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224-018
DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 7 3 3 - 2 0 7 1 9 - 0 0 - 0 0 We l l N a m e / N o . TR A D I N G B A Y U N I T M - 2 3 Co m p l e t i o n S t a t u s SU S P Co m p l e t i o n D a t e Pe r m i t t o D r i l l 22 4 0 1 8 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 11 2 9 6 TV D 87 0 5 Cu r r e n t S t a t u s SU S P 7/ 2 3 / 2 0 2 5 UI C No We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : CB L 5 / 1 / 2 4 , G e o t a p , L W D ( D G R , A D R , C T N , A L D , P W D , D D S R ) No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 5/ 1 3 / 2 0 2 4 59 5 2 1 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : T B U _ M - 23 _ C B L _ 1 - M a y - 2 0 2 4 _ ( 4 8 1 7 ) . l a s 38 7 9 1 ED Di g i t a l D a t a DF 5/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : T B U _ M - 2 3 _ C B L _ 1 - M a y - 20 2 4 _ ( 4 8 1 7 ) . p d f 38 7 9 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U _ M - 23 _ G e o T a p _ P r e s s _ T e s t s . d l i s 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U _ M - 23 _ G e o T a p _ P r e s s _ T e s t s . v e r 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 G e o - T a p P r e s s u r e Te s t s . c g m 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 G e o - T a p P r e s s u r e Te s t s . e m f 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 G e o - T a p P r e s s u r e Te s t s . p d f 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 G e o - T a p P r e s s u r e Te s t s . t i f 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 8 i n - 1 2 . 2 5 i n H o l e Se c t i o n G e o t a p R e p o r t . p d f 38 8 1 0 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 47 8 1 1 2 9 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 : T B U M - 2 3 L W D Fi n a l . l a s 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l M D . c g m 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l T V D . c g m 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 - D e f i n i t i v e S u r v e y Re p o r t . p d f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 - D S R _ G e o . t x t 38 8 1 1 ED Di g i t a l D a t a We d n e s d a y , J u l y 2 3 , 2 0 2 5 AO G C C P a g e 1 o f 3 TB U M - 2 3 L W D Fi n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 7 3 3 - 2 0 7 1 9 - 0 0 - 0 0 We l l N a m e / N o . TR A D I N G B A Y U N I T M - 2 3 Co m p l e t i o n S t a t u s SU S P Co m p l e t i o n D a t e Pe r m i t t o D r i l l 22 4 0 1 8 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 11 2 9 6 TV D 87 0 5 Cu r r e n t S t a t u s SU S P 7/ 2 3 / 2 0 2 5 UI C No We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : 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 : Re l e a s e D a t e : 3 / 1 8 / 2 0 2 4 DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 - D S R _ G I S . t x t 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 - F i n a l S u r v e y s . x l s x 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 _ D S R A c t u a l _ P l a n . p d f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 _ D S R A c t u a l _ V S e c . p d f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l M D . e m f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l T V D . e m f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l M D . p d f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l T V D . p d f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l M D . t i f 38 8 1 1 ED Di g i t a l D a t a DF 5/ 1 6 / 2 0 2 4 E l e c t r o n i c F i l e : T B U M - 2 3 L W D F I n a l T V D . t i f 38 8 1 1 ED Di g i t a l D a t a 00 19 3 6 We d n e s d a y , J u l y 2 3 , 2 0 2 5 AO G C C P a g e 2 o f 3 No s a m p l e s f r o m t h i s w e l l DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 7 3 3 - 2 0 7 1 9 - 0 0 - 0 0 We l l N a m e / N o . TR A D I N G B A Y U N I T M - 2 3 Co m p l e t i o n S t a t u s SU S P Co m p l e t i o n D a t e Pe r m i t t o D r i l l 22 4 0 1 8 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 11 2 9 6 TV D 87 0 5 Cu r r e n t S t a t u s SU S P 7/ 2 3 / 2 0 2 5 UI C No Co m p l i a n c e R e v i e w e d B y : Da t e : We d n e s d a y , J u l y 2 3 , 2 0 2 5 AO G C C P a g e 3 o f 3 7/ 2 3 / 2 0 2 5 M. G u h l Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 04/30/2025 InspectNo:susJDH250408192228 Well Pressures (psi): Date Inspected:4/4/2025 Inspector:Josh Hunt If Verified, How?Other (specify in comments) Suspension Date:5/4/2024 Tubing:5 IA:80 OA:475 Operator:Hilcorp Alaska, LLC Operator Rep:Brad Blossom Date AOGCC Notified:3/25/2025 Type of Inspection:Initial Well Name:TRADING BAY UNIT M-23 Permit Number:2240180 Wellhead Condition The well head was in very good condition. The cellar area was difficult to get a picture of due to so many other wells stacked aound it. All the valves and gauges were in good working condition. Surrounding Surface Condition The well bay area on both levels was very clean and well kept. Condition of Cellar Very clean and well kept but congested. Comments The only verification I could find was the well names listed on a board in the control room and a painted on number on each individual well. Supervisor Comments Photos (6) attached Suspension Approval:Completion Report Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Wednesday, April 30, 2025 2025-0404_Suspend_TBU_M-23_photos_jh Page 1 of 3 Suspended Well Inspection – TBU M-23 PTD 2240180 AOGCC Inspection Rpt # susJDH250408192228 Photos by AOGCC Inspector Josh Hunt 4/4/2025 IA pressure gauge TBU M-23 2025-0404_Suspend_TBU_M-23_photos_jh Page 2 of 3 Tubing pressure gauge Well Room (Platform Leg) Congestion 2025-0404_Suspend_TBU_M-23_photos_jh Page 3 of 3 Outer Annuli pressure gauges Well Cellar 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): McArthur River GL:N/A BF:N/A Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 187' (ft MSL) 22. Logs Obtained: 23. BOTTOM 28" - 480' 13-3/8" L-80 1,613' 9-5/8" L-80 3,790' 4-1/2" L-80 8,699' 4-1/2" L-80 3,571' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): Surface 6,150' Surface ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 550 sx8-1/2" TUBING RECORD Tieback Assy. 5,969' L - 1033 sx / T - 172 sx Surface 12-1/4" Tieback 17-1/2" Driven Surface L - 1020 sx / T - 370 sx 12.6# Surface 5,919' 1,700' 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 214240 2499432 50-733-20719-00-00March 24, 2024 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 5/4/2024 224-018 / 324-224 / 324-196 N/A TBU M-23April 25, 20241067' FNL, 624' FWL, Sec 33, T9N, R13W, SM, AK 160' BOTTOMCASINGWT. PER FT.GRADE CEMENTING RECORD N/A SETTING DEPTH TVD 2504742 TOP HOLE SIZE CBL 5/1/24, Geotap, LWD ( DGR, ADR, CTN, ALD, PWD, DDSR) Middle Kenai Gas Pool ADL 18730 Date of Test: Oil-Bbl: N/A Gas-Oil Ratio: AMOUNT PULLED N/A 215164 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. PACKER SET (MD/TVD) Surface Conductor 12.6# N/A N/A 565' MD / 565' TVD 11,296' MD / 8,705' TVD 6,000' MD / 3,594' TVD N/A 1015' FNL, 1428' FWL, Sec 28, T9N, R13W, SM, AK Choke Size: Surface Per 20 AAC 25.283 (i)(2) attach electronic information 47# 11,290' Surface 3,535' 262# 68# 480' Water-Bbl: PRODUCTION TEST N/A - Future Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl:Flow Tubing WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 3:53 pm, Jul 29, 2024 Suspended 5/4/2024 JSB RBDMS JSB 080524 GDSR-8/27/24SFD 6/23/2025 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval N/A N/A 1474' 1432' 3551' 2492' 3843' 2605' 5213' 3173' 6290' 3839' 6683' 4210' 8790' 6262' 10016' 7456' 11031' 8446' 11247' 8657' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Digital Signature with Date:Contact Email:cdinger@hilcorp.com Contact Phone: 907-777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. G1 B1 SZ 10 C1 F1 SZ 24 A1 Formation Name at TD: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. INSTRUCTIONS G-05 D1 E1 Wellbore Schematic, Drilling Reports (Completion Not Executed), Definitive Directional Surveys, Csg and Cmt Reports Authorized Title: Drilling Manager No NoSidewall Cores: Yes No Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Drilling Manager 07/29/24 Monty M Myers Tyonek _____________________________________________________________________________________ Updated by CJD 7-15-24. PROPOSED SCHEMATIC McArthur River Well: TBU M-23 PTD: 224-018 API: 50-733-20719-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 28"Conductor 262 / - / Weld 27”Surf 480’ 13-3/8”Surface 68 / L-80 / BTC 12.415”Surf 1,700’ 9-5/8"Intermediate 47 / L-80 / DWC/C / TXP 8.861”Surf 6,150’ 4-1/2"Production 12.6 / L-80 /TXP 3.958”5,919’11,290’ Tieback Detail 4-1/2”Tieback 12.6 / L-80 / Hyd 533 3.958”Surface 5,969’ OPEN HOLE / CEMENT DETAIL 13-3/8”Est. TOC @ surface L – 435 bbls (100% OH excess) / T – 76 bbls 9-5/8"Est. TOC @ surface L – 438 bbls (40% OH excess) / T – 35 bbls 4-1/2” TOC @ ±10,700 L – 220 bbls pumped, dart failure and released early. Roughly 35 bbls (600’) of cement made it to the backside of the 4-1/2” Liner. The remaining cement is inside the 4-1/2” TOC @ ~6,000’ MD. JEWELRY DETAIL No.Depth Item 1 565’SSSV 2 2,247’GLM 3 4,371’GLM 4 5,912’GLM 5 5,929’X Nipple 3.813” Profile 6 5,959’Seal Stem 7 5,919’Liner hanger / LTP Assembly Page 1/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:3/15/2024 End Date:5/4/2024 Report Number 1 Report Start Date 3/15/2024 Report End Date 3/16/2024 Operation Clean and organize in N/W upper well bay room. Work on clogged rig floor drains. Build soap pill as per HES Mud Rep; flush through lines from pits to trip tank 1 & 2. Flush through all valves and pumps on trip tank. Rig electrician disconnect power f/ top drive VFD in preparation to skid. Rig up Pollard Wireline unit; rig up lubricator to well M-01. Test to 2,500psi- good. RIH W/ 3.5" GS and 5' prong to 418' WLM, Latch SSSV and pooh with same. RIH with 2.75" swedge and drift to 1,500' WLM; No obstruction. POOH, R/D from M-01 well. Clean trip tanks from flush. Assist welder in w elding Victaulic hinge in mud pit 4. Pollard M/U lubricator to Well M-05. Test to 2,500psi- good. RIH w/ 3.5" GS with 5' prong to 442' WLM. Latch SSSV, POOH with same. M/U 2.80" gauge ring and RIH T/1,500' WLM; No obsructions. POOH, R/D from M-05 well. Cont. cleaning drains under rig floor. Remove air hoist from upper well bay on Leg B-1 and move to cellar deck. Continue circulate soap pill through mud system lines. Pollard R/U on M-04 well. M/U and RIH with 3.77" gauge ring to 1,500' WLM; No obstructions. POOH and R/D Pollard wireline unit. Clean in cellar deck area, Circulate and flush mixing lines to all pits. Finnish cleaning drains from rig floor. Remove wireline work platform and two section of well covers from leg B-2. Install air hoist in Leg B-2 upper well bay. Stage 20" riser, 20" spool, and DSA into upper well bay. Clean in cellar deck. Clean mud pits after flushing thorugh lines. Lower accumulator lines, mud lines, water lines and start installing to piping in Upper well bay on B-2 leg in preparation for skidding rig to well bay. Continue cleaning mud pit system in preparation to build spud mud. Report Number 2 Report Start Date 3/16/2024 Report End Date 3/17/2024 Operation Rebuild accumulator Pump #1. Offload bara-clean rinse pill to ISO & send to G&I. Prep upper section of rig to skid. Welder finish covering patches in drain line from drain repairs. Move north diverter line in for skidding. Thaw and prep 21-1/4" diverter for bell nipple air boot. Remove derri ck wind sock mount and welder repair. Skid upper section of rig to center and past 2.5' to clear crane. Secure same. Install air controls for Water flood and fire w ater valves in driller console. Assist AK E-line in R/U & Gyro M-04, M-01. Take Gyro surveys every 30' on each well to ±850' ELM. AK E-line continue Gyro M-01 & M-05. Take Gyro surveys every 30' on each well to ±850' ELM. R/D AK E-line. Assist HES cementers in rigging up lines on unit, taking on drill water and test CMT unit. Install Boot flange on top of 21-1/4" Annular. Assit in R/U Pollard wireline unit. R/U on M-05; Test riser to 2,500psi- good. RIH with 3" X-line, 6' prong and SSSV, purge con trol line W/ diesel, set SSSV. Pump 3-4 gallon diesel and pressure up to shear off SSSV. Attempt to set mulitple times to pressure up SSSV with no success. RIH w/ 3-1/2" GS and 6' prong to 442' WLM. Latch SSSV, POOH. R/D wireline. Pollard wireline timed out; shut down to reset. Remove 20" riser section from NE well bay, bring to rig floor. Test run through derrick and rotary to verify fitment- good. Fin ish installing washing up line from HES CMT unit to SE leg. Cont preparing rig package for skidding operations. Continue building spud mud. Stage starter head and flange in upper NE well bay. Report Number 3 Report Start Date 3/17/2024 Report End Date 3/18/2024 Operation Clean in cellar deck area. Drain glycol lines and install in NE well bay room. R/U Pollard wireline on M-05 well. Test lubricat or to 2,500psi- good test. RIH w/ 3' X-line, 6' proxy and SSSV to 442' WLM. Purge control line w/ diesel, sheared x-line and set valve. POOH. R/U on well M-01. Test lubricator to 2,500psi- good test. RIH w/ 3" X-line, 6' proxy, and SSSV. Set vavle at 418' MWL. POOH. R/D Pollard wireline. Blow down all service lines with air. Install wind sock at Derrick crown section. Secure BOPE in substructure. Assist electrician in disabling control power to rig package. Remove skidding storm clamps and install guides. Continue assist electrician in disconnecting pwer cables and securing same. Move equipment and materials from skidding area. Skid rig package F/NW leg - T/NE leg. Stop at North crane and install diverter line back on sub base. Continue skid rig package F/NW leg - T/NE leg. Swap skid cylinders and clamps from NE side of rig to NW side in preparating to skid center over NE leg. Swap skid cylinders and clamps F/NE - T/NW side of rig. Continue skidding rig towards NE leg. Remove storm clamps on transverse beams. Transverse rig floor to center over well M-23. Report Number 4 Report Start Date 3/18/2024 Report End Date 3/19/2024 Operation Install storm clamps on upper drilling package. Install handrails over all open areas after skidding. Assist rig electrician in installing rig control power to NE well junction panel. Install rig air and steam to manifold in NE upper wellhead room. Continue build spud mud as per HES mud rep. Assist rig electrician in hooking up rig control power. Build spud mud, Install 4" Tee assembly on conductor outlets. Install lower pressure mud, drill water, glycol, and cement line to rig floor package. Spot pipe skate in preparation to rig up to floor. Install HP mud line and deluge lines to rig floor. Open Glycol lines to circulate in drilling package. Assist rig electrician i n ensuring equpiment runs correctly on rig floor. R/U and install wellhead adapter flange on conductor. Continue building spud mud as per HES rep. Cont installing 20-3/4" riser, DSA, on well M-23 conductor. Install work platforms in cellar deck. Remove job boxes from cellar in preparation to transfer diverter Tee and annular to well center. Transfer drill water from platform to upright tanks. Remove skid jacks from skid rails and store same. Report Number 5 Report Start Date 3/19/2024 Report End Date 3/20/2024 Operation N/U 21-1/4" diverter system. Install 16" diverter lines to mud cross, Install 21-1/4" annular to top of mud cross and clamp same. Torque all bolts to recommended specs. N/U 21-1/4" diverter system. Install 21-1/4" annular to top of mud cross and clamp same. Install North side 16" diverter pipe. Torque bolts to recommended specs from riser to spool, spool to DSA, and DSA to conductor wellhead flange. R/U Top drive VFD system. HES MWD rig up shack. Install 16" south side diverter line to mud cross adding extensions across deck to south side. Weight up spud mud to 9.2ppg. Offload MWD tools, DP, HWDP, and equipment from boat. Prep bottom of rotary pan flow box for upper bell nipple. Connect CMT service hose from well bay to drilling package. Weight up mud to 9.2ppg, adding 15ppb LCM. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51Permit to Drill (PTD) #: Page 2/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Install trip nipple boot adapter on flow box below rotary. Shim center of pipe skate. R/U dump shute on cellar deck. Cont. weighting up to 9.2ppg adding 15ppb LCM. Line up HP and low pressure lines for rig package to NE leg. Isolate service lines to NW leg. Install cuttings dump hose from shaker s to upper well bay. Report Number 6 Report Start Date 3/20/2024 Report End Date 3/21/2024 Operation Instal accumulator fittings to annular and diverter knife valves and install control lines to annular and diverter knife valves. Install overboard shute to rig and to overboard flange in NE upper well bay room. Weitght up spud mud to 9.2ppg adding 15ppb LCM. Clean centrifuge overboard line in pit room. Clean out flow line ditch and install flow line hose to ditch. Clean out centrifuge line, install overboard to same. Continue b uild 9.2ppg spud mud with 15ppb LCM. Insatll bell nipple and air up bladders. Clean and organize in pump room. Clean and organize in cellar deck. Change out broken prox switch on pipe skate. Install chain falls and supports to lower J-tube hose for cuttings chute. Cont. cleaning and organizing in pump room. Clean and organize around main deck, cellar deck, mezanine deck. Change 2" valves out on overboard sprayers for shakers, install same. Trace lines and verify line up for drill water and FIW wa ter for shakers.Continue cleaning up and saving tools around rig. Cont build 9.2ppg spud mud with 15ppb LCM. Test FIW water at shakers, verify dump chute hose is working properly- good. Cont building 9.2ppg spud mud. Cleaning and organizing around rig. Test water flood FIW line; found multiple leaks, Repair same. Test 2nd time, Tighten 4" hammer union connections. Backload boat with equipment. Clean solids from SW leg return ditch. Report Number 7 Report Start Date 3/21/2024 Report End Date 3/22/2024 Operation R/D rig up lines from top drive and install 5" elevators. Clean and organize on rig floor, BOP cellar and upper well bay. Clean south west flow line to pits. Continue built 9.2ppg spud mud. Torque bolts on diverter cross to 850 ft/lbs. R/U pipe skate to rig floor. Pipe skate not aligned with rig floor. L/D and adjust pipe skate frame to align with rig floor package. Cont. build spud mud as per HES Mud Rep. Conduct Pre spud meeting with all personnel @ 11:00 hrs. Insatll pipe skate to rig floor. Torque bolts on diverter cross to 850 ft/lbs. Function test Diverter system and accumulator- g ood. Test diverter function Red light to production control room- No joy, trouble shoot same. Repair broken wire and test same- good. Clean cellar of all tools and trash. Secure Diverter annular to substructure with chains and binders. Clean up around accumulator unit. Function test diverter system from dillers remote panel, NE and NW bruker remote stations- good test. Set support for extention section of diverter line on south side, flange up last diverter section. Install 3" line from SE mud return ditch to #14 upright mud tank. Change 3" and 4" hoses on Fire water and flood water on lower well room deck. Install 16" diverter extension on south side. Fun ction diverter with nightcrew for readiness. Conduct accumulator draw down test. Cont. build spud mud. Test flow sensor, trip tank alarm, and pit alarms. Insatll 2" diaphragm pump on slope tank under floor. Report Number 8 Report Start Date 3/22/2024 Report End Date 3/23/2024 Operation Install Wilden pump and hoses F/rig floor drain box to shakers. Replace bad drain line under rig floor. Assist mechanic in repa ir leak on 4" flood line in NE well bay. Work on rig acceptance checklist. Perform diverter function test, accumulator draw down test, CanRig PVT and flow show test, and perform test on Platform gas alarms- good test. All test witnessed by AOGCC Rep Sully Sullivan. Continue working on rig acceptance checklist. Build 50ppb LCM pills in pits. Move SRL F/NW wellhead room to NE wellhead room. Tighten diverter line clams on north and south lines. Install safety chains between pipe skate and rig floor. R/U vacuum lines and remove debris from SW return ditch. Test Deluge system in cellar deck- good. Tested 4" firewater outlet to M-23 conductor. Tested 3" FIW outlet to M-23 conductor. Change return hydraulic fittings on ST-80. Clean rig floor. Install new cable on breakout cathead. Perform flood test on diverter. 16" north diverter valve leaking. Attempt to tighten packing- no joy. Clean NE upper and lower well head room due to 4" fire hose to conductor partially parted, flooding room with drill water. Install gaitronics speaker in MWD shack. P/U and M/U 17 joints of 5" HWDP with jars from deck, drifting each joint with 2.78" drift, racking back in derrick. P/U and M/U 48 joints of 5" NC-50 DP from deck, drifting with 2.58" drift, rack back in derrick. Continue build 9.2ppg spud mud. Report Number 9 Report Start Date 3/23/2024 Report End Date 3/24/2024 Operation P/U off deck racking back in derrick 5" NC-50 DP, Drifting each joint with 2.58" drift. Calibrate block height with CanRig and HES MWD Rep. R/U and remove north side 16" knife valve from diverter due to leaking. Rig electrician troubleshoot top drive spin mode switch . Mount MWD screen in driller shack. Held Diverter and abandon drill with all personnel on platform in preparation to drill surface. Cont. changing out north side 16" diverter knife valve due to leak. Offload 13-3/8" CSG from boat, strap and drift same. Function test cuttings chute wash bar at shakers- good. Repair aluminum scaffolding in the cellar. Installed North 16" diverter valve on diverter line, unable to to tighten bolts sufficiently due to threads on valve. Decision made to install seco nd 16" knife valve. Conduct Diverter and abandon drill with all personnel on platform. Held after action review to discuss drill. Install 16" knife valve on the north diverter line. Attempted to flood test, valve leaking out end of diverter line as well as between valve and flange. Attempt to tighten bolts on valve. Observed bolt threads stripping. Remove valve and tap stripped threads. Clean corrosion and debris from threads. Remove 4" fire water hose from M-23 conductor. Remove 4" fig 200 connections from 4" hose and install on manufactured 4" hose. Install hose from fire main to M-23 conductor; function test system with 150-180psi- Good test. Finish tapping bolt holes on diverter valve. Install 16" knife valve on north diverter line. Clean and organize cellar deck. Organize equipment on deck. Report Number 10 Report Start Date 3/24/2024 Report End Date 3/25/2024 API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 3/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Finish insatll 16" knife valve on north diverter line. Attempted to flood test. Valve leaked out end of diverter and out of the line at valve itself. Gather tools for BHA and transfer to rig floor. Platform mechanic start changing seal on spare 16" knife valve. Remove north side diverter valve while platform mechanic changes -ring seal in spare valve. P/U wash out asssembly as per HES DD, 8" flex collars, stab, UBHO, bit sub and 17.5" rollar cone bit, TIH T/46' MD. Platform mechanic continue to rebuild 16" knife valve. Finish rebuilding and install north 16" diverter knife valve. Torque bolts on 16" knife valve on north diverter line. Flood test diverter. Small leak at valve. Retorque bolts- good. RIH with cleanout assembly, 2 stds 5" HWDP and 5" DP out derrick F/46' tagging @ 372' MD. Displace conductor T/ 9.2ppg spud mud at 168gpm= 500psi, catching returns into sand traps, (perform sheen test- good.) dump sand traps through cuttings chute. Continue displace conductor T/ spud mud unitl clean mud back at surface. Note: check stroke counters and pressure gauges, and monitoring system to verify working during circulation. Wash out and drill cmt in conductor F/372' - T/413' MD. 513gpm= 400psi, 50RPM= 1-2Kft-lbs TRQ, WOB-2-10K, F/O=43%. Wash out and drill cmt in conductor F/413' -T/442' MD. 512gpm- 395psi, 60RPM= 1-2Kft-lbs TRQ, WOB= 0-10K, F/O=43%. CBU 1x staging pumps up F/512gpm with 395psi - T/746gpm= 785psi to verify maximum flow rate. Test HP mud lines F/ mud pumps to Top drive with 2,900psi- good. Rig electrician change out #2 mud pump Rheostat pot. R/U AK E-line and Gyro services. RIH to 425' ELM, Taking shots every 60' to survey deviation prior to drilling out. POOH and R/D E-line. Change out #2 mud pump rheostat pot and test- good. POOH racking back 5" NC-50 DP and HWDP F/442'. L/D cleanout assembly. Monitor well on trip tank for proper displacements. P/U directional assembly, 17-1/2"tricone bit, 9-5/8" terraforce motor with a 1.83° bend, DM/TM collars as per HES DD/MWD F/surface - T/58.81'. Scribe same. Daily discharge: 336 bbls Cum Discharge: 385.5 bbls Daily DH Losses: 0 bbls Cum DH Losses: 0 bbls Daily Metal: 0.0 lbs Total Metal: 0.0 lbs Report Number 11 Report Start Date 3/25/2024 Report End Date 3/26/2024 Operation P/U directional assembly, 17-1/2" tricone, motor with 1.83° bend, DM/TM collars, UBHO, stab and flex. RIH T/97'. R/U AK E-line sheaves and line in derrick to survey while drilling. Trip in hole with 17.5" directional assembly on 5" HWDP and 5" NC-50 DP F/ derrick F/97' - T/370' MD. Monitor well on trip tank for proper displacements. E-line RIH with gyro to orienate motor, POOH. Cont. trip in hole to tag with 10K down at 438' MD. Observed 4' of fill. Trouble shoot Mud pump #2 stroking issue. Found loose wire on rheostat pot. repair same. Wash down and drill cmt F/438' - T/470' MD. 550gpm= 1400psi, 50RPM= 1-2Kft-lbs TQ, 0-3K WOB, F/O=43%. Observed hard spot at 462' MD. CBU 1x, hole unloading with cuttings. Slide/Drill 17.5" Surface Section F/470' - T/715' MD, taking survey's with Gyro services every 30' to reduce anticollision uncertainty. Total 245’ (AROP 41’) 650gpm = 1,300psi with 4-8K WOB, 9.5ppg MW, F/O = 48%. 50RPM = 1-3Kft-lbs TQ. P/U=90K, S/O=90K, ROTW=87K. Monitoring well on trip tank during survey operations. Slide/Drill 17.5" Surface Section F/715' - T/961' MD, taking survey's with Gyro services every 30' to reduce anticollision uncertainty. Total 246’ (AROP 41’) 650gpm = 1,300psi with 4-8K WOB, 9.4ppg MW, F/O = 48%. 50RPM = 1-3Kft-lbs TQ. P/U=90K, S/O=90K, ROTW=87K. Monitoring well on trip tank during survey operations. Slide/Drill 17.5" Surface Section F/961' - T/1018' MD, taking survey's with Gyro services every 30' to reduce anticollision uncertainty. Total 57’ (AROP 38’) 650gpm = 1,300psi with 4-8K WOB, 9.4ppg MW, F/O = 48%. 50RPM = 1-3Kft-lbs TQ. P/U=90K, S/O=90K, ROTW=87K. Monitoring well on trip tank during survey operations. CBU 1.5x, 640gpm, 1,250psi, Working F/1,018' - T/926' MD. Flow check well for 10 min- good. Pump 700gpm with 1,300psi pulling out of hole racking 5" DP in derrick F/1,018' T/ 364' MD to assist in cleaning hole due to inssuficient flow rates while drilling. CBU 1x 700gpm with 1,086psi to clean conductor of cuttings due to shakers loading up. Flow check well for 10 min- good. Pull 5" HWDP racking back in derrick F/346' MD to change out TM and P/U res tool. Daily discharge: 438 bbls Cum Discharge: 823.5 bbls Daily DH Losses: 0 bbls Cum DH Losses: 0 bbls Daily Metal: 8.0 lbs Total Metal: 8.0 lbs Report Number 12 Report Start Date 3/26/2024 Report End Date 3/27/2024 Operation P/U 17.5" BHA #3 f/45' t/83'. monitoring displacement on thhe TT. Program Haliburton tool. Static loss rate=.75bph. Cont. P/U BHA #3 f/83' t/126'. TIH with 17.5" BHA #3 f/126' t/431', 24k below jars. Monitoring displacement on the TT. R/U AK E-line wire and sheave in derrick. TIH with 17.5" BHA #3 f/431' t/955'. Monitoring displacement on the TT. Fill pipe and stage up pumps t/700gpm, 1400psi, 50rpm, 2-4k trq. Wash and ream f/95' t/1018'. Drilling 17.5" hole f/1018' t/1064' with 700gpm, 1400psi, 50rpm, 49% flow. Rotating and slding as per DD. P/U=92k, S/O=90k, Ro t=90k. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 4/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Drill/slide/survey 17.5" hole f/1064' t/1329' as per DD/wp, 700gpm, 1200psi, 50rpm, 3-4k trq, 12-16k wob, 49% flow, 75-100rop, p/u=95k, s/o=90k, rot=87k. Utilizing Gyro-AK E-line for survey every 30ft. Drill/slide/survey 17.5" hole f/1329' t/1539' as per DD/wp, 740gpm, 2000psi, 50rpm, 1-2k trq, 16-20k wob, 49% flow, 75-100rop, p/u=100k, s/o=95k, rot=95k. Utilizing Gyro-AK E-line for survey every std. Trouble shoot issue with #2 mud pump controls @ drillers console-pump failed to start. Drill/slide/survey 17.5" hole f/1539' t/1710' as per DD/wp, 740gpm, 1450psi, 50rpm, 1-2k trq, 16-20k wob, 49% flow, 75-100rop, p/u=100k, s/o=95k, rot=95k. Utilizing Gyro-AK E-line for survey every std. Pump 65bbl LCM/hi-vis sweep w/walnut for a marker. Circulate out marker sweep and figure washout (57.4bbl washout). Cont. circ. shakers clean. Report Number 13 Report Start Date 3/27/2024 Report End Date 3/28/2024 Operation Pump 65bbl LCM/hi-vis sweep w/walnut for a marker. Circulate out marker sweep and figure washout (57.4bbl washout). Cont. circ. shakers clean. Monitor well-static. Pump out of the hole f/1,710’ t/370’ @ 750gpm, 1400psi, work thru tight spots @1428’/ 894’-873’. Circulate conductor clean @370’-310’ w/780gpm/1200psi/50rpm. Flow check-well static. RIH t/1,710’ monitoring displacement on the TT, tagging bottom at 1,706’ w/4ft fill-clean to bottom. Work thru tight spots @1,428’-1,494’. BROOH t/1,142’, 700gpm, 1500psi, 40rpm, 2k trq. Heavy returns @1,142’-1,049’-circulate clean. Cont. BROOH t/380’ w/same parameters, mad passed from 495’-435’ as per MWD. L/D BHA #3 as per DD/MWD, down load MWD, clean and clear rig floor. R/U to run 13-3/8" surface casing. P/U elevators/bail ext./power tongs/slips/dog collar, r/u fill up line/ expedite bowsprings to rig floor. Run 13-3/8" 68# BTC, L-80 surface casing as per tally. P/U shoe track backer lock connections, check floats-good, install bowspring centralizers as per tally. Report Number 14 Report Start Date 3/28/2024 Report End Date 3/29/2024 Operation P/U 13-3/8", 68#, L-80, BTC thread surface casing. M/U shoe jt to spacer jt and fill w/mud and check float-good. Cont. p/u float collar and m/u to shoe track, fill w/mud and check floats-good. Install centralizers as per tally t/133". Blow down top drive and mud lines to pits. Adjust brakes on draw works. Cont. running casing as per tally f/133' t/428' in stalling centralizers and monitoring displacement on the TT. Cross thread jt#8, break out and l/d jts 7 & 8. Remove bail extensions. P/U 2 jts to replace 7 & 8, re-install centralizers. Cont. running 13-3/8", 68#, L-80, BTC thread surface casing f/471' t/1700', monitoring displacement on the TT. Installing centr alizers as per tally. (14 total) Avg trq=8k ft/#. p/u=160k, s/o=120k, broke over @180k. Circulate and condition mud for cementing, reciprocating f/1685' t/1700', 400gpm, 100psi, tagging hanger every 3X. M/U cement stinger t/5' pup w/bowspring centralizer. Trip in the hole w/5" DP and false table t/1610'. M/U side entry circ. sub w/10' pup and cement line and kelly up. Pressure test cement line f/ cement unit to low trq on side entry pump in sub on cement std. 300psi-good, 1500psi-good, 3500psi -good. S/O and engage stinger into float collar and set 26k dwn, f/75k s/o wt. t/block wt. Start cement job as per plan, cementers pumped 5bbls H2O, 80bbls/10.5ppg spacer-got spacer back 10bbls early, 432bbl/11.9ppg lead cement finished pumping @ 0700hrs-3/29. Cont. pumping 72bbl/15.8ppg Tail and displaced DP w/ 28.6bbls H2O, shut dwn and checked floats -good, 1/4bbl bled back. CIP@ 0737hrs. Estimated 87-90bbl cement to surface. Report Number 15 Report Start Date 3/29/2024 Report End Date 3/30/2024 Operation Cont. cementing 13-3/8" surface casingt- pumping 432bbl/11.9ppg lead cement, 72bbl/15.8ppg Tail and displaced DP w/ 28.6bbls H2O, shut dwn and checked floats -good, 1/4bbl bled back. CIP@ 0737hrs. Estimated 87-90bbl cement to surface. R/D cement hose. Break out cement stdassy. and set in mouse hole. POOH 1 std w/cement stinger t/1508'. P/U cement std f/mouse hole, break down same and l/d cement equipment. POOH f/1508' t/surface checking for cement rings. Bottom 4 jts had cement rings, washed out same for tool jts. Remove false table and install inner bushings. C/O elevators. Install pup jt into 13-3/8" landing jt., release hanger by turning to the right. L/D landing jts and running tool. R/D 13-3/8" handling equipment from rig floor. Clean out rotary pan of mud and cuttings. Dump sand traps and mud pits. N/D bell nipples and diverter lines at the mud cross. Clean pits 7, 8, 9 and 10. Slide north diverter line out of the way. N/D south diverter line in sections. N/D 21-1/4" pitcher nipple from annular and rotary pan. Remove studs f/ 21-1/4" annular to use on 13-5/8" annular. N/D 3" air actuated valve installed on conductor pipe for FIW/fire water. Remove clamp between annular/mud cross. Slide south diverter line out of the way. Remove accumulator fittings f/annular diverter. Clean pits 1, 2, 3, 5 and 6. N/D annular f/mud cross and set on cellar porch on west side. Crane annlar fron cellar porch to top deck. Simop-cleanning pits and dumping mud. N/D mud cross from 21" riser and set on cellar porch and remove same w/crane. Set geo-skid for MWD/DD's in cellar. Simop-filling pit w/FIW. Report Number 16 Report Start Date 3/30/2024 Report End Date 3/31/2024 Operation Install rig up slings on top drive. Break bolts on 21-1/4" riser, riser pup and DSA, l/d same. P/U tools and equipment in cella r deck. Greased choke manifold and std pipe. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 5/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation lower well head valves and 13-3/8" well head down into well bay. Check spacing and alignment, set well head to the side. Pull 21-1/4" diverter adapter from conductor and l/d same. Set 13-3/8" well head over conductor and oreint as per production operator, N/U well head and first riser peice. Cranes shut down due to high winds f/40-65mph. C/O accumulator hose drylock fittings t/fire rated Dixon style. Modify grating around well head to allow for annulus vaves. Dress 5" rams. Wind subsiding, cont. to p/u riser and m/u same on first peice. C/O bottom rams f/2-7/8" to 5" solids. P/U and stab BOP w/BOP carrie, notice riser is to short to M/U choke/kill hoses. Remove annular and 2ft spacer w/BOP carrier be tween annular/dbl gate. Remove carrier and 2ft spool f/annular. Lift dbl/single gates w/bridge cranes and set 2ft spool on riser w/tugger and m/u same. Set dbl/single gates on 2ft riser and m/u same. Set annular on dbl gate and m/u same. Report Number 17 Report Start Date 3/31/2024 Report End Date 4/1/2024 Operation Torque all connections. Pull up all koomey hoses from upper well bay and connect to BOP's. Clean and install bell nipple air boot flanges to annular and rotary pan. M/U choke and kill hoses to BOP mud X. Charge accumulator unit and function test BOP's. Clean rig floor. Center up BOP's in rotary. Install bell nipple and air up boots. L/D rig up lines and rig up skate too rig floor. Pull bare test plug to rig floor and dress with seals. Make up 5" test assy and set test plug. Flood stack and choke manifold. Perform shell test on annular t/250-2500psi, Bottom 5" rams and chke manifold 250-3500psi, upper 2-7/8" x 5.5" variable and HP mud line f/kill-geoskid-top drive to MP's t/250-3500psi-all good. R/D test equipment, pull test plug and set wear ring. Blow down top drive and mud lines to MP's. P/U 5"DP and RIH, monitoring displacement on the TT. f/surface t/1,700'. POOH racking back 5" DP to 560'. Very thick mud. Kelly up and displace thick mud overboard. Finish POOH t/surface racking back 5" DP. Report Number 18 Report Start Date 4/1/2024 Report End Date 4/2/2024 Operation Clear n clean rig floor of claboured mud from trip, cont. P/U 5" DP and single in the hole t/1612'. Displace cement contaminated mud from hole w/new 9.2ppg KCL mud. POOH racking back stds f/1612', monitoring fill on the TT. Strap drill pipe on deck. Cont. P/U 5" DP singling in the hole t/1599', simop-work boat, building mud. Simop- seal welding flutes on surface casing hanger w/Vault Rep., Hazard Mitigations performed and group meeting on hot work. POOH racking back stds t/surface. monitoring fill on the TT. Cont. seal welding flutes on surface casing hanger w/Vault Rep., Hazard Mitigations performed and group meeting on hot work. Cont. P/U 5" DP and single in the hole t/188' and rack back in the derrick. Cont. seal welding flutes on surface casing hanger w/Vault Rep., Hazard Mitigations performed and group meeting on hot work. Service rig and clean rig floor. grease crown, draw works, top drive, block and st-80. C/O dies in st-80. Cont. seal welding flutes on surface casing hanger w/Vault Rep., Hazard Mitigations performed and group meeting on hot work. Cont. seal welding flutes on surface casing hanger w/Vault Rep., Hazard Mitigations performed and group meeting on hot work. Back load boat, clean and clear rig floor, build mud Finish seal welding flutes on surface casing hanger w/Vault Rep., install pressure gauge on 4" outlet and monitor for pressure build. Simop-P/U all but 3 pieces of BHA as per Haliburton DD/MWD and rack in derrick. Report Number 19 Report Start Date 4/2/2024 Report End Date 4/3/2024 Operation Cont. re-weld flutes on surface casing to conductor after checking for leaks and discovering cracks. Simop- building mud, cleanning upper well bay, and electrician repairing heater in derrick house. Welding flutes on well head. Simop-clean and organize cement room, change end shaker screens f/100's t/80's, clean shaker area-rig floor and upper well bay. Install suction screens on both mud pumps, c/o rod wash on both pumps. Remove canrig volume sensor on upright tank #14. Cont. welding well head until 20:00hrs, let cool and check for leaks-2 small leaks. Welder timed out, sent to bed @ 22:00hrs. W ash out upright #14, cont. cleanning upper well bay, check gear & hydraulic oil level in top drive. Clean cellar room. Treating mud in pits. Pull wear ring, R/U to test BOP's-blow mud back to pits f/stack. Set test plug, R/U test manifold and test pump. install test sub on top drive. Fill stack/manifold/top drive w/water and work out air. Trouble shoot pressure difference on test chart to gauge. Sensator hose full of wrong gauge fluid, purged and c/o hose. C/O sensator. C/O chart recorder-same issue. Wrong charts-replace with correct chart. Test BOP's- test annular t/250-2500psi low/hi and all other equipment t/250-3500psi low/hi 5min. each on a chart as per AOGCC/H ilcorp policy. 9 of 10 test complete. AOGCC witness waived by Jim Regg. Report Number 20 Report Start Date 4/3/2024 Report End Date 4/4/2024 API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 6/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Test BOP's- test annular t/250-2500psi low/hi and all other equipment t/250-3500psi low/hi 5min. each on a chart as per AOGCC/H ilcorp policy. 10 of 10 test complete. All test performed w/water. AOGCC witness waived by Jim Regg. Pull test jt and test blind rams -good. Bleed pressure and open rams, install 5" test jts. Perform Accumulator draw down test-failed to pressure up to system pressure on time. Trouble shoot koomey unit. Bled down one bottle rack on koomey at a time and checked pre-charge, all good except #4 w/150psi. Remove bottle from bank and change out bladder. Pull test plug and l/d same. M/U std of DP and RIH to reverse out water. Plugged #4 bottle outlet. Fire alarm, report to muster-good, False alarm. Close anular and reverse out water from 90ft +-md. Cont. seal welding flutes on casing hanger. Clean in the cellar. Circulate surface mud. C/O bladder on #4 koomey bottle and re-install. Clean accumulator and surrounding area. Perform Koomey draw down test-good. Off load MV Titan of 9-5/8" casing. Finish welding on well head. Cont. circulate/cond. surface mud. R/U and test well head void t/5000psi-10min.-good. Install gauge on 4" conductor valve. Monitor pressure on OA-stabilized @50psi. Simop- pull thread protectors and strap casing. Fill stack and choke manifold with 9.2ppg mud, purge air. Perform 13-3/8" casing test t/1930psi for 30min.-good. Bled down 30psi first 15min. and 10psi the last 15min. bled back 2bbls of 3.5bbl pumped. Simop- cont. pull thread protectors and strap casing. Set wear ring in well head. L/D test jts. P/U BHA as per Haliburton DD/MWD, latch up bit-motor std and p/u MWD tool, scribe motor and up load MWD/LWD. RIH and shallow pulse test @510gpm, 745psi-good signal, POOH and rack 1 std. Load sources at report. RIH t/1432’, break circulation and warm up mud. Report Number 21 Report Start Date 4/4/2024 Report End Date 4/5/2024 Operation Wash and ream F/ 1432' T/ 1611'. Staging pumps up to 500 GPM, 25 RPM. 870 PSI. Tag FC at 1611'. Drill FE & Cmt F/ 1611' T/ 1698'. Tag shoe at 1698'. Drill out shoe + rat hole cmt to 1710'. at 550 GPM, 25 RPM, 5K TQ, 5-10 WOB, MW 9.2 in and out. Drill new formation F/ 1710'T/ 1730'. Pump sweep around. Circ clean. Back ream through FE three times. Pull in to casing & Perform FIT to 12.5 PPG. 277 PSI. Send results to Drilling engineer for approval. Good. Blow down choke and kill. RIH to 1730. Stage up pumps to 550 GPM. Drill aheaad F/ 1730' T/ 2040'. Stage pumps up to 630 GPM, 1400 PSI. 60 RPM, 5-7 K TQ. Holding back ROP to 200 FPH. Slide first 20-30' per stand. Back ream and mad pass slides as per DD on the conection. MW 9.2 in and out. Vis 45. ECDs at 9.6 PPG. WOB, 5-15, Max gas 700 units. Back ground running 100. Drill aheaad F/ 2040' T/ 2410',w/650 GPM, 1400 PSI. 50 RPM, 5-7 K TQ. Holding back ROP to 200 FPH. Slide first 20-30' per stand. Back ream and mad pass slides as per DD on the conection. MW 9.2 in and out. Vis 45. ECDs at 9.6 PPG. WOB, 5-15, Max gas 700 units. Back ground running 100. Drill aheaad F/ 2410' T/ 2745',w/640 GPM, 1550 PSI. 50 RPM, 5-7K TQ, flow=48%. Holding back ROP to 200 FPH. Slide first 20-30' per stand. Back ream and mad pass slides as per DD on the conection. MW 9.3 in and out. Vis 45. ECDs at 9.8 PPG. WOB= 5-12, Max gas 511 units. Back ground running 100. P/U=115k , S/O=100k , Rot=105k. Circ. B/U and until shakers clean @ 606gpm, 1300psi, 47% flow. Monitor well f/10min.-static. POOH on elevators f/2745' t/2180', 5-10k drag w/a few 15k bobbles. Monitoring fill on the TT. Report Number 22 Report Start Date 4/5/2024 Report End Date 4/6/2024 Operation POOH on elevators F/ 2180 T/ 1700'. Saw 10K over pull with stab coming in the shoe. Trip took Proper fill. Monitor well. Static. Blow down TD. Service Rig. Trouble shoot Low/High Drum clutch handle. Trouble shoot TD alarms, Adjust kelly hose to clear drill pipe while drilling. Monitor well. >5 BPH static Loss rate. TIH on elevators F/ 1700' T/ 2655'. Clean. Wash and ream staging pumps up to drilling rate at 650 GPM. Hole unloaded at btm up. Sweep brought back minimal increase in cuttings an back 20 BBL Late. Drill ahead 12.25 Hole as per DD. F/ 2747' T/ 3219'. 472' @ 78.6 FPH average with mad passing. 65 RPM, 650 GPM, Holding back at 200 FPH. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MAX GA S AT 661 UNITS. MW 9.5+ in and out. Build volume for dump and delute. Drill ahead 12.25 Hole as per DD. F/ 3219' T/ 3737'. 518' @ 86.3 FPH average with mad passing. 65 RPM, 645 GPM, 1900psi, 7-8k trq, 6-10k wob, 48% flow. Holding back at 200 FPH. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MAX GAS AT 689 UNITS. MW 9.6 in and out. Build volume for dump and delute. P/U=115k, S/O=100k, Rot=105k, ECD=10.2ppg. Drill ahead 12.25 Hole as per DD. F/ 3737' T/ 3783'. 46' @ 92 FPH average with mad passing. 65 RPM, 645 GPM, 1900psi, 7-8k trq, 6-10k wob, 48% flow. Holding back at 200 FPH. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MAX GAS AT 316 UNITS. MW 9.6 in and out. Build volume for dump and delute. P/U=115k, S/O=100k, Rot=105k, ECD=10.2ppg. Circ. & reciprocate, B/U and clean @640gpm, 1700psi, 48% flow, 50rpm, 3-6k trq. Monitor well-static. Short trip, POOH f/3783' t/2738',wiped tight spots @3070', 3250-40' w/20k+ overpull. RIH f/2738' t/3688', kelly up on last stand and wash down t/3783' @640gpm, 1750psi. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 7/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Drill ahead 12.25 Hole as per DD. F/ 3783' T/ 3900'. 117' @ 46.8 FPH average with mad passing. 65 RPM, 700 GPM, 2100psi, 7-8k trq, 6-10k wob, 52% flow. Holding back at 200 FPH. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MAX GAS AT 316 UNITS. MW 9.6 in and out. P/U=115k, S/O=100k, Rot=105k, ECD=10.2ppg. Report Number 23 Report Start Date 4/6/2024 Report End Date 4/7/2024 Operation Drill ahead 12.25 Hole as per DD. F/ 3900' T/ 4190'. 290' @ 48 FPH average with mad passing. 65 RPM, 700 GPM, 2000psi, 7-8k trq, 2-10k wob, 52% flow. Holding back at 200 FPH. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MAX GAS AT 272UNITS. MW 9.5 in and out. P/U=120k, S/O=100k, Rot=1010k, ECD=9.8ppg. Starting to getsome ratty drilling. Hard to maintain toolface. Fighting stall outs when touching bit to btm. Clean after pick up. Drill ahead 12.25 Hole as per DD. F/ 4190' T/ 4408'. 218' @ 36 FPH average with mad passing. 75 RPM, 700 GPM, 2000psi, 9-11k trq, 2-10k wob, 52% flow. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MW 9.5 in and out. P/U=120k, S/O=100k, Rot=1010k, ECD=9.8ppg. Lost swab in #2 pump. Circ on #1 while backreaming stand. Change swab and back to drilling. Drill ahead 12.25 Hole as per DD. F/ 4408' T/ 4610'. 202' @ 57.7 FPH average with mad passing. 75 RPM, 675 GPM, 2110psi, 8-10k trq, 10k wob, 49% flow. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MW 9.5 in and out. P/U=120k, S/O=100k, Rot=1010k, ECD=9.8ppg. Lost liner gasket on #2 pump. Circ on #1 w/400gpm, 875psi, 50rpm, while backreaming stand. Change liner/wearplate gaskets and back to drilling. Drill ahead 12.25 Hole as per DD. F/ 4610' T/ 4818'. 208' @ 69.3 FPH average with mad passing. 75 RPM, 700 GPM, 2285psi, 9-11k trq, 8-12k wob, 49% flow. Back ream full stands and mad pass all slides at 200 FPH at drillin g rate. MW 9.5 in and out. P/U=120k, S/O=100k, Rot=1010k, ECD=9.8ppg. Circ./reciprocate hole clean @570gpm, 1600psi, 50rpm, 5-6k trq, 47% flow. POOH on elevators f/4818' t/3772', pulling progressivily higher towards top of the tri, 25-50k over. Dragging cuttings beds. Circulate and reciprocate until hole cleans up, 710gpm, 2200psi, 50rpm, 5-6k trq, 50% flow. Report Number 24 Report Start Date 4/7/2024 Report End Date 4/8/2024 Operation TIH f/3785" t/4726', monitoring displacement on the TT. Wash/ream down f/4726' t/4818', no fill, pump 25bbl sweep on bottom. Rot/reciprocate sweep out of the hole @50rpm, 8k trq, 700gpm, 2100psi, max gas 300 on B/U. Hole unloaded on B/U. Drill ahead 12.25 Hole as per DD. F/ 4818' T/ 5028'. 210' @ 52.5 FPH average with mad passing. 75 RPM, 700 GPM, 2300psi, 10-12k trq, 10k wob, 49% flow. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MW 9.7 in and out. P/U=140k, S/O=120k, Rot=115k. Drill ahead 12.25 Hole as per DD. F/ 5028' T/ 5451'. 423' @ 70.5 FPH average with mad passing. 75 RPM, 700 GPM, 2200psi, 10-12k trq, 10k wob, 49% flow. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MW 9.5 in and out. P/U=150k, S/O=110k, Rot=118k. Drill ahead 12.25 Hole as per DD. F/ 5451' T/ 5598', 147' @ 18.37FPH average with mad passing. 700 GPM, 2270psi, 5-20k wob, 49% flow, 9.95ECD. Back ream full stands and mad pass all slides at 200 FPH at drilling rate. MW 9.5 in and out. P/U=150k, S/O=110k, Rot=118k. Pump Low vis/Hi vis sweep around while trying to slide with no effect, at lubes t/.75% w/no effect. POOH to C/O BHA, f/5998' t/3684', monitoring fill on the trip tank. Coming tight at 3684', try to pump/ wash thru and then pull 1 on elevator with no luck, . BROOH f/3684' t/3435', 654gpm, 1700psi, 46% flow, 50rpm, 5.5-7k tr q.. Report Number 25 Report Start Date 4/8/2024 Report End Date 4/9/2024 Operation BROOH F/3435' T/2400', 654gpm, 1500psi, 46% flow, 50rpm, 5.5-7k tr q.. #2 Pump leaking discharge screen cap. Back Ream with one pump at 400 GPM F/ 2400- 2200. Pump out at 400 GPM F/ 2400' T/ 2000'. Getting huge amounts of dry clay back. Pack off Rotary table with clay, Flow line and J tube overboard lines Plugged. Work pumps and flush clay while working rates u p to 600 GPM. Pull in to shoe continueing to clean large amounts of clay. Circ hole clean at 40 RPM 740 GPM. Clay cleaned up good in casing. Monitor well. Static. POOH F/ 1700' T/ 150' To BHA #4. Remove Nuclear sources, L/D Motor & bit. Bit 1/8 Under guage but we had an inline stab still in full guage. 12.25. Clean & Clear Rig Floor. Drain stack and Flush out. Perform weekly BOP funtion test. Prep BHA #5. Service rig. Change out DW Clutch control. Elecrition troubleshoot Drillers consol asignment #11. Adjust Kelly hose in derrick to clear DP while drilling. Simops- Pump 100 BBL Safe acid down M-31B chase with 150 bbl H20. All 180 deg. P/U BHA as per Haliburton DD/MWD: P/U motor and bit, m/u same, scribe motor. P/U MWD/LWD tools and upload same. Load sources. RIH t/2460' w/ 5"HWDP and 20stds 5"DP, kelly up and get pressures for Agitator/NOV, wash dwn last std of 20. Pumping 520gpm 1275psi. P/U Agitator and RIH w/1 std t/2670'+-, kelly up and get pressures for Agitator/NOV, pump 520gpm, 1630psi. Cont. RIH on elevators f/2589' t/4624', taking weight. Kelly up and wash/ream f/4624' t/4754', 490gpm, 1700psi, 50rpm, 7-8.5k trq, 40% flow. Report Number 26 Report Start Date 4/9/2024 Report End Date 4/10/2024 Operation Wash/ream F/4,754' -T/5,598', 490gpm=1700psi, 50rpm= 7-8.5Kft-lbs TQ, 40% flow. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 8/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Slide/Drill 12.25" Intermediate section F/5,598' - T/5,686' MD. Total 88' (AROP 35.2')Mad passing each slide at 200'/hr. 645gpm= 2,900psi, 12K WOB, 65RPM = 8-10Kft-lbs TQ, F/O= 48%, 9.7ppg MW. P/U= 150K, S/O= 110K, ROTW= 115K. Sperry lost power to shack twice due to bad battery backups totaling 1 hour getting systems rebooted. Slide/Drill 12.25" Intermediate section F/5,686' - T/5,960' MD. Total 274' (AROP 45.6')Mad passing each slide at 200'/hr. Pumping Hi-Vis sweeps every 500' or as needed to clean hole. 650gpm= 2,900psi, 12-14K WOB, 65RPM = 12-14Kft-lbs TQ, F/O= 47.5%, ECD= 10.05ppg with 9.6ppg MW. P/U= 160K, S/O= 115K, ROTW= 120K. Slide/Drill 12.25" Intermediate section F/5,960' - T/6,157' MD (3,726' TVD). Total 198' (AROP 33')Mad passing each slide at 200 '/hr. Pumping Hi-Vis sweeps every 500' or as needed to clean hole. 650gpm= 2,900psi, 12-14K WOB, 65RPM = 12-14Kft-lbs TQ, F/O= 47.5%, ECD= 10.05ppg with 9.6ppg MW. P/U= 160K, S/O= 115K, ROTW= 120K. Distance to plan: 25.50’, 24.01’ High, 8.59’ right. Sperry troubleshoot communication with tools. Exhausted all options to reset tools with no success. Decision made to POOH to swap to backup tools. Flow check well for 10 min- Static. POOH on elevators racking back 5" NC-50 DP F/6,157' - T/3,813' MD. Monitor well on trip tan k for proper displacement. Inspect top drive trolly, top drive, draw works. POOH on elevators racking back 5" NC-50 DP F/3,813' - T/2,867' MD. Monitor well on trip tank for proper displacement. Daily discharge: 450 bbls Cum Discharge: 6,778.05 bbls Daily DH Losses: 0 bbls Cum DH Losses: 135 bbls Daily Metal: 7.0 lbs Total Metal: 48.0 lbs Report Number 27 Report Start Date 4/10/2024 Report End Date 4/11/2024 Operation POOH F/ 2,867' T/ 1,624' MD. Pulled into shoe clean. Monitor well. Slight seepage losses at 4 BPH. CBU at 1,687' MD with 650 GPM, ROT 40 RPM. Shakers clean. Blow down service equipment with air. Service rig. Change TD carriage roller. Repair MP gauge in drillers console. POOH F/ 1,624' T/ 139' MD. Monitor well for displacment. L/D Halliburton tools as per DD/MWD F/139'. Offload sources. MWD attempt muliple time to download tools with no success. Halliburton MWD attempt to recover data from MWD tools. HES confer with town in establishing communication with tools. Download successful. L/D HES Directional BHA F/128' MD - T/surface. Bit Grade: 1-1-WT-A-1-E-N-BHA. P/U and RIH with 12.25" HES Geo-Tap directional assemlby as per DD/MWD T/104' MD. HES plug into tools and upload software to tools. Surface test MWD tools with 600gpm= 1,000psi- good test. TIH on elevators with Geo-Tap assembly on 5" NC-50 DP from derrick F/104' - T/1,610' MD. Monitor well on trip tank for displacement. Fill pipe. Service TD, Draw works, ST-80, Traveling blocks, and crown. Monitor well on trip tank. TIH on elevators with Geo-Tap assembly on 5" NC-50 DP from derrick F/1,610' - T/2,737' MD. Monitor well on trip tank for displacement. Fill pipe at 2,737' MD. Stage pumps up to 533gpm= 1,150psi to test Geo-Tap as per HES MWD. TIH on elevators with Geo-Tap assembly on 5" NC-50 DP from de rrick filling pipe every 20 stds, F/2,737' - T/5,523' MD. Monitor well on trip tank for displacement. Worked tight spot at 5,511', 5,530', and 5,543' MD with 30K down. Wash and Ream F/5,523' - T/ tag on depth at 6,157' MD. 569gpm= 1,885psi, 40RPM= 8-10Kft-lbs TQ, Pump 40bbls of low-vis followed by 40bbls of high-vis w/ Walnut (marker) sweep, followed by 9.5ppg WBM. Circulate and condition mud, 660gpm= 2,257psi. Obtain survey at 6,157' MD as per HES DD. Mad Pass F/6,157' - T/5,923' MD, 600gpm= 1,915psi. Daily discharge: 87 bbls Cum Discharge: 6,865.05 bbls Daily DH Losses: 61 bbls Cum DH Losses: 196 bbls Daily Metal: 2.0 lbs Total Metal: 50.0 lbs Report Number 28 Report Start Date 4/11/2024 Report End Date 4/12/2024 Operation Perform MadPass without rotation @ 180ft/hr F/6,155' - T/5,456' MD. 610gpm= 1,800psi, P/U=175K, S/O= 100K. Perform Geo-Tap at pre-planned targets as per HES MWD/ Hilcorp Geologist. Geo-Tap depths: 5,700', 5,654.51', & 5,567.45' MD. Perform Geo-Tap at pre-planned targets as per HES MWD/ Hicorp Geologist. Mad pass to corrilate correct test depths. 580gpm= 1,650psi, 9.5ppg MW. Geo-Tap depths: 5,385', 5,290',& 5,000' MD. P/U= 140K, S/O= 90K. Continue mad passing without rotation at 180FPH F/4,877' - T/4,804' MD, 425gpm= 1,100psi, 9.5ppg MW. MP #2 had swab leak. Shut down and isolated pump to change swab; continue at lower flow rate to conduct Geo-Tap operations. Performing Geo-Tap at pre-planned targets: 4,754.80'. P/U= 140K, S/O= 90K. Decision made to re-acquire sample at 5,516.07' MD. Wash F/4,804' - T/5,550' MD, 300gpm= 600psi. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 9/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Mad pass without rotation at 180FPH F/5,573' - T/5,363' MD, 500gpm= 1,600psi, 9.5ppg MW. Reduce flow rate to reduce chance of losing Geo-tap seal on wellbore, 420gpm= 1,150psi, Performing Geo-Tap at pre-planned targets: 5,516.07', 5,569.29', & 5,530.19' MD. P/U= 160K, S/O= 100K. Observe 1BPH losses to formation. Mad pass without rotation at 180FPH F/5,363' - T/4,424 MD, 500gpm= 1,600psi, 9.5ppg MW. Reduce flow rate to reduce chance of losing Geo-tap seal on wellbore, 420gpm= 997psi, Performing Geo-Tap at pre-planned targets: 5,308.92', 4,994.32', & 4,698.20', 4,644' MD. 10 of 26 Geo-Tap depths completed. P/U= 150K, S/O= 90K. Daily discharge: 169 bbls Cum Discharge: 7,034.05 bbls Daily DH Losses: 125 bbls Cum DH Losses: 321 bbls Daily Metal: 3.0 lbs Total Metal: 53.0 lbs Report Number 29 Report Start Date 4/12/2024 Report End Date 4/13/2024 Operation Mad pass without rotation at 180FPH F/4,403' - T/4,322' MD, 500gpm= 1,600psi, 9.5ppg MW. Reduce flow rate to reduce chance of losing Geo-tap seal on wellbore, 480gpm= 1,300psi, Performing Geo-Tap at pre-planned targets: 4,371.45', 4,322.33' MD. 12 of 26 Geo-Tap depths completed. P/U= 140K, S/O= 100K. Mad pass without rotation at 180FPH F/4,001' - T/3,239' MD, 500gpm= 1,600psi, 9.5ppg MW. Reduce flow rate to reduce chance of losing Geo-tap seal on wellbore, 480gpm= 1,300psi, Performing Geo-Tap at pre-planned targets: 3,958', 3,455', 3,395', & 3,239.85' MD. 16 of 26 Geo-Tap depths completed. P/U= 120K, S/O= 90K. Decision made to drop 4 of 26 test points. Mad pass without rotation at 180FPH F/3,291' - T/2,845' MD, 500gpm= 1,600psi, 9.5ppg MW. Reduce flow rate to reduce chance of losing Geo-tap seal on wellbore, 480gpm= 1,300psi, Performing Geo-Tap at pre-planned targets: 3,170.24', 2,948.65', 2,958', & 2,845.20' MD. 21 of 26 Geo-Tap depths completed; with decision to cancel 5 test. P/U= 110K, S/O= 90K. Decision made to drop 4 of 26 test points. Flow check well- static. Blow down surface equipment with air. TIH on elevators with 5" NC-50 DP out of derrick; filling pipe every 20 stds F/2,896', washing last std down 500gpm= 1,385psi; tagging on depth at 6,157' MD. P/U= 140K, S/O= 108K. Observed 3BPH seepage while tripping. CBU 2x at 6,157' MD, 550gpm= 1,620psi, 37RPM= 9-10K TQ, 9.7ppg ECD with 9.5ppg MW, P/U=140K, S/O= 100K, ROTW= 136K. Shakers loaded with coal on BU. Flow Check well 10 min- Static. POOH on elevators racking back 5" NC-50 DP F/6,157' - T/5,328' MD. Monitor well on trip tank for displacement. P/U= 170K, S/O= 110K. Observed 30K overpull at 6,010' MD. Daily discharge: 24 bbls Cum Discharge: 7,055.05 bbls Daily DH Losses: 50 bbls Cum DH Losses: 371 bbls Daily Metal: 2.0 lbs Total Metal: 55.0 lbs Report Number 30 Report Start Date 4/13/2024 Report End Date 4/14/2024 Operation POOH on elevators racking back 5" NC-50 DP F/5,328' - T/1,680' MD. Monitor well on trip tank for displacement. P/U= 110K, S/O= 90K. Flow check well at shoe- static. CBU at 1,680' MD, 550gpm= 1,100psi, 40RPM= 2-4Kft-lbs TQ, 9.7ppg ECD with 9.5ppg MW. P/U= 110K, S/O= 90K. Blow down surface equipment with air. POOH on elevators racking back 5" NC-50 DP in derrick F/1,680' - T/121' MD. Flow check well prior to pulling BHA- Static. Monitor well on trip tank for proper displacement. POOH with BHA F/121' -T/100' MD. HES MWD plug into and download from tools. L/D HES Geo-tap assembly F/121' - T/surface. Bit Grade: 1-1-WT-A-1-E-N-TD. Monitor well on trip tank for displacement. Functioned Blind rams while out of hole. M/U wear bushing retrieval tool. Retrieve wear bushing. Change upper rams to 9-5/8" fixed bore rams. Ram ser: UOCD 1310-A, UOCD 1310-B. Drain BOP and flush with water. M/U 9-5/8" CSG test assembly, land test plug. Fill with H2O. Attempt to pressure test upper rams, test plug leaking. Pull test plug, center bull plug not installed, install same. Test 9-5/8" CSG on upper rams 250psi/3,500psi on chart for 5 min each. L/D test assembly. PJSM, P/U Volant tool, break extention sub on Volant. Attempt to M/U into top drive, Top connetion of Volant larger than bell guide of top drive. Remove bell guide and Die carriers. M/U Volant into top drive. R/U Parker Wellbore CSG equipment. CSG safety valve on rig floor. Offload/backload equipment from M/V Endeavor. Hold PJSM with crews on running 9-5/8" CSG as per detail while offload/backload M/V Endeavor. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 10/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation M/U 9-5/8" BTC shoe track as per detail. Flashlight float equipment- Good. Bakerlok connections and M/U to "Mark" average shoe track 9K-lbs TQ. Check floats- Good. During check of floats, tore rubber cup on volant tool. Change same. RIH w/ 9-5/8" BTC, CDC, TXP, DWC, 47#, L-80 casing F/117' - T/351' MD. 23K-lbs TQ on TXP, 21K-lbs TQ on CDC connections. Daily discharge: 42 bbls Cum Discharge: 7,097.05 bbls Daily DH Losses: 115 bbls Cum DH Losses: 486 bbls Daily Metal: 0.0 lbs Total Metal: 55.0 lbs Report Number 31 Report Start Date 4/14/2024 Report End Date 4/15/2024 Operation M/U 9-5/8" 47# BTC , TXP, DWC, 47#, L-80 casing F/351' - T/619' MD. 23K-lbs TQ on TXP, 21K-lbs TQ on CDC connections. Cant get swivel to rotate. Chain off to snub post and apply steam. Establish rotationg. Taking 2500 LB after it freeed up. Chagne snub change on faulst table to keep casing center. Remove parker snub chains and install 3/8 rig chaines to cmt swivel. Test/ Good. Continue to P/U 9-5/8, 47# casing F/ 619' - T/1,592' MD. Try and torque DWD to 2K over shoulder but shoulder was 8K. Increase tq to. 24K as per Drilling engineer. Continue to P/U 9-5/8 47# casing F/ 1,592' - T/1,686' MD. Stage up pumps to 6 BPM= 112 PSI. Circ btm up. MW 9.5 Looked good. Continue to P/U, RIH 9-5/8, 47# casing F/1,686' - T/4,081' MD. CBU at 4,081' MD, 252gpm= 130psi. Continue P/U and RIH w/ 9-5/8", 47# casing as per tally F/4,081' - T/6,071' MD. M/U Hanger and landing jt. as per Vault Rep. Break circulation staging pumps up to 5 bpm w/200psi. wash down to shoe depth of 6,148' MD. Land out hanger in well head @ 75.8'. P/U to 6,144' MD. Set torque stall to 18K-lbs. Rotate and reciprocate 9-5/8" CSG to condition mud for cmt job, 5bpm= 200psi. 3-10RPM= 16-17K-lbs TQ. Hold PJSM with rig crew and Halliburton cement crew. Fill surface lines with 5bbl water. PT Halliburton cement lines T/1,500/4200psi - Good. Pump 60bbls 10.5ppg tuned spacer at 3BPM, 330 psi. Released Volant and drop bottom plug. Pump 438bbls (1,033 sks) 12.0ppg EconCem Lead cement at 5BPM (Cement wet: 03:50). Follow with 35bbls (172 sks) 15.3ppg HalCem Tail cement at 4BPM. Released volant and drop top plug. Kick out with 20bbls water from cementers at end of report. Daily discharge: 42 bbls Cum Discharge: 7,139.05 bbls Daily DH Losses: 30 bbls Cum DH Losses: 516 bbls Daily Metal: 0.0 lbs Total Metal: 55.0 lbs Report Number 32 Report Start Date 4/15/2024 Report End Date 4/16/2024 Operation Swap to rig pump #1 and displace with 425bbls 9.6ppg LSND mud at 7BPM, slowing to 3BPM for final 25bbls ICP=266psi, FCP=819psi. Bumped plug on calculated volume with 500psi over FCP. Bled off pressure and checked floats – holding.120bbls cmt returned to surface. Cement in place at 06:53. Rotated and reciprocated throughout job. Blow down cement line. Flush through return lines and BOP's with citric/citrate water. L/D 9-5/8" landing assembly. R/D Parker Wellbore CSG bowls, elevators, bell extentions. R/D Volant tool and cmt head. Change dies on top drive grabber. Install Bell guide. Clean and clear rig floor of non essential tools. M/U 13-5/8" wash tool, RIH washing out BOP's and wellhead profile. L/D same. M/U 9-5/8" pack off running tool with pack off as per Vault Rep. RIH attempting to land pack off, staging up to 35K down w/ no success. POOH w/ pack off and inspect with Vault Rep. Flush top of well head with fresh water and inspect wellhead bore for debris through CSG valve. Attempt to land pack off with no success. Pull pack off and remove btm two seals, mark seal grooves with colored paint stick. RIH w/ same and noticed pack off was landing out as designed. Pull same and install two bottom seals. RIH, Land out as per Vault Rep. Engage pack off and pull test to 40K, holding for 15 min. Test void to 5,000psi for 15 min- good. Release from pack off, L/D running tool. Change upper rams to 2-7/8" x 5" VBR. Change saver sub on top drive. P/U and RIH with test plug on 5" testing assembly, R/U to test BOPE. Fill BOPE and surface equipment with H2O and perform shell test on equipment prior to AOGCC arriving on location. Test BOPE on 5" test joint to 250/3,500psi charted for 5/5 Min. Tested CMV 1-14, (1)- 5" Dart, (2)- 5" TIW, UPR/LWR IBOP, Kill HCR, Choke HCR, manual Kill/choke, Super Choke and manual on CMV. Upper (2.875" x 5-1/2" VBR) and Lower VBR Rams (5" fixed), Annular 250/3,500psi. All testing conducted with H2O. Performed PVT, F/O, and gas alarms test.Test witnessed by AOGCC Rep Austin McLeod. Koomey draw down Initial system at -2975psi, Manifold - 1500psi, after system stabilized - 1400psi, 200psi increase 42 sec, full charge 230 sec. Nitrogen 8 bottles average 2325psi. Close times: Ann -24sec, UPRS 12 sec, Blind/Shear 12 sec, LPRS 12 sec, HCR Kill 6 sec, HCR choke 7 sec. Test took 4hrs. Drain stack. R/D 5" testing assembly. M/U wear bushing running tool, RIH and lock down same. L/D wear bushing running tool. Daily discharge: 1350 bbls Cum Discharge: 8,489.05 bbls Daily DH Losses: 0 bbls Cum DH Losses: 516 bbls Daily Metal: 0.0 lbs Total Metal: 55.0 lbs Report Number 33 Report Start Date 4/16/2024 Report End Date 4/17/2024 API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 11/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation R/D test equipment and jt.. Blow down top drive, choke manifold, choke/kill lines. Fill hole f/wellhead to bell nipple and monitor same on TT. C/O elevators. P/U BHA as per Haliburton DD/MWD, M/U bit, motor and scribe same. Inspect and rebuild TM collar. Down load MWD tools. Shallow t est MWD tools, un-able to get signal f/TM, re-cycle pumps several times with no-joy. Pull up to TM collar t/92', plug in and read tool, turn off same. L/D TM collar and C/O pulsar. P/U TM collar, flex collar and plug in. Upload MWD and turn on tools. Perform surface test on MWD tools @460gpm, 1000psi. L/D flex DC and stabilizer, pull bit to surface and inspect same-good. Load radio-active sources. P/U stabilizer, flex DC's and c/o jars. RIH w/5"HWDP f/400' t/732'. Monitoring displacement on the TT. P/U 5" DP off the deck and single in the hole f/732' t/1206'. Monitoring displacement on the TT. Service rig: grease crown, traveling block, drawworks, top drive and ST-80. C/O hi-clutch relay valve on draw works and speep on spin function on top drive from 7rpm to 16rpm. Slip/cut drill line,, Hang off block and set top drive in slips by screwing into stump w/same. cut 102' of drill line. Slip on same and secure dog knot. Clean and clear rig floor. Cont. P/U 5" DP off the deck and single in the hole f/1206' t/2527'. Monitoring displacement on the TT. Circ. B/U @350gpm, 810psi, 20rpm, 3-4k trq, 28% flow. Check signal of MWD @360gpm, 815psi-good. Cont. P/U 5" DP off the deck and single in the hole f/2527' t/5072'. Monitoring displacement on the TT. Circ. B/U @350gpm, 930psi, 31% flow. RIH out of the derrick f/5072' t/5628'. Report Number 34 Report Start Date 4/17/2024 Report End Date 4/18/2024 Operation Cont. RIH out of the derrick f/5628' t/6007'. Fill pipe and wash down @ 350gpm, 1000psi, tag at 6067' (2 plugs in the hole and flaot)on depth. Circ. B/U @350gpm, 1050psi, 12-14k trq. p/u=170k, s/o=95k, rot=125k. Attempt to test casing, no good due to 4" stand pipe valve. Rebuild valve. 4" stand pipe valve has washed out seat face, weld seat face and grind same. Install repaired stand pipe valve on spare stand pipe and use spare stand pipe valve on primary. Simop-service rig, top drive, draw works, ST-80 and pipe skate. Clean rig floor. L/D 10' pup jt. and space out with std. Break circulation and purge thru DP and across backside thru stack. Attempt to test 9-5 /8" casing with mud pump t/3500psi f/30min.-no test. Break out top drive and R/U test pump and attempt to test casing t/3500psi f/30min.-no test. Inspect surface equipment for leaks -none found. R/D test pump and lines while confiring with town. Decision made to shell test surface equipment. R/U test pump and lines, test surface equipment t/3500psi-good test. R/D. Circ. B/U @350gpm, 970psi, 5rpm, 11k trq. Pump 11.5ppg slug, POOH on elevators f/6067' t/550'. Monnitoring fill on the TT. Work BHA as per DD/MWD, Rack HWDP and flex collars. Upload MWD and rack same, L/D Motor and stab after breaking out bit. P/U Storm Packer BHA as per DD, M/U flush tool and flex DC, RIH w/2 stds 5"HWDP, M/U packer and xo's, RIH t/260'. RIH f/260' t/3000', monitoring displacement on the trip tank. Kelly up and space out for casing test on w/ center of elemont @ 2807 Report Number 35 Report Start Date 4/18/2024 Report End Date 4/19/2024 Operation Tested 9-5/8" csg above prk @ 2807' to surface t/ 3750 psi for 30 min on chart good test release prk and rih t/ tag @ 6067' w/ hanging weight pipe below. p/up and set prk w/ center of elemont @ 5799' Test above prk t/ 3806 psi w/ 4.6 bbls on chart for 30 min t/ 3778 psi good test bleed back 4.2 bbls release prk kelly up and reset and test below t/ 3709 psi and confirm leak below 5799' @ +-100psi loss in 5 min bleed off and release prk. crew chg day having weather let drill crew eat Flow check-static. Pump slug and POOH f/6055' t/246', mmonitoring fill on the TT. Break and l/d 9-5/8" Storm Packer, rack back flex DCs and HWDP. L/D bull nose wash tool. Clean and clear rig floor. P/U BHA #9 as per DD/MWD. P/U motor and stabilizer off skate and m/u bit and scribe tool face. P/U MWD tools from derrick and u pload same. P/U flex DC from derrick, RIH and shallow pulse test-good. Pull up to load sources. RIH w/6stds HWDP and jars. Monitoring displacement on the TT. RIH on elevators f/730' t/2574', monitoring displacement on the TT. Fill pipe, break circ. f/10min. @200gpm, 360psi, 8rpm, 3.5k trq. Cont. RIH on elevators f/2574' t/5061', monitoring displacement on the TT. Fill pipe, break circ. f/10min. @200gpm, 370psi, 8rpm, 7-8k trq. Cont. RIH on elevators f/5061' t/5921', monitoring displacement on the TT. Kelly up and wash down f/55921' t/6067' and confirm tag of F/C on depth. Pull up and get SPR's, set parameters and drill out float equipment @6067'-6070', slow pumps t/200gpm, 8rpm and slack off with no real bottom (cement). Ream F/C 2X and make connection, cont. drill to shoe @6149’ and rat hole t/6157’ w/no WOB. Drill 23’ new hole t/6180’. (started getting WOB @6160 to 6180, 3-9k) Report Number 36 Report Start Date 4/19/2024 Report End Date 4/20/2024 Operation Dump old mud f/pits, sand traps, degasser pit and trip tanks. Clean out same and flush lines in preperation for displacement. Transfer new mud to degasser pit and sand traps. Displace old 9.4ppg mud w/new 9.2ppg LSND fresh water mud @289gpm, 550psi, 30rpm, 12-13k trq. Over boarded all old mud. Circulated until even 9.2ppg in/out. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 12/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation Line up and flush choke/kill lines w/mud, perform FIT w/9.2ppg WBM t/693pis, pressure bled t/674psi over 15min. w/3.6bbls pumpe d and 1bbl bled back. Open rams and monitor well on the TT while consulting w/office. Line up and break circulation thru drill pipe. Flush choke/kill lines. Close top rams and perform FIT w/9.2ppg WBM t/671psi w/5bbls pumpedin, bled down t/657psi over 15min., bled back 2.3bbls. (Good test, 638psi required f/12.5ppg EMW) Drill/slide 8-1/2" hole f/6180' t/6640', 550gpm, 2000psi, 50rpm, 15k trq, 42%flow, p/u=170k , s/o=100k, rot=115k. Survey ever y connection, back ream std 2X and madd pass any slide 20+ft SPR's @6145'md/3712'tvd, 9.2ppg, #1pmp @20/30/40spm-w/120/160/210psi #2pmp @20/30/40spm-w/110/180/200psi Drill/slide 8-1/2" hole f/6640' t/6945', 550gpm, 2000psi, 50rpm, 15-16k trq, 42%flow, p/u=220k, s/o=110k, rot=k. Survey every connection, back ream std 2X and madd pass any slide 20+ft. Report Number 37 Report Start Date 4/20/2024 Report End Date 4/21/2024 Operation Drill/slide/survey f/6945' t/7130', 550gpm, 2000psi, 41% flow, 50rpm, 14-17k trq, p/u=220k, s/o=130k, rot=150k. Dbl back ream each std, Madd pass every slide over 20ft @200fph, pumping hi-vis sweeps every 500ft or as needed. Cycle pumps for survey, circ. 1.5 B/U rotating /reciprocating f/7130' t/7040' @500gpm, 1600psi, 30rpm, 15-16k trq, clean hole. Short trip t/shoe: Flow check-static, POOH on elevators f/7130' t/6091', monitoring fill onthe trip tank. Held well control trip drill @10:48hrs. Service Top drive, traveling block, crown, draw works and ST-80. Clean suction/discharge screens on mud pumps. Change out rod wash pump on #1 mud pump. RIH on elevators f/6091' t/7134', wash down last std @550gpm, 1950psi, 50rpm, 15-16k trq, 42% flow. Monitoring displacement on the TT. Drill/slide 8-1/2" production hole f/7134' t/7586', 550gpm, 2100psi, 50rpm, 18-20k trq, 2-5k wob. P/U=220k, s/o=135k, rot=155k. Get SPR's.@7228'. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pumped sweep @7134' and drilled ahead, 25% increase in cuttings on return. Hole unloaded at 1.5X B/U. Drill/slide 8-1/2" production hole f/7586' t/7762', 550gpm, 2100psi, 50rpm, 17k trq, 2-5k wob. P/U=210k, s/o=130k, rot=165k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pumped Hi-Lo 20/20bbls sweep @7630' w/drilling ahead, 30% increase in cuttings on return. Repair mud pump #1. Circ./rot./recip @ 7762', 419gpm, 1325psi, 50rpm, 11-13k trq. Drill/slide 8-1/2" production hole f/7762' t/7792', 550gpm, 2200psi, 50rpm, 13-14k trq, 2-5k wob. P/U=210k, s/o=130k, rot=165k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Report Number 38 Report Start Date 4/21/2024 Report End Date 4/22/2024 Operation Drill/slide 8-1/2" production hole f/7792' t/8170', 550gpm, 2200psi, 50rpm, 17-20k trq, 2-5k wob, 2-5k WOB, 10.13ECD, 9.4ppg. P/U=220k, s/o=145k, rot=170k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pump survey, Circ. cond. mud at 8170', @550gpm, 2100psi, 50rpm, 1.5 B/U until clean. Flow check-static, POOH on elevators f/8170' t/7132', no issues. RIH f/7132' t/8170', wash down last std @426gpm, 1400psi, 50rpm, 11k trq and no fill on bottom or issue on trip in. Drill/slide 8-1/2" production hole f/8170' t/8512', 550gpm, 2380psi, 50rpm, 20k trq, 3-5k WOB, 10.0ECD, 9.4ppg. P/U=230k, s/o=1 50k, rot=175k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Recorder SPR's @8265'md/5750'tvd, w/9.4ppg: #1=20/30/40spm=240/300/400psi #2=20/30/40spm=220/300/400psi Drill/slide 8-1/2" production hole f/8512' t/8674', 550gpm, 2325psi, 50rpm, 19-20k trq, 1-6k WOB, 10.17ECD, 9.4ppg. P/U=230k, s/o=145k, rot=180k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pump 25bbl LO-Vis, 25bbl Hi-Vis/ 1# over weighted sweeps while rot/reciprocating @ 535gpm, 2360psi, 65rpm, 19-20k trq, 40%flow. 40% increase in cutting on return, Circulated clean w/1.5 B/U. Drill/slide 8-1/2" production hole f/8674' t/8740', 550gpm, 2400psi, 50rpm, 19-20k trq, 3-6k WOB, 10.10ECD, 9.4ppg. P/U=230k, s/o=150k, rot=180k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Report Number 39 Report Start Date 4/22/2024 Report End Date 4/23/2024 Operation Drill/slide 8-1/2" production hole f/8740' t/9038', 550gpm, 2400psi, 50rpm, 22-24kk trq, 2-6k WOB, 40%flow, 10.05ECD, 9.4ppg. P /U=260k, s/o=150k, rot=180k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Drill/slide 8-1/2" production hole f/9038' t/9206', 550gpm, 2400psi, 50rpm, 22-24kk trq, 2-6k WOB, 40%flow, 10.05ECD, 9.4ppg. P /U=260k, s/o=150k, rot=180k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pump survey, circ. 1.5 B/U cleanning hole @550psi, 2350psi, 50rpm, 20-24k trq, 40% flow. Flow check-static. POOH on elevators f/9206' t/8152', no issues, p/u=265k broke over, pulling at 250k, s/o=140k. RIH on elevators f/8152' t/9206',with no issues, wsh down last std, 550gpm, 2300psi, 50rpm, 23k trq, 40% flow. No fill on bottom. Drill/slide 8-1/2" production hole f/9206' t/9339', 550gpm, 2400psi, 50rpm, 22-24kk trq, 2-6k WOB, 40%flow, 10.05ECD, 9.4ppg. P /U=260k, s/o=150k, rot=190k. Pumped tandem 25/25bbl lo/hi sweep @ 9222',40% increase onn return. Drill/slide 8-1/2" production hole f/9339' t/9483', 550gpm, 2400psi, 50rpm, 22-24kk trq, 2-6k WOB, 40%flow, 10.05ECD, 9.4ppg. P /U=260k, s/o=150k, rot=190k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Circ. and reciprocate f/9389'' t/9483'', 425gpm, 1630psi, 50rpm, 17kk trq, 36%flow. Repair mud pump #1, c/o liners and swabs. Drill/slide 8-1/2" production hole f/9483' t/9650', 550gpm, 2630psi, 50rpm, 24k trq, 2-6k WOB, 40%flow, 10.08ECD, 9.4ppg. P/U=2 60k, s/o=155k, rot=190k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 13/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Report Number 40 Report Start Date 4/23/2024 Report End Date 4/24/2024 Operation Drill/slide 8-1/2" production hole f/9650' t/9661', 550gpm, 2600psi, 50rpm, 25-28k trq, 4-6k WOB, 40%flow, 9.4ppg. Back ream e ach std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pump Lo-Vis /Hi-Vis weighted sweep and circ. out @550gpm, 2500psi, 50rpm, 20-22k trq. Sweep returned on time w/10% increase in cuttings, while repairing swab on MP. Drill/slide 8-1/2" production hole f/9661' t/9708', 550gpm, 2650psi, 50rpm, 25-25k trq, 4-8k WOB, 40%flow, 9.4ppg, 10.08. P/U=265k, S/O=165k, Rot=200k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Circ. @425gpm, 1650psi, 20rpm, 20-25k trq, and rot./reciprocating while repairing MP#2-swab. Drill/slide 8-1/2" production hole f/9708' t/9876', 550gpm, 2500psi, 50rpm, 22-24k trq, 2-4k WOB, 39%flow, 9.4ppg, 10.05. P/U=260k, S/O=160k, Rot=190k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Circ. and condition mud @550gpm, 2500psi,55rpm, 22k trq, while attempting to revive Haliburton ADR tool by recycling pump and down links, no success. Drill/slide 8-1/2" production hole f/9876' t/9952', 550gpm, 2500psi, 50rpm, 22-24k trq, 2-4k WOB, 39%flow, 9.4ppg, 10.05. P/U=260k, S/O=160k, Rot=190k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Circ/cond. mud @9952', @550gpm, 2600psi, 50rpm, 22k trq, trouble shoot CanRig screen failure, found router un-plugged by emmissions Tech. Plugged in router and reboot system and resumed drilling. Drill/slide 8-1/2" production hole f/9952' t/10,232', 550gpm, 2685psi, 50rpm, 24-27k trq, 1-8k WOB, 40%flow, 9.4ppg, 10.0ECD. P/U=270k, S/O=180k, Rot=200k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Pump Lo-Vis /Hi-Vis weighted sweep and circ. out @550gpm, 2500psi, 50rpm, 20-22k trq. Sweep returned 40bbl late w/10% increase in cuttings, while repairing swab on MP. Monitor well-static. Pooh on elevatorsf/10,232' t/8816', monitoring fill onn the TT. Hole took proper fill. Pump slug and cont. wiper trip f/8816' t/7487', monitoring fill on the TT. Report Number 41 Report Start Date 4/24/2024 Report End Date 4/25/2024 Operation Cont. wiper trip, POOH on elevator f/7487' t/6634', monitoring fill on the TT. Pump Lo-Vis /Hi-Vis weighted sweep and circ. out @550gpm, 2100psi, 80rpm, 12k trq. Sweep returned, while rot./reciprocating. Cont. POOH f/6634' t/6092', encountered tight spot f/6345' t/6320' bit depth had to ream thru no pump. Service rig: TD, crown, traveling block, 4-way valve on Koomey and swab rod self-aligning knuckles on MP #1 & #2. Clean suction screens and riostat on MP on console. Monitoring well on the TT, .25BPH loss rate. Function 13-5/8" 5M BOP on 5" DP. TIH f/6095' t/10,232, wash dwn last std @550gpm, 2600psi, 50rpm,20k Trq, no fill on bottom. Drill/slide 8-1/2" production hole f/10,232'' t/10,515', 550gpm, 2630psi, 65rpm, 24-27k trq, 1-5k WOB, 41%flow, 9.4ppg, 10.14EC D. P/U=300k, S/O=180k, Rot=210k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Report Number 42 Report Start Date 4/25/2024 Report End Date 4/26/2024 Operation Drill/slide 8-1/2" production hole f/10,515' t/10,703', 550gpm, 2550psi, 50rpm, 27-29k trq, 2-6k WOB, 39%flow, 9.4ppg, 9.99ECD. P/U=305k, S/O=185k, Rot=220k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Drill/slide 8-1/2" production hole f/10,703' t/10,964', 550gpm, 2550psi, 50rpm, 27-29k trq, 2-6k WOB, 39%flow, 9.4ppg, 9.99ECD. P/U=305k, S/O=185k, Rot=220k. Back ream each std 2X, sweep hole every 500ft or as needed, Madd pass slide over 20ft @200fph. Drill/slide 8-1/2" production hole f/10,964' to TD @ 11,296'MD/8705'TVD, p/u a single to TD. 530gpm, 2600psi, 50rpm, 28-29k trq , 5-8k WOB, 39%flow, 9.4ppg, 10.01ECD. P/U=320k, S/O=185k, Rot=225k. Back ream 2X, Pump survey on bottom. Pump Lo-Vis /Hi-Vis weighted sweep and circ. out @540gpm, 257000psi, 50rpm, 28.5k trq, while rot./reciprocating. P/U=320k, S/O=185k, Rot=225k. no increase in cuttings on B/U. Sweep returned w/20% increase in cuttings. Cont. to finish circ. SS 2X. Monitor well-static. POOH on a single f/catwalk f/11,296' t/10,250', p/u=320k-broke over @370k, s/o=195k. Monitoring fill on the TT. Report Number 43 Report Start Date 4/26/2024 Report End Date 4/27/2024 Operation POOH f/10,250' t/9,750. Monitoring fill on the TT. Pump dry job and POOH f/9750' t/7022', monitoring fill on the TT. Shut in well @08:52hrs, @7022'md with TPR due to improper fill up reading and human error and well appearing to flow. SICP=0, SIDPP=0, Monitor shut in pressure f/15min. w/no increase. Open super choke w/no returns or pressure. Open TPR and monitor f/15min.-well static. Cont. POOH f/7022' t/4678', monitoring fill on the TT. Stopped @6089' inside the shoe and monitor well f/15min.-2bph loss rate. cont. POOH t/732', hole took proper fill. Cont. POOH f/732' racking back 5"HWDP, p/u single and rack back non-mag flex DC. Cont. work BHA as per Haliburton DD/MWD. Break out and L/D stabilizer, pre-job on loading radio active sources. Pull sources and down load MWD. L/D MWD, drain motor, Brk off bit and L/D mtr. Clean and clear rig floor of BHA components and mud. Service rig, grease crown, block, TD, DW and ST-80, trouble shoot lo-hi clutch on draw works with no progress. Simop-drain stack and R/U test equipment. Pull wear ring and rack back running tool, M/U test plug and 5" test jt w/TIW, IBOP and side entry sub. Set plug in stack. Fill stack and choke manifold w/FIW, purge air from same. Test BOP's 250/3500psi 5min./charted all components w/ 5" and 4.5" test jts. as per AOGCC/Hilcorp procedure. 10 of 15 test complete @ report time. Report Number 44 Report Start Date 4/27/2024 Report End Date 4/28/2024 API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 14/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation R/D 5" assy, Pull test plug, p/u flush tool and flush stack, set test plug and P/U 4.5" assy, purge air from lines Test BOP's 250/3500psi 5min./charted all components w/4.5" test jts. as per AOGCC/Hilcorp procedure. Attempt t/test annular, leaking at connection above elements. Attempt to back out jt and broke at leaking connection above elements. M/U loose connection and pull test plug and assy, re-torq loose connection and re-set plug. Re-test, jt pumping out of the hole. Stop and bleed of pressure and pull and rack test assy. P/U wash tool and wash well head @600gpm and 25rpm, L/D wash tool. Set 4.5" test assy into plug and screw tight w/chain tong. Cont. test BOP's 250/3500psi 5min./charted all components w/4.5" test jts. as per AOGCC/Hilcorp procedure. Test annular, UPR, 2x 5" FOSV, 5" dart, CMV's, upper/lower kelly valves, Kill demco and choke step dwn. Perform Koomey draw dwn test. 11 of 11 test completed. R/D test equipment: un-seat test plug and l/d same, test plug was stuck and had to pull 30k to unseat. L/D 4.5" test assy. R/D test manifold and pump. Inspect wear rind and M/U running tool, set wear ring. L/D running tool and rack std back. P/U BHA #9 as per Haliburton DD/MWD, P/U motor and scribe same. M/U bit and trq same. M/U MWD t/101'. Plug in MWD and upload well data. M/U flex DC w/single and shallow test w/450gpm, 800psi-good. L/D single and RIH w/HWDP t/702'. TIH w/8-1/2" drilling assy on 5" dp f/702' t/5347', monitoring displacement on the TT. TIH f/5471' installing NRP’s on every jt to cover casing t/10,550 , monitoring displacement on the TT. Cont. RIH last 500’ wash down last std. ( tight spots that we had to ream through, 10,080’ and 10,557’) Report Number 45 Report Start Date 4/28/2024 Report End Date 4/29/2024 Operation Wash/ream f/11,050' t/11,296', 480gpm, 2100psi, 50rpm, 20-22k trq. Tag bottom w/4k dwn, no fill. Circ. clean rot/reciprocating. Madd pass as per Haliburton MWD f/11,296' t/10,740', 510gpm, 2300psi, 50rpm, 20k trq @180fpm. Madd pass as per Haliburton MWD f/10,740' t/9800', 510gpm, 2300psi, 50rpm, 20k trq @180fpm. Removing NRP's from DP after madd pass. Circ. hole clean @9800', 520gpm, 2200psi, 50rpm, 12kk trq. Circ. clean, shut dwn pumps, monitor well-static, pump slug. POOH w/8-1/2" drilling assy f/9800' t/7077', removing NRP's from each jt. Remove crates of NRP's from rig floor, bring more empty crates for NRP's to rig floor. Cont. POOH removing NRP's f/7077' t/5215', drop 2.4" drift on 100' wire @ 6630'. Slip/cut drill line. Cont. POOH removing NRP's f/5215' t/4000' on elevators, monitoring fill on the TT. Report Number 46 Report Start Date 4/29/2024 Report End Date 4/30/2024 Operation Cont. POOH removing NRP's f/4000' t/160' on elevators, monitoring fill on the TT. L/D BHA as per Halliburton DD/MWD. Down load tools, turn off, l/d same, L/D Motor and bit. P/U cement head and m/u 15' pup, L/D same. Clean and clear rig floor, R/U Parker casing: M/U XO to floor valve, prepare fill up line and skate. P/U 4.5" elevators and hang power tongs. Pre-job, P/U shoe track and baker lock-shoe jt/float jt/Landing collar jt.. Check floats-good. P/U 4.5 12.6# liner t/5325', trqing jts t/6170 ft/lbs. Filling pipe every 5 jts and monitoring displacement on the TT. No 7" handling equipment for packer seal bore extension. Call Parker well bore and line up equipment for chopper. Line up chopper. M/U packer inner string on deck and trq same with pipe wremches as per Baker Rep.. P/U and M/U seal bore extension onto bottom of packer assy as per Baker Rep.. P/U paker/seal bore assy and tail onto the rig floor with crane. Trq connections onseal bore ext. f/ 5" and 7" on rig floor in mouse hole and rotary table w/rig tongs. Mix and fill packer w/pa il mix, all as per Baker Rep.. Fill pipe and pump liner volume @4bpm, 170psi. R/D Packer wellbore casing equipment. RIH w/ 7"x 9-5/8" SLZXP (HRD-E) liner top hanger packer on 5"DP f/5485' t/8200''. Monitoring displacement on the TT, easy in/out of slips @1.5-2minuts a std. Report Number 47 Report Start Date 4/30/2024 Report End Date 5/1/2024 Operation Cont. RIH w/ 7"x 9-5/8" SLZXP (HRD-E) liner top hanger packer on 5"DP f/8200' t/11202'. Monitoring displacement on the TT, easy in/out of slips @1.5-2minuts a std. P/U cementing tool w/15' pup and wash dwn f/11202' t/11303', 7ft deep, tag w/10k dwn x2. Stage pumps up f/2bpm t/5bpm, 400psi, reciprocating 15'. Pumped 3.75 liner vol. Hold pre-job for cement w/circ.. Shut dwn pumps and R/U cement hose, cementers test lines w/5bbl h2o t/580psi-low, 4950psi-high-good. Mix and pump 50bbl/10.5ppg spacer. Haliburton mix/pump 220bbls of 14ppg lead cement @5bpm, 480psi; @211bbls pumped circ. slowed dwn, pressure increased t/1400psi. Stopped pumping, no pressure loss. Attempt to pump again, increase in pressure t/4800psi, pressure did not leak off. Decision made to set packer, set as per Baker Rep., Un-sting and Spaced out, closed annular and reversed out cement from DP w/357gpm, 2000psi. Cement returns at surface, dump same at shakers. Cont. circ. until clean. Stop pump, R/D cement head and Kelly up Topdrive on pup jt. After inspecting cement head, it was determined that there was a failure and the dart released early. 35 bbls and 50 bbls spacer were pumped before dart released. full returns during job until 211 bbls pumped. Circ. B/U @300gpm, 380psi, while monitoring shakers for cement, no cement. Flow check well-static. Pump slug. POOH w/SLZXP liner setting tool on 5"DP f/5919' t/4426'. P/U Baker cement head and break out 2 pup jts and L/D same. Cont. POOH w/SLZXP liner setting tool on 5"DP f/4426' t/surface. Clean and inspect SLZXP liner setting tool. Break and L/D assy as per Baker Rep. P/U Baker polish mill assy, check trq on breaks and M/U t/5"dp. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig 51 Page 15/15 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Well Operations Summary Operation RIH w/polish mill aasy t/5880', Kelly up and wash dwn @230gpm, 290psi, 20rpm, 3-5k trq, P/U single and Tag bottom of the seal bore @ 5971', 7ft deep, putting TOL @ 5926'md. Ream/polish PBR seal bore 3X, Pull up above PBR, no cement on B/U. R/U and test 9-5/8"x 4-1/2" SLZXP liner top hanger packer and 9-5/8" 47# casing t/3000psi f/30min.-good test. R/D same. Prep for displacement to FIW, flush and drain trip tanks, fill suction pit w/FIW. Displace well to FIW @500gpm, 1280 psi. Rot @ 20rpm, 4ktrq while washing thru PBR. Report Number 48 Report Start Date 5/1/2024 Report End Date 5/2/2024 Operation POOH w/polish mill L/D 5" dp, f/5964' t/surface, monitor fill on the TT. Inspect and clean polish mill, soft break all connections except bottom mill. L/D same. R/U E-line loggers f/CBL, hang sheave, string wire, p/u tools and confirm signal. Simop-top cleaning pits 8,9 and 10. RIH w/CBL logging tool t/5950', begin logging and observe malfunction in corilation.. POOH t/surface, trouble shoot corilation and repair centralizer on CXBL. RIH t/5950'. Perform CBL f/5950' t/surf. R/D E-line and L/D same. RIH w/6 stds 5"HWDP. POOH L/D 5"HWDP. RIH w/5"dp t/5300'+-, Report Number 49 Report Start Date 5/2/2024 Report End Date 5/3/2024 Operation Observed pipe skate out of alignment with V-door. P/U skate with crane, adjust and re-secure skate. POOH l/d 5"dp f/5349' t/4600, monitoring fill on the TT. Observed pipe skate out of alignment with V-door. P/U skate with crane, adjust and re-secure skate. Grease skate and make visual inspection of working components. POOH l/d 5"dp f/4600' t/185', monitoring fill on the TT. M/U running tool and pull wear ring and L/D tool. M/U Vault wash tool, wash dwn through BOP's, function same. Wash dwn and tag well head, p/u as per Vault Rep. and wash well head profile @175gpm,150psi, 5rpm, .5kTrq. POOH w/ tool and L/D tool and rack back std. Blown dwn HP mud line f/rig floor t/pits. C/O elevators t/4.5" tbg elevators, p/u power tongs, slips and air slips w/Parker Casing Rep. Pre-job on running 4.5" completion as per tally with all involved. P/U seal assy, pup and 1st GLM assy, M/U and RIH t/63'. Cont RIH w/4.5" 12.6# t/3600. Report Number 50 Report Start Date 5/3/2024 Report End Date 5/4/2024 Operation Cont RIH w4.5" completion as per tally 12.6# F/3600 T/ 5882'. M/U XO to Dp. Change handling equipment to 5'' DP. Wash down at 2 BPM. Saw good indication of seals engaging. Shut down pump. 100 psi . Bleed down. Land out on depth with 10 K Down. Test down tubing to 500 psi for 5 min Good. Strap out of the hole. No space out pups needed. M/U hanger and landing jopint. RIH and land out hanger. 1.10 off of no go. Wellhead hand test pack off seals. Good. Set hanger backing off ring. R/U & Test down tubing to 3000 psi 30 min. Good. Bleed down. R/U & perform combo test to 3000 psi. 30 min. Good. Back out landing joint. & L/D Running tool. R/U & Set TWC as per vault Rep. Clean and clear rig floor of unneded tools prep for shut down. Flush barakleen thru topdrive, std pipe manifold, kill line, choke manifold, trip tank and degasser. L/D 2 stds 5" dp, blow down HP lines f/rig floor t/pits. Flush lines on trip tank, degasser and send barakleen pill back t/pits. Build baracor pill and flush thru rig tankage, and send baracor pill back t/pits. Removing handling equipment, test pump. R/D skate on rig floor and prepping to clean rotary housing. Lay over skate. Remove master rotary bushings, pull bell riser. Remove geoskid and knack box f/cellar, simop-remove choke/kill hoses f/BOP outlets. R/D pollution pan and clean same. Breakoff annular and set out of cellar. Simop-transfer barakleen pill to ISO tank. Breal off DBL Gate and set out of cellar. Report Number 51 Report Start Date 5/4/2024 Report End Date 5/5/2024 Operation Cont. n/d BOPE, break off mud-X and valves and set outside of cellar. Break off single gate and set outside of cellar. N/D riser sections X2 and set out of cellar. Clean top of hanger and expedite tree peices into well room. Simop-work boat. Install bonnet, master valve, block T, swab, tree cap and air actuated valves. Position tree as per Production operator. Tighten same. Test neck seals on hanger-good, test void seal on bonnet-good, and test shell of whole tree-good as per wp10/Vault wellhead Rep. Simop-work boat. Clean rig floor. Clean well room and remove all tool and equipment, cleaning rig floor. Crane working top deck making room to skid rig package. Prep rig for skidding. API: 50733207190000 Field: McArthur River Field (MRF) Sundry #: 224-018 State: ALASKA Rig/Service: Rig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age 1/1 Well Name: MRF M-23 Report Printed: 7/15/2024 www.peloton.com Casing Surface Wellbore Wellbore Name: Original Hole Total Depth of Wellbore (ftKB): 11,296.00 Original KB/RT Elevation (ft): RKB to GL (ft): KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): 1,700.0 Depth (ftKB): 6,149.0 Depth (ftKB): 11,296.0 Casing Casing Description: Surface Run Date: 3/28/2024 Set Depth (ftKB): 1,700.00 Casing Weight on Slips (1000lbf): 92.5 Pick Up Weight (1000lbf): 165.0 Block Weight (1000lbf): 45.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 13.50 Ft/Min (ft/min): 2.10 Run Job: 241-00038 TBU M-23 Drilling, Drilling - Drilling, 3/15/2024 06:00 Set Depth (ftKB): 1,700.00 Set Depth (TVD) (ftKB): Centralizer Detail: 1-10ft above shoe, 1-10ft above float, every other jt to conductor=14total Attribute Subtype: Value: Pipe Reciprocated?: No Pipe Rotated?: No Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) RKB BTC 77.23 77.23 0.00 1 Casing Hanger 13 3/8 68.00 Left hand ACME Cactus 28x13-3/8x9-5/ 8x4-1/2 5M 0.52 77.75 77.23 1 Casing Pup Joint 13 3/8 12.41 68.00 L-80 BTC 3.95 81.70 77.75 36 Casing Joints 13 3/8 12.41 68.00 L-80 BTC 1,528.14 1,609.84 81.70 1 Float Collar 13 3/8 12.68 68.00 BTC Summit 1.93 1,611.77 1,609.84 1 Casing Joints 13 3/8 12.41 68.00 L-80 BTC 43.19 1,654.96 1,611.77 1 Casing Joints 13 3/8 12.41 68.00 L-80 BTC 43.04 1,698.00 1,654.96 1 Float Shoe 13 3/8 12.68 68.00 BTC Summit 2.00 1,700.00 1,698.00 Page 1/1 Well Name: MRF M-23 Report Printed: 7/15/2024 www.peloton.com Cement Surface Casing Cement Type Casing Description Surface Casing Cement Cemented String Surface, 1,700.00ftKB Wellbore Original Hole Job 241-00038 TBU M-23 Drilling, Drilling - Drilling, 3/15/2024 06:00 Cementing Start Date 3/29/2024 Cementing End Date 3/29/2024 Top Depth (ftKB) 77.8 Cement Stages Stage Number: 2 Description Surface casing cement Top Depth (ftKB) 77.8 Bottom Depth (ftKB) 1,710.0 Top Measurement Method Returns to Surface Pump Start Date 3/29/2024 Cement in Place At 3/29/2024 Final Circulating Pressure (psi) 432.0 Plug Bump Pressure (psi) Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 90.0 Volume Lost (bbl) 0.0 Bump Plug? No Float Failed? No Pipe Reciprocated? No Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Tuned Prime Spacer prime 10.50 80.0 80.0 5 cement Lead Slurry Lead Cement 1,020 2.35 12.00 435.0 432.0 5 cement Tail Slurry Tail Cement 370 1.16 15.80 76.0 76.0 4 cement Displacement Displacemen t 8.33 28.6 28.6 4 H2O Post Job Calculations Subtype Value Page 1/1 Well Name: MRF M-23 Report Printed: 7/15/2024 www.peloton.com Casing Intermediate1 Wellbore Wellbore Name: Original Hole Total Depth of Wellbore (ftKB): 11,296.00 Original KB/RT Elevation (ft): RKB to GL (ft): KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): 1,700.0 Depth (ftKB): 6,149.0 Depth (ftKB): 11,296.0 Casing Casing Description: Intermediate1 Run Date: 4/14/2024 Set Depth (ftKB): 6,149.81 Casing Weight on Slips (1000lbf): 140.0 Pick Up Weight (1000lbf): 250.0 Block Weight (1000lbf): 45.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 20.00 Ft/Min (ft/min): 5.12 Run Job: 241-00038 TBU M-23 Drilling, Drilling - Drilling, 3/15/2024 06:00 Set Depth (ftKB): 6,149.81 Set Depth (TVD) (ftKB): 6,149.8 Centralizer Detail: 1-10ft above shoe, 1-free float on spacer jt. 88 hydrostamp centralizers every other jt, 14-bow sp Attribute Subtype: Value: Pipe Reciprocated?: Yes Pipe Rotated?: Yes Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) RKB 75.91 77.72 1.81 1 Casing Hanger 9 5/8 8.84 47.00 Left hand ACME Cactus 28x13-3/8x9-5/ 8x4-1/2 5M 0.68 78.40 77.72 125 Casing Joints 9 5/8 8.84 47.00 L-80 DWC 5,185.24 5,263.64 78.40 16 Casing joints 9 5/8 8.84 47.00 L-80 BTC/TXP 612.92 5,876.56 5,263.64 4 Casing joints 9 5/8 8.84 47.00 L-80 CDC 155.81 6,032.37 5,876.56 1 Casing Joint Bkr lok 9 5/8 8.84 47.00 L-80 CDC 39.13 6,071.50 6,032.37 1 Float Collar Bkr lok 9 5/8 8.84 47.00 BTC Summit 1.33 6,072.83 6,071.50 1 Casing Joints 9 5/8 8.84 47.00 L-80 BTC 36.96 6,109.79 6,072.83 1 Casing Joints 9 5/8 8.84 47.00 L-80 BTC 38.23 6,148.02 6,109.79 1 Float Shoe 9 5/8 8.84 47.00 BTC Summit 1.79 6,149.81 6,148.02 Page 1/1 Well Name: MRF M-23 Report Printed: 7/15/2024 www.peloton.com Cement Intermediate Casing Cement Type Casing Description Intermediate Casing Cement Cemented String Intermediate1, 6,149.81ftKB Wellbore Original Hole Job 241-00038 TBU M-23 Drilling, Drilling - Drilling, 3/15/2024 06:00 Cementing Start Date 4/15/2024 Cementing End Date 4/15/2024 Top Depth (ftKB) 75.8 Cement Stages Stage Number: 1 Description Intermediate Casing Cement Top Depth (ftKB) 75.8 Bottom Depth (ftKB) 6,148.0 Top Measurement Method Returns to Surface Pump Start Date 4/15/2024 Cement in Place At 4/15/2024 Final Circulating Pressure (psi) 840.0 Plug Bump Pressure (psi) 1,300.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 120.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? Yes Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Spacer 3.82 10.50 60.0 60.0 HES Lead Slurry Lead 1,033 2.40 12.00 438.0 438.0 HES Tail Slurry Tail 172 1.24 15.30 35.0 35.0 HES Displacement LSND 9.60 425.0 425.0 Rig Pump #1 Post Job Calculations Subtype Value Page 1/1 Well Name: MRF M-23 Report Printed: 7/15/2024www.peloton.com Casing Liner 1 Wellbore Wellbore Name:Original Hole Total Depth of Wellbore (ftKB):11,296.00 Original KB/RT Elevation (ft): RKB to GL (ft):KB-Casing Flange Distance (ft):KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB):1,700.0 Depth (ftKB):6,149.0 Depth (ftKB):11,296.0 Casing Casing Description:Liner 1 Run Date:4/29/2024 Set Depth (ftKB):11,290.00 Casing Weight on Slips (1000lbf):205.0 Pick Up Weight (1000lbf):250.0 Block Weight (1000lbf):45.0 Make-Up Contractor:Parker Casing Number Hrs to Run (hr):21.00 Ft/Min (ft/min):8.96 Run Job:241-00038 TBU M-23 Drilling, Drilling - Drilling, 3/15/2024 06:00 Set Depth (ftKB):11,290.00 Set Depth (TVD) (ftKB): Centralizer Detail:1-10ft above shoe, 1-10ft above landing collar, every other jt t/5964ft Attribute Subtype:Value: Pipe Reciprocated?:No Pipe Rotated?:No Float Failed?:No Test Subtype:Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in)Wt (lb/ft)Grade Top Thread Make Section Length (ft)Btm (ftKB)Top (ftKB) 1 7"x 9-5/8"SLZXP Liner Hanger 8.42 6.18 L-80 TSH w563 Baker Hughes 21.62 5,940.78 5,919.16 1 7" Casing RS Nipple Joint 7 6.19 L-80 TSH w563 Baker Hughes 2.82 5,943.60 5,940.78 1 7" Casing Nipple Joint 7 6.18 26.00 L-80 TSH w563 Baker Hughes 1.35 5,944.95 5,943.60 1 7" Casing Pup Joint 7 6.18 26.00 L-80 TSH w563 Baker Hughes 6.11 5,951.06 5,944.95 1 XO 7"-32# x 5.5"-17#7 4.89 TSH w563 Baker Hughes 1.68 5,952.74 5,951.06 1 10' sealbore ext. 5.5-17#5 1/2 4.75 17.00 TSH w563 Baker Hughes 9.67 5,962.41 5,952.74 1 XO bushing 5.5-17# x 4.5-12.6#5 1/2 3.92 TSH w563 Baker Hughes 1.65 5,964.06 5,962.41 21 21 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 848.17 6,812.23 5,964.06 1 Liner Pup Joint 4 1/2 3.96 12.60 L-80 TXP/BTC 20.09 6,832.32 6,812.23 21 21 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 845.58 7,677.90 6,832.32 1 Marker Joint, RA 4 1/2 3.96 12.60 L-80 TXP/BTC 40.47 7,718.37 7,677.90 22 22 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 877.76 8,596.13 7,718.37 1 Liner Pup Joint 4 1/2 3.96 12.60 L-80 TXP/BTC 20.15 8,616.28 8,596.13 21 21 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 842.28 9,458.56 8,616.28 1 Marker Joint, RA 4 1/2 3.96 12.60 L-80 TXP/BTC 40.02 9,498.58 9,458.56 21 21 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 841.63 10,340.21 9,498.58 1 Liner Pup Joint 4 1/2 3.96 12.60 L-80 TXP/BTC 20.13 10,360.34 10,340.21 20 20 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 805.36 11,165.70 10,360.34 1 1 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 39.38 11,205.08 11,165.70 1 Landing Collar 4 1/2 2.39 12.60 L-80 TXP/BTC Baker Hughes 1.00 11,206.08 11,205.08 1 1 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 41.06 11,247.14 11,206.08 1 Float Collar 4 1/2 1.88 12.60 L-80 TXP/BTC OSP 1.29 11,248.43 11,247.14 1 1 jt. 4.5" 12.6# L-80 liner 4 1/2 3.96 12.60 L-80 TXP/BTC 40.11 11,288.54 11,248.43 1 Float Shoe 5 1/4 1.63 12.60 L-80 TXP/BTC OSP 1.46 11,290.00 11,288.54 Page 1/1 Well Name: MRF M-23 Report Printed: 7/15/2024 www.peloton.com Cement Liner Cement Type Casing Description Liner Cement Cemented String Liner 1, 11,290.00ftKB Wellbore Original Hole Job 241-00038 TBU M-23 Drilling, Drilling - Drilling, 3/15/2024 06:00 Cementing Start Date 4/30/2024 Cementing End Date 4/30/2024 Top Depth (ftKB) 11,229.0 Cement Stages Stage Number: 1 Description Liner Cement Top Depth (ftKB) 11,229.0 Bottom Depth (ftKB) 11,296.0 Top Measurement Method Volume Calculations Pump Start Date 4/30/2024 Cement in Place At 4/30/2024 Final Circulating Pressure (psi) 480.0 Plug Bump Pressure (psi) 1,400.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) Volume Lost (bbl) 0.0 Bump Plug? No Float Failed? No Pipe Reciprocated? No Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Spacer 10.50 50.0 HES Lead Slurry Lead A 550 2.39 12.00 211.0 211.0 HES Post Job Calculations Subtype Value 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: 05/14/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL TBU M-23 PTD: 224-018 API: 50-733-20719-00-00 FINAL LWD FORMATION EVALUATION LOGS (03/25/2024 to 04/28/2024) AGR, DGR, BaseStar Gamma Ray EWR-M5, ADR, ResiStar Resistivity LithoStar Density and Porosity ALD Lithodensity, CTN Thermal Neutron 2” & 5” MD/TVD Color Log Prints Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 224-018T38811 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.16 12:49:49 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 05/14/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL TBU M-23 PTD: 224-018 API: 50-733-20719-00-00 Final GeoTap Formation Pressure Tester (03/25/2024 to 04/28/2024) SFTP Transfer - Data Folders: Please include current contact information if different from above. 224-018T38810 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.16 12:44:18 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/10/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240510-1 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 242-04 50283201640000 212041 3/11/2024 AK E-LINE Perf LRU C-01RD 50283200610100 201168 4/26/2024 AK E-LINE Perf LRU C-02 50283201900000 223057 4/28/2024 AK E-LINE Perf MPU F-65 50029227526000 223121 5/3/2024 AK E-LINE HoistCut MPU L-07 50029220280000 190037 4/26/2024 AK E-LINE Perf NCIU A-17 50883201880000 223031 4/28/2024 AK E-LINE GPT/Perf NCIU B-02 50883200900100 197210 4/29/2024 AK E-LINE PPROF NCIU B-02 50883200900100 197210 5/4/2024 AK E-LINE PPROF PAXTON 6 50133207070000 222054 4/13/2024 AK E-LINE GPT/CIBP/Perf PAXTON 6 50133207070000 222054 4/16/2024 AK E-LINE GPT/CIBP/Perf SRU 14B-27 50133206040000 212089 4/23/2024 AK E-LINE Caliper SRU 32C-15 50133206130000 213070 4/24/2024 AK E-LINE Caliper TBU M-15 50733204220000 190109 4/18/2024 AK E-LINE GPT/Puncher TBU M-23 50733207190000 224018 5/1/2024 AK E-LINE CBL Please include current contact information if different from above. T38780 T38781 T38782 T38783 T38784 T38785 T38786 T38786 T38787 T38787 T38788 T38789 T38790 T38791TBU M-23 50733207190000 224018 5/1/2024 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.13 15:31:19 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Shane Hauck To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Steve Dambacher - (C); Bruce Hebert - (C); Sean McLaughlin Subject:Steelhead M-23 bope test report Date:Monday, April 29, 2024 8:44:47 AM Attachments:TBU-M-23 4-27-2024 Bop Test.xlsx Mr. Regg Here is our test report Thanks Shane R Hauck Hilcorp DSM Steelhead rig #51 907-776-6833 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Su bm it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:51 DATE: 4/27/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name: PTD #2240180 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: Weekly: Bi-Weekly: X Other: Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2825 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 FP Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13 5/8 / 5K P Pit Level Indicators P P #1 Rams 1 2-7/8" X 5-1/2'' / 5K P Flow Indicator P P #2 Rams 1 Blinds / 5K FP Meth Gas Detector P P #3 Rams 1 5'' Pipe / 5K P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8/ 5K P Time/Pressure Test Result HCR Valves 2 3 1/8 / 5K P System Pressure (psi)3100 P Kill Line Valves 2 3 1/8 / 5K P Pressure After Closure (psi)1400 P Check Valve 0 NA 200 psi Attained (sec)59 P BOP Misc 0 NA Full Pressure Attained (sec)230 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 8 @ 2350 P No. Valves 14 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec) Test Result CH Misc 0 NA Annular Preventer 24 P #1 Rams 12 P Coiled Tubing Only:#2 Rams 12 P Inside Reel valves 0 NA #3 Rams 12 P #4 Rams NA NA Test Results #5 Rams NA NA #6 Rams NA NA Number of Failures:2 Test Time:13.0 HCR Choke 10 P Repair or replacement of equipment will be made within 0 days. HCR Kill 10 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 4-23-2024 08:15 Waived By Test Start Date/Time:4/27/2024 1:00 (date) (time)Witness Test Finish Date/Time:4/27/2024 14:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp All rams and valves tested to 250/3500 psi. Tested annular to 250/3500 psi. Tested with 4-1/2" and 5'' Test joint. We did have F/P on blind test bleed air retest good. floor valve failed removed from floor tested back up valve good also had 4-1/2" test jt leak at connection re tightin conn and tested good ( did not count this as a F/P do to it beeing a test jt) all gas alarms test good shane Hauck Enterprise Offshore Bruce Hebert TBU M-23 Test Pressure (psi): shauck@hilcorp.com bruce.hebert@hilcorp.com Form 10-424 (Revised 08/2022) 2024-0427_BOP_Hilcorp51_TBU_M-23 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 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): ±11,192 (proposed)N/A Casing Collapse Structural Conductor Surface 2,260psi Intermediate Production 4,750psi Liner 7,500psi 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: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: Initial Completion McArthur River N/A Middle Kenai Gas ±8,671 (proposed) ±11,092 (proposed) ±7,530 (proposed) 2,833psi 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 8,430psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 224-018 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20719-00-00 Hilcorp Alaska, LLC Trading Bay Unit M-23 Length Size Proposed Pools: L-80 TVD Burst ±5,890' (proposed) 6,870psi MD 5,020psi 480' 1,580' 480' 1,700' 26" 13-3/8" 480' 1,700' ±5,900 - ±11,192(proposed) 6,148' 4-1/2" ±3,520 - ±8,671(proposed) 3,708'9-5/8" CO 228A 5/1/2024 ±11,192' (proposed)±5,302' (proposed) 4-1/2" 4,021' LTP & SSSV (proposed)±5,890' MD /±3,515' TVD &± 500' MD/TVD (proposed) 6,148' Perforation Depth MD (ft): 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 3:46 pm, Apr 17, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.04.17 15:22:22 - 08'00' Dan Marlowe (1267) 324-224 +/-8671' BJM 4/25/24 SFD 4/24/2024 10-407 CT BOP test to 3000 psi. Submit CBL to AOGCC and obtain approval before perforating. X DSR-4/23/24 -bjm *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.26 11:33:55 -08'00'04/26/24 RBDMS JSB 042924 Initial Completion Well: Steelhead M-23 Well Name:Steelhead M-23 API Number:50-733-20719-00-00 Current Status:New drill gas well Leg:Leg #B2 (NE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:224-018 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,700 psi @ 8,671’ TVD Worst case at TD from PTD Max. Potential Surface Pressure: 2833 psi Using 0.1 psi/ft Brief Well Summary Steelhead platform Rig #51 had TD’d and cased the intermediate section as of this writing. The drilling rig will leave the well with production tubing installed/tested, and nothing open to the formation. This procedure addresses the initial port-rig completion wellwork to get the well online. All planned perforations below are within the Middle Kenai Gas Pool as defined by CO 228A. The goal of this project is to complete the well after the drilling rig leaves. Pertinent wellbore information: - TRSSSV to be installed -Live GLV’s to be run with completion - MIT of Casing and tubing to be completed before post-rig wellwork begins Coiled Tubing Procedure 1. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. MU cleanout BHA 4. RIH to PBTD and swap well over to water if needed 5. Obtain CBL (may be executed on EL. TBD) Submit CBL to AOOGCC 6. RIH and blow well dry with nitrogen a. Reverse circulate water out of wellbore (no perforations, passing MIT’s) b. Want to evacuate all IA fluid through live GLV’s as well 7. RDMO CT Top of MKG Pool at 1475' MD/1432' TVD per R. Rupert email 4/23/24. -bjm All planned perforations below are 1 /1 32 /2within the Middle Kenai Gas Pool as defined by CO 228A Obtain CBL across 4-1/2" liner and 9-5/8" casing sections. -bjm Initial Completion Well: Steelhead M-23 E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. Ensure CBL approval from AOGCC before perforating 4. RIH and perforate D/E/F/G gas sands from ±5,900 - ±11,192’ MD (±3,520’ - ±8,671’ TVD) per RE/Geo a. No G-oil sands will be perforated b. No sands will be shot above the 4-1/2” Liner Top packer. c. Tubing integrity above LTP will not be compromised 5. RDMO EL CONTINGENCY plug/patch: (if any zone makes unwanted solids or water) 1. RU nitrogen to tubing and PT lines to 3000psi (or higher if needed) 2. Pressure up on tubing and displace water back into formation 3. MIRU E-line and pressure control equipment 4. PT lubricator to 250psi low / 3000psi high 5. Set 4-1/2” isolation plug or patch per OE 6. RDMO Nitrogen and EL CONTINGENCY CT Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. MU FCO BHA 4. RIH and cleanout to PBTD or as deep as practical a. Working fluid will be water (8.33ppg or greater) b. Take returns to surface up the CT x tubing annulus c. Add foam and nitrogen as necessary to carry solids to surface d. Can use GL to assist with hole cleaning 5. Once cleanout is completed, blow well down with nitrogen 6. RDMO CT Attachments: 1. Proposed Wellbore Schematic 2. CT BOP Drawing (Fox energy) 3. Nitrogen procedure ±5,900 - ±11,192’ MD (±3,520’ - ±8,671’ TVD) Shallowest allowable perforation is 8,162' MD (5,650' TVD) to stay below the 12.5 ppg FIT test obtained beneath the intermediate casing shoe, per Ryan Rupert email dated 4/23/2024 SFD Can not perf this entire interval at once due to PPFG limitations. -bjm SFD Top of Middle Kenai Gas Pool is 1,475' MD (1,432' TVD), per Ryan Rupert email dated, 4/23/2024 SFD Hilcorp requests to perforate from TD (8671' TVD) up to 8162' MD (5650' TVD). _____________________________________________________________________________________ Updated by JLL 04/17/24 PROPOSED SCHEMATIC McArthur River Well: TBU M-23 PTD: 224-018 API: 50-733-20719-00-00 TD =±11,192’(MD) /±8,671’(TVD) x 28” RKB: GL = 73.7’ 4-1/2” 4/5 6/7 13-3/8” 9-5/8” 3 2 1 Gas Sands D-G PBTD =±11,092’(MD) /±7,530’(TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 26" Conductor 262 / - / Weld 27” Surf 480’ 13-3/8” Surface 68 / L-80 / BTC 12.415” Surf 1,700’ 9-5/8" Intermediate 47 / L-80 / TXP 8.861” Surf 6,148' 4-1/2" Production 12.6 / L-80 /TXP 3.958”±5,890' ±11,192’ Tieback Detail 4-1/2” Tieback 12.6 / L-80 / TXP 3.958”Surface ±5,890' *Minimum 100’ overlap for liner OPEN HOLE / CEMENT DETAIL 13-3/8” Est. TOC @ surface L – 2137 ft3 (100% OH excess) / T – 424 ft3 9-5/8" Est. TOC @ surface L – 2457 ft3 (40% OH excess) / T – 194 ft3 4-1/2” TOC liner @ 6,400 L – 1691 ft3 (40% OH excess) / T – 148 ft3 JEWELRY DETAIL No.Depth MD Depth TVD Item 1 ±500’ ±500' SSSV 2 ±2,600’ ±2,135' GLM 3 ±5,100’ ±3,126' GLM 4 ±5,830' ±3,476' GLM 5 ±5,840' ±3,483' X Nipple 3.813” Profile 6 ±5,890' ±3,515' Seal Stem 7 ±5,890' ±3,515' Liner hanger / LTP Assembly PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status D-G ±5,900' ±11,192' ±3,520' ±8,671' ±5,292' Future Proposed +/-8571' (TVD) -bjm 6,148' MD / 4,118' TVD SFD See updated proposed perf interval on attached email from R. Rupert 4/23/24. -bjm KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Ryan Rupert To:Davies, Stephen F (OGC); McLellan, Bryan J (OGC) Cc:Dewhurst, Andrew D (OGC); Juanita Lovett; Ryan Rupert; Dan Marlowe Subject:RE: [EXTERNAL] RE: TBU M-23 (Permit 224-018, Sundry 324-224) - Request and Question Date:Tuesday, April 23, 2024 3:10:46 PM Steve/Bryan- Here’s the answers to your questions. Easier if we just withdraw and resubmit a new sundry? Top Middle Kenai Gas Pool in M-23: 1,475’ MD / 1,432’ TVD FIT passed to 12.5PPG at 6149’ MD (3714’ TVD) Hilcorp requests to perforate from TD (8671’ TVD) up to 8162’ MD (5650’ TVD). A worst case pressure at deepest perfs: 8671’ * 0.45psi/ft = 3,902psi Gas gradient up to shallowest requested perf: (8671’ – 5650’) * 0.1psi/ft = 302psi Worst case pressure at shallowest sand: 3902psi – 302psi = 3600psi at 5650’ TVD 3600psi / 5650’ / 0.052 = 12.3ppg EMW This falls below the 12.5ppg FIT test from intermediate casing shoe. Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, April 23, 2024 8:48 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL] RE: TBU M-23 (Permit 224-018, Sundry 324-224) - Request and Question CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Ryan, Just a reminder that additional information is needed for my review of Hilcorp’s Sundry Application for TBU M-23. I’d like to keep this application moving through AOGCC’s review process. Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov From: Davies, Stephen F (OGC) Sent: Sunday, April 21, 2024 9:02 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: TBU M-23 (Permit 224-018, Sundry 324-224) - Request and Question Ryan, Please provide the MD/TVD of the top of the Middle Kenai Gas Pool in TBU M-23. With such a broad depth range requested for the planned perforations (5,051 vertical feet), how will Hilcorp ensure that deep, open perforations will not create problems when opening additional perforations shallower in the well (i.e., calculate the shallowest allowable perforations)? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:McLellan, Bryan J (OGC) To:Sean McLaughlin Subject:RE: [EXTERNAL] RE: M-23 (224-018) Intermediate FIT Date:Friday, April 19, 2024 3:13:00 PM Sean, Looks like the correct volume of displacement was pumped, so cement was not overdisplaced, despite the wet shoe. I think the FIT is good at 12.67 ppg. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, April 19, 2024 3:03 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 (224-018) Intermediate FIT We did have a wet shoe that failed the PT. Was a bit surprised after a 1300psi plug bump on time, floats held, and reasonable amount of cmt to surface. I was happy with the pressure decay as well. The OIM suspects something is going on with the suction screens. We pulled and clean between test but didn’t help that much. The mud doesn’t appear to be aerated. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, April 19, 2024 2:44 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: M-23 (224-018) Intermediate FIT 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. Sean, Could you send the cement report? Was there anything unusual about the cement? FIT pressure held steady after shutting down the pumps so seems like the shoe is good to 12.6 ppg. Do you have any theories why it took so long to pressure up on both attempts? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, April 19, 2024 2:17 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: M-23 (224-018) Intermediate FIT M-23 (224-018) Intermediate FIT – This is the second test, first one acted the same. Taking a long time to catch pressure. sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Engineer Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. HILCORP ALASKA LLC For: Sloan Sunderland Date: Monday, April 15, 2024 M 23 HILCORP- M 23 INTERMEDIATE-15 April 2024 Job Date: Monday, April 15, 2024 Sincerely, Bahaa Abouchami Legal Notice Disclaimer: All information in this report is provided subject to the terms and conditions which govern the services provided by Halliburton. Halliburton personnel use their best efforts in gathering information and their best judgment in interpreting it, but any interpretation, research, analysis or recommendation furnished by Halliburton are opinions based upon inferences from measurements and empirical relationships and assumptions, which inferences and empirical relationships and assumptions are not infallible, and with respect to which professionals in the industry may differ. iCem 3D Displacement results are used to understand how fluids intermix during a cement job. Simulation and 3D displacement results are not intended as and should not be used as a replacement for bond logs in determining top of cement. Current 3D model calculations are known to model more volume than the input volume for standard cases due to known calculation improvements required. For rotational cases, the modeled volume will be impacted by the same calculations impacting the standard cases, as well as additional constraints imposed to make the calculation time required operationally feasible. Therefore, until further notice, 3D displacement results should not be used for replacement of a bond log, or used as an identifier of top of cement. HALLIBURTON IS UNABLE TO GUARANTEE THE ACCURACY OF ANY CHART INTERPRETATION, RESEARCH ANALYSIS, OR JOB RECOMMENDATION and any interpretation or recommendation is not for use of or reliance upon by any third party. The customer has full responsibility for any of its decisions which are based on the information provided in this report. © 2021 Halliburton. All rights reserved. Customer: HILCORP ALASKA LLC Job: HILCORP- M 23 INTERMEDIATE-14 April 2024 Case: HILCORP- M 23 INTERMEDIATE-14 April 2024 | SO#: 909274915 Page 3 (v. 7.0.192.0) Created: Monday, April 15, 2024 Table of Contents Real-Time Job Summary ......................................................................................................................................... 4 Job Event Log ......................................................................................................................................................................................... 4 Attachments ............................................................................................................................................................ 6 HILCORP- M 23 INTERMEDIATE-14 April 2024-Custom Results.png ..................................................................................................... 6 Custom Graphs .......................................................................................................... Error! Bookmark not defined. Custom Graph .......................................................................................................................................... Error! Bookmark not defined. Customer: HILCORP ALASKA LLC Job: HILCORP- M 23 INTERMEDIATE-14 April 2024 Case: HILCORP- M 23 INTERMEDIATE-14 April 2024 | SO#: 909274915 Page 4 (v. 7.0.192.0) Created: Monday, April 15, 2024 1.0 Real-Time Job Summary 1.1 Job Event Log Seq . No. Graph Label Date Time DS Pump Press DH Densit y Comb Pump Rate Pump Stg Tot Water Stg Tot Comments (psi) (ppg) (bbl/min) (bbl) (bbl) 1 called out by customer 4/14/2024 02:00:00 called out by customer @ 14:30 2 pre convoy meeting 4/14/2024 02:45:00 Pickup 12251191 pickup 11506323 3 arrive on location 4/14/2024 03:00:00 arrived at heliport at 03:00. Arrived on Steelhead at 04:00 met with company rep. Rig running casing 4 rig circulated 4/14/2024 04:00:00 rig circulated 9.6 ppg mud, 700 bbls Mud YP 19 / PV 10 reciprocated and rotated pipe rat hole length 8 ft 5 rig up Halliburton equipment 4/14/2024 05:00:00 pre job JSA and rig up iron and hoses. blow down all lines. 6 water test 4/14/2024 06:00:00 preformed water test CL 0 PPM, PH 7, temp 71 F 7 well information 4/14/2024 07:00:00 TD 6157 FT, SJ 6149 FT-6071 FT OH 12.25", CSG 9.625", 47 LB, L80 surface at 1700 ft 8 pre job safety meeting 4/15/2024 02:30:00 jsa completed and signed 9 Start Job 4/15/2024 02:42:23 0.87 0.00 0.00 0.00 0.11 10 fill lines and pressure test 4/15/2024 03:04:05 107.76 0.00 1.69 1.66 1.82 fill lines with 5 bbls water, PT 1500 psi low, 4200 psi high 11 pump spacer 4/15/2024 03:24:00 137.10 10.34 2.32 1.69 5.04 pump 60 bbls of 10.5 ppg @ 3 bpm, 330 psi Customer: HILCORP ALASKA LLC Job: HILCORP- M 23 INTERMEDIATE-14 April 2024 Case: HILCORP- M 23 INTERMEDIATE-14 April 2024 | SO#: 909274915 Page 5 (v. 7.0.192.0) Created: Monday, April 15, 2024 12 drop bottom plug 4/15/2024 03:48:00 40.77 9.70 0.00 55.07 51.58 13 pump lead cement 4/15/2024 03:50:00 40.47 9.68 0.00 55.07 51.58 pump 1033 sks lead cement, 12 ppg, Y 2.396 CF/sk, WR 14.114 gal/sk. pumped 438 bbls @ 5 bpm, 540 psi 14 pump tail cement 4/15/2024 05:25:47 789.83 15.06 3.94 18.85 378.67 mix 172 sks, 15.3ppg, Y 1.237 CF/sk, WR 5.58 gal/sk. pump 35 bbls cement @ 3bpm, 820 psi 15 drop top plug 4/15/2024 05:32:19 76.47 14.85 0.00 38.88 386.87 16 pump displacement 4/15/2024 05:36:00 68.83 14.85 0.00 38.88 388.09 pump 20 bbls water behind plug, 425 bbls 9.6 ppg mud @ 7 bpm, 660 psi, slow down to 4 bpm for last 20 bbls, FCP 840 psi. 17 bump plug 4/15/2024 06:53:00 bump plug @ 1300 psi, checked floats, floats held, CIP @ 6:58 18 End Job 4/15/2024 07:00:00 120 bbls cement returned to surface, 60 bbls spacer returned to surface. Rotated and reciprocated trough out cement job. Used 10 gal MMCR, 10 gal D Air. 19 rig down equipment 4/15/2024 08:00:00 pre rig down meeting, wash up cement unit, clean lines, rig down equipment. 20 depart location 4/15/2024 11:00:00 pre convoy and travel to yard 21 crew arrived at base 4/15/2024 13:00:00 Customer: HILCORP ALASKA LLC Job: HILCORP- M 23 INTERMEDIATE-14 April 2024 Case: HILCORP- M 23 INTERMEDIATE-14 April 2024 | SO#: 909274915 Page 6 (v. 7.0.192.0) Created: Monday, April 15, 2024 2.0 Attachments 2.1 HILCORP- M 23 INTERMEDIATE-14 April 2024-Custom Results.png From:McLellan, Bryan J (OGC) To:Sean McLaughlin Cc:Regg, James B (OGC); Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] RE: M-23 plan forward Date:Wednesday, April 3, 2024 3:37:00 PM Sean, The AOGCC approves a variance to 20 AAC 25.030(e) to pressure test surface casing to less than 50% of surface casing. The 13-3/8” 68# L-80 casing is rated to burst pressure of 5020 psi. The MPSP of the next hole section is 1558 psi, so an 1800 psi test pressure provides equal or better protection than following the test pressure as described in the regs. A test pressure of 1800 psi (35.8% of burst) is approved. This approval is conditioned on the lower test pressure being communicated to the Steelhead production operators and the maximum allowable annular pressure during well production operations being set below 1000 psi on the 13-3/8” x 9-5/8” annulus. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Wednesday, April 3, 2024 8:21 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 plan forward Bryan, 6 of the 8 conductor flutes were sealed up yesterday. The welders timed out and are resting now. Overnight we performed the BOPE test. Plan forward: Finish sealing two conductor flutes Shut in 4” valves and monitor pressure build up (limit to 165 psi) After pressure has stabilized monitor the conductor for gas. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Pressure test the surface casing Monitor the conductor for gas Preform dye penetrate inspection on the welds Request: The planned surface casing test is to 2500 psi. The MASP of the 12-1/4” hole section is 1558 psi. I would like to perform an 1800 psi surface casing test. The 9-5/8” intermediate casing will be brought to surface and cover the 13-3/8”. Regards, sean From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, April 2, 2024 8:59 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 plan forward Bryan, The welding of the flutes was completed at 0500. The 4” valves were shut in and no pressure was building. A LEL monitor detected a small amount of gas coming from a few weld spots that need more attention. Soapy water was used to confirm the leak points. After the welders get some rest, we will fill in the areas that need attention. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 2, 2024 8:16 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: Re: [EXTERNAL] RE: M-23 plan forward Can you send an update? Sent from my iPhone On Apr 1, 2024, at 6:25 PM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> wrote: Thank you Bryan, these are good discussion points. 1. How will you ensure Nitrogen leaking out through the open flutes during the Nitrogen purge operation will not create an asphyxiation hazard in this enclosed room? 1. There room will not be enclosed during the purge. A very small quantity of nitrogen will be used, only enough needed to clear the flutes. Nobody is required to be in the room during the purge, it can be done remotely. Positive air flow in the room from two exterior doors. Open water below and no place to accumulate nitrogen. There are O2 sensors in place to monitor air quality. 2. Please ensure Hilcorp’s learnings from the Nitrogen asphyxiation incident on the North Slope are being employed and reviewed by the crew. Please send include a copy of Hilcorp’s Nitrogen procedures. 1. Lessons have been discussed and policy attached. 3. Will you issue some kind of hot work permit to allow for welding in the wellbay? What are the mitigations to avoid creating an explosive environment? 1. Hot work permit will be issued when welder is on tower and preparing for the job. Venting and air monitoring will be in place to ensure a safe environment is maintained. 4. What other potential hydrocarbon sources will exist in the area during welding? 1. No other exposed hydrocarbons are in the area. Hydrocarbons exist behind pipe, we will make sure they stay there. 5. How will you ensure pressure does not build up beyond the limits of the conductor, valves, etc… after the conductor annulus is sealed up? What pressure limit will be applied? 1. The conductor holds 165 psi on offset wells. The valve is rated to 600 psi. 165 psi will be the pressure limit based on a like for like comparison. 6. How will you ensure the heat from welding will not damage any components of the wellhead? Has the wellhead manufacturer been consulted about the plan for welding? 1. There is no guarantee that heat will not damage the well head. There is no manufacture recommendation or specification for welding the flutes closed. The 13-3/8” casing test will re-establish integrity of the wellhead and a pressure envelope. 7. What other risks have been identified? 1. Gas accumulation is the main risk, methane presence needs to be mitigated prior to welding. Regards, sean CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 1, 2024 5:02 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 plan forward Sean, The proposed procedure has some process and personal safety risks that are out of the norm and there’s concern that there may not have been time to thoroughly think through them. The AOGCC has some concerns that we would like to see addressed. Please document a risk assessment to address the following issues, and others that you have identified. 1. How will you ensure Nitrogen leaking out through the open flutes during the Nitrogen purge operation will not create an asphyxiation hazard in this enclosed room? 2. Please ensure Hilcorp’s learnings from the Nitrogen asphyxiation incident on the North Slope are being employed and reviewed by the crew. Please send include a copy of Hilcorp’s Nitrogen procedures. 3. Will you issue some kind of hot work permit to allow for welding in the wellbay? What are the mitigations to avoid creating an explosive environment? 4. What other potential hydrocarbon sources will exist in the area during welding? 5. How will you ensure pressure does not build up beyond the limits of the conductor, valves, etc… after the conductor annulus is sealed up? What pressure limit will be applied? 6. How will you ensure the heat from welding will not damage any components of the wellhead? Has the wellhead manufacturer been consulted about the plan for welding? 7. What other risks have been identified? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@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. +1 (907) 250-9193 <image001.jpg> From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 1, 2024 4:41 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 plan forward All but 4 wells have conductor by surface casing pressure. The average is 50 psi. The lowest is 5 psi and the highest is 165 psi. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 1, 2024 3:33 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: M-23 plan forward Do you know the pressure rating of the valve and conductor pipe? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 1, 2024 3:31 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: M-23 plan forward Bryan, Below is the plan forward for sealing up the M-23 conductor x surface casing: 1. Fill conductor x casing with water (done) 1. It took 3-5 bbls (6’-9’) to fill. 2. Water was being pushed out 2. Open both 4” outlets 1. Purge with Water 2. Purge with Nitrogen 3. Fill hanger flutes with bar stock 4. Weld hanger flutes shut 1. Continuous monitoring of LEL levels required. 5. Place gauge on 4” outlet and monitor pressure build up. 1. Limit pressure 70% of rated valve pressure 2. Monitor for flow and LEL Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Engineer Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 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 thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phonenumber is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phonenumber is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phonenumber is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient 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. <STANDARD WELL PROCEDURE - NITROGEN OPERATIONS FINAL 12-08- 15.pdf> <September 25 Incident RCA (v6).pdf> The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________TRADING BAY UNIT M-23 JBR 06/07/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 5" joint. Good test. Test Results TEST DATA Rig Rep:Hebert/WilsonOperator:Hilcorp Alaska, LLC Operator Rep:Sunderland/Lafleur Rig Owner/Rig No.:Hilcorp 51 PTD#:2240180 DATE:4/16/2024 Type Operation:DRILL Annular: 250/3500Type Test:BIWKLY Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopSAM240418185343 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4 MASP: 2825 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 2-7/8"x5-1/2"P #2 Rams 1 Blinds P #3 Rams 1 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 3-1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P2975 Pressure After Closure P1400 200 PSI Attained P42 Full Pressure Attained P230 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P8@2325 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P24 #1 Rams P12 #2 Rams P12 #3 Rams P12 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P6 HCR Kill P7 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 1,710'N/A Casing Collapse Structural Conductor Surface 2260 Intermediate Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 907-223-6784 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Sean Mclaughlin sean.mclaughlin@hilcorp.com Drilling Manager Bryan McLellan 1,519' N/A TBU M-23 Middle Kenai Gas PoolMiddle Kenai Gas PoolMcArthur River Field Yes 1,619'1,610'2825 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 4/1/2023 Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 18730 224-018 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20719-00-00 Hilcorp Alaska, LLC Length Size Proposed Pools: N/A TVD Burst N/A MD 5020 450' 1,612' 450' 1,700' 26" 13-3/8" 450' 1,700' Perforation Depth MD (ft): N/A N/A 4/2/2024 N/A N/A m n P s 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Drilling Manager 04/03/24 Monty M Myers 324-196 By Grace Christianson at 3:09 pm, Apr 03, 2024 Include with 10-407 for PTD A.Dewhurst 15APR24 DSR-4/12/24BJM 4/15/24 JLC 4/15/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.15 15:54:13 -08'00'04/15/24 RBDMS JSB 041624 Well Prognosis Well: TBU M-23 Date: 4/3-24 Well Name: TBU M-23 API Number: 50-733-20719-00-00 Current Status: Welding Fluted Hanger Estimated Start Date: 4/2/2024 Rig: Steelhead Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: 4/1/24 Regulatory Contact: Cody Dinger 777-8389 Permit to Drill Number: 224-018 First Call Engineer: Sean McLaughlin (907)-223-6784 (M) Second Call Engineer AFE Number: Brief Well Summary – The M-23 surface hole was drilled to a TD of 1710’. 13-3/8” casing was run to 1,700’ and cemented to surface. After 3 days a gaseous fluid began to discharge from the fluted hanger. Below is a remediation plan forward. Plan Forward: 1. Fill conductor x casing with water (done) 1. It took 3-5 bbls (6’-9’) to fill. 2. Water was being pushed out 2. Open both 4” outlets 1. Purge with Water 2. Purge with Nitrogen 3. Fill hanger flutes with bar stock 4. Weld hanger flutes shut 1. Continuous monitoring of LEL levels required. 5. Place gauge and bleeder on 4” outlet and monitor pressure build up. 1. Limit pressure 165 psi 2. Monitor for flow and LEL Attachments 1. Current Schematic _____________________________________________________________________________________ Updated by CJD 4-3-24. CURRENT SCHEMATIC McArthur River Well: TBU M-23 PTD: 224-018 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 28"Conductor 262 / - / Weld 27”Surf 480’ 13-3/8”Surface 68 / L-80 / BTC 12.415”Surf 1,700’ OPEN HOLE / CEMENT DETAIL 13-3/8”Est. TOC @ surface L – 432 bbls / T – 72 bbls – 87-90 bbls returned From:McLellan, Bryan J (OGC) To:Sean McLaughlin Cc:Rixse, Melvin G (OGC); Regg, James B (OGC); Dewhurst, Andrew D (OGC); Roby, David S (OGC) Subject:Re: [EXTERNAL] RE: M-23 plan forward Date:Monday, April 1, 2024 6:50:48 PM Sean, Hilcorp has approval to proceed with the wellhead modifications proposed. Please follow up with a sundry application for a change to approved permit within 3 days. Regards Bryan McLellan Sent from my iPhone On Apr 1, 2024, at 6:25ௗPM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> wrote: Thank you Bryan, these are good discussion points. 1. How will you ensure Nitrogen leaking out through the open flutes during the Nitrogen purge operation will not create an asphyxiation hazard in this enclosed room? There room will not be enclosed during the purge. A very small quantity of nitrogen will be used, only enough needed to clear the flutes. Nobody is required to be in the room during the purge, it can be done remotely. Positive air flow in the room from two exterior doors. Open water below and no place to accumulate nitrogen. There are O2 sensors in place to monitor air quality. 2. Please ensure Hilcorp’s learnings from the Nitrogen asphyxiation incident on the North Slope are being employed and reviewed by the crew. Please send include a copy of Hilcorp’s Nitrogen procedures. Lessons have been discussed and policy attached. 3. Will you issue some kind of hot work permit to allow for welding in the wellbay? What are the mitigations to avoid creating an explosive environment? Hot work permit will be issued when welder is on tower and preparing for the job. Venting and air monitoring will be in place to ensure a safe environment is maintained. 4. What other potential hydrocarbon sources will exist in the area during welding? No other exposed hydrocarbons are in the area. Hydrocarbons exist behind pipe, we will make sure they stay there. 5. How will you ensure pressure does not build up beyond the limits of the CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. conductor, valves, etc… after the conductor annulus is sealed up? What pressure limit will be applied? The conductor holds 165 psi on offset wells. The valve is rated to 600 psi. 165 psi will be the pressure limit based on a like for like comparison. 6. How will you ensure the heat from welding will not damage any components of the wellhead? Has the wellhead manufacturer been consulted about the plan for welding? There is no guarantee that heat will not damage the well head. There is no manufacture recommendation or specification for welding the flutes closed. The 13-3/8” casing test will re-establish integrity of the wellhead and a pressure envelope. 7. What other risks have been identified? Gas accumulation is the main risk, methane presence needs to be mitigated prior to welding. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 1, 2024 5:02 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 plan forward Sean, The proposed procedure has some process and personal safety risks that are out of the norm and there’s concern that there may not have been time to thoroughly think through them. The AOGCC has some concerns that we would like to see addressed. Please document a risk assessment to address the following issues, and others that you have identified. 1. How will you ensure Nitrogen leaking out through the open flutes during the Nitrogen purge operation will not create an asphyxiation hazard in this enclosed room? 2. Please ensure Hilcorp’s learnings from the Nitrogen asphyxiation incident on the North Slope are being employed and reviewed by the crew. Please send include CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. a copy of Hilcorp’s Nitrogen procedures. 3. Will you issue some kind of hot work permit to allow for welding in the wellbay? What are the mitigations to avoid creating an explosive environment? 4. What other potential hydrocarbon sources will exist in the area during welding? 5. How will you ensure pressure does not build up beyond the limits of the conductor, valves, etc… after the conductor annulus is sealed up? What pressure limit will be applied? 6. How will you ensure the heat from welding will not damage any components of the wellhead? Has the wellhead manufacturer been consulted about the plan for welding? 7. What other risks have been identified? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 1, 2024 4:41 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: M-23 plan forward All but 4 wells have conductor by surface casing pressure. The average is 50 psi. The lowest is 5 psi and the highest is 165 psi. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 1, 2024 3:33 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: M-23 plan forward Do you know the pressure rating of the valve and conductor pipe? 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. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 1, 2024 3:31 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: M-23 plan forward Bryan, Below is the plan forward for sealing up the M-23 conductor x surface casing: Fill conductor x casing with water (done) It took 3-5 bbls (6’-9’) to fill. Water was being pushed out Open both 4” outlets Purge with Water Purge with Nitrogen Fill hanger flutes with bar stock Weld hanger flutes shut Continuous monitoring of LEL levels required. Place gauge on 4” outlet and monitor pressure build up. Limit pressure 70% of rated valve pressure Monitor for flow and LEL Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Engineer Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. <STANDARD WELL PROCEDURE - NITROGEN OPERATIONS FINAL 12- 08-15.pdf> <September 25 Incident RCA (v6).pdf> STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________TRADING BAY UNIT M-23 JBR 05/17/2024 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:Rig 51 has a twin diverter facing north at 49.8 ft and south at 142.5 ft. The knife valves on both diverter lines opened in 1.5 seconds. The closest ignition source at the north tip is the N crane at 54.48 ft. The closest to the south tip is the S crane at 61 ft. The knife valves open simultaneously and depending on wind direction the driller will close the windward valve. Leaking knife valve fail/pass (reported as a Diverter Misc. “FP” on the operator report) was prior to me arriving on location. TEST DATA Rig Rep:Nate MitchelOperator:Hilcorp Alaska, LLC Operator Rep:Shane Huack Contractor/Rig No.:Hilcorp 51 PTD#:2240180 DATE:3/25/2024 Well Class:DEV Inspection No:divSTS240329100629 Inspector Sully Sullivan Inspector Insp Source Related Insp No: Test Time:1.5 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:NA NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:17.5 P Vent Line(s) Size:16 P Vent Line(s) Length:142.5 P Closest Ignition Source:54.48 P Outlet from Rig Substructure:26.6 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:P Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:24 P Knife Valve Open Time:2 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P1680 200 psi Recharge Time:P42 Full Recharge Time:P155 Nitrogen Bottles (Number of):P8 Avg. Pressure:P2350 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: NA NAMud System Misc: jbr CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Sean McLaughlin Cc:Regg, James B (OGC) Subject:RE: Steelhead Permit Number 224-018 Date:Tuesday, March 19, 2024 9:07:00 AM Attachments:Steelhead M-28 BOP Test 3-10-2024.xlsx Sean, A 3500 psi Initial BOP test will be acceptable on TBU M-23, since the initial test on M-28 was done to 5000 psi, assuming Hilcorp is using the same BOP stack, choke manifold, control system, and other BOPE as was used on M-28. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, March 19, 2024 8:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Steelhead Permit Number 224-018 Bryan, I’d like to request a change to an initial pressure test of 3500 psi (permitted for 5000psi) on M- 23. We ended up delaying the M-28RD RWO so we could mobilize the full drilling stack and test all components to 5000psi. The M-28RD test was witnessed and the BOPE test form is attached. Regards, sean From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Sent: Tuesday, March 19, 2024 8:02:28 AM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Casey Morse <casey.morse@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Darci Horner - (C) <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jerimiah Galloway <jerimiah.Galloway@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] New Permit Number 224-018 Hello, Attached is the new Permit for TBU M-23. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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.:51 DATE:3/10/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2170260 Sundry #324083 Operation:Drilling:Workover:X Explor.: Test:Initial:x Weekly:Bi-Weekly:Other: Rams:250/5000 Annular:250/2500 Valves:250/5000 MASP:1237 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13 5/8 / 5K P Pit Level Indicators P P #1 Rams 1 2-7/8" X 5-1/2'' / 5K P Flow Indicator P P #2 Rams 1 Blinds / 5K P Meth Gas Detector P P #3 Rams 1 2-7/8" Pipe / 5K FP H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8/ 5K P Time/Pressure Test Result HCR Valves 2 3 1/8 / 5K FP System Pressure (psi)3050 P Kill Line Valves 2 3 1/8 / 5K FP Pressure After Closure (psi)1450 P Check Valve 0 NA 200 psi Attained (sec)34 P BOP Misc 0 NA Full Pressure Attained (sec)220 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):8@ 2300 Psi P No. Valves 14 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 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:3 Test Time:22.0 HCR Choke NA Repair or replacement of equipment will be made within 0 days. HCR Kill NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3-6-24 / 0717 Waived By Test Start Date/Time:3-9-2024 / 15:30 (date)(time)Witness Test Finish Date/Time:3/10/2024 13:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Hilcorp Test all valves & Rams to 250/5000 Psi. Tested Lower 2-7/8" x 5-1/2" vbr rams on 2 7/8 Test joint-failed & were replaced with 2 7/8 solid body rams. Retested Good. 3'' Kill Demco valve failed and was rebuilt and retested-good. Choke HCR failed while testing the blind rams and was replaced and retested-good. Sloan Sunderland Enterprize Offshore Norman Mitchell TBU M-28RD Test Pressure (psi): ssunderland@hilcorp.com Form 10-424 (Revised 08/2022)Steelhead M-28 BOP Test 3-10-2024 (002) Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: McArthur River Field, Middle Kenai Gas Pool, TBU M-23 Hilcorp Alaska, LLC Permit to Drill Number: 224-018 Surface Location: 1067' FNL, 624' FWL, Sec 33, T9N, R13W, SM, AK Bottomhole Location: 997' FNL, 1402' FWL, Sec 28, T9N, R13W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this day of March 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.18 21:00:05 -05'00' 18 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6.Proposed Depth: 12. Field/Pool(s): MD: 11,192' TVD: 8,671' 4a. Location of Well (Governmental Section): 7.Property Designation: Surface: Top of Productive Horizon: 8.DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property:14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 160' 15. Distance to Nearest Well Open Surface: x-214240 y- 2499432 Zone-4 N/A to Same Pool: 124' to M-24 16. Deviated wells: Kickoff depth: 480 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 65 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 26" 262# X-56 Weld 450' Surface Surface 450' 450' 17-1/2' 13-3/8" 68# L-80 BTC 1,700' Surface Surface 1,700' 1,580' 12-1/4" 9-5/8" 47# L-80 TXP 6,500' Surface Surface 6,500' 4,118' 8-1/2" 4-1/2" 12.6# L-80 TXP 4,792' 6,400' 4,021' 11,192' 8,671' Tieback 4-1/2" 12.6# L-80 TXP 6,400' Surface Surface 6,400' 4,021' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20.Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng TBU M-23 McArthur River Field Middle Kenai Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 2457 ft3 / T - 194 ft3 2825 784' FNL, 753' FWL, Sec 33, T9N, R13W, SM, AK 997' FNL, 1402' FWL, Sec 28, T9N, R13W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1067' FNL, 624' FWL, Sec 33, T9N, R13W, SM, AK ADL 18730 18. Casing Program: Top - Setting Depth - BottomSpecifications 3963 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 2137 ft3 / T - 424 ft3 Effect. Depth MD (ft): Effect. Depth TVD (ft): LengthCasing Size Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate Drilling Manager Monty Myers 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 3/10/2024 9461' to nearest unit boundary Jonathan Lawley jonathan.lawley@hilcorp.com 801-819-6579 L - 1691 ft3 / T - 148 ft3 Tieback Assy. 3840 Cement Volume MD Stratigraphic Test No Mud log req'd: Yes No No Directional svy req'd: Yes No Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Single Well Gas Hydrates No Inclination-only svy req'd: Yes No Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal No No Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 02/27/24 Monty M Myers By Grace Christianson at 3:34 pm, Feb 27, 2024 50-733-20719-00-00224-018 DSR-2/28/24SFD 3/1/2023 3693 SFD MGR11MAR2024 *Variance approved for 2 X 16" diverter lines capable of simul- taneous operation. *Perform gyro multishot surveys on wells TBU M-1, TBU M-04, TBU M-05 to 800' MD with same gyro tool to reduce anticollision uncertainty. *Monitoring of offset wells IA pressure and surface casing acoustic monitoring during close approach of TBU M-1, M-04, and M-05. Initial BOP test to 5000 psi. Initial annular test to 2500 psi. Subsequent BOP tests to 3500 psi, subsequent annular test to 2500 psi. Submit FIT/LOT data within 48 hrs of receiving it. ($8JLC 3/18/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.03.18 20:59:50 -05'00'03/18/24 03/18/24 TBU M-23 Drilling Program Steelhead Jonathan Lawley PTD February 26, 2024 Steelhead M-23 Drilling Program PTD Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Planned Wellbore Schematic.............................................................................................................6 7. Drilling Summary...............................................................................................................................7 8. Mandatory Regulatory Compliance / Notifications.........................................................................8 9. R/U and Preparatory Work.............................................................................................................10 10. N/U 21-1/4” 2M Diverter ..................................................................................................................10 11.Drill 17.5” Hole Section ....................................................................................................................12 12.Run 13.375” Surface Casing ............................................................................................................14 13.Cement 13.375” Surface Casing ......................................................................................................16 14. ND/NU BOPE, Test...........................................................................................................................19 15. Preparatory Work and Mud Program............................................................................................19 16.Drill 12.25” Hole Section ..................................................................................................................21 17.Run 9.625” Casing ............................................................................................................................22 18. Cement 9-5/8” Surface Casing .........................................................................................................25 19.Drill 8.5” Hole Section ......................................................................................................................28 20.Run 4.5” Liner / hanger / DP string ................................................................................................29 21. Cement 4-1/2” Production Liner .....................................................................................................31 23. Wellbore Clean Up & Displacement...............................................................................................34 24. Run Completion Assembly...............................................................................................................34 25. Diverter..............................................................................................................................................36 27. BOP Schematic..................................................................................................................................37 28. Wellhead Schematic..........................................................................................................................38 29. Anticipated Drilling Hazards...........................................................................................................39 30. Platform position...............................................................................................................................41 31. FIT Procedure...................................................................................................................................43 32. Choke Manifold Schematic..............................................................................................................44 33. Casing Design Information ..............................................................................................................45 34. 12.25” Hole Section MASP ...............................................................................................................46 35.8.5” Hole Section MASP...................................................................................................................47 36. Plot (NAD 27) (Governmental Sections).........................................................................................48 37. Slot Diagram......................................................................................................................................49 Page 2 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 38. Directional Program (wp06) - Attached separately......................................................................50 1. Well Summary Well Trading Bay Unit M-23 Drilling Rig Steelhead Rig 51 Leg & Slot Leg B-2 / Slot 12 Directional plan wp06 Pad & Old Well Designation NA –Grassroots Planned Completion Type 4-1/2”12.6# Liner, 4-1/2” Tubing GL Comp Target Reservoir(s)MacArthur Kick off point NA Planned Well TD, MD / TVD 11192’MD / 8671’TVD PBTD, MD 11092’MD AFE Number AFE Days AFE Drilling Amount Work String 5.0” 19.5# S-135 NC50 KB 73.7’ KB above MSL 160’ Page 3 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 2. Management of Change Information Date: February 26th, 2024 Subject: Changes to Approved Permit to Drill File #: TBU M-23 Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved By Approval: Drilling Manager Date Prepared: Engineer Date Page 4 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 3. Tubular Program Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft)Grade Conn Burst (psi) Collap se (psi) Tension (k-lbs) Conductor (previously installed) 26 Assume 25 --Assume 262 X-56 Weld 17.5”13.375 12.415 12.259 14.375 68 L-80 BTC 5020 2260 1556 12.25”9.625 8.681 8.525 10.625 47 L-80 TXP 6870 4750 1086 8.5”4.5 3.958 3.833 5.0 12.6 L-80 TXP 8430 7500 288 ** Minimum of 100’ overlap required between casing strings 4. Drill Pipe Information Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 5.0”4.276 2.75 6.625 19.5 S-135 NC50 15,640 10,030 560k Page 5 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Try to capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to Kenai/CIO Drilling distribution list. 3. EHS Incident Reporting x Notify EHS field coordinator. i. Garrett St. Clair: C: (907) 252-7780 x Spills: i. Adrian Kersten: C: 907-350-9439 ii. Monty Myers: O: 907-777-8431 C: 907-538-1168 iii. Jonathan Lawley: C:801-819-6579 x Submit Hilcorp Incident report to contacts above within 24 hrs x Report spills to water immediately 4. Casing Tally x Send final “As-Run” Casing tally to jonathan.lawley@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to jonathan.lawley@hilcorp.com and cdinger@hilcorp.com Page 6 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 6. Planned Wellbore Schematic Page 7 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 7. Drilling Summary TBU M-23 is a 11192’ MD / 8671’ TVD development gas well drilled from B-2 Leg slot #12 off the Steelhead platform. The well will be completed with a 4-1/2”tie-back completion. Drilling operations are expected to commence approximately March 10th 2024. General sequence of operations pertaining to this drilling operation: Rig 1. Rig 51 will MIRU over leg B-2, slot 12. 2. NU 21-1/4” x 2M diverter. 3. Drill 17.5” hole to 1700’ MD. Run and cmt 13-3/8”casing. Test casing to 2,500 PSI. 4. ND diverter and NU casing head & 13 5/8” 5M BOP to 5,000 PSI. Install bushing. 5.PU 12.25”directional BHA 6. Drill shoe track with 20’ of new formation. 7. Perform FIT to 13.8 PPG EMW 8. Drill 12.25” hole section to 6500 MD, performing short trips as needed. 9. POOH w/ directional tools. 10. RIH w/ 9-5/8” casing, circ. & cement. 11. Pull landing joint, install & test packoff. Install bushing. 12.PU 8.5” directional BHA. 13.Drill shoe track with 20’ new formation. 14. Perform FIT to 13.8 PPG EMW 15.Drill 8.5” hole section, performing short trips as needed. 16. POOH w/ directional tools. 17. RIH w/ 4-1/2” liner, circ., cement & set. Test liner top packer to 2,825 psi. 18. TOOH w/landing string. 19. RIH w/ 4-1/2” tieback, set & test liner top & IA to 2,825 psi. 20. ND BOPE, NU & test tree. Page 8 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 8. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/5000 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. o The highest reservoir pressure expected is 3519 psi in the F9 sand (8241' TVD). MASP is 2,825 psi with 0.1psi/ft gas in the wellbore. x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi. x If the BOP is used to shut in on the well in a well control situation, ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system” x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Diverter Assembly: In accordance with API RP 64 section 6, a diverter will be used. 2 x 16” diverter lines will be rigged up that will have straight paths off the platform and not be pointed at the Flare, Rig, or platform quarters. If needed, one or both diverter lines can be used depending on wind conditions. Page 9 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Variance Request: Per AOGCC a diverter line must be equal to hole size. Steelhead utilizes 2 x 16” diverter lines (201 in. 2 TFA each, 402 total), and Hilcorp would like to request drilling 17.5” hole (240 in.2 TFA). If required, one diverter line can flow gas/cuttings ejected from an open wellbore. As was granted on M35 drilled in 2018, Hilcorp would like to request drilling 17.5” hole with the same diverter setup. In addition to multiple wellbore penetrations on the platform with no indications of over pressured shallow gas above 2500 ft. TVD, M-23’s program calls for surface casing set depth of only ~1580 ft. TVD. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 17.5”x 21-1/4” x 2M Hydril MSP diverter w/2 x 16” diverter lines Function Test Only 12.25” / 8.5” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer LXT Double gate x Blind ram in bottom cavity x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 5M Choke Manifold x Standpipe, floor valves, etc Initial Test: 250/5000 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: electric triplex pump. Secondary: air pump. Tertiary: store pressure nitrogen bottles. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Variance Request: Page 10 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 9. R/U and Preparatory Work 1. N/U 21-1/4” 2M diverter assy to 28” starting head 2. Mix WBM mud for 17.5” hole section. 3. Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 4. Ensure all personnel are drilled and competent in Diverter and BOP operations. 5. 6.0” liners in both pumps should be sufficient. Plan to pump at 1,100 GPM minimum (126 strokes/min each) to clean the 26”conductor. 6.0” liners will output up to 1,300 GPM @ 3,968 PSI. 10. N/U 21-1/4” 2M Diverter 1. N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 21-1/4” x 2 M riser on 28”landing ring/starter head. x N/U 21-1/4” 2M T w/ diverters w/16” outlets. x Knife gates, 16” diverter lines. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(c). 2. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Annular element must close in less than 45 seconds. 3. Set wear bushing in wellhead. Page 11 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 4. Rig and Diverter Line Orientation on Steelhead Platform (same orientation on all legs): Page 12 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 11. Drill 17.5” Hole Section 1. P/U 17.5” clean out assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. x Recommended BHA: 17.5” mill tooth bit with bent motor x Pump at 1100 GPM minimum to clean the hole effectively. 2. 17.5” hole mud program summary: x Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.2ppg. x Electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x System type: Aquagel spud mud. x Properties: Mud Weight Viscosity Plastic Viscosity Yield Point pH API 9.2+85 –250 20 –40 25 –65 8.5-9.5 <10.0 x Formulation: Product Concentration Fresh Water soda Ash AQUAGEL BARAZAN D+ PAC-L /DEXTRID LT BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROID 41 caustic soda ALDACIDE G 0.905 bbl 0.5 ppb 15 -25 ppb as needed if required for <10 API FL 5 ppb total 5 ppb total 4.0 ppb as required for weight 9.2+ ppg 0.1 ppb (8.5 –9.5 pH) 0.1 ppb AQUAGEL and BARAZAN D+ should be used to maintain rheology. Begin system with a 55 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 - 20 ppb total) BARACARBs/BAROFIBRE/STEELSEALs should be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high-clay content sections. Maintain the pH in the 8.5 –9.5 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Page 13 PTD February 26th, 2024 TBU M-23 Drilling Program PTD Mix a ~50 bbl LCM pill prior to drilling out of the conductor, to be available for immediate use if losses are seen drilling the Surface hole. The pill formulation will be the 50 ppb pill from the LCM tree. Mix the recommended LCM material in thinned back base mud. Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Sweep Formulations: 20 barrels mud, add 1.0 ppb BARAZAN D. Additions of CON DET PREMIX are recommended when penetrating high-clay content sections to reduce the incidence of bit balling and shaker blinding. At TD, a Walnut “flag” (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout - to help calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. 3. TIH to TOC in the conductor. Should be between 350-400’. 4.Displace hole to spud mud and begin drilling out cmt plug at 350’ to 400’. This plug will be approx. 50 –100 ft thick. 5. Drill out cmt until formation is detected, then TOH to surface. 6. TIH w/ 17.5” directional drilling assy and drill 17.5” hole section from ~400’ to 1700’ MD. x Pick up 17.5” Mill tooth bit until clear of anti-collision concerns. A mill tooth roller cone cannot penetrate offset parallel casing strings. It would deflect off the steel and likely damage the bit skirts if anything. x Gyro required due to close approach wells when coming out of the shoe. x There are close approaches with 3 offset wells in Leg B-2. Frequent gyro shots may be required when drilling out of the conductor. o TBU M-1: Gas producer online @ 9 psi. 2.33’ CtC distance @ 605’. Strings @ 605’: 20” 91.5#, 13.375” 68#, 10.75” 55.5#, 9.625” 43.5#, 7” 79# o TBU M-04: Gas producer online @ 25 psi. 3.65’ CtC distance @ 703’. Strings @ 703’: 20” 133#, 16” 75#, 9.625” 47#, 4.5” 12.6# o TBU M-05: Gas producer online @ 12 psi. 5.61’ CtC distance @ 475’. Strings @ 475’: 20” 133#, 16” 75#, 13.375” 68#, 10.75” 55.5#, 7” 29#, 3.5” 9.2# x GR/RES only for surface hole. x Pump at 1100+ GPM. 1100 GPM is 97 ft/min AV open hole 45 ft/min AV in the 26” conductor which is poor for effective hole cleaning. Short trips and sweep will be required. Ensure shaker screens are set up to handle this flowrate. x Circulate hole clean and pump sweep before dropping rate to prevent fall back and sticking. Maximize drill string RPMs, Pump sweeps and 6rpm rheology (target 10) to ensure effective hole cleaning. Gyro required due to close approach wells when coming out of the shoe Pick up 17.5” Mill tooth bit until clear of anti-collision concerns. A mill tooth roller cone cannot penetratepp offset parallel casing strings. It would deflect off the steel and likely damage the bit skirts if anythingpgg y Acoustic and IA pressure monitoring required on offset wells M-1, M-04, and M-05 while drilling to 800'. Assure gyros run on offset wells prior to drilling. -mgr Page 14 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Do not allow MW to drop below a 9.2 ppg. x Pull wiper trips as often as necessary. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Take MWD surveys every stand drilled. 12. Run 13.375” Surface Casing 1. Pull bushing, RU casing running equipment. x Ensure necessary NC50 XO on rig floor and MU to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU fill line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Note that 68# drift is 12.259” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking 120’ shoe track assembly consisting of: 13.375” Float Shoe 1 joint –13.375” BTC, 1 Centralizer 10’ from bottom w/ stop ring 1 joint –13.375” BTC, NO Centralizer 13.375” Float Collar 1 joint – 13.375”, 1 Free floating centralizer Page 15 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and components. 4. Continue running 13.375” surface casing. x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralize every other joint to conductor. None needed in conductor. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 5. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 6. Slow in and out of slips. 7. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 8. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 9. P/U and R/U circulating equipment and circulate the greater of 1.5 x casing capacity or 1.5 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 10. After circulating, lower string and land hanger in wellhead again. Cement returns will be out the 2 x 4” side outlets. Ensure hose is in place to take returns and dump into the inlet over the side of the platform. Page 16 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 13. Cement 13.375” Surface Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. Page 17 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Drop bottom plug –HEC rep to witness. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 100% open hole excess for lead. Job will consist of lead & tail. Estimated Total Cement Volume: Cement Slurry Design: Section Calculation Vol (bbl) Vol (ft3) Vols (sxs) Lead 25" ID conductor x 13.375" casing 450' x 0.4333bpf 195 1094 17.5" OH x 13.375" casing (1700-450-500)' x 0.1237 bpf x 2 186 1043 Total Lead 381 2137 910 Tail 17.5" OH x 13.375" casing 500' x 0.1237 bpf 62 348 13.375" shoetrack 90' x 0.1497 bpf 13.5 76 Total Tail 75.5 424 365 TOTAL CEMENT VOLUME 456.5 2561 1275 Displacement (1700-90)' x 0.1497 bpf 241 n annular volume + 100% open hole excess for lead. Verified cement calculations -bjm Page 18 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 9. Attempt to reciprocate casing while cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop top plug and displace cement with spud mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 11. Ensure rig pump is used to displace cement. 12. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 13. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±13 bbls before consulting with Drilling Engineer. 14. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Test casing to 2500 psi. Bleed off. 15. Be prepared for cement returns to surface. Cement return to be taken overboard. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 16.Close 4” valves on wellhead side outlet and monitor pressure build up. 17. R/D cement equipment. Flush out wellhead with FW. 18. Back out and L/D landing joint. Flush out wellhead with FW. 19. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 20. Lay down landing joint and pack-off running tool. Ensure to report the following on Wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Page 19 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jonathan.lawley@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 14. ND/NU BOPE, Test 1. ND the 21-1/4” x 3M diverter and 20-3/4” riser assembly. 2. NU the 13-5/8” casing head assembly, 13-5/8” x 5M spacer spool, & 13-5/8” x 5M riser. 3. NU 13-5/8” 5M BOP per diagram in this document. 4. Install test plug, test BOPE to 250/5000 PSI for 5/5 min. Test annular to 250/2500 PSI for 5/5 min. x Test VBRs on a 5” test joint (5000 psi) x Test Annular on a 5” test joint (2500 psi) x Calibrate gas monitors. x Leave casing valve open as to not pressure up on casing if plug leaks. x Prior to running 9.625” casing, test said rams in upper pipe ram cavity to 5000 psi. 5. Pull plug & install bushing. 15. Preparatory Work and Mud Program 1. Mix 9.2 WBM mud for 12.25” hole section. 2. 5.5” liners will be sufficient for the remainder of the well. x Pumps are rated at 4723 PSI with 5.5” liners and can deliver 450 GPM each with 120 SPM. x Pump range for remainder of well will be 400-800 GPM, which is within these parameters with up to 2 pumps. Page 20 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 3. 12.25” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. x Electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x System type: 2% KCl/Barasure w-988/GEM/GP x Properties: x Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 9.2 –9.8 40-53 15-25 15-25 8.5-9.5 11.0 x Formulation: Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BARASURE W-988 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS BARAFLC-903 BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 –4 ppb as needed 9.2 –9.8 ppg 0.1 ppb 4. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. Page 21 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. 16. Drill 12.25” Hole Section 1. MU 12.25”cleanout BHA & TIH. 2. Wash down 3 stands above plug depth. Note depth TOC tagged on morning report. 3.Drill out shoe track and 20’ of new formation. 4. CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 5. Conduct FIT to 12.5 PPG EMW. Chart test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.5 PPG with 6.21 PPG BHP and 9.7 PP MW equates to a 32 bbl KTV. 6. POOH & LD Cleanout BHA 7. Drift & caliper all MWD components before MU. Visually verify no debris inside components that cannot be drifted. 8. Ensure TF offset is measured accurately and entered correctly into the MWD software. 9. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 600-800 GPM. 10. PU 8.0” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES). 11. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the build and drop sections of the wellbore. 12. TIH to window. Shallow test MWD on trip in. 13. Drill 12.25” hole to 6500’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. Page 22 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole 14. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 15. TOH with drilling assembly, handle BHA as appropriate. 17. Run 9.625” Casing 1.Ensure 9.625” rams are tested. 2. RU and pull wear bushing. 3. RU Volant 9-5/8” casing running equipment x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Plan to rig up Volant CRT if available x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8-1/2” on the location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 4. P/U shoe joint, visually verify no debris inside joint. 5. Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint –9-5/8” TXP, 1 Centralizer 10’ from bottom w/ stop ring 1 joint –9-5/8” TXP, NO Centralizer 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” TXP, 1 Free floating centralizer 9-5/8” HES Baffle Adaptor Page 23 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 6. Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every other joint x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. Page 24 PTD February 26th, 2024 TBU M-23 Drilling Program PTD Page 25 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 7. Continue running 9-5/8” surface casing x Fill casing while running using CRT. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: No centralizers in the conductor. 8. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 9. Slow in and out of slips. 10. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 11. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 12. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 13. After circulating, lower string and land hanger in wellhead again. Cement returns will be out the OA annular valve. Ensure hose is in place to take returns and dump into the inlet over the side of the platform. 18. Cement 9-5/8” Surface Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. Page 26 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Drop bottom plug –HEC rep to witness. Mix and pump cement per below calculations & confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess on lead. Job will consist of lead & tail, TOC to surface. Estimated Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): Section Calculation Vol (bbl) Vol (ft3) Vols (sxs) Lead 13.375" casing x 9.625" casing 1700' x 0.0597 102 572 12.25" OH x 9.625" casing (6500-1700-500)' x 0.0558 bpf x 1.4 336 1885 Total Lead 438 2457 1046 Tail 12.25" OH x 9.625" casing 500' x 0.0558 bpf 28 157 9.625" shoetrack 90' x 0.0732 bpf 6.6 37 Total Tail 34.6 194 167 TOTAL CEMENT VOLUME 472.6 2651 1213 Displacement (6500-90)' x 0.0732 bpf 469 Verified cement calcs. -bjm Page 27 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 9. Attempt to rotate casing during cement pumping if hole conditions allow. Keep TDU @ 20 RPM w/35k ft-lbs torque limited. About ½ way through displacement, pipe should gain buoyancy and start to rotate. 10. After pumping cement, drop top plug (shutoff plug) and displace cement with mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 11. Ensure rig pump is used to displace cement. 12. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 13. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±6.5 bbls before consulting with Drilling Engineer. 14. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Test casing to 3,440 (50% of burst). Bleed off. 15. Be prepared for cement returns to surface. Cement return to be taken overboard. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 16. R/D cement equipment. Flush out wellhead with FW. 17. Back out and L/D landing joint. Flush out wellhead with FW. 18. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 19. Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Page 28 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jonathan.lawley@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 19.Drill 8.5” Hole Section 1.Swap casing rams out for VBR’s & test 250/3500 psi 5/5 min. Test 4.5” & 5.0” joints on both rams. 2. Install short wear bushing. 3.M/U 8.5” Cleanout BHA. 4. TIH w/ 8-1/2” cleanout BHA to plug. Note depth TOC tagged on morning report. 5.Drill out shoe track and 20’ of new formation. 6. CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 7. Conduct FIT to 12.5 PPG EMW. Chart test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.5 PPG with 8.20 PPG BHP and 9.7 PP MW equates to a 38 bbl KTV. 8. POOH & LD Cleanout BHA 9. Drift & caliper all MWD components before M/U. Visually verify no debris inside components that cannot be drifted. 10. Ensure TF offset is measured accurately and entered correctly into the MWD software. 11. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-550 GPM. 12. P/U 6.5” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES). 13. Production section will be drilled with a motor. Must keep up with 2 deg/100 DLS in the drop & turn sections of the remainder of the wellbore. 14. TIH to window. Shallow test MWD on trip in. 15. Drill 8.5” hole to 11192’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Page 29 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. x Take MWD surveys every stand drilled. x Minimize back reaming when working tight hole 16. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 17. TOH with drilling assembly, handle BHA as appropriate. 20. Run 4.5”Liner / hanger / DP string 1. R/U Baker 4-1/2” liner running equipment. x Ensure 4-1/2”TXP x NC50 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (2) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer 10’ from the bottom with stop ring x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. No centralizer x Centralizers will be run on 4-1/2” liner every other joint. x Ensure proper operation of float shoe & FC. 4. Continue running 4-1/2” production liner to TD x Fill liner while running using fill up line on rig floor. Page 30 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 31 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7.M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. PU the cmt stand and tag bottom with the liner shoe. PU 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 21. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to rotate the casing during cmt operations until hole gets sticky. 3. Pump 15 bbls 12.5 ppg spacer. Page 32 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. 6. Mix and pump cement per below recipe and volume below with loss circulation fiber if warranted. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to 6400’ TMD (TOL). 7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs. Estimated Total Cement Volume: Slurry Information: 8. Drop DP dart and displace with 10.1 ppg WBM. 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point 10. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not over displace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Section Calculation Vol (bbl) Vol (ft3) Vols (sxs) Lead 9.625" casing x 4.5" casing 100' x 0.0535 5.5 31 8.5" OH x 4.5" casing (11192-6500-500)' x 0.0505 bpf x 1.4 296 1661 Total Lead 301.5 1691 720 Tail 8.5" OH x 4.5" casing 500' x 0.0505 bpf 25 140 4.5" shoetrack 90' x 0.0152 bpf 1.4 8 Total Tail 26.4 148 128 TOTAL CEMENT VOLUME 327.9 1840 847 Displacement 6400 x 0.0081 + 4792' x 0.0152 bpf 125 Verified cement calcs. -bjm Page 33 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 13. Bleed pressure to zero to check float equipment. 14. PU, verify setting tool is released. 15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19. POOH, LDDP. Backup release from liner running tool: 20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on Wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job Page 34 PTD February 26th, 2024 TBU M-23 Drilling Program PTD x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jonathan.lawley@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 22. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 3000 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 23. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly to above the liner top x Tubing will be 4-1/2” L-80 12.6# IBT x SSSV to be placed at 500’ x CIM to be placed at 2000’ x GLM will be run. 2. Swap the well over to FIW x Circulate a hi-vis pill followed by a soap train per Baroid x Circulate FIW until clean-up is satisfactory. x Leave FIW in the annulus. 3. Space out and land seal bore in tie back sleeve. RILDs. 4. Test IA to 2000 psi and tubing to 3500 psi. Charted 30 min test 5. Install BPV in wellhead. Page 35 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 6. ND BOPE, NU & test tree. 7. Rig Down Page 36 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 24. Diverter Hydril MSP 21 1/4-2000 4.30' 4.75' 35.92' 3.00' 4.22' 47.06' Bottom of flow box 22'’ Pipe 52.59' 22.84' 20 ¾ 3M Riser 20 ¾ 3M Diverter Tee #17 Clamp Wellhead Room Floor 16'’ 3M outlets 16'’ 3M outlets 4'’ ANSI 300 RF X2 For cement returns .44'DSA 21 ¼ 2M x 20 ¾ 3M Spool 20 ¾ 3M Page 37 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 25. BOP Schematic 13 5/8 5M Shaffer Shaffer LXT Shaffer SL 1.83' 1.44' 2.83' 3.74' 18.83' 21.75' Mud Cross 13 5/8 5M FE X FE w/ 3 1/8 5M EFO Riser 13 5/8 5M #13 API hub X 13 5/8 5M FE Riser 13 5/8 5M #13 API hub X 13 5/8 5M FE 2.00'Spacer spool installed for use of lift cradle on studded BOP 2 7/8-5.5 variables Blinds 27/8-5.5variables Page 38 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 26. Wellhead Schematic Valve, Wing, SSV, WKM-M, 3 1/8 5M FE, w/ 15'’ operator BHTA, Otis, 4 1/16 5M FE x 9.5 Otis quick union top Valve, Upper master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Swab, WKM-M 4 1/16 5M FE, HWO, EE trim Tubing hanger, Catcus CTF-ONE-CCL, 4 ½ Hydril 563 pin bottom x 6.125 LH acme top, 4'’ Type H BPV profile, 2- ¼ npt control line ports Valve, master, WKM-M, 4 1/16 5M FE, HWO, EE trim Cactus, MBU-EU-CFL- R-DBLO Wellhead system, 13 5/8'’ 5M API quick connect top w/ 4- 2 1/16 5M SSO 28'’ 13 3/8'’ 9 5/8'’ 4 ½’’ 4'’ LPO x 2 Page 39 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 27. Anticipated Drilling Hazards Shallow Gas Sands While Drilling Surface: Never lose circulation & empty the hole: x Top off drill water. x Build 1,200 bbls of spud mud prior to spud. 9.2 PPG with 14 PPB LCM. x Have boat available entire time to replenish drill water stores x Maintain plenty of LCM. Build LCM pills prior to spud. Maintain plenty of barite: x Maintain enough barite to weight up entire system per state regs and also keep enough free deck space to receive more. If diverter is needed: x Equalize all pits and leave pumps on while on diverter to enable best chance of keep hole full of fluid. Lost Circulation: Drill depleted reservoir may cause loss circulation events x Maintain sufficient volumes while drill. x Maintain ability to take on FIW during drilling phase x If a LC event occurs pumping cement will be the likely remedy Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible l depleted reservoir may cause loss circulation events Page 40 PTD February 26th, 2024 TBU M-23 Drilling Program PTD H2S: H2S is not present in this hole section. Anti Collision: Drill out of conductor with mill tooth bit, gyro, monitor annuli in offset wells. There are close approaches with two offset wells. Frequent gyro shots required when drilling out of the shoe. o TBU M-1: Gas producer online @ 9 psi. 2.33’ CtC distance @ 605’. Strings @ 605’: 20” 91.5#, 13.375” 68#, 10.75” 55.5#, 9.625” 43.5#, 7” 79# o TBU M-04: Gas producer online @ 25 psi. 3.65’ CtC distance @ 703’. Strings @ 703’: 20” 133#, 16” 75#, 9.625” 47#, 4.5” 12.6# o TBU M-05: Gas producer online @ 12 psi. 5.61’ CtC distance @ 475’. Strings @ 475’: 20” 133#, 16” 75#, 13.375” 68#, 10.75” 55.5#, 7” 29#, 3.5” 9.2# Page 41 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 28. Platform position Page 42 PTD February 26th, 2024 TBU M-23 Drilling Program PTD Page 43 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 29. FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 44 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 30. Choke Manifold Schematic Page 45 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 31. Casing Design Information 12-1/4"Mud Density:9.2 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: See attached MASP determination and calculation 1558 psi 2825 psi 2825 psi Collapse Calculation: Section Calculation All Max MW gradient external stress (9.2 ppg) and the casing evacuated for the internal stress 123 13-3/8" 9-5/8" 4.5" 006,400 004,018 1,700 6,500 11,192 1,580 4,118 8,671 1,700 6,500 4,792 68 47 12.6 L-80 L-80 L-80 BTC TXP BTC TXP BTC 115,600 305,500 60,379 1545 1086 288 13.37 3.55 4.77 750 1,955 4,117 2,263 4,754 7,500 3.02 2.43 1.82 597 1,558 2,825 5,024 6,865 8,431 8.42 4.41 2.98Worst case safety factor (Burst) DATE: 2-26-2024 WELL: M-23 FIELD: McArthur River DESIGN BY: Jonathan Lawley Hole Size Hole Size Minimum Yield (psi) MASP (8-1/2" hole): Drilling Mode MASP (12-1/4" hole): Worst Case Safety Factor (Collapse) Worst Case Safety Factor (Tension) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Collapse Pressure at bottom (Psi) MASP (psi) Top (MD) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Bottom (MD) Bottom (TVD) Length Top (TVD) Casing Section Calculation & Casing Design Factors Design Criteria: Steelhead Platform Calculation/Specification Casing OD Hole Size Production Mode MASP: Page 46 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 32. 12.25” Hole Section MASP MD TVD Planned Top: 1,700 1,580 Planned TD: 6,500 4,118 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SZ-17 2,002 492 Gas 4.7 0.246 SZ-21 2,335 489 Gas 4.0 0.209 SZ-24 2,488 527 Gas 4.1 0.212 A3 2,747 196 Gas 1.4 0.071 A5 2,871 290 Gas 1.9 0.101 B1 3,167 128 Gas 0.8 0.040 B5 3,547 102 Gas 0.6 0.029 B6 3,616 308 Gas 1.6 0.085 C1 3,835 151 Gas 0.8 0.039 C3 3,965 164 Gas 0.8 0.041 Int. Shoe TD 4,118 1970 Gas 9.2 0.478 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date M-21 9.0 - 9.3 0 2,691 2011 M-27 9.2 - 9.7 4,235 10,500 1990 M-28 9.4 - 9.7 4,610 10,500 1990 M-29 9.2 - 9.7 3,770 10,500 1991 M-30 9.1 - 9.7 4,247 10,500 1992 M-22 9.2-9.7 1,300 5,940 2018 Assumptions: 1. Fracture gradient at 1,700' MD / 1,580' TVD is estimated 12-14 PPG EMW per field data. 2. Maximum planned mud density for the hole section is 9.2 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is fully evacuated wellbore to reservoir gas. 5. Maximum original pressure in gas sands at 9.2 ppg EMW. Fracture Pressure at shoe considering a full column of gas from shoe to surface: FP= 13.0 PPG x 0.052 x 1,580 ft. TVD 1,068 psi 1068(psi) - [0.1(psi/ft)*1,580(ft)]= 910 psi MASP from pore pressure (unknown gas sand at TD, at 9.2 ppg (0.4784 psi/ft) 4118(ft) x 0.4784(psi/ft)= 1,970 psi 1970 psi - (.1 * 4118 ft) = 1,558 psi MASP Summary: MASP while drilling 12-1/4" hole is governed by gas to surface. Maximum Anticipated Surface Pressure Calculation 12-1/4" Hole Section M-23 McArthur River Depleted reservoirs SFD Page 47 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 33. 8.5” Hole Section MASP MD TVD Planned Top: 6,500 4,118 Planned TD: 11,192 8,671 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad D7 5035.39 823 Gas 3.1 0.16 D16 6,005 255 Gas 0.8 0.04 F7 7,933 2731 Gas 6.6 0.34 F9b 8,165 3176 Gas 7.5 0.39 F9c 8,241 3519 Gas 8.2 0.43 F-10 8,269 2970 Gas 6.9 0.36 G-01 8,359 3322 Gas 7.6 0.40 G-05 8,585 1994 Gas 4.5 0.23 TD 8,671 3700 Gas 8.2 0.43 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date M-21 9.0 - 9.3 2,691 2,691 2011 M-27 9.6 - 9.8 4,235 10,500 1990 M-28 9.4 - 9.6 4,610 10,500 1990 M-29 9.5 - 9.7 3,770 10,500 1991 M-30 9.4 - 9.9 4,247 10,500 1992 M-22 9.2 - 9.6 5,925 6,000 2018 Assumptions: 1. Fracture gradient at 6,500' MD / 4,118' TVD is estimated at 12-13 PPG based on field test data. 2. Maximum planned mud density for the hole section is 9.8 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is fully evacuated wellbore to reservoir gas. Fracture Pressure at shoe considering a full column of gas from shoe to surface: FP= 12.5 PPG x 0.052 x 4,118 (ft)= 2677 psi 2677(psi) - [0.1(psi/ft)*4,118(ft)]= 2265 psi MASP from pore pressure (F9 Sand (0.426 psi/ft) 8,671(ft) x 0.426(psi/ft)= 3693 psi 3693 psi - (.1 psi x 8,671') = 2825 psi MASP Summary: MASP while drilling 8-1/2" hole is governed by gas to surface. Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section M-23 McArthur River Depleted reservoirs SFD Page 48 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 34. Plot (NAD 27) (Governmental Sections) Page 49 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 35. Slot Diagram Page 50 PTD February 26th, 2024 TBU M-23 Drilling Program PTD 36. Directional Program (wp06) - Attached separately. 6WDQGDUG3URSRVDO5HSRUW )HEUXDU\ 3ODQ 0ZS +LOFRUS$ODVND//& 7UDGLQJ%D\0F$UWKXU5LYHU)LHOG 6WHHOKHDG 3ODQ 7%80 0 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225 So u t h ( - ) / N o r t h ( + ) ( 5 5 0 u s f t / i n ) -1375 -1100 -825 -550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 West(-)/East(+) (550 usft/in) 13 3/8" x 17 1/2" 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 250 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4500 5000 5500 6000 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 6 7 1M-23 wp06 Start Dir 2º/100' : 480' MD, 480'TVD Start Dir 4º/100' : 580' MD, 579.98'TVD End Dir : 2191.79' MD, 1858.39' TVD Start Dir 4º/100' : 5177' MD, 3120'TVD End Dir : 6453.43' MD, 4072.89' TVD Start Dir 1.5º/100' : 8654' MD, 6208.09'TVD End Dir : 9054' MD, 6596.21' TVD Total Depth : 11192' MD, 8670.7' TVD CASING DETAILS TVD TVDSS MD Size Name 1579.70 1419.70 1700.00 13-3/8 13 3/8" x 17 1/2" 4118.07 3958.07 6500.00 9-5/8 9 5/8" x 12 1/4" 8670.70 8510.70 11192.00 4-1/2 4 1/2" x 8 1/2" Project: Trading Bay - McArthur River Field Site: Steelhead Well: Plan: TBU M-23 Wellbore: M-23 Plan: M-23 wp06 WELL DETAILS: Plan: TBU M-23 Water Depth: 187.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2499432.48 214240.51 60° 49' 54.2995 N 151° 36' 5.3885 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: TBU M-23, True North Vertical (TVD) Reference:Prelim RKB @ 160.00usft Measured Depth Reference:Prelim RKB @ 160.00usft Calculation Method:Minimum Curvature 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 Tr u e V e r t i c a l D e p t h ( 1 2 0 0 u s f t / i n ) 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 Vertical Section at 8.17° (1200 usft/in) 13 3/8" x 17 1/2" 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 0 500 1 0 0 0 1 5 0 0 2000 2500 3000 3500 4000 4500 5000 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 1 1 0 0 0 1 1 1 9 2 M-23 wp06 Start Dir 2º/100' : 480' MD, 480'TVD Start Dir 4º/100' : 580' MD, 579.98'TVD End Dir : 2191.79' MD, 1858.39' TVD Start Dir 4º/100' : 5177' MD, 3120'TVD End Dir : 6453.43' MD, 4072.89' TVD Start Dir 1.5º/100' : 8654' MD, 6208.09'TVD End Dir : 9054' MD, 6596.21' TVD Total Depth : 11192' MD, 8670.7' TVD SZ-10 SZ-11 SZ-12 SZ-17 SZ-21 SZ-24 A3 A5 B1 B5 B6 C1 C3 D4 D7 D16 F7 F9b F9c F-10 G-01 G-05 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: TBU M-23 Water Depth: 187.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2499432.48 214240.51 60° 49' 54.2995 N 151° 36' 5.3885 W SURVEY PROGRAM Date: 2024-01-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 0.00 1200.00 M-23 wp06 (M-23) 3_Gyro-CT_Csg 1200.00 1700.00 M-23 wp06 (M-23) 3_MWD+IFR2+MS+Sag 1700.00 6500.00 M-23 wp06 (M-23) 3_MWD+IFR2+MS+Sag 6500.00 11192.00 M-23 wp06 (M-23) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1422.00 1262.00 1489.34 SZ-10 1449.00 1289.00 1523.61 SZ-11 1583.00 1423.00 1704.72 SZ-12 2002.00 1842.00 2531.59 SZ-17 2335.00 2175.00 3319.53 SZ-21 2488.00 2328.00 3681.56 SZ-24 2747.00 2587.00 4294.41 A3 2871.00 2711.00 4587.82 A5 3167.00 3007.00 5280.32 B1 3547.00 3387.00 5865.57 B5 3616.00 3456.00 5950.62 B6 3835.00 3675.00 6201.48 C1 3965.00 3805.00 6341.03 C3 4780.00 4620.00 7182.19 D4 5035.00 4875.00 7445.00 D7 6005.00 5845.00 8444.69 D16 7933.00 7773.00 10431.72 F7 8165.00 8005.00 10670.82 F9b 8241.00 8081.00 10749.15 F9c 8269.00 8109.00 10778.00 F-10 8359.00 8199.00 10870.76 G-01 8585.00 8425.00 11103.68 G-05 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: TBU M-23, True North Vertical (TVD) Reference:Prelim RKB @ 160.00usft Measured Depth Reference:Prelim RKB @ 160.00usft Calculation Method: Minimum Curvature Project:Trading Bay - McArthur River Field Site:Steelhead Well:Plan: TBU M-23 Wellbore:M-23 Design:M-23 wp06 CASING DETAILS TVD TVDSS MD Size Name 1579.70 1419.70 1700.00 13-3/8 13 3/8" x 17 1/2" 4118.07 3958.07 6500.00 9-5/8 9 5/8" x 12 1/4" 8670.70 8510.70 11192.00 4-1/2 4 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2 480.00 0.00 0.00 480.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 480' MD, 480'TVD 3 580.00 2.00 32.00 579.98 1.48 0.92 2.00 32.00 1.60 Start Dir 4º/100' : 580' MD, 579.98'TVD 4 980.00 18.00 32.00 972.62 60.19 37.61 4.00 0.00 64.93 5 2191.79 65.00 10.77 1858.39 803.28 252.42 4.00 -26.00 831.01 End Dir : 2191.79' MD, 1858.39' TVD 6 5177.00 65.00 10.77 3120.00 3461.14 758.02 0.00 0.00 3533.75 Start Dir 4º/100' : 5177' MD, 3120'TVD 7 6453.43 14.00 5.94 4072.89 4234.83 891.02 4.00 -178.50 4318.48 End Dir : 6453.43' MD, 4072.89' TVD 8 8654.00 14.00 5.94 6208.09 4764.34 946.14 0.00 0.00 4850.45 Start Dir 1.5º/100' : 8654' MD, 6208.09'TVD 9 9054.00 14.00 341.14 6596.21 4859.74 935.34 1.50 -90.00 4943.35 End Dir : 9054' MD, 6596.21' TVD 10 11192.00 14.00 341.14 8670.70 5349.21 768.17 0.00 0.00 5404.09 Total Depth : 11192' MD, 8670.7' TVD 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 7UDGLQJ%D\0F$UWKXU5LYHU)LHOG 6WHHOKHDG 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ 7%80 0 6XUYH\&DOFXODWLRQ0HWKRG 0LQLPXP&XUYDWXUH 3UHOLP5.%#XVIW 'HVLJQ 0ZS 'DWDEDVH 1257+86&$1$'$ 0'5HIHUHQFH 3UHOLP5.%#XVIW 1RUWK5HIHUHQFH :HOO3ODQ 7%80 7UXH 0DS6\VWHP *HR'DWXP 3URMHFW 0DS=RQH 6\VWHP'DWXP 866WDWH3ODQH ([DFWVROXWLRQ 1$' 1$'&21&2186 7UDGLQJ%D\0F$UWKXU5LYHU)LHOG $ODVND=RQH 0HDQ6HD/HYHO 8VLQJ:HOO5HIHUHQFH3RLQW 8VLQJJHRGHWLFVFDOHIDFWRU 6LWH3RVLWLRQ )URP 6LWH /DWLWXGH /RQJLWXGH 3RVLWLRQ8QFHUWDLQW\ 1RUWKLQJ (DVWLQJ *ULG&RQYHUJHQFH 6WHHOKHDG XVIW 0DS XVIW XVIW 6ORW5DGLXV 1 : :HOO :HOO3RVLWLRQ /RQJLWXGH /DWLWXGH (DVWLQJ 1RUWKLQJ XVIW (: 16 3RVLWLRQ8QFHUWDLQW\ XVIW XVIW 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e p a r a t i o n F a c t o r 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth (1200 usft/in) G-09 PB1 G-09 PB4 M-01 M-01PB1 M-21 M-07 M-30 G-32 G-25 G-18 G-16 M-04 K-25 K-21 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. WELL DETAILS:Plan: TBU M-23 NAD 1927 (NADCON CONUS)Alaska Zone 04 Water Depth: 187.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2499432.48 214240.51 60° 49' 54.2995 N 151° 36' 5.3885 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: TBU M-23, True North Vertical (TVD) Reference:Prelim RKB @ 160.00usft Measured Depth Reference:Prelim RKB @ 160.00usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2024-01-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 0.00 1200.00 M-23 wp06 (M-23) 3_Gyro-CT_Csg 1200.00 1700.00 M-23 wp06 (M-23) 3_MWD+IFR2+MS+Sag 1700.00 6500.00 M-23 wp06 (M-23) 3_MWD+IFR2+MS+Sag 6500.00 11192.00 M-23 wp06 (M-23) 3_MWD+IFR2+MS+Sag 0.00 30.00 60.00 90.00 120.00 150.00 180.00 Ce n t r e t o C e n t r e S e p a r a t i o n ( 6 0 . 0 0 u s f t / i n ) 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth (1200 usft/in) LA2 Slot 6M-35 WP16 M-01M-01PB1M-05 M-14RDM-14 M-06RDM-06M-03M-21 La-Vine WP1.0 M-09 TBU M-22 M-15 LA2 Slot11 M-17 M-07 M-30 M-37 Wp1 M-28RDM-28 M-13 M-29AM-29M-26M-31L1M-31AM-31 PB1M-31M-31BM-35L1 WP07M-35M-35PB1 M-36 WP1 LA2 Slot 4 M-18 M-19RDM-19 M-32 PB2M-32 PB1M-32RD PB1M-32 PB3M-32RDM-32RD2M-32 M-27 M-02 M-04 M-24 wp01 Prelim M-10PB1M-10M-12 M-16RDM-16 M-16 M-34 M-11M-20 M-25 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 0.00 To 11192.00 Project: Trading Bay - McArthur River Field Site: Steelhead Well: Plan: TBU M-23 Wellbore: M-23 Plan: M-23 wp06 Ladder / S.F. Plots CASING DETAILS TVD TVDSS MD Size Name 1579.70 1419.70 1700.00 13-3/8 13 3/8" x 17 1/2" 4118.07 3958.07 6500.00 9-5/8 9 5/8" x 12 1/4" 8670.70 8510.70 11192.00 4-1/2 4 1/2" x 8 1/2" 1 Davies, Stephen F (OGC) From:Jonathan Lawley - (C) <Jonathan.Lawley@hilcorp.com> Sent:Wednesday, February 28, 2024 2:49 PM To:Davies, Stephen F (OGC) Subject:RE: [EXTERNAL] TBU M-23 (PTD 224-018) - Question Steve, Thanksforyourpatience. 1. MudProgram,weightandlosses. a. Themudforboth12.25”and9.625”willbethesame;asdescribedinthe15.3. b. Mudweightforbothofsaidsectionswillbeaminimumof9.2PPGasin15.1. i. Weightcanbeadjustedhigherasneeded,ifcharacteristicsofhigherpressuresareobserved (progressivelyhighergasunitsonbottomsup,gascutmud,smallgain/SPPdecreaseonbottoms up,etc.) ii. Historically,itisnotanticipatedthatmudweightwillneedtobehigherthan9.8PPG. iii. Thesecondreasonformaintaininga9.2PPGminimumiscoalstabilization.Althoughthismay leadtosomefluidlosses,it’scriticaltomaintainasstableofawellboreaspossible. c. LCMismentionedonpages21&29withsomehighleveloverviewonpage39.Severalvarioustypesof LCMwillbeinventoriedandstrategymaychangedependingonobservationsandtoolcapacityforsaid variousLCMtypes. i. BackgroundLCMconcentration&type. ii. SweepLCMconcentration,type®ime. iii. Forseverelossofcirculation;spotting&soakingmethods. iv. Fluidvolumemanagementisacriticalpartoflosscirculationcontrol;maintainingenough volumetokeeptheholefullatgivenpump/lossratesispartofdecadesofCookinletexperience ofthe2leaddrillingforemanforthisproject.Someofthatismentionedinsection27. 2. Yes,astandardgasdetector“sniffer”willberiggedupontheshakerspriortospudandremainfortheduration ofthewell.Wewillnothaveamudloggingunitonthisjob. Ihopethatanswersyourquestionsfornow.Pleaseletmeknowifyou’dlikemoredetail. JonLawley ERDEngineer(Contractor) 801Ͳ819Ͳ6579 From:Davies,StephenF(OGC)<steve.davies@alaska.gov> Sent:Wednesday,February28,20248:00AM To:JonathanLawleyͲ(C)<Jonathan.Lawley@hilcorp.com> Subject:RE:[EXTERNAL]TBUMͲ23(PTD224Ͳ018)ͲQuestion Thankyoufortheupdate,Jon. Youdon'toftengetemailfromjonathan.lawley@hilcorp.com.Learnwhythisisimportant CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 2 ThanksAgainandBeSafe, SteveDavies AOGCC From:JonathanLawleyͲ(C)<Jonathan.Lawley@hilcorp.com> Sent:Wednesday,February28,20245:39AM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov> Subject:Re:[EXTERNAL]TBUMͲ23(PTD224Ͳ018)ͲQuestion Flightsyesterdaygotdelayedinto4AMandIhadtobetoarigearlythismorning.I’msendingemailsfrommyphone untillatertoday. JustwantedtonotifyyouguysthatthisistoppriorityformeandI’llgettoitASAP. JonLawley ERDEngineer(Contractor) 801Ͳ819Ͳ6579 OnFeb27,2024,at20:07,Davies,StephenF(OGC)<steve.davies@alaska.gov>wrote: Jon, Page39ofHilcorp’sapplicationlists“ShallowGasSandsWhileDrillingSurface”atthebeginningofthe AnticipatedDrillingHazardssection,yetIdon’tseeanymentionofmudloggingorgasmonitoringfor thiswell.Inadditiontomyrequestforadditionaldetailbelow,pleasedescribeHilcorp’sgasmonitoring andmitigationplansforthiswell. ThanksandBeWell, SteveDavies SeniorPetroleumGeologist AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGas ConservationCommission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/or privilegedinformation.Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateorfederallaw.Ifyouarean unintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit,and,sothattheAOGCCisawareofthemistakein sendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov From:Davies,StephenF(OGC) Sent:Tuesday,February27,20243:17PM To:JonathanLawleyͲ(C)<Jonathan.Lawley@hilcorp.com> Subject:RE:[EXTERNAL]TBUMͲ23(PTD224Ͳ018)ͲQuestion You don't often get email from jonathan.lawley@hilcorp.com. Learn why this is important CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 3 Jon, Thanksforthequickreply.Yes,ifyoucouldprovidemoredetail,itwillbeappreciated. Thanks, SteveDavies AOGCC From:JonathanLawleyͲ(C)<Jonathan.Lawley@hilcorp.com> Sent:Tuesday,February27,20243:15PM To:Davies,StephenF(OGC)<steve.davies@alaska.gov> Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;Guhl,MeredithD(OGC) <meredith.guhl@alaska.gov> Subject:Re:[EXTERNAL]TBUMͲ23(PTD224Ͳ018)ͲQuestion HiStephen, I’minanairportanddon’timmediatelyhavethedocumentinfrontofme. 1.Themudprogramforbothlowerholesectionsisthesame.ThePTDapp.maybeambiguousonthat;I canmakethatexplicit. 2.Yessir.ThehazardssectiondetailssomerisksforthesurfaceholeandstateshavingplentyofLCM& extrafluidsavailabletoastonotrunintoanevacuatedhole/WCsituation.Thosematerialswillbe presentandusedinthesubsequentholesectionsaswell.Andyesyou’recorrect,lossesandmitigation ofsuchareanticipated.Again,Idon’thaveitinfrontofme.Icanalsomakethatexplicitforthe subsequentholesections. WhenIgetsettledtonight,Icantakeabetterlookatansweringyourquestions. Thanks! JonLawley ERDEngineer(Contractor) 801Ͳ819Ͳ6579 OnFeb27,2024,at16:07,Davies,StephenF(OGC)<steve.davies@alaska.gov>wrote: Jonathan, You don't often get email from jonathan.lawley@hilcorp.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 4 I'mreviewingHilcorpAlaska'sPermittoDrillApplicationforTBUMͲ23(PTD224Ͳ018) andIhaveafewquestions. 1. Idon’tseea“PreparatoryWorkandMudProgram”sectionintheproposed workprogramforthe8Ͳ1/2”holelikethatprovidedforthe12Ͳ1/4”hole.What mudweight(s)is(are)Hilcorpplanningtousewhiledrillingthisfinalsectionof thewell? 2. Formostofthedrillingoperations,theplannedmudprogramforMͲ23will apparentlybesignificantlyoverͲbalancedduetonumerousdepletedgas reservoirs.WillappropriateamountsofLCMsuppliesbeavailableonthis offshorerigduringtheseoperations? Pleaseprovidethefollowupinformationassoonasyoucan.Sincewehavelessthan twoweeksuntiltheplannedspuddate,I’dliketomovethisapplicationalongthrough AOGCC’sreviewprocessbecauseI’llbegoingonvacationbeforethen. ThanksandBeWell, SteveDavies SeniorPetroleumGeologist AOGCC CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaska OilandGasConservationCommission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmay containconfidentialand/orprivilegedinformation.Theunauthorizedreview,useordisclosureofsuchinformationmay violatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingor forwardingit,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224 orsteve.davies@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. MCARTHUR RIVER, MIDDLE KENAI GAS 224-018 TBU M-23 MCARTHUR RIVER WELL PERMIT CHECKLIST Company Hilcorp Alaska, LLC Well Name:TRADING BAY UNIT M-23 Initial Class/Type DEV / PEND GeoArea 820 Unit 12070 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2240180 MCARTHUR RIVER, MIDKENAI GAS - 520550 NA1 Permit fee attached Yes Entire Well lies within ADL0018730.2 Lease number appropriate Yes3 Unique well name and number Yes MCARTHUR RIVER, MIDKENAI GAS - 520550 - governed by 228A4 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary Yes6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For s NA15 All wells within 1/4 mile area of review identified (For service well only) NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only) NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) Yes 26" 262 #/ft X-56 to 450' Vertically set.18 Conductor string provided Yes19 Surface casing protects all known USDWs Yes20 CMT vol adequate to circulate on conductor & surf csg Yes21 CMT vol adequate to tie-in long string to surf csg Yes22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit NA25 If a re-drill, has a 10-403 for abandonment been approved Yes Close approaches just below the conductor. Require gyros and acoustic monitoring.26 Adequate wellbore separation proposed Yes Diverter waiver requested to allow two 16" diverter lines < 17.5" diameter surface hole - can open simultaneo.27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP = 2825 psi, BOP rated to 5000 psi (BOP test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments) Yes31 Choke manifold complies w/API RP-53 (May 84) Yes32 Work will occur without operation shutdown No33 Is presence of H2S gas probable NA34 Mechanical condition of wells within AOR verified (For service well only) Yes None expected based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measures Yes Depleted reservoir sands abound mixed with normal to slightly overpressured (9.2 ppg EMW) intervals.36 Data presented on potential overpressure zones NA Lost circulation and differential sticking are possible. Sufficient LCM will be available onsite.37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr SFD Date 2/27/2024 Appr MGR Date 3/11/2024 Appr SFD Date 3/1/2024 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date *&: JLC 3/18/2024
