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220-058
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: 11/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251107 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Please include current contact information if different from above. T41066 T41067 T41068 T41068 T41069 T41069 T41070 T41071 T41072 T41073 T41074 T41074 T41075 T41076 T41077 T41078 T41079 T41080 T41081 T41082 T41083 T41084 BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.07 15:03:51 -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: Snubbing, 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): 8,001'6299 & 6321 Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi 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 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: Beluga River Hilcorp Alaska, LLC Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: 6.5# / L-80 chelgeson@hilcorp.com Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-058 50-283-20182-00-00 Proposed Pools: 17# / P-110 ICY TVD Burst 2,506' 10,600psi PRESENT WELL CONDITION SUMMARY Perforation Depth TVD (ft):Tubing MD (ft): 4,342' Size 138' 2,731' MD Tubing Size: 2-7/8" 2,980psi 5,750psi 138' 2,050' 138' September 22, 2025 5-1/2"See Schematic See Schematic; N/A See Schematic; N/A Sterling-Beluga Gas Pool 16" 9-5/8" ~1,466psi 5,506' 2,731' Length 5,261' 5-1/2"8,001' Perforation Depth MD (ft): See Schematic See Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-26CO 802A Same 6,789' 6,789'6,473' m n P s t N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:47 am, Sep 12, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.09.12 10:22:06 - 08'00' Noel Nocas (4361) 325-557 BJM 9/15/25 10-404 A.Dewhurst 15SEP25 DSR-9/12/25JLC 9/16/2025 Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.17 13:06:57 -08'00'09/17/25 RBDMS JSB 091925 Well Prognosis Well Name: BRU 212-26 API Number: 50-283-20182-00-00 Current Status: Gas Producer Permit to Drill Number: 220-058 First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8663 (C) Maximum Expected BHP: 1658 psi @ 3858’ TVD (Based on 0.43 psi/ft gradient) Max. Potential Surface Pressure: 1466 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.70 psi/ft using 13.53 ppg EMW FIT at the Surface shoe (2761ft) Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 1466 psi / 0.6 = 2,443‘ TVD Top of Applicable Gas Pool: ~3,937’ MD/ ~2,845’ TVD Brief Well Summary Drilled & completed in 2020, BRU 212-26 is an online producer in the Beluga River Undefined Gas Pool with a 5- 1/2” completion. In June 2023 the well began struggling to stay unloaded and additional perforations were added in the Beluga sands. In November of 2023 a 2-7/8” velocity string was snubbed in to the well. Objective: The purpose of this work/sundry is to increase production above unloading rate by adding additional perforations in the Beluga D sands. All sands lie in the BELUGA RIVER, UNDEFINED GAS POOL per CO 802A. Wellbore Conditions: x Flowing at ~1400mcf @ 112 psi with 4 bwpd x 5-1/2” TOC @ ~3400’ from CBL 9-4-20 x 2-7/8” V-string tubing run to 4342’ x X-nipple with 2.313” ID @ 4337’ x Unknown pipe restriction @ 3320’ (able to get through with flexible tool strings & strip guns) Procedure 1. RU E-line, PT lubricator to 250/2000 psi 2. Perforate Beluga sands within the below intervals with the well shut-in using 1-11/16” Strip guns at 4 spf: Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Formation MD TOP MD BASE TVD TOP TVD BASE H Top Pool ~3,937' ~2,845' BEL D1 ±4,871' ±4,881' ±3,665' ±3,675' ±10 BEL D1 ±4,885' ±4,895' ±3,679' ±3,688' ±10 BEL D2 ±4,900' ±4,907' ±3,693' ±3,700' ±7 BEL D3 ±4,913' ±4,917' ±3,706' ±3,710' ±4 BEL D3 ±4,928' ±4,942' ±3,720' ±3,734' ±14 BEL D4 ±4,962' ±4,966' ±3,753' ±3,757' ±4 BEL D5 ±4,990' ±4,995' ±3,781' ±3,786' ±5 BEL D6 ±5,034' ±5,050' ±3,824' ±3,840' ±16 BEL D7 ±5,063' ±5,069' ±3,853' ±3,858' ±6 Updated by CAH 09-08-25 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 2-7/8” Tubing 6.5 L-80 TBD 2.441” Surf 4,342’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 18 18’ 2.441 Hanger 2 7/8" EUE lift & suspend, 2" Type "H" BPV profile 2 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 3 4,337’ 3,175’ 2.313” X-nipple 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga E1 5,134’ 5,150’ 3,923’ 3,939’ 1.69” 3/22/25 Open Beluga E2 5,166' 5,169' 3,955' 3,958' 1.69” 3/22/25 Open Beluga E3 5,200' 5,203' 3,988' 3,991' 1.69” 3/21/25 Open Beluga E3 5,208' 5,212' 3,996' 4,000' 1.69” 3/21/25 Open Beluga E5 5,252' 5,257' 4,040' 4,045' 1.69” 3/18/25 Open Beluga E5 5,320' 5,327' 4,108' 4,115' 1.69” 3/18/25 Open Beluga E6 5,351' 5,366' 4,139' 4,154' 1.69” 3/17/25 Open Beluga E6 5,375’ 5,382’ 4,163’ 4,170’ 1.69” 3/17/25 Open Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open Beluga F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open Beluga F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open Beluga F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open Beluga G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open Beluga G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open (Continued on following page) OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 227 bbls (640 sx) of 12ppg lead followed by 31 bbls (115 sx) 15.3ppg tail. Lost 6 bbls during job, no cement or spacer at surface. TOC @ 3,400’ (CBL dated 9-4-2020) 1 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J FISH DETAIL @ 6,298’: 1.75” (22.5’ OAL) Workstring: rope socket (6") 2x Weight bar (10') Knuckle joint (6") Oil jars (3.5') Spangs(7.5')- 1.77 Blind box(6"), 5' 1.75 Go devil cutter bar 5' 1.50 Sheeps foot cutter bar. Possible 5' .125 wire. (11/18/23) FISH DETAIL @ 6,321’: 3.181” OD Pump out plug (11/18/23) 6 Bel H7 5 Bel H5 7 2 4 Bel F4-F7 Bel G1-G2 Bel G5-H4 3 Bel E1-E6 Restriction @ ~3320’ Updated by DMA 06-27-25 – Page 2 of 2 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PERFORATION DETAIL (continued from previous page) Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated Updated by DMA 08-28-25 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 2-7/8” Tubing 6.5 L-80 TBD 2.441” Surf 4,342’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 18 18’ 2.441 Hanger 2 7/8" EUE lift & suspend, 2" Type "H" BPV profile 2 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 3 4,337’ 3,175’ 2.313” X-nipple 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Top of Pool per CO 802A: ~3,937’ MD/2,845’ TVD Top of PA (BLM) BEL D1 ±4,871' ±4,881' ±3,665' ±3,675' 1.69” Proposed TBD BEL D1 ±4,885' ±4,895' ±3,679' ±3,688' 1.69” Proposed TBD BEL D2 ±4,900' ±4,907' ±3,693' ±3,700' 1.69” Proposed TBD BEL D3 ±4,913' ±4,917' ±3,706' ±3,710' 1.69” Proposed TBD BEL D3 ±4,928' ±4,942' ±3,720' ±3,734' 1.69” Proposed TBD BEL D4 ±4,962' ±4,966' ±3,753' ±3,757' 1.69” Proposed TBD BEL D5 ±4,990' ±4,995' ±3,781' ±3,786' 1.69” Proposed TBD BEL D6 ±5,034' ±5,050' ±3,824' ±3,840' 1.69” Proposed TBD BEL D7 ±5,063' ±5,069' ±3,853' ±3,858' 1.69” Proposed TBD BEL E1 5,134’ 5,150’ 3,923’ 3,939’ 1.69” 3/22/25 Open BEL E2 5,166' 5,169' 3,955' 3,958' 1.69” 3/22/25 Open BEL E3 5,200' 5,203' 3,988' 3,991' 1.69” 3/21/25 Open BEL E3 5,208' 5,212' 3,996' 4,000' 1.69” 3/21/25 Open BEL E5 5,252' 5,257' 4,040' 4,045' 1.69” 3/18/25 Open BEL E5 5,320' 5,327' 4,108' 4,115' 1.69” 3/18/25 Open BEL E6 5,351' 5,366' 4,139' 4,154' 1.69” 3/17/25 Open BEL E6 5,375’ 5,382’ 4,163’ 4,170’ 1.69” 3/17/25 Open BEL F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open BEL F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open BEL F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open BEL F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open BEL F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open BEL F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open BEL F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open BEL F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open (Continued on following page) OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 227 bbls (640 sx) of 12ppg lead followed by 31 bbls (115 sx) 15.3ppg tail. Lost 6 bbls during job, no cement or spacer at surface. TOC @ 3,400’ (CBL dated 9-4-2020) 1 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J Restriction @ ~3320: Swedged with 2.3” with KJ. Flexible tools make it through. 3/12/25 FISH DETAIL @ 6,298’: 1.75” (22.5’ OAL) Workstring: rope socket (6") 2x Weight bar (10') Knuckle joint (6") Oil jars (3.5') Spangs(7.5')- 1.77 Blind box(6"), 5' 1.75 Go devil cutter bar 5' 1.50 Sheeps foot cutter bar. Possible 5' .125 wire. (11/18/23) FISH DETAIL @ 6,321’: 3.181” OD Pump out plug (11/18/23) 6 Bel H7 5 Bel H5 7 2 4 Bel F4-F7 Bel G1-G2 Bel G5-H4 3 Bel E1-E6 Bel D Restriction @ ~3320’ Updated by DMA 08-28-25 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PERFORATION DETAIL (continued from previous page) Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status BEL F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open BEL F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open BEL G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open BEL G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open BEL G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open BEL G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open BEL G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open BEL G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open BEL G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open BEL H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open BEL H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open BEL H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open BEL H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open BEL H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open BEL H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open BEL H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open BEL H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open BEL H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated BEL H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated BEL H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated BEL I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated BEL J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated BEL J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated BEL J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated 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: 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 8,001 feet See schematic feet true vertical 6,789 feet 6,299 & 6,321 feet Effective Depth measured 6,473 feet 2,495 feet true vertical 5,261 feet 1,913 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet V-String 2-7/8" 6.5# / L-80 4,342' MD 3,180' TVD Tubing (size, grade, measured and true vertical depth)5-1/2" 17# / P-110 ICY 2,506 MD 1,919 TVD Packers and SSSV (type, measured and true vertical depth)See Schematic 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: 16" 9-5/8" 138' chelgeson@hilcorp.com 907-777-8405 8,730psi 2,980psi 5,750psi 10,600psi 2,731' 2,050' Casing Pressure Tubing Pressure measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-058 50-283-20182-00-00 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: FEDA029657 Beluga River / Sterling-Beluga Gas Beluga River Unit (BRU) 212-26 Plugs Junk measured Length Burst 4 1001910 0 577 64 Production Liner 5,506' 6,789'8,001' 0 Gas-Mcf MD 92 Size 138' 2,731' Collapse 1,410psi 3,090psi Casing Structural 138'Conductor Surface Intermediate Chad Helgeson, Operations Engineer 325-094 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 699 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 measured true vertical Packer Representative Daily Average Production or Injection Data 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517) Date: 2025.04.10 14:22:34 - 08'00' Chad Helgeson (1517) By Gavin Gluyas at 2:36 pm, Apr 10, 2025 DSR-4/11/25 RBDMS JSB 041825 BJM 6/26/25 Page 1/2 Well Name: BRU 212-26 Report Printed: 4/2/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20182-00-00 Field Name:Beluga River State/Province:ALASKA Permit to Drill (PTD) #:220-058 Sundry #:325-094 Rig Name/No: Jobs Actual Start Date:2/13/2025 End Date: Report Number 1 Report Start Date 2/28/2025 Report End Date 3/1/2025 Last 24hr Summary PJSM, Crew mob to location, Spot in & rig up, Pick up lube & tool string (1-11/16" PT), Pressure test 250/2000-good, Run in hole with PT tools, Tag @ 5491, Fluid @ 4400', Pull out of hole, Secure well & rig down. Report Number 2 Report Start Date 3/6/2025 Report End Date 3/7/2025 Last 24hr Summary PJSM, Crew mob to location, Spot in & rig up, Rehead (5/2), Pick up lube & tools (1 x wt bar, 1 x CCL/GR, 1 x SS, 1 x gun 7' loaded 6'), Pressure test 250/2000- good, Run in the hole to tag @ 3320, Pull out of hole, Pick up run #2, (CCL/WT bar/GR 2"), Run in hole, Tag @ 3320, Pull out of hole, Pick up run #3 (CCL/WT Bar/GR 1.84"), Run in hole, Tag @ 3320', Pull out of hole, Pick up run #4 (CCL/WT Bar/ GR 1.69"), Run in hole, Tag @ 3320', Pull out of the hole secure well, Ops flow well overnight. Report Number 3 Report Start Date 3/7/2025 Report End Date 3/8/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Cut line & rehead (5/2), Pick up lube & tool string (CCL/1-11/16 wt bar, 2" wt bar, 2" GR), Pressure test 250/2000-good, Run in hole, Tag @ 3316', Pull out of hole, Pick up run #2 (CCL/1-11/16 wt bar, 2" wt bar, 2" plug), Run in the hole, Tag @ 3316, Pull out of hole, Pick up un #3 (CCL/1-11/16 wt bar, 2" wt bar, Bow centralizer), Run in hole, Tag @ 3316', Pull out of hole, Pick up run #4 (CCL/1-11/16 wt bar, Knuckle, 2" wt bar, Bow Centralizer), Run in hole, Tag @ 3316', Pull out of hole, Rig down & release AK Eline Report Number 4 Report Start Date 3/11/2025 Report End Date 3/12/2025 Last 24hr Summary SL MIRU, PT lube 2500 psi, pass. Attempt to c/o tight spots @ 3322' 3326'slm 1 1/2'' tool string will pass 1.75'' tool string will not. SDFN Report Number 5 Report Start Date 3/12/2025 Report End Date 3/13/2025 Last 24hr Summary PJSM, travel to lcoation, Pick up & rig up lube & tool string, Pressure test 250/2500-good, Make passes with 1.75" stem, 2.25" tools, Make passes from 3322- t/3400, Run assortment of BHA with 1.75" stem 2.25" to 2.4" all passed thru obstruction, Pick up 2.25" stem with 2.3 swedge stack @ 3306, Run 1.75" stem with 5'x 2-1/8" stem tag @ 3310, Pick up up 1.75" stem with 2.12 gr run in hole 4400 ft, Pull out, Secure well & rig down. Report Number 6 Report Start Date 3/15/2025 Report End Date 3/16/2025 Last 24hr Summary PJSM, Crew travel to IRU & mob equipment to H-pad, Spot in & rig up, Pull line & cut 1150', Pick up lube & tools (1-11/16" GPT), Pressure test 250/2000-good, Run in hole to 5116' (found a broken strand of wire @ 5116'), Pull out of hole @ 30 ft/min inspecting line, Secure well & rig down for the night Report Number 7 Report Start Date 3/16/2025 Report End Date 3/17/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Cut 6210', of line check remaining line for breaks, Pick up lube & tool string (1-11/16" gpt total length 21.5'), Pressure test 250/2000-good, Run in hole, Tag @ 5496, Pull out of hole, Pick up run #2 (1 x wt bar, 1 x ss, 1 x CCL, 1 x 2-1/8 gun), Run in hole, Tag @ 3310 (4 attempts), Pull out of hole & secure well. Report Number 8 Report Start Date 3/17/2025 Report End Date 3/18/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tools (1 x wt bar, 1 x SS, 1 x CCL, 1 x 1-11/16" 7' gun), Stab on & pressure test 250/2000- good, Run in the hole, Correlate, Perf BEL E6 5375-5382 (6 SPF 7' gun), Pull out of hole, Pick up & make up run #2, Run in the hole, Correlate, Perf BEL E6 5356- 5366 (4 spf 10' gun), Pull out of the hole, Pick up & make up run #3, Run in the hole, Correlate, Perf Bel E6 5251-5355 (4 SPF 5' gun), Pull out of the hole, Secure well & rig down for the night. Report Number 9 Report Start Date 3/18/2025 Report End Date 3/19/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, (trouble shoot crane & Counter head),Pick up lube & tool string (1 x wt bar, 1 x ss, 1 x ccl, 1 x 7' gun 1- 11/16"), Pressure test 250/2000-good, Run in the hole, Correlate, Perf BEL E5 5320-5327, Pull out of hole, Pick up & make up run #2 (1 x wt bar, 1 x ss, 1 x ccl, 1 x 5' gun 1-11/16"), Run in hole, Correlate, Perf BEL E3 5252-5257, Pull out of hole, Secure well, Rig down & release AK ELINE Report Number 10 Report Start Date 3/21/2025 Report End Date 3/22/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tool string ( 1 x wt bar, 1 x GPT, 1 x Spangs, 1 x 1.69" GR), Pressure test 250/2000 psi-good, Run in the hole with run #1, Tag @ 3308', Pull out of hole, Drop wt bar, Run back in hole with run #2 (1 x GPT, 1 x spangs 1 x GR 1.19"), Tag @ 3320, Pull out of hole, Pick up Run # 3 (1 x wt bar, 1 x ss, 1 x CCL, 1 x 4' x 1-11/16"), Run in the hole, Tag @ 3320, Pull out of hole, Change BHA, Pick up & make up run #4, (1 x wt bar, 1 x CCL/GR, 1 x 1- 11/16" x 4' gun), Run in the hole, Correlate, Perf BEL E3 5208-5212, Pull out of the hole, PIck up & make up run #5, (1 x wt bar, 1 x CCL, 1 x 1-11/16" x 3' gun) Run in the hole, Correlate, Perf BEL E3 5200-5203, Pull out of hole, Secure well & rig down for the night. qp , p Perf BEL E6 5375-5382 (6 SPF 7' gun ,g@ Perf BEL E3 5208-5212,, Perf BEL E3 5200-5203 , Perf BEL E3 5252-5257, f BEL E6 5356-g, 5366 ( pp, Perf Bel E6 5251-5355 5351' verified by Chad Helgeson email 7/1/25 -bjm Perf BEL E5 5320-5327 Updated by DMA 04-02-25 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 2-7/8” Tubing 6.5 L-80 TBD 2.441” Surf 4,342’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 18 18’ 2.441 Hanger 2 7/8" EUE lift & suspend, 2" Type "H" BPV profile 2 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 3 4,337’ 3,175’ 2.313” X-nipple 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga E1 5,134’ 5,150’ 3,923’ 3,939’ 2-1/8” 3/22/25 Open Beluga E2 5,166' 5,169' 3,955' 3,958' 2-1/8” 3/22/25 Open Beluga E3 5,200' 5,203' 3,988' 3,991' 2-1/8” 3/21/25 Open Beluga E3 5,208' 5,212' 3,996' 4,000' 2-1/8” 3/21/25 Open Beluga E5 5,252' 5,257' 4,040' 4,045' 2-1/8” 3/18/25 Open Beluga E5 5,320' 5,327' 4,108' 4,115' 2-1/8” 3/18/25 Open Beluga E6 5,251' 5,355' 4,039' 4,143' 2-1/8” 3/17/25 Open Beluga E6 5,356' 5,366' 4,144' 4,154' 2-1/8” 3/17/25 Open Beluga E6 5,375’ 5,382’ 4,163’ 4,170’ 2-1/8” 3/17/25 Open Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open Beluga F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open Beluga F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open Beluga F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open Beluga G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open Beluga G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open (Continued on following page) OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 227 bbls (640 sx) of 12ppg lead followed by 31 bbls (115 sx) 15.3ppg tail. Lost 6 bbls during job, no cement or spacer at surface. TOC @ 3,400’ (CBL dated 9-4-2020) 1 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J FISH DETAIL @ 6,298’: 1.75” (22.5’ OAL) Workstring: rope socket (6") 2x Weight bar (10') Knuckle joint (6") Oil jars (3.5') Spangs(7.5')- 1.77 Blind box(6"), 5' 1.75 Go devil cutter bar 5' 1.50 Sheeps foot cutter bar. Possible 5' .125 wire. (11/18/23) FISH DETAIL @ 6,321’: 3.181” OD Pump out plug (11/18/23) 6 Bel H7 5 Bel H5 7 2 4 Bel F4-F7 Bel G1-G2 Bel G5-H4 3 Bel E1-E6 5351? Superseded Updated by DMA 04-02-25 – Page 2 of 2 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PERFORATION DETAIL (continued from previous page) Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40256 T40256 T40257 T40257 T40258 T40259 T40260 T40261 T40262 T40263 T40264 T40265 T40266 T40267 T40268 T40269 T40270 T40271 T40272 BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.02 12:55:27 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250318 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-51 50733204640000 195004 3/1/2025 READ CAliperSurvey AN-51 50733204640000 195004 3/1/2025 READ CaliperSurvey/SBHPS BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF BRU 241-34S 50283201980000 224077 3/1/2025 AK E-LINE PPROF IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper MRU A-12RD 50733200760100 171029 3/7/2025 AK E-LINE Correlation MRU A-13 (REVISED)50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-32RD2 50733204620200 217091 3/4/2025 AK E-LINE Correlation PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT PBU 16-24A 50029215360100 224158 2/23/2025 HALLIBURTON RBT-COILFLAG PBU F-21 50029219490000 189056 2/25/2025 READ CaliperSurvey SD37-DSP01 50629234510000 211089 2/28/2025 HALLIBURTON WFL-TMD3D Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40221 T40221 T40222 T40222 T40223 T40224 T40225 T40226 T40226 T40227 T40228 T40229 T40230 T40231 T40232 T40233 T40234 BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.18 15:55:41 -08'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, March 5, 2025 3:51 PM To:Chad Helgeson Cc:Donna Ambruz Subject:RE: BRU 212-26 (PTD# 220-058) Sundry # 325-094 Additional perfs Chad, Hilcorp has approval to add the additional perfs highlighted below as part of the sundry 325-094. Regards 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: Tuesday, March 4, 2025 3:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: BRU 212-26 (PTD# 220-058) Sundry # 325-094 Additional perfs Bryan, Our geologist just added a couple more intervals we would like to perforate that were not included in the original sundry request for BRU 212-26. These are in between zones we requested in original sundry. Please let us know if we have approval to add these perfs to Sundry # 325-094. The zones highlighted in yellow are the zones we would like to add to the existing sundry. SAND MD TOP MD BASE TVD TOP TVD BASE FOOTAGE TOP POOL 3,937 2,845 Beluga E1 5,134 5,150 3,923 3,939 16 Beluga E2 5,167 5,169 3,956 3,958 2 Beluga E3 5,200 5,203 3,988 3,991 3 Beluga E3 5,208 5,212 3,996 4,000 4 Beluga E3 5,252 5,257 4,040 4,045 5 Beluga E5 5,320 5,327 4,108 4,115 7 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Beluga E6 5,351 5,366 4,139 4,154 15 Beluga E6 5,375 5,382 4,163 4,170 7 Please let me know if you need any additional information. Thank you, 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 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. 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: Snubbing, 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): 8,001'6299 & 6321 Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi 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 PRESENT WELL CONDITION SUMMARY Perforation Depth TVD (ft): 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: Hilcorp Alaska, LLC Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: 6.5# / L-80 chelgeson@hilcorp.com Beluga River Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-058 50-283-20182-00-00 Tubing Size: 2-7/8" Length Proposed Pools: 17# / P-110 ICY TVD Burst 2,506' 10,600psi 2,050' 138' 2,731' Tubing MD (ft): 4,342' Size 138' 2,731' MD 2,980psi 5,750psi 138' March 3, 2025 5-1/2" 8,001' Perforation Depth MD (ft): Sterling-Beluga Gas Pool 16" 9-5/8" See Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-26CO 802A Same 6,789' See Schematic; N/A See Schematic; N/A 6,789'6,473'5,261' 5-1/2" ~1,402psi 5,506' See Schematic See Schematic m n P s t N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Gavin Gluyas at 3:52 pm, Feb 20, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.20 15:04:14 -09'00' DSR-2/20/25SFD 2/25/2025 325-094 Perforate 10-404 BJM 2/27/25*&: 2/27/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.27 13:20:05 -09'00' RBDMS JSB 022825 Well Prognosis Well Name: BRU 212-26 API Number: 50-283-20182-00-00 Current Status: Gas Producer Permit to Drill Number: 220-058 First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8663 (C) Maximum Expected BHP: 1818 psi @ 4163’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1402 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.70 psi/ft using 13.53 ppg EMW FIT at the Surface shoe (2761ft) Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 1402 psi / 0.6 = 2,336‘ TVD Top of Applicable Gas Pool: ~3,937’ MD/ ~2,845’ TVD Brief Well Summary Drilled & completed in 2020, BRU 212-26 is an online producer in the Beluga River Undefined Gas Pool with a 5- 1/2” completion. In June 2023 the well began struggling to stay unloaded and additional perforations were added in the Beluga sands. In November of 2023 a 2-7/8” velocity string was snubbed in to the well. Rate has dropped off enough that additional perfs need to be added. Objective: The purpose of this work/sundry is to increase production above unloading rate by adding additional perforations in the Beluga E sands. All sands lie in the BELUGA RIVER, UNDEFINED GAS POOL. Wellbore Conditions: x Flowing at ~800mcf @ 55 psi with 3 bwpd x 5-1/2” TOC @ ~3400’ from CBL 9-4-20 x 2-7/8” V-string tubing run to 4342’ x X-nipple with 2.313” ID @ 4337’ x 1.77” BB tagged @ 6321’ on 11-18-23 Procedure 1. RU E-line, PT lubricator to 250/2000 psi 2. Perforate Beluga sands within the below intervals with the well shut-in: Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Formation MD TOP MD BASE TVD TOP TVD BASE H Top Pool ~3,937' ~2,845' Bel E1 ±5,134’ ±5,150’ ±3,923’ ±3,939’ ±16 Bel E3 ±5,252’ ±5,257’ ±4,040’ ±4,045’ ±5 Bel E5 ±5,320’ ±5,327’ ±4,108’ ±4,115’ ±7 Bel E6 ±5,351’ ±5,366’ ±4,139’ ±4,154’ ±15 Bel E6 ±5,375’ ±5,382’ ±4,163’ ±4,170’ ±7 Sterling-Beluga SFD Sterling Beluga Gas Pool Updated by CAH 2-16-25 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 2-7/8” Tubing 6.5 L-80 TBD 2.441” Surf 4,342’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 18 18’ 2.441 Hanger 2 7/8" EUE lift & suspend, 2" Type "H" BPV profile 2 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 3 4,337’ 3,175’ 2.313” X-nipple 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open Beluga F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open Beluga F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open Beluga F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open Beluga G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open Beluga G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Perorations continued on Page 2 OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 227 bbls (640 sx) of 12ppg lead followed by 31 bbls (115 sx) 15.3ppg tail. Lost 6 bbls during job, no cement or spacer at surface. TOC @ 3,400’ (CBL dated 9-4-2020) 1 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J FISH DETAIL @ 6,298’: 1.75” (22.5’ OAL) Workstring: rope socket (6") 2x Weight bar (10') Knuckle joint (6") Oil jars (3.5') Spangs(7.5')- 1.77 Blind box(6"), 5' 1.75 Go devil cutter bar 5' 1.50 Sheeps foot cutter bar. Possible 5' .125 wire. (11/18/23) FISH DETAIL @ 6,321’: 3.181” OD Pump out plug (11/18/23) 6 Bel H7 5 Bel H5 7 2 4 Bel F4-F7 Bel G1-G2 Bel G5-H4 3 Updated by CAH 2-16-25 – Page 2 of 2 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PERFORATION DETAIL (Continued) Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated Updated by CAH 02-16-25 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 2-7/8” Tubing 6.5 L-80 TBD 2.441” Surf 4,342’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 18 18’ 2.441 Hanger 2 7/8" EUE lift & suspend, 2" Type "H" BPV profile 2 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 3 4,337’ 3,175’ 2.313” X-nipple 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga E1 ±5,134’ ±5,150’ ±3,923’ ±3,939’ 2-1/8” TBD Proposed Beluga E3 ±5,252’ ±5,257’ ±4,040’ ±4,045’ 2-1/8 TBD Proposed Beluga E5 ±5,320’ ±5,327’ ±4,108’ ±4,115’ 2-1/8 TBD Proposed Beluga E6 ±5,351 ±5,366’ ±4,139’ ±4,154’ 2-1/8 TBD Proposed Beluga E6 ±5,375’ ±5,382’ ±4,163’ ±4,170’ 2-1/8 TBD Proposed Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open Beluga F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open Beluga F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open Beluga F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open Beluga G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open Beluga G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 227 bbls (640 sx) of 12ppg lead followed by 31 bbls (115 sx) 15.3ppg tail. Lost 6 bbls 1 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J FISH DETAIL @ 6,298’: 1.75” (22.5’ OAL) Workstring: rope socket (6") 2x Weight bar (10') Knuckle joint (6") Oil jars (3.5') Spangs(7.5')- 1.77 Blind box(6"), 5' 1.75 Go devil cutter bar 5' 1.50 Sheeps foot cutter bar. Possible 5' .125 wire. (11/18/23) FISH DETAIL @ 6,321’: 3.181” OD Pump out plug (11/18/23) 6 Bel H7 5 Bel H5 7 2 4 Bel F4-F7 Bel G1-G2 Bel G5-H4 3 Bel E Updated by CAH 02-16-25 – Page 2 of 2 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 during job, no cement or spacer at surface. TOC @ 3,400’ (CBL dated 9-4-2020) PERFORATION DETAIL (Continued) Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated 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: Snubbing, Install V-String 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 8,001 feet See schematic feet true vertical 6,789 feet 6,299 & 6,321 feet Effective Depth measured 6,473 feet 100 & 2,495 feet true vertical 5,261 feet 100 & 1,913 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet V-String 2-7/8" 6.5# / L-80 4,342' MD 3,180' TVD Tubing (size, grade, measured and true vertical depth)5-1/2" 17# / P-110 ICY 2,506 MD 1,919 TVD 114 MD Packers and SSSV (type, measured and true vertical depth)See Schematic K-Valve 114 TVD 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: 8,730psi 2,980psi 5,750psi 10,600psi 2,731' 2,050' Burst Collapse 1,410psi 3,090psi Casing Structural 6,789'8,001' 138'Conductor Surface Intermediate 16" 9-5/8" 138' 2,731' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-058 50-283-20182-00-00 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: FEDA029657 Beluga River / Sterling-Beluga Gas* Beluga River Unit (BRU) 212-26 Plugs Junk measured Length Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 56 Size 138' 12 2361979 0 16412 236 Production Liner 5,506' *Beluga River, Strlg-Beluga Gas Pool, Prod Code 92500 Jake Flora, Operations Engineer 323-521 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1163 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 jake.flora@hilcorp.com 907-777-8442 N/A measured true vertical Packer Representative Daily Average Production or Injection Data 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 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.12.01 15:01:34 - 09'00' Noel Nocas (4361) By Grace Christianson at 3:34 pm, Dec 01, 2023 Rig Start Date End Date 11/8/23 11/18/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 PJSM, Review IRP-15 compliant TSI SOP for Snubbing pipe, Check Pressure on well, 700 psi, calculate Force, & transition point to heavy. P/U Jewlrey - Pup, x-nipple with PX plug, Pup, full joint, 10' marker pup, RIH t/above tubing spool, Shut in & test t/3060psi (1.3x BHP-2306psi =2998psi) from below good, P/U pump out plug & install on bottom of assy. Test from below t/3120psi good, install safety valve, Equalize & open well, open safety vavle check pressure, none, remove safety valve. Snub in hole P/U 2 7/8" L-80 6.5# EUE 8rd velocity string to full heavy transition @1034', Continue stripping in hole f/1034' t/4466'' up wt 48k dn wt 33k, string stacked out, p/u with 20k over pull, worked pipe down t/4469' unable to go down, pulling heavy till free, confer with Engineer decision made to pull up hole and land out. POOH m/u hanger w/TWC & landing Joint. RIH land placing tubing tail @ 4342', RILD pins, Pull test 10k good, open safety valve no pressure, R.D landing joint, close Blinds, test top of hanger, 3000psi Good. Blow Down lines, R/D pipe racks, prep snubbing unit to R/d, R/D circulating lines, accumulator lines, gas alarms, suck out & prep pits, prep accumulator, Down stack snubbing unit w/work basket, load trucks as available & transport to barge landing. N/D primary BOPE, N/U tree adaptor & master vavle, test void t/5k good, test neck seals t/5k good. Continue loading trucks mobing Eq. to barge landing. 11/08/2023 - Wednesday PJSM, discuss Day plan, and hazzards. Continue move Eq. from F pad to H pad, prep well site for stacking unit, check wellhead closed to master vavle good, N/D tree to master valve, N/U tubing spool. N/U primary BOPE with snubbing unit subbase, stack up rest of snubbing unit, secure same. spot aux secure well for night. 11/09/2023 - Thursday PJSM, discuss Day plan, and hazzards. Continue R/U aux e.q, pump lines, choke panel etc, c/o 2 3/8 slips & rams t/2 7/8", install work basket landings. R/U pick up line, R/U handling Eq. hook up eq. lines, R/U test Eq. M/U 2 7/8" Test joint, Fill surface eq. with test water, cycle & purge air. Test BOPE as per Hilcorp & AOGCC requirements, witness was waived By AOGCC inspector Jim Regg, Test with 2 7/8" Test Jt, 250/3000, Test Gas alarms good. 11/10/2023- Friday 11/11/2023 - Saturday PJSM, Discuss daily operations, Travel to location, Nipple up production tree & test to 5000 psi-good test. Shut in & secure well, Hand over to production. hanger w/TWC & landing Joint. RIH land placing tubing tail @ 4342', RILD pins, Pull test 10k good, open safety valve no & test t/3060psi (1.3x BHP-2306psi =2998psi) from below good, P/U pump out plug & install on bottom of assy. Test from below t/3120psi good, install safety valve, Equalize & open well, open safety vavle check pressure, none, remove hanger w/TWC & landing Joint. RIH land placing tubing tail @ 4342', RILD pins, Pull test 10k good, open safety valve no safety valve. Snub in hole P/U 2 7/8" L-80 6.5# EUE 8rd velocity string to full heavy transition @1034', Continue stripping joint, Fill surface eq. with test water, cycle & purge air. Test BOPE as per Hilcorp & AOGCC requirements, witness was waived By AOGCC inspector Jim Regg, Test with 2 7/8" Test Jt, 250/3000, Test Gas alarms good. PJSM, Review IRP-15 compliant TSI SOP for Snubbing pipe, Check Pressure on well, 700 psi, calculate Force, & transition Rig Start Date End Date 11/8/23 11/18/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 11/18/2023 -Saturday RIH W/ 1.77 Blind box to 4325'WL/4343KB- W/T- KO pump out plug- pull back to 4315'WL/4333'KB- Continue in hole to 6329'WL/6347'KB- Tag- POOH to 6303'WL/6321'KB & Hang up- No Spang action- No Jar action-work wire- cannot Cutters arrive- Gather man lift & prep bars- Drop 1.75 Go devil- No cut & no movement gained- prep and drop 1.50 Sheeps foot cutter bar- Successful cut- POOH - Line counter indicates all wire recovered- Possible 5' attached to Updated by DMA 11-27-23 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545 MD / TVD = 5,333 TD = 8,001 MD / TVD = 6,789 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681 Surf 2,731 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892 2,495 8,001 TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892 Surf 2,506 2-7/8 Tubing 6.5 L-80 TBD 2.441 Surf 4,342 JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100 100 2.813 Baker KB Packer, tailpipe, X-nipple, OAL 22 (set 2/25/22), 48k shear release 2 114 114 2.813 3-1/2 X-nipple 3 2,495 1,913 6.170 8.430 Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 4 4,337 3,175 X-nipple 5 6,473-6,488 5,261- 5,276 15 Cement Plug dump bailed on 1-21-22 6 6,545 5,333 5.500 CIBP set 10/21/20 7 6,633 5,421 5.500 MAP CIBP set on 10/18/20 8 7,500 6,288 5.500 CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496 5,505 4,284 4,293 3-3/8 2/9/22 Open Beluga F5 5,587 5,591 4,375 4,379 3-3/8 2/9/22 Open Beluga F6 5,632 5,641 4420 4429 2-3/8 9/2/23 Open Beluga F6 5,653 5,661 4441 4449 2-3/8 9/2/23 Open Beluga F7 5,725 5,730 4,513 4,518 3-3/8 2/8/22 Open Beluga F7 5,737 5,757 4,525 4,545 3-3/8 2/9/22 Open Beluga F7 5,781 5,787 4,569 4,575 3-3/8 2/8/22 Open Beluga F7 5,793 5,797 4581 4585 2-3/8 9/2/23 Open Beluga F10 5,866 5,878 4654 4666 2-3/8 9/2/23 Open Beluga F10 5,892 5,895 4680 4683 2-3/8 9/2/23 Open Beluga G1 5,960 5,963 4748 4751 2-3/8 9/2/23 Open Beluga G1 5,968 5,971 4756 4759 2-3/8 9/2/23 Open Beluga G2 5,994 6,012 4,782 4,800 2-7/8 2/8/22 Open Beluga G5 6,110 6,115 4,898 4,903 2-7/8 12/20/21 Open Beluga G6 6,136 6,141 4,924 4,929 2-7/8 12/20/21 Open Beluga G7 6,162 6,166 4,950 4,954 2-7/8 12/20/21 Open Beluga G9 6,224 6,229 5,012 5,017 2-7/8 12/20/21 Open Beluga H 6,283 6,289 5,071 5,077 2-7/8 12/20/21 Open Beluga H 6,318 6,321 5,106 5,109 2-7/8 12/20/21 Open Beluga H1 6,337 6,341 5,125 5,129 2-7/8 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8 09/29/20 Open Beluga H3 6,420 6,429 5,208 5,217 2-7/8 8/10/21 Open Beluga H4 6,447 6,459 5,231 5,243 2-7/8 12/19/21 Open Beluga H4 6,450 6,460 5,233 5,243 2-7/8 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2 TOC @ 3,400 (CBL dated 9-4-2020) 1 & 2 16 9-5/8 12-1/4 hole 5-1/2 Bel H15 Bel I Bel J FISH DETAIL @ 6,298: 1.75 (22.5 OAL) Workstring: rope socket (6") 2x Weight bar (10') Knuckle joint (6") Oil jars (3.5') Spangs(7.5')- 1.77 Blind box(6"), 5' 1.75 Go devil cutter bar 5' 1.50 Sheeps foot cutter bar. Possible 5' .125 wire. (11/18/23) FISH DETAIL @ 6,321: 3.181 OD Pump out plug (11/18/23) 7 Bel H7 6 Bel H5 8 3 5 Bel F4-F7 Bel G1-G2 Bel G5-H4 4 From:Jacob Flora To:McLellan, Bryan J (OGC) Cc:Joshua Stephenson - (C); Harold Soule - (C); Regg, James B (OGC); Rixse, Melvin G (OGC); Harold Soule - (C) Subject:RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Compliance (COA #5) Date:Saturday, October 28, 2023 4:54:35 PM Attachments:image002.png Hello Bryan, I believe the below chapters of IRP 15 are most relevant to our project. Working with our WSMs I’ve compiled in the below table what we believe are the pertinent chapters and how we plan on addressing the requirements. We will be addressing the side load analysis in a separate email. Lastly, the egress descender will be available for inspection on Wednesday during the BOP test. Please advise on anything additional you require in your review, Thanks, Jake Jake, The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and demonstrate how they will comply with each. The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a snubbing BOP stack on BRU 222-34 and BRU 212-26. AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket. IRP Chapter / Component Compliance Requirement IRP 15.01.07 BHA components fit in snubbing stack 27' of stack heigth between gate valve & snubbing annular, current BHA is 10' Min one plug in tubing 2 plugs are planned: pump out plug & PX plug Run a marker pup joint in tubing above BHA pup marker joints are planned IRP 15.01.08 Snubbing forces calculated on site Will be done on site, performed by operator Tubing buckling calculations Will be done on site, performed by operator Pipe heavy calculations done for MPSP Completed for MPSP of 2394 psi, pipe heavy at 1769' IRP 15.01.08.02 Prejob calculations including: max snubbing force required, depth of neutral point, critical buckling load of tubing string, collapse point of tubing Will be done on site, performed by operator IRP 15.01.09.01 Explosive mixture in casing Well is currently online and gas packed with no exposure to allowing air in the casing IRP 15.01.10 Written Procedure requirement TSI Snubbing SOP Job Scope requirement AOGCC Approved Sundry IRP 15.01.11 Vendor selection Team Snubbing International IRP 15.01.12 Supervisory control Hilcorp Wellsite Manager (WSM) IRP 15.02.02 Plugs shall be tested to 1.3x BHP (1.3 x 2394 psi = 3112psi) The PX plug has been shop tested to 5000psi. The pump out plug will be tested during the BOP test. Will be done on site during BOP test IRP 15.02.04 Certification Manufacturer spec sheet available for 2-3/8" pump out plug IRP 15.03.01 Regulatory requirements must be followed for all primary BOP equipment AOGCC Regulation/BOP test Install shear ram as the lowest primary BOP Blind shear ram is planned per approved sundry Minimum of one hole volume on site Hilcorp will have 240 bbls KWF on location (1.5x WBV (160 bbls x 2) IRP 15.03.02 Unit shall have engineered fall protection IRP 15.03.04 Certification & Inspection TSI HWO Unit is certified & inspected per IRP15. All certifications available on site. IRP 15.05.01 Worker training TSI training competencies and documentation available on site IRP 15.06.01 Hazard Assessment PJSM will review hazard assessments per TSI JSA / SOP for Tripping CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Pipe Into Wellbore IRP 15.06.02 Hazards PJSM will review IRP 15.06.02 Table 8 Hazard Register IRP 15.07.2 Joint Safety Meetings Hilcorp WSM will hold JSM prior to performing work with multiple vendors or services on site. Agenda will include a risk assessment, specific safety requirements, supervisory control, well shut in procedures, responsibilities, egress, and communication for and during SIMOPS. IRP 15.07.3 Meeting Guidance Involve ALL personnel in PJSMs. IRP 15.08.02 Pre-job calculations Will be done on site, performed by operator IRP 15.08.03 Egress from snubbing platform Emergency egress system to be shown to AOGCC inspector IRP 15.08.04 Primary BOPE tested per regulations AOGCC witnessed BOP test Installing tubing hanger or FOSV Perform 10 min low test to 200 psi, 10 min high pressure test to 3000 psi. Perform 10 min leak test to WHP if hanger is not landed IRP 15.08.05 Contingency Practices PJSM will review different failure mechanisms and the corrective action to then take place as detailed in IRP 15.8.5 IRP 15.08.06 Snubbing in the Dark:Hilcorp will have sufficient light plants on location IRP 15.08.07.01 Cold Weather Ops/Heaters Hilcorp will have multiple heaters on location IRP 15.08.09 Setting Jack Pressure Follow steps 1-11 in IRP 15.8.9 to set hydraulic jack pressure IRP 15.08.13 Landing tubing hanger Hilcorp WSM & TSI supervisor will ensure tubing hanger lock down screws are fully engaged & pull test is completed prior to bleeding off stack pressure above IRP 15.08.24.03 Overnight shut ins Ensure operation is in pipe heavy condition or out of the hole Ensure dual barriers in tubing: two tubing plugs are in place, TIW in place Ensure dual barriers in annulus: close multiple rams and lock Night watch required per AOGCC COA # 9 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Saturday, October 28, 2023 6:20 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12) Jake, The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and demonstrate how they will comply with each. The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a snubbing BOP stack on BRU 222-34 and BRU 212-26. AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> 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. Sent: Friday, October 27, 2023 11:21 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com> Subject: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12) Hello Bryan, Please see attachments meant to satisfy the below outlined COAs. These are the requirements that have to be met at this time per my understanding. Please let me know if you have questions or need anything additional as you review- Thanks, Jake COA Attachment 5 Snubbing SOP 6 Calculations below in this email (new pipe heavy depth = 1769’ with 1850 psi SITP) 8 Snubbing SOP 8 Installing tubing hanger 11.a Structural sideload (wind) analysis, drawing 11.b TSI safety meeting report, Rigless inspection 12 Egress / Descender spec sheet Snubbing calcs using MPSP Snub 2-3/8” tubing thru stripping annular to ~5700’ a. Expected SITP to snub against = 1850 psi b. Cross-sectional area of 2-3/8” tubing = 4.4 in2 x 1850 psi = 8140 lbs upward force c. 8140 lbs / 4.6 lb/ft = 1769 feet of 2-3/8” tubing to run before being pipe heavy COAs per approved sundry 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 recipientor if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 anyattachments 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 considersappropriate. 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 recipientor if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 anyattachments 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 considersappropriate. JSA / Safe Operating Procedure Page 1 Title: Installing Tubing Hanger While Pipe Heavy Specific Formal Hazard Assessment: Task Hazard Rating Control Rating Installing Tubing hanger while Heavy Uneven torques in landing joint and tubing hanger 3 Verify that connection below tubing hanger is torqued and the connection above is wrench tight. 1 Gas release 5 Ensure all equipment is pressure tested properly, take care tagging rams. 2 Improper install of lag bolts 5 Count turns, may require flushing bowl. 2 Reference to other related Formal Hazard Assessments Additional On-Site Hazard Assessment: Identify HAZARDS: Is there a possibility of striking against, being struck by, or making harmful contact with an object; of being caught in, by, or between objects; of slipping, tripping, or falling; of developing a strain from pushing, pulling, lif ting bending, or twisting; of coming in contact with electricity or other power source; of receiving a thermal or chemical burn; o f being exposed to hazardous environment or of compromising well control? Task Hazard Rating Control Rating JSA / Safe Operating Procedure Page 2 Standard Operating Procedure: 1. Measure landing joint and mark it to know when tagging bowl and install stabbing valve. 2. Install tubing hanger and landing joint on to stump. Tighten with tongs and confirm lower connection is torqued to specifications. 3. Close lower stripping Rams, bleed off fully and open Annular BOP. 4. Jack heavy, short strokes until hanger tags Rams and lift the string 0.3m (1’) to ensure the tubing hanger is in fluted spool. 5. Close Annular and ensure jack has a really low bite with only both traveling slips shut on tubing. 6. Equalize very slowly, watching weights to ensure dog nut is not sealing in the snubbing stack. 7. Once equalized, leave equalizer valve open. 8. Open Rams and jack down to tag point. 9. Ensure you know up and down weights. Tag bowl and tighten and measure leg screws. 10. Once legs screws are tight, pull pipe over 2daN. If good, recheck to make sure leg screws are tight. Position Requirements: Supervisor: Maintain clear communication and lead the operation, Direct all personnel as necessary. Work with all individuals with upmost respect and ethics. Operator: Maintain clear communication and lead the operation with direction from the supervisor, Direct all personnel as necessary and assist in identifying hazards. Work with all individuals with upmost respect and ethics. Assistant: Maintain clear communication and perform duties as directed by the operator, Direct personal as necessary, and identify hazards. Work with all individuals with upmost respect and ethics. Stop work if unsure of next task. JSA / Safe Operating Procedure Page 3 Specific PPE required: Please utilize back of sheets if required for notes. Please ensure signed copies are placed in Job File and sent to head off ice for filing. Initials of Review: MSDS Information Two-Way Radio's Barricades Chemical Respirator Wet Suit Rubber Boots Rubber Gloves LEL Monitor Lock-Out Equipment Vent Fans SABA SCBA Gas Detector Face Sheild Fall Protection Equipment Fire Extinguisher Steel Toed Work Boots Safety Glasses Chemical Goggles Gloves Hardhat Fire Resistant Coveralls JSA / Safe Operating Procedure Page 4 JSA / Safe Operating Procedure Page 1 Title: Tripping Pipe into Wellbore Specific Formal Hazard Assessment: Task Hazard Rating Control Rating Snubbing/Tripping pipe into Wellbore Dropping tubing string down hole. 8 Complete pipe Light/Heavy Calculation as follows: Tubing Diameter x Tubing Diameter x 0.7854 x well pressure 3 Pinch points and overhead hazards. 8 Use tag lines if necessary and position hands and body safely. 3 Slip failure. 8 Clean and replace slip dies before the job. 3 Gas release at surface. 8 Equalize slowly. 3 Tubing buckling/parting if the string bottom strikes the bit guide, etc. as it enters the well. 8 Refer to D.G.1.01 Setting Jack Pressure 3 Slip failure, accumulator failure, pressure building in the well as you compress fluid/gas, pipe dropping down the well or pressure lifting the tubing up and out of the well. 8 Watch your gauges for pressure build up and changes in accumulator status, slip dies for wear, and pay attention to everything around you - unusual noises and things that don't look and feel right. 3 JSA / Safe Operating Procedure Page 2 Dropping tubing string down hole. 8 Be aware of what you are doing. Go slow and be sure pipe is neutral. Double check pipe count to match number from Step #2. 3 Reference to other related Formal Hazard Assessments Additional On-Site Hazard Assessment: Identify HAZARDS: Is there a possibility of striking against, being struck by, or making harmful contact with an object; of being caught in, by, or between objects; of slipping, tripping, or falling; of developing a strain from pushing, pulling, lifting bending, or twisting; of coming in contact with electricity or other power source; of receiving a thermal or chemical burn; of being exposed to hazardous environment or of compromising well control? Task Hazard Rating Control Rating JSA / Safe Operating Procedure Page 3 Standard Operating Procedure: 1. Hold Pre-Job Safety Meeting and discuss with rig crew preferred method of handling tubulars while snubbing - winch line or blocks. 2. Use well bore pressure and tubing size to calculate approx. how many joints will need to be snubbed in. 3. Position 1st joint/BHA in stack. 4. Close stationary snubbing slips (SS), raise travelling plate ~ 6 inches, close travelling snubbing slips (TS), travelling hea vy slips (TH) and pull into SS with the jack to ensure SS are holding. 5. Close Annular and equalize the stack with casing pressure. Adjust the annular control as needed. 6. If there are no leaks anywhere on the stack, unlock and open blind rams and lubricate NSI annular with oil. 7. Set jack pressure and begin snubbing in the hole. 8. Continue snubbing in the hole until pipe starts to slide downwards in the slips a little bit indicating that you are approaching pipe neutral or, when you approach your number from Step #2. 9. When the pipe starts to slide down, on your first stoke after a connection, snub the first collar so it is just above the NSI annular. 10. Leaving the SS open and the TS closed, raise the jack plate. Watch tbg 11. If tubing does not rise with the jack plate, then pipe is neutral. Begin snubbing pipe in with TH closed as well. 12. After you have snubbed ~ 3 more joints in using 3 slips, on your last stroke of that joint, once pipe is moving down, open your TS. If pipe continues down, you are pipe heavy. 13. Tell driller you are ready to begin tripping with the blocks and snubbing only the collars. 14. After the connection is torqued with the tongs have the driller pick out of the TH and stop. Raise jack plate to near top. Set jack pressure to 5 daN 15. Have the driller come down slowly and smoothly. Match this speed with the jack. 16. Time your speed and jack height so you can push the collar through the annular smoothly in one stroke. JSA / Safe Operating Procedure Page 4 Position Requirements: Supervisor: Maintain clear communication and lead the operation, Direct all personnel, as necessary. Work with all individuals with upmost respect and ethics. Operator: Maintain clear communication and lead the operation with direction from the supervisor, direct all personal as necessary and assist in identifying hazards. Work with all individuals with upmost respect and ethics. Assistant: Maintain clear communication and perform duties as directed by the operator, Direct personal as necessary, and identify hazards. Work with all individuals with upmost respect and ethics. Stop work if unsure of next task. JSA / Safe Operating Procedure Page 5 Specific PPE required: Please utilize back of sheets if required for notes. Please ensure signed copies are placed in Job File and sent to head office for filing. Initials of Review: MSDS Information Two-Way Radio's Barricades Chemical Respirator Wet Suit Rubber Boots Rubber Gloves LEL Monitor Lock-Out Equipment Vent Fans SABA SCBA Gas Detector Face Sheild Fall Protection Equipment Fire Extinguisher Steel Toed Work Boots Safety Glasses Chemical Goggles Gloves Hardhat Fire Resistant Coveralls JSA / Safe Operating Procedure Page 6 DIMENSIONS & TOLERANCES 1° FRACTIONAL ANGULAR 0.0 0.00 0.000 ± 0.030 0.015 0.005 ± ± ± ±1/16 ±0.0000 0.001 ENERGY SERVICESICON 6" 48" 0" 191 1/2" 568" WORK FLOOR 60" TOP OF VALVE 78" 7-1/16 5M BLIND SHEAR 87" 111" 7-1/16 5M DOUBLE GATE 128 1/2" 144 1/2" 7-1/16 5M ANNULAR 159 1/2" 183 1/2" 224 1/2" 248 1/2" 272 1/2" 290 1/2" 7-1/16 15K SINGLE GATE 322" 330" WORK FLOOR 361" 7-1/16 5M ANNULAR 260 1/2" R40 FT A A GUY E GUY FGUY G GUY H NOTE: REFER TO OEM SPECS FOR GUY GIN POLE GUY REQUIREMENTS ESCAPE POLES DEPLOYED TO SUB STRUCTURE PLATFORM 50° MAX SECTION A-A NOTE: ANCHOR BLOCKS MUST BE PLACED ON SOLID GROUND WITH ANCHOR CLEATS EMBEDDED IN SOIL. RECOMMENED MINIMUM ANCHOR WEIGHT 18,000 LB NOTE: SCREW JACKS SHOULD BE TORQUED TO 100 LB*FT TO ENSURE LMS IS SUPORTING JACK LOAD. CONFIRM DAILY 4' SQUARE PADS 6" THICK NOTE: LINE LOADS ASSUME STRUCTURE IS FULLY ENCLOSED FOR WIND LOADING GUYWIRE SPECS EXPECTED LOAD TENSION 9,000 LB BASED ON 1,000 LB PRE-TENSION. 3/4 IWRC EIPS 6X19 WIRE ROPE GUY E 60 FT GUY F 60 FT GUY G 60 FT GUY H 60 FT 0SD05~HILCORP GUYLINESSHEET 1 OF 1 REV:ARCH C GENERAL NOTES:1. U.N.O. ALL FILLET WELDS TO BE 1/4" CONTINUOUS.2. U.N.O. ALL BUTT WELDS TO BE 1/4" CONTINUOUS.3. SEAL WELD ALL TUBING.4. STICK AND FLUX-CORE WELDING PROCEDURES ARE INTERCHANGABLE ON AN EQUIVALENT BASIS.5. DO NOT SCALE DRAWING.6. IF IN DOUBT ASK. RIG#DRAWN: CHECKED: APPROVED: DATE: SHEET SIZE:PROJECTION:SD02 TOP LEVEL ASSEMBLY IC RE CUSTOMER: FILE: TITLE: TEAM SNUBBING SHEET TITLE:GENERAL ASSY TS101 DWG#:2023-10-29 ALASKA JACK PACKAGE18033~ THE INFORMATION INCLUDED IN THIS DOCUMENT IS PROPRIETARY AND SHALL NOT BE REPRODUCED, TRANSFERRED, OR DISCLOSED TO OTHERS, FOR ANY PURPOSE WHATSOEVER, WITHOUT THE WRITTEN AUTHORIZATION OF ICON ENERGY SERVICES. 76146.1 LBWT: Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231017 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 212-26 50283201820000 220058 9/2/2023 AK E-LINE Perf KBU 14-6Y 50133205720000 207149 9/18/2023 AK E-LINE GPT/Plug KBU 23-05 50133206300000 214061 9/9/2023 AK E-LINE GPT/Perf MP S-21 50029230650000 202009 10/7/2023 READ CaliperSurvey MPU C-23 50029226430000 196016 9/21/2023 AK E-LINE Perf MPU M-22 50029236450000 219111 9/20/2023 AK E-LINE Mechanical Cutter Paxton 7 50133206430000 214130 9/8/2023 AK E-LINE Tubing Punch/RCT PBU 06-16B 50029204600200 223072 10/7/2023 HALLIBURTON RBT PBU D-18B 50029206940200 215001 9/14/2023 BAKER RPM PBU J-19 50029216290000 186135 9/26/2023 AK E-LINE TTBP/Cement PBU J-23A 50029217120100 204193 10/4/2023 BAKER SPN PBU N-18A 50029209060100 208175 9/4/2023 BAKER SPN PBU P1-02A 50029217790100 202065 9/11/2023 BAKER SPN PBU P1-13 50029223720000 193074 9/15/2023 HALLIBURTON IPROF PBU R-12A 50029209210100 211055 9/7/2023 BAKER SPN Please include current contact information if different from above. T38062 T38063 T38065 T38064 T38066 T38067 T38068 T38069 T38070 T38071 T38072 T38073 T38074 T38075 T38076 10/20/2023 BRU 212-26 50283201820000 220058 9/2/2023 AK E-LINE Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.20 08:34:04 -08'00' 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: ______________________ 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 8,001 feet See schematic feet true vertical 6,789 feet N/A feet Effective Depth measured 6,473 feet 100 & 2,495 feet true vertical 5,261 feet 100 & 1,913 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)5-1/2" 17# / P-110 ICY 2,506 MD 1,919 TVD 114 MD Packers and SSSV (type, measured and true vertical depth)See Schematic K-Valve 114 TVD 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: 8,730psi 2,980psi 5,750psi 10,600psi 2,731' 2,050' Burst Collapse 1,410psi 3,090psi Production Liner 5,506' Casing Structural 6,789'8,001' 138'Conductor Surface Intermediate 16" 9-5/8" 138' 2,731' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-058 50-283-20182-00-00 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: FEDA029657 Beluga River / Undefined Gas Pool Beluga River Unit (BRU) 212-26 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 50 Size 138' 15 553081 0 373 108 Jake Flora, Operations Engineer 323-007 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1096 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 jake.flora@hilcorp.com 907-777-8442 N/A p k ft t Fra O s O 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 8:06 am, Sep 14, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.09.13 18:18:48 - 08'00' Noel Nocas (4361) Rig Start Date End Date 9/1/23 9/2/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 Crew fly to Beluga River. PJSM and PTW,SIMOPS with production and construction Well flowing 1.1MMCFD @ 50psi. Mobilize equipment to H pad. Spot equipment and R/U AK E-line. M/U Gun gamma and 3x switchguns 2-3/8"" OD Geodynamics guns 6spf, 10.8gm (CCL to top shot) Gun #1 (3ft) 15.8ft Gun #2 (3ft) 11.2ft Gun #3 (3ft) 6.5ft Stab on well and pressure test lubricator to 250psi/2500psi - Test good. Open well and RIH with well flowing 1.1MMCFD @ 44psi Verify gun switches at 200ft Pull correlation log and send to town on depth. Pull on depth, verify switches, and attempt to perforate. Gun did not fire, unable to communicate with switches any longer. POOH Hold safety meeting about bringing a potentially live gun to surface and disarming procedure Inspect switch gun, no issues found. Re-dress switch gun swap out gun gamma RIH with Switch guns #1, #2, #3 again. E-line unit depth counter is reading off, and the problem consistently getting worse. Attempted adjusting settings, dismantling and cleaning counter head with no luck. New counter head dispatched to Beluga river tomorrow morning. POOH, Secure well and SDFN. 09/01/2023- Friday Rig Start Date End Date 9/1/23 9/2/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 09/02/2023 - Saturday PJSM and PTW, SIMOPS with production and construction Well flowing 1.2MMCFD at 53psi. Remove counter head on E-line truck, wait or parts. Receive parts and repair counter head on E-line unit. Repair worked, counter now on depth. M/U Gun gamma and 3x switchguns 2-3/8" OD Geodynamics guns 6spf, 10.8gm (CCL to top shot) Gun #1 - 3ft (15.8ft) Gun #2 - 3ft (11.2ft) Gun #3 - 3ft (6.5ft) RIH, Pull correlation log. On depth. Pull on depth and perforate Beluga G1 (5968-5971) @ 14:41hrs Initial 1.22MMCFD @ 52psi, no change in 15min Pull on depth and perforate Beluga G1 (5960-5963) 15:49hrs Initial 1.3MMCFD @ 55psi, after 15min 1.7MMCFD @ 70psi Pull on depth and perforate Beluga F10 (5892-5895) 16:07hrs Initial 1.7MMCFD @ 70psi, after 15min 1.6MMCFD @ 64psi 30min after shooting last gun 2.0MMCFD @ 70psi POOH, guns coated in wet thick mud. M/U Gun gamma and 2x switchguns 2-3/8" OD Geodynamics guns 6spf, 10.8gm (CCL to top shot) Gun #4 - 12ft (15.9ft) Gun #5 - 4ft (8.3ft) RIH, Pull correlation log. On depth. Pull on depth and perforate Beluga F10 (5866-5878) @ 17:32hrs Initial 1.9MMCFD @ 64psi, no change in 15min Pull on depth and perforate Beluga F7 (5793-5797) @ 17:47hrs Initial 1.9MMCFD @ 64psi, after 15min 2.1MMCFD @ 72psi Rig Start Date End Date 9/1/23 9/2/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 POOH, guns coated in wet thick mud. M/U Gun gamma and 2x switchguns 2-3/8" OD Geodynamics guns 6spf, 10.8gm (CCL to top shot) Gun #6 - 8ft (18.9ft) Gun #7 - 9ft (6.5ft) RIH, Pull correlation log. On depth. Pull on depth, switch guns won't communicate. Tried multiple things and couldn't get the guns to communicate. POOH, to 1600ft. Switches reading again RIH. Pull correlation log, on depth. Pull on depth and perforate Beluga F6 (5653-5661) @ 18:36hrs Initial 2.1MMCFD @ 72psi, no change in 10min Pull on depth and perforate Beluga F6 (5632-5641) @ 18:46hrs Initial 2.1MMCFD @ 73psi, after 15min 2.2MMCFD @ 104psi. Secure well R/D AK E-line Turn well over to production Final production 2.5MMCFD @ 89psi Updated by JMF 9-11-23 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545 MD / TVD = 5,333 TD = 8,001 MD / TVD = 6,789 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681 Surf 2,731 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892 2,495 8,001 TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892 Surf 2,506 JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100 100 2.813 Baker KB Packer, tailpipe, X-nipple, OAL 22 (set 2/25/22), 48k shear release 2 114 114 2.813 3-1/2 X-nipple 3 2,495 1,913 6.170 8.430 Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 4 6,473-6,488 5,261- 5,276 15 Cement Plug dump bailed on 1-21-22 5 6,545 5,333 5.500 CIBP set 10/21/20 6 6,633 5,421 5.500 MAP CIBP set on 10/18/20 7 7,500 6,288 5.500 CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496 5,505 4,284 4,293 3-3/8 2/9/22 Open Beluga F5 5,587 5,591 4,375 4,379 3-3/8 2/9/22 Open Beluga F6 5,632 5,641 4420 4429 2-3/8 9/2/23 Open Beluga F6 5,653 5,661 4441 4449 2-3/8 9/2/23 Open Beluga F7 5,725 5,730 4,513 4,518 3-3/8 2/8/22 Open Beluga F7 5,737 5,757 4,525 4,545 3-3/8 2/9/22 Open Beluga F7 5,781 5,787 4,569 4,575 3-3/8 2/8/22 Open Beluga F7 5,793 5,797 4581 4585 2-3/8 9/2/23 Open Beluga F10 5,866 5,878 4654 4666 2-3/8 9/2/23 Open Beluga F10 5,892 5,895 4680 4683 2-3/8 9/2/23 Open Beluga G1 5,960 5,963 4748 4751 2-3/8 9/2/23 Open Beluga G1 5,968 5,971 4756 4759 2-3/8 9/2/23 Open Beluga G2 5,994 6,012 4,782 4,800 2-7/8 2/8/22 Open Beluga G5 6,110 6,115 4,898 4,903 2-7/8 12/20/21 Open Beluga G6 6,136 6,141 4,924 4,929 2-7/8 12/20/21 Open Beluga G7 6,162 6,166 4,950 4,954 2-7/8 12/20/21 Open Beluga G9 6,224 6,229 5,012 5,017 2-7/8 12/20/21 Open Beluga H 6,283 6,289 5,071 5,077 2-7/8 12/20/21 Open Beluga H 6,318 6,321 5,106 5,109 2-7/8 12/20/21 Open Beluga H1 6,337 6,341 5,125 5,129 2-7/8 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8 09/29/20 Open Beluga H3 6,420 6,429 5,208 5,217 2-7/8 8/10/21 Open Beluga H4 6,447 6,459 5,231 5,243 2-7/8 12/19/21 Open Beluga H4 6,450 6,460 5,233 5,243 2-7/8 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2 TOC @ 3,400 (CBL dated 9-4-2020) 1 & 2 16 9-5/8 12-1/4 hole 5-1/2 Bel H15 Bel I Bel J 6 Bel H7 5 Bel H5 7 3 4 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 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: Install Velocity String, 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): 8,001'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi 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 jake.flora@hilcorp.com 907-777-8442 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 Jake Flora, 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 FEDA029657 220-058 50-283-20182-00-00 Hilcorp Alaska, LLC Proposed Pools: 17# / P-110 ICY TVD Burst 2,506' 10,600psi 2,050' Size 138' 2,731' MD See Schematic 2,980psi 5,750psi 138'138' 2,731' September 26, 2023 5-1/2" 8,001' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-26CO 802 Same 6,789'5-1/2" ~2,396psi 5,506' See schematic Length See Schematic See Schematic 6,789'6,473'5,261' Beluga River Sterling-Beluga Gas 16" 9-5/8" See Schematic m n P s t N 66 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 8:38 am, Sep 15, 2023LLLLSSSSBy Grace Christianson at 8:38 am, Sep 15, 2023 323-521 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.09.14 17:34:38 - 08'00' Noel Nocas (4361) 1782 psi -bjm 10-404 snubbing Snubbing operation. See attached conditions of approval. * Beluga River, Strlg-Beluga Gas Pool - Prod. Code 92500 SFD DSR-9/15/23 * MDG 9/18/2023 X BJM 10/23/23 BOP test to 3000 psi. Shear rams capable of shearing 2-7/8" tubing must be included in BOP stack. *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.10.23 15:09:46 -08'00'10/23/23 RBDMS JSB 102623 BRU 212-26 (PTD 220-058) Sundry 323-ϱϮϭ^ŶƵďďŝŶŐŽƉĞƌĂƟŽŶ ŽŶĚŝƟŽŶƐŽĨƉƉƌŽǀĂů 1. BOP test to 3000 psi. Shear rams capable of shearing 2-7/8" tubing must be included in BOP stack. 2. Provide 48 hrs ŶŽƟĐĞƚŽK'ĨŽƌƌŝŐŝŶƐƉĞĐƟŽŶĂŶĚKWƚĞƐƚ͘ 3. ŶŶƵůĂƌƉƌŽĚƵĐƟŽŶĨƌŽŵϮ-7/8" x 5-ϭͬϮΗĂŶŶƵůƵƐŝƐĂƉƉƌŽǀĞĚƚŽŝŶĐƌĞĂƐĞŇŽǁƌĂƚĞĂŶĚŝŵƉƌŽǀĞ ƵŶůŽĂĚŝŶŐĐĂƉĂďŝůŝƚLJ͘ƉƌŽĚƵĐƟŽŶWĂĐŬĞƌǁŝůůŶŽƚďĞƌĞƋƵŝƌĞĚŽŶƚŚĞϮ-7/8" velocity string. 4. ^ŶƵďďŝŶŐĞƋƵŝƉŵĞŶƚ͕ƉĞƌƐŽŶŶĞůĂŶĚŽƉĞƌĂƟŽŶƚŽďĞĐŽŵƉůŝĂŶƚǁŝƚŚĂŶĂĚŝĂŶ/ZWϭϱ͘ ůů “must” and “shall͟ƐƚĂƚĞŵĞŶƚƐĂƐĚĞƐĐƌŝďĞĚŝŶ/ZWϭϱ͘Ϭ͘ϳƐŚĂůůďĞĂĚŚĞƌĞĚƚŽƵŶůĞƐƐĂƉƉƌŽǀĂůŝƐ ŽďƚĂŝŶĞĚĨƌŽŵK'ƚŽĚĞǀŝĂƚĞĨƌŽŵƚŚĞƐĞƐƚĂƚĞŵĞŶƚƐ͘/ĨƚŚĞƌƵůĞƐŝŶ/ZWϭϱĐŽŶŇŝĐƚǁŝƚŚ K'ƌĞŐƵůĂƟŽŶƐ͕K'ƌĞŐƵůĂƟŽŶƐǁŝůůĂƉƉůLJƵŶůĞƐƐK'ǀĂƌŝĂŶĐĞŽƌǁĂŝǀĞƌŝƐŐƌĂŶƚĞĚ. 5. WƌŝŽƌƚŽƌŝŐŐŝŶŐƵƉŽŶƚŚĞǁĞůů͕,ŝůĐŽƌƉŵƵƐƚƉƌĞƐĞŶƚĂƉůĂŶƚŚĂƚŝƐĂĐĐĞƉƚĂďůĞƚŽƚŚĞK'͕ ĚĞŵŽŶƐƚƌĂƟŶŐŚŽǁƚŚĞƌƵůĞƐŽĨ/ZWϭϱǁŝůůďĞŝŵƉůĞŵĞŶƚĞĚ͘ 6. SnubbiŶŐĐĂůĐƵůĂƟŽŶƐƚŽďĞďĂƐĞĚŽŶDW^W͘ 7. tĞůůĐŽŶƚƌŽůƌĞŐƵůĂƟŽŶƐϮϬϮϱ͘ϮϴϱĨŽƌƌŽƚĂƌLJĚƌŝůůŝŶŐƌŝŐŽƉĞƌĂƟŽŶƐĂƉƉůLJ͘ 8. ĞƚĂŝůĞĚƚƵďŝŶŐĚĞƉůŽLJŵĞŶƚƉƌŽĐĞĚƵƌĞƚŽďĞƐƵďŵŝƩĞĚĂŶĚĂƉƉƌŽǀĞĚďLJK'ƉƌŝŽƌƚŽ deployment. 9. /ĨŶŽƚǁŽƌŬŝŶŐŽŶϮϰ-ŚŽƵƌĐŽŶƟŶƵŽƵƐŽƉĞƌĂƟŽŶĂůƐĐŚĞĚƵůĞ͕ƐŶƵďďŝŶŐƐƚƌŝŶŐŵƵƐƚďĞƌĞŵŽǀĞĚ ĨƌŽŵƚŚĞŚŽůĞŽƌŚƵŶŐŽīin a pipe-ŚĞĂǀLJĐŽŶĚŝƟŽŶ͕ǁŝƚŚƚƌĞĞǀĂůǀĞĂŶĚďůŝŶĚƌĂŵƐĐůŽƐĞĚďĞĨŽƌĞ ƐŚƵƫŶŐĚŽǁŶĨŽƌƚŚĞŶŝŐŚƚ͘ ŶŝŐŚƚǁĂƚĐŚŵĂŶƐŚĂůůďĞŽŶůŽĐĂƟŽŶƚŽŵŽŶŝƚŽƌƚŚĞǁĞůů͘ 10. Well site supervisors shall have ĂĐůĞĂƌƵŶĚĞƌƐƚĂŶĚŝŶŐŽĨƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ/ZWϭϱ͘ϱ͘Ϯ͕ĂŶĚ have an ĂǁĂƌĞŶĞƐƐ ŽĨƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐof /ZWϭϱ͘ ŽĐƵŵĞŶƚĞĚĐŽŶĮƌŵĂƟŽŶŽĨƵŶĚĞƌƐƚĂŶĚŝŶŐ ĂŶĚĂǁĂƌĞŶĞƐƐ ƚŽďĞĂǀĂŝůĂďůĞƵƉŽŶƌĞƋƵĞƐƚ͘ 11. Prior to ƌŝŐŐŝŶŐƵƉŽŶƚŚĞǁĞůů, provide evidence ƚŽK' of: a. WĞůůŚĞĂĚΘƐŶƵďďŝŶŐƐƚĂĐŬƐƚĂďŝůŝnjĂƟŽŶĚĞƐŝŐŶƉĞƌ/ZWϭϱ͘ϰ͘ϭ͘ϮƉƌŝŽƌƚŽƌŝŐŐŝŶŐƵƉŽŶƚŚĞ ǁĞůů͘ b. Well-ƐƉĞĐŝĮĐ,ĂnjĂƌĚƐƐĞƐƐŵĞŶƚƉĞƌ/ZWϭϱ͘ϲ. 12. WƌŝŽƌƚŽĞŶƚĞƌŝŶŐƚŚĞǁĞůůƚŽƉĞƌĨŽƌŵƐŶƵďďŝŶŐŽƉĞƌĂƟŽŶƐ͕ƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞŽĨEmergency Egress System in place ƉĞƌ/ZWϭϱ͘ϴ͘ϯ. Well Prognosis Well Name: BRU 212-26 API Number: 50-283-20182-00-00 Current Status: Gas Producer Permit to Drill Number: 220-058 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) Maximum Expected BHP: 2306 psi @ 5243’ TVD (0.44 psi/ft gradient to deepest open perf) Max. Potential Surface Pressure: 2396 psi (Based on 0.1 psi/ft gas gradient to surface) Well Status: Online gas producer @ 2000 mcfd, 3 bwpd @ 75 psi FTP Brief Well Summary: Drilled & completed in 2020, BRU 212-26 is an online producer in the Beluga River Undefined Gas Pool. It was discovered in November 2021 that the well is 17’ too close to an occupied structure (643’ vs allowed 660’) and requires a SSSV to be compliant with 20 AAC 25.265(d)(2)(a). In February of 2022 a packer assembly with tailpipe and x-nipple were installed at 100’ BGL. A 3-1/2 k-valve was installed and successfully tested in March. The well began struggling to stay unloaded in late June 2023. The k-valve was pulled for diagnostics and unloading. Perforations were added and the well was able to unload and flow just above the unload rate for 5- 1/2” tubing. Objective: The objective of this sundry is to install in a 2-7/8” velocity string without pumping fluids on the sands by using a hydraulic snubbing unit. Snubbing Detail: Prior to snubbing the existing tailpipe/nipple and packer assembly will be pulled from 100’ with coil tubing. Also an additional tubing hanger will be flanged up above the lower master to land the 2-7/8” tubing in. While snubbing, the tubing will be isolated from below with a pump out plug which holds pressure from below and a PX plug set in set in a X-nipple. The tubing will be snubbed using traveling and stationary inverted slips, through the snubbing annular, with the 2-7/8” snubbing rams used as needed to deploy the tubing hanger. Production: Flow will initially be up the 2-7/8” x 5-1/2” annulus with water being unloaded as necessary up the 2-7/8” tubing. The goal is to reduce slugging events and flatten production as this well continues to decline out. With this completion design there will not be a TRSSSV installed in the wellbore. History: 2/09/22 Perforate 5737-57’ w 20’ 3-3/8” perf gun 2/25/22 Install packer/tailpipe at 114’, set k-valve 07/31/23 Pulled k-valve, attempt to unload well with soap 08/12/23 Tag Cement Depth at 6473' RKB, Obtain Sample of thick Mud , Brush Perfs 4 Passes 08/20/23 Logged flowing GPT, found soapy water gradient in bottom 1500’ of the well, FBHP of 528 psi 09/01-02/23 Perforate BEL F6-G1 (7 gun runs), increased rate back above unloading 09/10/23 Set k-valve First snubbing operation in Alaska in many years. 1782 psi -bjm Permitted per 20 AAC 25.265(d)(4) -bjm Well Prognosis Pre-Rig: 1. Provide 48hrs notice 2. MIRU Coil Tubing 3. PT BOPs to 3000 psi 4. MU hydraulic GS, jars 5. Pull packer & tailpipe assembly from 114’ 6. RD Coil Tubing Snubbing Rig: 1. Review all COAs, provide 48hrs notice of BOP testing 2. MIRU PESI snubbing unit (Snubbing International, Alberta, CA: DBA PESI) 3. Set TWC, ND tree above lower master 4. NU additional tubing head on top of lower master (to land 2-7/8 velocity string) 5. NU BOPs 6. Test primary BOPs to 3000 psi (2-7/8” pipe rams / blind-shear rams / annular) 7. Test stripping BOPs to 3000 psi (dual 2-7/8” rams, annular) 8. Pull TWC, close blind rams 9. MU below completion components: a. Wireline Entry Guide b. Pump out plug (holds pressure from below) c. 10’ pup d. X-nipple with PX plug (tested from below) e. 5’ pup / handling joint 10. With the above completion below the stripping BOP (above the closed blind rams) close stripping annular on 2-7/8” handling joint 11. Stab/MU full opening safety valve in open position 12. Open equalizing valve, confirm no flow 13. Open blind rams, equalize pressure 14. Remove full opening safety valve 15. Snub 2-7/8” tubing thru stripping annular to ~5400’ a. Expected SITP to snub against = 750 psi b. Cross-sectional area of 2-7/8” tubing = 6.5 in2 x 750 psi = 4875 lbs upward force c. 4875 lbs / 6.4 lb/ft = 760 feet of 2-7/8” tubing to run before being pipe heavy 16. Close lower stripping rams, MU tubing hanger, close stripping annular, open lower rams 17. Land tubing hanger, RILDs, test 18. Set TWC 19. ND BOPs, NU new tree, test 20. RDMO snubbing unit Post Rig 1. Modify flowlines to include choke & SSV on both tubing and annulus flowlines 2. RU slickline, PT lubricator to 3000 psi 3. Pull PX plug 4. RU Nitrogen, pressure up on tubing to over balance with BHP, shear pump out plug 5. Return well to Operations include choke & SSV on both tubing and annulus flowlines If SITP = MPSP (1782 psi). Snubbing Force = 11583 lbs and 1809' tbg to be run before pipe heavy -bjm Pump out plug must be tested from below to 1.3x BHP per IRP 15.2.1.2 See attached email from Jake Flora 10/16/23 describing how barriers will be in place for NU/ND tree and BOP stack. -bjm No longer planning to set a TWC due to BOP height while pulling TWC. Well Prognosis Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Snubbing Unit Diagram 4. BOP diagram – Primary BOPs & Snubbing Rams/Annular 5. Current Wellhead Diagram 6. Proposed Wellhead Diagram 7. Nitrogen SOP 8. Change Form Updated by JMF 9-11-23 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100’ 100’ 2.813 Baker KB Packer, tailpipe, X-nipple, OAL 22’ (set 2/25/22), 48k shear release 2 114’ 114’ 2.813 3-1/2 X-nipple 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open Beluga F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open Beluga F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open Beluga F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open Beluga G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open Beluga G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J 6 Bel H7 5 Bel H5 7 3 4 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 Updated by JMF 9-11-23 PROPOSED Completion Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 2-7/8” Tubing 6.4 TBD TBD 2.441” Surf ~5500’ JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100’ 100’ 2.813 Baker KB Packer, tailpipe, X-nipple, OAL 22’ (set 2/25/22), 48k shear release 2 114’ 114’ 2.813 3-1/2 X-nipple 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 4 6,473’-6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F6 5,632’ 5,641’ 4420 4429 2-3/8” 9/2/23 Open Beluga F6 5,653’ 5,661’ 4441 4449 2-3/8” 9/2/23 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga F7 5,793’ 5,797’ 4581 4585 2-3/8” 9/2/23 Open Beluga F10 5,866’ 5,878’ 4654 4666 2-3/8” 9/2/23 Open Beluga F10 5,892’ 5,895’ 4680 4683 2-3/8” 9/2/23 Open Beluga G1 5,960’ 5,963’ 4748 4751 2-3/8” 9/2/23 Open Beluga G1 5,968’ 5,971’ 4756 4759 2-3/8” 9/2/23 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” Bel H15 Bel I Bel J 6 Bel H7 5 Bel H5 7 3 4 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 X nip w PX plug Pump out plug WLEG BOP stack is rated to 5k, per Jake Flora email attached. -bjm Beluga River Unit BRU 212-26 03/29/2022 Valve, Master, WKM-M, 5 1/8 5M FE, HWO, EE trim Valve, Upper master, WKM-M, 5 1/8 5M FE, HWO, EE trim Valve, Swab, WKM-M 5 1/8 5M FE, HWO, EE trim Valve, Wing, WKM-M, 3 1/8 5M FE, HWO, EE trim BHTA, Otis, 5 1/8 5M FE x 9.5 Otis quick union top 16'’ 9 5/8’’ 5 ½’’ Starting head, Cactus C-29L, 16 3/4 3M x 16 SOW, w/ 2- 2 1/16 5M SSO Tubing head, Cactus C-29L- HPS, 16 3/4 3M x 11 5M, w/ 2- 2 1/16 5M SSO Beluga River Unit New drill system 16 x 9 5/8 x 5 ½ Casing hanger, CW, 11 x 5 ½ DWC/C box btm x 6.125'’ LH stub acme box top, w/ 7 5/8 od neck, 5'’ type H BPV profile, DD-NL material Valve, Wing, SSV, WKM-M, 3 1/8 5M FE, w/ 15'’ Hydraulic operator Beluga River Unit BRU 212-26-Proposed 09/13/2023 Valve, Master, WKM-M, 5 1/8 5M FE, HWO, EE trim 16'’ 9 5/8’’ 5 ½’’ Starting head, Cactus C-29L, 16 3/4 3M x 16 SOW, w/ 2- 2 1/16 5M SSO Tubing head, Cactus C-29L- HPS, 16 3/4 3M x 11 5M, w/ 2- 2 1/16 5M SSO Attachment spool, Cactus- TCM, 7 1/16 5M FE top x 5 1/8 5M Studded bottom, w/2- 2 1/16 5M SSO, no bottom prep Adapter, Cactus-EN-CCL, 7 1/16 5M Stdd x 3 1/8 5M prepped for 5 ½ extended neck hanger Tubing hanger, Cactus-EN-CL, 7 x 3 1/2 EUE 8rd lift and susp, w/ 3'’ type H BPV profile 2 7/8'’ Tree assy, 3 1/8 5M Double master, swab, wing, ssv Beluga River Unit BRU 212-26 16 x 9 5/8 x 5 ½ x 2 7/8 Needs surface safety valve. -bjm 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. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BRU 212-26 (PTD 220-058) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Jacob Flora To:McLellan, Bryan J (OGC) Subject:Re: [EXTERNAL] BRU 212-26 (PTD 220-058) Snubbing sundry Date:Monday, October 16, 2023 1:12:53 PM Attachments:image002.png image003.png image004.png 5k Sent from my iPhone On Oct 16, 2023, at 1:01 PM, McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> wrote: What’s the BOP pressure rating? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, October 16, 2023 12:57 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] BRU 212-26 (PTD 220-058) Snubbing sundry Bryan, Yes you are correct, the pressure of 2396 psi was a typo. MPSP = 1782 psi. Thanks and let me know if you have additional questions- From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, October 16, 2023 12:17 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: RE: [EXTERNAL] BRU 212-26 (PTD 220-058) Snubbing sundry 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. Jake, You have MPSP at 2396 psi, which is higher than the reservoir pressure. It should be reservoir pressure minus a gas column. Reservoir pressure = 2306 psi MPSP = 2306 psi –(0.1 psi/ft x 5243’ TVD) = 1782 psi. Do you agree? Thanks for the other details. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, October 16, 2023 11:32 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] BRU 212-26 (PTD 220-058) Snubbing sundry Hi Bryan, Please see answers below: Pressure: The MPSP is what you’ve required in the past to either have build up test showing a SITP or use the normal gradient. We never obtain build ups as shutting in the well causes a loading event with water influx, that then has to be surged to unload. Below is the production history with WHP. There have been just a few times where we had the well SI since it’s initial POP in 2020. Two of these were between 1200-1300 psi with the 1300 psi SITP recorded after a 3 day SI. Since then the well has fought loading and has water in the well that cannot unload. Our operators believe that the SIPT now CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. is closer to 700 psi. Operationally, at SITPs below 1500 psi we can snub thru the stripping annular. At over 1500 psi we will have to used the stripping rams. We will be equipped and tested for both. <image002.png> Wellhead Prior to rigging up BOPs: 1. SI well, close lower master 2. Remove tree & upper master (lower master staying in place) 3. NU new tubing spool above lower master 4. NU snubbing BOP & test 5. Snub 2-7/8 tubing 6. Land tubing hanger with TWC in place 7. Close blind rams, test TWC & hanger seals from above 8. ND BOPs, NU tree & test 9. Pull TWC using lubricator 10. Hand to operations We are not planning a valve over the 2-7/8 hanger. The hanger will be landed with a TWC in addition to the downhole PX plug and downhole pump out plug Pump out plug (diagram and picture below) has a single small shear pin requiring a few hundred psi to shear and drop out. We will use pad sales gas pressure, or nitrogen to blow it out. <image003.png> <image004.png> From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, October 16, 2023 9:59 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] BRU 212-26 (PTD 220-058) Snubbing sundry Jake, A few questions about the sundry… Please verify MPSP for this well. It is shown in the sundry application to be higher than BHP. Why do you assume a THP of 750 psi during snubbing operations when your MPSP is much higher than that? With a full column of gas, wouldn’t you expect tubing pressure to be roughly equal to MPSP? Can you verify your plans for setting/pulling TWC during installation and removal of BOP stack? Send an updated wellhead diagram showing a master valve on top of the 2-7/8” tubing hanger to be included for installation/removal of BOPs. How will the pump out plug be removed? What differential pressure is required to blow it out? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. 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If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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:Carlisle, Samantha J (OGC) To:Brooks, James S (OGC) Subject:FW: [EXTERNAL] Sundry_BRU 212-26 322-188 - WITHDRAWAL/CANCEL Date:Tuesday, September 12, 2023 11:49:11 AM From: Donna Ambruz <dambruz@hilcorp.com> Sent: Tuesday, September 12, 2023 10:11 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Subject: RE: [EXTERNAL] Sundry_BRU 212-26 322-188 - WITHDRAWAL/CANCEL Please withdraw/cancel the above-referenced sundry. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Thursday, April 21, 2022 3:39 PM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Darci Horner - (C) <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] Sundry_BRU 212-26 322-188 Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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:Christianson, Grace K (OGC) To:Brooks, James S (OGC) Subject:FW: [EXTERNAL] Completed Sundry 323-452 BRU 212-26 - WITHDRAWAL/CANCEL Date:Wednesday, September 13, 2023 8:29:07 AM Here is the other Sundry cancellation. Thanks again, Grace From: Donna Ambruz <dambruz@hilcorp.com> Sent: Tuesday, September 12, 2023 10:11 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Subject: RE: [EXTERNAL] Completed Sundry 323-452 BRU 212-26 - WITHDRAWAL/CANCEL Please withdraw/cancel the above-referenced sundry. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Sent: Thursday, August 17, 2023 7:43 AM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Darci Horner - (C) <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jerimiah Galloway <jerimiah.Galloway@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] Completed Sundry 323-452 BRU 212-26 Hello, Attached is the completed Sundry for BRU 212-26. Thank you, Grace Christianson Executive Assistant AOGCC (907) 793-1230 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of 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. RBDMS JBS 091423 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: 09/12/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 18RD 50133205840100 222033 9/6/2023 YELLOW JACKET GPT-PERF BCU 18RD 50133205840100 222033 8/24/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 8/28/2023 YELLOW JACKET PLUG-PERF BCU 18RD 50133205840100 222033 9/9/2023 YELLOW JACKET PLU-GPT-PERF BCU 18RD 50133205840100 222033 9/4/2023 YELLOW JACKET SCBL BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf KTU 43-6XRD2 50133203280200 205117 9/4/2023 YELLOW JACKET CALIPER KU 42-12 50133206890000 220045 8/31/2023 YELLOW JACKET GPT-PERF KU 42-12 50133206890000 220045 8/20/2023 YELLOW JACKET SCBL MPU E-23 50029225700000 195094 8/18/2023 YELLOW JACKET CBL-PLUG MPU E-23 50029225700000 195094 8/20/2023 YELLOW JACKET PERF Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf PBU L-240 50029237030000 221086 8/30/2023 READ IPROF Please include current contact information if different from above. T37983 T37983 T37983 T37983 T37983 T37984 T37984 T37984 T37985 T37986 T37987 T37988 T37989 T37989 T37990 T37990 T37991 T37991 T37992 9/13/2023 BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.13 10:28:30 -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: Install Cap String 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): 8,001'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi 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 jake.flora@hilcorp.com 907-777-8442 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 Jake Flora, 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 FEDA029657 220-058 50-283-20182-00-00 Hilcorp Alaska, LLC Proposed Pools: 17# / P-110 ICY TVD Burst 2,506' 10,600psi 2,050' Size 138' 2,731' MD See Schematic 2,980psi 5,750psi 138'138' 2,731' August 22, 2023 5-1/2" 8,001' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-26CO 802 Same 6,789'5-1/2" ~2,396psi 5,506' See schematic Length See Schematic See Schematic 6,789'6,473'5,261' Beluga River Sterling-Beluga Gas 16" 9-5/8" See Schematic m n P s t g N 66 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 11:01 am, Aug 10, 2023 323-452 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.09 10:34:06 - 08'00' Noel Nocas (4361) SFD 8/14/2023 CT BOP test to 2500 psi, if CT is rigged up. BJM 8/16/23 DSR-8/14/23 10-404 GCW 08/16/2023JLC 8/16/2023 08/17/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.17 08:02:49 -05'00' RBDMS JSB 081723 Well Prognosis Well Name: BRU 212-26 API Number: 50-283-20182-00-00 Current Status: Gas Producer Permit to Drill Number: 220-058 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) Maximum Expected BHP: 2306 psi @ 5243’ TVD (0.44 psi/ft gradient to deepest open perf) Max. Potential Surface Pressure: 2396 psi (Based on 0.1 psi/ft gas gradient to surface) Well Status: Online gas producer @ 1500 mcfd, 3 bwpd @ 75 psi FTP Brief Well Summary: Drilled & completed in 2020, BRU 212-26 is an online producer in the Beluga River Undefined Gas Pool. It was discovered in November 2021 that the well requires a SSSV to be compliant with 20 AAC 25.265(d)(2)(a). In February of 2022 a packer assembly with tailpipe and x-nipple were installed at 100’ BGL. A 3-1/2 k-valve was installed and successfully tested in March and the well has been online since. The well is currently struggling to stay unloaded and is producing below the unload rate for 5-1/2” tubing. The objective of this sundry is to install a capillary soap string to stabilize the unloading events in the wellbore. Note: the k-valve (SSSV) will be removed from the wellbore and remain out while the cap sting is installed Wellbore Conditions: 2/09/22 Perforate 5737-57’ w 20’ 3-3/8” perf gun 2/25/22 Install packer/tailpipe at 114’, set k-valve Procedure: 1. RU Cap String Truck 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve to 2500 psi 3. RIH with 3/8” capillary string to ±5400’ MD. a. Set cap string as deep as practical 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Contingency: (removal of packer & tailpipe assembly at 114’ w/ coil tubing) 1. RU Coil tubing, provide 48hrs notice of BOP test 2. BOP test to 2500 psi 3. Pull packer from 100’ (top of packer fishing neck) (5.5” flowgard packer & tailpipe: 22’ OAL) Contingency: (removal of packer & tailpipe assembly at 114’ w/ braided line) 1. RU braided line 2. PT lubricator to 2500 psi 3. Pull packer from 100’ (top of packer fishing neck) (5.5” flowgard packer & tailpipe: 22’ OAL) The attached production trends support the need for soap injection via cap string. -bjm Well Prognosis Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic 3. Proposed Contingency Well Schematic Updated by JMF 8-8-23 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100’ 100’ 2.813 Baker KB Packer, tailpipe, X-nipple, OAL 22’ (set 2/25/22), 48k shear release 2 114’ 114’ 2.813 3-1/2 X-nipple 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2,506’ 1,919’ 6.180” 7.400” Baker tieback Seal Assembly 4 6,473’- 6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 6 Bel H7 5 Bel H5 7 3 4 Muddy Fill @ 6,488’ MD 12/19/21 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 Updated by JMF 8-8-23 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100’ 100’ 2.813 Baker KB Packer, tailpipe, X-nipple, OAL 22’ (set 2/25/22), 48k shear release 2 114’ 114’ 2.813 3-1/2 X-nipple 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 4 6,473’- 6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 6 Bel H7 5 Bel H5 7 3 4 Muddy Fill @ 6,488’ MD 12/19/21 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 3/8” capillary soap string to ~5400’ Updated by DMA 08-09-23 PROPOSED CONTINGENCY Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger, tieback seal assembly 4 6,473’- 6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 6 Bel H7 5 Bel H5 7 3 4 Muddy Fill @ 6,488’ MD 12/19/21 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 3/8” capillary soap string to ~5400’ 1 Christianson, Grace K (OGC) From:Jacob Flora <Jake.Flora@hilcorp.com> Sent:Wednesday, August 16, 2023 7:13 AM To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] BRU 212-26 (PTD 220-058) cap string sundry HiBryan, Here’sa3monthsnapshotoftheproduction.Rateinred(0Ͳ5000mcfd),FTPinblack(0Ͳ500psi). PleaseletmeknowifyouneedanythingelseinyourreviewͲ Thanks, Jake CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov> Sent:Tuesday,August15,20234:19PM To:JacobFlora<Jake.Flora@hilcorp.com> Subject:[EXTERNAL]BRU212Ͳ26(PTD220Ͳ058)capstringsundry Jake, CanyousendtheproductiontrendsandWHPplotstosupportremovingtheKͲvalveandinstallingthecapstring? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 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: 06/20/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230419 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 04RD 50133202390100 219011 5/10/2023 AK E-LINE PERF BRU 212-26 50283201820000 220058 5/31/2023 AK E-LINE PPROF NCI B-01A 50883200930100 198002 4/24/2023 AK E-LINE Cut CBL CIBP Paxton 12 50133207100000 223014 5/24/2023 AK E-LINE Perf Record Paxton 12 50133207100000 223014 4/27/2023 AK E-LINE GPT/PERF SRU 213B-15 50133206540000 215130 5/1/2023 AK E-LINE CIBP Perf TBU M-29A 50733204280100 212050 5/7/2023 AK E-LINE Drift Punch Please include current contact information if different from above. T37759 T37760 T37761 T37762 T37762 T37763 T37764 BRU 212-26 50283201820000 220058 5/31/2023 AK E-LINE PPROF Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.20 11:55:19 -08'00' 1 Regg, James B (OGC) From:Regg, James B (OGC) Sent:Thursday, February 2, 2023 2:29 PM To:Chad Helgeson Cc:Jacob Flora; McLellan, Bryan J (OGC) Subject:RE: BRU 212-26 k-valve pulled 2/19/23 (PTD: 220-058) Extension approved; well can remain online until the valve is installed and can be performance tested. This well has a lengthy history of k valve issues. Our records indicate Hilcorp has an approved sundry (322 188; apprvd 4/21/2022) for replacing K valve with a standard surface controlled SSSV. When does Hilcorp plan to do that tubing workover? Jim Regg Supervisor, Inspections AOGCC 333 W. 7 th Ave, Suite 100 Anchorage, AK 99501 907 793 1236 From:Chad Helgeson <chelgeson@hilcorp.com> Sent:Thursday, February 2, 2023 11:57 AM To:McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc:Jacob Flora <Jake.Flora@hilcorp.com> Subject:RE: BRU 212 26 k valve pulled 2/19/23 (PTD: 220 058) Bryan/Jim, I just wanted to give you an update on our K Valve status on BRU 212 26. The valve just flew down from the slope to Anchorage this morning. We are working on getting it to Kenai today and then having it charged and tested in the shop tomorrow. Our 14 day window from when we pulled the valve expires tomorrow. Since we need to provide a 48hr window for testing, can we get approval to get the valve set Saturday/Sunday (weather dependent for Beluga travel) and test the valve Sunday or Monday depending on when the valve gets installed? We will provide notice once we get the valve to the west side. Can we also keep the well flowing until the valve is installed sometime this weekend, even though it will be a couple days outside the 14 day window. Thanks Chad Helgeson 907 229 4824 From:Jacob Flora <Jake.Flora@hilcorp.com> Sent:Tuesday, January 31, 2023 11:04 AM To:McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc:Regg, James B (OGC) <jim.regg@alaska.gov>; Chad Helgeson <chelgeson@hilcorp.com> Subject:RE: BRU 212 26 k valve pulled 2/19/23 (PTD: 220 058) 2 Hi Bryan, We have not added perforations per Sundry 232 007 and we will have to pull the k valve to do so. The workover Sundry 322 188 to install a TR SSSV is still a possibility this spring and we would like to keep it open. Update on the K valve: We could not get a passing closure test and sourced a new back up Halliburton. It was set 1/27/23 and unfortunately would not pass a test and was pulled back out on 1/28/23. I found one on the slope that is newly re built that is on the way down here to try again. Let me know if you need anything additional, Thanks, Jake From:McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent:Friday, January 27, 2023 7:58 PM To:Jacob Flora <Jake.Flora@hilcorp.com> Cc:Regg, James B (OGC) <jim.regg@alaska.gov> Subject:[EXTERNAL] RE: BRU 212 26 k valve pulled 2/19/23 (PTD: 220 058) OK, sounds good. Did you already perforate per Sundry 323 007 or are you going to have to pull the K valve again soon to perforate? Also, I just noticed we had approved sundry 322 188 to pull tubing and install a SCSSSV. Did you decide not to do the RWO? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7 th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250 9193 From:Jacob Flora <Jake.Flora@hilcorp.com> Sent:Friday, January 27, 2023 9:38 AM To:McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject:BRU 212 26 k valve pulled 2/19/23 (PTD: 220 058) Hello Bryan, 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. 3 We pulled the k valve out of this well one week ago to lower the set pressure. The reason is that the valve would trip when we would lower the FTP to unload the well. We are currently in the process of re installing the new valve and will then obtain a new test. I wanted to keep you informed of this timing, Thanks, Jake The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,001'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi 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: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 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: AOGCC USE ONLY Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 17# / P-110 ICY 2,506' January 23, 2023 See Schematic See Schematic See Schematic See Schematic 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-058 50-283-20182-00-00 Beluga River Sterling-Beluga Gas Same CO 786 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-26 Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 6,789'6,473'5,261'~1,604psi See schematic MD 2,980psi 5,750psi 138' 2,050' 138' 2,731' Perforation Depth MD (ft): 5,506'5-1/2" 16" 9-5/8" 138' 2,731' 10,600psi6,789'8,001' m n P s t _ 66 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 2:16 pm, Jan 09, 2023 323-007 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.01.09 14:08:52 -09'00' Noel Nocas (4361) 10-404 CO 802 SFD DSR-1/9/23BJM 1/12/23 SFD 1/9/2023 Brett W. Huber, Sr. GCW 01/13/23JLC 1/13/2023 1/13/23 RBDMS JSB 011723 Well Prognosis Well Name: BRU 212-26 API Number: 50-283-20182-00-00 Current Status: Online Gas Producer Permit to Drill Number: 220-058 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 2079 psi @ 4759’ TVD (Based on a .437 gradient.) Max. Potential Surface Pressure: ~ 1604 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft) Well Status: Online Gas Producer Brief Well Summary Drilled & completed in 2020, BRU 212-26 is an online producer in the Beluga River Undefined Gas Pool. In February of 2022 a packer assembly with tailpipe and x-nipple were installed at 100’ BGL. A 3-1/2 k-valve was installed and successfully tested in March and the well has been online since. The objective of this sundry is to increase productivity by perforating additional Beluga sands. Notes Regarding Wellbore Condition: 2/09/2022 Perforate 5737-57’ w 20’ 3-3/8” perf gun 3/16/2022 Pull K-valve from 117’ SLM, install new k-valve 4/5/2022 Pull k-valve, tag TD at 6428’ w 2.25” DDB, set k-valve 8/26/2022 Pull k-valve, tag TD at 6385’ w 2.25” DDB, set k-valve Procedure: 1. RU Slickline, PT lubricator to 2500 psi 2. Pull K-valve, tag fill top 3. RU E-line, PT lubricator to 2500 psi 4. Perforate Beluga E – G sands: Top Beluga E 5083’ MD 3873’ TVD Bottom Beluga G 5970’ MD 4759’ TVD a) All sands lie in the BELUGA RIVER, UNDEFINED GAS POOL b) If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. c) Frac Calcs: Using 13.5 ppg EMW FIT at SC shoe (8/21/2020) (0.702 psi/ft frac grad) d) Shallowest Allowable Perf TVD = MPSP/(0.702-0.1) = 1604 psi / 0.602 = 2664‘ TVD 5. RU Slickline, PT lubricator to 2500 psi 6. Set K-valve, test Attachments: 1. Current Schematic 2. Proposed Schematic Use deepest open perf for this calculation unless pressure data is available to demonstrate depleted zones. This puts shallowest allowable perf near 3000' TVD, still above the requested perf depths. - bjm Updated by JLL 03/24/22 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8"189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No.Depth MD Depth TVD ID OD Item 1 100’ 100’ Baker KB Packer w tailpipe & X-nipple (set 2/25/22) 2 114’ 114’ 3-1/2 X-nipple 2.a 114’ 114’ K-valve w 200 psi closure pressure (set 3/16/22) 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2,506’ 1,919’ 6.180” 7.400” Baker tieback Seal Assembly 4 6,473’- 6,488’ 5,261’- 5,276’15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 6 Bel H7 5 Bel H5 7 3 4 Muddy Fill @ 6,488’ MD 12/19/21 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 Fill above Bel H5 capped w/ 15' of cement. -bjm Updated by DMA 01-09-23 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga E-G ±5,083’ ±5,970’ ±3,873’ ±4,759’ 3-3/8” Proposed TBD Beluga F4 5,496’ 5,505’ 4,284’ 4,293’ 3-3/8” 2/9/22 Open Beluga F5 5,587’ 5,591’ 4,375’ 4,379’ 3-3/8” 2/9/22 Open Beluga F7 5,725’ 5,730’ 4,513’ 4,518’ 3-3/8” 2/8/22 Open Beluga F7 5,737’ 5,757’ 4,525’ 4,545’ 3-3/8” 2/9/22 Open Beluga F7 5,781’ 5,787’ 4,569’ 4,575’ 3-3/8” 2/8/22 Open Beluga G2 5,994’ 6,012’ 4,782’ 4,800’ 2-7/8” 2/8/22 Open Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,370' 6,382' 5,158' 5,170' 3-3/8” 12/19/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,447’ 6,459’ 5,231’ 5,243’ 2-7/8” 12/19/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 08/10/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth MD Depth TVD ID OD Item 1 100’ 100’ Baker KB Packer w tailpipe & X-nipple (set 2/25/22) 2 114’ 114’ 3-1/2 X-nipple 2.a 114’ 114’ K-valve w 200 psi closure pressure (set 3/16/22) 3 2,495’ 1,913’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2,506’ 1,919’ 6.180” 7.400” Baker tieback Seal Assembly 4 6,473’- 6,488’ 5,261’- 5,276’ 15’ Cement Plug dump bailed on 1-21-22 5 6,545’ 5,333’ 5.500” CIBP set 10/21/20 6 6,633’ 5,421’ 5.500” MAP CIBP set on 10/18/20 7 7,500’ 6,288’ 5.500” CIBP set 09/28/20 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) Bel E-G 6 Bel H7 5 Bel H5 7 3 4 Muddy Fill @ 6,488’ MD 12/19/21 Bel F4-F7 Bel G2-G9 Bel H-H1 Bel H2-H3 Bel H4 1 Carlisle, Samantha J (OGC) From:Jacob Flora <Jake.Flora@hilcorp.com> Sent:Thursday, January 12, 2023 2:43 PM To:McLellan, Bryan J (OGC) Subject:BRU 212-26 AOGCC 10-403 PTD 220-058 Submitted 01-09-23 - Sundry Application - Correction to MPSP Calcs HiBryan, Pleaseseebelowthenewcalcsusingthedeepestopenperf. Letmeknowifyouthiscoverswhatyouneed. Thanks, Jake CAUTION: This email originated from outside the State of Alaska mail system. 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ϱ͕ϳϯϬ͛ ϰ͕ϱϭϯ͛ ϰ͕ϱϭϴ͛ ϯͲϯͬϴ͟ ϮͬϴͬϮϮ KƉĞŶ ĞůƵŐĂ&ϳ ϱ͕ϳϯϳ͛ ϱ͕ϳϱϳ͛ ϰ͕ϱϮϱ͛ ϰ͕ϱϰϱ͛ ϯͲϯͬϴ͟ ϮͬϵͬϮϮ KƉĞŶ ĞůƵŐĂ&ϳ ϱ͕ϳϴϭ͛ ϱ͕ϳϴϳ͛ ϰ͕ϱϲϵ͛ ϰ͕ϱϳϱ͛ ϯͲϯͬϴ͟ ϮͬϴͬϮϮ KƉĞŶ ĞůƵŐĂ'Ϯ ϱ͕ϵϵϰ͛ ϲ͕ϬϭϮ͛ ϰ͕ϳϴϮ͛ ϰ͕ϴϬϬ͛ ϮͲϳͬϴ͟ ϮͬϴͬϮϮ KƉĞŶ ĞůƵŐĂ'ϱ ϲ͕ϭϭϬ͛ ϲ͕ϭϭϱ͛ ϰ͕ϴϵϴ͛ ϰ͕ϵϬϯ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ'ϲ ϲ͕ϭϯϲ͛ ϲ͕ϭϰϭ͛ ϰ͕ϵϮϰ͛ ϰ͕ϵϮϵ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ'ϳ ϲ͕ϭϲϮ͛ ϲ͕ϭϲϲ͛ ϰ͕ϵϱϬ͛ ϰ͕ϵϱϰ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ'ϵ ϲ͕ϮϮϰ͛ ϲ͕ϮϮϵ͛ ϱ͕ϬϭϮ͛ ϱ͕Ϭϭϳ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ, ϲ͕Ϯϴϯ͛ ϲ͕Ϯϴϵ͛ ϱ͕Ϭϳϭ͛ ϱ͕Ϭϳϳ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ, ϲ͕ϯϭϴ͛ ϲ͕ϯϮϭ͛ ϱ͕ϭϬϲ͛ ϱ͕ϭϬϵ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ,ϭ ϲ͕ϯϯϳ͛ ϲ͕ϯϰϭ͛ ϱ͕ϭϮϱ͛ ϱ͕ϭϮϵ͛ ϮͲϳͬϴ͟ ϭϮͬϮϬͬϮϭ KƉĞŶ ĞůƵŐĂ,Ϯ ϲ͕ϯϳϬΖ ϲ͕ϯϴϮΖ ϱ͕ϭϱϴΖ ϱ͕ϭϳϬΖ ϯͲϯͬϴ͟ ϭϮͬϭϵͬϮϭ KƉĞŶ ĞůƵŐĂ,Ϯ ϲ͕ϯϲϵΖ ϲ͕ϯϵϭΖ ϱ͕ϭϱϳΖ ϱ͕ϭϳϵΖ ϯͲϯͬϴ͟ ϬϵͬϮϵͬϮϬ KƉĞŶ ĞůƵŐĂ,ϯ ϲ͕ϰϮϬ͛ ϲ͕ϰϮϵ͛ ϱ͕ϮϬϴ͛ ϱ͕Ϯϭϳ͛ ϮͲϳͬϴ͟ ϴͬϭϬͬϮϭ KƉĞŶ ĞůƵŐĂ,ϰ ϲ͕ϰϰϳ͛ ϲ͕ϰϱϵ͛ ϱ͕Ϯϯϭ͛ ϱ͕Ϯϰϯ͛ ϮͲϳͬϴ͟ ϭϮͬϭϵͬϮϭ KƉĞŶ ĞůƵŐĂ,ϰ ϲ͕ϰϱϬ͛ ϲ͕ϰϲϬ͛ ϱ͕Ϯϯϯ͛ ϱ͕Ϯϰϯ͛ ϮͲϳͬϴ͟ ϬϴͬϭϬͬϮϭ KƉĞŶ ĞůƵŐĂ,ϱ ϲ͕ϱϭϮΖ ϲ͕ϱϮϬΖ ϱ͕ϯϬϬΖ ϱ͕ϯϬϴΖ ϯͲϯͬϴ͟ ϬϭͬϮϭͬϮϮ /ƐŽůĂƚĞĚ ĞůƵŐĂ,ϳ ϲ͕ϱϲϬΖ ϲ͕ϱϴϯΖ ϱ͕ϯϰϴΖ ϱ͕ϯϳϭΖ ϯͲϯͬϴ͟ ϬϵͬϮϵͬϮϬ /ƐŽůĂƚĞĚ ĞůƵŐĂ,ϭϱ ϲ͕ϵϯϮΖ ϲ͕ϵϱϮΖ ϱ͕ϳϮϬΖ ϱ͕ϳϰϬΖ ϯͲϯͬϴ͟ ϬϵͬϮϵͬϮϬ /ƐŽůĂƚĞĚ ĞůƵŐĂ/ϭϮ ϳ͕ϱϯϲΖ ϳ͕ϱϰϵΖ ϲ͕ϯϮϰΖ ϲ͕ϯϯϳΖ ϮͲϳͬϴ͟ ϬϵͬϮϰͬϮϬ /ƐŽůĂƚĞĚ ĞůƵŐĂ:Ϯ ϳ͕ϳϬϮΖ ϳ͕ϳϭϰΖ ϲ͕ϰϵϬΖ ϲ͕ϱϬϮΖ ϮͲϳͬϴ͟ ϬϵͬϮϰͬϮϬ /ƐŽůĂƚĞĚ ĞůƵŐĂ:ϯ ϳ͕ϴϯϬΖ ϳ͕ϴϰϭΖ ϲ͕ϱϭϴΖ ϲ͕ϱϮϵΖ ϮͲϳͬϴ͟ ϬϵͬϮϰͬϮϬ /ƐŽůĂƚĞĚ ĞůƵŐĂ:ϰ ϳ͕ϴϱϮΖ ϳ͕ϴϲϯΖ ϲ͕ϲϰϬΖ ϲ͕ϱϱϭΖ ϮͲϳͬϴ͟ ϬϵͬϮϰͬϮϬ /ƐŽůĂƚĞĚ KW E,K> ͬ D Ed d/> ϵͲϱͬϴΗ ϭϴϵ͘ϱďďůƐŽĨϭϮ͘ϬƉƉŐůĞĂĚͬϰϳ͘ϴďďůƐŽĨϭϱ͘ϴƉƉŐƚĂŝůͬdKΛƐƵƌĨĂĐĞ;ϲϱ͘ϱďďůƐŽĨ ĐĞŵĞŶƚƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞͿ ϱͲϭͬϮ͟ dKΛϯ͕ϰϬϬ͛;>ĚĂƚĞĚϵͲϰͲϮϬϮϬͿ ^/E' d/> ^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶƚŽ^Ğƚ ĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϯϴΖ ϵͲϱͬϴΗ ^ƵƌĨƐŐ ϰϳ >ͲϴϬ d ϴ͘ϲϴϭ͟ ^ƵƌĨ Ϯ͕ϳϯϭ͛ ϱͲϭͬϮΗ WƌŽĚ>Ŷƌ ϭϳ WͲϭϭϬ/z dyWd ϰ͘ϴϵϮ͟ Ϯ͕ϰϵϱ͛ ϴ͕ϬϬϭ͛ dh/E' d/> ϱͲϭͬϮΗ dƵďŝŶŐ ϭϳ WͲϭϭϬ/z dyWd ϰ͘ϴϵϮ͟ ^ƵƌĨ Ϯ͕ϱϬϲ͛ ϭΘϮ ϭϲ͟ ϵͲϱͬϴ͟ ϭϮͲϭͬϰ͟ ŚŽůĞ ϱͲϭͬϮ͟ : t >Zz d/> EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ϭ ϭϬϬ͛ ϭϬϬ͛ ĂŬĞƌ<WĂĐŬĞƌǁƚĂŝůƉŝƉĞΘyͲŶŝƉƉůĞ;ƐĞƚϮͬϮϱͬϮϮͿ Ϯ ϭϭϰ͛ ϭϭϰ͛ ϯͲϭͬϮyͲŶŝƉƉůĞ Ϯ͘Ă ϭϭϰ͛ ϭϭϰ͛ <ͲǀĂůǀĞǁϮϬϬƉƐŝĐůŽƐƵƌĞƉƌĞƐƐƵƌĞ;ƐĞƚϯͬϭϲͬϮϮͿ ϯ Ϯ͕ϰϵϱ͛ ϭ͕ϵϭϯ͛ ϲ͘ϭϳϬ͟ ϴ͘ϰϯϬ͟ ĂŬĞƌyW>ŝŶĞƌdŽƉWĂĐŬĞƌ&ůĞdžͲ>ŽĐŬsůŝŶĞƌŚĂŶŐĞƌ Ϯ͕ϱϬϲ͛ ϭ͕ϵϭϵ͛ ϲ͘ϭϴϬ͟ ϳ͘ϰϬϬ͟ ĂŬĞƌƚŝĞďĂĐŬ^ĞĂůƐƐĞŵďůLJ ϰ ϲ͕ϰϳϯ͛Ͳ ϲ͕ϰϴϴ͛ ϱ͕Ϯϲϭ͛Ͳ ϱ͕Ϯϳϲ͛ϭϱ͛ĞŵĞŶƚWůƵŐĚƵŵƉďĂŝůĞĚŽŶϭͲϮϭͲϮϮ ϱ ϲ͕ϱϰϱ͛ ϱ͕ϯϯϯ͛ ϱ͘ϱϬϬ͟ /WƐĞƚϭϬͬϮϭͬϮϬ ϲ ϲ͕ϲϯϯ͛ ϱ͕ϰϮϭ͛ ϱ͘ϱϬϬ͟ DW/WƐĞƚŽŶϭϬͬϭϴͬϮϬ ϳ ϳ͕ϱϬϬ͛ ϲ͕Ϯϴϴ͛ ϱ͘ϱϬϬ͟ /WƐĞƚϬϵͬϮϴͬϮϬ ϴͲϭͬϮ͟ ŚŽůĞ Ğů,ϭϱ Ğů/ Ğů: &ŝůů ŶĐŽƵŶƚĞƌĞĚ Λϲ͕ϱϳϬ͛D ϭϬͬϭϴͬϮϬ ;DŝĚĚůĞŽĨ,ϳ WĞƌĨƐͿ ϲ Ğů,ϳ ϱ Ğů,ϱ ϳ ϯ ϰ DƵĚĚLJ&ŝůů Λ ϲ͕ϰϴϴ͛D ϭϮͬϭϵͬϮϭ Ğů &ϰͲ&ϳ Ğů 'ϮͲ'ϵ Ğů ,Ͳ,ϭ Ğů ,ϮͲ,ϯ Ğů ,ϰ hƉĚĂƚĞĚďLJ:>>ϬϯͬϮϱͬϮϮ WZKWK^ ĞůƵŐĂZŝǀĞƌhŶŝƚ ZhϮϭϮͲϮϲ Wd͗ϮϮϬͲϬϱϴ W/͗ϱϬͲϮϴϯͲϮϬϭϴϮͲϬϬͲϬϬ Wdсϲ͕ϱϰϱ͛Dͬdsсϱ͕ϯϯϯ͛ dсϴ͕ϬϬϭ͛Dͬdsсϲ͕ϳϴϵ͛ Z<ƚŽ'>сϭϴ͛ W Z&KZd/KE d/> ^ĂŶĚ dKWD dD D dKW ds dD ds^ŝnjĞ ĂƚĞ ^ƚĂƚƵƐ ĞůƵŐĂ&ϰϱ͕ϰϵϲ͛ϱ͕ϱϬϱ͛ϰ͕Ϯϴϰ͛ϰ͕Ϯϵϯ͛ϯͲϯͬϴ͟ϮͬϵͬϮϮKƉĞŶ ĞůƵŐĂ&ϱϱ͕ϱϴϳ͛ϱ͕ϱϵϭ͛ϰ͕ϯϳϱ͛ϰ͕ϯϳϵ͛ϯͲϯͬϴ͟ϮͬϵͬϮϮKƉĞŶ ĞůƵŐĂ&ϳϱ͕ϳϮϱ͛ϱ͕ϳϯϬ͛ϰ͕ϱϭϯ͛ϰ͕ϱϭϴ͛ϯͲϯͬϴ͟ϮͬϴͬϮϮKƉĞŶ ĞůƵŐĂ&ϳϱ͕ϳϯϳ͛ϱ͕ϳϱϳ͛ϰ͕ϱϮϱ͛ϰ͕ϱϰϱ͛ϯͲϯͬϴ͟ϮͬϵͬϮϮKƉĞŶ ĞůƵŐĂ&ϳϱ͕ϳϴϭ͛ϱ͕ϳϴϳ͛ϰ͕ϱϲϵ͛ϰ͕ϱϳϱ͛ϯͲϯͬϴ͟ϮͬϴͬϮϮKƉĞŶ ĞůƵŐĂ'Ϯϱ͕ϵϵϰ͛ϲ͕ϬϭϮ͛ϰ͕ϳϴϮ͛ϰ͕ϴϬϬ͛ϮͲϳͬϴ͟ϮͬϴͬϮϮKƉĞŶ ĞůƵŐĂ'ϱϲ͕ϭϭϬ͛ϲ͕ϭϭϱ͛ϰ͕ϴϵϴ͛ϰ͕ϵϬϯ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ'ϲϲ͕ϭϯϲ͛ϲ͕ϭϰϭ͛ϰ͕ϵϮϰ͛ϰ͕ϵϮϵ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ'ϳϲ͕ϭϲϮ͛ϲ͕ϭϲϲ͛ϰ͕ϵϱϬ͛ϰ͕ϵϱϰ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ'ϵϲ͕ϮϮϰ͛ϲ͕ϮϮϵ͛ϱ͕ϬϭϮ͛ϱ͕Ϭϭϳ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ,ϲ͕Ϯϴϯ͛ϲ͕Ϯϴϵ͛ϱ͕Ϭϳϭ͛ϱ͕Ϭϳϳ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ,ϲ͕ϯϭϴ͛ϲ͕ϯϮϭ͛ϱ͕ϭϬϲ͛ϱ͕ϭϬϵ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ,ϭϲ͕ϯϯϳ͛ϲ͕ϯϰϭ͛ϱ͕ϭϮϱ͛ϱ͕ϭϮϵ͛ϮͲϳͬϴ͟ϭϮͬϮϬͬϮϭKƉĞŶ ĞůƵŐĂ,Ϯϲ͕ϯϳϬΖϲ͕ϯϴϮΖϱ͕ϭϱϴΖϱ͕ϭϳϬΖϯͲϯͬϴ͟ϭϮͬϭϵͬϮϭKƉĞŶ ĞůƵŐĂ,Ϯϲ͕ϯϲϵΖϲ͕ϯϵϭΖϱ͕ϭϱϳΖϱ͕ϭϳϵΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬKƉĞŶ ĞůƵŐĂ,ϯϲ͕ϰϮϬ͛ϲ͕ϰϮϵ͛ϱ͕ϮϬϴ͛ϱ͕Ϯϭϳ͛ϮͲϳͬϴ͟ϴͬϭϬͬϮϭKƉĞŶ ĞůƵŐĂ,ϰϲ͕ϰϰϳ͛ϲ͕ϰϱϵ͛ϱ͕Ϯϯϭ͛ϱ͕Ϯϰϯ͛ϮͲϳͬϴ͟ϭϮͬϭϵͬϮϭKƉĞŶ ĞůƵŐĂ,ϰϲ͕ϰϱϬ͛ϲ͕ϰϲϬ͛ϱ͕Ϯϯϯ͛ϱ͕Ϯϰϯ͛ϮͲϳͬϴ͟ϬϴͬϭϬͬϮϭKƉĞŶ ĞůƵŐĂ,ϱϲ͕ϱϭϮΖϲ͕ϱϮϬΖϱ͕ϯϬϬΖϱ͕ϯϬϴΖϯͲϯͬϴ͟ϬϭͬϮϭͬϮϮ/ƐŽůĂƚĞĚ ĞůƵŐĂ,ϳϲ͕ϱϲϬΖϲ͕ϱϴϯΖϱ͕ϯϰϴΖϱ͕ϯϳϭΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ,ϭϱϲ͕ϵϯϮΖϲ͕ϵϱϮΖϱ͕ϳϮϬΖϱ͕ϳϰϬΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ/ϭϮϳ͕ϱϯϲΖϳ͕ϱϰϵΖϲ͕ϯϮϰΖϲ͕ϯϯϳΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:Ϯϳ͕ϳϬϮΖϳ͕ϳϭϰΖϲ͕ϰϵϬΖϲ͕ϱϬϮΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:ϯϳ͕ϴϯϬΖϳ͕ϴϰϭΖϲ͕ϱϭϴΖϲ͕ϱϮϵΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:ϰϳ͕ϴϱϮΖϳ͕ϴϲϯΖϲ͕ϲϰϬΖϲ͕ϱϱϭΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ KW E,K> ͬ D Ed d/> ϵͲϱͬϴΗϭϴϵ͘ϱďďůƐŽĨϭϮ͘ϬƉƉŐůĞĂĚͬϰϳ͘ϴďďůƐŽĨϭϱ͘ϴƉƉŐƚĂŝůͬdKΛƐƵƌĨĂĐĞ;ϲϱ͘ϱďďůƐŽĨ ĐĞŵĞŶƚƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞͿ ϱͲϭͬϮ͟dKΛϯ͕ϰϬϬ͛;>ĚĂƚĞĚϵͲϰͲϮϬϮϬͿ ^/E' d/> ^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶƚŽ^Ğƚ ĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϯϴΖ ϵͲϱͬϴΗ^ƵƌĨƐŐϰϳ>ͲϴϬdϴ͘ϲϴϭ͟^ƵƌĨϮ͕ϳϯϭ͛ ϱͲϭͬϮΗWƌŽĚ>ŶƌϭϳWͲϭϭϬ/zdyWdϰ͘ϴϵϮ͟Ϯ͕ϰϵϱ͛ϴ͕ϬϬϭ͛ dh/E' d/> ϱͲϭͬϮΗdƵďŝŶŐϭϳWͲϭϭϬ/zdyWdϰ͘ϴϵϮ͟^ƵƌĨϮ͕ϱϬϲ͛ ϭϭϲ͟ ϵͲϱͬϴ͟ ϭϮͲϭͬϰ͟ ŚŽůĞ ϱͲϭͬϮ͟ : t >Zz d/> EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ϭцϭϭϬ͛цϭϭϬ͛ϱͲϭͬϮ͟^^^s ϮϮ͕ϰϵϱ͛ϭ͕ϵϭϯ͛ϲ͘ϭϳϬ͟ϴ͘ϰϯϬ͟ĂŬĞƌyW>ŝŶĞƌdŽƉWĂĐŬĞƌ&ůĞdžͲ>ŽĐŬsůŝŶĞƌŚĂŶŐĞƌ Ϯ͕ϱϬϲ͛ϭ͕ϵϭϵ͛ϲ͘ϭϴϬ͟ϳ͘ϰϬϬ͟ĂŬĞƌƚŝĞďĂĐŬ^ĞĂůƐƐĞŵďůLJ ϯϲ͕ϰϳϯ͛Ͳ ϲ͕ϰϴϴ͛ ϱ͕Ϯϲϭ͛Ͳ ϱ͕Ϯϳϲ͛ ϭϱ͛ĞŵĞŶƚWůƵŐĚƵŵƉďĂŝůĞĚŽŶϭͲϮϭͲϮϮ ϰϲ͕ϱϰϱ͛ϱ͕ϯϯϯ͛ϱ͘ϱϬϬ͟/WƐĞƚϭϬͬϮϭͬϮϬ ϱϲ͕ϲϯϯ͛ϱ͕ϰϮϭ͛ϱ͘ϱϬϬ͟DW/WƐĞƚŽŶϭϬͬϭϴͬϮϬ ϲϳ͕ϱϬϬ͛ϲ͕Ϯϴϴ͛ϱ͘ϱϬϬ͟/WƐĞƚϬϵͬϮϴͬϮϬ ϴͲϭͬϮ͟ ŚŽůĞ Ğů,ϭϱ Ğů/ Ğů: &ŝůů ŶĐŽƵŶƚĞƌĞĚ Λϲ͕ϱϳϬ͛D ϭϬͬϭϴͬϮϬ ;DŝĚĚůĞŽĨ,ϳ WĞƌĨƐͿ ϱ Ğů,ϳ ϰ Ğů,ϱ ϲ Ϯ ϯ DƵĚĚLJ&ŝůůΛ ϲ͕ϰϴϴ͛D ϭϮͬϭϵͬϮϭ Ğů&ϰͲ&ϳ Ğů'ϮͲ'ϵ Ğů,Ͳ,ϭ Ğů,ϮͲ,ϯ Ğů,ϰ %HOXJD5LYHU8QLW %58 sĂůǀĞ͕DĂƐƚĞƌ͕t<DͲD͕ ϱϭͬϴϱD& ͕,tK͕ ƚƌŝŵ sĂůǀĞ͕hƉƉĞƌŵĂƐƚĞƌ͕ t<DͲD͕ ϱϭͬϴϱD& 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/WƐĞƚϬϵͬϮϴͬϮϬ ϴͲϭͬϮ͟ ŚŽůĞ Ğů,ϭϱ Ğů/ Ğů: &ŝůů ŶĐŽƵŶƚĞƌĞĚ Λϲ͕ϱϳϬ͛D ϭϬͬϭϴͬϮϬ ;DŝĚĚůĞŽĨ,ϳ WĞƌĨƐͿ ϲ Ğů,ϳ ϱ Ğů,ϱ ϳ ϯ ϰ DƵĚĚLJ&ŝůů Λ ϲ͕ϰϴϴ͛D ϭϮͬϭϵͬϮϭ Ğů &ϰͲ&ϳ Ğů 'ϮͲ'ϵ Ğů ,Ͳ,ϭ Ğů ,ϮͲ,ϯ Ğů ,ϰ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ůŝŶĞ ϭϮͬϭϵͬϮϭ ϯͬϭϵͬϮϮ ϭϮͬϭϵͬϮϬϮϭͲ^ƵŶĚĂLJ W:^DĂŶĚWdt͘DŽďŝůŝnjĞĞƋƵŝƉŵĞŶƚƚŽůŽĐĂƚŝŽŶĂŶĚƐƉŽƚĞƋƵŝƉŵĞŶƚ͕ZŝŐƵƉĞƋƵŝƉŵĞŶƚ͕DhůƵďƌŝĐĂƚŽƌ͘WdůƵďƌŝĐĂƚŽƌƚŽ ϮϱϬƉƐŝͬϮϱϬϬƉƐŝͲdĞƐƚŐŽŽĚ ^ŚƵƚŝŶǁĞůů;ĨůŽǁŝŶŐϭ͘ϱϳDD&͕ϭϲϲƉƐŝƚƵďŝŶŐƉƌĞƐƐƵƌĞͿ͕DͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϲĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕ 'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϬΖͿĂŶĚZ/,͘ dĂŐĂƚϲ͕ϱϭϲΖ͕ŐƵŶƐƚƵĐŬ͘WƵůůϮϱϬϬůďƐǁŝƚŚŶŽůƵĐŬ͘KƉĞŶƵƉĂŶĚĨůŽǁǁĞůů͕ŐƵŶĐĂŵĞĨƌĞĞ͘WKK,͘tŝůůŶŽƚďĞƐŚŽŽƚŝŶŐ ƚŚĞ,ϱƐĂŶĚƐ͘>ͬƵŶƐŚŽƚϲĨƚŐƵŶ͕͘'ƵŶηϭͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϭϮĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽ ƚŽƉƐŚŽƚϭϭ͘ϴΖͿĂŶĚZ/,͘WƵůůĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ,ϰƐĂŶĚƐ ĨƌŽŵ;ϲ͕ϰϰϳΖͲϲ͕ϰϱϵΖͿ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϰϭϵƉƐŝ ϱŵŝŶͲϰϮϮƉƐŝ ϭϬŵŝŶͲϰϮϰƉƐŝ ϭϱŵŝŶͲϰϮϲƉƐŝ͕'ƵŶηϮͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϭϮĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϭ͘ϴΖͿ ĂŶĚZ/,͘WƵůůĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ,ϮƐĂŶĚƐĨƌŽŵ;ϲ͕ϯϳϬΖͲ ϲ͕ϯϴϮΖͿ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϰϱϵƉƐŝ ϱŵŝŶͲϰϲϮƉƐŝ ϭϬŵŝŶͲϰϲϰƉƐŝ ϭϱŵŝŶͲϰϲϲƉƐŝ͕>ĂLJĚŽǁŶůƵďƌŝĐĂƚŽƌ͕ƐĞĐƵƌĞǁĞůůĂŶĚ^&E͘ WƌŽĚƵĐƚŝŽŶǁŝůůĨůŽǁƚŚĞǁĞůůŽǀĞƌŶŝŐŚƚ ĂŝůLJKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůLJKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌLJ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ZhϮϭϮͲϮϲ ϱϬͲϮϴϯͲϮϬϭϴϮͲϬϬͲϬϬ ϮϮϬͲϬϱϴ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ůŝŶĞ ϭϮͬϭϵͬϮϭ ϯͬϭϵͬϮϮ ĂŝůLJKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůLJKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌLJ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ZhϮϭϮͲϮϲ ϱϬͲϮϴϯͲϮϬϭϴϮͲϬϬͲϬϬ ϮϮϬͲϬϱϴ ϭϮͬϮϬͬϮϬϮϭͲDŽŶĚĂLJ W:^DĂŶĚWdt͘tĂƌŵƵƉĞƋƵŝƉŵĞŶƚ͘^ŚƵƚǁĞůůŝŶ͕'ƵŶηϯͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϰĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕ 'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϭ͘ϴΖͿĂŶĚZ/,͘WƵůůĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚ ĂŶĚƐŚŽŽƚĞůƵŐĂ,ϭƐĂŶĚƐĨƌŽŵ;ϲ͕ϯϯϳΖͲϲ͕ϯϰϭΖͿ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϯϱϮƉƐŝ͖ϱŵŝŶͲϯϱϳƉƐŝ͖ϭϬŵŝŶͲϯϲϱƉƐŝ͖ϭϱŵŝŶͲϯϳƉƐŝ͘ 'ƵŶηϰͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϯĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϮ͘ϴΖͿĂŶĚZ/,͘WƵůů ĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ,ƐĂŶĚƐĨƌŽŵ;ϲ͕ϯϭϴΖͲϲ͕ϯϮϭΖͿ͘WKK,͘ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϰϴϲƉƐŝ͖ϱŵŝŶͲϰϴϳƉƐŝ͖ϭϬŵŝŶͲϰϴϴƉƐŝ͖ϭϱŵŝŶͲϰϴϵƉƐŝ͘ 'ƵŶηϱͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϲĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϬ͘ϬΖͿĂŶĚZ/,͘WƵůů ĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ,ƐĂŶĚƐĨƌŽŵ;ϲ͕ϮϴϯΖͲϲ͕ϮϴϵΖͿ͘WKK,͘ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϱϭϱƉƐŝ͖ϱŵŝŶͲϱϭϳƉƐŝ͖ϭϬŵŝŶͲϱϭϵƉƐŝ͖ϭϱŵŝŶͲϱϮϬƉƐŝ͘ 'ƵŶηϲͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϱĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϬ͘ϵΖͿĂŶĚZ/,͘WƵůů ĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ'ϵƐĂŶĚƐĨƌŽŵ;ϲ͕ϮϮϰΖͲϲ͕ϮϮϵΖͿ͘WKK,͘ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϱϯϴƉƐŝ͖ϱŵŝŶͲϱϰϵƉƐŝ͖ϭϬŵŝŶͲϱϱϵƉƐŝ͖ϭϱŵŝŶͲϱϳϬƉƐŝ͘ 'ƵŶηϳͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϰĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϭ͘ϴΖͿĂŶĚZ/,͘WƵůů ĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ'ϳƐĂŶĚƐĨƌŽŵ;ϲ͕ϭϲϮͲϲ͕ϭϲϲΖͿ͘WKK,͘ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶĐŽĂƚĞĚŝŶŵƵĚ ϬŵŝŶͲϳϴϱƉƐŝ͖ϱŵŝŶͲϴϱϵƉƐŝ͖ϭϬŵŝŶͲϵϭϯƉƐŝ͖ϭϱŵŝŶͲϵϲϱƉƐŝ͖ϯϬŵŝŶͲϭϬϱϳƉƐŝ͘ 'ƵŶηϴͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϱĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϬ͘ϴΖͿĂŶĚZ/,͘WƵůů ĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘^ŚŝĨƚůŽŐĚŽǁŶϭĨƚ͕͘WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ'ϲƐĂŶĚƐĨƌŽŵ;ϲ͕ϭϯϲͲϲ͕ϭϰϭΖͿ͘ WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶŚĂƐůĞƐƐŵƵĚŽŶŝƚƚŚĂŶƚŚĞƉƌĞǀŝŽƵƐŐƵŶƐ ϬŵŝŶͲϭϭϱϵƉƐŝ͖ϱŵŝŶͲϭϭϲϯƉƐŝ͖ϭϬŵŝŶͲϭϭϲϳƉƐŝ͖ϭϱŵŝŶͲϭϭϳϭƉƐŝ͘ 'ƵŶηϵͲDͬhŐĂŵŵĂ͕ĐĐů͕ĂŶĚϱĨƚͲϮͲϳͬϴΗ͕ϲ^W&͕ϭϱŐƌĂŵ͕'ĞŽĚLJŶĂŵŝĐƐŐƵŶ;>ƚŽƚŽƉƐŚŽƚϭϬ͘ϴΖͿĂŶĚZ/,͘WƵůů ĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͕WƵůůŐƵŶŽŶĚĞƉƚŚĂŶĚƐŚŽŽƚĞůƵŐĂ'ϱƐĂŶĚƐĨƌŽŵ;ϲ͕ϭϭϬͲϲ͕ϭϭϱΖͿ͘WKK,͘ ůůƐŚŽƚƐĨŝƌĞĚ͘ůŝƚƚůĞŵƵĚŽŶƚŚĞŐƵŶ ϬŵŝŶͲϭϮϬϲƉƐŝ͖ϱŵŝŶͲϭϮϬϵƉƐŝ͖ϭϬŵŝŶͲϭϮϭϬƉƐŝ͖ϭϱŵŝŶͲϭϮϭϬƉƐŝ͘ ZŝŐĚŽǁŶ ͲůŝŶĞ͘^ĞĐƵƌĞǁĞůů͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘WĞƌĨŽƌĂƚŝŶŐĚŽŶĞŽŶZhϮϭϮͲϮϲ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ůŝŶĞ ϭϮͬϭϵͬϮϭ ϯͬϭϵͬϮϮ ĂŝůLJKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůLJKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌLJ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ZhϮϭϮͲϮϲ ϱϬͲϮϴϯͲϮϬϭϴϮͲϬϬͲϬϬ ϮϮϬͲϬϱϴ ϬϭͬϭϵͬϮϬϮϮͲtĞĚŶĞƐĚĂLJ DŽďŝůŝnjĞ< ͲůŝŶĞĐƌĞǁƚŽĞůƵŐĂ͕͘KĨĨůŽĂĚ ͲůŝŶĞƚŽŽůƐĨƌŽŵƉůĂŶĞ͘ŚĞĐŬŝŶƚŽĐĂŵƉ͘ ^ƚĂƌƚŵƚƌƵĐŬ͘ ͲůŝŶĞhŶŝƚǁŽŶΖƚƐƚĂƌƚ͕ŝƐƐƵĞƐǁŝƚŚďĂƚƚĞƌLJĂŶĚƐƚĂƌƚĞƌ͘dƌŽƵďůĞƐŚŽŽƚĂŶĚŐĞƚƐƚĂƌƚĞĚ͘ ZĞŵŽǀĞƐŶŽǁĨƌŽŵĂƌŽƵŶĚǁĞůů͘ ^&E͘ ϬϭͬϮϬͬϮϬϮϮͲdŚƵƌƐĚĂLJ < ͲůŝŶĞĐŽŶĚƵĐƚ:^͘ƉƉƌŽǀĞWdt͘ D/Zh ͲůŝŶĞĞƋƵŝƉŵĞŶƚ͘^ƉŽƚƚƌŝƉůĞdžĂŶĚďůŽǁĚŽǁŶƚĂŶŬ͘ZŽĂĚŵĂŶůŝĨƚƚŽůŽĐĂƚŝŽŶ͘ZĞͲŚĞĂĚ ͲůŝŶĞ͘ DhϳΗƌŝƐĞƌĂŶĚǁŝƌĞůŝŶĞǀĂůǀĞŽŶƚƌĞĞ͘DhůƵďƌŝĐĂƚŽƌ͕͘Dh'WdǁŝƚŚϰ͘ϱΗŐĂƵŐĞƌŝŶŐͬũƵŶŬďĂƐŬĞƚ͘ WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϮϱϬϬƉƐŝŚŝŐŚ͕͘KƉĞŶǁĞůůĂŶĚZ/,͘t,WсϭϬϬϬƉƐŝ͘ dĂŐĂƚƚŝĞďĂĐŬƐĞĂůĂƐƐĞŵďůLJĂƚϮϱϬϬΖ͘tŽƌŬǁŝƌĞĂŶĚĂƚƚĞŵƉƚƚŽŚĂŶĚƐƉĂŶŐƚŚƌŽƵŐŚ͘hŶĂďůĞƚŽƉĂƐƐ͘ WKK,͕͘Z/,ǁŝƚŚ'WdƚŽŽůƐƚƌŝŶŐŽŶůLJ͘EŽŝƐƐƵĞƐŐŽŝŶŐƚŚƌŽƵŐŚƚŝĞďĂĐŬƐĞĂůĂƐƐĞŵďůLJ͘ &ŝŶĚĨůƵŝĚůĞǀĞůĂƚϲϰϭϬΖ͘dĂŐĂƚϲϱϭϬΖ;ƵŶĐŽƌƌĞĐƚĞĚͿ͘ WKK,͕͘DhĚƌŝĨƚĂƐƐĞŵďůLJǁŝƚŚϮΗǁƚďĂƌ͕ϯΗũƵŶŬďĂƐŬĞƚĂŶĚϰ͘ϱϬΗŐĂƵŐĞƌŝŶŐ͘ tŽƌŬƚŚƌŽƵŐŚƐĞĂůĂƐƐĞŵďůLJĂƚϮϱϬϬΖ͘ dĂŐĂƚϲϱϭϬΖ;ƵŶĐŽƌƌĞĐƚĞĚͿ͘ WKK,͕͘>ĂLJĚŽǁŶŐĂƵŐĞƌŝŶŐͬũƵŶŬďĂƐŬĞƚ͘^ĂŶĚŝŶũƵŶŬďĂƐŬĞƚ͘ >ĂLJĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚƐĞĐƵƌĞǁĞůů͘/ŶƐƚĂůůŶŝŐŚƚĐĂƉ͘ ^&E͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ůŝŶĞ ϭϮͬϭϵͬϮϭ ϯͬϭϵͬϮϮ ĂŝůLJKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůLJKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌLJ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ZhϮϭϮͲϮϲ ϱϬͲϮϴϯͲϮϬϭϴϮͲϬϬͲϬϬ ϮϮϬͲϬϱϴ ϬϮͬϬϳͬϮϬϮϮͲDŽŶĚĂLJ < ͲůŝŶĞĐŽŶĚƵĐƚ:^͘ƉƉƌŽǀĞWdt͘ Dhϱ͘ϱΗ/WƚŽŽůƐƚƌŝŶŐ͘'Zͬ>ƚŽƚŽƉŽĨƉůƵŐсϭϮ͘ϬΖ͘ DhůƵďƌŝĐĂƚŽƌĂŶĚŽƉĞŶǁĞůů͕͘dĂŐĂƚϲϰϭϱΖǁŝƚŚ/W͘ WKK,͘EŽƚŝĐĞǁĞŝŐŚƚƐǁŝŶŐƐǁŚŝůĞWKK,ǁŝƚŚ/W͕͘DhĂŶĚZ/,ǁŝƚŚĂŶĞŵƉƚLJϯΗdžϮϬΖĐĞŵĞŶƚďĂŝůĞƌ͘'Zͬ>ƚŽ ďŽƚƚŽŵŽĨďĂŝůĞƌсϮϲ͘ϬΖΖ͘ dĂŐĂƚϲϰϴϰΖ͘^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽZ ͬ' K͘KŶĚĞƉƚŚ͘WKK,͕͘DhĂŶĚZ/,ǁŝƚŚϯΗdžϮϬΖĐĞŵĞŶƚďĂŝůĞƌηϭ͘>ŽĂĚϱ ŐĂůůŽŶƐŽĨĐĞŵĞŶƚŝŶďĂŝůĞƌ;ϱ͘ϭΖŝŶϱͲϭͬϮΗƚƵďŝŶŐͿ͘'Zͬ>ƚŽďŽƚƚŽŵŽĨďĂŝůĞƌсϮϲ͘ϬΖ͘ ŽƌƌĞůĂƚĞ͘dĂŐĂƚϲϰϴϴΖ͘Wh,ƚŽϲϰϴϭΖĂŶĚĚƵŵƉĐĞŵĞŶƚ͘tŽƌŬǁŝƌĞƚŽŐĞƚĂůůĐĞŵĞŶƚŽƵƚ͘WKK,͕͘DhĂŶĚZ/,ǁŝƚŚϯΗ džϮϬΖĐĞŵĞŶƚďĂŝůĞƌηϮ͘>ŽĂĚϱŐĂůůŽŶƐŽĨĐĞŵĞŶƚŝŶďĂŝůĞƌ;ϱ͘ϭΖŝŶϱͲϭͬϮΗƚƵďŝŶŐͿ͘'Zͬ>ƚŽďŽƚƚŽŵŽĨďĂŝůĞƌсϮϲ͘ϬΖ͘ ŽƌƌĞůĂƚĞ͘Wh,ƚŽϲϰϳϲΖĂŶĚĚƵŵƉĐĞŵĞŶƚ͘tŽƌŬǁŝƌĞƚŽŐĞƚĂůůĐĞŵĞŶƚŽƵƚ͘WKK,͕͘DhĂŶĚZ/,ǁŝƚŚϯΗdžϮϬΖĐĞŵĞŶƚ ďĂŝůĞƌηϯ͘>ŽĂĚϱŐĂůůŽŶƐŽĨĐĞŵĞŶƚŝŶďĂŝůĞƌ;ϱ͘ϭΖŝŶϱͲϭͬϮΗƚƵďŝŶŐͿ͘'Zͬ>ƚŽďŽƚƚŽŵŽĨďĂŝůĞƌсϮϲ͘ϬΖ͘ ŽƌƌĞůĂƚĞ͘Wh,ƚŽϲϰϳϭΖĂŶĚĚƵŵƉĐĞŵĞŶƚ͘tŽƌŬǁŝƌĞƚŽŐĞƚĂůůĐĞŵĞŶƚŽƵƚ͘WKK,͘ dŽƚĂůĐĞŵĞŶƚĚƵŵƉĞĚǁĂƐϭϱŐĂůůŽŶƐ͘&ƌŽŵϲϰϳϯͲϲϰϴϴΖ͕͘>ĂLJĚŽǁŶĐĞŵĞŶƚďĂŝůĞƌƚŽŽůƐƚƌŝŶŐĂŶĚůƵďƌŝĐĂƚŽƌ͘ ZĞŵŽǀĞǁŝƌĞůŝŶĞǀĂůǀĞƐĂŶĚƌŝƐĞƌ͘/ŶƐƚĂůůƚƌĞĞĐĂƉ͘ Z ϬϭͬϮϮͬϮϬϮϮͲ^ĂƚƵƌĚĂLJ ZDKĨƌŽŵůŽĐĂƚŝŽŶ͘ DŽǀĞĞƋƵŝƉŵĞŶƚƚŽĞŶƚƌĂŶĐĞŽĨƉĂĚ͘ 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rom:McLellan, Bryan J (OGC) To:Jacob Flora Cc:Dan Marlowe; Juanita Lovett Subject:RE: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Date:Tuesday, March 29, 2022 12:28:00 PM Jake, Dan, Thanks for the self reporting. What will you do to prevent recurrence? At a minimum, Hilcorp should do the following: 1. For future sundries, test pressures should state a value for the required test pressure so it is not left up to the discretion of the individual performing the test. Write “pressure test e-line lubricator to 2000 psi” instead of “Pressure test to MPSP”, for example. 2. I think there are a number of already approved Sundries out there that say to PT to MPSP. Hilcorp should communicate the issue with service companies and company reps to make sure they know what MPSP means and where they can find it on the Sundry. Or make a change to all the approved procedures, stating a required test pressure value that is greater than MPSP. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, March 28, 2022 9:59 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Bryan, While wrapping up documentation for the 10-404 we discovered an E-line PT of 1500 psi was performed which was below the PT stated in the sundry. The sundry PT was to be above MASP, stated as 1707 psi in the header. It is worth mentioning that the SITP at this time was around 1000 psi, and that the activity was to set a packer, which would not have changed the MPSP. I wanted to point this discrepancy out prior to submitting the 10-404 this week. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, March 8, 2022 11:35 AM To: Jacob Flora <Jake.Flora@hilcorp.com>; Pete Iverson <jpiverson@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Jake, your request for a 10-day extension to troubleshoot the K-valve is approved. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Tuesday, March 8, 2022 10:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Pete Iverson <jpiverson@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Bryan, Yesterday we tested the k-valve and were unable to bleed the flowline pressure low enough to trip the 100psi set pressure. We are working now on 1) re-routing the flow path to the bleed down tank, if this doesn’t work we will pull/reset the k-valve with a higher closure pressure. We would like to request a 10 day extension to perform the above work, get a repeatable field test and then resubmit for a state witnessed test. Best Regards, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, March 7, 2022 10:06 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Jake, Thanks for the update. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, March 7, 2022 9:56 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Hello Bryan, I wanted to provide an operational update on our k-valve install: 2/25/22 Packer/nipple/k-valve were installed, the k-valve had a closure pressure of 300psi. Testing the valve indicated we needed a lower closure pressure. 3/1/22 K-valve was pulled, a new k-valve was run with 100 psi closure pressure. There were issues with the flowline not allowing a closure test (the v-cone meter had to be repaired). 3/5/22 48hr notice sent for a witnessed closure test 3/7/22 Today we will test the k-valve. Today is also the extended deadline date per the below email thread. If we are unsuccessful in obtaining a passing closure test today I will need to ask for an extension to reset the valve. We appreciate the AOGCCs patience as we work toward bringing this well into compliance. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, February 23, 2022 11:27 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Jake, You have approval for extending the deadline until 3/7/22 due to the weather delays and because Hilcorp has been working diligently to get this well cleaned out, perforated and repaired. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, February 23, 2022 11:15 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Hello Bryan, Jim, We are flying crews over Saturday to set the packer/tailpipe/k-valve assembly- there is a good weather window to work in. It may take a few iterations of pulling the k-valve to adjust the dome pressure to see it work properly. Once we do this we will provide 48hrs notice to witness the closure test. I would anticipate requesting a state witness approximately 3/3 of next week. I wanted to provide this timing update as the testing portion of the work will likely exceed the 2/28 deadline (per the 1/28 email in the below chain). Please advise if you require an extension request or if this email will suffice. Greatly appreciated, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, February 22, 2022 5:14 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Jake, Yes, you have approval to set the K-valve no shallower than 100 feet below ground level, as allowed in 20 AAC 25.265(g)(1)(A). Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, February 21, 2022 1:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Subject: RE: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Welcome back Bryan, I just returned myself and getting caught up on a few projects. On this Beluga K-valve install, we added additional perfs and are now proceeding with the K-valve install. I have one request/change at this time: in the sundry I wrote in that we would set it at 250’. If possible we would like to change this to 100’ below ground level which is the state requirement. The reason is that the well has a higher SITP than before and to open the K-valve we likely will have to use fluid pressure to open it. A smaller volume of fluid will have less impact on the well. Please advise if this is acceptable, we are currently standing down a few days to let the weather pass through before sending crews over. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, January 28, 2022 1:55 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Extension Request Jake, Your request for a one month extension is granted. Plan to install the SSSV by Feb 28, 2022. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, January 28, 2022 12:02 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Extension Request Bryan, Hilcorp respectfully requests a timeline extension of one month (from 1/31/22 to 2/28/22) to install the required K-valve into the BRU 212-26 wellbore. Operations Update: 1/13/22 We logged a flowing PT survey and found the fluid level to be around 3600’ meaning we have significant amount of water in the wellbore 1/21/22 A CIBP was attempted to set over the suspected wet H5 perforations at 6512-20’. E-line was unable to get a CIBP down to the perforations. A dump bailer was able to get doen to the perfs and 15’ cement plug was dump bailed at 6473-88’. 1/24/21 The well was brought online and is currently being evaluated for water inflow. We anticipate logging a second flowing PT survey and potentially a second water shutoff attempt based on the data. A one month extension will allow us time to properly evaluate and perform the work prior to installing the K-valve packer (which is now in Beluga, along with the K-valve) Thanks, Jake From: Jacob Flora Sent: Wednesday, January 5, 2022 11:05 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Perforate & K-valve installation update Hello Bryan, I wanted to provide a status update of where we are in the process of installing the k-valve. Per the approved sundry we added multiple Beluga perforations to improved the flowrate prior to installing the k-valve. This has improved the flow, however during the perforating we saw mud on the guns and have reason to believe it’s the bottom set of perforations that need to be plugged over. My next steps down this path: 1. Mobe slickline, drift/bail to ensure a plug can be set 2. Set plug with e-line 3. Flow well 4. Set Baker packer w tailpipe (it’s being shipped down from the slope this week, will be flown over and assembled in Beluga as it all has to fit in the Otter) 5. Set k-valve/x-lock with slickline & test same We are getting there, however I believe this will run into and past the 1/13/22 deadline per Sundry 321-622. Can I request an extension now or would it be better to request one closer to the deadline? I anticipate needing till the end of the month to get all these steps done. Below is a picture of the mud we saw on the recent perforating. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, December 16, 2021 8:53 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] RE: Perforation Change: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Jake, You have approval to re-perf the requested intervals in your email below. Since you are not opening up any new pools with these perfs, we will approve via this email. No need for an additional Sundry. Please include this email with your 10-404. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Thursday, December 16, 2021 8:42 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Perforation Change: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) 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. Hi Bryan, Our geologist made a slight change to the planned perforations- we now want to re-perf the existing Beluga H2-H5 perfs (highlighted below) before moving uphole to the approved new perf intervals (Beluga D-H1). Can we add this to the existing Sundry? Thanks, Jake Sand Name MD Top MD Bot MD Tot TVD Top TVD Bot Beluga H2 6370 6382 12 5158 5170 Beluga H4 6447 6459 12 5231 5243 Beluga H5 6512 6518 6 5299 5305 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 telephoneif 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 onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephoneif 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 onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entitynamed 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 telephoneif the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entitynamed 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 thecompany in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 telephoneif 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 thecompany in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 03/03/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) Strip Gun 02/08/2022 Please include current contact information if different from above. 220-058 T36417 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.15 14:27:37 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 3/08/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) Setting Record 2/26/2022 Please include current contact information if different from above. 220-058 T36405 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.08 13:55:35 -09'00' From:McLellan, Bryan J (OGC) To:Jacob Flora Cc:Regg, James B (OGC) Subject:RE: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Date:Tuesday, February 22, 2022 5:13:00 PM Jake, Yes, you have approval to set the K-valve no shallower than 100 feet below ground level, as allowed in 20 AAC 25.265(g)(1)(A). Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, February 21, 2022 1:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) K-Valve install update Welcome back Bryan, I just returned myself and getting caught up on a few projects. On this Beluga K-valve install, we added additional perfs and are now proceeding with the K-valve install. I have one request/change at this time: in the sundry I wrote in that we would set it at 250’. If possible we would like to change this to 100’ below ground level which is the state requirement. The reason is that the well has a higher SITP than before and to open the K-valve we likely will have to use fluid pressure to open it. A smaller volume of fluid will have less impact on the well. Please advise if this is acceptable, we are currently standing down a few days to let the weather pass through before sending crews over. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, January 28, 2022 1:55 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: [EXTERNAL] FW: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Extension Request Jake, Your request for a one month extension is granted. Plan to install the SSSV by Feb 28, 2022. 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 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, January 28, 2022 12:02 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Extension Request Bryan, Hilcorp respectfully requests a timeline extension of one month (from 1/31/22 to 2/28/22) to install the required K- valve into the BRU 212-26 wellbore. Operations Update: 1/13/22 We logged a flowing PT survey and found the fluid level to be around 3600’ meaning we have significant amount of water in the wellbore 1/21/22 A CIBP was attempted to set over the suspected wet H5 perforations at 6512-20’. E-line was unable to get a CIBP down to the perforations. A dump bailer was able to get doen to the perfs and 15’ cement plug was dump bailed at 6473-88’. 1/24/21 The well was brought online and is currently being evaluated for water inflow. We anticipate logging a second flowing PT survey and potentially a second water shutoff attempt based on the data. A one month extension will allow us time to properly evaluate and perform the work prior to installing the K- valve packer (which is now in Beluga, along with the K-valve) Thanks, Jake From: Jacob Flora Sent: Wednesday, January 5, 2022 11:05 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Perforate & K-valve installation update Hello Bryan, I wanted to provide a status update of where we are in the process of installing the k-valve. Per the approved sundry we added multiple Beluga perforations to improved the flowrate prior to installing the k- valve. This has improved the flow, however during the perforating we saw mud on the guns and have reason to believe it’s the bottom set of perforations that need to be plugged over. My next steps down this path: 1. Mobe slickline, drift/bail to ensure a plug can be set 2. Set plug with e-line 3. Flow well 4. Set Baker packer w tailpipe (it’s being shipped down from the slope this week, will be flown over and assembled in Beluga as it all has to fit in the Otter) 5. Set k-valve/x-lock with slickline & test same We are getting there, however I believe this will run into and past the 1/13/22 deadline per Sundry 321-622. Can I request an extension now or would it be better to request one closer to the deadline? I anticipate needing till the end of the month to get all these steps done. Below is a picture of the mud we saw on the recent perforating. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, December 16, 2021 8:53 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] RE: Perforation Change: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Jake, You have approval to re-perf the requested intervals in your email below. Since you are not opening up any new pools with these perfs, we will approve via this email. No need for an additional Sundry. Please include this email with your 10-404. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 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: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Thursday, December 16, 2021 8:42 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Perforation Change: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Hi Bryan, Our geologist made a slight change to the planned perforations- we now want to re-perf the existing Beluga H2-H5 perfs (highlighted below) before moving uphole to the approved new perf intervals (Beluga D-H1). Can we add this to the existing Sundry? Thanks, Jake Sand Name MD Top MD Bot MD Tot TVD Top TVD Bot Beluga H2 6370 6382 12 5158 5170 Beluga H4 6447 6459 12 5231 5243 Beluga H5 6512 6518 6 5299 5305 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 2/15/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) GPT 01/26/2022 Please include current contact information if different from above. 37' (6HW Received By: 02/15/2022 By Abby Bell at 11:42 am, Feb 15, 2022 CAUTION: This email originated from outside the State of Alaska mail system. Do notclick links or open attachments unless you recognize the sender and know the contentis safe.From:Jacob FloraTo:McLellan, Bryan J (OGC)Subject:BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Extension RequestDate:Friday, January 28, 2022 12:02:08 PMAttachments:BRU 212-26 Schematic 2022-01-24.pdfBryan, Hilcorp respectfully requests a timeline extension of one month (from 1/31/22 to 2/28/22) to install the required K-valve into the BRU 212-26 wellbore. Operations Update: 1/13/22 We logged a flowing PT survey and found the fluid level to be around 3600’ meaning we have significant amount of water in the wellbore 1/21/22 A CIBP was attempted to set over the suspected wet H5 perforations at 6512-20’. E-line was unable to get a CIBP down to the perforations. A dump bailer was able to get doen to the perfs and 15’ cement plug was dump bailed at 6473-88’. 1/24/21 The well was brought online and is currently being evaluated for water inflow. We anticipate logging a second flowing PT survey and potentially a second water shutoff attempt based on the data. A one month extension will allow us time to properly evaluate and perform the work prior to installing the K- valve packer (which is now in Beluga, along with the K-valve) Thanks, Jake From: Jacob Flora Sent: Wednesday, January 5, 2022 11:05 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Perforate & K-valve installation update Hello Bryan, I wanted to provide a status update of where we are in the process of installing the k-valve. Per the approved sundry we added multiple Beluga perforations to improved the flowrate prior to installing the k- valve. This has improved the flow, however during the perforating we saw mud on the guns and have reason to believe it’s the bottom set of perforations that need to be plugged over. My next steps down this path: Updated by JMF 12-21-21 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD Size Date Status Beluga G5 6,110’ 6,115’ 4,898’ 4,903’ 2-7/8” 12/20/21 Open Beluga G6 6,136’ 6,141’ 4,924’ 4,929’ 2-7/8” 12/20/21 Open Beluga G7 6,162’ 6,166’ 4,950’ 4,954’ 2-7/8” 12/20/21 Open Beluga G9 6,224’ 6,229’ 5,012’ 5,017’ 2-7/8” 12/20/21 Open Beluga H 6,283’ 6,289’ 5,071’ 5,077’ 2-7/8” 12/20/21 Open Beluga H 6,318’ 6,321’ 5,106’ 5,109’ 2-7/8” 12/20/21 Open Beluga H1 6,337’ 6,341’ 5,125’ 5,129’ 2-7/8” 12/20/21 Open Beluga H2 6,369' 6,391' 5,157' 5,179' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 2-7/8” 8/10/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 2-7/8” 8/4/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 3-3/8” 01/21/22 Isolated Beluga H7 6,560' 6,583' 5,348' 5,371' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 6 & 7 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,506’ 6.180” 7.400” Baker tieback Seal Assembly 3 6,545’ 5.500” CIBP set 10/21/20 4 6,633’ 5.500” MAP CIBP set on 10/18/20 5 7,500’ 5.500” CIBP set 09/28/20 6 ~250’ Baker KB Packer w tailpipe & X-nipple (~25’ OAL) 7 ~250’ K or PB valve beneath X-lock 8 6473-88’ 15’ Cement Plug dump bailed on 1-21-22 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 4 Bel H7 3 Bel H5 5 1 & 2 8 Muddy Fill @ 6,488’ MD 12/19/21 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/17/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 232-26 (PTD 184-138) Perforation Record 12/10/2021 Please include current contact information if different from above. Received By: 01/20/2022 37' (6HW By Abby Bell at 10:21 am, Jan 20, 2022 1 Guhl, Meredith D (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, January 5, 2022 11:12 AM To:Jacob Flora Subject:RE: BRU 212-26 (PTD: 220-058) (Sundry: 321-622) Perforate & K-valve installation update Jake, I will extend the deadline for setting the K‐valve and the AOGCC witnessed SSSV performance test until 1/31/22, to allow time to source and install the plug. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, January 5, 2022 11:05 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 212‐26 (PTD: 220‐058) (Sundry: 321‐622) Perforate & K‐valve installation update Hello Bryan, I wanted to provide a status update of where we are in the process of installing the k‐valve. Per the approved sundry we added multiple Beluga perforations to improved the flowrate prior to installing the k‐valve. This has improved the flow, however during the perforating we saw mud on the guns and have reason to believe it’s the bottom set of perforations that need to be plugged over. My next steps down this path: 1. Mobe slickline, drift/bail to ensure a plug can be set 2. Set plug with e‐line 3. Flow well 4. Set Baker packer w tailpipe (it’s being shipped down from the slope this week, will be flown over and assembled in Beluga as it all has to fit in the Otter) 5. Set k‐valve/x‐lock with slickline & test same We are getting there, however I believe this will run into and past the 1/13/22 deadline per Sundry 321‐622. Can I request an extension now or would it be better to request one closer to the deadline? I anticipate needing till the end of the month to get all these steps done. Below is a picture of the mud we saw on the recent perforating. Thanks, Jake CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, December 16, 2021 8:53 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] RE: Perforation Change: BRU 212‐26 (PTD: 220‐058) (Sundry: 321‐622) Jake, You have approval to re‐perf the requested intervals in your email below. Since you are not opening up any new pools with these perfs, we will approve via this email. No need for an additional Sundry. Please include this email with your 10‐404. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Thursday, December 16, 2021 8:42 AM 3 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Perforation Change: BRU 212‐26 (PTD: 220‐058) (Sundry: 321‐622) Hi Bryan, Our geologist made a slight change to the planned perforations‐ we now want to re‐perf the existing Beluga H2‐H5 perfs (highlighted below) before moving uphole to the approved new perf intervals (Beluga D‐H1). Can we add this to the existing Sundry? Thanks, Jake Sand Name MD Top MD Bot MD Tot TVD Top TVD Bot Beluga H2 6370 6382 12 5158 5170 Beluga H4 6447 6459 12 5231 5243 Beluga H5 6512 6518 6 5299 5305 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. 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If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. 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ĞůƵŐĂ:Ϯϳ͕ϳϬϮΖϳ͕ϳϭϰΖϲ͕ϰϵϬΖϲ͕ϱϬϮΖϭϮΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:ϯϳ͕ϴϯϬΖϳ͕ϴϰϭΖϲ͕ϱϭϴΖϲ͕ϱϮϵΖϭϭΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:ϰϳ͕ϴϱϮΖϳ͕ϴϲϯΖϲ͕ϲϰϬΖϲ͕ϱϱϭΖϭϭΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ Ğů,ϭϱ Ğů/ Ğů: &ŝůů ŶĐŽƵŶƚĞƌĞĚ Λϲ͕ϱϳϬ͛D ϭϬͬϭϴͬϮϬ ;DŝĚĚůĞŽĨ,ϳ WĞƌĨƐͿ ϰ Ğů,ϳ ϯ Ğů,ϱ ϱ KW E,K> ͬ D Ed d/> ϵͲϱͬϴΗϭϴϵ͘ϱďďůƐŽĨϭϮ͘ϬƉƉŐůĞĂĚͬϰϳ͘ϴďďůƐŽĨϭϱ͘ϴƉƉŐƚĂŝůͬdKΛƐƵƌĨĂĐĞ;ϲϱ͘ϱďďůƐŽĨ ĐĞŵĞŶƚƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞͿ ϱͲϭͬϮ͟ϮϳϳďďůƐŽĨϭϮ͘ϬƉƉŐůĞĂĚͬϯϬ͘ϵďďůƐŽĨϭϱ͘ϴƉƉŐƚĂŝůͬdKΛϯ͕ϰϬϬ͛;>ĚĂƚĞĚϵͲϰͲ ϮϬϮϬͿ Ğů,Ϯ Ğů,ϯ Ğů,ϰ Updated by JMF 12-07-21 PROPOSED Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Beluga D-H1 ~4,874 ~6,352 ~3,575 ~5,047 TBD TBD TBD Planned Beluga H2 6,369' 6,391' 5,157' 5,179' 22' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 9’ 2-7/8” 8/10/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 10’ 2-7/8” 8/4/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 8' 3-3/8” 09/29/20 Open Beluga H7 6,560' 6,583' 5,348' 5,371' 23' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 20' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 13' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 12' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 11' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 11' 2-7/8” 09/24/20 Isolated OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” TOC @ 3,400’ (CBL dated 9-4-2020) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ TUBING DETAIL 5-1/2" Tubing 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 6 & 7 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,506’ 6.180” 7.400” Baker tieback Seal Assembly 3 6,545’ 5.500” CIBP set 10/21/20 4 6,633’ 5.500” MAP CIBP set on 10/18/20 5 7,500’ 5.500” CIBP set 09/28/20 6 ~250’ Baker KB Packer w tailpipe & X-nipple (~25’ OAL) 7 ~250’ K or PB valve beneath X-lock 8-1/2” hole Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 4 Bel H7 3 Bel H5 5 Bel H2 Bel H3 Bel H4 BEL D to H1 (PROPOSED) 1 & 2 hƉĚĂƚĞĚďLJ:D&ϭϮͲϬϳͲϮϭ WZKWK^ ĞůƵŐĂZŝǀĞƌhŶŝƚ ZhϮϭϮͲϮϲ Wd͗ϮϮϬͲϬϱϴ W/͗ϱϬͲϮϴϯͲϮϬϭϴϮͲϬϬͲϬϬ Wdсϲ͕ϱϰϱ͛Dͬdsсϱ͕ϯϯϯ͛ dсϴ͕ϬϬϭ͛Dͬdsсϲ͕ϳϴϵ͛ Z<ƚŽ'>сϭϴ͛ W Z&KZd/KE d/> ^ĂŶĚ dKWD dD D dKW ds dD ds&d ^ŝnjĞ ĂƚĞ ^ƚĂƚƵƐ ĞůƵŐĂͲ,ϭΕϰ͕ϴϳϰΕϲ͕ϯϱϮΕϯ͕ϱϳϱΕϱ͕ϬϰϳdddWůĂŶŶĞĚ ĞůƵŐĂ,Ϯϲ͕ϯϲϵΖϲ͕ϯϵϭΖϱ͕ϭϱϳΖϱ͕ϭϳϵΖϮϮΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬKƉĞŶ ĞůƵŐĂ,ϯϲ͕ϰϮϬ͛ϲ͕ϰϮϵ͛ϱ͕ϮϬϴ͛ϱ͕Ϯϭϳ͛ϵ͛ϮͲϳͬϴ͟ϴͬϭϬͬϮϭKƉĞŶ ĞůƵŐĂ,ϰϲ͕ϰϱϬ͛ϲ͕ϰϲϬ͛ϱ͕Ϯϯϯ͛ϱ͕Ϯϰϯ͛ϭϬ͛ϮͲϳͬϴ͟ϴͬϰͬϮϭKƉĞŶ ĞůƵŐĂ,ϱϲ͕ϱϭϮΖϲ͕ϱϮϬΖϱ͕ϯϬϬΖϱ͕ϯϬϴΖϴΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬKƉĞŶ ĞůƵŐĂ,ϳϲ͕ϱϲϬΖϲ͕ϱϴϯΖϱ͕ϯϰϴΖϱ͕ϯϳϭΖϮϯΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ,ϭϱϲ͕ϵϯϮΖϲ͕ϵϱϮΖϱ͕ϳϮϬΖϱ͕ϳϰϬΖϮϬΖϯͲϯͬϴ͟ϬϵͬϮϵͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ/ϭϮϳ͕ϱϯϲΖϳ͕ϱϰϵΖϲ͕ϯϮϰΖϲ͕ϯϯϳΖϭϯΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:Ϯϳ͕ϳϬϮΖϳ͕ϳϭϰΖϲ͕ϰϵϬΖϲ͕ϱϬϮΖϭϮΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:ϯϳ͕ϴϯϬΖϳ͕ϴϰϭΖϲ͕ϱϭϴΖϲ͕ϱϮϵΖϭϭΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ ĞůƵŐĂ:ϰϳ͕ϴϱϮΖϳ͕ϴϲϯΖϲ͕ϲϰϬΖϲ͕ϱϱϭΖϭϭΖϮͲϳͬϴ͟ϬϵͬϮϰͬϮϬ/ƐŽůĂƚĞĚ KW E,K> ͬ D Ed d/> ϵͲϱͬϴΗϭϴϵ͘ϱďďůƐŽĨϭϮ͘ϬƉƉŐůĞĂĚͬϰϳ͘ϴďďůƐŽĨϭϱ͘ϴƉƉŐƚĂŝůͬdKΛƐƵƌĨĂĐĞ;ϲϱ͘ϱďďůƐŽĨ ĐĞŵĞŶƚƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞͿ ϱͲϭͬϮ͟ϮϳϳďďůƐŽĨϭϮ͘ϬƉƉŐůĞĂĚͬϯϬ͘ϵďďůƐŽĨϭϱ͘ϴƉƉŐƚĂŝůͬdKΛϯ͕ϰϬϬ͛;>ĚĂƚĞĚϵͲϰͲ ϮϬϮϬͿ ^/E' d/> ^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶƚŽ^Ğƚ ĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϯϴΖ ϵͲϱͬϴΗ^ƵƌĨƐŐϰϳ>ͲϴϬdϴ͘ϲϴϭ͟^ƵƌĨϮ͕ϳϯϭ͛ ϱͲϭͬϮΗWƌŽĚ>ŶƌϭϳWͲϭϭϬ/zdyWdϰ͘ϴϵϮ͟Ϯ͕ϰϵϱ͛ϴ͕ϬϬϭ͛ dh/E' d/> ϱͲϭͬϮΗdƵďŝŶŐϭϳWͲϭϭϬ/zdyWdϰ͘ϴϵϮ͟^ƵƌĨϮ͕ϱϬϲ͛ ϲΘϳ ϭϲ͟ ϵͲϱͬϴ͟ ϭϮͲϭͬϰ͟ ŚŽůĞ ϱͲϭͬϮ͟ : t >Zz d/> EŽ͘ ĞƉƚŚ / K /ƚĞŵ ϭϮ͕ϰϵϱ͛ϲ͘ϭϳϬ͟ϴ͘ϰϯϬ͟ĂŬĞƌyW>ŝŶĞƌdŽƉWĂĐŬĞƌ&ůĞdžͲ>ŽĐŬsůŝŶĞƌŚĂŶŐĞƌ ϮϮ͕ϱϬϲ͛ϲ͘ϭϴϬ͟ϳ͘ϰϬϬ͟ĂŬĞƌƚŝĞďĂĐŬ^ĞĂůƐƐĞŵďůLJ ϯϲ͕ϱϰϱ͛ϱ͘ϱϬϬ͟/WƐĞƚϭϬͬϮϭͬϮϬ ϰϲ͕ϲϯϯ͛ϱ͘ϱϬϬ͟DW/WƐĞƚŽŶϭϬͬϭϴͬϮϬ ϱϳ͕ϱϬϬ͛ϱ͘ϱϬϬ͟/WƐĞƚϬϵͬϮϴͬϮϬ ϲΕϮϱϬ͛ĂŬĞƌ<WĂĐŬĞƌǁƚĂŝůƉŝƉĞΘyͲŶŝƉƉůĞ;ΕϮϱ͛K>Ϳ ϳΕϮϱϬ͛<ͲǀĂůǀĞďĞŶĞĂƚŚyͲůŽĐŬ ϴͲϭͬϮ͟ ŚŽůĞ Ğů,ϭϱ Ğů/ Ğů: &ŝůů ŶĐŽƵŶƚĞƌĞĚ Λϲ͕ϱϳϬ͛D ϭϬͬϭϴͬϮϬ ;DŝĚĚůĞŽĨ,ϳ WĞƌĨƐͿ ϰ Ğů,ϳ ϯ Ğů,ϱ ϱ Ğů,Ϯ Ğů,ϯ Ğů,ϰ >ƚŽ,ϭ ;WZKWK^ Ϳ ϭΘϮ 6XSHUVHGHG 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Gravel Pack Development Exploratory 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: 6,545; Total Depth measured 8,001 feet 6,633; 7,500 feet true vertical 6,789 feet N/A feet Effective Depth measured 6,545 feet 2,495 feet true vertical 5,333 feet 1,913 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Liner Top Pkr; N/A 2,495' MD 1,913' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 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: Taylor Wellman 777-8449 Contact Name:Jake Flora Authorized Title:Operations Manager Contact Email: Contact Phone:777-8442 WINJ WAG 1,639 Water-Bbl MD 138' 2,731' 8,001' 0 Oil-Bbl measured true vertical Packer 5-1/2" 5-1/2" 2,495'1,913' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beluga River Unit - Beluga River Undefined GasN/A measured TVD Tubing Pressure 3190 Beluga River Unit (BRU) 212-26 N/A FEDA029657 Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-058 50-283-20182-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-369 400 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 25 Authorized Signature with date: Authorized Name: 30 Casing Pressure Liner 5,506' 3,648 6,789' 0 Representative Daily Average Production or Injection Data 138' 2,731' 2,495' Conductor Surface Intermediate Production 8,730psi 8,730psi Casing Structural 16" 9-5/8" Length 5,750psi Collapse 1,410psi 3,090psi jake.flora@hilcorp.com Senior Engineer:Senior Res. Engineer: 10,600psi Burst 2,980psi 10,600psi 138' 2,050' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 8:48 am, Sep 03, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.02 16:09:39 -08'00' Taylor Wellman (2143) SFD 9/7/2021DSR-9/3/21BJM 10/26/21 RBDMS HEW 9/3/2021 Rig Start Date End Date 7/29/21 8/10/21 07/29/2021 - Thursday Arrive at PWL, gather tools, depart for airport. Flight departing to Beluga. Arrive in Beluga, talk with company rep. Sign permits. Grab equipment, move to well 212-26. 9:45 hr - Rig up on well. PT 1,500 PSI - Good. 13:20 hr - RIH with 2.5" X 7' DD Bailer to 2,548' KB, spang down several times, fall through to 6,548' kb, (top of plug), POOH. Ooh tools are covered in thick mud. Empty. 15:05 hr - RIH with 3" x 6' DD Bailer to 6,548' KB, pooh. Ooh tools covered in mud. Rig down off well. Move equipment to next well. 07/30/2021- Friday 08/04/2021 - Wednesday JSA/Rig up e line. Rehead line to 4/2. Pick up top sheave and find high stranded wire. Cut 110' of wire tie on new head 4/2. Make up 10' 2-7/8" gun. PT pump empty wait to be filled. Wait on new PT pump to be brought to location. RIH with 10' 2-7/8" gun. Correlation gun 1 pass 14, depth 6,400'. Send correlation pass to town, depth 5,800'. Shoot gun 1 pass 17 6,450.5'-6,460.5'. POOH. Surface lay down tool rig down. Leave location park equipment on D pad. 08/03/2021 - Tuesday 0530 hr - Safety Meeting, Permit, drive to pad. Rig up slickline, PT. 0720 hr - RIH with 3" x 6' DD Bailer to 2,550' KB, W/T, POOH, full light mud. Standby for change out. 0915 hr - Add 3 1/2 roller bogies. RIH with 3" x 6' DD Bailer to 6,540' KB. Pick up weight is 1300 #, can't see spangs. POOH, bottom is packed off with thick mud, rest is light mud. 10:45 hr- RIH with same to 6,550' KB W/T, POOH, full solids with the consistency of grease. Most of it blew out into the lubricator from the differential pressure. 12:15 hr - RIH with same to 6,530'KB W/T, POOH, Full same. 1315 hr - Rig down and moved to C Pad. 07/31/2021 - Saturday MIRU coiled tubing with Nitrogen. Spot tanks. Slickline tagged CIBP at 6,548'. Coil FCO with N2 cancelled. RDMO. 08/02/2021 - Monday Move on well from 232-26. PT 1,500 PSI - Good. RIH with 3" x 5' DD bailer to 100' KB, have to hand spang down to 120' KB, fall through to 2,546' KB, w/t 2,551' KB pooh. Ooh w/1" of mud, bailer full of water. 16:15 hr - RIH with 2.5 x 7' DD Bailer to 2,546' KB w/t 2,548' KB, pooh, ooh empty. 17:40 hr - RIH with KJ w/3" x 5' DD Bailer to 2,548' KB, w/t 2,549' KB, pooh, ooh w/1/2" of mud on top of flapper. Rig down. Performed JSA/Rehead/Rig up E-line. Crane wire backspool fix wire. and wait for manlift. RIH with 18' 2-7/8th" gun. made it to 3,800' correlate to bond log depth. looks good continue in hole. 6,450' depth started log to correlate pulling 1,100# overpull related to mud and deviation. 6,300' unable to get log Gamma ray stopped working. troubleshooting gamma ray and was unable to fix POOH. at surface lay down tool and secure well, surface check gamma ray tool works, unable to find problem. Lay down equipment for the night. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 Shoot gun 1 pass 17 6,450.5'-6,460.5'. Rig Start Date End Date 7/29/21 8/10/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-26 50-283-20182-00-00 220-058 08/10/2021 - Tuesday Covid Test. Travel to Beluga. Arrive at Beluga, Sign in, JSA. Inspect Trucks and equipment. Travel to well site, spot trucks. 09:45 Rig up. MU 9' 2-7/8" GEO Razor gun w/GR-CCL, PT 250/2,500 PSI. 10:50 RIH to 6,478' and log Correlation pass to 5,800'. Send correlation log to Geologist in Anchorage for confirmation. Place gun on depth 6,420'-6,429', CCL depth 6,412.2'. 13:45 - Fire gun with well flowing and 425 psi on tubing. 13:50 POOH. 14:25 - Surface all shots fired. 14:30 - Rig down. Place gun on depth 6,420'-6,429', CCL depth 6,412.2'. 13:45 - Fire gun with well flowing and 425 psi on tubing. Updated by JMF 08-17-21 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,545’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ TUBING DETAIL - NA 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,506’ 6.180” 7.400” Baker tieback Seal Assembly 3 6,545’ 5.500” CIBP set 10/21/20 4 6,633’ 5.500” MAP CIBP set on 10/18/20 5 7,500’ 5.500” CIBP set 09/28/20 8-1/2” hole PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Beluga H2 6,369' 6,391' 5,157' 5,179' 22' 3-3/8” 09/29/20 Open Beluga H3 6,420’ 6,429’ 5,208’ 5,217’ 9’ 2-7/8” 8/10/21 Open Beluga H4 6,450’ 6,460’ 5,233’ 5,243’ 10’ 2-7/8” 8/4/21 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 8' 3-3/8” 09/29/20 Open Beluga H7 6,560' 6,583' 5,348' 5,371' 23' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 20' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 13' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 12' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 11' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 11' 2-7/8” 09/24/20 Isolated Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 4 Bel H7 3 Bel H5 5 OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 277 bbls of 12.0 ppg lead / 30.9 bbls of 15.8 ppg tail / TOC @ 3,400’ (CBL dated 9-4- 2020) Bel H2 Bel H3 Bel H4 Beluga H2 6,369 6,391 5,157 5,179 22 33/8 09/29/20 Open Beluga H3 6,420’6,429’5,208’5,217’9’2-7/8”8/10/21 Open Beluga H4 6,450’6,460’5,233’5,243’10’2-7/8”8/4/21 Open Beluga H2 6,369 6,391 5,157 5,179 22 33/8 09/29/20 Open David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: BRU 212-26 Perf (PTD 220-058) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/30/2021 By Abby Bell at 12:34 pm, Aug 26, 2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/25/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: BRU 212-26 Perf (PTD 220-058) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/30/2021 By Abby Bell at 9:08 am, Aug 26, 2021 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: Install Gravel Pack 2.Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:CO 786 0 Approved Spacing Exception 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,001'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production Tieback 8,730psi Production Liner 8,730psi 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng tkramer@hilcorp.com 6,789'7,902'6,690'~2,032 N/A ZXP Liner Top Pkr; N/A 2,495' MD/1,913'TVD; N/A; N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: 10,600psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-058 50-283-20182-00-00 Beluga River Unit (BRU) 212-26 Beluga River Unit - Beluga River Undefined Length Size State Wide Spacing Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,600psi MD 2,980psi 5,750psi 138' 2,050' 138' 2,731' 1,913'5-1/2" 16" 9-5/8" 138' 2,731' 2,495' Perforation Depth MD (ft): See Attached Schematic 2,495' 5-1/2" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: Aug. 04, 2021 8,001'5,506' N/A 6,789' m n P s 66 t k Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 8:20 am, Jul 26, 2021 321-369 Digitally signed by Jennifer Starck (4520) DN: cn=Jennifer Starck (4520), ou=Users Date: 2021.07.23 16:01:44 -08'00' Jennifer Starck (4520) DLB 07/26/2021 DSR-7/26/21 CO 786 applies. DLB X X BJM 7/28/21 10-404 CT CT BOP test to 4000 psi. dts 7/28/2021 JLC 7/28/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.28 15:20:10 -08'00' RBDMS HEW 7/30/2021 Well Prognosis Well: BRU 212-26 Date: 7-23-2021 Well Name: BRU 212-26 API Number: 50-283-20182-00 Current Status: Gas Producer Leg: N/A Estimated Start Date: Aug 4, 2021 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-058 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (907)-632-4113 (C) AFE Number: Maximum Expected BHP: ~ 2,258 psi @ 5,158’ TVD (Based on a .437 gradient.) Max. Potential Surface Pressure: ~ 2,032 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary BRU 212-26 is a gas well Drilled in 2020 and currently producing in Beluga H2 and H5 sands. These zones have recently begun producing sand. The purpose of this work/sundry is to add perforations in two sand intervals and place a gravel pack within producing zones. Note: A Coil tubing Cleanout may be required to clean excess fill out of the well prior to running the Gravel Pack. Safety Concerns x Ensure all crews are aware of stop work authority If Coil Clean out is needed: x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) Slick line Tag (Pre-Sundry Work x MIRU Slickline Unit x Pressure test Lubricator to 250 psi low, 3,000 psi high. x PU RIH W/ 4.60” GR to PBTD (6,545’). POOH. ( Note: Last Tag was at 6,626’ W/ 3.75” GR.) x RDMO Slickline. Coiled Tubing Procedure (Contingency) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 48 hrs. in advance of BOP test. 2. MU Jet nozzle. 3. RIH W/ nozzle. RU N2 pumping unit. 4. Come online with N2/ foam and C/O Well and blow well dry. 8.41 ppg EMW AOGCC notification not required if Schlumberger coil is used. Well Prognosis Well: BRU 212-26 Date: 7-23-2021 5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD (6,545’). 6. POOH w/ coil leaving 1,000 psi on well. LD BHA. 7. RDMO Coiled Tubing. E-line Perforating Procedure 8. POOH.PU RIH W/perf guns. Perforate each interval with Perf guns 6- 12 JSPF 60° phasing. 9. Proposed Perforated Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Comments Beluga H2 ±6,369’ ±6,391' 22’ ±5,065' ±5,087' Re-perf Beluga H3 ±6,420' ±6,429' 9' ±5,208' ±5,217' 12 JSPF Beluga H4 ±6,445' ±6,463' 18' ±5,233' ±5,251 12 JSPF Beluga H5 ±6,512' ±6,520' 8’ ±5,140' ±5,158' Re-perf a. Proposed perfs. also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. f. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. g. Sand intervals are governed by State Wide Spacing rules. 10. POOH and lay down perf guns. E-line Gravel Pack Procedure - (This portion will be working with both E-line and SL – all lubricators will be pressure tested to 3,000 psi) 11. PU RIH W/ 5-1/2” CIBP to 6,525’ (+/-) and set same. 12. PU RIH W/ 4.60” GR to 6,525’. Note any tight spots or fill encountered. POOH 13. PU and RIH on E-line W/ Paragon Packer assembly #1 (Sump Packer) and log on depth to set bottom of assembly @ 6,525’, Top to be 6,518.9’(+/-) and set same. POOH. BHA #1 All BHA's must be lubricated per 20 AAC 25.287 - bjm Well Prognosis Well: BRU 212-26 Date: 7-23-2021 14. PU and RIH W/ Screen assembly ( BHA #2) and latch into Sump Packer spacing out to straddle H5 perforations F/ 6,512 to 6,520’. BHA #2 15. Latch screen assembly into Sump packer and release from Screen assembly. POOH. 16. PU Dump Bailer and RIH to top of Screen Assembly #1 and dump bail sand to cover perforations. POOH W/ Bailer. (Estimated 2 bailer Runs) 17. PU RIH W/ SL. RIH W/ Wash over tool and then JDC Pulling tool. Latch fishing neck on removable vent plug. Jar up 1,600 lbs. to release vent plug. POOH W/ same. (2 runs) 18. On E-line, PU RIH W/ the Vent Screen isolation packer assembly (BHA #3). Well Prognosis Well: BRU 212-26 Date: 7-23-2021 19. Latch BHA #3 into vent screen. Set isolation packer. POOH. 20. PU BHA #4. Consisting of a seal bore receptacle and Delta Screen. 21. Sting into paragon Packer # 2. Fire charge to release from screen. POOH. 22. PU BHA #5. Consisting of some blank pipe and more delta screen: 64.96 ft bjm Well Prognosis Well: BRU 212-26 Date: 7-23-2021 23. Sting into the top of BHA # 4 and latch. Fire charge to release. POOH. 24. PU BHA #6 Consisting of Latch Seal Assembly, blank pipe and a Polish seal bore. 25. Run in hole and latch into BHA # 5. Release off, and POOH. 26. PU BHA #7. RIH W/ Latch seal assembly, blank pipe, and the Removable Vent Plug Assembly: 27. RIH And Latch into BHA #6. Release off and POOH. 28. PU Dump bailer. RIH dumping sand around the delta screen assembly. ( Estimated to be 5 runs W/ 3.50” X 30’ bailer) POOH. 29. RU SL. RIH W/ JDC Pulling tool. Latch fishing neck on removable vent plug. Jar up 1,600 lbs. to release vent plug. POOH W/ same. 30. PU RIH W/ BHA # 8 Consists of: 44.43 ft Well Prognosis Well: BRU 212-26 Date: 7-23-2021 31. RIH and latch into the vent of the previous assembly. Set top packer. POOH. (Note: Additional E-line and Slick line runs may need to be made to adjust the height of the sand prior to setting the top packer. 32. RD E-line. 33. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. TTS Proposed Gravel Pack Schematic 4. Coil Tubing BOP Schematic 5. Standard Well Procedure – N2 Operations Updated by TCS 1-5-21 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,645’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,506’ 6.180” 7.400” Baker tieback Seal Assembly 3 6,545’ 5.500” CIBP set 10/21/20 4 6,633’ 5.500” MAP CIBP set on 10/18/20 5 7,500’ 5.500” CIBP set 09/28/20 8-1/2” hole PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Beluga H2 6,369' 6,391' 5,157' 5,179' 22' 3-3/8” 09/29/20 Open Beluga H5 6,512' 6,520' 5,300' 5,308' 8' 3-3/8” 09/29/20 Open Beluga H7 6,560' 6,583' 5,348' 5,371' 23' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 20' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 13' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 12' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 11' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 11' 2-7/8” 09/24/20 Isolated Bel H Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 4 Bel H 3 Bel H 5 OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 277 bbls of 12.0 ppg lead / 30.9 bbls of 15.8 ppg tail / TOC @ 3,400’ (CBL dated 9-4- 2020) Updated by DMA 07-19-21 PROPOSED SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 6,645’ MD / TVD = 5,333’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,731’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,506’ TUBING DETAIL 2-7/8” Tubing w/Screen 3.5 L-80 10RD IJ 1.751” ±6,324’ ±6,525’ 1 & 2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,506’ 6.180” 7.400” Baker tieback Seal Assembly 3 ±6,323’ 2.812” 4.531” 5-1/2” Paragon II Packer 4 ±6,467’ 2.812” 4.531” 5-1/2” Paragon II Packer 5 ±6,519’ 5-1/2” Paragon II Packer 6 6,545’ 5.500” CIBP set 10/21/20 7 6,633’ 5.500” MAP CIBP set on 10/18/20 8 7,500’ 5.500” CIBP set 09/28/20 8-1/2” hole PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Beluga H2 6,369' 6,391' 5,157' 5,179' 22' 3-3/8” 09/29/20 Open Beluga H3 ±6,420’ ±6,429’ ±5,208’ ±5,217’ ±9’ Proposed TBD Beluga H4 ±6,445’ ±6,463’ ±5,233’ ±5,251’ ±18’ Proposed TBD Beluga H5 6,512' 6,520' 5,300' 5,308' 8' 3-3/8” 09/29/20 Open Beluga H7 6,560' 6,583' 5,348' 5,371' 23' 3-3/8” 09/29/20 Isolated Beluga H15 6,932' 6,952' 5,720' 5,740' 20' 3-3/8” 09/29/20 Isolated Beluga I12 7,536' 7,549' 6,324' 6,337' 13' 2-7/8” 09/24/20 Isolated Beluga J2 7,702' 7,714' 6,490' 6,502' 12' 2-7/8” 09/24/20 Isolated Beluga J3 7,830' 7,841' 6,518' 6,529' 11' 2-7/8” 09/24/20 Isolated Beluga J4 7,852' 7,863' 6,640' 6,551' 11' 2-7/8” 09/24/20 Isolated Bel H15 Bel I Bel J Fill Encountered @ 6,570’ MD 10/18/20 (Middle of H7 Perfs) 7 Bel H7 6 Bel H5 8 OPEN HOLE / CEMENT DETAIL 9-5/8" 189.5 bbls of 12.0 ppg lead / 47.8 bbls of 15.8 ppg tail / TOC @ surface (65.5 bbls of cement returns to surface) 5-1/2” 277 bbls of 12.0 ppg lead / 30.9 bbls of 15.8 ppg tail / TOC @ 3,400’ (CBL dated 9-4- 2020) 3 4 5 Bel H2 Bel H3 Bel H4 TITLE: SERVICE DISTRICT: SERVICE SPECIALIST: OPERATOR: CELL #: 1 COMPANY REP: PHONE #: 2 FIELD: WELL #: 3 STATE: LEASE: SERVICE CO.: Minimum ID 6,369’ to 6,391’ 6,420’ to 6,429’ 6,445’ to 6,512’ to 6,520’ to to ACCT. REP: PHONE #: COMP. FLUID: INHIBITOR: COATING: 504-481-8567 #N/A 4 DATE SUBMITTED: QUOTE#: SCREEN SIZE: SAND SIZE: JOB #: 5 PREPARED BY: PHONE #: BHP (psi):BHT (°F):MAX. DEV.: ZONE DEV.: 6 7 No. DEPTH-FT. LENGTH-FT. O.D. I.D. 8 1 6,323.46’ 5.60’ 4.531” 2.812” 9 2 6,329.06’ 0.50’ 4.500” 2.441” 10 3 6,329.56’ 4.98’ 4.300” 2.440” 11 12 4 6,332.54’ 2.52’ 3.500” 2.440” 5 6,335.06’ 27.00’ 2.875” 2.441” 13 6 6,362.06’ 1.59’ 4.470” 2.440” 7 6,330.06’ 2.00’ 4.470” 2.440” 14 8 6,332.06’ 30.00’ 3.760” 2.441” 15 9 6,362.06’ 2.00’ 4.470” 2.440” 10 6,362.32’ 2.00’ 4.470” 2.440” 16 11 6,416.58’ 0.53’ 3.670” 2.313” 12 6,364.32’ 30.00’ 3.760” 2.441” 17 13 6,394.32’ 20.00’ 2.875” 2.441” 18 14 6,414.32’ 2.00’ 4.470” 2.440” 19 15 6,414.58’ 2.00’ 4.470” 2.440” 20 16 6,417.11’ 50.00’ 3.760” 2.441” 17 6,467.11’ 2.00’ 4.470” 2.440” 21 18 6,467.37’ 5.60’ 4.531” 2.812” 22 19 6,472.97’ 0.50’ 4.500” 2.441” 20 6,473.47’ 4.98’ 4.300” 2.440” 23 21 6,476.45’ 2.52’ 3.500” 2.440” 22 6,478.97’ 30.00’ 2.875” 2.441” 24 23 6,508.97’ 0.53’ 3.670” 2.313” 25 24 6,509.50’ 15.00’ 3.760” 2.441” 26 25 6,518.64’ 2.00’ 4.470” 2.440” 26 6,518.90’ 5.60’ 4.531” 2.812” 27 27 6,524.50’ 0.50’ 3.760” 2.820” 6,525.00’ 5-1/2” 17-23# Polished Seal Bore Receptacle 3.500” Seal Bore x 2-7/8” NU 10Rd Box 2-7/8” NU 10RD Blank Pipe w/ 3.500” O.D. Couplings 5-1/2” 17-23# Latch Seal Assembly 2-7/8” NU 10RD Box x 3.500” Seal Bore (18,000#) 2-7/8” NU 10RD Delta Elite Screen (2 Jts.) 125 3.760” O.D. x 2.441” I.D. 15.6lbs/ft 15.00ft Long w/ 4.470” O.D. Weld-on Centralizers (Pin End and Middle) 5-1/2” 17-23# Latch Seal Assembly 2-7/8” NU 10RD Box x 3.500” Seal Bore (18,000#) N/AN/A 57.93° DESCRIPTION 6,369’ - 6,391’6,420’ - 6,429’6,445’ - 6,463’6,512’ - 6,520’ Beluga H2, H3, H4, & H5 Lee Coulon III 5-1/2” 17-23# Latch Seal Assembly 2-7/8” NU 10RD Box x 3.500” Seal Bore (18,000#) 5-1/2” 17-23# Polished Seal Bore Receptacle 3.500” Seal Bore x 2-7/8” NU 10Rd Box PBTD 5-1/2” 17-23# Polished Seal Bore Receptacle 3.500” Seal Bore x 2-7/8” NU 10Rd Box 2-7/8” NU 10 RD Blank Pipe w/ 3.500" O.D. Couplings 5-1/2” Latching Production Overshot 3.500” O.D. x 2.822” I.D. 2-7/8" NU Box 5-1/2” & 17-23# Removable Vent Plug Assembly Non- Latching; includes Polished nipple w/ 4.420” OD centralizer, 18” 8 gauge Vent screen and 2.313” Removable Vent Screen (1,600#) 2-7/8” NU 10RD Delta Elite Screen (2 Jts.) 125 3.760” O.D. x 2.441” I.D. 15.6lbs/ft 15.00ft Long w/ 4.470” O.D. Weld-on Centralizers (Pin End and Middle) 5 1/2CASING LINER 17 17 BTCP-110 BTC 985-867-8420 0.45°337-606-0031 BRU 212-26 BRU Hilcorp Ted Kramer Beluga River Unit 4.892” Alaska 907-777-8420 TUBING Beluga H2, H3, H4, & H5 Robbie Picou New Iberia THREADSIZE WEIGHT GRADE 7/15/2021 062121-01LC Rev.3 P-110 125 5 1/2 N/A 6,463’ 5-1/2” 17-23# Paragon II Packer 4.531” O.D. x 2.812” I.D. Seal Bore (HNBR Element - V3 - 5k psi 300°F) 5-1/2” 17.0-23.0# Hangoff Crossover for Paragon II Packers 2-7/8” NU 10RD Pin 5-1/2” Latching Production Overshot 3.500” O.D. x 2.822” I.D. 2-7/8" NU Box 5-1/2” & 17-23# Removable Vent Plug Assembly Non- Latching; includes Polished nipple w/ 4.420” OD centralizer, 18” 8 gauge Vent screen and 2.313” Removable Vent Screen (1,600#) 2-7/8” NU 10 RD Blank Pipe w/ 3.500” O.D. Couplings 2-7/8” NU 10Rd Re-Entry Guide 2-7/8” NU 10 RD X-Nipple w/ Check Valve Mandrel 5-1/2” 17-23# Latch Seal Assembly 2-7/8” NU 10RD Box x 3.500” Seal Bore (18,000#) 5-1/2" 17-23# Paragon II Packer 4.531" O.D. x 2.812" I.D. Seal Bore (HNBR Element - V3 - 5k psi 300°F) 5-1/2" 17.0-23.0# Hangoff Crossover for Paragon II Packers 2-7/8” NU 10RD Pin 5-1/2” 17-23# Latch Seal Assembly 2-7/8” NU 10RD Box x 3.500” Seal Bore (18,000#) 5-1/2” 17-23# Paragon II Packer 4.531” O.D. x 2.812” I.D. Seal Bore (HNBR Element - V3 - 5k psi 300°F) 2-7/8” NU 10 RD X-Nipple w/ Check Valve Mandrel 2-7/8” NU 10 RD Blank Pipe w/ 3.500" O.D. Couplings 2-7/8” NU 10RD Delta Elite Screen (1 Jt.) 125 3.760” O.D. x 2.441” I.D. 15.6lbs/ft 15.00ft Long w/ 4.470” O.D. Proposed Vent Screen w/ Packer Isolation 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. 1a. Test:Initial Annual Special 1b. Type Test:Stabilized Non Stabilized Multipoint Constant Time Isochronal Other: 2. Operator Name:5. Date Completed:11. Permit to Drill Number: 3. Address:6. Date TD Reached:12. API Number: 50- 4a. Location of Well (Governmental Section):7. KB Elevation above MSL (feet):13. W ell Name and Number: Surface: Top of Productive Horizon:8. Plug Back Depth(MD+TVD):14. Field/Pool(s): Total Depth:9. Total Depth (MD + TVD): 4b. Location of Well (State Base Plane Coordinates NAD 27):10.Land Use Permit:15. Property Designation: Surface:x-y-Zone- 4 TPI:x-y-Zone- 4 16. Type of Completion (Describe): Total Depth: x-y-Zone- 4 17. Casing Size Weight per foot, lb. I.D. in inches Set at ft.19.Perforations:From 18. Tubing Size Weight per foot, lb. I.D. in inches Set at ft. 20. Packer set at ft:21. GOR cf/bbl:22. API Liquid Hydrocardbons:23. Specific Gravity Flowing Fluid (G): 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure:24d. Barometric Pressure (Pa): Tubing Casing Fo psia @ Datum 5,139' TVDSS psia 25. Length of Flow Channel (L): Vertical Depth (H):% N2:% H2S: 0.22 0 1.X 2.X 3.X 4.X 5.X 1. 2. 3. 4. 5. 1. 2. 3. 4. 5. 7852-7863 Nodal________________ 283-20182-00-00 BRU 212-26 Beluga River Unit Critical Pressure Critical Temperature No. Pr Temperature T Tr No. Basic Coefficient (24-Hour) Fb or Fp hwPm Pressure psig Prover Line Size (in.) No. Choke Orifice Size (in.) X Rate of Flow Q1 Mcfd FLOW DATA Duration of Flow Hr. Pressure Pm Flow Temp. Factor Ft Gravity Factor Fg Super Comp. Factor Fpv Temp. Fo Pressure psig Temp. Fo Pressure psig 26. 0.555 0 6,789 2495' 96 816' FSL, 400' FWL, Sec 26, T13N, R10W, SM, AK 1658' FNL, 1217' FWL, Sec 26, T13N, R10W, SM, AK 1673' FNL, 1200' FWL, Sec 26, T13N, R10W, SM, AK 5-1/2" 17# 2625971318339 319202 319184 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT Hilcorp Alaska, LLC 9/24/2020 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 220-058 Beluga River Undefined Gas 5-1/2" Production String, Perforated A029657 CASING DATATUBING DATA 1501 Meter Run: Taps:Prover: 7,915' MD / 6,703' TVD 93.3' August 26, 2020 N/A 8,001' MD / 6,789' TVD 6369-6391 6512-6520 6560-6583 2628756 2628742 5-1/2"17# To 6932-6952 7536-7549 7702-7714 7830-7841 Diff. Hw Gg: % CO2: Temp. Fo for Flowing Fluid G z for Separator Gas Gg Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE SIDE Submit in DuplicateRBDMS HEW 4/30/2021 Pc Pc2 Pf Pf2 Pt2 Pc2-Pt2 Pw Pw2 Pc2-Pw2 Ps Ps2 Pf2-Ps2 AOF (Mcfd)n Remarks: I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Date AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= 1/Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless No.Pt 1. 2. 3. 4. 5. 25. 6,056 BRU 212-26 is flowing from the Beluga H2 & H5 gas sands (6,369' - 6,520' MD). The AOF was calculated w/ nodal software based on initial reservoir pressure data and initial flowing conditions. The matched data indicates a perm of 10 md and a skin of +/-3 likely from drilling/completion damage. The attached report from Prosper summarizes the matched IPR results. Trudi Hallett, Reservoir Engineer DEFINITIONS OF SYMBOLS Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells , Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 Digitally signed by Trudi Hallett (1231) DN: cn=Trudi Hallett (1231), ou=Users Date: 2021.04.27 10:20:21 -08'00' Trudi Hallett (1231) Page 1Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 212-26\BRU 212-26.Out ######################################## # INFLOW PERFORMANCE DATA (GAS WELL) # ######################################## Reservoir Model Jones M&G Skin Model Enter Skin By Hand Reservoir Pressure 1501.00 (psig) Reservoir Temperature 96.00 (deg F) Water-Gas Ratio 0 (STB/MMscf) Condensate Gas Ratio 0 (STB/MMscf) Absolute Open Flow (AOF) 6.056 (MMscf/day) Reservoir Permeability 10.00 (md) Reservoir Thickness 30.0 (feet) Drainage Area 60.0 (acres) Dietz Shape Factor 14.2678 Wellbore Radius 0.25 (feet) Perforation Interval 30.00 (feet) Calculated Non-Darcy Coefficent (Beta) 1466749440 Page 2Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 212-26\BRU 212-26.Out ++++++++++++++++++++++++++++++++++++++ + MECHANICAL/GEOMETRICAL SKIN DATA + ++++++++++++++++++++++++++++++++++++++ Skin 3 Page 3Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 212-26\BRU 212-26.Out +++++++++++++++++++++ + IPR - TEST DATA + +++++++++++++++++++++ Gas Pressure Date Comment Rate (FBHP) Status (MMscf/day) (psig) __________ _______ ___________ ________ ______ 10/05/2020 Page 4Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 212-26\BRU 212-26.Out +++++++++++++++++++++++++++++ + IPR Calculation Results + +++++++++++++++++++++++++++++ dP dP dP Sand Sand dP dP dP Total Total Completion Completion Control Control Perforation Damage Penetration Rate Pressure Temperature Skin Skin Skin Skin Skin Skin Skin Skin Skin (MMscf/day) (psig) (deg F) (psi) (psi) (psi) (psi) (psi) (psi) ___________ ________ ___________ ______ _____ __________ __________ _______ _______ ___________ ___ 1e-5 1501.00 96.00 0 3.00 0 3.00 0 0 0 0 0 0.31876 1463.23 95.16 10.47 3.00 0 3.00 0 0 0 0 0 0.63751 1424.22 94.28 21.36 3.00 0 3.00 0 0 0 0 0 0.95626 1383.88 93.35 32.72 3.00 0 3.00 0 0 0 0 0 1.275 1342.07 92.37 44.63 3.00 0 3.00 0 0 0 0 0 1.594 1298.65 91.34 57.16 3.00 0 3.00 0 0 0 0 0 1.913 1253.44 90.25 70.42 3.00 0 3.00 0 0 0 0 0 2.231 1206.25 89.09 84.53 3.00 0 3.00 0 0 0 0 0 2.550 1156.82 87.84 99.65 3.00 0 3.00 0 0 0 0 0 2.869 1104.85 86.50 115.98 3.00 0 3.00 0 0 0 0 0 3.188 1049.94 85.04 133.79 3.00 0 3.00 0 0 0 0 0 3.506 991.61 83.39 153.42 3.00 0 3.00 0 0 0 0 0 3.825 929.20 79.28 175.36 3.00 0 3.00 0 0 0 0 0 4.144 861.81 74.67 200.30 3.00 0 3.00 0 0 0 0 0 4.463 788.14 69.45 229.28 3.00 0 3.00 0 0 0 0 0 4.781 706.22 63.39 263.97 3.00 0 3.00 0 0 0 0 0 5.100 612.73 56.15 307.28 3.00 0 3.00 0 0 0 0 0 5.419 501.20 47.09 365.17 3.00 0 3.00 0 0 0 0 0 5.737 354.95 34.63 453.61 3.00 0 3.00 0 0 0 0 0 6.056 0 9.00 745.62 3.00 0 3.00 0 0 0 0 0 dP Non Deviation Perforation Damage Penetration Deviation Darcy Darcy Rate Skin Skin Skin Skin Skin Coefficient Coefficient (MMscf/day) (psi) (psi2/(Mscf/day)2) (psi2/(Mscf/day)) ___________ _________ ___________ ______ ___________ _________ __________________ _______________ 1e-5 0 0 0 0 0 0.0054676 253.386 0.31876 0 0 0 0 0 0.0054727 253.022 0.63751 0 0 0 0 0 0.0054785 252.632 0.95626 0 0 0 0 0 0.0054842 252.254 1.275 0 0 0 0 0 0.0054902 251.875 1.594 0 0 0 0 0 0.0054964 251.495 1.913 0 0 0 0 0 0.0055028 251.115 2.231 0 0 0 0 0 0.0055094 250.735 2.550 0 0 0 0 0 0.0055163 250.354 2.869 0 0 0 0 0 0.0055234 249.974 3.188 0 0 0 0 0 0.0055308 249.594 3.506 0 0 0 0 0 0.0055385 249.214 3.825 0 0 0 0 0 0.0055465 248.836 4.144 0 0 0 0 0 0.0055548 248.458 4.463 0 0 0 0 0 0.0055634 248.082 4.781 0 0 0 0 0 0.0055723 247.707 5.100 0 0 0 0 0 0.0055817 247.334 5.419 0 0 0 0 0 0.0055914 246.963 5.737 0 0 0 0 0 0.0056015 246.595 6.056 0 0 0 0 0 0.005612 246.229 Page 5Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 212-26\BRU 212-26.Out Total Skin : 3.00 ( = Entered + Perforation + Damage + Deviation + Partial Penet Completion Skin : 3.00 ( = Entered + Perforation + Damage + Sand Control ) Perforation Skin : 0 Damage Skin : 0 Penetration Skin : 0 Deviation Skin : 0 Sand Control Skin : 0 Calculated Non-Darcy Coefficent (Beta) : 1466749440 +++++++++++++++++++ + End of Report + +++++++++++++++++++ DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-283-20182-00-00Well Name/No. BELUGA RIV UNIT 212-26Completion Status1-GASCompletion Date9/24/2020Permit to Drill2200580Operator Hilcorp Alaska, LLCMD8001TVD6789Current Status1-GAS1/5/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:Mudlogs, MWD/LWD, CBL 9-4-20, GeoTapNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF9/10/20207915 2399 Electronic Data Set, Filename: BRU 212-26 CBL MAIN PASS 09-04-2020.LAS33818EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 CBL FINAL_09-04-2020.PDF33818EDDigital Data0 0 2200580 BELUGA RIV UNIT 212-26 LOG HEADERS33818LogLog Header Scans0 0 2200580 BELUGA RIV UNIT 212-26 LOG HEADERS33819LogLog Header ScansDF9/10/2020250 8120 Electronic Data Set, Filename: BRU 212-26.las33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Geolog AM Reports.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 EOW Report.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log MD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log MD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log TVD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log TVD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log MD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log MD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log TVD 2 in.pdf33819EDDigital DataTuesday, January 5, 2021AOGCCPage 1 of 6BRU 212-26.lasSupplied by OpSupplied by Op DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-283-20182-00-00Well Name/No. BELUGA RIV UNIT 212-26Completion Status1-GASCompletion Date9/24/2020Permit to Drill2200580Operator Hilcorp Alaska, LLCMD8001TVD6789Current Status1-GAS1/5/2021UICNoDF9/10/2020 Electronic File: BRU 212-26 Formation Log TVD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log MD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log MD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log TVD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log TVD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log MD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log MD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log TVD 2 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log TVD 5 in.pdf33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log MD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log MD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log TVD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Drilling Dynamics Log TVD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log MD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log MD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log TVD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Formation Log TVD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log MD 2 in.tif33819EDDigital DataTuesday, January 5, 2021AOGCCPage 2 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-283-20182-00-00Well Name/No. BELUGA RIV UNIT 212-26Completion Status1-GASCompletion Date9/24/2020Permit to Drill2200580Operator Hilcorp Alaska, LLCMD8001TVD6789Current Status1-GAS1/5/2021UICNoDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log MD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log TVD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Ratio Log TVD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log MD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log MD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log TVD 2 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 LWD Combo Log TVD 5 in.tif33819EDDigital DataDF9/10/2020 Electronic File: BRU212-26.dbf33819EDDigital DataDF9/10/2020 Electronic File: bru212-26.hdr33819EDDigital DataDF9/10/2020 Electronic File: BRU212-26.mdx33819EDDigital DataDF9/10/2020 Electronic File: bru212-26r.dbf33819EDDigital DataDF9/10/2020 Electronic File: bru212-26r.mdx33819EDDigital DataDF9/10/2020 Electronic File: BRU212-26_SCL.DBF33819EDDigital DataDF9/10/2020 Electronic File: BRU212-26_SCL.MDX33819EDDigital DataDF9/10/2020 Electronic File: BRU212-26_TVD.DBF33819EDDigital DataDF9/10/2020 Electronic File: BRU212-26_TVD.mdx33819EDDigital DataDF9/10/2020 Electronic File: BRU 212-26 Gas Show Reports.pdf33819EDDigital DataDF10/22/202072 8000 Electronic Data Set, Filename: BRU 212-26 LWD Final.las34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 Geo-Tap Pressure Tests.cgm34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final MD.cgm34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final TVD.cgm34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 Final Surveys.xlsx34125EDDigital DataTuesday, January 5, 2021AOGCCPage 3 of 6BRU 212-26 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-283-20182-00-00Well Name/No. BELUGA RIV UNIT 212-26Completion Status1-GASCompletion Date9/24/2020Permit to Drill2200580Operator Hilcorp Alaska, LLCMD8001TVD6789Current Status1-GAS1/5/2021UICNoDF10/22/2020 Electronic File: BRU 212-26_Defintive Survey Report.pdf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26_DSR.txt34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26_GIS.txt34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 Geo-Tap Pressure Tests.emf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final MD.emf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final TVD.emf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 Geo-Tap Pressure Tests.pdf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final MD.pdf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final TVD.pdf34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 Geo-Tap Pressure Tests.tif34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final MD.tif34125EDDigital DataDF10/22/2020 Electronic File: BRU 212-26 LWD Final TVD.tif34125EDDigital Data0 0 2200580 BELUGA RIV UNIT 212-26 LOG HEADERS34125LogLog Header ScansDF12/30/202044 1736 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20BASELINE DOWN FROM SURF.las34488EDDigital DataDF12/30/20201176 4264 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20BASELINE DOWN THROUGH DEVIATION ~300 FPM.las34488EDDigital DataDF12/30/20204275 6911 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_BASELINE DOWN FROM 4300 TO TD.las34488EDDigital DataDF12/30/20206301 6903 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_DOWN PASS @ 120 FPM.las34488EDDigital DataDF12/30/20206315 6895 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_DOWN PASS @ 40 FPM.las34488EDDigital DataDF12/30/20206292 6892 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_DOWN PASS @ 80 FPM.las34488EDDigital DataTuesday, January 5, 2021AOGCCPage 4 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-283-20182-00-00Well Name/No. BELUGA RIV UNIT 212-26Completion Status1-GASCompletion Date9/24/2020Permit to Drill2200580Operator Hilcorp Alaska, LLCMD8001TVD6789Current Status1-GAS1/5/2021UICNoDF12/30/20206333 6954 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_DOWN PASS ~150 FPM TRYING TO GET THROUGH BOTTOM PERFS.las34488EDDigital DataDF12/30/20206901 -20 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_POOH ~215 FPM.las34488EDDigital DataDF12/30/20206292 6956 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_ProcessedLog-V1.las34488EDDigital DataDF12/30/20200 304 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_STATION STOP @ 6325.las34488EDDigital DataDF12/30/20200 314 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_STATION STOP @ 6500.las34488EDDigital DataDF12/30/20200 310 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_STATION STOP @ 6550.las34488EDDigital DataDF12/30/20200 337 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_STATION STOP @ 6911.25'.las34488EDDigital DataDF12/30/20200 389 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_STATION STOP @ 6918.5.las34488EDDigital DataDF12/30/20206906 6305 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_UP PASS @ 120 FPM.las34488EDDigital DataDF12/30/20206916 6317 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_UP PASS @ 40 FPM.las34488EDDigital DataDF12/30/20206902 6302 Electronic Data Set, Filename: BRU_212-26_PPROF_17OCT20_UP PASS @ 80 FPM.las34488EDDigital DataDF12/30/2020 Electronic File: BRU_212-26_PPROF_17OCT20.pdf34488EDDigital DataDF12/30/2020 Electronic File: BRU_212-26_PPROF_17OCT20_img.tiff34488EDDigital DataDF12/30/2020 Electronic File: BRU_212-26_PPROF_17OCT20_Report-V1.pdf34488EDDigital Data0 0 2200580 BELUGA RIV UNIT 212-26 LOG HEADERS34488LogLog Header ScansTuesday, January 5, 2021AOGCCPage 5 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-283-20182-00-00Well Name/No. BELUGA RIV UNIT 212-26Completion Status1-GASCompletion Date9/24/2020Permit to Drill2200580Operator Hilcorp Alaska, LLCMD8001TVD6789Current Status1-GAS1/5/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:9/24/2020Release Date:8/12/20209/10/20202700 800041764CuttingsTuesday, January 5, 2021AOGCCPage 6 of 6M. Guhl1/6/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 12/30/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) Production Profile (PPROF) 10/17/2020: 1.PPROF LOG 2.PPROF ANALYSIS REPORT 3.LAS FILES Folder Contents: Please include current contact information if different from above. 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(no spacer or cement in returns ... gls 1/5/21) David Douglas Hilcorp Alaska, LLC 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 or FAX to 907 777.8510 Received By: Date: DATE 10/22/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) FINAL CD – LWD Data •EWR-DGR-ADR-CTN-ALD (MD / TVD) •GeoTap Formation Pressures (MD /TVD) •Definitive Directional Survey Folder Contents: Please include current contact information if different from above. Received by the AOGCC 10/22/2020 PTD: 2200580 E-Set: 34125 Abby Bell 10/23/2020 Dvid Douglas Hilcorp Alaska, LLC 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 or FAX to 907 777.8510 Received By: Date: DATE 9/09/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) FINAL CD - DRILL REPORTS-LWD LOGS-MUDLOGS Please include current contact information if different from above. PTD: 2200580 E-Set: 33819 Received by the AOGCC 09/10/2020 Abby Bell 09/10/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchrage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 8/27/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) CBL 09-04-2020 Please include current contact information if different from above. Received by the AOGCC 09/10/2020 PTD:2200580 E-Set: 33818 Abby Bell 09/10/2020 DATE 9/09/2020 a,zo-0SU David Douglas Hilcorp Alaska, LLC I I GeoTechnician 3800 CenterPoint Drive, Suite 1400 6 �O Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-26 (PTD 220-058) WELL BOX SAMPLE INTERVAL (FEET / MD) BRU 212-26 BOX 1 OF 4 2700'— 4410' MD BRU 212-26 BOX 2 OF 4 4410'- 6030' MD BRU 212-26 BOX 3 OF 4 6030'- 7500' MD BRU 212-26 BOX 4 OF 4 7500'- 8000' MD (TD) Please include current contact information if different from above. RECENED SEP 10 202,1 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to: (907) 777-8510 Received By: Date: ° __ "l 45120 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 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? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,001'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production Tieback 8,730psi Production Liner 8,730psi 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng tkramer@hilcorp.com 6,789'7,902'6,690'~2,217 N/A Swell Pkr; N/A 2,495' MD/1,913'TVD; N/A; N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: 10,600psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-058 50-283-20182-00-00 Beluga River Unit (BRU) 212-26 Beluga River Unit - Beluga River Undefined Length Size State Wide Spacing Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,600psi MD 2,980psi 5,750psi 138' 2,050' 138' 2,731' 1,913'5-1/2" 16" 9-5/8" 138' 2,731' 2,495' Perforation Depth MD (ft): See Attached Schematic 2,495' 5-1/2" Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 23, 2020 8,001'5,506' N/A 6,789' m n P 66 t n Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:38 am, Sep 09, 2020 320-371 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.08 16:04:31 -08'00' Taylor Wellman SFD 9/9/2020 X GAS Perforate X DSR-9/10/2020 CO 786 - Approved Spacing Exception SFD 9/9/2020 Initial Completionn Gas CTU Approved CO 786 (08/12/20) Spacing Exception applies. DLB DLB 09/09/2020 gls 9/15/20 10-407 * 4000 psi BOP test (CTU) q Yes C XX 9/15/2020 dts 9/15/2020 JLC 9/15/2020 RBDMS HEW 9/16/2020 Well Prognosis Well: BRU 212-26 Date: 9-8-2020 Well Name: BRU 212-26 API Number: 50-283-20182-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: Sep 23, 2020 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-058 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Ryan Rupert (907) 777-8503 (O) (907) 301-1736 (C) AFE Number: 2011740C Maximum Expected BHP: ~ 2,875 psi @ 6,580’ TVD (Based on a .437 gradient.) Max. Potential Surface Pressure: ~ 2,217 psi @ 6,580’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary BRU 212-26 is a grass roots well targeting gas sands in the Beluga formation. This new well TD was reached on 8-27-2020 at 8,000’ MD. The purpose of this work/sundry is to jet the well dry with CT, and perforate. Notes Regarding Wellbore Condition x Well will be filled with 6% KCL x Rig cleaned out well to PBTD prior to rigging down. x E-line ran a CBL. x MITIA Was conducted by the rig to 2,580 psi on chart for 30 mins. (Good Test). Electronic copy of CBL to be sent to AOGCC. Safety Concerns x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority Coiled Tubing Procedure 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 48 hrs. in advance of BOP test. 2. MU Jet nozzle. 3. RIH W/ nozzle. RU N2 pumping unit. 4. Drop ball and come online with N2 and blow well dry of 6% KCL. a) Estimated volume of displaced 6% KCl is (+/-) 184 bbls. (Based on estimated PBTD of 7,902’). 5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 6. Once well is dry, leave 1,800 psi. on the well for first perforation interval. 7. POOH w/ coil. LD BHA. 8. RDMO Coiled Tubing. E-Line Procedure Recieved 9/14/20 .. gls (yellowjacket CBL) (Review N2 SOP/Pre-job with crews) Well Prognosis Well: BRU 212-26 Date: 9-8-2020 9. MIRU e-line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. a) If necessary, bleed pressure down as requested by the OE to establish a drawdown on the formation. 10. PU RIH W/perf guns. Perforate each interval with Perf guns 6 to 12 JSPF 60 degree phasing. 11. Proposed Perforated Intervals (NOTE: A plug will need to be set at 4,850’(MD) between the Beluga and Sterling Sands to comply with state wide spacing rules). Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom ST_A1 ±4,257' ±4,276' 19' ±3,012' ±3,031' ST_A2 ±4,286' ±4,290' 4' ±3,037' ±3,041' ST_A3 ±4,311' ±4,321' 10' ±3,059' ±3,069' ST_A3 ±4,329' ±4,332' 3' ±3,075' ±3,078' ST_A4 ±4,366' ±4,421' 55' ±3,108' ±3,163' ST_A5 ±4,431' ±4,453' 22' ±3,166' ±3,188' ST_B1 ±4,486' ±4,497' 11' ±3,215' ±3,226' ST_B2 ±4,506' ±4,514' 8' ±3,233' ±3,241' ST_B2 ±4,524' ±4,550' 26' ±3,250' ±3,276' ST_B3 ±4,576' ±4,588' 12' ±3,297' ±3,309' ST_B4 ±4,601' ±4,617' 16' ±3,320' ±3,336' ST_C ±4,632' ±4,634' 2' ±3,348' ±3,350' ST_C1 ±4,646' ±4,670' 24' ±3,362' ±3,386' ST_C2 ±4,679' ±4,701' 22' ±3,392' ±3,414' ST_C3 ±4,718' ±4,745' 27' ±3,430' ±3,457' ST_C4 ±4,755' ±4,768' 13' ±3,464' ±3,477' ST_C5 ±4,781' ±4,789' 8' ±3,487' ±3,495' ST_C5 ±4,816' ±4,825' 9' ±3,520' ±3,529' ST_C5 ±4,828' ±4,836' 8' ±3,532' ±3,540' Beluga D1 ±4,874' ±4,883' 9' ±3,575' ±3,584' Beluga D1 ±4,887' ±4,895' 8' ±3,587' ±3,595' Beluga D2 ±4,902' ±4,908' 6' ±3,602' ±3,608' Beluga D3 ±4,915' ±4,919' 4' ±3,615' ±3,619' Beluga D3 ±4,929' ±4,941' 12' ±3,629' ±3,641' Beluga D4 ±4,965' ±4,968' 3' ±3,663' ±3,666' Beluga D5 ±4,993' ±4,996' 3' ±3,690' ±3,693' Beluga D5 ±5,011' ±5,013' 2' ±3,709' ±3,711' Beluga D6 ±5,038' ±5,042' 4' ±3,735' ±3,739' Beluga D7 ±5,066' ±5,071' 5' ±3,762' ±3,767' Beluga E ±5,086' ±5,088' 2' ±3,781' ±3,783' Beluga E1 ±5,136' ±5,152' 16' ±3,832' ±3,848' NOTE Proposed Perforated Intervals (NOTE: A plug will need to be set at 4,850’(MD) between the Beluga and Sterling Sands to comply with state wide spacing rules). Note: DLB 09/09/2020 Well Prognosis Well: BRU 212-26 Date: 9-8-2020 Beluga E2 ±5,169' ±5,172' 3' ±3,865' ±3,868' Beluga E3 ±5,191' ±5,194' 3' ±3,886' ±3,889' Beluga E3 ±5,201' ±5,205' 4' ±3,896' ±3,900' Beluga E3 ±5,253' ±5,259' 6' ±3,948' ±3,954' Beluga E5 ±5,322' ±5,329' 7' ±4,017' ±4,024' Beluga E6 ±5,353' ±5,356' 3' ±4,048' ±4,051' Beluga E6 ±5,360' ±5,367' 7' ±4,056' ±4,063' Beluga E6 ±5,381' ±5,385' 4' ±4,076' ±4,080' Beluga E6 ±5,400' ±5,404' 4' ±4,096' ±4,100' Beluga F4 ±5,496' ±5,505' 9' ±4,191' ±4,200' Beluga F4 ±5,540' ±5,545' 5' ±4,235' ±4,240' Beluga F5 ±5,587' ±5,591' 4' ±4,279' ±4,283' Beluga F7 ±5,725' ±5,761' 36' ±4,420' ±4,456' Beluga F7 ±5,781' ±5,787' 6' ±4,476' ±4,482' Beluga F9 ±5,866' ±5,874' 8' ±4,561' ±4,569' Beluga G1 ±5,960' ±5,964' 4' ±4,655' ±4,659' Beluga G2 ±5,994' ±6,012' 18' ±4,689' ±4,707' Beluga G5 ±6,110' ±6,121' 11' ±4,805' ±4,816' Beluga G6 ±6,136' ±6,141' 5' ±4,831' ±4,836' Beluga G7 ±6,161' ±6,168' 7' ±4,856' ±4,863' Beluga G8 ±6,178' ±6,182' 4' ±4,873' ±4,877' Beluga G9 ±6,224' ±6,234' 10' ±4,919' ±4,929' Beluga G10 ±6,237' ±6,246' 9' ±4,932' ±4,941' Beluga H ±6,283' ±6,289' 6' ±4,978' ±4,984' Beluga H ±6,317' ±6,321' 4' ±5,012' ±5,016' Beluga H1 ±6,338' ±6,342' 4' ±5,032' ±5,036' Beluga H1 ±6,348' ±6,352' 4' ±5,043' ±5,047' Beluga H2 ±6,369' ±6,391' 22' ±5,065' ±5,087' Beluga H3 ±6,420' ±6,429' 9' ±5,116' ±5,125' Beluga H4 ±6,445' ±6,463' 18' ±5,140' ±5,158' Beluga H5 ±6,512' ±6,520' 8' ±5,207' ±5,215' Beluga H6 ±6,529' ±6,533' 4' ±5,224' ±5,228' Beluga H6 ±6,539' ±6,542' 3' ±5,234' ±5,237' Beluga H7 ±6,560' ±6,583' 23' ±5,255' ±5,278' Beluga H10 ±6,684' ±6,730' 46' ±5,379' ±5,425' Beluga H11 ±6,741' ±6,746' 5' ±5,436' ±5,441' Beluga H11 ±6,752' ±6,759' 7' ±5,447' ±5,454' Beluga H12 ±6,777' ±6,788' 11' ±5,472' ±5,483' Beluga H13 ±6,799' ±6,819' 20' ±5,494' ±5,514' Beluga H14 ±6,907' ±6,916' 9' ±5,602' ±5,611' Beluga H15 ±6,932' ±6,952' 20' ±5,627' ±5,647' Beluga H15 ±6,956' ±6,966' 10' ±5,652' ±5,662' Well Prognosis Well: BRU 212-26 Date: 9-8-2020 Beluga H16 ±6,987' ±7,015' 28' ±5,683' ±5,711' Beluga I12 ±7,536' ±7,549' 13' ±6,230' ±6,243' Beluga J1 ±7,637' ±7,648' 11' ±6,332' ±6,343' Beluga J2 ±7,681' ±7,692' 11' ±6,377' ±6,388' Beluga J2 ±7,702' ±7,714' 12' ±6,397' ±6,409' Beluga J3 ±7,830' ±7,841' 11' ±6,525' ±6,536' Beluga J4 ±7,852' ±7,863' 11' ±6,547' ±6,558' Beluga J4 ±7,875' ±7,885' 10' ±6,570' ±6,580' a. Proposed perfs. also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. f. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. g. Sand intervals are governed by State Wide Spacing rules. 12. POOH. 13. RD e-line. 14. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil tubing BOPE 4. Standard Well Procedure – N2 Operations Updated by DMA 09-08-20 SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 7,902’ MD / TVD = 6,690’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,733’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,495’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,495’ 6.180” 7.010” Baker tieback Seal Assembly 8-1/2” hole CBL indicates TOC at 3600 ft md Updated by DMA 09-08-20 – Page 1 of 2 PROPOSED SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 PBTD = 7,902’ MD / TVD = 6,690’ TD = 8,001’ MD / TVD = 6,789’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,733’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,495’ 8,001’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,495’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,495’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,495’ 6.180” 7.010” Baker tieback Seal Assembly 8-1/2” hole PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status ST_A1 ±4,257' ±4,276' ±3,012' ±3,031' 19' Proposed TBD ST_A2 ±4,286' ±4,290' ±3,037' ±3,041' 4' Proposed TBD ST_A3 ±4,311' ±4,321' ±3,059' ±3,069' 10' Proposed TBD ST_A3 ±4,329' ±4,332' ±3,075' ±3,078' 3' Proposed TBD ST_A4 ±4,366' ±4,421' ±3,108' ±3,163' 55' Proposed TBD ST_A5 ±4,431' ±4,453' ±3,166' ±3,188' 22' Proposed TBD ST_B1 ±4,486' ±4,497' ±3,215' ±3,226' 11' Proposed TBD ST_B2 ±4,506' ±4,514' ±3,233' ±3,241' 8' Proposed TBD ST_B2 ±4,524' ±4,550' ±3,250' ±3,276' 26' Proposed TBD ST_B3 ±4,576' ±4,588' ±3,297' ±3,309' 12' Proposed TBD ST_B4 ±4,601' ±4,617' ±3,320' ±3,336' 16' Proposed TBD ST_C ±4,632' ±4,634' ±3,348' ±3,350' 2' Proposed TBD ST_C1 ±4,646' ±4,670' ±3,362' ±3,386' 24' Proposed TBD ST_C2 ±4,679' ±4,701' ±3,392' ±3,414' 22' Proposed TBD ST_C3 ±4,718' ±4,745' ±3,430' ±3,457' 27' Proposed TBD ST_C4 ±4,755' ±4,768' ±3,464' ±3,477' 13' Proposed TBD Beluga D ±3,567' ±3,571' ±3,556' ±3,560' 4' Proposed TBD Beluga D1 ±4,874' ±4,883' ±3,575' ±3,584' 9' Proposed TBD Beluga D1 ±4,887' ±4,895' ±3,587' ±3,595' 8' Proposed TBD Beluga D2 ±4,902' ±4,908' ±3,602' ±3,608' 6' Proposed TBD Beluga D3 ±4,915' ±4,919' ±3,615' ±3,619' 4' Proposed TBD Beluga D3 ±4,929' ±4,941' ±3,629' ±3,641' 12' Proposed TBD Beluga D4 ±4,965' ±4,968' ±3,663' ±3,666' 3' Proposed TBD Beluga D5 ±4,993' ±4,996' ±3,690' ±3,693' 3' Proposed TBD Beluga D5 ±5,011' ±5,013' ±3,709' ±3,711' 2' Proposed TBD Beluga D6 ±5,038' ±5,042' ±3,735' ±3,739' 4' Proposed TBD Beluga D7 ±5,066' ±5,071' ±3,762' ±3,767' 5' Proposed TBD ** PERFORATION DETAIL CONTINUED ON FOLLOWING PAGE ** Bel H Bel I Bel J ST A Bel F Bel G Bel E Bel D ST C ST B TOC Approx 3800 ft plug required between sands Updated by DMA 09-08-20 – Page 2 of 2 PROPOSED SCHEMATIC Beluga River Unit BRU 212-26 PTD: 220-058 API: 50-283-20182-00-00 ** PERFORATION DETAIL CONTINUED FROM PREVIOUS PAGE ** PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga E ±5,086' ±5,088' ±3,781' ±3,783' 2' Proposed TBD Beluga E1 ±5,136' ±5,152' ±3,832' ±3,848' 16' Proposed TBD Beluga E2 ±5,169' ±5,172' ±3,865' ±3,868' 3' Proposed TBD Beluga E3 ±5,191' ±5,194' ±3,886' ±3,889' 3' Proposed TBD Beluga E3 ±5,201' ±5,205' ±3,896' ±3,900' 4' Proposed TBD Beluga E3 ±5,253' ±5,259' ±3,948' ±3,954' 6' Proposed TBD Beluga E5 ±5,322' ±5,329' ±4,017' ±4,024' 7' Proposed TBD Beluga E6 ±5,353' ±5,356' ±4,048' ±4,051' 3' Proposed TBD Beluga E6 ±5,360' ±5,367' ±4,056' ±4,063' 7' Proposed TBD Beluga E6 ±5,381' ±5,385' ±4,076' ±4,080' 4' Proposed TBD Beluga E6 ±5,400' ±5,404' ±4,096' ±4,100' 4' Proposed TBD Beluga F4 ±5,496' ±5,505' ±4,191' ±4,200' 9' Proposed TBD Beluga F4 ±5,540' ±5,545' ±4,235' ±4,240' 5' Proposed TBD Beluga F5 ±5,587' ±5,591' ±4,279' ±4,283' 4' Proposed TBD Beluga F7 ±5,725' ±5,761' ±4,420' ±4,456' 36' Proposed TBD Beluga F7 ±5,781' ±5,787' ±4,476' ±4,482' 6' Proposed TBD Beluga F9 ±5,866' ±5,874' ±4,561' ±4,569' 8' Proposed TBD Beluga G1 ±5,960' ±5,964' ±4,655' ±4,659' 4' Proposed TBD Beluga G2 ±5,994' ±6,012' ±4,689' ±4,707' 18' Proposed TBD Beluga G5 ±6,110' ±6,121' ±4,805' ±4,816' 11' Proposed TBD Beluga G6 ±6,136' ±6,141' ±4,831' ±4,836' 5' Proposed TBD Beluga G7 ±6,161' ±6,168' ±4,856' ±4,863' 7' Proposed TBD Beluga G8 ±6,178' ±6,182' ±4,873' ±4,877' 4' Proposed TBD Beluga G9 ±6,224' ±6,234' ±4,919' ±4,929' 10' Proposed TBD Beluga G10 ±6,237' ±6,246' ±4,932' ±4,941' 9' Proposed TBD Beluga H ±6,283' ±6,289' ±4,978' ±4,984' 6' Proposed TBD Beluga H ±6,317' ±6,321' ±5,012' ±5,016' 4' Proposed TBD Beluga H1 ±6,338' ±6,342' ±5,032' ±5,036' 4' Proposed TBD Beluga H1 ±6,348' ±6,352' ±5,043' ±5,047' 4' Proposed TBD Beluga H2 ±6,369' ±6,391' ±5,065' ±5,087' 22' Proposed TBD Beluga H3 ±6,420' ±6,429' ±5,116' ±5,125' 9' Proposed TBD Beluga H4 ±6,445' ±6,463' ±5,140' ±5,158' 18' Proposed TBD Beluga H5 ±6,512' ±6,520' ±5,207' ±5,215' 8' Proposed TBD Beluga H6 ±6,529' ±6,533' ±5,224' ±5,228' 4' Proposed TBD Beluga H6 ±6,539' ±6,542' ±5,234' ±5,237' 3' Proposed TBD Beluga H7 ±6,560' ±6,583' ±5,255' ±5,278' 23' Proposed TBD Beluga H10 ±6,684' ±6,730' ±5,379' ±5,425' 46' Proposed TBD Beluga H11 ±6,741' ±6,746' ±5,436' ±5,441' 5' Proposed TBD Beluga H11 ±6,752' ±6,759' ±5,447' ±5,454' 7' Proposed TBD Beluga H12 ±6,777' ±6,788' ±5,472' ±5,483' 11' Proposed TBD Beluga H13 ±6,799' ±6,819' ±5,494' ±5,514' 20' Proposed TBD Beluga H14 ±6,907' ±6,916' ±5,602' ±5,611' 9' Proposed TBD Beluga H15 ±6,932' ±6,952' ±5,627' ±5,647' 20' Proposed TBD Beluga H15 ±6,956' ±6,966' ±5,652' ±5,662' 10' Proposed TBD Beluga H16 ±6,987' ±7,015' ±5,683' ±5,711' 28' Proposed TBD Beluga I12 ±7,536' ±7,549' ±6,230' ±6,243' 13' Proposed TBD Beluga J1 ±7,637' ±7,648' ±6,332' ±6,343' 11' Proposed TBD Beluga J2 ±7,681' ±7,692' ±6,377' ±6,388' 11' Proposed TBD Beluga J2 ±7,702' ±7,714' ±6,397' ±6,409' 12' Proposed TBD Beluga J3 ±7,830' ±7,841' ±6,525' ±6,536' 11' Proposed TBD Beluga J4 ±7,852' ±7,863' ±6,547' ±6,558' 11' Proposed TBD Beluga J4 ±7,875' ±7,885' ±6,570' ±6,580' 10' Proposed TBD 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION RevieSuprv. wed B �� qe� z� P.I. BOPE Test Report for: BELUGA RIV UNIT 212-26 - Comm Contractor/Rig No.: Hilcorp 169' PTD#: 2200580 ' DATE: 8/21/2020 Inspector Austin McLeod Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Hauck/Riley Rig Rep: VanEvera/Lynch Inspector Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopSAM200823105031 / Rams: Annular: Valves: MASP: Type Test: INIT 250/3500 , 250/3500' 250/3500 ' 1620 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly - i-_ P/F Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank P P _- System Pressure -_ 3000_ --__P_ 0 Housekeeping: P Pit Level Indicators _ P P Pressure After Closure - 1550 --P ' PTD On Location P Flow Indicator P P 200 PSI Attained 26 P ' Standing Order Posted - P Meth Gas Detector --P- _ P Full Pressure Attained 90 " -P Well Sign P_'_ H2S Gas Detector P P ' Blind Switch Covers: All stations, P Drl. Rig I— MS Misc NA - NA Nitgn. Bottles (avg): 4(d,)2512 _' P Hazard Sec. P P Inside Reel Valves -_ 0 - -NA ACC Misc 0 NA Misc NA Check Valve 0 NA FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly - i-_ F Lower Kelly I_ -- P Ball Type _ 1 _ - P ' Inside BOP I P FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0 NA No. Valves 15 P - Annular Preventer 1 11" P Manual Chokes 1 P- #1 Rams - 1 ' 2-7/8"x5" P Hydraulic Chokes 1 -_ _ P #2 Rams 1 Blinds P CH Misc 0 NA #3 Rams 1 2-7/8"x5"' P #4 Rams NA_ _0 #5 Rams -_ 0 _ NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 -3-1/8" P Quantity P/F HCR Valves 2 '2-1/16"/3-1/8'1 P Inside Reel Valves -_ 0 - -NA Kill Line Valves 2 2-1/16" P ' Check Valve 0 NA BOP Misc 0 NA Number of Failures: 1 '/ Test Results ,/ Test Time 4 Remarks: 4-1/2" joint. Upper kelly failed. Was replaced and tested post me leaving location. Chart was sent to Jim Regg. BLM also witnessed this BOP test. , 12 �°�v�e4rwA •�cpnri t/y rbr.yy�pwWdlo. ran- 45 .30 W% 1w NPLIT *S 11 -Jan- 16 5500 _ • �i, � i ` 1 \\ � 5000 45, { SPP � ►`� 4500 f �y 5000 5 1 -4000 5 3500 t �p0 i j 11r ` soo p 1 i 1 3006 es 06 loop 1 � t poop 0.0 Is 00 .- 1000 ,y ' t , tT • DO i' �• ark � " � �� :) � -r' _ , t Q Gf'd Ii0�5 11l" o chic Ccul . r U, p " Nil` o A ISO rJ ca � �.. 1, 1 n o 0 0 0 0 o CHART N0. MC MP -60c12 j o o o l i-htcT METER - 4.271 _. ;i r`ss ' r/ TAt;EN OFF O I CHART PUrT ON I O G c) p '.�. LOCATION L��u ala—aL O Q c O _i to {' C7 a �S+ ,O% t 0 N- . REMARKS � �� �' O Ocq ter. \G'0 p/l / ar Obip�% / o bw 0 �o fJ i cL �C��►, 4S p°S OifS OQS �J`! S i /0OT t700� 1 F 0000 � r �� %9 00Op 5©� . i 000yA \\\\\\\\\ 0OP f 0006 ! t OOS� Sj 00 r S4. , 1 OOOg' f • / j .ni 0, r yr O£ or ; ati bae:i a:a.i" to ,n>u+e the acc urai� o11>sr S; 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 Field, Beluga River Undefined Pool, BRU 212-26 Hilcorp Alaska, LLC Permit to Drill Number: 220-058 Surface Location: 816' FSL, 400' FWL, Sec 26, T13N, R10W, SM, AK Bottomhole Location: 1661' FNL, 1237' FWL, Sec 26, T13N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. 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, Jeremy M. Price Chair DATED this ___ day of August, 2020. Sincerely, 12 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: 8,347' TVD: 7,093' 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): 93.1 15. Distance to Nearest Well Open Surface: x-318343 y- 2625964 Zone-4 75.1 to Same Pool:1486' to BRU 211-26 16. Deviated wells:Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 55 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# J-55 Weld 138' Surface Surface 138' 138' 12-1/4" 9-5/8" 47# L-80 BTC 2,750' Surface Surface 2,750' 2,066' 8-1/2" 5-1/2" 17# P-110 TXP BTC 8,347' Surface Surface 8,347' 7,093' 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:50- 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: Sr Pet Eng Sr Pet Geo Sr Res Eng 4892' to nearest unit boundary 8/15/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Frank Roach frank.roach@hilcorp.com 777-8413 18. Casing Program:Top - Setting Depth - BottomSpecifications BRU 212-26 Beluga River Unit Beluga River Undefined 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 816' FSL, 400' FWL, Sec 26, T13N, R10W, SM, AK A029657 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1299 ft3 / T - 138 ft3 1620 1661' FNL, 1237' FWL, Sec 26, T13N, R10W, SM, AK 1661' FNL, 1237' FWL, Sec 26, T13N, R10W, SM, AK N/A 1474 2237 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 1076 ft3 / T - 270 ft3 Effect. Depth TVD (ft): Conductor/Structural Length Production Liner Casing Intermediate Commission Use Only Effect. Depth MD (ft): Authorized Signature: See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 7/7/2020 s N ype of W L l R L 1b S Class: os N s No s N o D s s s D 84 o well is p G S S 20 S S S s No s No S G y E S s No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Samantha Carlisle at 3:17 pm, Jul 07, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.07 14:57:55 -08'00' Monty M Myers SFD 8/12/2020 220-058 50-283-20182-00-00 (post rig) *Sundry approval required to perforate well. DSR-7/7/2020gls 8/12/20 Development - Gas *3500 PSI BOP test * CBL and MIT-IA required to 2500psi /12/20 8/12/2020 8/12/2020 BRU 212-26 Drilling Program Beluga River Unit Rev 0 June 19, 2020 BRU 212-26 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 12-1/4” Hole Section ................................................................................................... 14 12.0 Run 9-5/8” Surface Casing.................................................................................................. 17 13.0 Cement 9-5/8” Surface Casing ............................................................................................ 20 14.0 BOP N/U and Test.............................................................................................................. 23 15.0 Drill 8-1/2” Hole Section ..................................................................................................... 24 16.0 Run 5-1/2” Production Casing ............................................................................................ 28 17.0 Cement 5-1/2” Production Casing....................................................................................... 31 18.0 RDMO ................................................................................................................................ 34 19.0 BOP Schematic ................................................................................................................... 35 20.0 Wellhead Schematic............................................................................................................ 36 21.0 Days Vs Depth .................................................................................................................... 37 22.0 Geo-Prog............................................................................................................................. 38 23.0 Anticipated Drilling Hazards .............................................................................................. 39 24.0 Hilcorp Rig 169 Layout....................................................................................................... 41 25.0 FIT Procedure .................................................................................................................... 42 26.0 Choke Manifold Schematic ................................................................................................. 43 27.0 Casing Design Information ................................................................................................. 44 28.0 8-1/2” Hole Section MASP .................................................................................................. 45 29.0 Spider Plot (Governmental Sections) .................................................................................. 46 30.0 Surface Plat (As-Built NAD27 & NAD83) ........................................................................... 47 31.0 Directional Plan (wp05) ...................................................................................................... 48 Page 2 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 1.0 Well Summary Well BRU 212-26 Pad & Old Well Designation BRU 212-26 is a grass roots well on BRU H Pad Planned Completion Type 5-1/2” Production Longstring (monobore) Target Reservoir(s) Sterling/Beluga Planned Well TD, MD / TVD 8,347 MD / 7,093’ TVD PBTD, MD / TVD 8,200’ MD / 6,946’ TVD Surface Location (Governmental) 816’ FSL, 400’ FWL, Sec 26, T13N, R10W, SM, AK Surface Location (NAD 27) X=318343.38 Y=2625964.52 Surface Location (NAD 83) X=1458370.44 Y=2625725.00 Top of Productive Horizon (Governmental) 1661’ FNL, 1237’ FWL, Sec 26, T13N, R10W, SM, AK TPH Location (NAD 27) X=319221.68, Y=2628753.77 TPH Location (NAD 83) X=1459248.89 Y=2628514.22 BHL (Governmental) 1661’ FNL, 1237’ FWL, Sec 26, T13N, R10W, SM, AK BHL (NAD 27) X=319221.68, Y=2628753.77 BHL (NAD 83) X=1459248.89 Y=2628514.22 AFE Number 2011740 (D, C, F) AFE Drilling Days 3 MOB, 19 DRLG AFE Completion Days AFE Drilling Amount $4,216,500 AFE Completion Amount $1,081,200 Maximum Anticipated Pressure (Surface) 1620 psi Maximum Anticipated Pressure (Downhole/Reservoir) 2237 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 93.1’(75.1 + 18) Ground Elevation 75.1’ BOP Equipment 11” 5M Control Tech Type 90 Annular BOP 11” 5M Control Tech Type 82 Double Ram 11” 5M Control Tech Type 82 Single Ram Page 3 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01” 14.822 17” 84 J-55 Weld 2980 1410 - 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 BTC 5750 3090 947 8-1/2” 5-1/2” 4.892” 4.767” 6.05” 17 P110HC USS-CDC 10600 8730 568 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). (p ) 2980 5750 1060 Page 5 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 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 Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com , mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 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. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 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 mmyers@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to mmyers@hilcorp.com and cdinger@hilcorp.com Page 6 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic MIT-IA to 2500 psi CBL over 5 1/2" casing to TOC Page 7 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary BRU 212-26 is an S-shaped directional grassroots development well to be drilled off of the BRU H pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Upper Sterling sands, as well as an area with little to no production in the Beluga sands. The base plan is an S-shaped directional wellbore with a kick off point at 250’ MD. Maximum hole angle will be 55 deg. and TD of the well will be 8,347’ TMD/ 7,093’ TVD, ending with 0 deg inclination left in the hole. Vertical section will be 2924 ft. Drilling operations are expected to commence approximately A ugust 15 th 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2,750 MD / 2,066’ 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 Temp log will be run between 6 – 18 hrs after CIP to 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. In the event that we cannot store cuttings at the waste cells, we will haul cutting to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to well site 2. N/U diverter and test. 3. Drill 12-1/4 ” hole to 2,750’ MD. Run and cmt 9-5/8” surface casing. 4. ND diverter, N/U & test 11” x 5M BOP. 5. Drill 8-1/2 ” hole section to 8,347’ MD. Perform Wiper trip. 6. Make cleanout run 7. POOH laying down drill pipe. 8. Run and cmt 5-1/2” production casing. 9. PU clean out assembly and RIH to clean out 5-1/2” to float collar 10. Displace well to 6% KCL completion fluid. 11. POOH and LD clean out assembly. 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res 2. Production Hole: GR + Res 3. Mud loggers from surface casing point to TD. Drilling operations are expected to commence approximately A ugust 15AA t h 2020. NOTE: CBL and MIT-IA required post rig. BRU 212-26 is an S-shaped directional grassroots development well to be drilled off of the BRU H pad. Page 8 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations and all BLM regulations pertaining to Onshore Order No.1. 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 212-26. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 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 and BLM approved drilling permits are posted on the rig floor and in Co Man office. Regulation Variance Requests: x Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 21-1/4” x 2M Hydril MSP diverter Function Test Only 8-1/2” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time. x 48 hours before casing running and cmt operations x 48 hours before BOPE tests x 48 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Ema il: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Ema il: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Ema il: 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/TestWitne ssNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Amanda Eagle / BLM Petroleum Engineer / (O): 907-271-3266 (C): 907-538-2300 Email: aeagle@blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (O): 907-271-4224 Email: melganzoory@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov Page 11 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 12-1/4” hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners . Page 12 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 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. Notify AOGCC inspector to witness Page 13 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 10.5 Rig 169 and estimated Diverter line Orientation on BRU H Pad: Page 14 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 11.0 Drill 12-1/4 ” Hole Section 11.1 P/U 12-1/4” 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. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Primary Bit: Page 15 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 11.3 4-1/2” Workstring & HWDP will come from Hilcorp. 11.4 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.5 Drill 12-1/4 ” hole section to 2,750’ MD/ 2,066’ 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 thro ugh coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ 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 between 2650’ MD and 2850’ MD. x Take MWD surveys every stand drilled (6 0’ intervals). 11.6 12-1/4” 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 thro ughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2750’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 8.8 – 9.5 y Page 16 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 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 11.7 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.8 TOH with the drilling assy, handle BHA as appropriate. Page 17 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment. x Ensure 9-5/8” BTC 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 9-5/8 ” surface casing x Fill casing while r unning using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. x After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. 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 18 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 Page 19 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 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 20 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 13.0 Cement 9-5/8 ”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 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 16” Conductor x 9 -5/8” casing annulus: 120’ x .1125 bpf = 13.5 76 12.0 ppg LEAD: 12-1/4” OH x 9-5/8” Casing annulus: (2250’ – 120’) x .0 5578 bpf x 1.5 = 178.2 1000 Total LEAD: 191.7 1076 ft3 15.4 ppg TAIL: 12-1/4” OH x 9-5/8” Casing annulus: (2750’- 2250’) x .05578 bpf x 1.5 = 41.8 235 15.4 ppg TAIL: 9-5/8” Shoe track: 80 x .07582 bpf = 6.1 35 Total TAIL: 47.9 bbl 270 ft3 50% open hole excess. 437 sx 221 sx Page 21 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 Cement Slurry Design: 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 Displacement calculation: 2750’- 80’ = 2670’ x .07582 bpf = 203 bbls 13.12 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. Lead Slurry (2250’ MD to surface) Tail Slurry (2750’ to 2250’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC 2.46 ft3/1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk okp 2750’- 80’ = 2670’ x .07582 bpf = 203 bbls Page 22 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 6.1 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 us to run steel pipe thro ugh the hanger flutes. The ID of the flutes is 1.5”. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 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. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure 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 mmyers@hilcorp.com . This will be included with the EOW documentation that goes to the AOGCC. Page 23 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M Type 90 annular BOP/11” x 5M Model 82 double ram /11” x 5M mud cross/11” x 5M Type 82 single ram x Double ram should be dressed with 4-1/2” solid body rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 4-1/2” solid body rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2” BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.0 ppg 6% KCL PHPA mud system. 14.8 R/U mud loggers for production hole section. 14.9 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 3500 psi BOP test N/U multi-bowl wellhead assy. N/U 11” x 5M BOP as follows: Page 24 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 15.0 Drill 8-1/2 ” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity 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. Hydraulics calculations and recommended TFA is attached below. 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. Page 25 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 15.8 Primary Bit: Page 26 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 15.9 8-1/2” 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 thro ughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2,750’- 8,347’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.10 TIH w/ 8-1/2 ” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 2000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 9-5/8” burst is 5750 psi / 2 = 2875 psi. We are asking to test to 2000 psi. 15.12 Drill out shoe track and 20’ of new formation. 15.13 CBU and condition mud for FIT. fbu g 9.0 – 10.0– Page 27 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 15.14 Conduct FIT to 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 9-5/8” shoe to be between 11 - 13 ppg EMW. A 13.5 ppg FIT results in a 4 ppg kick margin while drilling with the planned MW of 9.5 ppg. Kick tolerance = (13.5-9.0)X(2066/7093) = 1.3 15.15 Drill 8-1/2 ” hole section to 8,347’ MD / 7,093’ 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 Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8” shoe. 15.17 TOH with the drilling assy, standing back drill pipe. 15.18 LD BHA 15.19 PU 8-1/2”clean out BHA, and TIH to TD. 15.20 Pump sweep, CBU and condition mud for casing run. 15.21 POOH LDDP and BHA 15.22 Install 5-1/2” pipe rams in BOP stack and test. Kick tolerance = (13.5-9.0)X(2066/7093) = 1.3 Swap rams and test Page 28 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 16.0 Run 5-1/2 ” Production Casing 16.1. R/U Weatherford 5-1/2” casing running equipment. x Ensure 5-1/2” CDC HTQ x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while r unning. 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 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 5-1/2 ” production casing x Fill casing while r unning using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 9-5/8” shoe. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 2500’. 16.5. Continue running 5-1/2 ” production casing 5-1/2” CDC HTQ M/U torques Casing OD Minimum Maximum Yield Torque 5-1/2” 8,500 ft-lbs 11,500 ft-lbs 13,900 ft-lbs g Pick up swell packer and place in string at approximately 2500’Swell packer at 2500 ft (NOTE : Contingency plan to run liner and tieback is attached to PTD) Page 29 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 Page 30 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 16.6. Run in hole w/ 5-1/2 ” casing to the 9-5/8” 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 5-1/2” X 9-5/8” swell packer to be placed at approximately 2500’. Swell packer should have 10’ handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate . Circ and condition mud with casing 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. 16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. PU 5-1/2” X 9-5/8” swell packer to be placed at approximately 2500’ Page 31 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 17.0 Cement 5-1/2 ”Production Casing 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 reciprocate the casing during cmt operations until hole gets sticky 17.3. Pump 5 bbls of 12.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 30 bbls 12.5 ppg Mud Push 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 10% OH excess. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 9-5/8” csg x 5-1/2” casing annulus: 500’ x .04644 bpf = 23.2 131 12.0 ppg LEAD: 8-1/2” OH x 5-1/2” annulus: (7847’ – 2750’) x .0408 bpf x 1.1 = 229 1416 Total LEAD: 252.2 1299 ft3 15.4 ppg TAIL: 8-1/2” OH x 5-1/2” annulus: (8347’- 7847’) x .0408 bpf x 1.1 = 22.4 126 15.4 ppg TAIL: 5-1/2” Shoe track: 80 x .02325 bpf = 2 12 Total TAIL: 24.4 bbl 138 ft3 575sx 1416 ft3 113 sx 1285 Page 32 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 Cement Slurry Design: Lead Slurry (7847’ MD to 2250’ MD) Tail Slurry (8347’ to 7847’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Page 33 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 17.7. Drop wiper plug and displace with drilling mud. 17.8. If hole conditions allow – continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not overdisplace by more than ½ shoe track. Shoe track volume is 2 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. 17.14. WOC minimum of 12 hours, test casing to 2500 psi and chart for 30 minutes. 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 mmyers@hilcorp.com . This will be included with the EOW documentation that goes to the AOGCC. Page 34 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Hilcorp Rig #169 NOTE: Sundry to perf required. CBL and MIT -IA required before perfing well. Page 35 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 19.0 BOP Schematic Page 36 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 20.0 Wellhead Schematic SSV Page 37 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 21.0 Days Vs Depth Page 38 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 22.0 Geo-Prog Well Name:BRU 212-26 Survey Type KB Field Name:Beluga River Unit Surface Hole:93.1 Pool Name:BELUGA RIVER, UNDEFI Bottom Hole:HAK 169 State:Alaska 18 Field Location:Onshore Coord Ref Sys:75.1 County/Parish:Tyonek Borough Objective: Reference Plan: BRU_ST_A1_COAL Sand / Coals Gas / Water 4178.18 2,999.6 -2981.60 2628501.98 319087.61 600.00 0.20 STERLING_B Sand / Coals Gas / Water 4390.48 3,186.3 -3168.33 2628597.25 319120.42 600.00 0.19 STERLING_C Sand / Coals Gas / Water 4551.85 3,335.1 -3317.10 2628656.20 319140.72 800.00 0.24 BELUGA_D Sand / Coals Gas / Water 4764.00 3,537.7 -3519.70 2628715.34 319161.08 900.00 0.25 BELUGA_E Sand / Coals Gas / Water 4980.92 3,750.7 -3732.74 2628753.37 319174.17 1600.00 0.43 BELUGA_F Sand / Coals Gas / Water 5343.57 4,112.7 -4094.69 2628768.69 319179.45 1200.00 0.29 BELUGA_G Sand / Coals Gas / Water 5852.43 4,621.5 -4603.54 2628768.69 319179.45 1600.00 0.35 BELUGA_H Sand / Coals Gas / Water 6201.01 4,970.1 -4952.12 2628768.69 319179.45 2228.45 0.45 BELUGA_I Sand / Coals Gas / Water 6943.51 5,712.6 -5694.62 2628768.69 319179.45 1400.00 0.25 BRU_BELUGA_J Sand / Coals Gas / Water 7501.18 6,270.3 -6252.29 2628768.69 319179.45 1400.00 0.22 BRU_BELUGA_J6 Sand / Coals Gas / Water 8011.72 6,780.8 -6762.83 2628768.69 319179.45 700.00 0.10 = Reservoir Objectives = Possible Geo Hazards TARGET RADIUS Mud Logging: LWD Data: Other Log Data: Coreing: Frac Half-Length SH Max Direction Surf. Inter. Prod. NOTES: DATA COLLECTION REQUIREMENTS: LWD Triple Combo Pressure data collected throughout sands 30 rotary sidewall cores total for oil and gas target reservoirs 2750 8347 PROSED PIPE SET DEPTHS Chance of Success & Anticipated Rate ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE Drill a grassroots well off of H-pad at BRU targeting the Beluga H, I, and J gas sands. COMPLETION TYPE Monobore Fault Constraints 100 FT at TD Surface casing to total depth, 30 ft samples with 20' samples in zones of interest, two sets of dry cut cuttings, chromatograph, show reports, pixler plots. BRU 212-26 WP 01ANTICIPATED FORMATION TOPS & GEOHAZARDS Geo Summary/ Justification: H, I and J gas sands are under developed in the northern part of BRU. Additional untapped A sterling sands targets. TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING EASTING Est. Pressure Gradient Ground Elevation: GEOLOGICAL PROGNOSIS As-Built x = 318,343.38 y = 2,625,964.52 TVD Ref Datum: TVD Ref Elevation: Planned Rig: Rig Height: x = 319,221.68 y = 2,628,753.77 8,347' MD -6,780' TVD NAD27 Zone 4 Page 39 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 23.0 Anticipated Drilling Hazards 12-1/4” 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 insure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 40 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 8-1/2” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 41 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 42 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 43 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 44 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 27.0 Casing Design Information 12-1/4"Mud Density:9 ppg 8-1/2"Mud Density:10 ppg Mud Density: 1620 psi (see attached MASP determination & calculation) 2237 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8" 5-1/2" 00 00 2,750 8,347 2,066 7,093 2,750 8,347 40 17 L-80 L-80 BTC CDC HTQ 110,000 141,899 110,000 141,899 916 428 8.33 3.02 967 3,085 3,090 6,290 3.20 2.04 620 2,237 5,750 7,740 9.27 3.46 Collapse Pressure at bottom (Psi) Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) Tension at Top of Section (lbs) Design Criteria: Minimum Yield (psi) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Worst Case Safety Factor (Collapse) MASP (psi) Worst Case Safety Factor (Tension) Casing Section MASP: Drilling Mode MASP: Length Top (TVD) Worst case safety factor (Burst) DATE: 06/19/2020 WELL: BRU 212-26 FIELD: Beluga River Unit DESIGN BY: Monty M Myers Hole Size Hole Size Hole Size MASP: Production Mode 8.33 3.02 3.20 9.27 2.04 3.46 0 Page 45 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 28.0 8-1/2” Hole Section MASP MD TVD Planned Top: 0 0 Planned TD: 8,347 7,093 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad BRU_ST_A1_COAL 3000 600 Gas/Wet 3.8 0.20 STERLING_B 3186 600 Gas/Wet 3.6 0.19 STERLING_C 3335 800 Gas/Wet 4.6 0.24 BELUGA_D 3538 900 Gas/Wet 4.9 0.25 BELUGA_E 3751 1600 Gas/Wet 8.2 0.43 BELUGA_F 4113 1200 Gas/Wet 5.6 0.29 BELUGA_G 4622 1600 Gas/Wet 6.7 0.35 BELUGA_H 4970 2228 Gas/Wet 8.6 0.45 BELUGA_I 5713 1400 Gas/Wet 4.7 0.25 BRU_BELUGA_J 6270 1400 Gas/Wet 4.3 0.22 BRU_BELUGA_J6 6781 700 Gas/Wet 2.0 0.10 TD 7093 800 Gas/Wet 2.2 0.11 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD)Date BRU 212-18 9 - 9.2 4,167 6,998 1975 BRU 214-35 9 - 9.2 3,262 6,000 1980 BRU 232-09 9 - 9.2 3,322 7,179 1984 Assumptions: 1. Fracture gradient at shoe (2066' TVD) is estimated at 17 ppg based on field test data. 2. Maximum planned mud density for the 8-1/2" hole section is 10.0 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is 100% evacuation of wellbore to gas. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: TVD Frac Grad 2066 ft X 0.884 psi/ft 1826 psi 1826(psi) - [0.1(psi/ft)*2066(ft)]= 1620 psi Surface MASP from pore pressure during production mode (Complete evacuation to gas) 4970 ft X 0.450 psi/ft 2237 psi Downhol e 2237(psi) - [0.1(psi/ft)* 4970 (ft)]= 1740 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by frac pressure at 9-5/8" shoe with entire wellbore evacuated to gas WELL: BRU 212-26 Beluga River Unit 8-1/2" Hole Section Maximum Anticipated Surface Pressure Calculation wnhole 2237(psi) - [0.1(psi/ft)* 4970 (ft)]= 1 MASP based on sands 4970 ft TVD 8.6 ppg Page 46 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 29.0 Spider Plot (Governmental Sections) Page 47 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 30.0 Surface Plat (As-Built NAD27 & NAD83) Page 48 Version 0 June, 2020 BRU 212-26 Drilling Procedure Rev 0 31.0 Directional Plan (wp04) !""# $ % $ % 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 7125 7600True Vertical Depth (950 usft/in)0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 Vertical Section at 16.58° (950 usft/in) BRU 212-26 tgt1 BRU 212-26 TD 9 5/8" x 12 1/4" 5 1/2" x 8 1/2" 5 0 0 1 0 0 0 1500200025003000350040004 5 0 0 5 0 0 0 5500 6000 6500 7000 7500 8000 8347 BRU 212-26 wp04 Start Dir 4º/100' : 250' MD, 250'TVD End Dir : 1629.6' MD, 1425.98' TVD Start Dir 3º/100' : 3443.64' MD, 2461.69'TVD End Dir : 5285.44' MD, 4031.43' TVD Total Depth : 8347.11' MD, 7093.1' TVD BRU_ST_A1_COAL STERLING_B STERLING_C BELUGA_D BELUGA_E BELUGA_F BELUGA_G BELUGA_H BELUGA_I BRU_BELUGA_J BRU_BELUGA_J6 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio WELL DETAILS: Plan: BRU 212-26 75.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2625964.52 318343.38 61° 11' 0.667 N 151° 1' 45.665 W SURVEY PROGRAM Date: 2020-06-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 2750.00 BRU 212-26 wp04 (BRU 212-26) 3_MWD+AX+Sag 2750.00 8347.11 BRU 212-26 wp04 (BRU 212-26) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3075.10 2982.00 4283.82 BRU_ST_A1_COAL 3261.10 3168.00 4492.53 STERLING_B 3410.10 3317.00 4652.59 STERLING_C 3613.10 3520.00 4863.69 BELUGA_D 3826.10 3733.00 5079.71 BELUGA_E 4188.10 4095.00 5442.11 BELUGA_F 4697.10 4604.00 5951.11 BELUGA_G 5045.10 4952.00 6299.11 BELUGA_H 5788.10 5695.00 7042.11 BELUGA_I 6345.10 6252.00 7599.11 BRU_BELUGA_J 6856.10 6763.00 8110.11 BRU_BELUGA_J6 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 212-26, True North Vertical (TVD) Reference:As-Built RKB @ 93.10usft (HEC 169) Measured Depth Reference:As-Built RKB @ 93.10usft (HEC 169) Calculation Method:Minimum Curvature Project:Beluga River Site:Beluga River Well:Plan: BRU 212-26 Wellbore:BRU 212-26 Design:BRU 212-26 wp04 Beluga River Beluga River Plan: BRU 212-26 BRU 212-26 BRU 212-26 wp04 5.671 CASING DETAILS TVD TVDSS MD Size Name 2065.67 1972.57 2750.00 9-5/8 9 5/8" x 12 1/4" 7093.10 7000.00 8347.11 5-1/2 5 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 250' MD, 250'TVD 3 1629.60 55.18 16.11 1425.98 590.44 170.57 4.00 16.11 614.56 End Dir : 1629.6' MD, 1425.98' TVD 4 3443.64 55.18 16.11 2461.69 2021.24 583.90 0.00 0.00 2103.82 Start Dir 3º/100' : 3443.64' MD, 2461.69'TVD 5 4285.44 30.00 19.00 3076.50 2560.97 751.03 3.00 176.62 2668.80 BRU 212-26 tgt1 6 5285.44 0.00 0.00 4031.43 2802.90 834.33 3.00 180.00 2924.44 End Dir : 5285.44' MD, 4031.43' TVD 7 8347.11 0.00 0.00 7093.10 2802.90 834.33 0.00 0.00 2924.44 BRU 212-26 TD Total Depth : 8347.11' MD, 7093.1' TVD -400 -200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 South(-)/North(+) (400 usft/in)-1000 -800 -600 -400 -200 0 200 400 600 800 1000 1200 1400 1600 West(-)/East(+) (400 usft/in) BRU 212-26 TD BRU 212-26 tgt1 9 5/8" x 12 1/4" 5 1/2" x 8 1/2" 250 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 7093 BRU 212-26 wp04 Start Dir 4º/100' : 250' MD, 250'TVD End Dir : 1629.6' MD, 1425.98' TVD Start Dir 3º/100' : 3443.64' MD, 2461.69'TVD End Dir : 5285.44' MD, 4031.43' TVD Total Depth : 8347.11' MD, 7093.1' TVD CASING DETAILS TVD TVDSS MD Size Name 2065.67 1972.57 2750.00 9-5/8 9 5/8" x 12 1/4" 7093.10 7000.00 8347.11 5-1/2 5 1/2" x 8 1/2" Project: Beluga River Site: Beluga River Well: Plan: BRU 212-26 Wellbore: BRU 212-26 Plan: BRU 212-26 wp04 WELL DETAILS: Plan: BRU 212-26 75.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2625964.52 318343.38 61° 11' 0.667 N 151° 1' 45.665 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 212-26, True North Vertical (TVD) Reference:As-Built RKB @ 93.10usft (HEC 169) Measured Depth Reference:As-Built RKB @ 93.10usft (HEC 169) Calculation Method:Minimum Curvature -233 0 233 467 700 933 1167 1400 1633 1867 2100 2333 2567 2800 3033 South(-)/North(+) (350 usft/in)-467 -233 0 233 467 700 933 1167 1400 1633 1867 West(-)/East(+) (350 usft/in) 20040060 08001000120014001600180020002200240026002800300032003 4 0 0 360 0 3800 4000 4200 4400 4600 4800 5000 5200 5400 5 6 0 0 5 8 0 0 6 0 0 0 6 1 4 2 BRU 214-26 20040060 08001000120014001600180020002200240026002800300032003400360038004000420044004450BRU 214-26PB1 9 5/8" x 12 1/4" 5 1/2" x 8 1/2" 200400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200440046004800500052005400560058006000620064006600680070007093 BRU 212-26 wp04 Azimuths to True North Magnetic North: 15.64° Magnetic Field Strength: 55361.6nT Dip Angle: 74.00° Date: 8/4/2020 Model: BGGM2020 T MProject: Beluga River Site: Beluga River Well: Plan: BRU 212-26 Wellbore: BRU 212-26 Plan: BRU 212-26 wp04 -100 0 100 West(-)/East(+) (150 usft/in) 0 100 South(-)/North(+) (150 usft/in)5 0 0 1000BRU 214-26 500 BRU 212-26 wp04 BRU 212-26 wp04 & # ' ( " # ) *+, ) - . . - %(# /0 !"" #$%&' ( )*+ %, , $ -(. ,- /01 2 / 3 /, ) #$%&' ( )*+ %, 1 0 ) 4 1 / ( ' 2 ,' & / 3 ( ',' % 5*+6 , / 3 % 5*/ 30/0/ , 7(. 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eparation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthNo-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: BRU 212-26 NAD 1927 (NADCON CONUS)Alaska Zone 0475.10+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002625964.52 318343.38 61° 11' 0.667 N151° 1' 45.665 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 212-26, True NorthVertical (TVD) Reference:As-Built RKB @ 93.10usft (HEC 169)Measured Depth Reference:As-Built RKB @ 93.10usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-06-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 2750.00 BRU 212-26 wp04 (BRU 212-26) 3_MWD+AX+Sag2750.00 8347.11 BRU 212-26 wp04 (BRU 212-26) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthBRU 214-26BRU 214-26PB1GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 8347.11Project: Beluga RiverSite: Beluga RiverWell: Plan: BRU 212-26Wellbore: BRU 212-26Plan: BRU 212-26 wp04Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name2065.67 1972.57 2750.00 9-5/8 9 5/8" x 12 1/4"7093.10 7000.00 8347.11 5-1/2 5 1/2" x 8 1/2" 16.0 Run 5-1/2” Production Liner 16.1. R/U Weatherford 5-1/2” casing running equipment. xx Ensure 5-1/2” CDC HTQ 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 (coupling also thread locked). 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 5-1/2” 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 across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 9-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 5-1/2” production liner per plan. 5-1/2” TXP BTC M/U torques Casing OD Minimum Maximum Yield Torque 5-1/2” 9,740 ft-lbs 11,900 ft-lbs 16,500 ft-lbs 16.6. Run in hole w/ 5-1/2” liner to the 9-5/8” 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 5-1/2” X 9-5/8” 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 of the casing. 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 casing 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. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 1 Carlisle, Samantha J (CED) From:Frank Roach <Frank.Roach@hilcorp.com> Sent:Wednesday, August 12, 2020 10:37 AM To:Schwartz, Guy L (CED) Cc:Monty Myers Subject:RE: Proposed changes to (PTD 220-052) BRU 241-34T and (PTD 220-058) BRU 212-26 Attachments:BRU 5.5in Production Liner Running Contingency.docx Mr.Schwartz, Aswediscussedthismorningoverthephone,pleaseseetheattachedcontingencyprocedureforrunninglinerinthe twoBelugawellsreferencedintheemailsubject. Linerhanger/linertoppackerdepthistomatchtheoriginallyplannedswellpackerplacementsoastokeepthe cementingvolumesconsistent. Letmeknowifyouneedanyadditionalinformation. Regards, FrankVRoach DrillingEngineer 907.854.2321(c) 907.777.8413(o) From:MontyMyers Sent:Tuesday,August11,202011:30 To:'guy.schwartz@alaska.gov'<guy.schwartz@alaska.gov> Cc:FrankRoach<Frank.Roach@hilcorp.com> Subject:Proposedchangesto(PTD220Ͳ052)BRU241Ͳ34Tand(PTD220Ͳ058)BRU212Ͳ26 GoodmorningGuy, Withtherecenteventswe’vehadwithlosscirculationonBRU241Ͳ34TandapoorlookingCBLonBRU222Ͳ24,Iwould liketoproposechangingourproductionsstringsfromlongstringstolinerswithtiebackstosurfaceonour2remaining BelugaRiverwells.Thedepths,directionalplans,andpipeallremainthesame.Nowwewillhavetheabilityto: x Rotatethepipeduringourcementjobwhichiscriticaltogettinggoodbondandcementplacement. x Allowustopumpadditionalcementupinsidethesurfaceshoethencirculateitouttoleaveagoodtestable annulus x Runapackeronourlinertoptoalsoachieveagoodtestableannulus. Doyouhaveanyissueswithuschangingtheproceduretorunalinerwithatiebackvs.runningthelongstringonthese 2wells. MontyMMyers DrillingManager 907.538.1168(c) 2 907.777.8431(o) 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. Updated by FVR 8.12.2020 PROPOSED SCHEMATIC Beluga River Unit BRU 212-26 PTD: TBD API: TBD PBTD = 8,267’ MD/ TVD = 7,013’ TD = 8,347’ MD / TVD = 7,093’ 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 138' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,732’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” ~2,500’ 8,347’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf ~2,500’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~2,500’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 ~2,500’ 6.180” 7.010” Baker tieback Seal Assembly OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – Returns to surface (50% excess) 5-1/2” 194 BBL’s of cement in 8-1/2” hole. Est. TOC @ TOL – ~2,500’ (10% excess) 8-1/2” hole WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 212-26Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200580BELUGA RIVER, UNDEFINED GAS - 92500NA1 Permit fee attachedYes Entire well in Federal lease A029657.2 Lease number appropriateYes3 Unique well name and numberNo BELUGA RIVER, UNDEFINED GAS - 92500, governed by statewide rules.4 Well located in a defined poolNo SPACING EXCEPTION REQUIRED: Well does not conform with 20 AAC 25.055;5 Well located proper distance from drilling unit boundaryNo will lie in the same governmental section as, and within 3,000' of, nearby6 Well located proper distance from other wellsNo open wells BRU 214-26, BRU 232-26, and BRU 211-26.7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedNo9 Operator only affected partyYes10 Operator has appropriate bond in forceNo If PTD is approved prior to CO approval, strongly recommend adding "Full11 Permit can be issued without conservation orderYes Compliance with 20 ACC 25.055" condition to approval letter. SFD 7/13/202012 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 sNA15 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 providedYes Surface casing will be set and fully cemented from 2750' MD19 Surface casing protects all known USDWsYes 56% excess cement20 CMT vol adequate to circulate on conductor & surf csgYes 5-1/2" casing will be cemented up into the 9-5/8" surface casing21 CMT vol adequate to tie-in long string to surf csgYes (contingency to run liner and tieback is in PTD package. )22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Rig 169 has steel tanks. All waste to be transported to the KGF disposal wells.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues with close crossings26 Adequate wellbore separation proposedYes 16" diverter provided on Rig 169. Diverter route meets regulation27 If diverter required, does it meet regulationsYes Max formation pressure is 2730 psig(8.1 ppg EMW); will drill w/ 9.0-10.0 ppg EMW28 Drilling fluid program schematic & equip list adequateYes Rig 169 has 13-5/8" 5000# working pressure BOP29 BOPEs, do they meet regulationYes MPSP is 2080 psig; will test BOPs to 3500 psig30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes Sundry required to perforate well ( need MIT-IA and CBL before perfing)32 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 is not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Maximum expected reservoir pressure is 8.6 ppg EMW; however, most sands encountered are expected36 Data presented on potential overpressure zonesNA to be depleted to severely depleted. LCM materials will also be available onsite. Production interval37 Seismic analysis of shallow gas zonesNA will be drilled using 9.0 to 10.0 ppg mud. Additional materials will be onsite to build38 Seabed condition survey (if off-shore)NA mud to 1 ppg more than the greatest anticipated mud weight.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/13/2020ApprGLSDate8/12/2020ApprSFDDate7/8/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateSPACING EXCEPTION REQUIRED before Permit to Drill can be issued. May run a liner and tieback if well conditions warranet vs cement packer/swell pack completion as a contingency. GlsJMP8/12/2020JLC 8/12/2020
