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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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 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 , M U D L O G S , C B L 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 10 / 1 2 / 2 0 2 3 24 0 0 5 8 4 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : AC E _ S A N T O S _ N D B - 03 2 _ 1 2 S E P 2 0 2 3 _ v 2 _ L A S . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B - 03 2 _ A P _ R 0 1 _ R M _ 2 0 2 3 0 8 2 1 . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B - 03 2 _ A P _ R 0 2 _ R M _ 2 0 2 3 0 8 2 3 . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B - 03 2 _ A P _ R 0 3 _ R M _ 2 0 2 3 0 8 2 9 . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B - 03 2 _ A P _ R 0 4 _ R M _ 2 0 2 3 0 9 0 9 . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 10 0 1 2 3 8 1 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 - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 12 8 1 2 3 8 1 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 - 03 2 _ D r i l l G a s _ A S C I I _ d e p t h _ 1 2 3 8 1 f t ( 1 ) . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 12 8 1 2 3 8 1 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 - 03 2 _ D r i l l G a s _ A S C I I _ d e p t h _ 1 2 3 8 1 f t . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 12 8 1 2 3 8 1 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 - 03 2 _ D r i l l G a s _ A S C I I _ d e p t h _ L i t h o l o g y _ 1 2 3 8 1 f t (1 ) . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 12 8 1 2 3 8 1 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 - 03 2 _ D r i l l G a s _ A S C I I _ d e p t h _ L i t h o l o g y _ 1 2 3 8 1 f t . l a s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 F i n a l C o m p a s s S u r v e y NA D 2 7 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 F i n a l C o m p a s s Su r v e y . p d f 38 0 4 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 1 o f 7 Su p p l i e d b y Op Su p p l i e d b y Op ND B - , 032 _ L W D _ R M _ 1 2 3 8 1 ft. l a s ND B - , 032 _ D r i l l Gas _ A SC II _ d e p t h _ L i t h o l o gy _1 2 3 8 1 ft. l a s 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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 UI C No DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 P l a n V i e w . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 V e r t i c a l S e c t i o n . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 . t x t 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B i - 0 3 2 W A S u r v e y Re p o r t s . x l s x 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : A C E _ S A N T O S _ N D B - 03 2 _ 1 2 S E P 2 0 2 3 _ R e p o r t . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : A C E _ S A N T O S _ N D B - 03 2 _ 1 2 S E P 2 0 2 3 _ v 2 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : A C E _ S A N T O S _ N D B - 03 2 _ 1 2 S E P 2 0 2 3 _ v 2 . t i f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : A C E _ S A N T O S _ N D B - 03 2 _ 1 2 S E P 2 0 2 3 _ v 2 _ D L I S . d l i s 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ A P _ R M _ 2 0 2 3 0 9 1 0 . c g m 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ A P _ R M _ 2 0 2 3 0 9 1 0 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ D M D _ R M _ 1 2 3 8 1 f t . c g m 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ D M D _ R M _ 1 2 3 8 1 f t . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ D M T _ R M _ 2 0 2 3 0 9 1 0 . c g m 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ D M T _ R M _ 2 0 2 3 0 9 1 0 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 2 M D . c g m 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 2 M D . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 2 T V D . c g m 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 2 T V D . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 5 M D . c g m 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 5 M D . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 5 T V D . c g m 38 0 4 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 2 o f 7 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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 UI C No DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R M _ 1 2 3 8 1 f t _ 5 T V D . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 M u d l o g g i n g E n d o f W e l l Re p o r t . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 M u d l o g g i n g G e o l o g i c a l Re p o r t s . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 C u t t i n g s M a n i f e s t . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ G a s R a t i o L o g _ 1 2 3 8 1 f t _ M D - 2 i n . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 03 2 _ G a s R a t i o L o g _ 1 2 3 8 1 f t _ M D - 5 i n . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ G a s R p t . x l s x 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ L i t h o l o g y . x l s x 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ M u d l o g _ 1 2 3 8 1 f t _ M D - 2i n . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : N D B - 0 3 2 _ M u d l o g _ 1 2 3 8 1 f t _ M D - 5i n . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 1 0 1 5 0 - 1 0 1 7 0 _ # 1 4 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 1 0 2 8 0 - 1 0 3 2 0 _ # 1 5 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 1 0 6 3 0 - 1 0 7 0 0 _ # 1 6 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 1 2 0 6 0 - 1 2 1 1 0 _ # 1 7 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 1 2 3 2 0 - 1 2 3 8 1 _ # 1 8 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 2 9 1 0 - 3 1 5 0 _ # 1 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 4 8 6 5 - 4 9 5 0 _ # 2 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 5 1 0 0 - 5 2 0 5 _ # 3 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 5 2 5 0 - 5 3 3 0 _ # 4 . p d f 38 0 4 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 3 o f 7 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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 UI C No DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 6 0 0 0 - 6 1 0 0 _ # 5 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 6 8 2 5 - 6 9 0 0 _ # 6 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 7 4 5 0 - 7 5 9 0 _ # 7 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 8 3 4 0 - 8 6 6 0 _ # 8 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 8 7 5 0 - 8 8 4 0 _ # 9 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 8 8 7 5 - 8 8 9 5 _ # 1 0 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 8 9 8 0 - 9 0 5 0 _ # 1 1 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 9 4 4 0 - 9 4 8 3 _ # 1 2 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 10 / 1 2 / 2 0 2 3 E l e c t r o n i c F i l e : S h o w R e p o r t G e o l o g _ N D B - 03 2 _ 9 7 4 0 - 9 8 0 0 _ # 1 3 . p d f 38 0 4 8 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 47 1 2 3 8 1 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 - 03 2 _ L W D _ G R _ R e s _ D e n s _ N e u _ C a l _ A z i R e s _ D e ep A z i R e s _ 1 2 3 8 1 . l a s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 23 4 7 6 2 9 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ C B L .l a s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 23 4 7 6 2 9 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ T O C. l a s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 62 7 0 1 2 0 4 5 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 - 32 _ G e o I s o t o p e s C o r r e c t e d d a t a _ 6 2 8 0 - 12 0 4 5 f t . l a s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ D T C _ R A W _ W A V E F O R M S_ 5 9 0 0 _ 1 2 2 4 9 . p d f 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ D T S _ R A W _ W A V E F O R M S_ 5 9 0 0 _ 1 2 2 4 9 . p d f 38 4 9 7 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 4 o f 7 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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 UI C No DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ F I E L D _ D T C _ G R A M _ 5 9 0 0 _1 2 2 4 9 . p d f 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ R A W _ W A V E F O R M S _ 5 9 0 0_ 1 2 2 4 9 . d l i s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ R A W _ W A V E F O R M S _ 5 9 0 0_ 1 2 2 4 9 _ d l i s . t x t 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ C B L .c g m 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ C B L .d l i s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ C B L .P D F 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ C B L _d l i s . t x t 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ T O C. c g m 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ T O C. d l i s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ T O C. P D F 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 03 2 _ L W D _ R 0 4 _ 2 3 4 7 f t _ 6 1 1 8 f t _ S D T K _ M E M _ T O C_ d l i s . t x t 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ D T C _ R A W _ W A V E F O R M S_ 5 9 0 0 _ 1 2 2 4 9 . p d f 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ D T S _ R A W _ W A V E F O R M S_ 5 9 0 0 _ 1 2 2 4 9 . p d f 38 4 9 7 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 5 o f 7 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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 UI C No DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ F I E L D _ D T C _ G R A M _ 5 9 0 0 _1 2 2 4 9 . p d f 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ R A W _ W A V E F O R M S _ 5 9 0 0_ 1 2 2 4 9 . d l i s 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : S a n t o s _ N D B - 03 2 _ M D _ S D T K _ M E M _ R A W _ W A V E F O R M S _ 5 9 0 0_ 1 2 2 4 9 _ d l i s . t x t 38 4 9 7 ED Di g i t a l D a t a DF 2/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : N D B - 3 2 _ G e o I s o t o p e s C o r r e c t e d Lo g _ 6 2 8 0 - 1 2 0 4 5 f t _ 2 i n c h . p d f 38 4 9 7 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 2 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s _R M _ 1 0 9 4 7 f t _ 2 M D . c g m 38 4 9 7 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 2 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s _R M _ 1 0 9 4 7 f t _ 2 T V D . c g m 38 4 9 7 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 2 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s _R M _ 1 0 9 4 7 f t _ 2 M D . p d f 38 4 9 7 ED Di g i t a l D a t a DF 3/ 2 0 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 2 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ D e e p A z i R e s _R M _ 1 0 9 4 7 f t _ 2 T V D . p d f 38 4 9 7 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 . 3 _ N D B - 0 3 2 _ R e v A_ S i g n e d . p d f 39 8 2 9 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 3 2 _ 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 D a t a (1 ) . x l s x 39 8 2 9 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 3 2 _ 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 (1 ) . x l s x 39 8 2 9 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 24 0 6 6 2 2 4 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 - 03 2 _ B H P _ 1 2 _ 2 5 _ 2 5 9 8 _ 6 2 2 4 f t _ R u n 3 . l a s 41 1 1 4 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 60 4 4 1 2 2 7 6 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 - 03 2 _ B H P _ 8 _ 5 _ 6 2 8 5 _ 1 2 2 8 0 f t _ R u n 4 . l a s 41 1 1 4 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 : SA N T O S _ N D B _ 0 3 2 _ B H P _ 1 2 _ 2 5 _ 2 5 9 8 _ 6 2 2 4 f t _ Ru n 3 . d l i s 41 1 1 4 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 6 o f 7 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 6 0 - 0 0 - 0 0 We l l N a m e / N o . P I K K A N D B - 0 3 2 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 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 6 0 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 12 3 8 1 TV D 41 9 7 Cu r r e n t S t a t u s 1- O I L 12 / 2 2 / 2 0 2 5 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 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 : 9/ 1 3 / 2 0 2 3 Re l e a s e D a t e : 8/ 1 / 2 0 2 3 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 - 03 2 _ B H P _ 8 _ 5 _ 6 2 8 5 _ 1 2 2 8 0 f t _ R u n 4 . d l i s 41 1 1 4 ED Di g i t a l D a t a 9/ 2 7 / 2 0 2 3 12 8 1 2 3 8 1 61 8 5 8 Cu t t i n g s Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 7 o f 7 1/ 2 / 2 0 2 6 M. G u h l 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-032 50103208600000 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.las ؒ جؐؐؐNDB-024 Lithotrak Caliper data ؒ جؐؐؐRun 6 ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.dlis ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.las ؒ ؒ ؒ ؤؐؐؐRun 7 ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.dlis ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.las ؒ جؐؐؐNDB-025 Lithotrak Caliper data ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.dlis ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.las ؒ جؐؐؐNDB-027 Lithotrak Caliper data ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.dlis ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.las ؒ جؐؐؐNDB-031 Lithotrak Caliper data ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.dlis ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.las ؒ جؐؐؐNDB-032 Lithotrak Caliper data ؒ جؐؐؐRun 3 ؒ ؒ SANTOS_NDB-032_BHP_12_25_2598_6224ft_Run3.las ؒ ؒ SANTOS_NDB_032_BHP_12_25_2598_6224ft_Run3.dlis ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.dlis ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.las ؒ جؐؐؐNDB-037 Lithotrak Caliper data ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.dlis ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.las ؒ جؐؐؐNDB-048 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.dlis ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 223-076 T41110 224-006 T41111 225-066 T41112 225-028 T41113 223-060 T41114 224-124 T41115 224-143 T41116 ؐNDB-032 Lithotrak Caliper data LETTER OF TRANSMITTAL ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.dlis ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.las ؒ جؐؐؐNDB-051 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.dlis ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.dlis ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.las ؒ جؐؐؐNDBi-014 Lithotrak Caliper data ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.dlis ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.las ؒ جؐؐؐNDBi-016 Lithotrak Caliper data ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4.las ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4_1.dlis ؒ جؐؐؐNDBi-018 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.dlis ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.dlis ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.las ؒ جؐؐؐNDBi-030 Lithotrak Caliper data ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.dlis ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.las ؒ جؐؐؐNDBi-036 Lithotrak Caliper data ؒ جؐؐؐRun 4 ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.dlis ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.las ؒ ؒ ؒ ؤؐؐؐRun 6 ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.dlis ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.las ؒ 224-013 T41117 223-105 T41118 224-105 T41119 224-085 T41120 223-120 T41121 225-012 T41122 LETTER OF TRANSMITTAL جؐؐؐNDBi-043 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.dlis ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.dlis ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.las ؒ جؐؐؐNDBi-044 Lithotrak Caliper data ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.dlis ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.las ؒ جؐؐؐNDBi-046 Lithotrak Caliper data ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.dlis ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.las ؒ جؐؐؐNDBi-049 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.dlis ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.dlis ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.las ؒ جؐؐؐNDBi-050 Lithotrak Caliper data ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.dlis ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.las ؒ ؤؐؐؐPWD-02 Lithotrak Caliper data SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.dlis SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.las 223-051 T41123 223-087 T41124 224-028 T41125 224-119 T41126 224-154 T41127 224-009 T41128 1. 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 12,381 feet N/A feet true vertical 4,197 feet N/A feet Effective Depth measured 12,374 feet See attached rpt feet true vertical 4,197 feet See attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6ppf P-110S 12,374' MD 4,197' TVD Packers and SSSV (type, measured and true vertical depth) See attached packer report 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Authorized Title: Completions Specialist Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone:907-- 323-616 Sr Pet Eng: 9210 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 MDSize 128' 9-5/8" 11590 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-060 50-103-20860-00-00 900 E Benson Boulevard, Suite 500 Anchorage, AK 99508 3. Address: N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393020 Pikka / Nanushuk Oil Pool NDB-032 Plugs Junk measured Length 128' 2588' 128'Conductor Surface Intermediate 20"x34" 13-3/8" measured TVD Production Liner 6283' 6272' 6136' Casing Structural 4322' 4294' 4-1/2" 6283' 6157' 12374' 4197' 4750 9210 N/A 5020 6870 11590 2588' 2273' Burst Collapse N/A 2260 pppppppp kkkkk ft tttttt ntt e Fra O g g s g y 223 e 6. A y G L PG 25.070,2 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 07/08/2024 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 12,381 feet N/A feet true vertical 4,197 feet N/A feet Effective Depth measured 12,374 feet See attached rpt feet true vertical 4,197 feet See attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6ppf P-110S 12,374' MD 4,197' TVD Packers and SSSV (type, measured and true vertical depth) See attached packer report 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Authorized Title: Completions Specialist Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone:907-- 323-616 Sr Pet Eng: 9210 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 MDSize 128' N/A 9-5/8" 11590 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-060 50-103-20860-00-00 900 E Benson Boulevard, Suite 500 Anchorage, AK 99508 3. Address: N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393020 Pikka / Nanushuk Oil Pool NDB-032 Plugs Junk measured Length 128' 2588' 128'Conductor Surface Intermediate 20"x34" 13-3/8" measured TVD Production Liner 6283' 6272' 6136' Casing Structural 4322' 4294' 4-1/2" 6283' 6157' 12374' 4197' 4750 9210 N/A 5020 6870 11590 2588' 2273' Burst Collapse N/A 2260 pppppppp kkkkk ft tttttt ntt e Fra O g g s g y 223 e 6.A y G L PG 25.070,2 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 07/08/2024 By Grace Christianson at 8:02 am, Aug 06, 2024 CDW 08/16/2024 DSR-8/12/24 RBDMS JSB 080824 Superseded Page 1 of 1 Well Name: NDB-032 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 6,125.5 4,308.2 OH Packer #12 6,959.1 4,313.8 OH Packer #11 7,451.4 4,303.6 OH Packer #10 8,026.4 4,291.6 OH Packer #9 8,517.7 4,281.2 OH Packer #8 9,050.5 4,269.6 OH Packer #7 9,457.9 4,260.1 OH Packer #6 9,902.6 4,250.3 OH Packer #5 10,345.1 4,240.9 OH Packer #4 10,992.6 4,227.1 OH Packer #3 11,396.0 4,218.5 OH Packer #2 11,843.1 4,208.9 OH Packer #1 12,247.9 4,200.1 NDB-032 Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2417' MD 13-3/8" 68 ppf L-80 Surface Casing2588' MD 9-5/8", 47ppf L-80 Production Liner 6283' MD 4-½, 12.6ppf P-110S Production Liner12376' MD GL 9-5/8" 68 ppf L-80 Tieback2417' MD 9.14.2023 41.5' RKB Tubing Hanger Flange 1 2 3 4 5 6 7 8 9 8-½ Openhole12381' MD # Completion Item Depth (MD') Depth (TVD') Inc ID" OD" 1 GasliftMandrel 1.5" 2908 2478 50 3.865 7.684 2 X LandingNipple 2971 2518 50 3.813 4.787 3 X LandingNipple 5847 4256 76 3.813 4.790 4 D/HPsi TempGauge 5902 4270 77 3.905 6.002 5 SSDNERA GL 5957 4281 79 3.813 6.922 6 Slimline Dial 6016 4292 80 3.898 5.990 7 X LandingNipple 6039 4296 80 3.813 4.784 8 Tieback Seal Assy 6136 4309 83 3.860 5.230 9 9.625"x 4.5"LH/Packer 6104 4305 83 6.180 8.420 10 #12Openhole Packer 6952 4314 91 3.918 8.000 11 Stage 11 FracSleeve 7222 4308 91 3.735 5.627 12 #11Openhole Packer 7444 4303 91 3.918 8.000 13 Stage 10 FracSleeve 7714 4298 91 3.735 5.627 14 #10Openhole Packer 8019 4291 91 3.918 8.000 15 Stage 9 FracSleeve 8206 4287 91 3.735 5.627 16 #9Openhole Packer 8511 4281 91 3.918 8.000 17 Stage 8 FracSleeve 8698 4277 91 3.735 5.627 18 #8Openhole Packer 9043 4269 91 3.918 8.000 19 Stage 7 FracSleeve 9188 4266 91 3.735 5.627 20 #7Openhole Packer 9451 4260 91 3.918 8.000 21 Stage 6 FracSleeve 9676 4255 91 3.735 5.627 22 #6Openhole Packer 9896 4250 91 3.918 8.000 23 Stage 5 FracSleeve 10160 4244 91 3.735 5.627 24 #5Openhole Packer 10338 4241 91 3.918 8.000 25 Stage 4 FracSleeve 10644 4234 91 3.735 5.627 26 #4Openhole Packer 10985 4227 91 3.918 8.000 27 Stage 3 FracSleeve 11126 4224 91 3.735 5.627 28 #3Openhole Packer 11389 4218 91 3.918 8.000 29 Stage 2 FracSleeve 11613 4213 91 3.735 5.627 30 #2Openhole Packer 11836 4209 91 3.918 8.000 31 Stage 1 FracSleeve 12102 4203 91 3.735 5.627 32 #1Openhole Packer 12241 4200 91 3.918 8.000 33 #2Toe Sleeve 12300 4198 91 3.500 5.875 34 #1Toe Sleeve 12308 4198 91 3.500 5.875 35 WIV Collar 12363 4197 91 5.620 36 Eccentricshoe 12372 4197 91 3.930 5.220 Frac Ops Summary Report - AOGCC Well Name NDB-032 Primary Job Type Fracture Treatment Start Date End Date Summary 4/3/2024 4/4/2024 MIRU Frac equipment. Load proppant. Fill and heat Frac tanks. 4/4/2024 4/5/2024 MIRU Frac equipment. Fill and heat Frac tanks. 4/5/2024 4/6/2024 RU Frac equipment. Fill and heat Frac tanks. 4/6/2024 4/7/2024 Prepare to Frac Stages 1-4 4/7/2024 4/8/2024 Frac Stages 1-4 Finish RU of Frac equipment, prime up, pressure test. Pump Freeze Protect fluid past wellhead with 40 bbls WF125. Pump Check with 250 bbls WF125 DataFrac: 241.7 bbls YF125ST and 207 bbls WF125 fluid at 40bpm. Frac stage 1: 2,439.4 bbls slurry (YF125ST fluid), 230,772 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 2,215.6 bbls clean fluid at 40bpm, as per design. Frac stage 2: 1,623.8 bbls slurry (YF125ST fluid), 250,780 lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,381.3 bbls clean fluid at 40bpm, as per design. Frac stage 3: 1,930.0 bbls slurry (YF125ST fluid), 15,941 lbs 40/70 Carbolite (1, 3ppa), 287,041 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10, 12ppa), 1,637.5 bbls clean fluid at 40bpm, as per design. Frac stage 4: 2,277.5 bbls slurry (YF125ST fluid), 16,059 lbs 40/70 Carbolite (1, 3ppa), 207,807 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10, 12ppa), 2,062.3 bbls clean fluid at 40bpm, as per design. TLTR (Stages 1-4) 7,995.4 bbls 4/8/2024 4/9/2024 Load proppant. Fill and heat Frac tanks. 4/9/2024 4/10/2024 Load proppant. Fill and heat Frac tanks. 4/10/2024 4/11/2024 Frac Stages 5-6 Finish RU of frac equipment and chemical/water testing. Frac stage 5: Pump ball down at 4bpm to start frac; 2,255bbls slurry (YF125ST fluid), 16,000 lbs 40/70 carbolite (1, 3ppa), 278,785lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 1,957bbs clean fluid at 40bpm as per design. Frac stage 6: 3,075bbls slurry (YF125ST fluid), 272,248lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 2,739bbs clean fluid at 40bpm; hydration unit lost prime on 1ppa step and had to lower rate and shutdown before recovery, pumped 1ppa and 2ppa and then flushed well to restart job and ensure good fluid, restarted the job and pumped as per design. Landed collet for stage 7 frac but were having trouble with discharge pressure on the blender. Attempted to diagnose and then made decision to flush well and continue frac after sand/water refill. Tracerco tracers pumped as per plan on stages (details in job time log on each stage). Well freeze protected with 63bbls (47bbls downhole and 16bbls surface lines). Total Load to Recover (TLTR) stage 5-6 4,745bbls Total Load to Recover for well 12,740bbls NPT on SLB until next frac day due to blender replacement. 4/11/2024 4/12/2024 Load proppant. Fill and heat Frac tanks. Page 1 of 2 Frac Ops Summary Report - AOGCC Start Date End Date Summary 4/12/2024 4/13/2024 Frac Stages 7-8 Finish RU of frac equipment and chemical/water testing. Frac stage 7: Pump ball down at 4bpm to start frac, 2,184bbls slurry (YF125ST fluid), 188,078lbs 16/20 carbolite scaleguard (1, 2, 3, 4, 5, 6, 7ppa), 64,974lbs 12/18 carbolite (7, 8ppa), 1,928bbs clean fluid at 40bpm as per design. Frac stage 8: 2,070bbls slurry (YF125ST fluid), 234,111lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10ppa), 1,838bbs clean fluid at 40bpm as per design. Tracerco tracers pumped as per design (details in the job time log for each stage). Well freeze protected with 65bbls (49bbls downhole and 16bbls surface lines). Total Load to Recover (TLTR) stage 7-8 3,766bbls Total Load to Recover (TLTR) 16,506bbls 4/13/2024 4/14/2024 Load proppant. Fill and heat frac tanks. 4/14/2024 4/15/2024 Finish loading proppant and heating tanks. Complete fluid testing and spot chemicals/equipment in prep for frac. 4/15/2024 4/16/2024 Pump frac stages 9-11 Finish RU equipment, prime up and pressure test. Frac stage 9: Pump ball down at 4bpm to start frac; 2,094bbls slurry (YF125ST fluid), 12,343 lbs 40/70 carbolite (1, 3ppa), 256,750lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 1,826bbs clean fluid at 40bpm as per design. Frac stage 10: 1,970bbls slurry (YF125ST fluid), 14,306 lbs 40/70 carbolite (1, 3ppa), 242,155lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 1,714bbs clean fluid at 40bpm as per design. Shut down after initial collet land to fix issue with sand chief before continuing with job. Frac stage 11: 2,029bbls slurry (YF125ST fluid), 21,351 lbs 40/70 carbolite (1, 3ppa), 198,352lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8ppa), 1,809bbs clean fluid at 35-40bpm. 6ppa and 8ppa extended and did not go to 10ppa due to pressure. Tracerco tracers pumped as per design (details in the job time log for each stage). Well freeze protected with 60bbls (44bbls downhole and 16bbls surface lines). 8gal diesel spill (5gal to pad and 3 gal to containment) from miscommunication while blowing down frac lines. Total Load to Recover (TLTR) stage 9-11 5,349bbls Total Load to Recover (TLTR) 21,855bbls 4/16/2024 4/17/2024 Continue to RD frac equipment. RD Cameron launch tree. Page 2 of 2 Flowback Ops Summary Report - AOGCC Well Name NDB-032 Primary Job Type Flowback/Testing Start Date End Date Summary 3/21/2024 3/22/2024 No accidents no spills. Expro prepare equipment to move. 3/22/2024 3/23/2024 No accidents no spills. Expro prepare equipment to move. 3/23/2024 3/24/2024 No accidents no spills. Expro prepare equipment to move. 3/24/2024 3/25/2024 No accidents no spills. Expro prepare equipment to move. 3/25/2024 3/26/2024 No accidents no spills. Expro prepare equipment to move. 3/26/2024 3/27/2024 No accidents no spills. Expro prepare equipment to move. 3/27/2024 3/28/2024 No accidents no spills. Expro prepare equipment to move. 3/28/2024 3/29/2024 No accidents no spills. Expro prepare equipment to move. 3/29/2024 3/30/2024 No accidents no spills. Expro prepare equipment to move. 3/30/2024 3/31/2024 No accidents no spills. Expro prepare equipment to move. Move Sand separator and Well control equipment into containment. 3/31/2024 4/1/2024 No accidents no spills. Expro prepare equipment to move. 4/1/2024 4/2/2024 No accidents no spills. Expro prepare crane for equipment move. Move DPI ST into containment. Move Sparge tank into containment. RU HP piping to Sand separation and well control equip. 4/2/2024 4/3/2024 Expro Rigged up hard line to wellhead SDV and inner connecting pipe for sand management system. 4/3/2024 4/4/2024 Expro completed rigging up hard line in the well head containment. 4/4/2024 4/5/2024 Expro lowered flare to install new ignitor system. 4/5/2024 4/6/2024 Expro continued woking on safety system ad DAQ. 4/6/2024 4/7/2024 Expro ran lines for safety system to the WH equipment. 4/7/2024 4/8/2024 Expro installed and tested back up igniter on flare. 4/8/2024 4/9/2024 Expro continued working on ESD system. 4/9/2024 4/10/2024 Expro began clearing area for frac move. 4/10/2024 4/11/2024 Expro conducted air test on HP and LP header. 4/11/2024 4/12/2024 Expro got good leak test on LP header. 4/12/2024 4/13/2024 Check DPI unit for leaks throughout entire unit and crew completed preliminary Safety systems test. 4/13/2024 4/14/2024 Expro Wrapped lines and rigged up port for LRS. 4/14/2024 4/15/2024 Finish up Safety systems connections with 1" air line installed. PT Test lines to tank manifolds including Sand trap, DPI unit, Choke manifold and Separator. Low 231psi and High 1120psi Good Test. 4/15/2024 4/16/2024 Remove snow from WT area and equipment. Installed 1 13/16" 10M blind flange on the DPI vent line and Expro trained personnel on the operations of the DPI. 4/16/2024 4/17/2024 SLB tech setup DH logger in Expros test unit. Inspect entire ESD lines, repair quick exhaust O' rings, clean up Tank farm and TTLA. Page 1 of 4 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 4/17/2024 4/18/2024 Rig up ball catcher, rig up hard-lines to well and PT to Low 500psi and High 4500psi. Continue to get equipment ready for Well clean-up. 4/18/2024 4/19/2024 Test safety systems to wellhead, hutch wellhead and ball catcher. Perform final check on equipment and complete pre-flow checklist. 4/19/2024 4/20/2024 Continue to get equipment ready for Well clean-up. Finish rigging up Magtec and LRS equipment at the injection well. Make a walk through all WT equipment. Hold a Pre-Flow meeting with all vendors. LRS pressure test lines to 4500psi. Good test. 4/20/2024 4/21/2024 Hold safety meeting, make a final walk through, open up well, record Well pressures and start Well clean-up operation. Open up well on 12/64" choke and worked choke up to 28/64" at midnight. 4/21/2024 4/22/2024 Expro flowing well per clean up procedure. 4/22/2024 4/23/2024 Expro flowing well per clean up procedure. 4/23/2024 4/24/2024 Expro shut in well and began rigging down. 5/2/2024 5/3/2024 Expro Rigging up equuipment in preperation to flow well. 5/3/2024 5/4/2024 Expro Rigging up equuipment in preperation to flow well. 5/4/2024 5/5/2024 Expro Rigging up equuipment in preperation to flow well. 5/5/2024 5/6/2024 Expro Rigging up equuipment in preperation to flow well. 5/6/2024 5/7/2024 Expro Complete ESD System function test. ESD Pre flow checklist verification. Leak detection testing. 5/7/2024 5/8/2024 Monitor Down hole pressure and temperature. Heat equipment prep to flow well. Wait on Coil Tubing, 5/8/2024 5/9/2024 Monitor Down hole pressure and temperature. Heat equipment prep to flow well. Wait on Coil Tubing, 5/9/2024 5/10/2024 Monitor Down hole pressure and temperature. Wait on Coil Tubing, 5/10/2024 5/11/2024 Monitor Down hole pressure and temperature. Wait on Coil Tubing, 5/11/2024 5/12/2024 LRS Coiled tubing unit #2 arrive on location. Spot equipment and raise mast. Stab 2" coil through injector. Pick up injector with lubricator and NU BOPE to pump-in sub on well. Perform weekly BOP test to 350 psi low/4000 psi high. Good test. MU and Test coiled tubing cleanout BHA #1. 5/12/2024 5/13/2024 RIH with coil and start cleanout at 6,000' ctmd. Lost hydraulic pressure to coil reel at 6,300'. Circulate 1.5x bottoms up to return tanks and close choke. Replace proportional valve on coil reel and resume cleanout. Cleanout from 6,300' to 7,325' with slick/safe seawater. Did not see any obstructions when cleaning past Frac sleeve #11 at 7,222'. Chase returns to surface. Did not see any substantial amount of proppant at surface. Troubleshoot coil reel hydraulic pressure issues again. RIH cleanout to 7825' ctmd. Continue cleanout. 5/13/2024 5/14/2024 Cleanout from 7825' to 8825' ctmd with 2" coil. Start to get overpulls during wiper trip at 5400', reduce speed and continue to pull to 1,000' and get proppant/sand slugs at surface. Make another cleanout bite from 8825' to 9300' and chase returns to 1,000' at 40 fpm and 1.9 bpm. Page 2 of 4 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 5/14/2024 5/15/2024 Cleanout from 9300' to 9800' ctmd with 2" coil. Got overpulls during wiper trip at 5080', reduce speed and continue to pull to 1,000' at 40 fpm @ 1.9 bpm. Significant proppant/sand slugs at surface. Did a short trip to 6400', pump gel sweep, POOH to 1000'. Started to lose returns, slowed running speed to 25 ft/min. Change valves and seats on coil pump. Start RIH however reel hydraulics started malfunctioning again. POOH and wait on MT and ET to arrive to trouble shoot. Determined the Power Pack was creating the issue, waiting on backup Power Pack coming out from town. 5/15/2024 5/16/2024 Cleanout from 9800' to 10,800' ctmd with 2" coil. Got overpulls through the heel during wiper trips, reduce speed and continue to pull to 1,000' ctmd at 2.0 bpm. Significant proppant/sand seen in returns at surface on 2nd run. Pumped gel pills at 6400' coming up through the heel. Started to lose returns at 5600' ctmd on 2nd run, ran back in hole through the heel and made a second pass, slowed running speed to 15 ft/min. 5/16/2024 5/17/2024 POOH from 10,800' to surface, chasing returns at 40 fpm and 2.0 bpm. Observed significant sand/proppant returns. Cut pipe, install new contector, pull tested to 25k lbs for 5 minutes. Install Baker Slick Catch tool. Nipple up to well, pressure test 3500 psi for 5 mins. RIH to tag collet at 7222'. No set down weight at expected depth. Continued to RIH and set down 3,000 lbs at 7699'. POOH with the collet to 5460', working through some tight spots using the jars and pump rate. Had sand stacking on top of collet through the heel. Released the Slick Catch tool. POOH to surface, pick up jet nozzle. RIH with swirl nozzle. Clean out to 5565'. POOH chasing returns to surface. No significant sand/proppant seen at surface. 5/17/2024 5/18/2024 Coil N2 lift from 6,350' ctmd. Expro flowing well per clean up procedure. 5/18/2024 5/19/2024 Expro flowing well per clean up procedure. Shutdown flowback operations for about 12hrs to mitigate higher than normal H2S concentration in the flowback fluids before resuming operation. 5/19/2024 5/20/2024 Expro flowing well per clean up procedure. Lost WHP and BHP due to possible sand plugs downhole. Pumped a total of 81,800scf of N2 on two attempts to breakdown and remove sand plug but was unsuccessful. Shut-in well at midnight with 0psi WHP and 1490psi BHP. 5/20/2024 5/21/2024 Shut-in well and monitor for pressure build up enough to flow well. A decision was made to suspend flowback operations and wait on CTU to clean up well before resuming the FB operations. 5/21/2024 5/22/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/22/2024 5/23/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/23/2024 5/24/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/24/2024 5/25/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/25/2024 5/26/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/26/2024 5/27/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/27/2024 5/28/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/28/2024 5/29/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/29/2024 5/30/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/30/2024 5/31/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/31/2024 6/1/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 6/1/2024 6/2/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 6/2/2024 6/3/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, Page 3 of 4 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 6/3/2024 6/4/2024 LRS coiled tubing unit #2 arrived on location with 2" coil. Spot equipment and RU hardline from well to choke and out to return tanks. Perform weekly BOP test to 250 psi low / 4,000 psi high. MU BHA with Tempress and 2.30" JSN. PT out to Choke skid. Open well and RIH to start cleanout. Having issues with reel motor. Call out for mechanic to replace reel motor. 6/4/2024 6/5/2024 Cleanout from 5,500' to 6,000'. Change out reel motor on coil unit. POOH to surface and troubleshoot reel motor interntal brake issues. 6/5/2024 6/6/2024 Continue to troubleshoot hydraulic issue with reel motors on location. Decision was made to rig down coiled tubing unit and travel back to LRS shop in Deadhorse for diagnostics and repair. Blowdown coil with N2. RDMO. 6/6/2024 6/7/2024 LRS Coil departs location enroute to Deadhorse for repairs. 6/7/2024 6/8/2024 LRS coil unit #2 arrive on location. MIRU. Complete BOP test. 6/8/2024 6/9/2024 Coiled tubing cleaned out with 2" coil from 5,500' to 7,500' ctmd using slick/safe seawater with gel pills. Cleaned out proppant in increments of 500' and then chased returns to 1,000'. Seen heavy proppant returns at surface once coil reaches ~ 1,400'. 6/9/2024 6/10/2024 Coiled tubing cleanout with 2" coil from 7,500' to 9,100' ctmd using slick/safe seawater with gel pills. Cleaned out proppant in increments of 500-600' and then chased returns to 1,000'. Get heavy proppant returns to surface once coil reaches ~ 1,400'. After cleaning out to 9,100', coil pressured up at 2500' ctmd while chasing returns to surface and were only able to achieve 0.8 bpm on pumps. Trip to surface to inspect tempress tools. No material appeared to be plugging the tempress screen sub. Change out Tempress and screen sub. RIH after tool swap and tagged sand at 5529' ctmd. Cleanout down to 6500' ctmd and then chase returns uphole to clean out proppant. 6/10/2024 6/11/2024 Cleanout with 2" coiled tubing from 9,100' to 10,700' ctmd using slick/safe seawater with gel pills. Cleaned out proppant in increments of 500-600' and then chased returns to 1,000'. Get heavy proppant to surface once coil reaches ~ 1,400'. 6/11/2024 6/12/2024 Cleanout with 2" coiled tubing from 10,700 to 11,250' ctmd. Coil reached lock-up ~ 11,000', but able to continue to 11,250' ctmd with use of Tempress tool. Lost returns to surface at ~ 5,600' and coil was hung up until returns established. Chase returns to surface, getting proppant slug to surface from 1,400' until 1,000' when it cleaned up. POOH and laydown Tempress BHA. Swap to a 2" slim cleanout BHA with 2" jet swirl nozzle. RIH and tag at 5600' ctmd. Pump gel/slick seawater and cleanout to 6,000' ctmd and chase returns to 1,000. RBIH to 6,500' ctmd without pumping. Pump final gel/slick seawater sweep taking returns to surface while POOH to 1,000'. RIH to 6,350'. Pump N2 down coil at 500scf/min while taking returns to tanks until N2 reaches surface. Hand well over to Expro for welltest while pumping N2 at 500scf/min for first 24hrs. 6/12/2024 6/13/2024 LRS coil reciprocate coiled tubing from ~ 6350' to 5,000 while pumping ~ 350 scfm of Nitrogen. Expro flowing well per clean up procedure. 6/13/2024 6/14/2024 Expro flowing well per clean up procedure. 6/14/2024 6/15/2024 Expro flowing well per clean up procedure. 6/15/2024 6/16/2024 Expro flowing well per clean up procedure. 6/16/2024 6/17/2024 Expro flowing well per clean up procedure. 6/17/2024 6/18/2024 Expro flowing well per clean up procedure. 09:00 shut in well and monitor DH pressure & Temp. Rig off of well head & Move to Well NDBi-030. Page 4 of 4 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 890.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 428.3 gal J475 Breaker J475 5.9 lb/mGal 5,166.0 lbm J511 Stabilizing Agent 1.5 lb/mGal 1,286.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,911.0 gal J580 Gel J580 25.6 lb/mGal 22,473.4 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 50.1 gal M117 Clay Control Agent 342.9 lb/mGal 301,065.0 lbm M275 Bactericide 0.3 lb/mGal 293.9 lbm S522-1218 Propping Agent varied concentrations 64,974.0 lbm S522-1620 Propping Agent varied concentrations 2,541,004.0 lbm S522-4070 Propping Agent varied concentrations 96,000.0 lbm S901 Proppant with Scale Inhibitor S901 varied concentrations 105,875.0 lbm 69.79133 % 26.76831 % 2.79671 % 0.21468 % 0.10139 % 0.08650 % 0.03958 % 0.03957 % 0.03777 % 0.03084 % 0.02028 % 0.01333 % 0.01333 % 0.01232 % 0.01224 % 0.00940 % 0.00664 % 0.00152 % 0.00141 % 0.00107 % 0.00054 % 0.00028 % 0.00025 % 0.00025 % 0.00017 % 0.00014 % 0.00004 % 0.00004 % 0.00003 % 0.00003 % 0.00001 % 0.00001 % < 0.00001 % 100 % * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 64-19-7 Acetic acid (impurity) 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate Total 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 532-32-1 Sodium benzoate 7786-30-3 Magnesium chloride 9000-90-2 Amylase, alpha 127-08-2 Acetic acid, potassium salt (impurity) 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 50-70-4 Sorbitol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 9003-35-4 Phenolic resin 111-76-2 2-butoxyethanol 67-63-0 Propan-2-ol 102-71-6 2,2`,2"-nitrilotriethanol 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 7727-54-0 Diammonium peroxodisulphate 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF125ST:WF125 878,105 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-1928 Fluid Name & Volume Concentration Volume Disclosure Type: Post-Job Well Completed: Date Prepared: 8/2/2024 State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search (Alaska), LLC Well: PIKKA NDB-032 Basin/Field: Pikka # SLB-Private Page: 1 / 1 Updated 7/18/2024INPUT4-7-24 to 4-15-24AK TSCA Status50-103-20860-00-00Post878,10571.86368%10,499,929Trade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SME Tracerco Carrier Fluid Soy Methyl Ester 67784-80-9 100 0.0009200676 96.6064484000T-165D Tracerco Chemical Tracer 4-Iodobiphenyl 1591-31-7 100 0.0000041993 0.4409240000T-716 Tracerco Chemical Tracer 1,3,5-Tribromobenzene 626-39-1 100 0.0000041993 0.4409240000T-784 Tracerco Chemical Tracer 2,4,6-Tribromoanisole 607-99-8 100 0.0000041993 0.4409240000T-164C Tracerco Chemical Tracer 1-Iodonaphthalene 90-14-2 100 0.0000041993 0.4409240000T-164B Tracerco Chemical Tracer 2-Bromonaphthalene 580-13-2 100 0.0000104983 1.1023100000T-772 Tracerco Chemical Tracer 2-(Trifluoromethyl)Benzophenone 727-99-1 100 0.0000041993 0.4409240000T-734 Tracerco Chemical Tracer 1-Bromo-2-(trifluoromethyl)benzene 392-83-6 100 0.0000062990 0.6613860000T-706 Tracerco Chemical Tracer 1-Bromo-4-chlorobenzen 106-39-8 100 0.0000209965 2.2046200000T-161B Tracerco Chemical Tracer 4-Iodotoluene 624-31-7 100 0.0000041993 0.4409240000T-769TracercoChemical Tracer4-Fluorobenzophenone345-83-51000.00001049831.1023100000T-731 Tracerco Chemical Tracer 1-Bromo-3,5-dichlorobenzene 19752-55-7 100 0.0000041993 0.4409240000T-716 Tracerco Chemical Tracer 1,3,5-Tribromobenzene 626-39-1 100 0.0002939513 30.8646800000T-719 Tracerco Chemical Tracer 3,4-Dichlorobenzophenone 6284-79-3 100 0.0002939513 30.8646800000T-721 Tracerco Chemical Tracer 4,4'-Dichlorobenzophenone 90-98-2 100 0.0002939513 30.8646800000Water Tracerco Carrier Fluid Water 7732-18-5 100 0.0007159814 75.1775420000T-803 Tracerco Chemical Tracer Sodium-4-chlorobenzoate 3686-66-6 100 0.0000073488 0.7716170000T-801 Tracerco Chemical Tracer Sodium-2-chlorobenzoate 17264-74-3 100 0.0000073488 0.7716170000T-955TracercoChemical TracerSodium-4-fluoro-2-(Trifluoromethyl)-benzoate1708942-22-61000.00000734880.7716170000T-190ATracercoChemical TracerSodium-2-(Trifluoromethyl) benzoate2966-44-11000.00000734880.7716170000T-804TracercoChemical TracerSodium-2,3-dichlorobenzoate118537-84-11000.00000734880.7716170000T-158CTracercoChemical TracerSodium-2,6-Difluorobenzoate6185-28-01000.00000734880.7716170000T-809TracercoChemical TracerSodium-3,5-dichlorobenzoate154862-40-51000.00000734880.7716170000T-926TracercoChemical TracerSodium-4-chloro-3-methylbenzoate1431868-21-11000.00000734880.7716170000T-140ATracercoChemical TracerSodium-2-fluorobenzoate490-97-11000.00000734880.7716170000T-911TracercoChemical TracerSodium-2-chloro-4-fluorobenzoate885471-43-11000.00000734880.7716170000T-805TracercoChemical TracerSodium-2,4-Dichlorobenzoate38402-11-81000.00000734880.7716170000Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)County:API Number:Operator Name: SantosWell Name and Number: NDBi-032Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco SLB-Private SLB-Private 11:57:15 13:20:35 14:43:55 16:07:15 17:30:35 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop ConStage 1 Stage 2 Stage 3 Stage 4 FracCAT* © Schlumberger 1994-2017 Santos NDB-32 4-7-2024 SLB-Private 12:36:42 12:57:32 13:18:22 13:39:12 14:00:02 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 1 4-7-2024 SLB-Private SLB-Private SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) Average Viscosity (cP) 13:42:29 13:54:59 14:07:29 14:19:59 14:32:29 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 2 4-7-2024 SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) Average Viscosity (cP) 14:21:56 14:38:36 14:55:16 15:11:56 15:28:36 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 3 4-7-2024 SLB-Private SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) Freeze Protect (bbl) 15:14:44 15:35:34 15:56:24 16:17:14 16:38:04 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 4 4-7-2024 SLB-Private SLB-Private SLB-Private SLB-Private FracCAT Treatment Report Well : NDB-32, Stages 5 and 6 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : 4/10/2024 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 330 Initial BHP at Gauge (psi) 1,972 Final Surface ISIP (psi) 1,039 Final ISIP at Gauge (psi) 2,907 Surface Shut in Pressure(psi) 750 BH Shut in Pressure (psi) 2,467 Maximum Treating Pressure (psi) 5,287 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 5,329.3 Total Proppant Pumped per load tickets (lb) 567,034 Total YF125ST Past Wellhead (bbl) 4,266.6 Total Proppant in Formation per load tickets (lb) 567,034 Total WF125 Past Wellhead (bbl) 430.6 Total SG IV blend (lb) 551,034 Total Freeze Protect Past Wellhead (bbl) 47.2 Total Carbolite 40/70 (lb) 16,000 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 198 197 M275 (lb) 114 88 J450 (gal) 100 100 J753 (gal) 11 11 J580 (lb) 5,035 5,002 J475 (lb) 1,210 1,206 J532 (gal) 453 453 J134 (lb) 3 0 J511 (lb) 321 321 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-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Summary On April 10, 2024 SLB performed a hydraulic fracturing treatment on Stages 5 and 6 of NBD-32. The design called for the completion of stages 5- 7, but due to problems with the POD IVs hydraulic system the job was shutdown right after the sleeve was shifted for Stage 7. Stage 5 consisted of a Pad, 1PPA scour, 3 PPA scour 1, 2, 4, 6, 8, 10 and 12 PPA stages. Stage 2 consisted of a Pad, 1, 2, 4, 6, 8, 10 and 12 PPA stages. Pump trips were staggered from 7,800 to 8,000 psi. The popoff was initially set to 8,300 psi. A summary of the job and individual stages is below. Summary of Stages 5-6 Material Actual Design Slurry Volume (bbl) 5,329.3 3,936 Clean Fluid Volume(bbl) 4,697.2 3,370 Proppant (lb) 567,034 535,575 15:04:20 15:54:20 16:44:20 17:34:20 18:24:20 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 3 6 9 12 15 18 21 24 27 30 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Stage 5 Stage 6 Shut down Due to Lost Suction Shutdown Due to POD IV Hydraulics Main Treatment © Schlumberger 1994-2017 SantosNDB-3204-10-2024 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 5 Initial treating pressure on PAD was around 3,100 psi and slowly fell to about 2,400 psi once 2 PPA was going into formation. At this point, the treating pressure gradually increased to 4,675 psi once sand was cut on surface. Slurry rate remained steady at 40bpm until rate was slowed for the collet to seat. A summary of the Stage and its measured pump schedule is below: 14:21:29 14:50:39 15:19:49 15:48:59 16:18:09 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 3 6 9 12 15 18 21 24 27 30 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Drop rate to Seat Collet Shift Sleeve Pumping Ball to Seat Main Treatment © Schlumberger 1994-2017 SantosNDB-32, Stage 504-10-2024 Summary of Pressures When Collet Seats Collet #6 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 2,064 2,751 5,287 Bottomhole Pressure 3,480 3,473 6,528 Summary of Stage 5 Total Proppant Pumped (lb) 294,786 Max pumping Rate (bpm) 41.1 Total Proppant in Formation (lb) 294,786 Average Pumping Rate (bpm) 36.5 Total CarboLite 40/70 16,000 Maximum Treating Pressure (psi) 4,655 Total CarboLite 16/20- 4% SG 278,786 Average Treating Pressure (psi) 2,896 Total Slurry Pumped (bbl) 2,254.4 Average Water Temperature (F)100 YF125ST Pumped (bbl) 1,752.2 WF125 Pumped (bbl)205.6 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States As Measured Pump Schedule 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 FP 40.1 3.9 10.6 WF125 1685 0.0 0.0 0 2 Pump Ball 165.7 4.9 39.0 WF125 6950 0.0 0.0 0 3 XL Check 13.7 16.0 0.9 YF125ST 573 0.0 0.0 0 4 PAD 325.0 39.2 8.3 YF125ST 13635 0.0 0.0 0 5 1.0 PPA 59.5 39.9 1.5 YF125ST 2405 CarboLite 40/70 1.2 0.9 2162 6 3.0 PPA 120.0 40.0 3.0 YF125ST 4474 CarboLite 40/70 3.2 2.9 13838 7 Resume PAD 75.0 40.0 1.9 YF125ST 3115 0.0 0.0 0 8 1.0 PPA 179.5 39.9 4.5 YF125ST 7241 CarboLite 16/20- 4% SG 1.0 0.9 7073 9 2.0 PPA 200.1 40.1 5.0 YF125ST 7740 CarboLite 16/20- 4% SG 2.1 2.0 15741 10 4.0 PPA 219.7 40.0 5.5 YF125ST 7876 CarboLite 16/20- 4% SG 4.1 3.9 32059 11 6.0 PPA 219.7 39.9 5.5 YF125ST 7327 CarboLite 16/20- 4% SG 6.1 5.9 45067 12 8.0 PPA 218.7 40.0 5.5 YF125ST 6818 CarboLite 16/20- 4% SG 8.2 7.9 56148 13 10.0 PPA 198.4 39.9 5.0 YF125ST 5813 CarboLite 16/20- 4% SG 10.2 9.9 59774 14 12.0 PPA 176.6 39.7 4.4 YF125ST 4879 CarboLite 16/20- 4% SG 12.5 11.9 62923 15 Spacer 39.7 40.4 1.0 YF125ST 1570 0.0 0.0 0 16 Drop Collet 3.0 40.3 0.1 YF125ST 127 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 Displace FP 3.9 4.1 1503 1570 334 2 Pump Ball 4.9 16.0 1394 1854 664 3 XL Check 16.0 16.0 1818 1904 1808 4 PAD 39.2 41.1 2855 3049 1973 5 1.0 PPA 39.9 40.4 2689 2733 2650 6 3.0 PPA 40.0 40.3 2574 2660 2467 7 Resume PAD 40.0 40.4 2513 2582 2467 8 1.0 PPA 39.9 40.2 2519 2660 2431 9 2.0 PPA 40.1 40.2 2413 2449 2376 10 4.0 PPA 40.0 40.3 2436 2527 2371 11 6.0 PPA 39.9 40.4 2760 3003 2527 12 8.0 PPA 40.0 40.3 3480 3886 3003 13 10.0 PPA 39.9 40.4 4085 4358 3841 14 12.0 PPA 39.7 40.3 4459 4655 4344 15 Spacer 40.4 40.9 4535 4655 4312 16 Drop Collet 40.3 40.3 4330 4369 4312 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other 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 12:21:32 Good Check Valve 4239 18 0.0 0.0 0.0 2 12:45:53 Good PT 41 23 0.0 0.0 0.0 3 13:00:59 PJSM 46 27 0.0 0.0 0.0 4 14:05:50 Open Well 366 2989 0.0 0.0 0.0 5 14:06:39 Start Displace FP Automatically 334 2980 0.0 0.0 0.0 6 14:06:39 Start Propped Frac Automatically 334 2980 0.0 0.0 0.0 7 14:06:39 Start Stage 5 Automatically 334 2980 0.0 0.0 0.0 8 14:06:44 Started Pumping 334 2980 0.0 0.0 0.0 9 14:07:10 Activated Extend Stage 1176 3012 0.7 3.7 0.0 10 14:29:19 Deactivated Extend Stage 659 2971 40.1 0.0 0.0 11 14:29:19 Start Pump Ball Manually 659 2971 40.1 0.0 0.0 12 14:31:58 Activated Extend Stage 1520 3012 50.2 4.0 0.0 13 15:02:40 Stage at Perfs: Displace FP 1328 3310 170.9 4.0 0.0 14 15:08:40 Deactivated Extend Stage 1822 3397 205.9 16.0 0.0 15 15:08:40 Start XL Check Manually 1822 3397 205.9 16.0 0.0 16 15:09:01 Stage at Perfs: XL Check 1813 3401 211.5 16.0 0.0 17 15:09:15 Activated Extend Stage 1808 3406 215.2 16.0 0.0 18 15:09:31 Deactivated Extend Stage 2138 3333 219.5 18.2 0.0 19 15:09:31 Start PAD Manually 2138 3333 219.5 18.2 0.0 20 15:13:41 Stage at Perfs: PAD 2861 3314 377.9 39.8 0.0 21 15:14:01 Stage at Perfs: PAD 2847 3305 391.2 40.0 0.0 22 15:17:52 Start 1.0 PPA Automatically 2728 3378 545.1 40.1 0.0 23 15:17:52 Started Pumping Prop 2728 3378 545.1 40.1 0.0 24 15:19:21 Start 3.0 PPA Automatically 2655 3250 604.2 40.4 1.0 25 15:20:15 Activated Extend Stage 2618 3291 640.1 40.0 3.0 26 15:22:10 Stage at Perfs: 3.0 PPA 2476 3360 716.8 39.2 3.0 27 15:22:21 Deactivated Extend Stage 2467 3365 724.0 39.5 3.0 28 15:22:21 Start Resume PAD Manually 2467 3365 724.0 39.5 3.0 29 15:22:41 Stopped Pumping Prop 2463 3378 737.3 40.2 0.0 30 15:23:39 Stage at Perfs: Resume PAD 2550 3410 776.1 40.1 0.0 31 15:24:14 Start 1.0 PPA Automatically 2591 3246 799.4 40.0 0.0 32 15:24:14 Started Pumping Prop 2591 3246 799.4 40.0 0.0 33 15:26:39 Stage at Perfs: 1.0 PPA 2463 3342 895.7 40.1 1.0 34 15:28:32 Stage at Perfs: 1.0 PPA 2449 3392 971.2 39.8 1.0 35 15:28:44 Start 2.0 PPA Automatically 2435 3397 979.2 40.1 1.0 36 15:33:01 Stage at Perfs: 2.0 PPA 2417 3291 1150.8 40.2 1.9 37 15:33:43 Start 4.0 PPA Automatically 2431 3305 1178.8 40.1 2.0 38 15:38:01 Stage at Perfs: 4.0 PPA 2472 3378 1350.8 40.1 4.0 39 15:39:13 Start 6.0 PPA Automatically 2527 3378 1398.7 40.1 4.0 40 15:43:31 Stage at Perfs: 6.0 PPA 2911 3323 1570.4 40.0 6.0 41 15:44:43 Start 8.0 PPA Automatically 3007 3342 1618.2 39.7 6.0 42 15:49:01 Stage at Perfs: 8.0 PPA 3777 3392 1790.1 40.2 7.9 43 15:50:12 Start 10.0 PPA Automatically 3886 3246 1837.3 40.0 8.0 44 15:54:30 Stage at Perfs: 10.0 PPA 4312 3282 2008.9 40.2 10.0 45 15:55:10 Start 12.0 PPA Automatically 4349 3287 2035.7 39.9 10.3 46 15:55:58 Activated Extend Stage 4275 3282 2067.8 39.8 12.4 47 15:59:29 Stage at Perfs: 12.0 PPA 4665 3296 2207.2 39.8 11.7 48 15:59:36 Deactivated Extend Stage 4646 3296 2211.8 39.8 12.1 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 49 15:59:36 Start Spacer Manually 4646 3296 2211.8 39.8 12.1 50 15:59:50 Activated Extend Stage 4655 3296 2221.1 40.6 0.9 51 16:00:35 Deactivated Extend Stage 4390 3296 2251.6 40.3 -0.1 52 16:00:35 Start Drop Collet Manually 4390 3296 2251.6 40.3 -0.1 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 6 As expected, the transition from Stage 5 to 6 went very well. The 1PPA and 2PPA steps started well, but towards the end of the 2PPA step, the PCM lost suction pressure. This was the result of a miscommunication on the tank swap, and Tank 13 was allowed to empty causing the c-pump on the PCM to lose prime. As a result, sand was cut and the stage was stopped. When examining the published viscosity, the value appears to drop sharply. This is a direct result of the fluid velocity of the fluid going through the c-pump and mixing gel after losing prime. Immediately before the incident, a linear gel sample was taken and the gel tested at 25#. This 25# gel was in the rear compartment of the PCM and is what was being pumped downhole. The front 4 compartments were used to mix gel and the viscometer is measuring viscosity of the fluid going through tank 5. This is evident once the new gel started to move to the rear of the PCM. A value of 18.5 was the published viscosity. Prior to the job, the viscometer was reset to indicate that a value of 19 would represent 25# gel. After the shutdown, chemical additive quantities were evaluated and an additional amount of J753 was mixed. In addition, alterations were made to the concentration of J511. It was decreased from 2 gpt to 1.8 gpt. Once the additive amounts were verified, the stage was started from the beginning of the design. The stage treated very well with pressures initially falling sharply to 2,500 psi and then gradually decreasing to about 2,230 psi once 2PPA was going into formation. Pressure then increased over time to about 4,700 psi and fell once rate was lowered to seat the collet. During the 12PPA step, the road side hydraulics of the POD IV started to surge. At this point, the decision was made to shift the sleeve and shutdown to evaluate the problem. Without knowing the cause of the problem, the decision was made to stop the job and begin the post job clean up. Before the cleanup, a 225 bbl injection test was pumped to evaluate Stage 7. The POD IV will be sent back to the SLB yard for evaluation and the SuperPOD will be brought to location to continue operations. Moving forward, the plan is to pump Stages 7 and 8 on April 12, 2024. A summary of the Stage and its measured pump schedule is below: 16:03:40 16:53:40 17:43:40 18:33:40 19:23:40 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 3 6 9 12 15 18 21 24 27 30 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Drop rate to Seat Collet Shift Sleeve Shutdown Due to Tanks Shutdown Due to POD Injection Test Main Treatment © Schlumberger 1994-2017 Santos NDB-32, Stage 604-10-2024 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Summary of Pressures When Collet Seats Collet #7 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 1,913 1,824 1,867 Bottomhole Pressure 3,374 3,320 3,328 Summary of Stage 6 Total Proppant Pumped (lb) 272,248 Max pumping Rate (bpm) 40.5 Total Proppant in Formation (lb) 272,248 Average Pumping Rate (bpm) 38.1 Total Slurry Pumped (bbl) 3,074.9 Maximum Treating Pressure (psi) 5,287 YF125ST Pumped (bbl) 2,514.4 Average Treating Pressure (psi) 2,896 WF125 Pumped (bbl)225 Average Water Temperature (F)100 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States As Measured Pump Schedule 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 117.0 40.0 2.9 YF125ST 4933 -0.1 0.0 0 2 Slow for Seat 50.0 19.9 2.6 YF125ST 2111 0.0 0.0 0 3 PAD 226.6 37.1 6.4 YF125ST 9504 0.0 0.0 0 4 1.0 PPA 204.3 36.7 6.2 YF125ST 8278 CarboLite 16/20- 4% SG 1.1 0.9 7723 5 PAD 17.2 21.6 0.8 YF125ST 721 -0.2 0.0 0 6 1.0 PPA 62.4 36.4 1.7 YF125ST 2524 CarboLite 16/20- 4% SG 1.0 0.8 1975 7 2.0 PPA 142.9 40.0 3.6 YF125ST 5533 CarboLite 16/20- 4% SG 2.0 1.9 11683 8 PAD 305.1 34.5 10.7 YF125ST 12810 0.0 0.0 0 9 PAD 148.0 38.2 4.0 YF125ST 6199 0.0 0.0 0 10 1.0 PPA 175.4 39.9 4.4 YF125ST 7071 CarboLite 16/20- 4% SG 1.0 0.9 6952 11 2.0 PPA 190.3 40.0 4.8 YF125ST 7363 CarboLite 16/20- 4% SG 2.1 2.0 14924 12 4.0 PPA 209.2 40.0 5.2 YF125ST 7500 CarboLite 16/20- 4% SG 4.2 3.9 30437 13 6.0 PPA 209.6 40.0 5.2 YF125ST 6994 CarboLite 16/20- 4% SG 6.1 5.9 42867 14 8.0 PPA 209.3 39.9 5.2 YF125ST 6528 CarboLite 16/20- 4% SG 8.4 7.9 53630 15 10.0 PPA 189.8 40.0 4.7 YF125ST 5560 CarboLite 16/20- 4% SG 10.3 9.9 57162 16 12.0 PPA 130.1 39.8 3.3 YF125ST 3637 CarboLite 16/20- 4% SG 12.2 11.5 44896 17 Spacer 37.5 40.2 0.9 YF125ST 1521 0.0 0.0 0 18 Drop Collet 3.0 39.8 0.1 YF125ST 126 0.0 0.0 0 19 PAD 109.0 40.1 2.7 YF125ST 4582 0.0 0.0 0 20 Slow for Seat 50.0 20.0 2.6 YF125ST 2110 0.0 0.0 0 21 Injection Test 225.0 35.2 7.1 WF125 9449 0.0 0.0 0 22 FP 63.2 19.6 3.7 Freeze Protect 2582 0.0 0.0 0 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States 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 40.0 40.2 3748 4445 2118 2 Slow for Seat 19.9 38.3 3094 5287 1872 3 PAD 37.1 40.4 3137 5127 2545 4 1.0 PPA 36.7 40.1 2312 2550 838 5 PAD 21.6 24.8 2052 2206 1772 6 1.0 PPA 36.4 40.1 2428 2499 1932 7 2.0 PPA 40.0 40.2 2333 2449 2280 8 PAD 34.5 40.4 2297 2495 604 9 PAD 38.2 40.3 2860 3616 1868 10 1.0 PPA 39.9 40.2 2411 2509 2353 11 2.0 PPA 40.0 40.2 2286 2353 2248 12 4.0 PPA 40.0 40.2 2293 2394 2220 13 6.0 PPA 40.0 40.3 2732 3105 2394 14 8.0 PPA 39.9 40.2 3498 3891 3099 15 10.0 PPA 40.0 40.3 4137 4449 3882 16 12.0 PPA 39.8 40.0 4513 4633 4449 17 Spacer 40.2 40.5 4329 4660 4106 18 Drop Collet 39.8 39.8 4144 4191 4120 19 PAD 40.1 40.3 3585 4216 2001 20 Slow for Seat 20.0 37.6 1870 1918 1762 21 PAD 35.2 40.0 2308 2518 595 22 FP 19.6 20.3 1777 2023 5 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other 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 16:00:40 Start PAD Automatically 4454 3300 0.0 40.1 -0.1 2 16:00:40 Start Propped Frac Automatically 4454 3300 0.0 40.1 -0.1 3 16:00:40 Start Stage 6 Automatically 4454 3300 0.0 40.1 -0.1 4 16:02:33 Stopped Pumping Prop 3625 3319 75.3 39.9 -0.1 5 16:03:36 Start Slow for Sea Automatically 1772 3282 117.0 30.0 0.0 6 16:04:06 Stage at Perfs: Drop Collet 2023 3300 127.5 18.7 0.0 7 16:06:14 Start PAD Automatically 5113 3250 166.8 18.1 0.0 8 16:06:16 Stage at Perfs: PAD 5104 3255 167.4 18.1 0.0 9 16:06:27 Stage at Perfs: Slow for Sea 5040 3255 170.7 18.2 0.0 10 16:07:40 Activated Extend Stage 3950 3218 195.4 28.3 0.0 11 16:09:51 Stage at Perfs: PAD 2856 3223 280.5 40.2 0.0 12 16:11:06 Stage At Perfs 2650 3246 330.6 40.0 0.0 13 16:12:40 Deactivated Extend Stage 2550 3273 393.3 39.9 0.0 14 16:12:40 Start 1.0 PPA Manually 2550 3273 393.3 39.9 0.0 15 16:12:42 Started Pumping Prop 2541 3278 394.6 39.9 0.0 16 16:13:17 Activated Extend Stage 2490 3282 417.7 39.3 1.0 17 16:16:48 Stage At Perfs 1913 3319 556.9 33.5 1.1 18 16:18:50 Deactivated Extend Stage 1927 3314 597.6 14.9 -0.2 19 16:18:50 Start PAD Manually 1927 3314 597.6 14.9 -0.2 20 16:19:06 Stopped Pumping Prop 2119 3310 602.6 23.2 -0.2 21 16:19:38 Start 1.0 PPA Manually 2270 3328 614.8 18.6 0.0 22 16:19:43 Started Pumping Prop 2138 3291 616.4 21.2 0.0 23 16:21:22 Start 2.0 PPA Manually 2449 3328 677.2 40.0 1.0 24 16:23:28 Stage at Perfs: 1.0 PPA 2289 3333 761.3 40.1 2.0 25 16:23:54 Stage at Perfs: PAD 2298 3333 778.7 40.1 2.0 26 16:24:56 Start PAD Manually 2316 3333 820.1 39.9 2.0 27 16:25:24 Stopped Pumping Prop 2348 3333 838.9 40.2 -0.1 28 16:25:27 Stage at Perfs: 1.0 PPA 2330 3328 840.9 40.3 0.0 29 16:28:03 Activated Extend Stage 2467 3342 944.9 39.3 0.0 30 16:29:01 Stage at Perfs: 1.0 PPA 2431 3355 983.5 40.2 0.0 31 17:16:35 Deactivated Extend Stage 1868 2975 1125.2 16.0 0.0 32 17:16:35 Start PAD Manually 1868 2975 1125.2 16.0 0.0 33 17:20:34 Start 1.0 PPA Automatically 2513 3131 1273.7 40.1 0.0 34 17:20:40 Started Pumping Prop 2463 3131 1277.7 40.0 0.0 35 17:20:57 Stage at Perfs: 1.0 PPA 2435 3140 1289.0 39.5 0.9 36 17:24:40 Stage at Perfs: PAD 2362 3264 1437.4 40.0 1.0 37 17:24:57 Start 2.0 PPA Automatically 2344 3273 1448.8 40.2 1.0 38 17:29:02 Stage at Perfs: 1.0 PPA 2298 3360 1612.2 40.0 2.0 39 17:29:43 Start 4.0 PPA Automatically 2289 3264 1639.5 40.1 2.0 40 17:33:48 Stage at Perfs: 2.0 PPA 2339 3328 1803.0 40.1 4.0 41 17:34:56 Start 6.0 PPA Automatically 2399 3278 1848.2 40.2 3.9 42 17:39:02 Stage at Perfs: PAD 2998 3246 2012.2 40.0 5.9 43 17:40:11 Start 8.0 PPA Automatically 3113 3236 2058.1 40.0 6.0 44 17:44:17 Stage at Perfs: PAD 3813 3227 2221.6 40.0 8.1 45 17:45:26 Start 10.0 PPA Automatically 3886 3218 2267.5 40.0 7.8 46 17:49:32 Stage at Perfs: 1.0 PPA 4395 3186 2431.4 39.8 9.7 47 17:50:10 Start 12.0 PPA Automatically 4459 3177 2456.7 40.0 9.9 48 17:52:18 Activated Extend Stage 4546 3154 2541.7 39.8 11.7 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 49 17:53:26 Deactivated Extend Stage 4665 3140 2586.7 40.2 4.3 50 17:53:26 Start Spacer Manually 4665 3140 2586.7 40.2 4.3 51 17:53:37 Activated Extend Stage 4395 3131 2594.2 40.1 2.4 52 17:54:04 Stopped Pumping Prop 4138 3131 2612.3 40.0 -0.1 53 17:54:16 Stage at Perfs: 2.0 PPA 4124 3127 2620.3 39.9 0.0 54 17:54:22 Deactivated Extend Stage 4216 3136 2624.2 40.0 0.0 55 17:54:22 Start Drop Collet Manually 4216 3136 2624.2 40.0 0.0 56 17:54:27 Start PAD Automatically 4266 3131 0.0 39.9 0.0 57 17:54:27 Start Propped Frac Automatically 4266 3131 0.0 39.9 0.0 58 17:54:27 Start Stage 7 Automatically 4266 3131 0.0 39.9 0.0 59 17:57:11 Start Slow for Sea Automatically 1593 3090 109.1 30.8 0.0 60 17:59:48 Start PAD Automatically 1845 3117 158.8 19.1 0.0 61 18:41:44 Activated Extend Stage 595 2724 174.8 0.0 0.0 62 18:48:09 Start FP Manually 1666 2971 383.7 20.3 0.0 63 19:21:44 Well Shut 774 2586 443.4 0.0 0.0 SLB-Private SLB-Private 15:05:02 15:55:02 16:45:02 17:35:02 18:25:02 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Stage 7 Stage 8 Main Treatment © Schlumberger 1994-2017 SantosNDB-3204-12-2024 SLB-Private 15:54:00 16:10:40 16:27:20 16:44:00 17:00:40 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT Generator Shut Off FracCAT Generator Online Slow to Launch Ball Shift Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32 Stage 7 04-12-2024 SLB-Private SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) 16:47:02 17:03:42 17:20:22 17:37:02 17:53:42 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Shutdown Slow to Launch Ball Shift Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32 Stage 8 04-12-2024 SLB-Private SLB-Private 09:12:33 10:19:13 11:25:53 12:32:33 13:39:13 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Stage 9 Stage 10 Stage 11 Main Treatment © Schlumberger 1994-2017 SantosNDB-32 04-15-2024 09:42:16 10:11:26 10:40:36 11:09:46 11:38:56 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Slow for Seat Open Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stages 9 4/15/2024 Average Water Temperature (F) 11:27:35 11:44:15 12:00:55 12:17:35 12:34:15 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Slow for Seat Open Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stages 10 4/15/2024 Average Water Temperature (F) 12:22:43 12:43:33 13:04:23 13:25:13 13:46:03 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Swap to Diesel Close Well Shutdown Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stages 11 4/15/2024 Average Water Temperature (F) WF125 Pumped (bbl) Santos Definitive Survey Report14 September, 2023Design: NDB-032Santos NAD27 ConversionPikkaNDBNDB032NDB032 ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMap SystemGeo DatumProjectMap ZoneSystem DatumUS 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 PositionFromSiteLatitudeLongitudePosition UncertaintyNorthingEastingGrid ConvergenceNDBusftMap usftusft-0.59Slot Radius205,972,909.70423,383.567.070° 20' 10.138 N150° 37' 17.796 WWellWell PositionLongitudeLatitudeEastingNorthingusft/-/-Position UncertaintyusftusftusftGround Level:NDB-032usftusft0.00.05,972,751.32422,115.3522.8Wellhead Elevation:0.0usft0.570° 20' 8.452 N150° 37' 54.787 WWellboreDeclinationField StrengthnTSample Date Dip AngleNDB-032Model NameMagneticsBGGM2023 30/08/2023 14.56 80.59 57,187.32046450PhaseVersionAudit NotesDesignNDB-0321.0 ACTUALVertical SectionDepth From TVDusft/-usftDirection/-usftTie On Depth47.0320.630.00.047.014092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueFromusftSurvey ProgramDescriptionTool NameSurvey WellboreTousftDate14/09/2023SDI_KPR_ADK SDI Keeper ADK140.8 646.801 SDIGyro16in Hole 46646> NDB033_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag686.7 2,527.102 BH OntraK16in Hole 6862527> ND3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,623.1 6,244.903 BH OntraK1225in Hole 26236244> 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag6,317.5 12,349.204 BH AzitraKin Hole 631712349> MDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft47.0 0.00 0.00 47.0 -22.8 0.0 0.0 5,972,751.32 422,115.35 0.00 0.0128.0 0.06 70.41 128.0 58.2 0.0 0.0 5,972,751.33 422,115.39 0.07 0.020" Conductor140.8 0.07 70.41 140.8 71.0 0.0 0.1 5,972,751.34 422,115.40 0.07 0.0175.8 0.06 66.62 175.8 106.0 0.0 0.1 5,972,751.35 422,115.44 0.03 0.0267.8 0.08 19.09 267.8 198.0 0.1 0.2 5,972,751.43 422,115.51 0.06 0.0361.8 0.26 28.91 361.8 292.0 0.4 0.3 5,972,751.68 422,115.63 0.19 0.1456.8 0.56 34.91 456.8 387.0 0.9 0.7 5,972,752.24 422,116.01 0.32 0.3550.8 1.35 14.32 550.8 481.0 2.4 1.2 5,972,753.69 422,116.56 0.90 1.1646.8 3.10 355.95 646.7 576.9 6.1 1.3 5,972,757.37 422,116.70 1.95 3.9686.7 3.37 351.11 686.6 616.8 8.3 1.0 5,972,759.61 422,116.46 0.96 5.8757.9 4.04 346.97 757.6 687.8 12.8 0.1 5,972,764.13 422,115.62 1.01 9.8853.4 7.59 344.52 852.6 782.8 22.2 -2.3 5,972,773.51 422,113.28 3.72 18.6950.3 9.41 342.78 948.4 878.6 35.9 -6.4 5,972,787.28 422,109.37 1.90 31.81,039.0 10.06 342.52 1,035.8 966.0 50.2 -10.8 5,972,801.64 422,105.04 0.73 45.7Upper Schrader Bluff1,043.1 10.09 342.51 1,039.9 970.1 50.9 -11.0 5,972,802.33 422,104.83 0.73 46.41,130.0 10.51 340.07 1,125.4 1,055.6 65.6 -16.0 5,972,817.09 422,100.00 0.70 60.9Base Ice Bearing Permafrost1,137.5 10.55 339.87 1,132.7 1,062.9 66.9 -16.5 5,972,818.38 422,099.54 0.70 62.21,231.3 11.94 326.26 1,224.7 1,154.9 83.0 -24.9 5,972,834.60 422,091.36 3.18 80.014092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft1,325.1 14.43 309.52 1,316.21,246.498.6 -39.3 5,972,850.27 422,077.11 4.83 101.11,359.5 16.21 306.57 1,349.3 1,279.5 104.1 -46.4 5,972,855.92 422,070.02 5.66 109.91,389.4 17.87 304.60 1,377.8 1,308.0 109.2 -53.5 5,972,861.09 422,062.94 5.88 118.41,412.0 19.23 303.92 1,399.3 1,329.5 113.3 -59.5 5,972,865.20 422,057.03 6.10 125.3Base Permafrost Transition1,420.2 19.73 303.70 1,407.1 1,337.3 114.8 -61.8 5,972,866.75 422,054.77 6.10 127.91,454.3 21.99 301.28 1,438.9 1,369.1 121.3 -72.0 5,972,873.36 422,044.60 7.10 139.51,484.3 23.08 299.42 1,466.6 1,396.8 127.1 -81.9 5,972,879.26 422,034.75 4.35 150.21,516.1 24.24297.941,495.7 1,425.9 133.2 -93.1 5,972,885.50 422,023.62 4.10 162.11,609.4 27.88 294.70 1,579.5 1,509.7 151.3 -129.9 5,972,903.98 421,987.05 4.19 199.41,704.1 32.48 295.05 1,661.4 1,591.6 171.4 -173.1 5,972,924.46 421,944.06 4.86 242.31,800.5 36.60 297.70 1,740.8 1,671.0 195.7 -222.0 5,972,949.28 421,895.44 4.55 292.11,822.0 37.53 298.22 1,757.9 1,688.1 201.8 -233.4 5,972,955.48 421,884.05 4.56 304.1Middle Schrader Bluff1,895.9 40.74 299.87 1,815.3 1,745.5 224.4 -274.2 5,972,978.57 421,843.53 4.56 347.41,990.7 44.35 301.13 1,885.1 1,815.3 257.0 -329.4 5,973,011.69 421,788.65 3.91 407.62,085.2 48.36 301.22 1,950.3 1,880.5 292.4 -387.9 5,973,047.66 421,730.57 4.25 472.12,179.4 49.12 302.12 2,012.4 1,942.6 329.5 -448.1 5,973,085.46 421,670.71 1.08 539.02,274.6 50.24 301.33 2,074.0 2,004.2 367.7 -509.9 5,973,124.28 421,609.35 1.34 607.72,369.2 50.58 300.59 2,134.3 2,064.5 405.2-572.45,973,162.44 421,547.21 0.70 676.42,390.0 50.56 300.50 2,147.5 2,077.7 413.4 -586.2 5,973,170.72 421,533.49 0.35 691.4MCU2,463.9 50.48 300.18 2,194.5 2,124.7 442.2 -635.5 5,973,200.04 421,484.57 0.35 744.92,527.1 50.31 300.18 2,234.8 2,165.0 466.7 -677.6 5,973,224.98 421,442.70 0.27 790.62,588.0 50.04 300.64 2,273.8 2,204.0 490.3 -717.9 5,973,249.05 421,402.65 0.73 834.513-3/8" Surface Casing2,623.1 49.89 300.91 2,296.4 2,226.6 504.1 -741.0 5,973,263.05 421,379.69 0.73 859.82,648.9 50.28 300.74 2,312.9 2,243.1 514.2 -758.0 5,973,273.36 421,362.81 1.59 878.414092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft2,743.2 50.31 300.59 2,373.22,303.4551.3 -820.4 5,973,311.01 421,300.78 0.13 946.62,838.2 50.37 299.95 2,433.8 2,364.0 588.1 -883.6 5,973,348.52 421,238.03 0.52 1,015.12,867.0 50.33 299.70 2,452.22,382.4599.1 -902.8 5,973,359.74 421,218.92 0.69 1,035.8Tuluvak Shale2,932.8 50.24 299.12 2,494.22,424.4624.0 -946.9 5,973,385.06 421,175.07 0.69 1,083.12,934.0 50.23 299.11 2,495.0 2,425.2 624.4 -947.7 5,973,385.50 421,174.29 1.10 1,083.9Tuluvak Sand3,026.9 49.38 298.36 2,555.0 2,485.2 658.6 -1,009.9 5,973,420.27 421,112.43 1.10 1,149.73,121.0 49.20298.942,616.3 2,546.5 692.7 -1,072.5 5,973,455.09 421,050.23 0.51 1,215.93,217.3 48.25 298.26 2,679.9 2,610.1 727.4 -1,136.0 5,973,490.41 420,987.03 1.12 1,283.03,311.7 47.28 297.93 2,743.3 2,673.5 760.3 -1,197.7 5,973,523.97 420,925.70 1.06 1,347.63,406.7 46.66 298.38 2,808.1 2,738.3 793.1 -1,258.9 5,973,557.35 420,864.86 0.74 1,411.73,501.2 46.71 299.69 2,873.0 2,803.2 826.5 -1,319.0 5,973,591.35 420,805.08 1.01 1,475.63,596.5 46.71 299.89 2,938.3 2,868.5 860.9 -1,379.3 5,973,626.44 420,745.24 0.15 1,540.53,691.446.78 300.22 3,003.3 2,933.5 895.5 -1,439.1 5,973,661.66 420,685.79 0.26 1,605.23,785.0 46.71 300.76 3,067.5 2,997.7 930.1 -1,497.8 5,973,696.85 420,627.43 0.43 1,669.23,880.0 45.98 300.86 3,133.0 3,063.2 965.3 -1,556.8 5,973,732.65 420,568.78 0.77 1,733.83,940.0 45.95 300.71 3,174.8 3,105.0 987.4 -1,593.9 5,973,755.12 420,531.94 0.19 1,774.4Seabee3,974.445.94 300.62 3,198.7 3,128.9 1,000.0 -1,615.1 5,973,767.95 420,510.82 0.19 1,797.64,069.5 45.99 300.52 3,264.8 3,195.0 1,034.8 -1,674.0 5,973,803.33 420,452.31 0.09 1,861.94,164.5 45.96 300.40 3,330.8 3,261.0 1,069.4 -1,732.9 5,973,838.58 420,393.78 0.10 1,926.04,259.3 45.96 299.17 3,396.7 3,326.9 1,103.2 -1,792.0 5,973,873.01 420,335.04 0.93 1,989.74,354.0 45.94 299.12 3,462.5 3,392.7 1,136.4 -1,851.5 5,973,906.78 420,275.94 0.04 2,053.04,450.0 46.13 299.59 3,529.2 3,459.4 1,170.3 -1,911.7 5,973,941.27 420,216.07 0.40 2,117.44,544.2 46.19 299.96 3,594.4 3,524.6 1,204.0 -1,970.7 5,973,975.61 420,157.47 0.29 2,180.94,638.5 46.21 300.56 3,659.7 3,589.9 1,238.3 -2,029.5 5,974,010.54 420,099.02 0.46 2,244.74,733.8 47.37 303.65 3,724.9 3,655.1 1,275.2 -2,088.3 5,974,048.04 420,040.63 2.66 2,310.514092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft4,828.7 49.58 305.40 3,787.9 3,718.1 1,315.5 -2,146.8 5,974,088.93 419,982.52 2.71 2,378.84,922.7 52.11 306.78 3,847.3 3,777.5 1,358.5 -2,205.7 5,974,132.51 419,924.05 2.92 2,449.44,952.0 52.80 306.99 3,865.1 3,795.3 1,372.4 -2,224.3 5,974,146.62 419,905.65 2.44 2,471.9Nanushuk4,974.0 53.33307.143,878.3 3,808.5 1,383.0 -2,238.3 5,974,157.37 419,891.73 2.44 2,489.0NT8 MFS5,017.9 54.37 307.44 3,904.2 3,834.4 1,404.5 -2,266.5 5,974,179.13 419,863.76 2.44 2,523.55,021.0 54.44 307.48 3,906.0 3,836.2 1,406.0 -2,268.5 5,974,180.69 419,861.77 2.54 2,526.0NT7 MFS5,111.9 56.53 308.68 3,957.5 3,887.7 1,452.2 -2,327.4 5,974,227.48 419,803.33 2.54 2,599.15,140.0 57.12 309.18 3,972.9 3,903.1 1,467.0 -2,345.8 5,974,242.46 419,785.17 2.57 2,622.1NT6 MFS5,207.2 58.54 310.35 4,008.7 3,938.9 1,503.4 -2,389.5 5,974,279.30 419,741.83 2.57 2,678.05,249.0 59.60 310.95 4,030.23,960.41,526.7 -2,416.7 5,974,302.93 419,714.88 2.82 2,713.3NT5 MFS5,302.2 60.95 311.70 4,056.5 3,986.7 1,557.3 -2,451.4 5,974,333.81 419,680.49 2.82 2,758.95,390.0 63.53 313.97 4,097.4 4,027.6 1,610.1 -2,508.3 5,974,387.21 419,624.12 3.73 2,835.9NT4 MFS5,396.3 63.72 314.13 4,100.24,030.41,614.0 -2,512.4 5,974,391.15 419,620.13 3.73 2,841.45,491.3 66.10 316.28 4,140.5 4,070.7 1,675.1 -2,573.0 5,974,452.87 419,560.13 3.23 2,927.15,585.6 68.65 318.03 4,176.8 4,107.0 1,738.9 -2,632.2 5,974,517.30 419,501.62 3.20 3,014.05,680.2 71.17 319.44 4,209.3 4,139.5 1,805.7 -2,690.8 5,974,584.69 419,443.73 3.01 3,102.85,775.6 73.83 320.51 4,238.0 4,168.2 1,875.3 -2,749.2 5,974,654.90 419,386.00 2.99 3,193.75,870.4 76.24 321.22 4,262.5 4,192.7 1,946.4 -2,807.1 5,974,726.58 419,328.91 2.64 3,285.35,964.1 78.76 322.21 4,282.7 4,212.9 2,018.2 -2,863.7 5,974,798.96 419,272.99 2.88 3,376.86,058.7 81.26 322.80 4,299.1 4,229.3 2,092.1 -2,920.4 5,974,873.40 419,217.10 2.71 3,469.96,140.0 83.51 324.22 4,309.9 4,240.1 2,156.9 -2,968.3 5,974,938.68 419,169.86 3.26 3,550.3NT3 MFS6,152.9 83.87 324.44 4,311.3 4,241.5 2,167.3 -2,975.8 5,974,949.20 419,162.47 3.26 3,563.214092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft6,244.9 86.11 326.11 4,319.4 4,249.6 2,242.6 -3,028.0 5,975,025.02 419,111.08 3.03 3,654.56,283.0 86.83 326.63 4,321.7 4,251.9 2,274.2 -3,049.1 5,975,056.90 419,090.35 2.34 3,692.39-5/8" Intermediate Casing6,317.5 87.49 327.10 4,323.4 4,253.6 2,303.1 -3,067.9 5,975,085.94 419,071.82 2.34 3,726.66,412.9 89.92 328.25 4,325.6 4,255.8 2,383.7 -3,118.9 5,975,167.03 419,021.68 2.82 3,821.26,468.0 90.77 328.66 4,325.2 4,255.4 2,430.6 -3,147.7 5,975,214.30 418,993.34 1.72 3,875.8NT3.2 Top Reservoir6,507.9 91.39 328.96 4,324.5 4,254.7 2,464.8 -3,168.4 5,975,248.62 418,973.05 1.72 3,915.36,603.1 91.42 328.92 4,322.1 4,252.3 2,546.3 -3,217.5 5,975,330.69 418,924.77 0.05 4,009.56,697.9 91.45 328.42 4,319.8 4,250.0 2,627.3 -3,266.8 5,975,412.14 418,876.34 0.53 4,103.36,793.2 91.27 328.40 4,317.5 4,247.7 2,708.4 -3,316.7 5,975,493.75 418,827.31 0.19 4,197.76,888.5 91.30 328.04 4,315.4 4,245.6 2,789.4 -3,366.9 5,975,575.31 418,777.94 0.38 4,292.26,983.2 91.18 328.09 4,313.3 4,243.5 2,869.8 -3,416.9 5,975,656.15 418,728.72 0.14 4,386.07,079.1 91.24 328.52 4,311.3 4,241.5 2,951.3 -3,467.3 5,975,738.23 418,679.20 0.45 4,481.07,174.0 91.15 329.16 4,309.3 4,239.5 3,032.5 -3,516.4 5,975,819.87 418,630.99 0.68 4,574.97,267.6 91.15329.844,307.4 4,237.6 3,113.1 -3,563.9 5,975,900.99 418,584.33 0.73 4,667.47,363.2 91.21 329.79 4,305.5 4,235.7 3,195.8 -3,611.9 5,975,984.12 418,537.13 0.08 4,761.77,457.9 91.21 329.98 4,303.5 4,233.7 3,277.7 -3,659.4 5,976,066.50 418,490.48 0.20 4,855.27,554.0 91.24 330.30 4,301.4 4,231.6 3,361.0 -3,707.3 5,976,150.31 418,443.52 0.33 4,949.97,649.1 91.18 330.22 4,299.4 4,229.6 3,443.5 -3,754.4 5,976,233.33 418,397.23 0.11 5,043.77,743.7 91.18 330.12 4,297.5 4,227.7 3,525.6 -3,801.5 5,976,315.86 418,351.03 0.11 5,136.97,838.8 91.18 329.77 4,295.5 4,225.7 3,607.9 -3,849.1 5,976,398.65 418,304.27 0.37 5,230.87,934.2 91.21 330.13 4,293.5 4,223.7 3,690.4 -3,896.9 5,976,481.69 418,257.37 0.38 5,324.98,028.7 91.21 329.56 4,291.5 4,221.7 3,772.2 -3,944.4 5,976,563.91 418,210.74 0.60 5,418.28,123.5 91.21 329.26 4,289.5 4,219.7 3,853.8 -3,992.6 5,976,645.97 418,163.38 0.32 5,511.88,218.9 91.27 329.03 4,287.5 4,217.7 3,935.6 -4,041.5 5,976,728.34 418,115.32 0.25 5,606.28,314.3 91.18 328.81 4,285.4 4,215.6 4,017.3 -4,090.7 5,976,810.49 418,066.96 0.25 5,700.58,408.9 91.18 328.66 4,283.5 4,213.7 4,098.2 -4,139.8 5,976,891.88 418,018.69 0.16 5,794.214092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft8,503.2 91.18 328.81 4,281.5 4,211.7 4,178.8 -4,188.8 5,976,972.97 417,970.60 0.16 5,887.58,599.5 91.24 328.92 4,279.5 4,209.7 4,261.2 -4,238.5 5,977,055.89 417,921.68 0.13 5,982.88,692.8 91.21 328.82 4,277.5 4,207.7 4,341.0 -4,286.8 5,977,136.20 417,874.31 0.11 6,075.18,788.0 91.21 328.46 4,275.5 4,205.7 4,422.3 -4,336.3 5,977,217.99 417,825.62 0.38 6,169.48,883.4 91.21 328.42 4,273.5 4,203.7 4,503.6 -4,386.2 5,977,299.77 417,776.55 0.04 6,263.98,979.0 91.36 328.63 4,271.3 4,201.5 4,585.1 -4,436.1 5,977,381.77 417,727.51 0.27 6,358.59,073.8 91.36 328.83 4,269.1 4,199.3 4,666.0 -4,485.3 5,977,463.23 417,679.19 0.21 6,452.39,169.2 91.30329.244,266.9 4,197.1 4,747.8 -4,534.4 5,977,545.56 417,630.95 0.43 6,546.79,264.5 91.39 329.42 4,264.6 4,194.8 4,829.8 -4,582.9 5,977,627.95 417,583.23 0.21 6,640.89,360.0 91.33 329.30 4,262.4 4,192.6 4,911.9 -4,631.6 5,977,710.57 417,535.45 0.14 6,735.29,454.2 91.36 329.59 4,260.1 4,190.3 4,993.0 -4,679.5 5,977,792.22 417,488.38 0.31 6,828.39,550.0 91.36 329.54 4,257.9 4,188.1 5,075.6 -4,728.0 5,977,875.28 417,440.74 0.05 6,922.99,644.7 91.21 329.72 4,255.8 4,186.0 5,157.2 -4,775.9 5,977,957.40 417,393.75 0.25 7,016.49,739.8 91.21 329.65 4,253.7 4,183.9 5,239.3 -4,823.9 5,978,039.99 417,346.61 0.07 7,110.39,830.6 91.21 329.79 4,251.8 4,182.0 5,317.7 -4,869.6 5,978,118.82 417,301.67 0.15 7,199.99,926.7 91.21 329.75 4,249.8 4,180.0 5,400.7 -4,918.0 5,978,202.34 417,254.16 0.04 7,294.810,024.1 91.24 330.24 4,247.7 4,177.9 5,485.1 -4,966.7 5,978,287.19 417,206.33 0.50 7,390.910,118.3 91.21 330.08 4,245.7 4,175.9 5,566.8 -5,013.6 5,978,369.37 417,160.31 0.17 7,483.810,212.0 91.21 330.42 4,243.7 4,173.9 5,648.1 -5,060.0 5,978,451.11 417,114.72 0.36 7,576.110,307.7 91.21 330.15 4,241.7 4,171.9 5,731.2 -5,107.5 5,978,534.70 417,068.15 0.28 7,670.410,400.7 91.18 329.61 4,239.8 4,170.0 5,811.7 -5,154.2 5,978,615.66 417,022.30 0.58 7,762.210,500.2 91.30 329.15 4,237.6 4,167.8 5,897.2 -5,204.8 5,978,701.74 416,972.55 0.48 7,860.510,595.1 91.21 328.97 4,235.5 4,165.7 5,978.6 -5,253.6 5,978,783.60 416,924.63 0.21 7,954.410,690.6 91.21 328.91 4,233.5 4,163.7 6,060.4 -5,302.9 5,978,865.94 416,876.20 0.06 8,048.910,785.1 91.21 329.20 4,231.5 4,161.7 6,141.5 -5,351.4 5,978,947.46 416,828.46 0.31 8,142.310,879.7 91.21 329.36 4,229.5 4,159.7 6,222.7 -5,399.7 5,979,029.20 416,781.03 0.17 8,235.814092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft10,930.0 91.23 329.40 4,228.5 4,158.7 6,266.0 -5,425.4 5,979,072.76 416,755.86 0.08 8,285.5NT3.2410,975.7 91.24 329.43 4,227.5 4,157.7 6,305.4 -5,448.6 5,979,112.34 416,733.02 0.08 8,330.711,070.7 91.18 329.72 4,225.5 4,155.7 6,387.2 -5,496.7 5,979,194.70 416,685.79 0.31 8,424.511,165.491.21 329.36 4,223.5 4,153.7 6,468.8 -5,544.7 5,979,276.78 416,638.66 0.38 8,518.011,260.7 91.24 329.23 4,221.4 4,151.6 6,550.8 -5,593.4 5,979,359.27 416,590.82 0.14 8,612.311,355.9 91.24 329.06 4,219.4 4,149.6 6,632.5 -5,642.2 5,979,441.46 416,542.87 0.18 8,706.411,451.0 91.15 328.86 4,217.4 4,147.6 6,713.9 -5,691.2 5,979,523.37 416,494.73 0.23 8,800.411,546.1 91.27 328.80 4,215.4 4,145.6 6,795.3 -5,740.4 5,979,605.25 416,446.35 0.14 8,894.511,640.9 91.27 328.80 4,213.3 4,143.5 6,876.4 -5,789.5 5,979,686.83 416,398.10 0.00 8,988.411,735.9 91.21 329.04 4,211.2 4,141.4 6,957.7 -5,838.5 5,979,768.63 416,349.94 0.26 9,082.311,831.0 91.24 329.05 4,209.24,139.47,039.2 -5,887.4 5,979,850.67 416,301.89 0.03 9,176.411,926.0 91.24 329.23 4,207.2 4,137.4 7,120.8 -5,936.1 5,979,932.68 416,254.03 0.19 9,270.312,021.3 91.24 329.57 4,205.1 4,135.3 7,202.8 -5,984.6 5,980,015.18 416,206.39 0.36 9,364.412,112.5 91.27 329.78 4,203.1 4,133.3 7,281.5 -6,030.7 5,980,094.41 416,161.14 0.23 9,454.512,211.0 91.30 329.60 4,200.9 4,131.1 7,366.5 -6,080.4 5,980,179.91 416,112.34 0.19 9,551.812,306.6 91.21 329.94 4,198.8 4,129.0 7,449.1 -6,128.5 5,980,262.95 416,065.10 0.37 9,646.112,349.2 91.24329.844,197.9 4,128.1 7,485.9 -6,149.9 5,980,300.01 416,044.13 0.25 9,688.112,374.0 91.24329.844,197.3 4,127.5 7,507.4 -6,162.3 5,980,321.59 416,031.88 0.00 9,712.64-1/2" Production Casing12,381.0 91.24 329.84 4,197.2 4,127.4 7,513.4 -6,165.8 5,980,327.67 416,028.43 0.00 9,719.5TD Projection9-5/8" Intermediate Casing4,321.76,283.0 9-5/812-1/44-1/2" Production Casing4,197.312,374.0 4-1/2 8-1/220" Conductor128.0128.0 20 2013-3/8" Surface Casing2,273.82,588.0 13-3/8 1614092023 24124PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDB-032NDB-032Survey Calculation MethodMinimum CurvatureParker 272 As Drilled @ 69.8usftDesignNDB-032DatabaseEDM STO AlaskaMD ReferenceParker 272 As Drilled @ 69.8usftNorth ReferenceWell NDB032TrueMeasuredDepthusftVerticalDepthusftDipDirectionName LithologyDipFormations5,249.0 4,030.2 NT5 MFS4,974.0 3,878.3 NT8 MFS1,822.0 1,757.9 Middle Schrader Bluff6,140.0 4,309.9 NT3 MFS4,952.0 3,865.1 Nanushuk2,867.0 2,452.2 Tuluvak Shale2,390.0 2,147.5 MCU1,039.0 1,035.8 Upper Schrader Bluff6,468.0 4,325.2 NT3.2 Top Reservoir1,412.0 1,399.3 Base Permafrost Transition3,940.0 3,174.8 Seabee5,140.0 3,972.9 NT6 MFS5,390.0 4,097.4 NT4 MFS5,021.0 3,906.0 NT7 MFS2,934.0 2,495.0 Tuluvak Sand1,130.0 1,125.4 Base Ice Bearing Permafrost10,930.0 4,228.5 NT3.24MeasuredDepthusftVerticalDepthusft/-usft/-usftLocal CoordinatesCommentDesign Annotations12,381.0 4,197.2 -6,165.87,513.4 TD ProjectionApproved ByChecked ByDate14092023 24124PMCOMPASS 500017 Build 02 Page 10 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 12,381 feet N/A feet true vertical 4,197 feet N/A feet Effective Depth measured 12,374 feet See attached rpt feet true vertical 4,197 feet See attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6ppf P-110S 12,374' MD 4,197' TVD Packers and SSSV (type, measured and true vertical depth) See attached packer report 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Authorized Title: Completions Specialist Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone:907-- 323-616 Sr Pet Eng: 9210 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 MDSize 128' N/A 9-5/8" 11590 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-060 50-103-20860-00-00 900 E Benson Boulevard, Suite 500 Anchorage, AK 99508 3. Address: N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393020 Pikka / Nanushuk Oil Pool NDB-032 Plugs Junk measured Length 128' 2588' 128'Conductor Surface Intermediate 20"x34" 13-3/8" measured TVD Production Liner 6283' 6272' 6136' Casing Structural 4322' 4294' 4-1/2" 6283' 6157' 12374' 4197' 4750 9210 N/A 5020 6870 11590 2588' 2273' Burst Collapse N/A 2260 pppppppp kkkkk ft tttttt ntt e Fra O g g s g y 223 e 6.A y G L PG 25.070,2 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 07/08/2024 By Grace Christianson at 8:44 am, Jul 09, 2024 DSR-7/9/24 RBDMS JSB 071124 Page 1 of 1 Well Name: NDB-032 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 6,125.5 4,308.2 OH Packer #12 6,959.1 4,313.8 OH Packer #11 7,451.4 4,303.6 OH Packer #10 8,026.4 4,291.6 OH Packer #9 8,517.7 4,281.2 OH Packer #8 9,050.5 4,269.6 OH Packer #7 9,457.9 4,260.1 OH Packer #6 9,902.6 4,250.3 OH Packer #5 10,345.1 4,240.9 OH Packer #4 10,992.6 4,227.1 OH Packer #3 11,396.0 4,218.5 OH Packer #2 11,843.1 4,208.9 OH Packer #1 12,247.9 4,200.1 Frac Ops Summary Report - AOGCC Well Name NDB-032 Primary Job Type Fracture Treatment Start Date End Date Summary 4/3/2024 4/4/2024 MIRU Frac equipment. Load proppant. Fill and heat Frac tanks. 4/4/2024 4/5/2024 MIRU Frac equipment. Fill and heat Frac tanks. 4/5/2024 4/6/2024 RU Frac equipment. Fill and heat Frac tanks. 4/6/2024 4/7/2024 Prepare to Frac Stages 1-4 4/7/2024 4/8/2024 Frac Stages 1-4 Finish RU of Frac equipment, prime up, pressure test. Pump Freeze Protect fluid past wellhead with 40 bbls WF125. Pump Check with 250 bbls WF125 DataFrac: 241.7 bbls YF125ST and 207 bbls WF125 fluid at 40bpm. Frac stage 1: 2,439.4 bbls slurry (YF125ST fluid), 230,772 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 2,215.6 bbls clean fluid at 40bpm, as per design. Frac stage 2: 1,623.8 bbls slurry (YF125ST fluid), 250,780 lbs 16/20 Carbolite (1, 3, 5, 7, 9, 10ppa), 1,381.3 bbls clean fluid at 40bpm, as per design. Frac stage 3: 1,930.0 bbls slurry (YF125ST fluid), 15,941 lbs 40/70 Carbolite (1, 3ppa), 287,041 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10, 12ppa), 1,637.5 bbls clean fluid at 40bpm, as per design. Frac stage 4: 2,277.5 bbls slurry (YF125ST fluid), 16,059 lbs 40/70 Carbolite (1, 3ppa), 207,807 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10, 12ppa), 2,062.3 bbls clean fluid at 40bpm, as per design. TLTR (Stages 1-4) 7,995.4 bbls 4/8/2024 4/9/2024 Load proppant. Fill and heat Frac tanks. 4/9/2024 4/10/2024 Load proppant. Fill and heat Frac tanks. 4/10/2024 4/11/2024 Frac Stages 5-6 Finish RU of frac equipment and chemical/water testing. Frac stage 5: Pump ball down at 4bpm to start frac; 2,255bbls slurry (YF125ST fluid), 16,000 lbs 40/70 carbolite (1, 3ppa), 278,785lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 1,957bbs clean fluid at 40bpm as per design. Frac stage 6: 3,075bbls slurry (YF125ST fluid), 272,248lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 2,739bbs clean fluid at 40bpm; hydration unit lost prime on 1ppa step and had to lower rate and shutdown before recovery, pumped 1ppa and 2ppa and then flushed well to restart job and ensure good fluid, restarted the job and pumped as per design. Landed collet for stage 7 frac but were having trouble with discharge pressure on the blender. Attempted to diagnose and then made decision to flush well and continue frac after sand/water refill. Tracerco tracers pumped as per plan on stages (details in job time log on each stage). Well freeze protected with 63bbls (47bbls downhole and 16bbls surface lines). Total Load to Recover (TLTR) stage 5-6 4,745bbls Total Load to Recover for well 12,740bbls NPT on SLB until next frac day due to blender replacement. 4/11/2024 4/12/2024 Load proppant. Fill and heat Frac tanks. Page 1 of 2 Tracerco tracers pumped as per plan on stages (details in job time log on each stage). Frac Ops Summary Report - AOGCC Start Date End Date Summary 4/12/2024 4/13/2024 Frac Stages 7-8 Finish RU of frac equipment and chemical/water testing. Frac stage 7: Pump ball down at 4bpm to start frac, 2,184bbls slurry (YF125ST fluid), 188,078lbs 16/20 carbolite scaleguard (1, 2, 3, 4, 5, 6, 7ppa), 64,974lbs 12/18 carbolite (7, 8ppa), 1,928bbs clean fluid at 40bpm as per design. Frac stage 8: 2,070bbls slurry (YF125ST fluid), 234,111lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10ppa), 1,838bbs clean fluid at 40bpm as per design. Tracerco tracers pumped as per design (details in the job time log for each stage). Well freeze protected with 65bbls (49bbls downhole and 16bbls surface lines). Total Load to Recover (TLTR) stage 7-8 3,766bbls Total Load to Recover (TLTR) 16,506bbls 4/13/2024 4/14/2024 Load proppant. Fill and heat frac tanks. 4/14/2024 4/15/2024 Finish loading proppant and heating tanks. Complete fluid testing and spot chemicals/equipment in prep for frac. 4/15/2024 4/16/2024 Pump frac stages 9-11 Finish RU equipment, prime up and pressure test. Frac stage 9: Pump ball down at 4bpm to start frac; 2,094bbls slurry (YF125ST fluid), 12,343 lbs 40/70 carbolite (1, 3ppa), 256,750lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 1,826bbs clean fluid at 40bpm as per design. Frac stage 10: 1,970bbls slurry (YF125ST fluid), 14,306 lbs 40/70 carbolite (1, 3ppa), 242,155lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10, 12ppa), 1,714bbs clean fluid at 40bpm as per design. Shut down after initial collet land to fix issue with sand chief before continuing with job. Frac stage 11: 2,029bbls slurry (YF125ST fluid), 21,351 lbs 40/70 carbolite (1, 3ppa), 198,352lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8ppa), 1,809bbs clean fluid at 35-40bpm. 6ppa and 8ppa extended and did not go to 10ppa due to pressure. Tracerco tracers pumped as per design (details in the job time log for each stage). Well freeze protected with 60bbls (44bbls downhole and 16bbls surface lines). 8gal diesel spill (5gal to pad and 3 gal to containment) from miscommunication while blowing down frac lines. Total Load to Recover (TLTR) stage 9-11 5,349bbls Total Load to Recover (TLTR) 21,855bbls 4/16/2024 4/17/2024 Continue to RD frac equipment. RD Cameron launch tree. Page 2 of 2 Flowback Ops Summary Report - AOGCC Well Name NDB-032 Primary Job Type Flowback/Testing Start Date End Date Summary 3/21/2024 3/22/2024 No accidents no spills. Expro prepare equipment to move. 3/22/2024 3/23/2024 No accidents no spills. Expro prepare equipment to move. 3/23/2024 3/24/2024 No accidents no spills. Expro prepare equipment to move. 3/24/2024 3/25/2024 No accidents no spills. Expro prepare equipment to move. 3/25/2024 3/26/2024 No accidents no spills. Expro prepare equipment to move. 3/26/2024 3/27/2024 No accidents no spills. Expro prepare equipment to move. 3/27/2024 3/28/2024 No accidents no spills. Expro prepare equipment to move. 3/28/2024 3/29/2024 No accidents no spills. Expro prepare equipment to move. 3/29/2024 3/30/2024 No accidents no spills. Expro prepare equipment to move. 3/30/2024 3/31/2024 No accidents no spills. Expro prepare equipment to move. Move Sand separator and Well control equipment into containment. 3/31/2024 4/1/2024 No accidents no spills. Expro prepare equipment to move. 4/1/2024 4/2/2024 No accidents no spills. Expro prepare crane for equipment move. Move DPI ST into containment. Move Sparge tank into containment. RU HP piping to Sand separation and well control equip. 4/2/2024 4/3/2024 Expro Rigged up hard line to wellhead SDV and inner connecting pipe for sand management system. 4/3/2024 4/4/2024 Expro completed rigging up hard line in the well head containment. 4/4/2024 4/5/2024 Expro lowered flare to install new ignitor system. 4/5/2024 4/6/2024 Expro continued woking on safety system ad DAQ. 4/6/2024 4/7/2024 Expro ran lines for safety system to the WH equipment. 4/7/2024 4/8/2024 Expro installed and tested back up igniter on flare. 4/8/2024 4/9/2024 Expro continued working on ESD system. 4/9/2024 4/10/2024 Expro began clearing area for frac move. 4/10/2024 4/11/2024 Expro conducted air test on HP and LP header. 4/11/2024 4/12/2024 Expro got good leak test on LP header. 4/12/2024 4/13/2024 Check DPI unit for leaks throughout entire unit and crew completed preliminary Safety systems test. 4/13/2024 4/14/2024 Expro Wrapped lines and rigged up port for LRS. 4/14/2024 4/15/2024 Finish up Safety systems connections with 1" air line installed. PT Test lines to tank manifolds including Sand trap, DPI unit, Choke manifold and Separator. Low 231psi and High 1120psi Good Test. 4/15/2024 4/16/2024 Remove snow from WT area and equipment. Installed 1 13/16" 10M blind flange on the DPI vent line and Expro trained personnel on the operations of the DPI. 4/16/2024 4/17/2024 SLB tech setup DH logger in Expros test unit. Inspect entire ESD lines, repair quick exhaust O' rings, clean up Tank farm and TTLA. Page 1 of 4 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 4/17/2024 4/18/2024 Rig up ball catcher, rig up hard-lines to well and PT to Low 500psi and High 4500psi. Continue to get equipment ready for Well clean-up. 4/18/2024 4/19/2024 Test safety systems to wellhead, hutch wellhead and ball catcher. Perform final check on equipment and complete pre-flow checklist. 4/19/2024 4/20/2024 Continue to get equipment ready for Well clean-up. Finish rigging up Magtec and LRS equipment at the injection well. Make a walk through all WT equipment. Hold a Pre-Flow meeting with all vendors. LRS pressure test lines to 4500psi. Good test. 4/20/2024 4/21/2024 Hold safety meeting, make a final walk through, open up well, record Well pressures and start Well clean-up operation. Open up well on 12/64" choke and worked choke up to 28/64" at midnight. 4/21/2024 4/22/2024 Expro flowing well per clean up procedure. 4/22/2024 4/23/2024 Expro flowing well per clean up procedure. 4/23/2024 4/24/2024 Expro shut in well and began rigging down. 5/2/2024 5/3/2024 Expro Rigging up equuipment in preperation to flow well. 5/3/2024 5/4/2024 Expro Rigging up equuipment in preperation to flow well. 5/4/2024 5/5/2024 Expro Rigging up equuipment in preperation to flow well. 5/5/2024 5/6/2024 Expro Rigging up equuipment in preperation to flow well. 5/6/2024 5/7/2024 Expro Complete ESD System function test. ESD Pre flow checklist verification. Leak detection testing. 5/7/2024 5/8/2024 Monitor Down hole pressure and temperature. Heat equipment prep to flow well. Wait on Coil Tubing, 5/8/2024 5/9/2024 Monitor Down hole pressure and temperature. Heat equipment prep to flow well. Wait on Coil Tubing, 5/9/2024 5/10/2024 Monitor Down hole pressure and temperature. Wait on Coil Tubing, 5/10/2024 5/11/2024 Monitor Down hole pressure and temperature. Wait on Coil Tubing, 5/11/2024 5/12/2024 LRS Coiled tubing unit #2 arrive on location. Spot equipment and raise mast. Stab 2" coil through injector. Pick up injector with lubricator and NU BOPE to pump-in sub on well. Perform weekly BOP test to 350 psi low/4000 psi high. Good test. MU and Test coiled tubing cleanout BHA #1. 5/12/2024 5/13/2024 RIH with coil and start cleanout at 6,000' ctmd. Lost hydraulic pressure to coil reel at 6,300'. Circulate 1.5x bottoms up to return tanks and close choke. Replace proportional valve on coil reel and resume cleanout. Cleanout from 6,300' to 7,325' with slick/safe seawater. Did not see any obstructions when cleaning past Frac sleeve #11 at 7,222'. Chase returns to surface. Did not see any substantial amount of proppant at surface. Troubleshoot coil reel hydraulic pressure issues again. RIH cleanout to 7825' ctmd. Continue cleanout. 5/13/2024 5/14/2024 Cleanout from 7825' to 8825' ctmd with 2" coil. Start to get overpulls during wiper trip at 5400', reduce speed and continue to pull to 1,000' and get proppant/sand slugs at surface. Make another cleanout bite from 8825' to 9300' and chase returns to 1,000' at 40 fpm and 1.9 bpm. Page 2 of 4 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 5/14/2024 5/15/2024 Cleanout from 9300' to 9800' ctmd with 2" coil. Got overpulls during wiper trip at 5080', reduce speed and continue to pull to 1,000' at 40 fpm @ 1.9 bpm. Significant proppant/sand slugs at surface. Did a short trip to 6400', pump gel sweep, POOH to 1000'. Started to lose returns, slowed running speed to 25 ft/min. Change valves and seats on coil pump. Start RIH however reel hydraulics started malfunctioning again. POOH and wait on MT and ET to arrive to trouble shoot. Determined the Power Pack was creating the issue, waiting on backup Power Pack coming out from town. 5/15/2024 5/16/2024 Cleanout from 9800' to 10,800' ctmd with 2" coil. Got overpulls through the heel during wiper trips, reduce speed and continue to pull to 1,000' ctmd at 2.0 bpm. Significant proppant/sand seen in returns at surface on 2nd run. Pumped gel pills at 6400' coming up through the heel. Started to lose returns at 5600' ctmd on 2nd run, ran back in hole through the heel and made a second pass, slowed running speed to 15 ft/min. 5/16/2024 5/17/2024 POOH from 10,800' to surface, chasing returns at 40 fpm and 2.0 bpm. Observed significant sand/proppant returns. Cut pipe, install new contector, pull tested to 25k lbs for 5 minutes. Install Baker Slick Catch tool. Nipple up to well, pressure test 3500 psi for 5 mins. RIH to tag collet at 7222'. No set down weight at expected depth. Continued to RIH and set down 3,000 lbs at 7699'. POOH with the collet to 5460', working through some tight spots using the jars and pump rate. Had sand stacking on top of collet through the heel. Released the Slick Catch tool. POOH to surface, pick up jet nozzle. RIH with swirl nozzle. Clean out to 5565'. POOH chasing returns to surface. No significant sand/proppant seen at surface. 5/17/2024 5/18/2024 Coil N2 lift from 6,350' ctmd. Expro flowing well per clean up procedure. 5/18/2024 5/19/2024 Expro flowing well per clean up procedure. Shutdown flowback operations for about 12hrs to mitigate higher than normal H2S concentration in the flowback fluids before resuming operation. 5/19/2024 5/20/2024 Expro flowing well per clean up procedure. Lost WHP and BHP due to possible sand plugs downhole. Pumped a total of 81,800scf of N2 on two attempts to breakdown and remove sand plug but was unsuccessful. Shut-in well at midnight with 0psi WHP and 1490psi BHP. 5/20/2024 5/21/2024 Shut-in well and monitor for pressure build up enough to flow well. A decision was made to suspend flowback operations and wait on CTU to clean up well before resuming the FB operations. 5/21/2024 5/22/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/22/2024 5/23/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/23/2024 5/24/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/24/2024 5/25/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/25/2024 5/26/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/26/2024 5/27/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/27/2024 5/28/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/28/2024 5/29/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/29/2024 5/30/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/30/2024 5/31/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 5/31/2024 6/1/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 6/1/2024 6/2/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, 6/2/2024 6/3/2024 Monitor Down hole pressure and temperature while waiting on Coil Tubing, Page 3 of 4 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 6/3/2024 6/4/2024 LRS coiled tubing unit #2 arrived on location with 2" coil. Spot equipment and RU hardline from well to choke and out to return tanks. Perform weekly BOP test to 250 psi low / 4,000 psi high. MU BHA with Tempress and 2.30" JSN. PT out to Choke skid. Open well and RIH to start cleanout. Having issues with reel motor. Call out for mechanic to replace reel motor. 6/4/2024 6/5/2024 Cleanout from 5,500' to 6,000'. Change out reel motor on coil unit. POOH to surface and troubleshoot reel motor interntal brake issues. 6/5/2024 6/6/2024 Continue to troubleshoot hydraulic issue with reel motors on location. Decision was made to rig down coiled tubing unit and travel back to LRS shop in Deadhorse for diagnostics and repair. Blowdown coil with N2. RDMO. 6/6/2024 6/7/2024 LRS Coil departs location enroute to Deadhorse for repairs. 6/7/2024 6/8/2024 LRS coil unit #2 arrive on location. MIRU. Complete BOP test. 6/8/2024 6/9/2024 Coiled tubing cleaned out with 2" coil from 5,500' to 7,500' ctmd using slick/safe seawater with gel pills. Cleaned out proppant in increments of 500' and then chased returns to 1,000'. Seen heavy proppant returns at surface once coil reaches ~ 1,400'. 6/9/2024 6/10/2024 Coiled tubing cleanout with 2" coil from 7,500' to 9,100' ctmd using slick/safe seawater with gel pills. Cleaned out proppant in increments of 500-600' and then chased returns to 1,000'. Get heavy proppant returns to surface once coil reaches ~ 1,400'. After cleaning out to 9,100', coil pressured up at 2500' ctmd while chasing returns to surface and were only able to achieve 0.8 bpm on pumps. Trip to surface to inspect tempress tools. No material appeared to be plugging the tempress screen sub. Change out Tempress and screen sub. RIH after tool swap and tagged sand at 5529' ctmd. Cleanout down to 6500' ctmd and then chase returns uphole to clean out proppant. 6/10/2024 6/11/2024 Cleanout with 2" coiled tubing from 9,100' to 10,700' ctmd using slick/safe seawater with gel pills. Cleaned out proppant in increments of 500-600' and then chased returns to 1,000'. Get heavy proppant to surface once coil reaches ~ 1,400'. 6/11/2024 6/12/2024 Cleanout with 2" coiled tubing from 10,700 to 11,250' ctmd. Coil reached lock-up ~ 11,000', but able to continue to 11,250' ctmd with use of Tempress tool. Lost returns to surface at ~ 5,600' and coil was hung up until returns established. Chase returns to surface, getting proppant slug to surface from 1,400' until 1,000' when it cleaned up. POOH and laydown Tempress BHA. Swap to a 2" slim cleanout BHA with 2" jet swirl nozzle. RIH and tag at 5600' ctmd. Pump gel/slick seawater and cleanout to 6,000' ctmd and chase returns to 1,000. RBIH to 6,500' ctmd without pumping. Pump final gel/slick seawater sweep taking returns to surface while POOH to 1,000'. RIH to 6,350'. Pump N2 down coil at 500scf/min while taking returns to tanks until N2 reaches surface. Hand well over to Expro for welltest while pumping N2 at 500scf/min for first 24hrs. 6/12/2024 6/13/2024 LRS coil reciprocate coiled tubing from ~ 6350' to 5,000 while pumping ~ 350 scfm of Nitrogen. Expro flowing well per clean up procedure. 6/13/2024 6/14/2024 Expro flowing well per clean up procedure. 6/14/2024 6/15/2024 Expro flowing well per clean up procedure. 6/15/2024 6/16/2024 Expro flowing well per clean up procedure. 6/16/2024 6/17/2024 Expro flowing well per clean up procedure. 6/17/2024 6/18/2024 Expro flowing well per clean up procedure. 09:00 shut in well and monitor DH pressure & Temp. Rig off of well head & Move to Well NDBi-030. Page 4 of 4 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 890.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 428.3 gal J475 Breaker J475 5.9 lb/mGal 5,166.0 lbm J511 Stabilizing Agent 1.5 lb/mGal 1,286.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,911.0 gal J580 Gel J580 25.6 lb/mGal 22,473.4 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 50.1 gal M275 Bactericide 0.3 lb/mGal 293.9 lbm S522-1218 Propping Agent varied concentrations 64,974.0 lbm S522-1620 Propping Agent varied concentrations 2,541,004.0 lbm S522-4070 Propping Agent varied concentrations 96,000.0 lbm S901 Proppant with Scale Inhibitor S901 varied concentrations 105,875.0 lbm 71.86368 % 27.56388 % 0.22106 % 0.10441 % 0.04075 % 0.04075 % 0.03820 % 0.03119 % 0.02088 % 0.01373 % 0.01373 % 0.01268 % 0.01261 % 0.00968 % 0.00684 % 0.00157 % 0.00145 % 0.00110 % 0.00055 % 0.00029 % 0.00025 % 0.00025 % 0.00017 % 0.00014 % 0.00004 % 0.00004 % 0.00003 % 0.00003 % 0.00001 % 0.00001 % < 0.00001 % 100 %Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 127-08-2 Acetic acid, potassium salt (impurity) 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 9000-90-2 Amylase, alpha 10377-60-3 Magnesium nitrate 14807-96-6 Magnesium silicate hydrate (talc) 9002-84-0 poly(tetrafluoroethylene) 91053-39-3 Diatomaceous earth, calcined 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 9025-56-3 Hemicellulase 67-63-0 Propan-2-ol 50-70-4 Sorbitol 34398-01-1 Ethoxylated C11 Alcohol 1303-96-4 Sodium tetraborate decahydrate 9003-35-4 Phenolic resin 111-76-2 2-butoxyethanol 7727-54-0 Diammonium peroxodisulphate 102-71-6 2,2`,2"-nitrilotriethanol 56-81-5 1, 2, 3 - Propanetriol 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF125ST:WF125 878,105 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-1864 Fluid Name & Volume Concentration Volume Disclosure Type: Post-Job Well Completed: Date Prepared: 5/13/2024 State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search (Alaska), LLC Well: NDB-032 Basin/Field: Pikka # SLB-Private Page: 1 / 1 SLB-Private SLB-Private 11:57:15 13:20:35 14:43:55 16:07:15 17:30:35 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop ConStage 1 Stage 2 Stage 3 Stage 4 FracCAT* © Schlumberger 1994-2017 Santos NDB-32 4-7-2024 SLB-Private 12:36:42 12:57:32 13:18:22 13:39:12 14:00:02 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 1 4-7-2024 SLB-Private SLB-Private SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) Average Viscosity (cP) 13:42:29 13:54:59 14:07:29 14:19:59 14:32:29 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 2 4-7-2024 SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) Average Viscosity (cP) 14:21:56 14:38:36 14:55:16 15:11:56 15:28:36 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 3 4-7-2024 SLB-Private SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) Freeze Protect (bbl) 15:14:44 15:35:34 15:56:24 16:17:14 16:38:04 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stage 4 4-7-2024 SLB-Private SLB-Private SLB-Private SLB-Private FracCAT Treatment Report Well : NDB-32, Stages 5 and 6 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : 4/10/2024 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 330 Initial BHP at Gauge (psi) 1,972 Final Surface ISIP (psi) 1,039 Final ISIP at Gauge (psi) 2,907 Surface Shut in Pressure(psi) 750 BH Shut in Pressure (psi) 2,467 Maximum Treating Pressure (psi) 5,287 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 5,329.3 Total Proppant Pumped per load tickets (lb) 567,034 Total YF125ST Past Wellhead (bbl) 4,266.6 Total Proppant in Formation per load tickets (lb) 567,034 Total WF125 Past Wellhead (bbl) 430.6 Total SG IV blend (lb) 551,034 Total Freeze Protect Past Wellhead (bbl) 47.2 Total Carbolite 40/70 (lb) 16,000 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 198 197 M275 (lb) 114 88 J450 (gal) 100 100 J753 (gal) 11 11 J580 (lb) 5,035 5,002 J475 (lb) 1,210 1,206 J532 (gal) 453 453 J134 (lb) 3 0 J511 (lb) 321 321 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-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Summary On April 10, 2024 SLB performed a hydraulic fracturing treatment on Stages 5 and 6 of NBD-32. The design called for the completion of stages 5- 7, but due to problems with the POD IVs hydraulic system the job was shutdown right after the sleeve was shifted for Stage 7. Stage 5 consisted of a Pad, 1PPA scour, 3 PPA scour 1, 2, 4, 6, 8, 10 and 12 PPA stages. Stage 2 consisted of a Pad, 1, 2, 4, 6, 8, 10 and 12 PPA stages. Pump trips were staggered from 7,800 to 8,000 psi. The popoff was initially set to 8,300 psi. A summary of the job and individual stages is below. Summary of Stages 5-6 Material Actual Design Slurry Volume (bbl) 5,329.3 3,936 Clean Fluid Volume(bbl) 4,697.2 3,370 Proppant (lb) 567,034 535,575 15:04:20 15:54:20 16:44:20 17:34:20 18:24:20 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 3 6 9 12 15 18 21 24 27 30 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Stage 5 Stage 6 Shut down Due to Lost Suction Shutdown Due to POD IV Hydraulics Main Treatment © Schlumberger 1994-2017 SantosNDB-3204-10-2024 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 5 Initial treating pressure on PAD was around 3,100 psi and slowly fell to about 2,400 psi once 2 PPA was going into formation. At this point, the treating pressure gradually increased to 4,675 psi once sand was cut on surface. Slurry rate remained steady at 40bpm until rate was slowed for the collet to seat. A summary of the Stage and its measured pump schedule is below: 14:21:29 14:50:39 15:19:49 15:48:59 16:18:09 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 3 6 9 12 15 18 21 24 27 30 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Drop rate to Seat Collet Shift Sleeve Pumping Ball to Seat Main Treatment © Schlumberger 1994-2017 SantosNDB-32, Stage 504-10-2024 Summary of Pressures When Collet Seats Collet #6 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 2,064 2,751 5,287 Bottomhole Pressure 3,480 3,473 6,528 Summary of Stage 5 Total Proppant Pumped (lb) 294,786 Max pumping Rate (bpm) 41.1 Total Proppant in Formation (lb) 294,786 Average Pumping Rate (bpm) 36.5 Total CarboLite 40/70 16,000 Maximum Treating Pressure (psi) 4,655 Total CarboLite 16/20- 4% SG 278,786 Average Treating Pressure (psi) 2,896 Total Slurry Pumped (bbl) 2,254.4 Average Water Temperature (F)100 YF125ST Pumped (bbl) 1,752.2 WF125 Pumped (bbl)205.6 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States As Measured Pump Schedule 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 FP 40.1 3.9 10.6 WF125 1685 0.0 0.0 0 2 Pump Ball 165.7 4.9 39.0 WF125 6950 0.0 0.0 0 3 XL Check 13.7 16.0 0.9 YF125ST 573 0.0 0.0 0 4 PAD 325.0 39.2 8.3 YF125ST 13635 0.0 0.0 0 5 1.0 PPA 59.5 39.9 1.5 YF125ST 2405 CarboLite 40/70 1.2 0.9 2162 6 3.0 PPA 120.0 40.0 3.0 YF125ST 4474 CarboLite 40/70 3.2 2.9 13838 7 Resume PAD 75.0 40.0 1.9 YF125ST 3115 0.0 0.0 0 8 1.0 PPA 179.5 39.9 4.5 YF125ST 7241 CarboLite 16/20- 4% SG 1.0 0.9 7073 9 2.0 PPA 200.1 40.1 5.0 YF125ST 7740 CarboLite 16/20- 4% SG 2.1 2.0 15741 10 4.0 PPA 219.7 40.0 5.5 YF125ST 7876 CarboLite 16/20- 4% SG 4.1 3.9 32059 11 6.0 PPA 219.7 39.9 5.5 YF125ST 7327 CarboLite 16/20- 4% SG 6.1 5.9 45067 12 8.0 PPA 218.7 40.0 5.5 YF125ST 6818 CarboLite 16/20- 4% SG 8.2 7.9 56148 13 10.0 PPA 198.4 39.9 5.0 YF125ST 5813 CarboLite 16/20- 4% SG 10.2 9.9 59774 14 12.0 PPA 176.6 39.7 4.4 YF125ST 4879 CarboLite 16/20- 4% SG 12.5 11.9 62923 15 Spacer 39.7 40.4 1.0 YF125ST 1570 0.0 0.0 0 16 Drop Collet 3.0 40.3 0.1 YF125ST 127 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 Displace FP 3.9 4.1 1503 1570 334 2 Pump Ball 4.9 16.0 1394 1854 664 3 XL Check 16.0 16.0 1818 1904 1808 4 PAD 39.2 41.1 2855 3049 1973 5 1.0 PPA 39.9 40.4 2689 2733 2650 6 3.0 PPA 40.0 40.3 2574 2660 2467 7 Resume PAD 40.0 40.4 2513 2582 2467 8 1.0 PPA 39.9 40.2 2519 2660 2431 9 2.0 PPA 40.1 40.2 2413 2449 2376 10 4.0 PPA 40.0 40.3 2436 2527 2371 11 6.0 PPA 39.9 40.4 2760 3003 2527 12 8.0 PPA 40.0 40.3 3480 3886 3003 13 10.0 PPA 39.9 40.4 4085 4358 3841 14 12.0 PPA 39.7 40.3 4459 4655 4344 15 Spacer 40.4 40.9 4535 4655 4312 16 Drop Collet 40.3 40.3 4330 4369 4312 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other 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 12:21:32 Good Check Valve 4239 18 0.0 0.0 0.0 2 12:45:53 Good PT 41 23 0.0 0.0 0.0 3 13:00:59 PJSM 46 27 0.0 0.0 0.0 4 14:05:50 Open Well 366 2989 0.0 0.0 0.0 5 14:06:39 Start Displace FP Automatically 334 2980 0.0 0.0 0.0 6 14:06:39 Start Propped Frac Automatically 334 2980 0.0 0.0 0.0 7 14:06:39 Start Stage 5 Automatically 334 2980 0.0 0.0 0.0 8 14:06:44 Started Pumping 334 2980 0.0 0.0 0.0 9 14:07:10 Activated Extend Stage 1176 3012 0.7 3.7 0.0 10 14:29:19 Deactivated Extend Stage 659 2971 40.1 0.0 0.0 11 14:29:19 Start Pump Ball Manually 659 2971 40.1 0.0 0.0 12 14:31:58 Activated Extend Stage 1520 3012 50.2 4.0 0.0 13 15:02:40 Stage at Perfs: Displace FP 1328 3310 170.9 4.0 0.0 14 15:08:40 Deactivated Extend Stage 1822 3397 205.9 16.0 0.0 15 15:08:40 Start XL Check Manually 1822 3397 205.9 16.0 0.0 16 15:09:01 Stage at Perfs: XL Check 1813 3401 211.5 16.0 0.0 17 15:09:15 Activated Extend Stage 1808 3406 215.2 16.0 0.0 18 15:09:31 Deactivated Extend Stage 2138 3333 219.5 18.2 0.0 19 15:09:31 Start PAD Manually 2138 3333 219.5 18.2 0.0 20 15:13:41 Stage at Perfs: PAD 2861 3314 377.9 39.8 0.0 21 15:14:01 Stage at Perfs: PAD 2847 3305 391.2 40.0 0.0 22 15:17:52 Start 1.0 PPA Automatically 2728 3378 545.1 40.1 0.0 23 15:17:52 Started Pumping Prop 2728 3378 545.1 40.1 0.0 24 15:19:21 Start 3.0 PPA Automatically 2655 3250 604.2 40.4 1.0 25 15:20:15 Activated Extend Stage 2618 3291 640.1 40.0 3.0 26 15:22:10 Stage at Perfs: 3.0 PPA 2476 3360 716.8 39.2 3.0 27 15:22:21 Deactivated Extend Stage 2467 3365 724.0 39.5 3.0 28 15:22:21 Start Resume PAD Manually 2467 3365 724.0 39.5 3.0 29 15:22:41 Stopped Pumping Prop 2463 3378 737.3 40.2 0.0 30 15:23:39 Stage at Perfs: Resume PAD 2550 3410 776.1 40.1 0.0 31 15:24:14 Start 1.0 PPA Automatically 2591 3246 799.4 40.0 0.0 32 15:24:14 Started Pumping Prop 2591 3246 799.4 40.0 0.0 33 15:26:39 Stage at Perfs: 1.0 PPA 2463 3342 895.7 40.1 1.0 34 15:28:32 Stage at Perfs: 1.0 PPA 2449 3392 971.2 39.8 1.0 35 15:28:44 Start 2.0 PPA Automatically 2435 3397 979.2 40.1 1.0 36 15:33:01 Stage at Perfs: 2.0 PPA 2417 3291 1150.8 40.2 1.9 37 15:33:43 Start 4.0 PPA Automatically 2431 3305 1178.8 40.1 2.0 38 15:38:01 Stage at Perfs: 4.0 PPA 2472 3378 1350.8 40.1 4.0 39 15:39:13 Start 6.0 PPA Automatically 2527 3378 1398.7 40.1 4.0 40 15:43:31 Stage at Perfs: 6.0 PPA 2911 3323 1570.4 40.0 6.0 41 15:44:43 Start 8.0 PPA Automatically 3007 3342 1618.2 39.7 6.0 42 15:49:01 Stage at Perfs: 8.0 PPA 3777 3392 1790.1 40.2 7.9 43 15:50:12 Start 10.0 PPA Automatically 3886 3246 1837.3 40.0 8.0 44 15:54:30 Stage at Perfs: 10.0 PPA 4312 3282 2008.9 40.2 10.0 45 15:55:10 Start 12.0 PPA Automatically 4349 3287 2035.7 39.9 10.3 46 15:55:58 Activated Extend Stage 4275 3282 2067.8 39.8 12.4 47 15:59:29 Stage at Perfs: 12.0 PPA 4665 3296 2207.2 39.8 11.7 48 15:59:36 Deactivated Extend Stage 4646 3296 2211.8 39.8 12.1 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 49 15:59:36 Start Spacer Manually 4646 3296 2211.8 39.8 12.1 50 15:59:50 Activated Extend Stage 4655 3296 2221.1 40.6 0.9 51 16:00:35 Deactivated Extend Stage 4390 3296 2251.6 40.3 -0.1 52 16:00:35 Start Drop Collet Manually 4390 3296 2251.6 40.3 -0.1 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 6 As expected, the transition from Stage 5 to 6 went very well. The 1PPA and 2PPA steps started well, but towards the end of the 2PPA step, the PCM lost suction pressure. This was the result of a miscommunication on the tank swap, and Tank 13 was allowed to empty causing the c-pump on the PCM to lose prime. As a result, sand was cut and the stage was stopped. When examining the published viscosity, the value appears to drop sharply. This is a direct result of the fluid velocity of the fluid going through the c-pump and mixing gel after losing prime. Immediately before the incident, a linear gel sample was taken and the gel tested at 25#. This 25# gel was in the rear compartment of the PCM and is what was being pumped downhole. The front 4 compartments were used to mix gel and the viscometer is measuring viscosity of the fluid going through tank 5. This is evident once the new gel started to move to the rear of the PCM. A value of 18.5 was the published viscosity. Prior to the job, the viscometer was reset to indicate that a value of 19 would represent 25# gel. After the shutdown, chemical additive quantities were evaluated and an additional amount of J753 was mixed. In addition, alterations were made to the concentration of J511. It was decreased from 2 gpt to 1.8 gpt. Once the additive amounts were verified, the stage was started from the beginning of the design. The stage treated very well with pressures initially falling sharply to 2,500 psi and then gradually decreasing to about 2,230 psi once 2PPA was going into formation. Pressure then increased over time to about 4,700 psi and fell once rate was lowered to seat the collet. During the 12PPA step, the road side hydraulics of the POD IV started to surge. At this point, the decision was made to shift the sleeve and shutdown to evaluate the problem. Without knowing the cause of the problem, the decision was made to stop the job and begin the post job clean up. Before the cleanup, a 225 bbl injection test was pumped to evaluate Stage 7. The POD IV will be sent back to the SLB yard for evaluation and the SuperPOD will be brought to location to continue operations. Moving forward, the plan is to pump Stages 7 and 8 on April 12, 2024. A summary of the Stage and its measured pump schedule is below: 16:03:40 16:53:40 17:43:40 18:33:40 19:23:40 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 3 6 9 12 15 18 21 24 27 30 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Drop rate to Seat Collet Shift Sleeve Shutdown Due to Tanks Shutdown Due to POD Injection Test Main Treatment © Schlumberger 1994-2017 Santos NDB-32, Stage 604-10-2024 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Summary of Pressures When Collet Seats Collet #7 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 1,913 1,824 1,867 Bottomhole Pressure 3,374 3,320 3,328 Summary of Stage 6 Total Proppant Pumped (lb) 272,248 Max pumping Rate (bpm) 40.5 Total Proppant in Formation (lb) 272,248 Average Pumping Rate (bpm) 38.1 Total Slurry Pumped (bbl) 3,074.9 Maximum Treating Pressure (psi) 5,287 YF125ST Pumped (bbl) 2,514.4 Average Treating Pressure (psi) 2,896 WF125 Pumped (bbl)225 Average Water Temperature (F)100 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States As Measured Pump Schedule 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 117.0 40.0 2.9 YF125ST 4933 -0.1 0.0 0 2 Slow for Seat 50.0 19.9 2.6 YF125ST 2111 0.0 0.0 0 3 PAD 226.6 37.1 6.4 YF125ST 9504 0.0 0.0 0 4 1.0 PPA 204.3 36.7 6.2 YF125ST 8278 CarboLite 16/20- 4% SG 1.1 0.9 7723 5 PAD 17.2 21.6 0.8 YF125ST 721 -0.2 0.0 0 6 1.0 PPA 62.4 36.4 1.7 YF125ST 2524 CarboLite 16/20- 4% SG 1.0 0.8 1975 7 2.0 PPA 142.9 40.0 3.6 YF125ST 5533 CarboLite 16/20- 4% SG 2.0 1.9 11683 8 PAD 305.1 34.5 10.7 YF125ST 12810 0.0 0.0 0 9 PAD 148.0 38.2 4.0 YF125ST 6199 0.0 0.0 0 10 1.0 PPA 175.4 39.9 4.4 YF125ST 7071 CarboLite 16/20- 4% SG 1.0 0.9 6952 11 2.0 PPA 190.3 40.0 4.8 YF125ST 7363 CarboLite 16/20- 4% SG 2.1 2.0 14924 12 4.0 PPA 209.2 40.0 5.2 YF125ST 7500 CarboLite 16/20- 4% SG 4.2 3.9 30437 13 6.0 PPA 209.6 40.0 5.2 YF125ST 6994 CarboLite 16/20- 4% SG 6.1 5.9 42867 14 8.0 PPA 209.3 39.9 5.2 YF125ST 6528 CarboLite 16/20- 4% SG 8.4 7.9 53630 15 10.0 PPA 189.8 40.0 4.7 YF125ST 5560 CarboLite 16/20- 4% SG 10.3 9.9 57162 16 12.0 PPA 130.1 39.8 3.3 YF125ST 3637 CarboLite 16/20- 4% SG 12.2 11.5 44896 17 Spacer 37.5 40.2 0.9 YF125ST 1521 0.0 0.0 0 18 Drop Collet 3.0 39.8 0.1 YF125ST 126 0.0 0.0 0 19 PAD 109.0 40.1 2.7 YF125ST 4582 0.0 0.0 0 20 Slow for Seat 50.0 20.0 2.6 YF125ST 2110 0.0 0.0 0 21 Injection Test 225.0 35.2 7.1 WF125 9449 0.0 0.0 0 22 FP 63.2 19.6 3.7 Freeze Protect 2582 0.0 0.0 0 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States 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 40.0 40.2 3748 4445 2118 2 Slow for Seat 19.9 38.3 3094 5287 1872 3 PAD 37.1 40.4 3137 5127 2545 4 1.0 PPA 36.7 40.1 2312 2550 838 5 PAD 21.6 24.8 2052 2206 1772 6 1.0 PPA 36.4 40.1 2428 2499 1932 7 2.0 PPA 40.0 40.2 2333 2449 2280 8 PAD 34.5 40.4 2297 2495 604 9 PAD 38.2 40.3 2860 3616 1868 10 1.0 PPA 39.9 40.2 2411 2509 2353 11 2.0 PPA 40.0 40.2 2286 2353 2248 12 4.0 PPA 40.0 40.2 2293 2394 2220 13 6.0 PPA 40.0 40.3 2732 3105 2394 14 8.0 PPA 39.9 40.2 3498 3891 3099 15 10.0 PPA 40.0 40.3 4137 4449 3882 16 12.0 PPA 39.8 40.0 4513 4633 4449 17 Spacer 40.2 40.5 4329 4660 4106 18 Drop Collet 39.8 39.8 4144 4191 4120 19 PAD 40.1 40.3 3585 4216 2001 20 Slow for Seat 20.0 37.6 1870 1918 1762 21 PAD 35.2 40.0 2308 2518 595 22 FP 19.6 20.3 1777 2023 5 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other 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 16:00:40 Start PAD Automatically 4454 3300 0.0 40.1 -0.1 2 16:00:40 Start Propped Frac Automatically 4454 3300 0.0 40.1 -0.1 3 16:00:40 Start Stage 6 Automatically 4454 3300 0.0 40.1 -0.1 4 16:02:33 Stopped Pumping Prop 3625 3319 75.3 39.9 -0.1 5 16:03:36 Start Slow for Sea Automatically 1772 3282 117.0 30.0 0.0 6 16:04:06 Stage at Perfs: Drop Collet 2023 3300 127.5 18.7 0.0 7 16:06:14 Start PAD Automatically 5113 3250 166.8 18.1 0.0 8 16:06:16 Stage at Perfs: PAD 5104 3255 167.4 18.1 0.0 9 16:06:27 Stage at Perfs: Slow for Sea 5040 3255 170.7 18.2 0.0 10 16:07:40 Activated Extend Stage 3950 3218 195.4 28.3 0.0 11 16:09:51 Stage at Perfs: PAD 2856 3223 280.5 40.2 0.0 12 16:11:06 Stage At Perfs 2650 3246 330.6 40.0 0.0 13 16:12:40 Deactivated Extend Stage 2550 3273 393.3 39.9 0.0 14 16:12:40 Start 1.0 PPA Manually 2550 3273 393.3 39.9 0.0 15 16:12:42 Started Pumping Prop 2541 3278 394.6 39.9 0.0 16 16:13:17 Activated Extend Stage 2490 3282 417.7 39.3 1.0 17 16:16:48 Stage At Perfs 1913 3319 556.9 33.5 1.1 18 16:18:50 Deactivated Extend Stage 1927 3314 597.6 14.9 -0.2 19 16:18:50 Start PAD Manually 1927 3314 597.6 14.9 -0.2 20 16:19:06 Stopped Pumping Prop 2119 3310 602.6 23.2 -0.2 21 16:19:38 Start 1.0 PPA Manually 2270 3328 614.8 18.6 0.0 22 16:19:43 Started Pumping Prop 2138 3291 616.4 21.2 0.0 23 16:21:22 Start 2.0 PPA Manually 2449 3328 677.2 40.0 1.0 24 16:23:28 Stage at Perfs: 1.0 PPA 2289 3333 761.3 40.1 2.0 25 16:23:54 Stage at Perfs: PAD 2298 3333 778.7 40.1 2.0 26 16:24:56 Start PAD Manually 2316 3333 820.1 39.9 2.0 27 16:25:24 Stopped Pumping Prop 2348 3333 838.9 40.2 -0.1 28 16:25:27 Stage at Perfs: 1.0 PPA 2330 3328 840.9 40.3 0.0 29 16:28:03 Activated Extend Stage 2467 3342 944.9 39.3 0.0 30 16:29:01 Stage at Perfs: 1.0 PPA 2431 3355 983.5 40.2 0.0 31 17:16:35 Deactivated Extend Stage 1868 2975 1125.2 16.0 0.0 32 17:16:35 Start PAD Manually 1868 2975 1125.2 16.0 0.0 33 17:20:34 Start 1.0 PPA Automatically 2513 3131 1273.7 40.1 0.0 34 17:20:40 Started Pumping Prop 2463 3131 1277.7 40.0 0.0 35 17:20:57 Stage at Perfs: 1.0 PPA 2435 3140 1289.0 39.5 0.9 36 17:24:40 Stage at Perfs: PAD 2362 3264 1437.4 40.0 1.0 37 17:24:57 Start 2.0 PPA Automatically 2344 3273 1448.8 40.2 1.0 38 17:29:02 Stage at Perfs: 1.0 PPA 2298 3360 1612.2 40.0 2.0 39 17:29:43 Start 4.0 PPA Automatically 2289 3264 1639.5 40.1 2.0 40 17:33:48 Stage at Perfs: 2.0 PPA 2339 3328 1803.0 40.1 4.0 41 17:34:56 Start 6.0 PPA Automatically 2399 3278 1848.2 40.2 3.9 42 17:39:02 Stage at Perfs: PAD 2998 3246 2012.2 40.0 5.9 43 17:40:11 Start 8.0 PPA Automatically 3113 3236 2058.1 40.0 6.0 44 17:44:17 Stage at Perfs: PAD 3813 3227 2221.6 40.0 8.1 45 17:45:26 Start 10.0 PPA Automatically 3886 3218 2267.5 40.0 7.8 46 17:49:32 Stage at Perfs: 1.0 PPA 4395 3186 2431.4 39.8 9.7 47 17:50:10 Start 12.0 PPA Automatically 4459 3177 2456.7 40.0 9.9 48 17:52:18 Activated Extend Stage 4546 3154 2541.7 39.8 11.7 Client: Santos Well: NDB-32, Stages 5-6 Formation: Nanushuk District: Prudhoe Other Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop.Conc. (PPA) 49 17:53:26 Deactivated Extend Stage 4665 3140 2586.7 40.2 4.3 50 17:53:26 Start Spacer Manually 4665 3140 2586.7 40.2 4.3 51 17:53:37 Activated Extend Stage 4395 3131 2594.2 40.1 2.4 52 17:54:04 Stopped Pumping Prop 4138 3131 2612.3 40.0 -0.1 53 17:54:16 Stage at Perfs: 2.0 PPA 4124 3127 2620.3 39.9 0.0 54 17:54:22 Deactivated Extend Stage 4216 3136 2624.2 40.0 0.0 55 17:54:22 Start Drop Collet Manually 4216 3136 2624.2 40.0 0.0 56 17:54:27 Start PAD Automatically 4266 3131 0.0 39.9 0.0 57 17:54:27 Start Propped Frac Automatically 4266 3131 0.0 39.9 0.0 58 17:54:27 Start Stage 7 Automatically 4266 3131 0.0 39.9 0.0 59 17:57:11 Start Slow for Sea Automatically 1593 3090 109.1 30.8 0.0 60 17:59:48 Start PAD Automatically 1845 3117 158.8 19.1 0.0 61 18:41:44 Activated Extend Stage 595 2724 174.8 0.0 0.0 62 18:48:09 Start FP Manually 1666 2971 383.7 20.3 0.0 63 19:21:44 Well Shut 774 2586 443.4 0.0 0.0 SLB-Private SLB-Private 15:05:02 15:55:02 16:45:02 17:35:02 18:25:02 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Stage 7 Stage 8 Main Treatment © Schlumberger 1994-2017 SantosNDB-3204-12-2024 SLB-Private 15:54:00 16:10:40 16:27:20 16:44:00 17:00:40 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT Generator Shut Off FracCAT Generator Online Slow to Launch Ball Shift Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32 Stage 7 04-12-2024 SLB-Private SLB-Private SLB-Private SLB-Private WF125 Pumped (bbl)Average Water Temperature (F) 16:47:02 17:03:42 17:20:22 17:37:02 17:53:42 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Shutdown Slow to Launch Ball Shift Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32 Stage 8 04-12-2024 SLB-Private SLB-Private 09:12:33 10:19:13 11:25:53 12:32:33 13:39:13 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Con BH Prop Con Stage 9 Stage 10 Stage 11 Main Treatment © Schlumberger 1994-2017 SantosNDB-32 04-15-2024 09:42:16 10:11:26 10:40:36 11:09:46 11:38:56 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Slow for Seat Open Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stages 9 4/15/2024 Average Water Temperature (F) 11:27:35 11:44:15 12:00:55 12:17:35 12:34:15 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Slow for Seat Open Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stages 10 4/15/2024 Average Water Temperature (F) 12:22:43 12:43:33 13:04:23 13:25:13 13:46:03 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con Swap to Diesel Close Well Shutdown Main Treatment © Schlumberger 1994-2017 Santos NDB-32. Stages 11 4/15/2024 Average Water Temperature (F) WF125 Pumped (bbl) NDB-032 Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2417' MD 13-3/8" 68 ppf L-80 Surface Casing2588' MD 9-5/8", 47ppf L-80 Production Liner 6283' MD 4-½, 12.6ppf P-110S Production Liner12376' MD GL 9-5/8" 68 ppf L-80 Tieback2417' MD 9.14.2023 41.5' RKB Tubing Hanger Flange 1 2 3 4 5 6 7 8 9 8-½ Openhole12381' MD # Completion Item Depth (MD') Depth (TVD') Inc ID" OD" 1 GasliftMandrel 1.5" 2908 2478 50 3.865 7.684 2 X LandingNipple 2971 2518 50 3.813 4.787 3 X LandingNipple 5847 4256 76 3.813 4.790 4 D/HPsi TempGauge 5902 4270 77 3.905 6.002 5 SSDNERA GL 5957 4281 79 3.813 6.922 6 Slimline Dial 6016 4292 80 3.898 5.990 7 X LandingNipple 6039 4296 80 3.813 4.784 8 Tieback Seal Assy 6136 4309 83 3.860 5.230 9 9.625"x 4.5"LH/Packer 6104 4305 83 6.180 8.420 10 #12Openhole Packer 6952 4314 91 3.918 8.000 11 Stage 11 FracSleeve 7222 4308 91 3.735 5.627 12 #11Openhole Packer 7444 4303 91 3.918 8.000 13 Stage 10 FracSleeve 7714 4298 91 3.735 5.627 14 #10Openhole Packer 8019 4291 91 3.918 8.000 15 Stage 9 FracSleeve 8206 4287 91 3.735 5.627 16 #9Openhole Packer 8511 4281 91 3.918 8.000 17 Stage 8 FracSleeve 8698 4277 91 3.735 5.627 18 #8Openhole Packer 9043 4269 91 3.918 8.000 19 Stage 7 FracSleeve 9188 4266 91 3.735 5.627 20 #7Openhole Packer 9451 4260 91 3.918 8.000 21 Stage 6 FracSleeve 9676 4255 91 3.735 5.627 22 #6Openhole Packer 9896 4250 91 3.918 8.000 23 Stage 5 FracSleeve 10160 4244 91 3.735 5.627 24 #5Openhole Packer 10338 4241 91 3.918 8.000 25 Stage 4 FracSleeve 10644 4234 91 3.735 5.627 26 #4Openhole Packer 10985 4227 91 3.918 8.000 27 Stage 3 FracSleeve 11126 4224 91 3.735 5.627 28 #3Openhole Packer 11389 4218 91 3.918 8.000 29 Stage 2 FracSleeve 11613 4213 91 3.735 5.627 30 #2Openhole Packer 11836 4209 91 3.918 8.000 31 Stage 1 FracSleeve 12102 4203 91 3.735 5.627 32 #1Openhole Packer 12241 4200 91 3.918 8.000 33 #2Toe Sleeve 12300 4198 91 3.500 5.875 34 #1Toe Sleeve 12308 4198 91 3.500 5.875 35 WIV Collar 12363 4197 91 5.620 36 Eccentricshoe 12372 4197 91 3.930 5.220 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 1 PDF file NDB-032 (50-103-20860-0000) Well Clean up Report Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 12/5/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other – FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 223-060 T39829 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.06 08:12:20 -09'00' 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 September 11, 2024 Mr. Rob Tirpack Oil Search Alaska, LLC 900 E. Benson Blvd Anchorage, AK 99508 Re: Docket Number: OTH-24-027 Close Out of Notice of Violation – Hydraulic Fracturing Chemical Disclosures NDB-032 (PTD 2230600) Dear Mr. Tirpack: On August 8, 2024, the Alaska Oil and Gas Conservation Commission (AOGCC) issued a Notice of Violation (NOV) relating to the failure of Oil Search Alaska, LLC (Santos) to identify all hydraulic fracturing chemicals in the Application for Sundry Approval (Form 10-403) and Report of Sundry Well Operations (Form 10-404) for the NDB-032 well and other hydraulically fractured wells. Similarly, Santos had not disclosed the use of these chemicals on the www.fracfocus.org website. The NOV required Santos to provide AOGCC with; 1. a root cause analysis and actions taken to prevent recurrence of these violations; 2. corrected Form 10-404’s or Form 10-407’s and www.fracfocus.org submissions to include all chemicals used in the hydraulic fracturing operations, as required by regulation, for all wells found to be in violation after Oil Search performs a complete review. The AOGCC has reviewed the Santos response dated September 4, 2024, and agree the specific actions identified in the internal investigation -when implemented –should prevent recurrence of this type of violation. AOGCC has received and verified the corrected chemical disclosures associated with the 10-404’s and www.fracfocus.org requirements. AOGCC considers this NOV closed. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: AOGCC Inspectors Jim Regg Phoebe Brooks Bryan McClellan Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.11 09:58:27 -08'00'Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.11 13:24:51 -05'00' By Samantha Coldiron at 7:45 am, Sep 05, 2024 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 August 8, 2024 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7017 2400 0000 5648 0619 Mr. Rob Tirpack Oil Search Alaska, LLC 900 E. Benson Blvd Anchorage, AK 99508 Re: Docket Number: OTH-24-027 Notice of Violation – Hydraulic Fracturing Chemical Disclosures NDB-032 (PTD 2230600) Dear Mr. Tirpack: On July 9, 2024, the Alaska Oil and Gas Conservation Commission (AOGCC) noticed a discrepancy on the Oil Search Alaska, LLC (Oil Search) submitted Report of Sundry Well Operations (Form 10-404) for the NDB-032 well. The Form 10-404 made mention of the use of chemicals during the hydraulic fracturing operation that were not identified, and thus not approved by AOGCC, in the NDB-032 Application for Sundry Approval (Form 10-403) which was approved by AOGCC as Sundry Approval 323-616. AOGCC contacted Oil Search and immediately discovered that Oil Search had also not disclosed these chemicals for other hydraulically fractured wells. Similarly, Oil Search had not disclosed the use of these chemicals on the www.fracfocus.org website. AOGCC regulations at 20 AAC 25.283(a)(12)(C) require that the Application for Sundry Approvals (Form 10-403) contain: (a)(12)(C) chemical ingredient name of, and the Chemical Abstracts Service (CAS) registry number assigned to, each base fluid and additive to be used; the actual or maximum concentration of each chemical ingredient in each base fluid and additive used must be provided in percent by mass; the actual or maximum concentration of each chemical ingredient in the hydraulic fracturing fluid must be provided in percent by mass; freeze- protect fluids pumped before or after hydraulic fracturing may not be included; Docket Number: OTH-24-009 Notice of Violation – Hydraulic Fracturing Chemical Disclosures August 8, 2024 Page 2 of 3 AOGCC regulations at 20 AAC 25.283(h) requires: (h) Not later than 30 days after completion of hydraulic fracturing, operations, the operator shall file with the commission, on a Report of Sundry Well Operations (Form 10-404), a complete record of the work performed and the tests conducted, a summary of daily well operations as described in 20 AAC 25.070(3), and a copy of the daily record required under 20 AAC 25.070(1). As part or the filing the operator shall include, (1) for each hydraulic fracturing interval, (A) the measured depth and true vertical depth of each perforation or sleeve for the actual treated interval; and (B) the amount and type of each base fluid and each additive pumped during each stage; and (2) for each hydraulic fracturing treatment addressed in the Report of Sundry Well Operations, the total amount and type of each base fluid and each additive pumped, including (A) a description of each hydraulic fracturing fluid pumped, identified by individual base fluid or additive; the description must include (i) the trade name for the base fluid or additive; (ii) the supplier of the base fluid or additive; and (iii) a brief description of the purpose of the base fluid or additive; that purpose may be expressed as acid, biocide, breaker, brine, corrosion inhibitor, crosslinker, de-emulsifier, friction reducer, gel, iron control, oxygen scavenger, pH adjusting agent, proppant, scale inhibitor, surfactant, or another similar brief description; and (B) the chemical ingredient name of, and the Chemical Abstracts Service (CAS) registry number assigned to, each base fluid and additive used; the actual or maximum concentration of each chemical ingredient in each base fluid and additive used must be provided in percent by mass: the actual or maximum concentration of each chemical ingredient in the hydraulic fracturing fluid must be provided in percent by mass; freeze-protect fluids pumped before or after hydraulic fracturing may not be included. (i) Before submitting a Report of Sundry Well Operations under (h) of this section, the operator shall (1) post information required by the Interstate Oil and Gas Compact Commission and the Ground Water Protection Council on the FracFocus Chemical Disclosure Registry, or its successor database, maintained on the Internet by those organizations; and (2) file a printed copy and electronic copy of that information, in a format acceptable to the commission and as an attachment with the Report of Sundry Well Operations. On July 18, 2024, AOGCC met with Oil Search to discuss this matter and develop a strategy to correct the incomplete chemical disclosure submissions. Within 30 days of receipt of this notice of violation, you are requested to provide AOGCC with; 1. a root cause analysis and actions taken to prevent recurrence of these violations; Docket Number: OTH-24-009 Notice of Violation – Hydraulic Fracturing Chemical Disclosures August 8, 2024 Page 3 of 3 2. corrected Form 10-404’s or Form 10-407’s and www.fracfocus.org submissions to include all chemicals used in the hydraulic fracturing operations, as required by regulation, for all wells found to be in violation after Oil Search performs a complete review. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Failure to comply with this request is itself a regulatory violation. Should you have any questions about this violation notice, please contact Chris Wallace at 907- 793-1250 or chris.wallace@alaska.gov. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: AOGCC Inspectors Jim Regg, AOGCC Phoebe Brooks, AOGCC Bryan McClellan, AOGCC Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.08.08 14:35:09 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.08 14:47:58 -08'00' LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 4 files NDB-032 (50-103-20860-0000) جؐؐؐCGM ؒ NDBi-032_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_10947ft_2MD.cgm ؒ NDBi032_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_10947ft_2TVD.cgm ؒ ؤؐؐؐPDF NDBi-032_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_10947ft_2MD.pdf NDBi-032_LWD_GR_Res_Den_Neu_Cal_DeepAziRes_RM_10947ft_2TVD.pdf Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 3/19/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other – FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 223-060: T38497 additional Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 07:51:46 -08'00' LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-032 (50-103-20860-0000) Supplemental well data submittal – details on following pages Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 2/13/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Meredith Guhl AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other – FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܈Other COMMENTS: PTD: 223-060 T38497 2/13/2024 Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.13 11:06:48 -09'00' LETTER OF TRANSMITTAL ├───Baker LWD │ ├───Digital Data │ │ └───FE │ │ NDB-032_LWD_GR_Res_Dens_Neu_Cal_AziRes_DeepAziRes_12381.las │ │ │ └───Geoscience │ │ Santos_NDB-032_MD_SDTK_MEM_DTC_RAW_WAVEFORMS_5900_12249.pdf │ │ Santos_NDB-032_MD_SDTK_MEM_DTS_RAW_WAVEFORMS_5900_12249.pdf │ │ Santos_NDB-032_MD_SDTK_MEM_FIELD_DTC_GRAM_5900_12249.pdf │ │ Santos_NDB-032_MD_SDTK_MEM_RAW_WAVEFORMS_5900_12249.dlis │ │ Santos_NDB-032_MD_SDTK_MEM_RAW_WAVEFORMS_5900_12249_dlis.txt │ │ │ ├───CBL │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_CBL.cgm │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_CBL.dlis │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_CBL.las │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_CBL.PDF │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_CBL_dlis.txt │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_TOC.cgm │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_TOC.dlis │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_TOC.las │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_TOC.PDF │ │ NDB-032_LWD_R04_2347ft_6118ft_SDTK_MEM_TOC_dlis.txt │ │ │ └───SoundTrak │ Santos_NDB-032_MD_SDTK_MEM_DTC_RAW_WAVEFORMS_5900_12249.pdf │ Santos_NDB-032_MD_SDTK_MEM_DTS_RAW_WAVEFORMS_5900_12249.pdf │ Santos_NDB-032_MD_SDTK_MEM_FIELD_DTC_GRAM_5900_12249.pdf │ Santos_NDB-032_MD_SDTK_MEM_RAW_WAVEFORMS_5900_12249.dlis │ Santos_NDB-032_MD_SDTK_MEM_RAW_WAVEFORMS_5900_12249_dlis.txt │ └───Mudlogging NDB-32_GeoIsotopes Corrected data_6280-12045ft.las NDB-32_GeoIsotopes Corrected Log_6280-12045 ft_2inch.pdf 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-032 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): 12381' Casing Collapse Structural Conductor Surface 2260 Intermediate 4750 Production 9210 Liner 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone: 907-646-7063 Authorized Title: Completions Speialist 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 12/10/23 12374'6136 4-1/2" 12.6 ppf 4197' See attached Packer Report Perforation Depth MD (ft): P-110S 6283 2588 6283' 6272 4-1/2" 4-1/2" Perforation Depth TVD (ft): 128' 2588' 4294'6157' 20"x34" 13-3/8" 128' 9-5/8" 12376' 11590 MD 6870 5020 128' 2273' 4322' Proposed Pools: PRESENT WELL CONDITION SUMMARY 4197' TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393020 223-060 900 E Benson Boulevard, Anchorage, AK 99508 50-103-20860-00-00 Oil Search Alaska, LLC AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): See attached Packer Report Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: Length Size m n P 2 6 5 6 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov g g p 11/14/2023 By Grace Christianson at 11:54 am, Nov 15, 2023 323-616 Flaring of gas during well cleanup is allowed. Fracture Stimulate CDW 11/28/2023 SFD 11/27/2023 DSR-11/15/23 12/10/23 10-407 BJM 12/1/23 *&:JLC 12/1/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.12.01 12:28:52 -09'00'12/01/23 RBDMS JSB 120423 Page 1 of 1 Well Name: NDB-032 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 6,125.5 4,308.2 OH Packer #12 6,959.1 4,313.8 OH Packer #11 7,451.4 4,303.6 OH Packer #10 8,026.4 4,291.6 OH Packer #9 8,517.7 4,281.2 OH Packer #8 9,050.5 4,269.6 OH Packer #7 9,457.9 4,260.1 OH Packer #6 9,902.6 4,250.3 OH Packer #5 10,345.1 4,240.9 OH Packer #4 10,992.6 4,227.1 OH Packer #3 11,396.0 4,218.5 OH Packer #2 11,843.1 4,208.9 OH Packer #1 12,247.9 4,200.1 Page 1 of 20 NDB-032 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachments B and F 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBD-032. At the NDB-032 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-032 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 J 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachment D 9. Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 1,020 feet (ft) total vertical depth subsea (TVDSS)/1,020 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. (See also AOGCC's Well History File 223-076, p. 101-107 of Sundry Application 323-591 and AOGCC's Hydraulic Fracturing Checklist accompanying that application.) SFD Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 1,020 to 2,300 ft TVDSS/1,280 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelf setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,300 to 3,150 ft TVDSS/850 ft thick Hydrocarbon Zone: 2,484 to 3,057 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. Seabee Formation Depth/Thickness: 3,150 to 3,795 ft TVDSS/600 ft thick Lithological Description: The Seabee Fm in the Pikka Unit area consists predominantly of claystone, shale, and volcanic tuff deposited in a deep marine setting. The base of the Seabee Fm grades into a condensed organic shale and provides an excellent seal and confining interval above the Nanushuk Fm reservoirs and also acts as a thick second overlying confining unit. Nanushuk Formation Depth/Thickness: 3,795 to 4,690 ft TVDSS/940 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east (Exhibit B-10). The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Upper Confining Zone Name: Upper Torok Formation (Hue Shale) Depth/Thickness: 4,690 to 5,590 ft TVDSS/900 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is nearly devoid of sand and is composed primarily of shale (Hue Shale) with some thin interbedded siltstones, thereby forming an excellent overlying confining seal above the Lower Torok injection zone. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. Lower Confining Zone Name: Highly Radioactive Zone (HRZ) Hue Shale Depth/Thickness: 6,075 to 6,245 ft TVDSS/170 ft thick Lithological Description: Below the sandy interval of the Lower Torok is the Lower Torok arresting zone, which is approximately 100 feet thick and composed of siltstone and shale. This, in turn, is underlain by the HRZ (Hue Shale) Fm confining interval, which is approximately up to 225-foot-thick condensed marine shale. These units will provide an excellent underlying confining seal. 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) Stages 1- 11 3300 3600 8200 7400 9000 Fracture gradient values for each stage are listed in detail within Appendix G. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Sale gradient- 0.69 psi/ft 11.Mechanical condition of wells transecting the confining zones – NDB-024, NDBi- 043, and DW-02 are within 1/2-mile radius of NDB-032. Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones.Attachment F Note: Fractures are estimated to propagate along wellbore longitudinally at ~330o. 13.Detailed proposed fracturing program –Attachments G & H 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 12,102 4,203 233.7 323.9 40 4,726 10 2 11,613 4,213 233 354.6 40 4,567 10 3 11,126 4,224 267.7 407.9 40 4,366 8 4 10,644 4,234 263.7 391.8 40 4,292 10 5 10,160 4,244 226.9 336.9 40 4,018 10 6 9,676 4,255 227.9 346.1 40 3,827 10 7 9,188 4,266 268.4 380.3 40 3,764 10 8 8,698 4,277 266.5 372.1 40 3,590 10 9 8,206 4,287 308.4 272.2 30 2,442 8 10 7,714 4,298 303.8 521.9 25 2,124 7 11 7,222 4,308 281.9 421 20 1,813 7 4,726 14.Well Clean Up procedure –Attachment I Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment J Section (d) Pressure Relieve Valve –Attachment K Proposed Wellbore Schematic –Attachment L Attachment A ADL 392984 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393021 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 19.22% DNR - 80.78% ADL 393019 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393018 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 29.67% DNR - 70.33% ADL 393020 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393015 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 31.69% DNR - 68.31% ADL 393016 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 391445 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391455 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% OIL SEARCH (ALASKA), LLC A SUBSIDIARY OF SANTOS LTD NDB032 WELL AREA TARGET BOTTOM HOLE SURFACE LOCATION WELL TRAJECTORY LEASES BOUNDARY KUUKPIK BOUNDARY .5-MILE BUFFER TOWNSHIP SECTION DATE: 7/14/2023. REV: 1.0. By: JB 0 300 600 US Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDB032_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 100 200 Meters PIKKA PROJECT NDB Attachment B WELL NAME STATUS Casing Size Top 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 By Reservoir Status Zonal Isolation Cement Operations Summary Mechanical Integrity DW-02 ACTIVE 7" 26ppf 6,540 (Torok) 5,142 (Torok) 2,426' (Top of 7" Liner)2,067' log cemented liner for Torok injection TOC 2426' MD & packer @ 7,100' Lead: 137 bbls of 12.0ppg Tail: 52 bbls of 15.3ppg 7/12/23, 7" casing pressure tested to 4,000 psi for 30 minutes NDBi-043 ACTIVE 9-5/8" 47ppf 4,955 (Nanushuk) 3,795 (Nanushuk) 2792 2730 log open hole liner for injection TOC 2,792' MD & packer @ 6,071'' Lead: 277bbls of 12ppg Tail: 44bbls of 15.3ppg 8/21/23, 9-5/8" casing pressure tested to 4,200 psi for 30 minutes NDB-024 ACTIVE 9-5/8" 47ppf 10,255 (Nanushuk) 3,768 (Nanushuk) 8,725' (Top of 1st Stage Cement)3,429' log open hole liner for injection TOC 8,725' & packer @ 11,294' Stage 1 - Lead: 100 bbls of 13.0ppg EconoCem Type I/II. Tail: 80 bbls of 15.3ppg VersaCem Type I/II. Stage 2 - Lead: 240 bbls of 13.0ppg EconoCem Type I/II. Tail: 170 bbls of 15.3ppg VersaCem Type I/II. 11/12/23, 9-5/8" casing pressure tested to 3,800 psi for 30 minutes 223-076 22 3 - 05 1 22 3 - 05 2 223-039 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 Plan Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess Lead TOC Top of the 9-5/8” Liner. Tail Open hole volume + 30% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 11.8 ppg Clean Spacer Lead 12.0ppg Lead: 221.7bbls, 1241cuft, 523sks ExtendaCem, Yield: 2.38 cuft/sk Tail 15.3ppg Tail: 42.5bbls, 239cuft, 194sks VersaCem Type I/II – 1.23 cuft/sk Temp BHST 98° F Verification Method Cement returns off top of liner, Ultra Sonic Wireline log, and Sonic LWD Notes Job will be mixed on the fly Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program (details on job noted below). a) Cement job was pumped as follows: i. 93 bbls of 11.8ppg Tuned Spacer ii. Release bottom down plug iii. 300 bbls of 12ppg Lead ExtendaCem Slurry iv. 45 bbls of 15.3ppg Tail Type I/II Slurry v. Release top pump down plug, chased with 2 bbls of cement then 10 bbls of water washup from Halliburton pump vi. Final displacement with rig pump was with 264 bbls of 11.5 ppg VersaClean and 38bbls of 11.8 ppg tuned spacer. b) Btm pump down dart latch up confirmed at 54 bbl displaced, 819 psi. c) Btm liner wiper plug latch up confirmed @ 342 bbl displaced, 570 psi. d) Top pump down dart latch up confirmed @ 39 bbl displaced. e) Reduce rate to 4 BPM prior to plug bump: Final circulating pressure 550 PSI f) Total displacement volume 315 bbls (measured by strokes @ 96% pump efficiency) 3127 stk’s (Calculated 3277 stk’s). g) Total losses from cement exit shoe to cement in place: 0 bbls. h) CIP: 00:20. i) Circulate out cement 11 BPM 880 PSI j) Cement job was pumped as per plan. No losses were observed, good lift pressure observed, and plugs were pumped on schedule. k) After setting the LTP, ~211 bbls OBM/Spacer interface were circulated, followed by ~72 bbls of cement/OBM contaminated returns (estimated ~65% or 47 bbls cement / 35% or 25 bbls OBM by rig team). Intermediate Liner Cement Job Observations l) Based on volumetrics and job execution, cement is across the entire 9-5/8” liner m) Statement above is supported by the CAST-M/CBL-M log and interpretation, which indicates only 2 small areas of Poor bond (2417’-2608’ and 4790’- 4814’). The remaining and majority of the section is either Fair (50%-80% bond coverage) to Good (>80%). n) The assessment is that we have adequate isolation across both the upper Nanushuk and Tuluvak. o) See attached interpreted cement bond log from Halliburton Wireline. Santos NDB-032 Pikka North Slope Alaska Halliburton CAST-M/CBL-M (12 Sep 2023) Cement Evaluation Report 20 September 2023 Submitted by: Roddy Hebert Geoscience and Production Halliburton Energy Services Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 2 Formation Reservoir Services Executive Summary This report covers NDB-032 that was logged by Halliburton on 12 September 2023. Halliburton logged the 9.625 inch 47 lbs casing that was set at 6283 feet with a 13-3/8 inch 68 lbs surface casing set at 2588 feet. The NDB-032 was logged with a CAST-M/CBL-M tool combination ran from 0 to 5849 feet. No cement in tieback. Cement evaluation completed from 2417’ – 5822’ in 9.625” 47# liner. The CAST-M is an Ultrasonic tool that records a waveform for each “shot” around the pipe 360 degrees. In the NDB-032 well, the CAST-M waveforms were recorded at 90 shots/scan and 4 scans per foot. The CBL-M is a standard cement bond log recording 3-foot and 5-foot omni-directional waveforms. The 3-foot amplitude and travel time are measured from the amplitude of the E1 peak of the 3-foot waveform. Halliburton also uses a program called Advanced Cement Evaluation (ACE) that was developed 1998. This program is explained in detail in the appendix. DEPTH(ft)BONDCLASSIFICATIONCOMMENTS 2608–2646 3664–3804 4043–4250 4654–4790 4940–4998 5278–5822 GOODGoodbondingandcoverageseenintheseareas.Debrisonlowside (centerofimpedancetrack)causinglowerimpedanceinthat direction.Greaterthan80% 2646–3664 3804–4043 4250–4654 4814–4940 4998–5278 FAIRFairbondingandcoverageseenintheseareas.Debrisonlowside (centerofimpedancetrack)causinglowerimpedanceinthat direction.Between50%Ͳ80% 2417–2608 4790Ͳ4814 POORPoorbondingandcoverageseenintheseareas.Between20%Ͳ50% Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 3 Formation Reservoir Services Table of Contents Executive Summary ................................................................................................................................................................ 2 Table of Contents ................................................................................................................................................................... 3 Quality Control ....................................................................................................................................................................... 4 Well Schematic NDB-032 ...................................................................................................................................................... 5 Tool Diagram ......................................................................................................................................................................... 6 Cement Information ................................................................................................................................................................ 7 Advanced Cement Evaluation (ACE) Log Screen Captures .................................................................................................. 8 Disclaimer ............................................................................................................................................................................ 22 Appendix .............................................................................................................................................................................. 23 Advanced Cement Evaluation (ACE) ................................................................................................................................... 25 ACE for Cement Bond Log (CBL) Tools ......................................................................................................................... 25 Segmented Presentation for Ultrasonic Tools ...................................................................................................................... 30 Advanced Cement Evaluation for Ultrasonic Tools ............................................................................................................. 32 Table of Figures Figure 1: Well Schematic NDB-032 ...................................................................................................................................... 5 Figure 2: Halliburton CAST-M/CBL-M Tool Diagram ......................................................................................................... 6 Figure 3: Lead and Tail Cement Information ......................................................................................................................... 7 Figure 4: ACE presentation Full Liner Interval ...................................................................................................................... 8 Figure 5: ACE presentation; Lead Poor (2417’ – 2608’) & Good (2608’ – 2646’) Bonding and Coverage .......................... 9 Figure 6: ACE presentation 2646’ – 3664’; Lead Fair Bonding and Coverage .................................................................... 10 Figure 7: ACE presentation 3664’ – 3804’; Lead Good Bonding and Coverage ................................................................. 11 Figure 8: ACE presentation 3804’ – 4043’; Lead Fair Bonding and Coverage .................................................................... 12 Figure 9: ACE presentation 4043’ – 4250’; Lead Good Bonding and Coverage ................................................................. 13 Figure 10: ACE presentation 4250' - 4654'; Lead Fair Bonding and Coverage ................................................................... 14 Figure 11: ACE presentation 4654' - 4790'; Lead Good Bonding and Coverage ................................................................. 15 Figure 12: ACE presentation 4790' - 4814'; Lead Poor Bonding and Coverage .................................................................. 16 Figure 13: ACE presentation 4814' - 4940'; Lead Fair Bonding and Coverage ................................................................... 17 Figure 14: ACE presentation 4940' - 4998'; Lead Good Bonding and Coverage ................................................................. 18 Figure 15: ACE presentation 4998' - 5278'; Lead Fair Bonding and Coverage ................................................................... 19 Figure 16: ACE presentation 5278' - 5780'; Lead Good Bonding and Coverage ................................................................. 20 Figure 17: ACE presentation 5780' - 5822'; Tail Good Bonding and Coverage ................................................................... 21 Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 4 Formation Reservoir Services Quality Control All cement evaluation tools need to be very well centralized for proper usage. For the sonic cement bond log (CBL-M) the best curve to evaluate the centralization of the tool is the 3-foot travel time/transit time from the 3-foot receiver. This curve should be very straight in the free pipe section but will show movement in the areas of cement bond. It is assumed that the centralization does not change during the run, and if the 3-foot travel time curve indicates good centralization in free pipe that centralization is carried over into the bonded pipe section. For the ultrasonic CAST-M a tool eccentricity (ECC) is recorded from the CAST-M waveforms first arrival comparing each shot with the shot 180º out to check the centering of the CAST-M spinning head/transducer. Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 5 Formation Reservoir Services Well Schematic NDB-032 Figure 1: Well Schematic NDB-032 Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 6 Formation Reservoir Services Tool Diagram Figure 2: Halliburton CAST-M/CBL-M Tool Diagram Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 7 Formation Reservoir Services Cement Information Figure 3: Lead and Tail Cement Information Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 8 Formation Reservoir Services Advanced Cement Evaluation (ACE) Log Screen Captures Figure 4: ACE presentation Full Liner Interval Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 9 Formation Reservoir Services Figure 5: ACE presentation; Lead Poor (2417’ – 2608’) & Good (2608’ – 2646’) Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 10 Formation Reservoir Services Figure 6: ACE presentation 2646’ – 3664’; Lead Fair Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 11 Formation Reservoir Services Figure 7: ACE presentation 3664’ – 3804’; Lead Good Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 12 Formation Reservoir Services Figure 8: ACE presentation 3804’ – 4043’; Lead Fair Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 13 Formation Reservoir Services Figure 9: ACE presentation 4043’ – 4250’; Lead Good Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 14 Formation Reservoir Services Figure 10: ACE presentation 4250' - 4654'; Lead Fair Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 15 Formation Reservoir Services Figure 11: ACE presentation 4654' - 4790'; Lead Good Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 16 Formation Reservoir Services Figure 12: ACE presentation 4790' - 4814'; Lead Poor Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 17 Formation Reservoir Services Figure 13: ACE presentation 4814' - 4940'; Lead Fair Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 18 Formation Reservoir Services Figure 14: ACE presentation 4940' - 4998'; Lead Good Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 19 Formation Reservoir Services Figure 15: ACE presentation 4998' - 5278'; Lead Fair Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 20 Formation Reservoir Services Figure 16: ACE presentation 5278' - 5780'; Lead Good Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 21 Formation Reservoir Services Figure 17: ACE presentation 5780' - 5822'; Tail Good Bonding and Coverage Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 22 Formation Reservoir Services Disclaimer Because of the uncertainty of variable well conditions the necessity of relying on facts and supporting services furnished by others, Halliburton IS UNABLE TO GUARANTEE THE EFFECTIVENESS OF THE PRODUCTS, SUPPLIES OR MATERIALS, NOR THE RESULTS OF ANY TREATMENT OR SERVICE, NOR THE ACCURACY OF ANY CHART INTERPRETATION, RESEARCH ANALYSIS, JOB RECOMMENDATION OR OTHER DATA FURNISHED BY Halliburton. Halliburton personnel will use their best efforts in gathering such information and their best judgment in interpreting it, but Customer agrees that Halliburton shall not be liable for and Customer SHALL RELEASE, DEFEND AND INDEMNIFY Halliburton against any damages or liability arising from the use of such information even if such damages are contributed to or caused by the negligence, fault or strict liability of Halliburton Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 23 Formation Reservoir Services Appendix Overview Advanced Cement Evaluation or ACE consists of a series of programs that uses standard logging data from several types of tools to improve the interpretation of cement bonding. These programs use both the raw data, and how that data varies, to help determine the presence of a cement sheath or lack thereof. This process was originally developed for the early generation of ultrasonic tools that consisted of 8 transducers in the early 1990’s. Cement Interpretation Logging Tools The standard cement interpretation logging tools consists of two major classes, sonic and ultrasonic. The sonic logging tools are typically a Cement Bond Log (CBL), Segmented Bond Tool (SBT), and Radial Bond Tool (RBT). The ultrasonic tools consist of a rotating transducer (CAST-V/ USIT) or 8 stationary transducers (PET/CET) Advanced Cement Evaluation (ACE) An interpretation method Advanced Cement Evaluation (ACE) broadens and refines on previously published methods to effectively evaluate cement with the common cement evaluation tools. The original process developed in the early 1990s now incorporates a statistical variance mapping product for both sonic and ultrasonic tools. The resulting variance image from the ultrasonic tools allows detection of minor changes in cement or fluid composition and aids in the interpretation of the pipe- to-cement bond. This technique provides a robust product solving for zonal isolation and channeling for all cement compositions. ACE is valid and effective in both time and cost. Additionally, since the process does not require additional logging passes the expense for the improved evaluation is minimal. Halliburton can use ACE to process data acquired by any cement evaluation tool on the market, including the Schlumberger USIT, Baker-Atlas SBT and any radial bond tool RBT. It is also possible to process non-standard sonic data, such as monopoles from open hole logging tools such as the WaveSonic. The output of ACE can be tailored to any customer requirement, such as the BP option that defines a specific presentation which identifies material behind pipe as gas, liquid, contaminated cement, and cement. Changes can also be incorporated in the software as needed to adapt to new tools, specific casing conditions, and or other needs. Data Requirements Since the ACE programs work on the variance of the original logging data, the original data must be in digital format. If there is no waveform data, (CBL waveforms, ultrasonic impedance vectors) the Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 24 Formation Reservoir Services information can be provided in ASCII or LAS format. When waveforms are involved the data must be in either LIS or DLIS format to handle this type of data. All types of data can be delivered to Halliburton either on a CD, or via electronic transmission. Likewise the results of ACE can be delivered by either method. References Harness, P.E., Sabins, F.L., and Griffith, J.E.: “New Technique Provides Better Low-Density-Cement Evaluation,” paper SPE 24050 presented at the 1992 SPE Western Regional Meeting, Bakersfield, California, U.S.A., 30 March to 1 April 1992. Frisch, G., Graham, L., Griffith, J.: “Assessment of Foamed - Cement Slurries Using Conventional Cement Evaluation Logs and Improved Interpretation Methods,” paper SPE 55649, presented at the 1999 SPE Rocky Mountain Regional Meeting held in Gillette, Wyoming, 15–18 May 1999. Frisch, G., Graham, L., Griffith, J.: “A Novel and Economical Processing Technique Using Conventional Bond Logs and Ultrasonic Tools for Enhanced Cement Evaluation”, SPWLA Paper EE presented at the 41st Annual Logging Symposium, Dallas, Texas June 4 - 7, 2000. Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 25 Formation Reservoir Services Advanced Cement Evaluation (ACE) Unfortunately, the standard approach of cement evaluation does not provide the most accurate method for determination of zonal isolation. New cement additives, fluids, and nitrogen — all change the acoustic properties of the cement, which affect the zonal isolation assessment. Incorrect interpretation often leads to an unnecessary remedial cement treatment. Thus, it is time to seriously evaluate cement evaluation techniques to reduce needless remedial cement expenses. Ultrasonic tools normally require an impedance contrast in the materials behind pipe to differentiate between cement and fluids. The impedance of foam or complex cements can be lower than that of water, drilling mud, or spacer fluid, and can even approach the impedance of free gas. Because of low acoustic impedance, the data and images may indicate fluid behind casing rather than cement even when zonal isolation is achieved. An interpretation method Advanced Cement Evaluation (ACE) broadens and refines on previously published methods to effectively evaluate cement with the common cement evaluation tools. The new process directly calculates the level of activity of both the CBL and ultrasonic data. The resulting variance image from the ultrasonic tools allows detection of minor changes in cement or fluid composition and aids in the interpretation of the pipe-to-cement bond. Using this technique, several new ultrasonic cement-bond curves have been developed that, when used in conjunction with CBL amplitude data, refine the pipe-to-cement bond assessment. The CBL variance will allow differences between free, partially bonded, and bonded pipe to be easily recognized. A revolutionary result is presented from the CBL data alone that highlights this technique in evaluating cement bond in multiple casing strings. ACE is valid and effective in both time and cost. Additionally, since the process does not require additional logging passes the expense for the improved evaluation is minimal. The process will work with several different tools from assorted service companies. In the examples, the interpretation is focused to answer the basic question, "Should remedial cementing be performed, or should the well be perforated for production?" ACE for Cement Bond Log (CBL) Tools CBL analysis has not been updated since the development of the CBL MSG presentation in the early sixties. The use of digital recording units, more accurate timing of the receivers and transmitters, and enhancements in computer capabilities allowed new advancements in this 40-year-old technology. Previous work published by Harness et al. (1992) and Frisch et al. (1998) describes Statistical Variance Processing or SVP as applied to the ultrasonic tools. The aim of SVP processing was designed to highlight the subtle changes in the impedance in order to distinguish solid and liquid phases, especially in lightweight or foam cements. Adapting this technique to the CBL waveform data highlighted information currently not being used in the evaluation of cement bonding. The essential portions of this interpretation are collar response, and both the waveform amplitudes and behavior in free, bonded, partially bonded, and micro-annulus situations. Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 26 Formation Reservoir Services Applying the SVP processing to the entire acoustical waveform and determining the variance between vertical sample points allows subtle changes to be recognized. With the SVP processing color scheme, small changes are light in color while large variations are dark. Therefore, when pipe is free or has “railroad tracks”, there will be little difference in vertical samples and should be indicated by light colors. Likewise, when there are changes in the acoustic waveform in bonded pipe the variance color should be dark. The new processing applied in Figure 1 in track 4; the CBL variance shows the difference between vertical samples of the acoustic waveform. Collar response is particularly noticeable in the free pipe section as a wedge. This wedge expands from left to right. The initial vertical distance between the two sides of the wedge is about 5 feet, the same as the distance between the CBL source and receiver. As the pipe to cement bond increases, the ends of this wedge narrow and approach five feet as seen around X262. As the quality of the cement bond increases the collar response disappears almost entirely but is still visible at X350. As the bond increases from the top to the bottom of the log, a noticeable change in the colors is visible as expected. In the same example, the variance processing results are added to a combination clipped CBL MSG. The negative lobes are normalized, and the variance is added to achieve the CBL total. This will highlight both the high amplitude portion of the CBL waveform along with the differences. In other words, it combines the best of the normal CBL MSG display along with the new variance processing. As shown, the collar response in the free section is clearly visible along with the high amplitude free pipe signal at X100. Notice that in the bonded section, as the variance increases, the irregular pattern of the formation signal is accented. Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 27 Formation Reservoir Services ACE CBL Log Presentation X100X100 X200X200 X300X300 GAMMAGAMMA 0 1500 150 TTTT 250 150250 150 AMPLIFIEDAMPLIFIED AMPLITUDEAMPLITUDE 0 100 10 AMPLITUDEAMPLITUDE 0 700 70 CBL MSGCBL MSG --15 1515 15 CBL VARIANCE CBL VARIANCE 0 16 0 16 CBL TOTALCBL TOTAL --1 151 15 CCLCCL X100X100 X200X200 X300X300 X100X100 X200X200 X300X300 X100X100 X200X200 X300X300 GAMMAGAMMA 0 1500 150 TTTT 250 150250 150 AMPLIFIEDAMPLIFIED AMPLITUDEAMPLITUDE 0 100 10 AMPLITUDEAMPLITUDE 0 700 70 CBL MSGCBL MSG --15 1515 15 CBL VARIANCE CBL VARIANCE 0 16 0 16 CBL TOTALCBL TOTAL --1 151 15 CCLCCL GAMMAGAMMA 0 1500 150 TTTT 250 150250 150 AMPLIFIEDAMPLIFIED AMPLITUDEAMPLITUDE 0 100 10 AMPLITUDEAMPLITUDE 0 700 70 CBL MSGCBL MSG --15 1515 15 CBL VARIANCE CBL VARIANCE 0 16 0 16 CBL TOTALCBL TOTAL --1 151 15 CCLCCL Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 28 Formation Reservoir Services Cement Evaluation in Casing Overlap Cement evaluation in casing to casing annuli has been extremely difficult due to the excessive noise reflected from the outer string. In testing this new processing procedure, a startling phenomenon was observed which helps determine the presence of cement bonding in concentric strings of pipe. In Figure 2 the standard CBL acoustic waveform and MSG are shown in tracks 2 and 3. Standard interpretation of this 9 5/8-in. casing inside 13-in. casing should indicate that there is very little cement bond due to the classical appearance of the waveform and the high amplitude. With the SVP processing applied to the CBL waveform, the appearance of two sets of collars is noticeable. The collar response from the first string appears to be the same as the free pipe signal shown in the previous example; however, the response is more of a classical arrowhead. The arrowhead collar response is typical when there is a micro-annulus. The lack of variation in the first pipe signal arrival is also a sign of a micro-annulus. The center of the arrowhead remains constant in height while the wedge increases from left to right. The second collar response appears as a bonded pipe collar pattern later in time and is spaced about 45 feet apart while the inner string is around 40 feet apart. The outer casing collar response is only possible if there is acoustic coupling between the two strings. This CBL waveform processing has been successfully applied to 13 3/8-in. casing inside 17-in. casing and applied to other service companies’ data. This process does not extend to cement evaluation beyond the second string of pipe. Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 29 Formation Reservoir Services Casing Overlap or Liner Example A000A000 A100A100 TRAVELTRAVEL TIMETIME 350 250350 250 GAMMAGAMMA 0 1500 150 AMPLIFIEDAMPLIFIED AMPLITUDEAMPLITUDE 0 0 10 10 AMPLITUDEAMPLITUDE 0 700 70 CBL WAVEFORMCBL WAVEFORM WMSGWMSG -20 -20 20 20 VARIANCEVARIANCE CBL WAVEFORMCBL WAVEFORM WMSGDWMSGD 0 0 15 15 TOTALTOTAL CBL WAVEFORMCBL WAVEFORM WMSGTWMSGT 0 0 20 20CCLCCL Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 30 Formation Reservoir Services Segmented Presentation for Ultrasonic Tools The impedance calculation is performed in the same method whether using the new generation of ultrasonic tools or the previous eight transducer tools. Unlike the CBL logs, in which the data are Omni-Directional, the data from the ultrasonic tools are azimuthal. Not only can channels in cement be detected; but also the orientations of the channels can be determined and the proper squeeze and/or remedial action can be undertaken. Because of the high horizontal sample rate, the data are normally presented in a color-coded image instead of a single curve. The color coding is based on the impedances of gas, water, and cement. Color images as seen with the CBL provide detailed quality information. However, these images restrict presenting the data in an easy-to-understand manner when dealing with complex cements, or when fax transmissions are required. CAST with Segmented Curves Figure 3 shows the relative position of the impedance vector to the wellbore. The impedance map is broken into nine segments and five equally spaced curves from each segment are plotted. Since the map is orientated to the low side of the hole, segment E will always be on the low side while segments A and I will be on the high side. This curve segmentation provides two major evaluation purposes by allowing the actual impedance from each curve to be shown and by providing a measure of the activity level of the data. SECTION A SECTION B SECTION C SECTION DSECTION E SECTION F SECTION G SECTION H SECTION I LOW SIDE OF HOLELOW SIDE OF HOLE HIGH SIDE OF HOLEHIGH SIDE OF HOLE Left side of Left side of ZP imageZP image Right side ofRight side of ZP imageZP image Middle of ZP imageMiddle of ZP image SECTION A SECTION B SECTION C SECTION DSECTION E SECTION F SECTION G SECTION H SECTION I LOW SIDE OF HOLELOW SIDE OF HOLE HIGH SIDE OF HOLEHIGH SIDE OF HOLE Left side of Left side of ZP imageZP image Right side ofRight side of ZP imageZP image Middle of ZP imageMiddle of ZP image Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 31 Formation Reservoir Services . CAST with Segmented Curves Figure 4 is a log from an ultrasonic scanning tool. Track 1 provides correlation data, average, and tool decentering data. Post processing cement evaluation of a poorly centralized ultrasonic tool is difficult at best. These tools must be well centralized. The standard cement image presented in track 2 is corrected to the low side of the hole. This will help determine if the cement problem is correctable or not due to pipe position in the wellbore. Tracks 3-11 are the segmented curves from the impedance GAMMAGAMMA 0 1000 100 AVG. ZAVG. Z 10 10 0 0 ECENECEN 0 10 1 SEGMENTED IMPEDANCE CURVESSEGMENTED IMPEDANCE CURVES 0--------50--------5 IMPEDANCEIMPEDANCE 0 6.150 6.15 A2A2 A4A4 A6A6 A8A8 A10A10 C24C24 C26C26 C28C28 C30C30 C32C32 D36D36 D38D38 D40D40 D42D42 D44D44 B14B14 B16B16 B18B18 B20B20 B22B22 E46E46 E48E48 E50E50 E52E52 E54E54 F58F58 F60F60 F62F62 F64F64 F66F66 G68G68 G70G70 G72G72 G74G74 G76G76 H80H80 H82H82 H84H84 H86H86 H88H88 I90I90 I92I92 I94I94 I96I96 I98I98 HIGH--LOW--HIGHHIGH--LOW--HIGH SIDE OF HOLE SIDE OF HOLE A-B-C-D-E-F-G-H-IA-B-C-D-E-F-G-H-I M025 M025 M050 M050 M075 M075 Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 32 Formation Reservoir Services map. The channel is clearly identified on both the impedance map and the segmented curves starting about M067 to M010. The impedance of the material in the channel is about 1.7, which is an indication of water. Advanced Cement Evaluation for Ultrasonic Tools Harness et al. (1992) provided a technique for multi-transducer tools to distinguish foamed cement from fluid, even when both have the same impedance. The technique relies on a statistical variation process (SVP) to discern solid crystalline structures, such as cements, from fluids. Solid-free liquids have a consistent or steady activity level on logs while solids, when mixed with either fluid or gas, have an irregular activity level. In other words cement, with a mixture of solids, liquids, and in the case of foamed cement, gas, should exhibit a high degree of variability in the impedance measurement. A consistent phase, such as water, gas, or drilling mud, will exhibit less variation in the computed impedance. Analysis of the vertical rate of impedance change, once tool position is taken into account, permits easy determination of whether foamed cement or liquid is present. Frisch et al. (1998) developed a process using the initial SVP processing for the ultrasonic scanning that removes the normalization that was required for the multi-transducer tools. With this new process, the level of impedance activity is now calculated directly as a variance, enabling detection of minor changes in cement or fluid composition and aiding in the interpretation of foamed cement. A resulting variance image is used to distinguish cements from fluids. The fluid cutoff for the activity level should be consistent from tool to tool for a specific tool design. It may however, vary between different designs and, therefore, between service companies but range in general from 0.15 to 0.45. This fluid level cutoff will determine the scale at which the variance is plotted. SVP processing assumes that cements are not consistent, but it does not use the impedance values directly in determining if the material is solid or liquid. Combining the SVP processing methods with the original impedance data provides an easier method for determining the pipe-to-cement bond. Since liquids should have both low impedance and low activity level, it is sensible to use this information to determine if the annular material is solid or liquid. This new image combines the original impedance data along with the variance data to create a new image called cement. This cement image is binary, either cement or fluid depending upon user defined limits. Several new curves from the scanning tool are presented which will permit better understanding of the calculated bond between the pipe and cement. The curves are based on the number of shots per sample depth and are normalized between 0 (poor bond) and 1 (excellent bond). ZP BI is the normal bond index from the impedance map without any further processing. CEMENT BI is the bond index from the cement image. These curves should track the amplitude curve from the CBL because both measurements are an indication of cement-to-pipe bond. Examination of various logs and presentations illustrates the procedures involved in this new interpretation method Figure 5 illustrates a complete new analysis of both the CBL and ultrasonic data over the same well as Figure 4. The new ultrasonic process is presented in tracks 6 and 7, labeled variance and cement respectfully. The variance of the data is scaled from 0 to 0.6 with fluid displayed in blue while solids have varying shades of brown. In the variance track, the lower center section of the image below M075 is shown to be a fluid; however, referring back to Figure 36 the impedance is about 3. This is really consistent cement due to the low activity level as shown is in the previous figure. The inability of variance to distinguish consistent cement and water requires the use of the cement image incorporating the variance results and the original impedance data to correctly interpret the material behind casing. It is Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 33 Formation Reservoir Services still easy to see the channel from M067 to M010 on both the variance and cement image. The section below M075 is determined to be cement by the original impedance data. Standard ACE Log presentation with Variance and Cement Tracks CBL MSGCBL MSG -20 20-20 20 CBL TOTALCBL TOTAL 0 200 20 IMPEDANCEIMPEDANCE 0 6.150 6.15 VARIANCEVARIANCE 0 0 1 1 CEMENTCEMENT 0 10 1 GAMMAGAMMA 0 0 100 100 AVG. ZAVG. Z 10 010 0 ECENECEN 0 10 1 AMP.AMP. AMPLITUDEAMPLITUDE 0 0 10 10 AMPLITUDEAMPLITUDE 0 0 70 70 ZP BIZP BI 1 01 0 CEMENT BICEMENT BI 1 01 0 M025 M025 M050 M050 M075 M075 Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 34 Formation Reservoir Services The next example (Figures 6 and 7) displays the recommended presentations to fully utilize the information available from both the CBL and ultrasonic scanning tool in evaluating light weight (e.g., 8-lb/gal) cement. Figure 6 is the standard impedance image with sectional curves providing both the impedance data along with activity levels. Typical evaluation of the original impedance image would indicate free pipe and would be a candidate for a squeeze. The segmented curves indicate that there are solids present due to the activity level and lack of curve stacking over the entire log. CAST with Segmented Curves for an 8-Lb/Gal Slurry Figure 7 is the standard advanced cement evaluation log utilizing the new processing. As with the collar signature described above, use of these new process images and colors provides important characteristics in evaluating the cement. Notice that when high contrasts between black and white in the CBL data the corresponding data from the ultrasonic tool indicate liquids. At the same time, the orange colors in the CBL data correspond to browns in the ultrasonic data. X550X550 GAMMAGAMMA 0 1000 100 AVG. ZAVG. Z 10 10 00 ECENECEN 0 10 1 SEGMENTED IMPEDANCE CURVESSEGMENTED IMPEDANCE CURVES 0--------50--------5 IMPEDANCEIMPEDANCE 0 6.150 6.15 A2A2 A4A4 A6A6 A8A8 A10A10 C24C24 C26C26 C28C28 C30C30 C32C32 D36D36 D38D38 D40D40 D42D42 D44D44 B14B14 B16B16 B18B18 B20B20 B22B22 E46E46 E48E48 E50E50 E52E52 E54E54 F58F58 F60F60 F62F62 F64F64 F66F66 G68G68 G70G70 G72G72 G74G74 G76G76 H80H80 H82H82 H84H84 H86H86 H88H88 I90I90 I92I92 I94I94 I96I96 I98I98 HIGH--LOW--HIGHHIGH--LOW--HIGH SIDE OF HOLE SIDE OF HOLE A-B-C-D-E-F-G-H-IA-B-C-D-E-F-G-H-I X550X550X550X550 GAMMAGAMMA 0 1000 100 AVG. ZAVG. Z 10 10 00 ECENECEN 0 10 1 SEGMENTED IMPEDANCE CURVESSEGMENTED IMPEDANCE CURVES 0--------50--------5 IMPEDANCEIMPEDANCE 0 6.150 6.15 A2A2 A4A4 A6A6 A8A8 A10A10 C24C24 C26C26 C28C28 C30C30 C32C32 D36D36 D38D38 D40D40 D42D42 D44D44 B14B14 B16B16 B18B18 B20B20 B22B22 E46E46 E48E48 E50E50 E52E52 E54E54 F58F58 F60F60 F62F62 F64F64 F66F66 G68G68 G70G70 G72G72 G74G74 G76G76 H80H80 H82H82 H84H84 H86H86 H88H88 I90I90 I92I92 I94I94 I96I96 I98I98 HIGH--LOW--HIGHHIGH--LOW--HIGH SIDE OF HOLE SIDE OF HOLE A-B-C-D-E-F-G-H-IA-B-C-D-E-F-G-H-IGAMMAGAMMA 0 1000 100 AVG. ZAVG. Z 10 10 00 ECENECEN 0 10 1 SEGMENTED IMPEDANCE CURVESSEGMENTED IMPEDANCE CURVES 0--------50--------5 IMPEDANCEIMPEDANCE 0 6.150 6.15 A2A2 A4A4 A6A6 A8A8 A10A10 C24C24 C26C26 C28C28 C30C30 C32C32 D36D36 D38D38 D40D40 D42D42 D44D44 B14B14 B16B16 B18B18 B20B20 B22B22 E46E46 E48E48 E50E50 E52E52 E54E54 F58F58 F60F60 F62F62 F64F64 F66F66 G68G68 G70G70 G72G72 G74G74 G76G76 H80H80 H82H82 H84H84 H86H86 H88H88 I90I90 I92I92 I94I94 I96I96 I98I98 HIGH--LOW--HIGHHIGH--LOW--HIGH SIDE OF HOLE SIDE OF HOLE A-B-C-D-E-F-G-H-IA-B-C-D-E-F-G-H-I Santos Cement Evaluation Log NDB-032 Halliburton Energy Services 35 Formation Reservoir Services Advanced Cement Evaluation Display for an 8-Lb/Gal Slurry The cement in Figure 7 is very inconsistent and vuggy, but the vertical zonal isolation is probably achieved. At X570, the void in both cement and variance images corresponds to an indication of less than perfect cement-to-pipe bond as indicated by the CBL images. The amplitude curve and the cement BI curves indicate bonding ranging from a high of 90% down to about 25 %. Over the entire well, these two curves track each other, indicating about the same bond but measured and calculated from two different devices. Where they separate, the cement is more inconsistent or vuggy but is circumferential thus effectively dampening the acoustic signal. The presentation is oriented so that the high side of the hole, on the presentation, is at the intersection of Sections A and I. The low side of the hole is at Section E. X550X550 CBL MSGCBL MSG -20 20-20 20 CBL TOTALCBL TOTAL 0 200 20 IMPEDANCEIMPEDANCE 0 6.150 6.15 VARIANCEVARIANCE 0 0 11 CEMENTCEMENT 0 10 1 GAMMAGAMMA 0 0 100100 AVG. ZAVG. Z 10 010 0 ECENECEN 0 10 1 AMP.AMP. AMPLITUDEAMPLITUDE 0 0 1010 AMPLITUDEAMPLITUDE 0 0 7070 ZP BIZP BI 1 01 0 CEMENT BICEMENT BI 1 01 0CCLCCL X550X550X550X550 CBL MSGCBL MSG -20 20-20 20 CBL TOTALCBL TOTAL 0 200 20 IMPEDANCEIMPEDANCE 0 6.150 6.15 VARIANCEVARIANCE 0 0 11 CEMENTCEMENT 0 10 1 GAMMAGAMMA 0 0 100100 AVG. ZAVG. Z 10 010 0 ECENECEN 0 10 1 AMP.AMP. AMPLITUDEAMPLITUDE 0 0 1010 AMPLITUDEAMPLITUDE 0 0 7070 ZP BIZP BI 1 01 0 CEMENT BICEMENT BI 1 01 0CCLCCL CBL MSGCBL MSG -20 20-20 20 CBL TOTALCBL TOTAL 0 200 20 IMPEDANCEIMPEDANCE 0 6.150 6.15 VARIANCEVARIANCE 0 0 11 CEMENTCEMENT 0 10 1 GAMMAGAMMA 0 0 100100 AVG. ZAVG. Z 10 010 0 ECENECEN 0 10 1 AMP.AMP. AMPLITUDEAMPLITUDE 0 0 1010 AMPLITUDEAMPLITUDE 0 0 7070 ZP BIZP BI 1 01 0 CEMENT BICEMENT BI 1 01 0CCLCCL Attachment D Attachment E Attachment F A fault is mapped in the lateral of NDB-024 but there is uncertainty if the fault is present or if there is a shoreface depositional event in this area. This fault is discussed in the NDB-024 Frac Sundry. (See AOGCC's Well History File 223-076, p. 76-80, 92, 95-99 of Sundry Application 323-591 and AOGCC's Hydraulic Fracturing Checklist that accompanies that application. The fault shown above is labeled “Fault 4” in those documents.) SFD Attachment G Well Name NDB-32 11/13/23 Preliminary Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) a FP 0 b FP 0 c WF 25 3.5 30 30 1260 1260 30 30 d 30 e Pump Check WF 25 20 200 230 8400 9660 200 230 f Pump DataFRAC pad XL 25 40 300 530 12600 22260 300 530 g Displace DF WF 25 40 185 715 7770 30030 185 715 h Displace surface lines with FP if <20F FP 25 15 715 0 30030 0 715 i Shutdown & Monitor 715 0 30030 0 715 j WF 25 3.5 30 745 1260 31290 30 745 k Load Stage 2 ball/collet, Line up for stage 1 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT CLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOB STAGE CUM STAGE CUM Size or Stage Cum #PPA TYPE (BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type (BBL)(BBL) 1 0 Line out XL XL 25 21 40 40 785 1680 32970 0 0 40 785 2 0 Drop Stage 1 Ball/Collet FP 0 21 3 43 788 126 33096 0 0 16/20 3 788 3 0 Stage 1 PAD XL 25 30 154 197 942 6468 39564 00 154942 4 0 Slow for Seat XL 25 17 50 247 992 2100 41664 00 50992 5 0 Resume Pad XL 25 40 86 333 1078 3612 45276 0 0 86 1078 6 1 Flat XL 25 40 175 508 1253 7350 52626 7039 7039 16/20 168 1246 7 3 Flat XL 25 40 200 708 1453 8400 61026 22247 29285 16/20 177 1422 8 5 Flat XL 25 40 230 938 1683 9660 70686 39550 68835 16/20 188 1610 9 7 Flat XL 25 40 230 1168 1913 9660 80346 51629 120464 16/20 176 1786 10 9 Flat XL 25 40 215 1383 2128 9030 89376 58123 178588 16/20 154 1940 11 10 Flat XL 25 40 180 1563 2308 7560 96936 52410 230998 16/20 125 2065 12 0 Clear Surface Lines XL 25 40 20 1583 2328 840 97776 0 230998 20 2085 13 0 Spacer XL 25 40 5 1588 2333 210 97986 0 230998 5 2090 14 0 Drop Stage 2 Ball/Collet FP 0 40 3 1591 2336 126 98112 0 230998 3 2093 15 0 Stage 2 XL 25 40 147 1738 2483 6174 104286 0 230998 147 2240 16 0 Slow for Seat XL 25 17 50 1788 2533 2100 106386 0 230998 50 2290 17 0 Resume Pad XL 25 21 128 1916 2661 5376 111762 0 230998 128 2418 18 1 Flat XL 25 40 190 2106 2851 7980 119742 7642 238639 16/20 182 2600 19 3 Flat XL 25 40 225 2331 3076 9450 129192 25028 263667 16/20 199 2798 20 5 Flat XL 25 40 260 2591 3336 10920 140112 44709 308376 16/20 213 3011 21 7 Flat XL 25 40 260 2851 3596 10920 151032 58363 366739 16/20 199 3210 22 9 Flat XL 25 40 230 3081 3826 9660 160692 62179 428917 16/20 164 3374 23 10 Flat XL 25 40 200 3281 4026 8400 169092 58233 487151 16/20 139 3513 24 0 Clear Surface Lines XL 25 40 20 3301 4046 840 169932 0 487151 20 3533 25 0 Spacer XL 25 40 5 3306 4051 210 170142 0 487151 5 3538 26 0 Drop Stage 3 Ball/Collet FP 25 40 3 3309 4054 126 170268 0 487151 3 3541 FLUID Neat Water COMMENTS Shut down 10 minutes Shut down 10 minutes Prime and Pressure Test Open well and open initiator sleeve Displace Prime up Fluid Displace Prime up Fluid if required Well Name NDB-32 11/13/23 Preliminary Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) FLUID Neat Water 27 0 Stage 3 XL 25 40 139 3448 4193 5838 176106 0 487151 139 3680 28 0 Slow for Seat XL 25 17 50 3498 4243 2100 178206 0487151 503730 29 0 Resume Pad XL 25 40 111 3609 4354 4662 182868 0 487151 111 3841 30 1 Flat XL 25 40 100 3709 4454 4200 187068 4022 491173 16/20 96 3937 31 2 Flat XL 25 21 175 3884 4629 7350 194418 13505 504677 16/20 161 4097 32 3 Flat XL 25 40 200 4084 4829 8400 202818 22247 526924 16/20 177 4274 33 4 Flat XL 25 40 200 4284 5029 8400 211218 28547 555472 16/20 170 4444 34 5 Flat XL 25 40 200 4484 5229 8400 219618 34391 589863 16/20 164 4608 35 6 Flat XL 25 40 200 4684 5429 8400 228018 39827 629690 16/20 158 4766 36 7 Flat XL 25 40 150 4834 5579 6300 234318 33671 663360 16/20 115 4880 37 8 Flat XL 25 40 140 4974 5719 5880 240198 34742 698102 16/20 103 4984 38 0 Clear Surface Lines XL 25 40 20 4994 5739 840 241038 0698102 205004 39 0 Spacer XL 25 40 5 4999 5744 210 241248 0 698102 5 5009 40 0 Drop "x" Ball/Collet FP 0 40 3 5002 5747 126 241374 0 698102 3 5012 41 0 Stage 4 XL 25 40 131 5133 5878 5502 246876 0 698102 131 5143 42 0 Slow for Seat XL 25 17 50 5183 5928 2100 248976 0698102 505193 43 0 Resume Pad XL 25 40 94 5277 6022 3948 252924 0 698102 94 5287 44 1 Flat XL 22 40 190 5467 6212 7980 260904 7642 705744 16/20 182 5468 45 3 Flat XL 25 40 210 5677 6422 8820 269724 23359 729104 16/20 185 5654 46 5 Flat XL 25 40 235 5912 6657 9870 279594 40410 769513 16/20 192 5846 47 7 Flat XL 25 40 235 6147 6892 9870 289464 52751 822264 16/20 179 6026 48 9 Flat XL 25 40 180 6327 7072 7560 297024 48662 870926 16/20 129 6154 49 10 Flat XL 25 40 160 6487 7232 6720 303744 46587 917512 16/20 111 6265 50 0 Clear Surface Lines XL 25 40 20 6507 7252 840 304584 0917512 206285 51 0 Spacer XL 25 40 5 6512 7257 210 304794 0 917512 5 6290 52 0 Drop "x" Ball/Collet FP 25 40 3 6515 7260 126 304920 0 917512 3 6293 53 0 XL Flush XL 25 40 30 6545 7290 1260 306180 0 917512 30 6323 54 0 LG Flush WF 25 40 94 6639 7384 3948 310128 0 917512 94 6417 55 0 Slow for seat WF 25 17 50 6689 7434 2100 312228 0917512 506467 56 0 Overflush (empty PCM)WF 25 40 100 6789 7534 4200 316428 0 917512 100 6567 0 316428 0 6567 57 Linear Flush WF 27 30 167901 42 316470 16568 58 Linear Flush WF 27 30 167912 42 316512 16569 59 3000 feet MD + Surface Eqmt FP 15 58 6849 60 2433 318945 TOTALS 38139 318945 917512 Well Name NDB-32 11/13/23 Preliminary Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) a FP b FP c WF 25 3.5 40 40 1680 1680 40 40 d 40 Pump Ball to Seat WF 25 4 160 200 6720 8400 160 200 e Increase Rate and start XL- Stage to Stage 5PAD XL 25 40 40 240 1680 10080 40 240 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT CLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOB STAGE CUM STAGE CUM Size or Stage Cum #PPA TYPE (BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type (BBL)(BBL) 1 0 Stage 5 XL 22 40 300 300 540 12600 22680 0 0 300 540 2 1 Flat XL 22 40 180 480 720 7560 30240 7240 7240 16/20 172 712 3 3 Flat XL 22 40 210 690 930 8820 39060 23359 30599 16/20 185 898 4 5 Flat XL 22 40 230 920 1160 9660 48720 39550 70149 16/20 188 1086 5 7 Flat XL 22 40 230 1150 1390 9660 58380 51629 121778 16/20 176 1262 6 9 Flat XL 22 40 215 1365 1605 9030 67410 58123 179901 16/20 154 1415 7 10 Flat XL 22 40 190 1555 1795 7980 75390 55321 235223 16/20 132 1547 8 0 Clear Surface Lines XL 22 40 20 1575 1815 840 76230 0235223 201567 9 0 Spacer XL 22 40 5 1580 1820 210 76440 0 235223 5 1572 10 0 Drop Stage 6 Ball/Collet FP 0 40 3 1583 1823 126 76566 0 235223 3 1575 11 0 Stage 6 XL 22 40 117 1700 1940 4914 81480 0 235223 117 1692 12 0 Slow for Seat XL 22 17 50 1750 1990 2100 83580 0235223 501742 13 0 Resume Pad XL 22 40 133 1883 2123 5586 89166 0 235223 133 1875 14 1 Flat XL 22 40 190 2073 2313 7980 97146 7642 242864 16/20 182 2057 15 3 Flat XL 22 40 210 2283 2523 8820 105966 23359 266224 16/20 185 2243 16 5 Flat XL 22 40 230 2513 2753 9660 115626 39550 305774 16/20 188 2431 17 7 Flat XL 22 40 230 2743 2983 9660 125286 51629 357402 16/20 176 2606 18 9 Flat XL 22 40 200 2943 3183 8400 133686 54068 411471 16/20 143 2750 19 10 Flat XL 22 40 160 3103 3343 6720 140406 46587 458057 16/20 111 2860 20 0 Clear Surface Lines XL 22 40 20 3123 3363 840 141246 0458057 202880 21 0 Spacer XL 22 40 5 3128 3368 210 141456 0 458057 5 2885 22 0 Drop Stage 7 Ball/Collet FP 22 40 3 3131 3371 126 141582 0 458057 3 2888 23 0 Stage 7 XL 22 40 109 3240 3480 4578 146160 0 458057 109 2997 24 0 Slow for Seat XL 22 17 50 3290 3530 2100 148260 0458057 503047 25 0 Resume Pad XL 22 40 116 3406 3646 4872 153132 0 458057 116 3163 26 1 Flat XL 22 40 150 3556 3796 6300 159432 6033 464090 16/20 144 3307 27 3 Flat XL 22 40 175 3731 3971 7350 166782 19466 483556 16/20 154 3462 28 5 Flat XL 22 40 200 3931 4171 8400 175182 34391 517948 16/20 164 3625 29 7 Flat XL 22 40 200 4131 4371 8400 183582 44895 562842 16/20 153 3778 30 9 Flat XL 22 40 175 4306 4546 7350 190932 47310 610152 16/20 125 3903 31 10 Flat XL 22 40 150 4456 4696 6300 197232 43675 653827 16/20 104 4007 FLUID Neat Water COMMENTS SD 10 minutes- Load Stage 6 Ball/Collet Prime and Pressure Test Open Well and line up to drop ball Drop Ball and displace PT past WH Well Name NDB-32 11/13/23 Preliminary Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) FLUID Neat Water 32 0 Clear Surface Lines XL 22 40 20 4476 4716 840 198072 0653827 204027 33 0 Spacer XL 22 40 20 4496 4736 840 198912 0 653827 20 4047 34 0 Drop Stage 8 Ball/Collet FP 0 40 3 4499 4739 126 199038 0 653827 3 4050 35 0 Stage 8 XL 22 40 102 4601 4841 4284 203322 0 653827 102 4152 36 0 Slow for Seat XL 22 17 50 4651 4891 2100 205422 0653827 504202 37 0 Resume Pad XL 22 40 123 4774 5014 5166 210588 0 653827 123 4325 38 1 Flat XL 22 40 140 4914 5154 5880 216468 5631 659458 16/20 134 4459 39 3 Flat XL 22 40 160 5074 5314 6720 223188 17798 677255 16/20 141 4600 40 5 Flat XL 22 40 190 5264 5504 7980 231168 32672 709927 16/20 156 4756 41 7 Flat XL 22 40 190 5454 5694 7980 239148 42650 752577 16/20 145 4901 42 9 Flat XL 22 40 170 5624 5864 7140 246288 45958 798535 16/20 122 5023 43 10 Flat XL 22 40 150 5774 6014 6300 252588 43675 842210 16/20 104 5127 44 0 Clear Surface Lines XL 22 40 20 5794 6034 840 253428 0842210 205147 45 0 Spacer XL 22 40 5 5799 6039 210 253638 0 842210 5 5152 46 0 Drop Stage 9 Ball/Collet FP 22 40 3 5802 6042 126 253764 0 842210 3 5155 47 0 XL Flush XL 22 40 30 5832 6072 1260 255024 0 842210 30 5185 48 0 LG Flush WF 22 40 64 5896 6136 2688 257712 0 842210 64 5249 49 0 Slow for seat WF 22 17 50 5946 6186 2100 259812 0842210 505299 50 0 Overflush (empty PCM)WF 22 40 100 6046 6286 4200 264012 0 842210 100 5399 0 264012 0 5399 51 Linear Flush WF 27 30 160471 42 264054 15400 52 Linear Flush WF 27 30 160482 42 264096 15401 53 3000 feet MD + Surface Eqmt FP 15 58 6106 60 2433 266529 TOTALS 16186 266529 842210 Well Name NDB-32 11/13/23 Preliminary Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) a FP b FP c WF 25 3.5 40 40 1680 1680 40 40 d 40 Pump Ball to Seat WF 25 4 125 165 5250 6930 125 165 e Increase Rate and start XL- Stage to Stage 9 PAD XL 25 40 40 205 1680 8610 40 205 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT CLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOB STAGE CUM STAGE CUM Size or Stage Cum #PPA TYPE (BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type (BBL)(BBL) 1 0 Stage 9 XL 22 30 300 300 505 12600 21210 0 0 300 505 2 1 Flat XL 22 30 120 420 625 5040 26250 4826 4826 16/20 115 620 3 2 Flat XL 22 30 135 555 760 5670 31920 10418 15244 16/20 124 744 4 3 Flat XL 22 30 150 705 910 6300 38220 16685 31930 16/20 132 876 5 4 Flat XL 22 30 150 855 1060 6300 44520 21411 53340 16/20 127 1004 6 5 Flat XL 22 30 150 1005 1210 6300 50820 25793 79134 16/20 123 1127 7 6 Flat XL 22 30 150 1155 1360 6300 57120 29870 109004 16/20 119 1245 8 7 Flat XL 22 30 140 1295 1500 5880 63000 31426 140430 16/20 107 1352 9 8 Flat XL 22 30 120 1415 1620 5040 68040 29779 170209 16/20 89 1441 10 0 Clear Surface Lines XL 22 30 20 1435 1640 840 68880 0170209 201461 11 0 Spacer XL 22 30 5 1440 1645 210 69090 0 170209 5 1466 12 0 Drop Stage 10 Ball/Collet FP 0 30 3 1443 1648 126 69216 0 170209 3 1469 13 0 Stage 10 XL 22 30 87 1530 1735 3654 72870 0 170209 87 1556 14 0 Slow for Seat XL 22 17 50 1580 1785 2100 74970 0170209 501606 15 0 Resume Pad XL 22 25 88 1668 1873 3696 78666 0 170209 88 1694 16 1 Flat XL 22 25 100 1768 1973 4200 82866 4022 174231 16/20 96 1789 17 2 Flat XL 22 25 110 1878 2083 4620 87486 8489 182719 16/20 101 1891 18 3 Flat XL 22 25 130 2008 2213 5460 92946 14460 197180 16/20 115 2005 19 4 Flat XL 22 25 130 2138 2343 5460 98406 18556 215736 12/18 110 2116 20 5 Flat XL 22 25 130 2268 2473 5460 103866 22354 238090 16/20 106 2222 21 6 Flat XL 22 25 110 2378 2583 4620 108486 21905 259995 16/20 87 2309 22 7 Flat XL 22 25 90 2468 2673 3780 112266 20203 280197 16/20 69 2378 23 0 Clear Surface Lines XL 22 25 20 2488 2693 840 113106 0280197 202398 24 0 Spacer XL 22 25 20 2508 2713 840 113946 0 280197 20 2418 25 0 Drop "x" Ball/Collet FP 22 25 3 2511 2716 126 114072 0 280197 3 2421 26 0 Stage 11 XL 22 25 79 2590 2795 3318 117390 0 280197 79 2500 27 0 Slow for Seat XL 22 17 50 2640 2845 2100 119490 0280197 502550 28 0 Resume Pad XL 22 20 71 2711 2916 2982 122472 0 280197 71 2621 29 1 Flat XL 22 20 80 2791 2996 3360 125832 3218 283415 16/20 77 2697 30 2 Flat XL 22 20 90 2881 3086 3780 129612 6945 290360 16/20 83 2780 31 3 Flat XL 22 20 100 2981 3186 4200 133812 11123 301484 12/18 88 2868 32 4 Flat XL 22 20 100 3081 3286 4200 138012 14274 315757 16/20 85 2953 FLUID Neat Water COMMENTS SD 10 minutes- Load Stage 10 Ball/Collet Prime and Pressure Test Open Well and line up to drop ball Drop Ball and displace PT past WH Well Name NDB-32 11/13/23 Preliminary Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) FLUID Neat Water 33 5 Flat XL 22 20 100 3181 3386 4200 142212 17196 332953 16/20 82 3035 34 6 Flat XL 22 20 90 3271 3476 3780 145992 17922 350875 16/20 71 3106 35 7 Flat XL 22 20 80 3351 3556 3360 149352 17958 368833 16/20 61 3167 0 149352 0 3167 36 XL Flush XL 22 20 20 3371 20 840 150192 20 3187 37 Linear Flush WF 22 20 27 3398 47 1134 151326 27 3214 38 3000 feet MD + Surface Eqmt FP 20 58 3456 105 2433 153759 TOTALS 12066 153759 368833 FracCADE* STIMULATION PROPOSAL Operator :Oil Search Well :NDB-32 Field :Pikka East Formation :Nanushuk Stages 1 to 11 County : North Slope State : Alaska Country : United States Prepared for : Scott Leahy Service Point : Prudhoe Bay, Alaska Business Phone : 1 907 659 2434 Date Prepared : 10-02-2023 FAX No. : 1 907 659 2538 Prepared by : Alena Lutskaia Phone : 630-780-0058 E-Mail Address :Alutskaya@slb.com * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. # SLB-Private Attachment G Section 1: Zone Data (Stage 1; 12102 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4104.5 10.0 0.71 2937 1.46E+06 0.220 1000 Shale 4114.5 15.0 0.70 2865 1.76E+06 0.220 1000 Nanushuk 3 SS 4129.5 15.3 0.68 2805 1.90E+06 0.220 1000 Top Nan CS 4144.8 19.5 0.62 2595 9.00E+05 0.270 1000 Nan SS 4164.3 2.0 0.69 2880 2.67E+06 0.230 2500 Nan CS 4166.3 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4167.8 4.5 0.62 2569 6.44E+05 0.280 1000 Nan DS 4172.3 3.5 0.69 2886 1.77E+06 0.260 1500 Nan DS 4175.8 14.5 0.65 2726 1.39E+06 0.260 1500 Nan CS 4190.3 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4191.8 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4204.3 2.0 0.65 2729 1.40E+06 0.260 1500 Nan CS 4206.3 9.0 0.61 2558 8.54E+05 0.270 1000 Nan DS 4215.3 7.0 0.65 2755 1.40E+06 0.260 1500 Nan DS 4222.3 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4231.3 3.5 0.64 2720 1.69E+06 0.260 1500 Nan DS 4234.8 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4239.8 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4241.8 10.5 0.61 2607 7.36E+05 0.270 1000 Nan CS 4252.3 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4255.8 2.0 0.61 2614 6.70E+05 0.280 1000 Nan CS 4257.8 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4263.3 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4266.8 3.5 0.63 2701 1.19E+06 0.270 1500 Nan DS 4270.3 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4275.8 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4286.3 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4287.8 5.0 0.62 2671 1.14E+06 0.270 1500 Nan DS 4292.8 2.0 0.65 2809 1.56E+06 0.260 1500 Nan DS 4294.8 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4298.8 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4300.8 10.0 0.63 2700 9.81E+05 0.270 1500 Nan DS 4310.8 4.0 0.65 2821 1.63E+06 0.260 1500 Nan DS 4314.8 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4318.8 9.5 0.64 2784 1.33E+06 0.260 1500 Nan DS 4328.3 2.0 0.61 2649 7.82E+05 0.270 1000 Nan DS 4330.3 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4339.8 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4341.8 2.0 0.69 3002 2.67E+06 0.230 2500 Nan DS 4343.8 2.0 0.64 2765 1.09E+06 0.270 1500 Shale 4345.8 2.0 0.69 3005 2.67E+06 0.230 2500 Nan DS 4347.8 4.0 0.65 2844 1.29E+06 0.260 1500 Shale 4351.8 19.5 0.69 3015 2.67E+06 0.230 2500 Nan DS 4371.3 2.0 0.64 2820 1.36E+06 0.260 1500 Shale 4373.3 2.0 0.69 3024 2.67E+06 0.230 2500 Nan DS 4375.3 8.0 0.65 2855 1.37E+06 0.260 1500 Nan DS 4383.3 8.0 0.65 2841 1.56E+06 0.260 1500 Shale 4391.3 20.0 0.69 3042 2.67E+06 0.230 2500 Zone Name Poisson’s Ratio Formation Mechanical Properties # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4104.5 10.0 0.001 1.0 1890 4114.5 15.0 0.001 1.0 1898 4129.5 15.3 0.005 10.0 1905 4144.8 19.5 30.655 23.7 1915 4164.3 2.0 5.000 10.0 1924 4166.3 1.5 2.095 16.9 1925 4167.8 4.5 48.388 26.6 1926 4172.3 3.5 0.478 12.4 1928 4175.8 14.5 15.008 17.7 1930 4190.3 1.5 3.661 17.6 1937 4191.8 12.5 34.723 23.9 1937 4204.3 2.0 1.697 15.6 1943 4206.3 9.0 54.319 24.4 1944 4215.3 7.0 3.610 14.8 1948 4222.3 9.0 22.986 20.4 1952 4231.3 3.5 0.835 14.0 1956 4234.8 5.0 65.392 23.4 1957 4239.8 2.0 0.006 10.5 1960 4241.8 10.5 100.832 25.6 1961 4252.3 3.5 17.434 20.5 1966 4255.8 2.0 161.343 26.3 1967 4257.8 5.5 4.627 18.4 1968 4263.3 3.5 5.075 14.8 1971 4266.8 3.5 8.651 19.4 1972 4270.3 5.5 10.205 16.0 1974 4275.8 10.5 17.356 20.1 1977 4286.3 1.5 3.106 14.8 1982 4287.8 5.0 52.863 20.6 1982 4292.8 2.0 2.277 14.1 1985 4294.8 4.0 122.778 23.1 1986 4298.8 2.0 0.333 12.5 1987 4300.8 10.0 39.939 21.2 1988 4310.8 4.0 0.748 13.3 1993 4314.8 4.0 0.009 10.9 1995 4318.8 9.5 5.399 16.7 1997 4328.3 2.0 160.618 24.9 2001 4330.3 9.5 0.033 11.5 2002 4339.8 2.0 6.733 16.2 2007 4341.8 2.0 0.001 1.0 2008 4343.8 2.0 29.480 19.6 2009 4345.8 2.0 0.001 1.0 2009 4347.8 4.0 8.473 16.6 2010 4351.8 19.5 0.001 1.0 2012 4371.3 2.0 2.185 16.4 2021 4373.3 2.0 0.001 1.0 2022 4375.3 8.0 2.645 15.9 2023 4383.3 8.0 2.026 14.4 2027 4391.3 20.0 0.001 10.0 2031 Nan DS Shale Nan DS Nan DS Shale Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS 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 Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS # SLB-Private Attachment G Section 2: Propped Fracture Schedule (Stage 1; 12102 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 290.0 22 0 1.0 PPA 40 YF122ST 167.7 22 1 3.0 PPA 40 YF122ST 176.8 22 3 5.0 PPA 40 YF122ST 188.7 22 5 7.0 PPA 40 YF122ST 176.1 22 7 9.0 PPA 40 YF122ST 154.2 22 9 10.0 PPA 40 YF122ST 125.2 22 10 Flush 40 YF122ST 175.9 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1454.6 bbl of YF122ST 0 bbl of WF122 231604 lb of % PAD Clean 22.7 % PAD Dirty 19.1 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 290.0 290 290 290 0 0 3299 7.3 7.3 1.0 PPA 167.7 458 175 465 7042 7042 3270 4.4 11.6 3.0 PPA 176.8 634 200 665 22275 29317 3367 5.0 16.6 5.0 PPA 188.7 823 230 895 39630 68947 3869 5.8 22.4 7.0 PPA 176.1 999 230 1125 51765 120712 4308 5.8 28.1 9.0 PPA 154.2 1153 215 1340 58302 179014 4574 5.4 33.5 10.0 PPA 125.2 1279 180 1520 52590 231604 4699 4.5 38.0 Flush 175.9 1455 176 1696 0 231604 4454 4.4 42.4 Carbolite 16/20-4%SG Proppant Totals Carbolite 16/20-4%SG Pad Percentages Job Execution Step Name Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Fluid Totals The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 323.9 ft with an average conductivity (Kfw) of 16355.5 md.ft. Job Description Fluid Name Prop. Type and Mesh # SLB-Private Attachment G Section 3: Propped Fracture Simulation (Stage 1; 12102 ft MD) Initial Fracture Top TVD 4113.4 ft Initial Fracture Bottom TVD 4347 ft Propped Fracture Half-Length 323.9 ft EOJ Hyd Height at Well 233.7 ft Average Propped Width 0.19 in Net Pressure 262 psi Max Surface Pressure 4726 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 81 10.1 0.214 135.5 1.84 195.5 18963 81 162 9.1 0.209 208.6 1.84 196.7 18205 162 242.9 8.2 0.199 192.7 1.77 195.6 16999 242.9 323.9 4.2 0.147 144.4 1.36 253 12140 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. # SLB-Private Attachment G 4726 psi Section 4: Zone Data (Stage 2; 11613 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4107.7 10.0 0.71 2937 1.46E+06 0.220 1000 Shale 4117.7 15.0 0.70 2867 1.76E+06 0.220 1000 Nanushuk 3 SS 4132.7 15.3 0.68 2807 1.90E+06 0.220 1000 Top Nan CS 4148.0 19.5 0.62 2595 9.00E+05 0.270 1000 Nan SS 4167.5 2.0 0.69 2880 2.67E+06 0.230 2500 Nan CS 4169.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4171.0 4.5 0.62 2571 6.44E+05 0.280 1000 Nan DS 4175.5 3.5 0.69 2886 1.77E+06 0.260 1500 Nan DS 4179.0 14.5 0.65 2726 1.39E+06 0.260 1500 Nan CS 4193.5 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4195.0 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4207.5 2.0 0.65 2731 1.40E+06 0.260 1500 Nan CS 4209.5 9.0 0.61 2558 8.54E+05 0.270 1000 Nan DS 4218.5 7.0 0.65 2755 1.40E+06 0.260 1500 Nan DS 4225.5 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4234.5 3.5 0.64 2720 1.69E+06 0.260 1500 Nan DS 4238.0 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4243.0 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4245.0 10.5 0.61 2607 7.36E+05 0.270 1000 Nan CS 4255.5 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4259.0 2.0 0.61 2614 6.70E+05 0.280 1000 Nan CS 4261.0 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4266.5 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4270.0 3.5 0.63 2701 1.19E+06 0.270 1500 Nan DS 4273.5 5.5 0.68 2928 1.42E+06 0.260 1500 Nan CS 4279.0 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4289.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4291.0 5.0 0.62 2671 1.14E+06 0.270 1500 Nan DS 4296.0 2.0 0.65 2809 1.56E+06 0.260 1500 Nan DS 4298.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4302.0 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4304.0 10.0 0.63 2702 9.81E+05 0.270 1500 Nan DS 4314.0 4.0 0.65 2823 1.63E+06 0.260 1500 Nan DS 4318.0 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4322.0 9.5 0.64 2784 1.33E+06 0.260 1500 Nan DS 4331.5 2.0 0.61 2649 7.82E+05 0.270 1000 Nan DS 4333.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4343.0 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4345.0 2.0 0.69 3002 2.67E+06 0.230 2500 Nan DS 4347.0 2.0 0.64 2765 1.09E+06 0.270 1500 Shale 4349.0 2.0 0.69 3005 2.67E+06 0.230 2500 Nan DS 4351.0 4.0 0.65 2844 1.29E+06 0.260 1500 Shale 4355.0 19.5 0.69 3015 2.67E+06 0.230 2500 Nan DS 4374.5 2.0 0.64 2820 1.36E+06 0.260 1500 Shale 4376.5 2.0 0.69 3024 2.67E+06 0.230 2500 Nan DS 4378.5 8.0 0.65 2855 1.37E+06 0.260 1500 Nan DS 4386.5 8.0 0.65 2841 1.56E+06 0.260 1500 Shale 4394.5 20.0 0.69 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4107.7 10.0 0.001 1.0 1890 4117.7 15.0 0.001 1.0 1898 4132.7 15.3 0.005 10.0 1905 4148.0 19.5 30.655 23.7 1915 4167.5 2.0 5.000 10.0 1924 4169.5 1.5 2.095 16.9 1925 4171.0 4.5 48.388 26.6 1926 4175.5 3.5 0.478 12.4 1928 4179.0 14.5 15.008 17.7 1930 4193.5 1.5 3.661 17.6 1937 4195.0 12.5 34.723 23.9 1937 4207.5 2.0 1.697 15.6 1943 4209.5 9.0 54.319 24.4 1944 4218.5 7.0 3.610 14.8 1948 4225.5 9.0 22.986 20.4 1952 4234.5 3.5 0.835 14.0 1956 4238.0 5.0 65.392 23.4 1957 4243.0 2.0 0.006 10.5 1960 4245.0 10.5 100.832 25.6 1961 4255.5 3.5 17.434 20.5 1966 4259.0 2.0 161.343 26.3 1967 4261.0 5.5 4.627 18.4 1968 4266.5 3.5 5.075 14.8 1971 4270.0 3.5 8.651 19.4 1972 4273.5 5.5 10.205 16.0 1974 4279.0 10.5 17.356 20.1 1977 4289.5 1.5 3.106 14.8 1982 4291.0 5.0 52.863 20.6 1982 4296.0 2.0 2.277 14.1 1985 4298.0 4.0 122.778 23.1 1986 4302.0 2.0 0.333 12.5 1987 4304.0 10.0 39.939 21.2 1988 4314.0 4.0 0.748 13.3 1993 4318.0 4.0 0.009 10.9 1995 4322.0 9.5 5.399 16.7 1997 4331.5 2.0 160.618 24.9 2001 4333.5 9.5 0.033 11.5 2002 4343.0 2.0 6.733 16.2 2007 4345.0 2.0 0.001 1.0 2008 4347.0 2.0 29.480 19.6 2009 4349.0 2.0 0.001 1.0 2009 4351.0 4.0 8.473 16.6 2010 4355.0 19.5 0.001 1.0 2012 4374.5 2.0 2.185 16.4 2021 4376.5 2.0 0.001 1.0 2022 4378.5 8.0 2.645 15.9 2023 4386.5 8.0 2.026 14.4 2027 4394.5 20.0 0.001 10.0 2031 Nan DS Nan DS Shale Shale Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS # SLB-Private Attachment G Section 5: Propped Fracture Schedule (Stage 2; 11613 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 325.0 22 0 1.0 PPA 40 YF122ST 182.0 22 1 3.0 PPA 40 YF122ST 198.9 22 3 5.0 PPA 40 YF122ST 213.3 22 5 7.0 PPA 40 YF122ST 199.0 22 7 9.0 PPA 40 YF122ST 165.0 22 9 10.0 PPA 40 YF122ST 139.1 22 10 Flush 40 YF122ST 175.9 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1598.3 bbl of YF122ST 0 bbl of WF122 256818 lb of % PAD Clean 22.8 % PAD Dirty 19.2 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 325.0 325 325 325 0 0 3223 8.1 8.1 1.0 PPA 182.0 507 190 515 7645 7645 3186 4.8 12.9 3.0 PPA 198.9 706 225 740 25060 32705 3328 5.6 18.5 5.0 PPA 213.3 919 260 1000 44797 77503 3796 6.5 25.0 7.0 PPA 199.0 1118 260 1260 58514 136017 4184 6.5 31.5 9.0 PPA 165.0 1283 230 1490 62373 198389 4420 5.8 37.3 10.0 PPA 139.1 1422 200 1690 58429 256818 4533 5.0 42.3 Flush 175.9 1598 176 1866 0 256818 4338 4.4 46.6 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 354.6 ft with an average conductivity (Kfw) of 18263.3 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 6: Propped Fracture Simulation (Stage 2; 11613 ft MD) Initial Fracture Top TVD 4117.3 ft Initial Fracture Bottom TVD 4350.4 ft Propped Fracture Half-Length 354.6 ft EOJ Hyd Height at Well 233 ft Average Propped Width 0.208 in Net Pressure 356 psi Max Surface Pressure 4567 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 88.7 9.8 0.23 134.3 1.99 195.9 20768 88.7 177.3 8.8 0.228 201.1 2.02 196.1 20303 177.3 266 7.8 0.22 186 2 195.2 19511 266 354.6 3.6 0.162 123.1 1.58 231.9 13836 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 7: Zone Data (Stage 3; 11126 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4098.4 21.7 0.72 2965 1.46E+06 0.220 1000 SHALE 4120.1 15.0 0.70 2869 1.76E+06 0.220 1000 SILTSTONE 4135.1 24.1 0.68 2812 1.90E+06 0.220 1000 Top Nan CS 4159.2 7.0 0.64 2654 2.37E+06 0.240 1000 DIRTY-SANDSTONE 4166.2 1.5 0.69 2880 1.50E+06 0.240 1000 SHALE 4167.7 2.0 0.70 2917 2.67E+06 0.230 2500 CLEAN-SANDSTONE 4169.7 10.5 0.63 2622 6.84E+05 0.280 1000 DIRTY-SANDSTONE 4180.2 6.5 0.65 2711 1.02E+06 0.270 1500 DIRTY-SANDSTONE 4186.7 5.5 0.65 2739 1.54E+06 0.260 1500 DIRTY-SANDSTONE 4192.2 5.0 0.63 2662 1.23E+06 0.260 1000 DIRTY-SANDSTONE 4197.2 1.5 0.66 2777 1.41E+06 0.260 1500 DIRTY-SANDSTONE 4198.7 2.0 0.66 2767 1.70E+06 0.260 1500 DIRTY-SANDSTONE 4200.7 1.5 0.61 2576 5.77E+05 0.280 1500 DIRTY-SANDSTONE 4202.2 11.5 0.66 2767 1.31E+06 0.260 1500 DIRTY-SANDSTONE 4213.7 1.8 0.68 2878 1.24E+06 0.270 1500 DIRTY-SANDSTONE 4215.5 2.1 0.69 2929 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4217.6 8.2 0.64 2688 9.65E+05 0.270 1000 DIRTY-SANDSTONE 4225.8 4.9 0.66 2775 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4230.7 1.5 0.68 2890 1.68E+06 0.260 1500 DIRTY-SANDSTONE 4232.2 2.0 0.65 2732 1.51E+06 0.260 1500 SHALE 4234.2 3.5 0.69 2919 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4237.7 1.5 0.66 2814 1.65E+06 0.260 1500 SHALE 4239.2 1.5 0.70 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4240.7 3.5 0.64 2717 1.48E+06 0.260 1500 SHALE 4244.2 5.0 0.70 2971 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4249.2 2.0 0.63 2696 1.12E+06 0.270 1500 SHALE 4251.2 5.0 0.70 2976 2.67E+06 0.230 2500 SHALE 4256.2 3.5 0.70 2979 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4259.7 1.5 0.66 2819 1.31E+06 0.260 1500 SHALE 4261.2 11.0 0.70 2985 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4272.2 2.0 0.62 2654 8.37E+05 0.270 1000 SHALE 4274.2 1.5 0.70 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4275.7 2.0 0.63 2677 9.57E+05 0.270 1000 DIRTY-SANDSTONE 4277.7 4.0 0.70 2984 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4281.7 5.5 0.65 2769 1.20E+06 0.270 1500 DIRTY-SANDSTONE 4287.2 2.0 0.64 2728 9.33E+05 0.270 1000 DIRTY-SANDSTONE 4289.2 6.0 0.70 2992 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4295.2 21.5 0.65 2787 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4316.7 2.0 0.69 2966 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4318.7 4.0 0.66 2842 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4322.7 2.0 0.62 2660 8.76E+05 0.270 1500 SHALE 4324.7 2.0 0.70 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4326.7 4.0 0.65 2828 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4330.7 4.0 0.64 2768 1.12E+06 0.270 1500 DIRTY-SANDSTONE 4334.7 2.0 0.70 3021 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4336.7 7.5 0.65 2824 1.18E+06 0.270 1500 SHALE 4344.2 9.5 0.70 3041 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4353.7 2.0 0.68 2974 1.69E+06 0.260 1500 SHALE 4355.7 50.0 0.70 3085 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4098.4 21.7 0.010 1.0 1918 4120.1 15.0 0.010 1.0 1923 4135.1 24.1 0.050 10.0 1929 4159.2 7.0 6.009 4.1 1940 4166.2 1.5 0.192 12.0 1944 4167.7 2.0 0.010 1.0 1944 4169.7 10.5 100.314 26.7 1945 4180.2 6.5 21.598 22.3 1950 4186.7 5.5 1.009 16.6 1953 4192.2 5.0 3.544 19.9 1956 4197.2 1.5 5.023 17.9 1958 4198.7 2.0 0.319 14.9 1959 4200.7 1.5 236.504 28.4 1960 4202.2 11.5 21.887 19.1 1960 4213.7 1.8 50.818 20.1 1966 4215.5 2.1 0.026 15.0 1968 4217.6 8.2 62.684 23.0 1970 4225.8 4.9 4.489 17.4 1970 4230.7 1.5 0.488 15.1 1974 4232.2 2.0 1.982 16.9 1974 4234.2 3.5 0.010 1.0 1975 4237.7 1.5 0.552 15.4 1977 4239.2 1.5 0.010 1.0 1978 4240.7 3.5 3.859 17.2 1978 4244.2 5.0 0.010 1.0 1980 4249.2 2.0 41.288 21.2 1982 4251.2 5.0 0.010 1.0 1983 4256.2 3.5 0.010 1.0 1986 4259.7 1.5 5.111 19.0 1987 4261.2 11.0 0.010 1.0 1988 4272.2 2.0 111.829 24.6 1993 4274.2 1.5 0.010 1.0 1994 4275.7 2.0 102.765 23.1 1995 4277.7 4.0 0.016 15.0 1996 4281.7 5.5 24.191 20.3 1997 4287.2 2.0 33.759 23.4 2000 4289.2 6.0 0.015 14.5 2001 4295.2 21.5 82.778 21.8 2004 4316.7 2.0 0.014 15.0 2014 4318.7 4.0 26.711 20.7 2015 4322.7 2.0 162.436 24.1 2017 4324.7 2.0 0.010 1.0 2018 4326.7 4.0 1.983 16.8 2019 4330.7 4.0 30.725 21.1 2020 4334.7 2.0 0.009 15.0 2022 4336.7 7.5 8.533 20.5 2023 4344.2 9.5 0.010 1.0 2027 4353.7 2.0 15.000 10.0 2096 4355.7 50.0 0.010 1.0 2050SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 8: Propped Fracture Schedule (Stage 3; 11126 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 300.0 22 0 1.0 PPA 40 YF122ST 95.8 22 1 2.0 PPA 40 YF122ST 160.9 22 2 3.0 PPA 40 YF122ST 176.8 22 3 4.0 PPA 40 YF122ST 170.2 22 4 5.0 PPA 40 YF122ST 164.1 22 5 6.0 PPA 40 YF122ST 158.4 22 6 7.0 PPA 40 YF122ST 114.8 22 7 8.0 PPA 40 YF122ST 103.7 22 8 Flush 40 YF122ST 168.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1613.2 bbl of YF122ST 0 bbl of WF122 211388 lb of % PAD Clean 20.8 % PAD Dirty 18.0 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 3236 7.5 7.5 1.0 PPA 95.8 396 100 400 4024 4024 3232 2.5 10.0 2.0 PPA 160.9 557 175 575 13517 17541 3243 4.4 14.4 3.0 PPA 176.8 734 200 775 22275 39816 3438 5.0 19.4 4.0 PPA 170.2 904 200 975 28594 68411 3622 5.0 24.4 5.0 PPA 164.1 1068 200 1175 34460 102870 3816 5.0 29.4 6.0 PPA 158.4 1226 200 1375 39918 142788 4015 5.0 34.4 7.0 PPA 114.8 1341 150 1525 33758 176546 4180 3.8 38.1 8.0 PPA 103.7 1445 140 1665 34841 211388 4279 3.5 41.6 Flush 168.5 1613 168 1833 0 211388 4139 4.2 45.8 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 407.9 ft with an average conductivity (Kfw) of 10151.3 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 9: Propped Fracture Simulation (Stage 3; 11126 ft MD) Initial Fracture Top TVD 4097.3 ft Initial Fracture Bottom TVD 4365 ft Propped Fracture Half-Length 407.9 ft EOJ Hyd Height at Well 267.7 ft Average Propped Width 0.122 in Net Pressure 299 psi Max Surface Pressure 4366 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 102 7.5 0.159 252.1 1.37 204.3 14067 102 203.9 5.8 0.146 237.4 1.32 228.5 12372 203.9 305.9 4.4 0.115 218.3 1.09 279.3 9519 305.9 407.9 1.6 0.076 180.5 0.72 376.9 5774 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 10: Zone Data (Stage 4; 10644 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4110.2 21.7 0.72 2965 1.46E+06 0.220 1000 SHALE 4131.9 15.0 0.70 2877 1.76E+06 0.220 1000 SILTSTONE 4146.9 24.1 0.68 2820 1.90E+06 0.220 1000 Top Nan CS 4171.0 7.0 0.64 2654 2.37E+06 0.240 1000 DIRTY-SANDSTONE 4178.0 1.5 0.69 2880 1.50E+06 0.240 1000 SHALE 4179.5 2.0 0.70 2917 2.67E+06 0.230 2500 CLEAN-SANDSTONE 4181.5 10.5 0.63 2622 6.84E+05 0.280 1000 DIRTY-SANDSTONE 4192.0 6.5 0.65 2711 1.02E+06 0.270 1500 DIRTY-SANDSTONE 4198.5 5.5 0.65 2739 1.54E+06 0.260 1500 DIRTY-SANDSTONE 4204.0 5.0 0.63 2662 1.23E+06 0.260 1000 DIRTY-SANDSTONE 4209.0 1.5 0.66 2777 1.41E+06 0.260 1500 DIRTY-SANDSTONE 4210.5 2.0 0.66 2767 1.70E+06 0.260 1500 DIRTY-SANDSTONE 4212.5 1.5 0.61 2576 5.77E+05 0.280 1500 DIRTY-SANDSTONE 4214.0 11.5 0.66 2767 1.31E+06 0.260 1500 DIRTY-SANDSTONE 4225.5 1.8 0.68 2878 1.24E+06 0.270 1500 DIRTY-SANDSTONE 4227.3 2.1 0.69 2929 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4229.4 8.2 0.63 2688 9.65E+05 0.270 1000 DIRTY-SANDSTONE 4237.6 4.9 0.65 2775 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4242.5 1.5 0.68 2890 1.68E+06 0.260 1500 DIRTY-SANDSTONE 4244.0 2.0 0.64 2732 1.51E+06 0.260 1500 SHALE 4246.0 3.5 0.69 2927 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4249.5 1.5 0.66 2814 1.65E+06 0.260 1500 SHALE 4251.0 1.5 0.70 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4252.5 3.5 0.64 2717 1.48E+06 0.260 1500 SHALE 4256.0 5.0 0.70 2971 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4261.0 2.0 0.63 2696 1.12E+06 0.270 1500 SHALE 4263.0 5.0 0.70 2976 2.67E+06 0.230 2500 SHALE 4268.0 3.5 0.70 2979 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4271.5 1.5 0.66 2819 1.31E+06 0.260 1500 SHALE 4273.0 11.0 0.70 2985 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4284.0 2.0 0.62 2661 8.37E+05 0.270 1000 SHALE 4286.0 1.5 0.70 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4287.5 2.0 0.63 2685 9.57E+05 0.270 1000 DIRTY-SANDSTONE 4289.5 4.0 0.70 2984 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4293.5 5.5 0.64 2769 1.20E+06 0.270 1500 DIRTY-SANDSTONE 4299.0 2.0 0.63 2728 9.33E+05 0.270 1000 DIRTY-SANDSTONE 4301.0 6.0 0.70 2992 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4307.0 21.5 0.65 2787 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4328.5 2.0 0.69 2974 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4330.5 4.0 0.66 2842 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4334.5 2.0 0.61 2660 8.76E+05 0.270 1500 SHALE 4336.5 2.0 0.70 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4338.5 4.0 0.65 2828 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4342.5 4.0 0.64 2768 1.12E+06 0.270 1500 DIRTY-SANDSTONE 4346.5 2.0 0.69 3021 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4348.5 7.5 0.65 2824 1.18E+06 0.270 1500 SHALE 4356.0 9.5 0.70 3041 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4365.5 2.0 0.68 2982 1.69E+06 0.260 1500 SHALE 4367.5 50.0 0.70 3085 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4110.2 21.7 0.010 1.0 1918 4131.9 15.0 0.010 1.0 1923 4146.9 24.1 0.050 10.0 1929 4171.0 7.0 6.009 4.1 1940 4178.0 1.5 0.192 12.0 1944 4179.5 2.0 0.010 1.0 1944 4181.5 10.5 100.314 26.7 1945 4192.0 6.5 21.598 22.3 1950 4198.5 5.5 1.009 16.6 1953 4204.0 5.0 3.544 19.9 1956 4209.0 1.5 5.023 17.9 1958 4210.5 2.0 0.319 14.9 1959 4212.5 1.5 236.504 28.4 1960 4214.0 11.5 21.887 19.1 1960 4225.5 1.8 50.818 20.1 1966 4227.3 2.1 0.026 15.0 1968 4229.4 8.2 62.684 23.0 1970 4237.6 4.9 4.489 17.4 1970 4242.5 1.5 0.488 15.1 1974 4244.0 2.0 1.982 16.9 1974 4246.0 3.5 0.010 1.0 1975 4249.5 1.5 0.552 15.4 1977 4251.0 1.5 0.010 1.0 1978 4252.5 3.5 3.859 17.2 1978 4256.0 5.0 0.010 1.0 1980 4261.0 2.0 41.288 21.2 1982 4263.0 5.0 0.010 1.0 1983 4268.0 3.5 0.010 1.0 1986 4271.5 1.5 5.111 19.0 1987 4273.0 11.0 0.010 1.0 1988 4284.0 2.0 111.829 24.6 1993 4286.0 1.5 0.010 1.0 1994 4287.5 2.0 102.765 23.1 1995 4289.5 4.0 0.016 15.0 1996 4293.5 5.5 24.191 20.3 1997 4299.0 2.0 33.759 23.4 2000 4301.0 6.0 0.015 14.5 2001 4307.0 21.5 82.778 21.8 2004 4328.5 2.0 0.014 15.0 2014 4330.5 4.0 26.711 20.7 2015 4334.5 2.0 162.436 24.1 2017 4336.5 2.0 0.010 1.0 2018 4338.5 4.0 1.983 16.8 2019 4342.5 4.0 30.725 21.1 2020 4346.5 2.0 0.009 15.0 2022 4348.5 7.5 8.533 20.5 2023 4356.0 9.5 0.010 1.0 2027 4365.5 2.0 15.000 10.0 2096 4367.5 50.0 0.010 1.0 2056SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 11: Propped Fracture Schedule (Stage 4; 10644 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 182.0 22 1 3.0 PPA 40 YF122ST 185.6 22 3 5.0 PPA 40 YF122ST 192.8 22 5 7.0 PPA 40 YF122ST 179.9 22 7 9.0 PPA 40 YF122ST 129.1 22 9 10.0 PPA 40 YF122ST 111.3 22 10 Flush 40 YF122ST 161.1 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1416.9 bbl of YF122ST 0 bbl of WF122 219969 lb of % PAD Clean 21.9 % PAD Dirty 18.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 275.0 275 275 275 0 0 3152 6.9 6.9 1.0 PPA 182.0 457 210 485 7645 7645 3128 4.8 11.6 3.0 PPA 185.6 643 235 720 23389 31035 3238 5.3 16.9 5.0 PPA 192.8 835 235 955 40490 71524 3639 5.9 22.8 7.0 PPA 179.9 1015 180 1135 52888 124412 3984 5.9 28.6 9.0 PPA 129.1 1144 160 1295 48813 173226 4168 4.5 33.1 10.0 PPA 111.3 1256 161 1456 46743 219969 4263 4.0 37.1 Flush 161.1 1417 0 1456 0 219969 4089 4.0 41.2 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 391.8 ft with an average conductivity (Kfw) of 11438.3 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 12: Propped Fracture Simulation (Stage 4; 10644 ft MD) Initial Fracture Top TVD 4111.4 ft Initial Fracture Bottom TVD 4375.1 ft Propped Fracture Half-Length 391.8 ft EOJ Hyd Height at Well 263.7 ft Average Propped Width 0.136 in Net Pressure 306 psi Max Surface Pressure 4292 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 97.9 9.2 0.177 212.4 1.52 173.9 15574 97.9 195.9 7.3 0.166 230 1.46 186.6 14236 195.9 293.8 4.8 0.121 186.1 1.09 240.7 10138 293.8 391.8 1.4 0.087 146.5 0.79 333 6922 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 13: Zone Data (Stage 5; 10160 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4137.8 10.0 0.70 2919 1.46E+06 0.220 1000 Shale 4147.8 15.0 0.70 2888 1.76E+06 0.220 1000 Siltstone 4162.8 15.3 0.68 2828 1.90E+06 0.220 1000 Top Nan CS 4178.1 17.5 0.62 2616 8.18E+05 0.270 1000 Nan DS 4195.6 2.0 0.60 2518 7.85E+05 0.270 1000 Nan DS 4197.6 5.5 0.63 2645 1.25E+06 0.260 1500 SHALE 4203.1 3.5 0.68 2874 2.67E+06 0.230 2500 Nan DS 4206.6 1.5 0.63 2644 1.10E+06 0.270 1500 Nan DS 4208.1 2.0 0.64 2673 9.14E+05 0.270 1500 Nan CS 4210.1 1.5 0.61 2573 6.70E+05 0.280 1000 Nan CS 4211.6 2.0 0.64 2700 1.25E+06 0.260 1000 Nan CS 4213.6 1.5 0.60 2529 7.72E+05 0.270 1000 SHALE 4215.1 2.0 0.68 2882 2.67E+06 0.230 2500 Nan CS 4217.1 4.5 0.61 2573 8.74E+05 0.270 1000 Nan DS 4221.6 7.0 0.65 2735 1.42E+06 0.260 1500 Nan DS 4228.6 2.5 0.61 2580 7.58E+05 0.270 1000 Nan DS 4231.1 2.0 0.68 2882 1.69E+06 0.260 1500 Nan DS 4233.1 5.0 0.61 2595 9.98E+05 0.270 1500 Nan CS 4238.1 4.5 0.64 2698 1.12E+06 0.270 1000 Nan CS 4242.6 9.5 0.60 2562 7.78E+05 0.270 1000 Nan DS 4252.1 2.5 0.64 2734 1.69E+06 0.260 1500 Nan DS 4254.6 12.0 0.62 2653 9.65E+05 0.270 1500 Nan DS 4266.6 2.5 0.65 2767 1.47E+06 0.260 1500 Nan DS 4269.1 9.5 0.63 2678 1.30E+06 0.260 1500 Nan DS 4278.6 2.0 0.64 2732 1.44E+06 0.260 1500 Nan DS 4280.6 41.0 0.63 2697 1.02E+06 0.270 1500 Nan DS 4321.6 1.5 0.62 2700 8.62E+05 0.270 1000 Nan CS 4323.1 6.0 0.62 2663 7.65E+05 0.280 1000 Nan DS 4329.1 6.0 0.66 2865 1.24E+06 0.260 1500 Nan DS 4335.1 4.0 0.68 2956 1.69E+06 0.260 1500 Nan DS 4339.1 2.0 0.64 2758 1.01E+06 0.270 1500 Nan DS 4341.1 2.0 0.69 2983 1.69E+06 0.260 1500 Nan DS 4343.1 2.0 0.63 2753 1.13E+06 0.270 1500 Nan DS 4345.1 5.5 0.68 2959 1.69E+06 0.260 1500 Nan DS 4350.6 4.0 0.62 2688 9.50E+05 0.270 1000 Nan DS 4354.6 2.0 0.68 2965 1.69E+06 0.260 1500 Nan DS 4356.6 12.0 0.63 2744 9.20E+05 0.270 1000 Nan DS 4368.6 4.0 0.69 2994 1.43E+06 0.260 1500 Nan DS 4372.6 4.0 0.64 2778 1.47E+06 0.260 1500 SHALE 4376.6 2.0 0.68 2993 2.67E+06 0.230 2500 Nan DS 4378.6 1.5 0.64 2815 1.37E+06 0.260 1500 SHALE 4380.1 8.0 0.69 3021 2.67E+06 0.230 2500 Nan DS 4388.1 8.0 0.62 2739 1.13E+06 0.270 1500 Nan DS 4396.1 1.5 0.63 2759 1.42E+06 0.260 1500 SHALE 4397.6 2.0 0.69 3031 2.67E+06 0.230 2500 Nan DS 4399.6 4.0 0.64 2804 1.28E+06 0.260 1500 SHALE 4403.6 2.0 0.68 3012 2.67E+06 0.230 2500 Nan DS 4405.6 6.0 0.63 2769 1.07E+06 0.270 1500 SHALE 4411.6 20.0 0.68 3023 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4137.8 10.0 0.001 1.0 1913 4147.8 15.0 0.001 1.0 1918 4162.8 15.3 0.005 10.0 1925 4178.1 17.5 39.470 24.9 1932 4195.6 2.0 113.240 25.3 1940 4197.6 5.5 22.020 19.7 1941 4203.1 3.5 0.001 1.0 1944 4206.6 1.5 21.670 21.3 1945 4208.1 2.0 159.890 23.6 1946 4210.1 1.5 110.140 27.0 1947 4211.6 2.0 2.870 19.7 1948 4213.6 1.5 94.750 25.5 1949 4215.1 2.0 0.001 1.0 1949 4217.1 4.5 44.130 24.1 1950 4221.6 7.0 4.280 17.9 1952 4228.6 2.5 91.630 25.7 1956 4231.1 2.0 0.020 15.0 1957 4233.1 5.0 31.600 22.6 1958 4238.1 4.5 3.110 21.1 1960 4242.6 9.5 131.710 25.4 1962 4252.1 2.5 1.000 15.1 1967 4254.6 12.0 104.140 23.0 1968 4266.6 2.5 2.350 17.3 1974 4269.1 9.5 31.760 19.2 1975 4278.6 2.0 3.790 17.6 1979 4280.6 41.0 72.280 22.4 1980 4321.6 1.5 68.110 24.3 1999 4323.1 6.0 156.150 26.2 2000 4329.1 6.0 40.960 19.9 2003 4335.1 4.0 0.020 15.0 2006 4339.1 2.0 17.850 22.4 2008 4341.1 2.0 0.010 15.0 2009 4343.1 2.0 22.090 21.0 2010 4345.1 5.5 0.020 15.0 2011 4350.6 4.0 63.420 23.1 2013 4354.6 2.0 0.020 15.0 2015 4356.6 12.0 74.620 23.5 2016 4368.6 4.0 11.770 17.8 2022 4372.6 4.0 2.490 17.3 2023 4376.6 2.0 0.001 1.0 2025 4378.6 1.5 3.220 18.4 2026 4380.1 8.0 0.001 1.0 2027 4388.1 8.0 65.690 21.2 2031 4396.1 1.5 4.800 17.8 2035 4397.6 2.0 0.001 1.0 2035 4399.6 4.0 11.980 19.3 2036 4403.6 2.0 0.001 1.0 2038 4405.6 6.0 60.610 22.1 2039 4411.6 20.0 0.001 1.0 2042SHALE Nan DS Nan DS Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS SHALE Nan CS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Shale Shale Siltstone Top Nan CS Nan DS Nan DS SHALE Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 14: Propped Fracture Schedule (Stage 5; 10160 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 300.0 22 0 1.0 PPA 40 YF122ST 172.5 22 1 3.0 PPA 40 YF122ST 185.6 22 3 5.0 PPA 40 YF122ST 188.7 22 5 7.0 PPA 40 YF122ST 176.1 22 7 9.0 PPA 40 YF122ST 154.2 22 9 10.0 PPA 40 YF122ST 132.2 22 10 Flush 40 YF122ST 153.8 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1463 bbl of YF122ST 0 bbl of WF122 235836 lb of % PAD Clean 22.9 % PAD Dirty 19.3 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 2947 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 2912 4.5 12.0 3.0 PPA 185.6 658 210 690 23389 30632 3013 5.3 17.3 5.0 PPA 188.7 847 230 920 39628 70261 3401 5.8 23.0 7.0 PPA 176.1 1023 230 1150 51763 122023 3720 5.8 28.8 9.0 PPA 154.2 1177 215 1365 58305 180328 3907 5.4 34.1 10.0 PPA 132.2 1309 190 1555 55508 235836 3997 4.8 38.9 Flush 153.8 1463 154 1709 0 235836 3820 3.8 42.7 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 336.9 ft with an average conductivity (Kfw) of 17696.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 15: Propped Fracture Simulation (Stage 5; 10160 ft MD) Initial Fracture Top TVD 4153.5 ft Initial Fracture Bottom TVD 4380.4 ft Propped Fracture Half-Length 336.9 ft EOJ Hyd Height at Well 226.9 ft Average Propped Width 0.203 in Net Pressure 339 psi Max Surface Pressure 4018 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 84.2 9.8 0.234 130.6 2.02 187.8 20999 84.2 168.4 8.6 0.24 197.8 2.14 185.2 21250 168.4 252.7 7.4 0.22 164.6 1.96 198.3 19304 252.7 336.9 3.1 0.127 130.2 1.19 321.5 10316 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 16: Zone Data (Stage 6; 9676 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4142.4 10.0 0.70 2919 1.46E+06 0.220 1000 Shale 4152.4 15.0 0.70 2891 1.76E+06 0.220 1000 Siltstone 4167.4 15.3 0.68 2831 1.90E+06 0.220 1000 Top Nan CS 4182.7 17.5 0.62 2616 8.18E+05 0.270 1000 Nan DS 4200.2 2.0 0.60 2518 7.85E+05 0.270 1000 Nan DS 4202.2 5.5 0.63 2645 1.25E+06 0.260 1500 SHALE 4207.7 3.5 0.68 2874 2.67E+06 0.230 2500 Nan DS 4211.2 1.5 0.63 2644 1.10E+06 0.270 1500 Nan DS 4212.7 2.0 0.64 2676 9.14E+05 0.270 1500 Nan CS 4214.7 1.5 0.61 2573 6.70E+05 0.280 1000 Nan CS 4216.2 2.0 0.64 2703 1.25E+06 0.260 1000 Nan CS 4218.2 1.5 0.60 2529 7.72E+05 0.270 1000 SHALE 4219.7 2.0 0.68 2882 2.67E+06 0.230 2500 Nan CS 4221.7 4.5 0.61 2573 8.74E+05 0.270 1000 Nan DS 4226.2 7.0 0.65 2735 1.42E+06 0.260 1500 Nan DS 4233.2 2.5 0.61 2580 7.58E+05 0.270 1000 Nan DS 4235.7 2.0 0.68 2882 1.69E+06 0.260 1500 Nan DS 4237.7 5.0 0.61 2595 9.98E+05 0.270 1500 Nan CS 4242.7 4.5 0.64 2698 1.12E+06 0.270 1000 Nan CS 4247.2 9.5 0.60 2562 7.78E+05 0.270 1000 Nan DS 4256.7 2.5 0.64 2734 1.69E+06 0.260 1500 Nan DS 4259.2 12.0 0.62 2653 9.65E+05 0.270 1500 Nan DS 4271.2 2.5 0.65 2767 1.47E+06 0.260 1500 Nan DS 4273.7 9.5 0.63 2678 1.30E+06 0.260 1500 Nan DS 4283.2 2.0 0.64 2732 1.44E+06 0.260 1500 Nan DS 4285.2 41.0 0.63 2697 1.02E+06 0.270 1500 Nan DS 4326.2 1.5 0.62 2700 8.62E+05 0.270 1000 Nan CS 4327.7 6.0 0.61 2663 7.65E+05 0.280 1000 Nan DS 4333.7 6.0 0.66 2865 1.24E+06 0.260 1500 Nan DS 4339.7 4.0 0.68 2956 1.69E+06 0.260 1500 Nan DS 4343.7 2.0 0.63 2758 1.01E+06 0.270 1500 Nan DS 4345.7 2.0 0.69 2986 1.69E+06 0.260 1500 Nan DS 4347.7 2.0 0.63 2753 1.13E+06 0.270 1500 Nan DS 4349.7 5.5 0.68 2959 1.69E+06 0.260 1500 Nan DS 4355.2 4.0 0.62 2688 9.50E+05 0.270 1000 Nan DS 4359.2 2.0 0.68 2965 1.69E+06 0.260 1500 Nan DS 4361.2 12.0 0.63 2747 9.20E+05 0.270 1000 Nan DS 4373.2 4.0 0.69 2997 1.43E+06 0.260 1500 Nan DS 4377.2 4.0 0.63 2778 1.47E+06 0.260 1500 SHALE 4381.2 2.0 0.68 2993 2.67E+06 0.230 2500 Nan DS 4383.2 1.5 0.64 2815 1.37E+06 0.260 1500 SHALE 4384.7 8.0 0.69 3024 2.67E+06 0.230 2500 Nan DS 4392.7 8.0 0.62 2739 1.13E+06 0.270 1500 Nan DS 4400.7 1.5 0.63 2759 1.42E+06 0.260 1500 SHALE 4402.2 2.0 0.69 3034 2.67E+06 0.230 2500 Nan DS 4404.2 4.0 0.64 2807 1.28E+06 0.260 1500 SHALE 4408.2 2.0 0.68 3012 2.67E+06 0.230 2500 Nan DS 4410.2 6.0 0.63 2769 1.07E+06 0.270 1500 SHALE 4416.2 20.0 0.68 3023 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4142.4 10.0 0.001 1.0 1913 4152.4 15.0 0.001 1.0 1918 4167.4 15.3 0.005 10.0 1925 4182.7 17.5 39.470 24.9 1932 4200.2 2.0 113.240 25.3 1940 4202.2 5.5 22.020 19.7 1941 4207.7 3.5 0.001 1.0 1944 4211.2 1.5 21.670 21.3 1945 4212.7 2.0 159.890 23.6 1946 4214.7 1.5 110.140 27.0 1947 4216.2 2.0 2.870 19.7 1948 4218.2 1.5 94.750 25.5 1949 4219.7 2.0 0.001 1.0 1949 4221.7 4.5 44.130 24.1 1950 4226.2 7.0 4.280 17.9 1952 4233.2 2.5 91.630 25.7 1956 4235.7 2.0 0.020 15.0 1957 4237.7 5.0 31.600 22.6 1958 4242.7 4.5 3.110 21.1 1960 4247.2 9.5 131.710 25.4 1962 4256.7 2.5 1.000 15.1 1967 4259.2 12.0 104.140 23.0 1968 4271.2 2.5 2.350 17.3 1974 4273.7 9.5 31.760 19.2 1975 4283.2 2.0 3.790 17.6 1979 4285.2 41.0 72.280 22.4 1980 4326.2 1.5 68.110 24.3 1999 4327.7 6.0 156.150 26.2 2000 4333.7 6.0 40.960 19.9 2003 4339.7 4.0 0.020 15.0 2006 4343.7 2.0 17.850 22.4 2008 4345.7 2.0 0.010 15.0 2009 4347.7 2.0 22.090 21.0 2010 4349.7 5.5 0.020 15.0 2011 4355.2 4.0 63.420 23.1 2013 4359.2 2.0 0.020 15.0 2015 4361.2 12.0 74.620 23.5 2016 4373.2 4.0 11.770 17.8 2022 4377.2 4.0 2.490 17.3 2023 4381.2 2.0 0.001 1.0 2025 4383.2 1.5 3.220 18.4 2026 4384.7 8.0 0.001 1.0 2027 4392.7 8.0 65.690 21.2 2031 4400.7 1.5 4.800 17.8 2035 4402.2 2.0 0.001 1.0 2035 4404.2 4.0 11.980 19.3 2036 4408.2 2.0 0.001 1.0 2038 4410.2 6.0 60.610 22.1 2039 4416.2 20.0 0.001 1.0 2042SHALE Nan DS Nan DS Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS SHALE Nan CS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Shale Shale Siltstone Top Nan CS Nan DS Nan DS SHALE Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 17: Propped Fracture Schedule (Stage 6; 9676 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 300.0 22 0 1.0 PPA 40 YF122ST 182.0 22 1 3.0 PPA 40 YF122ST 185.6 22 3 5.0 PPA 40 YF122ST 188.7 22 5 7.0 PPA 40 YF122ST 176.1 22 7 9.0 PPA 40 YF122ST 143.5 22 9 10.0 PPA 40 YF122ST 111.3 22 10 Flush 40 YF122ST 146.4 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1433.6 bbl of YF122ST 0 bbl of WF122 223406 lb of % PAD Clean 23.3 % PAD Dirty 19.7 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 2861 7.5 7.5 1.0 PPA 182.0 482 190 490 7645 7645 2827 4.8 12.3 3.0 PPA 185.6 668 210 700 23389 31035 2924 5.3 17.5 5.0 PPA 188.7 856 230 930 39628 70663 3267 5.8 23.3 7.0 PPA 176.1 1032 230 1160 51763 122426 3562 5.8 29.0 9.0 PPA 143.5 1176 200 1360 54237 176663 3735 5.0 34.0 10.0 PPA 111.3 1287 160 1520 46743 223406 3809 4.0 38.0 Flush 146.4 1434 146 1666 0 223406 3655 3.7 41.7 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 346.1 ft with an average conductivity (Kfw) of 15705 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 18: Propped Fracture Simulation (Stage 6; 9676 ft MD) Initial Fracture Top TVD 4157.9 ft Initial Fracture Bottom TVD 4385.8 ft Propped Fracture Half-Length 346.1 ft EOJ Hyd Height at Well 227.9 ft Average Propped Width 0.182 in Net Pressure 332 psi Max Surface Pressure 3827 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 86.5 9.9 0.221 130.4 1.91 187.9 19723 86.5 173.1 8.3 0.219 196.1 1.93 192.1 19098 173.1 259.6 6.8 0.19 167.6 1.67 216.2 16483 259.6 346.1 2.8 0.107 122.6 0.95 339.8 8652 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 19: Zone Data (Stage 7; 9188 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4132.0 21.7 0.72 2965 1.46E+06 0.220 1000 SHALE 4153.7 15.0 0.70 2892 1.76E+06 0.220 1000 SILTSTONE 4168.7 24.1 0.68 2835 1.90E+06 0.220 1000 Top Nan CS 4192.8 7.0 0.63 2654 2.37E+06 0.240 1000 DIRTY-SANDSTONE 4199.8 1.5 0.69 2880 1.50E+06 0.240 1000 SHALE 4201.3 2.0 0.69 2917 2.67E+06 0.230 2500 CLEAN-SANDSTONE 4203.3 10.5 0.62 2622 6.84E+05 0.280 1000 DIRTY-SANDSTONE 4213.8 6.5 0.64 2711 1.02E+06 0.270 1500 DIRTY-SANDSTONE 4220.3 5.5 0.65 2739 1.54E+06 0.260 1500 DIRTY-SANDSTONE 4225.8 5.0 0.63 2662 1.23E+06 0.260 1000 DIRTY-SANDSTONE 4230.8 1.5 0.66 2777 1.41E+06 0.260 1500 DIRTY-SANDSTONE 4232.3 2.0 0.65 2767 1.70E+06 0.260 1500 DIRTY-SANDSTONE 4234.3 1.5 0.61 2576 5.77E+05 0.280 1500 DIRTY-SANDSTONE 4235.8 11.5 0.65 2767 1.31E+06 0.260 1500 DIRTY-SANDSTONE 4247.3 1.8 0.68 2878 1.24E+06 0.270 1500 DIRTY-SANDSTONE 4249.1 2.1 0.69 2929 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4251.2 8.2 0.63 2688 9.65E+05 0.270 1000 DIRTY-SANDSTONE 4259.4 4.9 0.65 2775 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4264.3 1.5 0.68 2890 1.68E+06 0.260 1500 DIRTY-SANDSTONE 4265.8 2.0 0.64 2732 1.51E+06 0.260 1500 SHALE 4267.8 3.5 0.69 2942 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4271.3 1.5 0.66 2814 1.65E+06 0.260 1500 SHALE 4272.8 1.5 0.69 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4274.3 3.5 0.64 2717 1.48E+06 0.260 1500 SHALE 4277.8 5.0 0.69 2971 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4282.8 2.0 0.63 2696 1.12E+06 0.270 1500 SHALE 4284.8 5.0 0.69 2976 2.67E+06 0.230 2500 SHALE 4289.8 3.5 0.69 2979 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4293.3 1.5 0.66 2819 1.31E+06 0.260 1500 SHALE 4294.8 11.0 0.69 2985 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4305.8 2.0 0.62 2675 8.37E+05 0.270 1000 SHALE 4307.8 1.5 0.69 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4309.3 2.0 0.63 2698 9.57E+05 0.270 1000 DIRTY-SANDSTONE 4311.3 4.0 0.69 2984 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4315.3 5.5 0.64 2769 1.20E+06 0.270 1500 DIRTY-SANDSTONE 4320.8 2.0 0.63 2728 9.33E+05 0.270 1000 DIRTY-SANDSTONE 4322.8 6.0 0.69 2992 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4328.8 21.5 0.64 2787 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4350.3 2.0 0.69 2989 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4352.3 4.0 0.65 2842 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4356.3 2.0 0.61 2660 8.76E+05 0.270 1500 SHALE 4358.3 2.0 0.69 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4360.3 4.0 0.65 2828 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4364.3 4.0 0.63 2768 1.12E+06 0.270 1500 DIRTY-SANDSTONE 4368.3 2.0 0.69 3021 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4370.3 7.5 0.65 2824 1.18E+06 0.270 1500 SHALE 4377.8 9.5 0.69 3041 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4387.3 2.0 0.68 2997 1.69E+06 0.260 1500 SHALE 4389.3 50.0 0.70 3085 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4132.0 21.7 0.010 1.0 1918 4153.7 15.0 0.010 1.0 1923 4168.7 24.1 0.050 10.0 1929 4192.8 7.0 6.009 4.1 1940 4199.8 1.5 0.192 12.0 1944 4201.3 2.0 0.010 1.0 1944 4203.3 10.5 100.314 26.7 1945 4213.8 6.5 21.598 22.3 1950 4220.3 5.5 1.009 16.6 1953 4225.8 5.0 3.544 19.9 1956 4230.8 1.5 5.023 17.9 1958 4232.3 2.0 0.319 14.9 1959 4234.3 1.5 236.504 28.4 1960 4235.8 11.5 21.887 19.1 1960 4247.3 1.8 50.818 20.1 1966 4249.1 2.1 0.026 15.0 1968 4251.2 8.2 62.684 23.0 1970 4259.4 4.9 4.489 17.4 1970 4264.3 1.5 0.488 15.1 1974 4265.8 2.0 1.982 16.9 1974 4267.8 3.5 0.010 1.0 1975 4271.3 1.5 0.552 15.4 1977 4272.8 1.5 0.010 1.0 1978 4274.3 3.5 3.859 17.2 1978 4277.8 5.0 0.010 1.0 1980 4282.8 2.0 41.288 21.2 1982 4284.8 5.0 0.010 1.0 1983 4289.8 3.5 0.010 1.0 1986 4293.3 1.5 5.111 19.0 1987 4294.8 11.0 0.010 1.0 1988 4305.8 2.0 111.829 24.6 1993 4307.8 1.5 0.010 1.0 1994 4309.3 2.0 102.765 23.1 1995 4311.3 4.0 0.016 15.0 1996 4315.3 5.5 24.191 20.3 1997 4320.8 2.0 33.759 23.4 2000 4322.8 6.0 0.015 14.5 2001 4328.8 21.5 82.778 21.8 2004 4350.3 2.0 0.014 15.0 2014 4352.3 4.0 26.711 20.7 2015 4356.3 2.0 162.436 24.1 2017 4358.3 2.0 0.010 1.0 2018 4360.3 4.0 1.983 16.8 2019 4364.3 4.0 30.725 21.1 2020 4368.3 2.0 0.009 15.0 2022 4370.3 7.5 8.533 20.5 2023 4377.8 9.5 0.010 1.0 2027 4387.3 2.0 15.000 10.0 2096 4389.3 50.0 0.010 1.0 2066SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 20: Propped Fracture Schedule (Stage 7; 9188 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 143.7 22 1 3.0 PPA 40 YF122ST 154.7 22 3 5.0 PPA 40 YF122ST 164.1 22 5 7.0 PPA 40 YF122ST 153.1 22 7 9.0 PPA 40 YF122ST 125.5 22 9 10.0 PPA 40 YF122ST 104.3 22 10 Flush 40 YF122ST 139.0 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1259.4 bbl of YF122ST 0 bbl of WF122 196276 lb of % PAD Clean 24.5 % PAD Dirty 20.8 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 275.0 275 275 275 0 0 2906 6.9 6.9 1.0 PPA 143.7 419 150 425 6036 6036 2882 3.8 10.6 3.0 PPA 154.7 573 175 600 19491 25527 2956 4.4 15.0 5.0 PPA 164.1 737 200 800 34460 59986 3274 5.0 20.0 7.0 PPA 153.1 891 200 1000 45011 104997 3543 5.0 25.0 9.0 PPA 125.5 1016 175 1175 47458 152455 3694 4.4 29.4 10.0 PPA 104.3 1120 150 1325 43822 196276 3752 3.8 33.1 Flush 139.0 1259 139 1464 0 196276 3596 3.5 36.6 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 380.3 ft with an average conductivity (Kfw) of 9765.5 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 21: Propped Fracture Simulation (Stage 7; 9188 ft MD) Initial Fracture Top TVD 4132.1 ft Initial Fracture Bottom TVD 4400.4 ft Propped Fracture Half-Length 380.3 ft EOJ Hyd Height at Well 268.4 ft Average Propped Width 0.119 in Net Pressure 251 psi Max Surface Pressure 3764 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 95.1 9.4 0.155 160.2 1.32 180.4 13327 95.1 190.2 7.2 0.145 235.3 1.26 195.5 12204 190.2 285.2 4.5 0.111 212.9 0.98 220.7 9073 285.2 380.3 1.5 0.07 140.2 0.62 403.8 4932 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 22: Zone Data (Stage 8; 8698 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4142.0 21.7 0.71 2965 1.46E+06 0.220 1000 SHALE 4163.7 15.0 0.70 2899 1.76E+06 0.220 1000 SILTSTONE 4178.7 24.1 0.68 2841 1.90E+06 0.220 1000 Top Nan CS 4202.8 7.0 0.63 2654 2.37E+06 0.240 1000 DIRTY-SANDSTONE 4209.8 1.5 0.68 2880 1.50E+06 0.240 1000 SHALE 4211.3 2.0 0.69 2917 2.67E+06 0.230 2500 CLEAN-SANDSTONE 4213.3 10.5 0.62 2622 6.84E+05 0.280 1000 DIRTY-SANDSTONE 4223.8 6.5 0.64 2711 1.02E+06 0.270 1500 DIRTY-SANDSTONE 4230.3 5.5 0.65 2739 1.54E+06 0.260 1500 DIRTY-SANDSTONE 4235.8 5.0 0.63 2662 1.23E+06 0.260 1000 DIRTY-SANDSTONE 4240.8 1.5 0.65 2777 1.41E+06 0.260 1500 DIRTY-SANDSTONE 4242.3 2.0 0.65 2767 1.70E+06 0.260 1500 DIRTY-SANDSTONE 4244.3 1.5 0.61 2576 5.77E+05 0.280 1500 DIRTY-SANDSTONE 4245.8 11.5 0.65 2767 1.31E+06 0.260 1500 DIRTY-SANDSTONE 4257.3 1.8 0.68 2878 1.24E+06 0.270 1500 DIRTY-SANDSTONE 4259.1 2.1 0.69 2929 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4261.2 8.2 0.63 2688 9.65E+05 0.270 1000 DIRTY-SANDSTONE 4269.4 4.9 0.65 2775 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4274.3 1.5 0.68 2890 1.68E+06 0.260 1500 DIRTY-SANDSTONE 4275.8 2.0 0.64 2732 1.51E+06 0.260 1500 SHALE 4277.8 3.5 0.69 2949 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4281.3 1.5 0.66 2814 1.65E+06 0.260 1500 SHALE 4282.8 1.5 0.69 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4284.3 3.5 0.63 2717 1.48E+06 0.260 1500 SHALE 4287.8 5.0 0.69 2971 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4292.8 2.0 0.63 2696 1.12E+06 0.270 1500 SHALE 4294.8 5.0 0.69 2976 2.67E+06 0.230 2500 SHALE 4299.8 3.5 0.69 2979 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4303.3 1.5 0.65 2819 1.31E+06 0.260 1500 SHALE 4304.8 11.0 0.69 2985 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4315.8 2.0 0.62 2681 8.37E+05 0.270 1000 SHALE 4317.8 1.5 0.69 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4319.3 2.0 0.63 2705 9.57E+05 0.270 1000 DIRTY-SANDSTONE 4321.3 4.0 0.69 2984 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4325.3 5.5 0.64 2769 1.20E+06 0.270 1500 DIRTY-SANDSTONE 4330.8 2.0 0.63 2728 9.33E+05 0.270 1000 DIRTY-SANDSTONE 4332.8 6.0 0.69 2992 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4338.8 21.5 0.64 2787 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4360.3 2.0 0.69 2996 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4362.3 4.0 0.65 2842 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4366.3 2.0 0.61 2660 8.76E+05 0.270 1500 SHALE 4368.3 2.0 0.69 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4370.3 4.0 0.65 2828 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4374.3 4.0 0.63 2768 1.12E+06 0.270 1500 DIRTY-SANDSTONE 4378.3 2.0 0.69 3021 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4380.3 7.5 0.64 2824 1.18E+06 0.270 1500 SHALE 4387.8 9.5 0.69 3041 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4397.3 2.0 0.68 3004 1.69E+06 0.260 1500 SHALE 4399.3 50.0 0.70 3085 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4142.0 21.7 0.010 1.0 1918 4163.7 15.0 0.010 1.0 1923 4178.7 24.1 0.050 10.0 1929 4202.8 7.0 6.009 4.1 1940 4209.8 1.5 0.192 12.0 1944 4211.3 2.0 0.010 1.0 1944 4213.3 10.5 100.314 26.7 1945 4223.8 6.5 21.598 22.3 1950 4230.3 5.5 1.009 16.6 1953 4235.8 5.0 3.544 19.9 1956 4240.8 1.5 5.023 17.9 1958 4242.3 2.0 0.319 14.9 1959 4244.3 1.5 236.504 28.4 1960 4245.8 11.5 21.887 19.1 1960 4257.3 1.8 50.818 20.1 1966 4259.1 2.1 0.026 15.0 1968 4261.2 8.2 62.684 23.0 1970 4269.4 4.9 4.489 17.4 1970 4274.3 1.5 0.488 15.1 1974 4275.8 2.0 1.982 16.9 1974 4277.8 3.5 0.010 1.0 1975 4281.3 1.5 0.552 15.4 1977 4282.8 1.5 0.010 1.0 1978 4284.3 3.5 3.859 17.2 1978 4287.8 5.0 0.010 1.0 1980 4292.8 2.0 41.288 21.2 1982 4294.8 5.0 0.010 1.0 1983 4299.8 3.5 0.010 1.0 1986 4303.3 1.5 5.111 19.0 1987 4304.8 11.0 0.010 1.0 1988 4315.8 2.0 111.829 24.6 1993 4317.8 1.5 0.010 1.0 1994 4319.3 2.0 102.765 23.1 1995 4321.3 4.0 0.016 15.0 1996 4325.3 5.5 24.191 20.3 1997 4330.8 2.0 33.759 23.4 2000 4332.8 6.0 0.015 14.5 2001 4338.8 21.5 82.778 21.8 2004 4360.3 2.0 0.014 15.0 2014 4362.3 4.0 26.711 20.7 2015 4366.3 2.0 162.436 24.1 2017 4368.3 2.0 0.010 1.0 2018 4370.3 4.0 1.983 16.8 2019 4374.3 4.0 30.725 21.1 2020 4378.3 2.0 0.009 15.0 2022 4380.3 7.5 8.533 20.5 2023 4387.8 9.5 0.010 1.0 2027 4397.3 2.0 15.000 10.0 2096 4399.3 50.0 0.010 1.0 2071SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 23: Propped Fracture Schedule (Stage 8; 8698 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF122ST 275.0 22 0 1.0 PPA 40 YF122ST 134.1 22 1 3.0 PPA 40 YF122ST 141.4 22 3 5.0 PPA 40 YF122ST 155.9 22 5 7.0 PPA 40 YF122ST 145.4 22 7 9.0 PPA 40 YF122ST 122.0 22 9 10.0 PPA 40 YF122ST 104.3 22 10 Flush 40 YF122ST 131.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1209.7 bbl of YF122ST 0 bbl of WF122 188874 lb of % PAD Clean 25.5 % PAD Dirty 21.6 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 275.0 275 275 275 0 0 2819 6.9 6.9 1.0 PPA 134.1 409 140 415 5633 5633 2796 3.5 10.4 3.0 PPA 141.4 551 160 575 17820 23454 2858 4.0 14.4 5.0 PPA 155.9 706 190 765 32737 56190 3152 4.8 19.1 7.0 PPA 145.4 852 190 955 42760 98951 3394 4.8 23.9 9.0 PPA 122.0 974 170 1125 46102 145052 3529 4.3 28.1 10.0 PPA 104.3 1078 150 1275 43822 188874 3577 3.8 31.9 Flush 131.5 1210 132 1407 0 188874 3446 3.3 35.2 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 372.1 ft with an average conductivity (Kfw) of 9679 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 24: Propped Fracture Simulation (Stage 8; 8698 ft MD) Initial Fracture Top TVD 4143.6 ft Initial Fracture Bottom TVD 4410.1 ft Propped Fracture Half-Length 372.1 ft EOJ Hyd Height at Well 266.5 ft Average Propped Width 0.118 in Net Pressure 255 psi Max Surface Pressure 3590 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 93 9.3 0.152 157.2 1.3 183.7 13070 93 186 7.2 0.144 233.7 1.25 187.3 12147 186 279.1 4.4 0.108 211.6 0.95 218.9 8782 279.1 372.1 1.4 0.074 143.4 0.65 304.8 5309 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 25: Zone Data (Stage 9; 8206 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4148.5 31.7 0.72 3001 1.46E+06 0.220 1000 SHALE 4180.2 15.0 0.70 2910 1.76E+06 0.220 1000 SILTSTONE 4195.2 24.1 0.68 2853 1.90E+06 0.220 1000 CLEAN-SANDSTONE 4219.3 3.5 0.62 2607 8.57E+05 0.270 1000 SHALE 4222.8 1.5 0.70 2952 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4224.3 1.5 0.63 2658 9.12E+05 0.270 1000 DIRTY-SANDSTONE 4225.8 3.5 0.66 2799 1.15E+06 0.270 1500 CLEAN-SANDSTONE 4229.3 2.0 0.62 2627 7.24E+05 0.280 1000 SHALE 4231.3 1.5 0.70 2958 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4232.8 14.0 0.64 2705 1.55E+06 0.260 1500 SHALE 4246.8 1.5 0.70 2969 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4248.3 3.5 0.62 2627 1.15E+06 0.270 1500 DIRTY-SANDSTONE 4251.8 1.5 0.70 2959 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4253.3 2.0 0.61 2582 8.10E+05 0.270 1000 DIRTY-SANDSTONE 4255.3 5.0 0.67 2868 1.28E+06 0.260 1500 DIRTY-SANDSTONE 4260.3 10.0 0.64 2717 1.50E+06 0.260 1500 DIRTY-SANDSTONE 4270.3 10.0 0.67 2847 8.70E+05 0.270 1500 DIRTY-SANDSTONE 4280.3 5.0 0.63 2709 1.22E+06 0.270 1500 DIRTY-SANDSTONE 4285.3 8.5 0.70 2987 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4293.8 3.5 0.63 2722 1.47E+06 0.260 1500 SHALE 4297.3 2.5 0.70 3004 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4299.8 1.0 0.66 2830 1.61E+06 0.260 1500 SHALE 4300.8 7.0 0.70 3008 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4307.8 3.5 0.64 2754 9.39E+05 0.270 1000 DIRTY-SANDSTONE 4311.3 4.5 0.70 3014 1.56E+06 0.260 1500 DIRTY-SANDSTONE 4315.8 2.0 0.65 2791 1.35E+06 0.260 1500 DIRTY-SANDSTONE 4317.8 2.0 0.70 3008 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4319.8 5.5 0.63 2730 9.70E+05 0.270 1500 DIRTY-SANDSTONE 4325.3 6.0 0.70 3018 1.65E+06 0.260 1500 DIRTY-SANDSTONE 4331.3 10.0 0.65 2819 1.24E+06 0.260 1500 DIRTY-SANDSTONE 4341.3 2.0 0.66 2869 1.50E+06 0.260 1500 DIRTY-SANDSTONE 4343.3 7.5 0.63 2739 9.80E+05 0.270 1500 DIRTY-SANDSTONE 4350.8 1.5 0.70 3029 1.87E+06 0.250 1500 DIRTY-SANDSTONE 4352.3 3.0 0.62 2706 9.11E+05 0.270 1500 DIRTY-SANDSTONE 4355.3 5.0 0.65 2830 1.76E+06 0.260 1500 SHALE 4360.3 6.0 0.69 3006 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4366.3 2.0 0.66 2903 1.72E+06 0.260 1500 SHALE 4368.3 23.0 0.70 3060 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4391.3 2.0 0.64 2817 1.24E+06 0.260 1500 SHALE 4393.3 2.0 0.70 3070 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4395.3 2.0 0.66 2910 1.68E+06 0.260 1500 SHALE 4397.3 4.5 0.69 3031 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4401.8 10.0 0.63 2794 1.28E+06 0.260 1500 SHALE 4411.8 10.5 0.69 3043 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4422.3 2.0 0.66 2926 1.40E+06 0.260 1500 SHALE 4424.3 19.0 0.70 3097 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4443.3 2.0 0.64 2840 1.44E+06 0.260 1500 SHALE 4445.3 25.0 0.70 3114 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4148.5 31.7 0.010 1.0 1919 4180.2 15.0 0.010 1.0 1929 4195.2 24.1 0.050 10.0 1936 4219.3 3.5 48.343 24.3 1947 4222.8 1.5 0.006 10.0 1949 4224.3 1.5 39.757 23.6 1949 4225.8 3.5 6.288 20.8 1950 4229.3 2.0 71.711 26.2 1952 4231.3 1.5 0.006 10.0 1952 4232.8 14.0 56.440 16.7 1953 4246.8 1.5 0.006 10.0 1960 4248.3 3.5 18.893 20.8 1960 4251.8 1.5 0.023 15.0 1962 4253.3 2.0 115.609 24.9 1963 4255.3 5.0 20.857 19.5 1964 4260.3 10.0 1.968 17.0 1966 4270.3 10.0 74.766 24.2 1971 4280.3 5.0 11.675 20.1 1975 4285.3 8.5 7.321 16.9 1978 4293.8 3.5 3.784 17.3 1982 4297.3 2.5 0.006 10.0 1983 4299.8 1.0 1.340 15.9 1984 4300.8 7.0 0.006 10.0 1985 4307.8 3.5 40.985 23.3 1988 4311.3 4.5 1.316 14.2 1990 4315.8 2.0 4.219 18.6 1992 4317.8 2.0 0.015 14.6 1993 4319.8 5.5 61.197 22.9 1994 4325.3 6.0 0.552 13.9 1996 4331.3 10.0 28.233 19.9 1999 4341.3 2.0 1.534 17.0 2004 4343.3 7.5 79.135 22.8 2005 4350.8 1.5 0.006 10.0 2008 4352.3 3.0 120.250 23.7 2009 4355.3 5.0 0.329 14.3 2010 4360.3 6.0 0.006 10.0 2013 4366.3 2.0 0.136 14.8 2015 4368.3 23.0 0.006 10.0 2016 4391.3 2.0 15.982 19.8 2027 4393.3 2.0 0.006 10.0 2028 4395.3 2.0 0.344 15.1 2029 4397.3 4.5 0.006 10.0 2030 4401.8 10.0 6.547 19.3 2032 4411.8 10.5 0.006 10.0 2036 4422.3 2.0 1.897 18.0 2041 4424.3 19.0 0.006 10.0 2042 4443.3 2.0 4.758 17.7 2051 4445.3 25.0 0.006 10.0 2052SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE Shale SHALE SILTSTONE CLEAN-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE CLEAN-SANDSTONE SHALE DIRTY-SANDSTONE SHALE Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 26: Propped Fracture Schedule (Stage 9; 8206 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 30 YF122ST 300.0 22 0 1.0 PPA 30 YF122ST 115.0 22 1 2.0 PPA 30 YF122ST 124.1 22 2 3.0 PPA 30 YF122ST 132.6 22 3 4.0 PPA 30 YF122ST 127.7 22 4 5.0 PPA 30 YF122ST 123.1 22 5 6.0 PPA 30 YF122ST 118.8 22 6 7.0 PPA 30 YF122ST 107.2 22 7 8.0 PPA 30 YF122ST 88.9 22 8 Flush 30 YF122ST 125.0 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1362.3 bbl of YF122ST 0 bbl of WF122 170563 lb of % PAD Clean 24.2 % PAD Dirty 21.2 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 2217 10.0 10.0 1.0 PPA 115.0 415 120 420 4829 4829 2198 4.0 14.0 2.0 PPA 124.1 539 135 555 10427 15256 2141 4.5 18.5 3.0 PPA 132.6 672 150 705 16707 31963 2170 5.0 23.5 4.0 PPA 127.7 799 150 855 21446 53408 2211 5.0 28.5 5.0 PPA 123.1 922 150 1005 25845 79253 2258 5.0 33.5 6.0 PPA 118.8 1041 150 1155 29939 109191 2310 5.0 38.5 7.0 PPA 107.2 1148 140 1295 31508 140699 2355 4.7 43.2 8.0 PPA 88.9 1237 120 1415 29864 170563 2369 4.0 47.2 Flush 125.0 1362 125 1540 0 170563 2406 4.2 51.3 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 272.2 ft with an average conductivity (Kfw) of 10500.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 27: Propped Fracture Simulation (Stage 9; 8206 ft MD) Initial Fracture Top TVD 4141.8 ft Initial Fracture Bottom TVD 4450.2 ft Propped Fracture Half-Length 272.2 ft EOJ Hyd Height at Well 308.4 ft Average Propped Width 0.122 in Net Pressure 42 psi Max Surface Pressure 2442 psi From To Prop. Conc. Propped Propped Frac.Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 68 8.2 0.14 253.1 1.16 214.4 12413 68 136.1 6.1 0.137 234.2 1.15 234 11807 136.1 204.1 4.1 0.127 229.2 1.1 244.4 10924 204.1 272.2 0.7 0.092 194.2 0.86 1059.6 7548 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 28: Zone Data (Stage 10; 7714 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4165.0 31.7 0.72 3017 1.46E+06 0.220 2500 SHALE 4196.7 15.0 0.70 2922 1.76E+06 0.220 2500 SHALE 4211.7 24.1 0.69 2919 1.90E+06 0.220 2500 SHALE 4235.8 3.5 0.70 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4239.3 1.5 0.63 2677 1.03E+06 0.270 1500 SHALE 4240.8 2.0 0.69 2923 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4242.8 5.0 0.64 2730 1.34E+06 0.260 1500 SHALE 4247.8 6.5 0.70 2975 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4254.3 7.0 0.66 2808 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4261.3 1.5 0.64 2733 1.42E+06 0.260 1500 SHALE 4262.8 2.0 0.70 2984 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4264.8 1.5 0.63 2707 1.18E+06 0.270 1500 SHALE 4266.3 7.0 0.70 2988 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4273.3 3.0 0.65 2779 1.60E+06 0.260 1500 SHALE 4276.3 2.0 0.70 2993 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4278.3 3.0 0.66 2832 1.59E+06 0.260 1500 SHALE 4281.3 5.5 0.70 2998 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4286.8 1.5 0.61 2632 1.20E+06 0.270 1500 SHALE 4288.3 8.5 0.69 2958 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4296.8 3.5 0.64 2734 9.21E+05 0.270 1500 DIRTY-SANDSTONE 4300.3 4.5 0.66 2844 1.74E+06 0.260 1500 SHALE 4304.8 12.0 0.70 3016 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4316.8 2.0 0.65 2802 1.55E+06 0.260 1500 SHALE 4318.8 9.5 0.70 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4328.3 1.5 0.66 2856 1.75E+06 0.260 1500 SHALE 4329.8 2.0 0.70 3030 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4331.8 2.0 0.65 2836 1.00E+06 0.270 1500 SHALE 4333.8 17.0 0.70 3038 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4350.8 4.0 0.64 2782 9.13E+05 0.270 1500 SHALE 4354.8 15.5 0.70 3052 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4370.3 1.5 0.64 2778 1.03E+06 0.270 1500 SHALE 4371.8 2.0 0.70 3059 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4373.8 2.0 0.66 2884 1.67E+06 0.260 1500 SHALE 4375.8 8.0 0.70 3064 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4383.8 5.5 0.67 2933 1.67E+06 0.260 1500 SHALE 4389.3 2.0 0.70 3071 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4391.3 2.0 0.64 2800 1.12E+06 0.270 1500 SHALE 4393.3 21.5 0.70 3080 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4414.8 2.0 0.65 2863 8.77E+05 0.270 1500 SHALE 4416.8 17.5 0.70 3095 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4434.3 3.5 0.66 2920 1.59E+06 0.260 1500 SHALE 4437.8 48.5 0.70 3120 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4486.3 4.0 0.64 2860 1.46E+06 0.260 1500 SHALE 4490.3 2.0 0.70 3140 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4492.3 2.0 0.66 2970 1.55E+06 0.260 1500 SHALE 4494.3 11.5 0.70 3146 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4505.8 10.0 0.65 2939 1.46E+06 0.260 1500 SHALE 4515.8 50.0 0.69 3129 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4165.0 31.7 0.010 1.0 1921 4196.7 15.0 0.010 1.0 1935 4211.7 24.1 0.050 10.0 1942 4235.8 3.5 0.010 1.0 1953 4239.3 1.5 21.752 22.2 1955 4240.8 2.0 0.010 1.0 1955 4242.8 5.0 4.241 18.7 1956 4247.8 6.5 0.010 1.0 1958 4254.3 7.0 0.799 17.4 1961 4261.3 1.5 3.800 17.9 1965 4262.8 2.0 0.010 1.0 1965 4264.8 1.5 11.075 20.5 1966 4266.3 7.0 0.010 1.0 1967 4273.3 3.0 0.357 15.9 1970 4276.3 2.0 0.010 1.0 1972 4278.3 3.0 0.920 16.1 1973 4281.3 5.5 0.010 1.0 1974 4286.8 1.5 19.275 20.2 1976 4288.3 8.5 0.010 1.0 1977 4296.8 3.5 54.122 23.5 1981 4300.3 4.5 0.208 14.5 1983 4304.8 12.0 0.010 1.0 1985 4316.8 2.0 1.323 16.5 1990 4318.8 9.5 0.010 1.0 1991 4328.3 1.5 0.361 14.4 1996 4329.8 2.0 0.010 1.0 1996 4331.8 2.0 25.112 22.5 1997 4333.8 17.0 0.010 1.0 1998 4350.8 4.0 74.241 23.6 2006 4354.8 15.5 0.010 1.0 2008 4370.3 1.5 29.847 22.2 2015 4371.8 2.0 0.010 1.0 2016 4373.8 2.0 0.355 15.2 2017 4375.8 8.0 0.010 1.0 2018 4383.8 5.5 0.306 15.2 2021 4389.3 2.0 0.010 1.0 2024 4391.3 2.0 33.540 21.1 2025 4393.3 21.5 0.010 1.0 2026 4414.8 2.0 62.109 24.1 2036 4416.8 17.5 0.010 1.0 2037 4434.3 3.5 0.629 7.5 2045 4437.8 48.5 0.010 1.0 2046 4486.3 4.0 15.520 10.0 2069 4490.3 2.0 0.010 1.0 2071 4492.3 2.0 1.839 16.4 2071 4494.3 11.5 0.010 1.0 2072 4505.8 10.0 4.688 14.4 2078 4515.8 50.0 0.010 1.0 2082SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE Shale SHALE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE Formation Transmissibility Properties Zone Name # SLB-Private Attachment G Section 29: Propped Fracture Schedule (Stage 10; 7714 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 25 YF122ST 225.0 22 0 1.0 PPA 25 YF122ST 95.8 22 1 2.0 PPA 25 YF122ST 101.1 22 2 3.0 PPA 25 YF122ST 114.9 22 3 4.0 PPA 25 YF122ST 110.6 22 4 5.0 PPA 25 YF122ST 106.7 22 5 6.0 PPA 25 YF122ST 87.1 22 6 7.0 PPA 25 YF122ST 68.9 22 7 Flush 25 YF122ST 116.5 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 1026.7 bbl of YF122ST 0 bbl of WF122 110194 lb of % PAD Clean 24.7 % PAD Dirty 22.0 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 225.0 225 225 225 0 0 2015 9.0 9.0 1.0 PPA 95.8 321 100 325 4024 4024 1971 4.0 13.0 2.0 PPA 101.1 422 110 435 8496 12520 1894 4.4 17.4 3.0 PPA 114.9 537 130 565 14479 26999 1880 5.2 22.6 4.0 PPA 110.6 647 130 695 18586 45586 1886 5.2 27.8 5.0 PPA 106.7 754 130 825 22399 67984 1895 5.2 33.0 6.0 PPA 87.1 841 110 935 21955 89939 1910 4.4 37.4 7.0 PPA 68.9 910 90 1025 20255 110194 1920 3.6 41.0 Flush 116.5 1027 117 1142 0 110194 1998 4.7 45.7 Job Execution Step Name Pad Percentages Carbolite 16/20-4%SG Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 521.9 ft with an average conductivity (Kfw) of 3558.4 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG # SLB-Private Attachment G Section 30: Propped Fracture Simulation (Stage 10; 7714 ft MD) Initial Fracture Top TVD 4152.5 ft Initial Fracture Bottom TVD 4456.2 ft Propped Fracture Half-Length 521.9 ft EOJ Hyd Height at Well 303.8 ft Average Propped Width 0.046 in Net Pressure 367 psi Max Surface Pressure 2124 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 130.5 5.5 0.071 226.3 0.63 219.4 6018 130.5 260.9 2.6 0.055 198.6 0.52 292.8 4420 260.9 391.4 0.9 0.037 160.6 0.36 411.1 2738 391.4 521.9 0 0.026 128.1 0.25 523.4 1604 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Section 31: Zone Data (Stage 11; 7222 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4194.8 31.7 0.72 3017 1.46E+06 0.220 2500 SHALE 4226.5 15.0 0.70 2943 1.76E+06 0.220 2500 SHALE 4241.5 24.1 0.69 2939 1.90E+06 0.220 2500 SHALE 4265.6 3.5 0.70 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4269.1 1.5 0.63 2677 1.03E+06 0.270 1500 SHALE 4270.6 2.0 0.69 2943 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4272.6 5.0 0.64 2749 1.34E+06 0.260 1500 SHALE 4277.6 6.5 0.69 2975 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4284.1 7.0 0.65 2808 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4291.1 1.5 0.64 2733 1.42E+06 0.260 1500 SHALE 4292.6 2.0 0.69 2984 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4294.6 1.5 0.63 2707 1.18E+06 0.270 1500 SHALE 4296.1 7.0 0.69 2988 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4303.1 3.0 0.65 2798 1.60E+06 0.260 1500 SHALE 4306.1 2.0 0.69 2993 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4308.1 3.0 0.66 2832 1.59E+06 0.260 1500 SHALE 4311.1 5.5 0.69 2998 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4316.6 1.5 0.61 2632 1.20E+06 0.270 1500 SHALE 4318.1 8.5 0.69 2978 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4326.6 3.5 0.64 2753 9.21E+05 0.270 1500 DIRTY-SANDSTONE 4330.1 4.5 0.66 2844 1.74E+06 0.260 1500 SHALE 4334.6 12.0 0.69 3016 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4346.6 2.0 0.64 2802 1.55E+06 0.260 1500 SHALE 4348.6 9.5 0.69 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4358.1 1.5 0.66 2856 1.75E+06 0.260 1500 SHALE 4359.6 2.0 0.69 3030 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4361.6 2.0 0.65 2836 1.00E+06 0.270 1500 SHALE 4363.6 17.0 0.69 3038 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4380.6 4.0 0.63 2782 9.13E+05 0.270 1500 SHALE 4384.6 15.5 0.69 3052 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4400.1 1.5 0.63 2778 1.03E+06 0.270 1500 SHALE 4401.6 2.0 0.69 3059 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4403.6 2.0 0.65 2884 1.67E+06 0.260 1500 SHALE 4405.6 8.0 0.69 3064 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4413.6 5.5 0.66 2933 1.67E+06 0.260 1500 SHALE 4419.1 2.0 0.69 3071 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4421.1 2.0 0.63 2800 1.12E+06 0.270 1500 SHALE 4423.1 21.5 0.69 3080 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4444.6 2.0 0.64 2863 8.77E+05 0.270 1500 SHALE 4446.6 17.5 0.69 3095 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4464.1 3.5 0.65 2920 1.59E+06 0.260 1500 SHALE 4467.6 48.5 0.69 3120 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4516.1 4.0 0.63 2860 1.46E+06 0.260 1500 SHALE 4520.1 2.0 0.69 3140 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4522.1 2.0 0.66 2970 1.55E+06 0.260 1500 SHALE 4524.1 11.5 0.69 3146 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4535.6 10.0 0.65 2939 1.46E+06 0.260 1500 SHALE 4545.6 50.0 0.69 3149 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio # SLB-Private Attachment G Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4194.8 31.7 0.010 1.0 1921 4226.5 15.0 0.010 1.0 1935 4241.5 24.1 0.050 10.0 1942 4265.6 3.5 0.010 1.0 1953 4269.1 1.5 21.752 22.2 1955 4270.6 2.0 0.010 1.0 1955 4272.6 5.0 4.241 18.7 1956 4277.6 6.5 0.010 1.0 1958 4284.1 7.0 0.799 17.4 1961 4291.1 1.5 3.800 17.9 1965 4292.6 2.0 0.010 1.0 1965 4294.6 1.5 11.075 20.5 1966 4296.1 7.0 0.010 1.0 1967 4303.1 3.0 0.357 15.9 1970 4306.1 2.0 0.010 1.0 1972 4308.1 3.0 0.920 16.1 1973 4311.1 5.5 0.010 1.0 1974 4316.6 1.5 19.275 20.2 1976 4318.1 8.5 0.010 1.0 1977 4326.6 3.5 54.122 23.5 1981 4330.1 4.5 0.208 14.5 1983 4334.6 12.0 0.010 1.0 1985 4346.6 2.0 1.323 16.5 1990 4348.6 9.5 0.010 1.0 1991 4358.1 1.5 0.361 14.4 1996 4359.6 2.0 0.010 1.0 1996 4361.6 2.0 25.112 22.5 1997 4363.6 17.0 0.010 1.0 1998 4380.6 4.0 74.241 23.6 2006 4384.6 15.5 0.010 1.0 2008 4400.1 1.5 29.847 22.2 2015 4401.6 2.0 0.010 1.0 2016 4403.6 2.0 0.355 15.2 2017 4405.6 8.0 0.010 1.0 2018 4413.6 5.5 0.306 15.2 2021 4419.1 2.0 0.010 1.0 2024 4421.1 2.0 33.540 21.1 2025 4423.1 21.5 0.010 1.0 2026 4444.6 2.0 62.109 24.1 2036 4446.6 17.5 0.010 1.0 2037 4464.1 3.5 0.629 7.5 2045 4467.6 48.5 0.010 1.0 2046 4516.1 4.0 15.520 10.0 2069 4520.1 2.0 0.010 1.0 2071 4522.1 2.0 1.839 16.4 2071 4524.1 11.5 0.010 1.0 2072 4535.6 10.0 4.688 14.4 2078 4545.6 50.0 0.010 1.0 2082 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE # SLB-Private Attachment G Section 32: Propped Fracture Schedule (Stage 11; 7222 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 20 YF122ST 200.0 22 0 1.0 PPA 20 YF122ST 76.6 22 1 2.0 PPA 20 YF122ST 82.8 22 2 3.0 PPA 20 YF122ST 88.4 22 3 4.0 PPA 20 YF122ST 85.1 22 4 5.0 PPA 20 YF122ST 82.0 22 5 6.0 PPA 20 YF122ST 71.3 22 6 7.0 PPA 20 YF122ST 61.2 22 7 Flush 20 YF122ST 105.0 22 0 Please note that this pumping schedule is under-displaced by 5.0 bbl. 852.5 bbl of YF122ST 0 bbl of WF122 88803 lb of % PAD Clean 26.8 % PAD Dirty 23.8 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 200.0 200 200 200 0 0 1763 10.0 10.0 1.0 PPA 76.6 277 80 280 3219 3219 1727 4.0 14.0 2.0 PPA 82.8 359 90 370 6952 10171 1636 4.5 18.5 3.0 PPA 88.4 448 100 470 11138 21308 1577 5.0 23.5 4.0 PPA 85.1 533 100 570 14297 35606 1542 5.0 28.5 5.0 PPA 82.0 615 100 670 17230 52835 1517 5.0 33.5 6.0 PPA 71.3 686 90 760 17963 70798 1501 4.5 38.0 7.0 PPA 61.2 747 80 840 18004 88803 1485 4.0 42.0 Flush 105.0 852 105 945 0 88803 1613 5.3 47.3 Carbolite 16/20-4%SG The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 421 ft with an average conductivity (Kfw) of 3544.3 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Carbolite 16/20-4%SG Pad Percentages Carbolite 16/20-4%SG Carbolite 16/20-4%SG Fluid Totals Proppant Totals Carbolite 16/20-4%SG Job Execution Step Name # SLB-Private Attachment G Section 33: Propped Fracture Simulation (Stage 11; 7222 ft MD) Initial Fracture Top TVD 4192.7 ft Initial Fracture Bottom TVD 4474.7 ft Propped Fracture Half-Length 421 ft EOJ Hyd Height at Well 281.9 ft Average Propped Width 0.048 in Net Pressure 265 psi Max Surface Pressure 1813 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 105.3 5.2 0.068 141.1 0.67 235.3 5499 105.3 210.5 3.2 0.061 208.4 0.66 269.4 4705 210.5 315.8 2.3 0.049 167.4 0.56 330.3 3633 315.8 421 0.7 0.018 131.9 0.29 770.3 928 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment # SLB-Private Attachment G Attachment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ttachment I NDB-032 Well Flowback 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 Attachment J NDB-032 4-1/2” Production Liner Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P-110S TSH563 lower completions per tally. 2. Circulate out 10.0 ppg OBM with 9.4 ppg NaCl brine to surface. 3. Flow check for 10 minutes. 4. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 5. Pressure up to close the WIV at 1,980 psi. 6. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 7. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. 8. Before releasing, pressure test the IA to top liner hanger/packer to 3,000 psi. 9. Release running tool from liner hanger. 10.Circulate 9.4 ppg NaCl brine to surface at 10 bpm pump rate. 11.POOH with liner hanger running tool. 12.Prepare to run upper completion. NDB-032 4-1/2” Upper Completion Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 2. Forward circulate 9.4 ppg inhibited NaCl brine before installing tubing hanger. 3. Land tubing hanger. 4. MIT-T to 4,000 psi. (Post Rig Move, MIT-T will be tested to 6,000 psi) a. (8,700 psi MAWP – 3,300 psi IA hold) * 1.1 = 5,940 psi 5. MIT-IA to 3,500 psi. (Post Rig, MIT-IA to be tested again to 3,800 psi with AOGCC notification) a. NOTE: AOGCC witnessed test 09/23/23 6. Shear circulation valve. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k psi frac tree. (Rig to start rigging down) 9. Pull the TWCV 10.Reverse circulate freeze protect and U-Tube. 11.Install TWCV check into the tubing hanger and pressure test from direction of flow. 12.RDMO tested to 6,000 psi) again to 3,800 psi with NDB-032 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up flowback as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment K Attachment L 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 November 28, 2023 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 11/27/2023 (a)(2) Plat Provided with application. SFD 11/27/2023 test (a)(2)(A) Well location Provided with application. Surface location lies in Section 4 of T11N, R6E, UM. Top of productive interval lies in Section 5 of T11N, R6E, UM. The productive interval and TD lie in Section 32 of T12N, R6E, UM. SFD 11/27/2023 (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 Nov. 27, 202), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of NDB-032. There are no subsurface water rights or temporary subsurface water rights within 14 miles of the surface location of NDB-032. SFD 11/27/2023 (a)(2)(C) Identify all well types within ½ mile NDB-043, NDB-043PB1, NDB-024, DW-02 SFD 11/27/2023 (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 SFD 11/27/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 November 28, 2023 between 1,400’ and 1,500’ MD (-1,463’ to -1,363’ TVDSS; base of permafrost 1,350’ MD (-1,305’ TVDSS)); and DW-02 (223-039) ~21,500 mg/l between 1,550’ and 1,650’ MD (-1,408’ to -1,486’ TVDSS; base of permafrost ~1,170’ MD (~-1,080’ TVDSS). (a)(4) Baseline water sampling plan None required: No freshwater aquifers are present. SFD 11/27/2023 (a)(5) Casing and cementing information NDB-032: 13-3/8” surface casing set at 2,588’ MD (-2,205’ TVDSS) and cemented to surface with 163 bbls of cement returns. 9-5/8” intermediate liner set at 6,283’ MD (-4,207’ TVDSS) and cemented with an estimated 47 barrels of cement returns. Cement evaluation log demonstrates that the Tuluvak interval between 2,934’ and 3,190’ MD (-2,461’ to -2,622’ TVDSS) is isolated by fair- to good-quality cement from 2,600’ to 3,460’ MD (-2,214’ to -2,809’ TVDSS). Nanushuk (top at 4,952’ MD / 3,795’ TVDSS) is isolated by overlying good - to excellent-quality cement extending upward to 4,500’ MD (-3,529’ TVDSS). After drilling 8-1/2" hole to about 12,381' MD (-4,128' TVDSS), the 4-1/2” production liner was run to a depth of about 12,374' MD (-4,128' TVDSS). This liner is uncemented. SFD 11/27/2023 (a)(6) Casing and cementing operation assessment 9-5/8” provided with application. CAST-M run and evaluated. Verified full cement coverage 9-5/8” – varying quality. Uncemented 4.5” liner CDW 11/28/2023 (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.) SFD 11/27/2023 (a)(6)( B) Each hydrocarbon zone is isolated Yes. Surface casing (13-3/8”) was set at 2,588’ MD (-2,205’ TVDSS) and cemented to surface with 163 bbls of cement SFD 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 November 28, 2023 returns. 9-5/8” intermediate liner set at 6,283’ MD (-4,207’ TVDSS) and cemented with an estimated 47 barrels of cement returns. Cement evaluation log demonstrates that the Tuluvak interval between 2,934’ and 3,190’ MD (-2,461’ to -2,622’ TVDSS) is isolated by fair- to good-quality cement from 2,600’ to 3,460’ MD (-2,214’ to -2,809’ TVDSS). So, the base of the permafrost zone and the underlying Tuluvak and middle Schrader Bluff are isolated by fair- to good- quality cement. 9-5/8” intermediate liner set at 6,283’ MD (-4,252’ TVDSS) and cemented. In NDB-032, the top of the Tuluvak Shale is 2,867’ MD (-2,383’ TVDSS) and the top of the Tuluvak Sands is 2,934’ MD (-2,425’ TVDSS), which are about 50’ thick in this area. Cement evaluation log demonstrates that the Tuluvak interval is isolated by fair- to good-quality cement from 2,600’ to 3,460’ MD (-2,214’ to -2,809’ TVDSS). The Nanushuk (top at 4,952’ MD / 3,795’ TVDSS) is isolated by good- to excellent-quality cement extending upward to 4,500’ MD (-3,529’ TVDSS). So, the top of the Nanushuk Formation and the target reservoir sand are cement isolated. 11/27/2023 SFD 11/27/2023 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3800 psi MITIA, 6000 psi MITT. CDW 11/28/2023 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree max. frac. Pressure 4726 psi (8700 psi MAWP). Pump knock out 7400 and GORV 8200 psi., lines test 9000 psi. CDW 11/28/2023 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone Upper Confining Zones: About 900’ true vertical thickness (TVT) of shale and thinly interbedded siltstone assigned to SFD 11/27/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 November 28, 2023 (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 the Upper Torok/Hue Shale 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 650’ TVT in this area and has an estimated fracture gradient of 11.7 ppg EMW (0.61 psi/ft). Lower Confining Zones: Lower Torok siltstone and shale that is about 170’ thick in this area with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft ). This is underlain by about 225’ of condensed marine shale assigned to the HRZ. (a)(10) Location, orientation, and a report on the mechanical condition of each well that may transect the confining zones, and information sufficient to support a determination that the well will not interfere with containment of the hydraulic fracturing fluid within the one- half mile radius of the proposed wellbore trajectory There are four wells and wellbores within ½ mile DW-02, NDB-024, NDB-043, and NDBi-043A. None are expected to interfere with containment of fracturing fluids. DW -02: This is the Class I disposal well for the Pikka Development. 9-5/8” surface casing set at 2,574’ MD (-2,187’ TVDSS) and cemented to surface with 135 bbls of cement returns. 7” production liner was set to 7,693’ MD (-6,195’ TVDSS) and cemented with a sufficient volume to reach the surface casing shoe. Operator’s reported top cement is 2,426’ MD (-2,068’ TVDSS). Cement evaluation logs demonstrate that the Tuluvak interval between 2,904’ and about 3,140’ MD (-2,425’ to -2,601’ TVDSS) is bracketed above and below by good- to excellent-quality cement, and that the Nanushuk 4,739’ to 6,540’ MD (-3,792’ to -5,142’ TVDSS) is covered and isolated by good - to excellent cement. NDB-024: After drilling 16" surface hole to about 3,240' MD (-2,206' TVDSS), 13-3/8” surface casing was set at 3,171 MD (-2,191’ TVDSS). Subsequent operations parted the casing at 2,837’ MD (-2,126’ TVDSS). Due to this parting, surface SFD 11/27/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 November 28, 2023 casing cement was over-displaced resulting in an estimated bottom depth of cement at 2,236’ MD (-1,887’ TVDSS). Returns were lost during the last 26 barrels. Gas was observed bubbling out of the conductor after the cement was pumped. Subsequently a top job was performed from the base of conductor to surface, and the surface casing was squeezed at the parted pipe at 2837’ MD. The well was then sidetracked at 2720’ MD. A subsequent FIT to 13.79 ppg was achieved, indicating cement isolation above the windo w. Interpretation of cement evaluation logs indicates that cement quality is fair from 2,526’ MD (-2,026’ TVDSS) to 1,510’ MD (-1,368’ TVDSS), good from 1,510’ MD (-1,368’ TVDSS) to 1,380’ MD (-1,257’ TVDSS), and poor from 1,380’ MD (-1,257’ TVDSS) to 844’ MD (-765’ TVDSS). Cement quality is uncertain between 844’ MD (-765’ TVDSS) and the ground surface. After drilling 12-1/4" hole to 11,465' MD (-4,044' TVDSS), 9-5/8” intermediate liner was set at 11,465’ (-4,046’ TVDSS) and cemented in two stages. The second- stage cementing collar for the 9-5/8” intermediate liner is located at 5,560’ MD (-2,731’ TVDSS). The operator reports that 105 bbls of second -stage cement was circulated off the liner top at 2,673’ MD (-2,080’ TVDSS). The operator estimates the first-stage cement top lies at 8,782’ MD (-3,553’ TVDSS), isolating the Nanushuk (top at 10,255’ MD, 3,769’ TVDSS). NDB-043 (Pilot Hole): 13-3/8” surface casing set at 2,502’ MD (-2,172’ TVDSS) and cemented to surface with 70 bbls of good cement returns. 9-5/8” intermediate liner set at 6,237’ MD (-4,249’ TVDSS) and cemented. Volumetric calculations indicate sufficient cement was pumped to reach the surface casing shoe. The operator’s estimated top of cement is SFD 11/27/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 November 28, 2023 2,792’ MD (2,371’ TVDSS). From the cement evaluation log, AOGCC’s consultant interprets poor to patchy cement from 2,370’ to 4,400’ MD (-2,083’ to -3,468’ TVDSS) and fair cement from 4,400’ to 5,800’ MD (-3,468’ to -4,153’ TVDSS). The Tuluvak interval lies between 2,894’ and 3,125’ MD 2,441’ to -2,600’ TVDSS), and the top of the Nanushuk lies at 4,955’ MD (-3,796’ TVDSS). So, the Tuluvak is isolated by poor to patchy cement, and the underlying Nanushuk is isolated by fair-quality cement that should be sufficient to contain hydraulic fracturing fluids. This pilot wellbore drilled to determine reservoir thickness was abandoned. NDB-043A: This horizontal wellbore kicked off from NDB-043 within the Nanushuk reservoir at 10,132’ MD (-4,126’ TVDSS). SFD 11/27/2023 (a)(11) Sufficient information to determine wells will not interfere with containment within ½ mile Yes. There are four wells and wellbores within ½ mile of DW-02, NDB-032: NDB-024, NDB-043, and NDB-043A. None of these wells should interfere with containment of fracturing fluids. SFD 11/27/2023 (a)(11) Faults and fractures, Location, orientation (a)(11) Faults and fractures, Sufficient information to determine no interference with containment within ½ mile One fault identified: The operator-provided fault map identifies one north-trending fault that lie within a ½-mile radius of NDB-032 and refers the reader to the fault-related discussion provided in the Sundry Application to hydraulically fracture nearby well NDB-024. (See AOGCC’s Well History File 223-076, p. 76-80, 92, 95-99 of S undry Application 323-591. The fault is labeled “Fault 4” in those documents.) Fault 4 is a 10-foot displacement, down-to-the-east, normal fault seismically mapped in the southeast portion of the Area of Review. This fault was expected to be intersected by the wellbore at NT6/7 level at about 10,250’ MD (3,836’ SFD 11/27/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 November 28, 2023 TVD, or -3,765’ TVDSS) and a location that is roughly 300 true vertical feet shallower than, and about 900’ mile northwest of the total depth of reached by NDB-032. However, the operator did not observe direct evidence of this fault on the LWD well logs recorded in well NDB-024, only an ROP change at about 10,720’ MD (-3,772’ TVDSS) and a small spike on the density log. If present, this fault is minor. Based on the regional stress field, induced fractures are expected to propagate along an azimuth of about 330°, which is approximately parallel with the azimuth of the horizontal production section of the NDB -032 well. The operator reported that the fault described above is stratigraphically contained to the Nanushuk and that they do not extend into the overlying confining layer. There is little likelihood that this fault will interfere with containment of the fracturing fluids. However, if there are indications that an induced fracture has intersected a fault or fractured interval during fracturing operations, the operator will go to flush and terminate the stage immediately. SFD 11/27/2023 (a)(12) Proposed program for fracturing operation Provided with application. CDW 11/28/2023 (a)(12)(A) Estimated volume Provided with application. 38K bbl, 2.1M lb total proppant CDW 11/28/2023 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 11/28/2023 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided. CDW 11/28/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 8 November 28, 2023 (a)(12)(D) Inert substances , weight or volume of each Provided with application. CDW 11/28/2023 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulations shows max surface pressure 4726 stage 1 psi. Max. Oil Search is calls for Max. Allowable Wellhead Pressure of 8700 psi. Max. setting pump trip as 7400 psi to Pump shutdown. With 3300 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 5400 psi. CDW 11/28/2023 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures will range from about 320’ to 520’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will range from about 220’ to 310’, and the shallowest frac top TVDSS of about -4,133’, which is about 300 true vertical feet deeper than the base of the upper confining layer. So, Schlumberger’s FracCADE computer model indicates that the induced fractures should not penetrate into the overlying confining interval that has an aggregate thickness of more than 900’ in this area. SFD 11/27/2023 (a)(13) Proposed program for post- fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. Oil Search has a Class I disposal well onsite, trucking options, and oil sales/disposal options. Finalized flowback to testing protocols, volumes, and disposal cutoff options (1.5 total frac volume to 2X frac volume). CDW 11/28/2023 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3300 psi back pressure, plan to test to 3800 psi, popoff set as 3600 psi CDW 11/28/2023 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be stung into liner top packer at 6104’ MD, 4.5” liner tie back assembly 6136 ft . 9-5/8” production liner to 6283 ft. CAST-M Halliburton cement eval has TOC as good from 2608 ft with varying intervals - but good 4940-4998, CDW 11/28/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 9 November 28, 2023 fair 4998-5278, good 5278 to 5822 ft. Shallowest frac sleeve as 7222 ft. (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 6000 psi. Max pressure differential is estimated as 4300 psi (7600 with 3300 psi backpressure) so test of 6000 psi satisfies 110% CDW 11/28/2023 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9000 psi line pressure test, pump knock out 7400 psi with max. global kickout 8200 psi. IA PRV set as 3600 psi. CDW 11/28/2023 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 11/28/2023 (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 11/28/2023 (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 p ressure or thermal transfer, the operator shall: CDW 11/28/2023 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required. No freshwater aquifers present. (See Section (a)(3), above.) SFD 11/27/2023 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Not applicable: This well is not confidential. SFD 11/27/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist NDB-032 (PTD No. 223-060; Sundry No. 323-616) Paragraph Sub-Paragraph Section Complete? AOGCC Page 10 November 28, 2023 (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 operatio n. 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Friday, October 13, 2023 9:31 AM To:Brake, Jared (Jared) Cc:Regg, James B (OGC) Subject:RE: Pikka NDB-032 MIT-IA form Attachments:MIT Pikka NDB-032 09-23-23 Witnessed.xlsx; MIT Pikka NDB-032 09-23-23.xlsx Also revised this report, separaƟng the two tests (MIT‐IA was witnessed by Josh Hunt not the MIT‐T). Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent: Monday, September 25, 2023 4:41 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: Pikka NDB‐032 MIT‐IA form All, Here is a state witnessed MIT‐IA form for the Pikka NDB‐032 Producer. We offered a witness on this well for the upcoming frac sundry, the inspectors accepted the offer to witness. Jared Brake Well Integrity & Well IntervenƟon Specialist t: 1 (907) 375‐4673 | m: 1 (832) 330‐4359| e: jared.brake@contractor.santos.com Santos.com | Follow us on LinkedIn, Facebook and TwiƩer You don't often get email from jared.brake@contractor.santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Pikka NDB-32PTD 2230600 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2230600 Type Inj N Tubing 2780 3215 3222 3219 Type Test P Packer TVD 4305 BBL Pump 5.4 IA 7 4000 3899 3870 Interval O Test psi 3800 BBL Return 5.2 OA 0 0 0 0 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Santos - Oil Search (Alaska), LLC Pikka / NDB Pad Josh Hunt Pere Keniye 09/23/23 Notes:Tested as per PTD # 223-0520. Pre-Frac sundry MIT-IA. Notes: Notes: Notes: NDB - 032 Form 10-426 (Revised 01/2017)2023-0923_MITP_Pikka_NDB-032_2tests Producer J. Regg; 10/13/2023 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2230600 Type Inj N Tubing 2791 6486 6437 6419 Type Test P Packer TVD 4305 BBL Pump 3.3 IA 500 672 675 677 Interval O Test psi 6200 BBL Return 3.3 OA 0 0 0 0 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Santos - Oil Search (Alaska), LLC Pikka / NDB Pad Pere Keniye 09/23/23 Notes:MIT-T. Pressured up tubing to 2780psi prior to pressure testing the IA Notes: Notes: Notes: NDB - 032 Form 10-426 (Revised 01/2017)2023-0923_MITP_Pikka_NDB-032_tbg Producer; not witnessed by AOGCC Inspector ========================================================= J. Regg; 10/12/2023 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-032 (50-103-20860-0000) Final well data submittal – details on following pages Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 907-375-4607 phone shannon.koh@santos.com DATE: 10/12/2023 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Kayla Junke AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈ External Request ܆ Internal Request TRANSMISSION METHOD: ܆ CD ܆ Thumb Drive ܆ Email ܆ SharePoint/Teams ܆ Hardcopy ܈ Other – FTP REASON FOR TRANSMITTAL: ܆ Approved ܆ Approved with Comments ܆ For Approval ܈ Information Only ܆ For Your Review ܆ For Your Use ܆ To Be Returned ܆ With Our Comments ܆ Other COMMENTS: PTD: 223-060 T38048 10/12/2023 Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.12 13:51:51 -08'00' LETTER OF TRANSMITTAL NDB-032 (50-103-20860-0000) جؐؐؐDirectional Survey ؒ NDB-032 Final Compass Survey NAD27.pdf ؒ NDB-032 Final Compass Survey.pdf ؒ NDB-032 Plan View.pdf ؒ NDB-032 Vertical Section.pdf ؒ NDB-032.txt ؒ NDBi-032 WA Survey Reports.xlsx ؒ جؐؐؐLog Digital Data (LWD and WL) ؒ جؐؐؐCement Evaluation Logs ؒ ؒ ACE_SANTOS_NDB-032_12SEP2023_Report.pdf ؒ ؒ ACE_SANTOS_NDB-032_12SEP2023_v2.pdf ؒ ؒ ACE_SANTOS_NDB-032_12SEP2023_v2.tif ؒ ؒ ACE_SANTOS_NDB-032_12SEP2023_v2_DLIS.zip ؒ ؒ ACE_SANTOS_NDB-032_12SEP2023_v2_LAS.zip ؒ ؒ ؒ ؤؐؐؐLWD ؒ جؐؐؐDigital Data ؒ ؒ NDB-032_AP_R01_RM_20230821.las ؒ ؒ NDB-032_AP_R02_RM_20230823.las ؒ ؒ NDB-032_AP_R03_RM_20230829.las ؒ ؒ NDB-032_AP_R04_RM_20230909.las ؒ ؒ NDB-032_LWD_RM_12381ft.las ؒ ؒ ؒ ؤؐؐؐGraphics ؒ NDB-032_AP_RM_20230910.cgm ؒ NDB-032_AP_RM_20230910.pdf ؒ NDB-032_DMD_RM_12381ft.cgm ؒ NDB-032_DMD_RM_12381ft.pdf ؒ NDB-032_DMT_RM_20230910.cgm ؒ NDB-032_DMT_RM_20230910.pdf ؒ NDB-032_LWD_RM_12381ft_2MD.cgm ؒ NDB-032_LWD_RM_12381ft_2MD.pdf ؒ NDB-032_LWD_RM_12381ft_2TVD.cgm ؒ NDB-032_LWD_RM_12381ft_2TVD.pdf ؒ NDB-032_LWD_RM_12381ft_5MD.cgm ؒ NDB-032_LWD_RM_12381ft_5MD.pdf ؒ NDB-032_LWD_RM_12381ft_5TVD.cgm ؒ NDB-032_LWD_RM_12381ft_5TVD.pdf ؒ ؤؐؐؐMudlog جؐؐؐEOW ؒ NDB-032 Mudlogging End of Well Report.pdf ؒ LETTER OF TRANSMITTAL جؐؐؐGeological Reports (compilation in PDF) ؒ NDB-032 Mudlogging Geological Reports.pdf ؒ جؐؐؐMudlogging final data ؒ NDB-032 Cuttings Manifest.pdf ؒ NDB-032_DrillGas_ASCII_depth_12381ft (1).las ؒ NDB-032_DrillGas_ASCII_depth_12381ft.las ؒ NDB-032_DrillGas_ASCII_depth_Lithology_12381ft (1).las ؒ NDB-032_DrillGas_ASCII_depth_Lithology_12381ft.las ؒ NDB-032_GasRatioLog_12381ft_MD-2in.pdf ؒ NDB-032_GasRatioLog_12381ft_MD-5in.pdf ؒ NDB-032_GasRpt.xlsx ؒ NDB-032_Lithology.xlsx ؒ NDB-032_Mudlog_12381ft_MD-2in.pdf ؒ NDB-032_Mudlog_12381ft_MD-5in.pdf ؒ ؤؐؐؐOil, Gas and Gas Hydrate Shows List Show Report Geolog_NDB-032_10150-10170_#14.pdf Show Report Geolog_NDB-032_10280-10320_#15.pdf Show Report Geolog_NDB-032_10630-10700_#16.pdf Show Report Geolog_NDB-032_12060-12110_#17.pdf Show Report Geolog_NDB-032_12320-12381_#18.pdf Show Report Geolog_NDB-032_2910-3150_#1.pdf Show Report Geolog_NDB-032_4865-4950_#2.pdf Show Report Geolog_NDB-032_5100-5205_#3.pdf Show Report Geolog_NDB-032_5250-5330_#4.pdf Show Report Geolog_NDB-032_6000-6100_#5.pdf Show Report Geolog_NDB-032_6825-6900_#6.pdf Show Report Geolog_NDB-032_7450-7590_#7.pdf Show Report Geolog_NDB-032_8340-8660_#8.pdf Show Report Geolog_NDB-032_8750-8840_#9.pdf Show Report Geolog_NDB-032_8875-8895_#10.pdf Show Report Geolog_NDB-032_8980-9050_#11.pdf Show Report Geolog_NDB-032_9440-9483_#12.pdf Show Report Geolog_NDB-032_9740-9800_#13.pdf 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: 2367 FSL, 3129 FEL, S4, T11N, R6E, UM Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): 4797 FSL, 991 FEL, S5, T11N, R6E, UM GL: 22.84 BF: 46.75 Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4598 FSL, 3996 FEL, S32, T12N, R6E, UM 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: GR-RES-NEU-DEN-Sonic, Mudlogs, CBL 23. BOTTOM 20"X34" X-52 128' 13-3/8" L-80 2273' 9-5/8" L-80 4322' 9-5/8" L-80 2165' 4-1/2" P-110S 4197' 4/1/2" P-110S 4294' 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil Search Alaska, LLC WAG Gas 09/13/23 223-060 50-103-20860-00-00 NDB-032 ADL 392984, 391445, 393020 LONS 19-003 08/20/23 12381' / 4197' N/A 69.59 900 E Benson Boulevard, Anchorage, AK 99508 422,115.35 5,972,751.32 09/06/23 418,993.34 416,028.43 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 BOTTOM 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, CEMENTING RECORD 5,975,214.30 1365' MD / 135' TVD SETTING DEPTH TVD 5,980,327.67 TOP HOLE SIZE AMOUNT PULLED 12.6# Surface 42" Tubing N/A CASING WT. PER FT.GRADE 16" Grouted to surface Surface See attached Surface cement report 47# Surface Surface 2588' N/ATie Back See attached Intermediate cement Report 12-1/4" 128' Surface 215# 68# Surface 2417' 6283' SIZE DEPTH SET (MD) See attached Packer report PACKER SET (MD/TVD) Gas-Oil Ratio: 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. TUBING RECORD 6157' Surface 12374'4-1/2" Per 20 AAC 25.283 (i)(2) attach electronic information 47# 2417' 2165' Date of Test: Oil-Bbl: Flow Tubing Choke Size: Sr Res EngSr Pet GeoSr Pet Eng Pikka/Nanushuk Oil Pool N/A Oil-Bbl: Water-Bbl: 12.6# 6105' 12374' 4306' 8-1/2" N/A Water-Bbl: PRODUCTION TEST G s d 1 0 yyp d t P l L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment Completed 9/13/2023 JSB RBDMS JSB 101123 Received 10/4/2023 DSR-10/13/23BJM 10/25/23 G Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface 1412' 1400' 6283' 4322' 1039' 1036' 1822' 1758' 2390' 2148' 2867' 2452' 2934' 2495' 3940' 3175' 4952' 3865' 4974' 3878' NT7 MFS 5021' 3906' NT6 MFS 5140' 3973' NT5 MFS 5249' 4030' NT4 MFS 5390' 4097' NT3 MFS 6140' 4310' NT3.2 Top Reservoir 6468' 4325' NT3.24 10930' 4228' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Mark Staudinger Digital Signature with Date:Contact Email:mark.staudinger@santos.com Contact Phone: 1-520-273-6643 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: 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 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS 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. Nanushuk TPI (Top of Producing Interval). Authorized Name and Formation Name at TD: INSTRUCTIONS Permafrost - Top Permafrost - Base Top of Productive Interval Upper Schrader Bluff Middle Schrader Bluff MCU Tuluvak Shale Tuluvak Sand Seabee 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. NT8 MFS N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov foregoing is true and correct to the best of lingEngineer uction or well test results, per 20 AAC 25.0 October 3, 2023 17 NDB-032 Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2417' MD 13-3/8" 68 ppf L-80 Surface Casing2588' MD 9-5/8", 47ppf L-80 Production Liner 6283' MD 4-½”, 12.6ppf P-110S Production Liner12376' MD GL 9-5/8" 68 ppf L-80 Tieback2417' MD 9.14.2023 41.5' RKB – Tubing Hanger Flange 1 2 3 4 5 6 7 8 9 8-½” Openhole12381' MD # CompletionItem Depth(MD')Depth(TVD') Inc ID" OD" 1 GasliftMandrel1.5" 2908 2478 50 3.865 7.684 2XLandingNipple 2971 2518 50 3.813 4.787 3XLandingNipple 5847 4256 76 3.813 4.790 4D/HPsiͲTempGauge 5902 4270 77 3.905 6.002 5 SSDNERAGL 5957 4281 79 3.813 6.922 6 SlimlineDial 6016 4292 80 3.898 5.990 7XLandingNipple 6039 4296 80 3.813 4.784 8TiebackSealAssy 6136 4309 83 3.860 5.230 9 9.625"x4.5"LH/Packer 6104 4305 83 6.180 8.420 10 #12OpenholePacker 6952 4314 91 3.918 8.000 11 Stage 11ͲFracSleeve 7222 4308 91 3.735 5.627 12 #11OpenholePacker 7444 4303 91 3.918 8.000 13 Stage 10ͲFracSleeve 7714 4298 91 3.735 5.627 14 #10OpenholePacker 8019 4291 91 3.918 8.000 15 Stage 9ͲFracSleeve 8206 4287 91 3.735 5.627 16 #9OpenholePacker 8511 4281 91 3.918 8.000 17 Stage 8ͲFracSleeve 8698 4277 91 3.735 5.627 18 #8OpenholePacker 9043 4269 91 3.918 8.000 19 Stage 7ͲFracSleeve 9188 4266 91 3.735 5.627 20 #7OpenholePacker 9451 4260 91 3.918 8.000 21 Stage 6ͲFracSleeve 9676 4255 91 3.735 5.627 22 #6OpenholePacker 9896 4250 91 3.918 8.000 23 Stage 5ͲFracSleeve 10160 4244 91 3.735 5.627 24 #5OpenholePacker 10338 4241 91 3.918 8.000 25 Stage 4ͲFracSleeve 10644 4234 91 3.735 5.627 26 #4OpenholePacker 10985 4227 91 3.918 8.000 27 Stage 3ͲFracSleeve 11126 4224 91 3.735 5.627 28 #3OpenholePacker 11389 4218 91 3.918 8.000 29 Stage 2ͲFracSleeve 11613 4213 91 3.735 5.627 30 #2OpenholePacker 11836 4209 91 3.918 8.000 31 Stage 1ͲFracSleeve 12102 4203 91 3.735 5.627 32 #1OpenholePacker 12241 4200 91 3.918 8.000 33 #2Toe Sleeve 12300 4198 91 3.500 5.875 34 #1Toe Sleeve 12308 4198 91 3.500 5.875 35 WIV Collar 12363 4197 91 5.620 36 Eccentricshoe 12372 4197 91 3.930 5.220 *£ě 0ě mě ěě i+ ě *ě ě Cě ä²ě /ě Ąě /ě ě ĕ Pě ě ě ;ě ě ( *ě 1ě ě qìě ě +ě ě ě >ěIě jě ¶ě G2ě 1ě øě ě BĀě ě ÜJ3ě 1ě +ě ě ³ě r¼ě ě H?Ýo-ě áÊě Ně &ě ě >ě Ė Ně ě ě ý ě 3ě ùě ě ě .*ě Ăm_ ě ñ èě n ě ě &g5½ě ěBQě ě ě ě ě /ě Cě ě ćě Ěě ě (òĊčěě «J ě pÂě Úě ě îě ?0 ě Wě @ě Iě Î ě ·3&2Ï2ě \ě āHě E`ě hÙ`éě ¾ě ě Tě ě .STØě àě Þ¡®ě ě 7º7Çě Yě ě ě ¢ě ,ě ,ě ě ,ě ïě H,ě '.ě ê ě o ě Eæbě 7ě µúěpbě ė Oě *qGÃě MüUUPě Ñ´ěěðě MYiÖÔOě [\ě ¸R1Ëě Z@*ě @ě&R ě ě ; 3 ě " "ě ě }ě ě Ðě Ęě ě ě {ě ě ;2tě &ě uě |ě ""vě ě ~ě ě zě &ě ě ě ""wě ě ě 9ě ě !ě=ċĎěě$¯k#A-$-ě ěB('ě í>'ě å6ě ě ě Ì'ě ¿ně ě Ò ě ě çÄ ě ě răě ě Iě ě Zě Èě ě .+ě _ ě ě jě ě 7û'ě ě ('ě ě ě óě 'ě , ě Jþ ě ě ëě EÓě ě ě +ě ě ě Gě ě [ě +ě ě 0ě ě 0 ě ""ě ě KÀ5#ě !$aěK!5ÁFě%6ě%<]°ě!ěôe#ěek#)#ě F%Å$âěDª#f¤ě F-cc¨õg-ě f%6ě!ÍÛě=%ö^»ě !ãěAěÕ!d<ě )4ě .ě /ě ě !6±4ě Sě¹ě ě AaD)ě=É¥ě ě ě ¬ßÿ#^ě×Vě h(ě &÷ě (ě )%<K4ě C?ě $5$d)4ě Æě ]%#)¦ě !$§DVě ęě Wě 99ě : :ěx©yělLē88Lě lL8ě ě XĐĆĉđĒsĈ8QěXďsĔČąě :ě +$*(!B @B A B # 0B B B 4<<9?&*.'- /,1%( 2B 5;3B76B >;48:=B)7B " B Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 8/18/2023 8/19/2023 0 No accidents, incidents or spills. Prepare for Rig Move. Skid haunch into moving position, skid the rig floor to lay-over position, lay mast over. Prep modules for splitting. 8/19/2023 8/20/2023 0 10.00 No accidents, incidents or spills. Finish moving rig modules over new well. R/U interconnect lines, communications & power supply. Raise derrick, skid rig floor in place. Prep rig floor & pipeshed for drilling operations. Prep mud pits & bring on spud mud. Dress mud pumps with 6- 1/2" liners & swabs. Install speed head on conductor, N/U diverter system & surface annular. M/U stands of 5-7/8" DP. 8/20/2023 8/21/2023 128 412.00 10.00 No accidents or incidents. 1/4 cup of Diesel to pad. Non recordable. PJSM with crew, continue to torque bolts on riser/diverter. P/U 5-7/8" HWDP rack back in derrick. Finish mobilizing BHA subs to floor. Perform diverter/rig evac drill with rig crews and support crews. P/U & M/U 16" Surface BHA. Drill 16” surface hole from 126’ MD to 540’ MD (540’ TVD). 8/21/2023 8/22/2023 540 576.00 10.00 No accidents, incidents or spills. Drill 16” surface hole from 540’ MD to 758’ MD. Circulate bottoms up 2 times. Flow check, well static. Drop gyro 1.83'' OD 23'. Pull out on elevators, from 758' MD to 126' MD. No tight spots. Retrieve gyro tool lay down to pipe shed. TIH on elevators from 126' MD to 758' MD. Drill 16” surface hole from 758’ MD to 1029’ MD. Circulate bottoms up 2 times for BHA/Bit Trip. Backream from 1029' MD to 832' MD. Monitor well for 10 min = Static. POOH on Elevators from 832' MD to surface. Lay down BHA. M/U 16" drilling BHA. Swap out motor, plug in and upload tools, m/u new bit. RIH with 16” drilling BHA from surface to 929’ MD. Wash down from 929' MD to 1029' MD. Drill 16” surface hole from 1029’ MD to 1116’ MD. 8/22/2023 8/23/2023 1,116 1,482.00 10.00 No accidents, incidents or spills. Drill 16” surface hole from 1116’ MD to TD at 2598’ MD. CBU 2x and rack back 2 stands. 8/23/2023 8/24/2023 2,598 0.00 10.10 No accidents, incidents or spills. Monitor well for 10 minutes: Static. BROOH from 2438' MD to 1150' MD. POOH on elevators from 1150' MD to surface to inspect bit. RIH with 16" BHA from surface to 2537'. Washing down at 2537' MD to 2598' MD. CBU 2x and rack back 1 stand each BU. Flow check for 10 minutes: Static. POOH on elevators from 2530’ MD to 157’ MD. L/D surface BHA from 157' to surface. R/U and Run 13-3/8”, 68#, L-80, Surface Casing to 1326’ MD. 8/24/2023 8/25/2023 2,598 0.00 10.00 No accidents, no incidents. PJSM, Run 13-3/8”, 68#, L-80, BTC, surface casing w/torque rings, from 1326' MD to 2572' MD. Redress threads on 13-3/8" split landing jt. Pin end of upper section & box end of lower section (originally 3/4" From being fully made up). After Dressing threads connection was made up by hand w/ chain Tongs and Torqued with power tongs to M/U torque of 15K. Engage CRT Tool, fill casing, break circulation with 2 bpm 204 psi, wash down, land casing hanger on landing ring at 2588' MD. 3' fill on bottom, work casing string several times while staging pumps to 10 bpm, 250 psi. Stage up to cementing rate in 1 BPM increments to final circulating rate of 10 BPM. PJSM, R/U cement lines & pump 13-3/8" Surface Casing Cement Job. Cement in place @ 14:10 hrs on 8/24/23. R/D cement equipment and blow down lines. R/D Tesco CRT equipment. LVT leak from tank, less than one gallon to matting board and less than one cup to gravel pad. N/D diverter pipe. N/D diverter, remove annular, diverter tee, knife valve & riser pipe. N/U Wellhead as per FMC rep. 8/25/2023 8/26/2023 2,598 0.00 10.00 No accidents, incidents. Nipple up BOP stack. Test BOPE to 250 PSI low, 3500 PSI high for 5 minutes each on chart. Had difficulty testing BOP, found leak in 4-1/2" x-over connection. Test witnessed by AOGCC rep Kam St. John. R/D BOPE testing equipment, make up wear ring running tool and set 12 5/8" wear ring. R/U and test 13 3/8" surface casing to 2600 psi for 30 mins on chart. Volume pumped 4.7 bbls, volume bled back 4.2 bbls. M/U & RIH with 12-1/4" Intermediate BHA to 88' MD. Plug in & upload tool. At 17:30 Vac truck released 1 cup of MOBM with 1/4 cup to the gravel pad. 8/26/2023 8/27/2023 2,598 1,221.00 11.50 No accidents, incidents or spills. Continue P/U BHA, PJSM with Baker/rig crew, Load radioactive sources, RIH with 12-1/4" drilling BHA from 88' MD to 2312' MD. M/U Top Drive wash down w/700 GPM, 1015 psi, from 2312' MD to 2504' MD, tag float collar at 2504' MD. Circulate bottoms up. PJSM, Displace 10 ppg spud mud to 11.5 ppg MOBM. Circulate and condition MOBM. Drill plugs/float and cement from 2504' MD to 2564' MD. Drill cmt and shoe + 20' new formation to 2618' MD. RU and perform LOT to 14.7 ppg - successful. Drill 12.25” Intermediate hole from 2618’ MD to 3819’ MD (3091’ TVD). Well Name Wellbore Name PTD # Start Drill Date End Drill Date Page 1 of 3 Well Name NDB-032 Wellbore Name Original Hole PTD # 223-060 Start Drill Date 8/18/2023 End Drill Date 9/7/2023 Run 13-3/8”, 68#, L-80, BTC g pump 13-3/8" Surface Casing Cementg, Job. Cement in place @ 14:10 hrs on 8/24/23. RU and perform LOT to 14.7 ppg - successful. Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 8/27/2023 8/28/2023 3,819 2,188.00 11.50 No accidents, incidents or spills. Drill 12.25" Intermediate hole from 3819' MD to 6007' MD. Limited ROP to 90'/hr when entering the Nanushuk formation @ 4884' MD. Last survey at 5964', Inc 78.86° is 0.48' low and 13.06' right of wellplan. 8/28/2023 8/29/2023 6,007 281.00 11.50 No accidents, incidents or spills. Drill 12.25" Intermediate hole from 6007' MD to section TD @ 6288' MD. Circulate until hole is clean. Backream out of hole from 6288' MD to 5207' MD. Encountered tight spots at 5793' MD and 5767' MD. While Backreaming @ 5207', encountered a packoff and subsequent wellbore beathing event. The well was shut in, the issue diagnosed as wellbore breathing, and the well was opened and normal ops resumed. AOGCC notified. Continue to backream out of hole from 5250' MD to 3070' MD. 8/29/2023 8/30/2023 6,288 0.00 11.50 No accidents, incidents or spills. Backream out of hole from 3070' MD to 10' above surface casing shoe at 2578' MD. Circulate hole clean. Flow check 10 minutes: Static. RIH with 12-1/4" drilling BHA from 2578' MD to 6288' MD on elevators. No tight spots. Wash down last stand and circulate hole clean. 1' of fill. Monitor well 10 minutes. Static. POOH on elevators from 6288' to 2580'. Monitor well 10 minutes. Static. POOH on elevators from 2,580’ MD to 796’ MD. Monitor well 10 minutes. Static. Rack back HWDP, L/D drilling BHA. Change 4.5"x 7" VBRS to 9 5/8" Solid Body Rams. Pull wear bushing and install test plug. R/U and test 9-5/8" annular and upper rams - good test. Pull test plug and install 12-5/8" wear bushing. R/U to run 9-5/8", 47#, L80, Hydril 563 casing. 8/30/2023 8/31/2023 6,288 0.00 11.60 No accidents, incidents or spills. Continue to RIH with 9-5/8" 47# L80 Hydril 563 Production Liner from 2535' MD to 3838' MD. Circulate and condition mud. R/D CRT, bail extensions, elevators and slips. Install DP elevators. P/U Baker Flexlock IV liner hanger/ ZXP LTP. P/U stand of DP and break circulation, obtain parameters. RIH w/9-5/8" 47# L80 Hydril 563 Production Liner on elevators with 5-7/8” DP from 3,876’ md to 6,288’ md. P/U TD-2 cement head, M/U up cement lines. Set liner at 6283' md. Stage up to cementing rate in 1 bpm. increments to final circulating rate of 10 bpm. Cement 9 5/8" liner. 8/31/2023 9/1/2023 6,288 0.00 11.65 No accidents or spills. Cement 9-5/8” 47# L-80 Hydril 563 liner per plan. Set liner hanger, attempt to neutralize the pusher tool but pump shut down at 3850 psi (pump pop-off set to 4500 psi). Attempt to pick up to see if the running tool had released from the string, no-go (same PUW as before job began). Call Baker Engineer, recommendation to on-site Baker rep to conduct the Emergency Release procedure to get released; emergency release procedure went per plan and hanger / packer confirmed set and tool released. Unsting from Liner receptacle, circulate bottoms up at 11 bpm, 72 bbls of contaminated cement returns to surface. LD cement head. Circulate wiper ball surface to surface. POH on elevators from 2292' MD. L/D Baker casing running tool. M/U Polish Mill BHA. RIH on elevators with Polish Mill BHA. Wash and ream from 2293'md to 2426' to polish liner top. Circulate bottoms-up. Monitor well 10 min: static. POOH on elevators from 2,424’ MD to surface, L/D Polish Mill BHA. R/U casing equipment to run 9-5/8" 47# L-80 Hyd 563 Tie Back. PJSM, run 9 5/8” 47# L-80 Hyd 563 intermediate tie back casing to 420’ md. 9/1/2023 9/2/2023 6,288 0.00 11.65 No accidents or spills. 1 First Aid. Run 9-5/8", 47#, L-80, Hydril 563 Tie-Back casing F/420' MD to 2387' MD. Break circulation to 2 BPM, 108 PSI. RIH with assembly slowly, see pressure increase to 200 PSI at 2416' indicating entering into liner top. Bleed pressure. Move down and NO-GO at 2424'. Pick completely out of LTP receptacle and run in again, Tag NO-GO at 2424'. Pickup to previous neutral weight of 108K, calculate space-out requirements, MU hanger pup and hanger. Freeze protect down 9-5/8 X 13-3/8 to liner top packer. Land string and perform No Flow test for 30 minutes. Rig down casing equipment. Set 9 5/8" Pack Off per FMC rep, Test Pack Off. Change rams from 9 5/8" to 4 1/2 x 7" VBR. Conduct full BOPE test. Install 12 3/8" wear bushing. R/U and test 9 5/8"x 13 3/8" annulus and liner top packer. 9/2/2023 9/3/2023 6,288 0.00 10.00 No accidents or spills. Continue to C/O saver sub to 5" Delta 544, test 9 5/8"x 13 3/8" annulus and liner top packer to 2600 PSI for 30 minutes as per Baker rep. Good test, lost 100 psi in 30 min. MU 8-1/2" drilling BHA to 455' MD. RIH with 8.5" drilling BHA to 5,970’ MD. Wash and ream down from 5,970’ md and tag good cement at 6,142’ md. Cut and slip 102' drilling line. Wash and ream down from 6,142’ md to 6,153’ md. Displace 11.6 ppg Versaclean to 10.0 ppg Versaclean. Test 9 5/8" casing to 3500 psi for 30 min on the chart. Good test, lost 110 psi. Choke drill. Drill 9 5/8” plugs, float collar, shoe as per baker from 6203’ MD to 6209’ MD. 9/3/2023 9/4/2023 6,288 879.00 10.00 No accidents, incidents or spills. Drill 9-5/8" Float Collar and Shoe track as per Baker rep from 6209' MD to 6283' MD. Drill 8.5" Production hole from 6283' MD to 6308' MD (4323' TVD). Rig up and perform FIT. Drill 8.5” production hole from 6308’ MD to 7167’ MD. Page 2 of 3 Cement 9-5/8” 47# L-80 Hydril 563 liner per plan Run 9-5/8", 47#, L-80, Hydril 563 Tie-Back casing Achieved 15.0 ppg FIT. -bjm While Backreaming @ 5207', encountered agp g@ , packoff and subsequent wellbore beathing event. The well was shut in, the issue diagnosed aspq g ,g wellbore breathing, and the well was opened and normal ops resumed. AOGCC notified g R/U and test 9-5/8" annular and uppery rams - good test. perform FIT. Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 9/4/2023 9/5/2023 7,167 2,399.00 10.10 No accidents, incidents or spills. Drill 8.5" Production hole from 7167' MD to 9,566’ md (4,259’ tvd). 9/5/2023 9/6/2023 9,566 1,590.00 10.00 No accidents, incidents or spills. Drill 8.5” Production hole from 9,566’ MD to 11,156’ MD (4224' TVD). 9/6/2023 9/7/2023 11,156 1,225.00 10.00 No accidents, incidents or spills. Drill 8.5” Production hole from 11,156’ MD to 12,381’ MD (4197’ TVD). Circulate bottoms-up 3 times rack back one stand per B/U. Monitor well for 10 minutes: static. Backream out of hole with MAD pass from 12,145’ MD to 11,637’ MD. Page 3 of 3 Page 1 of 1 Well Name: NDB-032 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 6,125.5 4,308.2 OH Packer #12 6,959.1 4,313.8 OH Packer #11 7,451.4 4,303.6 OH Packer #10 8,026.4 4,291.6 OH Packer #9 8,517.7 4,281.2 OH Packer #8 9,050.5 4,269.6 OH Packer #7 9,457.9 4,260.1 OH Packer #6 9,902.6 4,250.3 OH Packer #5 10,345.1 4,240.9 OH Packer #4 10,992.6 4,227.1 OH Packer #3 11,396.0 4,218.5 OH Packer #2 11,843.1 4,208.9 OH Packer #1 12,247.9 4,200.1 Page 1 of 1 Well Name: NDB-032 Cement Surface Casing Cement Surface Casing Cement, Casing, 8/24/2023 10:00 Type Casing Cementing Start Date 8/24/2023 Cementing End Date 8/24/2023 Wellbore Original Hole String Surface, 2,588.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Evaluation Results Comment Cement 13-3/8" Surface casing as follows: -Fill lines with 10 bbls H2O and pressure test to 1000/4000 PSI for 5 minutes. -Drop 1st 13.325" Bottom plug. -Pump 112 bbls of 10.5 ppg Tuned Spacer with red dye @ 4-5 bpm, 240 PSI. -Drop 2nd 13.325" Bottom plug. -Pump 506 bbls of 11 ppg ArcticCem Lead Cement @ 5 bpm @ 360 PSI, (yield 2.535 cu.ft/SK) -Observed Tuned Spacer/clabberd mud at shakers with 478 bbls of Lead Cement pumped, switched to Tail Cement on the fly. -Pump total of 69 bbls of 15.3 ppg Tail @ 3-5 BPM @ 410 PSI, (Yield 1.214 cu. ft/SK) -Observed both btm plugs shear at calculated stks. -Drop Top plug and kick out with 2 bbls 15.3 ppg Tail, 5 bbl H2O. Had contaminated mud and spacer at shakers. -Perform displacement with rig pumps and 10 ppg spud mud. -367 bbls displaced at 8-10 bpm: 200 PSI ICP, 440 PSI FCP. -Total displacement volume: 367 bbls (measured by strokes @ 96% pump efficiency). -Reduced rate to 3 BPM for plug bump, bump @ 3047 STK, pressure up to 1000 PSI on bump. -Check Floats-Good. -Estimated cement to surface 163 bbls. -LVT leak from rig mud pit tank, less than one gallon to matting board and less than one cup to gravel pad. -Total losses from cement exit shoe to cement in place: 0 bbls. Cement in place @ 14:10 hrs on 8/24/23. Note: Stage up pumps to 8 bpm, 407 psi at 88 bbls into displacement. Increased rate to 10 bpm, 700 psi. At 147 bbls into displacement, flowline and possum belly plugged up, diverted to cellar. Jetted flowline, slowed rate to 6 bpm – cleared up. At 206 bbls into displacement increased rate back to 8 bpm, 544 psi. Clean cement returns to plug bump. Slowed rate to 3 bpm, 448 psi for last 10 bbls. Plug bumped 1.5 bbls early. Landed plug and pressured up to 1000 psi, held for 5 mins. Bleed off, check floats – floats held. 1, 0.0-2,598.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 2,598.0 Full Return? Yes Vol Cement Ret (bbl) 163.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 8 Final Pump Rate (bbl/min) 8 Avg Pump Rate (bbl/min) 8 Final Pump Pressure (psi) 544.0 Plug Bump Pressure (psi) 544.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description TUNED PRIME CEMENT SPACER SYSTEM Amount (sacks) Class Volume Pumped (bbl) 112.0 Estimated Top (ftKB) Estimated Bottom Depth (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) Lead Fluid Type Lead Fluid Description SBM CEM ARCTICCEM BBL Amount (sacks) 1,054 Class Type I/II Volume Pumped (bbl) 506.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) Density (lb/gal) 11.00 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Tail Fluid Type Tail Fluid Description SBM CEM HALCEM™ SYS Amount (sacks) 322 Class Type I/II Volume Pumped (bbl) 69.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Displacement Fluid Type Displacement Fluid Description SPUD MUD Amount (sacks) Class Volume Pumped (bbl) 10.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Page 1 of 1 Well Name: NDB-032 Cement Intermediate Casing Cement Intermediate Casing Cement, Casing, 8/30/2023 17:27 Type Casing Cementing Start Date 8/30/2023 Cementing End Date 8/30/2023 Wellbore Original Hole String Intermediate, 6,283.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Evaluation Results Comment Cement 9 5/8" liner as follows: -Fill line with H20 and pressure test to 3k psi 5 min. -Pump 93 bbl 11.8 ppg Tuned Spacer @ 4 bpm 350 psi. -Release Bottom Pump Down Plug. -Pump 300 bbl 12 ppg Extendacem lead @ 4.5 bpm. 720 sks, Yld 2.354 cu/ft per sk. -pump 45 bbl 15.3 ppg Versacem type I/II tail @ 2.5 bpm. 218 sks, Yld 1.237 cu/ft per sk -Release Top Pump Down Plug, chase with 2 bbls of cement then 10 bbl of water washup from Halliburton. -Perform displacement with rig pumps. -264 bbl displaced with 11.5 ppg mud at 7 bpm: 690 ICP 3% return flow. FCP 775 psi 3% return flow. Swap to 11.8 ppg Tuned Spacer, 38 bbls at 7 bpm: ICP 490 psi 3% return flow. FCP 490 psi 3% return flow. -Btm pump down dart latch up confirmed at 54 bbl displaced, 819 psi. -Btm liner wiper plug latch up confirmed @ 342 bbl displaced, 570 psi. -Top pump down dart latch up confirmed @ 39 bbl displaced. - Reduce rate to 4 BPM prior to plug bump: Final circulating pressure 550 PSI -Total displacement volume 315 bbls (measured by strokes @ 96% pump efficiency) 3127 stk’s (Calculated 3277 stk’s). -Total losses from cement exit shoe to cement in place: 0 bbls. -CIP: 00:20. - Circulate out cement 11 BPM 880 PSI -Observed 72bbls of cement/OBM contaminated returns, estimated 65% cement 35% OBM, and 211bbls of OBM/Tuned Spacer interface. A total of 283bbls were dumped to the cuttings box. <StageNum>, 2,417.0-6,288.0ftKB Top Depth (ftKB) 2,417.0 Bottom Depth (ftKB) 6,288.0 Full Return? Yes Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 5 Avg Pump Rate (bbl/min) 3 Final Pump Pressure (psi) 570.0 Plug Bump Pressure (psi) 550.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Prime Cement Spacer Amount (sacks) Class Volume Pumped (bbl) 93.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 11.80 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Lead Fluid Type Lead Fluid Description Extendacem Amount (sacks) 720 Class Volume Pumped (bbl) 300.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.35 Mix H20 Ratio (gal/sack) 13.94 Free Water (%) Density (lb/gal) 12.00 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 218 Class Type I/II Volume Pumped (bbl) 45.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Displacement Fluid Type Displacement Fluid Description fresh water Amount (sacks) Class Volume Pumped (bbl) 10.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 11.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) 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 S e p t e m b e r , 2 0 2 3 De s i g n : N D B - 0 3 2 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 -03 2 ND B -03 2 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 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 7. 0 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 3 2 us f t us f t 0. 0 0. 0 5, 9 7 2 , 7 5 1 . 3 2 42 2 , 1 1 5 . 3 5 22 . 8 We l l h e a d E l e v a t i o n : 0. 0 us f t 0. 5 70 ° 2 0 ' 8 . 4 5 2 N 15 0 ° 3 7 ' 5 4 . 7 8 7 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 (nT ) Sa m p l e D a t e D i p A n g l e (° ) ND B - 0 3 2 Mo d e l N a m e Ma g n e t i c s BG G M 2 0 2 3 3 0 / 0 8 / 2 0 2 3 1 4 . 5 6 8 0 . 5 9 5 7 , 1 8 7 . 3 2 0 4 6 4 5 0 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 3 2 1. 0 A C T U A L Ve r t i c a l S e c t i o n : De p t h F r o m (TV D ) (us f t ) +N /- S (us f t ) Di r e c t i o n (° ) +E /- W (us f t ) Ti e O n D e p t h : 47 . 0 32 0 . 6 3 0. 0 0. 0 47 . 0 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 2 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e Fr o m (us 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 (We l l b o r e ) To (us f t )Da t e 14 / 0 9 / 2 0 2 3 SD I _ K P R _ A D K S D I K e e p e r A D K 14 0 . 8 6 4 6 . 8 01 SD I _Gy r o _16 i n H o l e <46 -64 6 > (ND B -03 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 68 6 . 7 2 , 5 2 7 . 1 02 B H O n t r a K _16 i n H o l e <68 6 -25 2 7 > (ND 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 2, 6 2 3 . 1 6 , 2 4 4 . 9 03 B H O n t r a K _12 .25 i n H o l e <26 2 3 -62 4 4 > 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 6, 3 1 7 . 5 1 2 , 3 4 9 . 2 04 B H A z i t r a K _8 . 5 in H o l e <63 1 7 -12 3 4 9 > ( MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 47 . 0 0 . 0 0 0 . 0 0 4 7 . 0 - 2 2 . 8 0 . 0 0 . 0 5 , 9 7 2 , 7 5 1 . 3 2 4 2 2 , 1 1 5 . 3 5 0 . 0 0 0 . 0 12 8 . 0 0 . 0 6 7 0 . 4 1 1 2 8 . 0 5 8 . 2 0 . 0 0 . 0 5 , 9 7 2 , 7 5 1 . 3 3 4 2 2 , 1 1 5 . 3 9 0 . 0 7 0 . 0 20 " C o n d u c t o r 14 0 . 8 0 . 0 7 7 0 . 4 1 1 4 0 . 8 7 1 . 0 0 . 0 0 . 1 5 , 9 7 2 , 7 5 1 . 3 4 4 2 2 , 1 1 5 . 4 0 0 . 0 7 0 . 0 17 5 . 8 0 . 0 6 6 6 . 6 2 1 7 5 . 8 1 0 6 . 0 0 . 0 0 . 1 5 , 9 7 2 , 7 5 1 . 3 5 4 2 2 , 1 1 5 . 4 4 0 . 0 3 0 . 0 26 7 . 8 0 . 0 8 1 9 . 0 9 2 6 7 . 8 1 9 8 . 0 0 . 1 0 . 2 5 , 9 7 2 , 7 5 1 . 4 3 4 2 2 , 1 1 5 . 5 1 0 . 0 6 0 . 0 36 1 . 8 0 . 2 6 2 8 . 9 1 3 6 1 . 8 2 9 2 . 0 0 . 4 0 . 3 5 , 9 7 2 , 7 5 1 . 6 8 4 2 2 , 1 1 5 . 6 3 0 . 1 9 0 . 1 45 6 . 8 0 . 5 6 3 4 . 9 1 4 5 6 . 8 3 8 7 . 0 0 . 9 0 . 7 5 , 9 7 2 , 7 5 2 . 2 4 4 2 2 , 1 1 6 . 0 1 0 . 3 2 0 . 3 55 0 . 8 1 . 3 5 1 4 . 3 2 5 5 0 . 8 4 8 1 . 0 2 . 4 1 . 2 5 , 9 7 2 , 7 5 3 . 6 9 4 2 2 , 1 1 6 . 5 6 0 . 9 0 1 . 1 64 6 . 8 3 . 1 0 3 5 5 . 9 5 6 4 6 . 7 5 7 6 . 9 6 . 1 1 . 3 5 , 9 7 2 , 7 5 7 . 3 7 4 2 2 , 1 1 6 . 7 0 1 . 9 5 3 . 9 68 6 . 7 3 . 3 7 3 5 1 . 1 1 6 8 6 . 6 6 1 6 . 8 8 . 3 1 . 0 5 , 9 7 2 , 7 5 9 . 6 1 4 2 2 , 1 1 6 . 4 6 0 . 9 6 5 . 8 75 7 . 9 4 . 0 4 3 4 6 . 9 7 7 5 7 . 6 6 8 7 . 8 1 2 . 8 0 . 1 5 , 9 7 2 , 7 6 4 . 1 3 4 2 2 , 1 1 5 . 6 2 1 . 0 1 9 . 8 85 3 . 4 7 . 5 9 3 4 4 . 5 2 8 5 2 . 6 7 8 2 . 8 2 2 . 2 - 2 . 3 5 , 9 7 2 , 7 7 3 . 5 1 4 2 2 , 1 1 3 . 2 8 3 . 7 2 1 8 . 6 95 0 . 3 9 . 4 1 3 4 2 . 7 8 9 4 8 . 4 8 7 8 . 6 3 5 . 9 - 6 . 4 5 , 9 7 2 , 7 8 7 . 2 8 4 2 2 , 1 0 9 . 3 7 1 . 9 0 3 1 . 8 1, 0 3 9 . 0 1 0 . 0 6 3 4 2 . 5 2 1 , 0 3 5 . 8 9 6 6 . 0 5 0 . 2 - 1 0 . 8 5 , 9 7 2 , 8 0 1 . 6 4 4 2 2 , 1 0 5 . 0 4 0 . 7 3 4 5 . 7 Up p e r S c h r a d e r B l u f f 1, 0 4 3 . 1 1 0 . 0 9 3 4 2 . 5 1 1 , 0 3 9 . 9 9 7 0 . 1 5 0 . 9 - 1 1 . 0 5 , 9 7 2 , 8 0 2 . 3 3 4 2 2 , 1 0 4 . 8 3 0 . 7 3 4 6 . 4 1, 1 3 0 . 0 1 0 . 5 1 3 4 0 . 0 7 1 , 1 2 5 . 4 1 , 0 5 5 . 6 6 5 . 6 - 1 6 . 0 5 , 9 7 2 , 8 1 7 . 0 9 4 2 2 , 1 0 0 . 0 0 0 . 7 0 6 0 . 9 Ba s e I c e B e a r i n g P e r m a f r o s t 1, 1 3 7 . 5 1 0 . 5 5 3 3 9 . 8 7 1 , 1 3 2 . 7 1 , 0 6 2 . 9 6 6 . 9 - 1 6 . 5 5 , 9 7 2 , 8 1 8 . 3 8 4 2 2 , 0 9 9 . 5 4 0 . 7 0 6 2 . 2 1, 2 3 1 . 3 1 1 . 9 4 3 2 6 . 2 6 1 , 2 2 4 . 7 1 , 1 5 4 . 9 8 3 . 0 - 2 4 . 9 5 , 9 7 2 , 8 3 4 . 6 0 4 2 2 , 0 9 1 . 3 6 3 . 1 8 8 0 . 0 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 3 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 1, 3 2 5 . 1 1 4 . 4 3 3 0 9 . 5 2 1 , 3 1 6 . 2 1, 2 4 6 . 4 98 . 6 - 3 9 . 3 5 , 9 7 2 , 8 5 0 . 2 7 4 2 2 , 0 7 7 . 1 1 4 . 8 3 1 0 1 . 1 1, 3 5 9 . 5 1 6 . 2 1 3 0 6 . 5 7 1 , 3 4 9 . 3 1 , 2 7 9 . 5 1 0 4 . 1 - 4 6 . 4 5 , 9 7 2 , 8 5 5 . 9 2 4 2 2 , 0 7 0 . 0 2 5 . 6 6 1 0 9 . 9 1, 3 8 9 . 4 1 7 . 8 7 3 0 4 . 6 0 1 , 3 7 7 . 8 1 , 3 0 8 . 0 1 0 9 . 2 - 5 3 . 5 5 , 9 7 2 , 8 6 1 . 0 9 4 2 2 , 0 6 2 . 9 4 5 . 8 8 1 1 8 . 4 1, 4 1 2 . 0 1 9 . 2 3 3 0 3 . 9 2 1 , 3 9 9 . 3 1 , 3 2 9 . 5 1 1 3 . 3 - 5 9 . 5 5 , 9 7 2 , 8 6 5 . 2 0 4 2 2 , 0 5 7 . 0 3 6 . 1 0 1 2 5 . 3 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 2 0 . 2 1 9 . 7 3 3 0 3 . 7 0 1 , 4 0 7 . 1 1 , 3 3 7 . 3 1 1 4 . 8 - 6 1 . 8 5 , 9 7 2 , 8 6 6 . 7 5 4 2 2 , 0 5 4 . 7 7 6 . 1 0 1 2 7 . 9 1, 4 5 4 . 3 2 1 . 9 9 3 0 1 . 2 8 1 , 4 3 8 . 9 1 , 3 6 9 . 1 1 2 1 . 3 - 7 2 . 0 5 , 9 7 2 , 8 7 3 . 3 6 4 2 2 , 0 4 4 . 6 0 7 . 1 0 1 3 9 . 5 1, 4 8 4 . 3 2 3 . 0 8 2 9 9 . 4 2 1 , 4 6 6 . 6 1 , 3 9 6 . 8 1 2 7 . 1 - 8 1 . 9 5 , 9 7 2 , 8 7 9 . 2 6 4 2 2 , 0 3 4 . 7 5 4 . 3 5 1 5 0 . 2 1, 5 1 6 . 1 2 4 . 2 4 29 7 . 9 4 1, 4 9 5 . 7 1 , 4 2 5 . 9 1 3 3 . 2 - 9 3 . 1 5 , 9 7 2 , 8 8 5 . 5 0 4 2 2 , 0 2 3 . 6 2 4 . 1 0 1 6 2 . 1 1, 6 0 9 . 4 2 7 . 8 8 2 9 4 . 7 0 1 , 5 7 9 . 5 1 , 5 0 9 . 7 1 5 1 . 3 - 1 2 9 . 9 5 , 9 7 2 , 9 0 3 . 9 8 4 2 1 , 9 8 7 . 0 5 4 . 1 9 1 9 9 . 4 1, 7 0 4 . 1 3 2 . 4 8 2 9 5 . 0 5 1 , 6 6 1 . 4 1 , 5 9 1 . 6 1 7 1 . 4 - 1 7 3 . 1 5 , 9 7 2 , 9 2 4 . 4 6 4 2 1 , 9 4 4 . 0 6 4 . 8 6 2 4 2 . 3 1, 8 0 0 . 5 3 6 . 6 0 2 9 7 . 7 0 1 , 7 4 0 . 8 1 , 6 7 1 . 0 1 9 5 . 7 - 2 2 2 . 0 5 , 9 7 2 , 9 4 9 . 2 8 4 2 1 , 8 9 5 . 4 4 4 . 5 5 2 9 2 . 1 1, 8 2 2 . 0 3 7 . 5 3 2 9 8 . 2 2 1 , 7 5 7 . 9 1 , 6 8 8 . 1 2 0 1 . 8 - 2 3 3 . 4 5 , 9 7 2 , 9 5 5 . 4 8 4 2 1 , 8 8 4 . 0 5 4 . 5 6 3 0 4 . 1 Mi d d l e S c h r a d e r B l u f f 1, 8 9 5 . 9 4 0 . 7 4 2 9 9 . 8 7 1 , 8 1 5 . 3 1 , 7 4 5 . 5 2 2 4 . 4 - 2 7 4 . 2 5 , 9 7 2 , 9 7 8 . 5 7 4 2 1 , 8 4 3 . 5 3 4 . 5 6 3 4 7 . 4 1, 9 9 0 . 7 4 4 . 3 5 3 0 1 . 1 3 1 , 8 8 5 . 1 1 , 8 1 5 . 3 2 5 7 . 0 - 3 2 9 . 4 5 , 9 7 3 , 0 1 1 . 6 9 4 2 1 , 7 8 8 . 6 5 3 . 9 1 4 0 7 . 6 2, 0 8 5 . 2 4 8 . 3 6 3 0 1 . 2 2 1 , 9 5 0 . 3 1 , 8 8 0 . 5 2 9 2 . 4 - 3 8 7 . 9 5 , 9 7 3 , 0 4 7 . 6 6 4 2 1 , 7 3 0 . 5 7 4 . 2 5 4 7 2 . 1 2, 1 7 9 . 4 4 9 . 1 2 3 0 2 . 1 2 2 , 0 1 2 . 4 1 , 9 4 2 . 6 3 2 9 . 5 - 4 4 8 . 1 5 , 9 7 3 , 0 8 5 . 4 6 4 2 1 , 6 7 0 . 7 1 1 . 0 8 5 3 9 . 0 2, 2 7 4 . 6 5 0 . 2 4 3 0 1 . 3 3 2 , 0 7 4 . 0 2 , 0 0 4 . 2 3 6 7 . 7 - 5 0 9 . 9 5 , 9 7 3 , 1 2 4 . 2 8 4 2 1 , 6 0 9 . 3 5 1 . 3 4 6 0 7 . 7 2, 3 6 9 . 2 5 0 . 5 8 3 0 0 . 5 9 2 , 1 3 4 . 3 2 , 0 6 4 . 5 4 0 5 . 2 -5 7 2 . 4 5, 9 7 3 , 1 6 2 . 4 4 4 2 1 , 5 4 7 . 2 1 0 . 7 0 6 7 6 . 4 2, 3 9 0 . 0 5 0 . 5 6 3 0 0 . 5 0 2 , 1 4 7 . 5 2 , 0 7 7 . 7 4 1 3 . 4 - 5 8 6 . 2 5 , 9 7 3 , 1 7 0 . 7 2 4 2 1 , 5 3 3 . 4 9 0 . 3 5 6 9 1 . 4 MC U 2, 4 6 3 . 9 5 0 . 4 8 3 0 0 . 1 8 2 , 1 9 4 . 5 2 , 1 2 4 . 7 4 4 2 . 2 - 6 3 5 . 5 5 , 9 7 3 , 2 0 0 . 0 4 4 2 1 , 4 8 4 . 5 7 0 . 3 5 7 4 4 . 9 2, 5 2 7 . 1 5 0 . 3 1 3 0 0 . 1 8 2 , 2 3 4 . 8 2 , 1 6 5 . 0 4 6 6 . 7 - 6 7 7 . 6 5 , 9 7 3 , 2 2 4 . 9 8 4 2 1 , 4 4 2 . 7 0 0 . 2 7 7 9 0 . 6 2, 5 8 8 . 0 5 0 . 0 4 3 0 0 . 6 4 2 , 2 7 3 . 8 2 , 2 0 4 . 0 4 9 0 . 3 - 7 1 7 . 9 5 , 9 7 3 , 2 4 9 . 0 5 4 2 1 , 4 0 2 . 6 5 0 . 7 3 8 3 4 . 5 13 - 3 / 8 " S u r f a c e C a s i n g 2, 6 2 3 . 1 4 9 . 8 9 3 0 0 . 9 1 2 , 2 9 6 . 4 2 , 2 2 6 . 6 5 0 4 . 1 - 7 4 1 . 0 5 , 9 7 3 , 2 6 3 . 0 5 4 2 1 , 3 7 9 . 6 9 0 . 7 3 8 5 9 . 8 2, 6 4 8 . 9 5 0 . 2 8 3 0 0 . 7 4 2 , 3 1 2 . 9 2 , 2 4 3 . 1 5 1 4 . 2 - 7 5 8 . 0 5 , 9 7 3 , 2 7 3 . 3 6 4 2 1 , 3 6 2 . 8 1 1 . 5 9 8 7 8 . 4 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 4 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 2, 7 4 3 . 2 5 0 . 3 1 3 0 0 . 5 9 2 , 3 7 3 . 2 2, 3 0 3 . 4 55 1 . 3 - 8 2 0 . 4 5 , 9 7 3 , 3 1 1 . 0 1 4 2 1 , 3 0 0 . 7 8 0 . 1 3 9 4 6 . 6 2, 8 3 8 . 2 5 0 . 3 7 2 9 9 . 9 5 2 , 4 3 3 . 8 2 , 3 6 4 . 0 5 8 8 . 1 - 8 8 3 . 6 5 , 9 7 3 , 3 4 8 . 5 2 4 2 1 , 2 3 8 . 0 3 0 . 5 2 1 , 0 1 5 . 1 2, 8 6 7 . 0 5 0 . 3 3 2 9 9 . 7 0 2 , 4 5 2 . 2 2, 3 8 2 . 4 59 9 . 1 - 9 0 2 . 8 5 , 9 7 3 , 3 5 9 . 7 4 4 2 1 , 2 1 8 . 9 2 0 . 6 9 1 , 0 3 5 . 8 Tu l u v a k S h a l e 2, 9 3 2 . 8 5 0 . 2 4 2 9 9 . 1 2 2 , 4 9 4 . 2 2, 4 2 4 . 4 62 4 . 0 - 9 4 6 . 9 5 , 9 7 3 , 3 8 5 . 0 6 4 2 1 , 1 7 5 . 0 7 0 . 6 9 1 , 0 8 3 . 1 2, 9 3 4 . 0 5 0 . 2 3 2 9 9 . 1 1 2 , 4 9 5 . 0 2 , 4 2 5 . 2 6 2 4 . 4 - 9 4 7 . 7 5 , 9 7 3 , 3 8 5 . 5 0 4 2 1 , 1 7 4 . 2 9 1 . 1 0 1 , 0 8 3 . 9 Tu l u v a k S a n d 3, 0 2 6 . 9 4 9 . 3 8 2 9 8 . 3 6 2 , 5 5 5 . 0 2 , 4 8 5 . 2 6 5 8 . 6 - 1 , 0 0 9 . 9 5 , 9 7 3 , 4 2 0 . 2 7 4 2 1 , 1 1 2 . 4 3 1 . 1 0 1 , 1 4 9 . 7 3, 1 2 1 . 0 4 9 . 2 0 29 8 . 9 4 2, 6 1 6 . 3 2 , 5 4 6 . 5 6 9 2 . 7 - 1 , 0 7 2 . 5 5 , 9 7 3 , 4 5 5 . 0 9 4 2 1 , 0 5 0 . 2 3 0 . 5 1 1 , 2 1 5 . 9 3, 2 1 7 . 3 4 8 . 2 5 2 9 8 . 2 6 2 , 6 7 9 . 9 2 , 6 1 0 . 1 7 2 7 . 4 - 1 , 1 3 6 . 0 5 , 9 7 3 , 4 9 0 . 4 1 4 2 0 , 9 8 7 . 0 3 1 . 1 2 1 , 2 8 3 . 0 3, 3 1 1 . 7 4 7 . 2 8 2 9 7 . 9 3 2 , 7 4 3 . 3 2 , 6 7 3 . 5 7 6 0 . 3 - 1 , 1 9 7 . 7 5 , 9 7 3 , 5 2 3 . 9 7 4 2 0 , 9 2 5 . 7 0 1 . 0 6 1 , 3 4 7 . 6 3, 4 0 6 . 7 4 6 . 6 6 2 9 8 . 3 8 2 , 8 0 8 . 1 2 , 7 3 8 . 3 7 9 3 . 1 - 1 , 2 5 8 . 9 5 , 9 7 3 , 5 5 7 . 3 5 4 2 0 , 8 6 4 . 8 6 0 . 7 4 1 , 4 1 1 . 7 3, 5 0 1 . 2 4 6 . 7 1 2 9 9 . 6 9 2 , 8 7 3 . 0 2 , 8 0 3 . 2 8 2 6 . 5 - 1 , 3 1 9 . 0 5 , 9 7 3 , 5 9 1 . 3 5 4 2 0 , 8 0 5 . 0 8 1 . 0 1 1 , 4 7 5 . 6 3, 5 9 6 . 5 4 6 . 7 1 2 9 9 . 8 9 2 , 9 3 8 . 3 2 , 8 6 8 . 5 8 6 0 . 9 - 1 , 3 7 9 . 3 5 , 9 7 3 , 6 2 6 . 4 4 4 2 0 , 7 4 5 . 2 4 0 . 1 5 1 , 5 4 0 . 5 3, 6 9 1 . 4 46 . 7 8 3 0 0 . 2 2 3 , 0 0 3 . 3 2 , 9 3 3 . 5 8 9 5 . 5 - 1 , 4 3 9 . 1 5 , 9 7 3 , 6 6 1 . 6 6 4 2 0 , 6 8 5 . 7 9 0 . 2 6 1 , 6 0 5 . 2 3, 7 8 5 . 0 4 6 . 7 1 3 0 0 . 7 6 3 , 0 6 7 . 5 2 , 9 9 7 . 7 9 3 0 . 1 - 1 , 4 9 7 . 8 5 , 9 7 3 , 6 9 6 . 8 5 4 2 0 , 6 2 7 . 4 3 0 . 4 3 1 , 6 6 9 . 2 3, 8 8 0 . 0 4 5 . 9 8 3 0 0 . 8 6 3 , 1 3 3 . 0 3 , 0 6 3 . 2 9 6 5 . 3 - 1 , 5 5 6 . 8 5 , 9 7 3 , 7 3 2 . 6 5 4 2 0 , 5 6 8 . 7 8 0 . 7 7 1 , 7 3 3 . 8 3, 9 4 0 . 0 4 5 . 9 5 3 0 0 . 7 1 3 , 1 7 4 . 8 3 , 1 0 5 . 0 9 8 7 . 4 - 1 , 5 9 3 . 9 5 , 9 7 3 , 7 5 5 . 1 2 4 2 0 , 5 3 1 . 9 4 0 . 1 9 1 , 7 7 4 . 4 Se a b e e 3, 9 7 4 . 4 45 . 9 4 3 0 0 . 6 2 3 , 1 9 8 . 7 3 , 1 2 8 . 9 1 , 0 0 0 . 0 - 1 , 6 1 5 . 1 5 , 9 7 3 , 7 6 7 . 9 5 4 2 0 , 5 1 0 . 8 2 0 . 1 9 1 , 7 9 7 . 6 4, 0 6 9 . 5 4 5 . 9 9 3 0 0 . 5 2 3 , 2 6 4 . 8 3 , 1 9 5 . 0 1 , 0 3 4 . 8 - 1 , 6 7 4 . 0 5 , 9 7 3 , 8 0 3 . 3 3 4 2 0 , 4 5 2 . 3 1 0 . 0 9 1 , 8 6 1 . 9 4, 1 6 4 . 5 4 5 . 9 6 3 0 0 . 4 0 3 , 3 3 0 . 8 3 , 2 6 1 . 0 1 , 0 6 9 . 4 - 1 , 7 3 2 . 9 5 , 9 7 3 , 8 3 8 . 5 8 4 2 0 , 3 9 3 . 7 8 0 . 1 0 1 , 9 2 6 . 0 4, 2 5 9 . 3 4 5 . 9 6 2 9 9 . 1 7 3 , 3 9 6 . 7 3 , 3 2 6 . 9 1 , 1 0 3 . 2 - 1 , 7 9 2 . 0 5 , 9 7 3 , 8 7 3 . 0 1 4 2 0 , 3 3 5 . 0 4 0 . 9 3 1 , 9 8 9 . 7 4, 3 5 4 . 0 4 5 . 9 4 2 9 9 . 1 2 3 , 4 6 2 . 5 3 , 3 9 2 . 7 1 , 1 3 6 . 4 - 1 , 8 5 1 . 5 5 , 9 7 3 , 9 0 6 . 7 8 4 2 0 , 2 7 5 . 9 4 0 . 0 4 2 , 0 5 3 . 0 4, 4 5 0 . 0 4 6 . 1 3 2 9 9 . 5 9 3 , 5 2 9 . 2 3 , 4 5 9 . 4 1 , 1 7 0 . 3 - 1 , 9 1 1 . 7 5 , 9 7 3 , 9 4 1 . 2 7 4 2 0 , 2 1 6 . 0 7 0 . 4 0 2 , 1 1 7 . 4 4, 5 4 4 . 2 4 6 . 1 9 2 9 9 . 9 6 3 , 5 9 4 . 4 3 , 5 2 4 . 6 1 , 2 0 4 . 0 - 1 , 9 7 0 . 7 5 , 9 7 3 , 9 7 5 . 6 1 4 2 0 , 1 5 7 . 4 7 0 . 2 9 2 , 1 8 0 . 9 4, 6 3 8 . 5 4 6 . 2 1 3 0 0 . 5 6 3 , 6 5 9 . 7 3 , 5 8 9 . 9 1 , 2 3 8 . 3 - 2 , 0 2 9 . 5 5 , 9 7 4 , 0 1 0 . 5 4 4 2 0 , 0 9 9 . 0 2 0 . 4 6 2 , 2 4 4 . 7 4, 7 3 3 . 8 4 7 . 3 7 3 0 3 . 6 5 3 , 7 2 4 . 9 3 , 6 5 5 . 1 1 , 2 7 5 . 2 - 2 , 0 8 8 . 3 5 , 9 7 4 , 0 4 8 . 0 4 4 2 0 , 0 4 0 . 6 3 2 . 6 6 2 , 3 1 0 . 5 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 5 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 4, 8 2 8 . 7 4 9 . 5 8 3 0 5 . 4 0 3 , 7 8 7 . 9 3 , 7 1 8 . 1 1 , 3 1 5 . 5 - 2 , 1 4 6 . 8 5 , 9 7 4 , 0 8 8 . 9 3 4 1 9 , 9 8 2 . 5 2 2 . 7 1 2 , 3 7 8 . 8 4, 9 2 2 . 7 5 2 . 1 1 3 0 6 . 7 8 3 , 8 4 7 . 3 3 , 7 7 7 . 5 1 , 3 5 8 . 5 - 2 , 2 0 5 . 7 5 , 9 7 4 , 1 3 2 . 5 1 4 1 9 , 9 2 4 . 0 5 2 . 9 2 2 , 4 4 9 . 4 4, 9 5 2 . 0 5 2 . 8 0 3 0 6 . 9 9 3 , 8 6 5 . 1 3 , 7 9 5 . 3 1 , 3 7 2 . 4 - 2 , 2 2 4 . 3 5 , 9 7 4 , 1 4 6 . 6 2 4 1 9 , 9 0 5 . 6 5 2 . 4 4 2 , 4 7 1 . 9 Na n u s h u k 4, 9 7 4 . 0 5 3 . 3 3 30 7 . 1 4 3, 8 7 8 . 3 3 , 8 0 8 . 5 1 , 3 8 3 . 0 - 2 , 2 3 8 . 3 5 , 9 7 4 , 1 5 7 . 3 7 4 1 9 , 8 9 1 . 7 3 2 . 4 4 2 , 4 8 9 . 0 NT 8 M F S 5, 0 1 7 . 9 5 4 . 3 7 3 0 7 . 4 4 3 , 9 0 4 . 2 3 , 8 3 4 . 4 1 , 4 0 4 . 5 - 2 , 2 6 6 . 5 5 , 9 7 4 , 1 7 9 . 1 3 4 1 9 , 8 6 3 . 7 6 2 . 4 4 2 , 5 2 3 . 5 5, 0 2 1 . 0 5 4 . 4 4 3 0 7 . 4 8 3 , 9 0 6 . 0 3 , 8 3 6 . 2 1 , 4 0 6 . 0 - 2 , 2 6 8 . 5 5 , 9 7 4 , 1 8 0 . 6 9 4 1 9 , 8 6 1 . 7 7 2 . 5 4 2 , 5 2 6 . 0 NT 7 M F S 5, 1 1 1 . 9 5 6 . 5 3 3 0 8 . 6 8 3 , 9 5 7 . 5 3 , 8 8 7 . 7 1 , 4 5 2 . 2 - 2 , 3 2 7 . 4 5 , 9 7 4 , 2 2 7 . 4 8 4 1 9 , 8 0 3 . 3 3 2 . 5 4 2 , 5 9 9 . 1 5, 1 4 0 . 0 5 7 . 1 2 3 0 9 . 1 8 3 , 9 7 2 . 9 3 , 9 0 3 . 1 1 , 4 6 7 . 0 - 2 , 3 4 5 . 8 5 , 9 7 4 , 2 4 2 . 4 6 4 1 9 , 7 8 5 . 1 7 2 . 5 7 2 , 6 2 2 . 1 NT 6 M F S 5, 2 0 7 . 2 5 8 . 5 4 3 1 0 . 3 5 4 , 0 0 8 . 7 3 , 9 3 8 . 9 1 , 5 0 3 . 4 - 2 , 3 8 9 . 5 5 , 9 7 4 , 2 7 9 . 3 0 4 1 9 , 7 4 1 . 8 3 2 . 5 7 2 , 6 7 8 . 0 5, 2 4 9 . 0 5 9 . 6 0 3 1 0 . 9 5 4 , 0 3 0 . 2 3, 9 6 0 . 4 1, 5 2 6 . 7 - 2 , 4 1 6 . 7 5 , 9 7 4 , 3 0 2 . 9 3 4 1 9 , 7 1 4 . 8 8 2 . 8 2 2 , 7 1 3 . 3 NT 5 M F S 5, 3 0 2 . 2 6 0 . 9 5 3 1 1 . 7 0 4 , 0 5 6 . 5 3 , 9 8 6 . 7 1 , 5 5 7 . 3 - 2 , 4 5 1 . 4 5 , 9 7 4 , 3 3 3 . 8 1 4 1 9 , 6 8 0 . 4 9 2 . 8 2 2 , 7 5 8 . 9 5, 3 9 0 . 0 6 3 . 5 3 3 1 3 . 9 7 4 , 0 9 7 . 4 4 , 0 2 7 . 6 1 , 6 1 0 . 1 - 2 , 5 0 8 . 3 5 , 9 7 4 , 3 8 7 . 2 1 4 1 9 , 6 2 4 . 1 2 3 . 7 3 2 , 8 3 5 . 9 NT 4 M F S 5, 3 9 6 . 3 6 3 . 7 2 3 1 4 . 1 3 4 , 1 0 0 . 2 4, 0 3 0 . 4 1, 6 1 4 . 0 - 2 , 5 1 2 . 4 5 , 9 7 4 , 3 9 1 . 1 5 4 1 9 , 6 2 0 . 1 3 3 . 7 3 2 , 8 4 1 . 4 5, 4 9 1 . 3 6 6 . 1 0 3 1 6 . 2 8 4 , 1 4 0 . 5 4 , 0 7 0 . 7 1 , 6 7 5 . 1 - 2 , 5 7 3 . 0 5 , 9 7 4 , 4 5 2 . 8 7 4 1 9 , 5 6 0 . 1 3 3 . 2 3 2 , 9 2 7 . 1 5, 5 8 5 . 6 6 8 . 6 5 3 1 8 . 0 3 4 , 1 7 6 . 8 4 , 1 0 7 . 0 1 , 7 3 8 . 9 - 2 , 6 3 2 . 2 5 , 9 7 4 , 5 1 7 . 3 0 4 1 9 , 5 0 1 . 6 2 3 . 2 0 3 , 0 1 4 . 0 5, 6 8 0 . 2 7 1 . 1 7 3 1 9 . 4 4 4 , 2 0 9 . 3 4 , 1 3 9 . 5 1 , 8 0 5 . 7 - 2 , 6 9 0 . 8 5 , 9 7 4 , 5 8 4 . 6 9 4 1 9 , 4 4 3 . 7 3 3 . 0 1 3 , 1 0 2 . 8 5, 7 7 5 . 6 7 3 . 8 3 3 2 0 . 5 1 4 , 2 3 8 . 0 4 , 1 6 8 . 2 1 , 8 7 5 . 3 - 2 , 7 4 9 . 2 5 , 9 7 4 , 6 5 4 . 9 0 4 1 9 , 3 8 6 . 0 0 2 . 9 9 3 , 1 9 3 . 7 5, 8 7 0 . 4 7 6 . 2 4 3 2 1 . 2 2 4 , 2 6 2 . 5 4 , 1 9 2 . 7 1 , 9 4 6 . 4 - 2 , 8 0 7 . 1 5 , 9 7 4 , 7 2 6 . 5 8 4 1 9 , 3 2 8 . 9 1 2 . 6 4 3 , 2 8 5 . 3 5, 9 6 4 . 1 7 8 . 7 6 3 2 2 . 2 1 4 , 2 8 2 . 7 4 , 2 1 2 . 9 2 , 0 1 8 . 2 - 2 , 8 6 3 . 7 5 , 9 7 4 , 7 9 8 . 9 6 4 1 9 , 2 7 2 . 9 9 2 . 8 8 3 , 3 7 6 . 8 6, 0 5 8 . 7 8 1 . 2 6 3 2 2 . 8 0 4 , 2 9 9 . 1 4 , 2 2 9 . 3 2 , 0 9 2 . 1 - 2 , 9 2 0 . 4 5 , 9 7 4 , 8 7 3 . 4 0 4 1 9 , 2 1 7 . 1 0 2 . 7 1 3 , 4 6 9 . 9 6, 1 4 0 . 0 8 3 . 5 1 3 2 4 . 2 2 4 , 3 0 9 . 9 4 , 2 4 0 . 1 2 , 1 5 6 . 9 - 2 , 9 6 8 . 3 5 , 9 7 4 , 9 3 8 . 6 8 4 1 9 , 1 6 9 . 8 6 3 . 2 6 3 , 5 5 0 . 3 NT 3 M F S 6, 1 5 2 . 9 8 3 . 8 7 3 2 4 . 4 4 4 , 3 1 1 . 3 4 , 2 4 1 . 5 2 , 1 6 7 . 3 - 2 , 9 7 5 . 8 5 , 9 7 4 , 9 4 9 . 2 0 4 1 9 , 1 6 2 . 4 7 3 . 2 6 3 , 5 6 3 . 2 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 6 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 6, 2 4 4 . 9 8 6 . 1 1 3 2 6 . 1 1 4 , 3 1 9 . 4 4 , 2 4 9 . 6 2 , 2 4 2 . 6 - 3 , 0 2 8 . 0 5 , 9 7 5 , 0 2 5 . 0 2 4 1 9 , 1 1 1 . 0 8 3 . 0 3 3 , 6 5 4 . 5 6, 2 8 3 . 0 8 6 . 8 3 3 2 6 . 6 3 4 , 3 2 1 . 7 4 , 2 5 1 . 9 2 , 2 7 4 . 2 - 3 , 0 4 9 . 1 5 , 9 7 5 , 0 5 6 . 9 0 4 1 9 , 0 9 0 . 3 5 2 . 3 4 3 , 6 9 2 . 3 9- 5 / 8 " I n t e r m e d i a t e C a s i n g 6, 3 1 7 . 5 8 7 . 4 9 3 2 7 . 1 0 4 , 3 2 3 . 4 4 , 2 5 3 . 6 2 , 3 0 3 . 1 - 3 , 0 6 7 . 9 5 , 9 7 5 , 0 8 5 . 9 4 4 1 9 , 0 7 1 . 8 2 2 . 3 4 3 , 7 2 6 . 6 6, 4 1 2 . 9 8 9 . 9 2 3 2 8 . 2 5 4 , 3 2 5 . 6 4 , 2 5 5 . 8 2 , 3 8 3 . 7 - 3 , 1 1 8 . 9 5 , 9 7 5 , 1 6 7 . 0 3 4 1 9 , 0 2 1 . 6 8 2 . 8 2 3 , 8 2 1 . 2 6, 4 6 8 . 0 9 0 . 7 7 3 2 8 . 6 6 4 , 3 2 5 . 2 4 , 2 5 5 . 4 2 , 4 3 0 . 6 - 3 , 1 4 7 . 7 5 , 9 7 5 , 2 1 4 . 3 0 4 1 8 , 9 9 3 . 3 4 1 . 7 2 3 , 8 7 5 . 8 NT 3 . 2 T o p R e s e r v o i r 6, 5 0 7 . 9 9 1 . 3 9 3 2 8 . 9 6 4 , 3 2 4 . 5 4 , 2 5 4 . 7 2 , 4 6 4 . 8 - 3 , 1 6 8 . 4 5 , 9 7 5 , 2 4 8 . 6 2 4 1 8 , 9 7 3 . 0 5 1 . 7 2 3 , 9 1 5 . 3 6, 6 0 3 . 1 9 1 . 4 2 3 2 8 . 9 2 4 , 3 2 2 . 1 4 , 2 5 2 . 3 2 , 5 4 6 . 3 - 3 , 2 1 7 . 5 5 , 9 7 5 , 3 3 0 . 6 9 4 1 8 , 9 2 4 . 7 7 0 . 0 5 4 , 0 0 9 . 5 6, 6 9 7 . 9 9 1 . 4 5 3 2 8 . 4 2 4 , 3 1 9 . 8 4 , 2 5 0 . 0 2 , 6 2 7 . 3 - 3 , 2 6 6 . 8 5 , 9 7 5 , 4 1 2 . 1 4 4 1 8 , 8 7 6 . 3 4 0 . 5 3 4 , 1 0 3 . 3 6, 7 9 3 . 2 9 1 . 2 7 3 2 8 . 4 0 4 , 3 1 7 . 5 4 , 2 4 7 . 7 2 , 7 0 8 . 4 - 3 , 3 1 6 . 7 5 , 9 7 5 , 4 9 3 . 7 5 4 1 8 , 8 2 7 . 3 1 0 . 1 9 4 , 1 9 7 . 7 6, 8 8 8 . 5 9 1 . 3 0 3 2 8 . 0 4 4 , 3 1 5 . 4 4 , 2 4 5 . 6 2 , 7 8 9 . 4 - 3 , 3 6 6 . 9 5 , 9 7 5 , 5 7 5 . 3 1 4 1 8 , 7 7 7 . 9 4 0 . 3 8 4 , 2 9 2 . 2 6, 9 8 3 . 2 9 1 . 1 8 3 2 8 . 0 9 4 , 3 1 3 . 3 4 , 2 4 3 . 5 2 , 8 6 9 . 8 - 3 , 4 1 6 . 9 5 , 9 7 5 , 6 5 6 . 1 5 4 1 8 , 7 2 8 . 7 2 0 . 1 4 4 , 3 8 6 . 0 7, 0 7 9 . 1 9 1 . 2 4 3 2 8 . 5 2 4 , 3 1 1 . 3 4 , 2 4 1 . 5 2 , 9 5 1 . 3 - 3 , 4 6 7 . 3 5 , 9 7 5 , 7 3 8 . 2 3 4 1 8 , 6 7 9 . 2 0 0 . 4 5 4 , 4 8 1 . 0 7, 1 7 4 . 0 9 1 . 1 5 3 2 9 . 1 6 4 , 3 0 9 . 3 4 , 2 3 9 . 5 3 , 0 3 2 . 5 - 3 , 5 1 6 . 4 5 , 9 7 5 , 8 1 9 . 8 7 4 1 8 , 6 3 0 . 9 9 0 . 6 8 4 , 5 7 4 . 9 7, 2 6 7 . 6 9 1 . 1 5 32 9 . 8 4 4, 3 0 7 . 4 4 , 2 3 7 . 6 3 , 1 1 3 . 1 - 3 , 5 6 3 . 9 5 , 9 7 5 , 9 0 0 . 9 9 4 1 8 , 5 8 4 . 3 3 0 . 7 3 4 , 6 6 7 . 4 7, 3 6 3 . 2 9 1 . 2 1 3 2 9 . 7 9 4 , 3 0 5 . 5 4 , 2 3 5 . 7 3 , 1 9 5 . 8 - 3 , 6 1 1 . 9 5 , 9 7 5 , 9 8 4 . 1 2 4 1 8 , 5 3 7 . 1 3 0 . 0 8 4 , 7 6 1 . 7 7, 4 5 7 . 9 9 1 . 2 1 3 2 9 . 9 8 4 , 3 0 3 . 5 4 , 2 3 3 . 7 3 , 2 7 7 . 7 - 3 , 6 5 9 . 4 5 , 9 7 6 , 0 6 6 . 5 0 4 1 8 , 4 9 0 . 4 8 0 . 2 0 4 , 8 5 5 . 2 7, 5 5 4 . 0 9 1 . 2 4 3 3 0 . 3 0 4 , 3 0 1 . 4 4 , 2 3 1 . 6 3 , 3 6 1 . 0 - 3 , 7 0 7 . 3 5 , 9 7 6 , 1 5 0 . 3 1 4 1 8 , 4 4 3 . 5 2 0 . 3 3 4 , 9 4 9 . 9 7, 6 4 9 . 1 9 1 . 1 8 3 3 0 . 2 2 4 , 2 9 9 . 4 4 , 2 2 9 . 6 3 , 4 4 3 . 5 - 3 , 7 5 4 . 4 5 , 9 7 6 , 2 3 3 . 3 3 4 1 8 , 3 9 7 . 2 3 0 . 1 1 5 , 0 4 3 . 7 7, 7 4 3 . 7 9 1 . 1 8 3 3 0 . 1 2 4 , 2 9 7 . 5 4 , 2 2 7 . 7 3 , 5 2 5 . 6 - 3 , 8 0 1 . 5 5 , 9 7 6 , 3 1 5 . 8 6 4 1 8 , 3 5 1 . 0 3 0 . 1 1 5 , 1 3 6 . 9 7, 8 3 8 . 8 9 1 . 1 8 3 2 9 . 7 7 4 , 2 9 5 . 5 4 , 2 2 5 . 7 3 , 6 0 7 . 9 - 3 , 8 4 9 . 1 5 , 9 7 6 , 3 9 8 . 6 5 4 1 8 , 3 0 4 . 2 7 0 . 3 7 5 , 2 3 0 . 8 7, 9 3 4 . 2 9 1 . 2 1 3 3 0 . 1 3 4 , 2 9 3 . 5 4 , 2 2 3 . 7 3 , 6 9 0 . 4 - 3 , 8 9 6 . 9 5 , 9 7 6 , 4 8 1 . 6 9 4 1 8 , 2 5 7 . 3 7 0 . 3 8 5 , 3 2 4 . 9 8, 0 2 8 . 7 9 1 . 2 1 3 2 9 . 5 6 4 , 2 9 1 . 5 4 , 2 2 1 . 7 3 , 7 7 2 . 2 - 3 , 9 4 4 . 4 5 , 9 7 6 , 5 6 3 . 9 1 4 1 8 , 2 1 0 . 7 4 0 . 6 0 5 , 4 1 8 . 2 8, 1 2 3 . 5 9 1 . 2 1 3 2 9 . 2 6 4 , 2 8 9 . 5 4 , 2 1 9 . 7 3 , 8 5 3 . 8 - 3 , 9 9 2 . 6 5 , 9 7 6 , 6 4 5 . 9 7 4 1 8 , 1 6 3 . 3 8 0 . 3 2 5 , 5 1 1 . 8 8, 2 1 8 . 9 9 1 . 2 7 3 2 9 . 0 3 4 , 2 8 7 . 5 4 , 2 1 7 . 7 3 , 9 3 5 . 6 - 4 , 0 4 1 . 5 5 , 9 7 6 , 7 2 8 . 3 4 4 1 8 , 1 1 5 . 3 2 0 . 2 5 5 , 6 0 6 . 2 8, 3 1 4 . 3 9 1 . 1 8 3 2 8 . 8 1 4 , 2 8 5 . 4 4 , 2 1 5 . 6 4 , 0 1 7 . 3 - 4 , 0 9 0 . 7 5 , 9 7 6 , 8 1 0 . 4 9 4 1 8 , 0 6 6 . 9 6 0 . 2 5 5 , 7 0 0 . 5 8, 4 0 8 . 9 9 1 . 1 8 3 2 8 . 6 6 4 , 2 8 3 . 5 4 , 2 1 3 . 7 4 , 0 9 8 . 2 - 4 , 1 3 9 . 8 5 , 9 7 6 , 8 9 1 . 8 8 4 1 8 , 0 1 8 . 6 9 0 . 1 6 5 , 7 9 4 . 2 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 7 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 8, 5 0 3 . 2 9 1 . 1 8 3 2 8 . 8 1 4 , 2 8 1 . 5 4 , 2 1 1 . 7 4 , 1 7 8 . 8 - 4 , 1 8 8 . 8 5 , 9 7 6 , 9 7 2 . 9 7 4 1 7 , 9 7 0 . 6 0 0 . 1 6 5 , 8 8 7 . 5 8, 5 9 9 . 5 9 1 . 2 4 3 2 8 . 9 2 4 , 2 7 9 . 5 4 , 2 0 9 . 7 4 , 2 6 1 . 2 - 4 , 2 3 8 . 5 5 , 9 7 7 , 0 5 5 . 8 9 4 1 7 , 9 2 1 . 6 8 0 . 1 3 5 , 9 8 2 . 8 8, 6 9 2 . 8 9 1 . 2 1 3 2 8 . 8 2 4 , 2 7 7 . 5 4 , 2 0 7 . 7 4 , 3 4 1 . 0 - 4 , 2 8 6 . 8 5 , 9 7 7 , 1 3 6 . 2 0 4 1 7 , 8 7 4 . 3 1 0 . 1 1 6 , 0 7 5 . 1 8, 7 8 8 . 0 9 1 . 2 1 3 2 8 . 4 6 4 , 2 7 5 . 5 4 , 2 0 5 . 7 4 , 4 2 2 . 3 - 4 , 3 3 6 . 3 5 , 9 7 7 , 2 1 7 . 9 9 4 1 7 , 8 2 5 . 6 2 0 . 3 8 6 , 1 6 9 . 4 8, 8 8 3 . 4 9 1 . 2 1 3 2 8 . 4 2 4 , 2 7 3 . 5 4 , 2 0 3 . 7 4 , 5 0 3 . 6 - 4 , 3 8 6 . 2 5 , 9 7 7 , 2 9 9 . 7 7 4 1 7 , 7 7 6 . 5 5 0 . 0 4 6 , 2 6 3 . 9 8, 9 7 9 . 0 9 1 . 3 6 3 2 8 . 6 3 4 , 2 7 1 . 3 4 , 2 0 1 . 5 4 , 5 8 5 . 1 - 4 , 4 3 6 . 1 5 , 9 7 7 , 3 8 1 . 7 7 4 1 7 , 7 2 7 . 5 1 0 . 2 7 6 , 3 5 8 . 5 9, 0 7 3 . 8 9 1 . 3 6 3 2 8 . 8 3 4 , 2 6 9 . 1 4 , 1 9 9 . 3 4 , 6 6 6 . 0 - 4 , 4 8 5 . 3 5 , 9 7 7 , 4 6 3 . 2 3 4 1 7 , 6 7 9 . 1 9 0 . 2 1 6 , 4 5 2 . 3 9, 1 6 9 . 2 9 1 . 3 0 32 9 . 2 4 4, 2 6 6 . 9 4 , 1 9 7 . 1 4 , 7 4 7 . 8 - 4 , 5 3 4 . 4 5 , 9 7 7 , 5 4 5 . 5 6 4 1 7 , 6 3 0 . 9 5 0 . 4 3 6 , 5 4 6 . 7 9, 2 6 4 . 5 9 1 . 3 9 3 2 9 . 4 2 4 , 2 6 4 . 6 4 , 1 9 4 . 8 4 , 8 2 9 . 8 - 4 , 5 8 2 . 9 5 , 9 7 7 , 6 2 7 . 9 5 4 1 7 , 5 8 3 . 2 3 0 . 2 1 6 , 6 4 0 . 8 9, 3 6 0 . 0 9 1 . 3 3 3 2 9 . 3 0 4 , 2 6 2 . 4 4 , 1 9 2 . 6 4 , 9 1 1 . 9 - 4 , 6 3 1 . 6 5 , 9 7 7 , 7 1 0 . 5 7 4 1 7 , 5 3 5 . 4 5 0 . 1 4 6 , 7 3 5 . 2 9, 4 5 4 . 2 9 1 . 3 6 3 2 9 . 5 9 4 , 2 6 0 . 1 4 , 1 9 0 . 3 4 , 9 9 3 . 0 - 4 , 6 7 9 . 5 5 , 9 7 7 , 7 9 2 . 2 2 4 1 7 , 4 8 8 . 3 8 0 . 3 1 6 , 8 2 8 . 3 9, 5 5 0 . 0 9 1 . 3 6 3 2 9 . 5 4 4 , 2 5 7 . 9 4 , 1 8 8 . 1 5 , 0 7 5 . 6 - 4 , 7 2 8 . 0 5 , 9 7 7 , 8 7 5 . 2 8 4 1 7 , 4 4 0 . 7 4 0 . 0 5 6 , 9 2 2 . 9 9, 6 4 4 . 7 9 1 . 2 1 3 2 9 . 7 2 4 , 2 5 5 . 8 4 , 1 8 6 . 0 5 , 1 5 7 . 2 - 4 , 7 7 5 . 9 5 , 9 7 7 , 9 5 7 . 4 0 4 1 7 , 3 9 3 . 7 5 0 . 2 5 7 , 0 1 6 . 4 9, 7 3 9 . 8 9 1 . 2 1 3 2 9 . 6 5 4 , 2 5 3 . 7 4 , 1 8 3 . 9 5 , 2 3 9 . 3 - 4 , 8 2 3 . 9 5 , 9 7 8 , 0 3 9 . 9 9 4 1 7 , 3 4 6 . 6 1 0 . 0 7 7 , 1 1 0 . 3 9, 8 3 0 . 6 9 1 . 2 1 3 2 9 . 7 9 4 , 2 5 1 . 8 4 , 1 8 2 . 0 5 , 3 1 7 . 7 - 4 , 8 6 9 . 6 5 , 9 7 8 , 1 1 8 . 8 2 4 1 7 , 3 0 1 . 6 7 0 . 1 5 7 , 1 9 9 . 9 9, 9 2 6 . 7 9 1 . 2 1 3 2 9 . 7 5 4 , 2 4 9 . 8 4 , 1 8 0 . 0 5 , 4 0 0 . 7 - 4 , 9 1 8 . 0 5 , 9 7 8 , 2 0 2 . 3 4 4 1 7 , 2 5 4 . 1 6 0 . 0 4 7 , 2 9 4 . 8 10 , 0 2 4 . 1 9 1 . 2 4 3 3 0 . 2 4 4 , 2 4 7 . 7 4 , 1 7 7 . 9 5 , 4 8 5 . 1 - 4 , 9 6 6 . 7 5 , 9 7 8 , 2 8 7 . 1 9 4 1 7 , 2 0 6 . 3 3 0 . 5 0 7 , 3 9 0 . 9 10 , 1 1 8 . 3 9 1 . 2 1 3 3 0 . 0 8 4 , 2 4 5 . 7 4 , 1 7 5 . 9 5 , 5 6 6 . 8 - 5 , 0 1 3 . 6 5 , 9 7 8 , 3 6 9 . 3 7 4 1 7 , 1 6 0 . 3 1 0 . 1 7 7 , 4 8 3 . 8 10 , 2 1 2 . 0 9 1 . 2 1 3 3 0 . 4 2 4 , 2 4 3 . 7 4 , 1 7 3 . 9 5 , 6 4 8 . 1 - 5 , 0 6 0 . 0 5 , 9 7 8 , 4 5 1 . 1 1 4 1 7 , 1 1 4 . 7 2 0 . 3 6 7 , 5 7 6 . 1 10 , 3 0 7 . 7 9 1 . 2 1 3 3 0 . 1 5 4 , 2 4 1 . 7 4 , 1 7 1 . 9 5 , 7 3 1 . 2 - 5 , 1 0 7 . 5 5 , 9 7 8 , 5 3 4 . 7 0 4 1 7 , 0 6 8 . 1 5 0 . 2 8 7 , 6 7 0 . 4 10 , 4 0 0 . 7 9 1 . 1 8 3 2 9 . 6 1 4 , 2 3 9 . 8 4 , 1 7 0 . 0 5 , 8 1 1 . 7 - 5 , 1 5 4 . 2 5 , 9 7 8 , 6 1 5 . 6 6 4 1 7 , 0 2 2 . 3 0 0 . 5 8 7 , 7 6 2 . 2 10 , 5 0 0 . 2 9 1 . 3 0 3 2 9 . 1 5 4 , 2 3 7 . 6 4 , 1 6 7 . 8 5 , 8 9 7 . 2 - 5 , 2 0 4 . 8 5 , 9 7 8 , 7 0 1 . 7 4 4 1 6 , 9 7 2 . 5 5 0 . 4 8 7 , 8 6 0 . 5 10 , 5 9 5 . 1 9 1 . 2 1 3 2 8 . 9 7 4 , 2 3 5 . 5 4 , 1 6 5 . 7 5 , 9 7 8 . 6 - 5 , 2 5 3 . 6 5 , 9 7 8 , 7 8 3 . 6 0 4 1 6 , 9 2 4 . 6 3 0 . 2 1 7 , 9 5 4 . 4 10 , 6 9 0 . 6 9 1 . 2 1 3 2 8 . 9 1 4 , 2 3 3 . 5 4 , 1 6 3 . 7 6 , 0 6 0 . 4 - 5 , 3 0 2 . 9 5 , 9 7 8 , 8 6 5 . 9 4 4 1 6 , 8 7 6 . 2 0 0 . 0 6 8 , 0 4 8 . 9 10 , 7 8 5 . 1 9 1 . 2 1 3 2 9 . 2 0 4 , 2 3 1 . 5 4 , 1 6 1 . 7 6 , 1 4 1 . 5 - 5 , 3 5 1 . 4 5 , 9 7 8 , 9 4 7 . 4 6 4 1 6 , 8 2 8 . 4 6 0 . 3 1 8 , 1 4 2 . 3 10 , 8 7 9 . 7 9 1 . 2 1 3 2 9 . 3 6 4 , 2 2 9 . 5 4 , 1 5 9 . 7 6 , 2 2 2 . 7 - 5 , 3 9 9 . 7 5 , 9 7 9 , 0 2 9 . 2 0 4 1 6 , 7 8 1 . 0 3 0 . 1 7 8 , 2 3 5 . 8 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 8 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 10 , 9 3 0 . 0 9 1 . 2 3 3 2 9 . 4 0 4 , 2 2 8 . 5 4 , 1 5 8 . 7 6 , 2 6 6 . 0 - 5 , 4 2 5 . 4 5 , 9 7 9 , 0 7 2 . 7 6 4 1 6 , 7 5 5 . 8 6 0 . 0 8 8 , 2 8 5 . 5 NT 3 . 2 4 10 , 9 7 5 . 7 9 1 . 2 4 3 2 9 . 4 3 4 , 2 2 7 . 5 4 , 1 5 7 . 7 6 , 3 0 5 . 4 - 5 , 4 4 8 . 6 5 , 9 7 9 , 1 1 2 . 3 4 4 1 6 , 7 3 3 . 0 2 0 . 0 8 8 , 3 3 0 . 7 11 , 0 7 0 . 7 9 1 . 1 8 3 2 9 . 7 2 4 , 2 2 5 . 5 4 , 1 5 5 . 7 6 , 3 8 7 . 2 - 5 , 4 9 6 . 7 5 , 9 7 9 , 1 9 4 . 7 0 4 1 6 , 6 8 5 . 7 9 0 . 3 1 8 , 4 2 4 . 5 11 , 1 6 5 . 4 91 . 2 1 3 2 9 . 3 6 4 , 2 2 3 . 5 4 , 1 5 3 . 7 6 , 4 6 8 . 8 - 5 , 5 4 4 . 7 5 , 9 7 9 , 2 7 6 . 7 8 4 1 6 , 6 3 8 . 6 6 0 . 3 8 8 , 5 1 8 . 0 11 , 2 6 0 . 7 9 1 . 2 4 3 2 9 . 2 3 4 , 2 2 1 . 4 4 , 1 5 1 . 6 6 , 5 5 0 . 8 - 5 , 5 9 3 . 4 5 , 9 7 9 , 3 5 9 . 2 7 4 1 6 , 5 9 0 . 8 2 0 . 1 4 8 , 6 1 2 . 3 11 , 3 5 5 . 9 9 1 . 2 4 3 2 9 . 0 6 4 , 2 1 9 . 4 4 , 1 4 9 . 6 6 , 6 3 2 . 5 - 5 , 6 4 2 . 2 5 , 9 7 9 , 4 4 1 . 4 6 4 1 6 , 5 4 2 . 8 7 0 . 1 8 8 , 7 0 6 . 4 11 , 4 5 1 . 0 9 1 . 1 5 3 2 8 . 8 6 4 , 2 1 7 . 4 4 , 1 4 7 . 6 6 , 7 1 3 . 9 - 5 , 6 9 1 . 2 5 , 9 7 9 , 5 2 3 . 3 7 4 1 6 , 4 9 4 . 7 3 0 . 2 3 8 , 8 0 0 . 4 11 , 5 4 6 . 1 9 1 . 2 7 3 2 8 . 8 0 4 , 2 1 5 . 4 4 , 1 4 5 . 6 6 , 7 9 5 . 3 - 5 , 7 4 0 . 4 5 , 9 7 9 , 6 0 5 . 2 5 4 1 6 , 4 4 6 . 3 5 0 . 1 4 8 , 8 9 4 . 5 11 , 6 4 0 . 9 9 1 . 2 7 3 2 8 . 8 0 4 , 2 1 3 . 3 4 , 1 4 3 . 5 6 , 8 7 6 . 4 - 5 , 7 8 9 . 5 5 , 9 7 9 , 6 8 6 . 8 3 4 1 6 , 3 9 8 . 1 0 0 . 0 0 8 , 9 8 8 . 4 11 , 7 3 5 . 9 9 1 . 2 1 3 2 9 . 0 4 4 , 2 1 1 . 2 4 , 1 4 1 . 4 6 , 9 5 7 . 7 - 5 , 8 3 8 . 5 5 , 9 7 9 , 7 6 8 . 6 3 4 1 6 , 3 4 9 . 9 4 0 . 2 6 9 , 0 8 2 . 3 11 , 8 3 1 . 0 9 1 . 2 4 3 2 9 . 0 5 4 , 2 0 9 . 2 4, 1 3 9 . 4 7, 0 3 9 . 2 - 5 , 8 8 7 . 4 5 , 9 7 9 , 8 5 0 . 6 7 4 1 6 , 3 0 1 . 8 9 0 . 0 3 9 , 1 7 6 . 4 11 , 9 2 6 . 0 9 1 . 2 4 3 2 9 . 2 3 4 , 2 0 7 . 2 4 , 1 3 7 . 4 7 , 1 2 0 . 8 - 5 , 9 3 6 . 1 5 , 9 7 9 , 9 3 2 . 6 8 4 1 6 , 2 5 4 . 0 3 0 . 1 9 9 , 2 7 0 . 3 12 , 0 2 1 . 3 9 1 . 2 4 3 2 9 . 5 7 4 , 2 0 5 . 1 4 , 1 3 5 . 3 7 , 2 0 2 . 8 - 5 , 9 8 4 . 6 5 , 9 8 0 , 0 1 5 . 1 8 4 1 6 , 2 0 6 . 3 9 0 . 3 6 9 , 3 6 4 . 4 12 , 1 1 2 . 5 9 1 . 2 7 3 2 9 . 7 8 4 , 2 0 3 . 1 4 , 1 3 3 . 3 7 , 2 8 1 . 5 - 6 , 0 3 0 . 7 5 , 9 8 0 , 0 9 4 . 4 1 4 1 6 , 1 6 1 . 1 4 0 . 2 3 9 , 4 5 4 . 5 12 , 2 1 1 . 0 9 1 . 3 0 3 2 9 . 6 0 4 , 2 0 0 . 9 4 , 1 3 1 . 1 7 , 3 6 6 . 5 - 6 , 0 8 0 . 4 5 , 9 8 0 , 1 7 9 . 9 1 4 1 6 , 1 1 2 . 3 4 0 . 1 9 9 , 5 5 1 . 8 12 , 3 0 6 . 6 9 1 . 2 1 3 2 9 . 9 4 4 , 1 9 8 . 8 4 , 1 2 9 . 0 7 , 4 4 9 . 1 - 6 , 1 2 8 . 5 5 , 9 8 0 , 2 6 2 . 9 5 4 1 6 , 0 6 5 . 1 0 0 . 3 7 9 , 6 4 6 . 1 12 , 3 4 9 . 2 9 1 . 2 4 32 9 . 8 4 4, 1 9 7 . 9 4 , 1 2 8 . 1 7 , 4 8 5 . 9 - 6 , 1 4 9 . 9 5 , 9 8 0 , 3 0 0 . 0 1 4 1 6 , 0 4 4 . 1 3 0 . 2 5 9 , 6 8 8 . 1 12 , 3 7 4 . 0 9 1 . 2 4 32 9 . 8 4 4, 1 9 7 . 3 4 , 1 2 7 . 5 7 , 5 0 7 . 4 - 6 , 1 6 2 . 3 5 , 9 8 0 , 3 2 1 . 5 9 4 1 6 , 0 3 1 . 8 8 0 . 0 0 9 , 7 1 2 . 6 4- 1 / 2 " P r o d u c t i o n C a s i n g 12 , 3 8 1 . 0 9 1 . 2 4 3 2 9 . 8 4 4 , 1 9 7 . 2 4 , 1 2 7 . 4 7 , 5 1 3 . 4 - 6 , 1 6 5 . 8 5 , 9 8 0 , 3 2 7 . 6 7 4 1 6 , 0 2 8 . 4 3 0 . 0 0 9 , 7 1 9 . 5 TD P r o j e c t i o n 9- 5 / 8 " I n t e r m e d i a t e C a s i n g 4, 3 2 1 . 7 6, 2 8 3 . 0 9- 5 / 8 12 - 1 / 4 4- 1 / 2 " P r o d u c t i o n C a s i n g 4, 1 9 7 . 3 12 , 3 7 4 . 0 4- 1 / 2 8 - 1 / 2 20 " C o n d u c t o r 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, 2 7 3 . 8 2, 5 8 8 . 0 13 - 3 / 8 1 6 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 9 Pr o j e c t : Co m p a n y : Lo c a l C o -or 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 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 3 2 ND B - 0 3 2 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 s D r i l l e d @ 6 9 . 8 u s f t De s i g n : ND B - 0 3 2 Da t a b a s e : ED M S T O A l a s k a MD R e f e r e n c e : Pa r k e r 2 7 2 A s D r i l l e d @ 6 9 . 8 u s f t No r t h R e f e r e n c e : We l l N D B -03 2 Tr u e Me a s u r e d De p t h (us f t ) Ve r t i c a l De p t h (us 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 5, 2 4 9 . 0 4 , 0 3 0 . 2 N T 5 M F S 4, 9 7 4 . 0 3 , 8 7 8 . 3 N T 8 M F S 1, 8 2 2 . 0 1 , 7 5 7 . 9 M i d d l e S c h r a d e r B l u f f 6, 1 4 0 . 0 4 , 3 0 9 . 9 N T 3 M F S 4, 9 5 2 . 0 3 , 8 6 5 . 1 N a n u s h u k 2, 8 6 7 . 0 2 , 4 5 2 . 2 T u l u v a k S h a l e 2, 3 9 0 . 0 2 , 1 4 7 . 5 M C U 1, 0 3 9 . 0 1 , 0 3 5 . 8 U p p e r S c h r a d e r B l u f f 6, 4 6 8 . 0 4 , 3 2 5 . 2 N T 3 . 2 T o p R e s e r v o i r 1, 4 1 2 . 0 1 , 3 9 9 . 3 B a s e P e r m a f r o s t T r a n s i t i o n 3, 9 4 0 . 0 3 , 1 7 4 . 8 S e a b e e 5, 1 4 0 . 0 3 , 9 7 2 . 9 N T 6 M F S 5, 3 9 0 . 0 4 , 0 9 7 . 4 N T 4 M F S 5, 0 2 1 . 0 3 , 9 0 6 . 0 N T 7 M F S 2, 9 3 4 . 0 2 , 4 9 5 . 0 T u l u v a k S a n d 1, 1 3 0 . 0 1 , 1 2 5 . 4 B a s e I c e B e a r i n g P e r m a f r o s t 10 , 9 3 0 . 0 4 , 2 2 8 . 5 N T 3 . 2 4 Me a s u r e d De p t h (us f t ) Ve r t i c a l De p t h (us f t ) +E /- W (us f t ) +N /- S (us f t )Lo c a l C o o r d i n a t e s Co m m e n t De s i g n A n n o t a t i o n s 12 , 3 8 1 . 0 4 , 1 9 7 . 2 - 6 , 1 6 5 . 8 7, 5 1 3 . 4 T D P r o j e c t i o n Ap p r o v e d B y : Ch e c k e d B y : Da t e : 14 /09 /20 2 3 2 :41 :24 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 1 0 LETTER OF TRANSMITTAL RECEIVED SEP 2 l 2023 aa3-b�-co I g5 Santos"�' DATE: 9/25/2023 ADGCc From: To: Shannon Koh Meredith Guhl Santos AOGCC P.O. Box 240927 333 W. 7th Avenue, Suite 100 Anchorage, AK 99524-0927 Anchorage, AK 99501 TRANSMISSION TYPE: TRANSMISSION METHOD: ®External Request ❑CD ❑ Thumb Drive ❑Internal Request ❑Email ❑SharePoint/Teams ❑Hardcopy ®Other— Dry cutting samples REASON FOR TRANSMITTAL: ❑To Be Returned []Approved❑Information Only ❑Approved with Comments El For Your Review ❑ With Our Comments [I For Approval ®For Your Use ❑Other COMMENTS: CITY 6 boxes of washed and dried cutting samples Received bJ� Y DETAIL DESCRIPTION NDB-032 (50-103-20860-0000) 1 of 6 39 Washed and Dried 50' 128'-2100' 2 of 6 38 50' 2100'-4000' 3 of 6 46 50' 4000'-6288' 4 of 6 40 5o' 6288'-8250' 5 of 6 41 50 8250'-10300' 6 of 6 42 50' 10300'-12381' Please $ign and return one copy to: Date: '?j D N\- S'3 � —2-81 ZE Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 907-375-4607 phone shannon.koh@santos.com Geological Sample Manifest/Inventory Operator: Santos/Oilsearch Date: 07-Sep-23 Well Name: NOM32 Prepared By: Geolog Location: North Slope, AK Received By: Santos Geologist Set Owner Box Quantity Of Containes (bags, jars, etc) Type Sampling Frequency Sampling Interval Enclosed Shipping Address 1 of 6 39 50' 128'-2100' 2 of 6 38 50, 2100'-4000' 1 AOGCC Washed and Dried Meredith Guhl Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 3 of 6 46 50' 4000'-6288' 4 of 6 40 50' 6288'-8250' Anchorage, AK 99501 5 of 6 41 50' 8250'-10300' (907) 793-1235 6 of 6 42 50, 10300'-12381' 1 of 6 39 50' 128'-2100' 2 of 6 38 50' 2100'-4000' Repsol 3 of 6 46 50' 4000'-6288' 2455 Technology Forest Blvd. 2 Repsol Washed and Dried The Woodlands, TX 77381 4 of 6 40 50' 6288'-8250' Attn: Alejandro Martin Vicente (832) 381-8898 5 of 6 41 50' 8250'-10300' 6 of 6 42 50, 10300'-12381' Total Boxes: 12 non hazardous Total Weight: 2SIbs RECEIVED 27 2023 A®GCC RECEIVED GEOLOG L*%Kkft Santos kuxmmWn Hub sip z z 2023 DRILL CUTTINGS SAMPLE MANIFEST WELL NAME, AU$-632 WELL API : 50-103-20860-00-00 Date Drilled FROM: 8/20/2023 09/06/2023 Area/Location INorth Slope Borough OVEN DRIED SAMPLES (SETS A, B) Box 1 Box 2 Box 3 Box 4 Box 5 Box 6 1 200 2150 4050 6308 8300 10350 2 250 2200 4100 6350 8350 10400 3 300 2250 4150 6400 8400 10450 4 350 2300 4200 6450 8450 10500 5 400 2350 4250 6500 8500 10550 6 450 2400 4300 6550 8550 10600 7 500 2450 4350 6600 8600 10650 8 550 2500 4400 6650 8650 10700 9 600 2550 4450 6700 8700 10750 10 650 2595 4500 6750 8750 10800 11 700 2650 4550 6800 8800 10850 12 750 2700 4600 6850 8850 10900 13 800 2750 4650 6900 8900 10950 14 850 2800 4700 6950 8950 11000 15 900 2850 4750 7000 9000 11050 16 950 2900 4800 7050 9050 11100 17 1000 2950 4850 7100 9100 11150 18 1050 3000 4900 7150 9150 11200 19 1100 3050 4950 7200 9200 11250 20 1150 3100 5000 7250 9250 11300 21 1200 3150 5050 7300 9300 11350 22 1250 3200 5100 7350 9350 11400 23 1300 3250 5150 7400 9400 11450 24 1350 3300 5200 7450 9450 11500 25 1400 3350 5250 7500 9500 11550 26 1450 3400 5300 7550 9550 11600 27 1500 3450 5350 7600 9600 11650 28 1550 3500 5400 7650 9650 11700 29 1600 3550 5450 7700 9700 11750 30 1650 3600 5500 7750 9750 11800 31 1700 3650 5550 7800 9800 11850 32 1750 3700 5600 7850 9850 11900 33 1800 3750 5650 7900 9900 11950 34 1850 3800 5700 7950 9950 12000 1 1 1 1 : 1■ : 1 1 1 1 1■ 1 -, 7 1 1 •111 It �� 1 1. 11 �■ !! 1 1 1 1 1� ! 1 It 1 _- tl 1 Preparation Date: MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, October 17, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Oil Search (Alaska), LLC NDB-032 PIKKA NDB-032 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/17/2023 NDB-032 50-103-20860-00-00 223-060-0 N SPT 4305 2230600 3800 2780 3215 3222 3219 0 0 0 0 OTHER P Josh Hunt 9/23/2023 This MIT was performed on this well which is a producer because it will be fracked using high pressure in December.. They used diesel to test the IA and tubing today due to freezing temperatures. MIT IA x T per PTD # 2230600. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PIKKA NDB-032 Inspection Date: Tubing OA Packer Depth 7 4000 3899 3870IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH230923164846 BBL Pumped:5.4 BBL Returned:5.2 Tuesday, October 17, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 producer James B. Regg Digitally signed by James B. Regg Date: 2023.10.17 16:02:59 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Staudinger, Mark (Mark) Cc:Tirpack, Robert (Robert); Davis, Rachel (Rachel); Kono, Randy (Randy); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC) Subject:RE: NDB-032 Permit To Drill updates / clarification (#223-060) Date:Sunday, August 27, 2023 6:26:00 PM Mark, These changes listed below are approved. As for the Cement log, if the cement job goes as planned, Oilsearch has authorization to run the completion without further authorization from the AOGCC, with the condition that the logs are submitted to AOGCC to review within 48 hours of obtaining them. Regular injection or production is not allowed without further authorization from AOGCC. Recognize that there is a lot of sensitivity and scrutiny around cementing hydrocarbon and overpressured zones and if the Tuluvak is not cemented, it might be necessary to pull tubing to remediate. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Thursday, August 17, 2023 9:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Davis, Rachel (Rachel) <Rachel.Davis@santos.com>; Kono, Randy (Randy) <Randy.Kono@santos.com> Subject: NDB-032 Permit To Drill updates / clarification (#223-060) Bryan, I wanted to follow up on a few things for the upcoming well’s (NDB-032) Permit to Drill. As per my note last week, I wanted to make sure you received the well program updates that affect the PTD. The below changes are being driven by issues that we encountered during production hole drilling in NDBi-043. The changes are as follows: Deepen the 9-5/8” intermediate casing point by ~350’ MD. We are now going to top set the reservoir instead of land in the shale package above it, hoping to get more of the unstable shales behind INT casing. Increase MW in the Prod hole to 10.0 ppg for shale stability. This in turn will increase the LOT requirement to 10.5ppg for min kick tolerance in the prod hole. We will take the test outside the 9-5/8” shoe to Leak-Off, or a max of 15.0ppg EMW, so as not to disturb any exposed shales too much. Additionally, I’d like to seek clarification on the permit comment in Section 13 (Proposed Drilling Program), stating that we need to “submit results of cement log to AOGCC and obtain approval before running upper completion.” Assuming the intermediate casing cement job goes as planned, is it acceptable to begin running upper completion prior to AOGCC approval of the cement log? I’m just trying to avoid a scenario where we get log results in the middle of the night and the rig is forced to go on standby while we are waiting on AOGCC approval to move forward. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-032 JBR 10/16/2023 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:1 Tested with 4-1/2" and 5-7/8" TJ accumulator bottles 24 @ 1049 psi precharge. Manual Choke line valve fail grease cycle passed. On last test of the LPR we had a leak that took a lot of trouble shooting and it was found to be a weep on a crossover connection on the test joint bleow the floor so was hard to find. Test Results TEST DATA Rig Rep:Pat/RyanOperator:Oil Search (Alaska), LLC Operator Rep:Brian Buzby Rig Owner/Rig No.:Parker 272 PTD#:2230600 DATE:8/25/2023 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopKPS230826224603 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 11.5 MASP: 1529 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 2 P Inside BOP 2 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 X 7 P #2 Rams 1 Blind Shears P #3 Rams 1 4-1/2 X 7 P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8 FP HCR Valves 2 3-1/8 P Kill Line Valves 1 3-1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1900 200 PSI Attained P19 Full Pressure Attained P86 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14 @ 2217 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P22 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 9 9 9 9 9 9 9 9 9FP Manual Choke line valve fail g 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-032 Oil Search Alaska, LLC Permit to Drill Number: 223-060 Surface Location: 2365' FSL, 3130' FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 4597' FSL, 3999' FEL, Sec 32, T12N, R6E, UM Dear Mr. Staudinger: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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 August 2023. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.01 16:40:37 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 12313'TVD:4217' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 08/1/23 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 70.47 15. Distance to Nearest Well Open Surface: x- 422115.35 y- 5972751.32 Zone- 4 23.8 to Same Pool:2060' 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 128' 16" 13-3/8” 68# L-80 BTC 2628' Surface Surface 2628' 2303' 12-1/4” 9-5/8” 47# L-80 HYD 563 3434' 2478' 2200' 5912' 4277' Tie Back 9-5/8” 47# L-80 HYD 563 2478' Surface Surface 2478' 2199' 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6561' 5762' 4240' 12323' 4217' Tubing 4-1/2” 12.6# P-110S HYD 563 5787' Surface Surface 5787' 4249' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Mark Staudinger Mark Staudinger Contact Email:mark.staudinger@santos.com Senior Drilling Engineer Contact Phone:1-520-273-6643 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10,639' N/A NDB-032 Pikka / Nanushuk Oil Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): IS000361277U Specifications 1957 psi Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface Please see attachment 6 for details STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Please see attachment 6 for details 1529 psi 4800' FSL, 1000' FEL, Sec 5., T11N, R6E, UM 4597' FSL, 3999' FEL, Sec 32, T12N, R6E, UM LONS 19-003 900 E Benson Boulevard, Anchorage, AK 99508 Oil Search Alaska, LLC 2365' FSL, 3130' FEL, Sec 4, T11N, R6E, UM ADL 392984, ADL 391445, ADL 393020 1,920 18. Casing Program: Top - Setting Depth - Bottom Conductor/Structural LengthCasing Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): N/A N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): s N ype of W L l R L 1b S Class: os N s No s N o D s ss D 612 7 o well is p G S S 20 S S S s Nos No S G E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Senior Drilling Engineer By Grace Christianson at 2:36 pm, Jul 10, 2023 SFD DSR-7/12/23 50-103-20860-00-00 8/10/23 223-060 BJM 7/28/23 IS000361277U SFD SFD 8/01/2023 BOP test to 3500 psi. Annular test to 3000 psi. GCW 08/01/2023 JLC 8/1/2023 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.08.01 16:41:09 -08'00' Page 1 of 1 10 July 2023 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-032 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-032 is planned to be a horizontal producer targeting the Nanushuk 3. The approximate spud date is anticipated to be August 15 th, 2023. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~47 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8” tieback will be run to the top of the 9-5/8” liner. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand. The well will be completed as a stimulated producer with 4-1/2” liner with frac sleeves and isolation packers. The production liner will be tied back to surface with a 4-1/2” tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (520) 273- 6643 or Mark.Staudinger@santos.com. Respectfully, Mark Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, August 10th -bjm NDB-032 PTD V1 - 1 - 10-Jul-23 Application for Permit to Drill NDB-032 Well NDB-032 PTD V1 - 2 - 10-Jul-23 Table of Contents 1. Well Name......................................................................................................................................3 2. Location Summary..........................................................................................................................3 3. Blowout Prevention Equipment Information.................................................................................4 4. Drilling Hazards Information...........................................................................................................5 5. Procedure for Conducting Formation Integrity Tests.....................................................................6 6. Casing and Cementing Program.....................................................................................................6 7. Diverter System Information..........................................................................................................7 8. Drilling Fluid Program.....................................................................................................................7 9. Abnormally Pressured Formation Information ..............................................................................7 10. Seismic Analysis............................................................................................................................8 11. Seabed Condition Analysis............................................................................................................8 12. Evidence of Bonding.....................................................................................................................8 13. Proposed Drilling Program ...........................................................................................................8 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................10 Attachments..................................................................................................................................................11 Attachment 1: Location Maps..........................................................................................................12 Attachment 2: Directional Plan........................................................................................................14 Attachment 3: BOPE Equipment ......................................................................................................25 Attachment 4: Drilling Hazards.........................................................................................................29 Attachment 5: Leak Off Test Procedure...........................................................................................31 Attachment 6: Cement Summary.....................................................................................................32 Attachment 7: Prognosed Formation Tops......................................................................................33 Attachment 8: Well Schematic.........................................................................................................34 Attachment 9: Formation Evaluation Program ................................................................................35 Attachment 10: Wellhead & Tree Diagram......................................................................................36 NDB-032 PTD V1 - 3 - 10-Jul-23 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDB-032. 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 2365’ FSL, 3130’ FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,751.32 E 422,115.35 Rig KB Elevation 47.0’ above ground level Ground Level 23.5’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 4800’ FSL, 1000’ FEL, Sec 5, T11N, R6E, UM NAD 27 Coordinate System N 5,975,216.87 E 418,981.94 Measured Depth, Rig KB (MD) 6,408’ Total Vertical Depth, Rig KB (TVD) 4,325.5’ Total vertical Depth, Subsea (TVDSS) 4,255’ Location at Bottom of Productive Interval Reference to Government Section Lines 4597’ FSL, 3999’ FEL, Sec 32, T12N, R6E, UM NAD 27 Coordinate System N 5,980,326.72 E 416,025.71 Measured Depth, Rig KB (MD) 12,312.9’ Total Vertical Depth, Rig KB (TVD) 4,217.5’ Total vertical Depth, Subsea (TVDSS) 4,147’ NDB-032 PTD V1 - 4 - 10-Jul-23 (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 2: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for NDB-032 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Parker 272 BOP Equipment: BOP Equipment x NOV Shaffer Spherical annular BOP, 13-5/8” x 5000 psi x NOV T3 6012 double gate, 13-5/8” x 5000 psi x Mud cross, 13-5/8” x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets x Choke Line, 3-1/8” x 5000 psi with 3-1/8” manual and HCR valve x Kill Line, 2-1/16” x 5000 psi with 3-1/8” manual and HCR valve x NOV T3 6012 single gate, 13-5/8” x 5000 psi Choke Manifold x 3-1/8” x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit x NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. NDB-032 PTD V1 - 5 - 10-Jul-23 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,957 psi in the Nanushuk 4 at 4,277’ TVD (8.8ppg EMW top Nanushuk 4 formation to section TD) Maximum surface pressure 1,529 psi from the NT4 (0.10 psi/ft gas gradient to surface, 4,277’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by 9-5/8” Casing Pressure Test] Integrity Test – 12-1/4” hole LOT after drilling 20’-50’ of new hole. 12.8 ppg LOT required for Kick Tolerance, 17 ppg maximum EMW LOT 13-3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by Maximum Surface Pressure] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,957 psi in the Nanushuk 3 at 4,326’ TVD (8.7ppg EMW top NT3 formation to heel target) Maximum surface pressure 1,525 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,326’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by 9-5/8” Casing Pressure Test] Integrity Test – 8-1/2” hole LOT after drilling 20’-50’ of new hole. 9.9 ppg for minimum kick tolerance. 9-5/8” Liner Test 3,500 psi surface pressure [Test pressure driven by Maximum Surface Pressure] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be over-pressured at 10.1ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; 13.3 ppg per M. Staudinger. -bjm NDB-032 PTD V1 - 6 - 10-Jul-23 Nearby offset Exploration and Appraisal wells in the area suggest that no significant hole problems are to be expected. Please refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 128’ 16” 13-3/8” 68# L-80 BTC 2,628’ Surface 2,628’ / 2,303’ 12-1/4” 9-5/8” 47# L-80 HYD 563 3,434’ 2,478’ 5,912’ / 4,277’ Tie Back 9-5/8” 47# L-80 HYD 563 2,478’ Surface 2,478’ / 2,199’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6,561’ 5,762’ 12,323’ / 4,217’ Tubing 4-1/2” 12.6# P-110S HYD 563 5,787’ Surface 5,787’ / 4,249’ Please refer to Attachment 6: Cement Summary for further details. NDB-032 PTD V1 - 7 - 10-Jul-23 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line Please refer to Attachment 3: BOPE Equipment for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Intermediate Hole Production Hole Mud Type Water based Spud Mud Mineral Oil Based Mud Mineral Oil Based Mud Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 10.5ppg 85-275 seconds 30-50 30-80 < 14 ml/30min n/a 9.5-10 <35 10.7-11.2ppg 50-100 seconds 20-40 15-30 n/a < 10 ml/30min n/a n/a 9.0-9.8ppg 50-80 seconds 15-20 10-20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10.0 ppg 11.5 ppg per M. Staudinger email 7/28/23. -bjm NDB-032 PTD V1 - 8 - 10-Jul-23 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-032 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-032 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program NDB-032 1. Drill 20” insulated 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. NDB-032 PTD V1 - 9 - 10-Jul-23 6. Spud well and drill surface hole section to TD. Circulate and clean well prior to trip. 7. POOH and lay down drilling assembly. 8. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 9. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 10. ND diverter and NUD casing head and spacer spool. NU BOPE (configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 4-1/2” x 7” VBR). Test rams to 3500 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing BOP test. 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 11.0ppg MOBM. Pressure test casing to 2,600 psi for 30 min. 12. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test and submit results to AOGCC. 13. Directionally drill 12-1/4” intermediate hole section to TD ~25’ TVD above the NT3 MFS. Perform wiper trips as required. Circulate and condition hole to run casing. POOH. 14. Change out upper BOP rams from 4-1/2”x7” VBR to 9-5/8” solid body and test to 3,500 psi. 15. Run 9-5/8” production liner as per casing tally then RIH on 5-7/8” DP. Circulate and condition mud prior to commencing cement job. 16. Cement 9-5/8” liner with single stage cement job as per cement program. Monitor returns during displacement. Bump plug then pressure up to set liner hanger, release running tool, and set liner top packer. 17. Un-sting from liner hanger and circulate cement returns from the top of liner. 18. POOH and LD liner running tools. 19. Run 9-5/8” tie-back string. Freeze protect 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 20. Pressure test 13-3/8” x 9-5/8” annulus to 2,600 psi for 30 min. 21. Pressure test 9-5/8” liner and tieback to 3,500 psi for 30 min. 22. Change out upper BOP rams from 9-5/8” solid body to 4-1/2” x 7” VBR and test to 3,500 psi. 23. Make up 8-1/2” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to 9.2ppg MOBM. 24. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test and submit results to AOGCC. 25. Directionally drill 8-1/2” hole section as per well plan to TD. Perform wiper trips as required. 26. POOH and lay down 8-1/2” drilling BHA. 27. RU and run 4-1/2” production liner with frac sleeves and mechanical packers. Notify AOGCC if cement is not circulated to surface. -bjm 11.5 ppg per M. Staudinger. -bjm NDB-032 PTD V1 - 10 - 10-Jul-23 28. Run 4-1/2” liner to TD. Set liner hanger and liner top packer and release the running tool. 29. Pressure test the 9-5/8” x 4-1/2” production liner to 3,500 psi for 30 min. 30. POOH and LD liner running tool. 31. RU wireline and run ultrasonic cement evaluation log. Submit results to AOGCC. 32. RU and run 4-1/2” upper completion with tech wire. Space out and stab seals inside the polish bore below the 9-5/8” x 4-1/2” liner top packer. 33. Pressure test tubing to 4,000 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 34. Circulate diesel to freeze protect annulus and tubing. 35. Install TWC, pressure test to 3,000 psi for 5 mins. ND BOPE, NU dry hole tree. 36. RDMO 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. Water-based and oil based drilling muds and cuttings will typically be hauled directly offsite via truck as it is generated. Contractual arrangements have been made with other operators on the North Slope to utilize their waste injection/disposal facilities (Class 1 and Class 2) at Prudhoe Bay, Kuparuk and Milne Point. If waste cannot be hauled directly offsite, it may be stored temporarily in drilling waste cuttings bins or a bermed cuttings storage cell in accordance with a drilling waste temporary storage plan approved by Alaska Department of Conservation (ADEC) Solid Waste Program until it can be transported for proper disposal. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. Submit results of Cement log to AOGCC and obtain approval before running upper completion. -bjm NDB-032 PTD V1 - 11 - 10-Jul-23 Attachments NDB-032 PTD V1 - 12 - 10-Jul-23 Attachment 1: Location Maps OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELLS RIG OUTLINES DIVERTER (50-ft) DATE: 5/25/2023. By: JB 0204010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB32_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDB32 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.33536 -150.63502 N 70° 20' 07.3005" W 150° 38' 06.0634" 5,972,499.32 1,562,148.16 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.33552 -150.63502 N 70° 20' 08.4517" W 150° 37' 54.7866" 5,972,751.32 422,115.35 State Plane NAD83 Zone 4 StatePlane NAD27 Zone 4 NDB-032 PTD V1 - 14 - 10-Jul-23 Attachment 2: Directional Plan NDB-032 Heel v.0 NDB-032 TD v.0 Tie On 3.00°/100ftEnd of Tangent EndofBuild 3.00°/100ft Endof3DArc 13.375in Casing Surface 9.625in Casing Intermediate End of Tangent 3.00°/100ftEndof3DArc 4.5in Casing ProductionTrue Vertical Depth (ft) Vertical Section (ft) Azimuth 320.61° with reference 0.00 N, 0.00 E 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 -750 0 750 1500 2250 3000 3750 4500 Scale 1 inch = 1500.01Scale 1 inch = 1500 Offset wellpath MDs are referenced to each path's default MD datum Mean Sea Level to Ground level (At Slot: B-32): 0 feet Rig on B-32 (RT) to Mean Sea Level: 70.47 feet Reference wellpath measured depths are referenced to Rig on B-32 (RT) True vertical depths are referenced to Rig on B-32 (RT) Plot reference wellpath is NDB-032 Rev A.3 Created by: meyedavr on 2023-06-06; Database: WellArchitectDB Depths are in feet Coordinates are in feet referenced to Slot Scale: True distance North Reference: True north Grid System: NAD83 / TM Alaska SP, Zone 4 (5004), US feet Location: Facility: Field: Pikka Pikka Alaska Santos Wellbore: Well: Slot: NDB-032 NDB-032 B-32 NDB-032 TD v.0 NDB-032 Heel v.0 B-32 4.5in Casing Production 13.375in Casing Surface 9.625in Casing Intermediate Northing (ft) Easting (ft) -8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0 1000 -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 Scale 1 inch = 2000 End of Tangent End of 3D Arc End of Tangent End of 3D Arc End of Build End of Tangent Tie On Design Comment 12312.93 91.048 6408.01 91.048 4696.60 46.817 2123.84 46.817 700.00 6.000 500.00 0.000 47.00 0.000 MD (ft) Inc (°) 329.354 329.354 300.279 300.279 345.000 345.000 345.000 Az (°) Well Profile Data 4217.47 4325.47 3714.07 1953.46 699.63 500.00 47.00 TVD (ft) 7512.47 2433.13 1306.00 360.09 10.11 0.00 0.00 Local N (ft) -6168.59 -3159.14 -2113.26 -493.19 -2.71 0.00 0.00 Local E (ft) DLS (°/100ft) 0.00 3.00 0.00 3.00 3.00 0.00 0.00 9720.53 3885.20 2350.40 591.27 9.53 0.00 0.00 VS (ft) Rig on B-32 (RT) to Mean Sea Level Mean Sea Level to Ground level (At Slot: B-32) Rig on B-32 (RT) to Ground level (At Slot: B-32) B-32 Slot -171.62 Local N (ft) Pikka Facility Name -1266.60 Local E (ft) 1562148.160 Grid East (US ft) 1563416.330 Grid East (US ft) Location Information Grid North (US ft) Grid North (US ft) 5972499.320 5972657.910 70.47ft 0ft 70.47ft 70°20'7.3005"N 70°20'8.9895"N Latitude Latitude 150°38'6.0633"W Longitude 150°37'29.0730"W Longitude NAD 83 SFD REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDB-032 NAD27 Slot B-32 NAD27 REPORT SETUP INFORMATION Projection System NAD27 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitect® 6.0 North Reference True User Meyedavr Scale 0.999907 Report Generated 6/6/2023 at 10:46:06 AM Convergence at slot 0.60° West Database WellArchitectDB WELLPATH LOCATION Local coordinates Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US ft] Northing[US ft] Latitude Longitude Slot Location -171.34 -1266.64 422115.35 5972751.32 70°20'8.4516"N 150°37'54.7867"W Facility Reference Pt 423383.56 5972909.70 70°20'10.1378"N 150°37'17.7961"W Field Reference Pt 423383.56 5972909.70 70°20'10.1378"N 150°37'17.7961"W WELLPATH DATUM Calculation method Minimum curvature Rig on B-32 NAD27 (RT) to Facility Vertical Datum 70.47ft Horizontal Reference Pt Slot Rig on B-32 NAD27 (RT) to Mean Sea Level 70.47ft Vertical Reference Pt Rig on B-32 NAD27 (RT) Rig on B-32 NAD27 (RT) to Ground Level at Slot (B-32 NAD27) 70.47ft MD Reference Pt Rig on B-32 NAD27 (RT)Section Origin N 0.00, E 0.00 ft Field Vertical Reference Mean Sea Level Section Azimuth 320.61° Actual Wellpath Report NDB-032 Rev A.3 NAD27 Page 1 of 6 Page 1 of 6Wellpath Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDB-032 NAD27 Slot B-32 NAD27 Actual Wellpath Report NDB-032 Rev A.3 NAD27 Page 2 of 6 WELLPATH DATA (130 stations)† = interpolated, ‡ = extrapolated station MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 0.00† 0.000 345.000 0.00 -70.47 0.00 0.00 0.00 422115.35 5972751.32 0.00 47.00 0.000 345.000 47.00 -23.47 0.00 0.00 0.00 422115.35 5972751.32 0.00 147.00 0.000 345.000 147.00 76.53 0.00 0.00 0.00 422115.35 5972751.32 0.00 247.00 0.000 345.000 247.00 176.53 0.00 0.00 0.00 422115.35 5972751.32 0.00 347.00 0.000 345.000 347.00 276.53 0.00 0.00 0.00 422115.35 5972751.32 0.00 447.00 0.000 345.000 447.00 376.53 0.00 0.00 0.00 422115.35 5972751.32 0.00 500.00 0.000 345.000 500.00 429.53 0.00 0.00 0.00 422115.35 5972751.32 0.00 547.00 1.410 345.000 547.00 476.53 0.53 0.56 -0.15 422115.21 5972751.88 3.00 647.00 4.410 345.000 646.85 576.38 5.15 5.46 -1.46 422113.94 5972756.80 3.00 700.00 6.000 345.000 699.63 629.16 9.53 10.11 -2.71 422112.75 5972761.45 3.00 747.00 7.004 336.220 746.33 675.86 14.53 15.10 -4.50 422111.01 5972766.47 3.00 847.00 9.488 324.340 845.30 774.83 28.63 27.38 -11.76 422103.87 5972778.82 3.00 947.00 12.205 317.521 943.51 873.04 47.41 41.88 -23.71 422092.08 5972793.44 3.00 1047.00 15.029 313.192 1040.69 970.22 70.83 58.55 -40.31 422075.66 5972810.28 3.00 1147.00 17.908 310.218 1136.58 1066.11 98.81 77.36 -61.50 422054.66 5972829.30 3.00 1247.00 20.821 308.048 1230.91 1160.44 131.29 98.24 -87.24 422029.14 5972850.45 3.00 1347.00 23.755 306.392 1323.43 1252.96 168.17 121.15 -117.46 421999.17 5972873.67 3.00 1447.00 26.703 305.082 1413.88 1343.41 209.35 146.02 -152.07 421964.82 5972898.90 3.00 1547.00 29.661 304.016 1502.02 1431.55 254.72 172.78 -190.97 421926.20 5972926.06 3.00 1647.00 32.625 303.128 1587.60 1517.13 304.16 201.36 -234.07 421883.41 5972955.08 3.00 1747.00 35.595 302.372 1670.39 1599.92 357.52 231.68 -281.23 421836.57 5972985.89 3.00 1847.00 38.569 301.719 1750.15 1679.68 414.67 263.66 -332.34 421785.80 5973018.39 3.00 1947.00 41.547 301.145 1826.69 1756.22 475.44 297.21 -387.25 421731.24 5973052.51 3.00 2047.00 44.526 300.636 1899.77 1829.30 539.68 332.24 -445.81 421673.05 5973088.14 3.00 2123.84 46.817 300.279 1953.46 1882.99 591.28 360.09 -493.19 421625.97 5973116.48 3.00 2147.00 46.817 300.279 1969.31 1898.84 607.11 368.61 -507.78 421611.47 5973125.15 0.00 2247.00 46.817 300.279 2037.74 1967.27 675.49 405.37 -570.75 421548.90 5973162.56 0.00 2347.00 46.817 300.279 2106.17 2035.70 743.86 442.14 -633.72 421486.32 5973199.97 0.00 2447.00 46.817 300.279 2174.61 2104.14 812.23 478.91 -696.69 421423.74 5973237.39 0.00 2547.00 46.817 300.279 2243.04 2172.57 880.61 515.67 -759.66 421361.16 5973274.80 0.00 Page 2 of 6Wellpath Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDB-032 NAD27 Slot B-32 NAD27 Actual Wellpath Report NDB-032 Rev A.3 NAD27 Page 3 of 6 WELLPATH DATA (130 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 2647.00 46.817 300.279 2311.47 2241.00 948.98 552.44 -822.63 421298.58 5973312.22 0.00 2747.00 46.817 300.279 2379.91 2309.44 1017.36 589.20 -885.60 421236.00 5973349.63 0.00 2847.00 46.817 300.279 2448.34 2377.87 1085.73 625.97 -948.57 421173.42 5973387.04 0.00 2947.00 46.817 300.279 2516.77 2446.30 1154.11 662.73 -1011.54 421110.85 5973424.46 0.00 3047.00 46.817 300.279 2585.21 2514.74 1222.48 699.50 -1074.51 421048.27 5973461.87 0.00 3147.00 46.817 300.279 2653.64 2583.17 1290.86 736.27 -1137.48 420985.69 5973499.29 0.00 3247.00 46.817 300.279 2722.07 2651.60 1359.23 773.03 -1200.45 420923.11 5973536.70 0.00 3347.00 46.817 300.279 2790.51 2720.04 1427.60 809.80 -1263.42 420860.53 5973574.12 0.00 3447.00 46.817 300.279 2858.94 2788.47 1495.98 846.56 -1326.39 420797.95 5973611.53 0.00 3547.00 46.817 300.279 2927.37 2856.90 1564.35 883.33 -1389.36 420735.37 5973648.94 0.00 3647.00 46.817 300.279 2995.80 2925.33 1632.73 920.09 -1452.33 420672.79 5973686.36 0.00 3747.00 46.817 300.279 3064.24 2993.77 1701.10 956.86 -1515.30 420610.22 5973723.77 0.00 3847.00 46.817 300.279 3132.67 3062.20 1769.48 993.62 -1578.27 420547.64 5973761.19 0.00 3947.00 46.817 300.279 3201.10 3130.63 1837.85 1030.39 -1641.24 420485.06 5973798.60 0.00 4047.00 46.817 300.279 3269.54 3199.07 1906.22 1067.16 -1704.21 420422.48 5973836.01 0.00 4147.00 46.817 300.279 3337.97 3267.50 1974.60 1103.92 -1767.18 420359.90 5973873.43 0.00 4247.00 46.817 300.279 3406.40 3335.93 2042.97 1140.69 -1830.15 420297.32 5973910.84 0.00 4347.00 46.817 300.279 3474.84 3404.37 2111.35 1177.45 -1893.12 420234.74 5973948.26 0.00 4447.00 46.817 300.279 3543.27 3472.80 2179.72 1214.22 -1956.08 420172.17 5973985.67 0.00 4547.00 46.817 300.279 3611.70 3541.23 2248.10 1250.98 -2019.05 420109.59 5974023.08 0.00 4647.00 46.817 300.279 3680.14 3609.67 2316.47 1287.75 -2082.02 420047.01 5974060.50 0.00 4696.60 46.817 300.279 3714.08 3643.61 2350.39 1305.99 -2113.26 420015.97 5974079.06 0.00 4747.00 48.008 301.545 3748.18 3677.71 2385.32 1325.05 -2145.09 419984.34 5974098.45 3.00 4847.00 50.409 303.921 3813.52 3743.05 2457.37 1366.00 -2208.75 419921.12 5974140.06 3.00 4947.00 52.856 306.136 3875.59 3805.12 2532.88 1411.02 -2272.92 419857.42 5974185.73 3.00 5047.00 55.341 308.212 3934.23 3863.76 2611.66 1459.97 -2337.44 419793.42 5974235.35 3.00 5147.00 57.859 310.165 3989.27 3918.80 2693.48 1512.73 -2402.13 419729.29 5974288.77 3.00 5247.00 60.405 312.013 4040.58 3970.11 2778.13 1569.15 -2466.80 419665.21 5974345.85 3.00 5347.00 62.976 313.770 4088.00 4017.53 2865.36 1629.08 -2531.28 419601.36 5974406.44 3.00 5447.00 65.568 315.448 4131.41 4060.94 2954.94 1692.34 -2595.39 419537.92 5974470.36 3.00 Page 3 of 6Wellpath Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDB-032 NAD27 Slot B-32 NAD27 Actual Wellpath Report NDB-032 Rev A.3 NAD27 Page 4 of 6 WELLPATH DATA (130 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 5547.00 68.177 317.057 4170.69 4100.22 3046.63 1758.78 -2658.97 419475.04 5974537.45 3.00 5647.00 70.801 318.609 4205.72 4135.25 3140.17 1828.20 -2721.83 419412.91 5974607.51 3.00 5747.00 73.439 320.112 4236.42 4165.95 3235.30 1900.41 -2783.80 419351.70 5974680.35 3.00 5847.00 76.086 321.575 4262.71 4192.24 3331.78 1975.22 -2844.71 419291.58 5974755.79 3.00 5947.00 78.742 323.004 4284.50 4214.03 3429.32 2052.43 -2904.39 419232.70 5974833.60 3.00 6047.00 81.405 324.407 4301.73 4231.26 3527.67 2131.81 -2962.69 419175.24 5974913.58 3.00 6147.00 84.073 325.790 4314.37 4243.90 3626.55 2213.16 -3019.44 419119.35 5974995.51 3.00 6247.00 86.744 327.161 4322.38 4251.91 3725.69 2296.25 -3074.48 419065.17 5975079.15 3.00 6347.00 89.417 328.523 4325.73 4255.26 3824.83 2380.85 -3127.67 419012.87 5975164.30 3.00 6408.01 91.048 329.354 4325.48 4255.01 3885.19 2433.11 -3159.15 418981.94 5975216.87 3.00 6447.00 91.048 329.354 4324.76 4254.29 3923.73 2466.65 -3179.02 418962.42 5975250.61 0.00 6547.00 91.048 329.354 4322.94 4252.47 4022.55 2552.67 -3229.98 418912.36 5975337.15 0.00 6647.00 91.048 329.354 4321.11 4250.64 4121.37 2638.69 -3280.95 418862.29 5975423.69 0.00 6747.00 91.048 329.354 4319.28 4248.81 4220.19 2724.71 -3331.91 418812.23 5975510.22 0.00 6847.00 91.048 329.354 4317.45 4246.98 4319.01 2810.73 -3382.88 418762.17 5975596.76 0.00 6947.00 91.048 329.354 4315.62 4245.15 4417.83 2896.75 -3433.84 418712.10 5975683.29 0.00 7047.00 91.048 329.354 4313.79 4243.32 4516.65 2982.76 -3484.81 418662.04 5975769.83 0.00 7147.00 91.048 329.354 4311.96 4241.49 4615.47 3068.78 -3535.77 418611.97 5975856.36 0.00 7247.00 91.048 329.354 4310.13 4239.66 4714.30 3154.80 -3586.73 418561.91 5975942.90 0.00 7347.00 91.048 329.354 4308.30 4237.83 4813.12 3240.82 -3637.70 418511.85 5976029.43 0.00 7447.00 91.048 329.354 4306.47 4236.00 4911.94 3326.84 -3688.66 418461.78 5976115.97 0.00 7547.00 91.048 329.354 4304.65 4234.18 5010.76 3412.86 -3739.63 418411.72 5976202.50 0.00 7647.00 91.048 329.354 4302.82 4232.35 5109.58 3498.88 -3790.59 418361.65 5976289.04 0.00 7747.00 91.048 329.354 4300.99 4230.52 5208.40 3584.90 -3841.56 418311.59 5976375.57 0.00 7847.00 91.048 329.354 4299.16 4228.69 5307.22 3670.92 -3892.52 418261.53 5976462.11 0.00 7947.00 91.048 329.354 4297.33 4226.86 5406.04 3756.93 -3943.49 418211.46 5976548.64 0.00 8047.00 91.048 329.354 4295.50 4225.03 5504.87 3842.95 -3994.45 418161.40 5976635.18 0.00 8147.00 91.048 329.354 4293.67 4223.20 5603.69 3928.97 -4045.42 418111.33 5976721.72 0.00 8247.00 91.048 329.354 4291.84 4221.37 5702.51 4014.99 -4096.38 418061.27 5976808.25 0.00 8347.00 91.048 329.354 4290.01 4219.54 5801.33 4101.01 -4147.35 418011.21 5976894.79 0.00 Page 4 of 6Wellpath Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDB-032 NAD27 Slot B-32 NAD27 Actual Wellpath Report NDB-032 Rev A.3 NAD27 Page 5 of 6 WELLPATH DATA (130 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 8447.00 91.048 329.354 4288.18 4217.71 5900.15 4187.03 -4198.31 417961.14 5976981.32 0.00 8547.00 91.048 329.354 4286.36 4215.89 5998.97 4273.05 -4249.28 417911.08 5977067.86 0.00 8647.00 91.048 329.354 4284.53 4214.06 6097.79 4359.07 -4300.24 417861.02 5977154.39 0.00 8747.00 91.048 329.354 4282.70 4212.23 6196.61 4445.09 -4351.21 417810.95 5977240.93 0.00 8847.00 91.048 329.354 4280.87 4210.40 6295.44 4531.10 -4402.17 417760.89 5977327.46 0.00 8947.00 91.048 329.354 4279.04 4208.57 6394.26 4617.12 -4453.13 417710.82 5977414.00 0.00 9047.00 91.048 329.354 4277.21 4206.74 6493.08 4703.14 -4504.10 417660.76 5977500.53 0.00 9147.00 91.048 329.354 4275.38 4204.91 6591.90 4789.16 -4555.06 417610.70 5977587.07 0.00 9247.00 91.048 329.354 4273.55 4203.08 6690.72 4875.18 -4606.03 417560.63 5977673.60 0.00 9347.00 91.048 329.354 4271.72 4201.25 6789.54 4961.20 -4656.99 417510.57 5977760.14 0.00 9447.00 91.048 329.354 4269.89 4199.42 6888.36 5047.22 -4707.96 417460.50 5977846.67 0.00 9547.00 91.048 329.354 4268.07 4197.60 6987.18 5133.24 -4758.92 417410.44 5977933.21 0.00 9647.00 91.048 329.354 4266.24 4195.77 7086.01 5219.26 -4809.89 417360.38 5978019.75 0.00 9747.00 91.048 329.354 4264.41 4193.94 7184.83 5305.28 -4860.85 417310.31 5978106.28 0.00 9847.00 91.048 329.354 4262.58 4192.11 7283.65 5391.29 -4911.82 417260.25 5978192.82 0.00 9947.00 91.048 329.354 4260.75 4190.28 7382.47 5477.31 -4962.78 417210.19 5978279.35 0.00 10047.00 91.048 329.354 4258.92 4188.45 7481.29 5563.33 -5013.75 417160.12 5978365.89 0.00 10147.00 91.048 329.354 4257.09 4186.62 7580.11 5649.35 -5064.71 417110.06 5978452.42 0.00 10247.00 91.048 329.354 4255.26 4184.79 7678.93 5735.37 -5115.68 417059.99 5978538.96 0.00 10347.00 91.048 329.354 4253.43 4182.96 7777.75 5821.39 -5166.64 417009.93 5978625.49 0.00 10447.00 91.048 329.354 4251.60 4181.13 7876.58 5907.41 -5217.61 416959.87 5978712.03 0.00 10547.00 91.048 329.354 4249.78 4179.31 7975.40 5993.43 -5268.57 416909.80 5978798.56 0.00 10647.00 91.048 329.354 4247.95 4177.48 8074.22 6079.45 -5319.53 416859.74 5978885.10 0.00 10747.00 91.048 329.354 4246.12 4175.65 8173.04 6165.46 -5370.50 416809.67 5978971.63 0.00 10847.00 91.048 329.354 4244.29 4173.82 8271.86 6251.48 -5421.46 416759.61 5979058.17 0.00 10947.00 91.048 329.354 4242.46 4171.99 8370.68 6337.50 -5472.43 416709.55 5979144.70 0.00 11047.00 91.048 329.354 4240.63 4170.16 8469.50 6423.52 -5523.39 416659.48 5979231.24 0.00 11147.00 91.048 329.354 4238.80 4168.33 8568.32 6509.54 -5574.36 416609.42 5979317.77 0.00 11247.00 91.048 329.354 4236.97 4166.50 8667.15 6595.56 -5625.32 416559.35 5979404.31 0.00 11347.00 91.048 329.354 4235.14 4164.67 8765.97 6681.58 -5676.29 416509.29 5979490.85 0.00 Page 5 of 6Wellpath Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 NAD27 Field Pikka NAD27 API/Legal Facility Pikka NAD27 Wellbore NDB-032 NAD27 Slot B-32 NAD27 Actual Wellpath Report NDB-032 Rev A.3 NAD27 Page 6 of 6 WELLPATH DATA (130 stations) MD [ft] Inclination [°] Azimuth [°] TVD [ft] TVDSS [ft] Vert Sect [ft] North [ft] East [ft] Grid East [US ft] Grid North [US ft] DLS [°/100ft] 11447.00 91.048 329.354 4233.31 4162.84 8864.79 6767.60 -5727.25 416459.23 5979577.38 0.00 11547.00 91.048 329.354 4231.49 4161.02 8963.61 6853.62 -5778.22 416409.16 5979663.92 0.00 11647.00 91.048 329.354 4229.66 4159.19 9062.43 6939.63 -5829.18 416359.10 5979750.45 0.00 11747.00 91.048 329.354 4227.83 4157.36 9161.25 7025.65 -5880.15 416309.04 5979836.99 0.00 11847.00 91.048 329.354 4226.00 4155.53 9260.07 7111.67 -5931.11 416258.97 5979923.52 0.00 11947.00 91.048 329.354 4224.17 4153.70 9358.89 7197.69 -5982.08 416208.91 5980010.06 0.00 12047.00 91.048 329.354 4222.34 4151.87 9457.72 7283.71 -6033.04 416158.84 5980096.59 0.00 12147.00 91.048 329.354 4220.51 4150.04 9556.54 7369.73 -6084.01 416108.78 5980183.13 0.00 12247.00 91.048 329.354 4218.68 4148.21 9655.36 7455.75 -6134.97 416058.72 5980269.66 0.00 12312.93 91.048 329.354 4217.48 4147.01 9720.51 7512.46 -6168.57 416025.71 5980326.72 0.00 WELLPATH COMPOSITION - Ref Wellbore: NDB-032 NAD27 Ref Wellpath: NDB-032 Rev A.3 NAD27 Start MD [ft] End MD [ft] Positional Uncertainty Model Log Name/Comment Wellbore Survey Date 47.00 12312.93 BH No Uncertainty Plan NDB-032 NAD27 5/31/2023 Page 6 of 6Wellpath Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_NAD27.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 Field Pikka API/Legal Facility Pikka Wellbore NDB-032 Slot B-32 REPORT SETUP INFORMATION Projection System NAD83 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitect® 6.0 North Reference True User Meyedavr Scale 0.999907 Report Generated 6/6/2023 at 10:30:16 AM Convergence at slot 0.60° West Database WellArchitectDB WELLPATH LOCATION Local coordinates Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US ft] Northing[US ft] Latitude Longitude Slot Location -171.62 -1266.60 1562148.16 5972499.32 70°20'7.3005"N 150°38'6.0633"W Facility Reference Pt 1563416.33 5972657.91 70°20'8.9895"N 150°37'29.0730"W Field Reference Pt 1563416.33 5972657.91 70°20'8.9895"N 150°37'29.0730"W WELLPATH DATUM Calculation method Minimum Curvature Rig on B-32 (RT) to Facility Vertical Datum 70.47ft Horizontal Reference Pt Slot RigonB-32(RT)toMeanSeaLevel 70.47ft Vertical Reference Pt Rig on B-32 (RT) RigonB-32(RT)toGroundLevelat Slot (B-32) 70.47ft MD Reference Pt Rig on B-32 (RT) Field Vertical Reference Mean Sea Level Closest Approach Clearance Summary Report NDB-032 Rev A.3 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 1 of 3 POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 2.79 Std Dev Ellipse Start MD 47.00ft Surface Position Uncertainty included Declination 14.80° East of TN Dip Angle 80.59°Mag Field Strength 57197 nT Slot Surface Uncertainty @1SD Horizontal 0.500ft Vertical 0.500ft Facility Surface Uncertainty @1SD Horizontal 20.000ft Vertical 3.000ft Positional Uncertainty values in the WELLPATH DATA table are the projection of the ellipsoid of uncertainty onto the vertical and horizontal planes Page 1 of 3Clearance Summary Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_CR.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 Field Pikka API/Legal Facility Pikka Wellbore NDB-032 Slot B-32 Closest Approach Clearance Summary Report NDB-032 Rev A.3 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 2 of 3 PROXIMITY-SCAN RULE Rule Name Santos - Stop Drilling HSE Risk (SF <1.25)Rule Based On Ratio Plane of Rule Closest Approach Threshold Value 1.25 IncludeCasing&HoleSize yes Apply Cone of Safety no HOLE & CASING SECTIONS - Ref Wellbore: NDB-032 Ref Wellpath: NDB-032 Rev A.3 String/Diameter Start MD [ft] End MD [ft] Interval [ft] Start TVD [ft] End TVD [ft] Start N/S [ft] Start E/W [ft] End N/S [ft] End E/W [ft] 13.375in Casing Surface 47.00 2633.89 2586.89 47.00 2302.50 0.00 0.00 547.62 -814.37 9.625in Casing Intermediate 47.00 5908.00 5861.00 47.00 4276.53 0.00 0.00 2022.06 -2881.27 4.5in Casing Production 47.00 12312.93 12265.93 47.00 4217.47 0.00 0.00 7512.47 -6168.59 SURVEY PROGRAM - Ref Wellbore: NDB-032 Ref Wellpath: NDB-032 Rev A.3 Start MD [ft] End MD [ft] Positional Uncertainty Model Log Name/Comment Wellbore 47.00 2633.90 OWSG MWD rev2 (MS+IFR2, SAG) NDB-032 2633.90 5908.00 OWSG MWD rev2 (MS+IFR2, SAG) NDB-032 5908.00 12312.93 OWSG MWD rev2 (MS+IFR2, SAG) NDB-032 Page 2 of 3Clearance Summary Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_CR.xml REFERENCE WELLPATH IDENTIFICATION Operator Santos Well NDB-032 Field Pikka API/Legal Facility Pikka Wellbore NDB-032 Slot B-32 CALCULATION RANGE & CUTOFF From:47.00ft MD To:12312.93ft MD C-C Cutoff:(none) Closest Approach Clearance Summary Report NDB-032 Rev A.3 -Santos - Stop Drilling HSE Risk (SF <1.25) Page 3 of 3 OFFSET WELL CLEARANCE SUMMARY (14 Offset Wellpaths selected) Ratios are calculated in Closest Approach plane Offset Facility Offset Slot Offset Well Offset Wellbore Offset Wellpath Wellbore Status C-C Clearance Distance Rule Separation Ratio Ref MD [ft] Min C-C Clear Dist [ft] Diverging from MD [ft] Ref MD of Min Ratio [ft] Min Ratio Min Ratio Dvrg from [ft] Rule Status Pikka B-24 NDB- 024 NDB-024 NDB-024 Rev A.1 Planned 12312.93 84.42 12312.93 12312.93 1.17 12312.93 FAIL Pikka B-31 B-31 B-31 B-31 Rev A.0 Planned 47.00 19.01 447.00 526.78 2.10 526.78 PASS Pikka B-33 B-33 B-33 B-33 Rev A.0 Planned 47.00 20.99 347.00 493.63 2.38 493.63 PASS Pikka B-34 B-34 B-34 B-34 Rev A.0 Planned 399.13 41.03 6447.00 523.20 4.89 11547.00 PASS Pikka B-30 NDBi- 030 NDBi-030 NDBi-030 Rev B.1 Planned 47.00 39.86 12312.93 913.33 5.31 12312.93 PASS Pikka B-26 B-26 B-26 B-26 Rev A.0 Planned 816.25 116.85 12312.93 12312.93 6.41 12312.93 PASS Pikka B-37 B-37 B-37 B-37 Rev A.0 Planned 419.77 101.15 12312.93 12312.93 6.66 12312.93 PASS Pikka B-27 B-27 B-27 B-27 Rev A.0 Planned 897.68 94.47 8647.00 12312.93 7.80 12312.93 PASS Pikka B-39 B-39 B-39 B-39 Rev A.0 Planned 431.29 141.14 431.29 2467.28 8.22 9947.00 PASS Pikka B-28 B-28 B-28 B-28 Rev A.0 Planned 393.88 79.10 393.88 721.37 8.89 3547.00 PASS Pikka B-36 B-36 B-36 B-36 Rev A.0 Planned 47.00 81.12 447.00 673.72 9.40 673.72 PASS Pikka B-38 B-38 B-38 B-38 Rev A.0 Planned 47.00 121.21 347.00 601.92 13.99 2547.00 PASS Pikka B-25 B-25 NBD-025 NBD-025 Rev A.0 Planned 491.04 139.22 9047.00 810.51 15.56 9947.00 PASS Pikka B-40 B-40 B-40 B-40 Rev A.0 Planned 47.00 161.20 347.00 684.70 19.07 2547.00 PASS Page 3 of 3Clearance Summary Report 6/6/2023file:///C:/WellArchitect/NDB-032_Rev_A.3_CR.xml NDB-032 PTD V1 - 25 - 10-Jul-23 Attachment 3: BOPE Equipment 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#FORWARD 13-5/8" X 5,000#13-5/8" X 5,000#30"13-5/8" X 5,000#186"13-5/8" X 5,000#DUTCH LOCK DOWN ChokeLinefromBOPPressureGauge1502PressureSensorPressureTransducerBill ofMaterialItemDescriptionToPanicLineItemDescriptionA3Ͳ1/8”– 5,000psi W.P.RemoteHydraulicOperatedChokeB3Ͳ1/8”–5,000psiW.P.AdjustableManualChoke1–14 3Ͳ1/8”– 5,000psi W.P.ManualGateValve1521/16”5 000 i WP152Ͳ1/16”–5,000psiW.P.ManualGateValveToMudGasLegendBlindSpareToTigerTankSeparatorValveNormally OpenValveNormally Closed NDB-032 PTD V1 - 29 - 10-Jul-23 Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (mud loggers, trained drilling personnel). Shallow Fault Fault crossing in shallow hole section. Well trajectory is parallel to the fault, but the fault appears to be very small but could potentially present a lost circulation or WBS risk 12-1/4” Intermediate Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Drill with oil based mud, maintain mud in specifications, use sufficient mud weight to hold back formations. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Fault Crossings Two planned fault crossings in the intermediate section. Both are minor and lost circulation / WBS risk is considered low. An additional minor fault crossing has been identified below the intermediate casing shoe. The intermediate casing point has been adjusted shallower to mitigate potential issues during the casing running / cement job. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. NDB-032 PTD V1 - 30 - 10-Jul-23 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. NDB-032 PTD V1 - 31 - 10-Jul-23 Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. NDB-032 PTD V1 - 32 - 10-Jul-23 Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 BTC Surface Casing Basis Lead Open hole volume + 250% excess in permafrost / 40% excess below permafrost Lead TOC Surface Tail Open hole volume + 40% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~60 bbls of 10.5 ppg Clean Spacer Lead 397.5 bbls, 2232 cuft, 780 sks of 10.7 ppg ArcticCem, Yield: 2.86 cuft/sk Tail 65.2 bbls, 366 cuft, 293 sks 15.3 ppg HalCem Type I/II – 1.25 cuft/sk Temp BHST 53° F Verification Method Cement returns to surface Notes Job will be mixed on the fly Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 30% excess + 150’ liner lap Lead TOC Top of the 9-5/8” Liner Tail Open hole volume + 30% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 11.8 ppg Clean Spacer Lead 221.7 bbls, 1241 cuft, 523 sks of 12.0 ppg ExtendaCem, Yield: 2.38 cuft/sk Tail 42.5 bbls, 239 cuft, 194 sks 15.3 ppg VersaCem Type I/II – 1.23 cuft/sk Temp BHST 98° F Verification Method Cement returns off top of liner, Ultrasonic wireline log / LWD Sonic log Notes Job will be mixed on the fly Verified cement calcs. -bjm Verified cement calcs. -bjm NDB-032 PTD V1 - 33 - 10-Jul-23 Attachment 7: Prognosed Formation Tops NDB-032 Prognosed Tops Formation MD (ft) TVD KB (ft) TVD SS (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1053 1047 976 100 7.3 Permafrost Base 1147 1137 1066 100 7.6 Middle Schrader Bluff 1834 1741 1670 100 7.8 MCU (Lwr. Sch. Bluff) 2411 2153 2082 100 7.9 Tuluvak Shale 2866 2468 2397 100 7.9 Tuluvak Sand 2958 2532 2461 100 10.1 Seabee 3946 3216 3145 100 9.1 Nanushuk 4884 3855 3784 100 8.9 NT6 MFS 5041 3947 3876 100 8.9 NT5 MFS 5226 4043 3972 100 8.8 NT4 MFS 5336 4094 4023 100 8.8 NT3 MFS 6050 4302 4231 100 8.7 NT3.2 Top Reservoir (NT3) 6257 4323 4252 100 8.7 NDB-032 PTD V1 - 34 - 10-Jul-23 Attachment 8: Well Schematic NDB-032 PTD V1 - 35 - 10-Jul-23 Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole LWD Gamma Ray Resistivity Density Neutron Cased Hole Wireline Ultra-Sonic Cement Bond Log (9-5/8” liner cement evaluation) 8-1/2” Production Hole LWD Gamma Ray Resistivity Density Neutron Ultra-Deep Resistivity Sonic (9-5/8” liner cement evaluation) Mudlogging and Sample Program Mudlogging will be utilized from surface to TD on NDB-032. Dried cuttings samples will be collected at 30ft intervals from surface to intermediate TD. Cuttings sampling in the production section will be collected at 50ft intervals. 50 ft intervals, per M. Staudinger. -BJM NDB-032 PTD V1 - 36 - 10-Jul-23 Attachment 10: Wellhead & Tree Diagram From:Staudinger, Mark (Mark) To:McLellan, Bryan J (OGC) Subject:RE: NDB-032 PTD Application Date:Friday, July 28, 2023 11:57:56 AM Attachments:image003.jpg image004.jpg image005.png image002.jpg Hey Bryan, I wanted to give you a list of changes to the PTD application for NDB-032. Apologize for all the changes, but things are very dynamic as we are just kicking off our campaign. The list of changes to the PTD application are as follows: 1. Section 8: Decrease in Surface Hole MW to 10.0 ppg – justification is detailed in the email below. 2. Section 8 & 13: Increase in Surface Hole MW to 11.5 ppg – justification detailed in email below. 3. Section 4: New calculated minimum LOT at the 13-3/8” Surface shoe is 13.3 ppg EMW. This is driven by the higher INT Hole MW requirement. 4. Attachment 9: Mudlogging will still be utilized from surface to TD. However, we’d like to increase the range of sample collection frequency from 30’ to 50’ from surface to intermediate TD. The subsurface team said they don’t need as tight of a sample collection frequency. 5. Cover Letter & PTD Application: Due to a potential acceleration of the rig schedule, I anticipate an approximate spud date now of 08/10/2023. Let me know if you have any questions on the above changes. Have a good weekend! Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Staudinger, Mark (Mark) Sent: Tuesday, July 25, 2023 7:57 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDB-032 PTD Application Hey Bryan, Thanks, I don’t see anywhere else in the permit that needs updating for the surface MW. On a related note to MW, I think we are going to also increase the intermediate MW to start with 11.5ppg. This will also be a slight change from the PTD (Section 8 and Section 13). We are experiencing Wellbore Stability issues on the current well B-43, so hoping that some additional MW will help with the issues. These mud weight changes may drive slight changes to the cement spacer densities and/or volumes. Would you like to be notified of small changes like that? No changes for the directional plan. I only forwarded you the original permit application since you weren’t on the original email chain. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, July 24, 2023 4:38 PM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: RE: NDB-032 PTD Application Mark, I’ve edited the PTD application, section 8, to show you’ll use 10.0 ppg mud for surface hole. Is there anywhere else in the procedure that surface hole mud weight needs updating? Also, I noticed that you attached a directional survey to your email. Is that different than the one included with the PTD you submitted a couple weeks ago? Wondering why you attached it? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, July 24, 2023 2:17 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: NDB-032 PTD Application Bryan, We submitted the PTD application for NDB-032 a couple or weeks ago. I’d like to make a minor change to the surface hole Mud Weight for this well from what is stated in the PTD application. We would like to drop the MW from 10.5ppg to 10.0ppg. The reason is that we have been fighting surface hole on the previous 2 wells drilled. The higher 10.5ppg MW makes the dilution more difficult, and has caused issues with keeping the rheology in spec. We would like to try a reduction in MW, which should allow the rig team to keep the dilution rates higher. Additionally, the 10.5ppg MW was originally chosen based on some gas they had seen when drilling Pikka C Appraisal well, but at ND-B we really haven’t seen much for gas except small shows when drilling hydrates near the base of the perm. Therefore, the reduction of MW to 10.0ppg doesn’t cause any concerns from the team here. The highest pore pressure in the surface hole is predicted at 7.9ppg EMW. Let me know if you have any questions on this change. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Sent: Monday, July 10, 2023 12:42 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: NDB-032 PTD Application Hello, Please see attached the PTD Application for NDB-032. 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 Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. NANUSHUK OILPIKKA 223-060 PIKKA NDB 032 WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-032Initial Class/TypeDEV / PENDGeoArea890Unit11580On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230600PIKKA, NANUSHUK OIL - 600100NA1 Permit fee attachedYes Surface Location lies within ADL0392984; Top Productive Interval lies in ADL0391445; TD lies in ADL0393020.2 Lease number appropriateYes3 Unique well name and numberYes PIKKA, NANUSHUK OIL - 600100 - governed by CO 8074 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1529 psi, BOP rated to 5000 psi, (BOP test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S measures not required: None anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Abnormal Pressure: high risk, Tuluvak expected at 10.1 ppg. Surface casing will be set above Tuluvak.36 Data presented on potential overpressure zonesNA Other mitigation discussed on p. 5. Faulting: high risk, two crossing expected, see p. 29.37 Seismic analysis of shallow gas zonesNA Gas hydrates, lost circulation, hole swabbing, and stuck pipe: some risk, mitigation discussed on p. 29 & 30.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate8/1/2023ApprBJMDate7/28/2023ApprSFDDate8/1/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 08/01/2023JLC 8/1/2023
