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Home My WebLink About224-0681. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,469 feet 5,460 & 5,491 feet true vertical 6,846 feet 5,427' (fish)feet Effective Depth measured 5,450 feet 2,932 feet true vertical 4,859 feet 2,578 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 3-1/2" 9.3# / L-80 2,925' MD 2,573' TVD Packers and SSSV (type, measured and true vertical depth)LTP; N/A 2,932' MD 2,578' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Sterling-Beluga Gas 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Chad Helgeson, Operations Engineer 325-201 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 01994 0 00 352 measured TVD 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-068 50-283-20197-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0017658 Beluga River / Sterling-Beluga Gas Beluga River Unit (BRU) 241-26 Plugs Junk measured Length Production Liner 4,580' Casing Structural 6,846'7,468' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 3,138' 10,540psi 2,980psi 6,890psi 10,160psi 3,138'2,742' Burst Collapse 1,410psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:56 pm, May 16, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.16 13:42:46 - 08'00' Noel Nocas (4361) BJM 8/12/25 DSR-6/3/25 RBDMS JSB 052125 Page 1/1 Well Name: BRU 241-26 Report Printed: 4/23/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20197-00-00 Field Name:Beluga River (BRU)State/Province:ALASKA Permit to Drill (PTD) #:224-068 Sundry #:325-201 Rig Name/No: Jobs Actual Start Date:11/7/2024 End Date: Report Number 26 Report Start Date 4/9/2025 Report End Date 4/10/2025 Last 24hr Summary PJSM, Crew mob to pad, Spot in & rig up, Nipple up BOPE & manifold, Secure well. Report Number 27 Report Start Date 4/10/2025 Report End Date 4/11/2025 Last 24hr Summary PJSM, Crew travel to location, Spot in pump & rig up lines, Wait on chain for reel & mechanic, Install leveling arm & stab into injector, Pick up injector head & lube, Pull test-good, Load reel with fluid, Pressure test connection-good, Pressure test BOPE 250-low, 3000-high, (Witness waived by Jim Regg), Secure well & rig down for the night. Report Number 28 Report Start Date 4/11/2025 Report End Date 4/12/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up injector & lube, Pump wiper ball with 45 bbls, Unstab Pick up BHA ( 1 x check 2.12 OD, 1 x wt bar 2.25", 1 x nozzle 5 ports 2.13" OD), Run in the hole to tag @ 5278, Pick up & get circulating pressures, Run in & wash f/ 5278-t/5460, Circulate 1.5 hole volume, Pull out of hole, Spot in & rig up Pollard slick line, Pick up lube & tools (LIB), Pressure test 250/3000-good, Run in hole tag 5453', Pull out of hole, Pick up fishing assembly, Run in the hole tag fish 5453', Jar & shear, Pull out of hole, Run in hole with JDC, Tag & latch @ 5453', Jar 5x @ 3200 lbs, Fish free, Pull out of hole, Attempt to close to swab (11 of 24), PJSM, Discuss open hole operations & people placement, Open needle valve no pressure, Monitor returns tank no returns well dead, Pull lube & pick up tool assembly & fish to clear tree, Secure well with swab 24 of 24 turns, 100% of fish recovered, Break down fish & fishing assembly, Lay down lube for the night. Report Number 29 Report Start Date 4/12/2025 Report End Date 4/13/2025 Last 24hr Summary PJSM, Crew mob to location, Spot in & rig up, Pick up lube & tool string (BHA), Pressure test 250/3000-good, Run in the hole Correlate, Set CIBP @ 5460, Pull out of the hole, Rig down & release AK Eline, Pick up lube & injector with reverse nozzle, Pressure test lube & injector to 3000-good, Run in the hole to tag @ 5493, Pick up to 5492, Start & cool N2 pump, Reverse circulate fluid, Recovering 85 bbls. Calculated: 82 bbls, Trap 1330 psi N2 psi on well while pulling out of the hole, Rig down & Release Fox coil tubing Report Number 30 Report Start Date 4/15/2025 Report End Date 4/16/2025 Last 24hr Summary PJSM, Crew travel to IRU, Mob equipment to G-pad, Spot in & rig up equipment, Pick up lube & bailer, Pressure test 250/2500-good, Run in hole with bailer (3.6 gal cmt), Tag plug @ 5460, Bail 3.6 gal est TOC @ 5450', Pull out of hole, RIg down, Load guns, Rig up party ball for perfing, Pick up lube & tools, Pressure test 250/2500-good, Run in hole, Correlate, Perf BEL G3 (5419-5435), Pull out of hole, Pick up run #2, Run in the hole, Correlate, Perf BEL G2 (5373-5387), Pull out of hole, Secure well & rig down for the night Report Number 31 Report Start Date 4/18/2025 Report End Date 4/19/2025 Last 24hr Summary R/u e-line. Pressure test lubricator250/3000psi, good test. RIH w/ 2-3/8"x6' gun. Correlate and perf Beluga G 5354'-5360'. Instantly gain weight, p/u to safe pull, tool not coming free. Flow well and try working tool string free multiple times at different flow rates with no luck. Pull wire free of rope socket, all wire recovered. R/d e- line, r/u slick line. RIH w/ 2.5" LIB tagging fish at 5349'kb, got impression of rope socket. RIH w/ 2"JDC bated w/ 2-1/2" JUC latch onto fish, one jar lick slipped off. POOH, pin not sheared. Secure well, SDFN. Report Number 32 Report Start Date 4/19/2025 Report End Date 4/20/2025 Last 24hr Summary R/u slick line. SITP 495psi. RIH w/ 2" JDC, tagging fish at 5352'KB, only getting friction bites, pin not sheared. RIH w/ 2.35" LIB tag fish at 5354' KB, fish falls to5421'. LIB showing rope socket impression. RIH w/ 2"JDC, only getting friction bites, pin did not shear. RIH JDC w/o bell guide, cant latch. RIH w/ KJ, cent, w/ 2" JUC, get 4 jar licks and comes off, pin not sheared. RIH w/ JUC w/ bell guide, 1 jar lick and comes off, pin sheared. RIH w/ JDC w/ bell guide, 1 jar lick and comes free, pin not sheared. Final tag depth of fish=5427'KB. Secure well SDFN. Report Number 33 Report Start Date 4/20/2025 Report End Date 4/21/2025 Last 24hr Summary R/u slickline. SITP 497psi. RIH w/ 2.7" LIB, tag at 5426'kb., POOH, got impression of top of rope socket off to one side and cocked. RIH w/ 2.75" cent w2" RS w/ 2.6" bell guide to 5427'kb. Work tool, can not latch fish. POOH. RIH w/2 KJ, w/ 2" RS w/ 2.6" bell guide to 5427'kb. Work tool, can not latch fish. POOH. RDMO slick line. MIRU e-line. PT lubricator 250/2500psi, good test. RIH w/ 2-3/8"x4' Perf gun, shoot Beluga G 5335'-5339'. RIH w/ 2"x10' Perf gun, shoot Beluga F10 5260'- 5270'. RIH w/ 2"x8' Perf gun, shoot Beluga F6 5058'-5066'. RIH w/ 2"x8' Perf gun,, shoot Beluga F2 4913'-4921'. All shots had SITP fluctuate between 503-507psi, all shots fired on guns, all guns dry. L/d lubricator, secure well, SDFN. p, Perf BEL G2 (5373-5387), shoot Beluga F2 4913'-4921 p,g shoot Beluga F6 5058'-5066 Run in hole with bailer (3.6,,qpp,p gal cmt), Tag plug @ 5460, Bail 3.6 gal est TOC @ 5450', g shoot Beluga G 5335'-5339'.g Fish free perf Beluga G 5354'-5360 Perf BEL G3 (5419-5435 @, shoot Beluga F10 5260'- 5270' Updated by CAH 05-07-25 SCHEMATIC Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD Max dev 40deg @ 2058’ RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,888’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.780”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’4”6.540”Ranger Liner Hanger w/ Scout liner to packer 5 5,460’CIBP w/ 10ft of cement - TOC @ 5,450’ (4/15/25) 6 5,491’CIBP (11/12/24) OPEN HOLE / CEMENT DETAIL 7-5/8"Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2”Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status Pool Top Sterling A1 – 3,392’ MD / 2,949’ TVD Beluga F2 4,913’4,921’4,331’4,339’8 4/20/25 Open Beluga F6 5,058’5,066’4,473’±4,493’8 4/20/25 Open Beluga F10 5,260’5,270’4,711’4,718’10 4/20/25 Open Beluga G 5,335’5,339’4,765’4,771’4 4/2025 Open Beluga G 5,354’5,360’4,784’4,797’6 4/18/25 Open Beluga G2 5,373’5,387’4,812’4,818’14 4/15/25 Open Beluga G3 5,419’5,435’4,828’4,844’16 4/15/25 Open Beluga G4 5,475’5,488’4,884’4,896’13 11/15/24 Isolated Beluga G5 5,495’5,501’4,903’4,909’6 8/13/24 Isolated Beluga G6 5,517’5,530’4,925’4,938’13 8/13/24 Isolated Beluga G7 5,542’5,548’4,950’4,956’6 8/13/24 Isolated Beluga G9 5,564’5,586’4,972’4,993’22 8/13/24 Isolated Beluga H2 5,742’5,773’5,146’5,177’31 8/13/24 Isolated Beluga H3 5,794’5,800’5,198’5,204’6 8/12/24 Isolated Beluga H4 5,814’5,824’5,217’5,227’10 8/12/24 Isolated Beluga H7 5,913’5,939’5,315’5,341’26 8/12/24 Isolated Beluga I 6,364’6,378’5,759’5,773’14 8/12/24 Isolated NOTES ***GR/JB & plug setting tool will stick in gap at liner top packer, or a small tool string because of mule shoe on low side of pipe. See wellfile pics for details A second liner hanger/packer was run due to the first packer leaking, July 2024 Fish Eline Perf tool string @ 5427’. 1-3/8” fish neck GR/CCL, weight bar, 7ft of 2-3/8” guns (OAL- 24.3ft) Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3/4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ *** 6 5 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/08/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250508 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 241-26 50283201970000 224068 4/15/2025 AK E-LINE Perf BRU 244-27 50283201850000 222038 4/19/2025 AK E-LINE Perf IRU 11-06 50283201300000 208184 4/14/2025 AK E-LINE CIBP PBU S-22B 50029221190200 197051 4/15/2025 AK E-LINE IPROF SRU 231-33 50133101630100 223008 4/13/2025 AK E-LINE CIBP PBU 14-33B 50029210020200 223067 1/22/2025 BAKER MRPM END 1-65A 50029226270100 203312 4/15/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON LDL END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON MFC40 MPU R-105 50029238150000 225017 4/20/2025 HALLIBURTON CAST-CBL NS-19 50029231220000 202207 4/12/2025 HALLIBURTON RBT PBU 06-12B 50029204560200 211115 3/22/2025 HALLIBURTON RBT PBU 07-22A 50029209250200 212085 3/31/2025 HALLIBURTON RBT PBU B-30B 50029215420100 201105 4/9/2025 HALLIBURTON RBT-COILFLAG PBU H-17A 50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU H-29B 50029218130200 225005 5/1/2025 HALLIBURTON RBT PBU J-10B 50029204440200 215112 4/15/2025 HALLIBURTON RBT PBU M-207 50029238070000 224141 4/21/2025 HALLIBURTON IPROF PBU Z-25 50029219020000 188159 4/23/2025 HALLIBURTON IPROF PBU Z-31 50029218710000 188112 4/25/2025 HALLIBURTON IPROF Please include current contact information if different from above. T40372 T40373 T40374 T40375 T40376 T40377 T40378 T40379 T40379 T40380 T40381 T40382 T40383 T40384 T40385 T40386 T40387 T40388 T40389 T40390 BRU 241-26 50283201970000 224068 4/15/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.08 12:42:44 -08'00' DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 9 7 - 0 0 - 0 0 We l l N a m e / N o . BE L U G A R I V U N I T 2 4 1 - 2 6 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 8/ 1 2 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 6 8 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 74 6 9 TV D 68 4 6 Cu r r e n t S t a t u s 1- G A S 5/ 8 / 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 7 - 2 4 & 7 - 3 1 - 2 4 , L W D ( D G R , P C G , A D R , C T N , A L D , P W D , D D S R ) , T i e I n / P e r f L o g s No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 7/ 3 0 / 2 0 2 4 88 7 4 6 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : B R U 2 4 1 - 2 6 LW D F i n a l . l a s 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l M D . c g m 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l T V D . c g m 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 - 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 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 - F i n a l S u r v e y s . x l s x 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 D S R _ G e o . t x t 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 D S R _ G I S . t x t 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 _ D S R Ac t u a l _ P l a n . p d f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 _ D S R Ac t u a l _ V S e c . p d f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l M D . e m f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l T V D . e m f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l M D . p d f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l T V D . p d f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l M D . t i f 39 3 2 5 ED Di g i t a l D a t a DF 7/ 3 0 / 2 0 2 4 E l e c t r o n i c F i l e : B R U 2 4 1 - 2 6 L W D F i n a l T V D . t i f 39 3 2 5 ED Di g i t a l D a t a DF 8/ 1 3 / 2 0 2 4 29 8 0 1 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 : B R U _ 2 4 1 - 26 _ C B L _ 2 4 - J u l y - 2 0 2 4 _ ( 4 9 6 0 ) . l a s 39 4 2 1 ED Di g i t a l D a t a DF 8/ 1 3 / 2 0 2 4 73 0 6 2 6 9 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 : B R U _ 2 4 1 - 26 _ C a l i p e r _ 3 1 - J u l y - 2 0 2 4 _ ( 4 9 6 7 ) . l a s 39 4 2 1 ED Di g i t a l D a t a Th u r s d a y , M a y 8 , 2 0 2 5 AO G C C P a g e 1 o f 3 BR U 2 4 1 - 2 6 LW D F i n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 9 7 - 0 0 - 0 0 We l l N a m e / N o . BE L U G A R I V U N I T 2 4 1 - 2 6 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 8/ 1 2 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 6 8 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 74 6 9 TV D 68 4 6 Cu r r e n t S t a t u s 1- G A S 5/ 8 / 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 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 Co m p l e t i o n D a t e : 8/ 1 2 / 2 0 2 4 Re l e a s e D a t e : 6/ 1 3 / 2 0 2 4 DF 8/ 1 3 / 2 0 2 4 73 3 4 6 9 3 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 : B R U _ 2 4 1 - 26 _ C B L _ 3 1 - J u l y - 2 0 2 4 _ ( 4 9 6 7 ) . l a s 39 4 2 1 ED Di g i t a l D a t a DF 8/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : B R U _ 2 4 1 - 2 6 _ C B L _ 2 4 - J u l y - 20 2 4 _ ( 4 9 6 0 ) . p d f 39 4 2 1 ED Di g i t a l D a t a DF 8/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : B R U _ 2 4 1 - 2 6 _ C a l i p e r _ 3 1 - J u l y - 20 2 4 _ ( 4 9 6 7 ) . p d f 39 4 2 1 ED Di g i t a l D a t a DF 8/ 1 3 / 2 0 2 4 E l e c t r o n i c F i l e : B R U _ 2 4 1 - 2 6 _ C B L _ 3 1 - J u l y - 20 2 4 _ ( 4 9 6 7 ) . p d f 39 4 2 1 ED Di g i t a l D a t a DF 8/ 2 7 / 2 0 2 4 64 2 6 5 3 9 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : B R U _ 2 4 1 - 26 _ P e r f _ 1 2 - A u g u s t - 2 0 2 4 _ ( 4 9 9 7 ) . l a s 39 4 9 4 ED Di g i t a l D a t a DF 8/ 2 7 / 2 0 2 4 E l e c t r o n i c F i l e : B R U _ 2 4 1 - 2 6 _ P e r f _ 1 2 - A u g u s t - 20 2 4 _ ( 4 9 9 7 ) . p d f 39 4 9 4 ED Di g i t a l D a t a DF 12 / 5 / 2 0 2 4 54 8 2 5 3 6 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : B R U _ 2 4 1 - 26 _ P l u g _ P e r f _ 1 2 - N o v e m b e r - 2 0 2 4 _ ( 5 1 6 8 ) . l a s 39 8 1 2 ED Di g i t a l D a t a DF 12 / 5 / 2 0 2 4 E l e c t r o n i c F i l e : B R U _ 2 4 1 - 2 6 _ P l u g _ P e r f _ 1 2 - No v e m b e r - 2 0 2 4 _ ( 5 1 6 8 ) . p d f 39 8 1 2 ED Di g i t a l D a t a DF 4/ 2 8 / 2 0 2 5 54 6 6 5 2 9 5 E l e c t r o n i c D a t a S e t , F i l e n a m e : B R U _ 2 4 1 - 26 _ C I B P _ 1 2 - A p r i l - 2 0 2 5 _ ( 5 3 9 3 ) . l a s 40 3 3 0 ED Di g i t a l D a t a DF 4/ 2 8 / 2 0 2 5 E l e c t r o n i c F i l e : B R U _ 2 4 1 - 2 6 _ C I B P _ 1 2 - A p r i l - 20 2 5 _ ( 5 3 9 3 ) . p d f 40 3 3 0 ED Di g i t a l D a t a Th u r s d a y , M a y 8 , 2 0 2 5 AO G C C P a g e 2 o f 3 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 2 8 3 - 2 0 1 9 7 - 0 0 - 0 0 We l l N a m e / N o . BE L U G A R I V U N I T 2 4 1 - 2 6 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 8/ 1 2 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 0 6 8 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 74 6 9 TV D 68 4 6 Cu r r e n t S t a t u s 1- G A S 5/ 8 / 2 0 2 5 UI C No 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 : Da t e C o m m e n t s De s c r i p t i o n Th u r s d a y , M a y 8 , 2 0 2 5 AO G C C P a g e 3 o f 3 5/ 8 / 2 0 2 5 M. G u h l 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: CTCO, 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): 7,469'5,313' (fish) Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate 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 chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017658 224-068 50-283-20197-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 2,925' 10,160psi 2,742' Size 120' 3,138' MD See Attached Schematic 2,980psi 6,890psi 120'120' 3,138' April 15, 2025 Tieback 3-1/2" 7,468' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 241-26CO 802A Same 6,846'3-1/2" 1897psi 4,580' 5,491' Length LTP; N/A 2,932' MD/2,578' TVD; N/A 6,846'5,491'4,899' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:45 am, Apr 03, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.02 11:29:54 - 08'00' Noel Nocas (4361) 325-201 X SFD 4/4/2025 10-404 CT BOP test to 3000 psi BJM 4/3/25 DSR-4/7/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.07 15:22:50 -08'00'04/07/25 RBDMS JSB 052125 Well Prognosis Well Name: BRU 241-26 API Number: 50-283-20197-00-00 Current Status: SI Gas Well Permit to Drill Number: 224-068 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 2082 psi @ 4844’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1897 psi (Based on 0.038 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.74 psi/ft using 14.17 ppg EMW FIT at the surface casing shoe 7/16/24 Shallowest Potential Perf TVD: MPSP/(0.74-0.038) = 1615 psi / 0.702 = 2702‘ TVD (above top of pool) Top of Pools per CO 802a: Sterling-Beluga Gas Pool: 3,392’ MD, ~2949' TVD Well Status: SI gas well with an Eline fish Brief Well Summary: BRU 241-26 was drilled during the 2024 Beluga River drilling campaign targeting the Sterling and Beluga sands. It was perforated and brought online in August 2024. The well flowed steady until October 2024, when it started slugging and making sand to surface. The zones were plugged back and a G4 sand was perforated. When checking fluid level for another plug set, the tools because stuck and Eline pulled out of the rope socket. Coil was unavailable over the winter, so slickline was used multiple times to recover the fish, but were unsuccessful. The objective of this sundry is to kill the well, cleanout & recover the fish, set a plug above Beluga G4 Sand, blow well dry with N2 and add more perforations to return the well to production. All proposed sands lie in the Sterling-Beluga Gas Pool. Wellbore Conditions: Current flowrate: SI, Fluid packed, TP- 0 psi The well has a 3.5” cemented liner Current open perfs to Beluga G4 Sands @ 5475-5488’ SL tag depth: 5313’ on 2/1/25 Eline Fish in well – GPT tools 33.70’ OAL below 5313’ (possible strands of SL 3-6” long) Procedure: 1. Review all approved COAs 2. MIRU Fox Coil Tubing unit with 1.75” Coil and pressure control equipment (enough lubricator to cover tools and 34’ fish) 3. PT lubricator to 250 psi low/ 3000 psi high a. Provide AOGCC 48 hr notice for BOP test 4. RIH and clean out wellbore to top of fish (~5313’ MD), keep well full with 8.4 ppg water 5. POOH and PU fish assembly 6. RIH and fish Eline tool string with coil x Latch/bait fish w/ SL if necessary x Potential for short pieces of SL wire in the well that may need to be removed with RCJB on coil Contingency (Open Hole fishing procedure If unable to close well with fish attached to coil -i.e. fish is too long) i. Once fish at surface and valves will not close ii. Confirm fluid at surface by pumping across flow cross iii. Shut down pump and monitor well for 15 minutes (no flow check) add more perforations Well Prognosis iv. Hold safety meeting 1. Crew and WSS to discuss plan and procedure in case of kick with lubricator removed 2. Review kick contingencies to cover at a minimum: a. Lift fish clear and close tree valves valves b. Lift fish clear and close BOP shear valves c. Stab back on to well v. Once well is confirmed dead and personnel monitoring trip tank while pumping across flow cross vi. Break off lubricator and lift tool string out of well. vii. Once tool string clear of tree valves close swab. 7. Once fish is removed, PU wash nozzle, RIH and clean well out to CIBP at 5491’ 8. MIRU E-line, PT lubricator to 2500 psi on top of Coil BOPE 9. RIH and set CIBP plug above G4 sand at ~5,460’ 10. PU bailer and dump ~10ft of cement on plug (1 bailer run) x A 10ft cement plug in 3.5” tubing will hold a differential pressure of >10,000psi differential. 11. RDMO Eline 12. PU nozzle without check valves, RIH to 10ft above the plug (do not tag cement) a. Reverse circulate water b. Target recovery = ~47bbls 13. RDMO CT 14. Leave N2 pressure on well when coil is rigged down 15. MIRU E-line and pressure control equipment 16. PT lubricator to 250psi low / 2500psi high 17. Ops will bleed pressure off well to planned perforating pressure determined by OE/RE 18. Perforate and test Beluga sands within the interval below, from the bottom up: a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. b. Pending well production, all perf intervals may not be completed Formation MD TOP MD BASE TVD TOP TVD BASE H Top Pool ~3,392’ ~2,949' Beluga F1 ±4,889’ ±4,897’ ±4,309’ ±4,315’ ±8 Beluga F2 ±4,913’ ±4,921’ ±4,331’ ±4,339’ ±8 Beluga F2 ±4,977’ ±4,982’ ±4,459’ ±4,468’ ±5 Beluga F6 ±5,058’ ±5,066’ ±4,473’ ±4,493’ ±8 Beluga F7 ±5,222’ ±5,234’ ±4,671’ ±4,683’ ±12 Beluga F10 ±5,259’ ±5,271’ ±4,712’ ±4,719’ ±12 Beluga F10 ±5,301’ ±5,308’ ±4,744’ ±4,749’ ±7 Beluga G ±5,334’ ±5,339’ ±4,765’ ±4,770’ ±5 Beluga G ±5,355’ ±5,360’ ±4,783’ ±4,797’ ±5 Beluga G2 ±5,373’ ±5,387’ ±4,812’ ±4,818’ ±14 Beluga G3 ±5,419’ ±5,435’ ±4,828’ ±4,844’ ±16 Less than 25' of cement on plug will be acceptable due to small window between old & new perfs. -bjm Well Prognosis c. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations d. Above perfs are in the Sterling-Beluga Gas Pool governed by CO 802A 19. RDMO Eline 20. Turn well over to production & flow test well 21. Test SVS as necessary once well has reached stabile flow rates Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 2. Provide AOGCC 24hrs notice of BOP test 3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 4. 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 5. RDMO coil tubing Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure Updated by DMA 03-31-25 SCHEMATIC Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD Max dev 40deg @ 2058’ RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,888’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.780”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’4”6.540”Ranger Liner Hanger w/ Scout liner to packer 5 5,491’CIBP (11/12/24) OPEN HOLE / CEMENT DETAIL 7-5/8"Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2”Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status Pool Top Sterling A1 – 3,392’ MD / 2,949’ TVD Beluga G4 5,475’5,488’4,884’4,896’13 11/15/24 Open Beluga G5 5,495’5,501’4,903’4,909’6 8/13/24 Isolated Beluga G6 5,517’5,530’4,925’4,938’13 8/13/24 Isolated Beluga G7 5,542’5,548’4,950’4,956’6 8/13/24 Isolated Beluga G9 5,564’5,586’4,972’4,993’22 8/13/24 Isolated Beluga H2 5,742’5,773’5,146’5,177’31 8/13/24 Isolated Beluga H3 5,794’5,800’5,198’5,204’6 8/12/24 Isolated Beluga H4 5,814’5,824’5,217’5,227’10 8/12/24 Isolated Beluga H7 5,913’5,939’5,315’5,341’26 8/12/24 Isolated Beluga I 6,364’6,378’5,759’5,773’14 8/12/24 Isolated NOTES ***GR/JB & plug setting tool will stick in gap at liner top packer, or a small tool string because of mule shoe on low side of pipe. See wellfile pics for details A second liner hanger/packer was run due to the first packer leaking, July 2024 Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3/4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ *** 5 E-LINE FISH DETAIL (33.70 OAL, GPT & 4 weight bars, w/ 1.375” fish neck) Tagged Fill @ 5313 (2/2/25) Updated by CAH 03-31-25 PROPOSED Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD Max dev 40deg @ 2058’ RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,888’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.780”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’4”6.540”Ranger Liner Hanger w/ Scout liner to packer 5 ±5,460’CIBP w/ 10ft of cement 6 5,491’CIBP (11/12/24) OPEN HOLE / CEMENT DETAIL 7-5/8"Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2”Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status Pool Top Sterling A1 – 3,392’ MD / 2,949’ TVD Beluga F1 ±4,889’±4,897’±4,309’±4,315’±8 TBD PROPOSED Beluga F2 ±4,913’±4,921’±4,331’±4,339’±8 TBD PROPOSED Beluga F2 ±4,977’±4,982’±4,459’±4,468’±5 TBD PROPOSED Beluga F6 ±5,058’±5,066’±4,473’±4,493’±8 TBD PROPOSED Beluga F7 ±5,222’±5,234’±4,671’±4,683’±12 TBD PROPOSED Beluga F10 ±5,259’±5,271’±4,712’±4,719’±12 TBD PROPOSED Beluga F10 ±5,301’±5,308’±4,744’±4,749’±7 TBD PROPOSED Beluga G ±5,334’±5,339’±4,765’±4,770’±5 TBD PROPOSED Beluga G ±5,355’±5,360’±4,783’±4,797’±5 TBD PROPOSED Beluga G2 ±5,373’±5,387’±4,812’±4,818’±14 TBD PROPOSED Beluga G3 ±5,419’±5,435’±4,828’±4,844’±16 TBD PROPOSED Beluga G4 5,475’5,488’4,884’4,896’13 11/15/24 Open Beluga G5 5,495’5,501’4,903’4,909’6 8/13/24 Isolated Beluga G6 5,517’5,530’4,925’4,938’13 8/13/24 Isolated Beluga G7 5,542’5,548’4,950’4,956’6 8/13/24 Isolated Beluga G9 5,564’5,586’4,972’4,993’22 8/13/24 Isolated Beluga H2 5,742’5,773’5,146’5,177’31 8/13/24 Isolated Beluga H3 5,794’5,800’5,198’5,204’6 8/12/24 Isolated Beluga H4 5,814’5,824’5,217’5,227’10 8/12/24 Isolated Beluga H7 5,913’5,939’5,315’5,341’26 8/12/24 Isolated Beluga I 6,364’6,378’5,759’5,773’14 8/12/24 Isolated NOTES ***GR/JB & plug setting tool will stick in gap at liner top packer, or a small tool string because of mule shoe on low side of pipe. See wellfile pics for details A second liner hanger/packer was run due to the first packer leaking, July 2024 Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3/4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ *** 6 5 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. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,469 feet 5,491 feet true vertical 6,846 feet 5,313' (fish) feet Effective Depth measured 5,491 feet 2,932 feet true vertical 4,899 feet 2,578 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 3-1/2" 9.3# / L-80 2,925' MD 2,573' TVD Packers and SSSV (type, measured and true vertical depth)LTP; N/A 2,932' MD 2,578' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 10,540psi 2,980psi 6,890psi 10,160psi 3,138'2,742' Burst Collapse 1,410psi Production Liner 4,580' Casing Structural 6,846'7,468' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 3,138' measured TVD 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-068 50-283-20197-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0017658 Beluga River / Sterling-Beluga Gas Beluga River Unit (BRU) 241-26 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 00 0 3520 0 Chad Helgeson, Operations Engineer 324-626 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 1994 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 2:53 pm, Apr 02, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.02 11:02:56 - 08'00' Noel Nocas (4361) RBDMS JSB 040325 DSR-4/2/25BJM 5/2/25 Page 1/2 Well Name: BRU 241-26 Report Printed: 3/31/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20197-00-00 Field Name:Beluga River (BRU)State/Province:ALASKA Permit to Drill (PTD) #:224-068 Sundry #:324-626 Rig Name/No: Jobs Actual Start Date:11/7/2024 End Date: Report Number 1 Report Start Date 11/12/2024 Report End Date 11/13/2024 Last 24hr Summary PJSM, Crew mob to location, Spot in & rig up equipment, Nipple up BOPE, Pressure test 250/3000 as per AOGGC, Waived by Jim Regg, Make up 2.8" wash nozzle, Run in hole while filling, Wash down from 5100' to 5535', Tag @ 5535', Wash up, Wash down, Wait 45 min run in dry tag @ 5535', Pull out of hole, Lay down lube & injector, Pick up eline lube & tool string CCL/GR/PLUG (2.75"), Run in hole, Correlate, Set plug @ 5491', Pull out of hole, Work tight spot @ 2967', Tool string stuck no movement up or down, Pull out of rope socket, Pull out of the hole Secure well, Rig down. Report Number 2 Report Start Date 11/13/2024 Report End Date 11/14/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in N2 & rig up, Pick up injector head & lube, Unload reel with N2, Run in the hole to tag @ 5307', Unload hole to N2 @ surface, Recover 25 bbls. Pull out of hole, Rig down & nipple down, Mob to IRU. Report Number 3 Report Start Date 11/14/2024 Report End Date 11/15/2024 Last 24hr Summary SL MIRU, SL Fished e-line tool string and bailed fluid from 5345' to 5355'kb Report Number 4 Report Start Date 11/15/2024 Report End Date 11/16/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string (CCL/GR/GUN (2.5" x 13'), Pressure test 250/2500-good, Run in hole & correlate, Perf G4 5475-5488, Pull out of hole. Pick up run #2 (CCL/GPT), Run in hole, Fluid level @ 5250', Pull above fluid and continue to draw down & check for fluid rise in wellbore, Fluid @ 4670', Pull out of the hole, Secure well & rig down for the night. Report Number 5 Report Start Date 11/16/2024 Report End Date 11/17/2024 Last 24hr Summary PJSM, Crew travel to location, spot in N2 pump, Rig up N2, Cool down & pressure test lines to 3500 psi-good, Pressure up on well to 1500 psi, Run in hole with run #1 CCL/GPT, Fluid @ 4620', Tag @ 5300', Stuck in fill, Pull out of rope socket, Pull out of hole, Closed swab on wire and cut wire, Secure well, Rig down for the night. Call for SL crews to fish. Demobe N2 unit. Report Number 6 Report Start Date 11/17/2024 Report End Date 11/18/2024 Last 24hr Summary SL MIRU start fishing operations of eline wire and tool string. Unable to latch anything and lose wiregrab downhole. Worked tools down to 1920'. SDFN. Report Number 7 Report Start Date 11/18/2024 Report End Date 11/19/2024 Last 24hr Summary SL Swapped units because drum break failure (custom parts). Recovered baited wire grab assembly left in hole. LIB identified wire at 5253'. SDFN Report Number 8 Report Start Date 11/19/2024 Report End Date 11/20/2024 Last 24hr Summary SL latched cable at 5253'. Recovered 58' of E-line cable. latched and baited eline tools at 5304'. Unable to recover fish. Sheared off fish and will build new tool string. SDFN Report Number 9 Report Start Date 11/20/2024 Report End Date 11/21/2024 Last 24hr Summary Repair crane electronics. RIH and latch fish at 5399'. Move fish 1ft. SDFN. Report Number 10 Report Start Date 11/21/2024 Report End Date 11/22/2024 Last 24hr Summary SL conitued to fish, moved fish 5ft but unable to get off tool string. Continue to work without success. Order cutter bars. Report Number 11 Report Start Date 11/22/2024 Report End Date 11/23/2024 Last 24hr Summary SL worked wire all night, maintaining 1650# of bind. TOols moved 12ft overnight. Tools stopped moving, dropped 3 cutters bars with no success. Clamp wire, wait on kinley cutter. Leave man watch on overnight. Report Number 12 Report Start Date 11/23/2024 Report End Date 11/24/2024 Last 24hr Summary SL Crews monitored crane and lubricator overnight. Kinley cutter arrived, set tool to cut in 60 min. Drop Kinley cutter, work wire and wait for cut. Wire cut, POOH without cutter. RD AK Eline Crane, RU Pollard SL crane. Fish Kinley cutter from well at 5113'. SDFN. Report Number 13 Report Start Date 11/24/2024 Report End Date 11/25/2024 Last 24hr Summary SL Continued to fish tools, Recovered 2ea 3' Cutter bars and 6' .125 Wire. SDFN Report Number 14 Report Start Date 11/25/2024 Report End Date 11/26/2024 Last 24hr Summary SL Continue to fish, recovered 5' Flat bar, 5' cutter bar, 3.5' of 0.125 wire. LIB shows impression of tool string fish and wire folded over. SDFn Continue fishing tomorrow. Page 2/2 Well Name: BRU 241-26 Report Printed: 3/31/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 15 Report Start Date 11/26/2024 Report End Date 11/27/2024 Last 24hr Summary SL continued to fish, recovered 5' of 1.25" wire all bent up. LIB shows impression of wire next to fish neck, work to catch fish. SDFN. Report Number 16 Report Start Date 11/27/2024 Report End Date 11/28/2024 Last 24hr Summary JSA and permit, Slip and cut wire, SL continued to fish, perform multiple runs, Recovered 3.5' .125 Wire Report Number 17 Report Start Date 11/28/2024 Report End Date 11/29/2024 Last 24hr Summary SL continued to fish, retreived batied wire grab assembly from prior day and 2' of 0.125 wire JSA and permit, SL continued to fish, perform multiple runs, retreived batied wire grab assembly from prior day and 2' of 0.125 wire Report Number 18 Report Start Date 12/19/2024 Report End Date 12/20/2024 Last 24hr Summary Tag fish at 5,149' KB with 2.70" lead impression block, shows clean rope socket and possible wire mark on side. Run 2.62" magnet, magnet comes back clean. Report Number 19 Report Start Date 12/20/2024 Report End Date 12/21/2024 Last 24hr Summary Latch fish, move fish from 5,154' KB to 5,080'. Accidently bird nested drum. Cut 6,000' wire. Report Number 20 Report Start Date 12/21/2024 Report End Date 12/22/2024 Last 24hr Summary Fish slickline toolstring, recover 20'. 125 wire Report Number 21 Report Start Date 12/22/2024 Report End Date 12/23/2024 Last 24hr Summary Fish wire. Bail mud. Report Number 22 Report Start Date 12/23/2024 Report End Date 12/24/2024 Last 24hr Summary Bail to 5,326' KB, see no wire, or fish. Report Number 23 Report Start Date 12/24/2024 Report End Date 12/25/2024 Last 24hr Summary Bail from 5,328' KB to 5,333'. Report Number 24 Report Start Date 2/1/2025 Report End Date 2/2/2025 Last 24hr Summary Tag at 5,313' with 2.5" pump bailer. Got stuck, jarred out. PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string, Pressure test 250/2500-good, Run in hole w/ 2.72” GR, Tag @ 5297’, Pull out of hole, Pick up run #2 (pump bailer), Run in hole, Tag @ 5313’, Bailer stuck, Work till free, (4 hrs), Pull out of hole, Rig down & release to BRU 244-27 Report Number 25 Report Start Date 3/27/2025 Report End Date 3/27/2025 Last 24hr Summary Decision made by Engineer to closeout open sundry for perf adds and create a new sundry to cover coil fishing operations and complete the perf adds in the existing sundry #324-626. Updated by DMA 03-31-25 SCHEMATIC Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD Max dev 40deg @ 2058’ RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,888’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.780”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’4”6.540”Ranger Liner Hanger w/ Scout liner to packer 5 5,491’CIBP (11/12/24) OPEN HOLE / CEMENT DETAIL 7-5/8"Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2”Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status Pool Top Sterling A1 – 3,392’ MD / 2,949’ TVD Beluga G4 5,475’5,488’4,884’4,896’13 11/15/24 Open Beluga G5 5,495’5,501’4,903’4,909’6 8/13/24 Isolated Beluga G6 5,517’5,530’4,925’4,938’13 8/13/24 Isolated Beluga G7 5,542’5,548’4,950’4,956’6 8/13/24 Isolated Beluga G9 5,564’5,586’4,972’4,993’22 8/13/24 Isolated Beluga H2 5,742’5,773’5,146’5,177’31 8/13/24 Isolated Beluga H3 5,794’5,800’5,198’5,204’6 8/12/24 Isolated Beluga H4 5,814’5,824’5,217’5,227’10 8/12/24 Isolated Beluga H7 5,913’5,939’5,315’5,341’26 8/12/24 Isolated Beluga I 6,364’6,378’5,759’5,773’14 8/12/24 Isolated NOTES ***GR/JB & plug setting tool will stick in gap at liner top packer, or a small tool string because of mule shoe on low side of pipe. See wellfile pics for details A second liner hanger/packer was run due to the first packer leaking, July 2024 Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3/4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ *** 5 E-LINE FISH DETAIL (33.70 OAL, GPT & 4 weight bars, w/ 1.375” fish neck) Tagged Fill @ 5313 (2/2/25) Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#2025022 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 14B 50133205390200 222057 4/10/2025 AK E-LINE CBL BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP BRU 244-27 50283201850000 222038 4/8/2025 AK E-LINE Perf MPU B-21 50029215350000 186023 4/7/2025 AK E-LINE LDL MPU C-24A 50029230200100 209134 4/6/2025 AK E-LINE CBL MPU J-25 50029232070000 204073 4/5/2025 AK E-LINE JetCut NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf NCIU A-18 50883201890000 223033 4/5/2025 AK E-LINE Perf PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40328 T40329 T40330 T40331 T40332 T40333 T40334 T40335 T40336 T40337 T40338 T40339 BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.28 08:42:09 -08'00' David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Note:This revision is being re-submitted due to depth alignment issues between multiple log curves. Please replace the previously distributed files with this revision. Well: BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 FINAL LWD FORMATION EVALUATION LOGS (07/12/2024 to 07/21/2024) - REVISED DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) - REVISED Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 224-068 T39325 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.12 09:59:37 -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#20241205 Well API #PTD #Log Date Log Company Log Type AOGCC ESet AN 15(GRANITE PT ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24 MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Please include current contact information if different from above. T39808 T39809 T39810 T39810 T39811 T39812 T39813 T39813 T39814 T39815 T39816 T39817 T39818 T39819 T39820 T39820 T39821 T39822 T39823 T39823 T39823 T39823 T39824 T39825 T39826 T39827 BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.05 14:52:46 -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: 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): 7,469'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate 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 chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017658 224-068 50-283-20197-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 2,925' 10,160psi 2,742' Size 120' 3,138' MD See Attached Schematic 2,980psi 6,890psi 120'120' 3,138' November 15, 2024 Tieback 3-1/2" 7,468' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 241-26CO 802A Same 6,846'3-1/2" 1615psi 4,580' N/A Length LTP; N/A 2,932' MD/2,578' TVD; N/A 6,846' 7,435' 6,813' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.11.01 11:23:45 - 08'00' Noel Nocas (4361) 324-626 By Grace Christianson at 1:54 pm, Nov 01, 2024 SFD 11/5/2024 10-404 Perforate DSR-11/6/24BJM 11/7/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.08 08:24:47 -09'00'11/08/24 RBDMS JSB 111224 Well Prognosis Well Name: BRU 241-26 API Number: 50-283-20197-00-00 Current Status: New Drill Well Permit to Drill Number: 224-068 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP:2105 psi @ 4896’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure:1615 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient:0.74 psi/ft using 14.17 ppg EMW FIT at the surface casing shoe 7/16/24 Shallowest Potential Perf TVD:MPSP/(0.74-0.1) = 1615 psi / 0.64 = 2523‘ TVD (above top of pool) Top of Pools per CO 802a:Sterling-Beluga Gas Pool: 3,392’ MD, ~2949' TVD Well Status:Online gas Well Brief Well Summary: BRU 222-26 was drilled during the 2024 Beluga River drilling campaign targeting the Sterling and Beluga sands. It was perforated and brought online in August 2024. The pressure has depleted enough in the well to continue to add perfs, that were originally approved in drill well sundry. The objective of this sundry is to perforate multiple Beluga sands. All sands lie in the Sterling-Beluga Gas Pool. Wellbore Conditions: Current flowrate: ~2 mmscfd @ 330 psi The well has a 3.5” cemented liner Current open perfs to Beluga G5 Sands @ 5495-6378’ SL tag depth: 5550’ on 8/27/24 Procedure: 1. Review all approved COAs 2. MIRU E-line, PT lubricator to 2500 psi 3. Perforate and test Beluga sands within the interval below, from the bottom up: Pool Top (Sterling A1) 3392’ MD 2949’ TVD Planned Interval (Beluga F4-G4) 4913’ – 5488’ MD 4331’ – 4896’ TVD a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. 4. RDMO 5. Turn well over to production & flow test well Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Updated by CJD 9-9-24 Current Schematic Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 3,138’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” 2,888’ 7,468’ 3-1/2" Prod Tieback 9.3 L-80 EUE 2.992” Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 29’ 3.856” 11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’ 4” 6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’ 4.780” 5.780” 5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’ 4” 6.540” Ranger Liner Hanger w/ Scout liner to packer OPEN HOLE / CEMENT DETAIL 7-5/8" Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2” Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status Pool Top Sterling A1 - 3,709’ MD / 3,215’ TVD Beluga G5 5,495’ 5,501’ 4,903’ 4,909’ 6 ͗ϯ͐͒ϯ͓͑Open Beluga G6 5,517’ 5,530’ 4,925’ 4,938’ 13 ͗ϯ͐͒ϯ͓͑Open Beluga G7 5,542’ 5,548’ 4,950’ 4,956’ 6 ͗ϯ͐͒ϯ͓͑Open Beluga G9 5,564’ 5,586’ 4,972’ 4,993’ 22 ͗ϯ͐͒ϯ͓͑Open Beluga H2 5,742’ 5,773’ 5,146’ 5,177’ 31 ͗ϯ͐͒ϯ͓͑Open Beluga H3 5,794’ 5,800’ 5,198’ 5,204’ 6 ͗ϯ͐͑ϯ͓͑Open Beluga H4 5,814’ 5,824’ 5,217’ 5,227’ 10 ͗ϯ͐͑ϯ͓͑Open Beluga H7 5,913’ 5,939’ 5,315’ 5,341’ 26 ͗ϯ͐͑ϯ͓͑Open Beluga I 6,364’ 6,378’ 5,759’ 5,773’ 14 ͗ϯ͐͑ϯ͓͑Open NOTES A second liner hanger/packer was run due to the first packer leaking, July 2024 Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft) 3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3 4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ 3392' MD / 2949' TVD SFD Updated by CAH 10-30-24 PROPOSED Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 3,138’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” 2,888’ 7,468’ 3-1/2" Prod Tieback 9.3 L-80 EUE 2.992” Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 29’ 3.856” 11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’ 4” 6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’ 4.780” 5.780” 5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’ 4” 6.540” Ranger Liner Hanger w/ Scout liner to packer OPEN HOLE / CEMENT DETAIL 7-5/8" Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2” Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand TopMD BtmMD TopTVD Btm TVD Amt Date Status Pool Top Sterling A1 – 3,392’ MD / 2,949’ TVD Beluga F4-G6 ±4,913’ ±5,488’ ±4,331 ±4,896’"Proposed Beluga G5 5,495’ 5,501’ 4,903’ 4,909’ 6 ͗ϯ͐͒ϯ͓͑Open Beluga G6 5,517’ 5,530’ 4,925’ 4,938’ 13 ͗ϯ͐͒ϯ͓͑Open Beluga G7 5,542’ 5,548’ 4,950’ 4,956’ 6 ͗ϯ͐͒ϯ͓͑Open Beluga G9 5,564’ 5,586’ 4,972’ 4,993’ 22 ͗ϯ͐͒ϯ͓͑Open Beluga H2 5,742’ 5,773’ 5,146’ 5,177’ 31 ͗ϯ͐͒ϯ͓͑Open Beluga H3 5,794’ 5,800’ 5,198’ 5,204’ 6 ͗ϯ͐͑ϯ͓͑Open Beluga H4 5,814’ 5,824’ 5,217’ 5,227’ 10 ͗ϯ͐͑ϯ͓͑Open Beluga H7 5,913’ 5,939’ 5,315’ 5,341’ 26 ͗ϯ͐͑ϯ͓͑Open Beluga I 6,364’ 6,378’ 5,759’ 5,773’ 14 ͗ϯ͐͑ϯ͓͑Open NOTES A second liner hanger/packer was run due to the first packer leaking, July 2024 Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft) 3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3 4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ 3392' MD / 2949' TVD SFD CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Chad Helgeson To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] BRU 241-26 (Permit 224-068, Sundry 324-626) - Question Date:Tuesday, November 5, 2024 7:11:50 AM Attachments:image001.png image002.png I apologize the tops on the current schematic were the old pool tops, and weren’t updated last week when the new conservation order was issued. The proposed schematic and the procedure have the correct Pool Tops, 3392’ MD and 2949 TVD. Chad From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, November 4, 2024 5:37 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] BRU 241-26 (Permit 224-068, Sundry 324-626) - Question Chad, I’m reviewing Hilcorp’s Sundry Application to perforate BRU 241-26. I notice that the Procedure section states: And the Perforation Detail sections state: Which pool-top MD and TVD values are correct? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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): Beluga River Field GL: 23.2' BF: N/A Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number: Surface:x- y- Zone- 4 TPI:x- y- Zone- 4 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD: Total Depth:x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 16" L-80 120' 7-5/8"L-80 2,742' 3-1/2"L-80 6,845' 3-1/2"L-80 2,573' 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 3,138' 9.3# 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): 2,888'7,468' Surface 9-7/8" Driven Surface L - 440 sx / T - 174 sx SETTING DEPTH TVD ACID, FRACTURE, CEMENT SQUEEZE, ETC. Tieback Assy.Tieback TUBING RECORD L - 432 sx / T - 122 sx6-3/4" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 8/12/2024 224-068 / 324-430 / 324-443 TOP HOLE SIZE CBL 7-24 & 7-31-24, LWD (DGR, PCG, ADR, CTN, ALD, PWD, DDSR), Tie In/Perf Logs N/A N/A N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 323851 2628295 50-283-20197-00-00July 12, 2024 N/A BRU 241-26July 20, 20242054' FNL, 597' FWL, Sec 25, T13N, R10W, SM, AK 41.7' Sterling - Beluga Gas Pool ADL 17658 7,469' MD / 6,846' TVD 7,435' MD / 6,813' TVD 609' FNL, 1047' FEL, Sec 26, T13N, R10W, SM, AK CASING, LINER AND CEMENTING RECORD 404' FNL, 1317' FEL, Sec 26, T13N, R10W, 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 322233 321966 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 2629758 2629968 Choke Size: Surface Per 20 AAC 25.283 (i)(2) attach electronic information 9.2# 2,925' 2,544' Surface 84# 29.7# 120' 4.5 bbls top job in 7-5/8" x 16" annulus 0-33'Top Job - Pumped 7.5 bbls / Returned 3 bbls Water-Bbl: PRODUCTION TEST 8/13/2024 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 506200 8/27/2024 24 Flow Tubing 50 3128 N/A31280 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 By James Brooks at 3:37 pm, Sep 09, 2024 Completed 8/12/2024 JSB RBDMS JSB 091124 GBJM 1/27/25 DSR-10/14/24SFD 3/27/2025 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval Bel G5 5495' 4904' 4080' 3538' 4279' 3721' 4497' 3927' 4860' 4280' 5317' 4729' 5657' 5063' 6347' 5741' 6905' 6291' 7386' 6765' 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 Bel F Sterling C Bel G Bel J Bel D Bel E Bel H Bel I Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. 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. Bel J6 N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Drilling Manager 09/09/24 Monty M Myers Updated by CJD 9-9-24 Current Schematic Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,435’ MD / 6,813’ TVD TD = 7,468’ MD / 6,846’ TVD RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,888’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888’4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.780”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’4”6.540”Ranger Liner Hanger w/ Scout liner to packer OPEN HOLE / CEMENT DETAIL 7-5/8"Est. TOC @ Surface (75% lead excess) L – 192 bbls / T – 36 bbls 3-1/2”Est. TOC @ 2,932’ (40% excess) L – 181 bbls / T – 24 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status Pool Top Sterling A1 - 3,709’ MD / 3,215’ TVD Beluga G5 5,495’5,501’4,903’4,909’6 8/13/24 Open Beluga G6 5,517’5,530’4,925’4,938’13 8/13/24 Open Beluga G7 5,542’5,548’4,950’4,956’6 8/13/24 Open Beluga G9 5,564’5,586’4,972’4,993’22 8/13/24 Open Beluga H2 5,742’5,773’5,146’5,177’31 8/13/24 Open Beluga H3 5,794’5,800’5,198’5,204’6 8/12/24 Open Beluga H4 5,814’5,824’5,217’5,227’10 8/12/24 Open Beluga H7 5,913’5,939’5,315’5,341’26 8/12/24 Open Beluga I 6,364’6,378’5,759’5,773’14 8/12/24 Open NOTES A second liner hanger/packer was run due to the first packer leaking, July 2024 Top Job 7/26/24 RIH w/1” piping down the 7-5/8” x Conductor annulus – tagged at 33’. Pumped 7.5 bbls cement – returned 3 bbls. 4.5 bbls left in hole. Cement to Surface. Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3 4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ Page 1/6 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:7/9/2024 End Date:7/28/2024 Report Number 1 Report Start Date 7/9/2024 Report End Date 7/10/2024 Operation Continue loading diverter equipment prep rig to move continue cleaning and organizing modules. Rig movers on location, split apart back yard and stage to move to G pad, set felt liner and mats, set diverter and T and annul ar. L/D down mast. Worked on scrubbing & pressure washing mast, carrier, and sub. Crew change, held PTSM. Cleaned & pressure washed mast, carrier, and sub. Vacuumed out remaining water in rig tank. Lower dog house into water tank. Shut down gen. Prepping mast, carrier, and sub to move to G pad. Report Number 2 Report Start Date 7/10/2024 Report End Date 7/11/2024 Operation Continue cleaning and organizing location load trailers and prep f/ crane, offload barge and transport crane to location spot i n and set up cranes, hoist derrick and draw works off sub onto trailers, hoist sub onto truck, transport pony subs and modules to G pad, transport cranes to g pad Set pony subs and sub over well and center, set draw works and derrick on sub and pin, spot in pit modules and jig set pump mod ules, spot in doghouse/water tank, spot in top drive HPU and gen skid, set pump house bubble, welder working on doghouse leg that was bent. Welder straightened & re-enforced leg on doghouse. Hooked crane to dog house for percautionary measurements. Lifted dog remainder of the way up with HYD/cable system. Spotted & set catwalk, and laisd over beaver slide. Stated hooking up electrical, water, and air lines. Prepped to rais e derrick. Held PJSM, raised derrick. Installed drive line for DWKS. Hooked up mud lines & jumper hoses between pit modules. Fired gen. Rasied roofs on all three pit modules. Power up light in pits, mast, rig floor, and sub. At 21:30 hrs. a CCI vac truck operator was rolling drilling fluid in a vertical tank at the tank farm on D pad. The 4" aluminum flange/male camlock broke at the weld causing a 1-1/2 barrels of drilling fluid to go into containment and a half of barrel to go outside of containment. The discharge was cleaned up and the proper personal were notified. Crew change, held PTSM. Cont. R/U. Pinned derrick board.Spooled drill line on drum, hung weight indicator. Installed equilizer liners between pits. Changed out valve on gun line in pit # 5. Brought on water to rig tank. Got water & air going through out the rig. M/U lower section of TQ tube to upper section. Scoped derrick while P/U lower section of TQ tube off catwalk, locked in dogs. Power up lights/beacon on top section of derrick. Installed T bar to derrick/TQ tube. Cont. hauling misc. tools/equip. from H pad to G pad. Report Number 3 Report Start Date 7/11/2024 Report End Date 7/12/2024 Operation P/U TDS & TQ bushing. M/U Kelley hose & service loop to TDS. Function tested robotics on TDS (ok). M/U saver sub. Set MGS & centrifuge with crane and R/U same. Repaired hopper #3. Hydro tested pit system with water (ok). Finished R/U catwalk, removed shipping beams in sub. Spotted, set, and powered up service shacks. Hooked Pason cables. R/U bails, elevators, rig tongs, and set up sub rack on rig floor. Checked pressure on accumulator bottles. Hammered up annular for diverter system. Installed riser, flow line, bleeder, and fill up line. Moved DSM & Toolpusher trailers to G pad and set up comm's. M/U knife valve, diverter vent line, and installed line anchors. Hooked up HYD koomey lines to stack. Started mixing first batch of spud mud. Bump tested centrifuge. Cont. working through rig acceptance check list. Obtained RKB's. Crew change, held PTSM. Cont R/U. Currently P/U 4.5" DP singles, building stds in rotary table mouse hole and racking them back in the derrick. Report Number 4 Report Start Date 7/12/2024 Report End Date 7/13/2024 Operation Continue P/U and racking back DP. R/U and Perform Diverter test with state inspector Kam St John, perfrom Drawdown test and R/D, Perfrom gas alarm test and test PVT alarms. P/U and rack back Jar Stand, load BHA on skate M/U BHA as per DD/MWD, download MWD, M/U HWDP Spud well Drill 9 7/8'' Hole section f/ 128' t/ 138' sperry transducer not working Wait on Sperry to trouble shoot transducer issues. Fixed transducer issues. Cont. stage drilling to bury flex collars & jar std. F/138'-T/405'. Started the 2 degree per/100' build section @ 250'. Directional drilled 9-7/8" surface hole F/405'-T/589'. P/U-26K S/O-25K ROT-26K GPM-400 SPP-1237 psi RPM-45 TQ-3.2K WOB-0/3.2K MW-8.8 ppg max gas-2 units. Crew change, held PTSM. Cont. directional drilling 9-7/8" surface hole F/589' to current depth of 1107'. Pumped 25 bbl Hi-Vis sweep with walnut/condet @ 950', sweep came back 8 bbls early with 25% increase in cuttings. P/U-34K S/O-31K ROT-32K GPM-400 SPP-1260 psi Flow-33% RPM-45 TQ-3K WOB-0/2.5K MW-8.75 ppg ECD-9.5 ppg Max gas-3 units. Distance to well plan: 14.74' 5.93' High 13.49' Right. Report Number 5 Report Start Date 7/13/2024 Report End Date 7/14/2024 Operation Continue Drilling 9 7/8'' Hole section from 1107' t/ 1531' 350 gpm 1190 psi 45 rpm 4.1k tq on bottom PUW 38k SOW 33k ROT 35k Circulate hole clean, obtain survey and flow check well static. Attempt to pull on elevators over pulling right away 25-35k, BROOH f/ 1531' t/ 713' POOH on elevators t/ 343' Service rig and top drive, grease blocks and crown, inspect draw works static loss rate 1 bph RIH f/ 343' t/ 1531' without issues wash last stand to bottom. Pump Hi Vis Sweep around back on time 20% increase in cuttings Drill Ahead 9 7/8'' Hole Section f/ 1531' t/ 1909' API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147Permit to Drill (PTD) #:224-068 Page 2/6 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Operation Cont. directional drilling 9-7/8" surface hole F/1908'-T/2413'. P/U-52K S/O-37K ROT-49K GPM-400 SPP-1422 psi Flow-32% RPM-45 TQ-6K Diff-32 psi WOB-0/3K MW-8.8 ppg ECD-9.58 ppg Max gas-13 units. Crew change, held PTSM. Cont. directional drilling 9-7/8" surface hole F/2413' to current depth of 2970'. P/U-59K S/O-38K ROT-43K GPM-400 SPP-1540 psi Flow-31% RPM-45 TQ-9K WOB-4K MW-8.95 ppg ECD-9.7 ppg Max gas-12 units. Distance to well plan: 11.42' 10.16' High 5.20' Right. Report Number 6 Report Start Date 7/14/2024 Report End Date 7/15/2024 Operation Continue Drilling 9 7/8'' Surface Section f/ 2970' t/ 3145' TD, 400 gpm 1570 psi 110 diff psi, 45 rpm 6.6k Tq on bottom, 8.9 ppg mw 2-5k WOB, 63k PUW 38k SOW 46k ROT. Distance to well plan: 14.71' 14.06' High 4.32' Right. Circulate hole clean, obtain survey and flow check well static. POOH on elevators f/ 3145' t/ 2219' Pulling tight unable to work through, BROOH f/ 2219' t/ 1469' at full drilling rate. Stalli ng rotary and over pulling, minor packing off. RIH f/ 1469' t/ 2965' with out issues, set down unable to work through, wash and ream to bottom @3145' Circulate Hi Vis Sweep around, Sweep back 219 stks early 10% increase in cutting returns POOH f/ 3145' t/ 2468' unable to work through, wash and ream f/ 2468' t/ 2275' Pulled on elevators to BHA without issue. Rack Back BHA, L/D collars , download MWD, L/D Remainig BHA. Bit graded 2-3 1/8" under gauge. Servied rig- Inspected & greased crown, Blocks, TDS, wash pipe, IR, DWKS, break linkage, and drive shaft. Changed out O-ring seal on TDS HYD line. R/U TRS handling equip. M/U LJ to hanger. loaded up catwalk pipe racks with casing. M/U safety valve. R/U fill up line. Held PJSM on running surface casing. Test run hanger. P/U & M/U 7-5/8" shoe track, tested floats (ok). Cont. running 7-5/8" 29.7# L-80 DWC/C surface casing as per run tally F/surfac e-T/1659', filling on the fly and topping off every 10 jts. P/U-51K S/O-38K M/U drive sub, broke circ. stagged up MP. Pumped string volume. P/U-53K S/O-39K GPM-221 SPP-99 psi MW-9.0 ppg Max gas- 5 units. Cont. running 7-5/8" surface casing as per run tally to current depth of 2608'. Report Number 7 Report Start Date 7/15/2024 Report End Date 7/16/2024 Operation Continue RIH w/ 7 5/8'' Casing f/ 2608' t/ 3145' work tight hole from 2608' down 3050' tag bottom L/D Jt M/U hanger and landing jt Circulate and condition mud for cement job stage rate to 6 bpm 110 psi, R/D Parker casing equipment, spot in and rig up cementers PJSM, PT lines t/ 400 low 3800 high, pump 60 bbls 10.5 ppg spacer drop bottom plug, pump 192 bbls 12 ppg Lead cement, followed by 36 bls 15.8 ppg Tail all cement pumpoed 5 bpm, displaced well with 134.5 bbls spud mud bumping plugs FCP 770 psi pressure up to 1370 psi hold f/ 5 min bleed off nad check floats held, bled back 1.5 bbls, no lossses throughout job, got back 60 bbls spacer and 85 bbls cement CIP 11:48 hrs Flush and drain diverter stack, N/D DIverter assembly and vent line, N/U wellhead B Section test seals, spot in crane and crane BOP Stack to cellar transfer to bridge cranes, set on well, M/U choke and kill lines N/U spacer spool, and BOP stack. M/U choke & kill lines. N/U bell nipple, installed riser, flow box, and flow line. R/U flow pa ddle, fill up line, and bleeder line. Hooked up koomey HYD lines to stack. Cleaned modules 1 & 2. Inspected shakers and found crack in shaker bed #1, bringing out welder in the morning to address shaker. Brought over 6% KCL PHPA mud from tank farm to pit module #2. Greased choke manifold, manual inside valves, and HCR valves. Removed 4" valves off conductor and installed caps. Obtained RKB's. Inspected MP's, found wash on MP #1, pod #3, on suction side of pod. Patched with Steel Seal till new pod arrives from drilling Crew change, held PTSM. Double checked bolts/flanges for proper TQ on BOP stack. Function tested BOP's. Trouble shoot lower pipe ram function, found loose HYD connection on stack. Picked cleaned up tools & etc. R/U testing equip. Flooded stack, choke manifold, and mud lines with water. Purged out air. Currently performing initial bi-weekly BOP test on 4.5” & 3.5” test jt as per AOGCC regulations. Report Number 8 Report Start Date 7/16/2024 Report End Date 7/17/2024 Operation ContinueTest BOP's with 3.5'' and 4.5'' Test jts, had 1 FP on choke line flange had to tighten and retest, state inspector Jim Regg waived witness R/D test equipment pull test plug, R/U to test casing Test caing to 3500 psi f/ 30 min on chart, pumped in 1.9 bbls bled back 1.9 bbls R/D test equipment. Level Rig M/U BHA as per DD/MWD, upload MWD shallow test tools and load sources, continue RIH w/ BHA. RIH w/ Drilling BHA P/U single off catwalk f/ 678' t/ 2980' Wash down f/ 2985' to tag on wiper plugs on depth at 3054. Drill up FE, cemented rate hole and 20' of new formation. 200GPM 1100PSI 30RPM 4.9K TQ 4-7k WOB CBU x2 PJSM w/ rig crew, Bariod and CCI. Displace well over to 6% KCL Mud. CBU x2 to get good even mud weight in/out. 200GPM 950PSI 30RPM 4.4K TQ. R/U test equipment and perform FIT. Pressured up to 737psi for 14.1 ppg EMW. Pumped 0.38 bbl bled back 0.32 bbl. R/D test equipment. Drill 6-3/4" hole F/ 3165’ t/ 3550' MD (3086' TVD) Total 385' (AROP 64') GPM= 1300psi, 40 RPM=6.1k TRQ , 0.5-3k WOB, ECD 10.1 MW 9.05ppg P/U 64k, S/O 46k, ROT 54k. Report Number 9 Report Start Date 7/17/2024 Report End Date 7/18/2024 Operation Continue Drilling 6 3/4'' Hole section f/ 3550' t/ 4180', 250 gpm 1350' 60 rpm 7.2k Max gas 190 units of gas, 72k PUW 51k SOW 60k ROT 3-4k WOB Circulate bottoms up, obtain survey and SPR's Flow check well static Make wiper trip f/ 4180' t/ 3170' without issues Service rig and top drive, grease blocks and crown, inspect brake linkage and draw works. RIh f/ 3170' t/ 4180' wash and ream last stand to bottom, Pump Hi Vis Sweep around resume drilling ahead. Drill 6-3/4" hole F/ 4180’ t/ 4498' MD (3924' TVD) Total 318' (AROP 45') 175GPM = 1300psi, 50 RPM=7.2k TRQ , 3k WOB, ECD 9.7 MW 9.0ppg P/U 79k, S/O 52k, ROT 60k. Max Gas 291 API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147 Page 3/6 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Operation Drill 6-3/4" hole F/ 4498’ t/ 4731' MD (4154' TVD) Total 233' (AROP 39') 175GPM = 1060psi, 40 RPM=7.2k TRQ , 2k WOB, ECD 9.8 MW 9.0ppg P/U 76k, S/O 55k, ROT 63k. Max Gas 88 Report Number 10 Report Start Date 7/18/2024 Report End Date 7/19/2024 Operation Drill 6 3/4'' Hole f/ 4731' t/ 4945' 175 gpm 1300 psi 50 rpm 7.8k tq on bottom, MW 9 ppg ECD 9.94 ppg, 4-6k WOB 81k PUW 56k SOW 64k ROT Hold ROP t/ 60 and slow pump rate due to possible loss circulation zones. Drill 6 3/4'' Hole f/ 4945' t/ 5180' 190 gpm 1188 psi 60 rpm 7.8k tq on bottom, 6-10k WOB MW 9.05ppg ECD 10.1 ppg 83k PUW 54k SOW 66k ROT Max Gas 290 units CBU while working pipe. 200GPM=1115PSI, 60RPM=8.5K TQ. P/U-82K, S/O-54K, ROT-61K. POOH on elevators f/5180' t/3108' without issue. P/U-62K, S/O-42K. DISP: calc-14.7 bbl, act-15.9 bbl Service floor motor, drawworks, brake linkage, top drive, crown, iron roughneck. Inspect saver sub. Clean suction screens on mud pumps. Monitor well on trip tank- static loss rate 1bbl/hr. RIH P/U singles fromcat walk f/3108' t/4994'. (60 jnts total). RIH with 3 stands from the derrick washing last stand down. P/U-71K, S/O-46K. Disp: calc-39.04, act-36.04. Drill 6-3/4" hole F/ 5180’ T/5731' MD (4154' TVD) Total 233' (AROP 39') 210GPM = 1260psi, 60 RPM=7.9K TRQ , 3k WOB, ECD 10.1 MW 9.05ppg P/U 76k, S/O 55k, ROT 63k. Max Gas 305 Pump sweep at 5180' back 6.2 bbl early witha 15% increase in cuttings. Report Number 11 Report Start Date 7/19/2024 Report End Date 7/20/2024 Operation Drill 6 3/4'' Hole Section f/ 5731' t/ 5747' 230 gpm 1450 psi 60 rpm 9.3k tq on bottom, MW 9.1 ppg 10.22 ppg ECD, WOB 6-10, 91k PUW 55k SOW 68k ROT Max Gas 682 units Drill 6 3/4'' Hole f/ 5747' t/ 6060' 230 gpm 1350 psi 60 rpm 10k tq on bottom, 9.15ppg 10.23 ppg ECD, 94k PUW 57k SOW 72k ROT Drill 6-3/4" hole F/6060’ T/6249' MD (5646' TVD) Total 189' (AROP 47') 220GPM = 1660psi, 60 RPM=10.3K TRQ , 3-12k WOB, ECD 10.37 MW 9.2ppg P/U 96k, S/O 54k, ROT 68k. Max Gas 221 CBU at 220GPM=1350PSI 60RPM=10.2k TQ. Flow check well-slight seepage. POOH f/6249' t/5867'. P/U-97k, S/O-56K. Disp: calc-2.3bbl act-1.3bbl. Decision was made to RIH back to bottom after swabbing was noticed. Had to ream f/5867' t/6249'. 175GPM=1015PSI 40RPM=8.5K TQ. CBU to remove gas from well bore at 175GPM=1010PSI 40RPM=10.3K TQ. Max gas at BU was 1872 units. Flow check well-slight seepage. POOH on elevators f/6249' t/5800' P/U-105k, S/O-59k. Oberserved 20-30k overpulls and indications of swabbing. Decision was made to BROOH to previous wiper depth. BROOH f/5800' t/5173'. 175GPM=1400PSI, 40RPM=9-10.5k TQ (5-10k overpulls and 100-400PSI pressure ups) Service floor motor, drawworks, brake linkage, top drive, crown, iron roughneck. Inspect saver sub. Clean suction screens on mud pumps. Monitor well on trip tank- static loss rate 1bbl/hr. RIH on elevators f/5173' t/6249'. P/U-93k S/O-53k. Wash last stand to bottom. Report Number 12 Report Start Date 7/20/2024 Report End Date 7/21/2024 Operation Drill 6 3/4'' Hole f/ 6249' t/ 6515' 230 gpm 1700 psi, 60 rpm 10.9k tq on bottom, MW 9.2 ppg ECD 10.3 ppg, 99k PUW 58k SOW 76k ROT Max Gas 639 units Drill 6 3/4'' Hole f/ 6515' t/ 6836' 254 gpm 1912 psi 65 rpm 10.8k tq on bottom, 3k WOB 99k PUW 56k SOW 74k ROT Max Gas 757 units Drill 6 3/4'' Hole f/ 6836' t/ 7185' 254 gpm 1951 psi 65 rpm 11.6k tq on bottom, 3-6k WOB 100k PUW 72k SOW 72k ROT Max Gas 333 units Drill 6 3/4'' Hole f/7185 ' to TD at 7469' 254 gpm 2040 psi 60 rpm 12.4k tq on bottom, 3-6k WOB 119k PUW 64k SOW 83k ROT Max Gas 358 units Circulate bottoms up. Obtain final survey and get SPR's. Flow check well. Report Number 13 Report Start Date 7/21/2024 Report End Date 7/22/2024 Operation Make wiper trip f/ 7469' t/ 6247' some 25-35k over pulls but worked through Service rig and top drive, inspect brake linkage and draw works, grease blocks and crown. RIH f/ 6247' t/ 7469' wash last stand to bottom. Pump 25 bbl sweep around, sweep back 200 stks early 33% increase in cuttings Max gas from wiper trip 3108 units at bottoms up. Flow checked well 10 min well static. POOH f/ 7469' t/ 685' without issues L/D HWDP f/ 685' t/ 132'. PJSM, remove sources, and download MWD data. Finish L/D directional BHA. Bit graded: 1-1-WT-A-X-I-PN-TD. Clean and clear rig floor. M/U swedge and floor valve. R/U Parker TRS casing equipment. M/U shoe track Baker Locing all connections and check floats-good. Cont. RIH w/3.5" liner as per tally f/64' t/638'. Cont. to RIH w/3.5" Hyd 563 f/638' t/3182'. Circulate string volume. Cont t RIH f/3182' t/4012'. P/U-32K, S/O-28K. Report Number 14 Report Start Date 7/22/2024 Report End Date 7/23/2024 Operation Continue RIIH w/ 3.5'' Liner on 4.5'' DP f/ 4012' t/ 7469' filling pipe every 1000', wash last stand to bottom. Circulate and conditon mud for cement job, stage rate to 5 bpm 180 psi, spot in and R/U cementers. PJSM, PT lines to 1500 psi low 4500 psi high, pump 30 bbls 10.5 ppg spacer, 184 bbls 12 ppg Lead, 27 bbls 15.3 ppg Tail, Drop top plug, displace with 76 bbls drilling mud, Bumped plugs @ 2 bpm 1400 psi pressure up t/ 1900 psi hold f/ 2 min bleed off and check floats, bled back 1.5 bbls, Pressure up t/ 3100 psi and set and release liner hanger packer, PUW 35k after release, Bleed off and L/D cement head and lines, set 25k on liner top and rotate attempt to shear dog sub, P/U clear of liner top Circulate out spacer and cement, stage rate to 420 gpm 460 psi 30 bbls of spacer and 66 bbls of cement to surface, circulate and additional bottoms up POOH f/2873' t/ surface. L/D running tool as per YJ rep. P/U and break XO's and pup joints off cement head. M/U polish mill assembly and RIH w/ polish mill f/37' t/2967'. Polish PBR and dress liner top as per YJ rep. 140GPM=250PSI, 5RPM=2.1k TQ. API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147 Page 4/6 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Operation PJSM with all parties involed, displace well over to CI water. Pumped 20bbl hi-vis spacer, over oboard returns until clean water at surface. Visually monitor wellbore for flow for 30 min- no flow. POOH f/2967' to surface laying down 4.5" DP singles. L/D polish mills. R/U test equipment to pressure test liner lap. Report Number 15 Report Start Date 7/23/2024 Report End Date 7/24/2024 Operation Pressured up to 3000 psi on wellbore and held 30 min on chart. Lost 450 psi over 30 minutes. Triple checked all surface equipment for any leaks and found nothing. Notified Drilling Engineer, decision made to RIH with seal assembly and test liner then IA seperately. Bled off and RD test equ ipment. Staged seal assembly, XO's and 3 1/2" EUE jnt. MU seal assembly on jnt tubing and XO to CDS-40 DP. Total length 42.50'. RIH on 4 1/2" DP from 42.50' to 2958', LD topsingle, PU 10' pup, S/O and tagged no-go on lower SBR at 2969'. Down wt 36K. PU 2' and set in slips. MU head pin on stump and topped off with water. RU test equipment and purged air. Pumped down DP to test 3 1/2" liner, to 1000 psi and held for 5 min, good test, 0 psi on IA. Pressured up to 2000 psi and held 5 min, good test, 0 psi on IA, pressured up to 3000 psi and held 15 minutes, good test, 0 psi on IA. Bled off, RU test pump to IA. Pumped down 7 5/8" x 3 1/2" IA to 1000 psi, 50 psi on DP, held 20 minutes and lost 120 psi. Started seeing water trickle out 4" outlets on conductor. Pressured up to 2000 psi and held for 8 minutes, lost 120 psi, had a slight increase in water running from 4" conductor outlet that did not sto p. Notified Drilling Engineer, decision made to POOH for dogsub run. Bled off IA, at 900 psi water stopped running from 4" conductor outlet. Captured a sample of water from outlet, mud Engineer thinks it is inhibited fresh water, but had a PH of 12.5 (likely from contact with cement). RD test equipment. LD 10' pup and headpin, PU top single, POOH racking back from 2958', up wt 43K, to 42.50'. LD XO, jnt 3 1/2" EUE and seal assembly. Racked 17 jnts 4 1/2" HWDP, PU Yellow Jackets upper liner hanger run tool assembly (lift sub, pusher tool, spacer sub and dog sub) to 27.02'. PU singled in hole 17 joints 4 1/2" HWDP to 459'. Cont RIH on DP from 459' to 2933'. Set down 25k on liner top with dog sub and rotate at 5RPM. P/U and set down multiple times. R/U test equipment and attempt jug test 7-5/8" and 3-1/2" liner- no good. Pressure bled off 200PSI in 5 min. Water coming out of 4" valve increased during test. Notified Drilling engineer and decision made to POOH and P/U test packer to determine where the leak is. POOH f/2933' t/551'. Rack back HWDP f/551 t/37'. P/U-50K, S/O-40K. L/D YJ running tool. P/U test packer, M/U 10' pup and XO on bottom of HWDP single. RIH with 8 stands of HWDP and DP f/51' t/1032'. Set packer as per YJ rep. R/U testing equipment. Test surface casing f/1032' to surface. 1000 psi for 5 min-good, 2000psi for 5 min-good, 3000psi for 5 min-good. R/D test equipment and release packer. RIH with 4.5" DP f/1032' t/2104'. Set packer and R/U testing equipment. Test tubing and surface casing below packer. 1000psi for 5 min-good. 2000psi for 5 min seals leaking on packer not enough down weight. Tested surface casing f/2104' t/surface. 1000psi for 5 min-good, 2000psi for 5 min-good, 3000psi for 5 min-good. R/D test equipment and release packer. RIH f/2104' t/2893' Set packer and R/U test eqiupment. Test surface casing f/2893' t/ surface: 1000psi for 5 min-good test, 2000psi for 5 min-good test, 3000psi for 5 min-good test. Test tubing and surface casing below packer: 1000psi for 5 min-good test, 2000psi for 5 min-fail. R/D test equipment and release packer. Report Number 16 Report Start Date 7/24/2024 Report End Date 7/25/2024 Operation Bled off wellbore test pressure, released test packer as per Yellow Jacket Rep, L/D 10' pup and kelly joint. POOH slow racking back in derrick from 2893' to surface, up wt 46K. Packer pulled wear ring from wellhead, had to work that off packer with little issue. L/D packer. P/U test joint and re-set wear ring. RU test equipment on mezz kill valve, purged aire from lines, closed blinds and held PJSM with crew coming on tour. Pumped 27.5 gallons and pressured up on wellbore to 1000 psi on chart. Started seeing slight water flow at 4" outlet on conductor at 250 psi. Held pressure for 5 minutes then flow check at outlet was .06 bph. Held another 12 minutes and lost 30 psi on wellbore. Pumped an additional 27.5 gallons to achieve 2000 psi, held 5 minutes and flow check at .05 bph. After 20 minutes flow check at .035 bph. Lost 120 psi on wellbore over 30 minutes. Pumped an additional 30 gallons to achieve 3000 psi. Held 5 minutes and flow check at .027 bph from conductor. At 20 minutes flow check at .026 bph. Lost 350 psi on wellbore over 30 minutes. Sent chart and flow rate data to Drilling Engineer. RD test equipment, spotted AK E-Line unit, re-headed cable and assembled tool string to perform CBL on 3 1/2" liner. RU sheaves . RIH with e-line to 7340', start CBL in 3 1/2" liner. At 15:30 flow from conductor outlet at .04 bph, at 18:00 flow at .035 bph. Logged up to top of the liner at 2932'. POOH and Change out logging tool. RIH w e-line to liner top at 2932' and perform CBL logging OOH on the 7-5/8" casing to surface. Flow from conductor outlet: 21:00- 0.032BPH 22:00- 0.032BPH L/D E-Line tools and R/D E-Line equipment. Drain stack R/U vac truck and suck water level down below 4" outlet to determine if water flow is from wellbore U-tube. Flow from conductor outlet: 00:00- 0.022BPH API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147 Started seeing slight water flow at 4" outlet on conductor at 250 psi. Pumped an additional 30 gallons to achieve 3000 psi. Held 5 minutes and flow check at .027 bph from conductor. At 20 minutes flow check at .026 bph RIH w e-line to liner top at 2932' and perform CBL logging OOH on the 7-5/8" casing to surface.p Flow from conductor outlet: 21:00- 0.032BPH 22:00- 0.032BPH Page 5/6 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Operation Perform rig service, Maintenance, and work on EAMs. Monitor annulus and and condutor outlet: 01:00-0.023BPH 02:00-0.025BPH Cont Maintenance and EAM's. Fill BOPE stack and contine to monitor 4" outlet: 03:00-0.029BPH 04:00-0.036BPH 05:00-0.033BPH Report Number 17 Report Start Date 7/25/2024 Report End Date 7/26/2024 Operation Installed gauge on conductor outlet and monitored pressure build to 8 psi over 2 hours. Welder repaired crack on mud pump threaded cap ring and two hinges in pits, rig electrician and mechanic replaced pulg end on topdrive HPU cable. Started to see water leech out of wellhead flange, removed ga uge and drained conductor down to outlets. At 10:57 got approval from AOGCC to run 2nd liner hanger assembly. Staged seal assembly, XO joint and hanger, MU seal assembly, XO pup and XO joint, PU and MU Yellow Jacket liner hanger assembly, mixed and poured Xanstar. PU single HWDP and MU XO, RIH one stand HWDP, MU topdrive, pumped 3.5 bbls to ensure we could circulate at 112'. RIH HWDP stands (total 17 jnts) followed with 37 stands DP to 2924', up wt 40K, dwn 32K. PU kelly jnt and 10' pup, saw no-go tag lower SBR with mule shoe at 2957', PU 1'PU 1' and parked. RU test pump on stand pipe, topfilled 10' pup, MU topdrive, pressured up to 1594 psi and saw 4K loss in string weight, shut down at 1713 psi and held 5 minutes to set hanger. Increased to 2452 psi and held 4 minutes to set packer, saw another 2K loss in string weight. PU to 50K, S/O to 40K, increased pressure to 3250 psi to release run tool, felt pins shear at 2963 psi and held 2 minutes. Bled off pressure and gained 4K in string weight. S/O to 28K, PU to 40K and verified we released from hanger. Pulled up hole 7', S/O to 12K and rotated 5 turns right to transfer weight down on dogsub. Pulled up hole 1 jnt, up wt 40K, TOL = 2888'. Closed upper rams and pumped down kill line 80 gallons to achieve 3000 psi on wellbore. Held 30 min on chart, good test. Bled off and RD test equipment. POOH LD DP, vacuumed wiper balls through pipe on rack, dried and cleaned threads, re-doped and installed thread protectors. Racked back HWDP and L/D running M/U mule shoe and RIH w/ 4.5" DP out of derrick f/ surface t/1660'. P/U-22K, S/O 21K. Circulate a string volume. POOH L/D 4.5" DP to catwalk f/1660' t/ surface. (120 jnts total). M/U mule shoe and RIH w/ HWDP out of the derrick f/ surface t/538'. M/U XO's and Tri-Point storm packer as per rep. RIH w/ 2 stands of DP out of the derrick t/667'. Set and release from packer as per Tri-Point rep. POOH f/123' t/ surface. R/U test equipment and pressure test packer to 500psi/10 min. Bleed down koomy. Remove flow line, riser, koomy lines for kill HCR, choke and kill lines. N/D BOPE from spacer spool. N/D well head. M/U 2 sticks of 1" work string and tag top of cement at 27.3'. R/U and prep to perform cement top job. Report Number 18 Report Start Date 7/26/2024 Report End Date 7/27/2024 Operation Spotted cementers pump and bulk units, RU HP hoses and hardware, ran two joints 1" pipe down into conductor through surface hanger flute and tagged firm cement at 27'. Removed joints and cleared soft cement, XO to 1502 hammer union on top and tied into HP hose. Held PJSM with cementers and rig team. Using pump truck charge pump, washed 1" piping down to 33' from GL and tagged up on hard cement. PU 6" and swapped to 16 ppg cement, pumped 7.5 bbls cement displacing water from conductor, recovered 3 bbls cement at surface leaving 4.5 bbls cement in conductor. Shut down pump, broke off 1502 connection. CIP at 08:00 on 7-26-24. Using winch line, removed 1" piping from wellhead through mousehole to rig floor. Broke connection and flushed piping into cellar box then LD same. Pump truck flushed water though HP hose until clean water into cellar box, then washed up truck to cuttings box. Vac'd out cement and trash water from cellar. At 09:00 we have no water flow from conductor outlet. Stabbed wellhead and spacer spool combined back onto conductor. Wellhead Rep RILD's then tested neck seals at 3500 psi for 10 minutes, good test. At 10:00 we have no water flow from conductor. Set BOP stack on spacer spool and NU. NU choke and kill line flanges, installed flow riser and chained off stack, re-connected koomey lines. Cont to monitor conductor outlet for water flow every hour, no flow. Cement sample is good and hard. Set test plug, flooded stack, choke and kill lines, opened annulus valve, functioned rams, purged air, closed blinds and tested all flange breaks at 250 low, 3000 high for 5 minutes each on chart with no issues. RD test equipment and removed test plug. Witness of testing was waived by AOGCC Jim Regg at 08:34 on 7-26-24. Held PJSM with Tri-Point Rep on retrieving storm packer. MU stinger and XO on stand of DP, eased in hole two stands and tagged packer top. MU TIW on stump, rotated right 14 turns to engage packer, opened TIW and removed same, pulled to 20K and packer is free, allowed packer to relax 5 minutes and POOH racking back 1st stand, L/D single, broke down storm packer and L/D same. No water flow from conductor outlet. RIH 2 stands DP from derrick, then POOH L/D DP and HWDP. CCI vacuumed wiper balls on pipe rack, dried and cleaned threads, re-doped and installed thread protectors. Cleaned and cleared rig floor, RU tubing tongs and elevators, staged seal assembly and brought in 3 1/2" tubing for PU. No water flow from conductor at 18:00, installed 4" cap and valve on outlet. Held PJSM with YJ Rep, tong hand and rig crew. MU seal assembly with 3.41' of seals, 10.23' overall length to no-go. Cont PU single in hole with 3 1/2" 9.2# L-80 EUE tubing t/2882' P/U jnts 97, 98 and space out set down at 2913'. Close bag P/U jnts 97, 98 and space out set down 10K at 2918'. Close bag and put 1000 psi on backside to ensure stung in. L/D jnts 97 and 98. M/U 8.28' space out pup and hanger and land out. Set snap ring, pull test 40k over and PT to 5000psi/10min-good test. R/U test equipment on tubing for MIT-T. Pressure up on tubing, at 2400psi pressure bleed off down to 1400psi, and there was 1000psi on the IA. R/D test equipment. API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147 4 Top job. -bjm Using pump truck charge pump, washed 1" piping down to 33' from GL and tagged up on hard cement. PU 6" and swapped to 16 ppg cement, pumped 7.5 bbls cementgp p g p p, pp g gg p displacing water from conductor, recovered 3 bbls cement at surface leaving 4.5 bbls cement in conductor Spotted cementers pump and bulk units, RU HP hoses and hardware, ran two joints 1" pipe down into conductor through surface hanger flute and tagged firm cement atp 27'. pp Cont to monitor conductor outlet for water flow every hour, no flow pp At 10:00 we have no water flow from conductor g, gg ,g No water flow from conductor at 18:00, installed 4" cap and valve on outlet g, p No water flow from conductor outlet Page 6/6 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Operation Dis-engauge snap ring, pull hanger to floor and L/D. P/U and RIH w/ jnts 97 and 98. Able to get 9' deeper without even a bobble seen on the weight indicator. L/D tag jnts. M/U 8.07' on bottom of 8.28' pup. M/U hanger, land out, 0.73' off no-go, set snap ring, pull test 40k over and PT 5000psi/10min -good test. R/U test equipment on tubing and perform MIT-T 3000psi/30min charted-good test. Pumped 11.5"/0.68bbl, bleed back 11"/0.65bbl. R/U test equipment on IA and perform MIT-IA 3000psi/30min charted-good test. Pumped 22"/1.31bbl, bled back 22"/1.31bbl. Report Number 19 Report Start Date 7/27/2024 Report End Date 7/28/2024 Operation Bled off MIT-IA pressure, BO and L/D landing joint, RD tubing tongs and elevators, PU T bar and set 2 way check in hanger. Flushed pumps, mudline, topdrive, BOP stack, choke line and manifold and poorboy degasser with BarKlean, followed with fresh wa ter, blew everything down and cleaned excess fluid from pits. Opened ram doors for inspection, greased and buttoned up doors. RD gas alarm equipment, prepped trip tank pump for removal. ND flow riser, drip pan and flowline, removed choke and kill lines, hoisted stack and staged in cellar on bridge cranes, remove d spacer spool. Staged dry hole tree. Installed dry hole tree (master valve), wellhead rep tested tree, hanger seals and void at 5000 psi for 10 minutes, good test. CCI shipped out upright water tank and cement silo along with various tool baskets. RD service shacks and spooled up elec cords. Removed saver sub, kelly hose and service loop from topdrive, staged cradle and pinned to topdrive, removed torque bushing, un-pinned becket from blocks. RD interconnects between pit modules and pump modules. Shipped out upright water tank and cement silo. RD and shipped out service shacks, L/D topdrive, removed T bar, bridled up, held PJSM, scoped mast down, and LD lower torque tube, brought in crane and transfered BOP stack to cradle, LD poor boy degasser, removed centrifuge, shipped out screen connex, removed trip tank pump for repair. Hang blocks in derrick and fold up wind walls on monkey board. Install shipping beams in sub. Unhook Pason wires. Unspooled drill line from drawworks. Lay over pit roof #3. R/D topdrive HPU. Changed wire rope raising cable on dogdhouse. R/D electrical lines. Lower roofs on pit mods 1 and 2. Lay derrick over and inspect. Flod up electrical grasshopper on pump one . Remove lights, fold up roof flaps and walk ways between mud pumps. Disconnect fuel lines between skids. Fold up v-door on catwalk. API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147 perform MIT-T 3000psi/30min charted-good test MIT-IA 3000psi/30min charted-good test qp g p Page 1/2 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:7/30/2024 End Date: Report Number 1 Report Start Date 7/30/2024 Report End Date 7/31/2024 Operation PJSM, Crew travel to IRU, Rig down equipment and MOB to pad, Spot in & rig up. PIck up lube & tool string CCL/GR/CBL, Pressure test 250/3000 good. Run in hole with run #1, CCL/GR/CBL, Run in hole & tag @ 7280'. Log up & perform repeat passes, Pull out of hole. Pick up & make up Caliper tools, Calibrate and surface test tool string. Run in hole with run #2, Caliper, Perform caliper log. perform caliper. Pull out of hole. Secure well, Rig down AK Eline & release. Report Number 2 Report Start Date 7/31/2024 Report End Date 8/1/2024 Operation PJSM, Crew Mob to location, Spot in and rig up, Spot in tanks and top off water tanks, Rig up hard lines & prepare to nipple up bope, Secure well and shut down for the night. Report Number 3 Report Start Date 8/8/2024 Report End Date 8/9/2024 Operation PTW/PJSM. Road equipment from K pad to G pad. MIRU Fox 1.75" CTU. Pressure test BOPE 250/2,500 psi. Accumulator drawdown/BOP function test. Spot N2 pump and transfer N2 from transport. SDFN. Note: AOGCC witness waived by Jim Regg. Report Number 4 Report Start Date 8/9/2024 Report End Date 8/10/2024 Operation PTW/PJSM. PU coil injector and MU 2.125" OD center-port reverse nozzle. P-test lub to 250/3,000 psi. GIH w/ coil. Tag at 7,335' CTM. PU to 7,300', pump 66 bbl fresh water at 1 bpm, displace drilling mud and got clean returns. Reverse circulate nitrogen at 800-1000 scfm. Max N2 pump pressure 2750 psi. Pumped a total of 98,524 scf nitrogen. Recovered a total of 81 bbl water based on tank straps (calc annular vol + reel vol 76 bbl). POH with coil. Bump up with 2,020 psi SITP. SI well and bleed off reel. RDMO. Report Number 5 Report Start Date 8/12/2024 Report End Date 8/13/2024 Operation PJSM, Crew mob to location, Spot in & rig up, Pick up lube & gun, Pressure test 250/2500-good. Run in hole with gun #1, CCL/GR/GUN, Correlate, Perf BEL I (6364-6378), Gun misfired Pull out of hole & check head (teardrop grounded). **2-3/8", 11.5 gr geo, 60 deg. 5 spf Run in hole with gun #1, CCL/GR/GUN, Correlate, Perf BEL I (6364-6378), OG psi-1619, 5-1620, 10-1619, 15-1617, Pull out of hole **2-3/8", 11.5 gr geo, 60 deg. 5 spf Run in hole with gun #2, CCL/GR/GUN, Correlate, Perf BEL H7 (5913-5939), OG psi-1592, 5-1564, 10-1530, 15-1495, Pull out of hole **2-3/8", 11.5 gr geo, 60 deg. 5 spf Run in hole with gun #3, CCL/GR/GUN, Correlate, Perf BEL H4 (5814-5824), OG psi-1164, 5-1170, 10-1171, 15-1171, Pull out of hole **2-1/2", 12 gr, 60 deg. 6 spf Run in hole with gun #3, CCL/GR/GUN, Correlate, Perf BEL H3 (5794-5800), OG psi-1145, 5-1148, 10-1148, 15-1148, Pull out of hole **2-3/8", 11.5 gr, 60 deg. 5 spf Secure well & rig down for the night. Report Number 6 Report Start Date 8/13/2024 Report End Date 8/14/2024 Operation PJSM, Crew travel to location, Pick up lube & GPT, Pressure test 250/2500-good. Run in the hole with run #1, GPT, run in hole fluid level @ 6790'. Pull out of hole & lay down tools. Run in hole with run #2, CCL/GR/GUN (31'), Correlate, Perf BEL H2 (5742-5773), OG psi: 994, 5-1009, 10-1017, 15-1023, Pull out of the hole. **2-3/8", 11.5 gr, 60 deg, 6 spf Run in hole with run #3, CCL/GR/GUN (22'), Correlate, Perf BEL G9 (5564-5586), OG psi: 697, 5-750, 10-808, 15-875, Pull out of the hole. **2-3/8", 11.5 gr, 60 deg, 5 spf Run in hole with run #4, CCL/GR/GUN (6'), Correlate, Perf BEL G7 (5542-5548), OG psi: 841, Flowing well Pull out of the hole. **2-3/8", 11.5 gr, 60 deg, 5 spf API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service:Permit to Drill (PTD) #:224-068 Page 2/2 Well Name: BRU 241-26 Report Printed: 9/9/2024www.peloton.com Well Operations Summary Operation Run in hole with run #5, CCL/GR/GUN (13'), Correlate, Perf BEL G6 (5517-5530), OG psi: 1070, Flowing well, Pull out of the hole . **2-3/8", 11.5 gr, 60 deg, 5 spf Run in hole with run #6, CCL/GR/GUN (6'), Correlate, Perf BEL G5 (5495-5501), OG psi: 841, Flowing well Pull out of the hole. **2-3/8", 11.5 gr, 60 deg, 5 spf Secure well & rig down for the night. Report Number 7 Report Start Date 8/14/2024 Report End Date 8/15/2024 Operation PJSM, Crew travel to location, Pick up lube & GPT, Pressure test 250/2500-good. Run in hole run #1 with GPT, Fluid level @ 5530, Log to 6400', Log out of hole. Pull out of hole & secure well. Rig down & mob to 222-26. Report Number 8 Report Start Date 8/20/2024 Report End Date 8/21/2024 Operation Rig up slickline p/t lub. To 2500psi good test, Stand by for construction crew to remove hard line from tree & open top tank, RIH w/ 2.25'' g-ring to 6870'slm 6890'kb tag pooh no obstruction pooh steering knuckle broke-fix, cont. to pooh, Lay down lub. Secure well for night , Drive to camp turn in permit Report Number 9 Report Start Date 8/26/2024 Report End Date 8/26/2024 Operation Move from Ivan River to 241-26. Rig up slicline. P/T to 2500 PSI, good. RIH W/ 2.19" G-Ring, sat down at 5,555' KB, would not pass, could not see spangs, POOH, a few bits of coal on the gauge ring. OOH, check wire, no signs of being blown up hole. RIH W/ P/T gauges. OOH, data good. Lay down lubricator, secure well head. Leave pad. Report Number 10 Report Start Date 8/27/2024 Report End Date 8/27/2024 Operation Morning meeting, permit JSA. Standby for tools. Pick up lubricator. RIH W/ 1.75"x4' DD bailer, tag at 5,550, no spangs, W/T, toolstring appears to be getting wedged, POOH bailer empty. Rig down, fuel up equipment. Move to Ivan River. API: 50-283-20197-00-00 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: !"#$% !&#' ()&*+ $,- .- #% - /0 - - 1- 12- !"#!$ !"#!$ 34%-%&& '("#)*+,-#"*. -!"#!$2-/012 / 3 - '("#)*+,-#"*. 54 - 3!"#!$ 1 3 .- " .- $, 36- . .- #4!*,-5 . / #4!*,/ 0/0/. 6+" % 3 1 1$ %- %- 7 - 54 - 879#1 859# $! 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"4*)*! 9=%32 >2 ,!. * "+#)#* #+)9$ !49)7$ $ *7+)+4 # $97)$" # 744)8#$ *97)94 ! $!4 4$9)!4 9!# 4**)*# +)$# ! 8+7)"" 9=%32 >2 ,!. * "9!)+" #+)97 !4!)4! $ 7#+)"8 # $"+)78 # 4+")$#$ *$7)*8 ! $!4 4$8)87 9!# 4*!)$8 +)88 ! 8#9)*! 9=%32 >2 ,!. * "$4)++ #+)97 !4!)4! $ 7"$)7# # $"9)"" # 4#+)*"$ 7+8)## ! $!4 4$7)!$ 9!# 4$$)8$ +)++ ! 8!+)+" 0D-1-1 AE A A Page 1/1 Well Name: BRU 241-26 Report Printed: 9/9/2024 www.peloton.com Casing Surface Wellbore Wellbore Name: Original Hole Total Depth of Wellbore (ftKB): 3,145.00 Original KB/RT Elevation (ft): 41.70 RKB to GL (ft): 18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Surface Run Date: 7/15/2024 Set Depth (ftKB): 3,138.07 Casing Weight on Slips (1000lbf): 25,000.0 Pick Up Weight (1000lbf): 80,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 9.00 Ft/Min (ft/min): 5.81 Run Job: 241-00080 BRU 241-26 Drilling, Drilling - Drilling, 7/9/2024 06:00 Set Depth (ftKB): 3,138.07 Set Depth (TVD) (ftKB): 2,742.5 Centralizer Detail: Attribute Subtype: Value: Pipe Reciprocated?: Yes Pipe Rotated?: No Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) Casing Hanger 7 5/8 DWC 0.64 22.42 21.78 73 Casing Joints 7 5/8 6.87 29.70 L-80 DWC 3,030.26 3,052.68 22.42 Float Collar 7 5/8 DWC 1.32 3,054.00 3,052.68 2 Casing Joints 7 5/8 6.87 29.70 L-80 DWC 82.54 3,136.54 3,054.00 Float Shoe 7 5/8 DWC 1.53 3,138.07 3,136.54 Page 1/1 Well Name: BRU 241-26 Report Printed: 9/9/2024 www.peloton.com Cement Surface Casing Cement Type Casing Description Surface Casing Cement Cemented String Surface, 3,138.07ftKB Wellbore Original Hole Job 241-00080 BRU 241-26 Drilling, Drilling - Drilling, 7/9/2024 06:00 Cementing Start Date 7/15/2024 Cementing End Date 7/15/2024 Top Depth (ftKB) 22.4 Cement Stages Stage Number: 1 Description Surface Casing Cement Top Depth (ftKB) 22.4 Bottom Depth (ftKB) 3,145.0 Top Measurement Method Returns to Surface Pump Start Date 7/15/2024 Cement in Place At 7/15/2024 Final Circulating Pressure (psi) 770.0 Plug Bump Pressure (psi) 1,370.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 85.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Spacer 281 10.50 60.0 60.0 5 Halliburton Lead Slurry Lead G 440 2.44 12.00 192.0 192.0 5 Halliburton Tail Slurry Tail G 174 1.58 15.80 36.0 36.0 5 Halliburton Displacement Displacemen t 9.05 134.5 140.0 5 Halliburton Post Job Calculations Subtype Value Page 1/1 Well Name: BRU 241-26 Report Printed: 9/9/2024 www.peloton.com Casing Liner 1 Wellbore Wellbore Name: Original Hole Total Depth of Wellbore (ftKB): 3,145.00 Original KB/RT Elevation (ft): 41.70 RKB to GL (ft): 18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Liner 1 Run Date: 7/21/2024 Set Depth (ftKB): 7,468.00 Casing Weight on Slips (1000lbf): 64,000.0 Pick Up Weight (1000lbf): 79,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 13.00 Ft/Min (ft/min): 9.57 Run Job: 241-00080 BRU 241-26 Drilling, Drilling - Drilling, 7/9/2024 06:00 Set Depth (ftKB): 7,468.00 Set Depth (TVD) (ftKB): 6,845.8 Centralizer Detail: 133 Attribute Subtype: Value: Pipe Reciprocated?: Yes Pipe Rotated?: No Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) 1 Liner Hanger 6.53 4.78 IBT 36.46 2,924.92 2,888.46 2 XO and Blank Liner 3 1/2 2.99 9.20 L-80 IBT 7.83 2,932.75 2,924.92 1 Liner Hanger 6.53 4.78 37.64 2,970.39 2,932.75 15 Blank Liner 3 1/2 2.99 9.20 L-80 H563 467.68 3,438.07 2,970.39 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.07 3,453.14 3,438.07 12 Blank Liner 3 1/2 2.99 9.20 L-80 H563 500.29 3,953.43 3,453.14 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.18 3,968.61 3,953.43 16 Blank Liner 3 1/2 2.99 9.20 L-80 H563 468.97 4,437.58 3,968.61 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.05 4,452.63 4,437.58 15 Blank Liner 3 1/2 2.99 9.20 L-80 H563 492.97 4,945.60 4,452.63 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.02 4,960.62 4,945.60 16 Blank Liner 3 1/2 2.99 9.20 L-80 H563 493.46 5,454.08 4,960.62 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.04 5,469.12 5,454.08 16 Blank Liner 3 1/2 2.99 9.20 L-80 H563 462.22 5,931.34 5,469.12 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.07 5,946.41 5,931.34 15 Blank Liner 3 1/2 2.99 9.20 L-80 H563 496.48 6,442.89 5,946.41 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 15.04 6,457.93 6,442.89 33 Blank Liner 3 1/2 2.99 9.20 L-80 H563 494.01 6,951.94 6,457.93 1 Marker Joint 3 1/2 2.99 9.20 L-80 H563 14.49 6,966.43 6,951.94 15 Blank Liner 3 1/2 2.99 9.20 L-80 H563 467.45 7,433.88 6,966.43 1 Float-Landing Collar 4 1/2 2.41 IBT 1.69 7,435.57 7,433.88 1 Blank Liner 3 1/2 2.99 9.20 L-80 IBT 30.51 7,466.08 7,435.57 1 Float Shoe 4 1/2 2.41 IBT 1.92 7,468.00 7,466.08 Page 1/1 Well Name: BRU 241-26 Report Printed: 9/9/2024 www.peloton.com Cement Liner Cement Type Casing Description Liner Cement Cemented String Liner 1, 7,468.00ftKB Wellbore Original Hole Job 241-00080 BRU 241-26 Drilling, Drilling - Drilling, 7/9/2024 06:00 Cementing Start Date 7/22/2024 Cementing End Date 7/22/2024 Top Depth (ftKB) 2,932.8 Cement Stages Stage Number: 1 Description Liner Cement Top Depth (ftKB) 2,932.8 Bottom Depth (ftKB) 7,469.0 Top Measurement Method Returns to Surface Pump Start Date 7/22/2024 Cement in Place At 7/22/2024 Final Circulating Pressure (psi) 1,400.0 Plug Bump Pressure (psi) 1,900.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 56.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Spacer 3.82 10.50 30.0 30.0 4 Halliburton Lead Slurry Lead G 432 2.39 12.00 181.0 181.0 4 Halliburton Tail Slurry Tail G 122 1.24 15.30 24.0 24.0 4 Halliburton Displacement Displacemen t 9.30 76.0 76.0 4 Halliburton Post Job Calculations Subtype Value 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: 8/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240827 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 23 50133206350000 214093 7/18/2024 AK E-LINE PPROF BRU 222-24 50283201800000 220043 8/8/2024 AK E-LINE Perf BRU 222-26 50283201950000 224035 8/6/2024 AK E-LINE Perf BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 8/12/2024 AK E-LINE Perf BRU 241-34S 50283201980000 224077 8/2/2024 AK E-LINE Perf BRU 241-34S 50283201980000 224077 7/28/2024 HALLIBURTON CAST-CBL IRU 44-36 50283200890000 193022 8/10/2024 AK E-LINE PlugPerf PBU 18-13D 50029217560400 224039 8/2/2024 HALLIBURTON RBT PBU 18-33A 50029225980100 204070 8/13/2024 HALLIBURTON RBT PBU Z-228 50029237180000 222055 7/28/2024 HALLIBURTON PPROF PBU Z-234 50029237620000 223065 7/29/2024 HALLIBURTON IPROF PCU 2 50283200229000 179009 7/9/2024 AK E-LINE TubingCut TBU M-02 50733203890000 187061 8/6/2024 AK E-LINE CBL TBU M-02 50733203890000 187061 8/12/2024 AK E-LINE Perf Please include current contact information if different from above. T39491 T39492 T39493 T39493 T39494 T39495 T39495 T39496 T39497 T39498 T39499 T39500 T39501 T39502 T39502 BRU 241-26 50283201970000 224068 8/12/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.27 11:27:22 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 8/13/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240813 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 222-24 50283201800000 22Ϭ043 8/1/2024 AK E-LINE CIBP BRU 222-26 50283201950000 224035 7/21/2024 AK E-LINE Plug BRU 232-04 50283100230000 162037 7/25/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 7/24/2024 AK E-LINE CBL BRU 241-26 50283201970000 224068 7/31/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/10/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/18/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/23/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/28/2024 AK E-LINE Hoist IRU 44-36 50283200890000 193022 8/3/2024 AK E-LINE CBL IRU 44-36 50283200890000 193022 7/31/2024 AK E-LINE CIBP IRU 44-36 50283200890000 193022 7/29/2024 AK E-LINE RCT MPU I-01 50029220650000 190090 7/20/2024 AK E-LINE CBL MRU M-02 50733203890000 187061 7/20/2024 AK E-LINE Plug PBU PTM P1-08A 50029223840100 202199 7/23/2024 AK E-LINE CBL PBU V-220 50029233830000 208020 6/28/2024 READ InjectionProfileAnalysis PTU DW-01 50089200320000 214206 7/16/2024 READ CaliperSurvey PTU DW-0ϭ 50089200320000 214206 7/17/2024 READ TemperatureSurvey Please include current contact information if different from above. T39418 T39419 T39420 T39421 T39421 T39422 T39422 T39422 T39422 T39423 T39423 T39423 T39424 T39425 T39426 T39427 T39428 T39428 BRU 241-26 50283201970000 224068 7/24/2024 AK E-LINE CBL BRU 241-26 50283201970000 224068 7/31/2024 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.13 13:58:22 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, CTCO, 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): 7,468'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate 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 LTP; N/A 2,932' MD/2,578' TVD; N/A 6,846'7,433'6,811' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 241-26CO 802 Same 6,846'3-1/2" ~1939 psi 4,580' N/A Length August 1, 2024 Tieback 3-1/2" 7,468' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 3,138' Size 120' 3,138' MD Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 2,925' 10,160psi 2,742' 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 ADL 17658 224-068 50-283-20197-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s O 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:50 am, Jul 31, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.07.31 08:33:21 - 08'00' Noel Nocas (4361) 324-443 CT BOP test to 2500 psi. DSR-8/2/24 X BJM 7/31/24 Yes for CTCO only 7/31/24 Bryan McLellan 10-407 A.Dewhurst 01AUG24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.05 11:22:18 -08'00'08/05/24 RBDMS JSB 080624 Well Prognosis Well Name: BRU 241-26 API Number: 50-283-20197-00-00 Current Status: New Drill Well Permit to Drill Number: 224-068 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 2515 psi @ 5757’ TVD (Based on 0.44 psi/ft gradient)) Max. Potential Surface Pressure: 1939 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.74 psi/ft using 14.17 ppg EMW FIT at the surface casing shoe 7/16/24 Shallowest Potential Perf TVD: MPSP/(0.74-0.1) = 1939 psi / 0.64 = 3029‘ TVD (above top of pool) Top of Pools per CO 802: Sterling-Beluga Gas Pool: 3,709’ MD, ~3,215' TVD Well Status: New Drill Initial Completion Brief Well Summary: BRU 222-26 is the third of five grass roots wells drilled in the 2024 Beluga River drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to clean out the liner with coil tubing/nitrogen, and perforate multiple Beluga sands. All sands lie in the Sterling-Beluga Gas Pool. Wellbore Conditions: The well has a 3.5” cemented liner with 9.3 ppg drilling mud, with the 3.5” tubing and annulus displaced to CI inhibited water, with the T & IA pressure tested to 3000 psi on 7/27/24. CBL was run on the drilling rig and provided to AOGCC. The well had a leaking liner top packer, so a second liner top packer was run and tested. Procedure: 1. Review all approved COAs 2. Provide AOGCC 48hrs notice for BOP test 3. MIRU Coiled Tubing 4. PT lubricator to 250psi low / 2500psi high a. Provide AOGCC 48hr notice for BOP test 5. MU cleanout BHA 6. RIH to PBTD (~7,300’ based on Eline tags) cleanout well and swap well over to 8.4 ppg water 7. Once well is clean with 8.4 ppg water, swap to N2 a. Reverse circulate water from well using N2 b.Target recovery = 76bbls i. Coil Reel volume: 34 bbls ii. Tubing x CT annulus volume: 42 bbls 8. Trap 1500 psi on N2 on wellbore 9. RDMO CT 10. MIRU E-line, PT lubricator to 2500 psi 11. Perforate and test Beluga sands within the interval below, from the bottom up: Pool Top (Sterling A1) 3709’ MD 3215’ TVD Planned Interval (Beluga D – I) 4303’ – 6363’ MD 3743’ – 5757’ TVD Shallowest Potential Perf TVD All sands lie in the Sterling-Beluga Gas Pool. 3029‘ TVD (above top of pool) Beluga Gas Pool: 3,709’ MD, ~3,215' TVDSterling- 3743’ – 5757’ TVD Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. b. Frac Calcs: Using 14.17 ppg EMW FIT at the surface casing shoe (0.737 psi/ft frac grad) c. Shallowest Allowable Perf TVD = MPSP/(0.737-0.1) = 1939 psi / 0.637 = 3044‘ TVD 12. RDMO 13. Turn well over to production & flow test well Contingencies: Coil Tubing & Nitrogen Procedure (Contingency if fill is encountered after perforating): 1. MIRU Coiled Tubing, notify AOGCC 48 hours in advance of BOP test, PT BOPE to 2500 psi 2. Clean out to TD (or desired depth by engineer) 3. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations 3044‘ TVD Shallowest Allowable Perf TVD = Updated by CAH 07-30-24 CURRENT SCHEMATIC Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,433’ MD / 6,811’ TVD TD = 7,468’ MD / 6,846’ RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,932’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888 4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.78 ”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’’4”6.540”Ranger Liner Hanger w/ Scout liner to packer OPEN HOLE / CEMENT DETAIL 7-5/8"192 bbls of 12 ppg lead followed by 36 bbls of 15.8 ppg tail, w/85 bbls of returns Cement top job with 3 bbls pumped down on 7/26/24. 3-1/2”184 bbls of 12 ppg lead followed by 27 bbls of 15.3 ppg tail in 6.75” hole. 66 bbls of Cement returned. TOC based on CBL run 7/30/24 @ 3098’. 6-3/4” hole NOTES A second liner hanger/packer was run due to the first packer leaking, July 2024 Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3 4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ TOC based on CBL run 7/30/24 @ 3098’. Updated by DMA 07-30-24 PROPOSED Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,433’ MD / 6,811’ TVD TD = 7,468’ MD / 6,846’ RKB to GL = 20’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 3,138’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”2,932’7,468’ 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992”Surf 2,925’ 116” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 29’3.856”11 Cactus CTF-ONE-CTL 11”x4-1/2” hanger w/ 4” type H BPV profile 2 2,888 4”6.540 Ranger Liner Hanger w/ Scout liner to packer w/ seal assembly 4” off nogo 3 2,925’4.780”5.78 ”5-1/2” 17” Seal Assembly w/ WLEG (10’) 0.73’ off seat 4 2,932’’4”6.540”Ranger Liner Hanger w/ Scout liner to packer OPEN HOLE / CEMENT DETAIL 7-5/8"Est. TOC @ Surface (75% lead excess) L – 188 bbls / T – 22.8 bbls 3-1/2”Est. TOC @ 2,489’ (40% excess) L – 180 bbls / T – 23 bbls 6-3/4” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Pool Top Sterling A1 - 3,709’ MD / 3,215’ TVD Beluga D-I ±4,303’±6,363’±3,743’±5,757’Proposed TBD NOTES A second liner hanger/packer was run due to the first packer leaking, July 2024 Short Joints (~15ft)3438, 4437, 5454, 6443’ RA Tag w/ 15ft short joint 3953, 4945, 5931, 6952’ 2 3 4 RA 3,853’ RA 4,945’ RA 5,931’ RA 6,952’ Pool Top Sterling A1 - 3,709’ MD / 3,215’ TVD 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. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: BRU 241-26 (PTD# 224-068) New well sundry & CBL Date:Wednesday, July 31, 2024 12:47:00 PM Chad, Hilcorp has verbal approval to perform the CT cleanout in this well. Condition of approval is for CT BOP test to 2500 psi. I’ve corrected the well name in the subject line of this email. As noted, the well name was incorrect in previous correspondence below. FYI, the CBL log you sent over is not depth corrected to the wellbore diagram or liner tally. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, July 31, 2024 10:23 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: BRU 241-34 (PTD# 224-068) New well sundry & CBL Attached is the summary for the top job from the daily report. Pumped 4.5 bbls of cement into surface casing annulus. No there is no leaks from the conductor. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, July 31, 2024 9:21 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: BRU 241-34 (PTD# 224-068) New well sundry & CBL 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. Chad, What were the results of the cement top job? Is liquid still leaking from the conductor? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, July 31, 2024 8:58 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: BRU 241-34 (PTD# 224-068) New well sundry & CBL Bryan, We just submitted this morning the Sundry completion for our new well at Beluga River, BRU 241-34. We are hoping we can get a verbal approval for the coil tubing blowdown on this well. The coil schedule in Beluga looks like it could move there as early as tomorrow, with the cleanout and blowdown on Friday. Our wellsite supervisor already submitted a BOP test request. This well is the one that had the leaking liner top packer and the rig set a second one. We did run another CBL on the 3.5” liner where we have free pipe to calibrate the tool and confirm we had good cement after a few days to let it set up, etc. and this log (attached) looks like really good cement too. Let me know if you can provide us with verbal approval for the coil cleanout portion of this work. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Page 1/2 Well Name: BRU 241-26 Report Printed: 7/31/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:7/9/2024 End Date:7/28/2024 Report Number 17 Report Start Date 7/25/2024 Report End Date 7/26/2024 Operation Installed gauge on conductor outlet and monitored pressure build to 8 psi over 2 hours. Welder repaired crack on mud pump threaded cap ring and two hinges in pits, rig electrician and mechanic replaced pulg end on topdrive HPU cable. Started to see water leech out of wellhead flange, removed gauge and drained conductor down to outlets. At 10:57 got approval from AOGCC to run 2nd liner hanger assembly. Staged seal assembly, XO joint and hanger, MU seal assembly, XO pup and XO joint, PU and MU Yellow Jacket liner hanger assembly, mixed and poured Xanstar. PU single HWDP and MU XO, RIH one stand HWDP, MU topdrive, pumped 3.5 bbls to ensure we could circulate at 112'. RIH HWDP stands (total 17 jnts) followed with 37 stands DP to 2924', up wt 40K, dwn 32K. PU kelly jnt and 10' pup, saw no-go tag lower SBR with mule shoe at 2957', PU 1'PU 1' and parked. RU test pump on stand pipe, topfilled 10' pup, MU topdrive, pressured up to 1594 psi and saw 4K loss in string weight, shut down at 1713 psi and held 5 minutes to set hanger. Increased to 2452 psi and held 4 minutes to set packer, saw another 2K loss in string weight. PU to 50K, S/O to 40K, increased pressure to 3250 psi to release run tool, felt pins shear at 2963 psi and held 2 minutes. Bled off pressure and gained 4K in string weight. S/O to 28K, PU to 40K and verified we released from hanger. Pulled up hole 7', S/O to 12K and rotated 5 turns right to transfer weight down on dogsub. Pulled up hole 1 jnt, up wt 40K, TOL = 2888'. Closed upper rams and pumped down kill line 80 gallons to achieve 3000 psi on wellbore. Held 30 min on chart, good test. Bled off and RD test equipment. POOH LD DP, vacuumed wiper balls through pipe on rack, dried and cleaned threads, re-doped and installed thread protectors. Racked back HWDP and L/D running tool. M/U mule shoe and RIH w/ 4.5" DP out of derrick f/ surface t/1660'. P/U-22K, S/O 21K. Circulate a string volume. POOH L/D 4.5" DP to catwalk f/1660' t/ surface. (120 jnts total). M/U mule shoe and RIH w/ HWDP out of the derrick f/ surface t/538'. M/U XO's and Tri-Point storm packer as per rep. RIH w/ 2 stands of DP out of the derrick t/667'. Set and release from packer as per Tri-Point rep. POOH f/123' t/ surface. R/U test equipment and pressure test packer to 500psi/10 min. Bleed down koomy. Remove flow line, riser, koomy lines for kill HCR, choke and kill lines. N/D BOPE from spacer spool. N/D well head. M/U 2 sticks of 1" work string and tag top of cement at 27.3'. R/U and prep to perform cement top job. Report Number 18 Report Start Date 7/26/2024 Report End Date 7/27/2024 Operation Spotted cementers pump and bulk units, RU HP hoses and hardware, ran two joints 1" pipe down into conductor through surface hanger flute and tagged firm cement at 27'. Removed joints and cleared soft cement, XO to 1502 hammer union on top and tied into HP hose. Held PJSM with cementers and rig team. Using pump truck charge pump, washed 1" piping down to 33' from GL and tagged up on hard cement. PU 6" and swapped to 16 ppg cement, pumped 7.5 bbls cement displacing water from conductor, recovered 3 bbls cement at surface leaving 4.5 bbls cement in conductor. Shut down pump, broke off 1502 connection. CIP at 08:00 on 7-26-24. Using winch line, removed 1" piping from wellhead through mousehole to rig floor. Broke connection and flushed piping into cellar box then LD same. Pump truck flushed water though HP hose until clean water into cellar box, then washed up truck to cuttings box. Vac'd out cement and trash water from cellar. At 09:00 we have no water flow from conductor outlet. Stabbed wellhead and spacer spool combined back onto conductor. Wellhead Rep RILD's then tested neck seals at 3500 psi for 10 minutes, good test. At 10:00 we have no water flow from conductor. Set BOP stack on spacer spool and NU. NU choke and kill line flanges, installed flow riser and chained off stack, re-connected koomey lines. Cont to monitor conductor outlet for water flow every hour, no flow. Cement sample is good and hard. Set test plug, flooded stack, choke and kill lines, opened annulus valve, functioned rams, purged air, closed blinds and tested all flange breaks at 250 low, 3000 high for 5 minutes each on chart with no issues. RD test equipment and removed test plug. Witness of testing was waived by AOGCC Jim Regg at 08:34 on 7-26-24. Held PJSM with Tri-Point Rep on retrieving storm packer. MU stinger and XO on stand of DP, eased in hole two stands and tagged packer top. MU TIW on stump, rotated right 14 turns to engage packer, opened TIW and removed same, pulled to 20K and packer is free, allowed packer to relax 5 minutes and POOH racking back 1st stand, L/D single, broke down storm packer and L/D same. No water flow from conductor outlet. RIH 2 stands DP from derrick, then POOH L/D DP and HWDP. CCI vacuumed wiper balls on pipe rack, dried and cleaned threads, re-doped and installed thread protectors. Cleaned and cleared rig floor, RU tubing tongs and elevators, staged seal assembly and brought in 3 1/2" tubing for PU. No water flow from conductor at 18:00, installed 4" cap and valve on outlet. Held PJSM with YJ Rep, tong hand and rig crew. MU seal assembly with 3.41' of seals, 10.23' overall length to no-go. Cont PU single in hole with 3 1/2" 9.2# L-80 EUE tubing t/2882' P/U jnts 97, 98 and space out set down at 2913'. Close bag P/U jnts 97, 98 and space out set down 10K at 2918'. Close bag and put 1000 psi on backside to ensure stung in. L/D jnts 97 and 98. M/U 8.28' space out pup and hanger and land out. Set snap ring, pull test 40k over and PT to 5000psi/10min-good test. R/U test equipment on tubing for MIT-T. Pressure up on tubing, at 2400psi pressure bleed off down to 1400psi, and there was 1000psi on the IA. R/D test equipment. Dis-engauge snap ring, pull hanger to floor and L/D. P/U and RIH w/ jnts 97 and 98. Able to get 9' deeper without even a bobble seen on the weight indicator. L/D tag jnts. M/U 8.07' on bottom of 8.28' pup. M/U hanger, land out, 0.73' off no-go, set snap ring, pull test 40k over and PT 5000psi/10min-good test. R/U test equipment on tubing and perform MIT-T 3000psi/30min charted-good test. Pumped 11.5"/0.68bbl, bleed back 11"/0.65bbl. R/U test equipment on IA and perform MIT-IA 3000psi/30min charted-good test. Pumped 22"/1.31bbl, bled back 22"/1.31bbl. API: 50283201970000 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147Permit to Drill (PTD) #:224-068 Page 2/2 Well Name: BRU 241-26 Report Printed: 7/31/2024www.peloton.com Well Operations Summary Report Number 19 Report Start Date 7/27/2024 Report End Date 7/28/2024 Operation Bled off MIT-IA pressure, BO and L/D landing joint, RD tubing tongs and elevators, PU T bar and set 2 way check in hanger. Flushed pumps, mudline, topdrive, BOP stack, choke line and manifold and poorboy degasser with BarKlean, followed with fresh water, blew everything down and cleaned excess fluid from pits. Opened ram doors for inspection, greased and buttoned up doors. RD gas alarm equipment, prepped trip tank pump for removal. ND flow riser, drip pan and flowline, removed choke and kill lines, hoisted stack and staged in cellar on bridge cranes, removed spacer spool. Staged dry hole tree. Installed dry hole tree (master valve), wellhead rep tested tree, hanger seals and void at 5000 psi for 10 minutes, good test. CCI shipped out upright water tank and cement silo along with various tool baskets. RD service shacks and spooled up elec cords. Removed saver sub, kelly hose and service loop from topdrive, staged cradle and pinned to topdrive, removed torque bushing, un-pinned becket from blocks. RD interconnects between pit modules and pump modules. Shipped out upright water tank and cement silo. RD and shipped out service shacks, L/D topdrive, removed T bar, bridled up, held PJSM, scoped mast down, and LD lower torque tube, brought in crane and transfered BOP stack to cradle, LD poorboy degasser, removed centrifuge, shipped out screen connex, removed trip tank pump for repair. Hang blocks in derrick and fold up wind walls on monkey board. Install shipping beams in sub. Unhook Pason wires. Unspooled drill line from drawworks. Lay over pit roof #3. R/D topdrive HPU. Changed wire rope raising cable on dogdhouse. R/D electrical lines. Lower roofs on pit mods 1 and 2. Lay derrick over and inspect. Flod up electrical grasshopper on pump one. Remove lights, fold up roof flaps and walk ways between mud pumps. Disconnect fuel lines between skids. Fold up v-door on catwalk. API: 50283201970000 Field: Beluga River (BRU) Sundry #: State: ALASKA Rig/Service: Hilcorp 147 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: 7/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 FINAL LWD FORMATION EVALUATION LOGS (07/12/2024 to 07/21/2024) DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 224-068 T39325 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.30 13:22:59 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rance Pederson - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:Rig 147 MIT Test Report Date:Saturday, July 27, 2024 3:18:40 PM Attachments:MIT Hilcorp 147 07-27-24.xlsx BRU 241-26 MIT-T_MIT-IA Chart.pdf Please see the attached MIT test report and chart for BRU 241-26. Rance Pederson Drilling Foreman Beluga River Unit 907-776-6776 office 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. %HOXJD5LYHU8QLW 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2240680 Type Inj N Tubing 0 3100 3100 3100 Type Test P Packer TVD 2547 BBL Pump 0.7 IA 0 60 60 60 Interval O Test psi 3000 BBL Return 0.7 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2240680 Type Inj N Tubing 0 220 220 220 Type Test P Packer TVD 2547 BBL Pump 1.3 IA 0 3075 3075 3075 Interval O Test psi 3000 BBL Return 1.3 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Liner top packer at 2547' TVD, MIT-IA post completion 3.5" x 7.625" Notes: Notes: Hilcorp Alaska LLC Beluga / BRU 241-34S / H Pad Waived Justin Gruenberg 07/27/24 Notes:Liner top packer at 2547' TVD, MIT-T post completion 3.5" tubing and liner Notes: Notes: Notes: BRU 241-26 BRU 241-26 Form 10-426 (Revised 01/2017)2024-0727_MITP_BRU_241-26_2tests -5HJJ 9 9 9 99 9 9 999 9 0,77 0,7,$ CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Regg, James B (OGC) To:McLellan, Bryan J (OGC) Subject:FW: [EXTERNAL] RE: Short Notice oF BOP Break Tests Date:Friday, July 26, 2024 10:50:37 AM Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Rance Pederson - (C) <rpederson@hilcorp.com> Sent: Friday, July 26, 2024 10:47 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: Short Notice oF BOP Break Tests Thank you Jim, top job went well. Tagged hard cement at 33’ with 1” tubing, pumped total 7.5 bbls of 16 ppg cement with 3 bbls to surface. CIP at 08:00. From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Friday, July 26, 2024 8:34 AM To: Rance Pederson - (C) <rpederson@hilcorp.com> Subject: [EXTERNAL] RE: Short Notice oF BOP Break Tests AOGCC witness is waived Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Rance Pederson - (C) <rpederson@hilcorp.com> Sent: Thursday, July 25, 2024 2:24 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: Short Notice oF BOP Break Tests 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. Jim, rig 147 on G pad in Beluga had issue with failed liner lap test on 7-23-24. Decision was made this morning to run a second liner hanger/packer assembly in attempt to seal 1st liner lap. Once hanger #2 is set we will perform a surface casing test. If this test passes, we will set a storm packer, lift the BOP stack and run 1” conduit pipe down through surface hanger flutes and perform a top job between 7 5/8” surface casing and 16” conductor to eliminate the slight water flow we have seen at conductor outlets. Once cemented, we will install BOP stack and test all breaks at 250/3000 psi. I anticipate test time/date to be at 12:00 tomorrow, 7-26-24. Our bi-weekly BOP test is due on 7-30-24, just thought I would update you on current operation. Well: BRU 241-26 on G pad PTD: 224-068 Rance Pederson Drilling Foreman Beluga River Unit 907-776-6776 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. 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. a NA if • We / , 1 e • w •` • ` e • moo 40 41 t i .��. i• r, � ram" .�, .- �_ w 1 f • • • O • lb • •_ :' : . • • �. 4 • ' A Ilop t • r�.s w y ' 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: ___Top Job 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): 7,469'N/A Casing Collapse Structural Conductor Surface 7150 Intermediate 10540 Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 907-223-6784 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng N/A N/A 7/25/2024 N/A N/A 3-1/2"4,535' 3,138' Perforation Depth MD (ft): 7,467' 6,843' 120' 3,138 16" 7-5/8" 120' Burst N/A MD 10160 9470 120' 2,745' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 17658 224-068 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-283-20197-00-00 Hilcorp Alaska, LLC Proposed Pools: AOGCC USE ONLY 7/25/2024 Tubing Grade: Tubing MD (ft): N/A Perforation Depth TVD (ft): N/A Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size Yes 6,845' 7,433' 2441 N/A Subsequent Form Required: Suspension Expiration Date: TVD Sean Mclaughlin sean.mclaughlin@hilcorp.com Drilling Manager Bryan McLellan 6,811 N/A BRU 241-26 Sterling-Beluga Gas PoolSterling-Beluga Gas PoolBeluga River Field Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:25 pm, Jul 25, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.07.25 15:06:06 - 08'00' Sean McLaughlin (4311) 324-430 A.Dewhurst 26JUL24 BJM 7/25/24 10-407 ($8 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.26 15:13:45 -08'00'07/26/26 RBDMS JSB 073024 Well Prognosis Well: BRU 241-26 Date: 7/25/24 Well Name: BRU 241-26 API Number: 50-733-20197-00-00 Current Status: Run Stacker Hanger Estimated Start Date: 7/25/24 Rig: Rig 147 Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: 7/25/24 Regulatory Contact: Cody Dinger 777-8389 Permit to Drill Number: 224-068 First Call Engineer: Sean McLaughlin (907)-223-6784 (M) Second Call Engineer AFE Number: Brief Well Summary: The 7-5/8” surface casing failed to hold pressure during the liner lap test. The pressure loss is 350 psi over 30 min at 3000 psi. A test packer run has confirmed the leak path is past the liner top packer. While troubleshooting the failed casing pressure test water was observed coming out of the 4” conductor valve. The rate is about 0.03 bph with and without pressure on the casing. The water source appears to be from mobile ground water and pressure will build to 9 psi on the conductor. The slow set time of the 12# lead may have allowed ground water contamination prior to building compressive strength. Cement bond logs were run in both the 3-1/2” liner and 7-5/8” casing and show cement behind pipe in both cases. Plan Forward: 1) Run a stacker hanger consisting of a seal stem, 1 joint of 3-1/2” spacer pipe, and YJOC 7-5/8 x 3-1/2” LTP. 2) Use flow down DP to ensure the seals are engaged. 3) Set hanger per YJOC rep (hydraulic hanger set via pressure) 4) Perform 30 min / 3000 psi charted casing test. If failed test, stop work 5) Set storm packer at ~120’. Perform 10 min 2500 psi operational assurance test. 6) Split the stack at the tubing spool to gain access to the conductor flutes. 7) Run 1” workstring and tag TOC. 8) Pump a 16ppg top job (20’ = 3.2 bbls) a. The plan is to use the preloaded 15.8 ppg LCM cement currently available in Beluga as a top job cement. Accelerator will be added and will be mixing to 16ppg. This slurry will be similar to the surface tail cement with a ~2.5 hr pump time. Mixing at 16ppg vs 15.8ppg will shorten this thickening time slightly as well. This slurry will build gel strength significantly quicker than the surface lead cement which should be better suited for staying in place after placement. 9) NU wellhead and test the break. 10) Monitor conductor for flow hourly. 11) Run 3-1/2” tie back as planned. Attachments: 1) Wellbore Schematic 2) Wellhead Schematic Updated by CJD 7/25/24 Current SCHEMATIC Beluga River Unit BRU 241-26 PTD: 224-068 API: 50-283-20197-00-00 PBTD = 7,433’ MD / TVD = 6,811’ TD = 7,469’ MD / TVD = 6,845’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 3,138’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” 2,932’ 7,467’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 2,932’ Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 7-5/8" L – 440 sx / T – 174 sx Top Job needed ground water aquifer entering the well and exiting the 4” conductor valve. 3-1/2” L – 432 sx / T – 122 sx 6-3/4” hole 11’’ 5M Beluga River systemϭϲΖ͛4 ½͛͛Tree assy, 4 1/16 5M x3 1/8 5M wing sectionCactus, CTF-CFL-R-DBLOWellhead system,ϭϭΖ͛5MAPI quick connect top w/ 2- 22/16 5M SSOBeluga River UnitGrass roots system16 x 7 5/8 x 4 1/2ϳϱͬϴΖ͛On DiverterϭϲΖ͛ϳϱͬϴΖ͛On BOPϰΖ͛LPϳϱͬϴΖ͛ 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:FW: BRU 241-26 10-403 Change to Approved Program - Top Job Sundry Date:Thursday, July 25, 2024 4:39:00 PM Attachments:BRU 241-26 10-403 Change to Approved Top Job Submitted 7-25-24.pdf Hilcorp has verbal approval to proceed with the work described in the sundry. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Cody Dinger <cdinger@hilcorp.com> Sent: Thursday, July 25, 2024 3:11 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: BRU 241-26 10-403 Change to Approved Program - Top Job Sundry Hello, Attached is the 10-403 for BRU 241-26, change to approved program – top job sundry. Thank you! Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, 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. From:McLellan, Bryan J (OGC) To:Sean McLaughlin Subject:RE: [EXTERNAL] RE: BRU 241-26 casing integrity (PTD 224-068) Date:Thursday, July 25, 2024 10:47:00 AM Sean, Hilcorp has approval to proceed with the plan of setting the liner top packer and performing the casing test. I am in agreement with your plans for the top job, but please submit a sundry application that includes a bit more detail and current wellbore diagram & wellhead diagram. Thanks 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: Thursday, July 25, 2024 7:27 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BRU 241-26 casing integrity (PTD 224-068) The Cement logs for the 7-5/8” and 3-1/2” are attached. There is now variable flow out the 4” outlet without any pressure on the casing. The latest measurement was 0.02 bph. The volumes are so small accurate rate measurements are difficult. We started looking at the conductor outlet after the failed test and assuming they were related. After watching for 36 hrs now we believe there are two separate issues. 1) Failing LTP 2) Surface water flow (artesian or tidal). Suggested plan forward: 1. Set another LTP and perform a casing test. This can be done under out existing PTD. 2. Set a storm packer, split the wellhead, run 1” pipe through the conductor flute, perform top job. This would require a sundry. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Regards, sean From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Wednesday, July 24, 2024 5:37 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BRU 241-26 casing integrity (PTD 224-068) Bryan, We were trying to figure how to get cement on the outside of casing. A squeeze with these loss rates is not super promising as you know. We discussed shooting the 7-5/8” but there is no guarantee you will hit the channel and casing integrity will be compromised. Cement will likely be frac’d away rather than go into the channel. It is likely the channel will bridge over time. If the squeeze fails what is the next step, more holes? That is when we started to discuss the value of the 3-1/2” liner cement. If there is good cement 200’ below where you would punch the holes in the 7-5/8” wouldn’t that be an effective barrier? We were thinking another liner top packer for a casing barrier since that is already an acceptable barrier. However, if we wanted cement to bridge the gap, we could cement in the bottom 500’ of the 3-1/2” tie back. The QA/QC of the cement looks good as does the lab reports. We drilled hard cement out of the 7-5/8” shoe, so it set up as expected, as did the surface samples. I can’t explain what happened on the outside or why it appears so many barriers failed. There is probably something we don’t understand but should treat it as a channel for now. We are running the cement logs now. Afterward let’s discuss a plan forward. I’d like to see what the 3-1/2” liner cement looks like first. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, July 24, 2024 3:36 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: BRU 241-26 casing integrity (PTD 224-068) Seems like you need to get some cement outside casing. Can you shoot holes above the liner top, squeeze cement, run short scab liner with LTP across holes or something like that? Is there an issue with your cement quality control? CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Wednesday, July 24, 2024 2:35 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Chad Helgeson <chelgeson@hilcorp.com> Subject: BRU 241-26 casing integrity (PTD 224-068) Bryan, The 7-5/8” surface casing failed to hold pressure during the liner lap test. The pressure loss is 350 psi over 30 min at 3000 psi. A test packer run has confirmed the leak path is past the liner top packer. It appears that there may be a channel to surface. We just completed a flow test with the following results: 1000 psi, started seeing water trickle out 4” conductor outlet at 250 psi. At 1000 psi, flow rate at .06 bph. Lost 30 psi over 12 minutes. 2000 psi. 5 minute flow check was .05 bph. 15 minute flow check was .035 bph. Lost 120 psi over 30 minutes. 3000 psi. 5 minute flow check was .027 bph. 20 minute flow check was .026 bph. Lost 350 psi over 30 minutes. The suspected leak path is: Through 7-5/8” liner top packer – set appears to be good, pusher tool stroked fully, sufficient weight available to set the packer Past 3-1/2” x 7-5/8” liner lap - the 205’ lap had 66 bbls of cmt to surface Around the 7-5/8” shoe - drilled up solid cement in the shoe track and good FIT test Up 3138’ of 7-5/8” annulus - good surface job, plugs bumped, 15.8 tail and 12# lead, 85 bbls of cmt to surface, been in place for 8 days. Out the conductor We are currently rigging up to run cement bond logs across the 3-1/2” liner and 7-5/8” casing. I suspect we will see good cement behind the 7-5/8” and good cement behind 3-1/2” liner. If that is the case would setting another liner top packer mitigate the issue? sean The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________BELUGA RIV UNIT 241-26 JBR 08/27/2024 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:TJ 4-1/2" DP. There were no turns in the vent line it is straight. Good test. TEST DATA Rig Rep:Kenneth PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Contractor/Rig No.:Hilcorp 147 PTD#:2240680 DATE:7/12/2024 Well Class:DEV Inspection No:divKPS240712150642 Inspector Kam StJohn Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:NA NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:9.88 P Vent Line(s) Size:16 P Vent Line(s) Length:108.9 P Closest Ignition Source:92 P Outlet from Rig Substructure:97.3 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:P Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:32 P Knife Valve Open Time:18 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P1600 200 psi Recharge Time:P44 Full Recharge Time:P123 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2600 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: NA NAMud System Misc: 9 9 9 9 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: Beluga River Unit, Sterling-Beluga Gas Pool, BRU 241-26 Hilcorp Alaska, LLC Permit to Drill Number: 224-068 Surface Location: 2054' FNL, 597' FWL, Sec 25, T13N, R10W, SM, AK Bottomhole Location: 375' FNL, 1296' FEL, Sec 26, T13N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this 13th day of June 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.13 15:17:36 -08'00' 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: 7,469' TVD: 6,845' 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): 41.7 15. Distance to Nearest Well Open Surface: x-323851 y-2628295 Zone-4 23.2 to Same Pool:1455' to BRU 244-23 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 36 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 3,139' Surface Surface 3,139' 2,753' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,530' 2,939' 2,591' 7,469' 6,845' Tieback 3-1/2" 9.2# L-80 EUE 2,939' Surface Surface 2,939' 2,591' 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 7/1/2024 3727' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 Tieback Assy. 1480 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): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 1055 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 3125 GL / BF Elevation above MSL (ft): 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 - 1012 ft3 / T - 131 ft3 2441 861' FNL, 750' FEL, Sec 26, T13N, R10W, SM, AK 375' FNL, 1296' FEL, Sec 26, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2054' FNL, 597' FWL, Sec 25, T13N, R10W, SM, AK ADL 17658 BRU 241-26 Beluga River Unit Sterling-Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 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 05/22/24 Monty M Myers By Grace Christianson at 3:19 pm, May 22, 2024 224-068 Submit FIT/LOT data within 48 hrs of performing test. BOP test to 3000 psi, annular test to 2500 psi 50-283-20197-00-00 DSR-5/22/24BJM 6/13/24 SFD 6/13/2024*&:JLC 6/13/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.06.13 15:17:53 -08'00' 06/13/24 06/13/24 RBDMS JSB 061424 BRU 241-26 PTD Program Beluga River Unit May 121, 2024 BRU 241-26 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................11 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................12 11.0 Drill 9-7/8” Hole Section..............................................................................................................14 12.0 Run 7-5/8” Surface Casing..........................................................................................................16 13.0 Cement 7-5/8” Surface Casing....................................................................................................18 14.0 BOP N/U and Test........................................................................................................................21 15.0 Drill 6-3/4” Hole Section..............................................................................................................22 16.0 Run 3-1/2” Production Liner......................................................................................................24 17.0 Cement 3-1/2” Production Liner................................................................................................27 18.0 3-1/2” Liner Tieback Polish Run................................................................................................31 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................32 20.0 Diverter Schematic ......................................................................................................................33 21.0 BOP Schematic.............................................................................................................................34 22.0 Wellhead Schematic.....................................................................................................................35 23.0 Anticipated Drilling Hazards......................................................................................................36 24.0 Hilcorp Rig 147 Layout...............................................................................................................38 25.0 FIT/LOT Procedure ....................................................................................................................39 26.0 Choke Manifold Schematic.........................................................................................................40 27.0 Casing Design Information.........................................................................................................41 28.0 6-3/4” Hole Section MASP..........................................................................................................42 29.0 Spider Plot w/ 660’ Radius for SSSV.........................................................................................43 30.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................44 Page 2 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 1.0 Well Summary Well BRU 241-26 Pad & Old Well Designation BRU G Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 7469 MD / 6845’ TVD PBTD, MD / TVD 7369’ MD AFE Number AFE Drilling Days AFE Drilling Amount Maximum Anticipated Pressure (Surface)2441 psi Maximum Anticipated Pressure (Downhole/Reservoir)3125 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 41.70’ Ground Elevation 23.2’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 2.0 Management of Change Information Page 4 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 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”-84 X-56 Weld 2980 1410 - Surface 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 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. 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 day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: 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 May 21, 2024 BRU 241-26 Drilling Procedure PTD 6.0 Planned Wellbore Schematic Casing detail states 3-1/2" SFD Page 7 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 7.0 Drilling / Completion Summary BRU 241-26 is an S-shaped directional grassroots development well to be drilled from BRU G Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~250’ MD. Maximum hole angle will be ~36 deg. and TD of the well will be 7469’ TMD/ 6845’ TVD, ending with 10 deg inclination left in the hole. Vertical separation will be 2524 ft. Drilling operations are expected to commence approximately July, 2024. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 3139’ MD / 2753’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 147 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to 3139’ MD. Run and cmt 7-5/8” surface casing. 4. Test casing to 3500 psi. Perform 14.0# FIT 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to 7469’ MD. Perform Wiper trip. 7. Run and cmt 3-1/2” production liner. 8. Displace well to 6% KCL completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo y Sterling and Beluga sands Page 8 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of BRU 241-26. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must 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 approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. Page 9 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Page 10 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 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) Page 11 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 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 landing ring on conductor. 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 # 147, 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 9-7/8” 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 12 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Estimated Diverter line orientation on BRU G Pad: Page 13 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Page 14 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: 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. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 3139’ MD/ 2753’ 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 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” 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 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 15 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-3139’8.8 – 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 ALDACIDE G X-TEND II 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 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 16 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing 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 7-5/8” 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 Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 17 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 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. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 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. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 13.0 Cement 7-5/8” 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 How to handle cmt returns at surface. x 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. 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 + 75% lead open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 19 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2639’ MD to surface)Tail Slurry (3139’ to 2639’ MD) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Verified Cement Calcs -bjm Page 20 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 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. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 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 Page 21 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff 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 2-7/8” x 5” variable 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 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 22 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 15.0 Drill 6-3/4” 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 and conduct shallow hole test of MWD to 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 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3139’- 7469’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 Page 23 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 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 assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 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. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 13.6# ppg FIT will result in a 27 bbl KTV. 15.14 Drill 6-3/4” hole section to 7469’ MD / 6845’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 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. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Lost circulation potential when drilling through Beluga D and E (4392’ -4988’ MD). 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. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA Page 24 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA 15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYD 563 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. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. 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 16.4. Continue running 3-1/2” production liner 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 Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 25 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Page 26 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. 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. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 27 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 17.0 Cement 3-1/2” Production Liner 17.1. 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 How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x 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. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 28 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (6969’ MD to 2939’ MD)Tail Slurry (7469’ to 6969’ 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 Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs -bjm Page 29 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Page 30 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Backup release from liner hanger: 17.21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 17.22. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 17.24. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes. Page 31 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure 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 sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker procedure. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 32 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Install chemical injection mandrel at ~1,500’ MD. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.48 hr notice required. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.48 hr notice required. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #147 Page 33 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 20.0 Diverter Schematic Page 34 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 21.0 BOP Schematic Page 35 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 22.0 Wellhead Schematic Page 36 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: 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 ensure 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. No abnormal pressures or temperatures are present in this hole section. Page 37 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. 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. No abnormal temperatures are present in this hole section. Page 38 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 24.0 Hilcorp Rig 147 Layout Page 39 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 25.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 40 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 26.0 Choke Manifold Schematic Page 41 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 27.0 Casing Design Information Page 42 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 28.0 6-3/4” Hole Section MASP Page 43 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 29.0 Spider Plot w/ 660’ Radius for SSSV Page 44 Version PTD May 21, 2024 BRU 241-26 Drilling Procedure PTD 30.0 Surface Plat As-Built FWL SFD ! "# $ % -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500True Vertical Depth (1000 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 Vertical Section at 311.50° (1000 usft/in) BRU 241-26 Tgt1 7 5/8" Casing 3 1/2" Liner 500 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 000 5 5 00 600 0 6 50 0 7 0 00 7469 BRU 241-26 wp03 Start Dir 2º/100' : 250' MD, 250'TVD Start Dir 3º/100' : 450' MD, 449.84'TVD End Dir : 1544.85' MD, 1465.83' TVD Start Dir 2º/100' : 3567.16' MD, 3098.4'TVD End Dir : 4875.68' MD, 4291.7' TVD Total Depth : 7468.87' MD, 6845.5' TVD STERLING_A1 STERLING_B STERLING_C BELUGA_D BELUGA_E BELUGA_F BELUGA_G BELUGA H BELUGA_I BRU_BELUGA_J Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: BRU 241-26 23.20 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2628295.95 323851.86 61° 11' 24.4644 N 150° 59' 54.0419 W SURVEY PROGRAM Date: 2024-04-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 3139.00 BRU 241-26 wp03 (BRU 241-26) 3_MWD+AX+Sag 3139.00 7468.87 BRU 241-26 wp03 (BRU 241-26) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3203.70 3162.00 3695.54 STERLING_A1 3364.70 3323.00 3884.83 STERLING_B 3508.70 3467.00 4048.22 STERLING_C 3705.70 3664.00 4264.56 BELUGA_D 3915.70 3874.00 4488.08 BELUGA_E 4263.70 4222.00 4847.22 BELUGA_F 4717.70 4676.00 5308.25 BELUGA_G 5044.70 5003.00 5640.29 BELUGA H 5729.70 5688.00 6335.86 BELUGA_I 6274.70 6233.00 6889.27 BRU_BELUGA_J REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 241-26, True North Vertical (TVD) Reference:Permit RKB @ 41.70usft (HEC 147) Measured Depth Reference:Permit RKB @ 41.70usft (HEC 147) Calculation Method:Minimum Curvature Project:Beluga River Site:BRU G-Pad Well:Plan: BRU 241-26 Wellbore:BRU 241-26 Design:BRU 241-26 wp03 CASING DETAILS TVD TVDSS MD Size Name 2753.00 2711.30 3139.31 7-5/8 7 5/8" Casing 6845.50 6803.80 7468.87 3-1/2 3 1/2" Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 250' MD, 250'TVD 3 450.00 4.00 280.00 449.84 1.21 -6.87 2.00 280.00 5.95 Start Dir 3º/100' : 450' MD, 449.84'TVD 4 1544.85 36.17 312.23 1465.83 231.32 -291.54 3.00 35.47 371.63 End Dir : 1544.85' MD, 1465.83' TVD 5 3567.16 36.17 312.23 3098.40 1033.47 -1175.29 0.00 0.00 1565.04 Start Dir 2º/100' : 3567.16' MD, 3098.4'TVD 6 4875.68 10.00 311.50 4291.70 1374.21 -1552.88 2.00 -179.71 2073.62 BRU 241-26 Tgt1 End Dir : 4875.68' MD, 4291.7' TVD 7 7468.87 10.00 311.50 6845.50 1672.59 -1890.14 0.00 0.00 2523.92 Total Depth : 7468.87' MD, 6845.5' TVD 0125250375500625750875100011251250137515001625South(-)/North(+) (250 usft/in)-2125 -2000 -1875 -1750 -1625 -1500 -1375 -1250 -1125 -1000 -875 -750 -625 -500 -375 -250 -125 0 125 250West(-)/East(+) (250 usft/in)BRU 241-26 Tgt17 5/8" Casing3 1/2" Liner2505007501000125015001750200022502500275030003250350037504000425045004750500052505500575060006250650067506846BRU 241-26 wp03Start Dir 2º/100' : 250' MD, 250'TVDStart Dir 3º/100' : 450' MD, 449.84'TVDEnd Dir : 1544.85' MD, 1465.83' TVDStart Dir 2º/100' : 3567.16' MD, 3098.4'TVDEnd Dir : 4875.68' MD, 4291.7' TVDTotal Depth : 7468.87' MD, 6845.5' TVDCASING DETAILSTVDTVDSS MDSize Name2753.00 2711.30 3139.31 7-5/8 7 5/8" Casing6845.50 6803.80 7468.87 3-1/2 3 1/2" LinerProject: Beluga RiverSite: BRU G-PadWell: Plan: BRU 241-26Wellbore: BRU 241-26Plan: BRU 241-26 wp03WELL DETAILS: Plan: BRU 241-2623.20+N/-S +E/-WNorthingEastingLatitudeLongitude0.00 0.002628295.95 323851.86 61° 11' 24.4644 N 150° 59' 54.0419 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 241-26, True NorthVertical (TVD) Reference:Permit RKB @ 41.70usft (HEC 147)Measured Depth Reference:Permit RKB @ 41.70usft (HEC 147)Calculation Method:Minimum Curvature & ! 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(/:'!/!!'=)/ !/('= "6 :")'/!= "='"6 )')) /)'6= " //=':" !)')) = (6'() ! = ' ! ( '(6/!!'=)/ !/'6 "6 :" '=)= "::')))')) /('!: 4 %E; " ))')) !)')) = (6':( ! = 6'") ! (=!'!//!!'=)/ ! '(! "6 :(')!= (=!'!()')) //:'/ " =))')) !)')) = :6!'/= ! ="!'!! ! (" '!//!!'=)/ !!!':: "6 ::/'(!= : 6'"=)')) /=='": " "))')) !)')) = 6:6':/ ! =('" ! ((('! /!!'=)/ )66')= "6 :6=' != 6 :'!/)')) /(/')= " ())')) !)')) " )::'/! ! =: '! ! (6)'! /!!'=)/ ):"'/ "6 6)('!" ) "'"!)')) /6)' ! " :))')) !)')) " !:"'(6 ! =6='"/ ! :)/'!=/!!'=)/ )(/' ) "6 6!:':" ! =')6 )')) )('(( " ::6'( !)')) " ( '() ! ")='6) ! :! '("/!!'=)/ )"!'6= "6 66'(" //')))')) /': E4 %EF " 6))')) !)')) " :='( ! ")('! ! :!"'!=/!!'=)/ )")'=( "6 6/)'=" /'=()')) ='! ( )))')) !)')) " /:/'(= ! "!:'" ! :6'!"/!!'=)/ ) ('( "6 6 '" / ')=)')) '=) ( !))')) !)')) " :'/ ! "/)'!= ! : '!(/!!'=)/ )/ '6 "6 6=/'6/" )'=/)')) =6':( ( ))')) !)')) " =:)'(! ! " !'"= ! :=='!(/!!'=)/ )')6 "6 6"='"/" =/6')!)')) (('/ ( /))')) !)')) " "(6'!6 ! "=/'!" ! :":'!:/!!'=)/ ))6'" "6 6(('//" "/(' 6 )')) 6 '") ( ))')) !)')) " ((('"( ! "" '"( ! ::!'!:/!!'=)/! 66"' / "6 6:6') " (/='6()')) =!!'6" ( ":':( !)')) " : ='=) ! "('=6 ! :6)'! /!!'=)/! 6:('") "6 66('!)" :)/':))')) =/'6 * , 0CB=BC?/,B@=@?*+,6D *#1' 06'# 0 *+, 7")9 1 0# 7")9 4# 7")9 516 7")9 546- 7")9 *# , # 789 , ,= 789 !"2! 6!'() "6 "6/'" / /)' ! /( '! ! =='::)')) )')) ? + ))'))- + , 0 7")9 /" , 0 7")9 !# ,' 7D9 ,' 7D91' !# (=<:; (=/'))/ !/6'/!(=<: 6(<: /!<;" : ='=)( ":':(/!< "/< & ! ' ( ! ) *+, ) - -. !" !" "$(!" /0 #$$ $%& !'()*+,! (- ,# !".)/ ,.0123 0 4 /, )$%& !'()*+,! (- 1 0 ) 5 !" 2 /" , 0 7")9 + , 0 7")9 , , 7891' 0 #( , 789 3 ' + , 0 ::'): / 6!='() , @, / "6='= / )/'() 2,A0@ ! )')) " '=" / ()='() , @4 " //=':" = (6'() , @A / :: ':/ / /" '() 2,A0@ )')) = " )'6 = ) '() , = /):'= (!('() , @ : (' "/'() , @B " ::6'( " ( '() @, @C ) :' / =):'() 2,A0@ )')) /" , 0 7")9 + , 0 7")9 546- 7")9 516 7")9 ! ! '' =)')) =)')) )')) )')) 4D<!))>=)>#4 =)>2E4 =)')) 6': !'! "':( 4/D<!))> =)>#4 6': >2E4 ! = ':= ! "=':/ /!'/ 6!'= ,4!= ':=>#4 ! "=':/>2E4 / ="('!" / )6:' ) ! )//' ( ! !(='6 4D<!))>/="('!">#4 /)6:' >2E4 :(='": 6!'() ! /( '! ! ==':: ,4 :(='":>#4 6!'(>2E4 ( ":':( " : ='=) ! "('=6 ! :6)'! 2 4?( ":':(>#4 ": ='=>2E4 !"#"$%!&%!&%!&'()$ !"#!"$%!&!%!&!%!&' *)"+ ),*#(-.#$&/012013/1%2/&4,&%5%%62&73%15106127.-) *$"89%2: (,4%:- $2:&/2/: (2; #)*2 <$12%1 #$0%4 # #2= ((#2;+4 # !"#"$ $ >$ >$%& ("$%!&!%!&'.3!.?3!)9; #)*; ), (-4 , (-9; #)*= # #2= ((#2;+4 # 3 $2:&/2/: (2; #)*2 *)"+ ),*#(-()$ !"#!"$%!&!%!&!%!&'; #)* #; . !"#'"(%('"(%('"(%)"&* "+&% +&+ "+&+ "&",+"+&%- ('"(%('"(%('"(%)*&) *%& %&, *%&% *&.*%& ('"(%('"(%('"(%*"&)/ /%& +&+* /)&.% )&)*/%&- ( =, (->, (- @" >"+&% )0").& '*"(/) )123!4! 5)0").& ,0*/+&+, '*"(/) )123!4! 5 6 7 89(& 7 :&- 7 7 $ &- ; $#< $( =& 5 :: & 7 752676-7 8 7 6& 0.000.751.502.253.00Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)BRU 212-25No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: Plan: BRU 241-26 NAD 1927 (NADCON CONUS) Alaska Zone 0423.20+N/-S+E/-W NorthingEastingLatitudeLongitude0.00 0.002628295.95 323851.86 61° 11' 24.4644 N 150° 59' 54.0419 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 241-26, True NorthVertical (TVD) Reference: Permit RKB @ 41.70usft (HEC 147)Measured Depth Reference:Permit RKB @ 41.70usft (HEC 147)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2753.00 2711.30 3139.31 7-5/8 7 5/8" Casing6845.50 6803.80 7468.87 3-1/2 3 1/2" LinerSURVEY PROGRAMDate: 2024-04-30T00:00:00 Validated: Yes Version: Depth From Depth ToSurvey/PlanTool18.50 3139.00 BRU 241-26 wp03 (BRU 241-26)3_MWD+AX+Sag3139.00 7468.87 BRU 241-26 wp03 (BRU 241-26) 3_MWD+AX+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Measured Depth (1000 usft/in)BRU 212-25GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 7468.87Project: Beluga RiverSite: BRU G-PadWell: Plan: BRU 241-26Wellbore: BRU 241-26Plan: BRU 241-26 wp03Ladder/S.F. Plots 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. 224-068 BRU 241-26 Beluga River Sterling-Beluga Gas WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 241-26Initial Class/TypeSTR / PENDGeoArea820Unit50220On/Off ShoreOnProgramSTRField & PoolWell bore segAnnular DisposalPTD#:2240680BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes Entire Well lies within ADL0017658.2 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by CO 8024 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 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 proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2441 psi. BOP rated to 5k psi (BOP test to 3000 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 H2S not anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.119 to 0.457 psi/ft (2.3 to 8.8 ppg EMW). Depleted36 Data presented on potential overpressure zonesNA reservoirs anticipated from Sterling A to Beluga F (~3700' to 5300' MD).37 Seismic analysis of shallow gas zonesNA Operator's planned mud program appears sufficient to control anticipated38 Seabed condition survey (if off-shore)NA pressures and maintain wellbore stability.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/13/2024ApprBJMDate6/13/2024ApprSFDDate6/13/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDatePrincipal hazards include stuck pipe, lost circulation, wellbore instability, and running coal seams. LCM materials will be available onsite. Mitigation measures are discussed in Drilling Hazards section of application. SFD*&:JLC 6/13/2024