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Home My WebLink About220-052Nolan 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: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/24/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251024 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BR 11-86 (REVISED) 50733207370000 225057 8/1/2025 HALLIBURTON RMT3D BRU 241-34T 50283201810000 220052 9/23/2025 AK E-LINE Perf END 2-36 50029220140000 190024 10/13/2025 READ Caliper Survey MPI 2-72 50029237810000 224016 10/2/2025 AK E-LINE Patch MPU I-01 50029220650000 190090 9/25/2025 AK E-LINE Punch MPU J-08A 50029224970100 199117 10/22/2025 HALLIBURTON COILFLAG MPU R-109 50029238220000 225073 9/24/2025 YELLOWJACKET SCBL NCIU A-06A 50883200260100 225071 9/25/2025 AK E-LINE CBL NCIU A-06A 50883200260100 225071 9/26/2025 AK E-LINE Perf PBU A-24B 50029207430200 225067 10/20/2025 HALLIBURTON RBT PBU GC-2E 50029227400000 197018 10/21/2025 HALLIBURTON TEMP PBU W-35A 50029217990200 225076 10/10/2025 HALLIBURTON RBT SP-03-NE2 50629236390000 219089 9/25/2025 AK E-LINE Caliper Please include current contact information if different from above. T41022 T41023 T41024 T41025 T41026 T41027 T41028 T41029 T41029 T41030 T41031 T41032 T41033 BRU 241-34T 50283201810000 220052 9/23/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.24 13:32:55 -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: ___________________ 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): 5,865' 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 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 Baker ZXP Pkr; N/A 2,568' MD/2,560' TVD; N/A; N/A ~5,852 5,233' 5,221' Beluga River Sterling-Beluga Gas 16" 9-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 241-34TCO 802A Same 2,560'5-1/2" ~1643 psi 2,568' 5233, 5520' Length October 14, 2025 5,864'3,304' Tieback 5-1/2" 5,852' 2,568' Perforation Depth MD (ft): 5-/12" See Attached Schematic 2,980psi 5,750psi 138'138' 2,732' Size 138' 2,732' MD Hilcorp Alaska, LLC Proposed Pools: 17# / P110 TVD Burst 2,568' 10,600psi 2,723' 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 220-052 50-283-20181-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 10,600psi Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 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 October 30, 2025 325-639 By Gavin Gluyas at 11:25 am, Oct 16, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.10.15 17:11:28 - 08'00' Noel Nocas (4361) DSR-10/16/25BJM 10/20/25 10-404 A.Dewhurst 23OCT25 10/23/25 Well Prognosis update 1 Well Name: BRU 241-34T API Number: 50-283-20181-00-00 Current Status: Gas Producer Permit to Drill Number: 220-052 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: 1766 psi @ 4107 TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1643 psi (Based on 0.03 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.707 psi/ft using 13.59 ppg EMW FIT at the Surface shoe (2733ft) Shallowest Allowable Perf TVD: MPSP/(0.707-0.03) = 1643 psi / 0.677 = 2,426 TVD Top of SBGP (CO 802A): ~2,798 MD/ ~2,789 TVD Change of Program BRU 241-34T has an open sundry for adding perfs. We would like to keep adding perfs on that sundry in the Beluga D Sands. Current Wellbore Conditions: Flowing at ~1991mcf @ 191 psi with 5 bwpd 5-1/2 TOC @ ~3480 from CBL 8-20-20 No restrictions, minimum ID is 4.892 production liner Procedure 1. RU E-line, PT lubricator to 250/2000 psi 2. Perforate Beluga sands within the below intervals: 3. Return well to production Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Formation MD TOP MD BASE TVD TOP TVD BASE H Top Pool ~2,798 ~2,789' Beluga D ±3,568 ±3,571 ±3,556 ±3,559 ±3 Beluga D1 ±3,586 ±3,602 ±3,574 ±3,590 ±16 Beluga D3 ±3,627 ±3,653 ±3,630 ±3,641 ±26 Beluga D4 ±3,668 ±3,676 ±3,656 ±3,664 ±8 Beluga D5 ±3,697 ±3,703 ±3,685 ±3,691 ±6 Beluga D6 ±3,725 ±3,743 ±3,713 ±3,731 ±18 Updated by CAH 10-05-25 Page 2 of 2 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,233 MD / TVD = 5,221 TD = 5,865 MD / TVD = 5,852 RKB to GL = 19.8 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 TUBING DETAIL 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892 2,560 5,864 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892 Surf 2,568 1/2 16 9-5/8 12-1/4 hole 5-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,560 6.170 8.430 Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568 6.180 7.700 Baker tieback Seal Assembly, 2.92 off No-Go 3 5,233 - 5.500 CIBP 9/20/2020 4 5,520 CIBP 9/11/2020 OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBLs of cement in 12-1/4 hole 53 bbls returned to surface 5-1/2 152 BBLs of cement in 8-1/2 hole. TOC 3,480 CBL 8-1/2 hole Bel G3-G10 Bel H10 Bel H12-H15 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt SPF Date Status Top of Pool (CO 802A): 2,798 MD; 2,789 TVD BEL E 3,772' 3,784' 3,760' 3,772' 12' 2-3/4 9/24/25 Open BEL E1 3,798' 3,815' 3,786' 3,803' 17' 2-3/4 9/24/25 Open BEL E3 3,947' 3,952' 3,935 3,940 5' 2-3/4 9/24/25 Open BEL E5 3,992' 3,996' 3,980 3,984 4' 2-3/4 9/24/25 Open BEL E6 4,072' 4,077' 4,060' 4,065' 5' 2-3/4 9/23/25 Open BEL E6 4,094' 4,108' 4,082' 4,096' 14' 2-3/4 9/23/25 Open BEL E6 4,112' 4,116' 4,100' 4,104' 4' 2-3/4 9/23/25 Open BEL E6 4,119' 4,132' 4,107' 4,120' 13' 2-3/4 9/23/25 Open BEL E6 4,135' 4,147' 4,123' 4,135' 12' 2-7/8 8/4/2021 Open BEL F4 4,222' 4,233' 4,210' 4,221' 11' 2-7/8 8/4/2021 Open BEL F4 4,272' 4,279' 4,260' 4,267' 7' 2-7/8 8/4/2021 Open BEL F6 4,346' 4,363' 4,334' 4,351' 17' 2-7/8 8/2/2021 Open BEL F6 4,383' 4,391' 4,370' 4,378' 8' 2-7/8 8/2/2021 Open BEL F7 4,568' 4,583' 4,556 4,571 15' 2-7/8 9/24/2020 Open BEL G3 4,738' 4,777' 2,726 4,765 39' 2-7/8 9/24/2020 Open BEL G5 4,846' 4,851' 4,834 4,839 5' 2-7/8 9/7/2021 Open BEL G5 4,865' 4,870' 4,853 4,858 5' 2-7/8 9/7/2021 Open BEL G5 4,879' 4,884' 4,866 4,871 5' 2-7/8 9/7/2021 Open BEL G6 4,905' 4,914' 4,893 4,902 9' 2-7/8 9/7/2021 Open PERFORATION DETAIL Continued on Following Page 3 4 Bel E6 Bel F4-F7 Bel H-H2 5-1/2 TOC @ 3480 (8/20/220 CBL) EL Tag @ 5082 2/11/23 Bel E Updated by CAH 10-05-25 Page 2 of 2 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PERFORATION DETAIL Continued from Previous Page Sand Top MD Btm MD Top TVD Btm TVD Amt SPF Date Status BEL G8 4,947' 4,949' 4,935 4,937 2' 2-7/8 9/6/2021 Open BEL G8 4,962' 4,966' 4,950 4,954 4' 2-7/8 9/7/2021 Open BEL G9 4,979' 4,988' 4,966 4,975 9' 2-7/8 9/6/2021 Open BEL G9 4,991' 4,996' 4,979 4,984 5' 2-7/8 9/6/2021 Open BEL G10 5,025' 5,046' 5,010 5,033 21' 2-7/8 9/6/2021 Open BEL H 5,057' 5,064' 5,045 5,052 7' 2-7/8 9/6/2021 Open BEL H 5,077' 5,082' 5,065 5,070 5' 2-7/8 9/6/2021 Open BEL H2 5,143' 5,161' 5,131 5,149 18' 2-7/8 9/24/2020 Open BEL H10 5,477' 5,510' 5,465 5,498 33' 3-3/8 / 6 SPF 8/31/2020 Isolated BEL H10 5,477' 5,510' 5,465 5,498 33' 3-3/8 / 6 SPF 9/12/2020 Isolated BEL H12 5,537' 5,563' 5,525 5,551 26' 2-7/8 9/1/2020 Isolated BEL H13 5,563' 5,602' 5,551 5,590 39' 2-7/8 9/1/2020 Isolated BEL H14 5,698' 5,707' 5,686 5,695 9' 2-7/8 9/1/2020 Isolated BEL H15 5,732' 5,756' 5,720 5,744 24' 2-7/8 9/1/2020 Isolated Updated by CAH 10-05-25 Page 2 of 2 PROPOSED Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,233 MD / TVD = 5,221 TD = 5,865 MD / TVD = 5,852 RKB to GL = 19.8 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 TUBING DETAIL 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892 2,560 5,864 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892 Surf 2,568 1/2 16 9-5/8 12-1/4 hole 5-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,560 6.170 8.430 Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568 6.180 7.700 Baker tieback Seal Assembly, 2.92 off No-Go 3 5,233 - 5.500 CIBP 9/20/2020 4 5,520 CIBP 9/11/2020 OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBLs of cement in 12-1/4 hole 53 bbls returned to surface 5-1/2 152 BBLs of cement in 8-1/2 hole. TOC 3,480 CBL 8-1/2 hole Bel G3-G10 Bel H10 Bel H12-H15 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt SPF Date Status Top of Pool (CO 802A): 2,798 MD; 2,789 TVD BEL D ±3,568' ±3,571' ±3,556' ±3,559' ±3' Proposed TBD BEL D1 ±3,586' ±3,602' ±3,574' ±3,590' ±16' Proposed TBD BEL D3 ±3,627' ±3,653' ±3,630' ±3,641' ±26' Proposed TBD BEL D4 ±3,668' ±3,676' ±3,656' ±3,664' ±8' Proposed TBD BEL D5 ±3,697' ±3,703' ±3,685' ±3,691' ±6' Proposed TBD BEL D6 ±3,725' ±3,743' ±3,713' ±3,731' ±18' Proposed TBD BEL E 3,772' 3,784' 3,760' 3,772' 12' 2-3/4 9/24/25 Open BEL E1 3,798' 3,815' 3,786' 3,803' 17' 2-3/4 9/24/25 Open BEL E3 3,947' 3,952' 3,935 3,940 5' 2-3/4 9/24/25 Open BEL E5 3,992' 3,996' 3,980 3,984 4' 2-3/4 9/24/25 Open BEL E6 4,072' 4,077' 4,060' 4,065' 5' 2-3/4 9/23/25 Open BEL E6 4,094' 4,108' 4,082' 4,096' 14' 2-3/4 9/23/25 Open BEL E6 4,112' 4,116' 4,100' 4,104' 4' 2-3/4 9/23/25 Open BEL E6 4,119' 4,132' 4,107' 4,120' 13' 2-3/4 9/23/25 Open BEL E6 4,135' 4,147' 4,123' 4,135' 12' 2-7/8 8/4/2021 Open BEL F4 4,222' 4,233' 4,210' 4,221' 11' 2-7/8 8/4/2021 Open BEL F4 4,272' 4,279' 4,260' 4,267' 7' 2-7/8 8/4/2021 Open BEL F6 4,346' 4,363' 4,334' 4,351' 17' 2-7/8 8/2/2021 Open BEL F6 4,383' 4,391' 4,370' 4,378' 8' 2-7/8 8/2/2021 Open BEL F7 4,568' 4,583' 4,556 4,571 15' 2-7/8 9/24/2020 Open BEL G3 4,738' 4,777' 2,726 4,765 39' 2-7/8 9/24/2020 Open BEL G5 4,846' 4,851' 4,834 4,839 5' 2-7/8 9/7/2021 Open BEL G5 4,865' 4,870' 4,853 4,858 5' 2-7/8 9/7/2021 Open BEL G5 4,879' 4,884' 4,866 4,871 5' 2-7/8 9/7/2021 Open BEL G6 4,905' 4,914' 4,893 4,902 9' 2-7/8 9/7/2021 Open PERFORATION DETAIL Continued on Following Page 3 4 Bel E6 Bel F4-F7 Bel H-H2 5-1/2 TOC @ 3480 (8/20/220 CBL) EL Tag @ 5082 2/11/23 Bel E Bel D Updated by CAH 10-05-25 Page 2 of 2 PROPOSED Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PERFORATION DETAIL Continued from Previous Page Sand Top MD Btm MD Top TVD Btm TVD Amt SPF Date Status BEL G8 4,947' 4,949' 4,935 4,937 2' 2-7/8 9/6/2021 Open BEL G8 4,962' 4,966' 4,950 4,954 4' 2-7/8 9/7/2021 Open BEL G9 4,979' 4,988' 4,966 4,975 9' 2-7/8 9/6/2021 Open BEL G9 4,991' 4,996' 4,979 4,984 5' 2-7/8 9/6/2021 Open BEL G10 5,025' 5,046' 5,010 5,033 21' 2-7/8 9/6/2021 Open BEL H 5,057' 5,064' 5,045 5,052 7' 2-7/8 9/6/2021 Open BEL H 5,077' 5,082' 5,065 5,070 5' 2-7/8 9/6/2021 Open BEL H2 5,143' 5,161' 5,131 5,149 18' 2-7/8 9/24/2020 Open BEL H10 5,477' 5,510' 5,465 5,498 33' 3-3/8 / 6 SPF 8/31/2020 Isolated BEL H10 5,477' 5,510' 5,465 5,498 33' 3-3/8 / 6 SPF 9/12/2020 Isolated BEL H12 5,537' 5,563' 5,525 5,551 26' 2-7/8 9/1/2020 Isolated BEL H13 5,563' 5,602' 5,551 5,590 39' 2-7/8 9/1/2020 Isolated BEL H14 5,698' 5,707' 5,686 5,695 9' 2-7/8 9/1/2020 Isolated BEL H15 5,732' 5,756' 5,720 5,744 24' 2-7/8 9/1/2020 Isolated 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:Dewhurst, Andrew D (OGC) To:Chad Helgeson Cc:Donna Ambruz; McLellan, Bryan J (OGC); AOGCC Records (CED sponsored) Subject:RE: BRU 241-34T (PTD# 22-052) Sundry # 325-120 Additional Perfs Date:Monday, September 22, 2025 1:49:42 PM Chad, The additional perforated zone is approved. This email is sufficient documentation. Andy From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Monday, 22 September, 2025 10:24 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: BRU 241-34T (PTD# 22-052) Sundry # 325-120 Additional Perfs Bryan/Andrew, Hilcorp would like to add the additional perfs in BRU 241-34T on approved sundry # 325-120. The highlighted perfs are the new perfs that we would like to add to the existing approved perf table. LABEL SAND MD TOP MD BASE TVD TOP TVD BASE PERF TYPE FOOTAGE BRU 241- 34T TOP POOL 2798 2789 Beluga E 3,772 3,784 3,760 3,772 PROPOSED 12 Beluga E1 3,798 3,815 3,786 3,803 PROPOSED 17 Beluga E1 3,841 3,847 3,829 3,835 PROPOSED 6 Beluga E3 3,947 3,952 3,935 3,940 PROPOSED 5 Beluga E5 3,992 3,996 3,980 3,984 PROPOSED 4 Beluga E6 4,072 4,077 4,060 4,065 PROPOSED 5 Beluga E6 4,094 4,108 4,082 4,096 PROPOSED 14 Beluga E6 4,112 4,116 4,100 4,104 PROPOSED 4 Beluga E6 4,119 4,132 4,107 4,120 PROPOSED 13 Please let us know if we are approved to add these perfs. 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 anydissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us byreturn 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 bythe 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? 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): 5,865'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 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 Baker ZXP Pkr; N/A 2,568' MD/2,560' TVD; N/A; N/A ~5,852 5,233'5,221' Beluga River Sterling-Beluga Gas 16" 9-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 241-34TCO 802A Same 2,560'5-1/2" ~1643 psi 2,568' 5233, 5520' Length April 10, 2025 5,864'3,304' Tieback 5-1/2" 5,852' 2,568' Perforation Depth MD (ft): 5-/12" See Attached Schematic 2,980psi 5,750psi 138'138' 2,732' Size 138' 2,732' MD Hilcorp Alaska, LLC Proposed Pools: 17# / P110 TVD Burst 2,568' 10,600psi 2,723' 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 220-052 50-283-20181-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 10,600psi Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 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 325-120 By Gavin Gluyas at 8:20 am, Mar 03, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.02.28 10:43:26 - 09'00' Noel Nocas (4361) BJM 3/18/25 DSR-3/10/25A.Dewhurst 05MAR25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.19 10:23:26 -08'00'03/19/25 RBDMS JSB 032125 Well Prognosis Well Name: BRU 241-34T API Number: 50-283-20181-00-00 Current Status: Gas Producer Permit to Drill Number: 220-052 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: 1766 psi @ 4107’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1643 psi (Based on 0.03 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.707 psi/ft using 13.59 ppg EMW FIT at the Surface shoe (2733ft) Shallowest Allowable Perf TVD: MPSP/(0.707-0.03) = 1643 psi / 0.677 = 2,426‘ TVD Top of SBGP (CO 802A): ~2,798’ MD/ ~2,789’ TVD Brief Well Summary BRU 241-34T was drilled in 2020 as a replacement well for the original BRU 241-34. It is a 5-1/2” completion through the Beluga and the Sterling. Initially perforated 5 lower H sands with subpar results in early September 2020. After isolating the lower sands, came back and perforated the H2, G3, and F7 and the well came online making 6.4 MMCFD. The E sands have been tested in nearby wells and determined low risk perf adds. Objective: The purpose of this work/sundry is to increase production by adding additional perforations in the Beluga E sands. All sands lie in the BRU SBGP. Wellbore Conditions: x Flowing at ~1884mcf @ 91 psi with 5 bwpd x 5-1/2” TOC @ ~3480’ from CBL 8-20-20 x No restrictions, minimum ID is 4.892” production liner Procedure 1. RU E-line, PT lubricator to 250/2000 psi 2. Perforate Beluga sands within the below intervals with the well shut-in: 3. Return well to production Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Formation MD TOP MD BASE TVD TOP TVD BASE H Top Pool ~2,798’ ~2,789' Beluga E ±3,772’ ±3,784‘ ±3,760’ ±3,772’ ±12 Beluga E1 ±3,806’ ±3,815’ ±3,794’ ±3,803’ ±9 Beluga E3 ±3,947’ ±3,952’ ±3,935’ ±3,940’ ±5 Beluga E5 ±3,992’ ±3,996’ ±3,980’ ±3,984’ ±4 Beluga E6 ±4,072’ ±4,077’ ±4,060’ ±4,065’ ±5 Beluga E6 ±4,094’ ±4,108’ ±4,082’ ±4,096’ ±14 Beluga E6 ±4,112’ ±4,132’ ±4,100’ ±4,120’ ±20 Updated by CAH 02-27-25 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,233 MD / TVD = 5,221’ TD = 5,865’ MD / TVD = 5,852’ RKB to GL = 19.8 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’ TUBING DETAIL 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,560’ 5,864’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly, 2.92’ off No-Go 3 5,233’ - 5.500” CIBP 9/20/2020 4 5,520’ CIBP 9/11/2020 OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G3-G10 Bel H10 Bel H12-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD Date Size Status Beluga E6 4,135' 4,147' 4,123' 4,135' 8/4/2021 2-7/8” Open Beluga F4 4,222' 4,233' 4,210' 4,221' 8/4/2021 2-7/8” Open 4,272' 4,279' 4,260' 4,267' 8/4/2021 2-7/8” Open Beluga F6 4,346' 4,363' 4,334' 4,351' 8/2/2021 2-7/8” Open 4,383' 4,391' 4,370' 4,378' 8/2/2021 2-7/8” Open Beluga F7 4,568' 4,583' 4,556’ 4,571’ 9/24/2020 2-7/8” Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 9/24/2020 2-7/8” Open Beluga G5 4,846’ 4,851’ 4,834’ 4,839’ 9/7/2021 2-7/8” Open 4,865’ 4,870’ 4,853’ 4,858’ 9/7/2021 2-7/8” Open 4,879’ 4,884’ 4,866’ 4,871’ 9/7/2021 2-7/8” Open Beluga G6 4,905’ 4,914’ 4,893’ 4,902’ 9/7/2021 2-7/8” Open Beluga G8 4,947’ 4,949’ 4,935’ 4,937’ 9/6/2021 2-7/8” Open 4,962’ 4,966’ 4,950’ 4,954’ 9/7/2021 2-7/8” Open Beluga G9 4,979’ 4,988’ 4,966’ 4,975’ 9/6/2021 2-7/8” Open 4,991’ 4,996’ 4,979’ 4,984’ 9/6/2021 2-7/8” Open Beluga G10 5,025’ 5,046’ 5,010’ 5,033’ 9/6/2021 2-7/8” Open Beluga H 5,057’ 5,064’ 5,045’ 5,052’ 9/6/2021 2-7/8” Open 5,077’ 5,082’ 5,065’ 5,070’ 9/6/2021 2-7/8” Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 9/24/2020 2-7/8” Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 8/31/2020 3-3/8” / 6 SPF Isolated 5,477' 5,510' 5,465’ 5,498’ 9/12/2020 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 9/1/2020 2-7/8” Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 9/1/2020 2-7/8” Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9/1/2020 2-7/8” Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 9/1/2020 2-7/8” Isolated 3 4 Bel E6 Bel F4-F7 Bel H-H2 5-1/2” TOC @ 3480’ (8/20/220 CBL) Updated by CAH 02-27-25 PROPOSED Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,233 MD / TVD = 5,221’ TD = 5,865’ MD / TVD = 5,852’ RKB to GL = 19.8 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’ TUBING DETAIL 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,560’ 5,864’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly, 2.92’ off No-Go 3 5,233’ - 5.500” CIBP 9/20/2020 4 5,520’ CIBP 9/11/2020 OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G3-G10 Bel H10 Bel H12-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD Date Size Status Top of Pool (CO 802A): 2798’ MD; 2789’ TVD Beluga E ±3,772’ ±3,784‘ ±3,760’ ±3,772’ TBD 2-3/4” Proposed Beluga E1 ±3,806’ ±3,815’ ±3,794’ ±3,803’ TBD 2-3/4” Proposed Beluga E3 ±3,947’ ±3,952’ ±3,935’ ±3,940’ TBD 2-3/4” Proposed Beluga E5 ±3,992’ ±3,996’ ±3,980’ ±3,984’ TBD 2-3/4” Proposed Beluga E6 ±4,072’ ±4,077’ ±4,060’ ±4,065’ TBD 2-3/4” Proposed Beluga E6 ±4,094’ ±4,108’ ±4,082’ ±4,096’ TBD 2-3/4” Proposed Beluga E6 ±4,112’ ±4,132’ ±4,100’ ±4,120’ TBD 2-3/4” Proposed Beluga E6 4,135' 4,147' 4,123' 4,135' 8/4/2021 2-7/8” Open Beluga F4 4,222' 4,233' 4,210' 4,221' 8/4/2021 2-7/8” Open 4,272' 4,279' 4,260' 4,267' 8/4/2021 2-7/8” Open Beluga F6 4,346' 4,363' 4,334' 4,351' 8/2/2021 2-7/8” Open 4,383' 4,391' 4,370' 4,378' 8/2/2021 2-7/8” Open Beluga F7 4,568' 4,583' 4,556’ 4,571’ 9/24/2020 2-7/8” Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 9/24/2020 2-7/8” Open Beluga G5 4,846’ 4,851’ 4,834’ 4,839’ 9/7/2021 2-7/8” Open 4,865’ 4,870’ 4,853’ 4,858’ 9/7/2021 2-7/8” Open 4,879’ 4,884’ 4,866’ 4,871’ 9/7/2021 2-7/8” Open Beluga G6 4,905’ 4,914’ 4,893’ 4,902’ 9/7/2021 2-7/8” Open Beluga G8 4,947’ 4,949’ 4,935’ 4,937’ 9/6/2021 2-7/8” Open 4,962’ 4,966’ 4,950’ 4,954’ 9/7/2021 2-7/8” Open Beluga G9 4,979’ 4,988’ 4,966’ 4,975’ 9/6/2021 2-7/8” Open 4,991’ 4,996’ 4,979’ 4,984’ 9/6/2021 2-7/8” Open Beluga G10 5,025’ 5,046’ 5,010’ 5,033’ 9/6/2021 2-7/8” Open Beluga H 5,057’ 5,064’ 5,045’ 5,052’ 9/6/2021 2-7/8” Open 5,077’ 5,082’ 5,065’ 5,070’ 9/6/2021 2-7/8” Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 9/24/2020 2-7/8” Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 8/31/2020 3-3/8” / 6 SPF Isolated 5,477' 5,510' 5,465’ 5,498’ 9/12/2020 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 9/1/2020 2-7/8” Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 9/1/2020 2-7/8” Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9/1/2020 2-7/8” Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 9/1/2020 2-7/8” Isolated 3 4 Bel E6 Bel F4-F7 Bel H-H2 5-1/2” TOC @ 3480’ (8/20/220 CBL) EL Tag @ 5082’ 2/11/23 Bel E 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: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 241-34T (PTD 220-052) Completion Record Perf 09/07/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/19/2021 By Abby Bell at 10:57 am, Oct 19, 2021 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: 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: Total Depth measured 5,865 feet 5233', 5520' feet true vertical 5,852 feet N/A feet Effective Depth measured 5,233 feet 2,560 feet true vertical 5,221 feet 2,552 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic P Tieback 5-1/2" 17# / P110 2,568' MD 2,560' TVD Tubing (size, grade, measured and true vertical depth)P Liner 5-1/2" 17# / P110 5,864' MD 5,852' TVD Packers and SSSV (type, measured and true vertical depth)Baker ZXP Pkr; N/A 2,560' MD 2,552' 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 1,756 Water-Bbl MD 138' 2,732' 5,864' 0 Oil-Bbl measured true vertical Packer 5-1/2" 5-1/2" 2,568'2,560' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beluga River Unit / Beluga River Undefined GasN/A measured TVD Tubing Pressure 1060 Beluga River Unit (BRU) 241-34T N/A FEDA029657 Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-052 50-283-20181-00-00 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. 321-357 & 321-434 313 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 470 Authorized Signature with date: Authorized Name: 515 Casing Pressure Production Liner 3,304' 4,040 5,852' 0 Representative Daily Average Production or Injection Data 138' 2,732' 2,568' Conductor Surface Intermediate Production Tieback 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' 2,723' 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 2:27 pm, Sep 10, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.10 14:06:45 -08'00' Taylor Wellman (2143) BJM 11/4/21 DSR-9/13/21 RBDMS HEW 9/10/2021 SFD 9/10/2021 Rig Start Date End Date E-Line 7/30/21 9/7/21 09/05/2021 - Sunday AK E-line MIRU. Verify number of perforating guns and dimensions. Continue to RU. Re-dress wireline valve. Remove multi-line seal and insert 0.25" cable sized seal. 09/06/2021 - Monday Install wireline valves on swab and pressure test with test rod. Finish RU and PT lubricator to 250 psi low / 2,500 psi high. MU and RIH with 2-7/8" x 2' gun. GR/CCL to Top Shot = 15.3'. Tag fill at 5,070' (uncorrected). Move uphold to shoot another zone. Send correlation data to RE/GEO. Shift up 7'. Perforate with well flowing - Beluga G8 4,947' - 4,949'. Shots fired. Gun dry. MU and RIH with 2-7/8" x 5' gun. GR/CCL to Top Shot = 9.0'. Send correlation data to RE/GEO. Shift up 1'. Perforate with well flowing - Beluga H 5,077' - 5,082'. Shots fired. Sand in bull plug. MU and RIH with 2-7/8" x 7' gun. GR/CCL to Top Shot = 11.1'. Send correlation data to RE/GEO. on depth. Perforate with well flowing - Beluga H 5,057' - 5,064'. Shots fired. Gun dry. MU and RIH with 2-7/8" x 21' gun. GR/CCL to Top Shot = 7.8'. Send correlation data to RE/GEO. Shift up 2'. Perforate with well flowing - Beluga G10 5,025' - 5,046'. MU and RIH with 2-7/8" x 5' gun. GR/CCL to Top Shot = 9.1' Send correlation data to RE/GEO. On depth. Perforate with well flowing - Beluga G9 4,991' - 4,996'. MU and RIH with 2-7/8" x 9' gun. GR/CCL to Top Shot = 9.1' Send correlation data to RE/GEO. On depth. Perforate with well flowing - Beluga G9 4,979' - 4,988'. Laydown lubricator. Install tree cap. LDFN. 07/30/2021- Friday 0530 hr - Morning safety meeting, talk w/company rep, sign permits. TGSM. Rig up on well. 7:35 hr Rih w/2.5" x 7' DD Bailer to 5,138' kb, w/t 5,141' kb, pooh, ooh 1' of sand w/water on top. 8:45 hr ooh rig down. Stand by to make sure E-line dows not need equipment. Move to 232-26. 08/01/2021 - Sunday Rig down and move to BRU 241-34T. Spot equipment and Rig up. PT test 250 low 2,500 high, found o-ring leak fixed it. RIH with 8' 2-7/8" gun to 4,500' Correlation pass. Sent log to town. Perf depth of 4,383' to 4,391' (CCL 10.1 4,372.9'). Shot 1 CCL depth 4,372.9' guns shot 4,383'-4,391' all shots fired. POOH, laydown tool string, re-tool with 17' 2-7/8" gun. RIH to 4,500' correlation pass 2. Send log to town. Shot 2 (CCL 11.1 4,334.9') 4,346'-4,363' all shots fired. POOH lay down tool string secure well for the night. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 241-34T 50-283-20181-00-00-00 220-052 s shot 4,383'-4,391' all shots fired. Perforate with well flowing - Beluga G8 4,947' - 4,949'. Shots fired. Perforate with well flowing - Beluga G10 5,025' - 5,046' Perforate with well flowing - Beluga H 5,077' - 5,082'. Shots fired. S See attachment for additional perfs shot on 8/4/21. bjm 4,346'-4,363' all shots fired. Perforate with well flowing - Beluga G9 4,979' - 4,988' Perforate with well flowing - Beluga G9 4,991' - 4,996' Perforate with well flowing - Beluga H 5,057' - 5,064' Rig Start Date End Date E-Line 7/30/21 9/7/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 241-34T 50-283-20181-00-00-00 220-052 Conduct JSA and approve PTW. MU 4' perf gun bha and MU lubricator/wireline valves to tree. PT lubricator to 250 psi low / 2,500 psi high. MU and RIH with 2-7/8" x 4' perf gun. GR/CCL to Top Shot = 10.1'. Send correlation data to RE/GEO. Perforate well flowing - Beluga G8 4,962' - 4,966'. MU and RIH with 2-7/8" x 9' perf gun. GR/CCL to Top Shot = 9.1'. Send correlation data to RE/GEO. On depth. Perforate well flowing - Beluga G6 4,905' - 4,914'. MU and RIH with 2-7/8" x 5' perf gun. GR/CCL to Top Shot = 9.1'. Send correlation data to RE/GEO. On depth. Perforate well flowing - Beluga G5 4,879' - 4,844'. MU and RIH with 2-7/8" x 5' perf gun. GR/CCL to Top Shot = 9.1'. Send correlation data to RE/GEO. On depth. Perforate well flowing - Beluga G5 4,865' - 4,870'. MU and RIH with 2-7/8" x 5' perf gun. GR/CCL to Top Shot = 9.1'. Send correlation data to RE/GEO. On depth. Perforate well flowing - Beluga G5 4,846' - 4,851'. RDMO. 09/07/2021 - Tuesday Perforate well flowing - Beluga G6 4,905' - 4,914' Perforate well flowing - Beluga G5 4,846' - 4,851' Perforate well flowing - Beluga G5 4,879' - 4,844' Perforate well flowing - Beluga G8 4,962' - 4,966' Perforate well flowing - Beluga G5 4,865' - 4,870' Updated by DMA 09-10-21 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,233 MD / TVD = 5,221’ TD = 5,865’ MD / TVD = 5,852’ 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’ TUBING DETAIL 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,560’ 5,864’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly 3 5,233’ - 5.500” CIBP 9/20/2020 4 5,520’ CIBP 9/11/2020 OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G3-G10 Bel H10 Bel H12-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD Date Size Status Beluga E6 4,135' 4,147' 4,123' 4,135' 8/4/2021 2-7/8” Open Beluga F4 4,222' 4,233' 4,210' 4,221' 8/4/2021 2-7/8” Open 4,272' 4,279' 4,260' 4,267' 8/4/2021 2-7/8” Open Beluga F6 4,346' 4,363' 4,334' 4,351' 8/2/2021 2-7/8” Open 4,383' 4,391' 4,370' 4,378' 8/2/2021 2-7/8” Open Beluga F7 4,568' 4,583' 4,556’ 4,571’ 9/24/2020 2-7/8” Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 9/24/2020 2-7/8” Open Beluga G5 4,846’ 4,851’ 4,834’ 4,839’ 9/7/2021 2-7/8” Open 4,865’ 4,870’ 4,853’ 4,858’ 9/7/2021 2-7/8” Open 4,879’ 4,884’ 4,866’ 4,871’ 9/7/2021 2-7/8” Open Beluga G6 4,905’ 4,914’ 4,893’ 4,902’ 9/7/2021 2-7/8” Open Beluga G8 4,947’ 4,949’ 4,935’ 4,937’ 9/6/2021 2-7/8” Open 4,962’ 4,966’ 4,950’ 4,954’ 9/7/2021 2-7/8” Open Beluga G9 4,979’ 4,988’ 4,966’ 4,975’ 9/6/2021 2-7/8” Open 4,991’ 4,996’ 4,979’ 4,984’ 9/6/2021 2-7/8” Open Beluga G10 5,025’ 5,046’ 5,010’ 5,033’ 9/6/2021 2-7/8” Open Beluga H 5,057’ 5,064’ 5,045’ 5,052’ 9/6/2021 2-7/8” Open 5,077’ 5,082’ 5,065’ 5,070’ 9/6/2021 2-7/8” Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 9/24/2020 2-7/8” Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 8/31/2020 3-3/8” / 6 SPF Isolated 5,477' 5,510' 5,465’ 5,498’ 9/12/2020 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 9/1/2020 2-7/8” Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 9/1/2020 2-7/8” Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9/1/2020 2-7/8” Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 9/1/2020 2-7/8” Isolated 3 4 Bel E6 Bel F4-F7 Bel H-H2 TOC = 3480' md per CCL. See updated diagram attached - bjm Beluga E6 4,135'4,147'4,123'4,135'8/4/2021 2-7/8” Open Beluga F4 4,222'4,233'4,210'4,221'8/4/2021 2-7/8” Open 4,272'4,279'4,260'4,267'8/4/2021 2-7/8” Open Beluga F6 4,346'4,363'4,334'4,351' 8/2/2021 2-7/8” Open 4,383'4,391'4,370'4,378'8/2/2021 2-7/8” Open Beluga G5 4,846’4,851’4,834’4,839’9/7/2021 2-7/8” Open 4,865’4,870’4,853’4,858’9/7/2021 2-7/8” Open 4,879’4,884’4,866’4,871’9/7/2021 2-7/8” Open Beluga G6 4,905’4,914’4,893’4,902’9/7/2021 2-7/8” Open Beluga G8 4,947’4,949’4,935’4,937’9/6/2021 2-7/8” Open 4,962’4,966’4,950’4,954’9/7/2021 2-7/8” Open Beluga G9 4,979’4,988’4,966’4,975’9/6/2021 2-7/8” Open 4,991’4,996’4,979’4,984’9/6/2021 2-7/8” Open Beluga G10 5,025’5,046’5,010’5,033’9/6/2021 2-7/8” Open Beluga H 5,057’5,064’5,045’5,052’9/6/2021 2-7/8” Open 5,077’5,082’5,065’5,070’9/6/2021 2-7/8” Open WELL:BRU 241-34T Hilcorp Alaska, LLC DAILY OPERATIONS FIELD:Beluga River COUNTY/STATE:/Alaska PTD: LOCATION: ELEVATION (RKB): API #:50-283-20181-00-00 SERIAL NO: SPUD DATE:07/23/2020 OBJECTIVE: JOB NAME:212-00810 BRU 241-34T Add Beluga Perfs CONTRACTOR: TOTAL AFE BUDGET:$89,692 Jul 31 2021 ENGINEER: FIELD SUPERVISOR:Brian Wooley FW:0.0 PRESENT OPERATIONS:TAG 0530 hr - Morning safety meeting, talk w/company rep, sign permits. TGSM;Rig up on well;7:35 hr Rih w/2.5 x 7' DD Bailer to 5138' kb, w/t 5141' kb, pooh, ooh 1' of sand w/water on top;8:45 hr ooh rig down;Stand by to make sure E- line dows not need equipment;Move to 232-26 DAILY JOB COST:$1,631 TOTAL JOB COST:$1,631 Aug 2 2021 ENGINEER: FIELD SUPERVISOR:FW:0.0 PRESENT OPERATIONS: Rig down and move to BRU 241-34T. Spot equipment and Rig up. PT test 250 low 2500 high. found o-ring leak fixed it.;RIH with 8' 2-7/8" gun to 4500' Correlation pass. Sent log to town. Perf depth of 4383' to 4391' (CCL 10.1 4372.9');Shot 1 CCL depth 4372.9 guns shot 4383-4391' all shots fired;POOH. laydown tool string. re-tool with 17' 2- 7/8" gin RIH to 4500 correlation pass 2. Send log to town;Shot 2 (CCL 11.1 4334.9') 4346-4363 all shots fired;POOH lay down tool string secure well for the night. DAILY JOB COST:$43,617 TOTAL JOB COST:$45,248 Aug 4 2021 ENGINEER: FIELD SUPERVISOR:FW:0.0 PRESENT OPERATIONS: Rig up E-line Pressure test 250L 3000H. RIH with 6' 2-7/8 gun and shoot Beluga F4 @ 4272-4278'. Gamma Ray broke log incomplete. POOH. RIH with 10' 2-7/8 gun and shoot @ Beluga F4 4222-4232'. POOH. RIH with 12' 2-7/8 gun and shoot Beluga E6 @ 4135-4147. POOH and rig down job complete. DAILY JOB COST:$0 TOTAL JOB COST:$45,248 Aug 5 2021 MD:TVD:FOOTAGE:PTD: ENGINEER: FIELD SUPERVISOR:PBTD: DAILY JOB COST:$25,000 TOTAL JOB COST:$70,248 2001 - 2021 WellEz Information Management, LLC. All rights reserved Updated by JMF 11-03-21 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,233 MD / TVD = 5,221’ TD = 5,865’ MD / TVD = 5,852’ 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’ TUBING DETAIL 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,560’ 5,864’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly 3 5,233’ - 5.500” CIBP 9/20/2020 4 5,520’ CIBP 9/11/2020 OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G3-G10 Bel H10 Bel H12-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD Date Size Status Beluga E6 4,135' 4,147' 4,123' 4,135' 8/4/2021 2-7/8” Open Beluga F4 4,222' 4,233' 4,210' 4,221' 8/4/2021 2-7/8” Open 4,272' 4,279' 4,260' 4,267' 8/4/2021 2-7/8” Open Beluga F6 4,346' 4,363' 4,334' 4,351' 8/2/2021 2-7/8” Open 4,383' 4,391' 4,370' 4,378' 8/2/2021 2-7/8” Open Beluga F7 4,568' 4,583' 4,556’ 4,571’ 9/24/2020 2-7/8” Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 9/24/2020 2-7/8” Open Beluga G5 4,846’ 4,851’ 4,834’ 4,839’ 9/7/2021 2-7/8” Open 4,865’ 4,870’ 4,853’ 4,858’ 9/7/2021 2-7/8” Open 4,879’ 4,884’ 4,866’ 4,871’ 9/7/2021 2-7/8” Open Beluga G6 4,905’ 4,914’ 4,893’ 4,902’ 9/7/2021 2-7/8” Open Beluga G8 4,947’ 4,949’ 4,935’ 4,937’ 9/6/2021 2-7/8” Open 4,962’ 4,966’ 4,950’ 4,954’ 9/7/2021 2-7/8” Open Beluga G9 4,979’ 4,988’ 4,966’ 4,975’ 9/6/2021 2-7/8” Open 4,991’ 4,996’ 4,979’ 4,984’ 9/6/2021 2-7/8” Open Beluga G10 5,025’ 5,046’ 5,010’ 5,033’ 9/6/2021 2-7/8” Open Beluga H 5,057’ 5,064’ 5,045’ 5,052’ 9/6/2021 2-7/8” Open 5,077’ 5,082’ 5,065’ 5,070’ 9/6/2021 2-7/8” Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 9/24/2020 2-7/8” Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 8/31/2020 3-3/8” / 6 SPF Isolated 5,477' 5,510' 5,465’ 5,498’ 9/12/2020 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 9/1/2020 2-7/8” Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 9/1/2020 2-7/8” Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9/1/2020 2-7/8” Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 9/1/2020 2-7/8” Isolated 3 4 Bel E6 Bel F4-F7 Bel H-H2 5-1/2” TOC @ 3480’ (8/20/220 CBL) 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 241-34T Perf (PTD 220-052) 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 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:CO 785 (spacing exception for BRU 241-34T) and 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): 5,865'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: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 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 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 10, 2021 5,864'3,304' Production Liner 5-1/2" 5,852' 2,568' Perforation Depth MD (ft): See Attached Schematic 2,568' 5-/12" 2,560'5-1/2" 16" 9-5/8" 138' 2,732' 2,980psi 5,750psi 138' 2,723' 138' 2,732' 17# / P110 TVD Burst 5,864' 10,600psi MDLengthSize State Wide Spacing Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-052 50-283-20181-00-00 Beluga River Unit (BRU) 241-34T Beluga River Unit / Beluga River Undefined Gas COMMISSION USE ONLY Authorized Name: 10,600psi Tubing Grade: 17# / P110 Tubing MD (ft): 2,568' See Attached Schematic jake.flora@hilcorp.com ~5,852 5,233'5,221'~1866 psi 5233' Baker ZXP Pkr; N/A 2,560' MD/2,552' TVD; N/A; N/A Perforation Depth TVD (ft):Tubing Size: P Tieback 5-1/2" m n P s 66 t : Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:54 pm, Aug 26, 2021 321-434 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.26 13:42:57 -08'00' Taylor Wellman (2143) 10-404 SFD 8/26/2021 DSR-8/26/21BJM 8/27/21 JLC 8/27/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.27 15:11:36 -08'00' RBDMS HEW 8/30/2021 Well Prognosis Well: BRU 241-34T Date: 08/25/2021 Well Name: BRU 241-34T API Number: 50-283-20181-00-00 Current Status: Gas Producer Leg: N/A Estimated Start Date: 9/10/21 Rig: N/A Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-052 First Call Engineer: Jake Flora (907) 777-8442 (O)(720) 988-5375 Second Call Engineer: Todd Sidoti (907) 777-8443 (O)(907) 632-4113 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Maximum Expected BHP: ~2399 psi @ 5332’ TVD (Based on 0.45 psi/ft) Max. Allowable Surface Pressure: ~1866 psi (Based on 0.1 psi/ft gas gradient) Brief Well Summary: BRU 241-34T was originally drilled in 2020 as a replacement well for the original BRU 241-34. It is a 4-1/2” monobore completion through the Beluga and the Sterling. Initially perforated 5 lower H sands with subpar results in early September 2020. After isolating the lower sands, came back and perforated the H2, G3, and F7 and the well came online making 6.4 MMCFD. The well has fallen off to about 1.5 MMCFD and has cum’d just under 1 BCF of gas TD. In July 2021 the Beluga F6, F4 and E6 were added bringing the rate back up to just about 4.0 MMCFD @ 315 psi. The idea is to add a few more Beluga sands to get the rate up over 5 MMCFD. Objective: To add rate and improve productivity in BRU 241-34T, it is recommended to add perfs to the following Beluga/Sterling sands until desired rate is achieved. This work is an add on to open perf sundry 321-357 and they will both be reported on the same 10-404. Well Notes: - Beluga E6-F6 perforations added 8/4/2021 w 2-7/8 guns - No restrictions, minimum ID is 4.892” production liner E-line: 1. MIRU E-line, PT lubricator to 250 psi low and 2500 psi high. 2. While flowing perforate the below zones from the bottom up: Sand MD top MD btm Total Ftg TVD top TVD btm Beluga G5 ±4,846’ ±4,852’ ±5’ ±4,834’ ±4,839’ Beluga G5 ±4,865’ ±4,870’ ±5’ ±4,853’ ±4,858’ Beluga G5 ±4,879’ ±4,884’ ±5’ ±4,866’ ±4,871’ Beluga G6 ±4,905’ ±4,914’ ±9’ ±4,893’ ±4,902’ Beluga G8 ±4,947’ ±4,949’ ±2’ ±4,935’ ±4,937’ Beluga G8 ±4,962’ ±4,966’ ±4’ ±4,950’ ±4,954’ Beluga G9 ±4,979’ ±4,987’ ±9’ ±4,966’ ±4,975’ To add rate and improve productivity in BRU 241-34T, o add a few more Beluga sands t Well Prognosis Well: BRU 241-34T Date: 08/25/2021 Beluga G9 ±4,991’ ±4,996’ ±5’ ±4,979’ ±4,984’ Beluga G10 ±5,024’ ±5,046’ ±22’ ±5,011’ ±5,033’ Beluga H ±5,057’ ±5,064’ ±7’ ±5,045’ ±5,052’ Beluga H ±5,077’ ±5,082’ ±5’ ±5,065’ ±5,070’ Beluga H3 ±5,211’ ±5,214’ ±2’ ±5,199’ ±5,201’ a. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 c. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. d. The Beluga and Sterling sands can be co-mingled at BRU. 3. RD E-Line. 4.Turn well over to production. Nitrogen (Contingency) 1. If Nitrogen is required to pressure up well prior to perforating or push fluid away: 2. MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating pressure. E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments: Current Well Schematic Proposed Well Schematic Standard Well Procedure – N2 Operations Updated by DMA 08-26-21 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,778’ MD / TVD = 5,767’ TD = 5,865’ MD / TVD = 5,852’ 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’ TUBING DETAIL 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,560’ 5,864’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly 3 5,233’ - 5.500” CIBP OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G Sands Bel F Sands Bel H Sands Bel H10-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD FT Date Size Status Beluga E6 4,135' 4,147' 4,123' 4,135' 12' 8/4/2021 2-7/8” Open Beluga F4 4,222' 4,233' 4,210' 4,221' 11' 8/4/2021 2-7/8” Open Beluga F4 4,272' 4,279' 4,260' 4,267' 7' 8/4/2021 2-7/8” Open Beluga F6 4,346' 4,363' 4,334' 4,351' 17' 8/2/2021 2-7/8” Open Beluga F6 4,383' 4,391' 4,370' 4,378' 8' 8/2/2021 2-7/8” Open Beluga F7 4,568' 4,583' 4,556’ 4,571’ 15’ 9/24/2020 2-7/8” / 5 SPF Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 39’ 9/24/2020 2-7/8” / 5 SPF Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 18’ 9/24/2020 2-7/8” / 5 SPF Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 33' 8/31 & 9/12 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 26' 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 39' 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9’ 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 24' 9/1/2020 2-7/8” / 6 SPF Isolated Junk pushed to 5,284’ MD 3 Bel E Sands Updated by DMA 08-26-21 PROPOSED SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,778’ MD / TVD = 5,767’ TD = 5,865’ MD / TVD = 5,852’ 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’ TUBING DETAIL 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 5-1/2" Prod Lnr 17 P-110 ICY TXP BTC 4.892” 2,560’ 5,864’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly 3 5,233’ - 5.500” CIBP OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G Sands Bel F Sands Bel H Sands Bel H10-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD FT Date Size Status Beluga E6 4,135' 4,147' 4,123' 4,135' 12' 8/4/2021 2-7/8” Open Beluga F4 4,222' 4,233' 4,210' 4,221' 11' 8/4/2021 2-7/8” Open Beluga F4 4,272' 4,279' 4,260' 4,267' 7' 8/4/2021 2-7/8” Open Beluga F6 4,346' 4,363' 4,334' 4,351' 17' 8/2/2021 2-7/8” Open Beluga F6 4,383' 4,391' 4,370' 4,378' 8' 8/2/2021 2-7/8” Open Beluga F7 4,568' 4,583' 4,556’ 4,571’ 15’ 9/24/2020 2-7/8” / 5 SPF Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 39’ 9/24/2020 2-7/8” / 5 SPF Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 18’ 9/24/2020 2-7/8” / 5 SPF Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 33' 8/31 & 9/12 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 26' 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 39' 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9’ 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 24' 9/1/2020 2-7/8” / 6 SPF Isolated PROPOSED PERFORATIONS: 4846’ – 5350’ (G5 to H7), table to be updated with 10-404 Junk pushed to 5,284’ MD 3 Bel E Sands STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. 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/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 5,865'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: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 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: August 5, 2021 5,864'3,304' N/A 5,852' 2,568' Perforation Depth MD (ft): See Attached Schematic 2,568' 5-/12" 2,560'5-1/2" 16" 9-5/8" 138' 2,732' 2,980psi 5,750psi 138' 2,723' 138' 2,732' N/A TVD Burst N/A 10,600psi MDLength Size State Wide Spacing Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-052 50-283-20181-00-00 Beluga River Unit (BRU) 241-34T Beluga River Unit / Beluga River Undefined Gas COMMISSION USE ONLY Authorized Name: 10,600psi Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com ~5,852 5,233'5,221'334 N/A Baker ZXP Pkr; N/A 2,560' MD/2,552' TVD; N/A; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 11:39 am, Jul 20, 2021 321-357 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.20 11:18:10 -08'00' Taylor Wellman (2143) CO 785 (spacing exception for BRU 241-34T) and No perforating allowed above 3500' md without remedial cement job. Separate sundry required. DSR-7/21/21 10-404 - Include 3500' md top of cement on updated diagram. SFD 7/20/2021 SFD 7/20/2021 BJM 7/27/21 dts 7/28/2021 JLC 7/28/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.28 15:30:06 -08'00' RBDMS HEW 7/30/2021 Well Prognosis Well: BRU 241-34T Date: 07/19/2021 Well Name: BRU 241-34T API Number: 50-283-20181-00-00 Current Status: Gas Producer Leg: N/A Estimated Start Date: 08/05/2021 Rig: N/A Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-052 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Maximum Expected BHP: ~690psi @ 3556’ TVD (Based on offset RFT data) Max. Allowable Surface Pressure: ~334psi (Based on 0.1 psi/ft gas gradient) Brief Well Summary: BRU 241-34T was originally drilled in 2020 as a replacement well for the original BRU 241-34. It is a 4-1/2” monobore completion through the Beluga and the Sterling. Initially perforated 5 lower H sands with subpar results in early September 2020. After isolating the lower sands, came back and perforated the H2, G3, and F7 and the well came online making 6.4 MMCFD. The well has fallen off to about 1.5 MMCFD and has cum’d just under 1 BCF of gas TD. Objective: To add rate and improve productivity in BRU 241-34T, it is recommended to add perfs to the following Beluga/Sterling sands until desired rate is achieved. Well Notes: - SL tagged sand @ 5120’ with a 2.5” TS on 05/02/21 - No restrictions, minimum ID is 4.892” production liner Slickline: 1. MIRU slickline, PT lubricator to 250 psi low and 2500 psi high. 2. Drift for e-line with 3.7” dummy guns. E-line: 3. MIRU E-line, PT lubricator to 250 psi low and 2500 psi high. 4. Perforate the below zones from the bottom up with 3-3/8” Razor guns loaded with 22.7g charges at 6 SPF: Sand MD top MD btm Total Ftg TVD top TVD btm ST_A2 ±3,042' ±3,045' 3' ±3,033' ±3,036' ST_A3 ±3,105' ±3,117' 12' ±3,096' ±3,108' ST_A4 ±3,157' ±3,172' 15' ±3,147' ±3,162' ST_B4 ±3,340' ±3,350' 10' ±3,330' ±3,340' ST_C1 ±3,368' ±3,379' 11' ±3,358' ±3,369' ST_C3 ±3,455' ±3,468' 13' ±3,444' ±3,457' ST_C5 ±3,497' ±3,526' 29' ±3,486' ±3,515' The Beluga River Undefined Gas Pool is unusual in that historically it has included sands assigned to both the Beluga and Sterling Formations. CBL dated 8/20/20 found TOC at 3500' md. Remedial cement job required before any perfs will be permitted above 3500' md. Separate sundry required for remedial cement. bjm SFD 7/20/2021 Beluga/Sterling sands add perfs to the following Well Prognosis Well: BRU 241-34T Date: 07/19/2021 Beluga D ±3,567' ±3,571' 4' ±3,556' ±3,560' Beluga D1 ±3,585' ±3,601' 16' ±3,573' ±3,589' Beluga D3 ±3,641' ±3,652' 11' ±3,629' ±3,640' Beluga D4 ±3,668' ±3,675' 7' ±3,656' ±3,663' Beluga E6 ±4,135' ±4,147' 12' ±4,123' ±4,135' Beluga F4 ±4,222' ±4,233' 11' ±4,210' ±4,221' Beluga F4 ±4,272' ±4,279' 7' ±4,260' ±4,267' Beluga F6 ±4,346' ±4,363' 17' ±4,334' ±4,351' Beluga F6 ±4,383' ±4,391' 8' ±4,370' ±4,378' a. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 c. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. d. The Beluga and Sterling sands can be co-mingled at BRU. 5. RD E-Line. 6. Turn well over to production. Nitrogen (Contingency) 1. If Nitrogen is required to pressure up well prior to perforating or push fluid away: 2. MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating pressure. E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments: Current Well Schematic Proposed Well Schematic Standard Well Procedure – N2 Operations Updated by CJD 09-29-20 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,778’ MD / TVD = 5,767’ TD = 5,865’ MD / TVD = 5,852’ 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” 2,560’ 5,864’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly 3 5,233’ - 5.500” CIBP OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G3 Bel F7 Bel H2 Bel H10-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD FT Date Size Status Beluga F7 4,568' 4,583' 4,556’ 4,571’ 15’ 9/24/20 2-7/8” / 5 SPF Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 39’ 9/24/20 2-7/8” / 5 SPF Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 18’ 9/24/20 2-7/8” / 5 SPF Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 33' 8/31 & 9/12 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 26' 9/1/20 2-7/8” / 6 SPF Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 39' 9/1/20 2-7/8” / 6 SPF Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9’ 9/1/20 2-7/8” / 6 SPF Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 24' 9/1/20 2-7/8” / 6 SPF Isolated Junk pushed to 5,284’ MD 3 set 9/20/20 "CIBP set at 5520 ft failed .... fished core and element." Comments from G. Schwartz, AOGCC, added to this same schematic drawing that accompanies the original Well Completion Report for BRU 241-34T (received by AOGCC on 10/1/2020): (gls 10/23/20) 2732 ft "Yellow Jacket CBL (8/20/20) TOC at 3500 ft. Poor cement from 4050-4200 ft Good to mod cement from 4200 - TD." "CIBP @5233ft set 9/20/20" TOC at 3500 ft Updated by TCS 07-19-21 PROPOSED SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,778’ MD / TVD = 5,767’ TD = 5,865’ MD / TVD = 5,852’ 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” 2,560’ 5,864’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,568’ 1/2 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,568’ 6.180” 7.700” Baker tieback Seal Assembly 3 5,233’ - 5.500” CIBP OPEN HOLE / CEMENT DETAIL 9-5/8" 240 BBL’s of cement in 12-1/4” hole – 53 bbls returned to surface 5-1/2” 152 BBL’s of cement in 8-1/2” hole. Est. TOC 3,480’ CBL 8-1/2” hole Bel G3 Bel F7 Bel H2 Bel H10-H15 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD FT Date Size Status ST_A2 ±3,042' ±3,045' ±3,033' ±3,036' 3' TBD - - ST_A3 ±3,105' ±3,117' ±3,096' ±3,108' 12' TBD - - ST_A4 ±3,157' ±3,172' ±3,147' ±3,162' 15' TBD - - ST_B4 ±3,340' ±3,350' ±3,330' ±3,340' 10' TBD - - ST_C1 ±3,368' ±3,379' ±3,358' ±3,369' 11' TBD - - ST_C3 ±3,455' ±3,468' ±3,444' ±3,457' 13' TBD - - ST_C5 ±3,497' ±3,526' ±3,486' ±3,515' 29' TBD - - Beluga D ±3,567' ±3,571' ±3,556' ±3,560' 4' TBD - - Beluga D1 ±3,585' ±3,601' ±3,573' ±3,589' 16' TBD - - Beluga D3 ±3,641' ±3,652' ±3,629' ±3,640' 11' TBD - - Beluga D4 ±3,668' ±3,675' ±3,656' ±3,663' 7' TBD - - Beluga E6 ±4,135' ±4,147' ±4,123' ±4,135' 12' TBD - - Beluga F4 ±4,222' ±4,233' ±4,210' ±4,221' 11' TBD - - Beluga F4 ±4,272' ±4,279' ±4,260' ±4,267' 7' TBD - - Beluga F6 ±4,346' ±4,363' ±4,334' ±4,351' 17' TBD - - Beluga F6 ±4,383' ±4,391' ±4,370' ±4,378' 8' TBD - - Beluga F7 4,568' 4,583' 4,556’ 4,571’ 15’ 9/24/2020 2-7/8” / 5 SPF Open Beluga G3 4,738' 4,777' 2,726’ 4,765’ 39’ 9/24/2020 2-7/8” / 5 SPF Open Beluga H2 5,143' 5,161' 5,131’ 5,149’ 18’ 9/24/2020 2-7/8” / 5 SPF Open Beluga H10 5,477' 5,510' 5,465’ 5,498’ 33' 8/31 & 9/12 3-3/8” / 6 SPF Isolated Beluga H12 5,537' 5,563' 5,525’ 5,551’ 26' 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H13 5,563' 5,602' 5,551’ 5,590’ 39' 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H14 5,698' 5,707' 5,686’ 5,695’ 9’ 9/1/2020 2-7/8” / 6 SPF Isolated Beluga H15 5,732' 5,756' 5,720’ 5,744’ 24' 9/1/2020 2-7/8” / 6 SPF Isolated Junk pushed to 5,284’ MD 3 Beluga Sterling SFD 7/20/2021 SFD 7/20/2021 "CIBP set at 5520 ft failed .... fished core and element." SFD 7/20/2021 2732 ft "CIBP @5233ft set 9/20/20" "Yellow Jacket CBL (8/20/20) TOC at 3500 ft. Poor cement from 4050-4200 ft Good to mod cement from 4200 - TD." TOC at 3500 ft SFD 7/20/2021 after GLS 10/23/2020 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. David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564- 4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/21/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Log Vendor BRU 241-34T 502832018100 220052 8/30/2020 PERF RECORD Yellowjacket BRU 241-34T 502832018100 220052 09/09/2020 PERF RECORD Yellowjacket Please include current contact information if different from above. Received By: 06/28/2021 37' (6HW By Abby Bell at 11:15 am, Jun 28, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564- 4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/21/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Log Vendor BRU 241-34T 502832018100 220052 8/30/2020 PERF RECORD Yellowjacket BRU 241-34T 502832018100 220052 09/09/2020 PERF RECORD Yellowjacket Please include current contact information if different from above. Received By: 06/28/2021 37' (6HW By Abby Bell at 11:15 am, Jun 28, 2021 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 4538 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. 5,732-5,756 5,143-5,161 5,563-5,602 for Separator Gas Gg for Flowing Fluid G z Diff. Hw Gg: % CO2: Temp. Fo 2624375 2624376 N/A To 5,477-5,510 5,698-5,707 4,738-4,777 5,537-5,563 5,233' MD / 5,221' TVD 102.2' 08/02/20 N/A 5,865' MD / 5,853' TVD 4,568-4,583 2000 Meter Run: Taps:Prover: Beluga River Undef Gas 5-1/2" Production String, Perforated FEDA 029657 CASING DATATUBING DATA STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT Hilcorp Alaska, LLC 08/13/20 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 220-052 915' FNL, 1432' FEL, Sec 34, T13N, R10W, SM, AK 799' FNL, 1199' FEL, Sec 34, T13N, R10W, SM, AK 798' FNL, 1204' FEL, Sec 34, T13N, R10W, SM, AK 5-1/2"17#4.892" 2624263316486 316720 316716 26. 0.56 0 5,864' 2,560 90 Temp. Fo Pressure psig Temp. Fo Pressure psig Pressure Pm Flow Temp. Factor Ft Gravity Factor Fg Super Comp. Factor Fpv Rate of Flow Q1 Mcfd FLOW DATA Duration of Flow Hr. hwPm Pressure psig Prover Line Size (in.) No. Choke Orifice Size (in.) X No. Basic Coefficient (24-Hour) Fb or Fp No. Pr Temperature T Tr Critical Pressure Critical Temperature Nodal____________ 283-20181-00-00 BRU 241-34T Beluga River / Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE SIDE Submit in DuplicateRBDMS HEW 5/17/2021 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. BRU 212-26 is flowing from the Beluga H2,G3, & F7 gas sands (4,568' - 5,161' 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 5-8 md and a skin of +/-5 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. 11,143 Form 10-421 Revised 7/2009 Side 2 Digitally signed by Trudi Hallett (1231) DN: cn=Trudi Hallett (1231), ou=Users Date: 2021.05.10 15:20:00 -08'00' Trudi Hallett (1231) Page 1Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 241-34T\Nodal\BRU 241-34T.Out ######################################## # INFLOW PERFORMANCE DATA (GAS WELL) # ######################################## Reservoir Model Jones M&G Skin Model Enter Skin By Hand Reservoir Pressure 2000.00 (psig) Reservoir Temperature 90.00 (deg F) Water-Gas Ratio 0 (STB/MMscf) Condensate Gas Ratio 0 (STB/MMscf) Absolute Open Flow (AOF) 11.142 (MMscf/day) Reservoir Permeability 5.00 (md) Reservoir Thickness 72.0 (feet) Drainage Area 60.0 (acres) Dietz Shape Factor 14.2678 Wellbore Radius 0.25 (feet) Perforation Interval 72.00 (feet) Calculated Non-Darcy Coefficent (Beta) 3372041728 Page 2Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 241-34T\Nodal\BRU 241-34T.Out ++++++++++++++++++++++++++++++++++++++ + MECHANICAL/GEOMETRICAL SKIN DATA + ++++++++++++++++++++++++++++++++++++++ Skin 5 Page 3Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 241-34T\Nodal\BRU 241-34T.Out +++++++++++++++++++++ + IPR - TEST DATA + +++++++++++++++++++++ Gas Pressure Date Comment Rate (FBHP) Status (MMscf/day) (psig) __________ _______ ___________ ________ ______ 09/26/2020 Page 4Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 241-34T\Nodal\BRU 241-34T.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 2000.00 90.00 0 5.00 0 5.00 0 0 0 0 0 0.58641 1946.07 88.97 21.03 5.00 0 5.00 0 0 0 0 0 1.173 1890.73 87.89 42.73 5.00 0 5.00 0 0 0 0 0 1.759 1833.85 86.76 65.19 5.00 0 5.00 0 0 0 0 0 2.346 1775.27 85.58 88.52 5.00 0 5.00 0 0 0 0 0 2.932 1714.80 84.35 112.87 5.00 0 5.00 0 0 0 0 0 3.518 1652.22 83.04 138.39 5.00 0 5.00 0 0 0 0 0 4.105 1587.28 81.66 165.30 5.00 0 5.00 0 0 0 0 0 4.691 1519.65 80.18 193.83 5.00 0 5.00 0 0 0 0 0 5.278 1448.95 78.61 224.31 5.00 0 5.00 0 0 0 0 0 5.864 1374.67 76.90 257.14 5.00 0 5.00 0 0 0 0 0 6.450 1296.19 75.04 292.87 5.00 0 5.00 0 0 0 0 0 7.037 1212.60 72.99 332.27 5.00 0 5.00 0 0 0 0 0 7.623 1122.87 70.70 376.26 5.00 0 5.00 0 0 0 0 0 8.210 1025.30 68.08 426.38 5.00 0 5.00 0 0 0 0 0 8.796 917.34 61.73 485.01 5.00 0 5.00 0 0 0 0 0 9.382 794.73 52.37 556.18 5.00 0 5.00 0 0 0 0 0 9.969 649.16 40.34 647.96 5.00 0 5.00 0 0 0 0 0 10.555 459.22 23.01 781.45 5.00 0 5.00 0 0 0 0 0 11.142 0 7.50 1181.16 5.00 0 5.00 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 0.0020848 221.975 0.58641 0 0 0 0 0 0.0020859 221.35 1.173 0 0 0 0 0 0.002087 220.725 1.759 0 0 0 0 0 0.0020883 220.099 2.346 0 0 0 0 0 0.0020896 219.473 2.932 0 0 0 0 0 0.002091 218.847 3.518 0 0 0 0 0 0.0020925 218.221 4.105 0 0 0 0 0 0.002094 217.594 4.691 0 0 0 0 0 0.0020957 216.969 5.278 0 0 0 0 0 0.0020975 216.343 5.864 0 0 0 0 0 0.0020993 215.719 6.450 0 0 0 0 0 0.0021012 215.095 7.037 0 0 0 0 0 0.0021033 214.472 7.623 0 0 0 0 0 0.0021054 213.851 8.210 0 0 0 0 0 0.0021077 213.231 8.796 0 0 0 0 0 0.0021101 212.613 9.382 0 0 0 0 0 0.0021126 211.997 9.969 0 0 0 0 0 0.0021153 211.383 10.555 0 0 0 0 0 0.002118 210.772 11.142 0 0 0 0 0 0.002121 210.163 Page 5Hilcorp - O:\Alaska\Fields\Beluga River\Wells\BRU 241-34T\Nodal\BRU 241-34T.Out Total Skin : 5.00 ( = Entered + Perforation + Damage + Deviation + Partial Penet Completion Skin : 5.00 ( = 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) : 3372041728 +++++++++++++++++++ + End of Report + +++++++++++++++++++ DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20181-00-00Well Name/No.BELUGA RIV UNIT 241-34TCompletion Status1-GASCompletion Date8/13/2020Permit to Drill2200520OperatorHilcorp Alaska, LLCMD5865TVD5853Current Status1-GAS11/12/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:LWD/ Mudlog/ CBLNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF8/31/202010 5970 Electronic Data Set, Filename: BRU 241-34T.las33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Geolog AM Reports.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T EOW Report.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Drilling Dynamics Log MD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Drilling Dynamics Log MD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Drilling Dynamics Log TVD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Drilling Dynamics Log TVD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Formation Log MD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Formation Log MD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Formation Log TVD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Formation Log TVD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Gas Ratio Log MD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Gas Ratio Log MD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T Gas Ratio Log TVD 2 in.pdf33712EDDigital DataThursday, November 12, 2020AOGCC Page 1 of 6: BRU 241-34T.lasSupplied by OPSupplied by OP DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20181-00-00Well Name/No.BELUGA RIV UNIT 241-34TCompletion Status1-GASCompletion Date8/13/2020Permit to Drill2200520OperatorHilcorp Alaska, LLCMD5865TVD5853Current Status1-GAS11/12/2020UICNoDF8/31/2020 Electronic File: BRU241-34T Gas Ratio Log TVD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T LWD Combo Log MD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T LWD Combo Log MD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T LWD Combo Log TVD 2 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T LWD Combo Log TVD 5 in.pdf33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Drilling Dynamics Log MD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Drilling Dynamics Log MD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Drilling Dynamics Log TVD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Drilling Dynamics Log TVD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Formation Log MD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Formation Log MD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Formation Log TVD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Formation Log TVD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Gas Ratio Log MD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Gas Ratio Log MD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Gas Ratio Log TVD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Gas Ratio Log TVD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T LWD Combo Log MD 2 in.tif33712EDDigital DataThursday, November 12, 2020AOGCC Page 2 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20181-00-00Well Name/No.BELUGA RIV UNIT 241-34TCompletion Status1-GASCompletion Date8/13/2020Permit to Drill2200520OperatorHilcorp Alaska, LLCMD5865TVD5853Current Status1-GAS11/12/2020UICNoDF8/31/2020 Electronic File: BRU 241-34T LWD Combo Log MD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T LWD Combo Log TVD 2 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T LWD Combo Log TVD 5 in.tif33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T.dbf33712EDDigital DataDF8/31/2020 Electronic File: bru241-34t.hdr33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T.mdx33712EDDigital DataDF8/31/2020 Electronic File: bru241-34tr.dbf33712EDDigital DataDF8/31/2020 Electronic File: bru241-34tr.mdx33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T_SCL.DBF33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T_SCL.MDX33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T_TVD.DBF33712EDDigital DataDF8/31/2020 Electronic File: BRU241-34T_TVD.mdx33712EDDigital DataDF8/31/2020 Electronic File: DbRaw.dbf33712EDDigital DataDF8/31/2020 Electronic File: DbRaw.mdx33712EDDigital DataDF8/31/2020 Electronic File: BRU 241-34T Gas Show Reports.pdf33712EDDigital Data0 0 2200520 BELUGA RIV UNIT 241-34T LOG HEADERS33712LogLog Header ScansDF9/14/202070 5865 Electronic Data Set, Filename: BRU 241-34T LWD Final.las33832EDDigital DataDF9/14/20202720 3688 Electronic Data Set, Filename: BRU 241-34T Processed LWD XBAT.las33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final MD.cgm33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final TVD.cgm33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final MD.cgm33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final TVD.cgm33832EDDigital DataThursday, November 12, 2020AOGCC Page 3 of 6BRU 241-34TLWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20181-00-00Well Name/No.BELUGA RIV UNIT 241-34TCompletion Status1-GASCompletion Date8/13/2020Permit to Drill2200520OperatorHilcorp Alaska, LLCMD5865TVD5853Current Status1-GAS11/12/2020UICNoDF9/14/2020 Electronic File: BRU 241-34T - Definitive Survey Report.pdf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T Final Surveys.xlsx33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T_DSR.txt33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T_GIS.txt33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final MD.emf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final TVD.emf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final MD.emf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final TVD.emf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final MD.pdf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final TVD.pdf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final MD.pdf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final TVD.pdf33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final MD.tif33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T LWD Final TVD.tif33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final MD.tif33832EDDigital DataDF9/14/2020 Electronic File: BRU 241-34T XBAT Final TVD.tif33832EDDigital Data0 0 2200520 BELUGA RIV UNIT 241-34T LOG HEADERS33832LogLog Header ScansFL8/27/20205779 2388 Electronic Data Set, Filename: bru 241-34t_MAIN PASS.las34196EDDigital DataFL8/27/2020 Electronic File: BRU 241-34T FINAL COPY.pdf34196EDDigital Data0 0 2200520 BELUGA RIV UNIT 241-34T LOG HEADERS34196LogLog Header ScansDF11/6/20205779 196 Electronic Data Set, Filename: BRU_241-34T_TMD3D_19AUG20_Main.las34198EDDigital DataDF11/6/2020220 5760 Electronic Data Set, Filename: BRU_241-34T_TMD3D_19AUG20_ProcessedLog-V3.las34198EDDigital DataDF11/6/20203030 2772 Electronic Data Set, Filename: BRU_241-34T_TMD3D_19AUG20_Repeat.las34198EDDigital DataThursday, November 12, 2020AOGCC Page 4 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20181-00-00Well Name/No.BELUGA RIV UNIT 241-34TCompletion Status1-GASCompletion Date8/13/2020Permit to Drill2200520OperatorHilcorp Alaska, LLCMD5865TVD5853Current Status1-GAS11/12/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments: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: 8/13/2020Release Date: 7/16/2020DF11/6/2020 Electronic File: BRU_241-34T_TMD3D_19AUG20.pdf34198EDDigital DataDF11/6/2020 Electronic File: BRU_241-34T_TMD3D_19AUG20_img.tiff34198EDDigital DataDF11/6/2020 Electronic File: BRU_241-34T_TMD3D_19AUG20_ProcessedLog-V3.pdf34198EDDigital DataDF11/6/2020 Electronic File: BRU_241-34T_TMD3D_19AUG20_ProcessedLog-V3.tif34198EDDigital Data0 0 2200520 BELUGA RIV UNIT 241-34T LOG HEADERS34198LogLog Header Scans9/10/20202743 586531763CuttingsThursday, November 12, 2020AOGCC Page 5 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20181-00-00Well Name/No.BELUGA RIV UNIT 241-34TCompletion Status1-GASCompletion Date8/13/2020Permit to Drill2200520OperatorHilcorp Alaska, LLCMD5865TVD5853Current Status1-GAS11/12/2020UICNoCompliance Reviewed By:Date:Thursday, November 12, 2020AOGCC Page 6 of 6M. Guhl11/12/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 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: 11/06/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 SFTP DATA TRANSFER TRANSMITTAL BRU 241-34T (PTD 220-052) •BRU 241-34T TMD3D 19-AUG-2020 Folder Contents: Please include current contact information if different from above. 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Supry A BOPE Test Report for: BELUGA RIV UNIT 241-34T ' Comm Contractor/Rig No.: Petrospec 131 PTD#: 2200520 - DATE: 9/22/2020 - Inspector Lou Laubenstein - Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Colin McAmmond Rig Rep: Brad Gathman Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopLOL200926081849 320-354 - Rams: Annular: Valves: MASP: Type Test: INIT 250/4000 - ) 250/4000 - 1937 Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 0 P/F Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: _P Trip Tank NA NA System Pressure 2400 P ' Housekeeping: P Pit Level Indicators NA NA Pressure After Closure 1500 P PTD On Location P - Flow Indicator NA NA 200 PSI Attained 53 _ _" P_ _ Standing Order Posted P - Meth Gas Detector NA NA Full Pressure Attained 221 P Well Sign _P _ H2S Gas Detector NA -NA Blind Switch Covers: __yes -__P Drl. Rig _ P_ MS Mise 1 _0 NA Nitgn. Bottles (avg): Kill Line Valves NA - Hazard Sec. P _' Check Valve 0 ACC Misc 0 NA Misc NA P FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 0 NA_ Lower Kelly 0 - _ NA Ball Type 0 _- NA__ Inside BOP 0 NA FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 1 --13 /4" P, No. Valves 0 NA Annular Preventer - 0_ NA Manual Chokes 1 P " #1 Rams 1 13/4" blind/s _P_ Hydraulic Chokes 0 NA #2 Rams 1 - 1 3/4" pipe/sli " P CH Misc 0 NA #3 Rams 0 NA #4 Rams 0 NA_ #5 Rams - 0 - _ - NA_ INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 2 ' 2" FMC - P - Quantity P/F HCR Valves 0 NA Inside Reel Valves 1 P Kill Line Valves 2 ' 2" FMC P Check Valve 0 NA BOP Misc - 2 ' EQ ports _- P Number of Failures: 0 Test Results Remarks: Unit was in good shape and all equipment was in order, good test. ✓ ?1q (5) ai4zld et . Test Time 3 � O O &a) L) 04 G) O T- o 0c) o00 N � f4 G�C)NJ O) O N O J v'IT 0 a� QM a U) to O ON - U CL CE -U U1 > QD N Lu Co UO) O IL 5(D p N OT) 0 N m co < ) x U O I O O .r - CL Q I M ri N I cr 0o I M r -I U 4J Q V) O v a CL I O m N M N '} Ql O O -1 � � O a f -rZr�. � .16 1i616 A. x U O I !n O L Q I m c -I N I D Of m I M r -I U Q O i a-' N d a I O m NI M N 4- O O N O N N pp O N d x u O LnO O t Q H I m N I m r-I m u QJ Q N O L v a I CL O m I m N N +- � O O m O N N OA O ro N d Dvid Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 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 9/11/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 241-34T(PTD 220-052) BRU 241-34T_FINAL_HALLIBURTON_LWD_LOGS & Directional Survey Please include current contact information if different from above. Received by the AOGCC 09/14/2020 PD: 2200520 E-Set: 33832 Abby Bell 09/14/2020 DATE 9/09/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 CenterPoint Drive, Suite 1400 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 241.-34T (PTD 220-052) WELL BOX SAMPLE INTERVAL (FEET / MD) BRU 241-34T BOX 1 OF 3 2743'- 3900' MD BRU 241-34T BOX 2 OF 3 3900'- 5340' MD BRU 241-34T BOX 3 OF 3 5340'- 5865' MD (TD) Please include current contact information if different from above. RECEAVED SEP 10 2020 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to: (907)777-8510 30 Dvid Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 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 8/31/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 241-34T(PTD 220-052) FINAL CD - DRILL REPORTS-LWD LOGS-MUDLOGS Please include current contact information if different from above. Received by the AOGCC 08/31/2020 PTD: 2200520 E-Set:33712 Abby Bell 08/31/2020 II Hilr,1r11 Al..,lrn, 1.U. DATE 8/27/2020 Debra Oudean GeoTech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com PTD: 2200520E-Set: 34196 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician RECEIVED AUG 2 7 2020 AOGCC 333 w. 7th Ave. Ste#l00 Anchorage, AK 99501 DATA TRANSMITTAL BRU 241-34T(220-052) CBL f;. BRU 241-34T FINAL COPY -]l -br�-241-�34t_MAIN PASS----E/20/2020 3:30 PM PDF Document E/2D/202!; 3:30 PM L,i'.,S File 7,.642 KB 1,.442KBi Please include current contact information if different from above. g one copy of this transmittal or FAX to 907 777 .8510 Received By: Date: 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): 5,865'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 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 4, 2020 5,865'3,305' N/A ~5,853 2,560' Perforation Depth MD (ft): See Attached Schematic 2,560' 5-/12" 2,552'5-1/2" 16" 9-5/8" 138' 2,732' 2,980psi 5,750psi 138' 2,723' 138' 2,732' N/A TVD Burst N/A 10,600psi MDLength Size State Wide Spacing Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 220-052 50-283-20181-00-00 Beluga River Unit (BRU) 241-34T Beluga River Unit / Beluga River Undefined Gas COMMISSION USE ONLY Authorized Name: 10,601psi Tubing Grade: Tubing MD (ft): See Attached Schematic tkramer@hilcorp.com ~5,852 5,778'~5,767 1,937 N/A Baker ZXP Pkr; N/A 2,560' MD/2,551' TVD; N/A; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:21 am, Aug 24, 2020 320-354 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.08.21 16:14:34 -08'00' Taylor Wellman DSR-8/24/2020 10-407 gls 8/27/20 X DLB 08/24/2020 8/19/20 *4000 psi BOPE test min (CT) Guy Schwartz CBL PNL N2 * Sterling sand intervals (above 3526 ft md) not approved for perforating without Commission approval. CT X Comm 8/28/2020 JLC 8/28/2020 RBDMS HEW 8/31/2020 Well Prognosis Well: BRU 241-34T Date: 8-20-2020 Well Name:BRU 241-34T API Number:50-283-20181-00 Current Status:New Grassroots Well Leg:N/A Estimated Start Date:Sep 4, 2020 Rig:E-line Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:220-052 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:2011739C Maximum Expected BHP:~ 2,511 psi @ 5,743’ TVD (Based on a .437 gradient.) Max. Potential Surface Pressure:~ 1,937 psi @ 5,743’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary BRU 241-34T is a grass roots Twin well of the development well 241-34 and is targeting gas sands in the Beluga formation. This new well TD was reached on 8-10-2020. The purpose of this work/sundry is to Log well, evaluate cement, jet the well dry with CT, and perforate. Verbal approval has beed requested to perform the logging and the coil blowdown. 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 will complete Pulse Newtron log and CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when completed. 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 Pre-Sundry E-line Work 1. MIRU E-line unit. RU Stripping head. PU PNL and CBL. TIH to PBTD (5,778’). Run PNL and CBL log from PBTD up to 2,600’. RDMO E-line unit. Coiled Tubing Procedure (Start of Sundry work) 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 jet well dry. a) Estimated volume of displaced 6% KCl is (+/-)135 bbls. (Based on estimated PBTD of 5,778’). 5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 6. Once well is dry, leave 1,500 psi. on the well for first perforation interval. CBL indicates TOC at 3450 ft . Need cement sqz prior to any Sterling sand perforations.... gls 8/27/20 granted on 8/19/20 gls Well Prognosis Well: BRU 241-34T Date: 8-20-2020 7. POOH w/ coil. LD BHA. 8. RDMO Coiled Tubing. E-Line Procedure 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 3,550’ between the Beluga and Sterling perforations) Sand MD Top MD Bottom Total Footage (MD)TVD Top TVD Bottom ST_A1 ±3,024' ±3,033' 9' ±3,015' ±3,024' ST_A2 ±3,042' ±3,045' 3' ±3,033' ±3,036' ST_A3 ±3,071' ±3,101' 30' ±3,062' ±3,092' ST_A3 ±3,105' ±3,117' 12' ±3,096' ±3,108' ST_A4_COAL ±3,128' ±3,137' 9' ±3,119' ±3,128' ST_A4 ±3,157' ±3,172' 15' ±3,147' ±3,162' ST_A5 ±3,189' ±3,203' 14' ±3,179' ±3,193' ST_B1 ±3,224' ±3,240' 16' ±3,214' ±3,230' ST_B2 ±3,252' ±3,289' 37' ±3,242' ±3,279' ST_B3 ±3,317' ±3,325' 8' ±3,306' ±3,314' ST_B4 ±3,340' ±3,350' 10' ±3,330' ±3,340' ST_C1 ±3,368' ±3,379' 11' ±3,358' ±3,369' ST_C1 ±3,412' ±3,419' 7' ±3,402' ±3,409' ST_C2 ±3,422' ±3,434' 12' ±3,411' ±3,423' ST_C3 ±3,455' ±3,468' 13' ±3,444' ±3,457' ST_C5 ±3,497' ±3,526' 29' ±3,486' ±3,515' Beluga D ±3,567' ±3,571' 4' ±3,556' ±3,560' Beluga D1 ±3,585' ±3,601' 16' ±3,573' ±3,589' Beluga D2 ±3,606' ±3,613' 7' ±3,594' ±3,601' Beluga D3 ±3,641' ±3,652' 11' ±3,629' ±3,640' Beluga D4 ±3,668' ±3,675' 7' ±3,656' ±3,663' Beluga E1 ±3,802' ±3,818' 16'±3,790' ±3,806' Beluga E3 ±3,946' ±3,953' 7'±3,935' ±3,942' Beluga E6 ±4,117' ±4,147' 30'±4,105' ±4,135' Beluga F4 ±4,222' ±4,233' 11'±4,210' ±4,221' Beluga F4 ±4,272' ±4,279' 7'±4,260' ±4,267' Beluga F6 ±4,346' ±4,363' 17'±4,334' ±4,351' Beluga F6 ±4,383' ±4,391' 8'±4,370' ±4,378' Beluga F6 ±4,396' ±4,404' 8'±4,384' ±4,392' (No cement behind casing from liner top to 3450 ft. ) Sterling sands above 3526 ft not approved to perf.... cement sqz required. ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- (Sundry required to perforate ) All Beluga Sand intervals are approved. Sterling Perfs not approved. Beluga D ±3,567'±3,571'4'±3,556'±3,560' Beluga D1 ±3,585'±3,601'16'±3,573'±3,589' Beluga D2 ±3,606'±3,613'7'±3,594'±3,601' Beluga D3 ±3,641'±3,652'11'±3,629'±3,640' Beluga D4 ±3,668'±3,675'7'±3,656'±3,663' Beluga E1 ±3,802'±3,818'16'±3,790'±3,806' Beluga E3 ±3,946'±3,953'7'±3,935'±3,942' 30'Beluga E6 ±4,117'±4,147'±4,105'±4,135' Beluga F4 ±4,222'±4,233'11'±4,210'±4,221' Beluga F4 ±4,272'±4,279'7'±4,260'±4,267' 17'Beluga F6 ±4,346'±4,363'±4,334'±4,351' Beluga F6 ±4,383'±4,391'8'±4,370'±4,378' Beluga F6 ±4,396'±4,404'8'±4,384'±4,39 TOC @ 3450 ft MD Sterling Beluga completed wellwork gls Well Prognosis Well: BRU 241-34T Date: 8-20-2020 Beluga F7 ±4,463' ±4,492' 29'±4,451' ±4,480' Beluga F7 ±4,568' ±4,586' 18'±4,556' ±4,574' Beluga G1 ±4,692' ±4,709' 17'±4,680' ±4,697' Beluga G3 ±4,738' ±4,780' 42'±4,727' ±4,769' Beluga G5 ±4,847' ±4,852' 5'±4,835' ±4,840' Beluga G6 ±4,879' ±4,884' 5'±4,867' ±4,872' Beluga G6 ±4,909' ±4,913' 4'±4,896' ±4,900' Beluga G9 ±4,977' ±4,984' 23'±4,965' ±4,988' Beluga G10 ±5,019' ±5,047' 28'±5,007' ±5,035' Beluga H ±5,059' ±5,064' 5'±5,047' ±5,052' Beluga H ±5,075' ±5,082' 7'±5,063' ±5,070' Beluga H2 ±5,143' ±5,162' 19'±5,131' ±5,150' Beluga H4 ±5,236' ±5,246' 10'±5,224' ±5,234' Beluga H7 ±5,367' ±5,374' 7'±5,354' ±5,361' Beluga H10 ±5,477' ±5,510' 33'±5,464' ±5,497' Beluga H12 ±5,535' ±5,563' 28'±5,524' ±5,552' Beluga H13 ±5,563' ±5,589' 26'±5,551' ±5,577' Beluga H14 ±5,696' ±5,708' 12'±5,684' ±5,696' Beluga H15 ±5,732' ±5,756' 24'±5,719' ±5,743' 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 Beluga Beluga F7 ±4,463'±4,492'29'±4,451'±4,480' Beluga F7 ±4,568'±4,586'18'±4,556'±4,574' 17'Beluga G1 ±4,692'±4,709'±4,680'±4,697' Beluga G3 ±4,738'±4,780'42'±4,727'±4,769' Beluga G5 ±4,847'±4,852'5'±4,835'±4,840' 5'Beluga G6 ±4,879'±4,884'±4,867'±4,872' Beluga G6 ±4,909'±4,913'4'±4,896'±4,900' Beluga G9 ±4,977'±4,984'23'±4,965'±4,988' 28'Beluga G10 ±5,019'±5,047'±5,007'±5,035' Beluga H ±5,059'±5,064'5'±5,047'±5,052' Beluga H ±5,075'±5,082'7'±5,063'3'±5,070' Updated by DMA 08-20-20 SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,778’ MD / TVD = 5,767’ TD = 5,865’ MD / TVD = 5,852’ 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” 2,560’ 5,865’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,560’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,560’ 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 2732' MIT-IA to 2500 psi CBL TOC at 3450 ft. Updated by DMA 08-20-20 – Page 1 of 2 PROPOSED SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 PBTD = 5,778’ MD / TVD = 5,767’ TD = 5,865’ MD / TVD = 5,852’ 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” 2,560’ 5,865’ 5-1/2" Prod Tieback 17 P-110 ICY TXP BTC 4.892” Surf 2,560’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,560’ 6.170” 8.430” Baker ZXP Liner Top Packer Flex-Lock V liner hanger 2 2,560’ 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 PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD FT Date Status ST_A1 ±3,024' ±3,033' ±3,015' ±3,024' 9' Proposed TBD ST_A2 ±3,042' ±3,045' ±3,033' ±3,036' 3' Proposed TBD ST_A3 ±3,071' ±3,101' ±3,062' ±3,092' 30' Proposed TBD ST_A3 ±3,105' ±3,117' ±3,096' ±3,108' 12' Proposed TBD ST_A4_COAL ±3,128' ±3,137' ±3,119' ±3,128' 9' Proposed TBD ST_A4 ±3,157' ±3,172' ±3,147' ±3,162' 15' Proposed TBD ST_A5 ±3,189' ±3,203' ±3,179' ±3,193' 14' Proposed TBD ST_B1 ±3,224' ±3,240' ±3,214' ±3,230' 16' Proposed TBD ST_B2 ±3,252' ±3,289' ±3,242' ±3,279' 37' Proposed TBD ST_B3 ±3,317' ±3,325' ±3,306' ±3,314' 8' Proposed TBD ST_B4 ±3,340' ±3,350' ±3,330' ±3,340' 10' Proposed TBD ST_C1 ±3,368' ±3,379' ±3,358' ±3,369' 11' Proposed TBD ST_C1 ±3,412' ±3,419' ±3,402' ±3,409' 7' Proposed TBD ST_C2 ±3,422' ±3,434' ±3,411' ±3,423' 12' Proposed TBD ST_C3 ±3,455' ±3,468' ±3,444' ±3,457' 13' Proposed TBD ST_C5 ±3,497' ±3,526' ±3,486' ±3,515' 29' Proposed TBD ** PERFORATION DETAIL CONTINUED ON FOLLOWING PAGE ** ST A1-A5 Bel E1-E3 Bel F4-F7 Bel G1-G10 Bel H-H15 Bel D-D4 ST B1-B4 ST C1-C5 Updated by DMA 08-20-20 – Page 2 of 2 PROPOSED SCHEMATIC Beluga River Unit BRU 241-34T PTD: 220-052 API: 50-283-20181-00-00 ** PERFORATION DETAIL CONTINUED FROM PREVIOUS PAGE ** PERFORATION DETAIL Sand Top (MD) Btm (MD) Top TVD Btm TVD FT Date Status Beluga D ±3,567' ±3,571' ±3,556' ±3,560' 4' Proposed TBD Beluga D1 ±3,585' ±3,601' ±3,573' ±3,589' 16' Proposed TBD Beluga D2 ±3,606' ±3,613' ±3,594' ±3,601' 7' Proposed TBD Beluga D3 ±3,641' ±3,652' ±3,629' ±3,640' 11' Proposed TBD Beluga D4 ±3,668' ±3,675' ±3,656' ±3,663' 7' Proposed TBD Beluga E1 ±3,802' ±3,818' ±3,790' ±3,806' 16' Proposed TBD Beluga E3 ±3,946' ±3,953' ±3,935' ±3,942' 7' Proposed TBD Beluga E6 ±4,117' ±4,147' ±4,105' ±4,135' 30' Proposed TBD Beluga F4 ±4,222' ±4,233' ±4,210' ±4,221' 11' Proposed TBD Beluga F4 ±4,272' ±4,279' ±4,260' ±4,267' 7' Proposed TBD Beluga F6 ±4,346' ±4,363' ±4,334' ±4,351' 17' Proposed TBD Beluga F6 ±4,383' ±4,391' ±4,370' ±4,378' 8' Proposed TBD Beluga F6 ±4,396' ±4,404' ±4,384' ±4,392' 8' Proposed TBD Beluga F7 ±4,463' ±4,492' ±4,451' ±4,480' 29' Proposed TBD Beluga F7 ±4,568' ±4,586' ±4,556' ±4,574' 18' Proposed TBD Beluga G1 ±4,692' ±4,709' ±4,680' ±4,697' 17' Proposed TBD Beluga G3 ±4,738' ±4,780' ±4,727' ±4,769' 42' Proposed TBD Beluga G5 ±4,847' ±4,852' ±4,835' ±4,840' 5' Proposed TBD Beluga G6 ±4,879' ±4,884' ±4,867' ±4,872' 5' Proposed TBD Beluga G6 ±4,909' ±4,913' ±4,896' ±4,900' 4' Proposed TBD Beluga G9 ±4,977' ±4,984' ±4,965' ±4,988' 23' Proposed TBD Beluga G10 ±5,019' ±5,047' ±5,007' ±5,035' 28' Proposed TBD Beluga H ±5,059' ±5,064' ±5,047' ±5,052' 5' Proposed TBD Beluga H ±5,075' ±5,082' ±5,063' ±5,070' 7' Proposed TBD Beluga H2 ±5,143' ±5,162' ±5,131' ±5,150' 19' Proposed TBD Beluga H4 ±5,236' ±5,246' ±5,224' ±5,234' 10' Proposed TBD Beluga H7 ±5,367' ±5,374' ±5,354' ±5,361' 7' Proposed TBD Beluga H10 ±5,477' ±5,510' ±5,464' ±5,497' 33' Proposed TBD Beluga H12 ±5,535' ±5,563' ±5,524' ±5,552' 28' Proposed TBD Beluga H13 ±5,563' ±5,589' ±5,551' ±5,577' 26' Proposed TBD Beluga H14 ±5,696' ±5,708' ±5,684' ±5,696' 12' Proposed TBD Beluga H15 ±5,732' ±5,756' ±5,719' ±5,743' 24' 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. R&C zg ► - 34'T - P7 -b zzC657z_G Regg, James B (CED) From: Regg, James B (CED) Sent: Wednesday, August 5, 2020 10:37 AM��I`ol��'z To: Rance Pederson - (C) Cc: Monty Myers; Frank Roach; Jesse Richardson - (C); Loepp, Victoria T (CED); Schwartz, Guy L (CED) Subject: RE: Hilcorp Rig 169 Notice of BOP Closure Annular Preventer (used 8/3) must also be tested when trip to surface prior to reentry. As a suggestion, consider resetting the BOPE test clock with a full test prior to reentry. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Rance Pederson - (C) <rpederson@hilcorp.com> Sent: Wednesday, August 5, 2020 8:21 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Monty Myers <mmyers@hilcorp.com>; Frank Roach <Frank.Roach@hilcorp.com>; Jesse Richardson - (C) <jesrichardson@hilcorp.com> Subject: Hilcorp Rig 169 Notice of BOP Closure Jim, please see the attached notice of BOP closure for BRU 241-34T (PTD: 220-052). Rance Pederson Drilling Foreman Beluga River Unit 907-776-6776 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of 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 Notice of BOP Use • Date/Time: 8/4/2020 at 23:24 hrs. • Well: BRU 241-34T • Location: Beluga River Field, F Pad • PTD: 220-052 • Rig Name: Hilcorp Rig 169 • Operator Contact: Rance Pederson at 907-776-6776 / rpederson@hilcorp.com • Operation Summary: Drilled 8 %2" production hole to TD at 5865' md, 5853'tvd. POOH to PU logging BHA. On trip in with logging tools lost circulation just outside surface casing shoe. Spotted LCM pills and healed up well. POOH and PU cleanout assembly to make a run to bottom. At 2755' we had to wash and ream down to 2798' where well took 20 bbls fluid and then we had partial returns. Pulled back up into casing shoe at 2733' and monitored well with slight losses. Tripped in hole slow to 2953' and seeing over displacement of drill pipe. Stopped tripping, monitored well and had flow. • BOPE Used: Upper variable rams (2 7/8" x 5") and auto choke valve. • Reason For BOPE Use: Had over displacement while tripping 5 stands in hole. Lined up and started to circulate bottoms up, had drilling mud erupt through rotary table, flow show increased from 15% to 55% in a matter of seconds. • Actions Taken: Closed upper rams and monitored SICP and SIDPP, lined up and circulated one full circ through choke and poorboy degasser vessel to circ out gas. After one full circ at slow pump rate, checked for flow and had no flow. Opened well and circulated with 9.4 ppg mud, losing returns to the point we had no returns at all. Pulled up hole from 2953' to 2704' and back into surface casing while filling on backside with trip tank. Pumped LCM pill down drill pipe and another pill down backside. • Action To Be Taken: At this time, we are parked inside surface casing, have pumped and spotted 2 LCM pills to heal up losses. We do have returns back now and are building surface volume. Will continue to monitor and circulate out any gas with 9.4 ppg mud. Once we can safely pull out of hole, we will test our upper rams and auto choke prior to tripping back in hole and resuming any operations. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: v/1412 P.I. Suprv--1 1 BOPE Test Report for: BELUGA RIV UNIT 241-34T ✓ Comm Contractor/Rig No.: Ililcorp 169 PTD#: 2200520 - DATE: 7/27/2020 - Inspector Austin McLeod Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Rogers/Riley Rig Rep: Davis/Irick Inspector Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopSAM200728131906 Rams: Annular: Valves: MASP: Type Test: INIT 250/3500 - 250/3500 - 250/3500 - 2080 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: Quantity ACCUMULATOR SYSTEM: Upper Kelly 1 P/F Lower Kelly Visual Alarm P Time/Pressure P/F Location Gen.: P Trip Tank P _P System Pressure 3000 P Housekeeping: P Pit Level Indicators P P_ Pressure After Closure 1550 P PTD On Location P Flow Indicator P P 200 PSI Attained 1_6 P Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 83 P Well Sign P H2S Gas Detector FP ' FP Blind Switch Covers: All stations -_P NA Drl. Rig P MS Misc NA NA Nitgn. Bottles (avg): 4(&,2525 P Hazard Sec. P P Quantity P/F ACC Misc 0 NA Misc NA NA Kill Line Valves 2 _' 2-1/16" _ P FLOOR SAFTY VALVES: Quantity P/F Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 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 l - 11" P Manual Chokes l P #1 Rams 1 2-7/8" x 5" P Hydraulic Chokes 1 - P #2 Rams 1 Blinds P CH Misc 0 NA #3 Rams 1 2-7/8" x 5" P 44 Rams 0 NA INSIDE REEL VALVES: #5 Rams 0 NA #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves _ l , 3-1/8" P Quantity P/F HCR Valves 2 2-I1/16"/3-1/8, 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: 2 Test Results Remarks: 4-1/2" joint. Shaker 1-12S would not read. Calibrated for a pass. Test Time 4 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 Gas Pool, BRU 241-34T Hilcorp Alaska, LLC Permit to Drill Number: 220-052 Surface Location: 915' FNL, 1432' FEL, Sec 34, T13N, R10W, SM, AK Bottomhole Location: 803' FNL, 1198' FEL, Sec 34, T13N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. The permit to drill is approved. Once the well has been completed, Hilcorp shall notify AOGCC. Approval to test, produce, or inject is not authorized until issuance of an order approving a spacing exception. Hilcorp Alaska, LLC assumes all liability of any protest to the spacing exception that may occur. 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 July, 2020. y, JMPi 16 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: 6,511' TVD: 6,499' 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): 101.7 15. Distance to Nearest Well Open Surface: x-316486 y- 2624263 Zone-4 83.7 to Same Pool:1990' to BRU 212-35T 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 5 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' 2,741' 8-1/2" 5-1/2" 17# P-110 TXP 6,511' Surface Surface 6,511' 6,499' 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 4162' to nearest unit boundary 7/25/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Monty Myers mmyers@hilcorp.com 777-8431 18. Casing Program:Top - Setting Depth - BottomSpecifications BRU 241-34T Beluga River Unit Beluga River Undefined 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 915' FNL, 1432' FEL, Sec 34, T13N, R10W, SM, AK FEDA029657 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 953 ft3 / T - 138 ft3 2080 803' FNL, 1198' FEL, Sec 34, T13N, R10W, SM, AK 803' FNL, 1198' FEL, Sec 34, T13N, R10W, SM, AK N/A 1474 2730 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 LengthCasing Intermediate Authorized Signature: Surface Production Liner 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. Perforation Depth TVD (ft): Commission Use Only GL / BF Elevation above MSL (ft): 6/8/2020 Effect. Depth MD (ft): es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es 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 12:08 pm, Jun 08, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp AK, ou=Drilling Manager, email=mmyers@hilcorp.com Reason: I am approving this document Location: Anchorage AK Date: 2020.06.08 11:00:12 -08'00' Monty M Myers Separate sundry to perforate well is required CBL over 5 1/2" casing to TOC MIT-IA to 2500 psi on IA (5 1/2" x 9 5/8") after WOC 50-283-20181-00-00220-052 DSR-6/8/2020 BOP test pressure to 3500 psig Annular preventer test pressure to 2500 psig Gas X SFD 7/15/2020VTL 07/15/2020 eventer testpppppppppppppppppprerererereererereerrrerereerrererrerreeressu 7/16/2020 7/16/2020 BRU 241-34T Drilling Program Beluga River Unit Rev 0 June 5, 2020 BRU 241-34T 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 241-34T Drilling Procedure Rev 0 1.0 Well Summary Well BRU 241-34T Pad & Old Well Designation BRU 241-34T is a grass roots well on BRU F Pad Planned Completion Type 5-1/2” Production Longstring (monobore) Target Reservoir(s) Sterling/Beluga Planned Well TD, MD / TVD 6,511 MD / 6,499’ TVD PBTD, MD / TVD 6,400’ MD / 6,388’ TVD Surface Location (Governmental) 915’ FNL, 1432’ F EL, Sec 34, T13N, R10W, SM, AK Surface Location (NAD 27) X=316486.24 Y=2624263.31 Surface Location (NAD 83) X=1456513.22 Y=2624023.83 Top of Productive Horizon (Governmental) 803’ FNL, 1198’ F EL, Sec 34, T13N, R10W, SM, AK TPH Location (NAD 27) X=316721.42, Y=2624371.03 TPH Location (NAD 83) X=1456748.40 Y=2624131.55 BHL (Governmental) 803’ FNL, 1198’ FEL, Sec 34, T13N, R10W, SM, AK BHL (NAD 27) X=316721.42, Y=2624371.03 BHL (NAD 83) X=1456748.40 Y=2624131.55 AFE Number 2011739 (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) 2080 psi Maximum Anticipated Pressure (Downhole/Reservoir) 2730 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 101.7’(83.7 + 18) Ground Elevation 83.7’ 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 241-34T Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version 0 June, 2020 BRU 241-34T 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). Page 5 Version 0 June, 2020 BRU 241-34T 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 241-34T Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic Page 7 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 7.0 Drilling / Completion Summary BRU 241-34T is an S-shaped directional grassroots development well to be drilled off of the BRU F pad. It is designed to twin the existing BRU 241-34 and be a replacement well. This well is basically a vertical well. 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 300’ MD. Maximum hole angle will be 5 deg. and TD of the well will be 6,511’ TMD/ 6,499’ TVD, ending with 0 deg inclination left in the hole. Vertical section will be 259 ft. Drilling operations are expected to commence approximately July 25th 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 / 2,741’ 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 6,511’ 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. Refer to AOGCC Industry Guidance Bulletin 13-01: Remedial Cementing for Surface Casing. VTL 7/13/20 Page 8 Version 0 June, 2020 BRU 241-34T 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 241-34T. 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. flexible choke and kill lines in lieu of hard piping. See AOGCC Industry Guidance Bulletins: 06-01: BOPE Testing After Use 10-03: Reporting BOPE Use to Prevent the Flow of Fluids from a Well VTL 7/13/20 Page 9 Version 0 June, 2020 BRU 241-34T 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 Townsend Annular BOP x 11” x 5M Townsend Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Townsend 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 241-34T Drilling Procedure Rev 0 Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 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 241-34T 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. U Mud loggers on surface hole section for gas detection only. Page 12 Version 0 June, 2020 BRU 241-34T 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. Page 13 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 10.5 Rig 169 and estimated Diverter line Orientation on BRU F Pad: Page 14 Version 0 June, 2020 BRU 241-34T 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 241-34T 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/ 2,741’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. 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 (60’ 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 throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud 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 Page 16 Version 0 June, 2020 BRU 241-34T 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 241-34T 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 running 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 241-34T Drilling Procedure Rev 0 Page 19 Version 0 June, 2020 BRU 241-34T 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 241-34T 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 .05578 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 Page 21 Version 0 June, 2020 BRU 241-34T 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 Page 22 Version 0 June, 2020 BRU 241-34T 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 through 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 241-34T 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. Page 24 Version 0 June, 2020 BRU 241-34T 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 241-34T Drilling Procedure Rev 0 15.8 Primary Bit: Page 26 Version 0 June, 2020 BRU 241-34T 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 throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2,750’- 6,511’ 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 since the MASP is 2080 psi. 15.12 Drill out shoe track and 20’ of new formation. 15.13 CBU and condition mud for FIT. Page 27 Version 0 June, 2020 BRU 241-34T 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(2741/6499) = 1.89 15.15 Drill 8-1/2” hole section to 6,511’ MD / 6,499’ 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. Page 28 Version 0 June, 2020 BRU 241-34T 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 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 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 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. 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 Page 29 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 Page 30 Version 0 June, 2020 BRU 241-34T 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. Page 31 Version 0 June, 2020 BRU 241-34T 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: (6011’ – 2750’) x .0408 bpf x 1.1 = 146.4 822 Total LEAD: 169.6 953 ft3 15.4 ppg TAIL: 8-1/2” OH x 5-1/2” annulus: (6511’- 6011’) 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 Page 32 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 Cement Slurry Design: Lead Slurry (6011’ MD to 2250’ MD) Tail Slurry (6511’ to 6011’ 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 241-34T 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. CBL required over 5-1/2" casing to TOC Submit to AOGCC for review/approval VTL 7/13/20 Page 34 Version 0 June, 2020 BRU 241-34T 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 Page 35 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 19.0 BOP Schematic Page 36 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 20.0 Wellhead Schematic Page 37 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 21.0 Days Vs Depth Page 38 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 22.0 Geo-Prog Well Name:BRU 241-34T Survey Type KB Field Name:Beluga River Unit Surface Hole:101.7 Pool Name:BELUGA RIVER, UNDEFI Bottom Hole:HAK 169 State:Alaska 18 Field Location:Onshore Coord Ref Sys:83.7 County/Parish:Tyonek Borough Objective: Reference Plan: BRU_ST_A1_COAL Coal Gas / Water 2998.12 2,918.8 -2900.79 2624360.74 316689.56 1000.00 STERLING_B Sandstone Gas / Water 3198.37 3,118.4 -3100.39 2624365.67 316704.87 400.00 STERLING_C Sandstone Gas / Water 3342.3 3,261.9 -3243.87 2624369.19 316715.8 1000.00 BELUGA_D Sandstone / Siltstone Gas / Water 3541.65 3,461.1 -3443.06 2624371.08 316721.64 150.00 BELUGA_E Sandstone / Siltstone Gas / Water 3741.97 3,661.4 -3643.38 2624371.08 316721.64 700.00 BELUGA_F Sandstone / Siltstone Gas / Water 4126.76 4,046.2 -4028.18 2624371.08 316721.64 500.00 BELUGA_G Sandstone / Siltstone Gas / Water 4652.97 4,572.4 -4554.38 2624371.08 316721.64 1900.00 BELUGA_H Sandstone / Siltstone Gas / Water 5035.69 4,955.1 -4937.1 2624371.08 316721.64 2050.00 BELUGA_I Sandstone / Siltstone Gas / Water 5798.22 5,717.6 -5699.63 2624371.08 316721.64 2200.00 BRU_BELUGA_J Sandstone / Siltstone Gas / Water 6350.55 6,270.0 -6251.96 2624371.08 316721.64 2400.00 = 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: Several depleted sands throughout interval. See Frac Gradient Estimate Tab. OTHER COMMENTS LWD Triple Combo Pressure data collected throughout sands 2750 6511 PROSED PIPE SET DEPTHS Chance of Success & Anticipated Rate ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE NO INFORMATION CONCERNING THIS WELL IS TO BE RELEASED TO ANYONE EXCEPT THE EMPLOYEES OF HILCORP OR THEIR PARTNERS. Drill a grassroots well off of K-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 = 316,486.24 y = 2,624,263.31 TVD Ref Datum: TVD Ref Elevation: Planned Rig: Rig Height: x = 316,721.42 y = 2,624,371.03 6,511' MD 6,499' TVD NAD27 Zone 4 Beluga H, I, and J gas sands. Several depleted sands throughout interval. Page 39 Version 0 June, 2020 BRU 241-34T 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 241-34T 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 241-34T Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 42 Version 0 June, 2020 BRU 241-34T 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 241-34T Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 44 Version 0 June, 2020 BRU 241-34T 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: 2080 psi (see attached MASP determination & calculation) 2730 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 6,511 2,550 6,499 2,741 6,499 40 17 L-80 L-80 BTC CDC HTQ 109,640 110,483 109,640 110,483 916 428 8.35 3.87 1,193 2,827 3,090 6,290 2.59 2.22 645 2,080 5,750 7,740 8.91 3.72Worst case safety factor (Burst) DATE: 06/05/2020 WELL: BRU 241-34T FIELD: Beluga River Unit DESIGN BY: Monty M Myers Hole Size Hole Size Hole Size MASP: Production Mode Casing Section MASP: Drilling Mode MASP: Length Top (TVD) 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) 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: Page 45 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 28.0 8-1/2” Hole Section MASP MD TVD Planned Top: 0 0 Planned TD: 6511 6499 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad BRU_ST_A1_COAL 2918.79 1000 Gas/Wet 6.6 0.34 STERLING_B 3118.39 400 Gas/Wet 2.5 0.13 STERLING_C 3261.87 1000 Gas/Wet 5.9 0.31 BELUGA_D 3461.06 150 Gas/Wet 0.8 0.04 BELUGA_E 3661.38 700 Gas/Wet 3.7 0.19 BELUGA_F 4046.18 500 Gas/Wet 2.4 0.12 BELUGA_G 4572.38 1900 Gas/Wet 8.0 0.42 BELUGA_H 4955.1 2050 Gas/Wet 8.0 0.41 BELUGA_I 5717.63 2200 Gas/Wet 7.4 0.38 BRU_BELUGA_J 6269.96 2400 Gas/Wet 7.4 0.38 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 (2550' 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 2741 ft X 0.884 psi/ft 2423 psi 2423(psi) - [0.1(psi/ft)*2741(ft)]= 2149 psi MASP from pore pressure during production mode (Complete evacuation to gas) 6499 ft X 0.420 psi/ft 2730 psi Downhole 2730(psi) - [0.1(psi/ft)* 6499 (ft)]= 2080 psi Surface 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 BRU 241-34T Beluga River Unit 8-1/2" Hole Section Maximum Anticipated Surface Pressure Calculation Page 46 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 29.0 Spider Plot (Governmental Sections) Page 47 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 30.0 Surface Plat (As-Built NAD27 & NAD83) Page 48 Version 0 June, 2020 BRU 241-34T Drilling Procedure Rev 0 31.0 Directional Plan (wp05) !"##$ % & % & 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 7125 7600True Vertical Depth (950 usft/in)-950 -475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 Vertical Section at 64.48° (950 usft/in) BRU 241-34T wp01 9 5/8" x 12 1/4" 5 1/2" x 8 1/2" 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4000 4500 5000 5500 6000 65006512 BRU 241-34T wp05 Start Dir 2.5º/100' : 300' MD, 300'TVD End Dir : 500' MD, 499.75' TVD Start Dir 2.5º/100' : 1040' MD, 1037.69'TVD End Dir : 1250.36' MD, 1247.4' TVD Start Dir 2.5º/100' : 3603.56' MD, 3591.63'TVD End Dir : 3803.65' MD, 3791.47' TVD Total Depth : 6511' MD, 6498.82' TVD BRU_ST_A1_COAL STERLING_B STERLING_C BELUGA_D BELUGA_E BELUGA_F BELUGA_G BELUGA_H BELUGA_I BRU_BELUGA_J Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio WELL DETAILS: Plan: BRU 241-34T 83.70 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2624263.31 316486.24 61° 10' 43.628 N 151° 2' 22.990 W SURVEY PROGRAM Date: 2020-06-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 2750.00 BRU 241-34T wp05 (BRU 241-34T) 3_MWD+AX+Sag 2750.00 6511.00 BRU 241-34T wp05 (BRU 241-34T) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3002.70 2901.00 3012.37 BRU_ST_A1_COAL 3201.70 3100.00 3212.13 STERLING_B 3345.70 3244.00 3356.68 STERLING_C 3544.70 3443.00 3556.45 BELUGA_D 3744.70 3643.00 3756.88 BELUGA_E 4129.70 4028.00 4141.88 BELUGA_F 4655.70 4554.00 4667.88 BELUGA_G 5038.70 4937.00 5050.88 BELUGA_H 5801.70 5700.00 5813.88 BELUGA_I 6353.70 6252.00 6365.88 BRU_BELUGA_J REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 241-34T, True North Vertical (TVD) Reference:As-Built RKB @ 101.70usft (HEC 169) Measured Depth Reference:As-Built RKB @ 101.70usft (HEC 169) Calculation Method:Minimum Curvature Project:Beluga River Site:Beluga River Well:Plan: BRU 241-34T Wellbore:BRU 241-34T Design:BRU 241-34T wp05 Beluga River Beluga River Plan: BRU 241-34T BRU 241-34T BRU 241-34T wp05 4.108 CASING DETAILS TVD TVDSS MD Size Name 2741.33 2639.63 2750.00 9-5/8 9 5/8" x 12 1/4" 6498.82 6397.12 6511.00 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 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2.5º/100' : 300' MD, 300'TVD 3 500.00 5.00 115.00 499.75 -3.69 7.90 2.50 115.00 5.54 End Dir : 500' MD, 499.75' TVD 4 1040.00 5.00 115.00 1037.69 -23.58 50.56 0.00 0.00 35.47 Start Dir 2.5º/100' : 1040' MD, 1037.69'TVD 5 1250.36 5.00 51.49 1247.40 -21.74 66.05 2.50 -121.63 50.24 End Dir : 1250.36' MD, 1247.4' TVD 6 3603.56 5.00 51.49 3591.63 106.02 226.62 0.00 0.00 250.19 Start Dir 2.5º/100' : 3603.56' MD, 3591.63'TVD 7 3803.65 0.00 71.29 3791.47 111.45 233.45 2.50 180.00 258.69 End Dir : 3803.65' MD, 3791.47' TVD 8 6504.37 0.00 71.29 6492.19 111.45 233.45 0.00 0.00 258.69 BRU 241-34T wp01 9 6511.00 0.00 71.29 6498.82 111.45 233.45 0.00 71.29 258.69 Total Depth : 6511' MD, 6498.82' TVD -53-270275380107133160187213South(-)/North(+) (40 usft/in)-53 -27 0 27 53 80 107 133 160 187 213 240 267 293 320West(-)/East(+) (40 usft/in)BRU 241-34T wp019 5/8" x 12 1/4"5 1/2" x 8 1/2"25050075010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506 5 0 0BRU 241-34T wp05Start Dir 2.5º/100' : 300' MD, 300'TVDEnd Dir : 500' MD, 499.75' TVDStart Dir 2.5º/100' : 1040' MD, 1037.69'TVDEnd Dir : 1250.36' MD, 1247.4' TVDStart Dir 2.5º/100' : 3603.56' MD, 3591.63'TVDEnd Dir : 3803.65' MD, 3791.47' TVDTotal Depth : 6511' MD, 6498.82' TVDProject: Beluga RiverSite: Beluga RiverWell: Plan: BRU 241-34TWellbore: BRU 241-34TPlan: BRU 241-34T wp05WELL DETAILS: Plan: BRU 241-34T83.70+N/-S +E/-W NorthingEastingLatittude Longitude0.000.002624263.31 316486.24 61° 10' 43.628 N 151° 2' 22.990 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 241-34T, True NorthVertical (TVD) Reference:As-Built RKB @ 101.70usft (HEC 169)Measured Depth Reference:As-Built RKB @ 101.70usft (HEC 169)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2741.33 2639.63 2750.00 9-5/8 9 5/8" x 12 1/4"6498.82 6397.12 6511.00 5-1/2 5 1/2" x 8 1/2" -60-40-20020406080100120140South(-)/North(+) (30 usft/in)-20 0 20 40 60 80 100 120 140 160 180 200 220 240 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eparation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthBRU 241-34No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: BRU 241-34T NAD 1927 (NADCON CONUS)Alaska Zone 0483.70+N/-S +E/-W Northing EastingLatittudeLongitude0.000.00 2624263.31 316486.24 61° 10' 43.628 N 151° 2' 22.990 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 241-34T, True NorthVertical (TVD) Reference:As-Built RKB @ 101.70usft (HEC 169)Measured Depth Reference:As-Built RKB @ 101.70usft (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 241-34T wp05 (BRU 241-34T)3_MWD+AX+Sag2750.00 6511.00 BRU 241-34T wp05 (BRU 241-34T)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 241-34BRU 241-34GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 6511.88Project: Beluga RiverSite: Beluga RiverWell: Plan: BRU 241-34TWellbore: BRU 241-34TPlan: BRU 241-34T wp05Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name2741.33 2639.63 2750.00 9-5/8 9 5/8" x 12 1/4"6498.82 6397.12 6511.00 5-1/2 5 1/2" x 8 1/2" From:Monty Myers To:Loepp, Victoria T (CED); Schwartz, Guy L (CED) Cc:Frank Roach Subject:RE: [EXTERNAL] BRU 241-34T(PTD 220-052) Drilling Permit Date:Monday, July 13, 2020 4:13:16 PM Please see response below in red Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Loepp, Victoria T (CED) [mailto:victoria.loepp@alaska.gov] Sent: Monday, July 13, 2020 2:09 PM To: Monty Myers <mmyers@hilcorp.com> Subject: [EXTERNAL] BRU 241-34T(PTD 220-052) Drilling Permit Monty, A few questions on BRU 222-24: 1. What was the FIT out of the surface casing? We performed the FIT to a 13.5ppg EMW using a 9.0 ppg mud 2. When is the CBL planned for the production casing cement? The CBL will be run after the rig moves off, could be as early as Monday July 20th 2020 if everything continues on track. 3. On the surface casing cement job, were there cement returns to surface? We had 68 bbls of good lead cement returned to surface 4. What is the status of drilling this well? We have called TD on BRU 222-24 at a depth of 7,485’ 5. What is the latest estimate of when the rig will move? The rig could be ready to move on July 17th 2020 if operations continue on track. 6. How many days planned to drill BRU 241-34T? We have 21 days planned for drilling 241-34T Thanx, Victoria From: Monty Myers <mmyers@hilcorp.com> Sent: Monday, July 13, 2020 10:49 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: RE: [EXTERNAL] BRU 241-34T(PTD 220-052) Drilling Permit Victoria, Please see the attached page with the information as requested. There will be no ignition sources inside the 75’ radius of the end of the diverter line. The guys do a great job of hanging signage and putting up barricades to keep anyone from entering also. For the BOP test, a 5000 psi initial BOP test seems a bit excessive for a well that has a MASP of 2730 psi, and we have always tested the Annular in accordance with 20 AAC 25.035(e)(10)(A) that states it only needs to be tested to 50 percent of its rated working pressure. Since we have our first well near TD and were approved to test BOPE to 3500 psi I would prefer to leave it at this pressure as to not cause undue stress and wear on the BOP components. The CBL will be done by the Operations group and will be in their perforation sundry. Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Loepp, Victoria T (CED) [mailto:victoria.loepp@alaska.gov] Sent: Monday, July 13, 2020 9:26 AM To: Monty Myers <mmyers@hilcorp.com> Subject: [EXTERNAL] BRU 241-34T(PTD 220-052) Drilling Permit Monty, Would like to see a 75’ radius circle around discharge of the diverter line. Are there any ignition sources within that area? We have been requiring the initial BOP test to the rated working pressure(5000 psi) except the annular can be limited to 70%(3500 psi). I don’t see a CBL on the production casing cement. This will be required. Thanx, Victoria From: Monty Myers <mmyers@hilcorp.com> Sent: Monday, July 13, 2020 8:50 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov>; Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com>; Frank Roach <Frank.Roach@hilcorp.com>; Darci Horner - (C) <dhorner@hilcorp.com> Subject: BRU 241-34T drilling permit Good morning Victoria! We are about 4 days out from finishing up on BRU 222-24 in Beluga River. I haven’t seen an approved permit for BRU 241-34T and wanted to know if you had any questions about it? It was submitted on 6.8.2020. Please let me know if you need any additional information from us. Thank you! Monty M Myers Drilling Manager 907.538.1168 (c) 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. 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. WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 241-34TInitial Class/TypeDEV / 1-GASGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200520BELUGA RIVER, UNDEFINED GAS - 92500NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA1Permit fee attachedYesEntire Well lies within FEDA029657.2Lease number appropriateYes3Unique well name and numberNoBELUGA RIVER, UNDEFINED GAS - 925004Well located in a defined poolYesSPACING EXCEPTION REQUIRED: Well does not conform with 20 AAC 25.055;5Well located proper distance from drilling unit boundaryNolies within 3,000' of nearby open wells BRU 233-27, BRU 212-35T, and BRU 243-34.6Well located proper distance from other wellsYesThis well will be the second well open to the undefined pool in Section 34.7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceNoIf PTD is approved prior to CO approval, strongly recommend adding "Full11Permit can be issued without conservation orderYesCompliance with 20 ACC 25.055" condition to approval letter. SFD 7/13/202012Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)Yes18Conductor string providedYesSurface casing will be set and fully cemented from 2750' MD19Surface casing protects all known USDWsYes56% excess cement planned20CMT vol adequate to circulate on conductor & surf csgYes5-1/2" casing will be cemented up into the 9-5/8" surface casing21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYesBTC calculations are provided23Casing designs adequate for C, T, B & permafrostYesRig 169 has steel tanks. All waste will be transported to the KGF disposal wells24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesAnti-collision analysis completed; no major risk failures26Adequate wellbore separation proposedYes16" diverter of Rig 169 and diverter discharge line route meet regulations27If diverter required, does it meet regulationsYesMax formation pressure is 2730 psig(8.1 ppg EMW); will drill w/ 9.0-10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 2080 psig; will test BOPs to 3500 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)YesSundry required to perforate well32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S is not anticipated based on nearby wells.35Permit can be issued w/o hydrogen sulfide measuresYesMaximum expected reservoir pressure is 8.5 ppg EMW; however, most sands encountered are expected36Data presented on potential overpressure zonesNAto be depleted to severely depleted. LCM materials will also be available onsite. Production interval37Seismic analysis of shallow gas zonesNAwill be drilled using 9.0 to 10.0 ppg mud. Additional materials will be onsite to build38Seabed condition survey (if off-shore)NAmud to 1 ppg more than the greatest anticipated mud weight.39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/13/2020ApprVTLDate7/14/2020ApprSFDDate6/8/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateApproval to test, produce, or inject is not authorized until issuance of an order approving a spacing exception.JMP7/16/2020JLC 7/15/2020