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224-013
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 . 5 0 - 1 0 3 - 2 0 8 8 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 5 1 Co m p l e t i o n S t a t u s 1- O I L Co m p l e t i o n D a t e 6/ 1 1 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 1 3 0 Op e r a t o r O i l S e a r c h ( A l a s k a ) , L L C MD 17 4 7 8 TV D 41 3 7 Cu r r e n t S t a t u s 1- O I L 1/ 2 1 / 2 0 2 6 UI C No 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 c No No 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 7/ 1 / 2 0 2 4 20 0 1 7 4 7 8 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 - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t . l as 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ A P _ R 0 1 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ A P _ R 0 2 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ A P _ R 0 3 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ A P _ R 0 4 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ D M T _ R 0 1 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ D M T _ R 0 2 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ D M T _ R 0 3 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 ### # # # # #### # # # # # 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 - 05 1 _ D M T _ R 0 4 _ R M . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 79 0 0 1 1 6 0 7 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 - 05 1 _ S D T K _ C B L _ 7 9 2 5 _ 1 1 6 0 0 . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 79 0 0 1 1 6 0 7 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 - 05 1 _ S D T K _ T O C _ 7 9 2 5 _ 1 1 6 0 0 . l a s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 D e f i n i t i v e C o m p a s s Su r v e y R e p o r t - N A D 2 7 . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 D e f i n i t i v e C o m p a s s Su r v e y R e p o r t - N A D 8 3 . p d f 39 0 9 6 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 2 1 , 2 0 2 6 AO G C C Pa g e 1 o f 4 ND B - , 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t . 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 . 5 0 - 1 0 3 - 2 0 8 8 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 5 1 Co m p l e t i o n S t a t u s 1- O I L Co m p l e t i o n D a t e 6/ 1 1 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 1 3 0 Op e r a t o r O i l S e a r c h ( A l a s k a ) , L L C MD 17 4 7 8 TV D 41 3 7 Cu r r e n t S t a t u s 1- O I L 1/ 2 1 / 2 0 2 6 UI C No DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 D e f i n i t i v e S u r v e y Re p o r t . x l s x 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s L e t t e r P l a n V i e w . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s L e t t e r V e r t i c a l S e c t i o n . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ S D T K _ C B L _ 7 9 2 5 _ 1 1 6 0 0 . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ S D T K _ C B L _ 7 9 2 5 _ 1 1 6 0 0 . d l i s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ S D T K _ C B L _ 7 9 2 5 _ 1 1 6 0 0 . P D F 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ S D T K _ T O C _ 7 9 2 5 _ 1 1 6 0 0 . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ S D T K _ T O C _ 7 9 2 5 _ 1 1 6 0 0 . d l i s 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ S D T K _ T O C _ 7 9 2 5 _ 1 1 6 0 0 . P D F 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _2 M D . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _2 T V D . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _5 M D . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _5 T V D . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 _ A P _ R M . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 _ D M D _ R M _ 1 7 4 7 8 f t . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 _ D M T _ R M . c g m 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _2 M D . p d f 39 0 9 6 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 2 1 , 2 0 2 6 AO G C C Pa 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 . 5 0 - 1 0 3 - 2 0 8 8 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 5 1 Co m p l e t i o n S t a t u s 1- O I L Co m p l e t i o n D a t e 6/ 1 1 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 1 3 0 Op e r a t o r O i l S e a r c h ( A l a s k a ) , L L C MD 17 4 7 8 TV D 41 3 7 Cu r r e n t S t a t u s 1- O I L 1/ 2 1 / 2 0 2 6 UI C No 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 DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _2 T V D . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _5 M D . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 05 1 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 4 7 8 f t _5 T V D . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 _ A P _ R M . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 _ D M D _ R M _ 1 7 4 7 8 f t . p d f 39 0 9 6 ED Di g i t a l D a t a DF 7/ 1 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 0 5 1 _ D M T _ R M . p d f 39 0 9 6 ED Di g i t a l D a t a DF 12 / 6 / 2 0 2 4 E l e c t r o n i c F i l e : W T - X A K - 0 1 2 7 . 4 _ N D B - 0 5 1 _ R e v A_ S i g n e d . p d f 39 8 3 0 ED Di g i t a l D a t a DF 11 / 2 1 / 2 0 2 5 E l e c t r o n i c F i l e : S a n t o s _ P i k k a _ N D B - 0 5 1 _ E n d o f We l l C l e a n - u p D a t a R e p o r t _ 1 m i n _ F i n a l D a t a . x l s x 39 8 3 0 ED Di g i t a l D a t a DF 11 / 2 1 / 2 0 2 5 E l e c t r o n i c F i l e : S a n t o s _ P i k k a _ N D B - 0 5 1 _ E n d o f We l l C l e a n - u p D a t a R e p o r t _ 3 0 m i n _ F i n a l Da t a . x l s x 39 8 3 0 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 32 0 0 1 1 5 0 3 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 : S A N T O S _ N D B - 05 1 _ B H P _ 1 2 _ 2 5 _ 3 2 5 8 _ 1 1 5 0 2 _ R U N 2 . l a s 41 1 1 7 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 11 5 6 6 1 7 4 8 7 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 : S A N T O S _ N D B - 05 1 _ B H P _ 8 _ 5 _ 1 1 5 6 5 _ 1 7 4 2 9 . l a s 41 1 1 7 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 E l e c t r o n i c F i l e : S A N T O S _ N D B - 05 1 _ B H P _ 1 2 _ 2 5 _ 3 2 5 8 _ 1 1 5 0 2 _ R U N 2 . d l i s 41 1 1 7 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 E l e c t r o n i c F i l e : S A N T O S _ N D B - 05 1 _ B H P _ 8 _ 5 _ 1 1 5 6 5 _ 1 7 4 2 9 . d l i s 41 1 1 7 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 2 1 , 2 0 2 6 AO G C C Pa 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 . 5 0 - 1 0 3 - 2 0 8 8 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 5 1 Co m p l e t i o n S t a t u s 1- O I L Co m p l e t i o n D a t e 6/ 1 1 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 1 3 0 Op e r a t o r O i l S e a r c h ( A l a s k a ) , L L C MD 17 4 7 8 TV D 41 3 7 Cu r r e n t S t a t u s 1- O I L 1/ 2 1 / 2 0 2 6 UI C No 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 : 6 / 1 1 / 2 0 2 4 Re l e a s e D a t e : 3/ 1 8 / 2 0 2 4 We d n e s d a y , J a n u a r y 2 1 , 2 0 2 6 AO G C C Pa g e 4 o f 4 1/ 2 1 / 2 0 2 6 M. G u h l LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Well clean up data for 19 wells Details are provided on following pages with well name and API table as reference. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/20/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.21 09:00:44 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043A 50103208590100 NDBi-044 50103208650000 NDBi-046L1 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 جؐؐؐNDB-010 ؒ Santos_Pikka_NDB-010_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-010_End of Well Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-010_Rev A (1).pdf ؒ جؐؐؐNDB-011 ؒ Santos_Pikka_NDB-011_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-011_End of Well Data Report_30 Min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-011_Rev A (1).pdf ؒ جؐؐؐNDB-014 ؒ Santos_Pikka_NDBi-014_End of Well Clean-up Data Report_30 Minute_Final Data.xlsx ؒ Santos_Pikka_NDBi-014__End of Well Clean-up Data Report_1 Minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-014_Rev A_Signed.pdf ؒ جؐؐؐNDB-024 ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_ 30-min_Final (2).xlsx ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_1-min_Final (2).xlsx ؒ WT-XAK-0127.2_End of Well Clean-Up Data Report_NDB-024_Rev A_Signed.pdf 225-061 T41152 225-048 T41153 223-076 T39828 223-105 T39831 NDB-051 50103208800000 LETTER OF TRANSMITTAL ؒ جؐؐؐNDB-025 ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf ؒ جؐؐؐNDB-031 ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf ؒ جؐؐؐNDB-032 ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-037 ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-048 ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-051 ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf ؒ جؐؐؐNDBi-016 ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf ؒ جؐؐؐNDBi-018 ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf ؒ جؐؐؐNDBi-030 224-006 T41154 225-028 T41155 224-124 T41156 224-143 T41157 224-105 T41158 224-085 T41159 224-013 T39830 223-006 T39829 223-120 T39832 NDB-051 ؐ LETTER OF TRANSMITTAL ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf ؒ جؐؐؐNDBi-036 ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf ؒ جؐؐؐNDBi-043A ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf ؒ جؐؐؐNDBi-044 ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf ؒ جؐؐؐNDBi-046L1 ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf ؒ جؐؐؐNDBi-049 ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf ؒ ؤؐؐؐNDBi-050 Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf 225-012 T41160 224-119 T41161 224-154 T41162 223-052 T39834 223-087 T39835 224-029 T39837 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Baker Hughes has provided us with LithTrak Azimuthal Caliper data for all 22 previous wells. Details are provided on following pages with well name and API table as reference. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/18/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.19 08:30:05 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDB-027 50103209220000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043 50103208590000 NDBi-044 50103208650000 NDBi-046 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 DW-02 50103208550000 PWD-02 50103208790000 جؐؐؐDW-02 Lithotrak Caliper data ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.dlis ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.las ؒ جؐؐؐNDB-010 Lithotrak Caliper data ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.dlis ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.las ؒ جؐؐؐNDB-011 Lithotrak Caliper data ؒ جؐؐؐ12.25 in ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.dlis ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.las ؒ ؒ ؒ ؤؐؐؐ8.5 in ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.dlis 223-039 T41107 225-061 T41108 225-048 T41109 NDB-051 50103208800000 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.las ؒ جؐؐؐNDB-024 Lithotrak Caliper data ؒ جؐؐؐRun 6 ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.dlis ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.las ؒ ؒ ؒ ؤؐؐؐRun 7 ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.dlis ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.las ؒ جؐؐؐNDB-025 Lithotrak Caliper data ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.dlis ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.las ؒ جؐؐؐNDB-027 Lithotrak Caliper data ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.dlis ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.las ؒ جؐؐؐNDB-031 Lithotrak Caliper data ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.dlis ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.las ؒ جؐؐؐNDB-032 Lithotrak Caliper data ؒ جؐؐؐRun 3 ؒ ؒ SANTOS_NDB-032_BHP_12_25_2598_6224ft_Run3.las ؒ ؒ SANTOS_NDB_032_BHP_12_25_2598_6224ft_Run3.dlis ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.dlis ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.las ؒ جؐؐؐNDB-037 Lithotrak Caliper data ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.dlis ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.las ؒ جؐؐؐNDB-048 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.dlis ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 223-076 T41110 224-006 T41111 225-066 T41112 225-028 T41113 223-060 T41114 224-124 T41115 224-143 T41116 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.dlis ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.las ؒ جؐؐؐNDB-051 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.dlis ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.dlis ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.las ؒ جؐؐؐNDBi-014 Lithotrak Caliper data ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.dlis ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.las ؒ جؐؐؐNDBi-016 Lithotrak Caliper data ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4.las ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4_1.dlis ؒ جؐؐؐNDBi-018 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.dlis ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.dlis ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.las ؒ جؐؐؐNDBi-030 Lithotrak Caliper data ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.dlis ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.las ؒ جؐؐؐNDBi-036 Lithotrak Caliper data ؒ جؐؐؐRun 4 ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.dlis ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.las ؒ ؒ ؒ ؤؐؐؐRun 6 ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.dlis ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.las ؒ 224-013 T41117 223-105 T41118 224-105 T41119 224-085 T41120 223-120 T41121 225-012 T41122 ؐNDB-051 Lithotrak Caliper data LETTER OF TRANSMITTAL جؐؐؐNDBi-043 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.dlis ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.dlis ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.las ؒ جؐؐؐNDBi-044 Lithotrak Caliper data ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.dlis ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.las ؒ جؐؐؐNDBi-046 Lithotrak Caliper data ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.dlis ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.las ؒ جؐؐؐNDBi-049 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.dlis ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.dlis ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.las ؒ جؐؐؐNDBi-050 Lithotrak Caliper data ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.dlis ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.las ؒ ؤؐؐؐPWD-02 Lithotrak Caliper data SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.dlis SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.las 223-051 T41123 223-087 T41124 224-028 T41125 224-119 T41126 224-154 T41127 224-009 T41128 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Well Cleanup Oil Search Alaska, LLC Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,478 feet N/A feet true vertical 4,137 feet N/A feet Effective Depth measured 17,472 feet See rpt feet true vertical 4,137 feet See rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6 ppf P-110S 11,434' 4,099' Packers and SSSV (type, measured and true vertical depth) See attached 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Scott Leahy Contact Email:scott.leahy@santos.com Authorized Title: Completions Specialist Contact Phone: 907-330-4595 324-441 Sr Pet Eng: 9,210 Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf MD 128' Size 128' 2,302' Tieback 11,590 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-013 50-103-20880-00-00 601 W 5th Avenue, Suite 600 Anchorage, AK 99501 3. Address: N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393021, 393019, 392991 Pikka / Nanushuk Oil Pool NDB-051 Plugs Junk measured See attached reports See attached Reports Length 128' 3,218' 8,497' 3,218'Surface Intermediate Tie-Back 20"x34" 13-3/8" 9-5/8" measured TVD Production Liner 3,063' 11,434' 6,094' Casing Conductor 2,270' 4,099' 4-1/2" 3,063' 11,434' 17,473' 4,137' 4,750 9,210 5,020 6,870 6,870 11,590 11,560' 4,124' Burst Collapse 2,260 4,750 p k ft t Fra O s 224 6.A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 10/24/2024 By Meredith Guhl at 9:53 am, Dec 06, 2024 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Well Cleanup Oil Search Alaska, LLC Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,478 feet N/A feet true vertical 4,137 feet N/A feet Effective Depth measured 17,472 feet See rpt feet true vertical 4,137 feet See rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6 ppf P-110S 11,434' 4,099' Packers and SSSV (type, measured and true vertical depth) See attached 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Scott Leahy Contact Email:scott.leahy@santos.com Authorized Title: Completions Specialist Contact Phone: 907-330-4595 324-441 Sr Pet Eng: 9,210 Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf MD 128' Size 128' 2,302' N/A Tieback 11,590 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-013 50-103-20880-00-00 601 W 5th Avenue, Suite 600 Anchorage, AK 99501 3. Address: N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393021, 393019, 392991 Pikka / Nanushuk Oil Pool NDB-051 Plugs Junk measured See attached reports See attached Reports Length 128' 3,218' 8,497' 3,218'Surface Intermediate Tie-Back 20"x34" 13-3/8" 9-5/8" measured TVD Production Liner 3,063' 11,434' 6,094' Casing Conductor 2,270' 4,099' 4-1/2" 3,063' 11,434' 17,473' 4,137' 4,750 9,210 5,020 6,870 6,870 11,590 11,560' 4,124' Burst Collapse 2,260 4,750 p k ft t Fra O s 224 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 10/24/2024 By Grace Christianson at 10:17 am, Oct 24, 2024 RBDMS JSB 103124 CDW 10/24/2024 Superseded Page 1 of 1 Well Name: NDB-051 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,399.3 4,091.8 HES Zoneguard OH Packer #12 11,669.4 4,145.1 HES Zoneguard OH Packer #11 11,737.4 4,157.6 HES Zoneguard OH Packer #10 12,241.3 4,182.6 HES Zoneguard OH Packer #9 12,785.8 4,178.7 HES Zoneguard OH Packer #8 13,414.0 4,172.9 HES Zoneguard OH Packer #7 13,996.1 4,167.5 HES Zoneguard OH Packer #6 14,495.4 4,162.8 HES Zoneguard OH Packer #5 15,119.4 4,157.8 HES Zoneguard OH Packer #4 15,659.9 4,153.5 HES Zoneguard OH Packer #3 16,240.1 4,147.9 HES Zoneguard OH Packer #2 16,865.6 4,142.1 HES Zoneguard OH Packer #1 17,325.7 4,138.1 NDB-051 Well Schematic GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger/Top Packer3,063' MD 13-3/8" 68 ppf L-80 Surface Casing3,218' MD 9-5/8", 47ppf L-80 Intermediate Liner11,560' MD 4-½, 12.6ppf P-110S Production Liner 17,472' MD 4-½ Liner Hanger/ Packer11,378' MD Archer C-Flex Two-Stage Cementing Tool (50' MD below TS 790 top) 5,678' MD TOC First Stage Cement Job CBL Log9,200' MD 16" Hole Size 12-1/4" Hole Size 06.18.202447' RKB Bottom Flange 9-5/8" Tieback Assembly3,063' MD 8-½ Openhole 17,478' MD 9 8 3 4 5 6 7 1 2 # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1607 1546 33 3.813 4.778 2 Gaslift Mandrel 1.5" 2204 1980 55 3.865 7.630 3 X Landing Nipple 2272 2017 58 3.813 4.783 4 X Landing Nipple 11085 4025 77 3.813 4.787 5 D/HPsi Temp Gauge 11148 4039 77 3.905 6.000 6 SSDNERA Gaslift 11211 4052 78 3.813 5.040 7 Slimline Dial Unit 11277 4067 78 3.893 6.002 8 X Landing Nipple 11309 4073 78 3.813 4.783 9 Tieback Seal Assy 11413 4094 79 3.860 5.230 10 9.625"x 4.5" LH/Packer 11378 4087 79 6.030 8.430 11 #12Openhole Packer 11663 4144 79 3.918 8.000 12 #11Openhole Packer 11731 4156 80 3.918 8.000 13 Stage 10 FracSleeve 11922 4180 86 3.735 5.624 14 #10Openhole Packer 12235 4182 90 3.918 8.000 15 Stage 9 FracSleeve 12509 4180 90 3.735 5.624 16 #9Openhole Packer 12779 4178 90 3.918 8.000 17 Stage 8 FracSleeve 13095 4175 90 3.735 5.624 18 #8Openhole Packer 13407 4173 90 3.918 8.000 19 Stage 7 FracSleeve 13680 4170 90 3.735 5.624 20 #7Openhole Packer 13989 4167 90 3.918 8.000 21 Stage 6 FracSleeve 14261 4165 90 3.735 5.625 22 #6Openhole Packer 14489 4162 90 3.918 8.000 23 Stage 5 FracSleeve 14803 4160 90 3.735 5.624 24 #5Openhole Packer 15113 4157 90 3.918 8.000 25 Stage 4 FracSleeve 15426 4155 90 3.735 5.624 26 #4Openhole Packer 15653 4153 90 3.918 8.000 27 Stage 3 FracSleeve 15965 4148 90 3.735 5.624 28 #3Openhole Packer 16233 4144 90 3.918 8.000 29 Stage 2 FracSleeve 16589 4139 90 3.735 5.624 30 #2Openhole Packer 16859 4138 90 3.918 8.000 31 Stage 1 FracSleeve 17172 4138 90 3.735 5.624 32 #1Openhole Packer 17319 4138 90 3.918 8.000 33 #2Toe Sleeve 17387 4138 90 3.500 5.750 34 #1Toe Sleeve 17399 4138 90 3.500 5.750 35 WIV Collar 17462 4137 90 0.870 5.610 36 Eccentricshoe 17471 4137 90 3.900 5.190 Frac Ops Summary Report - AOGCC Well Name NDB-051 Primary Job Type Fracture Treatment Start Date End Date Summary 9/4/2024 9/5/2024 MIRU Frac equipment. MIRU backside pump. Prime up and Pressure Test surface lines to 9000 psi for 5 minutes. 9/5/2024 9/6/2024 Pump frac stages 1-4 Finish RU equipment, prime up and pressure test. Displace Wellbore Fluids with 275 bbls WF125ST. DataFrac: 250 bbls (WF125ST Fluid) at 40 bpm; as per design Frac stage 1: 1,933 bbls slurry (YF125ST fluid), 245,138 lbs 16/20 Carbolite SG (1, 3, 5, 7, 9, 10 ppa), 1,685 bbls clean fluid at 40 bpm; as per design Frac stage 2: 1,556 bbls slurry (YF125ST fluid), 244,655 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 1,309 bbls clean fluid at 40 bpm; as per design Frac stage 3: 1,754 bbls slurry (YF125ST fluid), 276,654 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 1,475 bbls clean fluid at 40 bpm; as per design Frac stage 4 : 2,337 bbls slurry (YF125ST fluid), 17,600 lbs 40/70 Scour (1, 3 ppa), 241,344 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 2,078 bbls clean fluid at 40 bpm; as per design Well Freeze Protected with 45 bbls down the tubing. Total Load to Recover (TLTR) Stages 1-4 7,072 bbls 9/6/2024 9/7/2024 Fill and Heat Frac Tanks. Load Proppant for Stages 5-7. 9/7/2024 9/8/2024 Pump frac stages 5-7 Prime up and pressure test. Drop ball. Pump 225 bbls WF125ST fluid to seat at 4.0 bpm. Pump Check 60 bbls WF125ST at 40 bpm Frac stage 5: 1,789 bbls slurry (YF125ST fluid), 16,042 lbs 40/70 (1, 3 ppa), 254,850 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 1,516 bbls clean fluid at 40 bpm; as per design Frac stage 6: 1,971 bbls slurry (YF125ST fluid), 18,113 lbs 40/70 (1,3 ppa), 283,760 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 1,667 bbls clean fluid at 40 bpm; as per design Frac stage 7: 2,249 bbls slurry (YF125ST fluid), 12,423 lbs 40/70 (1, 3 ppa), 216,499 lbs 16/20 Carbolite SG (1, 3,5,7,9,10 ppa), 25,260 lbs 12/18 (10 ppa), 1,993 bbls clean fluid at 40 bpm; as per design. Well Freeze Protected with 45 bbls down the tubing. Total Load to Recover (TLTR) Stages 5-7 5,461 bbls Total Load to Recover (TLTR) Well 12,533 bbls 9/8/2024 9/9/2024 Fill and Heat Frac Tanks. Load Proppant for Stages 5-7. 9/9/2024 9/10/2024 RDMO Frac Equipment. Prepare for Coil Unit. 9/10/2024 9/11/2024 Wait on Coil Unit. 9/11/2024 9/12/2024 Wait on Coil Unit. 9/12/2024 9/13/2024 Test BOPE. M/U BHA. RIH and Tag Collet at 13,663' ctmd. POH and swap BHAs. RIH to fish Collet #8. 9/13/2024 9/14/2024 RIH w/ Knockout Ball BHA and set Collet in Sleeve #8. Pressure up the Coil x Tubing Annulus to 2,200 psi and shift sleeve #8 open. POH. Blowdown reel with N2. RDMO. Page 1 of 2 Frac Ops Summary Report - AOGCC Start Date End Date Summary 9/14/2024 9/15/2024 Pump frac stages 8-10 Prime up and pressure test. Drop ball. Pump 200 bbls WF125ST fluid to seat at 4.0 bpm. Pump Check 120 bbls WF125ST at 40 bpm Frac Stage 8: 1,977 bbls slurry (YF125ST fluid), 16,904 lbs 40/70 (1, 3 ppa), 285,792 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 1,672 bbls clean fluid at 40 bpm; as per design Frac Stage 9: 1,762 bbls slurry (YF125ST fluid), 281,743 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 1,478 bbls clean fluid at 40 bpm; as per design Frac Stage 10: 2,090 bbls slurry (YF125ST fluid), 282,625 lbs 16/20 Carbolite SG (1, 2, 4, 6, 8, 10, 12 ppa), 37,936 lbs 12/18 (12 ppa), 1,706 bbls clean fluid at 40 bpm; as per design. Well Freeze Protected with 45 bbls down the tubing. Total Load to Recover (TLTR) Stages 8-10 5,176 bbls Total Load to Recover (TLTR) Well 17,709 bbls 9/15/2024 9/16/2024 RDMO Frac Equipment Page 2 of 2 Flowback Ops Summary Report - AOGCC Well Name NDB-051 Primary Job Type Flowback/Testing Start Date End Date Summary 9/15/2024 9/16/2024 Begin setting up area for TTLA 9/16/2024 9/17/2024 Expro rigged ball catcher off of B-46 and secured the well. 9/17/2024 9/18/2024 Expro prepping area for TTLA 9/18/2024 9/19/2024 Prep to rig up Ball catcher and TTLA 9/19/2024 9/20/2024 Prep to rig up Ball catcher, build Aux. TTLA and main TTLA for management of fluid from NDB 051 clean out operations 9/20/2024 9/21/2024 Rig up Ball catcher and Walkways for upright tanks. Pressure test lines from well, through ball catcher to Choke manifold. Low 400psi and High 4000psi. Good test. 9/21/2024 9/22/2024 Rig up twin pumper and injection lines to NDBi-014. Pressure test same. Start injectivity test 9/22/2024 9/23/2024 Prep for FB operations. 9/23/2024 9/24/2024 Open up well and perform Well clean-up and Flowback as per procedure. 9/24/2024 9/25/2024 Perform Well Clean Up operations as per procedure. 9/25/2024 9/26/2024 Perform Well Clean Up operations with N2 assist through Gaslift valves as per procedure. 9/26/2024 9/27/2024 Continue Well Clean Up operations as per procedure. 9/27/2024 9/28/2024 Continue Well Clean Up operations as per procedure. 9/28/2024 9/29/2024 Continue Well Clean Up operations as per procedure. 9/29/2024 9/30/2024 Complete Well Cleanout operations. Rig down from well while monitoring BHP and clean up tanks. 9/30/2024 10/1/2024 Complete the cleaning of tanks and injection of cleanout fluids into NDBi-014. Well cleanout operations is complete. Will continue to monitoring SLB BHP gauge. Page 1 of 1 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 4.0 gal F103 Surfactant 0.9 Gal/mGal 705.8 gal J134 Breaker 0.0 lb/mGal 4.0 lbm J450 Stabilizing Agent 0.6 Gal/mGal 409.4 gal J475 Breaker J475 6.0 lb/mGal 4,447.4 lbm J511 Stabilizing Agent 1.7 lb/mGal 1,287.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,653.0 gal J580 Gel J580 28.5 lb/mGal 21,213.9 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 66.1 gal M002 Additive 0.0 lb/mGal 1.3 lbm M117 Clay Control Agent 267.8 lb/mGal 199,335.6 lbm M275 Bactericide 0.4 lb/mGal 263.3 lbm S522-1218 Propping Agent varied concentrations 63,196.0 lbm S522-1620 Propping Agent varied concentrations 2,508,538.0 lbm S522-4070 Propping Agent varied concentrations 81,082.0 lbm S901 Proppant with Scale Inhibitor S901 varied concentrations 104,522.0 lbm 66.95097 % 30.25832 % 2.13153 % 0.23328 % 0.11522 % 0.06592 % 0.04354 % 0.03922 % 0.03694 % 0.03016 % 0.02304 % 0.01419 % 0.01217 % 0.01217 % 0.01118 % 0.00932 % 0.00607 % 0.00231 % 0.00145 % 0.00097 % 0.00058 % 0.00029 % 0.00025 % 0.00025 % 0.00017 % 0.00015 % 0.00006 % 0.00006 % 0.00004 % 0.00004 % 0.00004 % 0.00003 % 0.00003 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % Total 100 % 9012-54-8 Hemicellulase enzyme * 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. Total 9050-36-6 Maltodextrin 2634-33-5 1,2-benzisothiazolin-3-one 9004-53-9 Dextrin 11138-66-2 Xanthan Gum 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 7632-00-0 Sodium nitrite 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 9005-65-6 Sorbitan monooleate, ethoxylated 9004-32-4 Sodium carboxymethylcellulose 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 36089-45-9 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-propenoate 68308-89-4 Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 532-32-1 Sodium benzoate 1338-41-6 Sorbitan stearate 64-19-7 Acetic acid (impurity) 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 1310-73-2 Sodium hydroxide 63-42-3 Lactose 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 127-08-2 Acetic acid, potassium salt (impurity) 7786-30-3 Magnesium chloride 9000-90-2 Amylase, alpha 63148-62-9 Dimethyl siloxanes and silicones 14807-96-6 Magnesium silicate hydrate (talc) 9002-84-0 poly(tetrafluoroethylene) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 68131-39-5 Ethoxylated Alcohol 9025-56-3 Hemicellulase 91053-39-3 Diatomaceous earth, calcined 67-63-0 Propan-2-ol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 9003-35-4 Phenolic resin 50-70-4 Sorbitol 111-76-2 2-butoxyethanol 7727-54-0 Diammonium peroxodisulphate 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate 7647-14-5 Sodium chloride 102-71-6 2,2`,2"-nitrilotriethanol 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF125ST:WF125 744,250 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-1959 Fluid Name & Volume Concentration Volume Disclosure Type: Post-Job Well Completed: Date Prepared: 10/10/2024 State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDB-051 Basin/Field: Pikka # SLB-Private Page: 1 / 1 Updated 10/07/2024INPUT AK TSCA StatusNorth Slope50-103-20880-00-00Post526,54773.00000%9,071,208Trade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SMETracercoCarrier FluidSoy Methyl Ester67784-80-91000.0013670712124.0098750000T-166ATracercoChemical Tracer5-Iodo-m-xylene22445-41-61000.00001215171.1023100000T-772TracercoChemical Tracer2-(Trifluoromethyl)Benzophenone727-99-11000.00000486070.4409240000T-731TracercoChemical Tracer1-Bromo-3,5-dichlorobenzene19752-55-71000.00000486070.4409240000T-161BTracercoChemical Tracer4-Iodotoluene624-31-71000.00000486070.4409240000T-164BTracercoChemical Tracer2-Bromonaphthalene580-13-21000.00001215171.1023100000T-706TracercoChemical Tracer1-Bromo-4-chlorobenzen106-39-81000.00002430352.2046200000T-776TracercoChemical Tracer1,4-Dibromonaphthalene83-53-41000.00000729100.6613860000T-719TracercoChemical Tracer3,4-Dichlorobenzophenone6284-79-31000.00000486070.4409240000T-720TracercoChemical Tracer1,2,4,5-Tetrabromobenzene636-28-21000.00000486070.4409240000T-165CTracercoChemical Tracer9-Bromophenanthrene573-17-11000.00000729100.6613860000T-729TracercoChemical Tracer1,4-Dibromo-2,5-dimethyl benzene1074-24-41000.000340248830.8646800000T-734TracercoChemical Tracer1-Bromo-2-(trifluoromethyl)benzene392-83-61000.000340248830.8646800000T-750TracercoChemical Tracer1,4-Dibromo-2-fluorobenzene1435-52-51000.000340248830.8646800000WaterTracercoCarrier FluidWater7732-18-51000.000951539686.3161344380T-158cTracercoChemical TracerSodium-2,6-Difluorobenzoate6185-28-01000.00000884650.8024816800T-808TracercoChemical TracerSodium-3,4-dichlorobenzoate17274-10-11000.00000865200.7848447200T-913TracercoChemical TracerSodium-2-chloro-6-fluorobenzoate1382106-10-61000.00000873470.7923404280T-911TracercoChemical TracerSodium-2-chloro-4-fluorobenzoate885471-43-11000.00000888780.8062295340T-158eTracercoChemical TracerSodium-3,5-Difluorobenzoate530141-39-01000.00000853050.7738216200T-928TracercoChemical TracerSodium-2-fluoro-4-methylbenzoate1708942-19-11000.00000853050.7738216200T-176cTracercoChemical TracerSodium-2,4,5-trifluorobenzoate522651-48-51000.00000853050.7738216200T-190aTracercoChemical TracerSodium-2-(Trifluoromethyl) benzoate2966-44-11000.00000853050.7738216200T-809TracercoChemical TracerSodium-3,5-dichlorobenzoate154862-40-51000.00000853050.7738216200T-921TracercoChemical TracerSodium-3-chloro-2-fluorobenzoate1421029-89-11000.00000853050.7738216200Sodium FluoresceinTracercoChemical TracerSodium Fluorescein518-47-81000.00001701241.5432340000Rhodamine WTTracercoChemical TracerRhodamine WT37299-86-81000.00000850620.7716170000Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For TracercoCounty:API Number:Operator Name: Oil Search Alaska, LLCWell Name and Number: NDB-051Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs) FracCAT Treatment Report Well : NDB-051, Stages 1-4 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 5, 2024 Prepared by Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure (All Zones) Initial Wellhead Pressure (psi) 490 Initial BHP at Gauge (psi) 2,438 Final Surface ISIP (psi) 790 Final ISIP at Gauge (psi) 2,567 Surface Shut in Pressure(psi) 3,049 BH Shut in Pressure (psi) 3,261 Maximum Treating Pressure (psi) 7,702 BH Gauge at 11,148 ft MD, 4,039 ft TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 8,108.3 Total Proppant Pumped per Load Tickets(lb) 1,025,391 Total YF125ST Past Wellhead (bbl) 6,104.1 Total Proppant in Formation (lb) 1,025,391 Total WF125 Past Wellhead (bbl) 972.0 Total S522 - 16/20 CarboLite per Load Tickets (lb)967,479 Total Freeze Protect Past Wellhead (bbl) Pumped by LRS Total S522 - 40/70 CarboLite per Load Tickets (lb)17,600 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)40,312 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal)280 279.4 M275 (lb) 150 149.7 J450 (gal) 164 163.7 J753 (gal) 30.0 28.13 J580 (lb) 8,707 8,691.3 J475 (lb) 1,760 1756.2 J532 (gal) 622 622 J134 (lb) 0 0 J511 (lb) 610 500 D206 (gal) 2 2 M002 (lb) 0.5 0.44 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 b e 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. 7,702 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Summary On September 5th,2024, SLB opened P Sleeve and performed a hydraulic fracturing treatment on Stages 1-4 of NBD-051. The design called for the completion of stages 1-4, with a total of 962,832 lbs of proppant in 7,900 bbl of slurry. In the end of the Stage 4 there was a hard shutdown with ISIP = 790 psi and pressure decline was monitored for 60 min. A total of 1,025,391 pounds of proppant was pumped at surface and 1,025,391 was placed into formation in 8,108.3 bbl of slurry. Stages 1 consisted of a PAD and 8 proppant steps 1-10 PPA. Stage 2 consisted of a PAD, 7 proppant steps 1 - 12 PPA, Stage 3 consisted of 7 proppant steps 1 12PPA (per Downstream Densos max proppant concentration recorded @ 10PPA), Stage 4 consisted of PAD, two scour steps 1 3PPA 40/70 CarboLite and 7 proppant steps 1-12PPA. Pump trips were staggered from 7,600 to 8,100 psi. The GORV was set to 8,50 0 psi. Summary of Stages 1-4 Material Actual Design Slurry Volume (bbl)8,108 7,900 Clean Fluid Volume(bbl) 7,076 6,834 Proppant (lb) per Load Tickets 1,025,391 962,832 12:10:19 12:43:39 13:16:59 13:50:19 14:23:39 14:56:59 15:30:19 16:03:39 16:36:59 17:10:19 17:43:39 18:16:59 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 0 10 20 30 40 0 2 4 6 8 10 12 14 16 18 20 22 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stg 1-4 09-05-2024 Displ DFIT 0 Stage 1 Stage 2 Stage 3 Stage 4 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States P Sleeve Activation,Displacement and DFIT P Sleeve activation was successful. When the well was opened the pressure was 490 psi. P Sleeve was activated at the pressure 7,702 psi at average Slurry Rate of 4.2 bbl/min followed by Displacement Wellbore fluid step and hard shutdown with an ISIP of 764 psi. After the pressure was monitored for 30 min. The DFIT was pumped. In the end of pumping there was a hard shutdown with an ISIP of 750 psi and the pressure was monitored for 60 min. A summary of the Stage below: Summary of P Sleeve Activation,Displacement and DFIT Total Slurry Pumped (bbl) 528.5 Max pumping Rate (bpm) 40.5 WF125 Pumped (bbl) 528.5 Average Pumping Rate (bpm) 36.1 Average Water Temperature (F)96.6 Maximum Treating Pressure (psi) 7,702 Average Viscosity (cP)18.8 Average Treating Pressure (psi) 4,374 As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displace ment 278.5 34.2 10.7 WF125 11692 0.0 0.0 0.0 2 DFIT 250 37.9 7.4 WF125 10503 0.0 0.0 0.0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Displacement 34.2 40.5 5321 7702 189 2 DFIT 37.9 40.1 3427 3705 189 12:10:19 12:43:39 13:16:59 13:50:19 14:23:39 14:56:59 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 0 10 20 30 40 0 2 4 6 8 10 12 14 16 18 20 22 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stg 1-4 Displacement, DFIT 09-05-2024 0 P Sleeve activation Displ DFIT Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 10:47:37 Priming Pumps 71 2 0.0 0.0 0.0 2 11:18:56 Low Pressure Test 660 4 0.0 0.0 0.0 3 11:27:20 Started Mixing 25# Gel 4744 5 0.0 0.0 0.0 4 11:28:06 Mid Pressure Test 4987 4 0.0 0.0 0.0 5 11:33:03 High Pressure Test 9534 4 0.0 0.0 0.0 6 11:40:33 Pressure Test is good 731 5 0.0 0.0 0.0 7 11:41:46 Bleeding off the pressure 731 5 0.0 0.0 0.0 9 12:22:22 LR Pressuring Up IA To 3,000 722 1302 0.0 0.0 0.0 9 12:28:37 Open Well 511 3018 0.0 0.0 0.0 10 12:29:30 Start Displacement Automatically 501 3012 0.0 0.0 0.0 11 12:29:30 Start Propped Frac Automatically 501 3012 0.0 0.0 0.0 12 12:29:30 Start Displ and DFIT Automatically 501 3012 0.0 0.0 0.0 13 12:30:07 Started Pumping 1041 3034 0.0 2.2 0.0 14 12:38:38 Activated Extend Stage 6129 3136 179.5 40.4 0.0 15 12:41:09 Stopped Pumping 393 3074 278.6 15.2 0.0 16 12:43:34 Pressure Decline for 30 min 724 3058 278.6 0.0 0.0 17 13:07:32 Radio Check 341 3050 278.6 0.0 0.0 18 13:10:28 Started Pumping 325 3043 278.6 0.0 0.0 19 13:10:31 Start DFIT Automatically 325 3042 278.6 0.0 0.0 20 13:11:10 Stage at Perfs: Displacement Wellbore Fluid 1530 3094 280.0 6.7 0.0 21 13:18:02 Stopped Pumping 938 3078 528.6 0.0 0.0 22 13:18:56 Monitor Pressure Decline for 60 min 790 3089 528.6 0.0 0.0 23 14:26:29 Fueling Frac Equipment 354 2848 528.6 0.0 0.0 24 14:37:34 Ball/Collet#1 is loaded to Ball Launcher 328 2812 528.6 0.0 0.0 25 15:08:38 Radio Check 280 2725 528.6 0.0 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Stage 1 The treating pressure on PAD was around 3,800 psi before the Collet/Ball#1 hit the sleeve. When the rate was slowed down to 18 bpm there was clear indication that Ball/Collet#1 was seated. Immediately after collet was set in place treating pressure was 3,780 psi while after 1 PPA pass through the formation, the pressure fell to 3,560 psi. During the proppant stages treating pressure was gradually increasing from 3,560 to 6,270 psi. Slurry rate remained steady at 40bpm until ready to slow down for Collet/Ball#2 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #1 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,512 2,964 2,780 Bottomhole Pressure 3,280 3,693 3,530 Summary of Stage 1 Total Proppant Pumped (lb) 245,138 Max pumping Rate (bpm) 41.4 Total Proppant in Formation (lb) 245,138 Average Pumping Rate (bpm) 37.9 CarboLite 40/70 (lb) per Load Tickets 0 Maximum Treating Pressure (psi) 6,337 CarboLite 16/20 (lb) per Load Tickets 235,332 Average Treating Pressure (psi) 4,320 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)9,806 Average Water Temperature (F) 96.0 Total Slurry Pumped (bbl) 1,933.0 Average Viscosity (cP) 17.9 YF125ST Pumped (bbl) 1,685.4 WF125 Pumped (bbl) 0.0 15:09:37 15:17:57 15:26:17 15:34:37 15:42:57 15:51:17 15:59:37 16:07:57 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 1 09-05-2024 0 Collet/Ball#2 hit the sleeve Drop Rate for Ball/Collet#1 Drop Rate for Ball/Collet#2 Ball/Collet#1 hit the sleeve Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 XL tubing Flush 302.8 38.9 8.5 YF125ST 12702 0.0 0.0 0 2 Drop Collet#1 3.0 40.1 0.1 YF125ST 126 0.0 0.0 0 3 PAD st1 231.1 40.1 5.8 YF125ST 9709 0.0 0.0 0 4 Slow For Seat 40.2 19.1 2.2 YF125ST 1692 0.0 0.0 0 5 Resume Pad 44.0 33.9 1.3 YF125ST 1833 0.0 0.0 0 6 1.0 PPA 200.0 40.0 5.0 YF125ST 8074 16/20 CSG-IV 1.1 0.9 7704 7 3.0 PPA 200.0 40.0 5.0 YF125ST 7435 16/20 CSG-IV 3.1 2.9 22763 8 5.0 PPA 230.0 40.0 5.8 YF125ST 7925 16/20 CSG-IV 5.1 4.9 40951 9 7.0 PPA 230.0 39.9 5.8 YF125ST 7389 16/20 CSG-IV 7.1 6.9 53631 10 9.0 PPA 215.0 39.8 5.4 YF125ST 6467 16/20 CSG-IV 9.2 8.9 60540 11 10.0 PPA 197.5 39.8 5.0 YF125ST 5786 16/20 CSG-IV 10.2 9.8 59458 12 Clear Lines & Spacer 36.4 40.4 0.9 YF125ST 1524 16/20 CSG-IV 4.2 0.1 91 13 Drop Collet#2 3.0 40.7 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 XL tubing Flush 38.9 40.2 3860 3957 278 2 Drop Collet#1 40.1 40.1 3989 4022 3957 3 PAD st1 40.1 40.2 3847 4221 1988 4 Slow For Seat 19.1 34.9 2468 2964 1713 5 Resume Pad 33.9 40.4 3809 4064 2789 6 1.0 PPA 40.0 40.4 3871 3965 3750 7 3.0 PPA 40.0 40.2 3672 3763 3566 8 5.0 PPA 40.0 40.3 3675 3793 3571 9 7.0 PPA 39.9 40.4 4066 4401 3790 10 9.0 PPA 39.8 40.4 5013 5532 4403 11 10.0 PPA 39.8 40.3 6011 6330 5534 12 Clear Lines & Spacer 40.4 41.4 5924 6337 5540 13 Drop Collet#2 40.7 40.7 5947 5947 5947 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 15:10:23 Start XL tubing Flush Automatically 370 2723 0.0 0.0 0.0 2 15:10:23 Start Propped Frac Automatically 370 2723 0.0 0.0 0.0 3 15:10:23 Start Stage1 Automatically 370 2723 0.0 0.0 0.0 4 15:12:08 Stage at Perfs: DFIT 3933 2864 30.9 38.9 0.0 5 15:12:37 XL sample is good 3944 2876 50.0 39.8 0.0 6 15:18:23 Stage at Perfs: XL tub Flush 3911 3255 281.0 40.2 0.0 7 15:18:56 Start Drop Collet#1 Manually 4031 3240 303.1 40.1 0.0 8 15:19:01 Start PAD st1 Automatically 4126 3228 306.4 40.1 0.0 9 15:24:47 Start Slow For Seat Automatically 1569 3052 537.3 28.0 0.0 10 15:24:55 Activated Extend Stage 2381 3073 540.4 20.2 0.0 11 15:26:18 Ball/Collet#1 Hit the Sleeve 3100 3111 564.6 17.4 0.0 12 15:26:59 Deactivated Extend Stage 2779 3129 577.2 18.6 0.0 13 15:26:59 Start Resume Pad Manually 2779 3129 577.2 18.6 0.0 14 15:27:06 Stage at Perfs: Drop Collet#1 3254 3157 579.4 20.1 0.0 15 15:27:15 Stage at Perfs: PAD st1 3832 3172 582.7 24.6 0.0 16 15:28:19 Start 1.0 PPA Automatically 3778 3212 621.4 40.2 0.0 17 15:28:19 Started Pumping Prop 3778 3212 621.4 40.2 0.0 18 15:33:08 Stage at Perfs: Slow For Seat 3772 3267 813.8 40.0 1.0 19 15:33:19 Start 3.0 PPA Automatically 3740 3272 821.2 40.1 1.0 20 15:34:08 Stage at Perfs: Resume Pad 3704 3279 853.7 39.9 3.0 21 15:35:14 Stage at Perfs: 1.0 PPA 3756 3111 897.8 40.1 3.0 22 15:38:19 Start 5.0 PPA Automatically 3579 3071 1021.3 40.1 3.0 23 15:40:02 Ball/Collet#2 is loaded to Ball Launcher 3642 3112 1089.7 39.8 5.1 24 15:40:14 Stage at Perfs: 3.0 PPA 3653 3115 1097.6 40.0 5.1 25 15:44:05 Start 7.0 PPA Automatically 3782 3191 1251.8 40.2 5.1 26 15:45:15 Stage at Perfs: 5.0 PPA 3919 3219 1298.2 39.7 6.9 27 15:49:50 Start 9.0 PPA Automatically 4409 3303 1481.3 39.8 6.9 28 15:51:01 Stage at Perfs: 7.0 PPA 4653 3326 1528.4 40.0 9.2 29 15:55:15 Start 10.0 PPA Automatically 5545 3269 1696.6 39.7 8.8 30 15:56:48 Stage at Perfs: 9.0 PPA 5949 3258 1758.1 40.3 9.9 31 16:00:12 Start Clear Lines & Spacer Manually 6347 3191 1893.6 41.1 1.1 32 16:00:15 Stopped Pumping Prop 6325 3191 1895.7 41.4 0.5 33 16:01:06 Start Drop Collet#2 Manually 5947 3191 1930.0 40.7 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Stage 2 Once the Collet/Ball#2 landed the pressure transition from Stage 1 to 2 was typical. The average treating pressure on PAD was around 3,200 psi and stayed stable around 3,060 psi until 2 PPA 16/20 CSG-IV started going into the formation, since then the treating pressure was gradually increasing from 3,150 to 6,440 psi. During the Flush Pump #2 automatically shut down because of low power end lube pressure warning which caused slurry rate drop temporarily, immediately after rate was brought back to 40bpm (pump #2 was brought back online at the beginning of stage 2). Slurry rate remained steady at 40bpm until ready to slow down for Collet/Ball#3 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #2 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,385 2,831 3,442 Bottomhole Pressure 3,205 3,658 2,664 Summary of Stage 2 Total Proppant Pumped (lb) 244,655 Max pumping Rate (bpm) 41.2 Total Proppant in Formation (lb) 244,655 Average Pumping Rate (bpm) 37.8 CarboLite 40/70 (lb) per Load Tickets 0 Maximum Treating Pressure (psi) 6,448 CarboLite 16/20 (lb) per Load Tickets 234,869 Average Treating Pressure (psi) 4,258 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)9,786 Average Water Temperature (F) 98.9 Total Slurry Pumped (bbl) 1,555.5 Average Viscosity (cP) 18.1 YF125ST Pumped (bbl) 1,309.0 WF125 Pumped (bbl) 0.0 16:07:56 16:11:16 16:14:36 16:17:56 16:21:16 16:24:36 16:27:56 16:31:16 16:34:36 16:37:56 16:41:16 16:44:36 16:47:56 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 2 09-05-2024 Drop Rate for Ball/Collet#2 Collet/Ball#2 hit the sleeve Collet/Ball#3 hit the sleeve Drop Rate for Ball/Collet#3 0000 Lost pump#2 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st2 222.0 40.1 5.5 YF125ST 9327 0.0 0.0 0 2 Slow For Seat 44.9 20.1 2.4 YF125ST 1890 0.0 0.0 0 3 Resume Pad 29.6 33.6 0.9 YF125ST 1238 0.0 0.0 0 4 1.0 PPA 160.0 39.9 4.0 YF125ST 6445 16/20 CSG-IV 1.0 1.0 6478 5 2.0 PPA 160.0 40.0 4.0 YF125ST 6184 16/20 CSG-IV 2.1 1.9 12633 6 4.0 PPA 180.0 39.9 4.5 YF125ST 6443 16/20 CSG-IV 4.1 3.9 26358 7 6.0 PPA 180.0 40.0 4.5 YF125ST 5989 16/20 CSG-IV 6.1 3.0 37089 8 8.0 PPA 180.0 39.7 4.5 YF125ST 5595 16/20 CSG-IV 8.2 7.9 46409 9 10.0 PPA 180.0 40.0 4.5 YF125ST 5251 16/20 CSG-IV 10.2 9.9 54546 10 12.0 PPA 179.5 39.9 4.5 YF125ST 4964 16/20 CSG-IV 12.2 11.8 61063 11 Clear Lines & Spacer 36.5 40.5 0.9 YF125ST 1528 16/20 CSG-IV 5.9 0.1 79 12 Drop Collet#3 3.0 40.2 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st2 40.1 40.6 4797 6026 2921 2 Slow For Seat 20.1 39.9 2336 2832 1596 3 Resume Pad 33.6 40.0 3478 3728 2703 4 1.0 PPA 39.9 40.4 3071 3358 3004 5 2.0 PPA 40.0 40.2 3042 3080 3000 6 4.0 PPA 39.9 40.2 3130 3212 3060 7 6.0 PPA 40.0 40.3 3438 3651 3212 8 8.0 PPA 39.7 40.0 4151 4682 3651 9 10.0 PPA 40.0 40.6 5448 5925 4685 10 12.0 PPA 39.9 40.6 6224 6448 5933 11 Clear Lines & Spacer 40.5 41.2 6079 6439 5890 12 Drop Collet#3 40.2 40.2 5907 5933 5890 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 16:01:11 Start PAD st2 Automatically 6046 3197 0.0 40.4 0.0 2 16:01:11 Start Propped Frac Automatically 6046 3197 0.0 40.4 0.0 3 16:01:11 Start Stage2 Automatically 6046 3197 0.0 40.4 0.0 4 16:02:11 Stage at Perfs: 10.0 PPA 5506 3209 40.2 40.3 0.0 5 16:06:43 Start Slow For Seat Automatically 1347 3101 221.9 33.7 0.0 7 16:07:27 Stage at Perfs: Clear Lines & Spacer 2315 3136 236.6 18.0 0.0 8 16:08:25 Ball/Collet#2 Hit the Sleeve 2901 3149 254.0 18.0 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 9 16:09:06 Start Resume Pad Manually 2787 3146 266.3 18.0 0.0 10 16:09:08 Activated Extend Stage 2943 3150 266.9 18.3 0.0 11 16:09:24 Stage at Perfs: Drop Collet#2 3694 3178 273.3 31.5 0.0 12 16:09:30 Stage at Perfs: PAD st2 3629 3173 276.6 35.6 0.0 13 16:10:00 Start 1.0 PPA Manually 3173 3164 296.1 40.2 0.0 14 16:10:00 Started Pumping Prop 3173 3164 296.1 40.2 0.0 15 16:14:01 Start 2.0 PPA Automatically 3056 3192 456.5 40.0 1.0 16 16:14:51 Stage at Perfs: Slow For Seat 3049 3193 489.7 39.7 2.0 17 16:15:58 Stage at Perfs: Resume Pad 3009 3206 534.4 40.0 2.0 18 16:16:42 Stage at Perfs: 1.0 PPA 3072 3210 563.8 39.9 2.0 19 16:18:01 Start 4.0 PPA Automatically 3075 3226 616.5 40.0 2.0 20 16:20:43 Stage at Perfs: 2.0 PPA 3159 3178 724.2 39.9 4.0 21 16:22:31 Start 6.0 PPA Automatically 3213 3177 796.3 39.8 4.1 22 16:23:45 Ball/Collet#3 is loaded to Ball Launcher 3319 3185 845.4 40.0 6.0 23 16:24:43 Stage at Perfs: 4.0 PPA 3452 3192 884.0 40.1 6.0 24 16:27:01 Start 8.0 PPA Automatically 3651 3205 976.1 39.9 6.1 25 16:29:14 Stage at Perfs: 6.0 PPA 4177 3226 1064.2 39.6 7.8 26 16:31:33 Start 10.0 PPA Automatically 4703 3249 1156.2 39.7 8.1 27 16:33:45 Stage at Perfs: 8.0 PPA 5606 3285 1244.1 40.2 10.2 28 16:36:03 Start 12.0 PPA Automatically 5926 3230 1336.2 39.5 10.0 29 16:38:15 Stage at Perfs: 10.0 PPA 6279 3251 1423.9 39.6 11.9 30 16:40:33 Start Clear Lines & Spacer Manually 6468 3277 1515.6 40.6 1.2 31 16:40:35 Stopped Pumping Prop 6450 3273 1517.0 40.8 0.7 32 16:41:27 Start Drop Collet#3 Manually 5939 3274 1552.0 40.1 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Stage 3 Once the Collet/Ball#3 hit the sleeve the pressure transition from Stage 2to 3 was typical. The average treating pressure on PAD was around 3,050 psi and slowly fell to about 2,960 psi until 1PPA started going into the formation, since then pressure was gradually increasing from 2,960 to 6,290 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#4 to seat. While monitoring prop count during stages 1 & 2 it was observed S-POD RD tracking 3% to 5% higher gate position vs Handbook. The adjustment request to S-POD EO hasnt been correctly implemented which led to proppant concentration variance between S-POD density and in-line density. Issue was addressed prior stage 4. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #3 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,313 3,348 2,648 Bottomhole Pressure 3,122 3,789 3,422 Summary of Stage 3 Total Proppant Pumped (lb) 276,654 Max pumping Rate (bpm) 41.4 Total Proppant in Formation (lb) 276,654 Average Pumping Rate (bpm) 37.9 CarboLite 40/70 (lb) per Load Tickets 0 Maximum Treating Pressure (psi) 6,230 CarboLite 16/20 (lb) per Load Tickets 265,588 Average Treating Pressure (psi) 3,928 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)11,066 Average Water Temperature (F) 99.4 Total Slurry Pumped (bbl) 1,754.0 Average Viscosity (cP) 18.7 YF125ST Pumped (bbl) 1,475.3 WF125 Pumped (bbl) 0.0 16:47:56 16:51:16 16:54:36 16:57:56 17:01:16 17:04:36 17:07:56 17:11:16 17:14:36 17:17:56 17:21:16 17:24:36 17:27:56 17:31:16 17:34:36 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 3 09-05-2024 Drop Rate for Ball/Collet#3 Collet/Ball#3 hit the sleeve Drop Rate for Ball/Collet#4 Collet/Ball#4 hit the sleeve 00000000000000 Prop Conc as per In-Line Denso @ 8PPA vs 10PPA S-POD and 10PPA vs 12PPA S-POD Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st3 213.0 39.1 5.4 YF125ST 8947 0.0 0.0 0 2 Slow For Seat 48.8 20.4 2.6 YF125ST 2049 0.0 0.0 0 3 Resume Pad 36.6 35.3 1.0 YF125ST 1539 0.0 0.0 0 4 1.0 PPA 180.0 40.1 4.5 YF125ST 7254 16/20 CSG-IV 1.1 0.9 7229 5 2.0 PPA 200.0 40.0 5.0 YF125ST 7728 16/20 CSG-IV 2.1 2.0 15844 6 4.0 PPA 225.0 40.0 5.6 YF125ST 8049 16/20 CSG-IV 4.1 3.9 33054 7 6.0 PPA 225.0 40.1 5.6 YF125ST 7528 16/20 CSG-IV 6.2 5.7 45383 8 8.0 PPA 225.0 39.9 5.6 YF125ST 6997 16/20 CSG-IV 8.3 7.9 57903 9 10.0 PPA 175.0 40.0 4.4 YF125ST 5101 16/20 CSG-IV 8.0 8.0 53135 10 12.0 PPA 188.1 40.0 4.7 YF125ST 5198 16/20 CSG-IV 10.0 10.0 64027 11 Clear Lines & Spacer 34.5 40.6 0.9 YF125ST 1448 16/20 CSG-IV 6.9 0.1 79 12 Drop Collet#4 3.0 39.8 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st3 39.1 40.2 4513 6230 3144 2 Slow For Seat 20.4 39.6 2406 3101 1583 3 Resume Pad 35.3 40.5 3173 3364 3036 4 1.0 PPA 40.1 40.9 3017 3082 2947 5 2.0 PPA 40.0 40.2 2988 3020 2954 6 4.0 PPA 40.0 40.2 3086 3176 3019 7 6.0 PPA 40.1 40.4 3404 3602 3176 8 8.0 PPA 39.9 40.7 4182 4748 3602 9 10.0 PPA 40.0 40.8 4842 4882 4742 10 12.0 PPA 40.0 40.7 5198 5562 4840 11 Clear Lines & Spacer 40.6 41.4 5256 5564 5030 12 Drop Collet#4 39.8 39.8 5065 5099 5037 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 16:41:32 Start PAD st3 Automatically 6088 3282 0.0 40.1 0.0 2 16:41:32 Start Propped Frac Automatically 6088 3282 0.0 40.1 0.0 3 16:41:32 Start Stage3 Automatically 6088 3282 0.0 40.1 0.0 4 16:42:47 Stage at Perfs: 12.0 PPA 4888 3255 48.3 37.8 0.0 5 16:43:16 Pump 2 Low Power End Lube Pressure 4844 3258 66.7 38.7 0.0 6 16:46:59 Start Slow For Seat Automatically 1583 3165 213.0 36.5 0.0 7 16:47:41 Stage at Perfs: Clear Lines & Spacer 2235 3190 227.7 18.0 0.0 8 16:48:44 Ball/Collet#3 Hit the Sleeve 2756 3198 246.5 17.9 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 9 16:49:32 Start Resume Pad Manually 3294 3210 261.2 23.3 0.0 10 16:49:39 Stage at Perfs: Drop Collet#3 3339 3227 264.3 29.3 0.0 11 16:49:46 Stage at Perfs: PAD st3 3155 3211 267.9 32.9 0.0 12 16:50:34 Start 1.0 PPA Manually 3115 3221 298.1 40.7 0.0 13 16:50:34 Started Pumping Prop 3115 3221 298.1 40.7 0.0 14 16:54:53 Stage at Perfs: Slow For Seat 3010 3247 471.1 40.2 1.0 15 16:55:04 Start 2.0 PPA Automatically 2988 3251 478.5 40.1 1.0 16 16:56:06 Stage at Perfs: Resume Pad 2960 3252 519.8 40.1 2.0 17 16:57:01 Stage at Perfs: 1.0 PPA 2977 3259 556.5 40.0 2.0 18 17:00:04 Start 4.0 PPA Automatically 3024 3268 678.7 40.0 2.0 19 17:01:32 Stage at Perfs: 2.0 PPA 3044 3236 737.1 40.1 4.1 20 17:05:41 Start 6.0 PPA Automatically 3183 3231 903.2 40.2 4.1 21 17:06:32 Stage at Perfs: 4.0 PPA 3317 3241 937.0 40.1 6.0 22 17:08:58 Ball/Collet#4 is loaded to Ball Launcher 3435 3210 1034.7 40.3 5.6 23 17:11:18 Start 8.0 PPA Automatically 3617 3216 1128.2 39.9 5.9 24 17:12:08 Stage at Perfs: 6.0 PPA 3744 3219 1161.3 39.5 7.9 25 17:16:57 Start 10.0 PPA Automatically 4757 3257 1353.6 40.9 8.0 26 17:17:46 Stage at Perfs: 8.0 PPA 4822 3262 1386.5 39.6 10.0 27 17:21:19 Start 12.0 PPA Automatically 4844 3257 1528.2 39.6 9.9 28 17:23:25 Stage at Perfs: 10.0 PPA 5220 3260 1611.8 39.6 11.8 29 17:26:01 Start Clear Lines & Spacer Manually 5575 3272 1716.1 41.0 0.1 30 17:26:03 Stopped Pumping Prop 5556 3268 1717.5 41.3 0.1 31 17:26:52 Start Drop Collet#4 Manually 5110 3261 1750.6 39.8 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Stage 4 Once the Collet/Ball#4 hit the sleeve the pressure transition from Stage 3 to 4 was typical. The treatingpressure on PAD was around 3,000psi and fell to 2,860 psi while pumping 1-3PPA Scour CarboLite 40/70. When 1-3PPA Scour CarboLite 40/70 started going into formation the pressure increased to around 3,015 psi and slowly fell to about 2,870 psi when 1PPA 16/20 CSG-IV was going into the formation. Then pressure was gradually increasing from 3,870 to 6,020 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#5 to seat. After the Collet/Ball#5 shifted the sleeve MiniFrac was pumped followed by hard shutdown with an ISIP of 790 psi. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #4 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,195 3,034 2,326 Bottomhole Pressure 3,028 3,893 3,133 Summary of Stage 4 Total Proppant Pumped (lb) 258,944 Max pumping Rate (bpm) 41.4 Total Proppant in Formation (lb) 258,944 Average Pumping Rate (bpm) 37.5 CarboLite 40/70 (lb) per Load Tickets 17,600 Maximum Treating Pressure (psi) 6,009 CarboLite 16/20 (lb) per Load Tickets 231,690 Average Treating Pressure (psi) 3,798 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)9,654 Average Water Temperature (F) 98.6 Total Slurry Pumped (bbl) 2,337.3 Average Viscosity (cP) 19.1 YF125ST Pumped (bbl) 1,634.4 WF125 Pumped (bbl) 443.5 17:29:23 17:37:43 17:46:03 17:54:23 18:02:43 18:11:03 18:19:23 18:27:43 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 4 09-05-2024 0 Collet/Ball#4 hit the sleeve Drop Rate for Ball/Collet#4 Glitch Collet/Ball#5 hit the sleeve Close WellDrop Rate for Ball/Collet#5 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st4 205.0 40.1 5.1 YF125ST 8621 0.0 0.0 0 2 Slow For Seat 49.2 18.9 2.6 YF125ST 2062 0.0 0.0 0 3 1.0 PPA 60.0 38.5 1.5 YF125ST 2413 CarboLite 40/70 1.0 0.9 2434 4 3.0 PPA 147.8 40.1 3.7 YF125ST 5593 CarboLite 40/70 3.1 2.5 15163 5 Resume Pad 50.0 40.2 1.2 YF125ST 2100 CarboLite 40/70 0.2 0.0 3 6 1.0 PPA 180.0 39.9 4.5 YF125ST 7258 16/20 CSG-IV 1.0 0.9 7111 7 2.0 PPA 205.0 39.9 5.1 YF125ST 7919 16/20 CSG-IV 2.1 2.0 16328 8 4.0 PPA 225.6 39.8 5.7 YF125ST 8062 16/20 CSG-IV 4.1 3.9 33376 9 6.0 PPA 225.4 39.9 5.7 YF125ST 7505 16/20 CSG-IV 6.1 5.9 46294 10 8.0 PPA 225.1 39.9 5.7 YF125ST 7000 16/20 CSG-IV 8.1 7.9 58015 11 10.0 PPA 189.7 39.7 4.8 YF125ST 5536 16/20 CSG-IV 10.2 9.9 57455 12 12.0 PPA 70.3 39.8 1.8 YF125ST 1999 16/20 CSG-IV 12.2 11.0 22730 13 Clear Lines & Spacer 33.3 40.9 0.8 YF125ST 1400 16/20 CSG-IV 2.1 0.0 35 14 Drop Collet#5 3.0 39.7 0.1 YF125ST 126 0.0 0.0 0 15 XL Flush 25.0 40.0 0.6 YF125ST 1050 0.0 0.0 0 16 WF Flush 170.0 39.2 4.3 WF125 7148 0.0 0.0 0 17 Slow For Seat 41.7 19.1 2.3 WF125 1759 0.0 0.0 0 18 MiniFrac 231.2 38.7 6.1 WF125 9721 0.0 0.0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st4 40.1 40.5 4277 5311 1457 2 Slow For Seat 18.9 26.7 2327 3302 1577 3 1.0 PPA 38.5 40.3 3030 3302 2908 4 3.0 PPA 40.1 40.4 2912 2993 2886 5 Resume Pad 40.2 40.5 2914 2979 2877 6 1.0 PPA 39.9 40.2 2999 3031 2925 7 2.0 PPA 39.9 40.2 2894 2924 2881 8 4.0 PPA 39.8 40.0 2924 3024 2878 9 6.0 PPA 39.9 40.4 3342 3709 3025 10 8.0 PPA 39.9 40.5 4242 4712 3709 11 10.0 PPA 39.7 40.2 5205 5637 4712 12 12.0 PPA 39.8 40.4 5807 5991 5637 13 Clear Lines & Spacer 40.9 41.4 5742 6009 5395 14 Drop Collet#5 39.7 39.7 5400 5407 5395 15 XL Flush 40.0 40.2 5476 5612 5357 16 WF Flush 39.2 39.5 4022 4928 1598 17 Slow For Seat 19.1 32.1 1868 2562 1485 18 MiniFrac 38.7 40.6 2984 3131 443 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 17:26:57 Start PAD st4 Automatically 5238 3268 0.0 39.5 0.0 2 17:26:57 Start Propped Frac Automatically 5238 3268 0.0 39.5 0.0 3 17:26:57 Start Stage4 Automatically 5238 3268 0.0 39.5 0.0 4 17:27:46 Stage at Perfs: 12.0 PPA 4946 3264 32.6 40.0 0.0 5 17:32:06 Start Slow For Seat Automatically 2080 3167 205.0 21.9 0.0 6 17:32:55 Stage at Perfs: Clear Lines & Spacer 2186 3175 220.2 18.3 0.0 7 17:33:45 Ball/Collet#4 Hit the Sleeve 3140 3227 235.4 18.1 0.0 8 17:34:26 Resume PAD 2823 3195 247.8 19.2 0.0 9 17:34:41 Start 1.0 PPA Manually 3143 3185 253.9 30.6 0.0 10 17:34:41 Started Pumping Prop 3143 3185 253.9 30.6 0.0 11 17:34:43 Stage at Perfs: Drop Collet#4 3213 3187 254.9 32.0 0.0 12 17:34:49 Stage at Perfs: PAD st4 3278 3217 258.3 35.0 1.0 13 17:36:14 Start 3.0 PPA Automatically 2914 3200 314.0 40.0 0.8 14 17:39:45 Stage at Perfs: Slow For Seat 2897 3206 455.0 40.3 1.0 15 17:39:55 Start Resume Pad Manually 2882 3202 461.7 40.4 0.0 16 17:39:57 Stopped Pumping Prop 2886 3204 463.0 40.6 0.0 17 17:40:58 Stage at Perfs: 3.0 PPA 2979 3207 503.9 40.0 0.0 18 17:41:10 Start 1.0 PPA Automatically 2980 3207 511.9 40.0 0.0 19 17:41:15 Started Pumping Prop 3004 3208 515.2 39.9 0.0 20 17:42:29 Stage at Perfs: Resume Pad 3028 3216 564.1 40.0 1.0 21 17:45:40 Start 2.0 PPA Manually 2915 3215 691.7 40.1 1.0 22 17:46:10 Stage at Perfs: 1.0 PPA 2909 3222 711.7 40.1 2.0 23 17:47:26 Stage at Perfs: 2.0 PPA 2902 3218 762.1 40.0 2.0 24 17:50:48 Start 4.0 PPA Manually 2888 3219 896.7 39.9 2.0 25 17:51:56 Stage at Perfs: 4.0 PPA 2870 3220 941.7 39.7 4.0 26 17:56:28 Start 6.0 PPA Manually 3034 3214 1122.3 40.0 4.0 27 17:57:05 Stage at Perfs: 6.0 PPA 3106 3215 1146.8 39.5 5.9 28 18:02:07 Start 8.0 PPA Manually 3721 3225 1347.7 40.3 6.0 29 18:02:44 Stage at Perfs: 8.0 PPA 3806 3231 1372.3 39.6 7.9 30 18:07:46 Start 10.0 PPA Manually 4728 3258 1572.8 39.9 8.1 31 18:08:01 Ball/Collet#5 is loaded to Ball Launcher 4769 3257 1582.8 39.8 9.9 32 18:08:24 Stage at Perfs: 10.0 PPA 4831 3263 1598.0 39.8 10.0 33 18:12:33 Start 12.0 PPA Manually 5641 3291 1762.5 39.9 10.0 34 18:14:04 Stage at Perfs: 12.0 PPA 5963 3196 1822.8 39.8 12.1 35 18:14:19 Start Clear Lines & Spacer Manually 6009 3196 1832.8 41.1 0.6 36 18:14:21 Stopped Pumping Prop 6032 3197 1834.2 41.3 0.3 37 18:15:08 Start Drop Collet#5 Manually 5395 3179 1866.1 39.7 0.0 38 18:15:13 Start XL Flush Automatically 5510 3190 1869.5 39.7 0.0 39 18:15:50 Start WF Flush Automatically 5319 3191 1894.2 40.2 0.0 40 18:18:48 Stage at Perfs: Clear Lines & Spacer 4013 3165 2012.8 40.2 0.0 41 18:20:07 Start Slow For Seat Automatically 1485 3075 2064.5 26.3 0.0 42 18:21:04 Stage at Perfs: Drop Collet#5 1759 3072 2082.6 17.7 0.0 43 18:22:22 Start MiniFrac Manually 1918 3074 2105.8 17.9 0.0 44 18:22:49 Stage at Perfs: XL Flush 2783 3100 2116.3 31.8 0.0 45 18:22:55 Stage at Perfs: WF Flush 2832 3093 2119.7 34.1 0.0 46 18:23:34 Stage at Perfs: Slow For Seat 3060 3101 2144.4 40.7 0.0 47 18:27:49 Stage at Perfs: MiniFrac 3038 3093 2314.6 40.0 0.0 48 18:28:29 Stopped Pumping 955 3078 2337.0 0.0 0.0 Client: Santos Well: NDB-051, Stg1-4 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 49 18:34:50 Close Well 746 59 2337.0 0.0 0.0 50 18:36:01 Fanning Out Pumps LR will pump Freeze Protect later 215 70 2337.0 5.4 0.0 FracCAT Treatment Report Well : NDB-051, Stages 5-7 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 7, 2024 Prepared by Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure (All Zones) Initial Wellhead Pressure (psi) 264 Initial BHP at Gauge (psi) 1,878 Final Surface ISIP (psi) 823 Final ISIP at Gauge (psi) 2,627 Surface Shut in Pressure(psi) 3,778 BH Shut in Pressure (psi) 3,937 Maximum Treating Pressure (psi) 6,255 BH Gauge at 11,148 ft MD, 4,039 ft TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 6,293.3 Total Proppant Pumped per Load Tickets(lb) 826,947 Total YF125ST Past Wellhead (bbl) 4,731.8 Total Proppant in Formation (lb) 826,947 Total WF125 Past Wellhead (bbl) 728.8 Total S522 - 16/20 CarboLite per Load Tickets (lb) 724,905 Total Freeze Protect Past Wellhead (bbl) Pumped by LR Total S522 - 40/70 CarboLite per Load Tickets (lb) 46,578 Total 4% S901 ScaleGUARD IV per Load Tickets (lb) 30,204 Total S522 - 12/18 CarboLite per Load Tickets (lb) 25,260 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal)218 217.4 M275 (lb) 102 101.8 J450 (gal)134 133.7 J753 (gal) 13.6 13.55 J580 (lb)6,700 6,684.6 J475 (lb) 1,375 1,371.2 J532 (gal)489 489 J134 (lb) 0 0 J511 (lb)380 380 D206 (gal) 1.0 1.0 M002 (lb) 0.5 0.41 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: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Summary On September 7th,2024, SLB performed a hydraulic fracturing treatment on Stages 5-7 of NBD-051.The design called for the completion of stages 5-7, with a total of 787,475lbs of proppant in 6,233 bbl of slurry. In the end of the Stage 7 there was a hard shutdown with ISIP = 823 psi and pressure decline was monitored for 60 min. A total of 826,947 pounds of proppant was pumped at surface and 826,947 was placed into formation in 6,293.3 bbl of slurry. Stages 5 and 6 consisted of a PAD, 1-3PPA Scour steps of 40/70 CarboLite and 7 proppant steps from 1-12 PPA of 16/20 CSG-IV.Stage 7 consisted of a PAD, 1-3PPA Scour steps of 40/70 CarboLite,6 proppant steps from 1-10 PPA of 16/20 CSG-IV and 1 proppant step 10 PPA of 12/18 CarboLite. Pump trips were staggered from 7,600 to 8,100 psi. The GORV was set 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. Summary of Stages 5-7 Material Actual Design Slurry Volume (bbl)6,293 6,233 Clean Fluid Volume(bbl) 5,461 5,353 Proppant (lb) per Load Tickets 826,947 787,475 10:33:31 10:53:31 11:13:31 11:33:31 11:53:31 12:13:31 12:33:31 12:53:31 13:13:31 13:33:31 13:53:31 14:13:31 14:33:31 14:53:31 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 0 2 4 6 8 10 12 14 16 18 20 22 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stg 5-7 09-07-2024 Pump Ball to Seat 0 Stage 5 Stage 6 Stage 7Pump Check Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Pump Ball to Seat,Pump Check The Ball was seated to Collet#5 successfully, Stage Completion Representative noted pressure change. Then the Pump check was performed after which moved to stage 5. A summary of the Stage below: Summary of Pump Ball to Seat,Pump Check Total Slurry Pumped (bbl) 285.0 Max pumping Rate (bpm) 39.1 WF125 Pumped (bbl) 223.5 Average Pumping Rate (bpm) 16.8 YF125ST Pumped (bbl) 61.5 Maximum Treating Pressure (psi) 3,350 Average Water Temperature (F)78.8 Average Treating Pressure (psi) 1,906 Average Viscosity (cP)19.4 As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Ball to Seat 223.5 4.2 53.3 WF125 9389 0.0 0.0 0.0 2 Pump Check 61.5 29.3 2.4 YF125ST 2582 0.0 0.0 0.0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Ball to Seat 4.2 11.1 1023 1202 501 2 Pump Check 29.3 39.1 2789 3350 1017 10:33:31 10:41:51 10:50:11 10:58:31 11:06:51 11:15:11 11:23:31 11:31:51 11:40:11 11:48:31 11:56:51 12:05:11 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Pump Ball to Seat, Pump Check 09-07-2024 Ball hit the Collet#5 Open Well Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 7:27:16 Priming Pumps -1 0 0.0 4.5 0.0 2 7:50:34 Low Pressure Test 534 4 0.0 0.0 0.0 3 8:00:49 Mid Pressure Test 5126 4 0.0 0.0 0.0 4 8:08:15 High Pressure Test 9488 4 0.0 0.0 0.0 5 8:19:11 Good Test 548 4 0.0 0.0 0.0 6 8:19:22 Mixing 25# Gel 549 4 0.0 0.0 0.0 7 10:23:30 Safety meeting finished 344 2908 0.0 0.0 0.0 8 10:23:44 Still ongoing Lab testing 342 2908 0.0 0.0 0.0 9 10:52:52 Open Well 264 2884 0.0 0.0 0.0 10 10:54:37 Loaded Ball to the Ball Launcher 265 2884 0.0 0.0 0.0 11 10:57:56 Launched Ball 397 2888 0.0 0.0 0.0 12 11:08:57 Radio Check 286 2878 0.0 0.0 0.0 13 11:09:11 Start Ball to Seat Automatically 375 2879 0.0 0.0 0.0 14 11:09:11 Start Propped Frac Automatically 375 2879 0.0 0.0 0.0 15 11:09:11 Start Ball to seat Automatically 375 2879 0.0 0.0 0.0 16 11:09:18 Started Pumping 467 2882 0.0 2.2 0.0 17 12:02:01 Ball seated 1012 3265 220.0 4.2 0.0 18 12:02:33 Start Pump Check Manually 1224 3272 223.7 10.4 0.0 19 12:03:59 Stage at Perfs: Ball to Seat 2867 3270 250.7 30.6 0.0 20 12:04:39 XL sample is good 3302 3283 274.6 38.6 0.0 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Stage 5 The average treating pressure on the PAD was around 3,460 psi and fell to 3,120 psi when 1-3PPA Scour 40/70 CarboLite and 1PPA 16/20 SCG-IV were passing through the formation. The treating pressure then was gradually increasing from 3,120 to 6,220 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#6 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #5 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,761 2,917 1,876 Bottomhole Pressure 2,988 3,815 3,119 Summary of Stage 5 Total Proppant Pumped (lb) 270,892 Max pumping Rate (bpm) 41.9 Total Proppant in Formation (lb) 270,892 Average Pumping Rate (bpm) 40.1 CarboLite 40/70 (lb) per Load Tickets 16,042 Maximum Treating Pressure (psi) 6,255 CarboLite 16/20 (lb) per Load Tickets 244,656 Average Treating Pressure (psi) 4,201 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)10,194 Average Water Temperature (F) 80.3 Total Slurry Pumped (bbl) 1,788.5 Average Viscosity (cP) 18.4 YF125ST Pumped (bbl) 1,515.6 WF125 Pumped (bbl) 0.0 12:01:10 12:06:10 12:11:10 12:16:10 12:21:10 12:26:10 12:31:10 12:36:10 12:41:10 12:46:10 12:51:10 12:56:10 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 5 09-07-2024 000000000 Collet/Ball#6 hit the sleeve Drop Rate for Ball/Collet#6 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st5 250 40.1 6.2 YF125ST 10500 0 0 0 2 1.0 PPA Scour 60 40 1.5 YF125ST 2430 CarboLite 40/70 1 0.8 2129 3 3.0 PPA Scour 130.7 40.1 3.3 YF125ST 4903 CarboLite 40/70 3.1 2.7 13890 4 Resume Pad 50 40.2 1.2 YF125ST 2099 CarboLite 40/70 1.3 0 23 5 1.0 PPA 150 39.9 3.8 YF125ST 6046 16/20 CSG-IV 1 0.9 5977 6 2.0 PPA 175 40 4.4 YF125ST 6763 16/20 CSG-IV 2.1 2 13839 7 4.0 PPA 190 40 4.8 YF125ST 6798 16/20 CSG-IV 4.1 3.9 27872 8 6.0 PPA 190 39.9 4.8 YF125ST 6320 16/20 CSG-IV 6.1 5.9 39179 9 8.0 PPA 190 39.9 4.8 YF125ST 5904 16/20 CSG-IV 8.2 7.9 49034 10 10.0 PPA 190 39.8 4.8 YF125ST 5545 16/20 CSG-IV 10.1 9.9 57509 11 12.0 PPA 182.4 39.9 4.6 YF125ST 5071 16/20 CSG-IV 12.2 11.6 61375 12 Clear Lines & Spacer 27.4 41.3 0.7 YF125ST 1151 16/20 CSG-IV 3 0.1 65 13 Drop Collet#6 3 39.8 0.1 YF125ST 126 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st5 40.1 40.2 3462 3575 3322 2 1.0 PPA Scour 40.0 40.1 3512 3553 3464 3 3.0 PPA Scour 40.1 40.2 3421 3462 3375 4 Resume Pad 40.2 40.4 3422 3476 3361 5 1.0 PPA 39.9 40.2 3411 3483 3332 6 2.0 PPA 40.0 40.1 3213 3331 3128 7 4.0 PPA 40.0 40.1 3217 3311 3133 8 6.0 PPA 39.9 40.4 3668 3990 3315 9 8.0 PPA 39.9 40.5 4478 4858 3986 10 10.0 PPA 39.8 40.3 5383 5729 4865 11 12.0 PPA 39.9 40.4 6014 6230 5732 12 Clear Lines & Spacer 41.3 41.9 5928 6255 5486 13 Drop Collet#6 39.8 39.8 5489 5492 5486 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 12:04:56 Start PAD st5 Manually 3326 3299 285.6 39.5 0.0 2 12:04:56 Start Propped Frac Manually 3326 3299 285.6 39.5 0.0 3 12:04:56 Start Stage5 Automatically 3326 3299 285.6 39.5 0.0 4 12:09:39 Stage at Perfs: Pump Check 3527 3302 188.9 40.0 0.0 5 12:11:11 Stage at Perfs: PAD st5 3539 3269 250.4 40.1 0.0 6 12:11:11 Start 1.0 PPA Scour Automatically 3539 3269 250.4 40.1 0.0 7 12:11:11 Started Pumping Prop 3539 3269 250.4 40.1 0.0 8 12:12:41 Start 3.0 PPA Scour Automatically 3460 3331 310.5 40.0 1.0 9 12:15:56 Start Resume Pad Manually 3366 3263 440.7 40.2 0.4 10 12:15:58 Stopped Pumping Prop 3343 3262 442.0 40.2 0.2 11 12:17:11 Stage at Perfs: 1.0 PPA 3479 3306 490.9 40.3 0.0 12 12:17:11 Start 1.0 PPA Automatically 3479 3306 490.9 40.3 0.0 13 12:17:15 Started Pumping Prop 3480 3308 493.6 40.2 0.0 14 12:18:41 Stage at Perfs: 3.0 PPA 3427 3244 550.8 39.9 0.9 15 12:20:57 Start 2.0 PPA Automatically 3319 3307 641.3 39.9 1.0 16 12:21:02 WF sample is good 3320 3309 644.6 39.9 1.0 17 12:21:57 Stage at Perfs: Resume Pad 3228 3333 681.2 40.0 2.0 18 12:22:24 Ball/Collet#6 is loaded to Ball Launcher 3225 3345 699.2 39.8 2.0 19 12:23:12 Stage at Perfs: 1.0 PPA 3196 3362 731.2 40.0 1.9 20 12:25:19 Start 4.0 PPA Automatically 3134 3230 815.8 39.9 2.0 21 12:26:58 Stage at Perfs: 2.0 PPA 3182 3266 881.7 40.1 3.9 22 12:30:04 Start 6.0 PPA Automatically 3316 3321 1005.8 40.1 4.0 23 12:31:20 Stage at Perfs: 4.0 PPA 3525 3345 1056.2 39.8 6.1 24 12:34:50 Start 8.0 PPA Automatically 3984 3211 1196.1 40.3 6.1 25 12:36:06 Stage at Perfs: 6.0 PPA 4282 3238 1246.5 39.4 8.1 26 12:39:36 Start 10.0 PPA Automatically 4869 3312 1386.1 40.0 8.0 27 12:40:52 Stage at Perfs: 8.0 PPA 5265 3306 1436.4 39.3 10.1 28 12:44:22 Start 12.0 PPA Automatically 5744 3185 1575.8 40.0 9.9 29 12:45:39 Stage at Perfs: 10.0 PPA 5900 3214 1626.9 39.4 11.8 30 12:48:56 Start Clear Lines & Spacer Manually 6270 3273 1757.9 41.6 0.5 31 12:49:02 Stopped Pumping Prop 6206 3278 1762.1 42.1 0.2 32 12:49:36 Start Drop Collet#6 Manually 5492 3272 1785.4 39.7 0.0 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Stage 6 Once the Collet/Ball#6hit the sleeve the pressure transition from Stage 5to 6 was typical. The average treating pressure on PAD was around 3,080 psi increased to around 3,030 psi while 1 PPA Scour was passing into formation, then it decreased to 2,880 psi until 2 PPA 16/20 CarboLite started going into the formation, since then the treating pressure was gradually increasing from 2,880 to 5,975 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#7 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #6 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,100 2,606 2,329 Bottomhole Pressure 2,954 3,281 3,175 Summary of Stage 6 Total Proppant Pumped (lb) 301,873 Max pumping Rate (bpm) 41.5 Total Proppant in Formation (lb) 301,873 Average Pumping Rate (bpm) 37.9 CarboLite 40/70 (lb) per Load Tickets 18,113 Maximum Treating Pressure (psi) 5,975 CarboLite 16/20 (lb) per Load Tickets 272,410 Average Treating Pressure (psi) 3,736 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)11,350 Average Water Temperature (F) 85.1 Total Slurry Pumped (bbl) 1,970.8 Average Viscosity (cP) 19.3 YF125ST Pumped (bbl) 1,666.6 WF125 Pumped (bbl) 0.0 12:53:19 12:58:19 13:03:19 13:08:19 13:13:19 13:18:19 13:23:19 13:28:19 13:33:19 13:38:19 13:43:19 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 6 09-07-2024 Drop Rate for Ball/Collet#6 Collet/Ball#6 hit the sleeve Collet/Ball#7 hit the sleeve Drop Rate for Ball/Collet#7 0 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st6 187 40.2 4.7 YF125ST 7856 0 0 0 2 Slow For Seat 39.1 20.8 2.1 YF125ST 1642 0 0 0 3 Resume Pad 23.3 28.3 0.8 YF125ST 975 0 0 0 4 1PPA Scour 60 39.9 1.5 YF125ST 2427 CarboLite 40/70 1 0.8 2151 5 3PPA Scour 144.3 39.9 3.6 YF125ST 5388 CarboLite 40/70 3.2 2.8 15929 6 Resume Pad 50 40 1.3 YF125ST 2099 CarboLite 40/70 1.5 0 33 7 1.0 PPA 180 39.9 4.5 YF125ST 7267 16/20 CSG-IV 1 0.9 6896 8 2.0 PPA 200 40 5 YF125ST 7725 16/20 CSG-IV 2.1 2 15916 9 4.0 PPA 220 39.8 5.5 YF125ST 7862 16/20 CSG-IV 4.1 3.9 32514 10 6.0 PPA 220 39.8 5.5 YF125ST 7312 16/20 CSG-IV 6.1 5.9 45524 11 8.0 PPA 220 39.8 5.5 YF125ST 6832 16/20 CSG-IV 8.1 7.9 56859 12 10.0 PPA 200 39.8 5 YF125ST 5821 16/20 CSG-IV 10.2 10 60913 13 12.0 PPA 193.1 39.8 4.8 YF125ST 5364 16/20 CSG-IV 12.2 11.6 65070 14 Clear Lines & Spacer 31 40.6 0.8 YF125ST 1303 16/20 CSG-IV 4.8 0 68 15 Drop Collet#7 3 39.6 0.1 YF125ST 126 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st6 40.2 40.5 4609 5917 3274 2 Slow For Seat 20.8 40.1 2060 2816 1556 3 Resume Pad 28.3 37.6 2901 3097 2302 4 1PPA Scour 39.9 40.3 2937 3074 2900 5 3PPA Scour 39.9 40.0 2934 2980 2904 6 Resume Pad 40.0 40.3 2962 3031 2905 7 1.0 PPA 39.9 40.1 2981 3035 2882 8 2.0 PPA 40.0 40.1 2876 2903 2860 9 4.0 PPA 39.8 40.1 2956 3085 2876 10 6.0 PPA 39.8 40.1 3272 3488 3087 11 8.0 PPA 39.8 40.2 4039 4535 3491 12 10.0 PPA 39.8 40.5 5082 5463 4538 13 12.0 PPA 39.8 41.5 5736 5975 5471 14 Clear Lines & Spacer 40.6 41.5 5433 5822 5214 15 Drop Collet#7 39.6 39.7 5257 5298 5221 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 12:49:41 Start PAD st6 Automatically 5647 3274 0.0 39.7 0.0 2 12:49:41 Start Propped Frac Automatically 5647 3274 0.0 39.7 0.0 3 12:49:41 Start Stage6 Automatically 5647 3274 0.0 39.7 0.0 4 12:50:23 Stage at Perfs: 12.0 PPA 5387 3213 28.0 40.5 0.0 5 12:54:20 Start Slow For Seat Automatically 1556 3121 186.7 36.0 0.0 7 12:55:30 Stage at Perfs: Clear Lines & Spacer 2086 3154 209.6 17.9 0.0 8 12:56:03 Ball/Collet#6 Hit the Sleeve 2434 3181 219.5 17.8 0.0 9 12:56:23 Start Resume Pad Manually 2289 3172 225.5 17.9 0.0 10 12:56:53 Stage at Perfs: Drop Collet#6 3101 3190 237.2 31.5 0.0 11 12:56:59 Stage at Perfs: PAD st6 3153 3193 240.5 34.1 0.0 12 12:57:13 Start 1PPA Scour Manually 3086 3200 249.1 39.0 0.0 13 12:57:13 Started Pumping Prop 3086 3200 249.1 39.0 0.0 14 12:58:44 Start 3PPA Scour Automatically 2962 3231 309.7 40.0 1.0 15 13:01:29 Stage at Perfs: Slow For Seat 2927 3206 419.4 39.9 3.0 16 13:02:20 Start Resume Pad Manually 2920 3227 453.3 40.2 0.6 17 13:02:22 Stopped Pumping Prop 2917 3224 454.7 40.3 0.4 18 13:02:27 Stage at Perfs: Resume Pad 2916 3226 458.0 40.2 0.0 19 13:03:02 Stage at Perfs: 1PPA Scour 3008 3235 481.4 39.9 0.0 20 13:03:36 Start 1.0 PPA Automatically 3020 3246 503.9 39.6 0.0 21 13:03:53 Started Pumping Prop 3026 3250 515.1 39.6 0.0 22 13:04:34 Stage at Perfs: 3PPA Scour 3046 3265 542.0 39.6 0.9 23 13:08:08 Start 2.0 PPA Automatically 2896 3248 684.6 40.1 1.0 24 13:08:11 Stage at Perfs: Resume Pad 2874 3244 686.6 40.1 1.0 25 13:09:26 Stage at Perfs: 1.0 PPA 2874 3264 736.6 40.1 2.0 26 13:13:06 Start 4.0 PPA Automatically 2878 3213 883.4 40.1 2.0 27 13:13:57 Stage at Perfs: 2.0 PPA 2896 3224 917.2 39.8 4.0 28 13:18:38 Start 6.0 PPA Automatically 3105 3258 1103.7 39.8 4.0 29 13:18:56 Stage at Perfs: 4.0 PPA 3133 3263 1115.6 39.7 5.9 30 13:24:10 Start 8.0 PPA Automatically 3500 3294 1323.6 39.7 6.0 31 13:24:29 Stage at Perfs: 6.0 PPA 3515 3297 1336.2 39.9 7.9 32 13:29:41 Start 10.0 PPA Automatically 4549 3273 1543.3 39.9 8.1 33 13:30:00 Stage at Perfs: 8.0 PPA 4582 3277 1555.8 39.5 10.0 34 13:34:43 Start 12.0 PPA Automatically 5491 3220 1743.6 40.3 10.0 35 13:35:31 Stage at Perfs: 10.0 PPA 5552 3235 1775.5 40.2 12.0 36 13:39:33 Start Clear Lines & Spacer Manually 5745 3284 1936.3 41.5 0.1 37 13:39:38 Stopped Pumping Prop 5650 3285 1939.7 41.2 -0.2 38 13:40:19 Start Drop Collet#7 Manually 5300 3270 1967.3 39.6 0.0 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Stage 7 Once the Collet/Ball#7hit the sleeve the pressure transition from Stage 6to 7 was typical. The average treating pressure on PAD was around 3,040 psi and slowly fell to about 2,730 psi when 1PPA 16/20 CSG-IV started going into the formation, since then pressure was gradually increasing from 2,960 to 6,290 psi. Slurry rate remained steady at 40bpm until the 10PPA 12/18 CarboLite from that point on, the pumps starved / cavitated due to very dense slurry, which consisting of larger-sized and high-concentration proppant. When rate had to be slowed down for the Collet/Ball#8 to seat, the regular procedure of dropping rate as soon as possible was followed. However, due to pump cavitation rate dropped more than desired. Pump operator got the slurry rate at18-19bpm 2bbls ahead of Collet/Ball#8 mating the seat. Due to the pressure fluctuation on the surface caused by cavitation, there was no clear sign at surface that Collet/Ball#8 been seated. At 5,965 bbl count (5bbls after collet was supposed to land) BH Pressure increased from 2,910 psi to 3,128 psi. The decision was to shut down and review BH Gauge data. Pumping was restarted, and step by step increase the rate to planned 40bpm. After PCM was emptied it followed by hard shutdown with an ISIP of 823 psi. 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 2,168 3,151 2,255 Bottomhole Pressure 2,991 3,695 3,078 Summary of Stage 7 Total Proppant Pumped (lb) 254,182 Max pumping Rate (bpm) 40.6 Total Proppant in Formation (lb) 254,182 Average Pumping Rate (bpm) 36.8 CarboLite 40/70 (lb) per Load Tickets 12,423 Maximum Treating Pressure (psi) 5,686 CarboLite 16/20 (lb) per Load Tickets 207,839 Average Treating Pressure (psi) 3,505 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)8,660 Average Water Temperature (F) 78.8 CarboLite 12/18 (lb) per Load Tickets 25,260 Average Viscosity (cP) 19.4 Total Slurry Pumped (bbl) 2,249.0 YF125ST Pumped (bbl) 1,488.1 WF125 Pumped (bbl) 505.3 13:45:47 13:54:07 14:02:27 14:10:47 14:19:07 14:27:27 14:35:47 14:44:07 14:52:27 15:00:47 15:09:07 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 7 09-07-2024 Drop Rate for Ball/Collet#7 Collet/Ball#7 hit the sleeve Restarted Pumping 000 Pumps starving due to 10PPA 12/18 CarboLite Flush out Pumps to open top Not clear Sleeve#8 activation Drop Rate for Ball/Collet#7 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st7 178 40.2 4.4 YF125ST 7481 0 0 0 2 Slow For Seat 54.4 20.9 2.7 YF125ST 2283 0 0 0 3 1PPA Scour 60 38.3 1.6 YF125ST 2424 CarboLite 40/70 1 0.8 2132 4 3PPA Scour 100.3 39.9 2.5 YF125ST 3781 CarboLite 40/70 3 2.6 10273 5 Resume Pad 50 40.2 1.2 YF125ST 2100 CarboLite 40/70 0.4 0 18 6 1.0 PPA 180 39.7 4.5 YF125ST 7254 16/20 CSG-IV 1.3 0.9 7212 7 3.0 PPA 200 39.9 5 YF125ST 7437 16/20 CSG-IV 3.1 2.9 22689 8 5.0 PPA 230 39.9 5.8 YF125ST 7927 16/20 CSG-IV 5.1 4.9 40925 9 7.0 PPA 230 39.8 5.8 YF125ST 7392 16/20 CSG-IV 7.1 6.9 53565 10 9.0 PPA 215 39.8 5.4 YF125ST 6467 16/20 CSG-IV 9.2 8.9 60516 11 10.0 PPA 103.9 39.8 2.6 YF125ST 3030 16/20 CSG-IV 10.2 9.9 31592 12 10.0 PPA (12/18)88.2 35.4 2.5 YF125ST 2652 CarboLite 12/18 10.4 9.2 25232 13 Clear Lines & Spacer 26.1 38.2 0.7 YF125ST 1096 CarboLite 12/18 0.5 0 28 14 Drop Collet#8 3 36.7 0.1 YF125ST 126 0 0 0 15 XL Flush 25 36.9 0.7 YF125ST 1050 0 0 0 16 WF Flush 144 38.3 3.8 WF125 6048 0 0 0 17 Slow For Seat 116.7 20.9 5.9 WF125 4901 0 0 0 18 MiniFrac 244.4 38.2 6.5 WF125 10273 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st7 40.2 40.4 4266 5686 1953 2 Slow For Seat 20.9 38.0 2300 3039 1596 3 1PPA Scour 38.3 40.1 2863 3040 2791 4 3PPA Scour 39.9 40.2 2809 2840 2778 5 Resume Pad 40.2 40.3 2844 2897 2809 6 1.0 PPA 39.7 40.1 2836 2903 2764 7 3.0 PPA 39.9 40.1 2759 2786 2730 8 5.0 PPA 39.9 40.2 2954 3125 2786 9 7.0 PPA 39.8 40.3 3451 3878 3137 10 9.0 PPA 39.8 40.4 4509 5076 3885 11 10.0 PPA 39.8 40.2 5190 5283 4785 12 10.0 PPA (12/18) 35.4 38.5 4304 4744 3872 13 Clear Lines & Spacer 38.2 39.5 4467 4813 4007 14 Drop Collet#8 36.7 36.8 4290 4413 4203 15 XL Flush 36.9 37.1 4193 4544 3924 16 WF Flush 38.3 39.9 3551 4212 2414 17 Slow For Seat 20.9 38.9 1905 2459 715 18 MiniFrac 38.2 40.6 3601 3877 566 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 13:40:24 Start PAD st7 Automatically 5454 3272 0.0 39.6 0.0 2 13:40:24 Start Propped Frac Automatically 5454 3272 0.0 39.6 0.0 3 13:40:24 Start Stage7 Automatically 5454 3272 0.0 39.6 0.0 4 13:40:32 Stage at Perfs: 12.0 PPA 5686 3290 5.3 39.7 0.0 5 13:44:50 Start SlowForSeat Automatically 1434 3198 177.8 31.4 0.0 6 13:45:52 Stage at Perfs: Lines&Spacer 2160 3211 197.6 17.8 0.0 7 13:46:18 Collet Hit#7 the Sleeve 2785 3249 205.4 18.0 0.0 8 13:47:17 Resume pad 3109 3233 223.6 24.9 0.0 9 13:47:28 Stage at Perfs: Drop Collet#7 3105 3246 228.9 31.1 0.0 10 13:47:34 Stage at Perfs: PAD st7 2943 3238 232.1 33.0 0.0 11 13:47:34 Start 1PPA Scour Manually 2943 3238 232.1 33.0 0.0 12 13:47:34 Started Pumping Prop 2943 3238 232.1 33.0 0.0 13 13:49:08 Start 3PPA Scour Automatically 2821 3234 292.5 40.1 1.0 14 13:51:38 Start Resume Pad Manually 2826 3249 392.4 40.2 0.2 15 13:51:42 Stopped Pumping Prop 2816 3250 395.1 40.2 0.0 16 13:51:51 Stage at Perfs: Slow For Seat 2821 3249 401.1 40.4 0.0 17 13:52:53 Start 1.0 PPA Automatically 2895 3253 442.7 40.1 0.0 18 13:52:58 Started Pumping Prop 2909 3253 446.0 40.1 0.0 19 13:53:12 Stage at Perfs: 3PPA Scour 2883 3255 455.4 39.8 1.3 20 13:54:44 Stage at Perfs: Resume Pad 2839 3261 515.8 39.4 1.0 21 13:57:15 Stage at Perfs: 1.0 PPA 2769 3271 615.9 39.9 1.0 22 13:57:25 Start 3.0 PPA Automatically 2757 3270 622.6 39.9 1.0 23 13:58:31 Stage at Perfs: 3.0 PPA 2739 3281 666.2 39.8 3.0 24 13:59:06 Ball/Collet#8 is loaded to Ball Launcher 2731 3280 689.5 39.9 2.9 25 14:02:26 Start 5.0 PPA Automatically 2788 3294 822.5 39.9 3.1 26 14:03:02 Stage at Perfs: 5.0 PPA 2872 3296 846.4 39.5 5.0 27 14:08:02 Stage At Perfs 3109 3317 1046.0 39.9 5.0 28 14:08:12 Start 7.0 PPA Automatically 3151 3316 1052.7 39.9 4.9 29 14:13:49 Stage At Perfs 3871 3262 1276.4 39.8 7.0 30 14:13:58 Start 9.0 PPA Automatically 3892 3263 1282.4 39.4 7.1 31 14:19:23 Start 10.0 PPA Automatically 5101 3290 1497.8 40.0 9.0 32 14:19:35 Stage at Perfs: 10.0 PPA 5134 3289 1505.8 39.7 9.9 33 14:21:59 Start 10.0 PPA Manually 4498 3274 1601.2 38.0 10.3 34 14:23:44 as soon as 12-18 pump rate dropped 5bbl/min below due to cavitation 4063 3245 1663.3 33.7 9.9 35 14:24:29 Start Clear Lines & Spacer Manually 4450 3282 1689.4 36.9 0.2 36 14:24:41 Stopped Pumping Prop 4774 3301 1697.1 39.5 0.1 37 14:25:10 Start Drop Collet#8 Manually 4589 3276 1715.6 36.6 0.0 38 14:25:15 Start XL Flush Automatically 4422 3301 1718.6 36.6 0.0 39 14:25:19 Stage at Perfs: 10.0 PPA 4709 3289 1721.0 36.7 0.0 40 14:25:56 Start WF Flush Automatically 4044 3245 1743.8 36.8 0.0 41 14:26:20 Pumps are cavitating 3967 3287 1758.6 37.0 0.0 42 14:27:54 Trying to adjust rate on pumps 3420 3221 1817.3 38.3 0.0 43 14:28:06 Stage at Perfs: Clear Lines & Spacer 3576 3227 1825.0 39.0 0.0 44 14:28:32 Slurry Rate on pumps showing 44bpm 3459 3223 1842.0 39.4 0.0 45 14:29:42 Start Slow For Seat Automatically 1341 3149 1888.1 34.7 0.0 46 14:31:02 Stage at Perfs: Drop Collet8 1877 3140 1912.7 19.1 0.0 47 14:32:07 Stopped Pumping 715 3104 1933.1 10.0 0.0 Client: Santos Well: NDB-051, Stg5-7 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 48 14:32:27 Couldn't see clear sign of sleeve activation because of cavitation 855 3130 1933.1 0.0 0.0 49 14:37:19 Close the well 816 3070 1933.1 0.0 0.0 50 14:38:28 Will flush out few pumps to bleed off tank before continue pump -6 3055 1933.1 0.0 0.0 51 14:47:51 Flushing out all pumps 70 2929 1933.1 4.4 0.0 52 14:56:01 Equalize To Well Pressure 1330 2830 1933.1 0.0 0.0 53 14:56:37 Open well 1479 2823 1933.1 2.8 0.0 54 14:58:09 Well is open 678 2803 1933.1 3.1 0.0 55 14:59:01 Started Pumping 996 2803 1933.1 3.0 0.0 56 14:59:32 Stage at Perfs: XL Flush 1883 2836 1938.8 18.4 0.0 57 14:59:42 Stage at Perfs: WF Flush 1918 2841 1942.0 19.8 0.0 58 15:00:57 Increasing rate up to 25 1893 2839 1967.2 20.2 0.0 59 15:02:26 Increasing rate up to 30 2454 2861 2001.6 25.1 0.0 60 15:02:32 Start MiniFrac Manually 2548 2867 2004.2 26.4 0.0 61 15:03:04 Increasing up to 35 bpm 2911 2878 2019.5 30.3 0.0 62 15:03:12 Increasing up to 35 bpm 3080 2888 2023.6 31.5 0.0 63 15:03:41 Coming up to 40bpm 3415 2913 2040.4 36.2 0.0 64 15:05:34 Stage at Perfs: MiniFrac 3733 2944 2111.9 39.1 0.0 65 15:08:27 Stage At Perfs 3785 2989 2227.9 40.5 0.0 66 15:09:01 Stopped Pumping 277 2865 2248.5 5.3 0.0 67 15:10:50 Close Well 798 2877 2248.5 0.0 0.0 68 15:13:06 Fanning out pump 50 2855 2248.5 5.4 0.0 69 15:34:46 Finished Fanning out pumps -7 2597 2248.5 0.0 0.0 70 15:55:40 LR will pump freeze protect later -5 2444 2248.5 0.0 0.0 71 16:46:28 LR is pumping Freeze Protect 846 2132 2248.5 0.0 0.0 72 16:52:50 LR stopped pumping 1 2025 2248.5 0.0 0.0 73 16:52:56 Close well 1 2022 2248.5 0.0 0.0 74 16:53:05 Bleeding off IA 1 2020 2248.5 0.0 0.0 FracCAT Treatment Report Well : NDB-051, Stages 8-10 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 14, 2024 Prepared by Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure (All Zones) Initial Wellhead Pressure (psi) 261 Initial BHP at Gauge (psi) 1,870 Final Surface ISIP (psi) 989 Final ISIP at Gauge (psi) 2,590 Surface Shut in Pressure(psi) 1,956 BH Shut in Pressure (psi) 2,740 Maximum Treating Pressure (psi) 6,072 BH Gauge at 11,148 ft MD, 4,039 ft TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 6,157.6 Total Proppant Pumped per Load Tickets(lb) 905,000 Total YF125ST Past Wellhead (bbl) 4,839.7 Total Proppant in Formation (lb) 899,860 Total WF125 Past Wellhead (bbl) 343.70 Total S522 - 16/20 CarboLite per Load Tickets (lb) 816,154 Total Freeze Protect Past Wellhead (bbl) 60.0 Total S522 - 40/70 CarboLite per Load Tickets (lb) 16,904 Total 4% S901 ScaleGUARD IV per Load Tickets (lb) 34,006 Total S522 - 12/18 CarboLite per Load Tickets (lb) 37,936 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal)209 209 M275 (lb) 12 11.8 J450 (gal) 112 112 J753 (gal) 28.0 24.4 J580 (lb) 5,890 5,838 J475 (lb) 1,320 1,320 J532 (gal) 542 542 J134 (lb) 4 0 J511 (lb) 445 407 D206 (gal) 1 1 M002 (lb) 0.5 0.46 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: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Summary On September 14th, 2024, SLB performed a hydraulic fracturing treatment on Stages 8-10 of NBD-051. The design called for the completion of stages 8-10, with a total of 855,989 lbs of proppant in 6,066 bbl of slurry. In the end of the Stage 10there was a hard shutdown with ISIP = 989psiand pressure decline wasmonitored for 60 min. A total of 905,000pounds of proppant was pumped at surface and 899,860 lbs was placed into formation in 6157.6 bbl of slurry. Stage 8 consisted of a PAD, 1-3PPA Scour steps of 40/70 CarboLite and 7 proppant steps from 1-12 PPA of 16/20 CSG-IV. Stage 9 consisted of a PAD and 7 proppant steps from 1-12 PPA of 16/20 CSG-IV. Stage 10 consisted of a PAD, 7 proppant steps from 1-12 PPA of 16/20 CSG-IV and 1 proppant step 12 PPA of 12/18 CarboLite. Pump trips were staggered from 7,600 to 8,100 psi. The GORV was set to 8,500 psi. The highlight of the Stage 10: 12/18 CarboLite was pumped from the surface at 12PPA and successfully placed into formation, despite pump #2 experiencing starvation during this prop step. Summary of Stages 8-10 Material Actual Design Slurry Volume (bbl)6,158 6,066 Clean Fluid Volume(bbl) 5,183 5,102 Proppant (lb) per Load Tickets 905,000 855,989 14:22:52 14:47:52 15:12:52 15:37:52 16:02:52 16:27:52 16:52:52 17:17:52 17:42:52 18:07:52 Time - hh:mm:ss 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stg 8-10 09-14-2024 Pump Ball to Seat 0 Stage 8 Stage 9 Stage 10Pump Check Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Pump Ball to Seat,Pump Check The Ball was seated to Collet#8 successfully, Stage Completion Representative noted pressure change. Then the Pump check was performed after which moved to stage 8. A summary of the Stage below: Summary of Pump Ball to Seat,Pump Check Total Slurry Pumped (bbl) 328.5 Max pumping Rate (bpm) 40.5 WF125 Pumped (bbl) 236.0 Average Pumping Rate (bpm) 24.6 YF125ST Pumped (bbl) 92.5 Maximum Treating Pressure (psi) 4,275 Average Water Temperature (F) 85.7 Average Treating Pressure (psi) 2,172 Average Viscosity (cP) 20.9 As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Ball to Seat 200 4.2 48.7 WF125 8400 0 0 0 2 Pump Check 36 33.5 4.4 WF125 1512 0 0 0 3 Pump Check 92.5 33.5 4.4 YF125ST 3885 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Ball to Seat 4.2 8.6 699 936 246 2 and 3 Pump Check 33.5 40.5 3644 4275 918 14:22:52 14:31:12 14:39:32 14:47:52 14:56:12 15:04:32 15:12:52 15:21:12 15:29:32 Time - hh:mm:ss 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Pump Ball to Seat, Pump Check 09-14-2024 0 Ball hit the Collet#8 Open Well Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 7:56:25 Primed C-Pump Skid With Diesel 1 0 0.0 29.3 0.0 2 7:56:53 Fanning Diesel Out of Treating Line 1 -0 0.0 33.3 0.0 3 8:00:44 Priming Pumps 52 2 0.0 0.0 0.0 4 8:54:45 Low Pressure Test 660 -3 0.0 0.0 0.0 5 9:01:24 Low Pressure Test 722 -3 0.0 0.0 0.0 6 9:07:03 Mid Pressure Test 4986 -3 0.0 0.0 0.0 7 9:15:19 High Pressure Test 9440 -3 0.0 0.0 0.0 8 9:21:12 Pressure Test Ok 1016 -3 0.0 0.0 0.0 9 9:21:23 Bleed off the pressure 1026 -2 0.0 0.0 0.0 10 9:21:39 Start mixing Gel 25#1027 -3 0.0 0.0 0.0 11 9:32:02 LRS Pressuring Up IA 7 -15 0.0 0.0 0.0 12 10:32:03 Mid Pressure Test 4911 2924 0.0 0.0 0.0 13 10:51:43 Pressure Test Ok 883 2915 0.0 0.0 0.0 14 13:57:52 Safety Meeting 868 2878 0.0 0.0 0.0 15 14:26:46 Open well 269 2985 0.0 0.0 0.0 16 14:28:09 Ball Loaded 258 2977 0.0 0.0 0.0 17 14:30:00 Ball Launched 385 2990 0.0 0.0 0.0 18 14:32:33 Allow Ball To Free Fall 263 2981 0.0 0.0 0.0 19 14:40:40 Start Ball to Seat Automatically 458 2998 0.0 2.0 0.0 20 14:40:40 Start Propped Frac Automatically 458 2998 0.0 2.0 0.0 21 14:40:40 Start Ball to Seat#8 Automatically 458 2998 0.0 2.0 0.0 22 14:40:44 Started Pumping 424 2972 0.0 3.0 0.0 23 15:28:43 Ball seated to sleeve #8 930 3298 196.9 4.0 0.0 24 15:29:29 Start Pump Check Automatically 918 3301 200.0 4.0 0.0 25 15:30:58 Stage at Perfs: Ball to Seat 3114 3326 224.1 27.1 0.0 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Stage 8 The average treating pressure on the PAD was around 4,110 psi and fell to 3,210 psi when 1-3PPA Scour 40/70 CarboLite and 1PPA 16/20 CSG-IV were passing through the formation. The treating pressure then was gradually increasing from 3,120 to 6,072 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#9 to seat. 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 Sleeve was shifted by CTBottomhole Pressure Summary of Stage 8 Total Proppant Pumped (lb) 302,696 Max pumping Rate (bpm) 41.0 Total Proppant in Formation (lb) 302,696 Average Pumping Rate (bpm) 39.8 CarboLite 40/70 (lb) per Load Tickets 16,904 Maximum Treating Pressure (psi) 6,072 CarboLite 16/20 (lb) per Load Tickets 274,360 Average Treating Pressure (psi) 4,423 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)11,432 Average Water Temperature (F) 91.2 Total Slurry Pumped (bbl) 1,977.3 Average Viscosity (cP) 20.9 YF125ST Pumped (bbl) 1,671.6 WF125 Pumped (bbl) 0.0 15:27:45 15:34:25 15:41:05 15:47:45 15:54:25 16:01:05 16:07:45 16:14:25 16:21:05 16:27:45 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 8 09-14-2024 0 Collet/Ball#9 hit the sleeve Drop Rate for Ball/Collet#9 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st8 250 39.9 6.3 YF125ST 10500 0 0 0 2 1.0PPA Scour 60 39.8 1.5 YF125ST 2437 CarboLite 40/70 1 0.8 1989 3 3.0PPA Scour 137.6 39.7 3.5 YF125ST 5151 CarboLite 40/70 3.1 2.8 14908 4 Resume Pad 50 40.1 1.2 YF125ST 2100 CarboLite 40/70 0.8 0 7 5 1.0 PPA 180 39.9 4.5 YF125ST 7254 16/20 CSG-IV 1 0.9 7195 6 2.0 PPA 200 39.9 5 YF125ST 7728 16/20 CSG-IV 2.1 2 15816 7 4.0 PPA 220 39.7 5.5 YF125ST 7868 16/20 CSG-IV 4.1 3.9 32276 8 6.0 PPA 220 39.8 5.5 YF125ST 7320 16/20 CSG-IV 6.1 5.9 45213 9 8.0 PPA 220 39.6 5.6 YF125ST 6835 16/20 CSG-IV 8.2 7.9 56636 10 10.0 PPA 200 39.4 5.1 YF125ST 5833 16/20 CSG-IV 10.3 9.9 60456 11 12.0 PPA 198.9 39.3 5.1 YF125ST 5473 16/20 CSG-IV 12.4 11.9 67976 12 Clear Lines & Spacer 37.8 40.4 0.9 YF125ST 1582 16/20 CSG-IV 12 0.1 224 13 Drop Collet#9 3 40.3 0.1 YF125ST 126 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st8 39.9 40.1 4110 4188 4072 2 1.0PPA Scour 39.8 40.1 4079 4117 4038 3 3.0PPA Scour 39.7 40.1 3982 4038 3805 4 Resume Pad 40.1 40.3 4032 4074 3961 5 1.0 PPA 39.9 40.1 3861 4056 3548 6 2.0 PPA 39.9 40.2 3351 3548 3213 7 4.0 PPA 39.7 40.0 3258 3340 3205 8 6.0 PPA 39.8 40.0 3663 4023 3340 9 8.0 PPA 39.6 39.8 4416 4804 4025 10 10.0 PPA 39.4 39.7 5348 5701 4805 11 12.0 PPA 39.3 39.7 5856 6005 5701 12 Clear Lines & Spacer 40.4 41.0 5803 6072 5603 13 Drop Collet#9 40.3 40.5 5734 5820 5666 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 15:33:51 Start PAD st8 Manually 4124 3290 329.1 40.0 0.0 2 15:33:51 Start Propped Frac Manually 4124 3290 329.1 40.0 0.0 3 15:33:51 Start Stage8 Automatically 4124 3290 329.1 40.0 0.0 4 15:36:14 Stage at Perfs: Pump Check 4098 3432 95.2 40.0 0.0 5 15:39:28 Stage at Perfs: PAD st8 4112 3346 224.3 39.9 0.0 6 15:40:07 Start 1.0PPA Scour Automatically 4111 3372 250.3 40.1 0.0 7 15:40:07 Started Pumping Prop 4111 3372 250.3 40.1 0.0 8 15:41:37 Start 3.0PPA Scour Automatically 4029 3426 310.1 39.8 1.0 9 15:45:05 Start Resume Pad Manually 3954 3278 447.6 40.1 0.1 10 15:45:07 Stopped Pumping Prop 3946 3284 449.0 40.0 0.0 11 15:45:31 Stage at Perfs: 1.0PPA Scour 4060 3300 465.0 40.1 0.0 12 15:46:19 Started Pumping Prop 4056 3320 497.0 40.1 0.0 13 15:46:20 Start 1.0 PPA Automatically 4037 3321 497.7 40.0 -0.1 14 15:47:01 Stage at Perfs: 3.0PPA Scour 3914 3337 524.8 39.4 1.0 15 15:50:28 Stage at Perfs: Resume Pad 3632 3241 662.4 40.1 1.0 16 15:50:51 Start 2.0 PPA Automatically 3538 3246 677.7 40.1 1.1 17 15:51:04 Ball/Collet#9 is loaded to Ball Launcher 3529 3247 686.4 40.0 1.8 18 15:51:43 Stage at Perfs: 1.0 PPA 3512 3267 712.3 39.7 2.0 19 15:55:52 Start 4.0 PPA Automatically 3226 3357 877.7 39.8 2.0 20 15:56:14 Stage at Perfs: 2.0 PPA 3218 3369 892.3 39.5 4.0 21 16:01:16 Stage at Perfs: 4.0 PPA 3339 3231 1092.1 39.9 4.0 22 16:01:25 Start 6.0 PPA Automatically 3350 3234 1098.1 39.9 3.9 23 16:06:49 Stage at Perfs: 6.0 PPA 4020 3301 1312.9 39.8 6.1 24 16:06:57 Start 8.0 PPA Automatically 4021 3302 1318.1 39.7 5.8 25 16:12:22 Stage at Perfs: 8.0 PPA 4787 3375 1532.5 39.2 8.0 26 16:12:30 Start 10.0 PPA Automatically 4836 3378 1537.7 39.3 8.1 27 16:17:35 Start 12.0 PPA Automatically 5707 3294 1737.9 39.4 10.0 28 16:17:57 Stage at Perfs: 10.0 PPA 5712 3302 1752.3 39.6 11.8 29 16:22:38 Start Clear Lines & Spacer Manually 6050 3375 1936.3 39.3 2.6 30 16:22:41 Stopped Pumping Prop 6015 3378 1938.3 40.4 0.9 31 16:23:02 Stage at Perfs: 12.0 PPA 5745 3367 1952.7 40.8 0.0 32 16:23:34 Start Drop Collet#9 Manually 5871 3393 1974.2 40.2 0.0 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Stage 9 Once the Collet/Ball#9 hit the sleeve, the pressure transition from Stage 9 to Stage 10 was unusual, instead of a pressure spike, there was a pressure drop. The average treating pressure on PAD was around 2,690 psi and increased to approximately 2,870 psi before proppant reached the formation. While 1PAA and 2 PPA were going into the formation, treating pressure decreased from 2,870 psi to 2,700 psi. Afterwards, the treating pressure gradually increased from 2,700 to 5,219 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#10 to seat. 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 2,129 1,800 1,856 Bottomhole Pressure 3,022 2,705 2,760 Summary of Stage 9 Total Proppant Pumped (lb) 281,743 Max pumping Rate (bpm) 40.4 Total Proppant in Formation (lb) 281,743 Average Pumping Rate (bpm) 37.6 CarboLite 16/20 (lb) per Load Tickets 270,473 Maximum Treating Pressure (psi) 6,007 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)11,270 Average Treating Pressure (psi) 3,716 Total Slurry Pumped (bbl) 1,762.3 Average Water Temperature (F) 93.0 YF125ST Pumped (bbl) 1,477.6 Average Viscosity (cP) 21.5 WF125 Pumped (bbl) 0.0 16:26:32 16:31:32 16:36:32 16:41:32 16:46:32 16:51:32 16:56:32 17:01:32 17:06:32 17:11:32 17:16:32 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 9 09-14-2024 Drop Rate for Ball/Collet#9 Collet/Ball#9 hit the sleeve Collet/Ball#10 hit the sleeve Drop Rate for Ball/Collet#10 0 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st9 160 40.1 4 YF125ST 6720 0 0 0 2 Slow For Seat 64.7 20.1 3.4 YF125ST 2717 0 0 0 3 Resume Pad 73.3 36.3 2.1 YF125ST 3077 0 0 0 4 1.0 PPA 180 39.9 4.5 YF125ST 7254 16/20 CSG-IV 1.1 0.9 7196 5 2.0 PPA 200 39.8 5 YF125ST 7728 16/20 CSG-IV 2.1 2 15809 6 4.0 PPA 220 39.6 5.6 YF125ST 7871 16/20 CSG-IV 4.1 3.9 32226 7 6.0 PPA 220 39.7 5.6 YF125ST 7318 16/20 CSG-IV 5.9 3 45255 8 8.0 PPA 220 39.2 5.6 YF125ST 6837 16/20 CSG-IV 8.1 7.9 56590 9 10.0 PPA 200 38.7 5.2 YF125ST 5830 16/20 CSG-IV 10.1 9.9 60531 10 12.0 PPA 187.9 38.2 4.9 YF125ST 5184 16/20 CSG-IV 12.2 11.8 64009 11 Clear Lines & Spacer 33.4 39.9 0.8 YF125ST 1396 16/20 CSG-IV 7.7 0.1 127 12 Drop Collet#10 3 40 0.1 YF125ST 126 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st9 40.1 40.2 4623 6007 3629 2 Slow For Seat 20.1 40.1 1984 3528 1656 3 Resume Pad 36.3 40.3 2694 2820 1935 4 1.0 PPA 39.9 40.1 2865 2892 2826 5 2.0 PPA 39.8 39.9 2773 2868 2735 6 4.0 PPA 39.6 39.8 2810 2957 2707 7 6.0 PPA 39.7 39.7 3563 3564 3561 8 8.0 PPA 39.2 40.0 3798 4166 3525 9 10.0 PPA 38.7 39.4 4468 4753 4158 10 12.0 PPA 38.2 38.8 4941 5143 4756 11 Clear Lines & Spacer 39.9 40.4 5102 5219 4964 12 Drop Collet#10 40.0 40.0 4967 4976 4964 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 16:23:39 Start PAD st9 Automatically 6014 3405 0.0 39.9 0.0 2 16:23:39 Start Propped Frac Automatically 6014 3405 0.0 39.9 0.0 3 16:23:39 Start Stage9 Automatically 6014 3405 0.0 39.9 0.0 4 16:27:39 Start Slow For Seat Automatically 2139 3073 160.3 39.5 0.0 5 16:28:14 Stage at Perfs: Clear Lines & Spacer 2090 3061 173.1 17.7 0.0 6 16:30:20 Stage at Perfs: Drop Collet#9 1898 3043 210.8 17.9 0.0 7 16:30:32 Stage at Perfs: PAD st9 1915 3042 214.4 17.9 0.0 8 16:31:04 Start Resume Pad Manually 1937 3041 224.0 18.0 0.0 9 16:31:19 Activated Extend Stage 2760 3058 228.8 23.0 0.0 10 16:33:09 Start 1.0 PPA Manually 2838 3071 297.6 40.1 0.0 11 16:33:09 Started Pumping Prop 2838 3071 297.6 40.1 0.0 12 16:34:52 Stage at Perfs: Slow For Seat 2891 3083 365.9 40.0 1.0 13 16:36:28 Stage at Perfs: Resume Pad 2850 3093 429.8 39.9 1.0 14 16:37:40 Start 2.0 PPA Automatically 2868 3100 477.7 39.9 1.0 15 16:38:19 Stage at Perfs: 1.0 PPA 2838 3104 503.6 39.8 2.0 16 16:42:42 Start 4.0 PPA Automatically 2745 3137 677.8 39.8 2.1 17 16:42:50 Stage at Perfs: 2.0 PPA 2743 3139 683.1 39.8 2.1 18 16:45:06 Ball/Collet#10 is loaded to Ball Launcher 2783 3157 772.5 39.8 3.9 19 16:47:54 Stage at Perfs: 4.0 PPA 2928 3183 883.6 39.7 4.1 20 16:48:16 Start 6.0 PPA Automatically 2945 3188 898.2 39.6 4.0 21 16:53:28 Stage at Perfs: 6.0 PPA 3559 3240 1103.7 39.4 6.0 22 16:53:49 Start 8.0 PPA Automatically 3571 3242 1117.5 39.7 6.0 23 16:59:04 Stage at Perfs: 8.0 PPA 4134 3208 1323.5 39.2 7.9 24 16:59:26 Start 10.0 PPA Automatically 4177 3212 1337.8 39.1 8.1 25 17:04:36 Start 12.0 PPA Automatically 4795 3250 1537.8 38.8 10.1 26 17:04:45 Stage at Perfs: 10.0 PPA 4783 3250 1543.6 38.4 10.4 27 17:09:31 Start Clear Lines & Spacer Manually 5153 3294 1725.4 38.9 2.5 28 17:09:33 Stopped Pumping Prop 5140 3296 1726.7 39.3 1.3 29 17:09:58 Stage at Perfs: 12.0 PPA 5035 3306 1743.4 40.3 0.0 30 17:10:21 Start DropCollet#10 Manually 4949 3307 1758.8 40.0 0.0 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Stage 10 Once the Collet/Ball#10 hit the sleeve,the pressure transition from Stage 9 to 10 was typical. The average treating pressure on PAD was around 2,600 psi and slowly decreased to about 2,550 psi while 1PPA 16/20 CSG-IV was going into the formation. When 2PPA began entering the formation, the pressure gradually increased from 2,550 to 4,740 psi. Slurry rate remained steady at 40bpm until the 12PPA 12/18 CarboLite was pumped. At this point, the pumps starved / cavitated due to very dense slurry, which consisted of larger-sized and high-concentration proppant. 12PPA of 12/18 CarboLite was pumped and placed into formation successfully even though the pumps were starving. At 12/18 CarboLite 12PPA step SLB used only 5 pumps (3 Triplexes and 2 Quins) at a higher gear. During the flush, when switching from WF125 to Freeze Protect, the rate was lost on Blender flowmeter due to the non-conductive fluid presented to magnetic flowmeter. Upon noticing the rate drop on the flowmeter, the backup tachometer for the pumps was used. Flush was followed by a hard shutdown with an ISIP of 989 psi. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #10 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,931 2,899 1,954 Bottomhole Pressure 2,775 3,379 2,797 Summary of Stage 10 Total Proppant Pumped (lb) 320,561 Max pumping Rate (bpm) 40.4 Total Proppant in Formation (lb) 315,421 Average Pumping Rate (bpm) 35.9 CarboLite 16/20 (lb) per Load Tickets 271,320 Maximum Treating Pressure (psi) 5,172 Total 4% S901 ScaleGUARD IV per Load Tickets (lb)11,305 Average Treating Pressure (psi) 3,239 CarboLite 12/18 (lb) per Load Tickets 37,936 Average Water Temperature (F) 94.4 Total Slurry Pumped (bbl) 2,089.5 Average Viscosity (cP) 21.7 YF125ST Pumped (bbl) 1,598.0 WF125 Pumped (bbl) 107.7 17:14:29 17:43:39 18:12:49 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Conc FracCAT* PRC Plot Santos NDB-051 Stage 10 09-14-2024 Drop Rate for Ball/Collet#10 Collet/Ball#10 hit the sleeve 0 Pumps starving due to 12PPA 12/18 CarboLite Swapped to Freeze Protect # of Pumps reduced from 6 to 5 pumps prior 12PPA 12/18prop step Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st10 151 40.1 3.8 YF125ST 6342 0 0 0 2 Slow For Seat 50.9 21.8 2.6 YF125ST 2138 0 0 0 3 Resume Pad 97.7 37.2 2.7 YF125ST 4103 0 0 0 4 1.0 PPA 200 39.7 5 YF125ST 8058 16/20 CSG-IV 1.2 1 8052 5 2.0 PPA 220 39.5 5.6 YF125ST 8500 16/20 CSG-IV 2.1 2 17420 6 4.0 PPA 240 39.4 6.1 YF125ST 8583 16/20 CSG-IV 4.1 3.9 35218 7 6.0 PPA 250 39.6 6.3 YF125ST 8313 16/20 CSG-IV 6.1 5.9 51482 8 8.0 PPA 250 39.1 6.4 YF125ST 7763 16/20 CSG-IV 8.2 7.9 64477 9 10.0 PPA 220 39 5.6 YF125ST 6414 16/20 CSG-IV 10.2 9.9 66574 10 12.0 PPA 115.5 38.7 3 YF125ST 3178 16/20 CSG-IV 12.2 11.9 39402 11 12.0 PPA 116.7 34.9 3.4 YF125ST 3308 CarboLite 12/18 12.5 11.7 37936 12 XL Flush 10 37.3 0.3 YF125ST 418 0 0 0 13 WF Flush 107.7 38.2 2.9 WF125 4522 0 0 0 14 Freeze Protect 60 17.7 3.7 FP 2520 0 0 0 Stage Pressures &Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st10 40.1 40.4 4029 5172 3037 2 Slow For Seat 21.8 40.3 1984 3022 1425 3 Resume Pad 37.2 40.1 2599 2737 2290 4 1.0 PPA 39.7 40.1 2615 2674 2573 5 2.0 PPA 39.5 39.8 2552 2578 2410 6 4.0 PPA 39.4 39.8 2619 2722 2525 7 6.0 PPA 39.6 40.1 2933 3214 2713 8 8.0 PPA 39.1 39.9 3546 3921 3020 9 10.0 PPA 39.0 39.6 4172 4521 3847 10 12.0 PPA 38.7 39.5 4596 4737 4498 11 12.0 PPA 34.9 37.6 3920 4656 3614 12 XL Flush 37.3 38.6 4229 4301 3997 13 WF Flush 38.2 39.6 3705 4301 1500 14 Freeze Protect 17.7 19.9 1843 2050 1258 Client: Santos Well: NDB-051, Stg8-10 Formation: Nanushuk District: Pikka Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 1 17:10:26 Start PAD st10 Automatically 5118 3312 0.0 40.0 0.0 2 17:10:26 Start Propped Frac Automatically 5118 3312 0.0 40.0 0.0 3 17:10:26 Start Stage10 Automatically 5118 3312 0.0 40.0 0.0 4 17:14:12 Start Slow For Seat Automatically 2864 3300 151.2 40.3 0.0 5 17:14:58 Stage at Perfs: Lines&Spacer 1868 3273 168.8 17.8 0.0 6 17:16:10 Collet#10 Hit the Sleeve 1949 3294 190.3 17.9 0.0 7 17:16:46 Start Resume Pad Manually 2759 3298 201.2 21.6 0.0 8 17:16:48 Stage at Perfs: DropCollet10 2481 3294 202.0 23.3 0.0 9 17:16:56 Stage at Perfs: PAD st10 2619 3292 205.4 27.7 0.0 10 17:19:25 Start 1.0 PPA Manually 2675 3319 299.3 40.0 0.0 11 17:19:25 Started Pumping Prop 2675 3319 299.3 40.0 0.0 12 17:20:39 Stage at Perfs: SlowForSeat 2624 3337 348.2 39.6 1.0 13 17:21:55 Stage at Perfs: Resume Pad 2594 3354 398.4 39.8 1.0 14 17:24:22 Stage at Perfs: 1.0 PPA 2569 3369 495.8 39.8 1.0 15 17:24:28 Start 2.0 PPA Automatically 2570 3373 499.8 39.7 1.0 16 17:29:27 Stage at Perfs: 2.0 PPA 2551 3243 696.8 38.9 1.9 17 17:30:02 Start 4.0 PPA Automatically 2583 3250 719.8 39.5 2.0 18 17:35:02 Stage at Perfs: 4.0 PPA 2688 3244 916.8 39.5 4.0 19 17:36:07 Start 6.0 PPA Automatically 2722 3250 959.8 39.8 3.9 20 17:41:05 Stage at Perfs: 6.0 PPA 3140 3277 1156.4 39.7 6.0 21 17:42:25 Start 8.0 PPA Automatically 3204 3289 1209.5 39.8 6.1 22 17:43:25 Pumps swap before12/18 2880 3291 1249.0 39.5 8.0 23 17:47:27 Stage at Perfs: 8.0 PPA 3866 3338 1406.2 39.2 8.0 24 17:48:48 Start 10.0 PPA Automatically 3894 3349 1459.3 39.4 8.1 25 17:53:50 Stage at Perfs: 10.0 PPA 4481 3372 1655.7 39.0 9.8 26 17:54:27 Start 12.0 PPA Automatically 4530 3375 1679.7 38.9 10.1 27 17:57:25 Start 12.0 PPA 12/18 CarboLite Manually 4441 3374 1794.6 37.6 12.2 28 17:59:45 Stage at Perfs: 12.0 PPA 3729 3373 1876.6 33.9 11.7 29 18:00:46 Start XL Flush Manually 4332 3345 1911.3 36.4 -0.0 30 18:00:48 Stopped Pumping Prop 4146 3369 1912.5 37.0 -0.0 31 18:01:02 Start WF Flush Automatically 4178 3391 1921.5 39.1 0.0 32 18:02:49 Stage at Perfs: 12.0 PPA 3795 3365 1991.6 39.3 0.0 33 18:03:56 Start Freeze Protect Manually 1657 3317 2028.5 14.6 0.0 34 18:07:38 Stopped Pumping 1143 3244 2083.4 19.6 0.0 35 18:11:17 Shut down 926 3157 2083.4 0.0 0.0 36 18:15:57 Close well 22 3081 2083.4 0.0 0.0 37 18:32:59 Fanning out pumps 7 1500 2083.4 45.0 0.0 Santos Definitive Survey Report14 June, 2024Design: NDB-051Santos NAD27 ConversionPikkaNDBNDB-051NDB-051 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMap System:Geo Datum:ProjectMap Zone:System Datum:US State Plane 1927 (Exact solution)NAD 1927 (NADCON CONUS)Pikka, North Slope Alaska, United StatesAlaska Zone 04Mean Sea LevelUsing Well Reference PointUsing geodetic scale factorSite Position:From:SiteLatitude:Longitude:Position Uncertainty:Northing:Easting:Grid Convergence:NDBusftMap usftusft°-0.59Slot Radius:"205,972,909.70423,383.560.970° 20' 10.138 N150° 37' 17.796 WWellWell PositionLongitude:Latitude:Easting:Northing:usft+E/-W+N/-SPosition UncertaintyusftusftusftGround Level:NDB-051usftusft0.00.05,972,652.87421,748.1122.8Wellhead Elevation:usft0.570° 20' 7.446 N150° 38' 5.482 WWellboreDeclination(°)Field Strength(nT)Sample Date Dip Angle(°)NDB-051Model NameMagneticsIGRF2000 31/12/2004 24.72 80.61 57,282.16700987Phase:Version:Audit Notes:DesignNDB-0511.0 ACTUALVertical Section: Depth From (TVD)(usft)+N/-S(usft)Direction(°)+E/-W(usft)Tie On Depth:46.5289.880.00.046.514/06/2024 11:52:56COMPASS 5000.17 Build Page 2 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueFrom(usft)Survey ProgramDescriptionTool NameSurvey (Wellbore)To(usft)Date14/06/2024SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)124.6 467.801 SDI URSA GyroMWD 16in Hole <46-463_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag495.9 3,157.102 BH Ontrak16in Hole <495-3157> (NDB3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag3,251.6 4,937.003 BH Ontrak 12.25in Hole <3251-4936> (3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag5,001.3 5,065.0 04 BH OntraK 12.25 Hole <5001-5064> (N3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag5,127.4 5,127.405 BH OntraK 12.25 Hole <5127-5127> (N3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag5,221.1 5,316.206 BH Ontrak 12.25in Hole <5221-5316> (3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag5,411.3 11,528.607 BH OntraK 12.25in Hole <5411-11528>3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,590.2 17,478.008 BH OntraK 8.5in Hole <11590-17450> (MD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)46.5 0.00 0.00 46.5 -22.8 0.0 0.0 5,972,652.87 421,748.11 0.00 0.0124.6 0.44 348.75 124.6 55.3 0.3 -0.1 5,972,653.16 421,748.05 0.56 0.2128.0 0.43 350.36 128.0 58.7 0.3 -0.1 5,972,653.19 421,748.05 0.45 0.220" Conductor Casing187.1 0.35 28.48 187.1 117.8 0.7 0.0 5,972,653.57 421,748.10 0.45 0.3284.3 0.97 285.47 284.3 215.0 1.2 -0.7 5,972,654.05 421,747.46 1.13 1.0373.7 2.85 276.33 373.7 304.4 1.6 -3.6 5,972,654.53 421,744.52 2.12 3.9467.8 5.33 264.38 467.5 398.2 1.5 -10.3 5,972,654.43 421,737.84 2.77 10.2495.9 5.68 262.81 495.4 426.1 1.2 -13.0 5,972,654.16 421,735.17 1.36 12.6590.5 8.42 257.23 589.3 520.0 -1.0 -24.4 5,972,652.16 421,723.75 2.98 22.6685.0 11.35 255.10 682.4 613.1 -4.9 -40.1 5,972,648.40 421,707.97 3.12 36.0779.5 13.33 255.79 774.7 705.4 -10.0 -59.6 5,972,643.54 421,688.37 2.10 52.7874.4 15.12 256.51 866.8 797.5 -15.5 -82.3 5,972,638.20 421,665.66 1.89 72.1968.2 18.16 255.69 956.6 887.3 -22.0 -108.3 5,972,632.01 421,639.55 3.25 94.41,055.0 17.01 254.60 1,039.3 970.0 -28.7 -133.7 5,972,625.56 421,614.13 1.38 116.0Upper Schrader Bluff1,063.4 16.90 254.49 1,047.4 978.1 -29.4 -136.1 5,972,624.93 421,611.75 1.38 118.014/06/2024 11:52:56COMPASS 5000.17 Build Page 3 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)1,157.4 15.91 255.24 1,137.5 1,068.2 -36.3 -161.7 5,972,618.27 421,586.06 1.08 139.71,158.0 15.93 255.24 1,138.1 1,068.8 -36.3 -161.8 5,972,618.22 421,585.91 2.65 139.8Base Ice Bearing Permafrost1,251.8 18.41 255.54 1,227.7 1,158.4 -43.3 -188.6 5,972,611.53 421,559.05 2.65 162.71,349.1 21.31 256.10 1,319.3 1,250.0 -51.4 -220.7 5,972,603.77 421,526.91 2.99 190.11,380.7 22.93 256.08 1,348.6 1,279.3 -54.3 -232.3 5,972,601.03 421,515.32 5.13 200.01,409.0 24.45 256.78 1,374.4 1,305.1 -56.9 -243.3 5,972,598.49 421,504.26 5.48 209.4Base Permafrost Transition1,413.6 24.70 256.89 1,378.6 1,309.3 -57.4 -245.2 5,972,598.07 421,502.39 5.48 211.01,443.1 26.24 257.29 1,405.2 1,335.9 -60.2 -257.5 5,972,595.37 421,490.01 5.26 221.71,476.4 28.29 258.51 1,434.8 1,365.5 -63.4 -272.4 5,972,592.33 421,475.06 6.38 234.61,508.1 29.13 258.68 1,462.7 1,393.4 -66.4 -287.4 5,972,589.48 421,460.09 2.66 247.71,537.3 29.87 257.37 1,488.1 1,418.8 -69.4 -301.4 5,972,586.64 421,446.01 3.36 259.91,625.8 33.70 256.31 1,563.2 1,493.9 -80.0 -346.8 5,972,576.48 421,400.54 4.37 298.91,724.8 36.65 255.56 1,644.2 1,574.9 -93.9 -402.1 5,972,563.18 421,345.05 3.01 346.21,821.8 39.78 256.33 1,720.4 1,651.1 -108.5 -460.3 5,972,549.24 421,286.71 3.26 396.01,835.0 40.20 256.24 1,730.5 1,661.2 -110.5 -468.6 5,972,547.32 421,278.47 3.22 403.1Middle Schrader Bluff1,921.1 42.95 255.71 1,794.9 1,725.6 -124.3 -524.0 5,972,534.05 421,222.91 3.22 450.52,017.7 46.93 256.11 1,863.2 1,793.9 -140.9 -590.1 5,972,518.15 421,156.60 4.13 507.02,114.5 51.17 256.46 1,926.7 1,857.4 -158.2 -661.2 5,972,501.56 421,085.39 4.39 567.92,209.5 55.40 257.31 1,983.5 1,914.2 -175.5 -735.3 5,972,485.07 421,011.05 4.51 631.82,305.1 59.43 257.19 2,035.0 1,965.7 -193.3 -813.9 5,972,468.12 420,932.34 4.22 699.62,399.9 63.51 257.26 2,080.2 2,010.9 -211.7 -895.1 5,972,450.56 420,850.93 4.30 769.82,495.0 67.90 257.53 2,119.3 2,050.0 -230.6 -979.6 5,972,432.55 420,766.24 4.63 842.82,582.0 69.45 257.22 2,151.0 2,081.7 -248.3 -1,058.7 5,972,415.65 420,686.95 1.81 911.2MCU14/06/2024 11:52:56COMPASS 5000.17 Build Page 4 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)2,589.6 69.58 257.19 2,153.6 2,084.3 -249.9 -1,065.7 5,972,414.15 420,680.00 1.81 917.22,684.0 72.54 256.26 2,184.3 2,115.0 -270.4 -1,152.6 5,972,394.55 420,592.89 3.27 991.92,779.4 76.07 255.83 2,210.1 2,140.8 -292.5 -1,241.7 5,972,373.33 420,503.54 3.72 1,068.22,873.8 78.05 255.06 2,231.2 2,161.9 -315.7 -1,330.7 5,972,351.15 420,414.31 2.24 1,144.12,967.7 78.32 255.65 2,250.5 2,181.2 -338.9 -1,419.7 5,972,328.83 420,325.12 0.68 1,219.83,063.2 78.16 257.09 2,269.9 2,200.6 -360.9 -1,510.5 5,972,307.76 420,234.07 1.49 1,297.73,157.1 78.04 257.71 2,289.3 2,220.0 -381.0 -1,600.2 5,972,288.65 420,144.18 0.66 1,375.33,218.0 77.92 258.97 2,302.0 2,232.7 -393.0 -1,658.5 5,972,277.22 420,085.75 2.03 1,426.013-3/8" Surface Casing3,251.6 77.85 259.66 2,309.0 2,239.7 -399.1 -1,690.8 5,972,271.46 420,053.37 2.03 1,454.33,325.3 77.96 258.20 2,324.4 2,255.1 -412.9 -1,761.5 5,972,258.38 419,982.59 1.94 1,516.13,420.0 77.91 257.58 2,344.3 2,275.0 -432.4 -1,852.1 5,972,239.89 419,891.80 0.64 1,594.63,514.7 77.91 256.84 2,364.1 2,294.8 -452.9 -1,942.4 5,972,220.33 419,801.28 0.76 1,672.63,609.7 77.94 257.01 2,384.0 2,314.7 -473.9 -2,032.9 5,972,200.26 419,710.57 0.18 1,750.63,704.5 78.03 257.02 2,403.7 2,334.4 -494.7 -2,123.2 5,972,180.37 419,620.02 0.10 1,828.53,799.5 77.90 256.52 2,423.5 2,354.2 -516.0 -2,213.6 5,972,160.06 419,529.41 0.53 1,906.23,893.9 77.91 256.13 2,443.3 2,374.0 -537.8 -2,303.3 5,972,139.17 419,439.49 0.40 1,983.23,939.0 77.92 256.12 2,452.7 2,383.4 -548.4 -2,346.1 5,972,129.05 419,396.59 0.03 2,019.8Tuluvak Shale3,988.8 77.93 256.11 2,463.1 2,393.8 -560.1 -2,393.4 5,972,117.86 419,349.20 0.03 2,060.34,083.2 77.97 256.03 2,482.9 2,413.6 -582.3 -2,483.1 5,972,096.56 419,259.33 0.09 2,137.14,177.8 77.93 255.92 2,502.6 2,433.3 -604.7 -2,572.8 5,972,075.09 419,169.37 0.12 2,213.84,218.0 77.93 255.95 2,511.0 2,441.7 -614.3 -2,610.9 5,972,065.94 419,131.17 0.07 2,246.4Tuluvak Sand4,273.3 77.94 255.99 2,522.6 2,453.3 -627.4 -2,663.4 5,972,053.37 419,078.56 0.07 2,291.34,368.0 77.88 255.87 2,542.4 2,473.1 -649.9 -2,753.2 5,972,031.81 418,988.57 0.14 2,368.14,463.0 77.94 255.83 2,562.3 2,493.0 -672.6 -2,843.3 5,972,010.04 418,898.25 0.08 2,445.114/06/2024 11:52:56COMPASS 5000.17 Build Page 5 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)4,557.5 77.65 256.62 2,582.3 2,513.0 -694.6 -2,933.0 5,971,988.99 418,808.31 0.87 2,522.04,652.2 77.72 257.01 2,602.5 2,533.2 -715.7 -3,023.1 5,971,968.82 418,717.98 0.41 2,599.54,747.6 77.71 257.28 2,622.8 2,553.5 -736.4 -3,113.9 5,971,949.04 418,626.96 0.28 2,677.94,841.8 77.62 257.10 2,642.9 2,573.6 -756.8 -3,203.7 5,971,929.57 418,537.01 0.21 2,755.44,937.0 77.72 257.09 2,663.2 2,593.9 -777.6 -3,294.3 5,971,909.75 418,446.16 0.11 2,833.55,001.3 77.69 256.77 2,676.9 2,607.6 -791.8 -3,355.5 5,971,896.18 418,384.81 0.49 2,886.35,065.0 77.69 255.94 2,690.5 2,621.2 -806.5 -3,416.0 5,971,882.14 418,324.23 1.27 2,938.15,127.4 77.72 256.66 2,703.8 2,634.5 -820.9 -3,475.2 5,971,868.32 418,264.83 1.13 2,988.95,221.1 77.68 256.81 2,723.7 2,654.4 -841.9 -3,564.3 5,971,848.25 418,175.54 0.16 3,065.65,316.2 77.66 255.88 2,744.0 2,674.7 -863.9 -3,654.6 5,971,827.26 418,085.05 0.96 3,143.05,411.3 77.68 256.19 2,764.4 2,695.1 -886.3 -3,744.8 5,971,805.78 417,994.63 0.32 3,220.25,506.3 77.74 256.48 2,784.6 2,715.3 -908.2 -3,835.0 5,971,784.78 417,904.18 0.30 3,297.65,593.0 77.69 256.53 2,803.0 2,733.7 -928.0 -3,917.4 5,971,765.88 417,821.65 0.07 3,368.3TS_7905,600.3 77.69 256.53 2,804.6 2,735.3 -929.6 -3,924.3 5,971,764.30 417,814.73 0.07 3,374.25,695.7 77.84 256.86 2,824.8 2,755.5 -951.1 -4,015.0 5,971,743.79 417,723.75 0.37 3,452.35,790.4 77.91 257.20 2,844.7 2,775.4 -971.9 -4,105.3 5,971,723.95 417,633.30 0.36 3,530.15,885.1 77.93 257.50 2,864.5 2,795.2 -992.2 -4,195.6 5,971,704.62 417,542.76 0.31 3,608.15,979.9 77.90 257.30 2,884.4 2,815.1 -1,012.4 -4,286.0 5,971,685.35 417,452.14 0.21 3,686.36,074.5 77.91 257.35 2,904.2 2,834.9 -1,032.7 -4,376.4 5,971,665.98 417,361.62 0.05 3,764.36,169.2 77.84 256.85 2,924.1 2,854.8 -1,053.4 -4,466.5 5,971,646.27 417,271.25 0.52 3,842.16,263.9 77.88 256.76 2,944.0 2,874.7 -1,074.5 -4,556.7 5,971,626.08 417,180.89 0.10 3,919.76,358.5 77.93 256.89 2,963.8 2,894.5 -1,095.6 -4,646.8 5,971,605.93 417,090.58 0.14 3,997.26,452.7 77.88 256.31 2,983.5 2,914.2 -1,116.9 -4,736.4 5,971,585.53 417,000.80 0.60 4,074.26,547.8 77.84 256.31 3,003.6 2,934.3 -1,138.9 -4,826.7 5,971,564.46 416,910.20 0.04 4,151.76,642.7 77.84 255.76 3,023.5 2,954.2 -1,161.3 -4,916.7 5,971,543.03 416,820.01 0.57 4,228.714/06/2024 11:52:56COMPASS 5000.17 Build Page 6 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)6,670.0 77.85 255.84 3,029.3 2,960.0 -1,167.9 -4,942.6 5,971,536.75 416,794.05 0.29 4,250.9Seabee6,736.8 77.87 256.04 3,043.3 2,974.0 -1,183.7 -5,006.0 5,971,521.54 416,730.50 0.29 4,305.16,831.1 77.87 256.09 3,063.1 2,993.8 -1,205.9 -5,095.4 5,971,500.29 416,640.88 0.05 4,381.66,927.1 77.68 256.02 3,083.5 3,014.2 -1,228.5 -5,186.5 5,971,478.62 416,549.54 0.21 4,459.67,022.3 77.75 256.06 3,103.7 3,034.4 -1,251.0 -5,276.8 5,971,457.12 416,459.05 0.08 4,536.97,116.9 77.78 256.42 3,123.8 3,054.5 -1,273.0 -5,366.6 5,971,436.08 416,369.06 0.37 4,613.87,210.7 77.78 257.05 3,143.6 3,074.3 -1,294.0 -5,455.8 5,971,415.98 416,279.62 0.66 4,690.67,305.9 77.69 256.97 3,163.9 3,094.6 -1,314.9 -5,546.4 5,971,396.02 416,188.81 0.13 4,768.77,400.3 77.69 256.97 3,184.0 3,114.7 -1,335.7 -5,636.3 5,971,376.15 416,098.67 0.00 4,846.27,495.8 77.68 257.74 3,204.4 3,135.1 -1,356.1 -5,727.3 5,971,356.69 416,007.48 0.79 4,924.87,590.4 77.68 257.64 3,224.5 3,155.2 -1,375.8 -5,817.6 5,971,337.93 415,916.98 0.10 5,003.07,685.7 77.71 256.72 3,244.8 3,175.5 -1,396.5 -5,908.4 5,971,318.22 415,826.00 0.94 5,081.37,779.5 77.66 257.46 3,264.9 3,195.6 -1,417.0 -5,997.7 5,971,298.68 415,736.48 0.77 5,158.47,873.8 77.69 257.34 3,285.0 3,215.7 -1,437.1 -6,087.7 5,971,279.52 415,646.32 0.13 5,236.17,969.2 77.69 257.24 3,305.3 3,236.0 -1,457.6 -6,178.6 5,971,259.97 415,555.25 0.10 5,314.68,063.4 77.87 257.30 3,325.3 3,256.0 -1,477.9 -6,268.4 5,971,240.62 415,465.24 0.20 5,392.28,158.4 77.88 256.71 3,345.2 3,275.9 -1,498.8 -6,358.9 5,971,220.68 415,374.50 0.61 5,470.28,252.7 77.85 256.41 3,365.0 3,295.7 -1,520.2 -6,448.5 5,971,200.20 415,284.68 0.31 5,547.28,347.2 77.88 255.70 3,384.9 3,315.6 -1,542.5 -6,538.2 5,971,178.86 415,194.73 0.73 5,624.08,441.7 77.85 255.75 3,404.8 3,335.5 -1,565.2 -6,627.8 5,971,157.02 415,104.98 0.06 5,700.58,536.5 77.85 255.32 3,424.7 3,355.4 -1,588.4 -6,717.5 5,971,134.81 415,015.02 0.44 5,777.08,631.6 77.88 255.82 3,444.7 3,375.4 -1,611.6 -6,807.6 5,971,112.58 414,924.73 0.51 5,853.88,726.0 77.31 256.48 3,465.0 3,395.7 -1,633.6 -6,897.0 5,971,091.46 414,835.06 0.91 5,930.48,821.6 77.31 259.00 3,486.0 3,416.7 -1,653.4 -6,988.2 5,971,072.61 414,743.73 2.57 6,009.48,914.7 76.92 261.89 3,506.8 3,437.5 -1,668.5 -7,077.7 5,971,058.47 414,654.04 3.05 6,088.59,011.5 77.00 263.94 3,528.6 3,459.3 -1,680.1 -7,171.2 5,971,047.82 414,560.40 2.07 6,172.514/06/2024 11:52:56COMPASS 5000.17 Build Page 7 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)9,105.4 76.27 266.65 3,550.3 3,481.0 -1,687.6 -7,262.3 5,971,041.28 414,469.31 2.91 6,255.59,200.4 76.27 268.85 3,572.9 3,503.6 -1,691.2 -7,354.5 5,971,038.62 414,377.09 2.25 6,341.09,294.6 76.32 271.47 3,595.2 3,525.9 -1,691.0 -7,446.0 5,971,039.83 414,285.59 2.70 6,427.19,389.8 76.34 274.02 3,617.7 3,548.4 -1,686.5 -7,538.4 5,971,045.23 414,193.21 2.60 6,515.69,485.4 76.29 276.03 3,640.3 3,571.0 -1,678.4 -7,630.9 5,971,054.33 414,100.78 2.04 6,605.39,579.6 76.27 277.97 3,662.7 3,593.4 -1,667.3 -7,721.7 5,971,066.42 414,010.13 2.00 6,694.59,674.1 75.70 280.38 3,685.6 3,616.3 -1,652.6 -7,812.3 5,971,081.99 413,919.74 2.55 6,784.69,769.5 75.75 282.26 3,709.1 3,639.8 -1,634.5 -7,902.9 5,971,101.07 413,829.31 1.91 6,876.09,864.9 75.74 284.60 3,732.6 3,663.3 -1,613.0 -7,992.8 5,971,123.48 413,739.62 2.38 6,967.99,959.2 75.67 287.53 3,755.9 3,686.6 -1,587.7 -8,080.6 5,971,149.67 413,652.12 3.01 7,059.010,053.5 75.72 290.62 3,779.2 3,709.9 -1,557.9 -8,167.0 5,971,180.44 413,566.06 3.17 7,150.410,148.3 75.78 293.15 3,802.5 3,733.2 -1,523.6 -8,252.3 5,971,215.57 413,481.17 2.59 7,242.310,178.0 75.75 293.86 3,809.8 3,740.5 -1,512.2 -8,278.6 5,971,227.31 413,454.94 2.33 7,271.0Nanushuk10,243.2 75.70 295.43 3,825.9 3,756.6 -1,485.8 -8,336.0 5,971,254.24 413,397.81 2.33 7,333.910,261.0 75.71 295.88 3,830.3 3,761.0 -1,478.3 -8,351.6 5,971,261.88 413,382.33 2.44 7,351.1NT8 MFS10,338.1 75.76 297.82 3,849.3 3,780.0 -1,444.6 -8,418.2 5,971,296.31 413,316.03 2.44 7,425.210,364.0 75.86 298.40 3,855.6 3,786.3 -1,432.8 -8,440.4 5,971,308.38 413,294.00 2.19 7,450.1NT7 MFS10,433.1 76.14 299.93 3,872.3 3,803.0 -1,400.1 -8,499.0 5,971,341.68 413,235.76 2.19 7,516.310,526.9 76.14 302.26 3,894.8 3,825.5 -1,353.0 -8,577.0 5,971,389.51 413,158.30 2.41 7,605.610,622.5 76.02 305.71 3,917.8 3,848.5 -1,301.2 -8,653.8 5,971,442.14 413,081.96 3.51 7,695.610,717.5 76.65 308.81 3,940.3 3,871.0 -1,245.3 -8,727.3 5,971,498.80 413,009.07 3.24 7,783.710,735.0 76.65 309.10 3,944.3 3,875.0 -1,234.6 -8,740.6 5,971,509.62 412,995.96 1.61 7,799.7NT6 MFS10,812.0 76.65 310.37 3,962.1 3,892.8 -1,186.7 -8,798.1 5,971,558.09 412,938.88 1.61 7,870.214/06/2024 11:52:56COMPASS 5000.17 Build Page 8 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)10,906.0 76.64 311.46 3,983.8 3,914.5 -1,126.8 -8,867.3 5,971,618.72 412,870.38 1.13 7,955.610,940.0 76.67 312.23 3,991.6 3,922.3 -1,104.8 -8,891.9 5,971,641.04 412,845.97 2.22 7,986.3NT5 MFS11,002.2 76.73 313.65 4,006.0 3,936.7 -1,063.5 -8,936.3 5,971,682.76 412,802.07 2.22 8,042.011,096.1 76.68 316.51 4,027.6 3,958.3 -998.8 -9,000.8 5,971,748.13 412,738.23 2.96 8,124.711,142.0 77.20 317.94 4,037.9 3,968.6 -966.0 -9,031.1 5,971,781.23 412,708.24 3.24 8,164.3NT4 MFS11,191.0 77.76 319.46 4,048.5 3,979.2 -930.1 -9,062.7 5,971,817.47 412,677.07 3.24 8,206.211,285.7 77.72 321.12 4,068.7 3,999.4 -858.9 -9,121.8 5,971,889.26 412,618.70 1.71 8,286.011,380.5 78.67 323.32 4,088.1 4,018.8 -785.6 -9,178.6 5,971,963.19 412,562.63 2.48 8,364.411,474.8 78.62 326.48 4,106.6 4,037.3 -709.9 -9,231.8 5,972,039.40 412,510.24 3.28 8,440.211,506.0 78.59 327.38 4,112.8 4,043.5 -684.3 -9,248.5 5,972,065.18 412,493.84 2.85 8,464.6NT3 MFS11,528.6 78.57 328.04 4,117.3 4,048.0 -665.6 -9,260.3 5,972,084.01 412,482.21 2.85 8,482.011,560.0 78.57 328.07 4,123.5 4,054.2 -639.4 -9,276.6 5,972,110.31 412,466.19 0.10 8,506.39-5/8" Intermediate Liner11,590.2 78.57 328.10 4,129.5 4,060.2 -614.3 -9,292.3 5,972,135.60 412,450.81 0.10 8,529.511,632.0 78.67 327.86 4,137.7 4,068.4 -579.6 -9,314.0 5,972,170.56 412,429.45 0.61 8,561.8NT3.2 Top Reservoir11,683.6 78.79 327.56 4,147.8 4,078.5 -536.8 -9,341.0 5,972,213.63 412,402.85 0.61 8,601.811,762.0 80.99 328.80 4,161.6 4,092.3 -471.2 -9,381.7 5,972,279.61 412,362.86 3.21 8,662.3NT3.2411,780.6 81.51 329.09 4,164.4 4,095.1 -455.4 -9,391.2 5,972,295.49 412,353.53 3.21 8,676.611,875.3 84.99 330.47 4,175.5 4,106.2 -374.2 -9,438.5 5,972,377.18 412,307.08 3.95 8,748.711,969.2 87.26 330.54 4,181.9 4,112.6 -292.7 -9,484.6 5,972,459.18 412,261.82 2.42 8,819.812,065.3 90.31 330.61 4,183.9 4,114.6 -209.0 -9,531.8 5,972,543.35 412,215.49 3.17 8,892.712,160.1 90.53 329.99 4,183.2 4,113.9 -126.7 -9,578.8 5,972,626.14 412,169.41 0.69 8,964.812,255.2 90.41 329.71 4,182.4 4,113.1 -44.4 -9,626.6 5,972,708.90 412,122.49 0.32 9,037.714/06/2024 11:52:56COMPASS 5000.17 Build Page 9 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)12,349.8 90.35 328.97 4,181.8 4,112.5 37.0 -9,674.8 5,972,790.79 412,075.09 0.78 9,110.812,444.8 90.44 328.11 4,181.2 4,111.9 118.0 -9,724.4 5,972,872.28 412,026.39 0.91 9,184.912,539.7 90.38 328.95 4,180.5 4,111.2 198.9 -9,773.9 5,972,953.74 411,977.69 0.89 9,259.012,635.2 90.47 328.06 4,179.8 4,110.5 280.4 -9,823.8 5,973,035.69 411,928.65 0.94 9,333.712,730.4 90.38 328.25 4,179.1 4,109.8 361.2 -9,874.0 5,973,117.03 411,879.30 0.22 9,408.412,825.7 90.50 329.10 4,178.3 4,109.0 442.6 -9,923.6 5,973,198.95 411,830.61 0.90 9,482.612,920.6 90.47 329.05 4,177.5 4,108.2 524.1 -9,972.4 5,973,280.91 411,782.66 0.06 9,556.213,015.5 90.53 329.36 4,176.7 4,107.4 605.5 -10,020.9 5,973,362.85 411,734.98 0.33 9,629.613,110.6 90.56 329.09 4,175.8 4,106.5 687.3 -10,069.6 5,973,445.09 411,687.15 0.29 9,703.213,205.5 90.53 328.64 4,174.9 4,105.6 768.4 -10,118.7 5,973,526.77 411,638.97 0.48 9,776.913,300.1 90.56 329.05 4,174.0 4,104.7 849.4 -10,167.6 5,973,608.27 411,590.85 0.43 9,850.513,395.4 90.53 329.40 4,173.1 4,103.8 931.3 -10,216.4 5,973,690.62 411,542.97 0.37 9,924.213,490.0 90.53 330.09 4,172.2 4,102.9 1,013.0 -10,264.0 5,973,772.85 411,496.14 0.73 9,996.813,585.3 90.53 330.43 4,171.3 4,102.0 1,095.7 -10,311.3 5,973,856.01 411,449.78 0.36 10,069.313,681.0 90.53 330.22 4,170.4 4,101.1 1,178.9 -10,358.7 5,973,939.66 411,403.26 0.22 10,142.213,775.6 90.56 330.05 4,169.5 4,100.2 1,261.0 -10,405.8 5,974,022.23 411,356.99 0.18 10,214.413,871.1 90.53 330.27 4,168.6 4,099.3 1,343.8 -10,453.3 5,974,105.54 411,310.35 0.23 10,287.313,965.9 90.56 329.52 4,167.7 4,098.4 1,425.8 -10,500.8 5,974,187.99 411,263.69 0.79 10,359.814,060.5 90.50 329.59 4,166.9 4,097.6 1,507.3 -10,548.8 5,974,270.03 411,216.61 0.10 10,432.714,156.1 90.59 328.59 4,166.0 4,096.7 1,589.3 -10,597.9 5,974,352.54 411,168.38 1.05 10,506.714,250.8 90.53 329.01 4,165.0 4,095.7 1,670.4 -10,647.0 5,974,434.09 411,120.14 0.45 10,580.514,345.9 90.56 328.77 4,164.1 4,094.8 1,751.8 -10,696.1 5,974,516.00 411,071.87 0.25 10,654.314,440.6 90.50 328.56 4,163.2 4,093.9 1,832.6 -10,745.3 5,974,597.33 411,023.51 0.23 10,728.114,535.5 90.53 328.33 4,162.4 4,093.1 1,913.5 -10,795.0 5,974,678.75 410,974.67 0.24 10,802.314,630.7 90.56 329.04 4,161.5 4,092.2 1,994.8 -10,844.5 5,974,760.55 410,926.07 0.75 10,876.514,726.2 90.50 329.47 4,160.6 4,091.3 2,077.0 -10,893.3 5,974,843.17 410,878.08 0.45 10,950.414/06/2024 11:52:56COMPASS 5000.17 Build Page 10 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)14,820.9 90.35 329.63 4,159.9 4,090.6 2,158.5 -10,941.3 5,974,925.24 410,830.98 0.23 11,023.214,915.8 90.44 329.15 4,159.2 4,089.9 2,240.3 -10,989.6 5,975,007.46 410,783.49 0.51 11,096.515,011.2 90.41 329.93 4,158.5 4,089.2 2,322.5 -11,038.0 5,975,090.18 410,736.00 0.82 11,169.915,106.2 90.41 329.54 4,157.9 4,088.6 2,404.5 -11,085.8 5,975,172.68 410,689.00 0.41 11,242.815,201.2 90.41 329.45 4,157.2 4,087.9 2,486.4 -11,134.1 5,975,255.06 410,641.62 0.09 11,316.015,296.3 90.41 329.51 4,156.5 4,087.2 2,568.3 -11,182.4 5,975,337.48 410,594.18 0.06 11,389.315,391.0 90.44 329.30 4,155.8 4,086.5 2,649.8 -11,230.6 5,975,419.48 410,546.84 0.22 11,462.415,486.6 90.44 329.36 4,155.1 4,085.8 2,732.0 -11,279.3 5,975,502.13 410,498.98 0.06 11,536.115,581.2 90.59 329.25 4,154.2 4,084.9 2,813.4 -11,327.6 5,975,584.02 410,451.52 0.20 11,609.215,676.0 90.50 329.44 4,153.3 4,084.0 2,894.9 -11,375.9 5,975,666.07 410,404.04 0.22 11,682.415,770.7 90.53 329.39 4,152.5 4,083.2 2,976.5 -11,424.1 5,975,748.08 410,356.72 0.06 11,755.515,866.5 90.56 329.48 4,151.5 4,082.2 3,058.9 -11,472.8 5,975,831.00 410,308.91 0.10 11,829.315,961.6 90.53 329.57 4,150.6 4,081.3 3,140.8 -11,521.0 5,975,913.44 410,261.54 0.10 11,902.516,056.9 90.59 330.02 4,149.7 4,080.4 3,223.2 -11,569.0 5,975,996.31 410,214.45 0.48 11,975.616,150.6 90.56 329.85 4,148.8 4,079.5 3,304.3 -11,615.9 5,976,077.91 410,168.35 0.18 12,047.316,247.1 90.53 329.82 4,147.9 4,078.6 3,387.7 -11,664.4 5,976,161.79 410,120.76 0.04 12,121.316,341.4 90.56 329.79 4,147.0 4,077.7 3,469.2 -11,711.8 5,976,243.79 410,074.19 0.04 12,193.616,436.6 90.53 329.64 4,146.0 4,076.7 3,551.5 -11,759.9 5,976,326.51 410,027.02 0.16 12,266.716,531.1 90.53 329.89 4,145.2 4,075.9 3,633.1 -11,807.4 5,976,408.59 409,980.33 0.26 12,339.216,627.3 90.53 329.66 4,144.3 4,075.0 3,716.2 -11,855.9 5,976,492.25 409,932.75 0.24 12,413.016,722.0 90.53 329.64 4,143.4 4,074.1 3,797.9 -11,903.7 5,976,574.40 409,885.80 0.02 12,485.816,817.0 90.53 329.66 4,142.5 4,073.2 3,879.9 -11,951.7 5,976,656.86 409,838.66 0.02 12,558.816,912.0 90.53 329.12 4,141.7 4,072.4 3,961.6 -12,000.1 5,976,739.12 409,791.14 0.57 12,632.117,006.6 90.59 328.84 4,140.7 4,071.4 4,042.7 -12,048.8 5,976,820.70 409,743.24 0.30 12,705.517,102.3 90.53 328.46 4,139.8 4,070.5 4,124.5 -12,098.6 5,976,902.95 409,694.30 0.40 12,780.217,197.2 90.41 328.03 4,139.0 4,069.7 4,205.2 -12,148.6 5,976,984.15 409,645.21 0.47 12,854.614/06/2024 11:52:56COMPASS 5000.17 Build Page 11 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)17,292.1 90.38 328.84 4,138.4 4,069.1 4,286.0 -12,198.2 5,977,065.50 409,596.39 0.85 12,928.817,387.4 90.38 329.12 4,137.7 4,068.4 4,367.7 -12,247.4 5,977,147.69 409,548.13 0.29 13,002.717,450.6 90.41 329.55 4,137.3 4,068.0 4,422.0 -12,279.6 5,977,202.37 409,516.48 0.68 13,051.517,472.0 90.41 329.55 4,137.1 4,067.8 4,440.5 -12,290.4 5,977,220.92 409,505.83 0.00 13,068.04-1/2" Production Liner17,478.0 90.41 329.55 4,137.1 4,067.8 4,445.7 -12,293.5 5,977,226.13 409,502.84 0.00 13,072.6Vertical Depth(usft)Measured Depth(usft)CasingDiameter(")HoleDiameter(")NameCasing Points20" Conductor Casing128.0128.0 20 2013-3/8" Surface Casing2,302.03,218.0 13-3/8 169-5/8" Intermediate Liner4,123.511,560.0 9-5/8 12-1/44-1/2" Production Liner4,137.117,472.0 4-1/2 8-1/214/06/2024 11:52:56COMPASS 5000.17 Build Page 12 Project:Company: Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:NDB-051NDB-051Survey Calculation Method:Minimum CurvatureParker 272 Actual @ 69.3usftDesign:NDB-051Database:EDMMD Reference:Parker 272 Actual @ 69.3usftNorth Reference:Well NDB-051TrueMeasuredDepth(usft)VerticalDepth(usft)DipDirection(°)Name LithologyDip(°)Formations1,158.0 1,138.1 Base Ice Bearing Permafrost1,409.0 1,374.4 Base Permafrost Transition10,364.0 3,855.6 NT7 MFS10,735.0 3,944.3 NT6 MFS1,835.0 1,730.5 Middle Schrader Bluff10,940.0 3,991.6 NT5 MFS6,670.0 3,029.3 Seabee10,178.0 3,809.8 Nanushuk4,218.0 2,511.0 Tuluvak Sand1,055.0 1,039.3 Upper Schrader Bluff10,261.0 3,830.3 NT8 MFS11,506.0 4,112.8 NT3 MFS11,632.0 4,137.7 NT3.2 Top Reservoir11,142.0 4,037.9 NT4 MFS2,582.0 2,151.0 MCU11,762.0 4,161.6 NT3.245,593.0 2,803.0 TS_7903,939.0 2,452.7 Tuluvak ShaleApproved By:Checked By: Date:14/06/2024 11:52:56COMPASS 5000.17 Build Page 13 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 1 PDF file NDB-051 (50-103-20880-0000) Well clean up report Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 12/5/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 224-013 T39830 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.06 08:14:28 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Well Cleanup 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?NDB-051 Yes No 9. Property Designation (Lease Number): 10. Field: Pikka Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,478' 4,137' 17,472' 4,137' 1,467 N/A N/A Casing Collapse Conductor Surface 2260 Intermediate 4750 Tie-Back 4750 Production 9210 Liner 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone: 907-330-4595 Authorized Title: Completions Specialist Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 08/27/24 17,473'6,094' 4-1/2" 12.6ppf 4,137' See attached packer report 11,434' Perforation Depth MD (ft): 3,063' N/A 11,434, 4-1/2" N/A 4,099'4-1/2" 128' 20"x34" 13-3/8" 9-5/8" 3,218' Tieback3,063' 8,497' MD 6870 5020 6870 2,302' 4,124' 2,270' 3,218' 11,560' Length Size Proposed Pools: 128' 128' P-110S TVD Burst 11,434' 11590 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393021, 393019, 392991 224-013 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20880-00-00 Oil Search Alaska, LLC AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): See attached packer report Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY m n s 2 6 5 6 tc N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 07/30/2024 By Grace Christianson at 3:48 pm, Jul 30, 2024 324-441 08/27/24 CDW 08/13/2024 Pikka BJM 8/15/24 A.Dewhurst 13AUG24 DSR-8/2/24 same 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.15 13:46:23 -08'00'08/15/24 RBDMS JSB 081624 Page 1 of 1 Well Name: NDB-051 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,399.3 4,091.8 HES Zoneguard OH Packer #12 11,669.4 4,145.1 HES Zoneguard OH Packer #11 11,737.4 4,157.6 HES Zoneguard OH Packer #10 12,241.3 4,182.6 HES Zoneguard OH Packer #9 12,785.8 4,178.7 HES Zoneguard OH Packer #8 13,414.0 4,172.9 HES Zoneguard OH Packer #7 13,996.1 4,167.5 HES Zoneguard OH Packer #6 14,495.4 4,162.8 HES Zoneguard OH Packer #5 15,119.4 4,157.8 HES Zoneguard OH Packer #4 15,659.9 4,153.5 HES Zoneguard OH Packer #3 16,240.1 4,147.9 HES Zoneguard OH Packer #2 16,865.6 4,142.1 HES Zoneguard OH Packer #1 17,325.7 4,138.1 Page 1 of 18 NDB-051 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachment B 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBD-051. At the NDB-051 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifer (typically found down to 400 ft depth) are located at the NDB-051 location. 4. Plan for freshwater sampling – There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information – Attachment C 6. Assessment of casing and cementing operations – Attachment C 7. Casing and tubing pressure test information – Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachments D and I 9. Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 973 feet (ft) total vertical depth subsea (TVDSS)/ 973 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 973 to 2,373 ft TVDSS/1,400 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelf setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,373 to 3,081 ft TVDSS/ 708 ft thick Hydrocarbon Zone: 2,431 to 3,081 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,081 to 3,735 ft TVDSS/ 654 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: 3,735 to 4,691 ft TVDSS/ 956 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Lower Confining Zone Name: Torok Formation Depth/Thickness: 4,691 to 5,590 ft TVDSS/899 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is composed primarily of shale (Hue Shale) with some thin interbedded siltstones. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. 10.Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) MAWP (psi) Stages 1-10 3,300 3,600 8,500 8,000 9,000 8,900 Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft 11.Mechanical condition of wells transecting the confining zones –Qugruk 3, Qugruk 3A, Qugruk 301, NDBi-014, NDBi-044 and NDBi-046, are within 1/2-mile radius of NDB-051.Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones. Please see Attachment B Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 17,172 4,138 241.4 457.1 40 6,876 10 2 16,589 4,139 245.6 407.9 40 6,782 12 3 15,965 4,148 246.2 414.0 40 6,529 12 4 15,426 4,155 247.2 339.5 40 6,188 10 5 14,803 4,160 239.6 391.7 40 5,949 10 6 14,261 4,165 243.3 371.2 40 5,892 12 7 13,680 4,170 241.5 354.2 40 5,532 10 8 13,095 4,175 240.0 390.8 40 5,319 10 9 12,509 4,180 243.7 366.9 40 5,163 12 10 11,922 4,180 242.3 360.8 40 4,929 12 13.Detailed proposed fracturing program –Attachments F & K 14.Well Clean Up procedure –Attachment G Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment H Section (d) Pressure Relieve Valve –Attachment I Proposed Wellbore Schematic –Attachment J Attachment A Oil Search (Alaska), LLC a subsidiary of Santos Limited 900 E. Benson Blvd Anchorage, Alaska 99508 PO Box 240927 Anchorage, Alaska 99524 (T) +1 907 375 4642 — santos.com 1/2 June 28, 2024 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLC’s Sundry Application for a Fracture Stimulation for the Proposed NDB-051 Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDB-051 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC PO Box 240927 Anchorage, AK 99524 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDB-051 well trajectory and fracture stimulation. Please contact me should you require additional information. Sincerely, Tim Jones Land Manager Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL PO Box 240927 Anchorage, AK 99524 Repsol E&P USA LLC CERTIFIED MAIL Attn: Jeremy McKee 2455 Technology Forest Blvd. The Woodlands, TX 77381 ADL 392977OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 17.22% DNR - 82.78%ADL 392991OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 41.58% DNR - 58.42%ADL 392985OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 49.84% DNR - 50.16%ADL 392984OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 50% DNR - 50%ADL 392958OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 36.31% DNR - 63.69%ADL 393022OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 39.48% DNR - 60.52%ADL 393021OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 19.22% DNR - 80.78%ADL 393023OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 44.08% DNR - 55.92%ADL 393019OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 33.1% DNR - 66.9%ADL 393020OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 26.59% DNR - 73.41%ADL 393016OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 33.17% DNR - 66.83%ADL 391445OIL SEARCH - 51%, REPSOL - 49%Surface Owners: KuukpikSUBS.OWNERS:ASRC - 41.98% DNR - 58.02%U011N006E04U012N006E32U011N006E05U012N006E33U012N005E36U011N005E01U011N005E12U011N006E09U011N006E08U012N006E31U011N006E06U011N006E07OIL SEARCH (ALASKA), LLC A SUBSIDIARY OF SANTOS LTDNDB051 WELL AREATARGETBOTTOM HOLESURFACE LOCATIONWELL TRAJECTORYLEASES BOUNDARYKUUKPIK BOUNDARY.5-mile BufferTOWNSHIPSECTIONDATE: 7/11/2024. REV: 1.0. By: JB0 400 800US FeetProject: AP-DRL-GEN_assortedLayout: AP-DRL-PE-M_NDB051_well_ownershipGCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet0 100 200MetersPIKKA PROJECTNDB Attachment B Fault 1: The fault noted is a low confidence fault that has less than 20 ft of throw and could also be a stratigraphic feature. The fault as mapped on seismic tips out within the Nanushuk formation, so is it covered by the Seabee- the upper confining layer. WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityQ3 Abandoned Open Hole3875 3502 3502Tag TOC with DP.Open Hole Abandonment PlugTOC 3502' MDThe 12-1/4" open hole section was abandoned with 4 open hole plugs. Kuparuk C 6750' - 6753' MD, Alpine 6970' - 7230' MDCement Plug #1: Pump mud push, 120 bbls 15. 8 ppg Class G cement for openhole plug# 1. POOH to 6624' and circulate drill pipe clean. Pick up drill pipewhile WOC. Tag plug at 6852', with 14,000 lbs. Tag witnessed by Bob Noble. Plug at 7,500' MD - 6,852' MD, Cement Plug #2A: Pump mud push, 115 bbls 15. 8 ppg Class G cement for open hole plug# 2.Tag plug at 4216', with 10,000 lbs. Tag witnessed by Bob Noble. plug #2 4,581' MD - 4,216' MD. Plug #2 didn't meet regulations. Mixed up a second one. Cement Plug #2B: Pump mud push, 100 bbls 17 ppg Class G. Tag plug at 3,502' MD. Tag witnessed by Louis Grimaldi. Plug #2A 4,216' MD - 3,502' MD. Cement Plug #3: Pump mud push, 108 bbls 17 ppg Class G cement for bottom kick off plug. POOH to 2275. Cement plug #3 Kick off plug 3,144' - 2,507' MDCement Plug #4: Pump mud push, 88 bbls 15. 7 ppg AS1 cement for top kick off plug. Cement plug #4 top kick off plug 2,255 - 1,735' MDThe Q3A sidetrack wellbore was then kicked off by washing through soft cement and kicking off of cement plug #3 at 2708' MD. The Q3A well was then drilled and abandoned per the AOGCC Regulations. Well is fully abandoned. Q-301 Abandoned9-5/8" 47# L-804042 (Nanushuk)3841 (Nanushuk) 3810'3683'logAbandoned with Cased hole cement plugsTOC 3,810' MDQ-301 was an exploration/appraisal well that was drilled in 2015. Itwas hydraulic fractured in the Nanushuk reservoir, flowed back, andplugged and abandoned in the same winter season.• The Nanushuk formation top was identified at 4042’ MD, withNanushuk target formation at 4631’ MD.• 9-5/8” Intermediate casing is set at 5241’ MD in the Nanushukreservoir. The primary cement job has the TOC at 3810’ MD (96.7 bbls13.9ppg Extended Class G), with a second stage cement job from3008’ MD to surface (187 bbls of 12.2ppg Extended Type I/II).• The 4-1/2” production liner in the Nanushuk reservoir is set at 7495’MD. The liner was P&A with a cement retainer set at 4503’ MD and 48bbls squeezed below the retainer (4-1/2” liner volume).• 3 cement abandonment plugs were set in the 9-5/8” casing:1. 1st Plug (300’ above cement retainer): 18 bbls of 15.8 ppg cementlaid above the cement retainer at 4503’.2. 2nd Plug (300’ across 13-3/8” casing shoe): A 9-5/8” bridge plug wasset at 2207’ MD (100’ below the surface casing shoe) with 19.1 bbls of15.6ppg Class G cement plug laid on top of it.Well is fully abandoned. Q3A Abandoned Open Hole4678 (Nanushuk)4192' (Nanushuk)4678' 4177' Tag TOC set down 15k with DP.Open Hole Abandonment PlugTOC 4,177' MD• The 8-1/2” open hole section was abandoned with two open hole plugs:1st plug (open hole plug): An open hole balanced cement plugwas attempted to be laid in the well from 10,420’ MD by pumping a136 bbls of 15.8 ppg cement. Cement was pumped with fullreturns, but while laying in the balanced plug in the well the stringincluding the drill pipe and 4-1/2” 2,000’ 12.6 ppf tubing stingerbecame stuck at 10,383’ MD. The pipe was severed at 6,243’ MD.TOC was estimated to be at 8,003’ MD in the annulus and 8,650’MD inside the drill pipe.2.) 2nd plug (open hole balanced plug): A second open holebalanced plug was placed in the well by circulating 73 bbls of 15.8ppg class G cement into the hole at 4950’ MD. TOC was confirmedat 4,177’ MD by tagging and placing 15k WOB several timesWell is fully abandoned. NDBi-044 ACTIVE9-5/8"47ppf9678 (Nanushuk)3,804 (Nanushuk) 7964 3,496 logopen hole liner for productionTOC 7,964' & packer @ 10,823' 1.9-5/8” x 13-3/8” Primary cement job a.Pump 80 bbls 12.5 ppg tuned spacer, 131 bbls 13.0 ppg 400 sxs 1.84 Ō^3/sx EconoCem Tpe I-II lead cement, and 80 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail. Planned TOC was ~8,350’ MD. b.No returns while displacing cement job. Wiper dart #2 was lodged in the liner running tool when it was recovered. The follow liner wiper plug was then found just below the 9-5/8” x 13-3/8” Liner top. A cleanout run was required to push the follow liner wiper plug to bottom and the shoe track was drilled out. Dynamic losses were encountered while drilling the float equipment indicating the lost circulation zone had not been isolated. c.A cement retainer was run in the hole and set at 11,010’ MD and a second cement job was pumped through the shoe d.15bbls 12.0 ppg tuned spacer and 95 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail were circulated through the retainer, and 5 bbls wereplaced on top of the retainer. 2.9-5/8” Secondary Cement Job a.RIH and open up the Archer CŇex cement tool. Establish circulaƟon and pump 80 bbls 12.5 ppg Tuned spacer 214 bbls 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail. 129 bbls were lost while displacing. The LTP was set and 263 bbls of contaminated mud / cement/ spacer was circulated to surface while circulating with the Cflex running tool. An additional 5 bbls of cement was circulated out off the top of the liner when circulating with the liner running too at the top of the liner. 3.9-5/8” Cement EvaluaƟon Logs a.HES Cast tool was run in the hole on a welltec tractor. The 9-5/8” cement was logged. Showing the TOC of the primary job at 7,964' MD. 01/30/24, 9-5/8" casing pressure tested to 4284 psi for 30 minutes NDBi-014 ACTIVE9-5/8" 47ppf7677 (Nanushuk)3799 (Nanushuk) 7739 3,817 logopen hole liner for productionTOC 7,739' & packer @ 10,257' 1.9-5/8” x 13-3/8” Primary cement job a.Pump 80 bbls 13.5 ppg tuned spacer, 270 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail. Planned TOC was ~6,820’ MD. b.Displace with rig pumps, adjusƟng rate to manage losses. Total losses from cement exit shoe to cement in place = 75 bbls. 2.9-5/8” Secondary Cement Job - stage collar located at base of Tuluvak formaƟon (5,140' MD) a.RIH and open up the Archer CŇex cement tool. Establish circulaƟon and pump 80 bbls 12.5 ppg Mud Flush spacer, 80 bbls of 13.5 ppg Tuned Spacer, 305 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. Slight losses reported but reduced with lower displacement rate. The LTP was set and 104 bbls of contaminated cement was circulated to surface while circulating with the Cflex running tool. 3.9-5/8” Cement EvaluaƟon Logs a.Baker SoundTrak CBL tool was used to log cement aŌer drilling the ProducƟon Hole. The 9-5/8” 1st stage cement was logged showing the TOC of the primary job at 7,739' MD. Top of hydrocarbon bearing zone in the Nanushuk was in the NT7 at 7,857' MD. CBL also showed adequate isolation throughout the Tuluvak with the 2nd stage cement job.2/14/24, 9-5/8" casing pressure tested to 4190 psi for 30 minutesNDBi-046 ACTIVE9-5/8" 47ppf11,166' (Nanushuk)3,733' (Nanushuk) 10255 3,615 logopen hole liner for productionTOC 10,255' & packer @ 12,572'9-5/8” x 13-3/8” Primary cement job- Pump 5 bbls water & pressure test cement lines to 1,000 psi low, 5,000 psi high.- Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol at 3.7-4 bpm, release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 197 bbls at 4 bpm, release top pump down plug, chase with 20 bbls of water from Halliburton. Perform displacement with rig pumps, displace with 11.8 ppg OBM at 4 bpm, ICP 395 psi 8% flow, FCP 596 psi, 2% return flow, reduce rate to 3 bpm prior to plug bump: Final circulating pressure 596 psi. pressured up 500 psi over FCP 1,080 psi. Held 5 min, bled off checked floats. Floats held. CIP @ 12:45 hrs.- Total losses from cement exit shoe to cement in place: 43 bbls.Cement Evaluation Results: See attached interpretation. TOC was found to be 911’ above the Top of the Nanushuk Pool (11,166’ MD) at 10,255’ MD. Cement isolation from the TOC down to the casing show was found to be in good quality ranging down to partial coverage in limited areas. 07/11/24, 9-5/8" casing pressure tested to 3,667 psi for 30 minutes Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensil e (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design x 13-3/8” Casing Shoe: 3,218’ MD x 9-5/8” x 13-3/8” Liner top: 3,063’ MD x 9-5/8” Liner Shoe: 11,560 MD x 9-5/8” Archer Cflex Mechanical Stage tool: 5,678’ MD Geology x Top of Tuluvak TS 790 formation at 5,593’ MD. Significant hydrocarbons are contained only within the upper Tuluvak in the Tuluvak Sand (4,218 MD). x Top of the Nanushuk picked at 10,178’ MD. Cement Job Planning/Execution See attached cementing reports starting on the next page for a summary of the work performed. Observations The top of cement was found to be 928’ above the Top of the Nanushuk Pool (10,178’ MD) at 9,250’ MD. Cement isolation from the top of cement down to the casing shoe was found to be in good quality ranging down to partial coverage in some areas. See attached interpretation from the Baker Hughes SoundTrak Cement Bond Log Evaluation Report. Page 1 of 1 Well Name: NDB-051 Cement Surface Casing Cement Surface Casing Cement, Casing, 5/6/2024 15:00 Type Casing Cementing Start Date 5/6/2024 Cementing End Date 5/6/2024 Wellbore Original Hole String Surface Casing, 3,218.8ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 200 bbls of clean cement returned to surface. Comment Cement 13-3/8” Surface Casing as follows: -M/U cement hose, PJSM with 3rd party and all rig personnel -Fill lines with water and pressure test to 3,500 psi for 3 minutes -Drop 1st Bottom Non-Rotating Plug -Pump 80 bbls of 10.5 ppg Tuned Spacer at 6 bpm, 391 psi. -Release 2nd Bottom Non-Rotating Plug -Pump 452 bbls of 11.0 ppg ArcticCem lead cement at 6 bpm, Excess Volume 200% (1,002 sacks, yield 2.535 cu.ft/sk) -Pump 72 bbls of 15.3 ppg Type I/II tail at 3.7 bpm, Excess Volume 50% (310 sacks, yield 1.24 cu.ft/sk) -Drop top plug and chasse with 2 bbls Tail Cement -Perform displacement with rig pumps and 10.0 ppg mud -410 bbls displaced at 6 bpm: ICP 181 psi 10% return flow, FCP 757 psi 5% return flow. -33 bbls displaced at 3 bpm: ICP 540 psi 5% return flow, FCP 525 psi 5% return flow. -Reduce rate to 3 bpm prior to plug bump: Final circulating pressure 525 psi prior to plug bump. -Bump plug and increase pressure to 1,140 psi, check floats – good. -Total displacement volume 443 bbls (measured by strokes at 96% pump efficiency). -Observed 82 bbls of mud / tuned spacer contaminated returns, 63 bbls of cement / Tuned Spacer contaminated returns, and 200 bbls clean cement to surface. A total of 345 bbls were dumped to the cuttings box. -Total losses from cement exit shoe to cement in place: 0 bbls. - CIP at 2030 hrs. 1, 0.0-3,228.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 3,228.0 Full Return? Yes Vol Cement Ret (bbl) 200.0 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) 525.0 Plug Bump Pressure (psi) 525.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Lead Fluid Type Lead Fluid Description ArcticCem Amount (sacks) 1,002 Class I/II Volume Pumped (bbl) 452.0 Estimated Top (ftKB) 0.0 Percent Excess Pumped (%) 200.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) 0.00 Density (lb/gal) 11.00 Plastic Viscosity (cP) 18.0 Thickening Time (hr) 13.39 1st Compressive Strength (psi) 750.0 CmprStr Time 1 (hr) 129.00 Tail Fluid Type Tail Fluid Description Type I/II Amount (sacks) 310 Class Type I/II Volume Pumped (bbl) 72.0 Estimated Top (ftKB) Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 23.3 Thickening Time (hr) 6.34 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 11.40 Page 1 of 1 Well Name: NDB-051 Cement 1st Stage 9-5/8" Liner Cement 1st Stage 9-5/8" Liner Cement, Casing, 5/21/2024 03:35 Type Casing Cementing Start Date 5/21/2024 Cementing End Date 5/21/2024 Wellbore Original Hole String Intermediate Liner, 11,560.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Evaluation Results Comment Conduct 1st Stage Cement Job of 9-5/8”, 47#, L-80, Hyd 563 Liner. -Pressure test cement lines to 5000 psi. -Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 2.9-3 bpm, 93% returns. -Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 2.9-3 bpm, Excess Volume 30% (839 sacks, yield 1.237 cu.ft/sk), initial circulating pressure 440 psi. -Added 300 lbs of Halliburton Bridgemaker II LCM to cement: 10 bbls neat cement ahead, 60 bbls with LCM added, 115 bbls of neat cement. -Land dart at 69 bbls away at 2.9 bpm at latch (1.5 bbls behind as calculated), clear indication of latch and release at 1000 psi. -Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 185 bbls at average of 2.9 bpm, 235-400 psi, excess volume 30% (839 sacks, yield 1.237 cu ft/sk). -Release top pump down plug, chase with 20 bbls of washup from Halliburton. -Perform displacement with rig pumps, displace with 11.8 ppg OBM at 2.5 bpm, ICP 272 psi 1% return flow, FCP 600 psi 7% return flow. -Top pump down dart latch up confirmed at 45 bbls displaced. -Continue to displace with 11.8 ppg OBM, reduce rate to 2.5 bpm prior to plug bump: Final circulating pressure 600 psi. -Total displacement volume 656 bbls (measured by strokes at 96% pump efficiency). -Total losses from cement exit shoe to cement in place: 52 bbls w/4 bbls bleed back. 1, 8,352.0-11,560.0ftKB Top Depth (ftKB) 8,352.0 Bottom Depth (ftKB) 11,560.0 Full Return? No Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 3 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 3 Final Pump Pressure (psi) 286.0 Plug Bump Pressure (psi) 602.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail Amount (sacks) 840 Class I/II Volume Pumped (bbl) 185.0 Estimated Top (ftKB) Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 122.3 Thickening Time (hr) 5.28 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 9.11 Page 1 of 1 Well Name: NDB-051 Cement 2nd Stage 9-5/8" Liner Cement 2nd Stage 9-5/8" Liner Cement, Casing, 5/22/2024 03:40 Type Casing Cementing Start Date 5/22/2024 Cementing End Date 5/22/2024 Wellbore Original Hole String Intermediate Liner, 11,560.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 41 bbls contaminated cement returns to surface. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 5691’ (center of circulation port) as follows: -Mix and pump 80 bbls of 12.5 ppg Mud Push Spacer at 4 bpm, 90% returns (both spacers with Surfactant B and Musol A). -Mix and pump 80 bbls of 13.5 ppg Tuned Spacer at 4 bpm, 230 psi, full returns. -Mix and pump 284 bbls of 15.3 ppg Versacem Type I-II Tail cement at 3.85 bpm initial, ICP 450 psi, FCP 285 psi at 3 bpm -Excess Volume 100% (1288 sacks, yield 1.237 cu ft/sk). Displace Cement from 9-5/8” 47# Intermediate casing, 2nd Stage. -Displace to calculated volume of 132 bbls to Archer Stage Collar. -Begin displacing with 20 bbls fresh water from cementing unit. -Continue to displace using rig pumps with 112 bbls, 11.8 ppg OBM. -Stage up to 4 bpm, 860 psi ICP , 7% flow returns; 4 bpm 875 psi FCP. -Slow displacement to 3 bpm, 640 psi, last 10 bbls. -0 bbls lost during displacement -CIP at 06:12 hrs 2, 3,069.0-5,678.0ftKB Top Depth (ftKB) 3,069.0 Bottom Depth (ftKB) 5,678.0 Full Return? No Vol Cement Ret (bbl) 41.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 3 Final Pump Pressure (psi) 285.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Mud Push Spacer with 8 LBS of Red Dye, 65 Gal of Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.86 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Spacer Fluid Type Spacer Fluid Description Tuned Spacer with 4 LBS of Red Dye, 65 Gal of Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 0.00 Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 1,289 Class I/II Volume Pumped (bbl) 284.0 Estimated Top (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 5.56 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 27.20 Attachment D Attachment E Attachment F Well NameNDB-5107/15/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbFPcWF 253.54040168016804040d Pump CheckWF25 4035039014700163803503900390390 0 16380 0 390 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Line out XL XL 25214040430168018060004043020Drop Stage 1 Ball/Collet FP 0213434331261818600CSG-IV343330Stage 1 PADXL 2540 231274 6649702 2788800 23166440Slow for Seat XL 251850324 7142100 2998800 5071450Resume PadXL 2540 44368 7581848 3183600 4475861FlatXL 2540 200568 9588400 402368043 8043CSG-IV191 94973FlatXL 2540 200768 11588400 4863622238 30280CSG-IV176 112685FlatXL 2540 230998 13889660 5829639525 69805CSG-IV188 131497FlatXL 2540 2301228 16189660 6795651585 121390CSG-IV175 1490109FlatXL 2540 2151443 18339030 7698658065 179455CSG-IV154 16431110FlatXL 2540 1801623 20137560 8454652353 231808CSG-IV125 1768120Clear Surface LinesXL 2540 201643 2033840 853860231808 201788130Spacer XL 2540101653 2043420 858060231808 101798140Drop Stage 2 Ball/Collet FP 04031656 2046126 859320 231808 3 1801150Stage 2XL 2540 2221878 22689324 952560 231808 222 2023160Slow for Seat XL 2518501928 23182100 973560231808 502073170Resume PadXL 2540 281956 23461176 985320231808 282101181FlatXL 2540 1602116 25066720 1052526434 238242CSG-IV153 2254192FlatXL 2540 1602276 26666720 11197212344 250586CSG-IV147 2401204FlatXL 2540 1802456 28467560 11953225679 276265CSG-IV153 2554216FlatXL 2540 1802636 30267560 12709235817 312082CSG-IV142 2696228FlatXL 2540 1802816 32067560 13465244627 356709CSG-IV133 28292310FlatXL 2540 1802996 33867560 14221252353 409062CSG-IV125 29542412FlatXL 2540 1603156 35466720 14893252608 461669CSG-IV104 3058250Clear Surface LinesXL 2540 203176 3566840 1497720461669 203078260Spacer XL 2540103186 3576420 1501920461669 103088270Drop Stage 3 Ball/Collet FP 04033189 3579126 1503180 461669 3 3091280Stage 3XL 2540 2133402 37928946 1592640 461669 213 3304290Slow for Seat XL 2518503452 38422100 1613640461669 503354300Resume PadXL 2540 373489 38791554 1629180461669 373391311FlatXL 2540 1803669 40597560 1704787239 468908CSG-IV172 3563322FlatXL 2540 2003869 42598400 17887815430 484338CSG-IV184 3747334FlatXL 2540 2254094 44849450 18832832099 516436CSG-IV191 3938346FlatXL 2540 2254319 47099450 19777844772 561208CSG-IV178 4116FLUIDNeat WaterCOMMENTSSD monitor 30 min, line up for XLPrime and Pressure TestOpen well and open initiator sleeveDisplace PT- Shut down 10 minLoad Stage 1 ball/collet, Well NameNDB-5107/15/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water358FlatXL 2540 2254544 49349450 20722855783 616991CSG-IV166 42823610FlatXL 2540 1754719 51097350 21457850899 667890CSG-IV121 44033712FlatXL 2540 1504869 52596300 22087849320 717209CSG-IV98 4501380Clear Surface LinesXL 2540 204889 5279840 2217180717209 204521390Spacer XL 2540104899 5289420 2221380717209 104531400Drop Stage 4 Ball/Collet FP 04034902 5292126 2222640 717209 3 4534410Stage 4XL 2540 2055107 54978610 2308740 717209 205 4739420Slow for Seat XL 2518495156 55462058 2329320717209 494788430Resume PadXL 2540 15157 554742 2329740 717209 1 4789441ScourXL 2540 605217 56072520 2354942413 71962340/7057 4846453ScourXL 2540 1205337 57275040 24053413348 73297140/70106 4952460Resume PadXL 2540 505387 57772100 2426340732971 505002471FlatXL 2540 1805567 59577560 2501947239 740209CSG-IV172 5174482FlatXL 2540 2205787 61779240 25943416973 757182CSG-IV202 5377494FlatXL 2540 2406027 641710080 26951434239 791420CSG-IV204 5580506FlatXL 2540 2406267 665710080 27959447756 839177CSG-IV190 5770518FlatXL 2540 2406507 689710080 28967459502 898679CSG-IV177 59475210FlatXL 2540 2006707 70978400 29807458170 956849CSG-IV138 6085530Clear Surface LinesXL 2540 206727 7117840 2989140956849 206105540Spacer XL 2540106737 7127420 2993340956849 106115550Drop Stage 5 Ball/Collet FP 04036740 7130126 2994600 956849 3 6118560XL FlushXL 2540 256765 71551050 3005100956849 256143570WF FlushWF 2540 1706935 73257140 3076500 956849 170 6313580Slow for seat WF 2518506985 73752100 3097500956849 506363590MiniFrac & MT PCMWF 2540 2007185 75758400 3181500 956849 200 656303181500656360Linear FlushWF 252017186617842 3181921 656461Linear FlushWF 252017187617942 3182341 6565623000 feet MD + Surface EqmtFP20 487235 62271995 320229TOTALS7625 320229956849 Well NameNDB-5107/15/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbFPcWF 253.54040168016804040040dPump Ball to seatWF 254225265 9450 11130225265ePump CheckWF 2540120385 5040 16170 120 385 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Stage 5 PADXL 254025025063510500266700025063521ScourXL 2540603106952520291902413241340/705769233ScourXL 2540 120430 8155040 3423013348 1576140/70106 79840Resume PadXL 2540 50480 8652100 363300 15761 50 84851FlatXL 2540 180660 10457560 438907239 23000CSG-IV172 102163FlatXL 2540 200860 12458400 5229022238 45238CSG-IV176 119775FlatXL 2540 2301090 14759660 6195039525 84762CSG-IV188 138587FlatXL 2540 2301320 17059660 7161051585 136348CSG-IV175 156199FlatXL 2540 2151535 19209030 8064058065 194412CSG-IV154 17151010FlatXL 2540 1801715 21007560 8820052353 246765CSG-IV125 1839110Clear Surface LinesXL 2540 201735 2120840 890400 246765 20 1859120Spacer XL 2540101745 2130420 894600 246765 10 1869130Drop Stage 6 Ball/Collet FP 04031748 2133126 895860246765 31872140Stage 6XL 2540 1871935 23207854 974400 246765 187 2059150Slow for Seat XL 2518501985 23702100 995400246765 502109160Resume PadXL 2540 131998 2383546 1000860246765 132122171ScourXL 2540 602058 24432520 1026062413 24917840/7057 2180183ScourXL 2540 1202178 25635040 10764613348 26252640/70106 2286190Resume PadXL 2540 502228 26132100 1097460262526 502336201FlatXL 2540 1802408 27937560 1173067239 269765CSG-IV172 2508212FlatXL 2540 2002608 29938400 12570615430 285195CSG-IV184 2692224FlatXL 2540 2202828 32139240 13494631385 316580CSG-IV187 2878236FlatXL 2540 2203048 34339240 14418643777 360357CSG-IV174 3052248FlatXL 2540 2203268 36539240 15342654544 414900CSG-IV162 32142510FlatXL 2540 2003468 38538400 16182658170 473070CSG-IV138 33532612FlatXL 2540 1803648 40337560 16938659183 532254CSG-IV117 3470270Clear Surface LinesXL 2540 203668 4053840 1702260532254 203490280Spacer XL 2540103678 4063420 1706460532254 103500290Drop Stage 7 Ball/Collet FP 04033681 4066126 1707720532254 33503300Stage 7XL 2540 1783859 42447476 1782480 532254 178 3681310Slow for Seat XL 2518503909 42942100 1803480532254 503731320Resume PadXL 2540 23911 429684 1804320532254 23733331ScourXL 2540 603971 43562520 1829522413 53466740/7057 3791FLUIDNeat WaterCOMMENTSStart XL- Stage to Stage 5Prime and Pressure TestOpen well and line up to displace PTDisplace PT past WHDrop Ball- SD 10 min Well NameNDB-5107/15/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water343ScourXL 2540 1204091 44765040 18799213348 54801540/70106 3897350Resume PadXL 2540 504141 45262100 1900920548015 503947361FlatXL 2540 1804321 47067560 1976527239 555254CSG-IV172 4119373FlatXL 2540 2004521 49068400 20605222238 577491CSG-IV176 4296385FlatXL 2540 2304751 51369660 21571239525 617016CSG-IV188 4484397FlatXL 2540 2304981 53669660 22537251585 668601CSG-IV175 4659409FlatXL 2540 2155196 55819030 23440258065 726666CSG-IV154 48134110FlatXL 2540 555251 56362310 23671215997 742663CSG-IV38 48514210FlatXL 2540 1255376 57615250 24196236396 77905812/1887 4938430Clear Surface LinesXL 2540 205396 5781840 2428020779058 204958440Spacer XL 2540105406 5791420 2432220779058 104968450Drop Stage 8 Ball/Collet FP 04035409 5794126 2433480779058 34971460XL FlushXL 2540 255434 58191050 2443980779058 254996470WF FlushWF 2540 1445578 59636048 2504460 779058 144 5140480Slow for Seat WF 2518505628 60132100 2525460779058 505190490Overflush (MiniFrac)WF 2540 2005828 62138400 2609460 779058 200 539002609460539050Linear FlushWF 25201 5829 601442 2609881 539151Linear FlushWF 25201 5830 601542 2610301 5392523000 feet MD + Surface EqmtFP20 485878 60631995 263025TOTALS6263 263025779058 Well NameNDB-5107/15/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbFPcWF 253.54040168016804040040dPump Ball to seatWF 254200240 8400 10080200240ePump CheckWF 2540120360 5040 15120 120 360 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGEAVERAGEFLUIDRATESTAGECUMTOT JOBSTAGECUMSTAGECUM Size orStageCum#PPATYPE(BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type(BBL)(BBL)10Stage 8 PADXL 254025025061010500256200025061021ScourXL 2540603106702520281402413241340/705766733ScourXL 2540 120430 7905040 3318013348 1576140/70106 77340Resume PadXL 2540 50480 8402100 352800 15761 50 82351FlatXL 2540 205685 10458610 438908244 24005CSG-IV196 102063FlatXL 2540 205890 12508610 5250022794 46799CSG-IV181 120175FlatXL 2540 2801170 153011760 6426048117 94916CSG-IV229 143087FlatXL 2540 2551425 178510710 7497057193 152108CSG-IV195 162499FlatXL 2540 2551680 204010710 8568068867 220976CSG-IV182 18061010FlatXL 2540 1051785 21454410 9009030539 251515CSG-IV73 18791110FlatXL 2540 1201905 22655040 9513034940 28645512/1883 1962120Clear Surface LinesXL 2540 201925 2285840 959700 286455 20 1982130Spacer XL 2540101935 2295420 963900 286455 10 1992140Drop Stage 9 Ball/Collet FP 04031938 2298126 965160286455 31995150Stage 9XL 2540 1602098 24586720 1032360 286455 160 2155160Slow for Seat XL 2518502148 25082100 1053360286455 502205170Resume PadXL 2540 902238 25983780 1091160286455 902295181FlatXL 2540 1802418 27787560 1166767239 293693CSG-IV172 2468192FlatXL 2540 2002618 29788400 12507615430 309123CSG-IV184 2651204FlatXL 2540 2202838 31989240 13431631385 340508CSG-IV187 2838216FlatXL 2540 2203058 34189240 14355643777 384285CSG-IV174 3012228FlatXL 2540 2203278 36389240 15279654544 438829CSG-IV162 31742310FlatXL 2540 2003478 38388400 16119658170 496999CSG-IV138 33132412FlatXL 2540 703548 39082940 16413623016 520014CSG-IV46 33582512FlatXL 2540 1103658 40184620 16875636212 55622712/1872 3430260Clear Surface LinesXL 2540 203678 4038840 1695960556227 203450270Spacer XL 2540103688 4048420 1700160556227 103460280Drop Stage 10 Ball/Collet FP 04033691 4051126 1701420556227 33463290Stage 10XL 2540 1513842 42026342 1764840 556227 151 3614300Slow for Seat XL 2518503892 42522100 1785840556227 503664310Resume PadXL 2540 743966 43263108 1816920556227 743738321FlatXL 2540 1804146 45067560 1892527239 563465CSG-IV172 3911332FlatXL 2540 2004346 47068400 19765215430 578895CSG-IV184 4094FLUIDNeat WaterCOMMENTSStart XL- Stage to Stage 8Prime and Pressure TestOpen well and line up to displace PTDisplace PT past WHDrop Ball- SD 10 min Well NameNDB-5107/15/24 Preliminary DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT#TYPEPPTRATESTAGECUMSTAGE CUMSTAGECUM SIZEStageCumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water344FlatXL 2540 2204566 49269240 20689231385 610280CSG-IV187 4281356FlatXL 2540 2204786 51469240 21613243777 654057CSG-IV174 4455368FlatXL 2540 2205006 53669240 22537254544 708601CSG-IV162 46173710FlatXL 2540 1905196 55567980 23335255261 763862CSG-IV132 47493812FlatXL 2540 655261 56212730 23608221372 785234CSG-IV42 47913912FlatXL 2540 1105371 57314620 24070236212 82144612/1872 486302407020486340XL FlushXL 252010 5381 5741420 24112210 487341Linear FlushWF 2520121 5502 58625082 246204121 4994423000 feet MD + Surface EqmtFP20 485550 59101995 248199TOTALS5910 248199821446 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 709.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 355.0 gal J475 Breaker J475 6.0 lb/mGal 4,254.0 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,418.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,559.0 gal J580 Gel J580 25.0 lb/mGal 17,725.0 lbm J753 Enzyme Breaker J753 0.0 Gal/mGal 35.0 gal M117 Clay Control Agent 339.0 lb/mGal 240,340.1 lbm M275 Bactericide 0.3 lb/mGal 213.0 lbm S522-1218 Propping Agent varied concentrations 143,760.0 lbm S522-1620 Propping Agent varied concentrations 2,241,395.0 lbm S522-4070 Propping Agent varied concentrations 78,806.0 lbm S901 Proppant with Scale Inhibitor S901 varied concentrations 93,392.0 lbm ~ 67 % ~ 30 % ~ 3 % < 1 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % Total 100 % * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. Total 64-19-7 Acetic acid (impurity) 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 532-32-1 Sodium benzoate 7786-30-3 Magnesium chloride 127-08-2 Acetic acid, potassium salt (impurity) 9000-90-2 Amylase, alpha 9002-84-0 poly(tetrafluoroethylene) 14807-96-6 Magnesium silicate hydrate (talc) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 68131-39-5 Ethoxylated Alcohol 9025-56-3 Hemicellulase 91053-39-3 Diatomaceous earth, calcined 67-63-0 Propan-2-ol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 9003-35-4 Phenolic resin 50-70-4 Sorbitol 111-76-2 2-butoxyethanol 7727-54-0 Diammonium peroxodisulphate 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate 7647-14-5 Sodium chloride 102-71-6 2,2`,2"-nitrilotriethanol 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF125 ST:WF125 709,002 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-1896 Fluid Name & Volume Concentration Volume Disclosure Type:Pre-Job Well Completed: Date Prepared:7/25/2024 State:Alaska County/Parish:North Slope Borough Case: Client:Oil Search Alaska Well:NDB-051 Basin/Field:Pikka # SLB-Private Page: 1 / 1 INPUTTBDAK TSCA StatusTBDPreTrade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SMETracercoCarrier FluidSoy Methyl Ester67784-80-9100#DIV/0!69.004606T-166ATracercoChemical Tracer5-Iodo-m-xylene22445-41-6100#DIV/0!1.10231T-729TracercoChemical Tracer1,4-Dibromo-2,5-dimethyl benzene1074-24-4100#DIV/0!2.20462T-731TracercoChemical Tracer1-Bromo-3,5-dichlorobenzene19752-55-7100#DIV/0!0.440924T-161BTracercoChemical Tracer4-Iodotoluene624-31-7100#DIV/0!0.440924T-164BTracercoChemical Tracer2-Bromonaphthalene580-13-2100#DIV/0!1.10231T-706TracercoChemical Tracer1-Bromo-4-chlorobenzen106-39-8100#DIV/0!2.20462T-776TracercoChemical Tracer1,4-Dibromonaphthalene83-53-4100#DIV/0!0.661386T-719TracercoChemical Tracer3,4-Dichlorobenzophenone6284-79-3100#DIV/0!0.440924T-720TracercoChemical Tracer1,2,4,5-Tetrabromobenzene636-28-2100#DIV/0!0.440924T-165CTracercoChemical Tracer9-Bromophenanthrene573-17-1100#DIV/0!0.661386WaterTracercoCarrier FluidWater7732-18-5100#DIV/0!68.34322T-158CTracercoChemical TracerSodium-2,6-Difluorobenzoate6185-28-0100#DIV/0!0.771617T-808TracercoChemical TracerSodium-3,4-dichlorobenzoate17274-10-1100#DIV/0!0.771617T-913TracercoChemical TracerSodium-2-chloro-6-fluorobenzoate1382106-10-6100#DIV/0!0.771617T-911TracercoChemical TracerSodium-2-chloro-4-fluorobenzoate885471-43-1100#DIV/0!0.771617T-158ETracercoChemical TracerSodium-3,5-Difluorobenzoate530141-39-0100#DIV/0!0.771617T-928TracercoChemical TracerSodium-2-fluoro-4-methylbenzoate1708942-19-1100#DIV/0!0.771617T-176CTracercoChemical TracerSodium-2,4,5-trifluorobenzoate522651-48-5100#DIV/0!0.771617T-190ATracercoChemical TracerSodium-2-(Trifluoromethyl) benzoate2966-44-1100#DIV/0!0.771617T-809TracercoChemical TracerSodium-3,5-dichlorobenzoate154862-40-5100#DIV/0!0.771617T-921TracercoChemical TracerSodium-3-chloro-2-fluorobenzoate1421029-89-1100#DIV/0!0.771617Sodium FluoresceinTracercoChemical TracerSodium Fluorescein 518-47-8 100#DIV/0!1.10231Rhodamine WTTracercoChemical TracerRhodamine WT 37299-86-8 100#DIV/0!1.10231Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState:Approved For TracercoReport Type (Pre or Post Job)Total Water Volume (gal):Total Mass Pumped (lbs)County:API Number:Operator Name: Santos AKWell Name and Number: NDB-051 Attachment G NDB-051 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: x Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. x Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. x Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. x Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. x Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 g Attachment H NDB-051 4-1/2” Production Liner Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P-110S TSH563 lower completions per tally. 2. Circulate out 10.0 ppg OBM with 10.0 ppg NaCl/KCl brine to surface. 3. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 4. Pressure up to close the WIV at 1,980 psi. 5. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 6. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi for 10 minutes. 7. Release running tool from liner hanger. 8. Circulate 9.4 ppg NaCl Corrosion Inhibited brine with biocide to surface at 10 bpm pump rate. 9. POOH with liner hanger running tool. 10.Prepare to run upper completion. NDB-051 4-1/2” Upper Completion Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 2. Land tubing hanger. 3. MIT-T to 4,000 psi. (Post Rig Move, MIT-T was tested to 6,200 psi on 7/27/24. Passed MIT-T) a. (8,900 psi MAWP – 3,300 psi IA hold) * 1.1 = 6,160psi 4. MIT-IA to 4,000 psi. (Post Rig, MIT-IA was tested to 3,800 psi on 7/27/24. Passed MIT-IA) 5. Shear circulation valve. 6. Reverse circulate freeze protect and U-Tube. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k frac tree. 9. RDMO NDB-051 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment I Attachment J Attachment K FracCADE* STIMULATION PROPOSAL KƉĞƌĂƚŽƌ ͗Kŝů^ĞĂƌĐŚ tĞůů ͗EͲϬϱϭ &ŝĞůĚ ͗WŝŬŬĂ &ŽƌŵĂƚŝŽŶ ͗EĂŶƵƐŚƵŬ ^ƚĂŐĞƐϭƚŽϭϬ ŽƵŶƚLJ ͗EŽƌƚŚ^ůŽƉĞ ^ƚĂƚĞ ͗ůĂƐŬĂ ŽƵŶƚƌLJ ͗hŶŝƚĞĚ^ƚĂƚĞƐ WƌĞƉĂƌĞĚĨŽƌ͗^ĐŽƚƚ>ĞĂŚLJ ^ĞƌǀŝĐĞWŽŝŶƚ͗WƌƵĚŚŽĞĂLJ͕ůĂƐŬĂ ƵƐŝŶĞƐƐWŚŽŶĞ͗ϭϵϬϳϲϱϵϮϰϯϰ ĂƚĞWƌĞƉĂƌĞĚ͗ϬϳͲϮϵͲϮϬϮϰ &yEŽ͗͘ϭϵϬϳϲϱϵϮϱϯϴ WƌĞƉĂƌĞĚďLJ ͗>ĂƵƌĂĐŽƐƚĂ WŚŽŶĞ ͗ϴϯϮͲϰϱϰͲϭϰϮϳ ͲDĂŝůĚĚƌĞƐƐ ͗EdƌĞǀŝŶŽϮΛƐůď͘ĐŽŵ * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. ϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 1: Zone Data (Stage 1; 17172 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϰϴ͘ϰ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϮϱϬϬ ^ŚĂůĞ ϰϬϱϴ͘ϰ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϴϮϲ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϮϱϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϳϯ͘ϰ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϲϳ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϮϬϬϬ dŽƉEĂŶ ϰϬϴϴ͘ϳ ϲ͘Ϭ Ϭ͘ϲϰ ϮϲϯϬ ϴ͘ϯϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϵϰ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϴϱϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϬϵϲ͘ϳ ϭ͘ϱ Ϭ͘ϲϯ Ϯϱϴϰ ϴ͘ϭϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϬϵϴ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϲϭϱ ϭ͘ϮϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϬϬ͘Ϯ ϭϯ͘Ϭ Ϭ͘ϲϮ ϮϱϲϮ ϴ͘ϲϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϭϯ͘Ϯ ϭ͘ϱ Ϭ͘ϲϭ ϮϱϮϰ ϭ͘ϬϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϭϰ͘ϳ ϰ͘Ϭ Ϭ͘ϲϰ ϮϲϯϬ ϳ͘Ϭϳ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϭϴ͘ϳ ϵ͘Ϭ Ϭ͘ϲϭ ϮϱϬϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϮϳ͘ϳ ϳ͘Ϭ Ϭ͘ϲϰ Ϯϲϱϵ ϳ͘ϲϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϯϰ͘ϳ ϱ͘ϱ Ϭ͘ϲϭ Ϯϱϰϯ ϭ͘Ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϰϬ͘Ϯ ϭϯ͘Ϭ Ϭ͘ϲϰ Ϯϲϲϱ ϲ͘ϵϮ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϱϯ͘Ϯ Ϯ͘ϱ Ϭ͘ϲϴ Ϯϴϭϳ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϱ͘ϳ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϰϵ ϭ͘ϭϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϲϴ͘Ϯ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϴϵϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϮ͘Ϯ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϳϱ ϴ͘ϮϮ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϭϳϰ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϭϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϳϲ͘ϳ ϰ͘Ϭ Ϭ͘ϲϱ ϮϳϭϬ ϭ͘ϭϲ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϴϬ͘ϳ ϰ͘Ϭ Ϭ͘ϲϯ ϮϲϮϰ ϴ͘ϯϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϴϰ͘ϳ ϰ͘Ϭ Ϭ͘ϳϬ ϮϵϮϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϴϴ͘ϳ ϲ͘Ϭ Ϭ͘ϲϰ ϮϲϴϮ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϭϵϰ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϵϲ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϭ͘Ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϵϴ͘ϳ ϲ͘ϱ Ϭ͘ϲϲ Ϯϳϴϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϬϱ͘Ϯ ϰ͘Ϭ Ϭ͘ϲϭ Ϯϱϳϲ ϴ͘ϵϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϬϵ͘Ϯ ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϭϭ ϵ͘Ϯϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϭϮ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϯϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϭϰ͘ϳ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϵϴ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϮϳ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϰϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϮϵ͘Ϯ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϯϭ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϱϱ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϯϯ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϵ Ϯϵϭϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϰϭ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϯ ϮϲϵϬ ϵ͘ϯϯ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϰϯ͘Ϯ ϰ͘Ϭ Ϭ͘ϳϬ Ϯϵϲϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϰϳ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϱ Ϯϳϰϲ ϭ͘ϰϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϱϯ͘Ϯ ϴ͘Ϭ Ϭ͘ϳϬ Ϯϵϲϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϲϭ͘Ϯ ϲ͘ϱ Ϭ͘ϲϱ Ϯϳϲϲ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϲϳ͘ϳ ϲ͘Ϭ Ϭ͘ϲϵ Ϯϵϰϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϳϯ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϳϮϲ ϴ͘ϯϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϮϳϱ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϳϳ͘ϳ ϰ͘Ϭ Ϭ͘ϲϱ ϮϳϴϮ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϴϭ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϴϯ͘ϳ ϲ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϵ ϭ͘ϱϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϴϵ͘ϳ ϭϮ͘Ϭ Ϭ͘ϳϬ Ϯϵϵϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϬϭ͘ϳ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϱϰ ϭ͘Ϯϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϰ͘Ϯ ϮϬ͘Ϭ Ϭ͘ϲϵ ϮϵϳϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Zone Name Poisson’s Ratio Formation Mechanical Properties Ϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4048.4 10.0 0.001 1.0 1881 4058.4 15.0 0.001 1.0 1886 4073.4 15.3 0.005 10.0 1890 4088.7 6.0 56.445 22.0 1882 4094.7 2.0 0.001 1.0 1884 4096.7 1.5 109.347 15.0 1885 4098.2 2.0 4.377 15.0 1886 4100.2 13.0 42.829 22.0 1887 4113.2 1.5 11.097 22.0 1893 4114.7 4.0 91.857 22.0 1894 4118.7 9.0 4.906 22.0 1896 4127.7 7.0 12.361 22.0 1900 4134.7 5.5 2.537 22.0 1903 4140.2 13.0 61.847 22.0 1906 4153.2 2.5 0.081 15.0 1912 4155.7 12.5 22.858 15.0 1913 4168.2 4.0 0.018 15.0 1919 4172.2 2.5 94.329 15.0 1920 4174.7 2.0 0.001 1.0 1922 4176.7 4.0 45.186 15.0 1922 4180.7 4.0 24.865 15.0 1924 4184.7 4.0 0.001 1.0 1926 4188.7 6.0 6.405 15.0 1928 4194.7 2.0 0.001 1.0 1931 4196.7 2.0 13.686 15.0 1932 4198.7 6.5 0.229 15.0 1933 4205.2 4.0 49.420 15.0 1936 4209.2 3.5 63.759 15.0 1938 4212.7 2.0 0.001 1.0 1939 4214.7 12.5 1.337 15.0 1940 4227.2 2.0 1.843 15.0 1946 4229.2 2.0 0.001 1.0 1947 4231.2 2.0 4.320 15.0 1948 4233.2 8.0 0.001 1.0 1949 4241.2 2.0 91.060 15.0 1952 4243.2 4.0 0.001 1.0 1953 4247.2 6.0 4.551 15.0 1955 4253.2 8.0 0.001 1.0 1958 4261.2 6.5 7.953 15.0 1962 4267.7 6.0 0.001 1.0 1965 4273.7 2.0 24.687 15.0 1967 4275.7 2.0 0.001 1.0 1968 4277.7 4.0 2.159 10.0 1969 4281.7 2.0 0.001 1.0 1971 4283.7 6.0 1.534 10.0 1972 4289.7 12.0 0.001 1.0 1975 4301.7 2.5 5.632 10.0 1980 4304.2 20.0 0.001 1.0 1982 Nan DS Nan DS Shale Nan CS Nan CS Nan CS Nan CS Nan CS Nan CS Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan Shale Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale ϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 2: Propped Fracture Schedule (Stage 1; 17172 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 325.0 25 0 1.0 PPA 40 YF125ST 191.5 25 1 3.0 PPA 40 YF125ST 176.5 25 3 5.0 PPA 40 YF125ST 188.2 25 5 7.0 PPA 40 YF125ST 175.5 25 7 9.0 PPA 40 YF125ST 153.6 25 9 10.0 PPA 40 YF125ST 124.7 25 10 Flush 40 YF125ST 260.6 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1595.6 bbl of YF125ST 0 bbl of WF125 231839 lb of 0 lb of % PAD Clean 24.3 % PAD Dirty 20.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 325.0 325 325 325 0 0 4319 8.1 8.1 1.0 PPA 191.5 517 200 525 8043 8043 4344 5.0 13.1 3.0 PPA 176.5 693 200 725 22239 30282 4556 5.0 18.1 5.0 PPA 188.2 881 230 955 39529 69811 5285 5.8 23.9 7.0 PPA 175.5 1057 230 1185 51592 121403 6055 5.8 29.6 9.0 PPA 153.6 1210 215 1400 58074 179477 6560 5.4 35.0 10.0 PPA 124.7 1335 180 1580 52362 231839 6802 4.5 39.5 Flush 260.6 1596 261 1841 0 231839 6122 6.5 46.0 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 457.1 ft with an average conductivity (Kfw) of 12513.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Fluid Totals Step Name Pad Percentages Job Execution Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Proppant Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV ϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 3: Propped Fracture Simulation (Stage 1; 17,172ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϰϵ͘ϮĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϮϵϬ͘ϲĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϱϳ͘ϭĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϭ͘ϱĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϰϱŝŶ EĞƚWƌĞƐƐƵƌĞ ϯϱϴƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϲϴϳϲƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 114.3 9.2 0.172 124.5 1.45 210.1 15772 114.3 228.6 6.8 0.168 194.2 1.45 229.5 14811 228.6 342.8 4.8 0.147 172.5 1.27 252.3 12670 342.8 457.1 2.1 0.1 121.2 0.93 364.3 8170 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 ϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 4: Zone Data (Stage 2; 16589 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϰϵ͘ϭ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϮϱϬϬ ^ŚĂůĞ ϰϬϱϵ͘ϭ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϴϮϲ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϮϱϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϳϰ͘ϭ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϲϳ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϮϬϬϬ dŽƉEĂŶ ϰϬϴϵ͘ϰ ϲ͘Ϭ Ϭ͘ϲϰ ϮϲϯϬ ϴ͘ϯϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϵϱ͘ϰ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϴϱϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϬϵϳ͘ϰ ϭ͘ϱ Ϭ͘ϲϯ Ϯϱϴϰ ϴ͘ϭϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϬϵϴ͘ϵ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϲϭϱ ϭ͘ϮϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϬϬ͘ϵ ϭϯ͘Ϭ Ϭ͘ϲϮ ϮϱϲϮ ϴ͘ϲϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϭϯ͘ϵ ϭ͘ϱ Ϭ͘ϲϭ ϮϱϮϰ ϭ͘ϬϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϭϱ͘ϰ ϰ͘Ϭ Ϭ͘ϲϰ ϮϲϯϬ ϳ͘Ϭϳ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϭϵ͘ϰ ϵ͘Ϭ Ϭ͘ϲϭ ϮϱϬϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϮϴ͘ϰ ϳ͘Ϭ Ϭ͘ϲϰ Ϯϲϱϵ ϳ͘ϲϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϯϱ͘ϰ ϱ͘ϱ Ϭ͘ϲϭ Ϯϱϰϯ ϭ͘Ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϰϬ͘ϵ ϭϯ͘Ϭ Ϭ͘ϲϰ Ϯϲϲϱ ϲ͘ϵϮ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϱϯ͘ϵ Ϯ͘ϱ Ϭ͘ϲϴ Ϯϴϭϳ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϲ͘ϰ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϰϵ ϭ͘ϭϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϲϴ͘ϵ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϴϵϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϮ͘ϵ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϳϱ ϴ͘ϮϮ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϭϳϱ͘ϰ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϭϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϳϳ͘ϰ ϰ͘Ϭ Ϭ͘ϲϱ ϮϳϭϬ ϭ͘ϭϲ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϴϭ͘ϰ ϰ͘Ϭ Ϭ͘ϲϯ ϮϲϮϰ ϴ͘ϯϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϴϱ͘ϰ ϰ͘Ϭ Ϭ͘ϳϬ ϮϵϮϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϴϵ͘ϰ ϲ͘Ϭ Ϭ͘ϲϰ ϮϲϴϮ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϭϵϱ͘ϰ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϵϳ͘ϰ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϭ͘Ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϵϵ͘ϰ ϲ͘ϱ Ϭ͘ϲϲ Ϯϳϴϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϬϱ͘ϵ ϰ͘Ϭ Ϭ͘ϲϭ Ϯϱϳϲ ϴ͘ϵϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϬϵ͘ϵ ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϭϭ ϵ͘Ϯϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϭϯ͘ϰ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϯϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϭϱ͘ϰ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϵϴ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϮϳ͘ϵ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϰϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϮϵ͘ϵ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϯϭ͘ϵ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϱϲ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϯϯ͘ϵ ϴ͘Ϭ Ϭ͘ϲϵ ϮϵϮϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϰϭ͘ϵ Ϯ͘Ϭ Ϭ͘ϲϯ ϮϲϵϬ ϵ͘ϯϯ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϰϯ͘ϵ ϰ͘Ϭ Ϭ͘ϳϬ Ϯϵϲϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϰϳ͘ϵ ϲ͘Ϭ Ϭ͘ϲϱ Ϯϳϰϲ ϭ͘ϰϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϱϯ͘ϵ ϴ͘Ϭ Ϭ͘ϳϬ Ϯϵϲϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϲϭ͘ϵ ϲ͘ϱ Ϭ͘ϲϱ Ϯϳϲϲ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϲϴ͘ϰ ϲ͘Ϭ Ϭ͘ϲϵ Ϯϵϰϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϳϰ͘ϰ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϳϮϲ ϴ͘ϯϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϮϳϲ͘ϰ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϳϴ͘ϰ ϰ͘Ϭ Ϭ͘ϲϱ ϮϳϴϮ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϴϮ͘ϰ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϴϰ͘ϰ ϲ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϵ ϭ͘ϱϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϵϬ͘ϰ ϭϮ͘Ϭ Ϭ͘ϳϬ Ϯϵϵϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϬϮ͘ϰ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϱϰ ϭ͘Ϯϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϰ͘ϵ ϮϬ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4049.1 10.0 0.001 1.0 1881 4059.1 15.0 0.001 1.0 1886 4074.1 15.3 0.005 10.0 1890 4089.4 6.0 56.445 22.0 1882 4095.4 2.0 0.001 1.0 1884 4097.4 1.5 109.347 15.0 1885 4098.9 2.0 4.377 15.0 1886 4100.9 13.0 42.829 22.0 1887 4113.9 1.5 11.097 22.0 1893 4115.4 4.0 91.857 22.0 1894 4119.4 9.0 4.906 22.0 1896 4128.4 7.0 12.361 22.0 1900 4135.4 5.5 2.537 22.0 1903 4140.9 13.0 61.847 22.0 1906 4153.9 2.5 0.081 15.0 1912 4156.4 12.5 22.858 15.0 1913 4168.9 4.0 0.018 15.0 1919 4172.9 2.5 94.329 15.0 1920 4175.4 2.0 0.001 1.0 1922 4177.4 4.0 45.186 15.0 1922 4181.4 4.0 24.865 15.0 1924 4185.4 4.0 0.001 1.0 1926 4189.4 6.0 6.405 15.0 1928 4195.4 2.0 0.001 1.0 1931 4197.4 2.0 13.686 15.0 1932 4199.4 6.5 0.229 15.0 1933 4205.9 4.0 49.420 15.0 1936 4209.9 3.5 63.759 15.0 1938 4213.4 2.0 0.001 1.0 1939 4215.4 12.5 1.337 15.0 1940 4227.9 2.0 1.843 15.0 1946 4229.9 2.0 0.001 1.0 1947 4231.9 2.0 4.320 15.0 1948 4233.9 8.0 0.001 1.0 1949 4241.9 2.0 91.060 15.0 1952 4243.9 4.0 0.001 1.0 1953 4247.9 6.0 4.551 15.0 1955 4253.9 8.0 0.001 1.0 1958 4261.9 6.5 7.953 15.0 1962 4268.4 6.0 0.001 1.0 1965 4274.4 2.0 24.687 15.0 1967 4276.4 2.0 0.001 1.0 1968 4278.4 4.0 2.159 10.0 1969 4282.4 2.0 0.001 1.0 1971 4284.4 6.0 1.534 10.0 1972 4290.4 12.0 0.001 1.0 1975 4302.4 2.5 5.632 10.0 1980 4304.9 20.0 0.001 1.0 1982 Nan CS Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS Nan DS Nan CS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Shale Nan DS Shale ϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 5: Propped Fracture Schedule (Stage 2; 16589 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 153.2 25 1 2.0 PPA 40 YF125ST 147.0 25 2 4.0 PPA 40 YF125ST 152.9 25 4 6.0 PPA 40 YF125ST 142.1 25 6 8.0 PPA 40 YF125ST 132.8 25 8 10.0 PPA 40 YF125ST 124.7 25 10 12.0 PPA 40 YF125ST 104.4 25 12 Flush 40 YF125ST 251.7 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1508.8 bbl of YF125ST 0 bbl of WF125 229894 lb of 0 lb of % PAD Clean 23.9 % PAD Dirty 20.0 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 4207 7.5 7.5 1.0 PPA 153.2 453 160 460 6434 6434 4231 4.0 11.5 2.0 PPA 147.0 600 160 620 12344 18779 4314 4.0 15.5 4.0 PPA 152.9 753 180 800 25681 44460 4688 4.5 20.0 6.0 PPA 142.1 895 180 980 35821 80281 5354 4.5 24.5 8.0 PPA 132.8 1028 180 1160 44633 124915 6048 4.5 29.0 10.0 PPA 124.7 1153 180 1340 52362 177276 6489 4.5 33.5 12.0 PPA 104.4 1257 160 1500 52618 229894 6687 4.0 37.5 Flush 251.7 1509 252 1752 0 229894 6042 6.3 43.8 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 407.9 ft with an average conductivity (Kfw) of 12801.6 md.ft. Job Description Fluid Name Prop. Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV ϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 6: Propped Fracture Simulation (Stage 2; 16589 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϰϴ͘ϮĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϮϵϯ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϬϳ͘ϵĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϱ͘ϲĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϱŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϯϱƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϲϳϴϮƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 102 11.1 0.187 131.8 1.53 186.7 16686 102 204 7.5 0.183 209.1 1.6 199.3 16020 204 305.9 4.7 0.149 182.2 1.35 241.7 12701 305.9 407.9 1.5 0.087 151.9 0.81 462.2 6818 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. ϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 7: Zone Data (Stage 3; 15965 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϱϭ͘ϱ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϮϱϬϬ ^ŚĂůĞ ϰϬϲϭ͘ϱ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϴϮϴ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϮϱϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϳϲ͘ϱ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϲϵ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϮϬϬϬ dŽƉEĂŶ ϰϬϵϭ͘ϴ ϲ͘Ϭ Ϭ͘ϲϰ ϮϲϯϬ ϴ͘ϯϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϵϳ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϴϱϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϬϵϵ͘ϴ ϭ͘ϱ Ϭ͘ϲϯ Ϯϱϴϰ ϴ͘ϭϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϬϭ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϲϭϱ ϭ͘ϮϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϬϯ͘ϯ ϭϯ͘Ϭ Ϭ͘ϲϮ ϮϱϲϮ ϴ͘ϲϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϭϲ͘ϯ ϭ͘ϱ Ϭ͘ϲϭ ϮϱϮϰ ϭ͘ϬϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϭϳ͘ϴ ϰ͘Ϭ Ϭ͘ϲϰ ϮϲϯϬ ϳ͘Ϭϳ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϮϭ͘ϴ ϵ͘Ϭ Ϭ͘ϲϭ ϮϱϬϱ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϯϬ͘ϴ ϳ͘Ϭ Ϭ͘ϲϰ Ϯϲϱϵ ϳ͘ϲϵ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϯϳ͘ϴ ϱ͘ϱ Ϭ͘ϲϭ Ϯϱϰϯ ϭ͘Ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϰϯ͘ϯ ϭϯ͘Ϭ Ϭ͘ϲϰ Ϯϲϲϱ ϲ͘ϵϮ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϱϲ͘ϯ Ϯ͘ϱ Ϭ͘ϲϴ Ϯϴϭϳ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϴ͘ϴ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϰϵ ϭ͘ϭϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϳϭ͘ϯ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϴϵϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϱ͘ϯ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϳϱ ϴ͘ϮϮ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϭϳϳ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϭϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϳϵ͘ϴ ϰ͘Ϭ Ϭ͘ϲϱ ϮϳϭϬ ϭ͘ϭϲ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϴϯ͘ϴ ϰ͘Ϭ Ϭ͘ϲϯ ϮϲϮϰ ϴ͘ϯϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϴϳ͘ϴ ϰ͘Ϭ Ϭ͘ϳϬ ϮϵϮϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϵϭ͘ϴ ϲ͘Ϭ Ϭ͘ϲϰ ϮϲϴϮ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϭϵϳ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϵϵ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϭ͘Ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϬϭ͘ϴ ϲ͘ϱ Ϭ͘ϲϲ Ϯϳϴϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϬϴ͘ϯ ϰ͘Ϭ Ϭ͘ϲϭ Ϯϱϳϲ ϴ͘ϵϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϭϮ͘ϯ ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϭϭ ϵ͘Ϯϵ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϭϱ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϯϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϭϳ͘ϴ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϵϴ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϯϬ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϰϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϯϮ͘ϯ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϯϰ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϱϳ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϯϲ͘ϯ ϴ͘Ϭ Ϭ͘ϲϵ ϮϵϮϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϰϰ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϯ ϮϲϵϬ ϵ͘ϯϯ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϰϲ͘ϯ ϰ͘Ϭ Ϭ͘ϳϬ Ϯϵϲϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϱϬ͘ϯ ϲ͘Ϭ Ϭ͘ϲϱ Ϯϳϰϴ ϭ͘ϰϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϱϲ͘ϯ ϴ͘Ϭ Ϭ͘ϳϬ Ϯϵϲϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϲϰ͘ϯ ϲ͘ϱ Ϭ͘ϲϱ Ϯϳϲϲ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϳϬ͘ϴ ϲ͘Ϭ Ϭ͘ϲϵ Ϯϵϰϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϳϲ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϳϮϲ ϴ͘ϯϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^ŚĂůĞ ϰϮϳϴ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϴϬ͘ϴ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϴϰ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϴϲ͘ϴ ϲ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϵ ϭ͘ϱϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϵϮ͘ϴ ϭϮ͘Ϭ Ϭ͘ϳϬ Ϯϵϵϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϬϰ͘ϴ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϱϰ ϭ͘Ϯϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϳ͘ϯ ϮϬ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϭϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4051.5 10.0 0.001 1.0 1881 4061.5 15.0 0.001 1.0 1886 4076.5 15.3 0.005 10.0 1890 4091.8 6.0 56.445 22.0 1882 4097.8 2.0 0.001 1.0 1884 4099.8 1.5 109.347 15.0 1885 4101.3 2.0 4.377 15.0 1886 4103.3 13.0 42.829 22.0 1887 4116.3 1.5 11.097 22.0 1893 4117.8 4.0 91.857 22.0 1894 4121.8 9.0 4.906 22.0 1896 4130.8 7.0 12.361 22.0 1900 4137.8 5.5 2.537 22.0 1903 4143.3 13.0 61.847 22.0 1906 4156.3 2.5 0.081 15.0 1912 4158.8 12.5 22.858 15.0 1913 4171.3 4.0 0.018 15.0 1919 4175.3 2.5 94.329 15.0 1920 4177.8 2.0 0.001 1.0 1922 4179.8 4.0 45.186 15.0 1922 4183.8 4.0 24.865 15.0 1924 4187.8 4.0 0.001 1.0 1926 4191.8 6.0 6.405 15.0 1928 4197.8 2.0 0.001 1.0 1931 4199.8 2.0 13.686 15.0 1932 4201.8 6.5 0.229 15.0 1933 4208.3 4.0 49.420 15.0 1936 4212.3 3.5 63.759 15.0 1938 4215.8 2.0 0.001 1.0 1939 4217.8 12.5 1.337 15.0 1940 4230.3 2.0 1.843 15.0 1946 4232.3 2.0 0.001 1.0 1947 4234.3 2.0 4.320 15.0 1948 4236.3 8.0 0.001 1.0 1949 4244.3 2.0 91.060 15.0 1952 4246.3 4.0 0.001 1.0 1953 4250.3 6.0 4.551 15.0 1955 4256.3 8.0 0.001 1.0 1958 4264.3 6.5 7.953 15.0 1962 4270.8 6.0 0.001 1.0 1965 4276.8 2.0 24.687 15.0 1967 4278.8 2.0 0.001 1.0 1968 4280.8 4.0 2.159 10.0 1969 4284.8 2.0 0.001 1.0 1971 4286.8 6.0 1.534 10.0 1972 4292.8 12.0 0.001 1.0 1975 4304.8 2.5 5.632 10.0 1980 4307.3 20.0 0.001 1.0 1982 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Shale Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Shale Nan DS ϭϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 8: Propped Fracture Schedule (Stage 3; 15965 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 2.0 PPA 40 YF125ST 183.7 25 2 4.0 PPA 40 YF125ST 191.1 25 4 6.0 PPA 40 YF125ST 177.7 25 6 8.0 PPA 40 YF125ST 166.0 25 8 10.0 PPA 40 YF125ST 121.2 25 10 12.0 PPA 40 YF125ST 97.9 25 12 Flush 40 YF125ST 242.2 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1652.1 bbl of YF125ST 0 bbl of WF125 255575 lb of 0 lb of % PAD Clean 21.3 % PAD Dirty 17.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 4100 7.5 7.5 1.0 PPA 172.4 472 180 480 7239 7239 4118 4.5 12.0 2.0 PPA 183.7 656 200 680 15430 22669 4216 5.0 17.0 4.0 PPA 191.1 847 225 905 32101 54770 4609 5.6 22.6 6.0 PPA 177.7 1025 225 1130 44777 99547 5310 5.6 28.3 8.0 PPA 166.0 1191 225 1355 55792 155339 5939 5.6 33.9 10.0 PPA 121.2 1312 175 1530 50907 206246 6291 4.4 38.3 12.0 PPA 97.9 1410 150 1680 49329 255575 6437 3.8 42.0 Flush 242.2 1652 242 1922 0 255575 5828 6.1 48.1 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 414 ft with an average conductivity (Kfw) of 13910.5 md.ft. Job Description Fluid Name Prop. Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV ϭϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 9: Propped Fracture Simulation (Stage 3; 15965 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϱϬ͘ϱĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϮϵϲ͘ϳĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϭϰĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϲ͘ϭĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϲϮŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϰϲƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϲϱϮϵƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 103.5 10.8 0.203 133.4 1.73 189.5 18156 103.5 207 7.4 0.189 211.9 1.68 208.7 16642 207 310.5 5.1 0.162 192.9 1.45 247.3 13762 310.5 414 1.9 0.104 145.6 0.95 351.1 8431 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. ϭϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 10: Zone Data (Stage 4; 15426 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϱϰ͘ϱ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϲϰ͘ϱ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϴϯϬ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϳϵ͘ϱ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϳϭ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϬϵϰ͘ϴ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϭϰ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϰϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϭϲ͘ϯ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϭϳ͘ϴ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϯϴ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϮϮ͘ϯ ϯ͘ϱ Ϭ͘ϲϵ ϮϴϱϬ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϮϱ͘ϴ ϭϰ͘ϱ Ϭ͘ϲϲ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϰϬ͘ϯ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϰϭ͘ϴ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϱϰ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϲϵϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϲ͘ϯ ϵ͘Ϭ Ϭ͘ϲϭ ϮϱϮϲ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϲϱ͘ϯ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϮ͘ϯ ϵ͘Ϭ Ϭ͘ϲϱ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϴϭ͘ϯ ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϴϲ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϴϰ͘ϴ ϱ͘Ϭ Ϭ͘ϲϰ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϴϵ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϭϵϭ͘ϴ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϮ͘ϯ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϱ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϬϳ͘ϴ ϱ͘ϱ Ϭ͘ϲϲ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϭϯ͘ϯ ϯ͘ϱ Ϭ͘ϳϬ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϭϲ͘ϴ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϮϬ͘ϯ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϮϱ͘ϴ ϭϬ͘ϱ Ϭ͘ϲϰ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϯϲ͘ϯ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϯϳ͘ϴ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϯϳ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϰϮ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϰϰ͘ϴ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϰϴ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϴ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϬ͘ϴ ϭϬ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϴ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϲϬ͘ϴ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϳϴϴ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϰ͘ϴ ϰ͘Ϭ Ϭ͘ϳϬ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϴ͘ϴ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϳϴ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϴϬ͘ϯ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϵ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϵϭ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϵϯ͘ϴ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϯϭ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϵϱ͘ϴ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϵϳ͘ϴ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϭ͘ϴ ϭϵ͘ϱ Ϭ͘ϳϬ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϭ͘ϯ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϮϯ͘ϯ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϱ͘ϯ ϴ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϯϯ͘ϯ ϴ͘Ϭ Ϭ͘ϲϱ ϮϴϬϲ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϰϭ͘ϯ ϮϬ͘Ϭ Ϭ͘ϳϬ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϭϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4054.5 10.0 0.001 1.0 1890 4064.5 15.0 0.001 1.0 1898 4079.5 15.3 0.005 10.0 1905 4094.8 19.5 30.655 23.7 1915 4114.3 2.0 5.000 10.0 1924 4116.3 1.5 2.095 16.9 1925 4117.8 4.5 48.388 26.6 1926 4122.3 3.5 0.478 12.4 1928 4125.8 14.5 15.008 17.7 1930 4140.3 1.5 3.661 17.6 1937 4141.8 12.5 34.723 23.9 1937 4154.3 2.0 1.697 15.6 1943 4156.3 9.0 54.319 24.4 1944 4165.3 7.0 3.610 14.8 1948 4172.3 9.0 22.986 20.4 1952 4181.3 3.5 0.835 14.0 1956 4184.8 5.0 65.392 23.4 1957 4189.8 2.0 0.006 10.5 1960 4191.8 10.5 100.832 25.6 1961 4202.3 3.5 17.434 20.5 1966 4205.8 2.0 161.343 26.3 1967 4207.8 5.5 4.627 18.4 1968 4213.3 3.5 5.075 14.8 1971 4216.8 3.5 8.651 19.4 1972 4220.3 5.5 10.205 16.0 1974 4225.8 10.5 17.356 20.1 1977 4236.3 1.5 3.106 14.8 1982 4237.8 5.0 52.863 20.6 1982 4242.8 2.0 2.277 14.1 1985 4244.8 4.0 122.778 23.1 1986 4248.8 2.0 0.333 12.5 1987 4250.8 10.0 39.939 21.2 1988 4260.8 4.0 0.748 13.3 1993 4264.8 4.0 0.009 10.9 1995 4268.8 9.5 5.399 16.7 1997 4278.3 2.0 160.618 24.9 2001 4280.3 9.5 0.033 11.5 2002 4289.8 2.0 6.733 16.2 2007 4291.8 2.0 0.001 1.0 2008 4293.8 2.0 29.480 19.6 2009 4295.8 2.0 0.001 1.0 2009 4297.8 4.0 8.473 16.6 2010 4301.8 19.5 0.001 1.0 2012 4321.3 2.0 2.185 16.4 2021 4323.3 2.0 0.001 1.0 2022 4325.3 8.0 2.645 15.9 2023 4333.3 8.0 2.026 14.4 2027 4341.3 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS ϭϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 11: Propped Fracture Schedule (Stage 4; 15426 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 57.4 25 1 3.0 PPA 40 YF125ST 105.6 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 2.0 PPA 40 YF125ST 202.1 25 2 4.0 PPA 40 YF125ST 203.8 25 4 6.0 PPA 40 YF125ST 189.5 25 6 8.0 PPA 40 YF125ST 177.1 25 8 10.0 PPA 40 YF125ST 138.5 25 10 Flush 40 YF125ST 235.0 25 0 Please note that this pumping schedule is under-displaced by 0.0 bbl. 1781.4 bbl of YF125ST 0 bbl of WF125 223906 lb of 15718 lb of % PAD Clean 16.2 % PAD Dirty 13.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 4006 6.3 6.3 1.0 PPA 57.4 307 60 310 2411 2411 4006 1.5 7.8 3.0 PPA 105.6 413 120 430 13308 15718 4055 3.0 10.8 Resume PAD 50.0 463 50 480 0 15718 4191 1.3 12.0 1.0 PPA 172.4 635 180 660 7239 22957 4338 4.5 16.5 2.0 PPA 202.1 837 220 880 16973 39931 4178 5.5 22.0 4.0 PPA 203.8 1041 240 1120 34241 74172 4537 6.0 28.0 6.0 PPA 189.5 1231 240 1360 47762 121934 5212 6.0 34.0 8.0 PPA 177.1 1408 240 1600 59511 181445 5789 6.0 40.0 10.0 PPA 138.5 1546 200 1800 58180 239625 6102 5.0 45.0 Flush 235.0 1781 235 2035 0 239625 5538 5.9 50.9 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 339.5 ft with an average conductivity (Kfw) of 15145.1 md.ft. Job Description Fluid Name Prop. Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV ϭϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 12: Propped Fracture Simulation (Stage 4; 15426 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϱϳ͘ϳĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϬϰ͘ϵĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϯϵ͘ϱĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϳ͘ϮĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϳϰŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϭϮƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϲϭϴϴƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 84.9 9 0.234 205.9 2.02 214.3 21534 84.9 169.7 7 0.214 205.9 1.91 239.3 19162 169.7 254.6 5.2 0.174 206.1 1.58 291.3 15149 254.6 339.5 1.6 0.086 198.7 0.87 706.8 6624 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. ϭϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 13: Zone Data (Stage 5; 14803 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϱϳ͘ϴ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϲϳ͘ϴ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϴϯϮ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϴϮ͘ϴ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϳϯ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϬϵϴ͘ϭ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϭϳ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϰϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϭϵ͘ϲ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϮϭ͘ϭ ϰ͘ϱ Ϭ͘ϲϮ ϮϱϰϬ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϮϱ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ ϮϴϱϮ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϮϵ͘ϭ ϭϰ͘ϱ Ϭ͘ϲϲ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϰϯ͘ϲ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϰϱ͘ϭ ϭϮ͘ϱ Ϭ͘ϲϰ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϱϳ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϲϵϵ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϵ͘ϲ ϵ͘Ϭ Ϭ͘ϲϭ ϮϱϮϴ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϲϴ͘ϲ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϱ͘ϲ ϵ͘Ϭ Ϭ͘ϲϱ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϴϰ͘ϲ ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϴϴ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϴϴ͘ϭ ϱ͘Ϭ Ϭ͘ϲϰ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϵϯ͘ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϭϵϱ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϱ͘ϲ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϵ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϭϭ͘ϭ ϱ͘ϱ Ϭ͘ϲϲ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϭϲ͘ϲ ϯ͘ϱ Ϭ͘ϳϬ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϮϬ͘ϭ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϮϯ͘ϲ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϮϵ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϰ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϯϵ͘ϲ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϰϭ͘ϭ ϱ͘Ϭ Ϭ͘ϲϮ ϮϲϰϬ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϰϲ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϰϴ͘ϭ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϱϮ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϴ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϰ͘ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ ϮϲϳϬ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϲϰ͘ϭ ϰ͘Ϭ Ϭ͘ϲϱ ϮϳϵϬ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϴ͘ϭ ϰ͘Ϭ Ϭ͘ϳϬ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϳϮ͘ϭ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϭ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϴϯ͘ϲ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϵϯ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϵϱ͘ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϮϵϳ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϯϰ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϮϵϵ͘ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϬϭ͘ϭ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϱ͘ϭ ϭϵ͘ϱ Ϭ͘ϳϬ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϰ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϮϲ͘ϲ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϴ͘ϲ ϴ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϯϲ͘ϲ ϴ͘Ϭ Ϭ͘ϲϱ ϮϴϬϴ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϰϰ͘ϲ ϮϬ͘Ϭ Ϭ͘ϳϬ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϭϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4057.8 10.0 0.001 1.0 1890 4067.8 15.0 0.001 1.0 1898 4082.8 15.3 0.005 10.0 1905 4098.1 19.5 30.655 23.7 1915 4117.6 2.0 5.000 10.0 1924 4119.6 1.5 2.095 16.9 1925 4121.1 4.5 48.388 26.6 1926 4125.6 3.5 0.478 12.4 1928 4129.1 14.5 15.008 17.7 1930 4143.6 1.5 3.661 17.6 1937 4145.1 12.5 34.723 23.9 1937 4157.6 2.0 1.697 15.6 1943 4159.6 9.0 54.319 24.4 1944 4168.6 7.0 3.610 14.8 1948 4175.6 9.0 22.986 20.4 1952 4184.6 3.5 0.835 14.0 1956 4188.1 5.0 65.392 23.4 1957 4193.1 2.0 0.006 10.5 1960 4195.1 10.5 100.832 25.6 1961 4205.6 3.5 17.434 20.5 1966 4209.1 2.0 161.343 26.3 1967 4211.1 5.5 4.627 18.4 1968 4216.6 3.5 5.075 14.8 1971 4220.1 3.5 8.651 19.4 1972 4223.6 5.5 10.205 16.0 1974 4229.1 10.5 17.356 20.1 1977 4239.6 1.5 3.106 14.8 1982 4241.1 5.0 52.863 20.6 1982 4246.1 2.0 2.277 14.1 1985 4248.1 4.0 122.778 23.1 1986 4252.1 2.0 0.333 12.5 1987 4254.1 10.0 39.939 21.2 1988 4264.1 4.0 0.748 13.3 1993 4268.1 4.0 0.009 10.9 1995 4272.1 9.5 5.399 16.7 1997 4281.6 2.0 160.618 24.9 2001 4283.6 9.5 0.033 11.5 2002 4293.1 2.0 6.733 16.2 2007 4295.1 2.0 0.001 1.0 2008 4297.1 2.0 29.480 19.6 2009 4299.1 2.0 0.001 1.0 2009 4301.1 4.0 8.473 16.6 2010 4305.1 19.5 0.001 1.0 2012 4324.6 2.0 2.185 16.4 2021 4326.6 2.0 0.001 1.0 2022 4328.6 8.0 2.645 15.9 2023 4336.6 8.0 2.026 14.4 2027 4344.6 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS ϭϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 14: Propped Fracture Schedule (Stage 5; 14803 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 57.4 25 1 3.0 PPA 40 YF125ST 105.6 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 3.0 PPA 40 YF125ST 176.5 25 3 5.0 PPA 40 YF125ST 188.2 25 5 7.0 PPA 40 YF125ST 175.5 25 7 9.0 PPA 40 YF125ST 153.6 25 9 10.0 PPA 40 YF125ST 124.7 25 10 Flush 40 YF125ST 224.5 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1678.4 bbl of YF125ST 0 bbl of WF125 231034 lb of 15718 lb of % PAD Clean 17.2 % PAD Dirty 14.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3879 6.3 6.3 1.0 PPA 57.4 307 60 310 2411 2411 3895 1.5 7.8 3.0 PPA 105.6 413 120 430 13308 15718 3955 3.0 10.8 Resume PAD 50.0 463 50 480 0 15718 4122 1.3 12.0 1.0 PPA 172.4 635 180 660 7239 22957 4204 4.5 16.5 3.0 PPA 176.5 812 200 860 22239 45196 4102 5.0 21.5 5.0 PPA 188.2 1000 230 1090 39529 84725 4668 5.8 27.3 7.0 PPA 175.5 1176 230 1320 51592 136317 5297 5.8 33.0 9.0 PPA 153.6 1329 215 1535 58074 194391 5700 5.4 38.4 10.0 PPA 124.7 1454 180 1715 52362 246753 5895 4.5 42.9 Flush 224.5 1678 225 1940 0 246753 5351 5.6 48.5 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 391.7 ft with an average conductivity (Kfw) of 14007.2 md.ft. Job Description Fluid Name Prop. Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV ϮϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 15: Propped Fracture Simulation (Stage 5; 14803 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϲϯ͘ϯĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϬϮ͘ϵĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϵϭ͘ϳĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϯϵ͘ϲĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϲϮŝŶ EĞƚWƌĞƐƐƵƌĞ ϯϳϯƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϵϰϵƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 97.9 9.5 0.221 144.8 1.91 207.7 20062 97.9 195.8 7.6 0.203 208.8 1.81 226.3 17964 195.8 293.8 5.5 0.159 190.8 1.45 275.5 13738 293.8 391.7 1.5 0.08 125 0.76 541.9 6069 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. Ϯϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 16: Zone Data (Stage 6; 14261 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϲϴ͘ϰ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϳϴ͘ϰ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϴϰϬ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϵϯ͘ϰ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϴϭ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϭϬϴ͘ϳ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϮϴ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϱϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϯϬ͘Ϯ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϯϭ͘ϳ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϰϳ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϯϲ͘Ϯ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϱϵ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϯϵ͘ϳ ϭϰ͘ϱ Ϭ͘ϲϲ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϰ͘Ϯ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϱϱ͘ϳ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϲϴ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϬ͘Ϯ ϵ͘Ϭ Ϭ͘ϲϭ Ϯϱϯϰ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϳϵ͘Ϯ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϴϲ͘Ϯ ϵ͘Ϭ Ϭ͘ϲϱ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϵϱ͘Ϯ ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϵϰ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϵϴ͘ϳ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϯ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϮϬϱ͘ϳ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϭϲ͘Ϯ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϭϵ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϮϭ͘ϳ ϱ͘ϱ Ϭ͘ϲϲ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϮϳ͘Ϯ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϯϬ͘ϳ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϯϰ͘Ϯ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϯϵ͘ϳ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϱϬ͘Ϯ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϭ͘ϳ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϲ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϱϲ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϴ͘ϳ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϲϮ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϰ͘ϳ ϭϬ͘Ϭ Ϭ͘ϲϯ Ϯϲϳϳ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϳϰ͘ϳ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϳϵϳ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϳϴ͘ϳ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϮ͘ϳ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϵϮ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϵϰ͘Ϯ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϬϯ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϱ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϬϳ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϳϰϬ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϵ͘ϳ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϭϭ͘ϳ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϭϱ͘ϳ ϭϵ͘ϱ Ϭ͘ϳϬ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϯϱ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϯϳ͘Ϯ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϯϵ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϰϳ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϭϱ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϱ͘Ϯ ϮϬ͘Ϭ Ϭ͘ϳϬ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϮϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4068.4 10.0 0.001 1.0 1890 4078.4 15.0 0.001 1.0 1898 4093.4 15.3 0.005 10.0 1905 4108.7 19.5 30.655 23.7 1915 4128.2 2.0 5.000 10.0 1924 4130.2 1.5 2.095 16.9 1925 4131.7 4.5 48.388 26.6 1926 4136.2 3.5 0.478 12.4 1928 4139.7 14.5 15.008 17.7 1930 4154.2 1.5 3.661 17.6 1937 4155.7 12.5 34.723 23.9 1937 4168.2 2.0 1.697 15.6 1943 4170.2 9.0 54.319 24.4 1944 4179.2 7.0 3.610 14.8 1948 4186.2 9.0 22.986 20.4 1952 4195.2 3.5 0.835 14.0 1956 4198.7 5.0 65.392 23.4 1957 4203.7 2.0 0.006 10.5 1960 4205.7 10.5 100.832 25.6 1961 4216.2 3.5 17.434 20.5 1966 4219.7 2.0 161.343 26.3 1967 4221.7 5.5 4.627 18.4 1968 4227.2 3.5 5.075 14.8 1971 4230.7 3.5 8.651 19.4 1972 4234.2 5.5 10.205 16.0 1974 4239.7 10.5 17.356 20.1 1977 4250.2 1.5 3.106 14.8 1982 4251.7 5.0 52.863 20.6 1982 4256.7 2.0 2.277 14.1 1985 4258.7 4.0 122.778 23.1 1986 4262.7 2.0 0.333 12.5 1987 4264.7 10.0 39.939 21.2 1988 4274.7 4.0 0.748 13.3 1993 4278.7 4.0 0.009 10.9 1995 4282.7 9.5 5.399 16.7 1997 4292.2 2.0 160.618 24.9 2001 4294.2 9.5 0.033 11.5 2002 4303.7 2.0 6.733 16.2 2007 4305.7 2.0 0.001 1.0 2008 4307.7 2.0 29.480 19.6 2009 4309.7 2.0 0.001 1.0 2009 4311.7 4.0 8.473 16.6 2010 4315.7 19.5 0.001 1.0 2012 4335.2 2.0 2.185 16.4 2021 4337.2 2.0 0.001 1.0 2022 4339.2 8.0 2.645 15.9 2023 4347.2 8.0 2.026 14.4 2027 4355.2 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Ϯϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 17: Propped Fracture Schedule (Stage 6; 14261 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 57.4 25 1 3.0 PPA 40 YF125ST 105.6 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 2.0 PPA 40 YF125ST 183.7 25 2 4.0 PPA 40 YF125ST 186.8 25 4 6.0 PPA 40 YF125ST 173.7 25 6 8.0 PPA 40 YF125ST 162.4 25 8 10.0 PPA 40 YF125ST 138.5 25 10 12.0 PPA 40 YF125ST 117.5 25 12 Flush 40 YF125ST 216.2 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1814.2 bbl of YF125ST 0 bbl of WF125 269765 lb of 15718 lb of % PAD Clean 15.6 % PAD Dirty 13.2 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3562 6.3 6.3 1.0 PPA 57.4 307 60 310 2411 2411 3571 1.5 7.8 3.0 PPA 105.6 413 120 430 13308 15718 3623 3.0 10.8 Resume PAD 50.0 463 50 480 0 15718 3757 1.3 12.0 1.0 PPA 172.4 635 180 660 7239 22957 3794 4.5 16.5 2.0 PPA 183.7 819 200 860 15430 38388 3735 5.0 21.5 4.0 PPA 186.8 1006 220 1080 31388 69776 4333 5.5 27.0 6.0 PPA 173.7 1180 220 1300 43782 113557 4797 5.5 32.5 8.0 PPA 162.4 1342 220 1520 54552 168109 5127 5.5 38.0 10.0 PPA 138.5 1481 200 1720 58180 226289 5260 5.0 43.0 12.0 PPA 117.5 1598 180 1900 59195 285484 5278 4.5 47.5 Flush 216.2 1814 216 2116 0 285484 4792 5.4 52.9 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 371.2 ft with an average conductivity (Kfw) of 16591.8 md.ft. Job Description Fluid Name Prop. Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Ϯϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 18: Propped Fracture Simulation (Stage 6; 14261 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϳϯ͘ϳĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϭϳĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϳϭ͘ϮĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϯ͘ϯĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϵϭŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϵϯƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϴϵϮƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 92.8 10.3 0.298 198 2.58 193.7 27091 92.8 185.6 7.7 0.269 198 2.4 218.7 24029 185.6 278.4 5.1 0.185 196.6 1.7 311 15934 278.4 371.2 0.8 0.033 158.8 0.33 787.1 1693 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. Ϯϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 19: Zone Data (Stage 7; 13680 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϳϬ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϴϬ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϰϭ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϵϱ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ ϮϳϴϮ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϭϭϭ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϯϬ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϱϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϯϮ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϯϰ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϰϴ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϯϴ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϲϭ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϰϮ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϲ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϲ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϱϴ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϳϬ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϳϬϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϮ͘ϱ ϵ͘Ϭ Ϭ͘ϲϭ Ϯϱϯϱ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϴϭ͘ϱ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϴϴ͘ϱ ϵ͘Ϭ Ϭ͘ϲϱ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϵϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϵϲ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϬϭ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϲ͘Ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϮϬϴ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϭϴ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϮϮ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϮϰ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϮϵ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϯϯ͘Ϭ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϯϲ͘ϱ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϰϮ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϱϮ͘ϱ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϰ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϴ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϱϵ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϭ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϲϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϳ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ Ϯϲϳϵ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϳϳ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϳϵϴ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϭ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϱ͘Ϭ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϵϰ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϵϲ͘ϱ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϬϲ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϬϴ͘Ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϭϬ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϳϰϮ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϭϮ͘Ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϭϰ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϭϴ͘Ϭ ϭϵ͘ϱ Ϭ͘ϳϬ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϯϳ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϯϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϰϭ͘ϱ ϴ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϰϵ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϭϳ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϳ͘ϱ ϮϬ͘Ϭ Ϭ͘ϳϬ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio Ϯϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4070.7 10.0 0.001 1.0 1890 4080.7 15.0 0.001 1.0 1898 4095.7 15.3 0.005 10.0 1905 4111.0 19.5 30.655 23.7 1915 4130.5 2.0 5.000 10.0 1924 4132.5 1.5 2.095 16.9 1925 4134.0 4.5 48.388 26.6 1926 4138.5 3.5 0.478 12.4 1928 4142.0 14.5 15.008 17.7 1930 4156.5 1.5 3.661 17.6 1937 4158.0 12.5 34.723 23.9 1937 4170.5 2.0 1.697 15.6 1943 4172.5 9.0 54.319 24.4 1944 4181.5 7.0 3.610 14.8 1948 4188.5 9.0 22.986 20.4 1952 4197.5 3.5 0.835 14.0 1956 4201.0 5.0 65.392 23.4 1957 4206.0 2.0 0.006 10.5 1960 4208.0 10.5 100.832 25.6 1961 4218.5 3.5 17.434 20.5 1966 4222.0 2.0 161.343 26.3 1967 4224.0 5.5 4.627 18.4 1968 4229.5 3.5 5.075 14.8 1971 4233.0 3.5 8.651 19.4 1972 4236.5 5.5 10.205 16.0 1974 4242.0 10.5 17.356 20.1 1977 4252.5 1.5 3.106 14.8 1982 4254.0 5.0 52.863 20.6 1982 4259.0 2.0 2.277 14.1 1985 4261.0 4.0 122.778 23.1 1986 4265.0 2.0 0.333 12.5 1987 4267.0 10.0 39.939 21.2 1988 4277.0 4.0 0.748 13.3 1993 4281.0 4.0 0.009 10.9 1995 4285.0 9.5 5.399 16.7 1997 4294.5 2.0 160.618 24.9 2001 4296.5 9.5 0.033 11.5 2002 4306.0 2.0 6.733 16.2 2007 4308.0 2.0 0.001 1.0 2008 4310.0 2.0 29.480 19.6 2009 4312.0 2.0 0.001 1.0 2009 4314.0 4.0 8.473 16.6 2010 4318.0 19.5 0.001 1.0 2012 4337.5 2.0 2.185 16.4 2021 4339.5 2.0 0.001 1.0 2022 4341.5 8.0 2.645 15.9 2023 4349.5 8.0 2.026 14.4 2027 4357.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Ϯϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 20: Propped Fracture Schedule (Stage 7; 13680 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 230.0 25 0 1.0 PPA 40 YF125ST 57.5 25 1 3.0 PPA 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 3.0 PPA 40 YF125ST 176.5 25 3 5.0 PPA 40 YF125ST 188.2 25 5 7.0 PPA 40 YF125ST 175.5 25 7 9.0 PPA 40 YF125ST 153.6 25 9 10.0 PPA 40 YF125ST 38.1 25 10 10.0 PPA 40 YF125ST 86.6 25 10 Flush 40 YF125ST 207.4 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1641.6 bbl of YF125ST 0 bbl of WF125 194672 lb of 15756 lb of 36362 lb of % PAD Clean 16.0 % PAD Dirty 13.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 230.0 230 230 230 0 0 3689 5.8 5.8 1.0 PPA 57.5 287 60 290 2413 2413 3693 1.5 7.3 3.0 PPA 105.9 393 120 410 13343 15756 3758 3.0 10.3 Resume PAD 50.0 443 50 460 0 15756 3904 1.3 11.5 1.0 PPA 172.4 616 180 640 7239 22995 3972 4.5 16.0 3.0 PPA 176.5 792 200 840 22239 45234 3862 5.0 21.0 5.0 PPA 188.2 980 230 1070 39529 84763 4363 5.8 26.8 7.0 PPA 175.5 1156 230 1300 51592 136355 4931 5.8 32.5 9.0 PPA 153.6 1310 215 1515 58074 194429 5317 5.4 37.9 10.0 PPA 38.1 1348 55 1570 15999 210428 5463 1.4 39.3 10.0 PPA 86.6 1434 125 1695 36362 246791 5510 3.1 42.4 Flush 207.4 1642 207 1902 0 246791 4996 5.2 47.6 Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 354.2 ft with an average conductivity (Kfw) of 17031.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Proppant Totals Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Fluid Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Carbolite 40/70 Job Execution Step Name Ϯϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 21: Propped Fracture Simulation (Stage 7; 13680 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϳϲ͘ϰĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϭϳ͘ϵĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϱϰ͘ϮĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϭ͘ϱĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϳϴŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϲϴƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϱϯϮƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 88.6 9.1 0.228 136.9 1.97 217 30714 88.6 177.1 7.7 0.224 212.6 1.99 221.4 19699 177.1 265.7 6 0.186 197.9 1.68 253.6 16061 265.7 354.2 1.8 0.088 142.9 0.8 551 6906 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 Ϯϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 22: Zone Data (Stage 8; 13095 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϳϮ͘ϴ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϴϮ͘ϴ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϰϯ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϬϵϳ͘ϴ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϴϯ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϭϭϯ͘ϭ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϯϮ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϱϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϯϰ͘ϲ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϯϲ͘ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϰϵ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϰϬ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ ϮϴϲϮ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϰϰ͘ϭ ϭϰ͘ϱ Ϭ͘ϲϲ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϴ͘ϲ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϲϬ͘ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϳϮ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϳϬϵ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϰ͘ϲ ϵ͘Ϭ Ϭ͘ϲϭ Ϯϱϯϳ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϴϯ͘ϲ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϵϬ͘ϲ ϵ͘Ϭ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϭϵϵ͘ϲ ϯ͘ϱ Ϭ͘ϲϰ Ϯϲϵϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϬϯ͘ϭ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϴ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϮϭϬ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϮϬ͘ϲ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϮϰ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϮϲ͘ϭ ϱ͘ϱ Ϭ͘ϲϱ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϯϭ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϯϱ͘ϭ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϯϴ͘ϲ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϰϰ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϱϰ͘ϲ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϲ͘ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϲϭ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϯ͘ϭ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϲϳ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϵ͘ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ ϮϲϴϬ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϳϵ͘ϭ ϰ͘Ϭ Ϭ͘ϲϱ ϮϴϬϬ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϯ͘ϭ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϳ͘ϭ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϵϲ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϵϴ͘ϲ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϬϴ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϭϬ͘ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϭϮ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϰϯ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϭϰ͘ϭ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϭϲ͘ϭ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϮϬ͘ϭ ϭϵ͘ϱ Ϭ͘ϳϬ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϯϵ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϰϭ͘ϲ Ϯ͘Ϭ Ϭ͘ϳϬ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϰϯ͘ϲ ϴ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϱϭ͘ϲ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϭϴ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϵ͘ϲ ϮϬ͘Ϭ Ϭ͘ϳϬ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϯϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4072.8 10.0 0.001 1.0 1890 4082.8 15.0 0.001 1.0 1898 4097.8 15.3 0.005 10.0 1905 4113.1 19.5 30.655 23.7 1915 4132.6 2.0 5.000 10.0 1924 4134.6 1.5 2.095 16.9 1925 4136.1 4.5 48.388 26.6 1926 4140.6 3.5 0.478 12.4 1928 4144.1 14.5 15.008 17.7 1930 4158.6 1.5 3.661 17.6 1937 4160.1 12.5 34.723 23.9 1937 4172.6 2.0 1.697 15.6 1943 4174.6 9.0 54.319 24.4 1944 4183.6 7.0 3.610 14.8 1948 4190.6 9.0 22.986 20.4 1952 4199.6 3.5 0.835 14.0 1956 4203.1 5.0 65.392 23.4 1957 4208.1 2.0 0.006 10.5 1960 4210.1 10.5 100.832 25.6 1961 4220.6 3.5 17.434 20.5 1966 4224.1 2.0 161.343 26.3 1967 4226.1 5.5 4.627 18.4 1968 4231.6 3.5 5.075 14.8 1971 4235.1 3.5 8.651 19.4 1972 4238.6 5.5 10.205 16.0 1974 4244.1 10.5 17.356 20.1 1977 4254.6 1.5 3.106 14.8 1982 4256.1 5.0 52.863 20.6 1982 4261.1 2.0 2.277 14.1 1985 4263.1 4.0 122.778 23.1 1986 4267.1 2.0 0.333 12.5 1987 4269.1 10.0 39.939 21.2 1988 4279.1 4.0 0.748 13.3 1993 4283.1 4.0 0.009 10.9 1995 4287.1 9.5 5.399 16.7 1997 4296.6 2.0 160.618 24.9 2001 4298.6 9.5 0.033 11.5 2002 4308.1 2.0 6.733 16.2 2007 4310.1 2.0 0.001 1.0 2008 4312.1 2.0 29.480 19.6 2009 4314.1 2.0 0.001 1.0 2009 4316.1 4.0 8.473 16.6 2010 4320.1 19.5 0.001 1.0 2012 4339.6 2.0 2.185 16.4 2021 4341.6 2.0 0.001 1.0 2022 4343.6 8.0 2.645 15.9 2023 4351.6 8.0 2.026 14.4 2027 4359.6 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS ϯϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 23: Propped Fracture Schedule (Stage 8; 13095 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 57.5 25 1 3.0 PPA 40 YF125ST 105.9 25 3 Resume PAD 40 YF125ST 50.0 25 0 1.0 PPA 40 YF125ST 196.3 25 1 3.0 PPA 40 YF125ST 180.9 25 3 5.0 PPA 40 YF125ST 229.2 25 5 7.0 PPA 40 YF125ST 194.6 25 7 9.0 PPA 40 YF125ST 182.2 25 9 10.0 PPA 40 YF125ST 72.7 25 10 10.0 PPA 40 YF125ST 83.1 25 10 Flush 40 YF125ST 198.5 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1800.8 bbl of YF125ST 0 bbl of WF125 235784 lb of 15756 lb of 34908 lb of % PAD Clean 15.6 % PAD Dirty 13.1 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3562 6.3 6.3 1.0 PPA 57.5 307 60 310 2413 2413 3571 1.5 7.8 3.0 PPA 105.9 413 120 430 13343 15756 3623 3.0 10.8 Resume PAD 50.0 463 50 480 0 15756 3757 1.3 12.0 1.0 PPA 196.3 660 205 685 8244 24000 3794 5.1 17.1 3.0 PPA 180.9 841 205 890 22795 46796 3735 5.1 22.3 5.0 PPA 229.2 1070 280 1170 48122 94917 4333 7.0 29.3 7.0 PPA 194.6 1264 255 1425 57200 152117 4797 6.4 35.6 9.0 PPA 182.2 1446 255 1680 68878 220996 5127 6.4 42.0 10.0 PPA 72.7 1519 105 1785 30544 251540 5260 2.6 44.6 10.0 PPA 83.1 1602 120 1905 34908 286448 5278 3.0 47.6 Flush 198.5 1801 198 2103 0 286448 4792 5.0 52.6 Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 390.8 ft with an average conductivity (Kfw) of 18648.2 md.ft. Job Description Fluid Name Prop. Type and Mesh Proppant Totals Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Fluid Totals Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Carbolite 40/70 Job Execution Step Name ϯϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 24: Propped Fracture Simulation (Stage 8; 13095 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϳϴ͘ϴĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϭϴ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϵϬ͘ϴĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϯϵ͘ϵĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϵϭŝŶ EĞƚWƌĞƐƐƵƌĞ ϯϳϵƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϯϭϵƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 97.7 9.6 0.246 194.3 2.12 209.7 33338 97.7 195.4 7.9 0.233 211.3 2.08 216.9 21025 195.4 293.1 6.3 0.196 182.7 1.77 245.8 17350 293.1 390.8 1.8 0.104 157.8 0.96 466.6 8250 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 ϯϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 25: Zone Data (Stage 9; 12509 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϴϭ͘ϴ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϵϭ͘ϴ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϰϵ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϭϬϲ͘ϴ ϭϱ͘ϯ Ϭ͘ϲϴ ϮϳϵϬ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϭϮϮ͘ϭ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϰϭ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϲϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϰϯ͘ϲ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϰϱ͘ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϱϱ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϰϵ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϲϵ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϱϯ͘ϭ ϭϰ͘ϱ Ϭ͘ϲϲ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϲϳ͘ϲ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϲϵ͘ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϴϭ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϭϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϴϯ͘ϲ ϵ͘Ϭ Ϭ͘ϲϭ ϮϱϰϮ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϵϮ͘ϲ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϵϵ͘ϲ ϵ͘Ϭ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϬϴ͘ϲ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϯ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϭϮ͘ϭ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϭϳ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϮϭϵ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϮϵ͘ϲ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϯϯ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϯϱ͘ϭ ϱ͘ϱ Ϭ͘ϲϱ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϰϬ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϰϰ͘ϭ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϰϳ͘ϲ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϯ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϲϯ͘ϲ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϱ͘ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϱϰ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϳϬ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϳϮ͘ϭ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϳϲ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϳϴ͘ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϲ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϴϴ͘ϭ ϰ͘Ϭ Ϭ͘ϲϱ ϮϴϬϲ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϵϮ͘ϭ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϵϲ͘ϭ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϬϱ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϯϬϳ͘ϲ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϭϳ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϭϵ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϭ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϰϵ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϮϯ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϱ͘ϭ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϮϵ͘ϭ ϭϵ͘ϱ Ϭ͘ϲϵ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϰϴ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϬ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϱϮ͘ϲ ϴ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϲϬ͘ϲ ϴ͘Ϭ Ϭ͘ϲϱ ϮϴϮϰ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϲϴ͘ϲ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϯϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4081.8 10.0 0.001 1.0 1890 4091.8 15.0 0.001 1.0 1898 4106.8 15.3 0.005 10.0 1905 4122.1 19.5 30.655 23.7 1915 4141.6 2.0 5.000 10.0 1924 4143.6 1.5 2.095 16.9 1925 4145.1 4.5 48.388 26.6 1926 4149.6 3.5 0.478 12.4 1928 4153.1 14.5 15.008 17.7 1930 4167.6 1.5 3.661 17.6 1937 4169.1 12.5 34.723 23.9 1937 4181.6 2.0 1.697 15.6 1943 4183.6 9.0 54.319 24.4 1944 4192.6 7.0 3.610 14.8 1948 4199.6 9.0 22.986 20.4 1952 4208.6 3.5 0.835 14.0 1956 4212.1 5.0 65.392 23.4 1957 4217.1 2.0 0.006 10.5 1960 4219.1 10.5 100.832 25.6 1961 4229.6 3.5 17.434 20.5 1966 4233.1 2.0 161.343 26.3 1967 4235.1 5.5 4.627 18.4 1968 4240.6 3.5 5.075 14.8 1971 4244.1 3.5 8.651 19.4 1972 4247.6 5.5 10.205 16.0 1974 4253.1 10.5 17.356 20.1 1977 4263.6 1.5 3.106 14.8 1982 4265.1 5.0 52.863 20.6 1982 4270.1 2.0 2.277 14.1 1985 4272.1 4.0 122.778 23.1 1986 4276.1 2.0 0.333 12.5 1987 4278.1 10.0 39.939 21.2 1988 4288.1 4.0 0.748 13.3 1993 4292.1 4.0 0.009 10.9 1995 4296.1 9.5 5.399 16.7 1997 4305.6 2.0 160.618 24.9 2001 4307.6 9.5 0.033 11.5 2002 4317.1 2.0 6.733 16.2 2007 4319.1 2.0 0.001 1.0 2008 4321.1 2.0 29.480 19.6 2009 4323.1 2.0 0.001 1.0 2009 4325.1 4.0 8.473 16.6 2010 4329.1 19.5 0.001 1.0 2012 4348.6 2.0 2.185 16.4 2021 4350.6 2.0 0.001 1.0 2022 4352.6 8.0 2.645 15.9 2023 4360.6 8.0 2.026 14.4 2027 4368.6 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS ϯϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 26: Propped Fracture Schedule (Stage 9; 12509 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 2.0 PPA 40 YF125ST 183.7 25 2 4.0 PPA 40 YF125ST 186.8 25 4 6.0 PPA 40 YF125ST 173.7 25 6 8.0 PPA 40 YF125ST 162.4 25 8 10.0 PPA 40 YF125ST 138.5 25 10 12.0 PPA 40 YF125ST 45.7 25 12 12.0 PPA 40 YF125ST 71.8 25 12 Flush 40 YF125ST 189.6 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1580.4 bbl of YF125ST 0 bbl of WF125 233591 lb of 36175 lb of % PAD Clean 20.9 % PAD Dirty 17.4 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3471 7.5 7.5 1.0 PPA 172.4 472 180 480 7239 7239 3478 4.5 12.0 2.0 PPA 183.7 656 200 680 15430 22669 3552 5.0 17.0 4.0 PPA 186.8 843 220 900 31388 54057 3862 5.5 22.5 6.0 PPA 173.7 1017 220 1120 43782 97839 4342 5.5 28.0 8.0 PPA 162.4 1179 220 1340 54552 152391 4780 5.5 33.5 10.0 PPA 138.5 1317 200 1540 58180 210570 5014 5.0 38.5 12.0 PPA 45.7 1363 70 1610 23020 233591 5075 1.8 40.3 12.0 PPA 71.8 1435 110 1720 36175 269765 5113 2.8 43.0 Flush 189.6 1625 190 1910 0 269765 4678 4.7 47.7 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 366.9 ft with an average conductivity (Kfw) of 17886.5 md.ft. Job Description Fluid Name Prop. Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 ϯϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 27: Propped Fracture Simulation (Stage 9; 12509 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϴϳ͘ϯĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϯϭĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϲϲ͘ϵĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϯ͘ϳĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϴϳŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϲϵƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϭϲϯƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 91.7 11 0.238 208.4 2.05 197.4 31793 91.7 183.5 8.6 0.219 201.2 1.95 210.7 19296 183.5 275.2 6.8 0.184 192.5 1.66 236.3 15879 275.2 366.9 3 0.12 173.8 1.13 347.8 9589 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. ϯϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 28: Zone Data (Stage 10; 11922 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϬϴϵ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϮ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϬϵϵ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϱϱ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ϰϭϭϰ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϳϵϱ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ϰϭϯϬ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϯ Ϯϱϵϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ϰϭϰϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϴϲϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϭϱϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϱ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϭϱϯ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ ϮϱϲϬ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϭϱϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϳϰ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϲϭ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϱ ϮϳϮϲ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϳϱ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ ϮϳϬϲ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϳϳ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϰϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϭϴϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϳϮϬ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϭϵϭ͘ϱ ϵ͘Ϭ Ϭ͘ϲϭ Ϯϱϰϳ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϬϬ͘ϱ ϳ͘Ϭ Ϭ͘ϲϲ Ϯϳϱϱ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϬϳ͘ϱ ϵ͘Ϭ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϭϲ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϴ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϮϬ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϮϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϵϮϱ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ϰϮϮϳ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϮ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϯϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϰϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ϰϮϰϯ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ Ϯϳϲϴ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ϰϮϰϴ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϯϵ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϱϮ͘Ϭ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϬϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϱϱ͘ϱ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϲϭ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϮϳϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϲ Ϯϴϭϭ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϳϯ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϱϵ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϳϴ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϬϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϬ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϯ Ϯϲϴϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϴϰ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϮϴϲ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ ϮϲϵϬ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ϰϮϵϲ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϭϭ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϬϬ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϬϰ͘Ϭ ϵ͘ϱ Ϭ͘ϲϱ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϭϯ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϭ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ϰϯϭϱ͘ϱ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϮϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϮϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϮϵ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϱϰ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϯϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϯϯ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϲ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϯϳ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϵ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϱϲ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϴ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ϰϯϲϬ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ϰϯϲϴ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ ϮϴϮϵ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϳϲ͘ϱ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϰϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Poisson’s Ratio ϯϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4089.7 10.0 0.001 1.0 1890 4099.7 15.0 0.001 1.0 1898 4114.7 15.3 0.005 10.0 1905 4130.0 19.5 30.655 23.7 1915 4149.5 2.0 5.000 10.0 1924 4151.5 1.5 2.095 16.9 1925 4153.0 4.5 48.388 26.6 1926 4157.5 3.5 0.478 12.4 1928 4161.0 14.5 15.008 17.7 1930 4175.5 1.5 3.661 17.6 1937 4177.0 12.5 34.723 23.9 1937 4189.5 2.0 1.697 15.6 1943 4191.5 9.0 54.319 24.4 1944 4200.5 7.0 3.610 14.8 1948 4207.5 9.0 22.986 20.4 1952 4216.5 3.5 0.835 14.0 1956 4220.0 5.0 65.392 23.4 1957 4225.0 2.0 0.006 10.5 1960 4227.0 10.5 100.832 25.6 1961 4237.5 3.5 17.434 20.5 1966 4241.0 2.0 161.343 26.3 1967 4243.0 5.5 4.627 18.4 1968 4248.5 3.5 5.075 14.8 1971 4252.0 3.5 8.651 19.4 1972 4255.5 5.5 10.205 16.0 1974 4261.0 10.5 17.356 20.1 1977 4271.5 1.5 3.106 14.8 1982 4273.0 5.0 52.863 20.6 1982 4278.0 2.0 2.277 14.1 1985 4280.0 4.0 122.778 23.1 1986 4284.0 2.0 0.333 12.5 1987 4286.0 10.0 39.939 21.2 1988 4296.0 4.0 0.748 13.3 1993 4300.0 4.0 0.009 10.9 1995 4304.0 9.5 5.399 16.7 1997 4313.5 2.0 160.618 24.9 2001 4315.5 9.5 0.033 11.5 2002 4325.0 2.0 6.733 16.2 2007 4327.0 2.0 0.001 1.0 2008 4329.0 2.0 29.480 19.6 2009 4331.0 2.0 0.001 1.0 2009 4333.0 4.0 8.473 16.6 2010 4337.0 19.5 0.001 1.0 2012 4356.5 2.0 2.185 16.4 2021 4358.5 2.0 0.001 1.0 2022 4360.5 8.0 2.645 15.9 2023 4368.5 8.0 2.026 14.4 2027 4376.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS ϯϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 29: Propped Fracture Schedule (Stage 10; 11922 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 275.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 2.0 PPA 40 YF125ST 183.7 25 2 4.0 PPA 40 YF125ST 186.8 25 4 6.0 PPA 40 YF125ST 173.7 25 6 8.0 PPA 40 YF125ST 162.4 25 8 10.0 PPA 40 YF125ST 131.6 25 10 12.0 PPA 40 YF125ST 42.4 25 12 12.0 PPA 40 YF125ST 71.8 25 12 Flush 40 YF125ST 180.6 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1580.4 bbl of YF125ST 0 bbl of WF125 229037 lb of 36175 lb of % PAD Clean 19.6 % PAD Dirty 16.4 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 275.0 275 275 275 0 0 3366 6.9 6.9 1.0 PPA 172.4 447 180 455 7239 7239 3368 4.5 11.4 2.0 PPA 183.7 631 200 655 15430 22669 3429 5.0 16.4 4.0 PPA 186.8 818 220 875 31388 54057 3763 5.5 21.9 6.0 PPA 173.7 992 220 1095 43782 97839 4245 5.5 27.4 8.0 PPA 162.4 1154 220 1315 54552 152391 4627 5.5 32.9 10.0 PPA 131.6 1286 190 1505 55271 207661 4803 4.8 37.6 12.0 PPA 42.4 1328 65 1570 21376 229037 4847 1.6 39.3 12.0 PPA 71.8 1400 110 1680 36175 265212 4882 2.8 42.0 Flush 180.6 1580 181 1861 0 265212 4466 4.5 46.5 Type and Mesh Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 360.8 ft with an average conductivity (Kfw) of 18640 md.ft. Job Description Fluid Name Prop. Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 Job Execution Step Name Fluid Totals Proppant Totals Pad Percentages Carbolite 16/20 + 4wt% ScaleGuard IV Carbolite 12/18 ϰϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 30: Propped Fracture Simulation (Stage 10; 11922 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϬϵϲĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϯϴ͘ϯĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϲϬ͘ϴĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů ϮϰϮ͘ϮĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϴϳŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϳϬƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϰϵϮϵƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 90.2 10.8 0.237 138.6 2.06 197.9 31974 90.2 180.4 8.5 0.225 206.4 2 206.4 19850 180.4 270.6 6.9 0.192 192.2 1.73 231.4 16625 270.6 360.8 2.7 0.106 167.2 1.01 523.1 8414 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. ϰϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Santos USA and Baker Hughes Confidential Page 1 © 2018 Baker Hughes, LLC - All rights reserved. LLWD Qualitative Cement Bond Log Evaluation Report Well Name, Section: NDBi-051, 9 5/8” Liner Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: Reservoir Technical Services Alaska Version: Preliminary Report Santos USA and Baker Hughes Confidential Page 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Tool Diagram .......................................................................................................................................................................................................... 7 Methodology of LWD Cement Bond Log Evaluation .................................................................................................................8 Log Screen Captures ...................................................................................................................................................................................... 13 Santos USA and Baker Hughes Confidential Page 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMER THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. Santos USA and Baker Hughes Confidential Page 4 Executive Summary Cement Bond Logging with LWD Acoustic (Sonic) tool SoundTrak was performed after drilling of 8 ½” section. Logs were acquired while pulling out of hole across 9 5/8” liner in upward direction. The objective and plan were to cover with CBL logs to evaluate the first stage cementing from the 9 5/8” Liner shoe to the planned TOC of 9100’ MD. Cement Bond Index (BI) curve was computed and presented in the log plot showing color gradation from good cement bond (brown) to poor cement (blue). The following values were used by interpreter to differentiate intervals of good bond (curve value above 0.8) to partial (0.2 to 0.8) and poor (lower than 0.2). Summaries of initial pre-job logging plan and Cement Bond Index interpretation are outlined below. Logging Plan Summary Down link to the SoundTrak tool after drilling of 8 ½” open hole and upon coming to the liner shoe at 11560ft MD to initiate top of cement mode and continue backreaming out of hole to log the cement in the 9 5/8” Liner at 400 gpm and 60-120 rpm (per Bakerhughes recommendation). x Log cement from 9-5/8” shoe (11,560’ MD) to 9,100’ MD planned top of cement. Log up at 1,200 fph. x Log free pipe from 9,100’ to 7,900’ MD (1,350’ of free pipe) at 1,200 fph. LWD logging was optimized to gain higher efficiency and reduce overall rig time by modifying acquisition parameters and logging at 1200 ft/hr entire well interval. Santos USA and Baker Hughes Confidential Page 5 Interpretation Summary The Intermediate was drilled and 9 5/8” Casing shoe was set at 11,560ft. After drilling 8 ½” to TD, a Logging up was performed to capture cement Bond on the 9 5/8” casing. Following observations are summarized below by interval. Please note that Bond Index curve (BI) and color coding in combination with other data on the log can be used for more detailed interval inspection to draw conclusions on zonal isolation of narrower intervals. Overall, 4 main zones were defined as listed below, with more detailed interpretation within each zone presented in the table that follows. - 7,900’-9,150’: Poor to no cement presence above 9150ft - 9,150’ to 92,50’ Partial to poor Cement presence, with some intervals of partial cement presence. - 9,250’ to 11,560’ Partial to Good. Mostly Good, with some intervals of partial cement presence. For more detailed description of each interval please refer to the table below summarizing Interpretation results. Santos USA and Baker Hughes Confidential Page 6 Santos USA and Baker Hughes Confidential Page 7 Tool Diagram Santos USA and Baker Hughes Confidential Page 8 Methodology of LWD Cement Bond Log Evaluation Before the arrival of more advanced Wireline technologies offering azimuthal coverage of the casing to cement and cement to formation bonding, oil and gas operators have been relying on traditional non-azimuthal CBL, Cement Bond Log, technique, that is being run successfully to date. Wireline Acoustic (Sonic) tool’s CBL measurement principle relies on detecting and measuring first “casing ringing” amplitude reflected from the casing wall. The idea is that free pipe (with cement absence) would “ring” freely creating high Casing Ringing Amplitude, whereas well cemented casing would result in dampened first arrival and thus indicate well cemented pipe. Traditional Wireline tool relies on the arrival of the sound detected at the receiver spaced at 3 ft for CBL Amplitude and for the one from the 5 ft spaced receiver for VDL (Variable Density Log). Figure 1: Traditional Wireline CBL technique Santos USA and Baker Hughes Confidential Page 9 LWD Acoustic (Sonic) tool is using the same principle for CBL measurement. It is also non- azimuthal. However, the one difference is that receiver spacing is longer and all measurements are based on the 10.7 ft receiver spacing for CBL Amplitude. See figures below for the main principle behind cemented vs free pipe detection in traditional CBL measurement. Figure 2: CBL concept in "free" pipe Figure 3: CBL concept in cemented pipe Santos USA and Baker Hughes Confidential Page 10 Figure 4: General CBL concept and corresponding log example Figure 5: LWD Acoustic (Sonic) tool and LWD CBL concept Current traditional offering of LWD Acoustic (Sonic) tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling trip typically on the way out of casing after drilling is completed. Santos USA and Baker Hughes Confidential Page 11 Baker Hughes offers both traditional TOC service and a more advanced workflow of providing Cement Bond Index. This Cement Bond Index is a relative Cement Quality Indicator helping operators to still acquire positive zonal isolation information in wells where running Wireline could be challenging and / or would otherwise increase overall rig time. To convert casing amplitude to cement bond index (BI), two reference points are required: - Free casing - 100% bonded point Figure 6: Cement Bond Index computation concept Traditionally as part of the CBL logging deliverable, Bond Index (BI) is computed and displayed in the log. Values above 80% BI are typically seen as “good" cement, whereas values below 80% are typically seen as either "poor," contaminated or channeled cement. Note however, that the TR spacing (10.66 ft) for LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality check must be carried out to validate the data, because If the casing amplitude in these well bonded intervals is below noise level, the 100% bonded reference point might be incorrect and the “BI” could be over-estimated, reducing quantitative precision of the measurement. Additionally, Cement Evaluation with LWD SoundTrak tool would be ideal in standard cements with slurry density of equal or greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. For example, detection of behind casing open hole DT from waveforms could confirm that proper cement is present. Santos USA and Baker Hughes Confidential Page 12 Furthermore, adding this service can increase operational efficiency since it can be done in the same drilling trip on the way out and logging speed for top of cement detection and CBL evaluation can be as high as ~1500 ft/hr still providing good data quality. With combination of casing mode semblance (SV) and formation arrival in correlogram, TOC can be detected in Real-Time. Good agreement between RT and memory TOC can be seen in the figure below. Figure 7: LWD capability of Real-Time Top of Cement acquisition This method has limitations though as it has no azimuthal coverage and can not identify micro channeling. It is not a replacement for quantitative cement evaluation tools such as SBT, InTex, or CICM Santos USA and Baker Hughes Confidential Page 13 Log Screen Captures Following figures contain interpretation observations, however Bond Index curve and color coding can be used for more detailed interval inspection to draw conclusions on zonal isolation. Please refer to the tables on pages 6 for more detailed interpretation. Figure 8: Interval 1 of LWD CBL logging General Interpretation Comments: 7,900’ to 9,150’ poor to no cement in that interval. Santos USA and Baker Hughes Confidential Page 14 Figure 9: Interval 3 of LWD CBL Logging General Interpretation Comments: 7,900’ to 9,150’ poor to no cement in that interval. 9,150’ to 92,50’ Partial to poor Cement presence, with some intervals of partial cement presence. Very Good cement Presence from 9250ft downward. Santos USA and Baker Hughes Confidential Page 15 Figure 10: Interval 4 of LWD CBL Logging General Interpretation Comments: 9,247’ to 11,560’ Partial to Good. Mostly Good, with some intervals of partial cement presence. Santos USA and Baker Hughes Confidential Page 16 Figure 11: Interval 5 of LWD CBL Logging General Interpretation Comments: 9,250’ to 11,560’ Partial to Good. Mostly Good, with some intervals of partial cement presence. 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 August 13, 2024 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 08AUG24 (a)(2) Plat Provided with application. A.Dewhurst 08AUG24 (a)(2)(A) Well location Provided with application. Well lies in Sections 4-6 of T11N, R6E, Section 5 of T12N, R6E, and Section 36 of T12N, R6E, UM. A.Dewhurst 08AUG24 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online 08 Aug, 2024), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of Pikka NDB-051. There are no subsurface water rights or temporary subsurface water rights within 15 miles of the surface location of Pikka NDB-051. A.Dewhurst 08AUG24 (a)(2)(C) Identify all well types within ½ mile Qugruk-3, Qugruk-301, Qugruk-3A, Pikka NDBi-044, Pikka NDBi-014, and Pikka NDBi-046 A.Dewhurst 08AUG24 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Pikka Unit per salinity calculations provided by the operator on Aug. 21, 2023 as part of their Sundry Application to hydraulically fracture nearby well NDB-024 (see AOGCC’s Well History File 223-076, p. 101-107 of Sundry Application 323-591). Pickett Plot well-log analyses were performed on three wells within the unit that have wireline log coverage from surface through the fracturing interval: Colville River 1, Till 1, and Pikka DW-02. Estimated salinity values for clean, porous 100% water-saturated sands beneath the base of the permafrost layer in these three wells are: Colville River 1 (192-153) ~20,000 mg/l between 1,400 and 2,000’ MD (-1,354’ to 1,954' TVDSS; base of permafrost 1,350’ MD (-1,313’ TVDSS)); Till 1 (193-004) 16,700 to ~23,000 mg/l between 1,400’ and 1,500’ MD (-1,463’ to -1,363’ TVDSS; A.Dewhurst 08AUG24 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 August 13, 2024 base of permafrost 1,350’ MD (-1,305’ TVDSS)); and DW-02 (223-039) ~21,500 mg/l between 1,550’ and 1,650’ MD (-1,408’ to -1,486’ TVDSS; base of permafrost ~1,170’ MD (~-1,080’ TVDSS). (a)(4) Baseline water sampling plan None required. A.Dewhurst 08AUG24 (a)(5) Casing and cementing information Provided with application. Updated schematic attached, TOC included, completion jewelry included. CDW 08/13/2024 (a)(6) Casing and cementing operation assessment 13-3/8” surface casing cemented from shoe of 3218 ft to surface. Lead 200% excess, tail 50% excess, bump plug, floats held, 200 bbl clean cement to surface, 345 bbl total to cuttings box. 9-5/8” intermediate liner shoe at 11560 ft and cemented to approx. 9200-9250 ft (SoundTrak CBL). 30% excess pumped Versacem, 52 bbl losses reported. 2nd stage tool cement from 5678 ft to 3068 ft (circulated off liner top). 100% excess Versacem. Minimal losses reported. 4.5” liner hanger at 11378 ft with top open hole packer at 11663 ft and top frac sleeve of 11922 ft. CBL conservatively shows good cement at areas of interest so no cement concerns. CDW 08/13/2024 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) A.Dewhurst 08AUG24 (a)(6)( B) Each hydrocarbon zone is isolated Yes: The Nanushuk and Tuluvak hydrocarbon zones are both isolated. A.Dewhurst 12AUG24/ 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 August 13, 2024 Isolation for the Nanushuk is provided by the first stage cement job of the intermediate liner, which was set at 11,560’ MD. TOC was measured by LWD Acoustic CBL to be at 9,250’ MD – providing 928’ MD (225’ TVD) of isolation above the top of the Nanushuk Oil Pool. Isolation for the Tuluvak significant hydrocarbon zone is provided by the second stage cement job of the intermediate liner. The stage tool was placed at 5,678’ MD (85’ MD below the base of TS 790 marker) and as there were both no losses and contaminated cement returns to surface, TOC is estimated to be at the top of the liner. CDW 08/13/2024 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3800 psi 7/27/2024), MITT 6200 psi 7/27/2024. CDW 08/13/2024 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi wellhead max. frac. Pressure 8900 psi. Pump knock out 8000 and GORV 8500 psi. lines test 9000 psi. CDW 08/13/2024 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper Confining Zones: About 650’ true vertical thickness (TVT) of claystone, shale and volcanic tuff assigned to the Seabee Formation having an estimated fracture gradient of 13.7 ppg EMW (0.71 psi/ft). Fracturing Zone: Perforated zone lies within a subdivision of the Nanushuk Formation that is about 950’ TVT in this area and has an estimated fracture gradient of 11.7 ppg EMW (0.61 psi/ft). Lower Confining Zones: over 1,000’ TVT of Lower Torok (Hue) shales and interbedded siltstones with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft). A.Dewhurst 12AUG24 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 August 13, 2024 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Provided with application. Existing wells will not interfere with containment. x Qugruk-3: Nanushuk isolated with open hole cement plug 2. x Qugruk-301: Nanushuk isolated by intermediate stage 1 cement. x Qugruk-3A: Open hole plug 2 isolates Upper Nanushuk sands. x NDBi-014: Nanushuk isolation provided by first stage of intermediate liner cement job. TOC around 7,750' MD. x NDBi-044: Nanushuk isolation provided by first stage of intermediate liner cement job. Poor/patchy cement with zero returns. Third-party expert concluded that cumulative amount of patchy cement over both Nanushuk Oil Pool and upper confining zone provides sufficient isolation. x NDBi-046: Nanushuk isolation provided by first stage of intermediate liner cement job. TOC around 10,300' MD. A.Dewhurst 13AUG24/ CDW 08/13/2024 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory One fault that will not interfere with containment. The operator has identified one low-confidence fault from seismic within a ½-mile radius of Pikka NDB-051. It has less than 20’ of throw and tips out within the Nanushuk formation and does not offset the upper confining zone. Alternatively, it may be a stratigraphic feature. It is unlikely that this fault will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. A.Dewhurst 12AUG24 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 August 13, 2024 (a)(12) Proposed program for fracturing operation Provided with application. CDW 08/13/2024 (a)(12)(A) Estimated volume Provided with application. 19798 bbl total dirty vol. 2.5M lb total proppant CDW 08/13/2024 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 08/13/2024 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger and Tracerco disclosures provided. CDW 08/13/2024 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 08/13/2024 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 6875 psi. Max. 8900 psi allowable treating pressure. Max pressure is 8000 psi to 8500 psi to Pump shutdown. With 3300 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be less than 5600 psi. CDW 08/13/2024 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the mulit-stage induced fractures range from 339.5’ to 457’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 240’ to 247’ (minimum TVD of about 4,048’ and maximum TVD of about 4,338’), so it is unlikely induced fractures will penetrate into the overlying confining Seabee Shale that is about 650’ thick in this area. A.Dewhurst 13AUG24 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 08/13/2024 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3300 psi back pressure, tested to 3800 psi 7/27/2024, popoff set as 3600 psi CDW 08/13/2024 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” liner hanger at 11378 ft with top open hole packer at 11663 ft and top frac sleeve of 11922 ft. 9-5/8” intermediate CDW 08/13/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 August 13, 2024 liner shoe at 11560 ft and cemented to approx. 9200-9250 ft (SoundTrak CBL). 2nd stage tool cement from 5678 ft to 3068 ft (circulated off liner top). 13-3/8” surface casing cemented from shoe of 3218 ft to surface. CBL conservatively shows good cement at area of interest so no cement concerns. (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 6200 psi 7/27/2024 psi. Max pressure differential is estimated as 5600 psi (8900 with 3300 psi backpressure) so test of 6200 psi satisfies 110% requirement. CDW 08/13/2024 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9000 psi line pressure test, pump knock out 8000 and 8500 psi max. global kickout. IA PRV set as 3600 psi. CDW 08/13/2024 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 08/13/2024 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 08/13/2024 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 08/13/2024 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-051 (PTD No. 224-013; Sundry No. 324-441) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 August 13, 2024 (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 13AUG24 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 13AUG24 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 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: 2264 FSL, 3496 FEL, S04, T11N, R6E, UM Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): 1679 FSL, 2251 FEL, S06, T11N, R6E, UM GL: 23' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: ADL 392984, 1420 FSL, 340 FEL, S12, T12N, R5E, UM 391445, 393021, 393019, 392991 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) 22. Logs Obtained: GR-RES-NEU-DEN-Sonic 23. BOTTOM 20"x34" X-52 128' 13-3/8" BTC 2,302' 9-5/8" HYD563 4,124' 9-5/8" HYD563 2,270' 4-1/2" P-110S 4,137' 4-1/2" P-110S 4,099' 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 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# 3,063' 2,270' Surface 215" 68# 128' 3,063' 11,560' SIZE DEPTH SET (MD) N/A PACKER SET (MD/TVD) 12.6# 11,377' Surface 42" 12.6# Tubing CASING WT. PER FT.GRADE 05/27/24 CEMENTING RECORD 5,972,170.56 1,362'MD / 1,331' TVD SETTING DEPTH TVD 5,977,226.13 TOP HOLE SIZE AMOUNT PULLED 412,429.45 409,502.84 TOP SETTING DEPTH MD 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, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A 50-103-20880-00-00 NDB-051 LONS 19-003 05/03/24 17,478' MD / 4,137' TVD N/A 70' 900 E Benson Boulevard, Anchorage, AK 99508 421,748.11 5,972,652.87 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil Search Alaska, LLC WAG Gas 06/11/24 224-013 BOTTOM 16" Grouted to surface Surface See attached cement rpt 47# Surface Surface 3,218'Surface Surface 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 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, See attached cement rptTie Back TUBING RECORD Uncemented 11,434' 17,472' See attached cement rpt 4,087' Surface 12-1/4" 8-1/2" 17,472'4-1/2" N/A J G s d 1 0 D y t yp d P l L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 8:19 am, Jul 01, 2024 Completed 6/11/2024 JSB RBDMS JSB 071124 G DSR-7/31/24 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface 1,409' 1,374' Top of Productive Interval 11,632' 4,138' 1,055' 1,039' 1,835' 1,731' 2,582' 2,151' 3,939' 2,453' 4,218' 2,511' 5,593' 2,803' 6,670' 3,029' 10,178' 3,810' NT8 MFS 10,261' 3,830' NT7 MFS 10,364' 3,856' NT6 MFS 10,735' 3,944' NT5 MFS 10,940' 3,992' NT4 MFS 11,142' 4,038' NT3MFS 11,506' 4,113' NT3.24 11,762' 4,162' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Garret Staudinger Digital Signature with Date:Contact Email:garret.staudinger@santos.com Contact Phone: 907-440-6892 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: INSTRUCTIONS Tuluvak Sand TS_790 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. Nanushuk MCU NT3.2 Tuluvak Shale 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. Seabee Upper Schrader Bluff TPI (Top of Producing Interval). Authorized Name and Middle Schrader Bluff Formation Name at TD: 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. 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 N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov :6/28/2024 NDB-051 Well Schematic GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger/Top Packer3,063' MD 13-3/8" 68 ppf L-80 Surface Casing3,218' MD 9-5/8", 47ppf L-80 Intermediate Liner11,560' MD 4-½”, 12.6ppf P-110S Production Liner 17,472' MD 4-½” Liner Hanger/ Packer11,378' MD Archer C-Flex Two-Stage Cementing Tool (50' MD below TS 790 top) 5,678' MD TOC First Stage Cement Job – CBL Log9,200' MD 16" Hole Size 12-1/4" Hole Size 06.18.202447' RKB – Bottom Flange 9-5/8" Tieback Assembly3,063' MD 8-½” Openhole 17,478' MD 9 8 3 4 5 6 7 1 2 #CompletionItem TopDepth(MD') Depth(TVD') Inc ID" OD" 1XLandingNipple 1607 1546 33 3.813 4.778 2GasliftMandrel1.5" 2204 1980 55 3.865 7.630 3XLandingNipple 2272 2017 58 3.813 4.783 4XLandingNipple 11085 4025 77 3.813 4.787 5D/HPsiͲTempGauge 11148 4039 77 3.905 6.000 6SSDNERAGaslift 11211 4052 78 3.813 5.040 7 SlimlineDialUnit 11277 4067 78 3.893 6.002 8XLandingNipple 11309 4073 78 3.813 4.783 9TiebackSealAssy 11413 4094 79 3.860 5.230 10 9.625"x4.5"LH/Packer 11378 4087 79 6.030 8.430 11 #12OpenholePacker 11663 4144 79 3.918 8.000 12 #11OpenholePacker 11731 4156 80 3.918 8.000 13 Stage 10ͲFracSleeve 11922 4180 86 3.735 5.624 14 #10OpenholePacker 12235 4182 90 3.918 8.000 15 Stage 9ͲFracSleeve 12509 4180 90 3.735 5.624 16 #9OpenholePacker 12779 4178 90 3.918 8.000 17 Stage 8ͲFracSleeve 13095 4175 90 3.735 5.624 18 #8OpenholePacker 13407 4173 90 3.918 8.000 19 Stage 7ͲFracSleeve 13680 4170 90 3.735 5.624 20 #7OpenholePacker 13989 4167 90 3.918 8.000 21 Stage 6ͲFracSleeve 14261 4165 90 3.735 5.625 22 #6OpenholePacker 14489 4162 90 3.918 8.000 23 Stage 5ͲFracSleeve 14803 4160 90 3.735 5.624 24 #5OpenholePacker 15113 4157 90 3.918 8.000 25 Stage 4ͲFracSleeve 15426 4155 90 3.735 5.624 26 #4OpenholePacker 15653 4153 90 3.918 8.000 27 Stage 3ͲFracSleeve 15965 4148 90 3.735 5.624 28 #3OpenholePacker 16233 4144 90 3.918 8.000 29 Stage 2ͲFracSleeve 16589 4139 90 3.735 5.624 30 #2OpenholePacker 16859 4138 90 3.918 8.000 31 Stage 1ͲFracSleeve 17172 4138 90 3.735 5.624 32 #1OpenholePacker 17319 4138 90 3.918 8.000 33 #2Toe Sleeve 17387 4138 90 3.500 5.750 34 #1Toe Sleeve 17399 4138 90 3.500 5.750 35 WIV Collar 17462 4137 90 0.870 5.610 36 Eccentricshoe 17471 4137 90 3.900 5.190 AS BUILT CERTIFICATION 3230 "C" Street, Ste. 201 Anchorage, Alaska 99503 PHONE: (907) 272-5451 FAX : (907) 272-9065 http://www.LOUNSBURYINC.com Certificate of Authorization No. AECC391 DATE: SHEET: FIELD BOOK: DRAWING NAME: DRAWN: CHECKED: GRID: OF SCALE: NORTH SLOPE BOROUGH PROJECT LOCATION: STATE OF ALASKA PIKKA UNIT AS BUILT SURVEY WELL 51 ND-B PAD CONDUCTORS WITHIN SECTION 4, TOWNSHIP 11 NORTH, RANGE 6 EAST, UMIAT MERIDIAN VICINITY MAP N Page 1 of 1 Well Name: NDB-051 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,399.3 4,091.8 HES Zoneguard OH Packer #12 11,669.4 4,145.1 HES Zoneguard OH Packer #11 11,737.4 4,157.6 HES Zoneguard OH Packer #10 12,241.3 4,182.6 HES Zoneguard OH Packer #9 12,785.8 4,178.7 HES Zoneguard OH Packer #8 13,414.0 4,172.9 HES Zoneguard OH Packer #7 13,996.1 4,167.5 HES Zoneguard OH Packer #6 14,495.4 4,162.8 HES Zoneguard OH Packer #5 15,119.4 4,157.8 HES Zoneguard OH Packer #4 15,659.9 4,153.5 HES Zoneguard OH Packer #3 16,240.1 4,147.9 HES Zoneguard OH Packer #2 16,865.6 4,142.1 HES Zoneguard OH Packer #1 17,325.7 4,138.1 Page 1 of 1 Well Name: NDB-051 Cement Surface Casing Cement Surface Casing Cement, Casing, 5/6/2024 15:00 Type Casing Cementing Start Date 5/6/2024 Cementing End Date 5/6/2024 Wellbore Original Hole String Surface Casing, 3,218.8ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 200 bbls of clean cement returned to surface. Comment Cement 13-3/8” Surface Casing as follows: -M/U cement hose, PJSM with 3rd party and all rig personnel -Fill lines with water and pressure test to 3,500 psi for 3 minutes -Drop 1st Bottom Non-Rotating Plug -Pump 80 bbls of 10.5 ppg Tuned Spacer at 6 bpm, 391 psi. -Release 2nd Bottom Non-Rotating Plug -Pump 452 bbls of 11.0 ppg ArcticCem lead cement at 6 bpm, Excess Volume 200% (1,002 sacks, yield 2.535 cu.ft/sk) -Pump 72 bbls of 15.3 ppg Type I/II tail at 3.7 bpm, Excess Volume 50% (310 sacks, yield 1.24 cu.ft/sk) -Drop top plug and chasse with 2 bbls Tail Cement -Perform displacement with rig pumps and 10.0 ppg mud -410 bbls displaced at 6 bpm: ICP 181 psi 10% return flow, FCP 757 psi 5% return flow. -33 bbls displaced at 3 bpm: ICP 540 psi 5% return flow, FCP 525 psi 5% return flow. -Reduce rate to 3 bpm prior to plug bump: Final circulating pressure 525 psi prior to plug bump. -Bump plug and increase pressure to 1,140 psi, check floats – good. -Total displacement volume 443 bbls (measured by strokes at 96% pump efficiency). -Observed 82 bbls of mud / tuned spacer contaminated returns, 63 bbls of cement / Tuned Spacer contaminated returns, and 200 bbls clean cement to surface. A total of 345 bbls were dumped to the cuttings box. -Total losses from cement exit shoe to cement in place: 0 bbls. - CIP at 2030 hrs. 1, 0.0-3,228.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 3,228.0 Full Return? Yes Vol Cement Ret (bbl) 200.0 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) 525.0 Plug Bump Pressure (psi) 525.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Lead Fluid Type Lead Fluid Description ArcticCem Amount (sacks) 1,002 Class I/II Volume Pumped (bbl) 452.0 Estimated Top (ftKB) 0.0 Percent Excess Pumped (%) 200.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) 0.00 Density (lb/gal) 11.00 Plastic Viscosity (cP) 18.0 Thickening Time (hr) 13.39 1st Compressive Strength (psi) 750.0 CmprStr Time 1 (hr) 129.00 Tail Fluid Type Tail Fluid Description Type I/II Amount (sacks) 310 Class Type I/II Volume Pumped (bbl) 72.0 Estimated Top (ftKB) Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 23.3 Thickening Time (hr) 6.34 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 11.40 Page 1 of 1 Well Name: NDB-051 Cement 1st Stage 9-5/8" Liner Cement 1st Stage 9-5/8" Liner Cement, Casing, 5/21/2024 03:35 Type Casing Cementing Start Date 5/21/2024 Cementing End Date 5/21/2024 Wellbore Original Hole String Intermediate Liner, 11,560.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Evaluation Results Comment Conduct 1st Stage Cement Job of 9-5/8”, 47#, L-80, Hyd 563 Liner. -Pressure test cement lines to 5000 psi. -Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 2.9-3 bpm, 93% returns. -Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 2.9-3 bpm, Excess Volume 30% (839 sacks, yield 1.237 cu.ft/sk), initial circulating pressure 440 psi. -Added 300 lbs of Halliburton Bridgemaker II LCM to cement: 10 bbls neat cement ahead, 60 bbls with LCM added, 115 bbls of neat cement. -Land dart at 69 bbls away at 2.9 bpm at latch (1.5 bbls behind as calculated), clear indication of latch and release at 1000 psi. -Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 185 bbls at average of 2.9 bpm, 235-400 psi, excess volume 30% (839 sacks, yield 1.237 cu ft/sk). -Release top pump down plug, chase with 20 bbls of washup from Halliburton. -Perform displacement with rig pumps, displace with 11.8 ppg OBM at 2.5 bpm, ICP 272 psi 1% return flow, FCP 600 psi 7% return flow. -Top pump down dart latch up confirmed at 45 bbls displaced. -Continue to displace with 11.8 ppg OBM, reduce rate to 2.5 bpm prior to plug bump: Final circulating pressure 600 psi. -Total displacement volume 656 bbls (measured by strokes at 96% pump efficiency). -Total losses from cement exit shoe to cement in place: 52 bbls w/4 bbls bleed back. 1, 8,352.0-11,560.0ftKB Top Depth (ftKB) 8,352.0 Bottom Depth (ftKB) 11,560.0 Full Return? No Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 3 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 3 Final Pump Pressure (psi) 286.0 Plug Bump Pressure (psi) 602.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail Amount (sacks) 840 Class I/II Volume Pumped (bbl) 185.0 Estimated Top (ftKB) Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 122.3 Thickening Time (hr) 5.28 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 9.11 Page 1 of 1 Well Name: NDB-051 Cement 2nd Stage 9-5/8" Liner Cement 2nd Stage 9-5/8" Liner Cement, Casing, 5/22/2024 03:40 Type Casing Cementing Start Date 5/22/2024 Cementing End Date 5/22/2024 Wellbore Original Hole String Intermediate Liner, 11,560.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 41 bbls contaminated cement returns to surface. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 5691’ (center of circulation port) as follows: -Mix and pump 80 bbls of 12.5 ppg Mud Push Spacer at 4 bpm, 90% returns (both spacers with Surfactant B and Musol A). -Mix and pump 80 bbls of 13.5 ppg Tuned Spacer at 4 bpm, 230 psi, full returns. -Mix and pump 284 bbls of 15.3 ppg Versacem Type I-II Tail cement at 3.85 bpm initial, ICP 450 psi, FCP 285 psi at 3 bpm -Excess Volume 100% (1288 sacks, yield 1.237 cu ft/sk). Displace Cement from 9-5/8” 47# Intermediate casing, 2nd Stage. -Displace to calculated volume of 132 bbls to Archer Stage Collar. -Begin displacing with 20 bbls fresh water from cementing unit. -Continue to displace using rig pumps with 112 bbls, 11.8 ppg OBM. -Stage up to 4 bpm, 860 psi ICP , 7% flow returns; 4 bpm 875 psi FCP. -Slow displacement to 3 bpm, 640 psi, last 10 bbls. -0 bbls lost during displacement -CIP at 06:12 hrs 2, 3,069.0-5,678.0ftKB Top Depth (ftKB) 3,069.0 Bottom Depth (ftKB) 5,678.0 Full Return? No Vol Cement Ret (bbl) 41.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 3 Final Pump Pressure (psi) 285.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Mud Push Spacer with 8 LBS of Red Dye, 65 Gal of Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.86 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Spacer Fluid Type Spacer Fluid Description Tuned Spacer with 4 LBS of Red Dye, 65 Gal of Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 0.00 Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 1,289 Class I/II Volume Pumped (bbl) 284.0 Estimated Top (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 5.56 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 27.20 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 5/1/2024 5/2/2024 0 No accidents, incidents or spills. Prep rig for move from PWD-02 to NDB-051. Diagnose and repair electrical fault preventing derrick from being layed down. Move rig from PWD-02 to NDB- 051 and spot Drill Module over well. 5/2/2024 5/3/2024 0 10.00 No accidents, incidents or spills. Spot Rig Modules on NDB-051. Connect power, raise derrick, skid floor. Rig up and prep for Spud. Take on Spud Mud. Complete Rig acceptance checklist. Accept rig for operations @ 17:00 hrs 5-2-24. Sent Notification of Diverter Function Test at 08:00 hrs on 5-03-2024 to AOGCC at 06:00 hrs. 5/3/2024 5/4/2024 125 915.00 10.00 No accidents, incidents or spills. Build 5-7/8" DP stands. Function test Diverter, annular, fire and gas alarms. Test PVT's, Flow out %, draw down test. 19 seconds to open knife valve, 24 seconds to close annular (Successful Test). Testing witnessed by AOGCC Rep Kam St. John. Drill 16" Surface hole from 125' to 135'. Drill 16" Surface hole from 135' to 249'. POH to P/U remaining BHA from 249' to 56'. P/U Ontrack, BCPM, MWD and plug in and initialize tools. Drill Surface hole from 249' MD to 1,040' MD (1,025' TVD). 5/4/2024 5/5/2024 1,040 1,586.00 10.05 No accidents, incidents or spills. Drill 16" Surface hole from 1,040' MD to 1,893' MD. BROOH from 1,893' MD to 1,607' MD. POH on elevators from 1.607' MD to 622' MD. RIH from 622' MD to 1,893' MD P/U 8" Drilling jars. Resume drilling 16" Surface hole from 1,893' MD to 2,626' MD. 5/5/2024 5/6/2024 2,626 602.00 10.10 No accidents, incidents or spills. Drill 16" Surface hole from 2,626' MD to Section TD at 3,228' MD. BROOH from 3,228' MD to 1,630' MD. POH on elevators from 1,630' MD to 862’ MD. Lay down BHA as per Baker rep. Mobilize casing running equipment to rig floor. 5/6/2024 5/7/2024 3,228 0.00 10.00 No accidents, incidents or spills. Continue to rig up 13-3/8" casing running equipment. Run 13- 3/8", 68#, L-80, BTC casing to 900' MD. Tight spot at 900' MD, circulated bottoms up 2x at 900' MD, washed down to 915' MD, picked up joint #23 and washed it down to 948' MD. Continued to run 13-3/8" casing from 948' MD to 3218' MD. AOGCC 24 hr notification for BOP test made at 06:00 5/6/2024. Performed 13-3/8" casing cement job. Pumped 80 bbls of 10.5 ppg Tuned Spacer @ 6 bpm, 391 psi. Pumped 452 bbls of 11.0 ppg ArcticCem Lead cement @ 6 bpm, excess volume 200%. Pumped 72 bbls of 15.3 ppg Type I/II Tail cement @ 3.7 bpm, excess volume 50%. Observed 82 bbls of mud/tuned spacer contaminated returns, 63 bbls of cement/tuned spacer contaminated returns and 200 bbls clean cement to surface. Total of 345 bbls were dumped to cuttings box. Total losses from cement exit shoe to cement in place 0 bbls. Cement in place at 20:30 hrs. Rig down Halliburton cementers. 5/7/2024 5/8/2024 3,228 0.00 10.05 No accidents, incidents or spills. ND diverter, knife valve and risers. Install 13-3/8” 5k Slim Hole Uni-Head. R/U test sub to TD. Test BOPE to 250 psi low, 3,500 psi high for 5 minutes each (Successful Test). Test witnessed by AOGCC Rep Brian Bixby. Tested with 5 7/8” and 9 5/8” test joints, test annular with 5 7/8” Joint. Test 13 3/8” casing to 2,600 psi for 30 min (Successful Test). Record on chart. Lost a total of 85 psi in 30 min. 5.5 bbls pumped 5.5 bbls bled back. Make up 12 ¼” AutoTrak directional BHA as per Baker DD. RIH with directional BHA on elevators from 429’ MD to 3,082’ MD. Wash down and tag cement at 3,115’ MD. 5/8/2024 5/9/2024 3,228 1,724.00 11.95 No accidents, incidents or spills. Circulate and condition mud. Test 13 3/8” casing to 2,600 psi for 30 min. Record on chart. Shut in pressure – 2,834 PSI. 15 min pressure – 2,811 PSI. Lost 23 PSI. 30 min pressure – 2,802 PSI. Lost 9 PSI. Total pressure lost 32 PSI. Good test. Displace from 10.0 ppg WBM to 12.0 PPG OBM. Drill out shoe track per plan. Drill 20' to 3,248’ MD of new formation. Pull into casing, conduct FIT with good test to 16.1 ppg EMW. Drill ahead in 12-1/4” hole section from 3,248’ MD to 4,952’ MD. 5/9/2024 5/10/2024 4,952 1,920.00 11.95 No accidents, incidents or spills. Drill ahead in 12-1/4" Intermediate hole from 4,952’ MD to 6,872’ MD. Circulate bottoms up 3 times while standing back a stand with each bottoms up. Conduct planned Backream operation to 13-3/8” casing shoe per K&M guidance; backream to 5,235’ MD as of midnight. 5/10/2024 5/11/2024 6,872 0.00 12.00 No accidents, incidents or spills. Complete backream/pump-out from 5,235’ MD up to 13-3/8” shoe, circulate bottoms up and flow check. Stage into hole on elevators to 4,120’ MD, circulate bottoms up. 5/11/2024 5/12/2024 6,872 2,463.00 12.00 No accidents, incidents or spills. Stage into 12-1/4" Intermediate hole on elevators, CBU at 4,590 MD’, clean returns and SOW. RIH on elevators to TD of 6,872’ MD. Drill ahead in 12-1/4” Intermediate section to 9,335’ MD per plan. Well Name Wellbore Name PTD # Start Drill Date End Drill Date Page 1 of 5 Well Name NDB-051 Wellbore Name Original Hole PTD # 224013 Start Drill Date 4/1/2023 End Drill Date 6/12/2024 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 5/12/2024 5/13/2024 9,335 2,231.00 12.00 No accidents or spills, one incident: Mud Lab equipment used for solids analysis started smoking. When Engineer opened door to investigate, a very small flame was observed on the cell sleeve. A nearby fire extinguisher was used to put it out. No further assistance was required, under investigation. Drill ahead in 12-1/4” Intermediate section per plan from 9,335’ MD to planned section TD of 11,566’ MD. Circulate cleanup cycles. 5/13/2024 5/14/2024 11,566 0.00 12.00 No accidents, incidents or spills. Backream out of 12-1/4" Intermediate hole from TD of 11,566’ MD to 7,631’ MD per well plan and K&M guidance. 5/14/2024 5/15/2024 11,566 0.00 12.00 No accidents, incidents or spills. Backream out of hole from 7,631’ MD to 6,247’ MD per revised plan. 5/15/2024 5/16/2024 11,566 0.00 12.00 No accidents, incidents or spills. Backream from 6247' to 5589' MD and unable to make further progress. Pump out of hole at 2 bpm and 40-50 RPM from 5589' to 4245' MD. 5/16/2024 5/17/2024 11,566 0.00 12.05 No accidents, incidents or spills. Complete backream out of hole from 4245’ to 13-3/8” casing shoe at 3218’, pull into Shoe and Circulate bottoms up until clean. Run in hole on elevators from 3185' to 7350' md, while circulating intermittent cleanup cycles for hole evaluation. 5/17/2024 5/18/2024 11,566 0.00 12.05 No accidents, incidents or spills. Run in hole from 7350’ to TD of 11,566’ md. Circulate bottoms up 3 times while racking back a stand per hour. Flow check, pump out at 2 bpm to casing shoe. Circulate bottoms up. 5/18/2024 5/19/2024 11,566 0.00 12.05 No accidents, incidents or spills. Flow check. Drop 2.5” drift, POOH to lay down BHA. Prep for running 9-5/8” Intermediate Liner. Rig up and run 9-5/8”, 47#, L-80, Hyd 563 Liner to 3217’ md. H2S evac drill 15 min for rig secure, rig personnel, wells to respond to primary muster area. 12 min for construction personnel. Roll call good. Rig secured. 5/19/2024 5/20/2024 11,566 0.00 12.00 No accidents, incidents or spills. Run 9-5/8” 47#, L-80, Hyd 563 Intermediate Liner while conducting intermittent circulations. Make up Baker Liner Top Hanger and Packer assembly to one stand of 5-7/8” drill pipe. Circulate full liner volume to ensure clear. 5/20/2024 5/21/2024 11,566 0.00 11.80 No accidents, incidents or spills. Circulate full liner volume to ensure clear after MU Liner Hanger and Running Tool. Complete running 9-5/8” 47#, L-80, Hyd 563 Intermediate Liner on 5-7/8” drill pipe and HWDP to TD. Lower mud weight from 12.0 ppg to 11.8 ppg, circulate to condition well for cement job. 5/21/2024 5/22/2024 11,566 0.00 11.75 No accidents, incidents or spills. Complete conditioning mud for cement operation. Set Liner top hanger. Conduct first-stage cement job per Halliburton plan. Circulate above liner top, POOH with BHA and lay down. Make up, RIH with Archer cementing tool and packers setting tool BHA. Function test through Archer C-flex, open C-flex and circulate to condition mud. Prepare to pump spacer, pump failure caused delay in operations. *Received approval from Jim Regg with AOGCC for BOPE test extension until after 2nd stage cement job was complete. 5/22/2024 5/23/2024 11,566 0.00 11.75 No accidents, incidents or spills. Repair rig pumps. Pump cased hole spacer per plan followed by Second Stage Cement job through Archer tools. Pump 80 bbls of 12.5 ppg Mud Flush Spacer, pump 80 bbls of 13.5 ppg Tuned Spacer, pump 284 bbls of 15.3 ppg Versacem Type I-II Tail cement. FCP 285 psi at 3 bpm. CIP at 06:12. Permanently close Archer C-Flex, set liner top packer, circulate wellbore clean of cement. 41 bbls of cement returned to surface. POOH, lay down BHA, conduct full BOP test. Test BOPE to 250 psi low, 3500 psi high for 5 minutes each. Test with 4-1/2", 5” and 9-5/8” test joints, test annular with 4-1/2” Joint (Successful Test). Test witnessed waived by AOGCC Rep Adam Earl. Page 2 of 5 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 5/23/2024 5/24/2024 11,566 0.00 11.75 No accidents, incidents or spills. Complete changing out Saver Sub to 5”. Run in hole to conduct Polish Mill cleanout run at Liner Top. POOH with Cleanout BHA, prep for running tie-back assembly. Run 9-5/8” Tie-back assembly, space out and Freeze protect backside with 183 bbls diesel, land with hanger. Conduct Annulus pressure test to 2600 psi: Initial test pressure 2872, lost 124 psi to 2748 in first 15 minutes, lost 30 psi with decline to 2718 psi in second 15 minutes, total 139 psi lost – good test. 5/24/2024 5/25/2024 11,566 0.00 11.70 No accidents, incidents or spills. Rig down casing running equipment, drain stack. Install 9-5/8” casing packoff, test to 5K, good test. Conduct 30-minute casing pressure test to 3500 psi: Initial test pressure 3958, lost 35 psi to 3923 in first 15 minutes, lost 25 psi with decline to 3898 psi in second 15 minutes, ran test additional 15 minutes for an 18 psi loss, total 78 psi lost – good test. Vol in 13 bls, Vol bled back 13 bbls. Discuss with Engineer, conduct second 30-minute test to confirm results, test to 3500 psi: Initial test pressure 3979, lost 33 psi to 3946 in first 15 minutes, lost 20 psi with decline to 3926 psi in second 15 minutes, good test. Vol in 13 bbls, Vol bled back 13 bbls. Change out 9- 5/8” Fixed Rams to 4-1/2” x 7” Variable Rams, test with 4-1/2” and 5” test joints to 250 psi low / 3500 psi high (Successful Test). Make up and run in hole with 8-1/2” Production drilling BHA to 9240’. 5/25/2024 5/26/2024 11,566 999.00 10.15 No accidents, incidents or spills. Run in hole with 8-1/2” Production drilling BHA from 9240’ to 11,472’. Displace from 11.8 ppg MOBM to 10.0 ppg MOBM. Mill out shoe track assembly, drill 20’ of new formation. Pull into shoe, conduct LOT Pumped 4.2 bbls to 1025 psi where it broke over to leak off. IBOP did not close and pressure bled off to 790 psi before it shut in (Unsuccessful Test). Decision made to bleed off and retest. Pump 2.6 bbls to 740 psi to break over and leak off. Initial shut-in pressure 740 psi, shut in pressure after 5 mins 592 psi, after 10 mins 561 psi. LOT equal to 13.8 ppg EMW, 2.5 bbls bled back after test (Successful Test). Drill ahead in 8-1/2” Production Hole from 11,586’ to 12,565’ md. 5/26/2024 5/27/2024 12,565 2,473.00 10.05 No accidents, incidents or spills. Drill ahead in 8-1/2” Production Hole from 12,565’ to 15,038' md. 5/27/2024 5/28/2024 15,038 2,440.00 10.00 No accidents, incidents or spills. Drill ahead in 8-1/2” Production Hole from 15,038' to TD of 17,478'. 5/28/2024 5/29/2024 17,478 0.00 9.95 No accidents, incidents or spills. Circulate bottoms up from TD per plan. Flow check off bottom, Backream from TD to 9-5/8” shoe at 11,560’ per K&M plan. Circulate bottoms-up 3 times from 11,422’. 5/29/2024 5/30/2024 17,478 0.00 10.00 No accidents, incidents or spills. Circulate bottoms up from inside casing. Conduct Sonic log while pumping out with no rotation to 8,300’ MD for cement evaluation, pump out to 8,000’ MD. Drop 2.5” drift, POH to LD BHA. Function test rams and annular, successful without incident. RU for and run 4-1/2” Lower Completion per running summary. 5/30/2024 5/31/2024 17,478 0.00 10.05 No accidents, incidents or spills. Run 4-1/2" 126# P-110 TSH 563 Production Tubing Assembly from 600' MD to 6011' MD per running summary. MU Baker SBE & SLZXP liner top hanger/packer assembly, RIH 1 stand and circulate full liner volume. Rig down casing handling equipment. Run Lower Completions Assembly on DP from 6183' MD to 11,733' MD. Observed tight spot at 11,743' MD. Made multiple attempts with different pump rates to wash through. No go. Discuss with team next steps forward. Continue to attempt to work pipe free until pipe became stuck with no free travel and unable to rotate. Dropped 1.5" backup ball and circulate to seat as per Baker rep. Ball seated. Monitor well for 10 minutes. Static. POOH on elevators from 5650' MD to surface, layed down running tool. Top of fish at 5661' MD. 5/31/2024 6/1/2024 17,478 10.05 No accidents, incidents or spills. Clean and clear floor of OBM. Cut and slip drill line. MU Spear Fishing assembly and RIH from surface to 5,640' MD. Grapple and unscrew PBR from Hanger. Monitor well for 10 minutes, static. POH on elevators from 5640' MD to 125' MD. Lay down Fishing BHA & recover PBR. MU Packer Milling BHA as per Baker rep and RIH from surface to 5,672' MD, tag liner hanger. Mill liner hanger from 5,672' MD to 5,674' MD. Page 3 of 5 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 6/1/2024 6/2/2024 17,478 10.20 No accidents, incidents or spills. Mill Liner Hanger from 5,674' MD to 5,682' MD. Pump sweep every 2'. Milled total of 10'. Pumped sweep at 5,690' MD. Monitor well for 10 minutes, static. POOH with Milling BHA from 5,690' MD to 3,134' MD. Observed overpull at 3,134' clean P/U wt 105K, pulled 20K over several times without success. Make up Top Drive and CBU. Backream from 3,134' MD to 3,025' MD while CBU. POH from 3,025' MD to BHA. Rack back DC's, clean magnets, break, lay down & inspect mill. Lay down & clean junk baskets. 164 lbs metal from magnets, 5 lbs metal from junk baskets. MU Clean Out BHA and RIH from 171' MD to 5,690' MD. Circulate 2X Bottoms Up. 6/2/2024 6/3/2024 17,478 10.10 No accidents, incidents or spills. Continue to circulate 2X Bottoms Up. POOH on Elevators w/Clean Out BHA #3 from 5,682' MD to 171' MD. Rack back and clean magnets, junk basket and RCJB. Recovered 115 lbs. metal. MU Fishing BHA #4 and RIH from 171' MD to 5,682' MD. MU Top Drive break circulation, Monitor well for 10 minutes, well static. POOH on Elevators w/Fishing Clean Out BHA #4 from 5,715' MD to 171' MD. Lay down Fishing Clean Out BHA #4, total metal from magnets and Boot baskets was 115 lbs. MU Fishing Clean Out BHA #5 and RIH from 171' MD to 5,715' MD. RIH from 5,715' MD to 5,735' MD. No indication of Fish, circulate Bottoms Up. 6/3/2024 6/4/2024 17,478 10.15 No accidents, incidents or spills. Continue to circulate 2X Bottoms Up. POOH on elevators from 5,730' MD to 170' MD. Lay down Fishing Clean Out BHA. Recovered 57 lbs metal on magnets. RCJB and junk baskets empty. MU Fishing Spear BHA assembly and RIH to recover Lower completions assembly from 174' MD to 5,689' MD. Tagged Fish at 5,699' MD to attempt to engage Fish. Pump out of hole with Fish from 6,050' MD. Lay down Fishing Spear BHA assembly, release spear from Fish. 86 lbs metal shavings recovered from magnets, 1 lb from ditch magnets and 679 lbs total recovered. Rig up TRS casing tools to lay down 4-1/2" Liner. 6/4/2024 6/5/2024 17,478 10.30 No accidents, incidents or spills. Continue to rig up TRS casing tools to lay down 4-1/2" Production Liner. Lay down 4-1/2" Production Liner from 6,047' MD to surface. Rig down casing equipment and clean rig floor. PU Cased Hole Clean Out BHA RIH to 5,690' MD. Ream & work string mills through Archer C-Flex tool multiple times. RIH from 5,690' MD to 6,184' MD. POOH from 6,184' MD to 1,618' MD, Passed through C-Flex and Liner top clean with no issues. **BOP Test notification was submitted on 6/3/2024 at 08:55 hrs. **Witness waived by Josh Hunt 6/4/2024 at 15:30 hrs. 6/5/2024 6/6/2024 17,478 0.00 10.25 No accidents, incidents or spills. POOH on elevators from 1,618' MD to 192' MD. Lay down Cased Hole Clean Out BHA from 192' MD. Make up string magnet to wear ring puller and pull wear ring. Make up magnet to Stack washer and jet stack. Break and lay down magnet. Test BOPE to 250 psi low, 3,500 psi high for 5 minutes each. Test with 5” and 4.5” test joints, test annular with 4.5” Joint. Perform Accumulator draw down test (Successful Test). Test Witness Waived by AOGCC Rep Josh Hunt. M/U cleanout BHA and TIH to 8,919’. 6/6/2024 6/7/2024 17,478 0.00 10.00 No accidents, incidents or spills. RIH with 8.5" Directional Clean Out BHA. Circulate and condition mud at shoe. Continue RIH on elevators from 11,565' to 12,994' MD. Some losses observed with 400 gpm/1800 psi/60 rpm/13K TQ. Reduced to 200 gpm/862 PSI and observed some ballooning. Continue RIH on elevators from 12,994' to 15,270' MD. Break circulation at 15,270' MD, staged pumps up to 10 bpm, 1810 psi, pumped 1/2 BU, no losses. Continue RIH on elevators from 15,270' to 17,367' MD. Circulate and condition mud, wash last stand to bottom from 17,367' to 17,478' MD, circulate 1X BU, minimal losses observed at 9 bpm. BROOH from 17,478' to 17,263' MD. Pump out of hole from 17,263' to 12,757' MD. 6/7/2024 6/8/2024 17,478 0.00 10.00 No accidents, incidents or spills. Pump out of hole from 12,757 to 11,560’ MD. Circulate bottoms up at the shoe 11,560’ while pulling one stand to 11,465’ MD. Pump out of the hole from 11,465’ to Archer tool at 7,762’ MD. Pull on elevators from 7,762’ to 5,766’ MD. Wash Archer C-Flex tool from 5,690 to 5,670’ MD. POH with Clean out BHA from 5,766’ to BHA. Lay Down Clean out BHA. R/U 4 ½” casing tools to run 4 ½” Lower Completion. Run 4 ½” 12.6# P-110 Hyd 563 Lower Completion per running tally to 4,550’ MD. Page 4 of 5 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 6/8/2024 6/9/2024 17,478 0.00 9.40 No accidents, incidents or spills. Run 4-1/2” 12.6# P-110S TSH 563 Production Tubing Assembly from 4,550’ to 6011’ MD. MU Baker SBE, & SLZXP liner top hanger/packer assembly. Run Lower Completions on DP from 6183’ to 11,435’ MD. Slow running speed to 30 ft/min past 9 5/8” tieback. (No resistance observed). Work Completion string down w/ No pumps or Rotation from 11,435 - 11,727’ MD. Set down 6k @11,727’ P/U to Sting wt. & rotate 2 turns to right. Continue S/O thru Archer tool from 11,727’ to 11,805’ MD with minimal down drag. 8-10 ft/min. RIH In Hole with Lower Completion from 11,805’ to TD. Perform 1st stage displacement to 10.0 PPG NaCl/KCL Brine. Set SLZXP liner hanger/packer and release running tool. Pressure test liner hanger/packer to 3,500 PSI for 10 mins. Good test. Begin 2nd stage displacement to 9.4 PPG corrosion inhibited NaCl/KCL brine. 6/9/2024 6/10/2024 17,478 0.00 9.40 No accidents, incidents or spills. Continue 2nd stage displacement to 9.4 PPG corrosion inhibited NaCl/KCL brine. POOH on elevators from 11,332’ to 9,380’ MD. PJSM: Cut and slip drill line. POOH on elevators from 9,380’ to Surface. Break and L/D Baker Liner running tools. Pull wear bushing. R/U to Run 4 ½” Upper Completion Equipment. RIH with 4-1/2” 12.6#, P-110S TSH563 Upper Completions Assembly from surface to 606’ MD. 6/10/2024 6/11/2024 17,478 0.00 9.40 No accidents, incidents or spills. RIH with 4-1/2” 12.6#, P-110S TSH563 Upper Completions Assembly from 606’ to 6,669' MD. Perform Well control Drill, Secure well. Evacuate to Muster area. Perform 1 year Drilling operations Anniversary, BBQ for all drilling and third party Personnel. Continue RIH with 4-1/2” 12.6#, P-110S TSH563 Upper Completions Assembly from 6,669’ to 11,398' MD. PU and make up DP to tubing string. Establish circulation through tubing string at 250 GPM / 230 PSI for 10 mins. Reduce rate to 1 BPM to engage seal bore. Observed pressure increase and 3k down drag. Shut pumps and bleed off pressure. Slack off to tag no-go at 11,436’ MD. Re-tag to confirm. LD DP and two joints of tubing. 6/11/2024 6/12/2024 17,478 0.00 9.40 No accidents, incidents or spills. PU space out pups and MU tubing hanger. Terminate and test Silverwell and SLB lines. MU landing joint. Land hanger Verify hanger is landed, run in lock down screws. B/O and Lay down landing jt. and Crossover. R/U to test tubing and IA. Pressure test Tubing to 250 psi low for 5 min / 4,000 psi high for 30 min, test approved by Santos WSS John Whitlach . Pressure test IA to 250 psi low for 5 min/ 3,500 psi high for 30 min, test approved by Santos WSS Brian Buzby. R/U and Freeze protect tubing & IA to 1,500’ with Diesel. Pump 105 bbls diesel down IA, 1.5 bpm, ICP 100 psi FCP, 275 psi. U-tube diesel for 1Hr. M/U T-bar and install TWC. Blow down mudline, blow down choke and kill lines. Nipple Down BOPE. N/D Fast lock adapter. Perform Rig and Pad evacuation Drill all personnel Muster to Pad entrance. Continue to terminate tech wire at wellhead. Nipple up tree and adapter as per FMC Rep. 6/12/2024 6/12/2024 17,478 0.00 9.40 No accidents, incidents or spills. Test void on hanger to 5,000 PSI for 10 mins. Open actuator and fill tree with test oil. Test tree to 10,000 PSI for 10 mins. Unplug mud mod electrical interconnect. Inspect and prepare carrier bay for rig move. Lower derrick and anti-seez pins. ***Rig Release from NDB-051 at 02:00*** Page 5 of 5 Sa n t o s D e f i n i t i v e S u r v e y R e p o r t 14 J u n e , 2 0 2 4 De s i g n : N D B - 0 5 1 Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B ND B - 0 5 1 ND B - 0 5 1 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e Ma p S y s t e m : Ge o D a t u m : Pr o j e c t Ma p Z o n e : Sy s t e m D a t u m : US S t a t e P l a n e 1 9 2 7 ( E x a c t s o l u t i o n ) NA D 1 9 2 7 ( N A D C O N C O N U S ) Pi k k a , N o r t h S l o p e A l a s k a , U n i t e d S t a t e s Al a s k a Z o n e 0 4 Me a n S e a L e v e l Us i n g W e l l R e f e r e n c e P o i n t Us i n g g e o d e t i c s c a l e f a c t o r Si t e P o s i t i o n : Fr o m : Si t e La t i t u d e : Lo n g i t u d e : Po s i t i o n U n c e r t a i n t y : No r t h i n g : Ea s t i n g : Gr i d C o n v e r g e n c e : ND B us f t Ma p us f t us f t ° -0 . 5 9 Sl o t R a d i u s : " 20 5, 9 7 2 , 9 0 9 . 7 0 42 3 , 3 8 3 . 5 6 0. 9 70 ° 2 0 ' 1 0 . 1 3 8 N 15 0 ° 3 7 ' 1 7 . 7 9 6 W We l l We l l P o s i t i o n Lo n g i t u d e : La t i t u d e : Ea s t i n g : No r t h i n g : us f t +E / - W +N / - S Po s i t i o n U n c e r t a i n t y us f t us f t us f t Gr o u n d L e v e l : ND B - 0 5 1 us f t us f t 0. 0 0. 0 5, 9 7 2 , 6 5 2 . 8 7 42 1 , 7 4 8 . 1 1 22 . 8 We l l h e a d E l e v a t i o n : us f t 0. 5 70 ° 2 0 ' 7 . 4 4 6 N 15 0 ° 3 8 ' 5 . 4 8 2 W We l l b o r e De c l i n a t i o n (° ) Fi e l d S t r e n g t h (n T ) Sa m p l e D a t e D i p A n g l e (° ) ND B - 0 5 1 Mo d e l N a m e Ma g n e t i c s IG R F 2 0 0 0 3 1 / 1 2 / 2 0 0 4 2 4 . 7 2 8 0 . 6 1 5 7 , 2 8 2 . 1 6 7 0 0 9 8 7 Ph a s e : Ve r s i o n : Au d i t N o t e s : De s i g n ND B - 0 5 1 1. 0 A C T U A L Ve r t i c a l S e c t i o n : D e p t h F r o m ( T V D ) (u s f t ) +N / - S (u s f t ) Di r e c t i o n (° ) +E / - W (u s f t ) Ti e O n D e p t h : 46 . 5 28 9 . 8 8 0. 0 0. 0 46 . 5 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 2 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e Fr o m (u s f t ) Su r v e y P r o g r a m De s c r i p t i o n To o l N a m e Su r v e y ( W e l l b o r e ) To (u s f t ) Da t e 14 / 0 6 / 2 0 2 4 SD I _ U R S A 1 _ I 4 S D I U R S A - 1 g y r o M W D ( I S C W S A R e v 4 ) 12 4 . 6 4 6 7 . 8 01 S D I U R S A G y r o M W D 1 6 i n H o l e < 4 6 - 46 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 49 5 . 9 3 , 1 5 7 . 1 02 B H O n t r a k 1 6 i n H o l e < 4 9 5 - 3 1 5 7 > ( N D B 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 3, 2 5 1 . 6 4 , 9 3 7 . 0 03 B H O n t r a k 1 2 . 2 5 i n H o l e < 3 2 5 1 - 4 9 3 6 > ( 3_ M W D + I F R 2 + S a g A 0 1 2 M b : I I F R d e c c o r r e c t i o n + s a g 5, 0 0 1 . 3 5 , 0 6 5 . 0 04 B H O n t r a K 1 2 . 2 5 H o l e < 5 0 0 1 - 5 0 6 4 > ( N 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 5, 1 2 7 . 4 5 , 1 2 7 . 4 05 B H O n t r a K 1 2 . 2 5 H o l e < 5 1 2 7 - 5 1 2 7 > ( N 3_ M W D + I F R 2 + S a g A 0 1 2 M b : I I F R d e c c o r r e c t i o n + s a g 5, 2 2 1 . 1 5 , 3 1 6 . 2 06 B H O n t r a k 1 2 . 2 5 i n H o l e < 5 2 2 1 - 5 3 1 6 > ( 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 5, 4 1 1 . 3 1 1 , 5 2 8 . 6 07 B H O n t r a K 1 2 . 2 5 i n H o l e < 5 4 1 1 - 1 1 5 2 8 > 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 11 , 5 9 0 . 2 1 7 , 4 7 8 . 0 08 B H O n t r a K 8 . 5 i n H o l e < 1 1 5 9 0 - 1 7 4 5 0 > ( MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 46 . 5 0 . 0 0 0 . 0 0 4 6 . 5 - 2 2 . 8 0 . 0 0 . 0 5 , 9 7 2 , 6 5 2 . 8 7 4 2 1 , 7 4 8 . 1 1 0 . 0 0 0 . 0 12 4 . 6 0 . 4 4 3 4 8 . 7 5 1 2 4 . 6 5 5 . 3 0 . 3 - 0 . 1 5 , 9 7 2 , 6 5 3 . 1 6 4 2 1 , 7 4 8 . 0 5 0 . 5 6 0 . 2 12 8 . 0 0 . 4 3 3 5 0 . 3 6 1 2 8 . 0 5 8 . 7 0 . 3 - 0 . 1 5 , 9 7 2 , 6 5 3 . 1 9 4 2 1 , 7 4 8 . 0 5 0 . 4 5 0 . 2 20 " C o n d u c t o r C a s i n g 18 7 . 1 0 . 3 5 2 8 . 4 8 1 8 7 . 1 1 1 7 . 8 0 . 7 0 . 0 5 , 9 7 2 , 6 5 3 . 5 7 4 2 1 , 7 4 8 . 1 0 0 . 4 5 0 . 3 28 4 . 3 0 . 9 7 2 8 5 . 4 7 2 8 4 . 3 2 1 5 . 0 1 . 2 - 0 . 7 5 , 9 7 2 , 6 5 4 . 0 5 4 2 1 , 7 4 7 . 4 6 1 . 1 3 1 . 0 37 3 . 7 2 . 8 5 2 7 6 . 3 3 3 7 3 . 7 3 0 4 . 4 1 . 6 - 3 . 6 5 , 9 7 2 , 6 5 4 . 5 3 4 2 1 , 7 4 4 . 5 2 2 . 1 2 3 . 9 46 7 . 8 5 . 3 3 2 6 4 . 3 8 4 6 7 . 5 3 9 8 . 2 1 . 5 - 1 0 . 3 5 , 9 7 2 , 6 5 4 . 4 3 4 2 1 , 7 3 7 . 8 4 2 . 7 7 1 0 . 2 49 5 . 9 5 . 6 8 2 6 2 . 8 1 4 9 5 . 4 4 2 6 . 1 1 . 2 - 1 3 . 0 5 , 9 7 2 , 6 5 4 . 1 6 4 2 1 , 7 3 5 . 1 7 1 . 3 6 1 2 . 6 59 0 . 5 8 . 4 2 2 5 7 . 2 3 5 8 9 . 3 5 2 0 . 0 - 1 . 0 - 2 4 . 4 5 , 9 7 2 , 6 5 2 . 1 6 4 2 1 , 7 2 3 . 7 5 2 . 9 8 2 2 . 6 68 5 . 0 1 1 . 3 5 2 5 5 . 1 0 6 8 2 . 4 6 1 3 . 1 - 4 . 9 - 4 0 . 1 5 , 9 7 2 , 6 4 8 . 4 0 4 2 1 , 7 0 7 . 9 7 3 . 1 2 3 6 . 0 77 9 . 5 1 3 . 3 3 2 5 5 . 7 9 7 7 4 . 7 7 0 5 . 4 - 1 0 . 0 - 5 9 . 6 5 , 9 7 2 , 6 4 3 . 5 4 4 2 1 , 6 8 8 . 3 7 2 . 1 0 5 2 . 7 87 4 . 4 1 5 . 1 2 2 5 6 . 5 1 8 6 6 . 8 7 9 7 . 5 - 1 5 . 5 - 8 2 . 3 5 , 9 7 2 , 6 3 8 . 2 0 4 2 1 , 6 6 5 . 6 6 1 . 8 9 7 2 . 1 96 8 . 2 1 8 . 1 6 2 5 5 . 6 9 9 5 6 . 6 8 8 7 . 3 - 2 2 . 0 - 1 0 8 . 3 5 , 9 7 2 , 6 3 2 . 0 1 4 2 1 , 6 3 9 . 5 5 3 . 2 5 9 4 . 4 1, 0 5 5 . 0 1 7 . 0 1 2 5 4 . 6 0 1 , 0 3 9 . 3 9 7 0 . 0 - 2 8 . 7 - 1 3 3 . 7 5 , 9 7 2 , 6 2 5 . 5 6 4 2 1 , 6 1 4 . 1 3 1 . 3 8 1 1 6 . 0 Up p e r S c h r a d e r B l u f f 1, 0 6 3 . 4 1 6 . 9 0 2 5 4 . 4 9 1 , 0 4 7 . 4 9 7 8 . 1 - 2 9 . 4 - 1 3 6 . 1 5 , 9 7 2 , 6 2 4 . 9 3 4 2 1 , 6 1 1 . 7 5 1 . 3 8 1 1 8 . 0 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 3 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 1, 1 5 7 . 4 1 5 . 9 1 2 5 5 . 2 4 1 , 1 3 7 . 5 1 , 0 6 8 . 2 - 3 6 . 3 - 1 6 1 . 7 5 , 9 7 2 , 6 1 8 . 2 7 4 2 1 , 5 8 6 . 0 6 1 . 0 8 1 3 9 . 7 1, 1 5 8 . 0 1 5 . 9 3 2 5 5 . 2 4 1 , 1 3 8 . 1 1 , 0 6 8 . 8 - 3 6 . 3 - 1 6 1 . 8 5 , 9 7 2 , 6 1 8 . 2 2 4 2 1 , 5 8 5 . 9 1 2 . 6 5 1 3 9 . 8 Ba s e I c e B e a r i n g P e r m a f r o s t 1, 2 5 1 . 8 1 8 . 4 1 2 5 5 . 5 4 1 , 2 2 7 . 7 1 , 1 5 8 . 4 - 4 3 . 3 - 1 8 8 . 6 5 , 9 7 2 , 6 1 1 . 5 3 4 2 1 , 5 5 9 . 0 5 2 . 6 5 1 6 2 . 7 1, 3 4 9 . 1 2 1 . 3 1 2 5 6 . 1 0 1 , 3 1 9 . 3 1 , 2 5 0 . 0 - 5 1 . 4 - 2 2 0 . 7 5 , 9 7 2 , 6 0 3 . 7 7 4 2 1 , 5 2 6 . 9 1 2 . 9 9 1 9 0 . 1 1, 3 8 0 . 7 2 2 . 9 3 2 5 6 . 0 8 1 , 3 4 8 . 6 1 , 2 7 9 . 3 - 5 4 . 3 - 2 3 2 . 3 5 , 9 7 2 , 6 0 1 . 0 3 4 2 1 , 5 1 5 . 3 2 5 . 1 3 2 0 0 . 0 1, 4 0 9 . 0 2 4 . 4 5 2 5 6 . 7 8 1 , 3 7 4 . 4 1 , 3 0 5 . 1 - 5 6 . 9 - 2 4 3 . 3 5 , 9 7 2 , 5 9 8 . 4 9 4 2 1 , 5 0 4 . 2 6 5 . 4 8 2 0 9 . 4 Ba s e P e r m a f r o s t T r a n s i t i o n 1, 4 1 3 . 6 2 4 . 7 0 2 5 6 . 8 9 1 , 3 7 8 . 6 1 , 3 0 9 . 3 - 5 7 . 4 - 2 4 5 . 2 5 , 9 7 2 , 5 9 8 . 0 7 4 2 1 , 5 0 2 . 3 9 5 . 4 8 2 1 1 . 0 1, 4 4 3 . 1 2 6 . 2 4 2 5 7 . 2 9 1 , 4 0 5 . 2 1 , 3 3 5 . 9 - 6 0 . 2 - 2 5 7 . 5 5 , 9 7 2 , 5 9 5 . 3 7 4 2 1 , 4 9 0 . 0 1 5 . 2 6 2 2 1 . 7 1, 4 7 6 . 4 2 8 . 2 9 2 5 8 . 5 1 1 , 4 3 4 . 8 1 , 3 6 5 . 5 - 6 3 . 4 - 2 7 2 . 4 5 , 9 7 2 , 5 9 2 . 3 3 4 2 1 , 4 7 5 . 0 6 6 . 3 8 2 3 4 . 6 1, 5 0 8 . 1 2 9 . 1 3 2 5 8 . 6 8 1 , 4 6 2 . 7 1 , 3 9 3 . 4 - 6 6 . 4 - 2 8 7 . 4 5 , 9 7 2 , 5 8 9 . 4 8 4 2 1 , 4 6 0 . 0 9 2 . 6 6 2 4 7 . 7 1, 5 3 7 . 3 2 9 . 8 7 2 5 7 . 3 7 1 , 4 8 8 . 1 1 , 4 1 8 . 8 - 6 9 . 4 - 3 0 1 . 4 5 , 9 7 2 , 5 8 6 . 6 4 4 2 1 , 4 4 6 . 0 1 3 . 3 6 2 5 9 . 9 1, 6 2 5 . 8 3 3 . 7 0 2 5 6 . 3 1 1 , 5 6 3 . 2 1 , 4 9 3 . 9 - 8 0 . 0 - 3 4 6 . 8 5 , 9 7 2 , 5 7 6 . 4 8 4 2 1 , 4 0 0 . 5 4 4 . 3 7 2 9 8 . 9 1, 7 2 4 . 8 3 6 . 6 5 2 5 5 . 5 6 1 , 6 4 4 . 2 1 , 5 7 4 . 9 - 9 3 . 9 - 4 0 2 . 1 5 , 9 7 2 , 5 6 3 . 1 8 4 2 1 , 3 4 5 . 0 5 3 . 0 1 3 4 6 . 2 1, 8 2 1 . 8 3 9 . 7 8 2 5 6 . 3 3 1 , 7 2 0 . 4 1 , 6 5 1 . 1 - 1 0 8 . 5 - 4 6 0 . 3 5 , 9 7 2 , 5 4 9 . 2 4 4 2 1 , 2 8 6 . 7 1 3 . 2 6 3 9 6 . 0 1, 8 3 5 . 0 4 0 . 2 0 2 5 6 . 2 4 1 , 7 3 0 . 5 1 , 6 6 1 . 2 - 1 1 0 . 5 - 4 6 8 . 6 5 , 9 7 2 , 5 4 7 . 3 2 4 2 1 , 2 7 8 . 4 7 3 . 2 2 4 0 3 . 1 Mi d d l e S c h r a d e r B l u f f 1, 9 2 1 . 1 4 2 . 9 5 2 5 5 . 7 1 1 , 7 9 4 . 9 1 , 7 2 5 . 6 - 1 2 4 . 3 - 5 2 4 . 0 5 , 9 7 2 , 5 3 4 . 0 5 4 2 1 , 2 2 2 . 9 1 3 . 2 2 4 5 0 . 5 2, 0 1 7 . 7 4 6 . 9 3 2 5 6 . 1 1 1 , 8 6 3 . 2 1 , 7 9 3 . 9 - 1 4 0 . 9 - 5 9 0 . 1 5 , 9 7 2 , 5 1 8 . 1 5 4 2 1 , 1 5 6 . 6 0 4 . 1 3 5 0 7 . 0 2, 1 1 4 . 5 5 1 . 1 7 2 5 6 . 4 6 1 , 9 2 6 . 7 1 , 8 5 7 . 4 - 1 5 8 . 2 - 6 6 1 . 2 5 , 9 7 2 , 5 0 1 . 5 6 4 2 1 , 0 8 5 . 3 9 4 . 3 9 5 6 7 . 9 2, 2 0 9 . 5 5 5 . 4 0 2 5 7 . 3 1 1 , 9 8 3 . 5 1 , 9 1 4 . 2 - 1 7 5 . 5 - 7 3 5 . 3 5 , 9 7 2 , 4 8 5 . 0 7 4 2 1 , 0 1 1 . 0 5 4 . 5 1 6 3 1 . 8 2, 3 0 5 . 1 5 9 . 4 3 2 5 7 . 1 9 2 , 0 3 5 . 0 1 , 9 6 5 . 7 - 1 9 3 . 3 - 8 1 3 . 9 5 , 9 7 2 , 4 6 8 . 1 2 4 2 0 , 9 3 2 . 3 4 4 . 2 2 6 9 9 . 6 2, 3 9 9 . 9 6 3 . 5 1 2 5 7 . 2 6 2 , 0 8 0 . 2 2 , 0 1 0 . 9 - 2 1 1 . 7 - 8 9 5 . 1 5 , 9 7 2 , 4 5 0 . 5 6 4 2 0 , 8 5 0 . 9 3 4 . 3 0 7 6 9 . 8 2, 4 9 5 . 0 6 7 . 9 0 2 5 7 . 5 3 2 , 1 1 9 . 3 2 , 0 5 0 . 0 - 2 3 0 . 6 - 9 7 9 . 6 5 , 9 7 2 , 4 3 2 . 5 5 4 2 0 , 7 6 6 . 2 4 4 . 6 3 8 4 2 . 8 2, 5 8 2 . 0 6 9 . 4 5 2 5 7 . 2 2 2 , 1 5 1 . 0 2 , 0 8 1 . 7 - 2 4 8 . 3 - 1 , 0 5 8 . 7 5 , 9 7 2 , 4 1 5 . 6 5 4 2 0 , 6 8 6 . 9 5 1 . 8 1 9 1 1 . 2 MC U 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 4 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 2, 5 8 9 . 6 6 9 . 5 8 2 5 7 . 1 9 2 , 1 5 3 . 6 2 , 0 8 4 . 3 - 2 4 9 . 9 - 1 , 0 6 5 . 7 5 , 9 7 2 , 4 1 4 . 1 5 4 2 0 , 6 8 0 . 0 0 1 . 8 1 9 1 7 . 2 2, 6 8 4 . 0 7 2 . 5 4 2 5 6 . 2 6 2 , 1 8 4 . 3 2 , 1 1 5 . 0 - 2 7 0 . 4 - 1 , 1 5 2 . 6 5 , 9 7 2 , 3 9 4 . 5 5 4 2 0 , 5 9 2 . 8 9 3 . 2 7 9 9 1 . 9 2, 7 7 9 . 4 7 6 . 0 7 2 5 5 . 8 3 2 , 2 1 0 . 1 2 , 1 4 0 . 8 - 2 9 2 . 5 - 1 , 2 4 1 . 7 5 , 9 7 2 , 3 7 3 . 3 3 4 2 0 , 5 0 3 . 5 4 3 . 7 2 1 , 0 6 8 . 2 2, 8 7 3 . 8 7 8 . 0 5 2 5 5 . 0 6 2 , 2 3 1 . 2 2 , 1 6 1 . 9 - 3 1 5 . 7 - 1 , 3 3 0 . 7 5 , 9 7 2 , 3 5 1 . 1 5 4 2 0 , 4 1 4 . 3 1 2 . 2 4 1 , 1 4 4 . 1 2, 9 6 7 . 7 7 8 . 3 2 2 5 5 . 6 5 2 , 2 5 0 . 5 2 , 1 8 1 . 2 - 3 3 8 . 9 - 1 , 4 1 9 . 7 5 , 9 7 2 , 3 2 8 . 8 3 4 2 0 , 3 2 5 . 1 2 0 . 6 8 1 , 2 1 9 . 8 3, 0 6 3 . 2 7 8 . 1 6 2 5 7 . 0 9 2 , 2 6 9 . 9 2 , 2 0 0 . 6 - 3 6 0 . 9 - 1 , 5 1 0 . 5 5 , 9 7 2 , 3 0 7 . 7 6 4 2 0 , 2 3 4 . 0 7 1 . 4 9 1 , 2 9 7 . 7 3, 1 5 7 . 1 7 8 . 0 4 2 5 7 . 7 1 2 , 2 8 9 . 3 2 , 2 2 0 . 0 - 3 8 1 . 0 - 1 , 6 0 0 . 2 5 , 9 7 2 , 2 8 8 . 6 5 4 2 0 , 1 4 4 . 1 8 0 . 6 6 1 , 3 7 5 . 3 3, 2 1 8 . 0 7 7 . 9 2 2 5 8 . 9 7 2 , 3 0 2 . 0 2 , 2 3 2 . 7 - 3 9 3 . 0 - 1 , 6 5 8 . 5 5 , 9 7 2 , 2 7 7 . 2 2 4 2 0 , 0 8 5 . 7 5 2 . 0 3 1 , 4 2 6 . 0 13 - 3 / 8 " S u r f a c e C a s i n g 3, 2 5 1 . 6 7 7 . 8 5 2 5 9 . 6 6 2 , 3 0 9 . 0 2 , 2 3 9 . 7 - 3 9 9 . 1 - 1 , 6 9 0 . 8 5 , 9 7 2 , 2 7 1 . 4 6 4 2 0 , 0 5 3 . 3 7 2 . 0 3 1 , 4 5 4 . 3 3, 3 2 5 . 3 7 7 . 9 6 2 5 8 . 2 0 2 , 3 2 4 . 4 2 , 2 5 5 . 1 - 4 1 2 . 9 - 1 , 7 6 1 . 5 5 , 9 7 2 , 2 5 8 . 3 8 4 1 9 , 9 8 2 . 5 9 1 . 9 4 1 , 5 1 6 . 1 3, 4 2 0 . 0 7 7 . 9 1 2 5 7 . 5 8 2 , 3 4 4 . 3 2 , 2 7 5 . 0 - 4 3 2 . 4 - 1 , 8 5 2 . 1 5 , 9 7 2 , 2 3 9 . 8 9 4 1 9 , 8 9 1 . 8 0 0 . 6 4 1 , 5 9 4 . 6 3, 5 1 4 . 7 7 7 . 9 1 2 5 6 . 8 4 2 , 3 6 4 . 1 2 , 2 9 4 . 8 - 4 5 2 . 9 - 1 , 9 4 2 . 4 5 , 9 7 2 , 2 2 0 . 3 3 4 1 9 , 8 0 1 . 2 8 0 . 7 6 1 , 6 7 2 . 6 3, 6 0 9 . 7 7 7 . 9 4 2 5 7 . 0 1 2 , 3 8 4 . 0 2 , 3 1 4 . 7 - 4 7 3 . 9 - 2 , 0 3 2 . 9 5 , 9 7 2 , 2 0 0 . 2 6 4 1 9 , 7 1 0 . 5 7 0 . 1 8 1 , 7 5 0 . 6 3, 7 0 4 . 5 7 8 . 0 3 2 5 7 . 0 2 2 , 4 0 3 . 7 2 , 3 3 4 . 4 - 4 9 4 . 7 - 2 , 1 2 3 . 2 5 , 9 7 2 , 1 8 0 . 3 7 4 1 9 , 6 2 0 . 0 2 0 . 1 0 1 , 8 2 8 . 5 3, 7 9 9 . 5 7 7 . 9 0 2 5 6 . 5 2 2 , 4 2 3 . 5 2 , 3 5 4 . 2 - 5 1 6 . 0 - 2 , 2 1 3 . 6 5 , 9 7 2 , 1 6 0 . 0 6 4 1 9 , 5 2 9 . 4 1 0 . 5 3 1 , 9 0 6 . 2 3, 8 9 3 . 9 7 7 . 9 1 2 5 6 . 1 3 2 , 4 4 3 . 3 2 , 3 7 4 . 0 - 5 3 7 . 8 - 2 , 3 0 3 . 3 5 , 9 7 2 , 1 3 9 . 1 7 4 1 9 , 4 3 9 . 4 9 0 . 4 0 1 , 9 8 3 . 2 3, 9 3 9 . 0 7 7 . 9 2 2 5 6 . 1 2 2 , 4 5 2 . 7 2 , 3 8 3 . 4 - 5 4 8 . 4 - 2 , 3 4 6 . 1 5 , 9 7 2 , 1 2 9 . 0 5 4 1 9 , 3 9 6 . 5 9 0 . 0 3 2 , 0 1 9 . 8 Tu l u v a k S h a l e 3, 9 8 8 . 8 7 7 . 9 3 2 5 6 . 1 1 2 , 4 6 3 . 1 2 , 3 9 3 . 8 - 5 6 0 . 1 - 2 , 3 9 3 . 4 5 , 9 7 2 , 1 1 7 . 8 6 4 1 9 , 3 4 9 . 2 0 0 . 0 3 2 , 0 6 0 . 3 4, 0 8 3 . 2 7 7 . 9 7 2 5 6 . 0 3 2 , 4 8 2 . 9 2 , 4 1 3 . 6 - 5 8 2 . 3 - 2 , 4 8 3 . 1 5 , 9 7 2 , 0 9 6 . 5 6 4 1 9 , 2 5 9 . 3 3 0 . 0 9 2 , 1 3 7 . 1 4, 1 7 7 . 8 7 7 . 9 3 2 5 5 . 9 2 2 , 5 0 2 . 6 2 , 4 3 3 . 3 - 6 0 4 . 7 - 2 , 5 7 2 . 8 5 , 9 7 2 , 0 7 5 . 0 9 4 1 9 , 1 6 9 . 3 7 0 . 1 2 2 , 2 1 3 . 8 4, 2 1 8 . 0 7 7 . 9 3 2 5 5 . 9 5 2 , 5 1 1 . 0 2 , 4 4 1 . 7 - 6 1 4 . 3 - 2 , 6 1 0 . 9 5 , 9 7 2 , 0 6 5 . 9 4 4 1 9 , 1 3 1 . 1 7 0 . 0 7 2 , 2 4 6 . 4 Tu l u v a k S a n d 4, 2 7 3 . 3 7 7 . 9 4 2 5 5 . 9 9 2 , 5 2 2 . 6 2 , 4 5 3 . 3 - 6 2 7 . 4 - 2 , 6 6 3 . 4 5 , 9 7 2 , 0 5 3 . 3 7 4 1 9 , 0 7 8 . 5 6 0 . 0 7 2 , 2 9 1 . 3 4, 3 6 8 . 0 7 7 . 8 8 2 5 5 . 8 7 2 , 5 4 2 . 4 2 , 4 7 3 . 1 - 6 4 9 . 9 - 2 , 7 5 3 . 2 5 , 9 7 2 , 0 3 1 . 8 1 4 1 8 , 9 8 8 . 5 7 0 . 1 4 2 , 3 6 8 . 1 4, 4 6 3 . 0 7 7 . 9 4 2 5 5 . 8 3 2 , 5 6 2 . 3 2 , 4 9 3 . 0 - 6 7 2 . 6 - 2 , 8 4 3 . 3 5 , 9 7 2 , 0 1 0 . 0 4 4 1 8 , 8 9 8 . 2 5 0 . 0 8 2 , 4 4 5 . 1 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 5 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 4, 5 5 7 . 5 7 7 . 6 5 2 5 6 . 6 2 2 , 5 8 2 . 3 2 , 5 1 3 . 0 - 6 9 4 . 6 - 2 , 9 3 3 . 0 5 , 9 7 1 , 9 8 8 . 9 9 4 1 8 , 8 0 8 . 3 1 0 . 8 7 2 , 5 2 2 . 0 4, 6 5 2 . 2 7 7 . 7 2 2 5 7 . 0 1 2 , 6 0 2 . 5 2 , 5 3 3 . 2 - 7 1 5 . 7 - 3 , 0 2 3 . 1 5 , 9 7 1 , 9 6 8 . 8 2 4 1 8 , 7 1 7 . 9 8 0 . 4 1 2 , 5 9 9 . 5 4, 7 4 7 . 6 7 7 . 7 1 2 5 7 . 2 8 2 , 6 2 2 . 8 2 , 5 5 3 . 5 - 7 3 6 . 4 - 3 , 1 1 3 . 9 5 , 9 7 1 , 9 4 9 . 0 4 4 1 8 , 6 2 6 . 9 6 0 . 2 8 2 , 6 7 7 . 9 4, 8 4 1 . 8 7 7 . 6 2 2 5 7 . 1 0 2 , 6 4 2 . 9 2 , 5 7 3 . 6 - 7 5 6 . 8 - 3 , 2 0 3 . 7 5 , 9 7 1 , 9 2 9 . 5 7 4 1 8 , 5 3 7 . 0 1 0 . 2 1 2 , 7 5 5 . 4 4, 9 3 7 . 0 7 7 . 7 2 2 5 7 . 0 9 2 , 6 6 3 . 2 2 , 5 9 3 . 9 - 7 7 7 . 6 - 3 , 2 9 4 . 3 5 , 9 7 1 , 9 0 9 . 7 5 4 1 8 , 4 4 6 . 1 6 0 . 1 1 2 , 8 3 3 . 5 5, 0 0 1 . 3 7 7 . 6 9 2 5 6 . 7 7 2 , 6 7 6 . 9 2 , 6 0 7 . 6 - 7 9 1 . 8 - 3 , 3 5 5 . 5 5 , 9 7 1 , 8 9 6 . 1 8 4 1 8 , 3 8 4 . 8 1 0 . 4 9 2 , 8 8 6 . 3 5, 0 6 5 . 0 7 7 . 6 9 2 5 5 . 9 4 2 , 6 9 0 . 5 2 , 6 2 1 . 2 - 8 0 6 . 5 - 3 , 4 1 6 . 0 5 , 9 7 1 , 8 8 2 . 1 4 4 1 8 , 3 2 4 . 2 3 1 . 2 7 2 , 9 3 8 . 1 5, 1 2 7 . 4 7 7 . 7 2 2 5 6 . 6 6 2 , 7 0 3 . 8 2 , 6 3 4 . 5 - 8 2 0 . 9 - 3 , 4 7 5 . 2 5 , 9 7 1 , 8 6 8 . 3 2 4 1 8 , 2 6 4 . 8 3 1 . 1 3 2 , 9 8 8 . 9 5, 2 2 1 . 1 7 7 . 6 8 2 5 6 . 8 1 2 , 7 2 3 . 7 2 , 6 5 4 . 4 - 8 4 1 . 9 - 3 , 5 6 4 . 3 5 , 9 7 1 , 8 4 8 . 2 5 4 1 8 , 1 7 5 . 5 4 0 . 1 6 3 , 0 6 5 . 6 5, 3 1 6 . 2 7 7 . 6 6 2 5 5 . 8 8 2 , 7 4 4 . 0 2 , 6 7 4 . 7 - 8 6 3 . 9 - 3 , 6 5 4 . 6 5 , 9 7 1 , 8 2 7 . 2 6 4 1 8 , 0 8 5 . 0 5 0 . 9 6 3 , 1 4 3 . 0 5, 4 1 1 . 3 7 7 . 6 8 2 5 6 . 1 9 2 , 7 6 4 . 4 2 , 6 9 5 . 1 - 8 8 6 . 3 - 3 , 7 4 4 . 8 5 , 9 7 1 , 8 0 5 . 7 8 4 1 7 , 9 9 4 . 6 3 0 . 3 2 3 , 2 2 0 . 2 5, 5 0 6 . 3 7 7 . 7 4 2 5 6 . 4 8 2 , 7 8 4 . 6 2 , 7 1 5 . 3 - 9 0 8 . 2 - 3 , 8 3 5 . 0 5 , 9 7 1 , 7 8 4 . 7 8 4 1 7 , 9 0 4 . 1 8 0 . 3 0 3 , 2 9 7 . 6 5, 5 9 3 . 0 7 7 . 6 9 2 5 6 . 5 3 2 , 8 0 3 . 0 2 , 7 3 3 . 7 - 9 2 8 . 0 - 3 , 9 1 7 . 4 5 , 9 7 1 , 7 6 5 . 8 8 4 1 7 , 8 2 1 . 6 5 0 . 0 7 3 , 3 6 8 . 3 TS _ 7 9 0 5, 6 0 0 . 3 7 7 . 6 9 2 5 6 . 5 3 2 , 8 0 4 . 6 2 , 7 3 5 . 3 - 9 2 9 . 6 - 3 , 9 2 4 . 3 5 , 9 7 1 , 7 6 4 . 3 0 4 1 7 , 8 1 4 . 7 3 0 . 0 7 3 , 3 7 4 . 2 5, 6 9 5 . 7 7 7 . 8 4 2 5 6 . 8 6 2 , 8 2 4 . 8 2 , 7 5 5 . 5 - 9 5 1 . 1 - 4 , 0 1 5 . 0 5 , 9 7 1 , 7 4 3 . 7 9 4 1 7 , 7 2 3 . 7 5 0 . 3 7 3 , 4 5 2 . 3 5, 7 9 0 . 4 7 7 . 9 1 2 5 7 . 2 0 2 , 8 4 4 . 7 2 , 7 7 5 . 4 - 9 7 1 . 9 - 4 , 1 0 5 . 3 5 , 9 7 1 , 7 2 3 . 9 5 4 1 7 , 6 3 3 . 3 0 0 . 3 6 3 , 5 3 0 . 1 5, 8 8 5 . 1 7 7 . 9 3 2 5 7 . 5 0 2 , 8 6 4 . 5 2 , 7 9 5 . 2 - 9 9 2 . 2 - 4 , 1 9 5 . 6 5 , 9 7 1 , 7 0 4 . 6 2 4 1 7 , 5 4 2 . 7 6 0 . 3 1 3 , 6 0 8 . 1 5, 9 7 9 . 9 7 7 . 9 0 2 5 7 . 3 0 2 , 8 8 4 . 4 2 , 8 1 5 . 1 - 1 , 0 1 2 . 4 - 4 , 2 8 6 . 0 5 , 9 7 1 , 6 8 5 . 3 5 4 1 7 , 4 5 2 . 1 4 0 . 2 1 3 , 6 8 6 . 3 6, 0 7 4 . 5 7 7 . 9 1 2 5 7 . 3 5 2 , 9 0 4 . 2 2 , 8 3 4 . 9 - 1 , 0 3 2 . 7 - 4 , 3 7 6 . 4 5 , 9 7 1 , 6 6 5 . 9 8 4 1 7 , 3 6 1 . 6 2 0 . 0 5 3 , 7 6 4 . 3 6, 1 6 9 . 2 7 7 . 8 4 2 5 6 . 8 5 2 , 9 2 4 . 1 2 , 8 5 4 . 8 - 1 , 0 5 3 . 4 - 4 , 4 6 6 . 5 5 , 9 7 1 , 6 4 6 . 2 7 4 1 7 , 2 7 1 . 2 5 0 . 5 2 3 , 8 4 2 . 1 6, 2 6 3 . 9 7 7 . 8 8 2 5 6 . 7 6 2 , 9 4 4 . 0 2 , 8 7 4 . 7 - 1 , 0 7 4 . 5 - 4 , 5 5 6 . 7 5 , 9 7 1 , 6 2 6 . 0 8 4 1 7 , 1 8 0 . 8 9 0 . 1 0 3 , 9 1 9 . 7 6, 3 5 8 . 5 7 7 . 9 3 2 5 6 . 8 9 2 , 9 6 3 . 8 2 , 8 9 4 . 5 - 1 , 0 9 5 . 6 - 4 , 6 4 6 . 8 5 , 9 7 1 , 6 0 5 . 9 3 4 1 7 , 0 9 0 . 5 8 0 . 1 4 3 , 9 9 7 . 2 6, 4 5 2 . 7 7 7 . 8 8 2 5 6 . 3 1 2 , 9 8 3 . 5 2 , 9 1 4 . 2 - 1 , 1 1 6 . 9 - 4 , 7 3 6 . 4 5 , 9 7 1 , 5 8 5 . 5 3 4 1 7 , 0 0 0 . 8 0 0 . 6 0 4 , 0 7 4 . 2 6, 5 4 7 . 8 7 7 . 8 4 2 5 6 . 3 1 3 , 0 0 3 . 6 2 , 9 3 4 . 3 - 1 , 1 3 8 . 9 - 4 , 8 2 6 . 7 5 , 9 7 1 , 5 6 4 . 4 6 4 1 6 , 9 1 0 . 2 0 0 . 0 4 4 , 1 5 1 . 7 6, 6 4 2 . 7 7 7 . 8 4 2 5 5 . 7 6 3 , 0 2 3 . 5 2 , 9 5 4 . 2 - 1 , 1 6 1 . 3 - 4 , 9 1 6 . 7 5 , 9 7 1 , 5 4 3 . 0 3 4 1 6 , 8 2 0 . 0 1 0 . 5 7 4 , 2 2 8 . 7 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 6 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 6, 6 7 0 . 0 7 7 . 8 5 2 5 5 . 8 4 3 , 0 2 9 . 3 2 , 9 6 0 . 0 - 1 , 1 6 7 . 9 - 4 , 9 4 2 . 6 5 , 9 7 1 , 5 3 6 . 7 5 4 1 6 , 7 9 4 . 0 5 0 . 2 9 4 , 2 5 0 . 9 Se a b e e 6, 7 3 6 . 8 7 7 . 8 7 2 5 6 . 0 4 3 , 0 4 3 . 3 2 , 9 7 4 . 0 - 1 , 1 8 3 . 7 - 5 , 0 0 6 . 0 5 , 9 7 1 , 5 2 1 . 5 4 4 1 6 , 7 3 0 . 5 0 0 . 2 9 4 , 3 0 5 . 1 6, 8 3 1 . 1 7 7 . 8 7 2 5 6 . 0 9 3 , 0 6 3 . 1 2 , 9 9 3 . 8 - 1 , 2 0 5 . 9 - 5 , 0 9 5 . 4 5 , 9 7 1 , 5 0 0 . 2 9 4 1 6 , 6 4 0 . 8 8 0 . 0 5 4 , 3 8 1 . 6 6, 9 2 7 . 1 7 7 . 6 8 2 5 6 . 0 2 3 , 0 8 3 . 5 3 , 0 1 4 . 2 - 1 , 2 2 8 . 5 - 5 , 1 8 6 . 5 5 , 9 7 1 , 4 7 8 . 6 2 4 1 6 , 5 4 9 . 5 4 0 . 2 1 4 , 4 5 9 . 6 7, 0 2 2 . 3 7 7 . 7 5 2 5 6 . 0 6 3 , 1 0 3 . 7 3 , 0 3 4 . 4 - 1 , 2 5 1 . 0 - 5 , 2 7 6 . 8 5 , 9 7 1 , 4 5 7 . 1 2 4 1 6 , 4 5 9 . 0 5 0 . 0 8 4 , 5 3 6 . 9 7, 1 1 6 . 9 7 7 . 7 8 2 5 6 . 4 2 3 , 1 2 3 . 8 3 , 0 5 4 . 5 - 1 , 2 7 3 . 0 - 5 , 3 6 6 . 6 5 , 9 7 1 , 4 3 6 . 0 8 4 1 6 , 3 6 9 . 0 6 0 . 3 7 4 , 6 1 3 . 8 7, 2 1 0 . 7 7 7 . 7 8 2 5 7 . 0 5 3 , 1 4 3 . 6 3 , 0 7 4 . 3 - 1 , 2 9 4 . 0 - 5 , 4 5 5 . 8 5 , 9 7 1 , 4 1 5 . 9 8 4 1 6 , 2 7 9 . 6 2 0 . 6 6 4 , 6 9 0 . 6 7, 3 0 5 . 9 7 7 . 6 9 2 5 6 . 9 7 3 , 1 6 3 . 9 3 , 0 9 4 . 6 - 1 , 3 1 4 . 9 - 5 , 5 4 6 . 4 5 , 9 7 1 , 3 9 6 . 0 2 4 1 6 , 1 8 8 . 8 1 0 . 1 3 4 , 7 6 8 . 7 7, 4 0 0 . 3 7 7 . 6 9 2 5 6 . 9 7 3 , 1 8 4 . 0 3 , 1 1 4 . 7 - 1 , 3 3 5 . 7 - 5 , 6 3 6 . 3 5 , 9 7 1 , 3 7 6 . 1 5 4 1 6 , 0 9 8 . 6 7 0 . 0 0 4 , 8 4 6 . 2 7, 4 9 5 . 8 7 7 . 6 8 2 5 7 . 7 4 3 , 2 0 4 . 4 3 , 1 3 5 . 1 - 1 , 3 5 6 . 1 - 5 , 7 2 7 . 3 5 , 9 7 1 , 3 5 6 . 6 9 4 1 6 , 0 0 7 . 4 8 0 . 7 9 4 , 9 2 4 . 8 7, 5 9 0 . 4 7 7 . 6 8 2 5 7 . 6 4 3 , 2 2 4 . 5 3 , 1 5 5 . 2 - 1 , 3 7 5 . 8 - 5 , 8 1 7 . 6 5 , 9 7 1 , 3 3 7 . 9 3 4 1 5 , 9 1 6 . 9 8 0 . 1 0 5 , 0 0 3 . 0 7, 6 8 5 . 7 7 7 . 7 1 2 5 6 . 7 2 3 , 2 4 4 . 8 3 , 1 7 5 . 5 - 1 , 3 9 6 . 5 - 5 , 9 0 8 . 4 5 , 9 7 1 , 3 1 8 . 2 2 4 1 5 , 8 2 6 . 0 0 0 . 9 4 5 , 0 8 1 . 3 7, 7 7 9 . 5 7 7 . 6 6 2 5 7 . 4 6 3 , 2 6 4 . 9 3 , 1 9 5 . 6 - 1 , 4 1 7 . 0 - 5 , 9 9 7 . 7 5 , 9 7 1 , 2 9 8 . 6 8 4 1 5 , 7 3 6 . 4 8 0 . 7 7 5 , 1 5 8 . 4 7, 8 7 3 . 8 7 7 . 6 9 2 5 7 . 3 4 3 , 2 8 5 . 0 3 , 2 1 5 . 7 - 1 , 4 3 7 . 1 - 6 , 0 8 7 . 7 5 , 9 7 1 , 2 7 9 . 5 2 4 1 5 , 6 4 6 . 3 2 0 . 1 3 5 , 2 3 6 . 1 7, 9 6 9 . 2 7 7 . 6 9 2 5 7 . 2 4 3 , 3 0 5 . 3 3 , 2 3 6 . 0 - 1 , 4 5 7 . 6 - 6 , 1 7 8 . 6 5 , 9 7 1 , 2 5 9 . 9 7 4 1 5 , 5 5 5 . 2 5 0 . 1 0 5 , 3 1 4 . 6 8, 0 6 3 . 4 7 7 . 8 7 2 5 7 . 3 0 3 , 3 2 5 . 3 3 , 2 5 6 . 0 - 1 , 4 7 7 . 9 - 6 , 2 6 8 . 4 5 , 9 7 1 , 2 4 0 . 6 2 4 1 5 , 4 6 5 . 2 4 0 . 2 0 5 , 3 9 2 . 2 8, 1 5 8 . 4 7 7 . 8 8 2 5 6 . 7 1 3 , 3 4 5 . 2 3 , 2 7 5 . 9 - 1 , 4 9 8 . 8 - 6 , 3 5 8 . 9 5 , 9 7 1 , 2 2 0 . 6 8 4 1 5 , 3 7 4 . 5 0 0 . 6 1 5 , 4 7 0 . 2 8, 2 5 2 . 7 7 7 . 8 5 2 5 6 . 4 1 3 , 3 6 5 . 0 3 , 2 9 5 . 7 - 1 , 5 2 0 . 2 - 6 , 4 4 8 . 5 5 , 9 7 1 , 2 0 0 . 2 0 4 1 5 , 2 8 4 . 6 8 0 . 3 1 5 , 5 4 7 . 2 8, 3 4 7 . 2 7 7 . 8 8 2 5 5 . 7 0 3 , 3 8 4 . 9 3 , 3 1 5 . 6 - 1 , 5 4 2 . 5 - 6 , 5 3 8 . 2 5 , 9 7 1 , 1 7 8 . 8 6 4 1 5 , 1 9 4 . 7 3 0 . 7 3 5 , 6 2 4 . 0 8, 4 4 1 . 7 7 7 . 8 5 2 5 5 . 7 5 3 , 4 0 4 . 8 3 , 3 3 5 . 5 - 1 , 5 6 5 . 2 - 6 , 6 2 7 . 8 5 , 9 7 1 , 1 5 7 . 0 2 4 1 5 , 1 0 4 . 9 8 0 . 0 6 5 , 7 0 0 . 5 8, 5 3 6 . 5 7 7 . 8 5 2 5 5 . 3 2 3 , 4 2 4 . 7 3 , 3 5 5 . 4 - 1 , 5 8 8 . 4 - 6 , 7 1 7 . 5 5 , 9 7 1 , 1 3 4 . 8 1 4 1 5 , 0 1 5 . 0 2 0 . 4 4 5 , 7 7 7 . 0 8, 6 3 1 . 6 7 7 . 8 8 2 5 5 . 8 2 3 , 4 4 4 . 7 3 , 3 7 5 . 4 - 1 , 6 1 1 . 6 - 6 , 8 0 7 . 6 5 , 9 7 1 , 1 1 2 . 5 8 4 1 4 , 9 2 4 . 7 3 0 . 5 1 5 , 8 5 3 . 8 8, 7 2 6 . 0 7 7 . 3 1 2 5 6 . 4 8 3 , 4 6 5 . 0 3 , 3 9 5 . 7 - 1 , 6 3 3 . 6 - 6 , 8 9 7 . 0 5 , 9 7 1 , 0 9 1 . 4 6 4 1 4 , 8 3 5 . 0 6 0 . 9 1 5 , 9 3 0 . 4 8, 8 2 1 . 6 7 7 . 3 1 2 5 9 . 0 0 3 , 4 8 6 . 0 3 , 4 1 6 . 7 - 1 , 6 5 3 . 4 - 6 , 9 8 8 . 2 5 , 9 7 1 , 0 7 2 . 6 1 4 1 4 , 7 4 3 . 7 3 2 . 5 7 6 , 0 0 9 . 4 8, 9 1 4 . 7 7 6 . 9 2 2 6 1 . 8 9 3 , 5 0 6 . 8 3 , 4 3 7 . 5 - 1 , 6 6 8 . 5 - 7 , 0 7 7 . 7 5 , 9 7 1 , 0 5 8 . 4 7 4 1 4 , 6 5 4 . 0 4 3 . 0 5 6 , 0 8 8 . 5 9, 0 1 1 . 5 7 7 . 0 0 2 6 3 . 9 4 3 , 5 2 8 . 6 3 , 4 5 9 . 3 - 1 , 6 8 0 . 1 - 7 , 1 7 1 . 2 5 , 9 7 1 , 0 4 7 . 8 2 4 1 4 , 5 6 0 . 4 0 2 . 0 7 6 , 1 7 2 . 5 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 7 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 9, 1 0 5 . 4 7 6 . 2 7 2 6 6 . 6 5 3 , 5 5 0 . 3 3 , 4 8 1 . 0 - 1 , 6 8 7 . 6 - 7 , 2 6 2 . 3 5 , 9 7 1 , 0 4 1 . 2 8 4 1 4 , 4 6 9 . 3 1 2 . 9 1 6 , 2 5 5 . 5 9, 2 0 0 . 4 7 6 . 2 7 2 6 8 . 8 5 3 , 5 7 2 . 9 3 , 5 0 3 . 6 - 1 , 6 9 1 . 2 - 7 , 3 5 4 . 5 5 , 9 7 1 , 0 3 8 . 6 2 4 1 4 , 3 7 7 . 0 9 2 . 2 5 6 , 3 4 1 . 0 9, 2 9 4 . 6 7 6 . 3 2 2 7 1 . 4 7 3 , 5 9 5 . 2 3 , 5 2 5 . 9 - 1 , 6 9 1 . 0 - 7 , 4 4 6 . 0 5 , 9 7 1 , 0 3 9 . 8 3 4 1 4 , 2 8 5 . 5 9 2 . 7 0 6 , 4 2 7 . 1 9, 3 8 9 . 8 7 6 . 3 4 2 7 4 . 0 2 3 , 6 1 7 . 7 3 , 5 4 8 . 4 - 1 , 6 8 6 . 5 - 7 , 5 3 8 . 4 5 , 9 7 1 , 0 4 5 . 2 3 4 1 4 , 1 9 3 . 2 1 2 . 6 0 6 , 5 1 5 . 6 9, 4 8 5 . 4 7 6 . 2 9 2 7 6 . 0 3 3 , 6 4 0 . 3 3 , 5 7 1 . 0 - 1 , 6 7 8 . 4 - 7 , 6 3 0 . 9 5 , 9 7 1 , 0 5 4 . 3 3 4 1 4 , 1 0 0 . 7 8 2 . 0 4 6 , 6 0 5 . 3 9, 5 7 9 . 6 7 6 . 2 7 2 7 7 . 9 7 3 , 6 6 2 . 7 3 , 5 9 3 . 4 - 1 , 6 6 7 . 3 - 7 , 7 2 1 . 7 5 , 9 7 1 , 0 6 6 . 4 2 4 1 4 , 0 1 0 . 1 3 2 . 0 0 6 , 6 9 4 . 5 9, 6 7 4 . 1 7 5 . 7 0 2 8 0 . 3 8 3 , 6 8 5 . 6 3 , 6 1 6 . 3 - 1 , 6 5 2 . 6 - 7 , 8 1 2 . 3 5 , 9 7 1 , 0 8 1 . 9 9 4 1 3 , 9 1 9 . 7 4 2 . 5 5 6 , 7 8 4 . 6 9, 7 6 9 . 5 7 5 . 7 5 2 8 2 . 2 6 3 , 7 0 9 . 1 3 , 6 3 9 . 8 - 1 , 6 3 4 . 5 - 7 , 9 0 2 . 9 5 , 9 7 1 , 1 0 1 . 0 7 4 1 3 , 8 2 9 . 3 1 1 . 9 1 6 , 8 7 6 . 0 9, 8 6 4 . 9 7 5 . 7 4 2 8 4 . 6 0 3 , 7 3 2 . 6 3 , 6 6 3 . 3 - 1 , 6 1 3 . 0 - 7 , 9 9 2 . 8 5 , 9 7 1 , 1 2 3 . 4 8 4 1 3 , 7 3 9 . 6 2 2 . 3 8 6 , 9 6 7 . 9 9, 9 5 9 . 2 7 5 . 6 7 2 8 7 . 5 3 3 , 7 5 5 . 9 3 , 6 8 6 . 6 - 1 , 5 8 7 . 7 - 8 , 0 8 0 . 6 5 , 9 7 1 , 1 4 9 . 6 7 4 1 3 , 6 5 2 . 1 2 3 . 0 1 7 , 0 5 9 . 0 10 , 0 5 3 . 5 7 5 . 7 2 2 9 0 . 6 2 3 , 7 7 9 . 2 3 , 7 0 9 . 9 - 1 , 5 5 7 . 9 - 8 , 1 6 7 . 0 5 , 9 7 1 , 1 8 0 . 4 4 4 1 3 , 5 6 6 . 0 6 3 . 1 7 7 , 1 5 0 . 4 10 , 1 4 8 . 3 7 5 . 7 8 2 9 3 . 1 5 3 , 8 0 2 . 5 3 , 7 3 3 . 2 - 1 , 5 2 3 . 6 - 8 , 2 5 2 . 3 5 , 9 7 1 , 2 1 5 . 5 7 4 1 3 , 4 8 1 . 1 7 2 . 5 9 7 , 2 4 2 . 3 10 , 1 7 8 . 0 7 5 . 7 5 2 9 3 . 8 6 3 , 8 0 9 . 8 3 , 7 4 0 . 5 - 1 , 5 1 2 . 2 - 8 , 2 7 8 . 6 5 , 9 7 1 , 2 2 7 . 3 1 4 1 3 , 4 5 4 . 9 4 2 . 3 3 7 , 2 7 1 . 0 Na n u s h u k 10 , 2 4 3 . 2 7 5 . 7 0 2 9 5 . 4 3 3 , 8 2 5 . 9 3 , 7 5 6 . 6 - 1 , 4 8 5 . 8 - 8 , 3 3 6 . 0 5 , 9 7 1 , 2 5 4 . 2 4 4 1 3 , 3 9 7 . 8 1 2 . 3 3 7 , 3 3 3 . 9 10 , 2 6 1 . 0 7 5 . 7 1 2 9 5 . 8 8 3 , 8 3 0 . 3 3 , 7 6 1 . 0 - 1 , 4 7 8 . 3 - 8 , 3 5 1 . 6 5 , 9 7 1 , 2 6 1 . 8 8 4 1 3 , 3 8 2 . 3 3 2 . 4 4 7 , 3 5 1 . 1 NT 8 M F S 10 , 3 3 8 . 1 7 5 . 7 6 2 9 7 . 8 2 3 , 8 4 9 . 3 3 , 7 8 0 . 0 - 1 , 4 4 4 . 6 - 8 , 4 1 8 . 2 5 , 9 7 1 , 2 9 6 . 3 1 4 1 3 , 3 1 6 . 0 3 2 . 4 4 7 , 4 2 5 . 2 10 , 3 6 4 . 0 7 5 . 8 6 2 9 8 . 4 0 3 , 8 5 5 . 6 3 , 7 8 6 . 3 - 1 , 4 3 2 . 8 - 8 , 4 4 0 . 4 5 , 9 7 1 , 3 0 8 . 3 8 4 1 3 , 2 9 4 . 0 0 2 . 1 9 7 , 4 5 0 . 1 NT 7 M F S 10 , 4 3 3 . 1 7 6 . 1 4 2 9 9 . 9 3 3 , 8 7 2 . 3 3 , 8 0 3 . 0 - 1 , 4 0 0 . 1 - 8 , 4 9 9 . 0 5 , 9 7 1 , 3 4 1 . 6 8 4 1 3 , 2 3 5 . 7 6 2 . 1 9 7 , 5 1 6 . 3 10 , 5 2 6 . 9 7 6 . 1 4 3 0 2 . 2 6 3 , 8 9 4 . 8 3 , 8 2 5 . 5 - 1 , 3 5 3 . 0 - 8 , 5 7 7 . 0 5 , 9 7 1 , 3 8 9 . 5 1 4 1 3 , 1 5 8 . 3 0 2 . 4 1 7 , 6 0 5 . 6 10 , 6 2 2 . 5 7 6 . 0 2 3 0 5 . 7 1 3 , 9 1 7 . 8 3 , 8 4 8 . 5 - 1 , 3 0 1 . 2 - 8 , 6 5 3 . 8 5 , 9 7 1 , 4 4 2 . 1 4 4 1 3 , 0 8 1 . 9 6 3 . 5 1 7 , 6 9 5 . 6 10 , 7 1 7 . 5 7 6 . 6 5 3 0 8 . 8 1 3 , 9 4 0 . 3 3 , 8 7 1 . 0 - 1 , 2 4 5 . 3 - 8 , 7 2 7 . 3 5 , 9 7 1 , 4 9 8 . 8 0 4 1 3 , 0 0 9 . 0 7 3 . 2 4 7 , 7 8 3 . 7 10 , 7 3 5 . 0 7 6 . 6 5 3 0 9 . 1 0 3 , 9 4 4 . 3 3 , 8 7 5 . 0 - 1 , 2 3 4 . 6 - 8 , 7 4 0 . 6 5 , 9 7 1 , 5 0 9 . 6 2 4 1 2 , 9 9 5 . 9 6 1 . 6 1 7 , 7 9 9 . 7 NT 6 M F S 10 , 8 1 2 . 0 7 6 . 6 5 3 1 0 . 3 7 3 , 9 6 2 . 1 3 , 8 9 2 . 8 - 1 , 1 8 6 . 7 - 8 , 7 9 8 . 1 5 , 9 7 1 , 5 5 8 . 0 9 4 1 2 , 9 3 8 . 8 8 1 . 6 1 7 , 8 7 0 . 2 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 8 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 10 , 9 0 6 . 0 7 6 . 6 4 3 1 1 . 4 6 3 , 9 8 3 . 8 3 , 9 1 4 . 5 - 1 , 1 2 6 . 8 - 8 , 8 6 7 . 3 5 , 9 7 1 , 6 1 8 . 7 2 4 1 2 , 8 7 0 . 3 8 1 . 1 3 7 , 9 5 5 . 6 10 , 9 4 0 . 0 7 6 . 6 7 3 1 2 . 2 3 3 , 9 9 1 . 6 3 , 9 2 2 . 3 - 1 , 1 0 4 . 8 - 8 , 8 9 1 . 9 5 , 9 7 1 , 6 4 1 . 0 4 4 1 2 , 8 4 5 . 9 7 2 . 2 2 7 , 9 8 6 . 3 NT 5 M F S 11 , 0 0 2 . 2 7 6 . 7 3 3 1 3 . 6 5 4 , 0 0 6 . 0 3 , 9 3 6 . 7 - 1 , 0 6 3 . 5 - 8 , 9 3 6 . 3 5 , 9 7 1 , 6 8 2 . 7 6 4 1 2 , 8 0 2 . 0 7 2 . 2 2 8 , 0 4 2 . 0 11 , 0 9 6 . 1 7 6 . 6 8 3 1 6 . 5 1 4 , 0 2 7 . 6 3 , 9 5 8 . 3 - 9 9 8 . 8 - 9 , 0 0 0 . 8 5 , 9 7 1 , 7 4 8 . 1 3 4 1 2 , 7 3 8 . 2 3 2 . 9 6 8 , 1 2 4 . 7 11 , 1 4 2 . 0 7 7 . 2 0 3 1 7 . 9 4 4 , 0 3 7 . 9 3 , 9 6 8 . 6 - 9 6 6 . 0 - 9 , 0 3 1 . 1 5 , 9 7 1 , 7 8 1 . 2 3 4 1 2 , 7 0 8 . 2 4 3 . 2 4 8 , 1 6 4 . 3 NT 4 M F S 11 , 1 9 1 . 0 7 7 . 7 6 3 1 9 . 4 6 4 , 0 4 8 . 5 3 , 9 7 9 . 2 - 9 3 0 . 1 - 9 , 0 6 2 . 7 5 , 9 7 1 , 8 1 7 . 4 7 4 1 2 , 6 7 7 . 0 7 3 . 2 4 8 , 2 0 6 . 2 11 , 2 8 5 . 7 7 7 . 7 2 3 2 1 . 1 2 4 , 0 6 8 . 7 3 , 9 9 9 . 4 - 8 5 8 . 9 - 9 , 1 2 1 . 8 5 , 9 7 1 , 8 8 9 . 2 6 4 1 2 , 6 1 8 . 7 0 1 . 7 1 8 , 2 8 6 . 0 11 , 3 8 0 . 5 7 8 . 6 7 3 2 3 . 3 2 4 , 0 8 8 . 1 4 , 0 1 8 . 8 - 7 8 5 . 6 - 9 , 1 7 8 . 6 5 , 9 7 1 , 9 6 3 . 1 9 4 1 2 , 5 6 2 . 6 3 2 . 4 8 8 , 3 6 4 . 4 11 , 4 7 4 . 8 7 8 . 6 2 3 2 6 . 4 8 4 , 1 0 6 . 6 4 , 0 3 7 . 3 - 7 0 9 . 9 - 9 , 2 3 1 . 8 5 , 9 7 2 , 0 3 9 . 4 0 4 1 2 , 5 1 0 . 2 4 3 . 2 8 8 , 4 4 0 . 2 11 , 5 0 6 . 0 7 8 . 5 9 3 2 7 . 3 8 4 , 1 1 2 . 8 4 , 0 4 3 . 5 - 6 8 4 . 3 - 9 , 2 4 8 . 5 5 , 9 7 2 , 0 6 5 . 1 8 4 1 2 , 4 9 3 . 8 4 2 . 8 5 8 , 4 6 4 . 6 NT 3 M F S 11 , 5 2 8 . 6 7 8 . 5 7 3 2 8 . 0 4 4 , 1 1 7 . 3 4 , 0 4 8 . 0 - 6 6 5 . 6 - 9 , 2 6 0 . 3 5 , 9 7 2 , 0 8 4 . 0 1 4 1 2 , 4 8 2 . 2 1 2 . 8 5 8 , 4 8 2 . 0 11 , 5 6 0 . 0 7 8 . 5 7 3 2 8 . 0 7 4 , 1 2 3 . 5 4 , 0 5 4 . 2 - 6 3 9 . 4 - 9 , 2 7 6 . 6 5 , 9 7 2 , 1 1 0 . 3 1 4 1 2 , 4 6 6 . 1 9 0 . 1 0 8 , 5 0 6 . 3 9- 5 / 8 " I n t e r m e d i a t e L i n e r 11 , 5 9 0 . 2 7 8 . 5 7 3 2 8 . 1 0 4 , 1 2 9 . 5 4 , 0 6 0 . 2 - 6 1 4 . 3 - 9 , 2 9 2 . 3 5 , 9 7 2 , 1 3 5 . 6 0 4 1 2 , 4 5 0 . 8 1 0 . 1 0 8 , 5 2 9 . 5 11 , 6 3 2 . 0 7 8 . 6 7 3 2 7 . 8 6 4 , 1 3 7 . 7 4 , 0 6 8 . 4 - 5 7 9 . 6 - 9 , 3 1 4 . 0 5 , 9 7 2 , 1 7 0 . 5 6 4 1 2 , 4 2 9 . 4 5 0 . 6 1 8 , 5 6 1 . 8 NT 3 . 2 T o p R e s e r v o i r 11 , 6 8 3 . 6 7 8 . 7 9 3 2 7 . 5 6 4 , 1 4 7 . 8 4 , 0 7 8 . 5 - 5 3 6 . 8 - 9 , 3 4 1 . 0 5 , 9 7 2 , 2 1 3 . 6 3 4 1 2 , 4 0 2 . 8 5 0 . 6 1 8 , 6 0 1 . 8 11 , 7 6 2 . 0 8 0 . 9 9 3 2 8 . 8 0 4 , 1 6 1 . 6 4 , 0 9 2 . 3 - 4 7 1 . 2 - 9 , 3 8 1 . 7 5 , 9 7 2 , 2 7 9 . 6 1 4 1 2 , 3 6 2 . 8 6 3 . 2 1 8 , 6 6 2 . 3 NT 3 . 2 4 11 , 7 8 0 . 6 8 1 . 5 1 3 2 9 . 0 9 4 , 1 6 4 . 4 4 , 0 9 5 . 1 - 4 5 5 . 4 - 9 , 3 9 1 . 2 5 , 9 7 2 , 2 9 5 . 4 9 4 1 2 , 3 5 3 . 5 3 3 . 2 1 8 , 6 7 6 . 6 11 , 8 7 5 . 3 8 4 . 9 9 3 3 0 . 4 7 4 , 1 7 5 . 5 4 , 1 0 6 . 2 - 3 7 4 . 2 - 9 , 4 3 8 . 5 5 , 9 7 2 , 3 7 7 . 1 8 4 1 2 , 3 0 7 . 0 8 3 . 9 5 8 , 7 4 8 . 7 11 , 9 6 9 . 2 8 7 . 2 6 3 3 0 . 5 4 4 , 1 8 1 . 9 4 , 1 1 2 . 6 - 2 9 2 . 7 - 9 , 4 8 4 . 6 5 , 9 7 2 , 4 5 9 . 1 8 4 1 2 , 2 6 1 . 8 2 2 . 4 2 8 , 8 1 9 . 8 12 , 0 6 5 . 3 9 0 . 3 1 3 3 0 . 6 1 4 , 1 8 3 . 9 4 , 1 1 4 . 6 - 2 0 9 . 0 - 9 , 5 3 1 . 8 5 , 9 7 2 , 5 4 3 . 3 5 4 1 2 , 2 1 5 . 4 9 3 . 1 7 8 , 8 9 2 . 7 12 , 1 6 0 . 1 9 0 . 5 3 3 2 9 . 9 9 4 , 1 8 3 . 2 4 , 1 1 3 . 9 - 1 2 6 . 7 - 9 , 5 7 8 . 8 5 , 9 7 2 , 6 2 6 . 1 4 4 1 2 , 1 6 9 . 4 1 0 . 6 9 8 , 9 6 4 . 8 12 , 2 5 5 . 2 9 0 . 4 1 3 2 9 . 7 1 4 , 1 8 2 . 4 4 , 1 1 3 . 1 - 4 4 . 4 - 9 , 6 2 6 . 6 5 , 9 7 2 , 7 0 8 . 9 0 4 1 2 , 1 2 2 . 4 9 0 . 3 2 9 , 0 3 7 . 7 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 9 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 12 , 3 4 9 . 8 9 0 . 3 5 3 2 8 . 9 7 4 , 1 8 1 . 8 4 , 1 1 2 . 5 3 7 . 0 - 9 , 6 7 4 . 8 5 , 9 7 2 , 7 9 0 . 7 9 4 1 2 , 0 7 5 . 0 9 0 . 7 8 9 , 1 1 0 . 8 12 , 4 4 4 . 8 9 0 . 4 4 3 2 8 . 1 1 4 , 1 8 1 . 2 4 , 1 1 1 . 9 1 1 8 . 0 - 9 , 7 2 4 . 4 5 , 9 7 2 , 8 7 2 . 2 8 4 1 2 , 0 2 6 . 3 9 0 . 9 1 9 , 1 8 4 . 9 12 , 5 3 9 . 7 9 0 . 3 8 3 2 8 . 9 5 4 , 1 8 0 . 5 4 , 1 1 1 . 2 1 9 8 . 9 - 9 , 7 7 3 . 9 5 , 9 7 2 , 9 5 3 . 7 4 4 1 1 , 9 7 7 . 6 9 0 . 8 9 9 , 2 5 9 . 0 12 , 6 3 5 . 2 9 0 . 4 7 3 2 8 . 0 6 4 , 1 7 9 . 8 4 , 1 1 0 . 5 2 8 0 . 4 - 9 , 8 2 3 . 8 5 , 9 7 3 , 0 3 5 . 6 9 4 1 1 , 9 2 8 . 6 5 0 . 9 4 9 , 3 3 3 . 7 12 , 7 3 0 . 4 9 0 . 3 8 3 2 8 . 2 5 4 , 1 7 9 . 1 4 , 1 0 9 . 8 3 6 1 . 2 - 9 , 8 7 4 . 0 5 , 9 7 3 , 1 1 7 . 0 3 4 1 1 , 8 7 9 . 3 0 0 . 2 2 9 , 4 0 8 . 4 12 , 8 2 5 . 7 9 0 . 5 0 3 2 9 . 1 0 4 , 1 7 8 . 3 4 , 1 0 9 . 0 4 4 2 . 6 - 9 , 9 2 3 . 6 5 , 9 7 3 , 1 9 8 . 9 5 4 1 1 , 8 3 0 . 6 1 0 . 9 0 9 , 4 8 2 . 6 12 , 9 2 0 . 6 9 0 . 4 7 3 2 9 . 0 5 4 , 1 7 7 . 5 4 , 1 0 8 . 2 5 2 4 . 1 - 9 , 9 7 2 . 4 5 , 9 7 3 , 2 8 0 . 9 1 4 1 1 , 7 8 2 . 6 6 0 . 0 6 9 , 5 5 6 . 2 13 , 0 1 5 . 5 9 0 . 5 3 3 2 9 . 3 6 4 , 1 7 6 . 7 4 , 1 0 7 . 4 6 0 5 . 5 - 1 0 , 0 2 0 . 9 5 , 9 7 3 , 3 6 2 . 8 5 4 1 1 , 7 3 4 . 9 8 0 . 3 3 9 , 6 2 9 . 6 13 , 1 1 0 . 6 9 0 . 5 6 3 2 9 . 0 9 4 , 1 7 5 . 8 4 , 1 0 6 . 5 6 8 7 . 3 - 1 0 , 0 6 9 . 6 5 , 9 7 3 , 4 4 5 . 0 9 4 1 1 , 6 8 7 . 1 5 0 . 2 9 9 , 7 0 3 . 2 13 , 2 0 5 . 5 9 0 . 5 3 3 2 8 . 6 4 4 , 1 7 4 . 9 4 , 1 0 5 . 6 7 6 8 . 4 - 1 0 , 1 1 8 . 7 5 , 9 7 3 , 5 2 6 . 7 7 4 1 1 , 6 3 8 . 9 7 0 . 4 8 9 , 7 7 6 . 9 13 , 3 0 0 . 1 9 0 . 5 6 3 2 9 . 0 5 4 , 1 7 4 . 0 4 , 1 0 4 . 7 8 4 9 . 4 - 1 0 , 1 6 7 . 6 5 , 9 7 3 , 6 0 8 . 2 7 4 1 1 , 5 9 0 . 8 5 0 . 4 3 9 , 8 5 0 . 5 13 , 3 9 5 . 4 9 0 . 5 3 3 2 9 . 4 0 4 , 1 7 3 . 1 4 , 1 0 3 . 8 9 3 1 . 3 - 1 0 , 2 1 6 . 4 5 , 9 7 3 , 6 9 0 . 6 2 4 1 1 , 5 4 2 . 9 7 0 . 3 7 9 , 9 2 4 . 2 13 , 4 9 0 . 0 9 0 . 5 3 3 3 0 . 0 9 4 , 1 7 2 . 2 4 , 1 0 2 . 9 1 , 0 1 3 . 0 - 1 0 , 2 6 4 . 0 5 , 9 7 3 , 7 7 2 . 8 5 4 1 1 , 4 9 6 . 1 4 0 . 7 3 9 , 9 9 6 . 8 13 , 5 8 5 . 3 9 0 . 5 3 3 3 0 . 4 3 4 , 1 7 1 . 3 4 , 1 0 2 . 0 1 , 0 9 5 . 7 - 1 0 , 3 1 1 . 3 5 , 9 7 3 , 8 5 6 . 0 1 4 1 1 , 4 4 9 . 7 8 0 . 3 6 1 0 , 0 6 9 . 3 13 , 6 8 1 . 0 9 0 . 5 3 3 3 0 . 2 2 4 , 1 7 0 . 4 4 , 1 0 1 . 1 1 , 1 7 8 . 9 - 1 0 , 3 5 8 . 7 5 , 9 7 3 , 9 3 9 . 6 6 4 1 1 , 4 0 3 . 2 6 0 . 2 2 1 0 , 1 4 2 . 2 13 , 7 7 5 . 6 9 0 . 5 6 3 3 0 . 0 5 4 , 1 6 9 . 5 4 , 1 0 0 . 2 1 , 2 6 1 . 0 - 1 0 , 4 0 5 . 8 5 , 9 7 4 , 0 2 2 . 2 3 4 1 1 , 3 5 6 . 9 9 0 . 1 8 1 0 , 2 1 4 . 4 13 , 8 7 1 . 1 9 0 . 5 3 3 3 0 . 2 7 4 , 1 6 8 . 6 4 , 0 9 9 . 3 1 , 3 4 3 . 8 - 1 0 , 4 5 3 . 3 5 , 9 7 4 , 1 0 5 . 5 4 4 1 1 , 3 1 0 . 3 5 0 . 2 3 1 0 , 2 8 7 . 3 13 , 9 6 5 . 9 9 0 . 5 6 3 2 9 . 5 2 4 , 1 6 7 . 7 4 , 0 9 8 . 4 1 , 4 2 5 . 8 - 1 0 , 5 0 0 . 8 5 , 9 7 4 , 1 8 7 . 9 9 4 1 1 , 2 6 3 . 6 9 0 . 7 9 1 0 , 3 5 9 . 8 14 , 0 6 0 . 5 9 0 . 5 0 3 2 9 . 5 9 4 , 1 6 6 . 9 4 , 0 9 7 . 6 1 , 5 0 7 . 3 - 1 0 , 5 4 8 . 8 5 , 9 7 4 , 2 7 0 . 0 3 4 1 1 , 2 1 6 . 6 1 0 . 1 0 1 0 , 4 3 2 . 7 14 , 1 5 6 . 1 9 0 . 5 9 3 2 8 . 5 9 4 , 1 6 6 . 0 4 , 0 9 6 . 7 1 , 5 8 9 . 3 - 1 0 , 5 9 7 . 9 5 , 9 7 4 , 3 5 2 . 5 4 4 1 1 , 1 6 8 . 3 8 1 . 0 5 1 0 , 5 0 6 . 7 14 , 2 5 0 . 8 9 0 . 5 3 3 2 9 . 0 1 4 , 1 6 5 . 0 4 , 0 9 5 . 7 1 , 6 7 0 . 4 - 1 0 , 6 4 7 . 0 5 , 9 7 4 , 4 3 4 . 0 9 4 1 1 , 1 2 0 . 1 4 0 . 4 5 1 0 , 5 8 0 . 5 14 , 3 4 5 . 9 9 0 . 5 6 3 2 8 . 7 7 4 , 1 6 4 . 1 4 , 0 9 4 . 8 1 , 7 5 1 . 8 - 1 0 , 6 9 6 . 1 5 , 9 7 4 , 5 1 6 . 0 0 4 1 1 , 0 7 1 . 8 7 0 . 2 5 1 0 , 6 5 4 . 3 14 , 4 4 0 . 6 9 0 . 5 0 3 2 8 . 5 6 4 , 1 6 3 . 2 4 , 0 9 3 . 9 1 , 8 3 2 . 6 - 1 0 , 7 4 5 . 3 5 , 9 7 4 , 5 9 7 . 3 3 4 1 1 , 0 2 3 . 5 1 0 . 2 3 1 0 , 7 2 8 . 1 14 , 5 3 5 . 5 9 0 . 5 3 3 2 8 . 3 3 4 , 1 6 2 . 4 4 , 0 9 3 . 1 1 , 9 1 3 . 5 - 1 0 , 7 9 5 . 0 5 , 9 7 4 , 6 7 8 . 7 5 4 1 0 , 9 7 4 . 6 7 0 . 2 4 1 0 , 8 0 2 . 3 14 , 6 3 0 . 7 9 0 . 5 6 3 2 9 . 0 4 4 , 1 6 1 . 5 4 , 0 9 2 . 2 1 , 9 9 4 . 8 - 1 0 , 8 4 4 . 5 5 , 9 7 4 , 7 6 0 . 5 5 4 1 0 , 9 2 6 . 0 7 0 . 7 5 1 0 , 8 7 6 . 5 14 , 7 2 6 . 2 9 0 . 5 0 3 2 9 . 4 7 4 , 1 6 0 . 6 4 , 0 9 1 . 3 2 , 0 7 7 . 0 - 1 0 , 8 9 3 . 3 5 , 9 7 4 , 8 4 3 . 1 7 4 1 0 , 8 7 8 . 0 8 0 . 4 5 1 0 , 9 5 0 . 4 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 1 0 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 14 , 8 2 0 . 9 9 0 . 3 5 3 2 9 . 6 3 4 , 1 5 9 . 9 4 , 0 9 0 . 6 2 , 1 5 8 . 5 - 1 0 , 9 4 1 . 3 5 , 9 7 4 , 9 2 5 . 2 4 4 1 0 , 8 3 0 . 9 8 0 . 2 3 1 1 , 0 2 3 . 2 14 , 9 1 5 . 8 9 0 . 4 4 3 2 9 . 1 5 4 , 1 5 9 . 2 4 , 0 8 9 . 9 2 , 2 4 0 . 3 - 1 0 , 9 8 9 . 6 5 , 9 7 5 , 0 0 7 . 4 6 4 1 0 , 7 8 3 . 4 9 0 . 5 1 1 1 , 0 9 6 . 5 15 , 0 1 1 . 2 9 0 . 4 1 3 2 9 . 9 3 4 , 1 5 8 . 5 4 , 0 8 9 . 2 2 , 3 2 2 . 5 - 1 1 , 0 3 8 . 0 5 , 9 7 5 , 0 9 0 . 1 8 4 1 0 , 7 3 6 . 0 0 0 . 8 2 1 1 , 1 6 9 . 9 15 , 1 0 6 . 2 9 0 . 4 1 3 2 9 . 5 4 4 , 1 5 7 . 9 4 , 0 8 8 . 6 2 , 4 0 4 . 5 - 1 1 , 0 8 5 . 8 5 , 9 7 5 , 1 7 2 . 6 8 4 1 0 , 6 8 9 . 0 0 0 . 4 1 1 1 , 2 4 2 . 8 15 , 2 0 1 . 2 9 0 . 4 1 3 2 9 . 4 5 4 , 1 5 7 . 2 4 , 0 8 7 . 9 2 , 4 8 6 . 4 - 1 1 , 1 3 4 . 1 5 , 9 7 5 , 2 5 5 . 0 6 4 1 0 , 6 4 1 . 6 2 0 . 0 9 1 1 , 3 1 6 . 0 15 , 2 9 6 . 3 9 0 . 4 1 3 2 9 . 5 1 4 , 1 5 6 . 5 4 , 0 8 7 . 2 2 , 5 6 8 . 3 - 1 1 , 1 8 2 . 4 5 , 9 7 5 , 3 3 7 . 4 8 4 1 0 , 5 9 4 . 1 8 0 . 0 6 1 1 , 3 8 9 . 3 15 , 3 9 1 . 0 9 0 . 4 4 3 2 9 . 3 0 4 , 1 5 5 . 8 4 , 0 8 6 . 5 2 , 6 4 9 . 8 - 1 1 , 2 3 0 . 6 5 , 9 7 5 , 4 1 9 . 4 8 4 1 0 , 5 4 6 . 8 4 0 . 2 2 1 1 , 4 6 2 . 4 15 , 4 8 6 . 6 9 0 . 4 4 3 2 9 . 3 6 4 , 1 5 5 . 1 4 , 0 8 5 . 8 2 , 7 3 2 . 0 - 1 1 , 2 7 9 . 3 5 , 9 7 5 , 5 0 2 . 1 3 4 1 0 , 4 9 8 . 9 8 0 . 0 6 1 1 , 5 3 6 . 1 15 , 5 8 1 . 2 9 0 . 5 9 3 2 9 . 2 5 4 , 1 5 4 . 2 4 , 0 8 4 . 9 2 , 8 1 3 . 4 - 1 1 , 3 2 7 . 6 5 , 9 7 5 , 5 8 4 . 0 2 4 1 0 , 4 5 1 . 5 2 0 . 2 0 1 1 , 6 0 9 . 2 15 , 6 7 6 . 0 9 0 . 5 0 3 2 9 . 4 4 4 , 1 5 3 . 3 4 , 0 8 4 . 0 2 , 8 9 4 . 9 - 1 1 , 3 7 5 . 9 5 , 9 7 5 , 6 6 6 . 0 7 4 1 0 , 4 0 4 . 0 4 0 . 2 2 1 1 , 6 8 2 . 4 15 , 7 7 0 . 7 9 0 . 5 3 3 2 9 . 3 9 4 , 1 5 2 . 5 4 , 0 8 3 . 2 2 , 9 7 6 . 5 - 1 1 , 4 2 4 . 1 5 , 9 7 5 , 7 4 8 . 0 8 4 1 0 , 3 5 6 . 7 2 0 . 0 6 1 1 , 7 5 5 . 5 15 , 8 6 6 . 5 9 0 . 5 6 3 2 9 . 4 8 4 , 1 5 1 . 5 4 , 0 8 2 . 2 3 , 0 5 8 . 9 - 1 1 , 4 7 2 . 8 5 , 9 7 5 , 8 3 1 . 0 0 4 1 0 , 3 0 8 . 9 1 0 . 1 0 1 1 , 8 2 9 . 3 15 , 9 6 1 . 6 9 0 . 5 3 3 2 9 . 5 7 4 , 1 5 0 . 6 4 , 0 8 1 . 3 3 , 1 4 0 . 8 - 1 1 , 5 2 1 . 0 5 , 9 7 5 , 9 1 3 . 4 4 4 1 0 , 2 6 1 . 5 4 0 . 1 0 1 1 , 9 0 2 . 5 16 , 0 5 6 . 9 9 0 . 5 9 3 3 0 . 0 2 4 , 1 4 9 . 7 4 , 0 8 0 . 4 3 , 2 2 3 . 2 - 1 1 , 5 6 9 . 0 5 , 9 7 5 , 9 9 6 . 3 1 4 1 0 , 2 1 4 . 4 5 0 . 4 8 1 1 , 9 7 5 . 6 16 , 1 5 0 . 6 9 0 . 5 6 3 2 9 . 8 5 4 , 1 4 8 . 8 4 , 0 7 9 . 5 3 , 3 0 4 . 3 - 1 1 , 6 1 5 . 9 5 , 9 7 6 , 0 7 7 . 9 1 4 1 0 , 1 6 8 . 3 5 0 . 1 8 1 2 , 0 4 7 . 3 16 , 2 4 7 . 1 9 0 . 5 3 3 2 9 . 8 2 4 , 1 4 7 . 9 4 , 0 7 8 . 6 3 , 3 8 7 . 7 - 1 1 , 6 6 4 . 4 5 , 9 7 6 , 1 6 1 . 7 9 4 1 0 , 1 2 0 . 7 6 0 . 0 4 1 2 , 1 2 1 . 3 16 , 3 4 1 . 4 9 0 . 5 6 3 2 9 . 7 9 4 , 1 4 7 . 0 4 , 0 7 7 . 7 3 , 4 6 9 . 2 - 1 1 , 7 1 1 . 8 5 , 9 7 6 , 2 4 3 . 7 9 4 1 0 , 0 7 4 . 1 9 0 . 0 4 1 2 , 1 9 3 . 6 16 , 4 3 6 . 6 9 0 . 5 3 3 2 9 . 6 4 4 , 1 4 6 . 0 4 , 0 7 6 . 7 3 , 5 5 1 . 5 - 1 1 , 7 5 9 . 9 5 , 9 7 6 , 3 2 6 . 5 1 4 1 0 , 0 2 7 . 0 2 0 . 1 6 1 2 , 2 6 6 . 7 16 , 5 3 1 . 1 9 0 . 5 3 3 2 9 . 8 9 4 , 1 4 5 . 2 4 , 0 7 5 . 9 3 , 6 3 3 . 1 - 1 1 , 8 0 7 . 4 5 , 9 7 6 , 4 0 8 . 5 9 4 0 9 , 9 8 0 . 3 3 0 . 2 6 1 2 , 3 3 9 . 2 16 , 6 2 7 . 3 9 0 . 5 3 3 2 9 . 6 6 4 , 1 4 4 . 3 4 , 0 7 5 . 0 3 , 7 1 6 . 2 - 1 1 , 8 5 5 . 9 5 , 9 7 6 , 4 9 2 . 2 5 4 0 9 , 9 3 2 . 7 5 0 . 2 4 1 2 , 4 1 3 . 0 16 , 7 2 2 . 0 9 0 . 5 3 3 2 9 . 6 4 4 , 1 4 3 . 4 4 , 0 7 4 . 1 3 , 7 9 7 . 9 - 1 1 , 9 0 3 . 7 5 , 9 7 6 , 5 7 4 . 4 0 4 0 9 , 8 8 5 . 8 0 0 . 0 2 1 2 , 4 8 5 . 8 16 , 8 1 7 . 0 9 0 . 5 3 3 2 9 . 6 6 4 , 1 4 2 . 5 4 , 0 7 3 . 2 3 , 8 7 9 . 9 - 1 1 , 9 5 1 . 7 5 , 9 7 6 , 6 5 6 . 8 6 4 0 9 , 8 3 8 . 6 6 0 . 0 2 1 2 , 5 5 8 . 8 16 , 9 1 2 . 0 9 0 . 5 3 3 2 9 . 1 2 4 , 1 4 1 . 7 4 , 0 7 2 . 4 3 , 9 6 1 . 6 - 1 2 , 0 0 0 . 1 5 , 9 7 6 , 7 3 9 . 1 2 4 0 9 , 7 9 1 . 1 4 0 . 5 7 1 2 , 6 3 2 . 1 17 , 0 0 6 . 6 9 0 . 5 9 3 2 8 . 8 4 4 , 1 4 0 . 7 4 , 0 7 1 . 4 4 , 0 4 2 . 7 - 1 2 , 0 4 8 . 8 5 , 9 7 6 , 8 2 0 . 7 0 4 0 9 , 7 4 3 . 2 4 0 . 3 0 1 2 , 7 0 5 . 5 17 , 1 0 2 . 3 9 0 . 5 3 3 2 8 . 4 6 4 , 1 3 9 . 8 4 , 0 7 0 . 5 4 , 1 2 4 . 5 - 1 2 , 0 9 8 . 6 5 , 9 7 6 , 9 0 2 . 9 5 4 0 9 , 6 9 4 . 3 0 0 . 4 0 1 2 , 7 8 0 . 2 17 , 1 9 7 . 2 9 0 . 4 1 3 2 8 . 0 3 4 , 1 3 9 . 0 4 , 0 6 9 . 7 4 , 2 0 5 . 2 - 1 2 , 1 4 8 . 6 5 , 9 7 6 , 9 8 4 . 1 5 4 0 9 , 6 4 5 . 2 1 0 . 4 7 1 2 , 8 5 4 . 6 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 1 1 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e MD (u s f t ) In c (° ) Az i ( a z i m u t h ) (° ) N/ S (u s f t ) E/ W (u s f t ) No r t h i n g (u s f t ) TV D S S (u s f t ) Ea s t i n g (u s f t ) Su r v e y TV D (u s f t ) DL e g (° / 1 0 0 u s f t ) V. S e c (u s f t ) 17 , 2 9 2 . 1 9 0 . 3 8 3 2 8 . 8 4 4 , 1 3 8 . 4 4 , 0 6 9 . 1 4 , 2 8 6 . 0 - 1 2 , 1 9 8 . 2 5 , 9 7 7 , 0 6 5 . 5 0 4 0 9 , 5 9 6 . 3 9 0 . 8 5 1 2 , 9 2 8 . 8 17 , 3 8 7 . 4 9 0 . 3 8 3 2 9 . 1 2 4 , 1 3 7 . 7 4 , 0 6 8 . 4 4 , 3 6 7 . 7 - 1 2 , 2 4 7 . 4 5 , 9 7 7 , 1 4 7 . 6 9 4 0 9 , 5 4 8 . 1 3 0 . 2 9 1 3 , 0 0 2 . 7 17 , 4 5 0 . 6 9 0 . 4 1 3 2 9 . 5 5 4 , 1 3 7 . 3 4 , 0 6 8 . 0 4 , 4 2 2 . 0 - 1 2 , 2 7 9 . 6 5 , 9 7 7 , 2 0 2 . 3 7 4 0 9 , 5 1 6 . 4 8 0 . 6 8 1 3 , 0 5 1 . 5 17 , 4 7 2 . 0 9 0 . 4 1 3 2 9 . 5 5 4 , 1 3 7 . 1 4 , 0 6 7 . 8 4 , 4 4 0 . 5 - 1 2 , 2 9 0 . 4 5 , 9 7 7 , 2 2 0 . 9 2 4 0 9 , 5 0 5 . 8 3 0 . 0 0 1 3 , 0 6 8 . 0 4- 1 / 2 " P r o d u c t i o n L i n e r 17 , 4 7 8 . 0 9 0 . 4 1 3 2 9 . 5 5 4 , 1 3 7 . 1 4 , 0 6 7 . 8 4 , 4 4 5 . 7 - 1 2 , 2 9 3 . 5 5 , 9 7 7 , 2 2 6 . 1 3 4 0 9 , 5 0 2 . 8 4 0 . 0 0 1 3 , 0 7 2 . 6 Ve r t i c a l De p t h (u s f t ) Me a s u r e d De p t h (u s f t ) Ca s i n g Di a m e t e r (" ) Ho l e Di a m e t e r (" ) Na m e Ca s i n g P o i n t s 20 " C o n d u c t o r C a s i n g 12 8 . 0 12 8 . 0 20 2 0 13 - 3 / 8 " S u r f a c e C a s i n g 2, 3 0 2 . 0 3, 2 1 8 . 0 13 - 3 / 8 1 6 9- 5 / 8 " I n t e r m e d i a t e L i n e r 4, 1 2 3 . 5 11 , 5 6 0 . 0 9- 5 / 8 1 2 - 1 / 4 4- 1 / 2 " P r o d u c t i o n L i n e r 4, 1 3 7 . 1 17 , 4 7 2 . 0 4- 1 / 2 8 - 1 / 2 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 1 2 Pr o j e c t : Co m p a n y : Lo c a l C o - o r d i n a t e R e f e r e n c e : TV D R e f e r e n c e : Si t e : Sa n t o s N A D 2 7 C o n v e r s i o n Pi k k a ND B Sa n t o s L t d Sa n t o s D e f i n i t i v e S u r v e y R e p o r t We l l : We l l b o r e : ND B - 0 5 1 ND B - 0 5 1 Su r v e y C a l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t De s i g n : ND B - 0 5 1 Da t a b a s e : ED M MD R e f e r e n c e : Pa r k e r 2 7 2 A c t u a l @ 6 9 . 3 u s f t No r t h R e f e r e n c e : We l l N D B - 0 5 1 Tr u e Me a s u r e d De p t h (u s f t ) Ve r t i c a l De p t h (u s f t ) Di p Di r e c t i o n (° ) Na m e L i t h o l o g y Di p (° ) Fo r m a t i o n s 1, 1 5 8 . 0 1 , 1 3 8 . 1 B a s e I c e B e a r i n g P e r m a f r o s t 1, 4 0 9 . 0 1 , 3 7 4 . 4 B a s e P e r m a f r o s t T r a n s i t i o n 10 , 3 6 4 . 0 3 , 8 5 5 . 6 N T 7 M F S 10 , 7 3 5 . 0 3 , 9 4 4 . 3 N T 6 M F S 1, 8 3 5 . 0 1 , 7 3 0 . 5 M i d d l e S c h r a d e r B l u f f 10 , 9 4 0 . 0 3 , 9 9 1 . 6 N T 5 M F S 6, 6 7 0 . 0 3 , 0 2 9 . 3 S e a b e e 10 , 1 7 8 . 0 3 , 8 0 9 . 8 N a n u s h u k 4, 2 1 8 . 0 2 , 5 1 1 . 0 T u l u v a k S a n d 1, 0 5 5 . 0 1 , 0 3 9 . 3 U p p e r S c h r a d e r B l u f f 10 , 2 6 1 . 0 3 , 8 3 0 . 3 N T 8 M F S 11 , 5 0 6 . 0 4 , 1 1 2 . 8 N T 3 M F S 11 , 6 3 2 . 0 4 , 1 3 7 . 7 N T 3 . 2 T o p R e s e r v o i r 11 , 1 4 2 . 0 4 , 0 3 7 . 9 N T 4 M F S 2, 5 8 2 . 0 2 , 1 5 1 . 0 M C U 11 , 7 6 2 . 0 4 , 1 6 1 . 6 N T 3 . 2 4 5, 5 9 3 . 0 2 , 8 0 3 . 0 T S _ 7 9 0 3, 9 3 9 . 0 2 , 4 5 2 . 7 T u l u v a k S h a l e Ap p r o v e d B y : Ch e c k e d B y : Da t e : 14 / 0 6 / 2 0 2 4 1 1 : 5 2 : 5 6 CO M P A S S 5 0 0 0 . 1 7 B u i l d Pa g e 1 3 From:Davis, Rachel (Rachel) To:Brooks, James S (OGC) Subject:RE: Logged 10-407 Oil Search NDB-051 10-407 Completion Report Date:Wednesday, July 17, 2024 10:45:07 AM Attachments:image002.png image003.png image001.png image004.png Hi James, I spoke with our Directional Planner and he stated the issue is with the sector number we listed. We have S12 and it should be S36. Thanks! Rachel Davis Technical Assistant t:1 (907) 375-4678 | e: rachel.davis@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Brooks, James S (OGC) <james.brooks@alaska.gov> Sent: July 17, 2024 8:11 AM To: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Subject: ![EXT]: FW: Logged 10-407 Oil Search NDB-051 10-407 Completion Report Hi, The BHL is off. Can you look at it ? 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. thanx -$0(6%522.6 5(6($5&+$1$/<67,,E$/$6.$2,/$1'*$6&216(59$7,21&200,66,21 '(3$570(172)&200(5&(&20081,7<$1'(&2120,&'(9(/230(17 E-$0(6%522.6#$/$6.$*29 From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Monday, July 1, 2024 8:30 AM To: Brooks, James S (OGC) <james.brooks@alaska.gov> Subject: Logged 10-407 Oil Search NDB-051 10-407 Completion Report Hi James, Attached is stamped 10-407 for NDB-051; it is logged in the 10-407 Excel spreadsheet. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 From: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Sent: Monday, July 1, 2024 7:52 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Subject: NDB-051 10-407 Completion Report Morning, Please see attached the 10-407 Completion Report for NDB-051. Thanks! Rachel Davis Technical Assistant t:1 (907) 375-4678 | e: rachel.davis@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 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 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-051 (50-103-20880-0000) Final Well data Submittal Details on following pages – Please note NO Mudlog services for this well. 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: 7/1/2024 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: 224-013 T39096 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.01 10:07:02 -08'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-051 Definitive Compass Survey Report - NAD27.pdf ؒ NDB-051 Definitive Compass Survey Report - NAD83.pdf ؒ NDB-051 Definitive Survey - NAD27.txt ؒ NDB-051 Definitive Survey - NAD83.txt ؒ NDB-051 Definitive Survey Report.xlsx ؒ Santos Letter PlanView.pdf ؒ Santos Letter Vertical Section.pdf ؒ جؐؐؐLog Digital Data and Plots ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐFE Data ؒ ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft.las ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDB-051_AP_R01_RM.las ؒ ؒ ؒ NDB-051_AP_R02_RM.las ؒ ؒ ؒ NDB-051_AP_R03_RM.las ؒ ؒ ؒ NDB-051_AP_R04_RM.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-051_DMT_R01_RM.las ؒ ؒ NDB-051_DMT_R02_RM.las ؒ ؒ NDB-051_DMT_R03_RM.las ؒ ؒ NDB-051_DMT_R04_RM.las ؒ ؒ ؒ جؐؐؐGeoscience deliverables ؒ ؒ NDB-051_SDTK_CBL_7925_11600.cgm ؒ ؒ NDB-051_SDTK_CBL_7925_11600.dlis ؒ ؒ NDB-051_SDTK_CBL_7925_11600.las ؒ ؒ NDB-051_SDTK_CBL_7925_11600.PDF ؒ ؒ NDB-051_SDTK_CBL_7925_11600_dlis.txt ؒ ؒ NDB-051_SDTK_TOC_7925_11600.cgm ؒ ؒ NDB-051_SDTK_TOC_7925_11600.dlis ؒ ؒ NDB-051_SDTK_TOC_7925_11600.las ؒ ؒ NDB-051_SDTK_TOC_7925_11600.PDF ؒ ؒ NDB-051_SDTK_TOC_7925_11600_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphics Images ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_2MD.cgm LETTER OF TRANSMITTAL ؒ ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_2TVD.cgm ؒ ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_5MD.cgm ؒ ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_5TVD.cgm ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDB-051_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDB-051_DMD_RM_17478ft.cgm ؒ ؒ NDB-051_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_2MD.pdf ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_2TVD.pdf ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_5MD.pdf ؒ ؒ NDB-051_LWD_GR_Res_Den_Neu_Cal_RM_17478ft_5TVD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-051_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-051_DMD_RM_17478ft.pdf ؒ NDB-051_DMT_RM.pdf ؒ ؤؐؐؐMudlog NoMudlogServices.txt STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-051 JBR 06/12/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Tested with 5 7/8" and 9 5/8" Test joints, Precharge Bottles =3 Ea. @ 1000psi, 15 Ea. @ 1100psi, 6 Ea. @1200psi. Good Test. Test Results TEST DATA Rig Rep:B. BuzbyOperator:Oil Search (Alaska), LLC Operator Rep:P. Lynch Rig Owner/Rig No.:Parker 272 PTD#:2240130 DATE:5/7/2024 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopBDB240509035322 Inspector Brian Bixby Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6 MASP: 1467 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8"P #1 Rams 1 4 1/2"x7"P #2 Rams 1 Blind/Shear P #3 Rams 1 9 5/8"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8"P Kill Line Valves 2 2 1/16", 3 1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P2950 Pressure After Closure P1800 200 PSI Attained P17 Full Pressure Attained P70 Blind Switch Covers:PYES Bottle precharge P Nitgn Btls# &psi (avg)P14@2300 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P21 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-051 JBR 06/12/2024 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:Good test, accumulator 24 bottles at pre charge 1109 psi avg TEST DATA Rig Rep:Pat LynchOperator:Oil Search (Alaska), LLC Operator Rep:Brian Buzby Contractor/Rig No.:Parker 272 PTD#:2240130 DATE:5/3/2024 Well Class:DEV Inspection No:divKPS240503081024 Inspector Kam StJohn Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:0 NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:16 P Vent Line(s) Size:16 P Vent Line(s) Length:40.25 P Closest Ignition Source:100 P Outlet from Rig Substructure:51 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:24 P Knife Valve Open Time:19 P Diverter Misc:0 NA Systems Pressure:P2900 Pressure After Closure:P2100 200 psi Recharge Time:P20 Full Recharge Time:P52 Nitrogen Bottles (Number of):P14 Avg. Pressure:P2300 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: 0 NAMud System Misc: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Mark Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 900 E Benson Boulevard Anchorage, AK, 99508 Re: Pikka Field, Nanushuk Oil Pool, NDB-051 Oil Search Alaska, LLC Permit to Drill Number: 224-013 Surface Location: 2266’ FSL, 3496 FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 1427’ FSL, 343’ FEL, Sec 36, T12N, R5E, UM Dear Mr. Staudinger: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. Proposed dry ditch sample interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30'). This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this day of March 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.18 13:56:44 -05'00' 18 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 17,478.6 TVD: 4,138 4a. Location of Well (Governmental Section): 7.Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 04/15/24 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3,617 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 70' 15. Distance to Nearest Well Open Surface: x- 421,747.01 y- 5972651.95 Zone- 4 23' to Same Pool:1,800 16. Deviated wells: Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90.5 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42” 20”x34” 215# X-52 Welded 80’ Surface Surface 128' 54' 16” 13-3/8” 68# L-80 BTC 3,167’ Surface Surface 3,167' 2,290' 12-1/4” 9-5/8” 47# L-80 HYD 563 11,500’ 3,017’ 2,258' 11,500' 4,114' See attachment 6 Tie Back 9-5/8” 47# L-80 HYD 563 3,017’ Surface Surface 3,017' 2,258' See attachment 6 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6,207’ 11,271’ 4,072' 17,478' 4,138' Tubing 4-1/2” 12.6# P-110S HYD 563 11,271’ Surface Surface 11,271' 4,072' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Garret Staudinger Garret Staudinger Contact Email:garret.staudinger@santos.com Senior Drilling Engineer Contact Phone:907-440-6892 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Effect. Depth MD (ft): Effect. Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (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) Grouted to surface See attachment 6 Uncemented N/A 18. Casing Program: Top - Setting Depth - BottomSpecifications 1,880 Cement Quantity, c.f. or sacks 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 1,467 2012’ FSL, 2458’ FEL, Sec 6, T11N, R6E, UM 1427’ FSL, 343’ FEL, Sec 36, T12N, R5E, UM LONS 19-003 900 E Benson Bouldevard, Anchorage, AK 99508 Oil Search Alaska, LLC 2266’ FSL, 3496 FEL, Sec 4, T11N, R6E, UM ADL 392984, 391445, 393021, 393019, 392991 3,064 acres NDB-051 Pikka/Nanushuk Oil Pool Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o D s s sD o well is p G S S 20 S S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Senior Drilling Engineer 2/23/2024 By Grace Christianson at 9:20 am, Feb 27, 2024 A.Dewhurst 01MAR24 DSR-2/28/24 See attached conditions of approval 9:23 am, Mar 01, 2024 50-103-20880-00-00224-013 Pikka BJM 3/15/24*&:JLC 3/18/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.03.18 13:57:21 -05'00' 03/18/24 03/18/24 NDB-051 (PTD 224-013) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨApproval 1.KWƚĞƐƚƚŽϯϱϬϬƉƐŝ͕ŶŶƵůĂƌƚĞƐƚƚŽϯϬϬϬƉƐŝ͘ 2.>Kdͬ&/dƌĞƐƵůƚƐƚŽďĞƐƵďŵŝƩĞĚƚŽK'ǁŝƚŚŝŶϰϴŚŽƵƌƐŽĨŽďƚĂ ŝŶŝŶŐƚŚĞĚĂƚĂ͘ 3.EŽƟĨLJK'ŝĨĐĞŵĞŶƚũŽďƐĚŽŶŽƚŐŽĂĐĐŽƌĚŝŶŐƚŽƉůĂŶ͕ŽƌŝĨĐĞŵĞŶƚŝƐŶŽƚĐŝƌĐƵůĂƚĞĚŽīƚŚĞ ƚŽƉŽĨƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞůŝŶĞƌ͘ Intermediate 2nd ƐƚĂŐĞĐĞŵĞŶƚƚŽďĞůŽŐŐĞĚŝĨũŽďĚŽĞƐŶŽƚŐŽ ĂĐĐŽƌĚŝŶŐƚŽƉůĂŶ͘ 4.sĂƌŝĂŶĐĞƚŽϮϬϮϱ͘ϬϯϬ;ĚͿ;ϱͿĨŽƌϮ-ƐƚĂŐĞŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐ ĐĞŵĞŶƚŽƉĞƌĂƟŽŶĂŶĚŐĂƉŝŶ ĐĞŵĞŶƚĐŽǀĞƌĂŐĞŝƐĂƉƉƌŽǀĞĚ͕ǁŝƚŚƐƚĂŐĞĐŽůůĂƌƉůĂĐĞŵĞŶƚĂƐĨŽůůŽǁƐ͗ a.^ƚĂŐĞĐŽůůĂƌŵƵƐƚďĞƉůĂĐĞĚŶŽƐŚĂůůŽǁĞƌƚŚĂŶϱϬΖDďĞůŽǁƚŚĞďĂƐĞŽĨƚŚĞhƉƉĞƌ dƵůƵǀĂŬĂƐĚĞĮŶĞĚďLJƚŚĞd^ϳϵϬŚŽƌŝnjŽŶ͘ ď͘ SƵďŵŝƚϭϮ-ϭͬϰΗK,ůŽŐƐƚŽK'ĂƐƐŽŽŶĂƐƉƌĂĐƟĐĂůĂŌĞƌdŽĨŚŽůĞƐĞĐƟŽŶ͘ 5.dŚĞ>t-^ŽŶŝĐůŽŐǁŝůůŽŶůLJďĞĂĐĐĞƉƚĞĚĨŽƌĐĞŵĞŶƚĞǀĂůƵĂƟŽŶǁŚĞŶƚŚĞĨŽůůŽǁŝŶŐĐŽŶĚŝƟŽŶƐ ĂƌĞŵĞƚ͗ a.KŝůƐĞĂƌĐŚƚŽƉƌŽǀŝĚĞĂǁƌŝƩĞŶůŽŐĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶƚŽƚŚĞK'ĂůŽŶŐǁŝƚŚƚŚĞ ůŽŐĂƐƐŽŽŶĂƐƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘dŚĞĞǀĂůƵĂƟŽŶŝƐƚŽŝŶĚŝ ĐĂƚĞƚŚĞŝŶƚĞƌǀĂůƐŽĨ ĐŽŵƉĞƚĞŶƚĐĞŵĞŶƚƚŚĂƚKŝůƐĞĂƌĐŚŝƐƵƐŝŶŐƚŽŵĞĞƚƚŚĞŽďũĞĐƟǀĞƌĞƋƵŝƌĞŵĞŶƚƐĨŽƌ aŶŶƵůĂƌŝƐŽůĂƟŽŶĂŶĚƌĞƐĞƌǀŽŝƌŝƐŽůĂƟŽŶ͕ĂŶĚƚŽŝŶĚŝĐĂƚĞƚŚĞůŽĐ ĂƟŽŶŽĨĐŽŶĮŶŝŶŐnjŽŶĞƐ͕ ŚLJĚƌŽĐĂƌďŽŶ-ďĞĂƌŝŶŐnjŽŶĞƐ͕ŽǀĞƌƉƌĞƐƐƵƌĞĚnjŽŶĞƐĂŶĚĨƌĞƐŚǁĂƚĞƌ͕ŝĨƉƌĞƐĞŶƚ͘WƌŽǀŝĚŝŶŐ ƚŚĞůŽŐǁŝƚŚŽƵƚĂŶĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶŝƐŶŽƚĂĐĐĞƉƚĂďůĞ͘ ď͘ >tƐŽŶŝĐůŽŐƐŵƵƐƚƐŚŽǁĨƌĞĞƉŝƉĞĂŶĚdŽƉŽĨĞŵĞŶƚ͘ dŚĞůŽŐŵƵƐƚďĞƌƵŶĂĐƌŽƐƐƚŚĞ ƚĂƌŐĞƚnjŽŶĞƐĂŶĚĂƚĂĚĞƉƚŚƚŽĞŶƐƵƌĞƚŚĞĨƌĞĞƉŝƉĞĂďŽǀĞƚŚĞdKŝƐĐĂƉƚƵƌĞĚĂƐǁĞůůĂƐ ƚŚĞdK͘/ĨƚŚĞůŽŐŐĞĚŝŶƚĞƌǀĂůĚŽĞƐŶŽƚĐĂƉƚƵƌĞƚŚĞdKĂŶĚĨƌĞĞƉŝƉĞĂďŽǀĞŝƚ͕ ŝƚǁŝůů ŶĞĞĚƚŽďĞƌĞ-ƌƵŶ͕ƵŶůĞƐƐƚŚĞĐĞŵĞŶƚǁĂƐƉůĂŶŶĞĚƚŽĐŽǀĞƌƚŚĞĞŶƟƌĞůĞŶŐƚŚŽĨůŝŶĞƌŽƌ ĐĂƐŝŶŐ͘ Đ͘ KŝůƐĞĂƌĐŚǁŝůůƉƌŽǀŝĚĞĂĐĞŵĞŶƚũŽďƐƵŵŵĂƌLJƌĞƉŽƌƚĂŶĚĞǀĂůƵĂƟŽŶĂůŽŶŐǁŝƚŚƚŚĞ ĐĞŵĞŶƚůŽŐĂŶĚĞǀĂůƵĂƟŽŶƚŽƚŚĞK'ǁŚĞŶƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘ d.ĞƉĞŶĚŝŶŐŽŶƚŚĞĐĞŵĞŶƚũŽďƌĞƐƵůƚƐŝŶĚŝĐĂƚĞĚďLJƚŚĞĐĞŵĞŶƚũŽď ƌĞƉŽƌƚ͕ƚŚĞůŽŐƐĂŶĚ ƚŚĞ&/d͕ƌĞŵĞĚŝĂůŵĞĂƐƵƌĞƐŽƌĂĚĚŝƟŽŶĂůůŽŐŐŝŶŐŵĂLJďĞƌĞƋƵŝƌĞĚ͘ Page 1 of 1 23 February 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-051 Dear Sir/Madam, Oil Search (Alaska), LLC hereby applies for a Permit to Drill an onshore development well from the NDB drilling pad on the North Slope of Alaska. NDB-051 is planned to be a horizontal producer targeting the Nanushuk 3. The approximate spud date is anticipated to be April 15 th, 2024. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~78 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8” tieback will be run to the top of the 9-5/8” liner. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand and the lateral will be drilled to TD. The well will be completed as a stimulated 4-1/2” liner with frac sleeves and isolation packers. The production liner will be tied back to surface with a 4-1/2” tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (907) 440-6892 or Garret.Staudinger@santos.com. Respectfully, Garret Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, Application for Permit to Drill NDB-051 Well Table of Contents 1. Well Name.................................................................................................................................3 2. Location Summary.....................................................................................................................3 3. Blowout Prevention Equipment Information..............................................................................4 4. Drilling Hazards Information......................................................................................................5 5. Procedure for Conducting Formation Integrity Tests..................................................................6 6. Casing and Cementing Program.................................................................................................6 7. Diverter System Information......................................................................................................7 8. Drilling Fluid Program................................................................................................................7 9. Abnormally Pressured Formation Information...........................................................................8 10. Seismic Analysis.......................................................................................................................8 11. Seabed Condition Analysis.......................................................................................................8 12. Evidence of Bonding................................................................................................................8 13. Proposed Drilling Program.......................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal..............................................11 15. Proposed Variance Request...................................................................................................11 Attachments............................................................................................................................................13 Attachment 1: Location Maps......................................................................................................14 Attachment 2: Directional Plan....................................................................................................15 Attachment 3: BOPE Equipment..................................................................................................1 6 Attachment 4: Drilling Hazards....................................................................................................17 Attachment 5: Leak Off Test Procedure.......................................................................................19 Attachment 6: Cement Summary.................................................................................................20 Attachment 7: Prognosed Formation Tops...................................................................................22 Attachment 8: Well Schematic.....................................................................................................23 Attachment 9: Formation Evaluation Program.............................................................................24 Attachment 10: Wellhead & Tree Diagram ..................................................................................25 Attachment 11: Tuluvak Isolation Significant Hydrocarbon Cross Section.....................................26 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDB-051. This will be a development production well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 2266’ FSL, 3496 FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,652 E 421,747 Rig KB Elevation 47’ above GL Ground Level 23’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 2012’ FSL, 2458’ FEL, Sec 6, T11N, R6E, UM NAD 27 Coordinate System N 5,972,505 E 412,230 Measured Depth, Rig KB (MD) 12,021’ Total Vertical Depth, Rig KB (TVD) 4,186’ Total vertical Depth, Subsea (TVDSS) 4,116’ Location at Bottom of Productive Interval Reference to Government Section Lines 1427’ FSL, 343’ FEL, Sec 36, T12N, R5E, UM NAD 27 Coordinate System N 5,977,231’ E 409,501’ Measured Depth, Rig KB (MD) 17,478’ Total Vertical Depth, Rig KB (TVD) 4,138’ Total vertical Depth, Subsea (TVDSS) 4,068’ (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 2: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for NDB-051 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Parker 272 BOP Equipment: BOP Equipment x NOV Shaffer Spherical annular BOP, 13-5/8” x 5000 psi x NOV T3 6012 double gate, 13-5/8” x 5000 psi x Mud cross, 13-5/8” x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets x Choke Line, 3-1/8” x 5000 psi with 3-1/8” manual and HCR valve x Kill Line, 2-1/16” x 5000 psi with 3-1/8” manual and HCR valve x NOV T3 6012 single gate, 13-5/8” x 5000 psi Choke Manifold x 3-1/8” x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit x NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,872 psi in the Nanushuk 3 at 4,104’ TVD (8.8ppg EMW Nanushuk 3 formation to section TD) Maximum surface pressure 1,462 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,104’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 12-1/4” hole LOT after drilling 20’-50’ of new hole. 13.2 ppg LOT required for Kick Tolerance. 13-3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by 50% of Casing Burst] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,880 psi in the Nanushuk 3.2 at 4,130’ TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,467 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,130’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 8-1/2” hole FIT after drilling 20’-50’ of new hole to 15.0 ppg. (10.6 ppg EMW LOT Required for infinite kick tolerance.) 9-5/8” Liner Test 4,000 psi surface pressure [Test pressure driven by annular pressure during frac job] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be overpressured at 10.2ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. Tuluvak is expected to be overpressured at 10.2ppg pore pressure Tuluvak formation is expected in this area and has a hi gh potential for gas (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 / TVD 42” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 54’ 16” 13-3/8” 68# L-80 BTC 3,167’ Surface 3,167’ / 2,290’ 12-1/4” 9-5/8” 47# L-80 HYD 563 11,500’ 3,017’ 11,500’ / 4,114’ Tie Back 9-5/8” 47# L-80 HYD 563 3,017’ Surface 3,017’ / 2,258’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6,207’ 11,271’ 17,478’ / 4,138’ Tubing 4-1/2” 12.6# P-110S HYD 563 11,271’ Surface 11,271’ / 4,072’ Please refer to Attachment 6: Cement Summary for further details. 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line Please refer to Attachment 3: BOPE Equipment for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Intermediate Hole Production Hole Mud Type Water based Spud Mud Mineral Oil Based Mud Mineral Oil Based Mud Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 10ppg 100-300 seconds ALAP 30-80 < 10 ml/30min n/a 8.6-10.5 <35 12-12.5 ppg 50-80 seconds ALAP 15-30 n/a < 5 ml/30min n/a n/a 10ppg 50-80 seconds ALAP 10-20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDB-051 Well is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Oil Search Alaska is on file with the Commission. 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to NDB-051 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program NDB-051 1. Drill 20” conductor to ~128’ MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools and diverter over the 20” conductor. Verify that the diverter line is at least 75’ away from a potential source of ignition and beyond the drill rig substructure. 4. Function test diverter and knife valve as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing diverter test. 5. Pick up 5-7/8” drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16” motor BHA with MWD and LWD tools. 6. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 7. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 8. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 9. ND diverter and NU casing head and spacer spool. NU BOPE (configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 9-5/8” Fixed Rams). Test rams to 3500 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing BOP test. 10. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 11. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to 12 ppg MOBM. 12. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test. 13. Directionally drill 12-1/4” intermediate hole section to TD ~10’ TVD below the NT3 MFS. Perform wiper trips as required. Circulate and condition hole to run casing. POOH. 14. 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. 15. Cement 9-5/8” liner with 1st stage cement job as per cement program. Monitor returns during displacement. Bump plug then pressure up to set liner hanger and release running tool. 16. Un-sting from liner hanger and POOH and LD liner running tools. 17. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Sting into second stage tool pump secondary stage, SO and set liner top packer. POOH and lay down running tool. 18. Run 9-5/8” tie-back string. Freeze protect the 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 19. Pressure test 13-3/8” x 9-5/8” to 2600 psi for 30 min. 20. Pressure test the 9-5/8” liner and tieback to 3500 psi for 30 min. 21. Change out lower BOP rams from 9-5/8” fixed to 4-1/2” x 7” VBR and test to 3500 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 10.0 ppg MOBM. 23. Drill out shoe track and 20 - 50’ of new formation. Perform formation integrity test. 24. Directionally drill 8-1/2” hole section as per well plan to TD. Perform wiper trips as required. 25. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary 26. RU and run 4-1/2” production liner with liner hanger / liner top packer and downhole jewelry to TD. 27. Set and pressure test the 9-5/8” x 4-1/2” IA to liner top packer to 4,000 psi for 10 min. Release the running tool. 28. Circulate corrosion inhibited brine. 29. POOH and LD liner running tool. 30. RU and run 4-1/2” upper completion and downhole jewelry with TEC wire. Space out seals. 31. Land tubing hanger 32. Pressure test tubing to 4,000 psi for 30 mins. Pressure up on the annulus to 3,500 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 33. Reverse circulate freeze protect and U-Tube. 34. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. Pressure test to 5,000 psi for 10 mins. 35. RDMO If cement job does not go according to plan, or if cement is not circulated off the top of the liner, notify AOGCC and discuss need for cement log across 2nd stage cement. -bjm 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. Water-based and oil based drilling muds and cuttings will typically be hauled directly offsite via truck as it is generated. Contractual arrangements have been made with other operators on the North Slope to utilize their waste injection/disposal facilities (Class 1 and Class 2) at Prudhoe Bay, Kuparuk and Milne Point. If waste cannot be hauled directly offsite, it may be stored temporarily in drilling waste cuttings bins or a bermed cuttings storage cell in accordance with a drilling waste temporary storage plan approved by Alaska Department of Conservation (ADEC) Solid Waste Program until it can be transported for proper disposal. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Request 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire annular space from the casing shoe to above shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the significant hydrocarbon zone in the Nanushuk formation (primary job), and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. The primary cement job will target a top of cement 500’ MD or 250’ TVD, whichever is greater, above the top of the Nanushuk. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the intermediate liner is not achievable without exceeding the fracture gradient and compromising cement placement and zonal isolation. The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be designed to: 1) provide suitable and safe operating conditions for the total measured depth proposed; 2) confine fluids to the wellbore; 3) prevent migration of fluids from one stratum to another; 4) ensure control of well pressures encountered; 5) protect against thaw subsidence and freezeback effects within permafrost; 6) prevent contamination of freshwater; 7) protect significant hydrocarbon zones; and 8) provide well control until the next casing is set, considering all factors relevant to well control including formation fracture gradients, formation pressures, casing setting depths, and proposed total depth. The formation interval between the top of stage one and the bottom of stage two includes the Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with very low permeability and contain no significant hydrocarbons. Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,640’ TVD. The Tuluvak formation below 2,640’ TVD is not a significant hydrocarbon zone. A stage collar placement is proposed 50’ MD below the TS 790 formation marker (Upper Tuluvak). This stage collar depth will isolate any potential gas based on offset well data. The TS 875 and TS 870 clinoform is between the TS 880 clinoform and TS 790 top. The TS 875 and TS 870 clinoforms are shale dominated, very low net to gross, has no vertical permeability, and represents a seal to the hydrocarbon bearing TS 880. Moving the cementing stage tool to be placed at 50’ MD below the TS 790 formation marker allows placement of higher quality cement that provides better isolation across the significant hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will add risk to the primary objective of cement isolation across the significant hydrocarbon zone which is only located in the upper portion of the Tuluvak (TS 880). The increased risk is due to: 1) Cementing the entire Tuluvak would require large cement jobs that jeopardize cement isolation across the upper Tuluvak. 2) Large cement jobs likely require the use of lighter weight cement across the significant hydrocarbon zone. 50’ MD below the TS 790 formation marker (Upper Tuluvak) Recommend approving request to set stage collar 50' below TS 790 (base of Upper Tuluvak) based on confidential evidence provided to AOGCC regarding base of significant hydrocarbon in Tuluvak. -A.Dewhurst 01MAR24 Attachments Attachment 1: Location Maps ADL 392977 ADL 392991 ADL 392985 ADL 392984 ADL 392958 ADL 392970 ADL 393022 ADL 393021 ADL 393023 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 391445 ADL 391455 U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N005E25 U012 U012N005E36 U011N005E01 U011N005E12 U011N006E09U011N006E08 U012N006E31 U011N006E06 U012N006E30 U011N006E07 FIORD 3A QUGRUK 3 QUGRUK 301 QUGRUK 3A DW-02 NDB-032 NDBi-014 NDBi-030 NDBi-043 NDBi-044 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDB-051 SURFACE LOCATION NDB-051 BOTTOM HOLE NDB-051 WELL TRAJECTORY OTHER DRILLED NDB WELLS .25-MILE BUFFER .5-MILE BUFFER EXPLORATION WELLS BOTTOM HOLES WELL TRAJECTORIES BY OTHERS PRODUCTION INTERVAL SANTOS LEASES SECTIONS DATE: 2/6/2024. By: JN 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB51_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDB-051 WELL OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD OTHER NDB WELLS WELL HEAD RIG OUTLINES DIVERTER (50-ft) DATE: 2/12/2024. By: JB 0204010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB51_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDB-051 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.3350833 Ͳ150.6379978 N 70° 20' 06.286" W 150° 38' 16.792" 5,972,400.06 1,561,779.79 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.3353983 Ͳ150.6348647 N 70° 20' 07.437" W 150° 38' 05.514" 5,972,651.95 421,747.01 State Plane NAD83 Zone 4 (as-planned) StatePlane NAD27 Zone 4 (as-planned) Attachment 2: Directional Plan SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 47.0 0.00 0.00 47.0 0.0 0.0 0.00 0.00 0.0 2 347.0 0.00 0.00 347.0 0.0 0.0 0.00 0.00 0.0 Start Build 2.50 3 587.0 6.00 256.66 586.6 -2.9 -12.2 2.50 256.66 10.5 Start Build 3.00 4 1000.6 18.40 256.66 990.0 -23.0 -97.1 3.00 0.00 83.5 Start 159.0 hold at 1000.6 MD 5 1159.6 18.40 256.66 1140.9 -34.6 -145.9 0.00 0.00 125.4 Start DLS 3.50 TFO -21.82 6 2856.1 77.78 256.68 2224.1 -312.7 -1320.2 3.50 0.03 1135.0 Start 5876.8 hold at 2856.1 MD 7 8732.9 77.78 256.68 3468.2 -1635.5 -6909.4 0.00 0.00 5940.1 Start DLS 2.50 TFO 97.65 8 11499.7 78.64 327.56 4114.0 -683.7 -9243.2 2.50 97.65 8458.5 Start 221.7 hold at 11499.7 MD 9 11721.4 78.64 327.56 4157.7 -500.2 -9359.8 0.00 0.00 8630.6 Start DLS 4.00 TFO 8.82 10 12021.4 90.50 329.39 4186.0 -246.0 -9515.6 4.00 8.82 8863.7 NDB-051 Rev 0.0 Heel Start 5457.2 hold at 12021.4 MD 11 17478.6 90.50 329.39 4138.0 4450.5 -12294.3 0.00 0.00 13075.0 NDB-051 Rev 0.0 Toe TD at 17478.6 Plan: NDB-051 Rev D.0 Plan Summary 0 3 Do g l e g S e v e r i t y 0 2500 5000 7500 10000 12500 15000 17500 Measured Depth 20" Conductor Casing13-3/8" Surface Casing 9-5/8" Intermediate Liner 45 45 90 90 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in] 5075100125150175200225250275300325327350375400425450475500525550NDBi-046A Rev B.0 5075100125150175200225250275300325327350375400425450475500525550Plan: NDBi-046 Rev D.0 75100125150175200225250275300325327350375400425450475500525550575600625650675700725750775800825850875900925950975100010251050107511001125115011751200122512501275130013251350137514001425145014751500 Plan: NDBi-050 Rev A.0 5075100125150175200225250275300325327350375400425450475 5005255505756006256506757007257507758008258508759009259509751000102510501075110011251150117512001225125012751300132513501375140014251450147515001525155015751600 Plan: NDBi-049 Rev E.0 5075100125150175200225250275300325327350375400425450475500525550575600625650675700725750775800825 NDB-048 Rev A.0 0 2250 Tr u e V e r t i c a l D e p t h 0 20004000600080001000012000 Vertical Section at 289.90° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 0 28 55 Ce n t r e t o C e n t r e S e p a r a t i o n 0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.160 SURVEY PROGRAM Date: 2021-02-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 300.0 Plan: NDB-051 Rev D.0 (NDB-051) SDI_URSA1_I4 300.0 1500.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag 300.0 3167.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag 3167.0 4367.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag 3167.0 5000.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag 5000.0 5500.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+Sag 5500.0 6700.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag 5500.0 11500.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag 11500.0 12700.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag 11500.0 17478.6 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag Surface Location North / 5972400.06 East / 1561779.77 Elevation / 23.0 CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner Mag Model & Date: IGRF2000 31-Dec-04 Magnetic North is 24.72° East of True North (Magnetic Declin Mag Dip & Field Strength: 80.61°57282.16066573nT FORMATION TOP DETAILS TVDPath Formation 1043.0 Upper SB 1133.0Base Ice Bearing Permafrost 1390.0Base Permafrost Transition 1737.0Middle Schrader Bluff 2140.0 MCU 2443.1Tuluvak Shale 2502.1Tuluvak Sand 3151.2 Seabee 3805.5 Nanushuk 3837.6 NT8 MFS 3858.1 NT7 MFS 3944.1 NT6 MFS 3989.7 NT5 MFS 4034.4 NT4 MFS 4104.7 NT3 MFS 4130.4NT3.2 Top Reservoir 4158.4 NT 3.24 4179.8 NT 3.23 By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet la teral tolerance. Prepared by Checked by BHI DE Accepted by BHI PSD Approved by Santos DE DF @ 70.0usft Standard Planning Report -Geographic 08 February, 2024 Plan: Plan: NDB-051 Rev D.0 Santos NAD27 Conversion Pikka NDB NDB-051 NDB-051 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka, North Slope Alaska, United States Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: NDB Map Slot Radius:0.9 usft usft usft " 5,972,909.70 423,383.56 20 70° 20' 10.138 N 150° 37' 17.796 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: NDB-051 Wellhead Elevation:0.5 0.0 0.0 5,972,651.95 421,747.01 70° 20' 7.437 N 150° 38' 5.514 W 23.0 usft usft usft usft usft usft usft °-0.60Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDB-051 Model NameMagnetics IGRF2020 30/03/2024 14.24 80.54 57,166.28186678 Phase:Version: Audit Notes: Design Plan: NDB-051 Rev D.0 PLAN Vertical Section:Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 289.900.00.047.0 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 2 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 8/02/2024 Depth To (usft) Depth From (usft) SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISC Plan: NDB-051 Rev D.0 (NDB-05147.0 300.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-051 Rev D.0 (NDB-052300.0 1,500.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-051 Rev D.0 (NDB-053300.0 3,167.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-051 Rev D.0 (NDB-0543,167.0 4,367.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-051 Rev D.0 (NDB-0553,167.0 5,000.0 3_MWD+Sag A002Mb/ISC4: BGGM dec + Plan: NDB-051 Rev D.0 (NDB-0565,000.0 5,500.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-051 Rev D.0 (NDB-0575,500.0 6,700.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-051 Rev D.0 (NDB-0585,500.0 11,500.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDB-051 Rev D.0 (NDB-05911,500.0 12,700.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-051 Rev D.0 (NDB-051011,500.0 17,478.6 Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.00.047.00.000.0047.0 0.000.000.000.000.00.0347.00.000.00347.0 256.660.002.502.50-12.2-2.9586.6256.666.00587.0 0.000.003.003.00-97.1-23.0990.0256.6618.401,000.6 0.000.000.000.00-145.9-34.61,140.9256.6618.401,159.6 0.030.003.503.50-1,320.2-312.62,224.1256.6977.782,856.1 0.000.000.000.00-6,909.6-1,635.13,468.3256.6977.788,733.0 97.652.560.032.50-9,243.3-683.34,114.0327.5678.6411,499.7 0.000.000.000.00-9,359.9-499.84,157.7327.5678.6411,721.4 8.820.613.954.00-9,515.7-245.74,186.0329.3990.5012,021.4 NDB-051 Rev 0.0 H 90.480.000.000.00-12,294.04,451.24,138.0329.4090.5017,478.7 NDB-051 Rev 0.0 T 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 3 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 47.0 0.00 47.0 0.0 0.00.00 421,747.015,972,651.95 70° 20' 7.437 N 150° 38' 5.514 W 100.0 0.00 100.0 0.0 0.00.00 421,747.015,972,651.95 70° 20' 7.437 N 150° 38' 5.514 W 128.0 0.00 128.0 0.0 0.00.00 421,747.015,972,651.95 70° 20' 7.437 N 150° 38' 5.514 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 421,747.015,972,651.95 70° 20' 7.437 N 150° 38' 5.514 W 300.0 0.00 300.0 0.0 0.00.00 421,747.015,972,651.95 70° 20' 7.437 N 150° 38' 5.514 W 347.0 0.00 347.0 0.0 0.00.00 421,747.015,972,651.95 70° 20' 7.437 N 150° 38' 5.514 W Start Build 2.50 400.0 1.33 400.0 -0.1 -0.6256.66 421,746.425,972,651.81 70° 20' 7.435 N 150° 38' 5.531 W 500.0 3.83 499.9 -1.2 -5.0256.66 421,742.035,972,650.82 70° 20' 7.425 N 150° 38' 5.659 W 547.0 5.00 546.7 -2.0 -8.5256.66 421,738.515,972,650.03 70° 20' 7.417 N 150° 38' 5.761 W Start Build 2.57 587.0 6.00 586.6 -2.9 -12.2256.66 421,734.775,972,649.18 70° 20' 7.408 N 150° 38' 5.870 W Start Build 3.00 600.0 6.39 599.5 -3.2 -13.6256.66 421,733.405,972,648.87 70° 20' 7.405 N 150° 38' 5.910 W 700.0 9.39 698.5 -6.4 -26.9256.66 421,720.025,972,645.84 70° 20' 7.374 N 150° 38' 6.300 W 800.0 12.39 796.7 -10.7 -45.3256.66 421,701.605,972,641.68 70° 20' 7.331 N 150° 38' 6.837 W 900.0 15.38 893.8 -16.3 -68.7256.66 421,678.195,972,636.39 70° 20' 7.276 N 150° 38' 7.519 W 1,000.0 18.38 989.5 -23.0 -96.9256.66 421,649.875,972,629.98 70° 20' 7.211 N 150° 38' 8.344 W 1,000.6 18.40 990.0 -23.0 -97.1256.66 421,649.705,972,629.94 70° 20' 7.210 N 150° 38' 8.349 W Start 159.0 hold at 1000.6 MD 1,056.4 18.40 1,043.0 -27.1 -114.2256.66 421,632.505,972,626.06 70° 20' 7.170 N 150° 38' 8.850 W Upper Schrader Bluff 1,100.0 18.40 1,084.3 -30.3 -127.6256.66 421,619.095,972,623.02 70° 20' 7.139 N 150° 38' 9.241 W 1,151.3 18.40 1,133.0 -34.0 -143.4256.66 421,603.305,972,619.45 70° 20' 7.102 N 150° 38' 9.701 W Base Ice Bearing Permafrost 1,158.8 18.40 1,140.1 -34.5 -145.7256.66 421,600.995,972,618.93 70° 20' 7.097 N 150° 38' 9.768 W Start DLS 3.50 TFO -21.82 1,159.6 18.40 1,140.9 -34.6 -145.9256.66 421,600.755,972,618.87 70° 20' 7.096 N 150° 38' 9.775 W Start DLS 3.50 TFO 0.03 1,200.0 19.82 1,179.1 -37.7 -158.8256.66 421,587.845,972,615.96 70° 20' 7.066 N 150° 38' 10.151 W 1,300.0 23.32 1,272.1 -46.1 -194.6256.67 421,552.005,972,607.85 70° 20' 6.983 N 150° 38' 11.195 W 1,400.0 26.82 1,362.6 -55.9 -235.8256.67 421,510.695,972,598.52 70° 20' 6.887 N 150° 38' 12.399 W 1,430.8 27.89 1,390.0 -59.2 -249.6256.67 421,496.885,972,595.40 70° 20' 6.855 N 150° 38' 12.801 W Base Permafrost Transition 1,500.0 30.32 1,450.4 -66.9 -282.3256.67 421,464.065,972,587.98 70° 20' 6.778 N 150° 38' 13.758 W 1,600.0 33.82 1,535.2 -79.2 -333.9256.68 421,412.295,972,576.29 70° 20' 6.658 N 150° 38' 15.266 W 1,700.0 37.32 1,616.5 -92.6 -390.5256.68 421,355.575,972,563.48 70° 20' 6.526 N 150° 38' 16.918 W 1,800.0 40.82 1,694.1 -107.1 -451.9256.68 421,294.115,972,549.60 70° 20' 6.383 N 150° 38' 18.709 W 1,857.5 42.83 1,737.0 -115.9 -489.2256.68 421,256.705,972,541.16 70° 20' 6.296 N 150° 38' 19.799 W Middle Schrader Bluff 1,900.0 44.32 1,767.8 -122.7 -517.7256.68 421,228.145,972,534.71 70° 20' 6.230 N 150° 38' 20.631 W 2,000.0 47.82 1,837.2 -139.2 -587.7256.68 421,157.925,972,518.86 70° 20' 6.067 N 150° 38' 22.677 W 2,100.0 51.32 1,902.0 -156.8 -661.8256.68 421,083.695,972,502.10 70° 20' 5.894 N 150° 38' 24.840 W 2,200.0 54.82 1,962.1 -175.2 -739.6256.68 421,005.745,972,484.50 70° 20' 5.713 N 150° 38' 27.111 W 2,300.0 58.32 2,017.2 -194.4 -820.8256.68 420,924.355,972,466.14 70° 20' 5.524 N 150° 38' 29.482 W 2,400.0 61.82 2,067.1 -214.4 -905.1256.68 420,839.845,972,447.06 70° 20' 5.328 N 150° 38' 31.944 W 2,500.0 65.32 2,111.6 -235.0 -992.2256.69 420,752.525,972,427.36 70° 20' 5.125 N 150° 38' 34.488 W 2,571.5 67.82 2,140.0 -250.1 -1,056.0256.69 420,688.555,972,412.92 70° 20' 4.976 N 150° 38' 36.352 W MCU 2,600.0 68.82 2,150.5 -256.2 -1,081.8256.69 420,662.705,972,407.09 70° 20' 4.916 N 150° 38' 37.105 W 2,700.0 72.32 2,183.8 -277.9 -1,173.6256.69 420,570.745,972,386.34 70° 20' 4.703 N 150° 38' 39.784 W 2,800.0 75.82 2,211.3 -300.0 -1,267.1256.69 420,476.965,972,365.18 70° 20' 4.485 N 150° 38' 42.516 W 2,856.1 77.78 2,224.1 -312.6 -1,320.2256.69 420,423.735,972,353.17 70° 20' 4.361 N 150° 38' 44.067 W Start 5876.8 hold at 2856.1 MD 2,900.0 77.78 2,233.4 -322.5 -1,362.0256.69 420,381.845,972,343.72 70° 20' 4.264 N 150° 38' 45.287 W 2,920.2 77.78 2,237.6 -327.0 -1,381.3256.69 420,362.545,972,339.36 70° 20' 4.219 N 150° 38' 45.849 W Start 5806.5 hold at 2920.2 MD 3,000.0 77.78 2,254.5 -345.0 -1,457.1256.69 420,286.515,972,322.21 70° 20' 4.042 N 150° 38' 48.064 W 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 4 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 3,100.0 77.78 2,275.7 -367.5 -1,552.2256.69 420,191.195,972,300.70 70° 20' 3.821 N 150° 38' 50.841 W 3,167.0 77.78 2,289.9 -382.6 -1,615.9256.69 420,127.325,972,286.29 70° 20' 3.672 N 150° 38' 52.702 W 13-3/8" Surface Casing 3,200.0 77.78 2,296.9 -390.0 -1,647.3256.69 420,095.865,972,279.19 70° 20' 3.599 N 150° 38' 53.619 W 3,300.0 77.78 2,318.0 -412.5 -1,742.4256.69 420,000.535,972,257.69 70° 20' 3.378 N 150° 38' 56.396 W 3,400.0 77.78 2,339.2 -435.0 -1,837.5256.69 419,905.205,972,236.18 70° 20' 3.156 N 150° 38' 59.173 W 3,500.0 77.78 2,360.4 -457.5 -1,932.7256.69 419,809.875,972,214.67 70° 20' 2.935 N 150° 39' 1.950 W 3,600.0 77.78 2,381.6 -480.0 -2,027.8256.69 419,714.555,972,193.16 70° 20' 2.713 N 150° 39' 4.727 W 3,700.0 77.78 2,402.7 -502.5 -2,122.9256.69 419,619.225,972,171.65 70° 20' 2.491 N 150° 39' 7.504 W 3,800.0 77.78 2,423.9 -525.0 -2,218.0256.69 419,523.895,972,150.15 70° 20' 2.270 N 150° 39' 10.281 W 3,890.4 77.78 2,443.1 -545.4 -2,304.0256.69 419,437.685,972,130.70 70° 20' 2.069 N 150° 39' 12.793 W Tuluvak Shale 3,900.0 77.78 2,445.1 -547.5 -2,313.1256.69 419,428.565,972,128.64 70° 20' 2.048 N 150° 39' 13.058 W 4,000.0 77.78 2,466.2 -570.0 -2,408.2256.69 419,333.235,972,107.13 70° 20' 1.827 N 150° 39' 15.835 W 4,100.0 77.78 2,487.4 -592.5 -2,503.3256.69 419,237.915,972,085.62 70° 20' 1.605 N 150° 39' 18.612 W 4,169.2 77.78 2,502.1 -608.1 -2,569.1256.69 419,171.965,972,070.74 70° 20' 1.452 N 150° 39' 20.534 W Tuluvak Sand 4,200.0 77.78 2,508.6 -615.0 -2,598.4256.69 419,142.585,972,064.12 70° 20' 1.383 N 150° 39' 21.389 W 4,300.0 77.78 2,529.8 -637.5 -2,693.5256.69 419,047.255,972,042.61 70° 20' 1.162 N 150° 39' 24.166 W 4,400.0 77.78 2,550.9 -660.0 -2,788.6256.69 418,951.925,972,021.10 70° 20' 0.940 N 150° 39' 26.943 W 4,500.0 77.78 2,572.1 -682.5 -2,883.7256.69 418,856.595,971,999.59 70° 20' 0.718 N 150° 39' 29.720 W 4,600.0 77.78 2,593.3 -705.0 -2,978.8256.69 418,761.275,971,978.08 70° 20' 0.497 N 150° 39' 32.497 W 4,700.0 77.78 2,614.4 -727.6 -3,073.9256.69 418,665.945,971,956.58 70° 20' 0.275 N 150° 39' 35.274 W 4,800.0 77.78 2,635.6 -750.1 -3,169.0256.69 418,570.615,971,935.07 70° 20' 0.053 N 150° 39' 38.051 W 4,900.0 77.78 2,656.8 -772.6 -3,264.2256.69 418,475.285,971,913.56 70° 19' 59.832 N 150° 39' 40.828 W 5,000.0 77.78 2,678.0 -795.1 -3,359.3256.69 418,379.955,971,892.05 70° 19' 59.610 N 150° 39' 43.605 W 5,100.0 77.78 2,699.1 -817.6 -3,454.4256.69 418,284.635,971,870.54 70° 19' 59.388 N 150° 39' 46.382 W 5,200.0 77.78 2,720.3 -840.1 -3,549.5256.69 418,189.305,971,849.04 70° 19' 59.166 N 150° 39' 49.158 W 5,300.0 77.78 2,741.5 -862.6 -3,644.6256.69 418,093.975,971,827.53 70° 19' 58.945 N 150° 39' 51.935 W 5,400.0 77.78 2,762.6 -885.1 -3,739.7256.69 417,998.645,971,806.02 70° 19' 58.723 N 150° 39' 54.712 W 5,500.0 77.78 2,783.8 -907.6 -3,834.8256.69 417,903.315,971,784.51 70° 19' 58.501 N 150° 39' 57.489 W 5,600.0 77.78 2,805.0 -930.1 -3,929.9256.69 417,807.995,971,763.01 70° 19' 58.279 N 150° 40' 0.266 W 5,700.0 77.78 2,826.2 -952.6 -4,025.0256.69 417,712.665,971,741.50 70° 19' 58.057 N 150° 40' 3.042 W 5,800.0 77.78 2,847.3 -975.1 -4,120.1256.69 417,617.335,971,719.99 70° 19' 57.836 N 150° 40' 5.819 W 5,900.0 77.78 2,868.5 -997.6 -4,215.2256.69 417,522.005,971,698.48 70° 19' 57.614 N 150° 40' 8.596 W 6,000.0 77.78 2,889.7 -1,020.1 -4,310.3256.69 417,426.685,971,676.97 70° 19' 57.392 N 150° 40' 11.373 W 6,100.0 77.78 2,910.8 -1,042.6 -4,405.4256.69 417,331.355,971,655.47 70° 19' 57.170 N 150° 40' 14.149 W 6,200.0 77.78 2,932.0 -1,065.1 -4,500.5256.69 417,236.025,971,633.96 70° 19' 56.948 N 150° 40' 16.926 W 6,300.0 77.78 2,953.2 -1,087.6 -4,595.7256.69 417,140.695,971,612.45 70° 19' 56.726 N 150° 40' 19.703 W 6,400.0 77.78 2,974.4 -1,110.1 -4,690.8256.69 417,045.365,971,590.94 70° 19' 56.504 N 150° 40' 22.479 W 6,500.0 77.78 2,995.5 -1,132.6 -4,785.9256.69 416,950.045,971,569.43 70° 19' 56.282 N 150° 40' 25.256 W 6,600.0 77.78 3,016.7 -1,155.1 -4,881.0256.69 416,854.715,971,547.93 70° 19' 56.060 N 150° 40' 28.032 W 6,700.0 77.78 3,037.9 -1,177.6 -4,976.1256.69 416,759.385,971,526.42 70° 19' 55.839 N 150° 40' 30.809 W 6,800.0 77.78 3,059.0 -1,200.1 -5,071.2256.69 416,664.055,971,504.91 70° 19' 55.617 N 150° 40' 33.585 W 6,900.0 77.78 3,080.2 -1,222.6 -5,166.3256.69 416,568.725,971,483.40 70° 19' 55.395 N 150° 40' 36.362 W 7,000.0 77.78 3,101.4 -1,245.1 -5,261.4256.69 416,473.405,971,461.90 70° 19' 55.173 N 150° 40' 39.139 W 7,100.0 77.78 3,122.6 -1,267.6 -5,356.5256.69 416,378.075,971,440.39 70° 19' 54.951 N 150° 40' 41.915 W 7,200.0 77.78 3,143.7 -1,290.1 -5,451.6256.69 416,282.745,971,418.88 70° 19' 54.729 N 150° 40' 44.692 W 7,235.3 77.78 3,151.2 -1,298.1 -5,485.2256.69 416,249.065,971,411.28 70° 19' 54.650 N 150° 40' 45.673 W Seabee 7,300.0 77.78 3,164.9 -1,312.6 -5,546.7256.69 416,187.415,971,397.37 70° 19' 54.507 N 150° 40' 47.468 W 7,400.0 77.78 3,186.1 -1,335.1 -5,641.8256.69 416,092.085,971,375.86 70° 19' 54.285 N 150° 40' 50.245 W 7,500.0 77.78 3,207.2 -1,357.6 -5,736.9256.69 415,996.765,971,354.36 70° 19' 54.063 N 150° 40' 53.021 W 7,600.0 77.78 3,228.4 -1,380.2 -5,832.0256.69 415,901.435,971,332.85 70° 19' 53.841 N 150° 40' 55.797 W 7,700.0 77.78 3,249.6 -1,402.7 -5,927.2256.69 415,806.105,971,311.34 70° 19' 53.619 N 150° 40' 58.574 W 7,800.0 77.78 3,270.8 -1,425.2 -6,022.3256.69 415,710.775,971,289.83 70° 19' 53.397 N 150° 41' 1.350 W 7,900.0 77.78 3,291.9 -1,447.7 -6,117.4256.69 415,615.445,971,268.33 70° 19' 53.174 N 150° 41' 4.127 W 8,000.0 77.78 3,313.1 -1,470.2 -6,212.5256.69 415,520.125,971,246.82 70° 19' 52.952 N 150° 41' 6.903 W 8,100.0 77.78 3,334.3 -1,492.7 -6,307.6256.69 415,424.795,971,225.31 70° 19' 52.730 N 150° 41' 9.679 W 8,200.0 77.78 3,355.4 -1,515.2 -6,402.7256.69 415,329.465,971,203.80 70° 19' 52.508 N 150° 41' 12.456 W 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 5 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 8,300.0 77.78 3,376.6 -1,537.7 -6,497.8256.69 415,234.135,971,182.29 70° 19' 52.286 N 150° 41' 15.232 W 8,400.0 77.78 3,397.8 -1,560.2 -6,592.9256.69 415,138.815,971,160.79 70° 19' 52.064 N 150° 41' 18.008 W 8,500.0 77.78 3,419.0 -1,582.7 -6,688.0256.69 415,043.485,971,139.28 70° 19' 51.842 N 150° 41' 20.785 W 8,600.0 77.78 3,440.1 -1,605.2 -6,783.1256.69 414,948.155,971,117.77 70° 19' 51.620 N 150° 41' 23.561 W 8,700.0 77.78 3,461.3 -1,627.7 -6,878.2256.69 414,852.825,971,096.26 70° 19' 51.397 N 150° 41' 26.337 W 8,726.7 77.78 3,467.0 -1,633.7 -6,903.7256.69 414,827.325,971,090.51 70° 19' 51.338 N 150° 41' 27.080 W Start DLS 2.50 TFO 98.29 8,732.9 77.78 3,468.3 -1,635.1 -6,909.5256.69 414,821.495,971,089.19 70° 19' 51.324 N 150° 41' 27.249 W Start DLS 2.50 TFO 97.65 8,733.0 77.78 3,468.3 -1,635.1 -6,909.6256.69 414,821.375,971,089.17 70° 19' 51.324 N 150° 41' 27.253 W 8,800.0 77.56 3,482.6 -1,649.2 -6,973.5258.39 414,757.325,971,075.71 70° 19' 51.185 N 150° 41' 29.119 W 8,900.0 77.25 3,504.4 -1,666.8 -7,069.5260.93 414,661.155,971,059.20 70° 19' 51.011 N 150° 41' 31.921 W 9,000.0 76.97 3,526.7 -1,680.0 -7,166.1263.48 414,564.455,971,046.98 70° 19' 50.880 N 150° 41' 34.740 W 9,100.0 76.72 3,549.5 -1,688.9 -7,263.0266.03 414,467.415,971,039.10 70° 19' 50.792 N 150° 41' 37.571 W 9,200.0 76.49 3,572.6 -1,693.4 -7,360.2268.59 414,370.225,971,035.55 70° 19' 50.746 N 150° 41' 40.408 W 9,300.0 76.28 3,596.2 -1,693.7 -7,457.4271.16 414,273.055,971,036.35 70° 19' 50.743 N 150° 41' 43.245 W 9,400.0 76.10 3,620.1 -1,689.5 -7,554.4273.72 414,176.095,971,041.49 70° 19' 50.783 N 150° 41' 46.078 W 9,500.0 75.95 3,644.2 -1,681.1 -7,651.1276.29 414,079.535,971,050.97 70° 19' 50.865 N 150° 41' 48.900 W 9,600.0 75.83 3,668.6 -1,668.3 -7,747.2278.87 413,983.565,971,064.77 70° 19' 50.990 N 150° 41' 51.707 W 9,700.0 75.73 3,693.2 -1,651.2 -7,842.6281.45 413,888.345,971,082.85 70° 19' 51.157 N 150° 41' 54.493 W 9,800.0 75.66 3,717.9 -1,629.8 -7,937.1284.03 413,794.075,971,105.20 70° 19' 51.366 N 150° 41' 57.253 W 9,900.0 75.62 3,742.7 -1,604.2 -8,030.5286.61 413,700.925,971,131.75 70° 19' 51.617 N 150° 41' 59.982 W 10,000.0 75.61 3,767.5 -1,574.5 -8,122.7289.19 413,609.085,971,162.47 70° 19' 51.909 N 150° 42' 2.674 W 10,100.0 75.62 3,792.4 -1,540.6 -8,213.4291.77 413,518.715,971,197.30 70° 19' 52.241 N 150° 42' 5.324 W 10,152.8 75.64 3,805.5 -1,521.0 -8,260.7293.13 413,471.635,971,217.33 70° 19' 52.433 N 150° 42' 6.705 W Nanushuk 10,200.0 75.67 3,817.1 -1,502.6 -8,302.6294.35 413,429.995,971,236.16 70° 19' 52.613 N 150° 42' 7.928 W 10,282.7 75.72 3,837.6 -1,468.2 -8,375.0296.48 413,357.945,971,271.33 70° 19' 52.951 N 150° 42' 10.043 W NT8 MFS 10,300.0 75.74 3,841.8 -1,460.7 -8,389.9296.93 413,343.085,971,278.99 70° 19' 53.025 N 150° 42' 10.480 W 10,366.2 75.80 3,858.1 -1,430.8 -8,446.7298.63 413,286.645,971,309.48 70° 19' 53.318 N 150° 42' 12.138 W NT7 MFS 10,400.0 75.84 3,866.4 -1,414.9 -8,475.3299.50 413,258.165,971,325.70 70° 19' 53.474 N 150° 42' 12.975 W 10,500.0 75.96 3,890.8 -1,365.2 -8,558.6302.08 413,175.385,971,376.21 70° 19' 53.962 N 150° 42' 15.409 W 10,600.0 76.12 3,914.9 -1,311.9 -8,639.7304.65 413,094.915,971,430.41 70° 19' 54.486 N 150° 42' 17.777 W 10,700.0 76.30 3,938.7 -1,254.9 -8,718.3307.22 413,016.895,971,488.21 70° 19' 55.045 N 150° 42' 20.075 W 10,722.6 76.34 3,944.1 -1,241.5 -8,735.7307.80 412,999.605,971,501.77 70° 19' 55.176 N 150° 42' 20.584 W NT6 MFS 10,800.0 76.50 3,962.3 -1,194.4 -8,794.4309.78 412,941.475,971,549.50 70° 19' 55.639 N 150° 42' 22.298 W 10,900.0 76.73 3,985.4 -1,130.5 -8,867.7312.34 412,868.805,971,614.15 70° 19' 56.267 N 150° 42' 24.442 W 10,918.6 76.78 3,989.7 -1,118.2 -8,881.1312.81 412,855.585,971,626.55 70° 19' 56.387 N 150° 42' 24.832 W NT5 MFS 11,000.0 76.99 4,008.1 -1,063.3 -8,938.2314.89 412,799.015,971,682.05 70° 19' 56.927 N 150° 42' 26.502 W 11,100.0 77.28 4,030.4 -993.0 -9,005.7317.44 412,732.255,971,753.06 70° 19' 57.617 N 150° 42' 28.476 W 11,117.9 77.33 4,034.4 -980.1 -9,017.5317.90 412,720.595,971,766.12 70° 19' 57.745 N 150° 42' 28.821 W NT4 MFS 11,200.0 77.58 4,052.2 -919.7 -9,070.1319.98 412,668.635,971,827.05 70° 19' 58.338 N 150° 42' 30.359 W 11,300.0 77.91 4,073.4 -843.5 -9,131.3322.52 412,608.275,971,903.89 70° 19' 59.087 N 150° 42' 32.147 W 11,400.0 78.27 4,094.0 -764.5 -9,189.1325.05 412,551.305,971,983.41 70° 19' 59.862 N 150° 42' 33.838 W 11,452.8 78.46 4,104.7 -721.8 -9,218.2326.38 412,522.625,972,026.42 70° 20' 0.282 N 150° 42' 34.690 W NT3 MFS 11,499.7 78.64 4,114.0 -683.3 -9,243.3327.56 412,497.985,972,065.21 70° 20' 0.661 N 150° 42' 35.423 W Start 221.7 hold at 11499.7 MD 11,500.0 78.64 4,114.1 -683.0 -9,243.4327.56 412,497.815,972,065.48 70° 20' 0.663 N 150° 42' 35.428 W 9-5/8" Intermediate Liner 11,582.9 78.64 4,130.4 -614.4 -9,287.1327.56 412,454.925,972,134.55 70° 20' 1.338 N 150° 42' 36.704 W NT3.2 Top Reservoir 11,600.0 78.64 4,133.8 -600.3 -9,296.0327.56 412,446.095,972,148.76 70° 20' 1.476 N 150° 42' 36.967 W 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 6 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 11,613.4 78.64 4,136.4 -589.2 -9,303.1327.56 412,439.165,972,159.92 70° 20' 1.585 N 150° 42' 37.173 W Start 150.0 hold at 11613.4 MD 11,700.0 78.64 4,153.5 -517.5 -9,348.6327.56 412,394.385,972,232.04 70° 20' 2.290 N 150° 42' 38.505 W 11,721.4 78.64 4,157.7 -499.8 -9,359.9327.56 412,383.315,972,249.86 70° 20' 2.463 N 150° 42' 38.834 W Start DLS 4.00 TFO 8.82 11,725.1 78.79 4,158.4 -496.8 -9,361.8327.59 412,381.415,972,252.92 70° 20' 2.493 N 150° 42' 38.891 W NT 3.24 11,763.4 80.30 4,165.3 -464.9 -9,381.9327.82 412,361.615,972,284.99 70° 20' 2.806 N 150° 42' 39.480 W Start Turn 0.00 11,800.0 81.75 4,171.1 -434.3 -9,401.1328.05 412,342.745,972,315.82 70° 20' 3.108 N 150° 42' 40.042 W 11,900.0 85.70 4,182.0 -349.7 -9,453.3328.66 412,291.495,972,400.96 70° 20' 3.939 N 150° 42' 41.567 W 12,000.0 89.66 4,186.0 -264.1 -9,504.8329.26 412,240.885,972,487.07 70° 20' 4.780 N 150° 42' 43.075 W 12,021.4 90.50 4,186.0 -245.7 -9,515.7329.39 412,230.145,972,505.61 70° 20' 4.961 N 150° 42' 43.395 W Start 5457.2 hold at 12021.4 MD 12,060.0 90.50 4,185.7 -212.5 -9,535.3329.39 412,210.865,972,538.99 70° 20' 5.287 N 150° 42' 43.969 W Start 5457.2 hold at 12060.0 MD 12,100.0 90.50 4,185.3 -178.0 -9,555.7329.39 412,190.855,972,573.64 70° 20' 5.626 N 150° 42' 44.566 W 12,200.0 90.50 4,184.4 -92.0 -9,606.6329.39 412,140.835,972,660.22 70° 20' 6.472 N 150° 42' 46.056 W 12,300.0 90.50 4,183.5 -5.9 -9,657.6329.39 412,090.825,972,746.80 70° 20' 7.317 N 150° 42' 47.546 W 12,400.0 90.50 4,182.7 80.2 -9,708.5329.39 412,040.815,972,833.39 70° 20' 8.163 N 150° 42' 49.036 W 12,500.0 90.50 4,181.8 166.2 -9,759.4329.39 411,990.805,972,919.97 70° 20' 9.009 N 150° 42' 50.526 W 12,600.0 90.50 4,180.9 252.3 -9,810.3329.39 411,940.795,973,006.55 70° 20' 9.855 N 150° 42' 52.016 W 12,700.0 90.50 4,180.0 338.3 -9,861.2329.39 411,890.785,973,093.13 70° 20' 10.700 N 150° 42' 53.507 W 12,729.5 90.50 4,179.8 363.7 -9,876.2329.39 411,876.045,973,118.65 70° 20' 10.950 N 150° 42' 53.946 W NT 3.23 12,800.0 90.50 4,179.2 424.4 -9,912.1329.39 411,840.775,973,179.71 70° 20' 11.546 N 150° 42' 54.997 W 12,900.0 90.50 4,178.3 510.5 -9,963.0329.39 411,790.765,973,266.29 70° 20' 12.392 N 150° 42' 56.487 W 13,000.0 90.50 4,177.4 596.5 -10,014.0329.39 411,740.755,973,352.88 70° 20' 13.238 N 150° 42' 57.978 W 13,100.0 90.50 4,176.5 682.6 -10,064.9329.39 411,690.745,973,439.46 70° 20' 14.083 N 150° 42' 59.468 W 13,200.0 90.50 4,175.6 768.7 -10,115.8329.39 411,640.735,973,526.04 70° 20' 14.929 N 150° 43' 0.958 W 13,300.0 90.50 4,174.8 854.7 -10,166.7329.39 411,590.735,973,612.62 70° 20' 15.775 N 150° 43' 2.449 W 13,400.0 90.50 4,173.9 940.8 -10,217.6329.39 411,540.725,973,699.20 70° 20' 16.621 N 150° 43' 3.939 W 13,500.0 90.50 4,173.0 1,026.9 -10,268.5329.39 411,490.715,973,785.79 70° 20' 17.466 N 150° 43' 5.430 W 13,600.0 90.50 4,172.1 1,112.9 -10,319.4329.39 411,440.705,973,872.37 70° 20' 18.312 N 150° 43' 6.920 W 13,700.0 90.50 4,171.2 1,199.0 -10,370.4329.39 411,390.695,973,958.95 70° 20' 19.158 N 150° 43' 8.411 W 13,800.0 90.50 4,170.4 1,285.0 -10,421.3329.39 411,340.695,974,045.54 70° 20' 20.004 N 150° 43' 9.901 W 13,900.0 90.50 4,169.5 1,371.1 -10,472.2329.39 411,290.685,974,132.12 70° 20' 20.849 N 150° 43' 11.392 W 14,000.0 90.50 4,168.6 1,457.2 -10,523.1329.39 411,240.675,974,218.70 70° 20' 21.695 N 150° 43' 12.882 W 14,100.0 90.50 4,167.7 1,543.2 -10,574.0329.39 411,190.675,974,305.29 70° 20' 22.541 N 150° 43' 14.373 W 14,200.0 90.50 4,166.8 1,629.3 -10,624.9329.39 411,140.665,974,391.87 70° 20' 23.387 N 150° 43' 15.864 W 14,300.0 90.50 4,166.0 1,715.4 -10,675.8329.39 411,090.655,974,478.45 70° 20' 24.232 N 150° 43' 17.354 W 14,400.0 90.50 4,165.1 1,801.4 -10,726.7329.39 411,040.655,974,565.04 70° 20' 25.078 N 150° 43' 18.845 W 14,500.0 90.50 4,164.2 1,887.5 -10,777.7329.39 410,990.645,974,651.62 70° 20' 25.924 N 150° 43' 20.336 W 14,600.0 90.50 4,163.3 1,973.6 -10,828.6329.39 410,940.645,974,738.21 70° 20' 26.770 N 150° 43' 21.827 W 14,700.0 90.50 4,162.4 2,059.6 -10,879.5329.39 410,890.635,974,824.79 70° 20' 27.615 N 150° 43' 23.317 W 14,800.0 90.50 4,161.6 2,145.7 -10,930.4329.39 410,840.635,974,911.38 70° 20' 28.461 N 150° 43' 24.808 W 14,900.0 90.50 4,160.7 2,231.8 -10,981.3329.39 410,790.625,974,997.96 70° 20' 29.307 N 150° 43' 26.299 W 15,000.0 90.50 4,159.8 2,317.8 -11,032.2329.40 410,740.625,975,084.54 70° 20' 30.152 N 150° 43' 27.790 W 15,100.0 90.50 4,158.9 2,403.9 -11,083.1329.40 410,690.625,975,171.13 70° 20' 30.998 N 150° 43' 29.281 W 15,200.0 90.50 4,158.0 2,490.0 -11,134.0329.40 410,640.615,975,257.72 70° 20' 31.844 N 150° 43' 30.772 W 15,300.0 90.50 4,157.2 2,576.0 -11,184.9329.40 410,590.615,975,344.30 70° 20' 32.690 N 150° 43' 32.263 W 15,400.0 90.50 4,156.3 2,662.1 -11,235.8329.40 410,540.615,975,430.89 70° 20' 33.535 N 150° 43' 33.754 W 15,500.0 90.50 4,155.4 2,748.2 -11,286.7329.40 410,490.605,975,517.47 70° 20' 34.381 N 150° 43' 35.245 W 15,600.0 90.50 4,154.5 2,834.2 -11,337.7329.40 410,440.605,975,604.06 70° 20' 35.227 N 150° 43' 36.736 W 15,700.0 90.50 4,153.6 2,920.3 -11,388.6329.40 410,390.605,975,690.64 70° 20' 36.072 N 150° 43' 38.227 W 15,800.0 90.50 4,152.8 3,006.4 -11,439.5329.40 410,340.605,975,777.23 70° 20' 36.918 N 150° 43' 39.718 W 15,900.0 90.50 4,151.9 3,092.4 -11,490.4329.40 410,290.595,975,863.82 70° 20' 37.764 N 150° 43' 41.209 W 16,000.0 90.50 4,151.0 3,178.5 -11,541.3329.40 410,240.595,975,950.40 70° 20' 38.609 N 150° 43' 42.700 W 16,100.0 90.50 4,150.1 3,264.6 -11,592.2329.40 410,190.595,976,036.99 70° 20' 39.455 N 150° 43' 44.191 W 16,200.0 90.50 4,149.2 3,350.6 -11,643.1329.40 410,140.595,976,123.58 70° 20' 40.301 N 150° 43' 45.682 W 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 7 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 16,300.0 90.50 4,148.4 3,436.7 -11,694.0329.40 410,090.595,976,210.16 70° 20' 41.147 N 150° 43' 47.174 W 16,400.0 90.50 4,147.5 3,522.8 -11,744.9329.40 410,040.595,976,296.75 70° 20' 41.992 N 150° 43' 48.665 W 16,500.0 90.50 4,146.6 3,608.8 -11,795.8329.40 409,990.595,976,383.34 70° 20' 42.838 N 150° 43' 50.156 W 16,600.0 90.50 4,145.7 3,694.9 -11,846.7329.40 409,940.595,976,469.92 70° 20' 43.684 N 150° 43' 51.647 W 16,700.0 90.50 4,144.8 3,781.0 -11,897.6329.40 409,890.595,976,556.51 70° 20' 44.529 N 150° 43' 53.139 W 16,800.0 90.50 4,144.0 3,867.1 -11,948.5329.40 409,840.595,976,643.10 70° 20' 45.375 N 150° 43' 54.630 W 16,900.0 90.50 4,143.1 3,953.1 -11,999.4329.40 409,790.595,976,729.69 70° 20' 46.221 N 150° 43' 56.121 W 17,000.0 90.50 4,142.2 4,039.2 -12,050.3329.40 409,740.595,976,816.27 70° 20' 47.066 N 150° 43' 57.613 W 17,100.0 90.50 4,141.3 4,125.3 -12,101.2329.40 409,690.595,976,902.86 70° 20' 47.912 N 150° 43' 59.104 W 17,200.0 90.50 4,140.5 4,211.3 -12,152.2329.40 409,640.595,976,989.45 70° 20' 48.758 N 150° 44' 0.596 W 17,300.0 90.50 4,139.6 4,297.4 -12,203.1329.40 409,590.595,977,076.04 70° 20' 49.603 N 150° 44' 2.087 W 17,400.0 90.50 4,138.7 4,383.5 -12,254.0329.40 409,540.605,977,162.63 70° 20' 50.449 N 150° 44' 3.579 W 17,478.6 90.50 4,138.0 4,451.1 -12,294.0329.40 409,501.285,977,230.71 70° 20' 51.114 N 150° 44' 4.752 W TD at 17478.6 Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Design Targets LongitudeLatitude Dip Angle (°) Dip Dir. (°) NDB-051 Rev 0.0 Toe 4,138.0 5,977,230.74 409,501.274,451.2 -12,294.00.00 0.00 70° 20' 51.114 N 150° 44' 4.752 W - plan hits target center - Point NDB-051 Rev 0.0 Hee 4,186.0 5,972,505.61 412,230.14-245.7 -9,515.70.00 0.00 70° 20' 4.961 N 150° 42' 43.395 W - plan hits target center - Polygon -317.3Point 1 5,972,188.83 412,182.144,186.0 -44.7 True -112.7Point 2 5,972,389.81 412,528.124,186.0 299.2 True 5,014.3Point 3 5,977,547.70 409,548.864,186.0 -2,734.0 True 4,809.6Point 4 5,977,346.62 409,202.884,186.0 -3,077.9 True Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing128.0128.0 20 20 13-3/8" Surface Casing2,289.93,167.0 13-3/8 16 9-5/8" Intermediate Liner4,114.111,500.0 9-5/8 12-1/4 4-1/2" x 8-1/2"Liner4,138.017,478.6 4-1/2 8-1/2 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 8 Planning Report -Geographic Well NDB-051Local Co-ordinate Reference:Database:EDM STO Alaska DF @ 70.0usftTVD Reference:Santos NAD27 ConversionCompany: DF @ 70.0usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDB-051Well: NDB-051Wellbore: Plan: NDB-051 Rev D.0Design: Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,056.4 Upper Schrader Bluff1,043.0 1,151.3 Base Ice Bearing Permafrost1,133.0 1,430.8 Base Permafrost Transition1,390.0 1,857.5 Middle Schrader Bluff1,737.0 2,571.5 MCU2,140.0 3,890.4 Tuluvak Shale2,443.1 4,169.2 Tuluvak Sand2,502.1 7,235.3 Seabee3,151.2 10,152.8 Nanushuk3,805.5 10,282.7 NT8 MFS3,837.6 10,366.2 NT7 MFS3,858.1 10,722.6 NT6 MFS3,944.1 10,918.6 NT5 MFS3,989.7 11,117.9 NT4 MFS4,034.4 11,452.8 NT3 MFS4,104.7 11,582.9 NT3.2 Top Reservoir4,130.4 11,725.1 NT 3.244,158.4 12,729.5 NT 3.234,179.8 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 347.0 347.0 0.0 0.0 Start Build 2.50 547.0 546.7 -2.0 -8.5 Start Build 2.57 587.0 586.6 -2.9 -12.2 Start Build 3.00 1,000.6 990.0 -23.0 -97.1 Start 159.0 hold at 1000.6 MD 1,158.8 1,140.1 -34.5 -145.7 Start DLS 3.50 TFO -21.82 1,159.6 1,140.9 -34.6 -145.9 Start DLS 3.50 TFO 0.03 2,856.1 2,224.1 -312.6 -1,320.2 Start 5876.8 hold at 2856.1 MD 2,920.2 2,237.6 -327.0 -1,381.3 Start 5806.5 hold at 2920.2 MD 8,726.7 3,467.0 -1,633.7 -6,903.7 Start DLS 2.50 TFO 98.29 8,732.9 3,468.3 -1,635.1 -6,909.5 Start DLS 2.50 TFO 97.65 11,499.7 4,114.0 -683.3 -9,243.3 Start 221.7 hold at 11499.7 MD 11,613.4 4,136.4 -589.2 -9,303.1 Start 150.0 hold at 11613.4 MD 11,721.4 4,157.7 -499.8 -9,359.9 Start DLS 4.00 TFO 8.82 11,763.4 4,165.3 -464.9 -9,381.9 Start Turn 0.00 12,021.4 4,186.0 -245.7 -9,515.7 Start 5457.2 hold at 12021.4 MD 12,060.0 4,185.7 -212.5 -9,535.3 Start 5457.2 hold at 12060.0 MD 17,478.6 4,138.0 4,451.1 -12,294.0 TD at 17478.6 17,517.2 TD at 17517.2 8/02/2024 3:31:04PM COMPASS 5000.17 Build 02 Page 9 -3000 -1500 0 1500 3000 4500 6000 So u t h ( - ) / N o r t h ( + ) -12000 -10500 -9000 -7500 -6000 -4500 -3000 -1500 0 West(-)/East(+) NDB-051 Rev 0.0 Heel 95% NDB-051 Rev 0.0 Toe 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" x 8-1/2"Liner Plan: N D B-051 R e v D . 0 Plan: NDB-051 Rev D.0 14:54, February 08 2024 -1500 0 1500 3000 4500 6000 Tr u e V e r t i c a l D e p t h 0 2000 4000 6000 8000 10000 12000 14000 16000 Vertical Section at 289.90° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" x 8-1/2"Liner 1000 200 0 3000 40 0 0 50 0 0 6000 70 00 80 0 0 9000 10 0 0 0 11 0 0 0 120 00 13 000 14 0 0 0 15 000 16 0 0 0 17 000 17 4 7 9 0° 3 0 ° 60° 78 ° 79 ° 90 ° 91 ° Pl a n : N D B -051 Rev D.0 Upper Schrader Bluff Base Ice Bearing Permafrost Base Permafrost Transition Middle Schrader Bluff MCU Tuluvak Shale Tuluvak Sand Seabee Nanushuk NT8 MFS NT7 MFS NT6 MFS NT5 MFS NT4 MFS NT3 MFS NT3.2 Top Reservoir NT 3.24 NT 3.23 Plan: NDB-051 Rev D.0 14:55, February 08 2024 08 February, 2024 Anticollision Summary Report Santos Pikka NDB NDB-051 NDB-051 Plan: NDB-051 Rev D.0 Anticollision Summary Report Well NDB-051 -Slot B-51Local Co-ordinate Reference:SantosCompany: DF @ 70.0usftTVD Reference:PikkaProject: DF @ 70.0usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDB-051Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-051 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDB-051 Rev D.0 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Combined Pedal Curve GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.0usft Unlimited Maximum centre distance of 1,943.2usft Plan: NDB-051 Rev D.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 8/02/2024 SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)47.0 300.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag300.0 1,500.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag300.0 3,167.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag3,167.0 4,367.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag3,167.0 5,000.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+Sag A002Mb/ISC4: BGGM dec + sag corrections5,000.0 5,500.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag5,500.0 6,700.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag5,500.0 11,500.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag11,500.0 12,700.0 Plan: NDB-051 Rev D.0 (NDB-051) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,500.0 17,478.6 Plan: NDB-051 Rev D.0 (NDB-051) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB Caution - Monitor CloselyNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 11,269.4 18,700.5 143.1 1.0 1.263 Stop Drilling, SFNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 11,350.0 18,700.5 164.6 -66.8 0.888 Stop Drilling, ESNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 11,375.0 18,700.5 178.5 -71.8 0.891 CCNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 2,671.0 3,365.0 472.6 416.5 11.012 ESNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 2,725.0 3,418.0 473.3 415.1 10.619 SFNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 8,850.0 9,484.0 1,164.2 882.7 5.208 CCNDB-039 - NDB-039 - Plan: NDB-039 Rev A.0 325.0 325.0 240.4 231.3 48.878 Normal Operations, ES, SNDB-039 - NDB-039 - Plan: NDB-039 Rev A.0 17,478.6 14,980.8 282.7 55.0 1.557 CCNDB-040 - NDB-040 - Plan: NDB-040 Rev A.0 325.0 325.0 220.3 211.3 44.761 ESNDB-040 - NDB-040 - Plan: NDB-040 Rev A.0 350.0 350.0 220.3 211.2 44.369 SFNDB-040 - NDB-040 - Plan: NDB-040 Rev A.0 4,300.0 4,499.5 901.9 778.0 9.268 CCNDB-045 - NDB-045 - Plan: NDB-045 Rev A.0 325.0 325.0 120.1 111.1 24.185 ESNDB-045 - NDB-045 - Plan: NDB-045 Rev A.0 350.0 350.0 120.1 111.0 23.972 SFNDB-045 - NDB-045 - Plan: NDB-045 Rev A.0 4,300.0 4,486.1 657.2 533.4 6.753 CCNDB-048 - NDB-048 - NDB-048 Rev A.0 325.0 325.0 60.1 51.1 11.820 ESNDB-048 - NDB-048 - NDB-048 Rev A.0 350.0 350.0 60.1 51.1 11.742 Normal Operations, SFNDB-048 - NDB-048 - NDB-048 Rev A.0 9,675.0 9,856.6 344.6 84.6 1.663 CC, ESNDBi-014 - NDBi-014 - NDBi-014 357.9 361.2 741.1 732.1 152.590 SFNDBi-014 - NDBi-014 - NDBi-014 12,125.0 15,409.0 1,808.6 1,582.1 10.065 CCNDBi-014 - NDBi-014 - Plan: NDBi-014 Rev D.0 325.0 324.8 741.2 732.3 153.154 ESNDBi-014 - NDBi-014 - Plan: NDBi-014 Rev D.0 350.0 349.8 741.2 732.3 152.575 SFNDBi-014 - NDBi-014 - Plan: NDBi-014 Rev D.0 12,123.5 15,418.0 1,801.8 1,573.1 9.931 CCNDBi-038 - NDBi-038 - NDBi-038 Rev A.0 325.0 325.0 260.3 251.3 52.974 ESNDBi-038 - NDBi-038 - NDBi-038 Rev A.0 350.0 350.0 260.3 251.2 52.510 SFNDBi-038 - NDBi-038 - NDBi-038 Rev A.0 4,300.0 4,522.9 960.0 834.2 9.717 CCNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 325.0 325.0 200.3 191.2 40.651 ESNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 350.0 350.0 200.3 191.2 40.293 SFNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 15,575.0 13,517.2 767.0 441.2 2.955 CC, ESNDBi-043 - NDBi-043 - NDBi-043 50.0 49.4 161.4 152.3 34.394 SFNDBi-043 - NDBi-043 - NDBi-043 2,325.0 2,528.3 421.0 390.1 18.566 CC, ESNDBi-043 - NDBi-043A - NDBi-043A 50.0 49.4 161.4 152.3 34.394 SFNDBi-043 - NDBi-043A - NDBi-043A 2,325.0 2,528.3 421.0 390.1 18.566 CC, ESNDBi-044 - NDBi-044 - NDBi-044 361.0 361.5 140.8 131.9 28.596 8/02/2024 2:43:24PM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 2 Anticollision Summary Report Well NDB-051 -Slot B-51Local Co-ordinate Reference:SantosCompany: DF @ 70.0usftTVD Reference:PikkaProject: DF @ 70.0usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDB-051Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-051 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDB-051 Rev D.0 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB SFNDBi-044 - NDBi-044 - NDBi-044 17,478.6 15,295.4 1,799.9 1,412.3 5.831 CCNDBi-046 - NDBi-046 - Plan: NDBi-046 Rev D.0 325.0 325.0 101.5 92.6 20.794 ESNDBi-046 - NDBi-046 - Plan: NDBi-046 Rev D.0 350.0 350.0 101.5 92.6 20.701 Normal Operations, SFNDBi-046 - NDBi-046 - Plan: NDBi-046 Rev D.0 11,225.0 11,064.2 451.1 162.8 1.964 CCNDBi-046 - NDBi-046A - NDBi-046A Rev B.0 325.0 325.0 101.5 92.4 20.076 ESNDBi-046 - NDBi-046A - NDBi-046A Rev B.0 350.0 350.0 101.5 92.4 19.912 Normal Operations, SFNDBi-046 - NDBi-046A - NDBi-046A Rev B.0 11,250.0 11,127.0 430.1 112.3 1.697 CCNDBi-049 - NDBi-049 - Plan: NDBi-049 Rev E.0 325.0 325.0 41.3 32.2 7.895 ESNDBi-049 - NDBi-049 - Plan: NDBi-049 Rev E.0 350.0 350.0 41.3 32.2 7.839 SFNDBi-049 - NDBi-049 - Plan: NDBi-049 Rev E.0 6,600.0 6,718.9 812.2 604.3 4.931 CCNDBi-050 - NDBi-050 - Plan: NDBi-050 Rev A.0 325.0 325.0 20.0 11.0 3.621 ESNDBi-050 - NDBi-050 - Plan: NDBi-050 Rev A.0 350.0 350.0 20.0 10.9 3.590 Caution - Monitor CloselyNDBi-050 - NDBi-050 - Plan: NDBi-050 Rev A.0 4,300.0 4,426.3 121.0 15.4 1.442 Qugruk 3 Take Immediate Action, SQugruk 3 - Qugruk 3 - Qugruk 3 10,875.0 4,084.0 202.4 -3.9 1.229 Take Immediate Action, EQugruk 3 - Qugruk 3 - Qugruk 3 10,900.0 4,083.1 193.0 -3.1 1.233 Normal Operations, CCQugruk 3 - Qugruk 3 - Qugruk 3 10,968.0 4,080.5 181.6 31.5 1.521 SFQugruk 3 - Quguruk 3A - Quguruk 3A 11,600.0 3,880.9 632.1 450.7 4.396 ESQugruk 3 - Quguruk 3A - Quguruk 3A 12,100.0 4,227.9 550.5 409.5 4.940 CCQugruk 3 - Quguruk 3A - Quguruk 3A 12,192.0 4,299.2 547.8 412.8 5.134 SFQugruk 301 - Qugruk 301 - Qugruk 301 11,300.0 3,569.0 992.1 800.0 6.530 ESQugruk 301 - Qugruk 301 - Qugruk 301 11,675.0 3,692.0 905.9 749.3 7.326 CCQugruk 301 - Qugruk 301 - Qugruk 301 11,884.7 3,760.8 896.2 769.0 8.956 Wildcat Take Immediate Action, SQugruk-3 - Qugruk-3 - Qugruk-3 10,900.0 4,084.9 179.2 -28.8 1.078 Take Immediate Action, EQugruk-3 - Qugruk-3 - Qugruk-3 10,925.0 4,084.3 169.6 -27.0 1.079 Caution - Monitor CloselyQugruk-3 - Qugruk-3 - Qugruk-3 10,984.6 4,082.5 159.5 8.8 1.328 SFQugruk-3 - Qugruk-3A - Qugruk -3A 11,625.0 3,897.0 624.8 443.9 4.357 ESQugruk-3 - Qugruk-3A - Qugruk -3A 12,075.0 4,213.3 551.5 401.5 4.647 CCQugruk-3 - Qugruk-3A - Qugruk -3A 12,191.8 4,299.5 547.1 403.7 4.824 SFQugruk-301 - Qugruk-301 - Qugruk-301 11,300.0 3,569.0 992.1 800.4 6.543 ESQugruk-301 - Qugruk-301 - Qugruk-301 11,675.0 3,692.0 905.9 749.8 7.351 CCQugruk-301 - Qugruk-301 - Qugruk-301 11,884.7 3,760.8 896.1 769.7 9.008 8/02/2024 2:43:24PM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 3 Anticollision Summary Report Well NDB-051 -Slot B-51Local Co-ordinate Reference:SantosCompany: DF @ 70.0usftTVD Reference:PikkaProject: DF @ 70.0usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDB-051Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-051 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDB-051 Rev D.0 Offset TVD Reference: 0 500 1000 1500 2000 Ce n t r e t o C e n t r e S e p a r a t i o n 0 3000 6000 9000 12000 15000 18000 Measured Depth Ladder Plot Qugruk-3, Qugruk-3, Qugruk-3 V0 Qugruk-3, Qugruk-3A, Qugruk-3A V0 Qugruk-301, Qugruk-301, Qugruk-301 V0 NDB-040, NDB-040, Plan: NDB-040 Rev A.0 V0 NDB-011, NDB-011, Plan: NDB-011 Rev A.0 V0 NDBi-046, NDBi-046A, NDBi-046A Rev B.0 V0 NDBi-046, NDBi-046, Plan: NDBi-046 Rev D.0 V0 NDB-021, NDB-021, Plan: NDB-021 Rev A.0 V0 NDB-045, NDB-045, Plan: NDB-045 Rev A.0 V0 NDBi-014, NDBi-014, Plan: NDBi-014 Rev D.0 V0 NDBi-038, NDBi-038, NDBi-038 Rev A.0 V0 NDBi-050, NDBi-050, Plan: NDBi-050 Rev A.0 V0 NDBi-041, NDBi-041, Plan: NDBi-041 Rev A.0 V0 NDB-039, NDB-039, Plan: NDB-039 Rev A.0 V0 NDBi-049, NDBi-049, Plan: NDBi-049 Rev E.0 V0 NDBi-043, NDBi-043, NDBi-043 V0 NDBi-043, NDBi-043A, NDBi-043A V0 NDBi-044, NDBi-044, NDBi-044 V0 NDBi-014, NDBi-014, NDBi-014 V0 Qugruk 301, Qugruk 301, Qugruk 301 V0 Qugruk 3, Qugruk 3, Qugruk 3 V0 Qugruk 3, Quguruk 3A, Quguruk 3A V0 NDB-048, NDB-048, NDB-048 Rev A.0 V0 L E G E N D Coordinates are relative to: NDB-051 - Slot B-51 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to DF @ 70.0usft 8/02/2024 2:43:24PM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 4 Anticollision Summary Report Well NDB-051 -Slot B-51Local Co-ordinate Reference:SantosCompany: DF @ 70.0usftTVD Reference:PikkaProject: DF @ 70.0usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDB-051Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-051 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDB-051 Rev D.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 Se p a r a t i o n F a c t o r 0 3000 6000 9000 12000 15000 18000 Measured Depth Stop Drilling Caution - Monitor Closely Normal Operations Separation Factor Plot Qugruk-3, Qugruk-3, Qugruk-3 V0 Qugruk-3, Qugruk-3A, Qugruk-3A V0 Qugruk-301, Qugruk-301, Qugruk-301 V0 NDB-040, NDB-040, Plan: NDB-040 Rev A.0 V0 NDB-011, NDB-011, Plan: NDB-011 Rev A.0 V0 NDBi-046, NDBi-046A, NDBi-046A Rev B.0 V0 NDBi-046, NDBi-046, Plan: NDBi-046 Rev D.0 V0 NDB-021, NDB-021, Plan: NDB-021 Rev A.0 V0 NDB-045, NDB-045, Plan: NDB-045 Rev A.0 V0 NDBi-014, NDBi-014, Plan: NDBi-014 Rev D.0 V0 NDBi-038, NDBi-038, NDBi-038 Rev A.0 V0 NDBi-050, NDBi-050, Plan: NDBi-050 Rev A.0 V0 NDBi-041, NDBi-041, Plan: NDBi-041 Rev A.0 V0 NDB-039, NDB-039, Plan: NDB-039 Rev A.0 V0 NDBi-049, NDBi-049, Plan: NDBi-049 Rev E.0 V0 NDBi-043, NDBi-043, NDBi-043 V0 NDBi-043, NDBi-043A, NDBi-043A V0 NDBi-044, NDBi-044, NDBi-044 V0 NDBi-014, NDBi-014, NDBi-014 V0 Qugruk 301, Qugruk 301, Qugruk 301 V0 Qugruk 3, Qugruk 3, Qugruk 3 V0 Qugruk 3, Quguruk 3A, Quguruk 3A V0 NDB-048, NDB-048, NDB-048 Rev A.0 V0 L E G E N D Coordinates are relative to: NDB-051 - Slot B-51 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to DF @ 70.0usft 8/02/2024 2:43:24PM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 No r t h i n g ( 4 0 0 0 u s f t / i n ) Easting (4000 usft/in) No r t h i n g ( 4 0 0 0 u s f t / i n ) Easting (4000 usft/in) Qugruk-3 Qugruk-3A Qugruk-301 Plan: NDB-040 Rev A.0 Plan: NDB-011 Rev A.0 NDBi-046A Rev B.0 Plan: NDBi-046 Rev D.0 Plan: NDB-021 Rev A.0 Plan: NDB-045 Rev A.0 Plan: NDBi-014 Rev D.0 NDBi-038 Rev A.0 Plan: NDBi-050 Rev A.0 Plan: NDBi-041 Rev A.0 Plan: NDB-039 Rev A.0 Plan: NDBi-049 Rev E.0 NDBi-043 NDBi-043A NDBi-044 NDBi-014 Qugruk 301 Qugruk 3 Quguruk 3A NDB-048 Rev A.0 1 0 0 0 2 0 0 03 0 0 0 Plan: NDB-051 Rev D.0 NDB NPF 14:58, February 08 2024 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 50 50 100 100 150 150 200 200 250 250 300 300 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in] 10999 10997 10996 10995 10994 10992 10991 10990 10989 10988 10987 10986 10985 10984 10983 10982 10981 10979 10977 10975 10973 10971 10969 10967 10966 Qugruk-3 7075100125150175200225250275300325350373395418441464486509531554577600621643665687709731753775796818840862884905927950971992101610401065109011141139116311841205122512481269129013111332135313751396141714381459148115021523154415651587160816291650167116931714173517561778Plan: NDB-040 Rev A.0 1073710758107791080010821108421086310885109061092810950109721099411016110391106111084111071113011153111761119911222112461126911269Plan: NDB-011 Rev A.0 47507510012515017520022525027530032535037439842244646949351754156558961263665968370673075377680082384686989291593896198410071032105610811105113011541177120012221244126712891311133313561378140014221445146714891511153315551577160016221644166616881710173217541775179818201842186418861908193019531975199720192041 11511 11518 11524 11531 11537 11542 11547 11552 11556 11560 11563NDBi-046A Rev B.0 475075100125150175200225250275300325350374398422446469493517541565589612636659683706730753776800823846869892915938961984100710321056108111051130115411771200122212441267128913111334135613781400142314451468149015121534155715791601162416461668169017131735175717801802182518471869189219141937195919812004202720492072209421172140 11517 11523 11530 11535 11541 11546 11551 11555 11559Plan: NDBi-046 Rev D.0 7075100125150175200225250275300325350374 39742144546849251653956358660963265567870172574777079381683986288490793095397599810231047107210971121114611701192121412371259128113041325134813711393141514381460148215041527155015711594161616381660168317051727175017721794181618391861188319051928195019721994201720392061208321062128215021722194221722392261Plan: NDB-045 Rev A.0 7075100125150175200225250275300325350372395417439462484506529550573595617638660681703725746767789810832853875896917939960981100310271052107711011126115011731193121412351255127512971318133813591380140014211442146314841504152515461567NDBi-038 Rev A.0 707510012515017520022525027530032535037540042444947449852354757259662164566969471874276679181583986388791293696098410081033105810831108113311581182120612301254127813021326134913731397142114451469149315171541156515891613163716611685170917331757178018041828185218761900192319471971199520182042 20662089211321372160218422072231225422782301232523482371239524182441246524882511253425572580260326272650267226952718274127642787281028322855288029052929295429793004302930543079310431293153317832033228325332773302332733523377340134263451347635013525355035753600362536493674369937243749377337983823384838733897392239473972399740214046407140964121414541704195422042454269429443194344436943934418444344684493451745424567459246174641466646914716474147654790481548404865488949144939496449895013503850635088511351375162518752125237526152865311533653615385541054355460548555095534555955845609563356585683570857335757578258075832585758815906593159565981600560306055608061056129615461796204622962536278630363286353637764026427645264776501652665516576Plan: NDBi-050 Rev A.0 70751001251501752002252502753003253503733964194424654875105335565786006236456676907127347567788008228448668889099319539759961020104510691094111811421166118712081229125012711292131313341355137513971418143914601481150215231544Plan: NDBi-041 Rev A.0 7075100125150175200225250275300325350372395418440463485508530552575597619640662684706727750770792813835856877900920941962984100510291054107811021126115011721192121212331253 173641738717410174331745617479Plan: NDB-039 Rev A.0 475075100125150175200225250275300325350375399424448473 497522546571595620644668693717741766790814839863887911936960984100810331058108311081133115811821206123012541278130213261350137413971421144514691492151615391563158616101633165716801703172717501773179618191842186518881911193419571980200320252048207120932116213821612183220622282250227322952317233923612384240624282450247124932515253725592580260226252645266726882710273127532775279528172838286028842909Plan: NDBi-049 Rev E.0 475176101126151176201226251276301326350374397420444467490513 537560583606628650673695717739761783805827850871892914936958980100210261051107511001125114911721193121512361257127813001320134113621383140414251447146814891510153115501573159416151635165616771700NDBi-043 475176101126151176201226251276301326350374397420444467490513 537560583606628650673695717739761783805827850871892914936958980100210261051107511001125114911721193121512361257127813001320134113621383140414251447146814891510153115501573159416151635165616771700NDBi-043A 475075100125150175200225250275300325350374397421444468491515538561585608630653676699722744767789812834857879901924946968990101310371061108611101135115911801202122312441265128613071328135013701391141214321453147514941514NDBi-044 10983 10982 10980 10979 10978 10976 10975 10973 10972 10971 10969 10968 10967 10966 10965 10963 10961 10959 10957 10954 10952 10950 10948 10946Qugruk 3 475075100125150175200225250275300325350374399423447472496520544568592616640664687711734758782805829852875899922946969992101610411066109111161141116511881211123412571280130313261349137213951418144114641487151015331556157816011625164716701693171617381761178418071830185218751898192119431966198920112034205720792102212521472170219222152237226022822305232723502372239424172439246224842506252925502573259526182640266226842706272827502773279528172839286128862911293629612986301130363061308631113136316131863211323632613286331033353360338534103435346034853510353535603585361036353660368437093734375937843809383438593884390939343959398440094034405940834108413341584183420842334258428343084333435843834408443344584482450745324557458246074632465746824707473247574782480748324856488149064931495649815006503150565081510651315156518152065231525552805305533053555380540554305455548055055530555555805605563056545679570457295754577958045829585458795904592959545979600460286053607861036128615361786203622862536278630363286353637864036427645264776502 96969721974697729796982198459869989399179940996399861000910031 100531007510096 10117 10138 10159 10180 10200 10220 10240 10259 10278 10297 10316 10335 10353 10371NDB-048 Rev A.0 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 47.0 To 17478.6 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 7075100125150175200225250275300325350375400424449474 498 523 547 572 596 621 645 669 694 718 742 766 791 815 839 863 Plan: NDBi-050 Rev A.0 475075100125150175200225250275300325350375399424448473 497522546571595620644668693717741766790814839863887911936960984 Plan: NDBi-049 Rev E.0 475075100125150175200225250275300325350374399423447472496520544 NDB-048 Rev A.0 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 47.0 To 1000.0 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 9119369609841008103310581083110811331158118212061230 Plan: NDBi-049 Rev E.0 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 900.0 To 3200.0 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 3100.0 To 4200.0 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 4100.0 To 11000.0 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 10900.0 To 11600.0 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 Plan: NDB-051 Rev D.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 SDI_URSA1_I4 300.0 1500.0 3_MWD+IFR2+Sag 300.0 3167.0 3_MWD+IFR2+MS+Sag 3167.0 4367.0 3_MWD+IFR2+Sag 3167.0 5000.0 3_MWD+IFR2+MS+Sag 5000.0 5500.0 3_MWD+Sag 5500.0 6700.0 3_MWD+IFR2+Sag 5500.0 11500.0 3_MWD+IFR2+MS+Sag 11500.0 12700.0 3_MWD+IFR2+Sag 11500.0 17478.6 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2289.9 3167.0 13-3/8" Surface Casing 4114.1 11500.0 9-5/8" Intermediate Liner 4138.0 17478.6 4-1/2" x 8-1/2"Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 2500 From Colour To MD 11400.0 To 17478.6 MD Azi TFace 47.0 0.00 0.00 347.0 0.00 0.00 587.0 256.66 256.66 1000.6 256.66 0.00 1159.6 256.66 0.00 2856.1 256.68 0.03 8732.9 256.68 0.00 11499.7 327.56 97.65 11721.4 327.56 0.00 12021.4 329.39 8.82 17478.6 329.39 0.00 At t a c h m e n t 3 : B O P E E q u i p m e n t 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 Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (trained drilling personnel). 12-1/4” Intermediate Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. 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. Hole Cleaning in 78q Sail Conduct hydraulics modeling and control ROP limits based on cuttings returns and observed ECD’s compared to model. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Close Approach Qugruk 3 NDB-051 fails anti-co llision to Qugruk 3 in the intermediate hole. Qugruk 3 has been fully abandoned with multiple cement plugs in accordance with AOGCC regulations and does not pose an HSE risk. Ensure sufficient mud is on location if a collision were to occur. Wireline Inaccessibility The sail angle on this section is too high for wireline to be run conventionally. If wireline logs are required for operations a Note presence of shallow gas in Tuluvak (as described in Section 4) with expected pressures of 10.2 ppg EMW. -A.Dewhurst 01MAR24 tractor will be required. Operational complexity with Mechanical two stage cement equipment The 2nd stage of the cement job will be conducted through a mechanically shifted sleeve. This will require the LTP to not be set until the 2nd stage is pumped giving a higher complexity leading to complications with setting the LTP. 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 BTC Surface Casing Basis Lead Open hole volume + 250% excess in permafrost / 50% excess below permafrost Lead TOC Surface Tail Open hole volume + 50% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Tuned Spacer Lead 11.0ppg Lead: 496 bbls, 2785 cuft, 1101 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 69 bbls, 387 cuft, 312 sks HalCem Type I/II – 1.24 cuft/sk Temp BHST 53° F Verification Method Cement returns to surface Notes Job will be mixed on the fly NDB-051 13-3/8" SURFACE CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 3082 3167 85 0.14973 12.7 TAIL LENGTH 2667 3167 500 0.07491 37.5 TAIL EXCESS 50% 18.7 LEAD TOP TO BASE OF PERMA 1430 2667 1237 0.07491 92.7 EXCESS FACTOR FOR ABOVE 50% 46.3 PERMAFROST ANNULUS (Lead) 128 1430 1302 0.07491 97.5 EXCESS FACTOR FOR ABOVE 250% 243.8 CASED HOLE ANNULUS 46 128 82 0.18620 15.3 Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume Lead TOC Stage 1: 250’ TVD above top Nanushuk Stage 2: N/A Tail Open hole volume + 85 ft shoe track Tail TOC Stage 1: 1000 ft above casing shoe Stage 2: Top of the 9-5/8” Liner Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead Stage 1: 30% Open Hole Excess 13.0ppg Lead: 101bbls, 567cuft, 308sks ExtendaCem, Yield: 1.84 cuft/sk Stage 2: N/A Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 79bbls, 444cuft, 358sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 100% Open Hole Excess Verified cement calcs. -bjm Verified cement calcs. -bjm 15.3ppg Tail: 292bbls, 1639cuft, 1322sks VersaCem Type I/II – 1.24 cuft/sk Temp BHST 94° F Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1 st Stage Cement Job Only. -2ndStage Cement Job will not be logged, assuming job parameters are as expected (No losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) -2ndStage bond evaluation does not affect 1 st Stage bond evaluation and frac decision. - Logging of 1 st Stage cement will demonstrate isolation of injection fluids in the Nanushuk reservoir, as well as isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -2ndStage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1 st stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. NDB-051 9.625" Production Liner - 1st Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME Shoe track length 11415 11500 85 0.07321 6.2 TAIL LENGTH 10500 11500 1000 0.05578 55.8 TAIL EXCESS 30% 16.7 LEAD LENGTH 9100 10500 1400 0.05578 78.1 LEAD EXCESS 30% 23.4 NDB-051 9.625" Production Liner - 2nd Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME TAIL LENGTH 3167 5708 2541 0.05578 141.7 TAIL EXCESS 100% 141.7 Liner Lap 13-3/8" 68# x 9-5/8" 47# LNR 3017 3167 150 0.05974 9.0 LWD Sonic will be used to log the 1st Stage Cement Job Only Attachment 7: Prognosed Formation Tops NDB-051 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1056 1043 973 100 7.2 Permafrost Base Transition 1430 1390 1320 100 7.3 Middle Schrader Bluff 1857 1737 1667 100 7.6 MCU (Lower Schrader Bluff) 2571 2140 2070 100 7.8 Tuluvak Shale 3890 2443 2373 100 7.9 Tuluvak Sand 4167 2502 2432 100 10.2 TS 790 5658 2817 2747 100 9.4 Seabee 7235 3151 3081 100 9.2 Nanushuk 10152 3805 3735 100 8.9 NT6 MFS 10722 3944 3874 100 8.9 NT5 MFS 10918 3990 3920 100 8.8 NT4 MFS 11118 4034 3964 100 8.8 NT3 MFS 11453 4104 4034 100 8.8 Nanushuk 3.2 (NT3) 11583 4130 4060 100 8.8 Attachment 8: Well Schematic Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole LWD Gamma Ray Resistivity 8-1/2” Production Hole LWD Gamma Ray Resistivity Sonic (9-5/8” Liner Cement Evaluation Only) Density Neutron Mudlogging No mudlogging is planned for NDB-051 Attachment 10: Wellhead & Tree Diagram Attachment 11: Tuluvak Isolation Significant Hydrocarbon Cross Section CONFIDENTIAL PURSUANT TO 20 AAC 25.537(b) Definition of Significant Hydrocarbon Distribution within the Tuluvak Fm Santos (Q)Lf5'5Z 3w UZ O11NtlOsand IVIIN301ANOO Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PIKKA NANUSHUK OIL POOL X Pikka NDB-051 224-013 WELL PERMIT CHECKLIST Company Oil Search (Alaska), LLC Well Name:PIKKA NDB-051 Initial Class/Type DEV / PEND GeoArea 890 Unit 11580 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2240130 PIKKA, NANUSHUK OIL - 600100 NA1 Permit fee attached Yes ADL392984, ADL391445, ADL393021, ADL393019, and ADL3929912 Lease number appropriate Yes3 Unique well name and number Yes PIKKA, NANUSHUK OIL - 600100 - governed by 8074 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary NA6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For serv NA15 All wells within 1/4 mile area of review identified (For service well only) NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only) NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) Yes18 Conductor string provided Yes19 Surface casing protects all known USDWs Yes20 CMT vol adequate to circulate on conductor & surf csg Yes21 CMT vol adequate to tie-in long string to surf csg Yes Variance approved for cement gap between hydrocarbon zones in Intermediate liner.22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit NA25 If a re-drill, has a 10-403 for abandonment been approved Yes Close approach with P&A'd well. Mitigations are appropriate for low risk collision.26 Adequate wellbore separation proposed Yes27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP = 1467 psi. BOP rated to 5K psi. (BOP test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments) Yes31 Choke manifold complies w/API RP-53 (May 84) Yes32 Work will occur without operation shutdown No33 Is presence of H2S gas probable NA34 Mechanical condition of wells within AOR verified (For service well only) Yes H2S has not been encountered at nearby offset wells and is not anticipated in this well35 Permit can be issued w/o hydrogen sulfide measures Yes Tuluvak (with shallow gas) pressures anticipated to be 10.2 ppg EMW. Nanushuk reservoir at 8.9 ppg EMW.36 Data presented on potential overpressure zones NA37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr ADD Date 3/1/2024 Appr BJM Date 3/15/2024 Appr ADD Date 3/1/2024 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date JLC 3/18/2024
