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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 6 9 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 1 4 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 2/ 1 4 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 0 5 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 15 4 0 9 TV D 42 0 6 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 , 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 3/ 1 5 / 2 0 2 4 47 1 5 4 0 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 f t . l as 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ A P _ R 0 1 _ R M _ 2 0 2 3 1 2 2 6 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ A P _ R 0 2 _ R M _ 2 0 2 4 0 1 1 6 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ A P _ R 0 3 _ R M _ 2 0 2 4 0 1 2 4 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ A P _ R 0 4 _ R M _ 2 0 2 4 0 2 1 0 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 47 1 5 4 0 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ D M D _ R M _ 1 5 4 0 9 f t _ 2 0 2 4 0 1 2 4 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ D M T _ R 0 1 _ 2 0 2 3 1 2 2 6 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ D M T _ R 0 2 _ R M _ 2 0 2 4 0 1 1 6 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ D M T _ R 0 3 _ R M _ 2 0 2 4 0 1 2 4 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 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 - 01 4 _ D M T _ R 0 4 _ R M _ 2 0 2 4 0 2 1 0 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 25 1 0 1 0 4 5 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ S D T K _ C B L _ 2 5 1 0 _ 1 0 4 5 0 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 23 1 7 1 0 4 5 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ S D T K _ T O C _ 2 3 0 0 _ 1 0 4 5 0 . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 10 4 4 7 1 5 4 0 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ D r i l l G a s _ d e p t h _ 1 5 4 0 9 f t M D . l a s 38 6 2 9 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 5 Su p p l i e d b y Op ND B i - , 014 _ D M D _ R M _ 1 5 4 0 9 f t _ 2 0 2 4 0 1 2 4 . 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 6 9 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 1 4 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 2/ 1 4 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 0 5 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 15 4 0 9 TV D 42 0 6 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 3/ 1 5 / 2 0 2 4 12 0 2 5 7 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ D r i l l G a s _ d e p t h _ 2 5 7 1 f t M D . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 10 4 4 7 1 5 4 0 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : N D B i - 01 4 _ G E O L O G _ G E O I S O T O P E S _ G 5 _ C o r r e c t e d da t a _ 1 0 4 4 7 - 1 5 4 0 9 f t _ F I N A L . l a s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 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 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 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 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 D e f i n i t i v e S u r v e y . x l s x 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 D e f i t 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 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 D e f i t 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 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 P l a n V i e w . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 V e r t i c a l S e c t i o n . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ 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 . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ C B L _ 2 5 1 0 _ 1 0 4 5 0 . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ C B L _ 2 5 1 0 _ 1 0 4 5 0 . d l i s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ C B L _ 2 5 1 0 _ 1 0 4 5 0 . P D F 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ C B L _ 2 5 1 0 _ 1 0 4 5 0 _ d l i s . t x t 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ T O C _ 2 3 0 0 _ 1 0 4 5 0 . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ T O C _ 2 3 0 0 _ 1 0 4 5 0 . d l i s 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ T O C _ 2 3 0 0 _ 1 0 4 5 0 . P D F 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ S D T K _ T O C _ 2 3 0 0 _ 1 0 4 5 0 _ d l i s . t x t 38 6 2 9 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 5 fu l l m u d l o g g i n g se r v i c e s w e r e no t u s e d 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 6 9 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 1 4 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 2/ 1 4 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 0 5 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 15 4 0 9 TV D 42 0 6 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 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ C a l _ R M _ 1 5 4 0 9 f t _ 5 T V D. c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 f t _2 T V D . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 f t _5 M D . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 _ 2M D . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ A P _ R M _ 2 0 2 4 0 2 1 0 . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ D M D _ R M _ 1 5 4 0 9 f t . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ D M T _ R M _ 2 0 2 4 0 2 1 0 . c g m 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l - RM _ 1 5 4 0 9 f t _ 5 T V D . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B I - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 f t _2 M D . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 f t _2 T V D . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ L W D _ G R _ R e s _ D e n _ N e u _ C a l _ R M _ 1 5 4 0 9 f t _5 M D . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 _ A P _ R M _ 2 0 2 4 0 2 1 0 . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 _ D M D _ R M _ 1 5 4 0 9 f t . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ D M T _ R M _ 2 0 2 4 0 2 1 0 . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 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 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 _ G a s R a t i o Lo g _ s u r f a c e _ 1 5 4 0 9 f t M D - 2 i n . p d f 38 6 2 9 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 5 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 6 9 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 1 4 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 2/ 1 4 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 0 5 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 15 4 0 9 TV D 42 0 6 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 DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 _ G a s R a t i o Lo g _ S u r f a c e _ 1 5 4 0 9 f t M D - 5 i n . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ G E O L O G _ G 5 _ C o m p o s i t e L o g _ 1 0 4 4 7 - 15 4 0 9 f t _ 2 i n c h . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 0 1 4 _ G E O L O G _ G 5 _ G a s I N OU T L o g _ 1 0 4 4 7 - 1 5 4 0 9 f t _ 2 i n c h . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ G E O L O G _ G 5 _ G E O I S O T O P E S L o g _ 1 0 4 4 7 - 15 4 0 9 f t _ 2 i n c h . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ M u d l o g _ S u r f a c e _ 1 5 4 0 9 f t M D - 2 i n . p d f 38 6 2 9 ED Di g i t a l D a t a DF 3/ 1 5 / 2 0 2 4 E l e c t r o n i c F i l e : N D B i - 01 4 _ M u d l o g _ S u r f a c e _ 1 5 4 0 9 f t M D - 5 i n . p d f 38 6 2 9 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 1 4 _ R e v A_ S i g n e d . p d f 39 8 3 1 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 1 4 _ 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 1 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 1 4 _ _ E n d of 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 u t e _ F i n a l Da t a . x l s x 39 8 3 1 ED Di g i t a l D a t a DF 11 / 1 9 / 2 0 2 5 10 3 1 5 1 5 4 2 3 E l e c t r o n i c D a t a S e t , F i l e n a m e : S A N T O S _ N D B i - 01 4 _ B H P _ 8 _ 5 _ 1 0 4 4 8 _ 1 5 3 6 2 _ R U N 3 . l a s 41 1 1 8 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 - 01 4 _ B H P _ 8 _ 5 _ 1 0 4 4 8 _ 1 5 3 6 2 _ R U N 3 . d l i s 41 1 1 8 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 5 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 6 9 - 0 0 - 0 0 We l l N a m e / N o . PI K K A N D B i - 0 1 4 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 2/ 1 4 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 0 5 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 15 4 0 9 TV D 42 0 6 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 e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 2/ 1 4 / 2 0 2 4 Re l e a s e D a t e : 12 / 6 / 2 0 2 3 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 5 1/ 1 5 / 2 0 2 6 M. G u h l 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 15,409 feet N/A feet true vertical 4,206 feet N/A feet Effective Depth measured 15,402 feet See attached rpt feet true vertical 4,206 feet See attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6ppf P-110S 15,402' MD 3,132' TVD Packers and SSSV (type, measured and true vertical depth) See attached 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 324-085 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 Report attached 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 2. Operator Name 4. Well Class Before Work: ADL 392984, 392985, 393023, 391445, 393021 Pikka / Nanushuk Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 5. Permit to Drill Number: 50-103-20869-00-00 601 W Fifth Avenue Anchorage, AK 99501-6301 3. Address: NDBi-014 Report attached Length 128' 2,564' 128'Conductor Surface Intermediate 20"x34" 13-3/8" Size 128' 9-5/8" 11,590 9-5/8" measured TVD Tie-Back Liner 10,440' 2,374' 5,144' Casing Structural 4,370' 2,175' 4-1/2" 8,066' 2,374' 15,402' 3,132' Plugs Junk measured Burst Collapse 2,260 4,750 4,750 5,020 6,870 6,870 11,590 9,210Production 10,251' 4-1/2" 10,251' 4,366' 2,564' 2,289' p k ft t Fra O s 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 08/07/24 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 15,409 feet N/A feet true vertical 4,206 feet N/A feet Effective Depth measured 15,402 feet See attached rpt feet true vertical 4,206 feet See attached rpt feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6ppf P-110S 15,402' MD 3,132' TVD Packers and SSSV (type, measured and true vertical depth) See attached 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 324-085 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 Report attached 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 2. Operator Name 4. Well Class Before Work: ADL 392984, 392985, 393023, 391445, 393021 Pikka / Nanushuk Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 5. Permit to Drill Number: 50-103-20869-00-00 601 W Fifth Avenue Anchorage, AK 99501-6301 3. Address: NDBi-014 Report attached Length 128' 2,564' 128'Conductor Surface Intermediate 20"x34" 13-3/8" Size 128' 9-5/8" 11,590 9-5/8" measured TVD Tie-Back Liner 10,440' 2,374' 5,144' Casing Structural 4,370' 2,175' 4-1/2" 8,066' 2,374' 15,402' 3,132' Plugs Junk measured Burst Collapse 2,260 4,750 4,750 5,020 6,870 6,870 11,590 9,210Production 10,251' 4-1/2" 10,251' 4,366' 2,564' 2,289' p k ft t Fra O s 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 08/07/24 By Grace Christianson at 3:12 pm, Sep 17, 2024 RBDMS JSB 091924 DSR-9/27/24 CDW 09/17/2024 Superseded Page 1 of 1 Well Name: NDBi-014 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) Remainder of the SLZXP Liner Top Hanger Packer 10,279.2 4,366.9 OH Packer #11 10,510.9 4,370.9 OH Packer #10 10,619.6 4,370.0 OH Packer #9 11,161.6 4,351.8 OH Packer #8 11,621.5 4,335.7 OH Packer #7 12,159.8 4,317.1 OH Packer #6 12,661.0 4,299.8 OH Packer #5 13,327.7 4,276.7 OH Packer #4 13,747.6 4,262.0 OH Packer #3 14,290.6 4,243.4 OH Packer #2 14,834.4 4,224.7 OH Packer #1 15,252.3 4,211.2 NDBi-014 Well Schematic GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,374' MD 13-3/8" 68 ppf L-80 Surface Casing2,564' MD 9-5/8", 47ppf L-80 Intermediate Liner10,440' MD 4-½, 12.6ppf P-110S Production Liner 15,402' MD 4-½ Liner Hanger Liner Top Packer10,257' MD Archer C-Flex Two-Stage Cementing Tool (Base of Tuluvak) 5,140' MD TOC First Stage Cement Job7,739' MD 16" Hole Size 12-1/4" Hole Size 02.14.202446.90' RKB Bottom Flange 9-5/8" Tieback and Seal Assembly2,374' MD 8-½ Openhole 15,409' MD 1 2 3 4 5 6 7 8 9 # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X LandingNipple 1489 1464 21 3.813 4.778 2 Gaslift Mandrel 1.5" 2087 1975 41 3.865 7.632 3 X LandingNipple 2157 2028 43 3.813 4.780 4 X LandingNipple 10106 4361 87 3.813 4.780 5 D/HPsi Temp Gauge 10168 4363 88 3.905 5.996 6 X LandingNipple 10191 4364 88 3.813 4.779 7 Tieback Seal Assy 10292 4367 88 3.860 5.230 8 9.625"x 4.5"LH/Packer 10257 4366 88 6.110 8.430 9 #11Openhole Packer 10504 4370 89 3.911 8.000 10 #10Openhole Packer 10612 4370 91 3.899 8.000 11 Stage 9 FracSleeve 10803 4364 91 3.735 5.628 12 #9Openhole Packer 11154 4352 91 3.898 8.000 13 Stage 8 FracSleeve 11304 4347 91 3.735 5.628 14 #8Openhole Packer 11614 4336 92 3.909 8.000 15 Stage 7 FracSleeve 11843 4328 91 3.735 5.628 16 #7Openhole Packer 12153 4317 92 3.911 8.000 17 Stage 6 FracSleeve 12385 4309 92 3.735 5.628 18 #6Openhole Packer 12654 4300 92 3.898 8.000 19 Stage 5 FracSleeve 13009 4287 92 3.735 5.628 20 #5Openhole Packer 13321 4276 92 3.911 8.000 21 Stage 4 FracSleeve 13553 4268 92 3.735 5.632 22 #4Openhole Packer 13740 4262 92 3.910 8.000 23 Stage 3 FracSleeve 14012 4252 92 3.735 5.628 24 #3Openhole Packer 14283 4243 92 3.908 8.000 25 Stage 2 FracSleeve 14558 4234 92 3.735 5.628 26 #2Openhole Packer 14827 4225 92 3.905 8.000 27 Stage 1 FracSleeve 15098 4216 92 3.735 5.628 28 #1Openhole Packer 15245 4211 92 3.907 8.000 29 #2Toe Sleeve 15313 4209 92 3.500 5.750 30 #1Toe Sleeve 15325 4208 92 3.500 5.750 31 WIV Collar 15388 4206 92 0.870 5.200 32 Eccentricshoe 15400 4206 92 3.900 5.210 Frac Ops Summary Report - AOGCC Well Name NDBi-014 Primary Job Type Fracture Treatment Start Date End Date Summary 3/15/2024 3/16/2024 Fill and heat water tanks. RU frac. 3/16/2024 3/17/2024 Fill and heat water tanks. RU frac. 3/17/2024 3/18/2024 Heat Frac tanks and continue RU Frac and support equipment. 3/18/2024 3/19/2024 RU hydration unit and blender. Finish heating Frac tanks. Complete Frac RU. 3/19/2024 3/20/2024 Complete RU. Perform equipment checks. Pressure Test surface equipment. 3/20/2024 3/21/2024 Got equipment ready to Frac. Primed up and pressure tested. Held PJSM with all personnel. Hydraulic issues with blender delayed the job. RD blender and send to SLB shop for diagnosis and repair. 3/21/2024 3/22/2024 Swapped out upper master valve on FMC tree. Pressure tested tree. Waiting on SLB blender. 3/22/2024 3/23/2024 Frac Stages 1-2 Finish RU of Frac equipment, prime up, pressure test. Pressure up to 7,400 psi to open Toe Port Pump Check with 350 bbls WF125 Frac stage 1: 2,391.5 bbls slurry (YF125ST fluid), 217,426 lbs 16/20 Carbolite (1, 2, 3, 4, 5, 6, 7, 8ppa), 2,165.9 bbls clean fluid at 40bpm, as per design. DataFrac: 297.3 bbls clean fluid (WF125 fluid) at 40bpm. Frac stage 2: 2,016.7 bbls slurry (YF125ST fluid), 104,715 lbs 16/20 Carbolite (1, 2, 4, 6ppa), 1,907.8 bbls clean fluid at 40bpm, comments: Blender lost boost pressure due to loss of hydraulic power, cut sand and overflushed with 200 bbls of WF125. TLTR - 4,721 bbls 3/23/2024 3/24/2024 Reload proppant. Refill and heat frac tanks. 3/24/2024 3/25/2024 Finished loading proppant. Heated frac tanks. RU blender and hydration unit. 3/25/2024 3/26/2024 Frac Stages 2-5 Finish RU of Frac equipment, prime up, pressure test. Pump ball to seat with 220 bbls WF125. Pump Check with 267 bbls WF125 Frac stage 2: 2,076.6 bbls slurry (YF125ST fluid), 197,986 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,871.6 bbls clean fluid at 40bpm, as per design. Frac stage 3: 1,845.5 bbls slurry (YF125ST fluid), 228,302 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 9ppa), 1,608.9 bbls clean fluid at 40bpm, comments: Changed the 10ppa stage to a 9ppa stage due to high breakdown pressure at beginning of stage. Frac stage 4: 1,695.1 bbls slurry (YF125ST fluid), 228,275 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,458.6 bbls clean fluid at 40bpm, as per design. Frac stage 5: 2,266.9 bbls slurry (YF125ST fluid), 229,650 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 2,029.3 bbls clean fluid at 40bpm, as per design. TLTR (Stages 2-5) : 7,455.4 bbls TLTR (Total) : 12,176.4 bbls 3/26/2024 3/27/2024 Reload proppant. Refill and heat frac tanks. 3/27/2024 3/28/2024 Reload proppant, fill and heat Frac tanks, and load chemicals for stages 6-9 Page 1 of 2 Frac Ops Summary Report - AOGCC Start Date End Date Summary 3/28/2024 3/29/2024 Finish loading proppant and heating frac tanks. RU blender, hydration unit, and chemical trailers. 3/29/2024 3/30/2024 Frac Stages 6-9 Finish RU of Frac equipment, prime up, pressure test. Pump ball to seat with 168.4 bbls WF125. Pump Check with 100 bbls WF125 Frac stage 6: 1,852.7 bbls slurry (YF125ST fluid), 15,446 lbs 40/70 Carbolite (1, 3ppa), 228,772 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,600.0 bbls clean fluid at 40bpm, as per design. Frac stage 7: 1,891.9 bbls slurry (YF125ST fluid), 17,710 lbs 40/70 Carbolite (1, 3ppa), 215,591 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,650.6 bbls clean fluid at 40bpm, as per design. Frac stage 8: 1,850.3 bbls slurry (YF125ST fluid), 11,644 lbs 40/70 Carbolite (1, 3ppa), 228,078 lbs 16/20 Carbolite (1, 2, 4, 6, 8, 10ppa), 1,602.1 bbls clean fluid at 40bpm, as per design. Frac stage 9: 2,483.3 bbls slurry (YF125ST fluid), 223,525 lbs 16/20 Carbolite (1, 2, 3, 4, 5, 6, 7, 8ppa), 2,252.3 bbls clean fluid at 35bpm, Comments: No pressure signature when collet landed, dropped a 2nd ball to confirm sleeve shift. TLTR (Stages 6-9) 7,373.4 bbls TLTR (Total) 19,549.8 bbls 3/30/2024 3/31/2024 Continue RD frac equipment 3/31/2024 4/1/2024 Finish RD Frac equipment. Page 2 of 2 Flowback Ops Summary Report - AOGCC Well Name NDBi-014 Primary Job Type Flowback/Testing Start Date End Date Summary 4/24/2024 4/25/2024 Expro rigged up to wellhead. 4/25/2024 4/26/2024 Expro RU Equipment in preperation to open the welll to flow. RU SSV controls and function test. 4/26/2024 4/27/2024 Wrap and heat well head. Pre flow check list walk through and valve alignment verification. Pre Flow meeting with supervisors and crews. 4/27/2024 4/28/2024 Final preperations, walk through, and safety meeting. Open well to flow per clean up procedure. 4/28/2024 4/29/2024 Expro flowing the well as per clean up procedure, Well unable to sustain flow, shut in well Monitor pressure build ups 4/29/2024 4/30/2024 Monitor pressure build up. open to flow the well as per clean up procedure. 4/30/2024 5/1/2024 Flow the well as per clean up procedure. SI Well, pump 35 bbls Diesel, and 130 bbls Seawater, shut in. Flow well as per clean up proceedure. 5/1/2024 5/2/2024 Flow well as per clean up procedure. Shut in well and record pressure build up. Well unable to maintain flow on its own. Freeze protect well. Freeze protect surface lines. Suspend operations on well, rig down Expro equipment and prepare to move to NDB-032. 6/29/2024 6/30/2024 MIRU Halliburton Slickline unit. Set catcher sub at 2198' slmd. Pull DV from 2087' and replace with 16/64" OV. Pull catcher sub. RDMO. 7/3/2024 7/4/2024 Rig up FB irons and safety systems, air test and fluid test LP lines to 1000psi and HP lines to 4500psi. FMC serviced Wellhead and choke manifold while waiting on CTU #3 to arrive on location. Expro serviced and UT critical iron connections. 7/4/2024 7/5/2024 LRS Coiled tubing unit #3 with 2-3/8" coil arrived on location. Spot in coil unit. Spot in LRS twin pumper. Spot choke skid. RU hardline from choke skid to return tanks. Held safety meeting with night shift crew to discuss the job, lift plan and the variance approved for working under a suspended load. Completed unit work permit. Continue to finish rigging up hardline to the well and final unit checks in preparations to pick up injector and BOP. Pick up BOPE and NU to top of tree. Expro completed testing ESD systems as per welltest checklist. 7/5/2024 7/6/2024 RU injector/lubricator/BOP onto well. PT all surface lines to 5,000psi. Pump 1.69" ball around coil. Held pre-job safety meeting with day crew to discuss job and lift plan. Perform push/pull test on coil with pipe/slip rams closed. Perform drawdown test on accumulator. Blind/shear test failed and determined that one of the blades was installed wrong and was damaged when functioned. Wait for replacement parts to come out of town. Replace and continue with testing. Drawdown, full body, blind/shear and pipe/slip BOP tests performed. 7/6/2024 7/7/2024 Perform push/pull test on coil. NU BOP's to Pump-in sub on tree. MU and pull test coil connector to 35K. MU 2.375" cleanout BHA with Tempress and test. Go to the well and MU lubricator to QTS and PT 350 psi low/4,500 high. Test coil checks. Open well and pump 65 bbls of 2% KCl at 0.8 bpm, did not exceed 2600 psi BHP. RIH and pull to surface to check counters are working. POOH and install fusible cap on SSV (accumulator bleeding off). RIH to 2250' ctmd and determine counters not matching. POOH to surface and then adjust K factor for electronic counter to match mechanical counter. RIH to 9500' ctmd with choke closed. 7/7/2024 7/8/2024 RIH and dry tag at 11,826' ctmd. Pick up to 10,650' and start cleanout to clean any residual fill in liner. Clean to 11,320' and chase to 3,000' for wiper trip. Clean to 12,000' ctmd and chase to 1,400' for wiper trip, getting heavy proppant returns to surface. RIH to 11,500'. Oil leak/drips from injector head discovered and decision made to POOH. Inspect injector head and see that chain oil was falling outside the sump and leaking outside the stripper sump box. Decision made to remove stripper from injector and seal. Remove the stripper from bottom of injector and clean/inspect all parts. Page 1 of 2 Flowback Ops Summary Report - AOGCC Start Date End Date Summary 7/8/2024 7/9/2024 Remove all the oil guards from injector and clean injector bottom pan. Clean stripper box assembly. Apply permatex oil resistant sealant to stripper box assembly and install into injector bottom pan. Apply sealant to top of joint to ensure good seal and let cure with heater. Re-install oil guards to injector. Rebuild standing iron at reel swivel. Inner Annulus pressure is tracking BHP and appears the OV is leaking. ND coil BOP's to allow slickline to RU. Spot slickline equipment and prep tools for morning runs. Shut down and wait on dayshift operations. 7/9/2024 7/10/2024 Replace OGLV. RDMO slickline. Coil operations on weather standby due to 20-30mph wind (unable to start crane/manlift operations). 7/10/2024 7/11/2024 Wait on wind. R/U and RIH to 12,000' and begin cleanout. RIH and dry tag at 13,219' ctmd. Pull up to 12,000' and begin pumping at 2.2bpm to start cleaning while RIH. Only able to maintain 60% return rate, increased pump rate to 2.4bpm with no change. Cleanout down to 13,165' where friction limited speed to 5-10fpm. Decision made to make short trip to 1,400' and sweep well. 7/11/2024 7/12/2024 RIH while cleaning out at 2.4 BPM at 2,600 psi from 13,165' to 13,265'. Wait for gel out of nozzle. Cleanout from 13,265' to 13,400'. Wait for gel at nozzle. Cleanout from 13,400' to 13,550'. Wait for gel at nozzle. Cleanout from 13,550' to 13,700'. Wait on gel at nozzle. Chase gel pill out of hole to surface at 75 fpm. Send gel sweep to exit nozzle at 10,000' and 3,000' while POH. Considerable sand to surface - come to surface to ensure clean. Perfom maintenance checks on coil and adjust crane/injector. RIH while circulating from 0.4-2.4bpm to 13,400' ctmd. Cleanout from 13,400' to 13,750'. Send gel pill. Continue cleaning but fighting lockup with coil. POOH to 12,000' to make another run. RIH to 13,658' ctmd. 7/12/2024 7/13/2024 RIH and cleanout to 14,250' 7/13/2024 7/14/2024 Cleanout to 14,993' ctmd. POH to surface while N2 lifting down IA. 7/14/2024 7/15/2024 Flow the well as per clean up procedure (with 500scf/min N2 down IA to GLV). Perform BOP test on coil unit and then standby in case more coil lift is needed. Install new CTC onto coil and test. Assemble BHA and tie back onto well. Blow 2-3/8 coil down with N2 to flowback tanks. RIH to 1,000' and begin circulating N2 down coil at 350scf/min while RIH to 10,000'. Heavy proppant returns seen at 114,000scf away. Continue to flow the well with coil in the hole (9,500-10,500' ctmd, 350-750scf/min N2 rate). 7/15/2024 7/16/2024 Continue to flow the well with coil in the hole (9,500-10,500' ctmd, 750scf/min N2 rate). Switched SLB N2 pump to HES N2 pump while reciprocating coil at 10,000ft and continue to pump N2 at 750scf/m. Reduce N2 rate to 500scf/m and POOH with coil. Shutdown N2 pumping with coil at 2500ft and POOH to surface with coil. Continue to flow the well as per clean up procedure with no N2 assist. 7/16/2024 7/17/2024 Continue to flow the well as per clean up procedure. 7/17/2024 7/18/2024 Monitor pressure build ups. Expro rigging down equipment, Clean up proceedure completed for this well. Page 2 of 2 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 10.0 gal F103 Surfactant 0.9 Gal/mGal 752.6 gal J450 Stabilizing Agent 0.6 Gal/mGal 458.9 gal J475 Breaker J475 5.8 lb/mGal 4,669.2 lbm J511 Stabilizing Agent 1.8 lb/mGal 1,425.0 lbm J532 Crosslinker 2.2 Gal/mGal 1,748.0 gal J580 Gel J580 26.8 lb/mGal 21,734.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 47.2 gal M002 Additive 0.0 lb/mGal 1.3 lbm M117 Clay Control Agent 342.9 lb/mGal 277,926.0 lbm M275 Bactericide 0.5 lb/mGal 365.2 lbm S522-1620 Propping Agent varied concentrations 2,102,320.0 lbm S522-4070 Propping Agent varied concentrations 44,800.0 lbm 73.15381 % 23.35175 % 2.93200 % 0.23578 % 0.09068 % 0.04815 % 0.04063 % 0.03923 % 0.03204 % 0.01550 % 0.01280 % 0.01280 % 0.01176 % 0.00965 % 0.00638 % 0.00199 % 0.00163 % 0.00102 % 0.00059 % 0.00040 % 0.00025 % 0.00025 % 0.00024 % 0.00020 % 0.00014 % 0.00009 % 0.00004 % 0.00004 % 0.00004 % 0.00004 % 0.00002 % 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 % Client: Oil Search Alaska Well: PIKKA NDBi-014 Basin/Field: Pikka Disclosure Type: Post-Job Well Completed: Date Prepared: 8/2/2024 State: Alaska County/Parish: North Slope Borough Case: YF125ST:WF125 810,618 gal Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Report ID: RPT-1930 Fluid Name & Volume Concentration Volume 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 50-70-4 Sorbitol 7647-14-5 Sodium chloride 102-71-6 2,2`,2"-nitrilotriethanol 7727-54-0 Diammonium peroxodisulphate 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 91053-39-3 Diatomaceous earth, calcined 111-76-2 2-butoxyethanol 67-63-0 Propan-2-ol 34398-01-1 Ethoxylated C11 Alcohol 10377-60-3 Magnesium nitrate 9002-84-0 poly(tetrafluoroethylene) 14807-96-6 Magnesium silicate hydrate (talc) 9025-56-3 Hemicellulase 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 9000-90-2 Amylase, alpha 14808-60-7 Quartz, Crystalline silica 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 63148-62-9 Dimethyl siloxanes and silicones 1310-73-2 Sodium hydroxide 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 14464-46-1 Cristobalite 127-08-2 Acetic acid, potassium salt (impurity) 1338-41-6 Sorbitan stearate 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9005-65-6 Sorbitan monooleate, ethoxylated 9004-32-4 Sodium carboxymethylcellulose 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 2634-33-5 1,2-benzisothiazolin-3-one Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 11138-66-2 Xanthan Gum 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 7632-00-0 Sodium nitrite # SLB-Private Page: 1 / 1 Updated 7/18/2024INPUT3-22-24 to 3-29-24AK TSCA Status50-103-20869-00-00Post810,61875.43451%9,247,276Trade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SME Tracerco Carrier Fluid Soy Methyl Ester 67784-80-9 100 0.0006715939 62.1041454000T-168B Tracerco Chemical Tracer 1,2-Dichloro-4-iodobenzene 20555-91-3 100 0.0000047682 0.4409240000T-168C Tracerco Chemical Tracer 1-Bromo-4-iodobenzene 589-87-7 100 0.0000047682 0.4409240000T-168A Tracerco Chemical Tracer 1-Chloro-4-iodobenzene 637-87-6 100 0.0000047682 0.4409240000T-729 Tracerco Chemical Tracer 1,4-Dibromo-2,5-dimethyl benzene 1074-24-4 100 0.0000238408 2.2046200000T-165B Tracerco Chemical Tracer 2-Iodobiphenyl 2113-51-1 100 0.0000047682 0.4409240000T-712 Tracerco Chemical Tracer 1,2,3-Trichlorobenzene 87-61-6 100 0.0000238408 2.2046200000T-748 Tracerco Chemical Tracer 1-Bromo-2-chlorobenzene 694-80-4 100 0.0000238408 2.2046200000T-776 Tracerco Chemical Tracer 1,4-Dibromonaphthalene 83-53-4 100 0.0000071522 0.6613860000T-169C Tracerco Chemical Tracer 2,4-Dibromomesitylene 6942-99-0 100 0.0000095363 0.8818480000Water Tracerco Carrier Fluid Water 7732-18-5 100 0.0006651569 61.5088980000T-912 Tracerco Chemical Tracer Sodium-2-chloro-5-fluorobenzoate 1382106-79-7 100 0.0000083443 0.7716170000T-158F Tracerco Chemical Tracer Sodium-2,3-Difluorobenzoate 1604819-08-0 100 0.0000083443 0.7716170000T-931TracercoChemical TracerSodium-4-fluoro-2-methylbenzoate1708942-23-71000.00000834430.7716170000T-257ATracercoChemical TracerSodium-3,5-di(Trifluoromethyl)benzoate87441-96-11000.00000834430.7716170000T-942TracercoChemical TracerSodium-2-chloro-5-methylbenzoate118537-88-51000.00000834430.7716170000T-929TracercoChemical TracerSodium-3-fluoro-2-methylbenzoate1708942-24-81000.00000834430.7716170000T-953TracercoChemical TracerSodium-3-fluoro-5-(Trifluoromethyl)-benzoate1535169-59-51000.00000834430.7716170000T-176ATracercoChemical TracerSodium-2,3,4-trifluorobenzoate402955-41-31000.00000834430.7716170000T-140CTracercoChemical TracerSodium-4-Fluorobenzoate499-90-11000.00000834430.7716170000Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)County:API Number:Operator Name: SantosWell Name and Number: NDBi-014Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco DisclaimerNotice 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 inputdata 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 affectingthem. 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 wellsaccordingly. Prices quoted are estimates only and are good for 30days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringementof patentsof Schlumberger or others isnotto beinferred. FracCAT Treatment Report Well :NDBi-014 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country :United States Preparedfor Client : Santos ClientRep : Scott Leahy Date Prepared :March 22, 2024 Preparedby Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure(AllZones) InitialWellheadPressure (psi) 860 InitialBHP atGauge (psi) 2,970 FinalSurface ISIP (psi) 2,247 Final ISIP at Gauge (psi) 3,138 SurfaceShutinPressure(psi) 1,139 BHShutin Pressure (psi) 2,826 MaximumTreating Pressure(psi) 7,414 BH Gauge at 10,168 ftMD, 4,363 ftTVD TreatmentTotals (All ZonesAs Per FracCAT) TotalSlurryPumped(Water+Adds+Proppant) (bbl)4,888.7 TotalProppantPumped(lb) 322,141 TotalYF125ST PastWellhead(bbl) 3,196.9 TotalProppantinFormation (lb) 322,141 TotalWF125PastWellhead (bbl) 1,266.9 TotalFreezeProtectPastWellhead (bbl) 67.7 ChemicalAdditives Mixed / Used PastWH ChemicalAdditives Mixed/ Used PastWH F103 (gal) 118 118 M275 (lb) 156 96 J450 (gal) 92 92 J753 (gal) 22 10 J580 (lb) 4,592 4,592 J475 (lb) 1,045 1,045 J532 (gal) 352 352 J134 (lb) 3 0 J511 (lb) 570 270 D206 (gal) 2 2 M002 (lb) 0.5 0.25 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Displacement PT Pump Check Stage 1 Stage 2 (attempt1) Summary On March22, 2024, SLBopenedToeSleeve and performed ahydraulicfracturingtreatment onStages 1and2(attempt1) ofNBDi- 014. The initial plan called for the completion of stages 1-4, on Stage 2 there was an issue with the hydraulic system on the POD Blender this led to suction loss on thepumps fromthePOD at stage6PPA, the decision alongwith Santos Company Rep was made to go on Flush and overflush the proppant tothe formation. Post shutdown pressuredecline was monitored for 60 min. Total of 322,141 pounds of proppant was pumped and 322,141 was placed into formation in 4,888.7 bbl of slurry. Please note, that proppant Volumes are adjusted per consumed BOLs. Stages 1 consisted of a PAD, and 8 proppant steps from 1-8 PPA followed by DFIT. Stage 2 consisted of a PAD, and 6 proppant steps from 1-10 PPA. Pump trips were staggered from 7,400 to 7,900 psi. The GORV was set to 8,300 psi. Summary of Stages 1-2(attempt 1) Material Actual Design Slurry Volume (bbl)4,889 8,901 Clean Fluid Volume(bbl)4,464 7,908 Proppant(lb)322,141 886,642 FracCAT*Santos NDBi-014 03-22-2024 Treating Pressure Annulus Pressure BH Pressure 50 15 9000 8000 14 45 13 40 12 7000 6000 11 35 10 30 9 5000 8 25 7 4000 20 6 5300015 4 2000 10 3 2 1000 5 1 0 0 0 12:17:35 12:50:55 13:24:15 13:57:35 14:30:55 15:04:15 15:37:35 16:10:55 16:44:15 Time - hh:mm:ss Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Toe Sleeve activation Open well Displacement PT Pump Check ToeSleeve Activation,Displacement PT and PumpCheck ToeSleeveactivationwassuccessful.Whenthewellwasopenedthepressurewas860psi.ToeSleevewasactivatedatthepressure 7415 psi at average Slurry Rate of 3.3 bbl/min followed by Displacement PT and hard shutdown with an ISIP of 870 psi. After 10 min shutdown Pump Check was pumped. In the end of pumping there was a hard shutdown with an ISIP of 1030 psi. A summary ofthe Stage below: Summary of Toe SleeveActivation, Displacement PT and Pump Check Total Slurry Pumped (bbl)390.1 Max pumping Rate (bpm)40.6 Average Treating Pressure (psi)4,302 Average Pumping Rate (bpm)32.4 Average Water Temperature (F)86.1 Maximum Treating Pressure (psi)7,415 Average Viscosity (cP)16.1 10000 FracCAT*Santos NDBi-014 stage Open Toe Sleve, Displacement PT, Pump Check 03-22-2024 Treating Pressure Annulus Pressure BH Pressure 45 10 9000 8000 40 9 8 35 7000 7 30 6000 6 25 5000 5 20 4000 4 15 3000 3 10 2000 2 1000 5 1 0 0 0 12:17:35 12:25:55 12:34:15 12:42:35 12:50:55 12:59:15 13:07:35 13:15:55 13:24:15 13:32:35 13:40:55 Time - hh:mm:ss Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displace PT 40.1 3.3 12.4 WF125 1683 -0.0 0.0 0 2 Shut Down 10min --------- 3 Pump Check 350 35.8 11.0 WF125 14701 -0.0 0.0 0 4 Shut Down 30min --------- Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 DisplacePT 3.3 3.6 1560 7415 631 2 Shut Down 10min ----- 3 PumpCheck 35.8 40.6 4625 6513 278 4 Shut Down 30min ----- Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates PCMsuction rate loss Collet/Ball#1 hitthe sleeve DropRatefor Ball/Collet#1 Drop Rate for Ball/Collet#2 Collet/Ball#2 hitthe sleeve Stage1 The treating pressure on PAD was around 3,380 psi before the Collet/Ball#1 hit the sleeve, then Treating pressure on PAD was around 3,200 psi. During the proppant staged treating pressure was gradually increasing from 2,900 to 4,500 psi. Suction was lost on the PCM at stage 2PPA, this led to decision to decrease pumping rate from 40 BPM to 29.5 BPM for 3 min, once suction rate was regained the rate was brought back to 40 BPM, and at stage 4PPA which led to decision to decrease of pumping rate from 40 BPM to 29.5 BPM for 2 min. Further slurry rate remained steady at 40 BPM until it was slowed for the Collet/Ball#2 to seat. After the Collet/Ball#2 shifted the sleeve DFIT was pumped followed by hard shutdown with an ISIP of 875 psi. Asummary ofthe Stageand its measured pump scheduleisbelow: FracCAT*Santos NDBi-014 stage 1 03-22-2024 Treating Pressure Annulus Pressure 6000 15 14 40 13 5000 12 11 4000 30 10 9 8 3000 7 20 6 2000 5 4 10 3 1000 2 1 0 0 0 13:38:51 13:55:31 14:12:11 14:28:51 14:45:31 15:02:11 15:18:51 15:35:31 Time - hh:mm:ss Summary of PressuresWhen Collet Seats Collet#1 BeforeCollet Hit (psi)Collet Hit (psi)AfterCollet (psi) WellheadPressure 1,898 3,098 2,512 BottomholePressure 3,163 4,246 3,788 Summary of Stage 1 TotalProppant Pumped(lb)217,426 Max pumping Rate (bpm)41.2 Total Proppant in Formation (lb)217,426 Average Pumping Rate (bpm)37.4 Total Slurry Pumped (bbl)2,391.5 Maximum Treating Pressure (psi)4,577 YF125STPumped(bbl)1,627.3 Average Treating Pressure (psi)3,347 WF125 Pumped (bbl)538.6 Average Water Temperature (F)95.1 AverageViscosity (cP)16.8 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step #StepName Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Line out XL 45.7 18.4 3.1 YF125ST 1921 0 0 0 2 Drop Collet#1 3 20.8 0.1 YF125ST 126 0 0 0 3 PAD st1 200 36.5 5.7 YF125ST 8394 0 0 0 4 Slow For Seat 50.2 19.1 2.7 YF125ST 2108 0 0 0 5 Resume Pad 96.6 33.9 3 YF125ST 4053 0 0 0 6 1.0 PPA 160 38.7 4.2 YF125ST 6456 CarboLite16/20 1.1 0.9 6162 7 2.0 PPA 180 35 5.2 YF125ST 6956 CarboLite16/20 2 1.9 13722 8 3.0 PPA 190 39.9 4.8 YF125ST 7057 CarboLite16/20 3.2 3 21281 9 4.0 PPA 190 38.2 5 YF125ST 6789 CarboLite16/20 4.1 3.9 27219 10 5.0 PPA 190 39.9 4.8 YF125ST 6543 CarboLite16/20 5.1 5 32989 11 6.0 PPA 190 39.9 4.8 YF125ST 6318 CarboLite16/20 6.1 5.9 38155 12 7.0 PPA 170 40 4.2 YF125ST 5460 CarboLite16/20 7.1 7 38572 13 8.0 PPA 161.1 40 4 YF125ST 5063 CarboLite16/20 8.2 7.7 39310 14 Clean lines & Spacer 23.2 41 0.6 YF125ST 977 CarboLite16/20 0.7 0 16 15 Drop Collet#2 3 40.6 0.1 YF125ST 126 0 0 0 16 DFIT 190.8 40.1 4.8 WF125 8015 0 0 0 17 Slow For Seat 50.4 20.9 2.6 WF125 2115 0 0 0 18 Resume DFIT 297.5 38.9 7.8 WF125 12490 0 0 0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 Line out XL 18.4 21.5 2085 2256 278 2 Drop Collet#1 20.8 20.9 2258 2370 2146 3 PAD st1 36.5 40.3 3255 3757 1926 4 Slow For Seat 19.1 37.0 2097 2952 1382 5 ResumePad 33.9 40.1 3051 3345 2379 6 1.0 PPA 38.7 40.4 3085 3345 2397 7 2.0 PPA 35.0 40.2 2673 3025 2260 8 3.0 PPA 39.9 40.2 3111 3208 2343 9 4.0 PPA 38.2 40.2 3027 3382 2334 10 5.0 PPA 39.9 40.4 3651 3867 3387 11 6.0 PPA 39.9 40.3 4072 4243 3872 12 7.0 PPA 40.0 40.3 4228 4252 4188 13 8.0 PPA 40.0 40.7 4322 4458 4188 14 Clean lines & Spacer 41.0 41.2 4483 4545 4307 15 Drop Collet#2 40.6 40.6 4309 4317 4307 16 DFIT 40.1 40.6 3897 4577 3162 17 Slow For Seat 20.9 39.7 2023 3158 1473 18 Resume DFIT 38.9 40.4 2913 3094 214 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Hydraulicsystem issue on POD Blender Loss suction on the Pumps fromBlender Overflushing Stage2 (attempt 1) The average treating pressure on PAD was 2,880 psi before the hydraulic system issue on the Road side of the POD Blender at stage 1PPA, this led to decision of cutting sand and try to fix the issue, once the issue was fixed, waited when proppant reach the formation and then started 1PPA again. Duringtheproppantstages treatingpressurewasgradually increasing from2,700 to 3,280 psi. Once the 6PPA stage started, the POD Road hydraulic pressure decreased and pumps lost suction pressure, proppant was cut. The attempt to return suction to pump was made and then continued with overflushing proppant into the formation. Asummary ofthe Stageand its measured pump scheduleisbelow: 5000 FracCAT*Santos NDBi-014 stage 2 03-22-2024 Treating Pressure Annulus Pressure BH Pressure 15 45 14 40 13 4000 12 35 11 30 10 3000 9 25 8 7 20 2000 6 15 5 4 10 1000 3 2 5 1 0 0 0 15:38:51 15:48:51 15:58:51 16:08:51 16:18:51 16:28:51 16:38:51 16:48:51 16:58:51 Time - hh:mm:ss Summary of Pressures When Collet Seats Collet #2 BeforeCollet Hit (psi)Collet Hit (psi)AfterCollet (psi) WellheadPressure 1,981 2,668 1,880 BottomholePressure 3,288 3,915 3,210 Summary of Stage 2 (attempt 1) TotalProppant Pumped(lb)104,715 Max pumping Rate (bpm)45.0 Total Proppant in Formation (lb)104,715 Average Pumping Rate (bpm)36.0 Total Slurry Pumped (bbl)2,107.1 Maximum Treating Pressure (psi)3,382 YF125STPumped(bbl)1,569.5 Average Treating Pressure (psi)2,679 WF125 Pumped(bbl)338.2 Average Water Temperature (F)100.7 AverageViscosity (cP)18.3 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st2 40 21.1 2.5 YF125ST 1666 0 0 0 2 Resume PAD 325 38.8 8.5 YF125ST 13638 0 0 0 3 1.0 PPA 144 37.5 3.9 YF125ST 5821 CarboLite16/20 1.1 0.9 5335 4 Crosslink ed gel 131.6 34.7 3.8 YF125ST 5523 CarboLite16/20 0.2 0 6 5 1.0 PPA 180 39.9 4.5 YF125ST 7256 CarboLite16/20 1 0.9 6943 6 2.0 PPA 220 40 5.5 YF125ST 8500 CarboLite16/20 2 2 16968 7 4.0 PPA 240 40 6 YF125ST 8587 CarboLite16/20 4.1 3.9 34233 8 6.0 PPA 207.4 39.5 5.2 YF125ST 6937 CarboLite16/20 7.5 5.8 40761 9 Clean lines & Flush 190.3 29.3 9.7 YF125ST 7993 CarboLite16/20 2.8 0 469 10 Overflush withWF 338.1 25.2 10.2 WF125 14205 0 0 0.0 11 Freeze Protect 90.7 22.5 4.2 FreezeProtect 3810 0 0 0.0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 PAD st2 21.1 23.3 2034 2292 214 2 ResumePAD 38.8 40.2 2887 3382 2178 3 1.0 PPA 37.5 40.0 2496 2686 2032 4 Crosslinkedgel 34.7 40.1 2339 2782 2077 5 1.0 PPA 39.9 40.3 2735 2796 2691 6 2.0 PPA 40.0 40.3 2765 2828 2695 7 4.0 PPA 40.0 40.4 2900 2970 2828 8 6.0 PPA 39.5 44.2 3032 3281 4 9 Clean lines & Flush 29.3 45.0 2448 2933 27 10 Overflush with WF 29.3 29.5 2319 2640 1175 11 FreezeProtect 22.5 29.4 1904 2238 855 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates ToeSleeveActivation JobMessages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 12:11:37 Radio check 1510 3167 0.0 0.0 0.0 2 12:12:20 Finishedsafety meeting 1514 3162 0.0 0.0 0.0 3 12:12:34 Finishedsafety meeting 1514 3162 0.0 0.0 0.0 4 12:23:40 Getting boost to pumps 1542 3116 0.0 0.0 0.0 5 12:24:30 Openwellhead 1304 3116 0.0 0.0 0.0 6 12:25:51 Start Displace PT Automatically 869 3112 0.0 0.0 0.0 7 12:25:51 Start Propped Frac Automatically 869 3112 0.0 0.0 0.0 8 12:25:51 Start DF1 Automatically 869 3112 0.0 0.0 0.0 9 12:26:36 Started Pumping 864 3107 0.0 0.0 0.0 10 12:43:48 Shut Down10min Automatically 1111 3139 40.1 3.5 0.0 11 12:43:49 Start Pump Check Automatically 1043 3135 40.2 3.5 0.0 12 12:43:54 Shut Down30min Manually 1139 3135 40.3 0.0 0.0 13 12:43:56 StoppedPumping 1185 3116 40.3 0.0 0.0 14 12:58:35 Started Pumping 558 3144 40.3 0.0 0.0 15 12:59:04 Start Pump Check Automatically 828 3158 40.3 1.7 0.0 16 12:59:07 Start Pump Check Manually 919 3158 40.5 2.9 0.0 17 13:06:30 Stage at Perfs: Displace PT 4362 3341 257.3 39.9 0.0 18 13:07:31 Stage at Perfs: Pump Check 3931 3350 297.9 39.9 0.0 19 13:09:56 StoppedPumping 992 3332 390.1 0.2 0.0 Stage1 Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 13:41:48 Radio Check 301 2897 390.1 0.0 0.0 2 13:45:08 Started Pumping 278 2856 390.1 0.0 0.0 3 13:45:08 Start Line out XL Manually 278 2856 390.1 0.0 0.0 4 13:45:08 Start Stage1 Automatically 278 2856 390.1 0.0 0.0 5 13:48:21 Start Drop Collet#1 Manually 2274 2892 46.1 20.8 0.0 6 13:48:30 Start PAD st1 Automatically 2361 2897 49.2 20.7 0.0 7 13:54:11 Start Slow For Seat Automatically 1162 3332 249.1 29.0 0.0 8 13:55:51 Ball & Collet Seated 2617 3382 280.0 18.0 0.0 9 13:56:54 Stage at Perfs: Pump Check 2393 3364 298.9 18.0 0.0 10 13:56:55 Start Resume Pad Automatically 2384 3359 299.2 17.9 0.0 11 13:57:05 Stage at Perfs: Pump Check 2398 3364 302.2 18.0 0.0 12 13:59:53 Start 1.0 PPA Manually 3258 3400 396.0 39.9 0.0 13 13:59:53 StartedPumping Prop 3258 3400 396.0 39.9 0.0 14 14:02:34 Stage at Perfs: Line out XL 3190 3437 502.6 39.7 1.0 15 14:03:56 Stage at Perfs: Drop Collet#1 2421 3419 552.5 34.3 1.0 16 14:04:03 Start 2.0 PPA Automatically 2306 3414 556.3 32.5 1.0 17 14:07:06 Stage at Perfs: PAD st1 2997 3428 649.2 38.0 1.9 18 14:09:17 Start 3.0 PPA Automatically 3025 3455 736.5 40.1 2.0 19 14:11:06 Stage at Perfs: Slow For Seat 3144 3469 809.4 39.8 3.0 20 14:14:03 Start 4.0 PPA Automatically 2329 3441 926.3 33.7 3.2 21 14:15:52 Stage at Perfs: Resume Pad 3075 3460 989.6 39.3 3.8 22 14:19:02 Start 5.0 PPA Automatically 3396 3460 1116.0 40.0 4.0 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 23 14:20:37 Stage at Perfs: 1.0 PPA 3606 3464 1179.3 39.9 5.1 24 14:23:48 Start 6.0 PPA Automatically 3876 3492 1306.2 39.9 5.0 25 14:25:23 Stage at Perfs: 2.0 PPA 4069 3519 1369.1 40.4 5.9 26 14:28:34 Start 7.0 PPA Automatically 4243 3542 1496.2 40.2 6.0 27 14:30:08 Stage at Perfs: 3.0 PPA 4243 3551 1559.1 40.3 7.0 28 14:32:49 Start 8.0 PPA Automatically 4215 3551 1666.3 40.0 7.0 29 14:34:54 Stage at Perfs: 4.0 PPA 4330 3547 1749.6 39.7 8.1 30 14:36:50 Start Clean lines & Spacer Manually 4490 3542 1827.0 40.8 0.2 31 14:37:24 Start Drop Collet#2 Manually 4302 3542 1850.2 40.6 -0.1 32 14:37:29 Start DFIT Automatically 4444 3547 1853.6 40.5 -0.1 33 14:38:25 StoppedPumping Prop 4215 3547 1891.1 40.4 -0.1 34 14:39:07 Stage at Perfs: 5.0 PPA 4064 3547 1919.2 40.1 0.0 35 14:42:14 Start Slow For Seat Manually 2100 3506 2043.9 39.4 0.0 36 14:44:04 Stage at Perfs: 6.0 PPA 1610 3373 2079.5 17.9 0.0 37 14:44:11 Ball & Collet Seated 2668 3510 2081.6 17.9 0.0 38 14:44:53 Start ResumeDFIT Automatically 1867 3464 2094.2 18.0 0.0 39 14:45:19 Stage at Perfs: 7.0 PPA 2338 3487 2102.8 29.4 0.0 40 14:45:26 Stage at Perfs: 8.0 PPA 2398 3460 2106.5 32.7 0.0 41 14:50:17 Stage at Perfs: Clean lines & Spacer 3062 3446 2297.2 40.0 0.0 42 14:51:32 Stage at Perfs: Drop Collet#2 2997 3437 2347.1 40.0 0.0 43 14:52:39 StoppedPumping -10 3318 2391.5 31.4 0.0 44 14:53:32 Shutdown for 45 min 873 3341 2391.5 0.0 0.0 Stage2 (attempt 1) Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 15:39:10 Radio check 228 2718 2391.5 0.0 0.0 2 15:42:27 Started Pumping 214 2700 2391.5 0.0 0.0 3 15:42:32 Start PAD st2 Manually 214 2700 2391.5 0.0 0.0 4 15:42:32 Start Propped Frac Manually 214 2700 2391.5 0.0 0.0 5 15:42:32 Start Stage2 Automatically 214 2700 2391.5 0.0 0.0 6 15:45:23 Start Resume PAD Automatically 2178 2759 40.2 22.8 0.0 7 15:51:04 Stage at Perfs: Slow For Seat 2691 2897 253.7 40.0 0.0 8 15:51:51 Stage at Perfs: Resume DFIT 2718 2920 285.1 40.1 0.0 9 15:53:51 Start 1.0 PPA Automatically 2686 2942 365.2 40.0 0.0 10 15:53:51 StartedPumping Prop 2686 2942 365.2 40.0 0.0 11 15:57:43 Start Resume PAD Manually 2086 2938 509.0 31.5 0.1 12 15:57:50 StoppedPumping Prop 2119 2942 512.7 31.7 0.0 13 16:00:45 Stage at Perfs: PAD st2 2718 2975 610.0 39.4 0.0 14 16:01:31 Start 1.0 PPA Manually 2787 2979 640.6 40.1 0.0 15 16:01:37 StartedPumping Prop 2796 2979 644.6 40.1 0.0 16 16:04:22 Stage at Perfs: Resume DFIT 2709 3029 754.1 40.4 1.0 17 16:06:02 Start 2.0 PPA Automatically 2700 3066 820.7 39.9 1.0 18 16:07:39 Stage at Perfs: PAD st2 2746 3414 885.3 40.0 2.0 19 16:11:32 Start 4.0 PPA Automatically 2828 3464 1040.7 39.9 2.0 20 16:12:10 Stage at Perfs: Resume PAD 2888 3478 1065.8 39.7 4.1 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 21 16:17:33 Start 6.0 PPA Automatically 2979 3524 1281.2 40.3 4.0 22 16:17:39 Stage at Perfs: 1.0 PPA 2988 3524 1285.2 40.2 4.0 23 16:22:47 Start Clean lines & flush Manually 2416 3570 1488.0 45.0 1.7 24 16:23:05 Cut Prop 27 3432 1500.9 24.1 -0.5 25 16:23:12 StoppedPumping Prop 585 3560 1502.3 6.4 0.1 26 16:26:58 Stage at Perfs: Resume PAD 2393 3533 1526.0 23.5 0.0 27 16:32:10 Overflushing the well with WF 2640 3565 1678.3 29.5 0.0 28 16:43:38 Freezeprotect 1372 3382 29.4 0.0 29 16:47:51 StoppedPumping 1143 3327 0.0 0.0 30 16:56:26 Well Shut in 31 17:15:10 Fanningand blowing out pumps FracCAT Treatment Report Well : NDBi-014 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country : United States Prepared for Client : Santos Client Rep : Scott Leahy Date Prepared : March 25, 2024 Prepared by Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure (All Zones) Initial Wellhead Pressure (psi) 302 Initial BHP at Gauge (psi) 2,015 Final Surface ISIP (psi) 933 Final ISIP at Gauge (psi) 2,930 Surface Shut in Pressure(psi) 4,463 BH Shut in Pressure (psi) 4,643 Maximum Treating Pressure (psi) 6,560 BH Gauge at 10,168 ft MD, 4,363 ft TVD Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 8,411.0 Total Proppant Pumped (lb) 884,213 Total YF125ST Past Wellhead (bbl) 6,594.7 Total Proppant in Formation (lb) 884,213 Total WF125 Past Wellhead (bbl) 900.0 Total Freeze Protect Past Wellhead (bbl) (pumped by LR)50.0 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 328 326.6 M275 (lb) 156 155.7 J450 (gal) 157 156.9 J753 (gal) 18 17.97 J580 (lb) 8,545 8,521 J475 (lb) 1,815 1,809.2 J532 (gal) 692 692 J134 (lb) - - J511 (lb) 580 580 D206 (gal) 4 4 M002 0.5 0.5 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-014 Formation: Nanushuk District: Pikka Country: United States Summary On March 25, 2024, SLB successfully performed a hydraulic fracturing treatment on Stages 2-5 of NDBi-014. According to the initial plan called for the completion of stages 2-5, there was change of Max Proppant concentration on stage 3, it decreased from 10PPA to 9PPA, were few times extending prop steps on Stages 4 and 5 unless the previous proppant concentration would hit the formation, for Stage 5 the step 1PPA was extended to around 70bbl, and step 2PPA was extended to around 20bbl. In addition, step Freeze Protect was pumped by LR instead of SLB by Santos decision. There were some issues with the SuperPOD in the beginning of stage 2, once the issues were fixed, SLB moved to pump Stage 2-3- 4-5. Also, there were found some plastic bag pieces which caused the proppant concentration spikes on stage 4. The Ball/Collet#6 was seated successfullyfollowed by PCM Overflush and Hard shutdown.Postshutdownpressure decline wasmonitored for 45min. Total of 884,213 pounds of proppant was pumped and 884,213 was placed into formation in 8,411.0bbl of slurry. Please note, that proppant Volumes are adjusted per consumed BOL. Stage 2, 4 and 5 consisted of a PAD, and 6 proppant steps from 1-10 PPA, Stage 3 consisted of a PAD, and 6 proppant steps from 1-9 PPA. Pump trips were staggered from 7,400 to 8,000 psi. The GORV was set to 8,300 psi. Summary of Stages 2-5 Material Actual Design Slurry Volume (bbl)8,411 7,571 Clean Fluid Volume(bbl) 7,495 6,568 Proppant (lb) 884,213 896,227 11:50:11 12:23:31 12:56:51 13:30:11 14:03:31 14:36:51 15:10:11 15:43:31 16:16:51 16:50:11 17:23:31 17:56:51 18:30:11 19:03:31 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 20 22 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT*Santos NDBi-014 03-25-2024 Stage2 Stage3 Stage5Stage4Displ PT Ball to Seat Pump Check Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Displacement PT, Ball to Seat and Pump Check. Stage included PT displacement, pumping Ball#2 to seat and pump check that was placed in the schedule to test the equipment and ensure the pumps were job ready. During Pump Check/PAD St2 (attempt 1) there was the issue with the Curb side of the Blender, the fluid was not moving through Curb side, the decision was to shut down and resolve the issue. Once the issue was resolved, the pump check step was started again and then moved to stage2. A summary of the stage and pressures as follows: Summary of Stage Displacement PT, Ball to Seat and Pump Check Total Proppant Pumped (lb)0 Max pumping Rate (bpm)40.1 Total Proppant in Formation (lb)0 Average Pumping Rate (bpm)19.8 Total Slurry Pumped (bbl)526.3 Maximum Treating Pressure (psi)3,346 YF125ST Pumped (bbl)206.2 Average Treating Pressure (psi)1,878 WF125 Pumped (bbl)320.1 Average Water Temperature (F)84.6 Average Viscosity (cP)17.7 11:50:11 12:06:51 12:23:31 12:40:11 12:56:51 13:13:31 13:30:11 13:46:51 14:03:31 14:20:11 14:36:51 14:53:31 15:10:11 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 16 18 20 22 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT*Santos NDBi-014 Displacement PT, Ball to Seat and Pump Check 03-25-2024 PT Displacement Pumping Ball to Seat Pump Check Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displace PT 40.6 3.4 12.3 WF125 1706 0 0 0 2 Ball to Seat 220 4 55.1 WF125 9239 0 0 0 3 Pump Check 7.3 4 1.8 WF125 308 0 0 0 4 Pump Check 52.2 24.9 2 WF125 2191 0 0 0 5 Pump Check / PAD st2 (attempt 1) 206.2 36.5 5.9 YF125ST 8659 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Displace PT 3.4 3.6 688 737 298 2 Ball to Seat 4.0 4.2 790 943 558 3 Pump Check 4.0 4.7 948 1346 929 4, 5 Pump Check + PAD st2 (attempt1)36.5 40.1 3033 3346 526 Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Stage 2 (attempt 2) Once the issue with the Curb side of the SuperPOD was resolve, started function testing the Curb side by pumping downhole 3.7 BPM. As soon as it was confirmed that Curb side is functioning correctly then moved to pumping PAD step but encountered the issue of chemical check valve and couldnt get the crosslinker to the blender. Santos representative asked to slow the rate until the issue will be resolved. After the issue was resolved, restarted the PAD step and continued pumping stage 2. The treating pressure on PAD was around 3,200 psi and slowly fell down to about 2,900 psi when 1PPA was going into the formation. At this point, the treating pressure was gradually increasing from 2,900 to 6,590 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#3 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #2 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,981 2,668 1,880 Bottomhole Pressure 3,288 3,915 3,210 Summary of Stage 2 Total Proppant Pumped (lb) 197,986 Max pumping Rate (bpm) 43.0 Total Proppant in Formation (lb) 197,986 Average Pumping Rate (bpm)38.4 Total Slurry Pumped (bbl) 2,077 Maximum Treating Pressure (psi) 6,353 YF125ST Pumped (bbl) 1,771 Average Treating Pressure (psi)3,585 WF125 Pumped (bbl) 100.6 Average Water Temperature (F)83.2 Average Viscosity (cP)18.7 15:20:11 15:26:51 15:33:31 15:40:11 15:46:51 15:53:31 16:00:11 16:06:51 16:13:31 16:20:11 16:26:51 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 16 18 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT*Santos NDBi-014 Stage1 03-25-2024 Collet/Ball#3 hit the sleeve Drop Rate for Ball/Collet#3Road gate sticking Glitch Function testing Curb side Slow rate to resolve the issue with chemical check valve Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st2 (attempt 1) 350 33.5 16.7 YF125ST 14706 0 0 0 2 Blender check 5.9 36.6 0.2 WF125 246 0 0 0 3 Blender check 94.7 36.1 2.8 WF125 3979 0 0 0 4 PAD st2 350 39 9 YF125ST 14687 0 0 0 5 1.0 PPA 180 39.9 4.5 YF125ST 7342 CarboLite 16/20 1.1 0.7 5010 6 2.0 PPA 220 39.8 5.5 YF125ST 8599 CarboLite 16/20 2.5 1.7 14697 7 4.0 PPA 240 39.7 6 YF125ST 8602 CarboLite 16/20 4.2 3.9 33912 8 6.0 PPA 240 39.5 6.1 YF125ST 7990 CarboLite 16/20 6.1 5.9 47954 9 8.0 PPA 240 39.4 6.1 YF125ST 7463 CarboLite 16/20 8.2 7.9 60145 10 10.0 PPA 129.3 39.6 3.3 YF125ST 3858 CarboLite 16/20 10.3 9.3 36255 11 Clean lines & Spacer 24.1 42.2 0.6 YF125ST 1009 CarboLite 16/20 0.6 0 13 12 Drop Collet#3 3 43 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st2 (attempt1) 33.5 40.5 2846 3154 700 2 Blender check 35.8 36.2 3126 3149 3090 3 Blender check 36.1 39.9 2864 3213 1950 4 PAD st2 39.0 40.4 3203 3488 2014 5 1.0 PPA 39.9 40.2 3074 3159 2971 6 2.0 PPA 39.8 40.1 2945 2980 2907 7 4.0 PPA 39.7 40.0 3104 3346 2939 8 6.0 PPA 39.5 40.0 3881 4596 3346 9 8.0 PPA 39.4 40.0 5163 5772 4564 10 10.0 PPA 39.6 40.4 5845 6061 5676 11 Clean line & Spacer 42.2 43.0 6249 6335 6061 12 Drop Collet#3 43.0 43.0 6308 6353 6258 Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Stage 3 When the Collet/Ball#3 was expected to hit the sleeve, there was no very clear indication of it and no confirmation from Completion rep. this led to decision to pump some volume and shutdown, wait for some time and start pumping at low rate around 20 BPM to see if there will be clearer sign of indication. Eventually, when didnt get any clearer sign of pressure decided stage over to Resume PAD step. Treating pressure on PAD was around 3,750 psi and slowly fell to about 2,900 psi when 1PPA was going into the formation. When 4 PPA started going into the formation the treating pressure was gradually increasing from 3,100 to 4,800 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#4 to seat. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #3 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 1,858 5,072 4,994 Bottomhole Pressure 2,793 6,284 6,310 Summary of Stage 3 Total Proppant Pumped (lb) 228,302 Max pumping Rate (bpm) 43.0 Total Proppant in Formation (lb) 228,302 Average Pumping Rate (bpm) 38.6 Total Slurry Pumped (bbl) 1,845.7 Maximum Treating Pressure (psi) 6,560 YF125ST Pumped (bbl) 1,608.9 Average Treating Pressure (psi) 3,777 WF125 Pumped (bbl) 0 Average Water Temperature (F) 83.9 Average Viscosity (cP) 19.1 16:30:11 16:35:11 16:40:11 16:45:11 16:50:11 16:55:11 17:00:11 17:05:11 17:10:11 17:15:11 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT*Santos NDBi-014 Stage2 03-25-2024 Drop Rate for Ball/Collet#4 Collet/Ball#4 hit the sleeve Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st3 183 40.6 4.5 YF125ST 7690 0 0 0 2 Slow For Seat 101.3 20.1 5.3 YF125ST 4256 0 0 0 3 Resume PAD 98.7 33.6 3 YF125ST 4131 0 0 0 4 1.0 PPA 253.1 40 6.3 YF125ST 10204 CarboLite 16/20 1 0.9 9787 5 2.0 PPA 220 39.9 5.5 YF125ST 8548 CarboLite 16/20 2.3 1.8 15854 6 4.0 PPA 260.7 40 6.5 YF125ST 9346 CarboLite 16/20 4.3 3.9 36808 7 6.0 PPA 252.8 39.9 6.3 YF125ST 8408 CarboLite 16/20 6.3 5.9 50760 8 8.0 PPA 275.3 39.9 6.3 YF125ST 8530 CarboLite 16/20 8.7 8.2 69093 9 9.0 PPA 173.4 39.9 5.0 YF125ST 5311 CarboLite 16/20 9.4 8.2 45988 10 Clean lines & Spacer 24.4 40.7 0.6 YF125ST 1024 CarboLite 16/20 1 0 12 11 Drop Collet#4 3 39.8 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st3 40.6 43.0 4798 6560 2902 2 Slow For Seat 20.1 39.9 3829 5196 1680 3 Resume PAD 33.6 40.1 4066 4907 3223 4 1.0 PPA 40.0 40.6 3367 3781 3127 5 2.0 PPA 39.9 40.1 2999 3113 2921 6 4.0 PPA 40.0 40.2 3047 3131 3003 7 6.0 PPA 39.9 40.4 3408 3786 3113 8 8.0 PPA 39.9 40.6 4480 4719 3777 9 9.0 PPA 39.9 40.5 4690 4820 4669 10 Clean lines & Spacer 40.7 41.1 4675 4797 4367 11 Drop Collet#4 39.8 39.9 4370 4381 4367 Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Stage 4 Once the Collet/Ball#4 hit the sleeve the pressure transition from Stage 3 to 4 was typical. Treating pressure on PAD was around 3,570 psi and stayed stable until 4PPA was going into formation, then treating pressure was gradually increasing from 3,330 to 4,450 psi. When 8PPA hit the formation, pressure slightly went down by 200psi.Slurry rate remained steady at 40BPM until it was slowed for the Collet/Ball#5 to seat. While pumping stage 4 the crew encounter the issue of POD Blender gate blockage caused by plastic bag pieces, once the plastic bag pieces were removed it resulted in proppant concentration spikes. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #4 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,060 2,298 2,266 Bottomhole Pressure 3,230 3,181 3,381 Summary of Stage 4 Total Proppant Pumped (lb) 228,275 Max pumping Rate (bpm) 40.9 Total Proppant in Formation (lb) 228,275 Average Pumping Rate (bpm) 39.3 Total Slurry Pumped (bbl) 1,695.2 Maximum Treating Pressure (psi) 4,948 YF125ST Pumped (bbl) 1,458.6 Average Treating Pressure (psi) 3,704 WF125 Pumped (bbl) 0 Average Water Temperature (F) 84.9 Average Viscosity (cP) 18.9 17:16:15 17:22:55 17:29:35 17:36:15 17:42:55 17:49:35 17:56:15 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 0 10 20 30 40 50 0 2 4 6 8 10 12 14 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT*Santos NDBi-014 Stage4 03-25-2024 Collet/Ball#4 hit the sleeve.Drop Rate for Ball/Collet#5 Collet/Ball#5 hit the sleeve. Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st4 176 40 4.4 YF125ST 7395 0 0 0 2 Slow For Seat 45.3 20.9 2.3 YF125ST 1914 0 0 0 3 Resume PAD 100.8 37.6 2.7 YF125ST 4219 0 0 0 4 1.0 PPA 180 39.9 4.5 YF125ST 7284 CarboLite 16/20 1.2 0.9 6312 5 2.0 PPA 220 39.9 5.5 YF125ST 8497 CarboLite 16/20 2.1 2 17037 6 4.0 PPA 240 40 6 YF125ST 8615 CarboLite 16/20 4.2 3.8 33584 7 6.0 PPA 240 40 6 YF125ST 8024 CarboLite 16/20 7.9 5.8 47163 8 8.0 PPA 225.3 39.8 5.7 YF125ST 7026 CarboLite 16/20 8.1 7.8 56004 9 10.0 PPA 240 40 6 YF125ST 7120 CarboLite 16/20 11.8 9.5 68163 10 Clean lines & Spacer 24.8 40.3 0.6 YF125ST 1041 CarboLite 16/20 5.6 0 12 11 Drop Collet#5 3 40.2 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st4 40.0 40.2 3923 4948 2399 2 Slow For Seat 20.9 39.2 2116 2298 1653 3 Resume PAD 37.6 40.4 3489 3612 2522 4 1.0 PPA 39.9 40.2 3548 3598 3513 5 2.0 PPA 39.9 40.2 3397 3548 3282 6 4.0 PPA 40.0 40.2 3327 3355 3296 7 6.0 PPA 40.0 40.4 3460 3807 3337 8 8.0 PPA 39.8 40.1 4264 4445 3813 9 10.0 PPA 40.0 40.9 4382 4477 4285 10 Clean lines & Spacer 40.3 40.9 4198 4445 4051 11 Drop Collet#5 40.2 40.2 4051 4051 4051 Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Stage 5 Once the Collet/Ball#5 hit the sleeve the pressure transition from Stage 4 to 5 was typical. Treating pressure on PAD was around 3,850 psi and slowly fell to about 3,310 psi after 1PPA passed through the frac port. When 4 PPA started going into the formation the treating pressure was gradually increasing from 3,400 to 5,900 psi. The Collet/Ball#6 was launched, successfully seated, and followed by a Flush, PCM Overflush and hard shutdown with an ISIP of 933 psi and recording of pressure decline for 45 mins. The pump was jacking off on the PAD step, this led to Rate drop because of some foreign objects got to the pumps. A summary of the Stage and its measured pump schedule is below: Summary of Pressures When Collet Seats Collet #5 Before Collet Hit (psi)Collet Hit (psi)After Collet (psi) Wellhead Pressure 2,229 2,596 2,563 Bottomhole Pressure 3,352 3,673 3,662 Summary of Stage 5 Total Proppant Pumped (lb) 229,650 Max pumping Rate (bpm) 41.5 Total Proppant in Formation (lb) 229,650 Average Pumping Rate (bpm) 38.7 Total Slurry Pumped (bbl) 2,266.8 Maximum Treating Pressure (psi) 5,914 YF125ST Pumped (bbl) 1550.0 Average Treating Pressure (psi) 4,189 WF125 Pumped (bbl) 479.3 Average Water Temperature (F) 85.7 Average Viscosity (cP) 19.2 17:59:15 18:05:55 18:12:35 18:19:15 18:25:55 18:32:35 18:39:15 18:45:55 18:52:35 18:59:15 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 14 Treating Pressure Annulus Pressure BH Pressure Slurry Rate Prop Conc BH Prop Con FracCAT*Santos NDBi-014 Stage 5 03-25-2024 Collet/Ball#6 hit the sleeve. Drop Rate for Ball/Collet#6 Pump was jacking off Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States As Measured Pump Schedule Step #Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st5 167 40.1 4.2 YF125ST 7015 0 0 0 2 Slow For Seat 44.3 21.3 2.3 YF125ST 1864 0 0 0 3 Resume PAD 116 37.1 3.2 YF125ST 4871 0 0 0 4 1.0 PPA 238.6 39.4 6.1 YF125ST 9625 CarboLite 16/20 1 0.9 9035 5 2.0 PPA 239.8 39.9 6 YF125ST 9284 CarboLite 16/20 2 1.9 18103 6 4.0 PPA 240 39.9 6 YF125ST 8648 CarboLite 16/20 4.1 3.7 32841 7 6.0 PPA 240 39.8 6 YF125ST 7990 CarboLite 16/20 6.4 5.9 47960 8 8.0 PPA 240 39.7 6 YF125ST 7497 CarboLite 16/20 8.2 7.8 59369 9 10.0 PPA 218.7 39.9 5.5 YF125ST 6480 CarboLite 16/20 10.5 9.5 62307 10 Clean lines & Spacer 29.5 40.4 0.7 YF125ST 1240 CarboLite 16/20 3.3 0 35 11 Drop Collet#6 3 39.7 0.1 YF125ST 126 0 0 0 12 XL Flush 11 39.9 0.3 YF125ST 461 0 0 0 13 LG Flush 147.5 40.4 3.7 WF125 6196 0 0 0 14 Slow For Seat 62.1 19.8 3.4 WF125 2622 0 0 0 15 Overflush PCM 269.3 38.9 7 WF125 11311 0 0 0 Stage Pressures & Rates Step #Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 PAD st5 40.1 40.3 3774 4408 3261 2 Slow For Seat 21.3 40.1 2290 3017 1758 3 Resume PAD 37.1 40.1 3767 3946 2582 4 1.0 PPA 39.4 40.3 3764 3932 3511 5 2.0 PPA 39.9 40.1 3418 3749 3314 6 4.0 PPA 39.9 40.1 3463 3644 3346 7 6.0 PPA 39.8 40.3 4061 4871 3580 8 8.0 PPA 39.7 40.3 5424 5882 4875 9 10.0 PPA 39.9 40.3 5835 5914 5736 10 Clean lines & Spacer 40.4 41.3 5515 5827 5278 11 Drop Collet#6 39.7 39.7 5283 5283 5283 12 XL Flush 39.9 39.9 5326 5360 5278 13 LG Flush 40.4 41.5 4736 5278 3918 14 Slow For Seat 19.8 39.9 2250 3699 1927 15 Overflush PCM 38.9 40.5 4287 4468 1208 Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Displacement PT, Ball to Seat and Pump Check Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 10:19:10 Priming Pumps With Diesel -5 3246 0.0 5.4 0.0 2 10:26:54 Mixing gel WF125 -5 3218 0.0 5.4 0.0 3 10:59:24 Low Pressure Test 325 3163 0.0 0.0 0.0 4 11:12:54 Mid Pressure Test 5054 3145 0.0 0.0 0.0 5 11:17:31 High Pressure Test 9503 3140 0.0 0.0 0.0 6 11:23:13 Bump Up Pressure Back To High Test 9434 3136 0.0 0.0 0.0 7 11:30:24 Bleeding off the pressure 1071 3131 0.0 0.0 0.0 8 11:31:01 Safety meeting 1181 3127 0.0 0.0 0.0 9 11:57:42 Finished Safety meeting 1373 3108 0.0 0.0 0.0 10 11:57:55 Radio check 1369 3108 0.0 0.0 0.0 11 12:04:25 Open the well 307 3104 0.0 0.0 0.0 12 12:11:47 Pulling On Fluid To The SuperPod 302 3264 0.0 0.0 0.0 13 13:21:43 Start Displace PT Automatically 302 3250 0.0 0.0 0.0 14 13:21:43 Start Propped Frac Automatically 302 3250 0.0 0.0 0.0 15 13:21:43 Start Pump Check Automatically 302 3250 0.0 0.0 0.0 16 13:21:59 Started Pumping 298 3250 0.0 0.0 0.0 17 13:34:50 Stopped Pumping 421 3181 40.3 0.0 0.0 18 13:35:54 Ball launched 449 3177 40.3 0.0 0.0 19 13:44:44 Radio Check 307 3200 40.3 0.0 0.0 20 13:46:34 Started Pumping 302 3204 40.3 0.0 0.0 21 13:46:50 Start Ball to Seat Automatically 563 3213 40.7 2.8 0.0 22 14:38:00 Stage at Perfs: Displace PT 888 3195 244.8 4.0 0.0 23 14:39:02 Ball Seated 893 3200 248.9 4.0 0.0 24 14:41:59 Start Pump Check Automatically 929 3218 260.7 4.0 0.0 25 14:43:45 Start Pump Check Manually 1373 3236 268.1 9.3 0.0 26 14:44:40 Stage at Perfs: Ball to Seat 2756 3287 286.4 28.8 0.0 27 14:46:50 Lost POD C-Pump Throttle 536 3232 312.1 0.0 0.0 28 14:52:48 Stage at Perfs: Pump Check 3113 3502 506.9 40.0 0.0 29 14:52:59 Stage at Perfs: Pump Check 3090 3511 514.3 40.0 0.0 Stage 2 (attempt2) Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:53:18 Start PAD st2 Manually 3044 3525 526.9 40.0 0.0 2 14:53:18 Start Propped Frac Manually 3044 3525 526.9 40.0 0.0 3 14:53:18 Start Stage2 Automatically 3044 3525 526.9 40.0 0.0 4 14:59:32 Stage at Perfs: Pump Check 2939 3337 245.8 39.9 0.0 5 15:01:45 Stopped Pumping 879 3319 294.9 0.0 0.0 6 15:02:35 Started Pumping 961 3342 294.9 0.0 0.0 7 15:11:01 Stopped Pumping 806 3296 295.5 0.0 0.0 8 15:28:18 Started Pumping 1863 3250 295.5 3.8 0.0 9 15:37:43 Start Pump Check (issues with chem check valve)2980 3323 352.1 37.2 -0.0 10 15:40:34 Start PAD st2 Manually 2014 3410 450.3 20.5 0.0 11 15:44:28 Stage at Perfs: PAD st2 3264 3616 594.9 40.0 0.0 12 15:44:31 Stage at Perfs: Pump Check 3264 3621 596.9 40.1 0.0 13 15:44:33 Stage at Perfs: Pump Check 3264 3621 598.2 39.9 0.0 Client: Santos Well: NDBi-014 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) 14 15:44:37 Stage at Perfs: Pump Check 3259 3625 600.9 40.1 0.0 15 15:46:59 Stage at Perfs: Pump Check 3117 3552 695.5 40.0 0.0 16 15:49:37 Start 1.0 PPA Automatically 3159 3374 800.9 39.8 0.0 17 15:49:40 Started Pumping Prop 3163 3374 802.9 39.9 0.0 18 15:54:08 Start 2.0 PPA Automatically 2975 3502 980.9 39.8 1.0 19 15:55:46 Stage at Perfs: PAD st2 2953 3502 1045.7 39.8 1.5 20 15:59:39 Start 4.0 PPA Automatically 2930 3314 1200.3 39.7 2.2 21 16:00:18 Stage at Perfs: 1.0 PPA 2953 3328 1226.0 39.4 3.9 22 16:05:42 Start 6.0 PPA Automatically 3365 3374 1440.8 39.9 3.9 23 16:05:49 Stage at Perfs: PAD st2 3378 3374 1445.4 39.9 4.1 24 16:11:46 Start 8.0 PPA Automatically 4619 3442 1680.5 39.5 5.9 25 16:11:54 Stage at Perfs: PAD st2 4619 3442 1685.8 39.2 6.4 26 16:17:52 Start 10.0 PPA Automatically 5777 3328 1920.9 39.9 8.1 27 16:17:59 Stage at Perfs: PAD st2 5736 3323 1925.5 39.6 8.0 28 16:21:07 Start Clean lines & Spacer Manually 6134 3355 2049.5 41.2 0.1 29 16:21:16 Stopped Pumping Prop 6331 3360 2055.8 41.9 -0.0 30 16:21:41 Start Drop Collet#3 Manually 6367 3374 2073.6 43.0 0.0 Stage 3 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 16:21:46 Start PAD st3 Automatically 6496 3383 0.0 42.7 0.0 2 16:21:46 Start Propped Frac Automatically 6496 3383 0.0 42.7 0.0 3 16:21:46 Start Stage3 Automatically 6496 3383 0.0 42.7 0.0 4 16:23:56 Stage at Perfs: PAD st2 4568 3401 88.7 39.8 0.0 5 16:26:17 Start Slow For Seat Automatically 1268 3319 182.8 35.5 0.0 6 16:27:50 Stopped Pumping 2788 3424 210.4 0.0 0.0 7 16:28:03 Started Pumping 2220 3378 210.4 0.0 0.0 8 16:28:50 Stage at Perfs: 1.0 PPA 5045 3497 216.8 19.3 0.0 9 16:29:24 Activated Extend Stage 4903 3493 228.1 20.2 0.0 10 16:30:03 Stage at Perfs: 2.0 PPA 3818 3447 241.1 20.2 0.0 11 16:30:13 Stage at Perfs: 4.0 PPA 3983 3452 244.5 20.0 0.0 12 16:32:10 Start Resume PAD Manually 3200 3419 283.6 20.0 0.0 13 16:35:09 Start 1.0 PPA Manually 3726 3465 382.2 39.9 0.0 14 16:35:09 Started Pumping Prop 3726 3465 382.2 39.9 0.0 15 16:36:05 Stage at Perfs: 6.0 PPA 3607 3470 419.4 40.4 1.0 16 16:38:36 Stage at Perfs: 8.0 PPA 3232 3493 520.1 40.3 1.0 17 16:41:04 Stage at Perfs: 10.0 PPA 3113 3497 618.7 39.9 1.0 18 16:41:29 Start 2.0 PPA Automatically 3072 3506 635.4 40.0 1.0 19 16:47:00 Start 4.0 PPA Automatically 3035 3328 855.7 40.0 2.0 20 16:47:24 Stage at Perfs: Clean lines & Spacer 3012 3323 871.6 39.8 3.8 21 16:52:55 Stage at Perfs: Drop Collet3 3131 3328 1092.1 39.9 3.9 22 16:53:31 Start 6.0 PPA Manually 3127 3328 1116.1 40.2 3.9 23 16:59:27 Stage at Perfs: PAD st3 3763 3355 1352.9 39.7 6.1 24 16:59:51 Start 8.0 PPA Manually 3781 3351 1368.9 39.9 6.1 25 17:05:47 Stage at Perfs: Slow For Seat 4724 3401 1605.7 39.8 7.9 26 17:06:45 9PPA step 4660 3401 1644.2 40.0 8.5 Client: Santos Well: NDBi-014 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) 27 17:11:06 Start Clean lines & Spacer Manually 4793 3410 1817.5 40.7 0.1 28 17:11:09 Stopped Pumping Prop 4779 3410 1819.6 40.9 0.1 29 17:11:42 Start Drop Collet#4 Manually 4395 3401 1841.9 39.9 0.0 Stage 4 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 17:11:47 Start PAD st4 Automatically 4587 3401 0.0 39.9 0.0 2 17:11:47 Start Propped Frac Automatically 4587 3401 0.0 39.9 0.0 3 17:11:47 Start Stage4 Automatically 4587 3401 0.0 39.9 0.0 4 17:16:11 Start Slow For Seat Automatically 1186 3296 176.0 34.1 0.0 5 17:17:32 Ball & Collet Seated 2321 3355 203.2 18.8 0.0 6 17:17:49 Stage at Perfs: 1.0 PPA 2275 3337 208.5 18.8 0.0 7 17:18:29 Start Resume PAD Manually 2756 3365 221.0 20.3 0.0 8 17:18:55 Stage at Perfs: 2.0 PPA 3200 3374 233.3 34.1 0.0 9 17:19:01 Stage at Perfs: 4.0 PPA 3172 3378 236.7 34.4 0.0 10 17:21:11 Start 1.0 PPA Manually 3598 3406 321.8 39.9 0.0 11 17:21:11 Started Pumping Prop 3598 3406 321.8 39.9 0.0 12 17:23:18 Stage at Perfs: 6.0 PPA 3552 3429 405.9 39.9 1.0 13 17:24:25 Stage at Perfs: 8.0 PPA 3557 3447 450.6 40.3 1.0 14 17:25:42 Start 2.0 PPA Automatically 3488 3456 502.0 40.0 1.0 15 17:26:56 Stage at Perfs: Clean lines & Spacer 3479 3474 551.4 40.0 1.8 16 17:31:13 Start 4.0 PPA Automatically 3305 3323 722.3 39.7 2.0 17 17:31:27 Stage at Perfs: Drop Collet4 3319 3328 731.6 39.9 3.5 18 17:36:58 Stage at Perfs: PAD st4 3333 3351 952.3 40.2 4.0 19 17:37:13 Start 6.0 PPA Automatically 3337 3351 962.3 39.9 3.9 20 17:42:58 Stage at Perfs: Slow For Seat 3786 3369 1192.0 39.8 6.1 21 17:43:13 Start 8.0 PPA Automatically 3831 3369 1202.0 40.0 6.2 22 17:48:52 Start 10.0 PPA Manually 4436 3387 1427.0 39.9 7.7 23 17:48:59 Stage at Perfs: Resume PAD 4413 3383 1431.7 39.9 8.8 24 17:54:37 Stage at Perfs: 1.0 PPA 4468 3369 1656.9 40.3 9.7 25 17:54:52 Start Clean lines & Spacer Manually 4344 3365 1667.0 41.0 0.2 26 17:54:55 Stopped Pumping Prop 4285 3365 1669.1 40.6 0.1 27 17:55:29 Start Drop Collet#5 Manually 4042 3360 1691.8 40.2 0.0 Stage 5 Job Messages Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 17:55:34 Start PAD st5 Automatically 4184 3360 0.0 40.2 0.0 2 17:55:34 Start Propped Frac Automatically 4184 3360 0.0 40.2 0.0 3 17:55:34 Start Stage5 Automatically 4184 3360 0.0 40.2 0.0 4 17:59:44 Start Slow For Seat Automatically 1662 3291 167.0 37.6 0.0 5 18:01:25 Ball & Collet#5 Seated 2573 3310 200.6 17.5 0.0 6 18:01:27 Stage at Perfs: 2.0 PPA 2586 3328 201.2 17.4 0.0 Client: Santos Well: NDBi-014 Formation: Nanushuk District: Pikka Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 7 18:02:00 Start Resume PAD Manually 2779 3328 210.7 17.3 0.0 8 18:02:36 Stage at Perfs: 4.0 PPA 3712 3387 226.3 35.5 0.0 9 18:02:41 Stage at Perfs: 6.0 PPA 3731 3351 229.3 36.5 0.0 10 18:05:12 Start 1.0 PPA Manually 3447 3378 326.9 35.1 0.0 11 18:05:12 Started Pumping Prop 3447 3378 326.9 35.1 0.0 12 18:06:47 Stage at Perfs: 8.0 PPA 3836 3442 388.1 39.5 0.9 13 18:07:54 Stage at Perfs: 10.0 PPA 3886 3406 432.3 40.2 1.0 14 18:10:49 Stage at Perfs: Clean lines & Spacer 3799 3419 548.2 40.1 1.0 15 18:11:15 Start 2.0 PPA Manually 3744 3415 565.6 39.9 1.0 16 18:16:48 Stage at Perfs: Drop Collet#5 3346 3392 786.8 39.7 1.9 17 18:17:16 Start 4.0 PPA Manually 3346 3401 805.4 39.6 1.9 18 18:22:49 Stage at Perfs: PAD st5 3571 3397 1026.7 39.9 4.1 19 18:23:18 Start 6.0 PPA Automatically 3648 3401 1046.0 39.9 4.0 20 18:28:51 Stage at Perfs: Slow For Seat 4802 3419 1267.1 39.8 6.3 21 18:29:19 Start 8.0 PPA Automatically 4880 3410 1285.7 39.8 5.9 22 18:34:53 Stage at Perfs: Resume PAD 5791 3415 1506.7 39.8 7.8 23 18:35:22 Start 10.0 PPA Automatically 5850 3415 1526.0 39.7 7.9 24 18:40:50 Start Clean lines & Spacer Manually 5841 3392 1744.1 41.1 0.5 25 18:40:52 Stopped Pumping Prop 5740 3378 1745.5 41.4 0.2 26 18:40:55 Stage at Perfs: 1.0 PPA 5823 3387 1747.5 41.4 0.0 27 18:41:35 Start DropCollet#6 Manually 5328 3374 1774.3 39.7 0.0 28 18:41:39 Start XL Flush Automatically 5360 3369 1776.9 39.9 0.0 29 18:41:55 Start LG Flush Manually 5205 3369 1787.6 40.1 0.0 30 18:45:34 Start Slow For Seat Manually 1991 3305 1935.1 37.9 0.0 31 18:47:08 Stage at Perfs: 2.0 PPA 2197 3328 1965.0 18.2 0.0 32 18:47:45 Ball & Collet#6 Seated 2357 3337 1976.1 17.9 0.0 33 18:48:49 Stage at Perfs: 4.0 PPA 2458 3346 1995.3 18.4 0.0 34 18:48:55 Start Overflush PCM Manually 2435 3351 1997.2 19.6 0.0 35 18:48:57 Stage at Perfs: 6.0 PPA 2710 3346 1997.9 19.9 0.0 36 18:49:21 Stage at Perfs: 8.0 PPA 3882 3401 2008.7 33.7 0.0 37 18:53:06 Stage at Perfs: 10.0 PPA 4353 3456 2156.3 39.8 0.0 38 18:54:40 Stage at Perfs: Clean lines & Spacer 4431 3479 2218.6 39.6 0.0 39 18:55:54 Stopped Pumping 572 3333 2266.5 16.8 0.0 40 18:57:23 Shut in the well 929 3369 2266.5 0.0 0.0 41 18:57:42 Monitor pressure decline for 45 min 911 3365 2266.5 0.0 0.0 42 19:25:22 Fanning and blowing out pumps 14 9 2266.5 8.1 0.0 43 20:01:49 open the well 595 2554 2266.5 7.6 0.0 44 20:02:01 LR pumping Freeze Protect (50 bbl past wellhead)632 2554 2266.5 5.4 0.0 45 20:15:17 LR finished pumping FP -5 1941 2266.5 45.0 0.0 46 20:15:25 Shut in well 0 1909 2266.5 45.0 0.0 DisclaimerNotice 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 inputdata 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 affectingthem. If the Operator isaware 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 wellsaccordingly. Prices quoted are estimates only and are good for 30days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringementof patentsof Schlumberger or others is notto beinferred. FracCAT Treatment Report Well :NDBi-014 Field : Pikka Formation : Nanushuk Well Location : County : North Slope State : Alaska Country :United States Preparedfor Client : Santos ClientRep : Scott Leahy Date Prepared : March 29, 2024 Preparedby Name : Alena Lutskaia Division : Schlumberger Phone : 630-780-0058 Pressure(AllZones) InitialWellheadPressure (psi) 325 InitialBHP atGauge (psi) 2,040 FinalSurface ISIP (psi) 1,180 Final ISIP at Gauge (psi) 2,912 SurfaceShutinPressure(psi) 2,138 BHShutin Pressure (psi) 3,162 MaximumTreating Pressure(psi) 5,644 BH Gauge at 10,168 ftMD, 4,363 ftTVD TreatmentTotals (All ZonesAs Per FracCAT) TotalSlurryPumped(Water+Adds+Proppant) (bbl)8,381.5 TotalProppantPumped(lb) 940,766 TotalYF125ST PastWellhead(bbl) 6,747.3 TotalProppantinFormation (lb) 940,766 TotalWF125PastWellhead (bbl) 594.7 TotalFreezeProtectPastWellhead (bbl) 42.5 ChemicalAdditives Mixed / Used PastWH ChemicalAdditives Mixed/ Used PastWH F103 (gal) 308 308 M275 (lb) 114 113.5 J450 (gal) 210 210 J753 (gal) 20 19.2 J580 (lb) 8,663 8,621 J475 (lb) 1,815 1,815 J532 (gal) 704 704 J134 (lb) 2.0 0 J511 (lb) 575 575 D206 (gal) 4.0 4.0 M002 0.5 0.5 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates DisplPT Ball to Seat Pump Check Stage6 Stage 7 Stage 8 Stage 9 Rate - bbl/min Summary On March 29, 2024, SLB successfully performed a hydraulic fracturing treatment on Stages 6-9 of NDBi-014. The initial plan called forthecompletionofstages6-9,thereweresomechangesduringthepumping:forStage7ResumePADstepvolumewasextended from 50bbl to 100bbl; for Stage 8 Resume PAD step volume was extended from 50bbl to 100bbl and change of Proppant steps slurry volumes - 2PPA step (from 200bbl to 220bbl), 4PPA-6PPA-8PPA steps (from 220bbl to 240bbl), 10PPA step (from 175bbl to 200bbl); for Stage9 Slurry Ratechanged from 30 BPM to 35BPM, changeofProppantsteps slurry volumes 1PPA-2PPA step (from 150bbl to 180bbl), 3PPA-4PPA-5PPA steps (from 160bbl to 190bbl), 6PPA step (from 160bbl to 175bbl), 7PPA step (from 140bbl to 150bbl), 8PPA step (from 125bbl to 175bbl). When the rate was slowed down before the Ball/Collet#9 hit the sleeve, there was no clear indication of that Ball/Collet#9 has shifted the sleeve, thus, the decision was made by Santos Rep. to pump some more fluid and shutdown and then check with the Completion Rep. if the gauges in thewell registered any pressure change. The decision was to launch the second ball and pump to seat to make sure that Ball/Collet#9 had shifted the sleeve and then stage over to PAD stage 9. Flush consisted ofWF125 fluid and Freeze Protect followed by hard shutdown. Post shutdown pressure decline was monitored for 60 min. Total of 940,766 pounds of proppant was pumped and 940,766 was placed into formation in 8,381.5bbl of slurry. Please note, that proppant Volumes are as per BOL consumed. Stages 6-7-8 consisted of a PAD, two Scour steps 1-3PPA with proppant 40/70 CBL, and 6 proppant steps from 1-10 PPA, Stages 9 consisted of a PAD, and 8 proppant steps from 1-8 PPA. Pump trips were staggered from 7,400 to 8,000 psi. The GORV was set to 8,300 psi. Summary of Stages 6-9 Material Actual Design Slurry Volume (bbl)8,382 7,265 Clean Fluid Volume(bbl)7,342 6,296 Proppant(lb)940,766 863,859 6500 6000 FracCAT*Santos NDBi-014 03-25-2024 Treating Pressure Annulus Pressure 45 BHPressure 22 SlurryRate Prop Conc 40 BHProp Con 20 5500 18 5000 35 16 4500 30 14 4000 3500 25 12 3000 20 10 2500 8 15 2000 6 1500 10 4 1000 5 2500 0 0 0 13:36:30 14:06:30 14:36:30 15:06:30 15:36:30 16:06:30 16:36:30 17:06:30 17:36:30 18:06:30 18:36:30 19:06:30 19:36:30 Time - hh:mm:ss Prop Con -PPA Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates PT Displacement PumpingBallto Seat Pump Check Displacement PT, Ball to Seat and Pump Check. Stage included PT displacement, pumping Ball#6 to seat and pump check that was placed in the schedule to test the equipment and ensure the pumps were job ready. After step Pump Check was pumped, then moved topumping Stage#6 without shutdown. A summary of the stage and pressures as follows: 7000 FracCAT*Santos NDBi-014 Displacement PT, Ball to Seat, Pump Check 03-29-2024 Treating Pressure Annulus Pressure 50 BHPressure SlurryRate 6000 Prop Conc 14 45 BH Prop Con 40 12 5000 35 10 30 4000 8 25 3000 20 6 2000 15 4 10 1000 2 5 0 0 0 13:30:17 13:38:37 13:46:57 13:55:17 14:03:37 14:11:57 14:20:17 14:28:37 14:36:57 14:45:17 14:53:37 Time - hh:mm:ss Summary of Stage Displacement PT, Ball to Seat and Pump Check TotalProppant Pumped(lb) 0 Max pumping Rate (bpm) 40.2 Total Proppant in Formation (lb) 0 Average Pumping Rate (bpm) 11.2 TotalSlurry Pumped (bbl) 308.2 Maximum Treating Pressure (psi) 4,568 YF125STPumped(bbl) 0 Average Treating Pressure (psi) 1,614 WF125 Pumped (bbl) 308.2 Average Water Temperature(F) 84.4 AverageViscosity (cP) 17.9 Prop Con -PPARate -bbl/min Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Displace PT 40 3.5 11.8 WF125 1678 0 0 0 2 Ball to Seat 181.9 4 45.5 WF125 7639 0 0 0 3 Pump Check 86.3 30.5 3.5 WF125 3623 0 0 0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 DisplacePT 3.5 3.6 733 797 320 2 Ball to Seat 4.0 4.1 757 851 558 3 PumpCheck 30.5 40.2 3891 4568 851 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Rate -bbl/min Stage6 The average treating pressure on PAD was around 4,000 psi and slowly fell to about 3,390 psi when 1PPA and 2PPA were going intotheformation.Atthispoint,thetreatingpressurewasgraduallyincreasingfrom3,390to5,650psi.Slurryrateremainedsteady at 40bpm until it was slowed for the Collet/Ball#7 to seat. Asummary ofthe Stageand its measured pump scheduleisbelow: 6000 FracCAT*Santos NDBi-014 Stage6 03-29-2024 Treating Pressure Annulus Pressure 50 BHPressure 16 SlurryRate Prop Conc 15 5000 45 BH Prop Con 14 40 13 Collet/Ball#7 12 4000 35 hitthesleeve 11 10 30 9 3000 25 8 2000 1000 0 DropRatefor Collet/Ball#7 7 20 6 15 5 4 10 3 2 5 1 0 0 14:51:49 14:58:29 15:05:09 15:11:49 15:18:29 15:25:09 15:31:49 15:38:29 15:45:09 15:51:49 Time - hh:mm:ss Summary of PressuresWhen Collet Seats Collet #6 BeforeCollet Hit (psi)Collet Hit (psi)AfterCollet (psi) WellheadPressure 2,202 2,389 2,248 BottomholePressure 3,555 3,715 3,604 Summary of Stage 6 TotalProppant Pumped(lb)244,218 Max pumping Rate (bpm)41.6 Total Proppant in Formation (lb)244,218 Average Pumping Rate (bpm)5,026 Total Slurry Pumped (bbl)1,850.5 Maximum Treating Pressure (psi)5,644 YF125STPumped(bbl)1,597.7 Average Treating Pressure (psi)39.8 WF125 Pumped (bbl)0 Average Water Temperature (F)79.9 AverageViscosity (cP)18.7 Prop Con -PPA Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st6 250 40.1 6.2 YF125ST 10500 0 0 0 2 1.0 PPA 50.1 40 1.3 YF125ST 2029 40/70Carbolite 1 0.8 1705 3 3.0 PPA 133 40 3.3 YF125ST 4999 40/70Carbolite 3.1 2.6 13735 4 Resume PAD 50 40 1.3 YF125ST 2100 40/70Carbolite 0.2 0 6 5 1.0 PPA 180 39.9 4.5 YF125ST 7254 CarboLite16/20 1.1 1 6996 6 2.0 PPA 220 39.9 5.5 YF125ST 8501 CarboLite16/20 2.1 2 16943 7 4.0 PPA 240 39.9 6 YF125ST 8590 CarboLite16/20 4.1 3.9 34168 8 6.0 PPA 240 39.9 6 YF125ST 7986 CarboLite16/20 6.1 5.9 48059 9 8.0 PPA 240 39.9 6 YF125ST 7466 CarboLite16/20 8.2 7.9 60085 10 10.0 PPA 218.1 39.9 5.5 YF125ST 6446 CarboLite16/20 10.5 9.6 62498 11 Clean lines & Spacer 26.3 41.3 0.7 YF125ST 1107 CarboLite16/20 1.3 0 23 13 Drop Collet#7 3 39.8 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 PAD st6 40.1 40.2 4005 4358 3763 2 1.0 PPA 40.0 40.2 3736 3786 3667 3 3.0 PPA 40.0 40.4 3611 3694 3502 4 ResumePAD 40.0 40.1 3541 3621 3484 5 1.0 PPA 39.9 40.1 3658 3731 3456 6 2.0 PPA 39.9 40.1 3412 3465 3374 7 4.0 PPA 39.9 40.2 3408 3483 3378 8 6.0 PPA 39.9 40.2 3608 3755 3484 9 8.0 PPA 39.9 40.6 4261 4870 3758 10 10.0 PPA 39.9 41.2 5249 5644 4871 11 Clean lines & Spacer 41.3 41.6 5509 5644 5118 13 Drop Collet#7 39.8 39.8 5026 5026 5026 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Rate -bbl/min Stage7 Once the Collet/Ball#5 hit the sleeve the pressure transition from Stage 6 to 7 was not typical. The average treating pressure on PAD was around 4,900 psi and slowly fell to about 3,720 psi when Scour 40/70 CBL was going into the formation. Then pressure stayed stable until 4 PPA started going into the formation the treating pressure was gradually increasing from 2,870 to 4,680 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#8 to seat. Asummary ofthe Stageand its measured pump scheduleisbelow: FracCAT*Santos NDBi-014 Stage7 03-29-2024 Treating Pressure Annulus Pressure 50 BH Pressure 18 6500 SlurryRate Prop Conc 17 6000 5500 5000 4500 4000 3500 3000 2500 2000 1500 1000 500 0 Collet/Ball#7 hitthe sleeve. DropRatefor Collet/Ball#8 45 BH Prop Con 16 15 40 14 1335 12 30 11 10 25 9 8 20 7 6 15 5Collet/Ball#8 4 10 hitthesleeve 3 5 2 1 0 0 15:47:09 15:52:09 15:57:09 16:02:09 16:07:09 16:12:09 16:17:09 16:22:09 16:27:09 16:32:09 16:37:09 Time - hh:mm:ss Summary of PressuresWhen Collet Seats Collet #7 BeforeCollet Hit (psi)Collet Hit (psi)AfterCollet (psi) WellheadPressure 2,481 4,079 4,724 BottomholePressure 3,386 4,853 5,672 Summary of Stage 7 TotalProppant Pumped(lb)233,301 Max pumping Rate (bpm)41.8 Total Proppant in Formation (lb)233,301 Average Pumping Rate (bpm)39.0 Total Slurry Pumped (bbl)1,889.1 Maximum Treating Pressure (psi)5,562 YF125STPumped(bbl)1,647.5 Average Treating Pressure (psi)3,544 WF125 Pumped (bbl)0 Average Water Temperature (F)83.0 AverageViscosity (cP)19.3 Prop Con -PPA Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st7 152.4 39.9 3.9 YF125ST 6401 0 0 0 2 Slow For Seat 66 19.1 3.6 YF125ST 2773 0 0 0 3 Resume PAD 46.1 29 1.6 YF125ST 1935 0 0 0 4 1.0 PPA 50.1 39.7 1.3 YF125ST 2027 40/70Carbolite 1 0.8 1719 5 3.0 PPA 145.8 40 3.6 YF125ST 5443 40/70Carbolite 3.1 2.8 15963 6 Resume PAD 120.7 40 3 YF125ST 5069 40/70Carbolite 0.8 0 28 7 1.0 PPA 180 39.9 4.5 YF125ST 7256 CarboLite16/20 1 0.9 6959 8 2.0 PPA 210 40 5.3 YF125ST 8116 CarboLite16/20 2.1 2 16142 9 4.0 PPA 230 39.9 5.8 YF125ST 8230 CarboLite16/20 4.1 3.9 32794 10 6.0 PPA 230 39.9 5.8 YF125ST 7654 CarboLite16/20 6.2 5.9 46016 11 8.0 PPA 230 40 5.8 YF125ST 7154 CarboLite16/20 8.2 7.9 57515 12 10.0 PPA 195.9 39.9 4.9 YF125ST 5789 CarboLite16/20 10.2 9.6 56153 13 Clean lines & Spacer 29.1 40.8 0.7 YF125ST 1224 CarboLite16/20 1 0 12 14 Drop Collet#8 3 39.6 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 PAD st7 39.9 40.4 4900 5045 2510 2 Slow For Seat 19.1 37.9 3315 4944 1959 3 ResumePAD 29.0 37.1 5293 5562 4944 4 1.0 PPA 39.7 40.4 5075 5356 4884 5 3.0 PPA 40.0 40.4 4380 5081 3864 6 ResumePAD 40.0 40.4 3312 3859 2989 7 1.0 PPA 39.9 40.3 2810 2985 2719 8 2.0 PPA 40.0 40.2 2769 2892 2692 9 4.0 PPA 39.9 40.1 2916 2953 2893 10 6.0 PPA 39.9 40.3 3002 3213 2875 11 8.0 PPA 40.0 40.3 3608 4033 3213 12 10.0 PPA 39.9 41.0 4293 4674 3987 13 Clean lines & Spacer 40.8 41.8 4408 4674 4120 14 Drop Collet#8 39.6 39.7 4115 4115 4115 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Drop Rate for Collet/Ball#9 Collet/Ball#8 hitthe sleeve Rate -bbl/min Stage8 Once the Collet/Ball#8 hit the sleeve the pressure transition from Stage 7 to 8 was like Stage 7. The average treating pressure on PAD was around 4,500 psi andslowly fell to about 2,560 psiwhen 1PPA was going into the formation. Then pressure stayed stable until 4 PPA started going into the formation the treating pressure was gradually increasing from 2,650 to 4,230 psi. Slurry rate remained steady at 40bpm until it was slowed for the Collet/Ball#8 to seat. Asummary ofthe Stage and its measured pump scheduleis below: 7000 FracCAT*Santos NDBi-014 Stage8 03-29-2024 Treating Pressure Annulus Pressure 50 BHPressure 16 SlurryRate Prop Conc 15 6000 5000 45 BH Prop Con 14 40 13 12 35 11 1030 4000 9 25 8 3000 7 20 6 2000 15 5 4 10 3 1000 25 1 0 0 0 16:37:56 16:44:36 16:51:16 16:57:56 17:04:36 17:11:16 17:17:56 17:24:36 17:31:16 Time - hh:mm:ss Summary of PressuresWhen Collet Seats Collet#8 BeforeCollet Hit (psi)Collet Hit (psi)AfterCollet (psi) WellheadPressure 2,183 3,721 4,015 BottomholePressure 3,120 4,598 5,008 Summary of Stage 8 TotalProppant Pumped(lb)239,722 Max pumping Rate (bpm)41.2 Total Proppant in Formation (lb)239,722 Average Pumping Rate (bpm)39.2 Total Slurry Pumped (bbl)1,850.4 Maximum Treating Pressure (psi)5,548 YF125STPumped(bbl)1,602.1 Average Treating Pressure (psi)3,261 WF125 Pumped (bbl)0 Average Water Temperature (F)81.1 AverageViscosity (cP)19.5 Prop Con -PPA Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st8 142 40 3.5 YF125ST 5964 0 0 0 2 Slow For Seat 57.8 20.4 3 YF125ST 2429 0 0 0 3 Resume PAD 31.6 30 1.1 YF125ST 1324 0 0 0 4 1.0 PPA 50.1 39.9 1.3 YF125ST 2026 40/70Carbolite 1 0.8 1751 5 3.0 PPA 101.4 40 2.5 YF125ST 3838 40/70Carbolite 3.1 2.4 9878 6 Resume PAD 100.5 40 2.5 YF125ST 4223 40/70Carbolite 0.1 0 15 7 1.0 PPA 180 39.9 4.5 YF125ST 7254 CarboLite16/20 1 0.9 6993 8 2.0 PPA 220.6 40.1 5.5 YF125ST 8523 CarboLite16/20 2 2 16989 9 4.0 PPA 240.5 40 6 YF125ST 8604 CarboLite16/20 4.1 3.9 34320 10 6.0 PPA 240.2 39.9 6 YF125ST 7994 CarboLite16/20 6.2 5.9 48095 11 8.0 PPA 240.4 40.1 6 YF125ST 7474 CarboLite16/20 8.3 7.9 60238 12 10.0 PPA 213.6 39.9 5.4 YF125ST 6304 CarboLite16/20 10.2 9.6 61438 13 Clean lines & Spacer 28.7 40.2 0.7 YF125ST 1207 CarboLite16/20 0.7 0 5 14 Drop Collet#9 3 40.1 0.1 YF125ST 126 0 0 0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 PAD st8 40.0 40.2 3636 4115 2942 2 Slow For Seat 20.4 40.1 2608 4138 1694 3 ResumePAD 30.0 38.1 5076 5466 4138 4 1.0 PPA 39.9 40.9 5256 5548 4971 5 3.0 PPA 40.0 40.5 3965 4958 3511 6 ResumePAD 40.0 40.5 3326 3539 3053 7 1.0 PPA 39.9 40.1 2845 3053 2769 8 2.0 PPA 40.1 40.2 2615 2769 2568 9 4.0 PPA 40.0 40.4 2614 2669 2577 10 6.0 PPA 39.9 40.2 2875 3072 2655 11 8.0 PPA 40.1 40.5 3519 3900 3026 12 10.0 PPA 39.9 41.2 3908 4230 3680 13 Clean lines & Spacer 40.2 41.2 3810 4083 3667 14 Drop Collet#9 40.1 40.1 3663 3667 3660 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates PumpextraVolume toseeindicationof FracSleeve shifted Pump 2ndBall to seat 2nd Ball for Frac sleeve#9hit Rate -bbl/min Stage9 When the rate was slowed down before the Ball/Collet#9 hit the sleeve, there was no clear indication of that Ball/Collet#9 has shifted the sleeve, thus, the decision was made by Santos Rep. to pump some more fluid and shutdown and then check with the Completion Rep. if the gauges in the well registered any pressure change. The decision was to launch the second ball and pump to seat to make sure that Ball/Collet#9 had shifted the sleeve and then stage over to PAD stage 9. Average treating pressure on PAD was around 3,250 psi and when 1PPA was going into the formation, treating pressure started slowly falling from 3,155 to 2,530 psi.When the7PPAstep wasgoinginto theformation thetreatingpressure was graduallyincreasingfrom 2,530to 2,850 psi.Flush consisted of WF125 and Freeze Protect followed by hard shutdown with an ISIP of 1,180 psi and recording of pressure decline for 60 mins. Asummary ofthe Stageand its measured pump scheduleis below: FracCAT*Santos NDBi-014 Stage9 03-29-2024 Treating Pressure Annulus Pressure 40 BHPressure 16 SlurryRate 4500 Prop Conc 15 4000 35 BH Prop Con 14 13 3500 30 12 11 3000 25 10 2500 9 20 8 2000 7 15 6 1500 5 1000 10 4 3 5 2500 1 0 0 0 17:27:56 17:37:56 17:47:56 17:57:56 18:07:56 18:17:56 18:27:56 18:37:56 18:47:56 18:57:56 19:07:56 19:17:56 19:27:56 19:37:56 Time - hh:mm:ss Summary of PressuresWhen Collet Seats Collet #9 BeforeCollet Hit (psi)Collet Hit (psi)AfterCollet (psi) WellheadPressure --- BottomholePressure --- Summary of Stage 9 TotalProppant Pumped(lb)223,525 Max pumping Rate (bpm)40.3 Total Proppant in Formation (lb)223,525 Average Pumping Rate (bpm)31.7 Total Slurry Pumped (bbl)2,483.3 Maximum Treating Pressure (psi)3,658 YF125STPumped(bbl)1,899.9 Average Treating Pressure (psi)2,703 WF125 Pumped (bbl)286.6 Average Water Temperature (F)84.7 AverageViscosity (cP)18.0 Prop Con -PPA Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates As Measured Pump Schedule Step #StepName Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 PAD st9 140.2 40.1 3.5 YF125ST 5894 0 0 0 2 Slow For Seat 59.5 18.8 3.3 YF125ST 2498 0 0 0 3 Resume PAD 125.1 21.3 6.2 YF125ST 5253 0 0 0 4 2nd Ball to seat 178 7 37.3 WF125 7474 0 0 0 5 Resume PAD 342.4 34.4 10 YF125ST 14380 0 0 0 6 1.0 PPA 179.8 35 5.1 YF125ST 7240 CarboLite16/20 1.1 1 7116 7 2.0 PPA 179.9 35.1 5.1 YF125ST 6949 CarboLite16/20 2.1 2 13944 8 3.0 PPA 190.3 35 5.4 YF125ST 7064 CarboLite16/20 3.1 3 21350 9 4.0 PPA 190.4 35 5.4 YF125ST 6805 CarboLite16/20 4.2 4 27417 10 5.0 PPA 189.7 34.9 5.4 YF125ST 6531 CarboLite16/20 5.1 5 32985 11 6.0 PPA 174.8 35.1 5 YF125ST 5808 CarboLite16/20 6.2 6 35221 12 7.0 PPA 150.4 35 4.3 YF125ST 4833 CarboLite16/20 7.2 7 34144 13 8.0 PPA 208.8 34.9 6 YF125ST 6541 CarboLite16/20 8.3 7.7 51328 14 LG Flush 108.5 34.3 3.2 WF125 4565 CarboLite16/20 3.7 0 20 15 Freeze Protect 65.5 20.1 3.3 FreezeProtect 2751 0 0 0 Stage Pressures & Rates Step#StepName Average Slurry Rate (bbl/min) MaximumSlurry Rate (bbl/min) AverageTreating Pressure (psi) MaximumTreating Pressure (psi) MinimumTreating Pressure (psi) 1 PAD st9 40.1 40.3 3249 3653 1643 2 Slow For Seat 18.8 34.6 2012 2133 1002 3 ResumePAD 21.3 30.9 2206 2824 893 4 2nd Ball to seat 7.0 19.9 1469 2055 1094 5 ResumePAD 34.4 35.5 3264 3658 2055 6 1.0 PPA 35.0 35.3 3153 3195 3113 7 2.0 PPA 35.1 35.3 2940 3159 2847 8 3.0 PPA 35.0 35.5 2803 2875 2756 9 4.0 PPA 35.0 35.3 2735 2779 2701 10 5.0 PPA 34.9 35.1 2674 2724 2637 11 6.0 PPA 35.1 35.2 2633 2682 2591 12 7.0 PPA 35.0 35.3 2580 2605 2554 13 8.0 PPA 34.9 36.3 2650 2834 2531 14 LG Flush 34.3 36.3 2705 2879 1936 15 FreezeProtect 20.1 22.9 1978 2133 984 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Displacement PT, Ball to Seat andPump Check Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 9:12:28 Priming Pumps With Diesel 5 0 0.0 0.0 0.0 2 10:08:31 Low Pressure Test 577 0 0.0 0.0 0.0 3 10:16:24 MidPressure Test 5003 0 0.0 0.0 0.0 4 10:23:25 HighPressureTest 9448 0 0.0 0.0 0.0 5 10:28:18 Good PT 9105 5 0.0 0.0 0.0 6 10:59:14 LR Testing PRV's 1570 0 0.0 0.0 0.0 7 13:24:32 Finished Safety Meeting 1648 0 0.0 0.0 0.0 8 13:32:47 Radio Check 1671 430 0.0 0.0 0.0 9 13:35:23 LR bump up the pressure to 3200psi 1680 1337 0.0 0.0 0.0 10 13:44:30 Open Well 316 3200 0.0 0.0 0.0 11 13:45:28 Start Displace PT Automatically 325 3195 0.0 0.0 0.0 12 13:45:28 Start Propped Frac Automatically 325 3195 0.0 0.0 0.0 13 13:45:28 Start Pump Check Automatically 325 3195 0.0 0.0 0.0 14 13:45:35 Started Pumping 320 3191 0.0 0.0 0.0 15 13:57:43 Start Ball to Seat Automatically 526 3104 40.0 3.5 0.0 16 13:57:47 StoppedPumping 453 3104 40.2 0.8 0.0 17 13:58:44 Shutdown for 10 min 343 3094 40.2 0.0 0.0 18 14:06:43 Radio check 311 3223 40.2 0.0 0.0 19 14:08:59 Started Pumping 572 3236 40.2 0.1 0.0 20 14:54:14 Ball Seated 842 3474 221.1 4.0 0.0 21 14:54:26 Start Pump Check Manually 856 3474 221.9 4.0 0.0 22 14:56:28 Stage at Perfs: Displace PT 3680 3484 254.5 29.1 0.0 23 14:57:33 Stage at Perfs: Ball to Seat 4500 3213 294.6 40.1 0.0 Stage 6 Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:57:54 Start PAD st6 Manually 4326 3223 0.0 40.2 0.0 2 14:57:54 Start Propped Frac Manually 4326 3223 0.0 40.2 0.0 3 14:57:54 Start Stage6 Automatically 4326 3223 0.0 40.2 0.0 4 15:02:06 Stage at Perfs: Pump Check 3987 3401 168.2 40.0 0.0 5 15:04:09 Start 1.0 PPA Automatically 3799 3209 250.4 40.3 0.0 6 15:04:09 StartedPumping Prop 3799 3209 250.4 40.3 0.0 7 15:04:15 Stage at Perfs: PAD st6 3786 3218 254.4 40.2 0.0 8 15:05:24 Start 3.0 PPA Automatically 3662 3259 300.4 40.1 1.0 9 15:08:43 Start Resume PAD Manually 3497 3369 433.0 40.0 0.1 10 15:08:47 StoppedPumping Prop 3488 3374 435.7 39.8 -0.0 11 15:09:27 Stage at Perfs: 1.0 PPA 3571 3355 462.3 40.0 0.0 12 15:09:59 Start 1.0 PPA Automatically 3639 3204 483.7 40.0 0.0 13 15:09:59 StartedPumping Prop 3639 3204 483.7 40.0 0.0 14 15:10:42 Stage at Perfs: 3.0 PPA 3694 3223 512.1 39.5 0.9 15 15:14:02 Stage at Perfs: Resume PAD 3548 3319 645.1 40.0 1.0 16 15:14:29 Start 2.0 PPA Automatically 3433 3328 663.1 40.2 1.0 17 15:15:18 Stage at Perfs: 1.0 PPA 3456 3351 695.7 39.9 2.0 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 18 15:19:47 Stage at Perfs: 2.0 PPA 3392 3241 874.9 40.0 2.0 19 15:20:00 Start 4.0 PPA Automatically 3401 3246 883.5 40.0 2.0 20 15:25:18 Stage at Perfs: 4.0 PPA 3433 3346 1095.1 40.0 3.9 21 15:26:00 Start 6.0 PPA Automatically 3488 3314 1123.1 40.0 4.0 22 15:31:18 Stage at Perfs: 6.0 PPA 3694 3259 1334.7 40.1 5.9 23 15:32:01 Start 8.0 PPA Automatically 3763 3264 1363.4 40.0 6.2 24 15:37:19 Stage at Perfs: 8.0 PPA 4752 3342 1575.0 40.0 8.0 25 15:38:01 Start 10.0 PPA Automatically 4889 3351 1603.0 39.7 8.1 26 15:43:20 Stage at Perfs: 10.0 PPA 5603 3241 1814.9 40.3 3.8 27 15:43:29 Start Clean lines & Spacer Manually 5644 3241 1821.1 41.4 0.3 28 15:43:32 StoppedPumping Prop 5630 3241 1823.1 41.6 0.1 29 15:44:08 Start Stage7 Automatically 5026 3236 0.0 39.7 0.0 30 15:44:11 Start Drop Collet#7 Manually 5012 3236 0.0 39.7 0.0 Stage 7 Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 15:44:16 Start PAD st7 Automatically 5035 3236 0.0 39.8 0.0 2 15:44:16 Start Propped Frac Automatically 5035 3236 0.0 39.8 0.0 3 15:44:16 Start Stage7 Automatically 5035 3236 0.0 39.8 0.0 4 15:48:01 Start Slow For Seat Automatically 1625 3195 149.7 32.2 0.0 5 15:49:35 Stage at Perfs: Clean lines & Spacer 2467 3223 179.3 18.0 0.0 6 15:50:01 Ball & Collet Seated 3571 3273 187.1 18.0 0.0 7 15:51:06 Stage at Perfs: Drop Collet#7 4916 3342 206.3 17.8 0.0 8 15:51:37 Start Resume PAD Manually 4926 3355 215.4 17.9 0.0 9 15:53:15 Start 1.0 PPA Manually 5159 3186 261.9 38.1 0.0 10 15:53:15 StartedPumping Prop 5159 3186 261.9 38.1 0.0 11 15:54:31 Start 3.0 PPA Automatically 5058 3223 312.3 39.7 1.0 12 15:57:11 Stage at Perfs: PAD st7 4015 3218 418.9 40.0 2.9 13 15:58:09 Start Resume PAD Manually 3772 3213 457.7 40.5 0.4 14 15:58:12 StoppedPumping Prop 3740 3213 459.8 40.4 0.1 15 15:58:20 Stage at Perfs: Slow For Seat 3726 3213 465.1 40.2 0.0 16 15:59:36 Stage at Perfs: Resume PAD 3369 3200 515.8 39.9 0.0 17 16:01:10 Start 1.0 PPA Manually 2975 3200 578.4 40.0 0.0 18 16:01:15 StartedPumping Prop 2989 3200 581.8 40.0 0.0 19 16:03:15 Stage at Perfs: 1.0 PPA 2760 3213 661.5 39.9 1.1 20 16:05:41 Start 2.0 PPA Automatically 2820 3236 758.8 39.9 1.0 21 16:06:16 Stage at Perfs: 3.0 PPA 2806 3241 782.0 39.8 2.0 22 16:10:47 Stage at Perfs: Resume PAD 2875 3264 962.6 40.1 2.0 23 16:10:56 Start 4.0 PPA Automatically 2902 3264 968.6 40.1 2.0 24 16:16:02 Stage at Perfs: 1.0 PPA 2916 3291 1172.0 39.9 4.0 25 16:16:42 Start 6.0 PPA Automatically 2902 3291 1198.7 40.1 3.9 26 16:21:48 Stage at Perfs: 2.0 PPA 3131 3305 1402.3 39.9 6.1 27 16:22:28 Start 8.0 PPA Automatically 3223 3305 1428.8 40.2 5.9 28 16:27:33 Stage at Perfs: 4.0 PPA 3983 3333 1632.2 39.5 8.3 29 16:28:13 Start 10.0 PPA Automatically 4024 3181 1658.7 40.3 8.0 30 16:33:07 Start Clean lines & Spacer Manually 4660 3209 1854.2 41.7 0.2 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 31 16:33:10 StoppedPumpingProp 4628 3213 1856.3 41.9 -0.0 32 16:33:19 Stage at Perfs: 6.0 PPA 4605 3209 1862.5 41.6 0.0 33 16:33:50 Start Drop Collet#8 Manually 4106 3200 1883.3 39.6 0.0 Stage 8 Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 16:33:55 Start PAD st8 Automatically 4120 3204 0.0 39.7 0.0 2 16:33:55 Start Propped Frac Automatically 4120 3204 0.0 39.7 0.0 3 16:33:55 Start Stage8 Automatically 4120 3204 0.0 39.7 0.0 4 16:37:28 Start Slow For Seat Automatically 1694 3177 142.1 38.2 0.0 5 16:38:55 Stage at Perfs: 8.0 PPA 2124 3200 170.8 17.9 0.0 6 16:39:29 Ball & Collet Seated 3300 3255 181.0 18.2 0.0 7 16:40:30 Start Resume PAD Manually 4500 3319 199.2 17.8 0.0 8 16:40:32 Stage at Perfs: 10.0 PPA 4555 3319 199.8 18.8 0.0 9 16:40:42 Stage at Perfs: Clean lines & Spacer 4820 3323 203.3 21.9 0.0 10 16:41:34 Start 1.0 PPA Manually 5580 3369 231.0 38.6 0.0 11 16:41:34 StartedPumping Prop 5580 3369 231.0 38.6 0.0 12 16:42:50 Start 3.0 PPA Automatically 4825 3140 281.7 39.9 1.0 13 16:44:14 Stage at Perfs: Drop Collet8 3726 3090 337.7 40.0 3.1 14 16:45:21 Start Resume PAD Manually 3506 3099 382.5 40.5 0.1 15 16:45:26 StoppedPumping Prop 3461 3099 385.9 40.3 0.1 16 16:45:39 Stage at Perfs: PAD st8 3397 3099 394.6 40.0 0.0 17 16:46:27 Stage at Perfs: Slow For Seat 3484 3099 426.5 39.9 0.0 18 16:47:43 Stage at Perfs: Resume PAD 3072 3094 477.1 39.9 0.0 19 16:47:52 Start 1.0 PPA Manually 3049 3094 483.1 40.0 0.0 20 16:47:55 StartedPumping Prop 3035 3094 485.1 40.0 0.0 21 16:50:15 Stage at Perfs: 1.0 PPA 2806 3108 578.1 39.9 1.0 22 16:52:23 Start 2.0 PPA Automatically 2765 3122 663.3 39.9 1.0 23 16:52:46 Stage at Perfs: 3.0 PPA 2733 3122 678.6 39.7 2.0 24 16:57:16 Stage at Perfs: Resume PAD 2582 3136 858.9 40.3 2.0 25 16:57:53 Start 4.0 PPA Manually 2605 3136 883.6 40.0 2.0 26 17:02:46 Stage at Perfs: 1.0 PPA 2641 3131 1078.8 39.8 4.0 27 17:03:54 Start 6.0 PPA Manually 2664 3122 1124.1 40.0 4.1 28 17:08:48 Stage at Perfs: 2.0 PPA 3030 3085 1319.6 40.1 6.0 29 17:09:55 Start 8.0 PPA Manually 3058 3076 1364.3 40.0 6.0 30 17:14:48 Stage at Perfs: 4.0 PPA 3877 3085 1559.8 40.3 8.0 31 17:15:55 Start 10.0 PPA Manually 3772 3085 1604.7 40.1 8.0 32 17:20:49 Stage at Perfs: 6.0 PPA 4234 3094 1800.1 40.1 10.2 33 17:21:16 Start Clean lines & Spacer Manually 3960 3090 1818.3 41.2 0.1 34 17:21:18 StoppedPumping Prop 3923 3085 1819.7 41.0 0.0 35 17:21:59 Start Drop Collet9 Manually 3653 3090 1847.0 40.1 0.0 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates Stage 9 Job Messages MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 17:22:04 Start PAD st9 Automatically 3653 3090 0.0 40.1 0.0 2 17:22:04 Start Propped Frac Automatically 3653 3090 0.0 40.1 0.0 3 17:22:04 Start Stage9 Automatically 3653 3090 0.0 40.1 0.0 4 17:25:34 Start Slow For Seat Manually 1781 3062 139.8 28.2 0.0 5 17:26:49 Stage at Perfs: 8.0 PPA 2037 3085 163.1 17.9 0.0 6 17:28:24 Stage at Perfs: 10.0 PPA 2129 3099 191.5 18.0 0.0 7 17:28:36 Stage at Perfs: Clean lines & Spacer 2133 3099 195.1 17.9 0.0 8 17:28:53 Start Resume PAD Automatically 1002 3076 198.8 0.0 0.0 9 17:28:54 StoppedPumping 993 3090 198.8 0.0 0.0 10 17:29:31 Waiting when completion check indication of Ball/Colled#9 shiftedthe sleeve 980 3067 198.8 0.0 0.0 11 17:32:57 Started Pumping 938 3040 198.8 0.0 0.0 12 17:38:18 rate 30bpm 2458 3104 299.5 22.7 0.0 13 17:39:34 StoppedPumping 1012 3062 323.8 0.0 0.0 14 17:40:10 Willlaunchadditional ball 989 3058 323.8 0.0 0.0 15 17:57:13 Ball Loaded 897 3246 323.8 0.0 0.0 16 17:58:12 Ball Launched 1231 3241 323.8 0.0 0.0 17 17:59:06 Started Pumping 1149 3232 323.8 0.0 0.0 18 17:59:13 Start Resume PAD Manually 1662 3236 324.0 2.8 0.0 19 18:00:00 Stage at Perfs: Drop Collet#9 1611 3236 327.1 4.0 0.0 20 18:00:28 Pumping Ball to Seat 1726 3236 329.0 4.0 0.0 21 18:14:49 Stage at Perfs: PAD st9 1337 3209 386.3 4.0 0.0 22 18:34:19 rate 20bpm 1122 3163 464.3 4.0 0.0 23 18:35:06 Ball Seated 1776 3186 474.7 19.9 0.0 24 18:36:29 Start Resume PAD Manually 2069 3195 502.1 19.8 0.0 25 18:36:54 Stage at Perfs: PAD st9 2884 3227 511.9 29.2 0.0 26 18:42:04 Stage at Perfs: PAD st9 3213 3296 690.2 35.0 0.0 27 18:46:29 Start 1.0 PPA Manually 3163 3342 844.8 35.0 0.0 28 18:46:29 StartedPumping Prop 3163 3342 844.8 35.0 0.0 29 18:51:37 Start 2.0 PPA Manually 3145 3392 1024.6 35.2 1.0 30 18:51:51 Stage at Perfs: Slow For Seat 3108 3387 1032.8 35.0 2.0 31 18:56:45 Start 3.0 PPA Manually 2847 3406 1204.5 35.0 2.0 32 18:56:58 Stage at Perfs: Resume PAD 2852 3406 1212.1 35.0 2.9 33 19:02:07 Stage at Perfs: Resume PAD 2765 3415 1392.5 35.1 3.0 34 19:02:11 Start 4.0 PPA Manually 2747 3415 1394.8 35.1 3.0 35 19:07:32 Stage at Perfs: Resume PAD 2701 3401 1582.3 35.1 4.1 36 19:07:37 Start 5.0 PPA Manually 2705 3401 1585.3 35.0 4.0 37 19:13:00 Stage at Perfs: 1.0 PPA 2660 3383 1773.2 35.2 4.9 38 19:13:03 Start 6.0 PPA Manually 2664 3383 1775.0 35.2 4.9 39 19:18:02 Start 7.0 PPA Manually 2596 3378 1949.8 35.0 6.1 40 19:18:24 Stage at Perfs: 2.0 PPA 2591 3378 1962.6 35.0 6.9 41 19:22:20 Start 8.0 PPA Manually 2559 3374 2100.2 35.0 7.0 42 19:23:24 Stage at Perfs: 3.0 PPA 2559 3369 2137.4 34.8 7.7 43 19:27:43 Stage at Perfs: 4.0 PPA 2774 3374 2287.7 34.7 8.0 44 19:28:19 Start LG Flush Manually 2747 3374 2309.0 35.8 0.0 45 19:30:43 StoppedPumping Prop 2815 3387 2393.7 35.2 0.0 46 19:31:32 Start Freeze Protect Manually 1941 3365 2417.5 22.0 0.0 47 19:34:51 StoppedPumping 984 3355 2482.9 0.0 0.0 Client: Santos Well:NDBi-014 Formation:Nanushuk District:Pikka Country:UnitedStates MessageLog #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 48 19:40:33 Close Well 1163 3278 2482.9 0.0 0.0 49 19:43:55 FanningOut Pumps.0 3241 2482.9 35.8 0.0 50 20:13:05 Blow down the line 23 3030 2482.9 8.1 0.0 Santos Definitive Survey Report14 February, 2024Design: NDBi-014Santos NAD27 ConversionPikkaNDBNDBi014NDBi014 ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMap 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-014usftusft0.00.05,972,844.34422,462.7722.8Wellhead Elevation:usft0.970° 20' 9.402 N150° 37' 44.668 WWellboreDeclinationField StrengthnTSample Date Dip AngleNDBi-014Model NameMagneticsBGGM2023 31/12/2023 14.41 80.58 57,175.92127402PhaseVersionAudit NotesDesignNDBi-0141.0 ACTUALVertical SectionDepth From TVDusft/-usftDirection/-usftTie On Depth46.9273.690.00.046.914022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueFromusftSurvey ProgramDescriptionTool NameSurvey WellboreTousftDate14/02/2024SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)113.1 629.501 SDI URSA GyroMWD 16in Hole 46623_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag697.1 2,495.602 BH Ontrak16in Hole 6972495> NDB3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,602.8 3,617.003 BH Ontrak1225in Hole 26023617> 3_MWD+Sag A002Mb/ISC4: BGGM dec + sag corrections3,711.8 3,806.404 BH OntraKk1225in Hole 37113806>3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag3,901.6 10,406.105 BH OntraKk1225in Hole 3901104063_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag10,468.5 15,409.006 BH Ontrakin Hole 10468 - 15409>MDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft46.9 0.00 0.00 46.9 -22.8 0.0 0.0 5,972,844.34 422,462.77 0.00 0.0113.1 0.25 134.30 113.1 43.4 -0.1 0.1 5,972,844.24 422,462.87 0.38 -0.1128.0 0.22 137.47 128.0 58.3 -0.1 0.1 5,972,844.19 422,462.91 0.23 -0.220" Conductor Driven207.2 0.09 192.30 207.2 137.5 -0.3 0.2 5,972,844.02 422,463.00 0.23 -0.3279.4 0.59 169.45 279.3 209.6 -0.7 0.3 5,972,843.60 422,463.05 0.70 -0.3374.5 3.02 170.51 374.4 304.7 -3.7 0.8 5,972,840.64 422,463.53 2.55 -1.0468.6 3.90 169.80 468.4 398.7 -9.3 1.8 5,972,835.03 422,464.44 0.94 -2.4562.5 5.24 170.51 562.0 492.3 -16.7 3.0 5,972,827.65 422,465.64 1.43 -4.1629.5 5.31 172.97 628.7 559.0 -22.8 3.9 5,972,821.55 422,466.46 0.35 -5.4697.1 7.83 187.04 695.8 626.1 -30.4 3.7 5,972,813.88 422,466.20 4.40 -5.7791.9 8.57 197.93 789.7 720.0 -43.6 0.8 5,972,800.78 422,463.10 1.81 -3.6885.3 10.76 201.60 881.7 812.0 -58.3 -4.6 5,972,786.11 422,457.59 2.44 0.8980.0 12.63 203.62 974.5 904.8 -76.0 -12.0 5,972,768.47 422,450.01 2.02 7.11,043.0 11.61204.141,036.1 966.4 -88.1 -17.3 5,972,756.44 422,444.53 1.64 11.6Upper Schrader Bluff1,074.7 11.09 204.43 1,067.2 997.5 -93.8 -19.9 5,972,750.79 422,441.911.6413.81,169.0 11.69 205.22 1,159.6 1,089.9 -110.7 -27.7 5,972,733.97 422,433.92 0.66 20.5Base Ice Bearing Permafrost14022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft1,169.3 11.69 205.22 1,159.9 1,090.2 -110.7 -27.7 5,972,733.92 422,433.89 0.66 20.61,264.2 15.07 206.83 1,252.2 1,182.5 -130.4 -37.4 5,972,714.31 422,424.02 3.58 28.91,359.6 17.95 208.41 1,343.7 1,274.0 -154.5 -50.0 5,972,690.43 422,411.17 3.05 40.01,406.0 19.37 208.29 1,387.6 1,317.9 -167.5 -57.0 5,972,677.45 422,404.00 3.06 46.1Base Permafrost Transition1,454.1 20.84 208.19 1,432.8 1,363.1 -182.1 -64.9 5,972,662.96 422,396.02 3.06 53.01,549.0 23.66 209.70 1,520.6 1,450.9 -213.5 -82.3 5,972,631.72 422,378.28 3.03 68.41,644.5 26.51 212.59 1,607.11,537.4-248.1 -103.3 5,972,597.33 422,356.95 3.25 87.11,738.7 29.26 213.61 1,690.3 1,620.6 -285.0 -127.3 5,972,560.72 422,332.52 2.96 108.71,796.0 30.71 214.02 1,740.0 1,670.3 -308.8 -143.3 5,972,537.08 422,316.32 2.55 123.1Middle Schrader Bluff1,832.8 31.64 214.27 1,771.5 1,701.8 -324.6 -154.0 5,972,521.40 422,305.46 2.55 132.81,927.5 34.40216.141,850.9 1,781.2 -366.7 -183.7 5,972,479.60 422,275.27 3.11 159.72,022.6 38.69 217.99 1,927.2 1,857.5 -411.8 -217.9 5,972,434.83 422,240.66 4.66 190.92,116.9 42.40 216.89 1,998.9 1,929.2 -460.5 -255.1 5,972,386.52 422,202.91 4.00 225.02,211.3 45.57 216.17 2,066.9 1,997.2 -513.2 -294.2 5,972,334.24 422,163.35 3.40 260.52,306.6 48.51 216.27 2,131.7 2,062.0 -569.4 -335.3 5,972,278.46 422,121.60 3.09 298.02,345.0 49.70 216.73 2,156.9 2,087.2 -592.8 -352.6 5,972,255.29 422,104.08 3.23 313.7MCU2,401.3 51.45 217.37 2,192.7 2,123.0 -627.5 -378.8 5,972,220.84 422,077.50 3.23 337.62,495.6 53.89 218.78 2,249.8 2,180.1 -686.5 -425.1 5,972,162.35 422,030.68 2.85 380.02,563.8 55.07 219.04 2,289.5 2,219.8 -729.7 -459.9 5,972,119.51 421,995.37 1.75 412.013-3/8" Surface Casing2,602.8 55.74 219.18 2,311.6 2,241.9 -754.6 -480.2 5,972,094.81 421,974.86 1.75 430.62,669.7 57.93 219.89 2,348.2 2,278.5 -797.8 -515.8 5,972,052.03 421,938.79 3.39 463.42,764.5 60.44 220.20 2,396.8 2,327.1 -860.1 -568.2 5,971,990.22 421,885.74 2.66 511.72,859.1 63.38 220.80 2,441.3 2,371.6 -923.5 -622.4 5,971,927.39 421,830.94 3.16 561.614022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft2,886.0 64.16 220.95 2,453.2 2,383.5 -941.8 -638.2 5,971,909.27 421,814.93 2.94 576.2Tuluvak Shale2,955.4 66.17 221.32 2,482.3 2,412.6 -989.2 -679.6 5,971,862.27 421,773.01 2.94 614.53,048.4 68.48 221.36 2,518.2 2,448.5 -1,053.7 -736.3 5,971,798.45 421,715.68 2.48 666.93,056.0 68.67 221.38 2,521.0 2,451.3 -1,059.0 -741.0 5,971,793.19 421,710.95 2.55 671.3Tuluvak Sand3,143.0 70.89 221.55 2,551.0 2,481.3 -1,120.2 -795.1 5,971,732.55 421,656.25 2.55 721.33,238.4 72.80 221.92 2,580.8 2,511.1 -1,187.8 -855.4 5,971,665.54 421,595.21 2.04 777.13,335.1 72.92 221.90 2,609.2 2,539.5 -1,256.5 -917.1 5,971,597.47 421,532.83 0.13 834.33,429.7 72.86 222.02 2,637.12,567.4-1,323.8 -977.6 5,971,530.84 421,471.66 0.14 890.33,522.0 72.92 221.91 2,664.2 2,594.5 -1,389.4 -1,036.6 5,971,465.87 421,412.01 0.13 944.93,617.0 72.88 221.70 2,692.2 2,622.5 -1,457.1 -1,097.1 5,971,398.83 421,350.80 0.22 1,001.03,711.8 72.86 221.79 2,720.12,650.4-1,524.6 -1,157.4 5,971,331.88 421,289.80 0.09 1,056.83,806.472.88 221.77 2,748.0 2,678.3 -1,592.1 -1,217.7 5,971,265.06 421,228.84 0.03 1,112.63,901.6 72.92 222.08 2,775.9 2,706.2 -1,659.8 -1,278.4 5,971,198.01 421,167.36 0.31 1,168.93,996.473.12 221.71 2,803.6 2,733.9 -1,727.2 -1,338.9 5,971,131.19 421,106.16 0.43 1,225.04,090.6 73.18 221.66 2,830.9 2,761.2 -1,794.6 -1,398.9 5,971,064.48 421,045.51 0.08 1,280.54,185.3 73.21 221.33 2,858.3 2,788.6 -1,862.5 -1,459.0 5,970,997.20 420,984.74 0.34 1,336.04,280.5 73.44 221.69 2,885.6 2,815.9 -1,930.8 -1,519.4 5,970,929.56 420,923.62 0.44 1,391.94,375.3 73.37 221.70 2,912.7 2,843.0 -1,998.6 -1,579.8 5,970,862.37 420,862.51 0.07 1,447.94,469.9 73.43 222.15 2,939.7 2,870.0 -2,066.1 -1,640.4 5,970,795.53 420,801.23 0.46 1,504.04,564.6 73.37 222.38 2,966.8 2,897.1 -2,133.2 -1,701.5 5,970,729.00 420,739.49 0.24 1,560.64,659.2 73.30 223.10 2,993.9 2,924.2 -2,199.8 -1,763.0 5,970,663.10 420,677.33 0.73 1,617.74,754.6 73.30 222.85 3,021.3 2,951.6 -2,266.7 -1,825.3 5,970,596.88 420,614.33 0.25 1,675.54,849.0 73.44 222.33 3,048.3 2,978.6 -2,333.3 -1,886.5 5,970,530.93 420,552.44 0.55 1,732.34,944.0 73.41 222.27 3,075.5 3,005.8 -2,400.6 -1,947.8 5,970,464.23 420,490.48 0.07 1,789.25,038.5 73.44 222.19 3,102.4 3,032.7 -2,467.7 -2,008.6 5,970,397.80 420,428.92 0.09 1,845.614022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft5,112.0 73.46 221.97 3,123.3 3,053.6 -2,519.9 -2,055.8 5,970,346.02 420,381.18 0.28 1,889.3Seabee5,133.4 73.47 221.91 3,129.4 3,059.7 -2,535.2 -2,069.5 5,970,330.94 420,367.34 0.28 1,902.05,228.3 73.31 222.08 3,156.6 3,086.9 -2,602.8 -2,130.4 5,970,263.94 420,305.76 0.24 1,958.45,322.5 73.18 221.59 3,183.7 3,114.0 -2,670.0 -2,190.6 5,970,197.37 420,244.91 0.52 2,014.15,417.2 73.25 221.30 3,211.1 3,141.4 -2,738.0 -2,250.6 5,970,130.03 420,184.20 0.30 2,069.65,512.0 73.27 220.84 3,238.4 3,168.7 -2,806.4 -2,310.2 5,970,062.23 420,123.87 0.47 2,124.75,606.6 73.27 220.79 3,265.6 3,195.9 -2,875.0 -2,369.4 5,969,994.29 420,063.96 0.05 2,179.45,702.0 73.08 220.52 3,293.2 3,223.5 -2,944.2 -2,428.9 5,969,925.67 420,003.79 0.34 2,234.35,796.9 73.05 220.90 3,320.8 3,251.1 -3,013.0 -2,488.1 5,969,857.48 419,943.87 0.38 2,288.95,891.0 73.02 220.93 3,348.3 3,278.6 -3,081.1 -2,547.1 5,969,790.04 419,884.19 0.04 2,343.45,985.8 72.99 221.58 3,376.0 3,306.3 -3,149.2 -2,606.9 5,969,722.54 419,823.74 0.66 2,398.76,081.6 72.99 222.35 3,404.0 3,334.3 -3,217.3 -2,668.1 5,969,655.06 419,761.78 0.77 2,455.46,174.6 73.05 223.05 3,431.2 3,361.5 -3,282.7 -2,728.5 5,969,590.31 419,700.78 0.72 2,511.46,269.8 73.01 223.35 3,459.0 3,389.3 -3,349.1 -2,790.8 5,969,524.61 419,637.79 0.30 2,569.36,363.2 73.05 224.19 3,486.2 3,416.5 -3,413.6 -2,852.5 5,969,460.76 419,575.35 0.86 2,626.86,460.1 73.14 224.41 3,514.4 3,444.7 -3,480.0 -2,917.3 5,969,395.06 419,509.89 0.24 2,687.26,554.8 73.04 224.04 3,542.0 3,472.3 -3,544.9 -2,980.5 5,969,330.78 419,446.02 0.39 2,746.16,649.0 73.37224.243,569.2 3,499.5 -3,609.6 -3,043.3 5,969,266.74 419,382.58 0.41 2,804.66,743.7 73.47 223.90 3,596.2 3,526.5 -3,674.8 -3,106.5 5,969,202.18 419,318.77 0.36 2,863.46,838.5 73.46 222.58 3,623.2 3,553.5 -3,741.0 -3,168.7 5,969,136.61 419,255.83 1.33 2,921.36,933.8 73.37 223.12 3,650.4 3,580.7 -3,808.0 -3,230.8 5,969,070.32 419,193.05 0.55 2,978.97,028.6 73.21 222.71 3,677.7 3,608.0 -3,874.5 -3,292.7 5,969,004.46 419,130.53 0.45 3,036.47,123.3 72.86 224.56 3,705.3 3,635.6 -3,940.0 -3,355.1 5,968,939.61 419,067.41 1.91 3,094.57,217.8 72.79 228.02 3,733.2 3,663.5 -4,002.4 -3,420.4 5,968,877.91 419,001.51 3.50 3,155.67,313.3 72.89 230.69 3,761.4 3,691.7 -4,061.8 -3,489.6 5,968,819.21 418,931.68 2.67 3,220.87,407.6 72.92 232.04 3,789.1 3,719.4 -4,118.1 -3,560.0 5,968,763.66 418,860.70 1.37 3,287.514022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft7,502.1 72.77234.343,817.0 3,747.3 -4,172.2 -3,632.3 5,968,710.33 418,787.88 2.33 3,356.17,596.8 72.89 236.48 3,844.9 3,775.2 -4,223.6 -3,706.8 5,968,659.72 418,712.83 2.16 3,427.27,677.0 72.81 239.05 3,868.6 3,798.9 -4,264.4 -3,771.6 5,968,619.53 418,647.62 3.06 3,489.2Nanushuk7,691.8 72.80 239.52 3,873.0 3,803.3 -4,271.7 -3,783.8 5,968,612.43 418,635.38 3.06 3,500.97,740.0 72.79 240.80 3,887.2 3,817.5 -4,294.6 -3,823.7 5,968,589.94 418,595.22 2.54 3,539.3NT8 MFS7,786.7 72.79 242.04 3,901.1 3,831.4 -4,315.9 -3,862.9 5,968,569.00 418,555.82 2.54 3,577.07,807.0 72.79 242.86 3,907.13,837.4-4,324.9 -3,880.1 5,968,560.22 418,538.55 3.85 3,593.6NT7 MFS7,881.3 72.83 245.85 3,929.0 3,859.3 -4,355.6 -3,944.1 5,968,530.16 418,474.27 3.85 3,655.47,975.9 73.37 249.22 3,956.5 3,886.8 -4,390.2 -4,027.7 5,968,496.45 418,390.28 3.46 3,736.78,070.473.49 252.49 3,983.5 3,913.8 -4,419.9 -4,113.3 5,968,467.63 418,304.41 3.32 3,820.18,133.0 73.89255.344,001.13,931.4-4,436.5 -4,171.0 5,968,451.60 418,246.56 4.42 3,876.6NT6 MFS8,165.7 74.11 256.83 4,010.1 3,940.4 -4,444.1 -4,201.5 5,968,444.36 418,215.97 4.42 3,906.68,260.6 74.52 260.08 4,035.7 3,966.0 -4,462.3 -4,290.9 5,968,427.01 418,126.33 3.33 3,994.78,355.5 74.62 263.23 4,061.0 3,991.3 -4,475.6 -4,381.5 5,968,414.67 418,035.65 3.20 4,084.28,450.0 75.54 265.62 4,085.3 4,015.6 -4,484.5 -4,472.3 5,968,406.75 417,944.72 2.63 4,174.3NT5 MFS8,450.3 75.54 265.63 4,085.4 4,015.7 -4,484.5 -4,472.7 5,968,406.73 417,944.40 2.63 4,174.68,544.0 75.48 268.03 4,108.9 4,039.2 -4,489.5 -4,563.2 5,968,402.65 417,853.78 2.48 4,264.78,639.5 76.57 270.44 4,131.9 4,062.2 -4,490.8 -4,655.9 5,968,402.37 417,761.11 2.70 4,357.18,734.2 76.84 273.03 4,153.7 4,084.0 -4,488.0 -4,748.0 5,968,406.11 417,669.09 2.68 4,449.28,785.0 77.30 274.23 4,165.14,095.4-4,484.8 -4,797.4 5,968,409.76 417,619.72 2.48 4,498.7NT4 MFS8,830.1 77.72 275.29 4,174.8 4,105.1 -4,481.2 -4,841.2 5,968,413.86 417,575.90 2.48 4,542.78,923.8 77.72 278.40 4,194.8 4,125.1 -4,470.3 -4,932.2 5,968,425.72 417,485.07 3.24 4,634.114022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft9,018.6 78.21 282.43 4,214.5 4,144.8 -4,453.5 -5,023.4 5,968,443.42 417,394.10 4.19 4,726.29,113.6 78.25 285.85 4,233.9 4,164.2 -4,430.8 -5,113.5 5,968,467.06 417,304.20 3.53 4,817.69,208.2 79.37 288.02 4,252.3 4,182.6 -4,403.8 -5,202.3 5,968,495.01 417,215.71 2.54 4,908.09,303.0 80.25 290.10 4,269.0 4,199.3 -4,373.3 -5,290.4 5,968,526.36 417,127.93 2.35 4,997.89,396.5 81.09 293.18 4,284.2 4,214.5 -4,339.3 -5,376.2 5,968,561.26 417,042.55 3.37 5,085.69,492.1 81.84 296.28 4,298.4 4,228.7 -4,299.7 -5,462.1 5,968,601.72 416,957.05 3.30 5,173.99,586.2 82.94 299.02 4,310.9 4,241.2 -4,256.4 -5,544.7 5,968,645.85 416,874.90 3.11 5,259.19,680.9 83.91 301.44 4,321.7 4,252.0 -4,209.1 -5,626.0 5,968,694.06 416,794.11 2.74 5,343.39,776.6 83.79 303.77 4,332.0 4,262.3 -4,157.8 -5,706.1 5,968,746.15 416,714.49 2.42 5,426.69,870.9 83.88 305.77 4,342.1 4,272.4 -4,104.4 -5,783.1 5,968,800.36 416,638.11 2.11 5,506.89,965.6 84.81 309.29 4,351.4 4,281.7 -4,047.0 -5,857.8 5,968,858.54 416,563.97 3.83 5,585.110,018.0 85.76 310.92 4,355.7 4,286.0 -4,013.3 -5,897.8 5,968,892.59 416,524.38 3.58 5,627.1NT3 MFS10,060.8 86.53 312.24 4,358.6 4,288.9 -3,985.0 -5,929.7 5,968,921.26 416,492.73 3.58 5,660.810,155.0 88.11 315.57 4,363.0 4,293.3 -3,919.7 -5,997.5 5,968,987.19 416,425.64 3.91 5,732.710,250.4 88.22 319.40 4,366.14,296.4-3,849.5 -6,061.9 5,969,058.10 416,361.96 4.02 5,801.510,346.2 88.83 322.19 4,368.5 4,298.8 -3,775.3 -6,122.4 5,969,132.91 416,302.22 2.98 5,866.610,406.1 89.05 323.71 4,369.6 4,299.9 -3,727.4 -6,158.5 5,969,181.12 416,266.60 2.56 5,905.810,440.0 89.20 323.43 4,370.2 4,300.5 -3,700.2 -6,178.7 5,969,208.57 416,246.77 0.95 5,927.69-5/8" Intermediate Liner10,447.0 89.23 323.37 4,370.3 4,300.6 -3,694.6 -6,182.8 5,969,214.23 416,242.65 0.95 5,932.1NT3.2 Top Reservoir10,468.5 89.33 323.19 4,370.5 4,300.8 -3,677.3 -6,195.7 5,969,231.60 416,229.97 0.95 5,946.110,546.2 90.10 325.01 4,370.9 4,301.2 -3,614.4 -6,241.2 5,969,295.00 416,185.07 2.54 5,995.610,640.4 91.60 327.44 4,369.5 4,299.8 -3,536.1 -6,293.6 5,969,373.80 416,133.54 3.03 6,052.910,735.7 91.97 327.97 4,366.6 4,296.9 -3,455.6 -6,344.5 5,969,454.80 416,083.51 0.68 6,108.810,830.9 91.94 327.81 4,363.3 4,293.6 -3,375.0 -6,395.1 5,969,535.94 416,033.75 0.17 6,164.510,926.3 91.97 329.09 4,360.1 4,290.4 -3,293.8 -6,444.9 5,969,617.66 415,984.73 1.34 6,219.514022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft11,021.7 92.04 329.15 4,356.7 4,287.0 -3,212.0 -6,493.9 5,969,699.98 415,936.65 0.10 6,273.611,116.6 92.01 329.33 4,353.4 4,283.7 -3,130.5 -6,542.4 5,969,781.98 415,888.99 0.19 6,327.211,212.0 91.91329.344,350.14,280.4-3,048.5 -6,591.0 5,969,864.46 415,841.23 0.11 6,381.011,306.5 91.94 328.91 4,346.9 4,277.2 -2,967.4 -6,639.5 5,969,946.04 415,793.59 0.46 6,434.611,401.8 92.04 329.42 4,343.6 4,273.9 -2,885.6 -6,688.3 5,970,028.32 415,745.62 0.54 6,488.611,496.4 92.07 329.67 4,340.2 4,270.5 -2,804.1 -6,736.2 5,970,110.29 415,698.56 0.27 6,541.711,591.2 92.04 329.16 4,336.8 4,267.1 -2,722.5 -6,784.4 5,970,192.33 415,651.21 0.54 6,595.011,686.7 92.01 328.86 4,333.4 4,263.7 -2,640.7 -6,833.6 5,970,274.70 415,602.89 0.32 6,649.411,781.6 91.97 328.74 4,330.1 4,260.4 -2,559.6 -6,882.7 5,970,356.32 415,554.60 0.13 6,703.611,876.4 91.91 328.78 4,326.9 4,257.2 -2,478.6 -6,931.8 5,970,437.80 415,506.32 0.08 6,757.911,971.3 92.01 328.81 4,323.7 4,254.0 -2,397.4 -6,981.0 5,970,519.45 415,458.01 0.11 6,812.112,066.5 92.04 328.52 4,320.3 4,250.6 -2,316.2 -7,030.4 5,970,601.15 415,409.42 0.31 6,866.712,161.7 91.97 329.17 4,317.0 4,247.3 -2,234.8 -7,079.7 5,970,683.10 415,361.02 0.69 6,921.112,257.0 91.94 329.16 4,313.7 4,244.0 -2,152.9 -7,128.5 5,970,765.40 415,313.04 0.03 6,975.112,351.9 92.01 329.40 4,310.5 4,240.8 -2,071.4 -7,176.9 5,970,847.39 415,265.46 0.26 7,028.712,446.9 92.04 329.86 4,307.1 4,237.4 -1,989.5 -7,225.0 5,970,929.80 415,218.31 0.48 7,081.912,541.4 91.94 329.33 4,303.8 4,234.1 -1,908.1 -7,272.7 5,971,011.69 415,171.39 0.57 7,134.812,636.7 91.94 329.36 4,300.6 4,230.9 -1,826.1 -7,321.3 5,971,094.17 415,123.65 0.03 7,188.512,731.3 92.01 329.75 4,297.4 4,227.7 -1,744.6 -7,369.2 5,971,176.16 415,076.59 0.42 7,241.612,826.7 92.07 329.86 4,294.0 4,224.3 -1,662.3 -7,417.1 5,971,259.00 415,029.52 0.13 7,294.712,921.4 92.01 329.95 4,290.6 4,220.9 -1,580.4 -7,464.6 5,971,341.35 414,982.93 0.11 7,347.313,016.0 91.91 329.54 4,287.4 4,217.7 -1,498.7 -7,512.3 5,971,423.56 414,936.11 0.45 7,400.213,111.0 91.94 329.41 4,284.2 4,214.5 -1,416.9 -7,560.5 5,971,505.77 414,888.78 0.14 7,453.513,206.7 92.01 329.55 4,280.9 4,211.2 -1,334.5 -7,609.0 5,971,588.67 414,841.05 0.16 7,507.313,301.2 91.98 329.35 4,277.6 4,207.9 -1,253.2 -7,657.1 5,971,670.52 414,793.88 0.21 7,560.513,396.9 91.97 329.36 4,274.3 4,204.6 -1,170.9 -7,705.8 5,971,753.29 414,745.99 0.01 7,614.413,491.8 91.98 329.21 4,271.0 4,201.3 -1,089.3 -7,754.3 5,971,835.34 414,698.38 0.16 7,668.014022024 92035AMCOMPASS 500017 Build 02 Page ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueMDusftIncAzi azimuthusftusftNorthingusftTVDSSusftEastingusftSurveyTVDusftDLeg100usft. Secusft13,586.5 92.01 329.09 4,267.7 4,198.0 -1,008.1 -7,802.8 5,971,917.07 414,650.70 0.13 7,721.713,682.0 92.04 329.07 4,264.3 4,194.6 -926.2 -7,851.8 5,971,999.45 414,602.51 0.04 7,775.913,776.9 92.01 328.91 4,261.0 4,191.3 -844.9 -7,900.7 5,972,081.22 414,554.50 0.17 7,829.913,837.0 91.98 329.37 4,258.9 4,189.2 -793.4 -7,931.5 5,972,133.07 414,524.24 0.77 7,863.9NT3.2413,871.7 91.97 329.64 4,257.7 4,188.0 -763.5 -7,949.1 5,972,163.11 414,506.97 0.77 7,883.413,966.0 92.04 329.75 4,254.4 4,184.7 -682.1 -7,996.6 5,972,244.98 414,460.25 0.14 7,936.114,061.7 92.01 329.86 4,251.0 4,181.3 -599.4 -8,044.8 5,972,328.17 414,412.99 0.12 7,989.514,156.4 91.79 329.06 4,247.9 4,178.2 -518.0 -8,092.8 5,972,410.12 414,365.77 0.88 8,042.714,252.0 91.98 328.71 4,244.7 4,175.0 -436.1 -8,142.2 5,972,492.47 414,317.22 0.42 8,097.314,346.2 92.04 328.72 4,241.4 4,171.7 -355.7 -8,191.1 5,972,573.36 414,269.21 0.06 8,151.214,442.5 91.98 329.21 4,238.0 4,168.3 -273.2 -8,240.7 5,972,656.38 414,220.41 0.51 8,206.114,537.4 91.94 329.09 4,234.8 4,165.1 -191.8 -8,289.3 5,972,738.22 414,172.67 0.13 8,259.814,631.9 91.94 329.57 4,231.6 4,161.9 -110.6 -8,337.5 5,972,819.96 414,125.33 0.51 8,313.114,727.2 91.98 329.81 4,228.3 4,158.6 -28.4 -8,385.6 5,972,902.67 414,078.12 0.26 8,366.414,821.5 91.88 329.60 4,225.2 4,155.5 53.0 -8,433.1 5,972,984.52 414,031.43 0.25 8,419.014,917.0 91.64 330.55 4,222.2 4,152.5 135.8 -8,480.8 5,973,067.76 413,984.65 1.03 8,471.915,012.3 91.88 330.40 4,219.3 4,149.6 218.7 -8,527.7 5,973,151.15 413,938.56 0.30 8,524.115,107.3 91.91 330.68 4,216.2 4,146.5 301.3 -8,574.4 5,973,234.23 413,892.76 0.30 8,576.015,202.8 91.98 330.57 4,212.9 4,143.2 384.4 -8,621.2 5,973,317.86 413,846.820.148,628.115,297.4 92.02 330.09 4,209.6 4,139.9 466.6 -8,668.0 5,973,400.48 413,800.87 0.51 8,680.115,384.0 91.94 329.42 4,206.6 4,136.9 541.4 -8,711.6 5,973,475.72 413,758.04 0.78 8,728.415,409.0 91.94 329.42 4,205.8 4,136.1 562.9 -8,724.3 5,973,497.36 413,745.55 0.00 8,742.5Proj TD - 4-1/2" Production Liner14022024 92035AMCOMPASS 500017 Build 02 Page 10 ProjectCompanyLocal Coordinate ReferenceTVD ReferenceSiteSantos NAD27 ConversionPikkaNDBSantos Definitive Survey ReportWellWellboreNDBi-014NDBi-014Survey Calculation MethodMinimum CurvatureAs Drilled: Parker 272 @ 69.7usftDesignNDBi-014DatabaseEDM STO AlaskaMD ReferenceAs Drilled: Parker 272 @ 69.7usftNorth ReferenceWell NDBi014TrueVertical DepthusftMeasured DepthusftCasingDiameter(")HoleDiameter(")NameCasing Points20" Conductor Driven128.0 20 2013-3/8" Surface Casing2,563.8 13-3/8 169-5/8" Intermediate Liner10,440.0 9-5/8 12-1/44-1/2" Production Liner15,409.0 4-1/2 8-1/2MeasuredDepthusftVerticalDepthusftDipDirectionName LithologyDipFormations1,169.0 1,159.6 Base Ice Bearing Permafrost2,345.0 2,156.9 MCU5,112.0 3,123.3 Seabee2,886.0 2,453.2 Tuluvak Shale1,406.0 1,387.6 Base Permafrost Transition10,018.0 4,355.7 NT3 MFS8,133.0 4,001.1 NT6 MFS1,796.0 1,740.0 Middle Schrader Bluff7,677.0 3,868.6 Nanushuk3,056.0 2,521.0 Tuluvak Sand10,447.0 4,370.3 NT3.2 Top Reservoir7,740.0 3,887.2 NT8 MFS8,785.0 4,165.1 NT4 MFS8,450.0 4,085.3 NT5 MFS13,837.0 4,258.9 NT3.247,807.0 3,907.1 NT7 MFS1,043.0 1,036.1 Upper Schrader Bluff14022024 92035AMCOMPASS 500017 Build 02 Page 11 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 travis.smith@santos.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NDB-014 (PTD# 223-105) SSV Update Date:Thursday, December 11, 2025 9:01:54 AM Attachments:image001.png From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Wednesday, December 10, 2025 4:03 PM To: Smith, Travis (Travis) <Travis.Smith@santos.com> Cc: Senden, Robert (Ty) <Ty.Senden@santos.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDB-014 (PTD# 223-105) SSV Update Thank you for clarifying. As described, the injection operations for NDB-14 are compliant with 20 AA C 25.265(j). AOGCC inspection would be appropriate when the pressure pilots are connected. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Smith, Travis (Travis) <Travis.Smith@santos.com> Sent: Wednesday, December 10, 2025 2:58 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Senden, Robert (Ty) <Ty.Senden@santos.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDB-014 (PTD# 223-105) SSV Update Hello Jim— I wanted to follow-up with more information regarding our Pikka injection well NDB-014 (PTD# 223-105) that we spoke about last week. As discussed, this is the well that we use for occasional injection of small amounts of flowback Pikka crude oil. A few pieces of relevant information that I didn’t speak to directly last week: The well passed an AOGCC-witnessed MIT-IA to 4,212 psi on September 21, 2024. The intermittent crude oil injection periods are performed like intervention wellwork with a standalone pump truck (not through a flowline or surface facility equipment). As such, the operation is continuously manned. Further, we use a fusible cap to lock out the SSV during injection as typical for well intervention operations. The pressure transducers on the Pikka wells are not yet fully set up with the associated SSV’s. We are happy to set up an initial test of the SSV of NDB-014, but until the pressure pilots are connected it won’t be a standard function test. Alternatively, I can notify you when the system is set up for a full function test of the SSV for the well. Please advise what your preference is for proceeding with NDB-014. Per your request last week, I am working to get you a representative schematic of our SSV arrangement. Thanks very much and let me know if you have any questions. Travis Travis Smith Well Intervention & Integrity Engineer m: +1 907 350 9119 | e: Travis.Smith@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. We pay our respects to their Elders past, present and emerging. Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 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 travis.smith@santos.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NDB-014 (PTD# 223-105) SSV Update Date:Thursday, December 11, 2025 9:01:25 AM Attachments:image001.png From: Smith, Travis (Travis) <Travis.Smith@santos.com> Sent: Wednesday, December 10, 2025 2:58 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Senden, Robert (Ty) <Ty.Senden@santos.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDB-014 (PTD# 223-105) SSV Update Hello Jim— I wanted to follow-up with more information regarding our Pikka injection well NDB-014 (PTD# 223-105) that we spoke about last week. As discussed, this is the well that we use for occasional injection of small amounts of flowback Pikka crude oil. A few pieces of relevant information that I didn’t speak to directly last week: The well passed an AOGCC-witnessed MIT-IA to 4,212 psi on September 21, 2024. The intermittent crude oil injection periods are performed like intervention wellwork with a standalone pump truck (not through a flowline or surface facility equipment). As such, the operation is continuously manned. Further, we use a fusible cap to lock out the SSV during injection as typical for well intervention operations. The pressure transducers on the Pikka wells are not yet fully set up with the associated SSV’s. We are happy to set up an initial test of the SSV of NDB-014, but until the pressure pilots are connected it won’t be a standard function test. Alternatively, I can notify you when the system is set up for a full function test of the SSV for the well. Please advise what your preference is for proceeding with NDB-014. Per your request last week, I am working to get you a representative schematic of our SSV arrangement. Thanks very much and let me know if you have any questions. Travis Travis Smith Well Intervention & Integrity Engineer m: +1 907 350 9119 | e: Travis.Smith@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. We pay our respects to their Elders past, present and emerging. Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 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 travis.smith@santos.com. Learn why this is important From:Regg, James B (OGC) To:Smith, Travis (Travis) Cc:Senden, Robert (Ty); Wallace, Chris D (OGC); McLellan, Bryan J (OGC) Subject:RE: NDB-014 (PTD# 223-105) SSV Update Date:Wednesday, December 10, 2025 4:03:00 PM Attachments:image001.png Thank you for clarifying. As described, the injection operations for NDB-14 are compliant with 20 AA C 25.265(j). AOGCC inspection would be appropriate when the pressure pilots are connected. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Smith, Travis (Travis) <Travis.Smith@santos.com> Sent: Wednesday, December 10, 2025 2:58 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Senden, Robert (Ty) <Ty.Senden@santos.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDB-014 (PTD# 223-105) SSV Update Hello Jim— I wanted to follow-up with more information regarding our Pikka injection well NDB-014 (PTD# 223-105) that we spoke about last week. As discussed, this is the well that we use for occasional injection of small amounts of flowback Pikka crude oil. A few pieces of relevant information that I didn’t speak to directly last week: The well passed an AOGCC-witnessed MIT-IA to 4,212 psi on September 21, 2024. The intermittent crude oil injection periods are performed like intervention wellwork with a standalone pump truck (not through a flowline or surface facility equipment). As such, the operation is continuously manned. Further, we use a fusible cap to lock out the SSV during injection as typical for well intervention operations. The pressure transducers on the Pikka wells are not yet fully set up with the associated SSV’s. We are happy to set up an initial test of the SSV of NDB-014, but until the pressure pilots are connected it won’t be a standard function test. Alternatively, I can notify you when the system is set up for a full function test of the SSV for the well. Please advise what your preference is for proceeding with NDB-014. Per your request last week, I am working to get you a representative schematic of our SSV arrangement. Thanks very much and let me know if you have any questions. Travis Travis Smith Well Intervention & Integrity Engineer m: +1 907 350 9119 | e: Travis.Smith@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. We pay our respects to their Elders past, present and emerging. Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 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-014 50103208690000 NDB-014 ؐ LETTER OF TRANSMITTAL ؒ جؐؐؐNDB-025 ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf ؒ جؐؐؐNDB-031 ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf ؒ جؐؐؐNDB-032 ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-037 ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-048 ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-051 ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf ؒ جؐؐؐNDBi-016 ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf ؒ جؐؐؐNDBi-018 ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf ؒ جؐؐؐNDBi-030 224-006 T41154 225-028 T41155 224-124 T41156 224-143 T41157 224-105 T41158 224-085 T41159 224-013 T39830 223-006 T39829 223-120 T39832 LETTER OF TRANSMITTAL ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf ؒ جؐؐؐNDBi-036 ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf ؒ جؐؐؐNDBi-043A ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf ؒ جؐؐؐNDBi-044 ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf ؒ جؐؐؐNDBi-046L1 ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf ؒ جؐؐؐNDBi-049 ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf ؒ ؤؐؐؐNDBi-050 Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf 225-012 T41160 224-119 T41161 224-154 T41162 223-052 T39834 223-087 T39835 224-029 T39837 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-014 50103208690000 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-014 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 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION 1 PDF file NDBi-014 (50-103-20869-0000) 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: 223-105 T39831 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.06 08:15:45 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, October 17, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Oil Search (Alaska), LLC NDBi-014 PIKKA NDBi-014 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/17/2024 NDBi-014 50-103-20869-00-00 223-105-0 N SPT 4366 2231050 4000 684 686 689 689 0 0 0 0 OTHER P Josh Hunt 9/21/2024 Tested to 4000 psi. This was a pre-injection MIT required by regulation 20 AAC 25.412c. Another MIT will be performed after injection has started. 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-014 Inspection Date: Tubing OA Packer Depth 12 4302 4236 4212IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH240921134731 BBL Pumped:8.5 BBL Returned:8.5 Thursday, October 17, 2024 Page 1 of 1 9 9 9 9 99 999 9 9 9 9 9 pre-injection MIT James B. Regg Digitally signed by James B. Regg Date: 2024.10.17 09:23:41 -08'00' You don't often get email from jared.brake@contractor.santos.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: ![EXT]: RE: AIC question for NDBi-014 (PTD 2231050) Date:Monday, August 26, 2024 12:12:28 PM From: Wallace, Chris D (OGC) Sent: Monday, August 26, 2024 11:42 AM To: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Senden, Robert (Ty) <Ty.Senden@santos.com>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: ![EXT]: RE: AIC question for NDBi-014 Jared, My answers below. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent: Monday, August 26, 2024 9:39 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Senden, Robert (Ty) <Ty.Senden@santos.com> Subject: RE: ![EXT]: RE: AIC question for NDBi-014 Chris, Mel thought you would be the most suited to answer the below questions. Any advice would be greatly appreciated. We had requested a Sundry for injection of flowback fluids down NDBi-014 at Pikka. That request was denied pending the distribution of the Area Injection Order, which was received Thursday. After reading the injection order, page 12, rule #6, I have a few of questions. 1. We performed an MIT-IA on 3/16/2024 that witness was waived by Austin McLeod. Do we need to perform another witnessed MIT-IA prior to startup of injection? If the current well configuration was tested on 3/16/2024 you will not need to re-do this pre-injection MITIA. 2. In the order it states an MIT must be performed following any workover affecting mechanical integrity. Would swapping out a dummy valve with Slickline constitute needing another witnessed MIT? In this instance and with 1. Above and 3. Below – we can waive this requirement in this case. However, in general, any time a workover replaces a component that, if it fails, would be seen by an MITIA – you would need to re- do the MITIA. It is always the operator responsibility to monitor, report, and correct any pressure communication or well integrity issue. 3. The order it also states that a second MIT must be performed after the well has thermally stabilized once injection has commenced. Since NDBi-14 will only be used for injecting flowback fluids back into formation, this will be stop and go injection and not continuous for a short period. The well will not have an opportunity to become thermally stabilized. Would the AOGCC still require us to perform another MIT, or can we get a Waiver for this? This has been a problem for several operators recently in that they do not do the required stabilized post-injection MITIA because they didn’t read the AIO, forgot, or they claim the well doesn’t have stabilized injection due to batch/short initial injection cycle - and then forget. When we catch this oversight several months into continuous injection it results in a violation and penalty. So we can delay (not waive) this requirement until stabilized injection can be achieved - but it is still the operator responsibility to get it done before continuous injection (say 10 days continuous) and definitely before we see monthly injection numbers which prompts us to request and review the Tubing/inner/outer pressure, injection rate, temperature plot. Jared Brake Well Integrity & Well Intervention Engineer m: 1 (832) 330-4359| e: brajg@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Brake, Jared (Jared) Sent: Friday, August 23, 2024 9:54 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Senden, Robert (Ty) <Ty.Senden@santos.com> Subject: Re: ![EXT]: RE: AIC question for NDBi-014 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. Mel, This will be ok we can wait until early next week. Thanks for replying. Jared On Aug 23, 2024, at 9:29 AM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Jared, First: Do you need an answer today? Second: I would prefer to defer this question to Chris Wallace, the AOGCC UIC engineer, as he will be most familiar with your plans and parameters. He is back from holiday on Monday. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Victoria From: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent: Thursday, August 22, 2024 4:16 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Senden, Robert (Ty) <Ty.Senden@santos.com> Subject: FW: AIC question for NDBi-014 Mel & Victoria, I just got an OOO reply from Bryan, could either of you answer the questions below? Regards, Jared From: Brake, Jared (Jared) Sent: Thursday, August 22, 2024 4:06 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Senden, Robert (Ty) <Ty.Senden@santos.com> Subject: AIC question for NDBi-014 Bryan, We had requested a Sundry for injection of flowback fluids down NDBi-014 at Pikka. That request was denied pending the distribution of the Area Injection Order, which was received today. After reading the injection order, page 12, rule #6, I have a few of questions. 1. We performed an MIT-IA on 3/16/2024 that witness was waived by Austin McLeod. Do we need to perform another witnessed MIT-IA prior to startup of injection? 2. In the order it states an MIT must be performed following any workover affecting mechanical integrity. Would swapping out a dummy valve with Slickline constitute needing another witnessed MIT? 3. The order it also states that a second MIT must be performed after the well has thermally stabilized once injection has commenced. Since NDBi-14 will only be used for injecting flowback fluids back into formation, this will be stop and go injection and not continuous for a short period. The well will not have an opportunity to become thermally stabilized. Would the AOGCC still require us to perform another MIT, or can we get a Waiver for this? Regards, Jared Brake Well Integrity & Well Intervention Engineer <image001.jpg> m: 1 (832) 330-4359| e: brajg@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDBi-014 JBR 08/15/2024 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 Used 2-3/8" Coil for testing, 5 Accumulator bottles with precharge Avg. of 2200 psi. Witnessed first couple tests and had fail on blind/shears block was installed incorrectly. The pass was after I left due to time to get parts I waived the rest of the test. I witnessed the Stripper, Inner reel valve and done a draw down on BOP system Also the general location stuff. Test Results TEST DATA Rig Rep:Tim LarsonOperator:Oil Search (Alaska), LLC Operator Rep:Brad Gathman Rig Owner/Rig No.:Little Red Services 3 PTD#:2231050 DATE:7/6/2024 Type Operation:WRKOV Annular: Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopKPS240707142152 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 2.5 MASP: 1540 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 0 NA Lower Kelly 0 NA Ball Type 0 NA Inside BOP 0 NA FSV Misc 0 NA 5 NTNo. Valves 2 NTManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 1 2-3/8"P Annular Preventer 0 NA #1 Rams 1 Blind/Shears F #2 Rams 1 2-3/8" Pipe/ S NT #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2"NT HCR Valves 0 NA Kill Line Valves 0 NA Check Valve 1 2"NT BOP Misc 1 EQ Port NT System Pressure P2900 Pressure After Closure P2200 200 PSI Attained P15 Full Pressure Attained P38 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)NA0 ACC Misc NA0 NA NATrip Tank NA NAPit Level Indicators NA NAFlow Indicator NA NAMeth Gas Detector NA NAH2S Gas Detector NA NAMS Misc Inside Reel Valves 1 P Annular Preventer NA0 #1 Rams P9 #2 Rams P9 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke NA0 HCR Kill NA0 9 9 9 9 9 99 9 9 F fail on blind/shears block was installed incorrectly waived the rest of the test 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 1 of 9 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 07/06/2024 P. I. Supervisor FROM: Kam StJohn SUBJECT: Rig Inspection Petroleum Inspector LRS CTU 3 Oil Search Alaska (Santos) Pikka NDB-14 PTD 2231050 07/05/2024: Went to Pikka development location and met with Oil Search representative Brad Gathman and Little Red Services (LRS) representative (CTU operator) Tim Larson for a visual inspection of the new LRS CTU 3. This service coil tubing unit is like others working on the North Slope except it uses a crane to deploy the injector head instead of a mast. LRS CTU 3 is all modular and capable of working onshore and offshore, including remote locations. The CTU equipment and dedicated BOP stack are rated to 10K psi. The accumulator system includes 5 dedicated bottles (1550 psi pre-charge) which were plus 3 additional bottles (2000 psi pre-charge) to support the heavy-duty Blind/Shears for cutting 2-3/8 inch coil (has been tested according to LRS). LRS CTU 3 has a separate remote pump truck with 2 pumps for backup so they can still circulate while milling or cleaning out fill. Overall LRS CTU 3 it is very well set up with options for doing and going to many locations and job scopes. During the Initial BOPE test, they found that the shop had installed one of the Blind Shear blocks was incorrectly installed (upside down) which destroyed the blocks. I did not stay for repairs and continuation of testing due to other commitments. I kept in contact with Santos with Brad Gathman (Oil Search) and was told LRS sourced new Blind Shear blocks. Oil Search and LRS completed BOPE testing to 5K psi after repairs. Attachments: Photos (15); Rig Inspection Report 9 9 9 9 9 9 9 9 ,QVSHFWLRQ6XSHUYLVRU1RWH%23(&HUWLILFDWHVDQG+\GUDXOLFV0DQXDODUHLQ 5LJ)LOHIRU/56&78-5HJJ James B. Regg Digitally signed by James B. Regg Date: 2024.08.05 15:44:22 -08'00' 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 2 of 9 Little Red Services Coil Tubing Unit 3 Pikka NDB-14 (PTD 2231050) Photos by AOGCC Inspector K. StJohn 7/5/2024 LRS CTU 3 – Crane Holding Injector Head 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 3 of 9 Coil Tubing Reel from Side Access (left) and Operator Cabin (right) 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 4 of 9 8-inch 10K psi Coil Tubing BOP Stack Accumulator Bottles 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 5 of 9 Choke Manifold 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 6 of 9 Remote BOPE Control Panel Control Panel for Pumps 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 7 of 9 Pump Unit; Dual Pumps 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 8 of 9 Dual Pump Engines Pump Unit Tie-In Manifold 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj Page 9 of 9 Work Area Behind CTU P.I. Supv Comm: Rig Coil Tubing Unit? Yes Rig Contractor Rig Representative Operator Contractor Representative Well Permit to Drill # 2231050 Sundry Approval # 324-085 Operation Inspection Location Working Pressure, W/H Flange P Pit Fluid Measurement NA Working Pressure P P Flow Rate Sensor NA Operating Pressure P NA Mud Gas Separator NA Fluid Level/Condition P P Degasser NA Pressure Gauges P P Separator Bypass NA Sufficient Valves P P Gas Detectors NA Regulator Bypass P P Alarms Separate/Distinct NA Actuators (4-way valves) P P Choke/Kill Line Connections NA Blind Ram Handle Cover P P Reserve Pits NA Control Panel, Driller P P Trip Tank NA Control Panel, Remote P NA Firewall P P 2 or More Pumps P P Kelly or TD Valves NA Independent Power Supply P P Floor Safety Valves NA N2 Backup NA P Driller's Console P Condition of Equipment P P Flow Monitor P Flow Rate Indicator P Pit Level Indicators NA Valves P PPE P Gauges P Remote Hydraulic Choke NA Well Control Trained P Gas Detection Monitor NA FOV Upstream of Chokes P Housekeeping P Hydraulic Control Panel P Targeted Turns P Well Control Plan P Kill Sheet Current NA Bypass Line P FAILURES:0 CORRECT BY: COMMENTS Kam StJohn 7/5/2024 refer to accompanying memorandum report for additional details and photos. INSPECT DATE AOGCC INSPECTOR LRS Coil Unit #3 LRS Oil Search (Santos) MISCELLANEOUS Flange/Hub Connections Drilling Spool Outlets Flow Nipple Control Lines RIG FLOOR ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT HCR Valve(s) Manual Valves Annular Preventer Working Pressure, BOP Stack Stack Anchored Choke Line Kill Line Targeted Turns Pipe Rams Blind Rams Tim Larson Brad Gathman Locking Devices, Rams BOP STACK CHOKE MANIFOLD Pikka NDBi-14 MUD SYSTEM Pikka NDBi-14 Other CLOSING UNIT 2024-0705_Rig_LRS_CTU3_Pikka_NDB-14_ksj rev. 5-8-18 9 9 9 9 9 9 -5HJJ Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov April 19, 2024 Mr. Rob Tirpack Drilling Manager Oil Search Alaska, LLC 900 E. Benson Blvd Anchorage, AK 99508 Re: Docket Number: OTH-24-014 Notice of Violation - RESCIND Parker Rig 272 Pikka Unit NDB-14 (PTD 2231050) Dear Mr. Tirpack: By letter dated April 2, 2024, Oil Search Alaska LLC (Oil Search) was notified of a violation for continued operation after failure of a critical safety component, specifically the annular preventer close time exceeded the allowed limit on Parker Rig 272. The Alaska Oil and Gas Conservation Commission (AOGCC) now rescinds that notice of violation based on information provided by Oil Search. On April 12, 2024, AOGCC was provided information gathered as part of Oil Search’s internal investigation that determined there was a clerical error during the transfer of data from the “Parker 272 Test Order” tracking document to the AOGCC BOPE Test Report form. The AOGCC accepts the explanation provided by Oil Search and appreciates the steps being taken to ensure the accuracy of test results prior to submission. Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: Steven Lambe, Santos (Steven.Lambe@contractor.santos.com) AOGCC Inspectors (email) Phoebe Brooks, AOGCC Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.21 10:13:34 -05'00' 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:Lambe, Steven (Steven) To:Regg, James B (OGC); Coldiron, Samantha J (OGC) Cc:Davis, Rachel (Rachel); Tirpack, Robert (Robert); Johnson, Vernon (Vern); Balash, Joseph (Joe) Subject:FW: AOGCC NOV, Docket OTH-24-014 Date:Friday, April 12, 2024 12:41:58 PM Attachments:BOPE Test State Form 02-02-2024.xlsx BOP Test Chart 2-2-24.PNG BOPE Test Order 2-2-24.docx SOA Docket OTH-24-014.pdf !EXT Findings from NDBi-014 BOPE Test.msg You don't often get email from steven.lambe@contractor.santos.com. Learn why this is important 12-April-2024 VIA ELECTRONIC MAIL Mr. Brett W. Huber, Sr. Chair Commissioner And Mr. Jim Regg Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Anchorage, Alaska, 99501 Dear Mr. Huber and Mr. Regg Thank you for the correspondence in Docket OTH-24-014 regarding a Notice of Violation regarding the 13-5/8” annular preventer in use on ParkerWellbore Rig 272. By Introduction, I am the Santos Senior Operations Manager responsible for Safe and CompliantOperations on our Drilling and Completions operations. I was on the Rig when Mr. Tirpack received the Notice of Violation on April 8th. The onsite Santos leadership team and myself conducted an investigation into both Parkers Files andProcesses, and additionally on Santo’s files and processes on 272. We have concluded the Subject annular preventer has been both tested and operated within API RP53 specifications with a closing time at or less than 30 seconds. We also concluded a clerical error was made to the State of Alaska BOP test Report dated February 2nd, 2024. As evidence to the findings, I am forwarding the correspondence from the Parker 272 Rig Managerarticulating the error, and the evidenced pulled directly from the files. To prevent a reoccurrence, we have adjusted our onsite processes to include: 1. A secondary Parker Review of transcribing the ParkerWellbore BOP test order, Word Document attached, onto the BOP test form. 2. The Raw ParkerWellbore BOP Test Form with handwritten results will be scanned and retained in the well files, 3. The Santos Leadership team (Day and Night Supervision) will review the raw and final data being submitted to the AOGCC. On behalf of Santos, we apologize for allowing the clerical error to be submitted to the AOGCC and generating concern on our adherence to State regulations. Our Drilling and Completions team operates on the Ethos of Safe and Compliant, Efficient delivery. Santos and ParkerWellbore put a lot of effort in bringing and operating Rig 272 in full compliance with API and AOGCC standards and we will continue to operate in full compliance. If you need any further clarifications or additional information to close this matter, please reach out to me directly. Thank you. Steven Steven Lambe Senior Operations Manager Drilling & Completion t: +1 907 375 4647 | m: +1 907 330 9219 | e: steven.lambe@contractor.santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter <Country acknowledgment of Traditional Owners and Custodians of the Land.> From:Rig 272 Senior Manager To:Buzby, Brian (Brian); Lawson, Rowland (Rowland); D&C WSS NDB; Lambe, Steven (Steven) Cc:Blydenburgh, Daniel Subject:![EXT]: Findings from NDBi-014 BOPE Test Date:Tuesday, April 9, 2024 4:17:08 PM Attachments:ParkerWellBore2_b2156175-9838-421a-9c51-e41d69c5d047.png BOPE Test State Form 02-02-2024.xlsx BOP Test Chart 2-2-24.PNG BOPE Test Order 2-2-24.docx All, Here is our response to the incident on the State of Alaska BOPE Test Report form. I haveincluded the Test form along with the Test order and test chart. Please let me know if there isanything else that we can assist with in this matter. Thank you, Thank you for bringing this matter to our attention. We have reviewed the informationregarding the BOPE test conducted on Well NDBi-014 on February 2nd, 2024, and thediscrepancy in the closing time recorded for the 13-5/8" Annular Preventer. We understand that the closing time criteria for an Annular Preventer smaller than 18-3/4" is30 seconds or less and that anything in excess of that time would result in a failed test, hadthis actually taken place it would have driven us to make any necessary corrections and retestwith acceptable results prior to proceeding forward. However, based on our investigation, it appears that there was a clerical error during thetransfer of data from our Test Order tracking document over to the State of Alaska BOPE TestReport. The closing time for the 13-5/8” Annular Preventer that was recorded on our Test Ordertracking document that is filled out at the time of the test indicates that we had a closing timeof 30 seconds, understanding that we transfer the information from the original documentover to the State of Alaska BOPE Test Report, we believe that an error occurred during themanual transfer of information using the Ten-Key key pad, subsequently resulting in theincorrect/inaccurate closing time of 32 seconds to be input onto the State of Alaska BOPE TestReport. We do recognize that the documenting and delivery of accurate data is a very importantcomponent to the overall testing process and so in an effort to prevent similar errors in thefuture, we will implement a mitigation plan that includes more stringent crosschecks by ParkerWellbore Field Superintendents and verifications of the State of Alaska BOPE Test Report foraccuracy of information prior to the final submission. We will also include the hand writtenraw data gathered during the BOPE test on the Parker Test Order form. We appreciate your attention to this matter and assure you that we will take the necessarysteps to prevent such errors in the future. If you have any further questions or concerns,please feel free to reach out to us. Rig 272 Senior Manager Rig272.SeniorManager@parkerwellbore.com Office: +1(907)685-4801 Pouch 340110, Prudhoe Bay, AK 99734 United States www.parkerwellbore.com Energy. Well engineered. NOTICE BY Parker Wellbore Company This message, as well as any attached document, contains information from Parker Wellbore Company that is confidential and/or privileged. The information is intended only for the use of the addressee named above. If you are not the intended recipient, you are hereby notified that any use, disclosure, copying, distribution or the taking of any action in reliance on the contents of this message or its attachments is strictly prohibited, and may be unlawful. If you have received this message in error, please delete all electronic copies of this message and its attachments, if any, destroy any hard copies you may have created, without disclosing the contents, and notify the sender immediately. Unless expressly stated otherwise, nothing contained in this message should be construed as a digital or electronic signature, nor is it intended to reflect an intention to make an agreement by electronic means. BOPE Test Order Parker Rig 272 2-2-2024 WELL NDBi-014 Test Annular, Rams, & all valves to 250PSI/LOW/5-MIN, 3500PSI/HIGH/5-MIN, CHART/SAME, as/per permit to drill. Rig up 5” Test joint 1. Close: 4 ½’’ X 7’’ VBR UPR, U-IBOP, D544 Dart Valve, Choke #1, 2, 3, 4 & 15, K-4. Open: Everything else. 2. Close: L-IBOP, D544 FOSV, HCR Kill, Choke #5, 6. Open: Annular, U-IBOP, D544 Dart Valve, K-4 and Choke #2 3. Close: Choke #7,8,9, Manual Kill Open: HCR Kill, Choke #5, 6 4. Close: Choke#10, 11, 12 Open: Choke#7, 8, 9 5. Close: Choke#13 Open: Choke#12 6. Close: 4 ½’’ X 7’’ VBR LPR Open: Open UPR Remove Test Joint. 7. Close: Blind Rams, Choke #10, 11, 14. Open: Choke #13 8. Close: (8a) Super Choke A & (8b) Choke B T/2000 PSI Bleed and catch. Open: Choke #10 Change out to 4-1/2” Test joint 9. Close: Annular, HCR Choke Open: Choke #14 10. Close: 4 ½’’ X 7’’ VBR UPR, Manual Choke Open: HCR Choke 11. Close: 4 ½’’ X 7’’ VBR LPR *Bleed pressure and perform draw down test. “Function all BOP Components from remote panels located in the LER & Rig Managers office, and Accumulator.” BOPE Test Order Parker Rig 272 2-2-2024 Closing Times for BOP Components: Annular Preventer = 30Sec. Upper Pipe rams = 6 Sec. Blind/Shear rams = 7 Sec. Lower Pipe Rams = 6 Sec. HCR Choke = 2 Sec. HCR Kill = 2 Sec. Accumulator Test: Time/Pressure System Pressure = 3100 PSI Pressure after Closure = 1900 PSI 200 psi Attained = 18 Sec. Full Pressure Attained = 80 Sec. Nitrogen Bottle Average = 2300 PSI X 14 Bottles Electric pump kick on pressure = 2800 PSI Electric pump kick off pressure = 3100 PSI Air pump kick on pressure = 2600 PSI Air pump kick off pressure = 2800 PSI 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:2/2/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231050 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:Weekly:Bi-Weekly:X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1540 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 1 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 4-1/2 x 7" VBR 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)1900 P Check Valve 0 N/A NA 200 psi Attained (sec)18 sec P BOP Misc 0 N/A NA Full Pressure Attained (sec)80 sec P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:1050 P Quantity Test Result Nitgn. Bottles # & psi (Avg.):2300 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 32 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 7 P Inside Reel valves 0 NA #3 Rams 6 P #4 Rams N/A NA Test Results #5 Rams N/A NA #6 Rams N/A NA Number of Failures:0 Test Time:4.0 Hrs 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 1/31/2024 22:09 hrs Waived By Test Start Date/Time:2/2/2024 19:00 (date)(time)Witness Test Finish Date/Time:2/2/2024 23:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Parker Tested with 5" and 4.5" test joints. Pat Lynch Oil Search (Alaska) LLC Rowland Lawson NDBi-014 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)BOPE Test State Form 02-02-2024 (002) Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov April 2, 2024 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7018 0680 0002 2049 1143 Mr. Rob Tirpack Drilling Manager Oil Search Alaska, LLC 900 E. Benson Blvd Anchorage, AK 99508 Re: Docket Number: OTH-24-014 Notice of Violation Parker Rig 272 Pikka Unit NDB-14 (PTD 2231050) Dear Mr. Tirpack: On February 2, 2024, a blowout prevention equipment (BOPE) test was performed by Parker Rig 272 in conjunction with drilling operations at Pikka Unit NDB-14. The Alaska Oil and Gas Conservation Commission (AOGCC) received a report for the 135/8-inch BOPE system test on February 3, 2024.1 Oil Search Alaska, LLC (Oil Search) reported the annular close time was 32 seconds, calling the test result a pass. Secondary well control for drilling operations (BOPE requirements) are addressed in 20 AAC 25.035. Paragraph (a) notes that drilling and completion operations are also subject to the requirements of 20 AAC 25.527 which incorporates by reference API RP 53, “Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells”.2 Closing time for an annular preventer that is less than 18 ¾ inches is within 30 seconds.3 For a passing annular preventer performance test, Oil Search needed to demonstrate a closure response time for the well control packing element which was within 30 seconds, and the ability to hold the required test pressure for at least 5 minutes. Oil Search provided neither evidence of repairs to the annular preventer or well control equipment control systems nor the results of a 1 AOGCC waived witness of the BOPE test. 2 API RP 53 has been superseded by API Standard 53, “Well Control Equipment Systems for Drilling Wells”, 5th Edition, December 2018. The annular close response times and description of what constitutes “closed” are unchanged. 3 Measurement of closing response time begins at pushing the button or turning the control valve handle to operate the function and ends when the BOP or valve is closed effecting a seal. (API RP 53, Section 12.3.3) Docket Number: OTH-24-014 April 2, 2024 Page 2 of 2 passing retest prior to continuing with drilling operations on Pikka NDB-14. Continued operation with an unresolved failure of safety critical equipment is a violation of AOGCC regulations. Within 14 days of receipt of this letter, you are requested to provide the AOGCC with a written description of how this occurred (root cause), and what has or will be done in the future to prevent recurrence at Oil Search-operated rigs in Alaska. Information requested in this notice is in accordance 20 AAC 25.300; failure to comply with this request will be an additional violation. The AOGCC reserves the right to pursue additional enforcement action in connection with this Notice of Violation. Questions regarding this letter should be directed to Jim Regg at (907) 793- 1236 (email: jim.regg@alaska.gov). Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: AOGCC Inspectors Phoebe Brooks, AOGCC Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.02 14:00:51 -08'00' From:Brooks, Phoebe L (OGC) To:Lawson, Rowland (Rowland) Cc:Regg, James B (OGC) Subject:RE: Parker 272 02/02/2024 BOP test form Date:Tuesday, February 20, 2024 2:45:48 PM Attachments:Parker 272 02-02-24 Revised.xlsx Thanks Rowland. I’ve attached a revised report adding that information and correcting the formatting. Please update your copy. 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: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Sent: Tuesday, February 20, 2024 2:27 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: Parker 272 02/02/2024 BOP test form Phoebe….It is 14 bottles. Do you want me to send you an updated form? Thank you Rowland Lawson - Day Wellsite Supervisor Mobile: 907-268-0648 Email: rowland.lawson@contractor.santos.com Alternate: Brian Buzby – brian.buzby@contractor.santos.com From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Tuesday, February 20, 2024 2:21 PM To: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Subject: ![EXT]: RE: Parker 272 02/02/2024 BOP test form Rowland, The # of Nitrogen bottles is missing; please advise. Thanks, Phoebe Phoebe Brooks Research Analyst Pikka NDB-14 PTD 2231050 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. 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: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Sent: Saturday, February 3, 2024 1:26 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: Parker 272 02/02/2024 BOP test form Please find attached the BOPE test form for Parker 272 on 02/02/2024. Thank you Rowland Lawson - Day Wellsite Supervisor Mobile: 907-268-0648 Email: rowland.lawson@contractor.santos.com Alternate: Brian Buzby – brian.buzby@contractor.santos.com 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:2/2/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231050 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:Weekly:Bi-Weekly:X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1540 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 1 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 4-1/2 x 7" VBR 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)1900 P Check Valve 0 N/A NA 200 psi Attained (sec)18 P BOP Misc 0 N/A NA Full Pressure Attained (sec)80 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):14 @ 2300 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 32 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 7 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:4.0 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 01/31/24 22:09 Waived By Test Start Date/Time:2/2/2024 19:00 (date)(time)Witness Test Finish Date/Time:2/2/2024 23:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Parker Tested with 5" and 4.5" test joints. Pat Lynch Oil Search (Alaska) LLC Rowland Lawson Pikka NDBi-014 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)2024-0202_BOP_Parker272_Pikka_NDB-14 ===F Annular Fail - API 53 and API Spec 16D: close time shall not exceed 30 seconds for annular BOP's smaller than 18 3/4 inches nominal bore. -- J. Regg, 4/1/2024 see Remarks == 1 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:Lambe, Steven (Steven) To:Regg, James B (OGC); Coldiron, Samantha J (OGC) Cc:Davis, Rachel (Rachel); Tirpack, Robert (Robert); Johnson, Vernon (Vern); Balash, Joseph (Joe) Subject:FW: AOGCC NOV, Docket OTH-24-014 Date:Friday, April 12, 2024 12:41:57 PM Attachments:image003.jpg BOPE Test State Form 02-02-2024.xlsx BOP Test Chart 2-2-24.PNG BOPE Test Order 2-2-24.docx SOA Docket OTH-24-014.pdf !EXT Findings from NDBi-014 BOPE Test.msg 12-April-2024 VIA ELECTRONIC MAIL Mr. Brett W. Huber, Sr. Chair Commissioner And Mr. Jim Regg Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Anchorage, Alaska, 99501 Dear Mr. Huber and Mr. Regg Thank you for the correspondence in Docket OTH-24-014 regarding a Notice of Violation regardingthe 13-5/8” annular preventer in use on ParkerWellbore Rig 272. By Introduction, I am the Santos Senior Operations Manager responsible for Safe and Compliant Operations on our Drilling and Completions operations. I was on the Rig when Mr. Tirpack received the Notice of Violation on April 8th. The onsite Santos leadership team and myself conducted an investigation into both Parkers Files and Processes, and additionally on Santo’s files and processes on 272. We have concluded the Subject annular preventer has been both tested and operated within API RP 53 specifications with a closing time at or less than 30 seconds. We also concluded a clerical error was made to the State of Alaska BOP test Report dated February 2nd, 2024. As evidence to the findings, I am forwarding the correspondence from the Parker 272 Rig Manager articulating the error, and the evidenced pulled directly from the files. To prevent a reoccurrence, we have adjusted our onsite processes to include: 1.A secondary Parker Review of transcribing the ParkerWellbore BOP test order, Word Document attached, onto the BOP test form. 2.The Raw ParkerWellbore BOP Test Form with handwritten results will be scanned and retained in the well files, Pikka NDB-14 PTD 2231050 jbr 3.The Santos Leadership team (Day and Night Supervision) will review the raw and final data being submitted to the AOGCC. On behalf of Santos, we apologize for allowing the clerical error to be submitted to the AOGCC andgenerating concern on our adherence to State regulations. Our Drilling and Completions team operates on the Ethos of Safe and Compliant, Efficient delivery. Santos and ParkerWellbore put a lot of effort in bringing and operating Rig 272 in full compliance with API and AOGCC standards and we will continue to operate in full compliance. If you need any further clarifications or additional information to close this matter, please reach outto me directly. Thank you. Steven Steven Lambe Senior Operations Manager Drilling & Completion t: +1 907 375 4647 | m: +1 907 330 9219 | e: steven.lambe@contractor.santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter <Country acknowledgment of Traditional Owners and Custodians of the Land.> From:Rig 272 Senior Manager To:Buzby, Brian (Brian); Lawson, Rowland (Rowland); D&C WSS NDB; Lambe, Steven (Steven) Cc:Blydenburgh, Daniel Subject:![EXT]: Findings from NDBi-014 BOPE Test Date:Tuesday, April 9, 2024 4:17:08 PM Attachments:ParkerWellBore2_b2156175-9838-421a-9c51-e41d69c5d047.png BOPE Test State Form 02-02-2024.xlsx BOP Test Chart 2-2-24.PNG BOPE Test Order 2-2-24.docx All, Here is our response to the incident on the State of Alaska BOPE Test Report form. I haveincluded the Test form along with the Test order and test chart. Please let me know if there isanything else that we can assist with in this matter. Thank you, Thank you for bringing this matter to our attention. We have reviewed the informationregarding the BOPE test conducted on Well NDBi-014 on February 2nd, 2024, and thediscrepancy in the closing time recorded for the 13-5/8" Annular Preventer. We understand that the closing time criteria for an Annular Preventer smaller than 18-3/4" is30 seconds or less and that anything in excess of that time would result in a failed test, hadthis actually taken place it would have driven us to make any necessary corrections and retestwith acceptable results prior to proceeding forward. However, based on our investigation, it appears that there was a clerical error during thetransfer of data from our Test Order tracking document over to the State of Alaska BOPE TestReport. The closing time for the 13-5/8” Annular Preventer that was recorded on our Test Ordertracking document that is filled out at the time of the test indicates that we had a closing timeof 30 seconds, understanding that we transfer the information from the original documentover to the State of Alaska BOPE Test Report, we believe that an error occurred during themanual transfer of information using the Ten-Key key pad, subsequently resulting in theincorrect/inaccurate closing time of 32 seconds to be input onto the State of Alaska BOPE TestReport. We do recognize that the documenting and delivery of accurate data is a very importantcomponent to the overall testing process and so in an effort to prevent similar errors in thefuture, we will implement a mitigation plan that includes more stringent crosschecks by ParkerWellbore Field Superintendents and verifications of the State of Alaska BOPE Test Report foraccuracy of information prior to the final submission. We will also include the hand writtenraw data gathered during the BOPE test on the Parker Test Order form. We appreciate your attention to this matter and assure you that we will take the necessarysteps to prevent such errors in the future. If you have any further questions or concerns,please feel free to reach out to us. Rig 272 Senior Manager Rig272.SeniorManager@parkerwellbore.com Office: +1(907)685-4801 Pouch 340110, Prudhoe Bay, AK 99734 United States www.parkerwellbore.com Energy. Well engineered. NOTICE BY Parker Wellbore Company This message, as well as any attached document, contains information from Parker Wellbore Company that is confidential and/or privileged. The information is intended only for the use of the addressee named above. If you are not the intended recipient, you are hereby notified that any use, disclosure, copying, distribution or the taking of any action in reliance on the contents of this message or its attachments is strictly prohibited, and may be unlawful. If you have received this message in error, please delete all electronic copies of this message and its attachments, if any, destroy any hard copies you may have created, without disclosing the contents, and notify the sender immediately. Unless expressly stated otherwise, nothing contained in this message should be construed as a digital or electronic signature, nor is it intended to reflect an intention to make an agreement by electronic means. 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.: 2/14/2024 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 2463 FSL, 2783 FEL, S4, T11N, R6E, UM Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): 4647 FSL, 3695 FEL, S08, T11N, R6E, UM GL: 22.82 BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: ADL 392984, 3022 FSL, 946 FEL, S06, T11N, R6E, UM 392985, 393023, 391445, 393021 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: GR-RES-NEU-DEN-Sonic, Mudlogs 23. BOTTOM 20"x34"X-52 128 13-3/8"L-80 2290 9-5/8"L-80 4370 Tieback L-80 2176 4-1/2"P-110S 4206 4-1/2"P-110S 4367 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 154024-1/2" N/A12-1/4" TUBING RECORD N/A 10293 15402 SIZE DEPTH SET (MD) PACKER SET (MD/TVD) See attached cement rpt 4366 Surface 12-1/4" 8-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil Search Alaska, LLC WAG Gas 223-105 12.6# 10258 Surface N/A 42" 12.6# Tubing N/A 900 E Benson Boulevard, Suite 500, Anchorage, AK 99508 422,462.77 5,972,844.34 CASING WT. PER FT.GRADE 01/24/24 CEMENTING RECORD 5,969,214.23 1406' MD / 1385' TVD SETTING DEPTH TVD 5,973,497.36 TOP 16" Grouted to surface 50-103-20869-00-00 NDBi-014 LONS 19-003 12/24/23 15,409' MD / 4,206' TVD N/A 69.72 HOLE SIZE AMOUNT PULLED 416,242.65 413,745.55 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. 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, BOTTOM Surface Surface Per 20 AAC 25.283 (i)(2) attach electronic information 47# 2374 2176 Surface 215# 68# 128 2374 10440 See attached packer rpt Surface See attached cement rpt 47# Surface Surface 2564 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. Gas-Oil Ratio:Choke Size: 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 J G s d 1 0 yyp dB P l L s (atta Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 11:17 am, Mar 08, 2024 Completed 2/14/2024 JSB RBDMS JSB 031124 4047 JSB GDSR-4/12/24 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface 1360 1344 Top of Productive Interval 10447 4370 1798 1736 2345 2156 2886 2453 3056 2521 Seabee 5112 3123 Nanushuk 7677 3868 7740 3887 7807 3907 NT6 MFS 8133 4001 NT5 MFS 8450 4085 NT4 MFS 8785 4165 NT3 MFS 10018 4356 NT3.24 13837 4259 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: Mark Staudinger Digital Signature with Date:Contact Email:mark.staudinger@santos.com Contact Phone:1-520-273-6643 Authorized Title: Senior Drilling Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS NT7 MFS Tuluvak Shale NT3.2 Tuluvak Sand Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. NT8 MFS Middle Schrader Bluff TPI (Top of Producing Interval). Authorized Name and MCU Formation Name at TD: INSTRUCTIONS 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. N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov foregoing is true and correct to the best lli E i uction or well test results, per 20 AAC 25 3/8/2024 Page 1 of 1 Well Name: NDBi-014 Packer Set Depths Item Des Btm (ftKB) Btm (TVD) (ftKB) Remainder of the SLZXP Liner Top Hanger Packer 10,279.2 4,366.9 OH Packer #11 10,510.9 4,370.9 OH Packer #10 10,619.6 4,370.0 OH Packer #9 11,161.6 4,351.8 OH Packer #8 11,621.5 4,335.7 OH Packer #7 12,159.8 4,317.1 OH Packer #6 12,661.0 4,299.8 OH Packer #5 13,327.7 4,276.7 OH Packer #4 13,747.6 4,262.0 OH Packer #3 14,290.6 4,243.4 OH Packer #2 14,834.4 4,224.7 OH Packer #1 15,252.3 4,211.2 NDBi-014 Well Schematic GL 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,374' MD 13-3/8" 68 ppf L-80 Surface Casing2,564' MD 9-5/8", 47ppf L-80 Intermediate Liner10,440' MD 4-½”, 12.6ppf P-110S Production Liner 15,402' MD 4-½” Liner Hanger Liner Top Packer10,257' MD Archer C-Flex Two-Stage Cementing Tool (Base of Tuluvak) 5,140' MD TOC First Stage Cement Job7,739' MD 16" Hole Size 12-1/4" Hole Size 02.14.202446.90' RKB – Bottom Flange 9-5/8" Tieback and Seal Assembly2,374' MD 8-½” Openhole 15,409' MD 1 2 3 4 5 6 7 8 9 #CompletionItem TopDepth(MD')Depth(TVD') Inc ID" OD" 1XLandingNipple 1489 1464 21 3.813 4.778 2GasliftMandrel 1.5" 2087 1975 41 3.865 7.632 3XLandingNipple 2157 2028 43 3.813 4.780 4XLandingNipple 10106 4361 87 3.813 4.780 5D/HPsiͲTempGauge 10168 4363 88 3.905 5.996 6XLandingNipple 10191 4364 88 3.813 4.779 7TiebackSealAssy 10292 4367 88 3.860 5.230 8 9.625"x4.5"LH/Packer 10257 4366 88 6.110 8.430 9#11OpenholePacker 10504 4370 89 3.911 8.000 10 #10OpenholePacker 10612 4370 91 3.899 8.000 11 Stage 9ͲFracSleeve 10803 4364 91 3.735 5.628 12 #9OpenholePacker 11154 4352 91 3.898 8.000 13 Stage 8ͲFracSleeve 11304 4347 91 3.735 5.628 14 #8OpenholePacker 11614 4336 92 3.909 8.000 15 Stage 7ͲFracSleeve 11843 4328 91 3.735 5.628 16 #7OpenholePacker 12153 4317 92 3.911 8.000 17 Stage 6ͲFracSleeve 12385 4309 92 3.735 5.628 18 #6OpenholePacker 12654 4300 92 3.898 8.000 19 Stage 5ͲFracSleeve 13009 4287 92 3.735 5.628 20 #5OpenholePacker 13321 4276 92 3.911 8.000 21 Stage 4ͲFracSleeve 13553 4268 92 3.735 5.632 22 #4OpenholePacker 13740 4262 92 3.910 8.000 23 Stage 3ͲFracSleeve 14012 4252 92 3.735 5.628 24 #3OpenholePacker 14283 4243 92 3.908 8.000 25 Stage 2ͲFracSleeve 14558 4234 92 3.735 5.628 26 #2OpenholePacker 14827 4225 92 3.905 8.000 27 Stage 1ͲFracSleeve 15098 4216 92 3.735 5.628 28 #1OpenholePacker 15245 4211 92 3.907 8.000 29 #2ToeSleeve 15313 4209 92 3.500 5.750 30 #1ToeSleeve 15325 4208 92 3.500 5.750 31 WIV Collar 15388 4206 92 0.870 5.200 32 Eccentricshoe 15400 4206 92 3.900 5.210 Page 1 of 1 Well Name: NDBi-014 Cement Surface Casing Cement Surface Casing Cement, Casing, 12/28/2023 06:30 Type Casing Cementing Start Date 12/28/2023 Cementing End Date 12/28/2023 Wellbore Original Hole String Surface, 2,563.8ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results 263 bbls of cement returned to surface. Comment Cement 13-3/8” casing as follows: -Hook up cement hose to the cement swivel. -Confirm circulation through cement hose 3 BPM, 80 psi. -Line up Halliburton and and pump 5 bbls water ahead 2 BPM, 135 psi. -PT to 1000 psi low, 4000 psi high. -Drop the bottom plug #1. -Mixed and pumped 80 bbls 10.5 ppg tuned spacer at 4.7 BPM, 285 psi. -Dropped bottom plug #2. -Mixed and pumped 480 bbls 11.0 ppg ArctiCem lead cement at 5.5 BPM 465 psi. Excess volume 337 bbls (yield 2.535 cuft/sk). -Mixed and pumped 72 bbls of 15.3 ppg Tail cement at 3-5 BPM, 307 psi (yield 1.24 cuft/sk). -Dropped the top plug. Washed up on top of the plug with 2 bbls cement and 18 bbls water with cement unit. -Line up on the rig pumps and displaced with 10 ppg spud mud at 8 BPM 325 bbls. -Reduced pump rate to 5 BPM to total 340 bbls displaced. -Reduced pump rate to 3 BPM to total 349 bbls displaced and bumped the plug with 1000 psi, 500 psi over last displacement pressure. -Held 1000 psi/5 min, bled off pressure and checked floats held OK. -No losses during the cement job with 263 bbls of 11.0 ppg cement returned to surface. CIP at 11:15 hrs 12/28/2023. 1, <DepthTop>-<DepthBtm>ftKB Top Depth (ftKB) Bottom Depth (ftKB) Full Return? No Vol Cement Ret (bbl) 263.0 Top Plug? Yes Bottom Plug? Yes 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 <Typ> Fluid Type Fluid Description Amount (sacks) Class Volume Pumped (bbl) Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Page 1 of 1 Well Name: NDBi-014 Cement Intermediate Casing Cement 1st Stage Intermediate Casing Cement 1st Stage, Casing, 1/17/2024 21:30 Type Casing Cementing Start Date 1/17/2024 Cementing End Date 1/18/2024 Wellbore Original Hole String Intermediate Liner, 10,440.0ftKB 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 7739' MD. Reference the CBL Report in the attachments for a detailed analysis of cement bond log results. Comment Conduct 1st Stage Cement Job of 9-5/8” Liner - 9-5/8” shoe at 10,440’, Float collar at 10,363’, Stage Tool at 5137’, Liner top at 2374’ - Pump 80 bbl 13.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 4 bpm, full returns - Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 3.7 bpm, initial circulating pressure 400 psi - Land dart at 52 bbls away at 3.5 bpm at latch (as calculated), clear indication of latch and release - Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 270 bbls @ average of 3.7 bpm, 400 psi, excess volume 30% (1225 sacks, yield 1.237 cu ft/sk), final circulating pressure 100 psi, full returns throughout - Release top pump down plug, chase with 10 bbls of washup from Halliburton. - Perform displacement with rig pumps, displace with 12.0 ppg OBM at initial rate of 6 bpm, 435 psi to catch cement (did not catch before slowing rate). - Top pump down dart latch up confirmed at 52 bbls displaced (as calculated) - Continue to displace with 12.0 ppg OBM at 4 bpm, 337 psi ICP with full returns as Spacer pill exits shoe. - Bottom plug lands 18 bbls behind calculated strokes at 3832, 1345 psi - Displace at 4 bpm, 545 psi with bottom plug landed, increase to 6 bpm, 850 psi at 4400 strokes, pushing fluid away, reduce back down to 4 bpm, 670 psi. Losing fluid, back down to 3 bpm, 593 psi initial. FCP 605 psi at plug bump. Pressure up to 1200 psi and hold. - Total displacement volume 632 bbls (measured by strokes @ 96% pump efficiency). - Total losses from cement exit shoe to cement in place: 75 bbls.. - Check floats, CIP 0415 hrs 1, <DepthTop>-10,440.0ftKB Top Depth (ftKB) Bottom Depth (ftKB) 10,440.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 605.0 Plug Bump Pressure (psi) 1,200.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) 10,365.0 Tag Method Drill Pipe Depth Plug Drilled Out To (ftKB) 10,440.0 Drill Out Diameter (in) 8 1/2 Drill Out Date 1/31/2024 Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 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) 1,225 Class Class I/II Volume Pumped (bbl) 270.0 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) Thickening Time (hr) 6.00 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 10.00 Page 1 of 1 Well Name: NDBi-014 Cement Intermediate Casing Cement 2nd Stage Intermediate Casing Cement 2nd Stage, Casing, 1/18/2024 21:30 Type Casing Cementing Start Date 1/18/2024 Cementing End Date 1/19/2024 Wellbore Original Hole String Intermediate Liner, 10,440.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Baker Soundtrack LWD Cement Evaluation Results Cement was identified from 5,152' MD to the Top of the 9-5/8" Liner. Log results indicate adequate cement isolation across the entire Tuluvak formation. Reference the CBL report in attachments for a detailed analysis. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 5,140’ (center of circulation port) as follows: - Mix and pump 80 bbls of 12.5 ppg Tuned Spacer at 4 bpm and full returns (both spacers with Surfactant B and Musol A). - Mix and pump 80 bbls of 13.5 Tuned Spacer @ 4 bpm with full returns. - Mix and pump 305 bbls of 15.3 ppg Versacem Type I-II Tail cement @ 3.5 bpm initial, 370 psi, final 385 psi; 16 bbls losses throughout job. Excess Volume 100% (1385 sacks, yield 1.237 cu ft/sk). - Displace to calculated displacement volume of 119 bbls to Archer Stage Collar. - Begin displacement with 10 bbls fresh clean-up water from cementing unit. - Continue to displace with 109 bbls 12.0 ppg OBM using rig pumps. Stage up to initial rate of 6 bpm, 860 psi, 7% flow returns, observing slight losses, back rate off to 5 bpm, 770 psi, 5% flow return. Final circulating pressure at 5 bpm 875 psi. - Slow displacement to 3 bpm, 640 psi, last 10 bbls. - Dump fluids when dyed Tuned Spacer back to surface. - Estimate 104 bbls cement returns, weight of 14.2 ppg. - CIP @ 0031 hrs. 2, <DepthTop>-<DepthBtm>ftKB Top Depth (ftKB) Bottom Depth (ftKB) Full Return? No Vol Cement Ret (bbl) 104.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 640.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Mud Flush 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 (%) 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) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 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 Tail Type I/II Amount (sacks) 1,385 Class Type I/II Volume Pumped (bbl) 305.0 Estimated Top (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 7.07 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 18.00 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 12/22/2023 12/23/2023 0 No accidents, incidents or spills. Begin Rig move to NDBi-014. 12/23/2023 12/24/2023 0 10.00 No accidents, incidents or spills. Skid rig floor to well center. Complete Rig acceptance check list. Accept rig for Well operations for NDB-014 06:00 hrs 12-23-23. Nipple up riser Diverter valve and diverter line. N/U Diverter. Function test surface annular and knife valve. Function test successful. Mobilize BHA to rig floor. 12/24/2023 12/25/2023 128 831.00 10.00 No accidents, incidents or spills. Make up Surface 16" Directional BHA. Wash down tag bottom at 127’ and drill to 137' w/ fresh water. Shut down swap to spud mud. Drill 16” Surface hole from 137’ md to 311'. POH rack back 2 stds. HWDP. P/U remaining Flex collars and Shock Sub. RIH to from 197’ to 311’. Drill 16” Surface hole from 311’ to 959' md. 12/25/2023 12/26/2023 959 1,611.00 10.00 No acccidents, incidents or spills. Drill 16” Surface hole from 959’ to 1,814' md. Circulate bottoms -up 2 times. Backream out from 1,814’ to 1,625’. POH on elevators from 1,625’ to 866’. Drill 16” Surface hole from 1,814' to 2,570' MD / 2293 TVD (Surface TD). Circulate 2xBU to clean the hole prior to BROOH. 12/26/2023 12/27/2023 2,570 0.00 10.00 No acccidents, incidents or spills. BROOH at 400-600 ft/hr from 2,379’ to 1,618’ MD. Orient to high side and pull on elevators from 1,618’ to HWDP @ 859’. Trip back in hole on elevators from 859’ to 1,815’ MD. CBUx3 while racking back stand every B/U from 1,815’ to 1,621’ MD. Pull on elevators to BHA from 1,621’ to 860’ MD. Rack back HWDP and Jars. L/D 16” surface BHA and bit. Make up shoe track and float. Baker lock to Joint #4. Attempt to make up Joint #5. Trouble shoot casing running equipment. 12/27/2023 12/28/2023 2,570 0.00 10.00 No accidents, incidents or spills. Run 13-3/8” 68# L-80 TXP Casing from 286’ md to 778’ md. Bad torque turn on connection between joints 19 and 20. Lay down both joints. Run 13-3/8” 68# L-80 Casing from 778’ md to 2551’ md. 12/28/2023 12/29/2023 2,570 0.00 10.00 No accidents, incidents or spills. Make up landing joint and land surface casing at 2,563’ md. Stage up circulation rate in increments to 10 bbls/min. Cement 13-3/8” casing. Hook up cement hose to the cement swivel. Confirm circulation through cement hose 3 BPM, 80 psi. Line up Halliburton and and pump 5 bbls water ahead 2 BPM, 135 psi. PT to 1000 psi low, 4000 psi high. Drop the bottom plug #1. Mixed and pumped 80 bbls 10.5 ppg tuned spacer at 4.7 BPM, 285 psi. Dropped bottom plug #2. Mixed and pumped 480 bbls 11.0 ppg ArctiCem lead cement at 5.5 BPM 465 psi. Excess volume 337 bbls (yield 2.535 cuft/sk). Mixed and pumped 72 bbls of 15.3 ppg Tail cement at 3-5 BPM, 307 psi (yield 1.24 cuft/sk). Dropped the top plug. Washed up on top of the plug with 2 bbls cement and 18 bbls water with cement unit. Line up on the rig pumps and displaced with 10 ppg spud mud at 8 BPM 325 bbls. Reduced pump rate to 5 BPM to total 340 bbls displaced. Reduced pump rate to 3 BPM to total 349 bbls displaced and bumped the plug with 1000 psi, 500 psi over last displacement pressure. Held 1000 psi/5 min, bled off pressure and checked floats held OK. No losses during the cement job with 263 bbls of 11.0 ppg cement returned to surface. CIP at 11:15 hrs 12/28/2023. Flush and clean after the cement job. Release the running tool from the hanger. And lay down the landing joint. N/D the diverter system. Clean and prep hanger. Make up wellhead and set orientation. Set adapter spool and high-pressure risers. 12/29/2023 12/30/2023 2,570 0.00 10.00 No accidents, incidents or spills. Nipple up 13-5/8" 5M, ARdSRs BOP. Test BOPE's 250 psi low, 3500 psi high. Tested the Annular to 250 psi low, 3500 psi high for 5 min with the 5-7/8” test joint. Tested the 4-1/2” X 7” VBR’s with the 5-7/8” test joint to 250 psi low, 3500 psi high for 5 min. Tested the 9-5/8” fixed rams to 250 psi low, 3500 psi high for 5 min with the 9-5/8” test joint. Tested all the choke manifold valves, 5-7/8” TIW, 5-7/8” IBOP, upper and lower TD IBOP’s, choke and kill line valves to 250 psi low, 3500 psi high for 5 min. All tests charted, see attached BOP test charts.Test witnessed by AOGCC rep Kam St. John. Performed the koomey draw down test. Tested all gas alarms. Tested the active and trip tank alarms and flow paddle alarm. Successful test. Rig up and test the 13-3/8” casing to 2600 psi high. Successful test. Pick up 12-1/4" bit and directional BHA. Tag top plug at 2,480’. Condition mud and circulate while waiting on Worley trucks for displacement. Well Name Wellbore Name PTD # Start Drill Date End Drill Date Page 1 of 7 Well Name NDBi-014 Wellbore Name Original Hole PTD # 223-105 Start Drill Date 4/1/2023 End Drill Date 2/15/2024 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 12/30/2023 12/31/2023 2,570 1,180.00 12.00 No accidents, incidents or spills. Circulate and condition mud. Displace 10 ppg spud mud with 12 ppg MOBM. Tag float collar at 2483’ md. Drill float collar, shoe track and shoe at 2564' md. Cleaned old hole to 2570'. Drilled 12-1/4” hole from 2570’ md to 2590’ md. Perform FIT. Pressured up down the DP and the Annulus to 592 psi. Monitored the casing and the casing pressure dropped to 520psi in 10 min. Mud Weight: 12.0 ppg, 2290' TVD, 2590' md. Pumped in 1.5bbls and bled back 1.3bbls. FIT EMW: 16.96 ppg. Good test. Drilled ahead 12-1/4" directional hole 2590’ md to 3750 md. 12/31/2023 1/1/2024 3,750 2,277.00 12.00 No accidents, incidents or spills. Drill ahead in 12-1/4" Intermediate Hole from 3750' md to 6027' md (3388' TVD). 1/1/2024 1/2/2024 6,027 2,765.00 12.00 No accidents, incidents or spills. Drill ahead in 12-1/4" Intermediate Hole from 6027' md to 8792' md (4166' TVD). 1/2/2024 1/3/2024 8,792 549.00 12.00 No accidents, incidents or spills. Drill ahead in 12-1/4" Intermediate Hole from 9054' md to 9341' md. (4275' TVD). Stopped drilling operations due to extreme weather conditions. Rotate at 5 rpm with pumps off. Monitor well on trip tank. Circulate bottoms up every ~6 hours. 1/3/2024 1/4/2024 9,341 0.00 12.15 No accidents or incidents. Hold for weather. Phase 3 conditions. Rotate 5 rpm 8.0-9.5k Torque at 9308’ md. Monitor the well on the trip tank. Circulate bottoms up every ~6 hours. 1/4/2024 1/5/2024 9,341 0.00 12.15 No accidents, incidents or spills. Hold for weather. Phase 2 conditions. Rotate 5 rpm 8.0-9.5k Torque at 9308’ md. Monitor the well on the trip tank. Circulate bottoms up every ~6 hours. 1/5/2024 1/6/2024 9,341 0.00 12.20 No accidents, incidents or spills. Hold for weather. Phase 2 conditions. Rotate 5 rpm 8.0k-9.5k Torque at 9308’ md. Monitor the well on the trip tank. Circulate bottoms up every ~6 hours. 1/6/2024 1/7/2024 9,341 949.00 12.10 No accidents, incidents or spills. Kuparuk roads at phase 2 at 04:50. Begin re-start plan. Condition mud and resume drilling ahead in 12-1/4" Intermediate Hole from 9341' md to 10,290' md. 1/7/2024 1/8/2024 10,290 157.00 12.10 No incidents or spills. Drilled 12-1/4" directional hole from 10290’ to TD at10447’ md (4370' TVD). Conduct Cleanup Cycles. Wait on weather Phase 3 Pikka, Phase 3 Kuparuk and Hilcorp. Circulate B/U while B/R 10285’ md to 10210’ md and ream back down to 10257’ md. Note: - Day shift down 4 rig personnel, the Day Rig Manager, and the Worley Day Loader Operator due to Norovirus – Santos Medical requiring 48 hour isolation AFTER symptoms have resolved. 1/8/2024 1/9/2024 10,447 0.00 12.05 No accidents, incidents or spills. Wait on weather, all clear called field wide by 08:00. Monitor the well on trip tank with bit at 10,257’ md. Rotate 5 rpm, 9-10k torque, Rot Wt 166k. Ream down to 10477' md and perform 2 clean up cycles. Rotate at 10415' md and monitor the well on trip tank. Circulate bottoms up every 6-8 hours. Too short on labor to back ream out of hole. Night shift down 6 personnel due to Norovirus. Day shift down 7 crew members due to Norovirus. 1/9/2024 1/10/2024 10,447 0.00 12.00 No accidents, incidents or spills. Monitor well due to lack of crew members sick from Norovirus. - Monitor the well on trip tank with bit at 10,415’ md. Rotate 5 rpm, 9-10k torque, Rot Wt 156k. Begin backreaming operations at 13:00. Backream Out of Hole from 10447’ md to 9344’ md. Page 2 of 7 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 1/10/2024 1/11/2024 10,447 0.00 12.00 No accidents, incidents or spills. Backream Out of Hole from 9344’ to 7507’ md. 1/11/2024 1/12/2024 10,447 0.00 12.00 No accidents, incidents or spills. Backream Out of Hole from 7507’ to 7263'. Flow check for 10 min. Well static. Pump out of hole from 7,556’ to 6,455’. Unable to get past 6,455', attempt to stage pumps to drilling rate. Packing off. Worked back down to 6,523’. Circulate 2 bottoms up. Pull string with no rotation, 2 bpm past 6450’ with no issues. Pull to 6392’, encounter overpull. Move down to 6415’, circulate wellbore. POOH from 6415’ to 5910’. Overpull at 5910’, move string down to 5927’. Circulate wellbore. POH from 5910’ to 5724’. 1/12/2024 1/13/2024 10,447 0.00 12.00 No accidents, incidents or spills. Circulate wellbore at 5,724'. POH from 5,724’ to 5,510’. RIH & Circulate wellbore at 5,535'. POH from 5,535’ to 5,419’. RIH & Conduct full cleanup cycle at 5,453'. Pikka - Declared Phase 3 weather conditions at 07:56 hrs. Phase 2 announced at 14:00 hrs. Pump out from 5,640’ to 4,410’. RIH & Conduct full cleanup cycle at 4,490'. Pump out from 4,490’ to 4,015’. RIH & Conduct circulation cycle at 4,114'. Due to operational and weather setbacks, unable to begin BOP test by Midnight of 1-12-2024 as required by AOGCC. AOGCC rep, Jim Regg, had granted tentative approval for extension based upon operations on 1-11-2024. Rig Well Site Supervisors have been keeping AOGCC rep Austin McLeod updated of operation progress and forecast for expected start time. 1/13/2024 1/14/2024 10,447 0.00 12.00 No accidents, incidents or spills. Circulate wellbore at 4,093'. Slack off to 4,118' to check SO wt. POH from 4,118’ to 3950’. RIH & circulate wellbore at 4,005'. POH from 4,015’ to 2,445’. Pull inside 13-3/8" casing shoe & CBU 3 times. Set Halliburton RTTS at 85' per Halliburton rep. Flush stack & test 13-5/8" BOPE. Test BOPE to 250 psi low, 3,500 psi high for 5 minutes each. Test with 5-7/8” and 9-5/8” test joints, test annular with 5-7/8” Joint. All tests charted, see attached BOP test charts. Test Witness Waived by AOGCC inspector Austin McLeod.RD BOPE test equipment. 1/14/2024 1/15/2024 10,447 0.00 12.05 No accidents, incidents or spills. Rig down from testing BOP. Pull Halliburton RTTS, circulate wellbore. RIH from 2,437’ to 3,015’. Circulate cleanup cycle from 3,015’. RIH from 3,015 to 3,470’. Circulate cleanup cycle from 3,470’. RIH from 3,561’ to 4,225’. Circulate cleanup cycle from 4,225’. RIH from 4,225’ to 4,585’. Circulate cleanup cycle from 4,585’. RIH from 4,585’ to 5,265’. Circulate cleanup cycle from 5,265’. RIH from 5,265’ to 6,028’. Circulate cleanup cycle from 6,028’. 1/15/2024 1/16/2024 10,447 0.00 12.00 No accidents, incidents or spills. Circulate cleanup cycle from 6,028’. RIH from 6,028’ to 7,495’. Circulate cleanup cycle from 7,495’. RIH from 7,495’ to 10,150’. Wash and ream to bottom from 10,150’ to 10,447’. Circulate cleanup cycle from 10,447’-10,191’. Pump out from 10,191’ to 2,540’. 1/16/2024 1/17/2024 10,447 0.00 12.05 No accidents, incidents or spills. Circulate inside shoe at 2,525’. Flow check at shoe. POH with BHA from 2,525’. RU & RIH with 9 -5/8”, 47#, L-80, HYD 563 Liner from surface to 4,734’. 1/17/2024 1/18/2024 10,447 0.00 12.00 No accidents, incidents or spills. Run in open hole with 9-5/8”, 47#, L-80, HYD 563 Liner from 4,734’ to 8,031’. Make up liner hanger/packer assembly. Circulate to condition mud for cement job. Set liner hanger, 9-5/8” shoe set at 10,440’, Liner top set at 2,374’. Begin 1st Stage Cement Job. Page 3 of 7 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 1/18/2024 1/19/2024 10,447 0.00 12.00 No accidents, incidents or spills. Conduct 1st Stage Cement Job of 9-5/8” Liner. 9-5/8” shoe at 10,440’, Float collar at 10,363’, Stage Tool at 5,137’, Liner top at 2,374’. Pump 80 bbl 13.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 4 bpm, full returns. Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 3.7 bpm, initial circulating pressure 400 psi. Land dart at 52 bbls away at 3.5 bpm at latch (as calculated), clear indication of latch and release. Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 270 bbls @ average of 3.7 bpm, 400 psi, excess volume 30% (1225 sacks, yield 1.237 cu ft/sk), final circulating pressure 100 psi, full returns throughout. Release top pump down plug, chase with 10 bbls of washup from Halliburton. Perform displacement with rig pumps, displace with 12.0 ppg OBM at initial rate of 6 bpm, 435 psi to catch cement (did not catch before slowing rate). Top pump down dart latch up confirmed at 52 bbls displaced (as calculated). Continue to displace with 12.0 ppg OBM at 4 bpm, 337 psi ICP with full returns as Spacer pill exits shoe. Bottom plug lands 18 bbls behind calculated strokes at 3,832, 1,345 psi. Displace at 4 bpm, 545 psi with bottom plug landed, increase to 6 bpm, 850 psi at 4,400 strokes, pushing fluid away, reduce back down to 4 bpm, 670 psi. Losing fluid, back down to 3 bpm, 593 psi initial. FCP 605 psi at plug bump. Pressure up to 1,200 psi and hold. Total displacement volume 632 bbls (measured by strokes @ 96% pump efficiency). Total losses from cement exit shoe to cement in place: 75 bbls, Check floats, Pick up out of liner hanger and circulate bottoms up. POOH with BHA. RIH with Cementing Tool. Circulate and condition annular well fluid for 2nd Stage Cement Job. Circulate Cased Hole Spacer in Prep for 2nd stage cement job. Conduct 2nd Stage Cement Job of 9-5/8” Liner. Cement 9-5/8” 47# Intermediate casing 1/19/2024 1/20/2024 10,447 0.00 12.00 No accidents, incidents or spills. Displace Cement from 9-5/8” 47# Intermediate casing 2nd Stage. Displace Cement from 9-5/8" 2nd Stage. Displace to calculated volume of 119 bbls to Archer Stage Collar. Begin displacing with 10 bbls fresh water from cementing unit. Continue to displace with 109 bbls 12.0 ppg OBM using rig pumps. Stage up to initial rate of 6 bpm, 860 psi, 7% flow returns, observing slight losses, back rate off to 5 bpm, 770 psi, 5% flow return. Final circulating pressure at 5 bpm 875 psi. Slow displacement to 3 bpm, 640 psi, last 10 bbls. Dump fluids when dyed Tuned Spacer back to surface. CIP @ 0031 hrs.Close C-Flex tool. Set Liner Top Packer. RD cementing equipment. POH with Archer cementing tool BHA. Clear and clean rig floor. RIH with Polish Mill Cleanout BHA. Dress liner top (tagged liner top on depth at 2,374’). POOH with Polish Mill Cleanout BHA. RU & Run 9-5/8” 47# L-80 Hyd 563 Tie-Back assembly to 2,378'. Seal test. Close in on Annular element and pump down backside to conduct test against seals to 650 psi. No bleed, good test. Conduct spaceout. 1/20/2024 1/21/2024 10,447 0.00 12.00 No accidents, incidents or spills. Freeze protect 13-3/8” x 9-5/8” annulus. Land out 9-5/8” Tie-Back Assembly string into Sealbore. Conduct 13-3/8” x 9-5/8” annulus in-flow test. Monitor well for 30 minutes. No flow from below liner top packer into annulus. Install Annulus monitoring equipment. Pressure test against sealbore element / Liner Top Packer to 2,600 psi. Install Casing Packoff. Pressure up backside to 2,900 psi with 6.8 ppg diesel test fluid. Monitor test for 30 minutes on chart. Bled off quickly on first and second attempt (bleeding at test pump). Pressure back up and close in two valves to isolate pump from annulus, initial pressure 2,900 psi, pressure after 15 minutes 2,810 psi, final pressure at 30 minutes 2,790 psi – good test. Fluid to pressure up 3 bbls (based on strokes), fluid bled back 3 bbls.Conduct 9-5/8” casing test. Pressure up 9-5/8" casing/tieback to 3,800 psi with 12.0 ppg OBM. Monitor test for 30 minutes on chart. Initial pressure 3,746 psi, pressure after 15 minutes 3,713 psi, final pressure at 30 minutes 3,691 psi, good test. Fluid to pressure up 11.5 bbls, fluid bled back 11.5 bbls.M/U and Install Test Plug. Test 13-5/8" BOPE to 250 psi low, 3,500 psi high for 5 minutes each. Test with 5” and 4-1/2” test joints, test annular with 4-1/2” Joint. All tests charted, see attached BOP test charts. Test Witness Waived by AOGCC inspector Kam St. John on 1/20/2024 at 06:20 hrs. 1/21/2024 1/22/2024 10,447 44.00 10.00 No accidents, incidents or spills. Swap out Saver Sub from 5-7/8” to 5”. Mobilize Directional tools to floor, MU & RIH with 8-1/2" Production BHA on 5” drill pipe from surface to 10,190'. Slip & cut drill line. Wash down from 10,190’ to 10,365’. Displace to 10 ppg MOBM. Drill out 9-5/8" shoe track to 10,467'. Conduct LOT. Test with target of 15.0 ppg EMW. Pressure up but clear breakover at ~720 psi, pump 3 more strokes to ensure leak-off, clear breakover trend. 3.1 bbls pumped. Close in to isolate pump, monitor, pressure bled but stabilized at ~680 psi with very slow decline. Record results, send to Engineer. Engineer interpreted Leak-off at 694 psi, equivalent LOT = 13.05 ppg EMW. Acceptable to drill ahead, 2.5 bbls bled back after test.Drill 8-1/2” Production Hole from 10,467’ MD to 10,491’ MD (4,370’ TVD). 1/22/2024 1/23/2024 10,491 2,489.00 10.00 No accidents, incidents or spills. Drill 8-1/2” Production Hole from 10,491’ MD to 12,980' MD. Page 4 of 7 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 1/23/2024 1/24/2024 12,980 920.00 10.00 No accidents, incidents or spills. Drill 8-1/2” Production Hole from 12,980’ to 13,229’. Phase 3 conditions called at 02:00 to 13:00 (Phase 3 across field). Drill 8-1/2” Production Hole from 13,229’ to 13,263’. Backream from 13,263’ to 13,135’. Drill 8-1/2” Production Hole from 13,263’ to 13,900’. 1/24/2024 1/25/2024 13,900 1,509.00 10.00 No accidents, incidents or spills. Drill ahead in 8-1/2” Production hole to TD of 15,409’ MD. Perform clean up cycles at 15,409'. Backream out of hole from 15,130’ to 14,751’. Rig Service. 1/25/2024 1/26/2024 15,409 0.00 10.05 No accidents, incidents or spills. Backream out of hole from 14,751’ MD to 12,475’ MD. At 12,475’ MD partial packoff. Continue to backream with reduced pulling speed from 12,475’ MD to 11,335’ MD. Rig Service. 1/26/2024 1/27/2024 15,409 0.00 10.00 No accidents, incidents or spills. Continue to backream with reduced pulling speed from 11335’ MD to 11,114’ MD. Packed off at 11,114’ MD, made multiple attempts while running deeper in the hole to 11,353’ MD. Low Energy BROOH from 11,353’ MD to 10,378' MD. Circulate a bottoms up at 10,378’ MD to 10,283’ MD. RIH from 10,283' MD to 10,760’ MD. Circulate bottoms up at 10,760' MD, could not backream due to packoff. RIH from 10,760’ MD to 12,570’ MD on elevators. Circulate bottoms up twice racking back a stand each bottoms up from 12,570' MD to 12,378' MD. Pump out of hole from 12,378’ MD to 10,953’ MD. Rig Service. 1/27/2024 1/28/2024 15,409 0.00 10.00 No accidents, incidents or spills. Pump out of hole from 10,953’ MD to 10,440’ MD. Downlink to SoundTrack tool to log top of cement. Log from 10,440' MD to 2,400' MD. POOH on elevators from 2,400’ MD. Perform weekly BOP ram function test. Good test. Lay down BHA. Clean and clear rig floor. Rig up to run 4-1/2” Lower Completions. Rig Service. 1/28/2024 1/29/2024 15,409 0.00 10.00 No accidents, incidents or spills. Run 4-1/2” 12.6#, P-110S, HYD 563 Production Liner to 5,060' MD. PU & MU Baker liner hanger packer tool. Circulate 90 bbls to clear the casing string. Run in hole with 4-1/2" Production Liner on 5” DP from 5,060’ MD to 10,250’ MD. At 10,250' MD the liner hanger hung up in the Archer tool (depth 5,137' MD to 5,145’ MD). Came free & RIH to 10,400’ MD. Conference Anchorage office to discuss. Continue RIH from 10,400' MD to 10,620' MD. 20K drag observed at 10,620’ MD. Work pipe until free and able to slack off to connection at 10,647’ MD with 80K down. Work pipe from 10,647’ MD to 10,725’ MD. At 10,725’ MD the string came free, P/U to 10,715' MD and attempt to RIH, rotary stalled. Release torque & resume working pipe with varying parameters. 1/29/2024 1/30/2024 15,409 0.00 10.00 No accidents, incidents or spills. Lower completion assembly stuck at 10,715’ MD. Conference with town and made decision to set the Baker SLZXP Liner Hanger/Packer. Increase pressure to activate SLZXP hanger/packer. Test packer to 2000 PSI for 5 minutes - Good test. Unsting from liner hanger/packer & POOH. Make up and run in hole with Fishing BHA #1, tag fish at 5,590' MD. Spear into fish. Broke the PBR connection free and observed a good indication of a backoff. POOH. OAL of fish-PBR 10.03’. No visible damage. 1/30/2024 1/31/2024 15,409 0.00 10.05 No accidents, incidents or spills. Wait on Baker fishing tools, stuck behind rig move. Make up 8-1/2” Packer milling BHA and run in hole from surface to 5,597’ MD, tagged solid at 5,597'. Mill the fish 5,598.83’ MD to 5,607’ MD. Circulate bottoms up twice to clean hole. POOH on elevators from 5,607’ MD to 2,626’ MD. Rig service. 1/31/2024 2/1/2024 15,409 0.00 10.00 No accidents, incidents or spills. POOH on elevators from 2,626’ MD to 345’ MD. Lay down milling BHA. Make up and Run in hole with Baker clean out assembly to 5,324’ MD. Drop 7/8” ball at 5,324’ MD for the RCJB. Wash down from 5,324' MD to 5,617’ MD. Circulate bottoms up twice & pump high vis super sweep. POOH from 5,621’ MD and lay down clean out assembly. Recovered 163 lbs of swarf from BHA. Rig Service. Page 5 of 7 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 2/1/2024 2/2/2024 15,409 0.00 10.00 No accidents, incidents or spills. Clean & clear rig floor of MOBM. Make up and run in hole with Baker clean out assembly to 5,296’ MD. Cleanout above the fish. Continue to run in hole with ball on seat to 5,583’ MD. Wash down and tag TOF at 5,622' MD. Pump 40 bbl high vis super sweep & circulate out. POOH from 5,621’ MD to surface. Lay down clean out assembly. Clean and clear rig floor. Make up and run in hole with Baker clean out assembly on elevators from surface to 5,108’ MD. Rig Service. 2/2/2024 2/3/2024 15,409 0.00 10.00 No accidents, incidents or spills. Wash down from 5,583’ MD to top of fish at 5,621’ MD. Set down 5K on fish. Dropped 7/8” ball to activate RCJB. Clean up top of fish. S/O to tag fish at 5,621.7’ with 94K hookload. Fish took 25K down weight to push to 5,627’ MD, (NO rotary). Pull and rack back 1 stand slowly to check for swabbing. No swabbing. POOH on elevators from 5,578’ MD to 464' MD. POOH from 464’ MD to surface laying down BHA. Rig up and test BOPE equipment, TEST BOPE as follows: ***AOGCC notified for BOP test at 22:05 hrs 1-31-2024. Witness waved by Austin McLeod at 05:49 hrs 2-1-2024. Test Annular, LPR’s, Blind/Shear, UPR’s, 5” and 4-1/2” test joints, Lower and Upper IBOP, Choke Manifold, and Delta 544 FOSV/Dart to 250 Low for 5 mins and 3,500 PSI High for 5 mins. Perform draw down test. Starting system pressure 3,000 PSI. Closing times: -Annular – 32 seconds. -UPR’s – 6 seconds. -Blind/Shear – 7 seconds. -LPR’s – 6 seconds. -HCR Kill – 2 seconds. -HCR Choke – 2 seconds. Pressure after closure – 1,900 PSI. 200 PSI attained at 18 seconds; full pressure attained at 80 seconds. Average Nitrogen for 14 bottles – 2,300 PSI. Good test. Rig down test equipment. 2/3/2024 2/4/2024 15,409 0.00 10.00 No accidents, incidents or spills. Cut and slip. Make up Baker fishing BHA (spear run). Run in hole with Baker fishing assembly from 306’ MD to 5,532’ MD. Circulate bottoms up X2 to condition mud. Stab into fish, TOF at 5,627’ MD. Conduct fishing operations. Only movement observed was down 5’. Discuss options with Baker office and Santos office. Work pipe at 5,632’ MD to check for stability of fish in the hole. POOH on elevators from 5,632’ MD to 307’ MD. Lay down BHA from 307' MD to surface. Pick up packer Milling assy fishing BHA #7. Run in hole with milling BHA on 5” DP from 367’ MD to 5,200’ MD, wash down to 5,600’ MD. 2/4/2024 2/5/2024 15,409 0.00 10.00 No accidents, incidents or spills. Wash down from 5,596’ MD to top of fish at 5,632’ MD. Mill fish from 5,632’ MD to 5,649.63’ MD. POOH from 5,649’ MD to 304' MD. Lay down the BHA. Make up fishing BHA #8. Run in hole on elevators 459’ MD to 5,215' MD. Work the RCJB cleanout BHA. Circulate down 5,215’ MD to 5,405’ MD. Run in hole and tag top of fish at 5,649’ MD. Wash off top of fish with 6 BPM. POOH on elevators from 5,649’ to 367’ MD. Lay down clean out assembly. 2/5/2024 2/6/2024 15,409 0.00 10.00 No accidents, incidents or spills. Lay down clean out assembly. Make up fixed RCJB assembly. Run in hole from 370’ to 5,600’. Wash down to tag top of fish at 5,649’. Pumped 37 bbl super sweep around. POOH 5,648’ to Surface. Lay down the RCJB assembly. Make up and RIH with the spear assy from 303' to 5,500' MD. Circulate bottoms up x2 before engaging liner with grapple/spear assembly. Tag top of fish at 5,653’ MD. Pull on elevators from 10,400’ MD (4-1/2" shoe depth) to 7,400’ MD. 2/6/2024 2/7/2024 15,409 0.00 10.00 No accidents or incidents. Continue to POOH on elevators from 7,400’ to 5,068’. Mix and pump 10 bbl dry job. Unsting from fish and lay down tools to pipe shed. Lay down 4-1/2" tubing from 5,068’ to surface. Make up cased hole clean out BHA. 2/7/2024 2/8/2024 15,409 0.00 10.00 No accidents, incidents or spills. RIH with cased hole clean out BHA from 376' to 2,473'. RIH on elevators from 2,473’ to 5,028’. MU TD and wash down from 5,028’ through Archer tool to 5,180’. Wash & ream down from 5,180’ to 6,000’. Pump 40 bbl Super sweep pill. POH with Casing clean out BHA from 6,000’ to BHA. Make up 8 ½” open hole clean out BHA. RIH with 8 ½” open hole clean out BHA from 377’ to 4,276’ MD. Page 6 of 7 Operations Summary Report - AOGCC Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal) Summary 2/8/2024 2/9/2024 15,409 0.00 10.05 No accidents, incidents or spills. Continue RIH on elevators with 8 ½” open hole cleanout BHA from 4,276’ to 10,363’ MD. MU TD and wash down from 10,363’ to shoe at 10,440’. Began taking wt. at 10,460’ worked down to 10,743’. Wash and Ream from 10,646’ to 10,770’. Drill string packed off and became stuck at 10,770’. Fired jars, freed up, pulled from 10,770 to 10,730’. Washing and reaming in the hole from 10,730 to 11,005’. Continue mitigating torque spikes and packoffs while washing down from 11,005’ to 11,377’. RIH on elevators at 70 ft/min from 11,377’ to 12,520’. Circulate bottoms up while reciprocating drill string. 2/9/2024 2/10/2024 15,409 0.00 10.05 No accidents, incidents or spills. RIH on elevators at 70 ft/min from 12,520’ to 13,974’. Circulate bottoms up while reciprocating drill string from 13,974’ to 15,394’. Circulate bottoms up 2X Racking back stand every B/U 15,394’ to 15,200’. Pump out of hole from 15,200’ to 11,490'. Circulate bottoms up 2X Racking back stand every B/U 11,490’ to 11,290’. Pump out of hole from 11,290 to 10,779’. Circulate bottoms up at the shoe. Pump out of hole from 10,440’ to 8,458’. 2/10/2024 2/11/2024 15,409 0.00 10.10 No accidents, incidents or spills. Pump dry job. POOH on elevators from 8,458’ to 392’. Lay down BHA. M/U Stack Washing Tool and String magnet flush stack. R/U TRS Torque Turn equipment, casing tongs and elevators. Run 4 1/2”, 12.6#, P-110S, TSH563 Completion Liner to 5,245’ MD. 2/11/2024 2/12/2024 15,409 0.00 10.10 No accidents, incidents or spills. Continue RIH at 40 FPM from 5,245’ to 15,385'. Displace MOBM with10 ppg NaCl/KCL Brine. R/U and Test Baker SLZXP Liner top packer, good test. Displace well with 2nd stage 9.4 ppg brine. POOH on elevators from 10,151’ to 9,235’ MD. 2/12/2024 2/13/2024 15,409 0.00 9.41 No accidents, incidents or spills. POOH with Liner running tools. from 9,235’ to Surface. R/U to Run 4 ½” Upper Completion. Run 4 ½” Upper tie back Completion from 134’ to 3,852’. 2/13/2024 2/14/2024 15,409 0.00 9.43 No accidents, incidents or spills. Run 4 ½” Upper tie back completion from 3,852’ to 10,172’. PU XO and stand of drill pipe. Run in to 10’ above liner hanger. Slack off to NO-GO with 10k down weight. PU and SO again to verify NO-GO. LD stand and XO. 2/14/2024 2/15/2024 15,409 0.00 9.43 No accidents, incidents or spills. Pick up Hanger pup, tubing hanger assembly, and landing joint. Pressure test the swagelock with FMC to 5,000 psi. MIT-T to 4,000 psi for 30 min, good test. MIT -IA to 4000 psi for 30 min, good test. Lay down landing joint and close in well. Freeze protect tubing and IA to 1,500’ with 105 bbls diesel, by pumping down IA with Diesel freeze protect pump. R/U and Install TWC. N/D BOPE. Rig Down Operations. Terminate wellhead lines. 2/15/2024 2/15/2024 15,409 0.00 9.43 No accidents, incidents or spills. Complete NU and torque of 10k frac tree. ***Rig release from NDBi-014 at 0300 hrs, continue with preparing for rig move to NDBi-030. Page 7 of 7 Sa n t o s D e f i n i t i v e S u r v e y R e p o r t 14 F e b r u a r y , 2 0 2 4 De s i g n : N D B i - 0 1 4 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 -01 4 ND B i -01 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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 1 4 us f t us f t 0. 0 0. 0 5, 9 7 2 , 8 4 4 . 3 4 42 2 , 4 6 2 . 7 7 22 . 8 We l l h e a d E l e v a t i o n : us f t 0. 9 70 ° 2 0 ' 9 . 4 0 2 N 15 0 ° 3 7 ' 4 4 . 6 6 8 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 1 4 Mo d e l N a m e Ma g n e t i c s BG G M 2 0 2 3 3 1 / 1 2 / 2 0 2 3 1 4 . 4 1 8 0 . 5 8 5 7 , 1 7 5 . 9 2 1 2 7 4 0 2 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 1 4 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 . 9 27 3 . 6 9 0. 0 0. 0 46 . 9 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 Tr u e Fr o m (us f t ) Su r v e y P r o g r a m De s c r i p t i o n To o l N a m e Su r v e y (We l l b o r e ) To (us f t )Da t e 14 / 0 2 / 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 ) 11 3 . 1 6 2 9 . 5 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 69 7 . 1 2 , 4 9 5 . 6 02 B H O n t r a k _16 i n H o l e <69 7 -24 9 5 > (ND B 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 2, 6 0 2 . 8 3 , 6 1 7 . 0 03 B H O n t r a k _12 .25 i n H o l e <26 0 2 -36 1 7 > 3_ M W D + S a g A 0 0 2 M b / I S C 4 : B G G M d e c + s a g c o r r e c t i o n s 3, 7 1 1 . 8 3 , 8 0 6 . 4 04 B H O n t r a K k _12 .25 i n H o l e <37 1 1 -38 0 6 > 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 3, 9 0 1 . 6 1 0 , 4 0 6 . 1 05 B H O n t r a K k _12 .25 i n H o l e <39 0 1 -10 4 0 6 3_ M W D + I F R 2 + M S + S a g A 0 1 3 M b : I I F R d e c & m u l t i - s t a t i o n a n a l y s i s + s a g 10 , 4 6 8 . 5 1 5 , 4 0 9 . 0 06 B H O n t r a k _8 . 5 in H o l e <10 4 6 8 - 1 5 4 0 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 . 9 0 . 0 0 0 . 0 0 4 6 . 9 - 2 2 . 8 0 . 0 0 . 0 5 , 9 7 2 , 8 4 4 . 3 4 4 2 2 , 4 6 2 . 7 7 0 . 0 0 0 . 0 11 3 . 1 0 . 2 5 1 3 4 . 3 0 1 1 3 . 1 4 3 . 4 - 0 . 1 0 . 1 5 , 9 7 2 , 8 4 4 . 2 4 4 2 2 , 4 6 2 . 8 7 0 . 3 8 - 0 . 1 12 8 . 0 0 . 2 2 1 3 7 . 4 7 1 2 8 . 0 5 8 . 3 - 0 . 1 0 . 1 5 , 9 7 2 , 8 4 4 . 1 9 4 2 2 , 4 6 2 . 9 1 0 . 2 3 - 0 . 2 20 " C o n d u c t o r D r i v e n 20 7 . 2 0 . 0 9 1 9 2 . 3 0 2 0 7 . 2 1 3 7 . 5 - 0 . 3 0 . 2 5 , 9 7 2 , 8 4 4 . 0 2 4 2 2 , 4 6 3 . 0 0 0 . 2 3 - 0 . 3 27 9 . 4 0 . 5 9 1 6 9 . 4 5 2 7 9 . 3 2 0 9 . 6 - 0 . 7 0 . 3 5 , 9 7 2 , 8 4 3 . 6 0 4 2 2 , 4 6 3 . 0 5 0 . 7 0 - 0 . 3 37 4 . 5 3 . 0 2 1 7 0 . 5 1 3 7 4 . 4 3 0 4 . 7 - 3 . 7 0 . 8 5 , 9 7 2 , 8 4 0 . 6 4 4 2 2 , 4 6 3 . 5 3 2 . 5 5 - 1 . 0 46 8 . 6 3 . 9 0 1 6 9 . 8 0 4 6 8 . 4 3 9 8 . 7 - 9 . 3 1 . 8 5 , 9 7 2 , 8 3 5 . 0 3 4 2 2 , 4 6 4 . 4 4 0 . 9 4 - 2 . 4 56 2 . 5 5 . 2 4 1 7 0 . 5 1 5 6 2 . 0 4 9 2 . 3 - 1 6 . 7 3 . 0 5 , 9 7 2 , 8 2 7 . 6 5 4 2 2 , 4 6 5 . 6 4 1 . 4 3 - 4 . 1 62 9 . 5 5 . 3 1 1 7 2 . 9 7 6 2 8 . 7 5 5 9 . 0 - 2 2 . 8 3 . 9 5 , 9 7 2 , 8 2 1 . 5 5 4 2 2 , 4 6 6 . 4 6 0 . 3 5 - 5 . 4 69 7 . 1 7 . 8 3 1 8 7 . 0 4 6 9 5 . 8 6 2 6 . 1 - 3 0 . 4 3 . 7 5 , 9 7 2 , 8 1 3 . 8 8 4 2 2 , 4 6 6 . 2 0 4 . 4 0 - 5 . 7 79 1 . 9 8 . 5 7 1 9 7 . 9 3 7 8 9 . 7 7 2 0 . 0 - 4 3 . 6 0 . 8 5 , 9 7 2 , 8 0 0 . 7 8 4 2 2 , 4 6 3 . 1 0 1 . 8 1 - 3 . 6 88 5 . 3 1 0 . 7 6 2 0 1 . 6 0 8 8 1 . 7 8 1 2 . 0 - 5 8 . 3 - 4 . 6 5 , 9 7 2 , 7 8 6 . 1 1 4 2 2 , 4 5 7 . 5 9 2 . 4 4 0 . 8 98 0 . 0 1 2 . 6 3 2 0 3 . 6 2 9 7 4 . 5 9 0 4 . 8 - 7 6 . 0 - 1 2 . 0 5 , 9 7 2 , 7 6 8 . 4 7 4 2 2 , 4 5 0 . 0 1 2 . 0 2 7 . 1 1, 0 4 3 . 0 1 1 . 6 1 20 4 . 1 4 1, 0 3 6 . 1 9 6 6 . 4 - 8 8 . 1 - 1 7 . 3 5 , 9 7 2 , 7 5 6 . 4 4 4 2 2 , 4 4 4 . 5 3 1 . 6 4 1 1 . 6 Up p e r S c h r a d e r B l u f f 1, 0 7 4 . 7 1 1 . 0 9 2 0 4 . 4 3 1 , 0 6 7 . 2 9 9 7 . 5 - 9 3 . 8 - 1 9 . 9 5 , 9 7 2 , 7 5 0 . 7 9 4 2 2 , 4 4 1 . 9 1 1. 6 4 13 . 8 1, 1 6 9 . 0 1 1 . 6 9 2 0 5 . 2 2 1 , 1 5 9 . 6 1 , 0 8 9 . 9 - 1 1 0 . 7 - 2 7 . 7 5 , 9 7 2 , 7 3 3 . 9 7 4 2 2 , 4 3 3 . 9 2 0 . 6 6 2 0 . 5 Ba s e I c e B e a r i n g P e r m a f r o s t 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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, 1 6 9 . 3 1 1 . 6 9 2 0 5 . 2 2 1 , 1 5 9 . 9 1 , 0 9 0 . 2 - 1 1 0 . 7 - 2 7 . 7 5 , 9 7 2 , 7 3 3 . 9 2 4 2 2 , 4 3 3 . 8 9 0 . 6 6 2 0 . 6 1, 2 6 4 . 2 1 5 . 0 7 2 0 6 . 8 3 1 , 2 5 2 . 2 1 , 1 8 2 . 5 - 1 3 0 . 4 - 3 7 . 4 5 , 9 7 2 , 7 1 4 . 3 1 4 2 2 , 4 2 4 . 0 2 3 . 5 8 2 8 . 9 1, 3 5 9 . 6 1 7 . 9 5 2 0 8 . 4 1 1 , 3 4 3 . 7 1 , 2 7 4 . 0 - 1 5 4 . 5 - 5 0 . 0 5 , 9 7 2 , 6 9 0 . 4 3 4 2 2 , 4 1 1 . 1 7 3 . 0 5 4 0 . 0 1, 4 0 6 . 0 1 9 . 3 7 2 0 8 . 2 9 1 , 3 8 7 . 6 1 , 3 1 7 . 9 - 1 6 7 . 5 - 5 7 . 0 5 , 9 7 2 , 6 7 7 . 4 5 4 2 2 , 4 0 4 . 0 0 3 . 0 6 4 6 . 1 Ba s e P e r m a f r o s t T r a n s i t i o n 1, 4 5 4 . 1 2 0 . 8 4 2 0 8 . 1 9 1 , 4 3 2 . 8 1 , 3 6 3 . 1 - 1 8 2 . 1 - 6 4 . 9 5 , 9 7 2 , 6 6 2 . 9 6 4 2 2 , 3 9 6 . 0 2 3 . 0 6 5 3 . 0 1, 5 4 9 . 0 2 3 . 6 6 2 0 9 . 7 0 1 , 5 2 0 . 6 1 , 4 5 0 . 9 - 2 1 3 . 5 - 8 2 . 3 5 , 9 7 2 , 6 3 1 . 7 2 4 2 2 , 3 7 8 . 2 8 3 . 0 3 6 8 . 4 1, 6 4 4 . 5 2 6 . 5 1 2 1 2 . 5 9 1 , 6 0 7 . 1 1, 5 3 7 . 4 -2 4 8 . 1 - 1 0 3 . 3 5 , 9 7 2 , 5 9 7 . 3 3 4 2 2 , 3 5 6 . 9 5 3 . 2 5 8 7 . 1 1, 7 3 8 . 7 2 9 . 2 6 2 1 3 . 6 1 1 , 6 9 0 . 3 1 , 6 2 0 . 6 - 2 8 5 . 0 - 1 2 7 . 3 5 , 9 7 2 , 5 6 0 . 7 2 4 2 2 , 3 3 2 . 5 2 2 . 9 6 1 0 8 . 7 1, 7 9 6 . 0 3 0 . 7 1 2 1 4 . 0 2 1 , 7 4 0 . 0 1 , 6 7 0 . 3 - 3 0 8 . 8 - 1 4 3 . 3 5 , 9 7 2 , 5 3 7 . 0 8 4 2 2 , 3 1 6 . 3 2 2 . 5 5 1 2 3 . 1 Mi d d l e S c h r a d e r B l u f f 1, 8 3 2 . 8 3 1 . 6 4 2 1 4 . 2 7 1 , 7 7 1 . 5 1 , 7 0 1 . 8 - 3 2 4 . 6 - 1 5 4 . 0 5 , 9 7 2 , 5 2 1 . 4 0 4 2 2 , 3 0 5 . 4 6 2 . 5 5 1 3 2 . 8 1, 9 2 7 . 5 3 4 . 4 0 21 6 . 1 4 1, 8 5 0 . 9 1 , 7 8 1 . 2 - 3 6 6 . 7 - 1 8 3 . 7 5 , 9 7 2 , 4 7 9 . 6 0 4 2 2 , 2 7 5 . 2 7 3 . 1 1 1 5 9 . 7 2, 0 2 2 . 6 3 8 . 6 9 2 1 7 . 9 9 1 , 9 2 7 . 2 1 , 8 5 7 . 5 - 4 1 1 . 8 - 2 1 7 . 9 5 , 9 7 2 , 4 3 4 . 8 3 4 2 2 , 2 4 0 . 6 6 4 . 6 6 1 9 0 . 9 2, 1 1 6 . 9 4 2 . 4 0 2 1 6 . 8 9 1 , 9 9 8 . 9 1 , 9 2 9 . 2 - 4 6 0 . 5 - 2 5 5 . 1 5 , 9 7 2 , 3 8 6 . 5 2 4 2 2 , 2 0 2 . 9 1 4 . 0 0 2 2 5 . 0 2, 2 1 1 . 3 4 5 . 5 7 2 1 6 . 1 7 2 , 0 6 6 . 9 1 , 9 9 7 . 2 - 5 1 3 . 2 - 2 9 4 . 2 5 , 9 7 2 , 3 3 4 . 2 4 4 2 2 , 1 6 3 . 3 5 3 . 4 0 2 6 0 . 5 2, 3 0 6 . 6 4 8 . 5 1 2 1 6 . 2 7 2 , 1 3 1 . 7 2 , 0 6 2 . 0 - 5 6 9 . 4 - 3 3 5 . 3 5 , 9 7 2 , 2 7 8 . 4 6 4 2 2 , 1 2 1 . 6 0 3 . 0 9 2 9 8 . 0 2, 3 4 5 . 0 4 9 . 7 0 2 1 6 . 7 3 2 , 1 5 6 . 9 2 , 0 8 7 . 2 - 5 9 2 . 8 - 3 5 2 . 6 5 , 9 7 2 , 2 5 5 . 2 9 4 2 2 , 1 0 4 . 0 8 3 . 2 3 3 1 3 . 7 MC U 2, 4 0 1 . 3 5 1 . 4 5 2 1 7 . 3 7 2 , 1 9 2 . 7 2 , 1 2 3 . 0 - 6 2 7 . 5 - 3 7 8 . 8 5 , 9 7 2 , 2 2 0 . 8 4 4 2 2 , 0 7 7 . 5 0 3 . 2 3 3 3 7 . 6 2, 4 9 5 . 6 5 3 . 8 9 2 1 8 . 7 8 2 , 2 4 9 . 8 2 , 1 8 0 . 1 - 6 8 6 . 5 - 4 2 5 . 1 5 , 9 7 2 , 1 6 2 . 3 5 4 2 2 , 0 3 0 . 6 8 2 . 8 5 3 8 0 . 0 2, 5 6 3 . 8 5 5 . 0 7 2 1 9 . 0 4 2 , 2 8 9 . 5 2 , 2 1 9 . 8 - 7 2 9 . 7 - 4 5 9 . 9 5 , 9 7 2 , 1 1 9 . 5 1 4 2 1 , 9 9 5 . 3 7 1 . 7 5 4 1 2 . 0 13 - 3 / 8 " S u r f a c e C a s i n g 2, 6 0 2 . 8 5 5 . 7 4 2 1 9 . 1 8 2 , 3 1 1 . 6 2 , 2 4 1 . 9 - 7 5 4 . 6 - 4 8 0 . 2 5 , 9 7 2 , 0 9 4 . 8 1 4 2 1 , 9 7 4 . 8 6 1 . 7 5 4 3 0 . 6 2, 6 6 9 . 7 5 7 . 9 3 2 1 9 . 8 9 2 , 3 4 8 . 2 2 , 2 7 8 . 5 - 7 9 7 . 8 - 5 1 5 . 8 5 , 9 7 2 , 0 5 2 . 0 3 4 2 1 , 9 3 8 . 7 9 3 . 3 9 4 6 3 . 4 2, 7 6 4 . 5 6 0 . 4 4 2 2 0 . 2 0 2 , 3 9 6 . 8 2 , 3 2 7 . 1 - 8 6 0 . 1 - 5 6 8 . 2 5 , 9 7 1 , 9 9 0 . 2 2 4 2 1 , 8 8 5 . 7 4 2 . 6 6 5 1 1 . 7 2, 8 5 9 . 1 6 3 . 3 8 2 2 0 . 8 0 2 , 4 4 1 . 3 2 , 3 7 1 . 6 - 9 2 3 . 5 - 6 2 2 . 4 5 , 9 7 1 , 9 2 7 . 3 9 4 2 1 , 8 3 0 . 9 4 3 . 1 6 5 6 1 . 6 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 Tr u e MD (us f t ) In c (° ) Az i (az i m u t h ) (° ) N/ S (us f t ) E/ W (us f t ) No r t h i n g (us f t ) TV D S S (us f t ) Ea s t i n g (us f t ) Su r v e y TV D (us f t ) DL e g (° / 10 0 u s f t ) V. S e c (us f t ) 2, 8 8 6 . 0 6 4 . 1 6 2 2 0 . 9 5 2 , 4 5 3 . 2 2 , 3 8 3 . 5 - 9 4 1 . 8 - 6 3 8 . 2 5 , 9 7 1 , 9 0 9 . 2 7 4 2 1 , 8 1 4 . 9 3 2 . 9 4 5 7 6 . 2 Tu l u v a k S h a l e 2, 9 5 5 . 4 6 6 . 1 7 2 2 1 . 3 2 2 , 4 8 2 . 3 2 , 4 1 2 . 6 - 9 8 9 . 2 - 6 7 9 . 6 5 , 9 7 1 , 8 6 2 . 2 7 4 2 1 , 7 7 3 . 0 1 2 . 9 4 6 1 4 . 5 3, 0 4 8 . 4 6 8 . 4 8 2 2 1 . 3 6 2 , 5 1 8 . 2 2 , 4 4 8 . 5 - 1 , 0 5 3 . 7 - 7 3 6 . 3 5 , 9 7 1 , 7 9 8 . 4 5 4 2 1 , 7 1 5 . 6 8 2 . 4 8 6 6 6 . 9 3, 0 5 6 . 0 6 8 . 6 7 2 2 1 . 3 8 2 , 5 2 1 . 0 2 , 4 5 1 . 3 - 1 , 0 5 9 . 0 - 7 4 1 . 0 5 , 9 7 1 , 7 9 3 . 1 9 4 2 1 , 7 1 0 . 9 5 2 . 5 5 6 7 1 . 3 Tu l u v a k S a n d 3, 1 4 3 . 0 7 0 . 8 9 2 2 1 . 5 5 2 , 5 5 1 . 0 2 , 4 8 1 . 3 - 1 , 1 2 0 . 2 - 7 9 5 . 1 5 , 9 7 1 , 7 3 2 . 5 5 4 2 1 , 6 5 6 . 2 5 2 . 5 5 7 2 1 . 3 3, 2 3 8 . 4 7 2 . 8 0 2 2 1 . 9 2 2 , 5 8 0 . 8 2 , 5 1 1 . 1 - 1 , 1 8 7 . 8 - 8 5 5 . 4 5 , 9 7 1 , 6 6 5 . 5 4 4 2 1 , 5 9 5 . 2 1 2 . 0 4 7 7 7 . 1 3, 3 3 5 . 1 7 2 . 9 2 2 2 1 . 9 0 2 , 6 0 9 . 2 2 , 5 3 9 . 5 - 1 , 2 5 6 . 5 - 9 1 7 . 1 5 , 9 7 1 , 5 9 7 . 4 7 4 2 1 , 5 3 2 . 8 3 0 . 1 3 8 3 4 . 3 3, 4 2 9 . 7 7 2 . 8 6 2 2 2 . 0 2 2 , 6 3 7 . 1 2, 5 6 7 . 4 -1 , 3 2 3 . 8 - 9 7 7 . 6 5 , 9 7 1 , 5 3 0 . 8 4 4 2 1 , 4 7 1 . 6 6 0 . 1 4 8 9 0 . 3 3, 5 2 2 . 0 7 2 . 9 2 2 2 1 . 9 1 2 , 6 6 4 . 2 2 , 5 9 4 . 5 - 1 , 3 8 9 . 4 - 1 , 0 3 6 . 6 5 , 9 7 1 , 4 6 5 . 8 7 4 2 1 , 4 1 2 . 0 1 0 . 1 3 9 4 4 . 9 3, 6 1 7 . 0 7 2 . 8 8 2 2 1 . 7 0 2 , 6 9 2 . 2 2 , 6 2 2 . 5 - 1 , 4 5 7 . 1 - 1 , 0 9 7 . 1 5 , 9 7 1 , 3 9 8 . 8 3 4 2 1 , 3 5 0 . 8 0 0 . 2 2 1 , 0 0 1 . 0 3, 7 1 1 . 8 7 2 . 8 6 2 2 1 . 7 9 2 , 7 2 0 . 1 2, 6 5 0 . 4 -1 , 5 2 4 . 6 - 1 , 1 5 7 . 4 5 , 9 7 1 , 3 3 1 . 8 8 4 2 1 , 2 8 9 . 8 0 0 . 0 9 1 , 0 5 6 . 8 3, 8 0 6 . 4 72 . 8 8 2 2 1 . 7 7 2 , 7 4 8 . 0 2 , 6 7 8 . 3 - 1 , 5 9 2 . 1 - 1 , 2 1 7 . 7 5 , 9 7 1 , 2 6 5 . 0 6 4 2 1 , 2 2 8 . 8 4 0 . 0 3 1 , 1 1 2 . 6 3, 9 0 1 . 6 7 2 . 9 2 2 2 2 . 0 8 2 , 7 7 5 . 9 2 , 7 0 6 . 2 - 1 , 6 5 9 . 8 - 1 , 2 7 8 . 4 5 , 9 7 1 , 1 9 8 . 0 1 4 2 1 , 1 6 7 . 3 6 0 . 3 1 1 , 1 6 8 . 9 3, 9 9 6 . 4 73 . 1 2 2 2 1 . 7 1 2 , 8 0 3 . 6 2 , 7 3 3 . 9 - 1 , 7 2 7 . 2 - 1 , 3 3 8 . 9 5 , 9 7 1 , 1 3 1 . 1 9 4 2 1 , 1 0 6 . 1 6 0 . 4 3 1 , 2 2 5 . 0 4, 0 9 0 . 6 7 3 . 1 8 2 2 1 . 6 6 2 , 8 3 0 . 9 2 , 7 6 1 . 2 - 1 , 7 9 4 . 6 - 1 , 3 9 8 . 9 5 , 9 7 1 , 0 6 4 . 4 8 4 2 1 , 0 4 5 . 5 1 0 . 0 8 1 , 2 8 0 . 5 4, 1 8 5 . 3 7 3 . 2 1 2 2 1 . 3 3 2 , 8 5 8 . 3 2 , 7 8 8 . 6 - 1 , 8 6 2 . 5 - 1 , 4 5 9 . 0 5 , 9 7 0 , 9 9 7 . 2 0 4 2 0 , 9 8 4 . 7 4 0 . 3 4 1 , 3 3 6 . 0 4, 2 8 0 . 5 7 3 . 4 4 2 2 1 . 6 9 2 , 8 8 5 . 6 2 , 8 1 5 . 9 - 1 , 9 3 0 . 8 - 1 , 5 1 9 . 4 5 , 9 7 0 , 9 2 9 . 5 6 4 2 0 , 9 2 3 . 6 2 0 . 4 4 1 , 3 9 1 . 9 4, 3 7 5 . 3 7 3 . 3 7 2 2 1 . 7 0 2 , 9 1 2 . 7 2 , 8 4 3 . 0 - 1 , 9 9 8 . 6 - 1 , 5 7 9 . 8 5 , 9 7 0 , 8 6 2 . 3 7 4 2 0 , 8 6 2 . 5 1 0 . 0 7 1 , 4 4 7 . 9 4, 4 6 9 . 9 7 3 . 4 3 2 2 2 . 1 5 2 , 9 3 9 . 7 2 , 8 7 0 . 0 - 2 , 0 6 6 . 1 - 1 , 6 4 0 . 4 5 , 9 7 0 , 7 9 5 . 5 3 4 2 0 , 8 0 1 . 2 3 0 . 4 6 1 , 5 0 4 . 0 4, 5 6 4 . 6 7 3 . 3 7 2 2 2 . 3 8 2 , 9 6 6 . 8 2 , 8 9 7 . 1 - 2 , 1 3 3 . 2 - 1 , 7 0 1 . 5 5 , 9 7 0 , 7 2 9 . 0 0 4 2 0 , 7 3 9 . 4 9 0 . 2 4 1 , 5 6 0 . 6 4, 6 5 9 . 2 7 3 . 3 0 2 2 3 . 1 0 2 , 9 9 3 . 9 2 , 9 2 4 . 2 - 2 , 1 9 9 . 8 - 1 , 7 6 3 . 0 5 , 9 7 0 , 6 6 3 . 1 0 4 2 0 , 6 7 7 . 3 3 0 . 7 3 1 , 6 1 7 . 7 4, 7 5 4 . 6 7 3 . 3 0 2 2 2 . 8 5 3 , 0 2 1 . 3 2 , 9 5 1 . 6 - 2 , 2 6 6 . 7 - 1 , 8 2 5 . 3 5 , 9 7 0 , 5 9 6 . 8 8 4 2 0 , 6 1 4 . 3 3 0 . 2 5 1 , 6 7 5 . 5 4, 8 4 9 . 0 7 3 . 4 4 2 2 2 . 3 3 3 , 0 4 8 . 3 2 , 9 7 8 . 6 - 2 , 3 3 3 . 3 - 1 , 8 8 6 . 5 5 , 9 7 0 , 5 3 0 . 9 3 4 2 0 , 5 5 2 . 4 4 0 . 5 5 1 , 7 3 2 . 3 4, 9 4 4 . 0 7 3 . 4 1 2 2 2 . 2 7 3 , 0 7 5 . 5 3 , 0 0 5 . 8 - 2 , 4 0 0 . 6 - 1 , 9 4 7 . 8 5 , 9 7 0 , 4 6 4 . 2 3 4 2 0 , 4 9 0 . 4 8 0 . 0 7 1 , 7 8 9 . 2 5, 0 3 8 . 5 7 3 . 4 4 2 2 2 . 1 9 3 , 1 0 2 . 4 3 , 0 3 2 . 7 - 2 , 4 6 7 . 7 - 2 , 0 0 8 . 6 5 , 9 7 0 , 3 9 7 . 8 0 4 2 0 , 4 2 8 . 9 2 0 . 0 9 1 , 8 4 5 . 6 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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, 1 1 2 . 0 7 3 . 4 6 2 2 1 . 9 7 3 , 1 2 3 . 3 3 , 0 5 3 . 6 - 2 , 5 1 9 . 9 - 2 , 0 5 5 . 8 5 , 9 7 0 , 3 4 6 . 0 2 4 2 0 , 3 8 1 . 1 8 0 . 2 8 1 , 8 8 9 . 3 Se a b e e 5, 1 3 3 . 4 7 3 . 4 7 2 2 1 . 9 1 3 , 1 2 9 . 4 3 , 0 5 9 . 7 - 2 , 5 3 5 . 2 - 2 , 0 6 9 . 5 5 , 9 7 0 , 3 3 0 . 9 4 4 2 0 , 3 6 7 . 3 4 0 . 2 8 1 , 9 0 2 . 0 5, 2 2 8 . 3 7 3 . 3 1 2 2 2 . 0 8 3 , 1 5 6 . 6 3 , 0 8 6 . 9 - 2 , 6 0 2 . 8 - 2 , 1 3 0 . 4 5 , 9 7 0 , 2 6 3 . 9 4 4 2 0 , 3 0 5 . 7 6 0 . 2 4 1 , 9 5 8 . 4 5, 3 2 2 . 5 7 3 . 1 8 2 2 1 . 5 9 3 , 1 8 3 . 7 3 , 1 1 4 . 0 - 2 , 6 7 0 . 0 - 2 , 1 9 0 . 6 5 , 9 7 0 , 1 9 7 . 3 7 4 2 0 , 2 4 4 . 9 1 0 . 5 2 2 , 0 1 4 . 1 5, 4 1 7 . 2 7 3 . 2 5 2 2 1 . 3 0 3 , 2 1 1 . 1 3 , 1 4 1 . 4 - 2 , 7 3 8 . 0 - 2 , 2 5 0 . 6 5 , 9 7 0 , 1 3 0 . 0 3 4 2 0 , 1 8 4 . 2 0 0 . 3 0 2 , 0 6 9 . 6 5, 5 1 2 . 0 7 3 . 2 7 2 2 0 . 8 4 3 , 2 3 8 . 4 3 , 1 6 8 . 7 - 2 , 8 0 6 . 4 - 2 , 3 1 0 . 2 5 , 9 7 0 , 0 6 2 . 2 3 4 2 0 , 1 2 3 . 8 7 0 . 4 7 2 , 1 2 4 . 7 5, 6 0 6 . 6 7 3 . 2 7 2 2 0 . 7 9 3 , 2 6 5 . 6 3 , 1 9 5 . 9 - 2 , 8 7 5 . 0 - 2 , 3 6 9 . 4 5 , 9 6 9 , 9 9 4 . 2 9 4 2 0 , 0 6 3 . 9 6 0 . 0 5 2 , 1 7 9 . 4 5, 7 0 2 . 0 7 3 . 0 8 2 2 0 . 5 2 3 , 2 9 3 . 2 3 , 2 2 3 . 5 - 2 , 9 4 4 . 2 - 2 , 4 2 8 . 9 5 , 9 6 9 , 9 2 5 . 6 7 4 2 0 , 0 0 3 . 7 9 0 . 3 4 2 , 2 3 4 . 3 5, 7 9 6 . 9 7 3 . 0 5 2 2 0 . 9 0 3 , 3 2 0 . 8 3 , 2 5 1 . 1 - 3 , 0 1 3 . 0 - 2 , 4 8 8 . 1 5 , 9 6 9 , 8 5 7 . 4 8 4 1 9 , 9 4 3 . 8 7 0 . 3 8 2 , 2 8 8 . 9 5, 8 9 1 . 0 7 3 . 0 2 2 2 0 . 9 3 3 , 3 4 8 . 3 3 , 2 7 8 . 6 - 3 , 0 8 1 . 1 - 2 , 5 4 7 . 1 5 , 9 6 9 , 7 9 0 . 0 4 4 1 9 , 8 8 4 . 1 9 0 . 0 4 2 , 3 4 3 . 4 5, 9 8 5 . 8 7 2 . 9 9 2 2 1 . 5 8 3 , 3 7 6 . 0 3 , 3 0 6 . 3 - 3 , 1 4 9 . 2 - 2 , 6 0 6 . 9 5 , 9 6 9 , 7 2 2 . 5 4 4 1 9 , 8 2 3 . 7 4 0 . 6 6 2 , 3 9 8 . 7 6, 0 8 1 . 6 7 2 . 9 9 2 2 2 . 3 5 3 , 4 0 4 . 0 3 , 3 3 4 . 3 - 3 , 2 1 7 . 3 - 2 , 6 6 8 . 1 5 , 9 6 9 , 6 5 5 . 0 6 4 1 9 , 7 6 1 . 7 8 0 . 7 7 2 , 4 5 5 . 4 6, 1 7 4 . 6 7 3 . 0 5 2 2 3 . 0 5 3 , 4 3 1 . 2 3 , 3 6 1 . 5 - 3 , 2 8 2 . 7 - 2 , 7 2 8 . 5 5 , 9 6 9 , 5 9 0 . 3 1 4 1 9 , 7 0 0 . 7 8 0 . 7 2 2 , 5 1 1 . 4 6, 2 6 9 . 8 7 3 . 0 1 2 2 3 . 3 5 3 , 4 5 9 . 0 3 , 3 8 9 . 3 - 3 , 3 4 9 . 1 - 2 , 7 9 0 . 8 5 , 9 6 9 , 5 2 4 . 6 1 4 1 9 , 6 3 7 . 7 9 0 . 3 0 2 , 5 6 9 . 3 6, 3 6 3 . 2 7 3 . 0 5 2 2 4 . 1 9 3 , 4 8 6 . 2 3 , 4 1 6 . 5 - 3 , 4 1 3 . 6 - 2 , 8 5 2 . 5 5 , 9 6 9 , 4 6 0 . 7 6 4 1 9 , 5 7 5 . 3 5 0 . 8 6 2 , 6 2 6 . 8 6, 4 6 0 . 1 7 3 . 1 4 2 2 4 . 4 1 3 , 5 1 4 . 4 3 , 4 4 4 . 7 - 3 , 4 8 0 . 0 - 2 , 9 1 7 . 3 5 , 9 6 9 , 3 9 5 . 0 6 4 1 9 , 5 0 9 . 8 9 0 . 2 4 2 , 6 8 7 . 2 6, 5 5 4 . 8 7 3 . 0 4 2 2 4 . 0 4 3 , 5 4 2 . 0 3 , 4 7 2 . 3 - 3 , 5 4 4 . 9 - 2 , 9 8 0 . 5 5 , 9 6 9 , 3 3 0 . 7 8 4 1 9 , 4 4 6 . 0 2 0 . 3 9 2 , 7 4 6 . 1 6, 6 4 9 . 0 7 3 . 3 7 22 4 . 2 4 3, 5 6 9 . 2 3 , 4 9 9 . 5 - 3 , 6 0 9 . 6 - 3 , 0 4 3 . 3 5 , 9 6 9 , 2 6 6 . 7 4 4 1 9 , 3 8 2 . 5 8 0 . 4 1 2 , 8 0 4 . 6 6, 7 4 3 . 7 7 3 . 4 7 2 2 3 . 9 0 3 , 5 9 6 . 2 3 , 5 2 6 . 5 - 3 , 6 7 4 . 8 - 3 , 1 0 6 . 5 5 , 9 6 9 , 2 0 2 . 1 8 4 1 9 , 3 1 8 . 7 7 0 . 3 6 2 , 8 6 3 . 4 6, 8 3 8 . 5 7 3 . 4 6 2 2 2 . 5 8 3 , 6 2 3 . 2 3 , 5 5 3 . 5 - 3 , 7 4 1 . 0 - 3 , 1 6 8 . 7 5 , 9 6 9 , 1 3 6 . 6 1 4 1 9 , 2 5 5 . 8 3 1 . 3 3 2 , 9 2 1 . 3 6, 9 3 3 . 8 7 3 . 3 7 2 2 3 . 1 2 3 , 6 5 0 . 4 3 , 5 8 0 . 7 - 3 , 8 0 8 . 0 - 3 , 2 3 0 . 8 5 , 9 6 9 , 0 7 0 . 3 2 4 1 9 , 1 9 3 . 0 5 0 . 5 5 2 , 9 7 8 . 9 7, 0 2 8 . 6 7 3 . 2 1 2 2 2 . 7 1 3 , 6 7 7 . 7 3 , 6 0 8 . 0 - 3 , 8 7 4 . 5 - 3 , 2 9 2 . 7 5 , 9 6 9 , 0 0 4 . 4 6 4 1 9 , 1 3 0 . 5 3 0 . 4 5 3 , 0 3 6 . 4 7, 1 2 3 . 3 7 2 . 8 6 2 2 4 . 5 6 3 , 7 0 5 . 3 3 , 6 3 5 . 6 - 3 , 9 4 0 . 0 - 3 , 3 5 5 . 1 5 , 9 6 8 , 9 3 9 . 6 1 4 1 9 , 0 6 7 . 4 1 1 . 9 1 3 , 0 9 4 . 5 7, 2 1 7 . 8 7 2 . 7 9 2 2 8 . 0 2 3 , 7 3 3 . 2 3 , 6 6 3 . 5 - 4 , 0 0 2 . 4 - 3 , 4 2 0 . 4 5 , 9 6 8 , 8 7 7 . 9 1 4 1 9 , 0 0 1 . 5 1 3 . 5 0 3 , 1 5 5 . 6 7, 3 1 3 . 3 7 2 . 8 9 2 3 0 . 6 9 3 , 7 6 1 . 4 3 , 6 9 1 . 7 - 4 , 0 6 1 . 8 - 3 , 4 8 9 . 6 5 , 9 6 8 , 8 1 9 . 2 1 4 1 8 , 9 3 1 . 6 8 2 . 6 7 3 , 2 2 0 . 8 7, 4 0 7 . 6 7 2 . 9 2 2 3 2 . 0 4 3 , 7 8 9 . 1 3 , 7 1 9 . 4 - 4 , 1 1 8 . 1 - 3 , 5 6 0 . 0 5 , 9 6 8 , 7 6 3 . 6 6 4 1 8 , 8 6 0 . 7 0 1 . 3 7 3 , 2 8 7 . 5 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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, 5 0 2 . 1 7 2 . 7 7 23 4 . 3 4 3, 8 1 7 . 0 3 , 7 4 7 . 3 - 4 , 1 7 2 . 2 - 3 , 6 3 2 . 3 5 , 9 6 8 , 7 1 0 . 3 3 4 1 8 , 7 8 7 . 8 8 2 . 3 3 3 , 3 5 6 . 1 7, 5 9 6 . 8 7 2 . 8 9 2 3 6 . 4 8 3 , 8 4 4 . 9 3 , 7 7 5 . 2 - 4 , 2 2 3 . 6 - 3 , 7 0 6 . 8 5 , 9 6 8 , 6 5 9 . 7 2 4 1 8 , 7 1 2 . 8 3 2 . 1 6 3 , 4 2 7 . 2 7, 6 7 7 . 0 7 2 . 8 1 2 3 9 . 0 5 3 , 8 6 8 . 6 3 , 7 9 8 . 9 - 4 , 2 6 4 . 4 - 3 , 7 7 1 . 6 5 , 9 6 8 , 6 1 9 . 5 3 4 1 8 , 6 4 7 . 6 2 3 . 0 6 3 , 4 8 9 . 2 Na n u s h u k 7, 6 9 1 . 8 7 2 . 8 0 2 3 9 . 5 2 3 , 8 7 3 . 0 3 , 8 0 3 . 3 - 4 , 2 7 1 . 7 - 3 , 7 8 3 . 8 5 , 9 6 8 , 6 1 2 . 4 3 4 1 8 , 6 3 5 . 3 8 3 . 0 6 3 , 5 0 0 . 9 7, 7 4 0 . 0 7 2 . 7 9 2 4 0 . 8 0 3 , 8 8 7 . 2 3 , 8 1 7 . 5 - 4 , 2 9 4 . 6 - 3 , 8 2 3 . 7 5 , 9 6 8 , 5 8 9 . 9 4 4 1 8 , 5 9 5 . 2 2 2 . 5 4 3 , 5 3 9 . 3 NT 8 M F S 7, 7 8 6 . 7 7 2 . 7 9 2 4 2 . 0 4 3 , 9 0 1 . 1 3 , 8 3 1 . 4 - 4 , 3 1 5 . 9 - 3 , 8 6 2 . 9 5 , 9 6 8 , 5 6 9 . 0 0 4 1 8 , 5 5 5 . 8 2 2 . 5 4 3 , 5 7 7 . 0 7, 8 0 7 . 0 7 2 . 7 9 2 4 2 . 8 6 3 , 9 0 7 . 1 3, 8 3 7 . 4 -4 , 3 2 4 . 9 - 3 , 8 8 0 . 1 5 , 9 6 8 , 5 6 0 . 2 2 4 1 8 , 5 3 8 . 5 5 3 . 8 5 3 , 5 9 3 . 6 NT 7 M F S 7, 8 8 1 . 3 7 2 . 8 3 2 4 5 . 8 5 3 , 9 2 9 . 0 3 , 8 5 9 . 3 - 4 , 3 5 5 . 6 - 3 , 9 4 4 . 1 5 , 9 6 8 , 5 3 0 . 1 6 4 1 8 , 4 7 4 . 2 7 3 . 8 5 3 , 6 5 5 . 4 7, 9 7 5 . 9 7 3 . 3 7 2 4 9 . 2 2 3 , 9 5 6 . 5 3 , 8 8 6 . 8 - 4 , 3 9 0 . 2 - 4 , 0 2 7 . 7 5 , 9 6 8 , 4 9 6 . 4 5 4 1 8 , 3 9 0 . 2 8 3 . 4 6 3 , 7 3 6 . 7 8, 0 7 0 . 4 73 . 4 9 2 5 2 . 4 9 3 , 9 8 3 . 5 3 , 9 1 3 . 8 - 4 , 4 1 9 . 9 - 4 , 1 1 3 . 3 5 , 9 6 8 , 4 6 7 . 6 3 4 1 8 , 3 0 4 . 4 1 3 . 3 2 3 , 8 2 0 . 1 8, 1 3 3 . 0 7 3 . 8 9 25 5 . 3 4 4, 0 0 1 . 1 3, 9 3 1 . 4 -4 , 4 3 6 . 5 - 4 , 1 7 1 . 0 5 , 9 6 8 , 4 5 1 . 6 0 4 1 8 , 2 4 6 . 5 6 4 . 4 2 3 , 8 7 6 . 6 NT 6 M F S 8, 1 6 5 . 7 7 4 . 1 1 2 5 6 . 8 3 4 , 0 1 0 . 1 3 , 9 4 0 . 4 - 4 , 4 4 4 . 1 - 4 , 2 0 1 . 5 5 , 9 6 8 , 4 4 4 . 3 6 4 1 8 , 2 1 5 . 9 7 4 . 4 2 3 , 9 0 6 . 6 8, 2 6 0 . 6 7 4 . 5 2 2 6 0 . 0 8 4 , 0 3 5 . 7 3 , 9 6 6 . 0 - 4 , 4 6 2 . 3 - 4 , 2 9 0 . 9 5 , 9 6 8 , 4 2 7 . 0 1 4 1 8 , 1 2 6 . 3 3 3 . 3 3 3 , 9 9 4 . 7 8, 3 5 5 . 5 7 4 . 6 2 2 6 3 . 2 3 4 , 0 6 1 . 0 3 , 9 9 1 . 3 - 4 , 4 7 5 . 6 - 4 , 3 8 1 . 5 5 , 9 6 8 , 4 1 4 . 6 7 4 1 8 , 0 3 5 . 6 5 3 . 2 0 4 , 0 8 4 . 2 8, 4 5 0 . 0 7 5 . 5 4 2 6 5 . 6 2 4 , 0 8 5 . 3 4 , 0 1 5 . 6 - 4 , 4 8 4 . 5 - 4 , 4 7 2 . 3 5 , 9 6 8 , 4 0 6 . 7 5 4 1 7 , 9 4 4 . 7 2 2 . 6 3 4 , 1 7 4 . 3 NT 5 M F S 8, 4 5 0 . 3 7 5 . 5 4 2 6 5 . 6 3 4 , 0 8 5 . 4 4 , 0 1 5 . 7 - 4 , 4 8 4 . 5 - 4 , 4 7 2 . 7 5 , 9 6 8 , 4 0 6 . 7 3 4 1 7 , 9 4 4 . 4 0 2 . 6 3 4 , 1 7 4 . 6 8, 5 4 4 . 0 7 5 . 4 8 2 6 8 . 0 3 4 , 1 0 8 . 9 4 , 0 3 9 . 2 - 4 , 4 8 9 . 5 - 4 , 5 6 3 . 2 5 , 9 6 8 , 4 0 2 . 6 5 4 1 7 , 8 5 3 . 7 8 2 . 4 8 4 , 2 6 4 . 7 8, 6 3 9 . 5 7 6 . 5 7 2 7 0 . 4 4 4 , 1 3 1 . 9 4 , 0 6 2 . 2 - 4 , 4 9 0 . 8 - 4 , 6 5 5 . 9 5 , 9 6 8 , 4 0 2 . 3 7 4 1 7 , 7 6 1 . 1 1 2 . 7 0 4 , 3 5 7 . 1 8, 7 3 4 . 2 7 6 . 8 4 2 7 3 . 0 3 4 , 1 5 3 . 7 4 , 0 8 4 . 0 - 4 , 4 8 8 . 0 - 4 , 7 4 8 . 0 5 , 9 6 8 , 4 0 6 . 1 1 4 1 7 , 6 6 9 . 0 9 2 . 6 8 4 , 4 4 9 . 2 8, 7 8 5 . 0 7 7 . 3 0 2 7 4 . 2 3 4 , 1 6 5 . 1 4, 0 9 5 . 4 -4 , 4 8 4 . 8 - 4 , 7 9 7 . 4 5 , 9 6 8 , 4 0 9 . 7 6 4 1 7 , 6 1 9 . 7 2 2 . 4 8 4 , 4 9 8 . 7 NT 4 M F S 8, 8 3 0 . 1 7 7 . 7 2 2 7 5 . 2 9 4 , 1 7 4 . 8 4 , 1 0 5 . 1 - 4 , 4 8 1 . 2 - 4 , 8 4 1 . 2 5 , 9 6 8 , 4 1 3 . 8 6 4 1 7 , 5 7 5 . 9 0 2 . 4 8 4 , 5 4 2 . 7 8, 9 2 3 . 8 7 7 . 7 2 2 7 8 . 4 0 4 , 1 9 4 . 8 4 , 1 2 5 . 1 - 4 , 4 7 0 . 3 - 4 , 9 3 2 . 2 5 , 9 6 8 , 4 2 5 . 7 2 4 1 7 , 4 8 5 . 0 7 3 . 2 4 4 , 6 3 4 . 1 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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, 0 1 8 . 6 7 8 . 2 1 2 8 2 . 4 3 4 , 2 1 4 . 5 4 , 1 4 4 . 8 - 4 , 4 5 3 . 5 - 5 , 0 2 3 . 4 5 , 9 6 8 , 4 4 3 . 4 2 4 1 7 , 3 9 4 . 1 0 4 . 1 9 4 , 7 2 6 . 2 9, 1 1 3 . 6 7 8 . 2 5 2 8 5 . 8 5 4 , 2 3 3 . 9 4 , 1 6 4 . 2 - 4 , 4 3 0 . 8 - 5 , 1 1 3 . 5 5 , 9 6 8 , 4 6 7 . 0 6 4 1 7 , 3 0 4 . 2 0 3 . 5 3 4 , 8 1 7 . 6 9, 2 0 8 . 2 7 9 . 3 7 2 8 8 . 0 2 4 , 2 5 2 . 3 4 , 1 8 2 . 6 - 4 , 4 0 3 . 8 - 5 , 2 0 2 . 3 5 , 9 6 8 , 4 9 5 . 0 1 4 1 7 , 2 1 5 . 7 1 2 . 5 4 4 , 9 0 8 . 0 9, 3 0 3 . 0 8 0 . 2 5 2 9 0 . 1 0 4 , 2 6 9 . 0 4 , 1 9 9 . 3 - 4 , 3 7 3 . 3 - 5 , 2 9 0 . 4 5 , 9 6 8 , 5 2 6 . 3 6 4 1 7 , 1 2 7 . 9 3 2 . 3 5 4 , 9 9 7 . 8 9, 3 9 6 . 5 8 1 . 0 9 2 9 3 . 1 8 4 , 2 8 4 . 2 4 , 2 1 4 . 5 - 4 , 3 3 9 . 3 - 5 , 3 7 6 . 2 5 , 9 6 8 , 5 6 1 . 2 6 4 1 7 , 0 4 2 . 5 5 3 . 3 7 5 , 0 8 5 . 6 9, 4 9 2 . 1 8 1 . 8 4 2 9 6 . 2 8 4 , 2 9 8 . 4 4 , 2 2 8 . 7 - 4 , 2 9 9 . 7 - 5 , 4 6 2 . 1 5 , 9 6 8 , 6 0 1 . 7 2 4 1 6 , 9 5 7 . 0 5 3 . 3 0 5 , 1 7 3 . 9 9, 5 8 6 . 2 8 2 . 9 4 2 9 9 . 0 2 4 , 3 1 0 . 9 4 , 2 4 1 . 2 - 4 , 2 5 6 . 4 - 5 , 5 4 4 . 7 5 , 9 6 8 , 6 4 5 . 8 5 4 1 6 , 8 7 4 . 9 0 3 . 1 1 5 , 2 5 9 . 1 9, 6 8 0 . 9 8 3 . 9 1 3 0 1 . 4 4 4 , 3 2 1 . 7 4 , 2 5 2 . 0 - 4 , 2 0 9 . 1 - 5 , 6 2 6 . 0 5 , 9 6 8 , 6 9 4 . 0 6 4 1 6 , 7 9 4 . 1 1 2 . 7 4 5 , 3 4 3 . 3 9, 7 7 6 . 6 8 3 . 7 9 3 0 3 . 7 7 4 , 3 3 2 . 0 4 , 2 6 2 . 3 - 4 , 1 5 7 . 8 - 5 , 7 0 6 . 1 5 , 9 6 8 , 7 4 6 . 1 5 4 1 6 , 7 1 4 . 4 9 2 . 4 2 5 , 4 2 6 . 6 9, 8 7 0 . 9 8 3 . 8 8 3 0 5 . 7 7 4 , 3 4 2 . 1 4 , 2 7 2 . 4 - 4 , 1 0 4 . 4 - 5 , 7 8 3 . 1 5 , 9 6 8 , 8 0 0 . 3 6 4 1 6 , 6 3 8 . 1 1 2 . 1 1 5 , 5 0 6 . 8 9, 9 6 5 . 6 8 4 . 8 1 3 0 9 . 2 9 4 , 3 5 1 . 4 4 , 2 8 1 . 7 - 4 , 0 4 7 . 0 - 5 , 8 5 7 . 8 5 , 9 6 8 , 8 5 8 . 5 4 4 1 6 , 5 6 3 . 9 7 3 . 8 3 5 , 5 8 5 . 1 10 , 0 1 8 . 0 8 5 . 7 6 3 1 0 . 9 2 4 , 3 5 5 . 7 4 , 2 8 6 . 0 - 4 , 0 1 3 . 3 - 5 , 8 9 7 . 8 5 , 9 6 8 , 8 9 2 . 5 9 4 1 6 , 5 2 4 . 3 8 3 . 5 8 5 , 6 2 7 . 1 NT 3 M F S 10 , 0 6 0 . 8 8 6 . 5 3 3 1 2 . 2 4 4 , 3 5 8 . 6 4 , 2 8 8 . 9 - 3 , 9 8 5 . 0 - 5 , 9 2 9 . 7 5 , 9 6 8 , 9 2 1 . 2 6 4 1 6 , 4 9 2 . 7 3 3 . 5 8 5 , 6 6 0 . 8 10 , 1 5 5 . 0 8 8 . 1 1 3 1 5 . 5 7 4 , 3 6 3 . 0 4 , 2 9 3 . 3 - 3 , 9 1 9 . 7 - 5 , 9 9 7 . 5 5 , 9 6 8 , 9 8 7 . 1 9 4 1 6 , 4 2 5 . 6 4 3 . 9 1 5 , 7 3 2 . 7 10 , 2 5 0 . 4 8 8 . 2 2 3 1 9 . 4 0 4 , 3 6 6 . 1 4, 2 9 6 . 4 -3 , 8 4 9 . 5 - 6 , 0 6 1 . 9 5 , 9 6 9 , 0 5 8 . 1 0 4 1 6 , 3 6 1 . 9 6 4 . 0 2 5 , 8 0 1 . 5 10 , 3 4 6 . 2 8 8 . 8 3 3 2 2 . 1 9 4 , 3 6 8 . 5 4 , 2 9 8 . 8 - 3 , 7 7 5 . 3 - 6 , 1 2 2 . 4 5 , 9 6 9 , 1 3 2 . 9 1 4 1 6 , 3 0 2 . 2 2 2 . 9 8 5 , 8 6 6 . 6 10 , 4 0 6 . 1 8 9 . 0 5 3 2 3 . 7 1 4 , 3 6 9 . 6 4 , 2 9 9 . 9 - 3 , 7 2 7 . 4 - 6 , 1 5 8 . 5 5 , 9 6 9 , 1 8 1 . 1 2 4 1 6 , 2 6 6 . 6 0 2 . 5 6 5 , 9 0 5 . 8 10 , 4 4 0 . 0 8 9 . 2 0 3 2 3 . 4 3 4 , 3 7 0 . 2 4 , 3 0 0 . 5 - 3 , 7 0 0 . 2 - 6 , 1 7 8 . 7 5 , 9 6 9 , 2 0 8 . 5 7 4 1 6 , 2 4 6 . 7 7 0 . 9 5 5 , 9 2 7 . 6 9- 5 / 8 " I n t e r m e d i a t e L i n e r 10 , 4 4 7 . 0 8 9 . 2 3 3 2 3 . 3 7 4 , 3 7 0 . 3 4 , 3 0 0 . 6 - 3 , 6 9 4 . 6 - 6 , 1 8 2 . 8 5 , 9 6 9 , 2 1 4 . 2 3 4 1 6 , 2 4 2 . 6 5 0 . 9 5 5 , 9 3 2 . 1 NT 3 . 2 T o p R e s e r v o i r 10 , 4 6 8 . 5 8 9 . 3 3 3 2 3 . 1 9 4 , 3 7 0 . 5 4 , 3 0 0 . 8 - 3 , 6 7 7 . 3 - 6 , 1 9 5 . 7 5 , 9 6 9 , 2 3 1 . 6 0 4 1 6 , 2 2 9 . 9 7 0 . 9 5 5 , 9 4 6 . 1 10 , 5 4 6 . 2 9 0 . 1 0 3 2 5 . 0 1 4 , 3 7 0 . 9 4 , 3 0 1 . 2 - 3 , 6 1 4 . 4 - 6 , 2 4 1 . 2 5 , 9 6 9 , 2 9 5 . 0 0 4 1 6 , 1 8 5 . 0 7 2 . 5 4 5 , 9 9 5 . 6 10 , 6 4 0 . 4 9 1 . 6 0 3 2 7 . 4 4 4 , 3 6 9 . 5 4 , 2 9 9 . 8 - 3 , 5 3 6 . 1 - 6 , 2 9 3 . 6 5 , 9 6 9 , 3 7 3 . 8 0 4 1 6 , 1 3 3 . 5 4 3 . 0 3 6 , 0 5 2 . 9 10 , 7 3 5 . 7 9 1 . 9 7 3 2 7 . 9 7 4 , 3 6 6 . 6 4 , 2 9 6 . 9 - 3 , 4 5 5 . 6 - 6 , 3 4 4 . 5 5 , 9 6 9 , 4 5 4 . 8 0 4 1 6 , 0 8 3 . 5 1 0 . 6 8 6 , 1 0 8 . 8 10 , 8 3 0 . 9 9 1 . 9 4 3 2 7 . 8 1 4 , 3 6 3 . 3 4 , 2 9 3 . 6 - 3 , 3 7 5 . 0 - 6 , 3 9 5 . 1 5 , 9 6 9 , 5 3 5 . 9 4 4 1 6 , 0 3 3 . 7 5 0 . 1 7 6 , 1 6 4 . 5 10 , 9 2 6 . 3 9 1 . 9 7 3 2 9 . 0 9 4 , 3 6 0 . 1 4 , 2 9 0 . 4 - 3 , 2 9 3 . 8 - 6 , 4 4 4 . 9 5 , 9 6 9 , 6 1 7 . 6 6 4 1 5 , 9 8 4 . 7 3 1 . 3 4 6 , 2 1 9 . 5 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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 , 0 2 1 . 7 9 2 . 0 4 3 2 9 . 1 5 4 , 3 5 6 . 7 4 , 2 8 7 . 0 - 3 , 2 1 2 . 0 - 6 , 4 9 3 . 9 5 , 9 6 9 , 6 9 9 . 9 8 4 1 5 , 9 3 6 . 6 5 0 . 1 0 6 , 2 7 3 . 6 11 , 1 1 6 . 6 9 2 . 0 1 3 2 9 . 3 3 4 , 3 5 3 . 4 4 , 2 8 3 . 7 - 3 , 1 3 0 . 5 - 6 , 5 4 2 . 4 5 , 9 6 9 , 7 8 1 . 9 8 4 1 5 , 8 8 8 . 9 9 0 . 1 9 6 , 3 2 7 . 2 11 , 2 1 2 . 0 9 1 . 9 1 32 9 . 3 4 4, 3 5 0 . 1 4, 2 8 0 . 4 -3 , 0 4 8 . 5 - 6 , 5 9 1 . 0 5 , 9 6 9 , 8 6 4 . 4 6 4 1 5 , 8 4 1 . 2 3 0 . 1 1 6 , 3 8 1 . 0 11 , 3 0 6 . 5 9 1 . 9 4 3 2 8 . 9 1 4 , 3 4 6 . 9 4 , 2 7 7 . 2 - 2 , 9 6 7 . 4 - 6 , 6 3 9 . 5 5 , 9 6 9 , 9 4 6 . 0 4 4 1 5 , 7 9 3 . 5 9 0 . 4 6 6 , 4 3 4 . 6 11 , 4 0 1 . 8 9 2 . 0 4 3 2 9 . 4 2 4 , 3 4 3 . 6 4 , 2 7 3 . 9 - 2 , 8 8 5 . 6 - 6 , 6 8 8 . 3 5 , 9 7 0 , 0 2 8 . 3 2 4 1 5 , 7 4 5 . 6 2 0 . 5 4 6 , 4 8 8 . 6 11 , 4 9 6 . 4 9 2 . 0 7 3 2 9 . 6 7 4 , 3 4 0 . 2 4 , 2 7 0 . 5 - 2 , 8 0 4 . 1 - 6 , 7 3 6 . 2 5 , 9 7 0 , 1 1 0 . 2 9 4 1 5 , 6 9 8 . 5 6 0 . 2 7 6 , 5 4 1 . 7 11 , 5 9 1 . 2 9 2 . 0 4 3 2 9 . 1 6 4 , 3 3 6 . 8 4 , 2 6 7 . 1 - 2 , 7 2 2 . 5 - 6 , 7 8 4 . 4 5 , 9 7 0 , 1 9 2 . 3 3 4 1 5 , 6 5 1 . 2 1 0 . 5 4 6 , 5 9 5 . 0 11 , 6 8 6 . 7 9 2 . 0 1 3 2 8 . 8 6 4 , 3 3 3 . 4 4 , 2 6 3 . 7 - 2 , 6 4 0 . 7 - 6 , 8 3 3 . 6 5 , 9 7 0 , 2 7 4 . 7 0 4 1 5 , 6 0 2 . 8 9 0 . 3 2 6 , 6 4 9 . 4 11 , 7 8 1 . 6 9 1 . 9 7 3 2 8 . 7 4 4 , 3 3 0 . 1 4 , 2 6 0 . 4 - 2 , 5 5 9 . 6 - 6 , 8 8 2 . 7 5 , 9 7 0 , 3 5 6 . 3 2 4 1 5 , 5 5 4 . 6 0 0 . 1 3 6 , 7 0 3 . 6 11 , 8 7 6 . 4 9 1 . 9 1 3 2 8 . 7 8 4 , 3 2 6 . 9 4 , 2 5 7 . 2 - 2 , 4 7 8 . 6 - 6 , 9 3 1 . 8 5 , 9 7 0 , 4 3 7 . 8 0 4 1 5 , 5 0 6 . 3 2 0 . 0 8 6 , 7 5 7 . 9 11 , 9 7 1 . 3 9 2 . 0 1 3 2 8 . 8 1 4 , 3 2 3 . 7 4 , 2 5 4 . 0 - 2 , 3 9 7 . 4 - 6 , 9 8 1 . 0 5 , 9 7 0 , 5 1 9 . 4 5 4 1 5 , 4 5 8 . 0 1 0 . 1 1 6 , 8 1 2 . 1 12 , 0 6 6 . 5 9 2 . 0 4 3 2 8 . 5 2 4 , 3 2 0 . 3 4 , 2 5 0 . 6 - 2 , 3 1 6 . 2 - 7 , 0 3 0 . 4 5 , 9 7 0 , 6 0 1 . 1 5 4 1 5 , 4 0 9 . 4 2 0 . 3 1 6 , 8 6 6 . 7 12 , 1 6 1 . 7 9 1 . 9 7 3 2 9 . 1 7 4 , 3 1 7 . 0 4 , 2 4 7 . 3 - 2 , 2 3 4 . 8 - 7 , 0 7 9 . 7 5 , 9 7 0 , 6 8 3 . 1 0 4 1 5 , 3 6 1 . 0 2 0 . 6 9 6 , 9 2 1 . 1 12 , 2 5 7 . 0 9 1 . 9 4 3 2 9 . 1 6 4 , 3 1 3 . 7 4 , 2 4 4 . 0 - 2 , 1 5 2 . 9 - 7 , 1 2 8 . 5 5 , 9 7 0 , 7 6 5 . 4 0 4 1 5 , 3 1 3 . 0 4 0 . 0 3 6 , 9 7 5 . 1 12 , 3 5 1 . 9 9 2 . 0 1 3 2 9 . 4 0 4 , 3 1 0 . 5 4 , 2 4 0 . 8 - 2 , 0 7 1 . 4 - 7 , 1 7 6 . 9 5 , 9 7 0 , 8 4 7 . 3 9 4 1 5 , 2 6 5 . 4 6 0 . 2 6 7 , 0 2 8 . 7 12 , 4 4 6 . 9 9 2 . 0 4 3 2 9 . 8 6 4 , 3 0 7 . 1 4 , 2 3 7 . 4 - 1 , 9 8 9 . 5 - 7 , 2 2 5 . 0 5 , 9 7 0 , 9 2 9 . 8 0 4 1 5 , 2 1 8 . 3 1 0 . 4 8 7 , 0 8 1 . 9 12 , 5 4 1 . 4 9 1 . 9 4 3 2 9 . 3 3 4 , 3 0 3 . 8 4 , 2 3 4 . 1 - 1 , 9 0 8 . 1 - 7 , 2 7 2 . 7 5 , 9 7 1 , 0 1 1 . 6 9 4 1 5 , 1 7 1 . 3 9 0 . 5 7 7 , 1 3 4 . 8 12 , 6 3 6 . 7 9 1 . 9 4 3 2 9 . 3 6 4 , 3 0 0 . 6 4 , 2 3 0 . 9 - 1 , 8 2 6 . 1 - 7 , 3 2 1 . 3 5 , 9 7 1 , 0 9 4 . 1 7 4 1 5 , 1 2 3 . 6 5 0 . 0 3 7 , 1 8 8 . 5 12 , 7 3 1 . 3 9 2 . 0 1 3 2 9 . 7 5 4 , 2 9 7 . 4 4 , 2 2 7 . 7 - 1 , 7 4 4 . 6 - 7 , 3 6 9 . 2 5 , 9 7 1 , 1 7 6 . 1 6 4 1 5 , 0 7 6 . 5 9 0 . 4 2 7 , 2 4 1 . 6 12 , 8 2 6 . 7 9 2 . 0 7 3 2 9 . 8 6 4 , 2 9 4 . 0 4 , 2 2 4 . 3 - 1 , 6 6 2 . 3 - 7 , 4 1 7 . 1 5 , 9 7 1 , 2 5 9 . 0 0 4 1 5 , 0 2 9 . 5 2 0 . 1 3 7 , 2 9 4 . 7 12 , 9 2 1 . 4 9 2 . 0 1 3 2 9 . 9 5 4 , 2 9 0 . 6 4 , 2 2 0 . 9 - 1 , 5 8 0 . 4 - 7 , 4 6 4 . 6 5 , 9 7 1 , 3 4 1 . 3 5 4 1 4 , 9 8 2 . 9 3 0 . 1 1 7 , 3 4 7 . 3 13 , 0 1 6 . 0 9 1 . 9 1 3 2 9 . 5 4 4 , 2 8 7 . 4 4 , 2 1 7 . 7 - 1 , 4 9 8 . 7 - 7 , 5 1 2 . 3 5 , 9 7 1 , 4 2 3 . 5 6 4 1 4 , 9 3 6 . 1 1 0 . 4 5 7 , 4 0 0 . 2 13 , 1 1 1 . 0 9 1 . 9 4 3 2 9 . 4 1 4 , 2 8 4 . 2 4 , 2 1 4 . 5 - 1 , 4 1 6 . 9 - 7 , 5 6 0 . 5 5 , 9 7 1 , 5 0 5 . 7 7 4 1 4 , 8 8 8 . 7 8 0 . 1 4 7 , 4 5 3 . 5 13 , 2 0 6 . 7 9 2 . 0 1 3 2 9 . 5 5 4 , 2 8 0 . 9 4 , 2 1 1 . 2 - 1 , 3 3 4 . 5 - 7 , 6 0 9 . 0 5 , 9 7 1 , 5 8 8 . 6 7 4 1 4 , 8 4 1 . 0 5 0 . 1 6 7 , 5 0 7 . 3 13 , 3 0 1 . 2 9 1 . 9 8 3 2 9 . 3 5 4 , 2 7 7 . 6 4 , 2 0 7 . 9 - 1 , 2 5 3 . 2 - 7 , 6 5 7 . 1 5 , 9 7 1 , 6 7 0 . 5 2 4 1 4 , 7 9 3 . 8 8 0 . 2 1 7 , 5 6 0 . 5 13 , 3 9 6 . 9 9 1 . 9 7 3 2 9 . 3 6 4 , 2 7 4 . 3 4 , 2 0 4 . 6 - 1 , 1 7 0 . 9 - 7 , 7 0 5 . 8 5 , 9 7 1 , 7 5 3 . 2 9 4 1 4 , 7 4 5 . 9 9 0 . 0 1 7 , 6 1 4 . 4 13 , 4 9 1 . 8 9 1 . 9 8 3 2 9 . 2 1 4 , 2 7 1 . 0 4 , 2 0 1 . 3 - 1 , 0 8 9 . 3 - 7 , 7 5 4 . 3 5 , 9 7 1 , 8 3 5 . 3 4 4 1 4 , 6 9 8 . 3 8 0 . 1 6 7 , 6 6 8 . 0 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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 , 5 8 6 . 5 9 2 . 0 1 3 2 9 . 0 9 4 , 2 6 7 . 7 4 , 1 9 8 . 0 - 1 , 0 0 8 . 1 - 7 , 8 0 2 . 8 5 , 9 7 1 , 9 1 7 . 0 7 4 1 4 , 6 5 0 . 7 0 0 . 1 3 7 , 7 2 1 . 7 13 , 6 8 2 . 0 9 2 . 0 4 3 2 9 . 0 7 4 , 2 6 4 . 3 4 , 1 9 4 . 6 - 9 2 6 . 2 - 7 , 8 5 1 . 8 5 , 9 7 1 , 9 9 9 . 4 5 4 1 4 , 6 0 2 . 5 1 0 . 0 4 7 , 7 7 5 . 9 13 , 7 7 6 . 9 9 2 . 0 1 3 2 8 . 9 1 4 , 2 6 1 . 0 4 , 1 9 1 . 3 - 8 4 4 . 9 - 7 , 9 0 0 . 7 5 , 9 7 2 , 0 8 1 . 2 2 4 1 4 , 5 5 4 . 5 0 0 . 1 7 7 , 8 2 9 . 9 13 , 8 3 7 . 0 9 1 . 9 8 3 2 9 . 3 7 4 , 2 5 8 . 9 4 , 1 8 9 . 2 - 7 9 3 . 4 - 7 , 9 3 1 . 5 5 , 9 7 2 , 1 3 3 . 0 7 4 1 4 , 5 2 4 . 2 4 0 . 7 7 7 , 8 6 3 . 9 NT 3 . 2 4 13 , 8 7 1 . 7 9 1 . 9 7 3 2 9 . 6 4 4 , 2 5 7 . 7 4 , 1 8 8 . 0 - 7 6 3 . 5 - 7 , 9 4 9 . 1 5 , 9 7 2 , 1 6 3 . 1 1 4 1 4 , 5 0 6 . 9 7 0 . 7 7 7 , 8 8 3 . 4 13 , 9 6 6 . 0 9 2 . 0 4 3 2 9 . 7 5 4 , 2 5 4 . 4 4 , 1 8 4 . 7 - 6 8 2 . 1 - 7 , 9 9 6 . 6 5 , 9 7 2 , 2 4 4 . 9 8 4 1 4 , 4 6 0 . 2 5 0 . 1 4 7 , 9 3 6 . 1 14 , 0 6 1 . 7 9 2 . 0 1 3 2 9 . 8 6 4 , 2 5 1 . 0 4 , 1 8 1 . 3 - 5 9 9 . 4 - 8 , 0 4 4 . 8 5 , 9 7 2 , 3 2 8 . 1 7 4 1 4 , 4 1 2 . 9 9 0 . 1 2 7 , 9 8 9 . 5 14 , 1 5 6 . 4 9 1 . 7 9 3 2 9 . 0 6 4 , 2 4 7 . 9 4 , 1 7 8 . 2 - 5 1 8 . 0 - 8 , 0 9 2 . 8 5 , 9 7 2 , 4 1 0 . 1 2 4 1 4 , 3 6 5 . 7 7 0 . 8 8 8 , 0 4 2 . 7 14 , 2 5 2 . 0 9 1 . 9 8 3 2 8 . 7 1 4 , 2 4 4 . 7 4 , 1 7 5 . 0 - 4 3 6 . 1 - 8 , 1 4 2 . 2 5 , 9 7 2 , 4 9 2 . 4 7 4 1 4 , 3 1 7 . 2 2 0 . 4 2 8 , 0 9 7 . 3 14 , 3 4 6 . 2 9 2 . 0 4 3 2 8 . 7 2 4 , 2 4 1 . 4 4 , 1 7 1 . 7 - 3 5 5 . 7 - 8 , 1 9 1 . 1 5 , 9 7 2 , 5 7 3 . 3 6 4 1 4 , 2 6 9 . 2 1 0 . 0 6 8 , 1 5 1 . 2 14 , 4 4 2 . 5 9 1 . 9 8 3 2 9 . 2 1 4 , 2 3 8 . 0 4 , 1 6 8 . 3 - 2 7 3 . 2 - 8 , 2 4 0 . 7 5 , 9 7 2 , 6 5 6 . 3 8 4 1 4 , 2 2 0 . 4 1 0 . 5 1 8 , 2 0 6 . 1 14 , 5 3 7 . 4 9 1 . 9 4 3 2 9 . 0 9 4 , 2 3 4 . 8 4 , 1 6 5 . 1 - 1 9 1 . 8 - 8 , 2 8 9 . 3 5 , 9 7 2 , 7 3 8 . 2 2 4 1 4 , 1 7 2 . 6 7 0 . 1 3 8 , 2 5 9 . 8 14 , 6 3 1 . 9 9 1 . 9 4 3 2 9 . 5 7 4 , 2 3 1 . 6 4 , 1 6 1 . 9 - 1 1 0 . 6 - 8 , 3 3 7 . 5 5 , 9 7 2 , 8 1 9 . 9 6 4 1 4 , 1 2 5 . 3 3 0 . 5 1 8 , 3 1 3 . 1 14 , 7 2 7 . 2 9 1 . 9 8 3 2 9 . 8 1 4 , 2 2 8 . 3 4 , 1 5 8 . 6 - 2 8 . 4 - 8 , 3 8 5 . 6 5 , 9 7 2 , 9 0 2 . 6 7 4 1 4 , 0 7 8 . 1 2 0 . 2 6 8 , 3 6 6 . 4 14 , 8 2 1 . 5 9 1 . 8 8 3 2 9 . 6 0 4 , 2 2 5 . 2 4 , 1 5 5 . 5 5 3 . 0 - 8 , 4 3 3 . 1 5 , 9 7 2 , 9 8 4 . 5 2 4 1 4 , 0 3 1 . 4 3 0 . 2 5 8 , 4 1 9 . 0 14 , 9 1 7 . 0 9 1 . 6 4 3 3 0 . 5 5 4 , 2 2 2 . 2 4 , 1 5 2 . 5 1 3 5 . 8 - 8 , 4 8 0 . 8 5 , 9 7 3 , 0 6 7 . 7 6 4 1 3 , 9 8 4 . 6 5 1 . 0 3 8 , 4 7 1 . 9 15 , 0 1 2 . 3 9 1 . 8 8 3 3 0 . 4 0 4 , 2 1 9 . 3 4 , 1 4 9 . 6 2 1 8 . 7 - 8 , 5 2 7 . 7 5 , 9 7 3 , 1 5 1 . 1 5 4 1 3 , 9 3 8 . 5 6 0 . 3 0 8 , 5 2 4 . 1 15 , 1 0 7 . 3 9 1 . 9 1 3 3 0 . 6 8 4 , 2 1 6 . 2 4 , 1 4 6 . 5 3 0 1 . 3 - 8 , 5 7 4 . 4 5 , 9 7 3 , 2 3 4 . 2 3 4 1 3 , 8 9 2 . 7 6 0 . 3 0 8 , 5 7 6 . 0 15 , 2 0 2 . 8 9 1 . 9 8 3 3 0 . 5 7 4 , 2 1 2 . 9 4 , 1 4 3 . 2 3 8 4 . 4 - 8 , 6 2 1 . 2 5 , 9 7 3 , 3 1 7 . 8 6 4 1 3 , 8 4 6 . 8 2 0. 1 4 8, 6 2 8 . 1 15 , 2 9 7 . 4 9 2 . 0 2 3 3 0 . 0 9 4 , 2 0 9 . 6 4 , 1 3 9 . 9 4 6 6 . 6 - 8 , 6 6 8 . 0 5 , 9 7 3 , 4 0 0 . 4 8 4 1 3 , 8 0 0 . 8 7 0 . 5 1 8 , 6 8 0 . 1 15 , 3 8 4 . 0 9 1 . 9 4 3 2 9 . 4 2 4 , 2 0 6 . 6 4 , 1 3 6 . 9 5 4 1 . 4 - 8 , 7 1 1 . 6 5 , 9 7 3 , 4 7 5 . 7 2 4 1 3 , 7 5 8 . 0 4 0 . 7 8 8 , 7 2 8 . 4 15 , 4 0 9 . 0 9 1 . 9 4 3 2 9 . 4 2 4 , 2 0 5 . 8 4 , 1 3 6 . 1 5 6 2 . 9 - 8 , 7 2 4 . 3 5 , 9 7 3 , 4 9 7 . 3 6 4 1 3 , 7 4 5 . 5 5 0 . 0 0 8 , 7 4 2 . 5 Pr o j T D - 4 - 1 / 2 " P r o d u c t i o n L i n e r 14 /02 /20 2 4 9 :20 :35 A 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 1 4 ND B i - 0 1 4 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 As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t De s i g n : ND B i - 0 1 4 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 : As D r i l l e d : P a r k e r 2 7 2 @ 6 9 . 7 u s f t No r t h R e f e r e n c e : We l l N D B i -01 4 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 20 2 0 13 - 3 / 8 " S u r f a c e C a s i n g 2, 5 6 3 . 8 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 10 , 4 4 0 . 0 9- 5 / 8 1 2 - 1 / 4 4- 1 / 2 " P r o d u c t i o n L i n e r 15 , 4 0 9 . 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 1, 1 6 9 . 0 1 , 1 5 9 . 6 B a s e I c e B e a r i n g P e r m a f r o s t 2, 3 4 5 . 0 2 , 1 5 6 . 9 M C U 5, 1 1 2 . 0 3 , 1 2 3 . 3 S e a b e e 2, 8 8 6 . 0 2 , 4 5 3 . 2 T u l u v a k S h a l e 1, 4 0 6 . 0 1 , 3 8 7 . 6 B a s e P e r m a f r o s t T r a n s i t i o n 10 , 0 1 8 . 0 4 , 3 5 5 . 7 N T 3 M F S 8, 1 3 3 . 0 4 , 0 0 1 . 1 N T 6 M F S 1, 7 9 6 . 0 1 , 7 4 0 . 0 M i d d l e S c h r a d e r B l u f f 7, 6 7 7 . 0 3 , 8 6 8 . 6 N a n u s h u k 3, 0 5 6 . 0 2 , 5 2 1 . 0 T u l u v a k S a n d 10 , 4 4 7 . 0 4 , 3 7 0 . 3 N T 3 . 2 T o p R e s e r v o i r 7, 7 4 0 . 0 3 , 8 8 7 . 2 N T 8 M F S 8, 7 8 5 . 0 4 , 1 6 5 . 1 N T 4 M F S 8, 4 5 0 . 0 4 , 0 8 5 . 3 N T 5 M F S 13 , 8 3 7 . 0 4 , 2 5 8 . 9 N T 3 . 2 4 7, 8 0 7 . 0 3 , 9 0 7 . 1 N T 7 M F S 1, 0 4 3 . 0 1 , 0 3 6 . 1 U p p e r S c h r a d e r B l u f f 14 /02 /20 2 4 9 :20 :35 A M CO M P A S S 5 0 0 0 .17 B u i l d 0 2 Pa g e 1 1 From:Davis, Rachel (Rachel) To:Brooks, James S (OGC) Subject:RE: NDBi-014 10-407 Completion Report Date:Monday, March 18, 2024 11:07:10 AM Attachments:image001.png image002.png image005.png Morning James, Please use the below values for TPI: 4047 FSL, 3695 FLE, S08, T11N, R6E, UM Apologies for the inconvenience! Thank you! Rachel Davis Technical Assistant t:1 (907) 375-4678 | e: rachel.davis@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: Brooks, James S (OGC) <james.brooks@alaska.gov> Sent: March 15, 2024 10:27 AM To: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Subject: ![EXT]: FW: NDBi-014 10-407 Completion Report Hi, The tpi ‘Y” value is off. Can you look at it ? thanx -$0(6%522.6 5(6($5&+$1$/<67,,E $/$6.$2,/$1'*$6&216(59$7,21&200,66,21 '(3$570(172)&200(5&(&20081,7<$1'(&2120,&'(9(/230(17 E-$0(6%522.6#$/$6.$*29 From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Friday, March 8, 2024 8:35 AM To: Brooks, James S (OGC) <james.brooks@alaska.gov> Subject: FW: NDBi-014 10-407 Completion Report Samantha Coldiron Special Assistant 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. (907) 793-1223 From: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Sent: Friday, March 8, 2024 7:21 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Subject: NDBi-014 10-407 Completion Report Morning, Please see attached the 10-407 Completion Report for NDBi-014. Thanks! Rachel Davis Technical Assistant t:1 (907) 375-4678 | e: rachel.davis@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email From:Brooks, Phoebe L (OGC) To:Lawson, Rowland (Rowland) Cc:Regg, James B (OGC) Subject:RE: Parker 272 02/02/2024 BOP test form Date:Tuesday, February 20, 2024 2:45:48 PM Attachments:Parker 272 02-02-24 Revised.xlsx Thanks Rowland. I’ve attached a revised report adding that information and correcting the formatting. Please update your copy. 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: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Sent: Tuesday, February 20, 2024 2:27 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: Parker 272 02/02/2024 BOP test form Phoebe….It is 14 bottles. Do you want me to send you an updated form? Thank you Rowland Lawson - Day Wellsite Supervisor Mobile: 907-268-0648 Email: rowland.lawson@contractor.santos.com Alternate: Brian Buzby – brian.buzby@contractor.santos.com From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Tuesday, February 20, 2024 2:21 PM To: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Subject: ![EXT]: RE: Parker 272 02/02/2024 BOP test form Rowland, The # of Nitrogen bottles is missing; please advise. Thanks, Phoebe Phoebe Brooks Research Analyst Pikka NDB-14 PTD 2231050 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. 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: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Sent: Saturday, February 3, 2024 1:26 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: Parker 272 02/02/2024 BOP test form Please find attached the BOPE test form for Parker 272 on 02/02/2024. Thank you Rowland Lawson - Day Wellsite Supervisor Mobile: 907-268-0648 Email: rowland.lawson@contractor.santos.com Alternate: Brian Buzby – brian.buzby@contractor.santos.com 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:2/2/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231050 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:Weekly:Bi-Weekly:X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1540 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 1 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 4-1/2 x 7" VBR 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)1900 P Check Valve 0 N/A NA 200 psi Attained (sec)18 P BOP Misc 0 N/A NA Full Pressure Attained (sec)80 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):14 @ 2300 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 32 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 7 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:4.0 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 01/31/24 22:09 Waived By Test Start Date/Time:2/2/2024 19:00 (date)(time)Witness Test Finish Date/Time:2/2/2024 23:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Parker Tested with 5" and 4.5" test joints. Pat Lynch Oil Search (Alaska) LLC Rowland Lawson Pikka NDBi-014 Test Pressure (psi): 2.seniormanager@parkerwellbor D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)Parker 272 02-02-24 Revised ====jbr 4/18/2024 Corrected BOPE Test report based on information provided by Oil Search (Santos) 4/12/2024. -- J. Regg, 4/18/2024 BOPE Test Order Parker Rig 272 2-2-2024 WELL NDBi-014 Test Annular, Rams, & all valves to 250PSI/LOW/5-MIN, 3500PSI/HIGH/5-MIN, CHART/SAME, as/per permit to drill. Rig up 5” Test joint 1.Close: 4 ½’’ X 7’’ VBR UPR, U-IBOP, D544 Dart Valve, Choke #1, 2, 3, 4 & 15, K-4. Open: Everything else. 2.Close: L-IBOP, D544 FOSV, HCR Kill, Choke #5, 6. Open: Annular, U-IBOP, D544 Dart Valve, K-4 and Choke #2 3.Close: Choke #7,8,9, Manual Kill Open: HCR Kill, Choke #5, 6 4.Close: Choke#10, 11, 12 Open: Choke#7, 8, 9 5.Close: Choke#13 Open: Choke#12 6.Close: 4 ½’’ X 7’’ VBR LPR Open: Open UPR Remove Test Joint. 7.Close: Blind Rams, Choke #10, 11, 14. Open: Choke #13 8.Close: (8a) Super Choke A & (8b) Choke B T/2000 PSI Bleed and catch. Open: Choke #10 Change out to 4-1/2” Test joint 9.Close: Annular, HCR Choke Open: Choke #14 10.Close: 4 ½’’ X 7’’ VBR UPR, Manual Choke Open: HCR Choke 11.Close: 4 ½’’ X 7’’ VBR LPR *Bleed pressure and perform draw down test. “Function all BOP Components from remote panels located in the LER & Rig Managers office, and Accumulator.” BOPE Test Order Parker Rig 272 2-2-2024 Closing Times for BOP Components: Annular Preventer = 30Sec. Upper Pipe rams = 6 Sec. Blind/Shear rams = 7 Sec. Lower Pipe Rams = 6 Sec. HCR Choke = 2 Sec. HCR Kill = 2 Sec. Accumulator Test: Time/Pressure System Pressure = 3100 PSI Pressure after Closure = 1900 PSI 200 psi Attained = 18 Sec. Full Pressure Attained = 80 Sec. Nitrogen Bottle Average = 2300 PSI X 14 Bottles Electric pump kick on pressure = 2800 PSI Electric pump kick off pressure = 3100 PSI Air pump kick on pressure = 2600 PSI Air pump kick off pressure = 2800 PSI jbr; 4/18/2024 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Wednesday, February 14, 2024 10:06 AM To:Regg, James B (OGC) Subject:FW: Parker 272 BOPE test 1-20-2024 Attachments:Parker 272 01-20-24 Revised.xlsx Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: D&C WSS NDB <D&C.WSS.NDB@santos.com> Sent: Wednesday, February 7, 2024 11:12 AM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: RE: Parker 272 BOPE test 1‐20‐2024 IniƟal test showed slight leak, they funcƟoned Blind shear’s and retested good. Thanks Brian From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Wednesday, February 7, 2024 9:33 AM To: D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: ![EXT]: RE: Parker 272 BOPE test 1‐20‐2024 Thanks Brian. For F or FPs, there should be remarks explaining the failure (such as, “FP on UPR 4.5" TJ low test: funcƟoned, reflooded and purged air – good”). Please let me know what remarks should be added to the report to explain the Blind/Shear Rams FP). Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you You don't often get email from d&c.wss.ndb@santos.com. Learn why this is important Pikka NDB-14PTD 2231050 2 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: D&C WSS NDB <D&C.WSS.NDB@santos.com> Sent: Wednesday, February 7, 2024 9:06 AM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; D&C WSS NDB <D&C.WSS.NDB@santos.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: Parker 272 BOPE test 1‐20‐2024 Phoebe Sorry for that here is the revised form. Thanks Brian Buzby From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Tuesday, February 6, 2024 3:20 PM To: D&C WSS NDB <D&C.WSS.NDB@santos.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: ![EXT]: RE: Parker 272 BOPE test 1‐20‐2024 The Blind/Shear Rams included a “FP”, but the Number of Failures included 0 with no remarks; please advise. Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: D&C WSS NDB <D&C.WSS.NDB@santos.com> Sent: Saturday, January 20, 2024 8:12 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> Subject: Parker 272 BOPE test 1‐20‐2024 Please see aƩached BOP test report and let us know if we need to make any correcƟons. Thank you. You don't often get email from d&c.wss.ndb@santos.com. Learn why this is important You don't often get email from d&c.wss.ndb@santos.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 From: Rig 272 Senior Manager <Rig272.SeniorManager@parkerwellbore.com> Sent: Saturday, January 20, 2024 7:33 PM To: D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: ![EXT]: BOPE test forms Here you guys go. Let me know if we need to change anything. Rig 272 Senior Manager Rig272.SeniorManager@parkerwellbore.com Office: +1(907)685-4801 Pouch 340110, Prudhoe Bay, AK 99734 United States www.parkerwellbore.com Energy. Well engineered. NOTICE BY Parker Wellbore Company This message, as well as any attached document, contains information from Parker Wellbore Company that is confidential and/or privileged. The information is intended only for the use of the addressee named above. If you are not the intended recipient, you are hereby notified that any use, disclosure, copying, distribution or the taking of any action in reliance on the contents of this message or its attachments is strictly prohibited, and may be unlawful. If you have received this message in error, please delete all electronic copies of this message and its attachments, if any, destroy any hard copies you may have created, without disclosing the contents, and notify the sender immediately. Unless expressly stated otherwise, nothing contained in this message should be construed as a digital or electronic signature, nor is it intended to reflect an intention to make an agreement by electronic means. 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 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:1/20/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231050 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:Weekly:Bi-Weekly:X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1540 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 1 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 FP Meth Gas Detector P P #3 Rams 1 4-1/2 x 7" VBR 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)3025 P Kill Line Valves 2 2-1/16" 3-1/8"P Pressure After Closure (psi)1900 P Check Valve 0 N/A NA 200 psi Attained (sec)16 P BOP Misc 0 N/A NA Full Pressure Attained (sec)75 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):14@2300 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 26 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 7 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:1 Test Time:5.5 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 1/19/2024 08:40 hrs Waived By Test Start Date/Time:1/20/2024 13:30 (date)(time)Witness Test Finish Date/Time:1/20/2024 19:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Kam StJohn Parker Tested with 5" and 4.5" test joints. Initial test showed slight leak, they functioned Blind shear’s and retested good. Sonny Clark Oil Search (Alaska) LLC Brian Buzby Pikka NDBi-014 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)2024-0120_BOP_Parker272_Pikka_NDB-14 J. Regg; 4/5/2024 BOPE - Parker 272 Pikka NDB-14 PTD 2231050 1/20/2024 BOPE Test Order Parker Rig 272 1-20-2024 WELL NDBi-014 Test Annular, Rams, & all valves to 250PSI/LOW/5-MIN, 3500PSI/HIGH/5-MIN, CHART/SAME, as/per permit to drill. Rig up 5” Test joint 1.Close: 4 ½’’ X 7’’ VBR UPR, U-IBOP, D544 Dart Valve, Choke #1, 2, 3, 4 & 15, K-4. Open: Everything else. 2.Close: L-IBOP, D544 FOSV, HCR Kill, Choke #5, 6. Open: Annular, U-IBOP, D544 Dart Valve, K-4 and Choke #2 3.Close: Choke #7,8,9, Manual Kill Open: HCR Kill, Choke #5, 6 4.Close: Choke#10, 11, 12 Open: Choke#7, 8, 9 5.Close: Choke#13 Open: Choke#12 6.Close: 4 ½’’ X 7’’ VBR LPR Open: Open UPR Remove Test Joint. 7.Close: Blind Rams, Choke #10, 11, 14. Open: Choke #13 8.Close: (8a) Super Choke A & (8b) Choke B T/2000 PSI Bleed and catch. Open: Choke #10 Change out to 4-1/2” Test joint 9.Close: Annular, HCR Choke Open: Choke #14 10.Close: 4 ½’’ X 7’’ VBR UPR, Manual Choke Open: HCR Choke 11.Close: 4 ½’’ X 7’’ VBR LPR *Bleed pressure and perform draw down test. “Function all BOP Components from remote panels located in the LER & Rig Managers office, and Accumulator.” PTD 2231050 BOPE Test Order Parker Rig 272 1-20-2024 Closing Times for BOP Components: Annular Preventer = 26Sec. Upper Pipe rams = 6 Sec. Blind/Shear rams = 7 Sec. Lower Pipe Rams = 6 Sec. HCR Choke = 2 Sec. HCR Kill = 2 Sec. Accumulator Test: Time/Pressure System Pressure = 3025 PSI Pressure after Closure = 1900 PSI 200 psi Attained = 16 Sec. Full Pressure Attained = 75 Sec. Nitrogen Bottle Average = 2300 PSI X 14 Bottles Electric pump kick on pressure = 2800 PSI Electric pump kick off pressure = 3100 PSI Air pump kick on pressure = 2600 PSI Air pump kick off pressure = 2800 PSI Pikka NDB-14 PTD 2231050 From:Brooks, Phoebe L (OGC) To:Lawson, Rowland (Rowland) Cc:Regg, James B (OGC) Subject:RE: Parker 272 02/02/2024 BOP test form Date:Tuesday, February 20, 2024 2:45:48 PM Attachments:Parker 272 02-02-24 Revised.xlsx Thanks Rowland. I’ve attached a revised report adding that information and correcting the formatting. Please update your copy. 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: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Sent: Tuesday, February 20, 2024 2:27 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: Parker 272 02/02/2024 BOP test form Phoebe….It is 14 bottles. Do you want me to send you an updated form? Thank you Rowland Lawson - Day Wellsite Supervisor Mobile: 907-268-0648 Email: rowland.lawson@contractor.santos.com Alternate: Brian Buzby – brian.buzby@contractor.santos.com From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Tuesday, February 20, 2024 2:21 PM To: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Subject: ![EXT]: RE: Parker 272 02/02/2024 BOP test form Rowland, The # of Nitrogen bottles is missing; please advise. Thanks, Phoebe Phoebe Brooks Research Analyst Pikka NDB-14 PTD 2231050 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. 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: Lawson, Rowland (Rowland) <Rowland.Lawson@contractor.santos.com> Sent: Saturday, February 3, 2024 1:26 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: D&C WSS NDB <D&C.WSS.NDB@santos.com> Subject: Parker 272 02/02/2024 BOP test form Please find attached the BOPE test form for Parker 272 on 02/02/2024. Thank you Rowland Lawson - Day Wellsite Supervisor Mobile: 907-268-0648 Email: rowland.lawson@contractor.santos.com Alternate: Brian Buzby – brian.buzby@contractor.santos.com 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:2/2/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2231050 Sundry # Operation:Drilling:X Workover:Explor.: Test:Initial:Weekly:Bi-Weekly:X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:1540 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 1 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 4-1/2 x 7" VBR 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)1900 P Check Valve 0 N/A NA 200 psi Attained (sec)18 P BOP Misc 0 N/A NA Full Pressure Attained (sec)80 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):14 @ 2300 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 32 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 7 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:4.0 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 01/31/24 22:09 Waived By Test Start Date/Time:2/2/2024 19:00 (date)(time)Witness Test Finish Date/Time:2/2/2024 23:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Parker Tested with 5" and 4.5" test joints. Pat Lynch Oil Search (Alaska) LLC Rowland Lawson Pikka NDBi-014 Test Pressure (psi): 72.seniormanager@parkerwellbore D&C.WSS.NDB@santos.com Form 10-424 (Revised 08/2022)2024-0202_BOP_Parker272_Pikka_NDB-14 ===F Annular Fail - API 53 and API Spec 16D: close time shall not exceed 30 seconds for annular BOP's smaller than 18 3/4 inches nominal bore. -- J. Regg, 4/1/2024 see Remarks == 1 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:Koh, Shannon (Shannon) To:Guhl, Meredith D (OGC) Cc:Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC) Subject:RE: NDBi-014, PTD 223-105, Complete mudlog LAS Date:Monday, April 1, 2024 9:00:31 AM Hi Meredith, It looks like there was a comment from the well geo that I forgot to add on the transmittal at the time of the submittal. “NDBi-014 had partial Geolog services which included gas monitoring in surface and production hole (no intermediate gas data was collected). No cuttings were described or gathered. Geoisotopes were collected in production hole only.” Hope this clarifies lack of data. Shannon From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Thursday, March 28, 2024 1:41 PM To: Koh, Shannon (Shannon) <Shannon.Koh@santos.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: ![EXT]: NDBi-014, PTD 223-105, Complete mudlog LAS Hi Shannon, I’m loading the mudlog data for NDBi-014, PTD 223-105, completed on Feb 14, 2024. The mudlog data received to date does not contain a complete mudlog LAS from surface to TD. Instead there are three LAS files, with tops and bottoms from the LAS files: DataType e-Media e-Set #Dt_Recvd Log Type Legacy Logs Hole Top Bot Scale Comments Electronic Data Digital File 38629 15-Mar- 24 Digital Data 120 2571 Electronic Data Set, Filename: NDBi-014_DrillGas_depth_2571 ft MD.las Electronic Data Digital File 38629 15-Mar- 24 Digital Data 10447 15409 Electronic Data Set, Filename: NDBi-014_DrillGas_depth_15409ft MD.las Electronic Data Digital File 38629 15-Mar- 24 Digital Data 10447 15409 Electronic Data Set, Filename: NDBi-014_GEOLOG_GEOISOTOPES_G5_Corrected data_10447-15409 ft_FINAL.las In addition to the lack of a composite LAS from surface to TD, none of the LAS files have lithology percentages. Please provide a complete LAS file for the subject well, from surface to TD, with lithology percentages. Thank you, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email From:McLellan, Bryan J (OGC) To:Regg, James B (OGC); Kono, Randy (Randy); Rixse, Melvin G (OGC); Wallace, Chris D (OGC) Cc:Gathman, Brad (Brad); Miller, Nicklaus (Nick) Subject:RE: Santos - MIT-IA Pressure Testing - Injector Wells Date:Thursday, March 14, 2024 2:21:00 PM Randy, The PTD 223-105 states in step 32 of the drilling procedure that an AOGCC-witnessed MIT-IA will be performed post-rig. That is the same MIT-IA mentioned in page 31, step 4 of the frac sundry #324-085. At some point before injection begins, Oilsearch will need to perform the pre-injection MIT-IA with AOGCC witness per 20 AAC 25.412(e), however the particular MIT-IA referenced in the frac sundry does not need to be witnessed. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Wednesday, March 13, 2024 10:17 AM To: Kono, Randy (Randy) <Randy.Kono@santos.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Gathman, Brad (Brad) <Brad.Gathman@contractor.santos.com>; Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Subject: RE: Santos - MIT-IA Pressure Testing - Injector Wells Pre-injection MIT is required by regulation (20 AAC 25.412(c); send notice for opportunity to witness. You are correct that the post-initial injection MIT is deferred until injection commences. That will be a requirement in the Area Injection Order (not yet submitted). I defer to others regarding the MIT associated with the frac sundry. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 randy.kono@santos.com. Learn why this is important From: Kono, Randy (Randy) <Randy.Kono@santos.com> Sent: Wednesday, March 13, 2024 9:59 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Gathman, Brad (Brad) <Brad.Gathman@contractor.santos.com>; Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Subject: RE: Santos - MIT-IA Pressure Testing - Injector Wells Sorry for the multiple emails. Saw that Bryan is out of office. Adding Mel for this clarification. Appreciate it Randy Kono – Senior Completions EngineerOil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7076 | m: +1 (907) 602-8677 randy.kono@santos.com https://www.santos.com/ From: Kono, Randy (Randy) Sent: March 13, 2024 9:56 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; jim.regg@alaska.gov Cc: Gathman, Brad (Brad) <Brad.Gathman@contractor.santos.com>; Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Subject: Santos - MIT-IA Pressure Testing - Injector Wells Hello Bryan and Jim, Hope all is well. I have a question in regards of witnessing the MIT-IA Pressure Testing for our injector wells. As you may know, we will not be putting these wells online for injection until our production facility is up and running. With that being said are we required to have AOGCC reps to witness the MIT-IA pressure test at the current state? (Just as a friendly reminder, we are fracing, flowback, and shutting in the wells until our facility is ready) Once we start turning these wells online, then is when we plan on having AOGCC witness the MIT-IA pressure test. If the above question is correct, Santos did put a comment in the frac sundry for NDBi-014, that we will request a AOGCC rep to witness the MIT-IA (page 31). (Sundry_324-085_022624) Can we get approval to forego that statement in the frac sundry? Appreciate your time to clarify this. Thank You Randy Kono – Senior Completions EngineerOil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1 (907) 646-7076 | m: +1 (907) 602-8677 randy.kono@santos.com https://www.santos.com/ Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure isstrictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy.Please consider the environment before printing this email LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-014 (50-103-20869-0000) Final Well data Submittal Details on following page 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: 3/15/2024 From: Shannon Koh Santos P.O. Box 240927 Anchorage, AK 99524-0927 To: Kayla Junke AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 223-105 T38629 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.15 10:35:12 -08'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDBi-014 Definitive Compass Survey Report - NAD27.pdf ؒ NDBi-014 Definitive Compass Survey Report - NAD83.pdf ؒ NDBi-014 Definitive Survey.xlsx ؒ NDBi-014 Defitinitive Survey Report - NAD27.txt ؒ NDBi-014 Defitinitive Survey Report - NAD83.txt ؒ NDBi-014 Plan View.pdf ؒ NDBi-014 Vertical Section.pdf ؒ جؐؐؐLog Digital Data and Plots (LWD) ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal_RM_15409ft.las ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-014_AP_R01_RM_20231226.las ؒ ؒ ؒ NDBi-014_AP_R02_RM_20240116.las ؒ ؒ ؒ NDBi-014_AP_R03_RM_20240124.las ؒ ؒ ؒ NDBi-014_AP_R04_RM_20240210.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-014_DMD_RM_15409ft_20240124.las ؒ ؒ NDBi-014_DMT_R01_20231226.las ؒ ؒ NDBi-014_DMT_R02_RM_20240116.las ؒ ؒ NDBi-014_DMT_R03_RM_20240124.las ؒ ؒ NDBi-014_DMT_R04_RM_20240210.las ؒ ؒ ؒ جؐؐؐGeoscience deliverables ؒ ؒ ؤؐؐؐSoundTrak- Acoustic Data ؒ ؒ NDBi-014_9_625_Liner_Baker_Hughes_CBL_Final Report.pdf ؒ ؒ NDBi-014_SDTK_CBL_2510_10450.cgm ؒ ؒ NDBi-014_SDTK_CBL_2510_10450.dlis ؒ ؒ NDBi-014_SDTK_CBL_2510_10450.las ؒ ؒ NDBi-014_SDTK_CBL_2510_10450.PDF ؒ ؒ NDBi-014_SDTK_CBL_2510_10450_dlis.txt ؒ ؒ NDBi-014_SDTK_TOC_2300_10450.cgm ؒ ؒ NDBi-014_SDTK_TOC_2300_10450.dlis ؒ ؒ NDBi-014_SDTK_TOC_2300_10450.las ؒ ؒ NDBi-014_SDTK_TOC_2300_10450.PDF ؒ ؒ NDBi-014_SDTK_TOC_2300_10450_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphics Images LETTER OF TRANSMITTAL ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-014_LWD_GR_Res_Den_Cal_RM_15409ft_5TVD.cgm ؒ ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal_RM_15409ft_2TVD.cgm ؒ ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal_RM_15409ft_5MD.cgm ؒ ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal_RM_15409_2MD.cgm ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-014_AP_RM_20240210.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-014_DMD_RM_15409ft.cgm ؒ ؒ NDBi-014_DMT_RM_20240210.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal-RM_15409ft_5TVD.pdf ؒ ؒ NDBI-014_LWD_GR_Res_Den_Neu_Cal_RM_15409ft_2MD.pdf ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal_RM_15409ft_2TVD.pdf ؒ ؒ NDBi-014_LWD_GR_Res_Den_Neu_Cal_RM_15409ft_5MD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDBi-014_AP_RM_20240210.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDBi-014_DMD_RM_15409ft.pdf ؒ NDBi-014_DMT_RM_20240210.pdf ؒ ؤؐؐؐMudlog جؐؐؐGeological Reports (compilation in PDF) ؒ NDBi-014 Mudlogging Daily Reports compilation.pdf ؒ ؤؐؐؐMudlogging final data NDBi-014_DrillGas_depth_15409ft MD.las NDBi-014_DrillGas_depth_2571 ft MD.las NDBi-014_Gas Ratio Log_surface_15409ft MD-2in.pdf NDBi-014_Gas Ratio Log_Surface_15409ft MD-5in.pdf NDBi-014_GEOLOG_G5_Composite Log_10447-15409ft_2inch.pdf NDBi-014_GEOLOG_G5_Gas IN OUT Log_10447-15409ft_2inch.pdf NDBi-014_GEOLOG_G5_GEOISOTOPES Log_10447-15409ft_2inch.pdf NDBi-014_GEOLOG_GEOISOTOPES_G5_Corrected data_10447-15409 ft_FINAL.las NDBi-014_Mudlog_Surface_15409ft MD-2in.pdf NDBi-014_Mudlog_Surface_15409ft MD-5in.pdf 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Well Cleanup 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?NDBi-014 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 Structural 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):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 392985, 393023, 391445, 393021 223-105 900 E Benson Boulevard, Anchorage, AK 99508 50-103-20869-00-00 Oil Search Alaska, LLC Length Size Proposed Pools: P-110S TVD Burst 15402 11590 MD 6870 5020 128 2289 4370 128 2564 43664-1/2" 20"x34" 13-3/8" 128 9-5/8"10440 2564 8066 10251 4-1/2" 2374 9-5/8" 2374 2175 6870 02/29/24 154025144 4-1/2" 12.6 ppf 3132 10251 Perforation Depth MD (ft): ramamaammaammam n d e owoowowwnnn nn l d s e ee e ll Clas 5 2 66 nt ceeeee p ritytttyty sttttttt dn uuuuuuuuuuppppppppppppppp ram Nooooooo c ryyyyyy osN Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 02/14/2024 324-085 By Kayla Junke at 4:24 pm, Feb 14, 2024 SFD 10-404 1540 psi - from PTD -bjm CDW 02/21/2024 SFD DSR-2/14/24BJM 2/23/24 SFD 2/23/2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.02.26 14:29:43 -09'00'02/26/24 RBDMS JSB 022724 Page 1 of 19 NDBi-014 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-014. At the NDBi-014 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-014 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 973feet (ft) total vertical depth subsea (TVDSS)/ 973 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 978 to 2,400 ft TVDSS/1,422 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: 2,400 to 3,113 ft TVDSS/713 ft thick Hydrocarbon Zone: 2,461 to 3,113 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: 3,113 to 3,776 ft TVDSS/663 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: 3,776 to 4,690 ft TVDSS/914 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 1-9 3,500 3,800 8,300 7,400 9,000 8,900 Fracture gradient values for each stage are listed in detail within Attachment .. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft 11.Mechanical condition of wells transecting the confining zones – Qugruk 3, Qugruk 3A, Qugruk 301 and NDBi-44, are within 1/2-mile radius of NDBi-044. Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones. Please see Attachment B Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 15098 4216 251 353 40 4789 10 2 14558 4234 240 340 40 4274 8 3 14012 4252 238 321 40 4156 8 4 13553 4268 243 325 40 4668 12 5 13009 4287 221 366 40 4230 10 6 12385 4309 277 412 40 4131 10 7 11843 4328 276 419 35 3052 8 8 11304 4347 272 367 30 2627 8 9 10803 4364 289 336 30 2535 8 4789 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 ADL 392963 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392985 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 49.84% DNR - 50.16% ADL 392984 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393022 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 39.48% DNR - 60.52% ADL 393021 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 19.22% DNR - 80.78% ADL 393023 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 44.08% DNR - 55.92% ADL 393019 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393020 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393017 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393016 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 391445 Surface Owners: Kuukpik OSA - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% U012N006E34 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N005E36 U011N005E01 U011N005E12 U011N006E09U011N006E08 U011N006E10 U011N006E03 U011N006E16 U011N006E15U011N006E17U011N005E13 U012N006E31 U011N006E06 U011N006E18 U011N006E07 OIL SEARCH (ALASKA), LLC A SUBSIDIARY OF SANTOS LTD NDBi014 WELL AREA .5-MILE BUFFER .25-MILE BUFFER TARGET BOTTOM HOLE SURFACE LOCATION WELL TRAJECTORY LEASES BOUNDARY TOWNSHIP SECTION KUUKPIK BOUNDARY DATE: 11/6/2023. REV: 1.0. By: JB 0 500 1,000 US Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDBi014_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 200 400 Meters PIKKA PROJECT NDB Attachment B The fault noted to towards the toe of NDBi-14 is low confidence fault that has less than 20 ft of throw and could also be a stratigraphic feature. The fault as mapped on seismic tips out within the Nanushuk formation, so is covered by the Seabee the upper confining layer. WELL NAME STATUS Casing Size Top of Oil Pool Confining Layer (MD) Top of Oil Pool Confining Layer (TVDSS) Top of Cement (MD) Top of Cement (TVDSS) Top of Cement Determined By Reservoir Status Zonal Isolation Cement Operations Summary Mechanical Integrity Q-301 Abandoned 9-5/8" 47# L-80 4042 (Nanushuk) 3841 (Nanushuk) 3810'3683'log Abandoned with Cased hole cement plugs TOC 3,810' MD Q-301 was an exploration/appraisal well that was drilled in 2015. It was hydraulic fractured in the Nanushuk reservoir, flowed back, and plugged and abandoned in the same winter season. • The Nanushuk formation top was identified at 4042’ MD, with Nanushuk target formation at 4631’ MD. • 9-5/8” Intermediate casing is set at 5241’ MD in the Nanushuk reservoir. The primary cement job has the TOC at 3810’ MD (96.7 bbls 13.9ppg Extended Class G), with a second stage cement job from 3008’ MD to surface (187 bbls of 12.2ppg Extended Type I/II). • The 4-1/2” production liner in the Nanushuk reservoir is set at 7495’ MD. The liner was P&A with a cement retainer set at 4503’ MD and 48 bbls squeezed below the retainer (4-1/2” liner volume). • 3 cement abandonment plugs were set in the 9-5/8” casing: 1. 1st Plug (300’ above cement retainer): 18 bbls of 15.8 ppg cement laid above the cement retainer at 4503’. 2. 2nd Plug (300’ across 13-3/8” casing shoe): A 9-5/8” bridge plug was set at 2207’ MD (100’ below the surface casing shoe) with 19.1 bbls of 15.6ppg Class G cement plug laid on top of it. Well is fully abandoned. Q3A Abandoned Open Hole 4678 (Nanushuk) 4192' (Nanushuk)4678' 4177' Tag TOC set down 15k with DP.Open Hole Abandonment Plug TOC 4,177' MD • The 8-1/2” open hole section was abandoned with two open hole plugs: 1st plug (open hole plug): An open hole balanced cement plug was attempted to be laid in the well from 10,420’ MD by pumping a 136 bbls of 15.8 ppg cement. Cement was pumped with full returns, but while laying in the balanced plug in the well the string including the drill pipe and 4-1/2” 2,000’ 12.6 ppf tubing stinger became stuck at 10,383’ MD. The pipe was severed at 6,243’ MD. TOC was estimated to be at 8,003’ MD in the annulus and 8,650’ MD inside the drill pipe. 2.) 2nd plug (open hole balanced plug): A second open hole balanced plug was placed in the well by circulating 73 bbls of 15.8 ppg class G cement into the hole at 4950’ MD. TOC was confirmed at 4,177’ MD by tagging and placing 15k WOB several times Well is fully abandoned. Q3 Abandoned Open Hole 3875 3502 3502 Tag TOC with DP. Open Hole Abandonment Plug TOC 3502' MD The 12-1/4" open hole section was abandoned with 4 open hole plugs. Kuparuk C 6750' - 6753' MD, Alpine 6970' - 7230' MD Cement Plug #1: Pump mud push, 120 bbls 15. 8 ppg Class G cement for open hole plug# 1. POOH to 6624' and circulate drill pipe clean. Pick up drill pipe while WOC. Tag plug at 6852', with 14,000 lbs. Tag witnessed by Bob Noble. Plug at 7,500' MD - 6,852' MD, Cement Plug #2A: Pump mud push, 115 bbls 15. 8 ppg Class G cement for open hole plug# 2.Tag plug at 4216', with 10,000 lbs. Tag witnessed by Bob Noble. plug #2 4,581' MD - 4,216' MD. Plug #2 didn't meet regulations. Mixed up a second one. Cement Plug #2B: Pump mud push, 100 bbls 17 ppg Class G. Tag plug at 3,502' MD. Tag witnessed by Louis Grimaldi. Plug #2A 4,216' MD - 3,502' MD. Cement Plug #3: Pump mud push, 108 bbls 17 ppg Class G cement for bottom kick off plug. POOH to 2275. Cement plug #3 Kick off plug 3,144' - 2,507' MD Cement Plug #4: Pump mud push, 88 bbls 15. 7 ppg AS1 cement for top kick off plug. Cement plug #4 top kick off plug 2,255 - 1,735' MD The Q3A sidetrack wellbore was then kicked off by washing through soft cement and kicking off of cement plug #3 at 2708' MD. The Q3A well was then drilled and abandoned per the AOGCC Regulations. Well is fully abandoned. NDBi-044 ACTIVE 9-5/8" 47ppf 9678 (Nanushuk) 3,804 (Nanushuk) 7964 3,496 log open hole liner for production TOC 7,964' & packer @ 10,823' 1.9-5/8” x 13-3/8” Primary cement job a.Pump 80 bbls 12.5 ppg tuned spacer, 131 bbls 13.0 ppg 400 sxs 1.84 ft^3/sx EconoCem Tpe I-II lead cement, and 80 bbls of 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. Planned TOC was ~8,350’ MD. b.No returns while displacing cement job. Wiper dart #2 was lodged in the liner running tool when it was recovered. The follow liner wiper plug was then found just below the 9-5/8” x 13-3/8” Liner top. A cleanout run was required to push the follow liner wiper plug to bottom and the shoe track was drilled out. Dynamic losses were encountered while drilling the float equipment indicating the lost circulation zone had not been isolated. c.A cement retainer was run in the hole and set at 11,010’ MD and a second cement job was pumped through the shoe d.15bbls 12.0 ppg tuned spacer and 95 bbls of 15.3 ppg 1.24 Ō^3/sx Versacem Type I-II Tail were circulated through the retainer, and 5 bbls were placed on top of the retainer. 2.9-5/8” Secondary Cement Job a.RIH and open up the Archer CŇex cement tool. Establish circulaƟon and pump 80 bbls 12.5 ppg Tuned spacer 214 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. 129 bbls were lost while displacing. The LTP was set and 263 bbls of contaminated mud / cement/ spacer was circulated to surface while circulating with the Cflex running tool. An additional 5 bbls of cement was circulated out off the top of the liner when circulating with the liner running too at the top of the liner. 3.9-5/8” Cement EvaluaƟon Logs a.HES Cast tool was run in the hole on a welltec tractor. The 9-5/8” cement was logged. Showing the TOC of the primary job at 7,964' MD. 01/30/24, 9-5/8" casing pressure tested to 4284 psi for 30 minutes 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: 2,564’ MD x 9-5/8” x13-3/8” Liner top: 2,374’ MD x 9-5/8” Liner Shoe: 10.440’ MD x 9-5/8” Archer Cflex Mechanical Stage tool: 5,140 MD Geology x Base of Tuluvak formation at 5,112’ BD. Base of significant hydrocarbons are located in the upper Tuluvak at ~3,440’ MD/ 2,640’ TVD. x Top of the Nanushuk picked at 7,677’ MD. o Top of the NT8 MFS picked at 7,740’ MD o Top of the NT7 MFS picked at 7,807’ MD. Based on offset well logs (NDBi-043A), the top of the residual Nanushuk hydrocarbon in NDBi-014 is estimated to be ~7,857’ MD/ 3,922’ TVD, which is within the NT7 MFS. This is further evidenced by the low resistivity values (i.e., clay 4-6 ohm) that were encountered above 7,857’ MD on NDBi-014. 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 6,780’ MD. b. During execution of the 1 st stage of cement, losses were encountered and 75 bbls were lost after the cement turned the corner. 5,140 MD 2. 9-5/8” Secondary Cement Job a. 2nd stage of cement job planned with CFLEX at the base of the Tuluvak formation (5,112’ MD / 3,123’ TVD). 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 16 bbls were lost. Cement returns were witnessed off the top of liner and 104 bbls of contaminated cement returned to surface (max weight measured at surface was 14.2 ppg) 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 ~7,857’ MD). This is supported by the CBL log, which indicates good cement throughout the first stage and TOC at 7,739’ MD. b. For the 2 nd stage of the cement job, the stage collar (5,140 MD) was placed well below the lower-most Tuluvak Significant hydrocarbon (~3,440’ MD). Based on job execution results, cement isolation was achieved across the Tuluvak formation. This is supported by the CBL results, which indicate large areas of partial to good cement presence (2,579’ to 3,216’ and 3,641’ to 5,152’), and only one are of poor cement presence (3,216’ to 3,641’). 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 shows adequate isolation below, across, and above the Tuluvak significant hydrocarbons. d. See attached interpreted cement bond log from baker SoundTrak LWD CBL. Page 1 of 1 Well Name: NDBi-014 Cement Intermediate Casing Cement 1st Stage Intermediate Casing Cement 1st Stage, Casing, 1/17/2024 21:30 Type Casing Cementing Start Date 1/17/2024 Cementing End Date 1/18/2024 Wellbore Original Hole String Intermediate Liner, 10,440.0ftKB 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 7739' MD. Reference the CBL Report in the attachments for a detailed analysis of cement bond log results. Comment Conduct 1st Stage Cement Job of 9-5/8” Liner - 9-5/8” shoe at 10,440’, Float collar at 10,363’, Stage Tool at 5137’, Liner top at 2374’ - Pump 80 bbl 13.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 4 bpm, full returns - Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 3.7 bpm, initial circulating pressure 400 psi - Land dart at 52 bbls away at 3.5 bpm at latch (as calculated), clear indication of latch and release - Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 270 bbls @ average of 3.7 bpm, 400 psi, excess volume 30% (1225 sacks, yield 1.237 cu ft/sk), final circulating pressure 100 psi, full returns throughout - Release top pump down plug, chase with 10 bbls of washup from Halliburton. - Perform displacement with rig pumps, displace with 12.0 ppg OBM at initial rate of 6 bpm, 435 psi to catch cement (did not catch before slowing rate). - Top pump down dart latch up confirmed at 52 bbls displaced (as calculated) - Continue to displace with 12.0 ppg OBM at 4 bpm, 337 psi ICP with full returns as Spacer pill exits shoe. - Bottom plug lands 18 bbls behind calculated strokes at 3832, 1345 psi - Displace at 4 bpm, 545 psi with bottom plug landed, increase to 6 bpm, 850 psi at 4400 strokes, pushing fluid away, reduce back down to 4 bpm, 670 psi. Losing fluid, back down to 3 bpm, 593 psi initial. FCP 605 psi at plug bump. Pressure up to 1200 psi and hold. - Total displacement volume 632 bbls (measured by strokes @ 96% pump efficiency). - Total losses from cement exit shoe to cement in place: 75 bbls.. - Check floats, CIP 0415 hrs 1, <DepthTop>-10,440.0ftKB Top Depth (ftKB) Bottom Depth (ftKB) 10,440.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 605.0 Plug Bump Pressure (psi) 1,200.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) 10,365.0 Tag Method Drill Pipe Depth Plug Drilled Out To (ftKB) 10,440.0 Drill Out Diameter (in) 8 1/2 Drill Out Date 1/31/2024 Spacer Fluid Type Spacer Fluid Description Tuned Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 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) 1,225 Class Class I/II Volume Pumped (bbl) 270.0 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) Thickening Time (hr) 6.00 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 10.00 Page 1 of 1 Well Name: NDBi-014 Cement Intermediate Casing Cement 2nd Stage Intermediate Casing Cement 2nd Stage, Casing, 1/18/2024 21:30 Type Casing Cementing Start Date 1/18/2024 Cementing End Date 1/19/2024 Wellbore Original Hole String Intermediate Liner, 10,440.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Baker Soundtrack LWD Cement Evaluation Results Cement was identified from 5,152' MD to the Top of the 9-5/8" Liner. Log results indicate adequate cement isolation across the entire Tuluvak formation. Reference the CBL report in attachments for a detailed analysis. Comment Cement 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool at 5,140’ (center of circulation port) as follows: - Mix and pump 80 bbls of 12.5 ppg Tuned Spacer at 4 bpm and full returns (both spacers with Surfactant B and Musol A). - Mix and pump 80 bbls of 13.5 Tuned Spacer @ 4 bpm with full returns. - Mix and pump 305 bbls of 15.3 ppg Versacem Type I-II Tail cement @ 3.5 bpm initial, 370 psi, final 385 psi; 16 bbls losses throughout job. Excess Volume 100% (1385 sacks, yield 1.237 cu ft/sk). - Displace to calculated displacement volume of 119 bbls to Archer Stage Collar. - Begin displacement with 10 bbls fresh clean-up water from cementing unit. - Continue to displace with 109 bbls 12.0 ppg OBM using rig pumps. Stage up to initial rate of 6 bpm, 860 psi, 7% flow returns, observing slight losses, back rate off to 5 bpm, 770 psi, 5% flow return. Final circulating pressure at 5 bpm 875 psi. - Slow displacement to 3 bpm, 640 psi, last 10 bbls. - Dump fluids when dyed Tuned Spacer back to surface. - Estimate 104 bbls cement returns, weight of 14.2 ppg. - CIP @ 0031 hrs. 2, <DepthTop>-<DepthBtm>ftKB Top Depth (ftKB) Bottom Depth (ftKB) Full Return? No Vol Cement Ret (bbl) 104.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 640.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) 0.00 Reciprocation Rate (spm) 0 Pipe Rotated? No Pipe RPM (rpm) 0 Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Mud Flush 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 (%) 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) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 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 Tail Type I/II Amount (sacks) 1,385 Class Type I/II Volume Pumped (bbl) 305.0 Estimated Top (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) Thickening Time (hr) 7.07 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 18.00 Attachment D Attachment E Attachment F Well Name NDBi-14 02/02/24 Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) a FP b FP c WF 25 3.5 40 40 1680 1680 40 40 40 0 1680 0 40 d Pump Ball to Seat WF 25 4 195 195 235 e Pump Check WF 25 40 70 110 2940 4620 70 305 f WF 25 32 40 150 1680 6300 40 345 g WF 25 24 30 180 1260 7560 30 375 h WF 25 16 20 200 840 8400 20 395 200 0 8400 0395 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT CLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOB STAGE CUM STAGE CUM Size or Stage Cum #PPA TYPE (BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type (BBL)(BBL) 1 0 Stage 5 PAD XL 25 40 325 325 525 13650 22050 0 0 325 720 2 1 Flat XL 25 40 180 505 705 7560 29610 7240 7240 16/20-CL 172 892 3 2 Flat XL 25 40 220 725 925 9240 38850 16978 24217 16/20-CL 202 1094 4 4 Flat XL 25 40 240 965 1165 10080 48930 34257 58474 16/20-CL 204 1298 5 6 Flat XL 25 40 240 1205 1405 10080 59010 47792 106266 16/20-CL 190 1488 6 8 Flat XL 25 40 240 1445 1645 10080 69090 59558 165824 16/20-CL 177 1665 7 10 Flat XL 25 40 200 1645 1845 8400 77490 58233 224057 16/20-CL 139 1804 8 0 Clear Surface Lines XL 25 40 20 1665 1865 840 78330 0 224057 20 1824 9 0 Spacer XL 25 40 5 1670 1870 210 78540 0 224057 5 1829 10 0 Drop Stage 6 Ball/Collet FP 0 40 3 1673 1873 126 78666 0 224057 3 1832 11 0 Stage 6 XL 25 40 158 1831 2031 6636 85302 0 224057 158 1990 12 0 Slow for Seat XL 25 17 50 1881 2081 2100 87402 0 224057 50 2040 13 0 Resume Pad XL 25 40 92 1973 2173 3864 91266 0 224057 92 2132 14 1 Flat XL 25 40 180 2153 2353 7560 98826 7240 231296 16/20-CL 172 2304 15 2 Flat XL 25 40 200 2353 2553 8400 107226 15434 246731 16/20-CL 184 2488 16 4 Flat XL 25 40 220 2573 2773 9240 116466 31402 278133 16/20-CL 187 2675 17 6 Flat XL 25 40 220 2793 2993 9240 125706 43809 321942 16/20-CL 174 2849 18 8 Flat XL 25 40 220 3013 3213 9240 134946 54595 376536 16/20-CL 162 3011 19 10 Flat XL 25 40 180 3193 3393 7560 142506 52410 428946 16/20-CL 125 3136 20 0 Clear Surface Lines XL 25 40 20 3213 3413 840 143346 0 428946 20 3156 21 0 Spacer XL 25 40 5 3218 3418 210 143556 0 428946 5 3161 22 0 Drop Stage 7 Ball/Collet FP 0 40 3 3221 3421 126 143682 0 428946 3 3164 23 0 Stage 7 XL 25 40 150 3371 3571 6300 149982 0 428946 150 3314 24 0 Slow for Seat XL 25 17 50 3421 3621 2100 152082 0 428946 50 3364 25 0 Resume Pad XL 25 40 150 3571 3771 6300 158382 0 428946 150 3514 26 1 Flat XL 25 40 160 3731 3931 6720 165102 6435 435381 16/20-CL 153 3667 27 2 Flat XL 25 40 160 3891 4091 6720 171822 12347 447729 16/20-CL 147 3814 28 3 Flat XL 25 40 180 4071 4271 7560 179382 20022 467751 16/20-CL 159 3973 29 4 Flat XL 25 40 180 4251 4451 7560 186942 25693 493444 16/20-CL 153 4126 FLUID Neat Water COMMENTS Prime and Pressure Test Open well and open initiator sleeve Displace PT- Shut down 10 min Drop Ball-SD 10 minutes Step Down - 32 bpm Step Down - 24 bpm Step Down - 16 bpm Well Name NDBi-14 02/02/24 Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) FLUID Neat Water 30 5 Flat XL 25 40 180 4431 4631 7560 194502 30952 524396 16/20-CL 147 4274 31 6 Flat XL 25 40 180 4611 4811 7560 202062 35844 560240 16/20-CL 142 4416 32 7 Flat XL 25 40 160 4771 4971 6720 208782 35916 596155 16/20-CL 122 4538 33 8 Flat XL 25 40 150 4921 5121 6300 215082 37224 633379 16/20-CL 111 4649 34 0 Clear Surface Lines XL 25 40 20 4941 5141 840 215922 0 633379 20 4669 35 0 Spacer XL 25 40 5 4946 5146 210 216132 0 633379 5 4674 36 0 Drop Stage 8 Ball/Collet FP 0 40 3 4949 5149 126 216258 0 633379 3 4677 37 0 Stage 8 XL 25 40 142 5091 5291 5964 222222 0 633379 142 4819 38 0 Slow for Seat XL 25 17 50 5141 5341 2100 224322 0 633379 50 4869 39 0 Resume Pad XL 25 40 158 5299 5499 6636 230958 0 633379 158 5027 40 1 Flat XL 25 40 150 5449 5649 6300 237258 6033 639412 16/20-CL 144 5170 41 2 Flat XL 25 40 150 5599 5799 6300 243558 11576 650988 16/20-CL 138 5308 42 3 Flat XL 25 40 160 5759 5959 6720 250278 17798 668785 16/20-CL 141 5449 43 4 Flat XL 25 40 160 5919 6119 6720 256998 22838 691623 16/20-CL 136 5585 44 5 Flat XL 25 40 160 6079 6279 6720 263718 27513 719136 16/20-CL 131 5716 45 6 Flat XL 25 40 160 6239 6439 6720 270438 31861 750997 16/20-CL 126 5843 46 7 Flat XL 25 40 140 6379 6579 5880 276318 31426 782423 16/20-CL 107 5950 47 8 Flat XL 25 40 125 6504 6704 5250 281568 31020 813443 16/20-CL 92 6042 48 0 Clear Surface Lines XL 25 40 20 6524 6724 840 282408 0 813443 20 6062 49 0 Spacer XL 25 40 5 6529 6729 210 282618 0 813443 5 6067 50 0 Drop Stage 9 Ball/Collet FP 0 40 3 6532 6732 126 282744 0 813443 3 6070 51 0 Stage 9 XL 25 40 133 6665 6865 5586 288330 0 813443 133 6203 52 0 Slow for Seat XL 25 17 50 6715 6915 2100 290430 0 813443 50 6253 53 0 Resume Pad XL 25 40 167 6882 7082 7014 297444 0 813443 167 6420 54 1 Flat XL 25 40 150 7032 7232 6300 303744 6033 819476 16/20-CL 144 6564 55 2 Flat XL 25 40 150 7182 7382 6300 310044 11576 831052 16/20-CL 138 6701 56 3 Flat XL 25 40 160 7342 7542 6720 316764 17798 848849 16/20-CL 141 6843 57 4 Flat XL 25 40 160 7502 7702 6720 323484 22838 871687 16/20-CL 136 6979 58 5 Flat XL 25 40 160 7662 7862 6720 330204 27513 899200 16/20-CL 131 7110 59 6 Flat XL 25 40 160 7822 8022 6720 336924 31861 931061 16/20-CL 126 7236 60 7 Flat XL 25 40 140 7962 8162 5880 342804 31426 962488 16/20-CL 107 7343 61 8 Flat XL 25 40 125 8087 8287 5250 348054 31020 993507 16/20-CL 92 7435 8087 8287 0 348054 0 993507 0 7435 62 Linear Flush WF 25 20 25 8112 6749 1050 349104 25 7460 63 Linear Flush WF 25 20 75 8187 6824 3150 352254 75 7535 64 3000 feet MD + Surface Eqmt FP 20 59 8246 6883 2482 354736 TOTALS 8641 354736 993507 Well Name NDBi-14 02/02/24 Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) a FP b FP c WF 25 3.5 40 40 1680 1680 40 40 d Pump Check WF 25 40 100 140 4200 5880 100 140 0 140 d Spot DataFRAC XL XL 25 16 200 340 8400 14280 200 340 e DataFRAC WF XL 25 16 50 390 2100 16380 50 390 e Displace DF (add surface lines to disp.)WF 25 40 183 573 7686 24066 183 573 f Shutdown and monitor 1.0-1.5H 573 0 24066 0 573 h Load Stage 1 ball/collet, 573 0 24066 0 573 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT CLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOB STAGE CUM STAGE CUM Size or Stage Cum #PPA TYPE (BPM)(BBL)(BBL)(BBL)(GAL)(GAL)(LBS)(LBS)Type (BBL)(BBL) 1 0 Line out XL XL 25 21 40 40 613 1680 25746 0 0 40 613 2 0 Drop Stage 1 Ball/Collet FP 0 21 3 43 616 126 25872 0 0 16/20-CL 3 616 3 0 Stage 1 PAD XL 25 30 237 280 853 9954 35826 0 0 237 853 4 0 Slow for Seat XL 25 17 50 330 903 2100 37926 00 50903 5 0 Resume Pad XL 25 40 38 368 941 1596 39522 00 38941 6 1 Flat XL 25 40 180 548 1121 7560 47082 7240 7240 16/20-CL 172 1113 7 2 Flat XL 25 40 220 768 1341 9240 56322 16978 24217 16/20-CL 202 1315 8 4 Flat XL 25 40 240 1008 1581 10080 66402 34257 58474 16/20-CL 204 1519 9 6 Flat XL 25 40 240 1248 1821 10080 76482 47792 106266 16/20-CL 190 1709 10 8 Flat XL 25 40 240 1488 2061 10080 86562 59558 165824 16/20-CL 177 1886 11 10 Flat XL 25 40 200 1688 2261 8400 94962 58233 224057 16/20-CL 139 2025 12 0 Clear Surface Lines XL 25 40 20 1708 2281 840 95802 0 224057 20 2045 13 0 Spacer XL 25 40 5 1713 2286 210 96012 0 224057 5 2050 14 0 Drop Stage 2 Ball/Collet FP 0 40 3 1716 2289 126 96138 0 224057 3 2053 15 0 Stage 2 XL 25 40 191 1907 2480 8022 104160 0 224057 191 2244 16 0 Slow for Seat XL 25 17 50 1957 2530 2100 106260 0 224057 50 2294 17 0 Resume Pad XL 25 40 109 2066 2639 4578 110838 0 224057 109 2403 18 1 Flat XL 25 40 180 2246 2819 7560 118398 7240 231296 16/20-CL 172 2575 19 2 Flat XL 25 40 180 2426 2999 7560 125958 13891 245187 16/20-CL 165 2741 20 3 Flat XL 25 40 200 2626 3199 8400 134358 22247 267434 16/20-CL 177 2917 21 4 Flat XL 25 40 200 2826 3399 8400 142758 28547 295981 16/20-CL 170 3087 22 5 Flat XL 25 40 200 3026 3599 8400 151158 34391 330373 16/20-CL 164 3251 23 6 Flat XL 25 40 200 3226 3799 8400 159558 39827 370199 16/20-CL 158 3409 24 7 Flat XL 25 40 180 3406 3979 7560 167118 40405 410604 16/20-CL 137 3546 25 8 Flat XL 25 40 160 3566 4139 6720 173838 39705 450309 16/20-CL 118 3665 26 0 Clear Surface Lines XL 25 40 20 3586 4159 840 174678 0 450309 20 3685 27 0 Spacer XL 25 40 5 3591 4164 210 174888 0 450309 5 3690 28 0 Drop Stage 3 Ball/Collet FP 0 40 3 3594 4167 126 175014 0 450309 3 3693 29 0 Stage 3 XL 25 40 183 3777 4350 7686 182700 0 450309 183 3876 FLUID Neat Water COMMENTS Shut Down, line up for XL Prime and Pressure Test Open well and open initiator sleeve Displace PT- Shut down 10 min Well Name NDBi-14 02/02/24 Design STAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT #TYPE PPT RATE STAGE CUM STAGE CUM STAGE CUM SIZE Stage Cum Pre Frac - Non Proppant stages (BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) FLUID Neat Water 30 0 Slow for Seat XL 25 17 50 3827 4400 2100 184800 0 450309 50 3926 31 0 Resume Pad XL 25 40 117 3944 4517 4914 189714 0 450309 117 4043 32 1 Flat XL 25 40 180 4124 4697 7560 197274 7240 457549 16/20-CL 172 4215 33 2 Flat XL 25 40 180 4304 4877 7560 204834 13891 471440 16/20-CL 165 4380 34 3 Flat XL 25 40 200 4504 5077 8400 213234 22247 493687 16/20-CL 177 4557 35 4 Flat XL 25 40 200 4704 5277 8400 221634 28547 522234 16/20-CL 170 4727 36 5 Flat XL 25 40 200 4904 5477 8400 230034 34391 556625 16/20-CL 164 4891 37 6 Flat XL 25 40 200 5104 5677 8400 238434 39827 596452 16/20-CL 158 5049 38 7 Flat XL 25 40 180 5284 5857 7560 245994 40405 636857 16/20-CL 137 5186 39 8 Flat XL 25 40 160 5444 6017 6720 252714 39705 676562 16/20-CL 118 5304 40 0 Clear Surface Lines XL 25 40 20 5464 6037 840 253554 0 676562 20 5324 41 0 Spacer XL 25 40 5 5469 6042 210 253764 0 676562 5 5329 42 0 Drop Stage 4 Ball/Collet FP 0 40 3 5472 6045 126 253890 0 676562 3 5332 43 0 Stage 4 XL 25 40 175 5647 6220 7350 261240 0 676562 175 5507 44 0 Slow for Seat XL 25 17 50 5697 6270 2100 263340 0 676562 50 5557 45 0 Resume Pad XL 25 40 25 5722 6295 1050 264390 0 676562 25 5582 46 1 Flat XL 25 40 140 5862 6435 5880 270270 5631 682193 16/20-CL 134 5716 47 2 Flat XL 25 40 160 6022 6595 6720 276990 12347 694540 16/20-CL 147 5863 48 4 Flat XL 25 40 180 6202 6775 7560 284550 25693 720233 16/20-CL 153 6016 49 6 Flat XL 25 40 180 6382 6955 7560 292110 35844 756077 16/20-CL 142 6158 50 8 Flat XL 25 40 180 6562 7135 7560 299670 44668 800745 16/20-CL 133 6291 51 10 Flat XL 25 40 180 6742 7315 7560 307230 52410 853155 16/20-CL 125 6416 52 12 Flat XL 25 40 150 6892 7465 6300 313530 49380 902535 16/20-CL 98 6514 53 0 Clear Surface Lines XL 25 40 20 6912 7485 840 314370 0 902535 20 6534 54 0 Spacer XL 25 40 5 6917 7490 210 314580 0 902535 5 6539 55 0 Drop Stage 5 Ball/Collet FP 0 40 3 6920 7493 126 314706 0 902535 3 6542 56 0 XL Flush XL 25 40 50 6970 7543 2100 316806 0 902535 50 6592 57 0 LG Flush WF 25 40 116 7086 7659 4872 321678 0 902535 116 6708 58 0 Slow for seat WF 25 17 50 7136 7709 2100 323778 0 902535 50 6758 59 0 Overflush (empty PCM)WF 25 40 100 7236 7809 4200 327978 0 902535 100 6858 0 327978 0 6858 63 Linear Flush WF 25 20 17237677642 328020 16859 64 Linear Flush WF 25 20 17238677742 328062 16860 65 3000 feet MD + Surface Eqmt FP 20 59 7297 6836 2482 330544 TOTALS 7870 330544 902535 Additive Additive Description F103 Surfactant 1.0 Gal/mGal 598.6 gal J450 Stabilizing Agent 0.5 Gal/mGal 299.3 gal J475 Breaker J475 6.0 lb/mGal 3,591.5 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,197.2 lbm J532 Crosslinker 2.3 Gal/mGal 1,365.2 gal J580 Gel J580 25.0 lb/mGal 14,964.6 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 35.9 gal M275 Bactericide 0.3 lb/mGal 179.6 lbm S522-1620 Propping Agent varied concentrations 1,896,400.0 lbm ~ 72 % ~ 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 % 100 % 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate Total * Mix water is supplied by the client. SLB has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 14808-60-7 Quartz, Crystalline silica 532-32-1 Sodium benzoate 64-19-7 Acetic acid (impurity) 9000-90-2 Amylase, alpha 127-08-2 Acetic acid, potassium salt (impurity) 14464-46-1 Cristobalite 9002-84-0 poly(tetrafluoroethylene) 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 7631-86-9 Silicon Dioxide (Impurity) 14807-96-6 Magnesium silicate hydrate (talc) 10377-60-3 Magnesium nitrate 9025-56-3 Hemicellulase 91053-39-3 Diatomaceous earth, calcined 112-42-5 1-undecanol (impurity) 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 68131-39-5 Ethoxylated Alcohol 50-70-4 Sorbitol 67-63-0 Propan-2-ol 111-76-2 2-butoxyethanol 7727-54-0 Diammonium peroxidisulphate 56-81-5 1, 2, 3 - Propanetriol 1303-96-4 Sodium tetraborate decahydrate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 102-71-6 2,2`,2"-nitrilotriethanol CAS Number Chemical Name Mass Fraction -Water (Including Mix Water Supplied by Client)* YF125ST:WF125 598,584 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Report ID:RPT-1793 Fluid Name & Volume Concentration Volume Disclosure Type:Pre-Job Well Completed: Date Prepared:2/8/2024 State:Alaska County/Parish:North Slope Borough Case: Client:Oil Search Alaska Well:NDBi-014 Basin/Field:Pikka # SLB-Private Page: 1 / 1 Attachment G NDBi-014 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 AOGCC permission to flare the produced gasqg k work. Total volume of gas per the flowback program ppg p outlined in Table 1 is approximately 15 MMscf. Attachment H NDBi-014 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-014 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 to be tested again to 4,000 psi with AOGCC notification, estimated pressure test timing 02/18/2024) a. NOTE: AOGCC will be notified for the MIT-IA pressure test to 4,000 psi 5. Shear circulation valve. 6. Reverse circulate freeze protect and U-Tube. 7. Install TWCV into the tubing hanger and pressure test from direction of flow. 8. Nipple down BOP stack and install 10k frac tree. 9. RDMO NDBi-014 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-014 Field :Pikka East Formation :Nanushuk Stages 1 to 9 County : North Slope State : Alaska Country : United States Prepared for : Scott Leahy Service Point : Prudhoe Bay, Alaska Business Phone : 1 907 659 2434 Date Prepared : 07-18-2023 FAX No. : 1 907 659 2538 Prepared by : Alena Lutskaia Phone : 630-780-0058 E-Mail Address :Alutskaya@slb.com * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. 1 Section 1: Zone Data (Stage 1; 15109 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 4115.7 10.0 0.71 2937 1.46E+06 0.220 1000 Shale 4125.7 15.0 0.70 2873 1.76E+06 0.220 1000 Nanushuk 3 SS 4140.7 15.3 0.68 2813 1.90E+06 0.220 1000 Top Nan CS 4156.0 19.5 0.62 2595 9.00E+05 0.270 1000 Nan SS 4175.5 2.0 0.69 2880 2.67E+06 0.230 2500 Nan CS 4177.5 1.5 0.64 2666 1.29E+06 0.260 1000 Nan CS 4179.0 4.5 0.62 2576 6.44E+05 0.280 1000 Nan DS 4183.5 3.5 0.69 2886 1.77E+06 0.260 1500 Nan DS 4187.0 14.5 0.65 2726 1.39E+06 0.260 1500 Nan CS 4201.5 1.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4203.0 12.5 0.63 2652 8.82E+05 0.270 1000 Nan DS 4215.5 2.0 0.65 2737 1.40E+06 0.260 1500 Nan CS 4217.5 9.0 0.61 2558 8.54E+05 0.270 1000 Nan DS 4226.5 7.0 0.65 2766 1.40E+06 0.260 1500 Nan DS 4233.5 9.0 0.64 2705 1.13E+06 0.270 1500 Nan DS 4242.5 3.5 0.64 2720 1.69E+06 0.260 1500 Nan DS 4246.0 5.0 0.63 2665 7.57E+05 0.270 1000 Nan DS 4251.0 2.0 0.69 2925 1.80E+06 0.250 1500 Nan CS 4253.0 10.5 0.61 2607 7.36E+05 0.270 1000 Nan CS 4263.5 3.5 0.63 2705 1.10E+06 0.270 1000 Nan CS 4267.0 2.0 0.62 2625 6.70E+05 0.280 1000 Nan CS 4269.0 5.5 0.65 2768 1.30E+06 0.260 1000 Nan DS 4274.5 3.5 0.69 2951 1.53E+06 0.260 1500 Nan DS 4278.0 3.5 0.63 2701 1.19E+06 0.270 1500 Nan DS 4281.5 5.5 0.68 2928 1.42E+06 0.260 1500 Nan CS 4287.0 10.5 0.63 2693 1.17E+06 0.270 1000 Nan DS 4297.5 1.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4299.0 5.0 0.62 2671 1.14E+06 0.270 1500 Nan DS 4304.0 2.0 0.66 2820 1.56E+06 0.260 1500 Nan DS 4306.0 4.0 0.62 2688 8.96E+05 0.270 1500 Nan DS 4310.0 2.0 0.67 2876 1.66E+06 0.260 1500 Nan DS 4312.0 10.0 0.63 2707 9.81E+05 0.270 1500 Nan DS 4322.0 4.0 0.65 2828 1.63E+06 0.260 1500 Nan DS 4326.0 4.0 0.69 2974 1.75E+06 0.260 1500 Nan DS 4330.0 9.5 0.64 2784 1.33E+06 0.260 1500 Nan DS 4339.5 2.0 0.61 2649 7.82E+05 0.270 1000 Nan DS 4341.5 9.5 0.68 2975 1.69E+06 0.260 1500 Nan DS 4351.0 2.0 0.65 2812 1.37E+06 0.260 1500 Shale 4353.0 2.0 0.69 3002 2.67E+06 0.230 2500 Nan DS 4355.0 2.0 0.63 2765 1.09E+06 0.270 1500 Shale 4357.0 2.0 0.69 3005 2.67E+06 0.230 2500 Nan DS 4359.0 4.0 0.65 2844 1.29E+06 0.260 1500 Shale 4363.0 19.5 0.69 3015 2.67E+06 0.230 2500 Nan DS 4382.5 2.0 0.64 2820 1.36E+06 0.260 1500 Shale 4384.5 2.0 0.69 3024 2.67E+06 0.230 2500 Nan DS 4386.5 8.0 0.65 2855 1.37E+06 0.260 1500 Nan DS 4394.5 8.0 0.65 2841 1.56E+06 0.260 1500 Shale 4402.5 20.0 0.69 3053 2.67E+06 0.230 2500 Zone Name Poisson’ s Ratio Formation Mechanical Properties 2 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4115.7 10.0 0.001 1.0 1890 4125.7 15.0 0.001 1.0 1898 4140.7 15.3 0.005 10.0 1905 4156.0 19.5 30.655 23.7 1915 4175.5 2.0 5.000 10.0 1924 4177.5 1.5 2.095 16.9 1925 4179.0 4.5 48.388 26.6 1926 4183.5 3.5 0.478 12.4 1928 4187.0 14.5 15.008 17.7 1930 4201.5 1.5 3.661 17.6 1937 4203.0 12.5 34.723 23.9 1937 4215.5 2.0 1.697 15.6 1943 4217.5 9.0 54.319 24.4 1944 4226.5 7.0 3.610 14.8 1948 4233.5 9.0 22.986 20.4 1952 4242.5 3.5 0.835 14.0 1956 4246.0 5.0 65.392 23.4 1957 4251.0 2.0 0.006 10.5 1960 4253.0 10.5 100.832 25.6 1961 4263.5 3.5 17.434 20.5 1966 4267.0 2.0 161.343 26.3 1967 4269.0 5.5 4.627 18.4 1968 4274.5 3.5 5.075 14.8 1971 4278.0 3.5 8.651 19.4 1972 4281.5 5.5 10.205 16.0 1974 4287.0 10.5 17.356 20.1 1977 4297.5 1.5 3.106 14.8 1982 4299.0 5.0 52.863 20.6 1982 4304.0 2.0 2.277 14.1 1985 4306.0 4.0 122.778 23.1 1986 4310.0 2.0 0.333 12.5 1987 4312.0 10.0 39.939 21.2 1988 4322.0 4.0 0.748 13.3 1993 4326.0 4.0 0.009 10.9 1995 4330.0 9.5 5.399 16.7 1997 4339.5 2.0 160.618 24.9 2001 4341.5 9.5 0.033 11.5 2002 4351.0 2.0 6.733 16.2 2007 4353.0 2.0 0.001 1.0 2008 4355.0 2.0 29.480 19.6 2009 4357.0 2.0 0.001 1.0 2009 4359.0 4.0 8.473 16.6 2010 4363.0 19.5 0.001 1.0 2012 4382.5 2.0 2.185 16.4 2021 4384.5 2.0 0.001 1.0 2022 4386.5 8.0 2.645 15.9 2023 4394.5 8.0 2.026 14.4 2027 4402.5 20.0 0.001 10.0 2031 Nan CS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Shale Nan DS Nan DS Shale 3 Section 2: Propped Fracture Schedule (Stage 1; 15109 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 172.4 25 1 2.0 PPA 40 YF125ST 202.1 25 2 4.0 PPA 40 YF125ST 203.9 25 4 6.0 PPA 40 YF125ST 189.7 25 6 8.0 PPA 40 YF125ST 177.3 25 8 10.0 PPA 40 YF125ST 138.7 25 10 Flush 40 YF125ST 229.2 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1638.2 bbl of YF125ST 0 bbl of WF125 224092 lb of % PAD Clean 23.1 % 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 3813 8.1 8.1 1.0 PPA 172.4 497 180 505 7240 7240 3817 4.5 12.6 2.0 PPA 202.1 700 220 725 16979 24218 3833 5.5 18.1 4.0 PPA 203.9 903 240 965 34260 58479 3909 6.0 24.1 6.0 PPA 189.7 1093 240 1205 47799 106278 4075 6.0 30.1 8.0 PPA 177.3 1270 240 1445 59569 165847 4299 6.0 36.1 10.0 PPA 138.7 1409 200 1645 58246 224092 4579 5.0 41.1 Flush 229.2 1638 229 1874 0 224092 4567 5.7 46.9 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 353.1 ft with an average conductivity (Kfw) of 14946.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 Fluid Totals Pad Percentages Job Execution Step Name Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Carbolite 16/20 Proppant Totals Carbolite 16/20 4 4567 Section 3: Propped Fracture Simulation (Stage 1; 15109 ft MD) Initial Fracture Top TVD 4118.9 ft Initial Fracture Bottom TVD 4369.9 ft Propped Fracture Half-Length 353.1 ft EOJ Hyd Height at Well 251 ft Average Propped Width 0.154 in Net Pressure 168 psi Max Surface Pressure 4789 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 88.3 9.5 0.192 137.1 1.65 219 19006 88.3 176.5 7.4 0.189 210.3 1.68 233.3 18363 176.5 264.8 5.5 0.17 199.3 1.53 255.2 16515 264.8 353.1 1.7 0.071 178.3 0.69 1254.3 6905 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 5 4789 psi Section 4: Zone Data (Stage 2; 14564 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 4139.5 10.0 0.71 2937 1.46E+06 0.220 1000 Shale 4149.5 15.0 0.70 2889 1.76E+06 0.220 1000 Nanushuk 3 SS 4164.5 15.3 0.68 2829 1.90E+06 0.220 1000 Top Nan CS 4179.8 19.5 0.62 2595 9.00E+05 0.270 1000 Nan SS 4199.3 2.0 0.69 2880 2.67E+06 0.230 2500 Nan CS 4201.3 1.5 0.64 2681 1.29E+06 0.260 1000 Nan CS 4202.8 4.5 0.62 2590 6.44E+05 0.280 1000 Nan DS 4207.3 3.5 0.69 2886 1.77E+06 0.260 1500 Nan DS 4210.8 14.5 0.65 2726 1.39E+06 0.260 1500 Nan CS 4225.3 1.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4226.8 12.5 0.63 2667 8.82E+05 0.270 1000 Nan DS 4239.3 2.0 0.65 2752 1.40E+06 0.260 1500 Nan CS 4241.3 9.0 0.60 2558 8.54E+05 0.270 1000 Nan DS 4250.3 7.0 0.65 2782 1.40E+06 0.260 1500 Nan DS 4257.3 9.0 0.63 2705 1.13E+06 0.270 1500 Nan DS 4266.3 3.5 0.64 2720 1.69E+06 0.260 1500 Nan DS 4269.8 5.0 0.62 2665 7.57E+05 0.270 1000 Nan DS 4274.8 2.0 0.68 2925 1.80E+06 0.250 1500 Nan CS 4276.8 10.5 0.61 2607 7.36E+05 0.270 1000 Nan CS 4287.3 3.5 0.63 2705 1.10E+06 0.270 1000 Nan CS 4290.8 2.0 0.62 2639 6.70E+05 0.280 1000 Nan CS 4292.8 5.5 0.64 2768 1.30E+06 0.260 1000 Nan DS 4298.3 3.5 0.69 2967 1.53E+06 0.260 1500 Nan DS 4301.8 3.5 0.63 2701 1.19E+06 0.270 1500 Nan DS 4305.3 5.5 0.68 2928 1.42E+06 0.260 1500 Nan CS 4310.8 10.5 0.62 2693 1.17E+06 0.270 1000 Nan DS 4321.3 1.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4322.8 5.0 0.62 2671 1.14E+06 0.270 1500 Nan DS 4327.8 2.0 0.66 2835 1.56E+06 0.260 1500 Nan DS 4329.8 4.0 0.62 2688 8.96E+05 0.270 1500 Nan DS 4333.8 2.0 0.66 2876 1.66E+06 0.260 1500 Nan DS 4335.8 10.0 0.63 2722 9.81E+05 0.270 1500 Nan DS 4345.8 4.0 0.65 2843 1.63E+06 0.260 1500 Nan DS 4349.8 4.0 0.68 2974 1.75E+06 0.260 1500 Nan DS 4353.8 9.5 0.64 2784 1.33E+06 0.260 1500 Nan DS 4363.3 2.0 0.61 2649 7.82E+05 0.270 1000 Nan DS 4365.3 9.5 0.68 2975 1.69E+06 0.260 1500 Nan DS 4374.8 2.0 0.64 2812 1.37E+06 0.260 1500 Shale 4376.8 2.0 0.69 3002 2.67E+06 0.230 2500 Nan DS 4378.8 2.0 0.63 2765 1.09E+06 0.270 1500 Shale 4380.8 2.0 0.69 3005 2.67E+06 0.230 2500 Nan DS 4382.8 4.0 0.65 2844 1.29E+06 0.260 1500 Shale 4386.8 19.5 0.69 3015 2.67E+06 0.230 2500 Nan DS 4406.3 2.0 0.64 2820 1.36E+06 0.260 1500 Shale 4408.3 2.0 0.69 3024 2.67E+06 0.230 2500 Nan DS 4410.3 8.0 0.65 2855 1.37E+06 0.260 1500 Nan DS 4418.3 8.0 0.64 2841 1.56E+06 0.260 1500 Shale 4426.3 20.0 0.69 3070 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 6 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4139.5 10.0 0.001 1.0 1890 4149.5 15.0 0.001 1.0 1898 4164.5 15.3 0.005 10.0 1905 4179.8 19.5 30.655 23.7 1915 4199.3 2.0 5.000 10.0 1924 4201.3 1.5 2.095 16.9 1925 4202.8 4.5 48.388 26.6 1926 4207.3 3.5 0.478 12.4 1928 4210.8 14.5 15.008 17.7 1930 4225.3 1.5 3.661 17.6 1937 4226.8 12.5 34.723 23.9 1937 4239.3 2.0 1.697 15.6 1943 4241.3 9.0 54.319 24.4 1944 4250.3 7.0 3.610 14.8 1948 4257.3 9.0 22.986 20.4 1952 4266.3 3.5 0.835 14.0 1956 4269.8 5.0 65.392 23.4 1957 4274.8 2.0 0.006 10.5 1960 4276.8 10.5 100.832 25.6 1961 4287.3 3.5 17.434 20.5 1966 4290.8 2.0 161.343 26.3 1967 4292.8 5.5 4.627 18.4 1968 4298.3 3.5 5.075 14.8 1971 4301.8 3.5 8.651 19.4 1972 4305.3 5.5 10.205 16.0 1974 4310.8 10.5 17.356 20.1 1977 4321.3 1.5 3.106 14.8 1982 4322.8 5.0 52.863 20.6 1982 4327.8 2.0 2.277 14.1 1985 4329.8 4.0 122.778 23.1 1986 4333.8 2.0 0.333 12.5 1987 4335.8 10.0 39.939 21.2 1988 4345.8 4.0 0.748 13.3 1993 4349.8 4.0 0.009 10.9 1995 4353.8 9.5 5.399 16.7 1997 4363.3 2.0 160.618 24.9 2001 4365.3 9.5 0.033 11.5 2002 4374.8 2.0 6.733 16.2 2007 4376.8 2.0 0.001 1.0 2008 4378.8 2.0 29.480 19.6 2009 4380.8 2.0 0.001 1.0 2009 4382.8 4.0 8.473 16.6 2010 4386.8 19.5 0.001 1.0 2012 4406.3 2.0 2.185 16.4 2021 4408.3 2.0 0.001 1.0 2022 4410.3 8.0 2.645 15.9 2023 4418.3 8.0 2.026 14.4 2027 4426.3 20.0 0.001 10.0 2031 Nan DS Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan CS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Shale 7 Section 5: Propped Fracture Schedule (Stage 2; 14564 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 172.4 25 1 2.0 PPA 40 YF125ST 165.4 25 2 3.0 PPA 40 YF125ST 176.6 25 3 4.0 PPA 40 YF125ST 169.9 25 4 5.0 PPA 40 YF125ST 163.8 25 5 6.0 PPA 40 YF125ST 158.1 25 6 7.0 PPA 40 YF125ST 137.5 25 7 8.0 PPA 40 YF125ST 118.2 25 8 Flush 40 YF125ST 221.9 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1833.6 bbl of YF125ST 0 bbl of WF125 226283 lb of % PAD Clean 21.7 % PAD Dirty 18.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 350.0 350 350 350 0 0 3720 8.8 8.8 1.0 PPA 172.4 522 180 530 7240 7240 3722 4.5 13.3 2.0 PPA 165.4 688 180 710 13892 21131 3734 4.5 17.8 3.0 PPA 176.6 864 200 910 22249 43380 3782 5.0 22.8 4.0 PPA 169.9 1034 200 1110 28550 71931 3837 5.0 27.8 5.0 PPA 163.8 1198 200 1310 34396 106326 3901 5.0 32.8 6.0 PPA 158.1 1356 200 1510 39832 146159 3979 5.0 37.8 7.0 PPA 137.5 1494 180 1690 40412 186571 4072 4.5 42.3 8.0 PPA 118.2 1612 160 1850 39712 226283 4175 4.0 46.3 Flush 221.9 1834 222 2072 0 226283 4196 5.5 51.8 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 339.5 ft with an average conductivity (Kfw) of 16705.4 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 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 8 Section 6: Propped Fracture Simulation (Stage 2; 14564 ft MD) Initial Fracture Top TVD 4148.7 ft Initial Fracture Bottom TVD 4388.8 ft Propped Fracture Half-Length 339.5 ft EOJ Hyd Height at Well 240.1 ft Average Propped Width 0.175 in Net Pressure 256 psi Max Surface Pressure 4274 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 7.5 0.2 191.5 1.73 268.2 19384 84.9 169.7 6.5 0.198 203.9 1.75 282.2 18983 169.7 254.6 6.2 0.194 181.4 1.76 282.7 18667 254.6 339.5 2.7 0.115 166.7 1.08 668.9 11026 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 Section 7: Zone Data (Stage 3; 14019 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 4166.1 10.0 0.70 2937 1.46E+06 0.220 1000 Shale 4176.1 15.0 0.70 2908 1.76E+06 0.220 1000 Nanushuk 3 SS 4191.1 15.3 0.68 2847 1.90E+06 0.220 1000 Top Nan CS 4206.4 19.5 0.62 2595 9.00E+05 0.270 1000 Nan SS 4225.9 2.0 0.68 2880 2.67E+06 0.230 2500 Nan CS 4227.9 1.5 0.64 2698 1.29E+06 0.260 1000 Nan CS 4229.4 4.5 0.62 2607 6.44E+05 0.280 1000 Nan DS 4233.9 3.5 0.68 2886 1.77E+06 0.260 1500 Nan DS 4237.4 14.5 0.64 2726 1.39E+06 0.260 1500 Nan CS 4251.9 1.5 0.64 2706 1.15E+06 0.270 1000 Nan CS 4253.4 12.5 0.63 2684 8.82E+05 0.270 1000 Nan DS 4265.9 2.0 0.65 2769 1.40E+06 0.260 1500 Nan CS 4267.9 9.0 0.60 2558 8.54E+05 0.270 1000 Nan DS 4276.9 7.0 0.65 2799 1.40E+06 0.260 1500 Nan DS 4283.9 9.0 0.63 2705 1.13E+06 0.270 1500 Nan DS 4292.9 3.5 0.63 2720 1.69E+06 0.260 1500 Nan DS 4296.4 5.0 0.62 2665 7.57E+05 0.270 1000 Nan DS 4301.4 2.0 0.68 2925 1.80E+06 0.250 1500 Nan CS 4303.4 10.5 0.61 2607 7.36E+05 0.270 1000 Nan CS 4313.9 3.5 0.63 2705 1.10E+06 0.270 1000 Nan CS 4317.4 2.0 0.62 2656 6.70E+05 0.280 1000 Nan CS 4319.4 5.5 0.64 2768 1.30E+06 0.260 1000 Nan DS 4324.9 3.5 0.69 2985 1.53E+06 0.260 1500 Nan DS 4328.4 3.5 0.62 2701 1.19E+06 0.270 1500 Nan DS 4331.9 5.5 0.68 2928 1.42E+06 0.260 1500 Nan CS 4337.4 10.5 0.62 2693 1.17E+06 0.270 1000 Nan DS 4347.9 1.5 0.65 2811 1.38E+06 0.260 1500 Nan DS 4349.4 5.0 0.61 2671 1.14E+06 0.270 1500 Nan DS 4354.4 2.0 0.66 2853 1.56E+06 0.260 1500 Nan DS 4356.4 4.0 0.62 2688 8.96E+05 0.270 1500 Nan DS 4360.4 2.0 0.66 2876 1.66E+06 0.260 1500 Nan DS 4362.4 10.0 0.63 2738 9.81E+05 0.270 1500 Nan DS 4372.4 4.0 0.65 2861 1.63E+06 0.260 1500 Nan DS 4376.4 4.0 0.68 2974 1.75E+06 0.260 1500 Nan DS 4380.4 9.5 0.63 2784 1.33E+06 0.260 1500 Nan DS 4389.9 2.0 0.60 2649 7.82E+05 0.270 1000 Nan DS 4391.9 9.5 0.68 2975 1.69E+06 0.260 1500 Nan DS 4401.4 2.0 0.64 2812 1.37E+06 0.260 1500 Shale 4403.4 2.0 0.68 3002 2.67E+06 0.230 2500 Nan DS 4405.4 2.0 0.63 2765 1.09E+06 0.270 1500 Shale 4407.4 2.0 0.68 3005 2.67E+06 0.230 2500 Nan DS 4409.4 4.0 0.64 2844 1.29E+06 0.260 1500 Shale 4413.4 19.5 0.68 3015 2.67E+06 0.230 2500 Nan DS 4432.9 2.0 0.64 2820 1.36E+06 0.260 1500 Shale 4434.9 2.0 0.68 3024 2.67E+06 0.230 2500 Nan DS 4436.9 8.0 0.64 2855 1.37E+06 0.260 1500 Nan DS 4444.9 8.0 0.64 2841 1.56E+06 0.260 1500 Shale 4452.9 20.0 0.69 3088 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 10 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4166.1 10.0 0.001 1.0 1890 4176.1 15.0 0.001 1.0 1898 4191.1 15.3 0.005 10.0 1905 4206.4 19.5 30.655 23.7 1915 4225.9 2.0 5.000 10.0 1924 4227.9 1.5 2.095 16.9 1925 4229.4 4.5 48.388 26.6 1926 4233.9 3.5 0.478 12.4 1928 4237.4 14.5 15.008 17.7 1930 4251.9 1.5 3.661 17.6 1937 4253.4 12.5 34.723 23.9 1937 4265.9 2.0 1.697 15.6 1943 4267.9 9.0 54.319 24.4 1944 4276.9 7.0 3.610 14.8 1948 4283.9 9.0 22.986 20.4 1952 4292.9 3.5 0.835 14.0 1956 4296.4 5.0 65.392 23.4 1957 4301.4 2.0 0.006 10.5 1960 4303.4 10.5 100.832 25.6 1961 4313.9 3.5 17.434 20.5 1966 4317.4 2.0 161.343 26.3 1967 4319.4 5.5 4.627 18.4 1968 4324.9 3.5 5.075 14.8 1971 4328.4 3.5 8.651 19.4 1972 4331.9 5.5 10.205 16.0 1974 4337.4 10.5 17.356 20.1 1977 4347.9 1.5 3.106 14.8 1982 4349.4 5.0 52.863 20.6 1982 4354.4 2.0 2.277 14.1 1985 4356.4 4.0 122.778 23.1 1986 4360.4 2.0 0.333 12.5 1987 4362.4 10.0 39.939 21.2 1988 4372.4 4.0 0.748 13.3 1993 4376.4 4.0 0.009 10.9 1995 4380.4 9.5 5.399 16.7 1997 4389.9 2.0 160.618 24.9 2001 4391.9 9.5 0.033 11.5 2002 4401.4 2.0 6.733 16.2 2007 4403.4 2.0 0.001 1.0 2008 4405.4 2.0 29.480 19.6 2009 4407.4 2.0 0.001 1.0 2009 4409.4 4.0 8.473 16.6 2010 4413.4 19.5 0.001 1.0 2012 4432.9 2.0 2.185 16.4 2021 4434.9 2.0 0.001 1.0 2022 4436.9 8.0 2.645 15.9 2023 4444.9 8.0 2.026 14.4 2027 4452.9 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 11 Section 8: Propped Fracture Schedule (Stage 3; 14019 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 172.4 25 1 2.0 PPA 40 YF125ST 165.4 25 2 3.0 PPA 40 YF125ST 176.6 25 3 4.0 PPA 40 YF125ST 169.9 25 4 5.0 PPA 40 YF125ST 163.8 25 5 6.0 PPA 40 YF125ST 158.1 25 6 7.0 PPA 40 YF125ST 137.5 25 7 8.0 PPA 40 YF125ST 118.2 25 8 Flush 40 YF125ST 212.6 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1824.3 bbl of YF125ST 0 bbl of WF125 226283 lb of % PAD Clean 21.7 % PAD Dirty 18.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 350.0 350 350 350 0 0 3630 8.8 8.8 1.0 PPA 172.4 522 180 530 7240 7240 3634 4.5 13.3 2.0 PPA 165.4 688 180 710 13892 21131 3650 4.5 17.8 3.0 PPA 176.6 864 200 910 22249 43380 3687 5.0 22.8 4.0 PPA 169.9 1034 200 1110 28550 71931 3737 5.0 27.8 5.0 PPA 163.8 1198 200 1310 34396 106326 3794 5.0 32.8 6.0 PPA 158.1 1356 200 1510 39832 146159 3867 5.0 37.8 7.0 PPA 137.5 1494 180 1690 40412 186571 3964 4.5 42.3 8.0 PPA 118.2 1612 160 1850 39712 226283 4065 4.0 46.3 Flush 212.6 1824 213 2063 0 226283 4082 5.3 51.6 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 321.3 ft with an average conductivity (Kfw) of 17471.4 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 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 12 Section 9: Propped Fracture Simulation (Stage 3; 14019 ft MD) Initial Fracture Top TVD 4177.6 ft Initial Fracture Bottom TVD 4416 ft Propped Fracture Half-Length 321.3 ft EOJ Hyd Height at Well 238.4 ft Average Propped Width 0.183 in Net Pressure 231 psi Max Surface Pressure 4156 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 7.4 0.215 185.3 1.86 259.5 20874 80.3 160.6 6.5 0.212 213.7 1.89 277 20342 160.6 241 6 0.197 192.6 1.78 294.7 19025 241 321.3 2.4 0.116 157 1.07 417.6 11076 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 Section 10: Zone Data (Stage 4; 13474 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 4189.2 10.0 0.70 2937 1.46E+06 0.220 1000 Shale 4199.2 15.0 0.70 2924 1.76E+06 0.220 1000 Nanushuk 3 SS 4214.2 15.3 0.68 2862 1.90E+06 0.220 1000 Top Nan CS 4229.5 19.5 0.61 2595 9.00E+05 0.270 1000 Nan SS 4249.0 2.0 0.68 2880 2.67E+06 0.230 2500 Nan CS 4251.0 1.5 0.64 2713 1.29E+06 0.260 1000 Nan CS 4252.5 4.5 0.62 2621 6.44E+05 0.280 1000 Nan DS 4257.0 3.5 0.68 2886 1.77E+06 0.260 1500 Nan DS 4260.5 14.5 0.64 2726 1.39E+06 0.260 1500 Nan CS 4275.0 1.5 0.63 2706 1.15E+06 0.270 1000 Nan CS 4276.5 12.5 0.63 2698 8.82E+05 0.270 1000 Nan DS 4289.0 2.0 0.65 2784 1.40E+06 0.260 1500 Nan CS 4291.0 9.0 0.60 2558 8.54E+05 0.270 1000 Nan DS 4300.0 7.0 0.65 2814 1.40E+06 0.260 1500 Nan DS 4307.0 9.0 0.63 2705 1.13E+06 0.270 1500 Nan DS 4316.0 3.5 0.63 2720 1.69E+06 0.260 1500 Nan DS 4319.5 5.0 0.62 2665 7.57E+05 0.270 1000 Nan DS 4324.5 2.0 0.68 2925 1.80E+06 0.250 1500 Nan CS 4326.5 10.5 0.60 2607 7.36E+05 0.270 1000 Nan CS 4337.0 3.5 0.62 2705 1.10E+06 0.270 1000 Nan CS 4340.5 2.0 0.62 2670 6.70E+05 0.280 1000 Nan CS 4342.5 5.5 0.64 2768 1.30E+06 0.260 1000 Nan DS 4348.0 3.5 0.69 3001 1.53E+06 0.260 1500 Nan DS 4351.5 3.5 0.62 2701 1.19E+06 0.270 1500 Nan DS 4355.0 5.5 0.67 2928 1.42E+06 0.260 1500 Nan CS 4360.5 10.5 0.62 2693 1.17E+06 0.270 1000 Nan DS 4371.0 1.5 0.64 2811 1.38E+06 0.260 1500 Nan DS 4372.5 5.0 0.61 2671 1.14E+06 0.270 1500 Nan DS 4377.5 2.0 0.66 2868 1.56E+06 0.260 1500 Nan DS 4379.5 4.0 0.61 2688 8.96E+05 0.270 1500 Nan DS 4383.5 2.0 0.66 2876 1.66E+06 0.260 1500 Nan DS 4385.5 10.0 0.63 2753 9.81E+05 0.270 1500 Nan DS 4395.5 4.0 0.65 2876 1.63E+06 0.260 1500 Nan DS 4399.5 4.0 0.68 2974 1.75E+06 0.260 1500 Nan DS 4403.5 9.5 0.63 2784 1.33E+06 0.260 1500 Nan DS 4413.0 2.0 0.60 2649 7.82E+05 0.270 1000 Nan DS 4415.0 9.5 0.67 2975 1.69E+06 0.260 1500 Nan DS 4424.5 2.0 0.64 2812 1.37E+06 0.260 1500 Shale 4426.5 2.0 0.68 3002 2.67E+06 0.230 2500 Nan DS 4428.5 2.0 0.62 2765 1.09E+06 0.270 1500 Shale 4430.5 2.0 0.68 3005 2.67E+06 0.230 2500 Nan DS 4432.5 4.0 0.64 2844 1.29E+06 0.260 1500 Shale 4436.5 19.5 0.68 3015 2.67E+06 0.230 2500 Nan DS 4456.0 2.0 0.63 2820 1.36E+06 0.260 1500 Shale 4458.0 2.0 0.68 3024 2.67E+06 0.230 2500 Nan DS 4460.0 8.0 0.64 2855 1.37E+06 0.260 1500 Nan DS 4468.0 8.0 0.64 2841 1.56E+06 0.260 1500 Shale 4476.0 20.0 0.69 3104 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 14 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4189.2 10.0 0.001 1.0 1890 4199.2 15.0 0.001 1.0 1898 4214.2 15.3 0.005 10.0 1905 4229.5 19.5 30.655 23.7 1915 4249.0 2.0 5.000 10.0 1924 4251.0 1.5 2.095 16.9 1925 4252.5 4.5 48.388 26.6 1926 4257.0 3.5 0.478 12.4 1928 4260.5 14.5 15.008 17.7 1930 4275.0 1.5 3.661 17.6 1937 4276.5 12.5 34.723 23.9 1937 4289.0 2.0 1.697 15.6 1943 4291.0 9.0 54.319 24.4 1944 4300.0 7.0 3.610 14.8 1948 4307.0 9.0 22.986 20.4 1952 4316.0 3.5 0.835 14.0 1956 4319.5 5.0 65.392 23.4 1957 4324.5 2.0 0.006 10.5 1960 4326.5 10.5 100.832 25.6 1961 4337.0 3.5 17.434 20.5 1966 4340.5 2.0 161.343 26.3 1967 4342.5 5.5 4.627 18.4 1968 4348.0 3.5 5.075 14.8 1971 4351.5 3.5 8.651 19.4 1972 4355.0 5.5 10.205 16.0 1974 4360.5 10.5 17.356 20.1 1977 4371.0 1.5 3.106 14.8 1982 4372.5 5.0 52.863 20.6 1982 4377.5 2.0 2.277 14.1 1985 4379.5 4.0 122.778 23.1 1986 4383.5 2.0 0.333 12.5 1987 4385.5 10.0 39.939 21.2 1988 4395.5 4.0 0.748 13.3 1993 4399.5 4.0 0.009 10.9 1995 4403.5 9.5 5.399 16.7 1997 4413.0 2.0 160.618 24.9 2001 4415.0 9.5 0.033 11.5 2002 4424.5 2.0 6.733 16.2 2007 4426.5 2.0 0.001 1.0 2008 4428.5 2.0 29.480 19.6 2009 4430.5 2.0 0.001 1.0 2009 4432.5 4.0 8.473 16.6 2010 4436.5 19.5 0.001 1.0 2012 4456.0 2.0 2.185 16.4 2021 4458.0 2.0 0.001 1.0 2022 4460.0 8.0 2.645 15.9 2023 4468.0 8.0 2.026 14.4 2027 4476.0 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 15 Section 11: Propped Fracture Schedule (Stage 4; 13474 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 250.0 25 0 1.0 PPA 40 YF125ST 134.1 25 1 2.0 PPA 40 YF125ST 147.0 25 2 4.0 PPA 40 YF125ST 152.9 25 4 6.0 PPA 40 YF125ST 142.3 25 6 8.0 PPA 40 YF125ST 133.0 25 8 10.0 PPA 40 YF125ST 124.8 25 10 12.0 PPA 40 YF125ST 98.0 25 12 Flush 40 YF125ST 204.3 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1386.3 bbl of YF125ST 0 bbl of WF125 226014 lb of % PAD Clean 21.1 % PAD Dirty 17.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3558 6.3 6.3 1.0 PPA 134.1 384 140 390 5631 5631 3547 3.5 9.8 2.0 PPA 147.0 531 160 550 12348 17979 3544 4.0 13.8 4.0 PPA 152.9 684 180 730 25695 43674 3593 4.5 18.3 6.0 PPA 142.3 826 180 910 35849 79524 3713 4.5 22.8 8.0 PPA 133.0 959 180 1090 44677 124200 3894 4.5 27.3 10.0 PPA 124.8 1084 180 1270 52421 176621 4145 4.5 31.8 12.0 PPA 98.0 1182 150 1420 49392 226014 4454 3.8 35.5 Flush 204.3 1386 204 1624 0 226014 4394 5.1 40.6 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 325.4 ft with an average conductivity (Kfw) of 16709.1 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 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 16 Section 12: Propped Fracture Simulation (Stage 4; 13474 ft MD) Initial Fracture Top TVD 4199.3 ft Initial Fracture Bottom TVD 4442.4 ft Propped Fracture Half-Length 325.4 ft EOJ Hyd Height at Well 243.1 ft Average Propped Width 0.176 in Net Pressure 197 psi Max Surface Pressure 4668 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 11.3 0.219 147.8 1.9 187.9 21172 81.4 162.7 9 0.212 214.3 1.88 200.6 20280 162.7 244.1 6.7 0.191 201.6 1.72 220.8 18131 244.1 325.4 1.9 0.088 130.3 0.8 417.9 8423 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 Section 13: Zone Data (Stage 5; 12929 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 4206.9 10.0 0.70 2955 1.46E+06 0.220 1000 Shale 4216.9 15.0 0.70 2936 1.76E+06 0.220 1000 Siltstone 4231.9 15.3 0.68 2874 1.90E+06 0.220 1000 Top Nan CS 4247.2 17.5 0.62 2648 8.18E+05 0.270 1000 Nan DS 4264.7 2.0 0.60 2549 7.85E+05 0.270 1000 Nan DS 4266.7 5.5 0.63 2677 1.25E+06 0.260 1500 SHALE 4272.2 3.5 0.68 2909 2.67E+06 0.230 2500 Nan DS 4275.7 1.5 0.63 2676 1.10E+06 0.270 1500 Nan DS 4277.2 2.0 0.64 2717 9.14E+05 0.270 1500 Nan CS 4279.2 1.5 0.61 2605 6.70E+05 0.280 1000 Nan CS 4280.7 2.0 0.64 2745 1.25E+06 0.260 1000 Nan CS 4282.7 3.5 0.60 2560 7.72E+05 0.270 1000 Nan CS 4286.2 4.5 0.61 2605 8.74E+05 0.270 1000 Nan DS 4290.7 7.0 0.64 2768 1.42E+06 0.260 1500 Nan DS 4297.7 4.5 0.61 2611 7.58E+05 0.270 1000 Nan DS 4302.2 5.0 0.61 2627 9.98E+05 0.270 1500 Nan CS 4307.2 4.5 0.64 2762 1.12E+06 0.270 1000 Nan CS 4311.7 9.5 0.60 2593 7.78E+05 0.270 1000 Nan DS 4321.2 2.5 0.64 2767 1.69E+06 0.260 1500 Nan DS 4323.7 12.0 0.62 2685 9.65E+05 0.270 1500 Nan DS 4335.7 2.5 0.65 2801 1.47E+06 0.260 1500 Nan DS 4338.2 9.5 0.62 2710 1.30E+06 0.260 1500 Nan DS 4347.7 2.0 0.64 2765 1.44E+06 0.260 1500 Nan DS 4349.7 41.0 0.62 2729 1.02E+06 0.270 1500 Nan DS 4390.7 1.5 0.62 2732 8.62E+05 0.270 1000 Nan CS 4392.2 6.0 0.61 2695 7.65E+05 0.280 1000 Nan DS 4398.2 6.0 0.66 2899 1.24E+06 0.260 1500 Nan DS 4404.2 4.0 0.68 2991 1.69E+06 0.260 1500 Nan DS 4408.2 2.0 0.64 2822 1.01E+06 0.270 1500 Nan DS 4410.2 2.0 0.69 3030 1.69E+06 0.260 1500 Nan DS 4412.2 2.0 0.63 2786 1.13E+06 0.270 1500 Nan DS 4414.2 5.5 0.68 2994 1.69E+06 0.260 1500 Nan DS 4419.7 4.0 0.62 2720 9.50E+05 0.270 1000 Nan DS 4423.7 2.0 0.68 3000 1.69E+06 0.260 1500 Nan DS 4425.7 12.0 0.63 2788 9.20E+05 0.270 1000 Nan DS 4437.7 4.0 0.69 3041 1.43E+06 0.260 1500 Nan DS 4441.7 4.0 0.63 2810 1.47E+06 0.260 1500 SHALE 4445.7 2.0 0.68 3028 2.67E+06 0.230 2500 Nan DS 4447.7 1.5 0.64 2849 1.37E+06 0.260 1500 SHALE 4449.2 8.0 0.68 3033 2.67E+06 0.230 2500 Nan DS 4457.2 8.0 0.62 2772 1.13E+06 0.270 1500 Nan DS 4465.2 1.5 0.63 2792 1.42E+06 0.260 1500 SHALE 4466.7 2.0 0.68 3043 2.67E+06 0.230 2500 Nan DS 4468.7 4.0 0.64 2848 1.28E+06 0.260 1500 SHALE 4472.7 2.0 0.68 3047 2.67E+06 0.230 2500 Nan DS 4474.7 6.0 0.63 2801 1.07E+06 0.270 1500 SHALE 4480.7 20.0 0.68 3059 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 18 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4206.9 10.0 0.001 1.0 1913 4216.9 15.0 0.001 1.0 1918 4231.9 15.3 0.005 10.0 1925 4247.2 17.5 39.470 24.9 1932 4264.7 2.0 113.240 25.3 1940 4266.7 5.5 22.020 19.7 1941 4272.2 3.5 0.001 1.0 1944 4275.7 1.5 21.670 21.3 1945 4277.2 2.0 159.890 23.6 1946 4279.2 1.5 110.140 27.0 1947 4280.7 2.0 2.870 19.7 1948 4282.7 3.5 94.750 25.5 1949 4286.2 4.5 44.130 24.1 1950 4290.7 7.0 4.280 17.9 1952 4297.7 4.5 91.630 25.7 1956 4302.2 5.0 31.600 22.6 1958 4307.2 4.5 3.110 21.1 1960 4311.7 9.5 131.710 25.4 1962 4321.2 2.5 1.000 15.1 1967 4323.7 12.0 104.140 23.0 1968 4335.7 2.5 2.350 17.3 1974 4338.2 9.5 31.760 19.2 1975 4347.7 2.0 3.790 17.6 1979 4349.7 41.0 72.280 22.4 1980 4390.7 1.5 68.110 24.3 1999 4392.2 6.0 156.150 26.2 2000 4398.2 6.0 40.960 19.9 2003 4404.2 4.0 0.020 15.0 2006 4408.2 2.0 17.850 22.4 2008 4410.2 2.0 0.010 15.0 2009 4412.2 2.0 22.090 21.0 2010 4414.2 5.5 0.020 15.0 2011 4419.7 4.0 63.420 23.1 2013 4423.7 2.0 0.020 15.0 2015 4425.7 12.0 74.620 23.5 2016 4437.7 4.0 11.770 17.8 2022 4441.7 4.0 2.490 17.3 2023 4445.7 2.0 0.001 1.0 2025 4447.7 1.5 3.220 18.4 2026 4449.2 8.0 0.001 1.0 2027 4457.2 8.0 65.690 21.2 2031 4465.2 1.5 4.800 17.8 2035 4466.7 2.0 0.001 1.0 2035 4468.7 4.0 11.980 19.3 2036 4472.7 2.0 0.001 1.0 2038 4474.7 6.0 60.610 22.1 2039 4480.7 20.0 0.001 1.0 2042 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Siltstone Top Nan CS Nan DS Nan DS SHALE Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan CS 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 DS Nan DS Nan DS Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS SHALE Nan DS SHALE Nan DS SHALE 19 Section 14: Propped Fracture Schedule (Stage 5; 12929 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 172.4 25 1 2.0 PPA 40 YF125ST 202.1 25 2 4.0 PPA 40 YF125ST 203.9 25 4 6.0 PPA 40 YF125ST 189.7 25 6 8.0 PPA 40 YF125ST 177.3 25 8 10.0 PPA 40 YF125ST 138.7 25 10 Flush 40 YF125ST 196.0 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1605 bbl of YF125ST 0 bbl of WF125 224092 lb of % PAD Clean 23.1 % 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 3437 8.1 8.1 1.0 PPA 172.4 497 180 505 7240 7240 3435 4.5 12.6 2.0 PPA 202.1 700 220 725 16979 24218 3450 5.5 18.1 4.0 PPA 203.9 903 240 965 34260 58479 3497 6.0 24.1 6.0 PPA 189.7 1093 240 1205 47799 106278 3617 6.0 30.1 8.0 PPA 177.3 1270 240 1445 59569 165847 3789 6.0 36.1 10.0 PPA 138.7 1409 200 1645 58246 224092 4017 5.0 41.1 Flush 196.0 1605 196 1841 0 224092 4019 4.9 46.0 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 366.2 ft with an average conductivity (Kfw) of 17313.8 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 20 Section 15: Propped Fracture Simulation (Stage 5; 12929 ft MD) Initial Fracture Top TVD 4224.2 ft Initial Fracture Bottom TVD 4445.5 ft Propped Fracture Half-Length 366.2 ft EOJ Hyd Height at Well 221.4 ft Average Propped Width 0.179 in Net Pressure 322 psi Max Surface Pressure 4230 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 91.6 9.4 0.231 144.4 2.01 218.6 22572 91.6 183.1 7.4 0.224 187.4 2.02 236.3 21775 183.1 274.7 6 0.179 163.2 1.62 296 17363 274.7 366.2 1.8 0.094 141.5 0.85 405.9 9030 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 Section 16: Zone Data (Stage 6; 12384 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 4185.4 41.7 0.70 2965 1.46E+06 0.220 1000 SHALE 4227.1 15.0 0.70 2943 1.76E+06 0.220 1000 SILTSTONE 4242.1 24.1 0.68 2884 1.90E+06 0.220 1000 Top Nan CS 4266.2 7.0 0.62 2654 2.37E+06 0.240 1000 DIRTY-SANDSTONE 4273.2 1.5 0.67 2880 1.50E+06 0.240 1000 SHALE 4274.7 2.0 0.68 2917 2.67E+06 0.230 2500 CLEAN-SANDSTONE 4276.7 10.5 0.61 2622 6.84E+05 0.280 1000 DIRTY-SANDSTONE 4287.2 6.5 0.63 2711 1.02E+06 0.270 1500 DIRTY-SANDSTONE 4293.7 5.5 0.64 2739 1.54E+06 0.260 1500 DIRTY-SANDSTONE 4299.2 5.0 0.62 2662 1.23E+06 0.260 1000 DIRTY-SANDSTONE 4304.2 1.5 0.65 2777 1.41E+06 0.260 1500 DIRTY-SANDSTONE 4305.7 2.0 0.64 2767 1.70E+06 0.260 1500 DIRTY-SANDSTONE 4307.7 1.5 0.60 2576 5.77E+05 0.280 1500 DIRTY-SANDSTONE 4309.2 11.5 0.64 2767 1.31E+06 0.260 1500 DIRTY-SANDSTONE 4320.7 1.8 0.67 2878 1.24E+06 0.270 1500 DIRTY-SANDSTONE 4322.5 2.1 0.68 2929 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4324.6 8.2 0.62 2688 9.65E+05 0.270 1000 DIRTY-SANDSTONE 4332.8 4.9 0.64 2775 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4337.7 1.5 0.67 2890 1.68E+06 0.260 1500 DIRTY-SANDSTONE 4339.2 2.0 0.63 2732 1.51E+06 0.260 1500 SHALE 4341.2 3.5 0.69 2992 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4344.7 1.5 0.65 2814 1.65E+06 0.260 1500 SHALE 4346.2 1.5 0.68 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4347.7 3.5 0.62 2717 1.48E+06 0.260 1500 SHALE 4351.2 5.0 0.68 2971 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4356.2 2.0 0.62 2696 1.12E+06 0.270 1500 SHALE 4358.2 5.0 0.68 2976 2.67E+06 0.230 2500 SHALE 4363.2 3.5 0.68 2979 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4366.7 1.5 0.65 2819 1.31E+06 0.260 1500 SHALE 4368.2 11.0 0.68 2985 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4379.2 2.0 0.62 2720 8.37E+05 0.270 1000 SHALE 4381.2 1.5 0.68 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4382.7 2.0 0.63 2744 9.57E+05 0.270 1000 DIRTY-SANDSTONE 4384.7 4.0 0.68 2984 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4388.7 5.5 0.63 2769 1.20E+06 0.270 1500 DIRTY-SANDSTONE 4394.2 2.0 0.62 2728 9.33E+05 0.270 1000 DIRTY-SANDSTONE 4396.2 6.0 0.68 2992 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4402.2 21.5 0.63 2787 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4423.7 2.0 0.69 3040 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4425.7 4.0 0.64 2842 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4429.7 2.0 0.60 2660 8.76E+05 0.270 1500 SHALE 4431.7 2.0 0.68 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4433.7 4.0 0.64 2828 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4437.7 4.0 0.62 2768 1.12E+06 0.270 1500 DIRTY-SANDSTONE 4441.7 2.0 0.68 3021 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4443.7 7.5 0.63 2824 1.18E+06 0.270 1500 SHALE 4451.2 9.5 0.68 3041 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4460.7 2.0 0.68 3047 1.69E+06 0.260 1500 SHALE 4462.7 50.0 0.69 3085 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 22 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4185.4 41.7 0.010 1.0 1918 4227.1 15.0 0.010 1.0 1923 4242.1 24.1 0.050 10.0 1929 4266.2 7.0 6.009 4.1 1940 4273.2 1.5 0.192 12.0 1944 4274.7 2.0 0.010 1.0 1944 4276.7 10.5 100.314 26.7 1945 4287.2 6.5 21.598 22.3 1950 4293.7 5.5 1.009 16.6 1953 4299.2 5.0 3.544 19.9 1956 4304.2 1.5 5.023 17.9 1958 4305.7 2.0 0.319 14.9 1959 4307.7 1.5 236.504 28.4 1960 4309.2 11.5 21.887 19.1 1960 4320.7 1.8 50.818 20.1 1966 4322.5 2.1 0.026 15.0 1968 4324.6 8.2 62.684 23.0 1970 4332.8 4.9 4.489 17.4 1970 4337.7 1.5 0.488 15.1 1974 4339.2 2.0 1.982 16.9 1974 4341.2 3.5 0.010 1.0 1975 4344.7 1.5 0.552 15.4 1977 4346.2 1.5 0.010 1.0 1978 4347.7 3.5 3.859 17.2 1978 4351.2 5.0 0.010 1.0 1980 4356.2 2.0 41.288 21.2 1982 4358.2 5.0 0.010 1.0 1983 4363.2 3.5 0.010 1.0 1986 4366.7 1.5 5.111 19.0 1987 4368.2 11.0 0.010 1.0 1988 4379.2 2.0 111.829 24.6 1993 4381.2 1.5 0.010 1.0 1994 4382.7 2.0 102.765 23.1 1995 4384.7 4.0 0.016 15.0 1996 4388.7 5.5 24.191 20.3 1997 4394.2 2.0 33.759 23.4 2000 4396.2 6.0 0.015 14.5 2001 4402.2 21.5 82.778 21.8 2004 4423.7 2.0 0.014 15.0 2014 4425.7 4.0 26.711 20.7 2015 4429.7 2.0 162.436 24.1 2017 4431.7 2.0 0.010 1.0 2018 4433.7 4.0 1.983 16.8 2019 4437.7 4.0 30.725 21.1 2020 4441.7 2.0 0.009 15.0 2022 4443.7 7.5 8.533 20.5 2023 4451.2 9.5 0.010 1.0 2027 4460.7 2.0 15.000 10.0 2096 4462.7 50.0 0.010 1.0 2100 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE SHALE 23 Section 17: Propped Fracture Schedule (Stage 6; 12384 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF125ST 300.0 25 0 1.0 PPA 40 YF125ST 172.4 25 1 2.0 PPA 40 YF125ST 183.8 25 2 4.0 PPA 40 YF125ST 186.9 25 4 6.0 PPA 40 YF125ST 173.9 25 6 8.0 PPA 40 YF125ST 162.5 25 8 10.0 PPA 40 YF125ST 124.8 25 10 Flush 40 YF125ST 187.7 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1491.9 bbl of YF125ST 0 bbl of WF125 204922 lb of % PAD Clean 23.0 % PAD Dirty 19.7 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 3468 7.5 7.5 1.0 PPA 172.4 472 180 480 7240 7240 3478 4.5 12.0 2.0 PPA 183.8 656 200 680 15435 22675 3474 5.0 17.0 4.0 PPA 186.9 843 220 900 31405 54080 3498 5.5 22.5 6.0 PPA 173.9 1017 220 1120 43816 97896 3587 5.5 28.0 8.0 PPA 162.5 1179 220 1340 54605 152501 3735 5.5 33.5 10.0 PPA 124.8 1304 180 1520 52421 204922 3933 4.5 38.0 Flush 187.7 1492 188 1708 0 204922 3966 4.7 42.7 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 411.5 ft with an average conductivity (Kfw) of 10470 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 24 Section 18: Propped Fracture Simulation (Stage 6; 12384 ft MD) Initial Fracture Top TVD 4204 ft Initial Fracture Bottom TVD 4480.6 ft Propped Fracture Half-Length 411.5 ft EOJ Hyd Height at Well 276.5 ft Average Propped Width 0.111 in Net Pressure 232 psi Max Surface Pressure 4131 psi From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 102.9 8.6 0.154 231.3 1.3 214.3 14804 102.9 205.7 6.1 0.138 226.5 1.21 244.5 13051 205.7 308.6 4.4 0.106 216.7 0.98 288 10087 308.6 411.5 1.7 0.053 191.7 0.48 1004.5 5029 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 Section 19: Zone Data (Stage 7; 11565 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 4212.8 41.7 0.70 2965 1.46E+06 0.220 1000 SHALE 4254.5 15.0 0.70 2962 1.76E+06 0.220 1000 SILTSTONE 4269.5 24.1 0.68 2903 1.90E+06 0.220 1000 Top Nan CS 4293.6 7.0 0.62 2654 2.37E+06 0.240 1000 DIRTY-SANDSTONE 4300.6 1.5 0.67 2880 1.50E+06 0.240 1000 SHALE 4302.1 2.0 0.68 2917 2.67E+06 0.230 2500 CLEAN-SANDSTONE 4304.1 10.5 0.61 2622 6.84E+05 0.280 1000 DIRTY-SANDSTONE 4314.6 6.5 0.63 2711 1.02E+06 0.270 1500 DIRTY-SANDSTONE 4321.1 5.5 0.63 2739 1.54E+06 0.260 1500 DIRTY-SANDSTONE 4326.6 5.0 0.61 2662 1.23E+06 0.260 1000 DIRTY-SANDSTONE 4331.6 1.5 0.64 2777 1.41E+06 0.260 1500 DIRTY-SANDSTONE 4333.1 2.0 0.64 2767 1.70E+06 0.260 1500 DIRTY-SANDSTONE 4335.1 1.5 0.59 2576 5.77E+05 0.280 1500 DIRTY-SANDSTONE 4336.6 11.5 0.64 2767 1.31E+06 0.260 1500 DIRTY-SANDSTONE 4348.1 1.8 0.66 2878 1.24E+06 0.270 1500 DIRTY-SANDSTONE 4349.9 2.1 0.67 2929 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4352.0 8.2 0.62 2688 9.65E+05 0.270 1000 DIRTY-SANDSTONE 4360.2 4.9 0.64 2775 1.46E+06 0.260 1500 DIRTY-SANDSTONE 4365.1 1.5 0.66 2890 1.68E+06 0.260 1500 DIRTY-SANDSTONE 4366.6 2.0 0.63 2732 1.51E+06 0.260 1500 SHALE 4368.6 3.5 0.69 3011 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4372.1 1.5 0.64 2814 1.65E+06 0.260 1500 SHALE 4373.6 1.5 0.68 2966 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4375.1 3.5 0.62 2717 1.48E+06 0.260 1500 SHALE 4378.6 5.0 0.68 2971 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4383.6 2.0 0.61 2696 1.12E+06 0.270 1500 SHALE 4385.6 5.0 0.68 2976 2.67E+06 0.230 2500 SHALE 4390.6 3.5 0.68 2979 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4394.1 1.5 0.64 2819 1.31E+06 0.260 1500 SHALE 4395.6 11.0 0.68 2985 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4406.6 2.0 0.62 2737 8.37E+05 0.270 1000 SHALE 4408.6 1.5 0.68 2990 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4410.1 2.0 0.63 2761 9.57E+05 0.270 1000 DIRTY-SANDSTONE 4412.1 4.0 0.68 2984 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4416.1 5.5 0.63 2769 1.20E+06 0.270 1500 DIRTY-SANDSTONE 4421.6 2.0 0.62 2728 9.33E+05 0.270 1000 DIRTY-SANDSTONE 4423.6 6.0 0.68 2992 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4429.6 21.5 0.63 2787 1.08E+06 0.270 1500 DIRTY-SANDSTONE 4451.1 2.0 0.69 3059 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4453.1 4.0 0.64 2842 1.16E+06 0.270 1500 DIRTY-SANDSTONE 4457.1 2.0 0.60 2660 8.76E+05 0.270 1500 SHALE 4459.1 2.0 0.68 3025 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4461.1 4.0 0.63 2828 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4465.1 4.0 0.62 2768 1.12E+06 0.270 1500 DIRTY-SANDSTONE 4469.1 2.0 0.68 3021 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4471.1 7.5 0.63 2824 1.18E+06 0.270 1500 SHALE 4478.6 9.5 0.68 3041 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4488.1 2.0 0.68 3066 1.69E+06 0.260 1500 SHALE 4490.1 50.0 0.68 3085 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 26 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4212.8 41.7 0.010 1.0 1918 4254.5 15.0 0.010 1.0 1923 4269.5 24.1 0.050 10.0 1929 4293.6 7.0 6.009 4.1 1940 4300.6 1.5 0.192 12.0 1944 4302.1 2.0 0.010 1.0 1944 4304.1 10.5 100.314 26.7 1945 4314.6 6.5 21.598 22.3 1950 4321.1 5.5 1.009 16.6 1953 4326.6 5.0 3.544 19.9 1956 4331.6 1.5 5.023 17.9 1958 4333.1 2.0 0.319 14.9 1959 4335.1 1.5 236.504 28.4 1960 4336.6 11.5 21.887 19.1 1960 4348.1 1.8 50.818 20.1 1966 4349.9 2.1 0.026 15.0 1968 4352.0 8.2 62.684 23.0 1970 4360.2 4.9 4.489 17.4 1970 4365.1 1.5 0.488 15.1 1974 4366.6 2.0 1.982 16.9 1974 4368.6 3.5 0.010 1.0 1975 4372.1 1.5 0.552 15.4 1977 4373.6 1.5 0.010 1.0 1978 4375.1 3.5 3.859 17.2 1978 4378.6 5.0 0.010 1.0 1980 4383.6 2.0 41.288 21.2 1982 4385.6 5.0 0.010 1.0 1983 4390.6 3.5 0.010 1.0 1986 4394.1 1.5 5.111 19.0 1987 4395.6 11.0 0.010 1.0 1988 4406.6 2.0 111.829 24.6 1993 4408.6 1.5 0.010 1.0 1994 4410.1 2.0 102.765 23.1 1995 4412.1 4.0 0.016 15.0 1996 4416.1 5.5 24.191 20.3 1997 4421.6 2.0 33.759 23.4 2000 4423.6 6.0 0.015 14.5 2001 4429.6 21.5 82.778 21.8 2004 4451.1 2.0 0.014 15.0 2014 4453.1 4.0 26.711 20.7 2015 4457.1 2.0 162.436 24.1 2017 4459.1 2.0 0.010 1.0 2018 4461.1 4.0 1.983 16.8 2019 4465.1 4.0 30.725 21.1 2020 4469.1 2.0 0.009 15.0 2022 4471.1 7.5 8.533 20.5 2023 4478.6 9.5 0.010 1.0 2027 4488.1 2.0 15.000 10.0 2096 4490.1 50.0 0.010 1.0 2113 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE SHALE 27 Section 20: Propped Fracture Schedule (Stage 7; 11565 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 35 YF125ST 350.0 25 0 1.0 PPA 35 YF125ST 153.2 25 1 2.0 PPA 35 YF125ST 147.0 25 2 3.0 PPA 35 YF125ST 158.9 25 3 4.0 PPA 35 YF125ST 152.9 25 4 5.0 PPA 35 YF125ST 147.4 25 5 6.0 PPA 35 YF125ST 142.3 25 6 7.0 PPA 35 YF125ST 122.2 25 7 8.0 PPA 35 YF125ST 110.8 25 8 Flush 35 YF125ST 175.2 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1659.9 bbl of YF125ST 0 bbl of WF125 204460 lb of % PAD Clean 23.6 % PAD Dirty 20.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 350.0 350 350 350 0 0 2928 10.0 10.0 1.0 PPA 153.2 503 160 510 6435 6435 2934 4.6 14.6 2.0 PPA 147.0 650 160 670 12348 18783 2902 4.6 19.1 3.0 PPA 158.9 809 180 850 20024 38807 2887 5.1 24.3 4.0 PPA 152.9 962 180 1030 25695 64503 2886 5.1 29.4 5.0 PPA 147.4 1110 180 1210 30956 95459 2896 5.1 34.6 6.0 PPA 142.3 1252 180 1390 35849 131308 2918 5.1 39.7 7.0 PPA 122.2 1374 160 1550 35922 167230 2951 4.6 44.3 8.0 PPA 110.8 1485 150 1700 37230 204460 2995 4.3 48.6 Flush 175.2 1660 175 1875 0 204460 3034 5.0 53.6 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 418.9 ft with an average conductivity (Kfw) of 10569.5 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 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 28 Section 21: Propped Fracture Simulation (Stage 7; 11565 ft MD) Initial Fracture Top TVD 4233.3 ft Initial Fracture Bottom TVD 4509.7 ft Propped Fracture Half-Length 418.9 ft EOJ Hyd Height at Well 276.4 ft Average Propped Width 0.112 in Net Pressure 232 psi Max Surface Pressure 3052 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) 0 104.7 7.5 0.135 240.7 1.14 261 13106 104.7 209.4 5.7 0.127 227.3 1.14 293.3 12021 209.4 314.2 4.8 0.11 220.1 0.99 291 10423 314.2 418.9 1.7 0.082 197.4 0.71 1305.4 7777 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 Section 22: Zone Data (Stage 8; 11298 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 4237.3 31.7 0.71 3001 1.46E+06 0.220 1000 SHALE 4269.0 15.0 0.70 2972 1.76E+06 0.220 1000 SILTSTONE 4284.0 24.1 0.68 2913 1.90E+06 0.220 1000 CLEAN-SANDSTONE 4308.1 3.5 0.60 2607 8.57E+05 0.270 1000 SHALE 4311.6 1.5 0.68 2952 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4313.1 1.5 0.63 2713 9.12E+05 0.270 1000 DIRTY-SANDSTONE 4314.6 3.5 0.66 2857 1.15E+06 0.270 1500 CLEAN-SANDSTONE 4318.1 2.0 0.62 2682 7.24E+05 0.280 1000 SHALE 4320.1 1.5 0.68 2958 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4321.6 14.0 0.64 2762 1.55E+06 0.260 1500 SHALE 4335.6 1.5 0.68 2969 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4337.1 3.5 0.62 2681 1.15E+06 0.270 1500 DIRTY-SANDSTONE 4340.6 1.5 0.68 2959 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4342.1 2.0 0.61 2636 8.10E+05 0.270 1000 DIRTY-SANDSTONE 4344.1 5.0 0.66 2868 1.28E+06 0.260 1500 DIRTY-SANDSTONE 4349.1 10.0 0.62 2717 1.50E+06 0.260 1500 DIRTY-SANDSTONE 4359.1 10.0 0.65 2847 8.70E+05 0.270 1500 DIRTY-SANDSTONE 4369.1 5.0 0.62 2709 1.22E+06 0.270 1500 DIRTY-SANDSTONE 4374.1 8.5 0.68 2987 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4382.6 3.5 0.62 2722 1.47E+06 0.260 1500 SHALE 4386.1 2.5 0.68 3004 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4388.6 1.0 0.64 2830 1.61E+06 0.260 1500 SHALE 4389.6 7.0 0.68 3008 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4396.6 3.5 0.64 2811 9.39E+05 0.270 1000 DIRTY-SANDSTONE 4400.1 4.5 0.68 3014 1.56E+06 0.260 1500 DIRTY-SANDSTONE 4404.6 2.0 0.63 2791 1.35E+06 0.260 1500 DIRTY-SANDSTONE 4406.6 2.0 0.68 3008 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4408.6 5.5 0.62 2730 9.70E+05 0.270 1500 DIRTY-SANDSTONE 4414.1 6.0 0.68 3018 1.65E+06 0.260 1500 DIRTY-SANDSTONE 4420.1 10.0 0.65 2876 1.24E+06 0.260 1500 DIRTY-SANDSTONE 4430.1 2.0 0.65 2869 1.50E+06 0.260 1500 DIRTY-SANDSTONE 4432.1 7.5 0.63 2795 9.80E+05 0.270 1500 DIRTY-SANDSTONE 4439.6 1.5 0.68 3029 1.87E+06 0.250 1500 DIRTY-SANDSTONE 4441.1 3.0 0.61 2706 9.11E+05 0.270 1500 DIRTY-SANDSTONE 4444.1 5.0 0.64 2830 1.76E+06 0.260 1500 SHALE 4449.1 6.0 0.69 3067 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4455.1 2.0 0.65 2903 1.72E+06 0.260 1500 SHALE 4457.1 23.0 0.68 3060 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4480.1 2.0 0.63 2817 1.24E+06 0.260 1500 SHALE 4482.1 2.0 0.68 3070 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4484.1 2.0 0.66 2969 1.68E+06 0.260 1500 SHALE 4486.1 4.5 0.69 3092 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4490.6 10.0 0.63 2850 1.28E+06 0.260 1500 SHALE 4500.6 10.5 0.69 3105 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4511.1 2.0 0.65 2926 1.40E+06 0.260 1500 SHALE 4513.1 19.0 0.68 3097 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4532.1 2.0 0.64 2897 1.44E+06 0.260 1500 SHALE 4534.1 25.0 0.68 3114 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 30 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4237.3 31.7 0.010 1.0 1919 4269.0 15.0 0.010 1.0 1929 4284.0 24.1 0.050 10.0 1936 4308.1 3.5 48.343 24.3 1947 4311.6 1.5 0.006 10.0 1949 4313.1 1.5 39.757 23.6 1949 4314.6 3.5 6.288 20.8 1950 4318.1 2.0 71.711 26.2 1952 4320.1 1.5 0.006 10.0 1952 4321.6 14.0 56.440 16.7 1953 4335.6 1.5 0.006 10.0 1960 4337.1 3.5 18.893 20.8 1960 4340.6 1.5 0.023 15.0 1962 4342.1 2.0 115.609 24.9 1963 4344.1 5.0 20.857 19.5 1964 4349.1 10.0 1.968 17.0 1966 4359.1 10.0 74.766 24.2 1971 4369.1 5.0 11.675 20.1 1975 4374.1 8.5 7.321 16.9 1978 4382.6 3.5 3.784 17.3 1982 4386.1 2.5 0.006 10.0 1983 4388.6 1.0 1.340 15.9 1984 4389.6 7.0 0.006 10.0 1985 4396.6 3.5 40.985 23.3 1988 4400.1 4.5 1.316 14.2 1990 4404.6 2.0 4.219 18.6 1992 4406.6 2.0 0.015 14.6 1993 4408.6 5.5 61.197 22.9 1994 4414.1 6.0 0.552 13.9 1996 4420.1 10.0 28.233 19.9 1999 4430.1 2.0 1.534 17.0 2004 4432.1 7.5 79.135 22.8 2005 4439.6 1.5 0.006 10.0 2008 4441.1 3.0 120.250 23.7 2009 4444.1 5.0 0.329 14.3 2010 4449.1 6.0 0.006 10.0 2013 4455.1 2.0 0.136 14.8 2015 4457.1 23.0 0.006 10.0 2016 4480.1 2.0 15.982 19.8 2027 4482.1 2.0 0.006 10.0 2028 4484.1 2.0 0.344 15.1 2029 4486.1 4.5 0.006 10.0 2030 4490.6 10.0 6.547 19.3 2032 4500.6 10.5 0.006 10.0 2036 4511.1 2.0 1.897 18.0 2041 4513.1 19.0 0.006 10.0 2042 4532.1 2.0 4.758 17.7 2051 4534.1 25.0 0.006 10.0 2052 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SILTSTONE CLEAN-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE CLEAN-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE 31 Section 23: Propped Fracture Schedule (Stage 8; 11298 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 30 YF125ST 350.0 25 0 1.0 PPA 30 YF125ST 143.6 25 1 2.0 PPA 30 YF125ST 137.8 25 2 3.0 PPA 30 YF125ST 141.3 25 3 4.0 PPA 30 YF125ST 136.0 25 4 5.0 PPA 30 YF125ST 131.0 25 5 6.0 PPA 30 YF125ST 126.5 25 6 7.0 PPA 30 YF125ST 106.9 25 7 8.0 PPA 30 YF125ST 92.3 25 8 Flush 30 YF125ST 171.1 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1536.5 bbl of YF125ST 0 bbl of WF125 180088 lb of % PAD Clean 25.6 % PAD Dirty 22.5 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 350.0 350 350 350 0 0 2567 11.7 11.7 1.0 PPA 143.6 494 150 500 6033 6033 2551 5.0 16.7 2.0 PPA 137.8 631 150 650 11576 17610 2513 5.0 21.7 3.0 PPA 141.3 773 160 810 17799 35408 2483 5.3 27.0 4.0 PPA 136.0 909 160 970 22840 58249 2461 5.3 32.3 5.0 PPA 131.0 1040 160 1130 27517 85765 2447 5.3 37.7 6.0 PPA 126.5 1166 160 1290 31866 117631 2445 5.3 43.0 7.0 PPA 106.9 1273 140 1430 31431 149063 2454 4.7 47.7 8.0 PPA 92.3 1365 125 1555 31025 180088 2473 4.2 51.8 Flush 171.1 1537 171 1726 0 180088 2547 5.7 57.5 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 367 ft with an average conductivity (Kfw) of 11221.6 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 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 32 Section 24: Propped Fracture Simulation (Stage 8; 11298 ft MD) Initial Fracture Top TVD 4246.2 ft Initial Fracture Bottom TVD 4518.1 ft Propped Fracture Half-Length 367 ft EOJ Hyd Height at Well 271.9 ft Average Propped Width 0.118 in Net Pressure 182 psi Max Surface Pressure 2627 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 91.7 6.8 0.131 218.7 1.01 271.9 12732 91.7 183.5 5.3 0.132 224.8 1.07 287.1 12563 183.5 275.2 4.7 0.136 188.9 1.17 297.9 12863 275.2 367 1.7 0.079 164.6 0.74 965.2 7486 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 Section 25: Zone Data (Stage 9; 10757 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 4266.9 31.7 0.70 3001 1.46E+06 0.220 1000 SHALE 4298.6 15.0 0.70 2993 1.76E+06 0.220 1000 SILTSTONE 4313.6 24.1 0.68 2933 1.90E+06 0.220 1000 CLEAN-SANDSTONE 4337.7 3.5 0.60 2607 8.57E+05 0.270 1000 SHALE 4341.2 1.5 0.68 2952 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4342.7 1.5 0.63 2732 9.12E+05 0.270 1000 DIRTY-SANDSTONE 4344.2 3.5 0.66 2877 1.15E+06 0.270 1500 CLEAN-SANDSTONE 4347.7 2.0 0.62 2701 7.24E+05 0.280 1000 SHALE 4349.7 1.5 0.68 2958 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4351.2 14.0 0.64 2781 1.55E+06 0.260 1500 SHALE 4365.2 1.5 0.68 2969 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4366.7 3.5 0.62 2700 1.15E+06 0.270 1500 DIRTY-SANDSTONE 4370.2 1.5 0.68 2959 1.69E+06 0.260 1500 DIRTY-SANDSTONE 4371.7 2.0 0.61 2654 8.10E+05 0.270 1000 DIRTY-SANDSTONE 4373.7 5.0 0.66 2868 1.28E+06 0.260 1500 DIRTY-SANDSTONE 4378.7 10.0 0.62 2717 1.50E+06 0.260 1500 DIRTY-SANDSTONE 4388.7 10.0 0.65 2847 8.70E+05 0.270 1500 DIRTY-SANDSTONE 4398.7 5.0 0.62 2709 1.22E+06 0.270 1500 DIRTY-SANDSTONE 4403.7 8.5 0.68 2987 1.52E+06 0.260 1500 DIRTY-SANDSTONE 4412.2 3.5 0.62 2722 1.47E+06 0.260 1500 SHALE 4415.7 2.5 0.68 3004 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4418.2 1.0 0.64 2830 1.61E+06 0.260 1500 SHALE 4419.2 7.0 0.68 3008 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4426.2 3.5 0.64 2829 9.39E+05 0.270 1000 DIRTY-SANDSTONE 4429.7 4.5 0.68 3014 1.56E+06 0.260 1500 DIRTY-SANDSTONE 4434.2 2.0 0.63 2791 1.35E+06 0.260 1500 DIRTY-SANDSTONE 4436.2 2.0 0.68 3008 1.74E+06 0.260 1500 DIRTY-SANDSTONE 4438.2 5.5 0.61 2730 9.70E+05 0.270 1500 DIRTY-SANDSTONE 4443.7 6.0 0.68 3018 1.65E+06 0.260 1500 DIRTY-SANDSTONE 4449.7 10.0 0.65 2896 1.24E+06 0.260 1500 DIRTY-SANDSTONE 4459.7 2.0 0.64 2869 1.50E+06 0.260 1500 DIRTY-SANDSTONE 4461.7 7.5 0.63 2813 9.80E+05 0.270 1500 DIRTY-SANDSTONE 4469.2 1.5 0.68 3029 1.87E+06 0.250 1500 DIRTY-SANDSTONE 4470.7 3.0 0.61 2706 9.11E+05 0.270 1500 DIRTY-SANDSTONE 4473.7 5.0 0.63 2830 1.76E+06 0.260 1500 SHALE 4478.7 6.0 0.69 3088 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4484.7 2.0 0.65 2903 1.72E+06 0.260 1500 SHALE 4486.7 23.0 0.68 3060 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4509.7 2.0 0.62 2817 1.24E+06 0.260 1500 SHALE 4511.7 2.0 0.68 3070 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4513.7 2.0 0.66 2989 1.68E+06 0.260 1500 SHALE 4515.7 4.5 0.69 3113 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4520.2 10.0 0.63 2869 1.28E+06 0.260 1500 SHALE 4530.2 10.5 0.69 3125 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4540.7 2.0 0.64 2926 1.40E+06 0.260 1500 SHALE 4542.7 19.0 0.68 3097 2.67E+06 0.230 2500 DIRTY-SANDSTONE 4561.7 2.0 0.64 2916 1.44E+06 0.260 1500 SHALE 4563.7 25.0 0.68 3114 2.67E+06 0.230 2500 Formation Mechanical Properties Zone Name Poisson’ s Ratio 34 Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4266.9 31.7 0.010 1.0 1919 4298.6 15.0 0.010 1.0 1929 4313.6 24.1 0.050 10.0 1936 4337.7 3.5 48.343 24.3 1947 4341.2 1.5 0.006 10.0 1949 4342.7 1.5 39.757 23.6 1949 4344.2 3.5 6.288 20.8 1950 4347.7 2.0 71.711 26.2 1952 4349.7 1.5 0.006 10.0 1952 4351.2 14.0 56.440 16.7 1953 4365.2 1.5 0.006 10.0 1960 4366.7 3.5 18.893 20.8 1960 4370.2 1.5 0.023 15.0 1962 4371.7 2.0 115.609 24.9 1963 4373.7 5.0 20.857 19.5 1964 4378.7 10.0 1.968 17.0 1966 4388.7 10.0 74.766 24.2 1971 4398.7 5.0 11.675 20.1 1975 4403.7 8.5 7.321 16.9 1978 4412.2 3.5 3.784 17.3 1982 4415.7 2.5 0.006 10.0 1983 4418.2 1.0 1.340 15.9 1984 4419.2 7.0 0.006 10.0 1985 4426.2 3.5 40.985 23.3 1988 4429.7 4.5 1.316 14.2 1990 4434.2 2.0 4.219 18.6 1992 4436.2 2.0 0.015 14.6 1993 4438.2 5.5 61.197 22.9 1994 4443.7 6.0 0.552 13.9 1996 4449.7 10.0 28.233 19.9 1999 4459.7 2.0 1.534 17.0 2004 4461.7 7.5 79.135 22.8 2005 4469.2 1.5 0.006 10.0 2008 4470.7 3.0 120.250 23.7 2009 4473.7 5.0 0.329 14.3 2010 4478.7 6.0 0.006 10.0 2013 4484.7 2.0 0.136 14.8 2015 4486.7 23.0 0.006 10.0 2016 4509.7 2.0 15.982 19.8 2027 4511.7 2.0 0.006 10.0 2028 4513.7 2.0 0.344 15.1 2029 4515.7 4.5 0.006 10.0 2030 4520.2 10.0 6.547 19.3 2032 4530.2 10.5 0.006 10.0 2036 4540.7 2.0 1.897 18.0 2041 4542.7 19.0 0.006 10.0 2042 4561.7 2.0 4.758 17.7 2051 4563.7 25.0 0.006 10.0 2052 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SILTSTONE CLEAN-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE CLEAN-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE 35 Section 26: Propped Fracture Schedule (Stage 9; 10757 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 30 YF125 ST 350.0 25 0 1.0 PPA 30 YF125 ST 143.6 25 1 2.0 PPA 30 YF125 ST 137.8 25 2 3.0 PPA 30 YF125 ST 141.3 25 3 4.0 PPA 30 YF125 ST 136.0 25 4 5.0 PPA 30 YF125 ST 131.0 25 5 6.0 PPA 30 YF125 ST 126.5 25 6 7.0 PPA 30 YF125 ST 106.9 25 7 8.0 PPA 30 YF125 ST 92.3 25 8 Flush 30 YF125 ST 162.9 25 0 Please note that this pumping schedule is under-displaced by 1.0 bbl. 1528.3 bbl of YF125 ST 0 bbl of WF125 180088 lb of % PAD Clean 25.6 % PAD Dirty 22.5 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 350.0 350 350 350 0 0 2528 11.7 11.7 1.0 PPA 143.6 494 150 500 6033 6033 2514 5.0 16.7 2.0 PPA 137.8 631 150 650 11576 17610 2476 5.0 21.7 3.0 PPA 141.3 773 160 810 17799 35408 2441 5.3 27.0 4.0 PPA 136.0 909 160 970 22840 58249 2411 5.3 32.3 5.0 PPA 131.0 1040 160 1130 27517 85765 2391 5.3 37.7 6.0 PPA 126.5 1166 160 1290 31866 117631 2383 5.3 43.0 7.0 PPA 106.9 1273 140 1430 31431 149063 2386 4.7 47.7 8.0 PPA 92.3 1365 125 1555 31025 180088 2403 4.2 51.8 Flush 162.9 1528 163 1718 0 180088 2461 5.4 57.3 Carbolite 16/20 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 336.4 ft with an average conductivity (Kfw) of 10917.6 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 Carbolite 16/20 Carbolite 16/20 Fluid Totals Proppant Totals Carbolite 16/20 Job Execution Step Name 36 Section 27: Propped Fracture Simulation (Stage 9; 10757 ft MD) Initial Fracture Top TVD 4268 ft Initial Fracture Bottom TVD 4556.6 ft Propped Fracture Half-Length 336.4 ft EOJ Hyd Height at Well 288.6 ft Average Propped Width 0.115 in Net Pressure 88 psi Max Surface Pressure 2535 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 84.1 7.2 0.135 172.7 1.13 258 13216 84.1 168.2 5.6 0.131 220 1.11 286.7 12473 168.2 252.3 4.6 0.121 187.2 1.05 311.5 11509 252.3 336.4 1.5 0.08 133.4 0.76 475.8 7604 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 Santos USA and Baker Hughes Confidential Page 1 © 2018 Baker Hughes, LLC - All rights reserved. LLWD Qualitative Cement Bond Log Evaluation Report Well Name, Section: NDBi-014, 9 5/8” Liner Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: Reservoir Technical Services Alaska Version: Preliminary Report Santos USA and Baker Hughes Confidential Page 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Tool Diagram ..........................................................................................................................................................................................................8 Methodology of LWD Cement Bond Log Evaluation .................................................................................................................9 Log Screen Captures ...................................................................................................................................................................................... 14 Santos USA and Baker Hughes Confidential Page 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMER THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. Santos USA and Baker Hughes Confidential Page 4 Executive Summary Cement Bond Logging with LWD Acoustic (Sonic) tool SoundTrak was performed after drilling of 8 ½” section. Logs were acquired while pulling out of hole across 9 5/8” liner in upward direction. The objective and plan was to cover with CBL logs to evaluate 2-stage cementing which took place earlier prior to drilling of 8 ½” open hole. Cement Bond Index (BI) curve was computed and presented in the log plot showing color gradation from good cement bond (brown) to poor cement (blue). The following values were used by interpreter to differentiate intervals of good bond (curve value above 0.8) to partial (0.2 to 0.8) and poor (lower than 0.2). Summaries of initial pre-job logging plan and Cement Bond Index interpretation are outlined below. Logging Plan Summary Down link to the SoundTrak tool after drilling of 8 ½” open hole and upon coming to the liner shoe at 10,440 ft 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 550-600 gpm and 60-120 rpm (per Baker Hughes recommendation). Limit pulling speed to recommendations below. Required logging intervals are below. x Log cement from 9-5/8” shoe (10,440’ MD) to 6,820’ MD which will be to the top of the planned 1st stage TOC at 1200 fph. x Log free pipe from 6,820’ to 6,220’ MD (600’ of free pipe) at 1200 fph. x Backream from 6,220’ MD to 5,240’ MD at 3000 fph. x Log cement from 100’ below Archer C-flex located at 5,140’ MD (log from 5,240’ MD) to 9- 5/8” liner top (2375’ MD) at 1200 fph. x On the last stand while logging cement at the liner top, adjust pulling speed to CBU x 1 during that stand. LWD logging was optimized to gain higher efficiency and reduce overall rig time by modifying acquisition parameters and logging at 1200 ft/hr across critical depth intervals presented below and was increased to 3000 ft/hr or higher everywhere else. Summary of logging intervals and logging speeds are as follows: Santos USA and Baker Hughes Confidential Page 5 Interpretation Summary Note that 13 3/8” casing shoe was set at 2564 ft MD and thus from 2564 ft MD upwards double casing is present. Interval of double casing was not taken into account during data interpretation, as the interpretation workflow is only designed for single casing string. Interpretation has been limited to 2578.5 ft as a top depth. 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. - 2578.5 to 3215.5 Partial to Good Cement. Mostly partial with intervals in the very top with good cement presence. - 3215.5 to 3640.5 Poor Cement presence, with some intervals of partial cement presence. - 3640.t to 5152.2 Partial to Good. Mostly partial, with the intervals in the middle of this zone appearing with good cement presence. - 5152.2 to 7738.8 Poor Cement presence. Note that in the interval from 5240 ft to 6220 ft MD logging speed was 3000 ft/hr. - 7738.8 to 10429.4 Partial to Good. Appears to be almost equal in the number of zones with good cement and partial cement presence. 2 short intervals where cement presence gets poor – in the middle of the zone and towards the shoe. For more detailed description of each interval please refer to two tables below summarizing Interpretation results. Santos USA and Baker Hughes Confidential Page 6 Santos USA and Baker Hughes Confidential Page 7 Santos USA and Baker Hughes Confidential Page 8 Tool Diagram Figure 1: Tool Diagram during actual run Santos USA and Baker Hughes Confidential Page 9 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 2: Traditional Wireline CBL technique Santos USA and Baker Hughes Confidential Page 10 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 3: CBL concept in "free" pipe Figure 4: CBL concept in cemented pipe Santos USA and Baker Hughes Confidential Page 11 Figure 5: General CBL concept and corresponding log example Figure 6: LWD Acoustic (Sonic) tool and LWD CBL concept Current traditional offering of LWD Acoustic (Sonic) tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling trip typically on the way out of casing after drilling is completed. Santos USA and Baker Hughes Confidential Page 12 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 7: Cement Bond Index computation concept Traditionally as part of the CBL logging deliverable, Bond Index (BI) is computed and displayed in the log. Values above 80% BI are typically seen as “good" cement, whereas values below 80% are typically seen as either "poor," contaminated or channeled cement. Note however, that the TR spacing (10.66 ft) for LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality check must be carried out to validate the data, because If the casing amplitude in these well bonded intervals is below noise level, the 100% bonded reference point might be incorrect and the “BI” could be over-estimated, reducing quantitative precision of the measurement. Additionally, Cement Evaluation with LWD SoundTrak tool would be ideal in standard cements with slurry density of equal or greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. For example, detection of behind casing open hole DT from waveforms could confirm that proper cement is present. Santos USA and Baker Hughes Confidential Page 13 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 8: LWD capability of Real-Time Top of Cement acquisition This method has limitations though as it has no azimuthal coverage and can not identify micro channeling. It is not a replacement for quantitative cement evaluation tools such as SBT, InTex, or CICM Santos USA and Baker Hughes Confidential Page 14 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 9: Interval 1 of LWD CBL logging General Interpretation Comments: 2578.5 to 3215.5 Partial to Good Cement. Mostly partial with intervals in the very top with good cement presence. Santos USA and Baker Hughes Confidential Page 15 Figure 10: Interval 2 of LWD CBL Logging General Interpretation Comments: 2578.5 to 3215.5 Partial to Good Cement. Mostly partial with intervals in the very top with good cement presence. 3215.5 to 3640.5 Poor Cement presence, with some intervals of partial cement presence. 3640.t to 5152.2 Partial to Good. Mostly partial, with the intervals in the middle of this zone appearing with good cement presence. Santos USA and Baker Hughes Confidential Page 16 Figure 11: Interval 3 of LWD CBL Logging General Interpretation Comments: 3640.t to 5152.2 Partial to Good. Mostly partial, with the intervals in the middle of this zone appearing with good cement presence. 5152.2 to 7738.8 Poor Cement presence. Note that in the interval from 5240 ft to 6220 ft MD logging speed was 3000 ft/hr. Santos USA and Baker Hughes Confidential Page 17 Figure 12: Interval 4 of LWD CBL Logging General Interpretation Comments: 5152.2 to 7738.8 Poor Cement presence. Note that in the interval from 5240 ft to 6220 ft MD logging speed was 3000 ft/hr. Santos USA and Baker Hughes Confidential Page 18 Figure 13: Interval 5 of LWD CBL Logging General Interpretation Comments: 5152.2 to 7738.8 Poor Cement presence. Note that in the interval from 5240 ft to 6220 ft MD logging speed was 3000 ft/hr. Santos USA and Baker Hughes Confidential Page 19 Figure 14: Interval 6 of LWD CBL Logging General Interpretation Comments: 5152.2 to 7738.8 Poor Cement presence. Note that in the interval from 5240 ft to 6220 ft MD logging speed was 3000 ft/hr. 7738.8 to 10429.4 Partial to Good. Appears to be almost equal in the number of zones with good cement and partial cement presence. 2 short intervals where cement presence gets poor – in the middle of the zone and towards the shoe. Santos USA and Baker Hughes Confidential Page 20 Figure 15: Interval 7 of LWD CBL Logging General Interpretation Comments: 7738.8 to 10429.4 Partial to Good. Appears to be almost equal in the number of zones with good cement and partial cement presence. 2 short intervals where cement presence gets poor – in the middle of the zone and towards the shoe. Santos USA and Baker Hughes Confidential Page 21 Figure 16: Interval 8 of LWD CBL Logging General Interpretation Comments: 7738.8 to 10429.4 Partial to Good. Appears to be almost equal in the number of zones with good cement and partial cement presence. 2 short intervals where cement presence gets poor – in the middle of the zone and towards the shoe. 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 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 2/ 1 5 / 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 2/ 1 5 / 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 , 9 , 8 , 5 , a n d 6 of T 1 1 N , R 0 6 E , U M . SF D 2/ 1 5 / 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 F e b . 15 , 20 24 ), 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 pu r p o s e s a r 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 lo c a t i o n o f N D B - 0 1 4 . Th 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 te m p o r a r y s u 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 1 4 . SF D 2/ 1 5 / 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 . T h e r e a r 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 1 4 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 , Q u g r u k 3 A , Q u g r u k 30 1 , a n d N D B - 0 4 4 . SF D 2/ 2 3 /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 . 2 1 , 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 hy 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 We l l H i s t o r y F i l e 2 2 3 - 0 7 6 , p . 1 0 1 - 10 7 o f S un d r y A p p l i c a t i o n 32 3 - 5 9 1 ) . P i c k e t t P l 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 th r e e w e l l s w i t h i n t h 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 t h 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 , Ti l l 1 , a n d P i k k a D W -0 2 . E s t i m a t e d s al 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 pe r m a f r o s t l a y e r i n t h 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 be 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 - 0 0 4 ) 16 , 7 0 0 t o ~ 2 3 , 0 0 0 m g / l SF D 2/ 1 5 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 2 4 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 ( - 1 , 3 0 5 ’ T V D S S ) ) ; a n d DW - 02 ( 2 2 3 - 0 3 9 ) ~ 2 1 , 5 0 0 m g / l be 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 : No 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 . SF D 2/ 1 5 / 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 g e n e r a t e d t o d a t e . CD W 02 / 2 1 / 2 0 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 ” s u r f a c e c e m e n t j o b s h o w s c e m e n t t o s u r f a c e . F I T / L O T t o 1 6 . 9 6 p p g . Tw o s t a g e c e m e n t j o b i n 9- 5 / 8 ” . 1 s t s t a g e , l o s s e s . ( 7 5 b b l ) . CB L s h o w s T O C 77 3 9 f t . 2nd s t a g e : ( 1 6 b b l l o s t ) l i n e r t o p c i r c u l a t e d wi t h c e m e n t re t u r n s t o s u r f a c e . S t a g e t o o l o f 5 1 4 0 f t a n d T O C C B L (B a k e r So u n d T r a k L W D ) sh o w s p a r t i a l t o g o o d c e m e n t ( 2 5 7 9 - 32 1 6 , an d 3 6 4 1 -5 1 5 2 ) a n d p o o r c e m e n t e l s e w h e r e … 4. 5 ” l i n e r s w e l l p a c k e r c o m p l e t i o n . CD W 02 / 2 1 / 2 0 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 2/ 1 5 / 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 Ye s : Su r f a c e c a s i n g w a s s e t a t 2 , 5 6 4 ’ M D ( - 2 , 2 2 3 ’ T V D S S ) a n d ce m e n t e d w i t h 10 4 b a r r e l s o f c e m e n t r e t u r n s a t s u r f a c e . Fo r N D B - 0 1 4 , 1 2 . 5 ” h o l e w a s d r i l l e d t o 1 0 , 4 4 0 ’ M D ( - 4, 3 0 0 ’ TV D S S ) , a n d 1 3 - 3 / 8 ” w a s s e t 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 2 7 0 b a r r e l s ( 1 2 2 5 s a c k s , 1 . 2 3 7 y i e l d ) o f V e r s a c e m T y p e I / I I 1 5 . 3 p p g w i t h 7 5 b a r r e l s o f l o s s e s . B o t h SF D 2/ 2 1 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 2 4 pl u g s b u m p e d . B a k e r - H u g h e s C B L i n t e r p r e t a t i o n p l a c e s t h e to p o f g o o d - q u a l i t y c e m e n t a t a b o u t 7 , 7 3 9 ’ M D ’ M D ( - 3, 8 1 4 ’ TV D S S ) . S o , c e m e n t i s o l a t e s t h e fr a c t u r i n g i n t e r v a l f r o m a n y ov e r l y i n g hy d r o c a r b o n z o n e s . S t a g e 2 p u m p e d 30 5 b a r r e l s o f Ve r s a c e m Ty p e I / I I 1 5 . 3 p p g ( 13 8 5 s a c k s , 1 . 2 3 7 y i e l d ) w i t h a n e s t i m a t e d 1 0 4 b a r r e l s o f c e m e n t r e t u r n s t o s u r f a c e . Ba k e r - Hu g h e s C B L i n t e r p r e t a t i o n re p o r t s m o s t l y g o o d - qu a l i t y t o p a r t i a l c e m e n t a c r o s s t h i s s t a g e i n t e r v a l , w i t h 1 0 0 ’ M D o f go o d -q u a l i t y c e m e n t i m m e d i a t e l y be n e a t h t h e s u r f a c e ca s i n g s h o e , s o t h e T u l u v a k in t e r v a l i s c e m e n t - is o l a t e d f r o m th e f r a c t u r i n g i n t e r v a l a n d t h e s u r f a c e c a s i n g s h o e . SF D 2/ 2 1 / 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 -t e s t p l a n s f o r c a s i n g a n d tu b i n g in s t a l l e d i n w e l l P r 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 , 40 0 0 a n d 60 0 0 p s i M I T T p l a n . CD W 02 / 2 1 / 2 0 2 4 (a ) (8 ) P r 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 P r 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 . f r a c . Pr 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 8 3 00 p s i li n e s t e s t 9 0 0 0 p s i . CD W 02 / 2 1 / 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 th e U p 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 gr 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 ) . 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 65 0’ 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 s i l t s t o n e a n d s h a l e t h a t is ab 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 2/ 2 1 / 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 Pr o v i d e d w i t h a p p l i c a t i o n . CD W 02 / 2 1 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 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 1 4 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 ( Qu g r u k 3 , Q u g r u k 3 A , Q u g r u k 30 1 , a n d N D B - 0 4 4 ) wi 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 f r a c fl u i d s . Qu g r u k 3 : Su r f a c e c a s i n g ( 1 3 - 3 / 8 ” ) s e t a t 2 , 1 2 0 ’ M D ( - 2, 0 7 4 ’ TV D S S ) a n d c e m e n t e d t o s u r f a c e w i t h 5 3 b a r r e l s o f c e m e n t re t u r n s t o s u r f a c e . W e l l d r i l l e d t o N u i q s u t t h e n p l u g g e d b a c k wi t h p l u g s s e t an d th e n t a g g e d a c r o s s t h e N u i q s u t a n d Al p i n e , N a n u s h u k , a n d T u l u v a k . I n t h i s w e l l , t h e N a n u s h u k 3 re s e r v o i r s a n d e x t e n d s f r o m 4 , 1 8 8 ’ t o 4 , 4 3 5 ’ M D ( - 4, 0 6 5 ’ t o -4 , 29 7 ’ T V D S S ) . T h e c e m e n t p l u g th a t i s o l a t e s t h i s r e s e r v o i r is s e t f r o m 3 , 5 0 2 ’ t o 4, 5 8 1 ’ M D ( - 3 , 4 1 7 ’ t o - 4 , 2 9 7 TV D S S ) . Th is w e l l i s p l u g g e d a n d a b a n d o n e d . (A d d i t i o n a l pl u g g i n g de t a i l s a r e p r o v i d e d w i t h i n O p e r a t o r ’ s a p p l i c a t i o n .) Qu g r u k 3 A : Ki c k e d o f f f r o m Q u g r u k 3 a t 2 , 7 0 8 ’ M D ( - 2, 6 6 0 ’ TV D S S ) a n d d r i l l e d a g a i n t o N u i q s u t . P l u g 1 i s se t a c r o s s N u i q s u t , A l p i n e , K u p C ( e s t i m a t e d c e m e n t t o p a t 8 , 0 0 3 ’ M D , - 5 8 1 2 ’ T V D S S ) an d P l u g 2 i s s e t f r o m 4 , 1 7 7 ’ t o 4 , 9 5 0 ’ M D (- 3, 9 1 3 ’ t o - 4 , 2 8 2 ’ T V D S S ) a c r o s s t h e N a n u s h u k 3 re s e r v o i r sa n d ( 4 , 4 8 9 ’ t o 4 , 6 8 4 ’ M D , o r - 4 , 0 5 0 ’ t o - 4 , 1 5 0 ’ T V D S S ) . Th i s we l l i s p l u g g e d a n d a b a n d o n e d (p l u g g i n g d e t a i l s a r e pr o v i d e d w i t h i n O p e r a t o r ’ s a p p l i c a t i o n ) . Qu g r u k 3 0 1 : S u 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, 07 0 ’ T V D S S ) a n d c e m e n t e d t o s u r f a c e w i t h 6 0 bb l s o f ce m e n t r e t u r n s a t s u r f a c e ; r e t u r n s w e r e t h e n th e n l o s t a n d ce m e n t f e l l b a c k t o 4 0 ’ M D . T o p j o b wa s pe r f o r m e d w i t h 3 . 4 bb l s of ce m e n t r e t u r n s a t 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 ” ) s e t a t 5 , 3 2 5 ’ M D ( - 4 , 1 4 7 ’ T V D S S ) an d c e m e n t e d i n t w o st a g e s . S t a g e 1 p u m p e d 8 9 b b l s o f C l a s s G 1 4 . 0 p p g w i t h a n SF D 2/ 2 3 /2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 2 4 SF D - ca l c u l a t e d t o p a t 4 , 0 3 2 ’ M D ( - 3 , 7 7 1 ’ T V D S S ; a s s u m i n g 30 % h o l e w a s h o u t ) , w h i c h i s o l a t e s t h e N a n u s h u k 3 r e s e r vo i r sa 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 ’ T V D S S ) a n d ce 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 a n d f u l l re t u r n s . Th e S F D - e s t i m 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 (- 39 2 ’ T V D S S ) , w h i c h i s o l a t e s t h e T u l u v a k , S c h r a d e r B l u f f a n d We s t S a k s t r a t a . Th i s w e l l i s p l u g g e d a n d a b a n d o n e d ( p l u g g i n g d e t a i l s a r e p r o v i d e d w i t h i n O p e r a t o r ’ s ap p l i c a t i o n ) . ND B - 0 4 4 : S u 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 1 4 ’ M D (- 2, 2 3 3 ’ T V D S S ) a n d c e m e n t e d . I n t e r m e d i a t e h o l e w a s dr i l l e d t h r o u g h t h e T u l u v a k I n t e r v a l ( U p p e r T u l u v a k f r o m 2, 8 7 0 ’ t o 4 , 1 7 6 ’ M D , o r - 2 , 4 4 0 ’ t o - 2, 7 5 2 ’ T V D S S ) . In t e r m e d i a t e c as i n g ( 9 - 5 / 8 ” ) w a s s e t a t 1 1 , 1 1 4 ’ M D ( - 4, 0 8 5 ’ TV 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 . F i r s t s t a g e s a w n o re t u r n s w h i l e d i s p l a c i n g c e m e n t . A c e m e n t r e t a i n e r w a s r u n an d s e t a t 1 1 , 0 1 0 ’ M D ( - 4 , 0 2 0 ’ T V D S S ) an d a s e c o n d c e m e n t jo b w a s p u m p e d t h r o u g h t h e s h o e . T h e s e c o n d s t a g e t o o l w a s s e t a t 4 , 1 5 8 ’ M D ( -2, 7 4 9 ’ T V D S S ) a t t h e b a s e o f t h e Up p e r T u l u v a k . Ne x t , 21 4 b b l s o f V e r s a c e m 1 5 . 3 c e m e n t w e r e p u m p e d , o f w h i c h 1 2 9 b a r r e l s w e r e l o s t w h i l e di s p l a c i n g . F o l l o w i n g c e m e n t i n g , a H a l i b u r t o n C A S T t o o l w a s ru n b e n e a t h t h e t o p o f t h e N a n u s h u k i n t e r v a l ( a t 9 , 9 4 0 ’ M D , - 3 , 7 8 5 ’ T V D S S ) b u t a b o v e t h e Na n u s h u k 3 r e s e r v o i r ( 11 , 1 8 0 ’ to 12 , 3 6 4 ’ M D , - 4 , 0 5 3 ’ t o - 4 , 0 9 6 ’ TV D S S ) . A c c o r d i n g t o Ha l i b u r t o n ’ s ce m e n t e v a l u a t i o n r e p o r t d a t e d 1 2 / 3 / 2 0 2 3 , th e r e i s n o g o o d q u a l i t y c e m e n t w i t h i n e i t h e r o f t h e t w o in t e r m e d i a t e c e m e n t s t a g e s . I n t h a t r e p o r t , f a i r - qu a l i t y ce m e n t i s i n d i c a t e d b y a c e m e n t b o n d i n d e x b e t w e e n 5 0 % SF D 2/ 2 3 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 2 4 an d 8 0 % . T a l l y i n g t h e f o o t a g e s o f c e m e n t q u a l i t y ( a s in t e r p r e t e d b y H a l l i b u r t o n ) w i t h i n t h e r e p o r t y i e l d s t h e f o l l o w i n g a g g r e g a t e t o t a l s : • A b o v e U p p e r T u l u v a k : 1 8 9 ’ M D f a i r , 3 3 2 ’ M D o f p o o r . • U p p e r T u l u v a k : 5 4 7 ’ M D o f f a i r , 7 1 5 ’ M D o f p o o r . • B e l o w U p p e r T u l u v a k : 9 3 6 ’ o f p o o r - q u a l i t y c e m e n t . • L o g g i n g i n t e r p r e t a t i o n g a p f r o m 5 , 1 1 3 ’ t o 7 , 9 6 4 ’ M D . • A b o v e N a n u s h u k F o r m a t i o n : 9 1 ’ M D f a i r , 1 , 8 8 5 ’ p o o r . Wi t h i n N a n u s h u k t o b o t t o m o f t h e C A S T l o g ( f r o m 9 , 9 4 0 ’ t o 10 , 8 3 9 ’ M D , - 3 , 7 8 5 ’ t o - 3, 9 8 1 ’ T V D S S , w i t h t h e t o p o f Na n u s h u k 3 re s e r v o i r l o c a t e d a t 1 1 , 1 8 0 ’ M D ( - 4, 0 5 3 ’ T V D S S ) : •21 6 ’ M D o f f a i r c e m e n t , 5 9 8 ’ M D o f p o o r c e m e n t , a n d 9 5 ’ of a p p a r e n t f r e e p i p e . In m y o p i n i o n , f o r N D B - 0 4 4 t h e ag g r e g a t e f o o t a g e s o f f a i r - an d p o o r- qu a l i t y c e m e n t a c r o s s e a c h z o n e l i s t e d a b o v e in d i c a t e t h a t c e m e n t v e r y l i k e l y i s o l a t e s th e Na n u s h u k 3 re s e r v o i r i n t e r v a l a n d t h a t N D B - 0 4 4 wi l l n o t i n t e r f e r e w i t h co n f i n e m e n t o f f r a c f l u i d s fo r t h e p l a n n e d o p e r a t i o n in ND B - 0 1 4 . SF D 2/ 2 3 / 2 0 2 4 (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 On e . T h e o p e r a t o r h a s i d e n t i f i e d o n e l o w - c o n f i d e n c e f a u l t wi t h i n t h e s e 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 1 4. Th i s sm a l l f a u l t ( w i t h l e s s t h a n 2 0 ’ o f v e r t i c a l d i s p l a c e m e n t ) wa s i n t e r s e c t e d b y N D B - 0 1 4 n e a r t h e t o e o f t h e w e l l , an d i t is co n t a i n e d w i t h i n t h e N a n u s h u k . It i s u n l i k e l y t h i s f a u l t w i l l in 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 f r a c t u r i n g fl 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 n i n d u c e d fr a c t u r e h a s i n t e r s e c t e d th i s f a u l t o r a n a t u r a l l y fr a c t u r e d in t e r v a l d u r i n g th e p l a n n e d op e r a t i o n s , t h e o p e r a t o r w i l l go t o f l u s h a n d t e 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 . SF D 2/ 2 3 /2 0 2 4 (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 a p p l i c a t i o n . CD W 02 / 2 1 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 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 6 5 1 1 b b l t o t a l d i r t y v o l . 1 . 9 M l b to t a l p r o p p a n t CD W 02 / 2 1 / 2 0 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 02 / 2 1 / 2 0 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 . N o p r o p r i e t a r y c h e m i c a l s l i s t e d . CD W 02 / 2 1 / 2 0 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 02 / 2 1 / 2 0 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 4 7 8 9 p s i . M a x . 8 9 0 0 ps 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 0 0 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 ps i b a c k p r e s s u r e I A (I A p o p o f f s e t 38 00 p s 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 54 0 0 p s i ( t e s t t o 6 0 0 0 p s i ) . . CD W 02 / 2 1 / 2 0 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 i n d u c e d f r a c t u r e s w il l r a n g e f r o m a b o u t 3 20 ’ t o 4 20 ’ 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 . Co m p u t e r s i 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 in d u c e d f r a c t u r e s w il l r a n g e f r o m a b o u t 2 2 0 ’ t o 29 0’ , a n d th e s h a l l o w e s t f r a c t o p T V D S S o f a b o u t - 4 , 1 4 7 ’ , w h i c h i s ab o u t 3 50 t r u e v e r t i c a l f e e t d e e p e r t h a n t h e b a s e o f t h e up p e r c o n f i n i n g l a y e r . S o , t h e O p e r a t o r ’ s co m p u t e r m o d e l in d i c a t e s t h a t t h e i n d u c e d f r a c t u r e s s h o u l d n o t p e n e t r a t e th 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 t h a t h a s a n es t i m a t e d ag g r e g a t e t h i c k n e s s o f m o r e t h a n 9 0 0 ’ i n t h i s a r e a . SF D 2/ 2 1 / 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 . A O G C C a n d O i l S e a r c h wo r k i n g t o w a r d s 1 . 5 X f l o w b a c k t o 2 X v o l u m e a l l o w e d . Di s p o s a l o p t i o n s s a m e a s pr e v i o u s f r a c s . CD W 02 / 2 1 / 2 0 2 4 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 2 4 (b ) T e s t i n g o f c a s i n g or i n 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 0 0 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 p s i , p o p o f f s e t as 3 8 0 0 p s i CD W 02 / 2 1 / 2 0 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 l i n e r t o p p a c k e r s e t a t ap p r o x . 10 2 5 7 f t w i t h f r a c s l e e v e s a t 1 0 , 8 0 3 f t . 9 - 5/ 8 ” in t e r m e d i a t e c a s i n g c e m e n t e d f r o m 1 0 , 4 4 0 t o 7 , 7 3 9 f t fr o m CB L e v a l u a t i o n . C e m e n t at a r e a o f i n t e r e s t s o n o c e m e n t co n c e r n s . CD W 02 / 2 1 / 2 0 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 5, 4 0 0 p s i ( 8 9 0 0 w i t h 3 , 5 00 p s i b a c k p r e s s u r e ) s o t e s t o f 6 0 0 p s i s a t i s f i e s 1 1 0 % CD W 02 / 2 1 / 2 0 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 8 0 0 p s i . CD W 02 / 2 1 / 2 0 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 02 / 2 1 / 2 0 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 IA P R V s e t a t 3 8 0 0 p s i . S u r f a c e a n n 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 02 / 2 1 / 2 0 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 t i m e 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 t h e a n n u l u s p r e s s u r e in 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 in 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 t r a n s f e r , t h e op e r a t o r s h a l l : CD W 02 / 2 1 / 2 0 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 (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 20 A A C 2 5 . 2 8 3 H y d r a ul 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 1 4 ( P T D N o . 2 2 3 - 1 0 5 ; S u n d r y N o . 3 2 4 - 0 8 5 ) 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 F e b r u a r y , 2 0 2 4 (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 . 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 2/ 1 5 / 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 No t a p p l i c a b l e : T h i s w e l l i s n o t c o n f i d e n t i a l . SF D 2/ 1 5 / 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 . 1 Junke, Kayla M (OGC) From:Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent:Tuesday, February 13, 2024 10:36 AM To:McLellan, Bryan J (OGC) Cc:Tirpack, Robert (Robert); Leahy, Scott (Scott) Subject:NDBi-014 Intermediate 9.625" Cement Bond Log Attachments:Reporting - Cement - NDBi-014 - 2024-02-12 11.45.01.pdf; NDBi-014_9_625 _Liner_Baker_Hughes_CBL_Final Report.pdf Bryan, Apologies it took so long, but I finally received the final 9-5/8” INT Casing CBL report from Baker. I’ve aƩached the Wellview CemenƟng Reports and the Baker Final CBL Report. Below is a high-level summary: Well Design - 9-5/8” Liner Top at 2,374’ MD - 13-3/8” Casing Shoe at 2,564’ MD - CFLEX Stage Tool Ports at 5,140’ MD - 9-5/8” Shoe at 10,440’ MD Geology - Base of Tuluvak FormaƟon at 5,112’ MD. Base of significant hydrocarbons are located in the upper Tuluvak at ~3,440’ MD / 2,640’ TVD - Top of the Nanushuk was picked at 7,677’ MD. o Top of the NT8 MFS was picked at 7,740’ MD. o Top of the NT7 MFS was picked at 7,807’ MD. Based on offset well logs (NDBi-043A), the top of the residual Nanushuk hydrocarbon in NDBi-014 is esƟmated to be ~7857’ MD / 3922’ TVD, which is within the NT7 MFS. This is further evidenced by the low resisƟvity values (i.e. clay 4-6 ohm) that were encountered above 7857’ MD on NDBi-014. Cement Job Planning / ExecuƟon - 1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeƟng TOC 250’ TVD above top of Nanushuk to 6,780’ MD. - During execuƟon of the 1st stage cement, we encountered losses and lost ~75 bbls aŌer cement turned the corner. - 2nd Stage of cement job planned with CFLEX at the base of the Tuluvak formaƟon (5,112’ MD / 3,123’ TVD). Also planned with a full 15.3 ppg tail slurry at 100% excess, targeƟng TOC at the 9-5/8” liner top. - During execuƟon of the 2nd stage cement, we encountered slight losses and lost ~16 bbls throughout the job. However, we saw cement returns off the top of liner and got ~104 bbls of contaminated cement returns to surface (max weight measured at surface was 14.2 ppg). ObservaƟons / Conclusions - For the 1st stage of the cement job, despite the losses, we have adequate isolaƟon in the upper Nanushuk formaƟons across the hydrocarbon-bearing formaƟons (top hydrocarbon esƟmated within NT7 at ~7857’ 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 MD). This is supported by the CBL log, which indicates good cement throughout the first stage and a TOC at 7739’ MD. - For the 2nd stage of the cement job, the stage collar (5,140 MD) was placed well below the lower-most Tuluvak significant hydrocarbon (~3,440’ MD). Based on job execuƟon results, cement isolaƟon was achieved across the Tuluvak formaƟon. This is supported by the CBL results, which indicate large areas of parƟal to good cement presence (2579’ to 3216’ and 3641’ to 5152’), and only 1 area of poor cement presence (3,216’ to 3,641’). - Our assessment is that we have adequate isolaƟon across hydrocarbon-bearing formaƟons in the upper Nanushuk, as well as adequate isolaƟon for frac operaƟons. The 2nd stage cement job shows adequate isolaƟon below, across and above the Tuluvak significant hydrocarbons. Let me know if you have any quesƟons. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. You don't often get email from brian.buzby@contractor.santos.com. Learn why this is important From:Brooks, Phoebe L (OGC) To:Buzby, Brian (Brian) Cc:Regg, James B (OGC) Subject:RE: Santos/Parker drilling Rig 272 Diverter Test Report 12-23-23 Date:Tuesday, January 30, 2024 4:56:58 PM Attachments:Diverter Parker 272 12-23-23.xlsx Brian, I added the well # NDBi-014 to the field/unit/well no. field. Please update your copy. 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: Buzby, Brian (Brian) <Brian.Buzby@contractor.santos.com> Sent: Sunday, December 24, 2023 3:16 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> Subject: Santos/Parker drilling Rig 272 Diverter Test Report 12-23-23 Here is the Diverter test report 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' added the well # NDBi-014 Date: 12/23/2023 Development: X Exploratory: Drlg Contractor: Rig No. 272 AOGCC Rep: Operator:Oper. Rep: Field/Unit/Well No.:Rig Rep: PTD No.: 2231050 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: 2300 psig P Vent Line(s) Size: 16 in. P 200 psi Recharge Time: 14 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: 2225 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: 43 sec P Mud System Misc: 0 NA Knife Valve Open Time: 32 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: 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* rig272.seniormanager@parkerwellbor TTEST DATA Pat Lynch phoebe.brooks@alaska.gov Oil Search (Alaska), LLC Wittness Waived by Adam Earl @ 12:30 on 12/23/2023. 0 Brian Buzby 0 907-685-4242 TTEST DETAILS jim.regg@alaska.gov AOGCC.Inspectors@alaska.gov Pikka / Nanushuk Oil Pool NDBi-014 Form 10-425 (Revised 05/2021)2023-1223_Diverter_Parker272_Pikka_NDB-14 9 9 9 9 9 9 1 Junke, Kayla M (OGC) From:Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent:Monday, January 29, 2024 4:30 PM To:McLellan, Bryan J (OGC) Subject:Fishing Operations on NDBi-014 Bryan, As a courtesy FYI, I just wanted to let you know that we had an issue running the 4.5” Lower Comple Ɵon liner yesterday. The liner hanger seemed to hang up in the CFLEX tool (cement stage collar) in the 9-5/8” casing. We eventually got it free, but had issues with it again shortly aŌer that. Long story short, we suspect that there is an issue with the slip body on the packer assembly aŌer it ran into the CFLEX. SƟll not sure what caused this, but we only made it about 300’ outside the 9-5/8” shoe before we were completely stuck. Set the liner hanger/packer this morning to get off of it. Currently are performing fishing operaƟons to mill the packer assembly up, then hopefully recover the 4.5” liner. EsƟmate that this will put us back at least a week. Just wanted to give you an update on what we have going on. Let me know if you have any quesƟons. Thanks, Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Junke, Kayla M (OGC) From:Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent:Thursday, January 25, 2024 11:25 AM To:McLellan, Bryan J (OGC) Subject:RE: NDBi-014: 9-5/8" Shoe LOT Results Ok will do Bryan. I’ll have the Frac Engineer include it. Thanks, Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and TwiƩer From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, January 25, 2024 11:16 AM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: RE: NDBi-014: 9-5/8" Shoe LOT Results Mark, Thanks for the explanaƟon. It would be good to include some of this assessment in the frac sundry applicaƟon. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Thursday, January 25, 2024 11:11 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDBi-014: 9-5/8" Shoe LOT Results Bryan, Yes, agree this well doesn’t follow the trend. There are some slight differences with this well that I’ll point out in my responses to your quesƟons below: 2 Do you have any explanaƟon as to why the formaƟon broke down at such a low pressure? We believe that in NDBi-014, due to the shoe locaƟon, we likely connected to a slightly cleaner sand that is within reservoir. For reference, the 13.05 ppg EMW LOT represents a 0.68 psi/Ō fracture gradient. This is within the expected frac gradient of the reservoir. The shoe locaƟon is slightly different than previous wells, as described below: - NDB-43 14.9 ppg FIT @ 4319’ TVD: Bench 1 well. Shoe set in the NT3 MFS. - NDB-32 15.0 ppg FIT @ 4322’ TVD: Bench 1 well. Shoe set at the NT3.2 reservoir top, but in a very low-quality secƟon of the reservoir at the shelf margin. - NDB-24 15.0 ppg FIT @ 4114’ TVD: Bench 2 well. Shoe set in the NT3 MFS. - NDB-44 14.0 ppg FIT @ 4112’ TVD: Bench 2 well. Shoe set in the NT3 MFS. - NDB-14 13.05 ppg LOT @ 4370’ TVD: Bench 1 well. Shoe set at the NT3.2 reservoir top at a locaƟon 500’ inboard of the shelf margin compared to previous bench 1 wells resulƟng in slightly beƩer reservoir quality. As you can see above, we believe that due to our shoe locaƟon for NDBi-014, being set at the top reservoir and within slightly beƩer reservoir quality, this resulted in the lower LOT that we saw. At the Ɵme of the LOT, we had roughly 27’ of hole open below the shoe, which was penetrated into the NT3.2 reservoir. What are the implicaƟons for the planned frac? No issues for the frac. The 0.68 psi/Ō fracture gradient is within the upper range of the fracture gradient within the reservoir. Our frac jobs assume an upper confining layer as the NT3 MFS, which is above the NT3.2 Reservoir. Since our shoe is set at the NT3.2 reservoir top, the NT3 MFS confining layer above will be the seal for the frac jobs. EsƟmates of the fracture gradient within the reservoir are noted below and have further detail provided within the frac sundry. Let me know if you have any quesƟons on the points above. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and TwiƩer From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, January 24, 2024 10:51 AM 3 To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: RE: NDBi-014: 9-5/8" Shoe LOT Results Mark, This well’s LOT pressure is definitely not following the trend of the other wells drilled to date at NDB pad. Do you have any explanaƟon as to why the formaƟon broke down at such a low pressure? What are the implicaƟons for the planned frac? NDB-43 14.9 ppg FIT @ 4319’ TVD NDB-32 15.0 ppg FIT @ 4322’ TVD NDB-24 15.0 ppg FIT @ 4114’ TVD NDB-44 14.0 ppg FIT @ 4112’ TVD NDB-14 13.05 ppg LOT @ 4370’ TVD NDB-14 is definitely not following the trend of the others. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Tuesday, January 23, 2024 11:17 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDBi-014: 9-5/8" Shoe LOT Results Bryan, Sorry I was trying to get you this earlier today, but it’s been a busy day with meeƟngs. Also wanted to QC these reports to make sure they were accurate. Reports are aƩached. Yes, cement jobs went well. 1st Stage: - Pumped 270 bbls of cement (used 30% excess), and esƟmated about 75 bbls of losses during the job (once cement turned the corner). However, saw good liŌ pressures during the job, indicated we do have a fair amount of coverage. I’m esƟmaƟng we have TOC somewhere near the top of the Nanushuk, but won’t be able to confirm unƟl we log. 2nd Stage: - Pumped 305 bbls of cement (used 100% excess), and only saw about 16 bbls of losses. Circulated ~104 bbls of contaminated cement off the top of liner, so we should have cement from stage tool to the top of liner. Again, we haven’t logged this yet. Let me know if you have any quesƟons. 4 Thanks, Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and TwiƩer From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, January 22, 2024 5:08 PM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: RE: NDBi-014: 9-5/8" Shoe LOT Results Mark, How did the cement jobs go? Could you send over the cemenƟng summary reports? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, January 22, 2024 2:26 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDBi-014: 9-5/8" Shoe LOT Results Bryan, Last night we performed our integrity test at the 9-5/8” casing shoe on NDBi-014. We had a bit of a strange event on the 1st aƩempt, so ended up performing another test, which resulted in a 13.05 ppg EMW LOT. I’ll walk you through the events below: 1st Test - Rig team walked up the test to the target FIT value of 1150 psi for a 15ppg EMW FIT. Everything looked great, then they shut it in. AŌer about 30 seconds, we had a sudden decrease in pressure of ~450 psi, at which point the line began to stabilize at ~700 psi. 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. 5 - Rig team double checked all surface equipment to make sure we didn’t have a leak somewhere, but could find nothing. - I instructed them to perform a 2nd test. 2nd Test - Again they performed the FIT, but this Ɵme as the test was walked up, the formaƟon broke down. - I evaluated the test and it appears that we had a leak-off pressure was ~694 psi, resulƟng in a 13.05ppg EMW LOT. - This test had a very similar stabilizaƟon curve as the first test, showing repeatability. We are good to drill ahead with the 13ppg EMW LOT (10.5ppg required for kick tolerance), and are currently drilling ahead in the hole secƟon. It’s a bit of a strange result, but it appears that we opened ourselves up to a weaker formaƟon/zone during the iniƟal test, which is apparent from the results of the 2nd test. I just wanted to give you an explanaƟon of the events and reasoning as to why we have 2 tests on the chart recorder. Let me know if you have any quesƟons. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 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 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDBi-014 JBR 01/22/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 5-7/8: & 9-5/8" TJ used. Accumulator bottles 24 with 1069 precharge average, one had a bad bladder and was noted. Test went well. Test Results TEST DATA Rig Rep:Pat LynchOperator:Oil Search (Alaska), LLC Operator Rep:Rowland Lawson Rig Owner/Rig No.:Parker 272 PTD#:2231050 DATE:12/29/2023 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopKPS231231105116 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 1540 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 4-1/2" x 7" V P #2 Rams 1 Blinds P #3 Rams 1 9-5/8" Fixed P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 3-1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2000 200 PSI Attained P18 Full Pressure Attained P75 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14 @ 2264 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P21 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 1 Junke, Kayla M (OGC) From:McLellan, Bryan J (OGC) Sent:Friday, December 15, 2023 9:33 AM To:Staudinger, Mark (Mark) Cc:Dewhurst, Andrew D (OGC) Subject:RE: New Permit Number 223-105 Mark, No issues with the change in pore pressure. Our geology team is evaluaƟng the proposed change in Tuluvak fluid determinaƟon and may have an addiƟonal informaƟon request soon. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, December 11, 2023 2:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: New Permit Number 223‐105 Hey Bryan, I just wanted to let you know that the Subsurface team had some updates to the Statement of Requirements, and in doing so, the updates are reflecƟng a minor increase in the predicted Tuluvak pore pressure, which yields an new PP predicƟon of 10.2 ppg (versus the 10.0 ppg) in the permit. It doesn’t affect kick tolerance, and we are well overbalanced with the 12.0 ppg MW, so this is more of an FYI. On a separate note, any idea when your team will provide feedback on our presentaƟon from last week? Thanks, Mark Mark Staudinger Senior Drilling Engineer 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 t: +1 (907) 375‐4654 | m: +1 (520) 273‐6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and TwiƩer From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Sent: Wednesday, December 6, 2023 11:01 AM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: New Permit Number 223‐105 Hello, AƩached is the new Permit for Pikka NDBi‐014. Thank you, Grace Christianson 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 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Mark Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 900 E Benson Boulevard Anchorage, AK, 99508 Re: Pikka Field, Nanushuk Oil Pool, NDBi-014 Oil Search Alaska, LLC Permit to Drill Number: 223-105 Surface Location: 2783’ FEL, 2463’ FSL, S4, T11N, R6E, UM Bottomhole Location: 952’ FEL, 3018’ FSL, S6, T11N, 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, Jessie Chmielowski Commissioner DATED this ___ day of December 2023. 6 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.06 10:24:55 -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: 15,419'TVD:4,206' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 12/10/23 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 7,892 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 69.8 15. Distance to Nearest Well Open Surface: x- 422463 y- 5972844 Zone- 4 22.8 to Same Pool:500' 16. Deviated wells: Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92 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 2,567' Surface Surface 2,567' 2,295' 12-1/4” 9-5/8” 47# L-80 HYD 563 8,000' 2,417' 2,192' 10,417' 4,369' 8-1/2” 4-1/2” 12.6# P-110S HYD 563 5,151' 10,267' 4,361' 15,418' 4,206' 9-5/8”4-1/2” 12.6# P-110S HYD 563 10,267' Surface Surface 10,267' 4,365' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Mark Staudinger Mark Staudinger Contact Email:mark.staudinger@santos.com Senior Drilling Engineer Contact Phone:1-520-273-6643 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng NDBi-014 Pikka / Nanushuk Oil Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): IS000361277U STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Please see attachment 6 1,540 3864 FEL, 4290 FSL, S8, T11N, R6E, UM 952 FEL, 3018 FSL, S6, T11N, R6E, UM LONS 19-003 900 E Benson Boulevard, Suite 500, Anchorage, AK 99508 Oil Search Alaska, LLC 2783 FEL, 2463 FSL, S4, T11N, R6E, UM ADL 392984, 392985, 393023, 391445, 393021 3153 18. Casing Program: Top - Setting Depth - BottomSpecifications 1,977 Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface Please see attachment 6 Conductor/Structural LengthCasing Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: 11/07/23 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): N/A N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): s N ype of W L l R L Class: os N s No s N o D s s sD o : well is p G S S 20 A SS S s No s No S G s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Senior Drilling Engineer By Grace Christianson at 9:24 am, Nov 07, 2023 A.Dewhurst 15NOV23BJM 12/5/23 *See 9-5/8" tieback detail below. -bjm 50-103-20869-00-00 PIKKA 223-105 *Addition to box 18 Casing Program: 9-5/8" 47# L80 Hyd 563 Tieback from Surface to liner top at 2417' MD/2192' TVD. The tieback will not be cemented. -bjm See attached conditions of approval DSR-11/15/23*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.06 10:25:12 -09'00' NDBi-014 (PTD 223-105) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨĂƉƉƌŽǀĂů 1.KWƚĞƐƚƚŽϯϱϬϬƉƐŝ͕ŶŶƵůĂƌƚĞƐƚƚŽϯϬϬϬƉƐŝ͘ 2.>Kdͬ&/dƌĞƐƵůƚƐƚŽďĞƐƵďŵŝƩĞĚƚŽK'ǁŝƚŚŝŶϰϴŚŽƵƌƐŽĨŽďƚĂŝŶŝŶŐƚŚĞĚĂƚĂ͘ 3.dŚĞϵ-ϱͬϴ͟ĂƐŝŶŐŵƵƐƚďĞůŽŐŐĞĚĂĐƌŽƐƐďŽƚŚĮƌƐƚĂŶĚƐĞĐŽŶĚƐƚĂŐĞĐĞŵĞŶƚĞĚŝŶƚĞƌǀĂůƐ͘ 4.dŚĞ>t-^ŽŶŝĐůŽŐǁŝůůŽŶůLJďĞĂĐĐĞƉƚĞĚǁŚĞŶƚŚĞĨŽůůŽǁŝŶŐĐŽŶĚŝƟŽŶƐĂƌĞŵĞƚ͗ Ă͘ KŝůƐĞĂƌĐŚƚŽƉƌŽǀŝĚĞĂǁƌŝƩĞŶůŽŐĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶƚŽƚŚĞK'ĂůŽŶŐǁŝƚŚƚŚĞ ůŽŐĂƐƐŽŽŶĂƐƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘dŚĞĞǀĂůƵĂƟŽŶŝƐƚŽŝŶĚŝ ĐĂƚĞƚŚĞŝŶƚĞƌǀĂůƐŽĨ ĐŽŵƉĞƚĞŶƚĐĞŵĞŶƚƚŚĂƚKŝůƐĞĂƌĐŚŝƐƵƐŝŶŐƚŽŵĞĞƚƚŚĞŽďũĞĐƟǀĞƌĞƋƵŝƌĞŵĞŶƚƐĨŽƌ ĂŶŶƵůĂƌŝƐŽůĂƟŽŶĂŶĚƌĞƐĞƌǀŽŝƌŝƐŽůĂƟŽŶ͕ĂŶĚƚŽŝŶĚŝĐĂƚĞƚŚĞůŽĐĂƟŽŶŽĨĐŽŶĮŶŝŶŐnjŽŶĞƐ͕ ŚLJĚƌŽĐĂƌďŽŶ-ďĞĂƌŝŶŐnjŽŶĞƐ͕ŽǀĞƌƉƌĞƐƐƵƌĞĚnjŽŶĞƐĂŶĚĨƌĞƐŚǁĂƚĞƌ͕ŝĨƉƌĞƐĞŶƚ͘WƌŽǀŝĚŝŶŐ ƚŚĞůŽŐǁŝƚŚŽƵƚĂŶĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶŝƐŶŽƚĂĐĐĞƉƚĂďůĞ͘ ď͘ >tƐŽŶŝĐůŽŐƐŵƵƐƚƐŚŽǁĨƌĞĞƉŝƉĞĂŶĚdŽƉŽĨĞŵĞŶƚ͘ dŚĞůŽŐŵƵƐƚďĞƌƵŶĂĐƌŽƐƐƚŚĞ ƚĂƌŐĞƚnjŽŶĞƐĂŶĚĂƚĂĚĞƉƚŚƚŽĞŶƐƵƌĞƚŚĞĨƌĞĞƉŝƉĞĂďŽǀĞƚŚĞdKŝƐĐĂƉƚƵƌĞĚĂƐǁĞůůĂƐ ƚŚĞdK͘/ĨƚŚĞůŽŐŐĞĚŝŶƚĞƌǀĂůĚŽĞƐŶŽƚĐĂƉƚƵƌĞƚŚĞdKĂŶĚĨƌĞĞƉŝƉĞĂďŽǀĞŝƚ͕ ŝƚǁŝůů ŶĞĞĚƚŽďĞƌĞ-ƌƵŶ͕ƵŶůĞƐƐƚŚĞĐĞŵĞŶƚǁĂƐƉůĂŶŶĞĚƚŽĐŽǀĞƌƚŚĞĞŶƟƌĞůĞŶŐƚŚŽĨůŝŶĞƌŽƌ ĐĂƐŝŶŐ͘ Đ͘ KŝůƐĞĂƌĐŚǁŝůůƉƌŽǀŝĚĞĂĐĞŵĞŶƚũŽďƐƵŵŵĂƌLJƌĞƉŽƌƚĂŶĚĞǀĂůƵĂƟŽŶĂůŽŶŐǁŝƚŚƚŚĞ ĐĞŵĞŶƚůŽŐĂŶĚĞǀĂůƵĂƟŽŶƚŽƚŚĞK'ǁŚĞŶƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘ d.ĞƉĞŶĚŝŶŐŽŶƚŚĞĐĞŵĞŶƚũŽďƌĞƐƵůƚƐŝŶĚŝĐĂƚĞĚďLJƚŚĞĐĞŵĞŶƚũŽďƌĞƉŽƌƚ͕ƚŚĞůŽŐƐĂŶĚ ƚŚĞ&/d͕ƌĞŵĞĚŝĂůŵĞĂƐƵƌĞƐŽƌĂĚĚŝƟŽŶĂůůŽŐŐŝŶŐŵĂLJďĞƌĞƋƵŝƌĞĚ͘ Page 1 of 1 07 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-014 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-014 is planned to be a horizontal Injector targeting the Nanushuk 3. The approximate spud date is anticipated to be December 10 th, 2023. Parker Rig 272 will be used to drill this well. The 16” surface hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~73 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 (520) 273-6643 or Mark.Staudinger@santos.com. Respectfully, Mark Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, Mark Staudinger NDBi-014 PTD AOGCC 11.3.23 - 1 - 03-Nov-23 Application for Permit to Drill NDBi-014 Well NDBi-014 PTD AOGCC 11.3.23 - 2 - 03-Nov-23 Table of Contents 1. Well Name.................................................................................................................................3 2. Location Summary.....................................................................................................................3 3. Blowout Prevention Equipment Information..............................................................................4 4. Drilling Hazards Information......................................................................................................5 5. Procedure for Conducting Formation Integrity Tests..................................................................6 6. Casing and Cementing Program.................................................................................................6 7. Diverter System Information......................................................................................................7 8. Drilling Fluid Program................................................................................................................7 9. Abnormally Pressured Formation Information...........................................................................8 10. Seismic Analysis.......................................................................................................................8 11. Seabed Condition Analysis.......................................................................................................9 12. Evidence of Bonding................................................................................................................9 13. Proposed Drilling Program.......................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal..............................................11 15. Proposed Variance Request........................................................Error! Bookmark not defined. Attachments............................................................................................................................................12 Attachment 1: Location Maps......................................................................................................13 Attachment 2: Directional Plan....................................................................................................16 Attachment 3: BOPE Equipment..................................................................................................3 8 Attachment 4: Drilling Hazards....................................................................................................43 * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well.......................................................................................................................................44 Attachment 5: Leak Off Test Procedure.......................................................................................45 Attachment 6: Cement Summary.................................................................................................46 Attachment 7: Prognosed Formation Tops...................................................................................48 Attachment 8: Well Schematic.....................................................................................................49 Attachment 9: Formation Evaluation Program.............................................................................49 Attachment 10: Wellhead & Tree Diagram ..................................................................................51 Attachment 11: Injector Area of Review......................................................................................52 NDBi-014 PTD AOGCC 11.3.23 - 3 - 03-Nov-23 An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDBi-014. 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 2783 FEL, 2463 FSL, S4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,844 E 422,463 Rig KB Elevation 47’ above GL Ground Level 22.8’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 3864 FEL, 4290 FSL, S8, T11N, R6E, UM NAD 27 Coordinate System N 5,969,459 E 416,075 Measured Depth, Rig KB (MD) 10,753’ Total Vertical Depth, Rig KB (TVD) 4,368’ Total vertical Depth, Subsea (TVDSS) 4,298’ Location at Bottom of Productive Interval Reference to Government Section Lines 952 FEL, 3018 FSL, S6, T11N, R6E, UM NAD 27 Coordinate System N 5,973,494’ E 413,739’ Measured Depth, Rig KB (MD) 15,418’ Total Vertical Depth, Rig KB (TVD) 4,206’ Total vertical Depth, Subsea (TVDSS) 4,136’ NDBi-014 PTD AOGCC 11.3.23 - 4 - 03-Nov-23 (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 2: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for NDBi-014 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. NDBi-014 PTD AOGCC 11.3.23 - 5 - 03-Nov-23 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,976 psi in the @10,417’ MD at 4,370’ TVD (8.7ppg EMW Nan 3.2 formation to section TD) Maximum surface pressure 1,540 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,370’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 12-1/4” hole LOT after drilling 20’-50’ of new hole. 13.7 ppg LOT required for Kick Tolerance. 13-3/8” Casing Test 2,600 psi surface pressure [Test pressure driven by 50% of Casing Burst] 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,977 psi in the Nanushuk 3 at 4,371’ TVD (8.7ppg EMW top NT3 formation to heel target) Maximum surface pressure 1,540 psi from the NT3 (0.10 psi/ft gas gradient to surface, 4,371’ TVD) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 3,000 psi / 250 psi [Test pressure driven by annular pressure during frac job] Integrity Test – 8-1/2” hole FIT after drilling 20’-50’ of new hole. 15.0 ppg. (10.5 ppg EMW LOT Required for infinite kick tolerance.) 9-5/8” Liner Test 4,000 psi surface pressure [Test pressure driven by annular pressure during frac job] (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be overpressured at 10.0 ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. (C)data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; FIT after drilling 20’-50’ of new hole. 15.0 ppg. ppg LOT requiredg for Kick Tolerance. 13.77 The Tuluvak is expected to be overpressured at 10.0 ppg pore pressure. The Tuluvak formation is expected in this area and has a high potential for gas a NDBi-014 PTD AOGCC 11.3.23 - 6 - 03-Nov-23 Nearby offset Exploration and Appraisal wells in the area suggest that no significant hole problems are to be expected. Please refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 54’ 16” 13-3/8” 68# L-80 BTC 2,567’ Surface 2,567’ / 2,295’ 12-1/4” 9-5/8” 47# L-80 HYD 563 8,000’ 2,417’ 10,417’ / 4,369’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 ~5,151 ~10,267 ~15,418’ / ~4,206’ 9-5/8” Casing 4-1/2” 12.6# P-110S HYD 563 ~10,267 Surface ~10,267/ ~4,365’ Please refer to Attachment 6: Cement Summary for further details. 9-5/8" 47# L-80 HYD 563 2417 Surface 2417' / 2192' Tieback13-3/8" casing Per Mark Staudinger email 11/29/23 -bjm NDBi-014 PTD AOGCC 11.3.23 - 7 - 03-Nov-23 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line Please refer to Attachment 3: BOPE Equipment for further details. 8.Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Intermediate Hole Production Hole Mud Type Water based Spud Mud Mineral Oil Based Mud Mineral Oil Based Mud Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 10ppg 100-300 seconds ALAP 30-80 < 10 ml/30min n/a 8.6-10.5 <35 11.5-12 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. NDBi-014 PTD AOGCC 11.3.23 - 8 - 03-Nov-23 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. NDBi-014 PTD AOGCC 11.3.23 - 9 - 03-Nov-23 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDBi-014 Well is to be dr illed 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-014 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling & Completions Program NDBi-014 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. NDBi-014 PTD AOGCC 11.3.23 - 10 - 03-Nov-23 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 the top NT3.2 reservoir. 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. Pump secondary stage, close cementing sleeve, release shifting tool, and SO to 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” annulus to 2600 psi for 30 min. 20. Pressure test 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 to run 4-1/2” production liner with liner hanger/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 TEC wire. Space out seals. 30. Circulate corrosion inhibited brine into annulus and stab seals inside the polish bore below the 9-5/8” x 4-1/2” liner top packer. 31. Landing tubing hanger 32. Pressure test tubing to 4,000 psi for 30 mins. Pressure up on the annulus to 4,000 psi for Log first and second stage cement with sonic LWD. -bjm Burst of 9-5/8" 47# L80 = 6870 psi. -bjm Burst of 13-3/8" 68# L80 is 5020 psi. -bjm NDBi-014 PTD AOGCC 11.3.23 - 11 - 03-Nov-23 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 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. NDBi-014 PTD AOGCC 11.3.23 - 12 - 03-Nov-23 Attachments NDBi-014 PTD AOGCC 11.3.23 - 13 - 03-Nov-23 Attachment 1: Location Maps OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PLANNED WELLS DIVERTER (50-ft) RIG OUTLINES DATE: 9/25/2023. By: JB 04080 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB14_well_diverter GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 010205 Meters PIKKA DEVELOPMENT NDB14 WELL DIVERTER Latitude (decimal degree) Long (decimal degree)Latitude Longitude Y (ft) x (ft) 70.335625 Ͳ150.632207 N 70° 20' 08.2511" W 150° 37' 55.9452" 5,972,592.35 1,562,495.57 Latitude (decimal degree) Long (decimal degree)Latitude Longitude y (ft) x (ft) 70.335944 Ͳ150.629107 N 70° 20' 09.4020" W 150° 37' 44.6684" 5,972,844.34 422,462.77 State Plane NAD83 Zone 4 StatePlane NAD27 Zone 4 AD L 3 9 2 9 6 3 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 2 9 8 5 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 9 . 8 4 % D N R - 5 0 . 1 6 % AD L 3 9 2 9 8 4 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 3 0 2 2 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 9 . 4 8 % D N R - 6 0 . 5 2 % AD L 3 9 3 0 2 1 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 1 9 . 2 2 % D N R - 8 0 . 7 8 % AD L 3 9 3 0 2 3 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 4 4 . 0 8 % D N R - 5 5 . 9 2 % AD L 3 9 3 0 1 9 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 % D N R - 6 6 . 9 % AD L 3 9 3 0 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 7 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 5 0 % D N R - 5 0 % AD L 3 9 3 0 1 6 Su r f a c e O w n e r s : K u u k p i k OS A - 5 1 % , R E P S O L - 4 9 % SU B S . O W N E R S : AS R C - 3 3 . 1 7 % D N R - 6 6 . 8 3 % AD L 3 9 1 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 % U0 1 2 N 0 0 6 E 3 4 U0 1 1 N 0 0 6 E 0 4 U0 1 2 N 0 0 6 E 3 2 U0 1 1 N 0 0 6 E 0 5 U0 1 2 N 0 0 6 E 3 3 U0 1 2 N 0 0 5 E 3 6 U0 1 1 N 0 0 5 E 0 1 U0 1 1 N 0 0 5 E 1 2 U0 1 1 N 0 0 6 E 0 9 U0 1 1 N 0 0 6 E 0 8 U0 1 1 N 0 0 6 E 1 0 U0 1 1 N 0 0 6 E 0 3 U0 1 1 N 0 0 6 E 1 6 U0 1 1 N 0 0 6 E 1 5 U0 1 1 N 0 0 6 E 1 7 U0 1 1 N 0 0 5 E 1 3 U0 1 2 N 0 0 6 E 3 1 U0 1 1 N 0 0 6 E 0 6 U0 1 1 N 0 0 6 E 1 8 U0 1 1 N 0 0 6 E 0 7 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 1 4 W E L L A R E A .5 - M I L E B U F F E R .2 5 - M I L E B U F F E R 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 TO W N S H I P SE C T I O N KU U K P I K B O U N D A R Y DA T E : 1 1 / 6 / 2 0 2 3 . R E V : 1 . 0 . B y : J B 0 5 0 0 1 , 0 0 0 US F e e t Pr o j e c t : A P - D R L - G E N _ a s s o r t e d La y o u t : A P - D R L - P E - M _ N D B i 0 1 4 _ 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 NDBi-014 PTD AOGCC 11.3.23 - 16 - 03-Nov-23 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 Start 300.0 hold at 47.0 MD 2 347.0 0.00 0.00 347.0 0.0 0.0 0.00 0.00 0.0 Start Build 2.00 3 647.0 6.00 165.00 646.5 -15.2 4.1 2.00 165.00 -5.0 Start DLS 2.50 TFO 53.68 4 995.6 13.18 197.37 990.2 -70.8 -3.1 2.50 53.68 -1.4 Start 154.0 hold at 995.6 MD 5 1149.6 13.18 197.37 1140.1 -104.3 -13.6 0.00 0.00 6.9 Start DLS 3.00 TFO 27.19 6 3195.4 73.24 222.13 2570.6 -1155.8 -818.8 3.00 27.19 743.2 Start 3889.4 hold at 3195.4 MD 7 7084.9 73.24 222.13 3692.4 -3917.7 -3317.0 0.00 0.00 3059.9 Start DLS 3.00 TFO 93.57 8 10318.7 88.63 319.88 4366.9 -3800.2 -6095.1 3.00 93.57 5839.8 Start 100.0 hold at 10318.7 MD 9 10418.7 88.63 319.88 4369.3 -3723.8 -6159.5 0.00 0.00 5909.0 Start DLS 3.00 TFO 70.47 10 10753.2 91.99 329.34 4367.5 -3451.4 -6353.0 3.00 70.47 6119.4 NDBi-014 Heel V1.0 Start 4665.1 hold at 10753.2 MD 11 15418.4 91.99 329.34 4205.8 559.0 -8730.7 0.00 0.00 8748.5 NDBi-014 Toe v.0 TD at 15418.4 47 299 299 499 499 649 649 849 849 1049 1049 1249 1249 1399 1399 1599 1599 2399 2399 3199 3199 3999 3999 4499 4499 5499 5499 6499 6499 7499 7499 8499 8499 9499 9499 10999 10999 11999 11999 12999 12999 13999 13999 14999 14999 15999 Plan: NDBi-014 Rev D.0 Plan Summary 0 3 Do g l e g S e v e r i t y 0 2500 5000 7500 10000 12500 15000 Measured Depth 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" x 6-1/8" 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] 7075100125150175200225250275300325350375400425450475500524549574598623647671694717740763 Plan: NDB-010 Rev A.0 70751001251501752002252502753003253503754004254504755005255495745996246496736987227467717958198448688929169419659891014103910641089111411391164118812121236126012841309133313571381140614301454147815031527155215761600162516491674169817231747177217961821184518701895191919441969199320182043206720922117214221662191221622412266Plan: NDB-011 Rev A.0 7075100125150175200225250275300325350375400425450475499524549573598622646670694717741764 787 810 832 855Plan: NDB-013 Rev A.0 7075100125150175200225250275300325350375400425450474499524548573597621645669693717740 763 786 809 Plan: NDB-015 Rev A.0 7075100125150175200225250275300325350375400425450474499524548573597621Plan: NDB-09 Rev A.0 7075100125150175200225250275300325350375400425450474499524548573597621645668692715 738 761 783 805Plan: NDBi-012 Rev A.0 7075100125150175200225250275300325350375400425450475500524549574598623647672696721745769793 816 840 863 Plan: NDBi-016 Rev A.0 100125150175200225250275300325350375400425450475500525550575600624649674700725750774799824848872896Plan: NDBi-018 Rev F.0 7075100125150175200225250275300325350375400425450475500525550575600625650676702728Plan: NDBi-019 Rev A.0 2250 Tr u e V e r t i c a l D e p t h 0 1250 2500 3750 5000 6250 7500 8750 Vertical Section at 273.66° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" x 6-1/8" Liner 0 28 55 Ce n t r e t o C e n t r e S e p a r a t i o n 0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.035 SURVEY PROGRAM Date: 2021-02-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 300.0 Plan: NDBi-014 Rev D.0 (NDBi-014) SDI_KPR_ADK 300.0 1300.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag 300.0 2567.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag 2567.0 3567.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag 2567.0 10417.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag 10417.0 11417.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag 10417.0 15418.4 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag Surface Location North / 5972592.35 East / 1562495.57 Elevation / 22.8 CASING DETAILS TVD MD Name 127.0 127.0 20" Conductor Casing 2295.1 2567.0 13-3/8" Surface Casing 4369.3 10417.0 9-5/8" Intermediate Liner 4205.8 15418.0 4-1/2" x 6-1/8" Liner Mag Model & Date: BGGM2023 26-Aug-23 Magnetic North is 14.56° East of True North (Magnetic Declin Mag Dip & Field Strength: 80.59°57188.12104287nT FORMATION TOP DETAILS TVDPath Formation 1046.0 Upper SB 1138.9Base Ice Bearing 1390.7 BaseTransition 1735.1 Middle SB 2144.9 MCU 2447.2Tuluvak Shale 2505.7Tuluvak Sand 3156.2 Seabee 3873.7 Nanushuk 3902.3 NT8 MFS 3919.8 NT7 MFS 3989.6 NT6 MFS 4070.5 NT5 MFS 4155.2 NT4 MFS 4350.2 NT3 MFS 4369.2NT3.2 Reservoir By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet la teral tolerance. Prepared by Checked by BHI DE Accepted by BHI PSD Approved by Santos DE Plan: Parker 272 @ 69.8usft Standard Planning Report -Geographic 06 November, 2023 Plan: Plan: NDBi-014 Rev D.0 Santos NAD27 Conversion Pikka NDB NDBi-014 NDBi-014 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka, North Slope Alaska, United States Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: NDB Map Slot Radius:0.9 usft usft usft " 5,972,909.70 423,383.56 20 70° 20' 10.138 N 150° 37' 17.796 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: NDBi-014 Wellhead Elevation:0.9 0.0 0.0 5,972,844.34 422,462.77 70° 20' 9.402 N 150° 37' 44.668 W 22.8 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDBi-014 Model NameMagnetics BGGM2023 26/08/2023 14.56 80.59 57,188.12076012 Phase:Version: Audit Notes: Design Plan: NDBi-014 Rev D.0 PLAN Vertical Section:Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 273.660.00.047.0 Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 6/11/2023 Depth To (usft) Depth From (usft) SDI_KPR_ADK SDI Keeper ADK Plan: NDBi-014 Rev D.0 (NDBi-01147.0 300.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-014 Rev D.0 (NDBi-012300.0 1,300.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-014 Rev D.0 (NDBi-013300.0 2,567.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-014 Rev D.0 (NDBi-0142,567.0 3,567.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-014 Rev D.0 (NDBi-0152,567.0 10,417.0 3_MWD+IFR2+Sag A012Mb: IIFR dec correctio Plan: NDBi-014 Rev D.0 (NDBi-01610,417.0 11,417.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-014 Rev D.0 (NDBi-01710,417.0 15,418.4 6/11/2023 10:59:30AM COMPASS 5000.17 Build 02 Page 2 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.00.047.00.000.0047.0 0.000.000.000.000.00.0347.00.000.00347.0 165.000.002.002.004.1-15.2646.5165.006.00647.0 53.689.292.062.50-3.1-70.8990.2197.3713.18995.6 0.000.000.000.00-13.6-104.31,140.1197.3713.181,149.6 27.191.212.943.00-818.8-1,155.82,570.6222.1373.243,195.4 0.000.000.000.00-3,317.3-3,917.73,692.4222.1373.247,085.1 93.573.020.483.00-6,095.3-3,800.24,366.9319.8888.6310,318.9 0.000.000.000.00-6,159.8-3,723.84,369.3319.8888.6310,418.9 70.472.831.003.00-6,353.2-3,451.54,367.5329.3491.9910,753.4 NDBi-014 Heel V1.0 83.940.000.000.00-8,730.6559.24,205.8329.3591.9915,418.6 NDBi-014 Toe v.0 6/11/2023 10:59:30AM COMPASS 5000.17 Build 02 Page 3 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 47.0 0.00 47.0 0.0 0.00.00 422,462.775,972,844.34 70° 20' 9.402 N 150° 37' 44.668 W Start 300.0 hold at 47.0 MD 100.0 0.00 100.0 0.0 0.00.00 422,462.775,972,844.34 70° 20' 9.402 N 150° 37' 44.668 W 127.0 0.00 127.0 0.0 0.00.00 422,462.775,972,844.34 70° 20' 9.402 N 150° 37' 44.668 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,462.775,972,844.34 70° 20' 9.402 N 150° 37' 44.668 W 300.0 0.00 300.0 0.0 0.00.00 422,462.775,972,844.34 70° 20' 9.402 N 150° 37' 44.668 W 347.0 0.00 347.0 0.0 0.00.00 422,462.775,972,844.34 70° 20' 9.402 N 150° 37' 44.668 W Start Build 2.00 400.0 1.06 400.0 -0.5 0.1165.00 422,462.895,972,843.87 70° 20' 9.397 N 150° 37' 44.665 W 500.0 3.06 499.9 -3.9 1.1165.00 422,463.795,972,840.39 70° 20' 9.363 N 150° 37' 44.638 W 600.0 5.06 599.7 -10.8 2.9165.00 422,465.555,972,833.53 70° 20' 9.296 N 150° 37' 44.584 W 647.0 6.00 646.5 -15.2 4.1165.00 422,466.675,972,829.14 70° 20' 9.253 N 150° 37' 44.550 W Start DLS 2.50 TFO 53.68 700.0 6.87 699.1 -21.0 5.1173.96 422,467.665,972,823.31 70° 20' 9.196 N 150° 37' 44.519 W 800.0 8.82 798.2 -34.6 5.0185.52 422,467.415,972,809.73 70° 20' 9.062 N 150° 37' 44.522 W 900.0 10.99 896.7 -51.5 2.2192.74 422,464.405,972,792.83 70° 20' 8.895 N 150° 37' 44.605 W 995.6 13.18 990.2 -70.8 -3.1197.37 422,458.945,972,773.59 70° 20' 8.706 N 150° 37' 44.759 W Start 154.0 hold at 995.6 MD 1,000.0 13.18 994.5 -71.8 -3.4197.37 422,458.635,972,772.64 70° 20' 8.696 N 150° 37' 44.768 W 1,053.0 13.18 1,046.0 -83.3 -7.0197.37 422,454.905,972,761.15 70° 20' 8.583 N 150° 37' 44.873 W Upper Schrader Bluff 1,100.0 13.18 1,091.8 -93.5 -10.2197.37 422,451.605,972,750.95 70° 20' 8.482 N 150° 37' 44.967 W 1,148.4 13.18 1,138.9 -104.0 -13.5197.37 422,448.195,972,740.46 70° 20' 8.379 N 150° 37' 45.063 W Base Ice Bearing Permafrost 1,149.6 13.18 1,140.1 -104.3 -13.6197.37 422,448.115,972,740.19 70° 20' 8.376 N 150° 37' 45.065 W Start DLS 3.00 TFO 27.19 1,200.0 14.54 1,189.0 -115.7 -17.5200.12 422,444.105,972,728.81 70° 20' 8.264 N 150° 37' 45.179 W 1,300.0 17.31 1,285.2 -141.1 -27.9204.31 422,433.395,972,703.56 70° 20' 8.014 N 150° 37' 45.484 W 1,400.0 20.15 1,379.9 -170.0 -42.0207.36 422,419.055,972,674.85 70° 20' 7.730 N 150° 37' 45.894 W 1,411.6 20.48 1,390.7 -173.5 -43.8207.66 422,417.165,972,671.31 70° 20' 7.695 N 150° 37' 45.948 W Base Permafrost Transition 1,500.0 23.03 1,472.9 -202.3 -59.6209.67 422,401.125,972,642.73 70° 20' 7.413 N 150° 37' 46.408 W 1,600.0 25.93 1,563.9 -237.9 -80.7211.50 422,379.645,972,607.31 70° 20' 7.062 N 150° 37' 47.025 W 1,700.0 28.85 1,652.7 -276.8 -105.2212.98 422,354.685,972,568.68 70° 20' 6.680 N 150° 37' 47.742 W 1,795.5 31.66 1,735.1 -316.9 -131.9214.16 422,327.655,972,528.89 70° 20' 6.286 N 150° 37' 48.519 W Middle Schrader Bluff 1,800.0 31.79 1,739.0 -318.8 -133.2214.21 422,326.305,972,526.94 70° 20' 6.266 N 150° 37' 48.558 W 1,900.0 34.73 1,822.6 -363.9 -164.5215.25 422,294.585,972,482.22 70° 20' 5.823 N 150° 37' 49.471 W 2,000.0 37.69 1,903.3 -411.8 -198.9216.15 422,259.605,972,434.62 70° 20' 5.352 N 150° 37' 50.478 W 2,100.0 40.65 1,980.8 -462.6 -236.5216.93 422,221.485,972,384.29 70° 20' 4.853 N 150° 37' 51.576 W 2,200.0 43.61 2,054.9 -515.9 -277.2217.63 422,180.305,972,331.36 70° 20' 4.328 N 150° 37' 52.763 W 2,300.0 46.58 2,125.5 -571.8 -320.7218.25 422,136.185,972,275.97 70° 20' 3.779 N 150° 37' 54.034 W 2,328.4 47.42 2,144.9 -588.1 -333.6218.42 422,123.115,972,259.79 70° 20' 3.618 N 150° 37' 54.411 W MCU 2,400.0 49.55 2,192.3 -629.9 -367.1218.82 422,089.245,972,218.29 70° 20' 3.206 N 150° 37' 55.388 W 2,500.0 52.52 2,255.2 -690.3 -416.1219.33 422,039.615,972,158.46 70° 20' 2.613 N 150° 37' 56.819 W 2,567.0 54.51 2,295.1 -731.9 -450.3219.66 422,004.925,972,117.25 70° 20' 2.204 N 150° 37' 57.819 W 13-3/8" Surface Casing 2,600.0 55.49 2,314.0 -752.6 -467.6219.81 421,987.435,972,096.64 70° 20' 2.000 N 150° 37' 58.324 W 2,700.0 58.47 2,368.5 -816.8 -521.6220.26 421,932.845,972,033.02 70° 20' 1.368 N 150° 37' 59.898 W 2,800.0 61.45 2,418.5 -882.7 -577.7220.67 421,875.995,971,967.76 70° 20' 0.721 N 150° 38' 1.539 W 2,861.9 63.29 2,447.2 -924.2 -613.6220.92 421,839.745,971,926.64 70° 20' 0.312 N 150° 38' 2.585 W Tuluvak Shale 2,900.0 64.43 2,464.0 -950.0 -636.0221.07 421,817.035,971,901.04 70° 20' 0.058 N 150° 38' 3.240 W 3,000.0 67.41 2,504.8 -1,018.6 -696.2221.44 421,756.135,971,833.05 70° 19' 59.383 N 150° 38' 4.998 W 3,002.4 67.48 2,505.7 -1,020.3 -697.7221.45 421,754.675,971,831.43 70° 19' 59.367 N 150° 38' 5.040 W Tuluvak Sand 3,100.0 70.39 2,540.8 -1,088.4 -758.2221.80 421,693.465,971,763.97 70° 19' 58.698 N 150° 38' 6.807 W 6/11 /2023 10:59:30AM COMPASS 5000.17 Build 02 Page 4 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 3,195.4 73.24 2,570.6 -1,155.8 -818.8222.13 421,632.155,971,697.21 70° 19' 58.035 N 150° 38' 8.577 W Start 3889.4 hold at 3195.4 MD 3,200.0 73.24 2,571.9 -1,159.0 -821.7222.13 421,629.185,971,693.99 70° 19' 58.003 N 150° 38' 8.663 W 3,300.0 73.24 2,600.7 -1,230.0 -886.0222.13 421,564.225,971,623.66 70° 19' 57.304 N 150° 38' 10.538 W 3,400.0 73.24 2,629.6 -1,301.0 -950.2222.13 421,499.265,971,553.33 70° 19' 56.606 N 150° 38' 12.413 W 3,500.0 73.24 2,658.4 -1,372.0 -1,014.4222.13 421,434.305,971,483.00 70° 19' 55.907 N 150° 38' 14.289 W 3,600.0 73.24 2,687.3 -1,443.0 -1,078.7222.13 421,369.345,971,412.66 70° 19' 55.209 N 150° 38' 16.164 W 3,700.0 73.24 2,716.1 -1,514.1 -1,142.9222.13 421,304.385,971,342.33 70° 19' 54.511 N 150° 38' 18.039 W 3,800.0 73.24 2,745.0 -1,585.1 -1,207.1222.13 421,239.425,971,272.00 70° 19' 53.812 N 150° 38' 19.915 W 3,900.0 73.24 2,773.8 -1,656.1 -1,271.4222.13 421,174.465,971,201.67 70° 19' 53.114 N 150° 38' 21.790 W 4,000.0 73.24 2,802.6 -1,727.1 -1,335.6222.13 421,109.505,971,131.33 70° 19' 52.415 N 150° 38' 23.665 W 4,100.0 73.24 2,831.5 -1,798.1 -1,399.8222.13 421,044.545,971,061.00 70° 19' 51.717 N 150° 38' 25.540 W 4,200.0 73.24 2,860.3 -1,869.1 -1,464.1222.13 420,979.585,970,990.67 70° 19' 51.018 N 150° 38' 27.415 W 4,300.0 73.24 2,889.2 -1,940.1 -1,528.3222.13 420,914.625,970,920.33 70° 19' 50.320 N 150° 38' 29.290 W 4,400.0 73.24 2,918.0 -2,011.1 -1,592.6222.13 420,849.665,970,850.00 70° 19' 49.621 N 150° 38' 31.165 W 4,500.0 73.24 2,946.8 -2,082.1 -1,656.8222.13 420,784.705,970,779.67 70° 19' 48.923 N 150° 38' 33.040 W 4,600.0 73.24 2,975.7 -2,153.1 -1,721.0222.13 420,719.745,970,709.34 70° 19' 48.224 N 150° 38' 34.915 W 4,700.0 73.24 3,004.5 -2,224.1 -1,785.3222.13 420,654.785,970,639.00 70° 19' 47.526 N 150° 38' 36.790 W 4,800.0 73.24 3,033.4 -2,295.1 -1,849.5222.13 420,589.825,970,568.67 70° 19' 46.827 N 150° 38' 38.665 W 4,900.0 73.24 3,062.2 -2,366.1 -1,913.7222.13 420,524.865,970,498.34 70° 19' 46.129 N 150° 38' 40.540 W 5,000.0 73.24 3,091.1 -2,437.1 -1,978.0222.13 420,459.905,970,428.01 70° 19' 45.430 N 150° 38' 42.414 W 5,100.0 73.24 3,119.9 -2,508.1 -2,042.2222.13 420,394.945,970,357.67 70° 19' 44.732 N 150° 38' 44.289 W 5,200.0 73.24 3,148.7 -2,579.2 -2,106.4222.13 420,329.985,970,287.34 70° 19' 44.033 N 150° 38' 46.164 W 5,225.9 73.24 3,156.2 -2,597.5 -2,123.1222.13 420,313.155,970,269.12 70° 19' 43.852 N 150° 38' 46.649 W Seabee 5,300.0 73.24 3,177.6 -2,650.2 -2,170.7222.13 420,265.025,970,217.01 70° 19' 43.335 N 150° 38' 48.039 W 5,400.0 73.24 3,206.4 -2,721.2 -2,234.9222.13 420,200.065,970,146.68 70° 19' 42.636 N 150° 38' 49.913 W 5,500.0 73.24 3,235.3 -2,792.2 -2,299.1222.13 420,135.105,970,076.34 70° 19' 41.938 N 150° 38' 51.788 W 5,600.0 73.24 3,264.1 -2,863.2 -2,363.4222.13 420,070.145,970,006.01 70° 19' 41.239 N 150° 38' 53.662 W 5,700.0 73.24 3,292.9 -2,934.2 -2,427.6222.13 420,005.185,969,935.68 70° 19' 40.541 N 150° 38' 55.537 W 5,800.0 73.24 3,321.8 -3,005.2 -2,491.8222.13 419,940.225,969,865.35 70° 19' 39.842 N 150° 38' 57.411 W 5,900.0 73.24 3,350.6 -3,076.2 -2,556.1222.13 419,875.265,969,795.01 70° 19' 39.143 N 150° 38' 59.286 W 6,000.0 73.24 3,379.5 -3,147.2 -2,620.3222.13 419,810.305,969,724.68 70° 19' 38.445 N 150° 39' 1.160 W 6,100.0 73.24 3,408.3 -3,218.2 -2,684.6222.13 419,745.345,969,654.35 70° 19' 37.746 N 150° 39' 3.035 W 6,200.0 73.24 3,437.2 -3,289.2 -2,748.8222.13 419,680.385,969,584.02 70° 19' 37.048 N 150° 39' 4.909 W 6,300.0 73.24 3,466.0 -3,360.2 -2,813.0222.13 419,615.425,969,513.68 70° 19' 36.349 N 150° 39' 6.783 W 6,400.0 73.24 3,494.8 -3,431.2 -2,877.3222.13 419,550.465,969,443.35 70° 19' 35.651 N 150° 39' 8.658 W 6,500.0 73.24 3,523.7 -3,502.2 -2,941.5222.13 419,485.505,969,373.02 70° 19' 34.952 N 150° 39' 10.532 W 6,600.0 73.24 3,552.5 -3,573.3 -3,005.7222.13 419,420.545,969,302.69 70° 19' 34.253 N 150° 39' 12.406 W 6,700.0 73.24 3,581.4 -3,644.3 -3,070.0222.13 419,355.585,969,232.35 70° 19' 33.555 N 150° 39' 14.280 W 6,800.0 73.24 3,610.2 -3,715.3 -3,134.2222.13 419,290.625,969,162.02 70° 19' 32.856 N 150° 39' 16.155 W 6,900.0 73.24 3,639.0 -3,786.3 -3,198.4222.13 419,225.665,969,091.69 70° 19' 32.158 N 150° 39' 18.029 W 7,000.0 73.24 3,667.9 -3,857.3 -3,262.7222.13 419,160.705,969,021.36 70° 19' 31.459 N 150° 39' 19.903 W 7,084.9 73.24 3,692.4 -3,917.5 -3,317.2222.13 419,105.585,968,961.67 70° 19' 30.866 N 150° 39' 21.493 W Start DLS 3.00 TFO 93.57 7,085.1 73.24 3,692.4 -3,917.7 -3,317.3222.13 419,105.415,968,961.49 70° 19' 30.864 N 150° 39' 21.498 W 7,100.0 73.21 3,696.7 -3,928.3 -3,326.9222.60 419,095.705,968,951.06 70° 19' 30.761 N 150° 39' 21.778 W 7,200.0 73.05 3,725.8 -3,996.9 -3,393.6225.73 419,028.345,968,883.12 70° 19' 30.085 N 150° 39' 23.723 W 7,300.0 72.95 3,755.0 -4,061.7 -3,463.9228.86 418,957.415,968,819.01 70° 19' 29.447 N 150° 39' 25.773 W 7,400.0 72.89 3,784.4 -4,122.6 -3,537.6232.00 418,883.125,968,758.90 70° 19' 28.848 N 150° 39' 27.923 W 7,500.0 72.87 3,813.8 -4,179.4 -3,614.4235.14 418,805.665,968,702.97 70° 19' 28.290 N 150° 39' 30.166 W 7,600.0 72.91 3,843.3 -4,231.8 -3,694.3238.28 418,725.255,968,651.35 70° 19' 27.774 N 150° 39' 32.497 W 7,700.0 72.99 3,872.6 -4,279.8 -3,777.0241.42 418,642.105,968,604.20 70° 19' 27.301 N 150° 39' 34.909 W 7,703.9 73.00 3,873.7 -4,281.6 -3,780.2241.54 418,638.815,968,602.46 70° 19' 27.283 N 150° 39' 35.004 W Nanushuk 7,800.0 73.13 3,901.7 -4,323.3 -3,862.2244.55 418,556.465,968,561.64 70° 19' 26.873 N 150° 39' 37.395 W 7,802.0 73.13 3,902.3 -4,324.1 -3,863.9244.61 418,554.735,968,560.84 70° 19' 26.865 N 150° 39' 37.445 W NT8 MFS 7,862.6 73.23 3,919.8 -4,348.1 -3,916.7246.51 418,501.705,968,537.40 70° 19' 26.629 N 150° 39' 38.986 W NT7 MFS 6/11 /2023 10:59:30AM COMPASS 5000.17 Build 02 Page 5 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 7,900.0 73.31 3,930.6 -4,362.0 -3,949.7247.68 418,468.545,968,523.79 70° 19' 26.492 N 150° 39' 39.949 W 8,000.0 73.54 3,959.1 -4,396.0 -4,039.3250.80 418,378.595,968,490.75 70° 19' 26.157 N 150° 39' 42.564 W 8,100.0 73.81 3,987.3 -4,425.1 -4,130.8253.91 418,286.875,968,462.62 70° 19' 25.871 N 150° 39' 45.233 W 8,108.5 73.83 3,989.6 -4,427.3 -4,138.6254.18 418,279.005,968,460.46 70° 19' 25.848 N 150° 39' 45.461 W NT6 MFS 8,200.0 74.13 4,014.9 -4,449.2 -4,223.8257.02 418,193.615,968,439.47 70° 19' 25.633 N 150° 39' 47.947 W 8,300.0 74.49 4,041.9 -4,468.3 -4,318.1260.11 418,099.085,968,421.36 70° 19' 25.445 N 150° 39' 50.701 W 8,400.0 74.89 4,068.3 -4,482.3 -4,413.5263.19 418,003.535,968,408.35 70° 19' 25.306 N 150° 39' 53.485 W 8,408.1 74.93 4,070.5 -4,483.2 -4,421.3263.44 417,995.745,968,407.52 70° 19' 25.297 N 150° 39' 53.712 W NT5 MFS 8,500.0 75.34 4,094.0 -4,491.2 -4,509.8266.26 417,907.235,968,400.46 70° 19' 25.218 N 150° 39' 56.293 W 8,600.0 75.83 4,118.9 -4,494.9 -4,606.5269.32 417,810.445,968,397.73 70° 19' 25.181 N 150° 39' 59.118 W 8,700.0 76.35 4,143.0 -4,493.5 -4,703.6272.36 417,713.425,968,400.16 70° 19' 25.195 N 150° 40' 1.950 W 8,752.3 76.64 4,155.2 -4,490.7 -4,754.4273.95 417,662.645,968,403.48 70° 19' 25.222 N 150° 40' 3.433 W NT4 MFS 8,800.0 76.92 4,166.1 -4,486.9 -4,800.6275.39 417,616.455,968,407.74 70° 19' 25.259 N 150° 40' 4.783 W 8,900.0 77.51 4,188.2 -4,475.2 -4,897.4278.40 417,519.785,968,420.45 70° 19' 25.373 N 150° 40' 7.609 W 9,000.0 78.14 4,209.3 -4,458.4 -4,993.7281.40 417,423.695,968,438.25 70° 19' 25.538 N 150° 40' 10.419 W 9,100.0 78.81 4,229.3 -4,436.5 -5,089.2284.39 417,328.435,968,461.11 70° 19' 25.752 N 150° 40' 13.207 W 9,200.0 79.50 4,248.1 -4,409.6 -5,183.7287.36 417,234.275,968,488.95 70° 19' 26.016 N 150° 40' 15.964 W 9,300.0 80.22 4,265.7 -4,377.8 -5,276.8290.32 417,141.465,968,521.70 70° 19' 26.328 N 150° 40' 18.684 W 9,400.0 80.96 4,282.1 -4,341.2 -5,368.4293.27 417,050.265,968,559.26 70° 19' 26.688 N 150° 40' 21.358 W 9,500.0 81.73 4,297.1 -4,299.9 -5,458.2296.20 416,960.925,968,601.55 70° 19' 27.094 N 150° 40' 23.979 W 9,600.0 82.52 4,310.8 -4,253.9 -5,545.9299.12 416,873.685,968,648.43 70° 19' 27.545 N 150° 40' 26.540 W 9,700.0 83.33 4,323.2 -4,203.4 -5,631.3302.03 416,788.795,968,699.79 70° 19' 28.041 N 150° 40' 29.035 W 9,800.0 84.15 4,334.1 -4,148.6 -5,714.2304.93 416,706.475,968,755.47 70° 19' 28.580 N 150° 40' 31.456 W 9,900.0 84.99 4,343.5 -4,089.5 -5,794.4307.83 416,626.965,968,815.34 70° 19' 29.160 N 150° 40' 33.796 W 9,982.5 85.70 4,350.2 -4,037.8 -5,858.2310.21 416,563.655,968,867.73 70° 19' 29.668 N 150° 40' 35.661 W NT3 MFS 10,000.0 85.85 4,351.5 -4,026.4 -5,871.5310.71 416,550.465,968,879.21 70° 19' 29.780 N 150° 40' 36.050 W 10,100.0 86.71 4,358.0 -3,959.5 -5,945.5313.59 416,477.205,968,946.93 70° 19' 30.438 N 150° 40' 38.210 W 10,200.0 87.58 4,363.0 -3,888.8 -6,016.1316.47 416,407.365,969,018.30 70° 19' 31.132 N 150° 40' 40.272 W 10,300.0 88.46 4,366.4 -3,814.7 -6,083.1319.34 416,341.145,969,093.13 70° 19' 31.861 N 150° 40' 42.229 W 10,318.7 88.63 4,366.9 -3,800.4 -6,095.2319.87 416,329.155,969,107.53 70° 19' 32.001 N 150° 40' 42.584 W Start 100.0 hold at 10318.7 MD 10,318.9 88.63 4,366.9 -3,800.2 -6,095.3319.88 416,329.035,969,107.67 70° 19' 32.003 N 150° 40' 42.587 W 10,400.0 88.63 4,368.8 -3,738.3 -6,147.6319.88 416,277.455,969,170.18 70° 19' 32.612 N 150° 40' 44.113 W 10,416.2 88.63 4,369.2 -3,725.9 -6,158.0319.88 416,267.175,969,182.64 70° 19' 32.733 N 150° 40' 44.418 W NT3.2 Top Reservoir 10,417.0 88.63 4,369.2 -3,725.3 -6,158.5319.88 416,266.645,969,183.28 70° 19' 32.739 N 150° 40' 44.433 W 9-5/8" Intermediate Liner 10,418.7 88.63 4,369.3 -3,723.9 -6,159.6319.88 416,265.535,969,184.63 70° 19' 32.753 N 150° 40' 44.466 W Start DLS 3.00 TFO 70.47 10,418.9 88.63 4,369.3 -3,723.8 -6,159.8319.88 416,265.415,969,184.77 70° 19' 32.754 N 150° 40' 44.470 W 10,500.0 89.44 4,370.7 -3,660.8 -6,210.7322.17 416,215.095,969,248.30 70° 19' 33.373 N 150° 40' 45.959 W 10,600.0 90.45 4,370.8 -3,580.3 -6,270.1325.00 416,156.575,969,329.37 70° 19' 34.164 N 150° 40' 47.694 W 10,700.0 91.45 4,369.1 -3,497.0 -6,325.4327.83 416,102.145,969,413.21 70° 19' 34.983 N 150° 40' 49.310 W 10,753.2 91.98 4,367.5 -3,451.6 -6,353.2329.33 416,074.875,969,458.91 70° 19' 35.429 N 150° 40' 50.121 W Start 4665.1 hold at 10753.2 MD 10,753.4 91.99 4,367.5 -3,451.5 -6,353.2329.34 416,074.775,969,459.07 70° 19' 35.431 N 150° 40' 50.124 W 10,800.0 91.99 4,365.9 -3,411.4 -6,377.0329.34 416,051.465,969,499.34 70° 19' 35.824 N 150° 40' 50.818 W 10,900.0 91.99 4,362.4 -3,325.5 -6,427.9329.34 416,001.395,969,585.82 70° 19' 36.669 N 150° 40' 52.308 W 11,000.0 91.99 4,359.0 -3,239.5 -6,478.9329.34 415,951.325,969,672.31 70° 19' 37.514 N 150° 40' 53.798 W 11,100.0 91.99 4,355.5 -3,153.5 -6,529.9329.34 415,901.255,969,758.79 70° 19' 38.359 N 150° 40' 55.288 W 11,200.0 91.99 4,352.0 -3,067.6 -6,580.8329.34 415,851.185,969,845.27 70° 19' 39.204 N 150° 40' 56.778 W 11,300.0 91.99 4,348.6 -2,981.6 -6,631.8329.34 415,801.115,969,931.75 70° 19' 40.050 N 150° 40' 58.268 W 11,400.0 91.99 4,345.1 -2,895.6 -6,682.8329.34 415,751.045,970,018.24 70° 19' 40.895 N 150° 40' 59.758 W 11,500.0 91.99 4,341.6 -2,809.7 -6,733.7329.34 415,700.975,970,104.72 70° 19' 41.740 N 150° 41' 1.248 W 11,600.0 91.99 4,338.2 -2,723.7 -6,784.7329.34 415,650.905,970,191.20 70° 19' 42.585 N 150° 41' 2.738 W 11,700.0 91.99 4,334.7 -2,637.7 -6,835.7329.34 415,600.835,970,277.68 70° 19' 43.430 N 150° 41' 4.228 W 6/11 /2023 10:59:30AM COMPASS 5000.17 Build 02 Page 6 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 11,800.0 91.99 4,331.2 -2,551.7 -6,886.6329.34 415,550.775,970,364.17 70° 19' 44.275 N 150° 41' 5.718 W 11,900.0 91.99 4,327.8 -2,465.8 -6,937.6329.34 415,500.705,970,450.65 70° 19' 45.120 N 150° 41' 7.208 W 12,000.0 91.99 4,324.3 -2,379.8 -6,988.6329.34 415,450.635,970,537.14 70° 19' 45.965 N 150° 41' 8.698 W 12,100.0 91.99 4,320.8 -2,293.8 -7,039.5329.34 415,400.565,970,623.62 70° 19' 46.810 N 150° 41' 10.188 W 12,200.0 91.99 4,317.4 -2,207.9 -7,090.5329.34 415,350.505,970,710.10 70° 19' 47.655 N 150° 41' 11.679 W 12,300.0 91.99 4,313.9 -2,121.9 -7,141.4329.34 415,300.435,970,796.59 70° 19' 48.500 N 150° 41' 13.169 W 12,400.0 91.99 4,310.4 -2,035.9 -7,192.4329.34 415,250.375,970,883.07 70° 19' 49.345 N 150° 41' 14.659 W 12,500.0 91.99 4,307.0 -1,950.0 -7,243.4329.34 415,200.305,970,969.56 70° 19' 50.190 N 150° 41' 16.150 W 12,600.0 91.99 4,303.5 -1,864.0 -7,294.3329.34 415,150.235,971,056.04 70° 19' 51.035 N 150° 41' 17.640 W 12,700.0 91.99 4,300.0 -1,778.0 -7,345.3329.34 415,100.175,971,142.52 70° 19' 51.880 N 150° 41' 19.130 W 12,800.0 91.99 4,296.6 -1,692.0 -7,396.3329.34 415,050.105,971,229.01 70° 19' 52.725 N 150° 41' 20.621 W 12,900.0 91.99 4,293.1 -1,606.1 -7,447.2329.34 415,000.045,971,315.49 70° 19' 53.570 N 150° 41' 22.111 W 13,000.0 91.99 4,289.6 -1,520.1 -7,498.2329.34 414,949.985,971,401.98 70° 19' 54.415 N 150° 41' 23.602 W 13,100.0 91.99 4,286.2 -1,434.1 -7,549.1329.34 414,899.915,971,488.46 70° 19' 55.260 N 150° 41' 25.092 W 13,200.0 91.99 4,282.7 -1,348.2 -7,600.1329.34 414,849.855,971,574.95 70° 19' 56.105 N 150° 41' 26.583 W 13,300.0 91.99 4,279.2 -1,262.2 -7,651.1329.34 414,799.785,971,661.44 70° 19' 56.950 N 150° 41' 28.073 W 13,400.0 91.99 4,275.8 -1,176.2 -7,702.0329.34 414,749.725,971,747.92 70° 19' 57.795 N 150° 41' 29.564 W 13,500.0 91.99 4,272.3 -1,090.2 -7,753.0329.34 414,699.665,971,834.41 70° 19' 58.640 N 150° 41' 31.054 W 13,600.0 91.99 4,268.8 -1,004.3 -7,803.9329.34 414,649.595,971,920.89 70° 19' 59.485 N 150° 41' 32.545 W 13,700.0 91.99 4,265.4 -918.3 -7,854.9329.34 414,599.535,972,007.38 70° 20' 0.330 N 150° 41' 34.035 W 13,800.0 91.99 4,261.9 -832.3 -7,905.9329.34 414,549.475,972,093.87 70° 20' 1.175 N 150° 41' 35.526 W 13,900.0 91.99 4,258.4 -746.4 -7,956.8329.34 414,499.415,972,180.35 70° 20' 2.020 N 150° 41' 37.017 W 14,000.0 91.99 4,255.0 -660.4 -8,007.8329.34 414,449.355,972,266.84 70° 20' 2.865 N 150° 41' 38.507 W 14,100.0 91.99 4,251.5 -574.4 -8,058.7329.34 414,399.285,972,353.33 70° 20' 3.710 N 150° 41' 39.998 W 14,200.0 91.99 4,248.0 -488.4 -8,109.7329.34 414,349.225,972,439.81 70° 20' 4.555 N 150° 41' 41.489 W 14,300.0 91.99 4,244.6 -402.5 -8,160.6329.34 414,299.165,972,526.30 70° 20' 5.400 N 150° 41' 42.980 W 14,400.0 91.99 4,241.1 -316.5 -8,211.6329.34 414,249.105,972,612.79 70° 20' 6.245 N 150° 41' 44.471 W 14,500.0 91.99 4,237.6 -230.5 -8,262.6329.34 414,199.045,972,699.28 70° 20' 7.090 N 150° 41' 45.961 W 14,600.0 91.99 4,234.2 -144.5 -8,313.5329.34 414,148.985,972,785.76 70° 20' 7.935 N 150° 41' 47.452 W 14,700.0 91.99 4,230.7 -58.6 -8,364.5329.35 414,098.925,972,872.25 70° 20' 8.780 N 150° 41' 48.943 W 14,800.0 91.99 4,227.2 27.4 -8,415.4329.35 414,048.865,972,958.74 70° 20' 9.625 N 150° 41' 50.434 W 14,900.0 91.99 4,223.8 113.4 -8,466.4329.35 413,998.805,973,045.23 70° 20' 10.470 N 150° 41' 51.925 W 15,000.0 91.99 4,220.3 199.3 -8,517.3329.35 413,948.745,973,131.72 70° 20' 11.315 N 150° 41' 53.416 W 15,100.0 91.99 4,216.8 285.3 -8,568.3329.35 413,898.695,973,218.20 70° 20' 12.160 N 150° 41' 54.907 W 15,200.0 91.99 4,213.4 371.3 -8,619.2329.35 413,848.635,973,304.69 70° 20' 13.005 N 150° 41' 56.398 W 15,300.0 91.99 4,209.9 457.3 -8,670.2329.35 413,798.575,973,391.18 70° 20' 13.850 N 150° 41' 57.889 W 15,400.0 91.99 4,206.4 543.2 -8,721.2329.35 413,748.515,973,477.67 70° 20' 14.695 N 150° 41' 59.380 W 15,418.0 91.99 4,205.8 558.7 -8,730.3329.35 413,739.505,973,493.24 70° 20' 14.847 N 150° 41' 59.649 W 4-1/2" Liner 15,418.4 91.99 4,205.8 559.0 -8,730.5329.35 413,739.325,973,493.56 70° 20' 14.850 N 150° 41' 59.654 W TD at 15418.4 15,418.6 91.99 4,205.8 559.2 -8,730.6329.35 413,739.215,973,493.74 70° 20' 14.852 N 150° 41' 59.657 W 6/11 /2023 10:59:30AM COMPASS 5000.17 Build 02 Page 7 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Design Targets LongitudeLatitude Dip Angle (°) Dip Dir. (°) NDBi-014 Toe v.0 4,205.8 5,973,493.74 413,739.21559.2 -8,730.60.00 0.00 70° 20' 14.852 N 150° 41' 59.657 W - plan hits target center - Point NDBi-014 Heel V1.0 4,367.5 5,969,459.07 416,074.77-3,451.5 -6,353.20.00 0.00 70° 19' 35.431 N 150° 40' 50.124 W - plan hits target center - Point NDBi-14 Geological P 4,367.5 5,969,459.07 416,074.77-3,451.5 -6,353.25.00 215.00 70° 19' 35.431 N 150° 40' 50.124 W - plan hits target center - Polygon -543.2Point 1 5,968,910.65 416,623.104,378.6 553.7 True 4,377.8Point 2 5,973,853.65 413,762.104,172.6 -2,353.3 True 4,172.1Point 3 5,973,652.65 413,416.104,204.5 -2,698.1 True -748.5Point 4 5,968,710.05 416,277.104,410.5 209.0 True Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing127.0127.0 20 20 13-3/8" Surface Casing2,295.12,567.0 13-3/8 16 9-5/8" Intermediate Liner4,369.210,417.0 9-5/8 12-1/4 4-1/2" Liner4,205.815,418.0 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,053.0 Upper Schrader Bluff 0.001,046.0 1,148.4 Base Ice Bearing Permafrost 0.001,138.9 1,411.6 Base Permafrost Transition 0.001,390.7 1,795.5 Middle Schrader Bluff 0.001,735.1 2,328.4 MCU 0.002,144.9 2,861.9 Tuluvak Shale 0.002,447.2 3,002.4 Tuluvak Sand 0.002,505.7 5,225.9 Seabee 0.003,156.2 7,703.9 Nanushuk 0.003,873.7 7,802.0 NT8 MFS 0.003,902.3 7,862.6 NT7 MFS 0.003,919.8 8,108.5 NT6 MFS 0.003,989.6 8,408.1 NT5 MFS4,070.5 8,752.3 NT4 MFS4,155.2 9,982.5 NT3 MFS4,350.2 10,416.2 NT3.2 Top Reservoir4,369.2 6/11/2023 10:59:30AM COMPASS 5000.17 Build 02 Page 8 Planning Report -Geographic Well NDBi-014Local Co-ordinate Reference:Database:EDM STO Alaska Plan: Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Plan: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:NDBi-014Well: NDBi-014Wellbore: Plan: NDBi-014 Rev D.0Design: Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 47.0 47.0 0.0 0.0 Start 300.0 hold at 47.0 MD 347.0 347.0 0.0 0.0 Start Build 2.00 647.0 646.5 -15.2 4.1 Start DLS 2.50 TFO 53.68 995.6 990.2 -70.8 -3.1 Start 154.0 hold at 995.6 MD 1,149.6 1,140.1 -104.3 -13.6 Start DLS 3.00 TFO 27.19 3,195.4 2,570.6 -1,155.8 -818.8 Start 3889.4 hold at 3195.4 MD 7,084.9 3,692.4 -3,917.5 -3,317.2 Start DLS 3.00 TFO 93.57 10,318.7 4,366.9 -3,800.4 -6,095.2 Start 100.0 hold at 10318.7 MD 10,418.7 4,369.3 -3,723.9 -6,159.6 Start DLS 3.00 TFO 70.47 10,753.2 4,367.5 -3,451.6 -6,353.2 Start 4665.1 hold at 10753.2 MD 15,418.4 4,205.8 559.0 -8,730.5 TD at 15418.4 6/11/2023 10:59:30AM COMPASS 5000.17 Build 02 Page 9 -1 5 0 0 0 15 0 0 30 0 0 45 0 0 60 0 0 True Vertical Depth -1 5 0 0 0 1 5 0 0 3 0 0 0 4 5 0 0 6 0 0 0 7 5 0 0 9 0 0 0 Ve r t i c a l S e c t i o n a t 2 7 3 . 6 6 ° 20 " C o n d u c t o r C a s i n g 13 - 3 / 8 " S u r f a c e C a s i n g 9- 5 / 8 " I n t e r m e d i a t e L i n e r 4- 1 / 2 " x 6 - 1 / 8 " L i n e r 10 0 0 2 0 0 0 30 0 0 4000 500 0 6000 7000 8000 9000 10000 11000 1 2 000 13000 14000 15 0 0 0 1 5 418 0° 3 0 ° 6 0 ° 73° 90° 92 ° Pla n: NDB i -01 4 Rev D.0 Up p e r S c h r a d e r B l u f f Ba s e I c e B e a r i n g P e r m a f r o s t Ba s e P e r m a f r o s t T r a n s i t i o n Mi d d l e S c h r a d e r B l u f f MC U Tu l u v a k S h a l e Tu l u v a k S a n d Se a b e e Na n u s h u k NT 8 M F S NT 7 M F S NT 6 M F S NT 5 M F S NT 4 M F S NT 3 M F S NT 3 . 2 T o p R e s e r v o i r Pl a n : N D B i - 0 1 4 R e v D . 0 9: 5 0 , N o v e m b e r 0 6 2 0 2 3 -4 5 0 0 -3 0 0 0 -1 5 0 0 0 South(-)/North(+) -9 0 0 0 - 7 5 0 0 - 6 0 0 0 - 4 5 0 0 - 3 0 0 0 - 1 5 0 0 0 We s t ( - ) / E a s t ( + ) ND B i - 0 1 4 T o e v . 0 ND B i - 1 4 G e o l o g i c a l P o l y g o n 95 % ND B i - 0 1 4 H e e l V 1 . 0 ND B i - 0 1 4 _ H e e l 20 " C o n d u c t o r C a s i n g 13 - 3 / 8 " S u r f a c e C a s i n g 9- 5 / 8 " I n t e r m e d i a t e L i n e r 4- 1 / 2 " L i n e r P l a n : N D B i - 0 1 4 R e v D . 0 Pl a n : N D B i - 0 1 4 R e v D . 0 9: 5 7 , N o v e m b e r 0 6 2 0 2 3 06 November, 2023 Anticollision Summary Report Santos Pikka NDB NDBi-014 NDBi-014 Plan: NDBi-014 Rev D.0 Anticollision Summary Report Well NDBi-014 -Slot B-14Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Plan: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-014Reference Well: Output errors are at 2.79 sigmaWell Error:0.9 usft Reference Wellbore NDBi-014 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-014 Rev D.0 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Trav. Cylinder North Combined Pedal Curve GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.0usft Unlimited Maximum centre distance of 1,000,000.0usft Plan: NDBi-014 Rev D.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 6/11/2023 SDI_KPR_ADK SDI Keeper ADK47.0 300.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag300.0 1,300.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag300.0 2,567.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag2,567.0 3,567.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,567.0 10,417.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag A012Mb: IIFR dec correction + sag10,417.0 11,417.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag10,417.0 15,418.4 Plan: NDBi-014 Rev D.0 (NDBi-014) 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 CCB-02 - Wellbore #1 - 12.1 344.8 275.0 240.1 228.8 35.676 ESB-02 - Wellbore #1 - 12.1 369.8 300.0 240.1 228.7 35.498 SFB-02 - Wellbore #1 - 12.1 568.3 500.0 249.1 237.2 34.704 CCB-04 - Wellbore #1 - 12.0 344.8 275.0 200.0 188.7 29.660 ESB-04 - Wellbore #1 - 12.0 369.8 300.0 200.0 188.7 29.512 SFB-04 - Wellbore #1 - 12.0 640.7 575.0 209.1 197.0 28.203 CCB-05 - Wellbore #1 - 12.0 344.8 275.0 180.1 168.8 26.666 ESB-05 - Wellbore #1 - 12.0 394.8 325.0 180.1 168.7 26.398 SFB-05 - Wellbore #1 - 12.0 663.5 600.0 189.1 176.8 25.189 CCB-06 - Wellbore #1 - 12.0 344.8 275.0 160.0 148.7 23.658 ESB-06 - Wellbore #1 - 12.0 469.7 400.0 160.1 148.5 22.953 SFB-06 - Wellbore #1 - 12.0 688.6 625.0 166.0 153.7 21.837 CCB-07 - Wellbore #1 - 12.0 344.8 275.0 140.0 128.7 20.650 ESB-07 - Wellbore #1 - 12.0 394.8 325.0 140.0 128.6 20.443 SFB-07 - Wellbore #1 - 12.0 616.6 550.0 145.3 133.3 19.709 CCB-09 - Wellbore #1 - 12.0 344.8 275.0 99.9 88.6 14.638 ESB-09 - Wellbore #1 - 12.0 394.8 325.0 99.9 88.5 14.491 SFB-09 - Wellbore #1 - 12.0 568.1 500.0 102.7 90.8 14.106 CCNDB-010 - NDB-010 - Plan: NDB-010 Rev A.0 324.8 325.0 79.9 70.6 15.324 ESNDB-010 - NDB-010 - Plan: NDB-010 Rev A.0 474.7 475.0 80.0 70.3 14.447 SFNDB-010 - NDB-010 - Plan: NDB-010 Rev A.0 622.8 625.0 83.2 72.9 13.785 CCNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 1,576.0 1,600.0 55.4 37.1 4.331 ESNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 1,624.8 1,650.0 55.8 36.8 4.162 SFNDB-011 - NDB-011 - Plan: NDB-011 Rev A.0 1,796.3 1,825.0 61.7 39.9 3.940 CCNDB-013 - NDB-013 - Plan: NDB-013 Rev A.0 324.8 325.0 19.8 10.5 3.441 ESNDB-013 - NDB-013 - Plan: NDB-013 Rev A.0 424.8 425.0 19.9 10.3 3.321 SFNDB-013 - NDB-013 - Plan: NDB-013 Rev A.0 449.7 450.0 19.9 10.3 3.296 CCNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 324.8 325.0 20.2 10.9 3.521 ESNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 374.8 375.0 20.3 10.9 3.469 SFNDB-015 - NDB-015 - Plan: NDB-015 Rev A.0 399.8 400.0 20.4 10.9 3.460 CCNDB-02 - NDB-02 - Plan: NDB-02 Rev A.0 324.8 325.0 240.1 230.8 46.857 ESNDB-02 - NDB-02 - Plan: NDB-02 Rev A.0 349.8 350.0 240.1 230.7 46.478 SFNDB-02 - NDB-02 - Plan: NDB-02 Rev A.0 667.8 675.0 265.5 254.9 43.299 CCNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 424.8 425.0 140.4 130.8 26.052 ESNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 574.9 575.0 140.4 130.3 24.132 SFNDB-021 - NDB-021 - Plan: NDB-021 Rev A.0 11,687.6 9,300.0 1,033.2 945.5 15.120 CCNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 399.8 400.0 160.4 150.9 30.142 6/11 /2023 9:35:53AM 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-014 -Slot B-14Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Plan: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-014Reference Well: Output errors are at 2.79 sigmaWell Error:0.9 usft Reference Wellbore NDBi-014 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-014 Rev D.0 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB ESNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 474.5 475.0 160.5 150.7 29.129 SFNDB-022 - NDB-022 - Plan NDB-022 Rev A.0 745.0 750.0 176.0 165.0 26.820 CCNDB-024 - NDB-024 - NDB-024 499.0 500.0 199.2 189.7 36.942 ESNDB-024 - NDB-024 - NDB-024 523.5 525.0 199.2 189.6 36.650 SFNDB-024 - NDB-024 - NDB-024 742.6 750.0 213.6 203.3 35.477 CCNDB-024 - NDB-024 - NDB-024 Rev F.0 499.3 500.0 199.2 189.6 36.938 ESNDB-024 - NDB-024 - NDB-024 Rev F.0 523.8 525.0 199.2 189.6 36.647 SFNDB-024 - NDB-024 - NDB-024 Rev F.0 742.9 750.0 213.6 203.3 35.477 CCNDB-024 - NDB-024PB1 - NDB-024PB1 499.3 500.0 199.2 189.6 36.938 ESNDB-024 - NDB-024PB1 - NDB-024PB1 523.8 525.0 199.2 189.6 36.647 SFNDB-024 - NDB-024PB1 - NDB-024PB1 742.9 750.0 213.6 203.3 35.477 CCNDB-024 - NDB-024PB1 - Plan: NDB-024PB1 Rev A.3 425.3 425.0 199.7 190.3 38.037 ESNDB-024 - NDB-024PB1 - Plan: NDB-024PB1 Rev A.3 475.0 475.0 199.7 190.2 37.348 SFNDB-024 - NDB-024PB1 - Plan: NDB-024PB1 Rev A.3 985.5 1,000.0 263.6 249.7 29.886 CCNDB-025 - NDB-025 - Plan: NDB-25 Rev A.0 499.2 500.0 219.9 210.2 40.193 ESNDB-025 - NDB-025 - Plan: NDB-25 Rev A.0 624.2 625.0 219.9 209.8 37.906 SFNDB-025 - NDB-025 - Plan: NDB-25 Rev A.0 4,785.2 4,525.0 495.4 393.0 6.173 CCNDB-031 - NDB-031 - Plan: NDB-031 Rev A.0 524.9 525.0 340.7 330.8 61.276 ESNDB-031 - NDB-031 - Plan: NDB-031 Rev A.0 707.0 700.0 340.8 330.1 54.874 SFNDB-031 - NDB-031 - Plan: NDB-031 Rev A.0 3,495.5 3,125.0 513.7 453.8 11.137 CCNDB-04 - NDB-04 - Plan: NDB-04 Rev A.0 324.8 325.0 200.0 190.7 38.955 ESNDB-04 - NDB-04 - Plan: NDB-04 Rev A.0 349.8 350.0 200.0 190.6 38.640 SFNDB-04 - NDB-04 - Plan: NDB-04 Rev A.0 711.1 725.0 220.9 210.1 34.748 CCNDB-045 - NDB-045 - Plan: NDB-045 Rev A.0 425.0 425.0 621.1 611.5 117.675 ESNDB-045 - NDB-045 - Plan: NDB-045 Rev A.0 575.3 575.0 621.1 611.0 109.118 SFNDB-045 - NDB-045 - Plan: NDB-045 Rev A.0 3,489.4 2,925.0 944.6 882.7 19.943 CCNDB-048 - NDB-048 - Plan: NDB-048 Rev A.0 524.8 525.0 681.1 671.2 122.760 ESNDB-048 - NDB-048 - Plan: NDB-048 Rev A.0 598.8 600.0 681.2 671.0 117.508 SFNDB-048 - NDB-048 - Plan: NDB-048 Rev A.0 15,418.4 12,400.0 1,800.2 1,573.9 10.026 CCNDB-05 - NDB-05 - Plan: NDB-05 Rev A.0 324.8 325.0 180.1 170.8 35.024 ESNDB-05 - NDB-05 - Plan: NDB-05 Rev A.0 374.8 375.0 180.1 170.7 34.453 SFNDB-05 - NDB-05 - Plan: NDB-05 Rev A.0 689.5 700.0 194.0 183.2 30.999 CCNDB-051 - NDB-051 - Plan: NDB-051 Rev A.0 324.8 325.0 741.2 731.9 145.629 ESNDB-051 - NDB-051 - Plan: NDB-051 Rev A.0 349.8 350.0 741.2 731.8 144.453 SFNDB-051 - NDB-051 - Plan: NDB-051 Rev A.0 13,786.8 9,550.0 1,304.6 1,172.0 12.510 CCNDB-09 - NDB-09 - Plan: NDB-09 Rev A.0 324.8 325.0 99.9 90.6 19.227 ESNDB-09 - NDB-09 - Plan: NDB-09 Rev A.0 374.8 375.0 99.9 90.5 18.912 SFNDB-09 - NDB-09 - Plan: NDB-09 Rev A.0 596.9 600.0 105.1 94.9 17.775 CCNDBi-012 - NDBi-012 - Plan: NDBi-012 Rev A.0 349.8 350.0 39.9 30.5 7.334 ESNDBi-012 - NDBi-012 - Plan: NDBi-012 Rev A.0 399.8 400.0 39.9 30.4 7.210 SFNDBi-012 - NDBi-012 - Plan: NDBi-012 Rev A.0 474.4 475.0 40.5 30.8 7.080 CCNDBi-016 - NDBi-016 - Plan: NDBi-016 Rev A.0 374.8 375.0 39.9 30.5 7.274 ESNDBi-016 - NDBi-016 - Plan: NDBi-016 Rev A.0 449.8 450.0 39.9 30.3 7.056 SFNDBi-016 - NDBi-016 - Plan: NDBi-016 Rev A.0 499.6 500.0 40.4 30.6 6.968 CCNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev F.0 425.3 425.0 79.9 70.4 14.732 ESNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev F.0 500.2 500.0 80.0 70.3 14.349 SFNDBi-018 - NDBi-018 - Plan: NDBi-018 Rev F.0 774.4 775.0 90.0 79.1 13.594 CCNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 324.8 325.0 100.3 91.0 19.299 ESNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 549.9 550.0 100.4 90.4 17.539 SFNDBi-019 - NDBi-019 - Plan: NDBi-019 Rev A.0 1,038.9 1,025.0 128.4 115.3 15.704 CCNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 399.8 400.0 120.3 110.8 22.659 ESNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 449.7 450.0 120.4 110.7 22.171 SFNDBi-020 - NDBi-020 - Plan: NDBi-020 Rev A.0 645.1 650.0 127.0 116.5 20.888 CCNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 425.5 425.0 240.5 230.9 45.234 ESNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 475.3 475.0 240.5 230.8 44.216 SFNDBi-026 - NDBi-026 - Plan: NDBi-026 Rev A.0 945.2 950.0 284.2 271.8 37.449 CCNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 324.8 325.0 280.6 271.3 54.836 ESNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 550.1 550.0 280.6 270.7 49.791 SFNDBi-028 - NDBi-028 - Plan NDBi-028 Rev A.0 3,504.5 3,100.0 477.4 427.5 12.608 6/11 /2023 9:35:53AM 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-014 -Slot B-14Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Plan: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-014Reference Well: Output errors are at 2.79 sigmaWell Error:0.9 usft Reference Wellbore NDBi-014 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-014 Rev D.0 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB CCNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 474.7 475.0 540.9 531.2 100.007 ESNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 548.7 550.0 541.0 531.0 96.074 SFNDBi-041 - NDBi-041 - Plan: NDBi-041 Rev A.0 15,409.5 8,700.0 1,828.0 1,642.7 12.485 CCNDBi-044 - NDBi-044 - Plan: NDBi-044 Rev G.0 800.8 775.0 599.6 588.6 91.514 ES, SFNDBi-044 - NDBi-044 - Plan: NDBi-044 Rev G.0 15,412.6 9,725.0 667.5 458.9 4.038 CCNDBi-046 - NDBi-046 - Plan: NDBi-046 Rev A.0 499.8 500.0 639.7 629.9 116.925 ESNDBi-046 - NDBi-046 - Plan: NDBi-046 Rev A.0 573.9 575.0 639.8 629.7 112.015 SFNDBi-046 - NDBi-046 - Plan: NDBi-046 Rev A.0 14,392.0 9,925.0 908.1 750.8 7.317 CCNDBi-050 - NDBi-050 - Plan: NDBi-050 Rev A.0 474.8 475.0 721.1 711.4 133.487 ESNDBi-050 - NDBi-050 - Plan: NDBi-050 Rev A.0 548.9 550.0 721.2 711.2 128.215 SFNDBi-050 - NDBi-050 - Plan: NDBi-050 Rev A.0 12,341.3 9,000.0 1,238.0 1,147.0 17.446 CCNDBi-06 - NDBi-06 - Plan: NDBi-06 Rev A.0 324.8 325.0 160.0 150.7 31.073 ESNDBi-06 - NDBi-06 - Plan: NDBi-06 Rev A.0 474.6 475.0 160.1 150.4 29.285 SFNDBi-06 - NDBi-06 - Plan: NDBi-06 Rev A.0 715.3 725.0 170.2 159.3 26.699 CCNDBi-07 - NDBi-007 - Plan: NDBi-007 Rev A.0 324.8 325.0 140.0 130.7 27.123 ESNDBi-07 - NDBi-007 - Plan: NDBi-007 Rev A.0 374.8 375.0 140.0 130.6 26.680 SFNDBi-07 - NDBi-007 - Plan: NDBi-007 Rev A.0 644.8 650.0 148.8 138.4 24.513 Qugruk 3 CCQugruk 3 - Qugruk 3 - Qugruk 3 14,322.5 4,125.0 1,553.4 1,405.7 13.355 ESQugruk 3 - Qugruk 3 - Qugruk 3 14,330.9 4,100.0 1,553.4 1,405.5 13.341 SFQugruk 3 - Qugruk 3 - Qugruk 3 14,347.8 4,050.0 1,554.5 1,406.4 13.330 CC, ES, SFQugruk 3 - Quguruk 3A - Quguruk 3A 15,416.2 4,200.0 1,311.5 1,129.8 9.135 CC, ES, SFQugruk 301 - Qugruk 301 - Qugruk 301 15,417.6 4,075.0 965.5 786.2 6.813 Wildcat CC, ESQugruk-3 - Qugruk-3 - Qugruk-3 14,349.0 4,075.0 1,578.6 1,427.7 13.280 SFQugruk-3 - Qugruk-3 - Qugruk-3 14,357.2 4,050.0 1,578.8 1,427.9 13.280 CC, ES, SFQugruk-3 - Qugruk-3A - Qugruk -3A 15,415.7 4,200.0 1,312.2 1,125.3 8.882 CC, ES, SFQugruk-301 - Qugruk-301 - Qugruk-301 15,417.6 4,075.0 965.5 786.9 6.839 6/11/2023 9:35:53AM 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-014 -Slot B-14Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Plan: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-014Reference Well: Output errors are at 2.79 sigmaWell Error:0.9 usft Reference Wellbore NDBi-014 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-014 Rev D.0 Offset TVD Reference: 0 6000 12000 18000 24000 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 Measured Depth Ladder Plot Qugruk 3, Qugruk 3, Qugruk 3 V0 Qugruk 3, Quguruk 3A, Quguruk 3A V0 Qugruk 301, Qugruk 301, Qugruk 301 V0 NDB-010, NDB-010, Plan: NDB-010 Rev A.0 V0 NDB-011, NDB-011, Plan: NDB-011 Rev A.0 V0 NDB-013, NDB-013, Plan: NDB-013 Rev A.0 V0 NDB-015, NDB-015, Plan: NDB-015 Rev A.0 V0 NDB-02, NDB-02, Plan: NDB-02 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-024, NDB-024 Rev F.0 V0 NDB-024, NDB-024PB1, NDB-024PB1 V0 NDB-024, NDB-024PB1, Plan: NDB-024PB1 Rev A.3 V0 NDB-025, NDB-025, Plan: NDB-25 Rev A.0 V0 NDB-031, NDB-031, Plan: NDB-031 Rev A.0 V0 NDB-04, NDB-04, Plan: NDB-04 Rev A.0 V0 NDB-045, NDB-045, Plan: NDB-045 Rev A.0 V0 NDB-048, NDB-048, Plan: NDB-048 Rev A.0 V0 NDB-05, NDB-05, Plan: NDB-05 Rev A.0 V0 NDB-051, NDB-051, Plan: NDB-051 Rev A.0 V0 NDB-09, NDB-09, Plan: NDB-09 Rev A.0 V0 NDBi-012, NDBi-012, Plan: NDBi-012 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-041, NDBi-041, Plan: NDBi-041 Rev A.0 V0 NDBi-044, NDBi-044, Plan: NDBi-044 Rev G.0 V0 NDBi-046, NDBi-046, Plan: NDBi-046 Rev A.0 V0 NDBi-050, NDBi-050, Plan: NDBi-050 Rev A.0 V0 NDBi-06, NDBi-06, Plan: NDBi-06 Rev A.0 V0 NDBi-07, NDBi-007, Plan: NDBi-007 Rev A.0 V0 Qugruk-3, Qugruk-3, Qugruk-3 V0 Qugruk-3, Qugruk-3A, Qugruk-3A V0 Qugruk-301, Qugruk-301, Qugruk-301 V0 B-02, Wellbore #1, 12.1 V0 B-04, Wellbore #1, 12.0 V0 B-05, Wellbore #1, 12.0 V0 B-06, Wellbore #1, 12.0 V0 B-07, Wellbore #1, 12.0 V0 B-09, Wellbore #1, 12.0 V0 L E G E N D Coordinates are relative to: NDBi-014 - Slot B-14 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 @ 69.8usft 6/11/2023 9:35:53AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 Anticollision Summary Report Well NDBi-014 -Slot B-14Local Co-ordinate Reference:SantosCompany: Plan: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Plan: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:NDBi-014Reference Well: Output errors are at 2.79 sigmaWell Error:0.9 usft Reference Wellbore NDBi-014 Database:EDM STO Alaska Offset DatumReference Design:Plan: NDBi-014 Rev D.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 Se p a r a t i o n F a c t o r 0 3000 6000 9000 12000 15000 Measured Depth Level 1 Level 3 Level 4 Separation Factor Plot Qugruk 3, Qugruk 3, Qugruk 3 V0 Qugruk 3, Quguruk 3A, Quguruk 3A V0 Qugruk 301, Qugruk 301, Qugruk 301 V0 NDB-010, NDB-010, Plan: NDB-010 Rev A.0 V0 NDB-011, NDB-011, Plan: NDB-011 Rev A.0 V0 NDB-013, NDB-013, Plan: NDB-013 Rev A.0 V0 NDB-015, NDB-015, Plan: NDB-015 Rev A.0 V0 NDB-02, NDB-02, Plan: NDB-02 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-024, NDB-024 Rev F.0 V0 NDB-024, NDB-024PB1, NDB-024PB1 V0 NDB-024, NDB-024PB1, Plan: NDB-024PB1 Rev A.3 V0 NDB-025, NDB-025, Plan: NDB-25 Rev A.0 V0 NDB-031, NDB-031, Plan: NDB-031 Rev A.0 V0 NDB-04, NDB-04, Plan: NDB-04 Rev A.0 V0 NDB-045, NDB-045, Plan: NDB-045 Rev A.0 V0 NDB-048, NDB-048, Plan: NDB-048 Rev A.0 V0 NDB-05, NDB-05, Plan: NDB-05 Rev A.0 V0 NDB-051, NDB-051, Plan: NDB-051 Rev A.0 V0 NDB-09, NDB-09, Plan: NDB-09 Rev A.0 V0 NDBi-012, NDBi-012, Plan: NDBi-012 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-041, NDBi-041, Plan: NDBi-041 Rev A.0 V0 NDBi-044, NDBi-044, Plan: NDBi-044 Rev G.0 V0 NDBi-046, NDBi-046, Plan: NDBi-046 Rev A.0 V0 NDBi-050, NDBi-050, Plan: NDBi-050 Rev A.0 V0 NDBi-06, NDBi-06, Plan: NDBi-06 Rev A.0 V0 NDBi-07, NDBi-007, Plan: NDBi-007 Rev A.0 V0 Qugruk-3, Qugruk-3, Qugruk-3 V0 Qugruk-3, Qugruk-3A, Qugruk-3A V0 Qugruk-301, Qugruk-301, Qugruk-301 V0 B-02, Wellbore #1, 12.1 V0 B-04, Wellbore #1, 12.0 V0 B-05, Wellbore #1, 12.0 V0 B-06, Wellbore #1, 12.0 V0 B-07, Wellbore #1, 12.0 V0 B-09, Wellbore #1, 12.0 V0 L E G E N D Coordinates are relative to: NDBi-014 - Slot B-14 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 @ 69.8usft 6/11/2023 9:35:53AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 6 Northing (6000 usft/in) Ea s t i n g ( 6 0 0 0 u s f t / i n ) Northing (6000 usft/in) Ea s t i n g ( 6 0 0 0 u s f t / i n ) Qu g r u k 3 Qu g u r u k 3 A Qu g r u k 3 0 1 Pl a n : N D B - 0 1 0 R e v A . 0 Pl a n : N D B - 0 1 1 R e v A . 0 Pl a n : N D B - 0 1 3 R e v A . 0 Pl a n : N D B - 0 1 5 R e v A . 0 Pl a n : N D B - 0 2 R e v A . 0 Pl a n : N D B - 0 2 1 R e v A . 0 Pl a n N D B - 0 2 2 R e v A . 0 Pl a n : N D B - 2 5 R e v A . 0 Pl a n : N D B - 0 3 1 R e v A . 0 Pl a n : N D B - 0 4 R e v A . 0 Pl a n : N D B - 0 4 5 R e v A . 0 Pl a n : N D B - 0 4 8 R e v A . 0 Pl a n : N D B - 0 5 R e v A . 0 Pl a n : N D B - 0 5 1 R e v A . 0 Pl a n : N D B - 0 9 R e v A . 0 Pl a n : N D B i - 0 1 2 R e v A . 0 Pl a n : N D B i - 0 1 6 R e v A . 0 Pl a n : N D B i - 0 1 8 R e v F . 0 Pl a n : N D B i - 0 1 9 R e v A . 0 Pl a n : N D B i - 0 2 0 R e v A . 0 Pl a n : N D B i - 0 2 6 R e v A . 0 Pl a n N D B i - 0 2 8 R e v A . 0 Pl a n : N D B i - 0 4 1 R e v A . 0 Pl a n : N D B i - 0 4 4 R e v G . 0 Pl a n : N D B i - 0 4 6 R e v A . 0 Pl a n : N D B i - 0 5 0 R e v A . 0 Pl a n : N D B i - 0 6 R e v A . 0 Pl a n : N D B i - 0 0 7 R e v A . 0 Qu g r u k - 3 Qu g r u k - 3 A Qu g r u k - 3 0 1 1000 2000 3 0 0 0 4000 Pl a n : N D B i - 0 1 4 R e v D . 0 ND B NP F 10 : 1 7 , N o v e m b e r 0 6 2 0 2 3 Pl a n : N D B i - 0 1 4 R e v D . 0 AC F l i p b o o k SU R V E Y P R O G R A M De p t h F r o m D e p t h T o T o o l 47 . 0 3 0 0 . 0 S D I _ K P R _ A D K 30 0 . 0 1 3 0 0 . 0 3 _ M W D + I F R 2 + S a g 30 0 . 0 2 5 6 7 . 0 3 _ M W D + I F R 2 + M S + S a g 25 6 7 . 0 3 5 6 7 . 0 3 _ M W D + I F R 2 + S a g 25 6 7 . 0 1 0 4 1 7 . 0 3 _ M W D + I F R 2 + M S + S a g 10 4 1 7 . 0 1 1 4 1 7 . 0 3 _ M W D + I F R 2 + S a g 10 4 1 7 . 0 1 5 4 1 8 . 4 3 _ M W D + I F R 2 + M S + S a g CA S I N G D E T A I L S TV D M D N a m e 12 7 . 0 1 2 7 . 0 2 0 " C o n d u c t o r C a s i n g 22 9 5 . 1 2 5 6 7 . 0 1 3 - 3 / 8 " S u r f a c e C a s i n g 43 6 9 . 3 1 0 4 1 7 . 0 9 - 5 / 8 " I n t e r m e d i a t e L i n e r 42 0 5 . 8 1 5 4 1 8 . 0 4 - 1 / 2 " L i n e r 10 1020 2030 3040 4050 5060 60 0 90 18 0 27 0 30 21 0 60 24 0 12 0 30 0 15 0 33 0 Tr a v e l l i n g C y l i n d e r A z i m u t h ( T F O + A Z I ) [ ° ] v s T r a v e l l i n g C y l i n d e r S e p a r a t i o n [ 2 0 u s f t / i n ] 707510 0 12 5 15 0 17 5 20 0 22 5 25 0 27 5 30 0 32 5 35 0 37 5 40 0 42 5 45 0 47 5 50 0 52 5 54 9 57 4 59 9 62 4 64 9 67 3 69 8 72 2 74 6 77 1 79 5 81 9 84 4 86 8 89 2 91 6 11 3 9 11 6 4 11 8 8 12 1 2 12 3 6 12 6 0 12 8 4 13 0 9 13 3 3 13 5 7 13 8 1 14 0 6 14 3 0 14 5 4 14 7 8 15 0 3 15 2 7 15 5 2 15 7 6 16 0 0 16 2 5 16 4 9 16 7 4 16 9 8 17 2 3 17 4 7 17 7 2 17 9 6 18 2 1 18 4 5 18 7 0 18 9 5 Pl a n : N D B - 0 1 1 R e v A . 0 707510 0 12 5 15 0 17 5 20 0 22 5 25 0 27 5 30 0 32 5 35 0 37 5 40 0 42 5 45 0 47 5 49 9 52 4 54 9 57 3 59 8 62 2 64 6 67 0 69 4 71 7 74 1 76 4 Pl a n : N D B - 0 1 3 R e v A . 0 707510 0 12 5 15 0 17 5 20 0 22 5 25 0 27 5 30 0 32 5 35 0 37 5 40 0 42 5 45 0 47 4 49 9 52 4 54 8 57 3 59 7 62 1 64 5 66 9 69 3 71 7 Pl a n : N D B - 0 1 5 R e v A . 0 707510 0 12 5 15 0 17 5 20 0 22 5 25 0 27 5 30 0 32 5 35 0 37 5 40 0 42 5 45 0 47 4 49 9 52 4 54 8 57 3 59 7 62 1 64 5 66 8 69 2 Pl a n : N D B i - 0 1 2 R e v A . 0 707510 0 12 5 15 0 17 5 20 0 22 5 25 0 27 5 30 0 32 5 35 0 37 5 40 0 42 5 45 0 47 5 50 0 52 4 54 9 57 4 59 8 62 3 64 7 67 2 69 6 72 1 74 5 Pl a n : N D B i - 0 1 6 R e v A . 0 47 2 9 9 29 9 4 9 9 49 9 6 4 9 64 9 8 4 9 84 9 1 0 4 9 10 4 9 1 2 4 9 12 4 9 1 3 9 9 13 9 9 1 5 9 9 15 9 9 2 3 9 9 23 9 9 3 1 9 9 31 9 9 3 9 9 9 39 9 9 4 4 9 9 44 9 9 5 4 9 9 54 9 9 6 4 9 9 64 9 9 7 4 9 9 74 9 9 8 4 9 9 84 9 9 9 4 9 9 94 9 9 1 0 9 9 9 10 9 9 9 1 1 9 9 9 11 9 9 9 1 2 9 9 9 12 9 9 9 1 3 9 9 9 13 9 9 9 1 4 9 9 9 14 9 9 9 1 5 9 9 9 Fr o m C o l o u r T o M D 47 . 0 T o 1 5 4 1 8 . 4 MD A z i T F a c e 47 . 0 0 . 0 0 0 . 0 0 34 7 . 0 0 . 0 0 0 . 0 0 64 7 . 0 1 6 5 . 0 0 1 6 5 . 0 0 99 5 . 6 1 9 7 . 3 7 5 3 . 6 8 11 4 9 . 6 1 9 7 . 3 7 0 . 0 0 31 9 5 . 4 2 2 2 . 1 3 2 7 . 1 9 70 8 4 . 9 2 2 2 . 1 3 0 . 0 0 10 3 1 8 . 7 3 1 9 . 8 8 9 3 . 5 7 10 4 1 8 . 7 3 1 9 . 8 8 0 . 0 0 10 7 5 3 . 2 3 2 9 . 3 4 7 0 . 4 7 15 4 1 8 . 4 3 2 9 . 3 4 0 . 0 0 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 1 1 R e v A. 0 Plan: N D B - 0 1 3 R e v A . 0 Pl a n : N DB - 0 1 5 R ev A . 0 Pl a n : N DBi - 0 1 2 R e v A . 0 Pl a n : N DB i - 0 1 6 R ev A . 0 Equivalent Magnetic Distance Plan: NDBi-014 Rev D.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 Measured Depth Pl a n : N DB - 0 1 0 Re v A . 0 Pl a n : N DB - 0 1 1 R e v A .0 Pl a n : N DB - 0 1 3 R e v A . 0 Pl a n : N DB - 0 1 5 R e v A .0 Pl a n : N DB - 0 2 R e v A . 0 Pl a n : N D B - 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 24 R e v F . 0 ND B - 0 24 P B 1 Pl a n : N DB - 0 2 4 P B 1 Rev A . 3 Pl a n : N DB - 2 5 Re v A . 0 Pl a n : N DB - 0 4 R ev A . 0 Plan : N DB- 0 5 R ev A . 0 Pl a n : N DB - 0 9 R ev A . 0 Pl a n : N D B i - 0 1 2 R e v A . 0 Pl a n : NDB i - 0 1 6 R ev A . 0 Pl a n : N DB i - 0 18 R e v F . 0 Pl a n : N DB i - 0 1 9 R ev A . 0 Pl a n : N DB i - 0 2 0 R e v A. 0 Pl a n : N D B i - 0 2 6 R e v A . 0 Pl a n N DB i - 0 2 8 R ev A . 0 Pl a n : N DB i - 0 6 R ev A . 0 Pl a n : N DB i - 0 07 R e v A . 0 Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 47.0 300.0 Plan: NDBi-014 Rev D.0 (NDBi-014) SDI_KPR_ADK 300.0 1300.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag 300.0 2567.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag 2567.0 3567.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag 2567.0 10417.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag 10417.0 11417.0 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+Sag 10417.0 15418.4 Plan: NDBi-014 Rev D.0 (NDBi-014) 3_MWD+IFR2+MS+Sag 10:09, November 06 2023 CASING DETAILS TVD MD Name 127.0 127.0 20" Conductor Casing 2295.1 2567.0 13-3/8" Surface Casing 4369.3 10417.09-5/8" Intermediate Liner 4205.8 15418.0 4-1/2" Liner NDBi-014 PTD AOGCC 11.3.23 - 38 - 03-Nov-23 Attachment 3: BOPE Equipment Ch o k e Li n e fr o m BO P Pr e s s u r e Ga u g e 15 0 2 Pr e s s u r e Se n s o r Pr e s s u r e Tr a n s d u c e r Bi l l o f Ma t e r i a l It e m De s c r i p t i o n To Pa n i c Li n e It e m De s c r i p t i o n A3 Ͳ1/ 8 ” – 5 , 0 0 0 ps i W . P . Re m o t e Hy d r a u l i c Op e r a t e d Ch o k e B3 Ͳ1/ 8 ” – 5, 0 0 0 ps i W. P . Ad j u s t a b l e Ma n u a l Ch o k e 1– 1 4 3 Ͳ1/ 8 ” – 5 , 0 0 0 ps i W . P . Ma n u a l Ga t e Va l v e 15 2 1/ 1 6 ” 5 0 0 0 i W P 15 2Ͳ1/ 1 6 ” – 5,00 0 ps iW.P. Ma n u a l Ga t e Va l v e To Mu d Ga s Le g e n d Bl i n d Sp a r e To Ti g e r Ta n k Se p a r a t o r Va l v e No r m a l l y O p e n Va l v e No r m a l l y C l o s e d 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # 21 - 1 / 4 " X 2 , 0 0 0 # FO R W A R D 13 - 5 / 8 " X 5 , 0 0 0 # 13 - 5 / 8 " X 5 , 0 0 0 # 30 " 13 - 5 / 8 " X 5 , 0 0 0 # 18 6 " 13 - 5 / 8 " X 5 , 0 0 0 # DU T C H L O C K D O W N NDBi-014 PTD AOGCC 11.3.23 - 43 - 03-Nov-23 Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Washouts/Hole Enlargement Keep mud cool, optimize pump rates, minimize any excess circulation. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Shallow Gas Shallow hazards assessment, sufficient mud weight, on site surveillance (mud loggers, trained drilling personnel). 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 73q 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 second stage is pumped giving a higher complexity leading to complication with setting the LTP. NDBi-014 PTD AOGCC 11.3.23 - 44 - 03-Nov-23 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. NDBi-014 PTD AOGCC 11.3.23 - 45 - 03-Nov-23 Attachment 5: Leak Off Test Procedure 1. Drill out shoe track, cement plus minimum of 20’ of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.25bbl/min. Record pump pressures at 0.25bbl increments. 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. NDBi-014 PTD AOGCC 11.3.23 - 46 - 03-Nov-23 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 + 85 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Tuned Prime Spacer Lead 11.0ppg Lead:473.6bbls, 2659cuft, 933sks ArcticCem, Yield: 2.85 cuft/sk Tail 15.3ppg Tail:68.9bbls, 387cuft, 310sks HalCem Type I/II – 1.25 cuft/sk Temp BHST 53° F Notes Job will be mixed on the fly Verification Method Cement returns to surface 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: Top of the 9-5/8” Liner Tail Open hole volume + 85 ft shoe track Tail TOC Stage 1: 500 ft above casing shoe Stage 2: 500 ft above stage collar Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead Stage 1: 30% Open Hole Excess 13.0ppg Lead:222.6bbls, 1250cuft, 678sks ExtendaCem, Yield: 1.84 cuft/sk Stage 2: 50% Open Hole Excess 13.0ppg Lead:190bbls, 1065cuft, 577sks ExtendaCem, Yield: 1.84 cuft/sk Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 42.5bbls, 238.5cuft, 192.9sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 50% Open Hole Excess 15.3ppg Tail: 41.8bbls, 234.9cuft, 190sks VersaCem Type I/II – 1.24 cuft/sk Temp BHST 99° F Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1 st Stage Cement Job Only. -2ndStage Cement Job will not be logged, assuming job parameters are as expected (No losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) 2nd stage cement must be logged also. -bjm verified cement calcs. -bjm NDBi-014 PTD AOGCC 11.3.23 - 47 - 03-Nov-23 -2ndStage bond evaluation does not affect 1 st Stage bond evaluation and frac decision. - Logging of 1 st Stage cement will demonstrate isolation of injection fluids in the Nanushuk reservoir, as well as isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -2ndStage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st stage cement job will verify proper isolation has been achieved for frac operations. - Seeking to simplify an already complicated operation, saving time/money. NDBi-014 PTD AOGCC 11.3.23 - 48 - 03-Nov-23 Attachment 7: Prognosed Formation Tops NDBi-014 Prognosed Tops Formation MD (ft) TVD KB (ft) TVD Path (ft) Uncertainty Range (±ft) Pore Pressure (ppg) Upper Schrader Bluff 1053.0 1046.0 976.2 100 7.2 Base Permafrost 1411.6 1390.7 1320.9 100 7.3 Middle Schrader Bluff 1795.5 1735.1 1665.3 100 7.6 MCU (Lower Schrader Bluff) 2328.4 2144.9 2075.1 100 7.8 Tuluvak Shale 2861.9 2447.2 2377.4 100 7.9 Tuluvak Sand 3002.4 2505.7 2435.9 100 10 Seabee 5225.9 3156.2 3086.4 100 9.1 Nanushuk 7703.8 3873.7 3803.9 100 8.9 NT7 MFS 7862.4 3919.8 3850.0 100 8.9 NT6 MFS 8108.4 3989.6 3919.8 100 8.8 NT5 MFS 8408.0 4070.5 4000.7 100 8.8 NT4 MFS 8752.2 4155.2 4085.4 100 8.7 NT3 MFS 9982.3 4350.2 4280.4 100 8.6 Nanushuk 3.2 (NT3) 10416.0 4369.2 4299.4 100 8.7 NDBi-014 PTD AOGCC 11.3.23 - 49 - 03-Nov-23 Attachment 8: Well Schematic Attachment 9: Formation Evaluation Program NDBi-014 PTD AOGCC 11.3.23 - 50 - 03-Nov-23 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 Mudlogging Mudlogging is not currently planned for NDBi-014. NDBi-014 PTD AOGCC 11.3.23 - 51 - 03-Nov-23 Attachment 10: Wellhead & Tree Diagram NDBi-014 PTD AOGCC 11.3.23 - 52 - 03-Nov-23 Attachment 11: Injector Area of Review Wells within ¼ mile of proposed injection well. Distance Annulus integrity Area of Review Information Qugruk 301 578’ P&A Exploration Well Q-301 was an exploration/appraisal well that was drilled in 2015. It was hydraulic fractured in the Nanushuk reservoir, flowed back, and plugged and abandoned in the same winter season. - The Nanushuk formation top was identified at 4042’ MD, with Nanushuk target formation at 4631’ MD. - 9-5/8” Intermediate casing is set at 5241’ MD in the Nanushuk reservoir. The primary cement job has the TOC at 3810’ MD (96.7 bbls 13.9ppg Extended Class G), with a second stage cement job from 3008’ MD to surface (187 bbls of 12.2ppg Extended Type I/II). - The 4-1/2” production liner in the Nanushuk reservoir is set at 7495’ MD. The liner was P&A with a cement retainer set at 4503’ MD and 48 bbls squeezed below the retainer (4-1/2” liner volume). - 3 cement abandonment plugs were set in the 9-5/8” casing: 1) 1 st Plug (300’ above cement retainer): 18 bbls of 15.8 ppg cement laid above the cement retainer at 4503’. 2) 2 nd Plug (300’ across 13-3/8” casing shoe): A 9-5/8” bridge plug was set at 2207’ MD (100’ below the surface casing shoe) with 19.1 bbls of 15.6ppg Class G cement plug laid on top of it. 3) 3 rd Plug (280’ RKB to surface): A 9-5/8” bridge plug was set at 280’ with 250’ (18 bbls) of 15.6ppg Permafrost C cement laid on top of the plug. Qugruk 3A 1272’ P&A Exploration Well Q3A was an exploration/appraisal well that was sidetracked off the abandoned Q3 mother bore drilled in 2013. - The Q3A well’s 8-1/2”open hole section was drilled to TD at 10,546’ MD. The Tuluvak, Nanushuk, Kupaurk C, and Alpine formations were drilled at 2472’, 4,678’, 9,342’, and 9,718’ MD respectively. - The 8-1/2” open hole section was abandoned with two open hole plugs: 1) 1st plug (open hole plug): An open hole balanced cement plug was attempted to be laid in the well from 10,420’ MD by pumping a 136 bbls of 15.8 ppg cement. Cement was pumped with full returns, but while laying in the balanced plug in the well the string including the drill pipe and 4-1/2” 2,000’ 12.6 ppf tubing stinger became stuck at 10,383’ MD. The pipe was severed at 6,243’ MD. TOC was estimated to be at 8,003’ MD in the annulus and 8,650’ MD inside the drill pipe. 2) 2nd plug (open hole balanced plug): A second open hole balanced plug was placed in the well by circulating 73 bbls of 15.8 ppg class NDBi-014 PTD AOGCC 11.3.23 - 53 - 03-Nov-23 G cement into the hole at 4950’ MD. TOC was confirmed at 4,177’ MD by tagging and placing 15k WOB several times. - The 13-3/8”casing was abandoned with two cased hole cement plugs placed on top of retainers. 1) 3 rd plug (Cased hole plug): A cement retainer was placed at 2,060’ MD and 37.5 bbl balanced cement plug was placed on top of the retainer with TOC estimated to be at 1,810’ MD. 2)4th plug (Cased hole plug): A final cement retainer was placed at 280’ MD and 42 bbls of 15.7 ppg AS1 cement was placed on top of the retainer to surface. An additional cement top off job was performed after the rig moved off location and the well was secured with a weld on metal cap. Based on the assessment from the Santos team, the permeable section of the Nanushuk 3 is isolated by cement plug #2, which will keep injection fluids within the injection zone, based on: 1)The entire Nanushuk-Torok interval is not cemented, but the abandonment of Q3A left cement over the key permeable zones in the Nanushuk 3 clinoform. Cement plug #2 from 4950’ MD – 4212’ MD isolates the Nanushuk 3 permeable zones (Lower Shoreface, Upper Offshore, Lower Offshore). 2)The base of the cement plug is in the Upper Slope (grey) of the Nanushuk 3 clinoform. The Upper Slope depofacies is filled with M1 muds that are non-reservoir and not permeable, illustrated in the diagram below: NDBi-044 495’ TBD NDBi-044 currently is not drilled, but is planned to be drilled just prior to NDBi-014. - Mechanical integrity will be demonstrated during the construction of NDBi-044. - NDBi-044 is another injector that will support enhanced recovery in the Nanushuk 3 formation. - NDBi-044 will be suspended and not be hydraulically fractured at the time of drilling NDBi-014. NDBi-014 (PTD 223-105) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨĂƉƉƌŽǀĂů 1. 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ĞƉĞŶĚŝŶŐŽŶƚŚĞĐĞŵĞŶƚũŽďƌĞƐƵůƚƐŝŶĚŝĐĂƚĞĚďLJƚŚĞĐĞŵĞŶƚũŽďƌĞƉŽƌƚ͕ƚŚĞůŽŐƐĂŶĚ ƚŚĞ&/d͕ƌĞŵĞĚŝĂůŵĞĂƐƵƌĞƐŽƌĂĚĚŝƟŽŶĂůůŽŐŐŝŶŐŵĂLJďĞƌĞƋƵŝƌĞĚ͘ From:Dewhurst, Andrew D (OGC) To:Staudinger, Mark (Mark) Cc:Davies, Stephen F (OGC); Roby, David S (OGC); McLellan, Bryan J (OGC); Guhl, Meredith D (OGC) Subject:RE: NDBi-014 PTD Status Date:Wednesday, November 29, 2023 2:01:55 PM Attachments:image002.jpg image003.jpg image004.jpg Mark, The 2,725’ TVD depth refers to the lowest known gas within the Tuluvak which was derived by petrophysical log analyses from offset wells provided to the AOGCC on 06 November 2023. This is not equivalent to the base of hydrocarbon bearing Tuluvak sands, which per pool rules must be isolated with cement. Therefore, the proposed change which leaves the bottom ~2/3 of hydrocarbon bearing Tuluvak open would not be approved. Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, November 29, 2023 08:11 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: FW: NDBi-014 PTD Status Andy, Santos has changed their pick of the base of hydrocarbon-bearing Tuluvak and therefore changed the location of their 2nd stage cement collar and length of cement. See attached schematic and discussion below. Let me know if you are happy with their new picks of base Tuluvak and if you need some more time to review. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Tuesday, November 28, 2023 5:26 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDBi-014 PTD Status Hey Bryan, Interesting – I’m looking and cannot find the discrepancy. Here are the calcs (total volume is 231.4 bbls): NDBi-014 9.625" Production Liner Discription TOP BOTTOM LENGTH CAPACITY VOLUME TAIL LENGTH 4726 5226 500 0.05578 27.9 TAIL EXCESS 50%13.9 LEAD LENGTH 2567 4726 2159 0.05578 120.4 LEAD EXCESS 50%60.2 Liner Lap 13-3/8" 68# x 9-5/8" 47# LNR 2417 2567 150 0.05974 9.0 On that note, I should probably bring to your attention a couple changes to the PTD application since I submitted. They are as follows: 1. I noticed I forgot to include the tieback in the Casing/Tubing Program table. I talk about the tieback at other placed in the PTD, but it is not included in this section. The tieback will be 9-5/8” 47# L-80 HYD 563 from the Top of Liner to Surface 2. Our Subsurface team has done further work to identify the lowest hydrocarbon in the Tuluvak based on all the offset wells. This work has allowed us to move the Stage Collar location to 2725’ TVD, which will allow the 2nd stage job to adequately cover all the Tuluvak hydrocarbons and simplify our 2nd stage job. For NDBi-014, this depth results in a stage collar placement of ~3731’ MD. I have attached the revised schematic. a. On that basis, our cementing calcs would change slightly for the 2nd stage job: 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: Top of the 9-5/8” Liner Tail Open hole volume + 85 ft shoe track Tail TOC Stage 1: 500 ft above casing shoe Stage 2: 500 ft above stage collar Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead Stage 1: 30% Open Hole Excess 13.0ppg Lead: 222.6bbls, 1250cuft, 678sks ExtendaCem, Yield: 1.84 cuft/sk Stage 2: 50% Open Hole Excess 13.0ppg Lead: 64.5bbls, 362.3cuft, 196sks ExtendaCem, Yield: 1.84 cuft/sk Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 42.5bbls, 238.5cuft, 192.9sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 50% Open Hole Excess 15.3ppg Tail: 41.8bbls, 234.9cuft, 190sks VersaCem Type I/II – 1.24 cuft/sk Temp BHST 99° F For your reference, my new cementing calcs are as follows (total volume of 106.4 bbls): NDBi-014 9.625" Production Liner Discription TOP BOTTOM LENGTH CAPACITY VOLUME TAIL LENGTH 3231 3731 500 0.05578 27.9 TAIL EXCESS 50%13.9 LEAD LENGTH 2567 3231 664 0.05578 37.0 LEAD EXCESS 50%18.5 Liner Lap 13-3/8" 68# x 9-5/8" 47# LNR 2417 2567 150 0.05974 9.0 Let me know if you have any questions on this. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, November 28, 2023 4:42 PM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: RE: NDBi-014 PTD Status Hey Mark, I have a small discrepancy on the stage 2 cement calcs for the intermediate liner. I’m calculating 244 bbls total (lead plus tail) vs. your 231 bbls. I know it’s a small discrepancy, but with the focus on getting good cement across the Tuluvak and across the top of the liner, I thought I would mention it. Could you double check your calcs? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Tuesday, November 28, 2023 9:30 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDBi-014 PTD Status Ok thanks for prioritizing it Bryan. For what it’s worth, we feel like we’ve had relatively good success to date on Tuluvak isolation, and we are continuing to put a lot of effort into optimizing our drilling and cementing of the INT section. Along with that, we have on-going efforts to deliver these wells in a cost-effective manner, so any efficiencies with rig time will be something we continue to strive for. Anyways, let me know if you have any questions on the PTD application. Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, November 27, 2023 3:02 PM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Subject: ![EXT]: RE: NDBi-014 PTD Status I’ll prioritize it this week. Of issue is CBL across intermediate liner. Commissioners are wanting to see a track record of successful cement jobs across the Tuluvak. You are making progress, but they may want this one logged. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, November 27, 2023 12:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDBi-014 PTD Status Hey Bryan, Just wanted to check on the status of the NDBi-014 PTD application? We sent it through about 3 weeks ago, so wanted to just check and see if there are any follow up questions on it? Thanks, Mark Mark Staudinger Senior Drilling Engineer t: +1 (907) 375-4654 | m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in 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. NANUSHUK OIL POOLPIKKA 223-105 X PIKKA NDBi-014 W E L L P E R M I T C H E C K L I S T Co m p a n y Oi l S e a r c h ( A l a s k a ) , L L C We l l N a m e : PI K K A N D B i - 0 1 4 In i t i a l C l a s s / T y p e SE R / P E N D Ge o A r e a 89 0 Un i t 11 5 8 0 On / O f f S h o r e On Pr o g r a m SE R Fi e l d & P o o l We l l b o r e s e g An n u l a r D i s p o s a l PT D # : 22 3 1 0 5 0 PI K K A , N A N U S H U K O I L - 6 0 0 1 0 0 NA 1 P e r m i t f e e a t t a c h e d Ye s AD L 3 9 2 9 8 4 , A D L 3 9 2 9 8 5 , A D L 3 9 3 0 2 3 , A D L 3 9 1 4 4 5 , a n d A D L 3 9 3 0 2 1 2 L e a s e n u m b e r a p p r o p r i a t e Ye s 3 U n i q u e w e l l n a m e a n d n u m b e r Ye s P I K K A , N A N U S H U K O I L - 6 0 0 1 0 0 - g o v e r n e d b y 8 0 7 4 W e l l l o c a t e d i n a d e f i n e d p o o l Ye s 5 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m d r i l l i n g u n i t b o u n d a r y NA 6 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m o t h e r w e l l s Ye s 7 S u f f i c i e n t a c r e a g e a v a i l a b l e i n d r i l l i n g u n i t Ye s 8 I f d e v i a t e d , i s w e l l b o r e p l a t i n c l u d e d Ye s 9 O p e r a t o r o n l y a f f e c t e d p a r t y Ye s 10 O p e r a t o r h a s a p p r o p r i a t e b o n d i n f o r c e Ye s 11 P e r m i t c a n b e i s s u e d w i t h o u t c o n s e r v a t i o n o r d e r Ye s 12 P e r m i t c a n b e i s s u e d w i t h o u t a d m i n i s t r a t i v e a p p r o v a l Ye s 13 C a n p e r m i t b e a p p r o v e d b e f o r e 1 5 - d a y w a i t No P e n d i n g i s s u a n c e o f P i k k a A I O 14 W e l l l o c a t e d w i t h i n a r e a a n d s t r a t a a u t h o r i z e d b y I n j e c t i o n O r d e r # ( p u t I O # i n c o m m e n t s ) ( F o r Ye s Q u g r u k 3 A a n d Q u g r u k 3 0 1 15 A l l w e l l s w i t h i n 1 / 4 m i l e a r e a o f r e v i e w i d e n t i f i e d ( F o r s e r v i c e w e l l o n l y ) No 16 P r e - p r o d u c e d i n j e c t o r : d u r a t i o n o f p r e - p r o d u c t i o n l e s s t h a n 3 m o n t h s ( F o r s e r v i c e w e l l o n l y ) NA 17 N o n c o n v e n . g a s c o n f o r m s t o A S 3 1 . 0 5 . 0 3 0 ( j . 1 . A ) , ( j . 2 . A - D ) Ye s 18 C o n d u c t o r s t r i n g p r o v i d e d Ye s 19 S u r f a c e c a s i n g p r o t e c t s a l l k n o w n U S D W s Ye s 20 C M T v o l a d e q u a t e t o c i r c u l a t e o n c o n d u c t o r & s u r f c s g Ye s T w o s t a g e c e m e n t j o b w i l l l e a v e a n u n c e m e n t e d g a p b e t w e e n s t a g e s . 21 C M T v o l a d e q u a t e t o t i e - i n l o n g s t r i n g t o s u r f c s g Ye s 22 C M T w i l l c o v e r a l l k n o w n p r o d u c t i v e h o r i z o n s Ye s 23 C a s i n g d e s i g n s a d e q u a t e f o r C , T , B & p e r m a f r o s t Ye s 24 A d e q u a t e t a n k a g e o r r e s e r v e p i t NA 25 I f a r e - d r i l l , h a s a 1 0 - 4 0 3 f o r a b a n d o n m e n t b e e n a p p r o v e d Ye s 26 A d e q u a t e w e l l b o r e s e p a r a t i o n p r o p o s e d Ye s 27 I f d i v e r t e r r e q u i r e d , d o e s i t m e e t r e g u l a t i o n s Ye s 28 D r i l l i n g f l u i d p r o g r a m s c h e m a t i c & e q u i p l i s t a d e q u a t e Ye s 29 B O P E s , d o t h e y m e e t r e g u l a t i o n Ye s M P S P = 1 5 4 0 p s i . B O P r a t e d t o 5 0 0 0 p s i . ( B O P t e s t t o 3 5 0 0 p s i ) 30 B O P E p r e s s r a t i n g a p p r o p r i a t e ; t e s t t o ( p u t p s i g i n c o m m e n t s ) Ye s 31 C h o k e m a n i f o l d c o m p l i e s w / A P I R P - 5 3 ( M a y 8 4 ) Ye s 32 W o r k w i l l o c c u r w i t h o u t o p e r a t i o n s h u t d o w n No 33 I s p r e s e n c e o f H 2 S g a s p r o b a b l e Ye s 34 M e c h a n i c a l c o n d i t i o n o f w e l l s w i t h i n A O R v e r i f i e d ( F o r s e r v i c e w e l l o n l y ) Ye s H 2 S n o t a n t i c i p a t e d 35 P e r m i t c a n b e i s s u e d w / o h y d r o g e n s u l f i d e m e a s u r e s Ye s T u l u v a k e x p e c t e d t o b e o v e r p r e s s u r e d t o 1 0 p p g E M W a n d g a s b e a r i n g 36 D a t a p r e s e n t e d o n p o t e n t i a l o v e r p r e s s u r e z o n e s NA 37 S e i s m i c a n a l y s i s o f s h a l l o w g a s z o n e s NA 38 S e a b e d c o n d i t i o n s u r v e y ( i f o f f - s h o r e ) NA 39 C o n t a c t n a m e / p h o n e f o r w e e k l y p r o g r e s s r e p o r t s [ e x p l o r a t o r y o n l y ] Ap p r AD D Da t e 11 / 1 5 / 2 0 2 3 Ap p r BJ M Da t e 12 / 5 / 2 0 2 3 Ap p r AD D Da t e 11 / 1 5 / 2 0 2 3 Ad m i n i s t r a t i o n En g i n e e r i n g Ge o l o g y Ge o l o g i c Co m m i s s i o n e r : Da t e : En g i n e e r i n g Co m m i s s i o n e r : Da t e Pu b l i c Co m m i s s i o n e r Da t e *& : JL C 1 2 / 6 / 2 0 2 3
