703 1.18E+06 0.27 1500 SHALE 4327.3 7.0 0.69 2983 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4334.3 3.0 0.65 2818 1.60E+06 0.26 1500 SHALE 4337.3 2.0 0.69 2988 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4339.3 3.0 0.65 2828 1.59E+06 0.26 1500 SHALE 4342.3 5.5 0.69 2993 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4347.8 1.5 0.60 2628 1.20E+06 0.27 1500 SHALE 4349.3 8.5 0.69 2999 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4357.8 3.5 0.64 2773 9.21E+05 0.27 1500 DIRTY-SANDSTONE 4361.3 4.5 0.65 2839 1.74E+06 0.26 1500 SHALE 4365.8 12.0 0.69 3011 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4377.8 2.0 0.64 2798 1.55E+06 0.26 1500 SHALE 4379.8 9.5 0.69 3020 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4389.3 1.5 0.65 2852 1.75E+06 0.26 1500 SHALE 4390.8 2.0 0.69 3025 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4392.8 2.0 0.64 2831 1.00E+06 0.27 1500 SHALE 4394.8 17.0 0.69 3033 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4411.8 4.0 0.63 2777 9.13E+05 0.27 1500 SHALE 4415.8 15.5 0.69 3047 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4431.3 1.5 0.63 2773 1.03E+06 0.27 1500 SHALE 4432.8 2.0 0.69 3054 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4434.8 2.0 0.65 2880 1.67E+06 0.26 1500 SHALE 4436.8 8.0 0.69 3059 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4444.8 5.5 0.66 2928 1.67E+06 0.26 1500 SHALE 4450.3 2.0 0.69 3066 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4452.3 2.0 0.63 2795 1.12E+06 0.27 1500 SHALE 4454.3 21.5 0.69 3076 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4475.8 2.0 0.64 2859 8.77E+05 0.27 1500 SHALE 4477.8 17.5 0.69 3090 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4495.3 3.5 0.65 2915 1.59E+06 0.26 1500 SHALE 4498.8 48.5 0.69 3115 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4547.3 4.0 0.63 2856 1.46E+06 0.26 1500 SHALE 4551.3 2.0 0.69 3136 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4553.3 2.0 0.65 2966 1.55E+06 0.26 1500 SHALE 4555.3 11.5 0.69 3142 2.67E+06 0.23 2500 DIRTY-SANDSTONE 4566.8 10.0 0.64 2934 1.46E+06 0.26 1500 SHALE 4576.8 50.0 0.69 3170 2.67E+06 0.23 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-PrivatePage 42 of 45 Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) Shale 4226.0 0.1 0.010 1.0 1921 SHALE 4257.7 0.1 0.010 1.0 1935 SHALE 4272.7 0.1 0.050 10.0 1942 SHALE 4296.8 0.1 0.010 1.0 1953 DIRTY-SANDSTONE 4300.3 1.1 21.752 22.2 1955 SHALE 4301.8 0.1 0.010 1.0 1955 DIRTY-SANDSTONE 4303.8 3.5 4.241 18.7 1956 SHALE 4308.8 0.1 0.010 1.0 1958 DIRTY-SANDSTONE 4315.3 4.9 0.799 17.4 1961 DIRTY-SANDSTONE 4322.3 1.1 3.800 17.9 1965 SHALE 4323.8 0.1 0.010 1.0 1965 DIRTY-SANDSTONE 4325.8 1.1 11.075 20.5 1966 SHALE 4327.3 0.1 0.010 1.0 1967 DIRTY-SANDSTONE 4334.3 2.1 0.357 15.9 1970 SHALE 4337.3 0.1 0.010 1.0 1972 DIRTY-SANDSTONE 4339.3 2.1 0.920 16.1 1973 SHALE 4342.3 0.1 0.010 1.0 1974 DIRTY-SANDSTONE 4347.8 1.1 19.275 20.2 1976 SHALE 4349.3 0.1 0.010 1.0 1977 DIRTY-SANDSTONE 4357.8 2.5 54.122 23.5 1981 DIRTY-SANDSTONE 4361.3 3.2 0.208 14.5 1983 SHALE 4365.8 0.1 0.010 1.0 1985 DIRTY-SANDSTONE 4377.8 1.4 1.323 16.5 1990 SHALE 4379.8 0.1 0.010 1.0 1991 DIRTY-SANDSTONE 4389.3 1.1 0.361 14.4 1996 SHALE 4390.8 0.1 0.010 1.0 1996 DIRTY-SANDSTONE 4392.8 1.4 25.112 22.5 1997 SHALE 4394.8 0.1 0.010 1.0 1998 DIRTY-SANDSTONE 4411.8 2.8 74.241 23.6 2006 SHALE 4415.8 0.1 0.010 1.0 2008 DIRTY-SANDSTONE 4431.3 1.1 29.847 22.2 2015 SHALE 4432.8 0.1 0.010 1.0 2016 DIRTY-SANDSTONE 4434.8 1.4 0.355 15.2 2017 SHALE 4436.8 0.1 0.010 1.0 2018 DIRTY-SANDSTONE 4444.8 3.9 0.306 15.2 2021 SHALE 4450.3 0.1 0.010 1.0 2024 DIRTY-SANDSTONE 4452.3 1.4 33.540 21.1 2025 SHALE 4454.3 2.5 0.010 1.0 2026 DIRTY-SANDSTONE 4475.8 0.1 62.109 24.1 2036 SHALE 4477.8 2.8 0.010 1.0 2037 DIRTY-SANDSTONE 4495.3 0.1 0.629 7.5 2045 SHALE 4498.8 1.4 0.010 1.0 2046 DIRTY-SANDSTONE 4547.3 0.1 15.520 10.0 2069 SHALE 4551.3 0.1 0.010 1.0 2071 DIRTY-SANDSTONE 4553.3 1.4 1.839 16.4 2071 SHALE 4555.3 0.1 0.010 1.0 2072 DIRTY-SANDSTONE 4566.8 7.0 4.688 14.4 2078 SHALE 4576.8 0.1 0.010 1.0 2082 Zone Name Formation Transmissibility Properties # SLB-PrivatePage 43 of 45 Attachment G Section 32: Propped Fracture Schedule (Stage 11; 7833 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 20 YF122ST 140.0 22 0 1.0 PPA 20 YF122ST 119.8 22 1.0 3.0 PPA 20 YF122ST 128.2 22 3.0 5.0 PPA 20 YF122ST 155.9 22 5.0 7.0 PPA 20 YF122ST 130.1 22 7.0 9.0 PPA 20 YF122ST 122.0 22 9.0 10.0 PPA 20 YF122ST 104.3 22 10.0 Flush 20 WF122 119.4 22 0.0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 900 bbl of YF122ST 119.4 bbl of WF122 182099 lb of 16/20 C-Lite % PAD Clean 15.6 % PAD Dirty 12.8 Step Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Pressure Step Time Cum. Fluid Volume Volume Volume (lb)Prop.(psi) (min)Time Volume (bbl) (bbl) (bbl) (lb) (min) (bbl) PAD 140.0 140 140 140 0 0 1839 7.0 7.0 1.0 PPA 119.8 260 125 265 5030 5030 1791 6.3 13.3 3.0 PPA 128.2 388 145 410 16150 21180 1692 7.3 20.5 5.0 PPA 155.9 544 190 600 32737 53916 1652 9.5 30.0 7.0 PPA 130.1 674 170 770 38259 92175 1632 8.5 38.5 9.0 PPA 122.0 796 170 940 46102 138277 1587 8.5 47.0 10.0 PPA 104.3 900 150 1090 43822 182099 1539 7.5 54.5 Flush 119.4 1020 119 1209 0 182099 1836 6.0 60.5 Carbolite 16/20 Fluid Totals Job Execution Job Description Prop. Type and MeshFluid Name Carbolite 16/20 Proppant Totals Pad Percentages The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 400.2 ft with an average conductivity (Kfw) of 9218 md.ft. Carbolite 16/20 Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 # SLB-PrivatePage 44 of 45 Attachment G Section 33: Propped Fracture Simulation (Stage 11; 7833 ft MD) Stage 11 MD 7833 ft Initial Fracture Top TVD 4251 ft Initial Fracture Bottom TVD 4446 ft Propped Fracture Half-Length 400.2 ft EOJ Hyd Height at Well 338.2 ft Average Propped Width 0.082 in Net Pressure 133 psi Max Surface Pressure 2150 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture Conductivity (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc.(md.ft) (PPA) (in) (ft) (lb/ft2) (lb/mgal) 0 100.1 8.4 0.114 181.8 0.96 140.7 9977 100.1 200.1 5.6 0.097 252.6 0.88 162.6 8160 200.1 300.2 2.4 0.072 212.8 0.69 217 5788 300.2 400.2 0.1 0.053 153 0.53 604.8 4114 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-PrivatePage 45 of 45 Attachment G Attachment H Additive Additive Description F103 Surfactant 1.0 Gal/mGal 686.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 304.8 gal J475 Breaker J475 6.0 lb/mGal 4,033.5 lbm J511 Stabilizing Agent 1.8 lb/mGal 1,219.3 lbm J532 Crosslinker 2.3 Gal/mGal 1,524.1 gal J580 Gel J580 22.0 lb/mGal 14,834.7 lbm J753 Enzyme Breaker J753 0.0 Gal/mGal 25.1 gal M275 Bactericide 0.3 lb/mGal 203.2 lbm S522-1620 Propping Agent varied concentrations 2,494,443.0 lbm ~ 69 % ~ 31 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % 100 % 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 14808-60-7 Quartz, Crystalline silica 64-19-7 Acetic acid (impurity) 532-32-1 Sodium benzoate 127-08-2 Acetic acid, potassium salt (impurity) 9000-90-2 Amylase, alpha 14464-46-1 Cristobalite 9002-84-0 poly(tetrafluoroethylene) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 14807-96-6 Magnesium silicate hydrate (talc) 91053-39-3 Diatomaceous earth, calcined 112-42-5 1-undecanol (impurity) 9025-56-3 Hemicellulase 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 50-70-4 Sorbitol 67-63-0 Propan-2-ol 111-76-2 2-butoxyethanol 56-81-5 1, 2, 3 - Propanetriol 102-71-6 2,2`,2"-nitrilotriethanol 1303-96-4 Sodium tetraborate decahydrate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 7727-54-0 Diammonium peroxidisulphate CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF122 ST:WF122 673,554 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-1638 Fluid Name & Volume Concentration Volume Disclosure Type:Pre-Job Well Completed: Date Prepared:7/17/2023 State:Alaska County/Parish:North Slope Borough Case: Client:Oil Search Alaska Well:NDBi-43 Basin/Field:Pikka # SLB-Private Page: 1 / 1 Attachment I NDBi-043 Clean-up and Test Summary TABLE OF FLOW PERIODS Flow / Build Up Table Duration (hours)Purpose / Remarks Clean-Up & Initial Flow As Required ~48 - 72 Bring well on slowly (16/64th) via adjustable choke, adjust as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to proppant pack and to minimize erosion to surface equipment. The Santos Reservoir Engineer will determine when the well is clean and advise choke changes/rates for initial flow period. Initial Pressure Build Up ~24 Shut in for Build-up / Analysis Well Test (Main Flow) 144 Conduct 3-day flow test as per table below or as directed by Santos Reservoir Engineer. Rate # Flow Rate BBL/D Duration (hours) Clean-up 1 500-3000 72 SI 0 24 Main Flow 2 1500 - 4800 72 SI 0 168 NOTE 1:If drawdown exceeds 400psi during main flow, Reduce Rate Note 2: Addition data point for IPR Curve. The IPR curve is a graphical presentation of the relationship between the flowing bottom-hole pressure and the liquid production rate. NOTE: Main flow period may be extended (TBD) Final Build-Up Period 168 Surface equipment will be rigged down during this SI period Table 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well clean-up flowback work. Total volume of gas per the well test program listed above are approximately 7.1 MMscf. Well Cleanup - Operational Summary: x Estimates Time: 24 – 72 hours or as dictated by Santos Reservoir Engineer. x Target Clean-up Flow Rate: 50 – 3000 BPD w/ some gas x Target Post Clean-up Flow Rate:Up to 4500 BPD & 2.2 mmscf/d x Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Reservoir Engineer or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. Conduct 3-day flow test a x Proppant Production:Proppant production is expected and will manage by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. x N2 Injection Rate: As per contingency N2 well kick-off procedures if required. x Methanol Injection Rate: MeoH will be injected into the well via the inner annulus to prevent the formation of hydrates. Injection rates will vary based on produced water volumes. x Sampling: As per sampling table 2 below Table 2 Main Flow- Operational Summary: x Estimates Time: 72 hours or as directed by Santos Reservoir Engineer. x Main Flow Period:Up to 4800 BPD & up to 2.4 mmscf/d x Choke Setting: Bring the well on slowly using the adjustable choke, Santos Reservoir Engineer will advise drawdown targets based on observation from initial flow. Step open choke until desired flow rate is achieved, then switch to a positive choke. The Santos Reservoir Engineer & Santos Well Test Supervisor will advise target rates and choke changes. x Proppant Production:Minimal proppant production is expected. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure will be 2,000 psi., bleed as required. x Sampling: As per sampling table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion coriolis flow meter will be used for gas rates & volumes. Surface Sampling Program Flow Period Sample Type Lab Analysis Number / Frequency Location Volume Sampling Container Collection Vendor Comments Cl e a n U p BS&W, API, WC Hourly Choke 100 ml Centrifuge Tube Expro Utilize EB as necessary, document in job log Oil API Gravity 2 per shift Separator 1000 ml Nalgene Bottle Expro Salinity H2O % Chlorides Hourly Separator NA NA Expro Perform hourly or as H2O production allows Ranarex Gas Gravity Hourly Separator NA NA Expro Glass Sample Tube H2S, CO2 Hourly Separator NA NA Expro Hourly to start, reduce to every 12 hrs if no H2S observed after 3 consecutive reads. Attachment J 1. 9-5/8” 47# & 13-3/8” 68# casing has been tested to 4,000 psi. 2. E-line - CBL will be completed after the 4-1/2” liner section has been ran. Once completed, results to be forward to AOGCC. NDBi-043 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 OBM with 9.4 ppg NaCl brine to surface. 3. Flow check for 10 minutes. 4. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 5. Pressure up to close the WIV at 1,980 psi. 6. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 7. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. 8. Before releasing, pressure test the IA to top liner hanger/packer to 3,000 psi. 9. Release running tool from liner hanger. 10.Circulate 9.4 ppg NaCl inhibited brine to surface at 10 bpm pump rate. 11.POOH with liner hanger running tool. 12.Prepare to run upper completion. NDBi-043 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 and pressure test void to 5,000 psi. 3. MIT-T to 4,000 psi on rig. (Post drilling rig move, 4-1/2” tubing and liner will be tested to 6,000 psi for MIT-T prior to frac with 10K frac tree). Chart Pressure Test and forward to AOGCC) a. (8,900 psi MAWP – 3,500 psi IA held) * 1.1 = 5,940 psi 4. MIT-IA to 4,000 psi. Chart Pressure Test and forward to AOGCC. 5. Shear circulation valve. 6. Circulate Freeze Protect 7. Install two-way check into the tubing hanger and pressure test from direction of flow. 8. Pressure test TWCV direction of flow to 2500 psi for 30 minutes. 9. Nipple down BOP stack and install 5k psi dry hole tree. 10.RDMO ,p g( gg , 6,000 psi for MIT-T prior to frac with 10K frac tree) MIT-IA to 4,000 psi. Chart Pressure Test and forward to AOGCC. g Chart Pressure Test). and forward to AOGCC) ,p NDBi-043 Flow Test Procedure 1. Move in and rig up Well Test Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up flowback as per procedures. 5. Perform flow test, shut in, and sampling as per procedures. 6.Rig down and demobilize equipment. Not approved on this sundry over disposal concerns and waste. CDW. This Flow Test procedure is authorized under this sundry per plan agreed to in email correspondence between Dave Roby and Nick Miller on 8/22/23 (attached). Disregard the diagonal line crossing out the text below. bjm Attachment K Attachment L 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Tuesday, August 22, 2023 1:37 PM To:Roby, David S (OGC) Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Guhl, Meredith D (OGC) Subject:RE: Conditional approval to inject clean-up fluid into DW-02 (Pikka NDBi-043A (PTD 223-052; Sundry 323-411) Dave, Notedandthankyouforthequickturnaround. NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Roby,DavidS(OGC)<dave.roby@alaska.gov> Sent:Tuesday,August22,20231:30PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>; Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov> Subject:![EXT]:RE:ConditionalapprovaltoinjectcleanͲupfluidintoDWͲ02(PikkaNDBiͲ043A(PTD223Ͳ052;Sundry 323Ͳ411) HiNick, Thanksforthis.TheplanoutlinedbelowisacceptabletotheAOGCCforhandlingtheŇuidsthatwillbeproducedduring thewellcleanupandsubsequentŇowtest. Regards, DaveRoby (907)793Ͳ1232 From:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Sent:Tuesday,August22,20231:28PM To:Roby,DavidS(OGC)<dave.roby@alaska.gov> Subject:ConditionalapprovaltoinjectcleanͲupfluidintoDWͲ02(PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411) CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Dave, SantosplanstoinjectŇuidsdesignatedascleanͲupfromourĮrst2Ͳ3daysofiniƟalŇowintoourDWͲ02G&Iwelllocated ontheNDBlocaƟon.AllŇuidsdesignatedwelltestwillbehauledoīNDBlocaƟontoMilnePointhydrocarbonrecycling facility.PleasegrantcondiƟonalfracsundryapprovalbasedonaboveplan. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Thursday, August 3, 2023 8:55 AM To:Roby, David S (OGC) Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Bond, Andrew (Andy) Subject:RE: Sundry application for NDBi-043 (PTD 223-052) Dave, Aswediscussed,ourbaseplanforflowbackfluiddisposalfromthePikkawellsistoinjectintoDWͲ02,theClass1 disposalwelllocatedontheNDBdrillsite.Thisrepresentsthesafestandmostefficientwaytodisposeofourflowback fluidandavoidstheneedtohaul35Ͳ50truckloadsofhydrocarbonͲbearingfluid,perwell,toanothersuitablelocation acrosstheSlope.Truckingtoanotherlocationandcomingtoanagreementwithanotheroperatortotakeourfluidwill likelyresultinsignificantcostincreases.Ourpadanddisposalwellsystemshavebeenengineeredandconstructedto receiveourflowbackfluid. Truckingthisfluidwouldunnecessarilyincreasetrafficacrossthefield.Severaloperatorsintheareaareconducting majornewprojects,suchastheWillowdevelopmentandHilcorp’sredevelopmentplansinPrudhoeBayandMilne Point.Alloftheseprojectsincreasetrucktrafficthroughoutthefieldandcreatecongestiononinfieldroads. Increasedtrucktrafficwillalsosignificantlyraisetheriskofaccidents,spillsorotherincidents.KeepingthefluidonͲpad anddelivereddirectlytotheDWͲ02disposalwellisthebestwaytominimizethisrisk. Santosdoesnothaveanarrangementwithanyotheroperatortotakeourflowbackfluidintotheirproductionstream, andit’suncertainwhetherwecouldfindanoperatortoagreetotakeitonreasonableterms.Thequalityofour flowbackfluidwillbehighlyvariableasourwellscleanupandwilllikelybeoffͲspecforotherfieldproductionfacilities. WhatisthenextsteptoallowustoproceedwithinjectingallflowbackfluidintoDWͲ02? Regards, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Roby,DavidS(OGC)<dave.roby@alaska.gov> Sent:Monday,July31,202311:59AM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>; Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Bond, Andrew(Andy)<Andy.Bond@santos.com> Subject:![EXT]:RE:SundryapplicationforNDBiͲ043(PTD223Ͳ052) 2 HiNick, Iwasmisrememberingwhatyoursundryapplicationsaidabouttesting.Here’swhatwas showninAttachmentI: Latteritsaysthecleanupperiodisexpectedtobe24Ͳ72hours.LikeIsaidwe’dmorethan likelynotconsideranyoilproducedduringthisstagetobewasteifitisdisposedof. So,assumingthisisthesameplanforallwellsitlookslikewe’retalkingabout3daysof productionandsomewhereuptoatotalof14,400totalbblsofliquids(perthepresentation Santosgaveatthepoolruleshearingitlookslikeverylittlewaterproductionisexpectedearly infieldlifesoitappearsthevastmajorityofthetestproductionwillbeoil)foreachwell,orfor the25wellscompletedpreprocessingfacilityinstallationandcommissioning75daysofflow andupto360,000bblsofmostlyoil. DaveRoby (907)793Ͳ1232 From:Roby,DavidS(OGC) Sent:Thursday,July20,202312:24PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>; Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Bond, Andrew(Andy)<Andy.Bond@santos.com> Subject:RE:SundryapplicationforNDBiͲ043(PTD223Ͳ052) HiNicklaus, 3 DisposalofoilisgenerallynotallowedbytheAOGCC.Thevolumethatcomesoutwiththesandandcompletionfluid duringtheinitialwellcleanupcangodownthedisposalwellwiththosefluids,butoncethewelliscleanedupandthe flowtestsbeginthatoilcannotbedisposedof,ifitisitwouldconstitutewaste.Typically,whenoperatorsflowtest wellstheytransporttheproducedoiltoanotherfacilitywhereitcanbeprocessedandsold.Pleaselookintoother meansofdealingwiththeproducedoil. Regards, DaveRoby (907)793Ͳ1232 From:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Sent:Thursday,July20,202310:55AM To:Roby,DavidS(OGC)<dave.roby@alaska.gov> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>; Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Bond, Andrew(Andy)<Andy.Bond@santos.com> Subject:RE:SundryapplicationforNDBiͲ043(PTD223Ͳ052) Dave, Weplantodisposeofallproducedfluids,oilincluded,inourDWͲ02ClassIinjectionwelllocatedonNDBpad.DWͲ02 targetstheTorokformationandSantoshasidentifiedprimaryandsecondaryinjectionintervalswithintheTorok. Asbackupoption,wehaveacontractinplacetohaulourproducedfluids,oilincluded,toDS4runbyHilcorpAlaska, LLC. Thanks, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Roby,DavidS(OGC)<dave.roby@alaska.gov> Sent:Wednesday,July19,20235:01PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>; Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>;Bond, Andrew(Andy)<Andy.Bond@santos.com> Subject:![EXT]:SundryapplicationforNDBiͲ043(PTD223Ͳ052) Nicklaus, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 4 InreviewingthesubjectsundryapplicationIdidn’tseewhatyouplantodowiththefluidsproducedduringthecleanup andpostͲcleanupflowtest.Pleaseletmeknowwhatyouplantodowiththefluids,particularlytheoil. Thankyou, DaveRoby SeniorReservoirEngineer AlaskaOilandGasConservationCommission (907)793Ͳ1232 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Monday, August 21, 2023 3:50 PM To:Davies, Stephen F (OGC) Subject:Shallow Aquifer Salinity - Pikka NDBi-043A (PTD 223-052; Sundry 323-411) Attachments:NDB pad shallow salinity petrophysical analysis.pdf Steve, Seeattachedanalysisthatexaminesthe3wellswithinthePikkaUnitwithadequatewirelinelogsforsalinity analysisandreportssalinitiesbetween16,700Ͳ23,000ppmNaClEquivalentwithintheSchraderBluffshallowsand. Ilookforwardtoyourresponseandappreciateyourtime. Thankyou, NicklausMiller 406Ͳ690Ͳ2896 GetOutlookforiOS Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Salinity CalculaƟons Within the Pikka Unit there are 3 wells that have wireline logs from the surface through the reservoir zone (the vintage exploraƟon wells, Colville River 1 and Till 1, and the recently-drilled disposal well, DW-02). No sands with calculated saliniƟes of less than 10,000 ppm NaCl equivalent saliniƟes were present in either of these two wells below the permafrost zone. SaliniƟes were calculated using PickeƩ Plots. PickeƩ Plots are a graphical soluƟon to the Archie equaƟon and require the presence of clean, porous, 100% water saturated sands and some knowledge of the rock properƟes in those sands: ܴ௪ ൌ כܴ௧ Rwa ResisƟvity of water necessary to make zone 100% water bearing Porosity in decimal (calculated from logs) Rt FormaƟon resisƟvity (from logs) m CementaƟon exponent (from core analysis) a Tortuosity (assumed to be 1.0 per Archie correlaƟon) There is no cementaƟon exponent (m) available for the shallow intervals in the wells included in this study. However, analogs indicaƟon that m = 1.8 is a reasonable assumpƟon. Porosity was calculated from the density log and Rt was read from the deepest-reading resisƟvity log available in each well in the shallow hole secƟon. ResisƟvity to salinity conversions were done using the Gen-6 ResisƟvity of NaCl Water SoluƟons chart (previously Gen-9) from the SLB Chartbook. Well Name StraƟgraphic Interval Approx. Depth Range Salinity (ppm NaCl equiv.) DW-02 Schrader Bluī 1550-1650’md ~21,500ppm Colville River 1 Schrader Bluī 1550-1700’md ~20,000ppm Till 1 Schrader Bluī 1400-1500’md ~16,700ppm Till 1 Schrader Bluī 1500-2000’md ~23,000ppm 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Monday, August 14, 2023 2:50 PM To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC); Thompson, Jacob (Jacob) Subject:RE: Pikka NDBi-043A (PTD 223-052; Sundry 323-411) - Additional Information Needed for Fracturing Application Review Steve, TwoofourinternalPetrophysicistsareworkingonthisrequestbutneedsomeaddiƟonalclarity.Canyouprovideusan exampleanalysisfromanotherAlaskanĮeldorotheroperatorfromtheNorthSlope? Thanks, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,August14,20232:37PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Thompson,Jacob(Jacob)<Jacob.Thompson@santos.com> Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview ThankyouNick.Per20AAC25.990DeĮniƟon27,freshwaterhasaTDSconcentraƟonoflessthan10,000mg/lsoI’m hesitanttoacceptsuchablanketstatement.Ifyouallhaveanystandardpetrophysicalanalysesfortheshallowaquifers neartheNDBDrillSite,couldyoupleaseprovidethem? ThanksagainandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Sent:Monday,August14,20231:46PM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> 2 Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Thompson,Jacob(Jacob)<Jacob.Thompson@santos.com> Subject:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Steve, Seebelowscreenshotthatdetails/documentsshallowaquiferĮndingsfromPetrophysicistWayneCampaign.I’ve requestedtheenƟrepresentaƟonandwillshareitwithyouoncereceivedonmyend. NOTE:TargetfracdatehasbeenmovedtoAugust24th. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,August14,202310:05AM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> 3 Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview Nick, I’mconƟnuingtoreviewthisapplicaƟontofractureNDBͲ043A.TwoquesƟons: 1. Inyourcommentsconcerningshallowaquifersalinity,youmenƟonthe“2018PetrophysicsCoursebyNorth SlopePetrophysicistWayneCampaign”andthatOilsearchhasstandardpetrophysicalanalysisforthese aquifers.CouldOilSearchpleaseprovidecopiesofthesedocumentssincetheyarecitedasevidenceforthe absenceoffreshwater? 2. IsAugust18thsƟllthetargetdateforbeginningfracturingoperaƟons? ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Sent:Friday,August11,202310:05AM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Steve, SeebelowanswersinRED. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,July31,20235:49PM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 4 MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview Nick, InaddiƟontothedatarequestedbelow,IhaveafewaddiƟonalitemsthatareneededorcommentsregardingthe geologyͲrelatedporƟonofAOGCC’sreview: x PleaseprovideinformaƟontosupportaĮndingthattherearenofreshwateraquifersbeneaththebaseof permafrostinthisareausingwatersampleanalysesorTDSesƟmatescalculatedfromwelllogdatarecordedin nearbywells(e.g.,DWͲ02andQugruk301).Wedonothaveanywatersampleanalysisfromthisintervalwithin thePikkaUnitbeneathbasepermafrostbutwedohavestandardpetrophysicalanalysis.Thepetrophysicaldata wehavedoesnotsuggesttherearefreshwateraquifersbelowpermafrostwithinourunit.Valuespresentedin the2018PetrophysicsCoursebyNorthSlopePetrophysicistWayneCampaignreferencesanAOGCCshallow aquiferdocumentaƟonstaƟngthatmostsaliniƟesareinexcessof12KppmNaClandaddsthatthereareno shallowfreshwateraquifersonthenorthslope. x IftheĮnal,archivalͲqualitydataforOilSearch’snearbywellDWͲ02havenotyetbeensubmiƩedtoAOGCC, pleaseprovideĮeldͲqualitycopiesofthemudlogandcementevaluaƟonlogs(electronicimagein.pdfor.pds format),LWDlogsfortheenƟrewell(in.lasorASCIItableformat),copiesofallcementreports,andpreliminary direcƟonalsurveydata(inspreadsheetorASCIItableformat).SubmiƩed8/8/23. x ForfutureapplicaƟons,itwouldgreatlyspeedAOGCC’sreviewiftheapplicaƟoncontainedasummaryof fracturegradientvalues(orrangesofvalues)fortheupperconĮning,fracturing,andlowerconĮningintervalsin unitsofpsi/ŌorppgEMW. UpperconĮning:shalegradient0.68psi/Ō Fracturing:sandgradient0.61psi/Ō LowerconĮning:shalegradient0.68psi/Ō x PleaseprovidesuĸcientcemenƟnginformaƟontodemonstratethattheiniƟalNDBͲ043wellboreisisolatedand willnotprovideaconduitforŇuidstomigrateoutofthefracturingintervalinNDBͲ043A.CBLwillberunaŌer lowercompleƟonisinstalled.EsƟmatedAugust14,2023. x ToaidAOGCC’sreviewoffutureapplicaƟons,pleasesuperimposethewellpathandtheAORoutline(asshown onAƩachmentB)onthelocalfaultmap(asshownonAƩachmentF).InfutureapplicaƟons,pleasealso describeOilSearch’sinterpretaƟonoftheorientaƟonofthecurrentregionalstressĮeldandthelikelydirecƟon ofpropagaƟonfortheinducedhydraulicfractures.Requestreceived,willmakeappropriatechangesand addiƟonsonfutureapplicaƟons. ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. 5 From:Davies,StephenF(OGC) Sent:Monday,July31,202310:30AM To:nick.miller@santos.com Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Nick, I’mSteveDavies,ageologistatAOGCC,andI’mreviewingOilSearch(Alaska),LLC’sSundryApplicaƟontofracture sƟmulatetheNDBͲ043Awell.TospeedmyporƟonofAOGCC’sreview,couldOilSearchpleaseprovideassoonasis pracƟcal: x ĮeldͲqualitycopiesofthewelllogs(mostimportantlyGR,resisƟvity,andanyavailableporositycurvesin.las, spreadsheet,orASCIItextĮleformat), x cementevaluaƟonlogs(electronicimagein.pdfor.pdsformat), x copiesofallcementreportsforthewell, x preliminarydirecƟonalsurveydata(MD,inclinaƟon,andazimuthvalues),and x geologicmarkerandformaƟontoppicks(MDandTVD). ProvidingthisinformaƟonasyoureceiveitfromthewellsitewouldbeappreciatedasIliketoconƟnuallymove applicaƟonreviewforwardasquicklyaspossible. PleasenotethatthispreliminaryinformaƟonisforapplicaƟonreviewpurposesonlyanditdoesnotmeettheĮnal reporƟngrequirementsofRegulaƟon20AAC25.071forNDBiͲ043A. ThanksandBeWell, SteveDavies SeniorPetroleumGeologist AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Monday, August 14, 2023 2:11 PM To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: Pikka NDBi-043A (PTD 223-052; Sundry 323-411) - Additional Information Needed for Fracturing Application Review Attachments:AK Salinities.pdf Steve, Aspromised,pleaseseeaƩachedWayneCampaigndocument. TargetfracdateisnowAugust24,2023. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Miller,Nicklaus(Nick) Sent:Monday,August14,20231:46PM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>; Thompson,Jacob(Jacob)<Jacob.Thompson@santos.com> Subject:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Steve, Seebelowscreenshotthatdetails/documentsshallowaquiferĮndingsfromPetrophysicistWayneCampaign.I’ve requestedtheenƟrepresentaƟonandwillshareitwithyouoncereceivedonmyend. In t e r p r e t a t i o n Pe t r o p h y s i c s C o u r s e Se p t e m b e r , 2 0 1 8 Wa y n e C a m p a i g n Lo g i n t e r p r e t a t i o n ; In t h i s s e c t i o n , w e w i l l e x p l o r e s e v e r a l p r o c e d u r e s t o f o l l o w t o b e g i n a n in t e r p r e t a t i o n . W e w i l l n o t a c t u a l l y l e a r n s o f t w a r e . T h a t i s b e y o n d t h e sc o p e o f t h i s s c h o o l . Fi r s t , o n e n e e d s t o d e f i n e t h e o b j e c t i v e . I s t h i s a n i n - d e p t h i n t e r p r e t a t i o n of a t a r g e t e d z o n e ( s ) o r a r e c o n n a i s s a n c e o f a l a r g e r i n t e r v a l ? Th e f i r s t s t e p i s t o g a t h e r a s m u c h i n f o a s y o u c a n f i n d , t o i n c l u d e m u d l o g s , lo g s a n d r e p o r t s . Bu t F i r s t … … … … Le t ’ s l o o k a t s o m e b a s i c f a c t s , i n p u t s , a n d c o n v e r s i o n s . In t e r p r e t a t i o n fa c t s , i n p u t s & c o n v e r s i o n s Pe t r o p h y s i c s C o u r s e Se p t e m b e r , 2 0 1 8 Wa y n e C a m p a i g n Sa l i n i t y : Th i s d e n o t e s s a l t c o n t e n t o f w a t e r , u s u a l l y i n p a r t - p e r - m i l l i o n , b y w e i g h t . Yo u w i l l g e n e r a l l y s e e i t l i s t e d a s “ p p m C l ” o r “ p p m N a C l ” o r s o m e d e r i v a t i o n . T h e co n v e r s i o n i s a f a c t o r o f 1 . 6 5 . S u b s u r f a c e w a t e r s u s u a l l y c o n t a i n m a n y m o r e i o n s . If y o u s e e w a t e r r e p o r t s l i s t e d a s “ p p m C l ” , be c a u t i o u s ! ! T h e s e u s u a l l y a r e s i m p l e ti t r a t i o n s a n d t h e y i g n o r e a l l t h e o t h e r c h e m i s t r y ! ! ! I f i o n s o t h e r t h a n N a a n d C l ar e i n v o l v e d , t h e y d o n o t h a v e t h e s a m e e l e c t r i c a l a c t i v i t y a s N a C l . T o c o n v e r t th e s e l a r g e r i o n s t o “ N a C l E q u i v a l e n t ” , g o t o c h a r t “ I o n E q u i v a l e n c y . p d f ” a n d f o l l o w th e i n s t r u c t i o n s . H e r e i s a l a b e x a m p l e o f a w a t e r a n a l y s i s f r o m t h e C o o k I n l e t . Rw : T h i s i s t h e r e s i s t i v i t y o f t h e n a t i v e f l u i d . A l l f l u i d r e s i s t i v i t i e s mu s t i n c l u d e a me a s u r e d t e m p e r a t u r e . T e m p e r a t u r e c o r r e c t i o n s a n d c o n v e r s i o n to /fr o m sa l i n i t y ca n b e d o n e t h r o u g h c h a r t G e n 9 . Ea r l y f l o w L a t e F l o w In t e r p r e t a t i o n fa c t s , i n p u t s & c o n v e r s i o n s Pe t r o p h y s i c s C o u r s e Se p t e m b e r , 2 0 1 8 Wa y n e C a m p a i g n Ty p i c a l A l a s k a R w ’ s N. S l o p e ; Sh a l l o w Ug n u / W . S a k s t a r t w i t h s a l i n i t i e s ~ 2 K p p m N a C l u p s h a l l o w ( 2 0 0 0 ’ ) a n d i n c r e a s e wi t h d e p t h t o 5 0 - 6 0 K p p m a t d e p t h o f 5 5 0 0 ’ a s y o u m o v e e a s t a n d d o w n d i p i n t o t h e Ni a k u k a r e a . T h e s h a l l o w s e c t i o n s d o h a v e a s i g n i f i c a n t b i c a r b o n a t e (p r o b a b l y t h e r e s u l t o f th e b i o d e g r a d a t i o n s e e n i n t h e o i l s ) co m p o n e n t t h a t d i m i n i s h e s g o i n g d e e p e r . W e s t i n t o N P R A , th e r e a r e f e w s h a l l o w s a n d s . T h e A O G C C h a s a f i l e o f s h a l l o w a q u i f e r d o c u m e n t a t i o n . Mo s t s a l i n i t i e s a r e i n e x c e s s o f 1 2 K p p m N a C l . Th e r e A r e N O S H A L L O W F R E S H W A T E R A Q U I F E R S o n t h e N o r t h S l o p e ! ! ! Na n u s h a k a n d b e l o w ex h i b i t s a l i n i t i e s o n t h e o r d e r o f 2 5 - 3 0 K p p m . T h i s i s a g o o d f i r s t ap p r o x i m a t i o n f o r m o s t a r e a s i n N . A l a s k a . Ea s t o f P B U , s a l i n i t i e s s t i l l l o o k t o b e 2 5 - 3 0 K p p m w i t h t h e e x c e p t i o n o f t h e P t . T h o m s o n re s e r v o i r . P r o d u c e d s a l i n i t i e s a r e i n t h e n e i g h b o r h o o d o f 5 7 K p p m T D S . Co o k I n l e t ; Rw v a r i e s a r o u n d t h e I n l e t f o r t h e S t e r l i n g a n d B e l u g a f o r m a t i o n s b u t a g o o d f i r s t ap p r o x i m a t i o n i s 1 0 K p p m N a C l e q . T h o u g h s o m e s h a l l o w e r s t u f f i s f r e s h e r . T y o n e k wa t e r s h a v e a s a l i n i t y i n t h e 1 5 - 2 0 K p p m r a n g e w i t h a n o t a b l e e x c e p t i o n i n t h e m i d d l e o f th e s e c t i o n . S a l i n i t y i n t h i s m i d - s e c t i o n i s l o w a n d w i l d l y v a r i a b l e . A l l s a m p l e s e x h i b i t hi g h B i c a r b o n a t e c o n t e n t , s o m e a s h i g h a s 5 5 0 0 p p m H C O 3. T h e p r e v i o u s s l i d e i s o n e ex a m p l e . T h e s e z o n e s a r e v e r y d i f f i c u l t t o p i c k a n d e v e r y o p e r a t o r h a s t e s t e d t h e m a t on e t i m e o r a n o t h e r . Be l o w T y o n e k , R w i s f a i r l y c o n s t a n t a t 2 5 K p p m N a C l . In t e r p r e t a t i o n fa c t s , i n p u t s & c o n v e r s i o n s Pe t r o p h y s i c s C o u r s e Se p t e m b e r , 2 0 1 8 Wa y n e C a m p a i g n Ty p i c a l A l a s k a T e m p e r a t u r e s N. S l o p e ; Te m p e r a t u r e g r a d i e n t s o n t h e N . S l o p e b e g i n w i t h a n e s t i m a t i o n o f d e p t h o f P e r m a f r o s t . Pe r m a f r o s t i s a T e m p e r a t u r e p i c k a n d do e s n o t ma n i f e s t i t s e l f o n a n y g e o p h y s i c a l l o g s . Sh a l e s m a y n o t f r e e z e b e l o w 0 ° C a n d h y d r a t e s ca n e x i s t s w e l l a b o v e 0 ° C . A n e x c e l l e n t re f e r e n c e a r t i c l e i s “ T e m p e r a t u r e a n d D e p t h o f P e r m a f r o s t o n t h e A r c t i c S l o p e o f A l a s k a ” by A r t h u r L a c h e n b r u c h , e t . a l . , U S G S p r o f e s s i o n a l p a p e r 1 3 9 9 . B y d e f i n i t i o n , p e r m a f r o s t is t h e s e c t i o n i n w h i c h t h e u n d i s t u r b e d f o r m a t i o n t e m p e r a t u r e i s a t o r b e l o w 0 oC, wi t h o u t r e g a r d t o w h e t h e r o r n o t i t i s f r o z e n . P o r e w a t e r s m a y n o t f r e e z e f o r a n y o f 3 pr i m a r y r e a s o n s ; di s s o l v e d s a l t c o n t e n t , co n f i n i n g p r e s s u r e , o r Ca p i l l a r y f o r c e s (w h y s h a l e s d o n ’ t f r e e z e s o l i d ) Ho w e v e r , w i t h h y d r a t e s , f r o z e n s e d i m e n t s m a y b e p r e s e n t b e l o w t h e p e r m a f r o s t . Fo l l o w i n g i s m y “ l o c a l k n o w l e d g e ” d a t a b a s e o f P e r m a f r o s t d e p t h s . Fi e l d o r a r e a B a s e P e r m a f r o s t ( T V D fr . G r o u n d l e v e l ) PB U ( E O A ) 2 2 0 0 ’ PB U ( W O A ) 2 0 0 0 ’ KR U 1 6 0 0 - 1 7 0 0 ’ Me l t w a t e r 1 3 5 0 ’ Al p i n e 1 5 0 0 ’ Ea s t e r n N P R A 1 0 0 0 ’ (S p a r k 1 a r e a ) We s t e r n N P R A 9 8 0 ’ Ch u k c h i - - - ( BH T = 3 6 . 5 + 0 . 0 1 9 5 * T V D ) In t e r p r e t a t i o n fa c t s , i n p u t s & c o n v e r s i o n s Pe t r o p h y s i c s C o u r s e Se p t e m b e r , 2 0 1 8 Wa y n e C a m p a i g n Ty p i c a l A l a s k a T e m p e r a t u r e s N. S l o p e ; Te m p e r a t u r e g r a d i e n t s o n t h e N . S l o p e a r e n o t c o n s t a n t . T h i s i s p r o b a b l y d u e t o t h e ch a n g e s i n P e r m a f r o s t d e p t h s a s a r e s u l t o f t h e c o m i n g s - a n d - g o i n g s o f t h e I c e A g e s . Be l o w a r e p l o t s o f t e m p e r a t u r e s f r o m P B U W O A a n d S p a r k 1 A i n N P R A . T o c a l c u l a t e fo r m a t i o n t e m p e r a t u r e s , p i c k d e p t h P e r m a f r o s t a n d s e t t e m p e r a t u r e t o 3 2 ° F . 0 10 0 0 20 0 0 30 0 0 40 0 0 50 0 0 60 0 0 70 0 0 80 0 0 90 0 0 10 0 0 0 0 5 0 1 0 0 1 5 0 2 0 0 25 0 Depth Te m p . d e g F In S i t u F o r m a t i o n T e m p s P B U WO A Av g F o r m a t i o n T e m p s Pe r m a f r o s t T e m p G r a d . Fo r m a t i o n T e m p G r a d . We l l 1 We l l 2 We l l 3 We l l 4 Us e a g r a d i e n t o f 0 . 0 2 1 8 ° / f t fo r t h e n e x t 4 7 0 0 ’ ( PF ’ + 4 7 0 0 ’ ). Be y o n d t h a t d e p t h , u s e a gr a d i e n t o f 0 . 0 2 8 ° / f t . Th i s w i l l g e t g o o d f o r m a t i o n te m p e r a t u r e s o n s h o r e o n th e s l o p e , b u t p r o b a b l y n o t in t h e f o o t h i l l s . Th e C h u k c h i i s a s p e c i a l c a s e gi v e n h e r e . (BH T = 3 6 . 5 + 0 . 0 1 9 5 * T V D ) 50 0 0 ’ 40 0 0 ’ 10 0 0 ’ In t e r p r e t a t i o n fa c t s , i n p u t s & c o n v e r s i o n s Pe t r o p h y s i c s C o u r s e Se p t e m b e r , 2 0 1 8 Wa y n e C a m p a i g n Ty p i c a l A l a s k a T e m p e r a t u r e s Co o k I n l e t ; De s p i t e t h e p r e s e n c e o f v o l c a n o s , t h e C o o k I n l e t i s a c o o l b a s i n . G e o l o g i s t s a s s u r e m e th i s i s b e c a u s e t h e P a c i f i c P l a t e i s d i v i n g b e l o w t h e A l a s k a P l a t e , t h u s t h e e a r t h ’ s c r u s t is n e a r l y t w i c e a s t h i c k a s n o r m a l ( ? ! ) . T h i s i s a p l o t o f M D T g a u g e t e m p e r a t u r e s i n of f s h o r e w e l l s t h a t h a v e b e e n u n d i s t u r b e d f o r 5 y e a r s . 0 10 0 0 20 0 0 30 0 0 40 0 0 50 0 0 60 0 0 70 0 0 05 0 1 0 0 15 0 SSTVD Te m p D e g F NC I U T y o n e k P l a t f o r m T e m p s . B- 0 1 B- 0 3 Gr a d i e n t Si m i l a r d a t a f r o m o n s h o r e s o u r c e s g i v e t h e sa m e g r a d i e n t ( 0. 0 1 3 6 4 ° F / f t ) w i t h a s l i g h t l y hi g h e r Mea n Ann u a l Sur f a c e Tem p e r a t u r e . Us e 4 1 ° F a t B R U . 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Thursday, August 17, 2023 1:56 PM To:Davies, Stephen F (OGC) Subject:NDBi-043 Frac Sundry Approval - Santos Dave, We'dliketopushforwardwithfracsundryapprovalonNDBiͲ043butappreciateweneedfurtherdiscussiononthe intermediatecasingbondlogresults.WithrespecttoourplannedAugust24thfracdate,I'dliketorequestaquick meetingwithyouandyourteamthisafternoontodiscussplanforward. Ideally,we'dliketospeakaboutsufficientcementisolationoftheplannedintervaltobestimulated. Pleaseletmeknowyouravailability. Thankyou, NickMiller 406Ͳ690Ͳ2896 GetOutlookforiOS Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Thursday, August 3, 2023 5:27 PM To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: Pikka NDBi-043A (PTD 223-052; Sundry 323-411) - Additional Information Needed for Fracturing Application Review Attachments:NDBi-043_Planned_Survey.xlsx; Santos-NDBI 043-9.625 GSG Liner Cement-27 July 2023.docx Steve, SeeaƩachmentsforrequesteditems.BelowchartshowsNDBiͲ043formaƟontopsandmarkers. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 FinalwelllogsandcementevaluaƟonlogwillbereadybynextweekoncethewellreachesTDandlowercompleƟonis installedonͲrig. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,July31,202310:30AM 3 To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:![EXT]:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview Nick, I’mSteveDavies,ageologistatAOGCC,andI’mreviewingOilSearch(Alaska),LLC’sSundryApplicaƟontofracture sƟmulatetheNDBͲ043Awell.TospeedmyporƟonofAOGCC’sreview,couldOilSearchpleaseprovideassoonasis pracƟcal: x ĮeldͲqualitycopiesofthewelllogs(mostimportantlyGR,resisƟvity,andanyavailableporositycurvesin.las, spreadsheet,orASCIItextĮleformat), x cementevaluaƟonlogs(electronicimagein.pdfor.pdsformat), x copiesofallcementreportsforthewell, x preliminarydirecƟonalsurveydata(MD,inclinaƟon,andazimuthvalues),and x geologicmarkerandformaƟontoppicks(MDandTVD). ProvidingthisinformaƟonasyoureceiveitfromthewellsitewouldbeappreciatedasIliketoconƟnuallymove applicaƟonreviewforwardasquicklyaspossible. PleasenotethatthispreliminaryinformaƟonisforapplicaƟonreviewpurposesonlyanditdoesnotmeettheĮnal reporƟngrequirementsofRegulaƟon20AAC25.071forNDBiͲ043A. ThanksandBeWell, SteveDavies SeniorPetroleumGeologist AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email 1 Davies, Stephen F (OGC) From:Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent:Wednesday, August 2, 2023 11:22 AM To:Davies, Stephen F (OGC) Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: Pikka NDBi-043A (PTD 223-052; Sundry 323-411) - Additional Information Needed for Fracturing Application Review Steve, Yes,IreceivedyoureͲmailsandapologizefornotrespondingbacksooner.IplantosendallcurrentlyexisƟngitemsto youbytomorrowEOB.Asnewlogsanddatacomestreamingin,I’llsendthem. EsƟmatedstartdateforfracoperaƟonsissƟllAugust18th,possiblyonedaysooner.Thisassumesourrigstayson scheduledrilling/compleƟngNDBiͲ043. Thankyou, NicklausMiller CompletionsTeamLead t:+1(907)646Ͳ7091|m:+1(406)690Ͳ2896|e:nick.miller@santos.com Santos.com|FollowusonLinkedIn,FacebookandTwitter From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Wednesday,August2,20238:49AM To:Miller,Nicklaus(Nick)<Nick.Miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:![EXT]:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturing ApplicationReview Nick, I’mfollowinguptoensurethatyoureceivedmypreviousemails.I’dliketokeepthisapplicaƟonmovingthrough AOGCC’sreviewprocess.Iwillbeoutoftheoĸcenextweek,returningtoworkonAugust14th,andtheesƟmatedstart dateforOilSearch’sfracoperaƟonsisAugust18th.IsthatstartdatesƟllaccurate? CheersandBeWell, SteveDavies AOGCC CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Davies,StephenF(OGC) Sent:Monday,July31,20235:49PM To:'nick.miller@santos.com'<nick.miller@santos.com> Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:RE:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Nick, InaddiƟontothedatarequestedbelow,IhaveafewaddiƟonalitemsthatareneededorcommentsregardingthe geologyͲrelatedporƟonofAOGCC’sreview: x PleaseprovideinformaƟontosupportaĮndingthattherearenofreshwateraquifersbeneaththebaseof permafrostinthisareausingwatersampleanalysesorTDSesƟmatescalculatedfromwelllogdatarecordedin nearbywells(e.g.,DWͲ02andQugruk301). x IftheĮnal,archivalͲqualitydataforOilSearch’snearbywellDWͲ02havenotyetbeensubmiƩedtoAOGCC, pleaseprovideĮeldͲqualitycopiesofthemudlogandcementevaluaƟonlogs(electronicimagein.pdfor.pds format),LWDlogsfortheenƟrewell(in.lasorASCIItableformat),copiesofallcementreports,andpreliminary direcƟonalsurveydata(inspreadsheetorASCIItableformat). x ForfutureapplicaƟons,itwouldgreatlyspeedAOGCC’sreviewiftheapplicaƟoncontainedasummaryof fracturegradientvalues(orrangesofvalues)fortheupperconĮning,fracturing,andlowerconĮningintervalsin unitsofpsi/ŌorppgEMW. x PleaseprovidesuĸcientcemenƟnginformaƟontodemonstratethattheiniƟalNDBͲ043wellboreisisolatedand willnotprovideaconduitforŇuidstomigrateoutofthefracturingintervalinNDBͲ043A. x ToaidAOGCC’sreviewoffutureapplicaƟons,pleasesuperimposethewellpathandtheAORoutline(asshown onAƩachmentB)onthelocalfaultmap(asshownonAƩachmentF).InfutureapplicaƟons,pleasealso describeOilSearch’sinterpretaƟonoftheorientaƟonofthecurrentregionalstressĮeldandthelikelydirecƟon ofpropagaƟonfortheinducedhydraulicfractures. ThanksandBeWell, SteveDavies AOGCC 3 CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Davies,StephenF(OGC) Sent:Monday,July31,202310:30AM To:nick.miller@santos.com Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>;Guhl, MeredithD(OGC)<meredith.guhl@alaska.gov>;Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:PikkaNDBiͲ043A(PTD223Ͳ052;Sundry323Ͳ411)ͲAdditionalInformationNeededforFracturingApplication Review Nick, I’mSteveDavies,ageologistatAOGCC,andI’mreviewingOilSearch(Alaska),LLC’sSundryApplicaƟontofracture sƟmulatetheNDBͲ043Awell.TospeedmyporƟonofAOGCC’sreview,couldOilSearchpleaseprovideassoonasis pracƟcal: x ĮeldͲqualitycopiesofthewelllogs(mostimportantlyGR,resisƟvity,andanyavailableporositycurvesin.las, spreadsheet,orASCIItextĮleformat), x cementevaluaƟonlogs(electronicimagein.pdfor.pdsformat), x copiesofallcementreportsforthewell, x preliminarydirecƟonalsurveydata(MD,inclinaƟon,andazimuthvalues),and x geologicmarkerandformaƟontoppicks(MDandTVD). ProvidingthisinformaƟonasyoureceiveitfromthewellsitewouldbeappreciatedasIliketoconƟnuallymove applicaƟonreviewforwardasquicklyaspossible. PleasenotethatthispreliminaryinformaƟonisforapplicaƟonreviewpurposesonlyanditdoesnotmeettheĮnal reporƟngrequirementsofRegulaƟon20AAC25.071forNDBiͲ043A. ThanksandBeWell, SteveDavies SeniorPetroleumGeologist AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. 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 Jacob Thompson Senior Drilling Engineer Oil Search Alaska, LLC 900 E Benson Boulevard Anchorage, AK, 99508 Re: Pikka Field, Nanushuk Oil Pool, NDBi-043A Oil Search Alaska, LLC Permit to Drill Number: 223-052 Surface Location: 2307' FSL, 1938' FWL, Sec 4, T11N, R6E, UM Bottomhole Location: 2806' FSL, 5034' FEL, Sec 32, T12N, R6E, UM Dear Mr. Thompson: Enclosed is the approved application for the permit to drill the above referenced well. All dry ditch sample sets submitted to the AOGCC must be obtained in accordance with Attachment 9. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this ___ day of July 2023. 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: 13,176'TVD:4,216' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 6678' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 70.8 15. Distance to Nearest Well Open Surface: x- 1561935 y- 5972441 Zone- 23.8 to Same Pool: 1930' 16. Deviated wells: Kickoff depth: 10,100' feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-65 Welded 80’ Surface Surface 128' 53' 16” 13-3/8” 68# L-80 BTC 2,590’ Surface Surface 2,591' 2,230' 12-1/4” 9-5/8” 47# L-80 Hydril 563 3,430’ 2,440’2,210' 6,195' 4,249' 8-1/2” 4-1/2” 12.6 P-110S Hydril 563 7,130' 6,045'4,292' 13,175' 4,145' Tubing 4-1/2” 12.6# P-110 Hydril 563 6,065' Surface Surface 6,065' 4,225' 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: Jake Thompson Jake Thompson Contact Email:jacob.thompson@santos.com Senior Drilling Engineer Contact Phone:1-907-854-4377 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Conductor/Structural LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Please see Attachment 6 for details Production Liner is uncemented. N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): Grouted to surface 640, 640, 640 = 1920 acres total 18. Casing Program: Top - Setting Depth - BottomSpecifications 1976 GL / BF Elevation above MSL (ft): Total Depth MD (ft): Total Depth TVD (ft): IS000361277U STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Please see Attachment 6 for details 1545 2521' FSL, 1739' FEL, Sec 4, T11N, R6E, UM 2806' FSL, 5034' FEL, Sec 12, T32N, R6E, UM LONS 19-003 900 E Benson Boulevard, Anchorage, AK 99508 Oil Search Alaska, LLC 2307' FSL, 1938' FEL, Sec 4, T11N, R6E, UM ADL 392984, ADL 391445, ADL 393020 NDBi-043 Pikka / Nanushuk Oil Pool 07/10/23 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s Nooo s N ooooo D s s s D t o : well is s G S S 20 S S S s No oo s No S s G y E S s No ooo 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 API N b 06/13/2023 By Grace Christianson at 3:15 pm, Jun 13, 2023 4 SFD Sec 32, T12N, SFD 7/4/2023 FWL SFD DSR-6/28/23 An approved injection order is required prior to commencement of injection into this well. 50-103-20859-01-00 NAD 27) BJM 6/27/23 A 223-052 This scope includes everything after the OH sidetrack at 10100' MD. BOP test to 3000 psi Waiver to 20 AAC 25.412(c) to test 13-3/8" casing to 80% of burst is approved. Provide 24 hrs notice to AOGCC for witness of MITIA to 4000 psi. 5972694421903 Page 1 of 1 07 June 2023 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDBi-043 Dear Sir/Madam Oil Search (Alaska), LLC hereby applies for a Permit to Drill an onshore development well from the NDB drilling pad on the North Slope of Alaska. NDBi-043 is planned to be a horizontal Injector targeting the Nanushuk 3. The approximate spud date is anticipated to be July 10th, 2023. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~46 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand. A plug back wellbore will be steered upward reaching total depth when the top of the Nanushuk 3 Maximum flood surface is logged with the LWD suite. The objective is to ascertain the reservoir quality in the upper portion of the Nanushuk 3, as well as obtain a structural top for the Nanushuk 3 to optimally place the rest of the lateral. An open hole sidetrack will be performed at ~10,100 MD and the NDBi-043 production 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) 854-4377 or Jacob.Thompson@santos.com. Respectfully, Jacob Thompson Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, Jacob Thompson 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. completed as a stimulated 4-1/2” liner with frac sleeves and isolation packers. ” production hole will be geo-steered in the Nanushuk 3 s July 10th, 2023. NDBi-043 PTD AOGCC 6-7-23 - 1 - 06-Jun-23 Application for Permit to Drill NDBi-043 Well NDBi-043 PTD AOGCC 6-7-23 - 2 - 06-Jun-23 Table of Contents 1. Well Name.................................................................................................................................3 2. Location Summary.....................................................................................................................3 3. Blowout Prevention Equipment Information..............................................................................4 4. Drilling Hazards Information......................................................................................................5 5. Procedure for Conducting Formation Integrity Tests ..................................................................6 6. Casing and Cementing Program.................................................................................................6 7. Diverter System Information......................................................................................................7 8. Drilling Fluid Program................................................................................................................7 9. Abnormally Pressured Formation Information...........................................................................7 10. Seismic Analysis.......................................................................................................................7 11. Seabed Condition Analysis.......................................................................................................8 12. Evidence of Bonding................................................................................................................8 13. Proposed Drilling Program.......................................................................................................8 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ..............................................10 15. Proposed Variance Request...................................................................................................10 Attachments............................................................................................................................................11 Attachment 1: Location Map.......................................................................................................12 Attachment 2: Directional Plan....................................................................................................14 Attachment 3: BOPE Equipment..................................................................................................2 2 Attachment 4: Drilling Hazards....................................................................................................27 Attachment 5: Leak Off Test Procedure .......................................................................................29 Attachment 6: Cement Summary.................................................................................................30 Attachment 7: Prognosed Formation Tops...................................................................................31 Attachment 8: Well Schematic.....................................................................................................32 Attachment 9: Formation Evaluation Program.............................................................................33 Attachment 10: Wellhead & Tree Diagram ..................................................................................34 Attachment 11: Area of Review...................................................................................................35 NDBi-043 PTD AOGCC 6-7-23 - 3 - 06-Jun-23 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDBi-043. 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 2,307’ FSL, 1,938’ FWL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,694.41 E 421,902.72 Rig KB Elevation 47.0’ above conductor level Conductor Level 23.8’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 2,521’ FSL, 1739’ FEL Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,956 E 418,227 Measured Depth, Rig KB (MD)6,705’ Total Vertical Depth, Rig KB (TVD)4,355’ Total vertical Depth, Subsea (TVDSS)4,285’ Location at Bottom of Productive Interval Reference to Government Section Lines 2,806’ FSL, 5,034’ FEL, Sec 12, T32N, R6E, UM NAD 27 Coordinate System N 5,978,548 E 414,975 Measured Depth, Rig KB (MD)13,176’ Total Vertical Depth, Rig KB (TVD)4,215’ Total vertical Depth, Subsea (TVDSS)4,145’ Sec 32, T12N, service injection well NDBi-043 PTD AOGCC 6-7-23 - 4 - 06-Jun-23 Location at Bottom Hole NDBi-043 PB1 Reference to Government Section Lines 700 FSL, 3,785’ FEL, Sec 12, T32N, R6E, UM NAD 27 Coordinate System N 5,976,428 E 416,208 Measured Depth, Rig KB (MD)11,744’ Total Vertical Depth, Rig KB (TVD)4,132’ Total vertical Depth, Subsea (TVDSS)4,062’ (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-043 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 NDBi-043 PTD AOGCC 6-7-23 - 5 - 06-Jun-23 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 1,976 psi in the TN4 at 4,315’ TVD (8.8ppg EMW top Nanushuk 4 to TD of the section) Maximum surface pressure 1,545 psi from TN4 at 4,315’ TVD (0.10 psi/ft gas gradient to surface, 4,315’ TVD) Planned BOP test pressure Rams test to 3,000 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by frac back pressure requirement] Integrity Test – 12-1/4” hole LOT after drilling 20’-50’ of new hole. 12.9 ppg LOT required for Kick Tolerance, 17 ppg maximum EMW LOT. 13-3/8” Casing Test 3,000 psi surface pressure [Test pressure driven by Maximum Surface Pressure] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,970 psi in the Nanushuk 3 at 4,355’ TVD (8.7ppg EMW top NT3) Maximum surface pressure 1,535 psi in the Nanushuk 3 at 4,355’ TVD (0.10 psi/ft gas gradient to surface, 4,355’ TVD) Planned BOP test pressure Rams test to 3,000 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by frac back pressure requirement] Integrity Test – 8-1/2” hole LOT after drilling 20’-50’ of new hole. 10.0 ppg for minimum kick tolerance. 9-5/8” Liner Test 3,000 psi surface pressure [Test pressure driven by Maximum Surface Pressure] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas based on offset Exploration and Appraisal well data. The Tuluvak is expected to be overpressured at 10.0ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. e Tuluvak formation is expected in this area and has a high potential for gas based o NDBi-043 PTD AOGCC 6-7-23 - 6 - 06-Jun-23 (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; Nearby offset Exploration and Appraisal wells in the area suggest that no significant hole problems are to be expected. Please refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure. 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVDss 42”20” x 34”215# X-65 Welded 80’Surface 128’ / 53’ 16”13-3/8”68# L-80 BTC 2,590’Surface 2,591’/2,230’ 12-1/4”9-5/8”47# L-80 Hydril 563 3,430’ 2,440’6,195’ / 4,249’ 8-1/2” PB1 --- --- --- --- 961’10,100’11,061’ / 3,927’ 8-1/2”4-1/2”12.6 P-110S Hydril 563 7,130’6,045’13,175’ / 4,145’ Tubing 4-1/2”12.6# P-110S Hydril 563 6,065’Surface 6,065’ / 4,225’ Please refer to Attachment 6: Cement Summary for further details. NDBi-043 PTD AOGCC 6-7-23 - 7 - 06-Jun-23 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, model GK, 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 10.5ppg 85-275 seconds 30-50 30-80 < 14 ml/30min n/a 9.5-10 <35 10.7-11.2ppg 50-100 seconds 20-40 15-30 n/a < 10 ml/30min n/a n/a 9.0-9.8ppg 50-80 seconds 15-20 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. 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. NDBi-043 PTD AOGCC 6-7-23 - 8 - 06-Jun-23 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-043 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-043 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program 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 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” assembly with motor, MWD, and LWD tools. 6. Spud well and drill surface hole section to TD. CBU and clean well prior to trip. 7. POOH and lay down drilling assembly. 8. Run 13-3/8” 68# BTC surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 9. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 10. ND diverter and NU casing head and spacer spool. NU BOPE (Configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 4-1/2” x 7” VBR). Test rams to 3000 psi high, and annular to 3000 psi. Give the AOGCC 24 hrs notice prior to testing. 11. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, pressure test casing to 3000 psi for 30 min, clean out to top of float equipment and displace well to 11.0 ppg MOBM. NDBi-043 PTD AOGCC 6-7-23 - 9 - 06-Jun-23 12. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test and submit results to AOGCC. 13. Directionally drill 12-1/4” intermediate hole section to TD ~15’ TVD above the NT3 MFS. Perform wiper trips as required. Circulate and condition hole to run casing. POOH. 14. Change out upper BOP rams from 4-1/2” x 7” VBR to 9-5/8” solid body and test to 3,000 psi. 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. Cement 9-5/8” Liner with single stage cement job as per cement program. Monitor returns during displacement. Bump plug pressure up to set liner hanger, release the running tool , and set liner top packer. 17. Un-sting from the liner hanger and circulate cement returns from the top of the liner. 18. POOH and lay down liner running tools. 19. RU wireline and run ultrasonic cement evaluation log. Submit results to AOGCC. 20. Pressure test 9-5/8” production liner to 3,000 psi for 30 mins. 21. Change out upper BOP rams from 9-5/8” solid body to 4-1/2” x 7” VBR and test to 3,000 psi. 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 9.2 ppg MOBM. 23. Drill out shoe track and 20 - 50’ of new formation. Perform LOT and submit results to AOGCC. 24. Directionally drill 8-1/2” hole section as per well plan to TD of NDBi-043 PB1 wellbore. Perform wiper trips as required. 25. POOH to the kick-off point of ~10,100’ and open hole sidetrack. 26. Directionally drill 8-1/2” hole section as per well plan to TD of NDBi-043. Perform wiper trips as required. 27. POOH and lay down 8-1/2” Drilling BHA. 28. RU and run 4-1/2” production liner with frac sleeves and mechanical packers. 29. Run 4-1/2” liner to TD. Set liner hanger and Liner top packer and release the running tool. 30. Pressure test 9-5/8” x 4-1/2” production liner to 3,000 psi for 30 mins. 31. POOH and lay down the running tool. 32. RU and run the 4-1/2” completion w/tech wire. 33. Run 4-1/2” upper completion. Space out and stab seals inside the polish bore below the 9- 5/8” x 4-1/2” Production liner top packer. 34. Pressure test tubing to 4,000 psi for 30 mins, pressure up on annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 35. Circulate diesel to freeze protect annulus. The activity covered in this permit to drill begins with step 26. Everything prior is part of the NDBi-043 PB1 (PTD 223-051) -bjm MITIA will test 13-3/8" 68# L-80 casing to 80% of yield. See waiver request. NDBi-043 PTD AOGCC 6-7-23 - 10 - 06-Jun-23 36. Install TWC pressure test to 3,000 psi for 5 mins, ND, BOP, NU dry hole tree. Pressure test to 3,000 psi for 5 mins. 37. 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 25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage. (c) Before injection begins, a well must be pressure-tested to demonstrate the mechanical integrity of the tubing and packer and of the casing immediately surrounding the injection tubing string. The casing must be tested at a surface pressure of 1,500 psig or at a surface pressure of 0.25 psi/ft multiplied by the true vertical depth of the casing shoe, whichever is greater, but the casing may not be subjected to a hoop stress that will exceed 70 percent of the minimum yield strength of the casing. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. A variance is requested to the above underlined regulation 20 AAC 25.412 (c) allowing the 13-3/8” 68# L-80 casing to be pressure tested to an internal yield pressure greater than 70% of its internal hoop stress. The pressure test is to be conducted after the upper completion has been run and the well has been displaced to completion brine. The pressure test will allow the inner annulus (A annulus) to maintain backpressure during the hydraulic fracturing operations to optimally fracture the productive interval. All operational and test pressure will be below the internal yield pressure of the tubulars, and within industry standard design specifications. Variance approved to 20 AAC 25.412(b). Production Packer may be located more than 200 feet measured depth above the top of the injection zone; however, packer must not be located above the confining zone. In cases where the distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300 feet measured depth above the planned packer depth. -bjm Oilsearch is planning to test to 4000 psi with 9.4 ppg brine in the well, which is 79% of internal yield of the 13-3/8" casing per Jacob Thompson email attached. - bjm NDBi-043 PTD AOGCC 6-7-23 - 11 - 06-Jun-23 Attachments NDBi-043 PTD AOGCC 6-7-23 - 12 - 06-Jun-23 Attachment 1: Location Map OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELLS RIG OUTLINES DIVERTER (50-ft) DATE: 5/1/2023. By: JB 0204010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi43_well GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDBi43 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.33520 -150.637 70° 20' 06.7188" N 150° 38' 12.2558" W 5,972,442.40 1,561,935.53 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.33552 -150.634 70° 20' 07.8701" N 150° 38' 00.9791" W 5,972,694.41 421,902.72 State Plane NAD83 Zone 4 StatePlane NAD27 Zone 4 NDBi-043 PTD AOGCC 6-7-23 - 14 - 06-Jun-23 Attachment 2: Directional Plan NDBi-043 Heel v.0 NDBi-043 TD v.0 Tie On 3.00°/100ftEnd of Tangent End of Build 3.00°/100ft End of 3D Arc 13.375in Casing Surface End of Tangent 3.00°/100ft End of 3D Arc 9.625in Casing Intermediate End of TangentTrue Vertical Depth (ft) Vertical Section (ft) Azimuth 309.60° with reference 0.00 N, 0.00 E 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 -1000 0 1000 2000 3000 4000 5000 Scale 1 inch = 2000Scale 1 inch = 2000 Offset wellpath MDs are referenced to each path's default MD datum Mean Sea Level to Ground level (At Slot: B-43): 0 feet RigonB-43(RT)toMeanSeaLevel:70.8feet Reference wellpath measured depths are referenced to Rig on B-43 (RT) True vertical depths are referenced to Rig on B-43 (RT) Plot reference wellpath is NDBi-043 Rev C.1 Created by: meyedavr on 2023-04-21; Database: WellArchitectDB Depths are in feet Coordinates are in feet referenced to Slot Scale: True distance North Reference: True north Grid System: NAD83 / TM Alaska SP, Zone 4 (5004), US feet Location: Facility: Field: Pikka Pikka Alaska Santos Wellbore: Well: Slot: NDBi-043 NDBi-043 B-43 NDBi-043 TD v.0 NDBi-043 Heel v.0 B-43 9.625in Casing Intermediate 13.375in Casing Surface Northing (ft) Easting (ft) -7500 -6250 -5000 -3750 -2500 -1250 0 1250 -1250 0 1250 2500 3750 5000 6250 Scale 1 inch = 2500 End of Tangent End of 3D Arc End of Tangent End of 3D Arc End of Build End of Tangent Tie On Design Comment 13175.91 6704.94 3862.45 2232.94 91.240 91.240 46.535 46.535 700.00 6.000 500.00 0.000 47.00 0.000 MD (ft) Inc (°) 329.220 329.220 246.924 246.924 165.000 165.000 165.000 Az (°) 4215.80 4355.80 3184.14 2063.18 699.63 500.00 47.00 TVD (ft) Well Profile Data 5782.33 224.14 -786.05 -322.49 -10.11 0.00 0.00 Local N (ft) -6989.08 -3678.43 -1604.57 -516.52 2.71 0.00 0.00 Local E (ft) DLS (°/100ft) 0.00 3.00 0.00 3.00 3.00 0.00 0.00 9070.98 2977.07 735.23 192.40 -8.53 0.00 0.00 VS (ft) RigonB-43(RT)toMeanSeaLevel Mean Sea Level to Ground level (At Slot: B-43) RigonB-43(RT)toGroundlevel(AtSlot:B-43) B-43 Slot -230.73 Local N (ft) Pikka Facility Name -1478.65 Local E (ft) 1561935.530 Grid East (US ft) 1563416.330 Grid East (US ft) Location Information 5972442.400 Grid North (US ft) 5972657.910 Grid North (US ft) 70.8ft 0ft 70.8ft 70°20'6.7188"N 70°20'8.9895"N Latitude Latitude 150°38'12.2560"W Longitude 150°37'29.0730"W Longitude REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDBi-043 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDBi-043 NAD27 Slot B-43 NAD 27 REPORT SETUP INFORMATION Projection System NAD27 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitect® 6.0 North Reference True User Meyedavr Scale 0.999907 Report Generated 5/1/2023 at 8:48:19 AM Convergence at slot 0.60° West Database WellArchitectDB WELLPATH LOCATION Local coordinates Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US ft] Northing[US ft] Latitude Longitude Slot Location -230.42 -1478.70 421902.72 5972694.41 70°20'7.8702"N 150°38'0.9792"W Facility Reference Pt 423383.56 5972909.70 70°20'10.1378"N 150°37'17.7961"W Field Reference Pt 423383.56 5972909.70 70°20'10.1378"N 150°37'17.7961"W WELLPATH DATUM Calculation method Minimum curvature Rig on B-43 (RT) to Facility Vertical Datum 70.80ft Horizontal Reference Pt Slot RigonB-43(RT)toMeanSeaLevel 70.80ft Vertical Reference Pt Rig on B-43 (RT) Rig on B-43 (RT) to Ground Level at Slot (B-43 NAD 27) 70.80ft MD Reference Pt Rig on B-43 (RT)Section Origin N 0.00, E 0.00 ft Field Vertical Reference Mean Sea Level Section Azimuth 309.60° Actual Wellpath Report NDBi-43 Rev C.1 NAD27 Page 1 of 6 Page 1 of 6Wellpath Report 5/1/2023file:///C:/WellArchitect/NDBi-43_Rev_C.1_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDBi-043 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDBi-043 NAD27 Slot B-43 NAD 27 Actual Wellpath Report NDBi-43 Rev C.1 NAD27 Page 2 of 6 WELLPATH DATA (139 stations)† = interpolated, ‡ = extrapolated station MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 0.00† 0.000 165.000 0.00 -70.80 0.00 0.00 0.00 421902.72 5972694.41 0.00 47.00 0.000 165.000 47.00 -23.80 0.00 0.00 0.00 421902.72 5972694.41 0.00 147.00 0.000 165.000 147.00 76.20 0.00 0.00 0.00 421902.72 5972694.41 0.00 247.00 0.000 165.000 247.00 176.20 0.00 0.00 0.00 421902.72 5972694.41 0.00 347.00 0.000 165.000 347.00 276.20 0.00 0.00 0.00 421902.72 5972694.41 0.00 447.00 0.000 165.000 447.00 376.20 0.00 0.00 0.00 421902.72 5972694.41 0.00 500.00 0.000 165.000 500.00 429.20 0.00 0.00 0.00 421902.72 5972694.41 0.00 547.00 1.410 165.000 547.00 476.20 -0.47 -0.56 0.15 421902.86 5972693.85 3.00 647.00 4.410 165.000 646.85 576.05 -4.61 -5.46 1.46 421904.13 5972688.93 3.00 700.00 6.000 165.000 699.63 628.83 -8.53 -10.11 2.71 421905.32 5972684.28 3.00 747.00 6.219 178.118 746.37 675.57 -12.22 -15.02 3.43 421905.99 5972679.35 3.00 847.00 7.586 200.589 845.66 774.86 -17.96 -26.62 1.28 421903.73 5972667.78 3.00 947.00 9.714 214.794 944.53 873.73 -20.82 -39.73 -5.85 421896.45 5972654.75 3.00 1047.00 12.210 223.605 1042.70 971.90 -20.78 -54.32 -17.96 421884.19 5972640.29 3.00 1147.00 14.892 229.376 1139.92 1069.12 -17.86 -70.34 -35.01 421866.98 5972624.44 3.00 1247.00 17.674 233.394 1235.90 1165.10 -12.06 -87.77 -56.96 421844.86 5972607.25 3.00 1347.00 20.516 236.338 1330.39 1259.59 -3.39 -106.54 -83.73 421817.89 5972588.76 3.00 1447.00 23.396 238.589 1423.13 1352.33 8.11 -126.60 -115.27 421786.15 5972569.03 3.00 1547.00 26.302 240.369 1513.86 1443.06 22.43 -147.91 -151.48 421749.72 5972548.10 3.00 1647.00 29.225 241.817 1602.34 1531.54 39.52 -170.40 -192.27 421708.71 5972526.04 3.00 1747.00 32.162 243.022 1688.32 1617.52 59.33 -194.01 -237.52 421663.22 5972502.91 3.00 1847.00 35.108 244.045 1771.57 1700.77 81.82 -218.67 -287.10 421613.38 5972478.76 3.00 1947.00 38.061 244.929 1851.86 1781.06 106.91 -244.32 -340.89 421559.34 5972453.67 3.00 2047.00 41.021 245.703 1928.97 1858.17 134.54 -270.90 -398.73 421501.22 5972427.71 3.00 2147.00 43.984 246.390 2002.69 1931.89 164.63 -298.31 -460.47 421439.21 5972400.94 3.00 2232.94 46.535 246.924 2063.18 1992.38 192.40 -322.49 -516.52 421382.92 5972377.35 3.00 2247.00 46.535 246.924 2072.85 2002.05 197.09 -326.49 -525.91 421373.49 5972373.44 0.00 2347.00 46.535 246.924 2141.64 2070.84 230.40 -354.94 -592.68 421306.43 5972345.70 0.00 2447.00 46.535 246.924 2210.43 2139.63 263.71 -383.39 -659.45 421239.38 5972317.95 0.00 2547.00 46.535 246.924 2279.22 2208.42 297.03 -411.83 -726.22 421172.32 5972290.20 0.00 Page 2 of 6Wellpath Report 5/1/2023file:///C:/WellArchitect/NDBi-43_Rev_C.1_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDBi-043 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDBi-043 NAD27 Slot B-43 NAD 27 Actual Wellpath Report NDBi-43 Rev C.1 NAD27 Page 3 of 6 WELLPATH DATA (139 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 2647.00 46.535 246.924 2348.01 2277.21 330.34 -440.28 -793.00 421105.26 5972262.45 0.00 2747.00 46.535 246.924 2416.80 2346.00 363.65 -468.73 -859.77 421038.20 5972234.70 0.00 2847.00 46.535 246.924 2485.59 2414.79 396.97 -497.18 -926.54 420971.14 5972206.96 0.00 2947.00 46.535 246.924 2554.39 2483.59 430.28 -525.62 -993.31 420904.08 5972179.21 0.00 3047.00 46.535 246.924 2623.18 2552.38 463.59 -554.07 -1060.08 420837.03 5972151.46 0.00 3147.00 46.535 246.924 2691.97 2621.17 496.91 -582.52 -1126.86 420769.97 5972123.71 0.00 3247.00 46.535 246.924 2760.76 2689.96 530.22 -610.97 -1193.63 420702.91 5972095.96 0.00 3347.00 46.535 246.924 2829.55 2758.75 563.53 -639.41 -1260.40 420635.85 5972068.21 0.00 3447.00 46.535 246.924 2898.34 2827.54 596.85 -667.86 -1327.17 420568.79 5972040.47 0.00 3547.00 46.535 246.924 2967.13 2896.33 630.16 -696.31 -1393.94 420501.73 5972012.72 0.00 3647.00 46.535 246.924 3035.92 2965.12 663.47 -724.76 -1460.72 420434.68 5971984.97 0.00 3747.00 46.535 246.924 3104.71 3033.91 696.79 -753.21 -1527.49 420367.62 5971957.22 0.00 3847.00 46.535 246.924 3173.51 3102.71 730.10 -781.65 -1594.26 420300.56 5971929.47 0.00 3862.45 46.535 246.924 3184.13 3113.33 735.25 -786.05 -1604.58 420290.20 5971925.19 0.00 3947.00 46.861 250.380 3242.13 3171.33 765.12 -808.44 -1661.87 420232.68 5971903.40 3.00 4047.00 47.380 254.413 3310.19 3239.39 804.80 -830.58 -1731.69 420162.64 5971881.99 3.00 4147.00 48.038 258.370 3377.50 3306.70 849.10 -847.96 -1803.57 420090.59 5971865.35 3.00 4247.00 48.829 262.238 3443.86 3373.06 897.88 -860.54 -1877.29 420016.75 5971853.54 3.00 4347.00 49.746 266.007 3509.10 3438.30 951.03 -868.29 -1952.67 419941.30 5971846.58 3.00 4447.00 50.782 269.669 3573.03 3502.23 1008.38 -871.17 -2029.49 419864.46 5971844.50 3.00 4547.00 51.929 273.218 3635.49 3564.69 1069.79 -869.18 -2107.54 419786.44 5971847.30 3.00 4647.00 53.180 276.653 3696.31 3625.51 1135.08 -862.33 -2186.62 419707.45 5971854.97 3.00 4747.00 54.525 279.974 3755.30 3684.50 1204.08 -850.64 -2266.50 419627.70 5971867.50 3.00 4847.00 55.959 283.182 3812.32 3741.52 1276.59 -834.14 -2346.96 419547.43 5971884.84 3.00 4947.00 57.474 286.280 3867.21 3796.41 1352.43 -812.87 -2427.78 419466.84 5971906.94 3.00 5047.00 59.061 289.273 3919.81 3849.01 1431.37 -786.89 -2508.75 419386.15 5971933.76 3.00 5147.00 60.716 292.167 3969.98 3899.18 1513.21 -756.27 -2589.64 419305.59 5971965.22 3.00 5247.00 62.430 294.966 4017.59 3946.79 1597.72 -721.10 -2670.23 419225.39 5972001.22 3.00 5347.00 64.199 297.678 4062.51 3991.71 1684.67 -681.47 -2750.29 419145.75 5972041.68 3.00 5447.00 66.017 300.309 4104.60 4033.80 1773.82 -637.50 -2829.61 419066.89 5972086.47 3.00 Page 3 of 6Wellpath Report 5/1/2023file:///C:/WellArchitect/NDBi-43_Rev_C.1_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDBi-043 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDBi-043 NAD27 Slot B-43 NAD 27 Actual Wellpath Report NDBi-43 Rev C.1 NAD27 Page 4 of 6 WELLPATH DATA (139 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 5547.00 67.879 302.866 4143.76 4072.96 1864.92 -589.30 -2907.97 418989.04 5972135.48 3.00 5647.00 69.779 305.356 4179.88 4109.08 1957.73 -537.00 -2985.16 418912.41 5972188.57 3.00 5747.00 71.713 307.785 4212.86 4142.06 2052.00 -480.75 -3060.96 418837.21 5972245.61 3.00 5847.00 73.678 310.160 4242.61 4171.81 2147.45 -420.70 -3135.17 418763.63 5972306.42 3.00 5947.00 75.668 312.488 4269.04 4198.24 2243.84 -357.02 -3207.59 418691.90 5972370.84 3.00 6047.00 77.681 314.774 4292.09 4221.29 2340.89 -289.88 -3278.00 418622.19 5972438.71 3.00 6147.00 79.712 317.025 4311.69 4240.89 2438.35 -219.46 -3346.23 418554.70 5972509.82 3.00 6247.00 81.759 319.248 4327.79 4256.99 2535.94 -145.96 -3412.09 418489.62 5972583.99 3.00 6347.00 83.818 321.447 4340.35 4269.55 2633.40 -69.59 -3475.38 418427.13 5972661.02 3.00 6447.00 85.886 323.630 4349.32 4278.52 2730.45 9.46 -3535.95 418367.40 5972740.69 3.00 6547.00 87.960 325.801 4354.69 4283.89 2826.84 90.96 -3593.62 418310.58 5972822.78 3.00 6647.00 90.036 327.966 4356.44 4285.64 2922.30 174.70 -3648.24 418256.84 5972907.07 3.00 6704.94 91.240 329.220 4355.79 4284.99 2977.08 224.15 -3678.43 418227.17 5972956.82 3.00 6747.00 91.240 329.220 4354.88 4284.08 3016.69 260.27 -3699.95 418206.03 5972993.17 0.00 6847.00 91.240 329.220 4352.72 4281.92 3110.87 346.17 -3751.11 418155.77 5973079.58 0.00 6947.00 91.240 329.220 4350.56 4279.76 3205.04 432.06 -3802.28 418105.51 5973166.00 0.00 7047.00 91.240 329.220 4348.39 4277.59 3299.21 517.95 -3853.44 418055.25 5973252.41 0.00 7147.00 91.240 329.220 4346.23 4275.43 3393.39 603.85 -3904.60 418004.99 5973338.82 0.00 7247.00 91.240 329.220 4344.06 4273.26 3487.56 689.74 -3955.76 417954.73 5973425.24 0.00 7347.00 91.240 329.220 4341.90 4271.10 3581.73 775.63 -4006.93 417904.47 5973511.65 0.00 7447.00 91.240 329.220 4339.74 4268.94 3675.90 861.53 -4058.09 417854.21 5973598.06 0.00 7547.00 91.240 329.220 4337.57 4266.77 3770.08 947.42 -4109.25 417803.95 5973684.48 0.00 7647.00 91.240 329.220 4335.41 4264.61 3864.25 1033.32 -4160.41 417753.69 5973770.89 0.00 7747.00 91.240 329.220 4333.24 4262.44 3958.42 1119.21 -4211.57 417703.43 5973857.30 0.00 7847.00 91.240 329.220 4331.08 4260.28 4052.60 1205.10 -4262.74 417653.17 5973943.72 0.00 7947.00 91.240 329.220 4328.92 4258.12 4146.77 1291.00 -4313.90 417602.91 5974030.13 0.00 8047.00 91.240 329.220 4326.75 4255.95 4240.94 1376.89 -4365.06 417552.65 5974116.55 0.00 8147.00 91.240 329.220 4324.59 4253.79 4335.12 1462.78 -4416.22 417502.39 5974202.96 0.00 8247.00 91.240 329.220 4322.42 4251.62 4429.29 1548.68 -4467.39 417452.13 5974289.37 0.00 8347.00 91.240 329.220 4320.26 4249.46 4523.46 1634.57 -4518.55 417401.87 5974375.79 0.00 Page 4 of 6Wellpath Report 5/1/2023file:///C:/WellArchitect/NDBi-43_Rev_C.1_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDBi-043 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDBi-043 NAD27 Slot B-43 NAD 27 Actual Wellpath Report NDBi-43 Rev C.1 NAD27 Page 5 of 6 WELLPATH DATA (139 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 8447.00 91.240 329.220 4318.10 4247.30 4617.64 1720.47 -4569.71 417351.61 5974462.20 0.00 8547.00 91.240 329.220 4315.93 4245.13 4711.81 1806.36 -4620.87 417301.35 5974548.61 0.00 8647.00 91.240 329.220 4313.77 4242.97 4805.98 1892.25 -4672.04 417251.09 5974635.03 0.00 8747.00 91.240 329.220 4311.60 4240.80 4900.16 1978.15 -4723.20 417200.82 5974721.44 0.00 8847.00 91.240 329.220 4309.44 4238.64 4994.33 2064.04 -4774.36 417150.56 5974807.86 0.00 8947.00 91.240 329.220 4307.28 4236.48 5088.50 2149.93 -4825.52 417100.30 5974894.27 0.00 9047.00 91.240 329.220 4305.11 4234.31 5182.67 2235.83 -4876.68 417050.04 5974980.68 0.00 9147.00 91.240 329.220 4302.95 4232.15 5276.85 2321.72 -4927.85 416999.78 5975067.10 0.00 9247.00 91.240 329.220 4300.78 4229.98 5371.02 2407.62 -4979.01 416949.52 5975153.51 0.00 9347.00 91.240 329.220 4298.62 4227.82 5465.19 2493.51 -5030.17 416899.26 5975239.92 0.00 9447.00 91.240 329.220 4296.45 4225.65 5559.37 2579.40 -5081.33 416849.00 5975326.34 0.00 9547.00 91.240 329.220 4294.29 4223.49 5653.54 2665.30 -5132.50 416798.74 5975412.75 0.00 9647.00 91.240 329.220 4292.13 4221.33 5747.71 2751.19 -5183.66 416748.48 5975499.16 0.00 9747.00 91.240 329.220 4289.96 4219.16 5841.89 2837.08 -5234.82 416698.22 5975585.58 0.00 9847.00 91.240 329.220 4287.80 4217.00 5936.06 2922.98 -5285.98 416647.96 5975671.99 0.00 9947.00 91.240 329.220 4285.63 4214.83 6030.23 3008.87 -5337.15 416597.70 5975758.41 0.00 10047.00 91.240 329.220 4283.47 4212.67 6124.41 3094.77 -5388.31 416547.44 5975844.82 0.00 10147.00 91.240 329.220 4281.31 4210.51 6218.58 3180.66 -5439.47 416497.18 5975931.23 0.00 10247.00 91.240 329.220 4279.14 4208.34 6312.75 3266.55 -5490.63 416446.92 5976017.65 0.00 10347.00 91.240 329.220 4276.98 4206.18 6406.92 3352.45 -5541.79 416396.66 5976104.06 0.00 10447.00 91.240 329.220 4274.81 4204.01 6501.10 3438.34 -5592.96 416346.40 5976190.47 0.00 10547.00 91.240 329.220 4272.65 4201.85 6595.27 3524.23 -5644.12 416296.14 5976276.89 0.00 10647.00 91.240 329.220 4270.49 4199.69 6689.44 3610.13 -5695.28 416245.88 5976363.30 0.00 10747.00 91.240 329.220 4268.32 4197.52 6783.62 3696.02 -5746.44 416195.62 5976449.71 0.00 10847.00 91.240 329.220 4266.16 4195.36 6877.79 3781.92 -5797.61 416145.36 5976536.13 0.00 10947.00 91.240 329.220 4263.99 4193.19 6971.96 3867.81 -5848.77 416095.10 5976622.54 0.00 11047.00 91.240 329.220 4261.83 4191.03 7066.14 3953.70 -5899.93 416044.84 5976708.96 0.00 11147.00 91.240 329.220 4259.67 4188.87 7160.31 4039.60 -5951.09 415994.58 5976795.37 0.00 11247.00 91.240 329.220 4257.50 4186.70 7254.48 4125.49 -6002.26 415944.32 5976881.78 0.00 11347.00 91.240 329.220 4255.34 4184.54 7348.66 4211.38 -6053.42 415894.06 5976968.20 0.00 Page 5 of 6Wellpath Report 5/1/2023file:///C:/WellArchitect/NDBi-43_Rev_C.1_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDBi-043 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDBi-043 NAD27 Slot B-43 NAD 27 Actual Wellpath Report NDBi-43 Rev C.1 NAD27 Page 6 of 6 WELLPATH DATA (139 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 11447.00 91.240 329.220 4253.17 4182.37 7442.83 4297.28 -6104.58 415843.80 5977054.61 0.00 11547.00 91.240 329.220 4251.01 4180.21 7537.00 4383.17 -6155.74 415793.54 5977141.02 0.00 11647.00 91.240 329.220 4248.85 4178.05 7631.17 4469.07 -6206.90 415743.28 5977227.44 0.00 11747.00 91.240 329.220 4246.68 4175.88 7725.35 4554.96 -6258.07 415693.02 5977313.85 0.00 11847.00 91.240 329.220 4244.52 4173.72 7819.52 4640.85 -6309.23 415642.76 5977400.26 0.00 11947.00 91.240 329.220 4242.35 4171.55 7913.69 4726.75 -6360.39 415592.49 5977486.68 0.00 12047.00 91.240 329.220 4240.19 4169.39 8007.87 4812.64 -6411.55 415542.23 5977573.09 0.00 12147.00 91.240 329.220 4238.03 4167.23 8102.04 4898.53 -6462.72 415491.97 5977659.51 0.00 12247.00 91.240 329.220 4235.86 4165.06 8196.21 4984.43 -6513.88 415441.71 5977745.92 0.00 12347.00 91.240 329.220 4233.70 4162.90 8290.39 5070.32 -6565.04 415391.45 5977832.33 0.00 12447.00 91.240 329.220 4231.53 4160.73 8384.56 5156.22 -6616.20 415341.19 5977918.75 0.00 12547.00 91.240 329.220 4229.37 4158.57 8478.73 5242.11 -6667.37 415290.93 5978005.16 0.00 12647.00 91.240 329.220 4227.21 4156.41 8572.91 5328.00 -6718.53 415240.67 5978091.57 0.00 12747.00 91.240 329.220 4225.04 4154.24 8667.08 5413.90 -6769.69 415190.41 5978177.99 0.00 12847.00 91.240 329.220 4222.88 4152.08 8761.25 5499.79 -6820.85 415140.15 5978264.40 0.00 12947.00 91.240 329.220 4220.71 4149.91 8855.42 5585.68 -6872.01 415089.89 5978350.81 0.00 13047.00 91.240 329.220 4218.55 4147.75 8949.60 5671.58 -6923.18 415039.63 5978437.23 0.00 13147.00 91.240 329.220 4216.39 4145.59 9043.77 5757.47 -6974.34 414989.37 5978523.64 0.00 13175.91 91.240 329.220 4215.76 4144.96 9071.00 5782.30 -6989.13 414974.84 5978548.62 0.00 WELLPATH COMPOSITION - Ref Wellbore: NDBi-043 NAD27 Ref Wellpath: NDBi-43 Rev C.1 NAD27 Start MD [ft] End MD [ft] Positional Uncertainty Model Log Name/Comment Wellbore Survey Date 47.00 13175.91 BH No Uncertainty Plan NDBi-043 NAD27 4/30/2023 Page 6 of 6Wellpath Report 5/1/2023file:///C:/WellArchitect/NDBi-43_Rev_C.1_NAD27.xml NDBi-043 PTD AOGCC 6-7-23 - 22 - 06-Jun-23 Attachment 3: BOPE Equipment 21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# FORWARD 13-5/8" X 5,000# 13-5/8" X 5,000# 30" 13-5/8" X 5,000# 186" 13-5/8" X 5,000# DUTCH LOCK DOWN ChokeLine fromBOP PressureGauge 1502PressureSensorPressureTransducer Bill ofMaterial Item Description To PanicLine Item Description A3Ͳ1/8”– 5,000psi W.P. RemoteHydraulic OperatedChoke B3Ͳ1/8”–5,000psiW.P. AdjustableManual Choke 1–14 3Ͳ1/8”– 5,000psi W.P. ManualGateValve 15 2 1/16”5 000 i WP152Ͳ1/16”–5,000psiW.P. ManualGateValve To MudGas Legend BlindSpare To TigerTankSeparatorValveNormally Open Valve Normally Closed NDBi-043 PTD AOGCC 6-7-23 - 27 - 06-Jun-23 Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (mud loggers, trained drilling personnel). Shallow Fault Fault crossing in shallow hole section. Well trajectory is parallel to the fault, but the fault appears to be very small but could potentially present a lost circulation or WBS risk 12-1/4” 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. Washouts/Hole Enlargement Drill with oil based mud, maintain mud in specifications, use sufficient mud weight to hold back formations. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. 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. NDBi-043 PTD AOGCC 6-7-23 - 28 - 06-Jun-23 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. 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 signsof washout. Limit time out of TN3 in PB1 wellbore. Unable To Sidetrack Drill PB1 wellbore first with hard turn up. Follow proper open hole sidetrack procedure and plan to Kick off low side where PB1 plan deviates from original wellbore. Have bent motor assembly on location if sidetrack cannot be achieved with RSS. *Note that no H2S has been encountered on nearby offset well, and H2S is not anticipated in this well. NDBi-043 PTD AOGCC 6-7-23 - 29 - 06-Jun-23 Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. NDBi-043 PTD AOGCC 6-7-23 - 30 - 06-Jun-23 Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 BTC Surface Casing Basis Lead Open hole volume + 250% excess in permafrost / 40% excess below permafrost Lead TOC Surface Tail Open hole volume + 40% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~60 bbls of 10.7 ppg Clean Spacer Lead 10.7ppg Lead: 380.7bbls, 2138cuft, 747.6sks, ArcticCemYield: 2.86 cuft/sk Tail 15.3ppg Tail: 65.2bbls, 366cuft, 292.8sks HalCem Type I/II– 1.25 cuft/sk Temp BHST 53° F Verification Method Cement returns to surface Notes Job will be mixed on the fly Swap to tail cement when lead cement is seen at surface Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess Lead TOC Top of the 9-5/8” Liner. Tail Open hole volume + 30% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 11.8 ppg Clean Spacer Lead 12.0ppg Lead: 244.9bbls, 1375.3cuft, 577.8sks ExtendaCem, Yield: 2.38 cuft/sk Tail 15.3ppg Tail: 42.5bbls, 238.5cuft, 194sks VersaCem Type I/II– 1.23 cuft/sk Temp BHST 99° F Verification Method Cement returns off of top of liner, Ultra Sonic Wireline log, and Monopole Sonic Notes Job will be mixed on the fly NDBi-043 PTD AOGCC 6-7-23 - 31 - 06-Jun-23 Attachment 7: Prognosed Formation Tops NDBi-043 Prognosed Tops Formation MD (ft) TVD KB (ft) TVD Path (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1047 901 972 100 7.3 Permafrost Base 1138 990 1061 100 7.6 Middle Schrader Bluff 1798 1590 1661 100 7.8 MCU (Lwr. Sch. Bluff)2371 2017 2088 100 7.9 Tuluvak Shale 2861 2354 2425 100 7.9 Tuluvak Sand 2941 2409 2480 100 10 Seabee 3924 3085 3156 100 9.1 Nanushuk 4964 3735 3806 100 8.9 NT6 MFS 5130 3820 3891 100 8.8 NT5 MFS 5313 3906 3977 100 8.8 NT4 MFS 5454 3966 4037 100 8.8 NT3 MFS 6299 4193 4264 100 8.7 NT 3.2 Top Reservoir (NT3)6585 4214 4285 100 8.7 NDBi-043 PTD AOGCC 6-7-23 - 32 - 06-Jun-23 Attachment 8: Well Schematic NDBi-043 PTD AOGCC 6-7-23 - 33 - 06-Jun-23 Attachment 9: Formation Evaluation Program Hole Section Logging Tool Requirements Surface LWD GR/RES Intermediate I LWD GR/RES/Neu-Den/ Multipole Sonic Intermediate Liner Wireline Ultra Sonic Production Hole LWD GR / RES / Neu-Den / Monopole Sonic (Cement Evaluation 9-5/8” liner)/ Ultradeep Res PB1 LWD GR / RES / Neu-Den / Monopole Sonic / Ultradeep Res Mud Logging Sample Collection Program Depth Interval (ft)*Sampling type Frequency Comments Conductor- TD Samplex Sample Trays Samples available for Wellsite Geologist for every cuttings sample collected Conductor - TD Mud At the beginning, middle and the end of each section and any significant change of mud properties Conductor –6,150’Washed & Dried 2 sets (Santos, AOGCC)30’ –50’ MD Additional spot samples if shows or if requested by WSG. Sampling rate is dependent on ROP 4900’ MD -6150’ MD (Upper Nanushuk) Washed & Dried 2 sets (Santos, AOGCC)30’ –50’ MD Be prepared to catch additional samples by request w/in Upper Nanushuk Sampling rate is dependent on ROP 6,150’ MD –6700’ MD (NT3 MFS to landing) Washed & Dried 2 sets (Santos, AOGCC)10’ MD Increased density through zone-of- interest: NT3 MFS to landing *Request to Slow ROP 6,700-13,173 (TD) (Lateral) Washed & Dried 2 sets (Santos, AOGCC)30’ MD Target 30’ samples but 50’ acceptable as needed based on ROP PB1 Washed & Dried 2 sets (Santos, AOGCC)30’ MD 30’ samples for depofacies evaluation and identifying top reservoir *All Depth intervals are approximate and depend on as drilled formation markers. NDBi-043 PTD AOGCC 6-7-23 - 34 - 06-Jun-23 Attachment 10: Wellhead & Tree Diagram NDBi-043 PTD AOGCC 6-7-23 - 35 - 06-Jun-23 Attachment 11: Area of Review There will be no existing wells that are within ¼ mile of the planned trajectory in the injection zone Nanushuk 3 reservoir. From: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Sent: Wednesday, July 5, 2023 9:19 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: NDB-043 (PTD 223-052) - Questions Steve, I hope you had a good 4th of July. Right now the current plan is to flow the wells back for frac clean up only. We do not expect continued production for greater than 30 days, and will inform the AOGCC if plans change. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, July 4, 2023 6:45 AM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: NDB-043 (PTD 223-052) - Questions Hi Jacob, Will the planned NDB-043 injection well be pre-produced for 30 days or longer, or will it be simply flowed back briefly for clean up? Thanks and stay safe, Steve Davies AOGCC 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. 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:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:RE: NDBi-043 Anti-collision scan Date:Friday, June 23, 2023 10:56:16 AM Attachments:image003.png image004.png image005.png B-43_Rev_C.0_CR.pdf Brian, There are no existing wells in the clearance scan area. Just planned well to be drilled later in the development. The attached clearance scan is in NAD83, but that does not change the scan results. The clearance scan indicates a failed result against NDBi-030 however, this is because it has crossed a clearance factor threshold requiring us to perform a risk assessment and secure the well while drilling by. As I mentioned above this well does not exist, but we will have a close approach when we drill the NDBi-030 well. Probably more than you wanted to know but just giving you a heads up. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 3:55 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: NDBi-043 Anti-collision scan Jake, Can you send me the anti-collision scan for the directional plan on this well? I am assuming there are no wellbores nearby, but just checking. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email REFERENCE WELLPATH IDENTIFICATION Operator Santos Well B-43 Field Pikka API/Legal Facility Pikka Wellbore B-43 Slot B-43 REPORT SETUP INFORMATION Projection System NAD83 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitect® 6.0 North Reference True User Meyedavr Scale 0.999907 Report Generated 4/19/2023 at 3:37:47 PM Convergence at slot 0.60° West Database WellArchitectDB WELLPATH LOCATION Local coordinates Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US ft] Northing[US ft] Latitude Longitude Slot Location -230.73 -1478.65 1561935.53 5972442.40 70°20'6.7188"N 150°38'12.2560"W Facility Reference Pt 1563416.33 5972657.91 70°20'8.9895"N 150°37'29.0730"W Field Reference Pt 1563416.33 5972657.91 70°20'8.9895"N 150°37'29.0730"W WELLPATH DATUM Calculation method Minimum Curvature Rig on B-43 (RT) to Facility Vertical Datum 70.80ft Horizontal Reference Pt Slot RigonB-43(RT)toMeanSeaLevel 70.80ft Vertical Reference Pt Rig on B-43 (RT) RigonB-43(RT)toGroundLevelat Slot (B-43) 70.80ft MD Reference Pt Rig on B-43 (RT) Field Vertical Reference Mean Sea Level Closest Approach Clearance Summary Report B-43 Rev C.0 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 1 of 3 POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 2.79 Std Dev Ellipse Start MD 47.00ft Surface Position Uncertainty included Declination 14.80° East of TN Dip Angle 80.59°Mag Field Strength 57197 nT Slot Surface Uncertainty @1SD Horizontal 0.500ft Vertical 0.500ft Facility Surface Uncertainty @1SD Horizontal 20.000ft Vertical 3.000ft Positional Uncertainty values in the WELLPATH DATA table are the projection of the ellipsoid of uncertainty onto the vertical and horizontal planes Page 1 of 3Clearance Summary Report 4/19/2023file:///C:/WellArchitect/B-43_Rev_C.0_CR.xml.html REFERENCE WELLPATH IDENTIFICATION Operator Santos Well B-43 Field Pikka API/Legal Facility Pikka Wellbore B-43 Slot B-43 Closest Approach Clearance Summary Report B-43 Rev C.0 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 2 of 3 PROXIMITY-SCAN RULE Rule Name Santos - Stop Drilling HSE Risk (SF <1.25)Rule Based On Ratio Plane of Rule Closest Approach Threshold Value 1.25 IncludeCasing&HoleSize yes Apply Cone of Safety no SURVEY PROGRAM - Ref Wellbore: B-43 Ref Wellpath: B-43 Rev C.0 Start MD [ft] End MD [ft] Positional Uncertainty Model Log Name/Comment Wellbore 47.00 2591.10 OWSG MWD rev2 (MS+IFR2, SAG) B-43 2591.10 6125.00 OWSG MWD rev2 (MS+IFR2, SAG) B-43 6125.00 13438.44 OWSG MWD rev2 (MS+IFR2, SAG) B-43 Page 2 of 3Clearance Summary Report 4/19/2023file:///C:/WellArchitect/B-43_Rev_C.0_CR.xml.html REFERENCE WELLPATH IDENTIFICATION Operator Santos Well B-43 Field Pikka API/Legal Facility Pikka Wellbore B-43 Slot B-43 CALCULATION RANGE & CUTOFF From:47.00ft MD To:13175.91ft MD C-C Cutoff:(none) Closest Approach Clearance Summary Report B-43 Rev C.0 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 3 of 3 OFFSET WELL CLEARANCE SUMMARY (17 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane Offset Facility Offset Slot Offset Well Offset Wellbore Offset Wellpath Wellbore Status C-C Clearance Distance Rule Separation Ratio Ref MD [ft] Min C-C Clear Dist [ft] Diverging from MD [ft] Ref MD of Min Ratio [ft] Min Ratio Min Ratio Dvrg from [ft] Rule Status Pikka B-30 B-30 B-30 B-30 Rev B.0 Planned 13175.91 87.87 13175.91 13175.91 1.13 13175.91 FAIL Pikka B-44 B-44 B-44 B-44 Rev A.0 Planned 443.97 21.20 13175.91 501.54 2.17 13175.91 PASS Pikka B-40 B-40 B-40 B-40 Rev A.0 Planned 1163.12 37.67 1163.12 1268.07 2.57 6247.00 PASS Pikka B-37 B-37 B-37 B-37 Rev A.0 Planned 47.00 118.98 13175.91 13175.91 3.60 13175.91 PASS Pikka B-34 B-34 B-34 B-34 Rev A.0 Planned 47.00 179.11 11247.00 13175.91 3.61 13175.91 PASS Pikka B-41 B-41 B-41 B-41 Rev A.0 Planned 47.00 38.93 7747.00 521.58 4.40 10247.00 PASS Pikka B-38 B-38 B-38 B-38 Rev A.0 Planned 1233.84 73.00 1233.84 1506.87 4.56 5947.00 PASS Pikka B-45 B-45 B-45 B-45 Rev A.0 Planned 47.00 41.24 347.00 610.75 4.60 6547.00 PASS Pikka B-36 B-36 B-36 B-36 Rev A.0 Planned 47.00 139.02 500.00 2647.13 5.70 2647.13 PASS Pikka B-39 B-39 B-39 B-39 Rev A.0 Planned 47.00 78.99 8847.00 11373.44 6.24 11373.44 PASS Pikka B-33 B-33 B-33 B-33 Rev A.0 Planned 1388.00 162.00 1388.00 2149.11 6.87 2247.00 PASS Pikka B-46 B-46 B-46 B-46 Rev A.0 Planned 484.99 61.19 6347.00 602.91 6.99 8347.00 PASS Pikka B-31 B-31 B-31 B-31 Rev A.0 Planned 1365.16 228.35 1365.16 2647.00 7.34 2647.00 PASS Pikka B-51 B-51 B-51 B-51 Rev A.0 Planned 47.00 161.38 13175.91 12885.06 8.70 13175.91 PASS Pikka B-50 B-50 B-50 B-50 Rev A.0 Planned 457.60 141.35 457.60 2720.90 9.71 7247.00 PASS Pikka B-48 B-48 B-48 B-48 Rev A.0 Planned 519.58 101.27 519.58 667.38 11.61 8147.00 PASS Pikka B-49 B-49 B-49 B-49 Rev A.0 Planned 47.00 121.32 13175.91 2304.35 12.22 13175.91 PASS Page 3 of 3Clearance Summary Report 4/19/2023file:///C:/WellArchitect/B-43_Rev_C.0_CR.xml.html 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:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:RE: NDBi-043 permit to drill question Date:Friday, June 23, 2023 10:46:19 AM Attachments:image003.png image004.png image005.png Bryan, We plan to test the inner annulus after the 4-1/2” 12.6# P-110S completion is stung into the tie back receptical of the 4-1/2” Liner top packer. The test will be to 4,000 psi surface pressure with a 9.4 ppg completion brine. This will bring the casing to a 1.21 design factor for burst or ~79% of its internal Yield pressure. We are pressure testing the IA to allow maximum back pressure to be held during the frac, which will be ~3,500 -3,600 psi. We have to pressure test to 4,000 psi to allow room to set pop offs, and mechanical trips safely above the back pressure required for the frac. Thanks, Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 2:36 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: NDBi-043 permit to drill question Jake, Looking over your PTD and have a question. In part 15, proposed variance request, can you spell out what the percent of yield you plan to test to, with assumptions such as fluid density and any other relevant info at the time of applying test pressure? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email From:Thompson, Jacob (Jacob) To:McLellan, Bryan J (OGC) Subject:RE: NDBi-043 permit to drill question Date:Wednesday, June 28, 2023 3:13:24 PM Attachments:image004.png image005.png image006.png image008.png Bryan, NT 3.2 Top Reservoir (NT3) represents the top of or productive interval. Our confining layer extends above this depth all the way to the top of the pool which is the top of the Nanushuk. The planned 9-5/8” liner shoe is expected to be at 6,195’ MD and be fully cemented. This will put our 9-5/8” production liner shoe and our 4-1/2” x 9-5/8” liner top packer (Production packer) well within our confining layer with a long section of cement separating it any other zones. With this I believe we meet the requirements outlined in the excerpt from the proposed pool rules below. Let me know if you have any question or comments. Thanks, NDBi-043 Prognosed Tops Formation MD (ft) TVD KB (ft) TVD Path (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1047 901 972 100 7.3 Permafrost Base 1138 990 1061 100 7.6 Middle Schrader Bluff 1798 1590 1661 100 7.8 MCU (Lwr. Sch. Bluff) 2371 2017 2088 100 7.9 Tuluvak Shale 2861 2354 2425 100 7.9 Tuluvak Sand 2941 2409 2480 100 10 Seabee 3924 3085 3156 100 9.1 Nanushuk (Top Pool) 4964 3735 3806 100 8.9 NT6 MFS 5130 3820 3891 100 8.8 NT5 MFS 5313 3906 3977 100 8.8 NT4 MFS 5454 3966 4037 100 8.8 NT3 MFS 6299 4193 4264 100 8.7 NT 3.2 Top Reservoir (NT3) 6585 4214 4285 100 8.7 Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, June 27, 2023 4:06 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: RE: NDBi-043 permit to drill question Jake, The proposed pool rules, which are not yet approved, have the following language. I think I will just copy variance section for this well. a. Packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300 feet measured depth above the planned packer depth. 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: Monday, June 26, 2023 8:13 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Re: NDBi-043 permit to drill question Bryan, Would it be better to request the possibility of needing the variance by amending the permit to drill, or just asking for it if it comes to fruition during operations? It is expected to be just within the 500', but with the uncertainty outlined in my last email it could easily be required if tops come in differently. Glad to amend the PTD if you feel that is the easiest way forward. Thanks, Jacob Sent via the Samsung Galaxy S22 Ultra 5G, an AT&T 5G smartphone Get Outlook for Android From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, June 26, 2023 5:43:12 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: RE: NDBi-043 permit to drill question Jake, Need to request a variance if packer is more than 500’ MD from top injection zone. Bryan McLellan 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. 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: Friday, June 23, 2023 12:09 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDBi-043 permit to drill question Bryan, The MD of the first open hole packer is not yet know. It will likely be ~500’ from the shoe or ~6,695’ MD. We are drilling into the shelf edge of the reservoir and since this will be the first well to do so there is a bit of uncertainty as to where the edge of the target sand will be. Below is a cartoon depicting what our approach to our bench one wells will be. Well be putting our intermediate casing ~15’ TVD above the top of the Nanushuk 3 maximum flood surface MFS, and entering the Nan3 clean sand as the sand thickens. Sorry for not having a more concise answer, but it’s a bit complicated. Jacob Thompson – Senior Drilling Engineer Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7079| m: +1 (907) 854-4377 Jacob.Thompson@santos.com https://www.santos.com/ From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 3:35 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: ![EXT]: RE: NDBi-043 permit to drill question One more question in addition to the one below… What is the MD of the uppermost OH packer? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Thursday, June 22, 2023 2:36 PM To: Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com> Subject: NDBi-043 permit to drill question Jake, Looking over your PTD and have a question. In part 15, proposed variance request, can you spell out what the percent of yield you plan to test to, with assumptions such as fluid density and any other relevant info at the time of applying test pressure? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PIKKA PIKKA, NANUSHUK OIL 223-052 NDB-043 obtained in accordance with Attachment 9. SFD WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-043AInitial Class/TypeSER / WAGINGeoArea890Unit11580On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230520PIKKA, NANUSHUK OIL - 600100NA1Permit fee attachedYesSurface Location lies within ADL0392984; Top Productive Interval lies in ADL0391445; TD lies in ADL0393020.2Lease number appropriateYes3Unique well name and numberYesPIKKA, NANUSHUK OIL - 600100, Pool Rules CO currently in progress.4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryYes6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYesNone currently.15All wells within 1/4 mile area of review identified (For service well only)No16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NAThis PTD is only for an in-zone open-hole sidetrack and completion.18Conductor string providedNA19Surface casing protects all known USDWsNA20CMT vol adequate to circulate on conductor & surf csgNA21CMT vol adequate to tie-in long string to surf csgNoLiner will be uncemented with multiple Open Hole isolation packers and frac sleeves.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesFirst well to be drilled in this development26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP = 1545 psi, BOP rated to 5k psi (Test to 3000 psi)30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableYesThis is the first well to be drilled in this area.34Mechanical condition of wells within AOR verified (For service well only)YesNone expected based on nearby wells.35Permit can be issued w/o hydrogen sulfide measuresYesExpected Pressure Range is 0.379 to 0.519 psi/ft (7.3 to 10 ppg EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability.37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/6/2023ApprVTLDate7/7/2023ApprSFDDate7/4/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate
