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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 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : CB L 1 2 - 2 8 - 2 3 / C B L 1 - 1 2 - 2 4 , G P T / P e r f C o r r e l a t i o n L o g s , L W D ( P C G , A D R , C T N , A L D , P W D , D D S R ) 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 1/ 2 9 / 2 0 2 4 70 9 8 0 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A L W D Fi n a l . l a s 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l M D . c g m 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l T V D . c g m 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A - D e f i n i t i v e S u r v e y Re p o r t . p d f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A - F i n a l S u r v e y s . x l s x 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A _ D S R A c t u a l _ P l a n . p d f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A _ D S R Ac t u a l _ V S e c . p d f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A _ D S R - G I S . t x t 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A _ D S R . t x t 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l M D . e m f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l T V D . e m f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l M D . p d f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l T V D . p d f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l M D . t i f 38 4 4 8 ED Di g i t a l D a t a DF 1/ 2 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L W D F i n a l T V D . t i f 38 4 4 8 ED Di g i t a l D a t a DF 2/ 2 / 2 0 2 4 59 4 3 1 2 9 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A C B L 28 - D E C - 2 3 ( 4 6 3 8 ) . l a s 38 4 7 8 ED Di g i t a l D a t a DF 2/ 2 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C B L 2 8 - D E C - 2 3 (4 6 3 8 ) . p d f 38 4 7 8 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 1 o f 7 KU 1 3 - 0 6 A L W D Fi n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No DF 2/ 2 1 / 2 0 2 4 94 6 8 6 1 0 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G P T PA S S 0 2 - 0 7 - 2 4 . l a s 38 5 1 4 ED Di g i t a l D a t a DF 2/ 2 1 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A F I N A L L O G . p d f 38 5 1 4 ED Di g i t a l D a t a DF 2/ 2 1 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T P A S S 0 2 - 0 7 - 24 . p d f 38 5 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 4 58 7 4 3 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U _ 1 3 - 06 A _ C B L _ 1 2 - J a n - 2 0 2 4 _ ( 4 6 5 2 ) . l a s 38 6 2 1 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 4 E l e c t r o n i c F i l e : K U _ 1 3 - 0 6 A _ C B L _ 1 2 - J a n - 20 2 4 _ ( 4 6 5 2 ) . p d f 38 6 2 1 ED Di g i t a l D a t a DF 3/ 2 1 / 2 0 2 4 93 6 4 9 0 5 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U _ 1 3 - 06 A _ G P T _ 9 - F e b - 2 0 2 4 _ ( 4 6 7 7 ) . l a s 38 6 5 1 ED Di g i t a l D a t a DF 3/ 2 1 / 2 0 2 4 E l e c t r o n i c F i l e : K U _ 1 3 - 0 6 A _ G P T _ 9 - F e b - 20 2 4 _ ( 4 6 7 7 ) . p d f 38 6 5 1 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 69 7 5 9 1 0 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G P T DO W N P A S S . l a s 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 91 0 1 8 0 2 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G P T UP P A S S . l a s 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 89 5 5 8 5 8 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G U N 1 C O R R E L A T I O N P A S S . l a s 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T D O W N PA S S . p d f 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T F I N A L . p d f 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T U P P A S S . p d f 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G U N 1 CO R R E L A T I O N P A S S . p d f 38 6 8 9 ED Di g i t a l D a t a DF 4/ 5 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A P E R F F I N A L . p d f 38 6 8 9 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 74 2 2 6 9 1 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 : K U 1 3 - 0 6 A 2 N D CO R R E L A T I O N G U N 3 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 77 0 2 7 2 4 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 : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 1 C O R R . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 73 1 6 6 9 7 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 2 C O R R . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 76 9 5 7 2 4 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 : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 2 . l a s 38 7 4 6 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 2 o f 7 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No DF 5/ 1 3 / 2 0 2 4 72 7 1 6 9 9 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 : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 3 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 74 1 3 6 9 2 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 : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 4 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 89 9 8 8 6 4 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N P L U G 1 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 89 2 0 8 7 4 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 : K U 1 3 - 0 6 A CO R R E L A T I O N P L U G 2 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 77 0 2 7 0 7 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G P T 1 U P . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 73 8 0 7 0 8 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 : K U 1 3 - 0 6 A G P T 1. l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 70 7 0 7 7 1 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G P T 2 D N . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 77 1 4 7 1 3 5 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A G P T 3 U P . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 74 2 2 6 9 1 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 : K U 1 3 - 0 6 A 2 N D CO R R E L A T I O N G U N 3 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 73 2 5 6 9 8 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 1 C O R R . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 73 1 6 6 9 7 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 2 C O R R . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 73 2 1 6 9 8 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 2 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 72 7 1 6 9 9 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 : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 3 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 74 1 3 6 9 2 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 : K U 1 3 - 0 6 A CO R R E L A T I O N G U N 4 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 73 8 0 7 0 8 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 : K U 1 3 - 0 6 A G P T 1. l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 55 8 1 5 3 8 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 : K U 1 3 - 0 6 A CO R R E L A T I O N A C R O S S 5 4 5 0 F O R L B 1 C . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 64 9 3 6 1 8 2 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 : K U 1 3 - 0 6 A L B 1C _ 6 3 1 3 - 6 3 2 6 _ C O R R E L A T I O N P A S S . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 65 6 5 6 1 4 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A L B 1F _ 6 4 3 3 - 6 4 4 2 _ C O R R E L A T I O N P A S S . l a s 38 7 4 6 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 3 o f 7 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No DF 5/ 1 3 / 2 0 2 4 67 5 9 6 3 8 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A L B 2 C 66 2 9 - 6 6 4 8 C O R R E L A T I O N P A S S . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 68 6 8 6 4 7 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A L B 2 E LO W E R 6 7 4 0 - 6 7 4 4 L B 2 D 6 6 6 2 - 6 6 6 7 CO R R E L A T I O N P A S S . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 68 6 5 6 4 9 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A L B 3 B UP P E R 1 6 8 1 9 - 6 8 3 1 C O R R E L A T I O N P A S S . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 70 3 1 5 3 4 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A L B 4 69 2 7 - 6 9 3 1 _ L B 3 B M I D 6 8 4 8 - 6 8 5 3 _ L B 3 B UP P E R 2 6 8 3 5 - 6 8 3 9 C O R R E L A T I O N P A S S . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 71 1 2 6 6 8 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A , CO O R E L A T I O N P A S S , S E T C I B P A T 7 1 2 5 . l a s 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A 2 N D C O R R E L A T I O N GU N 3 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 1 C O R R . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 2 C O R R . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 2. p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 3. p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 4. p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N PL U G 1 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N PL U G 2 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T 1 U P . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T 1 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T 2 D N . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T 3 U P . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T - P L U G - P E R F FI N A L 3 - 2 2 - 2 4 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A 2 N D C O R R E L A T I O N GU N 3 . p d f 38 7 4 6 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 4 o f 7 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 1 C O R R . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 2 C O R R . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 2. p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 3. p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N G U N 4. p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T 1 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T - P E R F F I N A L 3 - 27 - 2 4 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N AC R O S S 5 4 5 0 F O R L B 1 C . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T - P L U G - P E R F FI N A L 4 - 1 - 2 4 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L B 1 C _ 6 3 1 3 - 63 2 6 _ C O R R E L A T I O N P A S S . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L B 1 F _ 6 4 3 3 - 64 4 2 _ C O R R E L A T I O N P A S S . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L B 2 C 6 6 2 9 - 6 6 4 8 CO R R E L A T I O N P A S S . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L B 2 E L O W E R 6 7 4 0 - 67 4 4 L B 2 D 6 6 6 2 - 6 6 6 7 C O R R E L A T I O N PA S S . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L B 3 B U P P E R 1 6 8 1 9 - 68 3 1 C O R R E L A T I O N P A S S . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A L B 4 6 9 2 7 - 69 3 1 _ L B 3 B M I D 6 8 4 8 - 6 8 5 3 _ L B 3 B U P P E R 2 68 3 5 - 6 8 3 9 C O R R E L A T I O N P A S S . p d f 38 7 4 6 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A , C O O R E L A T I O N PA S S , S E T C I B P A T 7 1 2 5 . p d f 38 7 4 6 ED Di g i t a l D a t a DF 12 / 1 8 / 2 0 2 4 56 0 2 5 4 5 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U _ 1 3 - 06 A _ P l u g S e t t i n g _ 5 - D e c e m b e r - 2 0 2 4 _ ( 5 1 9 3 ) . l a s 39 8 7 0 ED Di g i t a l D a t a DF 12 / 1 8 / 2 0 2 4 E l e c t r o n i c F i l e : K U _ 1 3 - 0 6 A _ P l u g S e t t i n g _ 5 - De c e m b e r - 2 0 2 4 _ ( 5 1 9 3 ) . p d f 39 8 7 0 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 5 o f 7 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No DF 2/ 1 8 / 2 0 2 5 53 1 8 2 5 4 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 : K U 1 3 - 0 6 A S C B L MA I N P A S S 1 - 1 2 - 2 0 2 5 . l a s 40 0 8 8 ED Di g i t a l D a t a DF 2/ 1 8 / 2 0 2 5 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A S C B L F I N A L 1 - 1 2 - 20 2 5 . p d f 40 0 8 8 ED Di g i t a l D a t a DF 2/ 1 8 / 2 0 2 5 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A S C B L M A I N P A S S 1 - 12 - 2 0 2 5 . d l i s 40 0 8 8 ED Di g i t a l D a t a DF 2/ 1 8 / 2 0 2 5 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A S C B L M A I N P A S S 1 - 12 - 2 0 2 5 . p d f 40 0 8 8 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 52 4 7 4 4 3 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 : K U 1 3 - 0 6 A CO R R E C T E D C O R R E L A T I O N L O G T O P E R F UB 5 A - S A N D @ 5 1 0 9 - 5 1 2 1 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 47 5 8 4 5 4 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N L O G T O P E R F U B S A N D @ 47 4 8 - 4 7 6 4 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 48 5 3 4 5 8 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 : K U 1 3 - 0 6 A CO R R E L A T I O N L O G T O P E R F U B 1 S A N D @ 47 8 6 - 4 7 9 8 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 51 0 7 4 5 8 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N L O G T O P E R F U B 5 S A N D @ 50 5 8 - 5 0 7 7 ' . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 52 4 6 4 4 3 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N L O G T O P E R F U B 5 A - S A N D @5 1 0 9 - 5 1 2 1 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 51 6 6 4 5 8 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N L O G T O P E R F U B 5 A - U P P E R SA N D @ 5 0 9 0 - 5 1 0 3 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 47 7 8 4 5 4 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 1 3 - 0 6 A CO R R E L A T I O N L O G T O S E T 4 . 2 4 I N C H C I B P @ 4 7 8 0 F T 1 - 2 4 - 2 5 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 45 4 2 5 3 1 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 : K U 1 3 - 0 6 A G P T BA S E L I N E L O G 1 - 2 1 - 2 5 . l a s 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A C O R R E L A T I O N L O G FI N A L . p d f 40 2 6 2 ED Di g i t a l D a t a DF 4/ 2 / 2 0 2 5 E l e c t r o n i c F i l e : K U 1 3 - 0 6 A G P T F I N A L 1 - 2 4 - 25 . p d f 40 2 6 2 ED Di g i t a l D a t a DF 6/ 1 6 / 2 0 2 5 47 3 2 4 5 7 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U _ 1 3 - 06 A _ C I B P _ 1 8 - M a r c h - 2 0 2 5 _ ( 5 3 5 1 ) . l a s 40 5 5 2 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 6 o f 7 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 7 1 6 - 0 0 - 0 0 We l l N a m e / N o . KE N A I U N I T 1 3 - 0 6 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 2/ 1 0 / 2 0 2 4 Pe r m i t t o D r i l l 22 3 1 1 2 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 98 3 0 TV D 97 2 3 Cu r r e n t S t a t u s 1- G A S 1/ 1 3 / 2 0 2 6 UI C No We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D 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 0 / 2 0 2 4 Re l e a s e D a t e : 12 / 8 / 2 0 2 3 DF 6/ 1 6 / 2 0 2 5 46 7 3 4 2 7 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U _ 1 3 - 06 A _ P e r f _ 0 9 - M a y - 2 0 2 5 _ ( 5 4 4 2 ) . l a s 40 5 5 2 ED Di g i t a l D a t a DF 6/ 1 6 / 2 0 2 5 E l e c t r o n i c F i l e : K U _ 1 3 - 0 6 A _ C I B P _ 1 8 - M a r c h - 20 2 5 _ ( 5 3 5 1 ) . p d f 40 5 5 2 ED Di g i t a l D a t a DF 6/ 1 6 / 2 0 2 5 E l e c t r o n i c F i l e : K U _ 1 3 - 0 6 A _ P e r f _ 0 9 - M a y - 20 2 5 _ ( 5 4 4 2 ) . p d f 40 5 5 2 ED Di g i t a l D a t a Tu e s d a y , J a n u a r y 1 3 , 2 0 2 6 AO G C C P a g e 7 o f 7 1/ 1 6 / 2 0 2 6 M. G u h l 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: N2 Development Exploratory 3. Address: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 9,830 feet See Schematic feet true vertical 9,723 feet N/A feet Effective Depth measured 4,700 feet 5,451 feet true vertical 4,653 feet 5,394 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)5-1/2" 17# / L-80 5,362' MD 5,306' TVD Packers and SSSV (type, measured and true vertical depth)LTP; N/A 5,451' MD 5,394' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 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: Contact Email: Authorized Title:Contact Phone: 4,790psi 8,540psi 2,980psi 5,860psi 6,890psi 9,020psi 1,699'1,689' Burst Collapse 1,410psi 2,560psi Production Liner 6,066' 3,950' Casing Structural 6,001' 9,300' 6,066' 9,401' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 1,699' measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-112 50-133-20716-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEE A028142 Kenai C.L.U. / Sterling Pool 6 Gas Kenai Unit (KU) 13-06A Plugs Junk measured Length 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) 0 Gas-Mcf MD 0 Size 120' 0 1683000 0 00 196 Stefan Reed, Operations Engineer 325-095 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A stefan.reed@hilcorp.com 206-518-0400 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 By Grace Christianson at 2:50 pm, Jun 06, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.06 14:17:38 - 08'00' Noel Nocas (4361) DSR-6/18/25 RBDMS JSB 061325 BJM 9/23/25 Page 1/1 Well Name: KEU KU 013-06A Report Printed: 6/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20716-00-00 Field Name:Kenai Loop State/Province:ALASKA Permit to Drill (PTD) #:223-112 Sundry #:325-095 Rig Name/No: Jobs Actual Start Date:2/26/2025 End Date: Report Number 1 Report Start Date 3/18/2025 Report End Date 3/19/2025 Last 24hr Summary PTW/PJSM, MIRU AK Eline, PT 250/3500. Ran GPT tag @ 4778', FL @ 4122'. MIRU Fox N2 PT 300/3500. Push fluid away W/ 70K SCF see pressure break over @ 1300psi. Set 4.24" CIBP @ 4730'. Pressure up tbg to 3200psi W/ N2. Pumped 222K total SCF (2390 gal) Report Number 2 Report Start Date 3/19/2025 Report End Date 3/20/2025 Last 24hr Summary PTW/PJSM, Dump 30 gals cement on CIBP @ 4730', est. TOC 4700'. Start 72hr MIT-T witnessed by AOGCC Josh Hunt. Test start time 14:00 Initial T/I/O=3239/65/0 Report Number 3 Report Start Date 3/22/2025 Report End Date 3/23/2025 Last 24hr Summary Complete state witnessed (Josh Hunt) MIT-T W/ nitrogen. start pressures 3239/65/0 72hr pressures 3233/77/0. MIRU PWL PT 250/3500, Tagged TOC W/ 2.75" cent, 2.50" DD bailer @ 4705' KB, (sample of cement) Witnessed by AOGCC Josh Hunt. Report Number 4 Report Start Date 5/9/2025 Report End Date 5/10/2025 Last 24hr Summary Complete PTW / PJSM. MIRU Ak Eline. Bleed WHP 1200 psi to 300 psi. Correlate and send logs to OE / Geo. Made 4 gun runs w/3-3/8" guns (6 spf, 60 deg phasing). Perforated Pool 6 sands 4501' - 4581'. Final WHP 176 psi. RDMO Ak Eline.Perforated Pool 6 sands 4501' - 4581'. ,, Set 4.24" CIBP @ 4730'. y Dump 30 gals cement on CIBP @ 4730', est. TOC 4700 _____________________________________________________________________________________ Updated By DMA 05-30-25 SCHEMATIC Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ Tieback Detail 5-1/2”Tubing 17 / L-80 / BTC SCC 4.767”Surface 5,362’ JEWELRY DETAIL No Depth ID Item 1 4,730’CIBP w/ 25’ of cement – TOC @ 4,705’ (3/19/25) 2 4,780’CIBP 1/24/25 3 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 4 5,490’CIBP 12/5/24 5 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 6 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 7 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 8 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Sterling Gas Pool 6 – 4,499’ MD, 4,707’ TVD P6 4,501’4,581’4,456’4,535’80 5/9/25 Open Top of Beluga/Upper Tyonek Gas Pool – 47,30’ MD, 4,683’ TVD UB 4,748’4,764’4,700’4,716’16’1/24/25 Isolated UB 1 4,786’4,798’4,738’4,749’12’1/22/25 Isolated UB 5 5,058’5,077’5,006’5,024’19’1/22/25 Isolated UB 5A Upper 5,090’5,103’5,037’5,050’13’1/21/25 Isolated UB 5A 5,109’5,121’5,056’5,068’12’1/21/25 Isolated LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Isolated LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Isolated LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Isolated LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Isolated LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Isolated LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Isolated LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Isolated LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Isolated LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Isolated LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9,001’ MD, 8,905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250807 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 6/26/2025 AK E-LINE PPROF T40741 BCU 25 50133206440000 214132 7/16/2025 AK E-LINE Plug/Cement T40742 BRU 211-35 50283201890000 223050 6/11/2025 AK E-LINE Perf T40743 BRU 211-35 50283201890000 223050 6/20/2025 AK E-LINE PPROF T40743 BRU 213-26 50283201920000 223069 7/7/2025 AK E-LINE Perf T40744 BRU 213-26T 50283202040000 225038 7/2/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 7/4/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 6/28/2025 AK E-LINE Perf T40745 BRU 241-23 50283201910000 223061 7/18/2025 AK E-LINE Perf T40746 GP 11-13RD 50733200260100 191133 6/2/2025 AK E-LINE PPFROF T40747 KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF T40748 MPU E-28 50029232590000 202055 5/8/2025 AK E-LINE Caliper T40749 MPU F-21 50029226940000 196135 7/10/2025 AK E-LINE Caliper T40750 MPU G-02 50029219260000 189028 7/6/2025 AK E-LINE Puncher T40751 MPU I-01 50029220650000 190090 7/7/2025 AK E-LINE TubingPunch T40752 NS-19 50029231220000 202207 6/27/2025 AK E-LINE Perf T40753 PBU J-07C 50029202410300 225026 5/29/2025 BAKER MRPM T40754 PBU N-07B 50029201370200 223122 6/7/2025 BAKER MRPM T40755 PCU-05 50283202030000 225037 7/10/2024 AK E-LINE Perf T40756 TBU D-07RD2 50733201170200 192155 7/19/2025 AK E-LINE Perf T40757 TBU M-09 50733204760000 196127 7/18/2025 AK E-LINE Perf T40758 Please include current contact information if different from above. T40755PBU N-07B 50029201370200 223122 6/7/2025 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.08 11:16:55 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 6/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250613 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-17A 50733203110100 213049 4/14/2025 AK E-LINE GPT T40549 AN-17A 50733203110100 213049 4/16/2025 AK E-LINE Perf T40549 BRU 244-27 50283201850000 222038 5/15/2025 AK E-LINE Perf T40550 IRU 241-01 50283201840000 221076 5/16/2025 AK E-LINE Perf T40551 KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP T40552 KU 13-06A 50133207160000 223112 5/9/2025 AK E-LINE Perf T40552 KU 33-08 50133207180000 224008 5/30/2025 AK E-LINE Perf T40553 MPU K-33 50029227290000 196202 5/2/2025 AK E-LINE Caliper T40554 Aurora S-100A 50029229620100 224083 5/8/2025 BAKER MRPM Borax #2 T40555 PBU 06-12C 50029204560300 225022 5/15/2025 BAKER MRPM T40556 PBU B-30B 50029215420200 225009 4/9/2025 BAKER MRPM T40557 PBU D-03B 50029200570300 225008 5/2/2025 BAKER MRPM T40558 PBU H-29B 50029218130200 225005 5/7/2025 BAKER MRPM T40559 END 1-25A 50029217220100 197075 5/4/2025 HALLIBURTON MFC40 T40560 END 3-03 50029223060000 192121 5/18/2025 HALLIBURTON PPROF T40561 NS-33A 50029233250100 208189 5/13/2025 HALLIBURTON MFC24 T40562 PBU D-03B 50029200570300 225008 5/2/2025 HALLIBURTON RBT T40558 PBU H-29B 50029218130200 225005 5/7/2025 HALLIBURTON RBT T40559 PBU L-108 50029230900000 202109 5/16/2025 HALLIBURTON IPROF T40563 Please include current contact information if different from above. KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP T40552 KU 13-06A 50133207160000 223112 5/9/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.17 11:38:14 -08'00' From:McLellan, Bryan J (OGC) To:Stefan Reed Cc:Donna Ambruz; McLellan, Bryan J (OGC) Subject:Re: [EXTERNAL] RE: 13-6A MIT Date:Friday, May 9, 2025 8:39:33 AM Attachments:image001.png image001.png image001.png image001.png Confirmed, 25’ of cement is sufficient. Sent from my iPhone On May 8, 2025, at 12:07 PM, Stefan Reed <Stefan.Reed@hilcorp.com> wrote: Bryan, We did a witnessed tag and test on this well back in March (22-Mar-25) but have not perforated yet. Reviewing the logs the plug was set @ 4730’ and TOC was tagged @ 4705’ showing 25’ of cement. The estimated cement top I put in the sundry was 4700’ (30’of cement). Confirming it is acceptable to continue with perforations with the 25’ cement on top of plug since this meets the states requirements. Thank you. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Monday, March 24, 2025 11:38 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: 13-6A MIT Bryan, Yes, the blue line on the graph is column D which is the IA pressure. The IA is fluid packed. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, March 24, 2025 11:02 AM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: [EXTERNAL] RE: 13-6A MIT Gavin, Is the blue line the IA pressure, same as the column D in the data tab? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Monday, March 24, 2025 10:04 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: 13-6A MIT Bryan, Attached is the data from the MIT using N2 on well 13-06A. Only a 6psi loss over the 72hr test interval. What are your thoughts on reducing test time? Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: Justin J Haxton - (C) <Justin.J.Haxton@hilcorp.com> Sent: Sunday, March 23, 2025 6:40 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: FW: 13-6A MIT Here is the log from the MIT & the MIT form. Thank you, Justin Haxton Hilcorp Alaska LLC. Kenai/CIO Well site supervisor 907-715-7722 Email: justin.j.haxton@hilcorp.com From: Zachary Rohr <zrohr@hilcorp.com> Sent: Saturday, March 22, 2025 6:48 PM To: Justin J Haxton - (C) <Justin.J.Haxton@hilcorp.com> Subject: 13-6A MIT/IA Sent from my iPhone The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phonenumber is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF T40256 BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG T40256 BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf T40257 BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf T40257 CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG T40258 IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf T40259 KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF T40260 KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF T40261 KU 13-06A 50133207160000 223112 1/21/2025 AK E-LINE GPT-PERF T40262 MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey T40263 MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF T40264 MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF T40265 MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper T40266 MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL T40267 MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut T40268 PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT T40269 PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey T40270 PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP T40271 PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL T40272 Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. KU 13-06A 50133207160000 223112 1/21/2025 AK E-LINE GPT-PERF MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 6 Township: 4N Range: 11W Meridian: Seward Drilling Rig: Rig Elevation: Total Depth: 9,830 ft MD Lease No.: FEE A028142 Operator Rep: Suspend: P&A: X Conductor: 16" O.D. Shoe@ 120 Feet Csg Cut@ Feet Surface: 10-3/4" O.D. Shoe@ 1,699 Feet Csg Cut@ Feet Intermediate: 7-5/8" O.D. Shoe@ 6,066 Feet Csg Cut@ Feet Production: 4-1/2" O.D. Shoe@ 9,401 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 5-1/2" O.D. Tail@ 5,362 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Tubing Bridge plug 4,730 ft 4.705 ft Wireline tag Initial 24 hrs 48 hrs 72 hrs Result Tubing 3239 3235 3234 3233 IA 65 71 75 77 OA 0 000 Remarks: Attachments: See attachment 3/19 - 3/22/2025 Josh Hunt Well Bore Plug & Abandonment KU 13-06A Hilcorp Alaska LLC PTD 2231120; Sundry 325-095 Details of Test and Tag; Photo Test Data: P Casing Removal: Justin Haxton Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0322_Plug_Verification_KU_13-06A_jh 9 9 9 9 9 9 999 9 9 9 9 9 9 9 9 9999 99 99 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 17:20:36 -08'00' īŪČϙ«ôŘĖƱèÍťĖĺIJϙ– XôIJÍĖ IJĖť ͐͒-͏͕ ϼ" ͑͑͒͐͐͑͏Ͻ AOGCC Inspector J. Hunt 3/22/2025 ôıÍŘħŜ 3/19/2025 – I traveled to location and met with Justin Haxton representing Hilcorp. We talked over the passing criteria for this nitrogen MIT-T and the plan forward from here for the well. KU 13- 06A ēÍîϙŕŘôŽĖĺŪŜīƅϙæôôIJϙŕŘôŜŜŪŘôîϙŪŕϙťĺϙŕŪŜēϙƲŪĖîϙĖIJϙťēôϙſôīīæĺŘôϙÍſÍƅϙŕŘĖĺŘϙťĺϙèôıôIJťĖIJČϟϙēĖŜϙ ÍīīĺſôîϙťēôϙIJĖťŘĺČôIJϙÍıŕīôϙťĖıôϙťĺϙÍîĤŪŜťϙťĺϙÍIJƅϙťôıŕôŘÍťŪŘôϙîĖƯôŘôIJèôϙſēĖīôϙťēôƅϙŕôŘċĺŘıôîϙ(- īĖIJôϙſĺŘħϙťēôϙŕŘôŽĖĺŪŜϙîÍƅϟϙIϙſÍťèēôîϙťēôϙŕŘôŜŜŪŘôϙċĺŘϙťēôϙƱŘŜťϙ͓͔ minutes and there was no loss ĖIJϙŕŘôŜŜŪŘôϙîŪŘĖIJČϙťēĖŜϙťĖıôϟϙIϙŘôŗŪôŜťôîϙÍIJϙŪŕîÍťôϙÍťϙ͓͐ϡ͏͏ϙôŽôŘƅϙîÍƅϙϼ͓͑ϙēour mark). 3/22/2025ϡϙIϙťŘÍŽeīôîϙæÍèħϙťĺϙīĺèÍťĖĺIJϙÍťϙ͐͒ϡ͏͏ϙÍIJîϙſÍťèēôîϙťēôϙèŘƅŜťÍīϙČÍŪČôϙċĺŘϙťēôϙƱIJÍīϙēĺŪŘϟϙ There was no change in pressure during ťēôϙƱIJÍīϙēĺŪŘϟϙiIJīƅϙÍϙ6-psi total loss in tubing pressure over the 72-hour monitoring period ϼless than a 2% loss over the test duration). Slickline was ŘĖČČôîϙŪŕϙĺIJèôϙťēôϙaIϙſÍŜϙƱIJĖŜēôîϟϙēôϙťĺĺīŜϙèĺIJŜĖŜťôîϙĺċϙ͔͐ feet of 13/͓-inch weight pipe, oil jars, spangs, and a 21/2-inch drive down bailer with a mule shoe ÍIJîϙƲÍŕŕôŘϙŽÍīŽôϟϙThe total weight of the tagging tools was 200 lbs with an overall length of 31.5 feet. They ran in the hole and ēÍîϙÍϙŜĺīĖîϙťÍČϙÍťϙ͓Ϡ͖͏͔ ft MD which leaves 25 feet of cement on top on the cast iron bridge plug. They tagged the cement top several times and retrieved a good thick/dry cement sample. 9 9 9 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: 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? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,830'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,560psi Intermediate 4,790psi Production 8,540psi Liner 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng LTP; N/A 5,451' MD / 5,394' TVD; N/A 9,723'7,125'7,049' Kenai C.L.U.Beluga/Up Tyonek GP 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 13-06ACO 510C Sterling Pool 6 9,300'4-1/2" ~1551 psi 3,950' See Schematic Length February 21, 2025 5-1/2" 9,401' Perforation Depth MD (ft): 6,066' See Attached Schematic 6,890psi 2,980psi 5,860psi 120' 6,001' 120' 1,699' Size 120' 7-5/8"6,066' 1,699' MD Hilcorp Alaska, LLC Proposed Pools: 17# / L-80 TVD Burst 5,362' 9,020psi 1,689' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 223-112 50-133-20716-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade: stefan.reed@hilcorp.com 206-518-0400 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Gavin Gluyas at 3:55 pm, Feb 20, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.20 15:33:38 -09'00' SFD Provide 24 hrs for opportunity to witness tag of top of cement and pressure test. See attached alternate test acceptance criteria. Variance to 20 AAC 25.112(g)(2) approved on condition alternative acceptance criteria for testing with gas are met. Perforate New Pool P Feb 20, 2025 Service February 21, 2025 GSTOR X SFD 2/21/2025 325-095 DSR-2/20/25 Sterling Pool 6 10-404 BJM 3/13/25 RUSH SFD Use of this well for storage injection is prohibited without further AOGCC review and approval. SFD *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.14 12:21:44 -08'00'03/14/25 RBDMS JSB 031825 P6 Conversion Well: KU 13-06A Date: 17-Feb-25 Well Name: KU 13-06A API Number: 50-133-20716-00-00 Current Status: Shut In Gas Producer Permit to Drill Number: 223-112 First Call Engineer: Stefan Reed (206) 518-0400 (c) Second Call Engineer: Chad Helgeson (907) 229-4824 (c) Maximum Expected BHP: 2021 psi @ 4700’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1551 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.66 psi/ft using 12.8 ppg EMW FIT at the surface casing shoe 12/19/23 Shallowest Potential Perf TVD: MPSP/(0.66-0.1) = 1551 psi / 0.56 = 2770‘ TVD Top of Pools per CO 510C:Beluga/Upper Tyonek Pool: 4730’ MD, ~4683' TVD Brief Well Summary KU 13-06A was drilled and completed with Hilcorp Rig 169 January 2024 targeting Tyonek, Upper Tyonek and Lower Beluga sands at Kenai Gas Field. The well was completed and did not find any commercial gas. The 4-1/2” tubing was pulled and new 5-1/2” tubing was ran and cemented in place. 5 zones in the UB sands were perforated but were unproductive. The purpose of this project is to isolate the UB perforations and perforate the pool 6 sands to convert the well to a gas storage producer. Hilcorp request a waiver from 20 AAC 25.112.(c)(1)(E), to not pressure test the plug and only tag top of cement after a 12-24 hour cure time. Wellbore Conditions: x CIBP @ 4780’ w/ open perf zone 4748’ – 4764’. Pool Tops: x Sterling Pool 6 – 4499’ MD/4454’ TVD x Beluga/Upper Tyonek Gas Pool – 4730’ MD/4683’ TVD Eline Procedure 1. MIRU E-line 2. PT lubricator to 250/2500psi 3. Log GPT to CIBP @ 4780’ to confirm fluid level. Push fluid away as necessary. 4.Set 5-1/2” CIBP @ ~4730’ 5. Dump bail 30’ cement (~30gals) a. Allow 12-24hrs for cement to cure 6. Tag TOC, estimated TOC ~4700’ a.Provide at least 24hr notice to AOGCC for witness 7. PU 3-3/8” perf guns and perforate proposed intervals bottoms up. Sands Top MD Btm MD Top TVD Btm TVD FT P6 4,501’ 4,581’ 4,456’ 4,535’ 80’ 8. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing Sterling Pool 6 – 4499’ MD/4454’ TVD isolate the UB perforations and perforate the pool 6 sands to convert the well to a gas storage producer. Beluga/Upper Tyonek Gas Pool – 4730’ MD/4683’ TVD Pressure test plug before perforating. See test acceptance criteria in attached email from Bryan McLellan. A variance from 20 AAC 25.112(g)(2) is approved to allow pressure testing with gas if the acceptance criteria are met. -bjm No justification provided for requested waiver. SFD CBL shows good-quality cement bond across intermediate hole (and Sterling Pool 6) beginning at 2,800' MD and continuing downward to the base of the CBL log at 5,300' MD. Intermediate casing shoe is located at 6,066' MD. SFD P6 Conversion Well: KU 13-06A Date: 17-Feb-25 b. Above perfs will be shot in the Kenai Sterling Gas Pool 6 governed by CO 510C 9. RD E-Line Unit and turn well over to operations for conversion to storage well. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic Kenai Sterling Gas Pool 6 governed by CO 510C _____________________________________________________________________________________ Updated By SAR 1-30-25 Schematic Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ Tieback Detail 5-1/2”Tubing 17 / L-80 / BTC SCC 4.767”Surface 5,362’ JEWELRY DETAIL No Depth ID Item 1 4,780’CIBP 1/24/25 2 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 3 5,490’CIBP 12/5/24 4 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 5 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 6 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 7 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD UB 4,748’4,764’4,700’4,716’16’1/24/25 Open UB 1 4,786’4,798’4,738’4,749’12’1/22/25 Isolated UB 5 5,058’5,077’5,006’5,024’19’1/22/25 Isolated UB 5A Upper 5,090’5,103’5,037’5,050’13’1/21/25 Isolated UB 5A 5,109’5,121’5,056’5,068’12’1/21/25 Isolated LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Isolated LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Isolated LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Isolated LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Isolated LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Isolated LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Isolated LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Isolated LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Isolated LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Isolated LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated _____________________________________________________________________________________ Updated By SAR 1-30-25 Proposed Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ Tieback Detail 5-1/2”Tubing 17 / L-80 / BTC SCC 4.767”Surface 5,362’ JEWELRY DETAIL No Depth ID Item 1 4,700’CIBP w/ 30’ of cement 2 4,780’CIBP 1/24/25 3 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 4 5,490’CIBP 12/5/24 5 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 6 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 7 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 8 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Sterling Gas Pool 6 – 4499’ MD, 4707’ TVD P6 4,501’4,581’4,456’4,535’80 TBD Proposed Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD UB 4,748’4,764’4,700’4,716’16’1/24/25 Isolated UB 1 4,786’4,798’4,738’4,749’12’1/22/25 Isolated UB 5 5,058’5,077’5,006’5,024’19’1/22/25 Isolated UB 5A Upper 5,090’5,103’5,037’5,050’13’1/21/25 Isolated UB 5A 5,109’5,121’5,056’5,068’12’1/21/25 Isolated LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Isolated LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Isolated LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Isolated LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Isolated LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Isolated LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Isolated LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Isolated LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Isolated LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Isolated LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, March 10, 2025 12:15 PM To:Stefan Reed Cc:Dan Marlowe; Noel Nocas Subject:RE: KU 13-06A (PTD# 223-112) - Variance Stefan, Testing with gas has some real drawbacks, including a limited amount of diƯerential pressure across the plug and diƯiculty identifying a leak since the gas is so compressible. A lot of gas can leak with not much pressure decline observed if using the acceptance criteria you’ve suggested in your email below. The AOGCC has not historically accepted pressure tests with gas and therefore does not have standardized acceptance criteria, however we recognize a need for developing criteria and that a test to gas can be as good or better than a test to liquid if the correct acceptance criteria are used. Verifying plug integrity for gas storage pools is especially important to ensure there are no leaks out of the storage pool. Given the complications of testing with liquid and the need to perforate in a dry well, if we address the points above, a test to gas will be accepted as follows: 1. Increase the test pressure to 2500 psi so diƯerential at the plug is signiƱcant. 2. Increasing test duration to 72 hrs with a 2% or less pressure loss over that time period. 3. The test may begin after allowing for wellbore temperature to stabilize so temperature eƯects don’t impact the results. The pressure over the entire duration of the test must be > 2500 psi test pressure. 4. IA pressure should be monitored and reported along with the tubing pressure over the period of the pressure test. Alternatively, a negative pressure test with a signiƱcant drawdown across the plug and similar acceptance criteria could be considered. These criteria may be modiƱed in the future with adequate justiƱcation. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Monday, February 24, 2025 3:56 PM 2 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: KU 13-06A (PTD# 223-112) - Variance Bryan, As discussed, Hilcorp requested a variance from regulation 20 AAC 25.112(g)(2) on a sundry submitted 20-Feb-25 for well KU 13-06A (PTD# 223-112). The variance requested was to not pressure test the proposed plug @ ~4730’ between Pool 6 and Beluga/Upper Tyonek gas pool. The reason for this request is to avoid loading the well with fluid for the sole purpose of pressure testing. Loading the well with fluid adds additional time, cost, and risk to the operation because the fluid column needs to be below any future perforations. This requires an additional step for coil tubing operations to reverse the well to N2 before perforating. Hilcorp removes its request for a variance from 20AAC25.112.g(2). However, Hilcorp will test the plug with Nitrogen instead of a fluid, which is not common for testing these plugs. Hilcorp proposes the following procedure for pressure testing with N2. 1) Set plug, dump cement on plug per procedure. 2) Pressure up well to 2000+ psi 3) using chart recorder or digital crystal gauge monitor the pressure for a minimum of 2hrs, however a 2-hr test procedure will start when the pressure stabilizes (temperature of the gas needs to equalize before the fluctuations in pressure may stop) 1. Criteria for test being a time of 2 hours showing stabilization and less than 10% drop of the maximum test pressure over the 2 hour test period Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. 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: N2, CTCO Development Exploratory 3. Address: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 9,830 feet See Schematic feet true vertical 9,723 feet N/A feet Effective Depth measured 7,125 feet 5,451 feet true vertical 7,049 feet 5,394 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)5-1/2" 17# / L-80 5,362' MD 5,306' TVD Packers and SSSV (type, measured and true vertical depth)LTP; N/A 5,451' MD 5,394' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 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: Contact Email: Authorized Title:Contact Phone: Stefan Reed, Operations Engineer 324-663 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A stefan.reed@hilcorp.com 206-518-0400 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) 0 Gas-Mcf MD 15 Size 120' 0 00 0 1980 50 measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 223-112 50-133-20716-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEE A028142 Kenai C.L.U. / Beluga-Up Tyonek Gas Kenai Unit (KU) 13-06A Plugs Junk measured Length Production Liner 6,066' 3,950' Casing Structural 6,001' 9,300' 6,066' 9,401' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 1,699' 4,790psi 8,540psi 2,980psi 5,860psi 6,890psi 9,020psi 1,699'1,689' Burst Collapse 1,410psi 2,560psi 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 By Gavin Gluyas at 9:45 am, Feb 18, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.17 20:14:34 -09'00' RBDMS JSB 021925 DSR-2/18/25BJM 4/28/25 Page 1/2 Well Name: KEU KU 13-06A Report Printed: 2/17/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:12/6/2024 End Date: Report Number 1 Report Start Date 12/5/2024 Report End Date 12/6/2024 Last 24hr Summary PTW/PJSM w/ AK E-line. MIRU AK E-Line, remove well house, PT 250/2000 PSI. RIH 3.71” CIBP, S/D at 1500’. RIH w/ 3.55” Gauge Ring & junk basket. No issues at 1500' and continue to 5600’ (Target depth 5500’). RIH w/ 3.50” CIBP, correlate and set at 5490'. L/D lubricator and secure well for the night. Plan forward: Pending arrival of hot oil truck, will continue w/ pressuring up well to 1000 PSI and shooting circ holes above liner top (~5420'). Report Number 2 Report Start Date 12/6/2024 Report End Date 12/7/2024 Last 24hr Summary PTW/PJSM with AK E-line. Rig back on well and RIH with tubing puncher. Bleed well to atmosphere, obtain vac truck and fill tubing with produced water to surface. Pressure tubing with triplex (methanol) to 1000 psi. IA - 30 psi. Tie-in and punch 12 holes at 5410'-5413', above tie-back at 5464'. Final T/I/O = 524 psi/0 psi/20 psi. Secure well and RDMO E-line. Report Number 3 Report Start Date 12/10/2024 Report End Date 12/11/2024 Last 24hr Summary MIRU hot oil truck. Spot fluid tanks. Load supply tank with lease water. RIg up pump truck to tubing wing. IA rigged to return tank. Circulate out Original drilling mudd. 338 bbls circulated. RDMO. Report Number 4 Report Start Date 12/21/2024 Report End Date 12/22/2024 Last 24hr Summary Load and move equipment from KU 24-07RD to KU 13-06A. Lay out felt & liner, spot base beam & carrier to well center. Set auxiliary equipment. Run electrical. Berm around liner. Raise and scope up derrick, secure guy lines. Install circulating hoses, choke and kill. Misc. winterizing and housekeeping. Ensure everything is closed up, covered and secure. Report Number 5 Report Start Date 1/6/2025 Report End Date 1/7/2025 Last 24hr Summary Rig crew on location. PTW / PJSM. WHP's, Tbg - 0 psi, IA - 0 psi, OA - 0 psi. Vault set BPV & Test Dart. N/D Wellhead. N/U DSA, Mud Cross, BOPE, and Annular. R/U choke/kill lines. Run koomy lines. M/U 5-1/2" & 4-1/2" test joints. Set rig floor and stairs. Fill pits. Attempt multiple shell tests w/4-1/2" test joint. Driller's side VBR ram door leaking, tighten but unable to stop leak. C/O VBR door seal. Good shell test 250 psi / 3000 psi. Contact AOGCC to location (Sean Sullivan). Report Number 6 Report Start Date 1/7/2025 Report End Date 1/8/2025 Last 24hr Summary Completed BOPE test w/ 4-1/2" & 5-1/2" test joints as per sundry 250 psi / 3000 psi, Annular 3000 psi. Test witnessed by AOGCC Sean Sullivan. Zero failures. Pulled test plug / BPV from hanger profile. M/U landing joint to tubing hanger. Reverse circulate 1xBU 83 bbls @ 3.5 bpm / 300 psi. Flow check good. BOLDS. Pulled and released hanger, 72k to release, PUW 68k. L/D tubing hanger. R/U 4-1/2" handling equipment. R/U pipe handler. C/O hydraulic line and repair skate on pipe handler. Begin pulling and laying down 4-1/2" L-80 12.6# TXP BTC tubing. Fill hole every 15 joints. Report Number 7 Report Start Date 1/8/2025 Report End Date 1/9/2025 Last 24hr Summary Completed pulling 4-1/2" 12.6# BTC tubing. R/U to run 5-1/2" BTC completion w/Parker TTS. Lay out and strap 5-1/2" tubing. RIH w/5-1/2" 17# BTC completion as per approved tally. M/U Tubing hanger and land completion, PUW 75k, SOW 66k. Float shoe =5,360' ORKB, Float Collar = 5,315' ORKB. MIRU Fox cement. Pumped FW w/CI down tubing and establish 1:1 returns off IA. PJSM w/Fox, Cruz, & Rig 401 crew. Cement wet 01:30am. Fox pumped 38 bbls of 15.3 ppg cement down tubing while taking 1:1 returns off IA. Loaded wiper plug and displaced w/FW. Bumped plug at calculated displacement 123 bbls / 1600 psi. Bleed tubing pressure to zero, no flow on tubing or IA. R/D Fox cement and L/D landing joint. Set TWC. Rig down floor and begin N/D BOPE. Report Number 8 Report Start Date 1/9/2025 Report End Date 1/10/2025 Last 24hr Summary N/D BOPE, Install packoff, N/U production tree, Test packoff and tree to 5,000 psi, Pull 2 way check valve, Rig down for trucks Report Number 9 Report Start Date 1/12/2025 Report End Date 1/12/2025 Last 24hr Summary CCI Contract Labor for WE 1/12/2025 for KGF 13-06A Piping Mods Report Number 10 Report Start Date 1/12/2025 Report End Date 1/13/2025 Last 24hr Summary PTW / PJSM. MIRU YJ Eline w/stripper head and RIH w/CBL BHA. Tagged wiper plug @ 5,308' elm. Logged CBL from 5,308'-2500'. IA TOC = 2,770'. RDMO YJ Eline. Report Number 11 Report Start Date 1/17/2025 Report End Date 1/18/2025 Last 24hr Summary Equipment arrive on location. PTW, JSA with crew and productioon operators. MIRU CTU package. Install BOPE on tree. RIg up 1502 treating iron. Test BOPE 250/3500 psi. Good test. RIg up N2 pump and spot in Air Liquid N2 transport. Top off N2 pump. Field: Kenai Loop Sundry #: 324-663 State: ALASKA Rig/Service: 401Permit to Drill (PTD) #:223-112Permit to Drill (PTD) #:223-112 Wellbore API/UWI:50-133-20716-00-00 Page 2/2 Well Name: KEU KU 13-06A Report Printed: 2/17/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 12 Report Start Date 1/18/2025 Report End Date 1/19/2025 Last 24hr Summary PTW, JSA with crew. Transfer N2 rig up reverse out iron. Change pack offs. Crew had issues with brass in side door packoff assembly. Pick injector head and lubricator. Make up reverse out nozzle. Stab on well. PT stack 250/3500 psi. RIH taking displacemnt returns. Tag PBTD at 5330'. Pick up clean @ 27K. Come online with N2 reversing out. Recovered 118 bbls of water when nitrogen hit surface. Remain on Bottom at 5328' for an additional 20 minutes. All fluid recovered. POOH to surface. Close in Choke manifold. Shut in well with 1240 psi N2 pressure. Haul returns to G&I facility Total N2 pumped for reverse N2 lift 145,000 scf or 1745 gallons. Report Number 13 Report Start Date 1/19/2025 Report End Date 1/19/2025 Last 24hr Summary CCI Contract Labor & Equip for WE 1/19/2025 on KGF 13-06A Piping Mods Report Number 14 Report Start Date 1/21/2025 Report End Date 1/22/2025 Last 24hr Summary PTW/PJSM. MIRU Yellow Jacket E-line. P-test 250/2,500 psi. Run GPT - FL at 5,290'. Perforate UB 5A Sand (5,109' - 5,121') with well SI. Flow test well. Run GPT - FL at 5,263'. Perforate UB 5A Upper Sand (5,090' - 5,103') with well SI. SDFN. Turn well over to Production to flow test. Report Number 15 Report Start Date 1/22/2025 Report End Date 1/23/2025 Last 24hr Summary PTW/PJSM. SI well. Run GPT - FL at 5,250'. Perforate UB 5 Sand (5,058' - 5,077') with well shut-in. Flow test well. Perforate UB 1 Sand (4,786' - 4,798') with well shut-in. SDFN. Turn well over to Production to flow test. Report Number 16 Report Start Date 1/24/2025 Report End Date 1/25/2025 Last 24hr Summary PTW/PJSM. Run GPT. Found fluid level at 3,650'. Pressure up on well with gas to 695 psi. Push fluid down to 4,800'. Set CIBP at 4,780'. Perforate UB Sand (4,748' - 4,764') with well shut-in. RDMO. Report Number 17 Report Start Date 2/14/2025 Report End Date 2/15/2025 Last 24hr Summary Performed MIT-IA to 2274 psi. Lost 25 psi first 15 min, lost 23 psi second 15 minutes. Let test run extra 30 minutes and showed stabilization. MIT-IA passed. Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Tubing 56 56 56 56 56 56 IA 0 2274 2249 2226 2204 2185 Field: Kenai Loop Sundry #: 324-663 State: ALASKA Rig/Service: 401 _____________________________________________________________________________________ Updated By SAR 1-30-25 Schematic Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ Tieback Detail 5-1/2”Tubing 17 / L-80 / BTC SCC 4.767”Surface 5,362’ JEWELRY DETAIL No Depth ID Item 1 4,780’CIBP 1/24/25 2 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 3 5,490’CIBP 12/5/24 4 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 5 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 6 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 7 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD UB 4,748’4,764’4,700’4,716’16’1/24/25 Open UB 1 4,786’4,798’4,738’4,749’12’1/22/25 Isolated UB 5 5,058’5,077’5,006’5,024’19’1/22/25 Isolated UB 5A Upper 5,090’5,103’5,037’5,050’13’1/21/25 Isolated UB 5A 5,109’5,121’5,056’5,068’12’1/21/25 Isolated LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Isolated LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Isolated LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Isolated LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Isolated LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Isolated LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Isolated LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Isolated LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Isolated LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Isolated LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250216 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. 162-037 T40080 T40081 T40082 T40082 T40083 T40084 T40085 T40086 T40087 T40088 T40089 T40090 T40091 T40092 T40093 T40094 T40095 T40096 T40097 KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.18 13:06:47 -09'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI UNIT 13-06A JBR 03/13/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Tested with 4-1/2" and 5-1/5" Test joints. Test H2s and LEL alarms (cal 1-6-24). 401 currently using 2 pit tanks tested both lvl indicators. When testing accumulator unit found leaking air valve to air pump. Tighten valve packing and stopped leakage. Horrible weather made for swapping test joints a long endeavor. No other issues. Test Results TEST DATA Rig Rep:Ryan ChabreOperator:Hilcorp Alaska, LLC Operator Rep:Tyson Renton Rig Owner/Rig No.:Hilcorp 401 PTD#:2231120 DATE:1/7/2025 Type Operation:WRKOV Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSTS250118155230 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5.5 MASP: 1672 Sundry No: 324-663 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 1 P Inside BOP 1 P FSV Misc 0 NA 8 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 3-1/2"x 5-1/2"P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 4-1/16 P HCR Valves 1 4-1/16 P Kill Line Valves 3 2-1/16, 4-1/16 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2050 200 PSI Attained P18 Full Pressure Attained P82 Blind Switch Covers:Pall stations Bottle precharge NA Nitgn Btls# &psi (avg)P6@1650 ACC Misc FP1 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P18 #1 Rams P7 #2 Rams P7 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke NA2 HCR Kill NA0 9 9 9 9 9999 9 9 9When testing accumulator unit found leaking air valve to air pump Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887 KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -09'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CT & N2 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? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,830'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,560psi Intermediate 4,790psi Production 8,540psi Liner 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng LTP; N/A 5,451' MD/5,394' TVD; N/A, N/A 9,723'7,125'7,049' Kenai C.L.U.Beluga/Up Tyonek GP 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 13-06ACO 510C Same 9,301'4-1/2" ~1672 psi 3,951' See Schematic Length December 8, 2024 4-1/2" Tieback 9,402' Perforation Depth MD (ft): 6,066' See Attached Schematic 6,890psi 2,980psi 5,860psi 120' 6,001' 120' 1,699' Size 120' 7-5/8"6,066' 1,699' MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 5,464' 9,020psi 1,689' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 223-112 50-133-20716-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2024.11.21 13:48:19 -09'00' 324-663 By Grace Christianson at 7:44 am, Nov 22, 2024 A.Dewhurst 25NOV24 DSR-11/22/24 10-404 X Perform MITIA to 2000 psi within 30 days after the final perforations are added and the well has been put on production to confirm cement is competent above top perf. BOP test to 3000 psi, Annular test to 2500 psi Submit CBL to AOGCC and obtain approval before adding perfs. BJM 11/26/24 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.26 15:25:43 -09'00'11/26/24 RBDMS JSB 112924 Initial Completion Well: KU 13-06A Well Name: KU 13-06A API Number: 50-133-20716-00-00 Current Status: Gas Producer Permit to Drill Number: 223-112 First Call Engineer: Chad Helgeson (907) 229-4824 (c) Second Call Engineer: Scott Warner (907) 830-8863 (c) Maximum Expected BHP: 2179 psi @ 5068’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1672 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.66 psi/ft using 12.8 ppg EMW FIT at the surface casing shoe 12/19/23 Shallowest Potential Perf TVD: MPSP/(0.66-0.1) = 1672 psi / 0.56 = 2986‘ TVD Top of Pools per CO 510C: Beluga/Upper Tyonek Pool: 4730’ MD, ~4683' TVD Brief Well Summary KU 13-06A was drilled and completed with Hilcorp Rig 169 January 2024 targeting Tyonek, Upper Tyonek and Lower Beluga sands at Kenai Gas Field. The well was completed and did not find any commercial gas with current completion. The goal of this project is to pull the tubing and replace with new 5-1/2” tubing that will be cemented in place, perforate the well in the Beluga/Upper Tyonek Pool per CO 510C. Wellbore Conditions: x Tubing Annulus is filled with 12 ppg drilling mud & tested to 3,000psi x 7-5/8” Intermediate casing – 6,066’ (cemented to 1774’) x Fill tagged @ 7094’ (4/5/24) x Fluid tagged at 4125’ (4/5/24) x Current Tubing pressure – 164 psi Pool Tops: x Sterling Pool 6 – 4499’ MD/4454’ TVD x Beluga/Upper Tyonek Gas Pool – 4730’ MD/4683’ TVD Eline Procedure 1. Review all approved COAs 2. MIRU E-line, PT lubricator to 2000/250 psi 3. RIH and set CIBP @ ~5500’ Note: This plug is not a pool isolation plug, additional perfs will be added in current pool after the tubing is changed out. 4. Fill tubing with 8.4 ppg Produced water (60-80 bbls) 5. Pressure up tubing to ~1000 psi and hold 6. RIH and tubing punch @ ~5420’ 7. POOH & RDMO Eline RWO Procedure 8. MIRU 401 workover rig 9. Reverse circulate well with 8.4 ppg fluid (ensure 12 ppg mud on backside of tubing is circulated out from well – 143 bbls of 12 ppg mud) and well is killed. Circ entire wellbore volume ( 10. Pressure test plug & casing to 2000 psi 11. Install TWC, ND tree, NU 13-5/8” BOPs w/ VBRs 12. Test BOPE Initial Completion Well: KU 13-06A ¾ Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. (Notify AOGCC 24 hours in advance of test to allow them to witness test). ¾ If the BOP is used to shut in on the well in a well control situation or if BOP equipment could be compromised, ALL BOP components utilized for well control or compromised must be tested prior to the next trip into the wellbore. ¾ BOPs will be closed as needed to circulate the well during this workover. 13. Pull TWC 14. Pick up on hanger with short joint 15. Pull tubing out of seal bore (no latch) 16. Pull and lay down 4-1/2” tubing 17. PU ~5300’ of new 5-1/2” 17# tubing with float shoe & collar with short joints @ ~4600’ & ~4300’ with centralizers every joint from 5300’ to 3500’ 18. RIH and land tubing in hanger 19. MIRU Cement unit, pressure test lines (May complete cement job with tree on well, depending on weather and timing of rig move, etc) 20. Pump 60 bbls of Corrosion Inhibited water down production tubing 21. Mix and pump 39 bbls of 15.3 ppg cement down 5-1/2” production string a. Plan TOC in 5-1/2” x 7-5/8” annulus – approx. 3,000ft b. Pump wiper dart and bump plug with 123 bbls of fresh water 22. Pressure tubing up to 800psi after bumping plug, check floats 23. Set TWC 24. ND BOPE, NU Tree and PT to 5000 psi 25. Pull TWC 26. RDMO Rig 401 Completion Procedure 27. MIRU E-line 28. Log CBL in 5-1/2” production liner from PBTD (est 5220) to above TOC x Send CBL to the state for review 29. RDMO EL 30. MIT-T to 3500 psi and MIT-IA to 2000 psi 31. MIRU Coil tubing 32. PT lubricator to 250/3500psi x Provide AOGCC 24hr-notice for BOP test 33. PU reverse nozzle, RIH, tag and reverse out fluid from well with N2. Total recovery should be 123 bbls of fresh water a. Strap tank pre/post unload b. If tag is not deeper than 5150’ PU motor and mill and cleanout well to 5200’ 34. POOH leaving 1700 psi of N2 on well after reversing fluid out 35. RDMO coil tubing Perf Procedure 36. MIRU E-line 37. PT lubricator to 250/2500psi Shoe track is 42.5' long per Chad Helgeson email 11/26/24. -bjm Initial Completion Well: KU 13-06A 38. PU 2-3/4” HC perf guns and perforate proposed intervals bottoms up, testing each sand as desired by reservoir engineer Sands Top MD Btm MD Top TVD Btm TVD FT UB ±4,748’ ±4,764’ ±4,700’ ±4,716’ ±16’ UB 1 ±4,786’ ±4,798’ ±4,738’ ±4,749’ ±12’ UB 5 ±5,058’ ±5,077’ ±5,006’ ±5,024’ ±19’ UB 5A Upper ±5,090’ ±5,103’ ±5,037’ ±5,050’ ±13’ UB 5A ±5,109’ ±5,121’ ±5,056’ ±5,068’ ±12’ 39. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing b. Above perfs will be shot in the Kenai Beluga/Upper Tyonek Gas Pool 1 governed by CO 510C 40. RD E-Line Unit and turn well over to production 41. Operations to flow well and test zones 42. Test SVS as per 20 AAC 25.265 once stable flow is achieved x Notify AOGCC 24hrs in advance of testing SVS E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 43. MIRU Eline and N2 pump truck 44. Pressure test equipment to 3,500 psi High/250 psi Low 45. Eline run PT to find fluid level 46. RU N2 or use gas lift and push fluid below perfs (verify fluid depth with PT tool) 47. Set 5-1/2” CIBP or patch to isolate water or sand production Coil Tubing Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 48. MIRU Coiled Tubing Unit, PT BOPE to 3,500 psi High/250 psi Low x Provide AOGCC 24hrs notice of BOP test 49. PU wash nozzle or motor & mill, RIH and cleanout well to below perfs or proposed plug depth 50. Set plug as necessary with coil or Eline 51. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 52. RDMO coil tubing Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current wellhead Schematic 4. Proposed Wellhead Schematic 5. 13-3/8” BOP Stack 6. Nitrogen procedure 7. Fox CT BOP Drawing Perform MITIA to 2000 psi within 30 days after the final perforations are added and the well has been put on production to confirm cement is competent above top perf. -bjm _____________________________________________________________________________________ Updated by CJD 04-12-24 CURRENT SCHEMATIC Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,402’ Tieback Detail 4-1/2”Tieback 12.6 / L-80 / TXP BTC 3.958”Surface 5,464’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go 4 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 5 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 6 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 7 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Open LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Open LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Open LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Open LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Open LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Open LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Open LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Open LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Open LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated _____________________________________________________________________________________ Updated By CAH 11-18-24 PROPOSED Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,402’ Tieback Detail 5-1/2”Tubing 17 / L-80 / BTC SCC 4.767”Surface ~5,300’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 ±5,500’CIBP 3 ±6,200’CIBP 4 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 5 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 6 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 7 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD UB ±4,748’±4,764’±4,700’±4,716’±16’TBD Proposed UB 1 ±4,786’±4,798’±4,738’±4,749’±12’TBD Proposed UB 5 ±5,058’±5,077’±5,006’±5,024’±19’TBD Proposed UB 5A Upper ±5,090’±5,103’±5,037’±5,050’±13’TBD Proposed UB 5A ±5,109’±5,121’±5,056’±5,068’±12’TBD Proposed LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Isolated LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Isolated LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Isolated LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Isolated LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Isolated LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Isolated LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Isolated LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Isolated LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Isolated LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated Place 25' of cement on top of plug at +/-6200' MD. -bjm Superseded Kenai Gas Field KU 13-06A 11/06/23 Starting head, Cactus C-29L, 16 3/4 3M x 16'’ SOW, w/ 2- 2 1/16 5M SSO Multi-bowl, Cactus MBS-2, 16 3/4 3M x 11 5M, w/ 4- 2 1/16 5M SSO 16'’ 7 5/8'’ 10 ¾’’ Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim BHTA, Bowen, 4 1/16 5M FE x 6.5 Otis quick union top Valve, Master, CIW-FLS, 4 1/16 10M FE, HWO, EE trim Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Kenai Gas Field KU 13-06A 16 x 10 3/4 x 7 5/8 x 4 ½ Tubing hanger, Cactus TC-1A- EN-CCL, 11 x 4 ½ EUE 8rd lift and susp, w/ 4'’ type H BPV profile, 2- 3/8 CCL ports, 6 ¼ EN 4 ½’’ Tree adapter, Cactus, 11'’ 5M bottom x 4 1/16 10M top, prepped f/ 2- control lines Kenai Gas Field KU 13-06A-Proposed 11/19/24 Starting head, Cactus C-29L, 16 3/4 3M x 16'’ SOW, w/ 2- 2 1/16 5M SSO Multi-bowl, Cactus MBS-2, 16 3/4 3M x 11 5M, w/ 4- 2 1/16 5M SSO 16'’ 7 5/8'’ 10 ¾’’ Valve, Master, WKM-M, 5 1/8 5M FE, HWO, EE trim BHTA, Bowen, 5 1/8 5M FE x 9.5 Otis quick union top Valve, Master, WKM-M, 5 1/8 5M FE, HWO, EE trim Valve, Swab, WKM-M, 5 1/8 5M FE, HWO, EE trim Kenai Gas Field KU 13-06A 16 x 10 3/4 x 7 5/8 x 5 ½ 5 ½’’ Tree adapter, Cactus, 11'’ 5M bottom x 5 1/8 5M top Tubing hanger, CXS, 11 X 5 ¾ left hand stub acme lift X 5 ½ DWC-C susp, w/ 5'’ Type H BPV profile The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 13-5/8"Spherical Annular Height: 46" Weight: 12,806 13-5/8"LWS Double BOP Height: 37" Width: 93" Weight 9,900 lbs. TOP RAMS 2-7/8" TO 5-1/2" MULTI- RAMS BOTTOM RAMS BLIND RAMS 13-5/8"Mud Cross W/ 4- 1/16" outlets Height:28.5" Width 31" Dual 4-1/16" Manual Gate valves W/ DSA to 2-1/16" 4-1/16" Manual Gate valve & 4-1/16" HCR W/ DSA to 2-1/16" Full Mud Cross Assy. width w/ valves installed Width: 98.5" Weight: 2200 lbs. Kill side Choke side Height Addition for Ring Gaskets: 0" BOP Total Height: 111.5" BOP Total weight: 24,906 lbs. 13-5/8" 5m BOP Package W/ 4-1/16" Valves STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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:Chad Helgeson To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] KU 13-06A (PTD 223-112) RWO sundry Date:Tuesday, November 26, 2024 11:08:59 AM Attachments:KU 13-06A PROPOSED 11-22-24.pdf See Below for responses in red Italic. Chad Helgeson From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, November 26, 2024 10:37 AM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] KU 13-06A (PTD 223-112) RWO sundry Chad, A couple questions regarding this sundry: 1. What is the length of your planned float shoe track on the 5-1/2” liner? (41.56ft +/-, however there is enough room to run an ~83ft shoe track and leave rat hole for additional perfs, if determined in the field that a longer shoe track is needed, but without any open hole or perfs, as shorter shoe track should be fine) 2. For displacement calcs, I think you might be using drift ID instead of nominal. The capacity of 5-1/2” 17# casing is 0.0232 bbl/ft (ID of 4.892”). That gives displacement volume of 126 bbls. Almost the same as what you have in the program, but not quite. Could you double check your displacement calcs? (The displacement volume will be finalized after the completion is run. We do not plan to install pup joints to land exactly at 5300ft, so this volume will be determined based on where the float equipment is placed in the well. When I calculated the volume for the program, I used 0.0232 bbl/ft x 5300ft = 122.96 bbls. This number will be adjusted based on final depth the completion is run.) Let me know if you need more information on this one as I was confused by the question. 3. The proposed diagram has a CIBP set at 6200’ MD, but procedure doesn’t mention it. Which is correct? (The procedure is correct. Attached is the correct proposed schematic.) Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. 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No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. _____________________________________________________________________________________ Updated By CAH 11-22-24 PROPOSED Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,402’ Tieback Detail 5-1/2”Tubing 17 / L-80 / BTC SCC 4.767”Surface ~5,300’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 ±5,500’CIBP 4 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 5 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 6 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 7 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD UB ±4,748’±4,764’±4,700’±4,716’±16’TBD Proposed UB 1 ±4,786’±4,798’±4,738’±4,749’±12’TBD Proposed UB 5 ±5,058’±5,077’±5,006’±5,024’±19’TBD Proposed UB 5A Upper ±5,090’±5,103’±5,037’±5,050’±13’TBD Proposed UB 5A ±5,109’±5,121’±5,056’±5,068’±12’TBD Proposed LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Isolated LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Isolated LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Isolated LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Isolated LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Isolated LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Isolated LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Isolated LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Isolated LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Isolated LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: WAG Injector N-07B (PTD #2231220) will lapse on AOGCC MIT-IA Date:Friday, July 19, 2024 10:03:45 AM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Friday, July 19, 2024 7:18 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Torin Roschinger <Torin.Roschinger@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: WAG Injector N-07B (PTD #2231220) will lapse on AOGCC MIT-IA Mr. Wallace, Injector N-07B (PTD #2231220) is due for its 4-year MIT-IA in July 2024. The well is currently shut-in and there are no plans to put it on injection. The well is now classified as NOT OPERABLE for tracking purposes. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/1/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240501 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# HV B-13 50231200320000 207151 4/10/2024 YELLOW JACKET GPT-PERF KU 13-06A 50133207160000 223112 3/27/2024 YELLOW JACKET GPT-PERF KU 13-06A 50133207160000 223112 4/1/2024 YELLOW JACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/22/2024 YELLOW JACKET GPT-PERF KU 33-08 50133207180000 224008 4/30/2024 YELLOW JACKET SCBL KU 41-08 50133207170000 224005 4/23/2024 YELLOW JACKET SCBL KU 41-08 50133207170000 224005 4/11/2024 AK E-LINE GPT/Perf/CIBP MPU F-30A 50029226230100 213188 4/12/2024 READ CaliperSurvey MPU S-13 50029230930000 202114 4/16/2024 READ Caliper Survey NCI A-17 50883201880000 223031 3/22/2024 AK E-LINE Perf Paxton 6 50133207070000 222054 4/14/2024 AK E-LINE GPT/Perf PBU PTM P1-13 50029223720000 193074 4/8/2024 YELLOW JACKET CBL SRU 232-15 50133207140000 223091 3/28/2024 YELLOW JACKET GPT-PLUG-PERF SRU 232-15 50133207140000 223091 4/22/2024 YELLOW JACKET PLUG-PERF SRU 241-33B 50133206960000 221053 4/12/2024 YELLOW JACKET GPT-PERF SRU 241-33B 50133206960000 221053 4/4/2024 YELLOW JACKET GPT-PERF Please include current contact information if different from above. T38745 T38746 T38746 T38746 T38747 T38748 T38748 T38749 T38750 T38751 T38752 T38753 T38754 T38754 T38755 T38755 KU 13-06A 50133207160000 223112 3/27/2024 YELLOW JACKET GPT-PERF KU 13-06A 50133207160000 223112 4/1/2024 YELLOW JACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/22/2024 YELLOW JACKET GPT-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.05.13 09:32:35 -08'00' 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Kenai Gas Field GL:65.2' BF:N/A Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 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: 23. BOTTOM 16" X-56 120' 10-3/4" L-80 1,690' 7-5/8" L-80 6,001' 4-1/2" L-80 5,337' 4-1/2" L-80 5,406' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 01.216 0 3/7/2024 24 Flow Tubing 1.2 240 N/A2400 N/A N/A N/A 9,830' MD / 9,723' TVD 7,125' MD / 7,049' TVD 1353' FSL, 1154' FWL, Sec 6, T4N, R11W, SM, AK 1800' FSL, 893' FWL, Sec 6, T4N, R11W, SM, AK Choke Size: Surface Per 20 AAC 25.283 (i)(2) attach electronic information 29.7# 9,402' Surface 5,393' 84# 45.5# 120' Water-Bbl: PRODUCTION TEST 2/11/2024 Date of Test: Oil-Bbl: Flowing *** Please see attached schematic for perforation detail *** Gas-Oil Ratio: AMOUNT PULLED 272172 271919 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. KU 13-06AJanuary 1, 2024418' FSL, 1065' FWL, Sec 6, T4N, R11W, SM, AK 83.2' BOTTOMCASINGWT. PER FT.GRADE CEMENTING RECORD 2363305 SETTING DEPTH TVD 2363758 TOP HOLE SIZE CBL 12-28-23 / CBL 1-12-24, GPT/Perf Correlation Logs, LWD (PCG, ADR, CTN, ALD, PWD, DDSR) Tyonek GP1, Beluga/Upper Tyonek GP FEE A028142 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 271981 2362473 50-133-20716-00-00December 14, 2023 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 2/10/2024 223-112 / 324-011 / 324-112 N/A PACKER SET (MD/TVD) Surface Conductor 12.6# 13-1/2" Driven Surface L - 317 sx / T - 304 sx 13.5# Surface 5,451' 1,699' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): Surface 6,066' Surface ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, L - 401 sx / T - 99 sx6-3/4" TUBING RECORD Tieback Assy.5,464' L - 653 sx / T - 154 sx Surface 9-7/8" Tieback N/AN/A SIZE DEPTH SET (MD) N/A WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 11:36 am, Apr 12, 2024 Completed 2/10/2024 JSB RBDMS JSB 050124 GSFD 2/21/2025 DSR-5/6/24 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval 6,245' (LB 1B) 6,198' 6237' 6170' 6501' 6431' 6744' 6672' 6911' 6837' 7116' 7040' 7264' 7187' 7361' 7282' 7392' 7313' 7467' 7388' 8723' 8630' 8856' 8762' 8998' 8902' Tyonek D6 9,737' 9,631' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Digital Signature with Date:Contact Email:cdinger@hilcorp.com Contact Phone: 907-777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: INSTRUCTIONS LB 6 TY 72 8 TY 86 2B Ty D1 Ty D2 Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Reports, Definitive Directional Surveys. Authorized Title: Drilling Manager 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. UP TY 1A LB 4 LB 1B LB 5 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 inc lination 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. TY 73 1 LB 2A TPI (Top of Producing Interval). Authorized Name and LB 3 Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS No NoSidewall Cores: Yes No Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Drilling Manager 04/12/24 Monty M Myers _____________________________________________________________________________________ Updated by CJD 04-12-24 CURRENT SCHEMATIC Kenai Gas Field Well: KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,402’ Tieback Detail 4-1/2”Tieback 12.6 / L-80 / TXP BTC 3.958”Surface 5,464’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go 4 7,125’CIBP w/ 10ft of 15.8ppg cement (4/1/24) 5 8,885’CIBP w/ 10ft of 15.8ppg cement (3/22/24) 6 9,005’CIBP w/ 25ft of 15.8ppg cement (3/22/24) 7 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD LB 1B 6,245'6,260'6,177’6,192’15'4/2/24 Open LB 1C 6,313'6,326'6,245’6,258’13'4/2/24 Open LB 1F 6,433’6,442’6,363’6,372’9’4/2/24 Open LB 2C 6,629'6,648'6,558’6,576’19'4/2/24 Open LB 2D 6,662'6,667'6,590’6,595’5'4/1/24 Open LB 3B Up 1 6,819'6,831'6,746’6,757’12'4/1/24 Open LB 3B Up 2 6,835'6,839'6,761’6,765’4'4/1/24 Open LB 3B Mid 6,848'6,853'6,774’6,779’5'4/1/24 Open LB 4 Up 6,927'6,931’6,852’6,856’4'4/1/24 Open LB 5A 7,141'7,153'7,064’7,076’12'3/27/24 Isolated LB 5A Lwr 7,174'7,179'7,097’7,102’5'3/27/24 Isolated LB 5C 7,243'7,255'7,165’7,177’12'3/27/24 Isolated LB 6A 7,282'7,295'7,204’7,217’13'3/27/24 Isolated TY 72_8 7,362'7,382'7,283’7,303’20'3/23/24 Isolated TY 73_1 7,421'7,429'7,341’7,349’8'3/23/24 Isolated TY D1 8,914'8,945'8,819’8,849’31'3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,919’8,978’59’02/10/24 Isolated Page 1/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:12/10/2023 End Date:1/9/2024 Report Number 1 Report Start Date 12/10/2023 Report End Date 12/11/2023 Operation Remove rig tongs winterize test pump, replace seal on #10 accumulator bottle, remove bails on top drive R/D pason flow paddle, R/D gas buster, blow down water and steam, Rig down gen #3, Prep top drive to R/D, L/D toue bushing, remove all tarps from rig floor Continue rigging down top drive, install top drive in craddle, lower top drive off rig floor, prep and scope derrick down. Cont. R/D mud tanks, cool down boilers. Remove derrick cylinder covers. R/D iron rough neck. Remove turnbuckles in derrick, hang blocks and cut 47.5' of drill line. Prep derrick to be lowered on to carrier. Remove brake linkage. Cont. R/D mud tanks. Prep doghouse to be lowered. Folded over beaver slide and R/D catwalk, electrical and iron roughneck HPU. Removed air lines. Report Number 2 Report Start Date 12/11/2023 Report End Date 12/12/2023 Operation R/D office and sleeper trailers, movers on location @ 0700 hrs, spot in cranes and start removing windwalls, Load out office trailers and transport to KGF, Continue R/D components and prep to move. Spot in office trailers and sleeper, spot change shack and mechanics and electricians shops, get power and comms going, continue rigging down and splitting apart rig, Lower mast and prep to remove, Crane off derrick and draworks on to trucks, Load sub on trailer Lay down felt, liner and set rig mats. Set pony sub. Raised hand rails on sub base, mud tanks and dog house. Hook up power to expiditor, DSM and break trailer. Clear rig mats of ice. Level pony sub and clear of ice. Put up lights on pump houses and pit roofs. Unloaded iron roughneck hpu, cleear steam heater and spotted. Unloaded iron roughneck, porta poties, and jetheater. Performed mast inspection. Tied up water and electric lines under the break shack. Report Number 3 Report Start Date 12/12/2023 Report End Date 12/13/2023 Operation Moved cranes to KGF, held PJSM, staged cranes, set sub and centered over well, set carrier and derrick, set iron roughneck and raised V door wall, pinned rams and stood mast. Set doghouse skid and raised same, set jig, pump 1 and pit 1, cont transporting rig equipment from Swanson River to KGF. Set HPU skid, shimmed modules for level, set pits 2 and 3 and raised the roof tops, set poorboy degasser skid, laid liner and mats for catwalk, strung cords between mods for power and lights, staged crane and set centrifuge, hung windwalls on pits, set choke house, set upright water tank, put gen on line, set catwalk, chase down 20" pipe for conductor riser extension. Hook up cameras, pason lines, and hydraulic lines for topdrive. Install equalizer lines for mud tanks, and jumper lines for mud pumps. Install s-pipe for stand pipe. Install brake linkage. Spool up drill line. Prep derrick to scope. Install turn buckles and scope derrick. Unhook bridle lines from blocks. Installed TEE and bottom turn buckles for torque tube. Leveled sub base. Hung and rigging up topdrive. Staging up boilers. Report Number 4 Report Start Date 12/13/2023 Report End Date 12/14/2023 Operation Installed lower conductor riser on wellhead, PU upper section and obtained measurement for needed extension, L/D for transport to CCI weld shop, expediter located 20” pipe for extension and dropped off at weld shop, loaded upper section and shaker slide for welder repair. Gave AOGCC 24 hr notice for spud. RU topdrive and function tested same, found bad hyd fitting on compensator equalizer line, rig mechanic C/O out hyd hose and fittings. Installed Handy Berm and took on rig fuel. RU comm's to service shacks, rig electrician tested all audio/visual gas alarms, C/O 8" hopper valve, hung choke line shock hose from choke house to cellar, adjusted torque tube to center topdrive over hole, installed standpipe bleeder hose, pressured up topdrive compensators, recieved two loads surface casing, installed upper riser section. R/U centrifuge and bump test. Bump test all mix pumps. Dress shakers with 120's. Install conductor riser, flow line and 4" valves. Hang tarps in cellar. Load 4.5" on cat walk and starp. Check top drive and load cell torques. Build 20 stands and rack back in derrick. Pump fluid through mud lines and PT to 1200psi. Pump through mixing/gun lines and move water through pits and check for leaks-good. Strap and tally 30 more jnts and 16 jnts of HWDP, P/U and stand back in derrick. Rig accepted at 06:00am. Report Number 5 Report Start Date 12/14/2023 Report End Date 12/15/2023 Operation Cont PU rack back total 40 stands DP and 8 stands HWDP, tagged bottom at 128’. Welder finished couple small projects on rig, pits and pump skid. Drifted surface casing, cont building spud mud, wait on delivery of Sperry directional tools. Dummy ran hanger/landing joint, cont building last of spud mud, PU racked back jar stand and NM flex DC's, strapped surface casing, Sperry tools arrived on location at 14:30 and did not recieve 8" DM or TM collars. Notified appropriate personnel in town, decision made to run 6 3/4" smart tools on top of 8" motor. Prepped 6 3/4" tools for PU, set 14" ID wear ring (incident with loader, wear ring/run tool put dent in exterior pick up bed, made appropriate notifications), staged bit and breaker on rig floor. M/U 13.5" surface BHA #1 and shallow pulse test-good. Drill 13.5” Hole F/ 133’ t/ 219' MD (219' TVD) Total 86 (AROP 172') 459 GPM= 1050psi, 30 RPM=2-3k TRQ, 2-3k WOB, ECD 9.39 Max Gas 2u. MW 9.2ppg P/U 32k, S/O 32k, ROT 32k. POOH and P/U Flex collars. Drill 13.5” Hole F/ 219’ t/ 402' MD (402' TVD) Total 183' (AROP 92') 459 GPM= 1150psi, 36 RPM=3.5k TRQ, 2-3k WOB, ECD 9.39 Max Gas 2u. MW 9.2ppg P/U 34k, S/O 30k, ROT 33k. Drill 13.5” Hole F/ 402’ t/ 841' MD (837' TVD) Total 439 (AROP 88') 500 GPM= 1150psi, 36 RPM=3.5k TRQ, 2-3k WOB, ECD 9.13 Max Gas 4u. MW 9.2ppg P/U 45k, S/O 38k, ROT 45k. CBU x2 at 500GPM=1470PSI 40RPM=2.1kTQ. Blow down and flow check well-static. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169Permit to Drill (PTD) #:223-112 Page 2/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Report Number 6 Report Start Date 12/15/2023 Report End Date 12/16/2023 Operation Pulled up hole on elevators from 841' to 349' (jars), S/O and parked at 435'. Up wt 48K. Serviced rig and topdrive TIH from 435' to 800', filled pipe and washed last stand to bottom. Cont drilling 13 1/2" hole from 841' to 1205', rot wob 3 to 10K, 515 gpm-1519 psi, 50 rpm-2390 ft/lbs on bott torque, 120 ft/hr ROP. (slowed ROP to slow cuttings hauled to G&I as they lost their water pump, CCI hauling water to G&I from rig to allow cleaning dump tank and process of cuttings). MW 9/vis 270, ECD's 9.6 to 9.8 ppg, BGG 3 units, max gas 41 units. Recieved 317 sacks lead cement in silo. Cont drilling from 1205' to TD at 1704' md/1694' tvd, sliding wob 15K, 511 gpm-1507 psi, 107 psi diff, 95 to 130 ft/hr ROP. Rot wob 1-5K, 510 gpm-1577 psi, 50 rpm -3100 ft/lbs on bott torque, 120 ft/hr ROP. MW 9.0/vis 137, ECD's 9.5 to 9.6 ppg, BGG 6 units, max gas 64 units. Obtained on bottom survey and CBU twice while Geo reviews logs. Geo gave the okay for TD at 1704'. POOH on elevators t/341' without issue. P/U 65k S/O 65k. Hole fill calc-13.1bbl, act-15.3bbl Grease blocks, topdrive, drawworks, iron rough neck, and crown. Clean suction and discharge screens on MP's, 50% packed off. TIH on elevaotrs f/341' t/1704', wash last stand to bottom 500gpm=1590psi 50rpm=2.7k tq. Pump sweep around, back 35 bbl late with a 15% increase. 500gpm=1577pis 50rpm=2.9k tq. Flow check well-slight seepage. POOH on elevators f/1704' t/413' P/U-65k S/O-65k. Hole fill calf-8.2bbl act-11.5bbl Rack back HWDP and L/D jar stnd. Rack back 6-3/4" flex collars. Down load MWD tools. L/D rest of BHA #1. Bit graded: 1-1-WT-A-E-I-NO-TD. Hole fill: calc- 20.26bbls act-23.1bbl. Clean and clear rig floor while monitoring well on trip tank. Pull wear bushing. R/U Parker TRS casing eqiupment, RU fill up hose, staged centralizers. Staged casing on racks, held PJSM. Report Number 7 Report Start Date 12/16/2023 Report End Date 12/17/2023 Operation PU and MU 10 3/4" shoe track filling each joint, stroked and checked floats (OK), cont PU and single in hole total 41 jnts. Seen shoulders on connection engage at 8,000 ft/lbs, then torqued to 20,000 ft/lbs. Filled on the fly, topped off every 5 jnts. At 1670' installed bail extensions on topdrive, installed circ swedge in top of landing jnt and MU same with topdrive. Broke circ at 135 gpm-76 psi, RD casing tongs and backup hand tongs. Increased to 190 gpm-50 psi and washed down landing hanger on seat with no issue. Up wt 90K, dwn wt 77K. Cont to circt at 211 gpm-52 psi with 9.1 ppg mud, laid down liner and spotted cementers. Staged plug launcher on floor and loaded plugs, MU jumper hose from cement line to rotary table. Held PJSM with rig team and cementers. Shut down pump and broke off topdrive and circ swedge. Blew down topdrive, blew air down cement line back to pump truck, installed plug launcher on stump and MU cement line. Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 800 psi low 4000 psi high, good tests. Halliburton pumped 57.5 bbls 10.5 ppg Tuned Spacer at 3.2 bpm-33 psi, dropped bottom plug and pumped 138 bbls (317 sx) 12 ppg Type I II lead cement at 5 bpm-33 to 91 psi, followed by 62 bbls (304 sx) 15.8 ppg Type I II tail cement at 5 bpm-91 to 170 psi. Halliburton dropped top plug then displaced with 9.1 ppg Spud Mud at 5 bpm 102 to 515 psi. Slowed pump to 3 bpm with 15 bbl to go. Did bump the plug 155 bbls into displacement (calculated 155.5 bbls). Held 1062 psi (FCP of 490 psi) for 3 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 57.5 bbls of Spacer returns to surface and 65 bbls lead cement to surface. Added Bridge Maker LCM to lead cement at 2.4 pps. Mix water temp 70 deg. Pumped 75% excess on lead and 50% on tail. Lost 0 bbls throughout the job. Did reciprocate casing. Up wt 90K, dwn wt 80K upon landing hanger at start of tail. CIP at 16:00 hrs, 12/16/2023. RD and released Halliburton. Broke off cement line and blew down to pump truck, removed plug launcher and flushed same, drained and flushed conductor riser with black water, B/O landing joint and flushed inside, L?D same. PU and MU packoff assembly, landed same with all topdrive weight applied. Wellhead Rep attempted to test packoff seals at 3000 psi, could not get a test, pulled packoff and found we had RILD's on top seal. Replaced seals and re-ran assembly on stand of HWDP, plus topdrive weight, pulled lockdown and verified assembly fully seated. RILD's and tested seals to 3000 psi. Backed out run tool and racked back stand. ND conductor riser and removed from cellar with crane, staged multi-bowl wellhead in cellar and set same. Bolted up on casing flange while crane transfered BOP stack to cellar bridge cranes. N/U wellhead test hanger neck seals and void to 3000psi/15 min-good test. Install test plug, and stab spacer spool. Remove 4" valves and remove the shipping beams. Nipple up spacer spool and BOPE's. Brake linkage parted while lifting sub base causing blocks and topdrive to free fall to the floor. Made notificatoin to HSE reps and Drilling manager. Had a safety stand down with the rig crew to re-group and a plan is in place to start making repairs. Secure blocks with tuggers. Pull covers off of drawworks and inspect all damaged equipment. Unspool drilling line. Report Number 8 Report Start Date 12/17/2023 Report End Date 12/18/2023 Operation Removed equalizer bar and brake shaft, all linkages from draw works. Removed broken crown saver actuator ram. Notified KGF Production Rep of need to use cutting torch in derrick, no issue with fire eye's, CCI spotted crane, welder and derrickman secured derrick board to crane and cut board loose from wrap around beam, lowered same to ground level. Cleaned front of draw works structure and componants for inspection and MPI. Hilcorp Inspector MPI'd various areas of draw works and brake linkage parts, welder repairing derrick board. Welder finished up board repair on location, rig managers and mechanic installed brake linkage in draw works, installed brake handle driveline from doghouse to sub base, test ran draw works checking brake action and tested crown saver, made neccessary adjustments, CCI hoisted derrick board back up and welder installed same, cont mixing 6% KCL mud, clearing snow throughout the rig. Installed dog nut on drill line tail and installed on drum. Spool up draw works, P/U topdrive to remove elevators, bails and link tilt. Screw into 10' pup and check end play. Hang blocks on winch lines, remove pason hook load sensor and respool drill line (cut 1061' of drill line). API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 3/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation N/U BOP. Open ram doors and get serial numbers off of rams. Hook up koomy lines. Replace grabber guide bolts on top drive. Report Number 9 Report Start Date 12/18/2023 Report End Date 12/19/2023 Operation Buttoned up ram doors, replaced lower dog bone pins in topdrive, installed drip pan, flow riser and flow line, cont mixing 6% KCL mud, cont clearing ice and snow between modules. Chained off stack, pulled and checked test plug, set same, opened lower annulus valve, flooded surface lines and equipment, purged air, shell tested at 250/3700 psi, cleaned cellar area, rig floor and choke house, installed caps on 4" outlets of conductor. AOGCC Rep on location at 15:00, tested BOPE at 250/3700 psi for 5 min each (250/2500 on annular), tested with 4 1/2" test jnt, tested audio and visual gas alarms, performed draw down test. No failures. Pulled test plug and set long wear ring in multi-bowl wellhead. RU test equipment on mezz kill, flooded stack and surface lines with water, purged air, closed blind rams. Pumped 80.64 gallons to achieve 3000 psi on 10 3/4" surface casing. Held 30 min on chart, good test, bled back 80.64 gallons, blew down surface lines and RD test equipment. Pump up compensators. Change out grabber dies. Install bails and elevators. Load DP on pipe racks, strap and tally. Install chains on stack. M/U mule shoe. Tighten link tilt clamps on bails. Adjust load collar. Rack,strap and tally 4.5" DP. P/U and rack back 34 stnds of 4.5" DP. Report Number 10 Report Start Date 12/19/2023 Report End Date 12/20/2023 Operation Staged BHA on catwalk, PU 6 3/4" motor, 1.5° bend, MU 9 7/8" HDBS PDC jetted w/5 x 14's, MU 8.380" IBS and DM collar, scribed tools with an RFO of 289.70°, PU EWR-M5 and TM collars, plugged in and uploaded tools, RIH with stand NM flex DC and stand HWDP, MU topdrive. Shallow pulse tested at 400 gpm with no issues. Blew down topdrive and RIH remainder HWDP and jars to 707'. Inspected and greased draw works and topdrive. PU singled in hole 28 jnts 4 1/2" DP fromm 707' to 1571', MU topdrive and filled pipe. Washed down from 1571' to 1612' and set down 5K tagging up on wiper plugs, 354 gpm-790 psi, 23 rpm-2800 to 3333 ft/lbs torque. Drilled through wiper plugs and FC to 1615', shoe track and shoe to 1699', 5' rathole cement to 1704' with 1-10K wob. Drilled 20' new formation from 1704' to 1724' at rot wob 1K, 418 gpm-1103 psi, 40 rpm-3400 ft/lbs on bott torque, 100 ft/hr ROP. CBU to clear hole for cement and cuttings at 416 gpm-1084 psi, 40 rpm, then shut down and cleaned up under shakers while RU jumper hose from pit 6 (new mud) to pump #2. Held PJSM, pumped 40 bbls hi-vis spacer then displaced well from spud mud to 9.2 ppg 6% KCL mud at 315 gpm-646 psi, 35 rpm. CBU twice. Racked back one stand and parked bit at 1695', Installed head pin on stump, RU test hoses to head pin and mezz kill, fluid packed test hoses and purged air, closed upper rams. Obtained FIT to 12.8 ppg EMW. Pumped in 23.5 gals, Bled back 6 gals. B/D & R/D testing equip. Obtained SPR's. Drilled ahead F/1724'-T/1789' as per wp03 at 80 ROP maintaining 9-9.2 ppg MW. P/U-60K S/O-60K ROT-60K GPM-407 SPP-943 psi TQ-3.5K RPM-50 Diff-45 psi WOB-1.3K ROP-80 MW-9.15 ppg ECD-9.96 ppg Max gas - 16 units. Crew change, held PTSM. Drilled ahead F/1789' as per wp03 at 80 ROP maintaining 9-9.2 ppg MW to current depth of 2183'. P/U-65K S/O-59K ROT-63K GPM- 416 SPP-1032 psi TQ-3.2K RPM-70 Diff-66 psi WOB-2K ROP-80 MW-9.2 ppg ECD-9.43 ppg Max gas -24 units. Report Number 11 Report Start Date 12/20/2023 Report End Date 12/21/2023 Operation Cont drilling 9 7/8" hole from 2183' to 2502'. Rot wob 1-2K, 416 gpm-989 psi, 70 rpm-3390 ft/lbs on bott torque, 80 ft/hr ROP. Sliding wob 1K, 416 gpm-1000 psi, 27 psi diff, 100 ft/hr ROP. MW 9.2/vis 53, ECD's 9.3 ppg, BGG 6 units, max gas 32 units. (Rig's loader had a failed transmission valve body and leaked approximately 1 gallon transmission fluid onto snow covered pad. Rig crews cleaned up oil, CCI loaded and transported loader to town for repair) Cont drilling from 2502' to 2749' (wiper trip depth). Sliding wob 6K, 414 gpm-1136 psi, 142 psi diff, 7 to 100 ft/hr ROP. Rot wob 1-3K, 414 gpm-1071 psi, 70 rpm- 3870 ft/lbs on bott torque, 80 ft/hr ROP. MW 9.1/vis 61, ECD's at 9.4 ppg, BGG 9 units, max gas 61 units. CBU at 415 gpm-1018 psi, 70 rpm-3870 ft/lbs off bott torque. Obtained on bottom survey and SPR's (2749' md/2724' tvd). Did 10 min flow check, fluid dropped 1' in wellbore. Pulled up hole on elevators from 2749', 5 stands, blew down topdrive, cont to pull to 1748', S/O and parked at 1772'. Up wt 83K, dwn wt 75K. No issues. Inspected and greased rig and topdrive. Checked brake linkage. TIH on elevators from 1772' to 2695', MU topdrive on last stand and filled pipe, washed/reamed to bottom at 2749'. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet. GPM-415 SPP-1180 RPM-70 TQ-3.3K. Sweep came back on time w/ a 30% increase in cuttings. Drilled ahead F/2749'-T/2935' as per wp03 at 80 ROP maintaining 9-9.2 ppg MW. P/U-79K S/O-72K ROT-75K GPM-415 SPP-1235 psi TQ-3.6K RPM-70 Diff-60 psi WOB-1/6K ROP-80 MW-9.15 ppg ECD-9.4 ppg Max gas -24 units. Crew change, held PTSM. Cont. drilling ahead F/2935' to current depth of 3304' as per wp03 at 80 ROP maintaining 9-9.2 ppg MW. P/U-80K S/O-73K ROT-77K GPM-415 SPP-1306 psi TQ-3.9K RPM-70 Diff-65 psi WOB-3K ROP-80 MW-9.15 ppg ECD-9.45 ppg Max gas -29 units. Distance to well plan: 2.30' 2.30' High .02' Left. Report Number 12 Report Start Date 12/21/2023 Report End Date 12/22/2023 Operation Cont drilling 9 7/8" hole from 3304' to 3571', rot wob 1-11K, 415 gpm-1300 psi, 70 rpm-3900 to 5300 ft/lbs on bott torque, 50 ft/hr ROP. Sliding wob 1K, 415 gpm- 1320 psi, 68 to 121 psi diff, 50 ft/hr ROP. MW 9.1+/vis 60, ECD's at 9.4 ppg, BGG 18 units, max gas 103 units. At 3321' we reduced ROP from 80 to 50 ft/hr, and reduced pump rate on down stroke while backreaming for connections. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 4/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation Cont drilling from 3571' to 3735'. Rot wob 4K, 415 gpm-1324 psi, 75 rpm-4100 ft/lbs on bottom torque, 50 ft/hr ROP. Sliding wob 1-2K, 415 gpm-1394 psi, 128 psi diff, 23 ft/hr ROP. MW 9.1+/vis 63, ECD's 9.39 ppg, BGG 16 units, max 82 units. HEA had area wide power outage about the time we reached 3735'. G&I had no power for water or to process cuttings, 14-06 pad water well had no power, so rig had no water supply. Recieved 7 5/8" casing, CCI racking that for drifting. CBU twice at 415 gpm-1325 psi, 75 rpm-2782 to 5390 ft/lbs off bott torque. Obtained on bottom survey, SPR's, fluid dropped well over 1' during 10 minute flow check. Still no power in field, decision made to pull to shoe for rig service and wait on HEA to restore area power. Pulled up hole on elevators from 3735' to 3492', up wt 94K, dwn wt 85K, blew down topdrive, cont to pull up hole to surface shoe and parked at 1768'. Monitored well on trip tank, serviced rig and topdrive. Wait on power restoration at G&I. Power restored at 20:30. Static loss rate = 1.26 bph. RIH on elevators F/1696'-T/3736'. Broke circulation, filled pipe washed to bottom with no fill. P/U-92K S/O-85K ROT-82K GPM-325 SPP-912 psi RPM-70 TQ-4.8K. Calculated pipe displacement for the trip- 37.82 bbls Act- 37.5 bbls Diff- .32 bbls. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet. Sweep came back on time w/ a 50% increase in cuttings. P/U-92K S/O-85K ROT-88K GPM-415 SPP-1311 psi TQ-3.9K MW-9.2 ppg ECD-9.45 ppg Max gas-36 units. Crew change, held PTSM. Cont. drilling ahead F/3735. started seeing moderate losses at 3857'. Slowed ROP to 40 fph and GPM to 375 @ 3937'. Drilling ahead at current depth of 3950' as per wp03 and maintaining 9-9.2 ppg MW. P/U-92K S/O-85K ROT-87K GPM-369 SPP-1118 psi Flow-25% TQ-4.2K RPM-70 Diff-26 psi WOB-1.6K ROP-40 MW-9.15 ppg ECD-9.36 ppg Max gas -93 units. Distance to well plan: 1.05' 1.02 High .27' Left. Report Number 13 Report Start Date 12/22/2023 Report End Date 12/23/2023 Operation Cont drilling 9 7/8" hole from 3950' md/3910' tvd to 4163' md/4122' tvd. Rot wob 1-2K, 375 gpm-1134 psi, 70 rpm-4446 ft/lbs on bott torque, 40 ft/hr ROP. Sliding wob 1-3K, 375 gpm-1179 psi, 100 psi diff, 50 ft/hr ROP. MW 9.1/vis 57, ECD at 9.35 ppg, BGG 25 units, max gas 106 units. Started backreaming twice before connections. Built 20 bbl LCM pill in pill pit at 60 ppb, built 252 bbls of 9.0 ppg mud in pre-mix pits. Strapped intermediate casing. Cont drilling 9 7/8" hole from 4163' to 4351' md/4310' tvd. Sliding wob 4-5K, 375 gpm-1140 psi, 24 psi diff, 50 ft/hr ROP. Rot wob 1-6K, 375 gpm-1128 psi, 70 rpm- 4500 ft/lbs on bott torque, 40 ft/hr ROP. MW 9.1+/vis 55, ECD 9.3 ppg, BGG 54 units, max gas 133 units. Lost 97 bbls down hole from 5am to 5pm. Cont. drilling ahead F/4351'-T/4539' as per wp03 and maintaining 9.1 ppg MW. P/U-106K S/O-98K ROT-104K GPM-375 SPP-1215 psi Flow-28% TQ-5K RPM-70 Diff-102 psi WOB-3K ROP-40 MW-9.1 ppg ECD-9.31 ppg Max gas -88 units. Crew change, held PTSM. Cont. drilling ahead F/4539' to current depth of 4718' as per wp03 and maintaining 9.1 ppg MW. P/U-108K S/O-100K ROT-104K GPM- 377 SPP-1212 psi Flow-28% TQ-5.3K RPM-70 Diff-160 psi WOB-4.5K ROP-40 MW-9.15 ppg ECD-9.36 ppg Max gas -83 units. Lost 30 bbl over last 12 hrs. Distance to well plan: 9.98' 9.95' Low .81' Left. Report Number 14 Report Start Date 12/23/2023 Report End Date 12/24/2023 Operation At 4721' CBU, 377 gpm-1161 psi, 70 rpm-4086 ft/lbs off bott torque, obtained on bottom survey and SPR's, fluid dropped 2' in wellbore during 10 minute flow check. Pulled up hole from 4721' 5 stands to 4412', up wt 115K. Blew down topdrive and cont pulling on elevators with no issue to 3676', S/O and parked at 3696'. Serviced rig and topdrive with well on trip tank. Cleaned pump suction screens. Loss rate at 6 bph. TIH from 3696' to 4663', dwn wt 90K, filled pipe on last stand, started 10 bbl LCM sweep down drill string, washed and reamed to bottom at 4721'. Circulated surface to surface at 371 gpm-1119 psi, rotated and reciprocated string. Max gas at bottoms up 32 units and no increase in cuttings. Sweep back on time with no increase in cuttings. Cont drilling 9 7/8" hole from 4721' to 4944'. Rot wob 2-6K, 374 gpm-1182 psi, 70 rpm-5200 ft/lbs on bott torque, 40 ft/hr ROP. Sliding wob 1-6K, 3800 gpm-1290 psi, 97 psi diff, 50 ft/hr ROP. MW 9.1/vis 50, ECD 9.37 ppg, BGG 12 units, max gas 221 units. Lost 79 bbls to the hole from 05:00 to 17:00. Cont. drilling ahead F/4944'-T/5140'. P/U-118K S/O-107K ROT-114K GPM-375 SPP-1215 psi Flow-28% TQ-5.8K RPM-70 Diff-110 psi WOB-4K ROP-40 MW-9.1 ppg ECD-9.34 ppg Max gas -269 units. Crew change, held PTSM. Cont. drilling ahead F/5140' to current depth of 5278'. P/U-117K S/O-105K ROT-112K GPM-380 SPP-1224 psi Flow-28% TQ-5.7K RPM-70 Diff-107 psi WOB-4.6K ROP-40 MW-9.1 ppg ECD-9.34 ppg Max gas -80 units. Lost 73 bbls over last 12 hrs. Distance to well plan: 3.11' 2.41' Low 1.97' Left. Report Number 15 Report Start Date 12/24/2023 Report End Date 12/25/2023 Operation Cont drilling 9 7/8" hole from 5278' to 5434'. Sliding wob 2-5K, 378 gpm-1354psi, 139 psi diff, 20 to 50 ft/hr ROP. Rot wob 5K, 379 gpm-1305 psi, 75 rpm-5600 ft/lbs on bott torque, 40 ft/hr ROP. MW 9.1/vis 57, ECD 9.34 ppg, BGG 24 units, max gas 72 units. Cont drilling from 5434' to 5638'. Rot wob 4K, 381 gpm-1285 psi, 70 rpm-5700 ft/lbs on bott torque, 40 ft/hr ROP. MW 9.1/vis 57, ECD 9.38 ppg, BGG 22 units, max gas 84 units. Loss to hole 47 bbls from 05:00 to 17:00. Cont. drilling ahead F/5638'-T/5778'. P/U-125K S/O-110K ROT-119K GPM-375 SPP-1280 psi Flow-27% TQ-5.8K RPM-70 Diff-98 psi WOB-3K ROP-40 MW-9.1 ppg ECD-9.45 ppg Max gas -51 units. Obtained new SPR's @ 5718'. Crew change, held PTSM. Cont. drilling ahead F/5778' to current depth of 5907'. Start of our drop & turn section @ 5842'. P/U-135K S/O-116K ROT-119K GPM- 360 SPP-1157 psi Flow-27% TQ-5.7K RPM-70 Diff-85 psi WOB-3.6K ROP-40 MW-9.1 ppg ECD-9.37 ppg Max gas -77 units. Lost 41 bbls over last 12 hrs. Distance to well plan: 4.69' 1.57' Low 4.42' Left. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 5/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Report Number 16 Report Start Date 12/25/2023 Report End Date 12/26/2023 Operation Cont drilling 9 7/8" hole from 5907' to 6031'. Started drop and turn at 3°/ 100' at 5907. Sliding wob 1-2K, 361 gpm-1206 psi, 52 psi diff, 15 to 25 ft/hr ROP. Rot wob 3-5K, 384 gpm-1335 psi, 70 rpm-6004 ft/lbs off bott torque, 40 ft/hr ROP. MW 9.1/vis 52, ECD 9.39 ppg, BGG 29 units, max gas 46 units. Cont drilling from 6031' to TD at 6074' md/6008' tvd. Sliding wob 1-2K, 380 gpm-1336 psi, 65 psi diff, 14 ft/hr ROP. Rot wob 3-5K, 380 gpm-1407 psi, 70 rpm-6500 ft/lbs on bott torque, 40 ft/hr ROP. MW 9.1/vis 54, ECD 9.4 ppg, BGG 25 units, max gas 70 units. CBU twice at 399 gpm-1387 psi, 70 rpm-5500 ft/lbs off bott torque. Obtained on bottom survey and SPR's. 10 flow check, fluid dropped 4' in wellbore. On bottom survey has us .11' low and 2.93' right of the line. Pulled up hole on elevators from 6074' to 5779' with no issue, up wt 139K. Blew down topdrive, cont pull up hole to 5153' and started seeing 25 to 30K overpulls and trying to swab. S/O and MU topdrive. Tried to pump OOH, still seeing over pull and psi increase, began backreaming from 5153' (claystone) up to 4721', 368 gpm-1154 psi, 50 rpm-3786 to 7566 ft/lbs off bott torque. CBU. P/U-108K S/O-104K ROT-106K GPM-375 SPP-1080 psi TQ-4.7K RPM-70 MW-9.15 ppg ECD-9.32 ppg Max gas-17 units. Serviced rig while monitoring hole on TT. Static loss rate- 1.2 bph. RIH on elevators F/4782'-T/5993'. P/U-112K S/O-102K. Had 15K set down @ 5993', attempted to work through on elevators with no luck. Kelley up, broke circ. filled pipe, washed/reamed F/5993' to bottom with 11' of fill. P/U-125K S/O-125K ROT-125K GPM-383 SPP-1285 psi RPM-70 TQ-6K Flow-28% MW-9.2 ppg ECD- 9.5 ppg. Pumped 20 bbl Hi-Vis LCM sweep, sweep came back on time with a 35% increase in cuttings. GPM-385 SPP-1297 psi RPM-70 TQ-5.6K MW -9.2 ppg ECD-9.52 ppg Flow-27%. Cont to circulate an additional STS to condition mud. GPM-385 SPP-1152 psi RPM-70 TQ-5.2 MW-9.2 ppg ECD-9.43 ppg Flow-27% Flow checked well (slight seepage). POOH on elevators F/6074' to current depth of 2433'. Had to work through 20K over pull tight spot on elevators F/4629'- T/4605'. Report Number 17 Report Start Date 12/26/2023 Report End Date 12/27/2023 Operation POOH on elevators f/ 2433' t/ 707' did a 10 min flow check at HWDP slight seepage Rack back HWDP and jars, Stand back flex collars, Download MWD, L/D remaining smart tools, Break Bit graded 1-2 and 1/16 under gauge P/U test joint pull wear ring Service rig and top drive, grease blocks and crown, greae and service draw works Open ram doors and change upper rams to 7 5/8'' Solid body rams and close doors back up. Set test plug Test 7 5/8'' Rams t/ 250/3700 psi test annular t/ 250/2500 psi w/ 7 5/8'' test jt, R/D Test Equipment R/U Parker TRS, dummy run hanger hold PJSM with all hands, P/U Float equipment casing tongs have wrong head they are 7'' Wait on hand to run back to Parker Shop and get correct heads f/ tongs M/U 7-5/8" shoe track, tested floats (ok). Cont. RIH F/83'-T/1667' at 30 fpm, filling on the fly and topping of every 10 jts. M/U drive sub, broke circ. Staged up MP, circulated string volume. GPM-212 SPP=75 psi MW-9.15 ppg. B/D TD. Cont. RIH with 7-5/8" TXP/BTC 29.7# L-80 intermediate casing as per run tally F/1667'-T/3646' at 30 fpm, filling on the fly and topping off every 10 jts. M/U drive sub, broke circ. Staged up MP. Circulated string volume. GPM-247 SPP-141 psi MW-9.25 ppg Max gas-15 units. Currently B/D TD and cont. to RIH with 7-5/8" intermediate casing as per tally. Report Number 18 Report Start Date 12/27/2023 Report End Date 12/28/2023 Operation Continue RIH w/ 7 5/8'' Intermeditae casing f/ 3646' t/ 5973' set down and work string unable to get past, M/U swedge and wash down 250 gpm 350 psi Wash last 2 jts down, M/U Hanger and Landing jt wash landing jt down and land on hanger Circulate and condition mud stage rate to 6 bpm 245 psi reciprocate string 15', spot in cementers and R/U, P/U Cement hoses and cement head to floor. PT Lines t/ 500 psi low 4300 psi high, pump 61 bbls 10.5 ppg spacer, dropped bottom plug, pumped 286 bbls 12 ppg Lead Cement, Followed by 31.5 bbls 15.3 ppg Tail, dropped top plug, displaced w/ 277 bbls of 9.2 ppg 6% kcl polymer mud and bumped plugs 2.5 bpm 850 psi pressured up t/ 1600 psi held f/ 5 min bled off and checked floats, bled back 1.5 bbls floats held CIP 18:27hrs R/D and B/D cementers. R/D cmt's. Drained stack and top washed back side of LJ. B/O and L/D LJ. M/U pack off running tool. Set pack off and test T/5000 psi for 15 min (ok). Johnny wacked stack. De-energized koomey. Openened up UPR doors. Removed 7-5/8" rams. Installed 4.5" VBR. M/U test plug to 4.5" test jt. Set test plug. Flooded stack, lines, and choke manifold with FW. Purged out air. Performed shell test T/3700 psi (ok). AOGCC witness arrived on location at 23:30 hrs. Testing BOP's at current time as per AOGCC regulations 250 psi Low/3700 psi High for 5/5 min Annular 250 psi Low/2500 psi High for 5/5 min. Tested audio/visual on gas detection system (ok). Cont. to weight up active mud system to 10 ppg. Report Number 19 Report Start Date 12/28/2023 Report End Date 12/29/2023 Operation Blow Down and rig down test equipment, set wear ring, Finish weighting up drilling mud t/ 10 ppg PJSM R/U AK ELine, RIH t/ 2000' sheave calibration off POOH and recalibrate, RIH 100' per min tag up @ 5927' tag up, POOH logging @ 30 fpm to surface, R/D ELine R/U and test casing to 3500 psi f/ 30 min pump 3.2 bbls in got 3.2 bbls back R/D test equipment. Clear floor, stage BHA and equipment on skate API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 6/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation P/U 6.75" Directional BHA #3. 5 bladed PDC bit, 1.5° mud motor, cauculated off set -296.86°, and MWD tools. Plugged in and uploaded MWD data, shallow pluse tested tools. Held PJSM, loaded sources. RIH out of derrick w/ HWDP, P/U & M/U jar std. (682' BHA) Serviced rig- Greased & inspected crown, blocks, TD, wash pipe, brake linkage, drive shaft, IR, and DWKS. Checked weight indicator calibration. Replaced bent shackle on compensator (ODS). Found missing keeper bolts on (DS) brake band-brake shaft link pin. Replaced all keeper bolt lock washers & standard nuts w/ lock nuts on brake band-brake shaft link pins, along w/ bell crank pins & anchor link pins. Crew change, held PTSM. P/U & singled in the hole w/ 4.5" CDS 40 DP on top of BHA #3 F/682-T/1419'. Filled pipe, MWD performed second shallow pulse test to confirm good inclination on survey. B/D TD. Cont. P/U & singling in the hole w/ 4.5" DP F/1419' to current depth of 3592'. Report Number 20 Report Start Date 12/29/2023 Report End Date 12/30/2023 Operation Continue RIH P/U DP SIngles f/ 3592' t/ 4945' RIH out of derrick f/ 4952' t/ 5931' Wash last stand down Tag cement 5977' 20k set down Drill Cement and FLoat Equipment f/ 5977' t/ 6066' Drill Rathole and 20' of new hole t/ 6094' 30 rpm 4.4k tq 225 GPM 1300 psi Displace well w/ 10 ppg 6% KCL Polymer Mud 250 gpm 1590 psi B/D Top Drive and R/U and Perform FIT t/ 13.45 ppg EMW pressure up t/ 1078 psi, pumped 35.7 gal in and got back 33.4 gal R/D and B/D Lines Service rig and Draw works, grease top drive and blocks Drill Ahead 6 3/4'' Production Section F/6094'-T/6555'. P/U-135K S/O-110K ROT-120K GPM-250 SPP-2018 psi RPM-40 TQ-6.2K Diff-356 psi WOB-6K MW-10.45 ppg ECD-11.08 ppg Max gas-226 units. Pumped 20 Hi-Vis sweep @ 6555'. Crew change, held PTSM. Sweep came back on time with a 125% increase in cuttings. Cont. directional drilling 6.75" production hole F/6555' to current depth of 6925' while weighting mud system up to 11.2 ppg. Obtained new SPR's @ 6650'. P/U-138K S/O-114K ROT-124K GPM-255 SPP-2205 psi RPM-40 TQ-6.4K Diff- 340 psi WOB-6.4K MW-10.8 ppg ECD-11.97 ppg Max gas-211 units. Distance to well plan: 6.62' 1.63' High 4.10' Right. Report Number 21 Report Start Date 12/30/2023 Report End Date 12/31/2023 Operation Continue Drilling Ahead 6 3/4'' Production section f/ 6925' t/ 7110' 250 gpm 2300 psi 40 rpm 6.6k tq 8 k WOB, PUW 140k SOW 115k ROT 125k Max gas 219 units MW 11.2ppg ECD 12.4 ppg Circulate bottoms up, obtain survey and spr's POOH f/ 7110't/ 6056' with no issues Service rig and top drive, grease and inspect draworks. RIH f/ 6056' t/ 7110' with out issues wash last stand to bottom pump Hi Vis sweep and resume drilling Drill Ahead f/ 7110' t/ 7253' 280 gpm 2700 psi 60 rpm 8k WOB 145k PUW 115k SOW 128k ROT Max Gas 149 units Rack back stand and change wash pipe .2 bph static loss rate Drill Ahead f/ 7253' t/ 7419' 280 gpm 2740 psi 60 rpm 7 k tq on bottom, 145k PUW 115k SOW 129k ROT MW 11.3 ppg ECD 12.55 Max gas 430 units Drilled 6 3/4'' Production Section F/7419'-T/7680'. P/U-150K S/O-116K ROT-132K GPM-280 SPP-2786 psi RPM-60 TQ-7.4K Diff-340 psi WOB-7K MW-11.35 ppg ECD-12.54 ppg Max gas-262 units. Pumped 20 bbl Hi-Vis sweep @ 7602', sweep came back 5.7 bbls early with a 200% increase in cuttings. Obtained new SPR's @ 7665'. Crew change, held PTSM. Cont. directional drilling 6.75" production hole F/7680' to current depth of 8096'. P/U-159K S/O-122K ROT-136K GPM-284 SPP-2617 psi RPM-60 TQ-7.4K Diff-360 psi WOB-8K MW-11.4 ppg ECD-13.32 ppg Max gas-388 units. Distance to well plan: 2.01' 1.77' Low .96' Left Report Number 22 Report Start Date 12/31/2023 Report End Date 1/1/2024 Operation Continue Drilling Ahead 6 3/4'' Hole section f/ 8096 t/ 8158' 280 gpm 2830 psi 60 rpm 7.6k tq on bottom 8k WOB, 157k PUW 121k SOW 135k ROT MW 11.4 ppg ECD 13.04 Max Gas 358 units Circulatge Bottoms Up, Obtain Survey and SPR's Make Wiper Trip f/ 8158' t/ 6055' 20-30k over puls, wiped through and gone. Service rig and top drive, grease blocks and crown, change oil in draworks motor and transmission, Inspect break linkage and break bands, Cut and slip drilling line 19 wraps RIH f/ 6055' t/ 7956' set down could work past, Pump Hi Vis Sweep and wash and ream last two stands to bottom 4559 units of gas on bottoms up sweep back 150 stks early 10% increase in cuttings Drill Ahead 6 3/4'' Hole Section F/ 8158' t/ 8342' 275 gpm 2675 psi 50 rpm 7.8k on bottom tq 11.6 ppg MW 13.14 ECD PUW 154k PUW 118k SOW 128k ROT 8 k WOB Drilled 6 3/4'' Production Section F/8342'-T/8592'. P/U-168K S/O-124K ROT-142K GPM-270 SPP-2960 psi RPM-50 TQ-7.9K Diff-308 psi WOB-6K MW-11.8 ppg ECD-13.07 ppg Max gas-865 units. Pumped 20 bbl Hi-Vis sweep @ 8592' while drilling ahead. Crew change, held PTSM and weekly safety meeting with rig crew. Cont. directional drilling 6.75" production hole F/8654'. Sweep came back 24.5 bbls early with a 125% increase in cuttings. Obtained new SPR's. Currently drilling ahead @ 8950'. P/U-171K S/O-125K ROT-144K GPM-273 SPP-2950 psi RPM-50 TQ-8K Diff- 230 psi WOB-5.5K MW-11.9 ppg ECD-13.45 ppg Max gas-680 units. Distance to well plan: .66' .50' High .43' Left Report Number 23 Report Start Date 1/1/2024 Report End Date 1/2/2024 Operation Drill Ahead 6 3/4'' Hole Section f/ 8950' t/ 9210' 273 gpm 3100 psi 65 rpm 9.4 k tq on bottom, Max gas 504 units, MW 12 ppg ECD 13.46 ppg Circulate Bottoms up, Obtain Survey and SPR's Make wiper ttrip f/ 9210' t/ 8159' with no hole issues. Service rig and top drive, grease blocks and crown, inspect draworks and break linkage API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 7/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation RIH f/ 8159' t/ 9210 with no issues wash last stand to bottom pump Hi vis sweep and resume drilling ahead sweep back on time w/ 50% increase in cuttings Drill Ahead 6 3/4'' Hole section f/ 9210' t/ 9340' 270 gpm 3100 psi 50 rpm 8.8k tq on bottom, WOB 7k MW 12 ppg ECD 13.36 ppg 176k PUW 130k SOW 151k ROT Drilled 6 3/4'' Production Section F/9340'-T/9615'. P/U-180K S/O-135K ROT-156K GPM-270 SPP-3020 psi RPM-50 TQ-9.1K Diff-240 psi WOB-7K MW-12.2 ppg ECD-13.38 ppg Max gas-408 unit. Crew change, held PTSM. Cont. directional drilling 6.75" production hole F/9615' to current depth of 9820'. P/U-182K S/O-140K ROT-158K GPM-273 SPP-3092 psi RPM-65 TQ-9K Diff-200 psi WOB-8K MW-12.2 ppg ECD-13.49 ppg Max gas-170 units. Distance to well plan: 42.93' 29.09' High 31.57' Right. Report Number 24 Report Start Date 1/2/2024 Report End Date 1/3/2024 Operation Obtain final Survey. Pump 20 bbl hi vis sweep back 100 strokes early with 10% increase. Get SPR's Flow check well-slight seepage. Blow down surface lines. POOH on elevators f/9830' t/9090' with no issues. P/U 200K, S/O 142K Service blocks, top drive (change saver sub), drawworks, floor motor, transmission, drive line, gear end, tight angle box, brake linkage and drill line anchor. RIH on elelvators f/9090' t/9830' with no issues. P/U 190K, S/O 142K Pump 20 bbl hi vis sweep back 100 strokes early with 20% increase. Flow check well 10 min-static. Blow down surface lines. POOH f/9830' t/8400'. P/U 198K, S/O 154K. Dropped drift on stand #138. POOH on elevators f/8400' t/6920' were assembly pulled tight. P/U 175K, S/O 130K BROOH f/6920' t/3073'. 250GPM=2292PSI POOH on elevators f/6073' to HWDP at 681'. P/U 126K, S/O 110K. Slip and cut 43' of drill line. 0.7 bbl/hr static loss rate. POOH f/ 680' to surface. Rack back 5 stnds of HWDP, L/D jars, rack back 3 stnds of HWDP. L/D flex collars. Download MWD tools. L/D rest of BHA #3. Bit graded:1-2-CT-N-X-I-NO-TD. Clean and clear rig floor. Mobilize Parker TRS casing equipment to rig floor and R/U. M/U TIW to casing swedge. Load pipe racks w/ 4.5" liner. Mobilize centralizers to rig floor. PJSM with Parker TRS and rig crew. Baker lock and M/U shoe, float collar, and Landing collar. Check floats-good. RIH with 4.5" L-80 13.5# TXP-BTC liner as per tally t/2174' Report Number 25 Report Start Date 1/3/2024 Report End Date 1/4/2024 Operation Continue RIH w/ 4.5'' Liner f/ 2174' t/ 3919' M/U Liner Hanger as per Baker Rep M/U Crossover and 1 Stand of DP Circulate a liner volume stage rate to 4 bpm 450 psi RIH w/ 4.5'' Liner on 4.5'' DP f/ 3965' t/ 9385' No issues filling pipe every 2000' Moved HWDP in derick unable to move pipe in hole WOrk String pulling 275k on weight indicator setting down 40k down weight, pumped lube pill around with no change no pipe movement, Continue working stuck pipe, stage rate up to 5 bpm 1215 psi intermittent pack offs. Circulate while working stuck pipe. Pump lube pil, once out the shoe, park with stirng in tension at 250k (100k over) and bring circulating rate down to 2.4 bbl/ min- no movement. Continue to Circulate at 5bbl/min while working pipe. Continue to Circulate while working pipe 5bbl/min 1050PSI. P/U to 250k (100K over) S/O to 100K (20K over). Report Number 26 Report Start Date 1/4/2024 Report End Date 1/5/2024 Operation Continue circulating 5 bpm pump pressure 1150 psi MW 11.85 ppg Work pipe periodically pulling 250-270k parking in tenstion No change or movement, mobilize truck to swanson river to take on load of Black Magic, return to rig. Pump 20 bbls Black magic pill and spot outside the pipe and let soak, pull drill string in tension park at 250k hook load, monitor well. Circulate out Black Magic pill through choke manifold. Over board 57 bbls of mud and contamination, no gas observed. R/U cement head, cement lines and low torque valves. PJSM with rig crew and 3rd party personel. Halliburton pumped 10 bbls water to flush and fill lines. Shut in at Baker cement head and PT lines at 410 psi low 4500 psi high-good tests. Lined up and pumped 26 bbls 12 ppg Tuned Spacer at 3 bpm-810psi, 10% flow, followed with 131 bbls (401 sx) 13 ppg Type I II Lead cement at 3 bpm-icp-780 to fcp-230 psi, 11% flow. Followed lead with 17.5 bbls (99 sx) 15.3 ppg Type I II Tail cement at 3bpm, icp-213 to fcp-250psi, 11.7% flow. Had 2 pps Bridgemaker LCM in lead. Baker released dart, Halliburton then displaced with 10 bbl of water followed by 11.8ppg 6% KCL mud at 5 slowing to 4 bpm- 57 psi ICP. Saw dart latch wiper plug 71 bbls into displacement as pressure increased from 900 psi to 1200 psi at 3 bpm. Once plug released pressure dropped and we resumed 3.5 bpm. With 20 bbls to go, reduced rate to 3bpm- 1280 psi. Bumped liner wiper plug/landing collar 128 bbls into displacement (calculated at 132.1 bbls). FCP 1400psi. Halliburton increased to and held 1750 psi (350 over fcp) for 2 minutes, then increased pressure to 2100 psi for 2 minutes to set hanger, set down 75k with hanger set. Pressured up, at 2755 psi set packer and continued up to 3530 psi to neutralize hyd set tool and then up to 4200 psi to release. Bled back 0.75 bbls to truck and floats held. PU wt 105K giving us good indication we had released run tool. CIP at 22:52 on 1/4/23. No losses throughout job. R/D cement lines and cement head. M/U TD to stump to circulate. Pressured up to 815 psi on drill string and PU 10’, string pressure started dropping, ramped up both pumps and CBU twice at 340 gpm-1130 psi. Had 26 bbls spacer and 56 bbls cement, and 134 bbls contaminated mud at the shakers. POOH racking back 38 stnds of DP, L/D 16 jnts. POOH at 1291’ laying down DP singles. Report Number 27 Report Start Date 1/5/2024 Report End Date 1/6/2024 Operation Continue L/D DP f/ 1291' t/ surface L/D Running tool Clean and clear floor R/U and Flush Stack, wash through choke line, pull wear ring. R/U and test Liner Lap t/ 3000 psi f/ 10 min on chart, good test 2.8 bbls pumped in 2.8 bbls bled back API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 8/8 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation Set Test plug w/ 2 7/8'' Test Jt, fill stack and purge air out of lines, Shell test, Test upper and lower rams w/ 2 7/8'' Test jt 250/3700 psi f/ 5 min each, R/D and blow down choke manifold. Strap and Tally 2 7/8'' Work string, R/U TRS and P/U BHA component to floor. Service Rig and top drive, Grease crown and blocks. Torque up BHA Bit bit sub motor and check valve, RIH P/U 2 7/8'' Work String t/ 4556' RIH w/ 4.5" DP out of the derrick t/5000', P/U-50K S/O-49K Set top drive torque t/ 7000 ft/lbs. Cont to RIH f/5000' t/9202'. No issues getting into liner top at 5450' Fill pipe then wash/ream f/9202' t/9304' and set down 3k on hard cement. Drill cement f/9304' t/9308'. Drilled through wiper plug and landing collar f/ 9308 t/ 9309'. Cont. driling shoe track t/9332'. 130GPM=2820PSI, 20RPM=4.4k Tq. 1-3k WOB. P/U-116k S/O-101k ROT-105k. Report Number 28 Report Start Date 1/6/2024 Report End Date 1/7/2024 Operation Continue Drilling Cement and Float shoe f/ 9332' t/ 9408' 135 gpm 2726 psi 20 rpm 3500 tq on bottom, 2-3k WOB 120 PUW 105k SOW 110k ROT MW 12 ppg Drill out cement f/ 9408' t/ 9665' 135 gpm 2622 psi 20 rpm 3.5k tq on bottom, 120k PUW 105k SOW 110k ROT Pump Hi vis sweep and circulate out. Back on time with 10% increase. 136GPM=1768PSI, 20RPM=3.7k tq, P/U-120K, S/O-104K, ROT-114K. POOH f/9665' t/8530' L/D 4.5" DP singles. Cont. POOH f/8530' t/4591' racking back 4.5" DP in derrick. Hole fill Calc-34.5 bbls Act-34.6 bbls. P/U 55K, S/O 50K. PJSM w/ Parker TRS. R/U power tongs, change out elevators and slip bowl. Cont. POOH f/4591' t/1639' L/D 2-7/8" PH-6 work string. Flushing each jnt with water. Report Number 29 Report Start Date 1/7/2024 Report End Date 1/8/2024 Operation Continue POOH L/D 2 7/8'' Work String F/ 1639' t/ surface, drain motor and break bit L/D BHA, Clear floor R/D TRS Service rig and top drive, grease crown and blocks, check oil in floor motor and transmission, inspect draworks and break linkage. M/U Polish Mill BHA RIH w/ 4.5'' DP f/ derrick to top of liner @ 5459' Polish Liner top as per Baker Rep 30 rpm 3.5k tq 100k PUW 91k SOW Pump High Vis Sweep around 246 gp, 752 psi POOH L/D 4.5" DP f/5459' t/ 551'. Cont. POOH f/551' t/ surface. L/D polish mill. clean and clear rig floor. Pull wear ring. PJSM with Parker TRS. R/U power tongs and handling equipment. M/U Bullet seal assembly as per Baker rep t/17.72'. RIH w/ 4.5" 12.6# TXP-BTC L80 tubing as per tally f/17.72' t/2356' Report Number 30 Report Start Date 1/8/2024 Report End Date 1/9/2024 Operation Continue RIH w/ 4.5'' Tie Back Assembly f/ 2356' t/ 5420' M/U 2 extra jts and Tag up on liner top, space out, L/D 2 jts and M/U 20.67' of pup jts and land on hanger, RILDS, R/D TRS R/U and test IA t/ 3000 psi f/ 30 min on chart pumped in 1.75 bbls bled back 1.7 bbls, R/D test equipment. P/U T bar and set TWC as per wellhead rep FLush all mud lines and gas buster choke manifold and BOP equipment with bara clean pill Pressure down accumulator and open all ram doors clean and inspect, button doors back up and remove bell nipple and flow line, remove all bolts from stack hook up bridge cranes and hoist off wellhead. R/D bails, saver sub, and change oil on top drive and swivel. Remove kelly hose and change out seals on top drive hyd line in derrick. Installed shipping beams. R/D gen#3 and sperry shack. Clean mud tanks. Changed liners in mud pump #2 to 5.5". R/D topdirve, remove torque bushing, and L/D topdrive. R/D rig tongs. Finish disconnecting high pressure lines (mud pumps, pits, sub structor). Cont. rigging down throughout pits 1 and 2. R/D gas buster, degasser, choke house. Blow down water lines and winterize pressure washers. Prep derrick to scope down ( t-bar, turn buckles, geronimo, electric, pason, hydrualic lines. Scope down derrick and remove torque tube. Prep derrick to be lowered (disconnect hydraulic and electric lines, unspool drill line). blow down boiler. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 223-112 State: ALASKA Rig/Service: HEC 169 Page 1/6 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:1/12/2024 End Date: Report Number 1 Report Start Date 1/12/2024 Report End Date 1/13/2024 Operation PJSM and PTW SITP 0psi RU Pollard SL Pressure test lubricator 250psi/1500psi M/U and RIH w/ 3.5" OD drive down bailer to 9,452', unable to pass. POOH M/U and RIH w/ 2.5" OD drive down bailer to 9,455', unable to pass. POOH Bailers full of drilling mud and one 4" long piece of metal debris (assume from drilling out the shoe) RD Pollard SL PJSM and PTW MIRU AK-E-line MU 1-11/16 centralized CBL tools Pressure test lubricator 250psi/3500psi RIH and log from 9,300' to 5170' (280ft above the liner hanger) POOH Good data. Send logs to town. RDMO Report Number 2 Report Start Date 1/13/2024 Report End Date 1/14/2024 Operation Mobe/Permit/PJSM/MIRU BOPE test 250 psi low/ 3500 psi high Secure well and location for night Report Number 3 Report Start Date 1/14/2024 Report End Date 1/15/2024 Operation RU CT injector on well fill coil reel with water. MU CTC, DFCV, Straight Mandral, Circ Nozzle. CT Inj on well. PT PCE 250 psi low/ 3500 psi high Trip in hole pumping 6% KCL at .3 bpm taking returns to surface Wt ck 15.5k/11.2k @ 5000' WHP 0/CP 732 @ .3 bpm Wt ck 21k/14.5k @ 9000' WHP 0/CP 1186 @ .3 bpm At taget depth. 9410'. WHP 0/CP 2883 @ 1 bpm Getting 1:1 returns, continue until CP declines Increase pump rate to 1.5 bpm, returns 1:1, POOH @ 80% Returns clean, drop pump rate to just above CT displacement while POOH. At surface, secure well, blow down CT reel w/N2 Lay down for night and secure location. Report Number 4 Report Start Date 1/15/2024 Report End Date 1/16/2024 Operation Mobe/Permit/PJSM/MIRU Manlift issues PCE issue, stuffing box PT 3500 psi, RIH set 4-1/2" AD2 Slipstop @ 9304' SLMD RIH set G-Packoff plug @ 9301' SLMD Finish surface Tie-in, and set up for MIT-T MIT-T 3500 psi. Initial- 3648/0/0 psi. 15 min- 3635/0/0 psi. 30 min- 3629/0/0 psi (Pass) RIH to EQ WRP @ 9303' SLMD RIH w/ 4-1/2" GS, Latch G-Packoff Plug @ 9301' SLMD and attempt to pull. Moved 10' to 9291' then worked wire for 1-1/2 hrs. Shear off and POOH RIH second time to EQ G-Packoff Plug @ 9291' SLMD, did not move. RIH w/ equalizing prong to 9293' no change. POOH & RD equipment. Report Number 5 Report Start Date 1/16/2024 Report End Date 1/17/2024 Operation Fox CTU obtain PTW. PIck injector head. MU lubricator. Source through tubing fishing tools from YJOS. Wrong tools on location. Co Rep and tool hand head YJOS shop to obtaain correct G spear. Pressure up production tubin wtih field triplex. 2000 psi held rock solid. 3350 psi pressure broke over. Shut down pump and monitor pressure drop. 1800 psi WHP pressure dropped slowed. Fox CTU down on NPT due to hydraulic circuit failure. Arttempts made to swap CTU tractor with no luck. Prep for slick line unit for AM. Report Number 6 Report Start Date 1/17/2024 Report End Date 1/18/2024 API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 324-011 State: ALASKA Rig/Service:Permit to Drill (PTD) #:223-112 Page 2/6 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation Mobilize, PJSM, Permit, MIRU SL PT PCE 3,500 psi RIH w/2.12" OD swedge, tag and work Kobe EQ @ 9297' SLMD. POOH - Definitive marks from Kobe Knockout. RIH w/ 4-1/2" GS. Latch G-Packoff @ 9298' SLMD Jar a few times. POOH w/Packoff. element intact. RIH w/ 4-1/2" GS. Latch AD-2 @ 9300' SLMD. POOH and recover slipstop. RIH w/2.0" swedge, 2" drive down bailer. Tag @ 9487' SLMD. POOH OOH w/tools RD Slickline Report Number 7 Report Start Date 1/18/2024 Report End Date 1/19/2024 Operation PTW, JSA with crew. Pick up Fox CTU 8 with 1.75" coil. Stab lubricator. Make up 2.125" wash nozzle assembly. Stab on well. Fluid pack CT. PT stack 250/3500 psi. Peform weight checks as needed. 0 PSI whp. Fluid to surface. Dry tag wtih nozzle at 9485' CTMD. PIck up and establish circulating parameters. 1.6 bbls/min 3200 psi. Start washing from 9400' to 9485'. Stacking 10K down. Not washing off. No weight coming back. Pick up and attempt to RIH past depth at different speeds and pump rates. No luck getting past 9485'. Call town to discuss. Circulate bottoms up from 9485' CTMD. Chase BU to surface. Tagged up at surface. Blow reel dry with N2. Call out YJOS for motor and mill run for following day. Rig down CTU pump and move to assist AK E-line for well kill operation on KBU 22-06Y. Report Number 8 Report Start Date 1/19/2024 Report End Date 1/20/2024 Operation PTW, JSA with crews. Fire equipment, pick injector head and stab lubricator. Make up YJOS milling BHA with 3.75" bladed junk mill. Stab on well. PT Stack 250/3500 psi. RIH, @ 9401 Start milling parameters. 1.0 bbls/min 2000 psi. Milling what feels like metal/rubber chunks. 20 stalls. Made it through tight spot at 9480'. Milling break. Tag TD @ 9833' CTMD. Wash/back ream through open hole 3 times. While back reaming on final trip Coil got stuck at 9515'. Normal up wieght 28K Couldn't RIH or POOH, circ pressure climbed from 2100 psi to 4500 psi. Continued with 1:1 returns. Returns dirty 30% solids. Possibly stuck in coal seam. Pulled 39K or 10 over to pop free. Circ pressure dropping back down. POOH to surface. Tagged up. Pop off well. Break down YJOS Milling BHA. No significant wear on mill faces. Stab on well. Blow reel dry. Rack back injector head. Install night cap. Well site secure. SDFN Report Number 9 Report Start Date 1/20/2024 Report End Date 1/21/2024 Operation PTW, JSA with crew. Fire equipment, Pick injector head and 10' lubricator. Make up BHA, Roll on coil connector, DFCV, Stinger/MBT, wash nozzle. Total 8' BHA . Stab on well PT 250/3500 psi. RIH . Perform weight checks as needed. RIH weight @ 9700' 16k. RIH for dry tag. Starting to stack weight at 9852'. Stop coil and weight comes back. Pick up at 9852' 30K clean. Parked at 9801' online down CT taking returns to open top tank at 1.5 bbls/min 2880 psi. 9830' Stack weight. 64 bbls on counter. Start pumping bottoms up. AT 9400' RIH back to bottom. Tagged 9830'CTM Wash OOH . 171 bbls pumped. PU from 9000' to 5000'. POOH online down CT with N2 at 1000 scf/min 7000' CTMD. Good returns at surface. 65 bbls. N2 at surface. RIH from 7000'. Pinch in choke. Tag while pumping n2 at 9725' CTMD. Holding 450 psi on choke. Pulled up to 8000' let wellbore settle out . Run in hole to 9543 tag. N2 online 1000 scf/min Circ pressure 2787 psi. Start POOH chasing fluid while pinching in choke. NO LEL at tank. 858 WHP 1500 circ. Continue Pulling out of hole. 124 bbls returned from wellbore. Tagged up at surface. Close well. 1500 psi SITP (N2). Rig back Fox CTU Report Number 10 Report Start Date 1/24/2024 Report End Date 1/25/2024 Operation Report Number 11 Report Start Date 1/25/2024 Report End Date 1/26/2024 Operation Report Number 12 Report Start Date 2/4/2024 Report End Date 2/5/2024 Operation PTW, JSA with crew. MIRU FOX CTU 8 with 1.75" CT. AOGCC witness waived BOPE test. Test all rams and valves 250/3500 psi. Stand up Injector head. Make up CT coil connector. SDFN. Report Number 13 Report Start Date 2/5/2024 Report End Date 2/6/2024 Operation PTW, JSA with crew. Fire equipment. Pick injector head and lubricator. Make up DFCV, 2x stinger and jet nozzle. BHA 8.9' x 2.125" OD Stab on well. Fill coil and pressure test pack off / wellhead connection 250/3500 psi. Open well RIH. 0 psi WHP. RIH peform weight checks when needed. Online down CT at 1 bbl/min to fill well . Returns at surface 55 bbls pumped and 19 bbls from coil displacemet at 5516' . 74 bbls pre CT fluid level 4862.5' Previous wire line log showed fluid level 5557'. Come offline and RIH for dry tag at 9412' CTMD. PIck up and start pumping at 1.3 bbls/min 2800 psi. FCO to 9520'. Pick up to liner tail at 9400' Clean 32K up weight. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 324-011 State: ALASKA Rig/Service: Page 3/6 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation Stacking weight cleaning out at 9511'. Pick up clean Trip back in hole stack weight at 9477' losing hole. 6K down and weight not coming back. Cleaned out and stacked weight at depths of 9480', 9485', 9487' Performed Wiper trip to liner tail at 9400'. Pump bottoms up POOH to surface pumping to keep well full. Tagged up. Blow coil dry for freeze protect. Rig Back CTU injector head. Prep for motor mill run. SDFN Report Number 14 Report Start Date 2/6/2024 Report End Date 2/7/2024 Operation Approve PTW and held PJSM, warmed up eq. Picked up injector and Stab on well, PT 250/3500psi. Began filling reel with 120deg 6% KCL. Pumped 30bbls and coil pressured up to 6000psi. Indication of an ice plug in coil. Open well RIH to 3000' and broke ice plug free. Pumped 20bbls and POOH. M/U YJ Ext CTC Pull test 25k, M/U BHA, 3-3/4" Rock Bit, 2-7/8" Motor, Cir Sub, Hyd Disconnect, Bi-Di Jar, DFCV. Stab on Well PT 250/3500psi. Open well and RIH pumping min rate. Took 77bbls to catch retruns. P/u Wt check at 9400' 35k, Began pumping 6%KCL at 2bpm, Cir Psi 3000psi. Washed ream down to 9519'. Stacked 15k down on bit with no motor work. Made several short trips with different parameters and worked past 9519'. Continue wash/ream working down. Retruns 1/1 with light sand and rocks in the retruns. Could not work past 9570'. Contacted OE. Pumped 10bbl Hi-Vis sweep, dropped ball pumped 34bbls and observed cir sub shift open. Pumped total of 714 bbls retruned 630 bbls. Started N2 at 1200scfm lost returns after 16 bbl recovered. POOH to the csg shoe at 9400' established returns recovered 30bbls and lost returns again. Began POOH slowly at 6800' catch returns. Unload well with ck while POOH to surface. SI and trapped 1500 psi on well. Unloaded 95bbls from well bore. L/D BHA and Injector head. Installed night cap. Empitied return tank and SDFN. Report Number 15 Report Start Date 2/7/2024 Report End Date 2/8/2024 Operation PJSM, DIscuss daily operations, Travel to location form KGF office, Spot in & rig up, Pick up 2.75" x 14' CCL/GR/GPT, Stab onto well. Pressure test 250/3000-good, Open swab, Run in hole to see fluid level @ 6510' (Line unable to pass thru grease tubes) Pull out of hole & change out grease tubes to .29, Rehead Bleed well from 1450 psi to 900 psi. Pick up CCL/GR/GPT, Make up lube & open swab, Run in hole with tool string, Fluid level @ 6376' tag pbtd @ 9476'. Blow down well to 100 psi & shut in, Wait 20 min to recheck fluid top, New fluid top @ 6330', Pull out of hole. Rig rig down & release Yellow Jacket Report Number 16 Report Start Date 2/8/2024 Report End Date 2/9/2024 Operation Approve PTW and Held PJSM, warmed eq. MIRU Cruz Crane. P/u Injector head, M/u roll on CTC, DFCV, Mandel and 2-1/8" OD Jet Nozzel. Total BHA Lenght 7". Stab on well. PT 250-3500psi. 5min test was good. Open well with 330psi. RIH 120fpm. Stopped at 7500'ctm. On line with N2 at 1200scfm, CP 1350psi. RIH at 100fpm and parked at 9400'. Monitored for 1 hr and started seeing returns of fluid at surface. Unloaded 54bbls. SD N2 Pump. RIH and dry tag 9500'ctm. POOH f/9400' at 120fpm. Pumping 1000scfm held 700psi on wellhead with choke. AT surface no fluid recovered while POOH. SI well with 675psi. L/d Tools and Injector Head. RDMO Fox CTU #8. Production started Bleeding well looking for gas. Report Number 17 Report Start Date 2/9/2024 Report End Date 2/10/2024 Operation PTW and PJSM, R/u Ak E-line Unit, P/u lubricator and PCE. M/u tool string, 1-11/16 CCL, 3-3/8" Wt Bar, 1-11/16" GPT. Stab on well test 250/3500psi. good test. RIH find fluid level at 7400'. RIh to 9356' pressure reading 1071.41psi. POOH. Waiting on N2 pump to arrive from beaver creek. Released Ak Eline crew for night. R/u Fox N2 pump truck, hooked up iron and PT 3500psi. Good test. Open well with 130psi, on line with N2 at 500scfm. Worked rate up to 1200scfm and pushed fluid away, at 209,000scf pumped away pressure built to 3500psi. S/d N2 pump. R/d Fox N2 pump.Monitored 30mins SITP 2900psi. SDFN Report Number 18 Report Start Date 2/10/2024 Report End Date 2/11/2024 Operation Approve PTW and PJSM. Warmed eq. P/u lubricator and tools. Stab on well PT PCE 250/3500psi. good. Open well with 1000psi and RIH w/GPT find fluid at 9026'. Monitor 30mins fluid level at 8996'. R/u Fox N2, PT 250/3500psi good. Online with N2 pushed fluid to 9165'. POOH L/d GPT tool. Trapped 2300psi on Tbg. R/d Fox N2 pump. M/u CCL/Gamma/Setting tool and 3.71" OD Big Boy Bridge Plug. RIH correlated with CBL and set CIBP AT 9300'. Tag plug confirmed set and POOH. Bleed N2 from well, pressued backup to 200psi with gas. M/u 3-1/2 dump bailer and loaded with 10gals of cement. RIH and dumped cement on top of the CIBP. Est TOC at 9285'. POOH L/d bailer. SITP 210psi. Gun run #1. M/u 2-3/4" x 20' 6spf, 15 gram charge, Owen Gun. RIH pulled correlation pass f/9020' t/8830'. Send log to town confirmed on depth. CCL to top shot = 10.4'. Parked CCL at 9044.6'. Fired gun and Perforated Tyk D2 at 9055'-9075'. No change with well pressure. POOH L/d gun. All shots fired gun dry. Gun Run #2. M/u 2-3/4" x 19' 6spf, 15 gram charge, Owen Gun. RIH pulled correlation pass f/9020' t/8910'. Send log to town confirmed on depth. CCL to top shot = 11.1'. Parked CCL at 9024.9'. Fired gun and Perforated Tyk D2 at 9036'-9055'. No change with well pressure. POOH L/d gun. All shots fired gun dry. Gun Run #3, un run #1. M/u 2-3/4" x 20' 6spf, 15 gram charge, Owen Gun. RIH pulled correlation pass f/9020' t/8830'. Send log to town confirmed on depth. CCL to top shot = 10.3'. Parked CCL at 9005.7'. Fired gun and Perforated Tyk D2 at 9016'-9036'. No real change with well pressure. POOH L/d gun. All shots fired gun dry. RDMO AK E-Line, closed out PTW. SI well. Monitor for build up Report Number 19 Report Start Date 3/13/2024 Report End Date 3/14/2024 API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 324-011 State: ALASKA Rig/Service: Page 4/6 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation PTW and PJSM. MIRU Yellow Jacket e-line. P-test 250/3500psi. GIH with 3.625" GR/JB and GPT tool with well flowing at 387 mcfd and 20 psi. Found fluid level at ~9,055'. SI well. RIH with 31' 2-3/4" guns with Gamma/CCL. Correlate on depth with town. Perforate TY D1 from 8,914 - 8,945' with 2-3/4" guns, Geo Razor XDP 15g charges (P/N EC2-27A1522), 6 spf, 60 deg phasing. Lost line weight after perfing (2100 lb to 1400 lb). Init SITP (Shut-In Tubing Pressure): 132 psi 5 min SITP: 278 psi 10 min SITP: 312 psi 15 min SITP: 337 psi Start POH. Gamma/CCL did not appear to be working correctly. While POH, WL "bumped up" at 506' - could not get above this depth. Appears a line issue preventing pulling through grease head flow tubes. SITP 450 psi. Closed WL valve and tried to bleed off pressure from lubricator - would not bleed off. Slowly closed swab valve - felt resistance at 19.5 turns so stopped (fully closed is 24 turns). Same result with upper master. Cycled WL valve and hand spanged the wire. No change - wire won't move and pressure won't bleed off lubricator. Flow well and bring FTP down <100 psi. Close WL valve and try to bleed off - won't bleed off. Slowly close upper master to pinch wireline (19.5 turns). Close swab valve fully and cut wireline. L/D lubricator. Line was kinked. NU nightcap on top of WL valve. RDMO eline. SDFN. Report Number 20 Report Start Date 3/14/2024 Report End Date 3/15/2024 Operation Pre-job meeting with Yellow Jacket and Pollard at Pollard yard to discuss plans, equip, and tools. PTW and PJSM. MIRU Pollard .125" Slickline, WL valves, and 72' lub from Yellow Jacket. P-test 250/3500psi. SITP: 540 psi. Open swab valve and GIH with 3.7" 3-prong wire grab and wire finder baited with GR tool to upper master. Could not grab wire. Close lower master on wire and open upper master. Could not grab wire. GIH with 3" blind box to lower master. GIH with 3.7" 3-prong wire grab again to lower master. Could not grab wire. Open lower master and GIH with wire grab. Tag at 4,993'. Work fishing tools but wire keeps slipping off. Continue in hole to 5,193'. Work tools along with a couple of jar licks. Appear to grab wire and POH with 100# over PU wt. Once in lubricator lost 80#. Close swab valve and bleed off lub. LD tools, no wire recovered. LD lub and secure well. SDFN. SITP: 660 psi. Report Number 21 Report Start Date 3/15/2024 Report End Date 3/16/2024 Operation PTW and PJSM. SITP: 850 psi. PU lubricator and SL tools. GIH with 2.88" 2-prong wire grab and 3.7" wire finder. Tag at 161' and work tools. POH with 60# over PU wt. Close swab valve and pinched wire with 19.5 turns. Close WL valves. Open well to bleed down pressure to ~40 psi. Bleed off lubricator. Break lub, clamp wire. LD lub and SL tools. PU 8' lub section and WL packoff. Clamp wire above packoff. Pull wire with crane - made 3 pulls ~75'/ea then pulled the rest by hand. Closed swab valve, LD lub. Remove packoff - recovered all wire - pulled out of rope socket. GIH with 3.75" swage and 3" lead impression block - tag at 9,228' KB, beat down to 9,236'. Sticky picking up. POH, no impression on block. Shut-in well. GIH with 3"x 6' ball-bottom bailer - tag at 9,238' KB. POH, bailer 1/4 full of sand, a few wire strands and perf debris, with fluid on top. GIH with same bailer again - tag at 9,242' KB. POH, bailer full of thick sand/fluid slurry. Did not see a fluid level on any of the runs. RD Yellow Jacket lubricator and WL valves. Secure well and SDFN. SITP: 190 psi. Report Number 22 Report Start Date 3/16/2024 Report End Date 3/17/2024 Operation Arrive KGF jsa permit, Rig up 74' lub. p/t to 3500psi good test. RIH w/ 3.5''x7' dd bailer to 9225'slm 9243'kb w/ tool pooh see fluid @ 7680' cont. to pooh full thick slurry & wire strands. RIH w/ same to 9251' kb, w/t. pooh 1/4 full dry sand w/ perf debris fluid on top RIH w/ same to 9250'kb w/ tool pooh empty w/ metal marks on bailer bottom (Chisel Btm Broken Needs to be Replaced) RIH w/ 3.5''x20' pump bailer w/ deep opened ball bottom to 9232' SLM (9250' RKB) w/t 15mins POOH w/ fluid only RIH w/ 3.75'' L.I.B. to 9250'kb hit one time pooh w/ impression of rope socket RIH w/ 1 7/16'' over shot baited w/ 3 "GR 39''(overall length) to 9250'kb w/ tool latch beet down 30 times 3 jar licks to 1600# shears off pooh RIH/w 3" GS to 9229'SLM 9247' RKB relatch Bait sub w/t for 1 hour- shear off and POOH OOH Slip 50' of Wire and Check Toolstring Connections RIH w/ same to 9224'slm 9242'kb w/ tool for 1hr. Shear off pooh OOH break off 4 1/2' lub. Lay down 3 1/2'' lub. Secure well for night Turn in permit head to shop Report Number 23 Report Start Date 3/17/2024 Report End Date 3/18/2024 Operation Arrive KGF jsa permit C/O tool string w/ 2.25'' stem & long stroke oil jars cut 100' wire build lub. Stab on riser p/t lub. To 3500 psi good test RIH w/ 3'' GS to 9244'kb latch w/ tool jar for 1hr. To 1800# shear off pooh moved 3'. OOH cut 100' wire check tool string RIH w/ same to 9242'kb latch w/ tool jar for 1hr. Shear off pooh moved 1' OOH cut 100' wire check tool string O-ring leak developes above wire line valves. Replace. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 324-011 State: ALASKA Rig/Service: Page 5/6 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation RIH w/ same to 9241'kb latch w/ tool jar for 1hr. Shear off pooh OOH cut 100' wire check tool string RIH w/ same to 9241'kb latch w/ tool jar for 1hr. Shear off pooh OOH cut 100' wire check tool string RIH w/ same to 9240' kb, latch w/ tool. Jar for 1 hr. Shear off, POOH OOH rig down slickline secure well for prod. Report Number 24 Report Start Date 3/20/2024 Report End Date 3/21/2024 Operation Arrive KGF meet w/ prod. Jsa permit Start up equip. spot Cruz's crane upon rigging up crane-crane oper. Noticed bad spot in wire call for tools Crane fixed rig up 74' lub. p/t to 3500psi RIH w/ 3'' PRGS to 9226'KB w/ tool 3 jar licks to 3600# comes free pooh w/ fish Assist Yellow jacket breaking tool string Rig down slickline secure well clean area-tools Turn in permit head to shop Report Number 25 Report Start Date 3/22/2024 Report End Date 3/23/2024 Operation PTW/PJSM. MIRU Yellow Jacket e-line unit. MU 3.50" CIBP and CCL/GR/PT tools. P-test 250/3,500 psi - good (had to fix a leak on the lub). SITP: 703 psi. GIH with 3.50" CIBP and log correlation strip. Set CIBP at 9,005'. Tagged plug to confirm set. Fluid level at 7,750' based on PT log. POH and LD tools. SITP 741 psi. MU 3" x 25' dump bailer. Fill with 8 gal 16 ppg cement. Fluid level at 7,690' based on weight. Tag plug at 9,005' and dump cement. POH. SITP 755 psi. MU 3" x 25' dump bailer. Fill with 8 gal 16 ppg cement. Fluid level at 7,670' based on weight. Get on depth and dump cement for a total of 25' of cement above CIBP. POH. SITP 761 psi. GIH w/ 3.50" CIBP and log correlation strip. Set CIBP at 8,885'. Tagged plug to confirm set. Fluid level at 7,650' based on PT log. POH and LD tools. SITP 767 psi. MU 3" x 25' dump bailer. Fill with 6 gal 16 ppg cement. Tag plug at 8,885' and dump 10' cement. POH. LD tools and lubricator. SDFN. Report Number 26 Report Start Date 3/23/2024 Report End Date 3/24/2024 Operation PTW/PJSM. Yellow Jacket e-line unit on location from yesterday. PU lub and 2-3/4" guns with GR/CCL. SITP: 762 psi. GIH with 2-3/4" x 8' guns + GR/CCL. Guns loaded 6 spf, 60deg phasing, 15g Geo Razor XDP charges. Correlate on depth with Geologist in town. Perforate the T 73_1 sand from 7,421 - 7,429'. Init SITP: 762 psi 5 min SITP: 751 psi 10 min SITP: 751 psi 15 min SITP: 750 psi POH and LD guns. Confirmed all shots fired. GIH with 2-3/4" x 20' guns + GR/CCL. Guns loaded 6 spf, 60deg phasing, 15g Geo Razor XDP charges. Correlate on depth with Geologist in town. Perforate the T 72_8 sand from 7,362 - 7,382'. Init SITP: 744 psi 5 min SITP: 743 psi 10 min SITP: 742 psi 15 min SITP: 741 psi POH and LD guns. Confirmed all shots fired. Flow test well to production facilities. GIH with PT tool for pressure survey with well flowing. Made a couple of passes. Last pass the fluid level was at 7,605' and the well had stopped flowing. WHP 55 psi. POH and LD tools. RDMO. Report Number 27 Report Start Date 3/27/2024 Report End Date 3/28/2024 Operation PTW, JSA with YJOS. MIRU. PT lubricator 250/3500 psi. RIH with GPT . Sat down at 7372'. No signs of fluid. Perforate LB6A (7282'-7295'), LB 5C (7243'-7255'), LB 5A lwr (7174'-7179'), LB 5a sands (7141'-7153'). Pressure of 700 lbs was applied to well prior to perforating. After all perfs pressure was 741 psi. All guns fired. Bull plugs dry. Production to flow well. Report Number 28 Report Start Date 4/1/2024 Report End Date 4/2/2024 Operation YJ E-line obtain PTW and hold PJSM. MIRU, M/U GPT with setting tool and 3.50" CIBP in tandem (CCL to plug 16'). Move tools and lubricator to well head. PT 250 psi, low pressure leak. Replace Oring and PT 250psi/3000 psi. Pass. SITP - 1022 psi. Open swab, RIH, correlate and confirm tie-in (add 12' depth shift). Locate fluid level at 7080'. Position and set plug at 7125'. POOH. L/D setting tool and PU 3.00" x 20' cement dump bailer. Mix and fill bailer with 5 gal. - 15.8# cement slurry. RIH, tag and dump cement on plug. (Est. TOC- 7117'). POOH. Bleed well down to 700 psi. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 324-011 State: ALASKA Rig/Service: Page 6/6 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Well Operations Summary Operation OOH. M/U GR/CCL & (3) x 2.75" (6spf/60D) switch guns (4', 5', 4'). Tally CCL-T.S (9.5', 17', 24'). RIH, correlate, confirm on depth and perforate interval LB_4 (6927'-6931'). Start 683 psi 10 min: 683 psi. Pick up, position and shoot LB_3B MID (6848'-6853'). Start: 683 psi 10 min: 683psi. Pick up, position and shoot LB_3B UPR2 (6835'-6839'). Start: 683 psi 10 min: 683 psi. POOH. OOH. All shots fired, guns dry. M/U 12' gun (CCL-T.S. - 13'). RIH, correlate and shoot interval LB_3B UPR1 (6819'-6831'). Start: 686 psi 5 min: 688 psi 10 min: 688 psi 15 min: 689 psi. POOH. OOH. All shots fired, gun dry. M/U (2) swith guns (4' & 5') CCL-T.S. 9.5' & 17'. RIH, correlate, confirm on depth and shoot interval LB_2E LWR (6740'-6744'). Start: 694 psi 10 min: 695 psi. Pick up, position and shoot interval LB_2D interval (6662'-6667'). Start: 694 psi 15 min: 696 psi. POOH. OOH. All shots fired, gun dry. L/D tools and lubricator, secure well and SDFN. Turn well over to production to flow test add perfs. Report Number 29 Report Start Date 4/2/2024 Report End Date 4/3/2024 Operation YJ E-line PTW, PJSM. Rig back on well. SI well (30 psi) and begin jump gas to build pressure. M/U GR/CCL & 2.75" x 19' (6spf/60D) perf gun (CCL-T.S. 9.5'). RIH, correlate and confirm on depth. SITP- 689 psi. Position and shoot interval LB_2C (6629'-6648'). Start: 689 psi 5 min: 692 psi 10 min: 693 psi 15 min: 695 psi. POOH. OOH. All shots fired, gun dry. M/U 9' gun (CCL-TS 10.5'). RIH, correlate, confirm on depth and shoot interval LB_1F (6433'-6442'). Start: 713 psi 5 min: 716 psi 10 min: 717 psi 15 min: 718 psi. POOH. OOH. All shots fired. Guns dry. Remove GR/CCL and spent gun. M/U CCL & 13' gun (4.5' CCL -TS) RIH, correlate to ZXP and perf interval, confirm on depth and shoot interval LB_1C (6313'-6326'). Start: 741 psi 5 min: 744 psi 10 min: 745 psi 15 min: 746 psi. POOH. All shots fired, gun dry. M/U 15' gun (8.5' CCL-TS). RIH, correlate, confirm on depth and shoot interval LB_1B (6245'-6260'). Start: 763 psi 5 min: 772 psi 10 min: 775 psi 15 min: 778 psi. POOH. All shots fired, gun dry. M/U Gamma/Press/Temp tool, RIH logging down pass through perforations and locating flud level at 6950'. P/U tools to 6000' and standby while production flows well to stablized FTP 48 psi/78 mcfd. Run down pass and locate fluid level at 6805'. Continue flowing well, P/U tools to 6000'. After 45 minutes, run down pass and locate fluid level at 6704'. POOH. Secure well, RDMO E-line. production to continue flowing well. API: 50-133-20716-00-00 Field: Kenai Loop Sundry #: 324-011 State: ALASKA Rig/Service: Page 1/1 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Casing Surface Wellbore Wellbore Name:Original Hole Total Depth of Wellbore (ftKB):9,830.00 Original KB/RT Elevation (ft):83.20 RKB to GL (ft):18.00 KB-Casing Flange Distance (ft):22.00 KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description:Surface Run Date:12/16/2023 Set Depth (ftKB):1,698.94 Casing Weight on Slips (1000lbf):66,000.0 Pick Up Weight (1000lbf):90,000.0 Block Weight (1000lbf):15,000.0 Make-Up Contractor:Parker Casing Number Hrs to Run (hr):6.50 Ft/Min (ft/min):4.36 Run Job:231-00155 KU 13-06A Drilling, Drilling - Drilling, 12/10/2023 06:00 Set Depth (ftKB):1,698.94 Set Depth (TVD) (ftKB):1,689.4 Centralizer Detail:Every other joint up to 300' (Ran 20) Attribute Subtype: Value: Pipe Reciprocated?:Yes Pipe Rotated?:No Float Failed?:No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in) Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft) Btm (ftKB) Top (ftKB) 1 Casing Hanger 15 9.95 Cactus 1.20 23.30 22.10 1 Casing Pup Joint 10 3/4 9.95 45.50 L-80 2.00 25.30 23.30 39 Casing Joints 10 3/4 9.95 45.50 L-80 DWC 1,588.71 1,614.01 25.30 1 Float Collar 10 3/4 1.44 1,615.45 1,614.01 2 Casing Joints 10 3/4 9.95 45.50 L-80 DWC 81.65 1,697.10 1,615.45 1 Float Shoe 10 3/4 1.84 1,698.94 1,697.10 Page 1/1 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Cement Surface Casing Cement Type Casing Description Surface Casing Cement Cemented String Surface, 1,698.94ftKB Wellbore Original Hole Job 231-00155 KU 13-06A Drilling, Drilling - Drilling, 12/10/2023 06:00 Cementing Start Date 12/16/2023 Cementing End Date 12/16/2023 Top Depth (ftKB) 24.4 Cement Stages Stage Number: 1 Description Surface Casing Cement Top Depth (ftKB) 24.4 Bottom Depth (ftKB) 1,704.0 Top Measurement Method Returns to Surface Pump Start Date 12/16/2023 Cement in Place At 12/16/2023 Final Circulating Pressure (psi) 490.0 Plug Bump Pressure (psi) 1,062.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 65.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Tuned Spacer 1.20 10.50 57.5 57.5 3 Halliburton Lead Slurry Type I II A 317 2.44 12.00 138.0 138.0 5 Halliburton Tail Slurry Type I II A 304 1.16 15.80 62.0 62.0 5 Halliburton Displacement Spud Mud 9.10 155.0 155.0 5 Halliburton Post Job Calculations Subtype Value Page 1/1 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Casing Intermediate1 Wellbore Wellbore Name:Original Hole Total Depth of Wellbore (ftKB):9,830.00 Original KB/RT Elevation (ft):83.20 RKB to GL (ft):18.00 KB-Casing Flange Distance (ft):22.00 KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description:Intermediate1 Run Date:12/26/2023 Set Depth (ftKB):6,066.10 Casing Weight on Slips (1000lbf):125,000.0 Pick Up Weight (1000lbf):147,000.0 Block Weight (1000lbf):15,000.0 Make-Up Contractor:Parker Casing Number Hrs to Run (hr):20.50 Ft/Min (ft/min):4.93 Run Job:231-00155 KU 13-06A Drilling, Drilling - Drilling, 12/10/2023 06:00 Set Depth (ftKB):6,066.10 Set Depth (TVD) (ftKB):6,001.1 Centralizer Detail:Every jt t/ 5000' 133 total Attribute Subtype: Value: Pipe Reciprocated?:Yes Pipe Rotated?:No Float Failed?:No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in) Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft) Btm (ftKB) Top (ftKB) Casing Hanger 11 6.88 0.44 20.24 19.80 1 Casing Pup Jts 7 5/8 6.87 29.70 L-80 3.22 23.46 20.24 148 Casing Joints 7 5/8 6.87 29.70 L-80 TXP-BTC 5,958.86 5,982.32 23.46 Float Collar 8 1/2 BTC 1.32 5,983.64 5,982.32 2 Casing Joints 7 5/8 6.87 29.70 L-80 TXP-BTC 80.90 6,064.54 5,983.64 Float Shoe 8 1/2 BTC 1.56 6,066.10 6,064.54 Page 1/1 Well Name: KU 13-06A Report Printed: 4/12/2024www.peloton.com Cement Intermediate Casing Cement Type Casing Description Intermediate Casing Cement Cemented String Intermediate1, 6,066.10ftKB Wellbore Original Hole Job 231-00155 KU 13-06A Drilling, Drilling - Drilling, 12/10/2023 06:00 Cementing Start Date 12/27/2023 Cementing End Date 12/27/2023 Top Depth (ftKB) 1,774.0 Cement Stages Stage Number: 1 Description Intermediate Casing Cement Top Depth (ftKB) 1,774.0 Bottom Depth (ftKB) 6,066.1 Top Measurement Method Acoustic Log (CBL) Pump Start Date 12/27/2023 Cement in Place At 12/27/2023 Final Circulating Pressure (psi) 850.0 Plug Bump Pressure (psi) 1,600.0 Full Return? No Returns During Job (%) Volume to Surface (bbl) 0.0 Volume Lost (bbl) 98.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) tuned prime 3.82 10.50 61.0 61.0 5 Halliburton Lead Slurry l ll 653 2.39 12.00 286.0 286.0 5 Haliburton Tail Slurry l ll 154 1.24 15.30 31.5 31.5 5 Halliburton Displacement 6% KCL Polymer Mud 9.20 277.0 275.0 5 Halliburton Post Job Calculations Subtype Value Page 1/1 Well Name: KU 13-06A Report Printed: 4/11/2024www.peloton.com Casing Production1 Wellbore Wellbore Name:Original Hole Total Depth of Wellbore (ftKB):9,830.00 Original KB/RT Elevation (ft):83.20 RKB to GL (ft):18.00 KB-Casing Flange Distance (ft):22.00 KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description:Production1 Run Date:1/3/2024 Set Depth (ftKB):9,401.61 Casing Weight on Slips (1000lbf):135,000.0 Pick Up Weight (1000lbf):150,000.0 Block Weight (1000lbf):15,000.0 Make-Up Contractor:Parker Casing Number Hrs to Run (hr):13.50 Ft/Min (ft/min):11.61 Run Job:231-00155 KU 13-06A Drilling, Drilling - Drilling, 12/10/2023 06:00 Set Depth (ftKB):9,401.61 Set Depth (TVD) (ftKB):9,300.4 Centralizer Detail:Every other jnt to 6063' 42 total Attribute Subtype: Value: Pipe Reciprocated?:No Pipe Rotated?:No Float Failed?:No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in) Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft) Btm (ftKB) Top (ftKB) 1 Liner Hanger 6.53 4.78 31.81 5,482.46 5,450.65 1 XO 5 1/2 3.92 H563 1.78 5,484.24 5,482.46 21 Blank Liner 4 1/2 3.92 13.50 L-80 TXP-BTC 868.21 6,352.45 5,484.24 1 Marker Joint 4 1/2 3.92 13.50 L-80 TXP-BTC 41.39 6,393.84 6,352.45 24 Blank Liner 4 1/2 3.92 13.50 L-80 TXP-BTC 991.06 7,384.90 6,393.84 1 Marker Joint 4 1/2 3.92 13.50 L-80 TXP-BTC 41.40 7,426.30 7,384.90 23 Blank Liner 4 1/2 3.92 13.50 L-80 TXP-BTC 947.27 8,373.57 7,426.30 1 Marker Joint 4 1/2 3.92 13.50 L-80 TXP-BTC 41.38 8,414.95 8,373.57 11 Blank Liner 4 1/2 3.92 13.50 L-80 TXP-BTC 452.90 8,867.85 8,414.95 1 Marker Joint 4 1/2 3.92 13.50 L-80 TXP-BTC 41.41 8,909.26 8,867.85 10 Blank Liner 4 1/2 3.92 13.50 L-80 TXP-BTC 405.24 9,314.50 8,909.26 1 Landing Collar 5.04 2.41 Buttress Thread 1.09 9,315.59 9,314.50 1 Float Joint 4 1/2 3.92 13.50 L-80 TXP-BTC 41.38 9,356.97 9,315.59 1 Float Collar 5.04 2.41 TXP-BTC 1.51 9,358.48 9,356.97 1 Float Joint 4 1/2 3.92 13.50 L-80 TXP-BTC 41.33 9,399.81 9,358.48 1 Shoe 5.04 2.41 TXP-BTC 1.80 9,401.61 9,399.81 Page 1/1 Well Name: KU 13-06A Report Printed: 4/12/2024www.peloton.com Cement Production Casing Cement Type Casing Description Production Casing Cement Cemented String Production1, 9,401.61ftKB Wellbore Original Hole Job 231-00155 KU 13-06A Drilling, Drilling - Drilling, 12/10/2023 06:00 Cementing Start Date 1/4/2024 Cementing End Date 1/4/2024 Top Depth (ftKB) 6,031.0 Cement Stages Stage Number: 1 Description Production Casing Cement Top Depth (ftKB) 6,031.0 Bottom Depth (ftKB) 9,401.6 Top Measurement Method CBL Pump Start Date 1/4/2024 Cement in Place At 1/4/2024 Final Circulating Pressure (psi) 1,400.0 Plug Bump Pressure (psi) 1,750.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 56.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? No Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Tuned Spacer 12.50 26.0 26.0 3 Halliburton Lead Slurry G 401 1.87 13.00 131.0 131.0 3 Halliburton Tail Slurry A 99 1.24 15.30 17.5 17.5 3 Halliburton Displacement 6% KCL 11.80 128.0 132.1 4 Halliburton Post Job Calculations Subtype Value ! 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+ -. + + !" /+ /0 + #$% #$% 12!+&' ' "( ( )*$+,% -./0 3+#$% 0+12"3# 4 1 1 +"( ( )*$+,% -./0 4 2 + 5#$% 3 1 9 ; = 9:; > 9:; 768#/ 9 ; 748# 9 ; -. 9 ; -. 9 ; 1 4 23 9; 1 63 9; . 9; 9:8"?; -4, $ $,%+/ /+:$ $+6, $ ,**+:6 %$+$% %%+$,$ ,%:+$6 , $, *6+:6 ,6, %*/+$ %+ $**+%6 $>&54?"4& 4 9-,0 $ $*+/ *+$ $+/* $ $*+$ ,+ %,+:6$ ,:+ , $, **$+ ,6, %/,+% ,+%, $/+*$ $>&54?"4& 4 9-,0 $ $+$: 6+/ $+:: $ %/+** ,%+/, %+:$ $,+* , $, */,+ ,6, %/+$% %+: %:+%$ $>&54?"4& 4 9-,0 $ :%+$ *+, +6* $ 6%+, ,/+, %+6:$ $*6+% , $, /%%+$ ,6, %/+:: %+:6 $+%% $>&54?"4& 4 9-,0 $ :+$ *+% +,6 $ :$+$/ $6+/ %/+%$ *+/ , $, /%/+% ,6, %/*+/* %+ ,+ $>&54?"4& 4 9-,0 $ ,6+:: /+% +$* $ :/,+%/ 6+%6 +$$ :%*+*/ , $, /*+, ,6, %+* %+6 $%+6 $>&54?"4& 4 9-,0 $ */+: *+:$ +:* $ :$+$, :+, $+6%$ :6%+, , $, /,6+,, ,6, %+%, %+6* $*+/ $>&54?"4& 4 9-,0 $ 6:%+6% *+: :+6$ $ 6$+*$ +// +%*$ $%+$ , $, /$:+/: ,6, %+: %+,* 6+$* $>&54?"4& 4 9-,0 $ *,+% /+%: +: $ 66+6 6+% *+:$$ /+,6 , $, /+/6 ,6, %/+/ %+*: :+%* $>&54?"4& 4 9-,0 $ *6+, /+:: +// $ *$:+*$ *$+66 ,+%/$ 6:,+$ , $, /:+$ ,6, +/ %+* :+ $>&54?"4& 4 9-,0 $ /$6+%$ /+/% +% $ */6+6, /$+// ,$+/$$ *+:, , $, /+6/ ,6, +/6 %+, 6:+, $>&54?"4& 4 9-,0 $ //6+,/ %+: +,* $ /:6+% :%+%6 ,+*:$ *6$+* , $, /6+* ,6, *+%* %+, *+*: $>&54?"4& 4 9-,0 %:/+6% *+6* +66 %*+, :$+/: ,/+$ /$:+, , $, /*+ ,6, ,+%$ ,+,$ /+$$ $>&54?"4& 4 9-,0 ,+:% *+$6 +,/ %6/+6$ :,,+*6 $+/,$ //+:$ , $, //$+: ,6, ,$+: %+6 :%,+/% $>&54?"4& 4 9-,0 *$+% 6+% :+%6 %+6 :$%+* $+%% %:6+: , $$ %%+ ,6, ,:+6 ,+,, :%+:: $>&54?"4& 4 9-,0 ,:+%* +6 +*, ,%,+$ :$*+% $:+/, /+ , $$ %%*+:6 ,6, ,6+*% %+ :6+ $>&54?"4& 4 9-,0 $%+/* 6+%* :+$ ,$+6 ::+, $6+* *%+: , $$ %:+6$ ,6, ,/+* %+:: :,+$: $>&54?"4& 4 9-,0 $*+6 6+$: :+%* $,:+%% ::,+/ $/+* ,+*% , $$ %,$+* ,6, $,+%, %+ :$+:$ $>&54?"4& 4 9-,0 $%+*6 6+*$ :+/ $*+ :%+% ,+% $%$+ , $$ %$+% ,6, $+$6 %+6/ :$/+ $>&54?"4& 4 9-,0 /,+6* *+, +% 6+/, :*+*/ +* $+6, , $$ %$/+,* ,6, $+/: %+$ :6+%: $>&54?"4& 4 9-,0 ::$+* *+% +, :%*+$* :66+,6 +:* ,:+* , $$ %6+, ,6, $/+, +,, :::+ $>&54?"4& 4 9-,0 +:/ *+,* *+% :6%+* :*+%: *+%* *6+,* , $$ %:+$6 ,6, %+** %+* :$+ $>&54?"4& 4 9-,0 66+%6 *+: ,+6/ $%+$% :/+*% /+6% :6+% , $$ %:+%* ,6, ,+ +$% :6,+, $>&54?"4& 4 9-,0 6$/+/ /+, +$ /,+ %+,/ :+// %/+, , $$ %6+:, ,6, :+ %+/6 :*+, $>&54?"4& 4 9-,0 *%$+% /+6, +: 6:+, +$$ :+:/ 6+, , $$ %*+: ,6, 6+/$ %+* :/%+/ $>&54?"4& 4 9-,0 *+$, %+$ :+$$ *+// ,+, :6+$: 6$+6/ , $$ %/+6 ,6, :%+** %+/* %%+*% $>&54?"4& 4 9-,0 /,+:, /+:: +%$ *6+, $:+%% %+%6 6/$+% , $$ %:+%* ,6, :$+*% +,6 %+6 $>&54?"4& 4 9-,0 /*6+% /+:/ $+6* /$+/ +* ,+: *:$+,/ , $$ +** ,6, :+$ %+%/ ,%+,: $>&54?"4& 4 9-,0 : %/+%/ %+% +$ //6+%/ ::+% :+% /$+*/ , $$ ,+// ,6, :/+: %+/ $%+%, $>&54?"4& 4 9-,0 : +$ %+$ +: : %:*+ :+* 6+*, /6:+ , $$ $:+6/ ,6, ,+: +%% %+: $>&54?"4& 4 9-,0 : 6+,* %+, :+*% : ,%+,$ 6+* 6%+*%: %$6+%$ , $$ +* ,6, :+$$ %+6 :%+/ $>&54?"4& 4 9-,0 : ,$:+$, /+6 :+: : *%+$6 *+*6 6$+: %/6+6 , $$ :+* ,6, *+$ +,6 %+% $>&54?"4& 4 9-,0 : ,/*+:/ *+,$ +* : ,,+** /+,* 6+: :/+* , $$ +% ,6, 6+%, +/* /+$ $>&54?"4& 4 9-,0 : $%+*$ 6+6 +* : $%+:, 6%+6 6*+,6: ,,+$, , $$ 6+$* ,6, 6$+$$ %+6 66+/ $>&54?"4& 4 9-,0 : ,$+6% *+,% :+$/ : $+6* 6$+%/ *%+:$: ,*$+:* , $$ *,+6 ,6, 6:+6 %+6, *:+6* $>&54?"4& 4 9-,0 : *:+% *+, +: : ,6+$ 6,+6, *,+/6: $+,$ , $$ /+$ ,6, 6*+$ %+6 /+%: $>&54?"4& 4 9-,0 : :+*, /+% +: : **+: 6$%+*$ *:+: %:+$ , $$ ,%%+$/ ,6, *+, %+/ 6%,+6 $>&54?"4& 4 9-,0 : %/+6, /+$ +6 : ::%+% 6%+ **+:: 6+% , $$ ,%/+/ ,6, *+, %+* 6+/6 $>&54?"4& 4 9-,0 : 6,+% /+*/ +* : ,+% 6:%+ /+*: :,*+/% , $$ ,/+*/ ,6, *6+, %+** 6,+:, $>&54?"4& 4 9-,0 : 6$+:: /+ +/: : 6$+6 6%+:, /+$,: :/%+6 , $$ ,,/+/ ,6, /%+: %+*6 6$+6 $>&54?"4& 4 9-,0 % *+ , + # ! + -. + + !" /+ /0 + #$% #$% 12!+&' ' "( ( )*$+,% -./0 3+#$% 0+12"3# 4 1 1 +"( ( )*$+,% -./0 4 2 + 5#$% 3 1 9 ; = 9:; > 9:; 768#/ 9 ; 748# 9 ; -. 9 ; -. 9 ; 1 4 23 9; 1 63 9; . 9; 9:8"?; -4, : 6/+/ /+*$ $+ : 6$+6 66%+: /+*,: :+: , $$ ,$/+/% ,6, /$+: %+* 6%+*$ $>&54?"4& 4 9-,0 : *:*+6 /+: *+6, : 6/+$ 6*%+$ /*+6*: 6,+/$ , $$ ,/+/$ ,6, /:+$% +:/ 6:%+:/ $>&54?"4& 4 9-,0 : /,+6 *+:* $:6+%$ : *:*+$, 6/%+, //+,/: 66:+, , $$ ,:/+:: ,6, /+%% $+%% 6%+%/ $>&54?"4& 4 9-,0 : /*$+6* *+, $,+ : //+6 6//+$$ /6+:: *$+: , $$ ,*+: ,6, /+:, $+: 6/+,* $>&54?"4& 4 9-,0 %,*+$* *+* $$+: : /$+*, *%:+ /:+,6: **%+, , $$ ,6:+% ,6, /,+,6 ,+%6 66:+* $>&54?"4& 4 9-,0 %*$+ *+* $$,+* %6+/6 *$+: /+6: /$+66 , $$ ,*,+:* ,6, **+* +, 6*$+6$ $>&54?"4& 4 9-$0 + *+6/ $,$+% %6*+: *,%+/6 *+6%: //:+$ , $$ ,/%+:% ,6, *$+// ,+,6 6/,+% $>&54?"4& 4 9-$0 ,%6+6, /+,* $,%+6 +%$ *,*+6/ *%+:: %:6+*$ , $$ ,/*+$ ,6, 6*+%% %+/6 *%%+ $>&54?"4& 4 9-$0 ,*+/% *+/ $,+/ ,%+:% *$+ 6+/ *+$% , $$ $%:+/ ,6, 6,+:% ,+% *%*+ $>&54?"4& 4 9-$0 $$+: *+, $,+: ,$+:$ *$+ /+6 *%+$$ , $$ $$+,: ,6, 6+/ %+, *+$ $>&54?"4& 4 9-$0 $/$+/$ *+:, $,:+, $,:+, *:%+* +% ,,+% , $$ $,%+6: ,6, ,+6 %+/ *,+ $>&54?"4& 4 9-$0 ::+$, *+/ $,+$% $*:+/, *:*+:$ :/+$* $%,+6, , $$ $,*+:6 ,6, :6+ %+6% *$,+6 $>&54?"4& 4 9-$0 :*+,6 6+ $,,+* *+,, *:+/, :+: $:+%, , $$ $$+% ,6, :,+$, ,+, *%+* $>&54?"4& 4 9-$0 :*%+,$ 6+$6 $,%+*6 :%/+: *6,+,6 /+6 ,+: , $$ $,+: ,6, 6+: %+:6 *6+% $>&54?"4& 4 9-$0 $+* 6+*% $,+:$ :6,+6, *6*+*, $+/% */+:, , $$ $/+: ,6, ,+$, %+/ *:+6$ $>&54?"4& 4 9-$0 6%+6% *+% $,,+/% $,+/* **:+: $*+6 :/+6* , $$ $::+** ,6, $6+$ %+:$ *+/: $>&54?"4& 4 9-$0 66+,/ *+,/ $,+ /+/$ */,+$ $$+:% +6$ , $$ $$+ ,6, $,+* %+:$ */+6 $>&54?"4& 4 9-$0 *,*+6% *+$* $,:+% 6::+/ *//+/$ ,*+ 6,+/ , $$ $6%+: ,6, ,6+,$ %+,* *66+:* $>&54?"4& 4 9-$0 */%+,$ *+* $,6+,6 *+:$ /%6+% ,$+$$ 6$$+$$ , $$ $6*+$, ,6, ,,+$% %+* **:+*% $>&54?"4& 4 9-$0 /:,+:% *+%% $,%+*: *6*+ /+/6 *+%, 6/+/ , $$ $*:+6/ ,6, 6+$ +// */$+66 $>&54?"4& 4 9-$0 6 %$+%$ *+%% $*+6, /$*+%* /,+% ,+:* *:+** , $$ $/,+$, ,6, +*, %+/ /%%+*, $>&54?"4& 4 9-$0 6 %6+* *+$ $,%+% ///+,* /,*+%6 %+* /+%* , $$ $//+% ,6, %+,, %+, /%*+$ $>&54?"4& 4 9-$0 6 $:+/, *+$6 $,,+$: 6 %:/+/ /$+/* %+$% /6+/ , $$ %+, ,6, %%+*% %+: /:+6 $>&54?"4& 4 9-$0 6 /*+: *+$6 $,+$ 6 ,+ /,+,* /:+*6 %$*+ , $$ $+:, ,6, %/:+* %+ /,$+:* $>&54?"4& 4 9-$0 6 ,:/+ *+6 $,:+$$ 6 *+:/ //+:$ /%+6,6 %/*+$/ , $$ ,%+* ,6, %/%+:% %+$$ /$+% $>&54?"4& 4 9-$0 6 $,%+ *+$/ $,6+// 6 ,,+,: /:6+% *:+6*6 :/+%: , $$ ,*+ ,6, %*:+6 %+: /$/+: $>&54?"4& 4 9-$0 6 $*,+,% *+6$ $,/+,6 6 $%$+$% /+** *+%%6 ,,%+% , $$ $+% ,6, %*+%* %+$ /6+*, $>&54?"4& 4 9-$0 6 $+: *+$* $,:+*, 6 $$+*6 /6,+:6 6+6 ,*%+6 , $$ +* ,6, %6+$ +% /:+%: $>&54?"4& 4 9-$0 6 :%+,, *+6 $,6+,: 6 ,:+// /*%+ 6+$6 $,+6/ , $$ :+* ,6, %6+: %+6 /+$ $>&54?"4& 4 9-$0 6 :*+,, *+ $,+6, 6 *6+$ /*6+$* +,,6 %+ , $$ :/+* ,6, %+6 %+:/ /6+/: $>&54?"4& 4 9-$0 6 ,/+$ *+,6 $,6+% 6 :6+/: //+% +$6 +6: , $$ +/ ,6, %+// %+ /6/+6 $>&54?"4& 4 9-$0 6 /+%* 6+,$ $,%+*, 6 %/+%$ %%+$$ :+*6 :,:+*$ , $$ 6$+$ ,6, %:6+, ,+6 /*+// $>&54?"4& 4 9-$0 6 6:,+% 6+$ $,%+$ 6 /+* %%6+$$ :+:6 :*+ , $$ 6/+% ,6, %:,+ %+: //$+: $>&54?"4& 4 9-$0 6 *$+6 6+6, $,,+/ 6 6$%+ %$+, +:/6 6+ , $$ *:+6/ ,6, %6+, %+* %%%+$/ $>&54?"4& 4 9-$0 6 *6:+$$ 6+/, $,:+% 6 6/+/ %,%+$ +6%6 6%*+/ , $$ /,+/ ,6, %,+*: %+6 %%6+6 $>&54?"4& 4 9-$0 6 /$+: 6+* $,6+*6 6 *:,+$ %,6+ $6+%/6 6/+ , $$ //+*% ,6, %$*+$* %+:, %:+,* $>&54?"4& 4 9-$0 6 //*+: 6+6% $,,+, 6 /$+66 %$+$$ $,+,/6 *$%+:6 , $$ :%+66 ,6, %$$+6 +, %,,+/ $>&54?"4& 4 9-$0 * %%+/ 6+, $,+,6 6 /6+*: %%+/ ,6+$66 */+: , $$ :$+ ,6, %,*+/, %+ %,/+*, $>&54?"4& 4 9-$0 * ,,+$ *+,% $,%+,$ * %$+:% %6+6 ,,+,6 /:$+$% , $$ :,%+$% ,6, %,$+*% +,/ %$6+6 $>&54?"4& 4 9-$0 * *$+$ *+6/ $/+*/ * %/+6 %:+:6 +$:* %$+: , $$ :,6+$% ,6, %*+ %+/6 %+6 $>&54?"4& 4 9-$0 % *+ , + # ! 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PTD 2231120 Type Inj N Tubing 0 0 0 Type Test P Packer TVD 6001 BBL Pump 1.8 IA 3080 3050 3050 Interval O Test psi 3000 BBL Return 1.8 OA Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hillcorp Alaska LLC Kenai Gas Field KU 13-06A Waived Josh Riley 01/08/24 Notes:Post Completion test on rig, Tubing open to atmosphere due to bare foot completion. Notes: Notes: Notes: KU 13-06A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2024-0108_MITP_KU_13-06A J. Regg; 5/6/2024 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI UNIT 13-06A JBR 04/04/2024 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:3 Tested all with 4.5" test joint. Transducer failure between tests #4 and #5, replace transducer and continue testing. Test #6 Choke HCR F/P Grease, retest and pass, Test #7 TIW Leaking, Swap out TIW, retest, pass. , Test #8 (Blinds)leaking past test plug out IA. Pull test plug, redress, reinstall, Pass. No other failures Test Results TEST DATA Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Rig Owner/Rig No.:Hilcorp 169 PTD#:2231120 DATE:12/28/2023 Type Operation:DRILL Annular: 250/2500Type Test:BIWKLY Valves: 250/3700 Rams: 250/3700 Test Pressures:Inspection No:bopSTS240109165924 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 3633 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 FP 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 11"P #1 Rams 1 2 7/8"x5"Vari P #2 Rams 1 Blinds FP #3 Rams 1 2 7/8"x5"Vari 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", 2 1/16 FP Kill Line Valves 1 3 1/8"P Check Valve 0 P BOP Misc 0 NA System Pressure P3050 Pressure After Closure P1650 200 PSI Attained P27 Full Pressure Attained P107 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2525 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 P17 #1 Rams P5 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: KU 13-06A (PTD# 223-112) Sundry # 324-112 Additional perfs Date:Thursday, March 28, 2024 2:53:00 PM Chad, Hilcorp has approval to add the additional perfs listed below as part of Sundry 324-112. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, March 28, 2024 2:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KU 13-06A (PTD# 223-112) Sundry # 324-112 Additional perfs Bryan, We are requesting to add 2 additional zones to the approved sundry for perf in KU 13-06A. These 2 zones are in between existing approved perfs. We would like to add the following 2 zones to this well that are in the Beluga/Upper Tyonek gas Pool we plan to shoot next week. They are shown on the attached schematic in Blue font. Pool Sand Top (MD)Btm (MD)Top (TVD)Btm (TVD)Ft Bel/Up Tyk LB 1C 6313 6326 6245 6258 13 Bel/Up Tyk LB 2C 6629 6648 6558 6576 19 Please let us know if these are approved to add these zones to our perf plans on this well. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. _____________________________________________________________________________________ Updated by CAH 03-21-24 PROPOSED Kenai Gas Field Well: KU 13-06A PTD: 223-112 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 84 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 / L-80 / DWC/C 9.950” Surf 1,699’ 7-5/8" Intermediate 29.7 / L-80 / TXP BTC 6.875” Surf 6,066’ 4-1/2" Production 13.5 / L-80 / TXP BTC 3.920” 5,451’ 9,401’ Tieback Detail 4-1/2” Tieback 12.6 / L-80 / TXP BTC 3.958” Surface 5,455’ JEWELRY DETAIL No Depth ID Item 1 5,451’ 4.8” HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’ 4.875” Crossover 2’ long seal x tubing 3 5,455’ 4.80” Bullet Seal Assembly 1.86’ off No-Go 4 ±8,900’ CIBP w/ 10ft of 15.8ppg cement (3/22/24) 5 9,005’ CIBP w/ 25ft of 15.8ppg cement (3/22/24) 6 9,300’ CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4” Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8" Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2” Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD LB 1B ±6,245' ±6,260' ±6,178' ±6,192' ±15' TBD Proposed LB 1C ±6,313’ ±6,326’ ±6,245’ ±6,258’ ±13 New Proposed LB 1F ±6,433' ±6,442' ±6,364' ±6,373' ±9' TBD Proposed LB 2 Up ±6,451' ±6,468' ±6,382' ±6,398' ±17' TBD Proposed LB 2 Lwr ±6,487' ±6,496' ±6,417' ±6,426' ±9' TBD Proposed LB 2A ±6,524' ±6,534' ±6,454' ±6,464' ±10' TBD Proposed LB 2C ±6,629’ ±6,648' ±6,558’ ±6,576’ ±19 New Proposed LB 2D ±6,662' ±6,667' ±6,591' ±6,595' ±5' TBD Proposed LB 2E Lwr ±6,740' ±6,744' ±6,668' ±6,672' ±4' TBD Proposed LB 3 ±6,755' ±6,767' ±6,683' ±6,695' ±12' TBD Proposed LB 3A Up ±6,786' ±6,793' ±6,713' ±6,720' ±7' TBD Proposed LB 3A Lwr ±6,798' ±6,801' ±6,725' ±6,728' ±3' TBD Proposed LB 3B Up 1 ±6,819' ±6,831' ±6,746' ±6,758' ±12' TBD Proposed LB 3B Up 2 ±6,835' ±6,839' ±6,762' ±6,766' ±4' TBD Proposed LB 3B Mid ±6,848' ±6,853' ±6,775' ±6,780' ±5' TBD Proposed LB 4 Up ±6,925' ±6,932' ±6,851' ±6,858' ±7' TBD Proposed LB 4 Lwr ±6,947' ±6,954' ±6,873' ±6,880' ±7' TBD Proposed LB 4A Up ±6,957' ±6,964' ±6,883' ±6,890' ±7' TBD Proposed LB 4A ±6,969' ±6,985' ±6,894' ±6,910' ±16' TBD Proposed LB 4C Up ±7,052' ±7,057' ±6,977' ±6,982' ±5' TBD Proposed LB 4C ±7,068' ±7,082' ±6,992' ±7,006' ±14' TBD Proposed LB 5A 7,141' 7,153' 7,065' 7,077' ±12' 3/27/24 Open LB 5A Lwr 7,174' 7,179' 7,097' 7,102' ±5' 3/27/24 Open LB 5C 7,243' 7,255' 7,166' 7,178' ±12' 3/27/24 Open LB 6A 7,282' 7,295' 7,204' 7,217' ±13' 3/27/24 Open TY 72_8 7,362' 7,382' 7,283' 7,303' ±20' 3/23/24 Open TY 73_1 7,421' 7,429' 7,342' 7,350' ±8' 3/23/24 Open TY D1 8,915' 8,945' 8,820' 8,850' 30' 3/13/24 Isolated Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’ 9,075’ 8,920’ 8,978’ 59 02/10/24 Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/4/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240404 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf Please include current contact information if different from above T38683 T38684 T38685 T38686 T38689 T38687 T38690 T38691 T38691T38692 T38963 T38963 T38694 T38694 T38694 T38695 T38696 T38697 T38698 KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.09 13:48:29 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/19/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240319 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/5/2023 AK E-LINE Plug/Cement/Cutter GP ST 18742 37 (AN 37) 50733203940000 187109 11/12/2023 AK E-LINE PERF IRU 241-01 50283201840000 221076 2/25/2024 AK E-LINE Perf/GPT KU 13-06A 50133207160000 223112 2/9/2024 AK E-LINE GPT MPU CFP-02 50029212580000 184242 3/13/2024 READ CaliperSurvey NCIU A-18 50883201890000 223033 12/13/2023 AK E-LINE GPT/Plug/Perf PBU L-122 50029231470000 203051 3/2/2024 AK E-LINE LowerPatchPacker PBU L4-14 50029219730000 189098 11/22/2023 AK E-LINE PERF SRU 241-33B 50133206960000 221053 3/4/2024 AK E-LINE GPT/Cmnt/CIBP/Perf Please include current contact information if different from above. T38648 T38649 T38650 T38651 T38652 T38653 T38654 T38655 T38656 KU 13-06A 50133207160000 223112 2/9/2024 AK E-LINE GPT Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 11:50:20 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/14/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240314 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/20/2024 AK E-LINE GPT/PL BCU 13 50133205250000 203138 1/4/2023 AK E-LINE JetCut/CBL BRU 221-35 50283201930000 223077 11/18/2023 AK E-LINE Perf HV B-13 50231200320000 207151 12/22/2023 AK E-LINE CBL IRU 41-01 50283200880000 192109 11/16/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 1/16/2024 AK E-LINE GPT/Perf KTU 32-07H 50133205110000 202043 10/27/2023 AK E-LINE PPROF KU 3-06A 50133207160000 223112 1/12/2024 AK E-LINE CBL KU 21X-32 50133202040000 169100 12/8/2023 AK E-LINE JetCut MPU CFP-02 50029212580000 184242 3/9/2024 READ CaliperSurvey NCI A-18 50883201890000 223033 12/8/2023 AK E-LINE Perf/GPT NIA NK-18 50029224210000 193177 12/13/2023 AK E-LINE IPROF PTM P1-13 50029223720000 193074 12/9/2023 AK E-LINE Cement TBU M-11 50733205900000 210145 1/8/2024 AK E-LINE Perf TBU M-15 50733204220000 190109 2/7/2024 AK E-LINE GPT/Perf Please include current contact information if different from above. T38615 T38615 T38616 T38617 T38618 T38619 T38620 T38621 T38622 T38623 T38624 T38625 T38626 T38627 T38628 KU 3-06A 50133207160000 223112 1/12/2024 AK E-LINE CBL Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.15 11:38:35 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2, CTCO 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? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,830'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,560psi Intermediate 4,790psi Production 8,540psi Liner 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng LTP; N/A 5,451' MD/5,394' TVD; N/A, N/A 9,723'9,300'9,200' Kenai C.L.U.Tyonek Gas Pool 1 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 13-06ACO 510C Gas Pool 1, Beluga-Up Tyonek Gas 9,300'4-1/2" 3,201psi 3,950' 9,300' Length March 8, 2024 4-1/2" Tieback 9,401' Perforation Depth MD (ft): 6,066' See Attached Schematic 6,890psi 2,980psi 5,860psi 120' 6,001' 120' 1,699' Size 120' 7-5/8"6,066' 1,699' MD Hilcorp Alaska, LLC Proposed Pools: Tyonek 12.6# / L-80 TVD Burst 5,455' 9,020psi 1,689' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 223-112 50-133-20716-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:22 pm, Feb 27, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.02.26 09:31:13 - 09'00' Noel Nocas (4361) 324-112 SFD 2/29/2024 DSR-2/28/24BJM 2/29/24 10-404 X CT CT BOP test to 3500 psi. *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.01 07:35:17 -09'00'03/01/24 RBDMS JSB 030124 Initial Completion Well: KU 13-06A Well Name: KU 13-06A API Number: 50-133-20716-00-00 Current Status: Gas Producer Permit to Drill Number: 223-112 First Call Engineer: Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (c) Second Call Engineer: Jake Flora (720) 988-5375 (c) Maximum Expected BHP: 3431 psi @ 7854’ TVD 8.4 ppg normal gradient Max. Potential Surface Pressure: 3201 psi Using 0.1 psi/ft Applicable Frac Gradient: 0.70 psi/ft using 13.45 ppg EMW FIT at the int casing 12/29/24 Shallowest Potential Perf TVD: 5394’ TVD (LTP) - MPSP/(0.70-0.1) = 3201 psi / 0.6 = 5,335‘ TVD Top of Pools per CO 510C:Beluga/Upper Tyonek Gas Pool - 4730’ MD, 4683’ TVD Tyonek Gas Pool 1 - 9,001’ MD/8,905’ TVD This is a change of program to Sundry # 324-011 to additional perforations in the Beluga/Upper Tyonek Pool and commingle production with the Tyonek Gas Pool #1 perf CO 510C. Brief Well Summary KU 13-06A was drilled and completed with Hilcorp Rig 169 January 2024 targeting Tyonek, Upper Tyonek and Lower Beluga sands at Kenai Gas Field. The well was completed with 4.5” completion with a barefoot/open hole tail. The open hole tail was unsuccessful of production and plugged back. The Tyonek D Sand was perforated and brought online at a rate of approximately 300 mcfd. Wellbore Conditions: Annulus is filled with 12 ppg drill mud & tested to 3,000psi 7-5/8” Intermediate casing – 6,066’ (Cement to surface) 4-1/2” Monobore completion (landed 1/8/24) - 9401’ 6-3/4” Open hole plugged back with CIBP @ 9300’ with 16ft of cement Eline Procedure 1. MIRU E-line and pressure control equipment 2.PT lubricator to 250psi low / 3500psi high 3. RIH and perforate following sands per RE/Geo (see table below) Sands Top MD Btm MD Top TVD Btm TVD FT LB 1B ±6,245' ±6,260' ±6,178' ±6,192' ±15' LB 1F ±6,433' ±6,442' ±6,364' ±6,373' ±9' LB 2 Up ±6,451' ±6,468' ±6,382' ±6,398' ±17' LB 2 Lwr ±6,487' ±6,496' ±6,417' ±6,426' ±9' LB 2A ±6,524' ±6,534' ±6,454' ±6,464' ±10' LB 2D ±6,662' ±6,667' ±6,591' ±6,595' ±5' LB 2E Lwr ±6,740' ±6,744' ±6,668' ±6,672' ±4' LB 3 ±6,755' ±6,767' ±6,683' ±6,695' ±12' LB 3A Up ±6,786' ±6,793' ±6,713' ±6,720' ±7' LB 3A Lwr ±6,798' ±6,801' ±6,725' ±6,728' ±3' LB 3B Up 1 ±6,819' ±6,831' ±6,746' ±6,758' ±12' LB 3B Up 2 ±6,835' ±6,839' ±6,762' ±6,766' ±4' LB 3B Mid ±6,848' ±6,853' ±6,775' ±6,780' ±5' LB 4 Up ±6,925' ±6,932' ±6,851' ±6,858' ±7' Top of Pools per CO 510C: Commingling conditionally allowed under CO 510C. Note requirements of Rule 5(b). SFD Initial Completion Well: KU 13-06A LB 4 Lwr ±6,947' ±6,954' ±6,873' ±6,880' ±7' LB 4A Up ±6,957' ±6,964' ±6,883' ±6,890' ±7' LB 4A ±6,969' ±6,985' ±6,894' ±6,910' ±16' LB 4C Up ±7,052' ±7,057' ±6,977' ±6,982' ±5' LB 4C ±7,068' ±7,082' ±6,992' ±7,006' ±14' LB 5A ±7,141' ±7,153' ±7,065' ±7,077' ±12' LB 5A Lwr ±7,174' ±7,179' ±7,097' ±7,102' ±5' LB 5C ±7,243' ±7,255' ±7,166' ±7,178' ±12' LB 6A ±7,282' ±7,295' ±7,204' ±7,217' ±13' TY 72_8 ±7,362' ±7,382' ±7,283' ±7,303' ±20' TY 73_1 ±7,421' ±7,429' ±7,342' ±7,350' ±8' TY D1 ±8,885' ±8,945' ±8,790' ±8,850' ±60' 4. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing, (if using switched guns, wait 10 min between shots) b. Pending well production, all perf intervals may not be completed c. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations d. If isolating the Tyonek Pool the plug will be set ~9000ft (avoiding collars & within 50ft of top Tyonek Gas 1 Pool Perf) and 25ft of cement will be placed on top of plug with a dump bailer. e. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations f. Above perfs are in the Beluga/Upper Tyonek Pool governed by CO 510C 5. RD E-Line Unit and turn well over to production 6. Operations to flow well and test zones 7. A production survey will be run within 30 days of commingling production as per CO 510C for allocation purposes. Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 8. MIRU Coiled Tubing Unit, PT BOPE to 3,500 psi High/250 psi Low 9. Provide AOGCC 24hrs notice of BOP test 10. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 11. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 12. RDMO coil tubing Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic _____________________________________________________________________________________ Updated by DMA 02-12-24 CURRENT SCHEMATIC Kenai Gas Field Well: KU 13-06A PTD: 223-112 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,401’ Tieback Detail 4-1/2”Tieback 12.6 / L-80 / TXP BTC 3.958”Surface 5,455’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go 4 9,300’CIBP (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2” Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top Of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,920’8,978’59 02/10/24 Open _____________________________________________________________________________________ Updated by DMA 02-21-24 PROPOSED Kenai Gas Field Well: KU 13-06A PTD: 223-112 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,401’ Tieback Detail 4-1/2”Tieback 12.6 / L-80 / TXP BTC 3.958”Surface 5,455’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go 4 9,300’CIBP w/ 15.6ft of 15.8ppg cement (2/10/24) OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Beluga/Upper Tyonek Gas Pool -4730’ MD, 4683’ TVD LB 1B ±6,245'±6,260'±6,178'±6,192'±15'TBD Proposed LB 1F ±6,433'±6,442'±6,364'±6,373'±9'TBD Proposed LB 2 Up ±6,451'±6,468'±6,382'±6,398'±17'TBD Proposed LB 2 Lwr ±6,487'±6,496'±6,417'±6,426'±9'TBD Proposed LB 2A ±6,524'±6,534'±6,454'±6,464'±10'TBD Proposed LB 2D ±6,662'±6,667'±6,591'±6,595'±5'TBD Proposed LB 2E Lwr ±6,740'±6,744'±6,668'±6,672'±4'TBD Proposed LB 3 ±6,755'±6,767'±6,683'±6,695'±12'TBD Proposed LB 3A Up ±6,786'±6,793'±6,713'±6,720'±7'TBD Proposed LB 3A Lwr ±6,798'±6,801'±6,725'±6,728'±3'TBD Proposed LB 3B Up 1 ±6,819'±6,831'±6,746'±6,758'±12'TBD Proposed LB 3B Up 2 ±6,835'±6,839'±6,762'±6,766'±4'TBD Proposed LB 3B Mid ±6,848'±6,853'±6,775'±6,780'±5'TBD Proposed LB 4 Up ±6,925'±6,932'±6,851'±6,858'±7'TBD Proposed LB 4 Lwr ±6,947'±6,954'±6,873'±6,880'±7'TBD Proposed LB 4A Up ±6,957'±6,964'±6,883'±6,890'±7'TBD Proposed LB 4A ±6,969'±6,985'±6,894'±6,910'±16'TBD Proposed LB 4C Up ±7,052'±7,057'±6,977'±6,982'±5'TBD Proposed LB 4C ±7,068'±7,082'±6,992'±7,006'±14'TBD Proposed LB 5A ±7,141'±7,153'±7,065'±7,077'±12'TBD Proposed LB 5A Lwr ±7,174'±7,179'±7,097'±7,102'±5'TBD Proposed LB 5C ±7,243'±7,255'±7,166'±7,178'±12'TBD Proposed LB 6A ±7,282'±7,295'±7,204'±7,217'±13'TBD Proposed TY 72_8 ±7,362'±7,382'±7,283'±7,303'±20'TBD Proposed TY 73_1 ±7,421'±7,429'±7,342'±7,350'±8'TBD Proposed TY D1 ±8,885'±8,945'±8,790'±8,850'±60'TBD Proposed Top of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 9,016’9,075’8,920’8,978’59 02/10/24 Open Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/16/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# END 1-27 50029216930000 187009 2/6/2024 YELLOW JACKET PERF KU 13-06A 50133207160000 223112 2/7/2024 YELLOW JACKET GPT MPU G-18 50029231940000 204020 2/8/2024 READ Caliper Survey MPU B-28 50029235660000 216027 1/15/2024 YELLOW JACKET PATCH PBU PAVE 1-1 50029237670000 223094 1/5/2024 YELLOW JACKET CBL SRU 241-33B 50133206960000 221053 2/8/2024 YELLOW JACKET GPT Please include current contact information if different from above. T38513 T38514 T38515 T38516 T38517 T38518 2/21/2024 YELLOW KU 13-06A 50133207160000 223112 2/7/2024 JACKET GPT Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.21 09:17:43 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/2/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240202 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 213-26 50283201920000 223069 11/5/2023 AK E-LINE PERF KU 13-06A 50133207160000 223112 12/28/2023 AK E-LINE CBL MPU B-09 50029212970000 185034 1/26/2024 READ Caliper Survey MPU B-19 50029214510000 185230 1/26/2024 READ Caliper Survey PBU W-08A 50029219060100 202090 12/27/2023 HALLIBURTON WFL-TMD3D SRU 222-33 50133207150000 223100 12/16/2023 AK E-LINE CBL Please include current contact information if different from above. T38477 T38478 T38479 T38480 T38481 T38482 2/2/2024 KU 13-06A 50133207160000 223112 12/28/2023 AK E-LINE CBL Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.02 15:40:47 -09'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 01/26/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 13-06A PTD: 223-112 API: 50-133-20716-00-00 FINAL LWD FORMATION EVALUATION LOGS (12/23/2023 to 01/02/2024) ROP, EWR-M5, ADR, AGR, PCG, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. PTD: 223-112 T38448 1/29/2024Kayla Junke Digitally signed by Kayla Junke Date: 2024.01.29 15:36:30 -09'00' 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:Daniel Scarpella To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Cole Bartlewski; Chad Helgeson Subject:Hilcorp Fox 8 1-13-2024 Date:Wednesday, January 17, 2024 2:30:32 PM Attachments:Hilcorp Fox CTU 8 1-13-24.xlsx Some people who received this message don't often get email from daniel.scarpella@hilcorp.com. Learn why this is important Phoebe, Attached is the BOPE test from Fox CTU #8 on KU 13-06A. Thank you, Daniel Scarpella Hilcorp North Slope LLC., Alaska | Sr. Well Site Supervisor | PBU Wells Team 907.230.2692 cell | 907.659.5580 office | H 2154 | alt. Anthony Knowles Well Interventions: daniel.scarpella@hilcorp.com RWO Operations: pbwellsrwowss@hilcorp.com P.O. Box 340067| DP PBOC 34 | PBOC 20| Prudhoe Bay, AK 99734 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. .HQDL8QLW$ 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSubmit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:8 DATE: 1/13/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2231120 Sundry #324-011 Operation: Drilling: Workover: x Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3500 Annular:n/a Valves:250/3500 MASP:3201 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Other Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA P Annular Preventer 0NAPit Level Indicators NA P #1 Rams 1 4-1/16" Blind/Shear P Flow Indicator NA P #2 Rams 1 1-3/4" Pipe/Slip P Meth Gas Detector NA P #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)2950 P Kill Line Valves 2 2"P Pressure After Closure (psi)2300 P Check Valve 0NA200 psi Attained (sec)4 P BOP Misc 1PFull Pressure Attained (sec)18 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge: 4/1400 P Quantity Test Result Nitgn. Bottles # & psi (Avg.):NA No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 27 P Coiled Tubing Only:#2 Rams 26 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:2.0 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/12/2023 14:50 hrs Waived By Test Start Date/Time:1/13/2024 14:00 (date) (time)Witness Test Finish Date/Time:1/13/2023 16:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Fox Test w/ Meth/water. Note: Daniel Scarpella sent the 24hr notice and received the system reply at 15:02 1/12/24, No response from AOGCC field rep... Called Jim Regg, as per automated email instructions, Left messages at 09:53 AM & 12:53 PM 1/13/2024. No reply. Jeremy Hart Hilcorp Alaska LLC. Daniel Scarpella KU 13-06A Test Pressure (psi): jeremyhart76@gmail.com daniel.scarpella@hilcorp.com Form 10-424 (Revised 08/2022)2024-0113_BOP_Fox8_KU_13-06A 9 9 À 9 9 9 9 9 9 9 9 MEU -5HJJ 9 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: Initial Completion, N2_ 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? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,830'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,560psi Intermediate 4,790psi Production 8,540psi Liner 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 223-112 50-133-20716-00-00 Hilcorp Alaska, LLC Proposed Pools: 13.5# / L-80 TVD Burst 5,455' 9,020psi 1,689' Size 120' 7-5/8"6,066' 1,699' MD See Attached Schematic 6,890psi 2,980psi 5,860psi 120' 6,001' 120' 1,699' January 20, 2024 4-1/2" Tieback 9,401' Perforation Depth MD (ft): 6,066' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 13-06ACO 510C Same 9,300'4-1/2" 3,201psi 3,950' N/A Length LTP; N/A 5,451' MD/5,394' TVD; N/A, N/A 9,723'9,665'9,560' Kenai C.L.U.Tyonek Gas Pool 1 16" 10-3/4" See Attached Schematic m n P 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:22 am, Jan 11, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.01.10 16:53:37 - 09'00' Noel Nocas (4361) 324-011 BJM 1/11/24 X Perforate Yes 1/12/24 & 1/17/24 Bryan McLellan SFD 1/11/2024 DSR-1/17/24 Verbal approval granted CT BOP test to 3500 psi. Submit CBL and Obtain approval from AOGCC before blowing down the well with N2 or perforating. 10-407 JLC 1/17/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.01.17 14:34:02 -09'00'01/17/24 RBDMS JSB 011724 Initial Completion Well: KU 13-06A Well Name: KU 13-06A API Number: 50-133-20716-00-00 Current Status: New Drill Gas Producer Permit to Drill Number: 223-112 First Call Engineer: Chad Helgeson (907) 229-4824 (c) Second Call Engineer: Jake Flora (720) 988-5375 (c) Maximum Expected BHP: 4151 psi @ 9504’ TVD 8.4 ppg normal gradient Max. Potential Surface Pressure: 3201 psi Using 0.1 psi/ft Brief Well Summary KU 13-06A was drilled and completed with Hilcorp Rig 169 January 2024 targeting Tyonek, Upper Tyonek and Lower Beluga sands at Kenai Gas Field. The well was TD’ last week and completed with 4.5” completion with a barefoot/open hole tail. The objective of this sundry is to run a CBL, test tubing, clean out the liner with coil tubing, and swap fluids in well and attempt to flow well from open hole completion. Initial targeted sands will be in the Kenai Tyonek Gas Pool 1per CO 510C Wellbore Conditions: Well is filled with 12 ppg drilling mud Annulus is filled with 12 ppg drill mud & tested to 3,000psi 7-5/8” Intermediate casing – 6,066’ (fully cemented) 4-1/2” Monobore completion (landed 1/8/24) - 9401’ 6-3/4” Open hole 9401-9830’ Pool Tops: Kenai Tyonek Gas Pool 1 – 9,001’ MD/8,905’ TVD Eline Procedure 1. Review all approved COAs 2. MIRU E-line, PT lubricator to 3500 psi High/250 psi Low 3. RIH and log CBL from 4. RD Eline Coiled Tubing Procedure 5. MIRU Coiled Tubing and pressure control equipment 6. PT lubricator to 250psi low / 3500psi high x Provide AOGCC notice for BOP test 7. MU cleanout BHA/Nozzle 8. Mix up 250bbls of 6% KCl 9. RIH to casing shoe (9400’) and circulate out 12 ppg drill mud to 8.5 ppg KCl (~140bbls of mud) x Open hole section is normal gradient (0.433 psi/ft) or depleted 10. POOH x Formation should be slightly over pressured, maintain hole fill while POOH. 11. PU 4-1/2” WRP to set on coil Log CBL from PBTD to at least 300' above top of 4-1/2" liner. Obtain approval from AOGCC before blowing down the well with N2 or perforating. -bjm Initial Completion Well: KU 13-06A x If necessary to run WRP on Eline PT lubrication to 3500 psi 12. Set WRP in production liner and test 4-1/2” tieback 13. POOH 14. Pressure test tubing to 3,500 psi (30 min charted) 15. RIH and pull WRP 16. RU Nozzle with side jets and RIH to bottom and tag between 9665-9830’ 17. If possible go to a minimum of 9700’ and circulate out 12 ppg mud. (~11 bbls of mud) circulate bottoms up +50bbls to ensure mud is removed 18. SI well to see if any flow or pressure build 19. If no pressure build, start N2 down tubing while moving pipe and staying open hole interval (9400- 9700) 20. Monitor fluid volume while starting N2 (when coil reel volume is returned ~30bbls) start pinching back choke on return tank 21. Pinch back well to maintain a bottom hole pressure >2500psi as N2 lifts fluid from well 22. Circulate fluid from wellbore (116 bbls) with coil at 9700ft 23. With 40-50 bbls returned, start POOH chasing N2 out of well 24. When N2 is returned at surface, target ~3200 psi of N2 on well 25. POOH 26. Operations attempt to flow well, bleed off N2 and route gas to production. 27. Test SVS as per 20 AAC 25.265 once stable flow is achieved a) Notify AOGCC 24hrs in advance of testing SVS Eline in Open Hole (Contingency) If Open hole completion does not flow without stimulation: 28. MIRU E-line and pressure control equipment 29. PT lubricator to 250psi low / 3500psi high 30. RIH and perforate sand in open hole per RE/Geo (see table below) Sands Top MD Btm MD Top TVD Btm TVD FT Comment Tyk D2 ±9,016’ ±9,075’ ±8,920’ ±8,978’ ±59 In casing Tyk D3B ±9,397’ ±9,431’ ±9,296’ ±9,329’ ±34 ½ shoe & ½ Open Hole Tyk D3D ±9,481’ ±9,514’ ±9,379’ ±9,411’ ±33 Open Hole Tyk D4B ±9,547’ ±9,586’ ±9,444’ ±9,482’ ±39 Open Hole Tyk D4D ±9,608’ ±9,654’ ±9,504’ ±9,549’ ±46 Open Hole 31. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing b. Above perfs will be shot in the Kenai Tyonek Gas Pool 1 governed by CO 510C 32. RD E-Line Unit and turn well over to production 33. Operations to flow well and test zones 34. Test SVS as per 20 AAC 25.265 once stable flow is achieved Initial Completion Well: KU 13-06A b) Notify AOGCC 24hrs in advance of testing SVS E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 35. MIRU Eline and N2 pump truck 36. Pressure test equipment to 3,500 psi High/250 psi Low 37. Eline run PT to find fluid level 38. RU N2 or use gas lift and push fluid below perfs (verify fluid depth with PT tool) 39. PU 4-1/2” CIBP/Expandable plug or patch (if in casing) If necessary to cleanout, place cement plug or unload well with coiled tubing, 40. MIRU Coiled Tubing Unit, PT BOPE to 3,500 psi High/250 psi Low 41. Provide AOGCC 24hrs notice of BOP test 42. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 43. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole b. If setting cement in open hole with coil tubing lay cement in to volume desired RE/GEO team 44. RDMO coil tubing Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure _____________________________________________________________________________________ Updated by CAH 1-9-24 SCHEMATIC Kenai Gas Field Well: KU 13-06A PTD: 223-112 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.958”5,451’9,401’ Tieback Detail 4-1/2”Tieback 13.5 / L-80 / TXP BTC 3.958”Surface 5,455’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 _____________________________________________________________________________________ Updated by CAH 1-9-24 PROPOSED Kenai Gas Field Well: KU 13-06A PTD: 223-112 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7 / L-80 / TXP BTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.958”5,451’9,401’ Tieback Detail 4-1/2”Tieback 13.5 / L-80 / TXP BTC 3.958”Surface 5,455’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2”Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top Of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 ±9,016’±9,075’±8,920’±8,978’±59 Proposed TBD Tyk D3B ±9,397’±9,431’±9,296’±9,329’±34 Proposed TBD Tyk D3D ±9,481’±9,514’±9,379’±9,411’±33 Proposed TBD Tyk D4B ±9,547’±9,586’±9,444’±9,482’±39 Proposed TBD Tyk D4D ±9,608’±9,654’±9,504’±9,549’±46 Proposed TBD Superseded STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. _____________________________________________________________________________________ Updated by CAH 1-16-24 PROPOSED Kenai Gas Field Well: KU 13-06A PTD: 223-112 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / DWC/C 9.950”Surf 1,699’ 7-5/8"Intermediate 29.7/ L-80/TXPBTC 6.875”Surf 6,066’ 4-1/2"Production 13.5 / L-80 / TXP BTC 3.920”5,451’9,401’ Tieback Detail 4-1/2”Tieback 12.6 / L-80 / TXP BTC 3.958”Surface 5,455’ JEWELRY DETAIL No Depth ID Item 1 5,451’4.8”HRDE ZXPN Liner Tops Packer 5.50” PBR 2 5,452’4.875”Crossover 2’ long seal x tubing 3 5,455’4.80”Bullet Seal Assembly 1.86’ off No-Go OPEN HOLE / CEMENT DETAIL 10-3/4”Pumped 138 bbls of 12ppg Type I lead, followed by 62 bbls of 15.8 ppg tail. 65 bbls of lead cement returns 7-5/8"Pumped 286 bbls of 12 ppg Lead & 31.5 bbls of 15.3 ppg tail in 9-7/8” Hole. CBL TOC at 1774’ on 12/28/23. 4-1/2” Pumped 131 BBL’s (401 sx) of 13ppg Lead & 17.5 bbls (99sx) of 15.3 ppg Type I cmt with LCM. Circed 56bbls of cement after setting liner. CBL run on 1/12/24 cement top at 6031’. Notes: RA Tags – 8868’, 8374’, 7385’, 6352 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top Of Tyonek Gas Pool 1 - 9001’ MD, 8905’ TVD Tyk D2 ±9,016’±9,075’±8,920’±8,978’±59 Proposed TBD Tyk D3B ±9,397’±9,431’±9,296’±9,329’±34 Proposed TBD Tyk D3D ±9,481’±9,514’±9,379’±9,411’±33 Proposed TBD Tyk D4B ±9,547’±9,586’±9,444’±9,482’±39 Proposed TBD Tyk D4D ±9,608’±9,654’±9,504’±9,549’±46 Proposed TBD 1 Christianson, Grace K (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, January 17, 2024 11:39 AM To:Chad Helgeson Cc:Donna Ambruz; Davies, Stephen F (OGC); Roby, David S (OGC); Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: KU 13-06A (PTD#223-112) Chad, Hilcorphasverbalapprovaltoproceedwiththeremainderofthesundry,includingŇowingthebarefootsecƟonand perforaƟngperthesundrysubmiƩedon1/11/24. FYI,thesundrynumberis324Ͳ011. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:ChadHelgeson<chelgeson@hilcorp.com> Sent:Tuesday,January16,20248:44AM To:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Cc:DonnaAmbruz<dambruz@hilcorp.com>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Roby,DavidS(OGC) <dave.roby@alaska.gov> Subject:RE:[EXTERNAL]RE:KU13Ͳ06A(PTD#223Ͳ112) Yes,therewasanextrasetofperfsshownabovethelineforthetopofthepool.AtthisƟmewedonotplanto perforateanythingabovethePool. IupdatedtheschemaƟcwiththeperfsremoved,ĮxedanerrorintheƟebackdetailsoftheweightofpipeandchanged thecommentonthecementtop. Chad From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Sent:Tuesday,January16,20248:04AM To:ChadHelgeson<chelgeson@hilcorp.com> Cc:DonnaAmbruz<dambruz@hilcorp.com>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Roby,DavidS(OGC) <dave.roby@alaska.gov> Subject:RE:[EXTERNAL]RE:KU13Ͳ06A(PTD#223Ͳ112) 2 Chad, I’dcallTOCat6051’MDwithfreepipeabovethat. TheproposedwellborediagramshowsthetopoftheTyonekGasPoolinthemiddleoftheproposedperfs,butthat doesn’talignwiththePooltoplistedat9001’MDonpage1oftheprocedureand9016’astheshallowestplanned addperf.Isthereamistakeonthediagram? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:ChadHelgeson<chelgeson@hilcorp.com> Sent:Tuesday,January16,20247:48AM To:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Cc:DonnaAmbruz<dambruz@hilcorp.com>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Roby,DavidS(OGC) <dave.roby@alaska.gov> Subject:RE:[EXTERNAL]RE:KU13Ͳ06A(PTD#223Ͳ112) Bryan, PleaseĮndaƩachedtheCBLforKU13Ͳ06A. ReminderthattheLeadcementonthisjobswas13ppg.Itlookslikewehave13ppgleadcementfrom8620tothetop oftheliner~5460’.Thetopofthe15.3ppgcementlooksgoodfromboƩomto8620’. Wedidstartthejobandsettheplugandtestedthetubingyesterday,heldlikearock.Wewillbepullingtheplugtoday andifwehaveapproval,probablymovingtoblowingdownthewellwithN2ifyouapprovetheplanforward. Thanks Chad From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Sent:Friday,January12,20242:20PM To:ChadHelgeson<chelgeson@hilcorp.com> Cc:DonnaAmbruz<dambruz@hilcorp.com>;DanielScarpella<Daniel.Scarpella@hilcorp.com>;Davies,StephenF(OGC) <steve.davies@alaska.gov>;Roby,DavidS(OGC)<dave.roby@alaska.gov> Subject:[EXTERNAL]RE:KU13Ͳ06A(PTD#223Ͳ112) CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 3 Chad, OnemorecondiƟonofapproval,theCBLloggingintervalshouldbefromapproximatelytheboƩomofthe4.5”linerto ~200’abovethetopoftheliner. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:McLellan,BryanJ(OGC) Sent:Friday,January12,20242:18PM To:ChadHelgeson<chelgeson@hilcorp.com> Cc:DonnaAmbruz<dambruz@hilcorp.com>;DanielScarpella<Daniel.Scarpella@hilcorp.com>;Davies,StephenF(OGC) <steve.davies@alaska.gov>;Roby,DavidS(OGC)<dave.roby@alaska.gov> Subject:RE:KU13Ͳ06A(PTD#223Ͳ112) Chad, Hilcorphasverbalapprovaltocompletesteps1Ͳ22ofthesundryapplicaƟonsubmiƩedon1/11/24forthiswell,withthe followingcondiƟons: 1. CTBOPtestto3500psi. 2. SubmitCBLandobtainapprovalfromAOGCCbeforeblowingdownthewellwithN2orperforaƟng. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:ChadHelgeson<chelgeson@hilcorp.com> Sent:Friday,January12,20241:18PM To:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Cc:DonnaAmbruz<dambruz@hilcorp.com>;DanielScarpella<Daniel.Scarpella@hilcorp.com> Subject:KU13Ͳ06A(PTD#223Ͳ112) CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 4 Bryan, Aswediscussed,wewouldliketostartprogressingthecompleƟononKU13Ͳ06AatKenaiGasField. Wewouldliketoproceedthisweekendwithstepsto#22wherewehavePTthetubingandcleanedthewelloutinopen holesecƟontoKCl.Ifyouconcurwithourplansforward,pleaseprovideusverbalapprovaltoStep22,andwewillbe abletostartworkthisweekend.IexpectwewouldnotbepastthispointunƟlMondayaŌernoon. PleaseletmeknowifyouhaveanyquesƟons. ChadHelgeson OperationsEngineer KenaiAssetTeam 907Ͳ777Ͳ8405ͲO 907Ͳ229Ͳ4824ͲC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Joshua Riley - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:BOPE Test Report Date:Monday, January 8, 2024 2:23:23 PM Attachments:KU 13-06A IA MIT 1-8-24.xlsx Here is the MIT IA from KU 13-06A Thank You Josh RileyHilcorp DSM: 907-283-1369Cell: 907-252-1211 Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Kenai Unit 13-06A PTD 2231120 ===========MITjbr STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI UNIT 13-06A JBR 03/01/2024 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 Test Results TEST DATA Rig Rep:Porterfield / VanWulfenOperator:Hilcorp Alaska, LLC Operator Rep:Pederson / Gruenberg Rig Owner/Rig No.:Hilcorp 169 PTD#:2231120 DATE:12/18/2023 Type Operation:DRILL Annular: 250/2500Type Test:INIT Valves: 250/3700 Rams: 250/3700 Test Pressures:Inspection No:bopAGE231227062634 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4.5 MASP: 3633 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2 7/8 X 5"P #2 Rams 1 Blind P #3 Rams 1 2 7/8 X 5"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 & 2 1/16 P Kill Line Valves 1 2 1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1700 200 PSI Attained P21 Full Pressure Attained P88 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@ 2469 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P18 #1 Rams P4 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 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 Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Kenai Gas Field, Tyonek Gas Pool 1, KU 13-06A Hilcorp Alaska, LLC Permit to Drill Number: 223-112 Surface Location: 418' FSL, 1065' FWL, Sec 6, T4N, R11W, SM, AK Bottomhole Location: 1809' FSL, 821' FWL, Sec 6, T4N, R11W, SM, AK Dear Mr. Myers: 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 8 day of December 2023. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.08 14:22:24 -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: 10,200' TVD: 10,092' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 83.2 15. Distance to Nearest Well Open Surface: x- 271981 y- 2362473 Zone-4 65.2 to Same Pool: 2893' to KBU 32-06 16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 9 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 13-1/2" 10-3/4" 45.5# L-80 VAM21 1,692' Surface Surface 1,692' 1,680' 9-7/8" 7-5/8" 29.7# L-80 TXP 6,064' Surface Surface 6,064' 6,000' 6-3/4" 4-1/2" 13.5# L-80 TXP 4,336' 5,864' 5,802' 10,200' 10,092' Tieback 4-1/2" 13.5# L-80 TXP 5,864' Surface Surface 5,864' 5,802' 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: Contact Email: Contact Phone: 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 KU 13-06A Kenai Gas Field Tyonek Gas Pool 1 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 561 sx / T - 148 sx 1480 1339' FSL, 1170' FWL, Sec 6, T4N, R11W, SM, AK 1809' FSL, 821' FWL, Sec 6, T4N, R11W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 418' FSL, 1065' FWL, Sec 6, T4N, R11W, SM, AK FEE A028142 2494 18. Casing Program:Top - Setting Depth - BottomSpecifications 4642 Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 274 sx / T - 291 sx LengthCasing Conductor/Structural Effect. Depth MD (ft):Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Drilling Manager Monty Myers 12/12/2023 7420' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 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): L - 226 sx / T - 91 sx Tieback Assy s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 11/16/23 Monty M Myers By Grace Christianson at 10:34 am, Nov 17, 2023 DSR-11/20/23 223-112 50-133-20716-00-00 ? SFD 12/12/2023 BOP test to 3700 psi. Annular test to 2500 psi. SFD 12/8/2023 Diverter waiver approved; see advisory cautions on page 8. *This application is for a proposed new well. *SFD Submit 7-5/8" CBL to AOGCC as soon as data becomes available Submit FIT/LOT data to AOGCC within 48 hrs of acquiring data 3633 psi -bjm BJM 12/8/23 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.08 14:22:48 -09'00' 12/08/23 12/08/23 KU 13-06A Drilling Program Kenai Gas Field Rev. PTD November 13, 2023 KU 13-06A Drilling Procedure Contents 1.0 Well Summary...........................................................................................................................2 2.0 Management of Change Information........................................................................................3 3.0 Tubular Program:......................................................................................................................4 4.0 Drill Pipe Information:..............................................................................................................4 5.0 Internal Reporting Requirements.............................................................................................5 6.0 Planned Wellbore Schematic.....................................................................................................6 7.0 Drilling / Completion Summary................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications..................................................................8 9.0 R/U and Preparatory Work.....................................................................................................10 10.0 N/U 21-1/4” 2M Diverter .........................................................................................................11 11.0 Drill 13-1/2” Surface Hole Section...........................................................................................12 12.0 Run 10-3/4” Surface Casing ....................................................................................................14 13.0 Cement 10-3/4” Surface Casing...............................................................................................16 14.0 BOP N/U and Test....................................................................................................................19 15.0 Drill 9-7/8” Hole Section ..........................................................................................................20 16.0 Run 7-5/8” Intermediate Casing..............................................................................................22 17.0 Cement 7-5/8” Intermediate Casing........................................................................................24 18.0 Drill 6-3/4” Hole Section ..........................................................................................................27 19.0 Run 4-1/2” Production Liner ...................................................................................................29 20.0 Cement 4-1/2” Production Liner .............................................................................................31 21.0 4-1/2” Liner Tieback Polish Run .............................................................................................35 22.0 4-1/2” Tieback Run ..................................................................................................................35 23.0 BOP Schematic ........................................................................................................................37 24.0 Wellhead Schematic.................................................................................................................38 25.0 Anticipated Drilling Hazards ..................................................................................................39 26.0 Hilcorp Rig 169 Layout ...........................................................................................................41 27.0 FIT/LOT Procedure.................................................................................................................42 28.0 Choke Manifold Schematic......................................................................................................43 29.0 Casing Design Information......................................................................................................44 30.0 9-7/8” Hole Section MASP .......................................................................................................45 31.0 6-3/4” Hole Section MASP .......................................................................................................46 32.0 Spider Plot (Governmental Sections NAD27).........................................................................47 33.0 Surface Plat (As-Staked NAD27 & NAD83)...........................................................................48 Page 2 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 1.0 Well Summary Well KU 13-06A Pad & Old Well Designation KGF 14-06 pad Planned Completion Type 4-1/2”Production Liner w/Tieback Target Reservoir(s)Lower Beluga through Deep Tyonek Planned Well TD, MD / TVD 10200’MD / 10092’ TVD PBTD, MD 10100’ MD AFE Number AFE Drilling Days 31 AFE Drilling Amount Maximum Anticipated Pressure (Surface)1480 psi Maximum Anticipated Pressure (Downhole/Reservoir)4642 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB –GL 83.20 Ground Elevation 65.20 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram ? See page 8. SFD MPSP = 3638 psi. -bjm 1480 psi Page 3 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”17”84 X-56 Weld 2980 1410 - Surface 13-1/2”10-3/4”9.95”9.875”11.48”45.5 L-80 VAM21 5860 2560 1171 Intermediate 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 TXP 6890 4790 683 Prod 6-3/4”4-1/2”3.920”3.795”5.0”13.5#L-80 TXP 9020 8540 307 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out of scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each work day to KenaiCIODrilling@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. Brad Duwe (907-398-6558) 2. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 3. For Spills: Jason Hobart –907-598-5889 © 907-283-1358 (O) x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com Page 6 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic Page 7 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 7.0 Drilling / Completion Summary KU 13-06A will target the lower Beluga through deep Tyonek sands. The Lower Beluga through Deep Tyonek section at KGF needs downspacing. Utilizing and existing conductor the grassroots well will kick off to the north at ~600’MD. Maximum hole angle will be 9 degrees. The TD of the three string well will be 10200’ TMD/ 10092’ TVD. Drilling operations are expected to commence in December 2023. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. 10-3/4” surface casing will be run and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to KGF 14-06 pad 2. Drill 13-1/2”hole to 1692’ MD. Run and cmt 10-3/4”surface casing. 3.N/U & test 11” x 5M BOP to 3000 psi 4. Test Surface casing to 3000 psi. 5. Drill out shoe and perform a FIT to 12.8 ppg EMW 6. Drill 9-7/8” intermediate hole to 6064’MD 7. RIH w/ 7-5/8” casing to surface and cement to 1000’. 8. Perform casing test to 3500 psi. Swap rams to 4-1/2”. 9.Run CBL across 7-5/8” casing 10. PU 6-3/4” motor drilling assembly and TIH to window. 11.Mill shoe track and 20’ of new hole. 12. Perform FIT to 13.3 ppg EMW 13. Drill 6-3/4” production hole to 10,200’MD 14. Run and cmt 4-1/2”production liner. 15. PU polish mill assembly and RIH to polish sealbore 16. Displace well above liner top to 6% KCL completion fluid. 17. RIH and land 4-1/2” tieback string in liner top. 18. MIT Tubing and IA to 3000 psi. 19. N/D BOP, N/U dry hole tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Intermediate hole: GR + Res LWD 3. Production Hole: Triple Combo LWD 4. Mud loggers from surface casing point to TD. TBD Test tubing and IA to 3700 psi. -bjm Test BOP to 3700 psi. -bjm Page 8 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of KU 13-06A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or could be assumed damaged, test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC drilling permit is posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. AOGCC Regulation Variance Requests: x 20 AAC 25.005(c)(4)(A) Requesting alternative calculation of maximum potential surface pressure. The worst case MASP in the drilling mode will be 2/3 evacuation of wellbore gas with the reaming 1/3 volume in wellbore remains drilling fluid density. The high pressure at TD is a pressurized water zone with any influx being water. o Alternative MASP calculation granted on KU 24-05B, KU 11-07X, KU 14-05, and others. x 20 AAC 25.035(h)(2) - Diverter waiver request requested due to the recent drilling of KU 11-07X , KU 24-05B, KU 24-32, KU 42-12, KU 44-08, and KU 44-01B. No issues or shallow gas was experienced on these wells drilling surface hole. Surface casing will be set at a similar depth of these wells. o Divert waiver requests granted on KU 44-08, KU 42-12, KU 24-32, KU 11-07X, and KU 14-05 * Of these, only wells KU 11-07X and 42-12 are located at this drill site. Recommend approving requested diverter waiver; however, very careful monitoring is strongly advised for mud weight and gas encountered. No shallow gas related incidents were reported in records examined from 19 nearby wells. However, 50 to 120 Units of gas (1 to 2.4% methane; LEL is 5%) were recorded in nearby wells 21-07X, 23-07, and 11-07X in strata equivalent to those between about 1,000' MD and surface casing shoe in this proposed well. SFD KU 42-12, KU 11-07X, * ()()( ) q g p p The worst case MASP in the drilling mode will be 2/3 evacuation of wellbore gas with the reamingg 1/3 volume in wellbore remains drilling fluid density. 3700 psi Request for alternative calculation of MPSP is denied. -bjm MPSP to be calculated based on reservoir pressure minus a 0.1 psi/ft gradient. -bjm * g No issues or shallow gas was,,,, experienced on these wells drilling surface hole. * Page 9 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 13-1/2”x 21-1/4” x 2M Riser N/A 9-7/8” and 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 2016 Waste Prevention Rule - Waste Minimization Plan for Drilling: Hilcorp Alaska will not be venting or flaring any gas while drilling this well. The only waste produced from this well will be used mud and cuttings and will be handled at the Kenai Gas Field G&I facility for injection disposal. Page 10 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 13-1/2”hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2”liners. Page 11 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE: Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. N/U 21-1/4” 2M Diverter 10.1 Depends on if diverter waiver is approved or not. If diverter waiver approved, these steps will be skipped. -bjm N/U 21-1/4” Hydril MSP 2M diverter System.N/U x yy N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. approved,these steps will be skipped x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x g Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit sog that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64:g 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of thepy g vent line tip. “Warning Zone” must include: x pg A prohibition on vehicle parking. x ppg A prohibition on ignition sources or running equipment. x pg gq A prohibition on staged equipment or materials. x pgqp Restriction of traffic to essential foot or vehicle traffic only. Page 12 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 10.5 KU 13-06A location on KGF 14-06 Pad: N/A 11.0 Drill 13-1/2”Surface Hole Section 11.1 P/U directional drilling assy: x 13-1/2” Openhole, 8” drilling tools x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Page 13 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor. 11.3 Drill surface hole section to 1692’MD/ 1680’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~700 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Kenai and Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x Take MWD surveys every stand drilled (60’ intervals). 11.4 13-1/2”hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.0 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1692’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed Page 14 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.5 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16”conductor shoe. 11.6 TOH with the drilling assy, handle BHA as appropriate. 12.0 Run 10-3/4”Surface Casing 12.1 R/U and pull wear bushing. 12.2 R/U Parker 10-3/4”casing running equipment. x Ensure 10-3/4”Vam21 x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 10-3/4”surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Note M/U torque values required to achieve this position. x Install (1) centralizer every other joint to 1200’. Do not run any centralizers above 1200’ in the event a top job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Page 16 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 12.7 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.9 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.10 After circulating, lower string and land hanger in wellhead again. 13.0 Cement 10-3/4”Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x Discuss how to handle cmt returns at surface. x Confirm which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Determine positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 17 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (1192’ MD to surface)Tail Slurry (1692’ to 1192’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.40 ft3/sk 1.16 ft3/sk Mixed Water 14.25 gal/sk 5.04 gal/sk Mixed Fluid 14.25 gal/sk 5.04 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss CalSeal Accelerator CalSeal Accelerator VersaSet Thixotropic CFR-3 Dispersant D-Air 5000 Anti Foam UCS Slurry Conditioner Econolite Light-weight add.Super CBL Anti-Gas Migration SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 18 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 11 bbls. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Page 19 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. 14.0 BOP N/U and Test 14.1 ND Riser 14.2 N/U multi-bowl wellhead assy. Install 10-3/4” packoff P-seals. Test to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 7-5/8” fixed bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run BOP test assy, land out test plug (if not installed previously). x Utilize 7-5/8” and 4-1/2” test joints. x Test BOP to 250/3000 psi for 5/10 min. x Test annular to 250/2500 psi for 5/10 min with a 4-1/2” test joint x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.2 ppg 6% KCL PHPA mud system. 14.8 R/U mud loggers for production hole section. 14.9 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section. BOP test to 3700 psi -bjm 9-7/8" SFD Page 20 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 15.0 Drill 9-7/8” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 9-7/8” hole section mud program summary: Starting mud weight for the production interval is 9.2ppg or the surface interval mud weight at TD, whichever is heavier. Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.2 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1692’- 6064’9.0 –9.7 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation: 6% KCL EZ Mud DP Page 21 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 –10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 10-3/4” burst is 5860 psi / 2 = 2930 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 12.8 ppg EMW. (12.5 FIT, 8.5 ppg BHP, 9.3 ppg MW = 22 bbl KTV) 15.14 Drill 9-7/8” hole section to 6064’ MD / 6000’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~400 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise.Halfway through the hole section make a wiper back to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4”shoe. 15.16 TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 15.17 POOH LDDP and BHA. 15.18 Ensure 7-5/8” FBRs previously installed in BOP stack and tested with 7-5/8” test joint. Page 22 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 16.0 Run 7-5/8” Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” TXP x CDS40 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Ensure all casing has been drifted to 6.75” on the location prior to running. x Note that 29.7# drift is 6.75” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80’ shoe track assembly consisting of: 7-5/8” Float Shoe 1 joint –7-5/8” BTC, 1 Centralizer 10’ from bottom w/ stop ring 7-5/8” Float Collar 1 joint –7-5/8” BTC, 1 Free floating centralizer 7-5/8” Landing collar 5. Continue running 7-5/8” intermediate casing x Centralization: x 1 centralizer every joint to 1000’ MD (Planned TOC) x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 23 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Page 24 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 8. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 9. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 10. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging. Stage up pump slowly and monitor losses closely while circulating. 11. After circulating, lower string and land hanger in wellhead again. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 17.0 Cement 7-5/8” Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. Page 25 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to 1000’. Estimated Cement Volume: Cement Slurry Design: Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs. -bjm Page 26 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 11. Ensure rig pump is used to displace cement. 12. Land hanger. 13. Displacement volume is in Table above. 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 17. Not expected, but be prepared for cement returns to surface. Cement return to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 18. R/D cement equipment. Flush out wellhead with FW. 19. Back out and L/D landing joint. Flush out wellhead with FW. 20. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 21. Lay down landing joint and pack-off running tool. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) Page 27 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 18.0 Drill 6-3/4” Hole Section 1. Set test plug, Swap 7-5/8” FBR to 2-7/8” x 5” VBR, test to 3000 psi.,Pull test plug, run and set wear bushing 2.Run CBL across the 7-5/8” casing. Ensure TOC is above 4000’ MD (~462’ above Pool 6) 3. Ensure BHA components have been inspected previously. 4. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly. 6. Ensure TF offset is measured accurately and entered correctly into the MWD software. 7. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 8.Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 9. 6-3/4” hole section mud program summary: Starting mud weight for the production interval is 11.2 ppg or the intermediate interval mud weight at TD, whichever is heavier. Ensure TOC is above 4000’ MD (~462’ above Pool 6)Run CBL Page 28 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 11.2 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 6064’- 10200’10.8 –12.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 –10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 10. TIH w/ 4-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 11. R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8” burst is 6880 psi / 2 = 3440 psi. 12.Drill out shoe track and 20’ of new formation. 13. CBU and condition mud for FIT. 14. Conduct FIT to 13.3 ppg EMW. (13.0 FIT, 8.8 ppg BHP, 11.2 ppg MW = 20 bbl KTV) 15. Drill 6-3/4” hole section to 10200’ MD / 10092’ TVD Page 29 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through to interval make a wiper trip to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. 16. At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 17. TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 18. POOH LDDP and BHA. 19. Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint 19.0 Run 4-1/2”Production Liner 1. R/U Parker 4-1/2”casing running equipment. x Ensure 4-1/2”TXP x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x MU a marker joint (short joint with RA tag) every 1000’ 4. Continue running 4-1/2”production liner Page 30 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free floating. Page 31 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 5. Run in hole w/ 4-1/2” liner to the 7-5/8” casing shoe. 6. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 7. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 8. Circulate 2X bottoms up at shoe, ease casing thru shoe. 9. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. Set casing slowly in and out of slips. 11. PU 4-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 12. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 13. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 14. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 20.0 Cement 4-1/2”Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x Plan for cmt returns at surface, regardless of how unlikely it is that this should occur. x Determine which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. Page 32 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 x Document efficiency of all possible displacement pumps prior to cement job. 2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 3. Pump 5 bbls spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining spacer. 6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Estimated Total Cement Volume: 125.2 bbls 130.42 bbls Volumes corrected per Sean McLaughlin email 12/4/23. Verified -bjm 402.1 sks -bjm 311.6 sks 149.12 bbls Page 33 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 Cement Slurry Design: 7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow –continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 11. Slack off total liner weight plus 30k to confirm hanger is set. 12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 1 bbls. 13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. Lead Slurry (9700’ MD to 5864 MD)Tail Slurry (10200’ to 9700’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Page 34 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from the liner. 15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on wellview: Page 35 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. 21.0 4-1/2”Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker procedure. 18.3. CBU and displace well to 6% KCl completion fluid. 18.4. POOH LDDP and BHA 18.5. If not completed, test 4-1/2” liner to 3000 psi and chart for 10 minutes 22.0 4-1/2” Tieback Run 19.1 PU 3-1/2” tieback assembly and RIH with 4-1/2” 13.5# L-80 TXP tubing x No SSSV, GLM, or CIM required. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 PU hanger and land string in hanger bowl. Note distance of seals from no-go. 19.4 Install packoff and test hanger void. Page 36 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 19.5 Test 4-1/2” liner and tieback to 3000 psi and chart for 30 minutes. 19.6 Test 7-5/8” x 4-1/2” annulus to 3000 psi and chart for 30 minutes. 19.7 Install BPV in wellhead 19.8 N/D BOPE 19.9 N/U dry hole tree or full tree (if available). 19.10 RDMO Hilcorp Rig #169 Test liner and tieback to 3700 psi. -bjm Page 37 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 23.0 BOP Schematic Page 38 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 24.0 Wellhead Schematic Page 39 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 25.0 Anticipated Drilling Hazards 9-7/8”Hole Section: Lost Circulation: Drilling through low pressure intervals: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 –45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. Abnormal pressures or temperatures: None Page 40 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. Reservoir Pressure: Abnormal pressures expected in the deep Tyonek inteval Page 41 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 26.0 Hilcorp Rig 169 Layout Page 42 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 27.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 43 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 28.0 Choke Manifold Schematic See updated choke manifold diagram for Rig 169 in attached email from Sean McLaughlin dated 12/4/23. -bjm Page 44 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 29.0 Casing Design Information Page 45 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 30.0 9-7/8” Hole Section MASP No justification provided for requested alternative MASP. See 20 AAC 25.005(c)(4)(A). SFD ? 2640 psi - (400 psi + 880 psi) = 1360 psi SFD Page 46 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 31.0 6-3/4” Hole Section MASP MPSP for this hole section is 3633 psi based on 0.1 psi/ft gas column. -bjm No justification provided for requested alternative MASP. See 20 AAC 25.005(c)(4)(A). SFD ? 4642 psi - (673 psi + 1480 psi) = 2489 psi SFD Page 47 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 32.0 Spider Plot (Governmental Sections NAD27) Page 48 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 33.0 Surface Plat (As-Built NAD27 & NAD83) Page 49 Version PTD November, 2023 KU 13-06A Drilling Procedure Rev 0 ! "##$ % & %&' -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 Tr u e V e r t i c a l D e p t h ( 1 5 0 0 u s f t / i n ) -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 353.00° (1500 usft/in) KU 13-06A tgt1 wp03 KU 13-06A tgt2 wp03 10 3/4" x 13 1/2" 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 500 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 2 0 1 KU 13-06A wp03 Start Dir 3º/100' : 500' MD, 500'TVD End Dir : 796.79' MD, 795.6' TVD Start Dir 3º/100' : 5907.79' MD, 5845'TVD End Dir : 6153.42' MD, 6088.2' TVD Total Depth : 10200' MD, 10092.22' TVD Top Pool 3_A6 Top Pool 4 Top Pool 5 Top Pool 6 Top Upper Beluga Top Middle Beluga Top Lower Beluga Top Upper Tyonek Top Tyonek D1 Tyonek D5 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: KU 13-06A 65.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2362473.29 271981.59 60° 27' 38.2441 N 151° 15' 47.7070 W SURVEY PROGRAM Date: 2023-11-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1692.00 KU 13-06A wp03 (KU 13-06A) 3_MWD+IFR1+MS+Sag 1692.00 6065.00 KU 13-06A wp03 (KU 13-06A) 3_MWD+IFR1+MS+Sag 6065.00 10200.00 KU 13-06A wp03 (KU 13-06A) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3354.20 3271.00 3386.60 Top Pool 3_A6 3741.20 3658.00 3778.32 Top Pool 4 3866.20 3783.00 3904.85 Top Pool 5 4417.20 4334.00 4462.57 Top Pool 6 4657.20 4574.00 4705.50 Top Upper Beluga 5282.20 5199.00 5338.12 Top Middle Beluga 6080.20 5997.00 6145.34 Top Lower Beluga 7243.20 7160.00 7320.70 Top Upper Tyonek 8770.20 8687.00 8863.93 Top Tyonek D1 9599.20 9516.00 9701.74 Tyonek D5 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: KU 13-06A, True North Vertical (TVD) Reference:RKB As-Built @ 83.20usft (HEC 169) Measured Depth Reference:RKB As-Built @ 83.20usft (HEC 169) Calculation Method: Minimum Curvature Project:Kenai Gas Field Site:KGF 14-6 Pad Well:Plan: KU 13-06A Wellbore:KU 13-06A Design:KU 13-06A wp03 CASING DETAILS TVD TVDSS MD Size Name 1680.00 1596.80 1691.98 10-3/4 10 3/4" x 13 1/2" 6000.00 5916.80 6064.36 7-5/8 7 5/8" x 9 7/8" 10092.22 10009.02 10200.00 4-1/2 4 1/2" x 6 3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD 3 796.79 8.90 14.01 795.60 22.33 5.57 3.00 14.01 21.49 End Dir : 796.79' MD, 795.6' TVD 4 5907.79 8.90 14.01 5845.00 789.87 197.06 0.00 0.00 759.97 Start Dir 3º/100' : 5907.79' MD, 5845'TVD 5 6153.42 8.32 323.32 6088.20 822.61 191.03 3.00 -119.20 793.20 KU 13-06A tgt1 wp03 End Dir : 6153.42' MD, 6088.2' TVD 6 10200.00 8.31 323.32 10092.22 1292.04 -158.63 0.00 -176.35 1301.74 Total Depth : 10200' MD, 10092.22' TVD 0 75 150 225 300 375 450 525 600 675 750 825 900 975 1050 1125 1200 1275 1350 1425 So u t h ( - ) / N o r t h ( + ) ( 1 5 0 u s f t / i n ) -450 -375 -300 -225 -150 -75 0 75 150 225 300 375 450 525 West(-)/East(+) (150 usft/in) KU 13-06A tgt2 wp03 KU 13-06A tgt1 wp03 10 3/4" x 13 1/2" 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 250500750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6 2 5 0 6 5 0 0 6 7 5 0 7 0 0 0 7 2 5 0 7 5 0 0 7 7 5 0 8 0 0 0 8 2 5 0 8 5 0 0 8 7 5 0 9 0 0 0 9 2 5 0 9 5 0 0 9 7 5 0 1 0 0 0 010201 K U 1 3 -0 6 A w p 0 3 Start Dir 3º/100' : 500' MD, 500'TVD End Dir : 796.79' MD, 795.6' TVD Start Dir 3º/100' : 5907.79' MD, 5845'TVD End Dir : 6153.42' MD, 6088.2' TVD Total Depth : 10200' MD, 10092.22' TVD CASING DETAILS TVD TVDSS MD Size Name 1680.00 1596.80 1691.98 10-3/4 10 3/4" x 13 1/2" 6000.00 5916.80 6064.36 7-5/8 7 5/8" x 9 7/8" 10092.22 10009.02 10200.00 4-1/2 4 1/2" x 6 3/4" Project: Kenai Gas Field Site: KGF 14-6 Pad Well: Plan: KU 13-06A Wellbore: KU 13-06A Plan: KU 13-06A wp03 WELL DETAILS: Plan: KU 13-06A 65.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2362473.29 271981.59 60° 27' 38.2441 N 151° 15' 47.7070 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: KU 13-06A, True North Vertical (TVD) Reference:RKB As-Built @ 83.20usft (HEC 169) Measured Depth Reference:RKB As-Built @ 83.20usft (HEC 169) Calculation Method:Minimum Curvature (! $ ) # ! $ *! +,- *! . . ! ! /)$ !/ 01 "#$#$% $ & &$ '( )*!$ + ,-./ - 2 ! 0! - 12 3 4 1 5 0- *! & &$ '( )*!$ + ,-./ 1 *! 6 ! 3$ 0 ) % -/ (! 0 3 ) -/ .*7,-8 $ / 1 5.*7,1 52121 / 9! 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" 2 . & . * & - "2 * % & ) '( " - ) + ) ' ( " - ) + ) ' ( " - ) + " - & . . " 2 - % & " + & " " 2 - - + & % + & , . / "2 - % & 0 ) '( " / ) + ) ' ( " / ) + ) ' ( " / ) + ". * & - % & " , % & , + % - & , " * & - - . % & 0 ) '( " / ) + ) ' ( " / ) + ) ' ( " / ) + ". * & , + % % & " , % & / " % % - & * . " % & , . . %% & ) '( " / ) + ) ' ( " / ) + ) ' ( " / ) + . % & + , % 2 / & / % . & " % % 2 - / % & " & . , / %2 / & 0 ) '( " / ) + ) ' ( " / ) + ) ' ( " / ) + ". * & - % & " , % & , + % - & , " * & - - . % & 0 ) '( " / ) + ) ' ( " / ) + ) ' ( " / ) + ". * & , + % % & " , % & / " % % - & * . " % & , . . %% & ) '( " / ) + ) ' ( " / ) + ) ' ( " / ) + "2 / + " & , " 2 & " 2 % % & - " 2 . & + , * & * , " 2 & 0 ) '( " / 3 ) + ) ' ( " / 3 ) + 4' ( , 5) ' ( " / 3 ) + ** & - . * , " & % , + * & " , * , / & * * & % * , *, " & % , 0 ) '( " / 3 ) + ) ' ( " / 3 ) + 4' ( , 5) ' ( " / 3 ) + ** & * , % & + + & . + , * & + * & - / , % & ) '( " / 3 ) + ) ' ( " / 3 ) + 4' ( , 5) ' ( " / 3 ) + ,, & " 2 % & * / & * - " 2 / . & + * + & % / - "2 % & 0 ) '( " ) * ) ' ( " ) * ) ' ( " ) * *. & % " * , & % * % & % . " , & - " & + " "* , & % 0 ) '( " ) * ) ' ( " ) * ) ' ( " ) * , & / % % & * & . , % + & % . " " & - . % % & ) '( " ) * ) ' ( " ) * ) ' ( " ) * .. & / - * % & , . & - * % & + . & , - - *% & 0 ) '( " ) * ) ' ( " ) * " ) ' ( " ) * *, & . + - - & + . * - & % - % & , . " / & / / / - - & + . 0 ) '( " ) * ) ' ( " ) * " ) ' ( " ) * *. & / - * % & * & , % - * + & * " & " " -* % & ) '( " ) * ) ' ( " ) * " ) ' ( " ) * .- & , + & , - & " % . , & - / . & + + + & 0 ) * & ' ( # % % ( # % ) 1 % 1 % + , <= " + - = + / * 0 7 / * 0 <= " + - ! " ( " 3 ! * * ( "3 = . 7 ( " ,' 3 # 3 6 6 * 3 = " + - 3 - + & . + / ,- " * 0 * + ,' ! # $ % & " % & ' ( # % % ( # % % ( # % ) = " + - ; " = 1 , '( " ) * 3 ) ' ( " ) * 3 ) ' ( " ) * 3 - " & . / " 2 % % & & % * " 2 % " & - & - , . "2 % % & ) '( " ) * 3 ) ' ( " ) * 3 ) ' ( " ) * 3 - " & . / " 2 % - " & / . & * " 2 % * & + . & + - + "2 % - " & / . 0 ) '( " ) * 3 ) ' ( " ) * 3 ) ' ( " ) * 3 - - & " / " 2 + * % & " & / " 2 + + , & . - " . & , . * "2 + * % & 0 ) '( / ) " ) ' ( / ) " ) ' ( / ) " "+ " & - " , & " % . & . " * & + * & - + . ", & 0 ) '( / ) " ) ' ( / ) " ) ' ( / ) " "+ " & / . % & " % , & + + & , % % * & " % & ) '( / ) " ) ' ( / ) " ) ' ( / ) " " - & % + * & * & + + * " & , " - % & . * . * & 0 ) ! / * 0 ? / * 0 @ & ? ", & " 2 + . & ' ( " - ) + - - 6 7 8 ! " ! 7 ! 9 "2 + . & + 2 + % & ' ( " - ) + - - 6 7 8 ! " ! 7 ! 9 +2 + % & " 2 & ' ( " - ) + - - 6 7 8 ! " ! 7 ! 9 : ; < = ) & ; > & 0 ; ; $ & 0 ? $ # 4 $ ) 5 & 9 > > & ; ; 9 7 : ; : 0 ; < ; : & 0. 0 0 1. 0 0 2. 0 0 3. 0 0 4. 0 0 Separation Factor 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 Me a s u r e d D e p t h ( 1 0 0 0 u s f t / i n ) KU 1 4 - 0 6 R D KD U 1 KD U 1 P B 1 KB U 1 1 - 0 7 No - G o Z o n e - S t o p D r i ll i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . NO E R R O R S WE L L D E T A I L S : P l a n : K U 1 3 - 0 6 A N A D 1 9 2 7 ( N A D C O N C O N U S ) A l a s k a Z o n e 0 4 65 . 2 0 +N / - S +E / - W N o r t h i n g Ea s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0. 0 0 23 6 2 4 7 3 . 2 9 2 7 1 9 8 1 . 5 9 6 0 ° 2 7 ' 3 8 . 2 4 4 1 N 1 5 1 ° 1 5 ' 4 7 . 7 0 7 0 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : K U 1 3 - 0 6 A , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : R K B A s - B u i l t @ 8 3 . 2 0 u s f t ( H E C 1 6 9 ) Me a s u r e d D e p t h R e f e r e n c e : RK B A s - B u i l t @ 8 3 . 2 0 u s f t ( H E C 1 6 9 ) Ca 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 CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 16 8 0 . 0 0 1 5 9 6 . 8 0 1 6 9 1 . 9 8 1 0 - 3 / 4 1 0 3 / 4 " x 1 3 1 / 2 " 60 0 0 . 0 0 5 9 1 6 . 8 0 6 0 6 4 . 3 6 7 - 5 / 8 7 5 / 8 " x 9 7 / 8 " 10 0 9 2 . 2 2 1 0 0 0 9 . 0 2 1 0 2 0 0 . 0 0 4 - 1 / 2 4 1 / 2 " x 6 3 / 4 " SU R V E Y P R O G R A M Da t e : 2 0 2 3 - 1 1 - 0 6 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m De p t h T o Su r v e y / P l a n To o l 18 . 0 0 1 6 9 2 . 0 0 K U 1 3 - 0 6 A w p 0 3 ( K U 1 3 - 0 6 A ) 3_ M W D + I F R 1 + M S + S a g 16 9 2 . 0 0 6 0 6 5 . 0 0 K U 1 3 - 0 6 A w p 0 3 ( K U 1 3 - 0 6 A ) 3_ M W D + I F R 1 + M S + S a g 60 6 5 . 0 0 1 0 2 0 0 . 0 0 K U 1 3 - 0 6 A w p 0 3 ( K U 1 3 - 0 6 A ) 3_ M W D + I F R 1 + M S + S a g 0. 0 0 40 . 0 0 80 . 0 0 12 0 . 0 0 16 0 . 0 0 20 0 . 0 0 Centre to Centre Separation (80.00 usft/in) 50 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 Me a s u r e d D e p t h ( 1 0 0 0 u s f t / i n ) KB U 2 3 - 0 7 KU 2 1 - 7 P B KU 4 2 - 1 2 KB U 2 2 - 0 6 Y KB U 1 4 - 0 6 Y KB U 1 1 - 0 7 KB U 2 3 X - 6 GL O B A L F I L T E R A P P L I E D : A l l w e l l p a t h s w i t h i n 2 0 0 ' + 1 0 0 / 1 0 0 0 o f r e f e r e n c e 18 . 0 0 T o 1 0 2 0 0 . 5 5 Pr o j e c t : K e n a i G a s F i e l d Si t e : K G F 1 4 - 6 P a d We l l : P l a n : K U 1 3 - 0 6 A We l l b o r e : K U 1 3 - 0 6 A Pl a n : K U 1 3 - 0 6 A w p 0 3 La d d e r / S . F . P l o t s 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. KENAI GAS KU 13-06A TYONEK GAS 1 223-112 1 Davies, Stephen F (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Thursday, December 7, 2023 11:33 AM To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] KU-13-06A (PTD 223-112) - Questions Steve, While50unitsmightlooklikeabigjumponthemudlogIseewhattranslatesto1%gas.ThisissigniĮcantlylowerthan the5%LELformethane.Idon’tbelievewhatisshownonthemudlogswouldconsƟtuteashallowgashazard.Neither oftheoīsetwellshasadvancedlogsoverthisintervalbutwebelieveittobenonreservoirandnotasigniĮcantgas source. IagreemonitoringandmiƟgaƟonsneedtobeinplace.TherighasagasanalyzerthatwillbeoperaƟonalwhile drilling.WeareabletodetectbackgroundgasandconnecƟongas.Maintainingpropermudweightisanimportant miƟgaƟon.9.0ppgspudmudisplannedtostart.ThisissuĸcientoverbalanceforthesurfaceholeandtypicallyMW climbsaswedrillandaddsolids.ThereisamudengineeronlocaƟonthatmonitorsthemudproperƟesand weight.However,Ibelievethemostimportantaspectofthediverterwaiverrequestisknowledgeofthearea.There areasigniĮcantnumberofwellsnearbysothereisalotofsurfaceholedata.Ihaven’tfoundevidenceofashallowgas hazard.Rightorwrong,itisalsoabitcomforƟngtomethatpastdrillingengineersandregulatorshaveagreedinalow shallowgashazardriskandgrantedawaiver. Regards, sean From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Thursday,December7,20238:38AM To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:RE:[EXTERNAL]KUͲ13Ͳ06A(PTD223Ͳ112)ͲQuestions Sean, WithrespecttoHilcorp’srequesteddiverterwaiver,I’venoƟcedthatmudlogsrecordedinnearbywellsKU21Ͳ07Xand KU11Ͳ07Xbothshowmorethan50unitsofshallowgasbelowabout1360’MD(Ͳ1,273’TVDSS)and1255’MD(Ͳ1,170’ TVDSS)with8.9and9.0ppgmud,respecƟvely.Surfacecasingin13Ͳ06Aisplannedfor1,362’MD(Ͳ1,597’TVDSS).What monitoringandmiƟgaƟonsmeasuresdoesHilcorpplantoensurethatanysuchshallowgasencounteredwillnot consƟtuteahazardwhiledrilling13Ͳ06A? ThanksandBeWell, SteveDavies AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 2 ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com> Sent:Monday,December4,20233:23PM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:RE:[EXTERNAL]KUͲ13Ͳ06A(PTD223Ͳ112)ͲQuestions Steve, TheshallowestgaseverproducedatKGFwasinSterlingPool3A6inKBU21Ͳ07XatadepthofͲ3300’TVDSS.Thereare nogasshowsofnotetypicallyabovetheSterlingPool3A6. AƩachedaresecƟonandplanviewsofwellsaroundKU13Ͳ06A.AsyoucanseethereareasigniĮcantnumberof penetraƟonsandsurfacecasingshoesaround1500’TVD.ThethreeclosestcasingshoesarefromwellsKBU22Ͳ06Y, KBU14Ͳ06Y,andKU21Ͳ07X KBU22Ͳ06Y,DiverterWaiverapproved,mudlogaƩached(nodataforsurfaceholesecƟons) KBU14Ͳ06Y,Drilled2007ondiverter,Noshallowgasencountered,mudlogaƩached KU21Ͳ07X,Drilled2006ondiverter,Noshallowgasencountered,mudlogaƩached Thereisseismicbutitdoesn’tshowshallowgasandtherearenogassagsovertheKGFarea.TheacquisiƟonparameters werenotdesignedforgoodimagingabove2000’TVDSS. Rig169iscurrently100’MDawayfromthesurfaceholeTDonSRU222Ͳ33andthatwellhasashortSterlingonly producƟononlysecƟon.WewillmovetoKU13Ͳ06Aonthe10thandspudonthe12th. Regards, sean From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Monday,December4,20237:51AM To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Subject:RE:[EXTERNAL]KUͲ13Ͳ06A(PTD223Ͳ112)ͲQuestions Sean, I’mreviewingthediverterwaiverrequestinHilcorp’sPermittoDrillapplicaƟonforKU13Ͳ06A,andIneedaddiƟonal informaƟon.Hilcorp’sapplicaƟonlistsseveralwellsforwhichdiverterwaivershavepreviouslybeenissuedbyAOGCC; however,onlytwoofthosewellsweredrilledfromthedrillsitewhere13Ͳ06Awillbelocated.ExtracauƟoniswarranted giventhattheshallowsandsinthisareaweredepositedinaŇuvialenvironment,andthatindividualsandscanbethin, isolated,andoflimitedextent. CouldHilcorppleaseprovide: CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 3 x AmapthatdisplaysthelocaƟonanddepthoftheproposedsurfacecasingshoefor13Ͳ06Aandthesurface casingshoesofallwellswithina2000’radiusoftheproposed13Ͳ06Asurfacecasingshoe? x WellͲbyͲwellconĮrmaƟonthatnosigniĮcantshallowgaswasencounteredinanyofthesewellsbyreviewof drillingrecordsandavailablemudlogsforeachofthosewells? Is3DseismicdataavailablefortheKenaiUnit?Ifso,haveanyshallowgasindicators(signalloss,gassags,Ňatspots, etc.)beenidenƟĮedinthatdatawithin2000’oftheproposedsurfacecasingshoefor13Ͳ06A? IsDecember12thsƟllthebestesƟmateforbeginningoperaƟonsforKU13Ͳ06A? I’llbeinatrainingcoursetoday,butwillbemonitoringemailperiodicallyshouldyouhaveanyquesƟons. Thanks, SteveDavies AOGCC From:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com> Sent:Tuesday,November28,202311:56AM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:RE:[EXTERNAL]KUͲ13Ͳ06A(PTD223Ͳ112)ͲQuestions HiSteve, KU13Ͳ06Aisanewwell.The‘A’istodiīerenƟatefromKTU13Ͳ06.AllnewwellsatKGFnowhavetheKUpreĮx.Having two13Ͳ06wellsonthesamepadcouldcreateamishap.Therewassomediscussionifthe“A”goesaŌer13oraŌer06. Ithasbeendonebothways.IntheendwechosewhatmadesenseatKGFandwouldbemostvisibletoatruckdriveror othersupportstaī. Regards, sean From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Tuesday,November28,202311:38AM To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:[EXTERNAL]KUͲ13Ͳ06A(PTD223Ͳ112)ͲQuestions Sean, IwouldliketoconĮrmthattheproposed13Ͳ06AisanewwellandnotaredrillofthewellannotatedasKTU13Ͳ06that isshownontheSurfacePlataccompanyingthePermittoDrillapplicaƟon.Ifthisisanewwell,whatisthesigniĮcanceof the“A”suĸxonthewellnumber? CheersandBeWell, SteveDavies CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 4 AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. 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Pr o j e c t : K e n a i G a s F i e l d Si t e : K G F 1 4 - 6 P a d We l l : P l a n : K U 1 3 - 0 6 A We l l b o r e : K U 1 3 - 0 6 A De s i g n : K U 1 3 - 0 6 A w p 0 3 -6 0 0 -5 0 0 -4 0 0 -3 0 0 -2 0 0 -1 0 0 0 10 0 20 0 30 0 40 0 50 0 60 0 South(-)/North(+) (200 usft/in) -8 0 0 - 7 0 0 - 6 0 0 - 5 0 0 - 4 0 0 - 3 0 0 - 2 0 0 - 1 0 0 0 1 0 0 2 0 0 3 0 0 4 0 0 5 0 0 6 0 0 7 0 0 8 0 0 9 0 0 1 0 0 0 1 1 0 0 We s t ( - ) / E a s t ( + ) ( 2 0 0 u s f t / i n ) 13 3 / 8 " KBU 11-0713 3 / 8 " 9 5 / 8 " KB U 14- 0 6Y 13 3 / 8 " K B U 2 2 - 0 6 10 3 / 4 " KBU 2 2 - 0 6 Y 13 3 / 8 " K B U 2 3 - 0 7 13 3 / 8 " KBU 2 3 X-6 KB U 24-0 6 13 3 / 8 " K B U 2 4 - 0 6 R D K B U 3 1 - 0 7 13 3 / 8 " 10 3 / 4 " K BU 3 2 - 06 K D U 1 13 3 / 8 " 9 5 / 8 " 13 3 / 8 " 10 3 / 4 " KU 1 1-07X 13 3 / 8 " K U 1 3 - 6 13 3 / 8 " 7" KU 1 4 - 0 6 R D 13 3 / 8 " 7" KU 1 4 - 6 13 3 / 8 " 9 5 / 8 " KU 14X-6 10 3 / 4 " 7 5 / 8 " KU 2 1-7 KU 2 1 -7P B 9 5 / 8 " 5 1 / 2 " K U 2 1 - 7 X 16 " KU 42 - 12 H o g s m e a d e w p 0 1 7 5 / 8 " x 9 - 7 / 8 " KU 33-06 B w p 01 13 3 / 8 " KU 1 3 - 0 6 A w p 0 3 Az i m u t h s t o T r u e N o r t h Ma g n e t i c N o r t h : 1 3 . 9 5 ° Ma g n e t i c F i e l d St r e n g t h : 5 5 1 2 1 . 8 n T Di p A n g l e : 7 3 . 3 1 ° Da t e : 1 0 / 3 / 2 0 2 3 Mo d e l : B G G M 2 0 2 1 _ S R V T M 0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000 Tr u e V e r t i c a l D e p t h ( 2 5 0 u s f t / i n ) -750 -625 -500 -375 -250 -125 0 125 250 375 500 625 750 875 1000 Vertical Section at 353.00° (250 usft/in) 20" 13 3/8" KBU 11-07 13 3/8" KBU 14-06Y 13 3/8" KBU 22-06 10 3/4" KBU 22 -0 6 Y 20" 13 3/8" KBU 23-07 KB U 23 X -6 13 3/8" KBU 24-06 20" KBU 31-07KBU 31-07RD 10 3/4" KB U 32-06 13 3/8" K D U 1 13 3/8" 10 3/4" KU 11-07X 13 3/8" K U 1 3-6 KU 14-6 K U 14X-6 10 3/4" KU 21-7 KU 21-7PB 9 5/8" KU 21-7X KU 42-12 9 5/8" Hog sm e a de wp0 1 20" 7 5/8" x 9-7/8" KU 33 -06 B w p 0 1 13 3/8" KU 13-06A wp03 Project: Kenai Gas Field Site: KGF 14-6 Pad Well: Plan: KU 13-06A Wellbore: KU 13-06A Design: KU 13-06A wp03 KBU 22-06Y4/201510,2006,942,212 KU 11-07X4/20179,8003,223,706 KBU 22-06Y KU 11-07X 0100GR01000TLGS10 5 ALHSI0100GK1_GPT_11_30100GK1_1117_TIE 1100RESD1100RESM1100RESS 0.6 0 NPHI1.65 2.65 RHOB60 0 TNPS 0100GR01000TLGS84ALHSI0100GMGRCC010000METH 1100RESD1100RESM1100RESS 0.6 0 NPHI1.65 2.65 RHOB60 0 CORE_POROSITY 11000CORE_PERMEABILITY50 150 PRESS_JUNE_202340 140 TEMP_JUNE_2023 L_BELUGA L_BELUGA LB_1 LB_1 LB_1A LB_1A LB_1B LB_1B LB_1C LB_1C LB_1D LB_1D LB_1E LB_1E LB_1F LB_1F LB_2 LB_2 LB_2A LB_2A LB_2B LB_2B LB_2C LB_2C LB_2D LB_2D LB_2E LB_2E LB_3 LB_3 LB_3A LB_3A LB_3B LB_3B LB_3C LB_3C LB_4 LB_4 LB_4A LB_4A LB_4B LB_4B LB_4C LB_4C LB_4D LB_4D LB_5 LB_5 LB_5A LB_5A LB_5B LB_5B LB_5C LB_5C LB_6 LB_6 LB_6A LB_6A LB_6B LB_6B TYONEK TYONEK TY_72_8 TY_72_8 TY_73_1 TY_73_1 TY_73_2 TY_73_2 UT_1A UT_1A UT_1B UT_1B UT_1B_1 UT_1C UT_1C UT_1D UT_1D TY_75_8 TY_75_8 UT_2A UT_2A UT_2B UT_2B TY_76_7 TY_76_7 UT_3A UT_3A UT_3B UT_3B TY_78_2 TY_78_2 UT_4A UT_4A UT_4B UT_4B UT_4C UT_4C UT_4D UT_4D UT_4D_1 UT_4D_1 UT_4D_2 UT_4D_2 UT_4E UT_4E UT_4F UT_4F TY_84_6A TY_84_6A TY_84_6B TY_84_6B TY_84_6D TY_84_6D TY_84_6E TY_86_2 TY_86_2 TY_86_2A TY_86_2A TY_86_2B TY_86_2B TY_D1 TY_D1 TY_D2 TY_D2 TY_D2_A TY_D2_A TY_D2_B TY_D2_B TY_D3 TY_D3 TY_D3_A TY_D3_A TY_D3_B TY_D3_B TY_D3_C TY_D3_C TY_D3_D TY_D3_D TY_D4_A TY_D4_A TY_D4_B TY_D4_B TY_D4_C TY_D4_C TY_D4_D TY_D4_D TY_D5 TY_D5 TY_D6 -6050(6390) -6100(6443) -6150(6496) -6200(6549) -6250(6602) -6300(6655) -6350(6709) -6400(6762) -6450(6816) -6500(6869) -6550(6923) -6600(6977) -6650(7030) -6700(7083) -6750(7137) -6800(7190) -6850(7244) -6900(7298) -6950(7351) -7000(7405) -7050(7458) -7100(7512) -7150(7565) -7200(7619) -7250(7673) -7300(7726) -7350(7780) -7400(7834) -7450(7887) -7500(7940) -7550(7994) -7600(8047) -7650(8099) -7700(8152) -7750(8205) -7800(8259) -7850(8312) -7900(8366) -7950(8420) -8000(8474) -8050(8528) -8100(8581) -8150(8634) -8200(8687) -8250(8741) -8300(8794) -8350(8848) -8400(8902) -8450(8956) -8500(9010) -8550(9064) -8600(9119) -8650(9173) -8700(9227) -8750(9280) -8800(9334) -8850(9387) -8900(9440) -8950(9493) -9000(9546) -9050(9599) -9100(9652) -9150(9706) -9200(9759) -9250(9812) -9300(9865) -9350(9918) -9400(9971) -9450(10025) -9500(10078) -9550(10132) -9600(10186) -6050(6183) -6100(6233) -6150(6284) -6200(6335) -6250(6386) -6300(6436) -6350(6487) -6400(6537) -6450(6588) -6500(6638) -6550(6689) -6600(6739) -6650(6790) -6700(6840) -6750(6891) -6800(6942) -6850(6992) -6900(7043) -6950(7094) -7000(7144) -7050(7195) -7100(7246) -7150(7296) -7200(7347) -7250(7397) -7300(7448) -7350(7498) -7400(7549) -7450(7600) -7500(7650) -7550(7701) -7600(7751) -7650(7802) -7700(7853) -7750(7904) -7800(7954) -7850(8005) -7900(8055) -7950(8106) -8000(8156) -8050(8207) -8100(8257) -8150(8308) -8200(8359) -8250(8409) -8300(8460) -8350(8510) -8400(8561) -8450(8612) -8500(8662) -8550(8713) -8600(8764) -8650(8814) -8700(8865) -8750(8915) -8800(8966) -8850(9017) -8900(9067) -8950(9118) -9000(9169) -9050(9219) -9100(9270) -9150(9321) -9200(9372) -9250(9422) -9300(9473) -9350(9524) -9400(9575) -9450(9626) -9500(9677) -9550(9728) -9600(9779) DST: 6426-642705/30/2015FSP: 1653 DST: 6464-646505/31/2015FSP: 2480 DST: 6522-652306/01/2015FSP: 2568 DST: 6623-662406/02/2015FSP: 2511 DST: 6806-680706/03/2015FSP: 3024 DST: 6873-687406/04/2015FSP: 1624 DST: 6972-697306/05/2015FSP: 1699 DST: 7235-723606/06/2015FSP: 2472 DST: 7281-728206/07/2015FSP: 2915 DST: 7304-730506/08/2015FSP: 599 DST: 7458-745906/09/2015FSP: 416 DST: 7503-750406/10/2015FSP: 334 DST: 7533-753406/11/2015FSP: 486 DST: 7658-765906/12/2015FSP: 1041DST: 7664-766506/13/2015FSP: 835 DST: 7834-783506/14/2015FSP: 2626 5 in 7 5/8 in DST: 9558-9558IHP: 5805.56FHP: 5806.99ISP: 4578.81BHT: 154.38 DST: 9557-9557IHP: 5805.85FHP: 5804.99ISP: 4650.28BHT: 155.14 DST: 9556-9556IHP: 5805.49FHP: 5805.08ISP: 5232.62BHT: 155.5 DST: 9520-9520IHP: 5783.63FHP: 5784.05ISP: 3470.12FSP: 3470.12BHT: 155.96 DST: 9519-9519IHP: 5783.54FHP: 5783.22ISP: 2386.43BHT: 156.21 DST: 9435-9435IHP: 5732.17FHP: 5732.29ISP: 1534.64FSP: 1534.64BHT: 155.75 DST: 9434-9434IHP: 5731.02FHP: 5731.5ISP: 837.31FSP: 837.31BHT: 156 DST: 9335-9335IHP: 5671.31FHP: 5671.1ISP: 4994.71BHT: 155.05 DST: 9333-9333IHP: 5671.21FHP: 5670.25ISP: 4466.54FSP: 4466.54BHT: 154.9 DST: 9290-9290IHP: 5643.83FHP: 5643.99ISP: 4761.09BHT: 154.34 DST: 9289-9289IHP: 5643.77FHP: 5643.36ISP: 3716.32FSP: 3716.32BHT: 154.27 DST: 9285-9285IHP: 5640.78FHP: 5640.77ISP: 2520.69FSP: 2520.69BHT: 154.32 DST: 9276-9276IHP: 5634.9FHP: 5635.26ISP: 1275.02FSP: 1275.02BHT: 154.4 DST: 9272-9272IHP: 5632.7FHP: 5632.26ISP: 3744.18FSP: 3744.18BHT: 154.23 DST: 9026-9026IHP: 5481.08FHP: 5480.99ISP: 2552.53FSP: 2552.53BHT: 152.46 DST: 9018-9018IHP: 5476.31FHP: 5476.29ISP: 1550.79FSP: 1550.79BHT: 151.77 DST: 9010-9010IHP: 5472.11FHP: 5472.92ISP: 342.17BHT: 149.73 DST: 8991-8991IHP: 5460.23FHP: 5459.97ISP: 3824.57FSP: 3824.57BHT: 150.59 DST: 8990-8990IHP: 5458.21FHP: 5459.33ISP: 344.31BHT: 151.23 DST: 8989-8989IHP: 5458.06FHP: 5458.32ISP: 532.59BHT: 151.54 DST: 8885-8885IHP: 5394.65FHP: 5394.16ISP: 4535.4FSP: 4535.4BHT: 150.5 DST: 8864-8864IHP: 5382.02FHP: 5381.94ISP: 3203.51FSP: 3203.51BHT: 149.92 DST: 7463-7463IHP: 4530.35FHP: 4529.74BHT: 137.82 DST: 7463-7463IHP: 4533.13FHP: 4533.74ISP: 4530.97BHT: 127.86 DST: 7461-7461IHP: 4531.05FHP: 4531.34BHT: 131.09 DST: 7399-7399IHP: 4492.85FHP: 4493.5ISP: 2196.26FSP: 2196.26BHT: 133.2 DST: 7252-7252IHP: 4403.35FHP: 4403.3ISP: 2281.06FSP: 2281.06BHT: 132.44 DST: 7245-7245IHP: 4399.09FHP: 4399.07ISP: 2532.92FSP: 2532.92BHT: 132.04 DST: 7212-7212IHP: 4378.79FHP: 4379.05BHT: 131.76 DST: 7211-7211IHP: 4378.89FHP: 4378.44ISP: 4021.72FSP: 4021.72BHT: 131.29 DST: 7210-7210IHP: 4378.38FHP: 4377.94ISP: 4233.27FSP: 4233.27BHT: 131.18 DST: 7139-7139IHP: 4334.3FHP: 4334.68ISP: 2572.86FSP: 2572.86BHT: 130.61 DST: 7010-7010IHP: 4256.22FHP: 4257.37ISP: 3191.62FSP: 3191.62BHT: 128.06 DST: 6827-6827IHP: 4143.82FHP: 4144.42ISP: 2092.19BHT: 128.02 DST: 6826-6826IHP: 4143.34FHP: 4143.39ISP: 792.05BHT: 127.81 DST: 6759-6759IHP: 4102.51FHP: 4102.75ISP: 1266.14FSP: 1266.14BHT: 127.43 DST: 6717-6717IHP: 4077.05FHP: 4076.79ISP: 2791.32FSP: 2791.32BHT: 126.49 DST: 6611-6611IHP: 4011.81FHP: 4012.17ISP: 977.5FSP: 977.5BHT: 125.75 DST: 6527-6527IHP: 3960.9FHP: 3960.54ISP: 3913.08FSP: 3913.08BHT: 124.81 DST: 6474-6474IHP: 3928.51FHP: 3928.43ISP: 2602.3FSP: 2602.3BHT: 123.98 DST: 6405-6405IHP: 3888.42FHP: 3886.27ISP: 2596.05FSP: 2596.05BHT: 123.17 DST: 6404-6404IHP: 3885.74FHP: 3885.65ISP: 3044.61FSP: 3044.61BHT: 123.07 DST: 6301-6301IHP: 3823.01FHP: 3822.93ISP: 2977.99FSP: 2977.99BHT: 122.47 DST: 6300-6300IHP: 3822.29FHP: 3822.19ISP: 3346.16BHT: 122.2 DST: 6234-6234IHP: 3781.97FHP: 3782.35ISP: 3036.55FSP: 3036.55BHT: 121.71 DST: 6229-6229IHP: 3780.56FHP: 3779.26ISP: 2269.32FSP: 2269.32BHT: 122 DST: 6168-6168IHP: 3741.64FHP: 3742.01ISP: 2458.58FSP: 2458.58BHT: 121.3 HS=1346 AA' 1 Davies, Stephen F (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Monday, December 4, 2023 3:22 PM To:McLellan, Bryan J (OGC) Cc:Davies, Stephen F (OGC) Subject:RE: [EXTERNAL] KU 13-06A PTD application Attachments:KBU 13-06A Offsets - MASP estimate - 12-4-23 - RTE.xlsx; KBU2206Y_KU1107X_XSEC.pdf Bryan, 125bblfortheLinerxOHleadcementiscorrect. AMASPruleofthumbisarbitrarybutusinganalternaƟveMASPatKGFdoeshavelongstandinghistorical acceptance.Lookingintooldwelldataitdoesn’tappearthataKGFwellwouldcompletelyevacuateleavinga0.1psi/Ō gasgradient.Priortothemorerecent2/3gas,1/3waterruleofthumbMarathonwasusinga70%gas,30%mudruleof thumbintheirMASPcalculaƟons.AlternaƟveMASPscalculaƟonatKGFspansdecadesandmulƟpleoperators.Using 0.1psi/ŌwouldbeoverlyconservaƟveandnotaccurate.IhaveprovidedproducƟonandlogdataforthetwonearest Tyonekoīsetwells(KBU22Ͳ06YandKU11Ͳ07X).IntheexcelsheettheperforaƟonsnotesareshownaswellasthe producƟonproĮle.WhenpickinggaszonestherewerequiteafewzonespluggedduetowaterproducƟon.Ibelieve thebiggerareaofinterestwouldbethelogs,especiallytheresisƟvitydata.Thereareclearwaterzonesacrossthe producƟonintervalthatarepermeableandwouldcontributewater. 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 ItisdiĸculttoquanƟfytheamountofwaterpresentsincewetrynottoproduceitbutIdobelievetheremustbesome validitytopastassumpƟons.Perhapsa0.2psi/ŌgradientwouldbemoreaccuratewhencalculaƟngMASPandafair placetostart.OrperhapswesimplyagreethatdrillingMASPwouldbebelow3000psi. The147and169chokesaresimilarbutweshouldbeusinganupdatedschemaƟc.Belowiswhatwassuppliedtothe AOGCCin2020. From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Sent:Tuesday,November28,20233:09PM To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com> 3 Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov> Subject:[EXTERNAL]KU13Ͳ06APTDapplication Sean, AfewcommentsandquesƟonsaboutthePTDapplicaƟon. 1. I’mnotabletomatchyourcementcalcsfortheLinerxOHleadcementonthe4Ͳ1/2”liner.Iget125.2bbls usingthefollowingformula:0.0246bbls/Ō*(10200Ͳ6064Ͳ500’)*1.4=125.2bbls.Couldyoudoublecheckyour calc? 2. Sincethisisagaswell,it’shardtojusƟfyadiīerentgradientforcalculaƟngMPSP.Assuminga2/3heightgas gradientfortheMPSPcalcisarbitraryandthesameargumentcouldbeusedforeverywelldrilled.Wewould needadiīerentjusƟĮcaƟonforusingsomethinglessthan0.1psi/Ōfordrillingthiswell.IcalculateMPSPas 3608psiusingthestandardcalculaƟonofreservoirpressureminus0.1psi/Ō. 3. ThechokemanifolddrawingislabeledasbeingforRig147.IsthereadiīerentchokemanifoldforRig169? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. 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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 Hi l c o r p A l a s k a , L L C We l l N a m e : KE N A I U N I T 1 3 - 0 6 A In i t i a l C l a s s / T y p e DE V / P E N D Ge o A r e a 82 0 Un i t 51 1 2 0 On / O f f S h o r e On Pr o g r a m DE V 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 1 2 0 KE N A I , T Y O N E K G A S - 4 4 8 5 7 0 NA 1 P e r m i t f e e a t t a c h e d Ye s E n t i r e W e l l l i e s w i t h i n F E E A 0 2 8 1 4 2 . 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 N o t a r e d r i l l . T h e " A " s u f f i x a p p e n d e d t o t h e w e l l n u m b e r i s t o d i f f e r e n t i a t e t h i s w e l l 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 f r o m a n o t h e r w e l l o n t h e s a m e p a d t h a t i s a l s o n u m b e r e d 1 3 - 0 6 . 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 KE N A I , T Y O N E K G A S 1 P o o l 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 Ye s 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 NA 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 NA 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 ) NA 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 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 NA D i v e r t e r W a i v e r r e q u e s t e d 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 = 3 6 3 8 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 7 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 NA 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 M e a s u r e s n o t r e q u i r e d . N e a r b y w e l l s d i d n o t e n c o u n t e r H 2 S g a s . 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 O v e r p r e s s u r e ( 1 0 . 2 p p g ) e x p e c t e d i n T y o n e k a t ~ 7 3 2 0 ' M D . S t e r l i n g a n d B e l u g a a r e d e p l e t e d g a s r e s e r v o i r s . 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 L o s t c i r c u l a t i o n m a y b e e n c o u n t e r e d . M i t i g a t i o n f o r r i s k s d i s c u s s e d o n p . 4 1 & 4 2 . 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 SF D Da t e 11 / 2 8 / 2 0 2 3 Ap p r BJ M Da t e 12 / 6 / 2 0 2 3 Ap p r SF D Da t e 11 / 2 8 / 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 / 8 / 2 0 2 3
