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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 . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : GR - R E S - N E U - D E N - S o n i c , I m a g e , M u d l o g s 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 4/ 2 4 / 2 0 2 4 15 0 1 7 5 2 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ L W D l _ R M _ 1 7 5 2 9 f t . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ A P _ R 0 1 _ R M _ 2 0 2 4 0 2 1 9 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ A P _ R 0 2 _ R M _ 2 0 2 4 0 3 0 3 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ A P _ R 0 3 _ R M _ 2 0 2 4 0 3 0 9 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ A P _ R 0 4 _ R M _ 2 0 2 4 0 3 1 6 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ A P _ R 0 5 _ R M _ 2 0 2 4 0 3 1 8 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ A P _ R 0 6 _ R M _ 2 0 2 4 0 3 2 3 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 10 0 1 7 5 2 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M D _ R M _ 1 7 5 2 9 f t . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M T _ R 0 1 _ 2 0 2 4 0 2 1 9 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M T _ R 0 2 _ 2 0 2 4 0 3 0 3 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M T _ R 0 3 _ 2 0 2 4 0 3 0 9 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M T _ R 0 4 _ 2 0 2 4 0 3 1 6 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M T _ R 0 5 _ 2 0 2 4 0 3 1 8 . l a s 38 7 3 7 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a 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 i - , 030 _ L W D l _ R M _17 5 2 9ft. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s DF 4/ 2 4 / 2 0 2 4 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D M T _ R 0 6 _ 2 0 2 4 0 3 2 3 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 70 0 0 1 1 2 5 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 70 0 0 1 1 2 5 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 70 0 0 1 1 2 5 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 70 0 0 1 1 2 5 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 11 0 8 0 1 7 5 2 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 0 3 0 L W D Re s i s t i v i t y F i n a l . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 12 8 1 7 5 2 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 0 3 0 GE O I S T O P E S G 5 C O R R E C T E D da t a _ 1 7 5 2 9 f t _ F i n a l . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 12 8 1 7 5 2 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D r i l l G a s _ d e p t h _ 1 7 5 2 9 f t M D . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 12 8 1 7 5 2 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 03 0 _ D r i l l G a s _ L i t h o l o g y _ d e p t h _ 1 7 5 2 9 f t M D . l a s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e f i n i t i v e C o m p a s s Su r v e y R e p o r t - N A D 2 7 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e f i n i t i v e C o m p a s s Su r v e y R e p o r t - N A D 8 3 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e f i n i t i v e S u r v e y Re p o r t - N A D 2 7 . t x t 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e f i n i t i v e S u r v e y Re p o r t - N A D 8 3 . t x t 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 P l a n V i e w . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 V e r t i c a l S e c t i o n . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ 1 - 2 0 0 f t M D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ 1 - 2 0 0 f t M D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ 1 - 4 0 f t M D . c g m 38 7 3 7 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a g e 2 o f 7 ND B i - , 030 _ D r i l l G a s _ L i t h o l o gy _d e p t h _ 1 7 5 2 9 f t M D . 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 . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ 1 - 4 0 f t M D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ 1 - 5 0 0 f t M D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ 1 - 5 0 0 f t M D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L W D _ I M G 1 0 0 _ I T K - PR O C _ 1 1 2 0 9 f t - 1 7 4 7 5 f t _ V 2 . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 _ d l i s . t x t 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . P D F 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 _ d l i s . t x t 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ 9 _ 6 2 5 _ L i n e r _ B a k e r _ H u g h e s _ C B L _ F i n a l Re p o r t . V 2 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ C B L _ 7 0 0 0 _ 1 1 2 0 1 _ d l i s . t x t 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . c g m 38 7 3 7 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a 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 . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 . P D F 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ S D T K _ T O C _ 7 0 0 0 _ 1 1 2 0 1 _ d l i s . t x t 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _2 M D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _2 T V D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _5 M D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _5 T V D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ A P _ R M _ 2 0 2 4 0 3 2 3 . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ D M D _ R M _ 1 7 5 2 9 f t . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ D M T _ R M _ 2 0 2 4 0 3 2 3 . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _2 M D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _2 T V D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _5 M D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 7 5 2 9 f t _5 T V D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ A P _ R M _ 2 0 2 4 0 3 2 3 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ D M D _ R M _ 1 7 5 2 9 f t . p d f 38 7 3 7 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a 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 . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 03 0 _ D M T _ R M _ 2 0 2 4 0 3 2 3 . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l M D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l T V D . c g m 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l M D . e m f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l T V D . e m f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ E a r t h S t a r _ I m a g e s . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ E a r t h s t a r _ I m a g e s . v e r 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ S t r a t a s t a r _ I m a g e s . d l i s 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ S t r a t a s t a r _ I m a g e s . v e r 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l M D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l T V D . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y F i n a l MD . t i f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 D e e p R e s i s t i v i t y L W D Fi n a l T V D . t i f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 M u d l o g g i n g D a i l y Re p o r t s c o m p i l a t i o n . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ G 5 D e l t a G a s Ra t i o s _ C o m p o s i t e _ F i n a l . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ G 5 D e l t a Ga s _ G E O I S O T O P E S _ C o m p o s i t e _ F i n a l . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ G a s R a t i o L o g _ 1 7 5 2 9 f t MD _ 2 i n c h . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ G a s R a t i o L o g _ 1 7 5 2 9 f t MD _ 5 i n c h . p d f 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ L i t h o l o g y . x l s x 38 7 3 7 ED Di g i t a l D a t a DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ M u d L o g _ 1 7 5 2 9 f t MD _ 2 i n c h . p d f 38 7 3 7 ED Di g i t a l D a t a We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a 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 . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : 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 : 3 / 2 6 / 2 0 2 4 Re l e a s e D a t e : 1/ 2 9 / 2 0 2 4 DF 4/ 2 4 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 3 0 _ M u d L o g _ 1 7 5 2 9 f t MD _ 5 i n c h . p d f 38 7 3 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 i - 0 3 0 _ R e v A_ S i g n e d . p d f 39 8 3 2 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 i - 0 3 0 _ E n d o f W e l l C l e a n - u p D a t a R e p o r t _ 1 - m i n _ F i n a l D a t a . x l s x 39 8 3 2 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 i - 0 3 0 _ E n d o f W e l l C l e a n - u p D a t a R e p o r t _ 3 0 m i n u t e _ F i n a l Da t a . x l s x 39 8 3 2 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 11 0 4 5 1 7 4 7 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 i - 03 0 _ B H P _ 8 _ 5 i n _ 1 1 2 0 0 _ 1 7 4 3 . 6 f t _ R u n 6 . l a s 41 1 2 1 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 E l e c t r o n i c F i l e : S A N T O S _ N D B i - 03 0 _ B H P _ 8 _ 5 i n _ 1 1 2 0 0 _ 1 7 4 3 . 6 f t _ R u n 6 . d l i s 41 1 2 1 ED Di g i t a l D a t a 3/ 2 8 / 2 0 2 4 12 0 1 7 5 2 9 12 1 8 7 5 Cu t t i n g s We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a 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 . 50 - 1 0 3 - 2 0 8 7 3 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 3 0 Co m p l e t i o n S t a t u s WA G I N Co m p l e t i o n D a t e 3/ 2 6 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 2 0 0 Op e r a t o r Oi l S e a r c h ( A l a s k a ) , L L C MD 17 5 2 9 TV D 41 4 1 Cu r r e n t S t a t u s WA G I N 1/ 1 4 / 2 0 2 6 UI C Ye s Co m p l i a n c e R e v i e w e d B y : Da t e : We d n e s d a y , J a n u a r y 1 4 , 2 0 2 6 AO G C C P a g e 7 o f 7 1/ 1 6 / 2 0 2 6 M. G u h l LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Well clean up data for 19 wells Details are provided on following pages with well name and API table as reference. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/20/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.21 09:00:44 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043A 50103208590100 NDBi-044 50103208650000 NDBi-046L1 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 جؐؐؐNDB-010 ؒ Santos_Pikka_NDB-010_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-010_End of Well Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-010_Rev A (1).pdf ؒ جؐؐؐNDB-011 ؒ Santos_Pikka_NDB-011_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-011_End of Well Data Report_30 Min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-011_Rev A (1).pdf ؒ جؐؐؐNDB-014 ؒ Santos_Pikka_NDBi-014_End of Well Clean-up Data Report_30 Minute_Final Data.xlsx ؒ Santos_Pikka_NDBi-014__End of Well Clean-up Data Report_1 Minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-014_Rev A_Signed.pdf ؒ جؐؐؐNDB-024 ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_ 30-min_Final (2).xlsx ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_1-min_Final (2).xlsx ؒ WT-XAK-0127.2_End of Well Clean-Up Data Report_NDB-024_Rev A_Signed.pdf 225-061 T41152 225-048 T41153 223-076 T39828 223-105 T39831 NDBi-030 50103208730000 LETTER OF TRANSMITTAL ؒ جؐؐؐNDB-025 ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf ؒ جؐؐؐNDB-031 ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf ؒ جؐؐؐNDB-032 ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-037 ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-048 ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-051 ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf ؒ جؐؐؐNDBi-016 ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf ؒ جؐؐؐNDBi-018 ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf ؒ جؐؐؐNDBi-030 224-006 T41154 225-028 T41155 224-124 T41156 224-143 T41157 224-105 T41158 224-085 T41159 224-013 T39830 223-006 T39829 223-120 T39832 NDBi-030 LETTER OF TRANSMITTAL ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf ؒ جؐؐؐNDBi-036 ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf ؒ جؐؐؐNDBi-043A ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf ؒ جؐؐؐNDBi-044 ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf ؒ جؐؐؐNDBi-046L1 ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf ؒ جؐؐؐNDBi-049 ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf ؒ ؤؐؐؐNDBi-050 Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf 225-012 T41160 224-119 T41161 224-154 T41162 223-052 T39834 223-087 T39835 224-029 T39837 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Baker Hughes has provided us with LithTrak Azimuthal Caliper data for all 22 previous wells. Details are provided on following pages with well name and API table as reference. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/18/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.19 08:30:05 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDB-027 50103209220000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043 50103208590000 NDBi-044 50103208650000 NDBi-046 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 DW-02 50103208550000 PWD-02 50103208790000 جؐؐؐDW-02 Lithotrak Caliper data ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.dlis ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.las ؒ جؐؐؐNDB-010 Lithotrak Caliper data ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.dlis ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.las ؒ جؐؐؐNDB-011 Lithotrak Caliper data ؒ جؐؐؐ12.25 in ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.dlis ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.las ؒ ؒ ؒ ؤؐؐؐ8.5 in ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.dlis 223-039 T41107 225-061 T41108 225-048 T41109 NDBi-030 50103208730000 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.las ؒ جؐؐؐNDB-024 Lithotrak Caliper data ؒ جؐؐؐRun 6 ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.dlis ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.las ؒ ؒ ؒ ؤؐؐؐRun 7 ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.dlis ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.las ؒ جؐؐؐNDB-025 Lithotrak Caliper data ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.dlis ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.las ؒ جؐؐؐNDB-027 Lithotrak Caliper data ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.dlis ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.las ؒ جؐؐؐNDB-031 Lithotrak Caliper data ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.dlis ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.las ؒ جؐؐؐNDB-032 Lithotrak Caliper data ؒ جؐؐؐRun 3 ؒ ؒ SANTOS_NDB-032_BHP_12_25_2598_6224ft_Run3.las ؒ ؒ SANTOS_NDB_032_BHP_12_25_2598_6224ft_Run3.dlis ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.dlis ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.las ؒ جؐؐؐNDB-037 Lithotrak Caliper data ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.dlis ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.las ؒ جؐؐؐNDB-048 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.dlis ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 223-076 T41110 224-006 T41111 225-066 T41112 225-028 T41113 223-060 T41114 224-124 T41115 224-143 T41116 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.dlis ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.las ؒ جؐؐؐNDB-051 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.dlis ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.dlis ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.las ؒ جؐؐؐNDBi-014 Lithotrak Caliper data ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.dlis ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.las ؒ جؐؐؐNDBi-016 Lithotrak Caliper data ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4.las ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4_1.dlis ؒ جؐؐؐNDBi-018 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.dlis ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.dlis ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.las ؒ جؐؐؐNDBi-030 Lithotrak Caliper data ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.dlis ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.las ؒ جؐؐؐNDBi-036 Lithotrak Caliper data ؒ جؐؐؐRun 4 ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.dlis ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.las ؒ ؒ ؒ ؤؐؐؐRun 6 ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.dlis ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.las ؒ 224-013 T41117 223-105 T41118 224-105 T41119 224-085 T41120 223-120 T41121 225-012 T41122 ؐNDBi-030 Lithotrak Caliper data LETTER OF TRANSMITTAL جؐؐؐNDBi-043 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.dlis ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.dlis ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.las ؒ جؐؐؐNDBi-044 Lithotrak Caliper data ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.dlis ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.las ؒ جؐؐؐNDBi-046 Lithotrak Caliper data ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.dlis ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.las ؒ جؐؐؐNDBi-049 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.dlis ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.dlis ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.las ؒ جؐؐؐNDBi-050 Lithotrak Caliper data ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.dlis ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.las ؒ ؤؐؐؐPWD-02 Lithotrak Caliper data SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.dlis SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.las 223-051 T41123 223-087 T41124 224-028 T41125 224-119 T41126 224-154 T41127 224-009 T41128 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, January 10, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Oil Search (Alaska), LLC NDBi-030 PIKKA NDBi-030 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/10/2025 NDBi-030 50-103-20873-00-00 223-120-0 N SPT 4056 2231200 4000 245 248 248 248 0 0 0 0 OTHER P Adam Earl 11/2/2024 MIT IA for pre-injection to 4000psi 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PIKKA NDBi-030 Inspection Date: Tubing OA Packer Depth 59 4213 4156 4137IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE241104111653 BBL Pumped:8.9 BBL Returned:8.8 Friday, January 10, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.01.10 15:03:02 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Well Cleanup Oil Search Alaska, LLC Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,529 feet N/A feet true vertical 4,141 feet N/A feet Effective Depth measured 11,050 feet See attached feet true vertical 4,067 feet See attached feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6 ppf P-110S 11,050' MD 4,067' 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: Contact Name: Scott Leahy Contact Email:scott.leahy@santos.com Authorized Title: Completions Specialist Contact Phone: 907-330-4595 324-212 Sr Pet Eng: 9,210 Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Gas-Mcf MD See attached reports 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) N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393020, 393019, 393018 Pikka / Nanushuk Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-120 50-103-20873-00-00 900 E Benson Boulevard, Suite 500 Anchorage, AK 99508 3. Address: NDBi-030 See attached reports Length 80' 2,550' 80'Conductor Surface Intermediate 20"x34" 13-3/8" Size 80' 9-5/8" 11,590 4-1/2" measured TVD Production Liner 8,834' 11,050' 6,508' Casing Structural 4,108' 4,067' 4-1/2" 11,201' 11,050' 17,522' 4,141' Plugs Junk measured Collapse 2,260 4,750 9,210 5,020 6,870 11,590 6,870 4,750Tie-Back 2,367' Tieback 2,367' 2,155' 2,550' 2,264' Burst p k ft t Fra O s 223 6.A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 08/01/2024 By Meredith Guhl at 9:53 am, Dec 06, 2024 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Well Cleanup Oil Search Alaska, LLC Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,529 feet N/A feet true vertical 4,141 feet N/A feet Effective Depth measured 11,050 feet See attached feet true vertical 4,067 feet See attached feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6 ppf P-110S 11,050' MD 4,067' 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: Contact Name: Scott Leahy Contact Email:scott.leahy@santos.com Authorized Title: Completions Specialist Contact Phone: 907-330-4595 324-212 Sr Pet Eng: 9,210 Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Gas-Mcf MD See attached reports measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure N/A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 392984, 391445, 393020, 393019, 393018 Pikka / Nanushuk Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-120 50-103-20873-00-00 900 E Benson Boulevard, Suite 500 Anchorage, AK 99508 3. Address: NDBi-030 See attached reports Length 80' 2,550' 80'Conductor Surface Intermediate 20"x34" 13-3/8" Size 80' 9-5/8" 11,590 4-1/2" measured TVD Production Liner 8,834' 11,050' 6,508' Casing Structural 4,108' 4,067' 4-1/2" 11,201' 11,050' 17,522' 4,141' Plugs Junk measured Collapse 2,260 4,750 9,210 5,020 6,870 11,590 6,870 4,750Tie-Back 2,367' Tieback 2,367' 2,155' 2,550' 2,264' Burst p k ft t Fra O s 223 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 08/01/2024 By Grace Christianson at 1:37 pm, Aug 01, 2024 CDW 08/01/2024 DSR-8/12/24 RBDMS JSB 080624 Superseded Page 1 of 1 Well Name: NDBi-030 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,036.6 4,061.4 OH Packer #13 11,314.4 4,135.3 OH Packer #12 11,382.0 4,149.6 OH Packer #11 11,842.8 4,175.5 OH Packer #10 12,388.3 4,171.0 OH Packer #9 12,844.2 4,166.2 OH Packer #8 13,460.0 4,163.6 OH Packer #7 14,045.4 4,161.5 OH Packer #6 14,664.8 4,159.6 OH Packer #5 15,249.2 4,158.5 OH Packer #4 15,751.3 4,154.5 OH Packer #3 16,376.6 4,149.7 OH Packer #2 16,955.3 4,145.4 OH Packer #1 17,332.9 4,142.7 NDBi-030 Well Schematic 20" Insulated Conductor80' MD 9-5/8" Liner Hanger and Liner Top Packer2367' MD 13-3/8" 68 ppf L-80 Surface Casing2550' MD 9-5/8", 47ppf L-80 Production Liner 11201' MD 4-½ x 9-5/8 Liner Hanger and Liner Top Packer 11014' MD Archer C-Flex Two-Stage Cementing Tool 4712' MD TOC First Stage Cement Job9950' MD 03.28.2024 16" Hole Size 12-1/4" Hole Size 9-5/8" Tieback and Seal Assembly2367' MD GL 1 2 3 4 5 6 7 8 8-½ Openhole 17,529' MD 4-½, 12.6ppf P-110S Production Liner 17,522' MD 9 46.4' RKB Bottom Flange # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 XLanding Nipple 1520 1486 25 3.813 4.790 2 Gaslift Mandrel 1.5" 2156 2007 43 3.865 7.650 3 XLanding Nipple 2226 2057 45 3.813 4.790 4 XLanding Nipple 10861 4017 76 3.813 4.790 5 D/H Psi Temp Gauge 10924 4033 75 3.905 6.000 6 XLanding Nipple 10946 4038 75 3.813 4.776 7 Tieback Seal Assy 11050 4065 75 3.860 5.230 8 9.625" x 4.5" LH/Packer 11014 4056 75 6.040 8.420 9 #13 Openhole Packer 11308 4134 76 3.910 8.000 10 #12 Openhole Packer 11375 4148 79 3.911 8.000 11 Stage 11 Frac Sleeve 11648 4176 89 3.735 5.630 12 #11 Openhole Packer 11836 4176 90 3.918 8.000 13 Stage 10 Frac Sleeve 12111 4174 90 3.735 5.629 14 #10 Openhole Packer 12382 4171 90 3.912 8.000 15 Stage 9 FracSleeve 12652 4169 90 3.735 5.632 16 #9 Openhole Packer 12838 4166 90 3.913 8.000 17 Stage 8 Frac Sleeve 13228 4164 90 3.735 5.630 18 #8 Openhole Packer 13453 4164 90 3.912 8.000 19 Stage 7 FracSleeve 13727 4163 90 3.735 5.635 20 #7 Openhole Packer 14039 4161 90 3.912 8.000 21 Stage 6 FracSleeve 14308 4161 90 3.735 5.632 22 #6 Openhole Packer 14658 4160 90 3.918 8.000 23 Stage 5 FracSleeve 14889 4159 90 3.735 5.635 24 #5 Openhole Packer 15242 4159 90 3.918 8.000 25 Stage 4 FracSleeve 15474 4157 90 3.735 5.630 26 #4 Openhole Packer 15744 4155 90 3.918 8.000 27 Stage 3 FracSleeve 16059 4152 90 3.735 5.632 28 #3 Openhole Packer 16370 4150 90 3.918 8.000 29 Stage 2 FracSleeve 16638 4148 90 3.735 5.632 30 #2 Openhole Packer 16949 4145 90 3.918 8.000 31 Stage 1 FracSleeve 17220 4144 90 3.735 5.634 32 #1 Openhole Packer 17326 4143 90 3.898 8.000 33 #2 Toe Sleeve 17434 4142 90 3.500 5.750 34 #1 Toe Sleeve 17446 4142 90 3.500 5.750 35 WIV Collar 17508 4141 90 0.870 5.200 36 Eccentricshoe 17521 4141 90 3.900 5.200 Frac Ops Summary Report - AOGCC Well Name NDBi-030 Primary Job Type Fracture Treatment Start Date End Date Summary 5/25/2024 5/26/2024 All water (and KCL) on location and heated. Finish hauling proppant. Continue to RU frac equipment. Install Cameron launch tree. Mix up frac chemicals and test fluids. 5/26/2024 5/27/2024 Frac Stage 1 Finish RU of Frac equipment, prime up, pressure test. Pump Freeze Protect fluid past wellhead with 29 bbls WF125. Pump Check with 210 bbls WF125 DataFrac: 250 bbls YF125ST and 283 bbls WF125 fluid at 40bpm. Shut down to analyze. Frac stage 1: 2,318 bbls slurry (YF125ST fluid), 228,602 lbs 16/20 Carbolite (1, 2, 3, 4, 5, 6, 7, 8ppa), 2,090 bbls clean fluid at 40bpm, as per design. Shut down to repair pumps. Found some rocks in pump suctions and had to clean out. Shut down for day. Pump 40bbls freeze protect down wellhead with LRS. Clean up and shut down for night. TLTR (Stage 1) 2,862 bbls 5/27/2024 5/28/2024 Frac Stages 2-4 Fire up frac equipment, prime up, pressure test. Pump Freeze Protect fluid past wellhead with 31bbls WF125. Drop ball and pump down at 4bpm. Frac stage 2: 2,246bbls slurry (YF125ST fluid), 238,420lbs 16/20 Carbolite (1, 2, 3, 4, 5, 6, 7, 8ppa), 2,004bbls clean fluid at 40bpm as per design. Frac stage 3: 1,672bbls slurry (YF125ST fluid), 223,234lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,446bbls clean fluid at 40bpm as per design. Frac stage 4: 2,100bbls slurry (YF125ST fluid), 204,223lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,894bbls clean fluid at 40bpm as per design. Tracerco tracers pumped as designed. Monitor well for 1hr. Pump 40bbls freeze protect fluid and shut in well (950psi on wellhead and 0psi on IA). TLTR (Stage 2-4) 5,344 bbls TLTR (total) 8,206 bbls 5/28/2024 5/29/2024 Refill water/prop and heat water. 5/29/2024 5/30/2024 Refill prop and heat water. 5/30/2024 5/31/2024 Pump frac stages 5-8 Fire equipment, prime up and pressure test. Frac stage 5: Pump ball down at 4bpm to start frac; 2,073bbls slurry (YF125ST fluid), 14,659 lbs 40/70 carbolite (1, 3ppa), 191,522lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 9ppa), 1,863bbs clean fluid at 40bpm, extended 8ppa and only went to 9ppa due to BH pressure trends, cut sand 20K short for job. Frac stage 6: 1,709bbls slurry (YF125ST fluid), 236,754lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10ppa), 1,468bbs clean fluid at 40bpm as per design. Frac stage 7: 1,900bbls slurry (YF125ST fluid), 14,710 lbs 40/70 carbolite (1, 3ppa), 234,688lbs 16/20 carbolite scaleguard (1, 2, 4, 6, 8, 10ppa), 1,646bbs clean fluid at 40bpm as per design. Datafrac stage 8: Pump datafrac and shut down to analyze. Frac stage 8: 2,747bbls slurry (YF125ST fluid), 14,868 lbs 40/70 carbolite (1, 3ppa), 194,499lbs 16/20 carbolite scaleguard (1, 2, 3, 4, 5, 6, 7, 8ppa), 2,535bbs clean fluid at 40bpm as per design. Tracerco tracers pumped as per design (details in the job time log for each stage). Monitor pressure for 1hr and then freeze protect well with 40bbls. Total Load to Recover (TLTR) stage 5-8 7,511bbls Total Load to Recover (TLTR) 15,717bbls 5/31/2024 6/1/2024 Refill water/prop and heat water. 6/1/2024 6/2/2024 Pump frac stages 9-11 Fire equipment, prime up and pressure test. Frac stage 9: Pump ball down at 4bpm to start frac; 1,814bbls slurry (YF125ST fluid), 241,325lbs 16/20 carbolite scaleguard (1, 3, 5, 7, 9, 10ppa), 1,572bbs clean fluid at 40bpm as per design. Frac stage 10: 1,673bbls slurry (YF125ST fluid), 254,408lbs 16/20 carbolite scaleguard (1, 3, 5, 7, 9, 10ppa), 1,419bbs clean fluid at 40bpm as per design. Frac stage 11: 1,969bbls slurry (YF125ST fluid), 16,563 lbs 40/70 carbolite (1, 3ppa), 231,534lbs 16/20 carbolite scaleguard (1, 3, 5, 7, 9, 10ppa), 1,722bbs clean fluid at 40bpm as per design (53bbls of freeze protect 37bbls downhole pumped at end of flush). Tracerco tracers pumped as per design (details in the job time log for each stage). Monitor pressure for 1hr and then blow down and vac out treating lines and equipment. Total Load to Recover (TLTR) stage 9-11 4,713bbls Total Load to Recover (TLTR) 20,430bbls Page 1 of 2 Frac Ops Summary Report - AOGCC Start Date End Date Summary 6/2/2024 6/3/2024 RDMO frac equipment. 6/13/2024 6/14/2024 Set XX Plug at 1,520'. Set TWC. N/D Frac Tree. N/U Production Tree. P/T Production Tree to 5,000 psi. 6/14/2024 6/15/2024 Pull TWC. Pull XX Plug at 1,520'. Page 2 of 2 Flowback Ops Summary Report - AOGCC Well Name NDBi-030 Primary Job Type Flowback/Testing Start Date End Date Summary 6/18/2024 6/19/2024 Expro RU equipment to the wellhead. Pressure test HP lines. Function test ESD, perform preflow checklist. prep to flow well on clean up. 6/19/2024 6/20/2024 R/U LRS Coil 2. BOP Test to 4,250 psi. Install BHA, pull test connector to 25k lbs. Stab onto well, open well, RIH. 6/20/2024 6/21/2024 M/U Cleanout BHA. RIH to 10,000' and N2 lift. Hand well over to Expro. Continue to pump N2 at 500 scf/min. 6/21/2024 6/22/2024 Continue to N2 lift well. POH to surface. Standby. Expro flow well as per clean up proceedure. 6/22/2024 6/23/2024 Flow well to Well Testers until 20:00. Shut in well. Freeze protect DW-02 well with 40 bbls FP Fluid. Rig out LRS Twin Pump and Magtec Filter Pods from DW-02 and R/U at NDBi-030 Coil Unit 2. Confirm cleanout BHA - 2.00" CTC, 2.12" DBPV, 2.13" Accelerator, 2x 2.12" Weight Bars, 2.13" Jar, 2.12" Disconnect, 2.13" Tempress, 2.0" Nozzle. PT lines to 250/4500 psi. Fluid pack reel with 49 bbls Slick SW. Test Tempress tool. Flush Expro flowback lines to tank farm with 30 bbls. Open well. Bullhead 200 bbls down the tubing to displace wellbore fluids. RIH to tag sand bridge. 6/23/2024 6/24/2024 RIH to 12,200'. Circulate PowerVis to surface. RIH and encounter sand between 11,538' and 11,624'. POH to surface. Wait on diesel to resume cleanout. 6/24/2024 6/25/2024 Displace well with diesel. RIH and Cleanout from 11,150' to 11,650'. POOH to surface. Heavy sand returns seen from 1200- 500'. LD Tempress BHA. MU slim Swirl Nozzle BHA for increased pump rates. RBIH to 11,650'. 6/25/2024 6/26/2024 Cleanout with 2" coil using diesel from 11,650' - 12,200'. POOH and get hung up ~ 12,150' and work past and chase returns to surface. Getting small/moderate amount of proppant at surface. RIH for another cleanout bite from 12,200' - 12,950'. POOH and get hung up ~ 12,125', chase returns to surface and get minimal proppant at surface. Remove Tempresss BHA and MU BHA with circ sub and 2" nozzle. RIH to 12,000' ctmd and circulate diesel to suface, minimal amount of proppant in returns to surface. 6/26/2024 6/27/2024 Complete weekly BOPE test to 250 psi low / 4,000 psi high. R/U Slickline. Retrieve gas lift dummy valve and set 5/16" OV. R/D Slickline. R/U 2" Coil Unit. Begin RIH with 2" CT to 11,500' 6/27/2024 6/28/2024 RIH with 2" coiled tubing to 11,500' ctmd. Pump down coil with N2 at 350 scfm. Start pumping N2 down IA at 500 scfm. Divert returns to Expro Well Test. POOH with coil while pumping N2 until 2500' ctmd. Close in double swab with coil at surface. Handover over SSV control to Well Test. RDMO coiled tubing unit. Flowback in Progress. 6/28/2024 6/29/2024 Expro continue to flow well per cleanup procedure with N2 assist through GLV until a decision was made to discontinue N2 assist. Well has continued to flow with no N2. 6/29/2024 6/30/2024 Expro continue flowing and monitoring well per cleanup procedure without N2 assist. 6/30/2024 7/1/2024 Expro continue flowing and monitoring well per cleanup procedure without N2 assist. Curently flowing on 128/64" choke. 7/1/2024 7/2/2024 Expro continue flowing and monitoring well per cleanup procedure without N2 assist. Currently flowing on 128/64" choke. Started the step-down rate test and changed the choke size to 54/64" @ 09:00hrs. Change choke to 42/64" @ 16:00hrs. Performed a hard shut-in @ 23:00hrs for pressure build-up. 7/2/2024 7/3/2024 Expro continue to monitor well for Pressure Build up as per procedure while rigging down from NDBi-030 Flush and vac out flowback lines from wellhead to the tank farm. Injected all the fluids in tank farm into NDB DW-02. Rig down Ball catcher and flowback lines. Complete rigging down FB equipment and move to NDBi-014. Page 1 of 1 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 8.0 gal F103 Surfactant 1.0 Gal/mGal 884.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 407.0 gal J475 Breaker J475 6.0 lb/mGal 5,164.0 lbm J511 Stabilizing Agent 1.7 lb/mGal 1,440.0 lbm J532 Crosslinker 2.1 Gal/mGal 1,835.0 gal J580 Gel J580 25.2 lb/mGal 21,557.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 50.0 gal M117 Clay Control Agent 342.9 lb/mGal 293,008.0 lbm M275 Bactericide 0.3 lb/mGal 277.0 lbm Tracers 0.2 lb/mGal 168.2 lbm S522-1620 Propping Agent varied concentrations 2,477,459.0 lbm S522-4070 Propping Agent varied concentrations 60,800.0 lbm 71.15256 % 25.46414 % 2.85131 % 0.21572 % 0.08818 % 0.04144 % 0.03939 % 0.03731 % 0.03047 % 0.01445 % 0.01387 % 0.01387 % 0.01274 % 0.00984 % 0.00691 % 0.00169 % 0.00159 % 0.00139 % 0.00111 % 0.00054 % 0.00028 % 0.00026 % 0.00026 % 0.00017 % 0.00014 % 0.00011 % 0.00007 % 0.00004 % 0.00004 % 0.00003 % 0.00003 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % 100 % 2634-33-5 1,2-benzisothiazolin-3-one Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 9004-32-4 Sodium carboxymethylcellulose 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 7632-00-0 Sodium nitrite 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9005-65-6 Sorbitan monooleate, ethoxylated 11138-66-2 Xanthan Gum 68308-89-4 Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 36089-45-9 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-propenoate 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 1338-41-6 Sorbitan stearate 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 127-08-2 Acetic acid, potassium salt (impurity) 14808-60-7 Quartz, Crystalline silica 14464-46-1 Cristobalite 63148-62-9 Dimethyl siloxanes and silicones 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 9000-90-2 Amylase, alpha 14807-96-6 Magnesium silicate hydrate (talc) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 9002-84-0 poly(tetrafluoroethylene) 9025-56-3 Hemicellulase 91053-39-3 Diatomaceous earth, calcined 112-42-5 1-undecanol (impurity) 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol Various Tracers 67-63-0 Propan-2-ol 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 50-70-4 Sorbitol 7647-14-5 Sodium chloride 7727-54-0 Diammonium peroxodisulphate 102-71-6 2,2`,2"-nitrilotriethanol 7447-40-7 Potassium chloride 9000-30-0 Guar gum CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* 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-1893 Fluid Name & Volume Concentration Volume 66402-68-4 Ceramic materials and wares, chemicals Date Prepared: 7/23/2024 State: Alaska County/Parish: North Slope Borough Case: YF125ST:WF125 854,606 gal Client: Oil Search Alaska Well: NDBi-030 Basin/Field: Pikka Disclosure Type: Post-Job Well Completed: # SLB-Private Page: 1 / 1 FracCAT Treatment Report Well : NDBi-030, Stage 1 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : May 26, 2024 Prepared by Name : Michael Hyatt Division : SLB Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 206 Initial BHP at Gauge (psi) 2,100 Final Surface ISIP (psi) 842 Final ISIP at Gauge (psi) 2,662 Surface Shut in Pressure(psi) 450 BH Shut in Pressure (psi) 2,538 Maximum Treating Pressure (psi) 5,406 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 3,096.2 Total Proppant Pumped per Load Tickets (lb) 228,602 Total YF125ST Past Wellhead (bbl) 2,010 Total Proppant in Formation per Load Tickets (lb) 228,602 Total WF125 Past Wellhead (bbl) 853.2 Carbolite 16/20 (lb) 228,602 Total Freeze Protect Past Wellhead (bbl) 0 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 121 121 M275 (lb) 114 42 J450 (gal) 56 56 J753 (gal) 7 7 J580 (lb) 3,224 2,975 J475 (lb) 770 770 J532 (gal) 212 212 J134 (lb) 8 0 J511 (lb) 163 163 D206 (gal) 1 1 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Summary On May 26, 2024 SLB performed a hydraulic fracturing treatment on Stage 1 of NBDi-030. The design called for the completion of stages 1-4, with a total of 897,034 pounds of proppant. Stage 1 consisted of a DataFRAC, Pad and 1-8 ppa steps. Pump trips were staggered from 7,800 to 8,100 psi. The popoff was initially set to 8,300 psi. Due to mechanical issues the, Stages 2-4 were unable to be completed. During the stage, 2 pumps started to cavitate and were brought offline. A third pump went to instant idle, and in order to maintain rate one of the previously shutdown pumps was brought online to complete the stage. After the stage, the fluid ends were inspected and small rocks were found in the sumps. These rocks are assumed to be the issue with the pumps. All pumps were inspected and rocks were removed from all of them. The stage was successfully completed with a total of 228,602 pounds of proppant placed into formation within 3,096.2 bbl of slurry. Summary of Stage 1 Material Actual Design Slurry Volume (bbl) 3,096.2 2,861 Clean Fluid Volume(bbl) 2,863.2 2,842 Proppant (lb) 228,602 229,857 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Figure 1. PRC for Job Figure 2. PRC of Opening Toe and DataFRAC 11:11:03 12:09:23 13:07:43 14:06:03 15:04:23 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 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 ConOpen Toe Pump Check Datafrac Stage 1 Treatment Plot © Schlumberger 1994-2017 Santos NDBi-030 5-26-2024 11:11:03 11:40:13 12:09:23 12:38:33 13:07:43 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 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 ConOpen Toe Pump Check Datafrac Treatment Plot © Schlumberger 1994-2017 Santos NDBi-030 5-26-2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Figure 3. PRC for Main Treatment Summary of Pressures When Collet Seats Collet #1 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,936 1,977 2,627 Bottomhole Pressure 3,027 3,078 3,444 Summary of Pressures When Collet Seats Collet #2 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,853 2,078 2,577 Bottomhole Pressure 3,070 3,134 3,481 Summary of Stage 1 Total Proppant Pumped (lb) 228,602 Max pumping Rate (bpm) 40.8 Total Proppant in Formation (lb) 228,602 Average Pumping Rate (bpm) 35.8 Carbolite 16/20 (lb) 228,602 Maximum Treating Pressure (psi) 7,269 Total Slurry Pumped (bbl) 3,096.2 Average Treating Pressure (psi) 3,474 YF125ST Pumped (bbl) 2,010 Average Water Temperature (F) 100 WF125 Pumped (bbl) 853.2 13:40:40 14:01:30 14:22:20 14:43:10 15:04:00 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 Treatment Plot © Schlumberger 1994-2017 Santos NDBi-030, Stage 1 5-26-2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States As Measured Pump Schedule As Measured Pump Schedule Step #Step Name Slurry Volum e (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 Load Hole 28.8 3.5 9.3 WF125 1208 0.0 0.0 0 2 Pump Check 173.1 33.8 5.9 WF125 7268 0.0 0.0 0 3 XL Check 36.9 18.8 2.2 WF125 1482 0.0 0.0 0 4 Spot DF 200.0 26.0 8.9 YF125ST 8403 0.0 0.0 0 5 DataFRAC 50.0 16.0 3.1 YF125ST 2100 0.0 0.0 0 6 Displace DF 282.5 38.7 7.5 WF125 11877 0.0 0.0 0 7 XL Check 45.2 19.8 2.5 YF125ST 1882 0.0 0.0 0 8 Drop Ball 3.0 21.0 0.1 YF125ST 126 0.0 0.0 0 9 PAD 232.0 38.6 6.1 YF125ST 9731 0.0 0.0 0 10 Slow for Seat 50.0 22.3 2.4 YF125ST 2106 0.0 0.0 0 11 Resume PAD 138.0 39.1 3.5 YF125ST 5790 0.0 0.0 0 12 1.0 PPA 180.0 39.1 4.6 YF125ST 7281 CarboLite 16/20 1.1 0.9 6543 13 2.0 PPA 180.0 39.9 4.5 YF125ST 6963 CarboLite 16/20 2.0 2.0 14014 14 3.0 PPA 200.0 40.0 5.0 YF125ST 7437 CarboLite 16/20 3.1 3.0 22625 15 4.0 PPA 200.0 39.2 5.1 YF125ST 7157 CarboLite 16/20 4.1 4.0 29249 16 5.0 PPA 200.0 39.0 5.1 YF125ST 6901 CarboLite 16/20 5.3 5.0 35210 17 6.0 PPA 200.0 37.5 5.4 YF125ST 6668 CarboLite 16/20 7.1 5.9 40725 18 7.0 PPA 185.0 37.5 4.9 YF125ST 5957 CarboLite 16/20 7.2 7.0 42686 19 8.0 PPA 175.8 36.7 4.8 YF125ST 5790 CarboLite 16/20 8.9 6.3 37550 20 Drop Collet 3.0 39.9 0.1 YF125ST 126 0.0 0.0 0 21 PAD 223 39.7 5.6 WF125 9370 0 0 0 22 Slow for Seat 50 19.3 2.8 WF125 2111 0 0 0 23 Resume PAD 59.9 34 2.3 WF125 2520 0 0 0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 Load Hole 3.5 4.2 1589 7269 174 2 Pump Check 33.8 39.6 5921 6798 398 3 XL Check 18.8 20.0 2452 2577 1305 4 Spot DF 26.0 39.9 2873 4170 1776 5 DataFRAC 16.0 16.2 2068 2087 2030 6 Displace DF 38.7 40.5 3519 3850 407 7 XL Check 19.8 21.3 2721 2939 407 8 Drop Ball 21.0 21.1 2836 2931 2742 9 PAD 38.6 40.2 4271 5063 2788 10 Slow for Seat 22.3 40.1 2081 3433 1579 11 Resume PAD 39.1 40.8 3039 3259 2724 12 1.0 PPA 39.1 40.2 2999 3136 2843 13 2.0 PPA 39.9 40.1 2961 3026 2907 14 3.0 PPA 40.0 40.3 2980 3012 2930 15 4.0 PPA 39.2 40.2 3037 3094 2902 16 5.0 PPA 39.0 40.4 3258 3418 2943 17 6.0 PPA 37.5 40.0 3381 3861 2403 18 7.0 PPA 37.5 39.6 3976 4230 3658 19 8.0 PPA 36.7 40.5 4375 5150 2962 20 Drop Collet 39.9 39.9 5037 5075 5012 21 PAD 39.7 39.8 2582 2652 2463 22 Slow for Seat 19.3 39.7 1875 2385 1506 23 Resume PAD 34.0 39.1 2998 3484 9 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 7:30:44 Waiting on Vac trucks 0 0 0.0 0.0 0.0 2 8:53:41 Flooding Lines 0 0 0.0 0.0 0.0 3 9:12:59 Priming Pumps 32 0 0.0 6.0 0.0 4 9:40:09 Beginning PT 18 -5 0.0 0.0 0.0 5 9:56:43 Good Check Valve 3950 -14 0.0 0.0 0.0 6 10:01:59 Good PT 9068 -9 0.0 0.0 0.0 7 10:15:15 PJSM 14 2664 0.0 0.0 0.0 8 11:00:43 Pulling on water 27 -5 0.0 0.0 0.0 9 11:15:09 Mixing Gel 27 3287 0.0 0.0 0.0 10 11:36:30 Start Load Hole Automatically 934 3213 0.0 0.0 0.0 11 11:36:30 Start Propped Frac Automatically 934 3213 0.0 0.0 0.0 12 11:36:30 Start Stage 1 Automatically 934 3213 0.0 0.0 0.0 13 11:36:38 Started Pumping 925 3218 0.0 0.0 0.0 14 11:37:57 Open Well 215 3218 0.0 0.0 0.0 15 11:45:17 Activated Extend Stage 1025 3204 10.2 4.0 0.0 16 12:07:09 Deactivated Extend Stage 439 3191 28.8 2.0 0.0 17 12:07:09 Start Pump Check Manually 439 3191 28.8 2.0 0.0 18 12:09:54 Activated Extend Stage 6317 3484 94.4 34.4 0.0 19 12:20:34 Deactivated Extend Stage 517 3470 201.9 0.0 0.0 20 12:20:34 Start Spot DF Manually 517 3470 201.9 0.0 0.0 21 12:20:42 Activated Extend Stage 723 3415 202.0 2.9 0.0 22 12:20:57 Deactivated Extend Stage 1282 3429 203.3 6.9 0.0 23 12:20:57 Start Pump Check Manually 1282 3429 203.3 6.9 0.0 24 12:22:27 Activated Extend Stage 2486 3456 230.2 20.0 0.0 25 12:22:53 Deactivated Extend Stage 2444 3392 238.8 20.0 0.0 26 12:22:53 Start Spot DF Manually 2444 3392 238.8 20.0 0.0 27 12:24:24 Stage at Perfs: Load Hole 3580 3410 279.7 34.0 0.0 28 12:25:10 Stage at Perfs: Pump Check 4129 3474 308.7 39.8 0.0 29 12:31:48 Start DataFRAC Automatically 2083 3484 438.8 16.0 0.0 30 12:34:25 Stage at Perfs: Spot DF 2042 3438 480.7 15.9 0.0 31 12:34:30 Stage at Perfs: Pump Check 2037 3442 482.0 15.9 0.0 32 12:34:56 Start Displace DF Automatically 2028 3452 488.9 16.0 0.0 33 12:35:18 Activated Extend Stage 2586 3474 495.4 22.1 0.0 34 12:36:00 Stage at Perfs: Spot DF 3191 3529 518.3 38.8 0.0 35 12:41:00 Stage at Perfs: Pump Check 3772 3493 718.2 39.9 0.0 36 12:42:15 Stage at Perfs: Spot DF 1405 3314 768.3 40.5 0.0 37 13:47:05 Deactivated Extend Stage 641 3049 771.3 0.0 0.0 38 13:47:05 Start XL Check Manually 641 3049 771.3 0.0 0.0 39 13:47:21 Activated Extend Stage 1524 3067 772.1 6.8 0.0 40 13:49:36 Deactivated Extend Stage 2852 3117 816.5 21.0 0.0 41 13:49:36 Start Drop Ball Manually 2852 3117 816.5 21.0 0.0 42 13:49:45 Start PAD Automatically 3030 3136 819.6 20.9 0.0 43 13:55:49 Stage at Perfs: Displace DF 2559 3410 1051.1 39.9 0.0 44 13:55:50 Start Slow for Sea Automatically 2161 3401 1051.8 38.9 0.0 45 13:58:01 Stage at Perfs: XlL Check 2609 3337 1095.3 24.8 0.0 46 13:58:09 Stage at Perfs: Drop Ball 2669 3300 1099.0 30.2 0.0 47 13:58:14 Start Resume PAD Automatically 2724 3278 1101.5 31.6 0.0 48 14:01:45 Start 1.0 PPA Automatically 3076 3378 1239.6 39.5 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 49 14:01:45 Started Pumping Prop 3076 3378 1239.6 39.5 0.0 50 14:04:07 Stage at Perfs: PAD 2907 3342 1331.2 37.7 0.9 51 14:05:23 Stage at Perfs: Slow for Sea 2989 3351 1380.8 39.7 1.0 52 14:06:21 Start 2.0 PPA Automatically 3017 3369 1419.5 40.0 1.0 53 14:08:51 Stage at Perfs: Resume PAD 2930 3291 1519.2 39.8 2.0 54 14:10:52 Start 3.0 PPA Automatically 2925 3378 1599.8 39.9 2.0 55 14:13:20 Stage at Perfs: 1.0 PPA 2962 3259 1698.5 39.9 2.9 56 14:15:52 Start 4.0 PPA Automatically 3007 3287 1799.7 39.9 3.0 57 14:17:51 Stage at Perfs: 2.0 PPA 3072 3328 1878.9 39.6 4.0 58 14:20:59 Start 5.0 PPA Automatically 2852 3401 2000.1 37.9 3.9 59 14:23:01 Stage at Perfs: 3.0 PPA 3177 3250 2079.2 37.9 5.0 60 14:26:06 Start 6.0 PPA Automatically 3452 3282 2199.7 39.3 5.0 61 14:28:06 Stage at Perfs: 4.0 PPA 3676 3342 2279.2 39.7 5.9 62 14:31:30 Start 7.0 PPA Automatically 3868 3365 2399.9 39.4 5.9 63 14:33:36 Stage at Perfs: 5.0 PPA 3983 3255 2479.0 37.5 7.0 64 14:36:26 Start 8.0 PPA Automatically 4175 3314 2584.6 37.0 7.0 65 14:37:59 Activated Extend Stage 4532 3296 2642.0 36.9 8.0 66 14:38:59 Stage at Perfs: 6.0 PPA 4390 3291 2679.0 35.5 7.9 67 14:40:51 Stopped Pumping Prop 5054 3342 2744.9 40.4 0.0 68 14:41:14 Deactivated Extend Stage 5090 3351 2760.3 39.8 0.0 69 14:41:14 Start Drop Collet Manually 5090 3351 2760.3 39.8 0.0 70 14:41:19 Start PAD Automatically 5241 3355 0.0 39.9 0.0 71 14:41:19 Start Propped Frac Automatically 5241 3355 0.0 39.9 0.0 72 14:41:19 Start Stage 2 Automatically 5241 3355 0.0 39.9 0.0 73 14:43:50 Stage at Perfs: 7.0 PPA 4582 3209 100.5 39.9 0.0 74 14:46:54 Start Slow for Sea Automatically 1273 3149 222.8 33.0 0.0 75 14:49:42 Start Resume PAD Automatically 2522 3223 272.8 18.6 0.0 76 14:49:45 Activated Extend Stage 2660 3232 273.8 20.1 0.0 77 14:49:49 Stage at Perfs: Drop Collet 2559 3200 275.3 24.2 0.0 78 14:49:57 Stage at Perfs: PAD 3246 3255 278.8 27.9 0.0 79 14:58:14 Well Shut 540 3131 329.2 0.0 0.0 FracCAT Treatment Report Well : NDBi-030, Stages 2-4 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : May 28, 2024 Prepared by Name : Michael Hyatt Division : SLB Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 375 Initial BHP at Gauge (psi) 1,969 Final Surface ISIP (psi) 950 Final ISIP at Gauge (psi) 2,549 Surface Shut in Pressure(psi) 695 BH Shut in Pressure (psi) 2,542 Maximum Treating Pressure (psi) 5,887 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 6,017.5 Total Proppant Pumped per Load Tickets (lb) 665,878 Total YF125ST Past Wellhead (bbl) 4,849.2 Total Proppant in Formation per Load Tickets (lb) 665,878 Total WF125 Past Wellhead (bbl) 494.4 Carbolite 16/20 665,878 Total Freeze Protect Past Wellhead (bbl) 0 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 231 231 M275 (lb) 78 77 J450 (gal) 101 101 J753 (gal) 13 12 J580 (lb) 5,689 5,664 J475 (lb) 1,320 1,320 J532 (gal) 469 469 J134 (lb) 0 0 J511 (lb) 437 355 D206 (gal) 1 1 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Other Country: United States Summary On May 27, 2024 SLB performed a hydraulic fracturing treatment on Stages 2-4 of NBDi-030. The design called for the completion of stages 2-4, with a total of 668,384 pounds of proppant in 6,070 bbl of slurry. Stage 2 consisted of 1, 2, 4, 6 and 8 ppa steps. Stages 3 and 4 consisted of 1, 2, 4, 6, 8 and 10 ppa steps. Pump trips were staggered from 7,800 to 8,100 psi. The popoff was initially set to 8,300 psi. Notable changes to these stages over previous wells was the increase in spacer size during the collet launch sequence an additional 5 bbl of spacer was added to each stage. Pressure changes indicated that all the collets landed on the expected barrel count. The stage was successfully completed with a total of 665,878 pounds of proppant placed into formation within 6,017.5 bbl of slurry. No mechanical issues were reported during the stage. A summary of the job is below. Summary of Stages 2-4 Material Actual Design Slurry Volume (bbl) 6,017.5 6,070 Clean Fluid Volume(bbl) 5,343.5 5,366 Proppant (lb) 665,878 668,384 11:40:06 12:46:46 13:53:26 15:00:06 16:06:46 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 Stage 2 Stage 3 Stage 4 Main Treatment © Schlumberger 1994-2017 SantosNDBi-030, Stages 2-45-27-2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 2 Initial treating pressure on PAD was around 4,200 psi and slowly fell to about 3,000 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 5,500 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: 13:02:36 13:19:16 13:35:56 13:52:36 14:09:16 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 ConDrop Rate to Seat Collet Sleeve Shifted Main Treatment © Schlumberger 1994-2017 SantosNDBi-030, Stage 25-27-2024 Summary of Pressures When Collet Seats Collet #3 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 2,000 2,341 2,966 Bottomhole Pressure 3,057 3,542 3,958 Summary of Stage 2 Total Proppant Pumped (lb) 238,420 Max pumping Rate (bpm) 40.6 Total Proppant in Formation (lb) 238,420 Average Pumping Rate (bpm) 34.9 Total Slurry Pumped (bbl) 2,246 Maximum Treating Pressure (psi) 5,548 Carbolite 16/20 238,420 Average Treating Pressure (psi) 3,300 YF125ST Pumped (bbl) 1,720.9 Average Water Temperature (F) 100 WF125 Pumped (bbl) 238.2 Client: Santos Well: NDBi-030 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 Load Hole 31.4 3.9 8.3 WF125 1320 0.0 0.0 0 2 Displace Ball 251.8 4.0 63.0 WF125 10574 0.0 0.0 0 3 Crosslink Check 27.9 14.4 2.0 YF125ST 1164 0.0 0.0 0 4 PAD 370.0 39.1 9.6 YF125ST 15523 0.0 0.0 0 5 1.0 PPA 180.0 39.9 4.5 YF125ST 7259 CarboLite 16/20 1.0 0.9 7063 6 2.0 PPA 180.0 40.1 4.5 YF125ST 6966 CarboLite 16/20 2.1 1.9 13942 7 3.0 PPA 200.0 40.0 5.0 YF125ST 7437 CarboLite 16/20 3.1 3.0 22623 8 4.0 PPA 200.0 40.0 5.0 YF125ST 7161 CarboLite 16/20 4.1 3.9 29120 9 5.0 PPA 200.0 39.9 5.0 YF125ST 6904 CarboLite 16/20 5.1 4.9 35160 10 6.0 PPA 200.0 39.8 5.0 YF125ST 6664 CarboLite 16/20 6.1 6.0 40817 11 7.0 PPA 185.0 39.9 4.6 YF125ST 5957 CarboLite 16/20 7.1 7.0 42629 12 8.0 PPA 176.4 39.8 4.4 YF125ST 5499 CarboLite 16/20 8.1 7.9 47067 13 Spacer 40.5 39.8 1.0 YF125ST 1619 0 0 0 14 Drop Collet 3.0 40.2 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Load Hole 3.9 4.0 1152 1241 407 2 Displace Ball 4.0 4.1 1088 1176 673 3 Crosslink Check 14.4 15.5 1880 2005 1099 4 PAD 39.1 40.3 3452 4152 1886 5 1.0 PPA 39.9 40.2 3134 3236 3081 6 2.0 PPA 40.1 40.3 3013 3076 2957 7 3.0 PPA 40.0 40.1 3002 3040 2957 8 4.0 PPA 40.0 40.3 3108 3159 3030 9 5.0 PPA 39.9 40.2 3365 3537 3159 10 6.0 PPA 39.8 40.1 3873 4189 3539 11 7.0 PPA 39.9 40.1 4553 4898 4189 12 8.0 PPA 39.8 40.2 5251 5516 4898 13 Spacer 39.8 40.6 5270 5548 5104 14 Drop Collet 40.2 40.2 5295 5337 5251 Client: Santos Well: NDBi-030 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 9:28:25 Priming Pumps with diesel 0 0 0.0 0.0 0.0 2 10:03:01 Starting PT 755 5 0.0 0.0 0.0 3 10:16:01 Flushing check valve 119 9 0.0 7.9 0.0 4 10:19:54 Good check valve 4257 5 0.0 0.0 0.0 5 10:36:16 Good PT -5 5 0.0 0.0 0.0 6 10:36:21 PJSM 0 5 0.0 0.0 0.0 7 11:06:21 Making gel 14 55 0.0 0.0 0.0 8 11:29:23 Open well 389 3250 0.0 0.0 0.0 9 11:33:25 Start Displace PT Automatically 1199 3273 0.0 4.0 0.0 10 11:33:25 Start Propped Frac Automatically 1199 3273 0.0 4.0 0.0 11 11:33:25 Start Stage 2 Automatically 1199 3273 0.0 4.0 0.0 12 11:33:31 Started Pumping 1199 3273 0.0 4.0 0.0 13 11:34:36 Activated Extend Stage 1277 3278 3.9 3.2 0.0 14 11:53:26 Deactivated Extend Stage 746 3268 31.4 3.9 0.0 15 11:53:26 Start Displace Bal Manually 746 3268 31.4 3.9 0.0 16 11:53:29 Activated Extend Stage 778 3278 31.6 4.1 0.0 17 12:53:03 Stage at Perfs: Displace PT 1108 3255 269.6 4.0 0.0 18 12:56:28 Deactivated Extend Stage 1057 3268 283.2 4.0 0.0 19 12:56:28 Start XL/Pump CHK Manually 1057 3268 283.2 4.0 0.0 20 12:57:23 Activated Extend Stage 1913 3305 294.5 15.1 0.0 21 12:57:50 Stage at Perfs: Displace Bal 1877 3310 301.3 15.0 0.0 22 12:58:29 Deactivated Extend Stage 1886 3319 311.1 15.3 0.0 23 12:58:29 Start PAD Manually 1886 3319 311.1 15.3 0.0 24 13:04:56 Stage at Perfs: XL/Pump CHK 3236 3337 554.2 40.0 0.0 25 13:05:37 Stage at Perfs: PAD 3204 3360 581.6 40.0 0.0 26 13:08:06 Start 1.0 PPA Automatically 3236 3195 681.2 40.3 0.0 27 13:08:06 Started Pumping Prop 3236 3195 681.2 40.3 0.0 28 13:12:37 Start 2.0 PPA Automatically 3076 3333 861.6 40.3 1.1 29 13:14:52 Stage at Perfs: 1.0 PPA 2989 3392 951.7 40.2 2.0 30 13:17:06 Start 3.0 PPA Automatically 2962 3177 1041.3 39.9 2.0 31 13:19:22 Stage at Perfs: 2.0 PPA 2998 3236 1131.9 39.8 3.0 32 13:22:06 Start 4.0 PPA Automatically 3030 3296 1241.2 40.0 3.0 33 13:23:52 Stage at Perfs: 3.0 PPA 3113 3323 1311.5 40.0 4.1 34 13:27:07 Start 5.0 PPA Automatically 3159 3113 1441.7 39.8 4.0 35 13:28:52 Stage at Perfs: 4.0 PPA 3323 3149 1511.5 40.2 5.0 36 13:32:07 Start 6.0 PPA Automatically 3539 3186 1641.4 40.1 5.0 37 13:33:54 Stage at Perfs: 5.0 PPA 3786 3209 1712.4 39.8 6.0 38 13:37:08 Start 7.0 PPA Automatically 4189 3264 1841.1 40.1 6.0 39 13:38:54 Stage at Perfs: 6.0 PPA 4500 3296 1911.5 39.8 7.0 40 13:41:47 Start 8.0 PPA Automatically 4907 3159 2026.7 40.2 6.9 41 13:43:51 Activated Extend Stage 5273 3209 2109.0 39.9 7.7 42 13:43:55 Stage at Perfs: 7.0 PPA 5278 3209 2111.7 40.2 8.1 43 13:46:12 Deactivated Extend Stage 5557 3246 2202.6 39.8 7.9 44 13:46:12 Start Spacer Manually 5557 3246 2202.6 39.8 7.9 45 13:46:29 Stopped Pumping Prop 5365 3246 2213.9 40.5 0.2 46 13:46:42 Activated Extend Stage 5086 3236 2222.6 39.4 0.0 47 13:47:13 Deactivated Extend Stage 5351 3255 2243.1 40.1 0.0 48 13:47:13 Start Drop Collet Manually 5351 3255 2243.1 40.1 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 3 Initial treating pressure on PAD was around 3,000 psi and quickly fell to about 2,700 after the breakdown. Pressure remained relatively flat until 2 ppa was going into formation. At this point, the treating pressure gradually increased to 5,800 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: 13:55:21 14:07:51 14:20:21 14:32:51 14:45:21 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 ConDrop Rate to Seat Collet Sleeve Shifted Main Treatment © Schlumberger 1994-2017 SantosNDBi-030, Stage 35-27-2024 Summary of Pressures When Collet Seats Collet #4 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 1,968 3,515 4,074 Bottomhole Pressure 3,027 4,350 5,004 Summary of Stage 3 Total Proppant Pumped (lb) 223,234 Max pumping Rate (bpm) 40.6 Total Proppant in Formation (lb) 223,234 Average Pumping Rate (bpm) 39.2 Total Slurry Pumped (bbl) 1,671.8 Maximum Treating Pressure (psi) 5,887 YF125ST Pumped (bbl) 1,445.9 Average Treating Pressure (psi) 3,707 WF125 Pumped (bbl) 0 Average Water Temperature (F) 100 Client: Santos Well: NDBi-030 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 214.0 40.1 5.3 YF125ST 8993 0.0 0.0 0 2 Slow for Seat 50.0 20.0 2.6 YF125ST 2108 0.0 0.0 0 3 Resume PAD 56.0 36.7 1.5 YF125ST 2339 0.0 0.0 0 4 1.0 PPA 200.0 39.9 5.0 YF125ST 8065 CarboLite 16/20 1.0 0.9 7849 5 2.0 PPA 220.0 40.1 5.5 YF125ST 8510 CarboLite 16/20 2.1 2.0 17151 6 4.0 PPA 240.0 40.0 6.0 YF125ST 8603 CarboLite 16/20 4.1 3.9 34694 7 6.0 PPA 240.0 39.9 6.0 YF125ST 8005 CarboLite 16/20 6.2 5.9 48783 8 8.0 PPA 220.0 39.9 5.5 YF125ST 6863 CarboLite 16/20 8.1 7.9 55859 9 10.0 PPA 190.0 39.5 4.8 YF125ST 5567 CarboLite 16/20 10.1 9.9 58898 10 Spacer 38.8 40.1 1.0 YF125ST 1548 0 0 0 11 Drop Collet 3.0 39.6 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD 40.1 40.3 4304 5365 1914 2 Slow for Seat 20.0 36.9 2053 2925 1511 3 Resume PAD 36.7 40.3 2689 2975 2385 4 1.0 PPA 39.9 40.1 2744 2765 2705 5 2.0 PPA 40.1 40.3 2726 2751 2715 6 4.0 PPA 40.0 40.3 2858 3017 2742 7 6.0 PPA 39.9 40.3 3470 4092 3026 8 8.0 PPA 39.9 40.4 4780 5344 4092 9 10.0 PPA 39.5 40.3 5614 5887 5347 10 Spacer 40.1 40.6 5723 5869 5521 11 Drop Collet 39.6 39.7 5589 5638 5534 Client: Santos Well: NDBi-030 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 13:47:18 Start PAD Automatically 5457 3264 0.0 40.1 0.0 2 13:47:18 Start Propped Frac Automatically 5457 3264 0.0 40.1 0.0 3 13:47:18 Start Stage 3 Automatically 5457 3264 0.0 40.1 0.0 4 13:48:34 Stage at Perfs: 8.0 PPA 4898 3268 50.9 40.0 0.0 5 13:52:39 Start Slow for Sea Automatically 1273 3200 214.0 31.4 0.0 6 13:53:12 Stage at Perfs: Spacer 1936 3209 225.8 18.8 0.0 7 13:55:16 Start Resume PAD Automatically 2550 3232 263.9 22.1 0.0 8 13:55:23 Stage at Perfs: Drop Collet 2289 3223 266.7 25.7 0.0 9 13:55:30 Stage at Perfs: PAD 2843 3232 269.9 29.9 0.0 10 13:56:48 Start 1.0 PPA Automatically 2724 3241 320.0 40.1 0.0 11 13:56:48 Started Pumping Prop 2724 3241 320.0 40.1 0.0 12 14:00:41 Stage at Perfs: Slow for Sea 2756 3241 475.0 40.1 1.0 13 14:01:48 Start 2.0 PPA Automatically 2733 3246 519.7 40.1 1.0 14 14:01:56 Stage at Perfs: Resume PAD 2733 3241 525.0 40.1 1.0 15 14:03:20 Stage at Perfs: 1.0 PPA 2719 3250 581.1 40.1 2.0 16 14:07:18 Start 4.0 PPA Automatically 2747 3278 740.2 40.2 2.0 17 14:08:19 Stage at Perfs: 2.0 PPA 2797 3278 780.8 39.9 4.1 18 14:13:18 Start 6.0 PPA Automatically 3017 3305 980.2 39.9 4.0 19 14:13:49 Stage at Perfs: 4.0 PPA 3081 3310 1000.8 39.5 6.1 20 14:19:19 Start 8.0 PPA Automatically 4124 3149 1220.1 40.0 5.9 21 14:19:51 Stage at Perfs: 6.0 PPA 4216 3154 1241.2 39.7 7.9 22 14:24:50 Start 10.0 PPA Automatically 5351 3168 1440.0 40.2 8.1 23 14:25:35 Activated Extend Stage 5415 3177 1469.7 39.0 10.1 24 14:25:52 Stage at Perfs: 8.0 PPA 5461 3177 1480.8 39.5 9.9 25 14:28:49 Deactivated Extend Stage 5827 3186 1597.2 39.3 10.0 26 14:29:38 Start Spacer Automatically 5841 3186 1629.7 39.8 10.3 27 14:29:52 Activated Extend Stage 5621 3186 1639.0 40.2 0.9 28 14:30:36 Deactivated Extend Stage 5644 3191 1668.5 39.4 0.0 29 14:30:36 Start Drop Collet Manually 5644 3191 1668.5 39.4 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Other Country: United States Stage 4 Initial treating pressure on PAD was around 3,800 psi and gradually fell to about 2,700 after 1 ppa was going into formation. Pressure remained. At this point, the treating pressure gradually increased to 5,700 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: Summary of Pressures When Collet Seats Collet #5 Before Collet Hit (psi) Collet Hit (psi) After Collet (psi) Wellhead Pressure 1,766 2,792 4,028 Bottomhole Pressure 2,955 3,506 5,224 Summary of Stage 4 Total Proppant Pumped (lb) 204,223 Max pumping Rate (bpm) 41.1 Total Proppant in Formation (lb) 204,223 Average Pumping Rate (bpm) 38.7 Carbolite 16/20 (lb) 204,223 Maximum Treating Pressure (psi) 5,786 Total Slurry Pumped (bbl) 2,099.7 Average Treating Pressure (psi) 3,672 YF125ST Pumped (bbl) 1682.4 Average Water Temperature (F) 100 WF125 Pumped (bbl) 211.2 14:37:17 14:53:57 15:10:37 15:27:17 15:43:57 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 20 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop ConDrop Rate to Seat Collet Sleeve Shifted Injection into Stage 5 Main Treatment © Schlumberger 1994-2017 SantosNDBi-030, Stage 4 5-27-2024 Client: Santos Well: NDBi-030 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 205.0 40.0 5.1 YF125ST 8616 0.0 0.0 0 2 Slow for Seat 50.0 19.7 2.6 YF125ST 2108 0.0 0.0 0 3 Resume PAD 91.7 36.8 2.6 YF125ST 3834 0.0 0.0 0 4 1.0 PPA 209.8 39.9 5.3 YF125ST 8457 CarboLite 16/20 1.0 1.0 8325 5 2.0 PPA 220.0 40.1 5.5 YF125ST 8510 CarboLite 16/20 2.1 2.0 17138 6 4.0 PPA 240.0 40.0 6.0 YF125ST 8604 CarboLite 16/20 4.1 3.9 34684 7 6.0 PPA 240.0 40.0 6.0 YF125ST 8006 CarboLite 16/20 6.1 5.9 48760 8 8.0 PPA 196.4 40.0 4.9 YF125ST 6129 CarboLite 16/20 8.1 7.9 49799 9 10.0 PPA 169.7 39.9 4.3 YF125ST 5199 CarboLite 16/20 10.3 8.6 45517 10 Spacer 15.3 39.9 0.4 YF125ST 642 0.0 0.0 0 11 Drop Collet 3.0 39.9 0.1 YF125ST 126 0.0 0.0 0 12 XL Flush 50.0 40.1 1.2 YF125ST 2100 0.0 0.0 0 13 LG Flush 146.0 40.0 3.7 YF125ST 6134 0.0 0.0 0 14 Slow for Seat 51.9 20.2 2.7 YF125ST 2194 0.0 0.0 0 15 Overflush PCM 210.9 38.6 5.6 WF125 8869 0.0 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD 40.0 40.3 4491 5786 1553 2 Slow for Sea 19.7 35.0 2507 3864 1469 3 Resume PAD 36.8 40.1 3140 3680 2559 4 1.0 PPA 39.9 40.1 2755 2911 2682 5 2.0 PPA 40.1 40.2 2676 2737 2655 6 4.0 PPA 40.0 40.2 2823 2996 2682 7 6.0 PPA 40.0 40.6 3488 4061 3003 8 8.0 PPA 40.0 40.5 4560 5031 4065 9 10.0 PPA 39.9 41.1 5389 5617 5035 10 Spacer 39.9 40.4 5235 5287 5214 11 Drop Collet 39.9 39.9 5343 5402 5287 12 XL Flush 40.1 40.1 5043 5201 4928 13 LG Flush 40.0 40.3 4110 4921 2901 14 Slow for Sea 20.2 40.1 2591 3996 1382 15 Overflush PCM 38.6 40.1 3792 4349 471 Client: Santos Well: NDBi-030 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 14:30:41 Start PAD Automatically 5859 3200 0.0 39.4 -0.0 2 14:30:41 Start Propped Frac Automatically 5859 3200 0.0 39.4 -0.0 3 14:30:41 Start Stage 4 Automatically 5859 3200 0.0 39.4 -0.0 4 14:31:04 Stopped Pumping Prop 5534 3204 15.2 39.8 -0.0 5 14:31:25 Stage at Perfs: 10.0 PPA 5447 3204 29.2 40.0 0.0 6 14:35:49 Start Slow for Sea Automatically 1469 3117 204.9 28.3 0.0 7 14:36:30 Stage at Perfs: Spacer 1913 3136 218.6 18.6 0.0 8 14:38:27 Start Resume PAD Automatically 2559 3154 254.9 18.7 0.0 9 14:38:35 Stage at Perfs: Drop Collet 2509 3163 257.4 18.7 0.0 10 14:38:45 Stage at Perfs: PAD 2953 3172 260.6 20.9 0.0 11 14:39:45 Activated Extend Stage 3172 3186 295.7 39.9 0.0 12 14:41:01 Deactivated Extend Stage 2925 3200 346.4 40.2 0.0 13 14:41:01 Start 1.0 PPA Manually 2925 3200 346.4 40.2 0.0 14 14:41:07 Started Pumping Prop 2884 3191 350.4 40.0 0.0 15 14:43:48 Stage at Perfs: Slow for Sea 2737 3218 457.2 40.0 1.0 16 14:45:03 Stage at Perfs: Resume PAD 2701 3213 507.1 40.0 1.0 17 14:46:17 Start 2.0 PPA Automatically 2710 3218 556.5 40.2 1.0 18 14:47:20 Stage at Perfs: 1.0 PPA 2705 3223 598.5 40.2 2.0 19 14:51:46 Start 4.0 PPA Automatically 2687 3200 776.3 40.2 2.0 20 14:52:34 Stage at Perfs: 2.0 PPA 2774 3200 808.3 40.2 4.1 21 14:57:46 Start 6.0 PPA Automatically 3007 3218 1016.5 40.1 4.1 22 14:58:04 Stage at Perfs: 4.0 PPA 3044 3213 1028.5 39.6 6.0 23 15:03:46 Start 8.0 PPA Automatically 4079 3278 1256.7 40.2 6.0 24 15:04:04 Stage at Perfs: 6.0 PPA 4138 3282 1268.7 39.8 8.2 25 15:08:40 Start 10.0 PPA Manually 5067 3328 1452.5 39.6 8.1 26 15:09:39 Activated Extend Stage 5191 3186 1492.0 40.3 9.9 27 15:10:04 Stage at Perfs: 8.0 PPA 5351 3191 1508.6 39.6 10.3 28 15:12:50 Stopped Pumping Prop 5370 3200 1618.8 40.5 0.0 29 15:12:55 Deactivated Extend Stage 5228 3195 1622.2 40.1 0.0 30 15:12:55 Start Spacer Manually 5228 3195 1622.2 40.1 0.0 31 15:12:58 Activated Extend Stage 5223 3200 1624.2 39.9 0.0 32 15:13:18 Deactivated Extend Stage 5411 3209 1637.5 40.1 0.0 33 15:13:18 Start Drop Collet Manually 5411 3209 1637.5 40.1 0.0 34 15:13:23 Start XL Flush Automatically 5525 3213 1640.8 39.8 0.0 35 15:14:38 Start LG Flush Automatically 4889 3204 1690.8 40.1 0.0 36 15:15:00 Stage at Perfs: 10.0 PPA 4733 3200 1705.6 40.2 0.0 37 15:18:17 Start Slow for Sea Automatically 1062 3067 1836.8 35.6 0.0 38 15:18:24 Activated Extend Stage 2042 3117 1840.1 23.8 0.0 39 15:20:13 Stage at Perfs: Spacer 3712 3191 1873.9 18.2 0.0 40 15:21:01 Deactivated Extend Stage 3012 3149 1888.4 18.2 0.0 41 15:21:01 Start Overflush PC Manually 3012 3149 1888.4 18.2 0.0 42 15:21:04 Stage at Perfs: Drop Collet 3012 3149 1889.3 18.2 0.0 43 15:21:14 Stage at Perfs: XL Flush 3525 3163 1892.4 20.8 0.0 44 15:21:40 Activated Extend Stage 4294 3186 1904.8 36.7 0.0 45 15:22:38 Stage at Perfs: LG Flush 4001 3177 1942.8 40.0 0.0 46 15:26:17 Stage at Perfs: Slow for Seat 3603 3186 2088.8 40.1 0.0 47 15:34:33 Well Closed 710 3040 2099.3 0.0 0.0 FracCAT Treatment Report Well : NDBi-030, Stages 5 to 8 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : 04-03-2024 Prepared by Name : Michael Hyatt Division : SLB Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 320 Initial BHP at Gauge (psi) 1,913 Final Surface ISIP (psi) 890 Final ISIP at Gauge (psi) 2,621 Surface Shut in Pressure(psi) 765 BH Shut in Pressure (psi) 2,350 Maximum Treating Pressure (psi) 5,502 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl)8,428.6 Total Proppant Pumped per Load Tickets (lb) 901,701 Total YF125ST Past Wellhead (bbl) 6,706.2 Total Proppant in Formation per Load Tickets (lb)901,701 Total WF125 Past Wellhead (bbl) 804.7 Total 16/20 Carbolite per load Tickets (lb) 857,464 Total Freeze Protect Past Wellhead (bbl) 0 Total 40/70 Carbolite per FracCAT (lb) 44,237 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 325 324 M275 (lb) 120 102 J450 (gal) 144 144 J753 (gal) 20 16 J580 (lb) 8,018 7,992 J475 (lb) 1,870 1,870 J532 (gal) 711 711 J134 (lb) 0 0 J511 (lb) 600 553 D206 (gal 3 3 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Summary On May 30, 2024 SLB performed a hydraulic fracturing treatment on Stage 5-8 of NBDi-030. The design called for the completion of stages 2-4, with a total of 859,533 pounds of proppant in 8,317 bbl of slurry. Stage 5 consisted of two Scour, 1, 2, 4, 6 and 8 ppa steps. Stage 6 consisted of a 1, 2, 4, 6, 8 and 10 ppa steps. Stage 7 consisted of two Scour, 1, 2, 4,6, 8 and a 10 ppa steps. Stage 8 consisted of 2 Scour, 1,2,4,6 and 8 ppa steps. Pump trips were staggered from 7,800 to 8,100 psi. The popoff was initially set to 8,300 psi. Notable changes to these stages over previous wells was the increase in spacer size during the collet launch sequence. An additional 5 bbl of spacer was added to each stage. Pressure changes indicated that all of the collets landed near the expected barrel count. The stage was successfully completed with a total of 901,701 pounds of proppant placed into formation within 8,428.6. bbl of slurry. No mechanical issues were reported during the stage. A summary of the job is below. Summary of Stages 5-8 Material Actual Design Slurry Volume (bbl) 8,428.6 8,317 Clean Fluid Volume(bbl) 7,510.9 7,412 Proppant (lb) 901,701 859,533 10:22:52 12:07:02 13:51:12 15:35:22 17:19:32 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 Stage 5 Stage 6 Stage 7 Stage 8DataFRACBall Drop Main Treatment © Schlumberger 1994-2017 Santos NDBi-30 May 30, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 5 Initial treating pressure on PAD was around 4,650 psi and slowly fell to about 2,700 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 5,500 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. Summary of Pressures When Collet Seats Collet #6 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,853 2,121 3,181 Bottomhole Pressure 2,902 3,228 3,680 Summary of Stage 5 Total Proppant Pumped (lb) 206,181 Max pumping Rate (bpm) 41.2 Total Proppant in Formation (lb) 206,181 Average Pumping Rate (bpm) 35.9 Total 16/20 Carbolite (lb) 191,522 Maximum Treating Pressure (psi) 5,461 Total 40/70 Carbolite (lb) 14,659 Average Treating Pressure (psi) 3,282 Total Slurry Pumped (bbl) 2,073.1 Average Water Temperature (F) 101 YF125ST Pumped (bbl) 1,637.4 WF125 Pumped (bbl) 225.1 11:14:20 11:31:00 11:47:40 12:04:20 12:21:00 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 Drop Rate to Seal Collet Shift Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDBi-30, Stage 5 May 30, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 Load Hole 0.0 0.0 0.0 WF125 0 0.0 0.0 0 2 Pump Ball 225.2 4.0 55.9 WF125 9455 0.0 0.0 0 3 XL Check 88.6 35.6 2.8 YF125ST 3694 0.0 0.0 0 4 PAD 325.0 40.1 8.1 YF125ST 13650 0.0 0.0 0 5 1.0 PPA 60.0 40.0 1.5 YF125ST 2431 CarboLite 40/70 1.0 0.8 2009 6 3.0 PPA 116.7 40.1 2.9 YF125ST 4367 CarboLite 40/70 3.1 2.8 12650 7 Resume PAD 50.0 40.1 1.2 YF125ST 2083 0.0 0.0 0 8 1.0 PPA 180.0 40.0 4.5 YF125ST 7259 CarboLite 16/20 1.0 0.9 7032 9 2.0 PPA 200.0 40.0 5.0 YF125ST 7736 CarboLite 16/20 2.1 2.0 15528 10 4.0 PPA 220.0 40.0 5.5 YF125ST 7885 CarboLite 16/20 4.1 3.9 31703 11 6.0 PPA 220.0 40.0 5.5 YF125ST 7337 CarboLite 16/20 6.1 5.9 44530 12 8.0 PPA 220.0 40.0 5.5 YF125ST 6864 CarboLite 16/20 8.1 7.9 55625 13 9.0 PPA 124.8 40.0 3.1 YF125ST 3768 CarboLite 16/20 9.2 8.9 37105 14 Spacer 39.8 40.5 1.0 YF125ST 1570 0.0 0.0 0 15 Drop Collet 3.0 40.2 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Load Hole 0.0 0.0 0 906 316 2 Pump Ball 4.0 4.1 1198 1355 307 3 XL Check 35.6 40.4 4076 4605 1149 4 PAD 40.1 40.2 3340 4033 2998 5 1.0 PPA 40.0 40.1 2957 2998 2925 6 3.0 PPA 40.1 40.4 2878 2957 2824 7 Resume PAD 40.1 40.3 2837 2915 2779 8 1.0 PPA 40.0 40.3 2896 2948 2780 9 2.0 PPA 40.0 40.2 2720 2779 2687 10 4.0 PPA 40.0 40.2 2788 2975 2692 11 6.0 PPA 40.0 40.5 3562 4166 2975 12 8.0 PPA 40.0 40.8 4857 5456 4166 13 9.0 PPA 40.0 40.7 5440 5461 5415 14 Spacer 40.5 41.2 5276 5452 5045 15 Drop Collet 40.2 40.2 5049 5060 5045 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 7:25:32 Waiting on Vac Driver 0 0 0.0 0.0 0.0 2 8:06:18 Flooding Lines 0 9 0.0 0.0 0.0 3 8:37:58 Starting PT 165 14 0.0 0.0 0.0 4 8:47:19 Leak on autoclave on missile 32 14 0.0 0.0 0.0 5 9:01:05 Good check valve 4381 18 0.0 0.0 0.0 6 9:14:22 Good PT 55 18 0.0 0.0 0.0 7 9:14:26 PJSM 55 18 0.0 0.0 0.0 8 9:39:42 Mixing Gel 55 5 0.0 0.0 0.0 9 10:01:39 Leak in choke trailer 938 298 0.0 0.0 0.0 10 10:04:50 Start Load Hole Automatically 906 302 0.0 0.0 0.0 11 10:04:50 Start Propped Frac Automatically 906 302 0.0 0.0 0.0 12 10:04:50 Start Stage 5 Automatically 906 302 0.0 0.0 0.0 13 10:05:01 Started Pumping 902 302 0.0 0.0 0.0 14 10:13:18 Well Open 320 1030 0.0 0.0 0.0 15 10:13:55 Start Pump Ball Manually 316 1286 0.0 0.0 0.0 16 10:25:57 Activated Extend Stage 1346 3085 4.7 4.0 0.0 17 11:20:39 Deactivated Extend Stage 1149 3314 225.2 4.0 0.0 18 11:20:39 Start XL Check Manually 1149 3314 225.2 4.0 0.0 19 11:21:38 Stage at Perfs: XL Check 4129 3438 243.7 34.5 0.0 20 11:23:25 Start PAD Manually 4005 3241 313.7 40.0 0.0 21 11:27:18 Stage at Perfs: PAD 3250 3410 469.5 40.1 0.0 22 11:29:30 Stage at Perfs: PAD 3122 3282 557.7 40.2 0.0 23 11:31:32 Start 1.0 PPA Automatically 2998 3360 639.2 40.2 0.0 24 11:31:32 Started Pumping Prop 2998 3360 639.2 40.2 0.0 25 11:33:02 Start 3.0 PPA Automatically 2930 3374 699.3 40.0 1.0 26 11:35:27 Activated Extend Stage 2834 3246 796.1 40.1 3.0 27 11:35:56 Deactivated Extend Stage 2806 3259 815.5 39.8 2.4 28 11:35:56 Start Resume PAD Manually 2806 3259 815.5 39.8 2.4 29 11:36:14 Stopped Pumping Prop 2783 3268 827.5 39.9 0.0 30 11:37:11 Start 1.0 PPA Automatically 2930 3296 865.7 40.3 0.0 31 11:37:14 Started Pumping Prop 2939 3300 867.7 40.3 0.0 32 11:37:37 Stage at Perfs: 3.0 PPA 2888 3305 883.0 39.8 1.0 33 11:39:07 Stage at Perfs: Resume PAD 2925 3346 942.9 40.0 1.0 34 11:41:41 Start 2.0 PPA Automatically 2774 3397 1045.6 40.0 1.0 35 11:42:02 Stage at Perfs: 1.0 PPA 2751 3397 1059.6 39.9 2.0 36 11:43:17 Stage at Perfs: 2.0 PPA 2724 3424 1109.6 40.4 2.0 37 11:46:41 Start 4.0 PPA Automatically 2692 3213 1245.9 40.1 2.0 38 11:47:46 Stage at Perfs: 4.0 PPA 2747 3232 1289.2 39.9 4.0 39 11:52:11 Start 6.0 PPA Automatically 2985 3314 1465.8 40.3 4.1 40 11:52:47 Stage at Perfs: 6.0 PPA 3090 3323 1489.6 40.0 5.9 41 11:57:41 Start 8.0 PPA Automatically 4179 3204 1685.6 40.4 6.1 42 11:58:17 Stage at Perfs: 8.0 PPA 4243 3218 1709.7 39.9 8.0 43 12:00:34 Activated Extend Stage 4971 3278 1800.5 40.0 7.8 44 12:03:04 Deactivated Extend Stage 5461 3337 1900.8 40.4 8.1 45 12:03:11 Start 9.0 PPA Automatically 5457 3337 1905.6 40.8 8.0 46 12:03:14 Activated Extend Stage 5438 3337 1907.6 40.4 7.9 47 12:03:46 Stage at Perfs: 9.0 PPA 5438 3346 1929.2 40.4 9.1 48 12:06:18 Deactivated Extend Stage 5438 3365 2030.3 40.0 9.1 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 49 12:06:18 Start Spacer Manually 5438 3365 2030.3 40.0 9.1 50 12:06:32 Activated Extend Stage 5438 3365 2039.7 40.9 1.6 51 12:06:43 Stopped Pumping Prop 5324 3365 2047.2 40.9 0.0 52 12:07:17 Deactivated Extend Stage 5067 3369 2070.1 40.3 0.0 53 12:07:17 Start Drop Collet Manually 5067 3369 2070.1 40.3 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 6 Initial treating pressure on PAD was around 3,400 psi and slowly fell to about 2,450 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 5,500 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. Summary of Pressures When Collet Seats Collet #7 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,831 2,273 3,126 Bottomhole Pressure 2,916 3,462 4,055 Summary of Stage 6 Total Proppant Pumped (lb) 236,754 Max pumping Rate (bpm) 41.0 Total Proppant in Formation (lb) 236,754 Average Pumping Rate (bpm) 39.1 Total 16/20 Carbolite (lb) 236,754 Maximum Treating Pressure (psi) 5,502 Total Slurry Pumped (bbl) 1,708.8 Average Treating Pressure (psi) 3,461 YF125ST Pumped (bbl) 1,468.2 Average Water Temperature (F) 101 WF125 Pumped (bbl) 0 12:11:58 12:24:28 12:36:58 12:49:28 13:01:58 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 Drop Rate to Seal Collet Shift Sleeve Main Treatment © Schlumberger 1994-2017 Santos NDBi-30, Stage 6 May 30, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 188.0 40.0 4.7 YF125ST 7898 0.0 0.0 0 2 Slow for Seat 50.0 20.7 2.6 YF125ST 2113 0.0 0.0 0 3 Resume PAD 87.0 36.1 2.5 YF125ST 3639 0.0 0.0 0 4 1.0 PPA 180.0 39.9 4.5 YF125ST 7258 CarboLite 16/20 1.0 0.9 7049 5 2.0 PPA 220.0 40.0 5.5 YF125ST 8509 CarboLite 16/20 2.1 2.0 17106 6 4.0 PPA 240.0 40.0 6.0 YF125ST 8599 CarboLite 16/20 4.1 3.9 34645 7 6.0 PPA 240.0 40.0 6.0 YF125ST 8004 CarboLite 16/20 6.1 5.9 48587 8 8.0 PPA 240.0 39.8 6.0 YF125ST 7482 CarboLite 16/20 8.2 7.9 60830 9 10.0 PPA 225.1 39.6 5.7 YF125ST 6596 CarboLite 16/20 10.3 9.9 68538 10 Spacer 35.7 40.3 0.9 YF125ST 1439 0.0 0.0 0 11 Drop Collet 3.0 40.1 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD 40.0 40.2 4130 5241 2742 2 Slow for Seat 20.7 40.1 2156 2934 1387 3 Resume PAD 36.1 40.2 2763 3149 2618 4 1.0 PPA 39.9 40.1 2542 2637 2481 5 2.0 PPA 40.0 40.2 2466 2509 2426 6 4.0 PPA 40.0 40.3 2620 2815 2495 7 6.0 PPA 40.0 40.4 3234 3749 2815 8 8.0 PPA 39.8 40.4 4287 4840 3754 9 10.0 PPA 39.6 40.1 5114 5452 4852 10 Spacer 40.3 41.0 5321 5502 5072 11 Drop Collet 40.1 40.1 5102 5123 5086 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 12:07:22 Start PAD Automatically 5205 3374 0.0 40.0 0.0 2 12:07:22 Start Propped Frac Automatically 5205 3374 0.0 40.0 0.0 3 12:07:22 Start Stage 6 Automatically 5205 3374 0.0 40.0 0.0 4 12:09:16 Stage at Perfs: Spacer 4330 3181 76.0 40.0 0.0 5 12:12:04 Start Slow for Sea Automatically 925 3099 188.1 34.7 0.0 6 12:12:37 Stage at Perfs: Drop Collet 1790 3136 200.0 18.7 0.0 7 12:14:39 Start Resume PAD Automatically 2710 3177 237.9 18.6 0.0 8 12:14:45 Stage at Perfs: PAD 2696 3177 239.8 18.7 0.0 9 12:14:56 Stage at Perfs: Slow for Sea 2600 3172 243.2 18.7 0.0 10 12:17:11 Start 1.0 PPA Automatically 2637 3191 325.2 40.1 0.0 11 12:17:11 Started Pumping Prop 2637 3191 325.2 40.1 0.0 12 12:19:37 Stage at Perfs: Resume PAD 2541 3223 422.2 40.0 1.0 13 12:20:52 Stage at Perfs: 1.0 PPA 2486 3236 472.1 40.1 1.0 14 12:21:41 Start 2.0 PPA Automatically 2486 3246 504.8 40.0 1.0 15 12:23:03 Stage at Perfs: 2.0 PPA 2449 3268 559.4 39.9 2.0 16 12:27:11 Start 4.0 PPA Automatically 2513 3305 724.8 40.0 2.1 17 12:27:33 Stage at Perfs: 4.0 PPA 2527 3310 739.4 39.5 3.9 18 12:33:03 Stage At Perfs 2815 3328 959.3 40.0 3.9 19 12:33:11 Start 6.0 PPA Automatically 2824 3333 964.6 39.9 4.0 20 12:39:02 Stage At Perfs 3726 3200 1198.7 40.1 6.0 21 12:39:11 Start 8.0 PPA Automatically 3777 3204 1204.7 40.2 6.0 22 12:45:05 Stage At Perfs 4829 3264 1439.3 39.7 8.0 23 12:45:14 Start 10.0 PPA Automatically 4852 3268 1445.2 39.8 7.9 24 12:46:38 Activated Extend Stage 4930 3278 1501.0 40.2 10.0 25 12:50:54 Deactivated Extend Stage 5466 3319 1669.8 39.0 9.1 26 12:50:54 Start Spacer Manually 5466 3319 1669.8 39.0 9.1 27 12:51:00 Activated Extend Stage 5502 3323 1673.7 39.8 4.7 28 12:51:09 Stage at Perfs: Spacer 5530 3323 1679.8 40.9 0.4 29 12:51:21 Stopped Pumping Prop 5379 3319 1687.9 40.9 0.0 30 12:51:47 Deactivated Extend Stage 5127 3319 1705.4 40.1 0.0 31 12:51:47 Start Drop Collet Manually 5127 3319 1705.4 40.1 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 7 Initial treating pressure on PAD was around 4,000 psi and slowly fell to about 2,400 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 5,400 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: Summary of Pressures When Collet Seats Collet #8 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,940 2,456 2,938 Bottomhole Pressure 2,855 3,148 3,800 Summary of Stage 7 Total Proppant Pumped (lb) 249,398 Max pumping Rate (bpm) 40.9 Total Proppant in Formation (lb) 249,398 Average Pumping Rate (bpm) 39.3 Total 16/20 Carbolite (lb) 234,688 Maximum Treating Pressure (psi) 5,365 Total 40/70 Carbolite (lb) 14,710 Average Treating Pressure (psi) 3,295 Total Slurry Pumped (bbl) 1,899.5 Average Water Temperature (F) 101 YF125ST Pumped (bbl) 1,645.6 WF125 Pumped (bbl) 0 12:57:15 13:13:55 13:30:35 13:47:15 14:03:55 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 ConDrop Rate to Seal Collet Shift Sleeve DataFRAC Main Treatment © Schlumberger 1994-2017 Santos NDBi-30, Stage 7 May 30, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 179.0 40.1 4.5 YF125ST 7519 0.0 0.0 0 2 Slow for Seat 50.0 20.5 2.6 YF125ST 2111 0.0 0.0 0 3 Resume Pad 71.0 37.4 1.9 YF125ST 2969 0.0 0.0 0 4 1.0 PPA 60.0 40.0 1.5 YF125ST 2428 CarboLite 40/70 1.0 0.9 2063 5 3.0 PPA 112.0 40.0 2.8 YF125ST 4182 CarboLite 40/70 3.1 2.8 12647 6 Resume PAD 50.0 40.1 1.2 YF125ST 2069 0.0 0.0 0 7 1.0 PPA 180.0 39.9 4.5 YF125ST 7258 CarboLite 16/20 1.1 0.9 7052 8 2.0 PPA 220.0 40.0 5.5 YF125ST 8509 CarboLite 16/20 2.1 2.0 17109 9 4.0 PPA 240.0 40.0 6.0 YF125ST 8599 CarboLite 16/20 4.1 3.9 34639 10 6.0 PPA 240.0 40.0 6.0 YF125ST 8002 CarboLite 16/20 6.1 5.9 48632 11 8.0 PPA 240.0 39.9 6.0 YF125ST 7483 CarboLite 16/20 8.1 7.9 60792 12 10.0 PPA 224.2 39.6 5.7 YF125ST 6598 CarboLite 16/20 10.2 9.8 66465 13 Spacer 30.3 40.4 0.8 YF125ST 1264 0.0 0.0 0 14 Drop Collet 3.0 40.0 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD 40.1 40.3 4098 5209 2649 2 Slow for Seat 20.5 39.7 2285 3044 1428 3 Resume Pad 37.4 40.3 3195 3699 2861 4 1.0 PPA 40.0 40.1 2742 2856 2637 5 3.0 PPA 40.0 40.1 2498 2632 2403 6 Resume PAD 40.1 40.3 2420 2483 2399 7 1.0 PPA 39.9 40.1 2491 2522 2426 8 2.0 PPA 40.0 40.1 2400 2431 2376 9 4.0 PPA 40.0 40.3 2553 2748 2426 10 6.0 PPA 40.0 40.4 3109 3652 2747 11 8.0 PPA 39.9 40.2 4149 4697 3653 12 10.0 PPA 39.6 40.1 4986 5365 4619 13 Spacer 40.4 40.9 5123 5347 4921 14 Drop Collet 40.0 40.0 4961 5001 4935 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 12:51:52 Start PAD Automatically 5209 3323 0.0 39.9 0.0 2 12:51:52 Start Propped Frac Automatically 5209 3323 0.0 39.9 0.0 3 12:51:52 Start Stage 7 Automatically 5209 3323 0.0 39.9 0.0 4 12:56:20 Start Slow for Sea Automatically 1163 3223 179.0 35.5 0.0 5 12:57:06 Stage at Perfs: Drop Collet 1817 3250 194.9 18.3 0.0 6 12:58:56 Start Resume Pad Automatically 3246 3213 228.7 22.0 0.0 7 12:59:01 Stage at Perfs: PAD 3232 3209 230.6 24.6 0.0 8 12:59:09 Stage at Perfs: Slow for Sea 3374 3227 234.3 30.2 0.0 9 13:00:51 Start 1.0 PPA Automatically 2861 3200 300.0 40.0 0.0 10 13:00:51 Started Pumping Prop 2861 3200 300.0 40.0 0.0 11 13:02:21 Start 3.0 PPA Automatically 2632 3200 360.0 40.0 1.0 12 13:03:28 Stage at Perfs: Resume Pad 2509 3200 404.6 39.9 3.0 13 13:04:42 Stage at Perfs: 1.0 PPA 2412 3200 454.0 40.1 3.0 14 13:05:09 Start Resume PAD Automatically 2431 3195 472.0 39.9 2.6 15 13:05:24 Stopped Pumping Prop 2408 3195 482.0 40.2 0.2 16 13:06:24 Start 1.0 PPA Automatically 2504 3195 522.1 40.1 0.0 17 13:06:28 Started Pumping Prop 2509 3200 524.7 40.0 0.0 18 13:06:29 Stage at Perfs: 3.0 PPA 2518 3204 525.4 40.1 0.0 19 13:08:00 Stage at Perfs: Resume PAD 2522 3204 585.6 39.9 1.0 20 13:10:48 Stage at Perfs: 1.0 PPA 2431 3218 697.4 40.1 1.0 21 13:10:55 Start 2.0 PPA Automatically 2412 3218 702.1 39.9 1.0 22 13:12:03 Stage at Perfs: 2.0 PPA 2399 3227 747.4 39.8 2.0 23 13:16:25 Start 4.0 PPA Automatically 2426 3246 922.0 39.9 2.0 24 13:16:33 Stage at Perfs: 4.0 PPA 2426 3246 927.3 40.0 2.1 25 13:22:03 Stage At Perfs 2733 3264 1147.3 40.2 4.1 26 13:22:25 Start 6.0 PPA Automatically 2756 3264 1162.1 40.0 4.0 27 13:28:03 Stage At Perfs 3593 3287 1387.2 39.8 6.1 28 13:28:25 Start 8.0 PPA Automatically 3671 3291 1401.8 39.9 6.0 29 13:34:04 Stage At Perfs 4646 3323 1627.1 39.7 8.0 30 13:34:26 Start 10.0 PPA Automatically 4697 3333 1641.8 40.1 8.1 31 13:40:06 Start Spacer Manually 5388 3246 1865.9 40.5 2.6 32 13:40:08 Stage at Perfs: Spacer 5333 3236 1867.2 41.0 1.1 33 13:40:14 Activated Extend Stage 5237 3236 1871.3 40.8 0.2 34 13:40:51 Deactivated Extend Stage 5022 3246 1896.2 40.2 0.0 35 13:40:51 Start Drop Collet Manually 5022 3246 1896.2 40.2 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 8 Stage 8 began with a 171 bbl of YF125ST - DataFRAC. The decline was observed for about 1 hour and 20 minutes. The redesign consisted of increasing pad volume by 25bbl and making the 8ppa step optional depending on treating pressures. As can be seen in the graph below, the 8ppa step was successfully pumped and there was no evidence during the treatment that the frac communicated with the fault. Initial treating pressure on PAD was around 4,200 psi and decreased to about 2,600 psi before the scour steps. Surface pressure slightly increased when the scours entered the formation but fell back to 2,600 once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 4,100 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. Summary of Pressures When Collet Seats Collet #9 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,783 1,906 2,185 Bottomhole Pressure 2,867 2,922 3,090 Summary of Stage 8 Total Proppant Pumped (lb) 209,367 Max pumping Rate (bpm) 41.0 Total Proppant in Formation (lb) 209,367 Average Pumping Rate (bpm) 38.8 Total 16/20 Carbolite (lb) 194,499 Maximum Treating Pressure (psi) 5,113 Total 40/70 Carbolite (lb) 14,868 Average Treating Pressure (psi) 2,940 Total Slurry Pumped (bbl) 2,747.2 Average Water Temperature (F) 101 YF125ST Pumped (bbl) 1,955 WF125 Pumped (bbl) 579.6 15:06:55 15:27:45 15:48:35 16:09:25 16:30:15 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 Drop Rate to Seal Collet Shift Sleeve Stage 9 Injection Main Treatment © Schlumberger 1994-2017 Santos NDBi-30, Stage 8 May 30, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 DataFRAC 171.0 40.1 4.3 YF125ST 7183 0.0 0.0 0 2 Slow for Seat 50.0 20.3 2.6 YF125ST 2107 0.0 0.0 0 3 DF Flush 214.2 39.4 5.5 WF125 9011 0.0 0.0 0 4 XL Check 36.3 18.9 2.1 YF125ST 1511 0.0 0.0 0 5 Pad 275.0 39.2 7.1 YF125ST 11535 0.0 0.0 0 6 1.0 PPA 60.0 40.0 1.5 YF125ST 2433 CarboLite 40/70 1.0 0.8 2011 7 3.0 PPA 112.0 40.0 2.8 YF125ST 4183 CarboLite 40/70 3.1 2.8 12857 8 Resume PAD 125.0 40.1 3.1 YF125ST 5209 0.0 0.0 0 9 1.0 PPA 140.0 39.8 3.5 YF125ST 5648 CarboLite 16/20 1.0 0.9 5397 10 2.0 PPA 160.0 40.1 4.0 YF125ST 6191 CarboLite 16/20 2.0 1.9 12359 11 3.0 PPA 160.0 40.0 4.0 YF125ST 5953 CarboLite 16/20 3.1 2.9 17944 12 4.0 PPA 170.0 40.0 4.2 YF125ST 6087 CarboLite 16/20 4.0 4.0 24638 13 5.0 PPA 170.0 40.0 4.3 YF125ST 5869 CarboLite 16/20 5.1 4.9 29755 14 6.0 PPA 159.1 39.9 4.0 YF125ST 5302 CarboLite 16/20 6.2 5.9 32314 15 7.0 PPA 140.0 39.8 3.5 YF125ST 4511 CarboLite 16/20 7.1 6.9 32038 16 8.0 PPA 163.7 40.0 4.1 YF125ST 5174 CarboLite 16/20 8.2 7.6 40053 17 Spacer 23.5 40.5 0.6 YF125ST 988 0.0 0.0 0 18 Drop Collet 3.0 39.8 0.1 YF125ST 126 0.0 0.0 0 19 XL Flush 50.0 40.0 1.3 YF125ST 2100 0.0 0.0 0 20 Linear Flush 112.0 40.0 2.8 WF125 4709 0.0 0.0 0 21 Slow For Seat 50.0 20.0 2.6 WF125 2102 0.0 0.0 0 22 Overflush 202.4 39.4 5.2 WF125 8522 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 DataFRAC 40.1 40.2 3936 5113 2242 2 Slow for Seat 20.3 39.6 2106 2866 1442 3 DF Flush 39.4 40.0 2629 2884 394 4 XL Check 18.9 20.1 2130 2348 407 5 Pad 39.2 40.6 3091 4120 2133 6 1.0 PPA 40.0 40.1 2647 2660 2623 7 3.0 PPA 40.0 40.1 2586 2637 2545 8 Resume PAD 40.1 40.4 2651 2715 2545 9 1.0 PPA 39.8 40.1 2608 2692 2568 10 2.0 PPA 40.1 40.3 2569 2596 2541 11 3.0 PPA 40.0 40.2 2639 2682 2596 12 4.0 PPA 40.0 40.2 2727 2756 2682 13 5.0 PPA 40.0 40.2 2781 2821 2742 14 6.0 PPA 39.9 40.3 2918 3012 2824 15 7.0 PPA 39.8 40.2 3216 3410 3003 16 8.0 PPA 40.0 41.0 3791 4079 3415 17 Spacer 40.5 41.0 3819 3978 3658 18 Drop Collet 39.8 39.8 3749 3810 3708 19 XL Flush 40.0 40.1 3831 3932 3739 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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) 20 Linear Flush 40.0 40.2 3304 3731 1796 21 Slow For Seat 20.0 37.7 1820 2536 1488 22 Overflush 39.4 40.0 2999 3250 5 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 13:40:56 Start DataFRAC Automatically 5122 3250 0.0 40.0 0.1 2 13:40:56 Start Propped Frac Automatically 5122 3250 0.0 40.0 0.1 3 13:40:56 Start Stage 8 Automatically 5122 3250 0.0 40.0 0.1 4 13:41:44 Stopped Pumping Prop 4642 3246 32.0 40.1 0.0 5 13:45:12 Start Slow for Sea Automatically 1030 3145 170.8 34.6 0.0 6 13:46:15 Stage at Perfs: Drop Collet 1941 3181 191.5 18.2 0.0 7 13:47:49 Start DF Flush Automatically 2687 3209 221.0 26.9 0.0 8 13:47:51 Stage at Perfs: DataFRAC 2806 3213 222.0 29.0 0.0 9 13:47:58 Stage at Perfs: Slow for Sea 2797 3213 225.7 34.9 0.0 10 13:49:29 Activated Extend Stage 2554 3213 285.7 39.9 0.0 11 13:52:04 Stage at Perfs: DF Flush 2802 3232 388.9 39.9 0.0 12 15:14:46 Deactivated Extend Stage 407 3342 434.9 0.0 0.0 13 15:14:46 Start XL Check Manually 407 3342 434.9 0.0 0.0 14 15:15:18 Stage at Perfs: XL Check 2403 3397 438.5 16.4 0.0 15 15:15:26 Activated Extend Stage 2248 3392 441.1 20.1 0.0 16 15:16:56 Deactivated Extend Stage 2133 3406 471.2 20.0 0.0 17 15:16:56 Start Pad Manually 2133 3406 471.2 20.0 0.0 18 15:21:41 Stage At Perfs 2692 3291 653.1 40.2 0.0 19 15:22:35 Stage At Perfs 2614 3310 689.1 40.0 0.0 20 15:24:01 Start 1.0 PPA Automatically 2646 3346 746.6 39.9 0.0 21 15:24:16 Started Pumping Prop 2646 3360 756.6 39.9 0.0 22 15:25:31 Start 3.0 PPA Automatically 2628 3387 806.6 40.1 1.1 23 15:28:19 Start Resume PAD Automatically 2559 3424 918.6 40.2 3.0 24 15:28:35 Stopped Pumping Prop 2568 3433 929.3 40.2 0.3 25 15:29:28 Stage at Perfs: Resume PAD 2669 3438 964.7 40.0 0.0 26 15:30:57 Stage At Perfs 2715 3465 1024.1 40.0 0.0 27 15:31:26 Start 1.0 PPA Automatically 2687 3424 1043.4 40.0 0.0 28 15:31:29 Started Pumping Prop 2719 3406 1045.4 40.0 0.0 29 15:33:46 Stage At Perfs 2568 3291 1136.2 39.9 1.0 30 15:34:57 Start 2.0 PPA Automatically 2559 3310 1183.5 39.9 1.0 31 15:36:54 Stage At Perfs 2541 3328 1261.5 40.0 2.0 32 15:38:57 Start 3.0 PPA Automatically 2591 3342 1343.7 40.1 2.0 33 15:40:23 Stage At Perfs 2618 3360 1401.0 40.0 3.0 34 15:42:57 Start 4.0 PPA Automatically 2701 3378 1503.7 40.1 3.0 35 15:44:24 Stage At Perfs 2715 3383 1561.7 40.0 4.0 36 15:47:12 Start 5.0 PPA Automatically 2737 3401 1673.8 40.3 4.0 37 15:48:24 Stage At Perfs 2783 3410 1721.7 40.0 5.0 38 15:51:27 Start 6.0 PPA Automatically 2824 3241 1843.7 39.9 5.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 39 15:52:39 Stage At Perfs 2888 3250 1891.5 39.4 5.9 40 15:55:26 Start 7.0 PPA Automatically 3030 3259 2002.6 39.6 6.0 41 15:56:55 Stage At Perfs 3204 3268 2061.8 40.1 6.9 42 15:58:57 Start 8.0 PPA Automatically 3429 3282 2142.7 40.1 7.0 43 15:59:41 Activated Extend Stage 3552 3287 2171.9 39.8 8.0 44 16:00:54 Stage At Perfs 3836 3291 2220.3 40.2 8.0 45 16:03:02 Deactivated Extend Stage 3960 3296 2306.0 41.0 0.3 46 16:03:02 Start Spacer Manually 3960 3296 2306.0 41.0 0.3 47 16:03:09 Activated Extend Stage 3932 3287 2310.8 40.8 0.0 48 16:03:11 Stopped Pumping Prop 3918 3305 2312.1 40.7 0.0 49 16:03:37 Deactivated Extend Stage 3841 3305 2329.5 39.8 0.0 50 16:03:37 Start Drop Collet Manually 3841 3305 2329.5 39.8 0.0 51 16:03:42 Start XL Flush Automatically 3932 3310 2332.9 39.8 0.0 52 16:04:23 Stage at Perfs: Drop Collet 3841 3305 2360.2 40.0 0.0 53 16:04:57 Start Linear Flush Automatically 3708 3310 2382.8 40.1 0.0 54 16:07:46 Start Slow For Sea Automatically 1263 3259 2495.0 29.5 0.0 55 16:09:16 Stage at Perfs: XL Flush 1767 3282 2523.4 18.2 0.0 56 16:10:20 Start Overflush Automatically 2380 3291 2544.6 30.4 0.0 57 16:10:25 Stage at Perfs: Linear Flush 2747 3305 2547.2 32.3 0.0 58 16:10:31 Stage at Perfs: Slow For Sea 2975 3305 2550.6 36.0 0.0 59 16:10:37 Activated Extend Stage 2783 3314 2554.4 38.7 0.0 60 16:11:47 Stage at Perfs: Overflush 3058 3319 2600.7 39.9 0.0 61 16:14:35 Stage At Perfs 3108 3369 2712.6 40.0 0.0 62 16:26:43 Well Closed 787 3227 2746.9 0.0 0.0 63 17:30:03 Open well to FP 558 2834 2746.9 0.0 0.0 64 17:41:38 Closed Well 769 2673 2746.9 0.0 0.0 FracCAT Treatment Report Well : NDBi-030, Stages 9-11 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : 04-03-2024 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 330 Initial BHP at Gauge (psi) 1,922 Final Surface ISIP (psi) 1,112 Final ISIP at Gauge (psi) 2,629 Surface Shut in Pressure(psi) 1,144 BH Shut in Pressure (psi) 2,705 Maximum Treating Pressure (psi) 6,150 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl)5,456.5 Total Proppant Pumped per Load Tickets (lb) 743,830 Total YF125ST Past Wellhead (bbl) 4,348.6 Total Proppant in Formation per Load Tickets (lb)742,078 Total WF125 Past Wellhead (bbl) 310.3 Total 16/20 Carbolite per load Tickets (lb) 727,267 Total Freeze Protect Past Wellhead (bbl) 37.2 Total 40/70 Carbolite per FracCAT (lb) 16,563 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 209 208 M275 (lb) 120 56 J450 (gal) 106 106 J753 (gal) 14 15 J580 (lb) 5,052 4,926 J475 (lb) 1,210 1204 J532 (gal) 443 443 J134 (lb) 6 0 J511 (lb) 450 369 D206 (gal 3 3 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Summary On June 1, 2024, SLB performed a hydraulic fracturing treatment on Stage 9-11 of NBDi-030. The design called for the completion of stages 9-11, with a total of 719,656 pounds of proppant in 5,142 bbl of slurry. Stages 9 and 10 consisted of 1, 3, 5, 7, 9 and 10 ppa steps. Stage 11 consisted of two Scour stages, 1, 3, 5, 7, 9 and 10 ppa steps. Pump trips were staggered from 7,800 to 8,100 psi. The popoff was initially set to 8,300 psi. The stage was successfully completed with a total of 743,830 pounds of proppant pumped within 5,456.5. bbl of slurry. No mechanical issues were reported during the stage. A summary of the job is below. Summary of Stages 9-11 Material Actual Design Slurry Volume (bbl) 5,456.5 5,142 Clean Fluid Volume(bbl) 4,658.9 5,025 Proppant (lb) 743,830 719,656 09:05:44 10:04:04 11:02:24 12:00:44 12:59:04 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 Stage 9 Stage 10 Stage 11 Main Treatment © Schlumberger 1994-2017 Santos NDBi-030 Stages 9-11 June 1, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 9 Initial treating pressure on PAD was around 3,460 psi and slowly fell to about 2,600 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 5,000 psi once sand was cut on surface. Slurry rate remained steady at 40bpm until rate was slowed for the collet to seat. When the collet for Stage 10 seated, the pressure signature was not very noticeable. The pressure after the sleeve shifting did not increase after the sleeve was shifted. A summary of the Stage and its measured pump schedule is below. Summary of Pressures When Collet Seats Collet #10 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,018 2,050 2,050 Bottomhole Pressure 2,866 2,888 2,888 Summary of Stage 9 Total Proppant Pumped (lb) 241,325 Max pumping Rate (bpm) 41.4 Total Proppant in Formation (lb) 241,325 Average Pumping Rate (bpm) 35.5 Total CarboLite 16/20 241,325 Maximum Treating Pressure (psi) 5,017 Total Slurry Pumped (bbl) 1,814.1 Average Treating Pressure (psi) 3,119 YF125ST Pumped (bbl) 1,380.3 Average Water Temperature (F) 101 WF125 Pumped (bbl) 191.4 09:58:04 10:14:44 10:31:24 10:48:04 11:04:44 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 NDBi-030 Stage 9 June 1, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 Load Hole 1.5 3.6 0.4 WF125 58 0.0 0.0 0 2 Pump Ball 190.0 4.0 47.2 WF125 7980 0.0 0.0 0 3 XL Check 44.6 19.1 2.5 YF125ST 1862 0.0 0.0 0 4 PAD 300.0 39.3 7.7 YF125ST 12586 0.0 0.0 0 5 1.0 PPA 180.0 39.9 4.5 YF125ST 7268 CarboLite 16/20 1.0 0.9 6934 6 3.0 PPA 200.0 39.9 5.0 YF125ST 7453 CarboLite 16/20 3.1 2.9 22478 7 5.0 PPA 230.0 39.9 5.8 YF125ST 7945 CarboLite 16/20 5.1 4.9 40733 8 7.0 PPA 230.0 40.1 5.7 YF125ST 7412 CarboLite 16/20 7.2 6.9 53397 9 9.0 PPA 215.0 39.8 5.4 YF125ST 6493 CarboLite 16/20 9.2 8.9 60287 10 10.0 PPA 180.2 40.0 4.5 YF125ST 5270 CarboLite 16/20 10.2 10.0 57496 11 Spacer 39.8 40.5 1.0 YF125ST 1558 0.0 0.0 0 12 Drop Collet 3.0 39.9 0.1 YF125ST 126 0.0 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Load Hole 3.6 4.0 563 600 325 2 Pump Ball 4.0 4.0 711 751 604 3 XL Check 19.1 20.1 1922 2014 751 4 PAD 39.3 40.2 2850 3392 1964 5 1.0 PPA 39.9 40.1 2688 2751 2628 6 3.0 PPA 39.9 40.2 2599 2660 2554 7 5.0 PPA 39.9 40.3 2807 3156 2618 8 7.0 PPA 40.1 40.8 3823 4367 3168 9 9.0 PPA 39.8 40.3 4512 4784 4294 10 10.0 PPA 40.0 40.7 4859 5003 4765 11 Spacer 40.5 41.4 4806 5017 4527 12 Drop Collet 39.9 39.9 4570 4601 4536 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 7:13:11 Flooding Lines 5 5 0.0 0.0 0.0 2 7:20:47 Priming Pumps 46 14 0.0 0.0 0.0 3 7:28:01 Good Check Valve 1241 9 0.0 5.4 0.0 4 7:49:58 Starting PT 1218 9 0.0 0.0 0.0 5 8:15:59 Good PT 8551 18 0.0 0.0 0.0 6 8:25:36 PJSM 69 18 0.0 0.0 0.0 7 8:47:53 Mixing Gel 27 0 0.0 0.0 0.0 8 9:14:06 Well Open 334 3012 0.0 0.0 0.0 9 9:15:26 Start Load Hole Automatically 330 3007 0.0 0.0 0.0 10 9:15:26 Start Propped Frac Automatically 330 3007 0.0 0.0 0.0 11 9:15:26 Start Stage 9 Automatically 330 3007 0.0 0.0 0.0 12 9:15:32 Started Pumping 330 3007 0.0 0.0 0.0 13 9:16:03 Dropped Ball 352 3003 0.0 0.0 0.0 14 9:17:06 Start Pump Ball Manually 609 3012 1.5 4.0 0.0 15 10:04:19 Start XL Check Automatically 746 3314 191.5 4.0 0.0 16 10:04:50 Activated Extend Stage 1982 3355 197.4 20.1 0.0 17 10:05:26 Stage at Perfs: Load Hole 1987 3365 209.4 20.0 0.0 18 10:05:30 Stage at Perfs: XL Check 1982 3365 210.7 20.0 0.0 19 10:06:46 Deactivated Extend Stage 1968 3383 236.1 20.1 0.0 20 10:06:46 Start PAD Manually 1968 3383 236.1 20.1 0.0 21 10:11:06 Stage at Perfs: PAD 2701 3305 401.6 39.9 0.0 22 10:12:12 Stage at Perfs: PAD 2710 3360 445.7 40.3 0.0 23 10:14:28 Start 1.0 PPA Automatically 2737 3456 536.6 40.1 0.0 24 10:14:28 Started Pumping Prop 2737 3456 536.6 40.1 0.0 25 10:18:59 Start 3.0 PPA Automatically 2632 3355 716.7 39.9 1.0 26 10:19:44 Stage at Perfs: 3.0 PPA 2660 3383 746.6 39.7 3.0 27 10:23:59 Start 5.0 PPA Automatically 2637 3291 916.5 40.0 2.9 28 10:24:14 Stage at Perfs: 5.0 PPA 2632 3296 926.5 39.6 4.9 29 10:29:15 Stage at Perfs: 5.0 PPA 3085 3419 1126.5 39.6 5.0 30 10:29:45 Start 7.0 PPA Automatically 3177 3433 1146.4 39.8 5.0 31 10:34:59 Stage at Perfs: 7.0 PPA 4330 3323 1356.1 40.5 6.8 32 10:35:29 Start 9.0 PPA Automatically 4362 3333 1376.2 40.0 7.0 33 10:40:45 Stage at Perfs: 9.0 PPA 4793 3419 1585.9 40.0 9.0 34 10:40:53 Start 10.0 PPA Automatically 4779 3419 1591.2 40.2 9.1 35 10:43:35 Activated Extend Stage 4852 3250 1699.3 39.9 9.9 36 10:45:23 Deactivated Extend Stage 5003 3282 1771.2 40.1 10.0 37 10:45:23 Start Spacer Manually 5003 3282 1771.2 40.1 10.0 38 10:45:27 Activated Extend Stage 5017 3282 1773.9 40.0 10.0 39 10:45:45 Stopped Pumping Prop 4852 3282 1786.1 41.3 0.0 40 10:46:07 Stage at Perfs: Spacer 4541 3282 1801.0 40.1 0.0 41 10:46:22 Deactivated Extend Stage 4619 3287 1811.0 39.8 0.0 42 10:46:22 Start Drop Collet Manually 4619 3287 1811.0 39.8 0.0 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 10 Initial treating pressure on PAD was around 3,100 psi and slowly fell to about 2,400 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to about 5,200 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. Summary of Pressures When Collet Seats Collet #11 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,046 2,253 2,450 Bottomhole Pressure 2,822 2,961 3,180 Summary of Stage 10 Total Proppant Pumped (lb) 254,408 Max pumping Rate (bpm) 41.0 Total Proppant in Formation (lb) 254,408 Average Pumping Rate (bpm) 39.1 CarboLite 16/20 254,408 Maximum Treating Pressure (psi) 5,150 Total Slurry Pumped (bbl) 1,673.2 Average Treating Pressure (psi) 3,204 YF125ST Pumped (bbl) 1,418.5 Average Water Temperature (F) 101 WF125 Pumped (bbl) 0 10:55:28 11:05:53 11:16:18 11:26:43 11:37:08 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 Main Treatment © Schlumberger 1994-2017 Santos NDBi-030 Stage 10 June 1, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 154.0 40.1 3.8 YF125ST 6469 0.0 0.0 0 2 Slow for Seat 50.0 20.4 2.6 YF125ST 2113 0.0 0.0 0 3 Resume PAD 121.0 36.4 3.5 YF125ST 5067 0.0 0.0 0 4 1.0 PPA 190.0 39.9 4.8 YF125ST 7662 CarboLite 16/20 1.0 0.9 7546 5 3.0 PPA 215.0 39.9 5.4 YF125ST 8006 CarboLite 16/20 3.1 2.9 24292 6 5.0 PPA 240.0 39.9 6.0 YF125ST 8292 CarboLite 16/20 5.1 4.9 42468 7 7.0 PPA 240.0 39.7 6.0 YF125ST 7738 CarboLite 16/20 7.2 6.9 55652 8 9.0 PPA 220.0 39.9 5.5 YF125ST 6645 CarboLite 16/20 9.2 8.9 61662 9 10.0 PPA 201.9 40.0 5.1 YF125ST 5907 CarboLite 16/20 10.2 10.0 62789 10 Spacer 38.3 40.3 1.0 YF125ST 1551 0.0 0.0 0 11 Drop Collet 3.0 39.8 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 PAD 40.1 40.2 3804 4678 2762 2 Slow for Seat 20.4 40.2 2011 2229 1570 3 Resume PAD 36.4 40.5 2510 2843 2202 4 1.0 PPA 39.9 40.1 2466 2518 2426 5 3.0 PPA 39.9 40.2 2440 2509 2380 6 5.0 PPA 39.9 40.3 2612 2747 2509 7 7.0 PPA 39.7 40.2 3007 3397 2724 8 9.0 PPA 39.9 40.5 3852 4517 3351 9 10.0 PPA 40.0 40.5 4879 5150 4518 10 Spacer 40.3 41.0 4805 5099 4509 11 Drop Collet 39.8 39.9 4597 4645 4559 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 10:46:27 Start PAD Automatically 4687 3291 0.0 39.9 0.0 2 10:46:27 Start Propped Frac Automatically 4687 3291 0.0 39.9 0.0 3 10:46:27 Start Stage 10 Automatically 4687 3291 0.0 39.9 0.0 4 10:50:18 Start Slow for Sea Automatically 1222 3200 154.2 34.9 0.0 5 10:50:51 Stage at Perfs: Drop Collet 2000 3213 166.0 18.3 0.0 6 10:52:54 Start Resume PAD Automatically 2211 3236 203.7 18.4 0.0 7 10:53:00 Stage at Perfs: PAD 2220 3236 205.5 18.3 0.0 8 10:53:11 Stage at Perfs: Slow for Sea 2220 3236 208.9 18.4 0.0 9 10:56:26 Start 1.0 PPA Automatically 2522 3291 325.1 40.1 0.0 10 10:56:26 Started Pumping Prop 2522 3291 325.1 40.1 0.0 11 10:57:11 Stage at Perfs: Resume PAD 2486 3300 355.0 39.7 1.0 12 10:58:26 Stage at Perfs: 1.0 PPA 2440 3319 404.8 39.9 1.0 13 11:01:11 Start 3.0 PPA Automatically 2486 3351 514.7 40.0 1.0 14 11:01:28 Stage at Perfs: 3.0 PPA 2431 3351 526.0 39.5 2.9 15 11:06:13 Stage At Perfs 2509 3392 715.4 40.1 3.0 16 11:06:35 Start 5.0 PPA Automatically 2509 3392 730.1 40.0 3.0 17 11:11:38 Stage At Perfs 2715 3419 931.3 40.0 5.0 18 11:12:36 Start 7.0 PPA Automatically 2742 3424 969.9 40.0 5.1 19 11:17:39 Stage At Perfs 3300 3246 1170.5 40.0 7.0 20 11:18:38 Start 9.0 PPA Automatically 3383 3255 1209.7 39.9 7.0 21 11:23:40 Stage At Perfs 4422 3314 1410.4 40.0 8.8 22 11:24:09 Start 10.0 PPA Automatically 4523 3319 1429.9 40.1 8.8 23 11:24:16 Activated Extend Stage 4541 3319 1434.6 40.2 8.9 24 11:29:11 Stage At Perfs 5095 3374 1631.0 40.0 10.2 25 11:29:12 Deactivated Extend Stage 5104 3374 1631.6 40.0 10.2 26 11:29:12 Start Spacer Manually 5104 3374 1631.6 40.0 10.2 27 11:29:15 Activated Extend Stage 5090 3374 1633.6 39.8 6.1 28 11:30:09 Deactivated Extend Stage 4660 3369 1669.9 39.8 0.1 29 11:30:09 Start Drop Collet Manually 4660 3369 1669.9 39.8 0.1 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay Country: United States Stage 11 Initial treating pressure on PAD was around 3,000 psi and slowly fell to about 2,400 psi once 1 ppa was going into formation. At this point, the treating pressure gradually increased to 4,800 psi once sand was cut on surface. Slurry rate remained steady at 40bpm until rate was lowered to swap to freeze protect. A summary of the Stage and its measured pump schedule is below. Summary of Stage 11 Total Proppant Pumped (lb) 248,097 Max Pumping Rate (bpm) 41.1 Total Proppant in Formation (lb) 246,345 Average Pumping Rate (bpm) 38.7 Total 16/20 Carbolite (lb) 231,534 Maximum Treating Pressure (psi) 4,752 Total 40/70 Carbolite (lb) 16,563 Average Treating Pressure (psi) 3,012 Total Slurry Pumped (bbl) 1,969.2 Average Water Temperature (F) 101 YF125ST Pumped (bbl) 1,549.8 WF125 Pumped (bbl) 118.9 11:33:21 11:50:01 12:06:41 12:23:21 12:40:01 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 Main Treatment © Schlumberger 1994-2017 Santos NDBi-030 Stage 11 June 1, 2024 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 147.0 40.0 3.7 YF125ST 6201 0.1 0.0 0 2 Slow for Seat 50.0 19.3 2.6 YF125ST 2105 0.0 0.0 0 3 Resume Pad 103.0 39.1 2.6 YF125ST 4318 0.1 0.0 0 4 1.0 PPA 60.0 40.0 1.5 YF125ST 2430 CarboLite 40/70 1.0 0.8 2145 5 3.0 PPA 121.3 39.8 3.0 YF125ST 4532 CarboLite 40/70 3.1 2.8 14418 6 PAD 50.0 40.3 1.2 YF125ST 2070 0.0 0.0 0 7 1.0 PPA 190.0 40.0 4.8 YF125ST 7660 CarboLite 16/20 1.1 0.9 7540 8 3.0 PPA 250.0 39.9 6.3 YF125ST 9305 CarboLite 16/20 3.1 2.9 28390 9 5.0 PPA 240.1 39.9 6.0 YF125ST 8296 CarboLite 16/20 5.1 4.9 42468 10 7.0 PPA 228.8 39.9 5.7 YF125ST 7375 CarboLite 16/20 7.1 6.9 53072 11 9.0 PPA 171.0 39.8 4.3 YF125ST 5167 CarboLite 16/20 9.2 8.9 47854 12 10.0 PPA 186.2 40.0 4.7 YF125ST 5631 CarboLite 16/20 10.2 9.0 52210 13 Flush 118.6 38.6 3.2 WF125 4995 0.0 0.0 0 14 Freeze Protect 53.2 19.9 2.8 Freeze Protect 2250 0.0 0.0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD 40.0 40.2 3725 4706 1543 2 Slow for Seat 19.3 31.0 2169 2820 1543 3 Resume Pad 39.1 40.5 2544 2779 2504 4 1.0 PPA 40.0 40.2 2525 2545 2472 5 3.0 PPA 39.8 40.3 2429 2472 2390 6 PAD 40.3 40.5 2448 2518 2422 7 1.0 PPA 40.0 40.1 2495 2563 2463 8 3.0 PPA 39.9 40.2 2464 2531 2390 9 5.0 PPA 39.9 40.1 2593 2696 2509 10 7.0 PPA 39.9 40.4 3021 3447 2687 11 9.0 PPA 39.8 40.3 3798 4243 3410 12 10.0 PPA 40.0 41.1 4521 4752 4248 13 Flush 38.6 40.7 3791 4504 1680 14 Freeze Protect 19.9 20.0 1889 2046 1016 Client: Santos Well: NDBi-030 Formation: Nanushuk District: Prudhoe Bay 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 11:30:14 Start PAD Automatically 4678 3374 0.0 39.9 0.1 2 11:30:14 Start Propped Frac Automatically 4678 3374 0.0 39.9 0.1 3 11:30:14 Start Stage 11 Automatically 4678 3374 0.0 39.9 0.1 4 11:33:56 Start Slow for Sea Automatically 2014 3232 147.1 24.8 0.1 5 11:34:31 Stage at Perfs: Drop Collet 2005 3227 158.3 18.4 0.0 6 11:36:32 Stage at Perfs: PAD 2737 3241 196.8 29.0 0.1 7 11:36:32 Start Resume Pad Automatically 2737 3241 196.8 29.0 0.1 8 11:36:37 Stopped Pumping Prop 2486 3232 199.4 31.9 0.1 9 11:36:38 Stage at Perfs: Slow for Sea 2481 3241 199.9 32.2 0.0 10 11:39:10 Start 1.0 PPA Automatically 2541 3268 300.1 40.1 0.0 11 11:39:14 Started Pumping Prop 2541 3264 302.8 40.1 0.0 12 11:40:11 Stage at Perfs: Resume Pad 2518 3273 340.9 40.2 1.1 13 11:40:40 Start 3.0 PPA Automatically 2467 3278 360.2 40.2 1.0 14 11:41:26 Stage at Perfs: 1.0 PPA 2435 3278 390.8 40.2 3.2 15 11:41:41 Activated Extend Stage 2412 3282 400.7 39.3 3.0 16 11:43:42 Deactivated Extend Stage 2435 3291 481.0 40.4 2.4 17 11:43:42 Start PAD Manually 2435 3291 481.0 40.4 2.4 18 11:43:59 Stopped Pumping Prop 2431 3291 492.4 40.4 0.0 19 11:44:01 Stage at Perfs: 3.0 PPA 2426 3291 493.8 40.5 0.0 20 11:44:57 Start 1.0 PPA Automatically 2541 3296 531.3 40.1 0.0 21 11:45:02 Started Pumping Prop 2541 3296 534.7 40.2 0.0 22 11:45:31 Stage at Perfs: PAD 2563 3300 553.9 39.2 1.0 23 11:48:32 Stage at Perfs: 1.0 PPA 2476 3310 674.5 40.0 1.0 24 11:49:42 Start 3.0 PPA Automatically 2476 3319 721.1 40.1 1.0 25 11:49:48 Stage at Perfs: 3.0 PPA 2467 3319 725.1 40.0 1.0 26 11:54:33 Stage At Perfs 2495 3337 914.7 40.0 3.0 27 11:55:58 Start 5.0 PPA Automatically 2545 3337 971.4 40.1 3.1 28 12:00:49 Stage At Perfs 2669 3241 1164.8 39.8 5.0 29 12:01:59 Start 7.0 PPA Automatically 2687 3241 1211.4 40.0 4.9 30 12:06:51 Stage At Perfs 3369 3250 1405.3 40.1 7.1 31 12:07:43 Start 9.0 PPA Manually 3447 3255 1439.9 40.3 7.1 32 12:12:01 Start 10.0 PPA Manually 4243 3268 1610.9 40.1 9.1 33 12:12:35 Stage at Perfs: 10.0 PPA 4344 3273 1633.5 39.8 10.0 34 12:13:13 Activated Extend Stage 4445 3273 1658.8 40.1 9.8 35 12:16:36 Stopped Pumping Prop 4509 3287 1794.3 40.7 0.0 36 12:16:40 Deactivated Extend Stage 4427 3287 1797.0 40.5 0.0 37 12:16:40 Start Flush Manually 4427 3287 1797.0 40.5 0.0 38 12:16:50 Activated Extend Stage 4335 3282 1803.7 40.1 0.0 39 12:16:51 Stage at Perfs: Flush 4326 3291 1804.4 40.1 0.0 40 12:19:49 Deactivated Extend Stage 1822 3246 1915.7 19.9 0.0 41 12:19:49 Start Freeze Protect Manually 1822 3246 1915.7 19.9 0.0 42 12:28:58 Well Closed 1140 3099 1968.9 0.0 0.0 Santos Definitive Survey Report02 April, 2024Design: NDBi-030Santos NAD27 ConversionPikkaNDBNDBi030NDBi030 ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMap 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 Radius205,972,909.70423,383.560.970° 20' 10.138 N150° 37' 17.796 WWellWell PositionLongitudeLatitudeEastingNorthingusft/-/-Position UncertaintyusftusftusftGround Level:NDBi-030usftusft0.00.05,972,761.56422,153.8722.8Wellhead Elevation:usft0.570° 20' 8.556 N150° 37' 53.665 WWellboreDeclinationField StrengthnTSample Date Dip AngleNDBi-030Model NameMagneticsBGGM2023 1/04/2024 14.29 80.57 57,166.74999926PhaseVersionAudit NotesDesignNDBi-0301.0 ACTUALVertical SectionDepth From TVDusft/-usftDirection/-usftTie On Depth46.4316.900.00.046.4042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueFromusftSurvey ProgramDescriptionTool NameSurvey WellboreTousftDate2/04/2024SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)121.2 1,518.001 SDI URSA GyroMWD 16in Hole 46623_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag1,547.6 2,484.002 BH Ontrak16in Hole 15472484> ND3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,571.4 11,163.903 BH OntraK 1225in Hole 257111163> 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,241.6 17,529.004 BH OntraK in Hole 1124117529> MDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft46.4 0.00 0.00 46.4 -22.8 0.0 0.0 5,972,761.56 422,153.87 0.00 0.0121.2 0.09 3.16 121.2 52.0 0.1 0.0 5,972,761.62 422,153.87 0.12 0.0128.0 0.10 3.65 128.0 58.8 0.1 0.0 5,972,761.63 422,153.87 0.15 0.020" Conductor Driven183.3 0.18 5.63 183.3 114.1 0.2 0.0 5,972,761.76 422,153.89 0.15 0.1277.7 0.44 28.48 277.7 208.5 0.7 0.2 5,972,762.23 422,154.08 0.30 0.4372.9 1.23 352.97 372.9 303.7 2.0 0.3 5,972,763.56 422,154.14 0.95 1.3467.7 2.20 350.16 467.6 398.4 4.8 -0.2 5,972,766.37 422,153.74 1.03 3.6562.0 3.87 339.26 561.9 492.7 9.6 -1.6 5,972,771.15 422,152.35 1.86 8.1660.3 6.34 326.95 659.7 590.5 17.2 -5.8 5,972,778.84 422,148.30 2.74 16.5719.8 7.85 328.71 718.8 649.6 23.4 -9.7 5,972,785.11 422,144.46 2.56 23.7760.3 9.00 328.71 758.8 689.6 28.5 -12.7 5,972,790.20 422,141.43 2.84 29.5854.1 11.99 332.58 851.0 781.8 43.4 -21.0 5,972,805.21 422,133.29 3.27 46.1949.1 15.15 333.98 943.4 874.2 63.4 -31.0 5,972,825.23 422,123.50 3.34 67.51,043.8 15.04 333.98 1,034.8 965.6 85.5 -41.8 5,972,847.50 422,112.91 0.12 91.01,048.0 15.04 333.92 1,038.9 969.7 86.5 -42.3 5,972,848.49 422,112.45 0.38 92.1Upper Schrader Bluff1,138.3 15.04 332.58 1,126.1 1,056.9 107.4 -52.9 5,972,869.51 422,102.12 0.38 114.61,232.7 16.81 327.30 1,216.9 1,147.7 129.8 -65.9 5,972,892.01 422,089.34 2.42 139.81,327.2 18.82 322.03 1,306.8 1,237.6 153.3 -82.7 5,972,915.70 422,072.82 2.72 168.4042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft1,415.0 21.41 317.45 1,389.3 1,320.1 176.3 -102.2 5,972,938.88 422,053.51 3.45 198.6Permafrost Base1,422.6 21.64 317.11 1,396.3 1,327.1 178.3 -104.1 5,972,940.93 422,051.65 3.45 201.31,518.0 24.81 312.19 1,484.0 1,414.8 204.7 -130.9 5,972,967.56 422,025.10 3.89 238.91,547.6 25.93 313.81 1,510.7 1,441.5 213.3 -140.2 5,972,976.31 422,015.92 4.45 251.51,642.1 29.26 310.68 1,594.5 1,525.3 242.7 -172.6 5,973,006.00 421,983.80 3.84 295.11,736.3 31.80 310.38 1,675.6 1,606.4 273.8 -209.0 5,973,037.47 421,947.75 2.70 342.71,831.3 34.13 309.69 1,755.4 1,686.2 307.0 -248.6 5,973,071.13 421,908.50 2.48 394.01,835.0 34.25 309.67 1,758.4 1,689.2 308.3 -250.2 5,973,072.46 421,906.94 3.40 396.1Middle Schrader Bluff1,926.3 37.34 309.11 1,832.4 1,763.2 342.2 -291.5 5,973,106.76 421,866.01 3.40 449.02,020.7 40.52 306.78 1,905.9 1,836.7 378.7 -338.2 5,973,143.67 421,819.61 3.71 507.62,115.5 42.40 306.00 1,976.9 1,907.7 415.9 -388.8 5,973,181.42 421,769.47 2.06 569.32,210.4 43.96 306.18 2,046.1 1,976.9 454.1 -441.2 5,973,220.21 421,717.41 1.65 633.12,304.8 47.90 305.31 2,111.8 2,042.6 493.8 -496.3 5,973,260.39 421,662.76 4.22 699.62,334.0 49.02 304.99 2,131.1 2,061.9 506.3 -514.2 5,973,273.14 421,645.05 3.92 721.0MCU (Lower Schrader Bluff)2,399.0 51.51 304.31 2,172.7 2,103.5 534.7 -555.3 5,973,301.98 421,604.23 3.92 769.82,484.0 54.26 305.71 2,223.9 2,154.7 573.6 -610.8 5,973,341.44 421,549.14 3.49 836.22,550.0 55.47 306.79 2,261.9 2,192.7 605.5 -654.3 5,973,373.80 421,505.95 2.26 889.213-3/8" Surface Casing2,571.455.86 307.13 2,274.0 2,204.8 616.2-668.45,973,384.59 421,491.92 2.26 906.62,666.2 58.04 307.60 2,325.7 2,256.5 664.4 -731.5 5,973,433.42 421,429.33 2.34 984.92,760.9 60.34 308.43 2,374.2 2,305.0 714.5 -795.6 5,973,484.18 421,365.79 2.54 1,065.32,856.7 63.65 308.77 2,419.2 2,350.0 767.2 -861.7 5,973,537.62 421,300.26 3.47 1,149.02,898.0 65.23 308.94 2,437.0 2,367.8 790.6 -890.7 5,973,561.31 421,271.47 3.85 1,185.9Tuluvak Shale2,950.8 67.26 309.16 2,458.3 2,389.1 821.1 -928.3 5,973,592.15 421,234.25 3.85 1,233.8042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft3,044.8 70.26 309.58 2,492.3 2,423.1 876.6 -996.0 5,973,648.41 421,167.13 3.22 1,320.63,062.0 70.77 309.55 2,498.0 2,428.8 887.0 -1,008.5 5,973,658.87 421,154.73 2.98 1,336.7Tuluvak Sand3,139.9 73.09 309.39 2,522.2 2,453.0 934.0 -1,065.7 5,973,706.52 421,098.07 2.98 1,410.13,235.2 76.21 309.32 2,547.4 2,478.2 992.3 -1,136.7 5,973,765.50 421,027.65 3.28 1,501.23,329.8 78.76 308.39 2,567.9 2,498.7 1,050.2 -1,208.6 5,973,824.18 420,956.33 2.86 1,592.73,425.2 78.86 308.03 2,586.4 2,517.2 1,108.1 -1,282.2 5,973,882.83 420,883.40 0.38 1,685.23,519.6 78.90 307.51 2,604.62,535.41,164.9 -1,355.4 5,973,940.32 420,810.78 0.54 1,776.63,615.2 78.94 307.44 2,623.0 2,553.8 1,221.9 -1,429.8 5,973,998.16 420,736.93 0.08 1,869.23,710.0 79.00 306.96 2,641.2 2,572.0 1,278.2 -1,504.0 5,974,055.18 420,663.41 0.50 1,960.93,804.0 78.97 306.71 2,659.1 2,589.9 1,333.5 -1,577.8 5,974,111.27 420,590.12 0.26 2,051.83,899.1 78.90 305.83 2,677.4 2,608.2 1,388.7 -1,653.1 5,974,167.26 420,515.46 0.91 2,143.53,988.0 79.03 305.73 2,694.4 2,625.2 1,439.8 -1,723.9 5,974,218.99 420,445.22 0.18 2,229.14,085.8 79.00 305.83 2,713.0 2,643.8 1,495.9 -1,801.7 5,974,275.89 420,367.97 0.11 2,323.34,180.5 79.18 306.12 2,730.9 2,661.7 1,550.5 -1,877.0 5,974,331.30 420,293.28 0.36 2,414.64,275.2 79.12 306.13 2,748.8 2,679.6 1,605.3 -1,952.1 5,974,386.91 420,218.73 0.06 2,505.94,372.8 79.09 305.90 2,767.2 2,698.0 1,661.7 -2,029.6 5,974,444.07 420,141.79 0.23 2,600.14,467.5 79.06 307.03 2,785.2 2,716.0 1,716.9 -2,104.4 5,974,500.08 420,067.62 1.17 2,691.54,562.5 79.08 306.80 2,803.2 2,734.0 1,773.0 -2,179.0 5,974,556.88 419,993.63 0.24 2,783.44,656.8 79.09 307.33 2,821.0 2,751.8 1,828.8 -2,252.9 5,974,613.47 419,920.30 0.55 2,874.64,660.0 79.09 307.33 2,821.6 2,752.4 1,830.7 -2,255.4 5,974,615.39 419,917.84 0.17 2,877.7TS 7904,752.1 79.16 307.48 2,839.0 2,769.8 1,885.6 -2,327.2 5,974,671.08 419,846.56 0.17 2,966.94,846.4 79.03 307.58 2,856.8 2,787.6 1,942.0 -2,400.6 5,974,728.21 419,773.76 0.17 3,058.34,941.6 79.05 307.81 2,875.0 2,805.8 1,999.2 -2,474.6 5,974,786.15 419,700.37 0.24 3,150.65,036.5 79.12 307.54 2,892.9 2,823.7 2,056.2 -2,548.4 5,974,843.86 419,627.22 0.29 3,242.55,130.5 79.06 307.60 2,910.7 2,841.5 2,112.4 -2,621.5 5,974,900.88 419,554.67 0.09 3,333.65,226.0 79.06 307.32 2,928.8 2,859.6 2,169.4 -2,695.9 5,974,958.65 419,480.88 0.29 3,426.1042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft5,320.5 79.09 307.29 2,946.7 2,877.5 2,225.7 -2,769.7 5,975,015.66 419,407.64 0.04 3,517.65,415.4 79.12 306.89 2,964.7 2,895.5 2,281.9 -2,844.1 5,975,072.63 419,333.89 0.42 3,609.45,510.2 79.11 306.35 2,982.62,913.42,337.4 -2,918.8 5,975,128.91 419,259.78 0.56 3,701.05,603.8 79.13 305.65 3,000.3 2,931.1 2,391.4 -2,993.2 5,975,183.72 419,185.97 0.73 3,791.35,699.2 79.06 306.07 3,018.3 2,949.1 2,446.3 -3,069.1 5,975,239.37 419,110.64 0.44 3,883.25,793.6 79.07 306.21 3,036.2 2,967.0 2,501.0 -3,143.9 5,975,294.80 419,036.36 0.15 3,974.35,888.7 79.13306.343,054.2 2,985.0 2,556.3 -3,219.2 5,975,350.85 418,961.63 0.15 4,066.15,983.9 79.09 306.43 3,072.2 3,003.0 2,611.7 -3,294.5 5,975,407.05 418,887.00 0.10 4,157.96,077.7 79.09 306.43 3,089.9 3,020.7 2,666.4 -3,368.6 5,975,462.50 418,813.48 0.00 4,248.56,148.0 79.07 306.38 3,103.3 3,034.1 2,707.3 -3,424.1 5,975,504.05 418,758.34 0.08 4,316.4Seabee6,172.8 79.06 306.36 3,108.0 3,038.8 2,721.8 -3,443.7 5,975,518.69 418,738.88 0.08 4,340.46,266.5 79.05 306.32 3,125.8 3,056.6 2,776.3 -3,517.9 5,975,573.98 418,665.34 0.04 4,430.86,362.3 79.03 306.24 3,144.0 3,074.8 2,832.0 -3,593.7 5,975,630.40 418,590.13 0.08 4,523.26,456.9 79.03 306.28 3,162.0 3,092.8 2,886.9 -3,668.6 5,975,686.10 418,515.82 0.04 4,614.56,551.479.16 306.65 3,179.8 3,110.6 2,942.0 -3,743.1 5,975,741.98 418,441.82 0.41 4,705.76,646.7 79.12 306.29 3,197.8 3,128.6 2,997.6 -3,818.4 5,975,798.40 418,367.13 0.37 4,797.86,740.8 78.97 306.65 3,215.7 3,146.5 3,052.6 -3,892.7 5,975,854.10 418,293.39 0.41 4,888.76,835.8 78.94 307.00 3,233.9 3,164.7 3,108.5 -3,967.4 5,975,910.75 418,219.35 0.36 4,980.56,929.5 78.96 307.12 3,251.8 3,182.6 3,163.9 -4,040.7 5,975,966.90 418,146.57 0.13 5,071.07,025.3 78.94 307.34 3,270.2 3,201.0 3,220.8 -4,115.6 5,976,024.58 418,072.28 0.23 5,163.87,119.4 78.91 307.52 3,288.3 3,219.1 3,276.9 -4,189.0 5,976,081.49 417,999.50 0.19 5,254.97,214.3 78.94 307.58 3,306.5 3,237.3 3,333.7 -4,262.8 5,976,139.00 417,926.28 0.07 5,346.87,309.3 78.96 307.31 3,324.7 3,255.5 3,390.3 -4,336.8 5,976,196.42 417,852.89 0.28 5,438.77,404.0 78.96 307.73 3,342.8 3,273.6 3,446.9 -4,410.5 5,976,253.78 417,779.77 0.44 5,530.47,498.5 78.94 307.77 3,361.0 3,291.8 3,503.8 -4,483.9 5,976,311.36 417,706.98 0.05 5,622.07,593.3 78.93 307.78 3,379.2 3,310.0 3,560.7 -4,557.4 5,976,369.06 417,634.10 0.01 5,713.8042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft7,687.5 78.90 308.16 3,397.3 3,328.1 3,617.6 -4,630.3 5,976,426.67 417,561.84 0.40 5,805.17,782.8 78.90 307.92 3,415.6 3,346.4 3,675.2 -4,703.9 5,976,485.08 417,488.76 0.25 5,897.67,877.4 78.93 308.27 3,433.8 3,364.6 3,732.5 -4,777.0 5,976,543.12 417,416.29 0.36 5,989.37,972.6 78.96 307.95 3,452.1 3,382.9 3,790.2 -4,850.5 5,976,601.52 417,343.42 0.33 6,081.68,067.2 78.94 307.48 3,470.2 3,401.0 3,847.0 -4,924.0 5,976,659.09 417,270.54 0.49 6,173.38,161.9 78.90 307.01 3,488.4 3,419.2 3,903.2 -4,998.0 5,976,716.08 417,197.17 0.49 6,264.98,256.2 78.91306.843,506.5 3,437.3 3,958.8 -5,071.9 5,976,772.41 417,123.82 0.18 6,356.08,350.8 78.94 306.20 3,524.7 3,455.5 4,014.1 -5,146.5 5,976,828.45 417,049.76 0.66 6,447.48,445.8 78.96 305.41 3,542.9 3,473.7 4,068.6 -5,222.1 5,976,883.77 416,974.72 0.82 6,538.98,541.0 78.90 305.34 3,561.2 3,492.0 4,122.7 -5,298.3 5,976,938.62 416,899.14 0.10 6,630.48,635.0 78.91 305.78 3,579.3 3,510.1 4,176.3 -5,373.4 5,976,993.06 416,824.64 0.46 6,720.98,730.1 78.90 305.92 3,597.6 3,528.4 4,231.0 -5,449.0 5,977,048.48 416,749.59 0.14 6,812.48,824.4 78.88 306.36 3,615.8 3,546.6 4,285.6 -5,523.7 5,977,103.83 416,675.43 0.46 6,903.48,919.7 78.88 306.41 3,634.1 3,564.9 4,341.0 -5,599.0 5,977,160.08 416,600.73 0.05 6,995.39,014.0 78.87306.543,652.3 3,583.1 4,396.0 -5,673.4 5,977,215.83 416,526.93 0.14 7,086.39,109.7 78.88 306.77 3,670.8 3,601.6 4,452.1 -5,748.8 5,977,272.68 416,452.17 0.24 7,178.79,204.0 78.91 307.25 3,689.0 3,619.8 4,507.8 -5,822.7 5,977,329.17 416,378.83 0.50 7,269.99,298.478.94 307.22 3,707.1 3,637.9 4,563.9 -5,896.4 5,977,385.95 416,305.70 0.04 7,361.29,393.478.91 306.86 3,725.3 3,656.1 4,620.0 -5,970.8 5,977,442.85 416,231.91 0.37 7,453.09,487.8 78.97 306.48 3,743.5 3,674.3 4,675.4 -6,045.2 5,977,498.99 416,158.12 0.40 7,544.39,582.9 78.84 306.15 3,761.7 3,692.5 4,730.6 -6,120.3 5,977,554.98 416,083.58 0.37 7,635.99,653.0 79.00 306.40 3,775.2 3,706.0 4,771.3 -6,175.8 5,977,596.28 416,028.52 0.42 7,703.6Nanushuk9,677.1 79.06 306.49 3,779.8 3,710.6 4,785.4 -6,194.8 5,977,610.52 416,009.64 0.42 7,726.89,771.4 79.12 306.47 3,797.7 3,728.5 4,840.4 -6,269.3 5,977,666.34 415,935.77 0.07 7,817.99,866.4 79.12 306.58 3,815.6 3,746.4 4,896.0 -6,344.2 5,977,722.64 415,861.38 0.11 7,909.79,960.0 79.18 306.60 3,833.2 3,764.0 4,950.7 -6,418.0 5,977,778.20 415,788.15 0.07 8,000.1NT8 MFS042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft9,961.2 79.18 306.60 3,833.4 3,764.2 4,951.4 -6,419.0 5,977,778.89 415,787.23 0.07 8,001.210,055.6 79.10 306.78 3,851.2 3,782.0 5,006.8 -6,493.3 5,977,835.06 415,713.45 0.21 8,092.510,150.0 79.13 306.74 3,869.0 3,799.8 5,062.3 -6,567.6 5,977,891.30 415,639.77 0.05 8,183.810,240.0 79.10 306.79 3,886.0 3,816.8 5,115.2 -6,638.4 5,977,944.93 415,569.53 0.06 8,270.8NT7 MFS10,244.8 79.10 306.79 3,886.9 3,817.7 5,118.0 -6,642.2 5,977,947.78 415,565.79 0.06 8,275.410,340.1 79.09 306.60 3,905.0 3,835.8 5,174.0 -6,717.2 5,978,004.48 415,491.34 0.20 8,367.510,435.7 78.36 307.35 3,923.7 3,854.5 5,230.3 -6,792.1 5,978,061.62 415,417.06 1.08 8,459.810,510.0 78.20 309.79 3,938.8 3,869.6 5,275.7 -6,849.0 5,978,107.58 415,360.64 3.22 8,531.8NT6 MFS10,529.9 78.16 310.44 3,942.8 3,873.6 5,288.2 -6,863.9 5,978,120.27 415,345.89 3.22 8,551.110,624.9 77.49 313.72 3,962.9 3,893.7 5,350.4 -6,932.8 5,978,183.18 415,277.65 3.45 8,643.610,693.0 77.13 315.76 3,977.8 3,908.6 5,397.2 -6,980.0 5,978,230.45 415,230.92 2.97 8,710.1NT5 MFS10,719.9 76.99 316.57 3,983.9 3,914.7 5,416.1 -6,998.1 5,978,249.55 415,212.97 2.97 8,736.310,813.9 76.18 319.19 4,005.7 3,936.5 5,484.0 -7,059.5 5,978,318.00 415,152.35 2.84 8,827.710,895.0 75.62 321.28 4,025.4 3,956.2 5,544.4 -7,109.8 5,978,378.96 415,102.68 2.59 8,906.2NT4 MFS10,909.1 75.53 321.64 4,028.9 3,959.7 5,555.1 -7,118.3 5,978,389.69 415,094.31 2.59 8,919.811,002.4 75.13 324.38 4,052.6 3,983.4 5,627.2 -7,172.6 5,978,462.36 415,040.74 2.87 9,009.611,098.4 74.64 326.56 4,077.6 4,008.4 5,703.5 -7,225.1 5,978,539.26 414,989.00 2.25 9,101.211,163.9 74.43 328.35 4,095.1 4,025.9 5,756.7 -7,259.1 5,978,592.79 414,955.61 2.65 9,163.311,168.0 74.39 328.39 4,096.2 4,027.0 5,760.1 -7,261.2 5,978,596.18 414,953.57 1.41 9,167.1NT3 MFS11,201.0 74.04 328.72 4,105.2 4,036.0 5,787.2 -7,277.7 5,978,623.44 414,937.29 1.41 9,198.29-5/8" Intermediate Liner11,241.6 73.62 329.12 4,116.5 4,047.3 5,820.6 -7,297.9 5,978,657.06 414,917.50 1.41 9,236.4042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft11,280.0 75.12 329.95 4,126.8 4,057.6 5,852.5 -7,316.6 5,978,689.10 414,899.09 4.43 9,272.5NT3.2 Top Reservoir11,335.9 77.31 331.13 4,140.1 4,070.9 5,899.7 -7,343.3 5,978,736.62 414,872.90 4.43 9,325.211,431.5 80.99 331.68 4,158.1 4,088.9 5,982.1 -7,388.2 5,978,819.50 414,828.83 3.89 9,416.111,526.6 84.77 332.29 4,169.9 4,100.7 6,065.4 -7,432.5 5,978,903.24 414,785.39 4.03 9,507.211,593.0 87.27 332.73 4,174.5 4,105.3 6,124.2 -7,463.1 5,978,962.33 414,755.42 3.83 9,571.0NT3.2411,622.1 88.37 332.92 4,175.6 4,106.4 6,150.1 -7,476.4 5,978,988.35 414,742.40 3.83 9,599.011,693.1 89.97 331.37 4,176.64,107.46,212.9 -7,509.6 5,979,051.46 414,709.88 3.14 9,667.5NDB-030 Heel v.2 (copy) (copy) (copy) (copy)11,717.4 90.52 330.84 4,176.5 4,107.3 6,234.1 -7,521.3 5,979,072.80 414,698.39 3.14 9,691.011,812.7 90.44 329.14 4,175.7 4,106.5 6,316.6 -7,568.9 5,979,155.79 414,651.59 1.79 9,783.811,907.9 90.38327.644,175.1 4,105.9 6,397.7 -7,618.9 5,979,237.41 414,602.53 1.58 9,877.112,003.4 90.38 325.98 4,174.4 4,105.2 6,477.6 -7,671.1 5,979,317.81 414,551.12 1.74 9,971.112,098.8 90.62 325.26 4,173.6 4,104.4 6,556.4 -7,725.0 5,979,397.13 414,498.05 0.80 10,065.512,192.7 90.41 325.07 4,172.8 4,103.6 6,633.4 -7,778.7 5,979,474.75 414,445.21 0.30 10,158.412,288.0 90.59 325.56 4,171.9 4,102.7 6,711.8 -7,832.9 5,979,553.67 414,391.81 0.55 10,252.712,382.8 90.53 326.32 4,171.0 4,101.8 6,790.3 -7,885.9 5,979,632.69 414,339.57 0.80 10,346.212,477.7 90.59 330.17 4,170.1 4,100.9 6,871.0 -7,935.9 5,979,713.94 414,290.44 4.05 10,439.312,573.0 90.47330.244,169.2 4,100.0 6,953.7 -7,983.3 5,979,797.12 414,243.95 0.15 10,532.112,668.2 90.56 330.47 4,168.3 4,099.1 7,036.4 -8,030.3 5,979,880.30 414,197.75 0.26 10,624.612,762.5 90.84 332.12 4,167.2 4,098.0 7,119.2 -8,075.6 5,979,963.49 414,153.31 1.77 10,716.012,858.0 90.53 332.77 4,166.0 4,096.8 7,203.8 -8,119.8 5,980,048.53 414,110.05 0.75 10,807.912,953.7 90.41 331.29 4,165.2 4,096.0 7,288.3 -8,164.7 5,980,133.54 414,066.04 1.55 10,900.313,048.1 90.10 330.55 4,164.8 4,095.6 7,370.8 -8,210.6 5,980,216.52 414,021.01 0.85 10,991.913,143.9 90.16 330.28 4,164.6 4,095.4 7,454.1 -8,257.8 5,980,300.26 413,974.61 0.29 11,085.013,239.0 90.26 328.51 4,164.3 4,095.1 7,536.0 -8,306.3 5,980,382.63 413,927.04 1.86 11,177.913,334.5 90.10 327.47 4,164.0 4,094.8 7,616.9 -8,356.9 5,980,464.09 413,877.28 1.10 11,271.6042024 34504PMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft13,428.8 90.19 327.32 4,163.7 4,094.5 7,696.4 -8,407.7 5,980,544.07 413,827.29 0.19 11,364.313,524.0 90.10 326.98 4,163.5 4,094.3 7,776.4 -8,459.4 5,980,624.59 413,776.47 0.37 11,458.113,618.7 90.16327.744,163.3 4,094.1 7,856.1 -8,510.4 5,980,704.84 413,726.24 0.81 11,551.213,714.1 90.19 328.56 4,163.0 4,093.8 7,937.1 -8,560.8 5,980,786.39 413,676.74 0.86 11,644.713,808.9 90.41 329.42 4,162.5 4,093.3 8,018.4 -8,609.6 5,980,868.15 413,628.74 0.94 11,737.413,903.2 90.22 328.87 4,162.0 4,092.8 8,099.3 -8,658.0 5,980,949.58 413,581.24 0.62 11,829.613,998.3 90.16 329.91 4,161.64,092.48,181.1 -8,706.4 5,981,031.87 413,533.69 1.10 11,922.414,093.2 90.19 330.05 4,161.4 4,092.2 8,263.4 -8,753.9 5,981,114.58 413,487.04 0.15 12,014.914,188.1 90.19 329.31 4,161.0 4,091.8 8,345.3 -8,801.8 5,981,196.99 413,439.99 0.78 12,107.414,283.6 90.16328.444,160.7 4,091.5 8,427.0 -8,851.1 5,981,279.21 413,391.50 0.91 12,200.814,379.4 90.16 328.85 4,160.5 4,091.3 8,508.9 -8,901.0 5,981,361.56 413,342.49 0.43 12,294.714,474.8 90.22 329.04 4,160.2 4,091.0 8,590.5 -8,950.2 5,981,443.72 413,294.16 0.21 12,387.914,569.8 90.19 328.53 4,159.8 4,090.6 8,671.8 -8,999.4 5,981,525.48 413,245.78 0.54 12,480.914,664.2 90.16 328.69 4,159.5 4,090.3 8,752.4 -9,048.6 5,981,606.59 413,197.43 0.17 12,573.314,759.6 90.07 329.45 4,159.3 4,090.1 8,834.2 -9,097.6 5,981,688.89 413,149.27 0.80 12,666.614,855.4 90.07 329.99 4,159.2 4,090.0 8,917.0 -9,146.0 5,981,772.16 413,101.80 0.56 12,760.014,949.7 90.10 330.25 4,159.1 4,089.9 8,998.7 -9,192.9 5,981,854.35 413,055.71 0.28 12,851.815,045.1 90.01 329.87 4,159.0 4,089.8 9,081.4 -9,240.5 5,981,937.49 413,008.97 0.41 12,944.715,139.3 90.01 330.17 4,159.0 4,089.8 9,163.0 -9,287.6 5,982,019.57 412,962.74 0.32 13,036.415,234.9 90.47 330.13 4,158.64,089.49,245.9 -9,335.2 5,982,103.02 412,916.00 0.48 13,129.515,330.3 90.47 329.91 4,157.8 4,088.6 9,328.5 -9,382.8 5,982,186.08 412,869.23 0.23 13,222.415,424.9 90.44 330.16 4,157.0 4,087.8 9,410.5 -9,430.1 5,982,268.53 412,822.82 0.27 13,314.515,519.0 90.47 330.07 4,156.3 4,087.1 9,492.1 -9,477.0 5,982,350.59 412,776.79 0.10 13,406.115,612.4 90.47 330.36 4,155.5 4,086.3 9,573.1 -9,523.4 5,982,432.11 412,731.25 0.31 13,497.015,710.5 90.41 330.39 4,154.8 4,085.6 9,658.4 -9,571.9 5,982,517.92 412,683.63 0.07 13,592.415,805.4 90.41 329.68 4,154.1 4,084.9 9,740.6 -9,619.3 5,982,600.56 412,637.12 0.75 13,684.815,900.4 90.53 329.63 4,153.3 4,084.1 9,822.6 -9,667.3 5,982,683.05 412,589.97 0.14 13,777.5042024 34504PMCOMPASS 500017 Build 02 Page 10 ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft15,995.4 90.44 329.41 4,152.5 4,083.3 9,904.5 -9,715.5 5,982,765.43 412,542.63 0.25 13,870.216,090.6 90.47 328.13 4,151.8 4,082.6 9,985.9 -9,764.8 5,982,847.34 412,494.12 1.34 13,963.416,186.2 90.35 328.20 4,151.1 4,081.9 10,067.1 -9,815.2 5,982,929.03 412,444.57 0.15 14,057.116,280.7 90.44328.144,150.4 4,081.2 10,147.4 -9,865.1 5,983,009.84 412,395.56 0.11 14,149.816,376.1 90.41 327.81 4,149.7 4,080.5 10,228.3 -9,915.7 5,983,091.22 412,345.82 0.35 14,243.416,471.1 90.47 329.76 4,149.0 4,079.8 10,309.4 -9,964.9 5,983,172.91 412,297.47 2.05 14,336.316,566.7 90.41 329.73 4,148.3 4,079.1 10,392.0 -10,013.1 5,983,256.01 412,250.15 0.07 14,429.516,661.6 90.41 329.39 4,147.6 4,078.4 10,473.9 -10,061.1 5,983,338.34 412,202.91 0.36 14,522.216,756.1 90.44 329.82 4,146.9 4,077.7 10,555.4 -10,108.9 5,983,420.29 412,155.98 0.46 14,614.316,850.5 90.44 330.32 4,146.1 4,076.9 10,637.2 -10,156.1 5,983,502.62 412,109.71 0.53 14,706.316,945.9 90.38 329.80 4,145.5 4,076.3 10,719.8 -10,203.6 5,983,585.71 412,063.00 0.55 14,799.117,041.0 90.47 329.68 4,144.8 4,075.6 10,802.0 -10,251.6 5,983,668.37 412,015.92 0.16 14,891.817,135.8 90.38 329.42 4,144.1 4,074.9 10,883.7 -10,299.6 5,983,750.59 411,968.72 0.29 14,984.417,230.2 90.38 329.39 4,143.4 4,074.2 10,965.0 -10,347.7 5,983,832.32 411,921.54 0.03 15,076.517,325.4 90.47 330.16 4,142.7 4,073.5 11,047.2 -10,395.6 5,983,915.05 411,874.48 0.81 15,169.317,420.9 90.44 328.84 4,142.0 4,072.8 11,129.5 -10,444.1 5,983,997.87 411,826.85 1.38 15,262.517,503.9 90.44 328.27 4,141.3 4,072.1 11,200.3 -10,487.4 5,984,069.11 411,784.29 0.69 15,343.817,521.6 90.44 328.27 4,141.2 4,072.0 11,215.4 -10,496.6 5,984,084.21 411,775.17 0.00 15,361.1NDB-030 TD v.3 (copy) (copy) (copy) (copy)17,522.0 90.44 328.27 4,141.2 4,072.0 11,215.7 -10,496.9 5,984,084.57 411,774.96 0.00 15,361.54-1/2" Production Liner17,529.0 90.44 328.27 4,141.1 4,071.9 11,221.7 -10,500.5 5,984,090.56 411,771.34 0.00 15,368.4Proj TD042024 34504PMCOMPASS 500017 Build 02 Page 11 ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-030NDBi-030Survey Calculation MethodMinimum CurvatureParker 272 RKB @ 69.2usftDesignNDBi-030DatabaseEDM STO AlaskaMD ReferenceParker 272 RKB @ 69.2usftNorth ReferenceWell NDBi030TrueVertical DepthusftMeasured DepthusftCasingDiameter(")HoleDiameter(")NameCasing Points20" Conductor Driven128.0128.0 20 2013-3/8" Surface Casing2,261.92,550.0 13-3/8 169-5/8" Intermediate Liner4,105.211,201.0 9-5/8 12-1/44-1/2" Production Liner4,141.217,522.0 4-1/2 8-1/2MeasuredDepthusftVerticalDepthusftDipDirectionName LithologyDipFormations2,898.0 2,437.0 Tuluvak Shale9,653.0 3,775.2 Nanushuk10,895.0 4,025.4 NT4 MFS1,415.0 1,389.3 Permafrost Base4,660.0 2,821.6 TS 7909,960.0 3,833.2 NT8 MFS 0.0010,693.0 3,977.8 NT5 MFS3,062.0 2,498.0 Tuluvak Sand6,148.0 3,103.3 Seabee1,835.0 1,758.4 Middle Schrader Bluff11,280.0 4,126.8 NT3.2 Top Reservoir1,048.0 1,038.9 Upper Schrader Bluff11,168.0 4,096.2 NT3 MFS10,240.0 3,886.0 NT7 MFS11,593.0 4,174.5 NT3.24 0.0010,510.0 3,938.8 NT6 MFS2,334.0 2,131.1 MCU (Lower Schrader Bluff)042024 34504PMCOMPASS 500017 Build 02 Page 12 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 1 PDF file NDBi-030 (50-103-20873-0000) 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: 223-120 T39832 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.06 08:17:06 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Injection test Oil Search Alaska LLC (Santos) 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 feet feet true vertical feet feet Effective Depth measured feet feet true vertical feet feet Perforation depth Measured depth feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth)4.5" 6 ppf Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Jared Brake Contact Email:jared.brake@contractor.santos.com Authorized Title: Well Intengrity & Intervention Engineer Contact Phone: 832-330-4359 2550' 2264' Burst Collapse 2260 4750 9210 5020 6870 11590 measured TVD Production Liner 8834' 11050' 6508' Casing Structural 4108' 4067' 4-1/2" 11201' 2367' 17522' 4141' Plugs Junk measured Length 80' 2550' 80'Conductor Surface Intermediate 20" 13-3/8" SLB ppost job treatment report 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL 392984/ADL 391445 Pikka Nanushuk Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-120 50-103-20873-00-00 Size 80' 832 180 psi 253 psi 9-5/8" 11590 4-1/2" 601 W. 5th Avenue, Anchorage AK 995013. Address: Pikka NDBi-030 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf MD 848 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 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. p k ft t Fra O s 223 6. A G L PG , t Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:43 pm, Jul 31, 2024 SLB-Private FracCAT Treatment Report Well : NDBi-30 Pulse Test Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Larry Skanderbeg Date Prepared : 07-21-2024 Prepared by Name : Alena Lutskaia Company : Schlumberger Phone : 1 630 780 0058 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 d ata and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client: Santos Well: NDBi-30 Formation: Nanushuk District: Pikka Country: United States Summary On July 15-21, 2024 SLB performed a Pulse test, continues pumping. The objective was To perform a Pulse Test consisting of pumping a KCL solution into an injection well, while monitoring pressure responses on adjacent wells in the pad. Pump trips were staggered from 3,700 psi. During pumping maximum allowed BHP was increased to 2475 psi from the original 2450 psi. The equipment set consisted of C-pump unit, 3 main pumps which were swapped periodically at the same time as frac tanks swapped occurred, SuperPOD as a backup equipment. The pumping started on July 15th and was finished on July 21st with the average rate 5.5 BPM. Average Treating Pressure: 646 psi Maximum Treating Pressure: 897 psi Minimum Treating Pressure: 211 psi Average Injection Rate: 5.5 bbl/min Maximum Injection Rate: 10.0 bbl/min 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 3.5 bpm 105.0 3.5 29.7 Brine 4410 0.0 0.0 0 2 4.5 bpm 135.0 4.5 30.1 Brine 5669 0.0 0.0 0 3 5.5 bpm 40120.6 5.5 7262.3 Brine 1685055 0.0 0.0 0 140.0 1140.0 2140.0 3140.0 4140.0 5140.0 6140.0 7140.0 8140.0 0 500 1000 1500 2000 2500 3000 0 20.0 40.0 60.0 80.0 100.0 Treating Pressure(psi) Annulus Pressure(psi) BHP(psi) Slurry Rate(bbl/min) BHT(degF) Treatment Time(min) PRC Plot Pulse Test NDBi-030 Client: Santos Well: NDBi-30 Formation: Nanushuk District: Pikka 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 3.5 bpm 3.5 4.1 265 384 222 2 4.5 bpm 4.5 4.7 228 320 211 3 5.5 bpm 5.5 10.0 646 897 248 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) 40360.6 7322.1 1695135 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 15:46:04 Starting PT 1140 848 0.0 0.0 0.0 2 16:00:32 Leak on Mainline 2827 848 0.0 0.0 0.0 3 16:40:27 Replaced O ring 21 848 0.0 0.0 0.0 4 17:20:13 Replaced O ring -0 848 0.0 0.0 0.0 5 17:22:21 Starting PT 10 849 0.0 0.0 0.0 6 17:37:23 Good PT 94 848 0.0 0.0 0.0 7 20:36:05 equalizing to open WH 884 829 0.0 0.0 0.0 8 20:37:05 Open WH 282 831 0.0 0.0 0.0 9 20:41:14 Start 3.5 bpm Automatically 371 834 0.0 3.7 0.0 10 20:41:14 Start Pulse Test Automatically 371 834 0.0 3.7 0.0 11 20:41:14 Start Pumping Automatically 371 834 0.0 3.7 0.0 12 20:41:24 Started Pumping 387 834 0.0 4.1 0.0 13 21:11:07 Start 4.5 bpm Automatically 223 860 105.1 3.5 0.0 14 21:41:12 Start 5.5 bpm Automatically 213 861 240.0 4.5 0.0 15 23:46:32 Tank Swap; tank 8 strap 11'4"318 859 927.7 5.5 0.0 16 23:48:39 Swapping pumps 278 860 939.1 5.3 0.0 17 2:35:59 Tank Swap, Tank 7 strap is 11'4"358 864 1864.1 5.5 0.0 18 2:41:35 Swapping pumps 356 863 1895.0 5.5 0.0 19 5:23:24 Tank swap; tank 6 strap is 11'3"360 867 2791.7 5.7 0.0 20 5:23:38 Swapped to Tank 8 354 867 2793.0 5.4 0.0 21 5:23:51 Swapping pumps 374 866 2794.1 5.2 0.0 22 6:34:30 Activated Extend Stage 401 859 3184.0 5.5 0.0 23 7:18:39 2000 BHP 412 857 3428.1 5.5 0.0 24 8:02:15 Swapped to Tank 7 425 856 3669.2 5.7 0.0 25 8:02:38 Tank 8 Strap 11'3"406 856 3671.3 5.6 0.0 26 8:02:56 Swapping pumps 404 856 3673.0 5.6 0.0 27 10:45:26 Swapped to Tank 6 437 850 4573.7 5.5 0.0 28 10:47:04 Tank 7 Strap 11'3"439 851 4582.8 5.5 0.0 29 10:52:57 Swapping Pumps 401 854 4615.4 5.5 0.0 30 13:30:21 Swapped to Tank 8 440 847 5484.5 5.5 0.0 31 13:31:46 Tank 6 Strap 11'3"459 848 5492.1 4.4 0.0 32 13:32:26 Swapped pumps 437 847 5495.7 5.5 0.0 33 16:18:49 Swapped to Tank 7 448 848 6415.0 5.5 0.0 34 16:19:05 Tank 8 strap 11'3"447 848 6416.5 5.5 0.0 Client: Santos Well: NDBi-30 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 35 16:19:17 Swapped pumps 448 848 6417.6 5.5 0.0 36 19:07:55 Tank swap to Tank 6; Tank 7 strap is 11'2"465 848 7349.0 5.5 0.0 37 19:11:49 Swapped pumps 444 852 7370.5 5.5 0.0 38 21:53:18 Tank swap to Tank 8; Tank 6 strap 11' 3"495 856 8262.8 5.5 0.0 39 21:53:26 Swapped pumps 492 856 8263.5 5.5 0.0 40 0:39:29 Tank swap to tank 7; Tank 8 strap 11' 4"499 862 9180.7 5.5 0.0 41 0:39:35 Swapped pumps 498 862 9181.2 5.5 0.0 42 3:21:52 Tank swap to tank 6; Tank 7 strap 11' 4"519 861 10078.0 5.5 0.0 43 3:21:58 Swapped pumps 519 861 10078.6 5.5 0.0 44 6:02:07 Tank swap to tank 8; Tank 6 strap 11' 4"542 856 10963.9 5.5 0.0 45 6:03:05 Swapped pumps 538 856 10969.0 5.5 0.0 46 8:47:21 Tank swap to tank 7; Tank 8 strap 11'4"547 852 11877.0 5.5 0.0 47 8:47:31 Swapping pumps 546 852 11877.9 5.5 0.0 48 11:30:06 Swapped to tank 6; Tank 7 strap 11'4"551 851 12776.7 5.5 0.0 49 11:31:14 Swapped pumps 553 852 12782.9 5.5 0.0 50 14:21:32 Swapped to tank 8; Tank 6 strap 11'4"552 851 13711.9 5.5 0.0 51 14:21:40 Swapped pumps 550 851 13712.6 5.5 0.0 52 17:08:31 Swapped to tank 7; Tank 8 strap 11'4"558 851 14634.6 5.5 0.0 53 17:08:54 Swapped Pumps 559 851 14636.7 5.5 0.0 54 19:56:50 Swapped to tank 6, Tank 7 strap 11' 3"573 858 15564.5 5.2 0.0 55 19:57:14 Swapped pumps 487 858 15566.6 4.9 0.0 56 22:43:49 Swapped to tank 8; tank 6 strap is 11' 3"587 867 16486.9 5.5 0.0 57 22:43:58 Swapped Pumps 585 867 16487.7 5.5 0.0 58 0:39:42 Started Pumping 17043.7 0.0 0.0 59 0:39:42 Activated Extend Stage 17043.7 0.0 0.0 60 0:39:42 Start stage Automatically 17043.7 0.0 0.0 61 0:52:48 Fraccat Crashed. Recovered job and rebroadcasted to interact 572 861 17049.6 5.5 0.0 62 1:29:31 Swapped to tank 7. Tank 8 strap is 11' 3" Swapped pumps 566 861 17252.2 5.5 0.0 63 4:15:22 Swapped to tank 6. Tank 7 strap is 11' 3"568 859 18168.6 5.5 0.0 64 4:15:37 Swapped Pumps 571 859 18170.0 5.5 0.0 65 7:00:55 Swapped to Tank 8; Tank 6 strap 11'4"587 856 19082.8 5.5 0.0 66 7:01:01 Swapped pumps 587 856 19083.3 5.5 0.0 67 9:46:20 Swapped to Tank 7; Tank 8 strap 11'4"597 852 19997.2 5.5 0.0 68 9:48:00 Swapping Pumps 592 853 20006.2 5.5 0.0 69 12:33:07 Swapped to Tank 6; 11'4"593 852 20919.0 5.5 0.0 70 12:34:30 Swapped pumps 590 854 20926.5 5.5 0.0 71 15:24:00 Swapped to Tank 8; Tank 6 strap 11'3''584 850 21861.3 5.5 0.0 72 15:24:12 Swapped pumps 584 851 21862.4 5.5 0.0 73 18:10:36 Swapped to Tank 7; Tank 8 strap 11'2"583 856 22767.1 5.5 0.0 74 18:10:51 Swapped pumps 585 856 22768.4 5.5 0.0 75 20:55:03 Swapped to Tank 6; Tank 7 strap 11'4"372 858 23675.7 0.7 0.0 76 20:55:09 Swapped pumps 505 858 23675.7 0.0 0.0 77 23:41:12 swapped to tank 8; Tank 6 strap 11'3"620 858 24578.3 5.5 0.0 78 23:41:35 swapped pumps 618 859 24580.4 5.5 0.0 79 2:24:15 Swapped to tank 7; Tank 8 strap 11'3'632 860 25464.1 5.5 0.0 80 2:24:30 Swapped pumps 633 860 25465.5 5.5 0.0 81 5:10:04 Swapped to Tank 6; Tank 7 strap 11'4"639 858 26380.0 5.5 0.0 82 5:10:14 Swapped pumps 639 858 26380.9 5.5 0.0 83 7:57:47 Swapped pumps 647 856 27306.4 5.6 0.0 Client: Santos Well: NDBi-30 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 84 7:58:49 Swapped to Tank 1; Tank 6 strap 11'2"647 856 27312.1 5.6 0.0 85 10:34:05 Swapped to Tank 2; Tank 1 strap 11' 3"649 844 28169.7 5.5 0.0 86 10:34:17 Swapped pumps 650 844 28170.8 5.5 0.0 87 13:23:19 Swapped to Tank 3; Tank 2 strap 11' 1"650 838 29104.2 5.5 0.0 88 13:23:29 Swapped pumps 651 839 29105.1 5.5 0.0 89 16:10:36 Swapped to Tank 6; Tank 3 strap 11' 2"643 838 30028.3 5.5 0.0 90 16:10:47 Swapped pumps 641 839 30029.3 5.5 0.0 91 18:54:13 Swapped to Tank 8; Tank 6 strap 11'2"669 854 30932.8 5.5 0.0 92 18:54:23 Swapped pumps 668 854 30933.7 5.5 0.0 93 21:39:17 Swapped to Tank 7; Tank 8 strap 11'3"681 851 31844.7 5.5 0.0 94 21:39:33 Swapped pumps 680 851 31846.2 5.5 0.0 95 0:21:06 Swapped to Tank 4; Tank 7 strap 11'3"688 852 32738.5 5.5 0.0 96 0:21:27 Swapped pumps 687 852 32740.4 5.5 0.0 97 2:54:18 Swapped to Tank 6; Tank 4 strap 11'3"701 836 33585.1 5.5 0.0 98 2:54:27 swapped pumps 699 836 33585.9 5.5 0.0 99 5:57:23 Swapped to Tank 8; Tank 6 strap 11'3"700 863 34597.0 5.5 0.0 100 5:57:36 Swapped pumps 702 862 34598.2 5.5 0.0 101 8:44:43 Swapped to Tank 7; Tank 8 strap 11'2"695 862 35521.1 5.5 0.0 102 8:45:08 Swapped Pumps 693 862 35523.4 5.5 0.0 103 11:29:21 Swapped to Tank 6; Tank 7 strap 11'2"703 859 36430.1 5.5 0.0 104 11:29:31 Swapped Pumps 700 859 36431.0 5.5 0.0 105 14:16:21 Swapped to Tank 8; Tank 6 strap 11'3"717 856 37352.2 5.5 0.0 106 14:16:30 Swapped Pumps 717 855 37353.0 5.5 0.0 107 17:01:12 Swapped to Tank 5; Tank 8 strap 11'2"721 858 38263.0 5.5 0.0 108 17:01:22 Swapped Pumps 717 858 38264.0 5.5 0.0 109 19:53:32 Swapped to Tank 7; Tank 5 strap 11'4"721 843 39215.3 5.5 0.0 110 19:53:43 Swapped pumps 715 843 39216.3 5.5 0.0 111 8:44:57 Completions Swapping To Monitor BH Pressure 256 833 40215.3 0.0 0.0 112 9:11:40 Well closed 253 832 40215.3 0.0 0.0 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: Injection test 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?Pikka NDBi-030 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): Casing Collapse Conductor Surface 2260 psi Intermediate 4750 psi Tie-Back 4750 psi Production 9210 psi Liner 9210 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Jared Brake Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7/14/2024 17,522'6,508' 4-1/2" 6 ppf 4,141' MD 6870 psi 5020 psi 6870 psi 2,264' 4,108' 2,155' 2,550' 11,201' 2,367' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984/ADL 391445 223-120 601 5th Avenue, Anchorage Ak 99501 50-103-20873-00-00 Oil Search Alaska LLC (Santos) Proposed Pools: AOGCC USE ONLY 11,590 psi Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): P-110S 11,050' Perforation Depth MD (ft): 4-1/2" Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 80'80' TVD Burst 20"80' Jared.brake@contractor.santos.com 832-330-4359 Well Integrity & Intervention Engineer 11,590 psi4,067'4-1/2" 13-3/8" 9-5/8" 2,550' Tie-back2,367' 8,834' 11,050'11,050' m n s 2 6 5 6 tc N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:54 pm, Jul 12, 2024 324-399 BJM 7/13/24 10-404 Jul 12, 2024 7/14/2024 SFD 7/12/2024 DSR-7/15/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.15 15:42:07 -08'00'07/15/24 RBDMS JSB 071624 Santos Ltd NDBi-030 Pulse Test Program - Ver 1.–8 July 2024 Page 1 NDBi-030 – Pulse Test Program NDBi-030 AOGCC PTD # 223-120 API# 50-103-20873-00-00 Approvals NAME SIGNATURE DATE Robert (Ty) Senden: Sr. Eng. Manager, Completions Jose (Jose) Gonzalez: Sr. Completions Engineer 8 July 2024 Santos Ltd NDBi-030 Pulse Test Program - Ver 1.–8 July 2024 Page 2 Operation Objectives Safely perform a pulse test by injecting fluid into well NDBi-030 and monitor any pressure responses on multiple wells in the pad to confirm downhole connectivity. Well Information Tubulars Reservoir Data Expected Reservoir Pressure:~1904 psi Reservoir Temperature: ~100° F Crude Oil API Gravity:28° to 30° @ 60 oF Gas Gravity ~0.77 H2S Content:0 ppm CO2 Content:0 - 0.2% Well Status The completion is 4-1/2” 12.6# TSH563 liner and tubing. x The well has been fractured and flowed back, tubing and jewellery have been MIT-T to 4,000 psi (passed) x MIT-IA to 4,000 psi (passed) as part of initial completion. x The fluid in the wellbore is a mix of oil, gas and water (formation and frac water) from the flowback operation. x Production tree installed and tested to 5,000 psi. Master valve, back up and wing valves closed. x The well is open to formation via 12 frac sleeves and toe sleeve. Current Well Barriers: Hole Section Top Depth (ft) Bottom Depth (ft) Hole Size (in) Csg/Tbg Size (in) Wt. (lb/ft) Grade Connection I.D (in) Drift (in) Burst (psi) Collapse (psi) Surface 0 MD 2,550 MD 16 13-3/8 68 L-80 BTC 12.415 12.259 5,020 2,260 Prod Liner 2,367 MD 11,201 MD 12-1/4 9-5/8 47 L-80 TSH563 8.681 8.525 6,870 4,750 Prod Tieback 0 MD 2,367 MD 9-5/8 47 L-80 TSH563 8.681 8.525 6,870 4,750 Comp Liner 11,014 MD 17,522 MD 8-1/2 4-1/2 12.6 P-110S TSH563 3.958 3.833 11,590 9,210 Upper Comp 0 MD 11,048 MD 8-1/2 4-1/2 12.6 P-110S TSH563 3.958 3.833 11,590 9,210 Current Well Barriers Operation #Barriers Tested Barrier Pulse Test 1 4-1/2” Tubing Tested during completion 2 Liner Hanger/Packer & Open to formation Tested during completion 3 Production tree with redundant valves Tested Santos Ltd NDBi-030 Pulse Test Program - Ver 1.–8 July 2024 Page 3 Wellbore Schematic Santos Ltd NDBi-030 Pulse Test Program - Ver 1.–8 July 2024 Page 4 Operations Overview The pulse test will include operations to be performed after the well has been flowed back on clean up (post- frac) and pressure build up period has been completed. The planned volume of fluid to be injected is a minimum of 40,000 BBL in total at a steady rate of 5.5 BPM (7500 - 8000 BPD). Final volume will depend on water available at the lake. The water used for the pulse test will be pumped directly from the lake adjacent to the NDB pad and mixed with trucked concentrated KCL. This operation will be performed continuously for the designed volume of fluid while simultaneously injecting into well NDBi-030. 1. Fluid Mixing: 1. Rig up lay-flat hose and C-pump to pump lake water to Hydrera tanks manifold with 250 micron filter. 2. Transfer concentrated 20% KCL solution from transport to Hydrera tanks. 3. Pump filtered water from lake using lay-flat hose into tank to be mixed with concentrated KCL and end up with a final concentration of 2% KCL. Add 0.3 lbs/1000 gal M275 biocide to the mix. 4. Continue mixing lake water with KCL and biocide until all fluid to be injected has been mixed. 5.NOTE: Before start pumping downhole, all Hydrera tanks should be pre-filled with 2% KCL solution trucked from MI. 6.NOTE:Arrange to have back up C-pump ready to go. 2. Pulse Test Injection: 1. Rig up suction lines from Hydrera tanks manifold to C-pump skid, including back up (POD Blender). 2. Rig up 10K psi pumping units and 2” fig 1502 treating iron (including pop off valve, bleed off containment) to wing valve of production tree . Use 4 1/16” 5K xWeco 2” fig 1502 X-over flange. Note: Rig up pumping equipment (including back up) to be able to continuously inject fluid at designed rate for the duration of the test. 3. Pressure test pumps and lines to well wing valve using water as per Santos requirements to 5000 psi. 4. Continuously monitor IA during the operation 5. Equalize pressure, open wing and treating iron master valves and start pumping fluid down tubing. Start at ~ 2 BPM for 10 minutes to confirm injectivity. Once injectivity is confirmed, ramp up to 5.5 BPM. 6. Continue pumping downhole maintaining a 5.5 BPM steady rate until all designed volume has been injected. Note: Depending on pressure behaviour, injection rate may be increased up to 6.25 BPM for last portion of the test. Instructions will be provided in advance. 7. The last 30 BBL of the test will be Diesel to be used as freeze protect. 8.Note: Maximum allowed treating pressure is 4,000 psi on the tubing.Maximum BHP allowed is 2700 psi. (DO NOT EXCEED). 9. Stop pumping, close and secure wellhead. Bleed off pressures. Vacate suction and treating lines, rig down and demob pumping and auxiliary equipment. Santos Ltd NDBi-030 Pulse Test Program - Ver 1.–8 July 2024 Page 5 10.NOTE: In case of operational issues (filter plugging, pump issues, etc.), or if full rate cannot be achieved without achieving BHP limitation, drop pump rate to about half and inform completion team in town. Avoid stopping pumping operations, if possible. 3. Data Collection Notes: 1. Before injection starts, confirm all pumping parameters (pumping pressure, rate, volume) are being recorded. Record parameters during the duration of the injection. 2. Confirm BH gauge on NDBi-030 and BH gauges in all monitoring wells (below) are collecting data by recording initial pressures at least 24 hrs prior to the start of the pulse test: a. NDB-024 b. NDBi-044 c. NDBi-043 d. NDBi-014 e. NDB-032 3. BH gauge data (1 second frequency)for all wells to be downloaded daily and emailed to Pedro San Blas, Dan Bonnar, Randy Kono and Jose Gonzalez. 4. FLUID SAMPLING: Take 1 fluid sample every 12 hours to confirm how cleanliness. Identify time and from what tank the samples were taken and store them for later analysis as much as possible. Santos Ltd NDBi-030 Pulse Test Program - Ver 1.–8 July 2024 Page 6 Attachments A.FMC Production Tree 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. You don't often get email from jared.brake@contractor.santos.com. Learn why this is important From:Brooks, Phoebe L (OGC) To:Brake, Jared (Jared) Cc:Regg, James B (OGC) Subject:RE: Santos Pikka NDBi-030 MIT_IA 4.1.2024 Date:Tuesday, May 14, 2024 4:49:55 PM Attachments:MIT Pikka NDBi-030 04-01-24.xlsx Jared, I made some minor revisions, removing the Waived by verbiage from the AOGCC Rep field (remarks is fine) and correcting the PTD # to reflect 2231200. Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation 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: Wednesday, April 10, 2024 2:50 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Subject: Santos Pikka NDBi-030 MIT_IA 4.1.2024 Folks, Attached is the initial MIT-IA for well NDBi-030 Pre-frac. Jared Brake Well Integrity & Well Intervention Engineer t: 1 (907) 375-4673 | m: 1 (832) 330-4359| e: brajg@santos.com 3LNND1'% 37' correcting the PTD # Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2231200 Type Inj W Tubing 0 3680 3676 3670 Type Test P Packer TVD 4056 BBL Pump 9.1 IA 0 4400 4436 4414 Interval I Test psi 1500 BBL Return 6.5 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 MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Oil Search (Santos) Pikka / NDB Nick Frasier 04/01/24 Notes:Initial MIT-IA Pre-frac and injection. State witness waived by Josh Hunt at 6:55 am on 4/1/2024 Notes: Notes: Notes: NDBi-030 Form 10-426 (Revised 01/2017)2024-0401_MIT_Pikka_NDB-030 9 9 9 9 9 999 9 -5HJJ 5(9,6(' 2231200 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Well Cleanup 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?NDBi-030 Yes No 9. Property Designation (Lease Number): 10. Field: Pikka Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 17,529' 4,141' Casing Collapse Conductor Surface 2260 Intermediate 4750 Tie-Back 4750 Production 9210 Liner 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Scott Leahy Contact Email:scott.leahy@santos.com Contact Phone: 907-646-7063 Authorized Title: Completions Specialist Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 11590 Tubing Grade: Tubing MD (ft): N/A Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393020, 393019, 393018 223-120 900 E Benson Boulevard, Suite 500, Anchorage, AK 99508 50-103-20873-00-00 Oil Search Alaska, LLC Length Size Proposed Pools: 80' 80' P-110S TVD Burst 11,050' 11590 MD 6870 5020 6870 2,264' 4,108' 2,155' 2,550' 11,201' 4,067'4-1/2" 80' 20"x34" 13-3/8" 9-5/8" 2,550' Tieback2,367 8,834' 11050 Perforation Depth MD (ft): 2367 11050 4-1/2" 05/14/24 17,522'6,508' 4-1/2" 12.6ppf 4,141' See attached packer report m n P 2 6 5 6 t 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 letions Specialist 04/12/2024 By Grace Christianson at 11:50 am, Apr 12, 2024 DSR-4/12/24 05/14/24 10-404 CDW 04/25/2024 1497 psi, from PTD -bjm SFD 4/25/2024BJM 4/26/24*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.26 11:33:12 -08'00'04/26/24 RBDMS JSB 042924 Page 1 of 1 Well Name: NDBi-030 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,036.6 4,061.4 OH Packer #13 11,314.4 4,135.3 OH Packer #12 11,382.0 4,149.6 OH Packer #11 11,842.8 4,175.5 OH Packer #10 12,388.3 4,171.0 OH Packer #9 12,844.2 4,166.2 OH Packer #8 13,460.0 4,163.6 OH Packer #7 14,045.4 4,161.5 OH Packer #6 14,664.8 4,159.6 OH Packer #5 15,249.2 4,158.5 OH Packer #4 15,751.3 4,154.5 OH Packer #3 16,376.6 4,149.7 OH Packer #2 16,955.3 4,145.4 OH Packer #1 17,332.9 4,142.7 Page 1 of 20 NDBi-030 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachment B 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBDi-030. At the NDBi-030 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifer (typically found down to 400 ft depth) are located at the NDBi-030 location. 4. Plan for freshwater sampling – There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information – Attachment C 6. Assessment of casing and cementing operations – Attachment C 7. Casing and tubing pressure test information – Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachments D and I 9. Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 976 feet (ft) total vertical depth subsea (TVDSS)/ 976 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 976 to 2,383 ft TVDSS/1,407 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: 2,383 to 3,063 ft TVDSS/680 ft thick Hydrocarbon Zone: 2,427 to 3,063 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: 3,063 to 3,723 ft TVDSS/660 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: 3,723 to 4,690 ft TVDSS/ 967 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. 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) MAWP (psi) Stages 1-11 3,500 3,700 8,300 7,400 9,000 8,900 Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft 11.Mechanical condition of wells transecting the confining zones –Qugruk 301. NDBi- 43, NDB-32, and NDB-24, are within 1/2-mile radius of NDBi-030. Note that the 1 st frac sleeve within NDBi-43 is >500 ft away from the lateral of NDBi-30 Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones. Please see Attachment B Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 17,220 4,144 240.1 384.8 40 6,636 8 2 16,638 4,148 238 390.8 40 6,432 8 3 16,059 4,152 225.8 350.7 40 6,433 10 4 15,474 4,157 235.9 334.5 40 6,167 10 5 14,889 4,159 235.9 339.6 40 5,939 10 6 14,308 4,161 236 337 40 5,740 10 7 13,727 4,163 235.6 327.6 40 5,523 10 8 13,228 4,164 235.1 325.2 40 5,331 10 9 12,652 4,169 235.3 321.2 40 5,109 10 10 12,111 4,174 235.6 328.5 40 4,901 10 11 11,648 4,176 234.7 325.6 40 4,730 10 6,636 Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. 13.Detailed proposed fracturing program –Attachments F & K 14.Well Clean Up procedure –Attachment G Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test –Attachment H Section (d) Pressure Relieve Valve –Attachment I Proposed Wellbore Schematic –Attachment J Attachment A 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:Brake, Jared (Jared) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Cc:Davis, Rachel (Rachel) Subject:Santos Pikka NDBi-030 MIT_IA 4.1.2024 Date:Wednesday, April 10, 2024 2:50:39 PM Attachments:NDBi-030 MIT-IA 4.1.2024.xlsx You don't often get email from jared.brake@contractor.santos.com. Learn why this is important Folks, Attached is the initial MIT-IA for well NDBi-030 Pre-frac. Jared Brake Well Integrity & Well Intervention Engineer t: 1 (907) 375-4673 | m: 1 (832) 330-4359| e: brajg@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Pikka NDB-30 PTD 2231200 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 223-120 Type Inj W Tubing 0 3680 3676 3670 Type Test P Packer TVD 4056 BBL Pump 9.1 IA 0 4400 4436 4414 Interval I Test psi 1500 BBL Return 6.5 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: Oil Search (Santos) Pikka / NDB Waived by Josh Hunt Nick Frasier 04/01/24 Notes:Initial MIT-IA Pre-frac and injection. State witness waived by Josh Hunt at 6:55 am on 4/1/2024 Notes: Notes: Notes: NDBi-030 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: Form 10-426 (Revised 01/2017)2024-0401_MIT_Pikka_NDB-030 J. Regg; 5/13/2024 Oil Search (Alaska), LLC a subsidiary of Santos Limited 900 E. Benson Blvd Anchorage, Alaska 99508 PO Box 240927 Anchorage, Alaska 99524 (T) +1 907 375 4642 — santos.com 1/2 April 10, 2024 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLC’s Sundry Application for a Fracture Stimulation for the Proposed NDBi-030 Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDBi-030 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC PO Box 240927 Anchorage, AK 99524 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDBi-030 well trajectory and fracture stimulation. Please contact me should you require additional information. Sincerely, Tim Jones Land Manager Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: Erik Kenning 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL PO Box 240927 Anchorage, AK 99524 Repsol E&P USA LLC CERTIFIED MAIL Attn: Jeremy McKee 2455 Technology Forest Blvd. The Woodlands, TX 77381 AD L 3 9 2 9 9 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 1 . 5 8 % D N R - 5 8 . 4 2 % AD L 3 9 2 9 6 3 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 8 4 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 6 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 5 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 6 . 3 1 % D N R - 6 3 . 6 9 % AD L 3 9 2 9 7 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 0 . 2 9 % D N R - 5 9 . 7 1 % AD L 3 9 3 0 2 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 1 9 . 2 2 % D N R - 8 0 . 7 8 % AD L 3 9 3 0 1 9 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 % D N R - 6 6 . 9 % AD L 3 9 3 0 1 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 9 . 6 7 % D N R - 7 0 . 3 3 % AD L 3 9 3 0 2 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 6 . 5 9 % D N R - 7 3 . 4 1 % AD L 3 9 3 0 1 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 1 . 6 9 % D N R - 6 8 . 3 1 % AD L 3 9 3 0 1 7 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 3 0 1 6 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 7 % D N R - 6 6 . 8 3 % AD L 3 9 3 0 0 7 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 4 . 3 5 % D N R - 6 5 . 6 5 % AD L 3 9 3 0 0 8 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 8 . 2 9 % D N R - 7 1 . 7 1 % AD L 3 9 1 3 2 2 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 8 . 2 5 % D N R - 7 1 . 7 5 % AD L 3 9 1 4 4 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 1 . 9 8 % D N R - 5 8 . 0 2 % AD L 3 9 1 4 5 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 6 . 4 % D N R - 5 3 . 6 % AD L 3 9 3 0 1 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 2 5 . 7 1 % D N R - 7 4 . 2 9 % AD L 3 9 3 0 1 0 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 8 . 5 4 % D N R - 6 1 . 4 6 % OI L S E A R C H ( A L A S K A ) , L L C A S U B S I D I A R Y O F S A N T O S L T D ND B i 0 3 0 W E L L A R E A TA R G E T BO T T O M H O L E SU R F A C E L O C A T I O N WE L L T R A J E C T O R Y LE A S E S B O U N D A R Y KU U K P I K B O U N D A R Y .5 - M I L E B U F F E R TO W N S H I P SE C T I O N DA T E : 8 / 7 / 2 0 2 3 . R E V : 1 . 0 . B y : J B 0 4 0 0 8 0 0 US F e e t Pr o j e c t : A P - D R L - G E N _ a s s o r t e d La y o u t : A P - D R L - P E - M _ N D B 0 i 3 0 _ w e l l _ o w n e r s h i p GC S : N A D 1 9 8 3 S t a t e P l a n e A l a s k a 4 F I P S 5 0 0 4 F e e t 0 2 0 0 4 0 0 Me t e r s PI K K A P R O J E C T ND B Attachment B Fault 1: The fault as mapped on seismic tips out within the Nanushuk formation and therefore is covered by the Seabee as the upper confining layer. Fault 2: Low confidence. Minor fault within the Tuluvak Formation. The fault as mapped on seismic tips out above within the Middle Schrader Bluff and below in the Seabee Formation and therefore bounded by the Seabee as the lower confining layer. Fault 3: Low confidence. Minor fault within the Tuluvak Formation. The fault as mapped on seismic tips out above within the Middle Schrader Bluff and below in the Seabee Formation and therefore bounded by the Seabee as the lower confining layer. WE L L N A M E S T A T U S C a s i n g S i z e To p o f O i l P o o l Co n f i n i n g L a y e r (M D ) To p o f O i l P o o l Co n f i n i n g L a y e r (T V D S S ) To p o f Ce m e n t (M D ) To p o f C e m e n t (T V D S S ) To p o f C e m e n t De t e r m i n e d B y Re s e r v o i r S t a t u s Z o n a l I s o l a t i o n Ce m e n t O p e r a t i o n s S u m m a r y Me c h a n i c a l I n t e g r i t y Q- 3 0 1 A b a n d o n e d 9- 5 / 8 " 4 7 # L- 8 0 40 4 2 (N a n u s h u k ) 38 4 1 ( N a n u s h u k ) 3 8 1 0 ' 36 8 3 ' lo g Ab a n d o n e d w i t h Ca s e d h o l e c e m e n t pl u g s TO C 3 , 8 1 0 ' M D Q- 3 0 1 w a s a n e x p l o r a t i o n / a p p r a i s a l w e l l t h a t w a s d r il l e d i n 2 01 5 . I t wa s h y d r a u l i c f r a c t u r e d i n t h e N a n u s h u k r e s e r v o i r , f l o w e d b a c k , a n d pl u g g e d a n d a b a n d o n e d i n t h e s a m e w i n t e r s e a s o n . • T h e N a n u s h u k f o r m a t i o n t o p w a s i d e n t i f i e d a t 4 0 4 2 ’ M D , w i t h Na n u s h u k t a r g e t f o r m a t i o n a t 4 6 3 1 ’ M D . • 9 - 5 / 8 ” I n t e r m e d i a t e c a s i n g i s s e t a t 5 2 4 1 ’ M D i n t h e N a n u s h u k re s e r v o i r . T h e p r i m a r y c e m e n t j o b h a s t h e T O C a t 3 8 1 0 ’ M D ( 9 6 . 7 b b l s 13 . 9 p p g E x t e n d e d C l a s s G ) , w i t h a s e c o n d s t a g e c e m e n t j o b f r o m 30 0 8 ’ M D t o s u r f a c e ( 1 8 7 b b l s o f 1 2 . 2 p p g E x t e n d e d T y p e I / I I ) . • T h e 4 - 1 / 2 ” p r o d u c t i o n l i n e r i n t h e N a n u s h u k r e s e r v o i r i s s e t a t 7 4 9 5 ’ MD . T h e l i n e r w a s P & A w i t h a c e m e n t r e t a i n e r s e t a t 4 5 0 3 ’ M D a n d 4 8 bb l s s q u e e z e d b e l o w t h e r e t a i n e r ( 4 - 1 / 2 ” l i n e r v o l u m e ) . • 3 c e m e n t a b a n d o n m e n t p l u g s w e r e s e t i n t h e 9 - 5 / 8 ” c a s i n g : 1. 1 s t P l u g ( 3 0 0 ’ a b o v e c e m e n t r e t a i n e r ) : 1 8 b b l s o f 1 5 . 8 p p g c e m e n t la i d a b o v e t h e c e m e n t r e t a i n e r a t 4 5 0 3 ’ . 2. 2 n d P l u g ( 3 0 0 ’ a c r o s s 1 3 - 3 / 8 ” c a s i n g s h o e ) : A 9 - 5 / 8 ” b r i d g e p l u g w a s se t a t 2 2 0 7 ’ M D ( 1 0 0 ’ b e l o w t h e s u r f a c e c a s i n g s h o e ) w i t h 1 9 . 1 b b l s o f 15 . 6 p p g C l a s s G c e m e n t p l u g l a i d o n t o p o f i t . We l l i s f u l l y ab a n d o n e d . ND B i - 0 4 3 A C T I V E 9- 5 / 8 " 47 p p f 4, 9 5 5 (N a n u s h u k ) 3, 7 9 5 ( N a n u s h u k ) 2 , 7 9 2 2 , 7 3 0 l o g op e n h o l e l i n e r f o r in j e c t i o n TO C 2 , 7 9 2 M D ' & p a c k e r @ 6, 0 7 1 ' Le a d : 2 7 7 b b l s o f 1 2 p p g T a i l : 4 4 b b l s o f 1 5 . 3 p p g 8/ 2 1 / 2 3 , 9 - 5 / 8 " c a s i n g pr e s s u r e t e s t e d t o 4, 2 0 0 p s i f o r 3 0 mi n u t e s ND B - 0 3 2 A C T I V E 9- 5 / 8 " 47 p p f 49 5 2 (N a n u s h u k ) 3, 7 9 5 ( N a n u s h u k ) 2 4 1 7 2 , 1 6 5 l o g op e n h o l e l i n e r f o r pr o d u c t i o n TO C 2 , 4 1 7 ' & pa c k e r @ 6, 1 0 4 ' 9- 5 / 8 ” x 1 3 - 3 / 8 ” P r i m a r y c e m e n t j o b Pu m p 9 3 b b l s 1 1 . 8 p p g T u n e d S p a c e r @ 4 b p m a n d 3 5 0 p s i . R e l e a s e b o t t o m p u m p d o w n p l u g a n d p u m p 3 0 0 b b l s 1 2 p p g E x t e n d a C e m le a d @ 4 . 5 b p m . P u m p 4 5 b b l s 1 5 . 3 p p g V e r s a C e m t y p e I / I I t a i l @ 2 . 5 b p m . R e l e a s e t o p p u m p d o w n p l u g , c h a s e w i t h 2 b b l s o f c e m e nt th e n 1 0 b b l s o f w a t e r w a s h u p f r o m H a ll i b u r t o n . P e r f o r m d i s p l a c e m e n t w i t h r i g p u m p s . 2 6 4 b b l s d i s p l a c e d w i t h 1 1 . 5 p p g m u d a t 7 b p m . Sw a p t o 1 1 . 8 p p g T u n e d S p a c e r , 3 8 b b l s a t 7 b p m . B t m p u m p d o w n d a r t l a t c h u p c o n f i r m e d a t 5 4 b b l s d i s p l a c e d , 8 1 9 p s i . B t m l i n e r w i p e r pl u g l a t c h u p c o n f i r m e d @ 3 4 2 b b l s d i s p l a c e d , 5 7 0 p s i . T o p p u m p d o w n d a r t l a t c h u p c o n f i r m e d @ 3 9 b b l s d i s p l a c e d . R e d u c e r a t e t o 4 BP M p r i o r t o p l u g b u m p : F i n a l c i r c u l a t i n g p r e s s u r e 5 5 0 P S I - T o t a l d i s p l a c e m e n t v o l u m e 3 1 5 b b l s ( m e a s u r e d b y s t r o k e s @ 9 6 % p u m p ef f i c i e n c y ) 3 1 2 7 s t k ’ s ( C a l c u l a t e d 3 2 7 7 s t k ’ s ) . T o t a l l o s s e s f r o m c e m e n t e x i t s h o e t o c e m e n t i n p l a c e : 0 b b l s . C i r c u l a t e o u t c e me n t 1 1 B P M 88 0 P S I - o b s e r v e d 7 2 b b l s o f c e m e n t / O B M c o n t a m i n a t e d r e t u r n s , e s t i m a t e d 6 5 % c e m e n t 3 5 % O B M , a n d 2 1 1 b b l s o f O B M / T u n e d S p a c e r in t e r f a c e . 09 / 0 2 / 2 3 , 9 - 5 / 8 " ca s i n g p r e s s u r e t e s t e d to 3 9 1 0 p s i f o r 3 0 mi n u t e s ND B - 0 2 4 A C T I V E 9- 5 / 8 " 47 p p f 10 , 2 5 5 (N a n u s h u k ) 3, 7 6 8 ( N a n u s h u k ) 8, 7 2 5 ( T o p o f 1s t s t a g e ce m e n t ) 3, 4 2 9 l o g op e n h o l e l i n e r f o r pr o d u c t i o n TO C 8 , 7 2 5 & pa c k e r @ 11 , 2 9 4 ' St a g e 1 - L e a d : 1 0 0 b b l s o f 1 3 . 0 p p g E c o n o C e m T y p e I / I I . T a i l : 8 0 b b l s o f 1 5 . 3 p p g V e r s a C e m T y p e I / I I . St a g e 2 - L e a d : 2 4 0 b b l s o f 1 3 . 0 p p g E c o n o C e m T y p e I / I I . T a i l : 1 7 0 b b l s o f 1 5 . 3 p p g V e r s a C e m T y p e I / I I . 11 / 1 2 / 2 3 , 9 - 5 / 8 " ca s i n g p r e s s u r e t e s t e d to 3 , 8 0 0 p s i f o r 3 0 mi n u t e s Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensil e (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design x 13-3/8” Casing Shoe: 2,550’ MD x 9-5/8” x 13-3/8” Liner top: 2,367’ MD x 9-5/8” Liner Shoe: 11.201’ MD x 9-5/8” Archer Cflex Mechanical Stage tool: 4,712 MD Geology x Top of Tuluvak TS 790 formation at 4,660’ MD. Significant hydrocarbons are contained only within the upper Tuluvak in the TS 880 (3,029’ MD). x Top of the Nanushuk picked at 9,653’ MD. o Top of the NT8 MFS picked at 9,960’ MD o Top of the hydrocarbons encountered within the NT7 MFS at 10,240’ MD evidenced by increase resistivity values (>6 ohm). Cement Job Planning/Execution 1. 9-5/8” x 13-3/8” Primary cement job a. 1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 250’ TVD above top of Nanushuk to 8,450’ MD. b. During execution of the 1 st stage of cement, encountered liner wiper plug system failure that left all cement inside liner. Cement was drilled out, a composite cement retainer was set in the shoe track, and the primary cement job was re-pumped. Circulation was difficult due to the 80 bbls of water-based spacer left against the formation from the initial cement job. During the re-pump of the primary cement job, losses were encountered and 110 bbls were lost after the cement turned the corner. 2. 9-5/8” Secondary Cement Job a. 2nd stage of cement job planned with CFLEX at 50’ MD the base of the Tuluvak TS 790 formation (4,712’ MD). Also planned with a full 15.3 ppg tail slurry with 100% excess, targeting TOC at the 9-5/8” liner top. b. During the execution of the 2 nd cement stage, slight losses were encountered and 26 bbls were lost. Cement returns were witnessed off the top of liner and 50 bbls of cement returned to surface. Observations/ Conclusions a. For the 1 st stage of the cement job, despite the losses, there is adequate isolation in the upper Nanushuk formations across the hydrocarbon- bearing formations (top hydrocarbon estimated within NT7 at ~10,240’ MD). This is supported by the CBL log, which indicates good cement throughout the first stage and TOC at 9,950’ MD. b. For the 2 nd stage of the cement job, the job went as planned with only slight losses of 26 bbls. Losses were likely induced by the extra hydrostatic pressure from bringing 50 bbls of cement above the liner top. c. Our assessment is that we have adequate isolation across hydrocarbon- bearing formations in the upper Nanushuk, as well as adequate isolation for frac operations. The 2nd stage cement job demonstrated adequate isolation below, across, and above the Tuluvak significant hydrocarbons. d. See attached interpreted cement bond log from Baker SoundTrak LWD CBL. , CBL log, which indicates good cement)ppyg, throughout the first stage and TOC at 9,950’ MD. There is very little "good" cement in the 1st stage interval. the only good cement according to the Baker interpretation is 10458 to 10491 ft and 10868-10882 ft. poor to partial everywhere else, but cumulatively adequate for isolation, verified by LOT to 14.1 ppg. -bjm Page 1 of 1 Well Name: NDBi-030 Cement Intermediate 1st Stage Cement Job Intermediate 1st Stage Cement Job, Casing, 3/11/2024 17:00 Type Casing Cementing Start Date 3/11/2024 Cementing End Date 3/11/2024 Wellbore Original Hole String Intermediate Liner, 11,201.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Baker Soundtrack LWD Cement Evaluation Results 1st Stage was logged with the Baker Soundtrack LWD tool. TOC was picked at 9950' MD. Reference the CBL Report in the attachments for a detailed analysis of cement bond log results. Comment Cement 9-5/8” Liner thru Halliburton Fas-Drill Cement retainer. -Pump 77.8 bbls of 12.5 ppg Tuned spacer @ 2.5 BPM, 950 psi. (pumped 10 bbls water & 77.5 bbls spacer got back 71.3 bbls) -Pump 205 bbls of 15.3 ppg Versacem Tail cement. -Flush lines with 10 bbls water from Halliburton. -Displace with rig pumps 177.8 bbls 12.0 ppg MOBM as follows: Pumped 85 bbls at 2.5 BPM. ICP 425 PSI, FCP 733 PSI. Pumped 18 bbls at 2 BPM. ICP 645 PSI, FCP 667 PSI. Pumped 47 bbls at 1 BPM. ICP 464 PSI, FCP 560 PSI. Pumped 26 bbls at 0.5 BPM. ICP 411 PSI. FCP 513 PSI. -Lost 110 bbls after cement entered annulus. (200 bbls total for job) 1, 2,396.0-11,204.0ftKB Top Depth (ftKB) 2,396.0 Bottom Depth (ftKB) 11,204.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 3 Final Pump Rate (bbl/min) 1 Avg Pump Rate (bbl/min) 2 Final Pump Pressure (psi) 513.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 77.8 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail Type I/II Amount (sacks) 935 Class Type I/II Volume Pumped (bbl) 205.0 Estimated Top (ftKB) Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 122.3 Thickening Time (hr) 5.28 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 9.12 Page 1 of 1 Well Name: NDBi-030 Cement Intermediate 2nd Stage Cement Job Intermediate 2nd Stage Cement Job, Casing, 3/13/2024 04:30 Type Casing Cementing Start Date 3/13/2024 Cementing End Date 3/13/2024 Wellbore Original Hole String Intermediate Liner, 11,201.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Cemented from Archer stage tool at 4712' MD to liner top at 2367' MD. Job went as planned and 50 bbls of cement was circulated off liner top. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 4712’ (center of circulation port) as follows: -Pump 80 BBLS of 12.5 ppg mudflush spacer @3-4 BPM, ICP 290 PSI, FCP 190 PSI. -Pump 78 BBLS of 13.5 ppg tuned spacer @ 3-4 BPM, ICP 240 PSI, FCP 202 PSI. -No losses while pumping spacers -Pump 252 BBLS of 15.3 ppg tail cement VERSACEM @ 3-4 BPM. 100% excess volume. No Losses. -Flush Lines with 10 bbls fresh water from Halliburton unit. 3.7 bpm, 237 psi. -Displace Cement to Archer stage tool with 64 bbls of 12.0 ppg MOBM, at 4.0 bpm. ICP 400 psi. slowed to 3 bpm 475 psi for last 10 bbls. FCP 465 psi. 26 bbls lost to hole during displacement. CIP @ 07:53. - Set LTP and circulated 50 bbls green cement off liner top. 2, 2,366.0-4,709.0ftKB Top Depth (ftKB) 2,366.0 Bottom Depth (ftKB) 4,709.0 Full Return? No Vol Cement Ret (bbl) Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) Final Pump Rate (bbl/min) Avg Pump Rate (bbl/min) Final Pump Pressure (psi) Plug Bump Pressure (psi) 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 Mudflush Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 78.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 0.00 Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 1,144 Class Type I/II Volume Pumped (bbl) 252.0 Estimated Top (ftKB) 2,467.0 Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 5.93 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 27.33 Attachment D Attachment E Attachment F Wel l N a m e ND B i - 3 0 04 / 0 8 / 2 4 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # TY P E PP T RA T E ST A G E CU M ST A G E C U M ST A G E CU M SI Z E St a g e Cu m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) a FP b FP c WF 2 5 3. 5 40 40 16 8 0 16 8 0 40 40 d P u m p C h e c k WF 25 4 0 35 0 39 0 14 7 0 0 16 3 8 0 35 0 39 0 0 39 0 d Sp o t D a t a F R A C X L XL 2 5 16 20 0 59 0 8 4 0 0 2 4 7 8 0 2 0 0 5 9 0 e Da t a F R A C W F XL 2 5 16 50 64 0 2 1 0 0 2 6 8 8 0 5 0 6 4 0 e Di s p l a c e D F ( ad d s u r f a c e l i n e s t o d i s p . ) WF 2 5 40 26 0 90 0 1 0 9 2 0 3 7 8 0 0 2 6 0 9 0 0 f Sh u t d o w n a n d m o n i t o r 1 . 0 - 1 . 5 H 9 0 0 0 3 7 8 0 0 0 9 0 0 h Lo a d S t a g e 1 b a l l / c o l l e t , 9 0 0 0 3 7 8 0 0 0 9 0 0 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T CL E A N V O L U M S T A G E AV E R A G E FL U I D RA T E ST A G E CU M TO T J O B ST A G E CU M ST A G E CU M Si z e o r St a g e Cu m # PP A TY P E (B P M ) (B B L ) (B B L ) (B B L ) (G A L ) (G A L ) (L B S ) (L B S ) Ty p e (B B L ) (B B L ) 1 0 Li n e o u t X L X L 2 5 21 40 40 94 0 16 8 0 39 4 8 0 0 0 40 94 0 2 0 Dr o p S t a g e 1 B a l l / C o l l e t F P 0 21 3 43 94 3 12 6 39 6 0 6 0 0 16 / 2 0 - C L 3 94 3 3 0 St a g e 1 P A D XL 2 5 30 2 3 2 27 5 1 1 7 5 97 4 4 4 9 3 5 0 00 2 3 2 1 1 7 5 4 0 Sl o w f o r S e a t X L 2 5 18 50 32 5 1 2 2 5 21 0 0 5 1 4 5 0 0 0 5 0 1 2 2 5 5 0 Re s u m e P a d XL 2 5 40 6 8 39 3 1 2 9 3 28 5 6 5 4 3 0 6 0 0 6 8 1 2 9 3 6 1 Fl a t XL 2 5 40 1 8 0 57 3 1 4 7 3 75 6 0 6 1 8 6 6 72 4 0 7 2 4 0 16 / 2 0 - C L 17 2 1 4 6 5 7 2 Fl a t XL 2 5 40 1 8 0 75 3 1 6 5 3 75 6 0 6 9 4 2 6 13 8 9 1 2 1 1 3 0 16 / 2 0 - C L 16 5 1 6 3 1 8 3 Fl a t XL 2 5 40 2 0 0 95 3 1 8 5 3 84 0 0 7 7 8 2 6 22 2 4 7 4 3 3 7 7 16 / 2 0 - C L 17 7 1 8 0 7 9 4 Fl a t XL 2 5 40 2 0 0 11 5 3 2 0 5 3 84 0 0 8 6 2 2 6 28 5 4 7 7 1 9 2 5 16 / 2 0 - C L 17 0 1 9 7 7 10 5 Fl a t XL 2 5 40 2 0 0 13 5 3 2 2 5 3 84 0 0 9 4 6 2 6 34 3 9 1 1 0 6 3 1 6 16 / 2 0 - C L 16 4 2 1 4 1 11 6 Fl a t XL 2 5 40 2 0 0 15 5 3 2 4 5 3 84 0 0 1 0 3 0 2 6 39 8 2 7 1 4 6 1 4 3 16 / 2 0 - C L 15 8 2 2 9 9 12 7 Fl a t XL 2 5 40 1 8 5 17 3 8 2 6 3 8 77 7 0 1 1 0 7 9 6 41 5 2 8 1 8 7 6 7 0 16 / 2 0 - C L 14 1 2 4 4 0 13 8 Fl a t XL 2 5 40 1 7 0 19 0 8 2 8 0 8 71 4 0 1 1 7 9 3 6 42 1 8 7 2 2 9 8 5 7 16 / 2 0 - C L 12 6 2 5 6 6 14 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 19 2 8 2 8 2 8 84 0 1 1 8 7 7 6 02 2 9 8 5 7 2 0 2 5 8 6 15 0 Sp a c e r X L 2 5 40 5 19 3 3 2 8 3 3 21 0 1 1 8 9 8 6 02 2 9 8 5 7 5 2 5 9 1 16 0 Dr o p S t a g e 2 B a l l / C o l l e t F P 0 40 3 19 3 6 2 8 3 6 12 6 1 1 9 1 1 2 02 2 9 8 5 7 3 2 5 9 4 17 0 St a g e 2 XL 2 5 40 2 2 3 21 5 9 3 0 5 9 93 6 6 1 2 8 4 7 8 0 2 2 9 8 5 7 2 2 3 2 8 1 7 18 0 Sl o w f o r S e a t X L 2 5 18 50 22 0 9 3 1 0 9 21 0 0 1 3 0 5 7 8 0 2 2 9 8 5 7 5 0 2 8 6 7 19 0 Re s u m e P a d XL 2 5 40 7 7 22 8 6 3 1 8 6 32 3 4 1 3 3 8 1 2 02 2 9 8 5 7 7 7 2 9 4 4 20 1 Fl a t XL 2 5 40 1 8 0 24 6 6 3 3 6 6 75 6 0 1 4 1 3 7 2 72 4 0 2 3 7 0 9 6 16 / 2 0 - C L 17 2 3 1 1 6 21 2 Fl a t XL 2 5 40 1 8 0 26 4 6 3 5 4 6 75 6 0 1 4 8 9 3 2 13 8 9 1 2 5 0 9 8 7 16 / 2 0 - C L 16 5 3 2 8 2 22 3 Fl a t XL 2 5 40 2 0 0 28 4 6 3 7 4 6 84 0 0 1 5 7 3 3 2 22 2 4 7 2 7 3 2 3 4 16 / 2 0 - C L 17 7 3 4 5 8 23 4 Fl a t XL 2 5 40 2 0 0 30 4 6 3 9 4 6 84 0 0 1 6 5 7 3 2 28 5 4 7 3 0 1 7 8 1 16 / 2 0 - C L 17 0 3 6 2 8 24 5 Fl a t XL 2 5 40 2 0 0 32 4 6 4 1 4 6 84 0 0 1 7 4 1 3 2 34 3 9 1 3 3 6 1 7 3 16 / 2 0 - C L 16 4 3 7 9 2 25 6 Fl a t XL 2 5 40 2 0 0 34 4 6 4 3 4 6 84 0 0 1 8 2 5 3 2 39 8 2 7 3 7 5 9 9 9 16 / 2 0 - C L 15 8 3 9 5 0 26 7 Fl a t XL 2 5 40 1 8 5 36 3 1 4 5 3 1 77 7 0 1 9 0 3 0 2 41 5 2 8 4 1 7 5 2 7 16 / 2 0 - C L 14 1 4 0 9 1 27 8 Fl a t XL 2 5 40 1 7 0 38 0 1 4 7 0 1 71 4 0 1 9 7 4 4 2 42 1 8 7 4 5 9 7 1 3 16 / 2 0 - C L 12 6 4 2 1 7 28 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 38 2 1 4 7 2 1 84 0 1 9 8 2 8 2 04 5 9 7 1 3 2 0 4 2 3 7 29 0 Sp a c e r X L 2 5 40 5 38 2 6 4 7 2 6 21 0 1 9 8 4 9 2 04 5 9 7 1 3 5 4 2 4 2 FL U I D Ne a t W a t e r CO M M E N T S Sh u t D o w n , l i n e u p f o r X L Pr i m e a n d P r e s s u r e T e s t Op e n w e l l a n d o p e n i n i t i a t o r s l e e v e Di s p l a c e P T - S h u t d o w n 1 0 m i n Wel l N a m e ND B i - 3 0 04 / 0 8 / 2 4 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # TY P E PP T RA T E ST A G E CU M ST A G E C U M ST A G E CU M SI Z E St a g e Cu m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 30 0 Dr o p S t a g e 3 B a l l / C o l l e t F P 0 40 3 38 2 9 4 7 2 9 12 6 1 9 8 6 1 8 04 5 9 7 1 3 3 4 2 4 5 31 0 St a g e 3 XL 2 5 40 2 1 4 40 4 3 4 9 4 3 89 8 8 2 0 7 6 0 6 0 4 5 9 7 1 3 2 1 4 4 4 5 9 32 0 Sl o w f o r S e a t X L 2 5 18 50 40 9 3 4 9 9 3 21 0 0 2 0 9 7 0 6 0 4 5 9 7 1 3 5 0 4 5 0 9 33 0 Re s u m e P a d XL 2 5 40 3 6 41 2 9 5 0 2 9 15 1 2 2 1 1 2 1 8 04 5 9 7 1 3 3 6 4 5 4 5 34 1 Fl a t XL 2 5 40 1 8 0 43 0 9 5 2 0 9 75 6 0 2 1 8 7 7 8 72 4 0 4 6 6 9 5 3 16 / 2 0 - C L 17 2 4 7 1 7 35 3 Fl a t XL 2 5 40 2 0 0 45 0 9 5 4 0 9 84 0 0 2 2 7 1 7 8 22 2 4 7 4 8 9 2 0 0 16 / 2 0 - C L 17 7 4 8 9 4 36 5 Fl a t XL 2 5 40 2 3 0 47 3 9 5 6 3 9 96 6 0 2 3 6 8 3 8 39 5 5 0 5 2 8 7 5 0 16 / 2 0 - C L 18 8 5 0 8 2 37 7 Fl a t XL 2 5 40 2 3 0 49 6 9 5 8 6 9 96 6 0 2 4 6 4 9 8 51 6 2 9 5 8 0 3 7 9 16 / 2 0 - C L 17 6 5 2 5 8 38 9 Fl a t XL 2 5 40 2 1 5 51 8 4 6 0 8 4 90 3 0 2 5 5 5 2 8 58 1 2 3 6 3 8 5 0 2 16 / 2 0 - C L 15 4 5 4 1 1 39 10 Fl a t XL 2 5 40 1 8 0 53 6 4 6 2 6 4 75 6 0 2 6 3 0 8 8 52 4 1 0 6 9 0 9 1 2 16 / 2 0 - C L 12 5 5 5 3 6 40 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 53 8 4 6 2 8 4 84 0 2 6 3 9 2 8 06 9 0 9 1 2 2 0 5 5 5 6 41 0 Sp a c e r X L 2 5 40 5 53 8 9 6 2 8 9 21 0 2 6 4 1 3 8 06 9 0 9 1 2 5 5 5 6 1 42 0 Dr o p S t a g e 4 B a l l / C o l l e t F P 0 40 3 53 9 2 6 2 9 2 12 6 2 6 4 2 6 4 06 9 0 9 1 2 3 5 5 6 4 43 0 St a g e 4 XL 2 5 40 2 0 5 55 9 7 6 4 9 7 86 1 0 2 7 2 8 7 4 0 6 9 0 9 1 2 2 0 5 5 7 6 9 44 0 Sl o w f o r S e a t X L 2 5 18 50 56 4 7 6 5 4 7 21 0 0 2 7 4 9 7 4 0 6 9 0 9 1 2 5 0 5 8 1 9 45 0 Re s u m e P a d XL 2 5 40 7 0 57 1 7 6 6 1 7 29 4 0 2 7 7 9 1 4 06 9 0 9 1 2 7 0 5 8 8 9 46 1 Fl a t XL 2 5 40 1 8 0 58 9 7 6 7 9 7 75 6 0 2 8 5 4 7 4 72 4 0 6 9 8 1 5 2 16 / 2 0 - C L 17 2 6 0 6 1 47 2 Fl a t XL 2 5 40 2 2 0 61 1 7 7 0 1 7 92 4 0 2 9 4 7 1 4 16 9 7 8 7 1 5 1 2 9 16 / 2 0 - C L 20 2 6 2 6 4 48 4 Fl a t XL 2 5 40 2 4 0 63 5 7 7 2 5 7 10 0 8 0 3 0 4 7 9 4 34 2 5 7 7 4 9 3 8 6 16 / 2 0 - C L 20 4 6 4 6 8 49 6 Fl a t XL 2 5 40 2 4 0 65 9 7 7 4 9 7 10 0 8 0 3 1 4 8 7 4 47 7 9 2 7 9 7 1 7 8 16 / 2 0 - C L 19 0 6 6 5 7 50 8 Fl a t XL 2 5 40 2 4 0 68 3 7 7 7 3 7 10 0 8 0 3 2 4 9 5 4 59 5 5 8 8 5 6 7 3 6 16 / 2 0 - C L 17 7 6 8 3 4 51 10 Fl a t XL 2 5 40 2 0 0 70 3 7 7 9 3 7 84 0 0 3 3 3 3 5 4 58 2 3 3 9 1 4 9 6 9 16 / 2 0 - C L 13 9 6 9 7 3 52 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 70 5 7 7 9 5 7 84 0 3 3 4 1 9 4 09 1 4 9 6 9 2 0 6 9 9 3 53 0 Sp a c e r X L 2 5 40 5 70 6 2 7 9 6 2 21 0 3 3 4 4 0 4 09 1 4 9 6 9 5 6 9 9 8 54 0 Dr o p S t a g e 5 B a l l / C o l l e t F P 0 40 3 70 6 5 7 9 6 5 12 6 3 3 4 5 3 0 09 1 4 9 6 9 3 7 0 0 1 55 0 XL F l u s h XL 2 5 40 5 0 71 1 5 8 0 1 5 21 0 0 3 3 6 6 3 0 09 1 4 9 6 9 5 0 7 0 5 1 56 0 LG F l u s h WF 2 5 40 1 5 4 72 6 9 8 1 6 9 64 6 8 3 4 3 0 9 8 0 9 1 4 9 6 9 1 5 4 7 2 0 5 57 0 Sl o w f o r s e a t W F 2 5 18 50 73 1 9 8 2 1 9 21 0 0 3 4 5 1 9 8 0 9 1 4 9 6 9 5 0 7 2 5 5 58 0 Ov e r f l u s h ( e m p t y P C M ) WF 2 5 40 2 0 0 75 1 9 8 4 1 9 84 0 0 3 5 3 5 9 8 0 9 1 4 9 6 9 2 0 0 7 4 5 5 0 35 3 5 9 8 0 74 5 5 59 Li n e a r F l u s h WF 2 5 20 17 5 2 0 7 2 5 8 42 3 5 3 6 4 0 17456 60 Li n e a r F l u s h WF 2 5 20 17 5 2 1 7 2 5 9 42 3 5 3 6 8 2 17457 61 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 5 9 75 8 0 7 3 1 8 24 8 2 3 5 6 1 6 4 TOT A L S 84 8 0 35 6 1 6 4 91 4 9 6 9 Wel l N a m e ND B i - 3 0 04 / 0 8 / 2 4 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # TY P E PP T RA T E ST A G E CU M ST A G E C U M ST A G E CU M SI Z E St a g e Cu m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) a FP b FP c WF 2 5 3. 5 40 40 16 8 0 16 8 0 40 40 40 0 16 8 0 0 40 d Pu m p B a l l t o S e a t WF 2 5 4 22 5 26 5 22 5 26 5 e Pu m p C h e c k WF 2 5 40 12 0 38 5 5 0 4 0 6 7 2 0 1 2 0 3 8 5 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T CL E A N V O L U M S T A G E AV E R A G E FL U I D RA T E ST A G E CU M TO T J O B ST A G E CU M ST A G E CU M Si z e o r St a g e Cu m # PP A TY P E (B P M ) (B B L ) (B B L ) (B B L ) (G A L ) (G A L ) (L B S ) (L B S ) Ty p e (B B L ) (B B L ) 1 0 St a g e 5 P A D XL 2 5 40 32 5 32 5 71 0 13 6 5 0 20 3 7 0 0 0 32 5 71 0 2 1 Fl a t XL 2 5 40 18 0 50 5 89 0 75 6 0 27 9 3 0 72 4 0 72 4 0 16 / 2 0 - C L 17 2 88 2 3 2 Fl a t XL 2 5 40 2 0 0 70 5 1 0 9 0 84 0 0 3 6 3 3 0 15 4 3 4 2 2 6 7 4 16 / 2 0 - C L 18 4 1 0 6 6 4 4 Fl a t XL 2 5 40 2 2 0 92 5 1 3 1 0 92 4 0 4 5 5 7 0 31 4 0 2 5 4 0 7 6 16 / 2 0 - C L 18 7 1 2 5 3 5 6 Fl a t XL 2 5 40 2 2 0 11 4 5 1 5 3 0 92 4 0 5 4 8 1 0 43 8 0 9 9 7 8 8 5 16 / 2 0 - C L 17 4 1 4 2 7 6 8 Fl a t XL 2 5 40 2 2 0 13 6 5 1 7 5 0 92 4 0 6 4 0 5 0 54 5 9 5 1 5 2 4 8 0 16 / 2 0 - C L 16 2 1 5 8 9 7 10 Fl a t XL 2 5 40 1 8 0 15 4 5 1 9 3 0 75 6 0 7 1 6 1 0 52 4 1 0 2 0 4 8 8 9 16 / 2 0 - C L 12 5 1 7 1 4 8 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 15 6 5 1 9 5 0 84 0 7 2 4 5 0 02 0 4 8 8 9 2 0 1 7 3 4 9 0 Sp a c e r X L 2 5 40 5 15 7 0 1 9 5 5 21 0 7 2 6 6 0 02 0 4 8 8 9 5 1 7 3 9 10 0 Dr o p S t a g e 6 B a l l / C o l l e t F P 0 40 3 15 7 3 1 9 5 8 12 6 7 2 7 8 6 02 0 4 8 8 9 3 1 7 4 2 11 0 St a g e 6 XL 2 5 40 1 8 8 17 6 1 2 1 4 6 78 9 6 8 0 6 8 2 0 2 0 4 8 8 9 1 8 8 1 9 3 0 12 0 Sl o w f o r S e a t X L 2 5 18 50 18 1 1 2 1 9 6 21 0 0 8 2 7 8 2 0 2 0 4 8 8 9 5 0 1 9 8 0 13 0 Re s u m e P a d XL 2 5 40 8 7 18 9 8 2 2 8 3 36 5 4 8 6 4 3 6 02 0 4 8 8 9 8 7 2 0 6 7 14 1 Fl a t XL 2 5 40 1 8 0 20 7 8 2 4 6 3 75 6 0 9 3 9 9 6 72 4 0 2 1 2 1 2 9 16 / 2 0 - C L 17 2 2 2 4 0 15 2 Fl a t XL 2 5 40 2 2 0 22 9 8 2 6 8 3 92 4 0 1 0 3 2 3 6 16 9 7 8 2 2 9 1 0 7 16 / 2 0 - C L 20 2 2 4 4 2 16 4 Fl a t XL 2 5 40 2 4 0 25 3 8 2 9 2 3 10 0 8 0 1 1 3 3 1 6 34 2 5 7 2 6 3 3 6 4 16 / 2 0 - C L 20 4 2 6 4 6 17 6 Fl a t XL 2 5 40 2 4 0 27 7 8 3 1 6 3 10 0 8 0 1 2 3 3 9 6 47 7 9 2 3 1 1 1 5 5 16 / 2 0 - C L 19 0 2 8 3 5 18 8 Fl a t XL 2 5 40 2 4 0 30 1 8 3 4 0 3 10 0 8 0 1 3 3 4 7 6 59 5 5 8 3 7 0 7 1 3 16 / 2 0 - C L 17 7 3 0 1 2 19 10 Fl a t XL 2 5 40 2 0 0 32 1 8 3 6 0 3 84 0 0 1 4 1 8 7 6 58 2 3 3 4 2 8 9 4 6 16 / 2 0 - C L 13 9 3 1 5 1 20 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 32 3 8 3 6 2 3 84 0 1 4 2 7 1 6 04 2 8 9 4 6 2 0 3 1 7 1 21 0 Sp a c e r X L 2 5 40 5 32 4 3 3 6 2 8 21 0 1 4 2 9 2 6 04 2 8 9 4 6 5 3 1 7 6 22 0 Dr o p S t a g e 7 B a l l / C o l l e t F P 0 40 3 32 4 6 3 6 3 1 12 6 1 4 3 0 5 2 04 2 8 9 4 6 3 3 1 7 9 23 0 St a g e 7 XL 2 5 40 1 7 9 34 2 5 3 8 1 0 75 1 8 1 5 0 5 7 0 0 4 2 8 9 4 6 1 7 9 3 3 5 8 24 0 Sl o w f o r S e a t X L 2 5 18 50 34 7 5 3 8 6 0 21 0 0 1 5 2 6 7 0 0 4 2 8 9 4 6 5 0 3 4 0 8 25 0 Re s u m e P a d XL 2 5 40 7 1 35 4 6 3 9 3 1 29 8 2 1 5 5 6 5 2 04 2 8 9 4 6 7 1 3 4 7 9 26 1 Fl a t XL 2 5 40 1 8 0 37 2 6 4 1 1 1 75 6 0 1 6 3 2 1 2 72 4 0 4 3 6 1 8 6 16 / 2 0 - C L 17 2 3 6 5 1 27 3 Fl a t XL 2 5 40 2 0 0 39 2 6 4 3 1 1 84 0 0 1 7 1 6 1 2 22 2 4 7 4 5 8 4 3 3 16 / 2 0 - C L 17 7 3 8 2 8 28 5 Fl a t XL 2 5 40 2 3 0 41 5 6 4 5 4 1 96 6 0 1 8 1 2 7 2 39 5 5 0 4 9 7 9 8 3 16 / 2 0 - C L 18 8 4 0 1 6 29 7 Fl a t XL 2 5 40 2 3 0 43 8 6 4 7 7 1 96 6 0 1 9 0 9 3 2 51 6 2 9 5 4 9 6 1 2 16 / 2 0 - C L 17 6 4 1 9 2 30 9 Fl a t XL 2 5 40 2 1 5 46 0 1 4 9 8 6 90 3 0 1 9 9 9 6 2 58 1 2 3 6 0 7 7 3 5 16 / 2 0 - C L 15 4 4 3 4 6 31 10 Fl a t XL 2 5 40 1 8 0 47 8 1 5 1 6 6 75 6 0 2 0 7 5 2 2 52 4 1 0 6 6 0 1 4 5 16 / 2 0 - C L 12 5 4 4 7 1 32 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 48 0 1 5 1 8 6 84 0 2 0 8 3 6 2 06 6 0 1 4 5 2 0 4 4 9 1 33 0 Sp a c e r X L 2 5 40 5 48 0 6 5 1 9 1 21 0 2 0 8 5 7 2 06 6 0 1 4 5 5 4 4 9 6 FL U I D Ne a t W a t e r CO M M E N T S St a r t X L - S t a g e t o P A D 5 Pr i m e a n d P r e s s u r e T e s t Op e n W e l l a n d l i n e u p t o d i s p l a c e P T Di s p l a c e P T p a s t W H Dr o p B a l l - S D 1 0 m i n u t e s Wel l N a m e ND B i - 3 0 04 / 0 8 / 2 4 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # TY P E PP T RA T E ST A G E CU M ST A G E C U M ST A G E CU M SI Z E St a g e Cu m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 34 0 Dr o p S t a g e 8 B a l l / C o l l e t F P 0 40 3 48 0 9 5 1 9 4 12 6 2 0 8 6 9 8 06 6 0 1 4 5 3 4 4 9 9 35 0 St a g e 8 XL 2 5 40 1 7 1 49 8 0 5 3 6 5 71 8 2 2 1 5 8 8 0 0 6 6 0 1 4 5 1 7 1 4 6 7 0 36 0 Sl o w f o r S e a t X L 2 5 18 50 50 3 0 5 4 1 5 21 0 0 2 1 7 9 8 0 0 6 6 0 1 4 5 5 0 4 7 2 0 37 0 Re s u m e P a d XL 2 5 40 7 9 51 0 9 5 4 9 4 33 1 8 2 2 1 2 9 8 06 6 0 1 4 5 7 9 4 7 9 9 38 1 Fl a t XL 2 5 40 1 8 0 52 8 9 5 6 7 4 75 6 0 2 2 8 8 5 8 72 4 0 6 6 7 3 8 4 16 / 2 0 - C L 17 2 4 9 7 1 39 3 Fl a t XL 2 5 40 2 0 0 54 8 9 5 8 7 4 84 0 0 2 3 7 2 5 8 22 2 4 7 6 8 9 6 3 1 16 / 2 0 - C L 17 7 5 1 4 7 40 5 Fl a t XL 2 5 40 2 3 0 57 1 9 6 1 0 4 96 6 0 2 4 6 9 1 8 39 5 5 0 7 2 9 1 8 1 16 / 2 0 - C L 18 8 5 3 3 6 41 7 Fl a t XL 2 5 40 2 3 0 59 4 9 6 3 3 4 96 6 0 2 5 6 5 7 8 51 6 2 9 7 8 0 8 1 0 16 / 2 0 - C L 17 6 5 5 1 1 42 9 Fl a t XL 2 5 40 2 1 5 61 6 4 6 5 4 9 90 3 0 2 6 5 6 0 8 58 1 2 3 8 3 8 9 3 4 16 / 2 0 - C L 15 4 5 6 6 5 43 10 Fl a t XL 2 5 40 1 8 0 63 4 4 6 7 2 9 75 6 0 2 7 3 1 6 8 52 4 1 0 8 9 1 3 4 3 16 / 2 0 - C L 12 5 5 7 9 0 44 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 63 6 4 6 7 4 9 84 0 2 7 4 0 0 8 08 9 1 3 4 3 2 0 5 8 1 0 45 0 Sp a c e r X L 2 5 40 5 63 6 9 6 7 5 4 21 0 2 7 4 2 1 8 08 9 1 3 4 3 5 5 8 1 5 46 0 Dr o p S t a g e 9 B a l l / C o l l e t F P 0 40 3 63 7 2 6 7 5 7 12 6 2 7 4 3 4 4 08 9 1 3 4 3 3 5 8 1 8 47 0 XL F l u s h XL 2 5 40 5 0 64 2 2 6 8 0 7 21 0 0 2 7 6 4 4 4 08 9 1 3 4 3 5 0 5 8 6 8 48 0 LG F l u s h WF 2 5 40 1 1 2 65 3 4 6 9 1 9 47 0 4 2 8 1 1 4 8 0 8 9 1 3 4 3 1 1 2 5 9 8 0 49 0 Sl o w f o r s e a t W F 2 5 18 50 65 8 4 6 9 6 9 21 0 0 2 8 3 2 4 8 0 8 9 1 3 4 3 5 0 6 0 3 0 50 0 Ov e r f l u s h ( e m p t y P C M ) WF 2 5 40 2 0 0 67 8 4 7 1 6 9 84 0 0 2 9 1 6 4 8 0 8 9 1 3 4 3 2 0 0 6 2 3 0 0 29 1 6 4 8 0 62 3 0 51 Li n e a r F l u s h WF 2 5 20 16 7 8 5 6 9 2 0 42 2 9 1 6 9 0 16231 52 Li n e a r F l u s h WF 2 5 20 16 7 8 6 6 9 2 1 42 2 9 1 7 3 2 16232 53 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 5 9 68 4 5 6 9 8 0 24 8 2 2 9 4 2 1 4 TOT A L S 72 3 0 29 4 2 1 4 89 1 3 4 3 Wel l N a m e ND B i - 3 0 04 / 0 8 / 2 4 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # TY P E PP T RA T E ST A G E CU M ST A G E C U M ST A G E CU M SI Z E St a g e Cu m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) a FP b FP c WF 2 5 3. 5 40 40 16 8 0 16 8 0 40 40 40 0 16 8 0 0 40 d Pu m p B a l l t o S e a t WF 2 5 4 19 0 23 0 19 0 23 0 e Pu m p C h e c k WF 2 5 40 12 0 35 0 5 0 4 0 6 7 2 0 1 2 0 3 5 0 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T CL E A N V O L U M S T A G E AV E R A G E FL U I D RA T E ST A G E CU M TO T J O B ST A G E CU M ST A G E CU M Si z e o r St a g e Cu m # PP A TY P E (B P M ) (B B L ) (B B L ) (B B L ) (G A L ) (G A L ) (L B S ) (L B S ) Ty p e (B B L ) (B B L ) 1 0 St a g e 9 P A D XL 2 5 40 30 0 30 0 65 0 12 6 0 0 19 3 2 0 0 0 30 0 65 0 2 1 Fl a t XL 2 5 40 18 0 48 0 83 0 75 6 0 26 8 8 0 72 4 0 72 4 0 16 / 2 0 - C L 17 2 82 2 3 3 Fl a t XL 2 5 40 2 0 0 68 0 1 0 3 0 84 0 0 3 5 2 8 0 22 2 4 7 2 9 4 8 7 16 / 2 0 - C L 17 7 9 9 9 4 5 Fl a t XL 2 5 40 2 3 0 91 0 1 2 6 0 96 6 0 4 4 9 4 0 39 5 5 0 6 9 0 3 7 16 / 2 0 - C L 18 8 1 1 8 7 5 7 Fl a t XL 2 5 40 2 3 0 11 4 0 1 4 9 0 96 6 0 5 4 6 0 0 51 6 2 9 1 2 0 6 6 5 16 / 2 0 - C L 17 6 1 3 6 3 6 9 Fl a t XL 2 5 40 2 1 5 13 5 5 1 7 0 5 90 3 0 6 3 6 3 0 58 1 2 3 1 7 8 7 8 9 16 / 2 0 - C L 15 4 1 5 1 7 7 10 Fl a t XL 2 5 40 1 8 0 15 3 5 1 8 8 5 75 6 0 7 1 1 9 0 52 4 1 0 2 3 1 1 9 9 16 / 2 0 - C L 12 5 1 6 4 1 8 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 15 5 5 1 9 0 5 84 0 7 2 0 3 0 02 3 1 1 9 9 2 0 1 6 6 1 9 0 Sp a c e r X L 2 5 40 5 15 6 0 1 9 1 0 21 0 7 2 2 4 0 02 3 1 1 9 9 5 1 6 6 6 10 0 Dr o p S t a g e 1 0 B a l l / C o l l e t F P 0 40 3 15 6 3 1 9 1 3 12 6 7 2 3 6 6 02 3 1 1 9 9 3 1 6 6 9 11 0 St a g e 1 0 P A D XL 2 5 40 1 5 4 17 1 7 2 0 6 7 64 6 8 7 8 8 3 4 0 2 3 1 1 9 9 1 5 4 1 8 2 3 12 0 Sl o w f o r S e a t X L 2 5 18 50 17 6 7 2 1 1 7 21 0 0 8 0 9 3 4 0 2 3 1 1 9 9 5 0 1 8 7 3 13 0 Re s u m e P a d XL 2 5 40 9 6 18 6 3 2 2 1 3 40 3 2 8 4 9 6 6 02 3 1 1 9 9 9 6 1 9 6 9 14 1 Fl a t XL 2 5 40 1 8 0 20 4 3 2 3 9 3 75 6 0 9 2 5 2 6 72 4 0 2 3 8 4 3 8 16 / 2 0 - C L 17 2 2 1 4 2 15 3 Fl a t XL 2 5 40 2 0 0 22 4 3 2 5 9 3 84 0 0 1 0 0 9 2 6 22 2 4 7 2 6 0 6 8 5 16 / 2 0 - C L 17 7 2 3 1 8 16 5 Fl a t XL 2 5 40 2 3 0 24 7 3 2 8 2 3 96 6 0 1 1 0 5 8 6 39 5 5 0 3 0 0 2 3 5 16 / 2 0 - C L 18 8 2 5 0 7 17 7 Fl a t XL 2 5 40 2 3 0 27 0 3 3 0 5 3 96 6 0 1 2 0 2 4 6 51 6 2 9 3 5 1 8 6 4 16 / 2 0 - C L 17 6 2 6 8 2 18 9 Fl a t XL 2 5 40 2 1 5 29 1 8 3 2 6 8 90 3 0 1 2 9 2 7 6 58 1 2 3 4 0 9 9 8 7 16 / 2 0 - C L 15 4 2 8 3 6 19 10 Fl a t XL 2 5 40 1 8 0 30 9 8 3 4 4 8 75 6 0 1 3 6 8 3 6 52 4 1 0 4 6 2 3 9 7 16 / 2 0 - C L 12 5 2 9 6 1 20 0 Cl e a r S u r f a c e L i n e s XL 2 5 40 2 0 31 1 8 3 4 6 8 84 0 1 3 7 6 7 6 04 6 2 3 9 7 2 0 2 9 8 1 21 0 Sp a c e r X L 2 5 40 5 31 2 3 3 4 7 3 21 0 1 3 7 8 8 6 04 6 2 3 9 7 5 2 9 8 6 22 0 Dr o p S t a g e 1 1 B a l l / C o l l e t F P 0 40 3 31 2 6 3 4 7 6 12 6 1 3 8 0 1 2 04 6 2 3 9 7 3 2 9 8 9 23 0 St a g e 1 1 XL 2 5 40 1 4 7 32 7 3 3 6 2 3 61 7 4 1 4 4 1 8 6 0 4 6 2 3 9 7 1 4 7 3 1 3 6 24 0 Sl o w f o r S e a t X L 2 5 18 50 33 2 3 3 6 7 3 21 0 0 1 4 6 2 8 6 0 4 6 2 3 9 7 5 0 3 1 8 6 25 0 Re s u m e P a d XL 2 5 40 1 0 3 34 2 6 3 7 7 6 43 2 6 1 5 0 6 1 2 0 4 6 2 3 9 7 1 0 3 3 2 8 9 26 1 Fl a t XL 2 5 40 1 8 0 36 0 6 3 9 5 6 75 6 0 1 5 8 1 7 2 72 4 0 4 6 9 6 3 7 16 / 2 0 - C L 17 2 3 4 6 1 27 3 Fl a t XL 2 5 40 2 0 0 38 0 6 4 1 5 6 84 0 0 1 6 6 5 7 2 22 2 4 7 4 9 1 8 8 4 16 / 2 0 - C L 17 7 3 6 3 8 28 5 Fl a t XL 2 5 40 2 3 0 40 3 6 4 3 8 6 96 6 0 1 7 6 2 3 2 39 5 5 0 5 3 1 4 3 4 16 / 2 0 - C L 18 8 3 8 2 6 29 7 Fl a t XL 2 5 40 2 3 0 42 6 6 4 6 1 6 96 6 0 1 8 5 8 9 2 51 6 2 9 5 8 3 0 6 3 16 / 2 0 - C L 17 6 4 0 0 2 30 9 Fl a t XL 2 5 40 2 1 5 44 8 1 4 8 3 1 90 3 0 1 9 4 9 2 2 58 1 2 3 6 4 1 1 8 6 16 / 2 0 - C L 15 4 4 1 5 5 31 10 Fl a t XL 2 5 40 1 8 0 46 6 1 5 0 1 1 75 6 0 2 0 2 4 8 2 52 4 1 0 6 9 3 5 9 6 16 / 2 0 - C L 12 5 4 2 8 0 0 20 2 4 8 2 0 42 8 0 FL U I D Ne a t W a t e r CO M M E N T S St a r t X L - S t a g e t o P A D 9 Pr i m e a n d P r e s s u r e T e s t Op e n W e l l a n d l i n e u p t o d i s p l a c e P T Di s p l a c e P T p a s t W H Dr o p B a l l - S D 1 0 m i n u t e s Wel l N a m e ND B i - 3 0 04 / 0 8 / 2 4 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # TY P E PP T RA T E ST A G E CU M ST A G E C U M ST A G E CU M SI Z E St a g e Cu m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 32 XL F l u s h XL 2 5 40 20 4 6 8 1 5 0 3 1 84 0 2 0 3 3 2 2 20 4 3 0 0 33 Li n e a r F l u s h WF 2 5 40 95 4 7 7 6 5 1 2 6 39 9 0 2 0 7 3 1 2 95 4 3 9 5 34 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 5 9 48 3 5 5 1 8 5 24 8 2 2 0 9 7 9 4 TOT A L S 51 8 5 20 9 7 9 4 69 3 5 9 6 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 759.5 gal J450 Stabilizing Agent 0.5 Gal/mGal 379.8 gal J475 Breaker J475 6.0 lb/mGal 4,557.2 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,519.1 lbm J532 Crosslinker 2.2 Gal/mGal 1662.6 gal J580 Gel J580 25 lb/mGal 18988.2 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 38.0 gal M275 Bactericide 0.3 lb/mGal 227.9 lbm S522-1620 Propping Agent varied concentrations 2,499,908.0 lbm ~ 71 % ~ 28 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % Total 100 % Client:Oil Search Alaska Well:NDBi-030 Basin/Field:Pikka State:Alaska County/Parish:North Slope Borough Case: Disclosure Type:Pre-Job Well Completed: Date Prepared:4/11/2024 Report ID:RPT-1849 Fluid Name & Volume Concentration Volume YF125 ST:WF125 759,528 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 102-71-6 2,2`,2"-nitrilotriethanol 7727-54-0 Diammonium peroxodisulphate 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 50-70-4 Sorbitol 67-63-0 Propan-2-ol 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 9025-56-3 Hemicellulase 91053-39-3 Diatomaceous earth, calcined 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 14807-96-6 Magnesium silicate hydrate (talc) 9002-84-0 poly(tetrafluoroethylene) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 127-08-2 Acetic acid, potassium salt (impurity) 9000-90-2 Amylase, alpha 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. Total # SLB-Private Page: 1 / 1 Attachment G NDBi-030 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: x Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. x Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. x Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. x Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. x Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gasg(),q for the duration of the development well flowback work. Attachment H NDBi-030 4-1/2” Production Liner Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P-110S TSH563 lower completions per tally. 2. Circulate out 10.0 ppg OBM with 10.0 ppg NaCl/KCl brine to surface. 3. Drop 1.125” phenolic ball and circulate up to 5 bpm to close WIV. 4. Pressure up to close the WIV at 1,980 psi. 5. Continue increasing pressure to start setting the openhole hydraulic packers at 2,688 psi. 6. Set the 9-5/8” x 4-1/2” SLZXP liner hanger/top packer and openhole packers to 4,000 psi. 7. Before releasing, pressure test the IA to top liner hanger/packer to 4,000 psi for 30 minutes. 8. Release running tool from liner hanger. 9. Circulate 9.4 ppg NaCl Corrosion Inhibited brine to surface at 10 bpm pump rate. 10.POOH with liner hanger running tool. 11.Prepare to run upper completion. NDBi-030 4-1/2” Upper Completion Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 2. Land tubing hanger. 3. MIT-T to 4,000 psi. (Post Rig Move, MIT-T will be tested to 6,000 psi) a. (8,900 psi MAWP – 3,500 psi IA hold) * 1.1 = 6,000 psi 4. MIT-IA to 4,000 psi. (Post Rig, MIT-IA was tested again to 4,000 psi with AOGCC notification and witness was waived by Josh Hunt on 04/01/2024) 5. Shear circulation valve. 6. Reverse circulate freeze protect and U-Tube. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k frac tree. 9. RDMO 4,000 psi. 6,000 NDBi-030 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment I Attachment J Attachment K FracCADE* STIMULATION PROPOSAL Operator :Oil Search Well :NDBi-030 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 : 04-11-2024 FAX No. : 1 907 659 2538 Prepared by : Laura Acosta Phone : E-Mail Address :NTrevino2@slb.com * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. 1 Attachment K Section 1: Zone Data (Stage 1; 17220 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Young’s Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) Shale 4043.2 10.0 0.73 2937 1.46E+06 0.220 2500 Shale 4053.2 15.0 0.70 2822 1.76E+06 0.220 2500 Nanushuk 3 SS 4068.2 15.3 0.68 2763 1.90E+06 0.220 2000 Top Nan 4083.5 6.0 0.64 2630 8.39E+05 0.270 1000 Shale 4089.5 2.0 0.70 2858 2.67E+06 0.230 2500 Nan DS 4091.5 1.5 0.63 2584 8.19E+05 0.270 1500 Nan DS 4093.0 2.0 0.64 2615 1.22E+06 0.260 1500 Nan CS 4095.0 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4108.0 1.5 0.61 2524 1.00E+06 0.270 1000 Nan CS 4109.5 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4113.5 9.0 0.61 2500 1.17E+06 0.270 1000 Nan CS 4122.5 7.0 0.64 2659 7.69E+05 0.270 1000 Nan CS 4129.5 5.5 0.62 2543 1.28E+06 0.260 1000 Nan CS 4135.0 13.0 0.64 2665 6.92E+05 0.280 1000 Nan DS 4148.0 2.5 0.68 2817 1.75E+06 0.260 1500 Nan DS 4150.5 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4163.0 4.0 0.69 2882 1.69E+06 0.260 1500 Nan DS 4167.0 2.5 0.64 2675 8.22E+05 0.270 1500 Shale 4169.5 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4171.5 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4175.5 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4179.5 4.0 0.70 2921 2.67E+06 0.230 2500 Nan DS 4183.5 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4189.5 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4191.5 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4193.5 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4200.0 4.0 0.61 2576 8.99E+05 0.270 1500 Nan DS 4204.0 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4207.5 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4209.5 12.5 0.64 2690 1.56E+06 0.260 1500 Nan DS 4222.0 2.0 0.65 2747 1.40E+06 0.260 1500 Shale 4224.0 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4226.0 2.0 0.65 2752 1.24E+06 0.260 1500 Shale 4228.0 8.0 0.69 2916 2.67E+06 0.230 2500 Nan DS 4236.0 2.0 0.63 2682 9.33E+05 0.270 1500 Shale 4238.0 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4242.0 6.0 0.65 2742 1.43E+06 0.260 1500 Shale 4248.0 8.0 0.70 2959 2.67E+06 0.230 2500 Nan DS 4256.0 6.5 0.65 2766 1.47E+06 0.260 1500 Shale 4262.5 6.0 0.69 2939 2.67E+06 0.230 2500 Nan DS 4268.5 2.0 0.64 2726 8.38E+05 0.270 1000 Shale 4270.5 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4272.5 4.0 0.65 2778 1.47E+06 0.260 1500 Shale 4276.5 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4278.5 6.0 0.67 2849 1.55E+06 0.260 1500 Shale 4284.5 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4296.5 2.5 0.64 2754 1.21E+06 0.270 1500 Shale 4299.0 20.0 0.69 2969 2.67E+06 0.230 2500 Zone Name Poisson’s Ratio Formation Mechanical Properties 2 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4043.2 10.0 0.001 1.0 1881 4053.2 15.0 0.001 1.0 1886 4068.2 15.3 0.005 10.0 1890 4083.5 6.0 56.445 22.0 1882 4089.5 2.0 0.001 1.0 1884 4091.5 1.5 109.347 15.0 1885 4093.0 2.0 4.377 15.0 1886 4095.0 13.0 42.829 22.0 1887 4108.0 1.5 11.097 22.0 1893 4109.5 4.0 91.857 22.0 1894 4113.5 9.0 4.906 22.0 1896 4122.5 7.0 12.361 22.0 1900 4129.5 5.5 2.537 22.0 1903 4135.0 13.0 61.847 22.0 1906 4148.0 2.5 0.081 15.0 1912 4150.5 12.5 22.858 15.0 1913 4163.0 4.0 0.018 15.0 1919 4167.0 2.5 94.329 15.0 1920 4169.5 2.0 0.001 1.0 1922 4171.5 4.0 45.186 15.0 1922 4175.5 4.0 24.865 15.0 1924 4179.5 4.0 0.001 1.0 1926 4183.5 6.0 6.405 15.0 1928 4189.5 2.0 0.001 1.0 1931 4191.5 2.0 13.686 15.0 1932 4193.5 6.5 0.229 15.0 1933 4200.0 4.0 49.420 15.0 1936 4204.0 3.5 63.759 15.0 1938 4207.5 2.0 0.001 1.0 1939 4209.5 12.5 1.337 15.0 1940 4222.0 2.0 1.843 15.0 1946 4224.0 2.0 0.001 1.0 1947 4226.0 2.0 4.320 15.0 1948 4228.0 8.0 0.001 1.0 1949 4236.0 2.0 91.060 15.0 1952 4238.0 4.0 0.001 1.0 1953 4242.0 6.0 4.551 15.0 1955 4248.0 8.0 0.001 1.0 1958 4256.0 6.5 7.953 15.0 1962 4262.5 6.0 0.001 1.0 1965 4268.5 2.0 24.687 15.0 1967 4270.5 2.0 0.001 1.0 1968 4272.5 4.0 2.159 10.0 1969 4276.5 2.0 0.001 1.0 1971 4278.5 6.0 1.534 10.0 1972 4284.5 12.0 0.001 1.0 1975 4296.5 2.5 5.632 10.0 1980 4299.0 20.0 0.001 1.0 1982 Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Shale Nan CS Nan CS Nan CS Nan CS Nan CS Nan CS 3 Attachment K Section 2: Propped Fracture Schedule (Stage 1; 17220 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 350.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 165.5 25 2 3.0 PPA 40 YF125ST 176.8 25 3 4.0 PPA 40 YF125ST 170.2 25 4 5.0 PPA 40 YF125ST 164.1 25 5 6.0 PPA 40 YF125ST 158.4 25 6 7.0 PPA 40 YF125ST 141.6 25 7 8.0 PPA 40 YF125ST 125.9 25 8 Flush 40 YF125ST 260.3 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1885.3 bbl of YF125ST 0 bbl of WF125 230336 lb of % PAD Clean 21.5 % PAD Dirty 18.8 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 350.0 350 350 350 0 0 4343 8.8 8.8 1.0 PPA 172.5 522 180 530 7243 7243 4359 4.5 13.3 2.0 PPA 165.5 688 180 710 13903 21146 4436 4.5 17.8 3.0 PPA 176.8 865 200 910 22275 43421 4758 5.0 22.8 4.0 PPA 170.2 1035 200 1110 28594 72016 5153 5.0 27.8 5.0 PPA 164.1 1199 200 1310 34460 106475 5533 5.0 32.8 6.0 PPA 158.4 1357 200 1510 39918 146393 5908 5.0 37.8 7.0 PPA 141.6 1499 185 1695 41635 188029 6256 4.6 42.4 8.0 PPA 125.9 1625 170 1865 42308 230336 6501 4.3 46.6 Flush 260.3 1885 260 2125 0 230336 5949 6.5 53.1 Carbolite 16/20 Proppant Totals Carbolite 16/20 Pad Percentages Job Execution Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 384.8 ft with an average conductivity (Kfw) of 14304.4 md.ft. Job Description Fluid Name Prop. Type and Mesh 4 Attachment K Section 3: Propped Fracture Simulation (Stage 1; 17720 ft MD) Initial Fracture Top TVD 4044.5 ft Initial Fracture Bottom TVD 4284.6 ft Propped Fracture Half-Length 384.8 ft EOJ Hyd Height at Well 240.1 ft Average Propped Width 0.166 in Net Pressure 250 psi Max Surface Pressure 6636 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 96.2 7.4 0.18 228.6 1.56 257.3 16024 96.2 192.4 6 0.183 208.9 1.64 271.7 15833 192.4 288.6 5.1 0.181 177.5 1.63 284.9 15701 288.6 384.8 2.3 0.128 154.6 1.21 431.5 10476 Simulation Results by Fracture Segment The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. 5 Attachment K 6636 psi Section 4: Zone Data (Stage 2; 16638 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 4047.4 10.0 0.72 2937 1.46E+06 0.220 2500 Shale 4057.4 15.0 0.70 2825 1.76E+06 0.220 2500 Nanushuk 3 SS 4072.4 15.3 0.68 2766 1.90E+06 0.220 2000 Top Nan 4087.7 6.0 0.64 2622 8.39E+05 0.270 1000 Shale 4093.7 2.0 0.70 2850 2.67E+06 0.230 2500 Nan DS 4095.7 1.5 0.63 2577 8.19E+05 0.270 1500 Nan DS 4097.2 2.0 0.64 2615 1.22E+06 0.260 1500 Nan CS 4099.2 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4112.2 1.5 0.61 2517 1.00E+06 0.270 1000 Nan CS 4113.7 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4117.7 9.0 0.61 2502 1.17E+06 0.270 1000 Nan CS 4126.7 7.0 0.64 2652 7.69E+05 0.270 1000 Nan CS 4133.7 5.5 0.61 2536 1.28E+06 0.260 1000 Nan CS 4139.2 13.0 0.64 2657 6.92E+05 0.280 1000 Nan DS 4152.2 2.5 0.68 2817 1.75E+06 0.260 1500 Nan DS 4154.7 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4167.2 4.0 0.69 2891 1.69E+06 0.260 1500 Nan DS 4171.2 2.5 0.64 2675 8.22E+05 0.270 1500 Shale 4173.7 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4175.7 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4179.7 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4183.7 4.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4187.7 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4193.7 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4195.7 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4197.7 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4204.2 4.0 0.61 2576 8.99E+05 0.270 1500 Nan DS 4208.2 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4211.7 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4213.7 12.5 0.64 2698 1.56E+06 0.260 1500 Nan DS 4226.2 2.0 0.65 2739 1.40E+06 0.260 1500 Shale 4228.2 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4230.2 2.0 0.65 2755 1.24E+06 0.260 1500 Shale 4232.2 8.0 0.69 2919 2.67E+06 0.230 2500 Nan DS 4240.2 2.0 0.63 2690 9.33E+05 0.270 1500 Shale 4242.2 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4246.2 6.0 0.65 2745 1.43E+06 0.260 1500 Shale 4252.2 8.0 0.70 2969 2.67E+06 0.230 2500 Nan DS 4260.2 6.5 0.65 2758 1.47E+06 0.260 1500 Shale 4266.7 6.0 0.69 2942 2.67E+06 0.230 2500 Nan DS 4272.7 2.0 0.64 2718 8.38E+05 0.270 1000 Shale 4274.7 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4276.7 4.0 0.65 2781 1.47E+06 0.260 1500 Shale 4280.7 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4282.7 6.0 0.66 2841 1.55E+06 0.260 1500 Shale 4288.7 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4300.7 2.5 0.64 2754 1.21E+06 0.270 1500 Shale 4303.2 20.0 0.69 2972 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 6 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4047.4 10.0 0.001 1.0 1881 4057.4 15.0 0.001 1.0 1886 4072.4 15.3 0.005 10.0 1890 4087.7 6.0 56.445 22.0 1882 4093.7 2.0 0.001 1.0 1884 4095.7 1.5 109.347 15.0 1885 4097.2 2.0 4.377 15.0 1886 4099.2 13.0 42.829 22.0 1887 4112.2 1.5 11.097 22.0 1893 4113.7 4.0 91.857 22.0 1894 4117.7 9.0 4.906 22.0 1896 4126.7 7.0 12.361 22.0 1900 4133.7 5.5 2.537 22.0 1903 4139.2 13.0 61.847 22.0 1906 4152.2 2.5 0.081 15.0 1912 4154.7 12.5 22.858 15.0 1913 4167.2 4.0 0.018 15.0 1919 4171.2 2.5 94.329 15.0 1920 4173.7 2.0 0.001 1.0 1922 4175.7 4.0 45.186 15.0 1922 4179.7 4.0 24.865 15.0 1924 4183.7 4.0 0.001 1.0 1926 4187.7 6.0 6.405 15.0 1928 4193.7 2.0 0.001 1.0 1931 4195.7 2.0 13.686 15.0 1932 4197.7 6.5 0.229 15.0 1933 4204.2 4.0 49.420 15.0 1936 4208.2 3.5 63.759 15.0 1938 4211.7 2.0 0.001 1.0 1939 4213.7 12.5 1.337 15.0 1940 4226.2 2.0 1.843 15.0 1946 4228.2 2.0 0.001 1.0 1947 4230.2 2.0 4.320 15.0 1948 4232.2 8.0 0.001 1.0 1949 4240.2 2.0 91.060 15.0 1952 4242.2 4.0 0.001 1.0 1953 4246.2 6.0 4.551 15.0 1955 4252.2 8.0 0.001 1.0 1958 4260.2 6.5 7.953 15.0 1962 4266.7 6.0 0.001 1.0 1965 4272.7 2.0 24.687 15.0 1967 4274.7 2.0 0.001 1.0 1968 4276.7 4.0 2.159 10.0 1969 4280.7 2.0 0.001 1.0 1971 4282.7 6.0 1.534 10.0 1972 4288.7 12.0 0.001 1.0 1975 4300.7 2.5 5.632 10.0 1980 4303.2 20.0 0.001 1.0 1982 Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Nan CS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan CS Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS 7 Attachment K Section 5: Propped Fracture Schedule (Stage 2; 16638 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 350.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 165.5 25 2 3.0 PPA 40 YF125ST 176.8 25 3 4.0 PPA 40 YF125ST 170.2 25 4 5.0 PPA 40 YF125ST 164.1 25 5 6.0 PPA 40 YF125ST 158.4 25 6 7.0 PPA 40 YF125ST 141.6 25 7 8.0 PPA 40 YF125ST 125.9 25 8 Flush 40 YF125ST 253.5 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1878.5 bbl of YF125ST 0 bbl of WF125 230336 lb of % PAD Clean 21.5 % PAD Dirty 18.8 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 350.0 350 350 350 0 0 4230 8.8 8.8 1.0 PPA 172.5 522 180 530 7243 7243 4248 4.5 13.2 2.0 PPA 165.5 688 180 710 13904 21147 4328 4.5 17.8 3.0 PPA 176.8 865 200 910 22275 43422 4620 5.0 22.8 4.0 PPA 170.2 1035 200 1110 28596 72018 4997 5.0 27.8 5.0 PPA 164.1 1199 200 1310 34460 106478 5359 5.0 32.8 6.0 PPA 158.4 1357 200 1510 39918 146396 5716 5.0 37.8 7.0 PPA 141.6 1499 185 1695 41636 188032 6051 4.6 42.4 8.0 PPA 125.9 1625 170 1865 42304 230336 6286 4.2 46.6 Flush 253.5 1878 253 2118 0 230336 5799 6.3 53.0 Job Execution Step Name Pad Percentages Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 390.8 ft with an average conductivity (Kfw) of 14297.6 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 8 Attachment K Section 6: Propped Fracture Simulation (Stage 2; 16638 ft MD) Initial Fracture Top TVD 4049.5 ft Initial Fracture Bottom TVD 4287.5 ft Propped Fracture Half-Length 390.8 ft EOJ Hyd Height at Well 238 ft Average Propped Width 0.165 in Net Pressure 256 psi Max Surface Pressure 6432 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 97.7 7.4 0.184 127.9 1.61 317.8 16420 97.7 195.4 5.9 0.177 200.7 1.53 352.6 15290 195.4 293.1 5 0.17 175.6 1.47 376.8 14806 293.1 390.8 2.3 0.139 126.3 1.26 450 11904 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 9 Attachment K Section 7: Zone Data (Stage 3; 16059 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 4051.7 10.0 0.72 2937 1.46E+06 0.220 2500 Shale 4061.7 15.0 0.70 2828 1.76E+06 0.220 2500 Nanushuk 3 SS 4076.7 15.3 0.68 2769 1.90E+06 0.220 2000 Top Nan 4092.0 6.0 0.64 2630 8.39E+05 0.270 1000 Shale 4098.0 2.0 0.70 2858 2.67E+06 0.230 2500 Nan DS 4100.0 1.5 0.63 2584 8.19E+05 0.270 1500 Nan DS 4101.5 2.0 0.64 2609 1.22E+06 0.260 1500 Nan CS 4103.5 13.0 0.62 2562 8.69E+05 0.270 1000 Nan CS 4116.5 1.5 0.61 2524 1.00E+06 0.270 1000 Nan CS 4118.0 4.0 0.64 2630 7.07E+05 0.280 1000 Nan CS 4122.0 9.0 0.61 2505 1.17E+06 0.270 1000 Nan CS 4131.0 7.0 0.64 2659 7.69E+05 0.270 1000 Nan CS 4138.0 5.5 0.61 2543 1.28E+06 0.260 1000 Nan CS 4143.5 13.0 0.64 2665 6.92E+05 0.280 1000 Nan DS 4156.5 2.5 0.68 2811 1.75E+06 0.260 1500 Nan DS 4159.0 12.5 0.64 2649 1.11E+06 0.270 1500 Nan DS 4171.5 4.0 0.69 2884 1.69E+06 0.260 1500 Nan DS 4175.5 2.5 0.64 2669 8.22E+05 0.270 1500 Shale 4178.0 2.0 0.70 2913 2.67E+06 0.230 2500 Nan DS 4180.0 4.0 0.65 2710 1.16E+06 0.270 1500 Nan DS 4184.0 4.0 0.63 2624 8.38E+05 0.270 1000 Shale 4188.0 4.0 0.70 2921 2.67E+06 0.230 2500 Nan DS 4192.0 6.0 0.64 2682 1.13E+06 0.270 1500 Shale 4198.0 2.0 0.70 2927 2.67E+06 0.230 2500 Nan DS 4200.0 2.0 0.62 2614 1.08E+06 0.270 1500 Nan DS 4202.0 6.5 0.66 2781 1.69E+06 0.260 1500 Nan DS 4208.5 4.0 0.61 2576 8.99E+05 0.270 1500 Nan DS 4212.5 3.5 0.64 2711 9.29E+05 0.270 1500 Shale 4216.0 2.0 0.70 2939 2.67E+06 0.230 2500 Nan DS 4218.0 12.5 0.64 2698 1.56E+06 0.260 1500 Nan DS 4230.5 2.0 0.65 2747 1.40E+06 0.260 1500 Shale 4232.5 2.0 0.70 2951 2.67E+06 0.230 2500 Nan DS 4234.5 2.0 0.65 2757 1.24E+06 0.260 1500 Shale 4236.5 8.0 0.69 2922 2.67E+06 0.230 2500 Nan DS 4244.5 2.0 0.63 2690 9.33E+05 0.270 1500 Shale 4246.5 4.0 0.70 2961 2.67E+06 0.230 2500 Nan DS 4250.5 6.0 0.65 2748 1.43E+06 0.260 1500 Shale 4256.5 8.0 0.70 2969 2.67E+06 0.230 2500 Nan DS 4264.5 6.5 0.65 2766 1.47E+06 0.260 1500 Shale 4271.0 6.0 0.69 2945 2.67E+06 0.230 2500 Nan DS 4277.0 2.0 0.64 2726 8.38E+05 0.270 1000 Shale 4279.0 2.0 0.70 2983 2.67E+06 0.230 2500 Nan DS 4281.0 4.0 0.65 2784 1.47E+06 0.260 1500 Shale 4285.0 2.0 0.70 2987 2.67E+06 0.230 2500 Nan DS 4287.0 6.0 0.66 2849 1.55E+06 0.260 1500 Shale 4293.0 12.0 0.70 2996 2.67E+06 0.230 2500 Nan DS 4305.0 2.5 0.64 2747 1.21E+06 0.270 1500 Shale 4307.5 20.0 0.69 2975 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 10 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4051.7 10.0 0.001 1.0 1881 4061.7 15.0 0.001 1.0 1886 4076.7 15.3 0.005 10.0 1890 4092.0 6.0 56.445 22.0 1882 4098.0 2.0 0.001 1.0 1884 4100.0 1.5 109.347 15.0 1885 4101.5 2.0 4.377 15.0 1886 4103.5 13.0 42.829 22.0 1887 4116.5 1.5 11.097 22.0 1893 4118.0 4.0 91.857 22.0 1894 4122.0 9.0 4.906 22.0 1896 4131.0 7.0 12.361 22.0 1900 4138.0 5.5 2.537 22.0 1903 4143.5 13.0 61.847 22.0 1906 4156.5 2.5 0.081 15.0 1912 4159.0 12.5 22.858 15.0 1913 4171.5 4.0 0.018 15.0 1919 4175.5 2.5 94.329 15.0 1920 4178.0 2.0 0.001 1.0 1922 4180.0 4.0 45.186 15.0 1922 4184.0 4.0 24.865 15.0 1924 4188.0 4.0 0.001 1.0 1926 4192.0 6.0 6.405 15.0 1928 4198.0 2.0 0.001 1.0 1931 4200.0 2.0 13.686 15.0 1932 4202.0 6.5 0.229 15.0 1933 4208.5 4.0 49.420 15.0 1936 4212.5 3.5 63.759 15.0 1938 4216.0 2.0 0.001 1.0 1939 4218.0 12.5 1.337 15.0 1940 4230.5 2.0 1.843 15.0 1946 4232.5 2.0 0.001 1.0 1947 4234.5 2.0 4.320 15.0 1948 4236.5 8.0 0.001 1.0 1949 4244.5 2.0 91.060 15.0 1952 4246.5 4.0 0.001 1.0 1953 4250.5 6.0 4.551 15.0 1955 4256.5 8.0 0.001 1.0 1958 4264.5 6.5 7.953 15.0 1962 4271.0 6.0 0.001 1.0 1965 4277.0 2.0 24.687 15.0 1967 4279.0 2.0 0.001 1.0 1968 4281.0 4.0 2.159 10.0 1969 4285.0 2.0 0.001 1.0 1971 4287.0 6.0 1.534 10.0 1972 4293.0 12.0 0.001 1.0 1975 4305.0 2.5 5.632 10.0 1980 4307.5 20.0 0.001 1.0 1982Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Nan CS Shale Shale Nanushuk 3 SS Top Nan Shale Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Formation Transmissibility Properties Zone Name 11 Attachment K Section 8: Propped Fracture Schedule (Stage 3; 16059 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 242.6 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1536.1 bbl of YF125ST 0 bbl of WF125 231800 lb of % PAD Clean 23.2 % PAD Dirty 19.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 4108 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 4130 4.5 12.0 3.0 PPA 176.8 649 200 680 22275 29518 4297 5.0 17.0 5.0 PPA 188.7 838 230 910 39628 69147 4956 5.8 22.8 7.0 PPA 176.1 1014 230 1140 51763 120909 5671 5.8 28.5 9.0 PPA 154.2 1168 215 1355 58305 179214 6156 5.4 33.9 10.0 PPA 125.2 1293 180 1535 52586 231800 6388 4.5 38.4 Flush 242.6 1536 243 1778 0 231800 5796 6.1 44.4 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 350.7 ft with an average conductivity (Kfw) of 16173.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 12 Attachment K Section 9: Propped Fracture Simulation (Stage 3; 16059 ft MD) Initial Fracture Top TVD 4054.3 ft Initial Fracture Bottom TVD 4280.1 ft Propped Fracture Half-Length 350.7 ft EOJ Hyd Height at Well 225.8 ft Average Propped Width 0.186 in Net Pressure 243 psi Max Surface Pressure 6433 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 87.7 9.7 0.209 132 1.79 259.3 18717 87.7 175.3 8.1 0.207 198.2 1.83 276.3 18226 175.3 263 6.6 0.185 169.5 1.6 309.3 16209 263 350.7 3 0.152 131.7 1.36 359.6 12891 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 13 Attachment K Section 10: Zone Data (Stage 4; 15474 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 4058.3 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4068.3 15.0 0.70 2833 1.76E+06 0.220 1000 Nanushuk 3 SS 4083.3 15.3 0.68 2774 1.90E+06 0.220 1000 Top Nan CS 4098.6 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4118.1 2.0 0.69 2846 2.67E+06 0.230 2500 Nan CS 4120.1 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4121.6 4.5 0.62 2540 6.44E+05 0.280 1000 Nan DS 4126.1 3.5 0.69 2852 1.77E+06 0.260 1500 Nan DS 4129.6 14.5 0.66 2722 1.39E+06 0.260 1500 Nan CS 4144.1 1.5 0.65 2702 1.15E+06 0.270 1000 Nan CS 4145.6 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4158.1 2.0 0.65 2699 1.40E+06 0.260 1500 Nan CS 4160.1 9.0 0.61 2528 8.54E+05 0.270 1000 Nan DS 4169.1 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4176.1 9.0 0.65 2701 1.13E+06 0.270 1500 Nan DS 4185.1 3.5 0.64 2688 1.69E+06 0.260 1500 Nan DS 4188.6 5.0 0.64 2661 7.57E+05 0.270 1000 Nan DS 4193.6 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4195.6 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4206.1 3.5 0.64 2701 1.10E+06 0.270 1000 Nan CS 4209.6 2.0 0.62 2611 6.70E+05 0.280 1000 Nan CS 4211.6 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4217.1 3.5 0.70 2939 1.53E+06 0.260 1500 Nan DS 4220.6 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4224.1 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4229.6 10.5 0.64 2689 1.17E+06 0.270 1000 Nan DS 4240.1 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4241.6 5.0 0.62 2640 1.14E+06 0.270 1500 Nan DS 4246.6 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4248.6 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4252.6 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4254.6 10.0 0.63 2671 9.81E+05 0.270 1500 Nan DS 4264.6 4.0 0.65 2790 1.63E+06 0.260 1500 Nan DS 4268.6 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4272.6 9.5 0.65 2780 1.33E+06 0.260 1500 Nan DS 4282.1 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4284.1 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4293.6 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4295.6 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4297.6 2.0 0.64 2734 1.09E+06 0.270 1500 Shale 4299.6 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4301.6 4.0 0.66 2840 1.29E+06 0.260 1500 Shale 4305.6 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4325.1 2.0 0.65 2816 1.36E+06 0.260 1500 Shale 4327.1 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4329.1 8.0 0.66 2851 1.37E+06 0.260 1500 Nan DS 4337.1 8.0 0.65 2809 1.56E+06 0.260 1500 Shale 4345.1 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 14 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4058.3 10.0 0.001 1.0 1890 4068.3 15.0 0.001 1.0 1898 4083.3 15.3 0.005 10.0 1905 4098.6 19.5 30.655 23.7 1915 4118.1 2.0 5.000 10.0 1924 4120.1 1.5 2.095 16.9 1925 4121.6 4.5 48.388 26.6 1926 4126.1 3.5 0.478 12.4 1928 4129.6 14.5 15.008 17.7 1930 4144.1 1.5 3.661 17.6 1937 4145.6 12.5 34.723 23.9 1937 4158.1 2.0 1.697 15.6 1943 4160.1 9.0 54.319 24.4 1944 4169.1 7.0 3.610 14.8 1948 4176.1 9.0 22.986 20.4 1952 4185.1 3.5 0.835 14.0 1956 4188.6 5.0 65.392 23.4 1957 4193.6 2.0 0.006 10.5 1960 4195.6 10.5 100.832 25.6 1961 4206.1 3.5 17.434 20.5 1966 4209.6 2.0 161.343 26.3 1967 4211.6 5.5 4.627 18.4 1968 4217.1 3.5 5.075 14.8 1971 4220.6 3.5 8.651 19.4 1972 4224.1 5.5 10.205 16.0 1974 4229.6 10.5 17.356 20.1 1977 4240.1 1.5 3.106 14.8 1982 4241.6 5.0 52.863 20.6 1982 4246.6 2.0 2.277 14.1 1985 4248.6 4.0 122.778 23.1 1986 4252.6 2.0 0.333 12.5 1987 4254.6 10.0 39.939 21.2 1988 4264.6 4.0 0.748 13.3 1993 4268.6 4.0 0.009 10.9 1995 4272.6 9.5 5.399 16.7 1997 4282.1 2.0 160.618 24.9 2001 4284.1 9.5 0.033 11.5 2002 4293.6 2.0 6.733 16.2 2007 4295.6 2.0 0.001 1.0 2008 4297.6 2.0 29.480 19.6 2009 4299.6 2.0 0.001 1.0 2009 4301.6 4.0 8.473 16.6 2010 4305.6 19.5 0.001 1.0 2012 4325.1 2.0 2.185 16.4 2021 4327.1 2.0 0.001 1.0 2022 4329.1 8.0 2.645 15.9 2023 4337.1 8.0 2.026 14.4 2027 4345.1 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 15 Attachment K Section 11: Propped Fracture Schedule (Stage 4; 15474 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 325.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 Flush 40 YF125ST 233.7 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1644.7 bbl of YF125ST 0 bbl of WF125 224608 lb of % PAD Clean 23.0 % PAD Dirty 19.8 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 325.0 325 325 325 0 0 4034 8.1 8.1 1.0 PPA 172.5 497 180 505 7243 7243 4034 4.5 12.6 2.0 PPA 202.3 700 220 725 16993 24236 4127 5.5 18.1 4.0 PPA 204.2 904 240 965 34313 58549 4560 6.0 24.1 6.0 PPA 190.1 1094 240 1205 47902 106451 5243 6.0 30.1 8.0 PPA 177.8 1272 240 1445 59728 166179 5812 6.0 36.1 10.0 PPA 139.1 1411 200 1645 58429 224608 6105 5.0 41.1 Flush 233.7 1645 234 1879 0 224608 5555 5.8 47.0 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 334.5 ft with an average conductivity (Kfw) of 14985.9 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 16 Attachment K Section 12: Propped Fracture Simulation (Stage 4; 15474 ft MD) Initial Fracture Top TVD 4064.9 ft Initial Fracture Bottom TVD 4300.8 ft Propped Fracture Half-Length 334.5 ft EOJ Hyd Height at Well 235.9 ft Average Propped Width 0.175 in Net Pressure 247 psi Max Surface Pressure 6167 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 83.6 9.5 0.204 138.1 1.76 293.5 18071 83.6 167.2 8.1 0.199 210.4 1.77 307.5 17365 167.2 250.9 6.8 0.177 196.1 1.57 323.2 15219 250.9 334.5 3.4 0.126 156.5 1.17 458.5 10289 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 17 Attachment K Section 13: Zone Data (Stage 5; 14889 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 4061.9 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4071.9 15.0 0.70 2835 1.76E+06 0.220 1000 Nanushuk 3 SS 4086.9 15.3 0.68 2776 1.90E+06 0.220 1000 Top Nan CS 4102.2 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4121.7 2.0 0.69 2849 2.67E+06 0.230 2500 Nan CS 4123.7 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4125.2 4.5 0.62 2543 6.44E+05 0.280 1000 Nan DS 4129.7 3.5 0.69 2855 1.77E+06 0.260 1500 Nan DS 4133.2 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4147.7 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4149.2 12.5 0.64 2641 8.82E+05 0.270 1000 Nan DS 4161.7 2.0 0.65 2702 1.40E+06 0.260 1500 Nan CS 4163.7 9.0 0.61 2530 8.54E+05 0.270 1000 Nan DS 4172.7 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4179.7 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4188.7 3.5 0.64 2690 1.69E+06 0.260 1500 Nan DS 4192.2 5.0 0.64 2665 7.57E+05 0.270 1000 Nan DS 4197.2 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4199.2 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4209.7 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4213.2 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4215.2 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4220.7 3.5 0.70 2935 1.53E+06 0.260 1500 Nan DS 4224.2 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4227.7 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4233.2 10.5 0.64 2693 1.17E+06 0.270 1000 Nan DS 4243.7 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4245.2 5.0 0.62 2642 1.14E+06 0.270 1500 Nan DS 4250.2 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4252.2 4.0 0.63 2684 8.96E+05 0.270 1500 Nan DS 4256.2 2.0 0.68 2876 1.66E+06 0.260 1500 Nan DS 4258.2 10.0 0.63 2673 9.81E+05 0.270 1500 Nan DS 4268.2 4.0 0.65 2793 1.63E+06 0.260 1500 Nan DS 4272.2 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4276.2 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4285.7 2.0 0.62 2645 7.82E+05 0.270 1000 Nan DS 4287.7 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4297.2 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4299.2 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4301.2 2.0 0.64 2736 1.09E+06 0.270 1500 Shale 4303.2 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4305.2 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4309.2 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4328.7 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4330.7 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4332.7 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4340.7 8.0 0.65 2811 1.56E+06 0.260 1500 Shale 4348.7 20.0 0.70 3038 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 18 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4061.9 10.0 0.001 1.0 1890 4071.9 15.0 0.001 1.0 1898 4086.9 15.3 0.005 10.0 1905 4102.2 19.5 30.655 23.7 1915 4121.7 2.0 5.000 10.0 1924 4123.7 1.5 2.095 16.9 1925 4125.2 4.5 48.388 26.6 1926 4129.7 3.5 0.478 12.4 1928 4133.2 14.5 15.008 17.7 1930 4147.7 1.5 3.661 17.6 1937 4149.2 12.5 34.723 23.9 1937 4161.7 2.0 1.697 15.6 1943 4163.7 9.0 54.319 24.4 1944 4172.7 7.0 3.610 14.8 1948 4179.7 9.0 22.986 20.4 1952 4188.7 3.5 0.835 14.0 1956 4192.2 5.0 65.392 23.4 1957 4197.2 2.0 0.006 10.5 1960 4199.2 10.5 100.832 25.6 1961 4209.7 3.5 17.434 20.5 1966 4213.2 2.0 161.343 26.3 1967 4215.2 5.5 4.627 18.4 1968 4220.7 3.5 5.075 14.8 1971 4224.2 3.5 8.651 19.4 1972 4227.7 5.5 10.205 16.0 1974 4233.2 10.5 17.356 20.1 1977 4243.7 1.5 3.106 14.8 1982 4245.2 5.0 52.863 20.6 1982 4250.2 2.0 2.277 14.1 1985 4252.2 4.0 122.778 23.1 1986 4256.2 2.0 0.333 12.5 1987 4258.2 10.0 39.939 21.2 1988 4268.2 4.0 0.748 13.3 1993 4272.2 4.0 0.009 10.9 1995 4276.2 9.5 5.399 16.7 1997 4285.7 2.0 160.618 24.9 2001 4287.7 9.5 0.033 11.5 2002 4297.2 2.0 6.733 16.2 2007 4299.2 2.0 0.001 1.0 2008 4301.2 2.0 29.480 19.6 2009 4303.2 2.0 0.001 1.0 2009 4305.2 4.0 8.473 16.6 2010 4309.2 19.5 0.001 1.0 2012 4328.7 2.0 2.185 16.4 2021 4330.7 2.0 0.001 1.0 2022 4332.7 8.0 2.645 15.9 2023 4340.7 8.0 2.026 14.4 2027 4348.7 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 19 Attachment K Section 14: Propped Fracture Schedule (Stage 5; 14889 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 325.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 183.9 25 2 4.0 PPA 40 YF125ST 187.2 25 4 6.0 PPA 40 YF125ST 174.2 25 6 8.0 PPA 40 YF125ST 162.9 25 8 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 226.8 25 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1557.8 bbl of YF125ST 0 bbl of WF125 205392 lb of % PAD Clean 24.4 % PAD Dirty 21.0 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 325.0 325 325 325 0 0 3925 8.1 8.1 1.0 PPA 172.5 497 180 505 7243 7243 3927 4.5 12.6 2.0 PPA 183.9 681 200 705 15448 22691 4008 5.0 17.6 4.0 PPA 187.2 869 220 925 31454 54145 4390 5.5 23.1 6.0 PPA 174.2 1043 220 1145 43910 98055 4994 5.5 28.6 8.0 PPA 162.9 1206 220 1365 54751 152805 5560 5.5 34.1 10.0 PPA 125.2 1331 180 1545 52586 205392 5871 4.5 38.6 Flush 226.8 1558 227 1772 0 205392 5367 5.7 44.3 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 339.6 ft with an average conductivity (Kfw) of 13488 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 20 Attachment K Section 15: Propped Fracture Simulation (Stage 5; 14889 ft MD) Initial Fracture Top TVD 4068.4 ft Initial Fracture Bottom TVD 4304.3 ft Propped Fracture Half-Length 339.6 ft EOJ Hyd Height at Well 235.9 ft Average Propped Width 0.16 in Net Pressure 242 psi Max Surface Pressure 5939 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 84.9 9.3 0.185 192.1 1.6 300.7 16436 84.9 169.8 7.8 0.181 206.3 1.6 315 15701 169.8 254.7 6.5 0.165 184.3 1.47 324.2 14031 254.7 339.6 2.9 0.11 166.1 1.03 527.2 8780 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 21 Attachment K Section 16: Zone Data (Stage 6; 14308 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 4066.4 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4076.4 15.0 0.70 2838 1.76E+06 0.220 1000 Nanushuk 3 SS 4091.4 15.3 0.68 2779 1.90E+06 0.220 1000 Top Nan CS 4106.7 19.5 0.63 2593 9.00E+05 0.270 1000 Nan SS 4126.2 2.0 0.69 2852 2.67E+06 0.230 2500 Nan CS 4128.2 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4129.7 4.5 0.62 2545 6.44E+05 0.280 1000 Nan DS 4134.2 3.5 0.69 2858 1.77E+06 0.260 1500 Nan DS 4137.7 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4152.2 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4153.7 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4166.2 2.0 0.65 2705 1.40E+06 0.260 1500 Nan CS 4168.2 9.0 0.61 2533 8.54E+05 0.270 1000 Nan DS 4177.2 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4184.2 9.0 0.65 2705 1.13E+06 0.270 1500 Nan DS 4193.2 3.5 0.64 2693 1.69E+06 0.260 1500 Nan DS 4196.7 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4201.7 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4203.7 10.5 0.62 2605 7.36E+05 0.270 1000 Nan CS 4214.2 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4217.7 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4219.7 5.5 0.66 2768 1.30E+06 0.260 1000 Nan DS 4225.2 3.5 0.70 2938 1.53E+06 0.260 1500 Nan DS 4228.7 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4232.2 5.5 0.69 2926 1.42E+06 0.260 1500 Nan CS 4237.7 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4248.2 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4249.7 5.0 0.62 2645 1.14E+06 0.270 1500 Nan DS 4254.7 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4256.7 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4260.7 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4262.7 10.0 0.63 2676 9.81E+05 0.270 1500 Nan DS 4272.7 4.0 0.65 2796 1.63E+06 0.260 1500 Nan DS 4276.7 4.0 0.70 2974 1.75E+06 0.260 1500 Nan DS 4280.7 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4290.2 2.0 0.62 2648 7.82E+05 0.270 1000 Nan DS 4292.2 9.5 0.69 2973 1.69E+06 0.260 1500 Nan DS 4301.7 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4303.7 2.0 0.70 3000 2.67E+06 0.230 2500 Nan DS 4305.7 2.0 0.64 2739 1.09E+06 0.270 1500 Shale 4307.7 2.0 0.70 3003 2.67E+06 0.230 2500 Nan DS 4309.7 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4313.7 19.5 0.70 3013 2.67E+06 0.230 2500 Nan DS 4333.2 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4335.2 2.0 0.70 3022 2.67E+06 0.230 2500 Nan DS 4337.2 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4345.2 8.0 0.65 2814 1.56E+06 0.260 1500 Shale 4353.2 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 22 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4066.4 10.0 0.001 1.0 1890 4076.4 15.0 0.001 1.0 1898 4091.4 15.3 0.005 10.0 1905 4106.7 19.5 30.655 23.7 1915 4126.2 2.0 5.000 10.0 1924 4128.2 1.5 2.095 16.9 1925 4129.7 4.5 48.388 26.6 1926 4134.2 3.5 0.478 12.4 1928 4137.7 14.5 15.008 17.7 1930 4152.2 1.5 3.661 17.6 1937 4153.7 12.5 34.723 23.9 1937 4166.2 2.0 1.697 15.6 1943 4168.2 9.0 54.319 24.4 1944 4177.2 7.0 3.610 14.8 1948 4184.2 9.0 22.986 20.4 1952 4193.2 3.5 0.835 14.0 1956 4196.7 5.0 65.392 23.4 1957 4201.7 2.0 0.006 10.5 1960 4203.7 10.5 100.832 25.6 1961 4214.2 3.5 17.434 20.5 1966 4217.7 2.0 161.343 26.3 1967 4219.7 5.5 4.627 18.4 1968 4225.2 3.5 5.075 14.8 1971 4228.7 3.5 8.651 19.4 1972 4232.2 5.5 10.205 16.0 1974 4237.7 10.5 17.356 20.1 1977 4248.2 1.5 3.106 14.8 1982 4249.7 5.0 52.863 20.6 1982 4254.7 2.0 2.277 14.1 1985 4256.7 4.0 122.778 23.1 1986 4260.7 2.0 0.333 12.5 1987 4262.7 10.0 39.939 21.2 1988 4272.7 4.0 0.748 13.3 1993 4276.7 4.0 0.009 10.9 1995 4280.7 9.5 5.399 16.7 1997 4290.2 2.0 160.618 24.9 2001 4292.2 9.5 0.033 11.5 2002 4301.7 2.0 6.733 16.2 2007 4303.7 2.0 0.001 1.0 2008 4305.7 2.0 29.480 19.6 2009 4307.7 2.0 0.001 1.0 2009 4309.7 4.0 8.473 16.6 2010 4313.7 19.5 0.001 1.0 2012 4333.2 2.0 2.185 16.4 2021 4335.2 2.0 0.001 1.0 2022 4337.2 8.0 2.645 15.9 2023 4345.2 8.0 2.026 14.4 2027 4353.2 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 23 Attachment K Section 17: Propped Fracture Schedule (Stage 6; 14308 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 325.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 2.0 PPA 40 YF125ST 202.3 25 2 4.0 PPA 40 YF125ST 204.2 25 4 6.0 PPA 40 YF125ST 190.1 25 6 8.0 PPA 40 YF125ST 177.8 25 8 10.0 PPA 40 YF125ST 139.1 25 10 Flush 40 YF125ST 216.0 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1626.9 bbl of YF125ST 0 bbl of WF125 224609 lb of % PAD Clean 23.0 % PAD Dirty 19.8 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 325.0 325 325 325 0 0 3816 8.1 8.1 1.0 PPA 172.5 497 180 505 7243 7243 3816 4.5 12.6 2.0 PPA 202.3 700 220 725 16992 24235 3908 5.5 18.1 4.0 PPA 204.2 904 240 965 34312 58547 4303 6.0 24.1 6.0 PPA 190.1 1094 240 1205 47904 106451 4881 6.0 30.1 8.0 PPA 177.8 1272 240 1445 59728 166179 5399 6.0 36.1 10.0 PPA 139.1 1411 200 1645 58430 224609 5672 5.0 41.1 Flush 216.0 1627 216 1861 0 224609 5147 5.4 46.5 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 337 ft with an average conductivity (Kfw) of 14841.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 24 Attachment K Section 18: Propped Fracture Simulation (Stage 6; 14308 ft MD) Initial Fracture Top TVD 4073 ft Initial Fracture Bottom TVD 4309 ft Propped Fracture Half-Length 337 ft EOJ Hyd Height at Well 236 ft Average Propped Width 0.173 in Net Pressure 250 psi Max Surface Pressure 5740 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 84.3 9.5 0.202 189.1 1.75 295.8 17875 84.3 168.5 8 0.201 210.3 1.78 307.8 17468 168.5 252.8 6.8 0.178 186.3 1.58 323.2 15328 252.8 337 3.3 0.119 165.7 1.12 498.2 9675 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 25 Attachment K Section 19: Zone Data (Stage 7; 13727 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 4072.6 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4082.6 15.0 0.70 2843 1.76E+06 0.220 1000 Nanushuk 3 SS 4097.6 15.3 0.68 2783 1.90E+06 0.220 1000 Top Nan CS 4112.9 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4132.4 2.0 0.69 2856 2.67E+06 0.230 2500 Nan CS 4134.4 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4135.9 4.5 0.62 2549 6.44E+05 0.280 1000 Nan DS 4140.4 3.5 0.69 2862 1.77E+06 0.260 1500 Nan DS 4143.9 14.5 0.66 2727 1.39E+06 0.260 1500 Nan CS 4158.4 1.5 0.65 2708 1.15E+06 0.270 1000 Nan CS 4159.9 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4172.4 2.0 0.65 2709 1.40E+06 0.260 1500 Nan CS 4174.4 9.0 0.61 2537 8.54E+05 0.270 1000 Nan DS 4183.4 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4190.4 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4199.4 3.5 0.64 2697 1.69E+06 0.260 1500 Nan DS 4202.9 5.0 0.63 2666 7.57E+05 0.270 1000 Nan DS 4207.9 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4209.9 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4220.4 3.5 0.64 2706 1.10E+06 0.270 1000 Nan CS 4223.9 2.0 0.62 2615 6.70E+05 0.280 1000 Nan CS 4225.9 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4231.4 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4234.9 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4238.4 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4243.9 10.5 0.63 2694 1.17E+06 0.270 1000 Nan DS 4254.4 1.5 0.66 2813 1.38E+06 0.260 1500 Nan DS 4255.9 5.0 0.62 2649 1.14E+06 0.270 1500 Nan DS 4260.9 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4262.9 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4266.9 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4268.9 10.0 0.63 2680 9.81E+05 0.270 1500 Nan DS 4278.9 4.0 0.65 2800 1.63E+06 0.260 1500 Nan DS 4282.9 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4286.9 9.5 0.65 2785 1.33E+06 0.260 1500 Nan DS 4296.4 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4298.4 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4307.9 2.0 0.65 2814 1.37E+06 0.260 1500 Shale 4309.9 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4311.9 2.0 0.64 2743 1.09E+06 0.270 1500 Shale 4313.9 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4315.9 4.0 0.66 2845 1.29E+06 0.260 1500 Shale 4319.9 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4339.4 2.0 0.65 2821 1.36E+06 0.260 1500 Shale 4341.4 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4343.4 8.0 0.66 2856 1.37E+06 0.260 1500 Nan DS 4351.4 8.0 0.65 2818 1.56E+06 0.260 1500 Shale 4359.4 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 26 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4072.6 10.0 0.001 1.0 1890 4082.6 15.0 0.001 1.0 1898 4097.6 15.3 0.005 10.0 1905 4112.9 19.5 30.655 23.7 1915 4132.4 2.0 5.000 10.0 1924 4134.4 1.5 2.095 16.9 1925 4135.9 4.5 48.388 26.6 1926 4140.4 3.5 0.478 12.4 1928 4143.9 14.5 15.008 17.7 1930 4158.4 1.5 3.661 17.6 1937 4159.9 12.5 34.723 23.9 1937 4172.4 2.0 1.697 15.6 1943 4174.4 9.0 54.319 24.4 1944 4183.4 7.0 3.610 14.8 1948 4190.4 9.0 22.986 20.4 1952 4199.4 3.5 0.835 14.0 1956 4202.9 5.0 65.392 23.4 1957 4207.9 2.0 0.006 10.5 1960 4209.9 10.5 100.832 25.6 1961 4220.4 3.5 17.434 20.5 1966 4223.9 2.0 161.343 26.3 1967 4225.9 5.5 4.627 18.4 1968 4231.4 3.5 5.075 14.8 1971 4234.9 3.5 8.651 19.4 1972 4238.4 5.5 10.205 16.0 1974 4243.9 10.5 17.356 20.1 1977 4254.4 1.5 3.106 14.8 1982 4255.9 5.0 52.863 20.6 1982 4260.9 2.0 2.277 14.1 1985 4262.9 4.0 122.778 23.1 1986 4266.9 2.0 0.333 12.5 1987 4268.9 10.0 39.939 21.2 1988 4278.9 4.0 0.748 13.3 1993 4282.9 4.0 0.009 10.9 1995 4286.9 9.5 5.399 16.7 1997 4296.4 2.0 160.618 24.9 2001 4298.4 9.5 0.033 11.5 2002 4307.9 2.0 6.733 16.2 2007 4309.9 2.0 0.001 1.0 2008 4311.9 2.0 29.480 19.6 2009 4313.9 2.0 0.001 1.0 2009 4315.9 4.0 8.473 16.6 2010 4319.9 19.5 0.001 1.0 2012 4339.4 2.0 2.185 16.4 2021 4341.4 2.0 0.001 1.0 2022 4343.4 8.0 2.645 15.9 2023 4351.4 8.0 2.026 14.4 2027 4359.4 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 27 Attachment K Section 20: Propped Fracture Schedule (Stage 7; 13727 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 207.1 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1500.6 bbl of YF125ST 0 bbl of WF125 231805 lb of % PAD Clean 23.2 % PAD Dirty 19.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3702 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 3706 4.5 12.0 3.0 PPA 176.8 649 200 680 22275 29518 3845 5.0 17.0 5.0 PPA 188.7 838 230 910 39630 69148 4400 5.8 22.8 7.0 PPA 176.1 1014 230 1140 51765 120913 4959 5.8 28.5 9.0 PPA 154.2 1168 215 1355 58302 179215 5329 5.4 33.9 10.0 PPA 125.2 1293 180 1535 52590 231805 5497 4.5 38.4 Flush 207.1 1501 207 1742 0 231805 4957 5.2 43.6 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 327.6 ft with an average conductivity (Kfw) of 16061.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 28 Attachment K Section 21: Propped Fracture Simulation (Stage 7; 13727 ft MD) Initial Fracture Top TVD 4079.9 ft Initial Fracture Bottom TVD 4315.5 ft Propped Fracture Half-Length 327.6 ft EOJ Hyd Height at Well 235.6 ft Average Propped Width 0.186 in Net Pressure 249 psi Max Surface Pressure 5523 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 81.9 9.9 0.206 138.3 1.78 285.5 18274 81.9 163.8 9 0.21 204.5 1.86 282.4 18253 163.8 245.7 8.1 0.198 194.7 1.76 280.4 17088 245.7 327.6 4 0.137 143.4 1.28 495 11344 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 29 Attachment K Section 22: Zone Data (Stage 8; 13228 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 4072.8 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4082.8 15.0 0.70 2843 1.76E+06 0.220 1000 Nanushuk 3 SS 4097.8 15.3 0.68 2783 1.90E+06 0.220 1000 Top Nan CS 4113.1 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4132.6 2.0 0.69 2856 2.67E+06 0.230 2500 Nan CS 4134.6 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4136.1 4.5 0.62 2549 6.44E+05 0.280 1000 Nan DS 4140.6 3.5 0.69 2862 1.77E+06 0.260 1500 Nan DS 4144.1 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4158.6 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4160.1 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4172.6 2.0 0.65 2709 1.40E+06 0.260 1500 Nan CS 4174.6 9.0 0.61 2537 8.54E+05 0.270 1000 Nan DS 4183.6 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4190.6 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4199.6 3.5 0.64 2697 1.69E+06 0.260 1500 Nan DS 4203.1 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4208.1 2.0 0.70 2925 1.80E+06 0.250 1500 Nan CS 4210.1 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4220.6 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4224.1 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4226.1 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4231.6 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4235.1 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4238.6 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4244.1 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4254.6 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4256.1 5.0 0.62 2649 1.14E+06 0.270 1500 Nan DS 4261.1 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4263.1 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4267.1 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4269.1 10.0 0.63 2680 9.81E+05 0.270 1500 Nan DS 4279.1 4.0 0.65 2800 1.63E+06 0.260 1500 Nan DS 4283.1 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4287.1 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4296.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4298.6 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4308.1 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4310.1 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4312.1 2.0 0.64 2743 1.09E+06 0.270 1500 Shale 4314.1 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4316.1 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4320.1 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4339.6 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4341.6 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4343.6 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4351.6 8.0 0.65 2818 1.56E+06 0.260 1500 Shale 4359.6 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 30 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4072.8 10.0 0.001 1.0 1890 4082.8 15.0 0.001 1.0 1898 4097.8 15.3 0.005 10.0 1905 4113.1 19.5 30.655 23.7 1915 4132.6 2.0 5.000 10.0 1924 4134.6 1.5 2.095 16.9 1925 4136.1 4.5 48.388 26.6 1926 4140.6 3.5 0.478 12.4 1928 4144.1 14.5 15.008 17.7 1930 4158.6 1.5 3.661 17.6 1937 4160.1 12.5 34.723 23.9 1937 4172.6 2.0 1.697 15.6 1943 4174.6 9.0 54.319 24.4 1944 4183.6 7.0 3.610 14.8 1948 4190.6 9.0 22.986 20.4 1952 4199.6 3.5 0.835 14.0 1956 4203.1 5.0 65.392 23.4 1957 4208.1 2.0 0.006 10.5 1960 4210.1 10.5 100.832 25.6 1961 4220.6 3.5 17.434 20.5 1966 4224.1 2.0 161.343 26.3 1967 4226.1 5.5 4.627 18.4 1968 4231.6 3.5 5.075 14.8 1971 4235.1 3.5 8.651 19.4 1972 4238.6 5.5 10.205 16.0 1974 4244.1 10.5 17.356 20.1 1977 4254.6 1.5 3.106 14.8 1982 4256.1 5.0 52.863 20.6 1982 4261.1 2.0 2.277 14.1 1985 4263.1 4.0 122.778 23.1 1986 4267.1 2.0 0.333 12.5 1987 4269.1 10.0 39.939 21.2 1988 4279.1 4.0 0.748 13.3 1993 4283.1 4.0 0.009 10.9 1995 4287.1 9.5 5.399 16.7 1997 4296.6 2.0 160.618 24.9 2001 4298.6 9.5 0.033 11.5 2002 4308.1 2.0 6.733 16.2 2007 4310.1 2.0 0.001 1.0 2008 4312.1 2.0 29.480 19.6 2009 4314.1 2.0 0.001 1.0 2009 4316.1 4.0 8.473 16.6 2010 4320.1 19.5 0.001 1.0 2012 4339.6 2.0 2.185 16.4 2021 4341.6 2.0 0.001 1.0 2022 4343.6 8.0 2.645 15.9 2023 4351.6 8.0 2.026 14.4 2027 4359.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 31 Attachment K Section 23: Propped Fracture Schedule (Stage 8; 13228 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 199.5 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1493 bbl of YF125ST 0 bbl of WF125 231805 lb of % PAD Clean 23.2 % PAD Dirty 19.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3608 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 3615 4.5 12.0 3.0 PPA 176.8 649 200 680 22275 29518 3737 5.0 17.0 5.0 PPA 188.7 838 230 910 39630 69148 4261 5.8 22.8 7.0 PPA 176.1 1014 230 1140 51765 120913 4794 5.8 28.5 9.0 PPA 154.2 1168 215 1355 58302 179215 5148 5.4 33.9 10.0 PPA 125.2 1293 180 1535 52590 231805 5306 4.5 38.4 Flush 199.5 1493 200 1735 0 231805 4810 5.0 43.4 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 325.2 ft with an average conductivity (Kfw) of 16183.5 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 32 Attachment K Section 24: Propped Fracture Simulation (Stage 8; 13228 ft MD) Initial Fracture Top TVD 4079.6 ft Initial Fracture Bottom TVD 4314.8 ft Propped Fracture Half-Length 325.2 ft EOJ Hyd Height at Well 235.1 ft Average Propped Width 0.187 in Net Pressure 249 psi Max Surface Pressure 5331 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 81.3 9.9 0.205 137.6 1.77 286.2 18156 81.3 162.6 9 0.207 204.9 1.83 283.9 18224 162.6 243.9 8.2 0.196 195 1.75 281.7 17026 243.9 325.2 4.3 0.147 148.9 1.36 396.9 12185 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 33 Attachment K Section 25: Zone Data (Stage 9; 12652 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 4074.8 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4084.8 15.0 0.70 2844 1.76E+06 0.220 1000 Nanushuk 3 SS 4099.8 15.3 0.68 2785 1.90E+06 0.220 1000 Top Nan CS 4115.1 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4134.6 2.0 0.69 2858 2.67E+06 0.230 2500 Nan CS 4136.6 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4138.1 4.5 0.62 2550 6.44E+05 0.280 1000 Nan DS 4142.6 3.5 0.69 2864 1.77E+06 0.260 1500 Nan DS 4146.1 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4160.6 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4162.1 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4174.6 2.0 0.65 2710 1.40E+06 0.260 1500 Nan CS 4176.6 9.0 0.61 2538 8.54E+05 0.270 1000 Nan DS 4185.6 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4192.6 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4201.6 3.5 0.64 2699 1.69E+06 0.260 1500 Nan DS 4205.1 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4210.1 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4212.1 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4222.6 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4226.1 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4228.1 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4233.6 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4237.1 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4240.6 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4246.1 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4256.6 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4258.1 5.0 0.62 2650 1.14E+06 0.270 1500 Nan DS 4263.1 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4265.1 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4269.1 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4271.1 10.0 0.63 2681 9.81E+05 0.270 1500 Nan DS 4281.1 4.0 0.65 2801 1.63E+06 0.260 1500 Nan DS 4285.1 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4289.1 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4298.6 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4300.6 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4310.1 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4312.1 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4314.1 2.0 0.64 2744 1.09E+06 0.270 1500 Shale 4316.1 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4318.1 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4322.1 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4341.6 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4343.6 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4345.6 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4353.6 8.0 0.65 2819 1.56E+06 0.260 1500 Shale 4361.6 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 34 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4074.8 10.0 0.001 1.0 1890 4084.8 15.0 0.001 1.0 1898 4099.8 15.3 0.005 10.0 1905 4115.1 19.5 30.655 23.7 1915 4134.6 2.0 5.000 10.0 1924 4136.6 1.5 2.095 16.9 1925 4138.1 4.5 48.388 26.6 1926 4142.6 3.5 0.478 12.4 1928 4146.1 14.5 15.008 17.7 1930 4160.6 1.5 3.661 17.6 1937 4162.1 12.5 34.723 23.9 1937 4174.6 2.0 1.697 15.6 1943 4176.6 9.0 54.319 24.4 1944 4185.6 7.0 3.610 14.8 1948 4192.6 9.0 22.986 20.4 1952 4201.6 3.5 0.835 14.0 1956 4205.1 5.0 65.392 23.4 1957 4210.1 2.0 0.006 10.5 1960 4212.1 10.5 100.832 25.6 1961 4222.6 3.5 17.434 20.5 1966 4226.1 2.0 161.343 26.3 1967 4228.1 5.5 4.627 18.4 1968 4233.6 3.5 5.075 14.8 1971 4237.1 3.5 8.651 19.4 1972 4240.6 5.5 10.205 16.0 1974 4246.1 10.5 17.356 20.1 1977 4256.6 1.5 3.106 14.8 1982 4258.1 5.0 52.863 20.6 1982 4263.1 2.0 2.277 14.1 1985 4265.1 4.0 122.778 23.1 1986 4269.1 2.0 0.333 12.5 1987 4271.1 10.0 39.939 21.2 1988 4281.1 4.0 0.748 13.3 1993 4285.1 4.0 0.009 10.9 1995 4289.1 9.5 5.399 16.7 1997 4298.6 2.0 160.618 24.9 2001 4300.6 9.5 0.033 11.5 2002 4310.1 2.0 6.733 16.2 2007 4312.1 2.0 0.001 1.0 2008 4314.1 2.0 29.480 19.6 2009 4316.1 2.0 0.001 1.0 2009 4318.1 4.0 8.473 16.6 2010 4322.1 19.5 0.001 1.0 2012 4341.6 2.0 2.185 16.4 2021 4343.6 2.0 0.001 1.0 2022 4345.6 8.0 2.645 15.9 2023 4353.6 8.0 2.026 14.4 2027 4361.6 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 35 Attachment K Section 26: Propped Fracture Schedule (Stage 9; 12652 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 190.7 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1484.2 bbl of YF125ST 0 bbl of WF125 231805 lb of % PAD Clean 23.2 % PAD Dirty 19.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3505 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 3507 4.5 12.0 3.0 PPA 176.8 649 200 680 22275 29518 3650 5.0 17.0 5.0 PPA 188.7 838 230 910 39630 69148 4194 5.8 22.8 7.0 PPA 176.1 1014 230 1140 51765 120913 4669 5.8 28.5 9.0 PPA 154.2 1168 215 1355 58302 179215 4956 5.4 33.9 10.0 PPA 125.2 1293 180 1535 52590 231805 5085 4.5 38.4 Flush 190.7 1484 191 1726 0 231805 4636 4.8 43.1 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 321.2 ft with an average conductivity (Kfw) of 16460.9 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 36 Attachment K Section 27: Propped Fracture Simulation (Stage 9; 12652 ft MD) Initial Fracture Top TVD 4081.8 ft Initial Fracture Bottom TVD 4317.1 ft Propped Fracture Half-Length 321.2 ft EOJ Hyd Height at Well 235.3 ft Average Propped Width 0.19 in Net Pressure 251 psi Max Surface Pressure 5109 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 80.3 9.9 0.208 135.8 1.79 282.8 18435 80.3 160.6 9.1 0.215 210.6 1.91 274.4 18889 160.6 240.9 8.1 0.196 194.6 1.75 286.6 17011 240.9 321.2 4.5 0.148 152.5 1.38 360.5 12394 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment 37 Attachment K Section 28: Zone Data (Stage 10; 12111 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 4076.7 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4086.7 15.0 0.70 2845 1.76E+06 0.220 1000 Nanushuk 3 SS 4101.7 15.3 0.68 2786 1.90E+06 0.220 1000 Top Nan CS 4117.0 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4136.5 2.0 0.69 2859 2.67E+06 0.230 2500 Nan CS 4138.5 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4140.0 4.5 0.62 2552 6.44E+05 0.280 1000 Nan DS 4144.5 3.5 0.69 2865 1.77E+06 0.260 1500 Nan DS 4148.0 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4162.5 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4164.0 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4176.5 2.0 0.65 2711 1.40E+06 0.260 1500 Nan CS 4178.5 9.0 0.61 2539 8.54E+05 0.270 1000 Nan DS 4187.5 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4194.5 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4203.5 3.5 0.64 2700 1.69E+06 0.260 1500 Nan DS 4207.0 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4212.0 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4214.0 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4224.5 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4228.0 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4230.0 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4235.5 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4239.0 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4242.5 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4248.0 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4258.5 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4260.0 5.0 0.62 2651 1.14E+06 0.270 1500 Nan DS 4265.0 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4267.0 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4271.0 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4273.0 10.0 0.63 2682 9.81E+05 0.270 1500 Nan DS 4283.0 4.0 0.65 2802 1.63E+06 0.260 1500 Nan DS 4287.0 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4291.0 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4300.5 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4302.5 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4312.0 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4314.0 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4316.0 2.0 0.64 2746 1.09E+06 0.270 1500 Shale 4318.0 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4320.0 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4324.0 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4343.5 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4345.5 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4347.5 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4355.5 8.0 0.65 2821 1.56E+06 0.260 1500 Shale 4363.5 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 38 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4076.7 10.0 0.001 1.0 1890 4086.7 15.0 0.001 1.0 1898 4101.7 15.3 0.005 10.0 1905 4117.0 19.5 30.655 23.7 1915 4136.5 2.0 5.000 10.0 1924 4138.5 1.5 2.095 16.9 1925 4140.0 4.5 48.388 26.6 1926 4144.5 3.5 0.478 12.4 1928 4148.0 14.5 15.008 17.7 1930 4162.5 1.5 3.661 17.6 1937 4164.0 12.5 34.723 23.9 1937 4176.5 2.0 1.697 15.6 1943 4178.5 9.0 54.319 24.4 1944 4187.5 7.0 3.610 14.8 1948 4194.5 9.0 22.986 20.4 1952 4203.5 3.5 0.835 14.0 1956 4207.0 5.0 65.392 23.4 1957 4212.0 2.0 0.006 10.5 1960 4214.0 10.5 100.832 25.6 1961 4224.5 3.5 17.434 20.5 1966 4228.0 2.0 161.343 26.3 1967 4230.0 5.5 4.627 18.4 1968 4235.5 3.5 5.075 14.8 1971 4239.0 3.5 8.651 19.4 1972 4242.5 5.5 10.205 16.0 1974 4248.0 10.5 17.356 20.1 1977 4258.5 1.5 3.106 14.8 1982 4260.0 5.0 52.863 20.6 1982 4265.0 2.0 2.277 14.1 1985 4267.0 4.0 122.778 23.1 1986 4271.0 2.0 0.333 12.5 1987 4273.0 10.0 39.939 21.2 1988 4283.0 4.0 0.748 13.3 1993 4287.0 4.0 0.009 10.9 1995 4291.0 9.5 5.399 16.7 1997 4300.5 2.0 160.618 24.9 2001 4302.5 9.5 0.033 11.5 2002 4312.0 2.0 6.733 16.2 2007 4314.0 2.0 0.001 1.0 2008 4316.0 2.0 29.480 19.6 2009 4318.0 2.0 0.001 1.0 2009 4320.0 4.0 8.473 16.6 2010 4324.0 19.5 0.001 1.0 2012 4343.5 2.0 2.185 16.4 2021 4345.5 2.0 0.001 1.0 2022 4347.5 8.0 2.645 15.9 2023 4355.5 8.0 2.026 14.4 2027 4363.5 20.0 0.001 10.0 2031Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Formation Transmissibility Properties Zone Name 39 Attachment K Section 29: Propped Fracture Schedule (Stage 10; 12111 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 182.5 25 0 Please note that this pumping schedule is under-displaced by 2 bbl. 1476 bbl of YF125ST 0 bbl of WF125 231805 lb of % PAD Clean 23.2 % PAD Dirty 19.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3404 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 3408 4.5 12.0 3.0 PPA 176.8 649 200 680 22275 29518 3533 5.0 17.0 5.0 PPA 188.7 838 230 910 39630 69148 4043 5.8 22.8 7.0 PPA 176.1 1014 230 1140 51765 120913 4489 5.8 28.5 9.0 PPA 154.2 1168 215 1355 58302 179215 4759 5.4 33.9 10.0 PPA 125.2 1293 180 1535 52590 231805 4879 4.5 38.4 Flush 182.5 1476 182 1718 0 231805 4471 4.6 42.9 Job Execution Step Name Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 328.5 ft with an average conductivity (Kfw) of 15992.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 40 Attachment K Section 30: Propped Fracture Simulation (Stage 10; 12111 ft MD) Initial Fracture Top TVD 4084 ft Initial Fracture Bottom TVD 4319.6 ft Propped Fracture Half-Length 328.5 ft EOJ Hyd Height at Well 235.6 ft Average Propped Width 0.185 in Net Pressure 251 psi Max Surface Pressure 4901 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 82.1 9.9 0.207 137.8 1.78 281.3 18339 82.1 164.3 9 0.206 204.5 1.82 286.1 17894 164.3 246.4 8.1 0.196 194.8 1.74 280.5 17038 246.4 328.5 3.9 0.139 145.1 1.29 446.9 11485 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 41 Attachment K Section 31: Zone Data (Stage 11; 11648 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 4078.4 10.0 0.72 2937 1.46E+06 0.220 1000 Shale 4088.4 15.0 0.70 2847 1.76E+06 0.220 1000 Nanushuk 3 SS 4103.4 15.3 0.68 2787 1.90E+06 0.220 1000 Top Nan CS 4118.7 19.5 0.63 2595 9.00E+05 0.270 1000 Nan SS 4138.2 2.0 0.69 2860 2.67E+06 0.230 2500 Nan CS 4140.2 1.5 0.64 2655 1.29E+06 0.260 1000 Nan CS 4141.7 4.5 0.62 2553 6.44E+05 0.280 1000 Nan DS 4146.2 3.5 0.69 2866 1.77E+06 0.260 1500 Nan DS 4149.7 14.5 0.66 2726 1.39E+06 0.260 1500 Nan CS 4164.2 1.5 0.65 2706 1.15E+06 0.270 1000 Nan CS 4165.7 12.5 0.63 2641 8.82E+05 0.270 1000 Nan DS 4178.2 2.0 0.65 2712 1.40E+06 0.260 1500 Nan CS 4180.2 9.0 0.61 2540 8.54E+05 0.270 1000 Nan DS 4189.2 7.0 0.66 2755 1.40E+06 0.260 1500 Nan DS 4196.2 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4205.2 3.5 0.64 2701 1.69E+06 0.260 1500 Nan DS 4208.7 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4213.7 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4215.7 10.5 0.62 2607 7.36E+05 0.270 1000 Nan CS 4226.2 3.5 0.64 2705 1.10E+06 0.270 1000 Nan CS 4229.7 2.0 0.62 2614 6.70E+05 0.280 1000 Nan CS 4231.7 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4237.2 3.5 0.69 2939 1.53E+06 0.260 1500 Nan DS 4240.7 3.5 0.64 2701 1.19E+06 0.270 1500 Nan DS 4244.2 5.5 0.69 2928 1.42E+06 0.260 1500 Nan CS 4249.7 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4260.2 1.5 0.66 2811 1.38E+06 0.260 1500 Nan DS 4261.7 5.0 0.62 2652 1.14E+06 0.270 1500 Nan DS 4266.7 2.0 0.66 2809 1.56E+06 0.260 1500 Nan DS 4268.7 4.0 0.63 2688 8.96E+05 0.270 1500 Nan DS 4272.7 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4274.7 10.0 0.63 2683 9.81E+05 0.270 1500 Nan DS 4284.7 4.0 0.65 2804 1.63E+06 0.260 1500 Nan DS 4288.7 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4292.7 9.5 0.65 2784 1.33E+06 0.260 1500 Nan DS 4302.2 2.0 0.62 2649 7.82E+05 0.270 1000 Nan DS 4304.2 9.5 0.69 2975 1.69E+06 0.260 1500 Nan DS 4313.7 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4315.7 2.0 0.70 3002 2.67E+06 0.230 2500 Nan DS 4317.7 2.0 0.64 2747 1.09E+06 0.270 1500 Shale 4319.7 2.0 0.70 3005 2.67E+06 0.230 2500 Nan DS 4321.7 4.0 0.66 2844 1.29E+06 0.260 1500 Shale 4325.7 19.5 0.70 3015 2.67E+06 0.230 2500 Nan DS 4345.2 2.0 0.65 2820 1.36E+06 0.260 1500 Shale 4347.2 2.0 0.70 3024 2.67E+06 0.230 2500 Nan DS 4349.2 8.0 0.66 2855 1.37E+06 0.260 1500 Nan DS 4357.2 8.0 0.65 2822 1.56E+06 0.260 1500 Shale 4365.2 20.0 0.70 3042 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’s Ratio 42 Attachment K Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4078.4 10.0 0.001 1.0 1890 4088.4 15.0 0.001 1.0 1898 4103.4 15.3 0.005 10.0 1905 4118.7 19.5 30.655 23.7 1915 4138.2 2.0 5.000 10.0 1924 4140.2 1.5 2.095 16.9 1925 4141.7 4.5 48.388 26.6 1926 4146.2 3.5 0.478 12.4 1928 4149.7 14.5 15.008 17.7 1930 4164.2 1.5 3.661 17.6 1937 4165.7 12.5 34.723 23.9 1937 4178.2 2.0 1.697 15.6 1943 4180.2 9.0 54.319 24.4 1944 4189.2 7.0 3.610 14.8 1948 4196.2 9.0 22.986 20.4 1952 4205.2 3.5 0.835 14.0 1956 4208.7 5.0 65.392 23.4 1957 4213.7 2.0 0.006 10.5 1960 4215.7 10.5 100.832 25.6 1961 4226.2 3.5 17.434 20.5 1966 4229.7 2.0 161.343 26.3 1967 4231.7 5.5 4.627 18.4 1968 4237.2 3.5 5.075 14.8 1971 4240.7 3.5 8.651 19.4 1972 4244.2 5.5 10.205 16.0 1974 4249.7 10.5 17.356 20.1 1977 4260.2 1.5 3.106 14.8 1982 4261.7 5.0 52.863 20.6 1982 4266.7 2.0 2.277 14.1 1985 4268.7 4.0 122.778 23.1 1986 4272.7 2.0 0.333 12.5 1987 4274.7 10.0 39.939 21.2 1988 4284.7 4.0 0.748 13.3 1993 4288.7 4.0 0.009 10.9 1995 4292.7 9.5 5.399 16.7 1997 4302.2 2.0 160.618 24.9 2001 4304.2 9.5 0.033 11.5 2002 4313.7 2.0 6.733 16.2 2007 4315.7 2.0 0.001 1.0 2008 4317.7 2.0 29.480 19.6 2009 4319.7 2.0 0.001 1.0 2009 4321.7 4.0 8.473 16.6 2010 4325.7 19.5 0.001 1.0 2012 4345.2 2.0 2.185 16.4 2021 4347.2 2.0 0.001 1.0 2022 4349.2 8.0 2.645 15.9 2023 4357.2 8.0 2.026 14.4 2027 4365.2 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS 43 Attachment K Section 32: Propped Fracture Schedule (Stage 11; 11648 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.5 25 1 3.0 PPA 40 YF125ST 176.8 25 3 5.0 PPA 40 YF125ST 188.7 25 5 7.0 PPA 40 YF125ST 176.1 25 7 9.0 PPA 40 YF125ST 154.2 25 9 10.0 PPA 40 YF125ST 125.2 25 10 Flush 40 YF125ST 174.4 25 0 Please note that this pumping schedule is under-displaced by 3 bbl. 1467.9 bbl of YF125ST 0 bbl of WF125 231805 lb of % PAD Clean 23.2 % PAD Dirty 19.5 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3317 7.5 7.5 1.0 PPA 172.5 472 180 480 7243 7243 3319 4.5 12.0 3.0 PPA 176.8 649 200 680 22275 29518 3452 5.0 17.0 5.0 PPA 188.7 838 230 910 39630 69148 3912 5.8 22.8 7.0 PPA 176.1 1014 230 1140 51765 120913 4334 5.8 28.5 9.0 PPA 154.2 1168 215 1355 58302 179215 4603 5.4 33.9 10.0 PPA 125.2 1293 180 1535 52590 231805 4710 4.5 38.4 Flush 174.4 1468 174 1709 0 231805 4261 4.4 42.7 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 325.6 ft with an average conductivity (Kfw) of 16095.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Pad Percentages Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 44 Attachment K Section 33: Propped Fracture Simulation (Stage 11; 11648 ft MD) Initial Fracture Top TVD 4085.6 ft Initial Fracture Bottom TVD 4320.3 ft Propped Fracture Half-Length 325.6 ft EOJ Hyd Height at Well 234.7 ft Average Propped Width 0.186 in Net Pressure 251 psi Max Surface Pressure 4730 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 81.4 9.9 0.208 136.5 1.79 282.3 18447 81.4 162.8 9.1 0.206 210.1 1.82 286.5 17986 162.8 244.2 8.1 0.192 194.1 1.69 286.2 16591 244.2 325.6 4.2 0.146 147 1.35 414.7 12227 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 45 Attachment K 4730 psi S t USA d B k H h C fid ti l P 1 © 2018 Baker Hughes, LLC - All rights reserved. LLWD Qualitative Cement Bond Log Evaluation Report Well Name, Section: NDBi-030, 9 5/8” Liner Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: Reservoir Technical Services Alaska Version: Preliminary Report S t USA d B k H h C fid ti l P 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Tool Diagram .......................................................................................................................................................................................................... 7 Methodology of LWD Cement Bond Log Evaluation .................................................................................................................8 Log Screen Captures ...................................................................................................................................................................................... 13 S t USA d B k H h C fid ti l P 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMER THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. S t USA d B k H h C fid ti l P 4 Executive Summary Cement Bond Logging with LWD Acoustic (Sonic) tool SoundTrak was performed after drilling of 8 ½” section. Logs were acquired while pulling out of hole across 9 5/8” liner in upward direction. The objective and plan were to cover with CBL logs to evaluate the first stage cementing from the 9 5/8” Liner shoe to the planned TOC of 8450’ MD. Cement Bond Index (BI) curve was computed and presented in the log plot showing color gradation from good cement bond (brown) to poor cement (blue). The following values were used by interpreter to differentiate intervals of good bond (curve value above 0.8) to partial (0.2 to 0.8) and poor (lower than 0.2). Summaries of initial pre-job logging plan and Cement Bond Index interpretation are outlined below. Logging Plan Summary Down link to the SoundTrak tool after drilling 9 5/8” shoe track and 50ft of open hole and upon coming to the liner shoe at 11,201’ MD to initiate top of cement mode and continue back reaming out of the hole to log the cement in the 9-5/8” Liner at 550 gpm and 60 RPM (per Baker Hughes recommendation). x Log cement from 9-5/8” shoe (11,201’ MD) to 8,450’ MD planned top of cement. Log up at 1,200 fph. x Log free pipe from 8,450’ to 7,200’ MD (1,250’ of free pipe) at 1,200 fph. LWD logging was optimized to gain higher efficiency and reduce overall rig time by modifying acquisition parameters and logging at 1200 ft/hr entire well interval. S t USA d B k H h C fid ti l P 5 Interpretation Summary The Intermediate was drilled and 9 5/8” Casing shoe was set at 11,201ft. The initial cement job was unsuccessful due to a liner wiper plug failure, leaving all cement inside the 9-5/8" liner. The cement was drilled out and a cement retainer was set in the shoe track to re-pump the 1st stage cement job. A Logging up was performed in order to capture cement Bond on the 9 5/8” casing. Following observations are summarized below by interval. Please note that Bond Index curve (BI) and color coding in combination with other data on the log can be used for more detailed interval inspection to draw conclusions on zonal isolation of narrower intervals. Overall, 5 main zones were defined as listed below, with more detailed interpretation within each zone presented in the table that follows. - 7,247’-9,949’: Poor to no cement presence above 9950ft - 9,950’ to 10,203’ Partial to poor Cement presence, with some intervals of partial cement presence. - 10,204’ to 10,882’ Partial to Good. Mostly partial, with a couple intervals in the middle of this zone appearing with good cement presence. - 10,883’ to 11,133’ Partial to poor Cement presence, with some intervals of partial cement presence. For more detailed description of each interval please refer to the table below summarizing Interpretation results. S t USA d B k H h C fid ti l P 6 S t USA d B k H h C fid ti l P 7 Tool Diagram S t USA d B k H h C fid ti l P 8 Methodology of LWD Cement Bond Log Evaluation Before the arrival of more advanced Wireline technologies offering azimuthal coverage of the casing to cement and cement to formation bonding, oil and gas operators have been relying on traditional non-azimuthal CBL, Cement Bond Log, technique, that is being run successfully to date. Wireline Acoustic (Sonic) tool’s CBL measurement principle relies on detecting and measuring first “casing ringing” amplitude reflected from the casing wall. The idea is that free pipe (with cement absence) would “ring” freely creating high Casing Ringing Amplitude, whereas well cemented casing would result in dampened first arrival and thus indicate well cemented pipe. Traditional Wireline tool relies on the arrival of the sound detected at the receiver spaced at 3 ft for CBL Amplitude and for the one from the 5 ft spaced receiver for VDL (Variable Density Log). Figure 1: Traditional Wireline CBL technique S t USA d B k H h C fid ti l P 9 LWD Acoustic (Sonic) tool is using the same principle for CBL measurement. It is also non- azimuthal. However, the one difference is that receiver spacing is longer and all measurements are based on the 10.7 ft receiver spacing for CBL Amplitude. See figures below for the main principle behind cemented vs free pipe detection in traditional CBL measurement. Figure 2: CBL concept in "free" pipe Figure 3: CBL concept in cemented pipe S t USA d B k H h C fid ti l P 10 Figure 4: General CBL concept and corresponding log example Figure 5: LWD Acoustic (Sonic) tool and LWD CBL concept Current traditional offering of LWD Acoustic (Sonic) tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling trip typically on the way out of casing after drilling is completed. S t USA d B k H h C fid ti l P 11 Baker Hughes offers both traditional TOC service and a more advanced workflow of providing Cement Bond Index. This Cement Bond Index is a relative Cement Quality Indicator helping operators to still acquire positive zonal isolation information in wells where running Wireline could be challenging and / or would otherwise increase overall rig time. To convert casing amplitude to cement bond index (BI), two reference points are required: -Free casing - 100% bonded point Figure 6: Cement Bond Index computation concept Traditionally as part of the CBL logging deliverable, Bond Index (BI) is computed and displayed in the log. Values above 80% BI are typically seen as “good" cement, whereas values below 80% are typically seen as either "poor," contaminated or channeled cement. Note however, that the TR spacing (10.66 ft) for LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality check must be carried out to validate the data, because If the casing amplitude in these well bonded intervals is below noise level, the 100% bonded reference point might be incorrect and the “BI” could be over-estimated, reducing quantitative precision of the measurement. Additionally, Cement Evaluation with LWD SoundTrak tool would be ideal in standard cements with slurry density of equal or greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. For example, detection of behind casing open hole DT from waveforms could confirm that proper cement is present. S t USA d B k H h C fid ti l P 12 Furthermore, adding this service can increase operational efficiency since it can be done in the same drilling trip on the way out and logging speed for top of cement detection and CBL evaluation can be as high as ~1500 ft/hr still providing good data quality. With combination of casing mode semblance (SV) and formation arrival in correlogram, TOC can be detected in Real-Time. Good agreement between RT and memory TOC can be seen in the figure below. Figure 7: LWD capability of Real-Time Top of Cement acquisition This method has limitations though as it has no azimuthal coverage and can not identify micro channeling. It is not a replacement for quantitative cement evaluation tools such as SBT, InTex, or CICM S t USA d B k H h C fid ti l P 13 Log Screen Captures Following figures contain interpretation observations, however Bond Index curve and color coding can be used for more detailed interval inspection to draw conclusions on zonal isolation. Please refer to the tables on pages 6 and 7 for more detailed interpretation. Figure 8: Interval 1 of LWD CBL logging General Interpretation Comments: 7,247’ to 9,950’ poor to no cement in that interval. S t USA d B k H h C fid ti l P 14 Figure 9: Interval 2 of LWD CBL Logging General Interpretation Comments: 7,247’ to 9,950’ poor to no cement in that interval. S t USA d B k H h C fid ti l P 15 Figure 10: Interval 3 of LWD CBL Logging General Interpretation Comments: 7,247’ to 9,950’ poor to no cement in that interval. S t USA d B k H h C fid ti l P 16 Figure 11: Interval 4 of LWD CBL Logging General Interpretation Comments: 7,247’ to 9,950’ poor to no cement in that interval. 9,950’-9,981’, 10,012-10,041’, 10090’-10095’, 10,126’-10,146’, 10,159’-10,186’, 10,204’-1,0457’, 10,492’-1,0625’ Partial cement presence in that interval. Mostly Good cement in interval 10,458’-10,491’. S t USA d B k H h C fid ti l P 17 Figure 12: Interval 5 of LWD CBL Logging General Interpretation Comments: 10,696’-10,834’, 11,026’-11,081’, 11,012’-11,125’ Poor Cement presence in these intervals. Good cement presence in intervals 10,868’-10,882’ and Partial cement presence elsewhere is that interval. 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 1 A p r i l , 2 0 2 4 (a ) A p p l i c a t i o n f o r Su n d r y A p p r o v a l (a ) ( 1) A f f i d a v i t Pr o v i d e d w i t h a p p l i c a t i o n . SF D 4/ 2 2 / 2 0 2 4 (a ) ( 2) P l a t Pr o v i d e d w i t h a p p l i c a t i o n . SF D 4/ 2 2 / 2 0 2 4 (a ) ( 2) ( A ) W e l l l o c a t i o n Pr o v i d e d w i t h a p p l i c a t i o n . W e l l l i e s i n S e c t i o n s 4 a n d 5 o f T1 1 N, R 6 E , U M , a n d S e c t i o n s 3 2 , 3 1 , a n d 3 0 o f T 1 2 N , R 6 E , U M . SF D 4/ 2 2 / 2 0 2 4 (a ) ( 2) ( B ) E a c h w a t e r w e l l w i t h i n ½ m i l e No n e : Ac c o r d i n g t o t h e W a t e r E s t a t e m a p a v a i l a b l e t h r o u g h DN R ’ s Al a s k a M a p p e r a p p l i c a t i o n (a c c e s s e d o n l i n e A p r i l 2 2 , 20 2 4), t h e r e a r e n o w e l l s a r e u s e d f o r d r i n k i n g w a t e r p u r p o s e s ar e k n o w n t o l i e w i t h i n ½ m i l e o f t h e s u r f a c e l o c a t i o n o f N D B - 03 0 . T h e r e a r e n o s u b s u r f a c e w a t e r r i g h t s o r t e m p o r a r y su b s u r f a c e w a t e r r i g h t s w i t h i n 14 mi l e s o f t h e s u r f a c e l o c a t i o n o f N D B - 0 3 0 . SF D 4/ 2 2 / 2 0 2 4 ( a ) ( 2 ) ( C ) I d e n t i f y a l l w e l l t y p e s w i t h i n ½ mi l e Ye s . Qu g r u k 3 0 1 , N D B - 0 2 4 , N D B - 0 3 2 , a n d N D B - 0 4 3 . SF D 4/ 2 2 / 2 0 2 4 (a ) (3 ) F r e s h w a t e r a q u i f e r s : g e o l o g i c a l na m e ; me a s u r e d a n d t r u e v e r t i c a l d e p t h No n e . N o f r e s h w a t e r a q u i f e r s a r e p r e s e n t w i t h i n t h e P i k k a Un i t pe r s a l i n i t y c a l c u l a t i o n s p r o v i d e d b y t h e o p e r a t o r o n A u g . 21 , 2 0 2 3 a s p a r t o f t h e ir Su n d r y A p p l i c a t i o n t o h y d r a u l i c a l l y f r a c t u r e n e a r b y w e l l N D B - 0 2 4 ( s e e A O G C C ’ s W e l l H i s t o r y F i l e 22 3 - 0 7 6 , p . 1 0 1 - 1 0 7 o f S un d r y A p p l i c a t i o n 3 2 3 - 59 1 ) . Pi c k e t t Pl o t w e l l -lo g a n a l y s e s w e r e p e r f o r m e d o n t h r e e w e l l s w i t h i n th e u n i t t h a t h a v e w i r e l i n e l o g c o v e r a g e f r o m s u r f a c e t h r o u g h th e f r a c t u r i n g i n t e r v a l : C o l v i l l e R i v e r 1 , T i l l 1 , a n d P i k k a D W - 02 . Es t i m a t e d s a l i n i t y v a l u e s f o r c l e a n , p o r o u s 1 0 0 % w a t e r - sa t u r a t e d s a n d s b e n e a t h t h e b a s e o f t h e p e r m a f r o s t l a y e r i n th e s e t h r e e w e l l s a r e : Co l v i l l e R i v e r 1 ( 1 9 2 - 1 5 3 ) ~ 2 0 , 0 0 0 m g / l b e t w e e n 1 , 4 0 0 a n d 2 , 0 0 0 ’ M D ( - 1 , 3 5 4 ’ t o 1, 9 5 4 ' T V D S S ; b a s e o f p e r m a f r o s t 1 , 3 5 0 ’ M D ( - 1 , 3 1 3 ’ T V D S S ) ) ; Ti l l 1 ( 1 9 3 - 00 4 ) 16 , 7 0 0 t o ~ 2 3 , 0 0 0 m g / l b e t w e e n 1 , 4 0 0 ’ a n d 1 , 5 0 0 ’ M D ( - 1 , 4 6 3 ’ t o - 1 , 3 6 3 ’ T V D S S ; b a s e o f p e r m a f r o s t 1 , 3 5 0 ’ M D SF D 4/ 2 2 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 2 A p r i l , 2 0 2 4 ( - 1 , 3 0 5 ’ T V D S S ) ) ; a n d DW - 0 2 ( 2 2 3 - 0 3 9 ) ~ 2 1 , 5 0 0 m g / l b e t w e e n 1 , 5 5 0 ’ a n d 1 , 6 5 0 ’ M D ( - 1 , 4 0 8 ’ t o - 1, 4 8 6 ’ T V D S S ; b a s e o f p e r m a f r o s t ~ 1 , 1 7 0 ’ M D ( ~ - 1 , 0 8 0 ’ T V D S S ) . (a ) ( 4 ) B a s e l i n e w a t e r s a m p l i n g p l a n No n e r e q u i r e d . SF D 4/ 2 2 / 2 0 2 4 (a ) (5 ) C a s i n g a n d c e m e n t i n g in f o r m a t i o n Pr o v i d e d w i t h a p p l i c a t i o n . P r o p o s e d s c h e m a t i c a t t a c h e d , a s bu i l t n o t g e n e r a t e d t o d a t e . CD W 4/ 2 3 / 2 4 (a ) (6 ) C a s i n g a n d c e m e n t i n g o p e r a t i o n as s e s s m e n t 13 - 3 / 8 ” c a s i n g c e m e n t t o s u r f a c e w i t h c e m e n t r e t u r n s . 9- 5/ 8 ” l i n e r t w o s t a g e c e m e n t j o b 9- 5/ 8 ” c a s i n g s e t a t 1 1 2 0 1 f t . 1 st s t a g e p r o b l e m s , r e d o . Lo s s e s d u r in g p u m p i n g . T O C 9 9 5 0 f t . a s p e r B a k e r So u n d T r a k r u n a n d in t e r p r e t a t i o n . S o u n d T r a k sh o w s p a r t i a l t o p o o r s t a r t i n g a t 9 9 4 9 f t w i t h t h e o n l y “g o o d ” c e m e n t me n t i o n e d f r o m 1 0 4 5 8 t o 1 0 4 9 1 f t a n d 1 0 8 6 8 t o 10 8 8 2 f t . 9- 5 / 8 ” c a s i n g s t a g e t o o l a t 4 7 1 2 f t w i t h c e m e n t p u m p e d ( 2 6 bb l l o s s e s ) t o l i n e r t o p a n d c e m e n t c i r c u l a t e d o f f l i n e r in d i c a t i n g c e m e n t t o l i n e r t o p o f 2 3 6 7 f t . No i s s u e s w i t h c e m e n t f o r t h is f r a c s t i m u l a t i o n . Th e L O T p r e s s u r e a t t h e I n t e r m e d i a t e l i n e r s h o e w a s 1 4 . 1 p p g , wi t h i n r a n g e o f e x p e c t a t i o n , i n d i c a t i n g c e m e n t i s l i k e l y ad e q u a t e t o c o n t a i n f r a c b e l o w t h e I n t er m e d i a t e l i n e r . -b j m CD W 4/ 2 3 / 2 4 (a ) (6 ) ( A ) C a s i n g c e m e n t e d b e l o w lo w e r m o s t f r e s h w a t e r a q u i f e r a n d co n f o r m s t o 2 0 A A C 2 5 . 0 3 0 No f r e s h w a t e r a q u i f e r s p r e s e n t . (S e e S e c t i o n ( a ) ( 3 ) , a b o v e . ) SF D 4/ 2 2 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 3 A p r i l , 2 0 2 4 (a ) (6 ) ( B ) E a c h h y d r o c a r b o n z o n e i s is o l a t e d Y e s : C e m e n t a p p e a r s s u f f i c i e n t i n N D B - 0 3 0 t o i s o l a t e t h e Na n u s h u k r e s e r v o i r t h a t w i l l b e h y d r a u l i c a l l y f r a c t u r e d . Su r f a c e c a s i n g w a s s e t a t 2, 5 5 0 ’ M D ( - 2 , 1 9 5 ’ T V D S S ) a n d ce m e n t e d. I n t e r m e d i a t e 9 - 5/ 8 ” c a s i n g w a s s e t a t 1 1 , 2 0 1 ’ M D (- 4, 0 3 4 ’ T V D S S ) a n d c e m e n t e d i n t w o s t a g e s . S t a g e 1 p u m p e d 20 5 b a r r e l s o f 1 5 . 3 p p g V e r s a c e m , bu t 1 1 0 b a r r e l s w e r e l o s t af t e r c e m e n t b e g a n e n t e r i n g t h e a n n u l u s ( 2 0 0 bb l t o t a l f o r jo b ) . In t h i s w e l l , t h e t o p o f t h e N a n u s h u k f o r m a t i o n i s 9 , 6 5 3 ’ MD ( - 3 , 7 0 4 ’ T V D S S ) . T h e C B L in d i c a t e s c e m e n t i s g e n e r a l l y p o o r f r o m t h e t o p o f t h e l o g a t 7 , 2 5 0 ’ M D t o 9 , 9 5 0 ’ M D . T h e to p o f f i r s t -s t a g e c e m e n t i s a 1 0 - f o o t - t h i c k in t e r v a l o f g o o d - qu a l i t y ce m e n t a t 9 , 9 5 0 ’ M D ( - 3 , 7 6 1 ’ T V D S S ) . A lt h o u g h t h e r e is a p o s s i b l e h y d r o c a r b o n - b e a r i n g s a n d y s i l t s t o n e in t e r v a l wi t h d e e p r e s i s t i v i t y e x c e e d i n g 8 o h m - m be t w e e n 1 0 , 6 9 0 ’ an d 10 , 8 4 2 ’ M D ( - 3 , 9 0 6 ’ a n d - 3 , 9 4 2 ’ T V D S S ) , a cc o r d i n g t o t h e mu d l o g , s i g n i f i c a n t h y d r o c a r b o n s h o w s d o n o t b e g i n u n t i l 11 , 7 0 0 ’ M D ( - 4 , 1 1 6 ’ T V D S S ) , w h i c h i s w i t h i n t h e Na n u s h u k fo r m a t i o n a n d be n e a t h t h e i n t e r m e d i a t e c a s i n g s h o e . Th e Na n u s h u k r e s e r v o i r s a n d - - l o c a t e d a t 1 1 , 2 8 0 ’ M D ( - 4, 0 5 6 ’ TV D S S ) a n d b e n e a t h t h e i n t e r m e d i a t e c a s i n g s h o e — an d t h e po s s i b l e h y d r o c a r b o n -b e a r i n g i n t e r v a l m e n t i o n e d a b o v e ar e bo t h is o l a t e d f r o m o v e r l y i n g s t r a t a by i n t e r v a l s o f g o o d t o e x c e l l e n t c e m e n t f r o m 1 0 , 4 5 0 ’ t o 1 0 , 6 9 5 ’ M D a n d fr o m 10 , 8 4 0 ’ t o 1 1 , 0 2 2 ’ M D . SF D 4/ 2 5 / 2 0 2 4 CD W 4/ 2 5 / 2 0 2 4 (a ) ( 7 ) P r e s s u r e t e s t : i n f o r m a t i o n a n d pr e s s u r e -te s t p l a n s f o r c a s i n g a n d t u b i n g in s t a l l e d i n w e l l Pr o v i d e d w i t h a p p l i c a t i o n . 40 0 0 p s i M I T I A p l a n n e d , 6 0 0 0 ps i MI T T p l a n . CD W 4/ 2 3 / 2 4 (a ) (8 ) Pr e s s u r e r a t i n g s a n d s c h e m a t i c s : wel l b o r e , w e l l h e a d , B O P E , t r e a t i n g h e a d Pr o v i d e d w i t h a p p l i c a t i o n . 1 0 K p s i w e l l h e a d m a x . a l l o w a b l e fr a c . P r e s s u r e 89 0 0 p s i . P u m p k n o c k o u t 7 4 0 0 a n d G O R V 83 0 0 p s i . , l i n e s t e s t 9 0 0 0 p s i . CD W 4/ 2 3 / 2 4 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 4 A p r i l , 2 0 2 4 (a ) (9 ) ( A ) Fr a c t u r i n g a n d c o n f i n i n g z o n e s : li t h o l o g i c d e s c r i p t i o n fo r e a c h z o n e (a ) (9 ) ( B ) G e o l o g i c a l n a m e o f e a c h z o n e (a ) (9 ) ( C ) a n d ( a ) ( 9 ) (D ) M e a s u r e d a n d t r u e ve r t i c a l d e p t h s (a ) (9 ) (E ) F r a c t u r e p r e s s u r e f o r e a c h z o n e Up p e r C o n f i n i n g Z o n e s : A b o u t 9 0 0 ’ t r u e v e r t i c a l t h i c k n e s s ( T V T ) o f s h a l e a n d t h i n l y i n t e r b e d d e d s i l t s t o n e a s s i g n e d t o t h e Up p e r T o r o k / H u e S h a l e h a v i n g a n e s t i m a t e d f r a c t u r e g r a d i e n t o f 1 3 . 7 p p g E M W ( 0. 7 1 p s i / f t ) . Th e L O T p r e s s u r e a t t h e I n t e r m e d i a t e l i n e r s h o e w a s 1 4 . 1 p p g . -b j m Fr a c t u r i n g Z o n e : Pe r f o r a t e d z o n e l i e s w i t h i n a s u b d i v i s i o n o f th e N a n u s h u k F o r m a t i o n t h a t i s a b o u t 96 7 ’ T V T i n t h i s a r e a an d h a s a n e s t i m a t e d f r a c t u r e g r a d i e n t o f 1 1 . 7 p p g E M W ( 0 . 6 1 p s i / f t ). Lo w e r C o n f i n i n g Z o n e s : L o w e r T o r o k si l t s t o n e a n d s h a l e t h a t is a b o u t 1 7 0 ’ t h i c k i n t h i s a r e a w i t h a n e s t i m a t e d f r a c t u r e gr a d i e n t o f 1 3 . 3 p p g E M W ( 0. 6 9 p s i / f t ) . Th i s i s u n d e r l a i n b y ab o u t 2 2 5 ’ o f c o n d e n s e d m a r i n e s h a l e a s s i g n e d t o t h e H R Z . SF D 4/ 2 3 / 2 0 2 4 (a ) ( 1 0 ) L o c a t i o n , o r i e n t a t i o n , r e p o r t o n me c h a n i c a l c o n d i t i o n o f e a c h w e l l Th r e e w e l l s i d e n t i f i e d a s a c t i v e , o n e a b a n d o n e d . CD W 4/ 2 3 / 2 4 (a ) ( 1 1 ) S u f f i c i e n t i n f o r m a t i o n t o d e t e r m i n e w e l l s w i l l n o t i n t e r f e r e w i t h c o n t a i n m e n t w i t h i n ½ m i l e Y e s . N o n e o f t h e f o u r w e l l s w i t h i n ½ m i l e o f N D B - 0 3 0 t h a t tr a n s e c t t h e c o n f i n i n g z o n e ( Q u g r u k 3 0 1 , N D B -02 4 , N D B - 03 2 , a n d N D B -04 3 ) w il l i n t e r f e r e w i t h c o n t a i n m e n t o f f l u i d s wi t h i n t h e N a n u s h u k r e s e r v o i r . Qu g r u k 3 0 1 ( P T D 2 1 4 - 1 9 9 ) : Na n u s h u k r e s e r v o i r is ad e q u a t e l y i s o l a t e d . Th i s w e l l i s p l u g g e d a n d ab a n d o n e d . Su r f a c e c a s i n g ( 1 3 - 3 / 8 ’ ) s e t a t 2 , 1 0 7 ’ M D ( - 2 , 0 7 0 ’ T V D S S ) a n d ce m e n t e d t o s u r f a c e w i t h 60 b b l s o f c e m e n t r e t u r n s at su r f a c e . R et u r n s w e r e t h e n l o s t a n d c e m e n t f e l l b a c k t o 4 0 ’ MD . To p j o b wa s p e r f o r m e d w i t h 3 . 4 b b l s o f c e m e n t r e t u r n s at s u r f a c e . I n t e r m e d i a t e c a s i n g ( 9 -5 / 8 ” ) w a s s e t a t 5 , 2 4 1 ’ M D (- 4, 1 4 8 ’ T V D S S ) an d c e m e n t e d i n t w o s t a g e s . S t a g e 1 p u m p e d 89 b b l s o f C l a s s G 1 4 . 0 p p g (p l u g d i d n o t b u m p , f l o a t s h e l d , n o re t u r n s t o s u r f a c e ) . T h e o p e r a t o r ’ s e s t i m a t e s o f c e m e n t t o p SF D 4/ 2 5 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 5 A p r i l , 2 0 2 4 ar e 3 , 8 1 0 ’ a n d 4 , 0 0 0 ’ M D . T h e a p p a r e n t c e m e n t t o p o n t h e US I T l o g is 3 , 8 2 0 ’ M D ( - 3 , 6 3 3 ’ T V D S S ) , w h i c h i s o l a t e s th e N a n u s h u k r e s e r v o i r s a n d , t h e t o p o f w h i c h l i e s a t 4 , 0 4 2 ’ M D (- 3, 7 7 7 ’ T V D S S ) . S t a g e 2 c o l l a r i s s e t a t 3 , 0 0 8 ’ M D ( - 2, 9 5 3 ’ TV D S S ) a n d c e m e n t e d w i t h 1 8 7 b b l s o f T y p e I / I I 1 2 . 2 c e m e n t (p l u g b u m p e d , n o r e t u r n s ) . T h e o p e r a t o r ’ s e s t i m a t e s fo r t h e to p o f c e m e n t ar e 2 0 ’ a n d 3 0 0 ’ M D , a n d t h e S F D - ca l c u l a t e d t o p o f c e m e n t i s a b o u t 4 3 0 ’ M D ( - 3 9 2 ’ T V D S S ) , al l o f w h i c h su g g e s t i s o l a t i o n o f Tu l u v a k , S c h r a d e r B l u f f a n d W e s t S a k st r a t a . ND B - 0 2 4 ( 2 2 3 - 0 7 6 ) : Na n u s h u k r e s e r v o i r a p p e a r s a d e q u a t e l y is o l a t e d . T h e 9 - 5/ 8 ” i n t e r m e d i a t e l i n e r s h o e s e t a t 1 1 , 4 6 3 ’ (- 4, 0 4 3 ’ T V D S S ) w a s c e m e n t e d i n t w o s t a g e s . Th e v e n d o r ’ s CB L ev a l u a t i o n r e p o r t s g o o d c e m e n t o v e r a l l f r o m 8 , 7 2 5 ’ t o 11 , 4 6 3 ’ M D ( - 3 , 4 3 1 ’ t o - 4 , 0 4 6 ’ T V D S S ) w h i c h i n d i c a t e s ce m e n t is o l a t e s t h e N a n u s h u k ( f o r m a t i o n t o p a t 1 0 , 0 7 7 ’ M D , - 3, 7 2 9 ’ TV D S S , w i t h t h e r e s e r v o i r t o p a t 1 1 , 4 9 6 ’ M D , -4, 0 5 4 ’ T V D S S ) . Th e s e c o n d s t a g e c e m e n t i n g c o l l a r f o r t h e 9 - 5/ 8 ” in t e r m e d i a t e l i n e r i s l o c a t e d b e t w e e n 5 , 5 5 5 ’ a n d 5, 5 6 0 ’ M D (- 2, 7 3 2 ’ a n d - 2 , 7 3 3 ’ T V D S S ) . T h e v e n d o r ’ s C B L ev a l u a t i o n su g g e s t s t h e u p p e r p o r t i o n o f t h e T u l u v a k ( t o p a t 4 , 2 3 9 ’ M D , - 2 , 4 6 6 ’ T V D S S ) l y i n g a b o v e t h a t c o l l a r i s c o v e r e d b y pa r t i a l ce m e n t w i t h s h o r t i n t e r v a l s o f g o o d c e m e n t . T h e lo w e r Tu l u v a k l y i n g be n e a t h t h a t c o l l a r h a s p o o r t o n o c e m e n t , b u t it i s is o l a t e d f r o m t h e u n d e r l y i n g N a n u s h u k b y g o o d qu a l i t y fi r s t -s t a g e c e m e n t . ND B - 0 3 2 ( P T D 2 2 3 - 0 6 0 ) : Na n u s h u k r e s e r v o i r a p p e a r s ad e q u a t e l y i s o l a t e d . S u r f a c e c a s i n g ( 1 3 - 3 / 8 ” ) w as s e t a t 2, 5 8 8 ’ M D ( - 2 , 2 0 4 ’ T V D S S ) a n d c e m e n t e d w i t h 1 6 3 b a r r e l s o f 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 6 A p r i l , 2 0 2 4 ce m e n t r e t u r n s t o s u r f a c e ( p l u g b u m p e d , f l o a t s h e l d ) . In t e r m e d i a t e c a s i n g ( 9 - 5 / 8 ” ) w a s s e t a t 6 , 2 8 3 ’ M D ( - 4 , 2 5 2’ TV D S S ) a n d c e m e n t e d , a n d 7 2 b a r r e l s o f OB M - co n t a m i n a t e d ce m e n t we r e o b s e r v e d a t s u r f a c e . V o l u m e t r i c ca l c u l a t i o n s su g g e s t t h a t t h e e n t i r e i n t e r m e d i a t e c a s i n g s t r i n g i s ce m e n t e d . A O G C C ’ s c o n s u l t a n t ’ s e v a l u a t i o n o f t h e C A S T l o g su g g e s t s t h e T u l u v a k sa n d ( 2 , 9 3 4 ’ t o 3 , 9 4 3 ’ M D , - 2, 4 2 5 ’ t o - 3 , 1 0 7 ’ T V D S S ) is i s o l a t e d b y g o o d - q u a l i t y c e m e n t f r o m 2 , 6 10 ’ to 3, 8 3 0 ’ M D ( - 2 , 2 1 8 t o - 3 , 0 2 9 ’ T V D S S ) a n d b y f a i r - t o - go o d qu a l i t y ce m e n t f r o m 3 , 8 3 0 ’ t o 3 , 9 5 0 M D ( - 3 , 0 2 9 ’ t o - 3, 1 1 2 ’ TV D S S ). AO G C C ’ s c o n s u l t a n t ’ s e v a l u a t i o n o f t h e C A S T l o g in d i c a t e s m o s t l y g o o d - q u a l i t y c e m e n t f r o m 3 , 9 5 0 ’ M D t o th e en d o f t h e C B L a t 5 , 8 1 3 ’ M D ( - 4 , 1 7 8 ’ T V D S S ) , w h i c h is o l a t e s th e N a n u s h u k f r o m t h e o v e r l y i n g T u l u v a k . T h e Na n u s h u k f o r m a t i o n t o p i s a t 4 , 9 5 2 ’ M D ( - 3 , 7 9 5 ’ T V D S S ) , w i t h t h e cu r r e n t r e s e r v o i r a t 6 , 4 6 8 ’ M D ( - 4 , 2 5 6 ’ T V D S S ) . ND B - 0 4 3 ( 2 2 3 - 0 5 1 ) : I n N D B - 0 4 3 , t h e N a n u s h u k re s e r v o i r in t e r v a l ap p e a r s ad e q u a t e l y c e m e n t i s o l a t e d , b u t t h e ov e r l y i n g T u l u v a k s a n d a t 2 , 8 9 4 ’ M D ( - 2 , 4 4 0 ’ T V D S S ) — a si g n i f i c a n t h y d r o c a r b o n -b e a r i n g i n t e r v a l — is n o t c e m e n t is o l a t e d . Su r f a c e c a s i n g ( 1 3 - 3 / 8 ” ) w a s s e t a t 2 , 5 0 2 ’ M D ( - 2, 1 7 2 ’ T V D S S ) an d c e m e n t e d w i t h f u l l r e t u r n s ( a n o p e r a t o r e m a i l da t e d 8/ 1 4 / 2 0 2 3 i n d i c a t e s c em e n t r e t u r n s w e r e o b s e r v e d a t su r f a c e ). R e t u r n s r e p o r t e d l y co n s i s t e d o f 7 0 b a r r e l s o f co n t a m i n a t e d c e m e n t a n d 7 0 b a r r e l s o f g o o d c e m e n t . Th e se c o n d p l u g b u m p e d a n d f l o a t s h e l d . In t e r m e d i a t e c a s i n g ( 9 - 5/ 8 ” ) w a s s e t a t 6 , 2 3 7 ’ M D ( - 4 , 9 4 9 ’ T V D S S ) an d c e m e n t e d . Op e r a t o r e m a i l d a t e d 8 / 1 1 / 2 0 2 3 i n d i c a t e s t h e 9 - 5/ 8 ” c e m e n t jo b w e n t w e l l : f u l l r e t u r n s t h r o u g h o u t t h e j o b , b u m p e d t h e 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 7 A p r i l , 2 0 2 4 pl u g o n s t r o k e s w i t h g o o d l i f t p r e s s u r e , a n d c i r c u l a t e d s p a c e r of f t h e t o p o f t h e l i n e r . A f t e r c i r c u l a t i n g o n t o p o f t h e l i n e r re t u r n e d a p p r o x i m a t e l y 9 5 b b l s o f s p a c e r i n d i c a t i n g t h e T O C sh o u l d b e v e r y c l o s e t o t h e T O L a t 2 , 4 4 1 ’ M D ( - 2, 1 3 1 ’ T V D S S ) . Lo g ev a l u a t i o n f r o m A O G C C ’ s in d e p e n d e n t c e m e n t e x p e r t o f th e HE S C A S T a n d B a k e r C B L c e m e n t e v a l u a t i o n l o g s in d i c a t e s 9- 5/ 8 ” i n t e r m e d i a t e l i n e r i s c e m e n t e d ac r o s s t h e T u l u v a k S a n d s f r o m 2 , 8 9 4 ’ t o 3 , 7 8 0 ’ M D ( - 2 , 4 4 1 ’ t o - 3, 0 5 2 ’ T V D S S ) wi t h p a t c h y / p o o r a n d p a t c h y / mo d e r a t e c e m e n t f r o m 2 , 8 9 0 ’ t o 3 , 2 5 0 ’ M D , f a i r t o m o d e r a t e c e m e n t f r o m 3 , 2 5 0 ’ t o 3 , 3 4 0 ’ MD , p a t c h y / p o o r c e m e n t f r o m 3 , 3 4 0 ’ t o 3 , 4 3 0 ’ M D , a n d mo d e r a t e t o f a i r c e m e n t f r o m 3 , 4 3 0 ’ t o 3 , 7 8 0 ’ M D . L o g ev a l u a t i o n f r o m AO G C C ’ s i n d e p e n d e n t c e m e n t e x p e r t of t h e HE S C A S T c e m e n t e v a l u a t i o n t o o l r e p o r t s f a i r to g o o d b o n d fr o m 4 , 5 5 0 ’ M D t o 4, 7 2 0 ’ M D , f a i r t o m o d e r a t e c e m e n t f r o m 4, 7 2 0 ’ t o 4 , 9 5 0 ’ M D , a n d g o o d c e m e n t f r o m 4 , 9 5 0 ’ to 5 , 7 3 0 ’ MD . T h e t o p o f t h e N a n u s h u k f o r m a t i o n l i e s a t 4 , 9 5 5 ’ M D ( - 3 , 7 9 6 ’ T V D S S ) , a n d t h e t o p o f t h e c u r r e n t r e s e r v o i r l i e s a t 6, 8 3 0 ’ M D ( - 4 , 2 8 1 ’ T V D S S ) . So , t h e N a n u s h u k i s a d e q u a t e l y is o l a t e d f r o m o v e r l y i n g s t r a t a . (a ) ( 1 1 ) F a u l t s a n d f r a c t u r e s , L o c a t i o n , or i e n t a t i o n (a ) ( 1 1 ) F a u l t s a n d f r a c t u r e s , S u f f i c i e n t in f o r m a t i o n t o d e t e r m i n e n o i n t e r f e r e n c e wi t h c o n t a i n m e n t w i t h i n ½ m i l e Th r e e f a u l t s ; n o n e w i l l i n t e r f e r e w i t h c o n t a i n m e n t . Th e o p e r a t o r h a s i d e n t i f i e d th r e e f a u l t s i n se i s m i c d a t a w i t h i n a ½ - m i l e r a d i u s o f N D B - 0 3 0 . Fa u l t 1 , w h i c h l i e s 1 0 1 5 ’ f r o m ND B -03 0 , i s r e s t r i c t e d t o t h e N a n u s h u k , a n d d o e s n o t pe n e t r a t e t h e o v e r l y i n g c o n f i n i n g i n t e r v a l . F a u l t 2 , w h i c h l i e s ab o u t 1 , 4 0 0 ’ f r o m t h e N D B -03 0 f r a c t u r i n g i n t e r v a l i s a l o w co n f i d e n c e f a u l t t h a t l i e s w i t h i n t h e T u l u v a k a n d do e s n o t pe n e t r a t e t h e u n d e r l y i n g N a n u s h u k r e s e r v o i r . F a u l t 3 , w h i c h li e s a b o u t 2 , 0 0 0 ’ f r o m t h e f r a c t u r i n g i nt e r v a l i n N D B - 03 0 , i s al s o a l o w c o n f i d e n c e f a u l t t h a t i s r e s t r i c t e d t o t h e T u l u v a k an d d o e s n o t p e n e t r a t e t h e N a n u s h u k . It i s u n l i k e l y t h a t a n y SF D 4/ 2 5 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 8 A p r i l , 2 0 2 4 fa u l t s w i l l i n t e r f e r e w i t h c o n t a i n m e n t o f t h e i n j e c t e d fr a c t u r i n g f l u i d s ; h o w e v e r , i f t h e r e a r e i n d i c a t i o n s t h a t a fr a c t u r e h a s i n t e r s e c t e d a f a u l t o r n a t u r a l -fr a c t u r e i n t e r v a l du r i n g f r a c o p e r a t i o n s , t h e o p e r a t o r w i l l g o t o f l u s h a n d te r m i n a t e t h e s t a g e i m m e d i a t e l y . (a ) ( 1 2 ) P r o p o s e d p r o g r a m f o r f r a c t u r i n g op e r a t i o n Pr o v i d e d w i t h ap p l i c a t i o n . CD W 4/ 2 3 / 2 4 (a ) ( 1 2 ) ( A ) E s t i m a t e d v o l u m e P r o v i d e d w i t h a p p l i c a t i o n . 1 9 7 4 5 b b l t o t a l d i r t y v o l . 2 . 5 M l b to t a l p r o p p a n t CD W 4/ 2 3 / 2 4 (a ) ( 1 2 ) ( B ) A d d i t i v e s : n a m e s , p u r p o s e s , co n c e n t r a t i o n s Pr o v i d e d w i t h a p p l i c a t i o n . CD W 4/ 2 3 / 2 4 (a ) ( 1 2 ) ( C ) C h e m i c a l n a m e a n d C A S nu m b e r o f e a c h Pr o v i d e d w i t h a p p l i c a t i o n . S c h l u m b e r g e r d i s c l o s u r e pr o v i d e d . CD W 4/ 2 3 / 2 4 (a ) ( 1 2 ) ( D ) I n e r t s u b s t a n c e s , w e i g h t o r vo l u m e o f e a c h Pr o v i d e d w i t h a p p l i c a t i o n . CD W 4/ 2 3 / 2 4 (a ) ( 1 2 ) ( E ) M a x i m u m t r e a t i n g p r e s s u r e w i t h su p p o r t i n g i n f o t o d e t e r m i n e ap p r o p r i a t e n e s s f o r p r o g r a m S i m u l a t i o n s h o w s m a x s u r f a c e p r e s s u r e 6 6 3 6 p s i . M a x . 89 00 p s i a l l o w a b l e t r e a t i n g p r e s s u r e . M a x p r e s s u r e i s 7 4 00 ps i t o 83 0 0 p s i t o P u m p s h u t d o w n . W i t h 3 5 0 0 p s i b a c k pr e s s u r e I A ( I A p o p o f f s e t 37 0 0 ps i ) , m a x t u b i n g d i f f e r e n t i a l s h o u l d b e 5 4 0 0 p s i . CD W 4/ 2 3 / 2 4 (a ) ( 1 2 ) ( F ) F r a c t u r e s – he i g h t , l e n g t h , M D an d T V D t o t o p , d e s c r i p t i o n o f f r a c t u r i n g mo d e l Pr o v i d e d w i t h a p p l i c a t i o n . T h e a n t i c i p a t e d h a l f - l e n g t h s o f th e 11 s t a g e s o f i n d u c e d f r a c t u r e s ra n g e f r o m 3 2 0 ’ t o 3 9 0 ’ ac c o r d i n g t o t h e O p e r a t o r ’ s c o m p u t e r s i m u l a t i o n . C o m p u t e r si m u l a t i o n i n d i c a t e s t h e a n t i c i p a t e d h e i g h t o f t h e i n d u c e d f r a c t u r e s w i l l b e 22 5 t o 2 4 0 t r u e v e r t i c a l f e e t . T h e sh a l l o w e s t fr a c t u r e - t o p T V D i s e x p e c t e d t o b e a b o u t 4 , 1 4 4 ’ , wh i c h l i e s we l l w i t h i n t h e N a n u s h u k F o r m a t i o n . S o , i n d u c e d f r a c t u r e s w i l l l i k e l y p e n e t r a t e i n t o , b u t n o t t h r o u g h , t h e o v e r l y i n g co n f i n i n g i n t e r v a l t h a t i s a b o u t 9 0 0 ’ t h i c k i n t h i s a r e a . SF D 4/ 2 3 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 9 A p r i l , 2 0 2 4 (a ) ( 1 3 ) P r o p o s e d p r o g r a m f o r p o s t - fr a c t u r i n g w e l l c l e a n u p a n d f l u i d r e c o v e r y We l l c l e a n o u t a n d f l o w b a c k p r o c e d u r e p r o v i d e d w i t h ap p l i c a t i o n . N o d i s p o s a l i d e n t i f i e d CD W 4/ 2 3 / 2 4 (b ) T e s t i n g o f c a s i n g or in t e r m e d i a t e ca s i n g Te s t e d > 1 1 0 % o f m a x a n t i c i p a t e d p r e s s u r e 35 00 p s i b a c k p r e s s u r e , p l a n t o t e s t t o 4 0 0 0 ps i , p o p o f f s e t as 37 0 0 p s i CD W 4/ 2 3 / 2 4 (c ) F r a c t u r i n g s t r i n g ( c ) ( 1 ) P a c k e r > 1 0 0 ’ b e l o w T O C o f pr o d u c t i o n o r i n t e r m e d i a t e c a s i n g 4. 5 ” t u b i n g w i l l b e a n c h o r e d w i t h a p a c k e r s e t a t a p p r o x . . 11 0 5 0 f t w i t h h e e l p a c k e r a t 1 1 3 7 5 f t . 9- 5/ 8 ” c a s i n g s e t a t 1 1 2 0 1 f t . T O C 99 5 0 f t . B a k e r S o un d T r a k ru n a n d s h o w s p a r t i a l t o p o o r s t a r t i n g a t 9 9 4 9 f t w i t h t h e o n l y g o o d c e m e n t m e n t i o n e d f r o m 1 0 4 5 8 t o 1 0 4 9 1 f t a n d 10 8 6 8 - 1 0 8 8 2 f t . A r e a o r i n t e r e s t h a s s o m e c e m e n t , f r a c zo n e i s i s o l a t e d . CD W 4/ 2 3 / 2 4 ( c ) ( 2 ) T e s t e d > 1 1 0 % o f m a x a n t i c i p a t e d pr e s s u r e d i f f e r e n t i a l Tu b i n g t e s t o f 6 0 0 0 p s i . M a x p r e s s u r e d i f f e r e n t i a l i s es t i m a t e d a s 54 0 0 p s i ( 8 9 0 0 w i t h 3 5 0 0 ps i b a c k p r e s s u r e ) s o t e s t o f 6 0 0 0 p s i s a t i s f i e s 1 1 0 % CD W 4/ 2 3 / 2 4 (d ) P r e s s u r e r e l i e f va l v e Li n e p r e s s u r e < = t e s t p r e s s u r e , r e m o t e l y co n t r o l l e d s h u t - i n d e v i c e 90 0 0 p s i l i n e p r e s s u r e t e s t , p u m p k n o c k o u t 7 4 0 0 p s i w i t h ma x . g l o b a l k i c k o u t 8 3 0 0 p s i . I A P R V s e t a s 3 7 0 0 p s i . CD W 4/ 2 3 / 2 4 (e ) C o n f i n e m e n t Fr a c f l u i d s c o n f i n e d t o a p p r o v e d fo r m a t i o n s Pr o v i d e d w i t h a p p l i c a t i o n . CD W 4/ 2 3 / 2 4 (f ) S u r f a c e c a s i n g pr e s s u r e s Mo n i t o r e d w i t h g a u g e a n d p r e s s u r e r e l i e f de v i c e I A P R V s e t a t 3 7 0 0 p s i . S u r f a c e a nn u l u s o p e n . F r a c p r e s s u r e s co n t i n u o u s l y m o n i t o r e d . CD W 4/ 2 3 / 2 4 (g ) A n n u l u s pr e s s u r e mo n i t o r i n g & no t i f i c a t i o n 50 0 p s i c r i t e r i a Du r i n g h y d r a u l i c f r a c t u r i n g o p e r a t i o n s , a l l a n n u l u s p r e s s u r e s mu s t b e c o n t i n u o u s l y m o n i t o r e d a n d r e c o r d e d . I f a t a n y ti m e d u r i n g h y d r a u l i c f r a c t u r i n g o p e r a t i o n s t h e a n n u l u s pr e s s u r e i n c r e a s e s m o r e t h a n 50 0 p s i g a b o v e t h o s e an t i c i p a t e d i n c r e a s e s c a u s e d b y p r e s s u r e o r t h e r m a l tr a n s f e r , t h e o p e r a t o r s h a l l : CD W 4/ 2 3 / 2 4 (g ) ( 1 ) N o t i f y A O G C C w i t h i n 2 4 h o u r s (g ) ( 2 ) C o r r e c t i v e a c t i o n o r s u r v e i l l a n c e (g ) ( 3 ) S u n d r y t o A O G C C 20 A A C 2 5 . 2 8 3 H y d r au l i c F r a c t u r i n g A p p l i c a t i o n – C h e c k l i s t Pi k k a N D B - 0 3 0 (P T D N o . 2 2 3 - 1 2 0 ; S u n d r y N o . 3 2 4 - 2 1 2 ) Pa r a g r a p h Su b - P a r a g r a p h Se c t i o n Co m p l e t e ? AO G C C P a g e 1 0 A p r i l , 2 0 2 4 (h ) S u n d r y R e p o r t (i ) R e p o r t i n g (i ) ( 1 ) F r a c F o c u s R e p o r t i n g (i ) ( 2 ) A O G C C R e p o r t i n g : p r i n t e d & el e c t r o n i c (j ) P o s t - f r a c w a t e r sa m p l i n g p l a n No t r e q u i r e d ( s e e S e c t i o n ( a ) ( 3 ) , a b o v e ) . SF D 4/ 2 2 / 2 0 2 4 (k ) C o n f i d e n t i a l in f o r m a t i o n Cl e a r l y m a r k e d a n d s p e c i f i c f a c t s su p p o r t i n g n o n d i s c l o s u r e N o t a p p l i c a b l e . SF D 4/ 2 2 / 2 0 2 4 (l ) V a r i a n c e s re q u e s t e d Mo d i f i c a t i o n s o f d e a d l i n e s , r e q u e s t s f o r va r i a n c e s o r w a i v e r s No p l a n f o r p o s t f r a c t u r e w a t e r w e l l a n a l y s i s . C o m m i s s i o n m a y r e q u i r e t h i s d e p e n d i n g o n p e r f o r m a n c e o f t h e f r a c t u r i n g o p e r a t i o n. 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. You don't often get email from rob.o'neal@contractor.santos.com. Learn why this is important From:Brooks, Phoebe L (OGC) To:O"Neal, Robert (Rob) Cc:Regg, James B (OGC) Subject:RE: BOP test Parker 272 NDBi-030, 2-22-2024 Date:Thursday, March 21, 2024 11:44:27 AM Attachments:Parker 272 02-22-24 Revised.xlsx image001.png Rob, Attached is a revised report changing the MASP to reflect 1497 and correcting some formatting. Please review and update your copy or let me know if you disagree. Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation 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: O'Neal, Robert (Rob) <Rob.O'Neal@contractor.santos.com> Sent: Friday, February 23, 2024 1:36 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Subject: BOP test Parker 272 NDBi-030, 2-22-2024 Please see attached with correct permit number format and let us know if anything needs to be corrected. Robert O’Neal (Rob) Drilling Well Site Supervisor, Parker 272 Alternate John Whitlatch o: +1 907-685-4230 | m: +1 907-268-0648 | e: rob.o’neal@contractor.santos.com Pikka NDB-30 PTD 2231200 J. Regg; 4/1/2024 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:272 DATE:2/22/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231200 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:X Weekly:Bi-Weekly:Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1497 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 2 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13-5/8" 5M P Pit Level Indicators P P #1 Rams 1 4-1/2 x 7" VBR P Flow Indicator P P #2 Rams 1 Blind/Shear P Meth Gas Detector P P #3 Rams 1 9 5/8" FBR P H2S Gas Detector P P #4 Rams 0 N/A NA MS Misc 0 NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3-1/8 P Time/Pressure Test Result HCR Valves 2 3-1/8 P System Pressure (psi)3000 P Kill Line Valves 2 2-1/16" 3-1/8"P Pressure After Closure (psi)2075 P Check Valve 0 N/A NA 200 psi Attained (sec)20 P BOP Misc 0 N/A NA Full Pressure Attained (sec)68 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):14@2100 P No. Valves 15 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 17 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 6 P Inside Reel valves 0 NA #3 Rams 6 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:5.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 02/20/2024 0543hrs Waived By Test Start Date/Time:2/22/2024 2:00 (date)(time)Witness Test Finish Date/Time:2/22/2024 7:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Parker Tested with 5 7/8" and 9 5/8" test Joints Sonny Clark Oil Search (Alaska) LLC Rowland Lawson Pikka NDBi-030 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)2024-0222_BOP_Parker272_Pikka_NDB-30 J.Regg; 4/1/2024 Test Chart attached (jbr; 4/1/2024) 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: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 22.84 BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: ADL 392984, 391445, 393020, 393019, 393018 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, Image, Mudlogs 23. BOTTOM 20"x34" X-52 54' 13-3/8" L-80 2,262' 9-5/8" L-80 4,105' Tieback L-80 2,153' 4-1/2" P-110S 4,141' 4-1/2" P-110S 4,065' 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 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, N/ATieback TUBING RECORD N/A 11,051' 17,522' See attached cement rpt 4,056' Surface 12-1/4" 8-1/2" 17,522'4-1/2" N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil Search Alaska, LLC WAG Gas 03/26/24 223-120 50-103-20873-00-00 NDBi-0302377 FSL, 3091 FEL, S4, T11N, R6E, UM 3032 FSL, 3003 FEL, S30, T12N, R6E, UM LONS 19-003 02/27/24 17,529' MD / 4,141' TVD N/A 900 E Benson Boulevard, Suite 500, Anchorage, AK 99508 422,153.87 5,972,761.56 2947 FSL, 5113 FEL, S32, T12N, R6E, UM CASING WT. PER FT.GRADE 03/22/24 CEMENTING RECORD 5,978,689.10 1,367' MD / 1,344' TVD SETTING DEPTH TVD 5,984,090.56 TOP HOLE SIZE AMOUNT PULLED 414,899.09 411,771.34 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 SIZE DEPTH SET (MD) See attached packer rpt PACKER SET (MD/TVD) 12.6# 11,015' Surface 42" 12.6# Tubing 16" Grouted to surface Surface See attached cement rpt 47# Surface Surface 2,550'Surface Surface 47# 2,368' 2,153' Surface 215# 68# 128' 2,368' 11,201' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information Sr Res EngSr Pet GeoSr Pet Eng Pikka/Nanushuk Oil Pool N/A Oil-Bbl: Water-Bbl: Water-Bbl: PRODUCTION TEST Date of Test: Oil-Bbl: Flow Tubing G s d 1 0 p d P L (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 8:22 am, Apr 11, 2024 Completed 3/26/2024 JSB RBDMS JSB 041924 G DSR-5/1/24 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface 1415 1389 Top of Productive Interval 11280 4127 1048 1039 Middle Schrader Bluff 1835 1758 MCU 2334 2131 Tuluvak Shale 2898 2437 Tuluvak Sand 3062 2498 TS 790 4660 2822 Seabee 6148 3103 Nanushuk 9653 3775 NT7 MFS 10240 3886 NT6 MFS 10510 3939 NT5 MFS 10693 3978 NT4 MFS 10895 4025 NT3 MFS 11168 4096 NT3.2 Top Reservoir 11280 4127 NT 3.24 11593 4175 NT 3.23 12788 4167 31. List of Attachments: Summary of Daily Operations, Cement Reports, Directional Survey, Schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Garret Staudinger Digital Signature with Date:Contact Email:garret.staudinger@santos.com Contact Phone: 907-440-6892 Authorized Title: Senior Drilling Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 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. 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS 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. Formation Name at TD: TPI (Top of Producing Interval). Authorized Name and INSTRUCTIONS NT3.2 Top Reservoir 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. Upper Schrader Bluff 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. N No Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov regoing is true and correct to the best of m Ei NDBi-030 Well Schematic 20" Insulated Conductor80' MD 9-5/8" Liner Hanger and Liner Top Packer2367' MD 13-3/8" 68 ppf L-80 Surface Casing2550' MD 9-5/8", 47ppf L-80 Production Liner 11201' MD 4-½” x 9-5/8” Liner Hanger and Liner Top Packer 11014' MD Archer C-Flex Two-Stage Cementing Tool 4712' MD TOC First Stage Cement Job9950' MD 03.28.2024 16" Hole Size 12-1/4" Hole Size 9-5/8" Tieback and Seal Assembly2367' MD GL 1 2 3 4 5 6 7 8 8-½” Openhole 17,529' MD 4-½”, 12.6ppf P-110S Production Liner 17,522' MD 9 46.4' RKB – Bottom Flange #CompletionItem TopDepth(MD') Depth(TVD') Inc ID" OD" 1XLandingNipple 1520 1486 25 3.813 4.790 2GasliftMandrel1.5" 2156 2007 43 3.865 7.650 3XLandingNipple 2226 2057 45 3.813 4.790 4XLandingNipple 10861 4017 76 3.813 4.790 5D/HPsiͲTempGauge 10924 4033 75 3.905 6.000 6XLandingNipple 10946 4038 75 3.813 4.776 7TiebackSealAssy 11050 4065 75 3.860 5.230 89.625"x4.5"LH/Packer 11014 4056 75 6.040 8.420 9#13OpenholePacker 11308 4134 76 3.910 8.000 10 #12OpenholePacker 11375 4148 79 3.911 8.000 11 Stage11ͲFracSleeve 11648 4176 89 3.735 5.630 12 #11OpenholePacker 11836 4176 90 3.918 8.000 13 Stage10ͲFracSleeve 12111 4174 90 3.735 5.629 14 #10OpenholePacker 12382 4171 90 3.912 8.000 15 Stage9ͲFracSleeve 12652 4169 90 3.735 5.632 16 #9OpenholePacker 12838 4166 90 3.913 8.000 17 Stage8ͲFracSleeve 13228 4164 90 3.735 5.630 18 #8OpenholePacker 13453 4164 90 3.912 8.000 19 Stage7ͲFracSleeve 13727 4163 90 3.735 5.635 20 #7OpenholePacker 14039 4161 90 3.912 8.000 21 Stage6ͲFracSleeve 14308 4161 90 3.735 5.632 22 #6OpenholePacker 14658 4160 90 3.918 8.000 23 Stage5ͲFracSleeve 14889 4159 90 3.735 5.635 24 #5OpenholePacker 15242 4159 90 3.918 8.000 25 Stage4ͲFracSleeve 15474 4157 90 3.735 5.630 26 #4OpenholePacker 15744 4155 90 3.918 8.000 27 Stage3ͲFracSleeve 16059 4152 90 3.735 5.632 28 #3OpenholePacker 16370 4150 90 3.918 8.000 29 Stage2ͲFracSleeve 16638 4148 90 3.735 5.632 30 #2OpenholePacker 16949 4145 90 3.918 8.000 31 Stage1ͲFracSleeve 17220 4144 90 3.735 5.634 32 #1OpenholePacker 17326 4143 90 3.898 8.000 33 #2ToeSleeve 17434 4142 90 3.500 5.750 34 #1ToeSleeve 17446 4142 90 3.500 5.750 35 WIVCollar 17508 4141 90 0.870 5.200 36 Eccentricshoe 17521 4141 90 3.900 5.200 Page 1 of 1 Well Name: NDBi-030 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) SLZXP Liner Top Hanger Packer 11,036.6 4,061.4 OH Packer #13 11,314.4 4,135.3 OH Packer #12 11,382.0 4,149.6 OH Packer #11 11,842.8 4,175.5 OH Packer #10 12,388.3 4,171.0 OH Packer #9 12,844.2 4,166.2 OH Packer #8 13,460.0 4,163.6 OH Packer #7 14,045.4 4,161.5 OH Packer #6 14,664.8 4,159.6 OH Packer #5 15,249.2 4,158.5 OH Packer #4 15,751.3 4,154.5 OH Packer #3 16,376.6 4,149.7 OH Packer #2 16,955.3 4,145.4 OH Packer #1 17,332.9 4,142.7 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 2/15/2024 2/16/2024 0 No accidents, incidents or spills. Rig release from NDBi-014 at 0300 hrs Continue with preparing for rig move to NDBi-030. Lay derrick over. Unplug, split and move complexes. Spot complexes together, shim as needed. Work on interconnects, plug in modules. 2/16/2024 2/17/2024 0 10.00 No accidents, incidents or spills. Raise Derrick 505k off stand. Skid rig floor. Bridle down. Install mud line on rig floor and Derrick interconnect. Accept Rig for operations on NDBi-030 at 09:00 hrs. N/U 21 ¼” Riser, Diverter spool w/ 16” knife valve. RU Risers. Conduct Divert Function Test. Slip and Cut drill line. Mobilize BHA equipment to rig floor. 2/17/2024 2/18/2024 128 476.00 10.00 No accidents, incidents or spills. Conduct Rig Evacuation Drill. MU 16” Surface BHA #1. Drill out conductor with 16” Surface BHA from 125' to 135'. POH P/U Remaining BHA. Drill 16” Intermediate hole from 210’ md to 604’ md (603' TVD). 2/18/2024 2/19/2024 604 1,585.00 10.05 No accidents, incidents or spills. Drill 16” Surface hole from 604’ to 1,810' md. Circulate B/U 2X. POH on elevators from 1,517’ to 865’. RIH no hole problems encountered. Drill 16” Surface hole from 1,810’ to 2,189’ md. 2/19/2024 2/20/2024 2,189 368.00 10.00 No accidents, incidents or spills. Drill 16” Surface hole from 2,189’ md to 2,557' md. CBU 2x Racking back std every B/U. Backream out of hole from 2,375’ to 1,615’ md. POH on elevators from 1,615’ to BHA. -Lay down BHA. Rig up casing handling equipment. Run 13-3/8” 68# L-80 BTC Casing to 180’ md. 2/20/2024 2/21/2024 2,557 0.00 10.00 No accidents, incidents or spills. Run 13-3/8” 68# L-80 BTC Surface Casing from 180’ to 2,546’ md. Condition wellbore for cement job. Cement 13-3/8” Surface Casing. Break out landing joint and lay down. Jet Diverter body, drain stack and clean cement out of cellar. ***24-hr BOP Test notice given to AOGCC at 0545 hrs on 2/20/2024*** 2/21/2024 2/22/2024 2,557 0.00 10.00 No accidents, incidents or spills. Begin ND of flanges for Diverter System. Wait on weather. N/D the annular, diverter T with the knife valve and risers. Install FMC 13-3/8” 5k Gen 5 Wellhead. NU BOP. 2/22/2024 2/23/2024 2,557 27.00 10.00 No accidents, incidents or spills. Conducted BOP Test with no issues, good test; witness waived due to Phase 3 travel conditions across Kuparuk field. Conducted 13-3/8” Casing pressure test to 2600 psi for 30-min, good test. Displaced to 12.0 MOBM, drilled out shoe track and new formation. Conducted LOT, 14.5 ppg EMW. Make up BHA #2. Run in hole and wash down the top plug at 2459'. 2/23/2024 2/24/2024 2,584 2,665.00 12.00 No accidents, incidents or spills. Drill ahead Directionally in 12-1/4” Intermediate hole section from 2577’ to 5249’. 2/24/2024 2/25/2024 5,249 2,573.00 12.00 No accidents, incidents or spills. Drill ahead Directionally in 12-1/4” Intermediate hole section from 5249’ to 7822’. 2/25/2024 2/26/2024 7,822 2,680.00 12.00 No accidents, incidents or spills. Drill ahead Directionally in 12-1/4” Intermediate hole section from 7822’ to 10,502’. 2/26/2024 2/27/2024 10,502 702.00 12.00 No accidents, incidents or spills. Drill ahead Directionally in 12-1/4” Intermediate hole section from 10,502’ to TD of 11,204’. Conduct Bottoms up cleanup cycles. Backream per plan. 2/27/2024 2/28/2024 11,204 0.00 12.10 No accidents, incidents or spills. Backream from 9390' to 7910’ MD. Adjust parameters as needed to mitigate packoffs. 2/28/2024 2/29/2024 11,204 0.00 12.10 No accidents, incidents or spills. Backream per plan from 7910’ to 5640’ MD. Adjust parameters as needed to mitigate packoffs. 2/29/2024 3/1/2024 11,204 0.00 12.10 No accidents, incidents or spills. Backream and pump out per plan from 5640’ to 2510’, circulate to clean up casing. Run in Hole in 500’ increments, conduct minimum of 2x bottoms up for cleanup cycle. Well Name Wellbore Name PTD # Start Drill Date End Drill Date Page 1 of 4 Well Name NDBi-030 Wellbore Name Original Hole PTD # 223-120 Start Drill Date 4/1/2023 End Drill Date 3/27/2024 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 3/1/2024 3/2/2024 11,204 0.00 12.00 No accidents, incidents or spills. Run in Hole in 500'-1000’ increments conducting cleanup cycles from 2993' to 7550'. 3/2/2024 3/3/2024 11,204 0.00 12.10 No accidents, incidents or spills. Run in Hole to 8690’, conduct cleanup cycle. Run in Hole on elevators to bottom. Circulate 5x BU, pump out of hole to casing shoe at 2 bpm. CBU 2x, POOH and Lay Down BHA. 3/3/2024 3/4/2024 11,204 0.00 12.10 No accidents, incidents or spills. Circulate bottoms up 2x, POOH and Lay Down BHA. Clear rig floor, prep for running 9-5/8” casing. Pick up and run 9-5/8” casing per running order to 4840’ MD. 3/4/2024 3/5/2024 11,204 0.00 12.15 No accidents, incidents or spills. Tested the fire alarm system in the camp and performed an evacuation drill. Occurred at 15:00, 7 minutes to perform evacuation, camp sweep and roll call. Run 9-5/8" Casing from 4840' MD to 11,204' MD. R/U Baker cement head. Circulate to condition well. 3/5/2024 3/6/2024 11,204 0.00 12.15 No accidents, incidents or spills. Finished circulating a bottoms up at 11,201’. Set Baker Flexlock IV Liner Top Hanger, verify set, release from hanger, shear ball seat and confirm release. Begin 1st stage 9-5/8” liner cement job. Pumped 80 bbls of 12.5 ppg Tuned Spacer followed by 15.3 ppg Versacem Tail Cement. 56.78 bbls into the job, observed drill pipe wiper plug latch into liner plug on calculated strokes but did not release. After multiple attempts to release, continued to pressure up and observed bypass shear at 4650 PSI. Continue pumping planned 206 bbls of cement, drop 2nd drill pipe wiper dart and begin displacing with 12.1 ppg MOBM. 482 bbls into displacement when the lower plug reached the float collar the pressure increased to 3580 PSI. Suspect top plug launched with bottom plug, leaving 206 bbls of cement in the liner. Pull liner running tool out of the liner top and circulate the drill pipe clean. POOH and M/U 8-½" cleanout BHA to 872’. TIH from 872’ to 7,030’. 3/6/2024 3/7/2024 11,204 0.00 12.05 No accidents, incidents or spills. RIH with 8-1/2" Clean out assembly on 5-7/8” DP from 7,030’ to 7,797’. Wash/ream cement stringers from 7,797’ to 7,875’. Drill soft cement from 7,875’ to 8,597’. Drill hard cement from 8,597’ to 9,808’. 3/7/2024 3/8/2024 11,204 0.00 12.10 No accidents, incidents or spills. Drill hard cement from 9,808’ to 10,915’. Circulate until shakers are clean. POOH on elevators from 10,720’ to surface & LD BHA. RU to test BOPE. 3/8/2024 3/9/2024 11,204 0.00 12.10 No accidents, incidents or spills. Test BOPE to 250 psi low, 3,500 psi high for 5 minutes each. Test with 5” and 9-5/8” test joints, test annular with 5” test joint. Test HCR choke & Kill, & manual valves, test choke valves to 250 psi low, 3,500 psi high. All tests charted, see attached BOP test charts. Conduct accumulator draw down test. Test witnessed by AOGCC Rep Guy Cook. Cut and slip drill line. Change Saver Sub. Perform Derrick inspection, Service and inspect Top drive. P/U & RIH with 8-1/2" Cleanout BHA #4 from surface to 10,885'. Rig Service. 3/9/2024 3/10/2024 11,204 0.00 11.90 No accidents, incidents or spills. Wash down from 10,885’ to 10,915’. Drill out cement from 10,915’ to 11,121’. Circulate the hole clean to lower ECD. Drill out cement from 11,121’ to 11,127’ then plugs from 11,127’ to 11,129’. Drill out float collar from 11,129’ to 11,131’. Wash down from 11,139’ and tag top of float shoe at 11,199’. POOH from 11,077’ to 2,367’ on elevators. Circulate bottoms up twice. Pull on elevators from 2,367’ to 902’. LD Clean out BHA. 3/10/2024 3/11/2024 11,204 0.00 11.90 No accidents, incidents or spills. Make up & RIH with Halliburton FAS-Drill Packer from surface to set depth at 11,160’ MD. Attempt to establish circulation through the cement retainer and up the 9-5/8” x 12-1/4" OH annulus. Page 2 of 4 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 3/11/2024 3/12/2024 11,204 0.00 11.95 No accidents, incidents or spills. Continue to establish circulation through the cement retainer and up the 9-5/8” x 12-¼" OH annulus. Slowly increasing pump rate at 1 stroke/min increments as pressure allows. M/U Cement Hose to cement head. Cement 9-5/8” Liner thru Halliburton Fast drill Cement retainer. Pump 77.8 bbls of 12.5 ppg Tuned spacer at 2.5 BPM, 950 psi. (pumped 10 bbls water & 77.5 bbls spacer got back 71.3 bbls). Pump 205 bbls of 15.3 ppg Versacem Tail cement. Flush lines with 10 bbls water from Halliburton. Displace with rig pumps 177.8 bbls 12.0 ppg MOBM as follows: Pumped 85 bbls at 2.5 BPM. ICP 425 PSI, FCP 733 PSI. Pumped 18 bbls at 2 BPM. ICP 645 PSI, FCP 667 PSI. Pumped 47 bbls at 1 BPM. ICP 464 PSI, FCP 560 PSI. Pumped 26 bbls at 0.5 BPM. ICP 411 PSI. FCP 513 PSI. Lost 110 bbls after cement entered annulus. (200 bbls total for job). Sting out of cement retainer. Circulate 1.5 times bottoms up. 3/12/2024 3/13/2024 11,204 0.00 11.95 No accidents, incidents or spills. POOH on elevators from 10,842’ to 10,492’. MU & RIH with Archer Cement tool to 2,627'. MU Baker rotating dog sub. Continue RIH to 4,725’. Latch into Archer cement tool. Circulate and condition mud prior to 2nd Stage Cement Job. 3/13/2024 3/14/2024 11,204 0.00 11.95 No accidents, incidents or spills. Latch onto C-Flex & shift open. Circulate bottoms up through C-Flex tool. Pump 2nd Stage 9-5/8” Liner Cement as follows: Pump 80 BBLS of 12.5 ppg Mud-Flush spacer @ 3-4 BPM, ICP 290 PSI, FCP 190 PSI. Pump 78 BBLS of 13.5 ppg Tuned Spacer @ 3-4 BPM, ICP 240 PSI, FCP 202 PSI. No losses while pumping spacers. Pump 252 BBLS of 15.3 ppg tail cement VERSACEM @ 3-4 BPM. 100% excess volume. No Losses. Flush Lines with 10 bbls fresh water from Halliburton unit. 3.7 bpm, 237 psi. Displace Cement to Archer stage tool with 64 bbls of 12.0 ppg MOBM, at 4.0 bpm. ICP 400 psi. slowed to 3 bpm 475 psi for last 10 bbls. FCP 465 psi. 26 bbls lost to hole during displacement. CIP @ 07:53 hrs. Close Cflex tool and set Liner top Packer. Circulate out 50 bbls cement. POOH with Archer cement tool and Baker Rotating dog sub. MU & RIH with polish mill BHA #5. Polish liner top at 2,368'. Circulate 2 bottoms up. POOH on elevators from 2,368’ to surface. RIH on elevators from surface to 962’ with Baker Polish mill assembly. 3/14/2024 3/15/2024 11,204 0.00 11.90 No accidents, incidents or spills. RIH with Baker Polish mill assembly. Polish liner top at 2,372’. Circulate hole clean. POOH & LD Polish assembly. RU & Run 9-5/8” Tie back to 2,256’. Space Out to land Tie back string. Freeze Protect OA. Land casing hanger. Test 13-3/8” x 9-5/8” OA to 2,600 psi for 30 min, good test. Set and test 9-5/8” Pack off to 5,000 PSI for 15 mins, good test. Test 9-5/8” casing to 3,500 psi for 30 min. record on chart. Pump 11 bbls of 12 ppg MOBM. Pressure Start: 3,701 PSI. Pressure at 15 mins: 3,670 PSI. Pressure at 30 mins: 3,665 PSI. Test approved by Santos WSS J. Whitlatch. Run and set wear ring. Make up 8-1/2” clean out/logging BHA. 3/15/2024 3/16/2024 11,204 46.00 10.10 No accidents, incidents or spills. --AOGCC notified of planned BOPE test at 05:00. RIH on elevators with Baker cleanout/logging BHA. Clean out cement, Drill Fas-Drill composite retainer. Drill retainer and cement from 11,160’ to 11,165. Circulate and condition mud. Displace well to 10.0 ppg Versapro. Drill out shoe track and 20’ of new hole from 11,204’ to11,224’. Circulate and condition mud for FIT test 1.5 times bottoms up. Rig up and perform LOT, good LOT. Drill 8.5” Production hole from 11,224’ to 11,250’ MD. Circulate 1 bottoms up. Perform CBL with Baker SoundTrak. 3/16/2024 3/17/2024 11,250 0.00 10.10 No accidents, incidents or spills. Perform CBL with Baker SoundTrak. Log cement from 10,825’ to 7,309’ MD. POH on elevators form 7,309’ to BHA. L/D BHA. R/U and Prep for BOP test. Test BOPE to 250 psi low, 3,500 psi high for 5 minutes each. Change annular element. Rig down flow line, remove annular from stack. 3/17/2024 3/18/2024 11,250 0.00 10.10 No accidents, incidents or spills. Change annular element. Test annular with 4 1/2” Test joint to 250 PSI low and 3,500 psi high, good test. Rig down test equipment. Pickup 8.5" Production Drilling assembly. RIH with 8-1/2" drilling assembly from 525' to 2,332'. Shallow test Baker and Halliburton LWD tools. Slip and cut drilling line. RIH from 11,000’ to 11,174’. Page 3 of 4 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 3/18/2024 3/19/2024 11,267 0.00 10.10 No accidents, incidents or spills. Wash down from 11,174’ to 11,250’. Drill ahead from 11,250’ to 11,259’. Observed increase in SPP and ratty torque. Top drive stalled at 17k limit. Worked string back inside shoe. Observed pressure and torque while trying to exit shoe again. Worked pipe several times until it was able to ream back to bottom trouble free. Gamma tool not communicating. Trouble shoot and conference with town. Drill ahead from 11,259’ to 11,267’. POOH on elevators from 11,170’ to BHA. Change 8 ½” Drilling BHA. RIH on elevators from 234’ to 2,143’. Shallow hole test tools. 3/19/2024 3/20/2024 11,267 943.00 10.20 No accidents, incidents or spills. Continue to shallow hole test tools at 2,139’. RIH with 8 ½” Directional BHA from 2,139’ to 4,049’. Repeat shallow tool test to confirm decoding issue is solved. Test good. Continue RIH with 8 ½” Directional BHA from 4,049’ to 11,079’. Wash down 11,079’ to 11,267’. Drill 8.5” Production hole from 11,267’ md to 12,210’ md. 3/20/2024 3/21/2024 12,210 2,700.00 10.10 No accidents, incidents or spills. Drill ahead in 8.5” Production hole from 12,210’ md to 14,910’ md. 3/21/2024 3/22/2024 14,910 2,559.00 10.10 No accidents, incidents or spills. Drill ahead in 8.5” Production hole from 15,640’ md to at 17,469' md. 3/22/2024 3/23/2024 17,469 60.00 10.05 No accidents, incidents or spills. Drill 8.5” hole from 17,469’ md to TD at 17,529’ md. Downlink to close steering tool. Perform clean up cycle. Pump 2 bottoms up. Racking back 1 per BU. Backream out of the hole from 17,441’ to 11,269' md. 3/23/2024 3/24/2024 17,529 0.00 10.10 No accidents, incidents or spills. Backream out of the hole from 11,269’ to 10,029’ md. Pull out of hole on elevators as per K&M trip schedule. Lay down the BHA 546’ to surface. Function and wash the BOP stack. R/U casing tool and equipment. 3/24/2024 3/25/2024 17,529 0.00 10.15 No accidents, incidents or spills. Run 4.5” liner from 4,584’ to 6,443’ md. Make up Baker SLZXP liner top hanger/packer assembly. Run in hole with lower completion assembly on 1st stand of 5” DP from 6,443’ to 6,599’. Run in hole with lower completion string on 5” DP from 6,559’ to 17,479’ md. Break off top single and MU ball dropping tool. 3/25/2024 3/26/2024 17,529 0.00 9.42 No accidents, incidents or spills. Clean and clear MOBM from rig floor while preparing pits for displacement. Displace well to 10.0 PPG Brine. 1st Stage. Test liner top packer to 4,000 psi, OK. Prepare pits for 2nd stage displacement. B/D ball dropper sub and lay down 2 singles. Displace above the liner top. POOH on elevators from 10,935’ to surface. Lay down the liner running tool. Pull the wear bushing. Mobilize the TEC wire, clamps and job box to the rig floor. Make up the FOSV and X/O. Run 4.5” P-110S 12.6# TSH-563 Upper completions liner to 1,055’. 3/26/2024 3/27/2024 17,529 0.00 9.42 No accidents, incidents or spills. Run 4.5” P-110S 12.6# TSH-563 Liner from 1,055’ to 11,002' md. Circulate at 11,002’ to clear any debris away from the liner top. Circulate down to 11,057’ and get a positive indication that the seal assembly is stabbed into the extended sealbore. Continue to RIH to 11,070’ and no go. Space out the upper completion. Run Schlumberger TEC line through the hanger and test Swagelok fittings to 5000 psi, good pressure test. Drain stack, land out tubing, run in lower lock downs and torque to 450 ft-lbs. Lay down landing joint. Rig up to MIT-T. Test tubing and IA. MIT- T to 4000 psi and MIT-IA to 4000 psi, both good tests. Rig up and freeze protect. 3/27/2024 3/27/2024 17,529 0.00 9.42 No accidents, incidents or spills. Complete freeze protect of Inner Annulus x Tubing. Install and test TWC from both directions. Begin rig down operations concurrent with installing 10K Frac Tree. Terminate control line connections through Frac Tree, pressure test tree and flange to 5000 psi. Conduct pressure test of tubing packoff to 5000 psi. Well secure at 1700 hrs. Continue with preparing for rig move. (See daily report for well PWD-02 3-27-2024 for further operation summary). Page 4 of 4 Page 1 of 1 Well Name: NDBi-030 Cement Surface Casing Cement Surface Casing Cement, Casing, 2/20/2024 16:00 Type Casing Cementing Start Date 2/20/2024 Cementing End Date 2/20/2024 Wellbore Original Hole String Surface Casing, 2,550.1ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 219 bbls of cement returned to surface. Comment Cement 13-3/8” Surface Casing as follows: - Fill lines with water and pressure test to 3500 psi for 5 minutes - Drop 1st Bottom Non-Rotating Plug - Pump 82 bbls of 10.5 ppg Tuned Spacer @ 5.0BPM, 300 psi. - Release 2nd Bottom Plug - Pump 455 bbls of 11.0 ppg ArcticCem lead cement @ 7.7 BPM, Excess Volume 250% (1007 sacks, yield 2.535 cu ft/sk) - Pump 70 bbls of 15.3 ppg Type I/II tail @ 9.3 BPM, Excess Volume 50% (316 sacks, yield 1.24 cu ft/sk) - Drop top plug and chase with 2 bbls Tail Cement and 20bbls water from cement unit. - Perform displacement with rig pumps and 10.0 ppg mud - 316 bbls displaced at 10 BPM: ICP 145 psi 22% return flow, FCP 585 psi 12% return flow. - 20 bbls displaced at 8 BPM: ICP 530 psi 10% return flow, FCP 545 psi 7% return flow. - Reduce rate to 4 BPM 10 bbls prior to plug bump: Final circulating pressure 505 psi prior to plug bump. - Bump plug and increase pressure to 1200 psi, check floats – good - Cement in place 1915 hrs - Total displacement volume 368 bbls (measured by strokes @ 96% pump efficiency) - Observed 80 bbls dyed Tuned Spacer, 63 bbls of cement contaminated interface returns, 219 bbls green cement returned to surface.ௗ A total of 362 bbls were dumped to the cuttings box. - Total losses from cement exit shoe to cement in place: 0 bbls 1, 0.0-2,557.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 2,557.0 Full Return? Yes Vol Cement Ret (bbl) 219.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 5 Final Pump Rate (bbl/min) 10 Avg Pump Rate (bbl/min) 8 Final Pump Pressure (psi) 530.0 Plug Bump Pressure (psi) 505.0 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 10.5 PPG Spacer Amount (sacks) Class Volume Pumped (bbl) 82.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Lead Fluid Type Lead Fluid Description ArcticCem Lead Amount (sacks) 965 Class Volume Pumped (bbl) 455.0 Estimated Top (ftKB) Percent Excess Pumped (%) 250.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 11.00 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description 15.3ppg Tail Amount (sacks) 310 Class Volume Pumped (bbl) 70.0 Estimated Top (ftKB) Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Displacement Fluid Type Displacement Fluid Description 10 PPG Mud Amount (sacks) Class Volume Pumped (bbl) 316.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 10.00 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Page 1 of 1 Well Name: NDBi-030 Cement Intermediate 1st Stage Cement Job Intermediate 1st Stage Cement Job, Casing, 3/11/2024 17:00 Type Casing Cementing Start Date 3/11/2024 Cementing End Date 3/11/2024 Wellbore Original Hole String Intermediate Liner, 11,201.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Baker Soundtrack LWD Cement Evaluation Results 1st Stage was logged with the Baker Soundtrack LWD tool. TOC was picked at 9950' MD. Reference the CBL Report in the attachments for a detailed analysis of cement bond log results. Comment Cement 9-5/8” Liner thru Halliburton Fas-Drill Cement retainer. -Pump 77.8 bbls of 12.5 ppg Tuned spacer @ 2.5 BPM, 950 psi. (pumped 10 bbls water & 77.5 bbls spacer got back 71.3 bbls) -Pump 205 bbls of 15.3 ppg Versacem Tail cement. -Flush lines with 10 bbls water from Halliburton. -Displace with rig pumps 177.8 bbls 12.0 ppg MOBM as follows: Pumped 85 bbls at 2.5 BPM. ICP 425 PSI, FCP 733 PSI. Pumped 18 bbls at 2 BPM. ICP 645 PSI, FCP 667 PSI. Pumped 47 bbls at 1 BPM. ICP 464 PSI, FCP 560 PSI. Pumped 26 bbls at 0.5 BPM. ICP 411 PSI. FCP 513 PSI. -Lost 110 bbls after cement entered annulus. (200 bbls total for job) 1, 2,396.0-11,204.0ftKB Top Depth (ftKB) 2,396.0 Bottom Depth (ftKB) 11,204.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 3 Final Pump Rate (bbl/min) 1 Avg Pump Rate (bbl/min) 2 Final Pump Pressure (psi) 513.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 77.8 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail Type I/II Amount (sacks) 935 Class Type I/II Volume Pumped (bbl) 205.0 Estimated Top (ftKB) Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 122.3 Thickening Time (hr) 5.28 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 9.12 Page 1 of 1 Well Name: NDBi-030 Cement Intermediate 2nd Stage Cement Job Intermediate 2nd Stage Cement Job, Casing, 3/13/2024 04:30 Type Casing Cementing Start Date 3/13/2024 Cementing End Date 3/13/2024 Wellbore Original Hole String Intermediate Liner, 11,201.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Cemented from Archer stage tool at 4712' MD to liner top at 2367' MD. Job went as planned and 50 bbls of cement was circulated off liner top. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 4712’ (center of circulation port) as follows: -Pump 80 BBLS of 12.5 ppg mudflush spacer @3-4 BPM, ICP 290 PSI, FCP 190 PSI. -Pump 78 BBLS of 13.5 ppg tuned spacer @ 3-4 BPM, ICP 240 PSI, FCP 202 PSI. -No losses while pumping spacers -Pump 252 BBLS of 15.3 ppg tail cement VERSACEM @ 3-4 BPM. 100% excess volume. No Losses. -Flush Lines with 10 bbls fresh water from Halliburton unit. 3.7 bpm, 237 psi. -Displace Cement to Archer stage tool with 64 bbls of 12.0 ppg MOBM, at 4.0 bpm. ICP 400 psi. slowed to 3 bpm 475 psi for last 10 bbls. FCP 465 psi. 26 bbls lost to hole during displacement. CIP @ 07:53. - Set LTP and circulated 50 bbls green cement off liner top. 2, 2,366.0-4,709.0ftKB Top Depth (ftKB) 2,366.0 Bottom Depth (ftKB) 4,709.0 Full Return? No Vol Cement Ret (bbl) Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) Final Pump Rate (bbl/min) Avg Pump Rate (bbl/min) Final Pump Pressure (psi) Plug Bump Pressure (psi) 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 Mudflush Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 78.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 0.00 Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 1,144 Class Type I/II Volume Pumped (bbl) 252.0 Estimated Top (ftKB) 2,467.0 Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 5.93 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 27.33 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 02 A p r i l , 2 0 2 4 De s i g n : N D B i - 0 3 0 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 i -03 0 ND B i -03 0 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 Tr u e Ma p S y s t e m : Ge o D a t u m : Pr o j e c t Ma p Z o n e : Sy s t e m D a t u m : US S t a t e P l a n e 1 9 2 7 ( E x a c t s o l u t i o n ) NA D 1 9 2 7 ( N A D C O N C O N U S ) Pi k k a , N o r t h S l o p e A l a s k a , U n i t e d S t a t e s Al a s k a Z o n e 0 4 Me a n S e a L e v e l Us i n g W e l l R e f e r e n c e P o i n t Us i n g g e o d e t i c s c a l e f a c t o r Si t e P o s i t i o n : Fr o m : Si t e La t i t u d e : Lo n g i t u d e : Po s i t i o n U n c e r t a i n t y : No r t h i n g : Ea s t i n g : Gr i d C o n v e r g e n c e : ND B us f t Ma p us f t us f t ° -0 . 5 9 Sl o t R a d i u s : " 20 5, 9 7 2 , 9 0 9 . 7 0 42 3 , 3 8 3 . 5 6 0. 9 70 ° 2 0 ' 1 0 . 1 3 8 N 15 0 ° 3 7 ' 1 7 . 7 9 6 W We l l We l l P o s i t i o n Lo n g i t u d e : La t i t u d e : Ea s t i n g : No r t h i n g : us f t +E /- W +N /- S Po s i t i o n U n c e r t a i n t y us f t us f t us f t Gr o u n d L e v e l : ND B i - 0 3 0 us f t us f t 0. 0 0. 0 5, 9 7 2 , 7 6 1 . 5 6 42 2 , 1 5 3 . 8 7 22 . 8 We l l h e a d E l e v a t i o n : us f t 0. 5 70 ° 2 0 ' 8 . 5 5 6 N 15 0 ° 3 7 ' 5 3 . 6 6 5 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 i - 0 3 0 Mo d e l N a m e Ma g n e t i c s BG G M 2 0 2 3 1 / 0 4 / 2 0 2 4 1 4 . 2 9 8 0 . 5 7 5 7 , 1 6 6 . 7 4 9 9 9 9 2 6 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 i - 0 3 0 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 : 46 . 4 31 6 . 9 0 0. 0 0. 0 46 . 4 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 2/ 0 4 / 2 0 2 4 SD I _ U R S A 1 _ I 4 S D I U R S A - 1 g y r o M W D ( I S C W S A R e v 4 ) 12 1 . 2 1 , 5 1 8 . 0 01 SD I U R S A G y r o M W D 1 6 i n H o l e <46 -62 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 1, 5 4 7 . 6 2 , 4 8 4 . 0 02 B H O n t r a k _16 i n H o l e <15 4 7 -24 8 4 > (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, 5 7 1 . 4 1 1 , 1 6 3 . 9 03 B H O n t r a K 1 2 .25 i n H o l e <25 7 1 -11 1 6 3 > 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 11 , 2 4 1 . 6 1 7 , 5 2 9 . 0 04 B H O n t r a K 8. 5 in H o l e <11 2 4 1 -17 5 2 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 ) 46 . 4 0 . 0 0 0 . 0 0 4 6 . 4 - 2 2 . 8 0 . 0 0 . 0 5 , 9 7 2 , 7 6 1 . 5 6 4 2 2 , 1 5 3 . 8 7 0 . 0 0 0 . 0 12 1 . 2 0 . 0 9 3 . 1 6 1 2 1 . 2 5 2 . 0 0 . 1 0 . 0 5 , 9 7 2 , 7 6 1 . 6 2 4 2 2 , 1 5 3 . 8 7 0 . 1 2 0 . 0 12 8 . 0 0 . 1 0 3 . 6 5 1 2 8 . 0 5 8 . 8 0 . 1 0 . 0 5 , 9 7 2 , 7 6 1 . 6 3 4 2 2 , 1 5 3 . 8 7 0 . 1 5 0 . 0 20 " C o n d u c t o r D r i v e n 18 3 . 3 0 . 1 8 5 . 6 3 1 8 3 . 3 1 1 4 . 1 0 . 2 0 . 0 5 , 9 7 2 , 7 6 1 . 7 6 4 2 2 , 1 5 3 . 8 9 0 . 1 5 0 . 1 27 7 . 7 0 . 4 4 2 8 . 4 8 2 7 7 . 7 2 0 8 . 5 0 . 7 0 . 2 5 , 9 7 2 , 7 6 2 . 2 3 4 2 2 , 1 5 4 . 0 8 0 . 3 0 0 . 4 37 2 . 9 1 . 2 3 3 5 2 . 9 7 3 7 2 . 9 3 0 3 . 7 2 . 0 0 . 3 5 , 9 7 2 , 7 6 3 . 5 6 4 2 2 , 1 5 4 . 1 4 0 . 9 5 1 . 3 46 7 . 7 2 . 2 0 3 5 0 . 1 6 4 6 7 . 6 3 9 8 . 4 4 . 8 - 0 . 2 5 , 9 7 2 , 7 6 6 . 3 7 4 2 2 , 1 5 3 . 7 4 1 . 0 3 3 . 6 56 2 . 0 3 . 8 7 3 3 9 . 2 6 5 6 1 . 9 4 9 2 . 7 9 . 6 - 1 . 6 5 , 9 7 2 , 7 7 1 . 1 5 4 2 2 , 1 5 2 . 3 5 1 . 8 6 8 . 1 66 0 . 3 6 . 3 4 3 2 6 . 9 5 6 5 9 . 7 5 9 0 . 5 1 7 . 2 - 5 . 8 5 , 9 7 2 , 7 7 8 . 8 4 4 2 2 , 1 4 8 . 3 0 2 . 7 4 1 6 . 5 71 9 . 8 7 . 8 5 3 2 8 . 7 1 7 1 8 . 8 6 4 9 . 6 2 3 . 4 - 9 . 7 5 , 9 7 2 , 7 8 5 . 1 1 4 2 2 , 1 4 4 . 4 6 2 . 5 6 2 3 . 7 76 0 . 3 9 . 0 0 3 2 8 . 7 1 7 5 8 . 8 6 8 9 . 6 2 8 . 5 - 1 2 . 7 5 , 9 7 2 , 7 9 0 . 2 0 4 2 2 , 1 4 1 . 4 3 2 . 8 4 2 9 . 5 85 4 . 1 1 1 . 9 9 3 3 2 . 5 8 8 5 1 . 0 7 8 1 . 8 4 3 . 4 - 2 1 . 0 5 , 9 7 2 , 8 0 5 . 2 1 4 2 2 , 1 3 3 . 2 9 3 . 2 7 4 6 . 1 94 9 . 1 1 5 . 1 5 3 3 3 . 9 8 9 4 3 . 4 8 7 4 . 2 6 3 . 4 - 3 1 . 0 5 , 9 7 2 , 8 2 5 . 2 3 4 2 2 , 1 2 3 . 5 0 3 . 3 4 6 7 . 5 1, 0 4 3 . 8 1 5 . 0 4 3 3 3 . 9 8 1 , 0 3 4 . 8 9 6 5 . 6 8 5 . 5 - 4 1 . 8 5 , 9 7 2 , 8 4 7 . 5 0 4 2 2 , 1 1 2 . 9 1 0 . 1 2 9 1 . 0 1, 0 4 8 . 0 1 5 . 0 4 3 3 3 . 9 2 1 , 0 3 8 . 9 9 6 9 . 7 8 6 . 5 - 4 2 . 3 5 , 9 7 2 , 8 4 8 . 4 9 4 2 2 , 1 1 2 . 4 5 0 . 3 8 9 2 . 1 Up p e r S c h r a d e r B l u f f 1, 1 3 8 . 3 1 5 . 0 4 3 3 2 . 5 8 1 , 1 2 6 . 1 1 , 0 5 6 . 9 1 0 7 . 4 - 5 2 . 9 5 , 9 7 2 , 8 6 9 . 5 1 4 2 2 , 1 0 2 . 1 2 0 . 3 8 1 1 4 . 6 1, 2 3 2 . 7 1 6 . 8 1 3 2 7 . 3 0 1 , 2 1 6 . 9 1 , 1 4 7 . 7 1 2 9 . 8 - 6 5 . 9 5 , 9 7 2 , 8 9 2 . 0 1 4 2 2 , 0 8 9 . 3 4 2 . 4 2 1 3 9 . 8 1, 3 2 7 . 2 1 8 . 8 2 3 2 2 . 0 3 1 , 3 0 6 . 8 1 , 2 3 7 . 6 1 5 3 . 3 - 8 2 . 7 5 , 9 7 2 , 9 1 5 . 7 0 4 2 2 , 0 7 2 . 8 2 2 . 7 2 1 6 8 . 4 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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, 4 1 5 . 0 2 1 . 4 1 3 1 7 . 4 5 1 , 3 8 9 . 3 1 , 3 2 0 . 1 1 7 6 . 3 - 1 0 2 . 2 5 , 9 7 2 , 9 3 8 . 8 8 4 2 2 , 0 5 3 . 5 1 3 . 4 5 1 9 8 . 6 Pe r m a f r o s t B a s e 1, 4 2 2 . 6 2 1 . 6 4 3 1 7 . 1 1 1 , 3 9 6 . 3 1 , 3 2 7 . 1 1 7 8 . 3 - 1 0 4 . 1 5 , 9 7 2 , 9 4 0 . 9 3 4 2 2 , 0 5 1 . 6 5 3 . 4 5 2 0 1 . 3 1, 5 1 8 . 0 2 4 . 8 1 3 1 2 . 1 9 1 , 4 8 4 . 0 1 , 4 1 4 . 8 2 0 4 . 7 - 1 3 0 . 9 5 , 9 7 2 , 9 6 7 . 5 6 4 2 2 , 0 2 5 . 1 0 3 . 8 9 2 3 8 . 9 1, 5 4 7 . 6 2 5 . 9 3 3 1 3 . 8 1 1 , 5 1 0 . 7 1 , 4 4 1 . 5 2 1 3 . 3 - 1 4 0 . 2 5 , 9 7 2 , 9 7 6 . 3 1 4 2 2 , 0 1 5 . 9 2 4 . 4 5 2 5 1 . 5 1, 6 4 2 . 1 2 9 . 2 6 3 1 0 . 6 8 1 , 5 9 4 . 5 1 , 5 2 5 . 3 2 4 2 . 7 - 1 7 2 . 6 5 , 9 7 3 , 0 0 6 . 0 0 4 2 1 , 9 8 3 . 8 0 3 . 8 4 2 9 5 . 1 1, 7 3 6 . 3 3 1 . 8 0 3 1 0 . 3 8 1 , 6 7 5 . 6 1 , 6 0 6 . 4 2 7 3 . 8 - 2 0 9 . 0 5 , 9 7 3 , 0 3 7 . 4 7 4 2 1 , 9 4 7 . 7 5 2 . 7 0 3 4 2 . 7 1, 8 3 1 . 3 3 4 . 1 3 3 0 9 . 6 9 1 , 7 5 5 . 4 1 , 6 8 6 . 2 3 0 7 . 0 - 2 4 8 . 6 5 , 9 7 3 , 0 7 1 . 1 3 4 2 1 , 9 0 8 . 5 0 2 . 4 8 3 9 4 . 0 1, 8 3 5 . 0 3 4 . 2 5 3 0 9 . 6 7 1 , 7 5 8 . 4 1 , 6 8 9 . 2 3 0 8 . 3 - 2 5 0 . 2 5 , 9 7 3 , 0 7 2 . 4 6 4 2 1 , 9 0 6 . 9 4 3 . 4 0 3 9 6 . 1 Mi d d l e S c h r a d e r B l u f f 1, 9 2 6 . 3 3 7 . 3 4 3 0 9 . 1 1 1 , 8 3 2 . 4 1 , 7 6 3 . 2 3 4 2 . 2 - 2 9 1 . 5 5 , 9 7 3 , 1 0 6 . 7 6 4 2 1 , 8 6 6 . 0 1 3 . 4 0 4 4 9 . 0 2, 0 2 0 . 7 4 0 . 5 2 3 0 6 . 7 8 1 , 9 0 5 . 9 1 , 8 3 6 . 7 3 7 8 . 7 - 3 3 8 . 2 5 , 9 7 3 , 1 4 3 . 6 7 4 2 1 , 8 1 9 . 6 1 3 . 7 1 5 0 7 . 6 2, 1 1 5 . 5 4 2 . 4 0 3 0 6 . 0 0 1 , 9 7 6 . 9 1 , 9 0 7 . 7 4 1 5 . 9 - 3 8 8 . 8 5 , 9 7 3 , 1 8 1 . 4 2 4 2 1 , 7 6 9 . 4 7 2 . 0 6 5 6 9 . 3 2, 2 1 0 . 4 4 3 . 9 6 3 0 6 . 1 8 2 , 0 4 6 . 1 1 , 9 7 6 . 9 4 5 4 . 1 - 4 4 1 . 2 5 , 9 7 3 , 2 2 0 . 2 1 4 2 1 , 7 1 7 . 4 1 1 . 6 5 6 3 3 . 1 2, 3 0 4 . 8 4 7 . 9 0 3 0 5 . 3 1 2 , 1 1 1 . 8 2 , 0 4 2 . 6 4 9 3 . 8 - 4 9 6 . 3 5 , 9 7 3 , 2 6 0 . 3 9 4 2 1 , 6 6 2 . 7 6 4 . 2 2 6 9 9 . 6 2, 3 3 4 . 0 4 9 . 0 2 3 0 4 . 9 9 2 , 1 3 1 . 1 2 , 0 6 1 . 9 5 0 6 . 3 - 5 1 4 . 2 5 , 9 7 3 , 2 7 3 . 1 4 4 2 1 , 6 4 5 . 0 5 3 . 9 2 7 2 1 . 0 MC U ( L o w e r S c h r a d e r B l u f f ) 2, 3 9 9 . 0 5 1 . 5 1 3 0 4 . 3 1 2 , 1 7 2 . 7 2 , 1 0 3 . 5 5 3 4 . 7 - 5 5 5 . 3 5 , 9 7 3 , 3 0 1 . 9 8 4 2 1 , 6 0 4 . 2 3 3 . 9 2 7 6 9 . 8 2, 4 8 4 . 0 5 4 . 2 6 3 0 5 . 7 1 2 , 2 2 3 . 9 2 , 1 5 4 . 7 5 7 3 . 6 - 6 1 0 . 8 5 , 9 7 3 , 3 4 1 . 4 4 4 2 1 , 5 4 9 . 1 4 3 . 4 9 8 3 6 . 2 2, 5 5 0 . 0 5 5 . 4 7 3 0 6 . 7 9 2 , 2 6 1 . 9 2 , 1 9 2 . 7 6 0 5 . 5 - 6 5 4 . 3 5 , 9 7 3 , 3 7 3 . 8 0 4 2 1 , 5 0 5 . 9 5 2 . 2 6 8 8 9 . 2 13 - 3 / 8 " S u r f a c e C a s i n g 2, 5 7 1 . 4 55 . 8 6 3 0 7 . 1 3 2 , 2 7 4 . 0 2 , 2 0 4 . 8 6 1 6 . 2 -6 6 8 . 4 5, 9 7 3 , 3 8 4 . 5 9 4 2 1 , 4 9 1 . 9 2 2 . 2 6 9 0 6 . 6 2, 6 6 6 . 2 5 8 . 0 4 3 0 7 . 6 0 2 , 3 2 5 . 7 2 , 2 5 6 . 5 6 6 4 . 4 - 7 3 1 . 5 5 , 9 7 3 , 4 3 3 . 4 2 4 2 1 , 4 2 9 . 3 3 2 . 3 4 9 8 4 . 9 2, 7 6 0 . 9 6 0 . 3 4 3 0 8 . 4 3 2 , 3 7 4 . 2 2 , 3 0 5 . 0 7 1 4 . 5 - 7 9 5 . 6 5 , 9 7 3 , 4 8 4 . 1 8 4 2 1 , 3 6 5 . 7 9 2 . 5 4 1 , 0 6 5 . 3 2, 8 5 6 . 7 6 3 . 6 5 3 0 8 . 7 7 2 , 4 1 9 . 2 2 , 3 5 0 . 0 7 6 7 . 2 - 8 6 1 . 7 5 , 9 7 3 , 5 3 7 . 6 2 4 2 1 , 3 0 0 . 2 6 3 . 4 7 1 , 1 4 9 . 0 2, 8 9 8 . 0 6 5 . 2 3 3 0 8 . 9 4 2 , 4 3 7 . 0 2 , 3 6 7 . 8 7 9 0 . 6 - 8 9 0 . 7 5 , 9 7 3 , 5 6 1 . 3 1 4 2 1 , 2 7 1 . 4 7 3 . 8 5 1 , 1 8 5 . 9 Tu l u v a k S h a l e 2, 9 5 0 . 8 6 7 . 2 6 3 0 9 . 1 6 2 , 4 5 8 . 3 2 , 3 8 9 . 1 8 2 1 . 1 - 9 2 8 . 3 5 , 9 7 3 , 5 9 2 . 1 5 4 2 1 , 2 3 4 . 2 5 3 . 8 5 1 , 2 3 3 . 8 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 3, 0 4 4 . 8 7 0 . 2 6 3 0 9 . 5 8 2 , 4 9 2 . 3 2 , 4 2 3 . 1 8 7 6 . 6 - 9 9 6 . 0 5 , 9 7 3 , 6 4 8 . 4 1 4 2 1 , 1 6 7 . 1 3 3 . 2 2 1 , 3 2 0 . 6 3, 0 6 2 . 0 7 0 . 7 7 3 0 9 . 5 5 2 , 4 9 8 . 0 2 , 4 2 8 . 8 8 8 7 . 0 - 1 , 0 0 8 . 5 5 , 9 7 3 , 6 5 8 . 8 7 4 2 1 , 1 5 4 . 7 3 2 . 9 8 1 , 3 3 6 . 7 Tu l u v a k S a n d 3, 1 3 9 . 9 7 3 . 0 9 3 0 9 . 3 9 2 , 5 2 2 . 2 2 , 4 5 3 . 0 9 3 4 . 0 - 1 , 0 6 5 . 7 5 , 9 7 3 , 7 0 6 . 5 2 4 2 1 , 0 9 8 . 0 7 2 . 9 8 1 , 4 1 0 . 1 3, 2 3 5 . 2 7 6 . 2 1 3 0 9 . 3 2 2 , 5 4 7 . 4 2 , 4 7 8 . 2 9 9 2 . 3 - 1 , 1 3 6 . 7 5 , 9 7 3 , 7 6 5 . 5 0 4 2 1 , 0 2 7 . 6 5 3 . 2 8 1 , 5 0 1 . 2 3, 3 2 9 . 8 7 8 . 7 6 3 0 8 . 3 9 2 , 5 6 7 . 9 2 , 4 9 8 . 7 1 , 0 5 0 . 2 - 1 , 2 0 8 . 6 5 , 9 7 3 , 8 2 4 . 1 8 4 2 0 , 9 5 6 . 3 3 2 . 8 6 1 , 5 9 2 . 7 3, 4 2 5 . 2 7 8 . 8 6 3 0 8 . 0 3 2 , 5 8 6 . 4 2 , 5 1 7 . 2 1 , 1 0 8 . 1 - 1 , 2 8 2 . 2 5 , 9 7 3 , 8 8 2 . 8 3 4 2 0 , 8 8 3 . 4 0 0 . 3 8 1 , 6 8 5 . 2 3, 5 1 9 . 6 7 8 . 9 0 3 0 7 . 5 1 2 , 6 0 4 . 6 2, 5 3 5 . 4 1, 1 6 4 . 9 - 1 , 3 5 5 . 4 5 , 9 7 3 , 9 4 0 . 3 2 4 2 0 , 8 1 0 . 7 8 0 . 5 4 1 , 7 7 6 . 6 3, 6 1 5 . 2 7 8 . 9 4 3 0 7 . 4 4 2 , 6 2 3 . 0 2 , 5 5 3 . 8 1 , 2 2 1 . 9 - 1 , 4 2 9 . 8 5 , 9 7 3 , 9 9 8 . 1 6 4 2 0 , 7 3 6 . 9 3 0 . 0 8 1 , 8 6 9 . 2 3, 7 1 0 . 0 7 9 . 0 0 3 0 6 . 9 6 2 , 6 4 1 . 2 2 , 5 7 2 . 0 1 , 2 7 8 . 2 - 1 , 5 0 4 . 0 5 , 9 7 4 , 0 5 5 . 1 8 4 2 0 , 6 6 3 . 4 1 0 . 5 0 1 , 9 6 0 . 9 3, 8 0 4 . 0 7 8 . 9 7 3 0 6 . 7 1 2 , 6 5 9 . 1 2 , 5 8 9 . 9 1 , 3 3 3 . 5 - 1 , 5 7 7 . 8 5 , 9 7 4 , 1 1 1 . 2 7 4 2 0 , 5 9 0 . 1 2 0 . 2 6 2 , 0 5 1 . 8 3, 8 9 9 . 1 7 8 . 9 0 3 0 5 . 8 3 2 , 6 7 7 . 4 2 , 6 0 8 . 2 1 , 3 8 8 . 7 - 1 , 6 5 3 . 1 5 , 9 7 4 , 1 6 7 . 2 6 4 2 0 , 5 1 5 . 4 6 0 . 9 1 2 , 1 4 3 . 5 3, 9 8 8 . 0 7 9 . 0 3 3 0 5 . 7 3 2 , 6 9 4 . 4 2 , 6 2 5 . 2 1 , 4 3 9 . 8 - 1 , 7 2 3 . 9 5 , 9 7 4 , 2 1 8 . 9 9 4 2 0 , 4 4 5 . 2 2 0 . 1 8 2 , 2 2 9 . 1 4, 0 8 5 . 8 7 9 . 0 0 3 0 5 . 8 3 2 , 7 1 3 . 0 2 , 6 4 3 . 8 1 , 4 9 5 . 9 - 1 , 8 0 1 . 7 5 , 9 7 4 , 2 7 5 . 8 9 4 2 0 , 3 6 7 . 9 7 0 . 1 1 2 , 3 2 3 . 3 4, 1 8 0 . 5 7 9 . 1 8 3 0 6 . 1 2 2 , 7 3 0 . 9 2 , 6 6 1 . 7 1 , 5 5 0 . 5 - 1 , 8 7 7 . 0 5 , 9 7 4 , 3 3 1 . 3 0 4 2 0 , 2 9 3 . 2 8 0 . 3 6 2 , 4 1 4 . 6 4, 2 7 5 . 2 7 9 . 1 2 3 0 6 . 1 3 2 , 7 4 8 . 8 2 , 6 7 9 . 6 1 , 6 0 5 . 3 - 1 , 9 5 2 . 1 5 , 9 7 4 , 3 8 6 . 9 1 4 2 0 , 2 1 8 . 7 3 0 . 0 6 2 , 5 0 5 . 9 4, 3 7 2 . 8 7 9 . 0 9 3 0 5 . 9 0 2 , 7 6 7 . 2 2 , 6 9 8 . 0 1 , 6 6 1 . 7 - 2 , 0 2 9 . 6 5 , 9 7 4 , 4 4 4 . 0 7 4 2 0 , 1 4 1 . 7 9 0 . 2 3 2 , 6 0 0 . 1 4, 4 6 7 . 5 7 9 . 0 6 3 0 7 . 0 3 2 , 7 8 5 . 2 2 , 7 1 6 . 0 1 , 7 1 6 . 9 - 2 , 1 0 4 . 4 5 , 9 7 4 , 5 0 0 . 0 8 4 2 0 , 0 6 7 . 6 2 1 . 1 7 2 , 6 9 1 . 5 4, 5 6 2 . 5 7 9 . 0 8 3 0 6 . 8 0 2 , 8 0 3 . 2 2 , 7 3 4 . 0 1 , 7 7 3 . 0 - 2 , 1 7 9 . 0 5 , 9 7 4 , 5 5 6 . 8 8 4 1 9 , 9 9 3 . 6 3 0 . 2 4 2 , 7 8 3 . 4 4, 6 5 6 . 8 7 9 . 0 9 3 0 7 . 3 3 2 , 8 2 1 . 0 2 , 7 5 1 . 8 1 , 8 2 8 . 8 - 2 , 2 5 2 . 9 5 , 9 7 4 , 6 1 3 . 4 7 4 1 9 , 9 2 0 . 3 0 0 . 5 5 2 , 8 7 4 . 6 4, 6 6 0 . 0 7 9 . 0 9 3 0 7 . 3 3 2 , 8 2 1 . 6 2 , 7 5 2 . 4 1 , 8 3 0 . 7 - 2 , 2 5 5 . 4 5 , 9 7 4 , 6 1 5 . 3 9 4 1 9 , 9 1 7 . 8 4 0 . 1 7 2 , 8 7 7 . 7 TS 7 9 0 4, 7 5 2 . 1 7 9 . 1 6 3 0 7 . 4 8 2 , 8 3 9 . 0 2 , 7 6 9 . 8 1 , 8 8 5 . 6 - 2 , 3 2 7 . 2 5 , 9 7 4 , 6 7 1 . 0 8 4 1 9 , 8 4 6 . 5 6 0 . 1 7 2 , 9 6 6 . 9 4, 8 4 6 . 4 7 9 . 0 3 3 0 7 . 5 8 2 , 8 5 6 . 8 2 , 7 8 7 . 6 1 , 9 4 2 . 0 - 2 , 4 0 0 . 6 5 , 9 7 4 , 7 2 8 . 2 1 4 1 9 , 7 7 3 . 7 6 0 . 1 7 3 , 0 5 8 . 3 4, 9 4 1 . 6 7 9 . 0 5 3 0 7 . 8 1 2 , 8 7 5 . 0 2 , 8 0 5 . 8 1 , 9 9 9 . 2 - 2 , 4 7 4 . 6 5 , 9 7 4 , 7 8 6 . 1 5 4 1 9 , 7 0 0 . 3 7 0 . 2 4 3 , 1 5 0 . 6 5, 0 3 6 . 5 7 9 . 1 2 3 0 7 . 5 4 2 , 8 9 2 . 9 2 , 8 2 3 . 7 2 , 0 5 6 . 2 - 2 , 5 4 8 . 4 5 , 9 7 4 , 8 4 3 . 8 6 4 1 9 , 6 2 7 . 2 2 0 . 2 9 3 , 2 4 2 . 5 5, 1 3 0 . 5 7 9 . 0 6 3 0 7 . 6 0 2 , 9 1 0 . 7 2 , 8 4 1 . 5 2 , 1 1 2 . 4 - 2 , 6 2 1 . 5 5 , 9 7 4 , 9 0 0 . 8 8 4 1 9 , 5 5 4 . 6 7 0 . 0 9 3 , 3 3 3 . 6 5, 2 2 6 . 0 7 9 . 0 6 3 0 7 . 3 2 2 , 9 2 8 . 8 2 , 8 5 9 . 6 2 , 1 6 9 . 4 - 2 , 6 9 5 . 9 5 , 9 7 4 , 9 5 8 . 6 5 4 1 9 , 4 8 0 . 8 8 0 . 2 9 3 , 4 2 6 . 1 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 5, 3 2 0 . 5 7 9 . 0 9 3 0 7 . 2 9 2 , 9 4 6 . 7 2 , 8 7 7 . 5 2 , 2 2 5 . 7 - 2 , 7 6 9 . 7 5 , 9 7 5 , 0 1 5 . 6 6 4 1 9 , 4 0 7 . 6 4 0 . 0 4 3 , 5 1 7 . 6 5, 4 1 5 . 4 7 9 . 1 2 3 0 6 . 8 9 2 , 9 6 4 . 7 2 , 8 9 5 . 5 2 , 2 8 1 . 9 - 2 , 8 4 4 . 1 5 , 9 7 5 , 0 7 2 . 6 3 4 1 9 , 3 3 3 . 8 9 0 . 4 2 3 , 6 0 9 . 4 5, 5 1 0 . 2 7 9 . 1 1 3 0 6 . 3 5 2 , 9 8 2 . 6 2, 9 1 3 . 4 2, 3 3 7 . 4 - 2 , 9 1 8 . 8 5 , 9 7 5 , 1 2 8 . 9 1 4 1 9 , 2 5 9 . 7 8 0 . 5 6 3 , 7 0 1 . 0 5, 6 0 3 . 8 7 9 . 1 3 3 0 5 . 6 5 3 , 0 0 0 . 3 2 , 9 3 1 . 1 2 , 3 9 1 . 4 - 2 , 9 9 3 . 2 5 , 9 7 5 , 1 8 3 . 7 2 4 1 9 , 1 8 5 . 9 7 0 . 7 3 3 , 7 9 1 . 3 5, 6 9 9 . 2 7 9 . 0 6 3 0 6 . 0 7 3 , 0 1 8 . 3 2 , 9 4 9 . 1 2 , 4 4 6 . 3 - 3 , 0 6 9 . 1 5 , 9 7 5 , 2 3 9 . 3 7 4 1 9 , 1 1 0 . 6 4 0 . 4 4 3 , 8 8 3 . 2 5, 7 9 3 . 6 7 9 . 0 7 3 0 6 . 2 1 3 , 0 3 6 . 2 2 , 9 6 7 . 0 2 , 5 0 1 . 0 - 3 , 1 4 3 . 9 5 , 9 7 5 , 2 9 4 . 8 0 4 1 9 , 0 3 6 . 3 6 0 . 1 5 3 , 9 7 4 . 3 5, 8 8 8 . 7 7 9 . 1 3 30 6 . 3 4 3, 0 5 4 . 2 2 , 9 8 5 . 0 2 , 5 5 6 . 3 - 3 , 2 1 9 . 2 5 , 9 7 5 , 3 5 0 . 8 5 4 1 8 , 9 6 1 . 6 3 0 . 1 5 4 , 0 6 6 . 1 5, 9 8 3 . 9 7 9 . 0 9 3 0 6 . 4 3 3 , 0 7 2 . 2 3 , 0 0 3 . 0 2 , 6 1 1 . 7 - 3 , 2 9 4 . 5 5 , 9 7 5 , 4 0 7 . 0 5 4 1 8 , 8 8 7 . 0 0 0 . 1 0 4 , 1 5 7 . 9 6, 0 7 7 . 7 7 9 . 0 9 3 0 6 . 4 3 3 , 0 8 9 . 9 3 , 0 2 0 . 7 2 , 6 6 6 . 4 - 3 , 3 6 8 . 6 5 , 9 7 5 , 4 6 2 . 5 0 4 1 8 , 8 1 3 . 4 8 0 . 0 0 4 , 2 4 8 . 5 6, 1 4 8 . 0 7 9 . 0 7 3 0 6 . 3 8 3 , 1 0 3 . 3 3 , 0 3 4 . 1 2 , 7 0 7 . 3 - 3 , 4 2 4 . 1 5 , 9 7 5 , 5 0 4 . 0 5 4 1 8 , 7 5 8 . 3 4 0 . 0 8 4 , 3 1 6 . 4 Se a b e e 6, 1 7 2 . 8 7 9 . 0 6 3 0 6 . 3 6 3 , 1 0 8 . 0 3 , 0 3 8 . 8 2 , 7 2 1 . 8 - 3 , 4 4 3 . 7 5 , 9 7 5 , 5 1 8 . 6 9 4 1 8 , 7 3 8 . 8 8 0 . 0 8 4 , 3 4 0 . 4 6, 2 6 6 . 5 7 9 . 0 5 3 0 6 . 3 2 3 , 1 2 5 . 8 3 , 0 5 6 . 6 2 , 7 7 6 . 3 - 3 , 5 1 7 . 9 5 , 9 7 5 , 5 7 3 . 9 8 4 1 8 , 6 6 5 . 3 4 0 . 0 4 4 , 4 3 0 . 8 6, 3 6 2 . 3 7 9 . 0 3 3 0 6 . 2 4 3 , 1 4 4 . 0 3 , 0 7 4 . 8 2 , 8 3 2 . 0 - 3 , 5 9 3 . 7 5 , 9 7 5 , 6 3 0 . 4 0 4 1 8 , 5 9 0 . 1 3 0 . 0 8 4 , 5 2 3 . 2 6, 4 5 6 . 9 7 9 . 0 3 3 0 6 . 2 8 3 , 1 6 2 . 0 3 , 0 9 2 . 8 2 , 8 8 6 . 9 - 3 , 6 6 8 . 6 5 , 9 7 5 , 6 8 6 . 1 0 4 1 8 , 5 1 5 . 8 2 0 . 0 4 4 , 6 1 4 . 5 6, 5 5 1 . 4 79 . 1 6 3 0 6 . 6 5 3 , 1 7 9 . 8 3 , 1 1 0 . 6 2 , 9 4 2 . 0 - 3 , 7 4 3 . 1 5 , 9 7 5 , 7 4 1 . 9 8 4 1 8 , 4 4 1 . 8 2 0 . 4 1 4 , 7 0 5 . 7 6, 6 4 6 . 7 7 9 . 1 2 3 0 6 . 2 9 3 , 1 9 7 . 8 3 , 1 2 8 . 6 2 , 9 9 7 . 6 - 3 , 8 1 8 . 4 5 , 9 7 5 , 7 9 8 . 4 0 4 1 8 , 3 6 7 . 1 3 0 . 3 7 4 , 7 9 7 . 8 6, 7 4 0 . 8 7 8 . 9 7 3 0 6 . 6 5 3 , 2 1 5 . 7 3 , 1 4 6 . 5 3 , 0 5 2 . 6 - 3 , 8 9 2 . 7 5 , 9 7 5 , 8 5 4 . 1 0 4 1 8 , 2 9 3 . 3 9 0 . 4 1 4 , 8 8 8 . 7 6, 8 3 5 . 8 7 8 . 9 4 3 0 7 . 0 0 3 , 2 3 3 . 9 3 , 1 6 4 . 7 3 , 1 0 8 . 5 - 3 , 9 6 7 . 4 5 , 9 7 5 , 9 1 0 . 7 5 4 1 8 , 2 1 9 . 3 5 0 . 3 6 4 , 9 8 0 . 5 6, 9 2 9 . 5 7 8 . 9 6 3 0 7 . 1 2 3 , 2 5 1 . 8 3 , 1 8 2 . 6 3 , 1 6 3 . 9 - 4 , 0 4 0 . 7 5 , 9 7 5 , 9 6 6 . 9 0 4 1 8 , 1 4 6 . 5 7 0 . 1 3 5 , 0 7 1 . 0 7, 0 2 5 . 3 7 8 . 9 4 3 0 7 . 3 4 3 , 2 7 0 . 2 3 , 2 0 1 . 0 3 , 2 2 0 . 8 - 4 , 1 1 5 . 6 5 , 9 7 6 , 0 2 4 . 5 8 4 1 8 , 0 7 2 . 2 8 0 . 2 3 5 , 1 6 3 . 8 7, 1 1 9 . 4 7 8 . 9 1 3 0 7 . 5 2 3 , 2 8 8 . 3 3 , 2 1 9 . 1 3 , 2 7 6 . 9 - 4 , 1 8 9 . 0 5 , 9 7 6 , 0 8 1 . 4 9 4 1 7 , 9 9 9 . 5 0 0 . 1 9 5 , 2 5 4 . 9 7, 2 1 4 . 3 7 8 . 9 4 3 0 7 . 5 8 3 , 3 0 6 . 5 3 , 2 3 7 . 3 3 , 3 3 3 . 7 - 4 , 2 6 2 . 8 5 , 9 7 6 , 1 3 9 . 0 0 4 1 7 , 9 2 6 . 2 8 0 . 0 7 5 , 3 4 6 . 8 7, 3 0 9 . 3 7 8 . 9 6 3 0 7 . 3 1 3 , 3 2 4 . 7 3 , 2 5 5 . 5 3 , 3 9 0 . 3 - 4 , 3 3 6 . 8 5 , 9 7 6 , 1 9 6 . 4 2 4 1 7 , 8 5 2 . 8 9 0 . 2 8 5 , 4 3 8 . 7 7, 4 0 4 . 0 7 8 . 9 6 3 0 7 . 7 3 3 , 3 4 2 . 8 3 , 2 7 3 . 6 3 , 4 4 6 . 9 - 4 , 4 1 0 . 5 5 , 9 7 6 , 2 5 3 . 7 8 4 1 7 , 7 7 9 . 7 7 0 . 4 4 5 , 5 3 0 . 4 7, 4 9 8 . 5 7 8 . 9 4 3 0 7 . 7 7 3 , 3 6 1 . 0 3 , 2 9 1 . 8 3 , 5 0 3 . 8 - 4 , 4 8 3 . 9 5 , 9 7 6 , 3 1 1 . 3 6 4 1 7 , 7 0 6 . 9 8 0 . 0 5 5 , 6 2 2 . 0 7, 5 9 3 . 3 7 8 . 9 3 3 0 7 . 7 8 3 , 3 7 9 . 2 3 , 3 1 0 . 0 3 , 5 6 0 . 7 - 4 , 5 5 7 . 4 5 , 9 7 6 , 3 6 9 . 0 6 4 1 7 , 6 3 4 . 1 0 0 . 0 1 5 , 7 1 3 . 8 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 7, 6 8 7 . 5 7 8 . 9 0 3 0 8 . 1 6 3 , 3 9 7 . 3 3 , 3 2 8 . 1 3 , 6 1 7 . 6 - 4 , 6 3 0 . 3 5 , 9 7 6 , 4 2 6 . 6 7 4 1 7 , 5 6 1 . 8 4 0 . 4 0 5 , 8 0 5 . 1 7, 7 8 2 . 8 7 8 . 9 0 3 0 7 . 9 2 3 , 4 1 5 . 6 3 , 3 4 6 . 4 3 , 6 7 5 . 2 - 4 , 7 0 3 . 9 5 , 9 7 6 , 4 8 5 . 0 8 4 1 7 , 4 8 8 . 7 6 0 . 2 5 5 , 8 9 7 . 6 7, 8 7 7 . 4 7 8 . 9 3 3 0 8 . 2 7 3 , 4 3 3 . 8 3 , 3 6 4 . 6 3 , 7 3 2 . 5 - 4 , 7 7 7 . 0 5 , 9 7 6 , 5 4 3 . 1 2 4 1 7 , 4 1 6 . 2 9 0 . 3 6 5 , 9 8 9 . 3 7, 9 7 2 . 6 7 8 . 9 6 3 0 7 . 9 5 3 , 4 5 2 . 1 3 , 3 8 2 . 9 3 , 7 9 0 . 2 - 4 , 8 5 0 . 5 5 , 9 7 6 , 6 0 1 . 5 2 4 1 7 , 3 4 3 . 4 2 0 . 3 3 6 , 0 8 1 . 6 8, 0 6 7 . 2 7 8 . 9 4 3 0 7 . 4 8 3 , 4 7 0 . 2 3 , 4 0 1 . 0 3 , 8 4 7 . 0 - 4 , 9 2 4 . 0 5 , 9 7 6 , 6 5 9 . 0 9 4 1 7 , 2 7 0 . 5 4 0 . 4 9 6 , 1 7 3 . 3 8, 1 6 1 . 9 7 8 . 9 0 3 0 7 . 0 1 3 , 4 8 8 . 4 3 , 4 1 9 . 2 3 , 9 0 3 . 2 - 4 , 9 9 8 . 0 5 , 9 7 6 , 7 1 6 . 0 8 4 1 7 , 1 9 7 . 1 7 0 . 4 9 6 , 2 6 4 . 9 8, 2 5 6 . 2 7 8 . 9 1 30 6 . 8 4 3, 5 0 6 . 5 3 , 4 3 7 . 3 3 , 9 5 8 . 8 - 5 , 0 7 1 . 9 5 , 9 7 6 , 7 7 2 . 4 1 4 1 7 , 1 2 3 . 8 2 0 . 1 8 6 , 3 5 6 . 0 8, 3 5 0 . 8 7 8 . 9 4 3 0 6 . 2 0 3 , 5 2 4 . 7 3 , 4 5 5 . 5 4 , 0 1 4 . 1 - 5 , 1 4 6 . 5 5 , 9 7 6 , 8 2 8 . 4 5 4 1 7 , 0 4 9 . 7 6 0 . 6 6 6 , 4 4 7 . 4 8, 4 4 5 . 8 7 8 . 9 6 3 0 5 . 4 1 3 , 5 4 2 . 9 3 , 4 7 3 . 7 4 , 0 6 8 . 6 - 5 , 2 2 2 . 1 5 , 9 7 6 , 8 8 3 . 7 7 4 1 6 , 9 7 4 . 7 2 0 . 8 2 6 , 5 3 8 . 9 8, 5 4 1 . 0 7 8 . 9 0 3 0 5 . 3 4 3 , 5 6 1 . 2 3 , 4 9 2 . 0 4 , 1 2 2 . 7 - 5 , 2 9 8 . 3 5 , 9 7 6 , 9 3 8 . 6 2 4 1 6 , 8 9 9 . 1 4 0 . 1 0 6 , 6 3 0 . 4 8, 6 3 5 . 0 7 8 . 9 1 3 0 5 . 7 8 3 , 5 7 9 . 3 3 , 5 1 0 . 1 4 , 1 7 6 . 3 - 5 , 3 7 3 . 4 5 , 9 7 6 , 9 9 3 . 0 6 4 1 6 , 8 2 4 . 6 4 0 . 4 6 6 , 7 2 0 . 9 8, 7 3 0 . 1 7 8 . 9 0 3 0 5 . 9 2 3 , 5 9 7 . 6 3 , 5 2 8 . 4 4 , 2 3 1 . 0 - 5 , 4 4 9 . 0 5 , 9 7 7 , 0 4 8 . 4 8 4 1 6 , 7 4 9 . 5 9 0 . 1 4 6 , 8 1 2 . 4 8, 8 2 4 . 4 7 8 . 8 8 3 0 6 . 3 6 3 , 6 1 5 . 8 3 , 5 4 6 . 6 4 , 2 8 5 . 6 - 5 , 5 2 3 . 7 5 , 9 7 7 , 1 0 3 . 8 3 4 1 6 , 6 7 5 . 4 3 0 . 4 6 6 , 9 0 3 . 4 8, 9 1 9 . 7 7 8 . 8 8 3 0 6 . 4 1 3 , 6 3 4 . 1 3 , 5 6 4 . 9 4 , 3 4 1 . 0 - 5 , 5 9 9 . 0 5 , 9 7 7 , 1 6 0 . 0 8 4 1 6 , 6 0 0 . 7 3 0 . 0 5 6 , 9 9 5 . 3 9, 0 1 4 . 0 7 8 . 8 7 30 6 . 5 4 3, 6 5 2 . 3 3 , 5 8 3 . 1 4 , 3 9 6 . 0 - 5 , 6 7 3 . 4 5 , 9 7 7 , 2 1 5 . 8 3 4 1 6 , 5 2 6 . 9 3 0 . 1 4 7 , 0 8 6 . 3 9, 1 0 9 . 7 7 8 . 8 8 3 0 6 . 7 7 3 , 6 7 0 . 8 3 , 6 0 1 . 6 4 , 4 5 2 . 1 - 5 , 7 4 8 . 8 5 , 9 7 7 , 2 7 2 . 6 8 4 1 6 , 4 5 2 . 1 7 0 . 2 4 7 , 1 7 8 . 7 9, 2 0 4 . 0 7 8 . 9 1 3 0 7 . 2 5 3 , 6 8 9 . 0 3 , 6 1 9 . 8 4 , 5 0 7 . 8 - 5 , 8 2 2 . 7 5 , 9 7 7 , 3 2 9 . 1 7 4 1 6 , 3 7 8 . 8 3 0 . 5 0 7 , 2 6 9 . 9 9, 2 9 8 . 4 78 . 9 4 3 0 7 . 2 2 3 , 7 0 7 . 1 3 , 6 3 7 . 9 4 , 5 6 3 . 9 - 5 , 8 9 6 . 4 5 , 9 7 7 , 3 8 5 . 9 5 4 1 6 , 3 0 5 . 7 0 0 . 0 4 7 , 3 6 1 . 2 9, 3 9 3 . 4 78 . 9 1 3 0 6 . 8 6 3 , 7 2 5 . 3 3 , 6 5 6 . 1 4 , 6 2 0 . 0 - 5 , 9 7 0 . 8 5 , 9 7 7 , 4 4 2 . 8 5 4 1 6 , 2 3 1 . 9 1 0 . 3 7 7 , 4 5 3 . 0 9, 4 8 7 . 8 7 8 . 9 7 3 0 6 . 4 8 3 , 7 4 3 . 5 3 , 6 7 4 . 3 4 , 6 7 5 . 4 - 6 , 0 4 5 . 2 5 , 9 7 7 , 4 9 8 . 9 9 4 1 6 , 1 5 8 . 1 2 0 . 4 0 7 , 5 4 4 . 3 9, 5 8 2 . 9 7 8 . 8 4 3 0 6 . 1 5 3 , 7 6 1 . 7 3 , 6 9 2 . 5 4 , 7 3 0 . 6 - 6 , 1 2 0 . 3 5 , 9 7 7 , 5 5 4 . 9 8 4 1 6 , 0 8 3 . 5 8 0 . 3 7 7 , 6 3 5 . 9 9, 6 5 3 . 0 7 9 . 0 0 3 0 6 . 4 0 3 , 7 7 5 . 2 3 , 7 0 6 . 0 4 , 7 7 1 . 3 - 6 , 1 7 5 . 8 5 , 9 7 7 , 5 9 6 . 2 8 4 1 6 , 0 2 8 . 5 2 0 . 4 2 7 , 7 0 3 . 6 Na n u s h u k 9, 6 7 7 . 1 7 9 . 0 6 3 0 6 . 4 9 3 , 7 7 9 . 8 3 , 7 1 0 . 6 4 , 7 8 5 . 4 - 6 , 1 9 4 . 8 5 , 9 7 7 , 6 1 0 . 5 2 4 1 6 , 0 0 9 . 6 4 0 . 4 2 7 , 7 2 6 . 8 9, 7 7 1 . 4 7 9 . 1 2 3 0 6 . 4 7 3 , 7 9 7 . 7 3 , 7 2 8 . 5 4 , 8 4 0 . 4 - 6 , 2 6 9 . 3 5 , 9 7 7 , 6 6 6 . 3 4 4 1 5 , 9 3 5 . 7 7 0 . 0 7 7 , 8 1 7 . 9 9, 8 6 6 . 4 7 9 . 1 2 3 0 6 . 5 8 3 , 8 1 5 . 6 3 , 7 4 6 . 4 4 , 8 9 6 . 0 - 6 , 3 4 4 . 2 5 , 9 7 7 , 7 2 2 . 6 4 4 1 5 , 8 6 1 . 3 8 0 . 1 1 7 , 9 0 9 . 7 9, 9 6 0 . 0 7 9 . 1 8 3 0 6 . 6 0 3 , 8 3 3 . 2 3 , 7 6 4 . 0 4 , 9 5 0 . 7 - 6 , 4 1 8 . 0 5 , 9 7 7 , 7 7 8 . 2 0 4 1 5 , 7 8 8 . 1 5 0 . 0 7 8 , 0 0 0 . 1 NT 8 M F S 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 9, 9 6 1 . 2 7 9 . 1 8 3 0 6 . 6 0 3 , 8 3 3 . 4 3 , 7 6 4 . 2 4 , 9 5 1 . 4 - 6 , 4 1 9 . 0 5 , 9 7 7 , 7 7 8 . 8 9 4 1 5 , 7 8 7 . 2 3 0 . 0 7 8 , 0 0 1 . 2 10 , 0 5 5 . 6 7 9 . 1 0 3 0 6 . 7 8 3 , 8 5 1 . 2 3 , 7 8 2 . 0 5 , 0 0 6 . 8 - 6 , 4 9 3 . 3 5 , 9 7 7 , 8 3 5 . 0 6 4 1 5 , 7 1 3 . 4 5 0 . 2 1 8 , 0 9 2 . 5 10 , 1 5 0 . 0 7 9 . 1 3 3 0 6 . 7 4 3 , 8 6 9 . 0 3 , 7 9 9 . 8 5 , 0 6 2 . 3 - 6 , 5 6 7 . 6 5 , 9 7 7 , 8 9 1 . 3 0 4 1 5 , 6 3 9 . 7 7 0 . 0 5 8 , 1 8 3 . 8 10 , 2 4 0 . 0 7 9 . 1 0 3 0 6 . 7 9 3 , 8 8 6 . 0 3 , 8 1 6 . 8 5 , 1 1 5 . 2 - 6 , 6 3 8 . 4 5 , 9 7 7 , 9 4 4 . 9 3 4 1 5 , 5 6 9 . 5 3 0 . 0 6 8 , 2 7 0 . 8 NT 7 M F S 10 , 2 4 4 . 8 7 9 . 1 0 3 0 6 . 7 9 3 , 8 8 6 . 9 3 , 8 1 7 . 7 5 , 1 1 8 . 0 - 6 , 6 4 2 . 2 5 , 9 7 7 , 9 4 7 . 7 8 4 1 5 , 5 6 5 . 7 9 0 . 0 6 8 , 2 7 5 . 4 10 , 3 4 0 . 1 7 9 . 0 9 3 0 6 . 6 0 3 , 9 0 5 . 0 3 , 8 3 5 . 8 5 , 1 7 4 . 0 - 6 , 7 1 7 . 2 5 , 9 7 8 , 0 0 4 . 4 8 4 1 5 , 4 9 1 . 3 4 0 . 2 0 8 , 3 6 7 . 5 10 , 4 3 5 . 7 7 8 . 3 6 3 0 7 . 3 5 3 , 9 2 3 . 7 3 , 8 5 4 . 5 5 , 2 3 0 . 3 - 6 , 7 9 2 . 1 5 , 9 7 8 , 0 6 1 . 6 2 4 1 5 , 4 1 7 . 0 6 1 . 0 8 8 , 4 5 9 . 8 10 , 5 1 0 . 0 7 8 . 2 0 3 0 9 . 7 9 3 , 9 3 8 . 8 3 , 8 6 9 . 6 5 , 2 7 5 . 7 - 6 , 8 4 9 . 0 5 , 9 7 8 , 1 0 7 . 5 8 4 1 5 , 3 6 0 . 6 4 3 . 2 2 8 , 5 3 1 . 8 NT 6 M F S 10 , 5 2 9 . 9 7 8 . 1 6 3 1 0 . 4 4 3 , 9 4 2 . 8 3 , 8 7 3 . 6 5 , 2 8 8 . 2 - 6 , 8 6 3 . 9 5 , 9 7 8 , 1 2 0 . 2 7 4 1 5 , 3 4 5 . 8 9 3 . 2 2 8 , 5 5 1 . 1 10 , 6 2 4 . 9 7 7 . 4 9 3 1 3 . 7 2 3 , 9 6 2 . 9 3 , 8 9 3 . 7 5 , 3 5 0 . 4 - 6 , 9 3 2 . 8 5 , 9 7 8 , 1 8 3 . 1 8 4 1 5 , 2 7 7 . 6 5 3 . 4 5 8 , 6 4 3 . 6 10 , 6 9 3 . 0 7 7 . 1 3 3 1 5 . 7 6 3 , 9 7 7 . 8 3 , 9 0 8 . 6 5 , 3 9 7 . 2 - 6 , 9 8 0 . 0 5 , 9 7 8 , 2 3 0 . 4 5 4 1 5 , 2 3 0 . 9 2 2 . 9 7 8 , 7 1 0 . 1 NT 5 M F S 10 , 7 1 9 . 9 7 6 . 9 9 3 1 6 . 5 7 3 , 9 8 3 . 9 3 , 9 1 4 . 7 5 , 4 1 6 . 1 - 6 , 9 9 8 . 1 5 , 9 7 8 , 2 4 9 . 5 5 4 1 5 , 2 1 2 . 9 7 2 . 9 7 8 , 7 3 6 . 3 10 , 8 1 3 . 9 7 6 . 1 8 3 1 9 . 1 9 4 , 0 0 5 . 7 3 , 9 3 6 . 5 5 , 4 8 4 . 0 - 7 , 0 5 9 . 5 5 , 9 7 8 , 3 1 8 . 0 0 4 1 5 , 1 5 2 . 3 5 2 . 8 4 8 , 8 2 7 . 7 10 , 8 9 5 . 0 7 5 . 6 2 3 2 1 . 2 8 4 , 0 2 5 . 4 3 , 9 5 6 . 2 5 , 5 4 4 . 4 - 7 , 1 0 9 . 8 5 , 9 7 8 , 3 7 8 . 9 6 4 1 5 , 1 0 2 . 6 8 2 . 5 9 8 , 9 0 6 . 2 NT 4 M F S 10 , 9 0 9 . 1 7 5 . 5 3 3 2 1 . 6 4 4 , 0 2 8 . 9 3 , 9 5 9 . 7 5 , 5 5 5 . 1 - 7 , 1 1 8 . 3 5 , 9 7 8 , 3 8 9 . 6 9 4 1 5 , 0 9 4 . 3 1 2 . 5 9 8 , 9 1 9 . 8 11 , 0 0 2 . 4 7 5 . 1 3 3 2 4 . 3 8 4 , 0 5 2 . 6 3 , 9 8 3 . 4 5 , 6 2 7 . 2 - 7 , 1 7 2 . 6 5 , 9 7 8 , 4 6 2 . 3 6 4 1 5 , 0 4 0 . 7 4 2 . 8 7 9 , 0 0 9 . 6 11 , 0 9 8 . 4 7 4 . 6 4 3 2 6 . 5 6 4 , 0 7 7 . 6 4 , 0 0 8 . 4 5 , 7 0 3 . 5 - 7 , 2 2 5 . 1 5 , 9 7 8 , 5 3 9 . 2 6 4 1 4 , 9 8 9 . 0 0 2 . 2 5 9 , 1 0 1 . 2 11 , 1 6 3 . 9 7 4 . 4 3 3 2 8 . 3 5 4 , 0 9 5 . 1 4 , 0 2 5 . 9 5 , 7 5 6 . 7 - 7 , 2 5 9 . 1 5 , 9 7 8 , 5 9 2 . 7 9 4 1 4 , 9 5 5 . 6 1 2 . 6 5 9 , 1 6 3 . 3 11 , 1 6 8 . 0 7 4 . 3 9 3 2 8 . 3 9 4 , 0 9 6 . 2 4 , 0 2 7 . 0 5 , 7 6 0 . 1 - 7 , 2 6 1 . 2 5 , 9 7 8 , 5 9 6 . 1 8 4 1 4 , 9 5 3 . 5 7 1 . 4 1 9 , 1 6 7 . 1 NT 3 M F S 11 , 2 0 1 . 0 7 4 . 0 4 3 2 8 . 7 2 4 , 1 0 5 . 2 4 , 0 3 6 . 0 5 , 7 8 7 . 2 - 7 , 2 7 7 . 7 5 , 9 7 8 , 6 2 3 . 4 4 4 1 4 , 9 3 7 . 2 9 1 . 4 1 9 , 1 9 8 . 2 9- 5 / 8 " I n t e r m e d i a t e L i n e r 11 , 2 4 1 . 6 7 3 . 6 2 3 2 9 . 1 2 4 , 1 1 6 . 5 4 , 0 4 7 . 3 5 , 8 2 0 . 6 - 7 , 2 9 7 . 9 5 , 9 7 8 , 6 5 7 . 0 6 4 1 4 , 9 1 7 . 5 0 1 . 4 1 9 , 2 3 6 . 4 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 11 , 2 8 0 . 0 7 5 . 1 2 3 2 9 . 9 5 4 , 1 2 6 . 8 4 , 0 5 7 . 6 5 , 8 5 2 . 5 - 7 , 3 1 6 . 6 5 , 9 7 8 , 6 8 9 . 1 0 4 1 4 , 8 9 9 . 0 9 4 . 4 3 9 , 2 7 2 . 5 NT 3 . 2 T o p R e s e r v o i r 11 , 3 3 5 . 9 7 7 . 3 1 3 3 1 . 1 3 4 , 1 4 0 . 1 4 , 0 7 0 . 9 5 , 8 9 9 . 7 - 7 , 3 4 3 . 3 5 , 9 7 8 , 7 3 6 . 6 2 4 1 4 , 8 7 2 . 9 0 4 . 4 3 9 , 3 2 5 . 2 11 , 4 3 1 . 5 8 0 . 9 9 3 3 1 . 6 8 4 , 1 5 8 . 1 4 , 0 8 8 . 9 5 , 9 8 2 . 1 - 7 , 3 8 8 . 2 5 , 9 7 8 , 8 1 9 . 5 0 4 1 4 , 8 2 8 . 8 3 3 . 8 9 9 , 4 1 6 . 1 11 , 5 2 6 . 6 8 4 . 7 7 3 3 2 . 2 9 4 , 1 6 9 . 9 4 , 1 0 0 . 7 6 , 0 6 5 . 4 - 7 , 4 3 2 . 5 5 , 9 7 8 , 9 0 3 . 2 4 4 1 4 , 7 8 5 . 3 9 4 . 0 3 9 , 5 0 7 . 2 11 , 5 9 3 . 0 8 7 . 2 7 3 3 2 . 7 3 4 , 1 7 4 . 5 4 , 1 0 5 . 3 6 , 1 2 4 . 2 - 7 , 4 6 3 . 1 5 , 9 7 8 , 9 6 2 . 3 3 4 1 4 , 7 5 5 . 4 2 3 . 8 3 9 , 5 7 1 . 0 NT 3 . 2 4 11 , 6 2 2 . 1 8 8 . 3 7 3 3 2 . 9 2 4 , 1 7 5 . 6 4 , 1 0 6 . 4 6 , 1 5 0 . 1 - 7 , 4 7 6 . 4 5 , 9 7 8 , 9 8 8 . 3 5 4 1 4 , 7 4 2 . 4 0 3 . 8 3 9 , 5 9 9 . 0 11 , 6 9 3 . 1 8 9 . 9 7 3 3 1 . 3 7 4 , 1 7 6 . 6 4, 1 0 7 . 4 6, 2 1 2 . 9 - 7 , 5 0 9 . 6 5 , 9 7 9 , 0 5 1 . 4 6 4 1 4 , 7 0 9 . 8 8 3 . 1 4 9 , 6 6 7 . 5 ND B - 0 3 0 H e e l v . 2 ( c o p y ) ( c o p y ) ( c o p y ) ( c o p y ) 11 , 7 1 7 . 4 9 0 . 5 2 3 3 0 . 8 4 4 , 1 7 6 . 5 4 , 1 0 7 . 3 6 , 2 3 4 . 1 - 7 , 5 2 1 . 3 5 , 9 7 9 , 0 7 2 . 8 0 4 1 4 , 6 9 8 . 3 9 3 . 1 4 9 , 6 9 1 . 0 11 , 8 1 2 . 7 9 0 . 4 4 3 2 9 . 1 4 4 , 1 7 5 . 7 4 , 1 0 6 . 5 6 , 3 1 6 . 6 - 7 , 5 6 8 . 9 5 , 9 7 9 , 1 5 5 . 7 9 4 1 4 , 6 5 1 . 5 9 1 . 7 9 9 , 7 8 3 . 8 11 , 9 0 7 . 9 9 0 . 3 8 32 7 . 6 4 4, 1 7 5 . 1 4 , 1 0 5 . 9 6 , 3 9 7 . 7 - 7 , 6 1 8 . 9 5 , 9 7 9 , 2 3 7 . 4 1 4 1 4 , 6 0 2 . 5 3 1 . 5 8 9 , 8 7 7 . 1 12 , 0 0 3 . 4 9 0 . 3 8 3 2 5 . 9 8 4 , 1 7 4 . 4 4 , 1 0 5 . 2 6 , 4 7 7 . 6 - 7 , 6 7 1 . 1 5 , 9 7 9 , 3 1 7 . 8 1 4 1 4 , 5 5 1 . 1 2 1 . 7 4 9 , 9 7 1 . 1 12 , 0 9 8 . 8 9 0 . 6 2 3 2 5 . 2 6 4 , 1 7 3 . 6 4 , 1 0 4 . 4 6 , 5 5 6 . 4 - 7 , 7 2 5 . 0 5 , 9 7 9 , 3 9 7 . 1 3 4 1 4 , 4 9 8 . 0 5 0 . 8 0 1 0 , 0 6 5 . 5 12 , 1 9 2 . 7 9 0 . 4 1 3 2 5 . 0 7 4 , 1 7 2 . 8 4 , 1 0 3 . 6 6 , 6 3 3 . 4 - 7 , 7 7 8 . 7 5 , 9 7 9 , 4 7 4 . 7 5 4 1 4 , 4 4 5 . 2 1 0 . 3 0 1 0 , 1 5 8 . 4 12 , 2 8 8 . 0 9 0 . 5 9 3 2 5 . 5 6 4 , 1 7 1 . 9 4 , 1 0 2 . 7 6 , 7 1 1 . 8 - 7 , 8 3 2 . 9 5 , 9 7 9 , 5 5 3 . 6 7 4 1 4 , 3 9 1 . 8 1 0 . 5 5 1 0 , 2 5 2 . 7 12 , 3 8 2 . 8 9 0 . 5 3 3 2 6 . 3 2 4 , 1 7 1 . 0 4 , 1 0 1 . 8 6 , 7 9 0 . 3 - 7 , 8 8 5 . 9 5 , 9 7 9 , 6 3 2 . 6 9 4 1 4 , 3 3 9 . 5 7 0 . 8 0 1 0 , 3 4 6 . 2 12 , 4 7 7 . 7 9 0 . 5 9 3 3 0 . 1 7 4 , 1 7 0 . 1 4 , 1 0 0 . 9 6 , 8 7 1 . 0 - 7 , 9 3 5 . 9 5 , 9 7 9 , 7 1 3 . 9 4 4 1 4 , 2 9 0 . 4 4 4 . 0 5 1 0 , 4 3 9 . 3 12 , 5 7 3 . 0 9 0 . 4 7 33 0 . 2 4 4, 1 6 9 . 2 4 , 1 0 0 . 0 6 , 9 5 3 . 7 - 7 , 9 8 3 . 3 5 , 9 7 9 , 7 9 7 . 1 2 4 1 4 , 2 4 3 . 9 5 0 . 1 5 1 0 , 5 3 2 . 1 12 , 6 6 8 . 2 9 0 . 5 6 3 3 0 . 4 7 4 , 1 6 8 . 3 4 , 0 9 9 . 1 7 , 0 3 6 . 4 - 8 , 0 3 0 . 3 5 , 9 7 9 , 8 8 0 . 3 0 4 1 4 , 1 9 7 . 7 5 0 . 2 6 1 0 , 6 2 4 . 6 12 , 7 6 2 . 5 9 0 . 8 4 3 3 2 . 1 2 4 , 1 6 7 . 2 4 , 0 9 8 . 0 7 , 1 1 9 . 2 - 8 , 0 7 5 . 6 5 , 9 7 9 , 9 6 3 . 4 9 4 1 4 , 1 5 3 . 3 1 1 . 7 7 1 0 , 7 1 6 . 0 12 , 8 5 8 . 0 9 0 . 5 3 3 3 2 . 7 7 4 , 1 6 6 . 0 4 , 0 9 6 . 8 7 , 2 0 3 . 8 - 8 , 1 1 9 . 8 5 , 9 8 0 , 0 4 8 . 5 3 4 1 4 , 1 1 0 . 0 5 0 . 7 5 1 0 , 8 0 7 . 9 12 , 9 5 3 . 7 9 0 . 4 1 3 3 1 . 2 9 4 , 1 6 5 . 2 4 , 0 9 6 . 0 7 , 2 8 8 . 3 - 8 , 1 6 4 . 7 5 , 9 8 0 , 1 3 3 . 5 4 4 1 4 , 0 6 6 . 0 4 1 . 5 5 1 0 , 9 0 0 . 3 13 , 0 4 8 . 1 9 0 . 1 0 3 3 0 . 5 5 4 , 1 6 4 . 8 4 , 0 9 5 . 6 7 , 3 7 0 . 8 - 8 , 2 1 0 . 6 5 , 9 8 0 , 2 1 6 . 5 2 4 1 4 , 0 2 1 . 0 1 0 . 8 5 1 0 , 9 9 1 . 9 13 , 1 4 3 . 9 9 0 . 1 6 3 3 0 . 2 8 4 , 1 6 4 . 6 4 , 0 9 5 . 4 7 , 4 5 4 . 1 - 8 , 2 5 7 . 8 5 , 9 8 0 , 3 0 0 . 2 6 4 1 3 , 9 7 4 . 6 1 0 . 2 9 1 1 , 0 8 5 . 0 13 , 2 3 9 . 0 9 0 . 2 6 3 2 8 . 5 1 4 , 1 6 4 . 3 4 , 0 9 5 . 1 7 , 5 3 6 . 0 - 8 , 3 0 6 . 3 5 , 9 8 0 , 3 8 2 . 6 3 4 1 3 , 9 2 7 . 0 4 1 . 8 6 1 1 , 1 7 7 . 9 13 , 3 3 4 . 5 9 0 . 1 0 3 2 7 . 4 7 4 , 1 6 4 . 0 4 , 0 9 4 . 8 7 , 6 1 6 . 9 - 8 , 3 5 6 . 9 5 , 9 8 0 , 4 6 4 . 0 9 4 1 3 , 8 7 7 . 2 8 1 . 1 0 1 1 , 2 7 1 . 6 2/ 04 /20 2 4 3 :45 :04 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 13 , 4 2 8 . 8 9 0 . 1 9 3 2 7 . 3 2 4 , 1 6 3 . 7 4 , 0 9 4 . 5 7 , 6 9 6 . 4 - 8 , 4 0 7 . 7 5 , 9 8 0 , 5 4 4 . 0 7 4 1 3 , 8 2 7 . 2 9 0 . 1 9 1 1 , 3 6 4 . 3 13 , 5 2 4 . 0 9 0 . 1 0 3 2 6 . 9 8 4 , 1 6 3 . 5 4 , 0 9 4 . 3 7 , 7 7 6 . 4 - 8 , 4 5 9 . 4 5 , 9 8 0 , 6 2 4 . 5 9 4 1 3 , 7 7 6 . 4 7 0 . 3 7 1 1 , 4 5 8 . 1 13 , 6 1 8 . 7 9 0 . 1 6 32 7 . 7 4 4, 1 6 3 . 3 4 , 0 9 4 . 1 7 , 8 5 6 . 1 - 8 , 5 1 0 . 4 5 , 9 8 0 , 7 0 4 . 8 4 4 1 3 , 7 2 6 . 2 4 0 . 8 1 1 1 , 5 5 1 . 2 13 , 7 1 4 . 1 9 0 . 1 9 3 2 8 . 5 6 4 , 1 6 3 . 0 4 , 0 9 3 . 8 7 , 9 3 7 . 1 - 8 , 5 6 0 . 8 5 , 9 8 0 , 7 8 6 . 3 9 4 1 3 , 6 7 6 . 7 4 0 . 8 6 1 1 , 6 4 4 . 7 13 , 8 0 8 . 9 9 0 . 4 1 3 2 9 . 4 2 4 , 1 6 2 . 5 4 , 0 9 3 . 3 8 , 0 1 8 . 4 - 8 , 6 0 9 . 6 5 , 9 8 0 , 8 6 8 . 1 5 4 1 3 , 6 2 8 . 7 4 0 . 9 4 1 1 , 7 3 7 . 4 13 , 9 0 3 . 2 9 0 . 2 2 3 2 8 . 8 7 4 , 1 6 2 . 0 4 , 0 9 2 . 8 8 , 0 9 9 . 3 - 8 , 6 5 8 . 0 5 , 9 8 0 , 9 4 9 . 5 8 4 1 3 , 5 8 1 . 2 4 0 . 6 2 1 1 , 8 2 9 . 6 13 , 9 9 8 . 3 9 0 . 1 6 3 2 9 . 9 1 4 , 1 6 1 . 6 4, 0 9 2 . 4 8, 1 8 1 . 1 - 8 , 7 0 6 . 4 5 , 9 8 1 , 0 3 1 . 8 7 4 1 3 , 5 3 3 . 6 9 1 . 1 0 1 1 , 9 2 2 . 4 14 , 0 9 3 . 2 9 0 . 1 9 3 3 0 . 0 5 4 , 1 6 1 . 4 4 , 0 9 2 . 2 8 , 2 6 3 . 4 - 8 , 7 5 3 . 9 5 , 9 8 1 , 1 1 4 . 5 8 4 1 3 , 4 8 7 . 0 4 0 . 1 5 1 2 , 0 1 4 . 9 14 , 1 8 8 . 1 9 0 . 1 9 3 2 9 . 3 1 4 , 1 6 1 . 0 4 , 0 9 1 . 8 8 , 3 4 5 . 3 - 8 , 8 0 1 . 8 5 , 9 8 1 , 1 9 6 . 9 9 4 1 3 , 4 3 9 . 9 9 0 . 7 8 1 2 , 1 0 7 . 4 14 , 2 8 3 . 6 9 0 . 1 6 32 8 . 4 4 4, 1 6 0 . 7 4 , 0 9 1 . 5 8 , 4 2 7 . 0 - 8 , 8 5 1 . 1 5 , 9 8 1 , 2 7 9 . 2 1 4 1 3 , 3 9 1 . 5 0 0 . 9 1 1 2 , 2 0 0 . 8 14 , 3 7 9 . 4 9 0 . 1 6 3 2 8 . 8 5 4 , 1 6 0 . 5 4 , 0 9 1 . 3 8 , 5 0 8 . 9 - 8 , 9 0 1 . 0 5 , 9 8 1 , 3 6 1 . 5 6 4 1 3 , 3 4 2 . 4 9 0 . 4 3 1 2 , 2 9 4 . 7 14 , 4 7 4 . 8 9 0 . 2 2 3 2 9 . 0 4 4 , 1 6 0 . 2 4 , 0 9 1 . 0 8 , 5 9 0 . 5 - 8 , 9 5 0 . 2 5 , 9 8 1 , 4 4 3 . 7 2 4 1 3 , 2 9 4 . 1 6 0 . 2 1 1 2 , 3 8 7 . 9 14 , 5 6 9 . 8 9 0 . 1 9 3 2 8 . 5 3 4 , 1 5 9 . 8 4 , 0 9 0 . 6 8 , 6 7 1 . 8 - 8 , 9 9 9 . 4 5 , 9 8 1 , 5 2 5 . 4 8 4 1 3 , 2 4 5 . 7 8 0 . 5 4 1 2 , 4 8 0 . 9 14 , 6 6 4 . 2 9 0 . 1 6 3 2 8 . 6 9 4 , 1 5 9 . 5 4 , 0 9 0 . 3 8 , 7 5 2 . 4 - 9 , 0 4 8 . 6 5 , 9 8 1 , 6 0 6 . 5 9 4 1 3 , 1 9 7 . 4 3 0 . 1 7 1 2 , 5 7 3 . 3 14 , 7 5 9 . 6 9 0 . 0 7 3 2 9 . 4 5 4 , 1 5 9 . 3 4 , 0 9 0 . 1 8 , 8 3 4 . 2 - 9 , 0 9 7 . 6 5 , 9 8 1 , 6 8 8 . 8 9 4 1 3 , 1 4 9 . 2 7 0 . 8 0 1 2 , 6 6 6 . 6 14 , 8 5 5 . 4 9 0 . 0 7 3 2 9 . 9 9 4 , 1 5 9 . 2 4 , 0 9 0 . 0 8 , 9 1 7 . 0 - 9 , 1 4 6 . 0 5 , 9 8 1 , 7 7 2 . 1 6 4 1 3 , 1 0 1 . 8 0 0 . 5 6 1 2 , 7 6 0 . 0 14 , 9 4 9 . 7 9 0 . 1 0 3 3 0 . 2 5 4 , 1 5 9 . 1 4 , 0 8 9 . 9 8 , 9 9 8 . 7 - 9 , 1 9 2 . 9 5 , 9 8 1 , 8 5 4 . 3 5 4 1 3 , 0 5 5 . 7 1 0 . 2 8 1 2 , 8 5 1 . 8 15 , 0 4 5 . 1 9 0 . 0 1 3 2 9 . 8 7 4 , 1 5 9 . 0 4 , 0 8 9 . 8 9 , 0 8 1 . 4 - 9 , 2 4 0 . 5 5 , 9 8 1 , 9 3 7 . 4 9 4 1 3 , 0 0 8 . 9 7 0 . 4 1 1 2 , 9 4 4 . 7 15 , 1 3 9 . 3 9 0 . 0 1 3 3 0 . 1 7 4 , 1 5 9 . 0 4 , 0 8 9 . 8 9 , 1 6 3 . 0 - 9 , 2 8 7 . 6 5 , 9 8 2 , 0 1 9 . 5 7 4 1 2 , 9 6 2 . 7 4 0 . 3 2 1 3 , 0 3 6 . 4 15 , 2 3 4 . 9 9 0 . 4 7 3 3 0 . 1 3 4 , 1 5 8 . 6 4, 0 8 9 . 4 9, 2 4 5 . 9 - 9 , 3 3 5 . 2 5 , 9 8 2 , 1 0 3 . 0 2 4 1 2 , 9 1 6 . 0 0 0 . 4 8 1 3 , 1 2 9 . 5 15 , 3 3 0 . 3 9 0 . 4 7 3 2 9 . 9 1 4 , 1 5 7 . 8 4 , 0 8 8 . 6 9 , 3 2 8 . 5 - 9 , 3 8 2 . 8 5 , 9 8 2 , 1 8 6 . 0 8 4 1 2 , 8 6 9 . 2 3 0 . 2 3 1 3 , 2 2 2 . 4 15 , 4 2 4 . 9 9 0 . 4 4 3 3 0 . 1 6 4 , 1 5 7 . 0 4 , 0 8 7 . 8 9 , 4 1 0 . 5 - 9 , 4 3 0 . 1 5 , 9 8 2 , 2 6 8 . 5 3 4 1 2 , 8 2 2 . 8 2 0 . 2 7 1 3 , 3 1 4 . 5 15 , 5 1 9 . 0 9 0 . 4 7 3 3 0 . 0 7 4 , 1 5 6 . 3 4 , 0 8 7 . 1 9 , 4 9 2 . 1 - 9 , 4 7 7 . 0 5 , 9 8 2 , 3 5 0 . 5 9 4 1 2 , 7 7 6 . 7 9 0 . 1 0 1 3 , 4 0 6 . 1 15 , 6 1 2 . 4 9 0 . 4 7 3 3 0 . 3 6 4 , 1 5 5 . 5 4 , 0 8 6 . 3 9 , 5 7 3 . 1 - 9 , 5 2 3 . 4 5 , 9 8 2 , 4 3 2 . 1 1 4 1 2 , 7 3 1 . 2 5 0 . 3 1 1 3 , 4 9 7 . 0 15 , 7 1 0 . 5 9 0 . 4 1 3 3 0 . 3 9 4 , 1 5 4 . 8 4 , 0 8 5 . 6 9 , 6 5 8 . 4 - 9 , 5 7 1 . 9 5 , 9 8 2 , 5 1 7 . 9 2 4 1 2 , 6 8 3 . 6 3 0 . 0 7 1 3 , 5 9 2 . 4 15 , 8 0 5 . 4 9 0 . 4 1 3 2 9 . 6 8 4 , 1 5 4 . 1 4 , 0 8 4 . 9 9 , 7 4 0 . 6 - 9 , 6 1 9 . 3 5 , 9 8 2 , 6 0 0 . 5 6 4 1 2 , 6 3 7 . 1 2 0 . 7 5 1 3 , 6 8 4 . 8 15 , 9 0 0 . 4 9 0 . 5 3 3 2 9 . 6 3 4 , 1 5 3 . 3 4 , 0 8 4 . 1 9 , 8 2 2 . 6 - 9 , 6 6 7 . 3 5 , 9 8 2 , 6 8 3 . 0 5 4 1 2 , 5 8 9 . 9 7 0 . 1 4 1 3 , 7 7 7 . 5 2/ 04 /20 2 4 3 :45 :04 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 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 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 ) 15 , 9 9 5 . 4 9 0 . 4 4 3 2 9 . 4 1 4 , 1 5 2 . 5 4 , 0 8 3 . 3 9 , 9 0 4 . 5 - 9 , 7 1 5 . 5 5 , 9 8 2 , 7 6 5 . 4 3 4 1 2 , 5 4 2 . 6 3 0 . 2 5 1 3 , 8 7 0 . 2 16 , 0 9 0 . 6 9 0 . 4 7 3 2 8 . 1 3 4 , 1 5 1 . 8 4 , 0 8 2 . 6 9 , 9 8 5 . 9 - 9 , 7 6 4 . 8 5 , 9 8 2 , 8 4 7 . 3 4 4 1 2 , 4 9 4 . 1 2 1 . 3 4 1 3 , 9 6 3 . 4 16 , 1 8 6 . 2 9 0 . 3 5 3 2 8 . 2 0 4 , 1 5 1 . 1 4 , 0 8 1 . 9 1 0 , 0 6 7 . 1 - 9 , 8 1 5 . 2 5 , 9 8 2 , 9 2 9 . 0 3 4 1 2 , 4 4 4 . 5 7 0 . 1 5 1 4 , 0 5 7 . 1 16 , 2 8 0 . 7 9 0 . 4 4 32 8 . 1 4 4, 1 5 0 . 4 4 , 0 8 1 . 2 1 0 , 1 4 7 . 4 - 9 , 8 6 5 . 1 5 , 9 8 3 , 0 0 9 . 8 4 4 1 2 , 3 9 5 . 5 6 0 . 1 1 1 4 , 1 4 9 . 8 16 , 3 7 6 . 1 9 0 . 4 1 3 2 7 . 8 1 4 , 1 4 9 . 7 4 , 0 8 0 . 5 1 0 , 2 2 8 . 3 - 9 , 9 1 5 . 7 5 , 9 8 3 , 0 9 1 . 2 2 4 1 2 , 3 4 5 . 8 2 0 . 3 5 1 4 , 2 4 3 . 4 16 , 4 7 1 . 1 9 0 . 4 7 3 2 9 . 7 6 4 , 1 4 9 . 0 4 , 0 7 9 . 8 1 0 , 3 0 9 . 4 - 9 , 9 6 4 . 9 5 , 9 8 3 , 1 7 2 . 9 1 4 1 2 , 2 9 7 . 4 7 2 . 0 5 1 4 , 3 3 6 . 3 16 , 5 6 6 . 7 9 0 . 4 1 3 2 9 . 7 3 4 , 1 4 8 . 3 4 , 0 7 9 . 1 1 0 , 3 9 2 . 0 - 1 0 , 0 1 3 . 1 5 , 9 8 3 , 2 5 6 . 0 1 4 1 2 , 2 5 0 . 1 5 0 . 0 7 1 4 , 4 2 9 . 5 16 , 6 6 1 . 6 9 0 . 4 1 3 2 9 . 3 9 4 , 1 4 7 . 6 4 , 0 7 8 . 4 1 0 , 4 7 3 . 9 - 1 0 , 0 6 1 . 1 5 , 9 8 3 , 3 3 8 . 3 4 4 1 2 , 2 0 2 . 9 1 0 . 3 6 1 4 , 5 2 2 . 2 16 , 7 5 6 . 1 9 0 . 4 4 3 2 9 . 8 2 4 , 1 4 6 . 9 4 , 0 7 7 . 7 1 0 , 5 5 5 . 4 - 1 0 , 1 0 8 . 9 5 , 9 8 3 , 4 2 0 . 2 9 4 1 2 , 1 5 5 . 9 8 0 . 4 6 1 4 , 6 1 4 . 3 16 , 8 5 0 . 5 9 0 . 4 4 3 3 0 . 3 2 4 , 1 4 6 . 1 4 , 0 7 6 . 9 1 0 , 6 3 7 . 2 - 1 0 , 1 5 6 . 1 5 , 9 8 3 , 5 0 2 . 6 2 4 1 2 , 1 0 9 . 7 1 0 . 5 3 1 4 , 7 0 6 . 3 16 , 9 4 5 . 9 9 0 . 3 8 3 2 9 . 8 0 4 , 1 4 5 . 5 4 , 0 7 6 . 3 1 0 , 7 1 9 . 8 - 1 0 , 2 0 3 . 6 5 , 9 8 3 , 5 8 5 . 7 1 4 1 2 , 0 6 3 . 0 0 0 . 5 5 1 4 , 7 9 9 . 1 17 , 0 4 1 . 0 9 0 . 4 7 3 2 9 . 6 8 4 , 1 4 4 . 8 4 , 0 7 5 . 6 1 0 , 8 0 2 . 0 - 1 0 , 2 5 1 . 6 5 , 9 8 3 , 6 6 8 . 3 7 4 1 2 , 0 1 5 . 9 2 0 . 1 6 1 4 , 8 9 1 . 8 17 , 1 3 5 . 8 9 0 . 3 8 3 2 9 . 4 2 4 , 1 4 4 . 1 4 , 0 7 4 . 9 1 0 , 8 8 3 . 7 - 1 0 , 2 9 9 . 6 5 , 9 8 3 , 7 5 0 . 5 9 4 1 1 , 9 6 8 . 7 2 0 . 2 9 1 4 , 9 8 4 . 4 17 , 2 3 0 . 2 9 0 . 3 8 3 2 9 . 3 9 4 , 1 4 3 . 4 4 , 0 7 4 . 2 1 0 , 9 6 5 . 0 - 1 0 , 3 4 7 . 7 5 , 9 8 3 , 8 3 2 . 3 2 4 1 1 , 9 2 1 . 5 4 0 . 0 3 1 5 , 0 7 6 . 5 17 , 3 2 5 . 4 9 0 . 4 7 3 3 0 . 1 6 4 , 1 4 2 . 7 4 , 0 7 3 . 5 1 1 , 0 4 7 . 2 - 1 0 , 3 9 5 . 6 5 , 9 8 3 , 9 1 5 . 0 5 4 1 1 , 8 7 4 . 4 8 0 . 8 1 1 5 , 1 6 9 . 3 17 , 4 2 0 . 9 9 0 . 4 4 3 2 8 . 8 4 4 , 1 4 2 . 0 4 , 0 7 2 . 8 1 1 , 1 2 9 . 5 - 1 0 , 4 4 4 . 1 5 , 9 8 3 , 9 9 7 . 8 7 4 1 1 , 8 2 6 . 8 5 1 . 3 8 1 5 , 2 6 2 . 5 17 , 5 0 3 . 9 9 0 . 4 4 3 2 8 . 2 7 4 , 1 4 1 . 3 4 , 0 7 2 . 1 1 1 , 2 0 0 . 3 - 1 0 , 4 8 7 . 4 5 , 9 8 4 , 0 6 9 . 1 1 4 1 1 , 7 8 4 . 2 9 0 . 6 9 1 5 , 3 4 3 . 8 17 , 5 2 1 . 6 9 0 . 4 4 3 2 8 . 2 7 4 , 1 4 1 . 2 4 , 0 7 2 . 0 1 1 , 2 1 5 . 4 - 1 0 , 4 9 6 . 6 5 , 9 8 4 , 0 8 4 . 2 1 4 1 1 , 7 7 5 . 1 7 0 . 0 0 1 5 , 3 6 1 . 1 ND B - 0 3 0 T D v . 3 ( c o p y ) ( c o p y ) ( c o p y ) ( c o p y ) 17 , 5 2 2 . 0 9 0 . 4 4 3 2 8 . 2 7 4 , 1 4 1 . 2 4 , 0 7 2 . 0 1 1 , 2 1 5 . 7 - 1 0 , 4 9 6 . 9 5 , 9 8 4 , 0 8 4 . 5 7 4 1 1 , 7 7 4 . 9 6 0 . 0 0 1 5 , 3 6 1 . 5 4- 1 / 2 " P r o d u c t i o n L i n e r 17 , 5 2 9 . 0 9 0 . 4 4 3 2 8 . 2 7 4 , 1 4 1 . 1 4 , 0 7 1 . 9 1 1 , 2 2 1 . 7 - 1 0 , 5 0 0 . 5 5 , 9 8 4 , 0 9 0 . 5 6 4 1 1 , 7 7 1 . 3 4 0 . 0 0 1 5 , 3 6 8 . 4 Pr o j T D 2/ 04 /20 2 4 3 :45 :04 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 1 1 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 i - 0 3 0 ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t De s i g n : ND B i - 0 3 0 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 R K B @ 6 9 . 2 u s f t No r t h R e f e r e n c e : We l l N D B i -03 0 Tr u e Ve r t i c a l De p t h (us f t ) Me a s u r e d De p t h (us f t ) Ca s i n g Di a m e t e r (" ) Ho l e Di a m e t e r (" ) Na m e Ca s i n g P o i n t s 20 " C o n d u c t o r D r i v e n 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 6 1 . 9 2, 5 5 0 . 0 13 - 3 / 8 1 6 9- 5 / 8 " I n t e r m e d i a t e L i n e r 4, 1 0 5 . 2 11 , 2 0 1 . 0 9- 5 / 8 1 2 - 1 / 4 4- 1 / 2 " P r o d u c t i o n L i n e r 4, 1 4 1 . 2 17 , 5 2 2 . 0 4- 1 / 2 8 - 1 / 2 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 2, 8 9 8 . 0 2 , 4 3 7 . 0 T u l u v a k S h a l e 9, 6 5 3 . 0 3 , 7 7 5 . 2 N a n u s h u k 10 , 8 9 5 . 0 4 , 0 2 5 . 4 N T 4 M F S 1, 4 1 5 . 0 1 , 3 8 9 . 3 P e r m a f r o s t B a s e 4, 6 6 0 . 0 2 , 8 2 1 . 6 T S 7 9 0 9, 9 6 0 . 0 3 , 8 3 3 . 2 N T 8 M F S 0 . 0 0 10 , 6 9 3 . 0 3 , 9 7 7 . 8 N T 5 M F S 3, 0 6 2 . 0 2 , 4 9 8 . 0 T u l u v a k S a n d 6, 1 4 8 . 0 3 , 1 0 3 . 3 S e a b e e 1, 8 3 5 . 0 1 , 7 5 8 . 4 M i d d l e S c h r a d e r B l u f f 11 , 2 8 0 . 0 4 , 1 2 6 . 8 N T 3 . 2 T o p R e s e r v o i r 1, 0 4 8 . 0 1 , 0 3 8 . 9 U p p e r S c h r a d e r B l u f f 11 , 1 6 8 . 0 4 , 0 9 6 . 2 N T 3 M F S 10 , 2 4 0 . 0 3 , 8 8 6 . 0 N T 7 M F S 11 , 5 9 3 . 0 4 , 1 7 4 . 5 N T 3 . 2 4 0 . 0 0 10 , 5 1 0 . 0 3 , 9 3 8 . 8 N T 6 M F S 2, 3 3 4 . 0 2 , 1 3 1 . 1 M C U ( L o w e r S c h r a d e r B l u f f ) 2/ 04 /20 2 4 3 :45 :04 P M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 1 2 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. You don't often get email from rob.o'neal@contractor.santos.com. Learn why this is important From:Brooks, Phoebe L (OGC) To:O"Neal, Robert (Rob) Cc:Regg, James B (OGC) Subject:RE: BOP test Parker 272 NDBi-030, 2-22-2024 Date:Thursday, March 21, 2024 11:44:27 AM Attachments:Parker 272 02-22-24 Revised.xlsx image001.png Rob, Attached is a revised report changing the MASP to reflect 1497 and correcting some formatting. Please review and update your copy or let me know if you disagree. Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation 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: O'Neal, Robert (Rob) <Rob.O'Neal@contractor.santos.com> Sent: Friday, February 23, 2024 1:36 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Subject: BOP test Parker 272 NDBi-030, 2-22-2024 Please see attached with correct permit number format and let us know if anything needs to be corrected. Robert O’Neal (Rob) Drilling Well Site Supervisor, Parker 272 Alternate John Whitlatch o: +1 907-685-4230 | m: +1 907-268-0648 | e: rob.o’neal@contractor.santos.com Pikka NDB-30 PTD 2231200 J. Regg; 4/1/2024 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:272 DATE:2/22/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231200 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:X Weekly:Bi-Weekly:Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1497 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 2 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13-5/8" 5M P Pit Level Indicators P P #1 Rams 1 4-1/2 x 7" VBR P Flow Indicator P P #2 Rams 1 Blind/Shear P Meth Gas Detector P P #3 Rams 1 9 5/8" FBR P H2S Gas Detector P P #4 Rams 0 N/A NA MS Misc 0 NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3-1/8 P Time/Pressure Test Result HCR Valves 2 3-1/8 P System Pressure (psi)3000 P Kill Line Valves 2 2-1/16" 3-1/8"P Pressure After Closure (psi)2075 P Check Valve 0 N/A NA 200 psi Attained (sec)20 P BOP Misc 0 N/A NA Full Pressure Attained (sec)68 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):14@2100 P No. Valves 15 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 17 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 6 P Inside Reel valves 0 NA #3 Rams 6 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:5.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 02/20/2024 0543hrs Waived By Test Start Date/Time:2/22/2024 2:00 (date)(time)Witness Test Finish Date/Time:2/22/2024 7:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Parker Tested with 5 7/8" and 9 5/8" test Joints Sonny Clark Oil Search (Alaska) LLC Rowland Lawson Pikka NDBi-030 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)2024-0222_BOP_Parker272_Pikka_NDB-30 J. Regg; 4/1/2024 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-030 (50-103-20873-0000) Final Well data Submittal Details on following pages Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh P.O. Box 240927, Anchorage, AK 99524-0927 shannon.koh@santos.com DATE: 4/24/2024 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: 223-120 T38737 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.24 12:43:18 -08'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDBi-030 Definitive Compass Survey Report - NAD27.pdf ؒ NDBi-030 Definitive Compass Survey Report - NAD83.pdf ؒ NDBi-030 Definitive Survey Report - NAD27.txt ؒ NDBi-030 Definitive Survey Report - NAD83.txt ؒ NDBi-030 Plan View.pdf ؒ NDBi-030 Vertical Section.pdf ؒ جؐؐؐLog Digital Data (LWD and WL) ؒ جؐؐؐBaker Hughes ؒ ؒ جؐؐؐDigital Data ؒ ؒ ؒ جؐؐؐFE ؒ ؒ ؒ ؒ NDBi-030_LWDl_RM_17529ft.las ؒ ؒ ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ ؒ NDBi-030_AP_R01_RM_20240219.las ؒ ؒ ؒ ؒ NDBi-030_AP_R02_RM_20240303.las ؒ ؒ ؒ ؒ NDBi-030_AP_R03_RM_20240309.las ؒ ؒ ؒ ؒ NDBi-030_AP_R04_RM_20240316.las ؒ ؒ ؒ ؒ NDBi-030_AP_R05_RM_20240318.las ؒ ؒ ؒ ؒ NDBi-030_AP_R06_RM_20240323.las ؒ ؒ ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ ؒ NDBi-030_DMD_RM_17529ft.las ؒ ؒ ؒ NDBi-030_DMT_R01_20240219.las ؒ ؒ ؒ NDBi-030_DMT_R02_20240303.las ؒ ؒ ؒ NDBi-030_DMT_R03_20240309.las ؒ ؒ ؒ NDBi-030_DMT_R04_20240316.las ؒ ؒ ؒ NDBi-030_DMT_R05_20240318.las ؒ ؒ ؒ NDBi-030_DMT_R06_20240323.las ؒ ؒ ؒ ؒ ؒ جؐؐؐGeoscience Deliverables ؒ ؒ ؒ جؐؐؐImageTrak ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_1-200ftMD.cgm ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_1-200ftMD.pdf ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_1-40ftMD.cgm ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_1-40ftMD.pdf ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_1-500ftMD.cgm ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_1-500ftMD.pdf ؒ ؒ ؒ ؒ NDBi-030_LWD_IMG100_ITK-PROC_11209ft-17475ft_V2.dlis ؒ ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.cgm ؒ ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.dlis LETTER OF TRANSMITTAL ؒ ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.las ؒ ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.pdf ؒ ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201_dlis.txt ؒ ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.cgm ؒ ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.dlis ؒ ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.las ؒ ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.PDF ؒ ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201_dlis.txt ؒ ؒ ؒ ؒ ؒ ؒ ؒ ؤؐؐؐSoundTrak CBL ؒ ؒ ؒ NDBi-030_9_625_Liner_Baker_Hughes_CBL_Final Report.V2.pdf ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.cgm ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.dlis ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.las ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201.pdf ؒ ؒ ؒ NDBi-030_SDTK_CBL_7000_11201_dlis.txt ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.cgm ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.dlis ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.las ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201.PDF ؒ ؒ ؒ NDBi-030_SDTK_TOC_7000_11201_dlis.txt ؒ ؒ ؒ ؒ ؒ ؤؐؐؐGraphics Images ؒ ؒ جؐؐؐCGM ؒ ؒ ؒ جؐؐؐFE ؒ ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_2MD.cgm ؒ ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_2TVD.cgm ؒ ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_5MD.cgm ؒ ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_5TVD.cgm ؒ ؒ ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ ؒ NDBi-030_AP_RM_20240323.cgm ؒ ؒ ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ ؒ NDBi-030_DMD_RM_17529ft.cgm ؒ ؒ ؒ NDBi-030_DMT_RM_20240323.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐPDF ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_2MD.pdf ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_2TVD.pdf ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_5MD.pdf LETTER OF TRANSMITTAL ؒ ؒ ؒ NDBi-030_LWD_GR_Res_Den_Neu_Cal_RM_17529ft_5TVD.pdf ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-030_AP_RM_20240323.pdf ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-030_DMD_RM_17529ft.pdf ؒ ؒ NDBi-030_DMT_RM_20240323.pdf ؒ ؒ ؒ ؤؐؐؐHalliburton ؒ جؐؐؐCGM ؒ ؒ NDBi-030 Deep Resistivity LWD Final MD.cgm ؒ ؒ NDBi-030 Deep Resistivity LWD Final TVD.cgm ؒ ؒ ؒ جؐؐؐEMF ؒ ؒ NDBi-030 Deep Resistivity LWD Final MD.emf ؒ ؒ NDBi-030 Deep Resistivity LWD Final TVD.emf ؒ ؒ ؒ جؐؐؐLWD Data ؒ ؒ NDBi-030 LWD Resistivity Final.las ؒ ؒ NDBi-030_EarthStar_Images.dlis ؒ ؒ NDBi-030_Earthstar_Images.ver ؒ ؒ NDBi-030_Stratastar_Images.dlis ؒ ؒ NDBi-030_Stratastar_Images.ver ؒ ؒ ؒ جؐؐؐPDF ؒ ؒ NDBi-030 Deep Resistivity LWD Final MD.pdf ؒ ؒ NDBi-030 Deep Resistivity LWD Final TVD.pdf ؒ ؒ ؒ ؤؐؐؐTIFF ؒ NDBi-030 Deep Resistivity Final MD.tif ؒ NDBi-030 Deep Resistivity LWD Final TVD.tif ؒ ؤؐؐؐMudlog جؐؐؐGeological Reports (compilation in PDF) ؒ NDBi-030 Mudlogging Daily Reports compilation.pdf ؒ ؤؐؐؐMudlogging final data NDBi-030 GEOISTOPES G5 CORRECTED data_17529ft_Final.las NDBi-030_DrillGas_depth_17529ft MD.las NDBi-030_DrillGas_Lithology_depth_17529ft MD.las NDBi-030_G5 Delta Gas Ratios_Composite_Final.pdf NDBi-030_G5 Delta Gas_GEOISOTOPES_Composite_Final.pdf LETTER OF TRANSMITTAL NDBi-030_GasRatioLog_17529ft MD_2inch.pdf NDBi-030_GasRatioLog_17529ft MD_5inch.pdf NDBi-030_Lithology.xlsx NDBi-030_MudLog_17529ft MD_2inch.pdf NDBi-030_MudLog_17529ft MD_5inch.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 12 boxes of washed and dried cutting samples NDBi-030 (50-103-20873-0000) 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: 3/25/2024 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 – Dry cutting samples 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: By Meredith Guhl at 11:56 am, Mar 28, 2024 223-120 1875 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.28 12:03:10 -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:Buzby, Brian (Brian) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Whitlatch, John (John); Lawson, Rowland (Rowland); O"Neal, Robert (Rob) Subject:Parker Rig 272 BOP Test Report NDBi-030 3-17-24 Date:Monday, March 18, 2024 10:27:34 AM Attachments:BOPE Test State Form NDBi-030 03-17-2024.xlsx Some people who received this message don't often get email from brian.buzby@contractor.santos.com. Learn why this is important Here is the BOP test report. Let me know of any changes. Thanks Brian Buzby Brian Buzby – Well Site Supervisor Parker 272 Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) xxx-xxx | m: +1 (907) 355-4253 Brian.buzby@contractor.santos.com https://www.santos.com/ 3LNND1'% 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:272 DATE: 3/17/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2231200 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: Weekly: Bi-Weekly: X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1497 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 1P Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8" 5M FP Pit Level Indicators PP #1 Rams 1 4-1/2 x 7" VBR P Flow Indicator PP #2 Rams 1 Blind/Shear P Meth Gas Detector PP #3 Rams 1 4-1/2 x 7" VBR P H2S Gas Detector PP #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3-1/8 P Time/Pressure Test Result HCR Valves 2 3-1/8 P System Pressure (psi)3000 P Kill Line Valves 2 2-1/16" 3-1/8"P Pressure After Closure (psi)1950 P Check Valve 0 N/A NA 200 psi Attained (sec)19 P BOP Misc 0 N/A NA Full Pressure Attained (sec)78 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2350 P No. Valves 15 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 29 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 10 P Inside Reel valves 0NA #3 Rams 6 P #4 Rams N/A NA Test Results #5 Rams N/A NA #6 Rams N/A NA Number of Failures:1 Test Time:11 Hours HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3/15/24 08:30 Waived By Test Start Date/Time:3/16/2024 17:00 (date) (time)Witness Test Finish Date/Time:3/17/2024 5:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Parker Tested with 4 1/2" and 5" DP, Annular failed on shell test. Replaced annular element and tested. Pat Lynch Oil Search (Alaska) LLC Brian Buzby Pikka NDBi-030 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022) 2024-0317_BOP_Parker272_Pikka_NDB-030 9 9 9 9 9 9 9 9 9 9 9 Annular failed FP From:McLellan, Bryan J (OGC) To:Staudinger, Garret (Garret) Subject:NDB-030 (PTD 223-120) logging 2nd stage cement Date:Thursday, March 14, 2024 1:28:00 PM Garret, Following up from the question you asked by phone: Q: Will there be a requirement to run a Cement evaluation log across the second stage cement in Intermediate 9-5/8” liner, based on the difficulties with the first stage cement job? A: No. The second stage cement job went essentially according to plan, with ~50 bbls of cement circulated across the top of the liner, indicating likely good cement coverage across and above the upper Tuluvak. Therefore, the procedures in the approved PTD, which do not require logging the second stage cement, can be followed. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDBi-030 JBR 04/12/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 5" and 9 5/8" test joints were used for testing. The annular failed and was cycled and retested for a pass. Test Results TEST DATA Rig Rep:S. Clark/N. WherleyOperator:Oil Search (Alaska), LLC Operator Rep:B. Buzby/J. Whitlatch Rig Owner/Rig No.:Parker 272 PTD#:2231200 DATE:3/8/2024 Type Operation:DRILL Annular: 250/3500Type Test:BIWKLY Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopGDC240308130654 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 11 MASP: 1497 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 FP #1 Rams 1 4.5"x7"VBR P #2 Rams 1 Blind/Shear P #3 Rams 1 9 5/8" Solids P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5000 P HCR Valves 2 3 1/8" 5000 P Kill Line Valves 2 2 1/16" 3 1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2050 200 PSI Attained P19 Full Pressure Attained P68 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2125 ACC Misc NA 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 P23 #1 Rams P7 #2 Rams P7 #3 Rams P7 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 1 Junke, Kayla M (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, February 26, 2024 8:56 AM To:Staudinger, Garret (Garret); Dewhurst, Andrew D (OGC) Cc:Villarreal, Aimee (Aimee) Subject:RE: NDBi-030 (PTD223-120) Open Hole Log for stage collar Garret, Oilsearch has approval to set the Intermediate stage collar no less than 50’ MD below the TS 790 top, which was picked at 4660’ MD (stage collar set no shallower than 4710’ MD). Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Sunday, February 25, 2024 9:14 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Villarreal, Aimee (Aimee) <Aimee.Villarreal@santos.com> Subject: NDBi-030 (PTD223-120) Open Hole Log for stage collar Bryan / Andy, Attached is the real time open hole log for NDBi-030. Note that we are currently still drilling the intermediate hole. I wanted to get this log of the Tuluvak formation to you as soon as possible to get approval for stage collar setting depth. FYI, we should reach TD of the hole section Monday morning sometime, and will then be performing a wiper trip prior to coming out of hole to pick up the liner. Let me know if you have any questions, and if we have approval for stage tool setting depth 50' MD below the top of the TS 790. Thanks, Garret CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 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:Buzby, Brian (Brian) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:O"Neal, Robert (Rob); Lawson, Rowland (Rowland); Whitlatch, John (John); Staudinger, Garret (Garret) Subject:Santos Pikka NDBi-030 Diverter Inspection test Report Date:Saturday, February 17, 2024 10:52:36 AM Attachments:NDBi-030 Diverter test 2-16-24.xlsx You don't often get email from brian.buzby@contractor.santos.com. Learn why this is important Diverter Test report Pikka NDBi-030 Thanks Brian Buzby Brian Buzby – Well Site Supervisor Parker 272 Oil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) xxx-xxx | m: +1 (907) 355-4253 Brian.buzby@contractor.santos.com https://www.santos.com/ 3LNND1'% 37' Date: 2/16/2024 Development: X Exploratory: Drlg Contractor: Rig No. 272 AOGCC Rep: Operator:Oper. Rep: Field/Unit/Well No.:Rig Rep: PTD No.: 2231200 Rig Phone: Rig Email: MMISCELLANEOUS:DIVERTER SYSTEM: Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P Warning Sign P Misc: NA No Threaded Connections? P 24 hr Notice: P Vent line Below Diverter? P AACCUMULATOR SYSTEM:Diverter Size: 21 1/4 in. Systems Pressure: 3000 psig P Hole Size: 16 in. Pressure After Closure: 2350 psig P Vent Line(s) Size: 16 in. P 200 psi Recharge Time: 15 Seconds P Vent Line(s) Length: 40.25 ft. P Full Recharge Time:48 Seconds P Closest Ignition Source: 100 ft. P Nitrogen Bottles (Number of): 14 Outlet from Rig Substructure: 51 ft. P Avg. Pressure: 2150 psig P Accumulator Misc: NA Vent Line(s) Anchored: P MMUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: NA Trip Tank: P P Divert Valve(s) Full Opening: P Mud Pits: P P Valve(s) Auto & Simultaneous: Flow Monitor: P P Annular Closed Time: 28 sec P Mud System Misc: 0 NA Knife Valve Open Time: 23 sec P Diverter Misc: NA GGAS DETECTORS:Visual Alarm Methane: P P Hydrogen Sulfide: P P Gas Detectors Misc: 0 NA Total Test Time: 2 hrs Non-Compliance Items: 0 Remarks: Submit to: rig272.seniormanager@parkerwellbor TTEST DATA Russell Woods phoebe.brooks@alaska.gov Oil Search (Alaska), LLC Wittness Waived by Guy Cook @ 06:00 on 2/15/2024 0 Rob O'Neal 0 907-685-4242 TTEST DETAILS jim.regg@alaska.gov AOGCC.Inspectors@alaska.gov Pikka / Nanushuk Oil Pool NDBi-030 SSTATE OF ALASK A AALASK A OIL AND GAS CONSERVATION COMMISSION DDiver ter Systems Inspection Report GGENERAL INFORMATION WaivedParker **All Diverter reports are due to the agency w ithin 5 days of testing* Form 10-425 (Revised 05/2021)2024-0216_Diverter_Parker272_Pikka_NDB-030 9 9 9 9 -5HJJ 9 9 9 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Garret Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 900 E Benson Blvd. Anchorage, AK 99508 Re: Pikka Field, Nanushuk Oil Pool, NDBi-030 Oil Search Alaska, LLC Permit to Drill Number: 223-120 Surface Location: 2377’ FSL, 3091 FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 3205’ FSL, 3105’ FEL, Sec 30, 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 January, 2024. 29 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.01.29 14:14:26 -09'00' 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: 17529 TVD:4143 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 3243’ FSL, 5’ FEL, Sec 31, T12N, R6E, UM Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3205’ FSL, 3105’ FEL, Sec 30, T12N, R6E, UM 7760' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10.KB Elevation above MSL (ft): 70.9 15.Distance to Nearest Well Open Surface: x- 422154 y- 5972762 Zone- 4 22.84 to Same Pool: 197' 16.Deviated wells: Kickoff depth: 350 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90.43 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 54' 16" 13-3/8" 68# L-80 BTC 2617' Surface Surface 2617' 2303' 12-1/4" 9-5/8" 47# L-80 HYD563 8675' 2467' 2217' 11142' 4089' Tie Back 9-5/8" 47# L-80 HYD563 2467' Surface Surface 2467' 2217' 8-1/2" 4-1/2" 12.6# P-110S HYD563 6607' 10992' 4049' 17529' 4143' Tubing 4-1/2" 12.6# P-110S HYD563 10992' Surface Surface 10992' 4049' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Garret Staudinger Garret Staudinger Contact Email:garret.staudinger@santos.com Senior Drilling Engineer Contact Phone:907-440-6892 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Signature: Production Liner Intermediate Authorized Name: Authorized Title: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Casing Total Depth MD (ft): Total Depth TVD (ft): Conductor/Structural Cement Volume MDSize Plugs (measured): Length 18.Casing Program: (including stage data) Grouted to Surface Please see attachment 6 for details Production liner is uncemented N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): Please see attachment 6 for details Please see attachment 6 for details STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Top - Setting Depth - BottomSpecifications 1893 GL / BF Elevation above MSL (ft): 1871 LONS 19-003 900 E Benson Boulevard, Anchorage, AK 99508 Oil Search Alaska, LLC 2365’ FSL, 3091 FEL, Sec 4, T11N, R6E, UM ADL 392984,391445,393020,393019,393018 3,099' Total IS000361277U NDBi-030 Pikka / Nanushuk Oil Pool 01/15/24 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o D s s D o well is p G S S 20 S S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 11/29/2023 Senior Drilling Engineer By Grace Christianson at 2:50 pm, Dec 11, 2023 Variance to 20 AAC 25.030(d)(5) for 2-stage intermediate casing cement operation and gap in cement coverage is approved, but with stage collar placement as follows: An AOGCC Injection Order is required prior to beginning injection operations. DSR-12/14/23 Stage collar must be placed no shallower than 50' MD below the base of the Upper Tuluvak as defined by the TS790 horizon. Submit 12-1/4" OH logs to AOGCC and obtain approval for stage collar setting depth before running 9-5/8" liner. BJM 1/26/24 Submit FIT/LOT data within 48 hrs of performing test. SFD 1/3/2023 223-120 2377' FSL SFD BOP Test to 3500 psi, annular test to 3000 psi. 50-103-20873-00-00 *&: 1497 SFD 1/29/2024 JLC 1/29/2024 1/29/24 1/29/24Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.01.29 14:14:41 -09'00' Page 1 of 1 29 November 2023 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDBi-030 Dear Sir/Madam Oil Search (Alaska), LLC hereby applies for a Permit to Drill an onshore development well from the NDB drilling pad on the North Slope of Alaska. NDBi-030 is planned to be a horizontal Injector targeting the Nanushuk 3. The approximate spud date is anticipated to be January 15 th, 2024. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~79 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8” tieback will be run to the top of the 9-5/8” liner. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand and the lateral will be drilled to TD. The well will be completed as a stimulated 4-1/2” liner with frac sleeves and isolation packers. The production liner will be tied back to surface with a 4-1/2” tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (907) 440-6892 or Garret.Staudinger@santos.com. Respectfully, Garret Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, G t St di Application for Permit to Drill NDBi-030 Well Table of Contents 1. Well Name.................................................................................................................................3 2. Location Summary.....................................................................................................................3 3. Blowout Prevention Equipment Information..............................................................................4 4. Drilling Hazards Information......................................................................................................5 5. Procedure for Conducting Formation Integrity Tests..................................................................6 6. Casing and Cementing Program.................................................................................................6 7. Diverter System Information......................................................................................................7 8. Drilling Fluid Program................................................................................................................7 9. Abnormally Pressured Formation Information...........................................................................8 10. Seismic Analysis.......................................................................................................................8 11. Seabed Condition Analysis.......................................................................................................8 12. Evidence of Bonding................................................................................................................8 13. Proposed Drilling Program.......................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal..............................................11 Attachments............................................................................................................................................12 Attachment 1: Location Maps......................................................................................................13 Attachment 2: Directional Plan....................................................................................................16 Attachment 3: BOPE Equipment..................................................................................................4 0 Attachment 4: Drilling Hazards....................................................................................................44 Attachment 5: Leak Off Test Procedure.......................................................................................46 Attachment 6: Cement Summary.................................................................................................47 Attachment 7: Prognosed Formation Tops...................................................................................49 Attachment 8: Well Schematic.....................................................................................................50 Attachment 9: Formation Evaluation Program.............................................................................51 Attachment 10: Wellhead & Tree Diagram ..................................................................................52 Attachment 11: Injector Area of Review......................................................................................53 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDBi-030. This will be a development injection well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 2365’ FSL, 3091 FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,761 E 422,154 Rig KB Elevation 47’ above GL Ground Level 23.9’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 3243’ FSL, 5’ FEL, Sec 31, T12N, R6E, UM NAD 27 Coordinate System N 5,979,211 E 414,585 Measured Depth, Rig KB (MD) 11,903’ Total Vertical Depth, Rig KB (TVD) 4,185’ Total vertical Depth, Subsea (TVDSS) 4,114’ Location at Bottom of Productive Interval Reference to Government Section Lines 3205’ FSL, 3105’ FEL, Sec 30, T12N, R6E, UM NAD 27 Coordinate System N 5,984,083’ E 411,773’ Measured Depth, Rig KB (MD) 17,529’ Total Vertical Depth, Rig KB (TVD) 4,143’ Total vertical Depth, Subsea (TVDSS) 4,072’ 2377' FSL SFD (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 2: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for NDBi-030 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Parker 272 BOP Equipment: BOP Equipment x NOV Shaffer Spherical annular BOP, 13-5/8” x 5000 psi x NOV T3 6012 double gate, 13-5/8” x 5000 psi x Mud cross, 13-5/8” x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets x Choke Line, 3-1/8” x 5000 psi with 3-1/8” manual and HCR valve x Kill Line, 2-1/16” x 5000 psi with 3-1/8” manual and HCR valve x NOV T3 6012 single gate, 13-5/8” x 5000 psi Choke Manifold x 3-1/8” x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit x NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12Ͳ1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,871 psi in the Nanushuk 4 at 4,089’ TVD (8.8ppg EMW Nanushuk 4 formation to section TD) Maximum surface pressure 1,462 psi from the NT4 (0.10 psi/ft gas gradient to surface, 4,089’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 12Ͳ1/4” hole LOT after drilling 20’Ͳ50’ of new hole.13.6 ppg LOT required for Kick Tolerance. 13Ͳ3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by 50% of Casing Burst] 8Ͳ1/2” Production Hole Pressure Data Maximum anticipated BHP 1,893 psi in the Nanushuk 3.2 at 4,137’ TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,479 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,137’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 8Ͳ1/2” hole FIT after drilling 20’Ͳ50’ of new hole. 15.0 ppg. (10.6 ppg EMW LOT Required for infinite kick tolerance.) 9Ͳ5/8” Liner Test 4,000 psi surface pressure [Test pressure driven by annular pressure during frac job] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data.The Tuluvak is expected to be overpressured at 10.2ppg pore pressure.The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone.BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. (C) data concerning potential causes of hole problems such as abnormally geoͲpressured strata, lost circulation zones, and zones that have a propensity for differential sticking; expected to be overpressured at 10.2ppg 401 Form states 1871 psi. SFD Tuluvak? SFD 1,479 psi from the NT3 high potential for gasTuluvakformationi Nearby offset Exploration and Appraisal wells in the area suggest that no significant hole problems are to be expected. Please refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 54’ 16” 13-3/8” 68# L-80 BTC 2,617’ Surface 2,617’ / 2,303’ 12-1/4” 9-5/8” 47# L-80 HYD 563 8,675’ 2,467’ 11,142’ / 4,089’ Tie Back 9-5/8” 47# L-80 HYD 563 2,467’ Surface 2,467’ / 2,217’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6,607’ 10,992’ 17,529’ / 4,143’ Tubing 4-1/2” 12.6# P-110S HYD 563 10,992’ Surface 10,992’ / 4,049’ Please refer to Attachment 6: Cement Summary for further details. 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line Please refer to Attachment 3: BOPE Equipment for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Intermediate Hole Production Hole Mud Type Water based Spud Mud Mineral Oil Based Mud Mineral Oil Based Mud Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 10ppg 100-300 seconds ALAP 30-80 < 10 ml/30min n/a 8.6-10.5 <35 12-12.5 ppg 50-80 seconds ALAP 15-30 n/a < 5 ml/30min n/a n/a 10ppg 50-80 seconds ALAP 10-20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDBi-030 Well is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Oil Search Alaska is on file with the Commission. 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to NDBi-030 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program NDBi-030 1. Drill 20” conductor to ~128’ MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools and diverter over the 20” conductor. Verify that the diverter line is at least 75’ away from a potential source of ignition and beyond the drill rig substructure. 4. Function test diverter and knife valve as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing diverter test. 5. Pick up 5-7/8” drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16” motor BHA with MWD and LWD tools. 6. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 7. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 8. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 9. ND diverter and NU casing head and spacer spool. NU BOPE (configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 9-5/8” Fixed Rams). Test rams to 3500 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs notice for witnessing BOP test. 10. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 11. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to 12 ppg MOBM. 12. Drill out shoe track and 20 - 50’ of new formation. Perform leak off test. 13. Directionally drill 12-1/4” intermediate hole section to TD ~15’ TVD above the NT3 MFS. Perform wiper trips as required. Circulate and condition hole to run casing. POOH. 14. Run 9-5/8” production liner as per casing tally then RIH on 5-7/8” DP. Circulate and condition mud prior to commencing cement job. 15. Cement 9-5/8” liner with 1st stage cement job as per cement program. Monitor returns during displacement. Bump plug then pressure up to set liner hanger and release running tool. 16. Un-sting from liner hanger and POOH and LD liner running tools. 17. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Sting into second stage tool pump secondary stage, SO and set liner top packer. POOH and lay down running tool. 18. Run 9-5/8” tie-back string. Freeze protect the 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 19. Pressure test 13-3/8” x 9-5/8” to 2600 psi for 30 min. 20. Pressure test the 9-5/8” liner and tieback to 3500 psi for 30 min. 21. Change out lower BOP rams from 9-5/8” fixed to 4-1/2” x 7” VBR and test to 3500 psi. 22. Make up 8-1/2” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to 10.0 ppg MOBM. 23. Drill out shoe track and 20 - 50’ of new formation. Perform formation integrity test. 24. Directionally drill 8-1/2” hole section as per well plan to TD. Perform wiper trips as required. 25. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary 26. RU and run 4-1/2” production liner with liner hanger / liner top packer and downhole jewelry to TD. 27. Set and pressure test the 9-5/8” x 4-1/2” IA to liner top packer to 3,000 psi for 30 min. Release the running tool. 28. POOH and LD liner running tool. 29. RU and run 4-1/2” upper completion and downhole jewelry with tech wire. Space out seals. 30. Circulate corrosion inhibited brine into annulus into annulus and stab seals inside the polish bore below the 9-5/8” x 4-1/2” liner top packer. 31. Land tubing hanger 32. Pressure test tubing to 4,000 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins (MIT-IA will be tested again post rig with AOGCC witness). Bleed pressure on tubing and shear upper gas lift valve. 33. Reverse circulate freeze protect and U-Tube. 34. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. Pressure test to 10,000 psi for 10 mins. 35. RDMO POOH. Log first stage cement with Sonic LWD.NOTE:See more details / justification in Attachment 6: Cement Summary Run 9-5/8” tie-back string. Freeze protect the 13-3/8” x 9-5/8” annulus with diesel and land tie-back. 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. Attachments Attachment 1: Location Maps ADL 392991 ADL 392984 ADL 392968 ADL 392958 ADL 392970 ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393007 ADL 391445 ADL 391455 ADL 393011 ADL 393010 U012N006E29 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N005E25 U012N006E28 U012N005E36 U012N006E20 U011N005E01 U012N006E2124 U012N006E31 U011N006E06 U012N006E19 U012N006E30 DW-02 N D B - 0 3 2 N D B i - 0 4 3 N D B i - 0 3 0 FIORD 3A FIORD 3 QUGRUK 3 QUGRUK 301 QUGRUK 3A OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELL SHL PLANNED BOTTOM HOLE PREVIOUSLY DRILLED NDB WELL NDBI-030 TRAJECTORY PRODUCTION INTERVAL EXPLORATION SHL BOTTOM HOLES WELL TRAJECTORY OTHER 0.25-MILE BUFFER .5-MILE BUFFER SANTOS LEASES DATE: 7/14/2023. By: JB 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi30_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDBi-030 WELL OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELLS RIG OUTLINES DIVERTER (50-ft) DATE: 8/7/2023. By: JB 0204010 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi30_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDBi-30 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.33539 -150.63471 N 70° 20' 7.4051" W 150° 38' 04.941" 5,972,509.24 1,562,185.92 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.33571 -150.63161 N 70° 20' 08.5562" W 150° 37' 53.6648" 5,972,761.37 422,149.90 State Plane NAD83 Zone 4 StatePlane NAD27 Zone 4 Attachment 2: Directional Plan SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 47.0 0.00 0.00 47.0 0.0 0.0 0.00 0.00 0.0 2 350.0 0.00 0.00 350.0 0.0 0.0 0.00 0.00 0.0 Start Build 2.00 3 650.0 6.00 345.00 649.5 15.2 -4.1 2.00 345.00 13.8 Start DLS 2.50 TFO -39.34 4 995.2 13.80 321.50 989.3 64.9 -34.4 2.50 -39.34 70.9 Start 150.0 hold at 995.2 MD 5 1145.2 13.80 321.50 1135.0 92.9 -56.7 0.00 0.00 106.6 Start DLS 3.00 TFO -15.83 6 3333.9 78.98 306.83 2567.3 1048.1 -1207.8 3.00 -15.83 1590.6 Start 7113.5 hold at 3333.9 MD 7 10447.4 78.98 306.83 3926.7 5233.9 -6796.4 0.00 0.00 8465.6 Start DLS 3.00 TFO 105.30 8 11197.3 74.00 329.41 4104.0 5771.7 -7280.6 3.00 105.30 9189.1 Start 100.0 hold at 11197.3 MD 9 11297.3 74.00 329.41 4131.5 5854.4 -7329.5 0.00 0.00 9283.0 Start Build 4.00 10 11703.9 90.27 329.41 4187.0 6200.0 -7533.8 4.00 0.00 9674.9 NDB-030 Heel v.2 Start DLS 3.00 TFO 0.23 11 11709.5 90.43 329.41 4187.0 6204.8 -7536.7 3.00 0.23 9680.3 Start 5819.9 hold at 11709.5 MD 12 17529.3 90.43 329.41 4143.0 11214.6 -10498.2 0.00 0.00 15361.6 NDB-030 TD v.3 TD at 17529.3 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 Plan: NDBi-030 Rev C.0 Plan Summary 0 3 Do g l e g S e v e r i t y 0 2500 5000 7500 10000 12500 15000 17500 Measured Depth 20" Conductor Casing 13-3/8" x 16" Surface Casing 9-5/8" x 12-1/4" Intermediate Liner 45 45 90 90 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in] 100125150175200225250275300325350375400425426450475500525550575600625650675700Plan: NDB-25 Rev A.0 1001251501752002252502753003253283503754004254504755005255505756006256506757007257507758008258508759009259509759971000102510501075110011251150117512001225125012751300132513501375140014251450147515001525155015751600Plan: NDB-027 Rev A.0 100125150175200225250275300325350375400425450475500525550575600625650675700725750775800825 850 875 900Plan: NDB-031 Rev A.0 1001251501752002252502753003253503754004254504755005255505756006046256506757007257507758008258508759009259509751000102510471050107511001125115011751200122512501275130013251350137514001425145014751500152515501575160016251650167517001725175017751800182518501875190019251950NDB-032 100125150175200225250275300325350375400425450475500525550575600625650675700725750775800 825Plan: NDB-033 Rev A.0 10012515017520022525027530032535037540042545047550052555057560062565067570072575077580082585087187590092595097510001025105010751100112511501175120012251250127513001325135013751400Plan: NDBi-026 Rev A.0 100125150175200225250275300325350372375400425450475500525550575600625650675700725750 775 800 825 850Plan NDBi-028 Rev A.0 100125150175200225250275300325350375400425450452475500525550575600625650675700725750775800825850875900925950975100010251050Plan: NDBi-034 Rev A.0 0 2250 Tr u e V e r t i c a l D e p t h 0 2250 4500 6750 9000 11250 13500 15750 Vertical Section at 316.89° 20" Conductor Casing 13-3/8" x 16" Surface Casing 9-5/8" x 12-1/4" Intermediate Liner 0 28 55 Ce n t r e t o C e n t r e S e p a r a t i o n 0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 6.904 SURVEY PROGRAM Date: 2021-02-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 300.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 2_MWD_Interp Azi 300.0 1500.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag 300.0 2617.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag 47.0 300.0 Plan: NDBi-030 Rev C.0 (NDBi-30) SDI_KPR_ADK 2617.0 3817.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag 2617.0 11142.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag 11142.0 12342.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag 11142.0 17529.3 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag Surface Location North / 5972509.55 East / 1562186.68 Elevation / 23.9 CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner Mag Model & Date: BGGM2023 31-Dec-23 Magnetic North is 14.40° East of True North (Magnetic Declin Mag Dip & Field Strength: 80.58°57175.54313321nT FORMATION TOP DETAILS TVDPath Formation 1046.9 Upper SB 1394.9Permafrost Base Transition 1741.9 Middle SB 2152.9MCU (Lower Schrader Bluff) 2471.9Tuluvak Shale 2495.9Tuluvak Sand 3159.9 Seabee 3819.9 Nanushuk 3837.9 NT7 MFS 3904.9 NT6 MFS 3980.9 NT5 MFS 4041.9 NT4 MFS 4103.9 NT3 MFS 4136.9Nanushuk 3.2 (NT3) By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by BHI DE Accepted by BHI PSD Approved by Santos DE Plan: Parker 272 @ 70.9usft Standard Planning Report -Geographic 15 November, 2023 Plan: Plan: NDBi-030 Rev C.0 Santos NAD27 Conversion Pikka NDB NDBi-030 NDBi-30 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka, North Slope Alaska, United States Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: NDB Map Slot Radius:0.9 usft usft usft " 5,972,909.70 423,383.56 20 70° 20' 10.138 N 150° 37' 17.796 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: NDBi-030 Wellhead Elevation:0.5 0.0 0.0 5,972,761.56 422,153.87 70° 20' 8.556 N 150° 37' 53.665 W 23.9 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDBi-30 Model NameMagnetics BGGM2023 31/12/2023 14.40 80.58 57,175.54283985 Phase:Version: Audit Notes: Design Plan: NDBi-030 Rev C.0 PLAN Vertical Section:Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 316.890.00.047.0 15/11/2023 9:04:13AM COMPASS 5000.17 Build 02 Page 2 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 15/11/2023 Depth To (usft) Depth From (usft) 2_MWD_Interp Azi H002Mb: Interpolated azim Plan: NDBi-030 Rev C.0 (NDBi-30147.0 300.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-030 Rev C.0 (NDBi-302300.0 1,500.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-030 Rev C.0 (NDBi-303300.0 2,617.0 SDI_KPR_ADK SDI Keeper ADK Plan: NDBi-030 Rev C.0 (NDBi-30447.0 300.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-030 Rev C.0 (NDBi-3052,617.0 3,817.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-030 Rev C.0 (NDBi-3062,617.0 11,142.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-030 Rev C.0 (NDBi-30711,142.0 12,342.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-030 Rev C.0 (NDBi-30811,142.0 17,529.3 Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.00.047.00.000.0047.0 0.000.000.000.000.00.0350.00.000.00350.0 345.000.002.002.00-4.115.2649.5345.006.00650.0 -39.34-6.812.262.50-34.464.9989.3321.5013.80995.2 0.000.000.000.00-56.792.91,135.0321.5013.801,145.2 -15.83-0.672.983.00-1,207.81,048.12,567.3306.8378.983,333.9 0.000.000.000.00-6,796.45,233.93,926.7306.8378.9810,447.4 105.303.01-0.663.00-7,280.65,771.74,104.0329.4174.0011,197.3 0.000.000.000.00-7,329.55,854.44,131.5329.4174.0011,297.3 0.000.004.004.00-7,533.86,200.04,187.0329.4190.2711,703.9 0.230.013.003.00-7,536.76,204.84,187.0329.4190.4311,709.5 0.000.000.000.00-10,498.211,214.64,143.0329.4190.4317,529.3 15/11/2023 9:04:13AM COMPASS 5000.17 Build 02 Page 3 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 47.0 0.00 47.0 0.0 0.00.00 422,153.875,972,761.56 70° 20' 8.556 N 150° 37' 53.665 W 100.0 0.00 100.0 0.0 0.00.00 422,153.875,972,761.56 70° 20' 8.556 N 150° 37' 53.665 W 128.0 0.00 128.0 0.0 0.00.00 422,153.875,972,761.56 70° 20' 8.556 N 150° 37' 53.665 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,153.875,972,761.56 70° 20' 8.556 N 150° 37' 53.665 W 300.0 0.00 300.0 0.0 0.00.00 422,153.875,972,761.56 70° 20' 8.556 N 150° 37' 53.665 W 350.0 0.00 350.0 0.0 0.00.00 422,153.875,972,761.56 70° 20' 8.556 N 150° 37' 53.665 W Start Build 2.00 400.0 1.00 400.0 0.4 -0.1345.00 422,153.765,972,761.99 70° 20' 8.560 N 150° 37' 53.668 W 500.0 3.00 499.9 3.8 -1.0345.00 422,152.895,972,765.37 70° 20' 8.594 N 150° 37' 53.695 W 600.0 5.00 599.7 10.5 -2.8345.00 422,151.165,972,772.12 70° 20' 8.660 N 150° 37' 53.747 W 650.0 6.00 649.5 15.2 -4.1345.00 422,149.975,972,776.76 70° 20' 8.705 N 150° 37' 53.783 W Start DLS 2.50 TFO -39.34 700.0 7.01 699.1 20.5 -5.9338.50 422,148.235,972,782.14 70° 20' 8.758 N 150° 37' 53.836 W 800.0 9.21 798.1 33.1 -12.1329.99 422,142.125,972,794.82 70° 20' 8.882 N 150° 37' 54.018 W 900.0 11.53 896.5 48.2 -21.9324.81 422,132.515,972,810.02 70° 20' 9.031 N 150° 37' 54.303 W 995.2 13.80 989.3 64.9 -34.4321.50 422,120.135,972,826.81 70° 20' 9.195 N 150° 37' 54.670 W Start 150.0 hold at 995.2 MD 1,000.0 13.80 994.0 65.8 -35.1321.50 422,119.425,972,827.72 70° 20' 9.203 N 150° 37' 54.691 W 1,054.4 13.80 1,046.9 76.0 -43.2321.50 422,111.455,972,837.96 70° 20' 9.303 N 150° 37' 54.927 W Upper Schrader Bluff 1,100.0 13.80 1,091.1 84.5 -50.0321.50 422,104.775,972,846.54 70° 20' 9.387 N 150° 37' 55.124 W 1,145.2 13.80 1,135.0 92.9 -56.7321.50 422,098.155,972,855.04 70° 20' 9.470 N 150° 37' 55.320 W Start DLS 3.00 TFO -15.83 1,200.0 15.39 1,188.1 103.6 -65.5319.81 422,089.505,972,865.80 70° 20' 9.575 N 150° 37' 55.576 W 1,300.0 18.31 1,283.8 125.3 -84.6317.47 422,070.545,972,887.71 70° 20' 9.789 N 150° 37' 56.137 W 1,400.0 21.26 1,377.9 149.9 -107.9315.76 422,047.535,972,912.52 70° 20' 10.030 N 150° 37' 56.816 W 1,418.3 21.80 1,394.9 154.7 -112.6315.49 422,042.875,972,917.37 70° 20' 10.077 N 150° 37' 56.954 W Permafrost Base Transition 1,500.0 24.21 1,470.1 177.2 -135.2314.44 422,020.525,972,940.15 70° 20' 10.299 N 150° 37' 57.613 W 1,600.0 27.18 1,560.2 207.3 -166.4313.40 421,989.605,972,970.53 70° 20' 10.595 N 150° 37' 58.526 W 1,700.0 30.15 1,647.9 239.9 -201.6312.55 421,954.845,973,003.57 70° 20' 10.916 N 150° 37' 59.551 W 1,800.0 33.13 1,733.0 275.2 -240.4311.84 421,916.345,973,039.18 70° 20' 11.262 N 150° 38' 0.686 W 1,810.6 33.44 1,741.9 279.0 -244.8311.77 421,912.055,973,043.11 70° 20' 11.301 N 150° 38' 0.813 W Middle Schrader Bluff 1,900.0 36.11 1,815.3 312.8 -282.9311.23 421,874.215,973,077.28 70° 20' 11.633 N 150° 38' 1.928 W 2,000.0 39.09 1,894.5 352.8 -329.0310.71 421,828.575,973,117.74 70° 20' 12.026 N 150° 38' 3.274 W 2,100.0 42.08 1,970.5 395.0 -378.5310.25 421,779.535,973,160.47 70° 20' 12.441 N 150° 38' 4.719 W 2,200.0 45.06 2,042.9 439.4 -431.3309.84 421,727.235,973,205.34 70° 20' 12.877 N 150° 38' 6.260 W 2,300.0 48.05 2,111.7 485.7 -487.2309.47 421,671.825,973,252.23 70° 20' 13.333 N 150° 38' 7.893 W 2,362.8 49.93 2,152.9 515.7 -523.8309.25 421,635.505,973,282.66 70° 20' 13.628 N 150° 38' 8.963 W MCU (Lower Schrader Bluff) 2,400.0 51.04 2,176.6 533.9 -546.0309.13 421,613.455,973,301.02 70° 20' 13.807 N 150° 38' 9.612 W 2,500.0 54.03 2,237.4 583.8 -607.7308.82 421,552.285,973,351.56 70° 20' 14.297 N 150° 38' 11.415 W 2,600.0 57.02 2,294.0 635.3 -672.1308.53 421,488.475,973,403.73 70° 20' 14.804 N 150° 38' 13.294 W 2,617.0 57.53 2,303.2 644.2 -683.3308.48 421,477.375,973,412.75 70° 20' 14.892 N 150° 38' 13.621 W 13-3/8" x 16" Surface Casing 2,700.0 60.01 2,346.2 688.2 -738.9308.26 421,422.205,973,457.37 70° 20' 15.325 N 150° 38' 15.246 W 2,800.0 63.00 2,393.9 742.5 -808.0308.01 421,353.655,973,512.35 70° 20' 15.858 N 150° 38' 17.265 W 2,900.0 65.99 2,437.0 797.9 -879.3307.77 421,283.015,973,568.50 70° 20' 16.403 N 150° 38' 19.346 W 2,990.7 68.71 2,471.9 849.1 -945.6307.56 421,217.265,973,620.35 70° 20' 16.906 N 150° 38' 21.282 W Tuluvak Shale 3,000.0 68.99 2,475.2 854.4 -952.4307.54 421,210.475,973,625.68 70° 20' 16.958 N 150° 38' 21.482 W 3,060.1 70.79 2,495.9 888.7 -997.2307.41 421,166.065,973,660.46 70° 20' 17.296 N 150° 38' 22.790 W Tuluvak Sand 3,100.0 71.98 2,508.6 911.6 -1,027.2307.32 421,136.245,973,683.73 70° 20' 17.521 N 150° 38' 23.668 W 3,200.0 74.97 2,537.1 969.6 -1,103.6307.11 421,060.515,973,742.49 70° 20' 18.092 N 150° 38' 25.898 W 3,300.0 77.97 2,560.5 1,028.1 -1,181.2306.90 420,983.505,973,801.79 70° 20' 18.667 N 150° 38' 28.166 W 15/11 /2023 9:04:13AM COMPASS 5000.17 Build 02 Page 4 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 3,333.9 78.98 2,567.3 1,048.1 -1,207.8306.83 420,957.105,973,822.02 70° 20' 18.863 N 150° 38' 28.943 W Start 7113.5 hold at 3333.9 MD 3,400.0 78.98 2,579.9 1,086.9 -1,259.7306.83 420,905.625,973,861.42 70° 20' 19.245 N 150° 38' 30.459 W 3,500.0 78.98 2,599.0 1,145.8 -1,338.3306.83 420,827.675,973,921.07 70° 20' 19.824 N 150° 38' 32.754 W 3,600.0 78.98 2,618.1 1,204.6 -1,416.8306.83 420,749.735,973,980.72 70° 20' 20.402 N 150° 38' 35.049 W 3,700.0 78.98 2,637.2 1,263.5 -1,495.4306.83 420,671.795,974,040.37 70° 20' 20.981 N 150° 38' 37.344 W 3,800.0 78.98 2,656.3 1,322.3 -1,574.0306.83 420,593.855,974,100.02 70° 20' 21.560 N 150° 38' 39.639 W 3,900.0 78.98 2,675.4 1,381.2 -1,652.5306.83 420,515.915,974,159.67 70° 20' 22.138 N 150° 38' 41.934 W 4,000.0 78.98 2,694.5 1,440.0 -1,731.1306.83 420,437.975,974,219.32 70° 20' 22.717 N 150° 38' 44.229 W 4,100.0 78.98 2,713.7 1,498.8 -1,809.7306.83 420,360.035,974,278.97 70° 20' 23.295 N 150° 38' 46.525 W 4,200.0 78.98 2,732.8 1,557.7 -1,888.2306.83 420,282.085,974,338.62 70° 20' 23.874 N 150° 38' 48.820 W 4,300.0 78.98 2,751.9 1,616.5 -1,966.8306.83 420,204.145,974,398.27 70° 20' 24.452 N 150° 38' 51.115 W 4,400.0 78.98 2,771.0 1,675.4 -2,045.4306.83 420,126.205,974,457.92 70° 20' 25.031 N 150° 38' 53.410 W 4,500.0 78.98 2,790.1 1,734.2 -2,123.9306.83 420,048.265,974,517.57 70° 20' 25.609 N 150° 38' 55.706 W 4,600.0 78.98 2,809.2 1,793.1 -2,202.5306.83 419,970.325,974,577.22 70° 20' 26.188 N 150° 38' 58.001 W 4,700.0 78.98 2,828.3 1,851.9 -2,281.0306.83 419,892.385,974,636.87 70° 20' 26.766 N 150° 39' 0.297 W 4,800.0 78.98 2,847.4 1,910.8 -2,359.6306.83 419,814.445,974,696.52 70° 20' 27.345 N 150° 39' 2.592 W 4,900.0 78.98 2,866.5 1,969.6 -2,438.2306.83 419,736.495,974,756.17 70° 20' 27.923 N 150° 39' 4.887 W 5,000.0 78.98 2,885.6 2,028.4 -2,516.7306.83 419,658.555,974,815.82 70° 20' 28.502 N 150° 39' 7.183 W 5,100.0 78.98 2,904.8 2,087.3 -2,595.3306.83 419,580.615,974,875.47 70° 20' 29.080 N 150° 39' 9.479 W 5,200.0 78.98 2,923.9 2,146.1 -2,673.9306.83 419,502.675,974,935.12 70° 20' 29.659 N 150° 39' 11.774 W 5,300.0 78.98 2,943.0 2,205.0 -2,752.4306.83 419,424.735,974,994.77 70° 20' 30.237 N 150° 39' 14.070 W 5,400.0 78.98 2,962.1 2,263.8 -2,831.0306.83 419,346.795,975,054.42 70° 20' 30.815 N 150° 39' 16.366 W 5,500.0 78.98 2,981.2 2,322.7 -2,909.6306.83 419,268.855,975,114.07 70° 20' 31.394 N 150° 39' 18.661 W 5,600.0 78.98 3,000.3 2,381.5 -2,988.1306.83 419,190.905,975,173.72 70° 20' 31.972 N 150° 39' 20.957 W 5,700.0 78.98 3,019.4 2,440.3 -3,066.7306.83 419,112.965,975,233.37 70° 20' 32.551 N 150° 39' 23.253 W 5,800.0 78.98 3,038.5 2,499.2 -3,145.2306.83 419,035.025,975,293.02 70° 20' 33.129 N 150° 39' 25.549 W 5,900.0 78.98 3,057.6 2,558.0 -3,223.8306.83 418,957.085,975,352.67 70° 20' 33.707 N 150° 39' 27.844 W 6,000.0 78.98 3,076.8 2,616.9 -3,302.4306.83 418,879.145,975,412.32 70° 20' 34.286 N 150° 39' 30.140 W 6,100.0 78.98 3,095.9 2,675.7 -3,380.9306.83 418,801.205,975,471.97 70° 20' 34.864 N 150° 39' 32.436 W 6,200.0 78.98 3,115.0 2,734.6 -3,459.5306.83 418,723.265,975,531.62 70° 20' 35.443 N 150° 39' 34.732 W 6,300.0 78.98 3,134.1 2,793.4 -3,538.1306.83 418,645.315,975,591.27 70° 20' 36.021 N 150° 39' 37.028 W 6,400.0 78.98 3,153.2 2,852.2 -3,616.6306.83 418,567.375,975,650.92 70° 20' 36.599 N 150° 39' 39.324 W 6,435.1 78.98 3,159.9 2,872.9 -3,644.2306.83 418,540.045,975,671.84 70° 20' 36.802 N 150° 39' 40.129 W Seabee 6,500.0 78.98 3,172.3 2,911.1 -3,695.2306.83 418,489.435,975,710.57 70° 20' 37.178 N 150° 39' 41.620 W 6,600.0 78.98 3,191.4 2,969.9 -3,773.8306.83 418,411.495,975,770.22 70° 20' 37.756 N 150° 39' 43.917 W 6,700.0 78.98 3,210.5 3,028.8 -3,852.3306.83 418,333.555,975,829.87 70° 20' 38.334 N 150° 39' 46.213 W 6,800.0 78.98 3,229.6 3,087.6 -3,930.9306.83 418,255.615,975,889.52 70° 20' 38.913 N 150° 39' 48.509 W 6,900.0 78.98 3,248.8 3,146.5 -4,009.5306.83 418,177.675,975,949.17 70° 20' 39.491 N 150° 39' 50.805 W 7,000.0 78.98 3,267.9 3,205.3 -4,088.0306.83 418,099.725,976,008.82 70° 20' 40.069 N 150° 39' 53.101 W 7,100.0 78.98 3,287.0 3,264.1 -4,166.6306.83 418,021.785,976,068.47 70° 20' 40.647 N 150° 39' 55.398 W 7,200.0 78.98 3,306.1 3,323.0 -4,245.1306.83 417,943.845,976,128.12 70° 20' 41.226 N 150° 39' 57.694 W 7,300.0 78.98 3,325.2 3,381.8 -4,323.7306.83 417,865.905,976,187.77 70° 20' 41.804 N 150° 39' 59.990 W 7,400.0 78.98 3,344.3 3,440.7 -4,402.3306.83 417,787.965,976,247.42 70° 20' 42.382 N 150° 40' 2.287 W 7,500.0 78.98 3,363.4 3,499.5 -4,480.8306.83 417,710.025,976,307.07 70° 20' 42.960 N 150° 40' 4.583 W 7,600.0 78.98 3,382.5 3,558.4 -4,559.4306.83 417,632.085,976,366.72 70° 20' 43.539 N 150° 40' 6.880 W 7,700.0 78.98 3,401.6 3,617.2 -4,638.0306.83 417,554.145,976,426.37 70° 20' 44.117 N 150° 40' 9.176 W 7,800.0 78.98 3,420.7 3,676.0 -4,716.5306.83 417,476.195,976,486.02 70° 20' 44.695 N 150° 40' 11.473 W 7,900.0 78.98 3,439.9 3,734.9 -4,795.1306.83 417,398.255,976,545.67 70° 20' 45.273 N 150° 40' 13.769 W 8,000.0 78.98 3,459.0 3,793.7 -4,873.7306.83 417,320.315,976,605.32 70° 20' 45.852 N 150° 40' 16.066 W 8,100.0 78.98 3,478.1 3,852.6 -4,952.2306.83 417,242.375,976,664.97 70° 20' 46.430 N 150° 40' 18.363 W 8,200.0 78.98 3,497.2 3,911.4 -5,030.8306.83 417,164.435,976,724.62 70° 20' 47.008 N 150° 40' 20.659 W 8,300.0 78.98 3,516.3 3,970.3 -5,109.3306.83 417,086.495,976,784.27 70° 20' 47.586 N 150° 40' 22.956 W 8,400.0 78.98 3,535.4 4,029.1 -5,187.9306.83 417,008.555,976,843.92 70° 20' 48.164 N 150° 40' 25.253 W 8,500.0 78.98 3,554.5 4,088.0 -5,266.5306.83 416,930.605,976,903.57 70° 20' 48.743 N 150° 40' 27.549 W 8,600.0 78.98 3,573.6 4,146.8 -5,345.0306.83 416,852.665,976,963.22 70° 20' 49.321 N 150° 40' 29.846 W 8,700.0 78.98 3,592.7 4,205.6 -5,423.6306.83 416,774.725,977,022.88 70° 20' 49.899 N 150° 40' 32.143 W 8,800.0 78.98 3,611.9 4,264.5 -5,502.2306.83 416,696.785,977,082.53 70° 20' 50.477 N 150° 40' 34.440 W 8,900.0 78.98 3,631.0 4,323.3 -5,580.7306.83 416,618.845,977,142.18 70° 20' 51.055 N 150° 40' 36.737 W 9,000.0 78.98 3,650.1 4,382.2 -5,659.3306.83 416,540.905,977,201.83 70° 20' 51.633 N 150° 40' 39.034 W 15/11 /2023 9:04:13AM COMPASS 5000.17 Build 02 Page 5 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 9,100.0 78.98 3,669.2 4,441.0 -5,737.9306.83 416,462.965,977,261.48 70° 20' 52.212 N 150° 40' 41.331 W 9,200.0 78.98 3,688.3 4,499.9 -5,816.4306.83 416,385.015,977,321.13 70° 20' 52.790 N 150° 40' 43.628 W 9,300.0 78.98 3,707.4 4,558.7 -5,895.0306.83 416,307.075,977,380.78 70° 20' 53.368 N 150° 40' 45.925 W 9,400.0 78.98 3,726.5 4,617.5 -5,973.5306.83 416,229.135,977,440.43 70° 20' 53.946 N 150° 40' 48.222 W 9,500.0 78.98 3,745.6 4,676.4 -6,052.1306.83 416,151.195,977,500.08 70° 20' 54.524 N 150° 40' 50.519 W 9,600.0 78.98 3,764.7 4,735.2 -6,130.7306.83 416,073.255,977,559.73 70° 20' 55.102 N 150° 40' 52.817 W 9,700.0 78.98 3,783.9 4,794.1 -6,209.2306.83 415,995.315,977,619.38 70° 20' 55.680 N 150° 40' 55.114 W 9,800.0 78.98 3,803.0 4,852.9 -6,287.8306.83 415,917.375,977,679.03 70° 20' 56.258 N 150° 40' 57.411 W 9,888.6 78.98 3,819.9 4,905.1 -6,357.4306.83 415,848.295,977,731.89 70° 20' 56.771 N 150° 40' 59.447 W Nanushuk 9,900.0 78.98 3,822.1 4,911.8 -6,366.4306.83 415,839.425,977,738.68 70° 20' 56.836 N 150° 40' 59.708 W 9,982.8 78.98 3,837.9 4,960.5 -6,431.4306.83 415,774.885,977,788.07 70° 20' 57.315 N 150° 41' 1.611 W NT7 MFS 10,000.0 78.98 3,841.2 4,970.6 -6,444.9306.83 415,761.485,977,798.33 70° 20' 57.414 N 150° 41' 2.006 W 10,100.0 78.98 3,860.3 5,029.4 -6,523.5306.83 415,683.545,977,857.98 70° 20' 57.992 N 150° 41' 4.303 W 10,200.0 78.98 3,879.4 5,088.3 -6,602.1306.83 415,605.605,977,917.63 70° 20' 58.570 N 150° 41' 6.601 W 10,300.0 78.98 3,898.5 5,147.1 -6,680.6306.83 415,527.665,977,977.28 70° 20' 59.148 N 150° 41' 8.898 W 10,333.4 78.98 3,904.9 5,166.8 -6,706.9306.83 415,501.625,977,997.20 70° 20' 59.342 N 150° 41' 9.665 W NT6 MFS 10,400.0 78.98 3,917.6 5,206.0 -6,759.2306.83 415,449.725,978,036.93 70° 20' 59.726 N 150° 41' 11.195 W 10,447.4 78.98 3,926.7 5,233.9 -6,796.4306.83 415,412.775,978,065.20 70° 21' 0.000 N 150° 41' 12.285 W Start DLS 3.00 TFO 105.30 10,500.0 78.57 3,936.9 5,265.3 -6,837.3308.39 415,372.235,978,097.10 70° 21' 0.310 N 150° 41' 13.480 W 10,600.0 77.81 3,957.4 5,328.1 -6,912.4311.35 415,297.785,978,160.61 70° 21' 0.926 N 150° 41' 15.677 W 10,700.0 77.08 3,979.1 5,394.4 -6,984.0314.33 415,226.915,978,227.70 70° 21' 1.578 N 150° 41' 17.770 W 10,707.9 77.02 3,980.9 5,399.8 -6,989.4314.57 415,221.505,978,233.12 70° 21' 1.631 N 150° 41' 17.930 W NT5 MFS 10,800.0 76.39 4,002.1 5,464.2 -7,051.8317.33 415,159.835,978,298.20 70° 21' 2.264 N 150° 41' 19.754 W 10,900.0 75.73 4,026.2 5,537.3 -7,115.7320.35 415,096.735,978,371.90 70° 21' 2.982 N 150° 41' 21.622 W 10,962.8 75.33 4,041.9 5,584.8 -7,153.7322.25 415,059.185,978,419.77 70° 21' 3.448 N 150° 41' 22.736 W NT4 MFS 11,000.0 75.11 4,051.4 5,613.4 -7,175.4323.38 415,037.775,978,448.62 70° 21' 3.730 N 150° 41' 23.371 W 11,100.0 74.52 4,077.6 5,692.4 -7,230.9326.43 414,983.115,978,528.13 70° 21' 4.506 N 150° 41' 24.995 W 11,142.0 74.29 4,088.9 5,726.3 -7,252.9327.71 414,961.475,978,562.31 70° 21' 4.839 N 150° 41' 25.639 W 9-5/8" x 12-1/4" Intermediate Liner 11,197.0 74.00 4,103.9 5,771.5 -7,280.5329.40 414,934.345,978,607.74 70° 21' 5.283 N 150° 41' 26.447 W NT3 MFS 11,197.3 74.00 4,104.0 5,771.7 -7,280.6329.41 414,934.235,978,607.94 70° 21' 5.285 N 150° 41' 26.450 W Start 100.0 hold at 11197.3 MD 11,200.0 74.00 4,104.7 5,773.9 -7,282.0329.41 414,932.915,978,610.22 70° 21' 5.307 N 150° 41' 26.489 W 11,297.3 74.00 4,131.5 5,854.4 -7,329.5329.41 414,886.185,978,691.18 70° 21' 6.098 N 150° 41' 27.882 W Start Build 4.00 11,300.0 74.11 4,132.3 5,856.7 -7,330.9329.41 414,884.865,978,693.47 70° 21' 6.121 N 150° 41' 27.921 W 11,317.2 74.80 4,136.9 5,871.0 -7,339.3329.41 414,876.565,978,707.84 70° 21' 6.261 N 150° 41' 28.169 W Nanushuk 3.2 (NT3) 11,391.7 77.78 4,154.5 5,933.2 -7,376.1329.41 414,840.395,978,770.49 70° 21' 6.873 N 150° 41' 29.246 W NDBi-030 Polygon (copy) (copy) 11,400.0 78.11 4,156.3 5,940.2 -7,380.3329.41 414,836.345,978,777.52 70° 21' 6.942 N 150° 41' 29.367 W 11,500.0 82.11 4,173.5 6,025.0 -7,430.4329.41 414,787.105,978,862.81 70° 21' 7.775 N 150° 41' 30.835 W 11,600.0 86.11 4,183.7 6,110.6 -7,481.0329.41 414,737.395,978,948.93 70° 21' 8.617 N 150° 41' 32.316 W 11,642.1 87.79 4,186.0 6,146.8 -7,502.4329.41 414,716.395,978,985.31 70° 21' 8.972 N 150° 41' 32.942 W NDBi-030 Geo Polygon 600' x 350' Ext. 11,642.7 87.82 4,186.0 6,147.4 -7,502.7329.41 414,716.055,978,985.90 70° 21' 8.978 N 150° 41' 32.952 W NDBi-030 Geo Polygon500' x 300' Ext. 11,700.0 90.11 4,187.0 6,196.6 -7,531.9329.41 414,687.445,979,035.47 70° 21' 9.462 N 150° 41' 33.805 W 11,703.9 90.27 4,187.0 6,200.0 -7,533.8329.41 414,685.495,979,038.85 70° 21' 9.495 N 150° 41' 33.863 W Start DLS 3.00 TFO 0.23 11,709.5 90.43 4,187.0 6,204.8 -7,536.7329.41 414,682.715,979,043.66 70° 21' 9.542 N 150° 41' 33.946 W Start 5819.9 hold at 11709.5 MD 15/11 /2023 9:04:13AM COMPASS 5000.17 Build 02 Page 6 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 11,800.0 90.43 4,186.3 6,282.7 -7,582.7329.41 414,637.455,979,122.07 70° 21' 10.308 N 150° 41' 35.295 W 11,900.0 90.43 4,185.5 6,368.8 -7,633.6329.41 414,587.475,979,208.66 70° 21' 11.154 N 150° 41' 36.785 W 11,903.1 90.43 4,185.5 6,371.5 -7,635.2329.41 414,585.905,979,211.38 70° 21' 11.181 N 150° 41' 36.832 W NDB_I26_R2_Rev11_Heel_250 (copy) (copy) 12,000.0 90.43 4,184.8 6,454.9 -7,684.5329.41 414,537.485,979,295.26 70° 21' 12.001 N 150° 41' 38.275 W 12,100.0 90.43 4,184.0 6,541.0 -7,735.4329.41 414,487.505,979,381.86 70° 21' 12.847 N 150° 41' 39.765 W 12,200.0 90.43 4,183.3 6,627.0 -7,786.3329.41 414,437.515,979,468.45 70° 21' 13.693 N 150° 41' 41.255 W 12,300.0 90.43 4,182.5 6,713.1 -7,837.2329.41 414,387.525,979,555.05 70° 21' 14.539 N 150° 41' 42.745 W 12,400.0 90.43 4,181.7 6,799.2 -7,888.1329.41 414,337.545,979,641.65 70° 21' 15.385 N 150° 41' 44.235 W 12,500.0 90.43 4,181.0 6,885.3 -7,938.9329.41 414,287.555,979,728.24 70° 21' 16.231 N 150° 41' 45.725 W 12,600.0 90.43 4,180.2 6,971.4 -7,989.8329.41 414,237.575,979,814.84 70° 21' 17.077 N 150° 41' 47.215 W 12,700.0 90.43 4,179.5 7,057.5 -8,040.7329.41 414,187.585,979,901.44 70° 21' 17.923 N 150° 41' 48.705 W 12,800.0 90.43 4,178.7 7,143.5 -8,091.6329.41 414,137.605,979,988.03 70° 21' 18.769 N 150° 41' 50.196 W 12,900.0 90.43 4,178.0 7,229.6 -8,142.5329.41 414,087.615,980,074.63 70° 21' 19.615 N 150° 41' 51.686 W 13,000.0 90.43 4,177.2 7,315.7 -8,193.4329.41 414,037.625,980,161.23 70° 21' 20.461 N 150° 41' 53.176 W 13,100.0 90.43 4,176.5 7,401.8 -8,244.3329.41 413,987.645,980,247.82 70° 21' 21.307 N 150° 41' 54.666 W 13,200.0 90.43 4,175.7 7,487.9 -8,295.2329.41 413,937.655,980,334.42 70° 21' 22.153 N 150° 41' 56.157 W 13,300.0 90.43 4,175.0 7,573.9 -8,346.0329.41 413,887.675,980,421.02 70° 21' 22.999 N 150° 41' 57.647 W 13,400.0 90.43 4,174.2 7,660.0 -8,396.9329.41 413,837.685,980,507.61 70° 21' 23.845 N 150° 41' 59.137 W 13,500.0 90.43 4,173.4 7,746.1 -8,447.8329.41 413,787.705,980,594.21 70° 21' 24.691 N 150° 42' 0.628 W 13,600.0 90.43 4,172.7 7,832.2 -8,498.7329.41 413,737.715,980,680.81 70° 21' 25.537 N 150° 42' 2.118 W 13,700.0 90.43 4,171.9 7,918.3 -8,549.6329.41 413,687.725,980,767.40 70° 21' 26.383 N 150° 42' 3.609 W 13,800.0 90.43 4,171.2 8,004.3 -8,600.5329.41 413,637.745,980,854.00 70° 21' 27.230 N 150° 42' 5.099 W 13,900.0 90.43 4,170.4 8,090.4 -8,651.4329.41 413,587.755,980,940.60 70° 21' 28.076 N 150° 42' 6.590 W 14,000.0 90.43 4,169.7 8,176.5 -8,702.2329.41 413,537.775,981,027.19 70° 21' 28.922 N 150° 42' 8.081 W 14,100.0 90.43 4,168.9 8,262.6 -8,753.1329.41 413,487.785,981,113.79 70° 21' 29.768 N 150° 42' 9.571 W 14,200.0 90.43 4,168.2 8,348.7 -8,804.0329.41 413,437.805,981,200.39 70° 21' 30.614 N 150° 42' 11.062 W 14,300.0 90.43 4,167.4 8,434.8 -8,854.9329.41 413,387.815,981,286.98 70° 21' 31.460 N 150° 42' 12.553 W 14,400.0 90.43 4,166.6 8,520.8 -8,905.8329.41 413,337.825,981,373.58 70° 21' 32.306 N 150° 42' 14.043 W 14,500.0 90.43 4,165.9 8,606.9 -8,956.7329.41 413,287.845,981,460.18 70° 21' 33.152 N 150° 42' 15.534 W 14,600.0 90.43 4,165.1 8,693.0 -9,007.6329.41 413,237.855,981,546.77 70° 21' 33.998 N 150° 42' 17.025 W 14,700.0 90.43 4,164.4 8,779.1 -9,058.5329.41 413,187.875,981,633.37 70° 21' 34.844 N 150° 42' 18.516 W 14,800.0 90.43 4,163.6 8,865.2 -9,109.3329.41 413,137.885,981,719.97 70° 21' 35.690 N 150° 42' 20.007 W 14,900.0 90.43 4,162.9 8,951.2 -9,160.2329.41 413,087.905,981,806.56 70° 21' 36.536 N 150° 42' 21.498 W 15,000.0 90.43 4,162.1 9,037.3 -9,211.1329.41 413,037.915,981,893.16 70° 21' 37.382 N 150° 42' 22.989 W 15,100.0 90.43 4,161.4 9,123.4 -9,262.0329.41 412,987.925,981,979.76 70° 21' 38.228 N 150° 42' 24.480 W 15,200.0 90.43 4,160.6 9,209.5 -9,312.9329.41 412,937.945,982,066.36 70° 21' 39.073 N 150° 42' 25.971 W 15,300.0 90.43 4,159.8 9,295.6 -9,363.8329.41 412,887.955,982,152.95 70° 21' 39.919 N 150° 42' 27.462 W 15,400.0 90.43 4,159.1 9,381.6 -9,414.7329.41 412,837.975,982,239.55 70° 21' 40.765 N 150° 42' 28.953 W 15,500.0 90.43 4,158.3 9,467.7 -9,465.5329.41 412,787.985,982,326.15 70° 21' 41.611 N 150° 42' 30.444 W 15,600.0 90.43 4,157.6 9,553.8 -9,516.4329.41 412,738.005,982,412.74 70° 21' 42.457 N 150° 42' 31.935 W 15,700.0 90.43 4,156.8 9,639.9 -9,567.3329.41 412,688.015,982,499.34 70° 21' 43.303 N 150° 42' 33.426 W 15,800.0 90.43 4,156.1 9,726.0 -9,618.2329.41 412,638.025,982,585.94 70° 21' 44.149 N 150° 42' 34.917 W 15,900.0 90.43 4,155.3 9,812.1 -9,669.1329.41 412,588.045,982,672.53 70° 21' 44.995 N 150° 42' 36.409 W 16,000.0 90.43 4,154.6 9,898.1 -9,720.0329.41 412,538.055,982,759.13 70° 21' 45.841 N 150° 42' 37.900 W 16,100.0 90.43 4,153.8 9,984.2 -9,770.9329.41 412,488.075,982,845.73 70° 21' 46.687 N 150° 42' 39.391 W 16,200.0 90.43 4,153.0 10,070.3 -9,821.8329.41 412,438.085,982,932.32 70° 21' 47.533 N 150° 42' 40.883 W 16,300.0 90.43 4,152.3 10,156.4 -9,872.6329.41 412,388.105,983,018.92 70° 21' 48.379 N 150° 42' 42.374 W 16,400.0 90.43 4,151.5 10,242.5 -9,923.5329.41 412,338.115,983,105.52 70° 21' 49.225 N 150° 42' 43.866 W 16,500.0 90.43 4,150.8 10,328.5 -9,974.4329.41 412,288.125,983,192.11 70° 21' 50.071 N 150° 42' 45.357 W 16,600.0 90.43 4,150.0 10,414.6 -10,025.3329.41 412,238.145,983,278.71 70° 21' 50.917 N 150° 42' 46.848 W 16,700.0 90.43 4,149.3 10,500.7 -10,076.2329.41 412,188.155,983,365.31 70° 21' 51.763 N 150° 42' 48.340 W 16,800.0 90.43 4,148.5 10,586.8 -10,127.1329.41 412,138.175,983,451.90 70° 21' 52.609 N 150° 42' 49.832 W 16,900.0 90.43 4,147.8 10,672.9 -10,178.0329.41 412,088.185,983,538.50 70° 21' 53.455 N 150° 42' 51.323 W 17,000.0 90.43 4,147.0 10,758.9 -10,228.8329.41 412,038.205,983,625.10 70° 21' 54.300 N 150° 42' 52.815 W 17,100.0 90.43 4,146.2 10,845.0 -10,279.7329.41 411,988.215,983,711.69 70° 21' 55.146 N 150° 42' 54.306 W 17,200.0 90.43 4,145.5 10,931.1 -10,330.6329.41 411,938.225,983,798.29 70° 21' 55.992 N 150° 42' 55.798 W 17,300.0 90.43 4,144.7 11,017.2 -10,381.5329.41 411,888.245,983,884.89 70° 21' 56.838 N 150° 42' 57.290 W 17,400.0 90.43 4,144.0 11,103.3 -10,432.4329.41 411,838.255,983,971.48 70° 21' 57.684 N 150° 42' 58.782 W 17,500.0 90.43 4,143.2 11,189.4 -10,483.3329.41 411,788.275,984,058.08 70° 21' 58.530 N 150° 43' 0.274 W 15/11 /2023 9:04:13AM COMPASS 5000.17 Build 02 Page 7 Planning Report -Geographic Well NDBi-030Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 70.9usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 70.9usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-030Well: NDBi-30Wellbore: Plan: NDBi-030 Rev C.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 17,529.3 90.43 4,143.0 11,214.6 -10,498.2329.41 411,773.615,984,083.48 70° 21' 58.778 N 150° 43' 0.711 W TD at 17529.3 - NDB_I26_R2_Rev11_Toe V2 (copy) (copy) - NDB_I26_R3_Rev11_Heel (copy) (copy) Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing128.0128.0 20 20 13-3/8" x 16" Surface Casing2,303.22,617.0 13-3/8 16 9-5/8" x 12-1/4" Intermediate Liner4,088.911,142.0 9-5/8 12-1/4 4-1/2" x 8 -1/2" Production Liner4,143.017,529.4 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,054.4 Upper Schrader Bluff1,046.9 1,418.3 Permafrost Base Transition1,394.9 1,810.6 Middle Schrader Bluff1,741.9 2,362.8 MCU (Lower Schrader Bluff)2,152.9 2,990.7 Tuluvak Shale2,471.9 3,060.1 Tuluvak Sand2,495.9 6,435.1 Seabee3,159.9 9,888.6 Nanushuk3,819.9 9,982.8 NT7 MFS3,837.9 10,333.4 NT6 MFS3,904.9 10,707.9 NT5 MFS3,980.9 10,962.8 NT4 MFS4,041.9 11,197.0 NT3 MFS4,103.9 11,317.2 Nanushuk 3.2 (NT3)4,136.9 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 350.0 350.0 0.0 0.0 Start Build 2.00 650.0 649.5 15.2 -4.1 Start DLS 2.50 TFO -39.34 995.2 989.3 64.9 -34.4 Start 150.0 hold at 995.2 MD 1,145.2 1,135.0 92.9 -56.7 Start DLS 3.00 TFO -15.83 3,333.9 2,567.3 1,048.1 -1,207.8 Start 7113.5 hold at 3333.9 MD 10,447.4 3,926.7 5,233.9 -6,796.4 Start DLS 3.00 TFO 105.30 11,197.3 4,104.0 5,771.7 -7,280.6 Start 100.0 hold at 11197.3 MD 11,297.3 4,131.5 5,854.4 -7,329.5 Start Build 4.00 11,703.9 4,187.0 6,200.0 -7,533.8 Start DLS 3.00 TFO 0.23 11,709.5 4,187.0 6,204.8 -7,536.7 Start 5819.9 hold at 11709.5 MD 17,529.3 4,143.0 11,214.6 -10,498.2 TD at 17529.3 15/11/2023 9:04:13AM COMPASS 5000.17 Build 02 Page 8 0 2000 4000 6000 8000 10000 12000 So u t h ( - ) / N o r t h ( + ) -14000 -12000 -10000 -8000 -6000 -4000 -2000 0 2000 West(-)/East(+) NDB-030 Heel v.2 NDB-030 TD v.3 20" Conductor Casing 13-3/8" x 16" Surface Casing 9-5/8" x 12-1/4" Intermediate Liner 4-1/2" x 8 -1/2" Production Liner P l an: N D B i -0 3 0 R e v C.0 Plan: NDBi-030 Rev C.0 16:47, November 14 2023 -1500 0 1500 3000 4500 6000 Tr u e V e r t i c a l D e p t h 0 2000 4000 6000 8000 10000 12000 14000 16000 Vertical Section at 316.89° 20" Conductor Casing 13-3/8" x 16" Surface Casing 9-5/8" x 12-1/4" Intermediate Liner 4-1/2" x 8 -1/2" Production Liner 10 00 20 00 30 00 4000 50 0 0 600 0 70 0 0 80 0 0 9000 1000 0 11 0 0 0 12 0 0 0 13 000 140 00 1500 0 160 00 17 0 0 0 17 5 2 9 0° 30 ° 60° 79 ° 90 ° 90° Pl a n : N D Bi- 030 R e v C.0 Upper Schrader Bluff Permafrost Base Transition Middle Schrader Bluff MCU (Lower Schrader Bluff) Tuluvak Shale Tuluvak Sand Seabee Nanushuk NT7 MFS NT6 MFS NT5 MFS NT4 MFS NT3 MFS Nanushuk 3.2 (NT3) Plan: NDBi-030 Rev C.0 7:31, November 15 2023 0 30 60 Ce n t r e t o C e n t r e S e p a r a t i o n 0 450 900 1350 1800 2250 Partial Measured Depth Pl a n : N DB - 0 2 7 R e v A . 0 Pl a n : N DB - 0 3 1 R e v A . 0 ND B - 0 32 Pl a n : N DB- 0 3 3 Re v A . 0 Pl a n N DB i - 0 2 8 R ev A . 0 Equivalent Magnetic Distance Plan: NDBi-030 Rev C.0 Ladder View 0 150 300 Ce n t r e t o C e n t r e S e p a r a t i o n 0 2500 5000 7500 10000 12500 15000 17500 Measured Depth Pl a n : N D B - 0 1 5 Re v A . 0 Pl a n : N DB - 0 2 1 R e v A . 0 Pl a n N DB - 0 2 2 Re v A . 0 ND B - 0 24 ND B - 0 24P B 1 Pla n : N DB - 2 5 R ev A .0 Plan : N DB - 0 2 7 R e v A . 0 Pl a n : N D B - 0 3 1 R e v A . 0 ND B - 0 32 Pl a n : N DB - 0 3 3 Re v A . 0 Pl a n : N DB - 0 3 7 Re v B. 0 Pl an : N DB - 0 3 9 R e v A . 0 Pl a n : N D B - 0 4 0 R e v A . 0 Pl a n : NDB i - 0 16 R e v A . 0 Plan : N DB i - 0 1 8 R ev F . 0 Pl an : N DBi - 0 1 9 R ev A.0 Pl a n : N DB i - 0 20 R e v A . 0 Pla n : N DB i - 0 2 6 R e v A . 0 Pl a n N DB i - 0 2 8 R e v A .0 Pl a n : NDB i - 0 3 4 R e v A. 0 Pl a n : N DB i - 0 3 6 R e v A. 0 ND B i - 0 38 R e v A . 0 Pl a n : N DB i - 0 4 1 R e v A . 0 ND B i - 0 43 NDBi - 0 4 3 A ND B i- 0 4 4 Pl a n : N DB i - 0 4 4 R ev G . 0 Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 47.0 300.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 2_MWD_Interp Azi 300.0 1500.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag 300.0 2617.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag 47.0 300.0 Plan: NDBi-030 Rev C.0 (NDBi-30) SDI_KPR_ADK 2617.0 3817.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag 2617.0 11142.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag 11142.0 12342.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag 11142.0 17529.3 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag 7:30, November 15 2023 CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 15 November, 2023 Anticollision Summary Report Santos Pikka NDB NDBi-030 NDBi-30 Plan: NDBi-030 Rev C.0 Anticollision Summary Report Well NDBi-030 -Slot B-30Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 70.9usftTVD Reference:PikkaProject: Plan: Parker 272 @ 70.9usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-030Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-30 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-030 Rev C.0 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Combined Pedal Curve GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.0usft Unlimited Maximum centre distance of 1,948.2usft Plan: NDBi-030 Rev C.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 14/11/2023 2_MWD_Interp Azi H002Mb: Interpolated azimuth47.0 300.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag300.0 1,500.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag300.0 2,617.0 Plan: NDBi-030 Rev C.0 (NDBi-30) SDI_KPR_ADK SDI Keeper ADK47.0 300.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag2,617.0 3,817.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,617.0 11,142.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag11,142.0 12,342.0 Plan: NDBi-030 Rev C.0 (NDBi-30) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,142.0 17,529.3 Plan: NDBi-030 Rev C.0 (NDBi-30) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB CCNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 778.5 787.3 293.7 277.4 27.426 ESNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 800.0 809.1 293.7 277.4 27.290 SFNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 3,800.0 3,393.4 1,217.8 1,110.4 14.527 CCNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 427.3 426.4 179.4 163.9 17.645 ESNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 475.0 473.9 179.5 163.8 17.475 SFNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 800.0 812.9 182.0 165.3 16.329 CCNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 802.5 807.5 157.3 141.0 14.619 ESNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 825.0 830.4 157.3 141.0 14.547 SFNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 17,529.3 16,902.9 1,925.7 1,358.3 4.254 CCNDB-024 - NDB-024 - NDB-024 190.1 188.7 120.2 110.6 21.543 ESNDB-024 - NDB-024 - NDB-024 350.0 348.5 120.3 105.3 11.980 SFNDB-024 - NDB-024 - NDB-024 17,529.3 16,848.3 1,798.7 1,247.6 4.092 CCNDB-024 - NDB-024PB1 - NDB-024PB1 190.1 188.7 120.2 110.4 21.515 ESNDB-024 - NDB-024PB1 - NDB-024PB1 350.0 348.5 120.3 105.1 11.965 SFNDB-024 - NDB-024PB1 - NDB-024PB1 3,375.0 3,181.0 512.0 433.2 8.379 CCNDB-025 - NDB-025 - Plan: NDB-25 Rev A.0 426.4 426.1 99.9 84.5 9.731 ESNDB-025 - NDB-025 - Plan: NDB-25 Rev A.0 475.0 474.6 99.9 84.4 9.647 SFNDB-025 - NDB-025 - Plan: NDB-25 Rev A.0 600.0 598.0 101.5 85.5 9.472 CC, ESNDB-027 - NDB-027 - Plan: NDB-027 Rev A.0 997.1 999.7 52.2 36.9 5.041 SFNDB-027 - NDB-027 - Plan: NDB-027 Rev A.0 14,350.0 13,890.3 1,089.5 672.1 3.274 Level 4, CCNDB-031 - NDB-031 - Plan: NDB-031 Rev A.0 350.0 349.1 20.9 5.5 1.865 Level 4, ES, SFNDB-031 - NDB-031 - Plan: NDB-031 Rev A.0 375.0 374.1 20.9 5.5 1.863 SFNDB-032 - NDB-032 - NDB-032 525.0 524.3 38.6 23.4 3.670 ESNDB-032 - NDB-032 - NDB-032 1,025.0 1,025.2 34.9 22.6 4.311 CCNDB-032 - NDB-032 - NDB-032 1,046.9 1,047.1 34.9 22.6 4.346 CCNDB-033 - NDB-033 - Plan: NDB-033 Rev A.0 350.0 349.1 60.8 45.5 5.900 ES, SFNDB-033 - NDB-033 - Plan: NDB-033 Rev A.0 400.0 399.1 60.9 45.4 5.882 CCNDB-037 - NDB-037 - Plan: NDB-037 Rev B.0 328.5 327.4 123.3 108.7 12.996 ESNDB-037 - NDB-037 - Plan: NDB-037 Rev B.0 350.0 348.9 123.3 108.1 12.278 SFNDB-037 - NDB-037 - Plan: NDB-037 Rev B.0 17,125.0 17,779.5 1,801.9 1,243.5 4.045 CCNDB-039 - NDB-039 - Plan: NDB-039 Rev A.0 501.5 500.7 181.0 165.4 17.656 ESNDB-039 - NDB-039 - Plan: NDB-039 Rev A.0 550.0 549.0 181.0 165.3 17.484 SFNDB-039 - NDB-039 - Plan: NDB-039 Rev A.0 3,800.0 3,318.6 791.1 682.2 9.287 CCNDB-040 - NDB-040 - Plan: NDB-040 Rev A.0 328.4 327.5 201.1 186.4 21.228 ESNDB-040 - NDB-040 - Plan: NDB-040 Rev A.0 400.0 399.0 201.1 185.7 19.979 15/11 /2023 7:45:54AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 2 Anticollision Summary Report Well NDBi-030 -Slot B-30Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 70.9usftTVD Reference:PikkaProject: Plan: Parker 272 @ 70.9usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-030Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-30 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-030 Rev C.0 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB SFNDB-040 - NDB-040 - Plan: NDB-040 Rev A.0 450.0 448.8 201.2 185.7 19.940 CCNDBi-016 - NDBi-016 - Plan: NDBi-016 Rev A.0 871.4 887.6 273.6 256.8 24.585 ESNDBi-016 - NDBi-016 - Plan: NDBi-016 Rev A.0 900.0 917.2 273.7 256.8 24.381 SFNDBi-016 - NDBi-016 - Plan: NDBi-016 Rev A.0 3,800.0 3,599.5 983.3 874.7 11.554 CCNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev F.0 703.8 706.9 239.3 223.3 22.571 ESNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev F.0 725.0 728.8 239.3 223.2 22.455 SFNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev F.0 3,800.0 3,803.3 944.8 840.0 11.522 CCNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 420.7 419.8 219.5 204.0 21.703 ESNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 701.1 710.3 219.6 203.2 20.180 SFNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 800.0 813.1 221.4 204.7 19.891 CCNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 726.1 728.8 198.5 182.5 18.781 ESNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 750.0 753.2 198.6 182.5 18.695 SFNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 3,800.0 3,476.3 994.8 884.1 11.496 CCNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 871.1 873.3 75.9 60.0 7.124 Level 1, ESNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 17,150.0 16,621.7 213.4 -71.6 0.936 Level 1, SFNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 17,175.0 16,645.8 208.0 -70.1 0.935 CCNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 372.0 371.1 39.2 23.8 3.703 ESNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 425.0 424.0 39.3 23.7 3.652 SFNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 450.0 448.9 39.5 23.7 3.633 CCNDBi-034 - NDBi-034 - Plan: NDBi-034 Rev A.0 452.3 451.5 80.9 65.4 7.830 ESNDBi-034 - NDBi-034 - Plan: NDBi-034 Rev A.0 550.0 549.0 80.9 65.2 7.708 SFNDBi-034 - NDBi-034 - Plan: NDBi-034 Rev A.0 10,400.0 10,046.1 1,294.9 923.7 4.383 CCNDBi-036 - NDBi-036 - Plan: NDBi-036 Rev A.0 350.0 349.1 121.0 105.6 11.967 ESNDBi-036 - NDBi-036 - Plan: NDBi-036 Rev A.0 450.0 449.1 121.0 105.5 11.874 SFNDBi-036 - NDBi-036 - Plan: NDBi-036 Rev A.0 525.0 523.9 121.2 105.7 11.843 CCNDBi-038 - NDBi-038 - NDBi-038 Rev A.0 328.4 327.5 161.1 146.4 16.955 ESNDBi-038 - NDBi-038 - NDBi-038 Rev A.0 375.0 374.1 161.1 145.7 15.982 SFNDBi-038 - NDBi-038 - NDBi-038 Rev A.0 425.0 423.9 161.1 145.7 15.949 CCNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 513.8 513.0 221.1 205.4 21.571 ESNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 550.0 547.0 221.1 205.3 21.427 SFNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 3,800.0 3,177.2 1,015.3 910.0 12.355 CC, ESNDBi-043 - NDBi-043 - NDBi-043 668.3 668.3 258.7 243.3 25.661 SFNDBi-043 - NDBi-043 - NDBi-043 9,025.0 10,947.0 852.9 574.6 3.856 Level 3, CCNDBi-043 - NDBi-043A - NDBi-043A 11,151.3 13,210.0 109.5 13.0 1.427 Level 2, ES, SFNDBi-043 - NDBi-043A - NDBi-043A 11,200.0 13,210.0 119.7 -7.3 1.181 CCNDBi-044 - NDBi-044 - NDBi-044 100.0 98.5 280.0 270.9 60.109 ESNDBi-044 - NDBi-044 - NDBi-044 350.0 347.2 280.6 265.4 28.260 SFNDBi-044 - NDBi-044 - NDBi-044 2,700.0 2,428.0 590.7 539.9 15.257 CCNDBi-044 - NDBi-044 - Plan: NDBi-044 Rev G.0 829.0 815.4 278.9 263.0 26.691 ESNDBi-044 - NDBi-044 - Plan: NDBi-044 Rev G.0 850.0 834.2 278.9 263.0 26.597 SFNDBi-044 - NDBi-044 - Plan: NDBi-044 Rev G.0 3,800.0 3,328.8 1,075.4 979.1 14.310 15/11 /2023 7:45:54AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 3 Anticollision Summary Report Well NDBi-030 -Slot B-30Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 70.9usftTVD Reference:PikkaProject: Plan: Parker 272 @ 70.9usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-030Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-30 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-030 Rev C.0 Offset TVD Reference: 0 500 1000 1500 2000 Ce n t r e t o C e n t r e S e p a r a t i o n 0 3000 6000 9000 12000 15000 18000 Measured Depth Ladder Plot NDB-015, NDB-015, Plan: NDB-015 Rev A.0 V0 NDB-021, NDB-021, Plan: NDB-021 Rev A.0 V0 NDB-022, NDB-022, Plan NDB-022 Rev A.0 V0 NDB-024, NDB-024, NDB-024 V0 NDB-024, NDB-024PB1, NDB-024PB1 V0 NDB-025, NDB-025, Plan: NDB-25 Rev A.0 V0 NDB-027, NDB-027, Plan: NDB-027 Rev A.0 V0 NDB-031, NDB-031, Plan: NDB-031 Rev A.0 V0 NDB-032, NDB-032, NDB-032 V0 NDB-033, NDB-033, Plan: NDB-033 Rev A.0 V0 NDB-037, NDB-037, Plan: NDB-037 Rev B.0 V0 NDB-039, NDB-039, Plan: NDB-039 Rev A.0 V0 NDB-040, NDB-040, Plan: NDB-040 Rev A.0 V0 NDBi-016, NDBi-016, Plan: NDBi-016 Rev A.0 V0 NDBi-018, NDBi-018, Plan: NDBi-018 Rev F.0 V0 NDBi-019, NDBi-019, Plan: NDBi-019 Rev A.0 V0 NDBi-020, NDBi-020, Plan: NDBi-020 Rev A.0 V0 NDBi-026, NDBi-026, Plan: NDBi-026 Rev A.0 V0 NDBi-028, NDBi-028, Plan NDBi-028 Rev A.0 V0 NDBi-034, NDBi-034, Plan: NDBi-034 Rev A.0 V0 NDBi-036, NDBi-036, Plan: NDBi-036 Rev A.0 V0 NDBi-038, NDBi-038, NDBi-038 Rev A.0 V0 NDBi-041, NDBi-041, Plan: NDBi-041 Rev A.0 V0 NDBi-043, NDBi-043, NDBi-043 V0 NDBi-043, NDBi-043A, NDBi-043A V0 NDBi-044, NDBi-044, NDBi-044 V0 NDBi-044, NDBi-044, Plan: NDBi-044 Rev G.0 V0 L E G E N D Coordinates are relative to: NDBi-030 - Slot B-30 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Plan: Parker 272 @ 70.9usft 15/11/2023 7:45:54AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 4 Anticollision Summary Report Well NDBi-030 -Slot B-30Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 70.9usftTVD Reference:PikkaProject: Plan: Parker 272 @ 70.9usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-030Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-30 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-030 Rev C.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 Se p a r a t i o n F a c t o r 0 3000 6000 9000 12000 15000 18000 Measured Depth Level 1 Level 3 Level 4 Separation Factor Plot NDB-015, NDB-015, Plan: NDB-015 Rev A.0 V0 NDB-021, NDB-021, Plan: NDB-021 Rev A.0 V0 NDB-022, NDB-022, Plan NDB-022 Rev A.0 V0 NDB-024, NDB-024, NDB-024 V0 NDB-024, NDB-024PB1, NDB-024PB1 V0 NDB-025, NDB-025, Plan: NDB-25 Rev A.0 V0 NDB-027, NDB-027, Plan: NDB-027 Rev A.0 V0 NDB-031, NDB-031, Plan: NDB-031 Rev A.0 V0 NDB-032, NDB-032, NDB-032 V0 NDB-033, NDB-033, Plan: NDB-033 Rev A.0 V0 NDB-037, NDB-037, Plan: NDB-037 Rev B.0 V0 NDB-039, NDB-039, Plan: NDB-039 Rev A.0 V0 NDB-040, NDB-040, Plan: NDB-040 Rev A.0 V0 NDBi-016, NDBi-016, Plan: NDBi-016 Rev A.0 V0 NDBi-018, NDBi-018, Plan: NDBi-018 Rev F.0 V0 NDBi-019, NDBi-019, Plan: NDBi-019 Rev A.0 V0 NDBi-020, NDBi-020, Plan: NDBi-020 Rev A.0 V0 NDBi-026, NDBi-026, Plan: NDBi-026 Rev A.0 V0 NDBi-028, NDBi-028, Plan NDBi-028 Rev A.0 V0 NDBi-034, NDBi-034, Plan: NDBi-034 Rev A.0 V0 NDBi-036, NDBi-036, Plan: NDBi-036 Rev A.0 V0 NDBi-038, NDBi-038, NDBi-038 Rev A.0 V0 NDBi-041, NDBi-041, Plan: NDBi-041 Rev A.0 V0 NDBi-043, NDBi-043, NDBi-043 V0 NDBi-043, NDBi-043A, NDBi-043A V0 NDBi-044, NDBi-044, NDBi-044 V0 NDBi-044, NDBi-044, Plan: NDBi-044 Rev G.0 V0 L E G E N D Coordinates are relative to: NDBi-030 - Slot B-30 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Plan: Parker 272 @ 70.9usft 15/11/2023 7:45:54AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 Plan: NDBi-030 Rev C.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 2_MWD_Interp Azi 300.0 1500.0 3_MWD+IFR2+Sag 300.0 2617.0 3_MWD+IFR2+MS+Sag 47.0 300.0 SDI_KPR_ADK 2617.0 3817.0 3_MWD+IFR2+Sag 2617.0 11142.0 3_MWD+IFR2+MS+Sag 11142.0 12342.0 3_MWD+IFR2+Sag 11142.0 17529.3 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 12615117620122625127630132635137640142645147650152655157660162665167670072575077479982484987389892394897399710221047 1072 1097 1121 1146 1171 1196 1221 1246 1271 1296 Plan: NDB-027 Rev A.0 126151176201226251276301326351376401426451476501 526 550 575 600 624 648 673 697 721 745 769 792 Plan: NDB-031 Rev A.0 1261511762012262512763013263513764014264514765015265515766016266506767017267517768018268518769019269509751000102510501075110011251149117411991223124812721297 1321 1346 1370 1394 1419 1443 1468 1492 1516 1540 1565 1589 NDB-032 126151176201226251276301326351376401426451476 501 525 550 574 599 623 647 Plan: NDB-033 Rev A.0 126151176201226251276301326351376401426451 476 500 525 549 574 598 622 646 670 694 717 Plan NDBi-028 Rev A.0 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 From Colour To MD 47.0 To 2700.0 MD Azi TFace 47.0 0.00 0.00 350.0 0.00 0.00 650.0 345.00 345.00 995.2 321.50 -39.34 1145.2 321.50 0.00 3333.9 306.83 -15.83 10447.4 306.83 0.00 11197.3 329.41 105.30 11297.3 329.41 0.00 11703.9 329.41 0.00 11709.5 329.41 0.23 17529.3 329.41 0.00 Plan: NDBi-030 Rev C.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 2_MWD_Interp Azi 300.0 1500.0 3_MWD+IFR2+Sag 300.0 2617.0 3_MWD+IFR2+MS+Sag 47.0 300.0 SDI_KPR_ADK 2617.0 3817.0 3_MWD+IFR2+Sag 2617.0 11142.0 3_MWD+IFR2+MS+Sag 11142.0 12342.0 3_MWD+IFR2+Sag 11142.0 17529.3 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 From Colour To MD 2600.0 To 9000.0 MD Azi TFace 47.0 0.00 0.00 350.0 0.00 0.00 650.0 345.00 345.00 995.2 321.50 -39.34 1145.2 321.50 0.00 3333.9 306.83 -15.83 10447.4 306.83 0.00 11197.3 329.41 105.30 11297.3 329.41 0.00 11703.9 329.41 0.00 11709.5 329.41 0.23 17529.3 329.41 0.00 Plan: NDBi-030 Rev C.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 2_MWD_Interp Azi 300.0 1500.0 3_MWD+IFR2+Sag 300.0 2617.0 3_MWD+IFR2+MS+Sag 47.0 300.0 SDI_KPR_ADK 2617.0 3817.0 3_MWD+IFR2+Sag 2617.0 11142.0 3_MWD+IFR2+MS+Sag 11142.0 12342.0 3_MWD+IFR2+Sag 11142.0 17529.3 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 From Colour To MD 8900.0 To 11200.0 MD Azi TFace 47.0 0.00 0.00 350.0 0.00 0.00 650.0 345.00 345.00 995.2 321.50 -39.34 1145.2 321.50 0.00 3333.9 306.83 -15.83 10447.4 306.83 0.00 11197.3 329.41 105.30 11297.3 329.41 0.00 11703.9 329.41 0.00 11709.5 329.41 0.23 17529.3 329.41 0.00 Plan: NDBi-030 Rev C.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 2_MWD_Interp Azi 300.0 1500.0 3_MWD+IFR2+Sag 300.0 2617.0 3_MWD+IFR2+MS+Sag 47.0 300.0 SDI_KPR_ADK 2617.0 3817.0 3_MWD+IFR2+Sag 2617.0 11142.0 3_MWD+IFR2+MS+Sag 11142.0 12342.0 3_MWD+IFR2+Sag 11142.0 17529.3 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 From Colour To MD 11000.0 To 11500.0 MD Azi TFace 47.0 0.00 0.00 350.0 0.00 0.00 650.0 345.00 345.00 995.2 321.50 -39.34 1145.2 321.50 0.00 3333.9 306.83 -15.83 10447.4 306.83 0.00 11197.3 329.41 105.30 11297.3 329.41 0.00 11703.9 329.41 0.00 11709.5 329.41 0.23 17529.3 329.41 0.00 Plan: NDBi-030 Rev C.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 2_MWD_Interp Azi 300.0 1500.0 3_MWD+IFR2+Sag 300.0 2617.0 3_MWD+IFR2+MS+Sag 47.0 300.0 SDI_KPR_ADK 2617.0 3817.0 3_MWD+IFR2+Sag 2617.0 11142.0 3_MWD+IFR2+MS+Sag 11142.0 12342.0 3_MWD+IFR2+Sag 11142.0 17529.3 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 From Colour To MD 11400.0 To 16000.0 MD Azi TFace 47.0 0.00 0.00 350.0 0.00 0.00 650.0 345.00 345.00 995.2 321.50 -39.34 1145.2 321.50 0.00 3333.9 306.83 -15.83 10447.4 306.83 0.00 11197.3 329.41 105.30 11297.3 329.41 0.00 11703.9 329.41 0.00 11709.5 329.41 0.23 17529.3 329.41 0.00 Plan: NDBi-030 Rev C.0 AC Flipbook SURVEY PROGRAM Depth From Depth To Tool 47.0 300.0 2_MWD_Interp Azi 300.0 1500.0 3_MWD+IFR2+Sag 300.0 2617.0 3_MWD+IFR2+MS+Sag 47.0 300.0 SDI_KPR_ADK 2617.0 3817.0 3_MWD+IFR2+Sag 2617.0 11142.0 3_MWD+IFR2+MS+Sag 11142.0 12342.0 3_MWD+IFR2+Sag 11142.0 17529.3 3_MWD+IFR2+MS+Sag CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2303.2 2617.013-3/8" x 16" Surface Casing 4088.9 11142.09-5/8" x 12-1/4" Intermediate Liner 4143.0 17529.44-1/2" x 8 -1/2" Production Liner 10 10 20 20 30 30 40 40 50 50 60 60 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in] 47 300 300 500 500 750 750 1000 1000 1250 1250 1500 1500 1750 1750 2000 2000 2500 2500 3000 3000 3500 3500 4500 4500 5500 5500 6500 6500 7500 7500 8500 8500 9500 9500 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 16000 16000 17000 17000 18000 From Colour To MD 16000.0 To 17530.0 MD Azi TFace 47.0 0.00 0.00 350.0 0.00 0.00 650.0 345.00 345.00 995.2 321.50 -39.34 1145.2 321.50 0.00 3333.9 306.83 -15.83 10447.4 306.83 0.00 11197.3 329.41 105.30 11297.3 329.41 0.00 11703.9 329.41 0.00 11709.5 329.41 0.23 17529.3 329.41 0.00 Attachment 3: BOPE Equipment 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# 21-1/4" X 2,000# FORWARD 13-5/8" X 5,000# 13-5/8" X 5,000# 30" 13-5/8" X 5,000# 186" 13-5/8" X 5,000# DUTCH LOCK DOWN ChokeLine fromBOP PressureGauge 1502PressureSensorPressureTransducer Bill ofMaterial Item Description To PanicLine Item Description A3Ͳ1/8”– 5,000psi W.P. RemoteHydraulic OperatedChoke B3Ͳ1/8”–5,000psiW.P. AdjustableManual Choke 1–14 3Ͳ1/8”– 5,000psi W.P. ManualGateValve 15 2 1/16”5 000 i WP152Ͳ1/16”–5,000psiW.P. ManualGateValve To MudGas Legend BlindSpare To TigerTankSeparatorValveNormally Open Valve Normally Closed Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (mud loggers, trained drilling personnel). 12-1/4” Intermediate Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Drill with oil based mud, maintain mud in specifications, use sufficient mud weight to hold back formations. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Hole Cleaning in 79q Sail Conduct hydraulics modeling and control ROP limits based on cuttings returns and observed ECD’s compared to model. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Wireline Inaccessibility The sail angle on this section is too high for wireline to be run conventionally. If wireline logs are required for operations a tractor will be required. Operational complexity with Mechanical two stage cement equipment The 2nd stage of the cement job will be conducted through a mechanically shifted sleeve. This will require the LTP to not be set until the 2nd stage is pumped giving a higher complexity leading to complications with setting the LTP. 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. Close Approach NDBi-043 The heel to toe separation between NDBi-043 production liner is ~500’. NDBi-043 will not have production, injection or frac operations happening when production hole drilling commences. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. Close Approach NDBi-043 Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8” 68# L-80 BTC Surface Casing Basis Lead Open hole volume + 300% excess in permafrost / 50% excess below permafrost Lead TOC Surface Tail Open hole volume + 50% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Clean Spacer Lead 11.0ppg Lead: 480 bbls, 2695 cuft, 945 sks ArcticCem, Yield: 2.85 cuft/sk Tail 15.3ppg Tail: 69 bbls, 387 cuft, 309 sks 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 NDBi-030 13-3/8" SURFACE CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME (bbls) Shoe track length 2532 2617 85 0.14973 12.7 TAIL LENGTH 2117 2617 500 0.07491 37.5 TAIL EXCESS 50% 18.7 LEAD TOP TO BASE OF PERMA 1418 2117 699 0.07491 52.4 EXCESS FACTOR FOR ABOVE 50% 26.2 PERMAFROST ANNULUS(Lead) 128 1418 1290 0.07491 96.6 EXCESS FACTOR FOR ABOVE 300% 289.9 CASED HOLE ANNULUS 46 128 82 0.18620 15.3 Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Lead Open hole volume + 150’ liner lap Lead TOC Stage 1: 250’ TVD above top Nanushuk Stage 2: N/A Tail Open hole volume + 85 ft shoe track Tail TOC Stage 1: 1000 ft above casing shoe Stage 2: Top of the 9-5/8” Liner Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead Stage 1: 30% Open Hole Excess 13.0ppg Lead:112bbls, 629cuft, 342sks ExtendaCem, Yield: 1.84 cuft/sk Stage 2: N/A Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 79bbls, 444cuft, 358sks VersaCem Type I/II – 1.24 cuft/sk Verified stage 1 cement calcs. -bjm Verified cement calcs. -bjm Stage 2: 100% Open Hole Excess 15.3ppg Tail: 209bbls, 1173cuft, 1172sks VersaCem Type I/II – 1.24 cuft/sk Temp BHST 94° F Notes Job will be mixed on the fly Verification Method Ͳ LWD Sonic will be used to log the 1 st Stage Cement Job Only. Ͳ 2nd Stage Cement Job will not be logged, assuming job parameters are as expected (No losses, good lift pressures, circulate cement off top of liner). Justification: Ͳ Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. Ͳ Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) Ͳ 2nd Stage bond evaluation does not affect 1 st Stage bond evaluation and frac decision. Ͳ Logging of 1 st Stage cement will demonstrate isolation of injection fluids in the Nanushuk reservoir, as well as isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. Ͳ 2nd Stage cement job will isolate Tuluvak with cement and a V0Ͳrated LTP above it as a redundant means of isolation. Ͳ Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place.With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. Ͳ Future hydraulic fracture operations will only be done in the Nanushuk formation.Log verification of the 1 st stage cement job will verify proper isolation has been achieved for frac operations. Ͳ Tuluvak isolation has been achieved on all historical Pikka development wells. Ͳ Seeking to simplify an already complicated operation, saving time/money. NDBͲ030 9.625" Production LinerͲ1st Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME (bbls) Shoe track length 11057 11142 85 0.07321 6.2 TAIL LENGTH 10142 11142 1000 0.05578 55.8 TAIL EXCESS30% 16.7 LEAD LENGTH 8600 10142 1542 0.05578 86.0 LEAD EXCESS 30% 25.8 NDBͲ030 9.625" Production LinerͲ2nd Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME (bbls) Shoe track length 4200 4200 0 0.07321 0.0 TAIL LENGTH 2617 4200 1583 0.05578 88.3 TAIL EXCESS100% 88.3 (946 sks x 1.24 cuft/sk = 1173 cuft / 5.61 cuft/bbl = 209 bbls) SFD Verified stage 2 cement calcs, based on mid-Tuluvak stage collar. Stage 2 cement volumes to be recalculated based on stage collar set depth of 50' MD below TS 790 pick, to be determined by GR/Res log. -bjm Stage collar must be placed no shallower than 50' MD below the base of the Upper Tuluvak as defined by the TS790 horizon. Submit 12-1/4" OH logs to AOGCC and obtain approval for stage collar setting depth before running 9-5/8" liner. -bjm 2nd Stage Cement Job will not be logged, 946 sacks (per email from G. Staudinger, 12/26/2023) SFD LinerLap13Ͳ3/8"68#x9Ͳ5/8"47#LNR246726171500.059749.0 200'abovelinertop226724672000.1162023.2 Attachment7:PrognosedFormationTops NDBiͲ030PrognosedTops FormationMD (ft) TVDKB (ft) TVDPath (ft) Uncertainty Range (±ft) PorePressure (ppg) UpperSchraderBluff105410479761007.2 PermafrostBaseTransition1418139513241007.3 MiddleSchraderBluff1810174216721007.6 MCU(LowerSchraderBluff)2363215320601007.8 TuluvakShale2991247223621007.9 TuluvakSand30602496242110010.2 Seabee6435316030751009.2 Nanushuk9889382037491008.9 NT6MFS10333390538351008.9 NT5MFS10708398139121008.8 NT4MFS10963404239741008.8 NT3MFS11197410440341008.8 Nanushuk3.2(NT3)11317413740661008.8 Attachment 8: Well Schematic Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole LWD Gamma Ray Resistivity 8-1/2” Production Hole LWD Gamma Ray Resistivity Sonic Density Neutron Ultra Deep Resistivity. Mudlogging Mudlogging will be utilized from surface to TD. Mudlogging will be utilized from surface to TD. Attachment 10: Wellhead & Tree Diagram Attachment 11: Injector Area of Review Wells within ¼ mile of proposed injection well. Distance Annulus integrity Area of Review Information NDBi-043 109’ Passing MIT-IA to 4,000. NDBi-043 is an injection well targeting the Nanushuk 3 reservoir. The 9-5/8” liner was set at 6,237’ MD in the NT4 and was fully cemented with 277 bbls, 665sxs, 2.35 ft^3/sx of 12.0 ppg lead and 44 bbls 200 sxs, 1.24 ft^3/sx 15.3 ppg tail cement. Full returns while pumping cement and the plug bumped on plan. A CAST-M wireline log was run and verified cement isolation of the 9-5/8” Liner appropriate to carry out hydraulic fracturing operations. NDBi-043’s lower completion consisted of a 4- 1/2” liner with mechanical packers and frac ports. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Staudinger, Garret (Garret) Cc:Roby, David S (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Tirpack, Robert (Robert); Thompson, Jacob (Jacob); Staudinger, Mark (Mark); Noll, Christian (Christian); Bond, Andrew (Andy) Subject:RE: NDBi-030 PTD Variance Request Date:Friday, January 26, 2024 6:00:00 PM Attachments:image002.jpg image003.jpg Garret, The AOGCC will grant a variance request to 20 AAC 25.030(d)(5) to set the stage collar in the 9-5/8” casing in this well 50’ MD below the TS 790 marker such that the Upper Tuluvak is fully cemented. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Monday, January 22, 2024 1:10 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com>; Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; Noll, Christian (Christian) <Christian.Noll@santos.com>; Bond, Andrew (Andy) <Andy.Bond@santos.com> Subject: RE: NDBi-030 PTD Variance Request Hey Bryan, Based on the latest discussion with the AOGCC, I have updated the verbiage to the NDBi-030 PTD Variance Request. Please see below: Oil Search (Alaska) would like to submit a proposed variance request for the Permit to Drill on the upcoming well, NDBi-030. Details of the variance request are below: Proposed Variance Request 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire annular space from the casing shoe to above shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the significant hydrocarbon zone in the Nanushuk formation (primary job), and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. The primary cement job will target a top of cement 500’ MD or 250’ TVD, whichever is greater, above the top of the Nanushuk. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the intermediate liner is not achievable without exceeding the fracture gradient and compromising cement placement and zonal isolation. The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be designed to: 1) provide suitable and safe operating conditions for the total measured depth proposed; 2) confine fluids to the wellbore; 3) prevent migration of fluids from one stratum to another; 4) ensure control of well pressures encountered; 5) protect against thaw subsidence and freezeback effects within permafrost; 6) prevent contamination of freshwater; 7) protect significant hydrocarbon zones; and 8) provide well control until the next casing is set, considering all factors relevant to well control including formation fracture gradients, formation pressures, casing setting depths, and proposed total depth. The formation interval between the top of stage one and the bottom of stage two includes the Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with very low permeability and contain no significant hydrocarbons. Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,640’ TVD. The Tuluvak formation below 2,640’ TVD is not a significant hydrocarbon zone. A stage collar placement is proposed within the TS 875 clinoform in the Tuluvak formation (below TS 880). A stage collar depth of 2,725’ TVD was picked as a conservative approach to include any potential gas based on offset well data. The TS 875 clinoform is shale dominated, very low net to gross, has no vertical permeability, and represents a seal to the hydrocarbon bearing TS 880. This stage collar location would provide the following benefits: 1) Minimum 85’ TVD of cement below the base of significant hydrocarbon zone in the Tuluvak. 2) Cement across and above the significant hydrocarbon zone in the Tuluvak, up to the top of liner. Moving the cementing stage tool to be placed at ~2,725’ TVD allows placement of higher quality cement that provides better isolation across the significant hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will add risk to the primary objective of cement isolation across the significant hydrocarbon zone which is only located in the upper portion of the Tuluvak (TS 880). The increased risk is due to: 1) Cementing the entire Tuluvak would require large cement jobs that jeopardize cement isolation across the upper Tuluvak. 2) Large cement jobs likely require the use of lighter weight cement across the significant hydrocarbon zone. I have attached some supporting documentation for subsurface characterization of the Tuluvak and Seabee formations. Please let me know if you have any questions. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 From: Staudinger, Garret (Garret) Sent: Monday, January 8, 2024 12:35 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Thompson, Jacob (Jacob) <Jacob.Thompson@santos.com>; Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; Noll, Christian (Christian) <Christian.Noll@santos.com>; Bond, Andrew (Andy) <Andy.Bond@santos.com> Subject: NDBi-030 PTD Variance Request Bryan, Oil Search (Alaska) would like to submit a proposed variance request for the Permit to Drill on the upcoming well, NDBi-030. Details of the variance request are below: Proposed Variance Request 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire Tuluvak formation. Based on offset well logs, cuttings, and mudlogging analysis, the base of the significant hydrocarbon zone in the Tuluvak is at 2725’ TVD. The Tuluvak formation below 2,725’ TVD is not a significant hydrocarbon zone. Moving the cementing stage tool to be placed at ~2,725’ TVD allows placement of higher quality cement that provides better isolation across the significant hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will add risk to cement isolation due to large cement jobs and the placement of lighter weight cement across the significant hydrocarbon zone. Please let me know if you have any questions or need any other information. Regards, Garret Staudinger Senior Drilling Engineer t: +1 (907) 375-4666 | m: +1 (907) 440-6892 | e: garret.staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 1 Davies, Stephen F (OGC) From:Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent:Tuesday, December 26, 2023 5:55 PM To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC) Subject:RE: PIKKA-NDB-030 (PTD 223-120) - Question Steve, Thevaluesforthebarrelsandcubicfeetforthe2ndstagecementjobarecorrect.However,Idoseeatypoonthe sacks.Itshouldread946sksinsteadof1172sks. Thanks, GarretStaudinger SeniorDrillingEngineer t:+1(907)375Ͳ4666|m:+1(907)440Ͳ6892 From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Tuesday,December26,20233:43PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:![EXT]:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲQuestion GarreƩ, I’mreviewingthisPermittoDrillapplicaƟon,andIhaveaquesƟon.Inthe“IntermediateLinerCement”secƟon,the informaƟonforStage2isgivenas: CouldyoupleaseconĮrmthesevalues? ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Davies, Stephen F (OGC) From:Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent:Tuesday, December 26, 2023 6:59 PM To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC) Subject:RE: PIKKA-NDB-030 (PTD 223-120) - Additional Question Steve, TheSurveyor’sAsͲBuiltsurfacecoordinatesarecorrect.Goodcatchandthanksforchecking. GarretStaudinger SeniorDrillingEngineer t:+1(907)375Ͳ4666|m:+1(907)440Ͳ6892 From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Tuesday,December26,20234:22PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:![EXT]:RE:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲAdditionalQuestion GarreƩ, AnaddiƟonalquesƟon:Which“FSL”surfacecoordinateiscorrect? 401FormSurveyor’sAsͲBuiltSurveyPlat ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 From:Davies,StephenF(OGC) Sent:Tuesday,December26,20233:43PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲQuestion GarreƩ, I’mreviewingthisPermittoDrillapplicaƟon,andIhaveaquesƟon.Inthe“IntermediateLinerCement”secƟon,the informaƟonforStage2isgivenas: CouldyoupleaseconĮrmthesevalues? ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email 1 Davies, Stephen F (OGC) From:Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent:Wednesday, January 3, 2024 12:51 PM To:Davies, Stephen F (OGC) Subject:Re: PIKKA-NDB-030 (PTD 223-120) - One More Question HeySteve, Sorryforthedelayedresponse.NDBͲ030willNOTbepreͲproduced.Letmeknowifthereareanyotherquestions. Thanks, Garret GetOutlookforiOS From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Tuesday,January2,202412:56PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Subject:![EXT]:RE:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲOneMoreQuestion Garret, WillNDBͲ030bepreͲproduced? ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov From:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Sent:Tuesday,December26,20236:59PM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:RE:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲAdditionalQuestion Steve, TheSurveyor’sAsͲBuiltsurfacecoordinatesarecorrect.Goodcatchandthanksforchecking. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 GarretStaudinger SeniorDrillingEngineer t:+1(907)375Ͳ4666|m:+1(907)440Ͳ6892 From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Tuesday,December26,20234:22PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:![EXT]:RE:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲAdditionalQuestion Garrett, Anadditionalquestion:Which“FSL”surfacecoordinateiscorrect? 401FormSurveyor’sAsͲBuiltSurveyPlat ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov From:Davies,StephenF(OGC) Sent:Tuesday,December26,20233:43PM To:Staudinger,Garret(Garret)<Garret.Staudinger@santos.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:PIKKAͲNDBͲ030(PTD223Ͳ120)ͲQuestion Garrett, I’mreviewingthisPermittoDrillapplication,andIhaveaquestion.Inthe“IntermediateLinerCement”section,the informationforStage2isgivenas: Couldyoupleaseconfirmthesevalues? Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 223-120 PIKKA PIKKA NDB-030 PIKKA, NANUSHUK OIL WELL PERMIT CHECKLIST Company Oil Search (Alaska), LLC Well Name:PIKKA NDB-030 Initial Class/Type SER / PEND GeoArea 890 Unit 11580 On/Off Shore On Program SERField & Pool Well bore seg Annular DisposalPTD#:2231200 PIKKA, NANUSHUK OIL - 600100 NA1 Permit fee attached Yes Surface Location lies within ADL0392984; Portion of Well Passes Thru ADL03914452 Lease number appropriate Yes & ADL0393020; Top Productive Interval lies in ADL0393019; TD lies in ADL0393018.3 Unique well name and number Yes PIKKA, NANUSHUK OIL - 600100 - governed by CO 8074 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary Yes6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait No An AOGCC Injection Order is required prior to beginning injection operations.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes NDB-043A.15 All wells within 1/4 mile area of review identified (For service well only) No Per G. Staudinger, Oil Search, well will not be pre-produced.16 Pre-produced injector: duration of pre-production less than 3 months (For service well only) NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) Yes18 Conductor string provided Yes19 Surface casing protects all known USDWs Yes20 CMT vol adequate to circulate on conductor & surf csg Yes Intermediate liner has 2-stage job with variance to leave uncemented gap. 2nd stage will come into sfc csg.21 CMT vol adequate to tie-in long string to surf csg Yes See variance22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit NA25 If a re-drill, has a 10-403 for abandonment been approved Yes Close approach well will be shut-in during drilling ops.26 Adequate wellbore separation proposed Yes27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP=1871 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 shutdown No33 Is presence of H2S gas probable NA34 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 measures Yes Abnormal Pressure: high risk, Tuluvak expected at 10.1 ppg. Surface casing will be set above Tuluvak.36 Data presented on potential overpressure zones NA Gas hydrates, lost circulation, hole swabbing, and stuck pipe: some risk, mitigation discussed on p. 46 &37 Seismic analysis of shallow gas zones NA 47. Operator's planned mud program appears sufficient to control anticipated pressures and38 Seabed condition survey (if off-shore) NA maintain wellbore stability.39 Contact name/phone for weekly progress reports [exploratory only] Appr SFD Date 1/3/2024 Appr BJM Date 1/26/2024 Appr SFD Date 1/2/2024 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date *&: JLC 1/29/2024
