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224-126
DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 3 3 - 2 0 7 3 0 - 0 0 - 0 0 We l l N a m e / N o . K E N A I U N I T 2 3 - 0 7 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 12 / 2 1 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 10 4 3 7 TV D 95 8 0 Cu r r e n t S t a t u s 1- G A S 10 / 1 0 / 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 1 1 - 2 3 - 2 4 + 1 2 - 7 - 2 4 , P e r f a n d G P T l o g s , L W D ( P C G , A D R , P W D , D D S R , C T N , A L D ) 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 12 / 1 8 / 2 0 2 4 75 0 5 5 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U _ 2 3 - 07 A _ C B L _ 7 - D e c e m b e r - 2 0 2 4 _ ( 5 1 9 5 ) . l a s 39 8 7 2 ED Di g i t a l D a t a DF 12 / 1 8 / 2 0 2 4 E l e c t r o n i c F i l e : K U _ 2 3 - 0 7 A _ C B L _ 7 - D e c e m b e r - 20 2 4 _ ( 5 1 9 5 ) . p d f 39 8 7 2 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 13 5 1 0 4 3 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 2 3 - 0 7 A L W D Fi n a l . l a s 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l M D . c g m 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l T V D . c g m 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A - D e f i n i t i v e S u r v e y Re p o r t . p d f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A - D S R . t x t 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A - D S R _ G I S . t x t 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A - F i n a l S u r v e y s . x l s x 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A _ D S R _ P l a n P l o t . p d f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A _ D S R _ V s e c P l o t . p d f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l M D . e m f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l T V D . e m f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l M D . p d f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l T V D . p d f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l M D . t i f 39 8 9 7 ED Di g i t a l D a t a DF 12 / 1 9 / 2 0 2 4 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A L W D F i n a l T V D . t i f 39 8 9 7 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 61 9 8 7 6 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : K U 2 3 - 0 7 A S C B L MA I N P A S S 1 1 - 2 3 - 2 4 . l a s 40 0 5 8 ED Di g i t a l D a t a Fr i d a y , O c t o b e r 1 0 , 2 0 2 5 AO G C C Pa g e 1 o f 2 KU 2 3 - 0 7 A L W D Fi n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 1 3 3 - 2 0 7 3 0 - 0 0 - 0 0 We l l N a m e / N o . K E N A I U N I T 2 3 - 0 7 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 12 / 2 1 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 2 6 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 10 4 3 7 TV D 95 8 0 Cu r r e n t S t a t u s 1- G A S 10 / 1 0 / 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 : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 12 / 2 1 / 2 0 2 4 Re l e a s e D a t e : 10 / 2 9 / 2 0 2 4 DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A S C B L F I N A L . p d f 40 0 5 8 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A S C B L M A I N P A S S 1 1 - 23 - 2 4 . d l i s 40 0 5 8 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : K U 2 3 - 0 7 A S C B L M A I N P A S S 1 1 - 23 - 2 4 . p d f 40 0 5 8 ED Di g i t a l D a t a Fr i d a y , O c t o b e r 1 0 , 2 0 2 5 AO G C C Pa g e 2 o f 2 10 / 1 0 / 2 0 2 5 M. G u h l Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/8/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. T40053 T40053 T40054 T40055 T40056 T40057 T40058 T40059 T40060 T40061 T40062 T40063 T40064 T40065 T40066 T40067 KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.07 13:25:23 -09'00' 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address:7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s): Kenai Gas Field GL:65.6' BF:N/A Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number: Surface:x- y- Zone- 4 TPI:x- y- Zone- 4 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD: Total Depth:x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 16" X-56 120' 10-3/4"L-80 1,620' 7-5/8"L-80 5,921' 3-1/2"L-80 9,576' 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 Surface 1,665' 9.2# Surface N/A 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 6,298' Surface 13-1/2" Driven Surface L - 393 sx / T - 351 sx SETTING DEPTH TVD ACID, FRACTURE, CEMENT SQUEEZE, ETC. L - 388 sx / T - 99 sx6-3/4" TUBING RECORD L - 709 sx / T - 140 sx9-7/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 12/21/2024 224-126 / 324-682 TOP HOLE SIZE CBL 11-23-24+ 12-7-24, Perf and GPT logs, LWD (PCG, ADR, PWD, DDSR, CTN, ALD) N/A N/A N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 275026 2361385 50-133-20730-00-00November 10, 2024 N/A KU 23-07ANovember 30, 2024627' FNL, 873' FEL, Sec 7, T4N, R11W, SM, AK 83.6' Tyonek Gas Pool 1 FEE A028142 10,437' MD / 9,580' TVD 10,358' MD / 9,508' TVD 1852' FSL, 1872' FWL, Sec 7, T4N, R11W, SM, AK CASING, LINER AND CEMENTING RECORD 1601' FSL, 1715' FWL, Sec 7, T4N, R11W, SM, AK 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, AMOUNT PULLED 272797 272635 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) Conductor BOTTOMCASINGWT. PER FT.GRADE CEMENTING RECORD 2358512 2358264 Choke Size: Surface Per 20 AAC 25.283 (i)(2) attach electronic information 29.7# 10,423' Surface Surface 84# 45.5# 120' Water-Bbl: PRODUCTION TEST 1/6/2025 Date of Test:Oil-Bbl: Flowing *** Please see attached schematic for perforation detail *** Gas-Oil Ratio: Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl:Water-Bbl: 0 0270 1/13/2025 24 Flow Tubing 0 836 N/A8360 G s d 1 0 p dB P L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment Recieved by J. Brooks on 1/22/2025 at 11:02AM Complete 12/21/2024 JSB RBDMS JSB 020425 GDSR-4/7/25BJM 10/6/25 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 9717' Ty D2 8,927' 4911' 4635' 5626' 5298' 6473' 6078' 7737' 7192' 9501' 8737' 9683' 8897' 9954' 9140' 10216' 9379' Ty D4D 10337' 9489' 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. INSTRUCTIONS Tyonek Upper Beluga Ty D1 Ty D4 Mid Beluga Lower Beluga Ty D2 Ty D3 Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Reports, Definitive Directional Survey Authorized Title: Drilling Manager 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. N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.01.20 12:48:42 - 09'00' Sean McLaughlin (4311) _____________________________________________________________________________________ Updated by CJD 1-20-25 CURRENT Schematic Kenai Gas Field Well: KU 23-07A PTD: 224-126 API# 50-133-20730-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 84 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 / L-80 / GBCD 9.950”Surf 1,665’ 7-5/8"Intermediate 29.7/ P-110/GBCD 6.875”Surf 6,298’ 3-1/2"Production 9.2 / L-80 / Hyd 563 2.992”Surf 10,423’ JEWELRY DETAIL No Depth Item 1 19.2 Cactus CTF-ONE-CTL 7” x 3-1/2” tubing hanger with 3- 1/2” EUE, 3.5” type H BPV profile OPEN HOLE / CEMENT DETAIL 10-3/4”147 bbls (393sx) of 12.5 ppg lead with 77 bbls (351 sx) of 15.3 ppg cement, 94 bbls of lead to surface 13-1/2” Hole. 7-5/8" 248 bbls (709 sx) of 12.5 ppg lead followed by 31 bbls (140 sx) of 15.3 ppg class G tail cement. Did not bump plug. CBL (11/23/24) shows TOC @ 1080’. 20 bbls of cmt return at surface, lost 11.8 bbls during job. 3-1/2”245 bbls (655sx) of 12.5 ppg lead with 24 bbls (109 sx) 15.3 ppg cement in 6-3/4” Hole. Est TOC @ 4,554’ (CBL) Notes: Short jt w/ RA tags 9429, 8411, 7423, 6433 Short joints 9909, 8921, 7903, 6911, 5516, 5008, 4560 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Tyonek Gas Pool 9692’ MD; 8905’ TVD D2 9,717'9,781'8,927'8,924'65'1/8/25 Open D3C 10,064'10,078'9,239'9,252'14'12/21/24 Open Page 1/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Jobs Actual Start Date:11/8/2024 End Date:12/4/2024 Report Number 1 Report Start Date 11/8/2024 Report End Date 11/9/2024 Operation Prep for rig movers, fly out choke manifold house and iron roughneck, remove windwalls from pits, pull out boiler and gen skid, crane out gen 3, pull top drive HPU pull pump skids, Lower pit rooves, remove pit modules, pull rig mats transport mods to KGF spot in cranes and prep to pick derrick Transport loads to KGF and stage, pick derrick and draw works off sub and load on trailers, pipck sub off well, pull pony subs and mats and prep to move waiting on road restrictions for last loads to KGF Crew mob to KGF. Lay felt, liner and rig mats. Install new 2" hydraulic hard line in derrick for top drive. Change liners in MP#1 to 5.5". CCI continue to load out and haul misc loads to KGF. Change liners in MP#2 to 5.5". Install lights on pit modules. CCI continue to load out and haul misc loads to KGF. Report Number 2 Report Start Date 11/9/2024 Report End Date 11/10/2024 Operation Spot in cranes, set sub center over well, set draw works and derrick, spot in pit mods and jig, set pump skids, spot and raise doghouse, set gen skid and top drive HPU, raise pit rooves, set wind walls with crane set iron roughneck and choke house, Prep and raise mast, set clam shell and centrifuge. Rig down and transport camps from beaver creek to KGF, spot in and rig up Continue RIgging up, lay felt liner and mats for catwalk, spot in catwalk and raise ramp, hook up power steam and air lines, get boilers going run steam around rig, continue hauling equipment from beaver creek, spot gen 3, hook up pit and pump lines, take on water and diesel to rig, String up drill line and slip 89' on drawworks. Scope up derrick. Installed TQ Tube and T-Bar. Connect Pason wires. Install turn buckles and transfer lines on mud pits. P/U Top Drive. Work on rig acceptance checklist. Handy berm crew built containment around rig. Connect lines to choke manifold and standpipe. Finish installing rig tarps. Dress out rig floor with handling equipment and subs. Install bails and elevators on Top Drive. Spot and set DD/MWD and mud man trailers. Remove all beams throughout sub structure. Build new transfer hoses for mix hoppers. Function test MP'. Function test Gai Tronics. R/U Iron roughneck and function test (fail) R/U Gen 3 and function test (fail). Continue working on rig acceptance checklist. Report Number 3 Report Start Date 11/10/2024 Report End Date 11/11/2024 Operation Re-wrap omni wrap on kelly hose, hand service loop sock, change filters on floor motor and loader, Function test pit equipment, hook up service loop and function test top drive, make up saver sub. Finish rig acceptance checklist, function test iron roughneck, spot in riser and N/U riser and flow line, hook up hole fill lines and chain off riser. Accept rig @ 1800 hrs. Pressure test surface lines to 1500psi-Good. Check TQ on rig tongs and iron roughneck-Good. P/U 30 stand of 4.5" CDS40 DP and 9 Stands of HWDP/Jars. Simops: Build 320bbls 8.8ppg 300+ vis spud mud. M/U 13-1/2" Bit, motor, and XO. RIH P/U HWDP tagging at 85', wash through observing no change in parameters and tag bottom on depth at 136'. Spud 13-1/2" surface section and drill rathole T/ 229'. 350gpm = 650/620psi on/off with a R/F of 33%, 30rpm = 4KFt-lbs TQ on/off with 4K WOB. P/U 27K, S/O 24K, ROT 26K. Observe heavy sand returns at shakers. Circulated hole clean. Flow check. POOH F/ 229' - T/ Surface on elevators. M/U DM, ADR, TM, and XO. Perform RFO (84.16°), download to MWD, and shallow pulse test tools. Report Number 4 Report Start Date 11/11/2024 Report End Date 11/12/2024 Operation Finish shallow pulse test, make up flex collars and 1 stand of HWDP, take survey on bottom Drill 13.5'' Surface hole f/ 136' t/ 404' 350 gpm 1100 psi 30 rpm 3.5k tq on bottom 5k wob MW 8.7 ppg, 31k PUW 28k SOW 30k ROT, having survey issues magnetic interferance. Continue Drilling 13.5'' Surface hole f/ 404' t/ 782' 380 gpm 1435 psi 30 rpm 4k tq on bottom, 9 ppg mw 33k PUW 30k SOW 32k ROT Drill 13.5" surface section F/ 782' - T/ 1222' (1148' TVD), Total: 440' (AROP: 73fph). 385gpm = 1450/1370psi on/off with a R/F of 35%, 40RPM = 5/4Kft-lbs on/off TQ with 3-10K WOB. ECD = 9.35ppg with 8.95ppg in/out MW. P/U 49K, S/O 50K, ROT 50K. Drill 13.5" surface section F/ 1222' - to TD at 1671' (1625' TVD), Total: 449' (AROP: 74fph). 350gpm = 1350/1275psi on/off with a R/F of 32%, 40RPM = 4-8Kft-lbs on/off TQ with 5K WOB. ECD = 9.61ppg with 9.0/9.1ppg in/out MW, Max Gas = 25u. P/U 57K, S/O 52K, ROT 54K. CBU observing some sand and clay at shakers until cleaned up. Flow check. Blow down surface lines. Report Number 5 Report Start Date 11/12/2024 Report End Date 11/13/2024 Operation Blew down topdrive, pulled up hole from 1671' to HWDP at 719' with no issue, decision made to cont POOH. Racked back HWDP and jars, LD NM flex DC's, downloaded MWD, LD smart tools and motor, bit graded 1-1 and in gauge. Calc hole fill = 14.4 bbls, actual hole fill - 19.2 bbls. Cleared and cleaned rig floor, serviced rig and topdrive. Staged casing tools for RU. RU casing tongs, manual backup tongs, false table and elevators. RU fill up line, staged centralizers and casing on rack. MU circ swedge on TIW, held PJSM. Inpected and MU shoe track filling each joint, stroked pipe to verify FE working (OK), cont PU single in hole total 39 jnts 10 3/4" GBCD 45.50# L-80 casing torqued to 15,000 ft/lbs. Flilled on the fly, topped off every 10 jnts, to 1637'. Sent 24 hour notice to state for initial BOP test (15:00 on 11-13-24) MU bail extensions on topdrive, installed circ swedge in landing jnt, MU same, broke circ at 134 gpm-40 psi, RD casing equipment and removed from rig floor. Washed down and landed hanger on depth with no issue during trip. Up wt 86K, dwn wt 73K. Cont stage pump rate up to 208 gpm-0 psi while staging cement trucks and R/U lines. Fox mix 10.5ppg spacer. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169Permit to Drill (PTD) #:224-126 Wellbore API/UWI:50-133-20730-00-00 Spud 13-1/2" surface section and drill rathole T/ 229'. Page 2/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation R/U plug launcher and hardline to cement unit. Loaded both wiper and closing plugs verifying tattle tale function prior to M/U with Fox rep. Fox loaded lines with 5bbls water and checked for leaks, pressure tested lines at 500/2500psi low/high- Good. Line up and pump 65bbls 10.5 ppg FMP300 Spacer at 4bpm 0psi. Line up and pump 147bbls (393sx) 12.5 ppg Type G Lead Cement at 5bpm 0-30psi, followed by 77bbls (351sx) 15.3 ppg Type G tail cement at 2.2bpm 0psi. Release top plug observing tattle tale function, displace with 9.0ppg Spud Mud at 4bpm 0-410psi. Slowed pump to 2bpm at 145bbls away, bumped the plug 155bbls into displacement (calculated 151.6bbls). Pressure up to 940psi for 3 minutes (FCP of 390psi), bled off and checked floats- Good. Bled back 1/2bbl to truck. Had 65bbls of Spacer returns to surface and 94bbls lead cement to surface. Mix water temp 70deg. Pumped 100% excess on lead/tail. No losses throughout the job. Did not reciprocate casing. P/U 86K, S/O 75K, 58K on hanger. CIP at 01:35 hrs. Release Fox. Flush out cement lines and blow down. Remove cement head, swage, bail extensions, and elevators. Install DP elevators. Remove landing Jt. per Vault rep. M/U Jonny Whacker to Jt. of DP and flush BOPE with black water. R/D Same. M/U running tool to pack off. RIH with Jt of HWDP and set per Vault rep. Verify landed and RILDS. Test packoff seals to 3000psi for 10 min- Good. Report Number 6 Report Start Date 11/13/2024 Report End Date 11/14/2024 Operation ND flowline and two piece conductor riser, removed cellar tarps and lay back beaver slide, removed riser from cellar, staged wellhead "B" section in cellar, installed trolly beam. Set B section on wellhead and wellhead Rep RILD's, then tested seals at 3000 psi for 10 minutes, good test. CCI crane transfered BOP stack from cradle to cellar bridgecranes, set beaver slide and re-hung tarps. Installed 10K x 5K adaptor spool on wellhead, installed BOP stack, torqued all bolts including single gate to mud cross. Hung drip pan, installed flow riser and flow line, installed choke and kill lines, chained off stack. SIMOPS: ship spud mud to G&I, cleaned tank bottoms, transfered KCL mud into active from pre-mix, took on water and start building 2nd batch of mud. Rig electrician tested all audio/visual gas alarms. Install koomey lines and powered up koomey unit. (AOGCC Jim Regg waived witness of BOP test at 09:33 on 11-13-24) R/U Testing equipment. M/U test jt and install test plug. Install test sub to top drive. Flood/Purge lines and attempt shell test. Observe leak on LPR doors, tighten and re-test observing leak coming out weep hole on LPR. Drain stack and de-energize Koomey. Open door and C/O lower ram shaft seal. Button up ram door. Simops: Remove 5.5" liners and install 5". Re-energize Accumulator, re-install test plug, and R/U testing equipment. Perform shell test to 5000psi for 5 min testing LPR, Singlegate connections, and seals-Good. R/U Test jt and flood/purge lines. Test BOPE conducting each test to 250/3500psi lo/hi for 5 min each. Witness waived by AOGCC Jim Regg. Test 4.5" test jt in Annular and UPR. Test Dart, TIW, UPR/LWR IBOP's, CMV #1-15, Mez kill, HCR Kill, Inside Kill. One fail/pass on UPR, functioned and re-tested-Good. Report Number 7 Report Start Date 11/14/2024 Report End Date 11/15/2024 Operation Cont testing BOPE at 250 low/3500 high, performed drawdown test, functioned flow show and PVT alarms. Had to sync lower ODS pipe ram for an F/P on high test. Pulled test plug draining BOP stack, set 10" ID long wear ring, L/D test joint, RU test pump on kill line, flooded stack and purged air, closed blinds. Pumped 66.7 gallons to achieve 2763 psi on 10 3/4" surface casing. Held 30 min on chart, bled back 66.7 gallons, good test. Started racking DP for PU during test. RD test equipment, blew down surface lines and choke manifold, lined up valves for drilling, crew found pipe skate bucket was damaged, called out welder. Moved HWDP to drillers side of derrick. Serviced rig and topdrive. Notified Production Rep of upcoming welding on skate, loosened skate cable to allow easy access to skate bucket, welder made repair, crew re-tightened skate cable, functioned skate while strapping DP. Strapped pipe, PU singled in hole with 4 1/2" DP, POOH racking back total 44 jnts. Continue to stage, strap, P/U singles, and rack back DP, 84 jts (128 total). Break down Johnny whacker. Prepare floor for M/U BHA. Stage tools on rig floor and pipe skate per Sperry. Verify nozzles/serial #'s on bit. M/U 9-7/8" PDC Bit to Mud Motor (28KFt-lbs TQ). M/U IBS, DM, DGR, PWD, ADR, ALD, CTN, and TM. Perform RFO: MWD to Motor = 246.51°, MWD to ALD = 114.71°, MWD = CTN = 134.93°. Plug in and download to MWD. Attempt to shallow pulse test tools multiple time with no success. Troubleshoot with town technicians-No Joy. Decision made to C/O the DM Collar. The Accelerometer G Totals not equaling correct value. Report Number 8 Report Start Date 11/15/2024 Report End Date 11/16/2024 Operation LD TM, CTN, ALD, ADR, PWD, DGR collars, swapped out DM collars. went to MU DGR collar to DM and found probe was too tall in DM. LD DGR and DM collars, swapped internals from backup to original DM. PU and MU smart tools. RFO = 250.13°. MU XO and topdrive, plugged in and uploaded MWD. Shallow pulse test was good at 400 gpm. Held PJSM and loaded sources. Blew down topdrive, cont TIH with HWDP and jars to 689'. Cont TIH on stands from 689' to 1496', up wt 55K, dwn wt 43K. SIMOPS: CCI racked and drifted 7 5/8" casing. MU topdrive, filled pipe, washed and reamed down from 1496' at 357 gpm-1000 psi, 40 rpm-5700 to 6300 ft/lbs off bott torque. Tagged a cement stringer at 1537', tagged up on top wiper plug at 1574'. Drilled wiper plugs, float collar, shoe track and shoe to 1665', rathole cement to 1671' and 20' new hole to 1691'. 367 gpm-1200 psi, 40 rpm-5800 to 6200 ft/lbs on bott torque, rot wob 1-2K, 16 to 26 ft/hr ROP. CBU 1 time at 367 gpm-1133 psi and had very fine sand at surface. Reduced pump rate to 223 gpm-358 psi and pumped 20 bbl hi-vis spacer followed with 8.9 ppg 6% KCL mud (10 ppb background LCM), overboarding spud mud returns until good KCL mud to surface. Removed shaker screens and cleaned under shakers and troughs during displacement. CBU twice more with KCL mud. Shut down pumps, LD single, racked back one stand. Blew down topdrive while RU headpin on stump and run test hoses, tied into stump and mezz kill. Purged air, closed rams, flooded choke manifold. Pumped 18.4 gallons to achieve 421 psi on surface shoe. Held 10 minutes and bled down to 177 psi. Bled back 7.5 gallons. Sent chart and data sheet to Drilling Engineer, approved to drill ahead. RD test equipment, blew down choke manifold and opened rams. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 Pumped 66.7 gallons to achieve 2763 psi on 10 3/4" surface casing. Held 30 min on chart, bled back 66.7 gallons, good test. Test BOPE conducting each test to 250/3500psi lo/hi for 5 min each. Witness waived by AOGCC Jim Regg No losses throughout the job Drilled wiper plugs, float collar, shoe track and shoe to 1665', rathole cement to 1671' and 20' new hole to 1691 g p( Had 65bbls of Spacer returns to surface)pp and 94bbls lead cement to surface. Line up and pump,p p gpppppgp 147bbls (393sx) 12.5 ppg Type G Lead Cement at 5bpm 0-30psi, followed by 77bbls (351sx) 15.3 ppg Type G tail cement at 2.2bpm 0psi p p Pumped 18.4 gallons to achieve 421 psi on surface shoe Page 3/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Resumed drilling 9 7/8" intermediate hole from 1691' to 1941' (1877' TVD) Total: 250' (AROP: 55fph). Initial rot wob 1-2K, 412 gpm-902 psi, 40 rpm-4600 ft/lbs on bott torque, 60 to 120 ft/hr ROP. 410GPM = 872/828psi on/off, 40RPM = 4.7/4.2Kft-lbs on/off TQ with 3-5K WOB, ECD = 9.18ppg with 8.9ppg MW 59vis in/out, Max Gas = 28u, BGG = 0. P/U 67K, S/O 55K, ROT 65K. Obtain SPR's at 1691'. Backreaming prior to connections. Drill 9-7/8" intermediate hole F/ 1941' - T/ 2443' (2353' TVD), Total: 502' (AROP: 84fph). 400GPM = 1180/1080psi on/off, 40RPM = 5.8/5.1Kft-lbs on/off TQ with 3-5K WOB, ECD = 9.3ppg with 9.0ppg in/out MW (59vis), Max Gas = 21u. P/U 73K, S/O 60K, ROT 66K. Obtain SPR's at 2190' MD with 8.9ppg MW (2107' TVD). Backreaming full stands prior to connections. Performing Mad Pass on any slides over 20'. Distance from wp02 is 6.93' (6.07' Low, 3.35' Right) Report Number 9 Report Start Date 11/16/2024 Report End Date 11/17/2024 Operation Cont drilling 9 7/8" hole from 2443' to 2693'. Rot wob 2-3K, 405 gpm-1069 psi, 40 rpm-5400 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 3K, 409 gpm-1129 psi, 140 psi diff, 130 ft/hr ROP. At 2587' we increased rotary RPM to 60. MW 8.9+/vis 55, ECD 9.3 ppg, BGG 7 units, max gas 33 units. Obtained on bottom survey then CBU 1 time at 407 gpm-1000 psi, 80 rpm-5690 ft/lbs off bott torque. 10 minute flow check fluid dropped 12 inches in wellbore. Pulled up hole from 2693' to 2503', up wt 82K, blew down topdrive, cont to pull up hole to 1689', S/O and parked at 1750'. No issues during trip. Serviced rig and topdrive. Monitored well on trip tank. Hole taking .88 bph. TIH from 1750' to 2628', dwn wt 60K. At 2628' MU topdrive on last stand, filled pipe, washed and reamed to bottom at 2693'. Pumped a 20 bbl hi-vis nutplug sweep around at 412 gpm-1012 psi, 80 rpm-5700 ft/lbs off bott torque. Max gas at bottoms up 11 units. Sweep back on time with a 15% increase in cuttings. Cont drilling from 2693' to 3130', rot wob 2-6K, 410 gpm-1139 psi, 60 rpm-6100 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 1-2K, 410 gpm-1157 psi, 105 psi diff, 125 ft/hr ROP. MW 9.0/vis 59, ECD 9.3 ppg, BGG 17 units, max gas 36. Drill 9-7/8" Intermediate section F/ 3130' - T/ 3694' (3504' TVD), Total: 564' (AROP: 71fph). 410GPM = 1050/950psi on/off, 60RPM = 6.7/6.1Kft-lbs on/off TQ with 2-6K WOB, ECD = 9.3ppg with 9.05ppg in/out MW (58vis), Max Gas = 77u. P/U 100K, S/O 76K, ROT 85K. Obtain SPR's at 3694' MD with 9.05ppg MW (3504' TVD). Backreaming full stands prior to connections. Obtain survey and CBU. Rot/Recip pipe, 410gpm = 950psi, 80RPM = 6-7KFt-lbs TQ. No change at shakers. Flow check for 10 min observing slight seepage loss. POOH F/ 3694' - T/ 2693' with no overpull or issues (Blew down TD after 3rd stand). Loss 1.04bbls on trip. P/U 102K, S/O 73K. Grease and inspect crown, blocks, TD, Iron Roughneck, Drawworks, Brake linkage, and Drive line. Check fluids in floor motor, Drawworks, Chaincase, and TD. Inspect saver sub. Clean suction screens. Static loss rate: 1.38bph Trip in hole F/ 2693' - T/ 3634' washing down last stand T/ 3694' with no issues or tight spots. No loss on trip in. P/U 95K, S/O 75K. Pump 20bbl hi vis sweep wtih walnut and condet. 415gpm = 1162psi, 60RPM = 5-6KFt-lbs TQ. Distance from plan is 1.35’ (1.24' High, .53' Right) Report Number 10 Report Start Date 11/17/2024 Report End Date 11/18/2024 Operation Cont to circ hi-vis nutplug sweep OOH at 411 gpm-1154 psi, 60 rpm-6000 ft/lbs off bott torque. Sweep back on time with 15% increase in fine sand and clay. Cont drilling 9 7/8" hole from 3694' md/3504' tvd, to 3918' md/3713' tvd. Rot wob 4-6K, 394 gpm-1229 psi, 60 rpm-7300 ft/lbs on bott torque, 108 to 120 ft/hr ROP. Sliding wob 4K, 350 gpm-1110 psi, 230 psi diff, 80 ft/hr ROP. MW 9.0/vis 56, ECD 9.2 ppg, BGG 26 units, max gas 187 units. At 3566' tvd we reduced drilling parameters in anticipation of losses encountered at 3669' tvd on KU 41-08. Reduced to 350 gpm-40 ft/hr ROP for the upcoming Pool 4 at 3771' tvd. No losses thus far. Cont drilling from 3918' md/3713' tvd to 4068' md/3855' tvd. Rot wob 2-5K, 350 gpm-990 psi, 60 rpm-7000 ft/lbs on bott torque, 40 ft/hr ROP. Sliding wob 3K, 350 gpm-974 psi, 150 psi diff, 50 ft/hr ROP. MW 9.0/ vis 61, ECD 9.2+ ppg, BGG 15, max gas 127 units. No losses thus far. At 17:00 hrs, at 4067', Pason went down. PU 20' and cont circ and rotate while tech remotely troubleshoots. Troubleshoot Pason issue with technician. Re-program system and bring back online. Drill 9-7/8" Intermediate section F/ 4068' - T/ 4259' (4055' TVD), Total: 191' (AROP: 35fph). 350GPM = 989/931psi on/off, 60RPM = 7.5/6.8Kft-lbs on/off TQ with 3K WOB, ECD = 9.28ppg with 9.05ppg in/out MW (60vis), Max Gas = 32u. P/U 105K, S/O 83K, ROT 94K. Obtain SPR's at 4196' MD with 9.05ppg MW (3972' TVD). Backreaming 30' prior to connections and mad passing any slides over 20'. Drill 9-7/8" Intermediate section F/ 4259' - T/ 4448' (4240' TVD), Total: 221' (AROP: 37fph). 350GPM = 1065/945psi on/off, 60RPM = 7.2/6.9Kft-lbs on/off TQ with 3-5K WOB, ECD = 9.29ppg with 9.05ppg in/out MW (59vis), Max Gas = 91u. P/U 112K, S/O 83K, ROT 95K. Backreaming 30' prior to connections and mad passing any slides over 20'. Distance from plan is 3.14’ (3.09' Low, .56' Left) Report Number 11 Report Start Date 11/18/2024 Report End Date 11/19/2024 Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 Page 4/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Cont drilling 9 7/8" hole from 4448' to 4666'. Rot wob 1-6K, 350 gpm-1036 psi, 60 rpm-7500 to 8400ft/lbs on bott torque, 40 ft/hr ROP. Sliding wob 1-4K, 350 gpm-1074 psi, 108 psi diff, 58 ft/hr ROP. MW 9.0+/vis 61, ECD 9.3 ppg, BGG 17 units, max gas 103 units. Drill 9-7/8" Intermediate section F/ 4666' - T/ 4948' (4669' TVD), Total: 282' (AROP: 32fph). 350GPM = 1090/999psi on/off, 60RPM = 8.1/7.5Kft-lbs on/off TQ with 3K WOB, ECD = 9.32ppg with 9.1ppg in/out MW (58vis), Max Gas = 30u. P/U 120K, S/O 88K, ROT 103K. Backreaming 30' prior to connections and mad passing any slides over 20'. Obtain survey. CBU while rot/recip. 350gpm = 1093psi, 80RPM = 7-8KFt-lbs TQ. Obtain SPR's at 4948' MD with 9.1ppg MW (4669' TVD). Flow check for 10 min observing slight seepage loss. POOH F/ 4948' - T/ 1627' with no issues or tight spots. Observed 10K bobble when motor/bit entered shoe. 6.58bbl loss for trip. P/U 83K, S/O 60K. Grease and inspect crown, blocks, TD, Iron Roughneck, Drawworks, Brake Linkage, and Drive Line. Check all fluid levels in equipment. C/O Saver sub. Clean suction screens on both MP's. RIH on elevators F/ 1627' setting down 15K at 4881' then washed down T/ 4948'. Filled pipe every 1500'. No bobble exiting the shoe. No issues or tight spots on trip in hole. 1.4bbl loss for trip. P/U 120K, S/O 80K. Pump 40bbl hI-vis sweep with walnut. 360gpm = 1125psi, 80RPM = 8-9KFt-lbs TQ. Distance from plan is 7.84’ (1.52' High, 7.69' Right) Report Number 12 Report Start Date 11/19/2024 Report End Date 11/20/2024 Operation Cont circ 40 bbl hi-vis nutplug sweep around, max gas at bottoms up 50 units, sweep back on time with a 50% increase in fine sand and clay. Cont drilling 9 7/8" hole from 4948' md/4669' tvd to 5134' md/4840' tvd. Rot wob 2-3K, 375 gpm-1279 psi, 50 rpm-8250 ft/lbs on bott torque, 40 ft/hr ROP. Sliding wob 4-5K, 375 gpm-1388 psi, 170 psi diff, 55 ft/hr ROP. MW 9.1/vis 64, ECD 9.3 ppg, BGG 20 units, max gas 100 units. Drilled from 5134' md/4840' tvd to 5333' md/5025' tvd. Rot wob 2-3K, 430 gpm-1656 psi, 60 rpm-9000 ft/lbs on bott torque, 50 ft/hr ROP. MW 9.2/vis 56, ECD 9.4 ppg, BGG 32 units, max gas 213 units. Strapped 7 5/8" casing, received lead cement in silo. Cont. drilling 9-7/8" intermediate section F/5333'-T/5576', stagging up drilling parameters as we get further away from thief zones. P/U-127K S/O-97K ROT-110K GPM-430 SPP-1584 psi RPM-60 TQ-9.1K Diff-155 psi WOB-4K Flow-32% ROP-60 MW-9.2 ppg ECD-9.47 ppg Mas gas-165 units. Crew change, held PTSM. Cont. drilling 9-7/8" intermediate section F/5576'-T/5701'. P/U-134K S/O-95K ROT-112K GPM-430 SPP-1799 psi RPM-60 TQ-9.5K Diff-152 psi WOB-4K Flow-32% ROP-70 MW-9.2 ppg ECD-9.5 ppg Mas gas-490 units. Distance to well plan: 7.05' 6.44' High 2.88' Right. CBU, shot on bottom survey, obtained new set of SPR's, and flow checked well (slight seepage). GPM-427 SPP-1594 psi RPM-60 TQ-8K Flow-32% MW-9.2 ppg ECD-9.49 ppg Mas gas-327 units. Pulled wiper trip F/5701'-T/4761' with no issues. P/U-140K S/O-100K Serviced rig- Inspected & greased crown, blocks, TD, wash pipe, IR, DWKS, brake linkage, and drive shaft. Inspected saver sub and cleaned suction screens on MP's. Replaced O-ring on 2" connection on service loop stand pipe. RIH on elevators F/4822' to current depth of 5095'. P/U-110K S/O-85K. Report Number 13 Report Start Date 11/20/2024 Report End Date 11/21/2024 Operation Cont TIH from 5095' to 5636', MU topdrive on last stand, filled pipe, washed/reamed down to bottom at 5701'. Pumped a 40 bbl hi-vis nutplug sweep around at 430 gpm-1612 psi, 80 rpm-8560 ft/lbs off bott torque. Max gas at bottoms up 158 units and significant cuttings along with that. Sweep back 5.7 bbls early with 50% increase in cuttings. Cont to circ until shakers cleaned up. Cont drilling from 5701' md/5367' tvd to 5950' md/5599' tvd. Rot wob 4 to 6K, 440 gpm-1750 psi, 70 rpm-9350 ft/lbs on bott torque, 80 ft/hr ROP. Sliding wob 3 to 8K, 430 gpm-1650 psi, 69 psi diff, 20 to 50 ft/hr ROP. MW 9.2+/vis 59, ECD 9.5 ppg, BGG 62 units, max gas 650 units. Cont drilling from 5950' to TD at 6306' md/5927' tvd. Rot wob 5-6K, 440 gpm-1868 psi, 70 rpm-10,200 ft/lbs on bott torque, 80 ft/hr ROP. Sliding wob 6-7K, 433 gpm-1800 psi, 180 psi diff, 80 ft/hr ROP. MW 9.3+/vis 54, ECD 9.6 ppg, BGG 89 units, max gas 703 units. Distance to well plan: 8.12' 7.66' High 2.71' Left. CBU at 432 gpm-1556 psi, 80 rpm-9100 ft/lbs off bott torque. Higher background gas so circ and increase MW to 9.4+ in/out. Shot on bottom survey, obtained new SPR's, flow checked well (slight seepage). POOH F/6306'-T/5760' worked through 30K over pulls on elevators at 5977' & 5759'. At 5727', unable to work though tight spot on elevators. M/U TDS, broke circ. Stagged up MP's. Washed/reamed F/5760'-T/5700', cleaning up tight spot. CBU. P/U- 139K S/O-99K ROT-122K GPM-430 SPP-1569 psi RPM-80 TQ-9K MW-9.45 ppg ECD-9.64 ppg Max gas- 57 units. Cont. pulling wiper trip F/5700'-T/5200', worked through two 30K over pulls at 5604' & 5518' (cleaned up). P/U-140K S/O-98K Caloculated hole fill- 6.9 bbls Act- 7.65 bbls Diff-.75 bbls over. Serviced rig while monitoring hole on TT. Inspected & grased crown, blocks, TD, wash pipe, IR, DWKS, brake linkage, and drive shaft. Inspected saver-sub. Static loss rate= 1.5 bph. TIH F/5200'-T/6266' with no issues. M/U TDS, filled pipe, broke cic. Stagged up MP's. Washed last std, to bottom with no fill. P/U-150K S/O-100K Calculated pipe displacement- 19.52 bbls Act- 17.7 bbls Diff-1.82 bbls lost to hole. CBU. P/U-150K S/O-100K ROT-120K GPM-437 SPP-1695 psi RPM-80 TQ-9.4K Flow-33% MW-9.45 ppg ECD-9.63 ppg Max gas- 206 units. Pumped 40 bbl Hi-Vis sweep. hole unloaded on BU, sweep back 11.5 bbls early, with a 50% increase in cuttings. Flow checked (slight seepage). POOH F/6306' with no issues. P/U-152K S/O-98K. Report Number 14 Report Start Date 11/21/2024 Report End Date 11/22/2024 Operation Cont POOH from 3197' to surface casing shoe, parked string at 1631', up wt 90K, flow checked. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 Page 5/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Hung blocks/topdrive, slipped and cut 62' drill line, spooled up drum, secured deadman, calibrated block height/hookload. Cont POOH from 1631' to BHA at 689'. Racked back HWDP, L/D jars, held PJSM and removed sources, plugged in and downloaded MWD data (twice due to download issue), L/D smart tools, drained and flushed motor, broke off bit and L/D same. Bit graded 1-3-BT-G-X-1-WT-TD. Cleaned and cleared rig floor/catwalk, drained BOP stack, removed wear ring, set test plug, de-energized koomey unit, opened upper doors and swapped upper rams to 7 5/8", buttoned up doors, set 7 5/8" test jnt and RU test equipment. Shell tested stack, tested annular at 250 low/2500 high 5 min each, tested upper rams at 250 low/3500 high 5 min each. RD test equipment, L/D test plug and test jnt. PU and dummy ran hanger (19.33' RKB), L/D same. RU elevators and casing tongs, fill up line, staged centralizers. Staged casing and held PJSM. M/U 7-5/8" shoe track, tested floats (ok). Resumed running 7-5/8" 29.7# GB CD-BTC P110 casing at 20 fpm. Filling on the fly and topping off every ten jts. F/86.65'-T/1636' M/U XO, broke circ. Stagged up MP. Circulated string volume to condition mud. Obtain rotary parameter @ 10 rpm- 4K 20 rpm- 4.3K 30 rpm- 4.6K. B/O XO and blew down TDS. P/U-55K S/O-52K GPM-255 SPP-67 MW-9.5 ppg Max gas-2 units. Crew change, held PTSM. Cont. running 7-5/8" casing F/1636'-T/4016' at 20 fpm. P/U-125K S/O-95K M/U XO, broke circ. Stagged up MP. Circulated string volume to condition mud. B/O XO and blew down TDS. Gave cementers 4 hr. notice. P/U-125K S/O-95K GPM-255 SPP-156 Flow-21% MW-9.5 ppg Max gas-21 units. Report Number 15 Report Start Date 11/22/2024 Report End Date 11/23/2024 Operation Cont PU single in hole with 7 5/8" GB CD BTC 29.70# P-110 intermediate casing, torqued 13,000 to 15,000 ft/lbs, from 4016' to 6189', filling on the fly, topping off every 10 jnts, 20 to 30 ft/min. On jnt 152 (2nd to last jnt) set down over 20K. PU with no issue at 210K. L/D jnt 152 and installed circ swedge in top, PU and MU, MU topdrive and broke circ at 156 gpm-276 psi. Started washing down, dwn wt 130K, increasing pump rate to 175 gpm-380 psi. Initially taking 2' bites but pump pressure increased and flow dropped off, PU and start washing down inches at a time to 6235'. Able to reciprocate with no issue. Installed circ swedge in last jnt in string, cont washing down much better to 6276'. PU extra joint with circ swedge, MU topdrive, washed down and tagged bottom at 6305' as per casing tally. Up wt 220K, dwn wt 125K. Shut down pump, L/D extra joint, could not remove circ swedge (to tight), had to PU joint and re-break circ swedge with topdrive, L/D joint again, installed circ swedge in landing jnt, MU same with topdrive, washed down and landed hanger on seat with no issue. 153 gpm-226 psi. PU 2' and parked string. CBU with hanger 2' off seat, occasional land and PU (11" hanger snags in stack, cannot work string more than 2'). 210 gpm-223 psi, RD casing equipment, staged plug launcher and HP hose on rig floor. Held PJSM with Fox Energy crew and rig team. Shut down pump, broke off topdrive and blew down, loaded plugs in launcher. MU plug launcher XO bowl, inserted bottom plug, MU plug launcher loaded with top plug, and hardline, Fox loaded lines with 10 b bls water and checked for leaks. Fox pressure tested lines at 1200 low 2500 high, good tests. Fox pumped 63 bbls 10.5 ppg FMP300 Spacer at 3.5 bpm 110-90 psi, followed with 248 bbls (709 sx) 12.5 ppg Class G lead cement at 4 bpm 40 - 0 psi, followed by 31 bbls (140 sx) 15.3 ppg Class G tail cement at 1.5 bpm 0 - 0 psi. Fox dropped top plug, then displaced with 9.5 ppg 6% KCL PHPA mud at 5 bpm 0 - 930 psi. Slowed pump to 2 bpm 870 psi, with 10 bbls to go. Did not bump the plug, Pumped calculated displacement 285 bbls, pumped half the shoe track for an additional 2 bbls (no bump) Held 750 psi (FCP of 750 psi) for 3 minutes, bled back 1 bbls to truck, floats held. CIP at 20:18 on 11-22-24. Had 63 bbls of Spacer returns to surface and 20 bbls lead cement to surface. Added LCM to lead cement at .5 ppb. Mix water temp 73 deg. Pumped 40% excess on lead. Lost 11.8 bbls throughout the job. Did not reciprocate casing. P/U-198K / S/O-136K Washed up & R/D Fox cmt head and cmt equip. Released cementers. R/D bail extensions. B/O LJ, flushed stack, LJ, and top of hanger, L/D LJ. M/U pack off too running tool. Set pack off as per WHR, tested pack off T/5000 psi for 10 min (ok). Cleaned out flow box, P/U Johnny Whacker tool & flushed stack, L/D same. Set test plug. Cleaned & cleared rig floor. Crew change, held PTSM. De-energized koomey, removed 7-5/8" rams in UPR, pressure washed ram cavities & inspected. Installed VBR's. Buttoned up ram doors, re-energized koomey. Changed out leaking IBOP on TDS. Flooded stack, mud lines, and CM with water, funtioned BOP components to work out air. R/U testing equip. Flooded stack, mud lines, and CM with water, funtioned BOP components and purged out air. Performed shell test - 250 Low/3500 High 5/5 min. Working on weighted out active mud system to 9.8 ppg. Cont. testing BOP's as per AOGCC regulations on 4.5" & 3.5" jt. Test witnessed by state rep Bob Noble. Working on weighting up active mud system to 9.8 ppg. Report Number 16 Report Start Date 11/23/2024 Report End Date 11/24/2024 Operation Cont testing BOPE at 250/3500 psi (250/2500 on annular w/3 1/2" test jnt) for 5 min each and AOGCC Rep witnessing. Had F/P on meth sensor visual alarm. C/O sensor, calibrated and tested ok. F/P on annular high test wih 3 1/2" test jnt. Tested early to allow for completion of drilling well before initial due date. RD test equipment and LD test plug, spotted YJ e-line and RU same for bond log. YJ RIH and tagged up at 6186' (FC at 6212'). Logged OOH, RD and released YJ. Set 7" ID wear ring, RU test equipment, flooded and purged, pumped 3.28 bbls to achieve 3533 psi on 7 5/8" casing, held 30 minutes on chart, lost 204 psi. Bled off and recovered all 3.28 bbls. C/O chart sensor and attempted to re-test, found blind ram shaft seal leaking on offside. Bled off, blew down, called out rig mechanic for seal change. De-energize koomey unit, open blind ram door, replaced ram shaft seals with same. Buttoned up ram doors. Pulled wear ring. set test plug/test jt. Flooded stack, mud lines, and CM. Purged out air. Performed shell test (ok). B/U test jt. Tested blid rams (ok). Pulled test plug and installed wear ring. Retested 7-5/8" intermediate casing T/3500 psi for 30 min with no luck. Discussed options with engineer, decision was made to P/U enough 4.5” DP to TD well, while resourcing a 7-5/8” RTTS/storm packer. R/D testing equip. P/U & singling in the hole with 4.5” DP while resourcing 7-5/8” RTTS/storm packer at report time. Report Number 17 Report Start Date 11/24/2024 Report End Date 11/25/2024 Operation Cont PU single in hole with 4 1/2" DP from 408' to 2076', total 66 jnts. POOH rack back 33 stands and L/D diffuser. Service rig and topdrive. MU XO and Tri-Point JS3 test packer on stand of HWDP, cont TIH on HWDP to 502'. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 p found blind ram shaft seal leaking on offside testing BOP's as per AOGCC regulations on 4.5" & 3.5" jt. Test witnessed by state rep Bob Noble. Working pp Did not bump the plug, p Lost 11.8 bbls throughout the job. 248 bbls (709 sx) 12.5 ppgpg,gpp ppgp Class G lead cement at 4 bpm 40 - 0 psi, followed by 31 bbls (140 sx) 15.3 ppg Class G tail cement Retested 7-5/8" intermediate casing T/3500 psi for 30 min with no luck (p) p( 20 bbls lead cement to surface Page 6/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Cont TIH slow from 502' to 6083', no sign of cement stringers, up wt 143K, dwn wt 93K, MU topdrive. Circulated surface to surface to condition mud and remove any air from wellbore. Pumped at 3 bpm-292 psi. RU test equipment for casing test. Set test packer as per Tri-Point Rep at 6088'. Tie test pump in to mezz kill, fluid packed and purged air in surface equipment. Closed upper rams. Tested 7-5/8" casing above packer T/3500 psi on a chart for 30 min (good test). Pumped in 2.3 bbls Bled back 2.3 bbls. B/D & R/D testing equip. Realeased Tri-Point packer. Flow checked well (static). POOH F/6088'-T/1581'. P/U-142K S/O-93K Crew change, held PTSM and weekly safety meeting with rig crew. Cont. POOH F/1581' to surface, Inspected & L/D Tri-Point JS3 packer tool (ok). Cleaned & cleared rig floor. Strapped & tallied 56 jts of CDS-40 on the catwalk racks. Static loss rate- 0 bph. held PJSM on M/U BHA. P/U & M/U 6.75" 5 bladed PDC bit to mud motor, scribed for off set = 169.89°. M/U MWD tools. Uploaded MWD data. Performed shallow pulse test (ok). Held PJSM on sources, loaded sources. P/U jar std. Report Number 18 Report Start Date 11/25/2024 Report End Date 11/26/2024 Operation Cont RIH with BHA #3 on HWDP to 677'. Cont PU single in hole with 4 1/2" DP from 677' to 4755' filling pipe every 1500', then TIH on stands to 6180' tagging top wipe r plug. PU 10' and MU topdrive. Up wt 140K, dwn wt 87K. Filled pipe, circ at 200 gpm-1181 psi, 30 rpm-8411 ft/lbs off bott torque, eased down and tagged wiper plug, drilled on plug seeing rubber on shakers at 1960 strokes. Plug gave way, started chasing plug with no wob to 6213' (top of FC). Drilled wiper plugs and FC with 1-7K wob, had little to no wob through shoe track to shoe, drilled through shoe, rathole cement to 6306', 20' new formation to 6326', rot wob 3-4K, 201 gpm-1437 psi, 30 rpm-9400 ft/lbs on bott torque. MW 9.8/vis 60, ECD 10.4 ppg, BGG 17 units, max gas 77 units. CBU at 251 gpm-1592 psi, 30 rpm-8910 ft/lbs off bott torque, keeping bit out of rathole and casing shoe. Up wt 125K. Racked back one stand, up wt 155K with no pump, parked at 6287', RU test equipment on stump and mezz kill, flooded and purged, closed upper rams and flooded choke manifold. Pumped 44.85 gallons down drill string and backside simultaneously to achieve 1204 psi, held 10 minutes, psi dropped to 1043, bled back 37.5 gallons. Sent data to town, approved to drill ahead. Called LOT at 1158 psi for an EMW of 13.56 ppg. RD test equipment, flushed and blew down, opened upper rams. RIH one stand. Resumed directional drilling 6 3/4" hole F/6326'-T/6484'. P/U-150K S/O-95K ROT-115K GPM-280 SPP-2209 psi RPM-40 TQ-9.8K WOB-6K Diff-220 psi Flow-24% MW-9.95 ppg ECD-11.0 ppg Max gas- 95 units. Cont. increasing MW as per program. Crew change, held PTSM. Cont. directional drilling 6 3/4" hole F/6484' to current depth of 6762'. P/U-155K S/O-100K ROT-120K GPM-273 SPP-2283 psi RPM-60 TQ-9.9K WOB-7K Diff-335 psi Flow-24% MW-10.3 ppg ECD-11.44 ppg Max gas- 194 units. Cont. increasing MW as per weight up schedule. Distance to well plan: 6.69' 3.41' High 5.76' left Report Number 19 Report Start Date 11/26/2024 Report End Date 11/27/2024 Operation Drill Ahead 6 3/4' Hole Section f/ 6762' t/ 7327' 273 gpm 2705 psi 70 rpm 10 k torque on bottom, 7k WOB, 212 units MW 10.7 ppg ECD 12.45 ppg,160k PUW 100k SOW 117k ROT Circulate bottoms up, Obtain survey and SPR's, Flow check well static slight loss, blow down top drive POOH f/ 7327' t/ 6324', Observed 5-25k over pulls/grag most of the trip out, was able to work through without pumps. Service rig and top drive, clean suctions screens on pumps, grease crown and blocks, inspect draw works and brake linkage Static loss rate- .25 bph. RIH on elevators F/6324'-T/7265', cont to see drag 20/25K. Filled pipe, broke circ. Washed to bottom with no fill. CBU, hole unloaded. Made hook and pumped 20 bbl High Vis sweep. Cont. directional drilling 6.75" production interval F/7329'-T/7598'. Sweep came back 3 bbls early with a 100% increase in cuttings. P/U-162K S/O-96K ROT-123K GPM-280 SPP-2755 psi RPM-60 TQ-105K WOB-8K Diff-322 psi Flow-23% MW-10.75 ppg ECD-11.96 ppg Max gas- 432 units. Cont. increasing MW as per program. Crew change, held PTSM. Resumed directional drilling 6.75" production interval F/7598' to current depth 7952'. Pumped sweep at 7832', sweep came back 11 bbls early with a 50% increase in cuttings. Obtained SPR's. Brought lube concentration up to 1% by volume in mud system. P/U-170K S/O-100K ROT-125K GPM-277 SPP-2747 psi RPM-60 TQ-10.2K WOB-8K Diff-360 psi Flow-23% MW-10.85 ppg ECD-12.41 ppg Max gas- 394 units. Cont. increasing MW as per program. Distance to well plan: 9.87' 5.15' Low 8.42' Left Report Number 20 Report Start Date 11/27/2024 Report End Date 11/28/2024 Operation Continue Drilling 6 3/4'' Hole Section f/ 7952' t/ 8332' 270 gpm 2876'psi 70 rpm 11k tq on bottom, 8k WOB, 640 max units of gas, 175k PUW 100k SOW 125k ROT pumped hi Vs Sweep @7832 back 2900 strokes early and 50% increase in cuttings. Circulate bottoms up, obtain survey and SPR's , Flow check well static POOH on elevators f/ 8332' t/ 7947' unable to work through overpull, BROOH f/ 7947' t/ 7261' Service rig and top drive, grease blocks and crown, clean suction screens, inspect draw works and brake linkage. RIH f/ 7261' t/ 8332' wash last stand to bottom, no issues, pumped Hi Vis Sweep resumed Drilling. Cont. directional drilling 6.75" production interval F/8332'-T/8771'. Sweep came back 11 bbls early with a 40% increase in cutt ings. P/U-180K S/O-108K ROT-134K GPM-282 SPP-2974 psi RPM-65 TQ-11.6K WOB-9K Diff-268 psi Flow-22% MW-11.0 ppg ECD-12.4 ppg Max gas- 813 units. Cont. increasing MW as per program. Crew change, held PTSM. Resumed directional drilling 6.75" production interval F/8771' to current depth 9337'. Pumped sweep at 8832', sweep came back 17 bbls early with a 80% increase in cuttings. Obtained SPR's. P/U-184K S/O-109K ROT-134K GPM-271 SPP-2840 psi RPM-65 TQ-12K WOB-9K Diff-375 psi Flow-22% MW-11 ppg ECD-12.55 ppg Max gas-2147 units. Cont. increasing MW as per program. Distance to well plan: 7.90' 4.55' Low 6.45' Left Report Number 21 Report Start Date 11/28/2024 Report End Date 11/29/2024 Operation Continue Drilling 6 3/4'' Hole Section f/ 9037' t/ 9333' 270 gpm 2900 psi 60 rpm 12.7k tq on bottom, 8k WOB 535 units, 190k PUW 114k SOW 139K ROT Circulate bottoms up obtain survey and SPR's, FLow Check well static. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 Tested 7-5/8" casing above packer T/3500 psi on a chart for 30 minp (good test). Called LOT at 1158 psi for an EMW of 13.56 ppg ,p pp,p , qp p Pumped 44.85 gallons down drill string and backside simultaneously to achieve 1204 psi, gy Page 7/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation POOH f/ 9333' t/ 7266' unable to work through tight spot, BROOH f/ 7266' t/ 6265' Service rig and top drive. Static loss rate- 1.6 bph. RIH on elevators F/6265'-T/8822', worked through multiple tight spots on elevators F/8007'-T/8822'. Unable to work through tight spot at 8822'. P/U-145K S/O-94K. Cal. pipe displacement- 48.8 bbls Act- 48.14 bbls Diff- .66 bbl loss. M/U TDS, filled pipe, broke circ. Washed/Reamed F/8822'-T/8868', cleaning up tight spot. Circ. STS, hole unloaded at BU with a max gas of 2622 units. GPM-280 SPP-2407 psi RPM-60 TQ-12.3K MW-11.2 ppg ECD-12.31 ppg. Cont. to wash/ream F/8868' to bottom at 9333', taken check shot surveys every 2 stds. GPM- 275 SPP-2681 psi RPM-60 TQ-12.2K MW-11.2 ppg ECD-12.49 ppg Max gas- 991 units. CBU with max gas of 730 units. Pumped 20 bbls Hi-Vis sweep with walnut & condet, sweep came back 9 bbls late with a 15% increase in cuttings. P/U-207K S/O-115K ROT-135K GPM-266 SPP-2504 psi RPM-80 TQ-12.6K MW- 11.2 ppg ECD- 12.46 ppg Resumed directional drilling 6.75" production interval F/9333' to current depth 9475'. P/U-197K S/O-113K ROT-141K GPM-282 SPP-2933 psi RPM-65 TQ-12.5K WOB-11K Diff-357 psi Flow-23% MW-11.3 ppg ECD-12.52 ppg Max gas- 232 units. Cont. increasing MW as per program. Distance to well plan: 9.52' .82' Low .64' Left Report Number 22 Report Start Date 11/29/2024 Report End Date 11/30/2024 Operation Continue Drilling 6 3/4'' Hole Section f/ 9475' t/ 9773' 280 gpm 3096 psi 60 rpm 14k torque on bottom, 6k WOB, MW 11.4 ppg, 200k PUW 120k SOW 148k ROT Change out swivel packing. Drill 6 3/4'' Hole Section f/ 9773' t/ 9898' 290 gpm 3130 psi 60 RPM 14k tq on bottom, 8k WOB, 200k PUW 125k SOW 168k ROT MW 11.4 ppg ECD 12.57 ppg Cont drilling 6.75" production interval F/9898'-T/10,164'. P/U-205K S/O-122K ROT-155K GPM-280 SPP-3185 psi RPM-60 TQ-4.4K WOB-7K Diff-349 psi Flow-24% MW-11.5 ppg ECD-12.7 ppg Max gas- 1077 units. Crew change, held PTSM. Cont. drilling 6.75" production interval F/10,164' to current depth of 10,388'. Bumped up lube concentration to 2% by volume in mud system to reduce torque. P/U-208K S/O-125K ROT-155K GPM-291 SPP-3192 psi RPM-60 TQ-13.9K WOB-11K Diff-300 psi Flow-24% MW-11.5 ppg ECD-12.78 ppg Max gas- 135 units. Distance to well plan: 42.47' 30.54' Low 29.51' Left Report Number 23 Report Start Date 11/30/2024 Report End Date 12/1/2024 Operation Continue Dirll 6 3/4'' Hole Section f/ 10388' t/ TD @ 10437' 280 gpm 3200 psi 60 rpm 14.5k torque on bottom, 9k WOB 205k PUW 125k SOW 155k ROT. Distance to well plan: 59.84' 40.48' Low 44.07 Left Circulate bottoms up, obtain final survey and SPR's, flow check well static POOH on elevators f/ 10437' t/ 10317' 25-35k overpulls unable to work through BROOH f/ 103117' t/ 9330' Service rig and top drive, grease blocks and crown, clean suction screens on mud pumps RIH f/ 9330' t/ 10437' wash last stand to bottom Pump 20 bbls Hi Vis Sweep around 280 gpm 2978 psi, sweep back 7 bbls early 25% increase in cuttings POOH on elevators f/ 10437' t/ 6262', racking back stds. in the derrick with no issuse. P/U-220K S/O-140K Calculated hole fill-29.9 bbls Act-33.92 bbls Diff-4.02 bbls over. Performed 10 min flow check (slight seepage). Pumped 15 bbl slug, 2 lbs over MW. POOH, L/D 4.5" DP F/6262'-T/4583', using good pipe handling practices, with calculated hole fill. Crew change, held PTSM. Cont. POOH L/D 4.5" DP, using good pipe handling practices. Report Number 24 Report Start Date 12/1/2024 Report End Date 12/2/2024 Operation Continue POOH L/D DP cleaning threads and redoping, flushing water and sucking wiper balls through pipe. L/D HWDP and Collars, unload sources and down load mwd, L/D BHA as per DD/MWD Bit Graded 1-1 in gauge Clean and Clear Floor Service rig and top drive, grease blocks and crown,clean suction screens M/U Round nose guide shoe, RIH w/ 4.5'' DP from derrick t/ 4210', L/D same using good pipe handling practices. P/U-72K S/O-67K L/D diffuser, drained stack, M/U wear ring puller/test plug, pulled wear ring and L/D same. M/U well head brushing tool, brushed wellhead and L/D same. Hoisted TRS power tongs to rig floor and R/U. Loaded out racks with 3.5" tubing. M/U XO to FOSV. R/U fill up line. Held PJSM. Currently M/U 3.5” production string shoe track. Report Number 25 Report Start Date 12/2/2024 Report End Date 12/3/2024 Operation Check floats good, Continue RIH w/ 3.5'' Long string completion t/ 6298' filling pipe on the fly topping off every 10 jts. Circulate bottoms up 4 bpm 615 psi Max gas observed 3000 units, MW dropped to 11.35 ppg, dusted back up with bar all mud pumped downhole stayed 11.5 ppg. Continue RIH f/ 6298' t/ 8242' filling jts on th fly topping off every 10 jts. P/U-60K S/O-54K M/U XO to stump, broke circ. CBU x2, stagging up MP. GPM-255 SPP-1320 psi Flow-22% MW-11.5 ppg Max gas- 3259 units. Resumed running 3.5" production string as per run tally F/8242'-T/10,400'. M/U XO to tag jt. Washed down F/10,400'-T/10,429'. Circ. & conditioned mud while R/U Fox energy cementer, stagging up MP. P/U-98K S/O-67K GPM-228 SPP-1402 psi Flow-20% MW-11.55 ppg Max gas- 2940 units. Held PJSM on cmt job. L/D tag jt. Blew down TDS, changed out elevators, P/U & M/U hanger & LJ. Attempted to drain stack. IA valve was packed off with debris. Removed VR plug from opposite side of B section. Flushed & blew out IA valves, got the stack to drain. Landed hanger on seat, tested hanger seals (ok). locked in hanger and pull tested (ok). M/U cmt head. Circ. through cmt head, taking returns out IA valve to shaker. Shut down MP, M/U 1502' hose to both IA outlets. Resumed circulating, staging up MP. GPM-184 SPP-1248 psi. Shut down MP. Currently R/U lines to cementers and prepping to pump cmt job. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 Page 8/8 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Well Operations Summary Report Number 26 Report Start Date 12/3/2024 Report End Date 12/4/2024 Operation Break Circulation down hole, Shut in head and PT lines t/ 4510 psi, Pump 30 bbls of 12 ppg spacer 4 bpm 120 psi, pump 245 bbls of 12.5 ppg lead 4.5 bbpm 650 psi, Pump 24 bbls 15.3 ppg lead cement, wash over top of plug, kick out plug and displace with 91.5 bbls of mud, FCP 1450 psi pressure up 400 psi over FCP t/ 1850 psi, bleed off and check floats .5 bbl bled back CIP 0845 hrs no losses through out job R/D cementers and flush through lines, Set check valve as per Vault rep, clean pit and mix up baraclean pill M/U stack washer assembly pump through lines and choke manifold, flush pumps. Open ram doors and clean and inspect rams, grease and close up ram doors, N/D flow box and riser, remove flow line, Go through MP #1 & #2. Finish R/D Gen #3. Installed trolly beam. Remove BOP. Installed dry hole tree. Tested void and Master valve to 5000pis/10min- good test. Clean cellar. Flushed lines in pits. Cleaned Pits 1-8. Open up vacuum degassed, cleaned out and resealed. Removed accumulator line from Koomey room. Started to R/D topdrive. Change oil in gear box and swivel on top drive. Remove save sub. Clean derrick and to dirve. Finish cleaning pit #1. Flush out MP suction lines. Start unplugging electircal to pits and pumps. Dress down racking board to lower derrick. Lay out top drive and torque bushing. Test IA and Tubing to 3500 psi f/ 30 min each, tubing test good IA test failed, RD test equipment secure well. Field: Kenai Gas Field (KEU KGF) Sundry #: 224126 State: ALASKA Rig/Service: HEC 169 gp pggg Test IA and Tubing to 3500 psi f/ 30 min each, tubing test good IAp test failed hrs no losses through out job pump 245 bbls of 12.5 ppg lead 4.5 bbpm 650 psi,,p, p ppg p p Pump 24 bbls 15.3 ppg lead cement, wash over top of plug, kick out plug and displace with 91.5 bbls of mud,pg,pg p Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:12/7/2024 End Date: Report Number 1 Report Start Date 12/7/2024 Report End Date 12/8/2024 Last 24hr Summary PTW/PJSM with AK E-line. MIRU to run Radial Sector CBL/GR/CCL. RIH, tag PBTD at 10357'and log main pass survey to 3000'. POOH, secure well and RDMO E-line. Report Number 2 Report Start Date 12/11/2024 Report End Date 12/12/2024 Last 24hr Summary MIRU HAK hot oil truck and rig up to IA. Pressure test pump lie to IA wing valve 250/4500 psi. Well is fluid packed. Slowly walk pressure up starting at 2000 psi, 3000 psi. Finally walk pressure up to 3500 psi and peform 30 minute recorded pressure test. RDMO. Send digital graphs to town engineers. Good IA PT. Report Number 3 Report Start Date 12/17/2024 Report End Date 12/18/2024 Last 24hr Summary PTW/PJSM. SITP 0 psi. MIRU Fox CT. Troubleshoot issues w/ CT unit. SDFN. Report Number 4 Report Start Date 12/18/2024 Report End Date 12/19/2024 Last 24hr Summary PTW/PJSM. SITP 0 psi. Continue RU Fox CT. Attempt to shell test, but found leaking reel swivel and choke manifold valves. Replace reel swivel, SDFN. Report Number 5 Report Start Date 12/19/2024 Report End Date 12/20/2024 Last 24hr Summary PTW/PJSM. SITP 0 psi. Continue RU Fox CT. Swap out choke manifold. Perform shell test and test BOPE to 250/3500 psi. Perform accumulator drawdown test. All passed. Witness waived by Jim Regg (AOGCC). SDFN. Report Number 6 Report Start Date 12/20/2024 Report End Date 12/21/2024 Last 24hr Summary PTW/PJSM. SITP 0 psi. RU Fox CT. RIH w/ 2.13" nozzle to 5,400' and displace 47 bbls drilling mud w/ N2. Found bad reel swivel and replace. Continue RIH and displace 43 bbls drilling mud w/ N2 and tag PBTD @ 10,333' CTM. Recovered 90 of 90 bbls drilling mud and pumped 242,617 scf (2,606 gals) N2. Left 2560 psi N2 trapped on well. POOH, secure well, and SDFN. Report Number 7 Report Start Date 12/21/2024 Report End Date 12/22/2024 Last 24hr Summary PTW/PJSM. SITP 2540 psi. RDMO Fox CT. MIRU YJ E-line. PT lubricator to 3000 psi - good test. Perforate Tyonek D3C (10,064'-10,078') w/ 2" 6SPF 60DEG guns. Bleed off well pressure @ 5 psi/min and shut in periodically to monitor pressure build. Continue bleeding pressure and RIH w/ GPT. Found fluid level @ ~8,985' and log pass through perfs. POOH and SI well with 500 psi. RIH w/ 14' x 2" 6SPF 60DEG guns and re-perf D3C. POOH and secure well, hand over to production. Report Number 8 Report Start Date 1/3/2025 Report End Date 1/4/2025 Last 24hr Summary PTW / PJSM. MIRU Fox CTU and support equipment. Complete BOPE testing 250 psi low / 3500 psi high. Witness waived by AOGCC Jim Regg on 1/2/25. Report Number 9 Report Start Date 1/4/2025 Report End Date 1/5/2025 Last 24hr Summary PTW/PJSM. WHP = 0 psi. MIRU Fox CTU #10. RIH w/ 2" DJN and dry tagged PBTD @ 10,338' CTM (STS Volume = 97 bbls). Circulated 115 bbls of hot FW down coil, taking returns up CTBS. Recovered sample of drilling mud on leading edge of fluid returns. MIRU Fox N2 pump and blow well dry w/N2 1500 scf/min. Recovered 105 bbls. Pumped 125,510 scf (1,348 gals) N2. POOH w/BHA. Secure well. SDFN. Report Number 10 Report Start Date 1/5/2025 Report End Date 1/6/2025 Last 24hr Summary PJSM, MIRU YJ Eline, Ran 1 11/16" GPT, SD @ 9890' SD multiple times and moved to 9910'. Sticky pick up. Ran CCL, spangs, 2.50"x6'DD bailer, SD @ 9915' & work to 10349' (no sample) Report Number 11 Report Start Date 1/6/2025 Report End Date 1/7/2025 Last 24hr Summary PTW/PJSM. Ran GPT FL @ 10170', tagged @ 10348'. Reperforated D3C from 10064'-10078' (no pressure change). Turn well over to ops to flow test. Report Number 12 Report Start Date 1/7/2025 Report End Date 1/8/2025 Last 24hr Summary PTW / PJSM w/ YJ E-line. Run GPT w/ fluid sample catcher with well flowing at 36 psi/~800 mcfd. Located fluid level at 10145', below the D2 open perfs at 10064'-10078'. Secure well and rig back E-line. Continue flowing well. Report Number 13 Report Start Date 1/8/2025 Report End Date 1/9/2025 Last 24hr Summary PTW/PJSM w/ YJ E-line. (flowing 900mcf @ 35 psi) Ops choked well back to 100 psi, flowing at 800 mcf. RU on well, PU 2" perf guns on 3 runs and perforate Tyonek D2 sand (9717-9781) RDMO well. Turn over to ops for flow. Report Number 14 Report Start Date 1/14/2025 Report End Date 1/14/2025 Last 24hr Summary Tag fluid level and fill, Run PT Survey Field: Kenai Gas Field (KEU KGF) Sundry #: 324-682 State: ALASKA Rig/Service:Permit to Drill (PTD) #:224-126Permit to Drill (PTD) #:224-126 Wellbore API/UWI:50-133-20730-00-00 PU 2" perf guns on 3 runs and perforate Tyonek D2 sand (9717-9781) Reperforated D3C from 10064'-10078' Perforate Tyonek D3C (10,064'-10,078') w/ 2" 6SPF 60DEG gp p p g Finally walk pressure up to 3500 psi and peform 30 minute recorded pressure test. Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025 WellViewAdmin@hilcorp.com Casing Surface Wellbore Wellbore Name: Original Hole Total Depth of Wellbore (ftKB): 10,437.00 Original KB/RT Elevation (ft): 83.60 RKB to GL (ft): 18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Surface Run Date: 11/12/2024 Set Depth (ftKB): 1,664.68 Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf): 86,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 5.00 Ft/Min (ft/min): 5.55 Run Job: 241-00163 KU 23-07A Drilling, Drilling - Drilling, 11/8/2024 06:00 Set Depth (ftKB): 1,664.68 Set Depth (TVD) (ftKB): 1,619.9 Centralizer Detail: 19 Solid Body Every Other Jnt to 300' 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 Casing Hanger 11 9.95 Cactus 1.12 22.82 21.70 1 Casing Pup Joint 10 3/4 9.95 45.50 L-80 GBCD BTC GB 4.02 26.84 22.82 37 Casing Joints 10 3/4 9.95 45.50 L-80 GBCD BTC GB 1,547.71 1,574.55 26.84 1 Float Collar 10 3/4 BTC Innovex 2.58 1,577.13 1,574.55 2 Casing Joints 10 3/4 9.95 45.50 L-80 BTC GB 84.72 1,661.85 1,577.13 1 Shoe 10 3/4 BTC Innovex 2.83 1,664.68 1,661.85 Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025 WellViewAdmin@hilcorp.com Cement Surface Casing Cement Type Casing Description Surface Casing Cement Cemented String Surface, 1,664.68ftKB Wellbore Original Hole Job 241-00163 KU 23-07A Drilling, Drilling - Drilling, 11/8/2024 06:00 Cementing Start Date 11/12/2024 Cementing End Date 11/13/2024 Top Depth (ftKB) 22.0 Cement Stages Stage Number: 1 Description Surface Casing Cement Top Depth (ftKB) 22.0 Bottom Depth (ftKB) 1,664.8 Top Measurement Method Returns to Surface Pump Start Date 11/12/2024 Cement in Place At 11/13/2024 Final Circulating Pressure (psi) 390.0 Plug Bump Pressure (psi) 940.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 94.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? No Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Spacer FMP300 10.50 65.0 65.0 4 Fox Lead Slurry Lead G 393 2.10 12.50 147.0 147.0 5 Fox Tail Slurry Tail G 351 1.23 15.30 77.0 77.0 2 Fox Displacement Spud Mud 9.00 155.0 151.6 4 Fox Post Job Calculations Subtype Value Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025 WellViewAdmin@hilcorp.com Casing Intermediate Wellbore Wellbore Name: Original Hole Total Depth of Wellbore (ftKB): 10,437.00 Original KB/RT Elevation (ft): 83.60 RKB to GL (ft): 18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Intermediate Run Date: 11/21/2024 Set Depth (ftKB): 6,297.92 Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf): 22,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 19.00 Ft/Min (ft/min): 5.52 Run Job: 241-00163 KU 23-07A Drilling, Drilling - Drilling, 11/8/2024 06:00 Set Depth (ftKB): 6,297.92 Set Depth (TVD) (ftKB): 5,920.9 Centralizer Detail: 131 Solid Body up to 1000' Every Jnt Attribute Subtype: Value: Pipe Reciprocated?: No Pipe Rotated?: No Float Failed?: Yes Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) 1 Casing Hanger 11 6.88 Cactus 1.99 21.32 19.33 151 Casing Joints 7 5/8 6.87 29.70 P-110 GB CD BTC GB CD 6,190.95 6,212.27 21.32 1 Float Collar 8 1/2 BTC IRI 1.40 6,213.67 6,212.27 2 Casing Joints 7 5/8 6.87 29.70 P-110 GB CD BTC GB CD 82.65 6,296.32 6,213.67 1 Float Shoe 8 1/2 BTC IRI 1.60 6,297.92 6,296.32 Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025 WellViewAdmin@hilcorp.com Cement Intermediate Casing Cement Type Casing Description Intermediate Casing Cement Cemented String Intermediate, 6,297.92ftKB Wellbore Original Hole Job 241-00163 KU 23-07A Drilling, Drilling - Drilling, 11/8/2024 06:00 Cementing Start Date 11/22/2024 Cementing End Date 11/22/2024 Top Depth (ftKB) 19.3 Cement Stages Stage Number: 1 Description Intermediate Casing Cement Top Depth (ftKB) 19.3 Bottom Depth (ftKB) 6,297.9 Top Measurement Method Acoustic Log (CBL) Pump Start Date 11/22/2024 Cement in Place At 11/22/2024 Final Circulating Pressure (psi) 750.0 Plug Bump Pressure (psi) Full Return? No Returns During Job (%) 98 Volume to Surface (bbl) 20.0 Volume Lost (bbl) 11.8 Bump Plug? No Float Failed? Yes 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) FMP300 10.50 63.0 63.0 4 Fox Energy Lead Slurry Class G 709 2.10 12.50 248.0 248.0 4 Fox Energy Tail Slurry Class G 140 1.23 15.30 31.0 31.0 2 Fox Energy Displacement 6% KCL PHPA mud 9.50 287.0 285.0 5 Fox Energy Post Job Calculations Subtype Value Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025 WellViewAdmin@hilcorp.com Casing ProdSction Welluore Welluore Name: Original Hole f otal bepth oTWelluore DTtK( B:10,437.00 ) riginal K( /Rf EleOation DTtB:83.60 RK( to v GDTtB:18.00 K( -Casing Llange bistance DTtB: K( -f Suing Fanger bistance DTtB: P( f bs bepthDTtK( B: Casing Casing bescription: Production RSn bate: 12/2/2024 Het bepth DTtK( B:10,423.18 Casing Weight on Hlips D1000luTB:PickUpWeightD1000luTB:98,000.0 ( lock Weight D1000luTB:15,000.0 Make-Up Contractor: Parker Casing NSmuer Frs to RSn DhrB:47.00 Lt/Min DTt/minB:3.70 RSn Jou: 241-00163 KU 23-07A Drilling, Drilling - Drilling, 11/8/2024 06:00 Het bepth DTtK( B:10,423.18 Het bepth DfVbBDTtK( B:9,567.8 Centralizer betail: 138 AttriuSte HSutype: ValSe: Pipe Reciprocated?: No Pipe Rotated?: No Lloat Lailed?: No f est HSutype: PressSre DpsiB: Casing D) r GinerBbetails Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) 1 Casing Hanger 11 6.88 0.80 19.20 18.40 1 Cross Over 3 1/2 2.99 9.20 L-80 IBT 3.76 22.96 19.20 145 Casing Joints 3 1/2 2.99 9.20 L-80 H563 4,536.90 4,559.86 22.96 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 9.99 4,569.85 4,559.86 14 Casing Joints 3 1/2 2.99 9.20 L-80 H563 438.38 5,008.23 4,569.85 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 5,018.23 5,008.23 16 Casing Joints 3 1/2 2.99 9.20 L-80 H563 498.54 5,516.77 5,018.23 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 5,526.77 5,516.77 29 Casing Joints 3 1/2 2.99 9.20 L-80 H563 906.24 6,433.01 5,526.77 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 6,443.01 6,433.01 16 Casing Joints 3 1/2 2.99 9.20 L-80 H563 468.63 6,911.64 6,443.01 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.01 6,921.65 6,911.64 16 Casing Joints 3 1/2 2.99 9.20 L-80 H563 501.50 7,423.15 6,921.65 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 7,433.15 7,423.15 15 Casing Joints 3 1/2 2.99 9.20 L-80 H563 470.30 7,903.45 7,433.15 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.01 7,913.46 7,903.45 16 Casing Joints 3 1/2 2.99 9.20 L-80 H563 497.97 8,411.43 7,913.46 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 8,421.43 8,411.43 16 Casing Joints 3 1/2 2.99 9.20 L-80 H563 499.70 8,921.13 8,421.43 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 8,931.13 8,921.13 16 Casing Joints 3 1/2 2.99 9.20 L-80 H563 497.99 9,429.12 8,931.13 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.01 9,439.13 9,429.12 15 Casing Joints 3 1/2 2.99 9.20 L-80 H563 469.77 9,908.90 9,439.13 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 10.00 9,918.90 9,908.90 13 Casing Joints 3 1/2 2.99 9.20 L-80 H563 407.05 10,325.95 9,918.90 1 Casing Joints 3 1/2 2.99 9.20 L-80 H563 30.90 10,356.85 10,325.95 1 Float Collar 3 1/2 2.99 9.20 L-80 H563 1.67 10,358.52 10,356.85 2 Casing Joints 3 1/2 2.99 9.20 L-80 H563 62.76 10,421.28 10,358.52 1 Float Shoe 3 1/2 2.99 9.20 L-80 H563 1.90 10,423.18 10,421.28 Page 1/1 Well Name: KEU KU 23-07A Report Printed: 1/20/2025 WellViewAdmin@hilcorp.com Cement Liner Cement Type Casing Description Liner Cement Cemented String Production, 10,423.18ftKB Wellbore Original Hole Job 241-00163 KU 23-07A Drilling, Drilling - Drilling, 11/8/2024 06:00 Cementing Start Date 12/3/2024 Cementing End Date 12/3/2024 Top Depth (ftKB) 4,554.0 Cement Stages Stage Number: 1 Description Liner Cement Top Depth (ftKB) 4,554.0 Bottom Depth (ftKB) 10,437.0 Top Measurement Method CBL Pump Start Date 12/3/2024 Cement in Place At 12/3/2024 Final Circulating Pressure (psi) 1,450.0 Plug Bump Pressure (psi) 1,850.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 0.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? No Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer)11.50 30.0 30.0 4 Fox Energy Lead Slurry G 655 2.10 12.50 245.0 245.0 5 Fox Energy Tail Slurry A 109 1.23 15.30 24.0 24.0 2 Fox Energy Displacement 11.50 91.5 11.5 4 Fox Energy Post Job Calculations Subtype Value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(.2 ' ''.; '?)4@A"@) @ #0'3 2 /&./& &-./ &;. - (.- & /2.& & (&(.(2- ';.& & ';- '&.-; && 2;;.-& (.-/ ' '/;.( '?)4@A"@) @ #0'3 2 &&.2& &-.22 &;.(- - 2;.( & ;.( & ('.-- .-( & ';- (-.& && 2'.2/ (.- ' '2;.( '?)4@A"@) @ #0'3 2 &-/. &2.(/ &.' - ;2.' & (.'; & (;.;;- /;.-' & ';- /-.( && 2&(. (./& ' &;.(( '?)4@A"@) @ #0'3 2 ';(. &-.2 &.& - /(;. & /;.2' & (&.- ;&.- & ';- /;2./ && 2(&.' (.'2 ' ;/.( '?)4@A"@) @ #0'3 2 '.- &2.(- &.( - //(.// & 2. & (-2.- ;.(/ & ';- /'.&; && --./& (.;2 ' -/.;/ '?)4@A"@) @ #0'3 2 /.; &-./( &'.' - ;. & -/.'; & (/.'&- /'&. & ';- /(2.( && -/.& (.-( ' ;/.-; '?)4@A"@) @ #0'3 2 ;'2.2& &-.( &.;2 - .'/ & -.' & &'.'- /-./ & ';- ;-.2 && -2.2/ . ' ;/. '?)4@A"@) @ #0'3 2 /(.;- &-.( &'.& - -&;./& & -/;.' & '2.;- &.(& & ';- ;/.(& && -''.(/ .'( ' ;/.( '?)4@A"@) @ #0'3 2 //;.; &2.& &'.2& - --.&' & -2(.2/ & ;/.&- 2./' & ';- ;';./ && -;. (.2 ' /(/. '?)4@A"@) @ #0'3 2 &.&; &/.2( &.'2 - 2'/.( & 2.& & '.&- -;&. & ';- ;&.'& && 2.22 ./' ' /';.2- '?)4@A"@) @ #0'3 2 -2.2 &/.2; &./( - 22.2 & 2'.&/ & 2.(- 2(-.' & ';- 2(.& && -(.&- (. ' //.'- '?)4@A"@) @ #0'3 2 -;&.;& &/./ &/.2( 2 (.-2 & 2;2.; & &(.2- 2/.&2 & ';- /-.2 && /&.2' .'/ ' /2&.'; '?)4@A"@) @ #0'3 2 2;. &;.-( &;.; 2 (.; & 2-.; & &&.&&2 (&(.-; & ';- /.&/ && /.&' .& ' 2.2( '?)4@A"@) @ #0'3 2 2.' &./ &.&' 2 /(./ ' (('.'( & &'2.&;2 (/.-/ & ';- &;.(( && '(.-( &.' ' /./ '?)4@A"@) @ #0'3 ( ((.; &.( &&.' 2 &-.(2 ' (&;.(( & &;'.22 '.2 & ';- ('.;- && /.; .( ' &.(/ '?)4@A"@) @ #0'3 ( (&.// &.(( &.22 2 &.-; ' (/. & &//.2/2 2.&; & ';- '-&.& && (&.&- (.& ' 2.& '?)4@A"@) @ #0'3 ( /.- &'.&( &(.'2 2 ''.-/ ' (/. & &2.-/2 &-.&/ & ';- '/.' && /--.2- ./; ' -&&.( '?)4@A"@) @ #0'3 ( &&/. &'./( &(-.2 2 '--.'2 ' (--.22 & &2.22 '(.2 & ';- '(.'' && //.;( .&& ' -/.'( '?)4@A"@) @ #0'3 ( &2(.2' &.' &(-.' 2 .' ' .2( & '(.(2 '/'. & ';- './ && //'./ (.-- ' -&.( '?)4@A"@) @ #0'3 ( ';'.2 &.; &(/. 2 ;(./ ' '.2; & '/.'2 &./ & ';- &2.- && /;.& .'2 ' -2./2 '?)4@A"@) @ #0'3 ( '2. &.'& &(;.&' 2 ;'2. ' 2.(& & '&'.;2 ;;.; & ';- &-(.2( && /./ .; ' 2'.(' '?)4@A"@) @ #0'3 ( '.(( &.'& &(;.&' 2 ;-(.& ' /;.-- & ''.(2 2/.-& & ';- &/.&( && /';.2( (.(( ' 2'.&- "8D151 5 +!$E +!$ $ 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: 12/19/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 23-07A PTD: 224-126 API: 50-133-20730-00-00 FINAL LWD FORMATION EVALUATION LOGS (11/11/2024 to 11/30/2024) DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 224-126 T39897 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.19 15:38:45 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887 KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,437'N/A Casing Collapse Structural Conductor 1,410psi Surface 2,470psi Intermediate 4,790psi Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng N/A; N/A N/A; N/A 9,580' 10,358' 9,508' Kenai Tyonek Gas Pool 1 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 23-07ACO 510C Same 9,442'3-1/2" 607psi 10,285' N/A Length December 9, 2024 N/A 10,285' Perforation Depth MD (ft): 6,297' See Attached Schematic 6,890psi 2,980psi 5,210psi 120' 5,920' 120' 1,664' Size 120' 7-5/8"6,297' 1,664' MD Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 10,160psi 1,619' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 224-126 50-133-20730-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: 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 10:04 am, Dec 05, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.12.04 18:10:13 - 09'00' Noel Nocas (4361) 324-682 BJM 12/5/24 3308 psi -bjm CT BOP test to 3500 psi December 9, 2024 Submit CBL to AOGCC and obtain approval before perforating. SFD 12/5/2024 10-407 DSR-12/9/2024 X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.10 15:51:15 -09'00'12/10/24 RBDMS JSB 121324 Initial Completion Well: KU 23-07A Well Name:KU 23-07A API Number:50-133-20730-00-00 Current Status:New Drill Gas Producer Permit to Drill Number:224-126 First Call Engineer:Chad Helgeson (907) 229-4824 (c) Second Call Engineer:Scott Warner (907) 830-8863 (c) Maximum Expected BHP:700 psi @ 9252’ TVD Offset Pressure data in D3C Sand Max. Potential Surface Pressure:607 psi Using 0.03 psi/ft LP gas gradient Applicable Frac Gradient:0.70 psi/ft using 13.56 ppg EMW FIT @ intermediate casing 11/25/24 Shallowest Potential Perf TVD:NA for proposed perfs in Tyonek Gas Pool 1 Top of Pools per CO 510C:Tyonek Gas Pool 1 – 9,692’ MD/8,905’ TVD Brief Well Summary KU 23-07A was drilled and completed with Hilcorp Rig 169 December 2024 targeting Tyonek, Upper Tyonek and Lower Beluga sands at Kenai Gas Field. The well was TD’ this week and completed with a 3.5” monobore completion. The objective of this sundry is to clean out the production liner with coil tubing, reverse the water from the well and perforate the Tyonek sands. Initial targeted sands will be in the Kenai Tyonek Gas Pool 1 per CO 510C Wellbore Conditions: - Liner & tubing full of 11.5 ppg mud - Provide 3.5” CBL to AOGCC once complete Pre sundry well work - Run CBL to bottom on Eline – send log to AOGCC prior to perfs - Pressure test tubing to 3500 psi – chart for 30 min - Pressure test IA to 2000 psi – chart for 30 min Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 24hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD (10,358’) cleanout well and swap well over to 8.4 ppg water 5. Once well is clean with 8.4 ppg water a. Reverse circulate water b. Target recovery = 90 bbls 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Eline Procedure 8. MIRU E-line and pressure control equipment 9. PT lubricator to 250psi low / 2500psi high 10. Ops pressure up well to ~400 psi or determined by Reservoir engineer Run CBL to bottom on Eline – send log to AOGCC prior to perfs 8.8 ppg (from drilling permit) @ 9252' TVD = 4233 psi BHP. MPSP = 3308 psi. -bjm Initial Completion Well: KU 23-07A 11. RIH and perforate per RE/Geo (see table below) Pool Bench Top MD Btm. MD Top TVD Btm. TVD Ft Tyonek 1 D2 ±9,716' ±9,781' ±8,926' ±8,924' ±65' Tyonek 1 D3B Lwr ±10,041’ ±10,047' ±9,218' ±9,224' ±6' Tyonek 1 D3C ±10,064' ±10,078' ±9,239' ±9,252' ±14' 12. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing, b. Pending well production, all perf intervals may not be completed c. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations d. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations e. Above perfs are in the Tyonek Gas Pool 1 governed by CO 510C 13. RD E-Line Unit and turn well over to production 14. Operations to flow well and test zones 15. Test SVS as necessary once well has reached stabile flow rates Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 16. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 17. Provide AOGCC 24hrs notice of BOP test 18. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 19. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 20. RDMO coil tubing Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure Agree. SFD _____________________________________________________________________________________ Updated by CAH 12-3-24 CURRENT SCHEMATIC Kenai Gas Field Well: KU 23-07A PTD: 224-126 API# 50-133-20730-00-00 TD =10,437’(MD) /9,580’(TVD) 16” RKB: GL = 18.4’ 3-1/2” 10-3/4” 7-5/8” 1 PBTD =10,358’(MD) / 9,508’ (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 84 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 / L-80 / GBCD 9.950” Surf 1,664’ 7-5/8" Intermediate 29.7 / P-110 / GBCD 6.875” Surf 6,297’ 3-1/2" Production 9.2 / L-80 / Hyd 563 2.992” Surf 10,285’ JEWELRY DETAIL No Depth Item 1 19.2 Cactus CTF-ONE-CTL 7” x 3-1/2” tubing hanger with 3- 1/2” EUE, 3.5” type H BPV profile OPEN HOLE / CEMENT DETAIL 10-3/4”147 bbls (393sx) of 12.5 ppg lead with 77 bbls (351 sx) of 15.3 ppg cement, 94 bbls of lead to surface 13-1/2” Hole. 7-5/8" 248 bbls (709 sx) of 12.5 ppg lead followed by 31 bbls (140 sx) of 15.3 ppg class G tail cement. Did not bump plug. CBL (11/23/24) shows TOC @ 1080ft. 20 bbls of cmt return at surface, lost 11.8 bbls during job. 3-1/2” 246 BBL’s of cement in 6-3/4” Hole. Est TOC @ 4,380’ (40% excess) Notes: Short jt w/ RA tags 9429, 8411, 7423, 6433 Short joints 9909, 8921, 7903, 6911, 5516, 5008, 4560 _____________________________________________________________________________________ Updated by CAH 12-3-24 PROPOSED Kenai Gas Field Well: KU 23-07A PTD: 224-126 API# 50-133-20730-00-00 TD =10,437’(MD) / 9,580’(TVD) 16” RKB: GL = 18.4’ 3-1/2” 10-3/4” 7-5/8” 1 PBTD =10,358’(MD) /9,508’(TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 84 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 / L-80 / GBCD 9.950” Surf 1,664’ 7-5/8" Intermediate 29.7 / P-110 / GBCD 6.875” Surf 6,297’ 3-1/2" Production 9.2 / L-80 / Hyd 563 2.992” Surf 10,285’ JEWELRY DETAIL No Depth Item 1 19.2 Cactus CTF-ONE-CTL 7” x 3-1/2” tubing hanger with 3- 1/2” EUE, 3.5” type H BPV profile OPEN HOLE / CEMENT DETAIL 10-3/4”147 bbls (393sx) of 12.5 ppg lead with 77 bbls (351 sx) of 15.3 ppg cement, 94 bbls of lead to surface 13-1/2” Hole. 7-5/8" 248 bbls (709 sx) of 12.5 ppg lead followed by 31 bbls (140 sx) of 15.3 ppg class G tail cement. Did not bump plug. CBL (11/23/24) shows TOC @ 1080ft. 20 bbls of cmt return at surface, lost 11.8 bbls during job. 3-1/2” 246 BBL’s of cement in 6-3/4” Hole. Est TOC @ 4,380’ (40% excess) Notes: Short jt w/ RA tags 9429, 8411, 7423, 6433 Short joints 9909, 8921, 7903, 6911, 5516, 5008, 4560 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of Tyonek Gas Pool 9692’ MD; 8905’ TVD D2 ±9,716' ±9,781' ±8,926' ±8,924' ±65' TBD Proposed D3B Lwr ±10,041’ ±10,047' ±9,218' ±9,224' ±6' TBD Proposed D3C ±10,064' ±10,078' ±9,239' ±9,252' ±14' TBD Proposed STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. CAUTION: 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 Subject:RE: KU 23-07A FIT test (244-126) Date:Friday, November 15, 2024 9:26:00 PM Sean, Agree that even with 12.8 ppg LOT you still have enough Kick tolerance to drill ahead. One could argue that LOT pressure is higher than 12.8 ppg, so that adds to the safety margin. Hilcorp has approval to drill ahead. 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, November 15, 2024 6:54 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: KU 23-07A FIT test (244-126) Results for KU 23-07A FIT test attached. The 20’ we drilled out was all soft sand. The test looks like a high perm situation that we have seen in other KGF wells. A 12.8# FIT results in a 25 bbl KTV. Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager 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 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 BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI UNIT 23-07A JBR 02/03/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 Tested 3 1/2" and 4 1/2" pipe sizes. They had a hard time getting the 3 1/2" size to test in annular. A number of things were tried. The sensor to the chart recorder was change out and they got a passing test. They had a F/P on meth sensor. It was changed out and passed re-test. With 2 sizes of pipe and only one set of floor valves, I ask them where their cross-over was. They said it was outside in a basket. They told me that they would get it on the floor. Test Results TEST DATA Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson Rig Owner/Rig No.:Hilcorp 169 PTD#:2241260 DATE:11/23/2024 Type Operation:DRILL Annular: 250/2500Type Test:BIWKLY Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopRCN241123174218 Inspector Bob Noble Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7.3 MASP: 3394 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2 7/8" x 5"P #2 Rams 1 Blinds P #3 Rams 1 2 7/8" x 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8" & 2 1/1 P Kill Line Valves 1 2 1/16"P Check Valve 0 NA BOP Misc 1 see remarks FP System Pressure P3025 Pressure After Closure P1800 200 PSI Attained P28 Full Pressure Attained P91 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4 @ 2512 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P FPMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P14 #1 Rams P4 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9 9999 9 9FP see remarks FPBOP Misc F/P on meth sensor With 2 sizes of pipe and only one set of floor valves, I ask them where their cross-over was. They said it was outside in a basket. They told me that they would get it on the floor. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Kenai Gas Field, Tyonek Gas Pool, KU 23-07A Hilcorp Alaska, LLC Permit to Drill Number: 224-126 Surface Location: 629' FNL, 874' FEL, Sec 7, T4N, R11W, SM, AK Bottomhole Location: 1645' FSL, 1698' FWL, Sec 7, T4N, R11W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 29th day of October 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.29 06:46:58 -06'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 10,285' TVD: 9,427' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 83.6 15. Distance to Nearest Well Open Surface: x-275026 y-2361385 Zone-4 65.6 to Same Pool: 7400' to KU 33-08 16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 29 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 13-1/2" 10-3/4" 45.5# L-80 GBCD 1,647' Surface Surface 1,647' 1,600' 9-7/8" 7-5/8" 29.7# P-110 GBCD 6,380' Surface Surface 6,380' 6,000' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 10,285' Surface Surface 10,285' 9,427' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng KU 23-07A Kenai Gas Field Tyonek Gas Pool 1 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1707 ft3 / T - 171 ft3 3394 2147' FNL, 2164' FEL, Sec 7, T4N, R11W, SM, AK 1645' FSL, 1698' FWL, Sec 7, T4N, R11W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 629' FNL, 874' FEL, Sec 7, T4N, R11W, SM, AK FEE A028142 18. Casing Program:Top - Setting Depth - BottomSpecifications 4337 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 727 ft3 / T - 427 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): 11/5/2024 5892' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 L - 634 ft3 / T - 105 ft3 2494 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 09/24/24 Monty M Myers By Grace Christianson at 2:35 pm, Sep 24, 2024 50-133-20730-00-00224-126 Diverter variance approved under 20 AAC 25.035(h)(2) DSR-9/27/24A.Dewhurst 23OCT24 BOP test to 3500 psi. Annular test to 2500 psi. Submit FIT/LOT data within 48 hrs of performing tests. BJM 10/28/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.29 06:47:14 -06'00' 10/29/24 10/29/24 RBDMS JSB 102924 KU 23-07A Drilling Program Kenai Gas Field Rev. PTD August 29, 2024 KU 23-07A Drilling Procedure PTD: xxx-xxx Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 KU 23-07A location on KGF 41-7 Pad:......................................................................................11 11.0 Drill 13-1/2” Surface Hole Section..............................................................................................11 12.0 Run 10-3/4” Surface Casing........................................................................................................13 13.0 Cement 10-3/4” Surface Casing..................................................................................................15 14.0 BOP N/U and Test........................................................................................................................18 15.0 Drill 9-7/8” Hole Section..............................................................................................................19 16.0 Run 7-5/8” Intermediate Casing.................................................................................................21 17.0 Cement 7-5/8” Intermediate Casing...........................................................................................23 18.0 Drill 6-3/4” Hole Section..............................................................................................................26 19.0 Run 3-1/2” longstring..................................................................................................................28 20.0 Cement 3-1/2” Production Casing..............................................................................................30 21.0 Test and RD..................................................................................................................................32 22.0 BOP Schematic.............................................................................................................................33 23.0 Wellhead Schematic.....................................................................................................................34 24.0 Anticipated Drilling Hazards......................................................................................................34 25.0 Hilcorp Rig 169 Layout...............................................................................................................37 26.0 FIT/LOT Procedure ....................................................................................................................38 27.0 Rig 169 Choke Manifold Schematic...........................................................................................39 28.0 Casing Design Information.........................................................................................................40 29.0 9-7/8” Hole Section MASP..........................................................................................................41 30.0 6-3/4” Hole Section MASP..........................................................................................................42 31.0 Spider Plot (Governmental Sections NAD27) ...........................................................................43 32.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................44 Page 2 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 1.0 Well Summary Well KU 23-07A Pad & Old Well Designation KGF 41-7 pad Planned Completion Type 3-1/2” longstring Target Reservoir(s)Lower Beluga through Deep Tyonek Planned Well TD, MD / TVD 10285’ MD / 9428’ TVD AFE Number AFE Drilling Days 31 AFE Drilling Amount Maximum Anticipated Pressure (Surface)3394 psi Maximum Anticipated Pressure (Downhole/Reservoir)4337 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 83.6 Ground Elevation 65.6 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 2.0 Management of Change Information Page 4 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”17”84 X-56 Weld 2980 1410 - Surface 13-1/2”10-3/4”9.95”9.875”11.75”45.5 L-80 GBCD 5210 2470 1040 Intermediate 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBCD 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k Page 5 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out of scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each work day to KenaiCIODrilling@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. Brad Duwe (907-398-6558) 2. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 3. For Spills: Jason Hobart – 907-598-5889 © 907-283-1358 (O) x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com,and cdinger@hilcorp.com Page 6 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 6.0 Planned Wellbore Schematic Page 7 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 7.0 Drilling / Completion Summary KU 23-07A will target the lower Beluga through deep Tyonek sands drilled from Pad 41-7. The Lower Beluga through Deep Tyonek section at KGF needs down spacing. The grassroots well will be drilled to the NE with a maximum hole angle of 29 degrees. The TD of the three string well will be 10285’ TMD/ 9428’ TVD. Drilling operations are expected to commence in November 2024. The Hilcorp Rig #169 will be used to drill the wellbore then run casing and cement. 10-3/4” surface casing will be run and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to KGF 41-7 pad x No diverter required 2. Drill 13-1/2” hole to 1647’ MD. Run and cmt 10-3/4” surface casing. 3. N/U & test 11” x 5M BOP to 3500 psi 4. Test Surface casing to 2700 psi. 5. Drill out shoe and perform a FIT to 12.8 ppg EMW 6. Drill 9-7/8” intermediate hole to 6380’ MD 7. RIH w/ 7-5/8” casing and cement to surface. 8. Perform casing test to 3500 psi. Swap rams to 3-1/2”. Test BOPE to 3500 psi 9.RU eline and Run CBL across 7-5/8” 10. PU 6-3/4” motor drilling assembly and TIH to window. 11. Mill shoe track and 20’ of new hole. 12. Perform FIT to 13.6 ppg EMW 13. Drill 6-3/4” production hole to 10285’ MD. 14. POOH & LDDP 15. Run and cement 3-1/2” long string. 16. MIT Tubing and IA to 3500 psi. 17. N/D BOP, N/U dry hole tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Intermediate hole: GR + Res LWD 3. Production Hole: Triple Combo LWD Page 8 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or could be assumed damaged, test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC drilling permit is posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. AOGCC Regulation Variance Request: x 20 AAC 25.035(h)(2) -Diverter waiver request requested due to the recent drilling of KU 13-06A, KU 11-07X , KU 24-05B, KU 24-32, KU 42-12, KU 44-08, KU 44-01B, KU 41-08, and KU 33-08. No issues or shallow gas was experienced on these wells while drilling surface hole. Surface casing will be set at a similar depth of these wells. o Divert waiver requests granted on KU 14-05, KBU 31-06X, KBU 42-06Y, KDU 10, KBU 23- 05, and KU 41-08 (all on 41-7 pad). Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) Recommend approving the requested diverter variance. -A.Dewhurst 23OCT24q Diverter waiver request requested AOGCC reviewed records for ten nearby wells: KU 43-07, KDU 2 (21-08), KDU 4, KBU 41-07, KBU 41-07X, KBU 11-08Z, KDU 10, KU 14-05, KU 24-05B, and KBU 31-06X.None of these wells reported encountering significant gas while drilling to surface casing points at depths ranging from -1,140’ to -2,913' TVDSS. However, nearby well KU 24-05B (PTD 219-072) encountered 40 units at 1,135' MD (-1,040' TVDSS) and a maximum of 62 units measured at 1,370' MD (-1,267' TVDSS). Monitoring of gas and caution are advised while drilling the equivalent interval. Page 9 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 13-1/2”x 21-1/4” x 2M Riser N/A 9-7/8” and 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 2016 Waste Prevention Rule - Waste Minimization Plan for Drilling: Hilcorp Alaska will not be venting or flaring any gas while drilling this well. The only waste produced from this well will be used mud and cuttings and will be handled at the Kenai Gas Field G&I facility for injection disposal. Page 10 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 13-1/2” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 10.0 KU 23-07A location on KGF 41-7 Pad: 11.0 Drill 13-1/2” Surface Hole Section 11.1 P/U directional drilling assy: x 13-1/2” Openhole, 8” drilling tools x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. Page 12 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.3 Drill surface hole section to 1647’ MD/ 1600’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~700 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Kenai and Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 800’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x Take MWD surveys every stand drilled (60’ intervals). 11.4 13-1/2” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.0 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1647’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL Page 13 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX ALDACIDE G X-TEND II 0.1 ppb 0.02 ppb 11.5 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.6 TOH with the drilling assy, handle BHA as appropriate. 12.0 Run 10-3/4” Surface Casing 12.1 R/U and pull wear bushing. 12.2 R/U Parker 10-3/4” casing running equipment. x Ensure 10-3/4” GBCD x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 10-3/4” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Note M/U torque values required to achieve this position. x Install (1) centralizer every other joint to 120’. Do not run any centralizers above 120’ in the event a top job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 14 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 12.7 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.9 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.10 After circulating, lower string and land hanger in wellhead again. Page 15 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 13.0 Cement 10-3/4” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x Discuss how to handle cmt returns at surface. x Confirm which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Determine positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 100% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 16 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (1147’ MD to surface)Tail Slurry (1647’ to 1147’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.40 ft3/sk 1.16 ft3/sk Mixed Water 14.25 gal/sk 5.04 gal/sk Mixed Fluid 14.25 gal/sk 5.04 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss CalSeal Accelerator CalSeal Accelerator VersaSet Thixotropic CFR-3 Dispersant D-Air 5000 Anti Foam UCS Slurry Conditioner Econolite Light-weight add.Super CBL Anti-Gas Migration SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 17 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 11 bbls. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Page 18 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. 14.0 BOP N/U and Test 14.1 ND Riser 14.2 N/U multi-bowl wellhead assy. Install 10-3/4” packoff P-seals. Test to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 7-5/8” fixed bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run BOP test assy, land out test plug (if not installed previously). x Utilize 7-5/8” and 4-1/2” test joints. x Test BOP to 250/3500 psi for 5/10 min. x Test annular to 250/2500 psi for 5/10 min with a 4-1/2” test joint x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.1 ppg 6% KCL PHPA mud system. 14.8 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 19 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 15.0 Drill 9-7/8” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 9-7/8” hole section mud program summary: Starting mud weight for the production interval is 9.1ppg. Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:9.1 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1647’- 6380’9.0 – 9.7 40-53 15-25 15-25 8.5-9.5 11.0 Page 20 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional BHA assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 R/U and test casing to 2700 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.10-3/4” burst is 5210 psi / 2 = 2605 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 12.8 ppg EMW. (12.8 FIT, 8.5 ppg BHP, 9.2 ppg MW = 25 bbl KTV) 15.14 Drill 9-7/8” hole section to 6380’ MD / 6000’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~400 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through the hole section make a wiper back to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Low BHP between Pool 4 and 6 (3979’ – 4652’). To minimize LC risk keep MW at 9.1 ppg, minimize ECD, stage up pumps on connections, add Black products and sized Calcium Carbonate to the mud, Control drill at 40 fph. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4” shoe. 15.16 TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 15.17 POOH and LD BHA. Page 21 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 15.18 Ensure 7-5/8” FBRs previously installed in BOP stack and tested with 7-5/8” test joint. 16.0 Run 7-5/8” Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” GBCD x CDS40 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Ensure all casing has been drifted to 6.75” on the location prior to running. x Note that 29.7# drift is 6.75” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80’ shoe track assembly consisting of: 7-5/8” Float Shoe 1 joint – 7-5/8” BTC, 1 Centralizer 10’ from bottom w/ stop ring 7-5/8” Float Collar 1 joint – 7-5/8” BTC, 1 Free floating centralizer 7-5/8” Landing collar 5. Continue running 7-5/8” intermediate casing x Centralization: x 1 centralizer every joint to 1000’ MD (Planned TOC) x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 22 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 8. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 9. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. Page 23 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 10. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging. Stage up pump slowly and monitor losses closely while circulating. 11. After circulating, lower string and land hanger in wellhead again. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 17.0 Cement 7-5/8” Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to 1000’. Page 24 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX Estimated Cement Volume: Cement Slurry Design: 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. Lead Slurry 5880’-1000’ Tail Slurry 6380’- 5880’ System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs. -bjm Page 25 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 11. Ensure rig pump is used to displace cement. 12. Land hanger. 13. Displacement volume is in Table above. 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. 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 x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 18.0 Drill 6-3/4” Hole Section 1. Set test plug, Swap 7-5/8” FBR to 2-7/8” x 5” VBR, test all rams to 3500 psi. and 4-1/2 and 3- 1/2 test joints,Pull test plug, run and set wear bushing 2. Ensure BHA components have been inspected previously. 3. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly (triple combo). 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 7. Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 8. 6-3/4” hole section mud program summary: Starting mud weight for the production interval is 9.8 ppg or the intermediate interval mud weight at TD, whichever is heavier.(10.7 ppg required at 7000’ TVD, 11.5 ppg required at TD) Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:11.5 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 6380’- 10285’9.8 – 12.5 40-53 15-25 15-25 8.5-9.5 11.0 Page 27 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 9. TIH w/ 4-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 10. R/U and test casing to 3500 psi / 30 min.Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 11. Drill out shoe track and 20’ of new formation. 12. CBU and condition mud for FIT. 13. Conduct FIT to 13.6 ppg EMW. (13.3 FIT, 8.8 ppg BHP, 11.5 ppg MW = 23 bbl KTV) 14. Drill 6-3/4” hole section to 10285’ MD / 9428’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through to interval make a wiper trip to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Mud Weight: 10.7 ppg required at 7000’ TVD, 11.5 ppg required at TD 15. At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 16. TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 17. POOH LDDP and BHA. 18. Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint Page 28 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 19.0 Run 3-1/2” longstring 1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” H563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x MU a marker joint (short joint with RA tag) every 1000’. 4. Continue running 3-1/2” longstring x Fill while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint x Differential sticking risk: Keep Mud “clean” as possible, remove low gravity solid (drilled solids), Centralizers every joint, Minimize connection time, Slow running speeds to reduce surge, Keep pipe moving whenever possible Page 29 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 5. Run in hole w/ 3-1/2” to the 7-5/8” casing shoe. x No SSSV, GLM, or CIM required. Page 30 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 6. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 7. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 8. Circulate 2X bottoms up at shoe, ease casing thru shoe. 9. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. Set casing slowly in and out of slips. 11. Swedge up and wash last four joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 12. Stage pump rates up slowly to circulating rate. Circ and condition mud. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 13. MU hanger and land 3-1/2” long string 20.0 Cement 3-1/2” Production Casing 1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x Plan for cmt returns at surface, regardless of how unlikely it is that this should occur. x Determine which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 2. Pump 5 bbls spacer. 3. Test surface cmt lines to 4500 psi. 4. Pump remaining spacer. 5. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Planned TOC at 4380’. Page 31 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (9785’ MD to 4380’ MD)Tail Slurry (10285’ to 9785’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Displacement should be 89 bbls per attached Sean McLaughlin email 10/27/24 -bjm Page 32 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 6. Drop LWP dart and displace with drilling mud. 7. Displace cement at max rate of 4 bbl/min. 8. Bump the plug and pressure up to 500 psi FCP. Hold pressure for 3-5 minutes. 9. Do not overdisplace by more than 2 shoe track volumes. Shoe track volume is 1 bbls. 10. RD cementers and flush equipment. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. 21.0 Test and RD 1. Test 3-1/2” tubing to 3500 psi and chart for 30 minutes. 2. Test 7-5/8” x 3-1/2” annulus to 3500 psi and chart for 30 minutes. 3. Install BPV in wellhead 4. N/D BOPE 5. N/U dry hole tree or full tree (if available). 6. RDMO Hilcorp Rig #169 Page 33 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 22.0 BOP Schematic Page 34 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 23.0 Wellhead Schematic 24.0 Anticipated Drilling Hazards Page 35 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 9-7/8” Hole Section: Lost Circulation: High risk in Pool 3-6 due to Low BHP.To minimize LC risk keep MW at 9.1 ppg, minimize ECD, stage up pumps on connections, add Black products and sized Calcium Carbonate to the mug, Control drill at 40 fph. Drilling through low pressure intervals: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. Abnormal pressures or temperatures:None 6-3/4” Hole Section: Page 36 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. Reservoir Pressure: Abnormal pressures expected in the deep Tyonek inteval Page 37 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 25.0 Hilcorp Rig 169 Layout Page 38 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 26.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at requiredsurface 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 39 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 27.0 Rig 169 Choke Manifold Schematic Page 40 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 28.0 Casing Design Information Page 41 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 29.0 9-7/8” Hole Section MASP Page 42 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 30.0 6-3/4” Hole Section MASP Page 43 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 31.0 Spider Plot (Governmental Sections NAD27) Page 44 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX 32.0 Surface Plat (As-Built NAD27 & NAD83) Page 45 Version PTD August 29, 2024 KU 23-07A Drilling Procedure PTD XXX-XXX Standard Planning Report 30 August, 2024 Plan: KU 23-07A wp02 Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 23-07 KU 23-07 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) -7500750150022503000375045005250600067507500825090009750True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750Vertical Section at 216.95° (1500 usft/in)KU 23-07A wp01 tgt1KU 23-07A wp02 tgt210 3/4" x 13 1/2"7 5/8" x 9 7/8"4 1/2" x 6 3/4"5001000150020002500300035004000450050005500600065007000750080008500900095001000010285KU 23-07A wp02Start Dir 3º/100' : 500' MD, 500'TVDEnd Dir : 1216.51' MD, 1199.82' TVDStart Dir 3º/100' : 6182.63' MD, 5820.54'TVDEnd Dir : 6421.33' MD, 6036.6' TVDTotal Depth : 10285.49' MD, 9427.65' TVDTop Pool 3_A6Top Pool 4Top Pool 5Top Pool 6Top Upp er BelugaTop Middle Be lu gaTop Low er BelugaTop Upp er TyonekTop Tyonek D1Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: KU 23-0765.60+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.002361385.266275026.385 60° 27' 28.102 N 151° 14' 46.586 WSURVEY PROGRAMDate: 2024-08-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool18.00 1674.00 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag1674.00 6380.00 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag6380.00 10285.49 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+SagFORMATION TOP DETAILSTVDPath MDPath Formation3397.60 3578.58 Top Pool 3_A63770.60 3979.46 Top Pool 43877.60 4094.46 Top Pool 54425.60 4683.42 Top Pool 64652.60 4927.39 Top Upper Beluga5286.60 5608.78 Top Middle Beluga6036.60 6421.33 Top Lower Beluga7167.60 7710.12 Top Upper Tyonek8725.60 9485.49 Top Tyonek D1REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 23-07, True NorthVertical (TVD) Reference:KU 23-07A @ 83.60usftMeasured Depth Reference:KU 23-07A @ 83.60usftCalculation Method:Minimum CurvatureProject:Kenai Gas FieldSite:KGF 41-7 PadWell:Plan: KU 23-07Wellbore:KU 23-07Design:KU 23-07A wp02CASING DETAILSTVDMDName Size1600.00 1646.60 10 3/4" x 13 1/2" 10-3/46000.00 6379.86 7 5/8" x 9 7/8" 7-5/89427.65 10285.48 4 1/2" x 6 3/4" 4-1/2SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.002 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD3 1216.51 21.50 217.29 1199.82 -105.68 -80.48 3.00 217.29 132.83 End Dir : 1216.51' MD, 1199.82' TVD4 6182.63 21.50 217.29 5820.54 -1553.32 -1183.05 0.00 0.00 1952.51 Start Dir 3º/100' : 6182.63' MD, 5820.54'TVD5 6421.33 28.65 216.59 6036.60 -1634.16 -1243.74 3.00 -2.71 2053.59 KU 23-07A wp01 tgt1 End Dir : 6421.33' MD, 6036.6' TVD6 9485.49 28.65 216.59 8725.60 -2813.76 -2119.47 0.00 0.00 3522.70 KU 23-07A wp02 tgt27 10285.49 28.65 216.59 9427.65 -3121.74 -2348.10 0.00 0.00 3906.26 Total Depth : 10285.49' MD, 9427.65' TVDYou created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) -3150-2925-2700-2475-2250-2025-1800-1575-1350-1125-900-675-450-2250South(-)/North(+) (450 usft/in)-3375 -3150 -2925 -2700 -2475 -2250 -2025 -1800 -1575 -1350 -1125 -900 -675 -450 -225 0 225 450 675 900West(-)/East(+) (450 usft/in)KU 23-07A wp02 tgt2KU 23-07A wp01 tgt110 3/4" x 13 1/2"7 5/8" x 9 7/8"4 1/2" x 6 3/4"50010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077508000825085008750900092509428KU 23-07A wp02Start Dir 3º/100' : 500' MD, 500'TVDEnd Dir : 1216.51' MD, 1199.82' TVDStart Dir 3º/100' : 6182.63' MD, 5820.54'TVDEnd Dir : 6421.33' MD, 6036.6' TVDTotal Depth : 10285.49' MD, 9427.65' TVDCASING DETAILSTVDMD Name Size1600.00 1646.60 10 3/4" x 13 1/2" 10-3/46000.00 6379.86 7 5/8" x 9 7/8" 7-5/89427.65 10285.48 4 1/2" x 6 3/4" 4-1/2Project: Kenai Gas FieldSite: KGF 41-7 PadWell: Plan: KU 23-07Wellbore: KU 23-07Plan: KU 23-07A wp02REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 23-07, True NorthVertical (TVD) Reference:KU 23-07A @ 83.60usftMeasured Depth Reference:KU 23-07A @ 83.60usftCalculation Method:Minimum CurvatureWELL DETAILS: Plan: KU 23-0765.60+N/-S +E/-W Northing Easting LatittudeLongitude0.00 0.00 2361385.266 275026.38560° 27' 28.102 N151° 14' 46.586 WYou created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: KU 23-07Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db KU 23-07A @ 83.60usftTVD Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftMD Reference:Kenai Gas FieldProject: TrueNorth Reference:KGF 41-7 PadSite: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Well: KU 23-07Wellbore: KU 23-07A wp02Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Kenai Gas Field Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: KGF 41-7 Pad Lat/Long Slot Radius:0.00 usft usft usft " 2,361,462.424 274,852.805 13-3/16 60° 27' 28.829 N 151° 14' 50.076 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: Plan: KU 23-07 Wellhead Elevation:0.00 0.00 0.00 2,361,385.266 275,026.385 60° 27' 28.102 N 151° 14' 46.586 W 65.60 usft usft usft usft usft usft usft °-1.08Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) KU 23-07 Model NameMagnetics BGGM2024 8/15/2024 13.67 73.29 55,065.12993445 Phase:Version: Audit Notes: Design KU 23-07A wp02 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:18.00 216.950.000.0018.00 Depth From (usft) Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Depth To (usft) Date 8/30/2024 3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & KU 23-07A wp02 (KU 23-07)18.00 1,674.001 3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & KU 23-07A wp02 (KU 23-07)1,674.00 6,380.002 3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & KU 23-07A wp02 (KU 23-07)6,380.00 10,285.493 8/30/2024 10:49:18AM COMPASS 5000.17 Build 02 Page 2 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: KU 23-07Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db KU 23-07A @ 83.60usftTVD Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftMD Reference:Kenai Gas FieldProject: TrueNorth Reference:KGF 41-7 PadSite: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Well: KU 23-07Wellbore: KU 23-07A wp02Design: Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.000.0018.000.000.0018.00 0.000.000.000.000.000.00500.000.000.00500.00 217.290.003.003.00-80.48-105.681,199.82217.2921.501,216.51 0.000.000.000.00-1,183.05-1,553.325,820.54217.2921.506,182.63 -2.71-0.293.003.00-1,243.74-1,634.166,036.60216.5928.656,421.33 KU 23-07A wp01 tg 0.000.000.000.00-2,119.47-2,813.768,725.60216.5928.659,485.49 KU 23-07A wp02 tg 0.000.000.000.00-2,348.10-3,121.749,427.65216.5928.6510,285.49 8/30/2024 10:49:18AM COMPASS 5000.17 Build 02 Page 3 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: KU 23-07Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db KU 23-07A @ 83.60usftTVD Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftMD Reference:Kenai Gas FieldProject: TrueNorth Reference:KGF 41-7 PadSite: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Well: KU 23-07Wellbore: KU 23-07A wp02Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 18.00 0.00 0.00 18.00 0.00 0.000.00 0.00 0.00 0.00 100.00 0.00 0.00 100.00 0.00 0.000.00 0.00 0.00 0.00 200.00 0.00 0.00 200.00 0.00 0.000.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.000.00 0.00 0.00 0.00 400.00 0.00 0.00 400.00 0.00 0.000.00 0.00 0.00 0.00 500.00 0.00 0.00 500.00 0.00 0.000.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD 600.00 3.00 217.29 599.95 2.62 3.00-2.08 -1.59 3.00 0.00 700.00 6.00 217.29 699.63 10.46 3.00-8.32 -6.34 3.00 0.00 800.00 9.00 217.29 798.77 23.51 3.00-18.71 -14.25 3.00 0.00 900.00 12.00 217.29 897.08 41.73 3.00-33.20 -25.29 3.00 0.00 1,000.00 15.00 217.29 994.31 65.08 3.00-51.77 -39.43 3.00 0.00 1,100.00 18.00 217.29 1,090.18 93.47 3.00-74.36 -56.64 3.00 0.00 1,200.00 21.00 217.29 1,184.43 126.85 3.00-100.92 -76.86 3.00 0.00 1,216.51 21.50 217.29 1,199.82 132.83 3.00-105.68 -80.49 3.00 0.00 End Dir : 1216.51' MD, 1199.82' TVD 1,300.00 21.50 217.29 1,277.50 163.43 0.00-130.01 -99.02 0.00 0.00 1,400.00 21.50 217.29 1,370.55 200.07 0.00-159.16 -121.22 0.00 0.00 1,500.00 21.50 217.29 1,463.59 236.71 0.00-188.31 -143.43 0.00 0.00 1,600.00 21.50 217.29 1,556.64 273.35 0.00-217.46 -165.63 0.00 0.00 1,646.60 21.50 217.29 1,600.00 290.43 0.00-231.05 -175.97 0.00 0.00 10 3/4" x 13 1/2" 1,700.00 21.50 217.29 1,649.68 309.99 0.00-246.62 -187.83 0.00 0.00 1,800.00 21.50 217.29 1,742.73 346.63 0.00-275.77 -210.03 0.00 0.00 1,900.00 21.50 217.29 1,835.77 383.28 0.00-304.92 -232.23 0.00 0.00 2,000.00 21.50 217.29 1,928.82 419.92 0.00-334.07 -254.43 0.00 0.00 2,100.00 21.50 217.29 2,021.86 456.56 0.00-363.22 -276.64 0.00 0.00 2,200.00 21.50 217.29 2,114.91 493.20 0.00-392.37 -298.84 0.00 0.00 2,300.00 21.50 217.29 2,207.95 529.84 0.00-421.52 -321.04 0.00 0.00 2,400.00 21.50 217.29 2,301.00 566.48 0.00-450.67 -343.24 0.00 0.00 2,500.00 21.50 217.29 2,394.04 603.13 0.00-479.82 -365.44 0.00 0.00 2,600.00 21.50 217.29 2,487.09 639.77 0.00-508.97 -387.64 0.00 0.00 2,700.00 21.50 217.29 2,580.13 676.41 0.00-538.12 -409.85 0.00 0.00 2,800.00 21.50 217.29 2,673.17 713.05 0.00-567.27 -432.05 0.00 0.00 2,900.00 21.50 217.29 2,766.22 749.69 0.00-596.42 -454.25 0.00 0.00 3,000.00 21.50 217.29 2,859.26 786.34 0.00-625.57 -476.45 0.00 0.00 3,100.00 21.50 217.29 2,952.31 822.98 0.00-654.72 -498.65 0.00 0.00 3,200.00 21.50 217.29 3,045.35 859.62 0.00-683.87 -520.86 0.00 0.00 3,300.00 21.50 217.29 3,138.40 896.26 0.00-713.02 -543.06 0.00 0.00 3,400.00 21.50 217.29 3,231.44 932.90 0.00-742.17 -565.26 0.00 0.00 3,500.00 21.50 217.29 3,324.49 969.54 0.00-771.32 -587.46 0.00 0.00 3,578.58 21.50 217.29 3,397.60 998.34 0.00-794.23 -604.91 0.00 0.00 Top Pool 3_A6 3,600.00 21.50 217.29 3,417.53 1,006.19 0.00-800.47 -609.66 0.00 0.00 3,700.00 21.50 217.29 3,510.58 1,042.83 0.00-829.62 -631.86 0.00 0.00 3,800.00 21.50 217.29 3,603.62 1,079.47 0.00-858.77 -654.07 0.00 0.00 3,900.00 21.50 217.29 3,696.67 1,116.11 0.00-887.93 -676.27 0.00 0.00 3,979.46 21.50 217.29 3,770.60 1,145.23 0.00-911.09 -693.91 0.00 0.00 Top Pool 4 4,000.00 21.50 217.29 3,789.71 1,152.75 0.00-917.08 -698.47 0.00 0.00 4,094.46 21.50 217.29 3,877.60 1,187.36 0.00-944.61 -719.44 0.00 0.00 Top Pool 5 4,100.00 21.50 217.29 3,882.76 1,189.39 0.00-946.23 -720.67 0.00 0.00 8/30/2024 10:49:18AM COMPASS 5000.17 Build 02 Page 4 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: KU 23-07Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db KU 23-07A @ 83.60usftTVD Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftMD Reference:Kenai Gas FieldProject: TrueNorth Reference:KGF 41-7 PadSite: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Well: KU 23-07Wellbore: KU 23-07A wp02Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 4,200.00 21.50 217.29 3,975.80 1,226.04 0.00-975.38 -742.87 0.00 0.00 4,300.00 21.50 217.29 4,068.85 1,262.68 0.00-1,004.53 -765.07 0.00 0.00 4,400.00 21.50 217.29 4,161.89 1,299.32 0.00-1,033.68 -787.28 0.00 0.00 4,500.00 21.50 217.29 4,254.94 1,335.96 0.00-1,062.83 -809.48 0.00 0.00 4,600.00 21.50 217.29 4,347.98 1,372.60 0.00-1,091.98 -831.68 0.00 0.00 4,683.42 21.50 217.29 4,425.60 1,403.17 0.00-1,116.30 -850.20 0.00 0.00 Top Pool 6 4,700.00 21.50 217.29 4,441.03 1,409.25 0.00-1,121.13 -853.88 0.00 0.00 4,800.00 21.50 217.29 4,534.07 1,445.89 0.00-1,150.28 -876.08 0.00 0.00 4,900.00 21.50 217.29 4,627.12 1,482.53 0.00-1,179.43 -898.28 0.00 0.00 4,927.39 21.50 217.29 4,652.60 1,492.56 0.00-1,187.41 -904.37 0.00 0.00 Top Upper Beluga 5,000.00 21.50 217.29 4,720.16 1,519.17 0.00-1,208.58 -920.49 0.00 0.00 5,100.00 21.50 217.29 4,813.21 1,555.81 0.00-1,237.73 -942.69 0.00 0.00 5,200.00 21.50 217.29 4,906.25 1,592.45 0.00-1,266.88 -964.89 0.00 0.00 5,300.00 21.50 217.29 4,999.29 1,629.10 0.00-1,296.03 -987.09 0.00 0.00 5,400.00 21.50 217.29 5,092.34 1,665.74 0.00-1,325.18 -1,009.29 0.00 0.00 5,500.00 21.50 217.29 5,185.38 1,702.38 0.00-1,354.33 -1,031.50 0.00 0.00 5,600.00 21.50 217.29 5,278.43 1,739.02 0.00-1,383.48 -1,053.70 0.00 0.00 5,608.78 21.50 217.29 5,286.60 1,742.24 0.00-1,386.04 -1,055.65 0.00 0.00 Top Middle Beluga 5,700.00 21.50 217.29 5,371.47 1,775.66 0.00-1,412.63 -1,075.90 0.00 0.00 5,800.00 21.50 217.29 5,464.52 1,812.30 0.00-1,441.78 -1,098.10 0.00 0.00 5,900.00 21.50 217.29 5,557.56 1,848.95 0.00-1,470.93 -1,120.30 0.00 0.00 6,000.00 21.50 217.29 5,650.61 1,885.59 0.00-1,500.08 -1,142.50 0.00 0.00 6,100.00 21.50 217.29 5,743.65 1,922.23 0.00-1,529.24 -1,164.71 0.00 0.00 6,182.63 21.50 217.29 5,820.54 1,952.51 0.00-1,553.32 -1,183.05 0.00 0.00 Start Dir 3º/100' : 6182.63' MD, 5820.54'TVD 6,200.00 22.02 217.23 5,836.67 1,958.95 3.00-1,558.45 -1,186.95 3.00 -0.38 6,300.00 25.01 216.90 5,928.35 1,998.84 3.00-1,590.28 -1,210.99 3.00 -0.33 6,379.86 27.41 216.69 6,000.00 2,034.11 3.00-1,618.53 -1,232.11 3.00 -0.27 7 5/8" x 9 7/8" 6,400.00 28.01 216.64 6,017.83 2,043.47 3.00-1,626.04 -1,237.70 3.00 -0.24 6,421.33 28.65 216.59 6,036.60 2,053.59 3.00-1,634.16 -1,243.74 3.00 -0.23 End Dir : 6421.33' MD, 6036.6' TVD - Top Lower Beluga 6,500.00 28.65 216.59 6,105.64 2,091.31 0.00-1,664.45 -1,266.22 0.00 0.00 6,600.00 28.65 216.59 6,193.40 2,139.26 0.00-1,702.95 -1,294.80 0.00 0.00 6,700.00 28.65 216.59 6,281.15 2,187.20 0.00-1,741.44 -1,323.38 0.00 0.00 6,800.00 28.65 216.59 6,368.91 2,235.15 0.00-1,779.94 -1,351.96 0.00 0.00 6,900.00 28.65 216.59 6,456.67 2,283.09 0.00-1,818.44 -1,380.54 0.00 0.00 7,000.00 28.65 216.59 6,544.42 2,331.04 0.00-1,856.93 -1,409.12 0.00 0.00 7,100.00 28.65 216.59 6,632.18 2,378.98 0.00-1,895.43 -1,437.70 0.00 0.00 7,200.00 28.65 216.59 6,719.94 2,426.93 0.00-1,933.93 -1,466.28 0.00 0.00 7,300.00 28.65 216.59 6,807.69 2,474.87 0.00-1,972.42 -1,494.86 0.00 0.00 7,400.00 28.65 216.59 6,895.45 2,522.81 0.00-2,010.92 -1,523.44 0.00 0.00 7,500.00 28.65 216.59 6,983.21 2,570.76 0.00-2,049.42 -1,552.02 0.00 0.00 7,600.00 28.65 216.59 7,070.96 2,618.70 0.00-2,087.91 -1,580.60 0.00 0.00 7,700.00 28.65 216.59 7,158.72 2,666.65 0.00-2,126.41 -1,609.18 0.00 0.00 7,710.12 28.65 216.59 7,167.60 2,671.50 0.00-2,130.31 -1,612.07 0.00 0.00 Top Upper Tyonek 7,800.00 28.65 216.59 7,246.48 2,714.59 0.00-2,164.91 -1,637.76 0.00 0.00 7,900.00 28.65 216.59 7,334.23 2,762.54 0.00-2,203.40 -1,666.34 0.00 0.00 8,000.00 28.65 216.59 7,421.99 2,810.48 0.00-2,241.90 -1,694.92 0.00 0.00 8/30/2024 10:49:18AM COMPASS 5000.17 Build 02 Page 5 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: KU 23-07Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db KU 23-07A @ 83.60usftTVD Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftMD Reference:Kenai Gas FieldProject: TrueNorth Reference:KGF 41-7 PadSite: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Well: KU 23-07Wellbore: KU 23-07A wp02Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 8,100.00 28.65 216.59 7,509.75 2,858.43 0.00-2,280.40 -1,723.50 0.00 0.00 8,200.00 28.65 216.59 7,597.50 2,906.37 0.00-2,318.89 -1,752.08 0.00 0.00 8,300.00 28.65 216.59 7,685.26 2,954.32 0.00-2,357.39 -1,780.66 0.00 0.00 8,400.00 28.65 216.59 7,773.01 3,002.26 0.00-2,395.89 -1,809.24 0.00 0.00 8,500.00 28.65 216.59 7,860.77 3,050.21 0.00-2,434.38 -1,837.82 0.00 0.00 8,600.00 28.65 216.59 7,948.53 3,098.15 0.00-2,472.88 -1,866.40 0.00 0.00 8,700.00 28.65 216.59 8,036.28 3,146.10 0.00-2,511.38 -1,894.98 0.00 0.00 8,800.00 28.65 216.59 8,124.04 3,194.04 0.00-2,549.87 -1,923.56 0.00 0.00 8,900.00 28.65 216.59 8,211.80 3,241.99 0.00-2,588.37 -1,952.14 0.00 0.00 9,000.00 28.65 216.59 8,299.55 3,289.93 0.00-2,626.87 -1,980.72 0.00 0.00 9,100.00 28.65 216.59 8,387.31 3,337.88 0.00-2,665.36 -2,009.30 0.00 0.00 9,200.00 28.65 216.59 8,475.07 3,385.82 0.00-2,703.86 -2,037.88 0.00 0.00 9,300.00 28.65 216.59 8,562.82 3,433.77 0.00-2,742.36 -2,066.45 0.00 0.00 9,400.00 28.65 216.59 8,650.58 3,481.71 0.00-2,780.85 -2,095.03 0.00 0.00 9,485.49 28.65 216.59 8,725.60 3,522.70 0.00-2,813.76 -2,119.47 0.00 0.00 Top Tyonek D1 9,500.00 28.65 216.59 8,738.34 3,529.66 0.00-2,819.35 -2,123.61 0.00 0.00 9,600.00 28.65 216.59 8,826.09 3,577.60 0.00-2,857.85 -2,152.19 0.00 0.00 9,700.00 28.65 216.59 8,913.85 3,625.55 0.00-2,896.34 -2,180.77 0.00 0.00 9,800.00 28.65 216.59 9,001.61 3,673.49 0.00-2,934.84 -2,209.35 0.00 0.00 9,900.00 28.65 216.59 9,089.36 3,721.44 0.00-2,973.34 -2,237.93 0.00 0.00 10,000.00 28.65 216.59 9,177.12 3,769.38 0.00-3,011.83 -2,266.51 0.00 0.00 10,100.00 28.65 216.59 9,264.88 3,817.33 0.00-3,050.33 -2,295.09 0.00 0.00 10,200.00 28.65 216.59 9,352.63 3,865.27 0.00-3,088.83 -2,323.67 0.00 0.00 10,285.48 28.65 216.59 9,427.65 3,906.26 0.00-3,121.74 -2,348.10 0.00 0.00 Total Depth : 10285.49' MD, 9427.65' TVD - 4 1/2" x 6 3/4" Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Design Targets LongitudeLatitude Dip Angle (°) Dip Dir. (°) KU 23-07A wp01 tgt1 6,036.60 2,359,775.000 273,752.000-1,634.16 -1,243.740.00 0.00 60° 27' 12.008 N 151° 15' 11.383 W - plan hits target center - Point KU 23-07A wp02 tgt2 8,725.60 2,358,612.000 272,854.000-2,814.00 -2,119.610.00 0.00 60° 27' 0.388 N 151° 15' 28.841 W - plan misses target center by 0.24usft at 9485.62usft MD (8725.71 TVD, -2813.81 N, -2119.50 E) - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 10 3/4" x 13 1/2"1,600.001,646.60 10-3/4 13-1/2 7 5/8" x 9 7/8"6,000.006,379.86 7-5/8 9-7/8 4 1/2" x 6 3/4"9,427.6510,285.48 4-1/2 6-3/4 8/30/2024 10:49:18AM COMPASS 5000.17 Build 02 Page 6 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: KU 23-07Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db KU 23-07A @ 83.60usftTVD Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftMD Reference:Kenai Gas FieldProject: TrueNorth Reference:KGF 41-7 PadSite: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Well: KU 23-07Wellbore: KU 23-07A wp02Design: Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 3,578.58 Top Pool 3_A63,397.60 3,979.46 Top Pool 43,770.60 4,094.46 Top Pool 53,877.60 4,683.42 Top Pool 64,425.60 4,927.39 Top Upper Beluga4,652.60 5,608.78 Top Middle Beluga5,286.60 6,421.33 Top Lower Beluga6,036.60 7,710.12 Top Upper Tyonek7,167.60 9,485.49 Top Tyonek D18,725.60 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 500.00 500.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD 1,216.51 1,199.82 -105.68 -80.49 End Dir : 1216.51' MD, 1199.82' TVD 6,182.63 5,820.54 -1,553.32 -1,183.05 Start Dir 3º/100' : 6182.63' MD, 5820.54'TVD 6,421.33 6,036.60 -1,634.16 -1,243.74 End Dir : 6421.33' MD, 6036.6' TVD 10,285.49 9,427.65 -3,121.74 -2,348.10 Total Depth : 10285.49' MD, 9427.65' TVD 8/30/2024 10:49:18AM COMPASS 5000.17 Build 02 Page 7 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) 30 August, 2024 Anticollision Summary Report Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 23-07 KU 23-07 KU 23-07A wp02 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Anticollision Summary Report Well Plan: KU 23-07Local Co-ordinate Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftTVD Reference:Kenai Gas FieldProject: KU 23-07A @ 83.60usftMD Reference:KGF 41-7 PadReference Site: TrueNorth Reference:0.00 usftSite Error: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Reference Well: Output errors are at 2.00 sigmaWell Error:0.00 usft Reference Wellbore KU 23-07 Database:EDM 5000.17 Single User Db Reference DatumReference Design:KU 23-07A wp02 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Ellipsoid Separation GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.00usft Unlimited Maximum centre distance of 1,226.75usft KU 23-07A wp02 Results Limited by: SigmaWarning Levels Evaluated at:2.00 Added to Error ValuesCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 8/30/2024 3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & axial + sag corr.18.00 1,674.00 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & axial + sag corr.1,674.00 6,380.00 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & axial + sag corr.6,380.00 10,285.49 KU 23-07A wp02 (KU 23-07) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance KGF 41-7 Pad CCKBU 11-08Z - KBU 11-08Z - KBU 11-08Z 18.00 18.10 81.36 80.35 80.492 ESKBU 11-08Z - KBU 11-08Z - KBU 11-08Z 225.00 224.54 81.82 79.65 37.852 SFKBU 11-08Z - KBU 11-08Z - KBU 11-08Z 625.00 618.47 99.89 94.85 19.844 CCKBU 31-06X - KBU 31-06X - KBU 31-06X 631.63 641.19 112.64 96.11 6.814 ESKBU 31-06X - KBU 31-06X - KBU 31-06X 650.00 659.59 112.75 95.98 6.721 SFKBU 31-06X - KBU 31-06X - KBU 31-06X 700.00 708.73 114.45 97.03 6.572 CCKBU 42-6X - KBU 42-6X - KBU 42-6X 18.00 21.34 176.49 175.37 157.555 ESKBU 42-6X - KBU 42-6X - KBU 42-6X 25.00 29.20 176.49 175.06 123.583 SFKBU 42-6X - KBU 42-6X - KBU 42-6X 1,425.00 1,209.00 541.55 529.53 45.060 CCKBU 43-7X - KBU 43-7X - KBU 43-7X 2,949.97 3,278.18 164.89 130.59 4.808 ESKBU 43-7X - KBU 43-7X - KBU 43-7X 3,000.00 3,322.44 166.48 128.77 4.415 SFKBU 43-7X - KBU 43-7X - KBU 43-7X 3,100.00 3,410.37 179.14 135.85 4.138 CCKDU-04 - KDU-04 - KDU-04 2,257.50 2,397.97 239.98 194.77 5.307 ESKDU-04 - KDU-04 - KDU-04 2,450.00 2,586.13 242.91 190.71 4.654 SFKDU-04 - KDU-04 - KDU-04 5,500.00 5,590.00 618.84 470.46 4.171 CCKDU-04 - KDU-04RD - KDU-04RD 2,257.50 2,397.97 239.98 195.04 5.340 ESKDU-04 - KDU-04RD - KDU-04RD 2,450.00 2,586.13 242.91 190.98 4.678 SFKDU-04 - KDU-04RD - KDU-04RD 8,850.00 8,900.00 715.06 364.19 2.038 CCKDU-10 - KDU 10 - KDU 10 518.42 519.22 77.88 73.45 17.557 ESKDU-10 - KDU 10 - KDU 10 600.00 600.70 78.23 73.22 15.629 SFKDU-10 - KDU 10 - KDU 10 875.00 873.50 89.82 82.84 12.876 CCKTU 32-07 - KTU 32-7 - KTU 32-7 18.00 21.00 597.50 596.54 619.857 ESKTU 32-07 - KTU 32-7 - KTU 32-7 5,650.00 5,953.40 612.96 563.40 12.368 SFKTU 32-07 - KTU 32-7 - KTU 32-7 6,150.00 6,392.49 641.14 585.08 11.436 CCKU 14-05 - KU 14-05 - KU 14-05 376.13 377.03 40.26 35.77 8.959 ESKU 14-05 - KU 14-05 - KU 14-05 501.58 502.51 40.26 35.12 7.836 SFKU 14-05 - KU 14-05 - KU 14-05 575.00 575.36 41.96 36.39 7.539 CCKU 24-05B - KU 24-05B - KU 24-05B 18.00 18.50 148.52 146.79 85.874 ESKU 24-05B - KU 24-05B - KU 24-05B 350.00 346.27 149.57 137.93 12.847 SFKU 24-05B - KU 24-05B - KU 24-05B 400.00 392.53 151.64 139.06 12.058 CCKU 41-08 - KU 41-08 - KU 41-08 850.00 850.37 36.32 29.54 5.353 ES, SFKU 41-08 - KU 41-08 - KU 41-08 851.13 851.43 36.33 29.53 5.349 CCKU 43-7 - KU 43-7 - KU 43-7 1,001.13 1,068.82 139.79 125.70 9.919 ESKU 43-7 - KU 43-7 - KU 43-7 1,025.00 1,092.50 140.00 125.47 9.639 8/30/2024 10:50:12AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 2 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Anticollision Summary Report Well Plan: KU 23-07Local Co-ordinate Reference:Hilcorp Alaska, LLCCompany: KU 23-07A @ 83.60usftTVD Reference:Kenai Gas FieldProject: KU 23-07A @ 83.60usftMD Reference:KGF 41-7 PadReference Site: TrueNorth Reference:0.00 usftSite Error: Minimum CurvatureSurvey Calculation Method:Plan: KU 23-07Reference Well: Output errors are at 2.00 sigmaWell Error:0.00 usft Reference Wellbore KU 23-07 Database:EDM 5000.17 Single User Db Reference DatumReference Design:KU 23-07A wp02 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance KGF 41-7 Pad SFKU 43-7 - KU 43-7 - KU 43-7 1,275.00 1,334.84 161.23 141.42 8.140 No-Go Zone - Stop DrillingPlan: KU 34-05 - KU 34-05 - KU 34-05 wp04 603.55 603.50 0.05 -5.14 0.011 8/30/2024 10:50:12AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 3 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) 0.001.002.003.004.00Separation Factor550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured Depth (1100 usft/in)KBU 43-7XKDU-04RDKDU-04KU 34-05 wp04No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: KU 23-07 NAD 1927 (NADCON CONUS) Alaska Zone 0465.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.002361385.266275026.38560° 27' 28.102 N151° 14' 46.586 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 23-07, True NorthVertical (TVD) Reference: KU 23-07A @ 83.60usftMeasured Depth Reference:KU 23-07A @ 83.60usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-08-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1674.00 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag1674.00 6380.00 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag6380.00 10285.49 KU 23-07A wp02 (KU 23-07) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured Depth (1100 usft/in)KU 24-05BKDU 10KU 14-05Project: Kenai Gas FieldSite: KGF 41-7 PadWell: Plan: KU 23-07Wellbore: KU 23-07Plan: KU 23-07A wp02CASING DETAILSTVD MD Name Size1600.00 1646.60 10 3/4" x 13 1/2" 10-3/46000.00 6379.86 7 5/8" x 9 7/8" 7-5/89427.65 10285.48 4 1/2" x 6 3/4" 4-1/2You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KENAI 224-126 KU 23-07A TYONEK GAS 1 1 McLellan, Bryan J (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Sunday, October 27, 2024 10:48 AM To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: KU 23-07A PTD application Attachments:KU 23-07A_wp02_v2.pdf Bryan, 89 bbls of displacement sounds good. 660’ schematic attached. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, October 23, 2024 12:18 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: KU 23-07A PTD application Sean, FYI, we are just waiting on this info before Ʊnishing up the permit application. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Thursday, October 17, 2024 1:01 PM To: Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Subject: KU 23-07A PTD application Sean, Can you double check your displacement calculations for the 3.5” long string production casing in this well? I calculate 88.6 bbls displacement vs. 112.9 bbls displacement in the PTD. 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. 2 Also, please send the aerial photo with the 660’ radius around the surface location to inform SSSV requirements. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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. WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:KENAI UNIT 23-07AInitial Class/TypeDEV / PENDGeoArea820Unit51120On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241260KENAI, TYONEK GAS - 448570NA1 Permit fee attachedYes FEE A0281422 Lease number appropriateYes3 Unique well name and numberYes KENAI, TYONEK GAS 1 - 448570 - governed by CO 510B4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 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)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA Diverter waiver approved.27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 3394 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 shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes Measures not required. Nearby wells did not encounter H2S gas.35 Permit can be issued w/o hydrogen sulfide measuresYes Sterling to Upper Beluga expected to be under-pressured to severely under-pressured with Middle 36 Data presented on potential overpressure zonesNA Beluga sands normally pressured and Upper Tyonek expected to be overpressured (10.2 ppg EMW).37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/23/2024ApprBJMDate10/17/2024ApprADDDate10/22/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 10/29/2024
