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Home My WebLink About223-026From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] Re: Operable - PWI MPF-89A (PTD# 2230260) & ESP MPF-93 (PTD# 2050870) - Return to service post wellhead tension modelling analysis Date:Tuesday, February 17, 2026 8:27:08 AM From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, February 6, 2026 3:56 PM To: Ryan Thompson <ryan.thompson@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: RE: [EXTERNAL] Re: Operable - PWI MPF-89A (PTD# 2230260) & ESP MPF-93 (PTD# 2050870) - Return to service post wellhead tension modelling analysis Thanks Ryan. Your plan is approved. Jack From: Ryan Thompson <ryan.thompson@hilcorp.com> Sent: Friday, February 6, 2026 3:16 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: RE: [EXTERNAL] Re: Operable - PWI MPF-89A (PTD# 2230260) & ESP MPF-93 (PTD# 2050870) - Return to service post wellhead tension modelling analysis Jack, Attached are the modelling results for MPF-89A & MPF-93. Please let me know if you need anything further. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, February 6, 2026 8:28 AM To: Ryan Thompson <ryan.thompson@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cc: Wyatt Rivard <wrivard@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] Re: Operable - PWI MPF-89A (PTD# 2230260) & ESP MPF-93 (PTD# 2050870) - Return to service post wellhead tension modelling analysis Thanks for your note Ryan. Please send over the wellhead tensioning model results for both wells. This info is required for documentation. Thanks Jack From: Ryan Thompson <ryan.thompson@hilcorp.com> Sent: Wednesday, February 4, 2026 3:42 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: Operable - PWI MPF-89A (PTD# 2230260) & ESP MPF-93 (PTD# 2050870) - Return to service post wellhead tension modelling analysis Mr. Lau – Following the PBU L-202 wellhead separation event in March 2025, 5 wells in total between PBU & MPU were found to have similar wellhead configurations as reported to the AOGCC in the Hilcorp response to OTH-25-017 – Request for Information - Modified FMC Starting Head Survey. PWI well MPF-89A and ESP producer MPF-93 were two of the wells identified, proactively shut-in and made not operable pending further analysis. Wellhead tension modelling on MPF-89A and MPF-93 has been completed, with findings presented to AOGCC staff on 2/3/26. These two wells are not at risk of failure similar to the L-202 incident based on current subsidence observation, and are re-classified as Operable to be brought online. We will continue to monitor these wells per the MPU well subsidence program. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 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 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 herebynotified 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. Wellhead Survey Data (From Subsidence Risk Score Sheet)Inputs HighlightedNote: Liner sidetracked in 2023 but casing forces would have remained unchanged20052011 2013 2015 2017 2018 2019 2021 2023 2025Polynomial Coefficients (From graph)Years Since Drilled06 8 10 12 13 14 16 18 20a 0.0011WH Elevation (Observed)NA 12.31 12.25 12.10 b -0.0458WH Elevation (Modeled12.544 12.3088 12.248 12.196 12.1528 12.1345 12.1184 12.0928 12.076 12.068 c 12.544Total Subsidence (Observed)0 0 -0.06 NA NA NA NA -0.21 NA NATotal Subsidence (Modeled)0 -0.2352 -0.296 -0.348 -0.3912 -0.4095 -0.4256 -0.4512 -0.468 -0.476Contact Load w/Subsidence226544 213705.7898 210387.0688 207548.689 205190.7 204191.8 203313 201915.6 200998.6 200561.91Contact Load w/Subsidence + Baseline Thermal & HOT Transient Force110750 97912 94593 91755 89397 88398 87519 86122 85205 84768& HOT Transient Force + Pressure Force at MOASP-25143 -37981 -41300 -44138 -46496-47495 -48374 -49771 -50688 -51125Wellhead Tension Capacity Rating-240000Estimated Wellhead Seperation Force-51125WellCat Outputs (from WC Sheets)Subsidence (In) Contact Load (lbs)Diff from Initial (Total Spring Incremental Spring RateInitial/ Post Cementing Condition0 226544"Baseline" No subsdience but w/ online thermal effects and transient HOT condition0 110750 -11579424" Induced Subsidence Online w/HOT24 39107 -187437 -7809.875 -2985.1336" Induced Subsidence Online w/HOT36 3066 -223478 -6207.722222 -3003.4248" Induced Subsidence Online w/HOT48 -33343 -259887 -5414.3125 -3034.0860" Induced Subsidence Online w/HOT60 -69378 -295922 -4932.033333 -3002.92Average Spring Rate (lb/inch of settlement) -4,549Pressure Forces (From TIOs or use MOASP)Tubing IA OA Total5000 2000 1000OD4.5 7.625 10.75ID 3.953 6.875 9.95Area12.27279564 21.2180219 32.09284103Pressure Forces-61363.9782 -42436.04379 -32092.84103 -135892.863WH Connection (From PBU & MPU Subsidence Risk 1 & 2 Wellheads)Wellhead Tension Capacity Rating-240000Uncertainty (WH Rating, temp profile, point of fixity, etc.) 0%WH Capacity w/Uncertainty-240000Estimated Wellhead Seperation Force-51125Tension Capacity Left-188875 Positive(red) number indicates potential connection failureInches left-41.52299409Years left-148.8642401Note: Positive forces are pulling down on WH placing SC in compression. Negative forces are pushing up on WH placing SC in tension MPF-89AWelly = 0.0011x2-0.0458x + 12.544R² = 111.0011.2011.4011.6011.8012.0012.2012.4012.6012.8013.000 2 4 6 8 101214161820WH Elevation (ft)Years Since DrilledWH Elevation SurveyObservedModeledPoly. (Observed)-300000-250000-200000-150000-100000-5000002005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025Tension Force (lbs)Wellhead Seperation Forces (Modeled)WH Separation ForceWH Rating DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 0 2 9 - 2 3 2 6 8 - 0 1 - 0 0 We l l N a m e / N o . M I L N E P T U N I T F - 8 9 A Co m p l e t i o n S t a t u s 1W I N J Co m p l e t i o n D a t e 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 13 1 6 6 TV D 73 0 9 Cu r r e n t S t a t u s 1W I N J 12 / 2 2 / 2 0 2 5 UI C Ye s We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : PB 1 : M W D / G R / R E S A : M W D / G R / R E S No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 8/ 3 1 / 2 0 2 3 11 0 9 7 1 3 1 6 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 : M P U F - 8 9 A LW D . l a s 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P W D Ru n 0 8 . l a s 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P W D Ru n 0 9 . l a s 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P W D Ru n 1 0 . l a s 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 2 M D F i n a l L o g . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 2 T V D S S F i n a l Lo g . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 5 M D F i n a l L o g . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 5 T V D S S F i n a l Lo g . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 0 8 . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 0 9 . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 1 0 . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A PW D _ R u n _ 1 0 . c g m . m e t a 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 1 1 . c g m 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A PW D _ R u n _ 1 1 . c g m . m e t a 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 2 M D F i n a l L o g . P D F 37 9 6 7 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 1 o f 6 PB 1 MP U F - 8 9 A LW D . l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 0 2 9 - 2 3 2 6 8 - 0 1 - 0 0 We l l N a m e / N o . M I L N E P T U N I T F - 8 9 A Co m p l e t i o n S t a t u s 1W I N J Co m p l e t i o n D a t e 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 13 1 6 6 TV D 73 0 9 Cu r r e n t S t a t u s 1W I N J 12 / 2 2 / 2 0 2 5 UI C Ye s DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 2 T V D S S F i n a l Lo g . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 5 M D F i n a l L o g . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 5 T V D S S F i n a l Lo g . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 0 8 . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 0 9 . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 1 0 . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 1 1 . P D F 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 2 M D F i n a l L o g . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 2 T V D S S F i n a l L o g . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 5 M D F i n a l L o g . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A 5 T V D S S F i n a l L o g . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 0 8 . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 0 9 . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 1 0 . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P W D _ R u n _ 1 1 . t i f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 8 9 A D e f i n i t i v e Su r v e y s . p d f 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 8 9 A D e f i n i t i v e Su r v e y s . x l s x 37 9 6 7 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 11 0 9 7 1 3 0 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 : M P U F - 8 9 A P B 1 LW D . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 1 . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 2 . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 3 . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 4 . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 5 . l a s 37 9 6 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 2 o f 6 MP U F - 8 9 A P B 1 LW D . l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 0 2 9 - 2 3 2 6 8 - 0 1 - 0 0 We l l N a m e / N o . M I L N E P T U N I T F - 8 9 A Co m p l e t i o n S t a t u s 1W I N J Co m p l e t i o n D a t e 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 13 1 6 6 TV D 73 0 9 Cu r r e n t S t a t u s 1W I N J 12 / 2 2 / 2 0 2 5 UI C Ye s DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 6 . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 ### # # # # #### # # # # # El e c t r o n i c D a t a S e t , F i l e n a m e : M P U F - 8 9 A P B 1 PW D R u n 0 7 . l a s 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 M D F i n a l Lo g . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 M D F i n a l Lo g . c g m . m e t a 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 T V D S S F i n a l Lo g . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 T V D S S F i n a l Lo g . c g m . m e t a 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 M D F i n a l Lo g . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 T V D S S F i n a l Lo g . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 T V D S S F i n a l Lo g . c g m . m e t a 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 1 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 2 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 3 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 4 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 5 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 6 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 7 . c g m 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 M D F i n a l Lo g . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 T V D S S F i n a l Lo g . P D F 37 9 6 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 3 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 0 2 9 - 2 3 2 6 8 - 0 1 - 0 0 We l l N a m e / N o . M I L N E P T U N I T F - 8 9 A Co m p l e t i o n S t a t u s 1W I N J Co m p l e t i o n D a t e 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 13 1 6 6 TV D 73 0 9 Cu r r e n t S t a t u s 1W I N J 12 / 2 2 / 2 0 2 5 UI C Ye s DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 M D F i n a l Lo g . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 T V D S S F i n a l Lo g . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 1 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 2 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 3 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 4 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 5 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 6 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 PW D _ R u n _ 0 7 . P D F 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 M D F i n a l L o g . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 2 T V D S S F i n a l Lo g . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 M D F i n a l L o g . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 5 T V D S S F i n a l Lo g . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 1 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 2 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 3 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 4 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 5 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 6 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U F - 8 9 A P B 1 P W D _ R u n _ 0 7 . t i f 37 9 6 8 ED Di g i t a l D a t a DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 8 9 A P B 1 D e f i n i t i v e Su r v e y s . p d f 37 9 6 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 4 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 0 2 9 - 2 3 2 6 8 - 0 1 - 0 0 We l l N a m e / N o . M I L N E P T U N I T F - 8 9 A Co m p l e t i o n S t a t u s 1W I N J Co m p l e t i o n D a t e 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 13 1 6 6 TV D 73 0 9 Cu r r e n t S t a t u s 1W I N J 12 / 2 2 / 2 0 2 5 UI C Ye s DF 8/ 3 1 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 8 9 A P B 1 D e f i n i t i v e Su r v e y s . x l s x 37 9 6 8 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 13 1 5 9 1 0 8 5 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 : M P U _ F - 89 A _ C O I L F L A G _ 1 2 S E P 2 3 . l a s 38 0 4 3 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 13 1 5 9 1 0 8 5 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 : M P U _ F - 89 A _ R B T _ 1 2 S E P 2 3 . l a s 38 0 4 3 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 89 A _ C O I L F L A G _ 1 2 S E P 2 3 . p d f 38 0 4 3 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 89 A _ C O I L F L A G _ 1 2 S E P 2 3 _ i m g . t i f f 38 0 4 3 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 8 9 A _ R B T _ 1 2 S E P 2 3 . d l i s 38 0 4 3 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 8 9 A _ R B T _ 1 2 S E P 2 3 . p d f 38 0 4 3 ED Di g i t a l D a t a DF 10 / 6 / 2 0 2 3 E l e c t r o n i c F i l e : M P U _ F - 89 A _ R B T _ 1 2 S E P 2 3 _ i m g . t i f f 38 0 4 3 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A G r u b s c r e w me a s u r e m e n t . d o c x 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H - F u l l 2 . j p e g 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H - F u l l . j p e g 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 1 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 1 0 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 1 1 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 1 2 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 1 3 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 1 4 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 2 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 3 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 4 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 5 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 6 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 7 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 8 . J P G 40 3 5 8 ED Di g i t a l D a t a DF 5/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : M P F - 8 9 A W H S c r e w s 9 . J P G 40 3 5 8 ED Di g i t a l D a t a Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 5 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 0 2 9 - 2 3 2 6 8 - 0 1 - 0 0 We l l N a m e / N o . M I L N E P T U N I T F - 8 9 A Co m p l e t i o n S t a t u s 1W I N J Co m p l e t i o n D a t e 9/ 1 3 / 2 0 2 3 Pe r m i t t o D r i l l 22 3 0 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 13 1 6 6 TV D 73 0 9 Cu r r e n t S t a t u s 1W I N J 12 / 2 2 / 2 0 2 5 UI C Ye s We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 9/ 1 3 / 2 0 2 3 Re l e a s e D a t e : 6/ 5 / 2 0 2 3 Mo n d a y , D e c e m b e r 2 2 , 2 0 2 5 AO G C C Pa g e 6 o f 6 12 / 2 6 / 2 0 2 5 M. G u h l 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: 10/06/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231006 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 11-17x 50133205850000 209016 9/23/2023 HALLIBURTON RMT3D MPU C-23 50029226430000 196016 9/15/2023 HALLIBURTON RBT MPU F-89A 50029232680100 223026 9/12/2023 HALLIBURTON COILFLAG MPU F-89A 50029232680100 223026 9/12/2023 HALLIBURTON RBT PCU-04 50283201000000 201193 9/14/2023 HALLIBURTON EPX PCU-04 50283201000000 201193 9/14/2023 HALLIBURTON MFC24 Please include current contact information if different from above. T38041 T38042 T38043 T38043 T38044 T38044 10/6/2023 MPU F-89A 50029232680100 223026 9/12/2023 HALLIBURTON COILFLAG MPU F-89A 50029232680100 223026 9/12/2023 HALLIBURTON RBT Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.06 15:41:18 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, October 17, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC F-89A MILNE PT UNIT F-89A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/17/2023 F-89A 50-029-23268-01-00 223-026-0 W SPT 6740 2230260 1685 2068 2079 2069 2066 5 15 15 15 INITAL P Guy Cook 9/19/2023 Initial MIT-IA test after new sidetrack was completed. Testing completed with a Little Red Services pump truck and calibrated gauges. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT F-89A Inspection Date: Tubing OA Packer Depth 142 2795 2737 2726IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC230919143245 BBL Pumped:3.4 BBL Returned:3.4 Tuesday, October 17, 2023 Page 1 of 1          By Grace Christianson at 11:39 am, Sep 22, 2023 Completed 9/13/2023 JSB RBDMS JSB 092823 GDSR-10/9/23 Drilling Manager 09/19/23 Monty M Myers Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.09.19 19:16:42 - 08'00' Taylor Wellman (2143) _____________________________________________________________________________________ Revised By: JNL 9/18/2023 SCHEMATIC Milne Point Unit Well: MPU F-89A Last Completed: 8/9/2023 PTD: 223-026 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 113' 10-3/4" Surface 45.5 / L-80 / BTC 9.950 Surface 6,723’ 7-5/8"Liner X-Over 29.7 / L-80 / BTC Mod 6.875 11,015’11,026’ 5-1/2”Liner X-Over 17 / L-80 IBT-M 4.892 11,026’11,041’ 3-1/2” Liner 9.2 / L-80 / IBT 2.992 11,015’ 11,490’ 2-3/8” Liner 4.7 / L-80 / Hyd 511 1.995 11,183’ 13,166’ TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TC-II 3.958 Surface 11,022’ JEWELRY DETAIL No Depth Item 1 2,992’ 4-1/2” HES X-Nipple w/ MCX .656 Bean Installed on 7/13/2013 2 10,966’ 4-1/2” HES X-Nipple ID= 3.813” 3 10,986’ 7-5/8”x4.5”Baker S-3 Permanent Packer 4 11,010’ 4-1/2” HES XN-Nipple ID= 3.725” No Go 5 11,015’ 7-5/8” x 5.5” Baker Tie Back Sleeve 6 11,022’ WLEG 7 11,026’ 7-5/8” x 5.5” Baker ZXP Liner Packer 8 11,032’ 7-5/8” x 5.5” Baker HMC Liner Hanger 9 11,072’7-5/8” x 5.5” Baker Tie Back Sleeve 10 11,083’7-5/8” x 5.5” Baker ZXP Liner Packer 11 11,090’7-5/8” x 5.5” Baker HMC Liner Hanger 12 11,183’ Liner Top Packer 13 11,183’ Deployment Sleeve PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status A3 12,862’ 12,917’ 7,260’ 7,268’ 55 9/13/2023 Open A2 12,932’ 13,022’ 7,270’ 7,283’ 90 9/13/2023 Open A1 13,036’ 13,058’ 7,286’ 7,290’ 22 9/13/2023 Open A1 13,074’ 13,135’ 7,293’ 7,303’ 61 9/13/2023 Open GENERAL WELL INFO API: 50-029-23268-01-00 Drilled, Cased & Completed by Doyon 14 - 8/20/2005 A Sidetrack CDR2: 8/9/2023 TD =13,166’ (MD) /TD =7,309’(TVD) 20” Orig. KB Elev.: 45.18/ GL Elev.: 11.5’ 7” 3 5, 7 & 86 12 & 13 10.75” Howco ES Cementer @ 2,785 MD 10-3/4” 1 2 Whipstockset @ 11,490’ Top of Window @11,490’ Top of Liner / Cement @11,183’ PBTD =13,150’(MD) / PBTD=7,308’(TVD) 4 2-3/8” PB1: 12134’– 13076’ 5-1/2” 3-1/2” 9, 10 & 11 3-1/2”LTP@ 11,183’ A B TREE & WELLHEAD Tree 4-1/16” 5M FMC Wellhead 11” 5M FMC ZGen 5 w/ 11” x 4.5” FMC Tbg. Hng. w/ 4.5” TC-II & 4” CIW ‘H’ BPV Profile OPEN HOLE / CEMENT DETAIL 42" 260 sx of Arcticset (Approx.) 13-1/2" 658 sx AS Lite, 644 sx Class ‘G’ 9-7/8” 275 sx Class ‘G’ 6-3/4” 79 sx Class ‘G’ 4-3/4” 123 sx Class ‘G’ 3-1/4” 68 sx Class G WELL INCLINATION DETAIL KOP @ 11490’ 90 deg Hole Angle = 11,809’ A B Activity Date Ops Summary 7/22/2023 Spot both rig modules over MPF-89A and set down. Accept rig 00:00. Start MIRU checklists. Use 1500 psi well pressure for LTT on SV, MV good. Install MPD line. Remove tree cap, install BOPs. 7/23/2023 Continue with RU checklists. NU BOPE. Install integral / check valve on B5. Perform top drive inspection. Fluid pack rig. Install injector. Test Gas alarms. All pass. Initial BOPE 250 psi / 4000 psi. 7-1/16" 5K Annular, Blind/ Shear, 2.0" Pipe / Slip, 2-3/8" Pipe/ Slip, 2.0" Pipe / Slip. Test 1: IRV, Packoff, C7, C9, C10, C11 Pass. Test 2: Blind / Shear, R2, BL2, C15 Pass. Test 3: Annular (2.0") TIW#2, B1, B4 Pass. Test 4: Upper 2.0" Pipe / Slip, TIW#1, B2, B3 Pass. Test 5: Lower 2" Pipe / Slip, C5, C6,C8, TV2 Pass. Test 6: Choke A, Choke C Pass. Test 7: 2-3/8" Pipe / Slip, C1, C4, TV1 Pass. Test 8: C2, C3 Pass. Accumulator draw down test. Rig down test joint and test risers. Install drilling risers. Get RKB measurements. Make up drillers side PDL. Test MPD line, Drilling risers, and PDL to 4000 psi. Test tiger tank line to 4000 psi. Good test. Install floats in BHI cable head and test, good. M/U BHA #1, nozzle w/ DPS. M/U injector to well. Circ 10 bbls MeOH to end of CT. Wait on load of 9.8# mud to arrive from Deadhorse. Mud arrives, start offloading. Start RIH. 1500 psi on well. Log CCL from 10900' to 11500'. PU 40k start swap well to 9.6# mud. POOH when mud reaches nozzle. 7/24/2023 Finish Pooh. Tag up. Close swabs. Put well on MPD. Lay down MWD w/ nozzle. Make up BHA#2 Whipstock in PDL lubricator. Pressure deploy. Rih w/ BHA#2 Whipstock. Rate: 0.35 bpm in, 0.65 bpm out. Mud Weight: 9.66 ppg in, 9.69 ppg out Window ECD: 12.3 ppg. Log down for tie-in from 11150' to 11306.19 MD (formation) with -27.5 correction. Log CCL from 11000' to 11250'. Run to set depth while correlating CCL. Rih to set depth of 11501.2' Bottom (TOWS @ 11490' ). Close EDC. Orientated @ 0 ROHS orientation. Pressure up. Taking weight. 4200 psi shear. Stacked 4.5K down. Good set. Pooh. Rate: 1.41 bpm in, 1.03 bpm out. Circ pressure: 2850psi. Mud Weight: 9.66 ppg in, 9.69 ppg out Window ECD: 12.3 ppg. Tag up and space out. Trap 900 psi. Pressure un-deploy BHA#2 Whipstock setting tool. Make up BHA#3 with NSAK 0.4 AKO motor, Reamer (2.79" Go / 2.80" Tight Go) Window mill (2.81" Go / 2.80" Nogo). Pressure deploy. Break circulation. Choke B stopped holding. Closed C13, Isolate flow. Blow down choke line. Inspect choke. RIH BHA #3 - Window Mill keep 12.25# ECD at window. Tie-in depth from 11220' correct -25.5'. Close EDC, dry tag whipstock 11491' up wt 35k. Mill 2.8" window from 11490.9'. 1.8 / 1.75 bpm In / Out. 9.66 / 9.72 bpm. Window ECD 12.24 ppg w/ 634 psi WHP. Mill 2.8" window from 11494.4'. 1.78 / 1.78 bpm In / Out. 9.65 / 9.69 bpm. Window ECD 12.20 ppg w/ 610 psi WHP ~2 bbl/hr losses. Start adding black product to mud. 7/25/2023 Mill 2.8" window from 11498' Bottom of window. 1.78 / 1.78 bpm In / Out. 9.65 / 9.69 bpm. Window ECD 12.20 ppg w/ 610 psi WHP ~2 bbl/hr losses. Start rathole at 11500' MD to 11510'. Pump sweeps. Ream Window. Perform 3 Reaming passes at 1 fpm. All reaming passes down at 0 ROHS (As milled). Ream up at: As milled, +15, -15. Rate: 1.73 bpm in, 1.72 bpm out. PUW: 37K, SOW: 15K. Shut down pumps, dry drift window at 0 ROHS (As milled) Clean. Final sample 50% formation. Pooh. Mud Weight: 9.67 ppg in, 9.70 ppg out. Rate: 2.08 bpm in, 1.59 bpm out Window ECD 12.3 ppg. Tag up and space out. Pressure un-deploy BHA#3 Window Milling. Stand off to side. Install nozzle. Jet stack while swapping BHA. Pressure deploy BHA#4 Build BHA. RIH with 3.25 drilling BHA #4 Build. Rate: 0.40 bpm in, 0.71 bpm out. Circ pressure: 1779 psi. Mud Weight: 9.65 ppg in, 9.72 ppg out Window ECD:12.33 ppg. Log down for tie-in from 11,200' MD (formation) with -27' correction. Close EDC. Pass window no issues go to min rate. Tag 11510' PU to breakover + 2' go to 1.8 bpm. Ease down and start drilling 3.25" build. PU and swap to shore power, no issues. Drill 3.25" build from 11530'. 1.84 / 1.83 bpm In / Out. Mud Wt 9.65 / 9.70#. Window ECD 12.24# w/ 560 psi WHP. ROP 25 - 50 fph w/ 1.5 - 2.5k DWOB. BHA wiper at 11600' clean up/down. 11660' 5 bbls lo/hi vis. 100' wiper from 11695' clean up/down. Drill 3.25" build from 11695'. 1.78 / 1.78 bpm In / Out. Mud Wt 9.65 / 9.71#. Window ECD 12.29# w/ 560 psi WHP. ROP 40 - 70 fph w/ 1.5 - 2.5k DWOB. 150' wiper from 11850' clean up/down. Drill 3.25" build from 11850'. 1.78 / 1.72 bpm In / Out. Mud Wt 9.66 / 9.76#. Window ECD 12.29# w/ 520 psi WHP. ROP 60 - 70 fph w/ 1.5k DWOB. 11915' 5 bbls lo/hi vis. Drill to 11920' TD of build section. Wiper to window, clean. Jog below window and pull through. Jog above window, open EDC. POOH pump 2.3 bpm keep 12.2# at window. 7/26/2023 Pooh. Mud Weight: 9.69 ppg in, 9.77 ppg out. Rate: 2.28 bpm in, 1.84 bpm out. Window ECD: 12.3 ppg, Circ pressure: 4667 psi. Pressure un-deploy BHA#3. Bit graded: 1-1-BU-S-X-I-NO-BHA. Make up BHA#4 lateral. Pressure Deploy. Shallow test agitator. Good test. RIH with 3.25 drilling BHA #5. Rate: 0.42 bpm in, 0.87 bpm out. Circ pressure: 1835 psi. Mud Weight: 9.73 ppg in, 9.79 ppg out. Log down for tie-in from 11200' MD (formation) with -14 correction. Close EDC, Run through window without issue. Run to bottom. Drill 3.25 lateral from 11920 MD to 12258'. Free spin: 4933 psi, 1.73 bpm (1410 psi diff). Rate: 1.78 bpm in, 1.73 bpm out. Circ pressure: 4933 5075 psi. Mud weight: 9.72 ppg in, 9.81 ppg out, Window ECD: 12.3 ppg. ROP: 20- 110 fph, WOB: 1.4 3.0 KLBS. DLS climbing. Drill 3.25 lateral from 12258' to 12370'. Free spin: 4713 psi, 1.73 bpm (1100 psi diff). Rate: 1.81 bpm in, 1.74 bpm out. Circ pressure: 4713 to 4806 psi. Mud weight: 9.76 ppg in, 9.83 ppg out, Window ECD: 12.3 ppg. ROP: 90 fph, WOB: 1.4 to 1.80 KLBS. POOH from 12370' to drop motor angle. Rate: 1.82 bpm in, 1.68 bpm out. Circ pressure: 4559 psi. Mud weight: 9.77 ppg in, 9.84 ppg out, Window ECD: 12.2ppg. OOH - Pressure undeploy BHA #5. Bit graded 1-1. M/U and pressure deploy BHA #6 w/.7 AKO motor and re-run HCC 3.25" bi-center bit. RIH w/BHA #6. Rate: .42 bpm in, .84 bpm out. Circ pressure: 1825 psi. Mud weight: 9.78 ppg in, 9.85 ppg out, Window ECD: 12.25 ppg. IA = 858 psi, OA = 46 psi. Log tie in from 11190' @ 5 fpm. Correct -10'. RIH through window clean. Drill 3.25 lateral from 12370' to 12,480'. Free spin: 4613 psi, 1.73 bpm (1100 psi diff). Rate: 1.81 bpm in, 1.75 bpm out. Circ pressure: 4683 to 4806 psi. Mud weight: 9.73 ppg in, 9.79 ppg out, Window ECD: 12.3 ppg. ROP: 60 fph, WOB: 1.4 to 2.3 KLBS. 7/27/2023 Drill 3.25 lateral from 12,485' to 12553' MD. Free spin: 4613 psi, 1.73 bpm (1100 psi diff). Rate: 1.83 bpm in, 1.81 bpm out. Circ pressure: 4683 to 4782 psi. Mud weight: 9.78 ppg in, 9.84 ppg out, Window ECD: 12.27 ppg. ROP: 60 fph, WOB: 1.4 to 2.3 KLBS. Geology anticipating fault anytime. Perform long wiper. Rate: 1.82 bpm in, 1.71 bpm out. Circ pressure: 4614 psi. Mud weight: 9.73 ppg in, 9.83 ppg out, Window ECD: 12.26 ppg. Pump 5 bbls Lovis / 5 bbls HiVis sweeps. Open EDC above window. Jet up to liner top. Log tie in with +3' correction. Drill 3.25 lateral from 12553' MD. Free spin: 4490 psi, 1.80 bpm (864 psi diff). Rate: 1.83 bpm in, 1.81 bpm out. Circ pressure: 4516 to 4782 psi. Mud weight: 9.79 ppg in, 9.84 ppg out, Window ECD: 12.29 ppg. ROP: 20-30 fph, WOB: 1.4 to 2.3 KLBS. Difficulty getting back to bottom. Drill 3.25 lateral from 12665' MD to 12700' . Free spin: 4454 psi, 1.78 bpm (820 psi diff). Rate: 1.79 bpm in, 1.77 bpm out. Circ pressure: 4454 to 4782 psi. Mud weight: 9.78 ppg in, 9.84 ppg out, Window ECD: 12.29 ppg. ROP: 20-30 fph, WOB: 1.4 to 2.3 KLBS. 150' BHA wiper. Drill 3.25 lateral from 12,700' to 12,775'. Free spin: 4456 psi, 1.82 bpm (812 psi diff). Rate: 1.73 bpm in, 1.71 bpm out. Circ pressure: 4456 to 4782 psi. Mud weight: 9.77 ppg in, 9.79 ppg out, Window ECD: 12.32 ppg. ROP: 60 fph, WOB: 1.4 to 2.3 KLBS. Field wide power outage. Swap to rig generators. Close choke and secure well. Monitor shaker for flow. Move coil after rig generators online. Some packing off and overpulls. Pump sweeps and clean hole. Wiper trip to window from 12,775'. Rate: 1.74 bpm in, 1.68 bpm out. Circ pressure: 4447 psi. Mud weight: 9.78 ppg in, 9.86 ppg out, Window ECD: 12.34 ppg. IA = 1243 psi, OA = 184 psi. Log tie in and correct +3'. RIH to resume drilling. Drill 3.25 lateral from 12,775' to 12,969'. Free spin: 4443 psi, 1.79 bpm (812 psi diff). Rate: 1.79 bpm in, 1.68 bpm out. Circ pressure: 4456 to 4782 psi. Mud weight: 9.75 ppg in, 9.86 ppg out, Window ECD: 12.31 ppg. ROP: 40 fph, WOB: 1.4 to 2.3 KLBS. 50-029-23268-01-00API #: Well Name: Field: County/State: MP F-89A Milne Point Hilcorp Energy Company Composite Report , Alaska 7/25/2023Spud Date: 7/28/2023 Drill 3.25 lateral from 12,974' to 13060'. Free spin: 4443 psi, 1.79 bpm (812 psi diff). Rate: 1.79 bpm in, 1.68 bpm out. Circ pressure: 4456 to 4782 psi. Mud weight: 9.77 ppg in, 9.76 ppg out, Window ECD: 12.31 ppg. ROP: 15-45 fph, WOB: 1.4 to 2.3 KLBS. Drill 3.25 lateral from 13060' to 13,076'. Free spin: 4436 psi, 1.76 bpm (739 psi diff). Rate: 1.76 bpm in, 1.72 bpm out. Circ pressure: 4436 to 4782 psi. Mud weight: 9.74 ppg in, 9.85 ppg out, Window ECD: 12.33 ppg. ROP: 15-45 fph, WOB: 1.4 to 2.3 KLBS. Wiper trip to window after weight transfer issues and 100% losses. Motor stall @ 12,665'. RIH and free BHA. POOH at 10 - 15 fpm. Pulling heavy with 4 - 6k higher. POOH for new agitator and inspect bit. Pull through window clean. Open EDC and POOH. Rate: 1.80 bpm in, 1.50 bpm out. Circ pressure: 3783 psi. Mud weight: 9.64 ppg in, 9.71 ppg out, Window ECD: 12.26 ppg. IA = 1169 psi, OA = 199 psi. Close EDC and test agitator @ 500'. Not working. OOH - PSJM with crew. Pressure undeploy BHA #6. ERT Max agitator had broken internal components. Bit graded 1-2 with a chipped tooth. Motor out of spec on bearing gap. M/U BHA #7 w/new ERT Max agitator, new motor and 3.25" bi-center bit. Pressure deploy BHA #7. RIH w/BHA #7 - Lateral BHA. Rate: 1.04 bpm in, 1.23 bpm out. Circ pressure: 2050 psi. Mud weight: 9.66 ppg in, 9.74 ppg out, Window ECD: 12.25 ppg. IA = 773 psi, OA = 31 psi. Close EDC and perform shallow hole test on ERT-Max agitator. Good Test. Log tie in from 11170' @ 5 fpm. Correct -26'. Close EDC. RIH through window clean. 7/29/2023 Rih to bottom. Bobble at 11650' Toolface issue. Continue to run in hole. Bobbled by 12484' Fault area. Tag at 12684' Roll by. Trouble spot. Roll through at min. Lost momentum at 13012' md. Bring to rate. Rih and immediately start packing off. Bring rate and come off bottom. Get ECD. Attempt going by multiple times. Immediately packing off. Pooh with difficulty up to 12500' Drop rate. Once tools moved smoothly. Bring rate up. Smooth trip to window. No issue. Open EDC. Pooh. Rate: 2.04 bpm in, 1.59 bpm out. Circ pressure: 4080 psi. Mud Weight: 9.63 ppg in, 9.72 ppg out. Preload PDL. Pressure un-deploy BHA#7. Pressure deploy BHA#8. RIH with 2.74 OH sidetrack BHA #8. Rate: 0.47 bpm in, 0.67bpm out. Circ pressure: 1736 psi. Mud Weight: 9.63 ppg in, 9.72 ppg out Window ECD: 12.25 ppg. Log down for tie-in from 11170' to 11237' MD (formation) with -27 correction. Rih to 12180' MD Roll to 180. Come up to rate to shuck brass protection cap. Min rate up to sidetrack depth. Drill 2.74 OH sidetrack from 12140 MD. Rate: 1.79 bpm in, 0.69 bpm out. Circ pressure: 3881 psi. Mud weight: 9.64 ppg in, 9.72 ppg out, Window ECD: 12.30 ppg. Back ream 1 fpm from 12140' MD to 12080' MD. Continue OH sidetrack operations. Rate: 1.9 bpm in, 0.9 bpm out. Circ pressure: 3882 psi. Mud weight: 9.67 ppg in, 9.73 ppg out, Window ECD: 12.27 ppg. Drill at 12,140' for 30 minutes while stationary. Time drill1 fpm for first 1'. Continue time drilling from 12,144' to 12,170'. Rate: 1.87 bpm in, 1.3 bpm out. Circ pressure: 4076 psi. Mud weight: 9.67 ppg in, 9.76 ppg out, Window ECD: 12.27 ppg. Pump 10 bbl HiVis after losses increased to 65 bph. Increase WOB to 1.5 - 2k. TD OH sidetrack at 12,170' and confirm departure. Backream from 12,170' @ 5 fpm as drilled. Backream 45 deg left and right of low side @ 5 fpm. All passes clean from initial KO to TD. POOH from 12,170' for lateral BHA. Pull through window clean. Open EDC. Rate: 1.87 bpm in, 1.3 bpm out. Circ pressure: 4076 psi. Mud weight: 9.71 ppg in, 9.76 ppg out, Window ECD: 12.21 ppg. 7/30/2023 Pooh. Mud Weight: 9.71 ppg in, 9.77 ppg out. Rate: 1.79 bpm in, 1.51 bpm out. Window ECD: 12.21 ppg, Circ pressure: 3811 psi. Tag up and space out. Pressure un-deploy BHA#8. Perform weekly BOPE function test. Pressure Deploy BHA#9. Shallow test agitator at 500' good test. RIH with 3.25 drilling BHA #9. Rate: 0.54 bpm in, 0.66 bpm out. Circ pressure: 1835 psi. Mud Weight: 9.72 ppg in, 9.82 ppg out. Log down for tie-in from 11215' to 11237.45 MD (formation) with - 22.5 correction. Rih above window. Close EDC. MAD pass from 12110' to TD. Drill 3.25" lateral from 12170 MD to 12421' MD. Free spin: 4837 psi, 1.80 bpm. Rate: 1.80 bpm in, 1.00 bpm out. Circ pressure: 4837 to 4902 psi. Mud weight: 9.72 ppg in, 9.79 ppg out, Window ECD: 12.24 ppg. ROP: 68 fph, WOB: 2.1 to 3.0 KLBS. Pump Multiple HiVis sweeps to regain circulation. Drill 3.25" lateral from 12421' MD to 12623' MD. Free spin: 4837 psi, 1.80 bpm. Rate: 1.80 bpm in, 1.00 bpm out. Circ pressure: 4837 to 5012 psi. Mud weight: 9.73 ppg in, 9.83 ppg out, Window ECD: 12.26ppg. ROP: 68 fph, WOB: 1.8 KLBS. Drill 3.25" lateral from 12623' MD to 12650' MD. Free spin: 4837 psi, 1.80 bpm. Rate: 1.72 bpm in, 1.71 bpm out. Circ pressure: 4837 to 5072 psi. Mud weight: 9.80 ppg in, 9.92 ppg out, Window ECD: 12.28 ppg. ROP: 68 fph, WOB: 2.4 KLBS. Wiper trip to window from 12,650' MD. Rate: 1.59 bpm in, 1.32 bpm out. Circ pressure: 4837 to 5072 psi. Mud weight: 9.83 ppg in, 9.89 ppg out, Window ECD: 12.24 ppg. Jog below window. Pull through clean. Open EDC and jet window. Log tie in from 11180' @ 5 fpm. Correct +3'. Close EDC and RIH. Drill 3.25" lateral from 12650' MD to 12,833' MD. Free spin: 4837 psi, 1.80 bpm. Rate: 1.83 bpm in, 1.74 bpm out. Circ pressure: 4837 to 5221 psi. Mud weight: 9.81 ppg in, 9.89 ppg out, Window ECD: 12.26 ppg. ROP: 54 fph, WOB: 2.2 KLBS. 7/31/2023 Drill 3.25" lateral from 12,833' MD to13022' MD. Free spin: 4837 psi, 1.80 bpm. Rate: 1.83 bpm in, 1.74 bpm out. Circ pressure: 4837 to 5221 psi. Mud weight: 9.76 ppg in, 9.84 ppg out, Window ECD: 12.28 ppg. ROP: 54 fph, WOB: 2.2 KLBS. Pickups getting sticky. Pull long wiper early. Long wiper. Rate: 1.77 bpm in, 1.73 bpm out. Mud weight: 9.76 ppg in, 9.85 ppg out, Window ECD: 12.21 ppg. Pull tight at 12817' MD. Come down on pumps. Attempt to move downhole. No Luck. Bring pumps on. Establish movement. Move BHA down. Puh at 4-5 fpm. Move through area. Motorwork observed at 12565' MD. Back off pumps and rih hole. Pull back up through. This spot appeared to be cuttings. Pump sweeps around. Perform job below window. Open EDC. Jet up to tie in depth with +8' correction. Close EDC. Run through window. PU weight prior to going by shale. Drill 3.25" lateral from 13022' MD - 13060' MD. Free spin: 5107 psi, 1.80 bpm (1250# diff). Rate: 1.80 bpm in, 1.76 bpm out. Circ pressure: 5107 to 5247 psi. Mud weight: 9.77 ppg in, 9.84 ppg out, Window ECD: 12.27 ppg. ROP: 54 fph, WOB: 1.5 KLBS. Started losing returns. Pickups clean. Drill 3.25" lateral from 13060' MD with losses. Rate: 1.80 bpm in, 0.00 bpm out. Circ pressure: 5482 psi. Mud weight: 9.77 ppg in, 9.84 ppg out, Window ECD: 12.1. ppg. ROP: 54 fph, WOB: 1.5 KLBS. Pump multiple HiVis pills in attempt to heal losses. Drill 3.25" lateral from 13,117' MD to 13,165' MD with 100% losses. Rate: 1.84 bpm in, 0.00 bpm out. Circ pressure: 5190 psi. Mud weight: 9.81 ppg in, 9.73 ppg out, Window ECD: 12.22 ppg. ROP: 54 fph, WOB: 1.5 KLBS. TD called at 13,165'. Wiper trip to window. Pump additional 10 bbl HiVis pill off bottom. Returns coming back to 80%. Rate: 1.81 bpm in, 1.57 bpm out. Circ pressure: 5190 psi. Mud weight: 9.81 ppg in, 9.83 ppg out, Window ECD: 12.3 ppg. Log tie in from 11180' @ 5 fpm. Correct +9'. Close EDC and RIH through window. Minor set downs from 12,820' - 12,859'. Tag and confirm TD at 13,166'. Wiper trip to swab - pump additional 10 bbl HiVis sweep off bottom. Pull through window clean. Open EDC and continue OOH. Rate: 1.80 bpm in, 1.49 bpm out. Circ pressure: 3790 psi. Mud weight: 9.76 ppg in, 9.84 ppg out, Window ECD: 12.23 ppg. Tag surface, correct depth. RIH to lay in liner running pill. Rate: 1.03 bpm in, 1.12 bpm out. Circ pressure: 2490 psi. Mud weight: 9.76 ppg in, 9.83 ppg out, Window ECD: 12.15 ppg. Log tie in from 11,180' @ 5 fpm. Correct -26'. RIH to window depth. Park coil and shut pumps down with a closed choke. BHP = 4460 psi. Close EDC and RIH to TD. 8/1/2023 Work through trouble area's from 12850' to 13058'. Pump 30 bbls of 9.9 ppg HiVis mud. Min rate to window. Circulate another HiVis above perfs. To attempt to Lockup while weighting up KWF. Discuss options with drilling engineer. Circulate 12.4 KWF around. 2.0 bpm / 1.1 bpm out. Circulate above EDC. . Run in to 11200' MD. Slow rate. Losses as high as 60 bph. Circulate to surface. Bring back inside. Still losing 30 bph. Lay in 30 bbls 12.4 HiVis. POOH. OOH - Flow check well and confirm no flow. L/D lateral BHA. Bit 1-1. Clear and clean rig floor. M/U liner running equipment. M/U NSAK ORCA liner system. M/U and RIH with 13 jts 2- 3/8" 4.7#, L-80 HYD511 Solid Liner. M/U and RIH with 50 jts 2-3/8" 4.7#, L-80 HYD511 Solid Liner w/SOC. Hole fill ~ 20 bph. Fill liner every 10 jts. Continue M/U and RIH with 2-3/8" liner. Conduct kick while tripping drill with crew. Hold AAR. M/U deployment sleeve and hydraulic G Spear to liner. M/U BHI tools to liner. RIH. RIH with 2-3/8" liner with NSAK ORCA cement valve. In Rate .56 bpm, Out Rate .17 bpm. In Mud WT = 12.37 ppg, Out Mud WT = 12.44 ppg. Begin swapping coil and well back to 9.8 mud. Correct to EOP flag at window -36'. 8/2/2023 Continue displacing well back to 9.8 mud system at window. 9.8 ppg back to surface. Close EDC. RIH through window clean pumping min rate. Begin working coil from 12,524' at different pump rates and coil speeds. Pump 20 bbl HiVis pill @ 12,544'. In Rate = 1.69 bpm, Out Rate = 1.1 bpm. In Mud WT = 9.93 ppg, Out Mud WT = 9.99 ppg. Made 28' from 12555' to 12583', continue working liner down. PU and liner is moving RIH, set down at 12586', PU and not able to move, online with pumps. Not making any progress, pump another Hi-Vis Pill down. No change pull to Max WT several times, no movement. Line up to pump 10 bbls of LVT down with 5 bbls spacers. At 35 bbls, shut down pump and sting into Deployment Sleeve. PU and confirmed we are latched on and hold 70k up WT. Pulled free, circ out LVT and pills while PUH slow to 12050'. High loss rate while stung into the liner pumping LVT & Pills OOH. At 12050', pump off of liner then open the EDC to pump LVT OOH. Dry drift @ 10 fpm from 12,100'. 3-4k WT bobble @ 12,138'. Tag @ 12,746'. 45k PUW. Pick up clean. Attempt to work liner down and pulled out of deployment sleeve. Attempt to reengage G spear. Pump 2 bpm and RIH and engaged again. Continue working liner from 12,767'. Work liner to 13,151' and unable to make any further progress. Pump off liner with 36k PUW. POOH for CCL log. Log CCL from 10,850' to TOL @ 16 fpm. Correct depth +22'. Liner on bottom. Log GR from 10,800' @ 5 fpm to confirm on depth. No correction needed. Tag TOL @ 11,183' on depth. Circulate 12.4 ppg KWF to surface from 11,150'. In Rate = 1.14 bpm, Out Rate = .93 bpm. In Mud WT = 12.28, Out Mud WT = 9.93. Circ pressure = 2510 psi. KWF back to surface - flow check well and confirm no flow. POOH from 11,150' keeping hole full. In Rate = 1.17 bpm, Out Rate = .7 bpm. In Mud WT = 12.28, Out Mud WT = 12.41. 8/3/2023 POOH at 6500' for the CMT BHA. OOH, flow check well. Good No Flow, well took 2 bbls in 10 min for ~12 bph loss rate. Remove injector and LD the LRT BHA. BHA OOH. Crush ring for the bottom seal on the seal assembly is missing. Discuss running a magnet on 1 jt of the 1" CSH to recover the steel crush ring. Got a 1.70" Magnet from a Slickline Unit in MPU but the Crush Ring does stick to the magnet but would strip off very easily. Call out for a 2.625" Venturi Junk Basket from BOT. Looks like we have compressed some air in the well during hole fills, getting a little KWF over the top of the lubricator. Close in swabs and monitor well through MPD Line, MU injector to well. 15 min 0psi. 30 min 0psi, open swabs fill hole well, well took 6 bbls consistent at 10-12 bph loss rate. Flow check after hole fill is good, remove the injector and MU the Venturi Junk Basket BHA. RIH with Venturi BHA. Log tie in from 10,800'. Correct -26'. Continue circulating across top with ~ 15 bph loss rate. Reciprocate coil from 10,800' while waiting for additional KWF. Worley Vac truck hauling KWF fluid for rig has mechanical. Transfer KWF to another truck. Continue standby for fluid. Truck with additional KWF on location. Offload into rig pits. Venturi at 1.7 bpm from 10,940' to liner top @ 11,181'. Reciprocate twice on TOL. In Rate = 1.76 bpm, Out Rate = 1.16 bpm. In Mud WT = 12.27, Out Mud WT = 12.42. POOH from 11,170' pumping across the top to keep the hole full. ~ 12 bph loss rate. OOH - PJSM with crew and flow check well. Confirm no flow. Establish 12 bph loss rate. Inspect last 50' of coil. L/D and inspect venturi BHA. No seal recovered. Stand back injector prep to cut coil and pump eline slack out. Call out fluids for cement job. 8/4/2023 Remove BHI UQC and Boot Eline to pump slack out. PU 1 jt of 2-1/16" CSH, stab injector on and pump slack out. Remove injector, cut & boot eline, pumped 172' of 260' out. We are PU 6 jts of 2-1/16" (176') that will cover the 88' of eline that was not pumped out. MU nozzle, stab on well, load 5/8" drift ball into the reel and pump. Recovered 5/8" Ball. RU to PT the CTC and Swivel to 5k. Good PT. MU CMT Stinger BHA with 6jts of 2-1/16" CSH. BHA MU, RIH circulating across the top. 11,100' RIH WT = 19k, PU WT = 39k. Call out HES CMT Crew. Get rate & pressures for 0.5, 1.0, 1.5 and 2.0 bpm. RIH to sting into the Deployment Sleeve. Start taking WT at 11182', set set down 13k to 11186.0', paint white flag. Online at 0.5 bpm to shear Seal Assembly Burst Disk, sheared at 2900psi continue pumping and sheared the lower Burst Disk at 3200psi. Shut down pump and PU 10' and paint Yellow flag. Line up to the CMT MM to displace the well to 10.5ppg KCl. Pump 5 bbl Hi-Vis Pill spacer followed by 10.5ppg KCl. Online at 1.0 bpm, loss rate at 0.3 bpm, increase rate to 1.5 bpm, loss rate at 0.4 bpm. Hi-Vis Pill out, RIH to sting into the liner and displace fluid from liner and OH with 10.5 KCl. On depth at flag & surface WT down, online with pump. 1.5 bpm In, 0.70 bpm Out, pump 15 bbls to displace the liner and OH then PU to finish displacement above the TOL. Well swapped to 10.5 KCl. In Rate = 2.05 bpm at 4209 psi circ pressure and 471 psi WHP. HES on location MIRU, Waiting on Exhaust Pill for contam, truck had a mechanical. R/U HES cementers and PT lines to 4700 psi. Contam truck on location. Offload to rig pits. Continue circulating at TOL. In Rate = .97 bpm, Out Rate = .88 bpm. In Mud WT = 10.55, Out Mud WT = 10.64. Sting into deployment sleeve with 15k wt. White flag at reel indicates on depth. Pump .5 bpm, 1 bpm and 1.5 bpm and record circulating pressures. .5 bpm = 1052 psi and 550 WHP. 1.0 bpm = 2100 psi and 532 WHP. 1.25 bpm = 2942 psi and 500 WHP. 1.5 bpm = 3922 psi and 475 WHP. PJSM with HES and Nabors crew. Continue circulating at 1 bpm. 529 psi WHP. Mix 20 bbls 15.3 ppg class G cement. Cement at wt at 23:30. Pump 15 bbls of 15.3 ppg class G cement into coil. Shut down HES cementers and trap 550 psi on well. Line up with rig pumps to displace cement with GeoVis contam pill. Pump cement around liner and have 1:1 returns entire job. Cement in place at 01:00. Full returns during cement job. Un-sting from TOL pumping .5 bpm of GeoVis. Open pump bleeders and confirm floats holding. PUH while contaminating cement at .5 bpm. POOH above WCTOC and then RIH to jet/clean out TOL. RBIH pumping 1 bpm maintaining 1:1 returns to TOL. Pump 12.4 KWF to displace GeoVis. In Rate 1.5 bpm, Out Rate = 1.47 bpm. CMT returns noted at calculated bottoms up. KWF to surface. Flow check well. 2 bph loss rate. POOH filling across the top. 8/5/2023 Continue POOH at 8900' filling hole across the top. Stop at 6600', trip sheet is off 2.6 bbls (not taking enough fluid), suspect fluid is falling out of coil as we POOH. Line up to pump down the coil only. Coil took 7 bbls to fill before we caught fluid and then got returns at surface. Well is on slight losses at 0.1 bpm, monitor In & Out Rates. In & Out rates are stable with 0.1 bpm loss rate,. Possible leaking Lap or Shoe, continue POOH. OOH flow check well, trip sheet from 6600' shows a loss of 5.1 bbls. Good no flow, well still showing 6 bph loss rate. Remove injector and LD the CMT Stinger BHA. Discuss loss rate with DE. MU Nozzle and jet BOP Stack. Cut off Nabors CTC and MU BOT CTC for 3/4" ball Disco. Pull test CTC to 42k and PT to 5k. Load verified 3/4" drift ball into the reel and pump. Decision made to redress and rerun the Seal Assembly to determine if the leak is at the lap or the shoe. MU BHA and RIH. 11160' Rates, pressures and Up & Down WT's. RIH WT = 16k, Up WT = 40k. In Rate = 0.5 bpm 500psi Out Rate = 0.32 bpm. In Rate = 1.0 bpm 1450psi Out Rate = 0.84 bpm. Start taking WT at 11193' set down at 11197' deeper than yesterday but on depth with flag. Online with pumps to test lap, line up across the top to fill hole then close choke and walk pressure up to 1000psi. Pumped 8 bbls with a LLR of 0.5 bpm WHP stable at 285psi WHP. Line up down the coil and test shoe. LLR of 0.5 bpm CIRC pressure stable at 722psi, no change in WHP seals are holding. PU off TOL, online at 1.0 bpm same loss rate 0.1 bpm. Flow check well and confirm no flow. POOH. In Rate = 1.2 bpm,Out Rate = 1 bpm. In Mud WT = 12.26 ppg, Out Mud WT = 12.39 ppg. OOH - Flow check well and confirm no flow. Well showing 6 bph loss rate. L/D CSH and NSAK seal assembly. Well flowing .25 bpm. Shut swab and monitor MPD line. Check mud wt and find 12.3 heavy returns. Monitor pressure build up from 7 psi to 29 psi in 15 minutes. Pressure build up to 36 psi in 30 minutes. Discuss plan forward with Drilling Foreman and DE. M/U and RIH with 2.5" nozzle BHA holding 1:1 returns. In Rate = .5 bpm, Out Rate = .96 bpm. In Mud WT = 12.38 ppg, Out Mud WT = 12.41 ppg. Tag at 11,065' PU and begin displacing to 12.4 ppg KWF. In Rate = 1.25 bpm, Out Rate = 1 bpm. In Mud WT = 12.43 ppg, Out Mud WT = 12.47 ppg. Light spot in mud noted at bottoms up. Take 10 bbls off rig to returns tank. Flow check well and confirm no flow. Well taking 6 bph equivalent loss rate. POOH from 11,065'. In Rate = .76 bpm, Out Rate = .5 bpm. In Mud WT = 12.43 ppg, Out Mud WT = 12.49 ppg. 8/6/2023 Continue POOH with nozzle BHA. OOH, flow check well, good no flow. PU injector and LD the Nozzle BHA. Displace reel to fresh water to test BOPE then swap back to KWF and line pump up to MPD Line to maintain hole fill on the well during BOP Test. Grease Stack & Choke Valves. Change Packoffs. Test Gas Alarms. Fluid pack surface lines. Bi-Weekly BOP Test 250/4000 psi. 7-1/16" 5K Annular, Blind/ Shear, 2.0" Pipe / Slip, 2-3/8" Pipe/ Slip, 2.0" Pipe / Slip. Test 1: IRV, Packoff, C7, C9, C10, C11 - Pass. Test 2: C15 F/G/P - & R2 F/G/F Replace R2. Move test 2 to end. Test 3: Annular (2.0" 4k) TIW#2, B1, B4 - Pass (Ann F/Cycle/P). Test 4: Upper 2.0" Pipe / Slip, TIW#1, B2, B3 - Pass. Test 5: Lower 2" Pipe / Slip, C5, C6,C8, TV2 - Pass. Test 6: Choke A, Choke C - Pass. Test 7: 2- 3/8" Pipe / Slip, C1, C4, TV1 - Pass. Test 8: C2, C3 - Pass. Accumulator draw down test. R/D BOP test joint. Test 2: Blind/Shears, R2, B2, C15 - Replaced R2 fail, replace valve with new R2. Test R2 - Pass. R/D BOP test equipment. Blow down stack and surface lines. R/D BOP test risers. R/U Drilling risers. PT Drilling risers to 4k. Load coil with 12.4 KWF while taking fresh water returns to tiger tank. M/U liner clean out BHA w/1.875 D331 mill. M/U 1" CSH work string. Rattle every joint on the floor. Fill every 22 jts. 8/7/2023 Continue PU the 1" CSH Clean out BHA. While PU the 1" CSH Work String the well started flowing, we PU and deployed the Safety Joint and closed the upper 2" Combi's to monitor the WHP through the MPD Line. 5 bbl gain in the pits. Make notification to Drilling Manager, Drilling Engineer, ASR Foreman and MP Well Operations Supervisor. Line up to flow through MGS with water to prep for TIH to circulate a bottoms up. Call MP WOS to shut in F-73 that might be influencing our BHP. Line up to circ through MGS to make sure it's clear. 07:05 WHP = 63 psi. 07:10 WHP = 79 psi. 07:15 WHP = 89 psi. 07:30 WHP = 98 psi. 07:40 WHP = 103 psi. 07:50 WHP = 107 psi. 08:00 WHP = 108 psi. 08:10 WHP = 110 psi. 08:20 WHP = 111 psi. 08:30 WHP = 112 psi. 08:40 WHP = 113 psi. 08:50 WHP = 114 psi. 09:00 WHP = 114 psi. 09:10 WHP = 114 psi. 09:15 WHP = 115 psi. 10:00 WHP = 116 psi. 10:10 WHP = 116 psi. 10:20 WHP = 116 psi. WHP has stabilized at 116 psi. Discuss plan forward with DE. Perform a step down bleed off to see if the pressure builds back up. Bleed off in 0.5 bbl increments. Displace MGS Liquid Leg with 12.4 KWF. Bleed off 0.5 bbls shut in and monitor WHP. Bled off 0.5 bbls and pressure built up to 118 psi in 5 min. Plan Forward is to RIH and circ a bottoms up. Asset team has decided to use Service Coil for clean out run and perf this well. With the wire not secured, minimal room for subs and after many BHA configurations, the only option is to run a screened sub to keep the wire out of the DFCV's. MU upper BHA to the 1" CSH BHA to RIH and circ a bottoms up. Load 1/2" ball on top of TIW Valve to open circ sub. Need to add a 2' & 1' section of lubricator to lubricate all the subs. MU Swivel and open TIW Valves. PT Lubricators, open rams, tag up at 0.36'. Pressure up to shear out circ sub, sheared at 3200 psi. RIH for bottoms up kill. In Rate = .51 bpm, Out Rate = .65 bpm. In Mud WT = 12.40, Out Mud WT = 12.48. Stop at 11,100' and circulate bottoms up. In Rate = 1.5 bpm, Out Rate = 1 bpm. In Mud WT = 12.26, Out Mud WT = 12.49. Circ pressure = 4605, WHP = 30 psi. 42k PUW, 16k RIW. Circulate bottoms up with KWF. Shut down pump and monitor 30 minutes for flow. Well taking ~ 3 bph loss rate. POOH from 11,021'. In Rate = 1.5 bpm, Out Rate = 1 bpm. In Mud WT = 12.26, Out Mud WT = 12.49. Circ pressure = 4605, WHP = 30 psi. OOH - Flow check well and confirm no flow. L/D clean out BHA. Recover 1/2" ball from circ sub. Fill hole and secure well with swab valve. - Flush stack and choke with fresh water. Prep to P/U BOP test joint and test 2 3/8" pipe rams. Test witness was waived by Guy Cook. 8/8/2023 BHA OOH, RU to test Upper 2" Combi Ram and Choke A that were used to shut in the well. Test completed, RD test equipment and remove the 1 & 2' lubricators installed for the Well Kill. PT Lubricators, good PT. MU Stinger Nozzle BHA W/DFCV's. RIH with nozzle BHA to recover 12.4 KWF from the well. Tag TOL, Displace well to 8.4ppg Source Water. PU above the top of the 3-1/2 liner, losing ~40% returns. Above the 3-1/2" In Rate = 2.0 bpm, Out Rate = 1.7 bpm. 8.4ppg at the the Nozzle maintain 1:1 return rate. 8.4 Source Water to surface POOH maintaining 1:1 while POOH. 6650' swap to diesel down the coil. Pumped 48 bbls into the coil. Good diesel to surface, POOH at pipe displacement. Tagged up, service both swabs and Master Valve. Close Master & lower swab and PT to secure the well. 1649psi WHP when MV was closed. Test valves to 4000psi, bleeding off, grease valves again, good PT to 4260psi. Displace last 1.5 bbls of diesel in coil out to the TT. PU injector and remove nozzle BHA to pump slack management. Pump eline slack back into reel. Cut 265' coil to fine eline. 1.7% slack in reel. M/U Nabors CTC. Pull test to 50k. M/U BHI UQC and test. Good. Pressure test connector to 3500 psi. Fluid pack coil with fresh water. Flush all surface lines and choke. Flush MGS. Blow down reel with rig air compressor. 8/9/2023 Continue offloading pits. R/D cellar and MPD. R/D steam lines, water lines and PUTZ. Bleed of and LOTO Koomey. N/D BOP's. N/U tree cap and flange. PT to 4000 psi with methanol. Pass. Release rig at 06:00. ACTIVITYDATE SUMMARY 8/11/2023 ***WELL SHUT IN ON ARRIVAL*** RAN 3.70'' CENT, BLB, 3.50'' MAGNET TO 3-1/2'' LINER TOP @ 11,047' SLM RAN 2.70'' CENT, 1.75'' SAMPLET BAILER TO 2-3/8'' LINER TOP @ 11,237' SLM ***WSR CONTINUES ON 08-12-2023*** 8/11/2023 MPU Well Support tied well back into process Post-RWO. PT'd surface line and serviced wellhead. Turned over to I&E Group No issues 8/12/2023 T/I/O=1605/88/0 Assist Slickline. Pumped 7 bbls of 180* diesel followed by 90 bbls of 180* produced water down TBG to assist Slickline stuck in hole. Pumped 54 bbls 60/40 down TBG to freeze protect. Slickline in control of well upon departure. Final Whps=1850/900/65 8/12/2023 ***WSR CONTINUED FROM 08-11-2023*** RAN 3-1/2'' GR W/ DMY LTP DRIFT TO 11,234' SLM TROUBLE SHEARING OFF, PUMP W/ LRS & FREEZE PROTECT GR PIN SHEARED, DUMMY LPT DRIFT LEFT IN HOLE @ 11,234' SLM ***LAY DOWN EQUIPMENT FOR THE NIGHT*** 8/13/2023 ***WELL S/I ON ARRIVAL*** JAR ON LTP DRIFT @ 11,189' SLM (2.5 hrs .125") JAR ON LTP DRIFT @ 11,189' SLM (1.5 hrs) ***CONTINUE 8/14/23*** 8/14/2023 ***CONTINUE FROM 8/13/23*** JARRED ON LTP DRIFT @ 11,180' SLM FOR 5 HOURS W/ .160" WIRE ***WELL LEFT S/I ON DEPARTURE, DRIFT STILL IN HOLE*** 8/21/2023 LRS CTU #2 - 2.0" Blue Coil. Job Scope: Fish LTP Drift MIRU and RIH with 2-1/8" Yellowjacket fishing BHA with 3" GS spear. Latch LTP drift at 11187' CTMD. Hit 4 jar licks at 16k over, pop free with 23k straight pull. POOH. LTP recovered, no marks on drift and was differentially stuck due to seals and no bypass. FP tubing with diesel. Rig down CTU. ***Job Complete****** 8/27/2023 ***WELL S/I ON ARRIVAL*** RAN 2.73'' CENT., 10' X 1-1/4'' STEM, 2.84'' NO-GO, 1-1/2'' BLB, TAG & WORK BLB @ 11226' SLM / 11183' MD SET 3-1/2 NORTHERN SOLUTION LTP, SET @ 11230' SLM / 11183' MD WELL WENT FROM 1700 psi TO 0 psi AFTER LTP WAS SET PULL RSG @ 11230' SM ***WELL S/I ON DEPARTURE*** 9/1/2023 ***WELL S/I ON ARRIVAL*** PERFORM SBHPS AS PER PROGRAM TO 11,386' ***WELL SHUT IN ON DEPARTURE*** 9/11/2023 LRS CTU #1, 1.5" Blue Coil. Job Objective: Extended Adperf MIRU and MU 1-11/16" BOT milling BHA with 1.77" round nose mill. RIH and spin through LTP at 11168' CTM / 11183' MD. Continue in hole and tag at 12850' MD. ***Job in Progress*** 9/12/2023 LRS CTU #1, 1.5" Blue Coil. Job Objective: Extended Adperf Continue milling from the initial tag at 12850 to 13120 CTM. Pump gel sweep, open circ sub and chase out of hole at 80%. Maintained 1:1 returns throughout cleanout. Bump up against the brass with the log and perf CTC and MHA.Make up and RIH with HES CBL BHA. RIH to bottom and log from 13140 CTM to 11000'. Flag pipe at 12700'. ***Job in Progress*** Daily Report of Well Operations PBU MPF-89A Daily Report of Well Operations PBU MPF-89A 9/13/2023 LRS CTU #1, 1.5" Blue Coil. Job Objective: Extended Adperf Continue POOH and confirm good data (+18' correction, PBTD ~ 13151', cement isolation above top target perf interval). Deploy 275' of 1.56" Titan, 6 SPF, 60 degree phase guns (228' loaded). RIH, tie-in to the flag at ~ 12700', and perforate 12862' - 12917', 12932' - 13022', 13036' - 13058', 13074' - 13135'. POOH pumping pipe displacement. Lay down perf guns (all shots fired in scallop). Freeze protect the tubing to 2500' TVD with diesel. ***Job Complete*** 9/15/2023 *** WELL SHUT-IN ON ARRIVAL.*** SET 4-1/2" MCX (1" bean)IN X-NIPPLE AT 2,992' MD. NO TUBING PRESSURE FOR DRAW DOWN TEST. *** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.*** 9/17/2023 T/I/O=1991/0/0 Pre AOGCC MIT-IA Passed to 1671 psi. Pressured up IA to 1732 psi with 4 bbls diesel. 1st 15 min IA lost 50 psi. 2nd 15 min IA lost 11 psi for a total loss of 61 psi in 30 min. Bled IA to 200 psi and recovered 2 bbls. Final Whp's=1990/200/0 WELL NAME Date : Shoe @ :FC @ :Top Liner @ : Type: Type : Type : Type : Type : Yes N/A No Yes N/A No Yes N/A No X Yes No X Yes No Date : Volume lost during displacement (bbls) : Density (ppg) : 10.5 Volume pumped (bbls) : 290 MP F-89A CEMENT REPORT 5-Aug-23 Hole Size :3.25"Casing Size :2-3/8" Lead Slurry Class G cement Volume (bbls): 15 15.3 Yield : 1.235 Sacks : 68.2 Mixing / Pumping Rate (bpm) : 1 Density (ppg) : Tail Slurry Volume (bbls) : Density (ppg) : Yield : Sacks : Mixing / Pumping Rate (bpm) : Post Flush (Spacer) 1.5 ppb Geovis/NaBr Density (ppg) : 10.5 Rate (bpm) : Bump press : Volume : 150 Displacement : .5 ppb Geovis/NaB Density (ppg) : 10.5 Rate (bpm) : 1.5 Volume (actual / calculated) : 1.5 Method Used To Determine TOC : Calculated Casing Rotated? Reciprocated? % Returns during job : 100% Cement returns to surface? Spacer returns? Vol to Sur : 125 FCP (psi) : 2606 Pump used for disp : GD Plug Bumped? Cement In Place At : 01:00 8/5/2023 Estimated TOC : 11,183' Remarks: FI R S T S T A G E 13,166 13150 & 13151 11,183' Preflush (Spacer) KCl/NaBr 9 / 9 0 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Extended Perfs 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): 13,166'N/A Casing Collapse Conductor N/A Surface 2,470psi Intermediate 4,790psi Liner 6,390psi Liner 10,540psi Liner 11,780psi 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: Wells Manager 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 Milne Point Unit F-89A Milne Point Kuparuk River Oil N/A 7,309' 13,150' 7,308' 1,214 N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 11,200psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 9/14/2023 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509, ADL355017 & ADL355018 223-026 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23268-01-00 Hilcorp Alaska LLC C.O. 4432E Length Size Proposed Pools: 113' 113' 12.6 / L-80 / TC-II TVD Burst 11,022' 10,160psi MD N/A 7,740psi 5,210psi 6,890psi 4,587' 6,836' 7,129' 6,723' 11,186' 7,129'3-1/2" 78' 20" 10-3/4" 7-5/8" 6,888' 5-1/2"418' 11,154' 11,490' Perforation Depth MD (ft): 11,490' See Schematic 475' 2-3/8" See Schematic 13,166'1,983' 4-1/2" 7,270' Baker S-3 Perm., Baker ZXP & Baker ZXP and N/A 10,986 MD/ 6,651 TVD, 11,026 MD/ 6,687 TVD & 11,083 MD/ 6,740 TVD and N/A Taylor Wellman twellman@hilcorp.com 777-8449 No 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 8:40 am, Sep 01, 2023 323-498 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.08.31 13:40:16 - 08'00' Taylor Wellman (2143) 10-404 SFD 9/6/2023 1,214 DSR-0/1/23 432E SFD MGR01SEP23*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.06 16:06:00 -08'00'09/06/23 RBDMS JBS 090823 Well: MPU F-89A PTD: 223-026 API: 50-029-23268-01 Well Name:MPU F-89A API Number: 50-029-23268-01 Current Status:Shut in – Post CTD Rig:Slickline / Coil Estimated Start Date:9/14/2023 Estimated Duration:3 days Regulatory Contact:Tom Fouts 777-8398 First Call Engineer:Ryan Lewis (907) 564-5277 (O) (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) MPU F-89A is a CTD sidetrack injector that was drilled across a fault in order to support 2 producers MPU L-14 and MPU F-73A. A LTP was set and the well went on a vacuum through a wet shoe. The LTP effectively isolated the liner lap. The most representative BHP’s are from the 2 producers MPL-14 and MPF-73A. The SDHPS from each of those wells were as follows. We will run a SBHPS in this well to confirm pressure. Current Bottom Hole Pressure:1,907 psi @ 6,938’ TVD 5.3 PPGE | MPL-14 9/20/20 Current Bottom Hole Pressure:1,806 psi @ 7,240’ TVD 4.8 PPGE | MPL-73A 10/16/21 Maximum Expected BHP:1,907 psi @ 6,938’ TVD 5.3 PPGE | MPL-14 9/20/20 Max. Proposed Surface Pressure:1,214psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:0psi (08/27/2023) Min ID:1.91” – 2-3/8” Deployment Sleeve @ 11,183’ MD Max Angle:97 Deg @ 12,319’ Tie In Log:MWD Log: To be provided by Geologist separately Brief Well Summary: MPU F-89A was sidetracked from a parent Kuparuk injection well. The fault block with the parent wellbore is overpressured and the toe of the liner is in an underpressured fault block. The liner in both fault blocks is within the Kuparuk pool. The sidetrack 2-3/8” liner was run to TD and cemented with 1:1 returns. Post cementing liner testing indicates a wet shoe and a leaking liner lap. Objectives: 1. Shoot Extended Adperf (one run; 275’ of guns, 45’ of blank pipe) to allow injection into the southern lower pressured fault block. Procedure: Coiled Tubing Notes: x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. x The well will be killed and monitored before making up the initial perfs guns. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. 1. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 2. Bullhead ~270 bbls 1% KCL/SW down tubing. Max tubing pressure 2500 psi. (This step can be performed any time prior to open-hole deployment of the perf guns. Timing of the well kill is at the discretion of the WSS.) o allow injection into the southernp lower pressured fault block. Well: MPU F-89A PTD: 223-026 API: 50-029-23268-01 a. Wellbore volume to bottom of liner (wet shoe) = 179 bbls b. 4-1/2” Tubing – 11,022’ X .0152 bpf = 168 bbls c. 5-1/2” Liner – 19’ X 0.0232 bpf = 1 bbl d. 3-1/2” Liner – 114’ X .0087 bpf = 2 bbl e. 2-3/8” Liner – 1,969’ X .0039 bpf = 8 bbls * All liner section volumes rounded up to closest bbl. 3. MU and RIH with motor and mill to clean 2-3/8” liner of any cement sheath to ORCA valve at 13,140’ MD. 4. MU and RIH w/ logging tools and drift BHA: 1-9/16” dmy gun & nozzle. 5. Flag pipe as appropriate per WSS for adperf/CBP runs. 6. POOH and freeze protect tubing as needed. 7. Confirm good log data and send into Geologist & OE for correlation: Graham Emerson, graham.emerson@hilcorp.com, 907-793-0315. 8. At surface, prepare for deployment of TCP guns. 9. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, 8.4 pp produced or source water as needed. Maintain hole fill taking returns to tank until lubricator connection is re- established. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 10.*Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. a.At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns one time to confirm the threads are compatible. 11.Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. Perf Schedule *SLB 2” PJO guns were used to estimate for this job and calculate gun weights. Perf Interval Perf Length Gun Length Weight of Gun (lbs) 12,862’-12,917’ 55’ 55’ 220 lbs (4 #/ft) 12,917’-12,932’ 15’ BLANK 15’ BLANK 57 lbs (3.8#/ft) 12,932’-13,022’ 90’ 90’360 13,022’-13,036’ 14’ BLANK 14’ BLANK 53 13,036’-13,058’ 22’ 22’88 13,058’-13,074’ 16’ BLANK 16’ BLANK 61 13,074’-13,135’ 61’ 63’252 Total 273’ 275’ (w/BLANK) 1,095 lbs 12. MU lubricator connection at QTS. Well: MPU F-89A PTD: 223-026 API: 50-029-23268-01 13. RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate interval per Perf Schedule above. a. Note any tubing pressure change in WSR. 14. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and stick the BHA. Confirm well is dead and re-kill if necessary before pulling to surface. 15. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary. 16. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 17. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 18. RDMO CTU. 19. RTP or FP well. Attachments: 1. Wellbore Schematic 2. Proposed Schematic 3. Coil Tubing BOPE Schematic 4. Standing Orders for Open Hole Well Control during Perf Gun Deployment 5. Equipment Layout Diagram _____________________________________________________________________________________ Revised By: JH 8/29/2023 SCHEMATIC Milne Point Unit Well: MPU F-89A Last Completed: 8/9/2023 PTD: 223-026 TD =13,166’ (MD) / TD =7,309’(TVD) 20” Orig. KB Elev.: 45.18/ GL Elev.: 11.5’ 7” 3 5, 7 & 86 12 10.75” Howco ES Cementer @ 2,785 MD 10-3/4” 1 2 3-1/2” LTP @ 11,230’ SLM Whipstockset @ 11,490’ Top of Window @11,490’ Top of Liner / Cement @11,183’ PBTD =13,150’(MD) / PBTD=7,308’(TVD) 4 2-3/8”PB1: 12134’– 13076’ 3-1/2” 9, 10 & 11 5-1/2” A B TREE & WELLHEAD Tree 4-1/16” 5M FMC Wellhead 11” 5M FMC ZGen 5 w/ 11” x 4.5” FMC Tbg. Hng. w/ 4.5” TC-II & 4” CIW ‘H’ BPV Profile OPEN HOLE / CEMENT DETAIL 42" 260 sx of Arcticset (Approx.) 13-1/2" 658 sx AS Lite, 644 sx Class ‘G’ 9-7/8” 275 sx Class ‘G’ 6-3/4” 79 sx Class ‘G’ 4-3/4” 123 sx Class ‘G’ 3-1/4” 68 sx Class G WELL INCLINATION DETAIL KOP @ 11490’ 90 deg Hole Angle = 11,809’ GENERAL WELL INFO API: 50-029-23268-01-00 Drilled, Cased & Completed by Doyon 14 - 8/20/2005 A Sidetrack CDR2: 8/9/2023 JEWELRY DETAIL No Depth Item 1 2,992’ 4-1/2” HES X-Nipple w/ MCX .656 Bean Installed on 7/13/2013 2 10,966’ 4-1/2” HES X-Nipple ID= 3.813” 3 10,986’ 7-5/8”x4.5”Baker S-3 Permanent Packer 4 11,010’ 4-1/2” HES XN-Nipple ID= 3.725” No Go 5 11,015’ 7-5/8” x 5.5” Baker Tie Back Sleeve 6 11,022’ WLEG 7 11,026’ 7-5/8” x 5.5” Baker ZXP Liner Packer –Btm @ 11,032’ for 7-58” 8 11,032’ 7-5/8” x 5.5” Baker HMC Liner Hanger -Btm @ 11,041’ for 5.5” 9 11,072’7-5/8” x 5.5” Baker Tie Back Sleeve 10 11,083’7-5/8” x 5.5” Baker ZXP Liner Packer 11 11,090’7-5/8” x 5.5” Baker HMC Liner Hanger 12 11,183’ Deployment Sleeve CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 113' 10-3/4" Surface 45.5 / L-80 / BTC 9.950 Surface 6,723’ 7-5/8" Intermediate 29.7 / L-80 / BTC Mod 6.875 Surface 11,186’ 7-5/8"Liner X-Over 29.7 / L-80 / BTC Mod 6.875 11,015’11,026’ 5-1/2”Liner X-Over 17 / L-80 IBT-M 4.892 11,026’11,041’ 5-1/2” Liner 17 / L-80 IBT-M 4.892 11,072’ 11,490’ 3-1/2” Liner 9.2 / L-80 / IBT 2.992 11,015’ 11,490’ 2-3/8” Liner 4.7 / L-80 / Hyd 511 1.995 11,183’ 13,166’ TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TC-II 3.958 Surface 11,022’ A B _____________________________________________________________________________________ Revised By: TDF 8/11/2023 PROPOSED Milne Point Unit Well: MPU F-89A Last Completed: 8/9/2023 PTD: 223-026 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 113' 10-3/4" Surface 45.5 / L-80 / BTC 9.950 Surface 6,723’ 7-5/8"Liner X-Over 29.7 / L-80 / BTC Mod 6.875 11,015’11,026’ 5-1/2”Liner X-Over 17 / L-80 IBT-M 4.892 11,026’11,041’ 3-1/2” Liner 9.2 / L-80 / IBT 2.992 11,015’ 11,490’ 2-3/8” Liner 4.7 / L-80 / Hyd 511 1.995 11,183’ 13,166’ TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TC-II 3.958 Surface 11,022’ JEWELRY DETAIL No Depth Item 1 2,992’ 4-1/2” HES X-Nipple w/ MCX .656 Bean Installed on 7/13/2013 2 10,966’ 4-1/2” HES X-Nipple ID= 3.813” 3 10,986’ 7-5/8”x4.5”Baker S-3 Permanent Packer 4 11,010’ 4-1/2” HES XN-Nipple ID= 3.725” No Go 5 11,015’ 7-5/8” x 5.5” Baker Tie Back Sleeve 6 11,022’ WLEG 7 11,026’ 7-5/8” x 5.5” Baker ZXP Liner Packer 8 11,032’ 7-5/8” x 5.5” Baker HMC Liner Hanger 9 11,072’7-5/8” x 5.5” Baker Tie Back Sleeve 10 11,083’7-5/8” x 5.5” Baker ZXP Liner Packer 11 11,090’7-5/8” x 5.5” Baker HMC Liner Hanger 12 11,183’ Deployment Sleeve PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status A3 ±12,862’ ±12,917’ ±7,293’ ±7,297’ ±55 Future Future A2 ±12,932’ ±13,022’ ±7,297’ ±7,293’ ±90 Future Future A1 ±13,036’ ±13,058’ ±7,291’ ±7,287’ ±22 Future Future A1 ±13,074’ ±13,135’ ±7,285’ ±7,275’ ±61 Future Future GENERAL WELL INFO API: 50-029-23268-01-00 Drilled, Cased & Completed by Doyon 14 - 8/20/2005 A Sidetrack CDR2: 8/9/2023 TD =13,166’ (MD) / TD =7,309’(TVD) 20” Orig. KB Elev.: 45.18/ GL Elev.: 11.5’ 7” 3 5, 7 & 86 12 10.75” Howco ES Cementer @ 2,785 MD 10-3/4” 1 2 Whipstockset @ 11,490’ Top of Window @11,490’ Top of Liner / Cement @11,183’ PBTD =13,150’(MD) / PBTD=7,308’(TVD) 4 2-3/8” PB1: 12134’– 13076’ 12 5-1/2” 3-1/2” 9, 10 & 11 3-1/2” LTP @ 11,230’ SLM A B TREE & WELLHEAD Tree 4-1/16” 5M FMC Wellhead 11” 5M FMC ZGen 5 w/ 11” x 4.5” FMC Tbg. Hng. w/ 4.5” TC-II & 4” CIW ‘H’ BPV Profile OPEN HOLE / CEMENT DETAIL 42" 260 sx of Arcticset (Approx.) 13-1/2" 658 sx AS Lite, 644 sx Class ‘G’ 9-7/8” 275 sx Class ‘G’ 6-3/4” 79 sx Class ‘G’ 4-3/4” 123 sx Class ‘G’ 3-1/4” 68 sx Class G WELL INCLINATION DETAIL KOP @ 11490’ 90 deg Hole Angle = 11,809’ A B Well: MPU F-89A PTD: 223-026 API: 50-029-23268-01 Coil Tubing BOPE Schematic Well: MPU F-89A PTD: 223-026 API: 50-029-23268-01 Standing Orders for Open Hole Well Control during Perf Gun Deployment Well: MPU F-89A PTD: 223-026 API: 50-029-23268-01 Equipment Layout Diagram 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: 08/31/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: MPU F-89A + PB1 PTD: 223-026 API: 50-029-23268-01-00 (MPU F-89A) 50-029-23268-70-00 (MPU F-89APB1) FINAL LWD FORMATION EVALUATION LOGS (07/23/2023 to 08/01/2023) Multiple Propagation Resistivity & Gamma Ray (2” & 5” MD/TVD Color Logs) Pressure While Drilling (PWD) Final Definitive Directional Surveys SFTP Transfer - Data Main Folders: SFTP Transfer - Data Sub-Folders: Please include current contact information if different from above. PTD: 223-026 MPU F-89A: T37967 MPU F-89A PB1: T37968 8/31/2023 Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.31 13:52:45 -08'00' 1 Regg, James B (OGC) From:Mark Igtanloc <Mark.Igtanloc@hilcorp.com> Sent:Tuesday, August 8, 2023 6:48 AM To:DOA AOGCC Prudhoe Bay Cc:Monty Myers; Ryan Ciolkosz; Alaska NS - CTD DSM; Richard Burnett - (C); Matt Hogge Subject:RE: CDR2 BOP Usage Form on MP F-89A Attachments:8-7-23 MP F-89A BOP Usage Form.doc Revised BOP Usage Form ‐ added Choke A to the form to test This test will be performed after we are able to RIH to perform a bottoms up kill then POOH to lay the BHA down and then test the 2” Combi ram and Choke A that were used to shut in the well Mark Igtanloc Sr. Drilling Foreman – CTD Rig (907) 670‐3097 Cell (907) 268‐9140 Positional Email AlaskaNS‐CTD‐DSM@hilcorp.com Alternate: John Perl Hilcorp Alaska, LLC From: Mark Igtanloc Sent: Monday, August 7, 2023 17:07 To: doa aogcc prudhoe bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: Monty Myers <mmyers@hilcorp.com>; Ryan Ciolkosz <Ryan.Ciolkosz@hilcorp.com>; Alaska NS ‐ CTD DSM <AlaskaNS‐CTD‐DSM@hilcorp.com>; Richard Burnett ‐ (C) <Richard.Burnett@hilcorp.com>; Matt Hogge <mhogge@hilcorp.com> Subject: CDR2 BOP Usage Form on MP F‐89A All, Attached is a BOP Usage form for a closure of our 2” Combi Rams for a Well Control Incident while making up a clean out BHA. We are currently making up the injector to the BHA that was shut in on then RIH and circulate a bottoms up with Kill Weight Fluid. After a good flow check we will POOH to LD the BHA and then test the Upper 2” Combi Rams used to shut in on our Safety Joint. If everything goes well, we anticipate having the well killed and the BHA OOH by crew change tomorrow morning. I will submit a Notification to Test the rams that were used. Mark Igtanloc Sr. Drilling Foreman – CTD Rig (907) 670‐3097 Cell (907) 268‐9140 Positional Email AlaskaNS‐CTD‐DSM@hilcorp.com Alternate: John Perl Hilcorp Alaska, LLC 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. Milne Point Unit F-89APTD 2230260 Attachments: - BOPE Use Report - BOPE Test After Use Report RP: Guidelines for Blow Out Preventer Equipment (BOPE) – Usage,Re-test and reporting to the AOGCC Page 1 of 3 HILCORP Confidential and © 2011 HILCORP Alaska LLC. Control Tier: 3 – HILCORP Alaska Revision Date: 4/4/2022 Document Number: UPS-US-AK-ADW-ALL-ADW-DOC-00209-3 Print Date: 10/24/2023 PAPER COPIES ARE UNCONTROLLED. THIS COPY VALID ONLY AT THE TIME OF PRINTING. THE CONTROLLED VERSION OF THIS DOCUMENT CAN BE FOUND AT http://eportal.Hilcorpweb.Hilcorp.com/hse/ HILCORP Alaska Region Recommended Practice: Guidelines for Blow Out Preventer Equipment (BOPE) - Usage and Re-test reporting to the AOGCC Authority: Drilling Manager Custodian: Drilling Manager Scope: Hilcorp Alaska - Operations Document Control Administrator: HILCORP Alaska, Document Control Specialist Issue Date: April 10, 2022 Issuing Dept: HILCORP Alaska Revision Date: April 10, 2022 Control Tier: Tier 3 Next Review Date: April 10, 2025 1.0 Purpose The purpose of this document is to provide concise guidance on required AOGCC regulatory compliance notifications and reporting following specific BOPE events related to Well Control, Wellbore Breathing and BOPE Work. 2.0 Abbreviations/Acronyms/Definitions Well Control Event Any use of BOPE to prevent the influx of formation fluid required to maintain pressure on open formations (that is, exposed to the wellbore) to prevent or direct the flow of formation fluids into the wellbore. Well Bore Breathing The continued flow of fluids from the well after shutting down the pumps. The flow in this case is due to mud loss in drilled zones resulting in a near-bore over-pressuring rather than a well control event. AOGCC BOPE USAGE REPORT FORM (Well Control event only) (Form is Attached to back of RP) INTELLECTUAL PROPERTY AND CONFIDENTIALITY NOTICE © 2022 HILCORP Alaska LLC Inc. (for all US copyright notices) All rights reserved. This document contains confidential information, which is the exclusive and proprietary property of HILCORP Alaska LLC Inc. and affiliates. In whole or part, this document or its attachments MAY NOT be reproduced by any means, disclosed or used for any purpose without the express written permission of HILCORP Alaska LLC or affiliates. SOP: BOPE and Wireline Valves for Well Control Page 2 of 3 HILCORP Confidential and © 2011 HILCORP Alaska LLC. Control Tier: 3 – HILCORP Alaska Revision Date: 4/4/2022 Document Number: UPS-US-AK-ADW-ALL-ADW-DOC-00209-3 Print Date: 10/24/2023 PAPER COPIES ARE UNCONTROLLED. THIS COPY VALID ONLY AT THE TIME OF PRINTING. THE CONTROLLED VERSION OF THIS DOCUMENT CAN BE FOUND AT http://eportal.Hilcorpweb.Hilcorp.com/hse/ START HERE (Instructions) What type of event? Event Type Well Control Well Bore Breathing BOPE Work outside routine test cycle (Ram swaps, Repair work) BOPE Usage report notification required within 24hrs yes No No BOPE test/re-test required Yes, timely notification of retest required (may be < 24hrs) Yes, but no AOGCC witness retest required Yes, but no AOGCC witness retest required BOPE re-test form 10-424 report required within 5 days Yes No, but Internal records shall be kept in the Daily Drilling Report No, but Internal records shall be kept in Open wells Who needs to be notified internally following a Well Control event? 1.Well Site Leader notifies the Drilling Engineer. HSE representative starts a Velocity report and adds this number as required to the AOGCC BOPE Usage Report Form (Well Control event only) and forwards to the Drill Site Foreman. 2.The Drill Site Foreman will complete the AOGCC BOPE Usage Report Form and submit it to the AOGCC within 24 hours of the event, to the Email list below: (Well Control event only) Email CC List HSE Representative Drilling Engineer Drilling Manager AOGCC BOPE USAGE REPORT FORM (Well Control event only) (Form is Attached to back of RP) RP: Guidelines for Blow Out Preventer Equipment (BOPE) - Usage and Re-test reporting to the AOGCC Page 3 of 3 HILCORP Confidential and © 2020 HILCORP Alaska LLC Control Tier: 3 – HILCORP Alaska Revision Date: 4/10/2022 Document Number: Print Date: 10/24/2023 PAPER COPIES ARE UNCONTROLLED. THIS COPY VALID ONLY AT THE TIME OF PRINTING. THE CONTROLLED VERSION OF THIS DOCUMENT CAN BE FOUND AT http://eportal.Hilcorpweb.Hilcorp.com/hse/ Revision Log Revision Date Approving Authority Custodian/ Author Revision Details April 11, 2022 Monty Myers Monty Myers Original Issue Appendix - AOGCC BOPE USAGE REPORT FORM (Well Control event only) AOGCC BOPE Usage Report form and retest notification guidance (updated April 16, 2014) AOGCC BOPE USAGE REPORT FORM (Well Control event only) Drilling Manager Name: Monty M Myers Drill Site Forman: Mark Igtanloc Contact Number: 907-777-8431 Contact Number: 907-670-3097 HILCORP Velocity Number: Rig Name & Well Pad or Drill Site & Well Name: Nabors CDR2 AC MP F-89A Permit To Drill (PTD) Number: 223-026 Date and Time of Incident: 8/7/2023 07:00 Original Scope of Work: Making up a Clean Out BHA Operational Description Leading up to Well Control Event: While making a clean out BHA BOPE Used and Reason: Upper 2” Combi Rams, flow coming over the top of the lubricator on the rig floor Current BOPE test time/date 01:30 08/07/2023 Is a BOPE re-test required after use: Yes, the WHP stabilized at 118 psi on the upper 2” Combi Rams BOPE Retest time/date and result: This test will be performed after we are able to RIH to perform a bottoms up kill then POOH to lay the BHA down and then test the 2” Combi ram and Choke A that were used to shut in the well Plan Forward: RIH to the top of liner and displace the well to KWF, flow check the well then POOH to LD the clean out BHA Additional Comments: ACTIONS REQUIRED: 1)Drill Site Forman: Timely email notification of BOPE re-test time estimate to AOGCC North Slope Inspectors is required following any WC incident to allow the State to witness re-test as required. (This is a judgment call given WC is an unplanned event during rig operations and factors such as wellbore condition and trip timing will influence timing of any retest) 2)Drilling Foreman: Email the completed BOPE Usage Report form to AOGCC North Slope Inspectors within 24 hours of a WC incident: doa.aogcc.prudhoe.bay@alaska.gov 3)Drill Site Foreman: Complete AOGCC BOPE Test report form 10-424 and send to three AOGCC addresses (noted in form) within 5 days following the test/retest. This is applicable to Well Control events Only.        STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:CDR2AC DATE:8/8/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2230260 Sundry # Operation:Drilling:Workover:Explor.: Test:Initial:Weekly:Bi-Weekly:Other:X Rams:250/4000 Annular:250/4000 Valves:250/4000 MASP:3888 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 0 NA Test Fluid Water Inside BOP 0 NA FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 2"NA Trip Tank NA NA Annular Preventer 0 7 1/16" GK NA Pit Level Indicators NA NA #1 Rams 0 Blind / Shears NA Flow Indicator NA NA #2 Rams 1 2" Pipe / Slip P Meth Gas Detector NA NA #3 Rams 0 2-3/8" Pipe / Slip NA H2S Gas Detector NA NA #4 Rams 0 2" Pipe / Slip NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 0 2-1/16"NA Time/Pressure Test Result HCR Valves 0 2-1/16"NA System Pressure (psi)NA Kill Line Valves 0 2-1/16"NA Pressure After Closure (psi)NA Check Valve 0 NA 200 psi Attained (sec)NA BOP Misc 0 2.0" Piper NA Full Pressure Attained (sec)NA Blind Switch Covers:All stations NA CHOKE MANIFOLD:Bottle Precharge:NA Quantity Test Result Nitgn. Bottles # & psi (Avg.):NA No. Valves 0 NA ACC Misc 0 NA Manual Chokes 0 NA Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer NA #1 Rams NA Coiled Tubing Only:#2 Rams NA Inside Reel valves 0 NA #3 Rams NA #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:0 Test Time:1.0 HCR Choke NA Repair or replacement of equipment will be made within days. HCR Kill NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 8/7/23 17:11 Waived By Test Start Date/Time:8/8/2023 7:00 (date)(time)Witness Test Finish Date/Time:8/8/2023 8:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Guy Cook Nabors This was a test for the 2 components used to shut in our well, the upper 2" Combi Rams and Choke A Igtanloc/Burnett Hilcorp Alaska, LLC N.Wheeler/W.Williams MPU F-89A Test Pressure (psi): Nathan.Wheeler@nabors.com alaskans-ctd-dsm@hilcorp.com Form 10-424 (Revised 08/2022)2023-0808_BOP_Nabors_CDR2AC_test-after-use_MPU_F-89A          J. Regg; 10/24/2023 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 Myers Drilling Manager Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK, 99503 Re: Milne Point, Kuparuk River Oil, MPU F-89A Hilcorp Alaska, LLC Permit to Drill Number: 223-026 Surface Location: 2162' FSL, 2888' FEL, Sec. 06, T13N, R10E, UM, AK Bottomhole Location: 2082' FNL, 427' FWL, Sec. 32, T14N, R10E, UM, AK Dear Mr. Meyers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this ___ day of June, 2023. 05 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.05 14:21:17 -08'00' 1a. Contact Name:Trevor Hyatt Contact Email:trevor.hyatt@hilcorp.comAuthorized Name:Monty Myers Authorized Title:Drilling Manager Authorized Signature: Contact Phone:907-777-8396 Approved by:COMMISSIONER APPROVED BY THE COMMISSION Date: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Drill Type of Work: Redrill Lateral 1b.Proposed Well Class:Exploratory - Gas Service - WAG 1c. Specify if well is proposed for: Development - Oil Service - Winj Multiple ZoneExploratory - Oil Gas Hydrates Geothermal Hilcorp Alaska, LLC Bond No.22224484 11.Well Name and Number: MPU F-89A TVD:13334'7259' 12.Field/Pool(s): MILNE POINT, KUPARUK RIVER OIL MD: ADL 025509, 355018 & 355017 94-019 June 10, 2023 4a. Surface: Top of Productive Horizon: Total Depth: 2162' FSL, 2888' FEL, Sec. 06, T13N, R10E, UM, AK 1191' FNL, 631' FWL, Sec. 32, T14N, R10E, UM, AK Kickoff Depth:11490 feet Maximum Hole Angle: 94 degrees Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole:Surface:4600 3888 17.Deviated wells:16. Surface: x-y-Zone -541673 6035613 4 10.KB Elevation above MSL: GL Elevation above MSL: feet feet 45.18 11.5 15.Distance to Nearest Well Open to Same Pool: Cement Quantity, c.f. or sacks MD Casing Program: 11200'6849' 19.PRESENT WELL CONDITION SUMMARY Liner 78 260 sx Arctic Set (Approx.) 11795 7424 None 11761 7391 None 35 - 113 Surface 658 sx AS Lite, 644 sx Class G 7111 - 7277 Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Shallow Hazard Analysis Commission Use Only See cover letter for other requirements: 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 H2S measures Yes No Spacing exception req'd:Yes No Mud log req'd:Yes No Directional svy req'd:Yes No Inclination-only svy req'd:Yes No Other: Date: Address: Location of Well (State Base Plane Coordinates - NAD 27): 4.6# 6888 11471 - 11643 50-029-23268-01-00 32 - 11186 123 sx Class G Intermediate Conductor/Structural Single Zone Service - Disp NoYesPost initial injection MIT req'd: NoYes Diverter Sketch Comm. TVD API Number: MD Sr Pet Geo 275 sx Class G 2082' FNL, 427' FWL, Sec. 32, T14N, R10E, UM, AK Time v. Depth PlotDrilling Program 20695' (To be completed for Redrill and Re-Entry Operations) 20" 10-3/4" 7-5/8" Hyd 511 11154 780 6677 - 7424 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stratigraphic Test Development - Gas Service - Supply Coalbed Gas Shale Gas 2.Operator Name:5.Bond Blanket Single Well 3. 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 6.Proposed Depth: 7.Property Designation (Lease Number): 8.DNR Approval Number:13.Approximate spud date: 9.Acres in Property:14.Distance to Nearest Property: Location of Well (Governmental Section): 4b. 12096 800' 18.Specifications Top - Setting Depth - Bottom Casing Weight Grade TVDHoleCouplingLengthTVD (including stage data) Total Depth MD (ft):Total Depth TVD (ft):Plugs (measured):Effect. Depth MD (ft):Effect. Depth TVD (ft):Junk (measured): Casing Length Size MD 35 - 113 35 - 6723 35 - 4587 456 5-1/2"79 sx Class G 11072 - 11528 6729 - 7166 Liner 3-1/2"11015 - 11795 Perforation Depth MD (ft):Perforation Depth TVD (ft): 20. Attachments Property Plat BOP Sketch Permit to Drill Number: Permit Approval Date: Reentry Hydraulic Fracture planned? Sr Pet Eng Sr Res Eng 32 - 6836 Cement Volume Comm. 13334'7259'70 sx Class G3-1/4"2-3/8"L-80 2134' Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) 3.21.2023 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.03.21 15:42:22 -08'00' Monty M Myers MGR22MAR2023 Service - Winj BOPE test to 4000 psi. 223-026 Variance to 20 AAC 25.112 (i) approved with a fully cemented production liner. SFD 5/28/2023 DSR-3/22/23GCW 06/05/2023JLC 6/5/2023 06/05/23 06/05/23 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.06.05 14:21:39 -08'00' L-04-7,166 L-05 -7,167 L-15-7,156 L-14-7,141 L-24-7,279 F-53-7,025 F-61-7,100 F-69-7,073 -7,414 F-88-7,062 L-43-7,187 93114 F-89-7,142 L-13-7,083 F-70-7,227 F-62-7,171 L-25-7,253 L-21-7,184 F-74-7,393 F-33-7,270 F-33A F-49-7,312 F-73 -7,201 F-73A-7,200 SAGCLOSE F-53A-7,025 F-70A-7,228F-70AL1-7,227 F-53AL2-7,025F-53AL1-7,025 F-74A-7,390 F-93L17,120F-93L1-027,120 * L-41-7,220 F-116-7,291 F-62A-7,158 L-21A-7,143 L63 L- 41A PROPL-13A F-89A PUD HILCORP ALASKA LLC Milne Point KUP A3 STRUCTURE F-89A injector 1320' radius circle(40 acres) POSTED WELL DATA Well Num berFMTOPS - KUP_A3[JTS] (SS) SYMBOL HIGHLIGHT ACTIVE OIL ABANDONED OIL ACTIVE INJ ABANDONED INJ OIL SHOW SHUT IN OIL SHUT IN INJECTO R SHALED OUT DRILL WELL WET WELL SYMBOLSACTIVE OIL D&A Location Shut In Oil INJ Well (Water Flood) P&A Oil P&A Oil/Gas Abandoned Injector SWD J&A Plug Back Injector Location Producer Location Injector Gas Shut In INJ WATER SOURCE RE MARKSCI = 25' By: JTS FEET 0 500 1,000 1,500 February 16, 2023 PETRA 2/16 /20 23 9 :17 :13 AM PTD API WELL STATUS Top of Kuparuk A (MD) Top of Kuparuk A (TVD) Top of Cement (MD) Top of Cement (TVD) Kuparuk A status Zonal Isolation 205-090 50-029-23268-00-00 MPU F-89 Kuparuk Injector 11590 7225 11,083 6740 Open 5-1/2" liner cemented w/ 16bbls (79sxs) of 15.8ppg Class G cmt. Dart landed and pressure held to 3,500psi. Floats held. No cmt ciruclated back. USIT ran 17-AUG-2005. Area of Review MPU F-89A F-89 is the parent well that will be abandoned by completion of F-89A. SFD To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: March 21, 2023 Re: MPU F-89A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well MPU F-89 with the Nabors CDR2 Coiled Tubing Drilling. Proposed plan for MPU F-89A Injector: See MPU F-89 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to MIT and drift for whipstock. E-line will then set a 3-1/2" packer whipstock (if not possible, will set with rig). A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. If unable to set or mill pre-rig, the rig will set a 3-1/2" packer whipstock and mill a dual string 2.80" window + 10' of formation. The well will kick off drilling and land in the Kuparuk. The lateral will continue in the Kuparuk to TD. The proposed sidetrack will be completed with a 2-3/8” L-80 solid liner and cemented. This completion WILL abandon the parent Kuparuk perfs. The well will be perforated post rig (see future perf sundry). Plan is to NOT pre-produce the wellbore. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: Reference MPU F-89 Sundry submitted in concert with this request for full details. General work scope of Pre-Rig work: 1. Slickline: Dummy WS drift 2. E-Line: Set whipstock 3. Fullbore: MITs Rig Work - (Estimated to start in June 2023): 1. MIRU and test BOPE to 4000 psi. MASP with gas (0.10 psi/ft) to surface is 3,888 psi a. Give AOGCC 24hr notice prior to BOPE test b. Test against swab and master valves (No TWC) c. Load pits with drilling fluid d. Open well and ensure zero pressure 2. Set 3-1/2” Packer Whipstock (only if unable to set pre-rig) a. Set top of whipstock at 11,490’ MD b. Set 10° ROHS 3. Mill 2.80” single string window (out of 7”) plus 10’ of rathole a. Top of window is top of whipstock (whipstock pinch point) b. Hold 12.6 ppg MPD while milling window 4. Drill – Build & Lateral a. 2-3/8” BHA with GR/RES / Bi-center Bit (3.25”) b. 32° DLS build section – 745’ MD / Planned TD 12,235’ MD c. 12° DLS lateral section – 1,099’ MD / Planned TD 13,334’ MD d. Drill with a constant bottom hole pressure for entire sidetrack e. Pressure deployment will be utilized f. After TD and on the last trip out of hole lay in completion/kill weight fluid in preparation for liner run g. No flow test prior to laying down drilling BHA PTD223-026 Sundry 323-169 p This completion WILL abandon the parent Kuparuk perfs. 5. Run and Cement 2-3/8” L-80 solid liner a. Have 2” safety joint with TIW valve ready to be picked up while running liner b. Release from liner and come out of hole. c. Make up cementing BHA and sting into liner shoe. Swap the well over to 2% KCl. d. Cement liner with 15.5 bbls, 15.3 ppg Class G (TOC to TOL).* e. Freeze protect well from ~2200’ TVD (min) f. RDMO Post Rig: 1. V: Valve & tree work 2. S: Set LTP* (if necessary) 3. C: Post rig perforate ~1000’ (see future perf sundry) 4. S: Set live LGLVs 5. T: Portable test separator flowback * Approved alternate plug placement per 20 AAC 25.112(i) Managed Pressure Drilling: Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of the WC choke. Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will be accomplished utilizing 3” (bighole) & 2-3/8” (slimhole) pipe/slip rams (see attached BOP configurations). The annular preventer will act as a secondary containment during deployment and not as a stripper. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected: MPD Pressure at the Planned Window (11,490’ MD - 7,130’ TVD) Pumps On Pumps Off A Target BHP at Window (ppg)4,672 psi 4,672 psi 12.6 B Annular friction - ECD (psi/ft)402 psi 0 psi 0.035 C Mud Hydrostatic (ppg)3,189 psi 3,189 psi 8.6 B+C Mud + ECD Combined 3,591 psi 3,189 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 1,081 psi 1,483 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 4,600 psi at 7,125’ TVD (12.4 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3,888 psi (from estimated reservoir pressure). (12.4 ppg equivalent) Mud Program: Drilling: Minimum MW of 8.4 ppg KCL with Geovis for drilling. Managed pressure used to maintain constant BHP. KWF will be stored on location. The tankage will contain 1.5 wellbore volumes of KWF to exceed the maximum possible BHP to be encountered as the lateral is drilled. Adjust with real time BHP monitoring. Completion: A minimum MW 8.4 ppg KWF to be used for liner deployment. Will target 12.6 ppg to match managed pressure target. Disposal: All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. Fluids >1% hydrocarbons or flammables must go to GNI. Fluids >15% solids by volume must go to GNI. Fluids with solids that will not pass through 1/4” screen must go to GNI. Fluids with PH >11 must go to GNI. Hole Size: 3.25” hole for the entirety of the production hole section. Liner Program: 2-3/8”, 4.6#, L-80 solid/cemented liner: 11,200’ MD – 13,334’ MD (2,134’ liner) The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Well Control: BOP diagram is attached. MPD and pressure deployment is planned. Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. The annular preventer will be tested to 250 psi and 2,500 psi. 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. A X-over shall be made up to a 2” safety joint including a TIW valve for all tubulars ran in hole. 2” safety joint will be utilized while running solid or slotted liner. The desire is to keep the same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint with pre- installed TIW valve). When closing on a 2” safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Directional: Directional plan attached. Maximum planned hole angle is 94°. Inclination at kick off point is 15°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line – 20,695’ Distance to nearest well within pool – 800’ Logging: MWD directional, Gamma Ray, and Resistivity will be run through the entire open hole section. Real time bore pressure to aid in MPD and ECD management. Perforating: ~1000’ perforated post rig – See future perf/frac sundry. If deemed necessary, the rig will perforate under this PTD (1-11/16” Perf Guns at 6 spf). Anti-Collision Failures: All wells pass AC with WP02. Hazards: The highest recorded H2S well on the pad was from MPU F-69 (47 ppm) in 2009. Last recorded H2S on MPU F-89 was 2 ppm in 2012. One fault crossing expected. Medium lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer (907-223-3087) Joseph Lastufka 4,000 _____________________________________________________________________________________ Created By: JNL 2/23/2023 PROPOSED SCHEMATIC Milne Point Unit Well: MPU F-89 Last Completed: 8/20/2005 PTD: 205-090 GENERAL WELL INFO API: 50-029-23268-00-00 Drilled, Cased & Completed by Doyon 14 - 8/20/2005 Perforate – 3/6/2015 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 113' 10-3/4" Surface 45.5 / L-80 / BTC 9.950 Surface 6,723’ 7-5/8" Intermediate 29.7 / L-80 / BTC Mod 6.875 Surface 11,186’ 5-1/2” Liner 17 / L-80 IBT-M 4.892 11,072’ 11,528’ 3-1/2” Liner 9.2 / L-80 / IBT 2.992 11,015’ 11,795’ TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TC-II 3.958 Surface 11,022’ JEWELRY DETAIL No Depth Item 1 2,992’ 4-1/2” HES X-Nipple w/ MCX .656 Bean Installed on 7/13/2013 2 10,966’ 4-1/2” HES X-Nipple ID= 3.813” 3 10,986’ 7-5/8”x4.5”Baker S-3 Permanent Packer 4 11,010’ 4-1/2” HES XN-Nipple ID= 3.725” No Go 5 11,015’ 7-5/8” x 5.5” Baker Tie Back Sleeve 6 11,022’ WLEG 7 11,026’ 7-5/8” x 5.5” Baker ZXP Liner Packer 8 11,032’ 7-5/8” x 5.5” Baker HMC Liner Hanger 9 11,072’ 7-5/8” x 5.5” Baker Tie Back Sleeve 10 11,083’ 7-5/8” x 5.5” Baker ZXP Liner Packer 11 11,090’ 7-5/8” x 5.5” Baker HMC Liner Hanger 12 11,490’ Whipstock PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. C Sands 11,471’ 11,511’ 7,111’ 7,149’ 40 3/6/2015 Open Kup. B Sands 11,514’ 11,534’ 7,152’ 7,171’ 20 3/6/2015 Open Kup. A3/A2 Sands 11,551’ 11,588’ 7,188’ 7,223’ 37 3/6/2015 Open Kup. A1 Sands 11,592’ 11,603’ 7,227’ 7,238’ 11 12/22/2005 Open Kup. A1 Sands 11,603’ 11,623’ 7,238’ 7,257’ 20 1/6/2006 Open Kup. A1 Sands 11,623’ 11,643’ 7,257’ 7,277’ 20 1/1/2006 Open TD =11,795’ (MD) / TD = 7,424’(TVD) 20” Orig. KB Elev.: 45.18’/ GL Elev.: 11.5’ 7” 3 5, 7 & 86 12 10.75” Howco ES Cementer @ 2,785 MD 10-3/4” 1 2 Whipstock set @ 11,490’ PBTD =11,761’(MD) / PBTD = 7,391’(TVD) 4 Kuparuk Sands 5-1/2” 3-1/2” 9, 10 & 11 TREE & WELLHEAD Tree 4-1/16” 5M FMC Wellhead 11” 5M FMC ZGen 5 w/ 11” x 4.5” FMC Tbg. Hng. w/ 4.5” TC-II & 4” CIW ‘H’ BPV Profile OPEN HOLE / CEMENT DETAIL 42" 260 sx of Arcticset (Approx.) 13-1/2" 658 sx ASL, 644 sx Class ‘G’ 9-7/8” 275 sx Class ‘G’ 6-3/4” 79 sx Class ‘G’ 4-3/4” 123 sx Class ‘G’ WELL INCLINATION DETAIL KOP @ 600’ Max Hole Angle = 60 to 68 deg. f/ 5,050’ to 9,800’ _____________________________________________________________________________________ Created By: JNL 2/23/2023 PROPOSED SCHEMATIC Milne Point Unit Well: MPU F-89A Last Completed: TBD PTD: TBD GENERAL WELL INFO API: 50-029-23268-01-00 Drilled, Cased & Completed by Doyon 14 - 8/20/2005 A Sidetrack CDR2: TBD PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status JEWELRY DETAIL No Depth Item 1 2,992’ 4-1/2” HES X-Nipple w/ MCX .656 Bean Installed on 7/13/2013 2 10,966’ 4-1/2” HES X-Nipple ID= 3.813” 3 10,986’ 7-5/8”x4.5”Baker S-3 Permanent Packer 4 11,010’ 4-1/2” HES XN-Nipple ID= 3.725” No Go 5 11,015’ 7-5/8” x 5.5” Baker Tie Back Sleeve 6 11,022’ WLEG 7 11,026’ 7-5/8” x 5.5” Baker ZXP Liner Packer 8 11,032’ 7-5/8” x 5.5” Baker HMC Liner Hanger 9 11,072’ 7-5/8” x 5.5” Baker Tie Back Sleeve 10 11,083’ 7-5/8” x 5.5” Baker ZXP Liner Packer 11 11,090’ 7-5/8” x 5.5” Baker HMC Liner Hanger CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 113' 10-3/4" Surface 45.5 / L-80 / BTC 9.950 Surface 6,723’ 7-5/8" Intermediate 29.7 / L-80 / BTC Mod 6.875 Surface 11,186’ 5-1/2” Liner 17 / L-80 IBT-M 4.892 11,072’ 11,528’ 3-1/2” Liner 9.2 / L-80 / IBT 2.992 11,015’ 11,795’ 2-3/8” Liner 4.6 / L-80 / Hyd 511 1.995 11,200’ 13,334’ TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TC-II 3.958 Surface 11,022’ TD =13,334’ (MD) /TD =7,259’(TVD) 20” Orig. KB Elev.: 45.18/ GL Elev.: 11.5’ 7” 3 5, 7 & 86 10.75” Howco ES Cementer @ 2,785 MD 10-3/4” 1 2 Whipstoc k set @ 11,490’ Top of Window @11,490’ Top of Liner / Cement @11,200’ PBTD =13,284’(MD) / PBTD =7,256’(TVD) 4 2-3/8” 5-1/2” 3-1/2” 9, 10 & 11 TREE & WELLHEAD Tree 4-1/16” 5M FMC Wellhead 11” 5M FMC ZGen 5 w/ 11” x 4.5” FMC Tbg. Hng. w/ 4.5” TC-II & 4” CIW ‘H’ BPV Profile OPEN HOLE / CEMENT DETAIL 42" 260 sx of Arcticset (Approx.) 13-1/2" 658 sx AS Lite, 644 sx Class ‘G’ 9-7/8” 275 sx Class ‘G’ 6-3/4” 79 sx Class ‘G’ 4-3/4” 123 sx Class ‘G’ 3-1/4” 70 sx Class G WELL INCLINATION DETAIL KOP @ 11490’ 90 deg Hole Angle = 11,790’ Well Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 2.75 ft C L Annular 3.40 ft Bottom Annular 4.75 ft CL Blind/Shears 6.09 ft CL 2.0" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip 9.54 ft CL 2.0" Pipe / Slips 10.40 ft TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR2-AC BOP Schematic CDR2 Rig's Drip Pan Fill Line from HF2 Normally Disconnected 3" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2.0" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2.0" Pipe/Slips 2-3/8" Pipe / Slip Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 223-026 MILNE POINT KUPARUK RIVER OIL MPU F-89A WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT F-89AInitial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230260MILNE POINT, KUPARUK RIVER OIL - 525100NA1 Permit fee attachedYes Surface Location lies within ADL0025509; Portion of Well Passes Thru ADL0355018;2 Lease number appropriateYes Top Prod Int & TD lie within ADL0355017.3 Unique well name and numberYes Milne Point, Kuparuk River Oil Pool, governed by CO 432E.4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes Only parent wellbore F-89 that will be abandoned by the completion for F-89A.15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes This well is an inzone sidetrack with a parent well with approved integrity.18 Conductor string providedYes This well is an inzone sidetrack with a parent well with approved integrity.19 Surface casing protects all known USDWsYes This well is an inzone sidetrack with a parent well with approved integrity.20 CMT vol adequate to circulate on conductor & surf csgYes This well is an inzone sidetrack with a parent well with approved integrity.21 CMT vol adequate to tie-in long string to surf csgYes This well is an inzone sidetrack with a parent well with approved integrity.22 CMT will cover all known productive horizonsYes This well is an inzone sidetrack with a parent well with approved integrity.23 Casing designs adequate for C, T, B & permafrostYes CDR2 has adequate tankage an dgood trucking support24 Adequate tankage or reserve pitYes Approved sundry 323-16925 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no collision risk26 Adequate wellbore separation proposedNA This well is an inzone sidetrack with a parent well with approved integrity.27 If diverter required, does it meet regulationsYes MPD utilized to maintain overbalance while drilling. KWF utilized for liner running28 Drilling fluid program schematic & equip list adequateYes 1 CT packoff, 1 annular, 4 ram CT, 2 flow cross29 BOPEs, do they meet regulationYes 5000 psi stack tested to 4000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo Highest hts recorded on MPU F pad 47 ppm33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No Measured required. F-Pad wells are H2S-bearing.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected reservoir pressure is 12.4 ppg EMW. Well will be drilled with 8.4 ppg mud using36 Data presented on potential overpressure zonesNA Managed Pressure Drilling technique to maintain an equivalent circulating density of 12.6 ppg EMW to37 Seismic analysis of shallow gas zonesNA mitigate expected reservoir pressure.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/28/2023ApprMGRDate6/2/2023ApprSFDDate5/28/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 06/05/2023JLC 6/5/2023